Xcel Energy (XEL) 10-K 21 Feb 20 2019 FY Annual report Financial data

Cover Page

Cover Page - USD ($)	12 Months Ended
	Dec. 31, 2019	Feb. 13, 2020	Jun. 28, 2019
Cover page.
Entity Registrant Name	XCEL ENERGY INC
Entity Central Index Key	0000072903
Current Fiscal Year End Date	--12-31
Document Fiscal Year Focus	2019
Document Fiscal Period Focus	FY
Amendment Flag	false
Document Type	10-K
Document Annual Report	true
Document Period End Date	Dec. 31, 2019
Document Transition Report	false
Entity File Number	001-3034
Entity Tax Identification Number	41-0448030
Entity Incorporation, State or Country Code	MN
Entity Address, Address Line One	414 Nicollet Mall
Entity Address, City or Town	Minneapolis
Entity Address, State or Province	MN
Entity Address, Postal Zip Code	55401
City Area Code	612
Local Phone Number	330-5500
Title of 12(b) Security	Common Stock, $2.50 par value
Trading Symbol	XEL
Security Exchange Name	NASDAQ
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Large Accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Shell Company	false
Entity Public Float			$ 30,629,347,167
Entity Common Stock, Shares Outstanding		524,669,024

CONSOLIDATED STATEMENTS OF INCO

CONSOLIDATED STATEMENTS OF INCOME - USD ($) shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Operating revenues
Electric	$ 9,575	$ 9,719	$ 9,676
Natural Gas	1,868	1,739	1,650
Other	86	79	78
Total operating revenues	11,529	11,537	11,404
Operating expenses
Electric fuel and purchased power	3,510	3,854	3,757
Cost of natural gas sold and transported	918	843	823
Cost of sales — other	40	35	34
Operating and maintenance expenses	2,338	2,352	2,270
Conservation and demand side management program expenses	285	290	273
Depreciation and amortization	1,765	1,642	1,479
Taxes (other than income taxes)	569	556	545
Total operating expenses	9,425	9,572	9,181
Operating income	2,104	1,965	2,223
Other income (expense), net	16	(14)	(10)
Equity earnings of unconsolidated subsidiaries	39	35	30
Allowance for funds used during construction — equity	77	108	75
Interest charges and financing costs
Interest charges — includes other financing costs of $26, $25 and $24, respectively	773	700	663
Allowance for funds used during construction — debt	(37)	(48)	(35)
Total interest charges and financing costs	736	652	628
Income before income taxes	1,500	1,442	1,690
Income taxes	128	181	542
Net income	$ 1,372	$ 1,261	$ 1,148
Weighted average common shares outstanding:
Basic (in shares)	519	511	509
Diluted (in shares)	520	511	509
Earnings per average common share:
Basic (in dollars per share)	$ 2.64	$ 2.47	$ 2.26
Diluted (in dollars per share)	$ 2.64	$ 2.47	$ 2.25

CONSOLIDATED STATEMENTS OF IN_2

CONSOLIDATED STATEMENTS OF INCOME (Parenthetical) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Interest charges and financing costs
Other financing costs	$ 26	$ 25	$ 24

CONSOLIDATED STATEMENTS OF COMP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Comprehensive income:
Net income	$ 1,372	$ 1,261	$ 1,148
Defined pension and other postretirement benefits:
Net pension and retiree medical loss arising during the period, net of tax of $0, $(2) and $(2), respectively	0	(6)	(3)
Reclassification of loss to net income, net of tax of $1, $3 and $5, respectively	3	9	7
Derivative instruments:
Net fair value decrease, net of tax of $(8), $(2) and $0, respectively	(23)	(5)	0
Reclassification of loss to net income, net of tax of $1, $1 and $2, respectively	3	3	3
Total other comprehensive (loss) income	(17)	1	7
Total comprehensive income	$ 1,355	$ 1,262	$ 1,155

CONSOLIDATED STATEMENTS OF CO_2

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - PARENTHETICAL - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Pension and retiree medical benefits:
Net pension and retiree medical benefit loss arising during the period, tax	$ 0	$ (2)	$ (2)
Reclassifications of loss included in net periodic benefit cost, tax	1	3	5
Derivative instruments:
Net fair value decrease, tax	(8)	(2)	0
Reclassification of losses to net income, tax	$ 1	$ 1	$ 2

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Operating activities
Net income	$ 1,372	$ 1,261	$ 1,148
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization	1,785	1,659	1,495
Nuclear fuel amortization	119	122	114
Deferred income taxes	143	218	640
Allowance for equity funds used during construction	(77)	(108)	(75)
Equity earnings of unconsolidated subsidiaries	(39)	(35)	(30)
Dividends from unconsolidated subsidiaries	40	37	41
Provision for bad debts	42	42	39
Share-based compensation expense	58	45	57
Net realized and unrealized hedging and derivative transactions	45	22	2
Changes in operating assets and liabilities:
Accounts receivable	(20)	(105)	(60)
Accrued unbilled revenues	42	9	(34)
Inventories	(84)	(65)	(3)
Other current assets	25	18	9
Accounts payable	(12)	90	43
Net regulatory assets and liabilities	(66)	223	(16)
Other current liabilities	(15)	(61)	(38)
Pension and other employee benefit obligations	(135)	(179)	(133)
Other, net	40	(71)	(73)
Net cash provided by operating activities	3,263	3,122	3,126
Investing activities
Utility capital/construction expenditures	(4,225)	(3,957)	(3,244)
Purchases of investment securities	(995)	(853)	(1,697)
Proceeds from the sale of investment securities	975	833	1,669
Other, net	(98)	(9)	(24)
Net cash used in investing activities	(4,343)	(3,986)	(3,296)
Financing activities
(Repayments of) proceeds from short-term borrowings, net	(443)	225	422
Proceeds from issuance of long-term debt	2,920	1,675	1,518
Repayments of long-term debt, including reacquisition premiums	(949)	(452)	(1,030)
Proceeds from issuance of common stock	458	230	0
Dividends paid	(791)	(730)	(721)
Other, net	(14)	(20)	(21)
Net cash provided by financing activities	1,181	928	168
Net change in cash and cash equivalents	101	64	(2)
Cash and cash equivalents at beginning of period	147	83	85
Cash and cash equivalents at end of period	248	147	83
Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized)	(698)	(633)	(616)
Cash received for income taxes, net	53	27	44
Supplemental disclosure of non-cash investing and financing transactions:
Accrued property, plant and equipment additions	421	388	464
Inventory transfers to plant, property and equipment	88	129	63
Operating lease right-of-use assets	1,843	0	0
Allowance for equity funds used during construction	77	108	75
Issuance of common stock for reinvested dividends and equity awards	$ 63	$ 67	$ 31

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions		Dec. 31, 2019	Dec. 31, 2018
Current assets
Cash and cash equivalents		$ 248	$ 147
Accounts receivable, net		837	860
Accrued unbilled revenues		713	755
Inventories		544	548
Regulatory assets		488	464
Derivative instruments		55	87
Prepaid taxes		43	79
Prepayments and other		185	154
Total current assets		3,113	3,094
Property, plant and equipment, net		39,483	36,944
Other assets
Nuclear decommissioning fund and other investments		2,731	2,317
Regulatory assets		2,935	3,326
Derivative instruments		22	34
Operating lease right-of-use assets		1,672	0
Other		492	272
Total other assets		7,852	5,949
Total assets		50,448	45,987
Current liabilities
Current portion of long-term debt		702	406
Short-term debt		595	1,038
Accounts payable		1,294	1,237
Regulatory liabilities	[1]	407	436
Taxes accrued		466	450
Accrued interest		192	174
Dividends payable		212	195
Derivative instruments		38	61
Other		662	463
Total current liabilities		4,568	4,460
Deferred credits and other liabilities
Deferred income taxes		4,509	4,165
Deferred investment tax credits		49	54
Regulatory liabilities	[1]	5,077	5,187
Asset retirement obligations		2,701	2,568
Derivative instruments		175	129
Customer advances		203	199
Pension and employee benefit obligations		785	994
Operating lease liabilities		1,549	0
Other		186	206
Total deferred credits and other liabilities		15,234	13,502
Commitments and contingencies
Capitalization
Long-term debt		17,407	15,803
Common stock — 1,000,000,000 shares authorized of $2.50 par value; 524,539,000 and 514,036,787 shares outstanding at Dec. 31, 2019 and 2018, respectively		1,311	1,285
Additional paid in capital		6,656	6,168
Retained earnings		5,413	4,893
Accumulated other comprehensive loss		(141)	(124)
Total common stockholders’ equity		13,239	12,222
Total liabilities and equity		$ 50,448	$ 45,987
[1]	Revenue subject to refund of $28 million and $29 million for 2019 and 2018, respectively, is included in other current liabilities.

CONSOLIDATED BALANCE SHEETS (Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) - $ / shares	Dec. 31, 2019	Dec. 31, 2018
Statement of Financial Position [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)	524,539,000	514,036,787

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
Balance (in shares) at Dec. 31, 2016		507,223,000
Beginning balance at Dec. 31, 2016	$ 11,021	$ 1,268	$ 5,881	$ 3,982	$ (110)
Increase (Decrease) in Stockholders' Equity
Net income	1,148			1,148
Other comprehensive income	7				7
Dividends declared on common stock	(736)			(736)
Issuances of common stock (in shares)		611,000
Issuances of common stock (value)	5	$ 1	4
Stock repurchased during period (in shares)		(71,000)
Repurchases of common stock (value)	(3)	$ 0	(3)
Share-based compensation	13		16	(3)
Adoption of ASU No. 2018-02	0			22	(22)
Balance (in shares) at Dec. 31, 2017		507,763,000
Ending balance at Dec. 31, 2017	11,455	$ 1,269	5,898	4,413	(125)
Increase (Decrease) in Stockholders' Equity
Net income	1,261			1,261
Other comprehensive income	1				1
Dividends declared on common stock	(780)			(780)
Issuances of common stock (in shares)		6,296,000
Issuances of common stock (value)	270	$ 16	254
Stock repurchased during period (in shares)		(22,000)
Repurchases of common stock (value)	(1)	$ 0	(1)
Share-based compensation	$ 16		17	(1)
Balance (in shares) at Dec. 31, 2018	514,036,787	514,037,000
Ending balance at Dec. 31, 2018	$ 12,222	$ 1,285	6,168	4,893	(124)
Increase (Decrease) in Stockholders' Equity
Net income	1,372			1,372
Other comprehensive income	(17)				(17)
Dividends declared on common stock	(846)			(846)
Issuances of common stock (in shares)		10,508,000
Issuances of common stock (value)	494	$ 26	468
Stock repurchased during period (in shares)		(6,000)
Repurchases of common stock (value)	0	$ 0	0
Share-based compensation	$ 14		20	(6)
Balance (in shares) at Dec. 31, 2019	524,539,000	524,539,000
Ending balance at Dec. 31, 2019	$ 13,239	$ 1,311	$ 6,656	$ 5,413	$ (141)

CONSOLIDATED STATEMENTS OF CO_3

CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS' EQUITY Consolidated Statements of Common Stockholders' Equity - Parenthetical - $ / shares	3 Months Ended								12 Months Ended
	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Statement of Stockholders' Equity [Abstract]
Cash dividends declared per common share (in dollars per share)	$ 0.405	$ 0.405	$ 0.405	$ 0.405	$ 0.380	$ 0.380	$ 0.380	$ 0.380	$ 1.62	$ 1.52	$ 1.44

Summary of Significant Accounti

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2019
Accounting Policies [Abstract]
Summary of Significant Accounting Policies	General — 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 regulated operations include the activities 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 regulated operations are WGI, an interstate natural gas pipeline company, and WYCO, a joint venture with CIG to develop and lease natural gas pipeline, storage and compression facilities. Xcel Energy Inc.’s nonregulated subsidiaries include Eloigne, Capital Services and the newly formed MEC Holdings LLC. 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, Xcel Energy Venture Holdings Inc. 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. All intercompany transactions and balances are eliminated, unless a different treatment is appropriate for rate regulated transactions. 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 certain 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. Xcel Energy’s consolidated financial statements are presented in accordance with GAAP. All of the utility subsidiaries’ underlying accounting records also conform to the FERC uniform system of accounts. Certain amounts in the 2018 and 2017 consolidated financial statements or notes have been reclassified to conform to the 2019 presentation for comparative purposes; however, such reclassifications did not affect net income, total assets, liabilities, equity or cash flows. Xcel Energy has evaluated events occurring after Dec. 31, 2019 up to the date of issuance of these consolidated financial statements. These statements contain all necessary adjustments and disclosures resulting from that evaluation. Use of Estimates — Xcel Energy uses estimates based on the best information available in recording transactions and balances resulting from business operations. Estimates are used on items such 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. Recorded estimates are revised when better information becomes available or actual amounts can be determined. Revisions can affect operating results. Regulatory Accounting — Xcel Energy Inc.’s regulated utility subsidiaries account for 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 other comprehensive income, 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 other comprehensive income, 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 changes in the regulatory environment occur, the 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 results of operations, financial condition and cash flows. See Note 4 for further information. Income Taxes — Xcel Energy accounts for income taxes using the asset and liability method, which requires 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 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 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. Reversal of certain temporary differences are accounted for as current income tax expense 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. 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 regulatory assets and liabilities related to income taxes. 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. 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 expense. Xcel Energy reports interest and penalties related to income taxes within the other income and interest charges in the consolidated statements of income. Xcel Energy Inc. and its subsidiaries file consolidated federal income tax returns as well as consolidated or separate state income tax returns. Federal income taxes paid by Xcel Energy Inc. are allocated to its subsidiaries based on separate company computations. A similar allocation is made for state income taxes paid by Xcel Energy Inc. in connection with consolidated state filings. Xcel Energy Inc. also allocates its own income tax benefits to its direct subsidiaries. See Note 7 for further information. Property, Plant and Equipment and Depreciation in Regulated Operations — 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 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 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. 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 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 3.3 % for 2019, 3.1 % for 2018 and 2017. See Note 3 for further information. AROs — Xcel Energy accounts 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. The 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 consolidated balance sheets as a regulatory liability. See Note 12 for further information. Nuclear Decommissioning — Nuclear decommissioning studies that estimate NSP-Minnesota’s costs of decommissioning its nuclear power plants are performed at least every three years and submitted to the state commissions for approval. For ratemaking purposes, NSP-Minnesota recovers regulator-approved decommissioning costs of its nuclear power plants over each facility’s expected service life, typically based on the triennial decommissioning studies. 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. For financial reporting purposes, NSP-Minnesota accounts for nuclear decommissioning as an ARO. 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 10 and 12 for further information. 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 requires management to make various assumptions and estimates. Certain unrecognized actuarial gains and losses and unrecognized prior service costs or credits are deferred as regulatory assets and liabilities, rather than recorded as other comprehensive income, based on regulatory recovery mechanisms. See Note 11 for further information. 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 are regularly adjusted as estimates are revised and remediation proceeds. If other participating potentially responsible parties exist and acknowledge their potential involvement with a site, costs are estimated and recorded only for Xcel Energy’s expected share of the cost. Future costs of restoring sites are treated as a capitalized cost of plant retirement. The depreciation expense levels recoverable in rates include a provision for removal expenses. Removal costs recovered in rates before the related costs are incurred are classified as a regulatory liability. See Note 12 for further information. Revenue from Contracts with Customers — Performance obligations related to the sale of energy are satisfied as energy is delivered to customers. Xcel Energy recognizes revenue that corresponds to the price of the energy delivered to the customer. The measurement of energy sales to customers is generally based on the reading of their meters, which occurs on a systematic basis throughout the month. At the end of each month, amounts of energy delivered to customers since the date of the last meter reading are estimated, and the corresponding unbilled revenue is recognized. Xcel Energy does not recognize a separate financing component of its collections from customers as contract terms are short-term in nature. Xcel Energy presents its revenues net of any excise or sales taxes or fees. The utility subsidiaries recognize sales to customers on a gross basis in electric revenues and cost of sales. Revenues and charges for short term wholesale sales of excess energy transacted through RTOs are also recorded on a gross basis. Other RTO revenues and charges are recorded on a net basis in cost of sales. See Note 6 for further information. Cash and Cash Equivalents — Xcel Energy considers investments in instruments 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. At both Dec. 31, 2019 and 2018, the allowance for bad debts was $55 million . Inventory — Inventory is recorded at average cost and consisted of the following: (Millions of Dollars) Dec. 31, 2019 Dec. 31, 2018 Inventories Materials and supplies $ 270 $ 271 Fuel 191 170 Natural gas 83 107 Total inventories $ 544 $ 548 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 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, 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 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 10 and 11 for further information. 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. Any derivative instruments not qualifying for the normal purchases and normal sales exception are recorded on the consolidated balance sheets at fair value as derivative instruments. 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. 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. Normal Purchases and Normal Sales — Xcel Energy enters into contracts for purchases and sales of commodities for use in its operations. At inception, contracts are evaluated to determine whether a derivative exists and/or whether an instrument may be exempted from derivative accounting if designated as a normal purchase or normal sale. See Note 10 for further information. Commodity Trading Operations — All applicable gains and losses related to commodity trading activities are shown on a net basis in electric operating revenues in the consolidated statements of income. 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 10 for further information. Other Utility Items 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 rates. Alternative Revenue — Certain rate rider mechanisms (including decoupling and CIP/DSM programs) qualify as alternative revenue programs. These mechanisms arise from costs imposed upon the utility by action of a regulator or legislative body related to an environmental, public safety or other mandate. When certain criteria are met, including expected collection within 24 months , revenue is recognized equal to the revenue requirement, which may include incentives and return on rate base items. Billing amounts are revised periodically for differences between total amount collected and revenue earned, which may increase or decrease the level of revenue collected from customers. Alternative revenues arising from these programs are presented on a gross basis and disclosed separately from revenue from contracts with customers. See Note 6 for further information. Conservation Programs — Costs incurred for DSM and CIP programs are deferred if it is probable future revenue will recover the incurred cost. Revenues recognized for incentive programs for the recovery of lost margins and/or conservation performance incentives are limited to amounts expected to be collected within 24 months from the year they are earned. Regulatory assets are recognized to reflect the amount of costs or earned incentives that have not yet been collected from customers. Emission Allowances — Emission allowances are recorded at cost, including broker commission fees. The inventory accounting model is utilized for all emission allowances and sales of these allowances are included in electric revenues. Nuclear Refueling Outage Costs — Xcel Energy uses a deferral and amortization method for nuclear refueling costs. This method amortizes costs over the period between refueling outages consistent with rate recovery. RECs — Cost of RECs that are utilized for compliance is recorded as electric fuel and purchased power expense. In certain jurisdictions, Xcel Energy reduces recoverable fuel costs for the cost of RECs and records that cost as a regulatory asset when the amount is recoverable in future rates. Sales of RECs are recorded in electric revenues on a gross basis. The cost of these RECs and amounts credited to customers under margin-sharing mechanisms are recorded in electric fuel and purchased power expense. Cost of RECs that are utilized to support commodity trading activities are recorded in a similar manner as the associated commodities and are shown on a net basis in electric operating revenues in the consolidated statements of income.

Accounting Pronouncements

Accounting Pronouncements	12 Months Ended
	Dec. 31, 2019
New Accounting Pronouncements and Changes in Accounting Principles [Abstract]
Accounting Pronouncements	Recently Issued Credit Losses — In 2016, the FASB issued Financial Instruments - Credit Losses, Topic 326 (ASC Topic 326), which changes how entities account for losses on receivables and certain other assets. The guidance requires use of a current expected credit loss model, which may result in earlier recognition of credit losses than under previous accounting standards. ASC Topic 326 is effective for interim and annual periods beginning on or after Dec. 15, 2019 and will be applied using a modified-retrospective approach, with a cumulative-effect adjustment to retained earnings as of Jan. 1, 2020. Xcel Energy expects the impact of adoption of the new standard to include first-time recognition of expected credit losses (i.e., bad debt expense) on unbilled revenues, with the initial allowance established at Jan. 1, 2020 charged to retained earnings. Recognition of this allowance and other impacts of adoption are expected to be immaterial to the consolidated financial statements. Recently Adopted Leases — In 2016, the FASB issued Leases , Topic 842 (ASC Topic 842) , which provides new accounting and disclosure guidance for leasing activities, most significantly requiring that operating leases be recognized on the balance sheet. Xcel Energy adopted the guidance on Jan. 1, 2019 utilizing the package of transition practical expedients provided by the new standard, including carrying forward prior conclusions on whether agreements existing before the adoption date contain leases and whether existing leases are operating or finance leases; ASC Topic 842 refers to capital leases as finance leases. Specifically, for land easement contracts, Xcel Energy has elected the practical expedient provided by ASU No. 2018-01 Leases: Land Easement Practical Expedient for Transition to Topic 842 , and as a result, only those easement contracts entered on or after Jan. 1, 2019 will be evaluated to determine if lease treatment is appropriate. Xcel Energy also utilized the transition practical expedient offered by ASU No. 2018-11 Leases: Targeted Improvements to implement the standard on a prospective basis. As a result, reporting periods in the consolidated financial statements beginning Jan. 1, 2019 reflect the implementation of ASC Topic 842, while prior periods continue to be reported in accordance with Leases, Topic 840 (ASC Topic 840) . Other than first-time recognition of operating leases on its consolidated balance sheet, the implementation of ASC Topic 842 did not have a significant impact on Xcel Energy’s consolidated financial statements. Adoption resulted in recognition of approximately $1.7 billion of operating lease ROU assets and current/noncurrent operating lease liabilities. See Note 12 for leasing disclosures.

Property Plant and Equipment Pr

Property Plant and Equipment Property Plant and Equipment	12 Months Ended
	Dec. 31, 2019
Property, Plant and Equipment [Abstract]
Property, Plant and Equipment Disclosure	Major classes of property, plant and equipment (Millions of Dollars) Dec. 31, 2019 Dec. 31, 2018 Property, plant and equipment Electric plant $ 44,355 $ 41,472 Natural gas plant 6,560 6,210 Common and other property 2,341 2,154 Plant to be retired (a) 259 322 CWIP 2,329 2,091 Total property, plant and equipment 55,844 52,249 Less accumulated depreciation (16,735 ) (15,659 ) Nuclear fuel 2,909 2,771 Less accumulated amortization (2,535 ) (2,417 ) Property, plant and equipment, net $ 39,483 $ 36,944 (a) In 2018, the CPUC approved early retirement of PSCo’s Comanche Units 1 and 2 in approximately 2022 and 2025, respectively. PSCo also expects Craig Unit 1 to be retired early in 2025. Amounts are presented net of accumulated depreciation. Joint Ownership of Generation, Transmission and Gas Facilities The utility subsidiaries’ jointly owned assets as of Dec. 31, 2019 : (Millions of Dollars) Plant in Service Accumulated Depreciation CWIP Percent Owned NSP-Minnesota Electric generation: Sherco Unit 3 $ 603 $ 426 $ 4 59 % Sherco common facilities 145 103 2 80 Sherco substation 5 3 — 59 Electric transmission: CapX2020 972 92 2 51 Grand Meadow 11 3 — 50 Total NSP-Minnesota $ 1,736 $ 627 $ 8 (Millions of Dollars) Plant in Service Accumulated Depreciation CWIP Percent Owned NSP-Wisconsin Electric transmission: La Crosse, WI to Madison, WI $ 187 $ 7 $ — 37 % CapX2020 169 19 — 80 Total NSP-Wisconsin $ 356 $ 26 $ — (Millions of Dollars) Plant in Service Accumulated Depreciation CWIP Percent Owned PSCo Electric generation: Hayden Unit 1 $ 152 $ 81 $ — 76 % Hayden Unit 2 149 71 — 37 Hayden common facilities 41 22 — 53 Craig Units 1 and 2 81 41 — 10 Craig common facilities 39 22 — 7 Comanche Unit 3 887 149 1 67 Comanche common facilities 29 3 — 82 Electric transmission: Transmission and other facilities 174 62 1 Various Gas transmission: Rifle, CO to Avon, CO 22 7 — 60 Gas transmission compressor 9 1 — 50 Total PSCo $ 1,583 $ 459 $ 2 Each company’s share of operating expenses and construction expenditures is included in the applicable utility accounts. Respective owners are responsible for providing their own financing.

Regulatory Assets and Liabiliti

Regulatory Assets and Liabilities	12 Months Ended
	Dec. 31, 2019
Regulatory Assets and Liabilities Disclosure [Abstract]
Regulatory Assets and Liabilities	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. Xcel Energy would be required to recognize the write-off of regulatory assets and liabilities in net income or other comprehensive income if changes in the utility industry no longer allow for the application of regulatory accounting guidance under GAAP. Components of regulatory assets: (Millions of Dollars) See Note(s) Remaining Dec. 31, 2019 Dec. 31, 2018 Regulatory Assets Current Noncurrent Current Noncurrent Pension and retiree medical obligations 11 Various $ 85 $ 1,328 $ 87 $ 1,500 Recoverable deferred taxes on AFUDC recorded in plant Plant lives — 271 — 264 Net AROs (a) 1, 12 Plant lives — 269 — 452 Excess deferred taxes — TCJA 7 Various 39 239 — 296 Depreciation differences One to twelve years 15 140 18 107 Environmental remediation costs 1, 12 Various 36 131 17 155 Benson biomass PPA termination and asset purchase Ten years 9 73 10 86 Contract valuation adjustments (b) 1, 10 Term of related contract 20 62 17 77 Purchased power contract costs Term of related contract 5 61 4 63 Laurentian biomass PPA termination Five years 19 54 18 73 PI extended power uprate Sixteen years 3 53 3 56 Losses on reacquired debt Term of related debt 4 41 4 44 State commission adjustments Plant lives 1 31 1 29 Property tax Various 2 30 14 10 Conservation programs (c) 1 One to two years 27 26 42 28 Nuclear refueling outage costs 1 One to two years 43 17 37 14 Sales true-up and revenue decoupling One to two years 54 16 38 7 Renewable resources and environmental initiatives One to two years 72 10 39 9 Gas pipeline inspection and remediation costs One to two years 26 8 28 3 Deferred purchased natural gas and electric energy costs One to three years 6 6 57 13 Other Various 22 69 30 40 Total regulatory assets $ 488 $ 2,935 $ 464 $ 3,326 (a) Includes amounts recorded for future recovery of AROs, less amounts recovered through nuclear decommissioning accruals and gains from decommissioning investments. (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. Components of regulatory liabilities: (Millions of Dollars) See Note(s) Remaining Dec. 31, 2019 Dec. 31, 2018 Regulatory Liabilities Current Noncurrent Current Noncurrent Deferred income tax adjustments and TCJA refunds (a) 7 Various $ 75 $ 3,523 $ 157 $ 3,715 Plant removal costs 1, 12 Plant lives — 1,217 — 1,175 Effects of regulation on employee benefit costs (b) Various — 196 — 137 Renewable resources and environmental initiatives Various — 45 9 54 ITC deferrals (c) 1 Various — 38 — 40 Deferred electric, natural gas and steam production costs Less than one year 138 — 102 — Contract valuation adjustments (d) 1, 10 Less than one year 19 — 26 — Conservation programs (e) 1 Less than one year 37 — 36 — DOE settlement Less than one year 37 — 19 — Other Various 101 58 87 66 Total regulatory liabilities (f) $ 407 $ 5,077 $ 436 $ 5,187 (a) Includes the revaluation of recoverable/regulated plant ADIT and revaluation impact of non-plant ADIT due to the TCJA. (b) Includes regulatory amortization and certain 2018 TCJA benefits approved by the CPUC to offset the PSCo prepaid pension asset. (c) Includes impact of lower federal tax rate due to the TCJA. (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. (f) Revenue subject to refund of $28 million and $29 million for 2019 and 2018, respectively, is included in other current liabilities. At Dec. 31, 2019 and 2018 , Xcel Energy’s regulatory assets not earning a return primarily included the unfunded portion of pension and retiree medical obligations, net AROs and Laurentian biomass PPA termination costs/obligations. In addition, regulatory assets included $544 million and $512 million at Dec. 31, 2019 and 2018, respectively, of past expenditures not earning a return. Amounts primarily related to funded pension obligations, sales true-up and revenue decoupling, purchased natural gas and electric energy costs, various renewable resources and certain environmental initiatives.

Borrowings and Other Financing

Borrowings and Other Financing Instruments Borrowings and Other Financing Instruments	12 Months Ended
	Dec. 31, 2019
Debt Disclosure [Abstract]
Borrowings and Other Financing Instruments	Short-Term Borrowings Short-Term Debt — Xcel Energy meets its short-term liquidity requirements primarily through the issuance of commercial paper and borrowings under their credit facilities and term loan agreements. Commercial paper and term loan borrowings outstanding: (Millions of Dollars, Except Interest Rates) Three Months Ended Dec. 31, 2019 Year Ended Dec. 31 2019 2018 2017 Borrowing limit $ 3,600 $ 3,600 $ 3,250 $ 3,250 Amount outstanding at period end 595 595 1,038 814 Average amount outstanding 663 1,115 788 644 Maximum amount outstanding 945 1,780 1,349 1,247 Weighted average interest rate, computed on a daily basis 2.40 % 2.72 % 2.34 % 1.35 % Weighted average interest rate at end of period 2.34 2.34 2.97 1.90 Term Loan Agreement — In December 2019, Xcel Energy Inc. entered into a $500 million 364 -Day Term Loan Agreement to pay down borrowings and terminate the expiring $500 million term loan made to Xcel Energy under the 364-Day Term Loan Agreement dated as of Dec. 4, 2018. The loan is unsecured and matures Dec. 1, 2020. Xcel Energy has an option to request an extension through Nov. 30, 2021. Term loan includes one financial covenant, requiring Xcel Energy’s consolidated funded debt to total capitalization ratio to be less than or equal to 65 percent. Interest is at a rate equal to either the Eurodollar rate, plus 50.0 basis points, or an alternate base rate. Term loan borrowings as of Dec. 31, 2019: (Millions of Dollars) Limit Amount Used Available Xcel Energy Inc. $ 500 $ 500 $ — Bilateral Credit Agreement — In March 2019, NSP-Minnesota entered into a one-year uncommitted bilateral credit agreement. The agreement is limited in use to support letters of credit. As of Dec. 31, 2019 , outstanding letters of credit under the Bilateral Credit Agreement were as follows: (Millions of Dollars) Limit Amount Used Available NSP-Minnesota $ 75 $ 22 $ 53 Letters of Credit — Xcel Energy uses letters of credit, typically with terms of one year , to provide financial guarantees for certain operating obligations. As of Dec. 31, 2019 and 2018 , there were $20 million and $49 million of letters of credit outstanding under the credit facilities. Amounts approximate their fair value. Credit Facilities — In order to use 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. Amended Credit Agreements — In June 2019, Xcel Energy Inc., NSP-Minnesota, NSP-Wisconsin, PSCo and SPS entered into amended five-year credit agreements with a syndicate of banks. The total borrowing limit under the amended credit agreements was increased to $3.1 billion , with the following changes: • Maturity extended from June 2021 to June 2024; • Borrowing limit for Xcel Energy was increased from $1.0 billion to $1.25 billion ; • Borrowing limit for SPS was increased from $400 million to $500 million ; and • Added swingline subfacility for Xcel Energy up to $75 million Features of the credit facilities: Debt-to-Total Capitalization Ratio (a) Amount Facility May Be Increased (millions) Additional Periods for Which a One-Year Extension May Be Requested (b) 2019 2018 Xcel Energy Inc. (c) 58 % 58 % $ 200 2 NSP-Wisconsin 48 48 N/A 1 NSP-Minnesota 48 48 100 2 SPS 46 46 50 2 PSCo 44 46 100 2 (a) Each credit facility has a financial covenant requiring that the debt-to-total capitalization ratio be less than or equal to 65% . (b) All extension requests are subject to majority bank group approval. (c) The Xcel Energy Inc. credit facility has a cross-default provision that 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% of Xcel Energy’s consolidated total assets) default on indebtedness in an aggregate principal amount exceeding $75 million . If Xcel Energy Inc. or 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. As of Dec. 31, 2019, Xcel Energy Inc. and its subsidiaries were in compliance with all financial covenants. Xcel Energy Inc. and its utility subsidiaries had the following committed credit facilities available as of Dec. 31, 2019 : (Millions of Dollars) Credit Facility (a) Drawn (b) Available Xcel Energy Inc. $ 1,250 $ — $ 1,250 PSCo 700 9 691 NSP-Minnesota 500 2 498 SPS 500 40 460 NSP-Wisconsin 150 65 85 Total $ 3,100 $ 116 $ 2,984 (a) These credit facilities mature in June 2024 . (b) Includes outstanding commercial paper and letters of credit. All credit facility bank borrowings, outstanding letters of credit and outstanding commercial paper reduce the available capacity under the credit facilities. Xcel Energy Inc. and its subsidiaries had no direct advances on facilities outstanding as of Dec. 31, 2019 and 2018 . Long-Term Borrowings and Other Financing Instruments Generally, all 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 for refinanced debt are deferred and amortized over the life of the new issuance. Long term debt obligations for Xcel Energy Inc. and its utility subsidiaries as of Dec. 31 (Millions of Dollars): Xcel Energy Inc. Financing Instrument Interest Rate Maturity Date 2019 2018 Unsecured senior notes (d) 4.70 % May 15, 2020 $ — $ 550 Unsecured senior notes 2.40 March 15, 2021 400 400 Unsecured senior notes 2.60 March 15, 2022 300 300 Unsecured senior notes 3.30 June 1, 2025 250 250 Unsecured senior notes 3.30 June 1, 2025 350 350 Unsecured senior notes 3.35 Dec. 1, 2026 500 500 Unsecured senior notes (a) 4.00 June 15, 2028 130 — Unsecured senior notes (b) 4.00 June 15, 2028 500 500 Unsecured senior notes (a) 2.60 Dec. 1, 2029 500 — Unsecured senior notes 6.50 July 1, 2036 300 300 Unsecured senior notes 4.80 Sept. 15, 2041 250 250 Unsecured senior notes (a) 3.50 Dec. 1, 2049 500 — Elimination of PSCo capital lease obligation with affiliates (c) — (60 ) Unamortized discount (5 ) (5 ) Unamortized debt issuance cost (28 ) (21 ) Current maturities (capital lease obligation) (c) — 2 Total long-term debt $ 3,947 $ 3,316 (a) 2019 financing. (b) 2018 financing. (c) Xcel Energy adopted ASC 842 on Jan. 1, 2019, which refers to capital leases as finance leases. Under ASC 842, the present value of future finance lease payments is included in other current liabilities and other noncurrent liabilities rather than debt. (d) Note was redeemed on Dec. 23, 2019. NSP-Minnesota Financing Instrument Interest Rate Maturity Date 2019 2018 First mortgage bonds 2.20 % Aug. 15, 2020 $ 300 $ 300 First mortgage bonds 2.15 Aug. 15, 2022 300 300 First mortgage bonds 2.60 May 15, 2023 400 400 First mortgage bonds 7.13 July 1, 2025 250 250 First mortgage bonds 6.50 March 1, 2028 150 150 First mortgage bonds 5.25 July 15, 2035 250 250 First mortgage bonds 6.25 June 1, 2036 400 400 First mortgage bonds 6.20 July 1, 2037 350 350 First mortgage bonds 5.35 Nov. 1, 2039 300 300 First mortgage bonds 4.85 Aug. 15, 2040 250 250 First mortgage bonds 3.40 Aug. 15, 2042 500 500 First mortgage bonds 4.13 May 15, 2044 300 300 First mortgage bonds 4.00 Aug. 15, 2045 300 300 First mortgage bonds 3.60 May 15, 2046 350 350 First mortgage bonds 3.60 Sept. 15, 2047 600 600 First mortgage bonds (a) 2.90 March 1, 2050 600 — Unamortized discount (31 ) (21 ) Unamortized debt issuance cost (48 ) (42 ) Current maturities (300 ) — Total long-term debt $ 5,221 $ 4,937 (a) 2019 financing. NSP-Wisconsin Financing Instrument Interest Rate Maturity Date 2019 2018 City of La Crosse resource recovery bond 6.00 % Nov 1, 2021 $ 19 $ 19 First mortgage bonds 3.30 June 15, 2024 100 100 First mortgage bonds 3.30 June 15, 2024 100 100 First mortgage bonds 6.38 Sept. 1, 2038 200 200 First mortgage bonds 3.70 Oct. 1, 2042 100 100 First mortgage bonds 3.75 Dec. 1, 2047 100 100 First mortgage bonds (a) 4.20 Sept. 1, 2048 200 200 Unamortized discount (3 ) (3 ) Unamortized debt issuance cost (8 ) (9 ) Total long-term debt $ 808 $ 807 (a) 2018 financing. PSCo Financing Instrument Interest Rate Maturity Date 2019 2018 First mortgage bonds (d) 5.13 % June 1, 2019 $ — $ 400 First mortgage bonds 3.20 Nov. 15, 2020 400 400 First mortgage bonds 2.25 Sept. 15, 2022 300 300 First mortgage bonds 2.50 March 15, 2023 250 250 First mortgage bonds 2.90 May 15, 2025 250 250 First mortgage bonds (b) 3.70 June 15, 2028 350 350 First mortgage bonds 6.25 Sept. 1, 2037 350 350 First mortgage bonds 6.50 Aug. 1, 2038 300 300 First mortgage bonds 4.75 Aug. 15, 2041 250 250 First mortgage bonds 3.60 Sept. 15, 2042 500 500 First mortgage bonds 3.95 March 15, 2043 250 250 First mortgage bonds 4.30 March 15, 2044 300 300 First mortgage bonds 3.55 June 15, 2046 250 250 First mortgage bonds 3.80 June 15, 2047 400 400 First mortgage bonds (b) 4.10 June 15, 2048 350 350 First mortgage bonds (a) 4.05 Sept. 15, 2049 400 — First mortgage bonds (a) 3.20 March 1, 2050 550 — Capital lease obligations (c) 11.20 - 14.30 2025 - 2060 — 145 Unamortized discount (24 ) (14 ) Unamortized debt issuance cost (41 ) (33 ) Current maturities (400 ) (406 ) Total long-term debt $ 4,985 $ 4,592 (a) 2019 financing. (b) 2018 financing. (c) PSCo adopted ASC 842 on Jan. 1, 2019, which refers to capital leases as finance leases. Under ASC 842, the present value of future finance lease payments is included in other current liabilities and other noncurrent liabilities rather than debt. (d) Bond was redeemed on March 29, 2019. SPS Financing Instrument Interest Rate Maturity Date 2019 2018 First mortgage bonds 3.30 % June 15, 2024 $ 150 $ 150 First mortgage bonds 3.30 June 15, 2024 200 200 Unsecured senior notes 6.00 Oct. 1, 2033 100 100 Unsecured senior notes 6.00 Oct. 1, 2036 250 250 First mortgage bonds 4.50 Aug. 15, 2041 200 200 First mortgage bonds 4.50 Aug. 15, 2041 100 100 First mortgage bonds 4.50 Aug. 15, 2041 100 100 First mortgage bonds 3.40 Aug. 15, 2046 300 300 First mortgage bonds 3.70 Aug. 15, 2047 450 450 First mortgage bonds (b) 4.40 Nov. 15, 2048 300 300 First mortgage bonds (a) 3.75 June 15, 2049 300 — Unamortized discount (7 ) (4 ) Unamortized debt issuance cost (23 ) (20 ) Total long-term debt $ 2,420 $ 2,126 (a) 2019 financing. (b) 2018 financing. Other Subsidiaries Financing Instrument Interest Rate Maturity Date 2019 2018 Various Eloigne affordable housing project notes 0.00% - 6.90% 2020 — 2052 $ 28 $ 26 Current maturities (2 ) (1 ) Total long-term debt $ 26 $ 25 Maturities of long-term debt: (Millions of Dollars) 2020 $ 702 2021 421 2022 900 2023 650 2024 552 Deferred Financing Costs — Deferred financing costs of approximately $ 148 million and $126 million , net of amortization, are presented as a deduction from the carrying amount of long-term debt as of Dec. 31, 2019 and 2018 , respectively. Forward Equity Agreements — In November 2018, Xcel Energy Inc. entered into forward equity agreements in connection with a completed $459 million public offering of 9.4 million shares of Xcel Energy common stock. In August 2019, Xcel Energy settled the forward equity agreements by physically delivering 9.4 million shares of common equity for cash proceeds of $453 million . In November 2019, Xcel Energy Inc. entered into forward equity agreements in connection with a completed $743 million public offering of 11.8 million shares of Xcel Energy common stock. The initial forward agreement was for 10.3 million shares with an additional agreement for 1.5 million shares exercised at the option of the banking counterparty. At Dec. 31, 2019, the forward agreements could have been settled with physical delivery of 11.8 million common shares to the banking counterparty in exchange for cash of $739 million . The forward instruments could also have been settled at Dec. 31, 2019 with delivery of approximately $6 million of cash or approximately 0.1 million shares of common stock to the counterparty, if Xcel Energy unilaterally elected net cash or net share settlement, respectively. The forward price used to determine amounts due at settlement is calculated based on the November 2019 public offering price for Xcel Energy’s common stock of $62.69 , increased for the overnight bank funding rate, less a spread of 0.75% and less expected dividends on Xcel Energy’s common stock during the period the instruments are outstanding. Xcel Energy may settle the agreements at any time up to the maturity date of Dec. 31, 2020 . Depending on settlement timing, cash proceeds are expected to be approximately $730 million to $740 million . Forward equity instruments were recognized within stockholders’ equity at fair value at execution of the agreements and will not be subsequently adjusted until settlement. Other Equity — Xcel Energy issued $39 million of equity annually through the DRIP program during the years ended Dec. 31, 2019 and 2018, respectively. Program allows stockholders to elect dividend reinvestment in Xcel Energy common stock through a non-cash transaction. See Note 8 for equity items related to share based compensation. Capital Stock — Preferred stock authorized/outstanding: Preferred Stock Authorized (Shares) Par Value of Preferred Stock Preferred Stock Outstanding (Shares) 2019 and 2018 Xcel Energy Inc. 7,000,000 $ 100 — PSCo 10,000,000 0.01 — SPS 10,000,000 1.00 — Xcel Energy Inc. had the following common stock authorized/outstanding: Common Stock Authorized (Shares) Par Value of Common Stock Common Stock Outstanding (Shares) as of Dec. 31, 2019 Common Stock Outstanding (Shares) as of Dec. 31, 2018 1,000,000,000 $ 2.50 524,539,000 514,036,787 Dividend and Other Capital-Related Restrictions — Xcel Energy depends on its subsidiaries to pay dividends. Xcel Energy Inc.’s utility subsidiaries’ dividends are subject to the FERC’s jurisdiction, which prohibits the payment of dividends out of capital accounts. Dividends are solely to be paid from retained earnings. Certain covenants also require Xcel Energy Inc. to be current on interest payments prior to dividend disbursements. State regulatory commissions impose dividend limitations for NSP-Minnesota, NSP-Wisconsin and SPS, which are more restrictive than those imposed by the FERC. Requirements and actuals as of Dec. 31, 2019: Equity to Total Capitalization Ratio Required Range Equity to Total Capitalization Ratio Actual Low High 2019 NSP-Minnesota 47.1 % 57.5 % 52.3 % NSP-Wisconsin 51.5 N/A 51.8 SPS (a) 45.0 55.0 54.4 (a) Excludes short-term debt. (Amounts in Millions) Unrestricted Retained Earnings Total Capitalization Limit on Total Capitalization NSP-Minnesota $ 1,147 $ 11,634 $ 12,700 NSP-Wisconsin (a) 12 1,827 N/A SPS (b) 535 5,304 N/A (a) Cannot pay annual dividends in excess of approximately $55 million if its average equity-to-total capitalization ratio falls below the commission authorized level. (b) May not pay a dividend that would cause a loss of its investment grade bond rating. Issuance of securities by Xcel Energy Inc. generally is not subject to regulatory approval. However, utility financings and intra-system financings are subject to the jurisdiction of state regulatory commissions and/or the FERC. Xcel Energy may seek additional authorization as necessary. Amounts authorized to issue as of Dec. 31, 2019 : (Millions of Dollars) Long-Term Debt Short-Term Debt NSP-Minnesota 52.93% of total capitalization (a) $ 1,905 (a) NSP-Wisconsin $ — (b) 150 SPS — (c) 600 PSCo 150 800 (a) NSP-Minnesota has authorization to issue long-term securities provided the equity-to-total capitalization remains within the required range, and to issue short-term debt provided it does not exceed 15% of total capitalization. (b) NSP-Wisconsin filed for additional long-term debt authorization in December 2019. (c) SPS filed for additional long-term debt authorization in February 2020.

