Xcel Energy (XEL) 10-K 23 Feb 22 2021 FY Annual report Financial data

Cover Page

Cover Page - USD ($)	12 Months Ended
	Dec. 31, 2021	Feb. 17, 2022	Jun. 30, 2021
Cover [Abstract]
Document Type	10-K
Document Annual Report	true
Document Period End Date	Dec. 31, 2021
Document Transition Report	false
Entity File Number	001-3034
Entity Incorporation, State or Country Code	MN
Entity Tax Identification Number	41-0448030
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 per share
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
ICFR Auditor Attestation Flag	true
Entity Shell Company	false
Entity Public Float			$ 35,463,594,471
Entity Common Stock, Shares Outstanding		544,213,730
Entity Registrant Name	XCEL ENERGY INC
Entity Central Index Key	0000072903
Current Fiscal Year End Date	--12-31
Document Fiscal Year Focus	2021
Document Fiscal Period Focus	FY
Amendment Flag	false

Audit Information

Audit Information	12 Months Ended
	Dec. 31, 2021
Auditor [Line Items]
Auditor Firm ID	34
Auditor Name	DELOITTE & TOUCHE LLP
Auditor Location	Minneapolis, Minnesota

Accounting Pronouncements

Accounting Pronouncements	12 Months Ended
	Dec. 31, 2021
Accounting Standards Update and Change in Accounting Principle [Abstract]
Accounting Pronouncements	Recently Adopted Credit Losses — In 2016, the FASB issued Financial Instruments - Credit Losses, Topic 32 6 (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.

CONSOLIDATED STATEMENTS OF INCO

CONSOLIDATED STATEMENTS OF INCOME - USD ($) shares in Millions, $ in Millions		12 Months Ended
		Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Operating revenues
Electric		$ 11,205	$ 9,802	$ 9,575
Natural Gas		2,132	1,636	1,868
Other		94	88	86
Total operating revenues		13,431	11,526	11,529
Operating expenses
Electric fuel and purchased power		4,733	3,512	3,510
Cost of natural gas sold and transported		1,081	689	918
Cost of sales — other		38	37	40
Operating and maintenance expenses		2,321	2,324	2,338
Conservation and demand side management expenses		304	288	285
Depreciation and amortization		2,121	1,948	1,765
Taxes (other than income taxes)		630	612	569
Total operating expenses		11,228	9,410	9,425
Operating income		2,203	2,116	2,104
Other income (expense), net		5	(6)	16
Equity earnings of unconsolidated subsidiaries		62	40	39
Allowance for funds used during construction — equity		73	115	77
Interest charges and financing costs
Interest charges — includes other financing costs of $29, $28 and $26, respectively		842	840	773
Allowance for funds used during construction — debt		(26)	(42)	(37)
Total interest charges and financing costs		816	798	736
Income before income taxes		1,527	1,467	1,500
Income tax (benefit) expense		(70)	(6)	128
Net income		$ 1,597	$ 1,473	$ 1,372
Weighted average common shares outstanding:
Basic		539	527	519
Diluted	[1]	540	528	520
Earnings per average common share:
Basic		$ 2.96	$ 2.79	$ 2.64
Diluted		$ 2.96	$ 2.79	$ 2.64
Net income		$ 1,597	$ 1,473	$ 1,372
[1]	Diluted common shares outstanding included common stock equivalents of 0.3 million, 1.1 million and 1.3 million shares for 2021, 2020 and 2019, respectively.

CONSOLIDATED STATEMENTS OF IN_2

CONSOLIDATED STATEMENTS OF INCOME (Parenthetical) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Income Statement [Abstract]
Other financing costs	$ 29	$ 28	$ 26

CONSOLIDATED STATEMENTS OF COMP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Comprehensive income:
Net income	$ 1,597	$ 1,473	$ 1,372
Pension and retiree medical benefits:
Net pension and retiree medical losses arising during the period, net of tax of $—, $(2) and $—, respectively	0	(5)	0
Reclassification of losses to net income, net of tax of $3, $3 and $1, respectively	(8)	(10)	(3)
Derivative instruments:
Net fair value increase (decrease), net of tax of $1, $(3) and $(8), respectively	4	(10)	(23)
Reclassification of losses to net income, net of tax of $2, $2 and $1, respectively	(6)	(5)	(3)
Total other comprehensive income (loss)	18		(17)
Total comprehensive income	$ 1,615	$ 1,473	$ 1,355

CONSOLIDATED STATEMENTS OF CO_2

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Statement of Comprehensive Income [Abstract]
Net pension gains, tax	$ 0	$ (2)	$ 0
Pension reclassifications, tax	(3)	(3)	(1)
Derivative fair value decrease, tax	1	(3)	(8)
Derivative reclassifications, tax	$ (2)	$ (2)	$ (1)

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Operating activities
Net income	$ 1,597	$ 1,473	$ 1,372
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization	2,143	1,959	1,785
Nuclear fuel amortization	114	123	119
Deferred income taxes	79	8	(143)
Allowance for equity funds used during construction	(73)	(115)	(77)
Earnings from equity method investments	(62)	(40)	(39)
Dividends from equity method investments	42	42	40
Provision for bad debts	60	60	42
Share-based compensation expense	31	73	58
Net realized and unrealized hedging and derivative transactions	(57)	(27)	45
Changes in operating assets and liabilities:
Accounts receivable	(164)	(154)	(20)
Accrued unbilled revenues	(149)	(3)	42
Inventories	(126)	(80)	(84)
Other current assets	(34)	(45)	25
Accounts payable	138	(33)	(12)
Net regulatory assets and liabilities	(973)	(144)	(66)
Other current liabilities	(1)	29	(15)
Pension and other employee benefit obligations	(135)	(125)	(135)
Other, net	(83)	(137)	40
Net Cash Provided by (Used in) Operating Activities, Total	2,189	2,848	3,263
Investing activities
Capital/construction expenditures	(4,244)	(5,369)	(4,225)
Sale of MEC	0	684	0
Purchase of investment securities	(757)	(1,398)	(995)
Proceeds from the sale of investment securities	743	1,378	975
Other, net	(29)	(35)	(98)
Net Cash Provided by (Used in) Investing Activities, Total	(4,287)	(4,740)	(4,343)
Financing activities
Proceeds from (repayments of) short-term borrowings, net	421	(11)	(443)
Proceeds from Issuance of Long-term Debt	2,710	2,940	2,920
Repayments of long-term debt, including reacquisition premiums	(417)	(1,001)	(949)
Proceeds from Issuance of Common Stock	366	727	458
Payments of Dividends	(935)	(856)	(791)
Proceeds from (Payments for) Other Financing Activities	(10)	(26)	(14)
Net Cash Provided by (Used in) Financing Activities, Total	2,135	1,773	1,181
Net change in cash and cash equivalents	37	(119)	101
Cash and Cash Equivalents, at Carrying Value, Beginning Balance	129	248	147
Cash and Cash Equivalents, at Carrying Value, Ending Balance	166	129	248
Supplemental disclosure of cash flow information:
Interest Paid, Excluding Capitalized Interest, Operating Activities	(788)	(758)	(698)
Income Taxes Paid, Net	(4)	12	53
Other Noncash Investing and Financing Items [Abstract]
Capital Expenditures Incurred but Not yet Paid	501	400	421
Inventory transfers to plant, property and equipment	87	275	88
Right-of-Use Asset Obtained in Exchange for Operating Lease Liability	8	369	1,843
Allowance for equity funds used during construction	73	115	77
Stock Issued	$ 60	$ 67	$ 63

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions		Dec. 31, 2021	Dec. 31, 2020
Current assets
Cash and cash equivalents		$ 166	$ 129
Accounts receivable, net		1,018	916
Accrued unbilled revenues		862	714
Inventories		631	535
Regulatory assets		1,106	640
Derivative instruments		123	49
Prepaid taxes		44	42
Prepayments and other		289	250
Total current assets		4,239	3,275
Property, plant and equipment, net		45,457	42,950
Other assets
Nuclear decommissioning fund and other investments		3,628	3,096
Regulatory assets		2,738	2,737
Derivative instruments		67	30
Operating lease right-of-use assets		1,291	1,490
Other		431	379
Total other assets		8,155	7,732
Total assets		57,851	53,957
Current liabilities
Current portion of long-term debt		601	421
Short-term debt		1,005	584
Accounts payable		1,409	1,237
Regulatory liabilities	[1]	271	311
Taxes accrued		569	578
Accrued interest		209	203
Dividends payable		249	231
Derivative instruments		69	53
Operating Lease, Liability, Current		205	214
Other		459	407
Total current liabilities		5,046	4,239
Deferred credits and other liabilities
Deferred income taxes		4,894	4,746
Deferred investment tax credits		53	45
Regulatory liabilities	[1]	5,405	5,302
Asset retirement obligations		3,151	2,884
Derivative instruments		105	131
Customer advances		196	197
Pension and employee benefit obligations		306	666
Operating lease liabilities		1,146	1,344
Other		158	183
Total deferred credits and other liabilities		15,414	15,498
Commitments and contingencies
Capitalization
Long-term debt		21,779	19,645
Common stock — 1,000,000,000 shares authorized of $2.50 par value; 544,025,269 and 537,438,394 shares outstanding at Dec. 31, 2021 and Dec. 31, 2020, respectively		$ 1,360	$ 1,344
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		544,025,269	537,438,394
Additional paid in capital		$ 7,803	$ 7,404
Retained earnings		6,572	5,968
Accumulated other comprehensive loss		(123)	(141)
Total common stockholders’ equity		15,612	14,575
Total liabilities and equity		$ 57,851	$ 53,957
[1]	Revenue subject to refund of $17 million for both 2021 and 2020 is included in other current liabilities.

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, 2018		514,036,787
Beginning balance at Dec. 31, 2018	$ 12,222	$ 1,285	$ 6,168	$ 4,893	$ (124)
Increase (Decrease) in Stockholders' Equity
Net income	1,372
Other comprehensive income	(17)				(17)
Cash dividends declared per common share (in dollars per share)		$ 1.62
Dividends declared on common stock	(846)			(846)
Issuances of common stock (in shares)		10,507,943
Issuances of common stock (value)	494	$ 26	468
Stock repurchased during period (in shares)		(5,730)
Repurchases of common stock (value)	0	$ 0	0
Share-based compensation	14		20	(6)
Balance (in shares) at Dec. 31, 2019		524,539,000
Ending balance at Dec. 31, 2019	13,239	$ 1,311	6,656	5,413	(141)
Increase (Decrease) in Stockholders' Equity
Net income	1,473
Other comprehensive income					0
Cash dividends declared per common share (in dollars per share)		$ 1.72
Dividends declared on common stock	(909)			(909)
Issuances of common stock (in shares)		12,953,869
Issuances of common stock (value)	764	$ 33	731
Stock repurchased during period (in shares)		(54,475)
Repurchases of common stock (value)	(4)	$ 0	(4)
Share-based compensation	14		21	(7)
Credit Losses, Topic 326 (ASC Topic 326)	$ (2)			(2)
Balance (in shares) at Dec. 31, 2020	537,438,394	537,438,394
Ending balance at Dec. 31, 2020	$ 14,575	$ 1,344	7,404	5,968	(141)
Increase (Decrease) in Stockholders' Equity
Net income	1,597
Other comprehensive income	18				18
Cash dividends declared per common share (in dollars per share)		$ 1.83
Dividends declared on common stock	(989)			(989)
Issuances of common stock (in shares)		6,586,875
Issuances of common stock (value)	403	$ 16	387
Share-based compensation	$ 8		12	(4)
Balance (in shares) at Dec. 31, 2021	544,025,269	544,025,269
Ending balance at Dec. 31, 2021	$ 15,612	$ 1,360	$ 7,803	$ 6,572	$ (123)

