Xcel Energy (XEL) 10-K 23 Feb 18 2017 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2017	Feb. 19, 2018	Jun. 30, 2017	Dec. 31, 2016
Document and Entity Information [Abstract]
Entity Registrant Name	XCEL ENERGY INC
Entity Central Index Key	72,903
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Entity Public Float			$ 23,304,874,235
Entity Common Stock, Shares Outstanding		508,064,983
Common Stock, Shares Outstanding (in shares)	507,762,881		507,952,795	507,222,795
Document Fiscal Year Focus	2,017
Document Fiscal Period Focus	FY
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2017

CONSOLIDATED STATEMENTS OF INCO

CONSOLIDATED STATEMENTS OF INCOME - USD ($) shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Operating revenues
Electric	$ 9,676	$ 9,500	$ 9,276
Natural gas	1,650	1,531	1,672
Other	78	76	76
Total operating revenues	11,404	11,107	11,024
Operating expenses
Electric fuel and purchased power	3,757	3,718	3,763
Cost of natural gas sold and transported	823	733	905
Cost of sales — other	34	36	36
Operating and maintenance expenses	2,303	2,326	2,330
Conservation and demand side management program expenses	273	245	225
Depreciation and amortization	1,479	1,303	1,124
Taxes (other than income taxes)	545	532	512
Loss on Monticello life cycle management/extended power uprate project	0	0	129
Total operating expenses	9,214	8,893	9,024
Operating income	2,190	2,214	2,000
Other income, net	23	8	6
Equity earnings of unconsolidated subsidiaries	30	42	34
Allowance for funds used during construction — equity	75	60	56
Interest charges and financing costs
Interest charges — includes other financing costs of $24, $25 and $24, respectively	663	647	595
Allowance for funds used during construction — debt	(35)	(27)	(26)
Total interest charges and financing costs	628	620	569
Income before income taxes	1,690	1,704	1,527
Income taxes	542	581	543
Net income	$ 1,148	$ 1,123	$ 984
Weighted average common shares outstanding:
Basic (in shares)	509	508.8	507.8
Diluted (in shares)	509.1	509	508.2
Earnings per average common share:
Basic (in dollars per share)	$ 2.26	$ 2.21	$ 1.94
Diluted (in dollars per share)	2.25	2.21	1.94
Cash dividends declared per common share (in dollars per share)	$ 1.44	$ 1.36	$ 1.28

CONSOLIDATED STATEMENTS OF INC3

CONSOLIDATED STATEMENTS OF INCOME (Parenthetical) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Interest charges and financing costs
Other financing costs	$ 24	$ 25	$ 24

CONSOLIDATED STATEMENTS OF COMP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Comprehensive income:
Net income	$ 1,148	$ 1,123	$ 984
Pension and retiree medical benefits:
Net pension and retiree medical losses arising during the period, net of tax of $(2), $(5), and $(5), respectively	(3)	(8)	(8)
Amortization of losses included in net periodic benefit cost, net of tax of $5, $2, and $2, respectively	7	4	3
Total pension and retiree medical benefits, net of tax	4	(4)	(5)
Derivative instruments:
Reclassification of losses to net income, net of tax of $2, $2, and $2, respectively	3	4	3
Other comprehensive income (loss)	7	0	(2)
Comprehensive income	$ 1,155	$ 1,123	$ 982

CONSOLIDATED STATEMENTS OF COM5

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Pension and retiree medical benefits:
Net pension and retiree medical benefit (losses) gains arising during the period, tax	$ (2)	$ (5)	$ (5)
Amortization of losses included in net periodic benefit cost, tax	5	2	2
Derivative instruments:
Reclassification of losses to net income, tax	$ 2	$ 2	$ 2

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Operating activities
Net income	$ 1,148	$ 1,123	$ 984
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization	1,495	1,319	1,143
Conservation and demand side management program amortization	2	4	5
Nuclear fuel amortization	114	117	106
Deferred income taxes	640	587	536
Amortization of investment tax credits	(5)	(5)	(5)
Allowance for equity funds used during construction	(75)	(60)	(56)
Equity earnings of unconsolidated subsidiaries	(30)	(42)	(34)
Dividends from unconsolidated subsidiaries	41	46	40
Provision for bad debts	39	39	36
Share-based compensation expense	57	41	45
Loss on Monticello life cycle management/extended power uprate project	0	0	129
Net realized and unrealized hedging and derivative transactions	2	8	22
Other, net	(3)	(1)	(1)
Changes in operating assets and liabilities:
Accounts receivable	(60)	(83)	66
Accrued unbilled revenues	(34)	(75)	74
Inventories	(3)	1	(11)
Other current assets	9	61	9
Accounts payable	43	118	(120)
Net regulatory assets and liabilities	(16)	(19)	102
Other current liabilities	(38)	20	78
Pension and other employee benefit obligations	(133)	(91)	(69)
Change in other noncurrent assets	(1)	(16)	11
Change in other noncurrent liabilities	(66)	(40)	(52)
Net cash provided by operating activities	3,126	3,052	3,038
Investing activities
Utility capital/construction expenditures	(3,319)	(3,256)	(3,683)
Allowance for equity funds used during construction	75	61	56
Proceeds from insurance recoveries	0	5	27
Purchases of investment securities	(1,697)	(547)	(1,258)
Proceeds from the sale of investment securities	1,669	479	1,237
Investments in unconsolidated subsidiaries and other	(17)	(4)	(2)
Other, net	(7)	1	0
Net cash used in investing activities	(3,296)	(3,261)	(3,623)
Financing activities
Proceeds from (repayments of) short-term borrowings, net	422	(454)	(174)
Proceeds from issuance of long-term debt	1,518	2,424	1,626
Repayments of long-term debt, including reacquisition premiums	(1,030)	(1,036)	(251)
Proceeds from issuance of common stock	0	0	7
Repurchases of common stock	(3)	(32)	0
Dividends paid	(721)	(681)	(607)
Other	(18)	(12)	(11)
Net cash provided by financing activities	168	209	590
Net change in cash and cash equivalents	(2)	0	5
Cash and cash equivalents at beginning of period	85	85	80
Cash and cash equivalents at end of period	83	85	85
Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized)	(616)	(592)	(543)
Cash received for income taxes, net	44	62	58
Supplemental disclosure of non-cash investing and financing transactions:
Property, plant and equipment additions in accounts payable	415	254	322
Issuance of common stock for reinvested dividends and equity awards	$ 31	$ 29	$ 53

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions		Dec. 31, 2017	Dec. 31, 2016
Current assets
Cash and cash equivalents		$ 83	$ 85
Accounts receivable, net		797	776
Accrued unbilled revenues		764	730
Inventories		610	604
Regulatory assets		424	364
Derivative instruments		44	38
Prepaid Taxes		68	107
Prepayments and other		183	138
Total current assets		2,973	2,842
Property, plant and equipment, net		34,329	32,842
Other assets
Nuclear decommissioning fund and other investments		2,397	2,092
Regulatory assets		3,005	3,081
Derivative instruments		48	50
Deposits and other		278	248
Total other assets		5,728	5,471
Total assets		43,030	41,155
Current liabilities
Current portion of long-term debt		457	255
Short-term debt		814	392
Accounts payable		1,243	1,045
Regulatory liabilities	[1]	239	221
Taxes accrued		448	457
Accrued interest		174	173
Dividends payable		183	172
Derivative instruments		29	27
Other		501	505
Total current liabilities		4,088	3,247
Deferred credits and other liabilities
Deferred income taxes		3,845	6,784
Deferred investment tax credits		58	63
Regulatory liabilities		5,083	1,383
Asset retirement obligations		2,475	2,782
Derivative instruments		126	148
Customer advances		193	195
Pension and employee benefit obligations		1,042	1,112
Other		145	225
Total deferred credits and other liabilities		12,967	12,692
Commitments and contingencies
Capitalization
Long-term debt		14,520	14,195
Common stock — 1,000,000,000 shares authorized of $2.50 par value; 507,762,881 and 507,222,795 shares outstanding at Dec. 31, 2017 and 2016, respectively		1,269	1,268
Additional paid in capital		5,898	5,881
Retained earnings		4,413	3,982
Accumulated other comprehensive loss		(125)	(110)
Total common stockholders’ equity		11,455	11,021
Total liabilities and equity		$ 43,030	$ 41,155
[1]	Revenue subject to refund of $15 million and $46 million for 2017 and 2016, respectively, is included in other current liabilities.

CONSOLIDATED BALANCE SHEETS (Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) - $ / shares	Dec. 31, 2017	Jun. 30, 2017	Dec. 31, 2016
Capitalization
Common stock, shares authorized (in shares)	1,000,000,000		1,000,000,000
Common stock, par value (in dollars per share)	$ 2.50		$ 2.50
Common stock, shares outstanding (in shares)	507,762,881	507,952,795	507,222,795

CONSOLIDATED STATEMENTS OF COMM

CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS' EQUITY - USD ($) $ in Millions	Total	Common stock	Additional Paid In Capital	Retained Earnings	Accumulated Other Comprehensive Loss
Beginning balance at Dec. 31, 2014	$ 10,214	$ 1,264	$ 5,837	$ 3,221	$ (108)
Balance (in shares) at Dec. 31, 2014		505,733,000
Increase (Decrease) in Stockholders' Equity
Net income	984			984
Other comprehensive income (loss)	(2)				(2)
Dividends declared on common stock	(652)			(652)
Issuances of common stock (in shares)		1,803,000
Issuances of common stock	33	$ 5	28
Share-based compensation	24		24
Ending balance at Dec. 31, 2015	10,601	$ 1,269	5,889	3,553	(110)
Balance (in shares) at Dec. 31, 2015		507,536,000
Increase (Decrease) in Stockholders' Equity
Net income	1,123			1,123
Other comprehensive income (loss)	0
Dividends declared on common stock	(694)			(694)
Issuances of common stock (in shares)		486,000
Issuances of common stock	16	$ 1	15
Stock Repurchased During Period, Shares		799,000
Repurchases of common stock	(32)	$ (2)	(30)
Share-based compensation	7		7
Ending balance at Dec. 31, 2016	$ 11,021	$ 1,268	5,881	3,982	(110)
Balance (in shares) at Dec. 31, 2016	507,222,795	507,223,000
Increase (Decrease) in Stockholders' Equity
Net income	$ 1,148			1,148
Other comprehensive income (loss)	7				7
Dividends declared on common stock	(736)			(736)
Issuances of common stock (in shares)		611,000
Issuances of common stock	$ 5	$ 1	4
Stock Repurchased During Period, Shares	100,000
Repurchases of common stock (in shares)		(71,000)
Repurchases of common stock	$ (3)	$ 0	(3)
Share-based compensation	13		16	(3)
Adoption of ASU No. 2018-02	0			22	(22)	[1]
Ending balance at Dec. 31, 2017	$ 11,455	$ 1,269	$ 5,898	$ 4,413	$ (125)
Balance (in shares) at Dec. 31, 2017	507,762,881	507,763,000
[1]	(a) In 2017, Xcel Energy implemented ASU No. 2018-02 related to the TCJA, which resulted in reclassification of certain credit balances within net accumulated other comprehensive loss to retained earnings. For further information, see Note 2.

CONSOLIDATED STATEMENTS OF CAPI

CONSOLIDATED STATEMENTS OF CAPITALIZATION - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Schedule of Capitalization, Long-term Debt [Line Items]
Less current maturities	$ 457	$ 255
Long-term debt, noncurrent	14,520	14,195
Common Stockholders' Equity
Common stock — 1,000,000,000 shares authorized of $2.50 par value; 507,762,881 and 507,222,795 shares outstanding at Dec. 31, 2017 and 2016, respectively	1,269	1,268
Additional paid in capital	5,898	5,881
Retained earnings	4,413	3,982
Accumulated other comprehensive loss	(125)	(110)
Total common stockholders’ equity	11,455	11,021
Other Subsidiaries
Schedule of Capitalization, Long-term Debt [Line Items]
Less current maturities	2	1
Long-term debt, noncurrent	26	30
Other Subsidiaries | Various Eloigne Co. Affordable Housing Project Notes | Due 2018-2052
Schedule of Capitalization, Long-term Debt [Line Items]
Long-term Debt, Gross	28	31
Xcel Energy Inc.
Schedule of Capitalization, Long-term Debt [Line Items]
Unamortized discount	(2)	(2)
Unamortized debt expense	(20)	(23)
Total long-term debt	2,816	3,061
Less current maturities	0	250
Less current maturities	(2)	248
Long-term debt, noncurrent	2,878	2,875
Long-term debt, noncurrent	2,818	2,813
Common Stockholders' Equity
Total common stockholders’ equity	11,455	11,021
Xcel Energy Inc. | Senior Unsecured Notes | Series Due June 1, 2017
Schedule of Capitalization, Long-term Debt [Line Items]
Long-term Debt, Gross	0	250
Xcel Energy Inc. | Senior Unsecured Notes | Series Due May 15, 2020
Schedule of Capitalization, Long-term Debt [Line Items]
Long-term Debt, Gross	550	550
Xcel Energy Inc. | Senior Unsecured Notes | Series Due March 15, 2021
Schedule of Capitalization, Long-term Debt [Line Items]
Long-term Debt, Gross	400	400
Xcel Energy Inc. | Senior Unsecured Notes | Series Due March 15, 2022
Schedule of Capitalization, Long-term Debt [Line Items]
Long-term Debt, Gross	300	300
Xcel Energy Inc. | Senior Unsecured Notes | Series Due June 1, 2025
Schedule of Capitalization, Long-term Debt [Line Items]
Long-term Debt, Gross	600	600
Xcel Energy Inc. | Senior Unsecured Notes | Series Due Dec. 1, 2026
Schedule of Capitalization, Long-term Debt [Line Items]
Long-term Debt, Gross	500	500
Xcel Energy Inc. | Senior Unsecured Notes | Series Due July 1, 2036
Schedule of Capitalization, Long-term Debt [Line Items]
Long-term Debt, Gross	300	300
Xcel Energy Inc. | Senior Unsecured Notes | Series Due Sept. 15, 2041
Schedule of Capitalization, Long-term Debt [Line Items]
Long-term Debt, Gross	250	250
Xcel Energy Inc. | Capital Lease Obligations
Schedule of Capitalization, Long-term Debt [Line Items]
Capital Lease Obligations	(62)	(64)
NSP-Minnesota
Schedule of Capitalization, Long-term Debt [Line Items]
Unamortized discount	(22)	(17)
Unamortized debt expense	(45)	(40)
Long-term debt, noncurrent	4,933	4,843
NSP-Minnesota | First Mortgage Bonds | Series Due March 1, 2018
Schedule of Capitalization, Long-term Debt [Line Items]
Long-term Debt, Gross	0	500
NSP-Minnesota | First Mortgage Bonds | Series Due Aug. 15, 2020
Schedule of Capitalization, Long-term Debt [Line Items]
Long-term Debt, Gross	300	300
NSP-Minnesota | First Mortgage Bonds | Series Due Aug. 15, 2022
Schedule of Capitalization, Long-term Debt [Line Items]
Long-term Debt, Gross	300	300
NSP-Minnesota | First Mortgage Bonds | Series Due May 15, 2023
Schedule of Capitalization, Long-term Debt [Line Items]
Long-term Debt, Gross	400	400
NSP-Minnesota | First Mortgage Bonds | Series Due July 1, 2025
Schedule of Capitalization, Long-term Debt [Line Items]
Long-term Debt, Gross	250	250
NSP-Minnesota | First Mortgage Bonds | Series Due March 1, 2028
Schedule of Capitalization, Long-term Debt [Line Items]
Long-term Debt, Gross	150	150
NSP-Minnesota | First Mortgage Bonds | Series Due July 15, 2035
Schedule of Capitalization, Long-term Debt [Line Items]
Long-term Debt, Gross	250	250
NSP-Minnesota | First Mortgage Bonds | Series Due June 1, 2036
Schedule of Capitalization, Long-term Debt [Line Items]
Long-term Debt, Gross	400	400
NSP-Minnesota | First Mortgage Bonds | Series Due July 1, 2037
Schedule of Capitalization, Long-term Debt [Line Items]
Long-term Debt, Gross	350	350
NSP-Minnesota | First Mortgage Bonds | Series Due Nov. 1, 2039
Schedule of Capitalization, Long-term Debt [Line Items]
Long-term Debt, Gross	300	300
NSP-Minnesota | First Mortgage Bonds | Series Due Aug. 15, 2040
Schedule of Capitalization, Long-term Debt [Line Items]
Long-term Debt, Gross	250	250
NSP-Minnesota | First Mortgage Bonds | Series Due Aug. 15, 2042
Schedule of Capitalization, Long-term Debt [Line Items]
Long-term Debt, Gross	500	500
NSP-Minnesota | First Mortgage Bonds | Series Due May 15, 2044
Schedule of Capitalization, Long-term Debt [Line Items]
Long-term Debt, Gross	300	300
NSP-Minnesota | First Mortgage Bonds | Series Due Aug. 15, 2045
Schedule of Capitalization, Long-term Debt [Line Items]
Long-term Debt, Gross	300	300
NSP-Minnesota | First Mortgage Bonds | Series Due May 15, 2046
Schedule of Capitalization, Long-term Debt [Line Items]
Long-term Debt, Gross	350	350
NSP-Minnesota | First Mortgage Bonds | Series Due Sept. 15, 2047
Schedule of Capitalization, Long-term Debt [Line Items]
Long-term Debt, Gross	600	0
PSCo
Schedule of Capitalization, Long-term Debt [Line Items]
Unamortized discount	(13)	(13)
Unamortized debt expense	(29)	(27)
Total long-term debt	4,609	4,216
Less current maturities	306	5
Long-term debt, noncurrent	4,303	4,211
PSCo | First Mortgage Bonds | Series Due Aug. 1, 2018
Schedule of Capitalization, Long-term Debt [Line Items]
Long-term Debt, Gross	300	300
PSCo | First Mortgage Bonds | Series Due June 1, 2019
Schedule of Capitalization, Long-term Debt [Line Items]
Long-term Debt, Gross	400	400
PSCo | First Mortgage Bonds | Series Due Nov. 15, 2020
Schedule of Capitalization, Long-term Debt [Line Items]
Long-term Debt, Gross	400	400
PSCo | First Mortgage Bonds | Series Due Sept. 15, 2022
Schedule of Capitalization, Long-term Debt [Line Items]
Long-term Debt, Gross	300	300
PSCo | First Mortgage Bonds | Series Due March 15, 2023
Schedule of Capitalization, Long-term Debt [Line Items]
Long-term Debt, Gross	250	250
PSCo | First Mortgage Bonds | Series Due May 15, 2025
Schedule of Capitalization, Long-term Debt [Line Items]
Long-term Debt, Gross	250	250
PSCo | First Mortgage Bonds | Series Due Sept. 1, 2037
Schedule of Capitalization, Long-term Debt [Line Items]
Long-term Debt, Gross	350	350
PSCo | First Mortgage Bonds | Series Due Aug. 1, 2038
Schedule of Capitalization, Long-term Debt [Line Items]
Long-term Debt, Gross	300	300
PSCo | First Mortgage Bonds | Series Due Aug. 15, 2041
Schedule of Capitalization, Long-term Debt [Line Items]
Long-term Debt, Gross	250	250
PSCo | First Mortgage Bonds | Series Due Sept. 15, 2042
Schedule of Capitalization, Long-term Debt [Line Items]
Long-term Debt, Gross	500	500
PSCo | First Mortgage Bonds | Series Due March 15, 2043
Schedule of Capitalization, Long-term Debt [Line Items]
Long-term Debt, Gross	250	250
PSCo | First Mortgage Bonds | Series Due March 15, 2044
Schedule of Capitalization, Long-term Debt [Line Items]
Long-term Debt, Gross	300	300
PSCo | First Mortgage Bonds | Series Due June 15, 2046
Schedule of Capitalization, Long-term Debt [Line Items]
Long-term Debt, Gross	250	250
PSCo | First Mortgage Bonds | Series Due June 15, 2047
Schedule of Capitalization, Long-term Debt [Line Items]
Long-term Debt, Gross	400	0
PSCo | Capital Lease Obligations
Schedule of Capitalization, Long-term Debt [Line Items]
Capital Lease Obligations	151	156
SPS
Schedule of Capitalization, Long-term Debt [Line Items]
Unamortized discount	(2)	0
Unamortized debt expense	(18)	(14)
Long-term debt, noncurrent	1,830	1,636
SPS | First Mortgage Bonds | Series Due Aug. 15, 2041
Schedule of Capitalization, Long-term Debt [Line Items]
Long-term Debt, Gross	400	400
SPS | First Mortgage Bonds | Series Due June 15, 2024
Schedule of Capitalization, Long-term Debt [Line Items]
Long-term Debt, Gross	350	350
SPS | First Mortgage Bonds | Series Due Aug. 15, 2046
Schedule of Capitalization, Long-term Debt [Line Items]
Long-term Debt, Gross	300	300
SPS | First Mortgage Bonds | Series Due Aug. 15, 2047
Schedule of Capitalization, Long-term Debt [Line Items]
Long-term Debt, Gross	450	0
SPS | Senior Unsecured Notes | Senior G Due Dec. 1, 2018
Schedule of Capitalization, Long-term Debt [Line Items]
Long-term Debt, Gross	0	250
SPS | Senior Unsecured Notes | Senior C and D Due Oct. 1, 2033
Schedule of Capitalization, Long-term Debt [Line Items]
Long-term Debt, Gross	100	100
SPS | Senior Unsecured Notes | Senior F Due Oct. 1, 2036
Schedule of Capitalization, Long-term Debt [Line Items]
Long-term Debt, Gross	250	250
NSP-Wisconsin
Schedule of Capitalization, Long-term Debt [Line Items]
Unamortized discount	(3)	(3)
Unamortized debt expense	(7)	(5)
Long-term Debt	761	663
Less current maturities	151	1
Long-term debt, noncurrent	610	662
NSP-Wisconsin | First Mortgage Bonds | Series Due June 15, 2024
Schedule of Capitalization, Long-term Debt [Line Items]
Long-term Debt, Gross	200	200
NSP-Wisconsin | First Mortgage Bonds | Series Due Oct. 1, 2018
Schedule of Capitalization, Long-term Debt [Line Items]
Long-term Debt, Gross	150	150
NSP-Wisconsin | First Mortgage Bonds | Series Due Sept. 1, 2038
Schedule of Capitalization, Long-term Debt [Line Items]
Long-term Debt, Gross	200	200
NSP-Wisconsin | First Mortgage Bonds | Series Due Oct. 1, 2042
Schedule of Capitalization, Long-term Debt [Line Items]
Long-term Debt, Gross	100	100
NSP-Wisconsin | First Mortgage Bonds | Series Due Dec. 1, 2047
Schedule of Capitalization, Long-term Debt [Line Items]
Long-term Debt, Gross	100	0
NSP-Wisconsin | City of La Crosse Resource Recovery Bond | Series Due Nov. 1, 2021
Schedule of Capitalization, Long-term Debt [Line Items]
Long-term Debt, Gross	19	19
NSP-Wisconsin | Other
Schedule of Capitalization, Long-term Debt [Line Items]
Long-term Debt, Gross	$ 2	$ 2

CONSOLIDATED STATEMENTS OF CA11

CONSOLIDATED STATEMENTS OF CAPITALIZATION (Parenthetical) - $ / shares		12 Months Ended
		Dec. 31, 2017	Dec. 31, 2016
Common Stockholders' Equity
Common stock, shares authorized (in shares)		1,000,000,000	1,000,000,000
Common stock, par value (in dollars per share)		$ 2.50	$ 2.50
Common stock, shares outstanding (in shares)		507,762,881	507,222,795
Other Subsidiaries | Various Eloigne Co. Affordable Housing Project Notes | Due 2018-2052
Schedule of Capitalization, Long-term Debt [Line Items]
Debt Instrument, Maturity Date Range, Start		Jan. 1, 2018
Debt Instrument, Maturity Date Range, End		Dec. 31, 2052
Other Subsidiaries | Various Eloigne Co. Affordable Housing Project Notes | Due 2018-2052 | Minimum
Schedule of Capitalization, Long-term Debt [Line Items]
Debt instrument, interest rate, stated percentage		0.00%
Other Subsidiaries | Various Eloigne Co. Affordable Housing Project Notes | Due 2018-2052 | Maximum
Schedule of Capitalization, Long-term Debt [Line Items]
Debt instrument, interest rate, stated percentage		7.05%
Xcel Energy Inc.
Common Stockholders' Equity
Common stock, shares authorized (in shares)		1,000,000,000
Common stock, shares outstanding (in shares)		507,762,881	507,222,795
Xcel Energy Inc. | Senior Unsecured Notes | Series Due June 1, 2017
Schedule of Capitalization, Long-term Debt [Line Items]
Debt instrument, interest rate, stated percentage		1.20%	1.20%
Debt instrument, maturity date		Jun. 1, 2017	Jun. 1, 2017
Xcel Energy Inc. | Senior Unsecured Notes | Series Due May 15, 2020
Schedule of Capitalization, Long-term Debt [Line Items]
Debt instrument, interest rate, stated percentage		4.70%	4.70%
Debt instrument, maturity date		May 15, 2020	May 15, 2020
Xcel Energy Inc. | Senior Unsecured Notes | Series Due March 15, 2021
Schedule of Capitalization, Long-term Debt [Line Items]
Debt instrument, interest rate, stated percentage		2.40%	2.40%
Debt instrument, maturity date		Mar. 15, 2021	Mar. 15, 2021
Xcel Energy Inc. | Senior Unsecured Notes | Series Due March 15, 2022
Schedule of Capitalization, Long-term Debt [Line Items]
Debt instrument, interest rate, stated percentage		2.60%	2.60%
Debt instrument, maturity date		Mar. 15, 2022	Mar. 15, 2022
Xcel Energy Inc. | Senior Unsecured Notes | Series Due June 1, 2025
Schedule of Capitalization, Long-term Debt [Line Items]
Debt instrument, interest rate, stated percentage		3.30%	3.30%
Debt instrument, maturity date		Jun. 1, 2025	Jun. 1, 2025
Xcel Energy Inc. | Senior Unsecured Notes | Series Due Dec. 1, 2026
Schedule of Capitalization, Long-term Debt [Line Items]
Debt instrument, interest rate, stated percentage		3.35%	3.35%
Debt instrument, maturity date		Dec. 1, 2026	Dec. 1, 2026
Xcel Energy Inc. | Senior Unsecured Notes | Series Due July 1, 2036
Schedule of Capitalization, Long-term Debt [Line Items]
Debt instrument, interest rate, stated percentage		6.50%	6.50%
Debt instrument, maturity date		Jul. 1, 2036	Jul. 1, 2036
Xcel Energy Inc. | Senior Unsecured Notes | Series Due Sept. 15, 2041
Schedule of Capitalization, Long-term Debt [Line Items]
Debt instrument, interest rate, stated percentage		4.80%	4.80%
Debt instrument, maturity date		Sep. 15, 2041	Sep. 15, 2041
NSP-Minnesota | First Mortgage Bonds | Series Due March 1, 2018
Schedule of Capitalization, Long-term Debt [Line Items]
Debt instrument, interest rate, stated percentage		5.25%	5.25%
Debt instrument, maturity date		Mar. 1, 2018	Mar. 1, 2018
NSP-Minnesota | First Mortgage Bonds | Series Due Sept. 15, 2047
Schedule of Capitalization, Long-term Debt [Line Items]
Debt instrument, interest rate, stated percentage		3.60%
Debt instrument, maturity date		Sep. 15, 2047
NSP-Minnesota | First Mortgage Bonds | Series Due Aug. 15, 2020
Schedule of Capitalization, Long-term Debt [Line Items]
Debt instrument, interest rate, stated percentage		2.20%	2.20%
Debt instrument, maturity date		Aug. 15, 2020	Aug. 15, 2020
NSP-Minnesota | First Mortgage Bonds | Series Due Aug. 15, 2022
Schedule of Capitalization, Long-term Debt [Line Items]
Debt instrument, interest rate, stated percentage		2.15%	2.15%
Debt instrument, maturity date		Aug. 15, 2022	Aug. 15, 2022
NSP-Minnesota | First Mortgage Bonds | Series Due May 15, 2023
Schedule of Capitalization, Long-term Debt [Line Items]
Debt instrument, interest rate, stated percentage		2.60%	2.60%
Debt instrument, maturity date		May 15, 2023	May 15, 2023
NSP-Minnesota | First Mortgage Bonds | Series Due July 1, 2025
Schedule of Capitalization, Long-term Debt [Line Items]
Debt instrument, interest rate, stated percentage		7.125%	7.125%
Debt instrument, maturity date		Jul. 1, 2025	Jul. 1, 2025
NSP-Minnesota | First Mortgage Bonds | Series Due March 1, 2028
Schedule of Capitalization, Long-term Debt [Line Items]
Debt instrument, interest rate, stated percentage		6.50%	6.50%
Debt instrument, maturity date		Mar. 1, 2028	Mar. 1, 2028
NSP-Minnesota | First Mortgage Bonds | Series Due July 15, 2035
Schedule of Capitalization, Long-term Debt [Line Items]
Debt instrument, interest rate, stated percentage		5.25%	5.25%
Debt instrument, maturity date		Jul. 15, 2035	Jul. 15, 2035
NSP-Minnesota | First Mortgage Bonds | Series Due June 1, 2036
Schedule of Capitalization, Long-term Debt [Line Items]
Debt instrument, interest rate, stated percentage		6.25%	6.25%
Debt instrument, maturity date		Jun. 1, 2036	Jun. 1, 2036
NSP-Minnesota | First Mortgage Bonds | Series Due July 1, 2037
Schedule of Capitalization, Long-term Debt [Line Items]
Debt instrument, interest rate, stated percentage		6.20%	6.20%
Debt instrument, maturity date		Jul. 1, 2037	Jul. 1, 2037
NSP-Minnesota | First Mortgage Bonds | Series Due Nov. 1, 2039
Schedule of Capitalization, Long-term Debt [Line Items]
Debt instrument, interest rate, stated percentage		5.35%	5.35%
Debt instrument, maturity date		Nov. 1, 2039	Nov. 1, 2039
NSP-Minnesota | First Mortgage Bonds | Series Due Aug. 15, 2040
Schedule of Capitalization, Long-term Debt [Line Items]
Debt instrument, interest rate, stated percentage		4.85%	4.85%
Debt instrument, maturity date		Aug. 15, 2040	Aug. 15, 2040
NSP-Minnesota | First Mortgage Bonds | Series Due Aug. 15, 2042
Schedule of Capitalization, Long-term Debt [Line Items]
Debt instrument, interest rate, stated percentage		3.40%	3.40%
Debt instrument, maturity date		Aug. 15, 2042	Aug. 15, 2042
NSP-Minnesota | First Mortgage Bonds | Series Due May 15, 2044
Schedule of Capitalization, Long-term Debt [Line Items]
Debt instrument, interest rate, stated percentage		4.125%	4.125%
Debt instrument, maturity date		May 15, 2044	May 15, 2044
NSP-Minnesota | First Mortgage Bonds | Series Due Aug. 15, 2045
Schedule of Capitalization, Long-term Debt [Line Items]
Debt instrument, interest rate, stated percentage		4.00%	4.00%
Debt instrument, maturity date		Aug. 15, 2045	Aug. 15, 2045
NSP-Minnesota | First Mortgage Bonds | Series Due May 15, 2046
Schedule of Capitalization, Long-term Debt [Line Items]
Debt instrument, interest rate, stated percentage		3.60%	3.60%
Debt instrument, maturity date		May 15, 2046	May 15, 2046
PSCo | First Mortgage Bonds | Series Due Aug. 1, 2018
Schedule of Capitalization, Long-term Debt [Line Items]
Debt instrument, interest rate, stated percentage		5.80%	5.80%
Debt instrument, maturity date		Aug. 1, 2018	Aug. 1, 2018
PSCo | First Mortgage Bonds | Series Due June 1, 2019
Schedule of Capitalization, Long-term Debt [Line Items]
Debt instrument, interest rate, stated percentage		5.125%	5.125%
Debt instrument, maturity date		Jun. 1, 2019	Jun. 1, 2019
PSCo | First Mortgage Bonds | Series Due Nov. 15, 2020
Schedule of Capitalization, Long-term Debt [Line Items]
Debt instrument, interest rate, stated percentage		3.20%	3.20%
Debt instrument, maturity date		Nov. 15, 2020	Nov. 15, 2020
PSCo | First Mortgage Bonds | Series Due Sept. 15, 2022
Schedule of Capitalization, Long-term Debt [Line Items]
Debt instrument, interest rate, stated percentage		2.25%	2.25%
Debt instrument, maturity date		Sep. 15, 2022	Sep. 15, 2022
PSCo | First Mortgage Bonds | Series Due March 15, 2023
Schedule of Capitalization, Long-term Debt [Line Items]
Debt instrument, interest rate, stated percentage		2.50%	2.50%
Debt instrument, maturity date		Mar. 15, 2023	Mar. 15, 2023
PSCo | First Mortgage Bonds | Series Due May 15, 2025
Schedule of Capitalization, Long-term Debt [Line Items]
Debt instrument, interest rate, stated percentage		2.90%	2.90%
Debt instrument, maturity date		May 15, 2025	May 15, 2025
PSCo | First Mortgage Bonds | Series Due Sept. 1, 2037
Schedule of Capitalization, Long-term Debt [Line Items]
Debt instrument, interest rate, stated percentage		6.25%	6.25%
Debt instrument, maturity date		Sep. 1, 2037	Sep. 1, 2037
PSCo | First Mortgage Bonds | Series Due Aug. 1, 2038
Schedule of Capitalization, Long-term Debt [Line Items]
Debt instrument, interest rate, stated percentage		6.50%	6.50%
Debt instrument, maturity date		Aug. 1, 2038	Aug. 1, 2038
PSCo | First Mortgage Bonds | Series Due Aug. 15, 2041
Schedule of Capitalization, Long-term Debt [Line Items]
Debt instrument, interest rate, stated percentage		4.75%	4.75%
Debt instrument, maturity date		Aug. 15, 2041	Aug. 15, 2041
PSCo | First Mortgage Bonds | Series Due Sept. 15, 2042
Schedule of Capitalization, Long-term Debt [Line Items]
Debt instrument, interest rate, stated percentage		3.60%	3.60%
Debt instrument, maturity date		Sep. 15, 2042	Sep. 15, 2042
PSCo | First Mortgage Bonds | Series Due March 15, 2043
Schedule of Capitalization, Long-term Debt [Line Items]
Debt instrument, interest rate, stated percentage		3.95%	3.95%
Debt instrument, maturity date		Mar. 15, 2043	Mar. 15, 2043
PSCo | First Mortgage Bonds | Series Due March 15, 2044
Schedule of Capitalization, Long-term Debt [Line Items]
Debt instrument, interest rate, stated percentage		4.30%	4.30%
Debt instrument, maturity date		Mar. 15, 2044	Mar. 15, 2044
PSCo | First Mortgage Bonds | Series Due June 15, 2046
Schedule of Capitalization, Long-term Debt [Line Items]
Debt instrument, interest rate, stated percentage		3.55%	3.55%
Debt instrument, maturity date		Jun. 15, 2046	Jun. 15, 2046
PSCo | First Mortgage Bonds | Series Due June 15, 2047
Schedule of Capitalization, Long-term Debt [Line Items]
Debt instrument, interest rate, stated percentage		3.80%
Debt instrument, maturity date		Jun. 15, 2047
PSCo | Capital Lease Obligations
Schedule of Capitalization, Long-term Debt [Line Items]
Debt Instrument, Maturity Date Range, End		Dec. 31, 2060
PSCo | Capital Lease Obligations | Minimum
Schedule of Capitalization, Long-term Debt [Line Items]
Debt instrument, interest rate, stated percentage		11.20%
PSCo | Capital Lease Obligations | Maximum
Schedule of Capitalization, Long-term Debt [Line Items]
Debt instrument, interest rate, stated percentage		14.30%
SPS | First Mortgage Bonds | Series Due Aug. 15, 2041
Schedule of Capitalization, Long-term Debt [Line Items]
Debt instrument, interest rate, stated percentage		4.50%	4.50%
Debt instrument, maturity date		Aug. 15, 2041	Aug. 15, 2041
SPS | First Mortgage Bonds | Series Due June 15, 2024
Schedule of Capitalization, Long-term Debt [Line Items]
Debt instrument, interest rate, stated percentage		3.30%	3.30%
Debt instrument, maturity date		Jun. 15, 2024	Jun. 15, 2024
SPS | First Mortgage Bonds | Series Due Aug. 15, 2046
Schedule of Capitalization, Long-term Debt [Line Items]
Debt instrument, interest rate, stated percentage		3.40%	3.40%
Debt instrument, maturity date		Aug. 15, 2046	Aug. 15, 2046
SPS | First Mortgage Bonds | Series Due Aug. 15, 2047
Schedule of Capitalization, Long-term Debt [Line Items]
Debt instrument, interest rate, stated percentage		3.70%
Debt instrument, maturity date		Aug. 15, 2047
SPS | Senior Unsecured Notes | Senior G Due Dec. 1, 2018
Schedule of Capitalization, Long-term Debt [Line Items]
Debt instrument, interest rate, stated percentage		8.75%	8.75%
Debt instrument, maturity date		Dec. 1, 2018	Dec. 1, 2018
SPS | Senior Unsecured Notes | Senior C and D Due Oct. 1, 2033
Schedule of Capitalization, Long-term Debt [Line Items]
Debt instrument, interest rate, stated percentage		6.00%	6.00%
Debt instrument, maturity date		Oct. 1, 2033	Oct. 1, 2033
SPS | Senior Unsecured Notes | Senior F Due Oct. 1, 2036
Schedule of Capitalization, Long-term Debt [Line Items]
Debt instrument, interest rate, stated percentage		6.00%	6.00%
Debt instrument, maturity date		Oct. 1, 2036	Oct. 1, 2036
NSP-Wisconsin | First Mortgage Bonds | Series Due Oct. 1, 2018
Schedule of Capitalization, Long-term Debt [Line Items]
Debt instrument, interest rate, stated percentage		5.25%	5.25%
Debt instrument, maturity date		Oct. 1, 2018	Oct. 1, 2018
NSP-Wisconsin | First Mortgage Bonds | Series Due June 15, 2024
Schedule of Capitalization, Long-term Debt [Line Items]
Debt instrument, interest rate, stated percentage		3.30%	3.30%
Debt instrument, maturity date		Jun. 15, 2024	Jun. 15, 2024
NSP-Wisconsin | First Mortgage Bonds | Series Due Sept. 1, 2038
Schedule of Capitalization, Long-term Debt [Line Items]
Debt instrument, interest rate, stated percentage		6.375%	6.375%
Debt instrument, maturity date		Sep. 1, 2038	Sep. 1, 2038
NSP-Wisconsin | First Mortgage Bonds | Series Due Oct. 1, 2042
Schedule of Capitalization, Long-term Debt [Line Items]
Debt instrument, interest rate, stated percentage		3.70%	3.70%
Debt instrument, maturity date		Oct. 1, 2042	Oct. 1, 2042
NSP-Wisconsin | First Mortgage Bonds | Series Due Dec. 1, 2047
Schedule of Capitalization, Long-term Debt [Line Items]
Debt instrument, interest rate, stated percentage		3.75%
Debt instrument, maturity date		Dec. 1, 2047
NSP-Wisconsin | City of La Crosse Resource Recovery Bond | Series Due Nov. 1, 2021
Schedule of Capitalization, Long-term Debt [Line Items]
Debt instrument, interest rate, stated percentage	[1]	6.00%	6.00%
Debt instrument, maturity date	[1]	Nov. 1, 2021	Nov. 1, 2021
[1]	Resource recovery financing.

Summary of Significant Accounti

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2017
Accounting Policies [Abstract]
Summary of Significant Accounting Policies	Summary of Significant Accounting Policies Business and System of Accounts — Xcel Energy Inc.’s utility subsidiaries are engaged in the regulated generation, purchase, transmission, distribution and sale of electricity and in the regulated purchase, transportation, distribution and sale of natural gas. Xcel Energy’s consolidated financial statements and disclosures are presented in accordance with GAAP. All of the utility subsidiaries’ underlying accounting records also conform to the FERC uniform system of accounts or to systems required by various state regulatory commissions, which are the same in all material respects. Principles of Consolidation — In 2017, Xcel Energy’s operations included the activity of NSP-Minnesota, NSP-Wisconsin, PSCo and SPS. These utility subsidiaries serve electric and natural gas customers in portions of Colorado, Michigan, Minnesota, New Mexico, North Dakota, South Dakota, Texas and Wisconsin. Also included in Xcel Energy’s operations are WGI, an interstate natural gas pipeline company, and WYCO, a joint venture with CIG to develop and lease natural gas pipelines, storage and compression facilities. Xcel Energy Inc.’s nonregulated subsidiaries include Eloigne and Capital Services. Eloigne invests in rental housing projects that qualify for low-income housing tax credits. Capital Services procures equipment for construction of renewable generation facilities at other subsidiaries. Xcel Energy Inc. owns the following additional direct subsidiaries, some of which are intermediate holding companies with additional subsidiaries: Xcel Energy Wholesale Group Inc., Xcel Energy Markets Holdings Inc., Xcel Energy Ventures Inc., Xcel Energy Retail Holdings Inc., Xcel Energy Communications Group, Inc., Xcel Energy International Inc., Xcel Energy Transmission Holding Company, LLC, Nicollet Holdings Company, LLC, Nicollet Project Holdings LLC and Xcel Energy Services Inc. Xcel Energy Inc. and its subsidiaries collectively are referred to as Xcel Energy. Xcel Energy’s consolidated financial statements include its wholly-owned subsidiaries and VIEs for which it is the primary beneficiary. In the consolidation process, all intercompany transactions and balances are eliminated. Xcel Energy uses the equity method of accounting for its investment in WYCO. Xcel Energy’s equity earnings in WYCO are included on the consolidated statements of income as equity earnings of unconsolidated subsidiaries. Xcel Energy has investments in several plants and transmission facilities jointly owned with nonaffiliated utilities. Xcel Energy’s proportionate share of jointly owned facilities is recorded as property, plant and equipment on the consolidated balance sheets, and Xcel Energy’s proportionate share of the operating costs associated with these facilities is included in its consolidated statements of income. See Note 5 for further discussion of jointly owned generation, transmission and gas facilities, and related ownership percentages. Xcel Energy evaluates its arrangements and contracts with other entities, including investments, PPAs and fuel contracts, to determine if the other party is a VIE, if Xcel Energy has a variable interest and if Xcel Energy is the primary beneficiary. Xcel Energy follows accounting guidance for VIEs which requires consideration of the activities that most significantly impact an entity’s financial performance and power to direct those activities, when determining whether Xcel Energy is a VIE’s primary beneficiary. See Note 13 for further discussion of VIEs. Use of Estimates — In recording transactions and balances resulting from business operations, Xcel Energy uses estimates based on the best information available. Estimates are used for such items as plant depreciable lives or potential disallowances, AROs, certain regulatory assets and liabilities, tax provisions, uncollectible amounts, environmental costs, unbilled revenues, jurisdictional fuel and energy cost allocations and actuarially determined benefit costs. The recorded estimates are revised when better information becomes available or when actual amounts can be determined. Those revisions can affect operating results. Regulatory Accounting — Our regulated utility subsidiaries account for certain income and expense items in accordance with accounting guidance for regulated operations. Under this guidance: • Certain costs, which would otherwise be charged to expense or OCI, are deferred as regulatory assets based on the expected ability to recover the costs in future rates; and • Certain credits, which would otherwise be reflected as income or OCI, are deferred as regulatory liabilities based on the expectation the amounts will be returned to customers in future rates, or because the amounts were collected in rates prior to the costs being incurred. Estimates of recovering deferred costs and returning deferred credits are based on specific ratemaking decisions or precedent for each item. Regulatory assets and liabilities are amortized consistent with the treatment in the rate setting process. If restructuring or other changes in the regulatory environment occur, regulated utility subsidiaries may no longer be eligible to apply this accounting treatment, and may be required to eliminate regulatory assets and liabilities from their balance sheets. Such changes could have a material effect on Xcel Energy’s financial condition, results of operations and cash flows. See Note 15 for further discussion of regulatory assets and liabilities. Revenue Recognition — Revenues related to the sale of energy are generally recorded when service is rendered or energy is delivered to customers. However, the determination of the energy sales to individual customers is based on the reading of their meter, which occurs on a systematic basis throughout the month. At the end of each month, amounts of energy delivered to customers since the date of the last meter reading are estimated and the corresponding unbilled revenue is recognized. Xcel Energy presents its revenues net of any excise or other fiduciary-type taxes or fees. NSP-Minnesota participates in MISO, and SPS participates in SPP. Xcel Energy’s utility subsidiaries recognize sales to both native load and other end use customers on a gross basis. Revenues and charges for short term wholesale sales of excess energy transacted through RTOs are recorded on a gross basis in electric revenues and cost of sales. Other revenues and charges related to participating and transacting in RTOs are recorded on a net basis in cost of sales. Xcel Energy Inc.’s utility subsidiaries have various rate-adjustment mechanisms in place that provide for the recovery of natural gas, electric fuel and purchased energy costs. These cost-adjustment tariffs may increase or decrease the level of revenue collected from customers and are revised periodically for differences between the total amount collected under the clauses and the costs incurred. When applicable, under governing regulatory commission rate orders, fuel cost over-recoveries (the excess of fuel revenue billed to customers over fuel costs incurred) are deferred as regulatory liabilities and under-recoveries (the excess of fuel costs incurred over fuel revenues billed to customers) are deferred as regulatory assets. Certain rate rider mechanisms qualify as alternative revenue programs under GAAP. These mechanisms arise from costs imposed upon the utility by action of a regulator or legislative body related to an environmental, public safety or other mandate. When certain criteria are met, revenue is recognized equal to the revenue requirement, including return on rate base items, for the qualified mechanisms. The mechanisms are revised periodically for differences between the total amount collected under the riders and the revenue recognized, which may increase or decrease the level of revenue collected from customers. Conservation Programs — Xcel Energy Inc.’s utility subsidiaries have implemented programs in many of their retail jurisdictions to assist customers in reducing peak demand and conserving energy on the electric and natural gas systems. These programs include efficiency and redesign programs, as well as rebates for the purchase of items such as high efficiency lighting. The costs incurred for DSM and CIP programs are deferred if it is probable future revenue will be provided to permit recovery of the incurred cost. Recorded revenues for incentive programs designed for recovery of lost margins and/or conservation performance incentives are limited to amounts expected to be collected within 24 months from the annual period in which they are earned. For PSCo, SPS and NSP-Minnesota, DSM and CIP program costs are recovered through a combination of base rate revenue and rider mechanisms. The revenue billed to customers recovers incurred costs for conservation programs and also incentive amounts that are designed to encourage Xcel Energy’s achievement of energy conservation goals and compensate for related lost sales margin. For these utility subsidiaries, regulatory assets are recognized to reflect the amount of costs or earned incentives that have not yet been collected from customers. NSP-Wisconsin recovers approved conservation program costs in base rate revenue. Property, Plant and Equipment and Depreciation — Property, plant and equipment is stated at original cost. The cost of plant includes direct labor and materials, contracted work, overhead costs and AFUDC. The cost of plant retired is charged to accumulated depreciation and amortization. Amounts recovered in rates for future removal costs are recorded as regulatory liabilities. Significant additions or improvements extending asset lives are capitalized, while repairs and maintenance costs are charged to expense as incurred. Maintenance and replacement of items determined to be less than a unit of property are charged to operating expenses as incurred. Planned major maintenance activities are charged to operating expense unless the cost represents the acquisition of an additional unit of property or the replacement of an existing unit of property. Property, plant and equipment also includes costs associated with property held for future use. The depreciable lives of certain plant assets are reviewed annually and revised, if appropriate. Property, plant and equipment is tested for impairment when it is determined that the carrying value of the assets may not be recoverable. A loss is recognized in the current period if it becomes probable that part of a cost of a plant under construction or recently completed plant will be disallowed for recovery from customers and a reasonable estimate of the disallowance can be made. See Note 12 for a discussion of the loss recognized in 2015 related to the Monticello LCM/EPU project. For investments in property, plant and equipment that are abandoned and not expected to go into service, incurred costs and related deferred tax amounts are compared to the discounted estimated future rate recovery, and a loss is recognized, if necessary. Xcel Energy records depreciation expense related to its plant using the straight-line method over the plant’s useful life. Actuarial life studies are performed and submitted to the state and federal commissions for review. Upon acceptance by the various commissions, the resulting lives and net salvage rates are used to calculate depreciation. Depreciation expense, expressed as a percentage of average depreciable property, was approximately 3.1 , 2.9 , and 2.8 percent for the years ended Dec. 31, 2017, 2016 and 2015, respectively. Leases — Xcel Energy evaluates a variety of contracts for lease classification at inception, including PPAs and rental arrangements for office space, vehicles and equipment. Contracts determined to contain a lease because of per unit pricing that is other than fixed or market price, terms regarding the use of a particular asset, and other factors are evaluated further to determine if the arrangement is a capital lease. See Note 13 for further discussion of leases. AFUDC — AFUDC represents the cost of capital used to finance utility construction activity. AFUDC is computed by applying a composite financing rate to qualified CWIP. The amount of AFUDC capitalized as a utility construction cost is credited to other nonoperating income (for equity capital) and interest charges (for debt capital). AFUDC amounts capitalized are included in Xcel Energy’s rate base for establishing utility service rates. Generally, AFUDC costs are recovered from customers as the related property is depreciated. However, in some cases commissions have approved a more current recovery of the cost of capital associated with large capital projects, resulting in a lower recognition of AFUDC. In other cases, some commissions have allowed an AFUDC calculation greater than the FERC-defined AFUDC rate, resulting in higher recognition of AFUDC. AROs — Xcel Energy Inc.’s utility subsidiaries account for AROs under accounting guidance that requires a liability for the fair value of an ARO to be recognized in the period in which it is incurred if it can be reasonably estimated, with the offsetting associated asset retirement costs capitalized as a long-lived asset. The liability is generally increased over time by applying the effective interest method of accretion, and the capitalized costs are depreciated over the useful life of the long-lived asset. Changes resulting from revisions to the timing or amount of expected asset retirement cash flows are recognized as an increase or a decrease in the ARO. Xcel Energy Inc.’s utility subsidiaries also recover through rates certain future plant removal costs in addition to AROs. The accumulated removal costs for these obligations are reflected in the balance sheets as a regulatory liability. See Note 13 for further discussion of AROs. Nuclear Decommissioning — Nuclear decommissioning studies estimate NSP-Minnesota’s ultimate costs of decommissioning its nuclear power plants and are performed at least every three years and submitted to the MPUC and other state commissions for approval. NSP-Minnesota’s most recent triennial nuclear decommissioning studies were filed with the MPUC in December 2017. These studies reflect NSP-Minnesota’s plans for dismantlement of the Monticello and PI facilities. These studies assume that NSP-Minnesota will store spent fuel on site pending removal to a U.S. government facility. For rate making purposes, NSP-Minnesota recovers the total decommissioning costs related to its nuclear power plants over each facility’s expected service life based on the triennial decommissioning studies filed with the MPUC and other state commissions. The studies consider estimated future costs of decommissioning and the market value of investments in trust funds, and recommend annual funding amounts. Amounts collected in rates are deposited in the trust funds. See Note 14 for further discussion of the approved nuclear decommissioning studies and funded amounts. For financial reporting purposes, NSP-Minnesota accounts for nuclear decommissioning as an ARO as described above. Restricted funds for the payment of future decommissioning expenditures for NSP-Minnesota’s nuclear facilities are included in nuclear decommissioning fund and other assets on the consolidated balance sheets. See Note 11 for further discussion of the nuclear decommissioning fund. Nuclear Fuel Expense — Nuclear fuel expense, which is recorded as NSP-Minnesota’s nuclear generating plants use fuel, includes the cost of fuel used in the current period (including AFUDC) and costs associated with the end-of-life fuel segments. Nuclear Refueling Outage Costs — Xcel Energy uses a deferral and amortization method for nuclear refueling O&M costs. This method amortizes refueling outage costs over the period between refueling outages consistent with how the costs are recovered ratably in electric rates. Income Taxes — Xcel Energy accounts for income taxes using the asset and liability method, which requires the recognition of deferred tax assets and liabilities for the expected future tax consequences of events that have been included in the financial statements. Xcel Energy defers income taxes for all temporary differences between pretax financial and taxable income, and between the book and tax bases of assets and liabilities. Xcel Energy uses the tax rates that are scheduled to be in effect when the temporary differences are expected to reverse. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in the period that includes the enactment date. The effects of tax rate changes that are attributable to the regulated utility subsidiaries are generally subject to a normalization method of accounting. Therefore, the revaluation of most of the utility subsidiaries’ net deferred taxes upon a tax rate reduction results in the establishment of a net regulatory liability which will be refundable to utility customers over the remaining life of the related assets. A tax rate increase would result in the establishment of a similar regulatory asset. Due to the effects of past regulatory practices, when deferred taxes were not required to be recorded due to the use of flow through accounting for ratemaking purposes, the reversal of some temporary differences are accounted for as current income tax expense. Tax credits are recorded when earned unless there is a requirement to defer the benefit and amortize it over the book depreciable lives of the related property. The requirement to defer and amortize tax credits only applies to federal ITCs related to public utility property. Utility rate regulation also has resulted in the recognition of certain regulatory assets and liabilities related to income taxes, which are summarized in Note 15. Deferred tax assets are reduced by a valuation allowance if it is more likely than not that some portion or all of the deferred tax asset will not be realized. In making such a determination, all available evidence is considered, including scheduled reversals of deferred tax liabilities, projected future taxable income, tax planning strategies and recent financial operations. Xcel Energy follows the applicable accounting guidance to measure and disclose uncertain tax positions that it has taken or expects to take in its income tax returns. Xcel Energy recognizes a tax position in its consolidated financial statements when it is more likely than not that the position will be sustained upon examination based on the technical merits of the position. Recognition of changes in uncertain tax positions are reflected as a component of income tax. Xcel Energy reports interest and penalties related to income taxes within the other income and interest charges sections in the consolidated statements of income. Xcel Energy Inc. and its subsidiaries file consolidated federal income tax returns as well as combined or separate state income tax returns. Federal income taxes paid by Xcel Energy Inc. are allocated to Xcel Energy Inc.’s subsidiaries based on separate company computations of tax. A similar allocation is made for state income taxes paid by Xcel Energy Inc. in connection with combined state filings. Xcel Energy Inc. also allocates its own income tax benefits to its direct subsidiaries based on the relative positive tax liabilities of the subsidiaries. See Note 6 for further discussion of income taxes. Types of and Accounting for Derivative Instruments — Xcel Energy uses derivative instruments in connection with its interest rate, utility commodity price, vehicle fuel price and commodity trading activities, including forward contracts, futures, swaps and options. All derivative instruments not designated and qualifying for the normal purchases and normal sales exception, as defined by the accounting guidance for derivatives and hedging, are recorded on the consolidated balance sheets at fair value as derivative instruments. This includes certain instruments used to mitigate market risk for the utility operations including transmission in organized markets and all instruments related to the commodity trading operations. The classification of changes in fair value for those derivative instruments is dependent on the designation of a qualifying hedging relationship. Changes in fair value of derivative instruments not designated in a qualifying hedging relationship are reflected in current earnings or as a regulatory asset or liability. The classification as a regulatory asset or liability is based on commission approved regulatory recovery mechanisms. Gains or losses on commodity trading transactions are recorded as a component of electric operating revenues; hedging transactions for vehicle fuel costs are recorded as a component of capital projects and O&M costs; and interest rate hedging transactions are recorded as a component of interest expense. Certain utility subsidiaries are allowed to recover in electric or natural gas rates the costs of certain financial instruments purchased to reduce commodity cost volatility. For further information on derivatives entered to mitigate commodity price risk on behalf of electric and natural gas customers, see Note 11. Cash Flow Hedges — Certain qualifying hedging relationships are designated as a hedge of a forecasted transaction, or future cash flow (cash flow hedge). Changes in the fair value of a derivative designated as a cash flow hedge, to the extent effective, are included in OCI or deferred as a regulatory asset or liability based on recovery mechanisms until earnings are affected by the hedged transaction. Normal Purchases and Normal Sales — Xcel Energy enters into contracts for the purchase and sale of commodities for use in its business operations. Derivatives and hedging accounting guidance requires a company to evaluate these contracts to determine whether the contracts are derivatives. Certain contracts that meet the definition of a derivative may be exempted from derivative accounting if designated as normal purchases or normal sales. Xcel Energy evaluates all of its contracts at inception to determine if they are derivatives and if they meet the normal purchases and normal sales designation requirements. None of the contracts entered into within the commodity trading operations qualify for a normal purchases and normal sales designation. See Note 11 for further discussion of Xcel Energy’s risk management and derivative activities. Commodity Trading Operations — All applicable gains and losses related to commodity trading activities, whether or not settled physically, are shown on a net basis in electric operating revenues in the consolidated statements of income. Xcel Energy’s commodity trading operations are primarily conducted by NSP-Minnesota and PSCo. Commodity trading activities are not associated with energy produced from Xcel Energy’s generation assets or energy and capacity purchased to serve native load. Commodity trading contracts are recorded at fair market value and commodity trading results include the impact of all margin-sharing mechanisms. See Note 11 for further discussion. Fair Value Measurements — Xcel Energy presents cash equivalents, interest rate derivatives, commodity derivatives and nuclear decommissioning fund assets at estimated fair values in its consolidated financial statements. Cash equivalents are recorded at cost plus accrued interest; money market funds are measured using quoted NAVs. For interest rate derivatives, quoted prices based primarily on observable market interest rate curves are used as a primary input to establish fair value. For commodity derivatives, the most observable inputs available are generally used to determine the fair value of each contract. In the absence of a quoted price for an identical contract in an active market, Xcel Energy may use quoted prices for similar contracts or internally prepared valuation models to determine fair value. For the pension and postretirement plan assets and the nuclear decommissioning fund, published trading data and pricing models, generally using the most observable inputs available, are utilized to estimate fair value for each security. See Notes 9 and 11 for further discussion. Cash and Cash Equivalents — Xcel Energy considers investments in certain instruments, including commercial paper and money market funds, with a remaining maturity of three months or less at the time of purchase, to be cash equivalents. Accounts Receivable and Allowance for Bad Debts — Accounts receivable are stated at the actual billed amount net of an allowance for bad debts. Xcel Energy establishes an allowance for uncollectible receivables based on a policy that reflects its expected exposure to the credit risk of customers. Inventory — All inventory is recorded at average cost. RECs — RECs are marketable environmental instruments that represent proof that energy was generated from eligible renewable energy sources. RECs are awarded upon delivery of the associated energy and can be bought and sold. RECs are typically used as a form of measurement of compliance to RPS enacted by those states that are encouraging construction and consumption from renewable energy sources, but can also be sold separately from the energy produced. Utility subsidiaries acquire RECs from the generation or purchase of renewable power. When RECs are purchased or acquired in the course of generation they are recorded as inventory at cost. The cost of RECs that are utilized for compliance purposes is recorded as electric fuel and purchased power expense. In certain jurisdictions, as a result of state regulatory orders, Xcel Energy reduces recoverable fuel costs for the cost of certain RECs and records that cost as a regulatory asset when the amount is recoverable in future rates. Sales of RECs that are purchased or acquired in the course of generation are recorded in electric utility operating revenues on a gross basis. The cost of these RECs, related transaction costs, and amounts credited to customers under margin-sharing mechanisms are recorded in electric fuel and purchased power expense. Emission Allowances — Emission allowances, including the annual SO 2 and NOx emission allowance entitlement received from the EPA, are recorded at cost plus associated broker commission fees. Xcel Energy follows the inventory accounting model for all emission allowances. Sales of emission allowances are included in electric utility operating revenue and the operating activities section of the consolidated statements of cash flows. Environmental Costs — Environmental costs are recorded when it is probable Xcel Energy is liable for remediation costs and the liability can be reasonably estimated. Costs are deferred as a regulatory asset if it is probable that the costs will be recovered from customers in future rates. Otherwise, the costs are expensed. If an environmental expense is related to facilities currently in use, such as emission-control equipment, the cost is capitalized and depreciated over the life of the plant. Estimated remediation costs, excluding inflationary increases, are recorded based on experience, an assessment of the current situation and the technology currently available for use in the remediation. The recorded costs are regularly adjusted as estimates are revised and remediation proceeds. If other participating PRPs exist and acknowledge their potential involvement with a site, costs are estimated and recorded only for Xcel Energy’s expected share of the cost. Any future costs of restoring sites where operation may extend indefinitely are treated as a capitalized cost of plant retirement. The depreciation expense levels recoverable in rates include a provision for removal expenses, which may include final remediation costs. Removal costs recovered in rates before the related costs are incurred are classified as a regulatory liability. See Note 13 for further discussion of environmental costs. Benefit Plans and Other Postretirement Benefits — Xcel Energy maintains pension and postretirement benefit plans for eligible employees. Recognizing the cost of providing benefits and measuring the projected benefit obligation of these plans under applicable accounting guidance requires management to make various assumptions and estimates. Based on the regulatory recovery mechanisms of Xcel Energy Inc.’s utility subsidiaries, certain unrecognized actuarial gains and losses and unrecognized prior service costs or credits are recorded as regulatory assets and liabilities, rather than OCI. See Note 9 for further discussion of benefit plans and other postretirement benefits. Guarantees — Xcel Energy recognizes, upon issuance or modification of a guarantee, a liability for the fair market value of the obligation that has been assumed in issuing the guarantee. This liability includes consideration of specific triggering events and other conditions which may modify the ongoing obligation to perform under the guarantee. The obligation recognized is reduced over the term of the guarantee as Xcel Energy is released from risk under the guarantee. See Note 13 for specific details of issued guarantees. Subsequent Events — Management has evaluated the impact of events occurring after Dec. 31, 2017 up to the date of issuance of these consolidated financial statements. These statements contain all necessary adjustments and disclosures resulting from that evaluation.