Revenues

Revenues	12 Months Ended
	Dec. 31, 2019
Revenue from Contract with Customer [Abstract]
Revenues	Revenue is classified by the type of goods/services rendered and market/customer type. Xcel Energy’s operating revenues consisted of the following: Year Ended Dec. 31, 2019 (Millions of Dollars) Electric Natural Gas All Other Total Major revenue types Revenue from contracts with customers: Residential $ 2,877 $ 1,127 $ 41 $ 4,045 C&I 4,844 567 29 5,440 Other 130 — 4 134 Total retail 7,851 1,694 74 9,619 Wholesale 737 — — 737 Transmission 507 — — 507 Other 49 120 — 169 Total revenue from contracts with customers 9,144 1,814 74 11,032 Alternative revenue and other 431 54 12 497 Total revenues $ 9,575 $ 1,868 $ 86 $ 11,529 Year Ended Dec. 31, 2018 (Millions of Dollars) Electric Natural Gas All Other Total Major revenue types Revenue from contracts with customers: Residential $ 2,919 $ 988 $ 38 $ 3,945 C&I 4,874 524 25 5,423 Other 134 — 6 140 Total retail 7,927 1,512 69 9,508 Wholesale 791 — — 791 Transmission 523 — — 523 Other 98 100 — 198 Total revenue from contracts with customers 9,339 1,612 69 11,020 Alternative revenue and other 380 127 10 517 Total revenues $ 9,719 $ 1,739 $ 79 $ 11,537

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2019
Income Tax Disclosure [Abstract]
Income Taxes	Federal Tax Reform — In 2017, the TCJA was signed into law. The key provisions impacting Xcel Energy, generally beginning in 2018, included: • Corporate federal tax rate reduction from 35% to 21% ; • 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% of taxable income); • Repeal of the section 199 manufacturing deduction; and • Reduced deductions for meals and entertainment as well as state and local lobbying. Reductions in deferred tax assets and liabilities due to a decrease in corporate federal tax rates typically result in a net tax benefit. However, the impacts are primarily recognized as regulatory liabilities refundable to utility customers as a result of IRS requirements and past regulatory treatment. Estimated impacts of the new tax law in December 2017 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% 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 accounted for the state tax impacts of federal tax reform based on 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. Federal Audit — Statute of limitations applicable to Xcel Energy’s consolidated federal income tax returns: Tax Year(s) Expiration 2009 - 2013 June 2020 2014 - 2016 September 2020 In 2015, the IRS commenced an examination of tax years 2012 and 2013 . In 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. Xcel Energy filed a protest with the IRS. As of Dec. 31, 2019, the case has been forwarded to the Office of Appeals and 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 unknown. In 2018, the IRS began an audit of tax years 2014 - 2016 . As of Dec. 31, 2019, no adjustments have been proposed. State Audits — Xcel Energy files consolidated state tax returns based on income in its major operating jurisdictions and various other state income-based tax returns. As of Dec. 31, 2019 , Xcel Energy’s earliest open tax years (subject to examination by state taxing authorities in its major operating jurisdictions) were as follows: State Year Colorado 2009 Minnesota 2009 Texas 2009 Wisconsin 2014 • In 2018, Wisconsin began an audit of tax years 2014 - 2016 . As of Dec. 31, 2019, no material adjustments have been proposed. • Xcel Energy had no other state income tax audits in progress for its major operating jurisdictions as of Dec. 31, 2019. Unrecognized Tax Benefits — 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 to the taxing authority to an earlier period. Unrecognized tax benefits - permanent vs. temporary: (Millions of Dollars) Dec. 31, 2019 Dec. 31, 2018 Unrecognized tax benefit — Permanent tax positions $ 35 $ 28 Unrecognized tax benefit — Temporary tax positions 9 9 Total unrecognized tax benefit $ 44 $ 37 Changes in unrecognized tax benefits: (Millions of Dollars) 2019 2018 2017 Balance at Jan. 1 $ 37 $ 39 $ 134 Additions based on tax positions related to the current year 10 9 6 Reductions based on tax positions related to the current year (4 ) (4 ) (4 ) Additions for tax positions of prior years 1 2 15 Reductions for tax positions of prior years — (4 ) (105 ) Settlements with taxing authorities — (5 ) (7 ) Balance at Dec. 31 $ 44 $ 37 $ 39 Unrecognized tax benefits were reduced by tax benefits associated with NOL and tax credit carryforwards: (Millions of Dollars) Dec. 31, 2019 Dec. 31, 2018 NOL and tax credit carryforwards $ (40 ) $ (35 ) Net deferred tax liability associated with the unrecognized tax benefit amounts and related NOLs and tax credits carryforwards were $29 million and $24 million at Dec. 31, 2019 and Dec. 31, 2018 , respectively. As the IRS Appeals and federal and state audits progress and other state audits resume, it is reasonably possible that the amount of unrecognized tax benefit could decrease up to approximately $28 million in the next 12 months. Payable for interest related to unrecognized tax benefits is partially offset by the interest benefit associated with NOL and tax credit carryforwards. No amounts were payable for interest related to unrecognized tax benefits as of Dec. 31, 2019, 2018 or 2017. No interest income related to unrecognized tax benefits was recorded in 2019 or 2018, and $3 million was recorded in 2017. No amounts were accrued for penalties related to unrecognized tax benefits as of Dec. 31, 2019 , 2018 or 2017 . Other Income Tax Matters — NOL amounts represent the tax loss that is carried forward and tax credits represent the deferred tax asset. NOL and tax credit carryforwards as of Dec. 31: (Millions of Dollars) 2019 2018 Federal tax credit carryforwards $ 639 $ 553 Valuation allowances for federal credit carryforwards — (5 ) State NOL carryforwards 937 1,104 Valuation allowances for state NOL carryforwards (19 ) (50 ) State tax credit carryforwards, net of federal detriment (a) 89 89 Valuation allowances for state credit carryforwards, net of federal benefit (b) (66 ) (69 ) (a) State tax credit carryforwards are net of federal detriment of $24 million as of Dec. 31, 2019 and 2018. (b) Valuation allowances for state tax credit carryforwards were net of federal benefit of $17 million and $18 million as of Dec. 31, 2019 and 2018, respectively. Federal carryforward periods expire between 2023 and 2039 and state carryforward periods expire between 2020 and 2036 . 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. Effective income tax rate for years ended Dec. 31: 2019 2018 (a) 2017 (a) Federal statutory rate 21.0 % 21.0 % 35.0 % State income tax on pretax income, net of federal tax effect 4.9 5.0 4.1 Increases (decreases) in tax from: Wind PTCs (9.4 ) (5.2 ) (4.7 ) Plant regulatory differences (b) (5.8 ) (6.2 ) (0.8 ) Other tax credits, net of NOL & tax credit allowances (1.7 ) (1.7 ) (1.0 ) Change in unrecognized tax benefits 0.5 0.4 (0.6 ) Tax reform — — 1.4 Other, net (1.0 ) (0.7 ) (1.3 ) Effective income tax rate 8.5 % 12.6 % 32.1 % (a) Prior periods have been reclassified to conform to current year presentation. (b) Regulatory differences for income tax primarily relate to the credit of excess deferred taxes to customers through the average rate assumption method. Income tax benefits associated with the credit of excess deferred credits are offset by corresponding revenue reductions and additional prepaid pension asset amortization. Components of income tax expense for years ended Dec. 31: (Millions of Dollars) 2019 2018 2017 Current federal tax (benefit) expense $ (16 ) $ (34 ) $ 1 Current state tax expense (benefit) 4 8 (11 ) Current change in unrecognized tax expense (benefit) 2 (6 ) (83 ) Deferred federal tax expense 55 122 460 Deferred state tax expense 83 85 107 Deferred change in unrecognized tax expense 5 11 73 Deferred ITCs (5 ) (5 ) (5 ) Total income tax expense $ 128 $ 181 $ 542 Components of deferred income tax expense as of Dec. 31: (Millions of Dollars) 2019 2018 2017 Deferred tax expense (benefit) excluding items below $ 344 $ 320 $ (2,939 ) Amortization and adjustments to deferred income taxes on income tax regulatory assets and liabilities (206 ) (102 ) 3,583 Tax benefit (expense) allocated to other comprehensive income, net of adoption of ASU No. 2018-02, and other 5 — (4 ) Deferred tax expense $ 143 $ 218 $ 640 Components of net deferred tax liability as of Dec. 31: (Millions of Dollars) 2019 2018 (a) Deferred tax liabilities: Differences between book and tax bases of property $ 5,474 $ 5,082 Operating lease assets 449 — Regulatory assets 598 599 Pension expense 173 178 Other 70 60 Total deferred tax liabilities $ 6,764 $ 5,919 Deferred tax assets: Regulatory liabilities $ 847 $ 879 Operating lease liabilities 449 — Tax credit carryforward 727 642 NOL carryforward 38 51 NOL and tax credit valuation allowances (67 ) (79 ) Other employee benefits 128 124 Deferred ITCs 14 16 Rate refund 26 60 Other 93 61 Total deferred tax assets $ 2,255 $ 1,754 Net deferred tax liability $ 4,509 $ 4,165 (a) Prior periods have been reclassified to conform to current year presentation.

Share-Based Compensation

Share-Based Compensation	12 Months Ended
	Dec. 31, 2019
Share-based Payment Arrangement [Abstract]
Share-Based Compensation	Incentive Plans Including Share-Based Compensation — Xcel Energy has two incentive plans which include share-based payment elements. Plans and authorized equity shares for awards: • Omnibus Incentive Plan - 7.0 million shares; and • Executive Annual Incentive Award Plan - 1.2 million shares. Restricted Stock — The Executive Annual Incentive Award Plan and Omnibus Incentive Plan allow certain employees to elect to receive shares of common or restricted stock. Restricted stock is treated as an equity award and vests and settles in equal annual installments over a three -year period. Restricted stock has a fair value equal to the market trading price of Xcel Energy stock at the grant date. Shares of restricted stock granted at Dec. 31: (Shares in Thousands) 2019 2018 2017 Granted shares 13 18 15 Grant date fair value $ 53.46 $ 44.68 $ 42.00 Changes in nonvested restricted stock: (Shares in Thousands) Shares Weighted Average Nonvested restricted stock at Jan. 1, 2019 36 $ 44.29 Granted 13 53.46 Forfeited — — Vested (19 ) 41.60 Dividend equivalents 1 57.09 Nonvested restricted stock at Dec. 31, 2019 31 50.15 Other Equity Awards — Xcel Energy‘s Board of Directors has granted equity awards under the Omnibus Incentive Plan, which includes various vesting conditions and performance goals. At the end of the restricted period, such grants will be awarded if vesting conditions and/or performance goals are met. Certain employees are granted equity awards with a portion subject only to service conditions, and the other portion subject to performance conditions. A total of 0.3 million time-based equity shares subject only to service conditions were granted annually in 2019, 2018 and 2017, respectively. The performance conditions for a portion of the awards granted from 2017 to 2019 are based on relative TSR and environmental goals. Equity awards with performance conditions will be settled or forfeited after three years , with payouts ranging from zero to 200 percent depending on achievement. Equity award units granted to employees (excluding restricted stock): (Units in Thousands) 2019 2018 2017 Granted units 483 500 503 Weighted average grant date fair value $ 49.67 $ 47.60 $ 41.02 Equity awards vested: (Units in Thousands) 2019 2018 2017 Vested Units 464 475 467 Total Fair Value $ 29,432 $ 23,393 $ 22,459 Changes in the nonvested portion of equity award units: (Units in Thousands) Units Weighted Average Nonvested Units at Jan. 1, 2019 939 $ 44.30 Granted 483 49.67 Forfeited (116 ) 50.19 Vested (464 ) 41.09 Dividend equivalents 38 45.22 Nonvested Units at Dec. 31, 2019 880 48.20 Stock Equivalent Units — Non-employee members of Xcel Energy‘s Board of Directors may elect to receive their annual equity grant as stock equivalent units in lieu of common stock. Each unit’s value is equal to one share of common stock. The annual equity grant is vested as of the date of each member’s election to the Board of Directors; there is no further service or other condition. Directors may also elect to receive their cash fees as stock equivalent units in lieu of cash. Stock equivalent units are payable as a distribution of common stock upon a director’s termination of service. Stock equivalent units granted: (Units in Thousands) 2019 2018 2017 Granted units 29 36 51 Weighted average grant date fair value $ 58.44 $ 45.44 $ 46.05 Changes in stock equivalent units: (Units in Thousands) Units Weighted Average Stock equivalent units at Jan. 1, 2019 688 $ 30.93 Granted 29 58.44 Units distributed (11 ) 32.56 Dividend equivalents 19 57.28 Stock equivalent units at Dec. 31, 2019 725 32.72 TSR Liability Awards — Xcel Energy Inc.’s Board of Directors has granted TSR liability awards under the Omnibus Incentive Plan. This plan allows Xcel Energy to attach various performance goals to the awards granted. The liability awards have been historically dependent on relative TSR measured over a three -year period. Xcel Energy Inc.’s TSR is compared to a peer group of 20 other utility members. Potential payouts of the awards range from zero to 200% . TSR liability awards granted: (In Thousands) 2019 2018 2017 Awards granted 225 239 240 TSR liability awards settled: (In Thousands) 2019 2018 2017 Awards settled 466 482 454 Settlement amount (cash, common stock and deferred amounts) $ 24,930 $ 21,534 $ 19,083 TSR liability awards of $21 million were settled in cash in 2019. Share-Based Compensation Expense — Other than for restricted stock, vesting of employee equity awards is typically predicated on the achievement of a TSR or environmental measures target. Additionally, approximately 0.3 million of equity award units were granted annually in 2017 - 2019, with vesting subject only to service conditions of three years. Generally, these instruments are considered to be equity awards as the award settlement determination (shares or cash) is made by Xcel Energy, not the participants. In addition, these awards have not been previously settled in cash and Xcel Energy plans to continue electing share settlement. Grant date fair value of equity awards is expensed over the service period. 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. Compensation costs related to share-based awards: (Millions of Dollars) 2019 2018 2017 Compensation cost for share-based awards (a) $ 58 $ 45 $ 57 Tax benefit recognized in income 15 12 22 (a) Compensation costs for share-based payment are included in O&M expense. There was approximately $40 million in 2019 and $38 million in 2018 of total unrecognized compensation cost related to nonvested share-based compensation awards. Xcel Energy expects to recognize the unrecognized amount over a weighted average period of 1.6 years .

Earnings Per Share

Earnings Per Share	12 Months Ended
	Dec. 31, 2019
Earnings Per Share [Abstract]
Earnings Per Share	Basic EPS was computed by dividing the earnings available to common shareholders by the weighted average number of common shares outstanding during the period. Diluted EPS was computed by dividing the earnings available to 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 diluted EPS is calculated using the treasury stock method. Common Stock Equivalents — Xcel Energy Inc. has common stock equivalents related to forward equity agreements and certain equity awards in share-based compensation arrangements. Common stock equivalents include commitments to issue common stock related to time-based equity compensation awards. Stock equivalent units granted to Xcel Energy’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. Restricted stock issued to employees under the 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; and • Liability awards subject to a performance condition; any portions settled in shares are included in common shares outstanding upon settlement. Diluted common shares outstanding included common stock equivalents of 1.3 million , 0.5 million and 0.6 million shares for 2019, 2018 and 2017.

Fair Value of Financial Assets

Fair Value of Financial Assets and Liabilities	12 Months Ended
	Dec. 31, 2019
Fair Value Disclosures [Abstract]
Fair Value of Financial Assets and Liabilities	Fair Value Measurements Accounting guidance for fair value measurements and disclosures provides a single definition of fair value and requires 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. • 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; and • 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: 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. The investments in commingled funds may be redeemed for NAV with proper notice. Private equity commingled fund 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 commingled funds investments may be redeemed with proper notice, however, withdrawals 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 — Fair values of interest rate derivatives are based on broker quotes that utilize current market interest rate forecasts. Commodity derivatives — 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 certain 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 immaterial to the consolidated financial statements. Non-Derivative Fair Value Measurements Nuclear Decommissioning Fund The NRC requires NSP-Minnesota to maintain a portfolio of investments to fund the costs of decommissioning its nuclear generating plants. Assets of the nuclear decommissioning fund are legally restricted for the purpose of decommissioning these facilities. The fund contains cash equivalents, debt securities, equity securities and other investments. 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 over the lives of the nuclear plants, assuming rate recovery of all costs. 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 are deferred as a component of the regulatory asset. Unrealized gains for the nuclear decommissioning fund were $706 million and $450 million as of Dec. 31, 2019 and 2018 , respectively, and unrealized losses were $6 million and $45 million as of Dec. 31, 2019 and 2018 , respectively. Non-derivative instruments with recurring fair value measurements: Dec. 31, 2019 Fair Value (Millions of Dollars) Cost Level 1 Level 2 Level 3 NAV Total Nuclear decommissioning fund (a) Cash equivalents $ 33 $ 33 $ — $ — $ — $ 33 Commingled funds 733 — — — 935 935 Debt securities 489 — 495 13 — 508 Equity securities 485 962 2 — — 964 Total $ 1,740 $ 995 $ 497 $ 13 $ 935 $ 2,440 (a) Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $155 million of equity investments in unconsolidated subsidiaries and $136 million of rabbi trust assets and miscellaneous investments. Dec. 31, 2018 Fair Value (Millions of Dollars) Cost Level 1 Level 2 Level 3 NAV Total Nuclear decommissioning fund (a) Cash equivalents $ 24 $ 24 $ — $ — $ — $ 24 Commingled funds 758 79 — — 819 898 Debt securities 466 — 436 — — 436 Equity securities 401 697 — — — 697 Total $ 1,649 $ 800 $ 436 $ — $ 819 $ 2,055 (a) Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $141 million of equity investments in unconsolidated subsidiaries and $121 million of rabbi trust assets and miscellaneous investments. For the years ended Dec. 31, 2019 and 2018 , there were immaterial Level 3 nuclear decommissioning fund investments or transfer of amounts between levels. Contractual maturity dates of debt securities in the nuclear decommissioning fund as of Dec. 31, 2019 : 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 Debt securities $ (7 ) $ 111 $ 246 $ 158 $ 508 Rabbi Trusts Xcel Energy has established rabbi trusts to provide partial funding for future distributions of its SERP and deferred compensation plan. Cost and fair value of assets held in rabbi trusts: Dec. 31, 2019 Fair Value (Millions of Dollars) Cost Level 1 Level 2 Level 3 Total Rabbi Trusts (a) Cash equivalents $ 17 $ 17 $ — $ — $ 17 Mutual funds 57 65 — — 65 Total $ 74 $ 82 $ — $ — $ 82 (a) Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet. Dec. 31, 2018 Fair Value (Millions of Dollars) Cost Level 1 Level 2 Level 3 Total Rabbi Trusts (a) Cash equivalents $ 16 $ 16 $ — $ — $ 16 Mutual funds 52 51 — — 51 Total $ 68 $ 67 $ — $ — $ 67 (a) Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet. Derivative 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, 2019 , accumulated other comprehensive losses related to interest rate derivatives included $5 million of net losses expected to be reclassified into earnings during the next 12 months as the hedged transactions impact earnings. As of Dec. 31, 2019 , Xcel Energy had no unsettled interest rate swaps outstanding. These interest rate derivatives were designated as hedges, and as such, changes in fair value are recorded to other comprehensive income. 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 is allowed to conduct these activities within guidelines and limitations as approved by its risk management committee, comprised of management personnel not directly involved in 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, 2019 , Xcel Energy had no commodity derivative contracts designated as cash flow hedges. Xcel Energy may enter into derivative instruments that mitigate commodity price risk on behalf of electric and natural gas customers but may not be designated as qualifying hedging transactions. Changes in the fair value of non-trading commodity derivative instruments are recorded in other comprehensive income or deferred as a regulatory asset or liability. The classification as a regulatory asset or liability is based on commission approved regulatory recovery mechanisms. Immaterial amounts to income related to the ineffectiveness of cash flow hedges were recorded for the years ended Dec. 31, 2019 and 2018 . As of Dec. 31, 2019 , there were no net gains related to commodity derivative cash flow hedges recorded as a component of accumulated other comprehensive losses or related amounts expected to be reclassified into earnings during the next 12 months. 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. Gross notional amount of commodity forwards, options and FTRs at Dec. 31: (Millions of Dollars) (a) (b) 2019 2018 MWh of electricity 95 87 MMBtu of natural gas 110 92 (a) Amounts are not reflective of net positions in the underlying commodities. (b) Notional amounts for options are included on a gross basis but weighted for the probability of exercise. Consideration of Credit Risk and Concentrations — Xcel Energy continuously monitors the creditworthiness of 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. Impact of credit risk was immaterial to the fair value of unsettled commodity derivatives presented in the consolidated balance sheets. 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, 2019 , six of Xcel Energy’s 10 most significant counterparties for these activities, comprising $154 million or 60% of this credit exposure, had investment grade credit ratings from Standard & Poor’s, Moody’s Investor Services or Fitch Ratings. Four of the 10 most significant counterparties, comprising $37 million or 14% 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. Nine of these significant counterparties are municipal or cooperative electric entities, RTOs or other utilities. Qualifying Cash Flow Hedges — Financial 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: (Millions of Dollars) 2019 2018 2017 Accumulated other comprehensive loss related to cash flow hedges at Jan. 1 $ (60 ) $ (58 ) $ (51 ) After-tax net unrealized losses related to derivatives accounted for as hedges (23 ) (5 ) — After-tax net realized losses on derivative transactions reclassified into earnings 3 3 3 Adoption of ASU. 2018-02 (a) — — (10 ) Accumulated other comprehensive loss related to cash flow hedges at Dec. 31 $ (80 ) $ (60 ) $ (58 ) (a) In 2017, Xcel Energy implemented ASU No 2018-02 related to TCJA, which resulted in reclassification of certain credit balances within net accumulated other comprehensive loss to retained earnings. Impact of derivative activity: Pre-Tax Fair Value Gains (Losses) Recognized During the Period in: (Millions of Dollars) Accumulated Regulatory Year Ended Dec. 31, 2019 Derivatives designated as cash flow hedges Interest rate $ (30 ) $ — Total (30 ) — Other derivative instruments Electric commodity — 8 Natural gas commodity — (9 ) Total — (1 ) Year Ended Dec. 31, 2018 Interest rate (7 ) — Total (7 ) — Other derivative instruments Electric commodity — 1 Natural gas commodity — 10 Total — 11 Year Ended Dec. 31, 2017 Other derivative instruments Electric commodity — 10 Natural gas commodity — (13 ) Total $ — $ (3 ) Pre-Tax (Gains) Losses Reclassified into Income During the Period from: Pre-Tax Gains (Losses) Recognized (Millions of Dollars) Accumulated Regulatory Year Ended Dec. 31, 2019 Derivatives designated as cash flow hedges Interest rate $ 4 (a) $ — $ — Total 4 — — Other derivative instruments Commodity trading — — 2 (b) Electric commodity — (5 ) (c) — Natural gas commodity — 2 (d) (7 ) (d) Total — (3 ) (5 ) Year Ended Dec. 31, 2018 Derivatives designated as cash flow hedges Interest rate 4 (a) — — Total 4 — — Other derivative instruments Commodity trading — — 14 (b) Electric commodity — (1 ) (c) — Natural gas commodity — (6 ) (d) (4 ) (d) Total — (7 ) 10 Year Ended Dec. 31, 2017 Derivatives designated as cash flow hedges Interest rate 5 (a) — — Total 5 — — Other derivative instruments Commodity trading — — 10 (b) Electric commodity — (15 ) (c) — Natural gas commodity — 3 (d) (6 ) (d) Total $ — $ (12 ) $ 4 (a) Amounts recorded to interest charges. (b) Amounts 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 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) Amounts for the year ended Dec. 31, 2019 included no settlement losses on derivatives entered to mitigate natural gas price risk for electric generation recorded to electric fuel and purchased power, subject to cost-recovery mechanisms and reclassified to a regulatory asset, as appropriate. Such losses and gains for the years ended Dec. 31, 2018 and 2017 were $1 million and immaterial, respectively. Remaining settlement losses for the years ended Dec. 31, 2019 , 2018 and 2017 related to natural gas operations and were 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, 2019 , 2018 and 2017 . 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 if there was a failure under other financing arrangements related to payment terms or other covenants. As of Dec. 31, 2019 and 2018 , the amounts for derivative instruments in a liability position with such underlying contract provisions were $7 million and none , respectively. 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, 2019 and 2018 . Recurring Fair Value Measurements — Xcel Energy’s derivative assets and liabilities measured at fair value on a recurring basis: Dec. 31, 2019 Dec. 31, 2018 Fair Value Fair Value Total Netting (a) Fair Value Fair Value Total Netting (a) (Millions of Dollars) Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Current derivative assets Commodity trading $ 3 $ 51 $ 24 $ 78 $ (52 ) $ 26 $ 4 $ 92 $ 2 $ 98 $ (44 ) $ 54 Electric commodity — — 21 21 (1 ) 20 — — 25 25 — 25 Natural gas commodity — 6 — 6 — 6 — 4 — 4 — 4 Total current derivative assets $ 3 $ 57 $ 45 $ 105 $ (53 ) 52 $ 4 $ 96 $ 27 $ 127 $ (44 ) 83 PPAs (b) 3 4 Current derivative instruments $ 55 $ 87 Noncurrent derivative assets Other derivative instruments: Commodity trading $ 9 $ 38 $ 7 $ 54 $ (45 ) $ 9 $ — $ 27 $ 5 $ 32 $ (14 ) $ 18 Total noncurrent derivative assets $ 9 $ 38 $ 7 $ 54 $ (45 ) 9 $ — $ 27 $ 5 $ 32 $ (14 ) 18 PPAs (b) 13 16 Noncurrent derivative instruments $ 22 $ 34 Dec. 31, 2019 Dec. 31, 2018 Fair Value Fair Value Total Netting (a) Fair Value Fair Value Total Netting (a) (Millions of Dollars) Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Current derivative liabilities Derivatives designated as cash flow hedges: Interest rate $ — $ — $ — $ — $ — $ — $ — $ 7 $ — $ 7 $ — $ 7 Other derivative instruments: Commodity trading 4 59 15 78 (63 ) 15 4 88 2 94 (60 ) 34 Electric commodity — — 1 1 (1 ) — — — — — — — Natural gas commodity — 5 — 5 — 5 — — — — — — Total current derivative liabilities $ 4 $ 64 $ 16 $ 84 $ (64 ) 20 $ 4 $ 95 $ 2 $ 101 $ (60 ) 41 PPAs (b) 18 20 Current derivative instruments $ 38 $ 61 Noncurrent derivative liabilities Other derivative instruments: Commodity trading $ 2 $ 79 $ 32 $ 113 $ (13 ) $ 100 $ — $ 18 $ 1 $ 19 $ 17 $ 36 Total noncurrent derivative liabilities $ 2 $ 79 $ 32 $ 113 $ (13 ) 100 $ — $ 18 $ 1 $ 19 $ 17 36 PPAs (b) 75 93 Noncurrent derivative instruments $ 175 $ 129 (a) 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, 2019 and 2018 . At both Dec. 31, 2019 and 2018 , derivative assets and liabilities included $32 million of obligations to return cash collateral. At Dec. 31, 2019 and 2018 , derivative assets and liabilities included rights to reclaim cash collateral of $11 million and $15 million , respectively. Counterparty netting excludes settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements. (b) 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. Changes in Level 3 commodity derivatives: Year Ended Dec. 31 (Millions of Dollars) 2019 2018 2017 Balance at Jan. 1 $ 29 $ 35 $ 17 Purchases 44 59 82 Settlements (64 ) (59 ) (97 ) Net transactions recorded during the period: (Losses) gains recognized in earnings (a) (8 ) (1 ) 5 Net gains (losses) recognized as regulatory assets and liabilities 3 (5 ) 28 Balance at Dec. 31 $ 4 $ 29 $ 35 (a) 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 2017 - 2019 Fair Value of Long-Term Debt As of Dec. 31, other financial instruments for which the carrying amount did not equal fair value: 2019 2018 (Millions of Dollars) Carrying Amount Fair Value Carrying Amount Fair Value Long-term debt, including current portion $ 18,109 $ 20,227 $ 16,209 $ 16,755 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. Fair value estimates are based on information available to management as of Dec. 31, 2019 and 2018 , and given the observability of the inputs, fair values presented for long-term debt were assigned as Level 2.

Benefit Plans and Other Postret

Benefit Plans and Other Postretirement Benefits	12 Months Ended
	Dec. 31, 2019
Retirement Benefits [Abstract]
Benefit Plans and Other Postretirement Benefits	and Postretirement Health Care 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 and average pay. Xcel Energy’s policy is to fully fund into an external trust the actuarially determined pension costs subject to the limitations of applicable employee benefit and tax laws. In addition to the qualified pension plans, Xcel Energy maintains a 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 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. Obligations of the SERP and nonqualified plan as of Dec. 31, 2019 and 2018 were $39 million and $33 million , respectively. Xcel Energy recognized net benefit cost for the SERP and nonqualified plans of $4 million in 2019 and in 2018. Xcel Energy bases the investment-return assumption on expected long-term performance for each of the asset classes in its pension and postretirement health care portfolios. For pension assets, Xcel Energy considers the historical returns achieved by its asset portfolio over the past 20 years or longer period, as well as long-term projected return levels. Pension cost determination assumes a forecasted mix of investment types over the long-term. • Investment returns in 2019 were above the assumed level of 6.87% ; • Investment returns in 2018 were below the assumed level of 6.87% ; • Investment returns in 2017 were above the assumed level of 6.87% ; and • In 2020, expected investment-return assumption is 6.87% . Pension plan and postretirement benefit 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 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 industry, index, or entity. Market volatility can impact even well-diversified portfolios and significantly affect the return levels achieved by the assets in any year. State agencies also have issued guidelines to the funding of postretirement benefit costs. SPS is required to fund postretirement benefit costs for Texas and New Mexico 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. 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. Plan Assets For each of the fair value hierarchy levels, Xcel Energy’s pension plan assets measured at fair value: Dec. 31, 2019 (a) Dec. 31, 2018 (a) (Millions of Dollars) Level 1 Level 2 Level 3 Measured at NAV Total Level 1 Level 2 Level 3 Measured at NAV Total Cash equivalents $ 145 $ — $ — $ — $ 145 $ 137 $ — $ — $ — $ 137 Commingled funds 1,408 — — 1,031 2,439 914 — — 987 1,901 Debt securities — 645 4 — 649 — 621 — — 621 Equity securities 86 — — — 86 106 — — — 106 Other (120 ) 5 — (20 ) (135 ) 2 5 — (30 ) (23 ) Total $ 1,519 $ 650 $ 4 $ 1,011 $ 3,184 $ 1,159 $ 626 $ — $ 957 $ 2,742 (a) See Note 10 for further information regarding fair value measurement inputs and methods. For each of the fair value hierarchy levels, Xcel Energy’s postretirement benefit plan assets that were measured at fair value: Dec. 31, 2019 (a) Dec. 31, 2018 (a) (Millions of Dollars) Level 1 Level 2 Level 3 Measured at NAV Total Level 1 Level 2 Level 3 Measured at NAV Total Cash equivalents $ 23 $ — $ — $ — $ 23 $ 19 $ — $ — $ — $ 19 Insurance contracts — 51 — — 51 — 45 — — 45 Commingled funds 69 — — 76 145 133 — — 40 173 Debt securities — 228 1 — 229 — 179 — — 179 Other — 1 — — 1 — 1 — — 1 Total $ 92 $ 280 $ 1 $ 76 $ 449 $ 152 $ 225 $ — $ 40 $ 417 (a) See Note 10 for further information on fair value measurement inputs and methods. Immaterial assets were transferred in or out of Level 3 for 2019. No assets were transferred in or out of Level 3 for 2018. Funded Status — Comparisons of the actuarially computed benefit obligation, changes in plan assets and funded status of the pension and postretirement health care plans for Xcel Energy are as follows: Pension Benefits Postretirement Benefits (Millions of Dollars) 2019 2018 2019 2018 Change in Benefit Obligation: Obligation at Jan. 1 $ 3,477 $ 3,828 $ 542 $ 621 Service cost 86 94 2 2 Interest cost 145 133 22 22 Plan amendments 1 — — — Actuarial loss (gain) 273 (224 ) 19 (62 ) Plan participants’ contributions — — 8 8 Medicare subsidy reimbursements — — 1 1 Benefit payments (a) (281 ) (354 ) (47 ) (50 ) Obligation at Dec. 31 $ 3,701 $ 3,477 $ 547 $ 542 Change in Fair Value of Plan Assets: Fair value of plan assets at Jan. 1 $ 2,742 $ 3,088 $ 417 $ 461 Actual return on plan assets 568 (142 ) 56 (13 ) Employer contributions 155 150 15 11 Plan participants’ contributions — — 8 8 Benefit payments (281 ) (354 ) (47 ) (50 ) Fair value of plan assets at Dec. 31 $ 3,184 $ 2,742 $ 449 $ 417 Funded status of plans at Dec. 31 $ (517 ) $ (735 ) $ (98 ) $ (125 ) Amounts recognized in the Consolidated Balance Sheet at Dec. 31: Noncurrent assets $ — $ — $ 21 $ — Current liabilities — — (6 ) (7 ) Noncurrent liabilities (517 ) (735 ) (113 ) (118 ) Net amounts recognized $ (517 ) $ (735 ) $ (98 ) $ (125 ) (a) Includes approximately $20 million in 2019 and $198 million in 2018 of lump-sum benefit payments used in the determination of a settlement charge. Pension Benefits Postretirement Benefits (Millions of Dollars) 2019 2018 2019 2018 Significant Assumptions Used to Measure Benefit Obligations: Discount rate for year-end valuation 3.49 % 4.31 % 3.47 % 4.32 % Expected average long-term increase in compensation level 3.75 3.75 N/A N/A Mortality table PRI-2012 RP-2014 PRI-2012 RP-2014 Health care costs trend rate — initial: Pre-65 N/A N/A 6.00 % 6.50 % Health care costs trend rate — initial: Post-65 N/A N/A 5.10 % 5.30 % Ultimate trend assumption — initial: Pre-65 N/A N/A 4.50 % 4.50 % Ultimate trend assumption — initial: Post-65 N/A N/A 4.50 % 4.50 % Years until ultimate trend is reached N/A N/A 3 4 Accumulated benefit obligation for the pension plan was $3,465 million and $3,275 million as of Dec. 31, 2019 and 2018, respectively. Net Periodic Benefit Cost (Credit) — Net periodic benefit cost (credit), other than the service cost component, is included in other income in the consolidated statements of income. Components of net periodic benefit cost (credit) and amounts recognized in other comprehensive income and regulatory assets and liabilities: Pension Benefits Postretirement Benefits (Millions of Dollars) 2019 2018 2017 2019 2018 2017 Service cost $ 86 $ 94 $ 94 $ 2 $ 2 $ 2 Interest cost 145 133 147 22 22 24 Expected return on plan assets (203 ) (209 ) (209 ) (21 ) (26 ) (25 ) Amortization of prior service credit (5 ) (5 ) (2 ) (10 ) (11 ) (11 ) Amortization of net loss 87 111 107 5 8 7 Settlement charge (a) 6 91 81 — — — Net periodic pension cost (credit) 116 215 218 (2 ) (5 ) (3 ) Costs not recognized due to effects of regulation (1 ) (75 ) (79 ) 1 2 — Net benefit cost (credit) recognized for financial reporting $ 115 $ 140 $ 139 $ (1 ) $ (3 ) $ (3 ) Significant Assumptions Used to Measure Costs: Discount rate 4.31 % 3.63 % 4.13 % 4.32 % 3.62 % 4.13 % Expected average long-term increase in compensation level 3.75 3.75 3.75 — — — Expected average long-term rate of return on assets 6.87 6.87 6.87 4.50 5.30 5.80 (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 2019 and 2018, as a result of lump-sum distributions during the 2019 and 2018 plan years, Xcel Energy recorded a total pension settlement charge of $6 million in 2019 and $91 million in 2018, the majority of which was not recognized due to the effects of regulation. A total of $1 million and $11 million was recorded in the consolidated statements of income in 2019 and 2018, respectively. Pension Benefits Postretirement Benefits (Millions of Dollars) 2019 2018 2019 2018 Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost: Net loss $ 1,447 $ 1,633 $ 95 $ 116 Prior service credit (15 ) (20 ) (23 ) (33 ) Total $ 1,432 $ 1,613 $ 72 $ 83 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 $ 78 $ 94 $ — $ — Noncurrent regulatory assets 1,285 1,446 80 89 Current regulatory liabilities — — (1 ) (1 ) Noncurrent regulatory liabilities — — (12 ) (10 ) Deferred income taxes 18 19 1 1 Net-of-tax accumulated other comprehensive income 51 54 4 4 Total $ 1,432 $ 1,613 $ 72 $ 83 Measurement date Dec. 31, 2019 Dec. 31, 2018 Dec. 31, 2019 Dec. 31, 2018 Cash Flows — Funding requirements can be impacted by changes to actuarial assumptions, actual asset levels and other calculations prescribed by the requirements of income tax and other pension-related regulations. Required contributions were made in 2017 — 2020 to meet minimum funding requirements. Voluntary and required pension funding contributions: • $150 million in January 2020; • $154 million in 2019; • $150 million in 2018; and • $162 million in 2017. The postretirement health care plans have no funding requirements other than fulfilling benefit payment obligations, when claims are presented and approved. Additional cash funding requirements are prescribed by certain state and federal rate regulatory authorities. Voluntary postretirement funding contributions: • $10 million during 2020; • $15 million during 2019; • $11 million during 2018; and • $20 million during 2017. Targeted asset allocations: Pension Benefits Postretirement Benefits 2019 2018 2019 2018 Domestic and international equity securities 37 % 36 % 15 % 18 % Long-duration fixed income securities 30 30 — — Short-to-intermediate fixed income securities 14 17 72 70 Alternative investments 17 15 9 8 Cash 2 2 4 4 Total 100 % 100 % 100 % 100 % Plan Amendments — The Xcel Energy Pension Plan and Xcel Energy Inc. Nonbargaining Pension Plan (South) were amended 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 2018, the PSCo postretirement plan was amended to add the 5% cash balance formula. In 2019, the Pension Protection Act measurement concept was extended beyond 2019 for NSP bargaining terminations and retirements to Dec. 31, 2022. There were no plan amendments made in 2019 which affected the postretirement benefit obligation. Projected Benefit Payments Xcel Energy’s projected benefit payments: (Millions of Dollars) Projected Gross Projected Expected Net Projected 2020 $ 278 $ 44 $ 2 $ 42 2021 263 43 2 41 2022 262 42 2 40 2023 260 41 2 39 2024 255 40 2 38 2025-2029 1,205 181 13 168 Defined Contribution Plans Xcel Energy maintains 401(k) and other defined contribution plans that cover most employees. Total expense to these plans was approximately $39 million in 2019, $38 million in 2018 and $37 million in 2017. 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.