Summary of Significant Accounti

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2021
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, Venture Holdings and Nicollet Project Holdings. 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. Venture Holdings invests in limited partnerships, including EIP funds with portfolios of investments in energy technology companies. Nicollet Project Holdings invests in nonregulated assets such as the MEC generating facility (through July 2020) and Minnesota community solar gardens. 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, Xcel Energy Nuclear Services Holdings, LLC and Xcel Energy Services Inc. Xcel Energy Inc. and its subsidiaries collectively are referred to as Xcel Energy. Xcel Energy’s consolidated financial statements include its wholly-owned subsidiaries and VIEs for which it is the primary beneficiary. 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 investments in EIP funds and WYCO. 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 consolidated financial statements or notes have been reclassified 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, 2021 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 for 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. • 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 would be refundable to utility customers over the remaining life of the related assets. Xcel Energy anticipates that a tax rate increase would result in the establishment of a regulatory asset, subject to an evaluation of whether future recovery is expected. 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 other (expense) income or 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 commission approved 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. Plant removal costs of Xcel Energy’s utility subsidiaries are recovered in rates as authorized by the appropriate regulatory entities. The amount of removal costs is based on current factors used in existing depreciation rates. Accumulated removal costs are reflected in the consolidated balance sheet as a regulatory liability. Depreciation expense, expressed as a percentage of average depreciable property, was approximately 3.5% for 2021, 3.4% for 2020 and 3.3% for 2019. 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. 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. 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 Notes 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. For certain environmental costs related to facilities currently in use, such as for 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 systematically 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 physical sales to customers (native load and wholesale) on a gross basis in electric revenues and cost of sales. Revenues and charges for short-term physical wholesale sales of excess energy transacted through RTOs are also recorded on a gross basis. Other revenues and charges settled/facilitated through an RTO 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. As of Dec. 31, 2021 and 2020, the allowance for bad debts was $106 million and $79 million, respectively. Inventory — Inventory is recorded at average cost and consisted of the following: (Millions of Dollars) Dec. 31, 2021 Dec. 31, 2020 Inventories Materials and supplies $ 289 $ 275 Fuel 182 176 Natural gas 160 84 Total inventories $ 631 $ 535 Equity Method Investments — The equity method of accounting is used for investments in WYCO and EIP funds, which results in Xcel Energy’s recognition of its share of these investees’ GAAP pretax earnings, based on Xcel Energy’s proportional ownership interest. For investments in EIP funds, this includes Xcel Energy’s share of fund expenses and realized gains and losses, as well as unrealized gains and losses resulting from valuations of the funds’ investments in emerging energy technology companies. 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 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 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/sales true up 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 or from other instances where the regulator authorizes a future surcharge in response to past activities or completed events. 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 and purchased power costs for the cost of RECs received. An inventory accounting model is used to account for RECs recognized on the consolidated balance sheets, however these assets are classified as regulatory assets if amounts are 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.

Property Plant and Equipment Pr

Property Plant and Equipment Property Plant and Equipment	12 Months Ended
	Dec. 31, 2021
Property, Plant and Equipment [Abstract]
Property, Plant and Equipment Disclosure	Major classes of property, plant and equipment (Millions of Dollars) Dec. 31, 2021 Dec. 31, 2020 Property, plant and equipment, net Electric plant $ 48,680 $ 47,104 Natural gas plant 7,758 7,135 Common and other property 2,602 2,503 Plant to be retired (a) 1,200 677 CWIP 1,969 1,877 Total property, plant and equipment 62,209 59,296 Less accumulated depreciation (17,060) (16,657) Nuclear fuel 3,081 2,970 Less accumulated amortization (2,773) (2,659) Property, plant and equipment, net $ 45,457 $ 42,950 (a) Includes regulator-approved retirements of Comanche Units 1 and 2 and jointly owned Craig Unit 1 for PSCo, and Sherco Units 1, 2 and 3 and A.S. King for NSP-Minnesota. Also includes SPS’ expected retirement of Tolk and conversion of Harrington to natural gas, and PSCo’s planned retirement of jointly owned Craig Unit 2. Joint Ownership of Generation, Transmission and Gas Facilities The utility subsidiaries’ jointly owned assets as of Dec. 31, 2021: (Millions of Dollars, Except Percent Owned) Plant in Service Accumulated Depreciation Percent Owned NSP-Minnesota Electric generation: Sherco Unit 3 $ 620 $ 451 59 % Sherco common facilities 178 108 80 Sherco substation 5 4 59 Electric transmission: Grand Meadow 11 3 50 Huntley Wilmarth 48 1 50 CapX2020 952 127 51 Total NSP-Minnesota (a) $ 1,814 $ 694 (a) Projects additionally include $7 million in CWIP. (Millions of Dollars, Except Percent Owned) Plant in Service Accumulated Depreciation Percent Owned NSP-Wisconsin Electric transmission: La Crosse, WI to Madison, WI $ 177 $ 15 37 % CapX2020 169 28 80 Total NSP-Wisconsin (a) $ 346 $ 43 (a) Projects additionally include $2 million in CWIP. (Millions of Dollars, Except Percent Owned) Plant in Service Accumulated Depreciation Percent Owned PSCo Electric generation: Hayden Unit 1 $ 156 $ 99 76 % Hayden Unit 2 151 78 37 Hayden common facilities 42 27 53 Craig Units 1 and 2 81 48 10 Craig common facilities 39 25 7 Comanche Unit 3 917 154 67 Comanche common facilities 28 2 82 Electric transmission: Transmission and other facilities 182 63 Various Gas transmission: Rifle, CO to Avon, CO 22 8 60 Gas transmission compressor 8 2 50 Total PSCo (a) $ 1,626 $ 506 (a) Projects additionally include $4 million in CWIP.

Regulatory Assets and Liabiliti

Regulatory Assets and Liabilities	12 Months Ended
	Dec. 31, 2021
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 Amortization Period Dec. 31, 2021 Dec. 31, 2020 Regulatory Assets Current Noncurrent Current Noncurrent Pension and retiree medical obligations 11 Various $ 77 $ 944 $ 82 $ 1,268 Deferred natural gas, electric, steam energy/fuel costs One five 504 543 14 18 Recoverable deferred taxes on AFUDC Plant lives — 289 — 283 Excess deferred taxes — TCJA 7 Various 14 219 16 229 Depreciation differences One 16 173 16 154 Environmental remediation costs 1, 12 Various 14 92 16 113 Texas revenue surcharges One two 20 64 54 17 Sales true-up and revenue decoupling One two 33 56 101 28 Benson biomass PPA termination and asset purchase Eight 10 55 10 65 Renewable resources and environmental initiatives One two 170 48 129 12 PI extended power uprate 13 years 4 46 3 49 Purchased power contract costs Term of related contract 9 45 7 54 Conservation programs (a) 1 One two 21 35 26 36 Losses on reacquired debt Term of related debt 3 35 4 38 Contract valuation adjustments (b) 1, 10 Term of related contract 22 34 23 48 State commission adjustments Plant lives 1 32 1 32 Laurentian biomass PPA termination Two 18 18 18 36 Nuclear refueling outage costs 1 One two 37 16 28 10 Property tax Various 16 16 16 21 Gas pipeline inspection and remediation costs One two 33 12 26 9 Net AROs (c) 1, 12 Various — (112) — 139 Other Various 84 78 50 78 Total regulatory assets $ 1,106 $ 2,738 $ 640 $ 2,737 (a) Includes costs for conservation programs, as well as incentives allowed in certain jurisdictions. (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 amounts recorded for future recovery of AROs, less amounts recovered through nuclear decommissioning accruals and gains from decommissioning investments. Components of regulatory liabilities: (Millions of Dollars) See Note(s) Remaining Amortization Period Dec. 31, 2021 Dec. 31, 2020 Regulatory Liabilities Current Noncurrent Current Noncurrent Deferred income tax adjustments and TCJA refunds (a) 7 Various $ 26 $ 3,230 $ 20 $ 3,368 Plant removal costs 1, 12 Various — 1,655 — 1,520 Effects of regulation on employee benefit costs (b) Various — 235 — 221 Renewable resources and environmental initiatives Various 1 101 5 59 ITC deferrals 1 Various — 53 — 51 Revenue decoupling One two 9 41 10 41 Contract valuation adjustments (c) 1, 10 One three 56 1 19 — Deferred natural gas, electric, steam energy/fuel costs Less than one year 50 — 84 — Conservation programs (d) 1 Less than one year 42 — 49 — DOE settlement Less than one year 14 14 23 — Other Various 73 75 101 42 Total regulatory liabilities (e) $ 271 $ 5,405 $ 311 $ 5,302 (a) Includes the revaluation of recoverable/regulated plant accumulated deferred income taxes and revaluation impact of non-plant accumulated deferred income taxes 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 the fair value of certain long-term PPAs used to meet energy capacity requirements and valuation adjustments on natural gas commodity purchases. (d) Includes costs for conservation programs, as well as incentives allowed in certain jurisdictions. (e) Revenue subject to refund of $17 million for both 2021 and 2020 is included in other current liabilities. At Dec. 31, 2021 and 2020, Xcel Energy’s regulatory assets not earning a return primarily included the unfunded portion of pension and retiree medical obligations and net AROs. In addition, regulatory assets included $1,718 million and $812 million at Dec. 31, 2021 and 2020, respectively, of past expenditures not earning a return. Amounts are related to funded pension obligations, sales true-up and revenue decoupling, purchased natural gas and electric energy costs (including those related to Winter Storm Uri), 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, 2021
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, 2021 Year Ended Dec. 31 2021 2020 2019 Borrowing limit $ 3,100 $ 3,100 $ 3,100 $ 3,600 Amount outstanding at period end 1,005 1,005 584 595 Average amount outstanding 1,200 1,399 1,126 1,115 Maximum amount outstanding 1,774 2,054 2,080 1,780 Weighted average interest rate, computed on a daily basis 0.54 % 0.57 % 1.45 % 2.72 % Weighted average interest rate at period end 0.31 0.31 0.23 2.34 Term Loan Agreements — In the fourth quarter of 2021, Xcel Energy repaid its $1.2 billion 364-Day Term Loan Agreement. Bilateral Credit Agreement — In April 2021, NSP-Minnesota’s uncommitted bilateral credit agreement was renewed for an additional one-year term. The credit agreement is limited in use to support letters of credit. As of Dec. 31, 2021, NSP-Minnesota had $45 million outstanding letters of credit under the $75 million the Bilateral Credit Agreement. 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, 2021 and 2020, there were $19 million and $20 million of letters of credit outstanding under the credit facilities, respectively. 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 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. Terms of Credit Agreements — Xcel Energy Inc., NSP-Minnesota, NSP-Wisconsin, PSCo and SPS entered five-year credit agreements with a syndicate of banks. The total borrowing limit under the amended credit agreements is $3.1 billion, with a swingline subfacility for Xcel Energy up to $75 million. The amended credit agreements mature in June 2024. Features of the credit facilities: Debt-to-Total Capitalization Ratio (a) Amount Facility May Be Increased (millions of dollars) Additional Periods for Which a One-Year Extension May Be Requested (b) 2021 2020 Xcel Energy Inc. (c) 60 % 59 % $ 250 2 NSP-Wisconsin 49 46 N/A 1 NSP-Minnesota 47 47 100 2 SPS 47 48 50 2 PSCo 44 44 100 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. would 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, 2021, 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, 2021: (Millions of Dollars) Credit Facility (a) Drawn (b) Available Xcel Energy Inc. $ 1,250 $ 638 $ 612 PSCo 700 155 545 NSP-Minnesota 500 9 491 SPS 500 139 361 NSP-Wisconsin 150 83 67 Total $ 3,100 $ 1,024 $ 2,076 (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 utility subsidiaries had no direct advances on facilities outstanding as of Dec. 31, 2021 and 2020. 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 (in millions of dollars): Xcel Energy Inc. Financing Instrument Interest Rate Maturity Date 2021 2020 Unsecured senior notes 2.40 % March 15, 2021 $ — $ 400 Unsecured senior notes (b) 0.50 Oct. 15, 2023 500 500 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) 1.75 March 15,2027 500 — Unsecured senior notes 4.00 June 15, 2028 130 130 Unsecured senior notes 4.00 June 15, 2028 500 500 Unsecured senior notes 2.60 Dec. 1, 2029 500 500 Unsecured senior notes (b) 3.40 June 1, 2030 600 600 Unsecured senior notes (a) 2.35 Nov. 15, 2031 300 — Unsecured senior notes 6.50 July 1, 2036 300 300 Unsecured senior notes 4.80 Sep. 15, 2041 250 250 Unsecured senior notes 3.50 Dec. 1, 2049 500 500 Unamortized discount (8) (7) Unamortized debt issuance cost (33) (32) Current maturities — (400) Total long-term debt $ 5,139 $ 4,341 (a) 2021 financing. (b) 2020 financing. NSP-Minnesota Financing Instrument Interest Rate Maturity Date 2021 2020 First mortgage bonds 2.15 % Aug. 15, 2022 $ 300 $ 300 First mortgage bonds 2.60 May 15, 2023 400 400 First mortgage bonds 7.125 July 1, 2025 250 250 First mortgage bonds 6.50 March 1, 2028 150 150 First mortgage bonds (a) 2.25 April 1, 2031 425 — 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 4.125 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 Sep. 15, 2047 600 600 First mortgage bonds 2.90 March 1, 2050 600 600 First mortgage bonds (b) 2.60 June 1, 2051 700 700 First mortgage bonds (a) 3.20 April 1,2052 425 — Other long-term debt 3 — Unamortized discount (44) (42) Unamortized debt issuance cost (62) (54) Current maturities (300) — Total long-term debt $ 6,447 $ 5,904 (a) 2021 financing. (b) 2020 financing. NSP-Wisconsin Financing Instrument Interest Rate Maturity Date 2021 2020 City of La Crosse resource recovery bond 6.00 % Nov. 1, 2021 $ — $ 19 First mortgage bonds 3.30 June 15, 2024 100 100 First mortgage bonds 3.30 June 15, 2024 100 100 First mortgage bonds 6.375 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 4.20 Sept. 1, 2048 200 200 First mortgage bonds (b) 3.05 May 1, 2051 100 100 First mortgage bonds (a) 2.82 May 1, 2051 100 — Other long-term debt 1 — Unamortized discount (4) (4) Unamortized debt issuance cost (10) (9) Current maturities — (19) Total long-term debt $ 987 $ 887 (a) 2021 financing. (b) 2020 financing. PSCo Financing Instrument Interest Rate Maturity Date 2021 2020 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 3.70 June 15, 2028 350 350 First mortgage bonds (b) 1.90 Jan. 15, 2031 375 375 First mortgage bonds (a) 1.875 June 15, 2031 750 — 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 4.10 June 15, 2048 350 350 First mortgage bonds 4.05 Sept. 15, 2049 400 400 First mortgage bonds 3.20 March 1, 2050 550 550 First mortgage bonds (b) 2.70 Jan. 15, 2051 375 375 Unamortized discount (33) (30) Unamortized debt issuance cost (50) (46) Current maturities (300) — Total long-term debt $ 6,167 $ 5,724 (a) 2021 financing. (b) 2020 financing. SPS Financing Instrument Interest Rate Maturity Date 2021 2020 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 4.40 Nov. 15, 2048 300 300 First mortgage bonds 3.75 June 15, 2049 300 300 First mortgage bonds (b) 3.15 May 1, 2050 350 350 First mortgage bonds (a) 3.15 May 1, 2050 250 — Unamortized discount (9) (10) Unamortized debt issuance cost (28) (26) Total long-term debt $ 3,013 $ 2,764 (a) 2020 financing re-opened in 2021. (b) 2020 financing. Other Subsidiaries Financing Instrument Interest Rate Maturity Date 2021 2020 Various Eloigne affordable housing project notes 0.00% - 6.50% 2022 — 2055 $ 27 $ 27 Current maturities (1) (2) Total long-term debt $ 26 $ 25 Maturities of long-term debt: (Millions of Dollars) 2022 $ 601 2023 1,150 2024 552 2025 1,102 2026 501 Deferred Financing Costs — Deferred financing costs of approximately $184 million and $167 million, net of amortization, are presented as a deduction from the carrying amount of long-term debt as of Dec. 31, 2021 and 2020, respectively. ATM Equity Offering — In November 2021, Xcel Energy Inc. filed a prospectus supplement under which it may sell up to $800 million of its common stock through an ATM program. As of Dec. 31, 2021, Xcel Energy Inc. had issued 5.33 million shares of common stock with net proceeds of $347 million through the ATM program. Capital Stock — Preferred stock authorized/outstanding: Preferred Stock Authorized (Shares) Par Value of Preferred Stock Preferred Stock Outstanding (Shares) 2021 and 2020 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, 2021 Common Stock Outstanding (Shares) as of Dec. 31, 2020 1,000,000,000 $ 2.50 544,025,269 537,438,394 Dividend and Other Capital-Related Restrictions — Xcel Energy depends on its utility 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, 2021: Equity to Total Equity to Total Capitalization Ratio Actual Low High 2021 NSP-Minnesota 47.2 % 57.6 % 52.9 % NSP-Wisconsin 52.5 N/A 52.8 SPS (a) 45.0 55.0 54.5 (a) Excludes short-term debt. (Amounts in Millions) Unrestricted Retained Earnings Total Capitalization Limit on Total Capitalization NSP-Minnesota $ 1,558 $ 14,321 $ 15,332 NSP-Wisconsin (a) 11 2,091 N/A SPS (b) 513 6,615 N/A (a) Cannot pay annual dividends in excess of forecasted levels 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. is not generally 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, 2021: (Millions of Dollars) Long-Term Debt Short-Term Debt NSP-Minnesota 52.8% of total capitalization (a) $ 2,300 (a) NSP-Wisconsin $ 150 150 SPS — 600 PSCo 700 (b) 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) PSCo filed for additional long-term debt authorization in December 2021.