Accounting Pronouncements

Accounting Pronouncements	12 Months Ended
	Dec. 31, 2017
New Accounting Pronouncements and Changes in Accounting Principles [Abstract]
Accounting Pronouncements	Accounting Pronouncements Recently Issued Revenue Recognition — In May 2014, the FASB issued Revenue from Contracts with Customers, Topic 606 (ASU No. 2014-09) , which provides a new framework for the recognition of revenue. As the appropriate timing of recognition of revenue from contracts with customers in our regulated operations continues to generally be based on the delivery of electricity and natural gas, Xcel Energy’s adoption will primarily result in increased disclosures regarding sources of revenues, including alternative revenue programs. The guidance is effective for interim and annual periods beginning after Dec. 15, 2017. Xcel Energy is implementing the standard on a modified retrospective basis, which requires application to contracts with customers effective Jan. 1, 2018. Classification and Measurement of Financial Instruments — In January 2016, the FASB issued Recognition and Measurement of Financial Assets and Financial Liabilities, Subtopic 825-10 (ASU No. 2016-01) , which eliminates the available-for-sale classification for marketable equity securities and also replaces the cost method of accounting for non-marketable equity securities with a model for recognizing impairments and observable price changes. Under the new standard, other than when the consolidation or equity method of accounting is utilized, changes in the fair value of equity securities are to be recognized in earnings. This guidance is effective for interim and annual reporting periods beginning after Dec. 15, 2017. As a result of application of accounting principles for rate regulated entities, changes in the fair value of the securities in the nuclear decommissioning fund, historically classified as available-for-sale, will continue to be deferred to a regulatory asset, and the overall impacts of the Jan. 1, 2018 adoption will not be material. Leases — I n February 2016, the FASB issued Leases, Topic 842 (ASU No. 2016-02) , which for lessees requires balance sheet recognition of right-of-use assets and lease liabilities for most leases. This guidance will be effective for interim and annual reporting periods beginning after Dec. 15, 2018. Xcel Energy has not yet fully determined the impacts of implementation. However, adoption is expected to occur on Jan. 1, 2019 utilizing the practical expedients provided by the standard and proposed in Targeted Improvements, Topic 842 (Proposed ASU 2018-200). As such, agreements entered prior to Jan. 1, 2019 that are currently considered leases are expected to be recognized on the consolidated balance sheet, including contracts for use of office space, equipment and natural gas storage assets, as well as certain purchased power agreements (PPAs) for natural gas-fueled generating facilities. Xcel Energy expects that similar agreements entered after Dec. 31, 2018 will generally qualify as leases under the new standard. Presentation of Net Periodic Benefit Cost — I n March 2017, the FASB issued Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost, Topic 715 (ASU No. 2017-07) , which establishes that only the service cost element of pension cost may be presented as a component of operating income in the income statement. Also under the guidance, only the service cost component of pension cost is eligible for capitalization. As a result of application of accounting principles for rate regulated entities, a similar amount of pension cost, including non-service components, will be recognized consistent with the historical ratemaking treatment and the impacts of adoption will be limited to changes in classification of non-service costs in the consolidated statement of income. This guidance is effective for interim and annual reporting periods beginning after Dec. 15, 2017. Recently Adopted Stock Compensation — In March 2016, the FASB issued Improvements to Employee Share-Based Payment Accounting, Topic 718 (ASU No. 2016-09), which simplifies accounting and financial statement presentation for share-based payment transactions. The guidance requires that the difference between the tax deduction available upon settlement of share-based equity awards and the tax benefit accumulated over the vesting period be recognized as an adjustment to income tax expense. Xcel Energy adopted the guidance in 2016, resulting in immaterial 2016 adjustments to income tax expense and changes in classification of cash flows related to tax withholding in the consolidated statements of cash flows for 2016 and prior presented periods. Accounting for the TCJA — In December 2017, the SEC staff issued Staff Accounting Bulletin No. 118 Income Tax Accounting Implications of the Tax Cuts and Jobs Act (SAB 118), to supplement the accounting requirements of ASC Topic 740 Income Taxes (ASC Topic 740) as it relates to assessing and recognizing the impacts of the TCJA in the period of enactment. SAB 118 allows an entity to recognize provisional amounts in its financial statements in circumstances in which the entity’s assessment is incomplete, but for which a reasonable estimate can be made. Provisional amounts recognized are subject to adjustment for up to one year from the enactment date. For further details, see Note 6 to the consolidated financial statements. Reporting Comprehensive Income — In February 2018, the FASB issued Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income, Topic 220 (ASU No. 2018-02), which addresses the stranded amounts of accumulated OCI which may result from enactment of a new tax law. Though accumulated OCI is presented on a net-of-tax basis, ASC Topic 740 requires that the effects of new tax laws on items in accumulated OCI be recognized without a corresponding adjustment to accumulated OCI, and instead recorded to income tax expense. ASU No. 2018-02 permits stranded amounts of accumulated OCI specifically resulting from the TCJA to be removed from accumulated OCI and reclassified to retained earnings, if elected. Xcel Energy adopted the guidance in the fourth quarter of 2017, and elected to recognize a $22 million increase to accumulated other comprehensive loss and retained earnings in the consolidated financial statements for the year ended Dec. 31, 2017, related to a revaluation of deferred income tax assets and liabilities for items in accumulated other comprehensive loss, at the TCJA federal tax rate.

Selected Balance Sheet Data

Selected Balance Sheet Data	12 Months Ended
	Dec. 31, 2017
Balance Sheet Related Disclosures [Abstract]
Selected Balance Sheet Data	Selected Balance Sheet Data (Millions of Dollars) Dec. 31, 2017 Dec. 31, 2016 Accounts receivable, net Accounts receivable $ 849 $ 827 Less allowance for bad debts (52 ) (51 ) $ 797 $ 776 (Millions of Dollars) Dec. 31, 2017 Dec. 31, 2016 Inventories Materials and supplies $ 311 $ 312 Fuel 186 182 Natural gas 113 110 $ 610 $ 604 (Millions of Dollars) Dec. 31, 2017 Dec. 31, 2016 Property, plant and equipment, net Electric plant $ 39,016 $ 38,221 Natural gas plant 5,800 5,318 Common and other property 2,013 1,888 Plant to be retired (a) 11 32 CWIP 2,087 1,373 Total property, plant and equipment 48,927 46,832 Less accumulated depreciation (15,000 ) (14,381 ) Nuclear fuel 2,697 2,572 Less accumulated amortization (2,295 ) (2,181 ) $ 34,329 $ 32,842 (a) In the third quarter of 2017, PSCo early retired Valmont Unit 5 and converted Cherokee Unit 4 from a coal-fueled generating facility to natural gas. PSCo also expects Craig Unit 1 to be early retired in approximately 2025. Amounts are presented net of accumulated depreciation.

Borrowings and Other Financing

Borrowings and Other Financing Instruments	12 Months Ended
	Dec. 31, 2017
Debt Disclosure [Abstract]
Borrowings and Other Financing Instruments	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. Short-Term Debt — Xcel Energy Inc. and its utility subsidiaries meet their short-term liquidity requirements primarily through the issuance of commercial paper and borrowings under their credit facilities and term loan. Commercial paper and term loan borrowings outstanding for Xcel Energy were as follows: (Amounts in Millions, Except Interest Rates) Three Months Ended Dec. 31, 2017 Borrowing limit $ 3,250 Amount outstanding at period end 814 Average amount outstanding 560 Maximum amount outstanding 814 Weighted average interest rate, computed on a daily basis 1.63 % Weighted average interest rate at period end 1.90 Year Ended Dec. 31 (Amounts in Millions, Except Interest Rates) 2017 2016 2015 Borrowing limit $ 3,250 $ 2,750 $ 2,750 Amount outstanding at period end 814 392 846 Average amount outstanding 644 485 601 Maximum amount outstanding 1,247 1,183 1,360 Weighted average interest rate, computed on a daily basis 1.35 % 0.74 % 0.48 % Weighted average interest rate at end of period 1.90 0.95 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. As of Dec. 31, 2017 and 2016 , there were $30 million and $19 million of letters of credit outstanding, respectively, under the credit facilities. The contract amounts of these letters of credit approximate their fair value and are subject to fees. Credit Facilities — In order to use their commercial paper programs to fulfill short-term funding needs, Xcel Energy Inc. and its utility subsidiaries must have revolving credit facilities in place at least equal to the amount of their respective commercial paper borrowing limits and cannot issue commercial paper in an aggregate amount exceeding available capacity under these credit facilities. The lines of credit provide short-term financing in the form of notes payable to banks, letters of credit and back-up support for commercial paper borrowings. NSP-Minnesota, PSCo, SPS, and Xcel Energy Inc. each have the right to request an extension of the June 2021 termination date for two additional one -year periods. NSP-Wisconsin has the right to request an extension of the termination date for an additional one -year period. All extension requests are subject to majority bank group approval. Other features of the credit facilities include: • Xcel Energy Inc. may increase its credit facility by up to $200 million , NSP-Minnesota and PSCo may each increase their credit facilities by $100 million and SPS may increase its credit facility by $50 million . The NSP-Wisconsin credit facility cannot be increased. • Each credit facility has a financial covenant requiring that the debt-to-total capitalization ratio of each entity be less than or equal to 65 percent . Each entity was in compliance as of Dec. 31, 2017 and 2016 , respectively, as evidenced by the table below: Debt-to-Total Capitalization Ratio 2017 2016 Xcel Energy Inc. 58 % 57 % NSP-Wisconsin 47 47 NSP-Minnesota 48 48 SPS 46 47 PSCo 44 45 • If Xcel Energy Inc. or any of its utility subsidiaries do not comply with the covenant, an event of default may be declared, and if not remedied, any outstanding amounts due under the facility can be declared due by the lender. • The Xcel Energy Inc. credit facility has a cross-default provision that provides Xcel Energy Inc. will be in default on its borrowings under the facility if it or any of its subsidiaries, except NSP-Wisconsin as long as its total assets do not comprise more than 15 percent of Xcel Energy’s consolidated total assets, default on certain indebtedness in an aggregate principal amount exceeding $75 million . • Xcel Energy Inc. and its subsidiaries were in compliance with all financial covenants in their debt agreements as of Dec. 31, 2017 and 2016. Xcel Energy Inc. entered into a 364 -day term loan agreement on Dec. 5, 2017 to borrow up to $500 million . As of Dec. 31, 2017, Xcel Energy Inc. had borrowed $250 million of the Term Loan. Xcel Energy Inc. may recommit for one additional 364 -day period from the December 2018 maturity date, subject to majority consent from lenders. As of Dec. 31, 2017 , Xcel Energy Inc. and its utility subsidiaries had the following committed credit facilities available: (Millions of Dollars) Credit Facility (a) Drawn (b) Available Xcel Energy Inc. $ 1,500 $ 783 $ 717 PSCo 700 3 697 NSP-Minnesota 500 44 456 SPS 400 2 398 NSP-Wisconsin 150 11 139 Total $ 3,250 $ 843 $ 2,407 (a) These credit facilities mature in June 2021 , with the exception of Xcel Energy Inc.’s $500 million 364 -day term loan agreement entered into in December 2017. (b) Includes outstanding commercial paper, term loan borrowings and letters of credit. All credit facility bank borrowings, outstanding letters of credit, term loan borrowings and outstanding commercial paper reduce the available capacity under the respective credit facilities. Xcel Energy Inc. and its subsidiaries had no direct advances on the credit facilities outstanding as of Dec. 31, 2017 and 2016 . Long-Term Borrowings and Other Financing Instruments Generally, all real and personal property of NSP-Minnesota, NSP-Wisconsin, PSCo and SPS are subject to the liens of their first mortgage indentures. Debt premiums, discounts and expenses are amortized over the life of the related debt. The premiums, discounts and expenses associated with refinanced debt are deferred and amortized over the life of the related new issuance, in accordance with regulatory guidelines. Maturities of long-term debt are as follows: (Millions of Dollars) 2018 $ 457 2019 405 2020 1,256 2021 425 2022 905 During 2017, Xcel Energy Inc. and its utility subsidiaries completed the following financings: • PSCo issued $400 million of 3.80 percent first mortgage bonds due June 15, 2047 ; • SPS issued $450 million of 3.70 percent first mortgage bonds due Aug. 15, 2047 ; • NSP-Minnesota issued $600 million of 3.60 percent first mortgage bonds due Sept. 15, 2017 ; • NSP-Wisconsin issued $100 million of 3.75 percent first mortgage bonds due Dec. 1, 2047 ; and • Xcel Energy Inc. entered into a $500 million 364 -Day Term Loan Agreement. During 2016, Xcel Energy Inc. and its utility subsidiaries completed the following financings: • Xcel Energy Inc. issued $400 million of 2.40 percent senior notes due March 15, 2021 and $350 million of 3.30 percent senior notes due June 1, 2025 ; • NSP-Minnesota issued $350 million of 3.60 percent first mortgage bonds due May 15, 2046 ; • PSCo issued $250 million of 3.55 percent first mortgage bonds due June 15, 2046 ; • SPS issued $300 million of 3.40 percent first mortgage bonds due Aug. 15, 2046 ; and • Xcel Energy Inc. issued $300 million of 2.60 percent senior notes due March 15, 2022 and $500 million of 3.35 percent senior notes due Dec. 1, 2026 . Deferred Financing Costs — Deferred financing costs of approximately $119 million and $109 million , net of amortization, are presented as a deduction from the carrying amount of long-term debt as of Dec. 31, 2017 and 2016 , respectively. Xcel Energy is amortizing these financing costs over the remaining maturity periods of the related debt. Capital Stock — Xcel Energy Inc. has 7,000,000 shares of preferred stock authorized to be issued with a $100 par value. As of Dec. 31, 2017 and 2016 , there were no shares of preferred stock outstanding. The charters of PSCo and SPS authorize each subsidiary to issue 10,000,000 shares of preferred stock with par values of $0.01 and $1.00 per share, respectively. As of Dec. 31, 2017 and 2016 , there were no preferred shares of subsidiaries outstanding. Xcel Energy Inc. has 1 billion shares of common stock authorized to be issued with a $2.50 par value. Outstanding shares as of Dec. 31, 2017 and 2016 were 507,762,881 and 507,222,795 , respectively. Dividend and Other Capital-Related Restrictions — Xcel Energy depends on its subsidiaries to pay dividends. All of Xcel Energy Inc.’s utility subsidiaries’ dividends are subject to the FERC’s jurisdiction, which prohibits the payment of dividends out of capital accounts; payment of dividends is allowed out of retained earnings only. Due to certain restrictive covenants, Xcel Energy Inc. is required to be current on particular interest payments before dividends can be paid. The most restrictive dividend limitations for NSP-Minnesota, NSP-Wisconsin and SPS are imposed by their respective state regulatory commission. PSCo’s dividends are subject to the FERC’s jurisdiction. Only NSP-Minnesota has a first mortgage indenture which places certain restrictions on the amount of cash dividends it can pay to Xcel Energy Inc., the holder of its common stock. Even with this restriction, NSP-Minnesota could have paid more than $1.9 billion and $1.7 billion in additional cash dividends to Xcel Energy Inc. as of Dec. 31, 2017 and 2016 , respectively. NSP-Minnesota’s state regulatory commissions indirectly limit the amount of dividends NSP-Minnesota can pay by requiring an equity-to-total capitalization ratio between 47.2 percent and 57.6 percent . NSP-Minnesota’s equity-to-total capitalization ratio was 52.1 percent at Dec. 31, 2017 and $1.1 billion in retained earnings was not restricted. Total capitalization for NSP-Minnesota was $10.4 billion at Dec. 31, 2017 , which did not exceed the limit of $11.2 billion . NSP-Wisconsin cannot pay annual dividends in excess of approximately $53 million if its calendar year average equity-to-total capitalization ratio is or falls below the state commission authorized level as calculated by PSCW requirements. NSP-Wisconsin’s calendar year average equity ratio calculated on this basis was 53.1 percent as of Dec. 31, 2017 and $19 million in retained earnings was not restricted. NSP-Wisconsin’s authorized equity ratio was 52.5 percent for 2016 and 2017, but will be 51.5 percent for 2018. SPS’ state regulatory commissions indirectly limit the amount of dividends that SPS can pay Xcel Energy Inc. by requiring an equity-to-total capitalization ratio (excluding short-term debt) between 45.0 percent and 55.0 percent . In addition, SPS may not pay a dividend that would cause it to lose its investment grade bond rating. SPS’ equity ratio (excluding short-term debt) was 53.8 percent as of Dec. 31, 2017 and $542 million in retained earnings was not restricted. The issuance of securities by Xcel Energy Inc. generally is not subject to regulatory approval. However, utility financings and certain intra-system financings are subject to the jurisdiction of the applicable state regulatory commissions and/or the FERC. As of Dec. 31, 2017 : • PSCo has authorization to issue up to an additional $1.8 billion of long-term debt and up to $800 million of short-term debt. • SPS has authorization to issue up to $500 million of short-term debt and SPS will file for additional long-term debt authorization. • NSP-Wisconsin has authorization to issue an additional $250 million of long-term debt and up to $150 million of short-term debt. • NSP-Minnesota has authorization to issue long-term securities provided the equity-to-total capitalization ratio remains between 47.2 percent and 57.6 percent and to issue short-term debt provided it does not exceed 15 percent of total capitalization. Total capitalization for NSP-Minnesota cannot exceed $11.2 billion . Xcel Energy believes these authorizations are adequate and seeks additional authorization as necessary.

Joint Ownership of Generation,

Joint Ownership of Generation, Transmission and Gas Facilities	12 Months Ended
	Dec. 31, 2017
Joint Ownership of Generation, Transmission and Gas Facilities [Abstract]
Joint Ownership of Generation, Transmission and Gas Facilities	Joint Ownership of Generation, Transmission and Gas Facilities Following are the investments by Xcel Energy Inc.’s utility subsidiaries in jointly owned generation, transmission and gas facilities and the related ownership percentages as of Dec. 31, 2017 : (Millions of Dollars) Plant in Service Accumulated Depreciation CWIP Ownership % NSP-Minnesota Electric Generation: Sherco Unit 3 $ 612 $ 411 $ 1 59 % Sherco Common Facilities Units 1, 2 and 3 145 99 1 80 Sherco Substation 5 3 — 59 Electric Transmission: Grand Meadow Line and Substation 11 2 — 50 CapX2020 Transmission 1,039 138 2 51 Total NSP-Minnesota $ 1,812 $ 653 $ 4 (Millions of Dollars) Plant in Service Accumulated Depreciation CWIP Ownership % NSP-Wisconsin Electric Transmission: CapX2020 Transmission $ 162 $ 12 $ 103 81 % La Crosse, Wis. to Madison, Wis. — — 102 37 Total NSP-Wisconsin $ 162 $ 12 $ 205 (Millions of Dollars) Plant in Service Accumulated Depreciation CWIP Ownership % PSCo Electric Generation: Hayden Unit 1 $ 150 $ 72 $ 1 76 % Hayden Unit 2 149 65 — 37 Hayden Common Facilities 39 20 — 53 Craig Units 1 and 2 81 39 — 10 Craig Common Facilities 1, 2 and 3 39 20 — 7 Comanche Unit 3 890 118 — 67 Comanche Common Facilities 24 2 3 82 Electric Transmission: Transmission and other facilities, including substations 177 67 1 Various Gas Transportation: Rifle, Colo. to Avon, Colo. 22 8 — 60 Gas Transportation Compressor 8 1 — 50 Total PSCo $ 1,579 $ 412 $ 5 NSP-Minnesota and PSCo have approximately 517 MW and 816 MW of jointly owned generating capacity, respectively. Each Company’s share of operating expenses and construction expenditures are included in the applicable utility accounts. Each of the respective owners is responsible for providing its own financing.

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2017
Income Tax Disclosure [Abstract]
Income Taxes	Income Taxes Federal Tax Reform — In December 2017, the TCJA was signed into law. While the legislation will require interpretations and regulations to be issued by the IRS, the key provisions impacting Xcel Energy, generally beginning in 2018, include: • Corporate federal tax rate reduction from 35 percent to 21 percent ; • Normalization of resulting plant-related excess deferred taxes; • Elimination of the corporate alternative minimum tax; • Continued interest expense deductibility and discontinued bonus depreciation for regulated public utilities; • Limitations on certain executive compensation deductions; • Limitations on certain deductions for NOLs arising after Dec. 31, 2017 (limited to 80 percent of taxable income); • Repeal of the section 199 manufacturing deduction; and • Reduced deductions for meals and entertainment as well as state and local lobbying. Entities are required under ASC Topic 740 to recognize the accounting impacts of a tax law change, including the impacts of a change in tax rates on deferred tax assets and liabilities, in the period including the date of the tax law enactment. The SEC staff issued guidance in SAB 118 that supplements the accounting requirements of ASC Topic 740 if elements of the TCJA assessment are not complete, and provides for up to a one year period to finalize the required accounting. Xcel Energy has estimated the effects of the TCJA, which have been reflected in the Dec. 31, 2017 consolidated financial statements. Issuance of U.S. Treasury regulations interpreting the TCJA, other U.S. Treasury and IRS guidance or interpretations of the application of ASC Topic 740 may result in changes to these estimates. Overall for Xcel Energy, reductions in deferred tax assets and liabilities due to the reduction in corporate federal tax rates result in a net tax benefit. However, as a result of IRS requirements and past regulatory treatment of deferred taxes in the determination of regulated rates of the utility subsidiaries, including deferred taxes related to regulated plant and certain other deferred tax assets and liabilities, the impact was primarily recognized as a regulatory liability refundable to utility customers. The fourth quarter 2017 estimated accounting impacts of the December 2017 enactment of the new tax law at Xcel Energy included: • $2.7 billion ( $3.8 billion grossed-up for tax) of reclassifications of plant-related excess deferred taxes to regulatory liabilities upon valuation at the new 21 percent federal rate. The regulatory liabilities will be amortized consistent with IRS normalization requirements, resulting in customer refunds over an estimated weighted average period of approximately 30 years; • $254 million and $174 million of reclassifications (grossed-up for tax) of excess deferred taxes for non-plant related deferred tax assets and liabilities, respectively, to regulatory assets and liabilities; and • $23 million of total estimated income tax expense related to the tax rate change on certain non-plant deferred taxes and all other 2017 income statement impacts of the federal tax reform. Xcel Energy has accounted for the state tax impacts of federal tax reform based on currently enacted state tax laws. Any future state tax law changes related to the TCJA will be accounted for in the periods state laws are enacted. Consolidated Appropriations Act, 2016 — In December 2015, the Consolidated Appropriations Act, 2016 (Act) was signed into law. The Act provided for the following: • Immediate expensing, or “bonus depreciation,” of 50 percent for property placed in service in 2015, 2016, and 2017; • PTCs at 100 percent of the applicable rate for wind energy projects that begin construction by the end of 2016; 80 percent of the credit rate for projects that begin construction in 2017; 60 percent of the credit rate for projects that begin construction in 2018; and 40 percent of the credit rate for projects that begin construction in 2019. The wind energy PTC was not extended for projects that begin construction after 2019; • ITCs at 30 percent for commercial solar projects that begin construction by the end of 2019; 26 percent for projects that begin construction in 2020; 22 percent for projects that begin construction in 2021; and 10 percent for projects thereafter; • R&E credit was permanently extended; and • Delay of two years (until 2020) of the excise tax on certain employer-provided health insurance plans. The accounting related to the Act was recorded beginning in the fourth quarter of 2015 because a change in tax law is accounted for beginning in the period of enactment. The fourth quarter 2015 accounting impacts included: • Recognition of additional tax deductions for bonus depreciation of $1.2 billion , and as a result, recognition of $5 million benefit related to a carryback claim (see additional discussion below) and $4 million expense related to valuation allowances and expirations of charitable contribution carryforwards; and • Recognition of $7 million benefit for federal R&E credits. 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. The statute of limitations applicable to Xcel Energy’s federal income tax returns expire as follows: Tax Year(s) Expiration 2009 - 2011 June 2018 2012 - 2013 October 2018 2014 September 2018 2015 September 2019 2016 September 2020 In 2012, the IRS commenced an examination of tax years 2010 and 2011 , including the 2009 carryback claim. The IRS proposed an adjustment to the federal tax loss carryback claims that would have resulted in $14 million of income tax expense for the 2009 through 2011 claims, and the 2013 through 2015 claims. In the fourth quarter of 2015, the IRS forwarded the issue to the Office of Appeals (“Appeals”). In the third quarter of 2017, Xcel Energy and Appeals reached an agreement and the benefit related to the agreed upon portions was recognized. As of Dec. 31, 2017, the case has been forwarded to the Joint Committee on Taxation. In the third quarter of 2015, the IRS commenced an examination of tax years 2012 and 2013 . In the third quarter of 2017, the IRS concluded the audit of tax years 2012 and 2013 and proposed an adjustment that would impact Xcel Energy’s NOL and ETR. After evaluating the proposed adjustment, Xcel Energy filed a protest with the IRS. Xcel Energy anticipates the issue will be forwarded to Appeals. As of Dec. 31, 2017, Xcel Energy has recognized its best estimate of income tax expense that will result from a final resolution of this issue; however, the outcome and timing of a resolution is uncertain. 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 Dec. 31, 2017, Xcel Energy’s earliest open tax years that are subject to examination by state taxing authorities in its major operating jurisdictions were as follows: State Year Colorado 2009 Minnesota 2009 Texas 2009 Wisconsin 2012 In 2016, Minnesota began an audit of years 2010 through 2014 . As of Dec. 31, 2017, Minnesota had not proposed any material adjustments. In 2016, Texas began an audit of years 2009 and 2010 , and in September 2017, began an audit of year 2011. In the fourth quarter of 2017, Texas concluded these audits and Xcel Energy recognized the related benefit. In 2016, Wisconsin began an audit of years 2012 and 2013 . As of Dec. 31, 2017, Wisconsin had not proposed any material adjustments. As of Dec. 31, 2017, there were no other state income tax audits in progress. Unrecognized Tax Benefits — The unrecognized tax benefit balance includes permanent tax positions, which if recognized would affect the annual 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) Dec. 31, 2017 Dec. 31, 2016 Unrecognized tax benefit — Permanent tax positions $ 20 $ 30 Unrecognized tax benefit — Temporary tax positions 19 104 Total unrecognized tax benefit $ 39 $ 134 A reconciliation of the beginning and ending amount of unrecognized tax benefit is as follows: (Millions of Dollars) 2017 2016 2015 Balance at Jan. 1 $ 134 $ 121 $ 67 Additions based on tax positions related to the current year 6 8 27 Reductions based on tax positions related to the current year (4 ) — (5 ) Additions for tax positions of prior years 15 10 35 Reductions for tax positions of prior years (105 ) (5 ) (3 ) Settlements with taxing authorities (7 ) — — Balance at Dec. 31 $ 39 $ 134 $ 121 The unrecognized tax benefit amounts were reduced by the tax benefits associated with NOL and tax credit carryforwards. The amounts of tax benefits associated with NOL and tax credit carryforwards are as follows: (Millions of Dollars) Dec. 31, 2017 Dec. 31, 2016 NOL and tax credit carryforwards $ (31 ) $ (44 ) It is reasonably possible that Xcel Energy’s amount of unrecognized tax benefits could significantly change in the next 12 months as the IRS Appeals progresses and audits resume, the Minnesota and Wisconsin audits progress, and other state audits resume. As the IRS Appeals, Minnesota and Wisconsin audits progress, it is reasonably possible that the amount of unrecognized tax benefit could decrease up to approximately $15 million . The payable for interest related to unrecognized tax benefits is partially offset by the interest benefit associated with NOL and tax credit carryforwards. A reconciliation of the beginning and ending amount of the payable for interest related to unrecognized tax benefits reported are as follows: (Millions of Dollars) 2017 2016 Payable for interest related to unrecognized tax benefits at Jan. 1 $ (3 ) $ — Interest income (expense) income related to unrecognized tax benefits 3 (3 ) Payable for interest related to unrecognized tax benefits at Dec. 31 $ — $ (3 ) The payable for interest related to unrecognized tax benefits was immaterial for 2015. No amounts were accrued for penalties related to unrecognized tax benefits as of Dec. 31, 2017, 2016 or 2015. Other Income Tax Matters — NOL amounts represent the amount of the tax loss that is carried forward and tax credits represent the deferred tax asset. NOL and tax credit carryforwards as of Dec. 31 were as follows: (Millions of Dollars) 2017 2016 Federal NOL carryforward $ 1,072 $ 1,916 Federal tax credit carryforwards 517 424 Valuation allowances for federal credit carryforwards (5 ) — State NOL carryforwards 1,592 1,949 Valuation allowances for state NOL carryforwards (55 ) (59 ) State tax credit carryforwards, net of federal detriment (a) 90 74 Valuation allowances for state credit carryforwards, net of federal benefit (b) (68 ) (54 ) (a) State tax credit carryforwards are net of federal detriment of $24 million and $40 million as of Dec. 31, 2017 and 2016, respectively. (b) Valuation allowances for state tax credit carryforwards were net of federal benefit of $18 million and $29 million as of Dec. 31, 2017 and 2016, respectively. The federal carryforward periods expire between 2021 and 2037 . The state carryforward periods expire between 2018 and 2037 . Total income tax expense from operations differs from the amount computed by applying the statutory federal income tax rate to income before income tax expense. The following reconciles such differences for the years ending Dec. 31: 2017 2016 (b) 2015 (b) Federal statutory rate 35.0 % 35.0 % 35.0 % State income tax on pretax income, net of federal tax effect 3.9 % 3.9 % 3.9 % Increases (decreases) in tax from: Wind production tax credits recognized (4.7 ) (3.4 ) (1.8 ) Other tax credits recognized, net of federal income tax expense (1.0 ) (0.8 ) (0.9 ) Tax reform 1.4 — — Regulatory differences - effects of rate changes (a) (0.1 ) (0.1 ) (0.1 ) Regulatory differences - other utility plant items (0.7 ) (0.5 ) (0.9 ) Change in unrecognized tax benefits (0.6 ) 0.2 0.6 NOL carryback — — (0.3 ) Other, net (1.1 ) (0.2 ) — Effective income tax rate 32.1 % 34.1 % 35.5 % (a) The amortization of excess deferred taxes. (b) The prior periods included in this footnote have been reclassified to conform to current year presentation. The components of Xcel Energy’s income tax expense for the years ending Dec. 31 were: (Millions of Dollars) 2017 2016 2015 Current federal tax expense (benefit) $ 1 $ (3 ) $ (36 ) Current state tax (benefit) expense (11 ) (4 ) 2 Current change in unrecognized tax (benefit) expense (83 ) 6 46 Deferred federal tax expense 460 477 480 Deferred state tax expense 107 112 92 Deferred change in unrecognized tax expense (benefit) 73 (2 ) (36 ) Deferred investment tax credits (5 ) (5 ) (5 ) Total income tax expense $ 542 $ 581 $ 543 The components of deferred income tax expense for the years ending Dec. 31 were: (Millions of Dollars) 2017 2016 2015 Deferred tax (benefit) expense excluding items below $ (2,939 ) $ 631 $ 547 Amortization and adjustments to deferred income taxes on income tax regulatory assets and liabilities 3,583 (45 ) (12 ) Tax (expense) benefit allocated to other comprehensive income, net of adoption of ASU No. 2018-02, and other (4 ) 1 1 Deferred tax expense $ 640 $ 587 $ 536 The components of Xcel Energy’s net deferred tax liability at Dec. 31 were as follows: (Millions of Dollars) 2017 2016 (a) Deferred tax liabilities: Differences between book and tax bases of property $ 4,989 $ 7,697 Regulatory assets 565 152 Pension expense 199 298 Other 69 89 Total deferred tax liabilities $ 5,822 $ 8,236 Deferred tax assets: Regulatory liabilities $ 886 $ (132 ) Tax credit carryforward 607 498 NOL carryforward 293 754 NOL and tax credit valuation allowances (77 ) (57 ) Other employee benefits 132 205 Deferred investment tax credits 17 27 Deferred fuel costs 12 11 Rate refund 10 33 Other 97 113 Total deferred tax assets $ 1,977 $ 1,452 Net deferred tax liability $ 3,845 $ 6,784 (a) The prior period included in this footnote has been reclassified to conform to current year presentation.

Earnings Per Share

Earnings Per Share	12 Months Ended
	Dec. 31, 2017
Earnings Per Share [Abstract]
Earnings Per Share	Earnings Per Share Basic EPS was computed by dividing the earnings available to Xcel Energy Inc.’s common shareholders by the weighted average number of common shares outstanding during the period. Diluted EPS was computed by dividing the earnings available to Xcel Energy Inc.’s common shareholders by the diluted weighted average number of common shares outstanding during the period. Diluted EPS reflects the potential dilution that could occur if securities or other agreements to issue common stock (i.e., common stock equivalents) were settled. The weighted average number of potentially dilutive shares outstanding used to calculate Xcel Energy Inc.’s diluted EPS is calculated using the treasury stock method. Common Stock Equivalents — Xcel Energy Inc. currently has common stock equivalents related to certain equity awards in share-based compensation arrangements. Common stock equivalents causing a dilutive impact to EPS include commitments to issue common stock related to time based equity compensation awards. Effective August 2015, 401(k) matching contributions are settled in cash for all Xcel Energy employee groups. 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: 2017 2016 2015 (Amounts in millions, except per share data) Income Shares Per Share Amount Income Shares Per Share Amount Income Shares Per Share Amount Net income $ 1,148 $ 1,123 $ 984 Basic EPS: Earnings available to common shareholders 1,148 508.5 $ 2.26 1,123 508.8 $ 2.21 984 507.8 $ 1.94 Effect of dilutive securities: Equity awards — 0.6 — 0.7 — 0.4 Diluted EPS: Earnings available to common shareholders $ 1,148 509.1 $ 2.25 $ 1,123 509.5 $ 2.21 $ 984 508.2 $ 1.94 Dividend Reinvestment and Stock Purchase Plan and Stock Compensation Settlements — In 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. In 2017, Xcel Energy Inc. repurchased approximately 0.1 million shares of common stock in the open market at a total cost of approximately $3 million .

Share-Based Compensation

Share-Based Compensation	12 Months Ended
	Dec. 31, 2017
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Share-Based Compensation	Share-Based Compensation Restricted Stock — Certain employees may elect to receive shares of common or restricted stock under the Xcel Energy Inc. Executive Annual Incentive Award Plan and the 2015 Omnibus Incentive Plan (effective May 20, 2015). Restricted stock is treated as an equity award and vests and settles in equal annual installments over a three -year period. Xcel Energy Inc. reinvests dividends on the restricted stock while restrictions are in place. Restrictions also apply to the additional shares of restricted stock acquired through dividend reinvestment. If the restricted shares are forfeited, the employee is not entitled to the dividends on those shares. Restricted stock has a fair value equal to the market trading price of Xcel Energy Inc.’s stock at the grant date. Xcel Energy Inc. granted shares of restricted stock for the years ended Dec. 31 as follows: (Shares in Thousands) 2017 2016 2015 Granted shares 15 20 42 Grant date fair value $ 42.00 $ 38.82 $ 35.00 A summary of the changes of nonvested restricted stock for the year ended 2017 were as follows: (Shares in Thousands) Shares Weighted Average Nonvested restricted stock at Jan. 1, 2017 67 $ 35.43 Granted 15 42.00 Forfeited — — Vested (40 ) 33.36 Dividend equivalents 2 44.69 Nonvested restricted stock at Dec. 31, 2017 44 39.71 Other Equity Awards — Xcel Energy Inc.’s Board of Directors has granted equity awards under the Xcel Energy Inc. 2005 Long-Term Incentive Plan (as amended and restated in 2010) and the 2015 Omnibus Incentive Plan (effective May 20, 2015). These plans allow the attachment of various vesting conditions and performance goals to the awards granted. The vesting conditions and performance goals may vary by plan year. At the end of the restricted period, such grants will be awarded if the vesting conditions and/or performance goals are met. Commencing in 2014, certain employees were granted equity awards with one portion of shares subject only to service conditions, and the other portion subject to performance conditions. Inclusive of other grants of time-based awards, a total of 0.3 million time-based equity shares subject only to service conditions were granted annually in 2017, 2016, and 2015, respectively. Other than shares associated with these time-based awards and restricted stock, payout of all other employee equity awards and the lapsing of restrictions on the transfer of units are based on the achievement of performance criteria. The performance conditions for a portion of the awards granted from 2015 to 2017 are based on relative TSR, measured identically to TSR liability awards granted in those years, and measurement of performance for a portion of units awarded from 2011 to 2013 is based on EPS growth with an additional condition that Xcel Energy Inc.’s annual dividend paid on its common stock remains at a specified amount per share or greater. The performance conditions for the remaining employee equity awards are based on environmental goals. Equity awards with performance conditions awarded from 2011 to 2017, plus associated dividend equivalents, will be settled or forfeited and the restricted period will lapse after three years , with potential payouts ranging from zero to 150 percent for 2011 to 2013 grants, and zero to 200 percent for 2014 to 2017 grants, depending on the level of achievement. • The 2012 awards measured on EPS growth and the 2012 environmental awards met their targets as of Dec. 31, 2014, and were settled in shares in February 2015. • The 2013 awards measured on EPS growth, the 2013 environmental awards and the 2013 time-based awards met their targets as of Dec. 31, 2015, and were settled in shares in February 2016. • The 2014 environmental awards and the 2014 time-based awards met their targets as of Dec. 31, 2016, and were settled in shares in February 2017. • The 2015 environmental awards and the 2015 time-based awards met their targets as of Dec. 31, 2017, and will be settled in shares in February 2018. Equity award units granted to employees, excluding restricted stock, for the years ended Dec. 31 were as follows: (Units in Thousands) 2017 2016 2015 Granted units 503 522 496 Weighted average grant date fair value $ 41.02 $ 36.00 $ 36.09 Approximately 0.5 million of these units vested during 2017 at a total fair value of $22 million . Approximately 0.5 million of these units vested during 2016 at a total fair value of $22 million . Approximately 0.8 million of these units vested during 2015 at a total fair value of $27 million . A summary of the changes in the nonvested portion of these equity award units for the year ended 2017, were as follows: (Units in Thousands) Units Weighted Average Nonvested Units at Jan. 1, 2017 984 $ 36.05 Granted 503 41.02 Forfeited (70 ) 37.12 Vested (467 ) 36.17 Dividend equivalents 45 37.20 Nonvested Units at Dec. 31, 2017 995 38.48 The total fair value of these nonvested equity awards as of Dec. 31, 2017 was $48 million and the weighted average remaining contractual life was 1.7 years . Stock Equivalent Units — Non-employee members of the Xcel Energy Inc. Board of Directors receive annual awards of stock equivalent units, with each unit having a value equal to one share of Xcel Energy Inc. common stock. The annual grants are vested as of the date of each member’s election to the Board of Directors; there is no further service or other condition attached to the annual grants. Additionally, directors may elect to receive their fees in stock equivalent units in lieu of cash. Dividends on Xcel Energy Inc.’s common stock are converted to stock equivalent units and granted based on the number of stock equivalent units held by each participant as of the dividend date. The stock equivalent units are payable as a distribution of Xcel Energy Inc.’s common stock upon a director’s termination of service. The stock equivalent units granted for the years ended Dec. 31 were as follows: (Units in Thousands) 2017 2016 2015 Granted units 51 49 60 Grant date fair value $ 46.05 $ 40.68 $ 34.58 A summary of the stock equivalent unit changes for the year ended 2017 are as follows: (Units in Thousands) Units Weighted Average Stock equivalent units at Jan. 1, 2017 750 $ 27.39 Granted 51 46.05 Units distributed (71 ) 20.52 Dividend equivalents 23 45.24 Stock equivalent units at Dec. 31, 2017 753 29.83 TSR Liability Awards — Xcel Energy Inc.’s Board of Directors has granted TSR liability awards under the Xcel Energy Inc. 2005 Long-Term Incentive Plan (as amended and restated effective in 2010) and 2015 Omnibus Incentive Plan. The plans allow Xcel Energy to attach various performance goals to the awards granted. The liability awards granted have been historically dependent on a single measure of performance, Xcel Energy Inc.’s relative TSR measured over a three -year period. For 2017, 2016 and 2015 awards, Xcel Energy Inc.’s TSR is compared to the TSR of other companies in a 22 -member utilities peer group. At the end of the three -year period, potential payouts of the awards range from zero to 200 percent , depending on Xcel Energy Inc.’s TSR compared to the applicable peer group or index. The TSR liability awards granted for the years ended Dec. 31 were as follows: (In Thousands) 2017 2016 2015 Awards granted 240 264 224 The total amounts of TSR liability awards settled during the years ended Dec. 31 were as follows: (In Thousands) 2017 2016 2015 Awards settled 454 354 — Settlement amount (cash, common stock and deferred amounts) $ 19,083 $ 13,724 $ — The amount of cash used to settle Xcel Energy’s TSR liability awards was $7 million in 2017. Share-Based Compensation Expense — Other than for restricted stock, the vesting of employee equity awards is generally predicated on the achievement of a performance condition, which is the achievement of a TSR, EPS or environmental measures target. Additionally, approximately 0.3 million of equity award units were granted annually in 2017, 2016, and 2015, respectively, with vesting subject only to service conditions for periods of three years. Generally, all of these instruments are considered to be equity awards since the plan settlement determination (shares or cash) resides with Xcel Energy and not the participants. In addition, these awards have not been previously settled in cash and Xcel Energy plans to continue electing share settlement. The grant date fair value of equity awards is expensed over the service period as employees vest in their rights to those awards. The TSR liability awards have been historically settled partially in cash, and do not qualify as equity awards, but rather are accounted for as liabilities. As liability awards, the fair value on which ratable expense is based, as employees vest in their rights to those awards, is remeasured each period based on the current stock price and performance achievement, and final expense is based on the market value of the shares on the date the award is settled. The compensation costs related to share-based awards for the years ended Dec. 31 were as follows: (Millions of Dollars) 2017 2016 2015 Compensation cost for share-based awards (a) $ 57 $ 41 $ 45 Tax benefit recognized in income 22 16 18 (a) Compensation costs for share-based payment arrangements are included in O&M expense in the consolidated statements of income. The maximum aggregate number of shares of common stock available for issuance under the Xcel Energy Inc. 2015 Omnibus Incentive Plan (effective May 20, 2015) is 7.0 million shares. The maximum aggregate number of shares of common stock available for issuance under the Xcel Energy Inc. 2005 Long-Term Incentive Plan (as amended and restated effective Feb. 17, 2010) is 8.3 million shares. Under the Xcel Energy Inc. Executive Annual Incentive Award Plan (as amended and restated effective Feb. 17, 2010), the total number of shares approved for issuance is 1.2 million shares. As of Dec. 31, 2017 and 2016, there was approximately $44 million and $29 million , respectively, of total unrecognized compensation cost related to nonvested share-based compensation awards. Xcel Energy expects to recognize the amount unrecognized at Dec. 31, 2017 over a weighted average period of 1.7 years .

Benefit Plans and Other Postret

Benefit Plans and Other Postretirement Benefits	12 Months Ended
	Dec. 31, 2017
Retirement Benefits [Abstract]
Benefit Plans and Other Postretirement Benefits	Benefit Plans and Other Postretirement Benefits Xcel Energy offers various benefit plans to its employees. Approximately 46 percent of employees that receive benefits are represented by several local labor unions under several collective-bargaining agreements. As of Dec. 31, 2017 : • NSP-Minnesota had 1,858 and NSP-Wisconsin had 383 bargaining employees covered under a collective-bargaining agreement, which expires in December 2019. NSP-Minnesota also had an additional 248 nuclear operation bargaining employees covered under several collective-bargaining agreements. These agreements expire in 2018 and 2019. • PSCo had 1,835 bargaining employees covered under a collective-bargaining agreement, which expired in May 2017. While collective bargaining is ongoing, the terms and conditions of the agreement are automatically extended. • SPS had 791 bargaining employees covered under a collective-bargaining agreement, which expires in October 2019. The plans invest in various instruments which are disclosed under the accounting guidance for fair value measurements which establishes a hierarchical framework for disclosing the observability of the inputs utilized in measuring fair value. The three levels in the hierarchy and examples of each level are as follows: Level 1 — Quoted prices are available in active markets for identical assets as of the reporting date. The types of assets 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 included in Level 2 are typically either comparable to actively traded securities or contracts, or priced with models using highly observable inputs. Level 3 — Significant inputs to pricing have little or no observability as of the reporting date. The types of assets included in Level 3 are those with inputs 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 NAVs. Insurance contracts — Insurance contract fair values take into consideration the value of the investments in separate accounts of the insurer, which are priced based on observable inputs. Investments in commingled funds, equity securities and other funds — Equity securities are valued using quoted prices in active markets. The fair values for commingled funds are measured using NAVs, which take into consideration the value of underlying fund investments, as well as the other accrued assets and liabilities of a fund, in order to determine a per share market value. The investments in commingled funds may be redeemed for NAV with proper notice. Proper notice varies by fund and can range from daily with a few 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. Depending on the fund, unscheduled distributions from real estate investments may require approval of the fund or may be redeemed with proper notice, which is typically quarterly with 45 - 90 days ’ notice; however, withdrawals from real estate investments may be delayed or discounted as a result of fund illiquidity. Investments in debt securities — Fair values for debt securities are determined by a third party pricing service using recent trades and observable spreads from benchmark interest rates for similar securities. Derivative Instruments — Fair values for foreign currency derivatives are determined using pricing models based on the prevailing forward exchange rate of the underlying currencies. The fair values of interest rate derivatives are based on broker quotes that utilize current market interest rate forecasts. Pension Benefits Xcel Energy has several noncontributory, defined benefit pension plans that cover almost all employees. Generally, benefits are based on a combination of years of service, the employee’s average pay and, in some cases, social security benefits. Xcel Energy’s policy is to fully fund into an external trust the actuarially determined pension costs recognized for ratemaking and financial reporting purposes, subject to the limitations of applicable employee benefit and tax laws. In addition to the qualified pension plans, Xcel Energy maintains a supplemental executive retirement plan (SERP) and a nonqualified pension plan. The SERP is maintained for certain executives that were participants in the plan in 2008, when the SERP was closed to new participants. The nonqualified pension plan provides unfunded, nonqualified benefits for compensation that is in excess of the limits applicable to the qualified pension plans, with distributions funded by Xcel Energy’s consolidated operating cash flows. The total obligations of the SERP and nonqualified plan as of Dec. 31, 2017 and 2016 were $37 million and $44 million , respectively. In 2017 and 2016 , Xcel Energy recognized net benefit cost for financial reporting for the SERP and nonqualified plans of $5 million and $8 million , respectively. In 2016, Xcel Energy established rabbi trusts to provide partial funding for future distributions of the SERP and its deferred compensation plan, supplemented by Xcel Energy’s consolidated operating cash flows as determined necessary. For more information regarding the funding of rabbi trusts, see Note 11 to the consolidated financial statements. Also in 2016, Xcel Energy amended the deferred compensation plan to provide eligible participants the ability to diversify deferred settlements of equity awards, other than time-based equity awards, into various fund options. Xcel Energy bases the investment-return assumption on expected long-term performance for each of the investment types included in its pension asset portfolio. Xcel Energy considers the historical returns achieved by its asset portfolio over the past 20 -year or longer period, as well as the long-term return levels projected and recommended by investment experts. Xcel Energy continually reviews its pension assumptions. The pension cost determination assumes a forecasted mix of investment types over the long-term. • Investment returns in 2017 were above the assumed level of 6.87 percent ; • Investment returns in 2016 were below the assumed level of 6.87 percent ; • Investment returns in 2015 were below the assumed level of 7.09 percent ; and • In 2018 , Xcel Energy’s expected investment-return assumption is 6.87 percent . The assets are invested in a portfolio according to Xcel Energy’s return, liquidity and diversification objectives to provide funding for plan obligations and minimize contributions to the plan, within appropriate levels of risk. The principal mechanism for achieving these objectives is the projected asset allocation given the long-term risk, return, and liquidity characteristics of each particular asset class. There were no significant concentrations of risk in any particular industry, index, or entity. Market volatility can impact even well-diversified portfolios and significantly affect the return levels achieved by pension assets in any year. The following table presents the target pension asset allocations for Xcel Energy at Dec. 31 for the upcoming year: 2017 2016 Domestic and international equity securities 36 % 38 % Long-duration fixed income and interest rate swap securities 27 27 Short-to-intermediate fixed income securities 20 16 Alternative investments 15 17 Cash 2 2 Total 100 % 100 % Xcel Energy’s ongoing investment strategy is based on plan-specific investment recommendations that seek to minimize potential investment and interest rate risk as a plan’s funded status increases over time. The investment recommendations result in a greater percentage of long-duration fixed income securities being allocated to specific plans having relatively higher funded status ratios and a greater percentage of growth assets being allocated to plans having relatively lower funded status ratios. The aggregate projected asset allocation presented in the table above for the master pension trust results from the plan-specific strategies. Pension Plan Assets The following tables present, for each of the fair value hierarchy levels, Xcel Energy’s pension plan assets that are measured at fair value as of Dec. 31, 2017 and 2016 : Dec. 31, 2017 (Millions of Dollars) Level 1 Level 2 Level 3 Investments Measured at NAV Total Cash equivalents $ 196 $ — $ — $ — $ 196 Commingled funds: U.S. equity funds 513 — — — 513 Non U.S. equity funds 92 — — 199 291 U.S. corporate bond funds 369 — — — 369 Emerging market equity funds — — — 314 314 Emerging market debt funds 75 — — 166 241 Private equity investments — — — 84 84 Real estate — — — 195 195 Other commingled funds 5 — — 117 122 Debt securities: Government securities — 356 — — 356 U.S. corporate bonds — 272 — — 272 Non U.S. corporate bonds — 45 — — 45 Equity securities: U.S. equities 114 — — — 114 Other (29 ) 4 — 1 (24 ) Total $ 1,335 $ 677 $ — $ 1,076 $ 3,088 Dec. 31, 2016 (Millions of Dollars) Level 1 Level 2 Level 3 Investments Measured at NAV Total Cash equivalents $ 113 $ — $ — $ — $ 113 U.S. equity funds 491 — — — 491 Non U.S. equity funds 167 — — 202 369 U.S. corporate bond funds 268 — — — 268 Emerging market equity funds — — — 194 194 Emerging market debt funds 79 — — 85 164 Commodity funds — — — 21 21 Private equity investments — — — 101 101 Real estate — — — 184 — 184 Other commingled funds — — — 210 210 Debt securities: Government securities — 364 — — 364 U.S. corporate bonds — 238 — — 238 Non U.S. corporate bonds — 38 — — 38 Mortgage-backed securities — 6 — — 6 Asset-backed securities — 3 — — 3 Equity securities: U.S. equities 89 — — — 89 Other — 3 — — 3 Total $ 1,207 $ 652 $ — $ 997 $ 2,856 There were no assets transferred in or out of Level 3 for the years ended Dec. 31, 2017, 2016 or 2015. Benefit Obligations — A comparison of the actuarially computed pension benefit obligation and plan assets for Xcel Energy is presented in the following table: (Millions of Dollars) 2017 2016 Accumulated Benefit Obligation at Dec. 31 $ 3,612 $ 3,489 Change in Projected Benefit Obligation: Obligation at Jan. 1 $ 3,682 $ 3,568 Service cost 94 92 Interest cost 147 160 Plan amendments (13 ) 2 Actuarial loss 259 186 Benefit payments (a) (341 ) (326 ) Obligation at Dec. 31 $ 3,828 $ 3,682 (Millions of Dollars) 2017 2016 Change in Fair Value of Plan Assets: Fair value of plan assets at Jan. 1 $ 2,856 $ 2,884 Actual return on plan assets 411 172 Employer contributions 162 125 Benefit payments (a) (341 ) (325 ) Fair value of plan assets at Dec. 31 $ 3,088 $ 2,856 (Millions of Dollars) 2017 2016 Funded Status of Plans at Dec. 31: Funded status (b) $ (740 ) $ (826 ) (a) 2017 amount includes approximately $174 million of lump-sum benefit payments used in the determination of a settlement charge. (b) Amounts are recognized in noncurrent liabilities on Xcel Energy’s consolidated balance sheets. (Millions of Dollars) 2017 2016 Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost: Net loss $ 1,709 $ 1,836 Prior service credit (25 ) (5 ) Total $ 1,684 $ 1,831 (Millions of Dollars) 2017 2016 Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost Have Been Recorded as Follows Based Upon Expected Recovery in Rates: Current regulatory assets $ 100 $ 101 Noncurrent regulatory assets 1,511 1,650 Deferred income taxes 19 31 Net-of-tax accumulated OCI 54 49 Total $ 1,684 $ 1,831 Measurement date Dec. 31, 2017 Dec. 31, 2016 2017 2016 Significant Assumptions Used to Measure Benefit Obligations: Discount rate for year-end valuation 3.63 % 4.13 % Expected average long-term increase in compensation level 3.75 3.75 Mortality table RP-2014 RP-2014 Mortality — In 2014, the Society of Actuaries published a new mortality table (RP-2014) that increased the overall life expectancy of males and females. In 2014, Xcel Energy adopted this mortality table, with modifications, based on its population and specific experience. During 2017, a new projection table was released (MP-2017). Xcel Energy evaluated the updated projection table and concluded that the methodology currently in use and adopted in 2016 is consistent with the recently updated 2017 table and continues to be representative of Xcel Energy’s population. Cash Flows — Cash funding requirements can be impacted by changes to actuarial assumptions, actual asset levels and other calculations prescribed by the funding requirements of income tax and other pension-related regulations. Required contributions were made in 2015 through 2018 to meet minimum funding requirements. Total voluntary and required pension funding contributions across all four of Xcel Energy’s pension plans were as follows: • $150 million in January 2018; • $162 million in 2017; • $125 million in 2016; and • $90 million in 2015. For future years, Xcel Energy anticipates contributions will be made as necessary. Plan Amendments — Xcel Energy amended the Xcel Energy Pension Plan and Xcel Energy Inc. Nonbargaining Pension Plan (South) in 2017 to reduce supplemental benefits for non-bargaining participants as well as to allow the transfer of a portion of non-qualified pension obligations into the qualified plans. In 2016, the Xcel Energy Pension Plan was amended to change the discount rate basis for lump-sum conversion to annuity participants and annuity conversion to lump-sum participants. Additionally in 2016, the annual credits contributed to the PSCo Bargaining Plan retirement spending account increased. Benefit Costs — The components of Xcel Energy’s net periodic pension cost were: (Millions of Dollars) 2017 2016 2015 Service cost $ 94 $ 92 $ 99 Interest cost 147 160 149 Expected return on plan assets (209 ) (210 ) (214 ) Amortization of prior service credit (2 ) (2 ) (2 ) Amortization of net loss 107 97 125 Settlement charge (a) 81 — — Net periodic pension cost 218 137 157 Costs not recognized due to effects of regulation (79 ) (15 ) (29 ) Net benefit cost recognized for financial reporting $ 139 $ 122 $ 128 (a) A settlement charge is required when the amount of all lump-sum distributions during the year is greater than the sum of the service and interest cost components of the annual net periodic pension cost. In the fourth quarter of 2017 as a result of lump-sum distributions during the 2017 plan year, Xcel Energy recorded a total pension settlement charge of $81 million , the majority of which was not recognized due to the effects of regulation. A total of $8 million of that amount was recorded in O&M expenses in the fourth quarter of 2017. 2017 2016 2015 Significant Assumptions Used to Measure Costs: Discount rate 4.13 % 4.66 % 4.11 % Expected average long-term increase in compensation level 3.75 4.00 3.75 Expected average long-term rate of return on assets 6.87 6.87 7.09 Pension costs include an expected return impact for the current year that may differ from actual investment performance in the plan. The return assumption used for 2018 pension cost calculations is 6.87 percent . Defined Contribution Plans Xcel Energy maintains 401(k) and other defined contribution plans that cover substantially all employees. Total expense to these plans was approximately $37 million in 2017 , $36 million in 2016 and $34 million in 2015 . Postretirement Health Care Benefits Xcel Energy has a contributory health and welfare benefit plan that provides health care and death benefits to certain Xcel Energy retirees. • NSP-Minnesota and NSP-Wisconsin discontinued contributing toward health care benefits for non-bargaining employees retiring after 1998 and for bargaining employees who retired after 1999. • Xcel Energy discontinued contributing toward health care benefits for nonbargaining employees of the former NCE who retired after June 30, 2003 and for PSCo bargaining employees hired on or after July 1, 2003. • Xcel Energy discontinued contributing toward health care benefits for SPS bargaining employees hired on or after Jan. 1, 2012. Plan Assets — Certain state agencies that regulate Xcel Energy Inc.’s utility subsidiaries also have issued guidelines related to the funding of postretirement benefit costs. SPS is required to fund postretirement benefit costs for Texas and New Mexico jurisdictional amounts collected in rates. PSCo is required to fund postretirement benefit costs in irrevocable external trusts that are dedicated to the payment of these postretirement benefits. These assets are invested in a manner consistent with the investment strategy for the pension plan. The following table presents the target postretirement asset allocations for Xcel Energy at Dec. 31 for the upcoming year: 2017 2016 Domestic and international equity securities 24 % 25 % Short-to-intermediate fixed income securities 60 57 Alternative investments 9 13 Cash 7 5 Total 100 % 100 % Xcel Energy bases its investment-return assumption for the postretirement health care fund assets on expected long-term performance for each of the investment types included in its asset portfolio. The assets are invested in a portfolio according to Xcel Energy’s return, liquidity and diversification objectives to provide a source of funding for plan obligations and minimize contributions to the plan, within appropriate levels of risk. The principal mechanism for achieving these objectives is the projected asset allocation given the long-term risk, return, correlation and liquidity characteristics of each particular asset class. There were no significant concentrations of risk in any particular industry, index, or entity. Market volatility can impact even well-diversified portfolios and significantly affect the return levels achieved by postretirement health care assets in any year. The following tables present, for each of the fair value hierarchy levels, Xcel Energy’s postretirement benefit plan assets that are measured at fair value as of Dec. 31, 2017 and 2016 : Dec. 31, 2017 (Millions of Dollars) Level 1 Level 2 Level 3 Investments Measured at NAV Total Cash equivalents $ 29 $ — $ — $ — $ 29 Insurance contracts — 50 — — 50 Commingled funds: U.S. equity funds 74 — — — 74 U.S fixed income funds 34 — — — 34 Emerging market debt funds 40 — — — 40 Debt securities: Government securities — 57 — — 57 U.S. corporate bonds — 63 — — 63 Non U.S. corporate bonds — 21 — — 21 Asset-backed securities — 23 — — 23 Mortgage-backed securities — 34 — — 34 Equity securities: Non U.S. equities 35 — — — 35 Other — 1 — — 1 Total $ 212 $ 249 $ — $ — $ 461 Dec. 31, 2016 (Millions of Dollars) Level 1 Level 2 Level 3 Investments Measured at NAV Total Cash equivalents $ 21 $ — $ — $ — $ 21 Insurance contracts — 47 — — 47 Commingled funds: U.S. equity funds 54 — — — 54 U.S fixed income funds 27 — — — 27 Emerging market debt funds 30 — — — 30 Other commingled funds — — — 55 55 Debt securities: Government securities — 38 — — 38 U.S. corporate bonds — 62 — — 62 Non U.S. corporate bonds — 17 — — 17 Asset-backed securities — 19 — — 19 Mortgage-backed securities — 29 — — 29 Equity securities: Non U.S. equities 41 — — — 41 Other — 2 — — 2 Total $ 173 $ 214 $ — $ 55 $ 442 There were no assets transferred in or out of Level 3 for the years ended Dec. 31, 2017 , 2016 or 2015 . Benefit Obligations — A comparison of the actuarially computed benefit obligation and plan assets for Xcel Energy is presented in the following table: (Millions of Dollars) 2017 2016 Change in Projected Benefit Obligation: Obligation at Jan. 1 $ 603 $ 584 Service cost 2 2 Interest cost 24 26 Medicare subsidy reimbursements 1 2 Plan participants’ contributions 8 7 Actuarial loss 33 33 Benefit payments (50 ) (51 ) Obligation at Dec. 31 $ 621 $ 603 (Millions of Dollars) 2017 2016 Change in Fair Value of Plan Assets: Fair value of plan assets at Jan. 1 $ 442 $ 448 Actual return on plan assets 41 20 Plan participants’ contributions 8 7 Employer contributions 20 18 Benefit payments (50 ) (51 ) Fair value of plan assets at Dec. 31 $ 461 $ 442 (Millions of Dollars) 2017 2016 Funded Status of Plans at Dec. 31: Funded status $ (160 ) $ (161 ) Current liabilities (3 ) (6 ) Noncurrent liabilities (157 ) (155 ) Net postretirement amounts recognized on consolidated balance sheets $ (160 ) $ (161 ) (Millions of Dollars) 2017 2016 Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost: Net loss $ 147 $ 136 Prior service credit (44 ) (54 ) Total $ 103 $ 82 (Millions of Dollars) 2017 2016 Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost Have Been Recorded as Follows Based Upon Expected Recovery in Rates: Noncurrent regulatory assets $ 107 $ 91 Current regulatory liabilities (1 ) (1 ) Noncurrent regulatory liabilities (10 ) (14 ) Deferred income taxes 2 2 Net-of-tax accumulated OCI 5 4 Total $ 103 $ 82 Measurement date Dec. 31, 2017 Dec. 31, 2016 2017 2016 Significant Assumptions Used to Measure Benefit Obligations: Discount rate for year-end valuation 3.62 % 4.13 % Mortality table RP 2014 RP 2014 Health care costs trend rate — initial: Pre-65 7.00 % 5.50 % Health care costs trend rate — initial: Post-65 5.50 % 5.50 % Beginning with the Dec. 31, 2017 measurement, Xcel Energy Inc. separated its initial medical trend assumption for pre-Medicare (Pre-65) and post-Medicare (Post-65) claims costs in order to reflect different short-term expectations based on recent experience differences. The Post-65 initial medical trend rate was set at 5.5 percent . The Pre-65 initial medical trend rate was set at 7.0 percent . The ultimate trend assumption remained at 4.5 percent for both groups. The period until the ultimate rate is reached is five years . Xcel Energy bases its medical trend assumption on the long-term cost inflation expected in the health care market, considering the levels projected and recommended by industry experts, as well as recent actual medical cost increases experienced by Xcel Energy’s retiree medical plan. A one-percent change in the assumed health care cost trend rate would have the following effects on Xcel Energy: One-Percentage Point (Millions of Dollars) Increase Decrease APBO $ 60 $ (51 ) Service and interest components 3 (2 ) Cash Flows — The postretirement health care plans have no funding requirements under income tax and other retirement-related regulations other than fulfilling benefit payment obligations, when claims are presented and approved under the plans. Additional cash funding requirements are prescribed by certain state and federal rate regulatory authorities. Xcel Energy contributed $20 million during 2017 , $18 million during 2016 , $18 million during 2015 and expects to contribute approximately $12 million during 2018 . Plan Amendments — In 2017 and 2016, there were no plan amendments made which affected the benefit obligation. Benefit Costs — The components of Xcel Energy’s net periodic postretirement benefit costs were: (Millions of Dollars) 2017 2016 2015 Service cost $ 2 $ 2 $ 2 Interest cost 24 26 25 Expected return on plan assets (25 ) (25 ) (26 ) Amortization of prior service credit (11 ) (11 ) (11 ) Amortization of net loss 7 4 6 Net periodic postretirement (credit) cost $ (3 ) $ (4 ) $ (4 ) 2017 2016 2015 Significant Assumptions Used to Measure Costs: Discount rate 4.13 % 4.65 % 4.08 % Expected average long-term rate of return on assets 5.80 5.80 5.80 Projected Benefit Payments The following table lists Xcel Energy’s projected benefit payments for the pension and postretirement benefit plans: (Millions of Dollars) Projected Gross Projected Expected Net Projected 2018 $ 307 $ 47 $ 2 $ 45 2019 262 47 2 45 2020 261 47 2 45 2021 261 47 3 44 2022 266 46 3 43 2023-2027 1,274 212 14 198 Multiemployer Plans NSP-Minnesota and NSP-Wisconsin each contribute to several union multiemployer pension and other postretirement benefit plans, none of which are individually significant. These plans provide pension and postretirement health care benefits to certain union employees who may perform services for multiple employers and do not participate in the NSP-Minnesota and NSP-Wisconsin sponsored pension and postretirement health care plans. Contributing to these types of plans creates risk that differs from providing benefits under NSP-Minnesota and NSP-Wisconsin sponsored plans, in that if another participating employer ceases to contribute to a multiemployer plan, additional unfunded obligations may need to be funded over time by remaining participating employers. Contributions to multiemployer plans were as follows for the years ended Dec. 31, 2017 , 2016 and 2015 . The average number of NSP-Minnesota union employees covered by the multiemployer pension plans decreased to approximately 576 in 2017 from 700 in 2016 . There were no other significant changes to the nature or magnitude of the participation of NSP-Minnesota and NSP-Wisconsin in multiemployer plans for the years presented: (Millions of Dollars) 2017 2016 2015 Multiemployer pension contributions: NSP-Minnesota $ 12 $ 14 $ 17 NSP-Wisconsin — 1 1 Total $ 12 $ 15 $ 18