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2019
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	Legal Xcel Energy is involved in various litigation matters that are being defended and handled in the ordinary course of business. Assessing whether a loss is probable or a reasonable possibility, and whether the loss or a range of loss is estimable, often involves complex judgments regarding future events. Management maintains accruals for losses that are probable of being incurred and subject to reasonable estimation. Management may be unable to estimate an amount or range of a reasonably possible loss in certain situations, including when (1) the damages sought are indeterminate, (2) the proceedings are in the early stages, or (3) the matters involve novel or unsettled legal theories. In such cases, there is considerable uncertainty regarding the timing or ultimate resolution of such matters, including a possible eventual loss. For current proceedings not specifically reported herein, management does not anticipate the ultimate liabilities, if any, arising from such current proceedings would have a material effect on Xcel Energy’s financial statements. Unless otherwise required by GAAP, legal fees are expensed as incurred. Gas Trading Litigation — e prime is a wholly owned subsidiary of Xcel Energy. e prime was in the business of natural gas trading and marketing but has not engaged in natural gas trading or marketing activities since 2003. Multiple lawsuits involving multiple plaintiffs seeking monetary damages were commenced against e prime and its affiliates, including Xcel Energy, between 2003 and 2009 alleging fraud and anticompetitive activities in conspiring to restrain the trade of natural gas and manipulate natural gas prices. Cases were all consolidated in the U.S. District Court in Nevada. Two cases remain active which include an MDL matter consisting of a Colorado purported class (Breckenridge) and a Wisconsin purported class (Arandell Corp.). Breckenridge/Colorado — In February 2019, the MDL panel remanded Breckenridge back to the U.S. District Court in Colorado. Arandell Corp. — In February 2019, the case was remanded back to the U.S. District Court in Wisconsin. Xcel Energy has concluded that a loss is remote for both remaining lawsuits. Line Extension Disputes — In December 2015, the DRC filed a lawsuit seeking monetary damages in the Denver District Court, stating PSCo failed to award proper allowances and refunds for line extensions to new developments pursuant to the terms of electric and gas service agreements. The dispute involves claims by over fifty developers. In February 2018, the Colorado Supreme Court denied DRC’s petition to appeal the Denver District Court’s dismissal of the lawsuit, effectively terminating this litigation. However, in January 2018, DRC filed a new lawsuit in Boulder County District Court, asserting a single claim that PSCo was required to file its line extension agreements with the CPUC but failed to do so. This claim is similar to the arguments previously raised by the DRC. PSCo filed a motion to dismiss this claim, which was granted in May 2018. The DRC subsequently filed an appeal to the Colorado Court of Appeals. In November 2019, the Colorado Court of Appeals issued an opinion affirming dismissal of the lawsuit based upon lack of subject matter jurisdiction. The Colorado Court of Appeals did not address the second issue based upon issue preclusion. Finally, the Colorado Court of Appeals remanded the case to the Boulder District Court to consider PSCo’s request for an award of costs, which it concluded does not include attorneys’ fees. The DRC did not file a petition for a Writ of Certiorari to the Colorado Supreme Court by the Dec. 26, 2019 deadline, effectively terminating this litigation. Rate Matters MEC Acquisition — In November 2018, NSP-Minnesota reached an agreement with Southern Power Company (a subsidiary of Southern Company) to purchase MEC, a 760 MW natural gas combined cycle facility, with capacity and energy historically sold to NSP-Minnesota under PPAs expiring in 2026 and 2039, for approximately $650 million . In September 2019, the MPUC denied NSP-Minnesota's request to purchase MEC as a rate base asset. In January 2020, the MPUC approved Xcel Energy’s plan to acquire MEC as a non-regulated investment and step into the terms of the existing PPAs with NSP-Minnesota. A newly formed non-regulated subsidiary of Xcel Energy completed the transaction to purchase MEC on Jan. 17, 2020. Sherco — In NSP-Minnesota’s 2013 fuel reconciliation filing, the MPUC made recovery of replacement power costs associated with the 2011 incident at its Sherco Unit 3 plant provisional and subject to further review following conclusion of litigation commenced by NSP-Minnesota, SMMPA (Co-owner of Sherco Unit 3) and insurance companies against GE. In 2018, NSP-Minnesota and SMMPA reached a settlement with GE. NSP-Minnesota notified the MPUC of its proposal to refund the GE settlement proceeds back to customers through the FCA. The insurance providers continued their litigation against GE and the case went to trial. In 2018, GE prevailed in the lawsuit with the insurance companies, however, the jury found comparable fault, finding that GE was 52% and NSP-Minnesota was 48% at fault. At that point in the litigation, NSP-Minnesota was no longer involved in the case and was not present to make arguments about its role in the event. The specific issue leading to the fault apportionment was also not before the jury and not relevant to the outcome of the trial. In January 2019, the DOC recommended that NSP-Minnesota refund $20 million of previously recovered purchased power costs to its customers, based on the jury’s apportionment of fault. The OAG recommended the MPUC withhold any decision until the underlying litigation by the insurance providers (currently under appeal) is concluded. The DOC subsequently filed comments agreeing with the OAG’s recommendation to withhold a decision pending the outcome of any appeals. NSP-Minnesota filed reply comments arguing that the DOC recommendations are without merit and that it acted prudently in operating the plant and its settlement with GE was reasonable. In March 2019, MPUC approved NSP-Minnesota’s proposal to refund the GE settlement proceeds back to customers through the FCA. It also decided to withhold any decision as to NSP-Minnesota’s prudence in connection with the incident at Sherco Unit 3 until after conclusion of the pending litigation between GE and NSP-Minnesota’s insurers. MISO ROE Complaints — In November 2013 and February 2015, customers filed complaints against MISO TOs including NSP-Minnesota and NSP-Wisconsin. The first complaint argued for a reduction in the base ROE in MISO transmission formula rates from 12.38% to 9.15% , and removal of ROE adders (including those for RTO membership). The second complaint sought to reduce base ROE from 12.38% to 8.67% . In September 2016, the FERC issued an order granting a 10.32% base ROE ( 10.82% with the RTO adder) effective for the first complaint period of Nov. 12, 2013 to Feb. 11, 2015 and subsequent to the date of the order. The D.C. Circuit subsequently vacated and remanded FERC Opinion No. 531, which had established the ROE methodology on which the September 2016 FERC order was based. On March 21, 2019, FERC announced a NOI seeking public comments on whether, and if so how, to revise ROE policies in light of the D.C. Circuit Court decision. FERC also initiated a NOI on whether to revise its policies on incentives for electric transmission investments, including the RTO membership incentive. In November 2019, the FERC issued an order adopting a new ROE methodology and settling the MISO base ROE at 9.88% ( 10.38% with the RTO adder), effective Sept. 28, 2016 and for the Nov. 12, 2013 to Feb. 11, 2015 refund period. The FERC also dismissed the second complaint. In December 2019, MISO TOs filed a request for rehearing. Customers also filed requests for rehearing claiming, among other points, that the FERC erred by dismissing the second complaint without refunds. Xcel Energy has recognized a liability for its best estimate of final refunds to customers. It is uncertain when the FERC will act on the requests for rehearing or any other pending matters related to the 2019 NOIs. Texas Fuel Reconciliation — In December 2018, SPS filed an application with the PUCT for reconciliation of fuel costs for the period Jan. 1, 2016, through June 30, 2018, to determine whether all fuel costs incurred were eligible for recovery. In December 2019, the PUCT issued an order disallowing recovery of costs for Texas customers related to two specific solar PPAs. These PPAs were previously approved by the NMPRC as reasonable, necessary and economic. SPS recorded a total disallowance of approximately $6 million in December 2019. SPP OATT Upgrade Costs — Under the SPP OATT, costs of transmission upgrades may be recovered from other SPP customers whose transmission service depends on capacity enabled by the upgrade. SPP had not been charging its customers for these upgrades, even though the SPP OATT had allowed SPP to do so since 2008. In 2016, the FERC granted SPP’s request to recover previously unbilled charges and SPP subsequently billed SPS approximately $13 million . In July 2018, SPS’ appeal to the D.C. Circuit over the FERC rulings granting SPP the right to recover previously unbilled charges was remanded to the FERC. In February 2019, the FERC reversed its 2016 decision and ordered SPP to refund charges retroactively collected from its transmission customers, including SPS, related to periods before September 2015. In April 2019, several parties, including SPP, filed requests for a rehearing. Timing of a FERC response to rehearing requests is uncertain. Any refunds received by SPS are expected to be given back to SPS customers through future rates. In October 2017, SPS filed a separate complaint against SPP asserting SPP assessed upgrade charges to SPS in violation of the SPP OATT. The FERC granted a rehearing for further consideration in May 2018. Timing of FERC action on the SPS rehearing is uncertain. If SPS’ complaint results in additional charges or refunds, SPS will seek to recover or refund the amounts through future SPS customer rates. Environmental New and changing federal and state environmental mandates can create financial liabilities for Xcel Energy, which are normally recovered through the regulated rate process. Site Remediation — Various federal and state environmental laws impose liability 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; and third-party sites, such as landfills, for which one or more of Xcel Energy Inc.’s subsidiaries are alleged to have sent wastes to that site. MGP Sites Ashland MGP Site — NSP-Wisconsin was named a responsible party for contamination at the Ashland/Northern States Power Lakefront Superfund Site (the Site) in Ashland, Wisconsin. Remediation was completed in 2019 and restoration activities are anticipated to be completed in 2020. Groundwater treatment activities will continue for many years. The current cost estimate for remediation and restoration of the entire site is approximately $199 million . At Dec. 31, 2019 and 2018, NSP-Wisconsin had a total liability of $23 million and $27 million , respectively, for the entire site. NSP-Wisconsin has deferred the unrecovered portion of the estimated Site remediation and restoration costs as a regulatory asset. The PSCW has authorized NSP-Wisconsin rate recovery for all remediation and restoration costs incurred at the Site. In its final December 2019 order approving 2020 and 2021 natural gas base rates, the PSCW authorized continued amortization of costs and application of a 3% carrying charge to the regulatory asset. MGP, Landfill or Disposal Sites — PSCo is cooperating with the City of Denver on an environmental investigation of the Rice Yards Site in Denver, Colorado, which had various historic industrial uses by multiple parties, including railroad, maintenance shop, scrap metal yard, and MGP operations. The area is being redeveloped into residential and commercial mixed uses, and PSCo is in discussions with the current property owner regarding legal claims related to the Rice Yards Site. In addition, Xcel Energy is currently investigating or remediating 12 other MGP, landfill or other disposal sites across its service territories. Xcel Energy has recognized its best estimate of costs/liabilities that will result from final resolution of these issues, however, the outcome and timing is unknown. In addition, there may be insurance recovery and/or recovery from other potentially responsible parties, offsetting a portion of costs incurred. Environmental Requirements — Water and Waste 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. Under the CCR Rule, utilities are required to complete groundwater sampling around their CCR landfills and surface impoundments. Currently, Xcel Energy has nine regulated ash units in operation. Xcel Energy is conducting groundwater sampling and, where appropriate, initiating the assessment of corrective measures and evaluating whether corrective action is required at any CCR landfills or surface impoundments. In 2019, groundwater monitoring consistent with the CCR Rule was conducted. In NSP-Minnesota, no results above the groundwater protection standards in the rule were identified. In PSCo, statistically significant increase above background concentration was detected at four locations. Subsequently, assessment monitoring samples were collected, and PSCo is evaluating the results to determine whether corrective action is required. Until PSCo completes its assessment, it is uncertain what impact, if any, there will be on the operations, financial condition or cash flows. In August 2018, the D.C. Circuit ruled that the EPA cannot allow utilities to continue to use unlined impoundments (including clay lined impoundments) for the storage or disposal of coal ash. In November 2019, the EPA proposed rules in response to this decision. If finalized in their current form, these rules would require NSP-Minnesota to expedite closure plans for one impoundment at an estimated cost of $2 million and the construction of a new impoundment at the cost of $9 million . In 2019, Xcel Energy initiated the construction of this new impoundment, an ash pond, expected to be in service in 2020. Upon placing the new ash pond in service, the existing ash pond will be taken out of service, and closure activities as prescribed by the CCR Rule and the facility’s National Pollutant Discharge Elimination System permit will be initiated. In addition, the rules proposed by the EPA may require PSCo to expedite the closure of one coal ash impoundment. Closure costs for existing impoundments are included in the calculation of the ARO liability. See Note 12 for further information. Federal CWA WOTUS Rule — In 2015, the EPA and U.S. Army Corps of Engineers published a final rule that significantly broadened the scope of waters under the CWA that are subject to federal jurisdiction, referred to as “WOTUS”. In 2019, the EPA repealed the 2015 rule and published a draft replacement rule. Until a final rule is issued, Xcel Energy cannot estimate potential impacts, but anticipates costs will be recoverable through regulatory mechanisms. Federal CWA ELG — In 2015, the EPA issued a final ELG rule for power plants that discharge treated effluent to surface waters as well as utility-owned landfills that receive CCRs. In 2017, the EPA delayed the compliance date for flue gas desulfurization wastewater and bottom ash transport until November 2020. After 2020, Xcel Energy estimates that ELG compliance will cost approximately $12 million to complete. The EPA, however, is conducting a rulemaking process to revise certain effluent limitations and pretreatment standards, which may impact compliance costs. Xcel Energy anticipates these costs will be fully recoverable through regulatory mechanisms. 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 impingement and entrainment of aquatic species. Xcel Energy estimates the likely cost for complying with impingement and entrainment requirements is approximately $40 million , to be incurred between 2020 and 2028. Xcel Energy believes six NSP-Minnesota plants and two NSP-Wisconsin plants could be required by state regulators to make improvements to reduce impingement and entrainment. The exact total cost of the impingement and entrainment improvements is uncertain but could be up to approximately $198 million . Xcel Energy anticipates these costs will be fully recoverable through regulatory mechanisms. Environmental Requirements — Air Regional Haze Rules — The regional haze program requires SO 2 , nitrogen oxide and particulate matter emission controls at power plants to reduce visibility impairment in national parks and wilderness areas. The program includes BART and reasonable further progress. The requirements of the first regional haze plans developed by Minnesota and Colorado have been approved and implemented. Texas’ first regional haze plan has undergone federal review as described below. BART Determination for Texas: The EPA has issued a revised final rule adopting a BART alternative Texas only SO 2 trading program that applies to all Harrington and Tolk units. Under the trading program, SPS expects the allowance allocations to be sufficient for SO 2 emissions. The anticipated costs of compliance are not expected to have a material impact; and SPS believes that compliance costs would be recoverable through regulatory mechanisms. Several parties have challenged whether the final rule issued by the EPA should be considered to have met the requirements imposed in a Consent Decree entered by the United States District Court for the District of Columbia that established deadlines for the EPA to take final action on state regional haze plan submissions. The court has required status reports from the parties while the EPA works on the reconsideration rulemaking. In December 2017, the National Parks Conservation Association, Sierra Club, and Environmental Defense Fund appealed the EPA’s 2017 final BART rule to the Fifth Circuit and filed a petition for administrative reconsideration. In January 2018, the court granted SPS’ motion to intervene in the Fifth Circuit litigation in support of the EPA’s final rule. The court has held the litigation in abeyance while the EPA decided whether to reconsider the rule. In August 2018, the EPA started a reconsideration rulemaking, which was supplemented by an additional agency notice in November 2019. It is not known when the EPA will make a final decision on this proposal. Reasonable Progress Rule: In 2016, the EPA adopted a final rule establishing a federal implementation plan for reasonable further progress under the regional haze program for the state of Texas. The rule imposes SO 2 emission limitations that would require the installation of dry scrubbers on Tolk Units 1 and 2, with compliance required by February 2021. Investment costs associated with dry scrubbers could be $600 million . SPS appealed the EPA’s decision and obtained a stay of the final rule. In March 2017, the Fifth Circuit remanded the rule to the EPA for reconsideration, leaving the stay in effect. In a future rulemaking, the EPA will address whether SO 2 emission reductions beyond those required in the BART alternative rule are needed at Tolk under the “reasonable progress” requirements. The EPA has not announced a schedule for acting on the remanded rule. Implementation of the NAAQS for SO 2 — The EPA has designated all areas near SPS’ generating plants as attaining the SO 2 NAAQS with an exception. The EPA issued final designations, which found the area near the SPS Harrington plant as “unclassifiable.” The area near the Harrington plant is to be monitored for three years and a final designation is expected to be made by December 2020. If the area near the Harrington plant is designated nonattainment in 2020, the TCEQ will need to develop an implementation plan, designed to achieve the NAAQS by 2025. The TCEQ could require additional SO 2 controls at Harrington as part of such a plan. Xcel Energy cannot evaluate the impacts until the final designation is made and any required state plans are developed. Xcel Energy believes that should SO 2 AROs — AROs have been recorded for Xcel Energy’s assets. For nuclear assets, the ARO is associated with the decommissioning of NSP-Minnesota nuclear generating plants. Aggregate fair value of NSP-Minnesota’s legally restricted assets, for funding future nuclear decommissioning, was $2.4 billion and $2.1 billion for 2019 and 2018 , respectively. Xcel Energy’s AROs were as follows: (Millions of Dollars) Jan. 1, 2019 Amounts Incurred (a) Amounts Settled (b) Accretion Cash Flow Revisions (c) Dec. 31, 2019 Electric Nuclear $ 1,968 $ — $ — $ 100 $ — $ 2,068 Steam, hydro and other production 177 — (5 ) 8 22 202 Wind 119 26 — 7 (6 ) 146 Distribution 42 — — 2 — 44 Miscellaneous 7 — — — (7 ) — Natural gas Transmission and distribution 249 — — 11 (24 ) 236 Miscellaneous 4 — — — (1 ) 3 Common Miscellaneous 1 — — — — 1 Non-utility Miscellaneous 1 — — — — 1 Total liability $ 2,568 $ 26 $ (5 ) $ 128 $ (16 ) $ 2,701 (a) Amounts incurred related to the wind farms placed in service in 2019 for NSP-Minnesota (Lake Benton and Foxtail) and SPS (Hale). (b) Amounts settled related to asbestos abatement projects and closure of certain ash containment facilities. (c) In 2019, AROs were revised for changes in timing and estimates of cash flows. Changes in gas transmission and distribution AROs were primarily related to increased gas line mileage and number of services, which were more than offset by decreased inflation rates. Changes in steam, hydro and other production AROs primarily related to the cost estimates to remediate ponds at production facilities. Changes in wind AROs were driven by new dismantling studies. (Millions of Dollars) Jan. 1, 2018 Amounts Incurred (a) Amounts Settled (b) Accretion Cash Flow Revisions (c) Dec. 31, 2018 Electric Nuclear $ 1,874 $ — $ — $ 94 $ — $ 1,968 Steam, hydro and other production 192 — (14 ) 8 (9 ) 177 Wind 96 12 — 4 7 119 Distribution 21 — — 1 20 42 Miscellaneous 5 — — — 2 7 Natural gas Transmission and distribution 282 — — 13 (46 ) 249 Miscellaneous 4 — — — — 4 Common Miscellaneous 1 — — — — 1 Non-utility Miscellaneous — 1 — — — 1 Total liability $ 2,475 $ 13 $ (14 ) $ 120 $ (26 ) $ 2,568 (a) Amounts incurred related to the PSCo Rush Creek wind farm and Nicollet Projects community solar gardens, which were placed in service in 2018. (b) Amounts settled related to asbestos abatement projects and closure of certain ash containment facilities. (c) In 2018, AROs were revised for changes in timing and estimates of cash flows. Changes in gas transmission and distribution AROs were primarily related to increased gas line mileage and number of services, which were more than offset by increased discount rates. Changes in electric distribution AROs primarily related to increased labor costs. Indeterminate AROs — Other plants or buildings may contain asbestos due to the age of many of Xcel Energy’s facilities, but no confirmation or measurement of the cost of removal could be determined as of Dec. 31, 2019. Therefore, an ARO was not recorded for these facilities. Removal Costs — Xcel Energy records a regulatory liability for the plant removal costs of its utility subsidiaries that are recovered currently in rates. Removal costs have accumulated based on varying rates as authorized by the appropriate regulatory entities. The utility subsidiaries have estimated the amount of removal costs accumulated through historic depreciation expense based on current factors used in the existing depreciation rates. Accumulated balances by entity at Dec. 31 : (Millions of Dollars) 2019 2018 NSP-Minnesota $ 520 $ 485 PSCo 351 344 SPS 175 188 NSP-Wisconsin 171 158 Total Xcel Energy $ 1,217 $ 1,175 Nuclear Related Nuclear Insurance — NSP-Minnesota’s public liability for claims from any nuclear incident is limited to $13.9 billion under the Price-Anderson amendment to the Atomic Energy Act. NSP-Minnesota has secured $450 million of coverage for its public liability exposure with a pool of insurance companies. The remaining $13.5 billion of exposure is funded by the Secondary Financial Protection Program, available from assessments by the federal government. NSP-Minnesota is subject to assessments of up to $138 million per reactor-incident for each of its three licensed reactors, for public liability arising from a nuclear incident at any licensed nuclear facility in the United States. The maximum funding requirement is $21 million per reactor-incident during any one year. Maximum assessments are subject to inflation adjustments by the NRC and state premium taxes. The NRC’s last adjustment was effective November 2018. NSP-Minnesota purchases insurance for property damage and site decontamination cleanup costs from NEIL and EMANI. The coverage limits are $2.7 billion for each of NSP-Minnesota’s two nuclear plant sites. NEIL also provides business interruption insurance coverage up to $350 million , including the cost of replacement power during prolonged accidental outages of nuclear generating units. Premiums are expensed over the policy term. All companies insured with NEIL are subject to retroactive premium adjustments if losses exceed accumulated reserve funds. Capital has been accumulated in the reserve funds of NEIL and EMANI to the extent that NSP-Minnesota would have no exposure for retroactive premium assessments in case of a single incident under the business interruption and the property damage insurance coverage. NSP-Minnesota could be subject to annual maximum assessments of approximately $12 million for business interruption insurance and $35 million for property damage insurance if losses exceed accumulated reserve funds. Nuclear Fuel Disposal — NSP-Minnesota is responsible for temporarily storing 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 owns temporary on-site storage facilities for spent fuel at its Monticello and PI nuclear plants, which consist of storage pools and dry cask facilities. The Monticello dry-cask storage facility currently stores all 30 of the authorized canisters. The PI dry-cask storage facility currently stores 44 of the 64 authorized casks. Monticello’s future spent fuel will continue to be placed in its spent fuel pool. The decommissioning plan addresses the disposition of spent fuel at the end of the licensed life. Regulatory Plant Decommissioning Recovery — Decommissioning activities for 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. Obligations for decommissioning are expected to be funded 100% by the external decommissioning trust fund. The cost study assumes the external decommissioning fund will earn an after-tax return between 5.23% and 6.30% . Realized and unrealized gains on fund investments are deferred as an offset of NSP-Minnesota’s regulatory asset for nuclear decommissioning costs. Decommissioning costs are quantified in 2014 dollars. Escalation rates are 4.36% for plant removal activities and 3.36% for fuel management and site restoration activities. NSP-Minnesota had $2.4 billion of assets held in external decommissioning trusts at Dec. 31, 2019. The following table summarizes the funded status of NSP-Minnesota’s decommissioning obligation. Xcel Energy believes future decommissioning costs will continue to be recovered in customer rates. The following amounts were prepared on a regulatory basis and not directly recorded in the financial statements as an ARO. Regulatory Basis (Millions of Dollars) 2019 2018 Estimated decommissioning cost obligation from most recently approved study (in 2014 dollars) $ 3,012 $ 3,012 Effect of escalating costs 688 539 Estimated decommissioning cost obligation (in current dollars) 3,700 3,551 Effect of escalating costs to payment date 7,505 7,654 Estimated future decommissioning costs (undiscounted) 11,205 11,205 Effect of discounting obligation (using average risk-free interest rate of 2.39% and 3.33% for 2019 and 2018, respectively) (5,562 ) (6,911 ) Discounted decommissioning cost obligation $ 5,643 $ 4,294 Assets held in external decommissioning trust $ 2,440 $ 2,055 Underfunding of external decommissioning fund compared to the discounted decommissioning obligation 3,203 2,239 Calculations and data used by the regulator in approving NSP-Minnesota’s rates are useful in assessing future cash flows. 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. Reconciliation of the discounted decommissioning cost obligation - regulated basis to the ARO recorded in accordance with GAAP: (Millions of Dollars) 2019 2018 Discounted decommissioning cost obligation - regulated basis $ 5,643 $ 4,294 Differences in discount rate and market risk premium (2,295 ) (1,447 ) O&M costs not included for GAAP (1,280 ) (879 ) Nuclear production decommissioning ARO - GAAP $ 2,068 $ 1,968 Decommissioning expenses recognized as a result of regulation: (Millions of Dollars) 2019 2018 2017 Annual decommissioning recorded as depreciation expense: (a) (b) $ 20 $ 20 $ 20 (a) Decommissioning expense does not include depreciation of the capitalized nuclear asset retirement costs. (b) Decommissioning expenses in 2019, 2018 and 2017 include Minnesota’s retail jurisdiction annual funding requirement of approximately $14 million. The 2014 nuclear decommissioning filing, approved in 2015, was used for regulatory presentation in 2019, 2018 and 2017. The 2017 filing, effective Jan. 1, 2019, has been approved by the MPUC. In December 2019, the MPUC verbally approved for NSP-Minnesota to delay any increase to the annual funding requirement until 2021. Leases Xcel Energy evaluates contracts that may contain leases, including PPAs and arrangements for the use of office space and other facilities, vehicles and equipment. Under ASC Topic 842, adopted by Xcel Energy on Jan. 1, 2019, a contract contains a lease if it conveys the exclusive right to control the use of a specific asset. A contract determined to contain a lease is evaluated further to determine if the arrangement is a finance lease. ROU assets represent Xcel Energy's rights to use leased assets. Starting in 2019, the present value of future operating lease payments are recognized in other current liabilities and noncurrent operating lease liabilities. These amounts, adjusted for any prepayments or incentives, are recognized as operating lease ROU assets. Most of Xcel Energy’s leases do not contain a readily determinable discount rate. Therefore, the present value of future lease payments is generally calculated using the applicable Xcel Energy subsidiary’s estimated incremental borrowing rate (weighted-average of 4.1% ). Xcel Energy has elected the practical expedient under which non-lease components, such as asset maintenance costs included in payments, are not deducted from minimum lease payments for the purposes of lease accounting and disclosure. Leases with an initial term of 12 months or less are classified as short-term leases and are not recognized on the consolidated balance sheet. Operating lease ROU assets: (Millions of Dollars) Dec. 31, 2019 PPAs $ 1,642 Other 201 Gross operating lease ROU assets 1,843 Accumulated amortization (171 ) Net operating lease ROU assets $ 1,672 In

Other Comprehensive Income

Other Comprehensive Income	12 Months Ended
	Dec. 31, 2019
Stockholders' Equity Note [Abstract]
Comprehensive Income (Loss) Note [Text Block]	Changes in accumulated other comprehensive loss, net of tax, for the years ended Dec. 31: 2019 (Millions of Dollars) Gains and Defined Benefit Total Accumulated other comprehensive loss at Jan. 1 $ (60 ) $ (64 ) $ (124 ) Other comprehensive loss before reclassifications (net of taxes of $(8) and $0, respectively) (23 ) — (23 ) Losses reclassified from net accumulated other comprehensive loss: Interest rate derivatives (net of taxes of $1 and $0, respectively) 3 (a) — 3 Amortization of net actuarial loss (net of taxes of $0 and $1, respectively) — 3 (b) 3 Net current period other comprehensive (loss) income (20 ) 3 (17 ) Accumulated other comprehensive loss at Dec. 31 $ (80 ) $ (61 ) $ (141 ) (a) Included in interest charges. (b) Included in the computation of net periodic pension and postretirement benefit costs. See Note 11 for further information. 2018 (Millions of Dollars) Gains and Losses on Cash Flow Hedges Defined Benefit Pension and Postretirement Items Total Accumulated other comprehensive loss at Jan. 1 $ (58 ) $ (67 ) $ (125 ) Other comprehensive loss before reclassifications (net of taxes of $(2) and $(2), respectively) (5 ) (6 ) (11 ) Losses reclassified from net accumulated other comprehensive loss: Interest rate derivatives (net of taxes of $1 and $0, respectively) 3 (a) — 3 Amortization of net actuarial loss (net of taxes of $0 and $3, respectively) — 9 (b) 9 Net current period other comprehensive (loss) income (2 ) 3 1 Accumulated other comprehensive loss at Dec. 31 $ (60 ) $ (64 ) $ (124 ) (a) Included in interest charges. (b) Included in the computation of net periodic pension and postretirement benefit costs. See Note 11 for further information.

Segments and Related Informatio

Segments and Related Information	12 Months Ended
	Dec. 31, 2019
Segment Reporting [Abstract]
Segment Information	Xcel Energy evaluates performance by each utility subsidiary based on profit or loss generated from the product or service provided, including 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. 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 - The 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. The regulated electric utility segment also includes wholesale commodity and trading operations; and • Regulated Natural Gas - The regulated natural gas utility segment transports, stores and distributes natural gas primarily in portions of Minnesota, Wisconsin, North Dakota, Michigan and Colorado. Xcel Energy presents Other, which includes operating segments, with revenues below the necessary quantitative thresholds. Those operating segments primarily include steam revenue, appliance repair services, non-utility 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 $155 million and $141 million as of Dec. 31, 2019 and 2018 , 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. As an integrated electric and natural gas utility, Xcel Energy operates significant assets that are not dedicated to a specific business segment. 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. Certain costs, such as common depreciation, common O&M expenses and interest expense are allocated based on cost causation allocators across each segment. In addition, a general allocator is used for certain general and administrative expenses, including office supplies, rent, property insurance and general advertising. Xcel Energy’s segment information: (Millions of Dollars) 2019 2018 2017 Regulated Electric Operating revenues from external customers $ 9,575 $ 9,719 $ 9,676 Intersegment revenue 1 1 2 Total revenues $ 9,576 $ 9,720 $ 9,678 Depreciation and amortization 1,535 1,421 1,298 Interest charges and financing costs 500 449 449 Income tax expense 125 187 528 Net income 1,288 1,177 1,066 Regulated Natural Gas Operating revenues from external customers $ 1,868 $ 1,739 $ 1,650 Intersegment revenue 2 2 1 Total revenues $ 1,870 $ 1,741 $ 1,651 Depreciation and amortization 219 212 174 Interest charges and financing costs 69 61 57 Income tax expense 48 28 23 Net income 195 187 182 Other Total operating revenue $ 86 $ 79 $ 78 Depreciation and amortization 11 9 7 Interest charges and financing costs 167 142 122 Income tax (benefit) (45 ) (34 ) (9 ) Net (loss) (111 ) (103 ) (100 ) Consolidated Total Total revenue $ 11,532 $ 11,540 $ 11,407 Reconciling eliminations (3 ) (3 ) (3 ) Consolidated total revenue $ 11,529 $ 11,537 $ 11,404 Depreciation and amortization 1,765 1,642 1,479 Interest charges and financing costs 736 652 628 Income tax expense 128 181 542 Net income 1,372 1,261 1,148

Summarized Quarterly Financial

Summarized Quarterly Financial Data (Unaudited)	12 Months Ended
	Dec. 31, 2019
Quarterly Financial Information Disclosure [Abstract]
Quarterly Financial Information [Text Block]	Quarter Ended (Amounts in millions, except per share data) March 31, 2019 June 30, 2019 Sept. 30, 2019 Dec. 31, 2019 Operating revenues $ 3,141 $ 2,577 $ 3,013 $ 2,798 Operating income 486 410 758 450 Net income 315 238 527 292 EPS total — basic $ 0.61 $ 0.46 $ 1.02 $ 0.56 EPS total — diluted 0.61 0.46 1.01 0.56 Cash dividends declared per common share 0.405 0.405 0.405 0.405 Quarter Ended (Amounts in millions, except per share data) March 31, 2018 June 30, 2018 Sept. 30, 2018 Dec. 31, 2018 Operating revenues $ 2,951 $ 2,658 $ 3,048 $ 2,880 Operating income (a) 480 450 696 339 Net income 291 265 491 214 EPS total — basic $ 0.57 $ 0.52 $ 0.96 $ 0.42 EPS total — diluted 0.57 0.52 0.96 0.42 Cash dividends declared per common share 0.380 0.380 0.380 0.380 (a)

Schedule I, Condensed Financial

Schedule I, Condensed Financial Statements of Xcel Energy Inc	12 Months Ended
	Dec. 31, 2019
Condensed Financial Information 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 2019 2018 2017 Income Equity earnings of subsidiaries $ 1,505 $ 1,393 $ 1,263 Total income 1,505 1,393 1,263 Expenses and other deductions Operating expenses 23 24 30 Other income (9 ) (1 ) (6 ) Interest charges and financing costs 173 149 128 Total expenses and other deductions 187 172 152 Income before income taxes 1,318 1,221 1,111 Income tax benefit (54 ) (40 ) (37 ) Net income $ 1,372 $ 1,261 $ 1,148 Other Comprehensive Income Pension and retiree medical benefits, net of tax of $1, $1 and $3, respectively $ 3 $ 3 $ 4 Derivative instruments, net of tax of $(7), $(1) and $2, respectively (20 ) (2 ) 3 Other comprehensive income (loss) (17 ) 1 7 Comprehensive income $ 1,355 $ 1,262 $ 1,155 Weighted average common shares outstanding: Basic 519 511 509 Diluted 520 511 509 Earnings per average common share: Basic $ 2.64 $ 2.47 $ 2.26 Diluted 2.64 2.47 2.25 See Notes to Condensed Financial Statements XCEL ENERGY INC. CONDENSED STATEMENTS OF CASH FLOWS (amounts in millions) Year Ended Dec. 31 2019 2018 2017 Operating activities Net cash provided by operating activities $ 1,389 $ 1,210 $ 1,208 Investing activities Capital contributions to subsidiaries (1,594 ) (809 ) (849 ) Investments in the utility money pool (1,054 ) (2,578 ) (1,258 ) Return of investments in the utility money pool 1,093 2,493 1,173 Net cash used in investing activities (1,555 ) (894 ) (934 ) Financing activities Proceeds from (repayment of) short-term borrowings, net 12 (295 ) 715 Proceeds from issuance of long-term debt 1,120 492 — Repayment of long-term debt (550 ) — (250 ) Proceeds from issuance of common stock 458 230 — Repurchase of common stock — (1 ) (3 ) Dividends paid (791 ) (730 ) (721 ) Other (14 ) (12 ) (14 ) Net cash (used in) provided by financing activities 235 (316 ) (273 ) Net change in cash and cash equivalents 69 — 1 Cash and cash equivalents at beginning of period 1 1 — Cash and cash equivalents at end of period $ 70 $ 1 $ 1 See Notes to Condensed Financial Statements XCEL ENERGY INC. CONDENSED BALANCE SHEETS (amounts in millions) Dec. 31 2019 2018 Assets Cash and cash equivalents $ 70 $ 1 Accounts receivable from subsidiaries 370 309 Other current assets 12 1 Total current assets 452 311 Investment in subsidiaries 17,443 15,965 Other assets 60 44 Total other assets 17,503 16,009 Total assets $ 17,955 $ 16,320 Liabilities and Equity Dividends payable 212 195 Short-term debt 500 488 Other current liabilities 33 10 Total current liabilities 745 693 Other liabilities 23 32 Total other liabilities 23 32 Commitments and contingencies Capitalization Long-term debt 3,948 3,373 Common stockholders’ equity 13,239 12,222 Total capitalization 17,187 15,595 Total liabilities and equity $ 17,955 $ 16,320 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 other comprehensive income 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. Guarantees and Indemnifications Xcel Energy Inc. provides 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. limit the exposure to a maximum stated amount. As of Dec. 31, 2019 and 2018, Xcel Energy Inc. had no assets held as collateral related to guarantees, bond indemnities and indemnification agreements. Guarantees and bond indemnities issued and outstanding as of Dec. 31, 2019: (Millions of Dollars) Guarantor Guarantee Amount Current Exposure Triggering Event Guarantee of loan for Hiawatha Collegiate High School (a) Xcel Energy Inc. $ 1.0 — (c) Guarantee performance and payment of surety bonds for Xcel Energy Inc.’s utility subsidiaries (b) Xcel Energy Inc. 60.4 (e) (d) (a) The term of this guarantee expires the earlier of 2024 or full repayment of the loan. (b) 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. (c) Nonperformance and/or nonpayment. (d) Per the indemnity agreement between Xcel Energy Inc. and the various surety companies, surety companies have the discretion to demand that collateral be posted. (e) 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. provides indemnifications through contracts entered into in the normal course of business. Indemnifications are primarily against adverse litigation outcomes in connection with underwriting agreements, breaches of representations and warranties, including corporate existence, transaction authorization and certain income tax matters. Obligations under these agreements may be limited in terms of duration or amount. Maximum future payments under these indemnifications cannot be reasonably estimated as the dollar amounts are often not explicitly stated. Related Party Transactions — Xcel Energy Inc. presents related party receivables net of payables. Accounts receivable and payable with affiliates at Dec. 31: 2019 2018 (Millions of Dollars) Accounts Receivable Accounts Payable Accounts Receivable Accounts Payable NSP-Minnesota $ 60 $ — $ 117 $ — NSP-Wisconsin 17 — 3 — PSCo 78 — 29 — SPS 47 — 39 — Xcel Energy Services Inc. 112 — 96 — Xcel Energy Ventures Inc. 25 — 13 — Other subsidiaries of Xcel Energy Inc. 31 — 12 — $ 370 $ — $ 309 $ — Dividends — Cash dividends paid to Xcel Energy Inc. by its subsidiaries were $2,987 million , $1,097 million and $1,063 million for the years ended Dec. 31, 2019 , 2018 and 2017 , respectively. These cash receipts are included in operating cash flows of the condensed statements of cash flows. Money Pool — FERC approval was received 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. Money pool lending for Xcel Energy Inc.: (Amounts in Millions, Except Interest Rates) Three Months Ended Dec. 31, 2019 Loan outstanding at period end $ 39 Average loan outstanding 35 Maximum loan outstanding 125 Weighted average interest rate, computed on a daily basis 1.67 % Weighted average interest rate at end of period 1.63 % Money pool interest income 1.47 % (Amounts in Millions, Except Interest Rates) Year Ended Dec. 31, 2019 Year Ended Dec. 31, 2018 Year Ended Loan outstanding at period end $ 39 $ — $ 85 Average loan outstanding 47 71 38 Maximum loan outstanding 250 243 226 Weighted average interest rate, computed on a daily basis 2.15 % 1.95 % 1.13 % Weighted average interest rate at end of period 1.63 % N/A 1.18 Money pool interest income $ 1.0 $ 1.4 $ 0.4 See notes to the consolidated financial statements in Part II, Item 8.

Schedule II, Valuation and Qual

Schedule II, Valuation and Qualifying Accounts	12 Months Ended
	Dec. 31, 2019
SEC Schedule, 12-09, Valuation and Qualifying Accounts [Abstract]
Schedule II, Valuation and Qualifying Accounts	Xcel Energy Inc. and Subsidiaries Valuation and Qualifying Accounts Years Ended Dec. 31 Allowance for bad debts NOL and tax credit valuation allowances (Millions of Dollars) 2019 2018 2017 2019 2018 2017 Balance at Jan. 1 $ 55 $ 52 $ 51 $ 79 $ 77 $ 58 Additions charged to costs and expenses 42 42 39 9 7 9 Additions charged to other accounts 16 (a) 11 (a) 10 (a) — — 22 (c) Deductions from reserves (58 ) (b) (50 ) (b) (48 ) (b) (21 ) (e) (5 ) (e) (12 ) (d) Balance at Dec. 31 $ 55 $ 55 $ 52 $ 67 $ 79 $ 77 (a) Recovery of amounts previously written off. (b) Deductions related primarily to bad debt write-offs. (c) Accrual of valuation allowances for North Dakota ITC, net of federal income tax benefit, that is offset to a regulatory liability and includes $14 million expense related to the revaluation of federal benefit as a result of the TCJA. (d) Primarily the reductions to valuation allowances for North Dakota ITC carryforwards, net of federal benefit, primarily due to a consolidated adjustment to the regulatory liability accrual referenced above; the change includes $4 million of reduced expense related to the revaluation of federal benefit as a result of TCJA. (e)

Summary of Significant Accoun_2

Summary of Significant Accounting Policies Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2019
Accounting Policies [Abstract]
Business and System of Accounts	Xcel Energy’s consolidated financial statements are presented in accordance with GAAP. All of the utility subsidiaries’ underlying accounting records also conform to the FERC uniform system of accounts. Certain amounts in the 2018 and 2017 consolidated financial statements or notes have been reclassified to conform to the 2019 presentation for comparative purposes; however, such reclassifications did not affect net income, total assets, liabilities, equity or cash flows. General — 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.
Principles of Consolidation	Xcel Energy’s regulated operations include the activities 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 regulated operations are WGI, an interstate natural gas pipeline company, and WYCO, a joint venture with CIG to develop and lease natural gas pipeline, storage and compression facilities. Xcel Energy Inc.’s nonregulated subsidiaries include Eloigne, Capital Services and the newly formed MEC Holdings LLC. 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, Xcel Energy Venture Holdings Inc. 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. All intercompany transactions and balances are eliminated, unless a different treatment is appropriate for rate regulated transactions. 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 certain 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. Xcel Energy’s consolidated financial statements are presented in accordance with GAAP. All of the utility subsidiaries’ underlying accounting records also conform to the FERC uniform system of accounts. Certain amounts in the 2018 and 2017 consolidated financial statements or notes have been reclassified to conform to the 2019 presentation for comparative purposes; however, such reclassifications did not affect net income, total assets, liabilities, equity or cash flows. Xcel Energy has evaluated events occurring after Dec. 31, 2019 up to the date of issuance of these consolidated financial statements. These statements contain all necessary adjustments and disclosures resulting from that evaluation.
Subsequent Events	Xcel Energy has evaluated events occurring after Dec. 31, 2019 up to the date of issuance of these consolidated financial statements. These statements contain all necessary adjustments and disclosures resulting from that evaluation.
Use of Estimates	Use of Estimates — Xcel Energy uses estimates based on the best information available in recording transactions and balances resulting from business operations. Estimates are used on items such 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. Recorded estimates are revised when better information becomes available or actual amounts can be determined. Revisions can affect operating results.
Regulatory Accounting	Regulatory Accounting — Xcel Energy Inc.’s regulated utility subsidiaries account for 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 other comprehensive income, 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 other comprehensive income, 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 changes in the regulatory environment occur, the 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 results of operations, financial condition and cash flows. See Note 4 for further information.
Income Taxes	Income Taxes — Xcel Energy accounts for income taxes using the asset and liability method, which requires 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 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 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. Reversal of certain temporary differences are accounted for as current income tax expense 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. 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 regulatory assets and liabilities related to income taxes. 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. 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 expense. Xcel Energy reports interest and penalties related to income taxes within the other income and interest charges in the consolidated statements of income. Xcel Energy Inc. and its subsidiaries file consolidated federal income tax returns as well as consolidated or separate state income tax returns. Federal income taxes paid by Xcel Energy Inc. are allocated to its subsidiaries based on separate company computations. A similar allocation is made for state income taxes paid by Xcel Energy Inc. in connection with consolidated state filings. Xcel Energy Inc. also allocates its own income tax benefits to its direct subsidiaries. See Note 7 for further information.
Property, Plant and Equipment and Depreciation	Property, Plant and Equipment and Depreciation in Regulated Operations — 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 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 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. 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 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 3.3 % for 2019, 3.1 % for 2018 and 2017. See Note 3 for further information.
Asset Retirement Obligations	AROs — Xcel Energy accounts 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. The 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 consolidated balance sheets as a regulatory liability. See Note 12 for further information.
Nuclear Decommissioning	Nuclear Decommissioning — Nuclear decommissioning studies that estimate NSP-Minnesota’s costs of decommissioning its nuclear power plants are performed at least every three years and submitted to the state commissions for approval. For ratemaking purposes, NSP-Minnesota recovers regulator-approved decommissioning costs of its nuclear power plants over each facility’s expected service life, typically based on the triennial decommissioning studies. 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. For financial reporting purposes, NSP-Minnesota accounts for nuclear decommissioning as an ARO. 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 10 and 12 for further information.
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 requires management to make various assumptions and estimates. Certain unrecognized actuarial gains and losses and unrecognized prior service costs or credits are deferred as regulatory assets and liabilities, rather than recorded as other comprehensive income, based on regulatory recovery mechanisms. See Note 11 for further information.
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 are regularly adjusted as estimates are revised and remediation proceeds. If other participating potentially responsible parties exist and acknowledge their potential involvement with a site, costs are estimated and recorded only for Xcel Energy’s expected share of the cost. Future costs of restoring sites are treated as a capitalized cost of plant retirement. The depreciation expense levels recoverable in rates include a provision for removal expenses. Removal costs recovered in rates before the related costs are incurred are classified as a regulatory liability. See Note 12 for further information.
Revenue From Contracts With Customers	Revenue from Contracts with Customers — Performance obligations related to the sale of energy are satisfied as energy is delivered to customers. Xcel Energy recognizes revenue that corresponds to the price of the energy delivered to the customer. The measurement of energy sales to customers is generally based on the reading of their meters, which occurs on a systematic basis throughout the month. At the end of each month, amounts of energy delivered to customers since the date of the last meter reading are estimated, and the corresponding unbilled revenue is recognized. Xcel Energy does not recognize a separate financing component of its collections from customers as contract terms are short-term in nature. Xcel Energy presents its revenues net of any excise or sales taxes or fees. The utility subsidiaries recognize sales to customers on a gross basis in electric revenues and cost of sales. Revenues and charges for short term wholesale sales of excess energy transacted through RTOs are also recorded on a gross basis. Other RTO revenues and charges are recorded on a net basis in cost of sales. See Note 6 for further information.
Cash and Cash Equivalents	Cash and Cash Equivalents — Xcel Energy considers investments in instruments 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. At both Dec. 31, 2019 and 2018, the allowance for bad debts was $55 million
Inventory	Inventory — Inventory is recorded at average cost and consisted of the following: (Millions of Dollars) Dec. 31, 2019 Dec. 31, 2018 Inventories Materials and supplies $ 270 $ 271 Fuel 191 170 Natural gas 83 107 Total inventories $ 544 $ 548
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 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, 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 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 10 and 11 for further information.
Derivative Instruments	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. Any derivative instruments not qualifying for the normal purchases and normal sales exception are recorded on the consolidated balance sheets at fair value as derivative instruments. 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. 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. Normal Purchases and Normal Sales — Xcel Energy enters into contracts for purchases and sales of commodities for use in its operations. At inception, contracts are evaluated to determine whether a derivative exists and/or whether an instrument may be exempted from derivative accounting if designated as a normal purchase or normal sale. See Note 10 for further information.
Commodity Trading Operations	Commodity Trading Operations — All applicable gains and losses related to commodity trading activities are shown on a net basis in electric operating revenues in the consolidated statements of income. 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 10 for further information.
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 rates.
Alternative Revenue Programs	Alternative Revenue — Certain rate rider mechanisms (including decoupling and CIP/DSM programs) qualify as alternative revenue programs. These mechanisms arise from costs imposed upon the utility by action of a regulator or legislative body related to an environmental, public safety or other mandate. When certain criteria are met, including expected collection within 24 months , revenue is recognized equal to the revenue requirement, which may include incentives and return on rate base items. Billing amounts are revised periodically for differences between total amount collected and revenue earned, which may increase or decrease the level of revenue collected from customers. Alternative revenues arising from these programs are presented on a gross basis and disclosed separately from revenue from contracts with customers. See Note 6 for further information. Conservation Programs — Costs incurred for DSM and CIP programs are deferred if it is probable future revenue will recover the incurred cost. Revenues recognized for incentive programs for the recovery of lost margins and/or conservation performance incentives are limited to amounts expected to be collected within 24 months from the year they are earned. Regulatory assets are recognized to reflect the amount of costs or earned incentives that have not yet been collected from customers.
Emission Allowances	Emission Allowances — Emission allowances are recorded at cost, including broker commission fees. The inventory accounting model is utilized for all emission allowances and sales of these allowances are included in electric revenues.
Nuclear Refueling Outage Costs	Nuclear Refueling Outage Costs — Xcel Energy uses a deferral and amortization method for nuclear refueling costs. This method amortizes costs over the period between refueling outages consistent with rate recovery.
Renewable Energy Credits	RECs — Cost of RECs that are utilized for compliance is recorded as electric fuel and purchased power expense. In certain jurisdictions, Xcel Energy reduces recoverable fuel costs for the cost of RECs and records that cost as a regulatory asset when the amount is recoverable in future rates. Sales of RECs are recorded in electric revenues on a gross basis. The cost of these RECs and amounts credited to customers under margin-sharing mechanisms are recorded in electric fuel and purchased power expense. Cost of RECs that are utilized to support commodity trading activities are recorded in a similar manner as the associated commodities and are shown on a net basis in electric operating revenues in the consolidated statements of income.