Revenues

Revenues	12 Months Ended
	Dec. 31, 2021
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, 2021 (Millions of Dollars) Electric Natural Gas All Other Total Major revenue types Revenue from contracts with customers: Residential $ 3,194 $ 1,222 $ 45 $ 4,461 C&I 5,050 640 30 5,720 Other 127 — 7 134 Total retail 8,371 1,862 82 10,315 Wholesale 1,540 — — 1,540 Transmission 604 — — 604 Other 61 148 — 209 Total revenue from contracts with customers 10,576 2,010 82 12,668 Alternative revenue and other 629 122 12 763 Total revenues $ 11,205 $ 2,132 $ 94 $ 13,431 Year Ended Dec. 31, 2020 (Millions of Dollars) Electric Natural Gas All Other Total Major revenue types Revenue from contracts with customers: Residential $ 3,066 $ 975 $ 42 $ 4,083 C&I 4,596 462 27 5,085 Other 125 — 6 131 Total retail 7,787 1,437 75 9,299 Wholesale 759 — — 759 Transmission 579 — — 579 Other 73 137 — 210 Total revenue from contracts with customers 9,198 1,574 75 10,847 Alternative revenue and other 604 62 13 679 Total revenues $ 9,802 $ 1,636 $ 88 $ 11,526 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

Share-Based Compensation

Share-Based Compensation	12 Months Ended
	Dec. 31, 2021
Share-based Payment Arrangement [Abstract]
Share-Based Compensation	Incentive Plan Including Share-Based Compensation — Xcel Energy has an incentive plan which includes share-based payment elements, the Amended and Restated 2015 Omnibus Incentive Plan with 7.0 million equity shares authorized. Restricted Stock — The Amended and Restated 2015 Omnibus Incentive Plan allows 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 Shares of restricted stock granted at Dec. 31: (Shares in Thousands) 2021 2020 2019 Granted shares 2 1 13 Grant date fair value $ 61.54 $ 70.26 $ 53.46 Changes in nonvested restricted stock: (Shares in Thousands) Shares Weighted Average Nonvested restricted stock at Jan. 1, 2021 15 $ 56.68 Granted 2 61.54 Forfeited — 70.26 Vested (9) 49.71 Dividend equivalents — 66.73 Nonvested restricted stock at Dec. 31, 2021 8 67.26 Other Equity Awards — Xcel Energy‘s Board of Directors has granted equity awards under the Amended and Restated 2015 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 0.2 million, 0.2 million, and 0.3 million time-based equity shares subject only to service conditions were granted annually in 2021, 2020 and 2019, respectively. The performance conditions for a portion of the awards granted from 2019 to 2021 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% depending on achievement. Equity award units granted to employees (excluding restricted stock): (Units in Thousands) 2021 2020 2019 Granted units 421 411 483 Weighted average grant date fair value $ 66.03 $ 62.92 $ 49.67 Equity awards vested: (Units in Thousands, Fair Value in Millions) 2021 2020 2019 Vested Units 392 442 464 Total Fair Value $ 27 $ 29 $ 29 Changes in the nonvested portion of equity award units: (Units in Thousands) Units Weighted Average Nonvested Units at Jan. 1, 2021 780 $ 55.68 Granted 421 66.03 Forfeited (146) 61.76 Vested (392) 48.91 Dividend equivalents 32 58.00 Nonvested Units at Dec. 31, 2021 695 64.59 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) 2021 2020 2019 Granted units 31 33 29 Weighted average grant date fair value $ 68.15 $ 61.61 $ 58.44 Changes in stock equivalent units: (Units in Thousands) Units Weighted Average Stock equivalent units at Jan. 1, 2021 630 $ 36.28 Granted 31 68.15 Units distributed (73) 31.47 Dividend equivalents 16 66.98 Stock equivalent units at Dec. 31, 2021 604 39.27 TSR Liability Awards — Xcel Energy Inc.’s Board of Directors has granted TSR liability awards under the Amended and Restated 2015 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 TSR liability awards granted: (In Thousands) 2021 2020 2019 Awards granted 221 212 225 TSR liability awards settled: (Units In Thousands, Settlement Amount in Millions) 2021 2020 2019 Awards settled 446 476 466 Settlement amount (cash, common stock and deferred amounts) $ 27 $ 33 $ 25 TSR liability awards of $22 million were settled in cash in 2021. 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 0.2 million, 0.2 million, and 0.3 million of equity award units were granted in 2021, 2020, and 2019, respectively, 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) 2021 2020 2019 Compensation cost for share-based awards (a) $ 31 $ 73 $ 58 Tax benefit recognized in income 8 19 15 (a) Compensation costs for share-based payments are included in O&M expense. There was approximately $28 million in 2021 and $51 million in 2020 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, 2021
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. Diluted EPS was computed by dividing the earnings available to common shareholders by the diluted weighted average number of common shares outstanding. 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. • Liability awards subject to a performance condition; any portions settled in shares are included in common shares outstanding upon settlement. Common shares outstanding used in the basic and diluted EPS computation: (Shares in Millions) 2021 2020 2019 Basic 539 527 519 Diluted (a) 540 528 520 (a) Diluted common shares outstanding included common stock equivalents of 0.3 million, 1.1 million and 1.3 million shares for 2021, 2020 and 2019, respectively.