Other Income, Net

Other Income, Net	12 Months Ended
	Dec. 31, 2017
Other Income and Expenses [Abstract]
Other Income, Net	Other Income, Net Other income, net for the years ended Dec. 31 consisted of the following: (Millions of Dollars) 2017 2016 2015 Interest income $ 19 $ 8 $ 6 Other nonoperating income 7 3 4 Insurance policy expense (3 ) (3 ) (4 ) Other income, net $ 23 $ 8 $ 6

Fair Value of Financial Assets

Fair Value of Financial Assets and Liabilities	12 Months Ended
	Dec. 31, 2017
Fair Value Disclosures [Abstract]
Fair Value of Financial Assets and Liabilities	Fair Value of Financial Assets and Liabilities Fair Value Measurements The accounting guidance for fair value measurements and disclosures provides a single definition of fair value and requires certain disclosures about assets and liabilities measured at fair value. A hierarchical framework for disclosing the observability of the inputs utilized in measuring assets and liabilities at fair value is established by this guidance. The three levels in the hierarchy are as follows: Level 1 — Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. The types of assets and liabilities included in Level 1 are highly liquid and actively traded instruments with quoted prices. Level 2 — Pricing inputs are other than quoted prices in active markets, but are either directly or indirectly observable as of the reporting date. The types of assets and liabilities included in Level 2 are typically either comparable to actively traded securities or contracts, or priced with models using highly observable inputs. Level 3 — Significant inputs to pricing have little or no observability as of the reporting date. The types of assets and liabilities included in Level 3 are those valued with models requiring significant management judgment or estimation. Specific valuation methods include the following: Cash equivalents — The fair values of cash equivalents are generally based on cost plus accrued interest; money market funds are measured using quoted NAV. Investments in equity securities and other funds — Equity securities are valued using quoted prices in active markets. The fair values for commingled funds are measured using NAVs, which take into consideration the value of underlying fund investments, as well as the other accrued assets and liabilities of a fund, in order to determine a per-share market value. The investments in commingled funds may be redeemed for NAV with proper notice. Proper notice varies by fund and can range from daily with one or two days notice to annually with 90 days notice. Private equity investments require approval of the fund for any unscheduled redemption, and such redemptions may be approved or denied by the fund at its sole discretion. Unscheduled distributions from real estate investments may be redeemed with proper notice, which is typically quarterly with 45 - 90 days notice; however, withdrawals from real estate investments may be delayed or discounted as a result of fund illiquidity. Investments in debt securities — Fair values for debt securities are determined by a third party pricing service using recent trades and observable spreads from benchmark interest rates for similar securities. Interest rate derivatives — The fair values of interest rate derivatives are based on broker quotes that utilize current market interest rate forecasts. Commodity derivatives — The methods used to measure the fair value of commodity derivative forwards and options utilize forward prices and volatilities, as well as pricing adjustments for specific delivery locations, and are generally assigned a Level 2 classification. When contractual settlements relate to inactive delivery locations or extend to periods beyond those readily observable on active exchanges or quoted by brokers, the significance of the use of less observable forecasts of forward prices and volatilities on a valuation is evaluated, and may result in Level 3 classification. Electric commodity derivatives held by NSP-Minnesota and SPS include transmission congestion instruments, generally referred to as FTRs. FTRs purchased from a RTO are financial instruments that entitle or obligate the holder to monthly revenues or charges based on transmission congestion across a given transmission path. The value of an FTR is derived from, and designed to offset, the cost of transmission congestion. In addition to overall transmission load, congestion is also influenced by the operating schedules of power plants and the consumption of electricity pertinent to a given transmission path. Unplanned plant outages, scheduled plant maintenance, changes in the relative costs of fuels used in generation, weather and overall changes in demand for electricity can each impact the operating schedules of the power plants on the transmission grid and the value of an FTR. 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 important inputs to the value of FTRs between auction processes, 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 settlements are included in fuel and purchased energy cost recovery mechanisms as applicable in each jurisdiction, and therefore changes in the fair value of the yet to be settled portions of most FTRs are deferred as a regulatory asset or liability. Given this regulatory treatment and the limited magnitude of FTRs relative to the electric utility operations of NSP-Minnesota and SPS, the numerous unobservable quantitative inputs pertinent to the value of FTRs are insignificant to the consolidated financial statements of Xcel Energy. Non-Derivative Instruments Fair Value Measurements The NRC requires NSP-Minnesota to maintain a portfolio of investments to fund the costs of decommissioning its nuclear generating plants. Together with all accumulated earnings or losses, the assets of the nuclear decommissioning fund are legally restricted for the purpose of decommissioning the Monticello and PI nuclear generating plants. The fund contains cash equivalents, debt securities, equity securities and other investments – all classified as available-for-sale. NSP-Minnesota plans to reinvest matured securities until decommissioning begins. NSP-Minnesota uses the MPUC approved asset allocation for the escrow and investment targets by asset class for both the escrow and qualified trust. NSP-Minnesota recognizes the costs of funding the decommissioning of its nuclear generating plants over the lives of the plants, assuming rate recovery of all costs. Given the purpose and legal restrictions on the use of nuclear decommissioning fund assets, realized and unrealized gains on fund investments over the life of the fund are deferred as an offset of NSP-Minnesota’s regulatory asset for nuclear decommissioning costs. Consequently, any realized and unrealized gains and losses on securities in the nuclear decommissioning fund, including any other-than-temporary impairments, are deferred as a component of the regulatory asset for nuclear decommissioning. Unrealized gains for the nuclear decommissioning fund were $560 million and $379 million as of Dec. 31, 2017 and 2016 , respectively, and unrealized losses and amounts recorded as other-than-temporary impairments were $7 million and $47 million as of Dec. 31, 2017 and 2016 , respectively. The following tables present the cost and fair value of Xcel Energy’s non-derivative instruments with recurring fair value measurements in the nuclear decommissioning fund as of Dec. 31, 2017 and 2016 : Dec. 31, 2017 Fair Value (Millions of Dollars) Cost Level 1 Level 2 Level 3 Investments Measured at NAV Total Nuclear decommissioning fund (a) Cash equivalents $ 29 $ 29 $ — $ — $ — $ 29 Commingled funds: Non U.S. equities 264 217 — — 90 307 Emerging market debt funds 156 — — — 166 166 Private equity investments 141 — — — 198 198 Real estate 131 — — — 202 202 Other commingled funds 9 6 — — 3 9 Debt securities: Government securities 68 — 69 — — 69 U.S. corporate bonds 320 — 322 — — 322 Non U.S. corporate bonds 50 — 50 — — 50 Equity securities: U.S. equities 271 557 — — — 557 Non U.S. equities 152 234 — — — 234 Total $ 1,591 $ 1,043 $ 441 $ — $ 659 $ 2,143 (a) Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $140 million of equity investments in unconsolidated subsidiaries and $114 million of rabbi trust assets and miscellaneous investments. Dec. 31, 2016 Fair Value (Millions of Dollars) Cost Level 1 Level 2 Level 3 Investments Measured at NAV Total Nuclear decommissioning fund (a) Cash equivalents $ 20 $ 20 $ — $ — $ — $ 20 Commingled funds: Non U.S. equities 261 133 — — 112 245 Emerging market debt funds 93 — — — 98 98 Commodity funds 106 — — — 92 92 Private equity investments 132 — — — 190 190 Real estate 129 — — — 188 188 Other commingled funds 151 — — — 160 160 Debt securities: Government securities 33 — 32 — — 32 U.S. corporate bonds 105 — 106 — — 106 Non U.S. corporate bonds 22 — 21 — — 21 Municipal bonds 14 — 14 — — 14 Mortgage-backed securities 3 — 3 — — 3 Equity securities: U.S. equities 271 474 — — — 474 Non U.S. equities 189 218 — — — 218 Total $ 1,529 $ 845 $ 176 $ — $ 840 $ 1,861 (a) Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $133 million of equity investments in unconsolidated subsidiaries and $98 million of rabbi trust assets and miscellaneous investments. For the years ended Dec. 31, 2017 and 2016 there were no Level 3 nuclear decommissioning fund investments and no transfers of amounts between levels. The following table summarizes the final contractual maturity dates of the debt securities in the nuclear decommissioning fund, by asset class, as of Dec. 31, 2017 : Final Contractual Maturity (Millions of Dollars) Due in 1 Year or Less Due in 1 to 5 Years Due in 5 to 10 Years Due after 10 Years Total Government securities $ — $ 2 $ — $ 67 $ 69 U.S. corporate bonds 5 85 174 58 322 Non U.S. corporate bonds — 15 31 4 50 Debt securities $ 5 $ 102 $ 205 $ 129 $ 441 Rabbi Trusts In June 2016, Xcel Energy established rabbi trusts to provide partial funding for future distributions of its supplemental executive retirement plan and deferred compensation plan. The following table presents the cost and fair value of the assets held in rabbi trusts as of Dec. 31, 2017 and 2016: Dec. 31, 2017 Fair Value (Millions of Dollars) Cost Level 1 Level 2 Level 3 Total Rabbi Trusts (a) Cash equivalents $ 12 $ 12 $ — $ — $ 12 Mutual funds 47 50 — — 50 Total $ 59 $ 62 $ — $ — $ 62 Dec. 31, 2016 Fair Value (Millions of Dollars) Cost Level 1 Level 2 Level 3 Total Rabbi Trusts (a) Cash equivalents $ 48 $ 48 $ — $ — $ 48 Mutual funds 2 2 — — 2 Total $ 50 $ 50 $ — $ — $ 50 (a) Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet. Derivative Instruments Fair Value Measurements Xcel Energy enters into derivative instruments, including forward contracts, futures, swaps and options, for trading purposes and to manage risk in connection with changes in interest rates, utility commodity prices and vehicle fuel prices. Interest Rate Derivatives — Xcel Energy enters into various instruments that effectively fix the interest payments on certain floating rate debt obligations or effectively fix the yield or price on a specified benchmark interest rate for an anticipated debt issuance for a specific period. These derivative instruments are generally designated as cash flow hedges for accounting purposes. As of Dec. 31, 2017, accumulated other comprehensive losses related to interest rate derivatives included $3 million of net losses expected to be reclassified into earnings during the next 12 months as the related hedged interest rate transactions impact earnings, including forecasted amounts for unsettled hedges, as applicable. Wholesale and Commodity Trading Risk — Xcel Energy Inc.’s utility subsidiaries conduct various wholesale and commodity trading activities, including the purchase and sale of electric capacity, energy, energy-related instruments and natural gas-related instruments, including derivatives. Xcel Energy’s risk management policy allows management to conduct these activities within guidelines and limitations as approved by its risk management committee, which is made up of management personnel not directly involved in the activities governed by this policy. 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. As of Dec. 31, 2017, Xcel Energy had various vehicle fuel contracts designated as cash flow hedges extending through December 2018. Xcel Energy enters into derivative instruments that mitigate commodity price risk on behalf of electric and natural gas customers, but may not be designated as qualifying hedging transactions. Changes in the fair value of non-trading commodity derivative instruments are recorded in OCI 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 years ended Dec. 31, 2017 and 2016. As of Dec. 31, 2017, net gains related to commodity derivative cash flow hedges recorded as a component of accumulated other comprehensive losses included immaterial net gains expected to be reclassified into earnings during the next 12 months as the hedged transactions occur. Additionally, Xcel Energy enters into commodity derivative instruments for trading purposes not directly related to commodity price risks associated with serving its electric and natural gas customers. Changes in the fair value of these commodity derivatives are recorded in electric operating revenues, net of amounts credited to customers under margin-sharing mechanisms. The following table details the gross notional amounts of commodity forwards, options and FTRs as of Dec. 31: (Amounts in Millions) (a)(b) 2017 2016 MWh of electricity 68 47 MMBtu of natural gas 37 122 (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. Consideration of Credit Risk and Concentrations — Xcel Energy continuously monitors the creditworthiness of the counterparties to its interest rate derivatives and commodity derivative contracts prior to settlement, and assesses each counterparty’s ability to perform on the transactions set forth in the contracts. Given this assessment, as well as an assessment of the impact of Xcel Energy’s own credit risk when determining the fair value of derivative liabilities, the impact of credit risk was immaterial to the fair value of unsettled commodity derivatives presented in the consolidated balance sheets. Xcel Energy Inc. and its subsidiaries employ additional credit risk control mechanisms when appropriate, such as letters of credit, parental guarantees, standardized master netting agreements and termination provisions that allow for offsetting of positive and negative exposures. Credit exposure is monitored and, when necessary, the activity with a specific counterparty is limited until credit enhancement is provided. Xcel Energy’s utility subsidiaries’ most significant concentrations of credit risk with particular entities or industries are contracts with counterparties to their wholesale, trading and non-trading commodity activities. As of Dec. 31, 2017, four of Xcel Energy’s 10 most significant counterparties for these activities, comprising $45 million or 29 percent of this credit exposure, had investment grade credit ratings from S&P’s, Moody’s or Fitch Ratings. Five of the 10 most significant counterparties, comprising $30 million or 19 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. Another of these significant counterparties, comprising $7 million or 5 percent of this credit exposure, had credit quality less than investment grade, based on ratings from external analysis. Eight of these significant counterparties are municipal or cooperative electric entities or other utilities. Financial Impact of Qualifying Cash Flow Hedges — The impact of qualifying interest rate and vehicle fuel cash flow hedges on Xcel Energy’s accumulated other comprehensive loss, included in the consolidated statements of common stockholders’ equity and in the consolidated statements of comprehensive income, is detailed in the following table: (Millions of Dollars) 2017 2016 2015 Accumulated other comprehensive loss related to cash flow hedges at Jan. 1 $ (51 ) $ (55 ) $ (58 ) After-tax net realized losses on derivative transactions reclassified into earnings 3 4 3 Accumulated other comprehensive loss related to cash flow hedges at Dec. 31 $ (48 ) $ (51 ) $ (55 ) The following tables detail the impact of derivative activity during the years ended Dec. 31, 2017, 2016 and 2015, on accumulated other comprehensive loss, regulatory assets and liabilities, and income: Year Ended Dec. 31, 2017 Pre-Tax Fair Value Gains (Losses) Recognized During the Period in: Pre-Tax (Gains) Losses Reclassified into Income During the Period from: Pre-Tax Gains (Losses) Recognized (Millions of Dollars) Accumulated Regulatory Accumulated Regulatory Derivatives designated as cash flow hedges Interest rate $ — $ — $ 5 (a) $ — $ — Total $ — $ — $ 5 $ — $ — Other derivative instruments Commodity trading $ — $ — $ — $ — $ 10 (b) Electric commodity — 10 — (15 ) (c) — Natural gas commodity — (13 ) — 3 (d) (6 ) (d) Total $ — $ (3 ) $ — $ (12 ) $ 4 Year Ended Dec. 31, 2016 Pre-Tax Fair Value Gains Recognized During the Period in: Pre-Tax (Gains) Losses Reclassified into Income During the Period from: Pre-Tax Gains (Losses) Recognized (Millions of Dollars) Accumulated Regulatory Accumulated Regulatory Derivatives designated as cash flow hedges Interest rate $ — $ — $ 6 (a) $ — $ — Total $ — $ — $ 6 $ — $ — Other derivative instruments Commodity trading $ — $ — $ — $ — $ 2 (b) Electric commodity — 17 — (8 ) (c) — Natural gas commodity — 1 — 15 (d) (8 ) (d) Total $ — $ 18 $ — $ 7 $ (6 ) Year Ended Dec. 31, 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 (Millions of Dollars) Accumulated Regulatory Accumulated Regulatory Derivatives designated as cash flow hedges Interest rate $ — $ — $ 5 (a) $ — $ — Total $ — $ — $ 5 $ — $ — Other derivative instruments Commodity trading $ — $ — $ — $ — $ (7 ) (b) Electric commodity — (19 ) — 16 (c) — Natural gas commodity — (16 ) — 16 (d) (12 ) (d) Total $ — $ (35 ) $ — $ 32 $ (19 ) (a) Amounts are recorded to interest charges. (b) 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. (c) Amounts are recorded to electric fuel and purchased power. These derivative settlement gains and losses are shared with electric customers through fuel and purchased energy cost-recovery mechanisms, and reclassified out of income as regulatory assets or liabilities, as appropriate. (d) Certain derivatives are utilized to mitigate natural gas price risk for electric generation and are recorded to electric fuel and purchased power, subject to cost-recovery mechanisms and reclassified to a regulatory asset, as appropriate. Amounts for the years ended Dec. 31, 2017 and Dec. 31, 2016 included immaterial settlement gains and losses. Amounts for the year ended Dec. 31, 2015 included $1 million of settlement losses. The remaining settlement losses for the years ended Dec. 31, 2017, 2016 and 2015 relate to natural gas operations and are recorded to cost of natural gas sold and transported. These losses are subject to cost-recovery mechanisms and reclassified out of income to a regulatory asset, as appropriate. Xcel Energy had no derivative instruments designated as fair value hedges during the years ended Dec. 31, 2017, 2016 and 2015. Therefore, no gains or losses from fair value hedges or related hedged transactions were recognized for these periods. Credit Related Contingent Features — Contract provisions for derivative instruments that the utility subsidiaries enter, including those accounted for as normal purchase-normal sale contracts and therefore not reflected on the consolidated balance sheets, may require the posting of collateral or settlement of the contracts for various reasons, including if the applicable utility subsidiary’s credit ratings are downgraded below its investment grade credit rating by any of the major credit rating agencies or for cross default contractual provisions that could result in the settlement of such contracts if there was a failure under other financing arrangements related to payment terms or other covenants. As of Dec. 31, 2017 and 2016, there were no derivative instruments in a material liability position with such underlying contract provisions. 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 Dec. 31, 2017 and 2016. Recurring Fair Value Measurements — The following table presents for each of the fair value hierarchy levels, Xcel Energy’s derivative assets and liabilities measured at fair value on a recurring basis as of Dec. 31, 2017: Dec. 31, 2017 Fair Value Fair Value Total Counterparty Netting (b) (Millions of Dollars) Level 1 Level 2 Level 3 Total Current derivative assets Commodity trading $ 2 $ 22 $ — $ 24 $ (15 ) $ 9 Electric commodity — — 32 32 (2 ) 30 Total current derivative assets $ 2 $ 22 $ 32 $ 56 $ (17 ) 39 PPAs (a) 5 Current derivative instruments $ 44 Noncurrent derivative assets Other derivative instruments: Commodity trading $ — $ 31 $ 5 $ 36 $ (7 ) $ 29 Total noncurrent derivative assets $ — $ 31 $ 5 $ 36 $ (7 ) 29 PPAs (a) 19 Noncurrent derivative instruments $ 48 Dec. 31, 2017 Fair Value Fair Value Total Counterparty Netting (b) (Millions of Dollars) Level 1 Level 2 Level 3 Total Current derivative liabilities Other derivative instruments: Commodity trading $ 2 $ 18 $ — $ 20 $ (15 ) $ 5 Electric commodity — — 2 2 (2 ) — Natural gas commodity — 1 — 1 — 1 Total current derivative liabilities $ 2 $ 19 $ 2 $ 23 $ (17 ) 6 PPAs (a) 23 Current derivative instruments $ 29 Noncurrent derivative liabilities Other derivative instruments: Commodity trading $ — $ 24 $ — $ 24 $ (10 ) $ 14 Total noncurrent derivative liabilities $ — $ 24 $ — $ 24 $ (10 ) 14 PPAs (a) 112 Noncurrent derivative instruments $ 126 (a) During 2006, Xcel Energy qualified these contracts under the normal purchase exception. Based on this qualification, the contracts are no longer adjusted to fair value and the previous carrying value of these contracts will be amortized over the remaining contract lives along with the offsetting regulatory assets and liabilities. (b) Xcel Energy nets derivative instruments and related collateral in its consolidated balance sheet when supported by a legally enforceable master netting agreement, and all derivative instruments and related collateral amounts were subject to master netting agreements as of Dec. 31, 2017. At Dec. 31, 2017, derivative assets and liabilities include no obligations to return cash collateral and rights to reclaim cash collateral of $3 million . The counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements. The following table presents for each of the fair value hierarchy levels, Xcel Energy’s derivative assets and liabilities measured at fair value on a recurring basis as of Dec. 31, 2016: Dec. 31, 2016 Fair Value Fair Value Total Counterparty Netting (b) (Millions of Dollars) Level 1 Level 2 Level 3 Total Current derivative assets Other derivative instruments: Commodity trading $ 13 $ 14 $ — $ 27 $ (20 ) $ 7 Electric commodity — — 19 19 (2 ) 17 Natural gas commodity — 9 — 9 — 9 Total current derivative assets $ 13 $ 23 $ 19 $ 55 $ (22 ) 33 PPAs (a) 5 Current derivative instruments $ 38 Noncurrent derivative assets Other derivative instruments: Commodity trading $ — $ 31 $ — $ 31 $ (7 ) $ 24 Natural gas commodity — 2 — 2 — 2 Total noncurrent derivative assets $ — $ 33 $ — $ 33 $ (7 ) 26 PPAs (a) 24 Noncurrent derivative instruments $ 50 Dec. 31, 2016 Fair Value Fair Value Total Counterparty Netting (b) (Millions of Dollars) Level 1 Level 2 Level 3 Total Current derivative liabilities Other derivative instruments: Commodity trading $ 14 $ 11 $ — $ 25 $ (21 ) $ 4 Electric commodity — — 2 2 (2 ) — Total current derivative liabilities $ 14 $ 11 $ 2 $ 27 $ (23 ) 4 PPAs (a) 23 Current derivative instruments $ 27 Noncurrent derivative liabilities Other derivative instruments: Commodity trading $ — $ 24 $ — $ 24 $ (11 ) $ 13 Total noncurrent derivative liabilities $ — $ 24 $ — $ 24 $ (11 ) 13 PPAs (a) 135 Noncurrent derivative instruments $ 148 (a) During 2006, Xcel Energy qualified these contracts under the normal purchase exception. Based on this qualification, the contracts are no longer adjusted to fair value and the previous carrying value of these contracts will be amortized over the remaining contract lives along with the offsetting regulatory assets and liabilities. (b) Xcel Energy nets derivative instruments and related collateral in its consolidated balance sheet when supported by a legally enforceable master netting agreement, and all derivative instruments and related collateral amounts were subject to master netting agreements as of Dec. 31, 2016. At Dec. 31, 2016, derivative assets and liabilities include no obligations to return cash collateral and rights to reclaim cash collateral of $4 million . The counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements. The following table presents the changes in Level 3 commodity derivatives for the years ended Dec. 31, 2017, 2016 and 2015: Year Ended Dec. 31 (Millions of Dollars) 2017 2016 2015 Balance at Jan. 1 $ 17 $ 18 $ 56 Purchases 82 35 64 Settlements (97 ) (89 ) (70 ) Net transactions recorded during the period: Gains recognized in earnings (a) 5 — 2 Net gains (losses) recognized as regulatory assets and liabilities 28 53 (34 ) Balance at Dec. 31 $ 35 $ 17 $ 18 (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 years ended Dec. 31, 2017, 2016 and 2015. Fair Value of Long-Term Debt As of Dec. 31, 2017 and 2016 , other financial instruments for which the carrying amount did not equal fair value were as follows: 2017 2016 (Millions of Dollars) Carrying Amount Fair Value Carrying Amount Fair Value Long-term debt, including current portion $ 14,976 $ 16,531 $ 14,450 $ 15,513 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 Dec. 31, 2017 and 2016 , and given the observability of the inputs to these estimates, the fair values presented for long-term debt have been assigned a Level 2.

Rate Matters

Rate Matters	12 Months Ended
	Dec. 31, 2017
Public Utilities, General Disclosures [Abstract]
Rate Matters	Rate Matters Tax Reform — Regulatory Proceedings The specific impacts of the TCJA on retail customer rates are subject to regulatory approval. Xcel Energy is in the process of quantifying the rate impacts of the TCJA and addressing these impacts in its open and recently concluded proceedings focused on retail base rate impacts for its utility subsidiaries. In addition, several states have opened dockets on the impact of tax reform, with the expectation that currently effective rates in those jurisdictions will be adjusted. NSP-Minnesota — A docket has been opened in Minnesota. NSP-Minnesota will provide a detailed filing to the MPUC by March 2, 2018, which will estimate the impact of the TCJA on the latest electric and natural gas rate case filings and corporate forecasts. Dockets have also been opened in North Dakota and South Dakota. In February 2018, NSP-Minnesota provided the NDPSC a preliminary quantification of the impact of the TCJA on electric and natural gas revenue requirements. NSP-Minnesota proposed multi-year moratoriums on electric and natural gas rate case filings. NSP-Minnesota also filed comments with the SDPUC and proposed using the reduced revenue requirements from the TCJA to defer planned future rate filings. NSP-Wisconsin — In January 2018, the PSCW issued an order requiring public utilities to apply deferred accounting for the impacts of the TCJA. The PSCW has also requested that utilities provide responses to questions on tax reform and its impact on electric and natural gas revenue requirements. In February 2018, NSP-Wisconsin proposed levelizing upcoming rate cases, advancing infrastructure investments and buying down assets such as the regulatory asset for Ashland clean-up. PSCo — The impacts associated with the TCJA on PSCO’s retail customer rates are being addressed in several proceedings, which include the following: • Colorado Statewide TCJA Proceeding — On Jan. 31, 2018, the CPUC opened a statewide TCJA proceeding and ordered deferred accounting for all investor-owned utilities. On Feb. 21, 2017, PSCo filed a response with the CPUC related to the deferred accounting order and statewide TCJA proceeding, addressing the estimated impacts along with other considerations given PSCo’s pending natural gas and electric rate cases. • Colorado 2017 Multi-Year Natural Gas Rate Case — On Feb. 14, 2018, the ALJ approved PSCo and CPUC Staff’s non-unanimous settlement agreement which addresses the impacts of the TCJA in 2018. This settlement agreement includes a $20 million reduction to provisional rates effective March 1, 2018, with future true-ups to be determined later in 2018 once a full analysis of the comprehensive impacts of tax reform is performed, including any outcomes associated with statewide proceeding. The final true-up would provide customers the full net benefit of the TCJA effective Jan. 1, 2018. • Colorado 2017 Multi-Year Electric Rate Case — On Feb. 16, 2018, the CPUC denied the proposed settlement agreement between PSCo and several intervenors, in favor of the state TCJA proceeding. In the second quarter of 2018, PSCo plans to file a revised rate request that will include the impacts of the TCJA. Provisional rates, subject to refund with interest, are expected to be effective June 1, 2018. The appropriate test year and the final approved revenue requirement will be determined in the pending rate case, discussed below. PSCo expects to defer the TCJA net benefits for the first five months of 2018, prior to provisional rates. The CPUC is expected to rule on the regulatory treatment of the TCJA, the natural gas rate case and the electric rate case later in 2018. SPS — On Jan. 25, 2018, the PUCT issued an order requiring utilities to apply deferred accounting for the impacts of the TCJA. On Feb. 16, 2018, SPS provided the PUCT supplemental testimony on the impacts of the TCJA for its ongoing Texas 2017 electric rate case, including increasing its equity ratio to 58 percent to offset the negative impact of the TCJA on its credit metrics and potentially its credit ratings. In February 2018, SPS provided the NMPRC a preliminary quantification of the impacts of the TCJA on its ongoing New Mexico 2017 electric rate case. SPS also recommended increasing its equity ratio to 58 percent to offset the negative impact of the TCJA on its credit metrics and potentially its credit ratings. In a separate NMPRC investigation into the impacts of the TCJA on regulated utilities in New Mexico, SPS provided additional information on the impacts of the TCJA on 2018 operations on Feb. 23, 2018. FERC Formula Rates — The FERC has not yet issued guidance on how and when utilities should reflect the impacts of the TCJA in formula rates. However, FERC-approved formula rates for wholesale customers are generally adjusted on an annual basis for certain changes in rate base and actual operating expenses, including income taxes. As a result, these revenues would be subject to an automatic reduction for the effect of the TCJA tax rate change, absent specific FERC action. NSP-Minnesota and NSP-Wisconsin were parties to a February 2018 FERC filing by MISO and MISO TOs proposing to early commence reductions to transmission formula rates in 2018 for tax rate impacts of the TCJA. Also in February 2018, PSCo made a filing with FERC similarly requesting early reductions in its transmission and production formula rates in 2018 for tax rate impacts of the TCJA. For SPS, as the TCJA tax rate change largely offsets a depreciation rate change that was effective Jan. 1, 2018 in its wholesale production rates, SPS has notified FERC that it will continue to charge rates established in 2017, subject to refund. FERC has not issued any orders on these matters, or commenced any formula rate proceedings related the impacts of the TCJA. NSP-Minnesota Pending and Recently Concluded Regulatory Proceedings — MPUC Minnesota 2016 Multi-Year Electric Rate Case — In June 2017, the MPUC issued a written order approving an estimated total rate increase of approximately $240 million over the four-year period covering 2016-2019. Key terms: • Four -year period covering 2016-2019; • Annual sales true-up with decoupling subject to a 3 percent cap on surcharges; • In February 2018, NSP-Minnesota reported the 2017 sales true-up and revenue decoupling surcharge amounts of $22 million and $27 million , respectively, to be collected beginning April 1, 2018 through March 31, 2019. • ROE of 9.2 percent and an equity ratio of 52.5 percent ; • Nuclear related costs will not be considered provisional; • Continued use of all existing electric riders, however no new electric riders may be utilized during the four -year term; • Deferral of incremental 2016 property tax expense above a fixed threshold to 2018 and 2019; • Four -year stay out provision for rate cases; • Property tax true-up mechanism for 2017-2019; and • Capital expenditure true-up mechanism for 2016-2019. (Millions of Dollars, incremental) 2016 2017 2018 2019 Total Revenues $ 75 $ 55 $ — $ 50 $ 180 NSP-Minnesota’s sales true-up 60 — — — 60 Total rate impact $ 135 $ 55 $ — $ 50 $ 240 Monticello Prudence Investigation — In 2013, NSP-Minnesota completed the Monticello LCM/EPU project. The multi-year project extended the life of the facility and increased the capacity from 600 to 671 MW in 2015. The Monticello LCM/EPU project expenditures were approximately $665 million . Total capitalized costs were approximately $748 million , which includes AFUDC. In 2008, project expenditures were initially estimated at approximately $320 million , excluding AFUDC. In 2015, the MPUC voted to allow for full recovery, including a return, on $415 million of the total plant costs (inclusive of AFUDC), but only allow recovery of the remaining $333 million of costs with no return on this portion of the investment. As a result, Xcel Energy recorded a pre-tax loss of $129 million in the first quarter of 2015, after which the remaining book value of the Monticello project represented the present value of the estimated future cash flows. 2017 and 2018 TCR Filing — In November 2017, NSP-Minnesota submitted a TCR filing with the MPUC, requesting a combined recovery of approximately $110 million of transmission investment costs not included in electric base rates for 2017 and 2018. In accordance with NSP-Minnesota’s most recent electric rate case, three CapX2020 transmission projects currently included in the TCR rider remain in the rider through the multi-year plan period. NSP-Minnesota has also proposed recovery of one additional project related to grid modernization. An MPUC decision is expected in 2018. Electric, Purchased Gas and Resource Adjustment Clauses CIP and CIP Rider — CIP expenses are recovered through base rates and a rider that is adjusted annually. The estimated electric and natural gas incentives for 2017 are expected to be $32 million and $3 million , respectively, based on the approved savings goals in NSP-Minnesota’s CIP Triennial Plan. The plan sets an annual electric goal of saving the equivalent of 1.5 percent of the volume of electric energy sales and an annual natural gas goal of saving 1.0 percent of the volume of gas energy sales. In 2017 the MPUC approved the following for NSP-Minnesota: • The 2016 CIP electric and natural gas financial incentives totaling $48 million and $6 million , respectively; and • The proposed 2017 electric and natural gas CIP riders with estimated 2017 recovery of $59 million of electric CIP expenses and $18 million of natural gas CIP expenses. The proposed recovery through the riders is in addition to an estimated $89 million and $4 million through electric and gas base rates, respectively. GUIC Rider — In February 2018, the MPUC approved a 2017 revenue requirement of approximately $20 million for GUIC investments. New rates are expected to be in effect in March 2018. In November 2017, NSP-Minnesota filed the 2018 GUIC rider with the MPUC requesting recovery of approximately $28 million from Minnesota gas utility customers. Costs in both filings include funding for pipeline assessments as well as deferred costs from NSP-Minnesota’s existing sewer separation and pipeline integrity management programs. The MPUC is currently considering the 2018 petition. Annual Automatic Adjustment of Fuel Clause Charges — In May 2017, the MPUC voted to disallow approximately $4 million of replacement energy costs for the PI nuclear facility outages allocated to the Minnesota jurisdiction in 2015. This disallowance was recognized in the second quarter of 2017. In December 2017, the MPUC issued an order to hold utilities responsible for incremental costs of replacement power incurred due to unplanned outages under certain circumstances. In January 2018, NSP-Minnesota filed a petition for clarification of the order. The outcome of the petition is uncertain. NSP-Wisconsin Recently Concluded Regulatory Proceedings — PSCW Wisconsin 2018 Electric and Gas Rate Case — In May 2017, NSP-Wisconsin filed a request with the PSCW to increase electric rates by $25 million , or 3.6 percent , and natural gas rates by $12 million , or 10.1 percent , effective Jan. 1, 2018. The rate filing was based on a 2018 FTY, a ROE of 10.0 percent , an equity ratio of 52.53 percent and a forecasted rate base of approximately $1.2 billion for the electric utility and $138 million for the natural gas utility. In December 2017, the PSCW approved electric and natural gas rate increases of approximately $9 million , or 1.4 percent , and $10 million , or 8.3 percent , respectively, based on a 9.8 percent ROE and an equity ratio of 51.45 percent . New rates went into effect on Jan. 1, 2018. PSCo Pending Regulatory Proceedings — CPUC Colorado 2017 Multi-Year Electric Rate Case — In October 2017, PSCo filed a multi-year request with the CPUC seeking to increase electric rates approximately $245 million over four years . The request, summarized below, is based on FTY ending Dec. 31, a 10.0 percent ROE and an equity ratio of 55.25 percent . Revenue Request (Millions of Dollars) 2018 2019 2020 2021 Total Revenue request $ 74 $ 75 $ 60 $ 36 $ 245 CACJA revenue conversion to base rates (a) 90 — — — 90 TCA revenue conversion to base rates (a) 43 — — — 43 Total (b) $ 207 $ 75 $ 60 $ 36 $ 378 Expected year-end rate base (billions of dollars) (b) $ 6.8 $ 7.1 $ 7.3 $ 7.4 (a) The roll-in of the TCA and CACJA rider revenues into base rates will not have an impact on customer bills or revenue as these costs are already being recovered through a rider. Transmission investments for 2019-2021 will be recovered through the TCA rider. (b) This base rate request does not include the impacts of the RESA and ECA for the Rush Creek wind investments or the proposed CEP. Key dates in the procedural schedule are as follows: • Supplemental direct testimony — April 16, 2018; • Answer testimony — May 31, 2018; • Rebuttal and cross-answer testimony — July 10, 2018; • Hearings — Aug. 21 - 31, 2018; and • Statement of position — Sept. 28, 2018. Interim rates, subject to refund and interest, are to be effective on June 1, 2018. PSCo also proposed a stay-out provision and earnings test through 2021. On Jan. 31, 2018, the CPUC ordered deferred accounting for the impacts of TCJA and opened a statewide TCJA proceeding, as discussed above. In the second quarter of 2018, PSCo plans to file a revised rate request that will include the impacts of the TCJA. The CPUC is expected to rule on the regulatory treatment of the TCJA and the electric rate case later in 2018. Colorado 2017 Multi-Year Natural Gas Rate Case — In June 2017, PSCo filed a multi-year request with the CPUC seeking to increase retail natural gas rates approximately $139 million over three years . The request, detailed below, is based on FTYs, a 10.0 percent ROE and an equity ratio of 55.25 percent . Revenue Request (Millions of Dollars) 2018 2019 2020 Total Revenue request $ 63 $ 33 $ 43 $ 139 PSIA revenue conversion to base rates (a) — 94 — 94 Total $ 63 $ 127 $ 43 $ 233 Expected year-end rate base (billions of dollars) (b) $ 1.5 $ 2.3 $ 2.4 (a) The roll-in of PSIA rider revenue into base rates will not have an impact on customer bills or revenue as these costs are already being recovered through the rider. The recovery of incremental PSIA related investments in 2019 and 2020 are included in the base rate request. (b) The additional rate base in 2019 predominantly reflects the roll-in of capital associated with the PSIA rider. In October 2017, several parties filed answer testimony. The CPUC Staff (Staff) and the OCC, recommended a single 2016 HTY, based on an average 13 -month rate base, and opposed a multi-year request. The Staff and OCC recommended an equity capital structure of 48.73 percent and 51.2 percent , respectively. Both the Staff and the OCC recommended the existing PSIA rider expire with the 2018 rates rolled into base rates beginning Jan. 1, 2019. Planned investments in 2019 and 2020 would be recoverable through base rates, subject to a future rate case. The final positions of the Staff and OCC provide for a recommended 2018 rate increase of approximately $30 million and $39 million , respectively. In December 2017, hearings before an ALJ were held and the evidentiary record for the case was closed. Provisional rates, subject to refund, were implemented on Jan. 1, 2018. As discussed above, PSCo and the CPUC Staff filed a non-unanimous settlement agreement to address the impacts of the TCJA on rates to be effective in 2018, which was approved by the ALJ. On Jan. 31, 2018, the CPUC ordered deferred accounting for the impacts of TCJA and opened a statewide TCJA proceeding, as discussed above. The CPUC is expected to rule on the regulatory treatment of the TCJA and the natural gas rate case later in 2018. Annual Electric Earnings Test — PSCo must share with customers earnings that exceed the authorized ROE of 9.83 percent for 2015 through 2017, as part of an annual earnings test. PSCo estimates the 2017 earnings test will not result in a customer refund obligation. PSCo will file its 2017 earnings test with the CPUC in April 2018. The final sharing obligation, if any, will be based on the CPUC approved tariff and could vary from the current estimate. Electric, Purchased Gas and Resource Adjustment Clauses DSM and the DSMCA riders — 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. Performance incentives are 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 . In 2017, PSCo earned an electric and natural gas DSM incentive of $11 million and $3 million , respectively, for achieving its 2016 electric and natural gas savings goals. For 2018, the electric energy savings goal is 400 GWh with a spending limit of $84 million . SPS Pending and Recently Concluded Regulatory Proceedings — PUCT Appeal of the Texas 2015 Electric Rate Case Decision — In 2014, SPS had requested an overall retail electric revenue rate increase of $42 million . In 2015, the PUCT approved an overall rate decrease of approximately $4 million , net of rate case expenses. In April 2016, SPS filed an appeal with the Texas State District Court (District Court) challenging the PUCT’s order that had denied SPS’ request for rehearing on certain items in SPS’ Texas 2015 electric rate case related to capital structure, incentive compensation and wholesale load reductions. In March 2017, the District Court denied SPS’ appeal. In April 2017, SPS appealed the District Court’s decision to the Court of Appeals. A decision is pending. Texas 2017 Electric Rate Case — In 2017, SPS filed a $55 million , or 5.8 percent , retail electric, non-fuel base rate increase case in Texas with each of its Texas municipalities and the PUCT. The request was based on the 12 -month period ended June 30, 2017, with the final three months based on estimates, a requested ROE of 10.25 percent , a Texas retail electric rate base of approximately $1.9 billion and an equity ratio of 53.97 percent . The following table summarizes SPS’ rate increase request: Revenue Request (Millions of Dollars) Incremental revenue request $ 69 TCRF revenue conversion to base rates (a) (14 ) Net revenue increase request $ 55 (a) The roll-in of the TCRF rider revenue into base rates will not have an impact on customer bills or revenue as these costs are already being recovered through the rider. SPS can request another TCRF rider after the conclusion of this rate case to recover transmission investments subsequent to June 30, 2017. Key dates in the revised procedural schedule are as follows: • Intervenors’ direct testimony — April 25, 2018; • PUCT Staff direct testimony — May 2, 2018; • PUCT Staff and intervenors’ cross-rebuttal testimony — May 14, 2018; • SPS’ rebuttal testimony — May 23, 2018; and • Hearings — June 4 - 14, 2018. The final rates are expected to be effective retroactive to Jan. 23, 2018 through a customer surcharge. A PUCT decision is expected in the fourth quarter of 2018. As discussed above, the PUCT has opened a docket on the impact of the TCJA, which may have a significant impact on this rate case. On Feb. 16, 2018, SPS provided additional information on the impacts of the TCJA. Pending Regulatory Proceedings — NMPRC Appeal of the New Mexico 2016 Electric Rate Case Dismissal — In November 2016, SPS filed an electric rate case with the NMPRC seeking an increase in base rates of approximately $41 million , representing a total revenue increase of approximately 10.9 percent . The rate filing was based on a requested ROE of 10.1 percent , an equity ratio of 53.97 percent , an electric rate base of approximately $832 million and a FTY ending June 30, 2018. In April 2017, the NMPRC dismissed SPS’ rate case. In May 2017, SPS filed a notice of appeal to the New Mexico Supreme Court. A decision is pending. New Mexico 2017 Electric Rate Case — In October 2017, SPS filed an electric rate case with the NMPRC seeking an increase in retail electric base rates of approximately $43 million . The request is based on a HTY ended June 30, 2017, a ROE of 10.25 percent , an equity ratio of 53.97 percent and a jurisdictional rate base of approximately $885 million , including rate base additions through Nov. 30, 2017. This rate case also takes into account the decline in sales of 380 MW in 2017 from certain wholesale customers and seeks to adjust the life of SPS’ Tolk power plant (Unit 1 from 2042 to 2032 and Unit 2 from 2045 to 2032). Key dates in the procedural schedule are as follows: • Staff and intervenor direct testimony — April 13, 2018; • SPS’ rebuttal testimony — May 2, 2018; and • Hearings — May 15 - 25, 2018. SPS anticipates a decision and implementation of final rates in the second half of 2018. As discussed above, the NMPRC has opened a docket on the impact of the TCJA, which may have a significant impact on this rate case. Pending Regulatory Proceedings — FERC MISO ROE Complaints/ROE Adder — In November 2013, a group of customers filed a complaint at the FERC against MISO TOs, including NSP-Minnesota and NSP-Wisconsin. The complaint argued for a reduction in the ROE in transmission formula rates in the MISO region from 12.38 percent to 9.15 percent , and the removal of ROE adders (including those for RTO membership), effective Nov. 12, 2013. In December 2015, an ALJ recommended the FERC approve a base ROE of 10.32 percent for the MISO TOs. The ALJ found the existing 12.38 percent ROE to be unjust and unreasonable. The recommended 10.32 percent ROE applied a FERC ROE policy adopted in a June 2014 order (Opinion 531). The FERC approved the ALJ recommended 10.32 percent base ROE in an order issued in September 2016. This ROE would be applicable for Nov. 12, 2013 to Feb. 11, 2015, and prospectively from the date of the FERC order. The total prospective ROE would be 10.82 percent , including a 50 basis point adder for RTO membership. Various parties requested rehearing of the September 2016 order. The requests are pending FERC action. In February 2015, a second complaint seeking to reduce the MISO ROE from 12.38 percent to 8.67 percent prior to any adder was filed with the FERC, resulting in a second period of potential refund from Feb. 12, 2015 to May 11, 2016. In June 2016, the ALJ recommended a ROE of 9.7 percent , applying the methodology adopted by the FERC in Opinion 531. In April 2017, the D.C. Circuit vacated and remanded Opinion 531. It is unclear how the D.C. Circuit’s opinion to vacate and remand Opinion 531 will affect the September 2016 FERC order or the timing and outcome of the second ROE complaint. In September 2017, certain MISO TOs (not including NSP-Minnesota and NSP-Wisconsin) filed a motion to dismiss the second ROE complaint. The motion to dismiss is pending FERC action. As of Dec. 31, 2017, NSP-Minnesota has processed the refunds for the Nov. 12, 2013 to Feb. 11, 2015 complaint period based on the 10.32 percent ROE. NSP-Minnesota has also recognized a current refund liability consistent with the best estimate of the final ROE for the Feb. 12, 2015 to May 11, 2016 complaint period. SPP OATT Upgrade Costs — Under the SPP OATT, costs of participant-funded, or “sponsored,” transmission upgrades may be recovered from other SPP customers whose transmission service depends on capacity enabled by the upgrade. The SPP OATT has allowed SPP to charge for these upgrades since 2008, but SPP had not been charging its customers for these upgrades. In 2016, the FERC granted SPP’s request to recover the charges not billed since 2008. SPP subsequently billed SPS approximately $13 million for these charges. SPP is also billing SPS ongoing charges of approximately $0.5 million per month. SPS is currently seeking recovery of these SPP charges in its pending Texas and New Mexico base rate cases. In October 2017, SPS filed a complaint against SPP regarding the amounts billed asserting that SPP has assessed upgrade charges to SPS even where SPS’ transmission service was not dependent upon the upgrade as required by the SPP OATT. If SPS’ complaint results in additional charges or refunds, SPS will seek to recover or refund the differential in future rate proceedings.