Summary of Significant Accoun_3

Summary of Significant Accounting Policies Inventory (Tables)	12 Months Ended
	Dec. 31, 2019
Balance Sheet Related Disclosure - Inventory [Abstract]
Public Utilities, Inventory	Inventory is recorded at average cost and consisted of the following: (Millions of Dollars) Dec. 31, 2019 Dec. 31, 2018 Inventories Materials and supplies $ 270 $ 271 Fuel 191 170 Natural gas 83 107 Total inventories $ 544 $ 548

Property Plant and Equipment _2

Property Plant and Equipment Property Plant and Equipment (Tables)	12 Months Ended
	Dec. 31, 2019
Property, Plant and Equipment [Line Items]
Public Utility Property, Plant, and Equipment	Major classes of property, plant and equipment (Millions of Dollars) Dec. 31, 2019 Dec. 31, 2018 Property, plant and equipment Electric plant $ 44,355 $ 41,472 Natural gas plant 6,560 6,210 Common and other property 2,341 2,154 Plant to be retired (a) 259 322 CWIP 2,329 2,091 Total property, plant and equipment 55,844 52,249 Less accumulated depreciation (16,735 ) (15,659 ) Nuclear fuel 2,909 2,771 Less accumulated amortization (2,535 ) (2,417 ) Property, plant and equipment, net $ 39,483 $ 36,944 (a) In 2018, the CPUC approved early retirement of PSCo’s Comanche Units 1 and 2 in approximately 2022 and 2025, respectively. PSCo also expects Craig Unit 1 to be retired early in 2025. Amounts are presented net of accumulated depreciation.
NSP Minnesota
Property, Plant and Equipment [Line Items]
Schedule of Jointly Owned Utility Plants	(Millions of Dollars) Plant in Service Accumulated Depreciation CWIP Percent Owned NSP-Minnesota Electric generation: Sherco Unit 3 $ 603 $ 426 $ 4 59 % Sherco common facilities 145 103 2 80 Sherco substation 5 3 — 59 Electric transmission: CapX2020 972 92 2 51 Grand Meadow 11 3 — 50 Total NSP-Minnesota $ 1,736 $ 627 $ 8
NSP-Wisconsin
Property, Plant and Equipment [Line Items]
Schedule of Jointly Owned Utility Plants	(Millions of Dollars) Plant in Service Accumulated Depreciation CWIP Percent Owned NSP-Wisconsin Electric transmission: La Crosse, WI to Madison, WI $ 187 $ 7 $ — 37 % CapX2020 169 19 — 80 Total NSP-Wisconsin $ 356 $ 26 $ —
PSCo
Property, Plant and Equipment [Line Items]
Schedule of Jointly Owned Utility Plants	(Millions of Dollars) Plant in Service Accumulated Depreciation CWIP Percent Owned PSCo Electric generation: Hayden Unit 1 $ 152 $ 81 $ — 76 % Hayden Unit 2 149 71 — 37 Hayden common facilities 41 22 — 53 Craig Units 1 and 2 81 41 — 10 Craig common facilities 39 22 — 7 Comanche Unit 3 887 149 1 67 Comanche common facilities 29 3 — 82 Electric transmission: Transmission and other facilities 174 62 1 Various Gas transmission: Rifle, CO to Avon, CO 22 7 — 60 Gas transmission compressor 9 1 — 50 Total PSCo $ 1,583 $ 459 $ 2

Regulatory Assets and Liabili_2

Regulatory Assets and Liabilities (Tables)	12 Months Ended
	Dec. 31, 2019
Regulatory Assets and Liabilities Disclosure [Abstract]
Regulatory Assets	Components of regulatory assets: (Millions of Dollars) See Note(s) Remaining Dec. 31, 2019 Dec. 31, 2018 Regulatory Assets Current Noncurrent Current Noncurrent Pension and retiree medical obligations 11 Various $ 85 $ 1,328 $ 87 $ 1,500 Recoverable deferred taxes on AFUDC recorded in plant Plant lives — 271 — 264 Net AROs (a) 1, 12 Plant lives — 269 — 452 Excess deferred taxes — TCJA 7 Various 39 239 — 296 Depreciation differences One to twelve years 15 140 18 107 Environmental remediation costs 1, 12 Various 36 131 17 155 Benson biomass PPA termination and asset purchase Ten years 9 73 10 86 Contract valuation adjustments (b) 1, 10 Term of related contract 20 62 17 77 Purchased power contract costs Term of related contract 5 61 4 63 Laurentian biomass PPA termination Five years 19 54 18 73 PI extended power uprate Sixteen years 3 53 3 56 Losses on reacquired debt Term of related debt 4 41 4 44 State commission adjustments Plant lives 1 31 1 29 Property tax Various 2 30 14 10 Conservation programs (c) 1 One to two years 27 26 42 28 Nuclear refueling outage costs 1 One to two years 43 17 37 14 Sales true-up and revenue decoupling One to two years 54 16 38 7 Renewable resources and environmental initiatives One to two years 72 10 39 9 Gas pipeline inspection and remediation costs One to two years 26 8 28 3 Deferred purchased natural gas and electric energy costs One to three years 6 6 57 13 Other Various 22 69 30 40 Total regulatory assets $ 488 $ 2,935 $ 464 $ 3,326 (a) Includes amounts recorded for future recovery of AROs, less amounts recovered through nuclear decommissioning accruals and gains from decommissioning investments. (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.
Regulatory Liabilities	Components of regulatory liabilities: (Millions of Dollars) See Note(s) Remaining Dec. 31, 2019 Dec. 31, 2018 Regulatory Liabilities Current Noncurrent Current Noncurrent Deferred income tax adjustments and TCJA refunds (a) 7 Various $ 75 $ 3,523 $ 157 $ 3,715 Plant removal costs 1, 12 Plant lives — 1,217 — 1,175 Effects of regulation on employee benefit costs (b) Various — 196 — 137 Renewable resources and environmental initiatives Various — 45 9 54 ITC deferrals (c) 1 Various — 38 — 40 Deferred electric, natural gas and steam production costs Less than one year 138 — 102 — Contract valuation adjustments (d) 1, 10 Less than one year 19 — 26 — Conservation programs (e) 1 Less than one year 37 — 36 — DOE settlement Less than one year 37 — 19 — Other Various 101 58 87 66 Total regulatory liabilities (f) $ 407 $ 5,077 $ 436 $ 5,187 (a) Includes the revaluation of recoverable/regulated plant ADIT and revaluation impact of non-plant ADIT due to the TCJA. (b) Includes regulatory amortization and certain 2018 TCJA benefits approved by the CPUC to offset the PSCo prepaid pension asset. (c) Includes impact of lower federal tax rate due to the TCJA. (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. (f) Revenue subject to refund of $28 million and $29 million for 2019 and 2018, respectively, is included in other current liabilities.

Borrowings and Other Financin_2

Borrowings and Other Financing Instruments Borrowings and Other Financing Instruments (Tables)	12 Months Ended
	Dec. 31, 2019
Debt Disclosure [Abstract]
Schedule of Stock by Class [Table Text Block]	Capital Stock — Preferred stock authorized/outstanding: Preferred Stock Authorized (Shares) Par Value of Preferred Stock Preferred Stock Outstanding (Shares) 2019 and 2018 Xcel Energy Inc. 7,000,000 $ 100 — PSCo 10,000,000 0.01 — SPS 10,000,000 1.00 — Xcel Energy Inc. had the following common stock authorized/outstanding: Common Stock Authorized (Shares) Par Value of Common Stock Common Stock Outstanding (Shares) as of Dec. 31, 2019 Common Stock Outstanding (Shares) as of Dec. 31, 2018 1,000,000,000 $ 2.50 524,539,000 514,036,787
Commercial Paper	Term loan borrowings as of Dec. 31, 2019: (Millions of Dollars) Limit Amount Used Available Xcel Energy Inc. $ 500 $ 500 $ — Commercial paper and term loan borrowings outstanding: (Millions of Dollars, Except Interest Rates) Three Months Ended Dec. 31, 2019 Year Ended Dec. 31 2019 2018 2017 Borrowing limit $ 3,600 $ 3,600 $ 3,250 $ 3,250 Amount outstanding at period end 595 595 1,038 814 Average amount outstanding 663 1,115 788 644 Maximum amount outstanding 945 1,780 1,349 1,247 Weighted average interest rate, computed on a daily basis 2.40 % 2.72 % 2.34 % 1.35 % Weighted average interest rate at end of period 2.34 2.34 2.97 1.90
Schedule of Debt To Total Capitalization Ratio	Features of the credit facilities: Debt-to-Total Capitalization Ratio (a) Amount Facility May Be Increased (millions) Additional Periods for Which a One-Year Extension May Be Requested (b) 2019 2018 Xcel Energy Inc. (c) 58 % 58 % $ 200 2 NSP-Wisconsin 48 48 N/A 1 NSP-Minnesota 48 48 100 2 SPS 46 46 50 2 PSCo 44 46 100 2 (a) Each credit facility has a financial covenant requiring that the debt-to-total capitalization ratio be less than or equal to 65% . (b) All extension requests are subject to majority bank group approval. (c) The Xcel Energy Inc. credit facility has a cross-default provision that 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% of Xcel Energy’s consolidated total assets) default on indebtedness in an aggregate principal amount exceeding $75 million .
Credit Facilities	Xcel Energy Inc. and its utility subsidiaries had the following committed credit facilities available as of Dec. 31, 2019 : (Millions of Dollars) Credit Facility (a) Drawn (b) Available Xcel Energy Inc. $ 1,250 $ — $ 1,250 PSCo 700 9 691 NSP-Minnesota 500 2 498 SPS 500 40 460 NSP-Wisconsin 150 65 85 Total $ 3,100 $ 116 $ 2,984 (a) These credit facilities mature in June 2024 . (b) Includes outstanding commercial paper and letters of credit. As of Dec. 31, 2019 , outstanding letters of credit under the Bilateral Credit Agreement were as follows: (Millions of Dollars) Limit Amount Used Available NSP-Minnesota $ 75 $ 22 $ 53
Schedule of Maturities of Long-term Debt	Maturities of long-term debt: (Millions of Dollars) 2020 $ 702 2021 421 2022 900 2023 650 2024 552
Capital Stock	Long term debt obligations for Xcel Energy Inc. and its utility subsidiaries as of Dec. 31 (Millions of Dollars): Xcel Energy Inc. Financing Instrument Interest Rate Maturity Date 2019 2018 Unsecured senior notes (d) 4.70 % May 15, 2020 $ — $ 550 Unsecured senior notes 2.40 March 15, 2021 400 400 Unsecured senior notes 2.60 March 15, 2022 300 300 Unsecured senior notes 3.30 June 1, 2025 250 250 Unsecured senior notes 3.30 June 1, 2025 350 350 Unsecured senior notes 3.35 Dec. 1, 2026 500 500 Unsecured senior notes (a) 4.00 June 15, 2028 130 — Unsecured senior notes (b) 4.00 June 15, 2028 500 500 Unsecured senior notes (a) 2.60 Dec. 1, 2029 500 — Unsecured senior notes 6.50 July 1, 2036 300 300 Unsecured senior notes 4.80 Sept. 15, 2041 250 250 Unsecured senior notes (a) 3.50 Dec. 1, 2049 500 — Elimination of PSCo capital lease obligation with affiliates (c) — (60 ) Unamortized discount (5 ) (5 ) Unamortized debt issuance cost (28 ) (21 ) Current maturities (capital lease obligation) (c) — 2 Total long-term debt $ 3,947 $ 3,316 (a) 2019 financing. (b) 2018 financing. (c) Xcel Energy adopted ASC 842 on Jan. 1, 2019, which refers to capital leases as finance leases. Under ASC 842, the present value of future finance lease payments is included in other current liabilities and other noncurrent liabilities rather than debt. (d) Note was redeemed on Dec. 23, 2019. NSP-Minnesota Financing Instrument Interest Rate Maturity Date 2019 2018 First mortgage bonds 2.20 % Aug. 15, 2020 $ 300 $ 300 First mortgage bonds 2.15 Aug. 15, 2022 300 300 First mortgage bonds 2.60 May 15, 2023 400 400 First mortgage bonds 7.13 July 1, 2025 250 250 First mortgage bonds 6.50 March 1, 2028 150 150 First mortgage bonds 5.25 July 15, 2035 250 250 First mortgage bonds 6.25 June 1, 2036 400 400 First mortgage bonds 6.20 July 1, 2037 350 350 First mortgage bonds 5.35 Nov. 1, 2039 300 300 First mortgage bonds 4.85 Aug. 15, 2040 250 250 First mortgage bonds 3.40 Aug. 15, 2042 500 500 First mortgage bonds 4.13 May 15, 2044 300 300 First mortgage bonds 4.00 Aug. 15, 2045 300 300 First mortgage bonds 3.60 May 15, 2046 350 350 First mortgage bonds 3.60 Sept. 15, 2047 600 600 First mortgage bonds (a) 2.90 March 1, 2050 600 — Unamortized discount (31 ) (21 ) Unamortized debt issuance cost (48 ) (42 ) Current maturities (300 ) — Total long-term debt $ 5,221 $ 4,937 (a) 2019 financing. NSP-Wisconsin Financing Instrument Interest Rate Maturity Date 2019 2018 City of La Crosse resource recovery bond 6.00 % Nov 1, 2021 $ 19 $ 19 First mortgage bonds 3.30 June 15, 2024 100 100 First mortgage bonds 3.30 June 15, 2024 100 100 First mortgage bonds 6.38 Sept. 1, 2038 200 200 First mortgage bonds 3.70 Oct. 1, 2042 100 100 First mortgage bonds 3.75 Dec. 1, 2047 100 100 First mortgage bonds (a) 4.20 Sept. 1, 2048 200 200 Unamortized discount (3 ) (3 ) Unamortized debt issuance cost (8 ) (9 ) Total long-term debt $ 808 $ 807 (a) 2018 financing. PSCo Financing Instrument Interest Rate Maturity Date 2019 2018 First mortgage bonds (d) 5.13 % June 1, 2019 $ — $ 400 First mortgage bonds 3.20 Nov. 15, 2020 400 400 First mortgage bonds 2.25 Sept. 15, 2022 300 300 First mortgage bonds 2.50 March 15, 2023 250 250 First mortgage bonds 2.90 May 15, 2025 250 250 First mortgage bonds (b) 3.70 June 15, 2028 350 350 First mortgage bonds 6.25 Sept. 1, 2037 350 350 First mortgage bonds 6.50 Aug. 1, 2038 300 300 First mortgage bonds 4.75 Aug. 15, 2041 250 250 First mortgage bonds 3.60 Sept. 15, 2042 500 500 First mortgage bonds 3.95 March 15, 2043 250 250 First mortgage bonds 4.30 March 15, 2044 300 300 First mortgage bonds 3.55 June 15, 2046 250 250 First mortgage bonds 3.80 June 15, 2047 400 400 First mortgage bonds (b) 4.10 June 15, 2048 350 350 First mortgage bonds (a) 4.05 Sept. 15, 2049 400 — First mortgage bonds (a) 3.20 March 1, 2050 550 — Capital lease obligations (c) 11.20 - 14.30 2025 - 2060 — 145 Unamortized discount (24 ) (14 ) Unamortized debt issuance cost (41 ) (33 ) Current maturities (400 ) (406 ) Total long-term debt $ 4,985 $ 4,592 (a) 2019 financing. (b) 2018 financing. (c) PSCo adopted ASC 842 on Jan. 1, 2019, which refers to capital leases as finance leases. Under ASC 842, the present value of future finance lease payments is included in other current liabilities and other noncurrent liabilities rather than debt. (d) Bond was redeemed on March 29, 2019.
Other Capital Restrictions	Amounts authorized to issue as of Dec. 31, 2019 : (Millions of Dollars) Long-Term Debt Short-Term Debt NSP-Minnesota 52.93% of total capitalization (a) $ 1,905 (a) NSP-Wisconsin $ — (b) 150 SPS — (c) 600 PSCo 150 800 (a) NSP-Minnesota has authorization to issue long-term securities provided the equity-to-total capitalization remains within the required range, and to issue short-term debt provided it does not exceed 15% of total capitalization. (b) NSP-Wisconsin filed for additional long-term debt authorization in December 2019. (c) SPS filed for additional long-term debt authorization in February 2020.
Share-based Payment Arrangement, Restricted Stock and Restricted Stock Unit, Activity [Table Text Block]	Requirements and actuals as of Dec. 31, 2019: Equity to Total Capitalization Ratio Required Range Equity to Total Capitalization Ratio Actual Low High 2019 NSP-Minnesota 47.1 % 57.5 % 52.3 % NSP-Wisconsin 51.5 N/A 51.8 SPS (a) 45.0 55.0 54.4 (a) Excludes short-term debt. (Amounts in Millions) Unrestricted Retained Earnings Total Capitalization Limit on Total Capitalization NSP-Minnesota $ 1,147 $ 11,634 $ 12,700 NSP-Wisconsin (a) 12 1,827 N/A SPS (b) 535 5,304 N/A (a) Cannot pay annual dividends in excess of approximately $55 million if its average equity-to-total capitalization ratio falls below the commission authorized level. (b)

Revenues (Tables)

Revenues (Tables)	12 Months Ended
	Dec. 31, 2019
Revenue from Contract with Customer [Abstract]
Disaggregation of Revenue	Xcel Energy’s operating revenues consisted of the following: Year Ended Dec. 31, 2019 (Millions of Dollars) Electric Natural Gas All Other Total Major revenue types Revenue from contracts with customers: Residential $ 2,877 $ 1,127 $ 41 $ 4,045 C&I 4,844 567 29 5,440 Other 130 — 4 134 Total retail 7,851 1,694 74 9,619 Wholesale 737 — — 737 Transmission 507 — — 507 Other 49 120 — 169 Total revenue from contracts with customers 9,144 1,814 74 11,032 Alternative revenue and other 431 54 12 497 Total revenues $ 9,575 $ 1,868 $ 86 $ 11,529 Year Ended Dec. 31, 2018 (Millions of Dollars) Electric Natural Gas All Other Total Major revenue types Revenue from contracts with customers: Residential $ 2,919 $ 988 $ 38 $ 3,945 C&I 4,874 524 25 5,423 Other 134 — 6 140 Total retail 7,927 1,512 69 9,508 Wholesale 791 — — 791 Transmission 523 — — 523 Other 98 100 — 198 Total revenue from contracts with customers 9,339 1,612 69 11,020 Alternative revenue and other 380 127 10 517 Total revenues $ 9,719 $ 1,739 $ 79 $ 11,537

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2019
Income Tax Disclosure [Abstract]
Summary of Statute of Limitations Applicable to Open Tax Years [Table Text Block]	Statute of limitations applicable to Xcel Energy’s consolidated federal income tax returns: Tax Year(s) Expiration 2009 - 2013 June 2020 2014 - 2016 September 2020
Earliest Open Tax Years Subject to Examination by State Taxing Authorities in the Major Operating Jurisdictions	Xcel Energy files consolidated state tax returns based on income in its major operating jurisdictions and various other state income-based tax returns. As of Dec. 31, 2019 , Xcel Energy’s earliest open tax years (subject to examination by state taxing authorities in its major operating jurisdictions) were as follows: State Year Colorado 2009 Minnesota 2009 Texas 2009 Wisconsin 2014 • In 2018, Wisconsin began an audit of tax years 2014 - 2016 . As of Dec. 31, 2019, no material adjustments have been proposed. •
Reconciliation of Unrecognized Tax Benefits	Unrecognized tax benefits - permanent vs. temporary: (Millions of Dollars) Dec. 31, 2019 Dec. 31, 2018 Unrecognized tax benefit — Permanent tax positions $ 35 $ 28 Unrecognized tax benefit — Temporary tax positions 9 9 Total unrecognized tax benefit $ 44 $ 37 Changes in unrecognized tax benefits: (Millions of Dollars) 2019 2018 2017 Balance at Jan. 1 $ 37 $ 39 $ 134 Additions based on tax positions related to the current year 10 9 6 Reductions based on tax positions related to the current year (4 ) (4 ) (4 ) Additions for tax positions of prior years 1 2 15 Reductions for tax positions of prior years — (4 ) (105 ) Settlements with taxing authorities — (5 ) (7 ) Balance at Dec. 31 $ 44 $ 37 $ 39
Tax Benefits Associated with NOL and Tax Credit Carryforwards	Unrecognized tax benefits were reduced by tax benefits associated with NOL and tax credit carryforwards: (Millions of Dollars) Dec. 31, 2019 Dec. 31, 2018 NOL and tax credit carryforwards $ (40 ) $ (35 )
NOL and Tax Credit Carryforwards	NOL amounts represent the tax loss that is carried forward and tax credits represent the deferred tax asset. NOL and tax credit carryforwards as of Dec. 31: (Millions of Dollars) 2019 2018 Federal tax credit carryforwards $ 639 $ 553 Valuation allowances for federal credit carryforwards — (5 ) State NOL carryforwards 937 1,104 Valuation allowances for state NOL carryforwards (19 ) (50 ) State tax credit carryforwards, net of federal detriment (a) 89 89 Valuation allowances for state credit carryforwards, net of federal benefit (b) (66 ) (69 ) (a) State tax credit carryforwards are net of federal detriment of $24 million as of Dec. 31, 2019 and 2018. (b) Valuation allowances for state tax credit carryforwards were net of federal benefit of $17 million and $18 million as of Dec. 31, 2019 and 2018, respectively.
Schedule of Effective Income Tax Rate Reconciliation	Effective income tax rate for years ended Dec. 31: 2019 2018 (a) 2017 (a) Federal statutory rate 21.0 % 21.0 % 35.0 % State income tax on pretax income, net of federal tax effect 4.9 5.0 4.1 Increases (decreases) in tax from: Wind PTCs (9.4 ) (5.2 ) (4.7 ) Plant regulatory differences (b) (5.8 ) (6.2 ) (0.8 ) Other tax credits, net of NOL & tax credit allowances (1.7 ) (1.7 ) (1.0 ) Change in unrecognized tax benefits 0.5 0.4 (0.6 ) Tax reform — — 1.4 Other, net (1.0 ) (0.7 ) (1.3 ) Effective income tax rate 8.5 % 12.6 % 32.1 % (a) Prior periods have been reclassified to conform to current year presentation. (b) Regulatory differences for income tax primarily relate to the credit of excess deferred taxes to customers through the average rate assumption method. Income tax benefits associated with the credit of excess deferred credits are offset by corresponding revenue reductions and additional prepaid pension asset amortization.
Schedule of Components of Income Tax Expense (Benefit)	Components of income tax expense for years ended Dec. 31: (Millions of Dollars) 2019 2018 2017 Current federal tax (benefit) expense $ (16 ) $ (34 ) $ 1 Current state tax expense (benefit) 4 8 (11 ) Current change in unrecognized tax expense (benefit) 2 (6 ) (83 ) Deferred federal tax expense 55 122 460 Deferred state tax expense 83 85 107 Deferred change in unrecognized tax expense 5 11 73 Deferred ITCs (5 ) (5 ) (5 ) Total income tax expense $ 128 $ 181 $ 542 Components of deferred income tax expense as of Dec. 31: (Millions of Dollars) 2019 2018 2017 Deferred tax expense (benefit) excluding items below $ 344 $ 320 $ (2,939 ) Amortization and adjustments to deferred income taxes on income tax regulatory assets and liabilities (206 ) (102 ) 3,583 Tax benefit (expense) allocated to other comprehensive income, net of adoption of ASU No. 2018-02, and other 5 — (4 ) Deferred tax expense $ 143 $ 218 $ 640
Schedule of Deferred Tax Assets and Liabilities	Components of net deferred tax liability as of Dec. 31: (Millions of Dollars) 2019 2018 (a) Deferred tax liabilities: Differences between book and tax bases of property $ 5,474 $ 5,082 Operating lease assets 449 — Regulatory assets 598 599 Pension expense 173 178 Other 70 60 Total deferred tax liabilities $ 6,764 $ 5,919 Deferred tax assets: Regulatory liabilities $ 847 $ 879 Operating lease liabilities 449 — Tax credit carryforward 727 642 NOL carryforward 38 51 NOL and tax credit valuation allowances (67 ) (79 ) Other employee benefits 128 124 Deferred ITCs 14 16 Rate refund 26 60 Other 93 61 Total deferred tax assets $ 2,255 $ 1,754 Net deferred tax liability $ 4,509 $ 4,165 (a) Prior periods have been reclassified to conform to current year presentation.

Share-Based Compensation (Table

Share-Based Compensation (Tables)	12 Months Ended
	Dec. 31, 2019
Share-based Payment Arrangement [Abstract]
Restricted Stock	Shares of restricted stock granted at Dec. 31: (Shares in Thousands) 2019 2018 2017 Granted shares 13 18 15 Grant date fair value $ 53.46 $ 44.68 $ 42.00 Changes in nonvested restricted stock: (Shares in Thousands) Shares Weighted Average Nonvested restricted stock at Jan. 1, 2019 36 $ 44.29 Granted 13 53.46 Forfeited — — Vested (19 ) 41.60 Dividend equivalents 1 57.09 Nonvested restricted stock at Dec. 31, 2019 31 50.15
Other Equity Awards	Equity award units granted to employees (excluding restricted stock): (Units in Thousands) 2019 2018 2017 Granted units 483 500 503 Weighted average grant date fair value $ 49.67 $ 47.60 $ 41.02 Equity awards vested: (Units in Thousands) 2019 2018 2017 Vested Units 464 475 467 Total Fair Value $ 29,432 $ 23,393 $ 22,459 Changes in the nonvested portion of equity award units: (Units in Thousands) Units Weighted Average Nonvested Units at Jan. 1, 2019 939 $ 44.30 Granted 483 49.67 Forfeited (116 ) 50.19 Vested (464 ) 41.09 Dividend equivalents 38 45.22 Nonvested Units at Dec. 31, 2019 880 48.20
Stock Equivalent Unit Plan	Stock equivalent units granted: (Units in Thousands) 2019 2018 2017 Granted units 29 36 51 Weighted average grant date fair value $ 58.44 $ 45.44 $ 46.05 Changes in stock equivalent units: (Units in Thousands) Units Weighted Average Stock equivalent units at Jan. 1, 2019 688 $ 30.93 Granted 29 58.44 Units distributed (11 ) 32.56 Dividend equivalents 19 57.28 Stock equivalent units at Dec. 31, 2019 725 32.72
TSR Liability Awards	TSR liability awards granted: (In Thousands) 2019 2018 2017 Awards granted 225 239 240 TSR liability awards settled: (In Thousands) 2019 2018 2017 Awards settled 466 482 454 Settlement amount (cash, common stock and deferred amounts) $ 24,930 $ 21,534 $ 19,083
Compensation costs related to share-based awards	Compensation costs related to share-based awards: (Millions of Dollars) 2019 2018 2017 Compensation cost for share-based awards (a) $ 58 $ 45 $ 57 Tax benefit recognized in income 15 12 22 (a) Compensation costs for share-based payment are included in O&M expense.

Fair Value of Financial Asset_2

Fair Value of Financial Assets and Liabilities (Tables)	12 Months Ended
	Dec. 31, 2019
Fair Value Disclosures [Abstract]
Cost and Fair Value of Nuclear Decommissioning Fund Investments	Non-derivative instruments with recurring fair value measurements: Dec. 31, 2019 Fair Value (Millions of Dollars) Cost Level 1 Level 2 Level 3 NAV Total Nuclear decommissioning fund (a) Cash equivalents $ 33 $ 33 $ — $ — $ — $ 33 Commingled funds 733 — — — 935 935 Debt securities 489 — 495 13 — 508 Equity securities 485 962 2 — — 964 Total $ 1,740 $ 995 $ 497 $ 13 $ 935 $ 2,440 (a) Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $155 million of equity investments in unconsolidated subsidiaries and $136 million of rabbi trust assets and miscellaneous investments. Dec. 31, 2018 Fair Value (Millions of Dollars) Cost Level 1 Level 2 Level 3 NAV Total Nuclear decommissioning fund (a) Cash equivalents $ 24 $ 24 $ — $ — $ — $ 24 Commingled funds 758 79 — — 819 898 Debt securities 466 — 436 — — 436 Equity securities 401 697 — — — 697 Total $ 1,649 $ 800 $ 436 $ — $ 819 $ 2,055 (a) Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $141 million of equity investments in unconsolidated subsidiaries and $121 million of rabbi trust assets and miscellaneous investments.
Final Contractual Maturity Dates of Debt Securities in the Nuclear Decommissioning Fund by Asset Class	Contractual maturity dates of debt securities in the nuclear decommissioning fund as of Dec. 31, 2019 : 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 Debt securities $ (7 ) $ 111 $ 246 $ 158 $ 508
Rabbi Trust Securities Amortized Cost and Fair Value Measured on Recurrring Basis [Table Text Block]	Dec. 31, 2018 Fair Value (Millions of Dollars) Cost Level 1 Level 2 Level 3 Total Rabbi Trusts (a) Cash equivalents $ 16 $ 16 $ — $ — $ 16 Mutual funds 52 51 — — 51 Total $ 68 $ 67 $ — $ — $ 67 (a) Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet. Cost and fair value of assets held in rabbi trusts: Dec. 31, 2019 Fair Value (Millions of Dollars) Cost Level 1 Level 2 Level 3 Total Rabbi Trusts (a) Cash equivalents $ 17 $ 17 $ — $ — $ 17 Mutual funds 57 65 — — 65 Total $ 74 $ 82 $ — $ — $ 82 (a) Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet.
Schedule of Notional Amounts of Outstanding Derivative Positions [Table Text Block]	Gross notional amount of commodity forwards, options and FTRs at Dec. 31: (Millions of Dollars) (a) (b) 2019 2018 MWh of electricity 95 87 MMBtu of natural gas 110 92 (a) Amounts are not reflective of net positions in the underlying commodities. (b) Notional amounts for options are included on a gross basis but weighted for the probability of exercise.
Schedule of Cash Flow Hedges Included in Accumulated Other Comprehensive Income (Loss) [Table Text Block]	Financial 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: (Millions of Dollars) 2019 2018 2017 Accumulated other comprehensive loss related to cash flow hedges at Jan. 1 $ (60 ) $ (58 ) $ (51 ) After-tax net unrealized losses related to derivatives accounted for as hedges (23 ) (5 ) — After-tax net realized losses on derivative transactions reclassified into earnings 3 3 3 Adoption of ASU. 2018-02 (a) — — (10 ) Accumulated other comprehensive loss related to cash flow hedges at Dec. 31 $ (80 ) $ (60 ) $ (58 ) (a)
Derivative Instruments, Gain (Loss) [Table Text Block]	Impact of derivative activity: Pre-Tax Fair Value Gains (Losses) Recognized During the Period in: (Millions of Dollars) Accumulated Regulatory Year Ended Dec. 31, 2019 Derivatives designated as cash flow hedges Interest rate $ (30 ) $ — Total (30 ) — Other derivative instruments Electric commodity — 8 Natural gas commodity — (9 ) Total — (1 ) Year Ended Dec. 31, 2018 Interest rate (7 ) — Total (7 ) — Other derivative instruments Electric commodity — 1 Natural gas commodity — 10 Total — 11 Year Ended Dec. 31, 2017 Other derivative instruments Electric commodity — 10 Natural gas commodity — (13 ) Total $ — $ (3 ) Pre-Tax (Gains) Losses Reclassified into Income During the Period from: Pre-Tax Gains (Losses) Recognized (Millions of Dollars) Accumulated Regulatory Year Ended Dec. 31, 2019 Derivatives designated as cash flow hedges Interest rate $ 4 (a) $ — $ — Total 4 — — Other derivative instruments Commodity trading — — 2 (b) Electric commodity — (5 ) (c) — Natural gas commodity — 2 (d) (7 ) (d) Total — (3 ) (5 ) Year Ended Dec. 31, 2018 Derivatives designated as cash flow hedges Interest rate 4 (a) — — Total 4 — — Other derivative instruments Commodity trading — — 14 (b) Electric commodity — (1 ) (c) — Natural gas commodity — (6 ) (d) (4 ) (d) Total — (7 ) 10 Year Ended Dec. 31, 2017 Derivatives designated as cash flow hedges Interest rate 5 (a) — — Total 5 — — Other derivative instruments Commodity trading — — 10 (b) Electric commodity — (15 ) (c) — Natural gas commodity — 3 (d) (6 ) (d) Total $ — $ (12 ) $ 4 (a) Amounts recorded to interest charges. (b) Amounts 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 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) Amounts for the year ended Dec. 31, 2019 included no settlement losses on derivatives entered to mitigate natural gas price risk for electric generation recorded to electric fuel and purchased power, subject to cost-recovery mechanisms and reclassified to a regulatory asset, as appropriate. Such losses and gains for the years ended Dec. 31, 2018 and 2017 were $1 million and immaterial, respectively. Remaining settlement losses for the years ended Dec. 31, 2019 , 2018 and 2017 related to natural gas operations and were 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.
Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis [Table Text Block]	Xcel Energy’s derivative assets and liabilities measured at fair value on a recurring basis: Dec. 31, 2019 Dec. 31, 2018 Fair Value Fair Value Total Netting (a) Fair Value Fair Value Total Netting (a) (Millions of Dollars) Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Current derivative assets Commodity trading $ 3 $ 51 $ 24 $ 78 $ (52 ) $ 26 $ 4 $ 92 $ 2 $ 98 $ (44 ) $ 54 Electric commodity — — 21 21 (1 ) 20 — — 25 25 — 25 Natural gas commodity — 6 — 6 — 6 — 4 — 4 — 4 Total current derivative assets $ 3 $ 57 $ 45 $ 105 $ (53 ) 52 $ 4 $ 96 $ 27 $ 127 $ (44 ) 83 PPAs (b) 3 4 Current derivative instruments $ 55 $ 87 Noncurrent derivative assets Other derivative instruments: Commodity trading $ 9 $ 38 $ 7 $ 54 $ (45 ) $ 9 $ — $ 27 $ 5 $ 32 $ (14 ) $ 18 Total noncurrent derivative assets $ 9 $ 38 $ 7 $ 54 $ (45 ) 9 $ — $ 27 $ 5 $ 32 $ (14 ) 18 PPAs (b) 13 16 Noncurrent derivative instruments $ 22 $ 34 Dec. 31, 2019 Dec. 31, 2018 Fair Value Fair Value Total Netting (a) Fair Value Fair Value Total Netting (a) (Millions of Dollars) Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Current derivative liabilities Derivatives designated as cash flow hedges: Interest rate $ — $ — $ — $ — $ — $ — $ — $ 7 $ — $ 7 $ — $ 7 Other derivative instruments: Commodity trading 4 59 15 78 (63 ) 15 4 88 2 94 (60 ) 34 Electric commodity — — 1 1 (1 ) — — — — — — — Natural gas commodity — 5 — 5 — 5 — — — — — — Total current derivative liabilities $ 4 $ 64 $ 16 $ 84 $ (64 ) 20 $ 4 $ 95 $ 2 $ 101 $ (60 ) 41 PPAs (b) 18 20 Current derivative instruments $ 38 $ 61 Noncurrent derivative liabilities Other derivative instruments: Commodity trading $ 2 $ 79 $ 32 $ 113 $ (13 ) $ 100 $ — $ 18 $ 1 $ 19 $ 17 $ 36 Total noncurrent derivative liabilities $ 2 $ 79 $ 32 $ 113 $ (13 ) 100 $ — $ 18 $ 1 $ 19 $ 17 36 PPAs (b) 75 93 Noncurrent derivative instruments $ 175 $ 129 (a) 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, 2019 and 2018 . At both Dec. 31, 2019 and 2018 , derivative assets and liabilities included $32 million of obligations to return cash collateral. At Dec. 31, 2019 and 2018 , derivative assets and liabilities included rights to reclaim cash collateral of $11 million and $15 million , respectively. Counterparty netting excludes settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements. (b)
Fair Value Assets And Liabilities Measured On Recurring Basis Unobservable Input Reconciliation [Table Text Block]	Changes in Level 3 commodity derivatives: Year Ended Dec. 31 (Millions of Dollars) 2019 2018 2017 Balance at Jan. 1 $ 29 $ 35 $ 17 Purchases 44 59 82 Settlements (64 ) (59 ) (97 ) Net transactions recorded during the period: (Losses) gains recognized in earnings (a) (8 ) (1 ) 5 Net gains (losses) recognized as regulatory assets and liabilities 3 (5 ) 28 Balance at Dec. 31 $ 4 $ 29 $ 35 (a) Amounts relate to commodity derivatives held at the end of the period.
Fair Value, by Balance Sheet Grouping [Table Text Block]	As of Dec. 31, other financial instruments for which the carrying amount did not equal fair value: 2019 2018 (Millions of Dollars) Carrying Amount Fair Value Carrying Amount Fair Value Long-term debt, including current portion $ 18,109 $ 20,227 $ 16,209 $ 16,755

Benefit Plans and Other Postr_2

Benefit Plans and Other Postretirement Benefits (Tables)	12 Months Ended
	Dec. 31, 2019
Benefit Plans and Other Postretirement Benefits [Abstract]
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost	Pension Benefits Postretirement Benefits (Millions of Dollars) 2019 2018 2019 2018 Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost: Net loss $ 1,447 $ 1,633 $ 95 $ 116 Prior service credit (15 ) (20 ) (23 ) (33 ) Total $ 1,432 $ 1,613 $ 72 $ 83 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 $ 78 $ 94 $ — $ — Noncurrent regulatory assets 1,285 1,446 80 89 Current regulatory liabilities — — (1 ) (1 ) Noncurrent regulatory liabilities — — (12 ) (10 ) Deferred income taxes 18 19 1 1 Net-of-tax accumulated other comprehensive income 51 54 4 4 Total $ 1,432 $ 1,613 $ 72 $ 83
Components of Net Periodic Benefit Costs	Net Periodic Benefit Cost (Credit) — Net periodic benefit cost (credit), other than the service cost component, is included in other income in the consolidated statements of income. Components of net periodic benefit cost (credit) and amounts recognized in other comprehensive income and regulatory assets and liabilities: Pension Benefits Postretirement Benefits (Millions of Dollars) 2019 2018 2017 2019 2018 2017 Service cost $ 86 $ 94 $ 94 $ 2 $ 2 $ 2 Interest cost 145 133 147 22 22 24 Expected return on plan assets (203 ) (209 ) (209 ) (21 ) (26 ) (25 ) Amortization of prior service credit (5 ) (5 ) (2 ) (10 ) (11 ) (11 ) Amortization of net loss 87 111 107 5 8 7 Settlement charge (a) 6 91 81 — — — Net periodic pension cost (credit) 116 215 218 (2 ) (5 ) (3 ) Costs not recognized due to effects of regulation (1 ) (75 ) (79 ) 1 2 — Net benefit cost (credit) recognized for financial reporting $ 115 $ 140 $ 139 $ (1 ) $ (3 ) $ (3 ) Significant Assumptions Used to Measure Costs: Discount rate 4.31 % 3.63 % 4.13 % 4.32 % 3.62 % 4.13 % Expected average long-term increase in compensation level 3.75 3.75 3.75 — — — Expected average long-term rate of return on assets 6.87 6.87 6.87 4.50 5.30 5.80 (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 2019 and 2018, as a result of lump-sum distributions during the 2019 and 2018 plan years, Xcel Energy recorded a total pension settlement charge of $6 million in 2019 and $91 million in 2018, the majority of which was not recognized due to the effects of regulation. A total of $1 million and $11 million was recorded in the consolidated statements of income in 2019 and 2018, respectively.
Target Asset Allocations and Plan Assets Measured at Fair Value	. Targeted asset allocations: Pension Benefits Postretirement Benefits 2019 2018 2019 2018 Domestic and international equity securities 37 % 36 % 15 % 18 % Long-duration fixed income securities 30 30 — — Short-to-intermediate fixed income securities 14 17 72 70 Alternative investments 17 15 9 8 Cash 2 2 4 4 Total 100 % 100 % 100 % 100 % Dec. 31, 2019 (a) Dec. 31, 2018 (a) (Millions of Dollars) Level 1 Level 2 Level 3 Measured at NAV Total Level 1 Level 2 Level 3 Measured at NAV Total Cash equivalents $ 145 $ — $ — $ — $ 145 $ 137 $ — $ — $ — $ 137 Commingled funds 1,408 — — 1,031 2,439 914 — — 987 1,901 Debt securities — 645 4 — 649 — 621 — — 621 Equity securities 86 — — — 86 106 — — — 106 Other (120 ) 5 — (20 ) (135 ) 2 5 — (30 ) (23 ) Total $ 1,519 $ 650 $ 4 $ 1,011 $ 3,184 $ 1,159 $ 626 $ — $ 957 $ 2,742 (a) See Note 10 for further information regarding fair value measurement inputs and methods. For each of the fair value hierarchy levels, Xcel Energy’s postretirement benefit plan assets that were measured at fair value: Dec. 31, 2019 (a) Dec. 31, 2018 (a) (Millions of Dollars) Level 1 Level 2 Level 3 Measured at NAV Total Level 1 Level 2 Level 3 Measured at NAV Total Cash equivalents $ 23 $ — $ — $ — $ 23 $ 19 $ — $ — $ — $ 19 Insurance contracts — 51 — — 51 — 45 — — 45 Commingled funds 69 — — 76 145 133 — — 40 173 Debt securities — 228 1 — 229 — 179 — — 179 Other — 1 — — 1 — 1 — — 1 Total $ 92 $ 280 $ 1 $ 76 $ 449 $ 152 $ 225 $ — $ 40 $ 417 (a) See Note 10 for further information on fair value measurement inputs and methods.
Changes in Projected Benefit Obligations, Fair Value of Plan Assets, and Funded Status of Plan [Table Text Block]	Funded Status — Comparisons of the actuarially computed benefit obligation, changes in plan assets and funded status of the pension and postretirement health care plans for Xcel Energy are as follows: Pension Benefits Postretirement Benefits (Millions of Dollars) 2019 2018 2019 2018 Change in Benefit Obligation: Obligation at Jan. 1 $ 3,477 $ 3,828 $ 542 $ 621 Service cost 86 94 2 2 Interest cost 145 133 22 22 Plan amendments 1 — — — Actuarial loss (gain) 273 (224 ) 19 (62 ) Plan participants’ contributions — — 8 8 Medicare subsidy reimbursements — — 1 1 Benefit payments (a) (281 ) (354 ) (47 ) (50 ) Obligation at Dec. 31 $ 3,701 $ 3,477 $ 547 $ 542 Change in Fair Value of Plan Assets: Fair value of plan assets at Jan. 1 $ 2,742 $ 3,088 $ 417 $ 461 Actual return on plan assets 568 (142 ) 56 (13 ) Employer contributions 155 150 15 11 Plan participants’ contributions — — 8 8 Benefit payments (281 ) (354 ) (47 ) (50 ) Fair value of plan assets at Dec. 31 $ 3,184 $ 2,742 $ 449 $ 417 Funded status of plans at Dec. 31 $ (517 ) $ (735 ) $ (98 ) $ (125 ) Amounts recognized in the Consolidated Balance Sheet at Dec. 31: Noncurrent assets $ — $ — $ 21 $ — Current liabilities — — (6 ) (7 ) Noncurrent liabilities (517 ) (735 ) (113 ) (118 ) Net amounts recognized $ (517 ) $ (735 ) $ (98 ) $ (125 ) (a) Includes approximately $20 million in 2019 and $198 million in 2018 of lump-sum benefit payments used in the determination of a settlement charge.
Projected Benefit Payments for the Pension and Postretirement Benefit Plans	Xcel Energy’s projected benefit payments: (Millions of Dollars) Projected Gross Projected Expected Net Projected 2020 $ 278 $ 44 $ 2 $ 42 2021 263 43 2 41 2022 262 42 2 40 2023 260 41 2 39 2024 255 40 2 38 2025-2029 1,205 181 13 168