Fair Value of Financial Assets

Fair Value of Financial Assets and Liabilities	12 Months Ended
	Dec. 31, 2021
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. • 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 fund 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 an 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. 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 investment targets by asset class for the 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 $1.3 billion and $981 million as of Dec. 31, 2021 and 2020, respectively, and unrealized losses were $7 million and $5 million as of Dec. 31, 2021 and 2020, respectively. Non-derivative instruments with recurring fair value measurements: Dec. 31, 2021 Fair Value (Millions of Dollars) Cost Level 1 Level 2 Level 3 NAV Total Nuclear decommissioning fund (a) Cash equivalents $ 64 $ 64 $ — $ — $ — $ 64 Commingled funds 856 — — — 1,294 1,294 Debt securities 631 — 666 9 — 675 Equity securities 411 1,222 1 — — 1,223 Total $ 1,962 $ 1,286 $ 667 $ 9 $ 1,294 $ 3,256 (a) Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $208 million of equity investments in unconsolidated subsidiaries and $164 million of rabbi trust assets and miscellaneous investments. Dec. 31, 2020 Fair Value (Millions of Dollars) Cost Level 1 Level 2 Level 3 NAV Total Nuclear decommissioning fund (a) Cash equivalents $ 40 $ 40 $ — $ — $ — $ 40 Commingled funds 787 — — — 1,041 1,041 Debt securities 528 — 572 13 — 585 Equity securities 446 1,109 2 — — 1,111 Total $ 1,801 $ 1,149 $ 574 $ 13 $ 1,041 $ 2,777 (a) Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $165 million of equity investments in unconsolidated subsidiaries and $154 million of rabbi trust assets and miscellaneous investments. For the years ended Dec. 31, 2021 and 2020, 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, 2021: 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 $ 4 $ 149 $ 208 $ 314 $ 675 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, 2021 Fair Value (Millions of Dollars) Cost Level 1 Level 2 Level 3 Total Rabbi Trusts (a) Cash equivalents $ 20 $ 20 $ — $ — $ 20 Mutual funds 75 89 — — 89 Total $ 95 $ 109 $ — $ — $ 109 (a) Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet. Dec. 31, 2020 Fair Value (Millions of Dollars) Cost Level 1 Level 2 Level 3 Total Rabbi Trusts (a) Cash equivalents $ 32 $ 32 $ — $ — $ 32 Mutual funds 60 70 — — 70 Total $ 92 $ 102 $ — $ — $ 102 (a) Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet. Derivative Instruments Fair Value Measurements Xcel Energy enters into derivative instruments, including forward contracts, futures, swaps and options, for trading purposes and to manage risk in connection with changes in interest rates, utility commodity prices and vehicle fuel prices. Interest Rate Derivatives — Xcel Energy enters into various instruments that effectively fix the 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, with changes in fair value prior to settlement recorded as other comprehensive income. As of Dec. 31, 2021, accumulated other comprehensive loss related to settled 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, 2021, Xcel Energy had no unsettled interest rate derivatives. 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. 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. The classification of unrealized losses or gains on these instruments as a regulatory asset or liability, if applicable, is based on approved regulatory recovery mechanisms. As of Dec. 31, 2021, Xcel Energy had no commodity contracts designated as cash flow hedges. 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 amounts of commodity forwards, options and FTRs: (Amounts in Millions) (a)(b) Dec. 31, 2021 Dec. 31, 2020 MWh of electricity 80 87 MMBtu of natural gas 156 175 (a) Not reflective of net positions in the underlying commodities. (b) Notional amounts for options 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 on 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, 2021, six of Xcel Energy’s 10 most significant counterparties for these activities, comprising $83 million or 38% of this credit exposure, had investment grade credit ratings from S&P, Moody’s Investor Services or Fitch Ratings. Three of the 10 most significant counterparties, comprising $44 million or 20% 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. One of these significant counterparties, comprising $38 million or 18% of this credit exposure, had credit quality less than investment grade, based on internal analysis. Eight of these significant counterparties are municipal or cooperative electric entities, RTOs or other utilities. Qualifying Cash Flow Hedges — Financial impact of qualifying interest rate 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) 2021 2020 2019 Accumulated other comprehensive loss related to cash flow hedges at Jan. 1 $ (85) $ (80) $ (60) After-tax net unrealized gains (losses) related to derivatives accounted for as hedges 4 (10) (23) After-tax net realized losses on derivative transactions reclassified into earnings 6 5 3 Accumulated other comprehensive loss related to cash flow hedges at Dec. 31 $ (75) $ (85) $ (80) Impact of derivative activity: Pre-Tax Fair Value (Millions of Dollars) Accumulated Regulatory Year Ended Dec. 31, 2021 Derivatives designated as cash flow hedges Interest rate $ 5 $ — Total $ 5 $ — Other derivative instruments Electric commodity $ — $ 32 Natural gas commodity — (4) Total $ — $ 28 Year Ended Dec. 31, 2020 Interest rate $ (13) $ — Total $ (13) $ — Other derivative instruments Electric commodity $ — $ (5) Natural gas commodity — (13) Total $ — $ (18) Year Ended Dec. 31, 2019 Interest rate $ (30) $ — Total $ (30) $ — Other derivative instruments Electric commodity $ — $ 8 Natural gas commodity — (9) Total $ — $ (1) Pre-Tax (Gains) Losses Pre-Tax Gains (Losses) Recognized During the Period in Income (Millions of Dollars) Accumulated Regulatory Year Ended Dec. 31, 2021 Derivatives designated as cash flow hedges Interest rate $ 8 (a) $ — $ — Total $ 8 $ — $ — Other derivative instruments Commodity trading $ — $ — $ 63 (b) Electric commodity — (23) (c) — Natural gas commodity — 5 (d) (22) (d) Total $ — $ (18) $ 41 Year Ended Dec. 31, 2020 Derivatives designated as cash flow hedges Interest rate $ 7 (a) $ — $ — Total $ 7 $ — $ — Other derivative instruments Commodity trading $ — $ — $ (1) (b) Electric commodity — (3) (c) — Natural gas commodity — 10 (d) (13) (d) Total $ — $ 7 $ (14) 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) (a) Recorded to interest charges. (b) 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) 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) Settlement losses related to natural gas operations are recorded to cost of natural gas sold and transported. These losses are subject to cost-recovery mechanisms and reclassified out of income to a regulatory asset, as appropriate. Xcel Energy had no derivative instruments designated as fair value hedges during the years ended Dec. 31, 2021, 2020 and 2019. Credit Related Contingent Features — Contract provisions for derivative instruments that the utility subsidiaries enter, including those accounted for as normal purchase and 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. As of Dec. 31, 2021 and 2020, there were $3 million and $4 million of derivative instruments in a liability position with such underlying contract provisions, respectively. Certain contracts also contain cross default provisions that may require the posting of collateral or settlement of the contracts if there was a failure under the other financing arrangements related to payment terms or other covenants. As of Dec. 31, 2021 and 2020, there were approximately $64 million and $60 million of derivative instruments in a liability position with such underlying contract provisions, respectively. Certain derivative instruments are also subject to contract provisions that contain adequate assurance clauses. 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, 2021 and 2020. Recurring Fair Value Measurements — Derivative assets and liabilities measured at fair value on a recurring basis were as follows: Dec. 31, 2021 Dec. 31, 2020 Fair Value Fair Value Total Netting (a) Total Fair Value Fair Value Total Netting (a) Total (Millions of Dollars) Level 1 Level 2 Level 3 Level 1 Level 2 Level 3 Current derivative assets Other derivative instruments: Commodity trading $ 22 $ 137 $ 21 $ 180 $ (134) $ 46 $ 2 $ 67 $ 1 $ 70 $ (52) $ 18 Electric commodity — — 57 57 (1) 56 — — 20 20 (1) 19 Natural gas commodity — 18 — 18 — 18 — 9 — 9 — 9 Total current derivative assets $ 22 $ 155 $ 78 $ 255 $ (135) 120 $ 2 $ 76 $ 21 $ 99 $ (53) 46 PPAs (b) 3 3 Current derivative instruments $ 123 $ 49 Noncurrent derivative assets Other derivative instruments: Commodity trading $ 16 $ 63 $ 89 $ 168 $ (107) $ 61 $ 8 $ 66 $ 8 $ 82 $ (62) $ 20 Total noncurrent derivative assets $ 16 $ 63 $ 89 $ 168 $ (107) 61 $ 8 $ 66 $ 8 $ 82 $ (62) 20 PPAs (b) 6 10 Noncurrent derivative instruments $ 67 $ 30 Dec. 31, 2021 Dec. 31, 2020 Fair Value Fair Value Total Netting (a) Total Fair Value Fair Value Total Netting (a) Total (Millions of Dollars) Level 1 Level 2 Level 3 Level 1 Level 2 Level 3 Current derivative liabilities Other derivative instruments: Commodity trading $ 19 $ 148 $ 20 $ 187 $ (143) $ 44 $ 4 $ 64 $ 17 $ 85 $ (58) $ 27 Electric commodity — — 1 1 (1) — — — 1 1 (1) — Natural gas commodity — 8 — 8 — 8 — 9 — 9 — 9 Total current derivative liabilities $ 19 $ 156 $ 21 $ 196 $ (144) 52 $ 4 $ 73 $ 18 $ 95 $ (59) 36 PPAs (b) 17 17 Current derivative instruments $ 69 $ 53 Noncurrent derivative liabilities Other derivative instruments: Commodity trading $ 18 $ 48 $ 127 $ 193 $ (128) $ 65 $ 3 $ 58 $ 60 $ 121 $ (47) $ 74 Total noncurrent derivative liabilities $ 18 $ 48 $ 127 $ 193 $ (128) 65 $ 3 $ 58 $ 60 $ 121 $ (47) 74 PPAs (b) 40 57 Noncurrent derivative instruments $ 105 $ 131 (a) Xcel Energy nets derivative instruments and related collateral on its consolidated balance sheets 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, 2021 and 2020. At Dec. 31, 2021, derivative assets and liabilities include no obligations to return cash collateral. At Dec. 31, 2020, derivative assets and liabilities include $15 million of obligations to return cash collateral. At Dec. 31, 2021 and 2020, derivative assets and liabilities include rights to reclaim cash collateral of $30 million and $6 million, respectively. Counterparty netting amounts presented exclude 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, contracts are no longer adjusted to fair value and the previous carrying value of these contracts is being 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) 2021 2020 2019 Balance at Jan. 1 $ (49) $ 4 $ 29 Purchases 65 51 44 Settlements (158) (73) (64) Net transactions recorded during the period: Gains (losses) recognized in earnings (a) 49 (39) (8) Net gains recognized as regulatory assets and liabilities 112 8 3 Balance at Dec. 31 $ 19 $ (49) $ 4 (a) Level 3 losses recognized in earnings are subject to offsetting gains of derivative instruments categorized as levels 1 and 2 in the income statement. Fair Value of Long-Term Debt As of Dec. 31, other financial instruments for which the carrying amount did not equal fair value: 2021 2020 (Millions of Dollars) Carrying Amount Fair Value Carrying Amount Fair Value Long-term debt, including current portion $ 22,380 $ 25,232 $ 20,066 $ 24,412 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, 2021 and 2020, 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, 2021
Retirement Benefits [Abstract]
Pension and Other Postretirement Benefits Disclosure [Text Block]	11. Benefit Plans and Other Postretirement Benefits Pension and Postretirement Health Care Benefits Xcel Energy has several noncontributory, qualified, defined benefit pension plans that cover almost all employees. All newly hired or rehired employees participate under the Cash Balance formula, which is based on pay credits using a percentage of annual eligible pay and annual interest credits. The average annual interest crediting rates for these plans was 2.03, 1.89 and 2.82% in 2021, 2020, and 2019, respectively. Some employees may participate under legacy formulas such as the traditional final average pay or pension equity. 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 who participated 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, 2021 and 2020 were $43 million and $43 million, respectively. Xcel Energy recognized net benefit cost for the SERP and nonqualified plans of $4 million in 2021 and $6 million in 2020. Xcel Energy’s investment-return assumption considers the expected long-term performance for each of the asset classes in its pension and postretirement health care portfolio. Xcel Energy considers the historical returns achieved by its asset portfolios over long time periods, 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 2021 were above the assumed level of 6.49%. • Investment returns in 2020 were above the assumed level of 6.87%. • Investment returns in 2019 were above the assumed level of 6.87%. • In 2022, expected investment-return assumption is 6.49%. 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 consider many factors and generally 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, 2021 (a) Dec. 31, 2020 (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 $ 133 $ — $ — $ — $ 133 $ 209 $ — $ — $ — $ 209 Commingled funds 1,324 — — 1,143 2,467 1,462 — — 1,115 2,577 Debt securities — 959 5 — 964 — 714 4 — 718 Equity securities 67 — — — 67 77 — — — 77 Other — 7 — 32 39 13 5 — — 18 Total $ 1,524 $ 966 $ 5 $ 1,175 $ 3,670 $ 1,761 $ 719 $ 4 $ 1,115 $ 3,599 (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, 2021 (a) Dec. 31, 2020 (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 $ 28 $ — $ — $ — $ 28 $ 27 $ — $ — $ — $ 27 Insurance contracts — 52 — — 52 — 50 — — 50 Commingled funds 64 — — 77 141 72 — — 69 141 Debt securities — 218 1 — 219 — 232 — — 232 Other — 2 — — 2 — 2 — — 2 Total $ 92 $ 272 $ 1 $ 77 $ 442 $ 99 $ 284 $ — $ 69 $ 452 (a) See Note 10 for further information on fair value measurement inputs and methods. No assets were transferred in or out of Level 3 for 2021 or 2020. Funded Status — Benefit obligations for both pension and postretirement plans decreased from Dec. 31, 2020 to Dec. 31, 2021, due primarily to benefit payments and increases in discount rates used in actuarial valuations. 