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2017
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	Commitments and Contingencies Commitments Capital Commitments — Xcel Energy has made commitments in connection with a portion of its projected capital expenditures. Xcel Energy’s capital commitments primarily relate to the following major projects: NSP-Minnesota Upper Midwest Wind Projects — NSP-Minnesota has gained approval to build and own 1,150 MW of new wind generation in the Upper Midwest. NSP-Minnesota is also seeking approval from the MPUC to build and own the Dakota Range project, a 300 MW wind project in South Dakota. PSCo Advanced Grid Intelligence and Security Initiative — PSCo is pursuing projects to update and advance its electric distribution grid to increase reliability and security standards, meet customer expectations, offer additional customer choice and control over energy usage and implement new rate structures. PSCo Rush Creek Wind Farm — PSCo has gained approval to build, own and operate a 600 MW wind generation facility and proposed transmission line in Colorado. PSCo Gas Transmission Integrity Management Programs — PSCo is proactively identifying and addressing the safety and reliability of natural gas transmission pipelines. The pipeline integrity efforts include primarily pipeline assessment and maintenance projects. PSCo Electric Distribution Integrity Management Programs — PSCo is assessing aging infrastructure for distribution assets and replacing worn components to increase system performance. SPS Transmission NTC — SPS has accepted NTCs for several hundred miles of transmission line and related substation projects based on needs identified through SPP’s various planning processes, including those associated with economics, reliability, generator interconnection and the load addition processes. Most significant are the 345 KV transmission line from TUCO to Yoakum County to Hobbs Plant and the Hobbs Plant to China Draw 345 KV transmission lines. SPS New Mexico and Texas Wind Projects — SPS is seeking approval from the NMPRC and the PUCT to build, own and operate 1,000 MW of new wind generation through the addition of two wind generation facilities in New Mexico and Texas. Fuel Contracts — Xcel Energy has entered into various long-term commitments for the purchase and delivery of a significant portion of its current coal, nuclear fuel and natural gas requirements. These contracts expire in various years between 2018 and 2060 . Xcel Energy is required to pay additional amounts depending on actual quantities shipped under these agreements. The estimated minimum purchases for Xcel Energy under these contracts as of Dec. 31, 2017 are as follows: (Millions of Dollars) Coal Nuclear fuel Natural gas supply Natural gas storage and transportation 2018 $ 655 $ 61 $ 391 $ 263 2019 255 118 288 251 2020 146 34 277 237 2021 59 85 280 227 2022 59 66 127 217 Thereafter 186 379 57 1,046 Total $ 1,360 $ 743 $ 1,420 $ 2,241 Additional expenditures for fuel and natural gas storage and transportation will be required to meet expected future electric generation and natural gas needs. Xcel Energy’s risk of loss, in the form of increased costs from market price changes in fuel, is mitigated through the use of natural gas and energy cost-rate adjustment mechanisms, which provide for pass-through of most fuel, storage and transportation costs to customers. PPAs — NSP Minnesota, PSCo and SPS have entered into PPAs with other utilities and energy suppliers with expiration dates through 2039 for purchased power to meet system load and energy requirements and meet operating reserve obligations. In general, these agreements provide for energy payments, based on actual energy delivered and capacity payments. Certain PPAs accounted for as executory contracts also contain minimum energy purchase commitments. Capacity and energy payments are typically contingent on the IPPs meeting contract obligations, including plant availability requirements. Contractual payments are adjusted based on market indices. The effects of price adjustments on our financial results are mitigated through purchased energy cost recovery mechanisms. Included in electric fuel and purchased power expenses for PPAs accounted for as executory contracts were payments for capacity of $168 million , $191 million and $231 million in 2017 , 2016 and 2015 , respectively. At Dec. 31, 2017 , the estimated future payments for capacity and energy that the utility subsidiaries of Xcel Energy are obligated to purchase pursuant to these executory contracts, subject to availability, are as follows: (Millions of Dollars) Capacity Energy (a) 2018 $ 133 $ 93 2019 87 99 2020 68 105 2021 73 140 2022 77 155 Thereafter 205 368 Total $ 643 $ 960 (a) Excludes contingent energy payments for renewable energy PPAs. Additional energy payments under these PPAs and PPAs accounted for as operating leases will be required to meet expected future electric demand. Leases — Xcel Energy leases a variety of equipment and facilities. Three of these leases are accounted for as capital leases. The assets and liabilities at the inception of a capital lease are recorded at the lower of fair market value or the present value of future lease payments and are amortized over the term of the contract. WYCO is a joint venture with CIG to develop and lease natural gas pipeline, storage, and compression facilities. Xcel Energy Inc. has a 50 percent ownership interest in WYCO. WYCO generally leases its facilities to CIG, and CIG operates the facilities, providing natural gas storage services to PSCo under separate service agreements. PSCo accounts for its Totem natural gas storage service arrangement with CIG as a capital lease. As a result, PSCo had $124 million and $127 million of capital lease obligations as of Dec. 31, 2017 and 2016 , respectively. Xcel Energy Inc. eliminates 50 percent of the capital lease obligation related to WYCO in the consolidated balance sheet along with an equal amount of Xcel Energy Inc.’s equity investment in WYCO. PSCo records amortization for its capital leases as cost of natural gas sold and transported on the consolidated statements of income. Total amortization expenses under capital lease assets were approximately $5 million , $8 million and $8 million for 2017 , 2016 and 2015 , respectively. Following is a summary of property held under capital leases: (Millions of Dollars) Dec. 31, 2017 Dec. 31, 2016 Gas storage facilities $ 201 $ 201 Gas pipeline 21 21 Property held under capital leases 222 222 Accumulated depreciation (71 ) (66 ) Total property held under capital leases, net $ 151 $ 156 The remainder of the leases, primarily for office space, railcars, generating facilities, natural gas pipeline transportation, vehicles, aircraft and power-operated equipment, are accounted for as operating leases. Total expenses under operating lease obligations for Xcel Energy were approximately $246 million , $255 million and $265 million for 2017 , 2016 and 2015 , respectively. These expenses include capacity payments for PPAs accounted for as operating leases of $210 million , $216 million and $224 million in 2017 , 2016 and 2015 , respectively, recorded to electric fuel and purchased power expenses. Included in the future commitments under operating leases are estimated future capacity payments under PPAs that have been accounted for as operating leases in accordance with the applicable accounting guidance. Future commitments under operating and capital leases are: (Millions of Dollars) Operating Leases PPA (a) (b) Operating Leases Total Leases Capital Leases 2018 $ 25 $ 213 $ 238 $ 15 2019 30 230 260 14 2020 24 244 268 14 2021 24 246 270 14 2022 22 235 257 12 Thereafter 148 1,682 1,830 233 Total minimum obligation 302 Interest component of obligation (213 ) Present value of minimum obligation $ 89 (c) (a) Amounts do not include PPAs accounted for as executory contracts. (b) PPA operating leases contractually expire through 2039 . (c) Future commitments exclude certain amounts related to Xcel Energy’s 50 percent ownership interest in WYCO. Variable Interest Entities — The accounting guidance for consolidation of VIEs requires enterprises to consider the activities that most significantly impact an entity’s financial performance, and power to direct those activities, when determining whether an enterprise is a VIE’s primary beneficiary. PPAs — Under certain PPAs, NSP-Minnesota, PSCo and SPS purchase power from IPPs 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. In addition, certain solar PPAs provide the utility subsidiaries with an option to purchase emission allowances or sharing provisions related to production credits generated by the solar facility under contract. These specific PPAs create a variable interest in the IPP. Xcel Energy has determined that certain IPPs are VIEs. Xcel Energy is not subject to risk of loss from the operations of these entities, and no significant financial support has been, or is required to be provided other than contractual payments for energy and capacity set forth in the PPAs. Xcel Energy has evaluated each of these VIEs for possible consolidation, including review of qualitative factors such as the length and terms of the contract, control over O&M, control over dispatch of electricity, historical and estimated future fuel and electricity prices, and financing activities. 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. Xcel Energy’s utility subsidiaries had approximately 3,537 MW of capacity under long-term PPAs at both Dec. 31, 2017 and 2016 with entities that have been determined to be VIEs. These agreements have expiration dates through the year 2041 . Fuel Contracts — SPS purchases all of its coal requirements for its Harrington and Tolk electric generating stations from TUCO under contracts for those facilities that will expire in December 2022 . TUCO arranges for the purchase, receiving, transporting, unloading, handling, crushing, weighing, and delivery of coal to meet SPS’ requirements. TUCO is responsible for negotiating and administering contracts with coal suppliers, transporters and handlers. No significant financial support has been, or is required to be provided to TUCO by SPS, other than contractual payments for delivered coal. However, the fuel contracts create a variable interest in TUCO due to SPS’ reimbursement of certain fuel procurement costs. SPS has determined that TUCO is a VIE. SPS has concluded that it is not the primary beneficiary of TUCO because SPS does not have the power to direct the activities that most significantly impact TUCO’s economic performance. Low-Income Housing Limited Partnerships — Eloigne and NSP-Wisconsin have entered into limited partnerships for the construction and operation of affordable rental housing developments which qualify for low-income housing tax credits. Xcel Energy Inc. has determined Eloigne and NSP-Wisconsin’s low-income housing limited partnerships to be VIEs primarily due to contractual arrangements within each limited partnership that establish sharing of ongoing voting control and profits and losses that does not consistently align with the partners’ proportional equity ownership. Xcel Energy Inc. has determined that Eloigne and NSP-Wisconsin have the power to direct the activities that most significantly impact these entities’ economic performance, and therefore Xcel Energy Inc. consolidates these limited partnerships in its consolidated financial statements. Equity financing for these entities has been provided by Eloigne, NSP-Wisconsin and the general partner of each limited partnership. Xcel Energy’s risk of loss is limited to its capital contributions, adjusted for any distributions and its share of undistributed profits and losses; no significant additional financial support has been, or is required to be provided to the limited partnerships by Eloigne or NSP-Wisconsin. Obligations of the limited partnerships are generally secured by the housing properties of each limited partnership, and the creditors of each limited partnership have no significant recourse to Xcel Energy Inc. or its subsidiaries. Likewise, the assets of the limited partnerships may only be used to settle obligations of the limited partnerships, and not those of Xcel Energy Inc. or its subsidiaries. Amounts reflected in Xcel Energy’s consolidated balance sheets for the Eloigne and NSP-Wisconsin low-income housing limited partnerships include the following: (Millions of Dollars) Dec. 31, 2017 Dec. 31, 2016 Current assets $ 6 $ 7 Property, plant and equipment, net 46 50 Other noncurrent assets 1 1 Total assets $ 53 $ 58 Current liabilities $ 9 $ 8 Mortgages and other long-term debt payable 26 30 Other noncurrent liabilities 1 1 Total liabilities $ 36 $ 39 Technology Agreements — Xcel Energy has a contract that extends through December 2022 with International Business Machines Corp. (IBM) for information technology services. The contract is cancelable at Xcel Energy’s option, although Xcel Energy would be obligated to pay 50 percent of the contract value for early termination. Xcel Energy capitalized or expensed $98 million , $119 million and $109 million associated with the IBM contract in 2017 , 2016 and 2015 , respectively. Xcel Energy’s contract with Accenture for information technology services extends through December 2020 . The contract is cancelable at Xcel Energy’s option, although there are financial penalties for early termination. Xcel Energy capitalized or expensed $16 million , $35 million and $17 million associated with the Accenture contract in 2017 , 2016 and 2015 , respectively. Committed minimum payments under these obligations are as follows: (Millions of Dollars) IBM Agreement Accenture Agreement 2018 $ 26 $ 11 2019 26 11 2020 8 11 2021 8 — 2022 3 — Thereafter — — Guarantees and Indemnifications Xcel Energy Inc. and its subsidiaries provide guarantees and bond indemnities under specified agreements or transactions, which guarantee payment or performance. Xcel Energy Inc.’s exposure is based upon the net liability of the relevant subsidiary under the specified agreements or transactions. Most of the guarantees and bond indemnities issued by Xcel Energy Inc. and its subsidiaries limit the exposure to a maximum stated amount. As of Dec. 31, 2017 and 2016 , Xcel Energy Inc. and its subsidiaries had no assets held as collateral related to their guarantees, bond indemnities and indemnification agreements. Guarantees and Surety Bonds The following table presents guarantees and bond indemnities issued and outstanding as of Dec. 31, 2017 : (Millions of Dollars) Guarantor Guarantee Amount Current Exposure Triggering Event Guarantee of customer loans for the Farm Rewiring Program (a) NSP-Wisconsin $ 1.0 $ — (f) Guarantee of the indemnification obligations of Xcel Energy Services Inc. under the aircraft leases (b) Xcel Energy Inc. 12.0 — (g) Guarantee of residual value of assets under the Bank of Tokyo-Mitsubishi Capital Corporation Equipment Leasing Agreement (c) NSP-Minnesota 4.8 — (h) Guarantee of loan for Hiawatha Collegiate High School (d) Xcel Energy Inc. 1.0 — (g) Total guarantees issued $ 18.8 $ — Guarantee performance and payment of surety bonds for Xcel Energy Inc.’s utility subsidiaries (e) Xcel Energy Inc. $ 53.1 (j) (i) (a) The term of this guarantee expires in 2020 , which is the final scheduled repayment date for the loans. As of Dec. 31, 2017, no claims had been made by the lender. (b) The terms of this guarantee expires in 2021 and 2023 when the associated leases expire. (c) The term of this guarantee expires in 2019 when the associated lease expires. (d) The term of this guarantee expires the earlier of 2024 or full repayment of the loan. (e) The surety bonds primarily relate to workers compensation benefits and utility projects. The workers compensation bonds are renewed annually and the project based bonds expire in conjunction with the completion of the related projects. (f) The debtor becomes the subject of bankruptcy or other insolvency proceedings. (g) Nonperformance and/or nonpayment. (h) Actual fair value of leased assets is less than the guaranteed residual value amount at the end of the lease term. (i) Failure of any one of Xcel Energy Inc.’s utility subsidiaries to perform under the agreement that is the subject of the relevant bond. In addition, per the indemnity agreement between Xcel Energy Inc. and the various surety companies, the surety companies have the discretion to demand that collateral be posted. (j) Due to the magnitude of projects associated with the surety bonds, the total current exposure of this indemnification cannot be determined. Xcel Energy Inc. believes the exposure to be significantly less than the total amount of the outstanding bonds. Indemnification Agreements Xcel Energy Inc. and its subsidiaries provide indemnifications through contracts entered into in the normal course of business. These are primarily indemnifications against adverse litigation outcomes in connection with underwriting agreements, as well as breaches of representations and warranties, including corporate existence, transaction authorization and income tax matters with respect to assets sold. Xcel Energy Inc.’s and its subsidiaries’ obligations under these agreements may be limited in terms of duration and amount. The maximum future payments under these indemnifications cannot be reasonably estimated as the dollar amounts are often not explicitly stated. Environmental Contingencies Xcel Energy has been or is currently involved with the cleanup of contamination from certain hazardous substances at several sites. In many situations, the subsidiary involved believes it will recover some portion of these costs through insurance claims. Additionally, where applicable, the subsidiary involved is pursuing, or intends to pursue, recovery from other PRPs and through the regulated rate process. New and changing federal and state environmental mandates can also create added financial liabilities for Xcel Energy, which are normally recovered through the regulated rate process. To the extent any costs are not recovered through the options listed above, Xcel Energy would be required to recognize an expense. Site Remediation — Various federal and state environmental laws impose liability, without regard to the legality of the original conduct, where hazardous substances or other regulated materials have been released to the environment. Xcel Energy Inc.’s subsidiaries may sometimes pay all or a portion of the cost to remediate sites where past activities of their predecessors or other parties have caused environmental contamination. Environmental contingencies could arise from various situations, including sites of former MGPs operated by Xcel Energy Inc.’s subsidiaries or their predecessors, or other entities; and third-party sites, such as landfills, for which one or more of Xcel Energy Inc.’s subsidiaries are alleged to be a PRP that sent wastes to that site. MGP Sites Ashland MGP Site — NSP-Wisconsin was named a PRP for contamination at a site in Ashland, Wis. The Ashland/Northern States Power Lakefront Superfund Site (the Site) includes NSP-Wisconsin property, previously operated as a MGP facility (the Upper Bluff), and two other properties: an adjacent city lakeshore park area (Kreher Park); and an area of Lake Superior’s Chequamegon Bay adjoining the park. In 2012, NSP-Wisconsin agreed to remediate the Phase I Project Area (which includes the Upper Bluff and Kreher Park areas of the Site), under a settlement agreement with the EPA. In January 2017, NSP-Wisconsin agreed to remediate the Phase II Project Area (the Sediments), under a settlement agreement with the EPA. The settlement agreements were approved by the U.S. District Court for the Western District of Wisconsin. NSP-Wisconsin initiated a full scale wet dredge remedy of the Sediments in 2017. Going forward, NSP-Wisconsin anticipates completion of restoration activities of the Sediments in 2018 with finalization of Phase I Project Area construction and restoration activities in 2019. Groundwater treatment activities at the Site will continue. The current cost estimate for the entire site (both Phase I Project Area and the Sediments) is approximately $168 million , of which approximately $138 million has been spent. As of Dec. 31, 2017 and 2016, NSP-Wisconsin had recorded a total liability of $30 million and $64 million , respectively, for the entire site. NSP-Wisconsin has deferred the unrecovered portion of the estimated Site remediation costs as a regulatory asset. The PSCW has authorized NSP-Wisconsin rate recovery for all remediation costs incurred at the Site. In 2012, the PSCW agreed to allow NSP-Wisconsin to pre-collect certain costs, to amortize costs over a ten -year period and to apply a three percent carrying cost to the unamortized regulatory asset. In December 2017, the PSCW approved an NSP-Wisconsin natural gas rate case, which included recovery of additional expenses associated with remediating the Site. The annual recovery of MGP clean-up costs will increase from $12 million in 2017 to $18 million in 2018. Fargo, N.D. MGP Site — In May 2015, underground pipes, tars and impacted soils were discovered in a right-of-way in Fargo, N.D. that appeared to be associated with a former MGP operated by NSP-Minnesota or prior companies. NSP-Minnesota removed impacted soils and other materials and commenced an investigation of the historic MGP and adjacent properties (the Fargo MGP Site). The North Dakota Department of Health approved NSP-Minnesota’s proposed cleanup plan in January 2017, which involves targeted source removal of impacted soils and historic MGP infrastructure. It is anticipated that remediation activities will be performed in 2018. NSP-Minnesota has also initiated insurance recovery litigation in North Dakota. The U.S. District Court for the District of North Dakota agreed to the parties’ request for a stay of the litigation until May 31, 2018. NSP-Minnesota had recorded an estimated liability of $16 million as of Dec. 31, 2017, and $11 million as of Dec. 31, 2016, for the Fargo MGP Site. The current cost estimate for the remediation of the site is approximately $23 million , of which approximately $7 million has been spent. NSP-Minnesota has deferred Fargo MGP Site costs allocable to the North Dakota jurisdiction, or approximately 88 percent of all remediation costs, as approved by the NDPSC. In December 2017, NSP-Minnesota filed a request with the MPUC to defer post-2017 expenditures allocable to the Minnesota jurisdiction. Other MGP, Landfill or Disposal Sites — Xcel Energy is currently involved in investigating and/or remediating several MGP, landfill or other disposal sites. Xcel Energy has identified twelve sites across its service territories in addition to the sites in Ashland and Fargo, where contamination is present and where investigation and/or remediation activities are currently underway. Other parties may have responsibility for some portion of the investigation and/or remediation activities that are underway. Xcel Energy anticipates that these investigation or remediation activities will continue through at least 2018. Xcel Energy had accrued $4 million as of Dec. 31, 2017 and $2 million as of Dec. 31, 2016 for all of these sites. There may be insurance recovery and/or recovery from other PRPs that will offset any costs incurred. Xcel Energy anticipates that any amounts spent will be fully recovered from customers. Environmental Requirements Water and Waste Asbestos Removal — Some of Xcel Energy’s facilities contain asbestos. Most asbestos will remain undisturbed until the facilities that contain it are demolished or removed. Xcel Energy has recorded an estimate for final removal of the asbestos as an ARO. It may be necessary to remove some asbestos to perform maintenance or make improvements to other equipment. The cost of removing asbestos as part of other work is not expected to be material and is recorded as incurred as operating expenses for maintenance projects, capital expenditures for construction projects or removal costs for demolition projects. 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 2015, the EPA published a final rule regulating the management, storage, and disposal of coal combustion residuals (CCRs) as a nonhazardous waste (CCR Rule). Industry and environmental non-governmental organizations sought judicial review of the final CCR Rule, but a final decision has not been issued in that litigation. The EPA announced in late 2017 its intent to revise the CCR Rule. It is anticipated that the EPA will publish the revised rule in the first quarter of 2018. Under the CCR Rule, utilities were required to complete groundwater sampling around their CCR landfills and surface impoundments and to analyze the results by early 2018 to determine if there were any statistically significant increases (SSIs) above background levels of certain constituents in the groundwater. Xcel Energy has identified SSIs at several sites located in Colorado and one site in Minnesota. Going forward, Xcel Energy will either conduct additional groundwater sampling to determine whether another source besides plant operations is impacting groundwater and/or to determine if corrective action is needed. Several Xcel Energy sites where SSIs were identified were already undergoing cessation of coal operations and closure of the on-site coal units and therefore no further corrective action is expected at those sites. Until a final decision is reached in the litigation, the EPA publishes its revised rule, and Xcel Energy completes additional groundwater sampling, it is uncertain what impact, if any, there will be on the operations, financial position or cash flows of Xcel Energy. Xcel Energy believes that any associated costs would be recoverable through regulatory mechanisms. Federal CWA Waters of the United States Rule — In 2015, the EPA and the U.S. Army Corps of Engineers (Corps) published a final rule that significantly expanded the types of water bodies regulated under the CWA and broadened the scope of waters subject to federal jurisdiction. In October 2015, the U.S. Court of Appeals for the Sixth Circuit issued a nationwide stay of the final rule and subsequently ruled that it, rather than the federal district courts, had jurisdiction over challenges to the rule. In January 2017, the U.S. Supreme Court agreed to resolve the dispute as to which court should hear challenges to the rule. A ruling is expected in 2018. In February 2017, President Trump issued an executive order requiring the EPA and the Corps to review and revise the final rule. In June 2017, the agencies issued a proposed rule that rescinds the final rule and reinstates the prior definition of “Water of the U.S.” The agencies are also undertaking a rulemaking to develop a new definition of “Waters of the U.S.” Federal CWA Effluent Limitations Guidelines (ELG) — In 2015, the EPA issued a final ELG rule for power plants that use coal, natural gas, oil or nuclear materials as fuel and discharge treated effluent to surface waters as well as utility-owned landfills that receive coal combustion residuals. In 2017, the EPA delayed the compliance date for flue gas desulfurization wastewater and bottom ash transport until November 2020 while the agency conducts a rulemaking process to potentially revise the effluent limitations and pretreatment standards for these waste streams. Federal CWA Section 316(b) — The federal CWA requires the EPA to regulate cooling water intake structures to assure that these structures reflect the best technology available for minimizing adverse environmental impacts to aquatic species. The EPA published the final 316(b) rule in 2014. The rule prescribes technology for protecting fish that get stuck on plant intake screens (known as impingement) and describes a process for site-specific determinations by each state for sites that must protect the small aquatic organisms that pass through the intake screens into the plant cooling systems (known as entrainment). For Xcel Energy, these requirements will primarily impact plants at NSP-Minnesota. Xcel Energy estimates the likely cost for complying with impingement requirements may be incurred between 2018 and 2027 and is approximately $41 million with the majority needed for NSP-Minnesota. Xcel Energy believes at least six NSP-Minnesota plants and two NSP-Wisconsin plants could be required by state regulators to make improvements to reduce entrainment. The exact total cost of the entrainment improvements is uncertain, but could be up to $192 million . Xcel Energy anticipates these costs will be fully recoverable in rates. Air GHG Emission Standard for Existing Sources (CPP) — In 2015, the EPA issued its final CPP rule for existing power plants. Among other things, the CPP requires that state plans include enforceable measures to ensure emissions from existing power plants achieve the EPA’s state-specific interim and final emission performance targets. The CPP was challenged by multiple parties in the D.C. Circuit Court. In February 2016, the U.S. Supreme Court issued an order staying the final CPP rule. The stay will remain in effect until the D.C. Circuit Court reaches its decision and the U.S. Supreme Court either declines to review the lower court’s decision or reaches a decision of its own. In March 2017, President Trump signed an executive order requiring the EPA Administrator to review the CPP rule and if appropriate publish proposed rules suspending, revising or rescinding it. Accordingly, the EPA requested that the D.C. Circuit Court hold the litigation in abeyance until the EPA completes its work under the executive order. The D.C. Circuit granted the EPA’s request and is holding the litigation in abeyance, while considering briefs by the parties on whether the court should remand the challenges to the EPA rather than holding them in abeyance, determining whether and how the court continues or ends the stay that currently applies to the CPP. In October 2017, the EPA published a proposed rule to repeal the CPP, based on an analysis that the CPP exceeds the EPA’s statutory authority under the CAA. In the proposal, the EPA stated it has not yet determined whether it will promulgate a new rule to regulate GHG emissions from existing EGUs. In December 2017, the EPA issued an Advanced Notice of Proposed Rulemaking to take and consider comments on whether to issue a future rule and what such a rule should include. CSAPR — CSAPR addresses long range transport of PM and ozone by requiring reductions in SO 2 and 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. CSAPR was adopted to address interstate emissions impacting downwind states’ attainment of the ozone and particulate NAAQS. As the EPA revises 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 September 2017, the EPA adopted a final rule that withdraws Texas from the CSAPR particle program and determines that further emission reductions in Texas are not needed to address interstate particle transport. Texas is no longer subject to the annual SO 2 and NO X emission budgets under CSAPR. In November 2017, the National Parks Conservation Association and Sierra Club appealed this rule to the D.C. Circuit Court. In January 2018, the Court granted SPS’ motion to intervene in support of the EPA’s final rule. Regional Haze Rules — The regional haze program requires SO 2 , NO X and PM emission controls at power plants and other industrial facilities to reduce visibility impairment in national parks and wilderness areas. The program is divided into two parts: BART and reasonable further progress. The requirements of the first regional haze plans developed by Minnesota and Colorado that apply to NSP-Minnesota and PSCo have been fully approved and implemented. Texas’ first regional haze plan has undergone federal review as described below. BART Determination for Texas: The EPA publish

Nuclear Obligations

Nuclear Obligations	12 Months Ended
	Dec. 31, 2017
Nuclear Obligations [Abstract]
Nuclear Obligations	Nuclear Obligations Fuel Disposal — NSP-Minnesota is responsible for temporarily storing used or spent nuclear fuel from its nuclear plants. The DOE is responsible for permanently storing spent fuel from U.S. nuclear plants, but no such facility is yet available. NSP-Minnesota has funded its portion of the DOE’s permanent disposal program since 1981. Through May 2014, the fuel disposal fees were based on a charge of 0.1 cent per KWh sold to customers from nuclear generation. Since that time, the DOE has set the fee to zero . There were no DOE fuel disposal assessments in 2017 or 2016 . NSP-Minnesota has its own temporary on-site storage facilities for spent fuel at its Monticello and PI nuclear plants, which consist of storage pools and dry cask facilities at both sites. The amount of spent fuel storage capacity is determined by the NRC and the MPUC. The Monticello dry-cask storage facility currently stores 16 of the 30 authorized canisters, and the PI dry-cask storage facility currently stores 40 of the 64 authorized casks. Regulatory Plant Decommissioning Recovery — Decommissioning activities related to NSP-Minnesota’s nuclear facilities are planned to begin at the end of each unit’s operating license and be completed by 2091. NSP-Minnesota’s current operating licenses allow continued use of its Monticello nuclear plant until 2030 and its PI nuclear plant until 2033 for Unit 1 and 2034 for Unit 2. Future decommissioning costs of nuclear facilities are estimated through triennial periodic studies that assess the costs and timing of planned nuclear decommissioning activities for each unit. The MPUC most recently approved NSP-Minnesota’s 2014 nuclear decommissioning study in October 2015. This cost study quantified decommissioning costs in 2014 dollars and utilized escalation rates of 4.36 percent per year for plant removal activities, and 3.36 percent for spent fuel management and site restoration activities over a 60 -year decommissioning scenario. The total obligation for decommissioning is expected to be funded 100 percent by the external decommissioning trust fund when decommissioning commences. NSP-Minnesota’s most recently approved decommissioning study resulted in an annual funding requirement of $14 million to be recovered in utility customer rates which started in 2016. This cost study assumes the external decommissioning fund will earn an after-tax return between 5.23 percent and 6.30 percent . Realized and unrealized gains on fund investments are deferred as an offset of NSP-Minnesota’s regulatory asset for nuclear decommissioning costs. As of Dec. 31, 2017 , NSP-Minnesota has accumulated $2.1 billion of assets held in external decommissioning trusts. The following table summarizes the funded status of NSP-Minnesota’s decommissioning obligation based on parameters established in the most recently approved decommissioning study. Xcel Energy believes future decommissioning costs, if necessary, will continue to be recovered in customer rates. The amounts presented below were prepared on a regulatory basis, and are not recorded in the financial statements for the ARO. Regulatory Basis (Millions of Dollars) 2017 2016 Estimated decommissioning cost obligation from most recently approved study (in 2014 dollars) $ 3,012 $ 3,012 Effect of escalating costs (to 2017 and 2016 dollars, respectively, at 4.36/3.36 percent) 396 258 Estimated decommissioning cost obligation (in current dollars) 3,408 3,270 Effect of escalating costs to payment date (4.36/3.36 percent) 7,797 7,935 Estimated future decommissioning costs (undiscounted) 11,205 11,205 Effect of discounting obligation (using average risk-free interest rate of 2.80 percent and 3.25 percent for 2017 and 2016, respectively) (6,398 ) (7,068 ) Discounted decommissioning cost obligation $ 4,807 $ 4,137 Assets held in external decommissioning trust $ 2,143 $ 1,861 Underfunding of external decommissioning fund compared to the discounted decommissioning obligation 2,664 2,276 Calculations and data used by the regulator in approving NSP-Minnesota’s rates are useful in assessing future cash flows. The regulatory basis information is a means to reconcile amounts previously provided to the MPUC and utilized for regulatory purposes to amounts used for financial reporting. The following table provides a reconciliation of the discounted decommissioning cost obligation - regulated basis to the ARO recorded in accordance with GAAP: (Millions of Dollars) 2017 2016 Discounted decommissioning cost obligation - regulated basis $ 4,807 $ 4,137 Differences in discount rate and market risk premium (1,403 ) (1,044 ) O&M costs not included for GAAP (1,041 ) (844 ) ARO differences between 2017 and 2014 cost studies (489 ) — Nuclear production decommissioning ARO - GAAP $ 1,874 $ 2,249 Decommissioning expenses recognized as a result of regulation for the years ending Dec. 31 were: (Millions of Dollars) 2017 2016 2015 Annual decommissioning recorded as depreciation expense: (a) (b) $ 20 $ 20 $ 7 (a) Decommissioning expense does not include depreciation of the capitalized nuclear asset retirement costs. (b) Decommissioning expenses in 2017 and 2016 include Minnesota’s retail jurisdiction annual funding requirement of approximately $14 million. The 2015 expense was offset by the DOE settlement refund. The 2014 nuclear decommissioning filing approved in 2015 has been used for the regulatory presentation for both 2017 and 2016. The most recent triennial filing was submitted in December 2017 and is currently pending with the MPUC, with an order expected in 2018.

Regulatory Assets and Liabiliti

Regulatory Assets and Liabilities	12 Months Ended
	Dec. 31, 2017
Regulatory Assets and Liabilities Disclosure [Abstract]
Regulatory Assets and Liabilities	15. Regulatory Assets and Liabilities Xcel Energy prepares its consolidated financial statements in accordance with the applicable accounting guidance, as discussed in Note 1. Under this guidance, regulatory assets and liabilities are created for amounts that regulators may allow to be collected, or may require to be paid back to customers in future electric and natural gas rates. Any portion of Xcel Energy’s business that is not regulated cannot establish regulatory assets and liabilities. If changes in the utility industry or the business of Xcel Energy no longer allow for the application of regulatory accounting guidance under GAAP, Xcel Energy would be required to recognize the write-off of regulatory assets and liabilities in net income or OCI. The components of regulatory assets shown on the consolidated balance sheets at Dec. 31, 2017 and 2016 are: (Millions of Dollars) See Note(s) Remaining Dec. 31, 2017 Dec. 31, 2016 Regulatory Assets Current Noncurrent Current Noncurrent Pension and retiree medical obligations (a) 9 Various $ 91 $ 1,499 $ 89 $ 1,549 Net AROs (b) 1, 13, 14 Plant lives — 301 — 379 Excess deferred taxes - TCJA 6 Various — 254 — — Recoverable deferred taxes on AFUDC recorded in plant (c) 1 Plant lives — 244 — 424 Environmental remediation costs 1, 13 Various 16 165 11 165 Contract valuation adjustments (d) 1, 11 Term of related contract 21 93 18 111 Depreciation differences 1 One to fourteen years 20 69 15 90 Purchased power contract costs 13 Term of related contract 3 67 2 70 PI EPU 12 Seventeen years 3 58 3 62 Losses on reacquired debt 4 Term of related debt 5 48 4 23 Conservation programs (e) 1 One to two years 50 32 48 48 State commission adjustments 1 Plant lives 1 29 1 27 Property tax Various 8 24 9 2 Nuclear refueling outage costs 1 One to two years 49 20 49 16 Deferred purchased natural gas and electric energy costs 1 Various 21 13 18 16 Sales true up and revenue decoupling One to two years 37 12 — — Gas pipeline inspection and remediation costs 12 One to two years 24 12 7 14 Renewable resources and environmental initiatives 13 One to three years 48 10 34 23 Other Various 27 55 56 62 Total regulatory assets $ 424 $ 3,005 $ 364 $ 3,081 (a) Includes $179 million and $241 million for the regulatory recognition of the NSP-Minnesota pension expense, of which $9 million and $15 million is included in the current asset at Dec. 31, 2017 and 2016 , respectively. Also included are $8 million and $11 million of regulatory assets related to the nonqualified pension plan, of which $1 million and $3 million is included in the current asset at Dec. 31, 2017 and 2016 , respectively. (b) Includes amounts recorded for future recovery of AROs, less amounts recovered through nuclear decommissioning accruals and gains from decommissioning investments. (c) Includes a write-down of $202 million as a result of the revaluation of deferred tax gross up at the new federal tax rate at Dec. 31, 2017. (d) Includes the fair value of certain long-term PPAs used to meet energy capacity requirements and valuation adjustments on natural gas commodity purchases. (e) Includes costs for conservation programs, as well as incentives allowed in certain jurisdictions. The components of regulatory liabilities shown on the consolidated balance sheets at Dec. 31, 2017 and 2016 are: (Millions of Dollars) See Note(s) Remaining Dec. 31, 2017 Dec. 31, 2016 Regulatory Liabilities Current Noncurrent Current Noncurrent Excess deferred taxes - TCJA (a) 6 Various $ — $ 3,733 $ — $ — Plant removal costs 1, 13 Plant lives — 1,131 — 1,135 Renewable resources and environmental initiatives 12, 13 Various 19 56 5 71 ITC deferrals 1, 6 Various — 42 — 45 Deferred income tax adjustment 1, 6 Various — 38 — 48 Deferred electric, natural gas and steam production costs 1 Less than one year 104 — 98 — Contract valuation adjustments (b) 1, 11 Term of related contract 30 — 22 2 Conservation programs (c) 1, 12 Less than one year 23 — 25 — DOE settlement Less than one year 18 — 20 — Other Various 45 83 51 82 Total regulatory liabilities (d) $ 239 $ 5,083 $ 221 $ 1,383 (a) Primarily relates to the revaluation of recoverable/regulated plant ADIT and $174 million revaluation impact of non-plant ADIT at Dec. 31, 2017. (b) Includes the fair value of certain long-term PPAs used to meet energy capacity requirements and valuation adjustments on natural gas commodity purchases. (c) Includes costs for conservation programs, as well as incentives allowed in certain jurisdictions. (d) Revenue subject to refund of $15 million and $46 million for 2017 and 2016, respectively, is included in other current liabilities. At Dec. 31, 2017 and 2016 , approximately $250 million and $166 million of Xcel Energy’s regulatory assets represented past expenditures not currently earning a return, respectively. This amount primarily includes recoverable purchased natural gas and electric energy costs and certain expenditures associated with pension and renewable resources and environmental initiatives.

Other Comprehensive Income

Other Comprehensive Income	12 Months Ended
	Dec. 31, 2017
Stockholders' Equity Note [Abstract]
Other Comprehensive Income	Other Comprehensive Income Changes in accumulated other comprehensive (loss), net of tax, for the years ended Dec. 31, 2017 and 2016 were as follows: Year Ended Dec. 31, 2017 (Millions of Dollars) Gains and Losses on Cash Flow Hedges Defined Benefit Pension and Postretirement Items Total Accumulated other comprehensive loss at Jan. 1 $ (51 ) $ (59 ) $ (110 ) Other comprehensive loss before reclassifications — (3 ) (3 ) Losses reclassified from net accumulated other comprehensive loss 3 7 10 Net current period other comprehensive income 3 4 7 Adoption of ASU No. 2018-02 (a) (10 ) (12 ) (22 ) Accumulated other comprehensive loss at Dec. 31 $ (58 ) $ (67 ) $ (125 ) (a) In 2017, Xcel Energy implemented ASU No. 2018-02 related to the TCJA, which resulted in reclassification of certain credit balances within net accumulated other comprehensive loss to retained earnings. For further information, see Note 2. Year Ended Dec. 31, 2016 (Millions of Dollars) Gains and Defined Benefit Total Accumulated other comprehensive loss at Jan. 1 $ (55 ) $ (55 ) $ (110 ) Other comprehensive loss before reclassifications — (8 ) (8 ) Losses reclassified from net accumulated other comprehensive loss 4 4 8 Net current period other comprehensive income (loss) 4 (4 ) — Accumulated other comprehensive loss at Dec. 31 $ (51 ) $ (59 ) $ (110 ) Reclassifications from accumulated other comprehensive loss for the years ended Dec. 31, 2017 and 2016 were as follows: Amounts Reclassified from Accumulated Other Comprehensive Loss (Millions of Dollars) Year Ended Dec. 31, 2017 Year Ended Dec. 31, 2016 Losses (gains) on cash flow hedges: Interest rate derivatives $ 5 (a) $ 6 (a) Total, pre-tax 5 6 Tax benefit (2 ) (2 ) Total, net of tax 3 4 Defined benefit pension and postretirement losses (gains): Amortization of net losses 12 (b) 6 (b) Total, pre-tax 12 6 Tax benefit (5 ) (2 ) Total, net of tax 7 4 Total amounts reclassified, net of tax $ 10 $ 8 (a) Included in interest charges. (b) Included in the computation of net periodic pension and postretirement benefit costs. See Note 9 for detail regarding these benefit plans.

Segments and Related Informatio

Segments and Related Information	12 Months Ended
	Dec. 31, 2017
Segment Reporting [Abstract]
Segment Information	Segments and Related Information The regulated electric utility operating results of NSP-Minnesota, NSP-Wisconsin, PSCo and SPS, as well as the regulated natural gas utility operating results of NSP-Minnesota, NSP-Wisconsin and PSCo are each separately and regularly reviewed by Xcel Energy’s chief operating decision maker. Xcel Energy evaluates performance by each utility subsidiary based on profit or loss generated from the product or service provided. These segments are managed separately because the revenue streams are dependent upon regulated rate recovery, which is separately determined for each segment. Xcel Energy has the following reportable segments: regulated electric utility, regulated natural gas utility and all other. • Xcel Energy’s regulated electric utility segment generates, transmits and distributes electricity in 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 wholesale commodity and 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 $140 million and $133 million as of Dec. 31, 2017 and 2016 , respectively, included in the natural gas utility and all other segments. 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. The accounting policies of the segments are the same as those described in Note 1. (Millions of Dollars) Regulated Electric Regulated Natural Gas All Other Reconciling Eliminations Consolidated Total 2017 Operating revenues from external customers $ 9,676 $ 1,650 $ 78 $ — $ 11,404 Intersegment revenues 2 1 — (3 ) — Total revenues $ 9,678 $ 1,651 $ 78 $ (3 ) $ 11,404 Depreciation and amortization $ 1,298 $ 174 $ 7 $ — $ 1,479 Interest charges and financing costs 449 57 122 — 628 Income tax expense (benefit) 528 23 (9 ) — 542 Net income (loss) 1,066 182 (100 ) — 1,148 (Millions of Dollars) Regulated Electric Regulated Natural Gas All Other Reconciling Eliminations Consolidated Total 2016 Operating revenues from external customers $ 9,500 $ 1,531 $ 76 $ — $ 11,107 Intersegment revenues 1 1 — (2 ) — Total revenues $ 9,501 $ 1,532 $ 76 $ (2 ) $ 11,107 Depreciation and amortization $ 1,136 $ 160 $ 7 $ — $ 1,303 Interest charges and financing costs 450 54 116 — 620 Income tax expense (benefit) 567 76 (62 ) — 581 Net income (loss) 1,067 124 (68 ) — 1,123 (Millions of Dollars) Regulated Electric Regulated Natural Gas All Other Reconciling Eliminations Consolidated Total 2015 Operating revenues from external customers $ 9,276 $ 1,672 $ 76 $ — $ 11,024 Intersegment revenues 2 1 — (3 ) — Total revenues $ 9,278 $ 1,673 $ 76 $ (3 ) $ 11,024 Depreciation and amortization $ 963 $ 155 $ 6 $ — $ 1,124 Interest charges and financing costs 426 50 93 — 569 Income tax expense (benefit) 509 60 (26 ) — 543 Net income (loss) 921 106 (43 ) — 984

Summarized Quarterly Financial

Summarized Quarterly Financial Data (Unaudited)	12 Months Ended
	Dec. 31, 2017
Quarterly Financial Information Disclosure [Abstract]
Summarized Quarterly Financial Data (Unaudited)	Summarized Quarterly Financial Data (Unaudited) Quarter Ended (Amounts in millions, except per share data) March 31, 2017 June 30, 2017 Sept. 30, 2017 Dec. 31, 2017 Operating revenues $ 2,946 $ 2,645 $ 3,017 $ 2,796 Operating income 486 460 818 426 Net income 239 227 492 189 EPS total — basic $ 0.47 $ 0.45 $ 0.97 $ 0.37 EPS total — diluted 0.47 0.45 0.97 0.37 Cash dividends declared per common share 0.36 0.36 0.36 0.36 Quarter Ended (Amounts in millions, except per share data) March 31, 2016 June 30, 2016 Sept. 30, 2016 Dec. 31, 2016 Operating revenues $ 2,772 $ 2,500 $ 3,040 $ 2,795 Operating income 490 432 827 465 Net income 241 197 458 227 EPS total — basic $ 0.47 $ 0.39 $ 0.90 $ 0.45 EPS total — diluted 0.47 0.39 0.90 0.45 Cash dividends declared per common share 0.34 0.34 0.34 0.34

Schedule I, Condensed Financial

Schedule I, Condensed Financial Statements of Xcel Energy Inc	12 Months Ended
	Dec. 31, 2017
Condensed Financial Information of Parent Company Only Disclosure [Abstract]
Schedule I, Condensed Financial Information	XCEL ENERGY INC. CONDENSED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME (amounts in millions, except per share data) Year Ended Dec. 31 2017 2016 2015 Income Equity earnings of subsidiaries $ 1,263 $ 1,199 $ 1,046 Total income 1,263 1,199 1,046 Expenses and other deductions Operating expenses 30 22 20 Other income (6 ) (3 ) (1 ) Interest charges and financing costs 128 116 91 Total expenses and other deductions 152 135 110 Income before income taxes 1,111 1,064 936 Income tax benefit (37 ) (59 ) (48 ) Net income $ 1,148 $ 1,123 $ 984 Other Comprehensive Income Pension and retiree medical benefits, net of tax of $3, $(3), and $(3) respectively $ 4 $ (4 ) $ (5 ) Derivative instruments, net of tax of $2, $2, and $2, respectively 3 4 3 Other comprehensive income (loss) 7 — (2 ) Comprehensive income $ 1,155 $ 1,123 $ 982 Weighted average common shares outstanding: Basic 509 509 508 Diluted 509 509 508 Earnings per average common share: Basic $ 2.26 $ 2.21 $ 1.94 Diluted 2.25 2.21 1.94 Cash dividends declared per common share 1.44 1.36 1.28 See Notes to Condensed Financial Statements XCEL ENERGY INC. CONDENSED STATEMENTS OF CASH FLOWS (amounts in millions) Year Ended Dec. 31 2017 2016 2015 Operating activities Net cash provided by operating activities $ 1,208 $ 817 $ 705 Investing activities Capital contributions to subsidiaries (849 ) (414 ) (820 ) Investments in the utility money pool (1,258 ) (1,880 ) (971 ) Return of investments in the utility money pool 1,173 1,880 987 Net cash used in investing activities (934 ) (414 ) (804 ) Financing activities Proceeds from (repayment of) short-term borrowings, net 715 (516 ) 204 Proceeds from issuance of long-term debt — 1,539 495 Repayment of long-term debt (250 ) (704 ) — Proceeds from issuance of common stock — — 7 Repurchase of common stock (3 ) (32 ) — Dividends paid (721 ) (681 ) (607 ) Other (14 ) (9 ) (1 ) Net cash (used in) provided by financing activities (273 ) (403 ) 98 Net change in cash and cash equivalents 1 — (1 ) Cash and cash equivalents at beginning of period — — 1 Cash and cash equivalents at end of period $ 1 $ — $ — See Notes to Condensed Financial Statements XCEL ENERGY INC. CONDENSED BALANCE SHEETS (amounts in millions) Dec. 31 2017 2016 Assets Cash and cash equivalents $ 1 $ — Accounts receivable from subsidiaries 302 364 Other current assets 1 10 Total current assets 304 374 Investment in subsidiaries 14,932 13,904 Other assets 103 163 Total other assets 15,035 14,067 Total assets $ 15,339 $ 14,441 Liabilities and Equity Current portion of long-term debt $ — $ 250 Dividends payable 183 172 Short-term debt 783 68 Other current liabilities 11 18 Total current liabilities 977 508 Other liabilities 29 37 Total other liabilities 29 37 Commitments and contingencies Capitalization Long-term debt 2,878 2,875 Common stockholders’ equity 11,455 11,021 Total capitalization 14,333 13,896 Total liabilities and equity $ 15,339 $ 14,441 See Notes to Condensed Financial Statements NOTES TO CONDENSED FINANCIAL STATEMENTS Incorporated by reference are Xcel Energy’s consolidated statements of common stockholders’ equity and OCI in Part II, Item 8. Basis of Presentation — The condensed financial information of Xcel Energy Inc. is presented to comply with Rule 12-04 of Regulation S-X. Xcel Energy Inc.’s investments in subsidiaries are presented under the equity method of accounting. Under this method, the assets and liabilities of subsidiaries are not consolidated. The investments in net assets of the subsidiaries are recorded in the balance sheets. The income from operations of the subsidiaries is reported on a net basis as equity in income of subsidiaries. As a holding company with no business operations, Xcel Energy Inc.’s assets consist primarily of investments in its utility subsidiaries. Xcel Energy Inc.’s material cash inflows are only from dividends and other payments received from its utility subsidiaries and the proceeds raised from the sale of debt and equity securities. The ability of its utility subsidiaries to make dividend and other payments is subject to the availability of funds after taking into account their respective funding requirements, the terms of their respective indebtedness, the regulations of the FERC under the Federal Power Act, and applicable state laws. Management does not expect maintaining these requirements to have an impact on Xcel Energy Inc.’s ability to pay dividends at the current level in the foreseeable future. Each of its utility subsidiaries, however, is legally distinct and has no obligation, contingent or otherwise, to make funds available to Xcel Energy Inc. Related Party Transactions — Xcel Energy Inc. presents its related party receivables net of payables. Accounts receivable and payable with affiliates at Dec. 31 were: 2017 2016 (Millions of Dollars) Accounts Receivable Accounts Payable Accounts Receivable Accounts Payable NSP-Minnesota $ 68 $ — $ 59 $ — NSP-Wisconsin 13 — 14 — PSCo 69 — 132 — SPS 26 — 31 — Xcel Energy Services Inc. 95 — 93 — Xcel Energy Ventures Inc. 14 — 17 — Other subsidiaries of Xcel Energy Inc. 17 — 18 — $ 302 $ — $ 364 $ — Dividends — Cash dividends paid to Xcel Energy Inc. by its subsidiaries were $1,063 million , $923 million and $784 million for the years ended Dec. 31, 2017 , 2016 and 2015 , respectively. These cash receipts are included in operating cash flows of the condensed statements of cash flows. 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 following tables present money pool lending for Xcel Energy Inc.: (Amounts in Millions, Except Interest Rates) Three Months Ended Dec. 31, 2017 Loan outstanding at period end 85 Average loan outstanding 36 Maximum loan outstanding 85 Weighted average interest rate, computed on a daily basis 1.15 % Weighted average interest rate at end of period 1.18 % Money pool interest income $ 0.1 (Amounts in Millions, Except Interest Rates) Year Ended Dec. 31, 2017 Year Ended Dec. 31, 2016 Year Ended Dec. 31, 2015 Loan outstanding at period end 85 — — Average loan outstanding 38 66 27 Maximum loan outstanding 226 211 141 Weighted average interest rate, computed on a daily basis 1.13 % 0.69 % 0.42 % Weighted average interest rate at end of period 1.18 % N/A N/A Money pool interest income $ 0.4 $ 0.5 $ 0.1 See Xcel Energy’s notes to the consolidated financial statements in Part II, Item 8 for other disclosures.

Schedule II, Valuation and Qual

Schedule II, Valuation and Qualifying Accounts	12 Months Ended
	Dec. 31, 2017
Valuation and Qualifying Accounts [Abstract]
Schedule II, Valuation and Qualifying Accounts	XCEL ENERGY INC. AND SUBSIDIARIES VALUATION AND QUALIFYING ACCOUNTS YEARS ENDED DEC. 31, 2017, 2016 AND 2015 (amounts in millions) Additions Balance at Jan. 1 Charged to Costs and Expenses Charged to Other Accounts (a) Deductions from Reserves (b) Balance at Dec. 31 Allowance for bad debts: 2017 $ 51 $ 39 $ 10 $ 48 $ 52 2016 52 39 11 51 51 2015 58 36 12 54 52 NOL and tax credit valuation allowances: 2017 $ 58 $ 9 $ 22 $ 12 $ 77 2016 28 3 35 8 58 2015 3 2 25 2 28 (a) Accrual of valuation allowance for North Dakota ITC, offset to regulatory liability. (b) Reductions to valuation allowances for North Dakota ITC carryforwards primarily due to a consolidated adjustment to the regulatory liability accrual referenced above. Reductions to valuation allowances for NOL carryforwards primarily due to changes in forecasted taxable income.

Summary of Significant Accoun32

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2017
Accounting Policies [Abstract]
Business and System of Accounts	Business and System of Accounts — Xcel Energy Inc.’s utility subsidiaries are engaged in the regulated generation, purchase, transmission, distribution and sale of electricity and in the regulated purchase, transportation, distribution and sale of natural gas. Xcel Energy’s consolidated financial statements and disclosures are presented in accordance with GAAP. All of the utility subsidiaries’ underlying accounting records also conform to the FERC uniform system of accounts or to systems required by various state regulatory commissions, which are the same in all material respects.
Principles of Consolidation	Principles of Consolidation — In 2017, Xcel Energy’s operations included the activity of NSP-Minnesota, NSP-Wisconsin, PSCo and SPS. These utility subsidiaries serve electric and natural gas customers in portions of Colorado, Michigan, Minnesota, New Mexico, North Dakota, South Dakota, Texas and Wisconsin. Also included in Xcel Energy’s operations are WGI, an interstate natural gas pipeline company, and WYCO, a joint venture with CIG to develop and lease natural gas pipelines, storage and compression facilities. Xcel Energy Inc.’s nonregulated subsidiaries include Eloigne and Capital Services. Eloigne invests in rental housing projects that qualify for low-income housing tax credits. Capital Services procures equipment for construction of renewable generation facilities at other subsidiaries. Xcel Energy Inc. owns the following additional direct subsidiaries, some of which are intermediate holding companies with additional subsidiaries: Xcel Energy Wholesale Group Inc., Xcel Energy Markets Holdings Inc., Xcel Energy Ventures Inc., Xcel Energy Retail Holdings Inc., Xcel Energy Communications Group, Inc., Xcel Energy International Inc., Xcel Energy Transmission Holding Company, LLC, Nicollet Holdings Company, LLC, Nicollet Project Holdings LLC and Xcel Energy Services Inc. Xcel Energy Inc. and its subsidiaries collectively are referred to as Xcel Energy. Xcel Energy’s consolidated financial statements include its wholly-owned subsidiaries and VIEs for which it is the primary beneficiary. In the consolidation process, all intercompany transactions and balances are eliminated. Xcel Energy uses the equity method of accounting for its investment in WYCO. Xcel Energy’s equity earnings in WYCO are included on the consolidated statements of income as equity earnings of unconsolidated subsidiaries. Xcel Energy has investments in several plants and transmission facilities jointly owned with nonaffiliated utilities. Xcel Energy’s proportionate share of jointly owned facilities is recorded as property, plant and equipment on the consolidated balance sheets, and Xcel Energy’s proportionate share of the operating costs associated with these facilities is included in its consolidated statements of income. See Note 5 for further discussion of jointly owned generation, transmission and gas facilities, and related ownership percentages. Xcel Energy evaluates its arrangements and contracts with other entities, including investments, PPAs and fuel contracts, to determine if the other party is a VIE, if Xcel Energy has a variable interest and if Xcel Energy is the primary beneficiary. Xcel Energy follows accounting guidance for VIEs which requires consideration of the activities that most significantly impact an entity’s financial performance and power to direct those activities, when determining whether Xcel Energy is a VIE’s primary beneficiary. See Note 13 for further discussion of VIEs.
Use of Estimates	Use of Estimates — In recording transactions and balances resulting from business operations, Xcel Energy uses estimates based on the best information available. Estimates are used for such items as plant depreciable lives or potential disallowances, AROs, certain regulatory assets and liabilities, tax provisions, uncollectible amounts, environmental costs, unbilled revenues, jurisdictional fuel and energy cost allocations and actuarially determined benefit costs. The recorded estimates are revised when better information becomes available or when actual amounts can be determined. Those revisions can affect operating results.
Regulatory Accounting	Regulatory Accounting — Our regulated utility subsidiaries account for certain income and expense items in accordance with accounting guidance for regulated operations. Under this guidance: • Certain costs, which would otherwise be charged to expense or OCI, are deferred as regulatory assets based on the expected ability to recover the costs in future rates; and • Certain credits, which would otherwise be reflected as income or OCI, are deferred as regulatory liabilities based on the expectation the amounts will be returned to customers in future rates, or because the amounts were collected in rates prior to the costs being incurred. Estimates of recovering deferred costs and returning deferred credits are based on specific ratemaking decisions or precedent for each item. Regulatory assets and liabilities are amortized consistent with the treatment in the rate setting process. If restructuring or other changes in the regulatory environment occur, regulated utility subsidiaries may no longer be eligible to apply this accounting treatment, and may be required to eliminate regulatory assets and liabilities from their balance sheets. Such changes could have a material effect on Xcel Energy’s financial condition, results of operations and cash flows. See Note 15 for further discussion of regulatory assets and liabilities.
Revenue Recognition	Revenue Recognition — Revenues related to the sale of energy are generally recorded when service is rendered or energy is delivered to customers. However, the determination of the energy sales to individual customers is based on the reading of their meter, which occurs on a systematic basis throughout the month. At the end of each month, amounts of energy delivered to customers since the date of the last meter reading are estimated and the corresponding unbilled revenue is recognized. Xcel Energy presents its revenues net of any excise or other fiduciary-type taxes or fees. NSP-Minnesota participates in MISO, and SPS participates in SPP. Xcel Energy’s utility subsidiaries recognize sales to both native load and other end use customers on a gross basis. Revenues and charges for short term wholesale sales of excess energy transacted through RTOs are recorded on a gross basis in electric revenues and cost of sales. Other revenues and charges related to participating and transacting in RTOs are recorded on a net basis in cost of sales. Xcel Energy Inc.’s utility subsidiaries have various rate-adjustment mechanisms in place that provide for the recovery of natural gas, electric fuel and purchased energy costs. These cost-adjustment tariffs may increase or decrease the level of revenue collected from customers and are revised periodically for differences between the total amount collected under the clauses and the costs incurred. When applicable, under governing regulatory commission rate orders, fuel cost over-recoveries (the excess of fuel revenue billed to customers over fuel costs incurred) are deferred as regulatory liabilities and under-recoveries (the excess of fuel costs incurred over fuel revenues billed to customers) are deferred as regulatory assets. Certain rate rider mechanisms qualify as alternative revenue programs under GAAP. These mechanisms arise from costs imposed upon the utility by action of a regulator or legislative body related to an environmental, public safety or other mandate. When certain criteria are met, revenue is recognized equal to the revenue requirement, including return on rate base items, for the qualified mechanisms. The mechanisms are revised periodically for differences between the total amount collected under the riders and the revenue recognized, which may increase or decrease the level of revenue collected from customers.
Conservation Programs	Conservation Programs — Xcel Energy Inc.’s utility subsidiaries have implemented programs in many of their retail jurisdictions to assist customers in reducing peak demand and conserving energy on the electric and natural gas systems. These programs include efficiency and redesign programs, as well as rebates for the purchase of items such as high efficiency lighting. The costs incurred for DSM and CIP programs are deferred if it is probable future revenue will be provided to permit recovery of the incurred cost. Recorded revenues for incentive programs designed for recovery of lost margins and/or conservation performance incentives are limited to amounts expected to be collected within 24 months from the annual period in which they are earned. For PSCo, SPS and NSP-Minnesota, DSM and CIP program costs are recovered through a combination of base rate revenue and rider mechanisms. The revenue billed to customers recovers incurred costs for conservation programs and also incentive amounts that are designed to encourage Xcel Energy’s achievement of energy conservation goals and compensate for related lost sales margin. For these utility subsidiaries, regulatory assets are recognized to reflect the amount of costs or earned incentives that have not yet been collected from customers. NSP-Wisconsin recovers approved conservation program costs in base rate revenue.
Property, Plant and Equipment and Depreciation	Property, Plant and Equipment and Depreciation — Property, plant and equipment is stated at original cost. The cost of plant includes direct labor and materials, contracted work, overhead costs and AFUDC. The cost of plant retired is charged to accumulated depreciation and amortization. Amounts recovered in rates for future removal costs are recorded as regulatory liabilities. Significant additions or improvements extending asset lives are capitalized, while repairs and maintenance costs are charged to expense as incurred. Maintenance and replacement of items determined to be less than a unit of property are charged to operating expenses as incurred. Planned major maintenance activities are charged to operating expense unless the cost represents the acquisition of an additional unit of property or the replacement of an existing unit of property. Property, plant and equipment also includes costs associated with property held for future use. The depreciable lives of certain plant assets are reviewed annually and revised, if appropriate. Property, plant and equipment is tested for impairment when it is determined that the carrying value of the assets may not be recoverable. A loss is recognized in the current period if it becomes probable that part of a cost of a plant under construction or recently completed plant will be disallowed for recovery from customers and a reasonable estimate of the disallowance can be made. See Note 12 for a discussion of the loss recognized in 2015 related to the Monticello LCM/EPU project. For investments in property, plant and equipment that are abandoned and not expected to go into service, incurred costs and related deferred tax amounts are compared to the discounted estimated future rate recovery, and a loss is recognized, if necessary. Xcel Energy records depreciation expense related to its plant using the straight-line method over the plant’s useful life. Actuarial life studies are performed and submitted to the state and federal commissions for review. Upon acceptance by the various commissions, the resulting lives and net salvage rates are used to calculate depreciation. Depreciation expense, expressed as a percentage of average depreciable property, was approximately 3.1 , 2.9 , and 2.8 percent for the years ended Dec. 31, 2017, 2016 and 2015, respectively.
Leases	Leases — Xcel Energy evaluates a variety of contracts for lease classification at inception, including PPAs and rental arrangements for office space, vehicles and equipment. Contracts determined to contain a lease because of per unit pricing that is other than fixed or market price, terms regarding the use of a particular asset, and other factors are evaluated further to determine if the arrangement is a capital lease. See Note 13 for further discussion of leases.
AFUDC	AFUDC — AFUDC represents the cost of capital used to finance utility construction activity. AFUDC is computed by applying a composite financing rate to qualified CWIP. The amount of AFUDC capitalized as a utility construction cost is credited to other nonoperating income (for equity capital) and interest charges (for debt capital). AFUDC amounts capitalized are included in Xcel Energy’s rate base for establishing utility service rates. Generally, AFUDC costs are recovered from customers as the related property is depreciated. However, in some cases commissions have approved a more current recovery of the cost of capital associated with large capital projects, resulting in a lower recognition of AFUDC. In other cases, some commissions have allowed an AFUDC calculation greater than the FERC-defined AFUDC rate, resulting in higher recognition of AFUDC.
Asset Retirement Obligations	AROs — Xcel Energy Inc.’s utility subsidiaries account for AROs under accounting guidance that requires a liability for the fair value of an ARO to be recognized in the period in which it is incurred if it can be reasonably estimated, with the offsetting associated asset retirement costs capitalized as a long-lived asset. The liability is generally increased over time by applying the effective interest method of accretion, and the capitalized costs are depreciated over the useful life of the long-lived asset. Changes resulting from revisions to the timing or amount of expected asset retirement cash flows are recognized as an increase or a decrease in the ARO. Xcel Energy Inc.’s utility subsidiaries also recover through rates certain future plant removal costs in addition to AROs. The accumulated removal costs for these obligations are reflected in the balance sheets as a regulatory liability. See Note 13 for further discussion of AROs.
Nuclear Decommissioning	Nuclear Decommissioning — Nuclear decommissioning studies estimate NSP-Minnesota’s ultimate costs of decommissioning its nuclear power plants and are performed at least every three years and submitted to the MPUC and other state commissions for approval. NSP-Minnesota’s most recent triennial nuclear decommissioning studies were filed with the MPUC in December 2017. These studies reflect NSP-Minnesota’s plans for dismantlement of the Monticello and PI facilities. These studies assume that NSP-Minnesota will store spent fuel on site pending removal to a U.S. government facility. For rate making purposes, NSP-Minnesota recovers the total decommissioning costs related to its nuclear power plants over each facility’s expected service life based on the triennial decommissioning studies filed with the MPUC and other state commissions. The studies consider estimated future costs of decommissioning and the market value of investments in trust funds, and recommend annual funding amounts. Amounts collected in rates are deposited in the trust funds. See Note 14 for further discussion of the approved nuclear decommissioning studies and funded amounts. For financial reporting purposes, NSP-Minnesota accounts for nuclear decommissioning as an ARO as described above. Restricted funds for the payment of future decommissioning expenditures for NSP-Minnesota’s nuclear facilities are included in nuclear decommissioning fund and other assets on the consolidated balance sheets. See Note 11 for further discussion of the nuclear decommissioning fund.
Nuclear Fuel Expense	Nuclear Fuel Expense — Nuclear fuel expense, which is recorded as NSP-Minnesota’s nuclear generating plants use fuel, includes the cost of fuel used in the current period (including AFUDC) and costs associated with the end-of-life fuel segments.
Nuclear Refueling Outage Costs	Nuclear Refueling Outage Costs — Xcel Energy uses a deferral and amortization method for nuclear refueling O&M costs. This method amortizes refueling outage costs over the period between refueling outages consistent with how the costs are recovered ratably in electric rates.
Income Taxes	Income Taxes — Xcel Energy accounts for income taxes using the asset and liability method, which requires the recognition of deferred tax assets and liabilities for the expected future tax consequences of events that have been included in the financial statements. Xcel Energy defers income taxes for all temporary differences between pretax financial and taxable income, and between the book and tax bases of assets and liabilities. Xcel Energy uses the tax rates that are scheduled to be in effect when the temporary differences are expected to reverse. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in the period that includes the enactment date. The effects of tax rate changes that are attributable to the regulated utility subsidiaries are generally subject to a normalization method of accounting. Therefore, the revaluation of most of the utility subsidiaries’ net deferred taxes upon a tax rate reduction results in the establishment of a net regulatory liability which will be refundable to utility customers over the remaining life of the related assets. A tax rate increase would result in the establishment of a similar regulatory asset. Due to the effects of past regulatory practices, when deferred taxes were not required to be recorded due to the use of flow through accounting for ratemaking purposes, the reversal of some temporary differences are accounted for as current income tax expense. Tax credits are recorded when earned unless there is a requirement to defer the benefit and amortize it over the book depreciable lives of the related property. The requirement to defer and amortize tax credits only applies to federal ITCs related to public utility property. Utility rate regulation also has resulted in the recognition of certain regulatory assets and liabilities related to income taxes, which are summarized in Note 15. Deferred tax assets are reduced by a valuation allowance if it is more likely than not that some portion or all of the deferred tax asset will not be realized. In making such a determination, all available evidence is considered, including scheduled reversals of deferred tax liabilities, projected future taxable income, tax planning strategies and recent financial operations. Xcel Energy follows the applicable accounting guidance to measure and disclose uncertain tax positions that it has taken or expects to take in its income tax returns. Xcel Energy recognizes a tax position in its consolidated financial statements when it is more likely than not that the position will be sustained upon examination based on the technical merits of the position. Recognition of changes in uncertain tax positions are reflected as a component of income tax. Xcel Energy reports interest and penalties related to income taxes within the other income and interest charges sections in the consolidated statements of income. Xcel Energy Inc. and its subsidiaries file consolidated federal income tax returns as well as combined or separate state income tax returns. Federal income taxes paid by Xcel Energy Inc. are allocated to Xcel Energy Inc.’s subsidiaries based on separate company computations of tax. A similar allocation is made for state income taxes paid by Xcel Energy Inc. in connection with combined state filings. Xcel Energy Inc. also allocates its own income tax benefits to its direct subsidiaries based on the relative positive tax liabilities of the subsidiaries. See Note 6 for further discussion of income taxes.
Types of and Accounting for Derivative Instruments	Types of and Accounting for Derivative Instruments — Xcel Energy uses derivative instruments in connection with its interest rate, utility commodity price, vehicle fuel price and commodity trading activities, including forward contracts, futures, swaps and options. All derivative instruments not designated and qualifying for the normal purchases and normal sales exception, as defined by the accounting guidance for derivatives and hedging, are recorded on the consolidated balance sheets at fair value as derivative instruments. This includes certain instruments used to mitigate market risk for the utility operations including transmission in organized markets and all instruments related to the commodity trading operations. The classification of changes in fair value for those derivative instruments is dependent on the designation of a qualifying hedging relationship. Changes in fair value of derivative instruments not designated in a qualifying hedging relationship are reflected in current earnings or as a regulatory asset or liability. The classification as a regulatory asset or liability is based on commission approved regulatory recovery mechanisms. Gains or losses on commodity trading transactions are recorded as a component of electric operating revenues; hedging transactions for vehicle fuel costs are recorded as a component of capital projects and O&M costs; and interest rate hedging transactions are recorded as a component of interest expense. Certain utility subsidiaries are allowed to recover in electric or natural gas rates the costs of certain financial instruments purchased to reduce commodity cost volatility. For further information on derivatives entered to mitigate commodity price risk on behalf of electric and natural gas customers, see Note 11. Cash Flow Hedges — Certain qualifying hedging relationships are designated as a hedge of a forecasted transaction, or future cash flow (cash flow hedge). Changes in the fair value of a derivative designated as a cash flow hedge, to the extent effective, are included in OCI or deferred as a regulatory asset or liability based on recovery mechanisms until earnings are affected by the hedged transaction. Normal Purchases and Normal Sales — Xcel Energy enters into contracts for the purchase and sale of commodities for use in its business operations. Derivatives and hedging accounting guidance requires a company to evaluate these contracts to determine whether the contracts are derivatives. Certain contracts that meet the definition of a derivative may be exempted from derivative accounting if designated as normal purchases or normal sales. Xcel Energy evaluates all of its contracts at inception to determine if they are derivatives and if they meet the normal purchases and normal sales designation requirements. None of the contracts entered into within the commodity trading operations qualify for a normal purchases and normal sales designation. See Note 11 for further discussion of Xcel Energy’s risk management and derivative activities.
Commodity Trading Operations	Commodity Trading Operations — All applicable gains and losses related to commodity trading activities, whether or not settled physically, are shown on a net basis in electric operating revenues in the consolidated statements of income. Xcel Energy’s commodity trading operations are primarily conducted by NSP-Minnesota and PSCo. Commodity trading activities are not associated with energy produced from Xcel Energy’s generation assets or energy and capacity purchased to serve native load. Commodity trading contracts are recorded at fair market value and commodity trading results include the impact of all margin-sharing mechanisms. See Note 11 for further discussion.
Fair Value Measurements	Fair Value Measurements — Xcel Energy presents cash equivalents, interest rate derivatives, commodity derivatives and nuclear decommissioning fund assets at estimated fair values in its consolidated financial statements. Cash equivalents are recorded at cost plus accrued interest; money market funds are measured using quoted NAVs. For interest rate derivatives, quoted prices based primarily on observable market interest rate curves are used as a primary input to establish fair value. For commodity derivatives, the most observable inputs available are generally used to determine the fair value of each contract. In the absence of a quoted price for an identical contract in an active market, Xcel Energy may use quoted prices for similar contracts or internally prepared valuation models to determine fair value. For the pension and postretirement plan assets and the nuclear decommissioning fund, published trading data and pricing models, generally using the most observable inputs available, are utilized to estimate fair value for each security. See Notes 9 and 11 for further discussion.
Cash and Cash Equivalents	Cash and Cash Equivalents — Xcel Energy considers investments in certain instruments, including commercial paper and money market funds, with a remaining maturity of three months or less at the time of purchase, to be cash equivalents.
Accounts Receivable and Allowance for Bad Debts	Accounts Receivable and Allowance for Bad Debts — Accounts receivable are stated at the actual billed amount net of an allowance for bad debts. Xcel Energy establishes an allowance for uncollectible receivables based on a policy that reflects its expected exposure to the credit risk of customers.
Inventory	Inventory — All inventory is recorded at average cost.
Renewable Energy Credits	RECs — RECs are marketable environmental instruments that represent proof that energy was generated from eligible renewable energy sources. RECs are awarded upon delivery of the associated energy and can be bought and sold. RECs are typically used as a form of measurement of compliance to RPS enacted by those states that are encouraging construction and consumption from renewable energy sources, but can also be sold separately from the energy produced. Utility subsidiaries acquire RECs from the generation or purchase of renewable power. When RECs are purchased or acquired in the course of generation they are recorded as inventory at cost. The cost of RECs that are utilized for compliance purposes is recorded as electric fuel and purchased power expense. In certain jurisdictions, as a result of state regulatory orders, Xcel Energy reduces recoverable fuel costs for the cost of certain RECs and records that cost as a regulatory asset when the amount is recoverable in future rates. Sales of RECs that are purchased or acquired in the course of generation are recorded in electric utility operating revenues on a gross basis. The cost of these RECs, related transaction costs, and amounts credited to customers under margin-sharing mechanisms are recorded in electric fuel and purchased power expense.
Emission Allowances	Emission Allowances — Emission allowances, including the annual SO 2 and NOx emission allowance entitlement received from the EPA, are recorded at cost plus associated broker commission fees. Xcel Energy follows the inventory accounting model for all emission allowances. Sales of emission allowances are included in electric utility operating revenue and the operating activities section of the consolidated statements of cash flows.
Environmental Costs	Environmental Costs — Environmental costs are recorded when it is probable Xcel Energy is liable for remediation costs and the liability can be reasonably estimated. Costs are deferred as a regulatory asset if it is probable that the costs will be recovered from customers in future rates. Otherwise, the costs are expensed. If an environmental expense is related to facilities currently in use, such as emission-control equipment, the cost is capitalized and depreciated over the life of the plant. Estimated remediation costs, excluding inflationary increases, are recorded based on experience, an assessment of the current situation and the technology currently available for use in the remediation. The recorded costs are regularly adjusted as estimates are revised and remediation proceeds. If other participating PRPs exist and acknowledge their potential involvement with a site, costs are estimated and recorded only for Xcel Energy’s expected share of the cost. Any future costs of restoring sites where operation may extend indefinitely are treated as a capitalized cost of plant retirement. The depreciation expense levels recoverable in rates include a provision for removal expenses, which may include final remediation costs. Removal costs recovered in rates before the related costs are incurred are classified as a regulatory liability. See Note 13 for further discussion of environmental costs.
Benefit Plans and Other Postretirement Benefits	Benefit Plans and Other Postretirement Benefits — Xcel Energy maintains pension and postretirement benefit plans for eligible employees. Recognizing the cost of providing benefits and measuring the projected benefit obligation of these plans under applicable accounting guidance requires management to make various assumptions and estimates. Based on the regulatory recovery mechanisms of Xcel Energy Inc.’s utility subsidiaries, certain unrecognized actuarial gains and losses and unrecognized prior service costs or credits are recorded as regulatory assets and liabilities, rather than OCI. See Note 9 for further discussion of benefit plans and other postretirement benefits.
Guarantees	Guarantees — Xcel Energy recognizes, upon issuance or modification of a guarantee, a liability for the fair market value of the obligation that has been assumed in issuing the guarantee. This liability includes consideration of specific triggering events and other conditions which may modify the ongoing obligation to perform under the guarantee. The obligation recognized is reduced over the term of the guarantee as Xcel Energy is released from risk under the guarantee. See Note 13 for specific details of issued guarantees.
Subsequent Events	Subsequent Events — Management has evaluated the impact of events occurring after Dec. 31, 2017 up to the date of issuance of these consolidated financial statements. These statements contain all necessary adjustments and disclosures resulting from that evaluation.