Commitments and Contingencies (

Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2019
Commitments and Contingencies Disclosure [Abstract]
Finance Lease, Liability, Maturity [Table Text Block]	Commitments under operating and finance leases as of Dec. 31, 2018: (Millions of Dollars) PPA (a) (b) Operating Leases Other Operating Leases Total Leases Finance Leases (c) 2019 $ 207 $ 32 $ 239 $ 14 2020 208 26 234 14 2021 210 25 235 14 2022 197 24 221 12 2023 186 22 208 12 Thereafter 883 154 1,037 220 Total minimum obligation 286 Interest component of obligation (201 ) Present value of minimum obligation $ 85 (a) Amounts do not include PPAs accounted for as executory contracts and/or contingent payments, such as energy payments on renewable PPAs. (b) PPA operating leases contractually expire at various dates through 2033. (c) Excludes certain amounts related to Xcel Energy’s 50% ownership interest in WYCO. Commitments under operating and finance leases as of Dec. 31, 2019: (Millions of Dollars) PPA (a) (b) Operating Leases Other Operating Leases Total Leases Finance Leases (c) 2020 $ 236 $ 26 $ 262 $ 14 2021 238 29 267 14 2022 225 28 253 12 2023 214 25 239 12 2024 208 22 230 12 Thereafter 750 115 865 207 Total minimum obligation 1,871 245 2,116 271 Interest component of obligation (321 ) (52 ) (373 ) (190 ) Present value of minimum obligation $ 1,550 193 1,743 81 Less current portion (194 ) (4 ) Noncurrent operating and finance lease liabilities $ 1,549 $ 77 Weighted-average remaining lease term in years 9.3 37.0 (a) Amounts do not include PPAs accounted for as executory contracts and/or contingent payments, such as energy payments on renewable PPAs. (b) PPA operating leases contractually expire at various dates through 2033. (c) Excludes certain amounts related to Xcel Energy’s 50% ownership interest in WYCO.
Assets and Liabilities, Lessee [Table Text Block]	(Millions of Dollars) Dec. 31, 2019 PPAs $ 1,642 Other 201 Gross operating lease ROU assets 1,843 Accumulated amortization (171 ) Net operating lease ROU assets $ 1,672 (Millions of Dollars) Dec. 31, 2019 Dec. 31, 2018 Gas storage facilities $ 201 $ 201 Gas pipeline 21 21 Gross finance lease ROU assets 222 222 Accumulated amortization (83 ) (77 ) Net finance lease ROU assets $ 139 $ 145
Lease, Cost [Table Text Block]	Components of lease expense: (Millions of Dollars) 2019 2018 2017 Operating leases PPA capacity payments $ 221 $ 210 $ 210 Other operating leases (a) 34 38 36 Total operating lease expense (b) $ 255 $ 248 $ 246 Finance leases Amortization of ROU assets $ 6 $ 6 $ 5 Interest expense on lease liability 19 19 20 Total finance lease expense $ 25 $ 25 $ 25 (a) Includes short-term lease expense of $5 million for 2019, 2018 and 2017. (b) PPA capacity payments are included in electric fuel and purchased power on the consolidated statements of income. Expense for other operating leases is included in O&M expense and electric fuel and purchased power.
Funded Status of Nuclear Decommissioning Obligation [Table Text Block]	Regulatory Basis (Millions of Dollars) 2019 2018 Estimated decommissioning cost obligation from most recently approved study (in 2014 dollars) $ 3,012 $ 3,012 Effect of escalating costs 688 539 Estimated decommissioning cost obligation (in current dollars) 3,700 3,551 Effect of escalating costs to payment date 7,505 7,654 Estimated future decommissioning costs (undiscounted) 11,205 11,205 Effect of discounting obligation (using average risk-free interest rate of 2.39% and 3.33% for 2019 and 2018, respectively) (5,562 ) (6,911 ) Discounted decommissioning cost obligation $ 5,643 $ 4,294 Assets held in external decommissioning trust $ 2,440 $ 2,055 Underfunding of external decommissioning fund compared to the discounted decommissioning obligation 3,203 2,239
Estimated Minimum Purchases Under Fuel Contracts	Estimated minimum purchases under these contracts as of Dec. 31, 2019: (Millions of Dollars) Coal Nuclear fuel Natural gas supply Natural gas supply and transportation 2020 $ 430 $ 54 $ 343 $ 295 2021 222 103 254 283 2022 135 85 104 269 2023 58 103 53 198 2024 24 74 3 153 Thereafter 74 275 — 860 Total $ 943 $ 694 $ 757 $ 2,058
Estimated Future Payments for Capacity and Energy Pursuant to Purchased Power Agreements	At Dec. 31, 2019 , 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, were as follows: (Millions of Dollars) Capacity Energy (a) 2020 $ 70 $ 110 2021 78 157 2022 77 173 2023 79 177 2024 74 182 Thereafter 56 146 Total $ 434 $ 945 (a) Excludes contingent energy payments for renewable energy PPAs.
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: (Millions of Dollars) Dec. 31, 2019 Dec. 31, 2018 Current assets $ 7 $ 5 Property, plant and equipment, net 41 42 Other noncurrent assets 1 1 Total assets $ 49 $ 48 Current liabilities $ 8 $ 7 Mortgages and other long-term debt payable 26 26 Other noncurrent liabilities — — Total liabilities $ 34 $ 33
Committed Minimum Payments Under Technology Agreements	Committed minimum payments under these obligations: (Millions of Dollars) IBM Agreement Accenture Agreement Cognizant Agreement 2020 $ 15 $ 11 $ 9 2021 15 — 7 2022 6 — 3 2023 — — — 2024 — — — Thereafter — — —
Asset Retirement Obligations	Xcel Energy’s AROs were as follows: (Millions of Dollars) Jan. 1, 2019 Amounts Incurred (a) Amounts Settled (b) Accretion Cash Flow Revisions (c) Dec. 31, 2019 Electric Nuclear $ 1,968 $ — $ — $ 100 $ — $ 2,068 Steam, hydro and other production 177 — (5 ) 8 22 202 Wind 119 26 — 7 (6 ) 146 Distribution 42 — — 2 — 44 Miscellaneous 7 — — — (7 ) — Natural gas Transmission and distribution 249 — — 11 (24 ) 236 Miscellaneous 4 — — — (1 ) 3 Common Miscellaneous 1 — — — — 1 Non-utility Miscellaneous 1 — — — — 1 Total liability $ 2,568 $ 26 $ (5 ) $ 128 $ (16 ) $ 2,701 (a) Amounts incurred related to the wind farms placed in service in 2019 for NSP-Minnesota (Lake Benton and Foxtail) and SPS (Hale). (b) Amounts settled related to asbestos abatement projects and closure of certain ash containment facilities. (c) In 2019, AROs were revised for changes in timing and estimates of cash flows. Changes in gas transmission and distribution AROs were primarily related to increased gas line mileage and number of services, which were more than offset by decreased inflation rates. Changes in steam, hydro and other production AROs primarily related to the cost estimates to remediate ponds at production facilities. Changes in wind AROs were driven by new dismantling studies. (Millions of Dollars) Jan. 1, 2018 Amounts Incurred (a) Amounts Settled (b) Accretion Cash Flow Revisions (c) Dec. 31, 2018 Electric Nuclear $ 1,874 $ — $ — $ 94 $ — $ 1,968 Steam, hydro and other production 192 — (14 ) 8 (9 ) 177 Wind 96 12 — 4 7 119 Distribution 21 — — 1 20 42 Miscellaneous 5 — — — 2 7 Natural gas Transmission and distribution 282 — — 13 (46 ) 249 Miscellaneous 4 — — — — 4 Common Miscellaneous 1 — — — — 1 Non-utility Miscellaneous — 1 — — — 1 Total liability $ 2,475 $ 13 $ (14 ) $ 120 $ (26 ) $ 2,568 (a) Amounts incurred related to the PSCo Rush Creek wind farm and Nicollet Projects community solar gardens, which were placed in service in 2018. (b) Amounts settled related to asbestos abatement projects and closure of certain ash containment facilities. (c) In 2018, AROs were revised for changes in timing and estimates of cash flows. Changes in gas transmission and distribution AROs were primarily related to increased gas line mileage and number of services, which were more than offset by increased discount rates. Changes in electric distribution AROs primarily related to increased labor costs.
Plant Removal Costs	Accumulated balances by entity at Dec. 31 : (Millions of Dollars) 2019 2018 NSP-Minnesota $ 520 $ 485 PSCo 351 344 SPS 175 188 NSP-Wisconsin 171 158 Total Xcel Energy $ 1,217 $ 1,175
Reconciliation of Decommissioning Cost Obligation - Regulatory to GAAP	(Millions of Dollars) 2019 2018 Discounted decommissioning cost obligation - regulated basis $ 5,643 $ 4,294 Differences in discount rate and market risk premium (2,295 ) (1,447 ) O&M costs not included for GAAP (1,280 ) (879 ) Nuclear production decommissioning ARO - GAAP $ 2,068 $ 1,968
Nuclear Decommissioning Expenses Recognized as Result of Regulation	Decommissioning expenses recognized as a result of regulation: (Millions of Dollars) 2019 2018 2017 Annual decommissioning recorded as depreciation expense: (a) (b) $ 20 $ 20 $ 20 (a) Decommissioning expense does not include depreciation of the capitalized nuclear asset retirement costs. (b) Decommissioning expenses in 2019, 2018 and 2017 include Minnesota’s retail jurisdiction annual funding requirement of approximately $14 million.

Other Comprehensive Income (Tab

Other Comprehensive Income (Tables)	12 Months Ended
	Dec. 31, 2019
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: 2019 (Millions of Dollars) Gains and Defined Benefit Total Accumulated other comprehensive loss at Jan. 1 $ (60 ) $ (64 ) $ (124 ) Other comprehensive loss before reclassifications (net of taxes of $(8) and $0, respectively) (23 ) — (23 ) Losses reclassified from net accumulated other comprehensive loss: Interest rate derivatives (net of taxes of $1 and $0, respectively) 3 (a) — 3 Amortization of net actuarial loss (net of taxes of $0 and $1, respectively) — 3 (b) 3 Net current period other comprehensive (loss) income (20 ) 3 (17 ) Accumulated other comprehensive loss at Dec. 31 $ (80 ) $ (61 ) $ (141 ) (a) Included in interest charges. (b) Included in the computation of net periodic pension and postretirement benefit costs. See Note 11 for further information. 2018 (Millions of Dollars) Gains and Losses on Cash Flow Hedges Defined Benefit Pension and Postretirement Items Total Accumulated other comprehensive loss at Jan. 1 $ (58 ) $ (67 ) $ (125 ) Other comprehensive loss before reclassifications (net of taxes of $(2) and $(2), respectively) (5 ) (6 ) (11 ) Losses reclassified from net accumulated other comprehensive loss: Interest rate derivatives (net of taxes of $1 and $0, respectively) 3 (a) — 3 Amortization of net actuarial loss (net of taxes of $0 and $3, respectively) — 9 (b) 9 Net current period other comprehensive (loss) income (2 ) 3 1 Accumulated other comprehensive loss at Dec. 31 $ (60 ) $ (64 ) $ (124 ) (a) Included in interest charges. (b) Included in the computation of net periodic pension and postretirement benefit costs. See Note 11 for further information.

Segments and Related Informat_2

Segments and Related Information (Tables)	12 Months Ended
	Dec. 31, 2019
Segment Reporting [Abstract]
Results from Operations by Reportable Segment	Xcel Energy’s segment information: (Millions of Dollars) 2019 2018 2017 Regulated Electric Operating revenues from external customers $ 9,575 $ 9,719 $ 9,676 Intersegment revenue 1 1 2 Total revenues $ 9,576 $ 9,720 $ 9,678 Depreciation and amortization 1,535 1,421 1,298 Interest charges and financing costs 500 449 449 Income tax expense 125 187 528 Net income 1,288 1,177 1,066 Regulated Natural Gas Operating revenues from external customers $ 1,868 $ 1,739 $ 1,650 Intersegment revenue 2 2 1 Total revenues $ 1,870 $ 1,741 $ 1,651 Depreciation and amortization 219 212 174 Interest charges and financing costs 69 61 57 Income tax expense 48 28 23 Net income 195 187 182 Other Total operating revenue $ 86 $ 79 $ 78 Depreciation and amortization 11 9 7 Interest charges and financing costs 167 142 122 Income tax (benefit) (45 ) (34 ) (9 ) Net (loss) (111 ) (103 ) (100 ) Consolidated Total Total revenue $ 11,532 $ 11,540 $ 11,407 Reconciling eliminations (3 ) (3 ) (3 ) Consolidated total revenue $ 11,529 $ 11,537 $ 11,404 Depreciation and amortization 1,765 1,642 1,479 Interest charges and financing costs 736 652 628 Income tax expense 128 181 542 Net income 1,372 1,261 1,148

Summarized Quarterly Financia_2

Summarized Quarterly Financial Data (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2019
Quarterly Financial Information Disclosure [Abstract]
Summarized Quarterly Financial Data (Unaudited)	Quarter Ended (Amounts in millions, except per share data) March 31, 2019 June 30, 2019 Sept. 30, 2019 Dec. 31, 2019 Operating revenues $ 3,141 $ 2,577 $ 3,013 $ 2,798 Operating income 486 410 758 450 Net income 315 238 527 292 EPS total — basic $ 0.61 $ 0.46 $ 1.02 $ 0.56 EPS total — diluted 0.61 0.46 1.01 0.56 Cash dividends declared per common share 0.405 0.405 0.405 0.405 Quarter Ended (Amounts in millions, except per share data) March 31, 2018 June 30, 2018 Sept. 30, 2018 Dec. 31, 2018 Operating revenues $ 2,951 $ 2,658 $ 3,048 $ 2,880 Operating income (a) 480 450 696 339 Net income 291 265 491 214 EPS total — basic $ 0.57 $ 0.52 $ 0.96 $ 0.42 EPS total — diluted 0.57 0.52 0.96 0.42 Cash dividends declared per common share 0.380 0.380 0.380 0.380 (a)

Schedule II, Valuation and Qu_2

Schedule II, Valuation and Qualifying Accounts SEC Schedule, 12-09, Schedule of Valuation and Qualifying Accounts (Tables)	12 Months Ended
	Dec. 31, 2019
SEC Schedule, 12-09, Valuation and Qualifying Accounts Disclosure [Line Items]
SEC Schedule, 12-09, Schedule of Valuation and Qualifying Accounts Disclosure [Text Block]	Xcel Energy Inc. and Subsidiaries Valuation and Qualifying Accounts Years Ended Dec. 31 Allowance for bad debts NOL and tax credit valuation allowances (Millions of Dollars) 2019 2018 2017 2019 2018 2017 Balance at Jan. 1 $ 55 $ 52 $ 51 $ 79 $ 77 $ 58 Additions charged to costs and expenses 42 42 39 9 7 9 Additions charged to other accounts 16 (a) 11 (a) 10 (a) — — 22 (c) Deductions from reserves (58 ) (b) (50 ) (b) (48 ) (b) (21 ) (e) (5 ) (e) (12 ) (d) Balance at Dec. 31 $ 55 $ 55 $ 52 $ 67 $ 79 $ 77 (a) Recovery of amounts previously written off. (b) Deductions related primarily to bad debt write-offs. (c) Accrual of valuation allowances for North Dakota ITC, net of federal income tax benefit, that is offset to a regulatory liability and includes $14 million expense related to the revaluation of federal benefit as a result of the TCJA. (d) Primarily the reductions to valuation allowances for North Dakota ITC carryforwards, net of federal benefit, primarily due to a consolidated adjustment to the regulatory liability accrual referenced above; the change includes $4 million of reduced expense related to the revaluation of federal benefit as a result of TCJA. (e)

Summary of Significant Accoun_4

Summary of Significant Accounting Policies Summary of Significant Accounting Policies (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Property, Plant and Equipment [Abstract]
Depreciation expense expressed as a percentage of average depreciable property	3.30%	3.10%	3.10%
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
Accounts, Notes, Loans and Financing Receivable
Allowance for bad debts	$ 55	$ 55
Alternative Revenue Programs [Abstract]
Maximum number of months following end of annual period in which revenues are earned to be included in incentive programs	24 months
Inventories	$ 544	548
Supplies [Member]
Inventories	270	271
Public Utilities, Inventory, Fuel [Member]
Inventories	191	170
Public Utilities, Inventory, Natural Gas [Member]
Inventories	$ 83	$ 107

Accounting Pronouncements - Rec

Accounting Pronouncements - Recently Adopted (Details) - USD ($) $ in Millions	Dec. 31, 2019	Jan. 01, 2019	Dec. 31, 2018
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Operating lease right-of-use assets	$ 1,672		$ 0
Operating lease liabilities	$ 1,743
Accounting Standards Update 2016-02 [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Operating lease right-of-use assets		$ 1,700
Operating lease liabilities		$ 1,700

Property Plant and Equipment Ma

Property Plant and Equipment Major classes of property, plant and equipment (Details) - USD ($) $ in Millions		Dec. 31, 2019	Dec. 31, 2018
Property, Plant and Equipment [Line Items]
Property, plant and equipment		$ 55,844	$ 52,249
Accumulated depreciation and amortization		(16,735)	(15,659)
Property, plant and equipment, net		39,483	36,944
Electric plant
Property, Plant and Equipment [Line Items]
Property, plant and equipment		44,355	41,472
Natural gas plant
Property, Plant and Equipment [Line Items]
Property, plant and equipment		6,560	6,210
Common and other property
Property, Plant and Equipment [Line Items]
Property, plant and equipment		2,341	2,154
Plant to be retired
Property, Plant and Equipment [Line Items]
Property, plant and equipment	[1]	259	322
CWIP
Property, Plant and Equipment [Line Items]
Property, plant and equipment		2,329	2,091
Nuclear fuel
Property, Plant and Equipment [Line Items]
Property, plant and equipment		2,909	2,771
Accumulated depreciation and amortization		$ (2,535)	$ (2,417)
[1]	In 2018, the CPUC approved early retirement of PSCo’s Comanche Units 1 and 2 in approximately 2022 and 2025, respectively. PSCo also expects Craig Unit 1 to be retired early in 2025. Amounts are presented net of accumulated depreciation.

Property Plant and Equipment Jo

Property Plant and Equipment Joint Ownership of Generation, Transmission and Gas Facilities (Details) $ in Millions	Dec. 31, 2019USD ($)
NSP Minnesota
Jointly Owned Utility Plant Interests [Line Items]
Plant in Service	$ 1,736
Accumulated Depreciation	627
CWIP	8
NSP Minnesota | Electric Generation | Sherco Unit 3
Jointly Owned Utility Plant Interests [Line Items]
Plant in Service	603
Accumulated Depreciation	426
CWIP	$ 4
Percent Owned	59.00%
NSP Minnesota | Electric Generation | Sherco Common Facilities
Jointly Owned Utility Plant Interests [Line Items]
Plant in Service	$ 145
Accumulated Depreciation	103
CWIP	$ 2
Percent Owned	80.00%
NSP Minnesota | Electric Generation | Sherco substation
Jointly Owned Utility Plant Interests [Line Items]
Plant in Service	$ 5
Accumulated Depreciation	3
CWIP	$ 0
Percent Owned	59.00%
NSP Minnesota | Electric Transmission | CapX2020
Jointly Owned Utility Plant Interests [Line Items]
Plant in Service	$ 972
Accumulated Depreciation	92
CWIP	$ 2
Percent Owned	51.00%
NSP Minnesota | Electric Transmission | Grand Meadow
Jointly Owned Utility Plant Interests [Line Items]
Plant in Service	$ 11
Accumulated Depreciation	3
CWIP	$ 0
Percent Owned	50.00%
NSP-Wisconsin
Jointly Owned Utility Plant Interests [Line Items]
Plant in Service	$ 356
Accumulated Depreciation	26
CWIP	0
NSP-Wisconsin | Electric Transmission | CapX2020
Jointly Owned Utility Plant Interests [Line Items]
Plant in Service	169
Accumulated Depreciation	19
CWIP	$ 0
Percent Owned	80.00%
NSP-Wisconsin | Electric Transmission | La Crosse, WI to Madison, WI
Jointly Owned Utility Plant Interests [Line Items]
Plant in Service	$ 187
Accumulated Depreciation	7
CWIP	$ 0
Percent Owned	37.00%
PSCo
Jointly Owned Utility Plant Interests [Line Items]
Plant in Service	$ 1,583
Accumulated Depreciation	459
CWIP	2
PSCo | Electric Generation | Hayden Unit 1
Jointly Owned Utility Plant Interests [Line Items]
Plant in Service	152
Accumulated Depreciation	81
CWIP	$ 0
Percent Owned	76.00%
PSCo | Electric Generation | Hayden Unit 2
Jointly Owned Utility Plant Interests [Line Items]
Plant in Service	$ 149
Accumulated Depreciation	71
CWIP	$ 0
Percent Owned	37.00%
PSCo | Electric Generation | Hayden Common Facilities
Jointly Owned Utility Plant Interests [Line Items]
Plant in Service	$ 41
Accumulated Depreciation	22
CWIP	$ 0
Percent Owned	53.00%
PSCo | Electric Generation | Craig Units 1 and 2
Jointly Owned Utility Plant Interests [Line Items]
Plant in Service	$ 81
Accumulated Depreciation	41
CWIP	$ 0
Percent Owned	10.00%
PSCo | Electric Generation | Craig Common Facilities
Jointly Owned Utility Plant Interests [Line Items]
Plant in Service	$ 39
Accumulated Depreciation	22
CWIP	$ 0
Percent Owned	7.00%
PSCo | Electric Generation | Comanche Unit 3
Jointly Owned Utility Plant Interests [Line Items]
Plant in Service	$ 887
Accumulated Depreciation	149
CWIP	$ 1
Percent Owned	67.00%
PSCo | Electric Generation | Comanche Common Facilities
Jointly Owned Utility Plant Interests [Line Items]
Plant in Service	$ 29
Accumulated Depreciation	3
CWIP	$ 0
Percent Owned	82.00%
PSCo | Electric Transmission | Transmission and other facilities
Jointly Owned Utility Plant Interests [Line Items]
Plant in Service	$ 174
Accumulated Depreciation	62
CWIP	1
PSCo | Gas Transportation | Rifle, CO to Avon, CO
Jointly Owned Utility Plant Interests [Line Items]
Plant in Service	22
Accumulated Depreciation	7
CWIP	$ 0
Percent Owned	60.00%
PSCo | Gas Transportation | Gas Transportation Compressor
Jointly Owned Utility Plant Interests [Line Items]
Plant in Service	$ 9
Accumulated Depreciation	1
CWIP	$ 0
Percent Owned	50.00%

Regulatory Assets and Liabili_3

Regulatory Assets and Liabilities, Regulatory Assets (Details) - USD ($) $ in Millions		Dec. 31, 2019	Dec. 31, 2018
Regulatory Assets [Line Items]
Regulatory Asset, Current		$ 488	$ 464
Regulatory Asset, Noncurrent		2,935	3,326
Pension and retiree medical obligations
Regulatory Assets [Line Items]
Regulatory Asset, Current		85	87
Regulatory Asset, Noncurrent		1,328	1,500
Recoverable deferred taxes on AFUDC recorded in plant
Regulatory Assets [Line Items]
Regulatory Asset, Current		0	0
Regulatory Asset, Noncurrent		271	264
Net AROs
Regulatory Assets [Line Items]
Regulatory Asset, Current	[1]	0	0
Regulatory Asset, Noncurrent	[1]	269	452
Excess deferred taxes - TCJA
Regulatory Assets [Line Items]
Regulatory Asset, Current		39	0
Regulatory Asset, Noncurrent		239	296
Depreciation differences
Regulatory Assets [Line Items]
Regulatory Asset, Current		15	18
Regulatory Asset, Noncurrent		140	107
Environmental remediation costs
Regulatory Assets [Line Items]
Regulatory Asset, Current		36	17
Regulatory Asset, Noncurrent		131	155
Benson Biomass PPA termination and asset purchase
Regulatory Assets [Line Items]
Regulatory Asset, Current		9	10
Regulatory Asset, Noncurrent		73	86
Contract valuation adjustments
Regulatory Assets [Line Items]
Regulatory Asset, Current	[2]	20	17
Regulatory Asset, Noncurrent	[2]	62	77
Purchased power contract costs
Regulatory Assets [Line Items]
Regulatory Asset, Current		5	4
Regulatory Asset, Noncurrent		61	63
Laurentian biomass PPA termination
Regulatory Assets [Line Items]
Regulatory Asset, Current		19	18
Regulatory Asset, Noncurrent		54	73
PI extended power update
Regulatory Assets [Line Items]
Regulatory Asset, Current		3	3
Regulatory Asset, Noncurrent		53	56
Losses on reacquired debt
Regulatory Assets [Line Items]
Regulatory Asset, Current		4	4
Regulatory Asset, Noncurrent		41	44
State commission adjustments
Regulatory Assets [Line Items]
Regulatory Asset, Current		1	1
Regulatory Asset, Noncurrent		31	29
Property tax
Regulatory Assets [Line Items]
Regulatory Asset, Current		2	14
Regulatory Asset, Noncurrent		30	10
Conservation programs
Regulatory Assets [Line Items]
Regulatory Asset, Current	[3]	27	42
Regulatory Asset, Noncurrent	[3]	26	28
Nuclear refueling outage costs
Regulatory Assets [Line Items]
Regulatory Asset, Current		43	37
Regulatory Asset, Noncurrent		17	14
Sales true-up and revenue decoupling
Regulatory Assets [Line Items]
Regulatory Asset, Current		54	38
Regulatory Asset, Noncurrent		16	7
Renewable resources and environmental initiatives
Regulatory Assets [Line Items]
Regulatory Asset, Current		72	39
Regulatory Asset, Noncurrent		10	9
Gas pipeline inspection and remediation costs
Regulatory Assets [Line Items]
Regulatory Asset, Current		26	28
Regulatory Asset, Noncurrent		8	3
Deferred purchased natural gas and electric energy costs
Regulatory Assets [Line Items]
Regulatory Asset, Current		6	57
Regulatory Asset, Noncurrent		6	13
Other
Regulatory Assets [Line Items]
Regulatory Asset, Current		22	30
Regulatory Asset, Noncurrent		$ 69	$ 40
[1]	Includes amounts recorded for future recovery of AROs, less amounts recovered through nuclear decommissioning accruals and gains from decommissioning investments.
[2]	Includes the fair value of certain long-term PPAs used to meet energy capacity requirements and valuation adjustments on natural gas commodity purchases.
[3]	Includes costs for conservation programs, as well as incentives allowed in certain jurisdictions.

Regulatory Assets and Liabili_4

Regulatory Assets and Liabilities, Regulatory Liabilities (Details) - USD ($) $ in Millions		Dec. 31, 2019	Dec. 31, 2018
Regulatory Liabilities [Line Items]
Regulatory Liability, Current	[1]	$ 407	$ 436
Regulatory Liability, Noncurrent	[1]	5,077	5,187
Regulatory assets not currently earning a return		544	512
Other Current Liabilities
Regulatory Liabilities [Line Items]
Entity's Recorded Provision for Revenue Subject To Refund		28	29
Deferred income tax adjustment and TCJA refunds
Regulatory Liabilities [Line Items]
Regulatory Liability, Current	[2]	75	157
Regulatory Liability, Noncurrent	[2]	3,523	3,715
Plant removal costs
Regulatory Liabilities [Line Items]
Regulatory Liability, Current		0	0
Regulatory Liability, Noncurrent		1,217	1,175
Effects of regulation on employee benefit costs
Regulatory Liabilities [Line Items]
Regulatory Liability, Current	[3]	0	0
Regulatory Liability, Noncurrent	[3]	196	137
Renewable resources and environmental initiatives
Regulatory Liabilities [Line Items]
Regulatory Liability, Current		0	9
Regulatory Liability, Noncurrent		45	54
ITC deferrals
Regulatory Liabilities [Line Items]
Regulatory Liability, Current	[4]	0	0
Regulatory Liability, Noncurrent	[4]	38	40
Deferred electric, natural gas and steam production costs
Regulatory Liabilities [Line Items]
Regulatory Liability, Current		138	102
Regulatory Liability, Noncurrent		0	0
Contract valuation adjustments
Regulatory Liabilities [Line Items]
Regulatory Liability, Current	[5]	19	26
Regulatory Liability, Noncurrent	[5]	0	0
Conservation programs
Regulatory Liabilities [Line Items]
Regulatory Liability, Current	[6]	37	36
Regulatory Liability, Noncurrent	[6]	0	0
DOE settlement
Regulatory Liabilities [Line Items]
Regulatory Liability, Current		37	19
Regulatory Liability, Noncurrent		0	0
Other
Regulatory Liabilities [Line Items]
Regulatory Liability, Current		101	87
Regulatory Liability, Noncurrent		$ 58	$ 66
[1]	Revenue subject to refund of $28 million and $29 million for 2019 and 2018, respectively, is included in other current liabilities.
[2]	Includes the revaluation of recoverable/regulated plant ADIT and revaluation impact of non-plant ADIT due to the TCJA.
[3]	Includes regulatory amortization and certain 2018 TCJA benefits approved by the CPUC to offset the PSCo prepaid pension asset.
[4]	Includes impact of lower federal tax rate due to the TCJA.
[5]	Includes the fair value of certain long-term PPAs used to meet energy capacity requirements and valuation adjustments on natural gas commodity purchases.
[6]	Includes costs for conservation programs, as well as incentives allowed in certain jurisdictions.

Regulatory Assets and Liabili_5

Regulatory Assets and Liabilities Regulatory Assets and Liabilities Phantom (Details)	12 Months Ended
	Dec. 31, 2019
Depreciation differences | Minimum
Regulatory Assets [Line Items]
Regulatory Asset, Remaining Amortization Period	1 year
Depreciation differences | Maximum
Regulatory Assets [Line Items]
Regulatory Asset, Remaining Amortization Period	12 years
Benson Biomass PPA termination and asset purchase
Regulatory Assets [Line Items]
Regulatory Asset, Remaining Amortization Period	10 years
Laurentian biomass PPA termination
Regulatory Assets [Line Items]
Regulatory Asset, Remaining Amortization Period	5 years
PI extended power update
Regulatory Assets [Line Items]
Regulatory Asset, Remaining Amortization Period	16 years
Conservation programs | Minimum
Regulatory Assets [Line Items]
Regulatory Asset, Remaining Amortization Period	1 year
Conservation programs | Maximum
Regulatory Assets [Line Items]
Regulatory Asset, Remaining Amortization Period	2 years
Nuclear refueling outage costs | Minimum
Regulatory Assets [Line Items]
Regulatory Asset, Remaining Amortization Period	1 year
Nuclear refueling outage costs | Maximum
Regulatory Assets [Line Items]
Regulatory Asset, Remaining Amortization Period	2 years
Deferred purchased natural gas and electric energy costs | Minimum
Regulatory Assets [Line Items]
Regulatory Asset, Remaining Amortization Period	1 year
Deferred purchased natural gas and electric energy costs | Maximum
Regulatory Assets [Line Items]
Regulatory Asset, Remaining Amortization Period	3 years
Renewable resources and environmental initiatives | Minimum
Regulatory Assets [Line Items]
Regulatory Asset, Remaining Amortization Period	1 year
Renewable resources and environmental initiatives | Maximum
Regulatory Assets [Line Items]
Regulatory Asset, Remaining Amortization Period	2 years
Sales true-up and revenue decoupling | Minimum
Regulatory Assets [Line Items]
Regulatory Asset, Remaining Amortization Period	1 year
Sales true-up and revenue decoupling | Maximum
Regulatory Assets [Line Items]
Regulatory Asset, Remaining Amortization Period	2 years
Gas pipeline inspection and remediation costs | Minimum
Regulatory Assets [Line Items]
Regulatory Asset, Remaining Amortization Period	1 year
Gas pipeline inspection and remediation costs | Maximum
Regulatory Assets [Line Items]
Regulatory Asset, Remaining Amortization Period	2 years

Borrowings and Other Financin_3

Borrowings and Other Financing Instruments Short-Term Debt (Details) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Short-term Debt [Line Items]
Amount outstanding at period end	$ 1,038	$ 595	$ 1,038
Commercial Paper
Short-term Debt [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	3,250	3,600	3,250	$ 3,250
Amount outstanding at period end	1,038	595	1,038	814
Average amount outstanding	663	1,115	788	644
Maximum amount outstanding	$ 945	$ 1,780	$ 1,349	$ 1,247
Weighted average interest rate, computed on a daily basis (percentage)	2.40%	2.72%	2.34%	1.35%
Weighted average interest rate at period end (percentage)	2.97%	2.34%	2.97%	1.90%

Borrowings and Other Financin_4

Borrowings and Other Financing Instruments Term Loan Agreement (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Short-term Debt [Line Items]
Amount outstanding at period end	$ 595	$ 1,038
Xcel Energy Inc.
Short-term Debt [Line Items]
Amount outstanding at period end	500	$ 488
Xcel Energy Inc. | 364-Day Term Loan
Short-term Debt [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	500
Amount outstanding at period end	500
Line of Credit Facility, Remaining Borrowing Capacity	0
Parent [Member] | Short-term Debt [Member] | 364-Day Term Loan
Short-term Debt [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	$ 500
Line of Credit Facility, Expiration Period	364 days

Borrowings and Other Financin_5

Borrowings and Other Financing Instruments Bilateral Credit Agreement (Details) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Short-term Debt [Line Items]
Amount outstanding at period end	$ 595	$ 1,038
NSP Minnesota | Letter of Credit | Bilateral Credit Agreement [Member]
Short-term Debt [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	75
Amount outstanding at period end	22
Line of Credit Facility, Remaining Borrowing Capacity	$ 53

Borrowings and Other Financin_6

Borrowings and Other Financing Instruments Letters of Credit (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Line of Credit Facility [Line Items]
Amount outstanding at period end	$ 595	$ 1,038
Letter of Credit
Line of Credit Facility [Line Items]
Line of Credit Facility, Expiration Period	1 year
Amount outstanding at period end	$ 20	$ 49

Borrowings and Other Financin_7

Borrowings and Other Financing Instruments Credit Facilities (Details) - Revolving Credit Facility [Member]		12 Months Ended
		Dec. 31, 2019USD ($)	Dec. 31, 2018USD ($)
Line of Credit Facility [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity		$ 3,100,000,000
Parent [Member]
Line of Credit Facility [Line Items]
Term Of Each Additional Period Revolving Termination Date Can Be Extended Subject To Majority Bank Group Approval		1 year
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
Line of Credit Facility, Maximum Borrowing Capacity	[1]	3,100,000,000
Drawn	[2]	116,000,000
Available		$ 2,984,000,000
Xcel Energy Inc.
Line of Credit Facility [Line Items]
Line Of Credit Facility Debt To Total Capitalization Ratio (as a percent)	[3],[4]	58.00%	58.00%
Line Of Credit Facility Maximum Amount Credit Facility May Be Increased	[4]	$ 200,000,000
Number Of Additional Periods Revolving Termination Date Can Be Extended Subject To Majority Bank Group Approval	[4],[5]	2
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
Line of Credit Facility, Maximum Borrowing Capacity	[1]	1,250,000,000
Drawn	[2]	0
Available		$ 1,250,000,000
Direct advances on the credit facility outstanding			$ 0
NSP-Wisconsin
Line of Credit Facility [Line Items]
Term Of Each Additional Period Revolving Termination Date Can Be Extended Subject To Majority Bank Group Approval		1 year
Line Of Credit Facility Debt To Total Capitalization Ratio (as a percent)	[3]	48.00%	48.00%
Number Of Additional Periods Revolving Termination Date Can Be Extended Subject To Majority Bank Group Approval	[5]	1
Line Of Credit Facility Maximum Debt To Total Capitalization Ratio Allowed		65.00%
Line of Credit Facility, Maximum Borrowing Capacity	[1]	$ 150,000,000
Drawn	[2]	65,000,000
Available		85,000,000
Direct advances on the credit facility outstanding		$ 0	$ 0
NSP Minnesota
Line of Credit Facility [Line Items]
Term Of Each Additional Period Revolving Termination Date Can Be Extended Subject To Majority Bank Group Approval		1 year
Line Of Credit Facility Debt To Total Capitalization Ratio (as a percent)	[3]	48.00%	48.00%
Line Of Credit Facility Maximum Amount Credit Facility May Be Increased		$ 100,000,000
Number Of Additional Periods Revolving Termination Date Can Be Extended Subject To Majority Bank Group Approval	[5]	2
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
Line of Credit Facility, Maximum Borrowing Capacity	[1]	500,000,000
Drawn	[2]	2,000,000
Available		498,000,000
Direct advances on the credit facility outstanding		$ 0	$ 0
SPS
Line of Credit Facility [Line Items]
Term Of Each Additional Period Revolving Termination Date Can Be Extended Subject To Majority Bank Group Approval		1 year
Line Of Credit Facility Debt To Total Capitalization Ratio (as a percent)	[3]	46.00%	46.00%
Line Of Credit Facility Maximum Amount Credit Facility May Be Increased		$ 50,000,000
Number Of Additional Periods Revolving Termination Date Can Be Extended Subject To Majority Bank Group Approval	[5]	2
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
Line of Credit Facility, Maximum Borrowing Capacity	[1]	500,000,000
Drawn	[2]	40,000,000
Available		460,000,000
Direct advances on the credit facility outstanding		$ 0	$ 0
PSCo
Line of Credit Facility [Line Items]
Term Of Each Additional Period Revolving Termination Date Can Be Extended Subject To Majority Bank Group Approval		1 year
Line Of Credit Facility Debt To Total Capitalization Ratio (as a percent)	[3]	44.00%	46.00%
Line Of Credit Facility Maximum Amount Credit Facility May Be Increased		$ 100,000,000
Number Of Additional Periods Revolving Termination Date Can Be Extended Subject To Majority Bank Group Approval	[5]	2
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
Line of Credit Facility, Maximum Borrowing Capacity	[1]	700,000,000
Drawn	[2]	9,000,000
Available		691,000,000
Direct advances on the credit facility outstanding		$ 0	$ 0
[1]	These credit facilities mature in June 2024 .
[2]	Includes outstanding commercial paper and letters of credit.
[3]	Each credit facility has a financial covenant requiring that the debt-to-total capitalization ratio be less than or equal to 65% .
[4]	The Xcel Energy Inc. credit facility has a cross-default provision that 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% of Xcel Energy’s consolidated total assets) default on indebtedness in an aggregate principal amount exceeding $75 million .
[5]	All extension requests are subject to majority bank group approval.