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) 2021 2020 2021 2020 Change in Benefit Obligation: Obligation at Jan. 1 $ 3,964 $ 3,701 $ 574 $ 547 Service cost 104 95 2 1 Interest cost 104 125 15 18 Plan amendments 5 — — — Actuarial (gain) loss (94) 328 (41) 50 Plan participants’ contributions — — 8 8 Medicare subsidy reimbursements — — 2 1 Benefit payments (a) (365) (285) (49) (51) Obligation at Dec. 31 $ 3,718 $ 3,964 $ 511 $ 574 Change in Fair Value of Plan Assets: Fair value of plan assets at Jan. 1 $ 3,599 $ 3,184 $ 452 $ 449 Actual return on plan assets 305 550 16 35 Employer contributions 131 150 15 11 Plan participants’ contributions — — 8 8 Benefit payments (365) (285) (49) (51) Fair value of plan assets at Dec. 31 $ 3,670 $ 3,599 $ 442 $ 452 Funded status of plans at Dec. 31 $ (48) $ (365) $ (69) $ (122) Amounts recognized in the Consolidated Balance Sheet at Dec. 31: Noncurrent assets $ 19 $ — $ 33 $ 6 Current liabilities — — (4) (7) Noncurrent liabilities (67) (365) (98) (121) Net amounts recognized $ (48) $ (365) $ (69) $ (122) (a) Includes approximately $197 million in 2021 and $0 million in 2020 of lump-sum benefit payments used in the determination of a settlement charge. Pension Benefits Postretirement Benefits Significant Assumptions Used to Measure Benefit Obligations: 2021 2020 2021 2020 Discount rate for year-end valuation 3.08 % 2.71 % 3.09 % 2.65 % Expected average long-term increase in compensation level 3.75 3.75 N/A N/A Mortality table PRI-2012 PRI-2012 PRI-2012 PRI-2012 Health care costs trend rate — initial: Pre-65 N/A N/A 5.30 % 5.50 % Health care costs trend rate — initial: Post-65 N/A N/A 4.90 % 5.00 % 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 4 5 Accumulated benefit obligation for the pension plan was $3,469 million and $3,693 million as of Dec. 31, 2021 and 2020, respectively. Net Periodic Benefit Cost (Credit) — Net periodic benefit cost (credit), other than the service cost component, is included in other income (expense) 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) 2021 2020 2019 2021 2020 2019 Service cost $ 104 $ 95 $ 86 $ 2 $ 1 $ 2 Interest cost 104 125 145 15 18 22 Expected return on plan assets (206) (208) (203) (18) (19) (21) Amortization of prior service credit (1) (4) (5) (8) (8) (10) Amortization of net loss 107 100 87 5 4 5 Settlement charge (a) 59 — 6 — — — Net periodic pension cost (credit) 167 108 116 (4) (4) (2) Effects of regulation (46) 9 (1) 2 3 1 Net benefit cost (credit) recognized for financial reporting $ 121 $ 117 $ 115 $ (2) $ (1) $ (1) Significant Assumptions Used to Measure Costs: Discount rate 2.71 % 3.49 % 4.31 % 2.65 % 3.47 % 4.32 % Expected average long-term increase in compensation level 3.75 3.75 3.75 — — — Expected average long-term rate of return on assets 6.49 6.87 6.87 4.10 4.50 4.50 (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 2021 and 2019, as a result of lump-sum distributions during each plan year, Xcel Energy recorded a total pension settlement charge of $59 million and $6 million, respectively, the majority of which was not recognized due to the effects of regulation. A total of $7 million and $1 million was recorded in the consolidated statements of income in 2021 and 2019, respectively. There were no settlement charges recorded for the qualified pension plans in 2020. Pension Benefits Postretirement Benefits (Millions of Dollars) 2021 2020 2021 2020 Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost: Net loss $ 978 $ 1,333 $ 81 $ 126 Prior service credit (9) (11) (7) (15) Total $ 969 $ 1,322 $ 74 $ 111 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 $ 74 $ 82 $ — $ — Noncurrent regulatory assets 846 1,181 90 125 Current regulatory liabilities — — (1) (1) Noncurrent regulatory liabilities — — (19) (18) Deferred income taxes 13 15 1 1 Net-of-tax accumulated other comprehensive income 36 44 3 4 Total $ 969 $ 1,322 $ 74 $ 111 Measurement date Dec. 31, 2021 Dec. 31, 2020 Dec. 31, 2021 Dec. 31, 2020 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 2019 - 2022 to meet minimum funding requirements. Voluntary and required pension funding contributions: • $50 million in January 2022. • $131 million in 2021. • $150 million in 2020. • $154 million in 2019. 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: • Expects to contribute approximately $9 million during 2022. • $15 million during 2021. • $11 million during 2020. • $15 million during 2019. Targeted asset allocations: Pension Benefits Postretirement Benefits 2021 2020 2021 2020 Domestic and international equity securities 33 % 35 % 15 % 15 % Long-duration fixed income securities 37 35 — — Short-to-intermediate fixed income securities 11 13 71 72 Alternative investments 17 15 8 9 Cash 2 2 6 4 Total 100 % 100 % 100 % 100 % The asset allocations above reflect target allocations approved in the calendar year to take effect in the subsequent year. Plan Amendments — 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 significant plan amendments made in 2020 which affected the postretirement benefit obligation. In 2021, Xcel Energy amended the Xcel Energy Pension Plan and Xcel Energy Inc. Nonbargaining Pension Plan (South) 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. Projected Benefit Payments Xcel Energy’s projected benefit payments: (Millions of Dollars) Projected Gross Projected Expected Net Projected 2022 $ 323 $ 42 $ 2 $ 40 2023 257 41 2 39 2024 253 40 2 38 2025 251 38 2 36 2026 245 37 2 35 2027-2031 1,156 165 13 152 Defined Contribution Plans Xcel Energy maintains 401(k) and other defined contribution plans that cover most employees. Total expense to these plans was approximately $43 million in 2021, $42 million in 2020 and $39 million in 2019. 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, 2021
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	Legal Xcel Energy is involved in various litigation matters in the ordinary course of business. The assessment of whether a loss is probable or is a reasonable possibility, and whether the loss or a range of loss is estimable, often involves a series of complex judgments about future events. Management maintains accruals for losses probable of being incurred and subject to reasonable estimation. Management is sometimes unable to estimate an amount or range of a reasonably possible loss in certain situations, including but not limited to when (1) the damages sought are indeterminate, (2) the proceedings are in the early stages, or (3) the matters involve novel or unsettled legal theories. In such cases, there is considerable uncertainty regarding the timing or ultimate resolution, including a possible eventual loss. For current proceedings not specifically reported herein, management does not anticipate that the ultimate liabilities, if any, would have a material effect on Xcel Energy’s consolidated financial statements. Legal fees are generally 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. One case remains active which includes a multi-district litigation matter consisting of a Wisconsin purported class (Arandell Corp.). Arandell Corp. — The trial has been vacated and will be rescheduled after the court rules on the pending motions for reconsideration and for class certification. Xcel Energy has concluded that a loss is remote for the remaining lawsuit. Breckenridge/Colorado — In February 2019, the MDL panel remanded Breckenridge back to the U.S. District Court in Colorado. Settlement of approximately $3 million was reached in February 2021. In July 2021, the settlement was approved. Rate Matters and Other Xcel Energy’s operating subsidiaries are involved in various regulatory proceedings arising in the ordinary course of business. Until resolution, typically in the form of a rate order, uncertainties may exist regarding the ultimate rate treatment for certain activities and transactions. Amounts have been recognized for probable and reasonably estimable losses that may result. Unless otherwise disclosed, any reasonably possible range of loss in excess of any recognized amount is not expected to have a material effect on the consolidated financial statements. Minnesota Winter Storm Uri Costs — In its Minnesota jurisdiction, NSP-Minnesota is participating in a contested case regarding the prudency of incremental natural gas costs incurred during Winter Storm Uri. Other parties to the case have recommended significant cost disallowances, and while ultimate resolution of the matter is uncertain, it is reasonably possible that the MPUC could disallow certain deferred costs, resulting in earnings losses. The OAG recommended the MPUC deny recovery of up to $179 million, the largest recommendation among the intervenor positions. NSP-Minnesota strongly disagrees with the recommendations of the DOC, OAG and CUB, and believes that it acted prudently and according to MPUC approved procedures for the best interest of its customers and stakeholders. NSP-Minnesota filed rebuttal testimony in January 2022 detailing its position that the disallowances recommended by other parties lack any merit in the prudency review given the pertinent facts regarding NSP-Minnesota’s actions before, during and after the storm event. An MPUC decision is expected in the summer of 2022. Sherco — In 2018, NSP-Minnesota and Southern Minnesota Municipal Power Agency (Co-owner of Sherco Unit 3) reached a settlement with GE related to a 2011 incident, which damaged the turbine at Sherco Unit 3 and resulted in an extended outage for repair. NSP-Minnesota notified the MPUC of its proposal to refund settlement proceeds to customers through the FCA. In March 2019, the MPUC approved NSP-Minnesota’s settlement refund proposal. Additionally, the MPUC decided to withhold any decision as to NSP-Minnesota’s prudence in connection with the incident at Sherco Unit 3 until after conclusion of an appeal pending between GE and NSP-Minnesota’s insurers. In February 2020, the Minnesota Court of Appeals affirmed the district court’s judgment in favor of GE. In March 2020, NSP-Minnesota’s insurers filed a petition seeking additional review by the Minnesota Supreme Court. In April 2020, the Minnesota Supreme Court denied the insurers’ petition for further review, ending the litigation. In January 2021, the OAG and DOC recommended that NSP-Minnesota refund approximately $17 million of replacement power costs previously recovered through the FCA. NSP-Minnesota subsequently filed its response, asserting that it acted prudently in connection with the Sherco Unit 3 outage, the MPUC has previously disallowed $22 million of related costs and no additional refund or disallowance is appropriate. A final decision by the MPUC is pending. A loss related to this matter is deemed remote. Westmoreland Arbitration — In November 2014, insurers of the Westmoreland Coal Company filed an arbitration demand against NSP-Minnesota, Southern Minnesota Municipal Power Agency and Western Fuels Association, seeking recovery of alleged $36 million of business losses due to a turbine failure at Sherco Unit 3. The Westmoreland insurers claim NSP-Minnesota’s invocation of the force majeure clause to stop the supply of coal was improper because the incident was allegedly caused by NSP-Minnesota’s failure to conform to industry maintenance standards. NSP-Minnesota denies the claims asserted by the Westmoreland insurers and believes it properly stopped the supply of coal based upon the force majeure provision . A final hearing has been scheduled for October 2022. The parties are also required to participate in mediation, which has been scheduled for the first quarter of 2022. At this stage of the proceeding, a reasonable estimate of damages or range of damages cannot be determined. MISO ROE Complaints — In November 2013 and February 2015, customer groups filed two ROE complaints against MISO TOs, which includes NSP-Minnesota and NSP-Wisconsin. The first complaint requested a reduction in base ROE transmission formula rates from 12.38% to 9.15% for the time period of Nov. 12, 2013 to Feb. 11, 2015, and removal of ROE adders (including those for RTO membership). The second complaint requested, for a subsequent time period, a base ROE reduction from 12.38% to 8.67%. In September 2016, the FERC issued an order (Opinion No. 551) granting a 10.32% base ROE 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 Opinion No. 551. In November 2019, the FERC issued an order (Opinion No. 569), which set the MISO base ROE at 9.88%, effective Sept. 28, 2016 and for the first complaint period. The FERC also dismissed the second complaint. In December 2019, MISO TOs filed a request for rehearing regarding the new ROE methodology announced in Opinion No. 569. Customers also filed requests for rehearing claiming, among other points, that the FERC erred by dismissing the second complaint without refunds. In May 2020, the FERC issued an order (Opinion No. 569-A) which granted rehearing in part to Opinion 569 and further refined the FERC’s ROE methodology, most significantly to incorporate the risk premium model (in addition to the discounted cash flow and capital asset pricing models), resulting in a new base ROE of 10.02%, effective Sept. 28, 2016 and for the first complaint period. The FERC also affirmed its decision in Opinion No. 569 to dismiss the second complaint. In November 2020, the FERC issued an order (Opinion No. 569-B) in response to rehearing requests. The FERC corrected certain inputs to its ROE calculation model, did not change the ROE effective Sept. 28, 2016, and for the first MISO complaint period and upheld its decision to deny refunds for the second complaint period. NSP-Minnesota has recognized a liability for its best estimate of final refunds to customers. Each 10 basis point reduction in ROE for the first complaint period, second complaint period and subsequent period relative to amounts accrued would reduce Xcel Energy’s net income by $1 million, $1 million and $2 million, respectively. The MISO TOs and various parties have filed petitions for review of Opinion Nos. 569, 569-A and 569-B at the D.C. Circuit. Oral arguments were held in late 2021 and a decision is expected by the end of the third quarter of 2022. SPP OATT Upgrade Costs — Costs of transmission upgrades may be recovered from other SPP customers whose transmission service depends on capacity enabled by the upgrade under the SPP OATT. 