Selected Balance Sheet Data (Ta

Selected Balance Sheet Data (Tables)	12 Months Ended
	Dec. 31, 2017
Balance Sheet Related Disclosures [Abstract]
Accounts Receivable, Net	(Millions of Dollars) Dec. 31, 2017 Dec. 31, 2016 Accounts receivable, net Accounts receivable $ 849 $ 827 Less allowance for bad debts (52 ) (51 ) $ 797 $ 776
Inventories	(Millions of Dollars) Dec. 31, 2017 Dec. 31, 2016 Inventories Materials and supplies $ 311 $ 312 Fuel 186 182 Natural gas 113 110 $ 610 $ 604
Property, Plant and Equipment, Net	(Millions of Dollars) Dec. 31, 2017 Dec. 31, 2016 Property, plant and equipment, net Electric plant $ 39,016 $ 38,221 Natural gas plant 5,800 5,318 Common and other property 2,013 1,888 Plant to be retired (a) 11 32 CWIP 2,087 1,373 Total property, plant and equipment 48,927 46,832 Less accumulated depreciation (15,000 ) (14,381 ) Nuclear fuel 2,697 2,572 Less accumulated amortization (2,295 ) (2,181 ) $ 34,329 $ 32,842 (a) In the third quarter of 2017, PSCo early retired Valmont Unit 5 and converted Cherokee Unit 4 from a coal-fueled generating facility to natural gas. PSCo also expects Craig Unit 1 to be early retired in approximately 2025. Amounts are presented net of accumulated depreciation.

Borrowings and Other Financin34

Borrowings and Other Financing Instruments (Tables)	12 Months Ended
	Dec. 31, 2017
Debt Disclosure [Abstract]
Commercial Paper	Commercial paper and term loan borrowings outstanding for Xcel Energy were as follows: (Amounts in Millions, Except Interest Rates) Three Months Ended Dec. 31, 2017 Borrowing limit $ 3,250 Amount outstanding at period end 814 Average amount outstanding 560 Maximum amount outstanding 814 Weighted average interest rate, computed on a daily basis 1.63 % Weighted average interest rate at period end 1.90 Year Ended Dec. 31 (Amounts in Millions, Except Interest Rates) 2017 2016 2015 Borrowing limit $ 3,250 $ 2,750 $ 2,750 Amount outstanding at period end 814 392 846 Average amount outstanding 644 485 601 Maximum amount outstanding 1,247 1,183 1,360 Weighted average interest rate, computed on a daily basis 1.35 % 0.74 % 0.48 % Weighted average interest rate at end of period 1.90 0.95 0.82
Schedule Of Debt To Total Capitalization Ratio	Each entity was in compliance as of Dec. 31, 2017 and 2016 , respectively, as evidenced by the table below: Debt-to-Total Capitalization Ratio 2017 2016 Xcel Energy Inc. 58 % 57 % NSP-Wisconsin 47 47 NSP-Minnesota 48 48 SPS 46 47 PSCo 44 45
Credit Facilities	As of Dec. 31, 2017 , Xcel Energy Inc. and its utility subsidiaries had the following committed credit facilities available: (Millions of Dollars) Credit Facility (a) Drawn (b) Available Xcel Energy Inc. $ 1,500 $ 783 $ 717 PSCo 700 3 697 NSP-Minnesota 500 44 456 SPS 400 2 398 NSP-Wisconsin 150 11 139 Total $ 3,250 $ 843 $ 2,407 (a) These credit facilities mature in June 2021 , with the exception of Xcel Energy Inc.’s $500 million 364 -day term loan agreement entered into in December 2017. (b) Includes outstanding commercial paper, term loan borrowings and letters of credit.
Schedule of Maturities of Long-term Debt	Maturities of long-term debt are as follows: (Millions of Dollars) 2018 $ 457 2019 405 2020 1,256 2021 425 2022 905

Joint Ownership of Generation35

Joint Ownership of Generation, Transmission and Gas Facilities (Tables)	12 Months Ended
	Dec. 31, 2017
Joint Ownership of Generation, Transmission and Gas Facilities [Abstract]
Investments in Jointly Owned Generation, Transmission and Gas Facilities	Following are the investments by Xcel Energy Inc.’s utility subsidiaries in jointly owned generation, transmission and gas facilities and the related ownership percentages as of Dec. 31, 2017 : (Millions of Dollars) Plant in Service Accumulated Depreciation CWIP Ownership % NSP-Minnesota Electric Generation: Sherco Unit 3 $ 612 $ 411 $ 1 59 % Sherco Common Facilities Units 1, 2 and 3 145 99 1 80 Sherco Substation 5 3 — 59 Electric Transmission: Grand Meadow Line and Substation 11 2 — 50 CapX2020 Transmission 1,039 138 2 51 Total NSP-Minnesota $ 1,812 $ 653 $ 4 (Millions of Dollars) Plant in Service Accumulated Depreciation CWIP Ownership % NSP-Wisconsin Electric Transmission: CapX2020 Transmission $ 162 $ 12 $ 103 81 % La Crosse, Wis. to Madison, Wis. — — 102 37 Total NSP-Wisconsin $ 162 $ 12 $ 205 (Millions of Dollars) Plant in Service Accumulated Depreciation CWIP Ownership % PSCo Electric Generation: Hayden Unit 1 $ 150 $ 72 $ 1 76 % Hayden Unit 2 149 65 — 37 Hayden Common Facilities 39 20 — 53 Craig Units 1 and 2 81 39 — 10 Craig Common Facilities 1, 2 and 3 39 20 — 7 Comanche Unit 3 890 118 — 67 Comanche Common Facilities 24 2 3 82 Electric Transmission: Transmission and other facilities, including substations 177 67 1 Various Gas Transportation: Rifle, Colo. to Avon, Colo. 22 8 — 60 Gas Transportation Compressor 8 1 — 50 Total PSCo $ 1,579 $ 412 $ 5

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2017
Income Tax Disclosure [Abstract]
Summary of Statute of Limitations Applicable to Open Tax Years [Table Text Block]	Xcel Energy files a consolidated federal income tax return. The statute of limitations applicable to Xcel Energy’s federal income tax returns expire as follows: Tax Year(s) Expiration 2009 - 2011 June 2018 2012 - 2013 October 2018 2014 September 2018 2015 September 2019 2016 September 2020
Earliest Open Tax Years Subject to Examination by State Taxing Authorities in the Major Operating Jurisdictions	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 Dec. 31, 2017, Xcel Energy’s earliest open tax years that are subject to examination by state taxing authorities in its major operating jurisdictions were as follows: State Year Colorado 2009 Minnesota 2009 Texas 2009 Wisconsin 2012
Reconciliation of Unrecognized Tax Benefits	A reconciliation of the amount of unrecognized tax benefit is as follows: (Millions of Dollars) Dec. 31, 2017 Dec. 31, 2016 Unrecognized tax benefit — Permanent tax positions $ 20 $ 30 Unrecognized tax benefit — Temporary tax positions 19 104 Total unrecognized tax benefit $ 39 $ 134 A reconciliation of the beginning and ending amount of unrecognized tax benefit is as follows: (Millions of Dollars) 2017 2016 2015 Balance at Jan. 1 $ 134 $ 121 $ 67 Additions based on tax positions related to the current year 6 8 27 Reductions based on tax positions related to the current year (4 ) — (5 ) Additions for tax positions of prior years 15 10 35 Reductions for tax positions of prior years (105 ) (5 ) (3 ) Settlements with taxing authorities (7 ) — — Balance at Dec. 31 $ 39 $ 134 $ 121
Tax Benefits Associated with NOL and Tax Credit Carryforwards	The unrecognized tax benefit amounts were reduced by the tax benefits associated with NOL and tax credit carryforwards. The amounts of tax benefits associated with NOL and tax credit carryforwards are as follows: (Millions of Dollars) Dec. 31, 2017 Dec. 31, 2016 NOL and tax credit carryforwards $ (31 ) $ (44 )
Interest Payable related to Unrecognized Tax Benefits [Table Text Block]	The payable for interest related to unrecognized tax benefits is partially offset by the interest benefit associated with NOL and tax credit carryforwards. A reconciliation of the beginning and ending amount of the payable for interest related to unrecognized tax benefits reported are as follows: (Millions of Dollars) 2017 2016 Payable for interest related to unrecognized tax benefits at Jan. 1 $ (3 ) $ — Interest income (expense) income related to unrecognized tax benefits 3 (3 ) Payable for interest related to unrecognized tax benefits at Dec. 31 $ — $ (3 )
NOL and Tax Credit Carryforwards	Other Income Tax Matters — NOL amounts represent the amount of the tax loss that is carried forward and tax credits represent the deferred tax asset. NOL and tax credit carryforwards as of Dec. 31 were as follows: (Millions of Dollars) 2017 2016 Federal NOL carryforward $ 1,072 $ 1,916 Federal tax credit carryforwards 517 424 Valuation allowances for federal credit carryforwards (5 ) — State NOL carryforwards 1,592 1,949 Valuation allowances for state NOL carryforwards (55 ) (59 ) State tax credit carryforwards, net of federal detriment (a) 90 74 Valuation allowances for state credit carryforwards, net of federal benefit (b) (68 ) (54 ) (a) State tax credit carryforwards are net of federal detriment of $24 million and $40 million as of Dec. 31, 2017 and 2016, respectively. (b) Valuation allowances for state tax credit carryforwards were net of federal benefit of $18 million and $29 million as of Dec. 31, 2017 and 2016, respectively.
Schedule of Effective Income Tax Rate Reconciliation	Total income tax expense from operations differs from the amount computed by applying the statutory federal income tax rate to income before income tax expense. The following reconciles such differences for the years ending Dec. 31: 2017 2016 (b) 2015 (b) Federal statutory rate 35.0 % 35.0 % 35.0 % State income tax on pretax income, net of federal tax effect 3.9 % 3.9 % 3.9 % Increases (decreases) in tax from: Wind production tax credits recognized (4.7 ) (3.4 ) (1.8 ) Other tax credits recognized, net of federal income tax expense (1.0 ) (0.8 ) (0.9 ) Tax reform 1.4 — — Regulatory differences - effects of rate changes (a) (0.1 ) (0.1 ) (0.1 ) Regulatory differences - other utility plant items (0.7 ) (0.5 ) (0.9 ) Change in unrecognized tax benefits (0.6 ) 0.2 0.6 NOL carryback — — (0.3 ) Other, net (1.1 ) (0.2 ) — Effective income tax rate 32.1 % 34.1 % 35.5 % (a) The amortization of excess deferred taxes. (b) The prior periods included in this footnote have been reclassified to conform to current year presentation.
Schedule of Components of Income Tax Expense (Benefit)	The components of Xcel Energy’s income tax expense for the years ending Dec. 31 were: (Millions of Dollars) 2017 2016 2015 Current federal tax expense (benefit) $ 1 $ (3 ) $ (36 ) Current state tax (benefit) expense (11 ) (4 ) 2 Current change in unrecognized tax (benefit) expense (83 ) 6 46 Deferred federal tax expense 460 477 480 Deferred state tax expense 107 112 92 Deferred change in unrecognized tax expense (benefit) 73 (2 ) (36 ) Deferred investment tax credits (5 ) (5 ) (5 ) Total income tax expense $ 542 $ 581 $ 543 The components of deferred income tax expense for the years ending Dec. 31 were: (Millions of Dollars) 2017 2016 2015 Deferred tax (benefit) expense excluding items below $ (2,939 ) $ 631 $ 547 Amortization and adjustments to deferred income taxes on income tax regulatory assets and liabilities 3,583 (45 ) (12 ) Tax (expense) benefit allocated to other comprehensive income, net of adoption of ASU No. 2018-02, and other (4 ) 1 1 Deferred tax expense $ 640 $ 587 $ 536
Schedule of Deferred Tax Assets and Liabilities	The components of Xcel Energy’s net deferred tax liability at Dec. 31 were as follows: (Millions of Dollars) 2017 2016 (a) Deferred tax liabilities: Differences between book and tax bases of property $ 4,989 $ 7,697 Regulatory assets 565 152 Pension expense 199 298 Other 69 89 Total deferred tax liabilities $ 5,822 $ 8,236 Deferred tax assets: Regulatory liabilities $ 886 $ (132 ) Tax credit carryforward 607 498 NOL carryforward 293 754 NOL and tax credit valuation allowances (77 ) (57 ) Other employee benefits 132 205 Deferred investment tax credits 17 27 Deferred fuel costs 12 11 Rate refund 10 33 Other 97 113 Total deferred tax assets $ 1,977 $ 1,452 Net deferred tax liability $ 3,845 $ 6,784 (a) The prior period included in this footnote has been reclassified to conform to current year presentation.

Earnings Per Share (Tables)

Earnings Per Share (Tables)	12 Months Ended
	Dec. 31, 2017
Earnings Per Share [Abstract]
Dilutive Impact of Common Stock Equivalents	The dilutive impact of common stock equivalents affecting EPS was as follows: 2017 2016 2015 (Amounts in millions, except per share data) Income Shares Per Share Amount Income Shares Per Share Amount Income Shares Per Share Amount Net income $ 1,148 $ 1,123 $ 984 Basic EPS: Earnings available to common shareholders 1,148 508.5 $ 2.26 1,123 508.8 $ 2.21 984 507.8 $ 1.94 Effect of dilutive securities: Equity awards — 0.6 — 0.7 — 0.4 Diluted EPS: Earnings available to common shareholders $ 1,148 509.1 $ 2.25 $ 1,123 509.5 $ 2.21 $ 984 508.2 $ 1.94

Share-Based Compensation (Table

Share-Based Compensation (Tables)	12 Months Ended
	Dec. 31, 2017
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Restricted Stock	Xcel Energy Inc. granted shares of restricted stock for the years ended Dec. 31 as follows: (Shares in Thousands) 2017 2016 2015 Granted shares 15 20 42 Grant date fair value $ 42.00 $ 38.82 $ 35.00 A summary of the changes of nonvested restricted stock for the year ended 2017 were as follows: (Shares in Thousands) Shares Weighted Average Nonvested restricted stock at Jan. 1, 2017 67 $ 35.43 Granted 15 42.00 Forfeited — — Vested (40 ) 33.36 Dividend equivalents 2 44.69 Nonvested restricted stock at Dec. 31, 2017 44 39.71
Other Equity Awards	Equity award units granted to employees, excluding restricted stock, for the years ended Dec. 31 were as follows: (Units in Thousands) 2017 2016 2015 Granted units 503 522 496 Weighted average grant date fair value $ 41.02 $ 36.00 $ 36.09 Approximately 0.5 million of these units vested during 2017 at a total fair value of $22 million . Approximately 0.5 million of these units vested during 2016 at a total fair value of $22 million . Approximately 0.8 million of these units vested during 2015 at a total fair value of $27 million . A summary of the changes in the nonvested portion of these equity award units for the year ended 2017, were as follows: (Units in Thousands) Units Weighted Average Nonvested Units at Jan. 1, 2017 984 $ 36.05 Granted 503 41.02 Forfeited (70 ) 37.12 Vested (467 ) 36.17 Dividend equivalents 45 37.20 Nonvested Units at Dec. 31, 2017 995 38.48
Stock Equivalent Unit Plan	The stock equivalent units granted for the years ended Dec. 31 were as follows: (Units in Thousands) 2017 2016 2015 Granted units 51 49 60 Grant date fair value $ 46.05 $ 40.68 $ 34.58 A summary of the stock equivalent unit changes for the year ended 2017 are as follows: (Units in Thousands) Units Weighted Average Stock equivalent units at Jan. 1, 2017 750 $ 27.39 Granted 51 46.05 Units distributed (71 ) 20.52 Dividend equivalents 23 45.24 Stock equivalent units at Dec. 31, 2017 753 29.83
TSR Liability Awards	The TSR liability awards granted for the years ended Dec. 31 were as follows: (In Thousands) 2017 2016 2015 Awards granted 240 264 224 The total amounts of TSR liability awards settled during the years ended Dec. 31 were as follows: (In Thousands) 2017 2016 2015 Awards settled 454 354 — Settlement amount (cash, common stock and deferred amounts) $ 19,083 $ 13,724 $ —
Compensation costs related to share-based awards	The compensation costs related to share-based awards for the years ended Dec. 31 were as follows: (Millions of Dollars) 2017 2016 2015 Compensation cost for share-based awards (a) $ 57 $ 41 $ 45 Tax benefit recognized in income 22 16 18 (a) Compensation costs for share-based payment arrangements are included in O&M expense in the consolidated statements of income.

Benefit Plans and Other Postr39

Benefit Plans and Other Postretirement Benefits (Tables)	12 Months Ended
	Dec. 31, 2017
Benefit Plans and Other Postretirement Benefits [Abstract]
Projected Benefit Payments for the Pension and Postretirement Benefit Plans	The following table lists Xcel Energy’s projected benefit payments for the pension and postretirement benefit plans: (Millions of Dollars) Projected Gross Projected Expected Net Projected 2018 $ 307 $ 47 $ 2 $ 45 2019 262 47 2 45 2020 261 47 2 45 2021 261 47 3 44 2022 266 46 3 43 2023-2027 1,274 212 14 198
Contributions to Multiemployer Plans	There were no other significant changes to the nature or magnitude of the participation of NSP-Minnesota and NSP-Wisconsin in multiemployer plans for the years presented: (Millions of Dollars) 2017 2016 2015 Multiemployer pension contributions: NSP-Minnesota $ 12 $ 14 $ 17 NSP-Wisconsin — 1 1 Total $ 12 $ 15 $ 18
Pension Plan [Member]
Benefit Plans and Other Postretirement Benefits [Abstract]
Target Asset Allocations and Plan Assets Measured at Fair Value	The following tables present, for each of the fair value hierarchy levels, Xcel Energy’s pension plan assets that are measured at fair value as of Dec. 31, 2017 and 2016 : Dec. 31, 2017 (Millions of Dollars) Level 1 Level 2 Level 3 Investments Measured at NAV Total Cash equivalents $ 196 $ — $ — $ — $ 196 Commingled funds: U.S. equity funds 513 — — — 513 Non U.S. equity funds 92 — — 199 291 U.S. corporate bond funds 369 — — — 369 Emerging market equity funds — — — 314 314 Emerging market debt funds 75 — — 166 241 Private equity investments — — — 84 84 Real estate — — — 195 195 Other commingled funds 5 — — 117 122 Debt securities: Government securities — 356 — — 356 U.S. corporate bonds — 272 — — 272 Non U.S. corporate bonds — 45 — — 45 Equity securities: U.S. equities 114 — — — 114 Other (29 ) 4 — 1 (24 ) Total $ 1,335 $ 677 $ — $ 1,076 $ 3,088 Dec. 31, 2016 (Millions of Dollars) Level 1 Level 2 Level 3 Investments Measured at NAV Total Cash equivalents $ 113 $ — $ — $ — $ 113 U.S. equity funds 491 — — — 491 Non U.S. equity funds 167 — — 202 369 U.S. corporate bond funds 268 — — — 268 Emerging market equity funds — — — 194 194 Emerging market debt funds 79 — — 85 164 Commodity funds — — — 21 21 Private equity investments — — — 101 101 Real estate — — — 184 — 184 Other commingled funds — — — 210 210 Debt securities: Government securities — 364 — — 364 U.S. corporate bonds — 238 — — 238 Non U.S. corporate bonds — 38 — — 38 Mortgage-backed securities — 6 — — 6 Asset-backed securities — 3 — — 3 Equity securities: U.S. equities 89 — — — 89 Other — 3 — — 3 Total $ 1,207 $ 652 $ — $ 997 $ 2,856 The following table presents the target pension asset allocations for Xcel Energy at Dec. 31 for the upcoming year: 2017 2016 Domestic and international equity securities 36 % 38 % Long-duration fixed income and interest rate swap securities 27 27 Short-to-intermediate fixed income securities 20 16 Alternative investments 15 17 Cash 2 2 Total 100 % 100 %
Change in Projected Benefit Obligation	A comparison of the actuarially computed pension benefit obligation and plan assets for Xcel Energy is presented in the following table: (Millions of Dollars) 2017 2016 Accumulated Benefit Obligation at Dec. 31 $ 3,612 $ 3,489 Change in Projected Benefit Obligation: Obligation at Jan. 1 $ 3,682 $ 3,568 Service cost 94 92 Interest cost 147 160 Plan amendments (13 ) 2 Actuarial loss 259 186 Benefit payments (a) (341 ) (326 ) Obligation at Dec. 31 $ 3,828 $ 3,682
Change in Fair Value of Plan Assets	(Millions of Dollars) 2017 2016 Change in Fair Value of Plan Assets: Fair value of plan assets at Jan. 1 $ 2,856 $ 2,884 Actual return on plan assets 411 172 Employer contributions 162 125 Benefit payments (a) (341 ) (325 ) Fair value of plan assets at Dec. 31 $ 3,088 $ 2,856
Funded Status of Plans	(Millions of Dollars) 2017 2016 Funded Status of Plans at Dec. 31: Funded status (b) $ (740 ) $ (826 ) (a) 2017 amount includes approximately $174 million of lump-sum benefit payments used in the determination of a settlement charge. (b) Amounts are recognized in noncurrent liabilities on Xcel Energy’s consolidated balance sheets.
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost	(Millions of Dollars) 2017 2016 Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost: Net loss $ 1,709 $ 1,836 Prior service credit (25 ) (5 ) Total $ 1,684 $ 1,831
Amounts Not Yet Recognized as Components of Net Periodic Benefit Costs Recorded on the Balance Sheet Based Upon Expected Recovery in Rates	(Millions of Dollars) 2017 2016 Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost Have Been Recorded as Follows Based Upon Expected Recovery in Rates: Current regulatory assets $ 100 $ 101 Noncurrent regulatory assets 1,511 1,650 Deferred income taxes 19 31 Net-of-tax accumulated OCI 54 49 Total $ 1,684 $ 1,831
Schedule of Assumptions Used	2017 2016 2015 Significant Assumptions Used to Measure Costs: Discount rate 4.13 % 4.66 % 4.11 % Expected average long-term increase in compensation level 3.75 4.00 3.75 Expected average long-term rate of return on assets 6.87 6.87 7.09 Measurement date Dec. 31, 2017 Dec. 31, 2016 2017 2016 Significant Assumptions Used to Measure Benefit Obligations: Discount rate for year-end valuation 3.63 % 4.13 % Expected average long-term increase in compensation level 3.75 3.75 Mortality table RP-2014 RP-2014
Components of Net Periodic Benefit Costs	The components of Xcel Energy’s net periodic pension cost were: (Millions of Dollars) 2017 2016 2015 Service cost $ 94 $ 92 $ 99 Interest cost 147 160 149 Expected return on plan assets (209 ) (210 ) (214 ) Amortization of prior service credit (2 ) (2 ) (2 ) Amortization of net loss 107 97 125 Settlement charge (a) 81 — — Net periodic pension cost 218 137 157 Costs not recognized due to effects of regulation (79 ) (15 ) (29 ) Net benefit cost recognized for financial reporting $ 139 $ 122 $ 128 (a) A settlement charge is required when the amount of all lump-sum distributions during the year is greater than the sum of the service and interest cost components of the annual net periodic pension cost. In the fourth quarter of 2017 as a result of lump-sum distributions during the 2017 plan year, Xcel Energy recorded a total pension settlement charge of $81 million , the majority of which was not recognized due to the effects of regulation. A total of $8 million of that amount was recorded in O&M expenses in the fourth quarter of 2017.
Other Postretirement Benefits Plan [Member]
Benefit Plans and Other Postretirement Benefits [Abstract]
Target Asset Allocations and Plan Assets Measured at Fair Value	The following table presents the target postretirement asset allocations for Xcel Energy at Dec. 31 for the upcoming year: 2017 2016 Domestic and international equity securities 24 % 25 % Short-to-intermediate fixed income securities 60 57 Alternative investments 9 13 Cash 7 5 Total 100 % 100 % The following tables present, for each of the fair value hierarchy levels, Xcel Energy’s postretirement benefit plan assets that are measured at fair value as of Dec. 31, 2017 and 2016 : Dec. 31, 2017 (Millions of Dollars) Level 1 Level 2 Level 3 Investments Measured at NAV Total Cash equivalents $ 29 $ — $ — $ — $ 29 Insurance contracts — 50 — — 50 Commingled funds: U.S. equity funds 74 — — — 74 U.S fixed income funds 34 — — — 34 Emerging market debt funds 40 — — — 40 Debt securities: Government securities — 57 — — 57 U.S. corporate bonds — 63 — — 63 Non U.S. corporate bonds — 21 — — 21 Asset-backed securities — 23 — — 23 Mortgage-backed securities — 34 — — 34 Equity securities: Non U.S. equities 35 — — — 35 Other — 1 — — 1 Total $ 212 $ 249 $ — $ — $ 461 Dec. 31, 2016 (Millions of Dollars) Level 1 Level 2 Level 3 Investments Measured at NAV Total Cash equivalents $ 21 $ — $ — $ — $ 21 Insurance contracts — 47 — — 47 Commingled funds: U.S. equity funds 54 — — — 54 U.S fixed income funds 27 — — — 27 Emerging market debt funds 30 — — — 30 Other commingled funds — — — 55 55 Debt securities: Government securities — 38 — — 38 U.S. corporate bonds — 62 — — 62 Non U.S. corporate bonds — 17 — — 17 Asset-backed securities — 19 — — 19 Mortgage-backed securities — 29 — — 29 Equity securities: Non U.S. equities 41 — — — 41 Other — 2 — — 2 Total $ 173 $ 214 $ — $ 55 $ 442
Change in Projected Benefit Obligation	A comparison of the actuarially computed benefit obligation and plan assets for Xcel Energy is presented in the following table: (Millions of Dollars) 2017 2016 Change in Projected Benefit Obligation: Obligation at Jan. 1 $ 603 $ 584 Service cost 2 2 Interest cost 24 26 Medicare subsidy reimbursements 1 2 Plan participants’ contributions 8 7 Actuarial loss 33 33 Benefit payments (50 ) (51 ) Obligation at Dec. 31 $ 621 $ 603
Change in Fair Value of Plan Assets	(Millions of Dollars) 2017 2016 Change in Fair Value of Plan Assets: Fair value of plan assets at Jan. 1 $ 442 $ 448 Actual return on plan assets 41 20 Plan participants’ contributions 8 7 Employer contributions 20 18 Benefit payments (50 ) (51 ) Fair value of plan assets at Dec. 31 $ 461 $ 442
Funded Status of Plans	(Millions of Dollars) 2017 2016 Funded Status of Plans at Dec. 31: Funded status $ (160 ) $ (161 ) Current liabilities (3 ) (6 ) Noncurrent liabilities (157 ) (155 ) Net postretirement amounts recognized on consolidated balance sheets $ (160 ) $ (161 )
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost	(Millions of Dollars) 2017 2016 Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost: Net loss $ 147 $ 136 Prior service credit (44 ) (54 ) Total $ 103 $ 82
Amounts Not Yet Recognized as Components of Net Periodic Benefit Costs Recorded on the Balance Sheet Based Upon Expected Recovery in Rates	(Millions of Dollars) 2017 2016 Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost Have Been Recorded as Follows Based Upon Expected Recovery in Rates: Noncurrent regulatory assets $ 107 $ 91 Current regulatory liabilities (1 ) (1 ) Noncurrent regulatory liabilities (10 ) (14 ) Deferred income taxes 2 2 Net-of-tax accumulated OCI 5 4 Total $ 103 $ 82
Schedule of Assumptions Used	Measurement date Dec. 31, 2017 Dec. 31, 2016 2017 2016 Significant Assumptions Used to Measure Benefit Obligations: Discount rate for year-end valuation 3.62 % 4.13 % Mortality table RP 2014 RP 2014 Health care costs trend rate — initial: Pre-65 7.00 % 5.50 % Health care costs trend rate — initial: Post-65 5.50 % 5.50 % 2017 2016 2015 Significant Assumptions Used to Measure Costs: Discount rate 4.13 % 4.65 % 4.08 % Expected average long-term rate of return on assets 5.80 5.80 5.80
Effects of One-Percent Change in Assumed Health Care Cost Trend Rate	A one-percent change in the assumed health care cost trend rate would have the following effects on Xcel Energy: One-Percentage Point (Millions of Dollars) Increase Decrease APBO $ 60 $ (51 ) Service and interest components 3 (2 )
Components of Net Periodic Benefit Costs	The components of Xcel Energy’s net periodic postretirement benefit costs were: (Millions of Dollars) 2017 2016 2015 Service cost $ 2 $ 2 $ 2 Interest cost 24 26 25 Expected return on plan assets (25 ) (25 ) (26 ) Amortization of prior service credit (11 ) (11 ) (11 ) Amortization of net loss 7 4 6 Net periodic postretirement (credit) cost $ (3 ) $ (4 ) $ (4 )

Other Income, Net (Tables)

Other Income, Net (Tables)	12 Months Ended
	Dec. 31, 2017
Other Income and Expenses [Abstract]
Other Income, Net	Other income, net for the years ended Dec. 31 consisted of the following: (Millions of Dollars) 2017 2016 2015 Interest income $ 19 $ 8 $ 6 Other nonoperating income 7 3 4 Insurance policy expense (3 ) (3 ) (4 ) Other income, net $ 23 $ 8 $ 6

Fair Value of Financial Asset41

Fair Value of Financial Assets and Liabilities (Tables)	12 Months Ended
	Dec. 31, 2017
Fair Value Disclosures [Abstract]
Cost and Fair Value of Nuclear Decommissioning Fund Investments	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 as of Dec. 31, 2017 and 2016 : Dec. 31, 2017 Fair Value (Millions of Dollars) Cost Level 1 Level 2 Level 3 Investments Measured at NAV Total Nuclear decommissioning fund (a) Cash equivalents $ 29 $ 29 $ — $ — $ — $ 29 Commingled funds: Non U.S. equities 264 217 — — 90 307 Emerging market debt funds 156 — — — 166 166 Private equity investments 141 — — — 198 198 Real estate 131 — — — 202 202 Other commingled funds 9 6 — — 3 9 Debt securities: Government securities 68 — 69 — — 69 U.S. corporate bonds 320 — 322 — — 322 Non U.S. corporate bonds 50 — 50 — — 50 Equity securities: U.S. equities 271 557 — — — 557 Non U.S. equities 152 234 — — — 234 Total $ 1,591 $ 1,043 $ 441 $ — $ 659 $ 2,143 (a) Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $140 million of equity investments in unconsolidated subsidiaries and $114 million of rabbi trust assets and miscellaneous investments. Dec. 31, 2016 Fair Value (Millions of Dollars) Cost Level 1 Level 2 Level 3 Investments Measured at NAV Total Nuclear decommissioning fund (a) Cash equivalents $ 20 $ 20 $ — $ — $ — $ 20 Commingled funds: Non U.S. equities 261 133 — — 112 245 Emerging market debt funds 93 — — — 98 98 Commodity funds 106 — — — 92 92 Private equity investments 132 — — — 190 190 Real estate 129 — — — 188 188 Other commingled funds 151 — — — 160 160 Debt securities: Government securities 33 — 32 — — 32 U.S. corporate bonds 105 — 106 — — 106 Non U.S. corporate bonds 22 — 21 — — 21 Municipal bonds 14 — 14 — — 14 Mortgage-backed securities 3 — 3 — — 3 Equity securities: U.S. equities 271 474 — — — 474 Non U.S. equities 189 218 — — — 218 Total $ 1,529 $ 845 $ 176 $ — $ 840 $ 1,861 (a) Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $133 million of equity investments in unconsolidated subsidiaries and $98 million of rabbi trust assets and miscellaneous investments.
Final Contractual Maturity Dates of Debt Securities in the Nuclear Decommissioning Fund by Asset Class	The following table summarizes the final contractual maturity dates of the debt securities in the nuclear decommissioning fund, by asset class, as of Dec. 31, 2017 : Final Contractual Maturity (Millions of Dollars) Due in 1 Year or Less Due in 1 to 5 Years Due in 5 to 10 Years Due after 10 Years Total Government securities $ — $ 2 $ — $ 67 $ 69 U.S. corporate bonds 5 85 174 58 322 Non U.S. corporate bonds — 15 31 4 50 Debt securities $ 5 $ 102 $ 205 $ 129 $ 441
Rabbi Trust Securities Amortized Cost and Fair Value Measured on Recurrring Basis [Table Text Block]	The following table presents the cost and fair value of the assets held in rabbi trusts as of Dec. 31, 2017 and 2016: Dec. 31, 2017 Fair Value (Millions of Dollars) Cost Level 1 Level 2 Level 3 Total Rabbi Trusts (a) Cash equivalents $ 12 $ 12 $ — $ — $ 12 Mutual funds 47 50 — — 50 Total $ 59 $ 62 $ — $ — $ 62 Dec. 31, 2016 Fair Value (Millions of Dollars) Cost Level 1 Level 2 Level 3 Total Rabbi Trusts (a) Cash equivalents $ 48 $ 48 $ — $ — $ 48 Mutual funds 2 2 — — 2 Total $ 50 $ 50 $ — $ — $ 50 (a) Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet.
Gross Notional Amounts of Commodity Forwards, Options, and FTRs	The following table details the gross notional amounts of commodity forwards, options and FTRs as of Dec. 31: (Amounts in Millions) (a)(b) 2017 2016 MWh of electricity 68 47 MMBtu of natural gas 37 122 (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.
Financial Impact of Qualifying Cash Flow Hedges on Accumulated Other Comprehensive Loss	The impact of qualifying interest rate and vehicle fuel cash flow hedges on Xcel Energy’s accumulated other comprehensive loss, included in the consolidated statements of common stockholders’ equity and in the consolidated statements of comprehensive income, is detailed in the following table: (Millions of Dollars) 2017 2016 2015 Accumulated other comprehensive loss related to cash flow hedges at Jan. 1 $ (51 ) $ (55 ) $ (58 ) After-tax net realized losses on derivative transactions reclassified into earnings 3 4 3 Accumulated other comprehensive loss related to cash flow hedges at Dec. 31 $ (48 ) $ (51 ) $ (55 )
Impact of Derivative Activity on Accumulated Other Comprehensive Loss, Regulatory Assets and Liabilities, and Income	The following tables detail the impact of derivative activity during the years ended Dec. 31, 2017, 2016 and 2015, on accumulated other comprehensive loss, regulatory assets and liabilities, and income: Year Ended Dec. 31, 2017 Pre-Tax Fair Value Gains (Losses) Recognized During the Period in: Pre-Tax (Gains) Losses Reclassified into Income During the Period from: Pre-Tax Gains (Losses) Recognized (Millions of Dollars) Accumulated Regulatory Accumulated Regulatory Derivatives designated as cash flow hedges Interest rate $ — $ — $ 5 (a) $ — $ — Total $ — $ — $ 5 $ — $ — Other derivative instruments Commodity trading $ — $ — $ — $ — $ 10 (b) Electric commodity — 10 — (15 ) (c) — Natural gas commodity — (13 ) — 3 (d) (6 ) (d) Total $ — $ (3 ) $ — $ (12 ) $ 4 Year Ended Dec. 31, 2016 Pre-Tax Fair Value Gains Recognized During the Period in: Pre-Tax (Gains) Losses Reclassified into Income During the Period from: Pre-Tax Gains (Losses) Recognized (Millions of Dollars) Accumulated Regulatory Accumulated Regulatory Derivatives designated as cash flow hedges Interest rate $ — $ — $ 6 (a) $ — $ — Total $ — $ — $ 6 $ — $ — Other derivative instruments Commodity trading $ — $ — $ — $ — $ 2 (b) Electric commodity — 17 — (8 ) (c) — Natural gas commodity — 1 — 15 (d) (8 ) (d) Total $ — $ 18 $ — $ 7 $ (6 ) Year Ended Dec. 31, 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 (Millions of Dollars) Accumulated Regulatory Accumulated Regulatory Derivatives designated as cash flow hedges Interest rate $ — $ — $ 5 (a) $ — $ — Total $ — $ — $ 5 $ — $ — Other derivative instruments Commodity trading $ — $ — $ — $ — $ (7 ) (b) Electric commodity — (19 ) — 16 (c) — Natural gas commodity — (16 ) — 16 (d) (12 ) (d) Total $ — $ (35 ) $ — $ 32 $ (19 ) (a) Amounts are recorded to interest charges. (b) 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. (c) Amounts are recorded to electric fuel and purchased power. These derivative settlement gains and losses are shared with electric customers through fuel and purchased energy cost-recovery mechanisms, and reclassified out of income as regulatory assets or liabilities, as appropriate. (d) Certain derivatives are utilized to mitigate natural gas price risk for electric generation and are recorded to electric fuel and purchased power, subject to cost-recovery mechanisms and reclassified to a regulatory asset, as appropriate. Amounts for the years ended Dec. 31, 2017 and Dec. 31, 2016 included immaterial settlement gains and losses. Amounts for the year ended Dec. 31, 2015 included $1 million of settlement losses. The remaining settlement losses for the years ended Dec. 31, 2017, 2016 and 2015 relate to natural gas operations and are recorded to cost of natural gas sold and transported. These losses are subject to cost-recovery mechanisms and reclassified out of income to a regulatory asset, as appropriate.
Derivative Assets and Liabilities Measured at Fair Value on a Recurring Basis by Hierarchy Level	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 as of Dec. 31, 2017: Dec. 31, 2017 Fair Value Fair Value Total Counterparty Netting (b) (Millions of Dollars) Level 1 Level 2 Level 3 Total Current derivative assets Commodity trading $ 2 $ 22 $ — $ 24 $ (15 ) $ 9 Electric commodity — — 32 32 (2 ) 30 Total current derivative assets $ 2 $ 22 $ 32 $ 56 $ (17 ) 39 PPAs (a) 5 Current derivative instruments $ 44 Noncurrent derivative assets Other derivative instruments: Commodity trading $ — $ 31 $ 5 $ 36 $ (7 ) $ 29 Total noncurrent derivative assets $ — $ 31 $ 5 $ 36 $ (7 ) 29 PPAs (a) 19 Noncurrent derivative instruments $ 48 Dec. 31, 2017 Fair Value Fair Value Total Counterparty Netting (b) (Millions of Dollars) Level 1 Level 2 Level 3 Total Current derivative liabilities Other derivative instruments: Commodity trading $ 2 $ 18 $ — $ 20 $ (15 ) $ 5 Electric commodity — — 2 2 (2 ) — Natural gas commodity — 1 — 1 — 1 Total current derivative liabilities $ 2 $ 19 $ 2 $ 23 $ (17 ) 6 PPAs (a) 23 Current derivative instruments $ 29 Noncurrent derivative liabilities Other derivative instruments: Commodity trading $ — $ 24 $ — $ 24 $ (10 ) $ 14 Total noncurrent derivative liabilities $ — $ 24 $ — $ 24 $ (10 ) 14 PPAs (a) 112 Noncurrent derivative instruments $ 126 (a) During 2006, Xcel Energy qualified these contracts under the normal purchase exception. Based on this qualification, the contracts are no longer adjusted to fair value and the previous carrying value of these contracts will be amortized over the remaining contract lives along with the offsetting regulatory assets and liabilities. (b) Xcel Energy nets derivative instruments and related collateral in its consolidated balance sheet when supported by a legally enforceable master netting agreement, and all derivative instruments and related collateral amounts were subject to master netting agreements as of Dec. 31, 2017. At Dec. 31, 2017, derivative assets and liabilities include no obligations to return cash collateral and rights to reclaim cash collateral of $3 million . The counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements. The following table presents for each of the fair value hierarchy levels, Xcel Energy’s derivative assets and liabilities measured at fair value on a recurring basis as of Dec. 31, 2016: Dec. 31, 2016 Fair Value Fair Value Total Counterparty Netting (b) (Millions of Dollars) Level 1 Level 2 Level 3 Total Current derivative assets Other derivative instruments: Commodity trading $ 13 $ 14 $ — $ 27 $ (20 ) $ 7 Electric commodity — — 19 19 (2 ) 17 Natural gas commodity — 9 — 9 — 9 Total current derivative assets $ 13 $ 23 $ 19 $ 55 $ (22 ) 33 PPAs (a) 5 Current derivative instruments $ 38 Noncurrent derivative assets Other derivative instruments: Commodity trading $ — $ 31 $ — $ 31 $ (7 ) $ 24 Natural gas commodity — 2 — 2 — 2 Total noncurrent derivative assets $ — $ 33 $ — $ 33 $ (7 ) 26 PPAs (a) 24 Noncurrent derivative instruments $ 50 Dec. 31, 2016 Fair Value Fair Value Total Counterparty Netting (b) (Millions of Dollars) Level 1 Level 2 Level 3 Total Current derivative liabilities Other derivative instruments: Commodity trading $ 14 $ 11 $ — $ 25 $ (21 ) $ 4 Electric commodity — — 2 2 (2 ) — Total current derivative liabilities $ 14 $ 11 $ 2 $ 27 $ (23 ) 4 PPAs (a) 23 Current derivative instruments $ 27 Noncurrent derivative liabilities Other derivative instruments: Commodity trading $ — $ 24 $ — $ 24 $ (11 ) $ 13 Total noncurrent derivative liabilities $ — $ 24 $ — $ 24 $ (11 ) 13 PPAs (a) 135 Noncurrent derivative instruments $ 148 (a) During 2006, Xcel Energy qualified these contracts under the normal purchase exception. Based on this qualification, the contracts are no longer adjusted to fair value and the previous carrying value of these contracts will be amortized over the remaining contract lives along with the offsetting regulatory assets and liabilities. (b) Xcel Energy nets derivative instruments and related collateral in its consolidated balance sheet when supported by a legally enforceable master netting agreement, and all derivative instruments and related collateral amounts were subject to master netting agreements as of Dec. 31, 2016. At Dec. 31, 2016, derivative assets and liabilities include no obligations to return cash collateral and rights to reclaim cash collateral of $4 million . The counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements.
Changes in Level 3 Commodity Derivatives	The following table presents the changes in Level 3 commodity derivatives for the years ended Dec. 31, 2017, 2016 and 2015: Year Ended Dec. 31 (Millions of Dollars) 2017 2016 2015 Balance at Jan. 1 $ 17 $ 18 $ 56 Purchases 82 35 64 Settlements (97 ) (89 ) (70 ) Net transactions recorded during the period: Gains recognized in earnings (a) 5 — 2 Net gains (losses) recognized as regulatory assets and liabilities 28 53 (34 ) Balance at Dec. 31 $ 35 $ 17 $ 18 (a) These amounts relate to commodity derivatives held at the end of the period.
Carrying Amount and Fair Value of Long-term Debt	As of Dec. 31, 2017 and 2016 , other financial instruments for which the carrying amount did not equal fair value were as follows: 2017 2016 (Millions of Dollars) Carrying Amount Fair Value Carrying Amount Fair Value Long-term debt, including current portion $ 14,976 $ 16,531 $ 14,450 $ 15,513

Rate Matters (Tables)

Rate Matters (Tables)	12 Months Ended
	Dec. 31, 2017
Public Utilities, General Disclosures [Abstract]
NSP-Minnesota 2016 Rate Case Final Order [Table Text Block]	(Millions of Dollars, incremental) 2016 2017 2018 2019 Total Revenues $ 75 $ 55 $ — $ 50 $ 180 NSP-Minnesota’s sales true-up 60 — — — 60 Total rate impact $ 135 $ 55 $ — $ 50 $ 240
Colorado 2017 Multi-Year Electric Rate Case [Table Text Block]	Revenue Request (Millions of Dollars) 2018 2019 2020 2021 Total Revenue request $ 74 $ 75 $ 60 $ 36 $ 245 CACJA revenue conversion to base rates (a) 90 — — — 90 TCA revenue conversion to base rates (a) 43 — — — 43 Total (b) $ 207 $ 75 $ 60 $ 36 $ 378 Expected year-end rate base (billions of dollars) (b) $ 6.8 $ 7.1 $ 7.3 $ 7.4 (a) The roll-in of the TCA and CACJA rider revenues into base rates will not have an impact on customer bills or revenue as these costs are already being recovered through a rider. Transmission investments for 2019-2021 will be recovered through the TCA rider. (b) This base rate request does not include the impacts of the RESA and ECA for the Rush Creek wind investments or the proposed CEP.
Colorado 2017 Multi-Year Gas Rate Case [Table Text Block]	Revenue Request (Millions of Dollars) 2018 2019 2020 Total Revenue request $ 63 $ 33 $ 43 $ 139 PSIA revenue conversion to base rates (a) — 94 — 94 Total $ 63 $ 127 $ 43 $ 233 Expected year-end rate base (billions of dollars) (b) $ 1.5 $ 2.3 $ 2.4 (a) The roll-in of PSIA rider revenue into base rates will not have an impact on customer bills or revenue as these costs are already being recovered through the rider. The recovery of incremental PSIA related investments in 2019 and 2020 are included in the base rate request. (b) The additional rate base in 2019 predominantly reflects the roll-in of capital associated with the PSIA rider.
Texas 2017 Rate Case [Table Text Block]	The following table summarizes SPS’ rate increase request: Revenue Request (Millions of Dollars) Incremental revenue request $ 69 TCRF revenue conversion to base rates (a) (14 ) Net revenue increase request $ 55 (a) The roll-in of the TCRF rider revenue into base rates will not have an impact on customer bills or revenue as these costs are already being recovered through the rider. SPS can request another TCRF rider after the conclusion of this rate case to recover transmission investments subsequent to June 30, 2017.

Commitments and Contingencies (

Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2017
Commitments and Contingencies Disclosure [Abstract]
Estimated Minimum Purchases Under Fuel Contracts	The estimated minimum purchases for Xcel Energy under these contracts as of Dec. 31, 2017 are as follows: (Millions of Dollars) Coal Nuclear fuel Natural gas supply Natural gas storage and transportation 2018 $ 655 $ 61 $ 391 $ 263 2019 255 118 288 251 2020 146 34 277 237 2021 59 85 280 227 2022 59 66 127 217 Thereafter 186 379 57 1,046 Total $ 1,360 $ 743 $ 1,420 $ 2,241
Estimated Future Payments for Capacity and Energy Pursuant to Purchased Power Agreements	At Dec. 31, 2017 , the estimated future payments for capacity and energy that the utility subsidiaries of Xcel Energy are obligated to purchase pursuant to these executory contracts, subject to availability, are as follows: (Millions of Dollars) Capacity Energy (a) 2018 $ 133 $ 93 2019 87 99 2020 68 105 2021 73 140 2022 77 155 Thereafter 205 368 Total $ 643 $ 960 (a) Excludes contingent energy payments for renewable energy PPAs.
Summary of Property Held Under Capital Leases	Total amortization expenses under capital lease assets were approximately $5 million , $8 million and $8 million for 2017 , 2016 and 2015 , respectively. Following is a summary of property held under capital leases: (Millions of Dollars) Dec. 31, 2017 Dec. 31, 2016 Gas storage facilities $ 201 $ 201 Gas pipeline 21 21 Property held under capital leases 222 222 Accumulated depreciation (71 ) (66 ) Total property held under capital leases, net $ 151 $ 156
Future Commitments Under Operating and Capital Leases	Future commitments under operating and capital leases are: (Millions of Dollars) Operating Leases PPA (a) (b) Operating Leases Total Leases Capital Leases 2018 $ 25 $ 213 $ 238 $ 15 2019 30 230 260 14 2020 24 244 268 14 2021 24 246 270 14 2022 22 235 257 12 Thereafter 148 1,682 1,830 233 Total minimum obligation 302 Interest component of obligation (213 ) Present value of minimum obligation $ 89 (c) (a) Amounts do not include PPAs accounted for as executory contracts. (b) PPA operating leases contractually expire through 2039 . (c) Future commitments exclude certain amounts related to Xcel Energy’s 50 percent ownership interest in WYCO.
Eloigne and NSP-Wisconsin Low-income Housing Limited Partnerships	Amounts reflected in Xcel Energy’s consolidated balance sheets for the Eloigne and NSP-Wisconsin low-income housing limited partnerships include the following: (Millions of Dollars) Dec. 31, 2017 Dec. 31, 2016 Current assets $ 6 $ 7 Property, plant and equipment, net 46 50 Other noncurrent assets 1 1 Total assets $ 53 $ 58 Current liabilities $ 9 $ 8 Mortgages and other long-term debt payable 26 30 Other noncurrent liabilities 1 1 Total liabilities $ 36 $ 39
Committed Minimum Payments Under Technology Agreements	Committed minimum payments under these obligations are as follows: (Millions of Dollars) IBM Agreement Accenture Agreement 2018 $ 26 $ 11 2019 26 11 2020 8 11 2021 8 — 2022 3 — Thereafter — —
Guarantees and Bond Indemnities Issued and Outstanding	The following table presents guarantees and bond indemnities issued and outstanding as of Dec. 31, 2017 : (Millions of Dollars) Guarantor Guarantee Amount Current Exposure Triggering Event Guarantee of customer loans for the Farm Rewiring Program (a) NSP-Wisconsin $ 1.0 $ — (f) Guarantee of the indemnification obligations of Xcel Energy Services Inc. under the aircraft leases (b) Xcel Energy Inc. 12.0 — (g) Guarantee of residual value of assets under the Bank of Tokyo-Mitsubishi Capital Corporation Equipment Leasing Agreement (c) NSP-Minnesota 4.8 — (h) Guarantee of loan for Hiawatha Collegiate High School (d) Xcel Energy Inc. 1.0 — (g) Total guarantees issued $ 18.8 $ — Guarantee performance and payment of surety bonds for Xcel Energy Inc.’s utility subsidiaries (e) Xcel Energy Inc. $ 53.1 (j) (i) (a) The term of this guarantee expires in 2020 , which is the final scheduled repayment date for the loans. As of Dec. 31, 2017, no claims had been made by the lender. (b) The terms of this guarantee expires in 2021 and 2023 when the associated leases expire. (c) The term of this guarantee expires in 2019 when the associated lease expires. (d) The term of this guarantee expires the earlier of 2024 or full repayment of the loan. (e) The surety bonds primarily relate to workers compensation benefits and utility projects. The workers compensation bonds are renewed annually and the project based bonds expire in conjunction with the completion of the related projects. (f) The debtor becomes the subject of bankruptcy or other insolvency proceedings. (g) Nonperformance and/or nonpayment. (h) Actual fair value of leased assets is less than the guaranteed residual value amount at the end of the lease term. (i) Failure of any one of Xcel Energy Inc.’s utility subsidiaries to perform under the agreement that is the subject of the relevant bond. In addition, per the indemnity agreement between Xcel Energy Inc. and the various surety companies, the surety companies have the discretion to demand that collateral be posted. (j) Due to the magnitude of projects associated with the surety bonds, the total current exposure of this indemnification cannot be determined. Xcel Energy Inc. believes the exposure to be significantly less than the total amount of the outstanding
Asset Retirement Obligations	A reconciliation of Xcel Energy’s AROs for the years ended Dec. 31, 2017 and 2016 is as follows: (Millions of Dollars) Beginning Jan. 1, 2017 Liabilities Recognized Liabilities Settled (a) Accretion Cash Flow Revisions (b) Ending Dec. 31, 2017 Electric plant Nuclear production decommissioning $ 2,249 $ — $ — $ 114 $ (489 ) $ 1,874 Steam and other production ash containment 117 — (16 ) 5 9 115 Wind production 92 — — 4 — 96 Steam, hydro and other production asbestos 88 1 (13 ) 4 (3 ) 77 Electric distribution 20 — — 1 — 21 Other 5 — — — — 5 Natural gas plant Gas transmission and distribution 205 — — 8 69 282 Other 4 — — — — 4 Common and other property Common general plant asbestos 1 — (1 ) — — — Common miscellaneous 1 — — — — 1 Total liability $ 2,782 $ 1 $ (30 ) $ 136 $ (414 ) $ 2,475 (a) The liabilities settled relate to asbestos abatement projects, the closure of certain ash containment facilities, and removal and proper disposal of storage tanks and other above ground equipment. (b) In 2017, AROs were revised for changes in estimated cash flows and the timing of those cash flows. The nuclear decommissioning ARO decreased due to updated assumptions in the nuclear triennial filing. Changes in the gas transmission and distribution AROs were mainly related to increased labor costs. The aggregate fair value of NSP-Minnesota’s legally restricted assets, for purposes of funding future nuclear decommissioning, was $2.1 billion as of Dec. 31, 2017 , consisting of external investment funds. (Millions of Dollars) Beginning Jan. 1, 2016 Liabilities Recognized Liabilities Settled Accretion Cash Flow Revisions (b) Ending Dec. 31, 2016 Electric plant Nuclear production decommissioning $ 2,141 $ — $ — $ 108 $ — $ 2,249 Steam and other production ash containment 132 — (6 ) 5 (14 ) 117 Steam, hydro and other production asbestos 84 — — 4 — 88 Wind production 72 17 (a) — 3 — 92 Electric distribution 13 — — 1 6 20 Other 4 1 — — — 5 Natural gas plant Gas transmission and distribution 156 — — 7 42 205 Other 4 — — — — 4 Common and other property Common general plant asbestos 1 — — — — 1 Common miscellaneous 2 — — — (1 ) 1 Total liability $ 2,609 $ 18 $ (6 ) $ 128 $ 33 $ 2,782 (a) The liability recognized relates to the NSP-Minnesota Courtenay Wind Farm which was placed in service during 2016. (b) In 2016, AROs were revised for changes in estimated cash flows and the timing of those cash flows. Changes in the gas transmission and distribution AROs were mainly related to increased miles of gas mains.
Plant Removal Costs	The accumulated balances by entity were as follows at Dec. 31 : (Millions of Dollars) 2017 2016 NSP-Minnesota $ 442 $ 419 PSCo 346 367 SPS 197 209 NSP-Wisconsin 146 140 Total Xcel Energy $ 1,131 $ 1,135

Nuclear Obligations (Tables)

Nuclear Obligations (Tables)	12 Months Ended
	Dec. 31, 2017
Nuclear Obligations [Abstract]
Funded Status of Nuclear Decommissioning Obligation	As of Dec. 31, 2017 , NSP-Minnesota has accumulated $2.1 billion of assets held in external decommissioning trusts. The following table summarizes the funded status of NSP-Minnesota’s decommissioning obligation based on parameters established in the most recently approved decommissioning study. Xcel Energy believes future decommissioning costs, if necessary, will continue to be recovered in customer rates. The amounts presented below were prepared on a regulatory basis, and are not recorded in the financial statements for the ARO. Regulatory Basis (Millions of Dollars) 2017 2016 Estimated decommissioning cost obligation from most recently approved study (in 2014 dollars) $ 3,012 $ 3,012 Effect of escalating costs (to 2017 and 2016 dollars, respectively, at 4.36/3.36 percent) 396 258 Estimated decommissioning cost obligation (in current dollars) 3,408 3,270 Effect of escalating costs to payment date (4.36/3.36 percent) 7,797 7,935 Estimated future decommissioning costs (undiscounted) 11,205 11,205 Effect of discounting obligation (using average risk-free interest rate of 2.80 percent and 3.25 percent for 2017 and 2016, respectively) (6,398 ) (7,068 ) Discounted decommissioning cost obligation $ 4,807 $ 4,137 Assets held in external decommissioning trust $ 2,143 $ 1,861 Underfunding of external decommissioning fund compared to the discounted decommissioning obligation 2,664 2,276
Reconciliation of Decommissioning Cost Obligation - Regulatory to GAAP	Calculations and data used by the regulator in approving NSP-Minnesota’s rates are useful in assessing future cash flows. The regulatory basis information is a means to reconcile amounts previously provided to the MPUC and utilized for regulatory purposes to amounts used for financial reporting. The following table provides a reconciliation of the discounted decommissioning cost obligation - regulated basis to the ARO recorded in accordance with GAAP: (Millions of Dollars) 2017 2016 Discounted decommissioning cost obligation - regulated basis $ 4,807 $ 4,137 Differences in discount rate and market risk premium (1,403 ) (1,044 ) O&M costs not included for GAAP (1,041 ) (844 ) ARO differences between 2017 and 2014 cost studies (489 ) — Nuclear production decommissioning ARO - GAAP $ 1,874 $ 2,249
Nuclear Decommissioning Expenses Recognized as Result of Regulation	Decommissioning expenses recognized as a result of regulation for the years ending Dec. 31 were: (Millions of Dollars) 2017 2016 2015 Annual decommissioning recorded as depreciation expense: (a) (b) $ 20 $ 20 $ 7 (a) Decommissioning expense does not include depreciation of the capitalized nuclear asset retirement costs. (b) Decommissioning expenses in 2017 and 2016 include Minnesota’s retail jurisdiction annual funding requirement of approximately $14 million. The 2015 expense was offset by the DOE settlement refund.