Borrowings and Other Financin_8

Borrowings and Other Financing Instruments Amended Credit Agreements (Details) - USD ($) $ in Millions	Dec. 31, 2019	Jun. 30, 2019
Revolving Credit Facility [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	$ 3,100
Xcel Energy Inc. | Revolving Credit Facility [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	1,250	$ 1,000
Xcel Energy Inc. | Swingline Subfacility [Domain]
Line of Credit Facility [Line Items]
Face Amount	75
SPS | Revolving Credit Facility [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	$ 500	$ 400

Borrowings and Other Financin_9

Borrowings and Other Financing Instruments Long-Term Borrowings and Other Financing Instruments (Details) - USD ($) $ in Millions		Dec. 31, 2019	Dec. 31, 2018
Long-Term Borrowings and Other Financing Instruments
Long-term Debt, Gross		$ 18,109	$ 16,209
Long-term debt			(85)
2020		702
2021		421
2022		900
2023		650
2024		552
Long-term Debt and Lease Obligation		17,407	15,803
NSP Minnesota
Long-Term Borrowings and Other Financing Instruments
Unamortized discount		(31)	(21)
Unamortized Debt Issuance Expense		(48)	(42)
Current Maturities		(300)	0
Long-term Debt		5,221	4,937
NSP Minnesota | Mortgage bonds | Series Due Aug. 15, 2020 [Member]
Long-Term Borrowings and Other Financing Instruments
Face Amount		$ 300	300
Debt Instrument, Interest Rate, Stated Percentage		2.20%
NSP Minnesota | Mortgage bonds | Series Due Sept. 15, 2047
Long-Term Borrowings and Other Financing Instruments
Face Amount		$ 600	600
Debt Instrument, Interest Rate, Stated Percentage		3.60%
NSP Minnesota | Mortgage bonds | Series Due Aug. 15, 2022 [Member]
Long-Term Borrowings and Other Financing Instruments
Face Amount		$ 300	300
Debt Instrument, Interest Rate, Stated Percentage		2.15%
NSP Minnesota | Mortgage bonds | Series Due July 1, 2025 [Member]
Long-Term Borrowings and Other Financing Instruments
Face Amount		$ 250	250
Debt Instrument, Interest Rate, Stated Percentage		7.13%
NSP Minnesota | Mortgage bonds | Series Due March 1, 2028 [Member]
Long-Term Borrowings and Other Financing Instruments
Face Amount		$ 150	150
Debt Instrument, Interest Rate, Stated Percentage		6.50%
NSP Minnesota | Mortgage bonds | Series Due July 15, 2035 [Member]
Long-Term Borrowings and Other Financing Instruments
Face Amount		$ 250	250
Debt Instrument, Interest Rate, Stated Percentage		5.25%
NSP Minnesota | Mortgage bonds | Series Due June 1, 2036 [Domain]
Long-Term Borrowings and Other Financing Instruments
Face Amount		$ 400	400
Debt Instrument, Interest Rate, Stated Percentage		6.25%
NSP Minnesota | Mortgage bonds | Series Due May 15, 2023 [Member]
Long-Term Borrowings and Other Financing Instruments
Face Amount		$ 400	400
Debt Instrument, Interest Rate, Stated Percentage		2.60%
NSP Minnesota | Mortgage bonds | Series Due July 1, 2037 [Member]
Long-Term Borrowings and Other Financing Instruments
Face Amount		$ 350	350
Debt Instrument, Interest Rate, Stated Percentage		6.20%
NSP Minnesota | Mortgage bonds | Series Due Nov. 1, 2039 [Member]
Long-Term Borrowings and Other Financing Instruments
Face Amount		$ 300	300
Debt Instrument, Interest Rate, Stated Percentage		5.35%
NSP Minnesota | Mortgage bonds | Series Due Aug. 15, 2040 [Member]
Long-Term Borrowings and Other Financing Instruments
Face Amount		$ 250	250
Debt Instrument, Interest Rate, Stated Percentage		4.85%
NSP Minnesota | Mortgage bonds | Series Due Aug. 15, 2042 [Member]
Long-Term Borrowings and Other Financing Instruments
Face Amount		$ 500	500
Debt Instrument, Interest Rate, Stated Percentage		3.40%
NSP Minnesota | Mortgage bonds | Series Due May 15, 2044 [Member]
Long-Term Borrowings and Other Financing Instruments
Face Amount		$ 300	300
Debt Instrument, Interest Rate, Stated Percentage		4.13%
NSP Minnesota | Mortgage bonds | Series Due Aug. 15, 2045 [Member]
Long-Term Borrowings and Other Financing Instruments
Face Amount		$ 300	300
Debt Instrument, Interest Rate, Stated Percentage		4.00%
NSP Minnesota | Mortgage bonds | Series Due May 15, 2046 [Member]
Long-Term Borrowings and Other Financing Instruments
Face Amount		$ 350	350
Debt Instrument, Interest Rate, Stated Percentage		3.60%
NSP Minnesota | Mortgage bonds | Series Due March 1, 2050
Long-Term Borrowings and Other Financing Instruments
Face Amount	[1]	$ 600	0
Debt Instrument, Interest Rate, Stated Percentage	[1]	2.90%
Other Subsidiaries
Long-Term Borrowings and Other Financing Instruments
Current Maturities		$ (2)	(1)
Long-term Debt and Lease Obligation		26	25
Other Subsidiaries | Various Eloigne Co. affordable housing project notes
Long-Term Borrowings and Other Financing Instruments
Long-term Debt, Gross		$ 28	$ 26
Other Subsidiaries | Various Eloigne Co. affordable housing project notes | Minimum
Long-Term Borrowings and Other Financing Instruments
Debt Instrument, Interest Rate, Stated Percentage		0.00%	0.00%
Other Subsidiaries | Various Eloigne Co. affordable housing project notes | Maximum
Long-Term Borrowings and Other Financing Instruments
Debt Instrument, Interest Rate, Stated Percentage		6.90%	7.05%
Xcel Energy Inc.
Long-Term Borrowings and Other Financing Instruments
Unamortized discount		$ (5)	$ (5)
Unamortized Debt Issuance Expense		(28)	(21)
Capital Lease Obligations, Current	[2]	0	2
Xcel Energy Inc. | Capital lease obligations
Long-Term Borrowings and Other Financing Instruments
Long-term debt	[2]	0	(60)
Long-term Debt and Lease Obligation		3,947	3,316
Xcel Energy Inc. | Unsecured Debt [Member] | Series Due May 15, 2020 [Member]
Long-Term Borrowings and Other Financing Instruments
Face Amount	[3]	$ 0	550
Debt Instrument, Interest Rate, Stated Percentage	[3]	4.70%
Xcel Energy Inc. | Unsecured Debt [Member] | Series Due June 15, 2028
Long-Term Borrowings and Other Financing Instruments
Face Amount	[4]	$ 130	0
Debt Instrument, Interest Rate, Stated Percentage	[4]	4.00%
Xcel Energy Inc. | Unsecured Debt [Member] | Series Due June 15, 2028 2 [Member]
Long-Term Borrowings and Other Financing Instruments
Face Amount	[5]	$ 500	500
Debt Instrument, Interest Rate, Stated Percentage	[5]	4.00%
Xcel Energy Inc. | Unsecured Debt [Member] | Series Due March 15, 2021 [Member]
Long-Term Borrowings and Other Financing Instruments
Face Amount		$ 400	400
Debt Instrument, Interest Rate, Stated Percentage		2.40%
Xcel Energy Inc. | Unsecured Debt [Member] | Series Due March 15, 2022 [Member]
Long-Term Borrowings and Other Financing Instruments
Face Amount		$ 300	300
Debt Instrument, Interest Rate, Stated Percentage		2.60%
Xcel Energy Inc. | Unsecured Debt [Member] | Series Due June 1, 2025 [Member]
Long-Term Borrowings and Other Financing Instruments
Face Amount		$ 250	250
Debt Instrument, Interest Rate, Stated Percentage		3.30%
Xcel Energy Inc. | Unsecured Debt [Member] | Series Due June 1, 2025 2 [Member]
Long-Term Borrowings and Other Financing Instruments
Face Amount		$ 350	350
Debt Instrument, Interest Rate, Stated Percentage		3.30%
Xcel Energy Inc. | Unsecured Debt [Member] | Series Due Dec. 1, 2026 [Member]
Long-Term Borrowings and Other Financing Instruments
Face Amount		$ 500	500
Debt Instrument, Interest Rate, Stated Percentage		3.35%
Xcel Energy Inc. | Unsecured Debt [Member] | Series Due Dec. 1, 2029 [Member]
Long-Term Borrowings and Other Financing Instruments
Face Amount	[4]	$ 500	0
Debt Instrument, Interest Rate, Stated Percentage	[4]	2.60%
Xcel Energy Inc. | Unsecured Debt [Member] | Series Due July 1, 2036 [Member]
Long-Term Borrowings and Other Financing Instruments
Face Amount		$ 300	300
Debt Instrument, Interest Rate, Stated Percentage		6.50%
Xcel Energy Inc. | Unsecured Debt [Member] | Series Due Sept. 15, 2041 [Member]
Long-Term Borrowings and Other Financing Instruments
Face Amount		$ 250	250
Debt Instrument, Interest Rate, Stated Percentage		4.80%
Xcel Energy Inc. | Unsecured Debt [Member] | Series Due Dec. 1, 2049 [Member]
Long-Term Borrowings and Other Financing Instruments
Face Amount	[4]	$ 500	0
Debt Instrument, Interest Rate, Stated Percentage	[4]	3.50%
NSP-Wisconsin
Long-Term Borrowings and Other Financing Instruments
Unamortized discount		$ (3)	(3)
Unamortized Debt Issuance Expense		(8)	(9)
Long-term Debt		808	807
NSP-Wisconsin | Mortgage bonds | Series Due September 1, 2048 [Member]
Long-Term Borrowings and Other Financing Instruments
Face Amount	[6]	$ 200	200
Debt Instrument, Interest Rate, Stated Percentage	[6]	4.20%
NSP-Wisconsin | Mortgage bonds | Series Due Dec. 1, 2047
Long-Term Borrowings and Other Financing Instruments
Face Amount		$ 100	100
Debt Instrument, Interest Rate, Stated Percentage		3.75%
NSP-Wisconsin | Mortgage bonds | Series Due June 15, 2024 [Member]
Long-Term Borrowings and Other Financing Instruments
Face Amount		$ 100	100
Debt Instrument, Interest Rate, Stated Percentage		3.30%
NSP-Wisconsin | Mortgage bonds | Series Due June 15, 2024 2 [Member]
Long-Term Borrowings and Other Financing Instruments
Face Amount		$ 100	100
Debt Instrument, Interest Rate, Stated Percentage		3.30%
NSP-Wisconsin | Mortgage bonds | Series Due Sept. 1, 2038 [Member]
Long-Term Borrowings and Other Financing Instruments
Face Amount		$ 200	200
Debt Instrument, Interest Rate, Stated Percentage		6.38%
NSP-Wisconsin | Mortgage bonds | Series Due Oct. 1, 2042 [Member]
Long-Term Borrowings and Other Financing Instruments
Face Amount		$ 100	100
Debt Instrument, Interest Rate, Stated Percentage		3.70%
NSP-Wisconsin | City of La Crosse resource recovery bond | Series Due Nov. 1, 2021 [Member]
Long-Term Borrowings and Other Financing Instruments
Face Amount		$ 19	19
Debt Instrument, Interest Rate, Stated Percentage		6.00%
PSCo
Long-Term Borrowings and Other Financing Instruments
Unamortized discount		$ (24)	(14)
Unamortized Debt Issuance Expense		(41)	(33)
Current Maturities		(400)	(406)
Long-term Debt and Lease Obligation		4,985	4,592
PSCo | Capital lease obligations
Long-Term Borrowings and Other Financing Instruments
Long-term debt	[7]	$ 0	$ (145)
PSCo | Capital lease obligations | Minimum
Long-Term Borrowings and Other Financing Instruments
Debt Instrument, Interest Rate, Stated Percentage		11.20%	11.20%
PSCo | Capital lease obligations | Maximum
Long-Term Borrowings and Other Financing Instruments
Debt Instrument, Interest Rate, Stated Percentage		14.30%	14.30%
PSCo | Mortgage bonds | Series Due June 1, 2019 [Member]
Long-Term Borrowings and Other Financing Instruments
Face Amount	[8]	$ 0	$ 400
Debt Instrument, Interest Rate, Stated Percentage	[3]	5.13%
PSCo | Mortgage bonds | Series Due June 15, 2028
Long-Term Borrowings and Other Financing Instruments
Face Amount	[9]	$ 350	350
Debt Instrument, Interest Rate, Stated Percentage	[3]	3.70%
PSCo | Mortgage bonds | Series Due June 15, 2048
Long-Term Borrowings and Other Financing Instruments
Face Amount	[9]	$ 350	350
Debt Instrument, Interest Rate, Stated Percentage	[3]	4.10%
PSCo | Mortgage bonds | Series Due June 15, 2047
Long-Term Borrowings and Other Financing Instruments
Face Amount		$ 400	400
Debt Instrument, Interest Rate, Stated Percentage		3.80%
PSCo | Mortgage bonds | Series Due March 1, 2050
Long-Term Borrowings and Other Financing Instruments
Face Amount	[10]	$ 550	0
Debt Instrument, Interest Rate, Stated Percentage	[3]	3.20%
PSCo | Mortgage bonds | Series Due Nov. 15, 2020 [Member]
Long-Term Borrowings and Other Financing Instruments
Face Amount		$ 400	400
Debt Instrument, Interest Rate, Stated Percentage		3.20%
PSCo | Mortgage bonds | Series Due Sept. 15, 2022 [Member]
Long-Term Borrowings and Other Financing Instruments
Face Amount		$ 300	300
Debt Instrument, Interest Rate, Stated Percentage		2.25%
PSCo | Mortgage bonds | Series Due March 15, 2023 [Member]
Long-Term Borrowings and Other Financing Instruments
Face Amount		$ 250	250
Debt Instrument, Interest Rate, Stated Percentage		2.50%
PSCo | Mortgage bonds | Series Due May 15, 2025 [Member]
Long-Term Borrowings and Other Financing Instruments
Face Amount		$ 250	250
Debt Instrument, Interest Rate, Stated Percentage		2.90%
PSCo | Mortgage bonds | Series Due Sept. 1, 2037 [Member]
Long-Term Borrowings and Other Financing Instruments
Face Amount		$ 350	350
Debt Instrument, Interest Rate, Stated Percentage		6.25%
PSCo | Mortgage bonds | Series Due Aug. 1, 2038 [Member]
Long-Term Borrowings and Other Financing Instruments
Face Amount		$ 300	300
Debt Instrument, Interest Rate, Stated Percentage		6.50%
PSCo | Mortgage bonds | Series Due Aug. 15, 2041 [Member]
Long-Term Borrowings and Other Financing Instruments
Face Amount		$ 250	250
Debt Instrument, Interest Rate, Stated Percentage		4.75%
PSCo | Mortgage bonds | Series Due Sept. 15, 2042 [Member]
Long-Term Borrowings and Other Financing Instruments
Face Amount		$ 500	500
Debt Instrument, Interest Rate, Stated Percentage		3.60%
PSCo | Mortgage bonds | Series Due March 15, 2043 [Member]
Long-Term Borrowings and Other Financing Instruments
Face Amount		$ 250	250
Debt Instrument, Interest Rate, Stated Percentage		3.95%
PSCo | Mortgage bonds | Series Due March 15, 2044 [Member]
Long-Term Borrowings and Other Financing Instruments
Face Amount		$ 300	300
Debt Instrument, Interest Rate, Stated Percentage		4.30%
PSCo | Mortgage bonds | Series Due June 15, 2046 [Member]
Long-Term Borrowings and Other Financing Instruments
Face Amount		$ 250	250
Debt Instrument, Interest Rate, Stated Percentage		3.55%
PSCo | Mortgage bonds | Series Due September 15, 2049
Long-Term Borrowings and Other Financing Instruments
Face Amount	[10]	$ 400	0
Debt Instrument, Interest Rate, Stated Percentage	[3]	4.05%
SPS
Long-Term Borrowings and Other Financing Instruments
Unamortized discount		$ (7)	(4)
Unamortized Debt Issuance Expense		(23)	(20)
Long-term Debt		2,420	2,126
SPS | Mortgage bonds | Series Due August 15, 2047
Long-Term Borrowings and Other Financing Instruments
Face Amount		$ 450	450
Debt Instrument, Interest Rate, Stated Percentage		3.70%
SPS | Mortgage bonds | Series Due June 15, 2024 [Member]
Long-Term Borrowings and Other Financing Instruments
Face Amount		$ 150	150
Debt Instrument, Interest Rate, Stated Percentage		3.30%
SPS | Mortgage bonds | Series Due June 15, 2024 2 [Member]
Long-Term Borrowings and Other Financing Instruments
Face Amount		$ 200	200
Debt Instrument, Interest Rate, Stated Percentage		3.30%
SPS | Mortgage bonds | Series Due Aug. 15, 2041 [Member]
Long-Term Borrowings and Other Financing Instruments
Face Amount		$ 200	200
Debt Instrument, Interest Rate, Stated Percentage		4.50%
SPS | Mortgage bonds | Series Due Aug. 15, 2041 2 [Member]
Long-Term Borrowings and Other Financing Instruments
Face Amount		$ 100	100
Debt Instrument, Interest Rate, Stated Percentage		4.50%
SPS | Mortgage bonds | Series Due Aug. 15, 2041 3 [Member]
Long-Term Borrowings and Other Financing Instruments
Face Amount		$ 100	100
Debt Instrument, Interest Rate, Stated Percentage		4.50%
SPS | Mortgage bonds | Series Due August 15, 2046 [Member]
Long-Term Borrowings and Other Financing Instruments
Face Amount		$ 300	300
Debt Instrument, Interest Rate, Stated Percentage		3.40%
SPS | Mortgage bonds | Series Due Nov. 15, 2048 [Member]
Long-Term Borrowings and Other Financing Instruments
Face Amount	[11]	$ 300	300
Debt Instrument, Interest Rate, Stated Percentage	[11]	4.40%
SPS | Mortgage bonds | Series Due June 15, 2049
Long-Term Borrowings and Other Financing Instruments
Face Amount	[12]	$ 300	0
Debt Instrument, Interest Rate, Stated Percentage	[12]	3.75%
SPS | Unsecured Debt [Member] | Senior C and D Due Oct. 1, 2033 [Member]
Long-Term Borrowings and Other Financing Instruments
Face Amount		$ 100	100
Debt Instrument, Interest Rate, Stated Percentage		6.00%
SPS | Unsecured Debt [Member] | Senior F Due Oct. 1, 2036 [Member]
Long-Term Borrowings and Other Financing Instruments
Face Amount		$ 250	$ 250
Debt Instrument, Interest Rate, Stated Percentage		6.00%
[1]	2019 financing
[2]	Xcel Energy adopted ASC 842 on Jan. 1, 2019, which refers to capital leases as finance leases. Under ASC 842, the present value of future finance lease payments is included in other current liabilities and other noncurrent liabilities rather than debt.
[3]	Note was redeemed on Dec. 23, 2019.
[4]	2019 financing
[5]	2018 financing
[6]	2018 financing
[7]	PSCo adopted ASC 842 on Jan. 1, 2019, which refers to capital leases as finance leases. Under ASC 842, the present value of future finance lease payments is included in other current liabilities and other noncurrent liabilities rather than debt.
[8]	Bond was redeemed on March 29, 2019.
[9]	2018 financing.
[10]	2019 financing
[11]	2018 financing
[12]	2019 financing

Borrowings and Other Financi_10

Borrowings and Other Financing Instruments Deferred Financing Costs (Details) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Deferred Financing Costs [Abstract]
Deferred Finance Costs, Noncurrent, Net	$ 148	$ 126

Borrowings and Other Financi_11

Borrowings and Other Financing Instruments Forward Equity Agreements (Details) - Forward Equity Agreements [Member] - USD ($) $ / shares in Units, shares in Millions, $ in Millions	Dec. 31, 2019	Nov. 01, 2019	Aug. 29, 2019	Nov. 30, 2018
Forward Contract Indexed to Issuer's Equity [Line Items]
Common stock, value, to be issued through Forward Equity Agreement		$ 743		$ 459
Common stock, shares to be issued through Forward Equity Agreement		11.8		9.4
Common Stock, Shares Issued through Forward Equity Agreement			9.4
Common Stock, Value Issued through Forward Equity Agreement			$ 453
Common stock, initial shares in an agreement		10.3
Common stock, additional shares in an agreement		1.5
Period end settlement price, in shares	11.8
Period end settlement price, in cash	$ 739
Period end net cash settlement price	$ 6
Period end net share settlement price	0.1
Common shares, price per share used in forward calculation		$ 62.69
Common stock, interest rate spread used in forward calculation		0.75%
Minimum
Forward Contract Indexed to Issuer's Equity [Line Items]
Expected settlement price	$ 730
Maximum
Forward Contract Indexed to Issuer's Equity [Line Items]
Expected settlement price	$ 740

Borrowings and Other Financi_12

Borrowings and Other Financing Instruments Other Equity (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Dividend Reinvestment Program [Line Items]
Proceeds from Issuance of Common Stock	$ 458	$ 230	$ 0
DividendReinvestmentProgram [Member]
Dividend Reinvestment Program [Line Items]
Proceeds from Issuance of Common Stock	$ 39	$ 39

Borrowings and Other Financi_13

Borrowings and Other Financing Instruments Capital Stock (Details) - $ / shares	Dec. 31, 2019	Dec. 31, 2018
Debt Instrument [Line Items]
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)	524,539,000	514,036,787
Xcel Energy Inc.
Debt Instrument [Line Items]
Preferred Stock, Shares Outstanding (in shares)		0
Common Stock, Shares Authorized (in shares)	1,000,000,000
Common Stock, Par Value (in dollars per share)	$ 2.50
Common Stock, Shares Outstanding (in shares)	524,539,000	514,036,787
Xcel Energy Inc.
Debt Instrument [Line Items]
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
PSCo
Debt Instrument [Line Items]
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
Debt Instrument [Line Items]
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 Financi_14

Borrowings and Other Financing Instruments Dividend and Other Capital-Related Restrictions (Details) $ in Millions	12 Months Ended
	Dec. 31, 2019USD ($)
NSP Minnesota
Debt Instrument [Line Items]
Equity to total capitalization ratio, low end of range (in hundredths)	47.10%
Equity to total capitalization ratio, high end of range (in hundredths)	57.50%
Equity to total capitalization ratio	52.30%
Unrestricted Retained Earnings Per State Regulatory Commissions Dividend Restrictions	$ 1,147
Capitalization, Short term debt, long term debt and equity	11,634
Maximum total capitalization	12,700
Maximum additional short term debt authorized for issuance	$ 1,905	[1]
Maximum percentage of short term debt to total capitalization (in hundredths)	15.00%
Maximum Percentage of long term debt to total capitalization	52.93%	[1]
NSP-Wisconsin
Debt Instrument [Line Items]
Minimum calendar year average equity to total capitalization ratio authorized by state commission	51.50%
Equity to total capitalization ratio	51.80%
Unrestricted Retained Earnings Per State Regulatory Commissions Dividend Restrictions	$ 12	[2]
Capitalization, Short term debt, long term debt and equity	1,827
Maximum annual dividends that can be paid if equity capitalization ratio condition is not met	55
Maximum additional long term debt authorized for issuance	0	[3]
Maximum additional short term debt authorized for issuance	$ 150
SPS
Debt Instrument [Line Items]
Equity to total capitalization ratio (excluding short-term debt), low end of range (in hundredths)	45.00%	[4]
Equity to total capitalization ratio (excluding short-term debt), high end of range (in hundredths)	55.00%	[4]
Equity to total capitalization ratio (excluding short-term debt) (in hundredths)	54.40%	[4]
Unrestricted Retained Earnings Per State Regulatory Commissions Dividend Restrictions	$ 535	[5]
Capitalization, Short term debt, long term debt and equity	5,304
Maximum additional long term debt authorized for issuance	0	[6]
Maximum additional short term debt authorized for issuance	600
PSCo
Debt Instrument [Line Items]
Maximum additional long term debt authorized for issuance	150
Maximum additional short term debt authorized for issuance	$ 800
[1]	NSP-Minnesota has authorization to issue long-term securities provided the equity-to-total capitalization remains within the required range, and to issue short-term debt provided it does not exceed 15% of total capitalization.
[2]	Cannot pay annual dividends in excess of approximately $55 million
[3]	NSP-Wisconsin filed for additional long-term debt authorization in December 2019.
[4]	Excludes short-term debt.
[5]	May not pay a dividend that would cause a loss of its investment grade bond rating.
[6]	SPS filed for additional long-term debt authorization in February 2020.

Borrowings and Other Financi_15

Borrowings and Other Financing Instruments Borrowings Phantom (Details)	Dec. 31, 2019
Xcel Energy Inc. | Revolving Credit Facility [Member]
Short-term Debt [Line Items]
Line Of Credit Facility Maximum Debt To Total Capitalization Ratio Allowed	65.00%

Revenues (Details)

Revenues (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Total revenue from contracts with customers
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	$ 11,032	$ 11,020
Total revenue from contracts with customers | Regulated Electric
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	9,144	9,339
Total revenue from contracts with customers | Natural Gas
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	1,814	1,612
Total revenue from contracts with customers | All Other
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	74	69
Retail
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	9,619	9,508
Retail | Residential
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	4,045	3,945
Retail | C&I
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	5,440	5,423
Retail | Other
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	134	140
Retail | Regulated Electric
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	7,851	7,927
Retail | Regulated Electric | Residential
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	2,877	2,919
Retail | Regulated Electric | C&I
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	4,844	4,874
Retail | Regulated Electric | Other
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	130	134
Retail | Natural Gas
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	1,694	1,512
Retail | Natural Gas | Residential
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	1,127	988
Retail | Natural Gas | C&I
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	567	524
Retail | Natural Gas | Other
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	0	0
Retail | All Other
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	74	69
Retail | All Other | Residential
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	41	38
Retail | All Other | C&I
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	29	25
Retail | All Other | Other
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	4	6
Wholesale
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	737	791
Wholesale | Regulated Electric
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	737	791
Wholesale | Natural Gas
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	0	0
Wholesale | All Other
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	0	0
Transmission
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	507	523
Transmission | Regulated Electric
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	507	523
Transmission | Natural Gas
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	0	0
Transmission | All Other
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	0	0
Other
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	169	198
Other | Regulated Electric
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	49	98
Other | Natural Gas
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	120	100
Other | All Other
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	0	0
Alternative revenue and other
Disaggregation of Revenue [Line Items]
Alternative revenue and other	497	517
Alternative revenue and other | Regulated Electric
Disaggregation of Revenue [Line Items]
Alternative revenue and other	431	380
Alternative revenue and other | Natural Gas
Disaggregation of Revenue [Line Items]
Alternative revenue and other	54	127
Alternative revenue and other | All Other
Disaggregation of Revenue [Line Items]
Alternative revenue and other	12	10
Operating Segments
Disaggregation of Revenue [Line Items]
Total revenues	11,529	11,537
Operating Segments | Regulated Electric
Disaggregation of Revenue [Line Items]
Total revenues	9,575	9,719
Operating Segments | Natural Gas
Disaggregation of Revenue [Line Items]
Total revenues	1,868	1,739
Operating Segments | All Other
Disaggregation of Revenue [Line Items]
Total revenues	$ 86	$ 79

Income Taxes (Details)

Income Taxes (Details) - USD ($)	1 Months Ended	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2019	Dec. 31, 2018		Dec. 31, 2017	Dec. 31, 2016
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
Unrecognized Tax Benefits [Abstract]
Unrecognized tax benefit — Permanent tax positions					$ 35,000,000	$ 28,000,000
Unrecognized tax benefit — Temporary tax positions					9,000,000	9,000,000
Total unrecognized tax benefit	39,000,000	$ 44,000,000	$ 39,000,000	$ 134,000,000	44,000,000	37,000,000		$ 39,000,000	$ 134,000,000
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Balance at Jan. 1		37,000,000	39,000,000	134,000,000
Unrecognized Tax Benefits, Increase Resulting from Current Period Tax Positions		10,000,000	9,000,000	6,000,000
Unrecognized Tax Benefits, Decrease Resulting from Current Period Tax Positions		(4,000,000)	(4,000,000)	(4,000,000)
Unrecognized Tax Benefits Increases Resulting From Prior Period Tax Positions		1,000,000	2,000,000	15,000,000
Unrecognized Tax Benefits Decreases Resulting From Prior Period Tax Positions		0	(4,000,000)	(105,000,000)
Unrecognized Tax Benefits, Decrease Resulting from Settlements with Taxing Authorities		0	(5,000,000)	(7,000,000)
Balance at Dec. 31	39,000,000	44,000,000	37,000,000	39,000,000
Tax Benefits Associated With NOL And Tax Credit Carryforwards [Abstract]
NOL and tax credit carryforwards					(40,000,000)	(35,000,000)
Net Deferred Tax Liability associated with the Unrecognized Tax Benefit Amounts and Related NOLs and Tax Credit Carryforwards					(29,000,000)	(24,000,000)
Upper bound of decrease in unrecognized tax benefit that is reasonably possible					28,000,000
Unrecognized Tax Benefits, Income Tax Penalties Accrued					0	0		0
Unrecognized Tax Benefits, Income Tax Penalties and Interest Accrued [Abstract]
Unrecognized Tax Benefits, Interest on Income Taxes Accrued					0	0		$ 0	$ (3,000,000)
Unrecognized Tax Benefits, Interest on Income Taxes Accrued		0	0	(3,000,000)
Components of Income Tax Expense (Benefit), Continuing Operations [Abstract]
Current Federal Tax Expense (Benefit)		(16,000,000)	(34,000,000)	1,000,000
Current State and Local Tax Expense (Benefit)		4,000,000	8,000,000	(11,000,000)
Current Change In Unrecognized Tax Expense (Benefit)		2,000,000	(6,000,000)	(83,000,000)
Deferred Federal Income Tax Expense (Benefit)		55,000,000	122,000,000	460,000,000
Deferred State and Local Income Tax Expense (Benefit)		83,000,000	85,000,000	107,000,000
Deferred Change In Unrecognized Tax Expense (Benefit)		5,000,000	11,000,000	73,000,000
Deferred investment tax credits		(5,000,000)	(5,000,000)	(5,000,000)
Income Tax Expense (Benefit)		128,000,000	181,000,000	542,000,000
Deferred Income Tax Expense (Benefit), Continuing Operations [Abstract]
Deferred tax expense (benefit) excluding selected items		344,000,000	320,000,000	(2,939,000,000)
Amortization and adjustments to deferred income taxes on income tax regulatory assets and liabilities		(206,000,000)	(102,000,000)	3,583,000,000
Other Comprehensive Income (Loss), Tax		5,000,000	0	(4,000,000)
Deferred Income Tax Expense (Benefit)		$ 143,000,000	$ 218,000,000	$ 640,000,000
Deferred Tax Liabilities, Gross [Abstract]
Deferred Tax Liabilities, Property, Plant and Equipment					5,474,000,000	5,082,000,000	[1]
Deferred Tax Liabilities, Operating Lease Asset					449,000,000	0	[1]
Deferred Tax Liabilities, Regulatory Assets					598,000,000	599,000,000	[1]
Pension expense					173,000,000	178,000,000	[1]
Deferred Tax Liabilities, Other					70,000,000	60,000,000	[1]
Deferred Tax Liabilities, Gross					6,764,000,000	5,919,000,000	[1]
Deferred Tax Assets, Gross [Abstract]
Deferred Tax Assets Regulatory Liabilities					847,000,000	879,000,000	[1]
Deferred Tax Assets, Operating Lease Liabilities					449,000,000	0	[1]
Deferred Tax Assets Tax credit carryforward					727,000,000	642,000,000	[1]
Deferred Tax Assets, Operating Loss Carryforwards					38,000,000	51,000,000	[1]
Deferred Tax Assets, Valuation Allowance					(67,000,000)	(79,000,000)	[1]
Deferred Tax Assets, Tax Deferred Expense, Compensation and Benefits, Employee Benefits					128,000,000	124,000,000	[1]
Deferred Tax Assets Deferred Investment Tax Credits					14,000,000	16,000,000	[1]
Deferred Tax Assets Rate Refund					26,000,000	60,000,000	[1]
Deferred Tax Assets, Other					93,000,000	61,000,000	[1]
Deferred Tax Assets, Net of Valuation Allowance					2,255,000,000	1,754,000,000	[1]
Deferred Tax Liabilities, Net					$ 4,509,000,000	$ 4,165,000,000	[1]
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
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
[1]	Prior periods have been reclassified to conform to current year presentation.

Income Taxes Federal Audit (Det

Income Taxes Federal Audit (Details)	3 Months Ended
	Dec. 31, 2018USD ($)
Internal Revenue Service (IRS) [Member]
Income Tax Examination [Line Items]
Potential Tax Adjustments	$ 0

Income Taxes Unrecognized Tax B

Income Taxes Unrecognized Tax Benefit (Details) - USD ($)		12 Months Ended
		Dec. 31, 2019	Dec. 31, 2018		Dec. 31, 2017		Dec. 31, 2016
Income Tax Examination [Line Items]
Unrecognized Tax Benefits, Interest on Income Taxes Accrued		$ 0	$ 0		$ 0		$ (3,000,000)
Interest Expense (Income) related to unrecognized tax benefits		$ 0	$ 0		$ 3,000,000
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent		21.00%	21.00%	[1]	35.00%	[1]	35.00%
Unrecognized Tax Benefits, Income Tax Penalties Accrued		$ 0	$ 0		$ 0
Unrecognized Tax Benefits that Would Impact Effective Tax Rate		$ 35,000,000	$ 28,000,000
Effective Income Tax Rate Reconciliation, State and Local Income Taxes, Percent		4.90%	5.00%	[1]	4.10%	[1]
Effective Income Tax Rate Reconciliation, Tax Credit, Percent		(9.40%)	(5.20%)	[1]	(4.70%)	[1]
Effective Income Tax Rate Reconciliation Regulatory Differences Utility Plant Items, Percent	[2]	5.80%	6.20%	[1]	0.80%	[1]
Effective Income Tax Rate Reconciliation, Other Regulatory Items, Percent		(1.70%)	(1.70%)	[1]	(1.00%)	[1]
Effective Income Tax Rate Reconciliation, Change in Enacted Tax Rate, Percent		0.50%	0.40%	[1]	(0.60%)	[1]
Tax reform, Percent		0.00%	0.00%	[1]	1.40%	[1]
Effective Income Tax Rate Reconciliation Change In Unrecognized Tax Benefits		(1.00%)	(0.70%)	[1]	(1.30%)	[1]
Effective Income Tax Rate Reconciliation, Percent		8.50%	12.60%	[1]	32.10%	[1]
[1]	Prior periods have been reclassified to conform to current year presentation.
[2]	Regulatory differences for income tax primarily relate to the credit of excess deferred taxes to customers through the average rate assumption method. Income tax benefits associated with the credit of excess deferred credits are offset by corresponding revenue reductions and additional prepaid pension asset amortization.

Income Taxes Other Income Tax M

Income Taxes Other Income Tax Matters (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Income Tax Examination [Line Items]
Current Federal Tax Expense (Benefit)		$ (16)	$ (34)	$ 1
Deferred tax expense (benefit) excluding selected items		344	320	(2,939)
Amortization and adjustments to deferred income taxes on income tax regulatory assets and liabilities		(206)	(102)	3,583
Other Comprehensive Income (Loss), Tax		5	0	(4)
Deferred Income Tax Expense (Benefit)		143	218	640
Current State and Local Tax Expense (Benefit)		4	8	(11)
Current Change In Unrecognized Tax Expense (Benefit)		2	(6)	(83)
Deferred Federal Income Tax Expense (Benefit)		55	122	460
Deferred State and Local Income Tax Expense (Benefit)		83	85	107
Deferred Change In Unrecognized Tax Expense (Benefit)		5	11	73
Deferred investment tax credits		5	5	5
Income Tax Expense (Benefit)		128	181	$ 542
Internal Revenue Service (IRS) [Member]
Income Tax Examination [Line Items]
Tax Credit Carryforward, Amount		639	553
Tax Credit Carryforward, Valuation Allowance		0	5
State and Local Jurisdiction [Member]
Income Tax Examination [Line Items]
Federal detriment		24	24
Operating Loss Carryforwards		937	1,104
Operating Loss Carryforwards, Valuation Allowance		19	50
Tax Credit Carryforward Net Of Federal Detriment	[1]	89	89
Valuation Allowance for Tax Credit Carryforward Net of Federal Benefit	[2]	66	69
Federal Benefit		$ 17	$ 18
[1]	State tax credit carryforwards are net of federal detriment of $24 million as of Dec. 31, 2019 and 2018.
[2]	Valuation allowances for state tax credit carryforwards were net of federal benefit of $17 million and $18 million as of Dec. 31, 2019 and 2018, respectively.

Income Taxes Income Tax Phantom

Income Taxes Income Tax Phantom (Details) - USD ($)	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Income Tax Disclosure [Abstract]
Unrecognized Tax Benefits, Income Tax Penalties Accrued	$ 0	$ 0	$ 0

Incentive Plans Including Share

Incentive Plans Including Share-Based Compensation (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Equity Instruments Other than Options Activity [Roll Forward]
Balance at January 1 (in shares)	939
Granted (in shares)	483	500	503
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Forfeited in Period (in shares)	(116)
Vested (in shares)	(464)	(475)	(467)
Dividend equivalents (in shares)	38
Balance at December 31 (in shares)	880	939
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)	$ 44.30
Granted, weighted average grant date fair value (in dollars per share)	49.67	$ 47.60	$ 41.02
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)	$ 50.19
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Fair Value	$ 29,432	$ 23,393	$ 22,459
Vested, weighted average grant date fair value (in dollars per share)	$ 41.09
Dividend equivalents, weighted average grant date fair value (in dollars per share)	45.22
Balance at December 31, weighted average grant date fair value (in dollars per share)	$ 48.20	$ 44.30
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)	36
Granted (in shares)	13	18	15
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Forfeited in Period (in shares)	0
Vested (in shares)	(19)
Dividend equivalents (in shares)	1
Balance at December 31 (in shares)	31	36
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)	$ 44.29
Granted, weighted average grant date fair value (in dollars per share)	53.46	$ 44.68	$ 42
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
Vested, weighted average grant date fair value (in dollars per share)	41.60
Dividend equivalents, weighted average grant date fair value (in dollars per share)	57.09
Balance at December 31, weighted average grant date fair value (in dollars per share)	$ 50.15	$ 44.29
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 Restri

Share-Based Compensation Restricted Stock (Details) - shares shares in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Granted (in shares)	483	500	503
Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Granted (in shares)	13	18	15

Other Equity Awards (Details)

Other Equity Awards (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Equity Instruments Other than Options Activity [Roll Forward]
Balance at January 1 (in shares)	939
Granted (in shares)	483	500	503
Forfeited (in shares)	(116)
Vested (in shares)	(464)	(475)	(467)
Dividend equivalents (in shares)	38
Balance at December 31 (in shares)	880	939
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)	$ 44.30
Granted, weighted average grant date fair value (in dollars per share)	49.67	$ 47.60	$ 41.02
Forfeited, weighted average grant date fair value (in dollars per share)	50.19
Vested, weighted average grant date fair value (in dollars per share)	41.09
Dividend equivalents, weighted average grant date fair value (in dollars per share)	45.22
Balance at December 31, weighted average grant date fair value (in dollars per share)	$ 48.20	$ 44.30
Equity Instruments Other than Options, Additional Disclosures [Abstract]
Award Vesting Period (in years)	3 years
Total fair value of equity awards vested during the period	$ 29,432	$ 23,393	$ 22,459
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
Xcel Energy Inc. 2015 Omnibus Incentive Plan [Member] | Service-based awards [Member]
Equity Instruments Other than Options Activity [Roll Forward]
Granted (in shares)	7,000
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%
Xcel Energy Inc. Executive Annual Incentive Award Plan [Member] | Service-based awards [Member]
Equity Instruments Other than Options Activity [Roll Forward]
Granted (in shares)	1,200

Stock Equivalent Units (Details

Stock Equivalent Units (Details) - $ / shares	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Equity Instruments Other than Options Activity [Roll Forward]
Balance at January 1 (in shares)	939,000
Granted (in shares)	483,000	500,000	503,000
Dividend equivalents (in shares)	38,000
Balance at December 31 (in shares)	880,000	939,000
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)	$ 44.30
Granted, weighted average grant date fair value (in dollars per share)	49.67	$ 47.60	$ 41.02
Dividend equivalents, weighted average grant date fair value (in dollars per share)	45.22
Balance at December 31, weighted average grant date fair value (in dollars per share)	$ 48.20	$ 44.30
Stock Equivalent Units [Member]
Equity Instruments Other than Options Activity [Roll Forward]
Balance at January 1 (in shares)	688,000
Granted (in shares)	29,000	36,000	51,000
Units distributed (in shares)	(11,000)
Dividend equivalents (in shares)	19,000
Balance at December 31 (in shares)	725,000	688,000
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)	$ 30.93
Granted, weighted average grant date fair value (in dollars per share)	58.44	$ 45.44	$ 46.05
Units distributed, weighted average grant date fair value (in dollars per share)	32.56
Dividend equivalents, weighted average grant date fair value (in dollars per share)	57.28
Balance at December 31, weighted average grant date fair value (in dollars per share)	$ 32.72	$ 30.93
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

TSR Liability Awards (Details)

TSR Liability Awards (Details) shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2019USD ($)Partiesshares	Dec. 31, 2018USD ($)shares	Dec. 31, 2017USD ($)shares
Equity Instruments Other than Options Activity [Roll Forward]
Granted (in shares)	483	500	503
Equity Instruments Other than Options, Additional Disclosures [Abstract]
Award Vesting Period (in years)	3 years
Number of Utilities in Peer Group | Parties	20
TSR Liability Awards
Equity Instruments Other than Options Activity [Roll Forward]
Granted (in shares)	225	239	240
Equity Instruments Other than Options, Additional Disclosures [Abstract]
Award Vesting Period (in years)	3 years
Amount of cash used to settle TSR liability awards | $	$ 21,000
Awards settled (in shares)	466	482	454
Settlement amount (cash and common stock) | $	$ 24,930	$ 21,534	$ 19,083
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 Expens

Share-Based Compensation Expense (Details) - USD ($) shares in Thousands, $ in Millions		12 Months Ended
		Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Share-Based Compensation Expense [Abstract]
Granted (in shares)		483	500	503
Compensation cost for share-based awards	[1]	$ 58	$ 45	$ 57
Tax benefit recognized in income		15	12	$ 22
Unrecognized compensation cost related to nonvested share-based compensation awards		$ 40	$ 38
Weighted-average period for recognition of unrecognized compensation cost related to nonvested share-based compensation awards (in years)		1 year 7 months 6 days
Award Vesting Period (in years)		3 years
Service-based awards [Member]
Share-Based Compensation Expense [Abstract]
Granted (in shares)		300	300	300
[1]	Compensation costs for share-based payment are included in O&M expense.

Share-Based Compensation Share-

Share-Based Compensation Share-Based Compensation Phantom (Details) - shares shares in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Granted (in shares)	483	500	503
Service-based awards [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Granted (in shares)	300	300	300

Common Stock Equivalent (Detail

Common Stock Equivalent (Details) - shares shares in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Effect of dilutive securities [Abstract]
401(k) equity awards (in shares)	1.3	0.5	0.6

Nuclear Decommissioning Fund (D

Nuclear Decommissioning Fund (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2019	Dec. 31, 2018
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Available-for-sale Securities, Gross Unrealized Gain		$ 706	$ 450
Available-for-sale Securities, Gross Unrealized Loss		6	45
Investments [Abstract]
Investment in subsidiaries		155	141
Miscellaneous investments		136	121
Final Contractual Maturity [Abstract]
Due in 1 Year or Less		(7)
Due in 1 to 5 Years		111
Due in 5 to 10 Years		246
Due after 10 Years		158
Total		508
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Decommissioning Fund Investments, Fair Value		2,440	2,100
Decommissioning Fund Investments		2,440	2,055
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]
Alternative Investment	[1]	935	819
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]
Cash equivalents	[1]	33	24
Alternative Investment	[1]	0	0
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Commingled Funds
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Alternative Investment	[1]	935	819
Available-for-sale Securities	[1]	935	898
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Debt Securities
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Alternative Investment	[1]	0	0
Debt Securities, Available-for-sale	[1]	508	436
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Equity Securities
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Alternative Investment	[1]	0	0
Available-for-sale Securities, Equity Securities	[1]	964	697
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]
Decommissioning Fund Investments, Fair Value	[1]	995	800
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 1 | Cash equivalents
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash equivalents	[1]	33	24
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 1 | Commingled Funds
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Available-for-sale Securities	[1]	0	79
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 1 | Debt Securities
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Debt Securities, Available-for-sale	[1]	0	0
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 1 | Equity Securities
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Available-for-sale Securities, Equity Securities	[1]	962	697
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]
Decommissioning Fund Investments, Fair Value	[1]	497	436
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 2 | Cash equivalents
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash equivalents	[1]	0	0
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 2 | Commingled Funds
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Available-for-sale Securities	[1]	0	0
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 2 | Debt Securities
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Debt Securities, Available-for-sale	[1]	495	436
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 2 | Equity Securities
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Available-for-sale Securities, Equity Securities	[1]	2	0
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]
Decommissioning Fund Investments, Fair Value	[1]	13	0
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 3 | Cash equivalents
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash equivalents	[1]	0	0
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 3 | Commingled Funds
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Available-for-sale Securities	[1]	0	0
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 3 | Debt Securities
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Debt Securities, Available-for-sale	[1]	13	0
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 3 | Equity Securities
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Available-for-sale Securities, Equity Securities	[1]	0	0
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Cost
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Decommissioning Fund Investments, Fair Value	[1]	1,740	1,649
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Cost | Cash equivalents
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash equivalents	[1]	33	24
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Cost | Commingled Funds
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Available-for-sale Securities	[1]	733	758
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Cost | Debt Securities
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Debt Securities, Available-for-sale	[1]	489	466
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Cost | Equity Securities
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Available-for-sale Securities, Equity Securities	[1]	$ 485	$ 401
[1]	Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $155 million of equity investments in unconsolidated subsidiaries and $136 million of rabbi trust assets and miscellaneous investments.