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 these 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 March 2020, SPP and Oklahoma Gas & Electric separately filed petitions for review of the FERC’s orders at the D.C. Circuit. In August 2021, the D.C Circuit issued a decision denying these appeals and upholding the FERC’s orders. Refunds received by SPS are expected to be given back to SPS customers through future rates. The timing of these refunds is uncertain. In October 2017, SPS filed a separate related complaint asserting SPP assessed upgrade charges to SPS in violation of the SPP OATT. In March 2018, the FERC issued an order denying the SPS complaint. SPS filed a request for rehearing in April 2018. The FERC issued a tolling order granting a rehearing for further consideration in May 2018. If SPS’ complaint results in additional charges or refunds, SPS will seek to recover or refund the amount through future SPS customer rates. In October 2020, SPS filed a petition for review of the FERC’s March 2018 order and May 2018 tolling order at the D.C. Circuit. FERC has asked that this appeal be stayed until early 2022, in order to provide FERC with time to issue an order on SPS’ April 2018 rehearing request. FERC’s order is expected in the first quarter of 2022. The D.C. Circuit appeal may resume after that FERC order is issued. Wind Operating Commitments — PUCT and NMPRC orders related to the Hale and Sagamore wind projects included certain operating and savings minimums. In general, annual generation must exceed a net capacity factor of 48%. If annual generation is below the guaranteed level, SPS would be obligated to refund an amount equal to foregone PTCs and fuel savings. Additionally, retail customer savings must exceed project costs included in base rates over the first ten years of operations. SPS would be required to refund excess costs, if any, after ten years of operations. As of Dec. 31, 2021, the full-year net capacity factor was 48.4%, resulting in no refund liability for 2021. Contract Termination — SPS and LP&L are parties to a 25-year, 170 MW partial requirements contract. In May 2021, SPS and LP&L finalized a settlement which would terminate the contract upon LP&L’s move from the SPP to the Electric Reliability Council of Texas (expected in 2023). The settlement agreement requires LP&L to pay SPS $78 million (lump sum or annual installments), to the benefit of SPS’ remaining customers. LP&L would remain obligated to pay for SPP transmission charges associated with LP&L’s load in SPP. The settlement agreement is subject to approval by the PUCT and FERC. Comanche Unit 3 Litigation — In February 2021, the joint owners of Comanche Unit 3 (CORE Electric Cooperative, formerly known as Intermountain Rural Electrical Association, and Holy Cross Electric) served PSCo with a notice of claim related to Comanche Unit 3's operation and availability. In September 2021, CORE Electric Cooperative filed a lawsuit in Colorado state court seeking an unspecified amount of damages. CORE Electric Cooperative alleges PSCo breached ownership agreement terms by failing to operate Comanche Unit 3 in accordance with prudent utility practices. PSCo filed a Motion to Dismiss several of CORE’s claims. In January 2022 the Court granted PSCo’s Motion to Dismiss CORE’s claim for damages for replacement power costs, claims for unjust enrichment and declaratory judgment. CORE’s claims for breach of contract, breach of the duty of good faith and fair dealing, and waste remain pending. In November 2021, PSCo resolved all differences with Holy Cross Electric related to their claim. 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. Historical MGP, Landfill and Disposal Sites Xcel Energy is currently investigating, remediating or performing post-closure actions at 16 historical MGP, landfill or other disposal sites across its service territories, excluding sites that are being addressed under current coal ash regulations (see below). Xcel Energy has recognized its best estimate of costs/liabilities from final resolution of these issues; however, the outcome and timing are 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 regulations 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 eight regulated ash units in operation. Xcel Energy is conducting groundwater sampling and monitoring and implementing assessment of corrective measures at certain CCR landfills and surface impoundments. In NSP-Minnesota, no results above the groundwater protection standards in the rule were identified. In PSCo, increases above background concentrations were detected at four locations. Based on further assessments, PSCo is evaluating options for corrective action at two locations, one of which indicates potential offsite impacts to groundwater. The total cost is uncertain, but could be up to $35 million. PSCo is continuing to assess the financial and regulatory impacts. In August 2020, the EPA published its final rule to implement closure by April 2021 for all CCR impoundments affected by the August 2018 D.C. Circuit ruling. This final rule required Xcel Energy to expedite closure plans for two impoundments. In October 2020, NSP-Minnesota completed construction and placed in service a new impoundment to replace the clay lined impoundment. With the new ash pond in service, NSP-Minnesota has initiated closure activities for the existing ash pond at an estimated cost of $4 million. NSP-Minnesota has five PSCo also built an alternative collection and treatment system to remove the Comanche Station bottom ash pond from service. The total cost of the alternate treatment system is approximately $25 million. PSCo worked expeditiously to meet the April 11, 2021 deadline, but was not able to remove the pond from service until June 18, 2021. PSCo expects to negotiate a compliance order with the EPA addressing the closure deadline as well as other potential issues. PSCo will also now proceed with closure of the pond, at an estimated cost of $3 million. Closure costs for existing impoundments are included in the calculation of the ARO. Federal CWA Waters of the U.S. Rule — Xcel Energy is monitoring ongoing changes to the definition of Waters of the U.S. under the CWA. Regardless of which definition is applicable in the states in which we operate, Xcel Energy does not anticipate that compliance costs will be material. 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 October 2020, the EPA published a final rule revising the regulations. The retirement of units affected by the final ELG rule is subject to regulatory approval. The exact total cost of ELG compliance is therefore uncertain but Xcel Energy does not anticipate that compliance costs will be material. 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 future cost for complying with impingement and entrainment requirements is approximately $39 million, to be incurred between 2022 and 2028. Xcel Energy believes six NSP-Minnesota plants and two NSP-Wisconsin plants could be required 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 $192 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 regional haze first planning period requirements developed by Minnesota and Colorado were approved by the EPA in 2012 and implemented by 2014 and 2016, respectively. Texas’ first regional haze plan has undergone federal review. All states are now subject to a second round of regional haze planning/rulemaking, focusing on additional reductions to meet reasonable progress requirements. Any additional impacts to Xcel Energy facilities are expected to be minimal. 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 D.C. Circuit 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. 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. The EPA reaffirmed the rule in August 2020 with minor changes. The 2020 EPA Action has been challenged. All pending actions could be consolidated and may proceed in the Fifth Circuit or the D.C. Circuit, where a parallel challenge has been filed. The timing of final decisions is unclear. 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; compliance would have been 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 referenced above are needed at Tolk under the “reasonable progress” requirements. As states are now proceeding with the second regional haze planning period, the EPA may choose not to act 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 one exception. The EPA issued final designations, which found the area near the SPS Harrington plant as “unclassifiable.” The area near the Harrington plant was monitored for the three years ending in 2019 and the monitoring showed the area to be exceeding the standard. To address this issue, SPS negotiated an order with the TCEQ providing for the end of coal combustion and the conversion of the Harrington plant to a natural gas fueled facility by Jan. 1, 2025. Xcel Energy believes compliance costs or the costs of alternative cost-effective generation will be recoverable through regulatory mechanisms and therefore does not expect a material impact on results of operations, financial condition or cash flows. 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 $3.3 billion and $2.8 billion for 2021 and 2020, respectively. Xcel Energy’s AROs were as follows: (Millions Jan. 1, 2021 Amounts Incurred (a) Accretion Cash Flow Revisions (b) Dec. 31, 2021 (c) Electric Nuclear $ 1,957 $ — $ 99 $ — $ 2,056 Wind 360 101 17 — 478 Steam, hydro and other production 264 6 10 8 288 Distribution 46 — 1 — 47 Natural gas Transmission and distribution 252 — 10 9 271 Miscellaneous 3 — — 5 8 Common Miscellaneous 1 — — — 1 Non-utility Miscellaneous 1 — 1 — 2 Total liability $ 2,884 $ 107 $ 138 $ 22 $ 3,151 (a) Amounts incurred related to the wind farms placed in service in 2021 for NSP-Minnesota (Blazing Star 2, Mower and Freeborn) and removal of a utility scale battery asset in NSP-Minnesota. (b) In 2021, AROs were revised for changes in timing and estimates of cash flows. Revisions in steam, hydro and other production AROs were primarily related to changes in cost estimates for remediation of ash containment facilities. Changes in gas transmission and distribution AROs were primarily related to changes in labor rates coupled with increased gas line mileage and number of services. (c) There were no ARO amounts settled in 2021. (Millions Jan. 1, 2020 Amounts Incurred (a) Amounts Settled (b) Accretion Cash Flow Revisions (c) Dec. 31, 2020 Electric Nuclear $ 2,068 $ — $ — $ 105 $ (216) $ 1,957 Steam, hydro and other production 202 — (5) 9 58 264 Wind 146 149 (3) 8 60 360 Distribution 44 — — 2 — 46 Natural gas Transmission and distribution 236 — — 10 6 252 Miscellaneous 3 — — — — 3 Common Miscellaneous 1 — — — — 1 Non-utility Miscellaneous 1 — — — — 1 Total liability $ 2,701 $ 149 $ (8) $ 134 $ (92) $ 2,884 (a) Amounts incurred related to the wind farms placed in service in 2020 for NSP-Minnesota (Blazing Star 1, Crowned Ridge 2, Jeffers and Community Wind North), PSCo (Cheyenne Ridge) and SPS (Sagamore). (b) Amounts settled primarily related to closure of certain ash containment facilities, removal of wind facilities and asbestos abatement projects. (c) In 2020, AROs were revised for changes in timing and estimates of cash flows. Revisions in the nuclear AROs were driven by reductions in spent fuel cooling time requirements in the nuclear triennial filing coupled with decreasing interest rates. Changes in wind AROs were driven by new dismantling studies. Revisions in steam, hydro and other production AROs were primarily related to changes in cost estimates for remediation of ash containment facilities. 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, 2021. Therefore, an ARO was not recorded for these facilities. Nuclear Nuclear Insurance — NSP-Minnesota’s public liability for claims from any nuclear incident is limited to $13.5 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 $13.0 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 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. NSP-Minnesota purchases insurance for property damage and site decontamination cleanup costs from NEIL and EMANI. The coverage limits are $2.8 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 $11 million for business interruption insurance and $33 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 47 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. A CON for additional storage at the Monticello site has been filed with the MPUC, to support possible life extension. NSP-Minnesota expects a decision by year-end 2023. 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 $3.3 billion of assets held in external decommissioning trusts at Dec. 31, 2021. 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) 2021 2020 Estimated decommissioning cost obligation from most recently approved study (in 2014 dollars) $ 3,012 $ 3,012 Effect of escalating costs 1,006 844 Estimated decommissioning cost obligation (in current dollars) 4,018 3,856 Effect of escalating costs to payment date 7,187 7,349 Estimated future decommissioning costs (undiscounted) 11,205 11,205 Effect of discounting obligation (using average risk-free interest rate of 1.96% and 1.64% for 2021 and 2020, respectively) (4,651) (4,181) Discounted decommissioning cost obligation $ 6,554 $ 7,024 Assets held in external decommissioning trust $ 3,256 $ 2,777 Underfunding of external decommissioning fund compared to the discounted decommissioning obligation 3,298 4,247 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) 2021 2020 Discounted decommissioning cost obligation - regulated basis $ 6,554 $ 7,024 Differences in discount rate and market risk premium (2,209) (2,628) O&M costs not included for GAAP (1,584) (1,734) ARO differences between 2020 and 2014 cost studies (705) (705) Nuclear production decommissioning ARO - GAAP $ 2,056 $ 1,957 Decommissioning expenses recognized as a result of regulation: (Millions of Dollars) 2021 2020 2019 Annual decommissioning recorded as depreciation expense: (a) (b) $ 22 $ 20 $ 20 (a) Decommissioning expense does not include depreciation of the capitalized nuclear asset retirement costs. (b) Decommissioning expenses in 2021, 2020 and 2019 include Minnesota’s retail jurisdiction annual funding requirement of approximately $14 million. The 2017 nuclear decommissioning filing, effective Jan. 1, 2019, has been approved by the MPUC. In March 2020, the MPUC approved for NSP-Minnesota to delay any increase to the annual funding requirement until 2021. In December 2020, the MPUC verbally approved for NSP-Minnesota to delay any increase to the annual funding requirement until 2022. In December 2021, NSP-Minnesota submitted a Petition for approval of the 2022 - 2024 Nuclear Decommissioning Study and Assumptions. Contemplated but not proposed in this filing, was the 10-year extension of the license to operate the Monticello Plant, moving the planned retirement date from 2030 to 2040. The 2019 Preferred Integrated Resource Plan Supplement does include a 10-year extension of the license. On Feb. 8, 2022, the