Regulatory Assets and Liabili45

Regulatory Assets and Liabilities (Tables)	12 Months Ended
	Dec. 31, 2017
Regulatory Assets and Liabilities Disclosure [Abstract]
Regulatory Assets	The components of regulatory assets shown on the consolidated balance sheets at Dec. 31, 2017 and 2016 are: (Millions of Dollars) See Note(s) Remaining Dec. 31, 2017 Dec. 31, 2016 Regulatory Assets Current Noncurrent Current Noncurrent Pension and retiree medical obligations (a) 9 Various $ 91 $ 1,499 $ 89 $ 1,549 Net AROs (b) 1, 13, 14 Plant lives — 301 — 379 Excess deferred taxes - TCJA 6 Various — 254 — — Recoverable deferred taxes on AFUDC recorded in plant (c) 1 Plant lives — 244 — 424 Environmental remediation costs 1, 13 Various 16 165 11 165 Contract valuation adjustments (d) 1, 11 Term of related contract 21 93 18 111 Depreciation differences 1 One to fourteen years 20 69 15 90 Purchased power contract costs 13 Term of related contract 3 67 2 70 PI EPU 12 Seventeen years 3 58 3 62 Losses on reacquired debt 4 Term of related debt 5 48 4 23 Conservation programs (e) 1 One to two years 50 32 48 48 State commission adjustments 1 Plant lives 1 29 1 27 Property tax Various 8 24 9 2 Nuclear refueling outage costs 1 One to two years 49 20 49 16 Deferred purchased natural gas and electric energy costs 1 Various 21 13 18 16 Sales true up and revenue decoupling One to two years 37 12 — — Gas pipeline inspection and remediation costs 12 One to two years 24 12 7 14 Renewable resources and environmental initiatives 13 One to three years 48 10 34 23 Other Various 27 55 56 62 Total regulatory assets $ 424 $ 3,005 $ 364 $ 3,081 (a) Includes $179 million and $241 million for the regulatory recognition of the NSP-Minnesota pension expense, of which $9 million and $15 million is included in the current asset at Dec. 31, 2017 and 2016 , respectively. Also included are $8 million and $11 million of regulatory assets related to the nonqualified pension plan, of which $1 million and $3 million is included in the current asset at Dec. 31, 2017 and 2016 , respectively. (b) Includes amounts recorded for future recovery of AROs, less amounts recovered through nuclear decommissioning accruals and gains from decommissioning investments. (c) Includes a write-down of $202 million as a result of the revaluation of deferred tax gross up at the new federal tax rate at Dec. 31, 2017. (d) Includes the fair value of certain long-term PPAs used to meet energy capacity requirements and valuation adjustments on natural gas commodity purchases. (e) Includes costs for conservation programs, as well as incentives allowed in certain jurisdictions.
Regulatory Liabilities	The components of regulatory liabilities shown on the consolidated balance sheets at Dec. 31, 2017 and 2016 are: (Millions of Dollars) See Note(s) Remaining Dec. 31, 2017 Dec. 31, 2016 Regulatory Liabilities Current Noncurrent Current Noncurrent Excess deferred taxes - TCJA (a) 6 Various $ — $ 3,733 $ — $ — Plant removal costs 1, 13 Plant lives — 1,131 — 1,135 Renewable resources and environmental initiatives 12, 13 Various 19 56 5 71 ITC deferrals 1, 6 Various — 42 — 45 Deferred income tax adjustment 1, 6 Various — 38 — 48 Deferred electric, natural gas and steam production costs 1 Less than one year 104 — 98 — Contract valuation adjustments (b) 1, 11 Term of related contract 30 — 22 2 Conservation programs (c) 1, 12 Less than one year 23 — 25 — DOE settlement Less than one year 18 — 20 — Other Various 45 83 51 82 Total regulatory liabilities (d) $ 239 $ 5,083 $ 221 $ 1,383 (a) Primarily relates to the revaluation of recoverable/regulated plant ADIT and $174 million revaluation impact of non-plant ADIT at Dec. 31, 2017. (b) Includes the fair value of certain long-term PPAs used to meet energy capacity requirements and valuation adjustments on natural gas commodity purchases. (c) Includes costs for conservation programs, as well as incentives allowed in certain jurisdictions. (d) Revenue subject to refund of $15 million and $46 million for 2017 and 2016, respectively, is included in other current liabilities.

Other Comprehensive Income (Tab

Other Comprehensive Income (Tables)	12 Months Ended
	Dec. 31, 2017
Stockholders' Equity Note [Abstract]
Changes in Accumulated Other Comprehensive Income (Loss), Net of Tax	Changes in accumulated other comprehensive (loss), net of tax, for the years ended Dec. 31, 2017 and 2016 were as follows: Year Ended Dec. 31, 2017 (Millions of Dollars) Gains and Losses on Cash Flow Hedges Defined Benefit Pension and Postretirement Items Total Accumulated other comprehensive loss at Jan. 1 $ (51 ) $ (59 ) $ (110 ) Other comprehensive loss before reclassifications — (3 ) (3 ) Losses reclassified from net accumulated other comprehensive loss 3 7 10 Net current period other comprehensive income 3 4 7 Adoption of ASU No. 2018-02 (a) (10 ) (12 ) (22 ) Accumulated other comprehensive loss at Dec. 31 $ (58 ) $ (67 ) $ (125 ) (a) In 2017, Xcel Energy implemented ASU No. 2018-02 related to the TCJA, which resulted in reclassification of certain credit balances within net accumulated other comprehensive loss to retained earnings. For further information, see Note 2. Year Ended Dec. 31, 2016 (Millions of Dollars) Gains and Defined Benefit Total Accumulated other comprehensive loss at Jan. 1 $ (55 ) $ (55 ) $ (110 ) Other comprehensive loss before reclassifications — (8 ) (8 ) Losses reclassified from net accumulated other comprehensive loss 4 4 8 Net current period other comprehensive income (loss) 4 (4 ) — Accumulated other comprehensive loss at Dec. 31 $ (51 ) $ (59 ) $ (110 )
Reclassifications out of Accumulated Other Comprehensive Loss	Reclassifications from accumulated other comprehensive loss for the years ended Dec. 31, 2017 and 2016 were as follows: Amounts Reclassified from Accumulated Other Comprehensive Loss (Millions of Dollars) Year Ended Dec. 31, 2017 Year Ended Dec. 31, 2016 Losses (gains) on cash flow hedges: Interest rate derivatives $ 5 (a) $ 6 (a) Total, pre-tax 5 6 Tax benefit (2 ) (2 ) Total, net of tax 3 4 Defined benefit pension and postretirement losses (gains): Amortization of net losses 12 (b) 6 (b) Total, pre-tax 12 6 Tax benefit (5 ) (2 ) Total, net of tax 7 4 Total amounts reclassified, net of tax $ 10 $ 8 (a) Included in interest charges. (b) Included in the computation of net periodic pension and postretirement benefit costs. See Note 9 for detail regarding these benefit plans.

Segments and Related Informat47

Segments and Related Information (Tables)	12 Months Ended
	Dec. 31, 2017
Segment Reporting [Abstract]
Results from Operations by Reportable Segment	(Millions of Dollars) Regulated Electric Regulated Natural Gas All Other Reconciling Eliminations Consolidated Total 2017 Operating revenues from external customers $ 9,676 $ 1,650 $ 78 $ — $ 11,404 Intersegment revenues 2 1 — (3 ) — Total revenues $ 9,678 $ 1,651 $ 78 $ (3 ) $ 11,404 Depreciation and amortization $ 1,298 $ 174 $ 7 $ — $ 1,479 Interest charges and financing costs 449 57 122 — 628 Income tax expense (benefit) 528 23 (9 ) — 542 Net income (loss) 1,066 182 (100 ) — 1,148 (Millions of Dollars) Regulated Electric Regulated Natural Gas All Other Reconciling Eliminations Consolidated Total 2016 Operating revenues from external customers $ 9,500 $ 1,531 $ 76 $ — $ 11,107 Intersegment revenues 1 1 — (2 ) — Total revenues $ 9,501 $ 1,532 $ 76 $ (2 ) $ 11,107 Depreciation and amortization $ 1,136 $ 160 $ 7 $ — $ 1,303 Interest charges and financing costs 450 54 116 — 620 Income tax expense (benefit) 567 76 (62 ) — 581 Net income (loss) 1,067 124 (68 ) — 1,123 (Millions of Dollars) Regulated Electric Regulated Natural Gas All Other Reconciling Eliminations Consolidated Total 2015 Operating revenues from external customers $ 9,276 $ 1,672 $ 76 $ — $ 11,024 Intersegment revenues 2 1 — (3 ) — Total revenues $ 9,278 $ 1,673 $ 76 $ (3 ) $ 11,024 Depreciation and amortization $ 963 $ 155 $ 6 $ — $ 1,124 Interest charges and financing costs 426 50 93 — 569 Income tax expense (benefit) 509 60 (26 ) — 543 Net income (loss) 921 106 (43 ) — 984

Summarized Quarterly Financia48

Summarized Quarterly Financial Data (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2017
Quarterly Financial Information Disclosure [Abstract]
Summarized Quarterly Financial Data (Unaudited)	Quarter Ended (Amounts in millions, except per share data) March 31, 2017 June 30, 2017 Sept. 30, 2017 Dec. 31, 2017 Operating revenues $ 2,946 $ 2,645 $ 3,017 $ 2,796 Operating income 486 460 818 426 Net income 239 227 492 189 EPS total — basic $ 0.47 $ 0.45 $ 0.97 $ 0.37 EPS total — diluted 0.47 0.45 0.97 0.37 Cash dividends declared per common share 0.36 0.36 0.36 0.36 Quarter Ended (Amounts in millions, except per share data) March 31, 2016 June 30, 2016 Sept. 30, 2016 Dec. 31, 2016 Operating revenues $ 2,772 $ 2,500 $ 3,040 $ 2,795 Operating income 490 432 827 465 Net income 241 197 458 227 EPS total — basic $ 0.47 $ 0.39 $ 0.90 $ 0.45 EPS total — diluted 0.47 0.39 0.90 0.45 Cash dividends declared per common share 0.34 0.34 0.34 0.34

Summary of Significant Accoun49

Summary of Significant Accounting Policies (Details)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Conservation Programs [Abstract]
Maximum number of months following end of annual period in which revenues are earned to be included in incentive programs	24 months
Property, Plant and Equipment [Abstract]
Depreciation expense expressed as a percentage of average depreciable property	3.10%	2.90%	2.80%
Nuclear Decommissioning [Abstract]
Minimum amount of time between nuclear decommissioning studies (in years)	3 years
Cash and Cash Equivalents [Abstract]
Maximum number of months of remaining maturity at time of purchase to consider investments in certain instruments as cash equivalents	3 months

Accounting Pronouncements Adopt

Accounting Pronouncements Adoption of New Accounting Pronouncements (Details) - Accounting Standards Update 2018-02 $ in Millions	12 Months Ended
	Dec. 31, 2017USD ($)
Accumulated Other Comprehensive Loss
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Reclassification of tax effects from AOCI to retained earnings	$ (22)
Retained Earnings
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Reclassification of tax effects from AOCI to retained earnings	$ 22

Balance Sheet Data, Accounts Re

Balance Sheet Data, Accounts Receivable (Details) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Accounts receivable, net
Accounts receivable	$ 849	$ 827
Less allowance for bad debts	(52)	(51)
Accounts receivable, net	$ 797	$ 776

Selected Balance Sheet Data Bal

Selected Balance Sheet Data Balance Sheet Related Disclosures, Inventories (Details) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Public Utilities, Inventory [Line Items]
Inventories	$ 610	$ 604
Materials and supplies
Public Utilities, Inventory [Line Items]
Inventories	311	312
Fuel
Public Utilities, Inventory [Line Items]
Inventories	186	182
Natural gas
Public Utilities, Inventory [Line Items]
Inventories	$ 113	$ 110

Selected Balance Sheet Data B53

Selected Balance Sheet Data Balance Sheet Related Disclosures, Property, Plant and Equipment (Details) - USD ($) $ in Millions		Dec. 31, 2017	Dec. 31, 2016
Public Utility, Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross		$ 48,927	$ 46,832
Less accumulated depreciation		(15,000)	(14,381)
Property, plant and equipment, net		34,329	32,842
Electric plant
Public Utility, Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross		39,016	38,221
Natural gas plant
Public Utility, Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross		5,800	5,318
Common and other property
Public Utility, Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross		2,013	1,888
Plant to be retired
Public Utility, Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	[1]	11	32
CWIP
Public Utility, Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross		2,087	1,373
Nuclear fuel
Public Utility, Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross		2,697	2,572
Less accumulated depreciation		$ (2,295)	$ (2,181)
[1]	In the third quarter of 2017, PSCo early retired Valmont Unit 5 and converted Cherokee Unit 4 from a coal-fueled generating facility to natural gas. PSCo also expects Craig Unit 1 to be early retired in approximately 2025. Amounts are presented net of accumulated depreciation.

Borrowings and Other Financin54

Borrowings and Other Financing Instruments, Commercial Paper (Details) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Short-term Debt [Line Items]
Amount outstanding at period end	$ 814	$ 814	$ 392
Commercial Paper
Short-term Debt [Line Items]
Borrowing Limit	3,250	3,250	2,750	$ 2,750
Amount outstanding at period end	814	814	392	846
Average amount outstanding	560	644	485	601
Maximum amount outstanding	$ 814	$ 1,247	$ 1,183	$ 1,360
Weighted average interest rate, computed on a daily basis (percentage)	1.63%	1.35%	0.74%	0.48%
Weighted average interest rate at period end (percentage)	1.90%	1.90%	0.95%	0.82%

Borrowings and Other Financin55

Borrowings and Other Financing Instruments, Letters of Credit (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Line of Credit Facility [Line Items]
Amount outstanding at period end	$ 814	$ 392
Letter of Credit
Line of Credit Facility [Line Items]
Amount outstanding at period end	$ 30	$ 19
Letter of Credit | Letter of Credit
Line of Credit Facility [Line Items]
Line of Credit Facility, Expiration Period	1 year

Borrowings and Other Financin56

Borrowings and Other Financing Instruments, Credit Facilities (Details)		12 Months Ended
		Dec. 31, 2017USD ($)	Dec. 31, 2016USD ($)
Credit Facilities
Line of Credit Facility [Line Items]
Credit facility	[1]	$ 3,250,000,000
Drawn	[2]	843,000,000
Available		$ 2,407,000,000
Xcel Energy Inc. | Credit Facilities
Line of Credit Facility [Line Items]
Line Of Credit Facility Debt To Total Capitalization Ratio (as a percent)		58.00%	57.00%
Credit facility	[1]	$ 1,500,000,000
Drawn	[2]	783,000,000
Available		717,000,000
Direct advances on the credit facility outstanding		0	$ 0
Line Of Credit Facility Maximum Amount Credit Facility May Be Increased		$ 200,000,000
Line Of Credit Facility Maximum Debt To Total Capitalization Ratio Allowed		65.00%
Line Of Credit Facility Minimum Threshhold Percentage Of Subsidiary Assets To Consolidated Assets Required To Initiate Cross Default Provisions		15.00%
Line of Credit Facility, Minimum Amount of Indebtedness in Default to Initiate Cross Default Provisions		$ 75,000,000
Number Of Additional Periods Revolving Termination Date Can Be Extended Subject To Majority Bank Group Approval		2
Term Of Each Additional Period Revolving Termination Date Can Be Extended Subject To Majority Bank Group Approval		1 year
Xcel Energy Inc. | 364-Day Term Loan
Line of Credit Facility [Line Items]
Line of Credit Facility, Expiration Period		364 days
Credit facility		$ 500,000,000
Line of Credit Facility, Fair Value of Amount Outstanding		$ 250,000,000
Number Of Additional Periods Revolving Termination Date Can Be Extended Subject To Majority Bank Group Approval		1
NSP-Minnesota | Credit Facilities
Line of Credit Facility [Line Items]
Line Of Credit Facility Debt To Total Capitalization Ratio (as a percent)		48.00%	48.00%
Credit facility	[1]	$ 500,000,000
Drawn	[2]	44,000,000
Available		456,000,000
Direct advances on the credit facility outstanding		0	$ 0
Line Of Credit Facility Maximum Amount Credit Facility May Be Increased		$ 100,000,000
Line Of Credit Facility Maximum Debt To Total Capitalization Ratio Allowed		65.00%
Number Of Additional Periods Revolving Termination Date Can Be Extended Subject To Majority Bank Group Approval		2
Term Of Each Additional Period Revolving Termination Date Can Be Extended Subject To Majority Bank Group Approval		1 year
PSCo | Credit Facilities
Line of Credit Facility [Line Items]
Line Of Credit Facility Debt To Total Capitalization Ratio (as a percent)		44.00%	45.00%
Credit facility	[1]	$ 700,000,000
Drawn	[2]	3,000,000
Available		697,000,000
Direct advances on the credit facility outstanding		0	$ 0
Line Of Credit Facility Maximum Amount Credit Facility May Be Increased		$ 100,000,000
Line Of Credit Facility Maximum Debt To Total Capitalization Ratio Allowed		65.00%
Number Of Additional Periods Revolving Termination Date Can Be Extended Subject To Majority Bank Group Approval		2
Term Of Each Additional Period Revolving Termination Date Can Be Extended Subject To Majority Bank Group Approval		1 year
SPS | Credit Facilities
Line of Credit Facility [Line Items]
Line Of Credit Facility Debt To Total Capitalization Ratio (as a percent)		46.00%	47.00%
Credit facility	[1]	$ 400,000,000
Drawn	[2]	2,000,000
Available		398,000,000
Direct advances on the credit facility outstanding		0	$ 0
Line Of Credit Facility Maximum Amount Credit Facility May Be Increased		$ 50,000,000
Line Of Credit Facility Maximum Debt To Total Capitalization Ratio Allowed		65.00%
Number Of Additional Periods Revolving Termination Date Can Be Extended Subject To Majority Bank Group Approval		2
Term Of Each Additional Period Revolving Termination Date Can Be Extended Subject To Majority Bank Group Approval		1 year
NSP-Wisconsin | Credit Facilities
Line of Credit Facility [Line Items]
Line Of Credit Facility Debt To Total Capitalization Ratio (as a percent)		47.00%	47.00%
Credit facility	[1]	$ 150,000,000
Drawn	[2]	11,000,000
Available		139,000,000
Direct advances on the credit facility outstanding		$ 0	$ 0
Line Of Credit Facility Maximum Debt To Total Capitalization Ratio Allowed		65.00%
Number Of Additional Periods Revolving Termination Date Can Be Extended Subject To Majority Bank Group Approval		1
Term Of Each Additional Period Revolving Termination Date Can Be Extended Subject To Majority Bank Group Approval		1 year
[1]	These credit facilities mature in June 2021, with the exception of Xcel Energy Inc.’s $500 million 364-day term loan agreement entered into in December 2017.
[2]	Includes outstanding commercial paper, term loan borrowings and letters of credit.

Borrowings and Other Financin57

Borrowings and Other Financing Instruments, Long-Term Borrowings and Other Financing Instruments (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Debt Instrument [Line Items]
2,018	$ 457
2,019	405
2,020	1,256
2,021	425
2,022	905
Xcel Energy Inc. | 364-Day Term Loan
Long-Term Borrowings and Other Financing Instruments [Abstract]
Face amount	$ 500
Xcel Energy Inc. | Senior Unsecured Notes | Series Due March 15, 2021
Long-Term Borrowings and Other Financing Instruments [Abstract]
Face amount		$ 400
Interest rate, stated percentage (in hundredths)	2.40%	2.40%
Maturity Date	Mar. 15, 2021	Mar. 15, 2021
Xcel Energy Inc. | Senior Unsecured Notes | Series Due June 1, 2025
Long-Term Borrowings and Other Financing Instruments [Abstract]
Face amount		$ 350
Interest rate, stated percentage (in hundredths)	3.30%	3.30%
Maturity Date	Jun. 1, 2025	Jun. 1, 2025
Xcel Energy Inc. | Senior Unsecured Notes | Series Due March 15, 2022
Long-Term Borrowings and Other Financing Instruments [Abstract]
Face amount		$ 300
Interest rate, stated percentage (in hundredths)	2.60%	2.60%
Maturity Date	Mar. 15, 2022	Mar. 15, 2022
Xcel Energy Inc. | Senior Unsecured Notes | Series Due Dec. 1, 2026
Long-Term Borrowings and Other Financing Instruments [Abstract]
Face amount		$ 500
Interest rate, stated percentage (in hundredths)	3.35%	3.35%
Maturity Date	Dec. 1, 2026	Dec. 1, 2026
PSCo | First Mortgage Bonds | Series Due June 15, 2047
Long-Term Borrowings and Other Financing Instruments [Abstract]
Face amount	$ 400
Interest rate, stated percentage (in hundredths)	3.80%
Maturity Date	Jun. 15, 2047
PSCo | First Mortgage Bonds | Series Due June 15, 2046
Long-Term Borrowings and Other Financing Instruments [Abstract]
Face amount		$ 250
Interest rate, stated percentage (in hundredths)	3.55%	3.55%
Maturity Date	Jun. 15, 2046	Jun. 15, 2046
NSP-Minnesota | First Mortgage Bonds | Series Due Sept. 15, 2047
Long-Term Borrowings and Other Financing Instruments [Abstract]
Face amount	$ 600
Interest rate, stated percentage (in hundredths)	3.60%
Maturity Date	Sep. 15, 2017
NSP-Minnesota | First Mortgage Bonds | Series Due May 15, 2046
Long-Term Borrowings and Other Financing Instruments [Abstract]
Face amount		$ 350
Interest rate, stated percentage (in hundredths)	3.60%	3.60%
Maturity Date	May 15, 2046	May 15, 2046
SPS | First Mortgage Bonds | Series Due Aug. 15, 2047
Long-Term Borrowings and Other Financing Instruments [Abstract]
Face amount	$ 450
Interest rate, stated percentage (in hundredths)	3.70%
Maturity Date	Aug. 15, 2047
SPS | First Mortgage Bonds | Series Due Aug. 15, 2046
Long-Term Borrowings and Other Financing Instruments [Abstract]
Face amount		$ 300
Interest rate, stated percentage (in hundredths)	3.40%	3.40%
Maturity Date	Aug. 15, 2046	Aug. 15, 2046
NSP-Wisconsin | First Mortgage Bonds | Series Due Dec. 1, 2047
Long-Term Borrowings and Other Financing Instruments [Abstract]
Face amount	$ 100
Interest rate, stated percentage (in hundredths)	3.75%
Maturity Date	Dec. 1, 2047
364-Day Term Loan | Xcel Energy Inc.
Long-Term Borrowings and Other Financing Instruments [Abstract]
Line of Credit Facility, Expiration Period	364 days

Borrowings and Other Financin58

Borrowings and Other Financing Instruments, Deferred Financing Costs (Details) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Debt Disclosure [Abstract]
Deferred Finance Costs, Noncurrent, Net	$ 119	$ 109

Borrowings and Other Financin59

Borrowings and Other Financing Instruments, Capital Stock (Details) - $ / shares	Dec. 31, 2017	Jun. 30, 2017	Dec. 31, 2016
Capital Stock [Abstract]
Common Stock, Shares Authorized (in shares)	1,000,000,000		1,000,000,000
Common Stock, Par Value (in dollars per share)	$ 2.50		$ 2.50
Common Stock, Shares Outstanding (in shares)	507,762,881	507,952,795	507,222,795
Xcel Energy Inc.
Capital Stock [Abstract]
Preferred Stock, Shares Authorized (in shares)	7,000,000
Preferred Stock, Par Value (in dollars per share)	$ 100
Preferred Stock, Shares Outstanding (in shares)	0		0
Common Stock, Shares Authorized (in shares)	1,000,000,000
Common Stock, Shares Outstanding (in shares)	507,762,881		507,222,795
PSCo
Capital Stock [Abstract]
Preferred Stock, Shares Authorized (in shares)	10,000,000
Preferred Stock, Par Value (in dollars per share)	$ 0.01
Preferred Stock, Shares Outstanding (in shares)	0		0
SPS
Capital Stock [Abstract]
Preferred Stock, Shares Authorized (in shares)	10,000,000
Preferred Stock, Par Value (in dollars per share)	$ 1
Preferred Stock, Shares Outstanding (in shares)	0		0

Borrowings and Other Financin60

Borrowings and Other Financing Instruments, Dividend and Other Capital-Related Restrictions (Details) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
PSCo
Dividend and Other Capital-Related Restrictions [Abstract]
Maximum additional long term debt authorized for issuance	$ 1,800
Maximum additional short term debt authorized for issuance	800
NSP-Minnesota
Dividend and Other Capital-Related Restrictions [Abstract]
Additional Cash Dividends On Common Stock Which Could Have Been Paid Per First Mortgage Indenture	$ 1,900	$ 1,700
Equity to total capitalization ratio, low end of range (in hundredths)	47.20%
Equity to total capitalization ratio, high end of range (in hundredths)	57.60%
Equity to total capitalization ratio	52.10%
Unrestricted Retained Earnings Per State Regulatory Commissions Dividend Restrictions	$ 1,100
Capitalization, Short term debt, long term debt and equity	10,400
Maximum total capitalization	$ 11,200
Maximum percentage of short term debt to total capitalization (in hundredths)	15.00%
NSP-Wisconsin
Debt Instrument [Line Items]
Expected equity to total capitalization ratio	51.50%
Dividend and Other Capital-Related Restrictions [Abstract]
Equity to total capitalization ratio	53.10%
Unrestricted Retained Earnings Per State Regulatory Commissions Dividend Restrictions	$ 19
Maximum annual dividends that can be paid if equity capitalization ratio condition is not met	53
Maximum additional long term debt authorized for issuance	250
Maximum additional short term debt authorized for issuance	$ 150
Minimum calendar year average equity to total capitalization ratio authorized by state commission	52.50%	52.50%
SPS
Dividend and Other Capital-Related Restrictions [Abstract]
Unrestricted Retained Earnings Per State Regulatory Commissions Dividend Restrictions	$ 542
Equity to total capitalization ratio (excluding short-term debt), low end of range (in hundredths)	45.00%
Equity to total capitalization ratio (excluding short-term debt), high end of range (in hundredths)	55.00%
Equity to total capitalization ratio (excluding short-term debt) (in hundredths)	53.80%
Maximum additional short term debt authorized for issuance	$ 500

Joint Ownership of Generation61

Joint Ownership of Generation, Transmission and Gas Facilities (Details) $ in Millions	12 Months Ended
	Dec. 31, 2017USD ($)MW
NSP-Minnesota
Jointly Owned Utility Plant [Abstract]
Plant in service	$ 1,812
Accumulated depreciation	653
Construction work in progress	$ 4
Generating capacity (in MW) | MW	517
NSP-Minnesota | Electric Generation | Sherco Unit 3
Jointly Owned Utility Plant [Abstract]
Plant in service	$ 612
Accumulated depreciation	411
Construction work in progress	$ 1
Ownership percentage (in hundredths)	59.00%
NSP-Minnesota | Electric Generation | Sherco Common Facilities Units 1, 2 and 3
Jointly Owned Utility Plant [Abstract]
Plant in service	$ 145
Accumulated depreciation	99
Construction work in progress	$ 1
Ownership percentage (in hundredths)	80.00%
NSP-Minnesota | Electric Generation | Sherco Substation
Jointly Owned Utility Plant [Abstract]
Plant in service	$ 5
Accumulated depreciation	3
Construction work in progress	$ 0
Ownership percentage (in hundredths)	59.00%
NSP-Minnesota | Electric Transmission | Grand Meadow Line and Substation
Jointly Owned Utility Plant [Abstract]
Plant in service	$ 11
Accumulated depreciation	2
Construction work in progress	$ 0
Ownership percentage (in hundredths)	50.00%
NSP-Minnesota | Electric Transmission | CapX2020 Transmission
Jointly Owned Utility Plant [Abstract]
Plant in service	$ 1,039
Accumulated depreciation	138
Construction work in progress	$ 2
Ownership percentage (in hundredths)	51.00%
NSP-Wisconsin
Jointly Owned Utility Plant [Abstract]
Plant in service	$ 162
Accumulated depreciation	12
Construction work in progress	205
NSP-Wisconsin | Electric Transmission | CapX2020 Transmission
Jointly Owned Utility Plant [Abstract]
Plant in service	162
Accumulated depreciation	12
Construction work in progress	$ 103
Ownership percentage (in hundredths)	81.00%
NSP-Wisconsin | Electric Transmission | La Crosse, Wis. to Madison, Wis.
Jointly Owned Utility Plant [Abstract]
Plant in service	$ 0
Accumulated depreciation	0
Construction work in progress	$ 102
Ownership percentage (in hundredths)	37.00%
PSCo
Jointly Owned Utility Plant [Abstract]
Plant in service	$ 1,579
Accumulated depreciation	412
Construction work in progress	$ 5
Generating capacity (in MW) | MW	816
PSCo | Electric Generation | Hayden Unit 1
Jointly Owned Utility Plant [Abstract]
Plant in service	$ 150
Accumulated depreciation	72
Construction work in progress	$ 1
Ownership percentage (in hundredths)	76.00%
PSCo | Electric Generation | Hayden Unit 2
Jointly Owned Utility Plant [Abstract]
Plant in service	$ 149
Accumulated depreciation	65
Construction work in progress	$ 0
Ownership percentage (in hundredths)	37.00%
PSCo | Electric Generation | Hayden Common Facilities
Jointly Owned Utility Plant [Abstract]
Plant in service	$ 39
Accumulated depreciation	20
Construction work in progress	$ 0
Ownership percentage (in hundredths)	53.00%
PSCo | Electric Generation | Craig Units 1 and 2
Jointly Owned Utility Plant [Abstract]
Plant in service	$ 81
Accumulated depreciation	39
Construction work in progress	$ 0
Ownership percentage (in hundredths)	10.00%
PSCo | Electric Generation | Craig Common Facilities 1, 2 and 3
Jointly Owned Utility Plant [Abstract]
Plant in service	$ 39
Accumulated depreciation	20
Construction work in progress	$ 0
Ownership percentage (in hundredths)	7.00%
PSCo | Electric Generation | Comanche Unit 3
Jointly Owned Utility Plant [Abstract]
Plant in service	$ 890
Accumulated depreciation	118
Construction work in progress	$ 0
Ownership percentage (in hundredths)	67.00%
PSCo | Electric Generation | Comanche Common Facilities
Jointly Owned Utility Plant [Abstract]
Plant in service	$ 24
Accumulated depreciation	2
Construction work in progress	$ 3
Ownership percentage (in hundredths)	82.00%
PSCo | Electric Transmission | Transmission and Other Facilities, including Substations
Jointly Owned Utility Plant [Abstract]
Plant in service	$ 177
Accumulated depreciation	67
Construction work in progress	$ 1
Ownership percentage of group of jointly owned facilities	Various
PSCo | Gas Transportation | Rifle to Avon
Jointly Owned Utility Plant [Abstract]
Plant in service	$ 22
Accumulated depreciation	8
Construction work in progress	$ 0
Ownership percentage (in hundredths)	60.00%
PSCo | Gas Transportation | Gas Transportation Compressor [Member]
Jointly Owned Utility Plant [Abstract]
Plant in service	$ 8
Accumulated depreciation	1
Construction work in progress	$ 0
Ownership percentage (in hundredths)	50.00%

Income Taxes (Details)

Income Taxes (Details) - USD ($)		1 Months Ended	3 Months Ended		12 Months Ended
		Dec. 31, 2017	Sep. 30, 2017	Sep. 30, 2015	Dec. 31, 2017	Dec. 31, 2016		Dec. 31, 2015		Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2017	Dec. 31, 2016		Dec. 31, 2015
Federal Tax Reform [Abstract]
Tax Cuts and Jobs Act of 2017, Corporate Federal Tax Rate		21.00%
Tax Cuts and Jobs Act of 2017, Net Operating Loss Deduction Limitation, Percent of Taxable income		80.00%
Reclassification of deferred taxes to regulatory liabilities, grossed-up for taxes					$ 3,800,000,000
Regulatory liability, customer refunds, weighted average period					30 years
Provisional income tax expense for tax reform					$ 23,000,000
Consolidated Appropriations Act of 2016 [Abstract]
Excise Tax Delay					2 years
Federal Tax Loss Carryback Claims [Abstract]
Number Of Years Of Tax Loss Carryback Period					two
Tax Adjustments, Settlements, and Unusual Provisions								$ 5,000,000		$ 17,000,000	$ 12,000,000	$ 15,000,000
Tax Audits [Abstract]
Unrecognized Tax Benefits, Interest on Income Taxes Accrued													$ 0	$ (3,000,000)		$ 0
Unrecognized Tax Benefits, Interest on Income Taxes Accrued					$ 3,000,000	$ (3,000,000)
Unrecognized Tax Benefits, Income Tax Penalties Accrued													0	0		0
Unrecognized Tax Benefits [Abstract]
Unrecognized tax benefit — Permanent tax positions													20,000,000	30,000,000
Unrecognized tax benefit — Temporary tax positions													19,000,000	104,000,000
Total unrecognized tax benefit		$ 39,000,000			134,000,000	121,000,000		67,000,000		67,000,000			39,000,000	134,000,000		121,000,000
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Balance at Jan. 1					134,000,000	121,000,000		67,000,000
Unrecognized Tax Benefits, Increase Resulting from Current Period Tax Positions					6,000,000	8,000,000		27,000,000
Unrecognized Tax Benefits, Decrease Resulting from Current Period Tax Positions					(4,000,000)	0		(5,000,000)
Unrecognized Tax Benefits Increases Resulting From Prior Period Tax Positions					15,000,000	10,000,000		35,000,000
Unrecognized Tax Benefits Decreases Resulting From Prior Period Tax Positions					(105,000,000)	(5,000,000)		(3,000,000)
Unrecognized Tax Benefits, Decrease Resulting from Settlements with Taxing Authorities					(7,000,000)	0		0
Balance at Dec. 31		$ 39,000,000			$ 39,000,000	$ 134,000,000		$ 121,000,000		$ 67,000,000
Tax Benefits Associated With NOL And Tax Credit Carryforwards [Abstract]
NOL and tax credit carryforwards													(31,000,000)	(44,000,000)
Upper bound of decrease in unrecognized tax benefit that is reasonably possible													15,000,000
Effective Income Tax Rate Reconciliation, Percent [Abstract]
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent					35.00%	35.00%	[1]	35.00%	[1]
Effective Income Tax Rate Reconciliation, State and Local Income Taxes, Percent					3.90%	3.90%	[1]	3.90%	[1]
Effective Income Tax Rate Reconciliation, Tax Credit, Percent					(4.70%)	(3.40%)	[1]	(1.80%)	[1]
Effective Income Tax Rate Reconciliation Regulatory Differences Utility Plant Items, Percent					(1.00%)	(0.80%)	[1]	(0.90%)	[1]
Tax reform, Percent					1.40%	0.00%	[1]	0.00%	[1]
Regulatory differences - effects of rate changes, Percent	[2]				(0.10%)	(0.10%)	[1]	(0.10%)	[1]
Regulatory differences - other utility plant items, Percent					(0.70%)	(0.50%)	[1]	(0.90%)	[1]
Effective Income Tax Rate Reconciliation Change In Unrecognized Tax Benefits, Percent					(0.60%)	0.20%	[1]	0.60%	[1]
Effective Income Tax Reconciliation, Net operating loss carryback, Percent					(0.00%)	(0.00%)	[1]	(0.30%)	[1]
Effective Income Tax Rate Reconciliation, Other Adjustments, Percent					(1.10%)	(0.20%)	[1]	0.00%	[1]
Effective Income Tax Rate Reconciliation, Percent					32.10%	34.10%	[1]	35.50%	[1]
Components of Income Tax Expense (Benefit), Continuing Operations [Abstract]
Current Federal Tax Expense (Benefit)					$ 1,000,000	$ (3,000,000)		$ (36,000,000)
Current State and Local Tax Expense (Benefit)					(11,000,000)	(4,000,000)		2,000,000
Current Change In Unrecognized Tax Expense (Benefit)					(83,000,000)	6,000,000		46,000,000
Deferred Federal Income Tax Expense (Benefit)					460,000,000	477,000,000		480,000,000
Deferred State and Local Income Tax Expense (Benefit)					107,000,000	112,000,000		92,000,000
Deferred Change In Unrecognized Tax Expense (Benefit)					73,000,000	(2,000,000)		(36,000,000)
Deferred investment tax credits					(5,000,000)	(5,000,000)		(5,000,000)
Income Tax Expense (Benefit)					542,000,000	581,000,000		543,000,000
Deferred Income Tax Expense (Benefit), Continuing Operations [Abstract]
Deferred tax expense (benefit) excluding selected items					(2,939,000,000)	631,000,000		547,000,000
Amortization and adjustments to deferred income taxes on income tax regulatory assets and liabilities					3,583,000,000	(45,000,000)		(12,000,000)
Other Comprehensive Income (Loss), Tax					(4,000,000)	1,000,000		1,000,000
Deferred Income Tax Expense (Benefit)					$ 640,000,000	$ 587,000,000		$ 536,000,000
Deferred Tax Liabilities, Gross [Abstract]
Deferred Tax Liabilities, Property, Plant and Equipment													4,989,000,000	7,697,000,000	[3]
Deferred Tax Liabilities, Regulatory Assets													565,000,000	152,000,000	[3]
Pension expense													199,000,000	298,000,000	[3]
Deferred Tax Liabilities, Other													69,000,000	89,000,000	[3]
Deferred Tax Liabilities, Gross													5,822,000,000	8,236,000,000	[3]
Deferred Tax Assets, Gross [Abstract]
Deferred Tax Assets Regulatory Liabilities													886,000,000	(132,000,000)	[3]
Deferred Tax Assets Tax credit carryforward													607,000,000	498,000,000	[3]
Deferred Tax Assets, Operating Loss Carryforwards													293,000,000	754,000,000	[3]
Deferred Tax Assets, Valuation Allowance													(77,000,000)	(57,000,000)	[3]
Deferred Tax Assets, Tax Deferred Expense, Compensation and Benefits, Employee Benefits													132,000,000	205,000,000	[3]
Deferred Tax Assets Deferred Investment Tax Credits													17,000,000	27,000,000	[3]
Deferred Tax Assets Unbilled Revenue Fuel Costs													12,000,000	11,000,000	[3]
Deferred Tax Assets Rate Refund													10,000,000	33,000,000	[3]
Deferred Tax Assets, Other													97,000,000	113,000,000	[3]
Deferred Tax Assets, Net of Valuation Allowance													1,977,000,000	1,452,000,000	[3]
Deferred Tax Liabilities, Net													3,845,000,000	6,784,000,000	[3]
Internal Revenue Service (IRS)
Tax Audits [Abstract]
Earliest year subject to examination					2,009
Tax years under examination				2012 and 2013								2010 and 2011
Year of carryback claim under examination												2,009
Potential Tax Adjustments					$ 14,000,000
Operating Loss Carryforwards													1,072,000,000	1,916,000,000
Tax Credit Carryforward, Amount													517,000,000	424,000,000
Tax Credit Carryforward, Valuation Allowance													(5,000,000)	0
Carryforward expiration date range, low					2,021
Carryforward expiration date range, high					2,037
Tax years under examination, Concluded			2012 and 2013
Colorado
Tax Audits [Abstract]
Earliest year subject to examination					2,009
Tax years under examination					None
Minnesota
Tax Audits [Abstract]
Earliest year subject to examination					2,009
Tax years under examination						2010 through 2014
Texas
Tax Audits [Abstract]
Earliest year subject to examination					2,009
Tax years under examination						2009 and 2010
Wisconsin
Tax Audits [Abstract]
Earliest year subject to examination					2,012
Tax years under examination						2012 and 2013
State and Local Jurisdiction
Tax Audits [Abstract]
Operating Loss Carryforwards													1,592,000,000	1,949,000,000
Operating Loss Carryforwards, Valuation Allowance													(55,000,000)	(59,000,000)
Tax Credit Carryforward Net Of Federal Detriment	[4]												90,000,000	74,000,000
Valuation Allowance for Tax Credit Carryforward Net of Federal Benefit	[5]												(68,000,000)	(54,000,000)
Federal detriment													24,000,000	40,000,000
Federal Benefit													$ 18,000,000	$ 29,000,000
Carryforward expiration date range, low					2,018
Carryforward expiration date range, high					2,037
Consolidated Appropriations Act of 2016; 2015, 2016, 2017 Impact [Member]
Consolidated Appropriations Act of 2016 [Abstract]
Bonus depreciation rate, Percent													50.00%
Consolidated Appropriations Act of 2016; 2016 Impact [Member]
Consolidated Appropriations Act of 2016 [Abstract]
Production Tax Credit Rate, Percent													100.00%
Consolidated Appropriations Act of 2016; 2017 Impact [Member]
Consolidated Appropriations Act of 2016 [Abstract]
Production Tax Credit Rate, Percent													80.00%
Consolidated Appropriations Act of 2016; 2018 Impact [Member]
Consolidated Appropriations Act of 2016 [Abstract]
Production Tax Credit Rate, Percent													60.00%
Consolidated Appropriations Act of 2016; 2019 Impact [Member]
Consolidated Appropriations Act of 2016 [Abstract]
Production Tax Credit Rate, Percent													40.00%
Investment Tax Credit Rate, Percent													30.00%
Consolidated Appropriations Act of 2016; 2020 Impact [Member]
Consolidated Appropriations Act of 2016 [Abstract]
Investment Tax Credit Rate, Percent													26.00%
Consolidated Appropriations Act of 2016; 2021 Impact [Member]
Consolidated Appropriations Act of 2016 [Abstract]
Investment Tax Credit Rate, Percent													22.00%
Consolidated Appropriations Act of 2016; After 2021 Impact [Member]
Consolidated Appropriations Act of 2016 [Abstract]
Investment Tax Credit Rate, Percent													10.00%
Consolidated Appropriations Act of 2016; 2015 Impact [Member]
Consolidated Appropriations Act of 2016 [Abstract]
Other Deductions and Charges																1,200,000,000
Federal R&E Benefit																7,000,000
Tax Audits [Abstract]
Federal detriment																4,000,000
Federal Benefit																$ 5,000,000
Plant Related Regulatory Liability [Member]
Federal Tax Reform [Abstract]
Tax Cuts and Jobs Act of 2017, Incomplete Accounting, Change in Tax Rate, Regulatory Liability, Provisional Income Tax (Expense) Benefit					$ 2,700,000,000
Non-Plant Related Regulated Liability [Member]
Federal Tax Reform [Abstract]
Tax Cuts and Jobs Act of 2017, Incomplete Accounting, Change in Tax Rate, Regulatory Liability, Provisional Income Tax (Expense) Benefit					174,000,000
Non-Plant Related Regulatory Asset [Member]
Federal Tax Reform [Abstract]
Tax Cuts and Jobs Act of 2017, Incomplete Accounting, Change in Tax Rate, Regulatory Asset, Provisional Income Tax Expense (Benefit)					$ 254,000,000
[1]	The prior periods included in this footnote have been reclassified to conform to current year presentation.
[2]	The amortization of excess deferred taxes.
[3]	The prior period included in this footnote has been reclassified to conform to current year presentation.
[4]	State tax credit carryforwards are net of federal detriment of $24 million and $40 million as of Dec. 31, 2017 and 2016, respectively.
[5]	Valuation allowances for state tax credit carryforwards were net of federal benefit of $18 million and $29 million as of Dec. 31, 2017 and 2016, respectively.

Earnings Per Share (Details)

Earnings Per Share (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Earnings Per Share [Abstract]
Stock Repurchase Program, Number of Shares Authorized to be Repurchased											3
Stock Repurchased During Period, Shares									0.1
Stock Repurchased During Period, Value									$ 3
Dilutive Impact of Common Stock Equivalents on Earnings per Share (Abstract]
Net income	$ 189	$ 492	$ 227	$ 239	$ 227	$ 458	$ 197	$ 241	1,148	$ 1,123	$ 984
Basic earnings per share [Abstract]
Earnings available to common shareholders									$ 1,148	$ 1,123	$ 984
Weighted average common shares outstanding - basic (in shares)									509	508.8	507.8
Earnings available to common shareholders - basic (in dollars per share)	$ 0.37	$ 0.97	$ 0.45	$ 0.47	$ 0.45	$ 0.90	$ 0.39	$ 0.47	$ 2.26	$ 2.21	$ 1.94
Effect of dilutive securities [Abstract]
401(k) equity awards (in shares)									0.6	0.7	0.4
Diluted earnings per share [Abstract]
Earnings available to common shareholders									$ 1,148	$ 1,123	$ 984
Weighted average common shares outstanding - diluted (in shares)									509.1	509	508.2
Earnings available to common shareholders - diluted (in dollars per share)	$ 0.37	$ 0.97	$ 0.45	$ 0.47	$ 0.45	$ 0.90	$ 0.39	$ 0.47	$ 2.25	$ 2.21	$ 1.94

Share-Based Compensation, Restr

Share-Based Compensation, Restricted Stock (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Equity Instruments Other than Options Activity [Roll Forward]
Balance at January 1 (in shares)	984
Granted (in shares)	503	522	496
Vested (in shares)	(467)	(500)	(800)
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Forfeited in Period (in shares)	(70)
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Forfeitures, Weighted Average Grant Date Fair Value (in dollars per share)	$ 37.12
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Fair Value	$ 22	$ 22	$ 27
Dividend equivalents (in shares)	45
Balance at December 31 (in shares)	995	984
Equity Instruments Other than Options, Weighted Average Grant Date Fair Value [Abstract]
Balance at January 1, weighted average grant date fair value (in dollars per share)	$ 36.05
Granted, weighted average grant date fair value (in dollars per share)	41.02	$ 36	$ 36.09
Vested, weighted average grant date fair value (in dollars per share)	36.17
Dividend equivalents, weighted average grant date fair value (in dollars per share)	37.20
Balance at December 31, weighted average grant date fair value (in dollars per share)	$ 38.48	$ 36.05
Equity Instruments Other than Options, Additional Disclosures [Abstract]
Award Vesting Period (in years)	3 years
Restricted Stock [Member]
Equity Instruments Other than Options Activity [Roll Forward]
Balance at January 1 (in shares)	67
Granted (in shares)	15	20	42
Vested (in shares)	(40)
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Forfeited in Period (in shares)	0
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Forfeitures, Weighted Average Grant Date Fair Value (in dollars per share)	$ 0
Dividend equivalents (in shares)	2
Balance at December 31 (in shares)	44	67
Equity Instruments Other than Options, Weighted Average Grant Date Fair Value [Abstract]
Balance at January 1, weighted average grant date fair value (in dollars per share)	$ 35.43
Granted, weighted average grant date fair value (in dollars per share)	42	$ 38.82	$ 35
Vested, weighted average grant date fair value (in dollars per share)	33.36
Dividend equivalents, weighted average grant date fair value (in dollars per share)	44.69
Balance at December 31, weighted average grant date fair value (in dollars per share)	$ 39.71	$ 35.43
Equity Instruments Other than Options, Additional Disclosures [Abstract]
Award Vesting Period (in years)	3 years
Service-based awards [Member]
Equity Instruments Other than Options Activity [Roll Forward]
Granted (in shares)	300	300	300

Share-Based Compensation, Other

Share-Based Compensation, Other Equity Awards (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Equity Instruments Other than Options Activity [Roll Forward]
Balance at January 1 (in shares)	984
Granted (in shares)	503	522	496
Forfeited (in shares)	(70)
Vested (in shares)	(467)	(500)	(800)
Dividend equivalents (in shares)	45
Balance at December 31 (in shares)	995	984
Equity Instruments Other than Options, Weighted Average Grant Date Fair Value [Abstract]
Balance at January 1, weighted average grant date fair value (in dollars per share)	$ 36.05
Granted, weighted average grant date fair value (in dollars per share)	41.02	$ 36	$ 36.09
Forfeited, weighted average grant date fair value (in dollars per share)	37.12
Vested, weighted average grant date fair value (in dollars per share)	36.17
Dividend equivalents, weighted average grant date fair value (in dollars per share)	37.20
Balance at December 31, weighted average grant date fair value (in dollars per share)	$ 38.48	$ 36.05
Equity Instruments Other than Options, Additional Disclosures [Abstract]
Award Vesting Period (in years)	3 years
Total fair value of nonvested equity awards	$ 48
Weighted average remaining contractual life of nonvested equity awards (in years)	1 year 8 months
Total fair value of equity awards vested during the period	$ 22	$ 22	$ 27
Performance-based awards [Member]
Equity Instruments Other than Options, Additional Disclosures [Abstract]
Award Vesting Period (in years)	3 years
Service-based awards [Member]
Equity Instruments Other than Options Activity [Roll Forward]
Granted (in shares)	300	300	300
Equity Award Granted Between 2011 and 2013 | Performance-based awards [Member] | Minimum
Equity Instruments Other than Options, Additional Disclosures [Abstract]
Percentage payout for performance-based equity awards	0.00%
Equity Award Granted Between 2011 and 2013 | Performance-based awards [Member] | Maximum
Equity Instruments Other than Options, Additional Disclosures [Abstract]
Percentage payout for performance-based equity awards	150.00%
Equity Award Granted Between 2014 and 2017 | Performance-based awards [Member] | Minimum
Equity Instruments Other than Options, Additional Disclosures [Abstract]
Percentage payout for performance-based equity awards	0.00%
Equity Award Granted Between 2014 and 2017 | Performance-based awards [Member] | Maximum
Equity Instruments Other than Options, Additional Disclosures [Abstract]
Percentage payout for performance-based equity awards	200.00%

Share-Based Compensation, Stock

Share-Based Compensation, Stock Equivalent Unit Plan (Details) - $ / shares	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Equity Instruments Other than Options Activity [Roll Forward]
Balance at January 1 (in shares)	984,000
Granted (in shares)	503,000	522,000	496,000
Dividend equivalents (in shares)	45,000
Balance at December 31 (in shares)	995,000	984,000
Equity Instruments Other than Options, Weighted Average Grant Date Fair Value [Abstract]
Balance at January 1, weighted average grant date fair value (in dollars per share)	$ 36.05
Granted, weighted average grant date fair value (in dollars per share)	41.02	$ 36	$ 36.09
Dividend equivalents, weighted average grant date fair value (in dollars per share)	37.20
Balance at December 31, weighted average grant date fair value (in dollars per share)	$ 38.48	$ 36.05
Stock Equivalent Units [Member]
Equity Instruments Other than Options Activity [Roll Forward]
Balance at January 1 (in shares)	750,000
Granted (in shares)	51,000	49,000	60,000
Units distributed (in shares)	(71,000)
Dividend equivalents (in shares)	23,000
Balance at December 31 (in shares)	753,000	750,000
Equity Instruments Other than Options, Weighted Average Grant Date Fair Value [Abstract]
Balance at January 1, weighted average grant date fair value (in dollars per share)	$ 27.39
Granted, weighted average grant date fair value (in dollars per share)	46.05	$ 40.68	$ 34.58
Units distributed, weighted average grant date fair value (in dollars per share)	20.52
Dividend equivalents, weighted average grant date fair value (in dollars per share)	45.24
Balance at December 31, weighted average grant date fair value (in dollars per share)	$ 29.83	$ 27.39
Equity Instruments Other than Options, Additional Disclosures [Abstract]
Number of shares of common stock into which the share-based compensation can be converted (in shares)	1

Share-Based Compensation, TSR L

Share-Based Compensation, TSR Liability Awards (Details) shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2017USD ($)Partiesshares	Dec. 31, 2016USD ($)shares	Dec. 31, 2015USD ($)shares
Equity Instruments Other than Options Activity [Roll Forward]
Granted (in shares)	503	522	496
Equity Instruments Other than Options, Additional Disclosures [Abstract]
Award Vesting Period (in years)	3 years
Number of Utilities in Peer Group | Parties	22
TSR Liability Awards
Equity Instruments Other than Options Activity [Roll Forward]
Granted (in shares)	240	264	224
Equity Instruments Other than Options, Additional Disclosures [Abstract]
Award Vesting Period (in years)	3 years
Amount of cash used to settle TSR liability awards | $	$ 7,000
Awards settled (in shares)	454	354	0
Settlement amount (cash and common stock) | $	$ 19,083	$ 13,724	$ 0
TSR Liability Awards | Minimum
Equity Instruments Other than Options, Additional Disclosures [Abstract]
Percentage payout for TSR liability awards	0.00%
TSR Liability Awards | Maximum
Equity Instruments Other than Options, Additional Disclosures [Abstract]
Percentage payout for TSR liability awards	200.00%

Share-Based Compensation, Share

Share-Based Compensation, Share-Based Compensation Expense (Details) - USD ($) shares in Thousands, $ in Millions		12 Months Ended
		Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Share-Based Compensation Expense [Abstract]
Granted (in shares)		503	522	496
Compensation cost for share-based awards	[1]	$ 57	$ 41	$ 45
Tax benefit recognized in income		22	16	$ 18
Unrecognized compensation cost related to nonvested share-based compensation awards		$ 44	$ 29
Weighted-average period for recognition of unrecognized compensation cost related to nonvested share-based compensation awards (in years)		1 year 8 months
Award Vesting Period (in years)		3 years
Xcel Energy Inc. 2015 Omnibus Incentive Plan [Member]
Share-Based Compensation Expense [Abstract]
Number of shares of common stock approved for issuance (in shares)		7,000
Xcel Energy Inc. Long-Term Incentive Plan [Member]
Share-Based Compensation Expense [Abstract]
Number of shares of common stock approved for issuance (in shares)		8,300
Xcel Energy Inc. Executive Annual Incentive Award Plan [Member]
Share-Based Compensation Expense [Abstract]
Number of shares of common stock approved for issuance (in shares)		1,200
Service-based awards [Member]
Share-Based Compensation Expense [Abstract]
Granted (in shares)		300	300	300
[1]	Compensation costs for share-based payment arrangements are included in O&M expense in the consolidated statements of income.

Benefit Plans and Other Postr69

Benefit Plans and Other Postretirement Benefits, Employees Represented by Local Labor Unions (Details)	Dec. 31, 2017Employee
Employees Represented by Local Labor Unions Under Collective Bargaining Agreements Receiving Benefits [Abstract]
Approximate percent of employees receiving benefits who are represented by local labor unions under collective bargaining agreements (as a percent)	46.00%
NSP-Minnesota
Employees Represented by Local Labor Unions Under Collective Bargaining Agreements Receiving Benefits [Abstract]
Number of bargaining employees receiving benefits under several collective bargaining agreements	1,858
Number of nuclear operation bargaining employees receiving benefits under several collective bargaining-agreements	248
NSP-Wisconsin
Employees Represented by Local Labor Unions Under Collective Bargaining Agreements Receiving Benefits [Abstract]
Number of bargaining employees receiving benefits under several collective bargaining agreements	383
PSCo
Employees Represented by Local Labor Unions Under Collective Bargaining Agreements Receiving Benefits [Abstract]
Number of bargaining employees receiving benefits under several collective bargaining agreements	1,835
SPS
Employees Represented by Local Labor Unions Under Collective Bargaining Agreements Receiving Benefits [Abstract]
Number of bargaining employees receiving benefits under several collective bargaining agreements	791

Benefit Plans and Other Postr70

Benefit Plans and Other Postretirement Benefits, Fair Value Hierarchy (Details)	12 Months Ended
	Dec. 31, 2017
Commingled funds | Maximum
Defined Benefit Plan Disclosure [Line Items]
Notice period for investment redemption	90 days
Real estate funds | Minimum
Defined Benefit Plan Disclosure [Line Items]
Notice period for investment redemption	45 days
Real estate funds | Maximum
Defined Benefit Plan Disclosure [Line Items]
Notice period for investment redemption	90 days

Benefit Plans and Other Postr71

Benefit Plans and Other Postretirement Benefits, Pension Benefits (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Supplemental Executive Retirement Plan (SERP) and Nonqualified Pension Plan
Pension Benefits [Abstract]
Total benefit obligation	$ 37	$ 44
Net benefit cost recognized for financial reporting	5	8
Pension Plan [Member]
Pension Benefits [Abstract]
Total benefit obligation	3,828	3,682	$ 3,568
Net benefit cost recognized for financial reporting	$ 139	$ 122	$ 128
Minimum number of years historical achieved weighted average annual returns are used to determine investment return assumptions (in years)	20 years
Expected average long-term rate of return on assets (as a percent)	6.87%	6.87%	7.09%
Expected average long-term rate of return on assets for next fiscal year (as a percent)	6.87%
Target Pension Asset Allocations [Abstract]
Target pension asset allocations (as a percent)	100.00%	100.00%
Pension Plan [Member] | Domestic and international equity securities
Target Pension Asset Allocations [Abstract]
Target pension asset allocations (as a percent)	36.00%	38.00%
Pension Plan [Member] | Long-duration fixed income and interest rate swap securities
Target Pension Asset Allocations [Abstract]
Target pension asset allocations (as a percent)	27.00%	27.00%
Pension Plan [Member] | Short-to-intermediate fixed income securities
Target Pension Asset Allocations [Abstract]
Target pension asset allocations (as a percent)	20.00%	16.00%
Pension Plan [Member] | Alternative investments
Target Pension Asset Allocations [Abstract]
Target pension asset allocations (as a percent)	15.00%	17.00%
Pension Plan [Member] | Cash
Target Pension Asset Allocations [Abstract]
Target pension asset allocations (as a percent)	2.00%	2.00%

Benefit Plans and Other Postr72

Benefit Plans and Other Postretirement Benefits, Fair Value of Pension Plan Assets (Details) - Pension Plan [Member] - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	$ 3,088	$ 2,856	$ 2,884
Plan assets at net asset value	1,076	997
Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	1,335	1,207
Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	677	652
Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Cash equivalents
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	196	113
Plan assets at net asset value	0	0
Cash equivalents | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	196	113
Cash equivalents | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Cash equivalents | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
U.S. equity funds
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	513	491
Plan assets at net asset value	0	0
U.S. equity funds | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	513	491
U.S. equity funds | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
U.S. equity funds | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Non U.S. equity funds
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	291	369
Plan assets at net asset value	199	202
Non U.S. equity funds | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	92	167
Non U.S. equity funds | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Non U.S. equity funds | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
U.S. corporate bond funds
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	369	268
Plan assets at net asset value	0	0
U.S. corporate bond funds | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	369	268
U.S. corporate bond funds | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
U.S. corporate bond funds | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Emerging market equity funds
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	314	194
Plan assets at net asset value	314	194
Emerging market equity funds | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Emerging market equity funds | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Emerging market equity funds | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Emerging market debt funds
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	241	164
Plan assets at net asset value	166	85
Emerging market debt funds | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	75	79
Emerging market debt funds | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Emerging market debt funds | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Commodity funds
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		21
Plan assets at net asset value		21
Commodity funds | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		0
Commodity funds | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		0
Commodity funds | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		0
Private equity investments
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	84	101
Plan assets at net asset value	84	101
Private equity investments | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Private equity investments | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Private equity investments | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Real estate
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	195	184
Plan assets at net asset value	195	184
Real estate | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Real estate | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Real estate | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Other commingled funds
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	122	210
Plan assets at net asset value	117	210
Other commingled funds | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	5	0
Other commingled funds | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Other commingled funds | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Government securities
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	356	364
Plan assets at net asset value	0	0
Government securities | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Government securities | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	356	364
Government securities | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
U.S. corporate bonds
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	272	238
Plan assets at net asset value	0	0
U.S. corporate bonds | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
U.S. corporate bonds | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	272	238
U.S. corporate bonds | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Non U.S. corporate bonds
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	45	38
Plan assets at net asset value	0	0
Non U.S. corporate bonds | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Non U.S. corporate bonds | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	45	38
Non U.S. corporate bonds | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Mortgage-backed securities
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		6
Plan assets at net asset value		0
Mortgage-backed securities | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		0
Mortgage-backed securities | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		6
Mortgage-backed securities | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		0
Asset-backed securities
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		3
Plan assets at net asset value		0
Asset-backed securities | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		0
Asset-backed securities | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		3
Asset-backed securities | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		0
U.S. equities
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	114	89
Plan assets at net asset value	0	0
U.S. equities | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	114	89
U.S. equities | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
U.S. equities | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Other
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	(24)	3
Plan assets at net asset value	1	0
Other | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	(29)	0
Other | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	4	3
Other | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	$ 0	$ 0

Benefit Plans and Other Postr73

Benefit Plans and Other Postretirement Benefits, Pension Plan Benefit Obligations, Cash Flows and Benefit Costs (Details) $ in Millions		1 Months Ended	12 Months Ended
		Jan. 31, 2018USD ($)Plan	Dec. 31, 2017USD ($)Plan	Dec. 31, 2016USD ($)Plan	Dec. 31, 2015USD ($)Plan
Components of Net Periodic Benefit Cost (Credit) [Abstract]
Settlement Charge Recognized in Operating and Maintenance Expenses			$ 2,303	$ 2,326	$ 2,330
Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Accumulated Benefit Obligation at Dec. 31			3,612	3,489
Change in Projected Benefit Obligation [Roll Forward]
Obligation at Jan. 1		$ 3,828	3,682	3,568
Service cost			94	92	99
Interest cost			147	160	149
Plan amendments			(13)	2
Actuarial loss			259	186
Benefit payments	[1]		(341)	(326)
Obligation at Dec. 31			3,828	3,682	3,568
Change in Fair Value of Plan Assets [Roll Forward]
Fair value of plan assets at Jan. 1		$ 3,088	2,856	2,884
Actual return (loss) on plan assets			411	172
Employer contributions			162	125
Benefit payments	[1]		(341)	(325)
Fair value of plan assets at Dec. 31			3,088	2,856	$ 2,884
Defined Benefit Plan, Plan Assets, Payment for Settlement			174
Funded Status of Plans at Dec. 31 [Abstract]
Funded status	[2]		(740)	(826)
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost [Abstract]
Net loss			1,709	1,836
Prior service (credit) cost			(25)	(5)
Total			1,684	1,831
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost Have Been Recorded as Follows Based Upon Expected Recovery in Rates [Abstract]
Current regulatory assets			100	101
Noncurrent regulatory assets			1,511	1,650
Deferred income taxes			19	31
Net-of-tax accumulated other comprehensive income			54	49
Total			$ 1,684	$ 1,831
Significant Assumptions Used to Measure Benefit Obligations [Abstract]
Discount rate for year-end valuation (as a percent)			3.63%	4.13%
Expected average long-term increase in compensation level (as a percent)			3.75%	3.75%
Mortality table			RP2014	RP2014
Cash Flows [Abstract]
Number of pension plans to which contributions were made | Plan			4	4	4
Total contributions to Xcel Energy's pension plans during the period			$ 162	$ 125	$ 90
Components of Net Periodic Benefit Cost (Credit) [Abstract]
Service cost			94	92	99
Interest cost			147	160	149
Expected return on plan assets			(209)	(210)	(214)
Amortization of prior service cost (credit)			(2)	(2)	(2)
Amortization of net loss			107	97	125
Settlement charge	[3]		81	0	0
Net periodic benefit cost			218	137	157
Costs not recognized due to regulation			(79)	(15)	(29)
Net benefit cost recognized for financial reporting			139	$ 122	$ 128
Settlement Charge Recognized in Operating and Maintenance Expenses			$ 8
Significant Assumptions Used to Measure Costs [Abstract]
Discount rate (as a percent)			4.13%	4.66%	4.11%
Expected average long-term increase in compensation level (as a percent)			3.75%	4.00%	3.75%
Expected average long-term rate of return on assets (as a percent)			6.87%	6.87%	7.09%
Expected average long-term rate of return on assets for next fiscal year (as a percent)			6.87%
Subsequent Event | Pension Plan [Member]
Cash Flows [Abstract]
Number of pension plans to which contributions were made | Plan		4
Total contributions to Xcel Energy's pension plans during the period		$ 150
[1]	2017 amount includes approximately $174 million of lump-sum benefit payments used in the determination of a settlement charge.
[2]	Amounts are recognized in noncurrent liabilities on Xcel Energy’s consolidated balance sheets.
[3]	A settlement charge is required when the amount of all lump-sum distributions during the year is greater than the sum of the service and interest cost components of the annual net periodic pension cost. In the fourth quarter of 2017 as a result of lump-sum distributions during the 2017 plan year, Xcel Energy recorded a total pension settlement charge of $81 million, the majority of which was not recognized due to the effects of regulation. A total of $8 million of that amount was recorded in O&M expenses in the fourth quarter of 2017.