Fair Value of Financial Asset_3

Fair Value of Financial Assets and Liabilities Rabbi Trusts (Details) - Fair Value Measured on a Recurring Basis - USD ($) $ in Millions		Dec. 31, 2019	Dec. 31, 2018
Cost
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Debt Securities, Trading, and Equity Securities, FV-NI	[1]	$ 74	$ 68
Cost | Rabbi Trust [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash and Cash Equivalents	[1]	17	16
Cost | Mutual Funds [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Debt Securities, Trading, and Equity Securities, FV-NI	[1]	57	52
Fair Value
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Debt Securities, Trading, and Equity Securities, FV-NI	[1]	82	67
Fair Value | Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Debt Securities, Trading, and Equity Securities, FV-NI	[1]	82	67
Fair Value | Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Debt Securities, Trading, and Equity Securities, FV-NI		0	0
Fair Value | Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Debt Securities, Trading, and Equity Securities, FV-NI	[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	[1]	17	16
Fair Value | Rabbi Trust [Member] | Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash and Cash Equivalents	[1]	17	16
Fair Value | Rabbi Trust [Member] | Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash and Cash Equivalents	[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	[1]	0	0
Fair Value | Mutual Funds [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Debt Securities, Trading, and Equity Securities, FV-NI	[1]	65	51
Fair Value | Mutual Funds [Member] | Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Debt Securities, Trading, and Equity Securities, FV-NI	[1]	65	51
Fair Value | Mutual Funds [Member] | Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Debt Securities, Trading, and Equity Securities, FV-NI	[1]	0	0
Fair Value | Mutual Funds [Member] | Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Debt Securities, Trading, and Equity Securities, FV-NI	[1]	$ 0	$ 0
[1]	Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet.

Interest Rate Derivatives (Deta

Interest Rate Derivatives (Details) - Interest Rate Swap $ in Millions	Dec. 31, 2019USD ($)
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	$ 5
Derivative Liability	$ 0

Fair Value of Financial Asset_4

Fair Value of Financial Assets and Liabilities Commodity Derivatives (Details) MWh in Millions, MMBTU in Millions, $ in Millions		12 Months Ended
		Dec. 31, 2019USD ($)MMBTUMWh	Dec. 31, 2018MMBTUMWh
Derivative [Line Items]
Commodity contracts designated as cash flow hedges		$ 0
Cash Flow Hedge Gain (Loss) to be Reclassified within Twelve Months		$ 0
Electric Commodity
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | MWh	[1],[2]	95	87
Natural Gas Commodity
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | MMBTU	[1],[2]	110	92
[1]	Amounts are not reflective of net positions in the underlying commodities.
[2]	Notional amounts for options are included on a gross basis but weighted for the probability of exercise.

Fair Value of Financial Asset_5

Fair Value of Financial Assets and Liabilities Consideration of Credit Risk and Concentrations (Details) - Credit Concentration Risk $ in Millions	Dec. 31, 2019USD ($)Counterparty
Derivative [Line Items]
Number of most significant counterparties	10
Municipal or Cooperative Entities or Other Utilities
Derivative [Line Items]
Number of most significant counterparties	9
External Credit Rating, Investment Grade
Derivative [Line Items]
Number of most significant counterparties	6
Credit exposure for the most significant counterparties | $	$ 154
Percentage of credit exposure for the most significant counterparties	60.00%
Internal Investment Grade
Derivative [Line Items]
Number of most significant counterparties	4
Credit exposure for the most significant counterparties | $	$ 37
Percentage of credit exposure for the most significant counterparties	14.00%

Qualifying Cash Flow Hedges (De

Qualifying Cash Flow Hedges (Details) - USD ($)		12 Months Ended
		Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
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		$ (60,000,000)	$ (58,000,000)	$ (51,000,000)
After-tax net unrealized losses related to derivatives accounted for as hedges		(23,000,000)	(5,000,000)	0
After-tax net realized losses on derivative transactions reclassified into earnings		3,000,000	3,000,000	3,000,000
Adoption of ASU. 2018-02 (a)	[1]	0	0	(10,000,000)
Accumulated other comprehensive loss related to cash flow hedges at Dec. 31		(80,000,000)	(60,000,000)	(58,000,000)
Impact of Derivative Activity
Fair Value Hedges, Net		0	0	0
Not Designated as Hedging Instrument
Impact of Derivative Activity
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, before Tax		0	0	0
Derivative Instruments Gain (Loss) Reclassified To Regulatory Assets And Liabilities Net		(1,000,000)	11,000,000	(3,000,000)
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net		0	0	0
Pre-tax gains (losses) reclassified into income during the period from regulatory assets and (liabilities)		3,000,000	7,000,000	12,000,000
Derivative, Gain (Loss) on Derivative, Net		(5,000,000)	10,000,000	4,000,000
Not Designated as Hedging Instrument | Commodity Trading Contract
Impact of Derivative Activity
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net		0	0	0
Pre-tax gains (losses) reclassified into income during the period from regulatory assets and (liabilities)		0	0	0
Derivative, Gain (Loss) on Derivative, Net	[2]	2,000,000	14,000,000	10,000,000
Not Designated as Hedging Instrument | Electric Commodity Contract
Impact of Derivative Activity
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, before Tax		0	0	0
Derivative Instruments Gain (Loss) Reclassified To Regulatory Assets And Liabilities Net		8,000,000	1,000,000	10,000,000
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net		0	0	0
Pre-tax gains (losses) reclassified into income during the period from regulatory assets and (liabilities)	[3]	5,000,000	1,000,000	15,000,000
Derivative, Gain (Loss) on Derivative, Net		0	0	0
Not Designated as Hedging Instrument | Natural Gas Commodity Contract
Impact of Derivative Activity
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, before Tax		0	0	0
Derivative Instruments Gain (Loss) Reclassified To Regulatory Assets And Liabilities Net		0	10,000,000	(13,000,000)
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net		0	0	0
Pre-tax gains (losses) reclassified into income during the period from regulatory assets and (liabilities)	[4]	2,000,000	6,000,000	3,000,000
Derivative, Gain (Loss) on Derivative, Net	[4]	(7,000,000)	(4,000,000)	(6,000,000)
Cash Flow Hedges | Designated as Hedging Instrument
Impact of Derivative Activity
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, before Tax		(30,000,000)	(7,000,000)
Derivative Instruments Gain (Loss) Reclassified To Regulatory Assets And Liabilities Net		0	0
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net		(4,000,000)	(4,000,000)	(5,000,000)
Pre-tax gains (losses) reclassified into income during the period from regulatory assets and (liabilities)		0	0	0
Derivative, Gain (Loss) on Derivative, Net		0	0	0
Cash Flow Hedges | Designated as Hedging Instrument | Interest Rate Contract
Impact of Derivative Activity
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, before Tax		(30,000,000)	(7,000,000)
Derivative Instruments Gain (Loss) Reclassified To Regulatory Assets And Liabilities Net		0	0
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	[5]	(4,000,000)	(4,000,000)	(5,000,000)
Pre-tax gains (losses) reclassified into income during the period from regulatory assets and (liabilities)		0	0	0
Derivative, Gain (Loss) on Derivative, Net		$ 0	$ 0	$ 0
[1]	In 2017, Xcel Energy implemented ASU No 2018-02 related to TCJA, which resulted in reclassification of certain credit balances within net accumulated other comprehensive loss to retained earnings.
[2]	Amounts 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 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]	Amounts for the year ended Dec. 31, 2019 included no settlement losses on derivatives entered to mitigate natural gas price risk for electric generation recorded to electric fuel and purchased power, subject to cost-recovery mechanisms and reclassified to a regulatory asset, as appropriate. Such losses and gains for the years ended Dec. 31, 2018 and 2017 were $1 million and immaterial, respectively. Remaining settlement losses for the years ended Dec. 31, 2019 , 2018 and 2017
[5]	Amounts recorded to interest charges.

Credit Related Contingent Featu

Credit Related Contingent Features (Details) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Fair Value Disclosures [Abstract]
Derivative instruments in a gross liability position	$ 7	$ 0
Collateral posted related to adequate assurance clauses in derivative contracts	$ 0	$ 0

Recurring Fair Value Measuremen

Recurring Fair Value Measurements (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Derivatives, Fair Value [Line Items]
Return Cash Collateral		$ 32	$ 32
Reclaim Cash Collateral		11	15
Commodity Contract
Changes in Level 3 Commodity Derivatives
Balance at beginning of period		29	35	$ 17
Purchases		44	59	82
Settlements		(64)	(59)	(97)
(Losses) gains recognized in earnings	[1]	(8)	(1)	5
Gains (losses) recognized as regulatory assets and liabilities		3	(5)	28
Balance at end of period		4	29	35
Transfers Between Levels, Net		0	0	$ 0
Interest Rate Swap
Derivatives, Fair Value [Line Items]
Derivative Liability, Net		0
Other Current Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Net		55	87
Other Noncurrent Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Net		22	34
Other Current Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Net		38	61
Other Noncurrent Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Net		175	129
Fair Value Measured on a Recurring Basis | Other Current Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Gross		105	127
Netting	[2]	(53)	(44)
Derivative Asset, Net		52	83
Fair Value Measured on a Recurring Basis | Other Current Assets | Level 1
Derivatives, Fair Value [Line Items]
Derivative Asset, Gross		3	4
Fair Value Measured on a Recurring Basis | Other Current Assets | Level 2
Derivatives, Fair Value [Line Items]
Derivative Asset, Gross		57	96
Fair Value Measured on a Recurring Basis | Other Current Assets | Level 3
Derivatives, Fair Value [Line Items]
Derivative Asset, Gross		45	27
Fair Value Measured on a Recurring Basis | Other Current Assets | Other Derivative Instruments | Commodity Contract
Derivatives, Fair Value [Line Items]
Derivative Asset, Gross		78	98
Netting	[2]	(52)	(44)
Derivative Asset, Net		26	54
Fair Value Measured on a Recurring Basis | Other Current Assets | Other Derivative Instruments | Commodity Contract | Level 1
Derivatives, Fair Value [Line Items]
Derivative Asset, Gross		3	4
Fair Value Measured on a Recurring Basis | Other Current Assets | Other Derivative Instruments | Commodity Contract | Level 2
Derivatives, Fair Value [Line Items]
Derivative Asset, Gross		51	92
Fair Value Measured on a Recurring Basis | Other Current Assets | Other Derivative Instruments | Commodity Contract | Level 3
Derivatives, Fair Value [Line Items]
Derivative Asset, Gross		24	2
Fair Value Measured on a Recurring Basis | Other Current Assets | Other Derivative Instruments | Electric Commodity
Derivatives, Fair Value [Line Items]
Derivative Asset, Gross		21	25
Netting	[2]	(1)	0
Derivative Asset, Net		20	25
Fair Value Measured on a Recurring Basis | Other Current Assets | Other Derivative Instruments | Electric Commodity | Level 1
Derivatives, Fair Value [Line Items]
Derivative Asset, Gross		0	0
Fair Value Measured on a Recurring Basis | Other Current Assets | Other Derivative Instruments | Electric Commodity | Level 2
Derivatives, Fair Value [Line Items]
Derivative Asset, Gross		0	0
Fair Value Measured on a Recurring Basis | Other Current Assets | Other Derivative Instruments | Electric Commodity | Level 3
Derivatives, Fair Value [Line Items]
Derivative Asset, Gross		21	25
Fair Value Measured on a Recurring Basis | Other Current Assets | Other Derivative Instruments | Natural Gas Commodity
Derivatives, Fair Value [Line Items]
Derivative Asset, Gross		6	4
Netting	[2]	0	0
Derivative Asset, Net		6	4
Fair Value Measured on a Recurring Basis | Other Current Assets | Other Derivative Instruments | Natural Gas Commodity | Level 1
Derivatives, Fair Value [Line Items]
Derivative Asset, Gross		0	0
Fair Value Measured on a Recurring Basis | Other Current Assets | Other Derivative Instruments | Natural Gas Commodity | Level 2
Derivatives, Fair Value [Line Items]
Derivative Asset, Gross		6	4
Fair Value Measured on a Recurring Basis | Other Current Assets | Other Derivative Instruments | Natural Gas Commodity | Level 3
Derivatives, Fair Value [Line Items]
Derivative Asset, Gross		0	0
Fair Value Measured on a Recurring Basis | Other Noncurrent Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Gross		54	32
Netting	[2]	(45)	(14)
Derivative Asset, Net		9	18
Fair Value Measured on a Recurring Basis | Other Noncurrent Assets | Level 1
Derivatives, Fair Value [Line Items]
Derivative Asset, Gross		9	0
Fair Value Measured on a Recurring Basis | Other Noncurrent Assets | Level 2
Derivatives, Fair Value [Line Items]
Derivative Asset, Gross		38	27
Fair Value Measured on a Recurring Basis | Other Noncurrent Assets | Level 3
Derivatives, Fair Value [Line Items]
Derivative Asset, Gross		7	5
Fair Value Measured on a Recurring Basis | Other Noncurrent Assets | Other Derivative Instruments | Commodity Contract
Derivatives, Fair Value [Line Items]
Derivative Asset, Gross		54	32
Netting	[2]	(45)	(14)
Derivative Asset, Net		9	18
Fair Value Measured on a Recurring Basis | Other Noncurrent Assets | Other Derivative Instruments | Commodity Contract | Level 1
Derivatives, Fair Value [Line Items]
Derivative Asset, Gross		9	0
Fair Value Measured on a Recurring Basis | Other Noncurrent Assets | Other Derivative Instruments | Commodity Contract | Level 2
Derivatives, Fair Value [Line Items]
Derivative Asset, Gross		38	27
Fair Value Measured on a Recurring Basis | Other Noncurrent Assets | Other Derivative Instruments | Commodity Contract | Level 3
Derivatives, Fair Value [Line Items]
Derivative Asset, Gross		7	5
Fair Value Measured on a Recurring Basis | Other Current Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Gross		84	101
Netting	[2]	64	60
Derivative Liability, Net		20	41
Fair Value Measured on a Recurring Basis | Other Current Liabilities | Level 1
Derivatives, Fair Value [Line Items]
Derivative Liability, Gross		4	4
Fair Value Measured on a Recurring Basis | Other Current Liabilities | Level 2
Derivatives, Fair Value [Line Items]
Derivative Liability, Gross		64	95
Fair Value Measured on a Recurring Basis | Other Current Liabilities | Level 3
Derivatives, Fair Value [Line Items]
Derivative Liability, Gross		16	2
Fair Value Measured on a Recurring Basis | Other Current Liabilities | Other Derivative Instruments | Commodity Contract
Derivatives, Fair Value [Line Items]
Derivative Liability, Gross		78	94
Netting	[2]	63	60
Derivative Liability, Net		15	34
Fair Value Measured on a Recurring Basis | Other Current Liabilities | Other Derivative Instruments | Commodity Contract | Level 1
Derivatives, Fair Value [Line Items]
Derivative Liability, Gross		4	4
Fair Value Measured on a Recurring Basis | Other Current Liabilities | Other Derivative Instruments | Commodity Contract | Level 2
Derivatives, Fair Value [Line Items]
Derivative Liability, Gross		59	88
Fair Value Measured on a Recurring Basis | Other Current Liabilities | Other Derivative Instruments | Commodity Contract | Level 3
Derivatives, Fair Value [Line Items]
Derivative Liability, Gross		15	2
Fair Value Measured on a Recurring Basis | Other Current Liabilities | Other Derivative Instruments | Electric Commodity
Derivatives, Fair Value [Line Items]
Derivative Liability, Gross		1	0
Netting	[2]	1	0
Derivative Liability, Net		0	0
Fair Value Measured on a Recurring Basis | Other Current Liabilities | Other Derivative Instruments | Electric Commodity | Level 1
Derivatives, Fair Value [Line Items]
Derivative Liability, Gross		0	0
Fair Value Measured on a Recurring Basis | Other Current Liabilities | Other Derivative Instruments | Electric Commodity | Level 2
Derivatives, Fair Value [Line Items]
Derivative Liability, Gross		0	0
Fair Value Measured on a Recurring Basis | Other Current Liabilities | Other Derivative Instruments | Electric Commodity | Level 3
Derivatives, Fair Value [Line Items]
Derivative Liability, Gross		1	0
Fair Value Measured on a Recurring Basis | Other Current Liabilities | Other Derivative Instruments | Natural Gas Commodity
Derivatives, Fair Value [Line Items]
Derivative Liability, Gross		5	0
Netting	[2]	0	0
Derivative Liability, Net		5	0
Fair Value Measured on a Recurring Basis | Other Current Liabilities | Other Derivative Instruments | Natural Gas Commodity | Level 1
Derivatives, Fair Value [Line Items]
Derivative Liability, Gross		0	0
Fair Value Measured on a Recurring Basis | Other Current Liabilities | Other Derivative Instruments | Natural Gas Commodity | Level 2
Derivatives, Fair Value [Line Items]
Derivative Liability, Gross		5	0
Fair Value Measured on a Recurring Basis | Other Current Liabilities | Other Derivative Instruments | Natural Gas Commodity | Level 3
Derivatives, Fair Value [Line Items]
Derivative Liability, Gross		0	0
Fair Value Measured on a Recurring Basis | Other Current Liabilities | Designated as Hedging Instrument | Interest Rate Swap
Derivatives, Fair Value [Line Items]
Netting	[2]	0	0
Fair Value Measured on a Recurring Basis | Other Current Liabilities | Designated as Hedging Instrument | Interest Rate Swap | Cash Flow Hedges
Derivatives, Fair Value [Line Items]
Derivative Liability, Gross		0	7
Derivative Liability, Net		0	7
Fair Value Measured on a Recurring Basis | Other Current Liabilities | Designated as Hedging Instrument | Interest Rate Swap | Level 1 | Cash Flow Hedges
Derivatives, Fair Value [Line Items]
Derivative Liability, Gross		0	0
Fair Value Measured on a Recurring Basis | Other Current Liabilities | Designated as Hedging Instrument | Interest Rate Swap | Level 2 | Cash Flow Hedges
Derivatives, Fair Value [Line Items]
Derivative Liability, Gross		0	7
Fair Value Measured on a Recurring Basis | Other Current Liabilities | Designated as Hedging Instrument | Interest Rate Swap | Level 3 | Cash Flow Hedges
Derivatives, Fair Value [Line Items]
Derivative Liability, Gross		0	0
Fair Value Measured on a Recurring Basis | Other Noncurrent Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Gross		113	19
Netting	[2]	13	17
Derivative Liability, Net		100	36
Fair Value Measured on a Recurring Basis | Other Noncurrent Liabilities | Level 1
Derivatives, Fair Value [Line Items]
Derivative Liability, Gross		2	0
Fair Value Measured on a Recurring Basis | Other Noncurrent Liabilities | Level 2
Derivatives, Fair Value [Line Items]
Derivative Liability, Gross		79	18
Fair Value Measured on a Recurring Basis | Other Noncurrent Liabilities | Level 3
Derivatives, Fair Value [Line Items]
Derivative Liability, Gross		32	1
Fair Value Measured on a Recurring Basis | Other Noncurrent Liabilities | Other Derivative Instruments | Commodity Contract
Derivatives, Fair Value [Line Items]
Derivative Liability, Gross		113	19
Netting	[2]	13	17
Derivative Liability, Net		100	36
Fair Value Measured on a Recurring Basis | Other Noncurrent Liabilities | Other Derivative Instruments | Commodity Contract | Level 1
Derivatives, Fair Value [Line Items]
Derivative Liability, Gross		2	0
Fair Value Measured on a Recurring Basis | Other Noncurrent Liabilities | Other Derivative Instruments | Commodity Contract | Level 2
Derivatives, Fair Value [Line Items]
Derivative Liability, Gross		79	18
Fair Value Measured on a Recurring Basis | Other Noncurrent Liabilities | Other Derivative Instruments | Commodity Contract | Level 3
Derivatives, Fair Value [Line Items]
Derivative Liability, Gross		32	1
Fair Value, Measurements, Nonrecurring | Other Current Assets | Purchased Power Agreements
Derivatives, Fair Value [Line Items]
Derivative Asset, Net	[3]	3	4
Fair Value, Measurements, Nonrecurring | Other Noncurrent Assets | Purchased Power Agreements
Derivatives, Fair Value [Line Items]
Derivative Asset, Net	[3]	13	16
Fair Value, Measurements, Nonrecurring | Other Current Liabilities | Purchased Power Agreements
Derivatives, Fair Value [Line Items]
Derivative Liability, Net	[3]	18	20
Fair Value, Measurements, Nonrecurring | Other Noncurrent Liabilities | Purchased Power Agreements
Derivatives, Fair Value [Line Items]
Derivative Liability, Net	[3]	$ 75	$ 93
[1]	Amounts relate to commodity derivatives held at the end of the period.
[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, 2019 and 2018 . At both Dec. 31, 2019 and 2018 , derivative assets and liabilities included $32 million of obligations to return cash collateral. At Dec. 31, 2019 and 2018 , derivative assets and liabilities included rights to reclaim cash collateral of $11 million and $15 million , respectively. Counterparty netting excludes 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.

Fair Value of Long-Term Debt (D

Fair Value of Long-Term Debt (Details) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Financial Liabilities, Balance Sheet Groupings [Abstract]
Long-term Debt, Gross	$ 18,109	$ 16,209
Long-term debt, Fair Value	$ 20,227	$ 16,755

Fair Value of Financial Asset_6

Fair Value of Financial Assets and Liabilities Fair Value Phantom (Details) - USD ($)	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value Hedges, Net	$ 0	$ 0	$ 0
Collateral Already Posted Adequate Assurance Clauses Aggregate Fair Value	0	0
Return Cash Collateral	32,000,000	32,000,000
Commodity Contract
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Transfers Between Levels, Net	$ 0	$ 0	$ 0

Pension and Postretirement Heal

Pension and Postretirement Health Care Benefits (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2020	Dec. 31, 2019		Dec. 31, 2018		Dec. 31, 2017
Supplemental Executive Retirement Plan (SERP) and Nonqualified Pension Plan
Pension Benefits [Abstract]
Total benefit obligation			$ 39		$ 33
Net benefit cost recognized for financial reporting			4		4
Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount			3,184	[1]	2,742	[1]	$ 3,088
Defined Benefit Plan, Alternative Investments, Fair Value Of Plan Assets	[1]		(1,011)		(957)
Pension Benefits [Abstract]
Total benefit obligation			3,701		3,477		3,828
Net benefit cost recognized for financial reporting			$ 115		$ 140		$ 139
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%		6.87%
Target Pension Asset Allocations [Abstract]
Target pension asset allocations (as a percent)			100.00%		100.00%
Pension Plan [Member] | Equity Securities
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount			$ 86		$ 106	[1]
Defined Benefit Plan, Alternative Investments, Fair Value Of Plan Assets			$ 0		$ 0	[1]
Target Pension Asset Allocations [Abstract]
Target pension asset allocations (as a percent)			37.00%		36.00%
Pension Plan [Member] | Long-duration fixed income and interest rate swap securities
Target Pension Asset Allocations [Abstract]
Target pension asset allocations (as a percent)			30.00%		30.00%
Pension Plan [Member] | Short-to-intermediate fixed income securities
Target Pension Asset Allocations [Abstract]
Target pension asset allocations (as a percent)			14.00%		17.00%
Pension Plan [Member] | Alternative investments
Target Pension Asset Allocations [Abstract]
Target pension asset allocations (as a percent)			17.00%		15.00%
Pension Plan [Member] | Cash
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	[1]		$ 145		$ 137
Defined Benefit Plan, Alternative Investments, Fair Value Of Plan Assets	[1]		$ 0		$ 0
Target Pension Asset Allocations [Abstract]
Target pension asset allocations (as a percent)			2.00%		2.00%
Forecast | Pension Plan [Member]
Pension Benefits [Abstract]
Expected average long-term rate of return on assets for next fiscal year (as a percent)		6.87%
[1]	(a) See Note 10 for further information regarding fair value measurement inputs and methods.

Plan Assets (Details)

Plan Assets (Details) - Pension Plan [Member] - USD ($) $ in Millions		Dec. 31, 2019		Dec. 31, 2018		Dec. 31, 2017
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		$ 3,184	[1]	$ 2,742	[1]	$ 3,088
Plan assets at net asset value	[1]	(1,011)		(957)
Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	[1]	1,519		1,159
Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	[1]	650		626
Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	[1]	4		0
Cash equivalents
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	[1]	145		137
Plan assets at net asset value	[1]	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	[1]	145		137
Cash equivalents | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	[1]	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	[1]	0		0
Other
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	[1]	(135)		(23)
Plan assets at net asset value	[1]	(20)		(30)
Other | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	[1]	(120)		2
Other | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	[1]	5		5
Other | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	[1]	0		0
Commingled Funds
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		2,439		1,901	[1]
Plan assets at net asset value		(1,031)		(987)	[1]
Commingled Funds | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		1,408		914	[1]
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	[1]
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	[1]
Debt Securities
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		649		621	[1]
Plan assets at net asset value		0		0	[1]
Debt 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	[1]
Debt Securities | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		645		621	[1]
Debt Securities | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		4		0	[1]
Equity Securities
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		86		106	[1]
Plan assets at net asset value		0		0	[1]
Equity Securities | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		86		106	[1]
Equity Securities | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		0		0	[1]
Equity 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	[1]
[1]	(a) See Note 10 for further information regarding fair value measurement inputs and methods.

Funded Status (Details)

Funded Status (Details) - USD ($) $ in Millions	1 Months Ended		12 Months Ended
	Jan. 31, 2020		Dec. 31, 2019		Dec. 31, 2018		Dec. 31, 2017
Change in Fair Value of Plan Assets [Roll Forward]
Defined Benefit Plan, Plan Assets, Payment for Settlement			$ 20		$ 198
Components of Net Periodic Benefit Cost (Credit) [Abstract]
Settlement Charge Recognized in Operating and Maintenance Expenses			2,338		2,352		$ 2,270
Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Accumulated Benefit Obligation at Dec. 31			3,465		3,275
Change in Projected Benefit Obligation [Roll Forward]
Obligation at Jan. 1	$ 3,701		3,477		3,828
Service cost			86		94		94
Interest cost			145		133		147
Plan amendments			1		0
Actuarial loss			273		(224)
Defined Benefit Plan, Benefit Obligation, Contributions by Plan Participant			0		0
Defined Benefit Plan, Benefit Obligation, Prescription Drug Subsidy Receipt			0		0
Benefit payments			(281)		(354)
Obligation at Dec. 31			3,701		3,477		3,828
Change in Fair Value of Plan Assets [Roll Forward]
Fair value of plan assets at Jan. 1	3,184	[1]	2,742	[1]	3,088
Actual return (loss) on plan assets			568		(142)
Employer contributions			155		150
Benefit payments			(281)		(354)
Fair value of plan assets at Dec. 31			3,184	[1]	2,742	[1]	3,088
Funded Status of Plans at Dec. 31 [Abstract]
Funded status			(517)		(735)
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost [Abstract]
Net loss			1,447		1,633
Prior service (credit) cost			(15)		(20)
Total			1,432		1,613
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			78		94
Noncurrent regulatory assets			1,285		1,446
Deferred income taxes			18		19
Net-of-tax accumulated other comprehensive income			51		54
Total			$ 1,432		$ 1,613
Significant Assumptions Used to Measure Benefit Obligations [Abstract]
Discount rate for year-end valuation (as a percent)			3.49%		4.31%
Expected average long-term increase in compensation level (as a percent)			3.75%		3.75%
Cash Flows [Abstract]
Total contributions to Xcel Energy's pension plans during the period			$ 154		$ 150		162
Components of Net Periodic Benefit Cost (Credit) [Abstract]
Service cost			86		94		94
Interest cost			145		133		147
Expected return on plan assets			(203)		(209)		(209)
Amortization of prior service cost (credit)			(5)		(5)		(2)
Amortization of net loss			87		111		107
Settlement charge			6		91		81
Net periodic benefit cost			116		215		218
Costs not recognized due to regulation			(1)		(75)		(79)
Net benefit cost recognized for financial reporting			115		140		$ 139
Settlement Charge Recognized in Operating and Maintenance Expenses			$ 1		$ 11
Significant Assumptions Used to Measure Costs [Abstract]
Discount rate (as a percent)			4.31%		3.63%		4.13%
Expected average long-term increase in compensation level (as a percent)			3.75%		3.75%		3.75%
Expected average long-term rate of return on assets (as a percent)			6.87%		6.87%		6.87%
Defined Benefit Plan, Plan Assets, Contributions by Plan Participant			$ 0		$ 0
Amounts Not Yet Recognized As Components Of Net Periodic Benefit Cost Recorded As Current Regulatory Liabilities			0		0
Amounts Not Yet Recognized As Components Of Net Periodic Benefit Cost Recorded As Noncurrent Regulatory Liabilities			0		0
Other Postretirement Benefits Plan [Member]
Change in Projected Benefit Obligation [Roll Forward]
Obligation at Jan. 1	547		542		621
Service cost			2		2		$ 2
Interest cost			22		22		24
Plan amendments			0		0
Actuarial loss			19		(62)
Defined Benefit Plan, Benefit Obligation, Contributions by Plan Participant			8		8
Defined Benefit Plan, Benefit Obligation, Prescription Drug Subsidy Receipt			1		1
Benefit payments			(47)		(50)
Obligation at Dec. 31			547		542		621
Change in Fair Value of Plan Assets [Roll Forward]
Fair value of plan assets at Jan. 1	449	[2]	417	[2]	461
Actual return (loss) on plan assets			56		(13)
Employer contributions			15		11
Benefit payments			(47)		(50)
Fair value of plan assets at Dec. 31			449	[2]	417	[2]	461
Funded Status of Plans at Dec. 31 [Abstract]
Funded status			(98)		(125)
Assets for Plan Benefits, Defined Benefit Plan			21
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost [Abstract]
Net loss			95		116
Prior service (credit) cost			(23)		(33)
Total			72		83
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			0		0
Noncurrent regulatory assets			80		89
Deferred income taxes			1		1
Net-of-tax accumulated other comprehensive income			4		4
Total			$ 72		$ 83
Significant Assumptions Used to Measure Benefit Obligations [Abstract]
Discount rate for year-end valuation (as a percent)			3.47%		4.32%
Defined Benefit Plan, Health Care Cost Trend Rate Assumed, Pre-65			6.00%		6.50%
Defined Benefit Plan, Health Care Cost Trend Rate Assumed, Post-65			5.10%		5.30%
Components of Net Periodic Benefit Cost (Credit) [Abstract]
Service cost			$ 2		$ 2		2
Interest cost			22		22		24
Expected return on plan assets			(21)		(26)		(25)
Amortization of prior service cost (credit)			(10)		(11)		(11)
Amortization of net loss			5		8		7
Settlement charge			0		0		0
Net periodic benefit cost			(2)		(5)		(3)
Costs not recognized due to regulation			1		2		0
Net benefit cost recognized for financial reporting			$ (1)		$ (3)		$ (3)
Significant Assumptions Used to Measure Costs [Abstract]
Discount rate (as a percent)			4.32%		3.62%		4.13%
Expected average long-term increase in compensation level (as a percent)			0.00%		0.00%		0.00%
Expected average long-term rate of return on assets (as a percent)			4.50%		5.30%		5.80%
Defined Benefit Plan, Plan Assets, Contributions by Plan Participant			$ 8		$ 8
Amounts Not Yet Recognized As Components Of Net Periodic Benefit Cost Recorded As Current Regulatory Liabilities			1		1
Amounts Not Yet Recognized As Components Of Net Periodic Benefit Cost Recorded As Noncurrent Regulatory Liabilities			$ 12		$ 10
Ultimate health care trend assumption rate (as a percent)			4.50%		4.50%
Period until ultimate trend rate is reached (in years)			3 years		4 years
Subsequent Event | Pension Plan [Member]
Cash Flows [Abstract]
Total contributions to Xcel Energy's pension plans during the period	$ 150
[1]	(a) See Note 10 for further information regarding fair value measurement inputs and methods.
[2]	(a) See Note 10 for further information on fair value measurement inputs and methods.

Benefit Plans and Other Postr_3

Benefit Plans and Other Postretirement Benefits Net Periodic Benefit Cost (Credit) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	$ 86	$ 94	$ 94

Benefit Plans and Other Postr_4

Benefit Plans and Other Postretirement Benefits Cash Flows (Details) - Pension Plan [Member] - USD ($) $ in Millions	1 Months Ended	12 Months Ended
	Jan. 31, 2020	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Defined Benefit Plan Disclosure [Line Items]
Payment for Pension Benefits		$ 154	$ 150	$ 162
Subsequent Event
Defined Benefit Plan Disclosure [Line Items]
Payment for Pension Benefits	$ 150

Benefit Plans and Other Postr_5

Benefit Plans and Other Postretirement Benefits, Defined Contribution Plans (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Defined Contribution Plans [Abstract]
Contributions to 401(k) and other defined contribution plans	$ 39	$ 38	$ 37

Benefit Plans and Other Postr_6

Benefit Plans and Other Postretirement Benefits, Postretirement Health Care Benefits (Details) - Other Postretirement Benefits Plan [Member]	Dec. 31, 2019	Dec. 31, 2018
Postretirement Health Care Benefits [Abstract]
Target pension asset allocations (as a percent)	100.00%	100.00%
Equity Securities
Postretirement Health Care Benefits [Abstract]
Target pension asset allocations (as a percent)	15.00%	18.00%
Long-duration fixed income and interest rate swap securities
Postretirement Health Care Benefits [Abstract]
Target pension asset allocations (as a percent)	0.00%	0.00%
Short-to-intermediate fixed income securities
Postretirement Health Care Benefits [Abstract]
Target pension asset allocations (as a percent)	72.00%	70.00%
Alternative investments
Postretirement Health Care Benefits [Abstract]
Target pension asset allocations (as a percent)	9.00%	8.00%
Cash
Postretirement Health Care Benefits [Abstract]
Target pension asset allocations (as a percent)	4.00%	4.00%

Benefit Plans and Other Postr_7

Benefit Plans and Other Postretirement Benefits, Fair Value of Postretirement Benefit Plan Assets (Details) - Other Postretirement Benefits Plan [Member] - USD ($) $ in Millions		Dec. 31, 2019		Dec. 31, 2018		Dec. 31, 2017
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		$ 449	[1]	$ 417	[1]	$ 461
Plan assets at net asset value	[1]	76		40
Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	[1]	92		152
Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	[1]	280		225
Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	[1]	1		0
Debt Securities
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		229		179	[2]
Plan assets at net asset value		0		0	[2]
Debt 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	[2]
Debt Securities | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		228		179	[2]
Debt Securities | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		1		0	[2]
Cash equivalents
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	[1]	23		19
Plan assets at net asset value	[1]	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	[1]	23		19
Cash equivalents | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	[1]	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	[1]	0		0
Insurance contracts
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	[1]	51		45
Plan assets at net asset value	[1]	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	[1]	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	[1]	51		45
Insurance contracts | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	[1]	0		0
Commingled Funds
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		145		173	[2]
Plan assets at net asset value		76		40	[2]
Commingled Funds | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		69		133	[2]
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	[2]
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	[2]
Other
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	[1]	1		1
Plan assets at net asset value	[1]	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	[1]	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]	1		1
Other | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	[1]	$ 0		$ 0
[1]	(a) See Note 10 for further information on fair value measurement inputs and methods.
[2]	(a) See Note 10 for further information regarding fair value measurement inputs and methods.

Benefit Plans and Other Postr_8

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, 2019		Dec. 31, 2018		Dec. 31, 2017	Dec. 31, 2020
Change in Projected Benefit Obligation [Roll Forward]
Defined Benefit Plan, Plan Assets, Payment for Settlement	$ 20		$ 198
Funded Status of Plans at Dec. 31 [Abstract]
Noncurrent liabilities	(785)		(994)
Cash Flows [Abstract]
Total contributions to Xcel Energy's postretirement health care plans during the year	15		11		$ 20
Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Plan amendments	1		0
Change in Projected Benefit Obligation [Roll Forward]
Obligation at Jan. 1	3,477		3,828
Service cost	86		94		94
Interest cost	145		133		147
Actuarial loss	273		(224)
Plan participants' contributions	0		0
Medicare subsidy reimbursements	0		0
Benefit payments	(281)		(354)
Obligation at Dec. 31	3,701		3,477		3,828
Change in Fair Value of Plan Assets [Roll Forward]
Fair value of plan assets at Jan. 1	2,742	[1]	3,088
Actual return (loss) on plan assets	568		(142)
Employer contributions	155		150
Participant contributions	0		0
Benefit payments	(281)		(354)
Fair value of plan assets at Dec. 31	3,184	[1]	2,742	[1]	3,088
Funded status	(517)		(735)
Funded Status of Plans at Dec. 31 [Abstract]
Current liabilities	0		0
Noncurrent liabilities	(517)		(735)
Net postretirement amounts recognized on consolidated balance sheets	(517)		(735)
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost [Abstract]
Net loss	1,447		1,633
Prior service (credit) cost	(15)		(20)
Total	1,432		1,613
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	78		94
Noncurrent regulatory assets	1,285		1,446
Current regulatory liabilities	0		0
Noncurrent regulatory liabilities	0		0
Deferred income taxes	18		19
Net-of-tax accumulated other comprehensive income	51		54
Total	$ 1,432		$ 1,613
Significant Assumptions Used to Measure Benefit Obligations [Abstract]
Discount rate for year-end valuation (as a percent)	3.49%		4.31%
Components of Net Periodic Benefit Cost (Credit) [Abstract]
Service cost	$ 86		$ 94		94
Interest cost	145		133		147
Expected return on plan assets	(203)		(209)		(209)
Amortization of prior service cost (credit)	(5)		(5)		(2)
Amortization of net loss	87		111		107
Defined Benefit Plan, Net Periodic Benefit Cost (Credit), Gain (Loss) Due to Settlement	(6)		(91)		(81)
Net periodic benefit cost	$ 116		$ 215		$ 218
Significant Assumptions Used to Measure Costs [Abstract]
Discount rate (as a percent)	4.31%		3.63%		4.13%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Rate of Compensation Increase	3.75%		3.75%		3.75%
Expected average long-term rate of return on assets (as a percent)	6.87%		6.87%		6.87%
Defined Benefit Plan, Costs Not Recognized Due To Regulation	$ (1)		$ (75)		$ (79)
Net benefit cost recognized for financial reporting	115		140		139
Other Postretirement Benefits Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Plan amendments	0		0
Change in Projected Benefit Obligation [Roll Forward]
Obligation at Jan. 1	542		621
Service cost	2		2		2
Interest cost	22		22		24
Actuarial loss	19		(62)
Plan participants' contributions	8		8
Medicare subsidy reimbursements	1		1
Benefit payments	(47)		(50)
Obligation at Dec. 31	547		542		621
Change in Fair Value of Plan Assets [Roll Forward]
Fair value of plan assets at Jan. 1	417	[2]	461
Actual return (loss) on plan assets	56		(13)
Employer contributions	15		11
Participant contributions	8		8
Benefit payments	(47)		(50)
Fair value of plan assets at Dec. 31	449	[2]	417	[2]	461
Funded status	(98)		(125)
Funded Status of Plans at Dec. 31 [Abstract]
Assets for Plan Benefits, Defined Benefit Plan	21
Current liabilities	(6)		(7)
Noncurrent liabilities	(113)		(118)
Net postretirement amounts recognized on consolidated balance sheets	(98)		(125)
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost [Abstract]
Net loss	95		116
Prior service (credit) cost	(23)		(33)
Total	72		83
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	0		0
Noncurrent regulatory assets	80		89
Current regulatory liabilities	(1)		(1)
Noncurrent regulatory liabilities	(12)		(10)
Deferred income taxes	1		1
Net-of-tax accumulated other comprehensive income	4		4
Total	$ 72		$ 83
Significant Assumptions Used to Measure Benefit Obligations [Abstract]
Discount rate for year-end valuation (as a percent)	3.47%		4.32%
Defined Benefit Plan, Health Care Cost Trend Rate Assumed, Pre-65	6.00%		6.50%
Defined Benefit Plan, Health Care Cost Trend Rate Assumed, Post-65	5.10%		5.30%
Ultimate health care trend assumption rate (as a percent)	4.50%		4.50%
Period until ultimate trend rate is reached (in years)	3 years		4 years
Components of Net Periodic Benefit Cost (Credit) [Abstract]
Service cost	$ 2		$ 2		2
Interest cost	22		22		24
Expected return on plan assets	(21)		(26)		(25)
Amortization of prior service cost (credit)	(10)		(11)		(11)
Amortization of net loss	5		8		7
Defined Benefit Plan, Net Periodic Benefit Cost (Credit), Gain (Loss) Due to Settlement	0		0		0
Net periodic benefit cost	$ (2)		$ (5)		$ (3)
Significant Assumptions Used to Measure Costs [Abstract]
Discount rate (as a percent)	4.32%		3.62%		4.13%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Rate of Compensation Increase	0.00%		0.00%		0.00%
Expected average long-term rate of return on assets (as a percent)	4.50%		5.30%		5.80%
Defined Benefit Plan, Costs Not Recognized Due To Regulation	$ 1		$ 2		$ 0
Net benefit cost recognized for financial reporting	$ (1)		$ (3)		$ (3)
Forecast
Cash Flows [Abstract]
Expected contribution to postretirement health care plans during 2018						$ 10
[1]	(a) See Note 10 for further information regarding fair value measurement inputs and methods.
[2]	(a) See Note 10 for further information on fair value measurement inputs and methods.