Other Comprehensive Income

Other Comprehensive Income	12 Months Ended
	Dec. 31, 2021
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: 2021 (Millions of Dollars) Gains and Losses on Cash Flow Hedges Defined Benefit Pension and Postretirement Items Total Accumulated other comprehensive loss at Jan. 1 $ (85) $ (56) $ (141) Other comprehensive loss before reclassifications (net of taxes of $1 and $—, respectively) 4 — 4 Losses reclassified from net accumulated other comprehensive loss: Interest rate derivatives (net of taxes of $2 and $—, respectively) 6 (a) — 6 Amortization of net actuarial loss (net of taxes of $— and $3, respectively) — 8 (b) 8 Net current period other comprehensive income 10 8 18 Accumulated other comprehensive loss at Dec. 31 $ (75) $ (48) $ (123) (a) Included in interest charges. (b) Included in the computation of net periodic pension and postretirement benefit costs. See Note 11 for further information. 2020 (Millions of Dollars) Gains and Losses on Cash Flow Hedges Defined Benefit Pension and Postretirement Items Total Accumulated other comprehensive loss at Jan. 1 $ (80) $ (61) $ (141) Other comprehensive loss before reclassifications (net of taxes of $(3) and $(2), respectively) (10) (5) (15) Losses reclassified from net accumulated other comprehensive loss: Interest rate derivatives (net of taxes of $2 and $—, respectively) 5 (a) — 5 Amortization of net actuarial loss (net of taxes of $— and $3, respectively) — 10 (b) 10 Net current period other comprehensive (loss) income (5) 5 — Accumulated other comprehensive loss at Dec. 31 $ (85) $ (56) $ (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.

Segments and Related Informatio

Segments and Related Information	12 Months Ended
	Dec. 31, 2021
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. • 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 also presents All 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, investments in rental housing projects that qualify for low-income housing tax credits and the operations of MEC until July 2020. Xcel Energy had equity method investments of $208 million and $165 million as of Dec. 31, 2021 and 2020, 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) 2021 2020 2019 Regulated Electric Operating revenues — external $ 11,205 $ 9,802 $ 9,575 Intersegment revenue 2 2 1 Total revenues $ 11,207 $ 9,804 $ 9,576 Depreciation and amortization 1,855 1,673 1,535 Interest charges and financing costs 568 534 500 Income tax (benefit) expense (96) 1 125 Net income 1,478 1,407 1,288 Regulated Natural Gas Operating revenues — external $ 2,132 $ 1,636 $ 1,868 Intersegment revenue 2 1 2 Total revenues $ 2,134 $ 1,637 $ 1,870 Depreciation and amortization 254 252 219 Interest charges and financing costs 75 71 69 Income tax expense 54 17 48 Net income 231 190 195 All Other Total revenues $ 94 $ 88 $ 86 Depreciation and amortization 12 23 11 Interest charges and financing costs 173 193 167 Income tax benefit (28) (24) (45) Net loss (112) (124) (111) Consolidated Total Total revenues $ 13,435 $ 11,529 $ 11,532 Reconciling eliminations (4) (3) (3) Total operating revenues $ 13,431 $ 11,526 $ 11,529 Depreciation and amortization 2,121 1,948 1,765 Interest charges and financing costs 816 798 736 Income tax (benefit) expense (70) (6) 128 Net income 1,597 1,473 1,372

Summarized Quarterly Financial

Summarized Quarterly Financial Data (Unaudited)	12 Months Ended
	Dec. 31, 2021
Quarterly Financial Information Disclosure [Abstract]
Quarterly Financial Information [Text Block]	Quarter Ended (Amounts in millions, except per share data) March 31, 2021 June 30, 2021 Sept. 30, 2021 Dec. 31, 2021 Operating revenues $ 2,811 $ 2,586 $ 3,182 $ 2,947 Operating income 455 422 813 426 Net income 295 287 603 288 EPS total — basic $ 0.56 $ 0.54 $ 1.15 $ 0.54 EPS total — diluted 0.56 0.54 1.14 0.54 Cash dividends declared per common share 0.43 0.43 0.43 0.43 Quarter Ended (Amounts in millions, except per share data) March 31, 2020 June 30, 2020 Sept. 30, 2020 Dec. 31, 2020 Operating revenues $ 2,811 $ 2,586 $ 3,182 $ 2,947 Operating income 455 422 813 426 Net income 295 287 603 288 EPS total — basic $ 0.56 $ 0.54 $ 1.15 $ 0.54 EPS total — diluted 0.56 0.54 1.14 0.54 Cash dividends declared per common share 0.43 0.43 0.43 0.43

Schedule I, Condensed Financial

Schedule I, Condensed Financial Statements of Xcel Energy Inc	12 Months Ended
	Dec. 31, 2021
Condensed Financial Information Disclosure [Abstract]
Schedule I, Condensed Financial Information	Year Ended Dec. 31 2021 2020 2019 Income Equity earnings of subsidiaries $ 1,744 $ 1,646 $ 1,505 Total income 1,744 1,646 1,505 Expenses and other deductions Operating expenses 21 43 23 Other income 3 (4) (9) Interest charges and financing costs 173 198 173 Total expenses and other deductions 197 237 187 Income before income taxes 1,547 1,409 1,318 Income tax benefit (50) (64) (54) Net income $ 1,597 $ 1,473 $ 1,372 Other Comprehensive Income Pension and retiree medical benefits, net of tax of $ 1, $1 and $1, respectively $ 8 $ 5 $ 3 Derivative instruments, net of tax of $3, $(1) and $(7), respectively 10 (5) (20) Other comprehensive income (loss) 18 — (17) Comprehensive income $ 1,615 $ 1,473 $ 1,355 Weighted average common shares outstanding: Basic 539 527 519 Diluted 540 528 520 Earnings per average common share: Basic $ 2.96 $ 2.79 $ 2.64 Diluted 2.96 2.79 2.64 See Notes to Condensed Financial Statements Year Ended Dec. 31 2021 2020 2019 Operating activities Net cash provided by operating activities $ 1,147 $ 2,377 $ 1,389 Investing activities Capital contributions to subsidiaries (1,661) (2,553) (1,594) Net return (investments) in the utility money pool 57 (18) 39 Other, net — (1) — Net cash used in investing activities (1,604) (2,572) (1,555) Financing activities Proceeds (repayment of) from short-term borrowings, net 638 (500) 12 Proceeds from issuance of long-term debt 791 1,089 1,120 Repayment of long-term debt (400) (300) (550) Proceeds from issuance of common stock 366 727 458 Repurchase of common stock — (4) — Dividends paid (935) (856) (791) Other (16) (17) (14) Net cash provided by financing activities 444 139 235 Net change in cash, cash equivalents, and restricted cash (13) (56) 69 Cash, cash equivalents and restricted cash at beginning of period 14 70 1 Cash, cash equivalents and restricted cash at end of period $ 1 $ 14 $ 70 See Notes to Condensed Financial Statements Dec. 31 2021 2020 Assets Cash and cash equivalents $ 1 $ 14 Accounts receivable from subsidiaries 430 424 Other current assets 6 6 Total current assets 437 444 Investment in subsidiaries 21,167 19,102 Other assets 71 40 Total other assets 21,238 19,142 Total assets $ 21,675 $ 19,586 Liabilities and Equity Current portion of long-term debt — 400 Dividends payable 249 231 Short-term debt 638 — Other current liabilities 29 21 Total current liabilities 916 652 Other liabilities 10 17 Total other liabilities 10 17 Commitments and contingencies Capitalization Long-term debt 5,137 4,342 Common stockholders' equity 15,612 14,575 Total capitalization 20,749 18,917 Total liabilities and equity $ 21,675 $ 19,586 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, 2021 and 2020, 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, 2021: (Millions of Dollars) Guarantor Guarantee Current Triggering Guarantee of loan for Hiawatha Collegiate High School (a) Xcel Energy Inc. $ 1 — (c) Guarantee performance and payment of surety bonds for Xcel Energy Inc.’s utility subsidiaries (b) Xcel Energy Inc. 59 (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 net of payables with affiliates at Dec. 31: (Millions of Dollars) 2021 2020 NSP-Minnesota $ 104 $ 81 NSP-Wisconsin 25 9 PSCo 91 98 SPS 58 55 Xcel Energy Services Inc. 125 159 Other subsidiaries of Xcel Energy Inc. 27 22 $ 430 $ 424 Dividends — Cash dividends paid to Xcel Energy Inc. by its subsidiaries were $1,344 million, $2,527 million and $2,987 million for the years ended Dec. 31, 2021, 2020 and 2019, 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, 2021 Loan outstanding at period end $ — Average loan outstanding — Maximum loan outstanding — Weighted average interest rate, computed on a daily basis N/A Weighted average interest rate at end of period N/A Money pool interest income $ — (Amounts in Millions, Except Interest Rates) Year Ended Dec. 31, 2021 Year Ended Dec. 31, 2020 Year Ended Dec. 31, 2019 Loan outstanding at period end $ — $ 57 $ 39 Average loan outstanding 16 104 47 Maximum loan outstanding 439 350 250 Weighted average interest rate, computed on a daily basis 0.08 % 0.60 % 2.15 % Weighted average interest rate at end of period N/A 0.07 % 1.63 Money pool interest income $ — $ 1 $ 1 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, 2021
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) 2021 2020 2019 2021 2020 2019 Balance at Jan. 1 $ 79 $ 55 $ 55 $ 64 $ 67 $ 79 Additions charged to costs and expenses 60 60 42 5 6 9 Additions charged to other accounts 14 (a) 12 (a) 16 (a) — — — Deductions from reserves (47) (b) (48) (b) (58) (b) (5) (d) (9) (c) (21) (d) Balance at Dec. 31 $ 106 $ 79 $ 55 $ 64 $ 64 $ 67 (a) Recovery of amounts previously written-off. (b) Deductions related primarily to bad debt write-offs. (c) Primarily the reduction of valuation allowances for North Dakota ITC, net of federal income tax benefit, that is offset to a regulatory liability forecasted to be used prior to expiration along with valuation allowances that expired.