Benefit Plans and Other Postr74

Benefit Plans and Other Postretirement Benefits, Defined Contribution Plans (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Defined Contribution Plans [Abstract]
Contributions to 401(k) and other defined contribution plans	$ 37	$ 36	$ 34

Benefit Plans and Other Postr75

Benefit Plans and Other Postretirement Benefits, Postretirement Health Care Benefits (Details) - Other Postretirement Benefits Plan [Member]	Dec. 31, 2017	Dec. 31, 2016
Postretirement Health Care Benefits [Abstract]
Target pension asset allocations (as a percent)	100.00%	100.00%
Domestic and international equity securities
Postretirement Health Care Benefits [Abstract]
Target pension asset allocations (as a percent)	24.00%	25.00%
Short-to-intermediate fixed income securities
Postretirement Health Care Benefits [Abstract]
Target pension asset allocations (as a percent)	60.00%	57.00%
Alternative investments
Postretirement Health Care Benefits [Abstract]
Target pension asset allocations (as a percent)	9.00%	13.00%
Cash
Postretirement Health Care Benefits [Abstract]
Target pension asset allocations (as a percent)	7.00%	5.00%

Benefit Plans and Other Postr76

Benefit Plans and Other Postretirement Benefits, Fair Value of Postretirement Benefit Plan Assets (Details) - Other Postretirement Benefits Plan [Member] - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	$ 461	$ 442	$ 448
Plan assets at net asset value	0	55
Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	212	173
Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	249	214
Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Cash equivalents
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	29	21
Plan assets at net asset value	0	0
Cash equivalents | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	29	21
Cash equivalents | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Cash equivalents | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Insurance contracts
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	50	47
Plan assets at net asset value	0	0
Insurance contracts | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Insurance contracts | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	50	47
Insurance contracts | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
U.S. equity funds
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	74	54
Plan assets at net asset value	0	0
U.S. equity funds | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	74	54
U.S. equity funds | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
U.S. equity funds | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
U.S fixed income funds
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	34	27
Plan assets at net asset value	0	0
U.S fixed income funds | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	34	27
U.S fixed income funds | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
U.S fixed income funds | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Emerging market debt funds
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	40	30
Plan assets at net asset value	0	0
Emerging market debt funds | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	40	30
Emerging market debt funds | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Emerging market debt funds | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Government securities
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	57	38
Plan assets at net asset value	0	0
Government securities | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Government securities | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	57	38
Government securities | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
U.S. corporate bonds
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	63	62
Plan assets at net asset value	0	0
U.S. corporate bonds | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
U.S. corporate bonds | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	63	62
U.S. corporate bonds | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Non U.S. corporate bonds
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	21	17
Plan assets at net asset value	0	0
Non U.S. corporate bonds | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Non U.S. corporate bonds | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	21	17
Non U.S. corporate bonds | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Asset-backed securities
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	23	19
Plan assets at net asset value	0	0
Asset-backed securities | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Asset-backed securities | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	23	19
Asset-backed securities | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Mortgage-backed securities
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	34	29
Plan assets at net asset value	0	0
Mortgage-backed securities | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Mortgage-backed securities | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	34	29
Mortgage-backed securities | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Non U.S. equities
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	35	41
Plan assets at net asset value	0	0
Non U.S. equities | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	35	41
Non U.S. equities | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Non U.S. equities | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Other
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	1	2
Plan assets at net asset value	0	0
Other | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Other | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	1	2
Other | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	$ 0	0
Other commingled funds
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		55
Plan assets at net asset value		55
Other commingled funds | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		0
Other commingled funds | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		0
Other commingled funds | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		$ 0

Benefit Plans and Other Postr77

Benefit Plans and Other Postretirement Benefits, Postretirement Benefit Plan Benefit Obligations, Cash Flows and Benefit Costs (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Funded Status of Plans at Dec. 31 [Abstract]
Noncurrent liabilities	$ (1,042)	$ (1,112)
Other Postretirement Benefits Plan [Member]
Change in Projected Benefit Obligation [Roll Forward]
Obligation at Jan. 1	603	584
Service cost	2	2	$ 2
Interest cost	24	26	25
Medicare subsidy reimbursements	1	2
Plan participants' contributions	8	7
Actuarial loss	33	33
Benefit payments	(50)	(51)
Obligation at Dec. 31	621	603	584
Change in Fair Value of Plan Assets [Roll Forward]
Fair value of plan assets at Jan. 1	442	448
Actual return (loss) on plan assets	41	20
Participant contributions	8	7
Employer contributions	20	18
Benefit payments	(50)	(51)
Fair value of plan assets at Dec. 31	461	442	448
Funded Status of Plans at Dec. 31 [Abstract]
Funded status	(160)	(161)
Current liabilities	(3)	(6)
Noncurrent liabilities	(157)	(155)
Net postretirement amounts recognized on consolidated balance sheets	(160)	(161)
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost [Abstract]
Net loss	147	136
Prior service (credit) cost	(44)	(54)
Total	103	82
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost Have Been Recorded as Follows Based Upon Expected Recovery in Rates [Abstract]
Noncurrent regulatory assets	107	91
Current regulatory liabilities	(1)	(1)
Noncurrent regulatory liabilities	(10)	(14)
Deferred income taxes	2	2
Net-of-tax accumulated other comprehensive income	5	4
Total	$ 103	$ 82
Significant Assumptions Used to Measure Benefit Obligations [Abstract]
Discount rate for year-end valuation (as a percent)	3.62%	4.13%
Mortality table	RP 2,014	RP 2,014
Defined Benefit Plan, Health Care Cost Trend Rate Assumed, Pre-65	7.00%	5.50%
Defined Benefit Plan, Health Care Cost Trend Rate Assumed, Post-65	5.50%	5.50%
Ultimate health care trend assumption rate (as a percent)	4.50%
Period until ultimate trend rate is reached (in years)	5 years
Effect of One-Percentage Point Change in Assumed Health Care Cost Trend Rate [Abstract]
One-percent increase in APBO	$ 60
One-percent decrease in APBO	(51)
One-percent increase in service and interest components	3
One-percent decrease in service and interest components	(2)
Cash Flows [Abstract]
Total contributions to Xcel Energy's postretirement health care plans during the year	20	$ 18	18
Expected contribution to postretirement health care plans during 2018	12
Components of Net Periodic Benefit Cost (Credit) [Abstract]
Service cost	2	2	2
Interest cost	24	26	25
Expected return on plan assets	(25)	(25)	(26)
Amortization of prior service cost (credit)	(11)	(11)	(11)
Amortization of net loss	7	4	6
Net periodic benefit cost	$ (3)	$ (4)	$ (4)
Significant Assumptions Used to Measure Costs [Abstract]
Discount rate (as a percent)	4.13%	4.65%	4.08%
Expected average long-term rate of return on assets (as a percent)	5.80%	5.80%	5.80%

Benefit Plans and Other Postr78

Benefit Plans and Other Postretirement Benefits, Projected Benefit Payments (Details) $ in Millions	Dec. 31, 2017USD ($)
Pension Plan [Member]
Defined Benefit Plan, Gross Projected Benefit Payments [Abstract]
2,018	$ 307
2,019	262
2,020	261
2,021	261
2,022	266
2023-2027	1,274
Other Postretirement Benefits Plan [Member]
Defined Benefit Plan, Gross Projected Benefit Payments [Abstract]
2,018	47
2,019	47
2,020	47
2,021	47
2,022	46
2023-2027	212
Expected Medicare Part D Subsidies [Abstract]
2,018	2
2,019	2
2,020	2
2,021	3
2,022	3
2023-2027	14
Defined Benefit Plan, Net Projected Benefit Payments [Abstract]
2,018	45
2,019	45
2,020	45
2,021	44
2,022	43
2023-2027	$ 198

Benefit Plans and Other Postr79

Benefit Plans and Other Postretirement Benefits, Multiemployer Plans (Details) - Multiemployer Pension Plans - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Multiemployer Plans [Abstract]
Multiemployer contributions	$ 12	$ 15	$ 18
NSP-Minnesota
Multiemployer Plans [Abstract]
Average number of NSP-Minnesota union employees covered by the multiemployer pension plan	576	700
Multiemployer contributions	$ 12	$ 14	17
NSP-Wisconsin
Multiemployer Plans [Abstract]
Multiemployer contributions	$ 0	$ 1	$ 1

Other Income, Net (Details)

Other Income, Net (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Other Income and Expenses [Abstract]
Interest income	$ 19	$ 8	$ 6
Other nonoperating income	7	3	4
Insurance policy expense	(3)	(3)	(4)
Other income, net	$ 23	$ 8	$ 6

Fair Value of Financial Asset81

Fair Value of Financial Assets and Liabilities Fair Value of Financial Assets and Liabilities (Details)	12 Months Ended
	Dec. 31, 2017
Minimum | Commingled and international equity funds
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share [Line Items]
Notice period for investment redemption	1 day
Minimum | Real estate funds
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share [Line Items]
Notice period for investment redemption	45 days
Maximum | Commingled and international equity funds
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share [Line Items]
Notice period for investment redemption	90 days
Maximum | Real estate funds
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share [Line Items]
Notice period for investment redemption	90 days

Fair Value of Financial Asset82

Fair Value of Financial Assets and Liabilities, Cost and Fair Value of Nuclear Decommissioning Fund (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2017		Dec. 31, 2016
Available-for-sale Securities [Abstract]
Available-for-sale Securities, Gross Unrealized Gain		$ 560		$ 379
Available-for-sale Securities, Gross Unrealized Loss		7		47
Decommissioning Fund Investments, Fair Value		2,143		1,900
Investments [Abstract]
Equity investments in unconsolidated subsidiaries		140		133
Miscellaneous investments		114		98
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash equivalents		29	[1]	20	[2]
Alternative Investment, Fair Value Disclosure		659	[1]	840	[2]
Available-for-sale Securities [Abstract]
Available-for-sale Securities	[2]			1,861
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Cash equivalents
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Alternative Investment, Fair Value Disclosure		0	[1]	0	[2]
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Non U.S. equities
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Alternative Investment, Fair Value Disclosure		90	[1]	112	[2]
Available-for-sale Securities [Abstract]
Available-for-sale Securities		307	[1]	245	[2]
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Emerging market debt funds
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Alternative Investment, Fair Value Disclosure		166	[1]	98	[2]
Available-for-sale Securities [Abstract]
Available-for-sale Securities		166	[1]	98	[2]
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Commodity funds
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Alternative Investment, Fair Value Disclosure	[2]			92
Available-for-sale Securities [Abstract]
Available-for-sale Securities	[2]			92
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Private equity investments
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Alternative Investment, Fair Value Disclosure		198	[1]	190	[2]
Available-for-sale Securities [Abstract]
Available-for-sale Securities		198	[1]	190	[2]
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Real estate
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Alternative Investment, Fair Value Disclosure		202	[1]	188	[2]
Available-for-sale Securities [Abstract]
Available-for-sale Securities		202	[1]	188	[2]
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Other commingled funds
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Alternative Investment, Fair Value Disclosure		3	[1]	160	[2]
Available-for-sale Securities [Abstract]
Available-for-sale Securities		9	[1]	160	[2]
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Government securities
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Alternative Investment, Fair Value Disclosure		0	[1]	0	[2]
Available-for-sale Securities [Abstract]
Available-for-sale Securities, Debt Securities		69	[1]	32	[2]
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | U.S. corporate bonds
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Alternative Investment, Fair Value Disclosure		0	[1]	0	[2]
Available-for-sale Securities [Abstract]
Available-for-sale Securities, Debt Securities		322	[1]	106	[2]
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Non U.S. corporate bonds
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Alternative Investment, Fair Value Disclosure		0	[1]	0	[2]
Available-for-sale Securities [Abstract]
Available-for-sale Securities, Debt Securities		50	[1]	21	[2]
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Municipal Bonds
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Alternative Investment, Fair Value Disclosure	[2]			0
Available-for-sale Securities [Abstract]
Available-for-sale Securities, Debt Securities	[2]			14
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Mortgage-backed securities
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Alternative Investment, Fair Value Disclosure	[2]			0
Available-for-sale Securities [Abstract]
Available-for-sale Securities, Debt Securities	[2]			3
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | U.S. equities
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Alternative Investment, Fair Value Disclosure		0	[1]	0	[2]
Available-for-sale Securities [Abstract]
Available-for-sale Securities, Equity Securities		557	[1]	474	[2]
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Non U.S. equities
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Alternative Investment, Fair Value Disclosure		0	[1]	0	[2]
Available-for-sale Securities [Abstract]
Available-for-sale Securities, Equity Securities		234	[1]	218	[2]
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash equivalents		29	[1]	20	[2]
Available-for-sale Securities [Abstract]
Available-for-sale Securities		1,043	[1]	845	[2]
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 1 | Non U.S. equities
Available-for-sale Securities [Abstract]
Available-for-sale Securities		217	[1]	133	[2]
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 1 | Emerging market debt funds
Available-for-sale Securities [Abstract]
Available-for-sale Securities		0	[1]	0	[2]
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 1 | Commodity funds
Available-for-sale Securities [Abstract]
Available-for-sale Securities	[2]			0
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 1 | Private equity investments
Available-for-sale Securities [Abstract]
Available-for-sale Securities		0	[1]	0	[2]
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 1 | Real estate
Available-for-sale Securities [Abstract]
Available-for-sale Securities		0	[1]	0	[2]
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 1 | Other commingled funds
Available-for-sale Securities [Abstract]
Available-for-sale Securities		6	[1]	0	[2]
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 1 | Government securities
Available-for-sale Securities [Abstract]
Available-for-sale Securities, Debt Securities		0	[1]	0	[2]
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 1 | U.S. corporate bonds
Available-for-sale Securities [Abstract]
Available-for-sale Securities, Debt Securities		0	[1]	0	[2]
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 1 | Non U.S. corporate bonds
Available-for-sale Securities [Abstract]
Available-for-sale Securities, Debt Securities		0	[1]	0	[2]
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 1 | Municipal Bonds
Available-for-sale Securities [Abstract]
Available-for-sale Securities, Debt Securities	[2]			0
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 1 | Mortgage-backed securities
Available-for-sale Securities [Abstract]
Available-for-sale Securities, Debt Securities	[2]			0
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 1 | U.S. equities
Available-for-sale Securities [Abstract]
Available-for-sale Securities, Equity Securities		557	[1]	474	[2]
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 1 | Non U.S. equities
Available-for-sale Securities [Abstract]
Available-for-sale Securities, Equity Securities		234	[1]	218	[2]
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash equivalents		0	[1]	0	[2]
Available-for-sale Securities [Abstract]
Available-for-sale Securities		441	[1]	176	[2]
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 2 | Non U.S. equities
Available-for-sale Securities [Abstract]
Available-for-sale Securities		0	[1]	0	[2]
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 2 | Emerging market debt funds
Available-for-sale Securities [Abstract]
Available-for-sale Securities		0	[1]	0	[2]
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 2 | Commodity funds
Available-for-sale Securities [Abstract]
Available-for-sale Securities	[2]			0
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 2 | Private equity investments
Available-for-sale Securities [Abstract]
Available-for-sale Securities		0	[1]	0	[2]
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 2 | Real estate
Available-for-sale Securities [Abstract]
Available-for-sale Securities		0	[1]	0	[2]
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 2 | Other commingled funds
Available-for-sale Securities [Abstract]
Available-for-sale Securities		0	[1]	0	[2]
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 2 | Government securities
Available-for-sale Securities [Abstract]
Available-for-sale Securities, Debt Securities		69	[1]	32	[2]
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 2 | U.S. corporate bonds
Available-for-sale Securities [Abstract]
Available-for-sale Securities, Debt Securities		322	[1]	106	[2]
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 2 | Non U.S. corporate bonds
Available-for-sale Securities [Abstract]
Available-for-sale Securities, Debt Securities		50	[1]	21	[2]
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 2 | Municipal Bonds
Available-for-sale Securities [Abstract]
Available-for-sale Securities, Debt Securities	[2]			14
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 2 | Mortgage-backed securities
Available-for-sale Securities [Abstract]
Available-for-sale Securities, Debt Securities	[2]			3
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 2 | U.S. equities
Available-for-sale Securities [Abstract]
Available-for-sale Securities, Equity Securities		0	[1]	0	[2]
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 2 | Non U.S. equities
Available-for-sale Securities [Abstract]
Available-for-sale Securities, Equity Securities		0	[1]	0	[2]
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash equivalents		0	[1]	0	[2]
Available-for-sale Securities [Abstract]
Available-for-sale Securities		0	[1]	0	[2]
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 3 | Non U.S. equities
Available-for-sale Securities [Abstract]
Available-for-sale Securities		0	[1]	0	[2]
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 3 | Emerging market debt funds
Available-for-sale Securities [Abstract]
Available-for-sale Securities		0	[1]	0	[2]
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 3 | Commodity funds
Available-for-sale Securities [Abstract]
Available-for-sale Securities	[2]			0
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 3 | Private equity investments
Available-for-sale Securities [Abstract]
Available-for-sale Securities		0	[1]	0	[2]
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 3 | Real estate
Available-for-sale Securities [Abstract]
Available-for-sale Securities		0	[1]	0	[2]
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 3 | Other commingled funds
Available-for-sale Securities [Abstract]
Available-for-sale Securities		0	[1]	0	[2]
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 3 | Government securities
Available-for-sale Securities [Abstract]
Available-for-sale Securities, Debt Securities		0	[1]	0	[2]
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 3 | U.S. corporate bonds
Available-for-sale Securities [Abstract]
Available-for-sale Securities, Debt Securities		0	[1]	0	[2]
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 3 | Non U.S. corporate bonds
Available-for-sale Securities [Abstract]
Available-for-sale Securities, Debt Securities		0	[1]	0	[2]
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 3 | Municipal Bonds
Available-for-sale Securities [Abstract]
Available-for-sale Securities, Debt Securities	[2]			0
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 3 | Mortgage-backed securities
Available-for-sale Securities [Abstract]
Available-for-sale Securities, Debt Securities	[2]			0
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 3 | U.S. equities
Available-for-sale Securities [Abstract]
Available-for-sale Securities, Equity Securities		0	[1]	0	[2]
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 3 | Non U.S. equities
Available-for-sale Securities [Abstract]
Available-for-sale Securities, Equity Securities		0	[1]	0	[2]
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Cost
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash equivalents		29	[1]	20	[2]
Available-for-sale Securities [Abstract]
Available-for-sale Securities		1,591	[1]	1,529	[2]
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Cost | Non U.S. equities
Available-for-sale Securities [Abstract]
Available-for-sale Securities		264	[1]	261	[2]
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Cost | Emerging market debt funds
Available-for-sale Securities [Abstract]
Available-for-sale Securities		156	[1]	93	[2]
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Cost | Commodity funds
Available-for-sale Securities [Abstract]
Available-for-sale Securities	[2]			106
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Cost | Private equity investments
Available-for-sale Securities [Abstract]
Available-for-sale Securities		141	[1]	132	[2]
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Cost | Real estate
Available-for-sale Securities [Abstract]
Available-for-sale Securities		131	[1]	129	[2]
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Cost | Other commingled funds
Available-for-sale Securities [Abstract]
Available-for-sale Securities		9	[1]	151	[2]
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Cost | Government securities
Available-for-sale Securities [Abstract]
Available-for-sale Securities, Debt Securities		68	[1]	33	[2]
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Cost | U.S. corporate bonds
Available-for-sale Securities [Abstract]
Available-for-sale Securities, Debt Securities		320	[1]	105	[2]
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Cost | Non U.S. corporate bonds
Available-for-sale Securities [Abstract]
Available-for-sale Securities, Debt Securities		50	[1]	22	[2]
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Cost | Municipal Bonds
Available-for-sale Securities [Abstract]
Available-for-sale Securities, Debt Securities	[2]			14
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Cost | Mortgage-backed securities
Available-for-sale Securities [Abstract]
Available-for-sale Securities, Debt Securities	[2]			3
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Cost | U.S. equities
Available-for-sale Securities [Abstract]
Available-for-sale Securities, Equity Securities		271	[1]	271	[2]
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Cost | Non U.S. equities
Available-for-sale Securities [Abstract]
Available-for-sale Securities, Equity Securities		$ 152	[1]	$ 189	[2]
[1]	Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $140 million of equity investments in unconsolidated subsidiaries and $114 million of rabbi trust assets and miscellaneous investments.
[2]	Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $133 million of equity investments in unconsolidated subsidiaries and $98 million of rabbi trust assets and miscellaneous investments.

Fair Value of Financial Asset83

Fair Value of Financial Assets and Liabilities Fair Value of Financial Assets and Liabilities, Cost and Fair Value of Rabbi Trusts (Details) - Fair Value Measured on a Recurring Basis - USD ($) $ in Millions		Dec. 31, 2017	Dec. 31, 2016
Cost
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Trading Securities	[1]	$ 59	$ 50
Cost | Rabbi Trust [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash and Cash Equivalents, Fair Value Disclosure	[1]	12	48
Cost | Mutual Funds [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Trading Securities	[1]	47	2
Fair Value
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Trading Securities	[1]	62	50
Fair Value | Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Trading Securities	[1]	62	50
Fair Value | Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Trading Securities	[1]	0	0
Fair Value | Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Trading Securities	[1]	0	0
Fair Value | Rabbi Trust [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash and Cash Equivalents, Fair Value Disclosure	[1]	12	48
Fair Value | Rabbi Trust [Member] | Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash and Cash Equivalents, Fair Value Disclosure	[1]	12	48
Fair Value | Rabbi Trust [Member] | Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash and Cash Equivalents, Fair Value Disclosure	[1]	0	0
Fair Value | Rabbi Trust [Member] | Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash and Cash Equivalents, Fair Value Disclosure	[1]	0	0
Fair Value | Mutual Funds [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Trading Securities	[1]	50	2
Fair Value | Mutual Funds [Member] | Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Trading Securities	[1]	50	2
Fair Value | Mutual Funds [Member] | Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Trading Securities	[1]	0	0
Fair Value | Mutual Funds [Member] | Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Trading Securities	[1]	$ 0	$ 0
[1]	Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet.

Fair Value of Financial Asset84

Fair Value of Financial Assets and Liabilities, Final Contractual Maturity Dates of Debt Securities in Nuclear Decommissioning Fund (Details) $ in Millions	Dec. 31, 2017USD ($)
Final Contractual Maturity [Abstract]
Due in 1 Year or Less	$ 5
Due in 1 to 5 Years	102
Due in 5 to 10 Years	205
Due after 10 Years	129
Total	441
Government securities
Final Contractual Maturity [Abstract]
Due in 1 Year or Less	0
Due in 1 to 5 Years	2
Due in 5 to 10 Years	0
Due after 10 Years	67
Total	69
U.S. corporate bonds
Final Contractual Maturity [Abstract]
Due in 1 Year or Less	5
Due in 1 to 5 Years	85
Due in 5 to 10 Years	174
Due after 10 Years	58
Total	322
Non U.S. corporate bonds
Final Contractual Maturity [Abstract]
Due in 1 Year or Less	0
Due in 1 to 5 Years	15
Due in 5 to 10 Years	31
Due after 10 Years	4
Total	$ 50

Fair Value of Financial Asset85

Fair Value of Financial Assets and Liabilities, Derivative Instruments (Details) MWh in Millions, MMBTU in Millions, $ in Millions		Dec. 31, 2017USD ($)MMBTUMWhCounterparty	Dec. 31, 2016MMBTUMWh
Credit Concentration Risk
Consideration of Credit Risk and Concentrations [Abstract]
Number of most significant counterparties for wholesale, trading and non-trading commodity activities with credit exposure		10
Credit Concentration Risk | Municipal or Cooperative Entities or Other Utilities [Member]
Consideration of Credit Risk and Concentrations [Abstract]
Number of most significant counterparties for wholesale, trading and non-trading commodity activities with credit exposure		8
Credit Concentration Risk | No Investment Grade Ratings from External Credit Rating Agencies [Member]
Consideration of Credit Risk and Concentrations [Abstract]
Number of most significant counterparties for wholesale, trading and non-trading commodity activities with credit exposure		5
Wholesale, trading and non-trading commodity credit exposure for the most significant counterparties | $		$ 30
Percentage of wholesale, trading and non-trading commodity credit exposure for the most significant counterparties (in hundredths)		19.00%
Credit Concentration Risk | External Credit Rating, Investment Grade [Member]
Consideration of Credit Risk and Concentrations [Abstract]
Number of most significant counterparties for wholesale, trading and non-trading commodity activities with credit exposure		4
Wholesale, trading and non-trading commodity credit exposure for the most significant counterparties | $		$ 45
Percentage of wholesale, trading and non-trading commodity credit exposure for the most significant counterparties (in hundredths)		29.00%
Credit Concentration Risk | External Credit Rating, Non Investment Grade [Member]
Consideration of Credit Risk and Concentrations [Abstract]
Number of most significant counterparties for wholesale, trading and non-trading commodity activities with credit exposure		1
Wholesale, trading and non-trading commodity credit exposure for the most significant counterparties | $		$ 7
Percentage of wholesale, trading and non-trading commodity credit exposure for the most significant counterparties (in hundredths)		5.00%
Interest Rate Swap
Interest Rate Derivatives [Abstract]
Amount of accumulated other comprehensive gains (losses) related to interest rate derivatives expected to be reclassified into earnings within the next twelve months | $		$ (3)
Electric Commodity (in megawatt hours)
Gross Notional Amounts of Commodity Forwards, Options and FTRs [Abstract]
Derivative, Nonmonetary Notional amount | MWh	[1],[2]	68	47
Natural Gas Commodity (in million British thermal units)
Gross Notional Amounts of Commodity Forwards, Options and FTRs [Abstract]
Derivative, Nonmonetary Notional amount | MMBTU	[1],[2]	37	122
[1]	Amounts are not reflective of net positions in the underlying commodities.
[2]	Notional amounts for options are included on a gross basis, but are weighted for the probability of exercise.

Fair Value of Financial Asset86

Fair Value of Financial Assets and Liabilities, Financial Impact of Qualifying Cash Flow Hedges (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Financial Impact of Qualifying Cash Flow Hedges on Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Accumulated other comprehensive loss related to cash flow hedges at Jan. 1	$ (51)	$ (55)	$ (58)
After-tax net realized losses on derivative transactions reclassified into earnings	3	4	3
Accumulated other comprehensive loss related to cash flow hedges at Dec. 31	$ (48)	$ (51)	$ (55)

Fair Value of Financial Asset87

Fair Value of Financial Assets and Liabilities, Impact of Derivative Activity (Details) - USD ($)		12 Months Ended
		Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Financial Impact of Qualifying Fair Value Hedges on Earnings [Abstract]
Derivative instruments designated as fair value hedges		$ 0	$ 0	$ 0
Recognized gains (losses) from fair value hedges or related hedged transactions		0	0	0
Designated as Hedging Instrument | Cash Flow Hedges
Impact of Derivative Activity on Accumulated Other Comprehensive Loss, Regulatory Assets and Liabilities, and Income [Abstract]
Pre-tax fair value gains (losses) recognized during the period in accumulated other comprehensive loss		0	0	0
Pre-tax fair value gains (losses) recognized during the period in regulatory (assets) and liabilities		0	0	0
Pre-tax (gains) losses reclassified into income during the period from accumulated other comprehensive loss		5,000,000	6,000,000	5,000,000
Pre-tax (gains) losses reclassified into income during the period from regulatory assets and (liabilities)		0	0	0
Pre-tax gains (losses) recognized during the period in income		0	0	0
Designated as Hedging Instrument | Cash Flow Hedges | Interest Rate
Impact of Derivative Activity on Accumulated Other Comprehensive Loss, Regulatory Assets and Liabilities, and Income [Abstract]
Pre-tax fair value gains (losses) recognized during the period in accumulated other comprehensive loss		0	0	0
Pre-tax fair value gains (losses) recognized during the period in regulatory (assets) and liabilities		0	0	0
Pre-tax (gains) losses reclassified into income during the period from accumulated other comprehensive loss	[1]	5,000,000	6,000,000	5,000,000
Pre-tax (gains) losses reclassified into income during the period from regulatory assets and (liabilities)		0	0	0
Pre-tax gains (losses) recognized during the period in income		0	0	0
Other Derivative Instruments
Impact of Derivative Activity on Accumulated Other Comprehensive Loss, Regulatory Assets and Liabilities, and Income [Abstract]
Pre-tax fair value gains (losses) recognized during the period in accumulated other comprehensive loss		0	0	0
Pre-tax fair value gains (losses) recognized during the period in regulatory (assets) and liabilities		(3,000,000)	18,000,000	(35,000,000)
Pre-tax (gains) losses reclassified into income during the period from accumulated other comprehensive loss		0	0	0
Pre-tax (gains) losses reclassified into income during the period from regulatory assets and (liabilities)		(12,000,000)	7,000,000	32,000,000
Pre-tax gains (losses) recognized during the period in income		4,000,000	(6,000,000)	(19,000,000)
Other Derivative Instruments | Commodity Trading
Impact of Derivative Activity on Accumulated Other Comprehensive Loss, Regulatory Assets and Liabilities, and Income [Abstract]
Pre-tax fair value gains (losses) recognized during the period in accumulated other comprehensive loss		0	0	0
Pre-tax fair value gains (losses) recognized during the period in regulatory (assets) and liabilities		0	0	0
Pre-tax (gains) losses reclassified into income during the period from accumulated other comprehensive loss		0	0	0
Pre-tax (gains) losses reclassified into income during the period from regulatory assets and (liabilities)		0	0	0
Pre-tax gains (losses) recognized during the period in income	[2]	10,000,000	2,000,000	(7,000,000)
Other Derivative Instruments | Electric Commodity
Impact of Derivative Activity on Accumulated Other Comprehensive Loss, Regulatory Assets and Liabilities, and Income [Abstract]
Pre-tax fair value gains (losses) recognized during the period in accumulated other comprehensive loss		0	0	0
Pre-tax fair value gains (losses) recognized during the period in regulatory (assets) and liabilities		10,000,000	17,000,000	(19,000,000)
Pre-tax (gains) losses reclassified into income during the period from accumulated other comprehensive loss		0	0	0
Pre-tax (gains) losses reclassified into income during the period from regulatory assets and (liabilities)	[3]	(15,000,000)	(8,000,000)	16,000,000
Pre-tax gains (losses) recognized during the period in income		0	0	0
Other Derivative Instruments | Natural Gas Commodity
Impact of Derivative Activity on Accumulated Other Comprehensive Loss, Regulatory Assets and Liabilities, and Income [Abstract]
Pre-tax fair value gains (losses) recognized during the period in accumulated other comprehensive loss		0	0	0
Pre-tax fair value gains (losses) recognized during the period in regulatory (assets) and liabilities		(13,000,000)	1,000,000	(16,000,000)
Pre-tax (gains) losses reclassified into income during the period from accumulated other comprehensive loss		0	0	0
Pre-tax (gains) losses reclassified into income during the period from regulatory assets and (liabilities)	[4]	3,000,000	15,000,000	16,000,000
Pre-tax gains (losses) recognized during the period in income	[4]	$ (6,000,000)	$ (8,000,000)	(12,000,000)
Other Derivative Instruments | Natural Gas Commodity for Electric Generation
Impact of Derivative Activity on Accumulated Other Comprehensive Loss, Regulatory Assets and Liabilities, and Income [Abstract]
Pre-tax fair value gains (losses) recognized during the period in regulatory (assets) and liabilities				$ (1,000,000)
[1]	Amounts are recorded to interest charges.
[2]	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.
[3]	Amounts are recorded to electric fuel and purchased power. These derivative settlement gains and losses are shared with electric customers through fuel and purchased energy cost-recovery mechanisms, and reclassified out of income as regulatory assets or liabilities, as appropriate.
[4]	Certain derivatives are utilized to mitigate natural gas price risk for electric generation and are recorded to electric fuel and purchased power, subject to cost-recovery mechanisms and reclassified to a regulatory asset, as appropriate. Amounts for the years ended Dec. 31, 2017 and Dec. 31, 2016 included immaterial settlement gains and losses. Amounts for the year ended Dec. 31, 2015 included $1 million of settlement losses. The remaining settlement losses for the years ended Dec. 31, 2017, 2016 and 2015 relate to natural gas operations and are recorded to cost of natural gas sold and transported. These losses are subject to cost-recovery mechanisms and reclassified out of income to a regulatory asset, as appropriate.

Fair Value of Financial Asset88

Fair Value of Financial Assets and Liabilities, Credit Related Contingent Features (Details) - USD ($)	Dec. 31, 2017	Dec. 31, 2016
Fair Value Disclosures [Abstract]
Derivative instruments in a gross liability position	$ 0	$ 0
Collateral posted on derivative instruments	0	0
Collateral posted related to adequate assurance clauses in derivative contracts	$ 0	$ 0

Fair Value of Financial Asset89

Fair Value of Financial Assets and Liabilities, Derivative Assets and Liabilities at Fair Value (Details) - USD ($)		Dec. 31, 2017		Dec. 31, 2016
Derivatives, Fair Value [Line Items]
Derivative Asset, Collateral, Obligation to Return Cash, Offset		$ 0		$ 0
Derivative Liability, Collateral, Right to Reclaim Cash, Offset		3,000,000		4,000,000
Other Current Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		44,000,000		38,000,000
Other Current Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		29,000,000		27,000,000
Other Noncurrent Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		48,000,000		50,000,000
Other Noncurrent Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		126,000,000		148,000,000
Fair Value Measured on a Recurring Basis | Other Current Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		39,000,000		33,000,000
Derivative Asset, Fair Value, Gross Liability and Obligation to Return Cash, Offset		(17,000,000)	[1]	(22,000,000)	[2]
Fair Value Measured on a Recurring Basis | Other Current Assets | Other Derivative Instruments | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		9,000,000		7,000,000
Derivative Asset, Fair Value, Gross Liability and Obligation to Return Cash, Offset		(15,000,000)	[1]	(20,000,000)	[2]
Fair Value Measured on a Recurring Basis | Other Current Assets | Other Derivative Instruments | Electric Commodity
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		30,000,000		17,000,000
Derivative Asset, Fair Value, Gross Liability and Obligation to Return Cash, Offset		(2,000,000)	[1]	(2,000,000)	[2]
Fair Value Measured on a Recurring Basis | Other Current Assets | Other Derivative Instruments | Natural Gas Commodity
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset				9,000,000
Derivative Asset, Fair Value, Gross Liability and Obligation to Return Cash, Offset	[2]			0
Fair Value Measured on a Recurring Basis | Other Current Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		6,000,000		4,000,000
Derivative Liability, Fair Value, Gross Asset and Right to Reclaim Cash, Offset		(17,000,000)	[1]	(23,000,000)	[2]
Fair Value Measured on a Recurring Basis | Other Current Liabilities | Other Derivative Instruments | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		5,000,000		4,000,000
Derivative Liability, Fair Value, Gross Asset and Right to Reclaim Cash, Offset		(15,000,000)	[1]	(21,000,000)	[2]
Fair Value Measured on a Recurring Basis | Other Current Liabilities | Other Derivative Instruments | Electric Commodity
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		0		0
Derivative Liability, Fair Value, Gross Asset and Right to Reclaim Cash, Offset		(2,000,000)	[1]	(2,000,000)	[2]
Fair Value Measured on a Recurring Basis | Other Current Liabilities | Other Derivative Instruments | Natural Gas Commodity
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		1,000,000
Derivative Liability, Fair Value, Gross Asset and Right to Reclaim Cash, Offset	[1]	0
Fair Value Measured on a Recurring Basis | Other Noncurrent Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		29,000,000		26,000,000
Derivative Asset, Fair Value, Gross Liability and Obligation to Return Cash, Offset		(7,000,000)	[1]	(7,000,000)	[2]
Fair Value Measured on a Recurring Basis | Other Noncurrent Assets | Other Derivative Instruments | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		29,000,000		24,000,000
Derivative Asset, Fair Value, Gross Liability and Obligation to Return Cash, Offset		(7,000,000)	[1]	(7,000,000)	[2]
Fair Value Measured on a Recurring Basis | Other Noncurrent Assets | Other Derivative Instruments | Natural Gas Commodity
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset				2,000,000
Derivative Asset, Fair Value, Gross Liability and Obligation to Return Cash, Offset	[2]			0
Fair Value Measured on a Recurring Basis | Other Noncurrent Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		14,000,000		13,000,000
Derivative Liability, Fair Value, Gross Asset and Right to Reclaim Cash, Offset		(10,000,000)	[1]	(11,000,000)	[2]
Fair Value Measured on a Recurring Basis | Other Noncurrent Liabilities | Other Derivative Instruments | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		14,000,000		13,000,000
Derivative Liability, Fair Value, Gross Asset and Right to Reclaim Cash, Offset		(10,000,000)	[1]	(11,000,000)	[2]
Fair Value Measured on a Recurring Basis | Level 1 | Other Current Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		2,000,000		13,000,000
Fair Value Measured on a Recurring Basis | Level 1 | Other Current Assets | Other Derivative Instruments | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		2,000,000		13,000,000
Fair Value Measured on a Recurring Basis | Level 1 | Other Current Assets | Other Derivative Instruments | Electric Commodity
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		0		0
Fair Value Measured on a Recurring Basis | Level 1 | Other Current Assets | Other Derivative Instruments | Natural Gas Commodity
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset				0
Fair Value Measured on a Recurring Basis | Level 1 | Other Current Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		2,000,000		14,000,000
Fair Value Measured on a Recurring Basis | Level 1 | Other Current Liabilities | Other Derivative Instruments | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		2,000,000		14,000,000
Fair Value Measured on a Recurring Basis | Level 1 | Other Current Liabilities | Other Derivative Instruments | Electric Commodity
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		0		0
Fair Value Measured on a Recurring Basis | Level 1 | Other Current Liabilities | Other Derivative Instruments | Natural Gas Commodity
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		0
Fair Value Measured on a Recurring Basis | Level 1 | Other Noncurrent Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		0		0
Fair Value Measured on a Recurring Basis | Level 1 | Other Noncurrent Assets | Other Derivative Instruments | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		0		0
Fair Value Measured on a Recurring Basis | Level 1 | Other Noncurrent Assets | Other Derivative Instruments | Natural Gas Commodity
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset				0
Fair Value Measured on a Recurring Basis | Level 1 | Other Noncurrent Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		0		0
Fair Value Measured on a Recurring Basis | Level 1 | Other Noncurrent Liabilities | Other Derivative Instruments | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		0		0
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		22,000,000		23,000,000
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Assets | Other Derivative Instruments | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		22,000,000		14,000,000
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Assets | Other Derivative Instruments | Electric Commodity
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		0		0
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Assets | Other Derivative Instruments | Natural Gas Commodity
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset				9,000,000
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		19,000,000		11,000,000
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Liabilities | Other Derivative Instruments | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		18,000,000		11,000,000
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Liabilities | Other Derivative Instruments | Electric Commodity
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		0		0
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Liabilities | Other Derivative Instruments | Natural Gas Commodity
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		1,000,000
Fair Value Measured on a Recurring Basis | Level 2 | Other Noncurrent Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		31,000,000		33,000,000
Fair Value Measured on a Recurring Basis | Level 2 | Other Noncurrent Assets | Other Derivative Instruments | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		31,000,000		31,000,000
Fair Value Measured on a Recurring Basis | Level 2 | Other Noncurrent Assets | Other Derivative Instruments | Natural Gas Commodity
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset				2,000,000
Fair Value Measured on a Recurring Basis | Level 2 | Other Noncurrent Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		24,000,000		24,000,000
Fair Value Measured on a Recurring Basis | Level 2 | Other Noncurrent Liabilities | Other Derivative Instruments | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		24,000,000		24,000,000
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		32,000,000		19,000,000
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Assets | Other Derivative Instruments | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		0		0
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Assets | Other Derivative Instruments | Electric Commodity
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		32,000,000		19,000,000
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Assets | Other Derivative Instruments | Natural Gas Commodity
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset				0
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		2,000,000		2,000,000
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Liabilities | Other Derivative Instruments | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		0		0
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Liabilities | Other Derivative Instruments | Electric Commodity
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		2,000,000		2,000,000
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Liabilities | Other Derivative Instruments | Natural Gas Commodity
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		0
Fair Value Measured on a Recurring Basis | Level 3 | Other Noncurrent Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		5,000,000		0
Fair Value Measured on a Recurring Basis | Level 3 | Other Noncurrent Assets | Other Derivative Instruments | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		5,000,000		0
Fair Value Measured on a Recurring Basis | Level 3 | Other Noncurrent Assets | Other Derivative Instruments | Natural Gas Commodity
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset				0
Fair Value Measured on a Recurring Basis | Level 3 | Other Noncurrent Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		0		0
Fair Value Measured on a Recurring Basis | Level 3 | Other Noncurrent Liabilities | Other Derivative Instruments | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		0		0
Fair Value, Measurements, Nonrecurring | Other Current Assets | Purchased Power Agreements
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		5,000,000	[3]	5,000,000	[4]
Fair Value, Measurements, Nonrecurring | Other Current Liabilities | Purchased Power Agreements
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		23,000,000	[3]	23,000,000	[4]
Fair Value, Measurements, Nonrecurring | Other Noncurrent Assets | Purchased Power Agreements
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		19,000,000	[3]	24,000,000	[4]
Fair Value, Measurements, Nonrecurring | Other Noncurrent Liabilities | Purchased Power Agreements
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		112,000,000	[3]	135,000,000	[4]
Estimate of Fair Value Measurement [Member] | Fair Value Measured on a Recurring Basis | Other Current Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		56,000,000		55,000,000
Estimate of Fair Value Measurement [Member] | Fair Value Measured on a Recurring Basis | Other Current Assets | Other Derivative Instruments | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		24,000,000		27,000,000
Estimate of Fair Value Measurement [Member] | Fair Value Measured on a Recurring Basis | Other Current Assets | Other Derivative Instruments | Electric Commodity
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		32,000,000		19,000,000
Estimate of Fair Value Measurement [Member] | Fair Value Measured on a Recurring Basis | Other Current Assets | Other Derivative Instruments | Natural Gas Commodity
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset				9,000,000
Estimate of Fair Value Measurement [Member] | Fair Value Measured on a Recurring Basis | Other Current Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		23,000,000		27,000,000
Estimate of Fair Value Measurement [Member] | Fair Value Measured on a Recurring Basis | Other Current Liabilities | Other Derivative Instruments | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		20,000,000		25,000,000
Estimate of Fair Value Measurement [Member] | Fair Value Measured on a Recurring Basis | Other Current Liabilities | Other Derivative Instruments | Electric Commodity
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		2,000,000		2,000,000
Estimate of Fair Value Measurement [Member] | Fair Value Measured on a Recurring Basis | Other Current Liabilities | Other Derivative Instruments | Natural Gas Commodity
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		1,000,000
Estimate of Fair Value Measurement [Member] | Fair Value Measured on a Recurring Basis | Other Noncurrent Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		36,000,000		33,000,000
Estimate of Fair Value Measurement [Member] | Fair Value Measured on a Recurring Basis | Other Noncurrent Assets | Other Derivative Instruments | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		36,000,000		31,000,000
Estimate of Fair Value Measurement [Member] | Fair Value Measured on a Recurring Basis | Other Noncurrent Assets | Other Derivative Instruments | Natural Gas Commodity
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset				2,000,000
Estimate of Fair Value Measurement [Member] | Fair Value Measured on a Recurring Basis | Other Noncurrent Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		24,000,000		24,000,000
Estimate of Fair Value Measurement [Member] | Fair Value Measured on a Recurring Basis | Other Noncurrent Liabilities | Other Derivative Instruments | Commodity Trading
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		$ 24,000,000		$ 24,000,000
[1]	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 as of Dec. 31, 2017. At Dec. 31, 2017, derivative assets and liabilities include no obligations to return cash collateral and rights to reclaim cash collateral of $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.
[2]	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 as of Dec. 31, 2016. At Dec. 31, 2016, derivative assets and liabilities include no obligations to return cash collateral and rights to reclaim cash collateral of $4 million. The counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements.
[3]	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.
[4]	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.

Fair Value of Financial Asset90

Fair Value of Financial Assets and Liabilities, Changes in Level 3 Commodity Derivatives (Details) - Commodity Contract - USD ($)		12 Months Ended
		Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]
Balance at beginning of period		$ 17,000,000	$ 18,000,000	$ 56,000,000
Purchases		82,000,000	35,000,000	64,000,000
Settlements		(97,000,000)	(89,000,000)	(70,000,000)
(Losses) gains recognized in earnings	[1]	5,000,000	0	2,000,000
Gains (losses) recognized as regulatory assets and liabilities		28,000,000	53,000,000	(34,000,000)
Balance at end of period		35,000,000	17,000,000	18,000,000
Transfers into Level 3		0	0	0
Transfers out of Level 3		$ 0	$ 0	$ 0
[1]	These amounts relate to commodity derivatives held at the end of the period.

Fair Value of Financial Asset91

Fair Value of Financial Assets and Liabilities, Fair Value of Long-Term Debt (Details) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Carrying Amount
Financial Liabilities, Balance Sheet Groupings [Abstract]
Long-term debt, including current portion	$ 14,976	$ 14,450
Fair Value
Financial Liabilities, Balance Sheet Groupings [Abstract]
Long-term debt, including current portion	$ 16,531	$ 15,513

Rate Matters, NSP-Minnesota (De

Rate Matters, NSP-Minnesota (Details) $ in Thousands

1 Months Ended

3 Months Ended

12 Months Ended

Feb. 28, 2018USD ($)

Dec. 31, 2017

Nov. 30, 2017USD ($)project

Jun. 30, 2017USD ($)

May 31, 2017USD ($)

Sep. 30, 2016

Jun. 30, 2016

Dec. 31, 2015

Feb. 28, 2015

Nov. 30, 2013

Mar. 31, 2015USD ($)

Dec. 31, 2017USD ($)

Dec. 31, 2016USD ($)

Dec. 31, 2015USD ($)MW

Dec. 31, 2013USD ($)

Dec. 31, 2008USD ($)

Rate Matters [Abstract]

Loss on Monticello life cycle management/extended power uprate project

$ 0

$ 0

$ 129,000

Minnesota Public Utilities Commission | Annual Automatic Adjustment of Charges [Member]

Rate Matters [Abstract]

Public Utilities; Approved Decrease Related To Disallowance Of Replacement Energy Costs

$ 4,000

NSP-Minnesota | MPUC Proceeding - Monticello Project Prudency Investigation

Rate Matters [Abstract]

Nuclear Project Expenditures, Amount

$ 665,000

Total Capitalized Nuclear Project Costs

$ 748,000

Initial Estimated Nuclear Project Expenditures

$ 320,000

Loss on Monticello life cycle management/extended power uprate project

$ 129,000

NSP-Minnesota | MPUC Proceeding - Transmission Cost Recovery Rider Filing 2017 and 2018

Rate Matters [Abstract]

Public Utilities, Additional Transmission Investment, Number Of Projects | project

3

Public Utilities, Additional Transmission Investment, Number Of Additional Projects | project

1

NSP-Minnesota | FERC Proceeding, MISO ROE Complaint

Rate Matters [Abstract]

Public Utilities, Base Return On Equity Charged To Customers Through Transmission Formula Rates

12.38%

12.38%

Public Utilities, ROE Applicable To Transmission Formula Rates In The MISO Region, Recommended By Third Parties

8.67%

9.15%

NSP-Minnesota | Minnesota Public Utilities Commission | MPUC Proceeding - Minnesota 2016 Multi-Year Electric Rate Case

Rate Matters [Abstract]

Public Utilities, Earnings Impact

$ 240,000

Public Utilities, Number Of Years Rate Case Is Applicable For

4 years

Public Utilities, Cap on Annual True-Up for Decoupled Classes, Percentage

3.00%

Public Utilities, Approved Return on Equity, Percentage

9.20%

Public Utilities, Approved Equity Capital Structure, Percentage

52.50%

Public Utilities, Length of Stay-out Provision, In Years

4 years

Public Utilities, Approved Incremental Revenue Increase (Decrease)

$ 180,000

Public Utilities, Increase (Decrease) Related to Sales True-up

60,000

Public Utilities, Approved Rate Increase (Decrease), Amount

240,000

NSP-Minnesota | Minnesota Public Utilities Commission | MPUC Proceeding - Minnesota 2016 Multi-Year Electric Rate Case, Rates 2016

Rate Matters [Abstract]

Public Utilities, Approved Incremental Revenue Increase (Decrease)

75,000

Public Utilities, Increase (Decrease) Related to Sales True-up

60,000

Public Utilities, Approved Rate Increase (Decrease), Amount

135,000

NSP-Minnesota | Minnesota Public Utilities Commission | MPUC Proceeding - Minnesota 2016 Multi-Year Electric Rate Case, Rates 2017

Rate Matters [Abstract]

Public Utilities, Approved Incremental Revenue Increase (Decrease)

55,000

Public Utilities, Increase (Decrease) Related to Sales True-up

0

Public Utilities, Approved Rate Increase (Decrease), Amount

55,000

NSP-Minnesota | Minnesota Public Utilities Commission | MPUC Proceeding - Minnesota 2016 Multi-Year Electric Rate Case, Rates 2018

Rate Matters [Abstract]

Public Utilities, Approved Incremental Revenue Increase (Decrease)

0

Public Utilities, Increase (Decrease) Related to Sales True-up

0

Public Utilities, Approved Rate Increase (Decrease), Amount

0

NSP-Minnesota | Minnesota Public Utilities Commission | MPUC Proceeding - Minnesota 2016 Multi-Year Electric Rate Case, Rates 2019

Rate Matters [Abstract]

Public Utilities, Approved Incremental Revenue Increase (Decrease)

50,000

Public Utilities, Increase (Decrease) Related to Sales True-up

0

Public Utilities, Approved Rate Increase (Decrease), Amount

$ 50,000

NSP-Minnesota | Minnesota Public Utilities Commission | MPUC Proceeding - Monticello Project Prudency Investigation

Rate Matters [Abstract]

Public Utilities, Amount Of Recoverable Investment, With Return

415,000

Public Utilities, Amount Of Recoverable Investment, Without A Return

$ 333,000

NSP-Minnesota | Minnesota Public Utilities Commission | MPUC Proceeding - Transmission Cost Recovery Rider Filing 2017 and 2018

Rate Matters [Abstract]

Public Utilities, Requested Rider Revenue, Amount

$ 110,000

NSP-Minnesota | Minnesota Public Utilities Commission | Electric Conservation Improvement Program (CIP) Rider 2017 [Member]

Rate Matters [Abstract]

Public Utilities, Estimated average annual incentives

$ 32,000

Public Utilities, Annual Electric Savings Goal, Percent of Volume of Electric Energy Sales

1.50%

Public Utilities, CIP expenses recovered through rate rider

$ 59,000

Public Utilities, CIP expenses recovered through base rates

89,000

NSP-Minnesota | Minnesota Public Utilities Commission | Natural Gas Conservation Improvement Program (CIP) Rider 2017 [Member]

Rate Matters [Abstract]

Public Utilities, Estimated average annual incentives

$ 3,000

Public Utilities, Annual Natural Gas Savings Goal, Percent of Volume of Natural Gas Sales

1.00%

Public Utilities, CIP expenses recovered through rate rider

$ 18,000

Public Utilities, CIP expenses recovered through base rates

4,000

NSP-Minnesota | Minnesota Public Utilities Commission | Electric Conservation Improvement Program (CIP) Rider 2016

Rate Matters [Abstract]

Public Utilities, CIP expenses recovered through rate rider

48,000

NSP-Minnesota | Minnesota Public Utilities Commission | Natural Gas Conservation Improvement Program (CIP) Rider 2016

Rate Matters [Abstract]

Public Utilities, CIP expenses recovered through rate rider

$ 6,000

NSP-Minnesota | Minnesota Public Utilities Commission | Gas Utility Infrastructure Cost Rider 2018 [Member]

Rate Matters [Abstract]

Public Utilities, Requested Rider Revenue, Amount

$ 28,000

NSP-Minnesota | Federal Energy Regulatory Commission (FERC) | FERC Proceeding, MISO ROE Complaint

Rate Matters [Abstract]

Public Utilities, ROE Applicable To Transmission Formula Rates In The MISO Region, Approved

10.32%

10.32%

10.32%

Public Utilities, ROE Applicable To Transmission Formula Rates In The MISO Region, with RTO Adder, Approved

10.82%

Public Utilities, ROE Basis Point Adder, Approved

50

NSP-Minnesota | Administrative Law Judge [Member] | FERC Proceeding, MISO ROE Complaint

Rate Matters [Abstract]

Public Utilities, ROE Applicable To Transmission Formula Rates In The MISO Region, Recommended By Third Parties

9.70%

Minimum | NSP-Minnesota | MPUC Proceeding - Monticello Project Prudency Investigation

Rate Matters [Abstract]

Public Utilities, Facility Generating Capacity | MW

600

Maximum | NSP-Minnesota | MPUC Proceeding - Monticello Project Prudency Investigation

Rate Matters [Abstract]

Public Utilities, Facility Generating Capacity | MW

671

Subsequent Event | NSP-Minnesota | Minnesota Public Utilities Commission | MPUC Proceeding - Minnesota 2016 Multi-Year Electric Rate Case

Rate Matters [Abstract]

Public Utilities, Surcharge Related to Annual Sales True-up Mechanism

$ 22,000

Public Utilities, Surcharge Related Related to Annual Revenue Decoupling Mechanism

27,000

Subsequent Event | NSP-Minnesota | Minnesota Public Utilities Commission | Gas Utility Infrastructure Cost Rider 2017

Rate Matters [Abstract]

Public Utilities, Approved Rider Revenue, Amount

$ 20,000

Rate Matters, NSP-Wisconsin (De

Rate Matters, NSP-Wisconsin (Details) - NSP-Wisconsin - Public Service Commission of Wisconsin (PSCW) - USD ($) $ in Millions	1 Months Ended
	Dec. 31, 2017	May 31, 2017
PSCW Proceeding - Wisconsin 2018 Electric and Natural Gas Rate Case - Electric Rates 2018 [Member]
Rate Matters [Abstract]
Public Utilities, Requested Rate Increase (Decrease), Amount		$ 25
Public Utilities, Requested Rate Increase (Decrease), Percentage		3.60%
Public Utilities, Requested Rate Base, Amount		$ 1,200
Public Utilities, Approved Rate Increase (Decrease), Amount	$ 9
Public Utilities, Approved Rate Increase (Decrease), Percentage	1.40%
PSCW Proceeding - Wisconsin 2018 Electric and Natural Gas Rate Case - Gas Rates 2018 [Member]
Rate Matters [Abstract]
Public Utilities, Requested Rate Increase (Decrease), Amount		$ 12
Public Utilities, Requested Rate Increase (Decrease), Percentage		10.10%
Public Utilities, Requested Rate Base, Amount		$ 138
Public Utilities, Approved Rate Increase (Decrease), Amount	$ 10
Public Utilities, Approved Rate Increase (Decrease), Percentage	8.30%
PSCW Proceeding - Wisconsin 2018 Electric and Natural Gas Rate Case [Member]
Rate Matters [Abstract]
Public Utilities, Requested Return on Equity, Percentage		10.00%
Public Utilities, Requested Equity Capital Structure, Percentage		52.53%
Public Utilities, Approved Return on Equity, Percentage	9.80%
Public Utilities, Approved Equity Capital Structure, Percentage	51.45%

Rate Matters, PSCo (Details)

Rate Matters, PSCo (Details) - PSCo $ in Millions		Feb. 16, 2018	Feb. 14, 2018USD ($)	Oct. 31, 2017USD ($)	Jun. 30, 2017USD ($)	Dec. 31, 2017USD ($)GWh
Colorado 2017 Multi-Year Electric Rate Case [Member]
Rate Matters [Abstract]
Public Utilities, Number of Years Which Rates are Requested to Increase				4 years
Public Utilities, Requested Return on Equity, Percentage				10.00%
Public Utilities, Requested Equity Capital Structure, Percentage				55.25%
Public Utilities, Requested Rate Increase (Decrease), Amount				$ 245
Public Utilities, Impact to Base Rates				378
CPUC Proceeding - 2017 Multi-Year Electric Rate Case, Electric Rates 2018 [Member]
Rate Matters [Abstract]
Public Utilities, Requested Rate Increase (Decrease), Amount				74
Public Utilities, Impact to Base Rates				207
Public Utilities, Expected Year-End Rate Base	[1]			6,800
CPUC Proceeding - 2017 Multi-Year Electric Rate Case, Electric Rates 2019 [Member]
Rate Matters [Abstract]
Public Utilities, Requested Rate Increase (Decrease), Amount				75
Public Utilities, Impact to Base Rates				75
Public Utilities, Expected Year-End Rate Base	[1]			7,100
CPUC Proceeding - 2017 Multi-Year Electric Rate Case, Electric Rates 2020 [Member]
Rate Matters [Abstract]
Public Utilities, Requested Rate Increase (Decrease), Amount				60
Public Utilities, Impact to Base Rates				60
Public Utilities, Expected Year-End Rate Base	[1]			7,300
CPUC Proceeding - 2017 Multi-Year Electric Rate Case, Electric Rates 2021 [Member]
Rate Matters [Abstract]
Public Utilities, Requested Rate Increase (Decrease), Amount				36
Public Utilities, Impact to Base Rates				36
Public Utilities, Expected Year-End Rate Base	[1]			$ 7,400
CPUC Proceeding - 2017 Multi-Year Gas Rate Case [Member]
Rate Matters [Abstract]
Public Utilities, Number of Years Which Rates are Requested to Increase					3 years
Public Utilities, Requested Return on Equity, Percentage					10.00%
Public Utilities, Requested Equity Capital Structure, Percentage					55.25%
Public Utilities, Requested Rate Increase (Decrease), Amount					$ 139
Public Utilities, Impact to Base Rates					233
CPUC Proceeding - 2017 Multi-Year Gas Rate Case, Gas Rates 2018 [Member]
Rate Matters [Abstract]
Public Utilities, Requested Rate Increase (Decrease), Amount					63
Public Utilities, Impact to Base Rates					63
Public Utilities, Expected Year-End Rate Base	[2]				1,500
CPUC Proceeding - 2017 Multi-Year Gas Rate Case, Gas Rates 2019 [Member]
Rate Matters [Abstract]
Public Utilities, Requested Rate Increase (Decrease), Amount					33
Public Utilities, Impact to Base Rates					127
Public Utilities, Expected Year-End Rate Base	[2]				2,300
CPUC Proceeding - 2017 Multi-Year Gas Rate Case, Gas Rates 2020 [Member]
Rate Matters [Abstract]
Public Utilities, Requested Rate Increase (Decrease), Amount					43
Public Utilities, Impact to Base Rates					43
Public Utilities, Expected Year-End Rate Base	[2]				2,400
CPUC Proceeding - Annual Electric Earnings Test 2015 through 2017
Rate Matters [Abstract]
Public Utilities, Return on Equity Threshold for Earnings Sharing						9.83%
CPUC Proceeding - Demand Side Management Cost Adjustment
Rate Matters [Abstract]
Public Utilities, Incentive Award Upon Achieving Savings Goal						$ 5
Public Utilities, Percentage of Net Economic Benefits on Which Incentive is Earned						5.00%
Public Utilities, Maximum Annual Incentive						$ 30
Public Utilities, Electric Incentive Award Earned for Achieving 2016 Savings Goal						11
Public Utilities, Gas Incentive Award Earned for Achieving 2016 Savings Goal						$ 3
CPUC Proceeding - Demand Side Cost Adjustment, 2018
Rate Matters [Abstract]
Public Utilities, Maximum Savings Goal (in GWh) | GWh						400
Public Utilities, Annual Spending Limit						$ 84
CPUC Staff [Member] | CPUC Proceeding - 2017 Multi-Year Gas Rate Case [Member]
Rate Matters [Abstract]
Public Utilities, Recommended Length of Average Rate Base				13 months
Public Utilities, Recommended Equity Capital Structure, Percentage				48.73%
Public Utilities, Total Recommended Rate Increase (Decrease)						30
Office of Consumer Council (OCC) [Member] | CPUC Proceeding - 2017 Multi-Year Gas Rate Case [Member]
Rate Matters [Abstract]
Public Utilities, Recommended Length of Average Rate Base				13 months
Public Utilities, Recommended Equity Capital Structure, Percentage				51.20%
Public Utilities, Total Recommended Rate Increase (Decrease)						$ 39
Subsequent Event | Colorado 2017 Multi-Year Electric Rate Case [Member]
Rate Matters [Abstract]
Public Utilities, Length of TCJA Net Benefits Deferral		5 months
Subsequent Event | CPUC Proceeding - 2017 Multi-Year Gas Rate Case [Member]
Rate Matters [Abstract]
Public Utilities, Reduction of Provisional Rates			$ 20
CACJA Recovery Rider | Colorado 2017 Multi-Year Electric Rate Case [Member]
Rate Matters [Abstract]
Public Utilities, Rider Conversion to Base Rates	[3]			$ 90
CACJA Recovery Rider | CPUC Proceeding - 2017 Multi-Year Electric Rate Case, Electric Rates 2018 [Member]
Rate Matters [Abstract]
Public Utilities, Rider Conversion to Base Rates	[3]			90
CACJA Recovery Rider | CPUC Proceeding - 2017 Multi-Year Electric Rate Case, Electric Rates 2019 [Member]
Rate Matters [Abstract]
Public Utilities, Rider Conversion to Base Rates	[3]			0
CACJA Recovery Rider | CPUC Proceeding - 2017 Multi-Year Electric Rate Case, Electric Rates 2020 [Member]
Rate Matters [Abstract]
Public Utilities, Rider Conversion to Base Rates	[3]			0
CACJA Recovery Rider | CPUC Proceeding - 2017 Multi-Year Electric Rate Case, Electric Rates 2021 [Member]
Rate Matters [Abstract]
Public Utilities, Rider Conversion to Base Rates	[3]			0
Transmission Cost Adjustment (TCA) Rider [Member] | Colorado 2017 Multi-Year Electric Rate Case [Member]
Rate Matters [Abstract]
Public Utilities, Rider Conversion to Base Rates	[3]			43
Transmission Cost Adjustment (TCA) Rider [Member] | CPUC Proceeding - 2017 Multi-Year Electric Rate Case, Electric Rates 2018 [Member]
Rate Matters [Abstract]
Public Utilities, Rider Conversion to Base Rates	[3]			43
Transmission Cost Adjustment (TCA) Rider [Member] | CPUC Proceeding - 2017 Multi-Year Electric Rate Case, Electric Rates 2019 [Member]
Rate Matters [Abstract]
Public Utilities, Rider Conversion to Base Rates	[3]			0
Transmission Cost Adjustment (TCA) Rider [Member] | CPUC Proceeding - 2017 Multi-Year Electric Rate Case, Electric Rates 2020 [Member]
Rate Matters [Abstract]
Public Utilities, Rider Conversion to Base Rates	[3]			0
Transmission Cost Adjustment (TCA) Rider [Member] | CPUC Proceeding - 2017 Multi-Year Electric Rate Case, Electric Rates 2021 [Member]
Rate Matters [Abstract]
Public Utilities, Rider Conversion to Base Rates	[3]			$ 0
Pipeline System Integrity Adjustment (PSIA) Rider [Member] | CPUC Proceeding - 2017 Multi-Year Gas Rate Case [Member]
Rate Matters [Abstract]
Public Utilities, Rider Conversion to Base Rates	[4]				94
Pipeline System Integrity Adjustment (PSIA) Rider [Member] | CPUC Proceeding - 2017 Multi-Year Gas Rate Case, Gas Rates 2018 [Member]
Rate Matters [Abstract]
Public Utilities, Rider Conversion to Base Rates	[4]				0
Pipeline System Integrity Adjustment (PSIA) Rider [Member] | CPUC Proceeding - 2017 Multi-Year Gas Rate Case, Gas Rates 2019 [Member]
Rate Matters [Abstract]
Public Utilities, Rider Conversion to Base Rates	[4]				94
Pipeline System Integrity Adjustment (PSIA) Rider [Member] | CPUC Proceeding - 2017 Multi-Year Gas Rate Case, Gas Rates 2020 [Member]
Rate Matters [Abstract]
Public Utilities, Rider Conversion to Base Rates	[4]				$ 0
[1]	This base rate request does not include the impacts of the RESA and ECA for the Rush Creek wind investments or the proposed CEP.
[2]	The additional rate base in 2019 predominantly reflects the roll-in of capital associated with the PSIA rider.
[3]	The roll-in of the TCA and CACJA rider revenues into base rates will not have an impact on customer bills or revenue as these costs are already being recovered through a rider. Transmission investments for 2019-2021 will be recovered through the TCA rider.
[4]	The roll-in of PSIA rider revenue into base rates will not have an impact on customer bills or revenue as these costs are already being recovered through the rider. The recovery of incremental PSIA related investments in 2019 and 2020 are included in the base rate request.