Projected Benefit Payments (Det

Projected Benefit Payments (Details) $ in Millions	Dec. 31, 2019USD ($)
Pension Plan [Member]
Defined Benefit Plan, Gross Projected Benefit Payments [Abstract]
2020	$ 278
2021	263
2022	262
2023	260
2024	255
2025-2029	1,205
Other Postretirement Benefits Plan [Member]
Defined Benefit Plan, Gross Projected Benefit Payments [Abstract]
2020	44
2021	43
2022	42
2023	41
2024	40
2025-2029	181
Expected Medicare Part D Subsidies [Abstract]
2020	2
2021	2
2022	2
2023	2
2024	2
2025-2029	13
Defined Benefit Plan, Net Projected Benefit Payments [Abstract]
2020	42
2021	41
2022	40
2023	39
2024	38
2025-2029	$ 168

Benefit Plans and Other Postr_9

Benefit Plans and Other Postretirement Benefits Plan Amendments (Details)	12 Months Ended
	Dec. 31, 2018
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Postretirement Cash Balance Formula	5.00%

Commitments and Contingencies G

Commitments and Contingencies Gas Trading Litigation (Details)	Dec. 31, 2019
Gas Trading Litigation [Member]
Loss Contingencies [Line Items]
Loss Contingency, Pending Claims, Number	2

Commitments and Contingencies L

Commitments and Contingencies Line Extension Disputes (Details)	1 Months Ended
	Dec. 31, 2015
PSCo | Line Extension Disputes [Member] | Minimum
Loss Contingencies [Line Items]
Loss Contingency, Number of Plaintiffs	50

Commitments and Contingencies M

Commitments and Contingencies MEC Acquisition (Details) - MEC Holdings LLC [Member] - Unregulated Operation [Member] $ in Millions	12 Months Ended
	Dec. 31, 2019USD ($)MW
Public Utilities, General Disclosures [Line Items]
Property, Plant, and Equipment, Additional Disclosures | MW	760
Property, Plant and Equipment, Additions | $	$ 650

Commitments and Contingencies S

Commitments and Contingencies Sherco (Details) - USD ($) $ in Millions	1 Months Ended	12 Months Ended
	Jan. 31, 2019	Dec. 31, 2019	Dec. 31, 2018
NSP Minnesota
Public Utilities, General Disclosures [Line Items]
Percentage of Fault			48.00%
Customer refund of previously recovered purchased power costs	$ 20
General Electric (GE) [Domain]
Public Utilities, General Disclosures [Line Items]
Percentage of Fault		52.00%

Commitments and Contingencies_2

Commitments and Contingencies MISO ROE Complaints (Details) - NSP Minnesota and NSP Wisconsin [Member] [Member] - FERC Proceeding, MISO ROE Complaint [Member]	1 Months Ended		12 Months Ended	39 Months Ended
	Feb. 28, 2015	Nov. 30, 2013	Dec. 31, 2016	Dec. 31, 2019
Public Utilities, General Disclosures [Line Items]
Public Utilities, ROE developed with new approach				9.88%
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%
Public Utilities, ROE Applicable To Transmission Formula Rates In The MISO Region, with RTO Adder, Approved				10.38%
Federal Energy Regulatory Commission (FERC) [Member]
Public Utilities, General Disclosures [Line Items]
Public Utilities, ROE Applicable To Transmission Formula Rates In The MISO Region, Approved			10.32%
Public Utilities, ROE Applicable To Transmission Formula Rates In The MISO Region, with RTO Adder, Approved			10.82%

Commitments and Contingencies T

Commitments and Contingencies Texas Fuel Reconciliation (Details) $ in Millions	12 Months Ended
	Dec. 31, 2019USD ($)
Alternative Energy [Member] | NMPRC [Member] | SPS
Public Utilities, General Disclosures [Line Items]
Fuel Costs Disallowed	$ 6

Commitments and Contingencies_3

Commitments and Contingencies SPP OATT Upgrade Costs (Details) $ in Millions	12 Months Ended
	Dec. 31, 2017USD ($)
SPS | Southwest Power Pool (SPP) [Member] | SPP Open Access Transmission Tariff Upgrade Costs [Member]
Loss Contingencies [Line Items]
Public Utilities, Billed Charges For Transmission Service Upgrades	$ 13

Commitments and Contingencies_4

Commitments and Contingencies MGP Sites (Details) $ in Millions	12 Months Ended
	Dec. 31, 2019USD ($)	Dec. 31, 2018USD ($)
Other MGP, Landfill, or Disposal Sites [Domain]
Loss Contingencies [Line Items]
Number of identified MGP, landfill, or disposal sites under current investigation and/or remediation	12
NSP-Wisconsin | Ashland MGP Site [Member]
Loss Contingencies [Line Items]
Current Cost Estimate for Site Remediation	$ 199
Accrual for Environmental Loss Contingencies, Gross	$ 23	$ 27
Carrying cost percentage to be applied to unamortized regulatory asset	3.00%

Commitments and Contingencies E

Commitments and Contingencies Environmental Requirements - Water and Waste (Details) $ in Millions	Dec. 31, 2019USD ($)Plant	Dec. 31, 2018USD ($)
NSP Minnesota
Loss Contingencies [Line Items]
Number of sites where statistically significant increases over established groundwater standards exist	0
PSCo
Loss Contingencies [Line Items]
Number of sites where statistically significant increases over established groundwater standards exist	4
Federal Coal Ash Regulation [Domain]
Loss Contingencies [Line Items]
Number of sites where regulated ash units will still be in operation at a specified date	9
Federal Coal Ash Regulation [Domain] | NSP Minnesota
Loss Contingencies [Line Items]
Number of impoundments where closure plans will be expedited	1
Estimated cost of closure of an impoundment	$ 2
Estimated cost of construction of a new impoundment	$ 9
Federal Coal Ash Regulation [Domain] | PSCo
Loss Contingencies [Line Items]
Number of impoundments where closure plans will be expedited	1
Clean Water Act Effluent Limitations Guidelines [Domain]
Loss Contingencies [Line Items]
Liability for estimated cost to comply with regulation	$ 12
Federal Clean Water Act Section 316 (b) | NSP Minnesota
Loss Contingencies [Line Items]
Minimum number of plants which could be required to make improvements to reduce entrainment | Plant	6
Federal Clean Water Act Section 316 (b) | NSP-Wisconsin
Loss Contingencies [Line Items]
Minimum number of plants which could be required to make improvements to reduce entrainment | Plant	2
Capital Addition Purchase Commitments [Member] | Federal Clean Water Act Section 316 (b)
Loss Contingencies [Line Items]
Liability for estimated cost to comply with regulation	$ 40
Liability for estimated cost to comply with impingement and entrainment regulation	198
Removal Costs [Member]
Loss Contingencies [Line Items]
Regulatory Liabilities	1,217	$ 1,175
Removal Costs [Member] | NSP Minnesota
Loss Contingencies [Line Items]
Regulatory Liabilities	520	485
Removal Costs [Member] | PSCo
Loss Contingencies [Line Items]
Regulatory Liabilities	351	344
Removal Costs [Member] | SPS
Loss Contingencies [Line Items]
Regulatory Liabilities	175	188
Removal Costs [Member] | NSP-Wisconsin
Loss Contingencies [Line Items]
Regulatory Liabilities	$ 171	$ 158

Commitments and Contingencies_5

Commitments and Contingencies Environmental Requirements - Air (Details) - SPS $ in Millions	12 Months Ended
	Dec. 31, 2019USD ($)
Implementation of the National Ambient Air Quality Standard for sulfur dioxide [Member] | Harrington Units 1 and 2 [Member]
Loss Contingencies [Line Items]
Number of years unclassifiable areas will be monitored	3 years
Capital Addition Purchase Commitments [Member] | Regional Haze Rules [Member] | Tolk Units 1 and 2 [Member]
Loss Contingencies [Line Items]
Liability for estimated cost to comply with regulation	$ 600

Asset Retirement Obligations (D

Asset Retirement Obligations (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019		Dec. 31, 2018
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance	$ 2,568		$ 2,475
Amounts Incurred	26	[1]	13	[2]
Amounts Settled	(5)	[3]	(14)	[4]
Accretion	128		120
Cash flow revisions	(16)	[5]	(26)	[6]
Ending balance	2,701		2,568
Electric Plant Nuclear Production Decommissioning
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance	1,968		1,874
Amounts Incurred	0	[1]	0	[2]
Amounts Settled	0	[3]	0	[4]
Accretion	100		94
Cash flow revisions	0	[5]	0	[6]
Ending balance	2,068		1,968
Electric Plant Steam, Hydro and Other Production Asbestos
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance	177		192
Amounts Incurred	0	[1]	0	[2]
Amounts Settled	(5)	[3]	(14)	[4]
Accretion	8		8
Cash flow revisions	22	[5]	(9)	[6]
Ending balance	202		177
Electric Plant Wind Production
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance	119		96
Amounts Incurred	26	[1]	12	[2]
Amounts Settled	0	[3]	0	[4]
Accretion	7		4
Cash flow revisions	(6)	[5]	7	[6]
Ending balance	146		119
Electric Plant Electric Distribution
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance	42		21
Amounts Incurred	0	[1]	0	[2]
Amounts Settled	0	[3]	0	[4]
Accretion	2		1
Cash flow revisions	0	[5]	20	[6]
Ending balance	44		42
Electric Plant Miscellaneous
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance	7		5
Amounts Incurred	0	[1]	0	[2]
Amounts Settled	0	[3]	0	[4]
Accretion	0		0
Cash flow revisions	(7)	[5]	2	[6]
Ending balance	0		7
Natural Gas Plant Gas Transmission and Distribution
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance	249		282
Amounts Incurred	0	[1]	0	[2]
Amounts Settled	0	[3]	0	[4]
Accretion	11		13
Cash flow revisions	(24)	[5]	(46)	[6]
Ending balance	236		249
Natural Gas Plant Miscellaneous
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance	4		4
Amounts Incurred	0	[1]	0	[2]
Amounts Settled	0	[3]	0	[4]
Accretion	0		0
Cash flow revisions	(1)	[5]	0	[6]
Ending balance	3		4
Common and Other Property Common Miscellaneous
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance	1		1
Amounts Incurred	0	[1]	0	[2]
Amounts Settled	0	[3]	0	[4]
Accretion	0		0
Cash flow revisions	0	[5]	0	[6]
Ending balance	1		1
Non utility and other
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance	1		0
Amounts Incurred	0	[1]	1	[2]
Amounts Settled	0	[3]	0	[4]
Accretion	0		0
Cash flow revisions	0	[5]	0	[6]
Ending balance	1		1
Nuclear Decommissioning Fund | Fair Value, Recurring [Member]
Asset Retirement Obligations [Line Items]
Decommissioning Fund Investments	2,440		2,055
Legally restricted assets, for purposes of funding future nuclear decommissioning	$ 2,440		$ 2,100
[1]	Amounts incurred related to the wind farms placed in service in 2019 for NSP-Minnesota (Lake Benton and Foxtail) and SPS (Hale).
[2]	Amounts incurred related to the PSCo Rush Creek wind farm and Nicollet Projects community solar gardens, which were placed in service in 2018.
[3]	Amounts settled related to asbestos abatement projects and closure of certain ash containment facilities.
[4]	Amounts settled related to asbestos abatement projects and closure of certain ash containment facilities.
[5]	In 2019, AROs were revised for changes in timing and estimates of cash flows. Changes in gas transmission and distribution AROs were primarily related to increased gas line mileage and number of services, which were more than offset by decreased inflation rates. Changes in steam, hydro and other production AROs primarily related to the cost estimates to remediate ponds at production facilities. Changes in wind AROs were driven by new dismantling studies.
[6]	In 2018, AROs were revised for changes in timing and estimates of cash flows. Changes in gas transmission and distribution AROs were primarily related to increased gas line mileage and number of services, which were more than offset by increased discount rates. Changes in electric distribution AROs primarily related to increased labor costs.

Commitments and Contingencies R

Commitments and Contingencies Removal Costs (Details) - Removal Costs [Member] - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Regulatory Liabilities [Line Items]
Regulatory Liabilities	$ 1,217	$ 1,175
NSP Minnesota
Regulatory Liabilities [Line Items]
Regulatory Liabilities	520	485
PSCo
Regulatory Liabilities [Line Items]
Regulatory Liabilities	351	344
SPS
Regulatory Liabilities [Line Items]
Regulatory Liabilities	175	188
NSP-Wisconsin
Regulatory Liabilities [Line Items]
Regulatory Liabilities	$ 171	$ 158

Nuclear Insurance (Details)

Nuclear Insurance (Details) - NSP Minnesota - Nuclear Insurance $ in Millions	12 Months Ended
	Dec. 31, 2019USD ($)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	13,500
Maximum assessments per reactor per accident	$ 138
Number of owned and licensed reactors | Reactor	3
Maximum funding requirement per reactor for any one year	$ 21
Number of nuclear plant sites operated by NSP-Minnesota | Plant	2
Maximum assessments for business interruption insurance each calendar year	$ 12
Maximum assessment for property damage insurance NSP-Minnesota is subject to each calendar year	35
Maximum
Nuclear Insurance [Abstract]
Loss Contingency, Estimate of Possible Loss	13,900
Insurance coverage limits for NSP-Minnesota's nuclear plant sites	2,700
Interruption Insurance Coverage Limits	$ 350

Commitments and Contingencies N

Commitments and Contingencies Nuclear Fuel Disposal (Details)	Dec. 31, 2019Canister
Monticello [Member]
Loss Contingencies [Line Items]
Number Of Authorized Canisters Filled And Placed In Dry Cask Nuclear Storage Facility	30
Prairie Island [Member]
Loss Contingencies [Line Items]
Number Of Authorized Canisters Filled And Placed In Dry Cask Nuclear Storage Facility	44
Number Of Authorized Canisters In Dry Cask Nuclear Storage Facility	64

Regulatory Plant Decommissionin

Regulatory Plant Decommissioning Recovery (Details) $ in Millions		12 Months Ended
		Dec. 31, 2019USD ($)	Dec. 31, 2018USD ($)	Dec. 31, 2017USD ($)
Regulatory Plant Decommissioning Recovery [Abstract]
Percentage Of Total Obligation For Decommissioning Expected To Be Funded By External Funds		100.00%
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%
Approved annual accrual for decommissioning costs		$ 14	$ 14	$ 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		688	539
Estimated decommissioning cost obligation (in current dollars)		3,700	3,551
Effect of escalating costs to payment date		7,505	7,654
Estimated future decommissioning costs (undiscounted)		11,205	11,205
Effect of discounting obligation (using average risk-free interest rate of 2.39% and 3.33% for 2019 and 2018, respectively)		(5,562)	(6,911)
Discounted decommissioning cost obligation		5,643	4,294
Underfunding of external decommissioning fund compared to the discounted decommissioning obligation		(3,203)	(2,239)
Regulatory Basis to GAAP Basis Reconciliation [Abstract]
Differences in Discount Rate and Market Risk Premium		(2,295)	(1,447)
Operating and Maintenance Costs Not Included for GAAP		(1,280)	(879)
Asset Retirement Obligation		2,701	2,568	2,475
Annual Decommissioning Recorded As Depreciation Expense [Abstract]
Annual decommissioning recorded as depreciation expense: (a) (b)	[1],[2]	$ 20	20	20
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		$ 2,068	1,968	$ 1,874
Fair Value Measured on a Recurring Basis | Nuclear Decommissioning Fund
Funded Status of Nuclear Decommissioning Obligation [Abstract]
Decommissioning Fund Investments		2,440	2,055
Annual Decommissioning Recorded As Depreciation Expense [Abstract]
Decommissioning Fund Investments, Fair Value		$ 2,440	$ 2,100
Measurement Input, Risk Free Interest Rate
Public Utilities, General Disclosures [Line Items]
Debt Instrument, Measurement Input		0.0239	0.0333
[1]	Decommissioning expense does not include depreciation of the capitalized nuclear asset retirement costs.
[2]	Decommissioning expenses in 2019, 2018 and 2017 include Minnesota’s retail jurisdiction annual funding requirement of approximately $14 million.

Commitments and Contingencies_6

Commitments and Contingencies Nuclear Obligations Phantom (Details) $ in Millions	12 Months Ended
	Dec. 31, 2019USD ($)	Dec. 31, 2018USD ($)	Dec. 31, 2017USD ($)
Public Utilities, General Disclosures [Line Items]
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%
Approved annual accrual for decommissioning costs	$ 14	$ 14	$ 14
Measurement Input, Risk Free Interest Rate
Public Utilities, General Disclosures [Line Items]
Debt Instrument, Measurement Input	0.0239	0.0333

Commitments and Contingencies_7

Commitments and Contingencies Leases (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Lessee, Lease, Description [Line Items]
Operating Lease, Weighted Average Discount Rate, Percent		4.10%
Operating Lease ROU Assets
Gross operating lease ROU assets		$ 1,843
Accumulated amortization		(171)
Net operating lease ROU assets		1,672	$ 0
Finance Lease ROU Assets
Gross finance lease ROU assets		222	222
Accumulated amortization		(83)	(77)
Net finance lease ROU assets		139	145
Components of Lease Expense
Operating Lease, Cost	[1]	255	248	$ 246
Finance Lease, Right-of-Use Asset, Amortization		6	6	5
Finance Lease, Interest Expense		19	19	20
Finance Lease, Cost		25	25	25
Short-term Lease, Cost		5	5	5
Operating Lease Commitments after Adoption of ASC Topic 842
2020		262
2021		267
2022		253
2023		239
2024		230
Thereafter		865
Total minimum obligation		2,116
Interest component of obligation		(373)
Present value of minimum obligation		1,743
Less current portion		(194)
Noncurrent operating and finance lease liabilities		$ 1,549	0
Operating Lease, Weighted Average Remaining Lease Term		9 years 3 months 18 days
Finance Lease, Liability, Payment, Due [Abstract]
2020	[2]	$ 14
2021	[2]	14
2022	[2]	12
2023	[2]	12
2024	[2]	12
Thereafter	[2]	207
Total minimum obligation	[2]	271
Interest component of obligation	[2]	(190)
Present value of minimum obligation	[2]	81
Finance Lease, Liability, Current	[2]	(4)
Finance Lease, Liability, Noncurrent	[2]	$ 77
Finance Lease, Weighted Average Remaining Lease Term	[2]	37 years
Operating Leases, Future Minimum Payments Due, Fiscal Year Maturity [Abstract]
2019			239
2020			234
2021			235
2022			221
2023			208
Thereafter			1,037
Capital Leases, Future Minimum Payments Due, Fiscal Year Maturity [Abstract]
2019			14
2020			14
2021			14
2022			12
2023			12
Thereafter			220
Total minimum obligation			286
Interest component of obligation			(201)
Capital Lease Obligations			85
Purchased Power Agreements
Operating Lease ROU Assets
Gross operating lease ROU assets		$ 1,642
Components of Lease Expense
Operating Lease, Cost		221	210	210
Operating Lease Commitments after Adoption of ASC Topic 842
2020	[3],[4]	236
2021	[3],[4]	238
2022	[3],[4]	225
2023	[3],[4]	214
2024	[3],[4]	208
Thereafter	[3],[4]	750
Total minimum obligation	[3],[4]	1,871
Interest component of obligation	[3],[4]	(321)
Present value of minimum obligation	[3],[4]	1,550
Operating Leases, Future Minimum Payments Due, Fiscal Year Maturity [Abstract]
2019			207
2020			208
2021			210
2022			197
2023			186
Thereafter			883
Gas Storage Facilities [Member]
Finance Lease ROU Assets
Gross finance lease ROU assets		201	201
Property, Plant and Equipment, Other Types [Member]
Operating Lease ROU Assets
Gross operating lease ROU assets		201
Components of Lease Expense
Operating Lease, Cost	[5]	34	38	$ 36
Operating Lease Commitments after Adoption of ASC Topic 842
2020		26
2021		29
2022		28
2023		25
2024		22
Thereafter		115
Total minimum obligation		245
Interest component of obligation		(52)
Present value of minimum obligation		193
Operating Leases, Future Minimum Payments Due, Fiscal Year Maturity [Abstract]
2019			32
2020			26
2021			25
2022			24
2023			22
Thereafter			154
Pipelines [Member]
Finance Lease ROU Assets
Gross finance lease ROU assets		$ 21	$ 21
WYCO, Inc. [Member]
Lessee, Lease, Description [Line Items]
Equity Method Investment, Ownership Percentage		50.00%	50.00%
Mankato Energy Center [Member] | NSP Minnesota | Purchased Power Agreements
Operating Lease Commitments after Adoption of ASC Topic 842
Noncurrent operating and finance lease liabilities		$ 400
[1]	PPA capacity payments are included in electric fuel and purchased power on the consolidated statements of income. Expense for other operating leases is included in O&M expense and electric fuel and purchased power.
[2]	Excludes certain amounts related to Xcel Energy’s 50% ownership interest in WYCO.
[3]	Amounts do not include PPAs accounted for as executory contracts and/or contingent payments, such as energy payments on renewable PPAs.
[4]	PPA operating leases contractually expire at various dates through 2033.
[5]	Includes short-term lease expense of $5 million for 2019, 2018 and 2017.

Non Lease PPAs (Details)

Non Lease PPAs (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Capacity
Purchased Power Agreements (PPAs) [Abstract]
Purchased power expense		$ 86	$ 131	$ 168
Estimated Future Payments Under PPAs [Abstract]
2020		70
2021		78
2022		77
2023		79
2024		74
Thereafter		56
Total		434
Energy
Purchased Power Agreements (PPAs) [Abstract]
Purchased power expense		102	$ 105	$ 100
Estimated Future Payments Under PPAs [Abstract]
2020	[1]	110
2021	[1]	157
2022	[1]	173
2023	[1]	177
2024	[1]	182
Thereafter	[1]	146
Total	[1]	$ 945
[1]	Excludes contingent energy payments for renewable energy PPAs.

Fuel Contracts (Details)

Fuel Contracts (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Coal
Fuel Contracts [Abstract]
2020	$ 430
2021	222
2022	135
2023	58
2024	24
Thereafter	74
Total	943
Nuclear Fuel
Fuel Contracts [Abstract]
2020	54
2021	103
2022	85
2023	103
2024	74
Thereafter	275
Total	694
Natural Gas Supply
Fuel Contracts [Abstract]
2020	343
2021	254
2022	104
2023	53
2024	3
Thereafter	0
Total	757
Natural Gas Storage and Transportation
Fuel Contracts [Abstract]
2020	295
2021	283
2022	269
2023	198
2024	153
Thereafter	860
Total	2,058
Capacity
Unrecorded Unconditional Purchase Obligation [Line Items]
Utilities Operating Expense, Purchased Power under Long-term Contracts	86	$ 131	$ 168
Fuel Contracts [Abstract]
2020	70
2021	78
2022	77
2023	79
2024	74
Thereafter	56
Total	$ 434

VIEs (Details)

VIEs (Details) $ in Millions	Dec. 31, 2019USD ($)MW	Dec. 31, 2018USD ($)MW
Independent Power Producing Entities
Purchased Power Agreements [Abstract]
Generating capacity (in MW) | MW	3,986	3,770
Low-Income Housing Limited Partnerships
Amount Reflected in Consolidated Balance Sheets [Abstract]
Current assets	$ 7	$ 5
Property, plant and equipment, net	41	42
Other noncurrent assets	1	1
Total assets	49	48
Current liabilities	8	7
Mortgages and other long-term debt payable	26	26
Other noncurrent liabilities	0	0
Total liabilities	$ 34	$ 33

Technology Agreements (Details)

Technology Agreements (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
IBM Agreement [Member]
Technology Agreements [Abstract]
Percent of contract value to be paid if contract is terminated (in hundredths)	50.00%
Technology Agreements, Minimum Payments Due [Abstract]
2020	$ 15
2021	15
2022	6
2023	0
2024	0
Thereafter	0
Information Technology and Data Processing	46	$ 81	$ 98
Accenture Agreement [Member]
Technology Agreements, Minimum Payments Due [Abstract]
2020	11
2021	0
2022	0
2023	0
2024	0
Thereafter	0
Information Technology and Data Processing	52	$ 46	$ 16
Cognizant Agreement [Member]
Technology Agreements, Minimum Payments Due [Abstract]
2020	9
2021	7
2022	3
2023	0
2024	0
Thereafter	0
Information Technology and Data Processing	$ 3

Guarantees and Bond Indemnifica

Guarantees and Bond Indemnifications (Details) - USD ($)	Dec. 31, 2019	Dec. 31, 2018
Commitments and Contingencies Disclosure [Abstract]
Assets Held As Collateral For Guarantor Obligations	$ 0	$ 0
Guarantor Obligations, Maximum Exposure, Undiscounted	$ 62,000,000	$ 69,000,000

Commitments and Contingencies C

Commitments and Contingencies Commitments and Contingencies Phantom (Details) $ in Millions	12 Months Ended
	Dec. 31, 2019USD ($)	Dec. 31, 2018USD ($)	Dec. 31, 2017USD ($)
Loss Contingencies [Line Items]
Approved annual accrual for decommissioning costs	$ 14	$ 14	$ 14
Measurement Input, Risk Free Interest Rate
Loss Contingencies [Line Items]
Debt Instrument, Measurement Input	0.0239	0.0333

Other Comprehensive Income (Det

Other Comprehensive Income (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019		Dec. 31, 2018
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Accumulated other comprehensive income (loss) at beginning of period	$ 12,222
Accumulated other comprehensive income (loss) at end of period	13,239		$ 12,222
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	(60)		(58)
Other comprehensive loss before reclassifications	(23)		(5)
Amortization of net actuarial loss	0		0
Net current period other comprehensive income (loss)	(20)		(2)
Accumulated other comprehensive income (loss) at end of period	(80)		(60)
Gains and Losses on Cash Flow Hedges | Interest Rate Swap
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Amortization of net actuarial loss	(3)	[1]	(3)	[2]
Defined Benefit Pension and Postretirement Items
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Accumulated other comprehensive income (loss) at beginning of period	(64)		(67)
Other comprehensive loss before reclassifications	0		(6)
Amortization of net actuarial loss	(3)	[3]	(9)	[4]
Net current period other comprehensive income (loss)	3		3
Accumulated other comprehensive income (loss) at end of period	(61)		(64)
Defined Benefit Pension and Postretirement Items | Interest Rate Swap
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Amortization of net actuarial loss	0		0
Total
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Accumulated other comprehensive income (loss) at beginning of period	(124)		(125)
Other comprehensive loss before reclassifications	(23)		(11)
Amortization of net actuarial loss	(3)		(9)
Net current period other comprehensive income (loss)	(17)		1
Accumulated other comprehensive income (loss) at end of period	(141)		(124)
Total | Interest Rate Swap
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Amortization of net actuarial loss	$ (3)		$ (3)
[1]	Included in interest charges.
[2]	Included in interest charges.
[3]	Included in the computation of net periodic pension and postretirement benefit costs. See Note 11 for further information.
[4]	Included in the computation of net periodic pension and postretirement benefit costs.

Other Comprehensive Income Phan

Other Comprehensive Income Phantom (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Accumulated Other Comprehensive Income (Loss) [Line Items]
Other Comprehensive Income (Loss) before Reclassifications, Tax	$ (8)	$ (2)	$ 0
Income Tax Expense (Benefit)	128	181	$ 542
Reclassification out of Accumulated Other Comprehensive Income | Gains and Losses on Cash Flow Hedges
Accumulated Other Comprehensive Income (Loss) [Line Items]
Other Comprehensive Income (Loss) before Reclassifications, Tax	(8)	(2)
Income Tax Expense (Benefit)	1	1
Reclassification from AOCI, Current Period, Tax	0	0
Reclassification out of Accumulated Other Comprehensive Income | Defined Benefit Pension and Postretirement Items
Accumulated Other Comprehensive Income (Loss) [Line Items]
Other Comprehensive Income (Loss) before Reclassifications, Tax	0	(2)
Income Tax Expense (Benefit)	0	0
Reclassification from AOCI, Current Period, Tax	$ 1	$ 3

Segments and Related Informat_3

Segments and Related Information (Details) - USD ($) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Segment Reporting Information [Line Items]
Investment in subsidiaries	$ 155				$ 141				$ 155	$ 141
Operating revenues from external customers, Regulated Electric									9,575	9,719	$ 9,676
Operating revenues from external customers, Regulated Natural Gas									1,868	1,739	1,650
Unregulated Operating Revenue									86	79	78
Regulated and Unregulated Operating Revenue	2,798	$ 3,013	$ 2,577	$ 3,141	2,880	$ 3,048	$ 2,658	$ 2,951	11,529	11,537	11,404
Depreciation and amortization									1,765	1,642	1,479
Interest charges and financing costs									736	652	628
Income Tax Expense (Benefit)									128	181	542
Net income (loss)	$ 292	$ 527	$ 238	$ 315	$ 214	$ 491	$ 265	$ 291	1,372	1,261	1,148
Regulated Electric
Segment Reporting Information [Line Items]
Revenues Including Intersegment Revenues									9,576	9,720	9,678
Depreciation and amortization									1,535	1,421	1,298
Interest charges and financing costs									500	449	449
Income Tax Expense (Benefit)									125	187	528
Net income (loss)									1,288	1,177	1,066
Regulated Natural Gas
Segment Reporting Information [Line Items]
Revenues Including Intersegment Revenues									1,870	1,741	1,651
Depreciation and amortization									219	212	174
Interest charges and financing costs									69	61	57
Income Tax Expense (Benefit)									48	28	23
Net income (loss)									195	187	182
All Other
Segment Reporting Information [Line Items]
Unregulated Operating Revenue									86	79	78
Depreciation and amortization									11	9	7
Interest charges and financing costs									167	142	122
Income Tax Expense (Benefit)									(45)	(34)	(9)
Net income (loss)									(111)	(103)	(100)
Operating Segments
Segment Reporting Information [Line Items]
Regulated and Unregulated Operating Revenue									11,532	11,540	11,407
Operating Segments | Regulated Electric
Segment Reporting Information [Line Items]
Operating revenues from external customers, Regulated Electric									9,575	9,719	9,676
Operating Segments | Regulated Natural Gas
Segment Reporting Information [Line Items]
Operating revenues from external customers, Regulated Natural Gas									1,868	1,739	1,650
Intersegment Eliminations
Segment Reporting Information [Line Items]
Regulated and Unregulated Operating Revenue									(3)	(3)	(3)
Intersegment Eliminations | Regulated Electric
Segment Reporting Information [Line Items]
Operating revenues from external customers, Regulated Electric									1	1	2
Intersegment Eliminations | Regulated Natural Gas
Segment Reporting Information [Line Items]
Operating revenues from external customers, Regulated Natural Gas									$ 2	$ 2	$ 1

Summarized Quarterly Financia_3

Summarized Quarterly Financial Data (Unaudited) (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended												12 Months Ended
	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018		Sep. 30, 2018		Jun. 30, 2018		Mar. 31, 2018		Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Quarterly Financial Information Disclosure [Abstract]
Regulated and Unregulated Operating Revenue	$ 2,798	$ 3,013	$ 2,577	$ 3,141	$ 2,880		$ 3,048		$ 2,658		$ 2,951		$ 11,529	$ 11,537	$ 11,404
Operating income	450	758	410	486	339	[1]	696	[1]	450	[1]	480	[1]	2,104	1,965	2,223
Net income	$ 292	$ 527	$ 238	$ 315	$ 214		$ 491		$ 265		$ 291		$ 1,372	$ 1,261	$ 1,148
Basic (in dollars per share)	$ 0.56	$ 1.02	$ 0.46	$ 0.61	$ 0.42		$ 0.96		$ 0.52		$ 0.57		$ 2.64	$ 2.47	$ 2.26
Diluted (in dollars per share)	0.56	1.01	0.46	0.61	0.42		0.96		0.52		0.57		2.64	2.47	2.25
Cash dividends declared per common share (in dollars per share)	$ 0.405	$ 0.405	$ 0.405	$ 0.405	$ 0.380		$ 0.380		$ 0.380		$ 0.380		$ 1.62	$ 1.52	$ 1.44
[1]	In 2018, Xcel Energy implemented ASU No. 2017-07 related to net periodic benefit cost, which resulted in retrospective reclassification of pension costs from O&M expense to other income.

Condensed Statements of Income

Condensed Statements of Income and Comprehensive Income (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Income
Income (Loss) from Equity Method Investments									$ 39	$ 35	$ 30
Expenses and other deductions
Other income									(16)	14	10
Interest charges and financing costs									773	700	663
Income before income taxes									1,500	1,442	1,690
Income tax benefit									128	181	542
Net income	$ 292	$ 527	$ 238	$ 315	$ 214	$ 491	$ 265	$ 291	1,372	1,261	1,148
Other Comprehensive Income (Loss), Net of Tax [Abstract]
Pension and retiree medical benefits, net of tax of $1, $1 and $3, respectively									0	(6)	(3)
Total comprehensive income									$ 1,355	$ 1,262	$ 1,155
Weighted average common shares outstanding:
Basic (in shares)									519	511	509
Diluted (in shares)									520	511	509
Earnings per average common share:
Basic (in dollars per share)	$ 0.56	$ 1.02	$ 0.46	$ 0.61	$ 0.42	$ 0.96	$ 0.52	$ 0.57	$ 2.64	$ 2.47	$ 2.26
Diluted (in dollars per share)	$ 0.56	$ 1.01	$ 0.46	$ 0.61	$ 0.42	$ 0.96	$ 0.52	$ 0.57	$ 2.64	$ 2.47	$ 2.25
Xcel Energy Inc.
Income
Income (Loss) from Equity Method Investments									$ 1,505	$ 1,393	$ 1,263
Total income									1,505	1,393	1,263
Expenses and other deductions
Operating expenses									23	24	30
Other income									(9)	(1)	(6)
Interest charges and financing costs									173	149	128
Total expenses and other deductions									187	172	152
Income before income taxes									1,318	1,221	1,111
Income tax benefit									(54)	(40)	(37)
Net income									1,372	1,261	1,148
Other Comprehensive Income (Loss), Net of Tax [Abstract]
Pension and retiree medical benefits, net of tax of $1, $1 and $3, respectively									3	3	4
Derivative instruments, net of tax of $(7), $(1) and $2, respectively									(20)	(2)	3
Other Comprehensive Income (Loss), Net of Tax									(17)	1	7
Total comprehensive income									$ 1,355	$ 1,262	$ 1,155

Condensed Statements Phantom (D

Condensed Statements Phantom (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Condensed Financial Information Disclosure [Abstract]
Pension and retiree medical benefits, tax expense(benefit)	$ 1	$ 1	$ 3
Derivative instruments, tax expense(benefit)	$ (7)	$ (1)	$ 2

Condensed Statement of Cash Flo

Condensed Statement of Cash Flows (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Operating activities
Net cash provided by (used in) operating activities	$ 3,263	$ 3,122	$ 3,126
Investing activities
Net cash provided by (used in) investing activities	(4,343)	(3,986)	(3,296)
Financing activities
Proceeds from (repayment of) short-term borrowings, net	(443)	225	422
Proceeds from issuance of long-term debt	2,920	1,675	1,518
Repayment of long-term debt	(949)	(452)	(1,030)
Proceeds from Issuance of Common Stock	458	230	0
Dividends paid	(791)	(730)	(721)
Other, net	(14)	(20)	(21)
Net cash provided by (used in) financing activities	1,181	928	168
Net change in cash and cash equivalents	101	64	(2)
Cash and cash equivalents at beginning of period	147	83	85
Cash and cash equivalents at end of period	248	147	83
Xcel Energy Inc.
Operating activities
Net cash provided by (used in) operating activities	1,389	1,210	1,208
Investing activities
Capital contributions to subsidiaries	(1,594)	(809)	(849)
Investments in the utility money pool	(1,054)	(2,578)	(1,258)
Return of investments in the utility money pool	1,093	2,493	1,173
Net cash provided by (used in) investing activities	(1,555)	(894)	(934)
Financing activities
Proceeds from (repayment of) short-term borrowings, net	12	(295)	715
Proceeds from issuance of long-term debt	1,120	492	0
Repayment of long-term debt	(550)	0	(250)
Proceeds from Issuance of Common Stock	458	230	0
Repurchases of common stock	0	(1)	(3)
Dividends paid	(791)	(730)	(721)
Other, net	(14)	(12)	(14)
Net cash provided by (used in) financing activities	235	(316)	(273)
Net change in cash and cash equivalents	69	0	1
Cash and cash equivalents at beginning of period	1	1	0
Cash and cash equivalents at end of period	$ 70	$ 1	$ 1

Condensed Balance Sheet (Detail

Condensed Balance Sheet (Details) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Assets
Cash and cash equivalents	$ 248	$ 147	$ 83	$ 85
Investment in subsidiaries	155	141
Other assets	492	272
Total other assets	7,852	5,949
Total assets	50,448	45,987
Total current assets	3,113	3,094
Liabilities and Equity
Dividends payable	212	195
Short-term debt	595	1,038
Other current liabilities	662	463
Total current liabilities	4,568	4,460
Other liabilities	186	206
Total deferred credits and other liabilities	15,234	13,502
Capitalization
Total common stockholders’ equity	13,239	12,222
Total liabilities and equity	50,448	45,987
Xcel Energy Inc.
Assets
Cash and cash equivalents	70	1	$ 1	$ 0
Accounts receivable from subsidiaries	370	309
Other current assets	12	1
Investment in subsidiaries	17,443	15,965
Other assets	60	44
Total other assets	17,503	16,009
Total assets	17,955	16,320
Total current assets	452	311
Liabilities and Equity
Dividends payable	212	195
Short-term debt	500	488
Other current liabilities	33	10
Total current liabilities	745	693
Other liabilities	23	32
Total deferred credits and other liabilities	23	32
Capitalization
Long-term debt, noncurrent	3,948	3,373
Total common stockholders’ equity	13,239	12,222
Total capitalization	17,187	15,595
Total liabilities and equity	$ 17,955	$ 16,320

Condensed Notes to the Financia

Condensed Notes to the Financial Statements (Details) - USD ($)		3 Months Ended	12 Months Ended
		Dec. 31, 2019	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Money Pool [Abstract]
Schedule of Guarantor Obligations			Guarantees and bond indemnities issued and outstanding as of Dec. 31, 2019: (Millions of Dollars) Guarantor Guarantee Amount Current Exposure Triggering Event Guarantee of loan for Hiawatha Collegiate High School (a) Xcel Energy Inc. $ 1.0 — (c) Guarantee performance and payment of surety bonds for Xcel Energy Inc.’s utility subsidiaries (b) Xcel Energy Inc. 60.4 (e) (d) (a) The term of this guarantee expires the earlier of 2024 or full repayment of the loan. (b) 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. (c) Nonperformance and/or nonpayment. (d) Per the indemnity agreement between Xcel Energy Inc. and the various surety companies, surety companies have the discretion to demand that collateral be posted. (e)
Guarantor Obligations [Line Items]
Guarantees issued and outstanding		$ 62,000,000	$ 62,000,000	$ 69,000,000
Payment or Performance Guarantee | Loan for Hiawatha Collegiate High School [Member]
Guarantor Obligations [Line Items]
Guarantees issued and outstanding	[1]	1,000,000	1,000,000
Current exposure under these guarantees	[1]	0	0
Payment or Performance Guarantee | Surety Bonds
Guarantor Obligations [Line Items]
Guarantees issued and outstanding	[2]	60,400,000	60,400,000
Xcel Energy Inc.
Accounts Receivable and Payable with Affiliates [Abstract]
Accounts Receivable		370,000,000	370,000,000	309,000,000
Accounts Payable		0	0	0
Dividends [Abstract]
Cash dividends paid to Xcel Energy by subsidiaries			2,987,000,000	1,097,000,000	$ 1,063,000,000
Money Pool [Abstract]
Loan outstanding at period end		39,000,000	39,000,000	0	85,000,000
Average loan outstanding		35,000,000	47,000,000	71,000,000	38,000,000
Maximum loan outstanding		$ 125,000,000	$ 250,000,000	$ 243,000,000	$ 226,000,000
Weighted average interest rate, computed on a daily basis (percentage)		1.67%	2.15%	1.95%	1.13%
Weighted average interest rate at period end (percentage)		1.63%	1.63%		1.18%
Money pool interest income		$ 0.0147	$ 1,000,000	$ 1,400,000	$ 400,000
Xcel Energy Inc. | NSP Minnesota
Accounts Receivable and Payable with Affiliates [Abstract]
Accounts Receivable		60,000,000	60,000,000	117,000,000
Accounts Payable		0	0	0
Xcel Energy Inc. | NSP-Wisconsin
Accounts Receivable and Payable with Affiliates [Abstract]
Accounts Receivable		17,000,000	17,000,000	3,000,000
Accounts Payable		0	0	0
Xcel Energy Inc. | PSCo
Accounts Receivable and Payable with Affiliates [Abstract]
Accounts Receivable		78,000,000	78,000,000	29,000,000
Accounts Payable		0	0	0
Xcel Energy Inc. | SPS
Accounts Receivable and Payable with Affiliates [Abstract]
Accounts Receivable		47,000,000	47,000,000	39,000,000
Accounts Payable		0	0	0
Xcel Energy Inc. | Xcel Energy Services Inc.
Accounts Receivable and Payable with Affiliates [Abstract]
Accounts Receivable		112,000,000	112,000,000	96,000,000
Accounts Payable		0	0	0
Xcel Energy Inc. | Xcel Energy Ventures Inc.
Accounts Receivable and Payable with Affiliates [Abstract]
Accounts Receivable		25,000,000	25,000,000	13,000,000
Accounts Payable		0	0	0
Xcel Energy Inc. | Other Subsidiaries
Accounts Receivable and Payable with Affiliates [Abstract]
Accounts Receivable		31,000,000	31,000,000	12,000,000
Accounts Payable		$ 0	$ 0	$ 0
[1]	The term of this guarantee expires the earlier of 2024 or full repayment of the loan.
[2]	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.

Schedule II (Details)

Schedule II (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2019		Dec. 31, 2018		Dec. 31, 2017
SEC Schedule, 12-09, Movement in Valuation Allowances and Reserves [Roll Forward]
Expense Related to Revaluation of Federal Benefit - TCJA		$ 14
Reduced Expense Related to Revaluation of Federal Benefits - TCJA		4
Allowance for Bad Debts
SEC Schedule, 12-09, Movement in Valuation Allowances and Reserves [Roll Forward]
Balance at Jan. 1		55		$ 52		$ 51
Charged to costs and expenses		42		42		39
Charged to other accounts	[1]	16		11		10
Deductions from reserves	[2]	(58)		(50)		(48)
Balance at Dec. 31		55		55		52
NOL and Tax Credit Valuation Allowances
SEC Schedule, 12-09, Movement in Valuation Allowances and Reserves [Roll Forward]
Balance at Jan. 1		79		77		58
Charged to costs and expenses		9		7		9
Charged to other accounts		0		0		22	[3]
Deductions from reserves		(21)	[4]	(5)	[4]	(12)	[5]
Balance at Dec. 31		$ 67		$ 79		$ 77
[1]	Recovery of amounts previously written off.
[2]	Deductions related primarily to bad debt write-offs.
[3]	Accrual of valuation allowances for North Dakota ITC, net of federal income tax benefit, that is offset to a regulatory liability and includes $14 million expense related to the revaluation of federal benefit as a result of the TCJA.
[4]	Primarily the reductions to valuation allowances due to additional NOLs and tax credits now forecasted to be used prior to expiration.
[5]	Primarily the reductions to valuation allowances for North Dakota ITC carryforwards, net of federal benefit, primarily due to a consolidated adjustment to the regulatory liability accrual referenced above; the change includes $4 million of reduced expense related to the revaluation of federal benefit as a result of TCJA.