Rate Matters, SPS (Details)

Rate Matters, SPS (Details) - SPS $ in Millions		Feb. 16, 2018	Feb. 28, 2018	Oct. 31, 2017USD ($)MW	Nov. 30, 2016USD ($)	Dec. 31, 2017USD ($)	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)
Appeal of the Texas 2015 Electric Rate Case Decision
Rate Matters [Abstract]
Public Utilities, Requested Rate Increase (Decrease), Amount									$ 42
Texas 2017 Electric Rate Case
Rate Matters [Abstract]
Public Utilities, Requested Rate Increase (Decrease), Amount						$ 55
Public Utilities, Requested Rate Increase (Decrease), Percentage						5.80%
Public Utilities, Requested Return on Equity, Percentage						10.25%
Public Utilities, Number of Months in Test Year						12 months
Public Utilities, Number of Months in Test Year which are Estimated						3 months
Public Utilities, Requested Rate Base, Amount						$ 1,900
Public Utilities, Requested Equity Capital Structure, Percentage						53.97%
Public Utilities, Incremental Revenue Request						$ 69
Appeal of the New Mexico 2016 Electric Rate Case Decision
Rate Matters [Abstract]
Public Utilities, Requested Rate Increase (Decrease), Amount					$ 41
Public Utilities, Requested Rate Increase (Decrease), Percentage					10.90%
Public Utilities, Requested Return on Equity, Percentage					10.10%
Public Utilities, Requested Rate Base, Amount					$ 832
Public Utilities, Requested Equity Capital Structure, Percentage					53.97%
New Mexico 2017 Electric Rate Case
Rate Matters [Abstract]
Public Utilities, Requested Rate Increase (Decrease), Amount				$ 43
Public Utilities, Requested Return on Equity, Percentage				10.25%
Public Utilities, Requested Rate Base, Amount				$ 885
Public Utilities, Requested Equity Capital Structure, Percentage				53.97%
Public Utilities, Decline in MW Sales from Wholesale Customers | MW				380
Public Utility Commission of Texas (PUCT) | Appeal of the Texas 2015 Electric Rate Case Decision
Rate Matters [Abstract]
Public Utilities, Approved Rate Decrease, Net of Rate Case Expenses								$ 4
Southwest Power Pool (SPP) | SPP Open Access Transmission Tariff Upgrade Costs
Rate Matters [Abstract]
Public Utilities, Billed Charges For Transmission Service Upgrades							$ 13
Public Utilities, Monthly Billed Charges For Transmission Service Upgrades						0.5
Transmission Cost Recovery Factory (TCRF) Rider [Member] | Texas 2017 Electric Rate Case
Rate Matters [Abstract]
Public Utilities, Rider Conversion to Base Rates	[1]					$ (14)
Subsequent Event | Texas 2017 Electric Rate Case
Rate Matters [Abstract]
Public Utilities, Revised Requested Equity Capital Structure, Percentage		58.00%
Subsequent Event | New Mexico 2017 Electric Rate Case
Rate Matters [Abstract]
Public Utilities, Revised Requested Equity Capital Structure, Percentage			58.00%
[1]	The roll-in of the TCRF rider revenue into base rates will not have an impact on customer bills or revenue as these costs are already being recovered through the rider. SPS can request another TCRF rider after the conclusion of this rate case to recover transmission investments subsequent to June 30, 2017.

Commitments and Contingencies,

Commitments and Contingencies, Capital Commitments (Details) - Capital Commitments	12 Months Ended
	Dec. 31, 2017kVMW
Upper Midwest Wind Projects
Capital Commitments [Abstract]
Public Utilities, Facility Generating Capacity	1,150
TUCO to Yoakum to Hobbs Plant Transmission Line
Capital Commitments [Abstract]
Voltage capacity for transmission line (in kV) | kV	345
Dakota Range
Capital Commitments [Abstract]
Public Utilities, Facility Generating Capacity	300
Rush Creek Wind Farm
Capital Commitments [Abstract]
Public Utilities, Facility Generating Capacity	600
Hobbs Plant to China Draw Transmission Line
Capital Commitments [Abstract]
Voltage capacity for transmission line (in kV) | kV	345
New Mexico and Texas Wind Projects
Capital Commitments [Abstract]
Public Utilities, Facility Generating Capacity	1,000

Commitments and Contingencies97

Commitments and Contingencies, Fuel Contracts (Details) $ in Millions	12 Months Ended
	Dec. 31, 2017USD ($)
Coal
Fuel Contracts [Abstract]
2,018	$ 655
2,019	255
2,020	146
2,021	59
2,022	59
Thereafter	186
Total	1,360
Nuclear Fuel
Fuel Contracts [Abstract]
2,018	61
2,019	118
2,020	34
2,021	85
2,022	66
Thereafter	379
Total	743
Natural Gas Supply
Fuel Contracts [Abstract]
2,018	391
2,019	288
2,020	277
2,021	280
2,022	127
Thereafter	57
Total	1,420
Natural Gas Storage and Transportation
Fuel Contracts [Abstract]
2,018	263
2,019	251
2,020	237
2,021	227
2,022	217
Thereafter	1,046
Total	$ 2,241
Minimum
Unrecorded Unconditional Purchase Obligation [Line Items]
Fuel Contract Expiration Date	2,018
Maximum
Unrecorded Unconditional Purchase Obligation [Line Items]
Fuel Contract Expiration Date	2,060

Commitments and Contingencies98

Commitments and Contingencies, Purchased Power Agreements (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Long-term Contract for Purchase of Electric Power [Line Items]
Purchase Power Agreement Expiration Date		2,039
Capacity
Purchased Power Agreements (PPAs) [Abstract]
Payments for capacity		$ 168	$ 191	$ 231
Estimated Future Payments Under PPAs [Abstract]
2,018		133
2,019		87
2,020		68
2,021		73
2,022		77
Thereafter		205
Total		643
Energy
Estimated Future Payments Under PPAs [Abstract]
2,018	[1]	93
2,019	[1]	99
2,020	[1]	105
2,021	[1]	140
2,022	[1]	155
Thereafter	[1]	368
Total	[1]	$ 960
[1]	Excludes contingent energy payments for renewable energy PPAs.

Commitments and Contingencies99

Commitments and Contingencies, Leases (Details) $ in Millions		12 Months Ended
		Dec. 31, 2017USD ($)Lease	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)
Capital Leases [Abstract]
Number of leases qualifying as capital leases | Lease		3
Amortization expense under capital lease assets		$ 5	$ 8	$ 8
Property Held Under Capital Leases, Net [Abstract]
Property held under capital lease		222	222
Accumulated depreciation		(71)	(66)
Total property held under capital leases, net		151	156
Capital Leases, Future Minimum Payments Due [Abstract]
2,018		15
2,019		14
2,020		14
2,021		14
2,022		12
Thereafter		233
Total minimum obligation		302
Interest component of obligation		(213)
Present value of minimum obligation	[1]	$ 89
Operating Leased Assets [Line Items]
Operating Lease Purchase Power Agreement Expiration Date		2,039
Operating Leases, Future Minimum Payments Due [Abstract]
2,018		$ 238
2,019		260
2,020		268
2,021		270
2,022		257
Thereafter		$ 1,830
WYCO Totem Gas Storage Facilities
Capital Leases [Abstract]
Ownership interest in joint venture (in hundredths)		50.00%
Capital Lease Obligations		$ 124	127
Percentage of the capital lease obligation related to WYCO eliminated (in hundredths)		50.00%
Gas Storage Facilities
Property Held Under Capital Leases, Net [Abstract]
Property held under capital lease		$ 201	201
Gas Pipeline
Property Held Under Capital Leases, Net [Abstract]
Property held under capital lease		21	21
Office Space and Other Equipment
Operating Leases [Abstract]
Total expenses under operating lease obligations		246	255	265
Operating Leases, Future Minimum Payments Due [Abstract]
2,018		25
2,019		30
2,020		24
2,021		24
2,022		22
Thereafter		148
Purchased Power Agreements
Operating Leases [Abstract]
Payments for capacity for PPAs under operating lease obligations		210	$ 216	$ 224
Operating Leases, Future Minimum Payments Due [Abstract]
2,018	[2],[3]	213
2,019	[2],[3]	230
2,020	[2],[3]	244
2,021	[2],[3]	246
2,022	[2],[3]	235
Thereafter	[2],[3]	$ 1,682
[1]	Future commitments exclude certain amounts related to Xcel Energy’s 50 percent ownership interest in WYCO.
[2]	Amounts do not include PPAs accounted for as executory contracts.
[3]	PPA operating leases contractually expire through 2039.

Commitments and Contingencie100

Commitments and Contingencies, Variable Interest Entities (Details) $ in Millions	12 Months Ended
	Dec. 31, 2017USD ($)MW	Dec. 31, 2016USD ($)MW
Purchased Power Agreements [Abstract]
VIE Purchase Power Agreement Expiration Date	2,041
Independent Power Producing Entities
Purchased Power Agreements [Abstract]
Generating capacity (in MW) | MW	3,537	3,537
Harrington Station Power Plant [Member]
Fuel Contracts [Abstract]
Coal Supply Agreement Expiration Date	2,022
Tolk Station Power Plant [Member]
Fuel Contracts [Abstract]
Coal Supply Agreement Expiration Date	2,022
Low-Income Housing Limited Partnerships
Amount Reflected in Consolidated Balance Sheets [Abstract]
Current assets	$ 6	$ 7
Property, plant and equipment, net	46	50
Other noncurrent assets	1	1
Total assets	53	58
Current liabilities	9	8
Mortgages and other long-term debt payable	26	30
Other noncurrent liabilities	1	1
Total liabilities	$ 36	$ 39

Commitments and Contingencie101

Commitments and Contingencies, Technology Agreements (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
IBM Agreement [Member]
Technology Agreements [Abstract]
Technology Agreement Expiration Date	2,022
Percent of contract value to be paid if contract is terminated (in hundredths)	50.00%
Amount capitalized or expensed under technology agreement	$ 98	$ 119	$ 109
Technology Agreements, Minimum Payments Due [Abstract]
2,018	26
2,019	26
2,020	8
2,021	8
2,022	3
Thereafter	$ 0
Accenture Agreement [Member]
Technology Agreements [Abstract]
Technology Agreement Expiration Date	2,020
Amount capitalized or expensed under technology agreement	$ 16	$ 35	$ 17
Technology Agreements, Minimum Payments Due [Abstract]
2,018	11
2,019	11
2,020	11
2,021	0
2,022	0
Thereafter	$ 0

Commitments and Contingencie102

Commitments and Contingencies, Guarantees and Indemnifications (Details) - USD ($)		12 Months Ended
		Dec. 31, 2017	Dec. 31, 2016
Parent Company
Guarantor Obligations [Line Items]
Assets held as collateral		$ 0	$ 0
Guarantees issued and outstanding		18,800,000
Current exposure under these guarantees		0
Payment or Performance Guarantee | Customer Loans for Farm Rewiring Program
Guarantor Obligations [Line Items]
Claims made under guarantee		$ 0
Guarantee Expiration Date (year)		2,020
Payment or Performance Guarantee | Customer Loans for Farm Rewiring Program | NSP-Wisconsin
Guarantor Obligations [Line Items]
Guarantor		NSP-Wisconsin
Guarantees issued and outstanding	[1],[2]	$ 1,000,000
Current exposure under these guarantees	[1],[2]	$ 0
Payment or Performance Guarantee | Obligations Under Aircraft Leases | Parent Company
Guarantor Obligations [Line Items]
Guarantor		Xcel Energy Inc.
Guarantees issued and outstanding	[3],[4]	$ 12,000,000
Current exposure under these guarantees	[3],[4]	$ 0
Payment or Performance Guarantee | Obligations under Equipment Leases [Member] | NSP-Minnesota
Guarantor Obligations [Line Items]
Guarantor		NSP-Minnesota
Guarantees issued and outstanding	[5],[6]	$ 4,800,000
Current exposure under these guarantees	[5],[6]	$ 0
Guarantee Expiration Date (year)		2,019
Payment or Performance Guarantee | Loan for Hiawatha Collegiate High School [Member]
Guarantor Obligations [Line Items]
Guarantee Expiration Date (year)		2,024
Payment or Performance Guarantee | Loan for Hiawatha Collegiate High School [Member] | Parent Company
Guarantor Obligations [Line Items]
Guarantor		Xcel Energy Inc.
Guarantees issued and outstanding	[4],[7]	$ 1,000,000
Current exposure under these guarantees		$ 0
Payment or Performance Guarantee | Surety Bonds | Parent Company
Guarantor Obligations [Line Items]
Guarantor		Xcel Energy Inc.
Guarantees issued and outstanding	[8],[9],[10]	$ 53,100,000
Minimum | Payment or Performance Guarantee | Obligations Under Aircraft Leases | Parent Company
Guarantor Obligations [Line Items]
Guarantee Expiration Date (year)		2,021
Maximum | Payment or Performance Guarantee | Obligations Under Aircraft Leases | Parent Company
Guarantor Obligations [Line Items]
Guarantee Expiration Date (year)		2,023
[1]	(a) The term of this guarantee expires in 2020, which is the final scheduled repayment date for the loans. As of Dec. 31, 2017, no claims had been made by the lender.
[2]	(f) The debtor becomes the subject of bankruptcy or other insolvency proceedings.
[3]	(b) The terms of this guarantee expires in 2021 and 2023 when the associated leases expire.
[4]	(g) Nonperformance and/or nonpayment.
[5]	(c) The term of this guarantee expires in 2019 when the associated lease expires.
[6]	(h) Actual fair value of leased assets is less than the guaranteed residual value amount at the end of the lease term.
[7]	(d) The term of this guarantee expires the earlier of 2024 or full repayment of the loan.
[8]	(e) The surety bonds primarily relate to workers compensation benefits and utility projects. The workers compensation bonds are renewed annually and the project based bonds expire in conjunction with the completion of the related projects.
[9]	(i) Failure of any one of Xcel Energy Inc.’s utility subsidiaries to perform under the agreement that is the subject of the relevant bond. In addition, per the indemnity agreement between Xcel Energy Inc. and the various surety companies, the surety companies have the discretion to demand that collateral be posted.
[10]	(j) Due to the magnitude of projects associated with the surety bonds, the total current exposure of this indemnification cannot be determined. Xcel Energy Inc. believes the exposure to be significantly less than the total amount of the outstanding bonds.

Commitments and Contingencie103

Commitments and Contingencies, Environmental Contingencies - Site Contingencies (Details) $ in Millions	12 Months Ended
	Dec. 31, 2017USD ($)Site	Dec. 31, 2016USD ($)
Ashland MGP Site | NSP-Wisconsin
Manufactured Gas Plant (MGP) Site [Abstract]
Number of Properties Not Owned Included in Superfund Site | Site	2
Current Cost Estimate for Site Remediation	$ 168
Accrual for Environmental Loss Contingencies, Gross	30	$ 64
Estimated Amount Spent on Cleanup	$ 138
Approved Amortization Period for Recovery of Remediation Costs in Natural Gas Rates	10 years
Carrying Cost Percentage to be Applied to Unamortized Regulatory Asset	3.00%
Fargo MGP Site | NSP-Minnesota
Manufactured Gas Plant (MGP) Site [Abstract]
Current Cost Estimate for Site Remediation	$ 23
Accrual for Environmental Loss Contingencies, Gross	16	11
Estimated Amount Spent on Cleanup	$ 7
Percentage of Response Costs Allocable to the North Dakota Jurisdiction	88.00%
Other MGP, Landfill, or Disposal Sites
Manufactured Gas Plant (MGP) Site [Abstract]
Accrual for Environmental Loss Contingencies, Gross	$ 4	$ 2
Number of Identified MGP, Landfill, or Disposal Sites Under Current Investigation and/or Remediation	12
PSCW Proceeding - Gas Rate Case 2017 - Gas Rates 2017 | Ashland MGP Site | NSP-Wisconsin
Manufactured Gas Plant (MGP) Site [Abstract]
Public Utilities, Approved Annual Recovery, Collected Through Base Rates	$ 12
PSCW Proceeding - Gas Rate Case 2017 - Gas Rates 2018 | Ashland MGP Site | NSP-Wisconsin
Manufactured Gas Plant (MGP) Site [Abstract]
Public Utilities, Approved Annual Recovery, Collected Through Base Rates	$ 18

Commitments and Contingencie104

Commitments and Contingencies, Environmental Contingencies - Unrecorded Unconditional Purchase Obligation (Details) $ in Millions	12 Months Ended
	Dec. 31, 2017USD ($)SitePlant	Dec. 31, 2015Period
Implementation of the National Ambient Air Quality Standard for Sulfur Dioxide
Environmental Requirements [Abstract]
Number of Phases Under a Consent Decree Which the EPA is Requiring States to Evaluate Areas for Attainment	3
National Ambient Air Quality Standards for Ozone
Environmental Requirements [Abstract]
Number of Hours Measured for Standard | Period		8
Former Level of Air Quality Concentrations (in parts per billion)		75
Revised Level of Air Quality Concentrations (in parts per billion)		70
NSP-Minnesota | Federal Coal Ash Regulation [Domain]
Unrecorded Unconditional Purchase Obligation [Line Items]
Number of sites where SSI's have been identified | Site	1
NSP-Minnesota | Federal Clean Water Act Section 316(b)
Environmental Requirements [Abstract]
Minimum Number of Plants Which Could Be Required to Make Improvements to Reduce Entrainment | Plant	6
NSP-Wisconsin | Federal Clean Water Act Section 316(b)
Environmental Requirements [Abstract]
Minimum Number of Plants Which Could Be Required to Make Improvements to Reduce Entrainment | Plant	2
Capital Commitments | Federal Clean Water Act Section 316(b)
Environmental Requirements [Abstract]
Liability for Estimated Cost to Comply with Regulation	$ 41
Maximum | Capital Commitments | Federal Clean Water Act Section 316(b)
Environmental Requirements [Abstract]
Liability for Estimated Cost to Comply With Entrainment Regulation	$ 192
Harrington Units 1 and 2 | Implementation of the National Ambient Air Quality Standard for Sulfur Dioxide
Environmental Requirements [Abstract]
Number of Years Unclassifiable Areas Will Be Monitored	3 years
Harrington Units 1 and 2 | Capital Commitments | SPS | Regional Haze Rules
Environmental Requirements [Abstract]
Liability for Estimated Cost to Comply with Regulation	$ 400
Tolk Units 1 and 2 | Capital Commitments | SPS | Regional Haze Rules
Environmental Requirements [Abstract]
Liability for Estimated Cost to Comply with Regulation	$ 600

Commitments and Contingencie105

Commitments and Contingencies, Asset Retirement Obligations (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017		Dec. 31, 2016
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance	$ 2,782		$ 2,609
Liabilities Incurred	1		18
Liabilities Settled	(30)	[1]	(6)
Accretion	136		128
Cash flow revisions	(414)	[2]	33	[3]
Ending balance	2,475		2,782
Legally restricted assets, for purposes of funding future nuclear decommissioning	2,143		1,900
Electric Plant Nuclear Production Decommissioning
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance	2,249		2,141
Liabilities Incurred	0		0
Liabilities Settled	0	[1]	0
Accretion	114		108
Cash flow revisions	(489)	[2]	0	[3]
Ending balance	1,874		2,249
Electric Plant Steam and Other Production Ash Containment
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance	117		132
Liabilities Incurred	0		0
Liabilities Settled	(16)	[1]	(6)
Accretion	5		5
Cash flow revisions	9	[2]	(14)	[3]
Ending balance	115		117
Electric Plant Wind Production
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance	92		72
Liabilities Incurred	0		17	[4]
Liabilities Settled	0	[1]	0
Accretion	4		3
Cash flow revisions	0	[2]	0	[3]
Ending balance	96		92
Electric Plant Steam, Hydro and Other Production Asbestos
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance	88		84
Liabilities Incurred	1		0
Liabilities Settled	(13)	[1]	0
Accretion	4		4
Cash flow revisions	(3)	[2]	0	[3]
Ending balance	77		88
Electric Plant Electric Distribution
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance	20		13
Liabilities Incurred	0		0
Liabilities Settled	0	[1]	0
Accretion	1		1
Cash flow revisions	0	[2]	6	[3]
Ending balance	21		20
Electric Plant Other
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance	5		4
Liabilities Incurred	0		1
Liabilities Settled	0	[1]	0
Accretion	0		0
Cash flow revisions	0	[2]	0	[3]
Ending balance	5		5
Natural Gas Plant Gas Transmission and Distribution
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance	205		156
Liabilities Incurred	0		0
Liabilities Settled	0	[1]	0
Accretion	8		7
Cash flow revisions	69	[2]	42	[3]
Ending balance	282		205
Natural Gas Plant Other
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance	4		4
Liabilities Incurred	0		0
Liabilities Settled	0	[1]	0
Accretion	0		0
Cash flow revisions	0	[2]	0	[3]
Ending balance	4		4
Common and Other Property Common General Plant Asbestos
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance	1		1
Liabilities Incurred	0		0
Liabilities Settled	(1)	[1]	0
Accretion	0		0
Cash flow revisions	0	[2]	0	[3]
Ending balance	0		1
Common and Other Property Common Miscellaneous
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance	1		2
Liabilities Incurred	0		0
Liabilities Settled	0	[1]	0
Accretion	0		0
Cash flow revisions	0	[2]	(1)	[3]
Ending balance	$ 1		$ 1
[1]	The liabilities settled relate to asbestos abatement projects, the closure of certain ash containment facilities, and removal and proper disposal of storage tanks and other above ground equipment.
[2]	In 2017, AROs were revised for changes in estimated cash flows and the timing of those cash flows. The nuclear decommissioning ARO decreased due to updated assumptions in the nuclear triennial filing. Changes in the gas transmission and distribution AROs were mainly related to increased labor costs.
[3]	In 2016, AROs were revised for changes in estimated cash flows and the timing of those cash flows. Changes in the gas transmission and distribution AROs were mainly related to increased miles of gas mains.
[4]	The liability recognized relates to the NSP-Minnesota Courtenay Wind Farm which was placed in service during 2016.

Commitments and Contingencie106

Commitments and Contingencies, Removal Costs (Details) - Plant Removal Costs - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Regulatory Liabilities [Line Items]
Regulatory liabilities	$ 1,131	$ 1,135
NSP-Minnesota
Regulatory Liabilities [Line Items]
Regulatory liabilities	442	419
PSCo
Regulatory Liabilities [Line Items]
Regulatory liabilities	346	367
SPS
Regulatory Liabilities [Line Items]
Regulatory liabilities	197	209
NSP-Wisconsin
Regulatory Liabilities [Line Items]
Regulatory liabilities	$ 146	$ 140

Commitments and Contingencie107

Commitments and Contingencies, Nuclear Insurance (Details) - NSP-Minnesota - Nuclear Insurance $ in Millions	12 Months Ended
	Dec. 31, 2017USD ($)PlantReactor
Nuclear Insurance [Abstract]
Nuclear insurance coverage secured for the Company's public liability exposure	$ 450
Nuclear insurance coverage exposure funded by the Secondary Financial Protection Program	13,000
Maximum assessments per reactor per accident	$ 127
Number of owned and licensed reactors | Reactor	3
Maximum funding requirement per reactor for any one year	$ 19
Insurance coverage limits for NSP-Minnesota's nuclear plant sites	$ 2,300
Number of nuclear plant sites operated by NSP-Minnesota | Plant	2
Maximum assessments for business interruption insurance each calendar year	$ 19
Maximum assessment for property damage insurance NSP-Minnesota is subject to each calendar year	41
Maximum
Nuclear Insurance [Abstract]
Loss Contingency, Estimate of Possible Loss	$ 13,400

Commitments and Contingencie108

Commitments and Contingencies, Legal Contingencies (Details)	1 Months Ended
	Nov. 30, 2017	Dec. 31, 2015	Dec. 31, 2017USD ($)	Dec. 31, 2009
Gas Trading Litigation
Legal Contingencies [Abstract]
Loss Contingency, Pending Claims, Number			6	13
Loss Contingency, Subset of Cases within Multi-District Litigation, Number			2
PSCo | Line Extension Disputes
Legal Contingencies [Abstract]
Accrual For Legal Contingency			$ 0
NSP-Wisconsin | Gas Trading Litigation
Legal Contingencies [Abstract]
Loss Contingency, Pending Claims, Number				2
Minimum | PSCo | Line Extension Disputes
Legal Contingencies [Abstract]
Loss Contingency, Number of Plaintiffs		50
Summary Judgment Granted Against Plaintiff [Member] | Gas Trading Litigation
Legal Contingencies [Abstract]
Loss Contingency, Number of Plaintiffs	2
Remaining in Litigation [Member] | Gas Trading Litigation
Legal Contingencies [Abstract]
Loss Contingency, Number of Plaintiffs	3

Nuclear Obligations (Details)

Nuclear Obligations (Details) $ in Millions		5 Months Ended	12 Months Ended
		May 31, 2014$ / kWh	Dec. 31, 2017USD ($)Canister$ / kWh	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)
Public Utilities, General Disclosures [Line Items]
Decommissioning Fund Investments, Fair Value			$ 2,143	$ 1,900
Fair Value Assumptions, Risk Free Interest Rate			2.80%	3.25%
Fuel Disposal [Abstract]
Fuel disposal fee charge (in dollars per KWh) | $ / kWh		0.001	0
DOE fuel disposal assessments included in fuel expense			$ 0	$ 0
Regulatory Plant Decommissioning Recovery [Abstract]
Assumed annual escalation rate during plant removal activities			4.36%	4.36%
Assumed annual escalation rate during spent fuel management and site restoration activities			3.36%	3.36%
Number of years approved for use in decommissioning scenario (in years)			60 years
Percentage Of Total Obligation For Decommissioning Expected To Be Funded By External Funds			100.00%
Approved annual accrual for decommissioning costs			$ 14
Funded Status of Nuclear Decommissioning Obligation [Abstract]
Estimated decommissioning cost obligation from most recently approved study (in 2014 dollars)			3,012	$ 3,012
Effect of escalating costs (to 2017 and 2016 dollars, respectively, at 4.36/3.36 percent)			396	258
Estimated decommissioning cost obligation (in current dollars)			3,408	3,270
Effect of escalating costs to payment date (4.36/3.36 percent)			7,797	7,935
Estimated future decommissioning costs (undiscounted)			11,205	11,205
Effect of discounting obligation (using average risk-free interest rate of 2.80 percent and 3.25 percent for 2017 and 2016, respectively)			(6,398)	(7,068)
Discounted decommissioning cost obligation			4,807	4,137
Underfunding of external decommissioning fund compared to the discounted decommissioning obligation			2,664	2,276
Regulatory Basis to GAAP Basis Reconciliation [Abstract]
Differences in Discount Rate and Market Risk Premium			(1,403)	(1,044)
Operating and Maintenance Costs Not Included for GAAP			(1,041)	(844)
ARO differences between 2017 and 2014 cost studies			(489)	0
Asset Retirement Obligation			2,475	2,782	$ 2,609
Annual Decommissioning Recorded As Depreciation Expense [Abstract]
Annual decommissioning recorded as depreciation expense: (a) (b)	[1],[2]		$ 20	20	7
Minimum
Regulatory Plant Decommissioning Recovery [Abstract]
Assumed after tax rate of return used to determine funding for external decommissioning trust fund			5.23%
Maximum
Regulatory Plant Decommissioning Recovery [Abstract]
Assumed after tax rate of return used to determine funding for external decommissioning trust fund			6.30%
Nuclear Plant [Member]
Regulatory Basis to GAAP Basis Reconciliation [Abstract]
Asset Retirement Obligation			$ 1,874	2,249	$ 2,141
Monticello [Member]
Fuel Disposal [Abstract]
Number of authorized canisters filled and placed In dry cask nuclear storage facility | Canister			16
Number of authorized canisters in dry cask nuclear storage facility | Canister			30
Prairie Island [Member]
Fuel Disposal [Abstract]
Number of authorized canisters filled and placed In dry cask nuclear storage facility | Canister			40
Number of authorized canisters in dry cask nuclear storage facility | Canister			64
Estimate of Fair Value Measurement [Member] | Fair Value Measured on a Recurring Basis | Nuclear Decommissioning Fund
Funded Status of Nuclear Decommissioning Obligation [Abstract]
Assets Held in External Decommissioning Trust	[3]			$ 1,861
[1]	Decommissioning expense does not include depreciation of the capitalized nuclear asset retirement costs.
[2]	Decommissioning expenses in 2017 and 2016 include Minnesota’s retail jurisdiction annual funding requirement of approximately $14 million. The 2015 expense was offset by the DOE settlement refund.
[3]	Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $133 million of equity investments in unconsolidated subsidiaries and $98 million of rabbi trust assets and miscellaneous investments.

Regulatory Assets and Liabil110

Regulatory Assets and Liabilities, Regulatory Assets (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2017		Dec. 31, 2016
Regulatory Assets [Line Items]
Regulatory Asset, Current		$ 424		$ 364
Regulatory Asset, Noncurrent		3,005		3,081
Past expenditures not currently earning a return		250		166
Pension and Retiree Medical Obligations
Regulatory Assets [Line Items]
Regulatory Asset, Current	[1]	91		89
Regulatory Asset, Noncurrent	[1]	$ 1,499		1,549
Regulatory asset, remaining amortization period		Various
Pension Costs | NSP-Minnesota
Regulatory Assets [Line Items]
Regulatory Asset, Current		$ 9		15
Regulatory Asset		179		241
Non Qualified Pension Plan
Regulatory Assets [Line Items]
Regulatory Asset, Current		1		3
Regulatory Asset		8		11
Net AROs
Regulatory Assets [Line Items]
Regulatory Asset, Current	[2]	0		0
Regulatory Asset, Noncurrent	[2]	$ 301		379
Regulatory asset, remaining amortization period		Plant lives
Excess deferred taxes - TCJA
Regulatory Assets [Line Items]
Regulatory Asset, Current		$ 0		0
Regulatory Asset, Noncurrent		$ 254		0
Regulatory asset, remaining amortization period		Various
Revaluation of Regulatory Assets for New Federal Tax Rate [Member]
Regulatory Assets [Line Items]
Contra Regulatory Asset		$ 202
Recoverable Deferred Taxes on AFUDC Recorded in Plant
Regulatory Assets [Line Items]
Regulatory Asset, Current		0	[3]	0
Regulatory Asset, Noncurrent		$ 244	[3]	424
Regulatory asset, remaining amortization period		Plant lives
Environmental Remediation Costs
Regulatory Assets [Line Items]
Regulatory Asset, Current		$ 16		11
Regulatory Asset, Noncurrent		$ 165		165
Regulatory asset, remaining amortization period		Various
Contract Valuation Adjustments
Regulatory Assets [Line Items]
Regulatory Asset, Current	[4]	$ 21		18
Regulatory Asset, Noncurrent	[4]	$ 93		111
Regulatory asset, remaining amortization period		Term of related contract
Depreciation Differences
Regulatory Assets [Line Items]
Regulatory Asset, Current		$ 20		15
Regulatory Asset, Noncurrent		$ 69		90
Regulatory asset, remaining amortization period, minimum		1 year
Regulatory asset, remaining amortization period, maximum		14 years
Purchased Power Agreements
Regulatory Assets [Line Items]
Regulatory Asset, Current		$ 3		2
Regulatory Asset, Noncurrent		$ 67		70
Regulatory asset, remaining amortization period		Term of related contract
Prairie Island EPU
Regulatory Assets [Line Items]
Regulatory Asset, Current		$ 3		3
Regulatory Asset, Noncurrent		$ 58		62
Regulatory asset, remaining amortization period		17 years
Losses on Reacquired Debt
Regulatory Assets [Line Items]
Regulatory Asset, Current		$ 5		4
Regulatory Asset, Noncurrent		$ 48		23
Regulatory asset, remaining amortization period		Term of related debt
Conservation Programs
Regulatory Assets [Line Items]
Regulatory Asset, Current	[5]	$ 50		48
Regulatory Asset, Noncurrent	[5]	$ 32		48
Regulatory asset, remaining amortization period, minimum		1 year
Regulatory asset, remaining amortization period, maximum		2 years
State Commission Adjustments
Regulatory Assets [Line Items]
Regulatory Asset, Current		$ 1		1
Regulatory Asset, Noncurrent		$ 29		27
Regulatory asset, remaining amortization period		Plant lives
Property Tax
Regulatory Assets [Line Items]
Regulatory Asset, Current		$ 8		9
Regulatory Asset, Noncurrent		$ 24		2
Regulatory asset, remaining amortization period		Various
Nuclear Refueling Outage Costs
Regulatory Assets [Line Items]
Regulatory Asset, Current		$ 49		49
Regulatory Asset, Noncurrent		$ 20		16
Regulatory asset, remaining amortization period, minimum		1 year
Regulatory asset, remaining amortization period, maximum		2 years
Deferred Purchased Natural Gas and Electric Energy Costs
Regulatory Assets [Line Items]
Regulatory Asset, Current		$ 21		18
Regulatory Asset, Noncurrent		$ 13		16
Regulatory asset, remaining amortization period		Various
CACJA Recovery Rider
Regulatory Assets [Line Items]
Regulatory asset, remaining amortization period, minimum		1 year
Regulatory asset, remaining amortization period, maximum		2 years
Sales True Up and Revenue Decoupling [Member]
Regulatory Assets [Line Items]
Regulatory Asset, Current		$ 37		0
Regulatory Asset, Noncurrent		12		0
Gas Pipeline Inspection and Remediation Costs
Regulatory Assets [Line Items]
Regulatory Asset, Current		24		7
Regulatory Asset, Noncurrent		$ 12		14
Regulatory asset, remaining amortization period, minimum		1 year
Regulatory asset, remaining amortization period, maximum		2 years
Renewable Resources and Environmental Initiatives
Regulatory Assets [Line Items]
Regulatory Asset, Current		$ 48		34
Regulatory Asset, Noncurrent		$ 10		23
Regulatory asset, remaining amortization period, minimum		1 year
Regulatory asset, remaining amortization period, maximum		3 years
Other Regulatory Assets
Regulatory Assets [Line Items]
Regulatory Asset, Current		$ 27		56
Regulatory Asset, Noncurrent		$ 55		$ 62
Regulatory asset, remaining amortization period		Various
[1]	Includes $179 million and $241 million for the regulatory recognition of the NSP-Minnesota pension expense, of which $9 million and $15 million is included in the current asset at Dec. 31, 2017 and 2016, respectively. Also included are $8 million and $11 million of regulatory assets related to the nonqualified pension plan, of which $1 million and $3 million is included in the current asset at Dec. 31, 2017 and 2016, respectively.
[2]	Includes amounts recorded for future recovery of AROs, less amounts recovered through nuclear decommissioning accruals and gains from decommissioning investments.
[3]	Includes a write-down of $202 million as a result of the revaluation of deferred tax gross up at the new federal tax rate at Dec. 31, 2017.
[4]	Includes the fair value of certain long-term PPAs used to meet energy capacity requirements and valuation adjustments on natural gas commodity purchases.
[5]	Includes costs for conservation programs, as well as incentives allowed in certain jurisdictions.

Regulatory Assets and Liabil111

Regulatory Assets and Liabilities, Regulatory Liabilities (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2017		Dec. 31, 2016
Regulatory Liabilities [Line Items]
Regulatory Liability, Current	[1]	$ 239		$ 221
Regulatory Liability, Noncurrent		5,083		1,383
Excess deferred taxes - TCJA
Regulatory Liabilities [Line Items]
Regulatory Liability, Current		0	[2]	0
Regulatory Liability, Noncurrent		3,733	[2]	0
Revaluation of Non-plant ADIT	[2]	$ 174
Regulatory liability, remaining amortization period		Various
Plant Removal Costs
Regulatory Liabilities [Line Items]
Regulatory Liability, Current		$ 0		0
Regulatory Liability, Noncurrent		$ 1,131		1,135
Regulatory liability, remaining amortization period		Plant lives
Renewable Resources and Environmental Initiatives
Regulatory Liabilities [Line Items]
Regulatory Liability, Current		$ 19		5
Regulatory Liability, Noncurrent		$ 56		71
Regulatory liability, remaining amortization period		Various
Investment Tax Credit Deferrals
Regulatory Liabilities [Line Items]
Regulatory Liability, Current		$ 0		0
Regulatory Liability, Noncurrent		$ 42		45
Regulatory liability, remaining amortization period		Various
Deferred Income Tax Adjustment
Regulatory Liabilities [Line Items]
Regulatory Liability, Current		$ 0		0
Regulatory Liability, Noncurrent		$ 38		48
Regulatory liability, remaining amortization period		Various
Deferred Electric, Natural Gas and Steam Production Costs
Regulatory Liabilities [Line Items]
Regulatory Liability, Current		$ 104		98
Regulatory Liability, Noncurrent		$ 0		0
Regulatory liability remaining amortization period, maximum		1 year
Contract Valuation Adjustments
Regulatory Liabilities [Line Items]
Regulatory Liability, Current	[3]	$ 30		22
Regulatory Liability, Noncurrent	[3]	$ 0		2
Regulatory liability, remaining amortization period		Term of related contract
Conservation Programs
Regulatory Liabilities [Line Items]
Regulatory Liability, Current	[4]	$ 23		25
Regulatory Liability, Noncurrent	[4]	$ 0		0
Regulatory liability remaining amortization period, maximum		1 year
DOE Settlement
Regulatory Liabilities [Line Items]
Regulatory Liability, Current		$ 18		20
Regulatory Liability, Noncurrent		$ 0		0
Regulatory liability remaining amortization period, maximum		1 year
Other Regulatory Liabilities
Regulatory Liabilities [Line Items]
Regulatory Liability, Current		$ 45		51
Regulatory Liability, Noncurrent		$ 83		82
Regulatory liability, remaining amortization period		Various
Other Current Liabilities
Regulatory Liabilities [Line Items]
Entity's Recorded Provision for Revenue Subject To Refund		$ 15		$ 46
[1]	Revenue subject to refund of $15 million and $46 million for 2017 and 2016, respectively, is included in other current liabilities.
[2]	Primarily relates to the revaluation of recoverable/regulated plant ADIT and $174 million revaluation impact of non-plant ADIT at Dec. 31, 2017.
[3]	Includes the fair value of certain long-term PPAs used to meet energy capacity requirements and valuation adjustments on natural gas commodity purchases.
[4]	Includes costs for conservation programs, as well as incentives allowed in certain jurisdictions.

Other Comprehensive Income (Det

Other Comprehensive Income (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2017	Dec. 31, 2016
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Accumulated other comprehensive income (loss) at beginning of period		$ 11,021
Losses reclassified from net accumulated other comprehensive loss		10	$ 8
Adoption of ASU No. 2018-02		0
Accumulated other comprehensive income (loss) at end of period		11,455	11,021
Gains and Losses on Cash Flow Hedges
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Accumulated other comprehensive income (loss) at beginning of period		(51)	(55)
Other comprehensive income (loss) before reclassifications		0	0
Losses reclassified from net accumulated other comprehensive loss		3	4
Net current period other comprehensive income (loss)		3	4
Adoption of ASU No. 2018-02	[1]	(10)
Accumulated other comprehensive income (loss) at end of period		(58)	(51)
Defined Benefit Pension and Postretirement Items
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Accumulated other comprehensive income (loss) at beginning of period		(59)	(55)
Other comprehensive income (loss) before reclassifications		(3)	(8)
Losses reclassified from net accumulated other comprehensive loss		7	4
Net current period other comprehensive income (loss)		4	(4)
Adoption of ASU No. 2018-02	[1]	(12)
Accumulated other comprehensive income (loss) at end of period		(67)	(59)
Total
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Accumulated other comprehensive income (loss) at beginning of period		(110)	(110)
Other comprehensive income (loss) before reclassifications		(3)	(8)
Losses reclassified from net accumulated other comprehensive loss		10	8
Net current period other comprehensive income (loss)		7	0
Adoption of ASU No. 2018-02	[1]	(22)
Accumulated other comprehensive income (loss) at end of period		$ (125)	$ (110)
[1]	(a) In 2017, Xcel Energy implemented ASU No. 2018-02 related to the TCJA, which resulted in reclassification of certain credit balances within net accumulated other comprehensive loss to retained earnings. For further information, see Note 2.

Other Comprehensive Income - Re

Other Comprehensive Income - Reclassification from AOCI (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Total, pre-tax		$ (1,690)	$ (1,704)	$ (1,527)
Income tax expense (benefit)		542	581	$ 543
Total amounts reclassified, net of tax		(10)	(8)
Gains and Losses on Cash Flow Hedges
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Total amounts reclassified, net of tax		(3)	(4)
Gains and Losses on Cash Flow Hedges | Amounts Reclassified from Accumulated Other Comprehensive Loss
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Total, pre-tax		5	6
Income tax expense (benefit)		(2)	(2)
Total, net of tax		3	4
Gains and Losses on Cash Flow Hedges | Interest Rate Derivatives | Amounts Reclassified from Accumulated Other Comprehensive Loss
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Interest charges	[1]	5	6
Amortization of net losses | Amounts Reclassified from Accumulated Other Comprehensive Loss
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Total, pre-tax	[2]	12	6
Defined Benefit Pension and Postretirement Items
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Total amounts reclassified, net of tax		(7)	(4)
Defined Benefit Pension and Postretirement Items | Amounts Reclassified from Accumulated Other Comprehensive Loss
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Total, pre-tax		(12)	(6)
Tax benefit		5	2
Total amounts reclassified, net of tax		$ 7	$ 4
[1]	(a) Included in interest charges.
[2]	(b) Included in the computation of net periodic pension and postretirement benefit costs. See Note 9 for detail regarding these benefit plans.

Segments and Related Informa114

Segments and Related Information (Details) - USD ($) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Segment Reporting Information [Line Items]
Operating revenues	$ 2,796	$ 3,017	$ 2,645	$ 2,946	$ 2,795	$ 3,040	$ 2,500	$ 2,772	$ 11,404	$ 11,107	$ 11,024
Depreciation and amortization									1,479	1,303	1,124
Total interest charges and financing costs									628	620	569
Income tax expense (benefit)									542	581	543
Net income (loss)	$ 189	$ 492	$ 227	$ 239	$ 227	$ 458	$ 197	$ 241	1,148	1,123	984
Regulated Electric
Segment Reporting Information [Line Items]
Operating revenues									9,678	9,501	9,278
Depreciation and amortization									1,298	1,136	963
Total interest charges and financing costs									449	450	426
Income tax expense (benefit)									528	567	509
Net income (loss)									1,066	1,067	921
Regulated Natural Gas
Segment Reporting Information [Line Items]
Operating revenues									1,651	1,532	1,673
Depreciation and amortization									174	160	155
Total interest charges and financing costs									57	54	50
Income tax expense (benefit)									23	76	60
Net income (loss)									182	124	106
All Other
Segment Reporting Information [Line Items]
Operating revenues									78	76	76
Depreciation and amortization									7	7	6
Total interest charges and financing costs									122	116	93
Income tax expense (benefit)									(9)	(62)	(26)
Net income (loss)									(100)	(68)	(43)
Operating Segments
Segment Reporting Information [Line Items]
Operating revenues									11,404	11,107	11,024
Operating Segments | Regulated Electric
Segment Reporting Information [Line Items]
Operating revenues									9,676	9,500	9,276
Operating Segments | Regulated Natural Gas
Segment Reporting Information [Line Items]
Operating revenues									1,650	1,531	1,672
Operating Segments | All Other
Segment Reporting Information [Line Items]
Operating revenues									78	76	76
Intersegment Eliminations
Segment Reporting Information [Line Items]
Operating revenues									(3)	(2)	(3)
Depreciation and amortization									0	0	0
Total interest charges and financing costs									0	0	0
Income tax expense (benefit)									0	0	0
Net income (loss)									0	0	0
Intersegment Eliminations | Regulated Electric
Segment Reporting Information [Line Items]
Operating revenues									2	1	2
Intersegment Eliminations | Regulated Natural Gas
Segment Reporting Information [Line Items]
Operating revenues									1	1	1
Intersegment Eliminations | All Other
Segment Reporting Information [Line Items]
Operating revenues									$ 0	$ 0	$ 0

Summarized Quarterly Financi115

Summarized Quarterly Financial Data (Unaudited) (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Quarterly Financial Information Disclosure [Abstract]
Operating revenues	$ 2,796	$ 3,017	$ 2,645	$ 2,946	$ 2,795	$ 3,040	$ 2,500	$ 2,772	$ 11,404	$ 11,107	$ 11,024
Operating income	426	818	460	486	465	827	432	490	2,190	2,214	2,000
Net income	$ 189	$ 492	$ 227	$ 239	$ 227	$ 458	$ 197	$ 241	$ 1,148	$ 1,123	$ 984
Basic (in dollars per share)	$ 0.37	$ 0.97	$ 0.45	$ 0.47	$ 0.45	$ 0.90	$ 0.39	$ 0.47	$ 2.26	$ 2.21	$ 1.94
Diluted (in dollars per share)	0.37	0.97	0.45	0.47	0.45	0.90	0.39	0.47	2.25	2.21	1.94
Cash dividends declared per common share (in dollars per share)	$ 0.36	$ 0.36	$ 0.36	$ 0.36	$ 0.34	$ 0.34	$ 0.34	$ 0.34	$ 1.44	$ 1.36	$ 1.28

Schedule I, Condensed Financ116

Schedule I, Condensed Financial Statements of Xcel Energy Inc, Condensed Statements of Income (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Income
Equity earnings of subsidiaries									$ 30	$ 42	$ 34
Expenses and other deductions
Other income									(23)	(8)	(6)
Interest charges and financing costs									663	647	595
Income before income taxes									1,690	1,704	1,527
Income tax benefit									542	581	543
Net income	$ 189	$ 492	$ 227	$ 239	$ 227	$ 458	$ 197	$ 241	1,148	1,123	984
Other Comprehensive Income (Loss), Net of Tax [Abstract]
Pension and retiree medical benefits, net of tax of $3, $(3), and $(3) respectively									(3)	(8)	(8)
Comprehensive Income, Net of Tax									$ 1,155	$ 1,123	$ 982
Weighted average common shares outstanding:
Basic (in shares)									509	508.8	507.8
Diluted (in shares)									509.1	509	508.2
Earnings per average common share:
Basic (in dollars per share)	$ 0.37	$ 0.97	$ 0.45	$ 0.47	$ 0.45	$ 0.90	$ 0.39	$ 0.47	$ 2.26	$ 2.21	$ 1.94
Diluted (in dollars per share)	0.37	0.97	0.45	0.47	0.45	0.90	0.39	0.47	2.25	2.21	1.94
Cash dividends declared per common share (in dollars per share)	$ 0.36	$ 0.36	$ 0.36	$ 0.36	$ 0.34	$ 0.34	$ 0.34	$ 0.34	$ 1.44	$ 1.36	$ 1.28
Xcel Energy Inc.
Income
Equity earnings of subsidiaries									$ 1,263	$ 1,199	$ 1,046
Total income									1,263	1,199	1,046
Expenses and other deductions
Operating expenses									30	22	20
Other income									(6)	(3)	(1)
Interest charges and financing costs									128	116	91
Total expenses and other deductions									152	135	110
Income before income taxes									1,111	1,064	936
Income tax benefit									(37)	(59)	(48)
Net income									1,148	1,123	984
Other Comprehensive Income (Loss), Net of Tax [Abstract]
Pension and retiree medical benefits, net of tax of $3, $(3), and $(3) respectively									4	(4)	(5)
Derivative instruments, net of tax of $2, $2, and $2, respectively									3	4	3
Other Comprehensive Income (Loss), Net of Tax									7	0	(2)
Comprehensive Income, Net of Tax									$ 1,155	$ 1,123	$ 982

Schedule I, Condensed Financ117

Schedule I, Condensed Financial Statements of Xcel Energy Inc, Condensed Statements of Income (Parenthetical) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Condensed Financial Information of Parent Company Only Disclosure [Abstract]
Pension and retiree medical benefits, tax expense(benefit)	$ 3	$ (3)	$ (3)
Derivative instruments, tax expense(benefit)	$ 2	$ 2	$ 2

Schedule I, Condensed Financ118

Schedule I, Condensed Financial Statements of Xcel Energy Inc, Condensed Statements of Cash Flows (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Operating activities
Net cash provided by (used in) operating activities	$ 3,126	$ 3,052	$ 3,038
Investing activities
Net cash provided by (used in) investing activities	(3,296)	(3,261)	(3,623)
Financing activities
Proceeds from (repayment of) short-term borrowings, net	422	(454)	(174)
Proceeds from issuance of long-term debt	1,518	2,424	1,626
Repayment of long-term debt	(1,030)	(1,036)	(251)
Proceeds from issuance of common stock	0	0	7
Repurchases of common stock	(3)	(32)	0
Dividends paid	(721)	(681)	(607)
Other	(18)	(12)	(11)
Net cash provided by (used in) financing activities	168	209	590
Net change in cash and cash equivalents	(2)	0	5
Cash and cash equivalents at beginning of period	85	85	80
Cash and cash equivalents at end of period	83	85	85
Xcel Energy Inc.
Operating activities
Net cash provided by (used in) operating activities	1,208	817	705
Investing activities
Capital contributions to subsidiaries	(849)	(414)	(820)
Investments in the utility money pool	(1,258)	(1,880)	(971)
Return of investments in the utility money pool	1,173	1,880	987
Net cash provided by (used in) investing activities	(934)	(414)	(804)
Financing activities
Proceeds from (repayment of) short-term borrowings, net	715	(516)	204
Proceeds from issuance of long-term debt	0	1,539	495
Repayment of long-term debt	(250)	(704)	0
Proceeds from issuance of common stock	0	0	7
Repurchases of common stock	(3)	(32)	0
Dividends paid	(721)	(681)	(607)
Other	(14)	(9)	(1)
Net cash provided by (used in) financing activities	(273)	(403)	98
Net change in cash and cash equivalents	1	0	(1)
Cash and cash equivalents at beginning of period	0	0	1
Cash and cash equivalents at end of period	$ 1	$ 0	$ 0

Schedule I, Condensed Financ119

Schedule I, Condensed Financial Statements of Xcel Energy Inc, Condensed Balance Sheets (Details) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Assets
Cash and cash equivalents	$ 83	$ 85	$ 85	$ 80
Total current assets	2,973	2,842
Investment in subsidiaries	140	133
Other assets	278	248
Total other assets	5,728	5,471
Total assets	43,030	41,155
Liabilities and Equity
Dividends payable	183	172
Short-term debt	814	392
Other current liabilities	501	505
Total current liabilities	4,088	3,247
Other liabilities	145	225
Total deferred credits and other liabilities	12,967	12,692
Commitments and contingencies
Capitalization
Total common stockholders’ equity	11,455	11,021
Total liabilities and equity	43,030	41,155
Xcel Energy Inc.
Assets
Cash and cash equivalents	1	0	$ 0	$ 1
Accounts receivable from subsidiaries	302	364
Other current assets	1	10
Total current assets	304	374
Investment in subsidiaries	14,932	13,904
Other assets	103	163
Total other assets	15,035	14,067
Total assets	15,339	14,441
Liabilities and Equity
Long-term Debt, Current Maturities	0	250
Dividends payable	183	172
Short-term debt	783	68
Other current liabilities	11	18
Total current liabilities	977	508
Other liabilities	29	37
Total deferred credits and other liabilities	29	37
Commitments and contingencies
Capitalization
Long-term debt, noncurrent	2,878	2,875
Total common stockholders’ equity	11,455	11,021
Total capitalization	14,333	13,896
Total liabilities and equity	$ 15,339	$ 14,441

Schedule I, Condensed Financ120

Schedule I, Condensed Financial Statements of Xcel Energy Inc, Notes to Condensed Financial Statements (Details) - Xcel Energy Inc. - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Accounts Receivable and Payable with Affiliates [Abstract]
Accounts Receivable	$ 302	$ 302	$ 364
Accounts Payable	0	0	0
Dividends [Abstract]
Cash dividends paid to Xcel Energy by subsidiaries		1,063	923	$ 784
Money Pool [Abstract]
Loan outstanding at period end	85	85	0	0
Average loan outstanding	36	38	66	27
Maximum loan outstanding	$ 85	$ 226	$ 211	$ 141
Weighted average interest rate, computed on a daily basis (percentage)	1.15%	1.13%	0.69%	0.42%
Weighted average interest rate at period end (percentage)	1.18%	1.18%
Money pool interest income	$ 0.1	$ 0.4	$ 0.5	$ 0.1
NSP-Minnesota
Accounts Receivable and Payable with Affiliates [Abstract]
Accounts Receivable	68	68	59
Accounts Payable	0	0	0
NSP-Wisconsin
Accounts Receivable and Payable with Affiliates [Abstract]
Accounts Receivable	13	13	14
Accounts Payable	0	0	0
PSCo
Accounts Receivable and Payable with Affiliates [Abstract]
Accounts Receivable	69	69	132
Accounts Payable	0	0	0
SPS
Accounts Receivable and Payable with Affiliates [Abstract]
Accounts Receivable	26	26	31
Accounts Payable	0	0	0
Xcel Energy Services Inc.
Accounts Receivable and Payable with Affiliates [Abstract]
Accounts Receivable	95	95	93
Accounts Payable	0	0	0
Xcel Energy Ventures Inc.
Accounts Receivable and Payable with Affiliates [Abstract]
Accounts Receivable	14	14	17
Accounts Payable	0	0	0
Other Subsidiaries
Accounts Receivable and Payable with Affiliates [Abstract]
Accounts Receivable	17	17	18
Accounts Payable	$ 0	$ 0	$ 0

Schedule II, Valuation and Q121

Schedule II, Valuation and Qualifying Accounts (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Allowance for Bad Debts
Movement in Valuation Allowances and Reserves [Roll Forward]
Balance at Jan. 1		$ 51	$ 52	$ 58
Charged to costs and expenses		39	39	36
Charged to other accounts	[1]	10	11	12
Deductions from reserves	[2]	48	51	54
Balance at Dec. 31		52	51	52
NOL and Tax Credit Valuation Allowances
Movement in Valuation Allowances and Reserves [Roll Forward]
Balance at Jan. 1		58	28	3
Charged to costs and expenses		9	3	2
Charged to other accounts	[1]	22	35	25
Deductions from reserves	[2]	12	8	2
Balance at Dec. 31		$ 77	$ 58	$ 28
[1]	Accrual of valuation allowance for North Dakota ITC, offset to regulatory liability.
[2]	Reductions to valuation allowances for North Dakota ITC carryforwards primarily due to a consolidated adjustment to the regulatory liability accrual referenced above. Reductions to valuation allowances for NOL carryforwards primarily due to changes in forecasted taxable income.