Summary of Significant Accoun_2

Summary of Significant Accounting Policies Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2021
Accounting Policies [Abstract]
Business and System of Accounts	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, Venture Holdings and Nicollet Project Holdings. 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. Venture Holdings invests in limited partnerships, including EIP funds with portfolios of investments in energy technology companies. Nicollet Project Holdings invests in nonregulated assets such as the MEC generating facility (through July 2020) and Minnesota community solar gardens. 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, Xcel Energy Nuclear Services Holdings, LLC and Xcel Energy Services Inc. Xcel Energy Inc. and its subsidiaries collectively are referred to as Xcel Energy. Xcel Energy’s consolidated financial statements include its wholly-owned subsidiaries and VIEs for which it is the primary beneficiary. 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 investments in EIP funds and WYCO. 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 consolidated financial statements or notes have been reclassified 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, 2021 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, 2021 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 for 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. • 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 would be refundable to utility customers over the remaining life of the related assets. Xcel Energy anticipates that a tax rate increase would result in the establishment of a regulatory asset, subject to an evaluation of whether future recovery is expected. 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 other (expense) income or 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 commission approved 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. Plant removal costs of Xcel Energy’s utility subsidiaries are recovered in rates as authorized by the appropriate regulatory entities. The amount of removal costs is based on current factors used in existing depreciation rates. Accumulated removal costs are reflected in the consolidated balance sheet as a regulatory liability. Depreciation expense, expressed as a percentage of average depreciable property, was approximately 3.5% for 2021, 3.4% for 2020 and 3.3% for 2019.
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. 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. 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 Notes 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. For certain environmental costs related to facilities currently in use, such as for 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 systematically 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 physical sales to customers (native load and wholesale) on a gross basis in electric revenues and cost of sales. Revenues and charges for short-term physical wholesale sales of excess energy transacted through RTOs are also recorded on a gross basis. Other revenues and charges settled/facilitated through an RTO 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.
Inventory	Inventory — Inventory is recorded at average cost and consisted of the following: (Millions of Dollars) Dec. 31, 2021 Dec. 31, 2020 Inventories Materials and supplies $ 289 $ 275 Fuel 182 176 Natural gas 160 84 Total inventories $ 631 $ 535 Equity Method Investments —
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 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 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 —
Alternative Revenue Programs	Alternative Revenue — Certain rate rider mechanisms (including decoupling/sales true up 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 or from other instances where the regulator authorizes a future surcharge in response to past activities or completed events. 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 and purchased power costs for the cost of RECs received. An inventory accounting model is used to account for RECs recognized on the consolidated balance sheets, however these assets are classified as regulatory assets if amounts are 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, 2021
Balance Sheet Related Disclosure - Inventory [Abstract]
Public Utilities, Inventory	Inventory — Inventory is recorded at average cost and consisted of the following: (Millions of Dollars) Dec. 31, 2021 Dec. 31, 2020 Inventories Materials and supplies $ 289 $ 275 Fuel 182 176 Natural gas 160 84 Total inventories $ 631 $ 535 Equity Method Investments —

Property Plant and Equipment _2

Property Plant and Equipment Property Plant and Equipment (Tables)	12 Months Ended
	Dec. 31, 2021
Property, Plant and Equipment [Line Items]
Public Utility Property, Plant, and Equipment	Major classes of property, plant and equipment (Millions of Dollars) Dec. 31, 2021 Dec. 31, 2020 Property, plant and equipment, net Electric plant $ 48,680 $ 47,104 Natural gas plant 7,758 7,135 Common and other property 2,602 2,503 Plant to be retired (a) 1,200 677 CWIP 1,969 1,877 Total property, plant and equipment 62,209 59,296 Less accumulated depreciation (17,060) (16,657) Nuclear fuel 3,081 2,970 Less accumulated amortization (2,773) (2,659) Property, plant and equipment, net $ 45,457 $ 42,950 (a) Includes regulator-approved retirements of Comanche Units 1 and 2 and jointly owned Craig Unit 1 for PSCo, and Sherco Units 1, 2 and 3 and A.S. King for NSP-Minnesota. Also includes SPS’ expected retirement of Tolk and conversion of Harrington to natural gas, and PSCo’s planned retirement of jointly owned Craig Unit 2.
NSP Minnesota
Property, Plant and Equipment [Line Items]
Schedule of Jointly Owned Utility Plants	(Millions of Dollars, Except Percent Owned) Plant in Service Accumulated Depreciation Percent Owned NSP-Minnesota Electric generation: Sherco Unit 3 $ 620 $ 451 59 % Sherco common facilities 178 108 80 Sherco substation 5 4 59 Electric transmission: Grand Meadow 11 3 50 Huntley Wilmarth 48 1 50 CapX2020 952 127 51 Total NSP-Minnesota (a) $ 1,814 $ 694 (a) Projects additionally include $7 million in CWIP.
NSP-Wisconsin
Property, Plant and Equipment [Line Items]
Schedule of Jointly Owned Utility Plants	(Millions of Dollars, Except Percent Owned) Plant in Service Accumulated Depreciation Percent Owned NSP-Wisconsin Electric transmission: La Crosse, WI to Madison, WI $ 177 $ 15 37 % CapX2020 169 28 80 Total NSP-Wisconsin (a) $ 346 $ 43 (a) Projects additionally include $2 million in CWIP.
PSCo
Property, Plant and Equipment [Line Items]
Schedule of Jointly Owned Utility Plants	(Millions of Dollars, Except Percent Owned) Plant in Service Accumulated Depreciation Percent Owned PSCo Electric generation: Hayden Unit 1 $ 156 $ 99 76 % Hayden Unit 2 151 78 37 Hayden common facilities 42 27 53 Craig Units 1 and 2 81 48 10 Craig common facilities 39 25 7 Comanche Unit 3 917 154 67 Comanche common facilities 28 2 82 Electric transmission: Transmission and other facilities 182 63 Various Gas transmission: Rifle, CO to Avon, CO 22 8 60 Gas transmission compressor 8 2 50 Total PSCo (a) $ 1,626 $ 506 (a) Projects additionally include $4 million in CWIP.

Regulatory Assets and Liabili_2

Regulatory Assets and Liabilities (Tables)	12 Months Ended
	Dec. 31, 2021
Regulatory Assets and Liabilities Disclosure [Abstract]
Regulatory Assets	Components of regulatory assets: (Millions of Dollars) See Note(s) Remaining Amortization Period Dec. 31, 2021 Dec. 31, 2020 Regulatory Assets Current Noncurrent Current Noncurrent Pension and retiree medical obligations 11 Various $ 77 $ 944 $ 82 $ 1,268 Deferred natural gas, electric, steam energy/fuel costs One five 504 543 14 18 Recoverable deferred taxes on AFUDC Plant lives — 289 — 283 Excess deferred taxes — TCJA 7 Various 14 219 16 229 Depreciation differences One 16 173 16 154 Environmental remediation costs 1, 12 Various 14 92 16 113 Texas revenue surcharges One two 20 64 54 17 Sales true-up and revenue decoupling One two 33 56 101 28 Benson biomass PPA termination and asset purchase Eight 10 55 10 65 Renewable resources and environmental initiatives One two 170 48 129 12 PI extended power uprate 13 years 4 46 3 49 Purchased power contract costs Term of related contract 9 45 7 54 Conservation programs (a) 1 One two 21 35 26 36 Losses on reacquired debt Term of related debt 3 35 4 38 Contract valuation adjustments (b) 1, 10 Term of related contract 22 34 23 48 State commission adjustments Plant lives 1 32 1 32 Laurentian biomass PPA termination Two 18 18 18 36 Nuclear refueling outage costs 1 One two 37 16 28 10 Property tax Various 16 16 16 21 Gas pipeline inspection and remediation costs One two 33 12 26 9 Net AROs (c) 1, 12 Various — (112) — 139 Other Various 84 78 50 78 Total regulatory assets $ 1,106 $ 2,738 $ 640 $ 2,737 (a) Includes costs for conservation programs, as well as incentives allowed in certain jurisdictions. (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 amounts recorded for future recovery of AROs, less amounts recovered through nuclear decommissioning accruals and gains from decommissioning investments.
Regulatory Liabilities	Components of regulatory liabilities: (Millions of Dollars) See Note(s) Remaining Amortization Period Dec. 31, 2021 Dec. 31, 2020 Regulatory Liabilities Current Noncurrent Current Noncurrent Deferred income tax adjustments and TCJA refunds (a) 7 Various $ 26 $ 3,230 $ 20 $ 3,368 Plant removal costs 1, 12 Various — 1,655 — 1,520 Effects of regulation on employee benefit costs (b) Various — 235 — 221 Renewable resources and environmental initiatives Various 1 101 5 59 ITC deferrals 1 Various — 53 — 51 Revenue decoupling One two 9 41 10 41 Contract valuation adjustments (c) 1, 10 One three 56 1 19 — Deferred natural gas, electric, steam energy/fuel costs Less than one year 50 — 84 — Conservation programs (d) 1 Less than one year 42 — 49 — DOE settlement Less than one year 14 14 23 — Other Various 73 75 101 42 Total regulatory liabilities (e) $ 271 $ 5,405 $ 311 $ 5,302 (a) Includes the revaluation of recoverable/regulated plant accumulated deferred income taxes and revaluation impact of non-plant accumulated deferred income taxes 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 the fair value of certain long-term PPAs used to meet energy capacity requirements and valuation adjustments on natural gas commodity purchases. (d) Includes costs for conservation programs, as well as incentives allowed in certain jurisdictions. (e) Revenue subject to refund of $17 million for both 2021 and 2020 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, 2021
Debt Disclosure [Abstract]
Commercial Paper	Commercial paper and term loan borrowings outstanding: (Millions of Dollars, Except Interest Rates) Three Months Ended Dec. 31, 2021 Year Ended Dec. 31 2021 2020 2019 Borrowing limit $ 3,100 $ 3,100 $ 3,100 $ 3,600 Amount outstanding at period end 1,005 1,005 584 595 Average amount outstanding 1,200 1,399 1,126 1,115 Maximum amount outstanding 1,774 2,054 2,080 1,780 Weighted average interest rate, computed on a daily basis 0.54 % 0.57 % 1.45 % 2.72 % Weighted average interest rate at period end 0.31 0.31 0.23 2.34
Schedule of Debt To Total Capitalization Ratio	Features of the credit facilities: Debt-to-Total Capitalization Ratio (a) Amount Facility May Be Increased (millions of dollars) Additional Periods for Which a One-Year Extension May Be Requested (b) 2021 2020 Xcel Energy Inc. (c) 60 % 59 % $ 250 2 NSP-Wisconsin 49 46 N/A 1 NSP-Minnesota 47 47 100 2 SPS 47 48 50 2 PSCo 44 44 100 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. would 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	As of Dec. 31, 2021, NSP-Minnesota had $45 million outstanding letters of credit under the $75 million the Bilateral Credit Agreement. Xcel Energy Inc. and its utility subsidiaries had the following committed credit facilities available as of Dec. 31, 2021: (Millions of Dollars) Credit Facility (a) Drawn (b) Available Xcel Energy Inc. $ 1,250 $ 638 $ 612 PSCo 700 155 545 NSP-Minnesota 500 9 491 SPS 500 139 361 NSP-Wisconsin 150 83 67 Total $ 3,100 $ 1,024 $ 2,076 (a) These credit facilities mature in June 2024. (b) Includes outstanding commercial paper and letters of credit.
Schedule of Long Term Debt Instruments	Long-term debt obligations for Xcel Energy Inc. and its utility subsidiaries as of Dec. 31 (in millions of dollars): Xcel Energy Inc. Financing Instrument Interest Rate Maturity Date 2021 2020 Unsecured senior notes 2.40 % March 15, 2021 $ — $ 400 Unsecured senior notes (b) 0.50 Oct. 15, 2023 500 500 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) 1.75 March 15,2027 500 — Unsecured senior notes 4.00 June 15, 2028 130 130 Unsecured senior notes 4.00 June 15, 2028 500 500 Unsecured senior notes 2.60 Dec. 1, 2029 500 500 Unsecured senior notes (b) 3.40 June 1, 2030 600 600 Unsecured senior notes (a) 2.35 Nov. 15, 2031 300 — Unsecured senior notes 6.50 July 1, 2036 300 300 Unsecured senior notes 4.80 Sep. 15, 2041 250 250 Unsecured senior notes 3.50 Dec. 1, 2049 500 500 Unamortized discount (8) (7) Unamortized debt issuance cost (33) (32) Current maturities — (400) Total long-term debt $ 5,139 $ 4,341 (a) 2021 financing. (b) 2020 financing. NSP-Minnesota Financing Instrument Interest Rate Maturity Date 2021 2020 First mortgage bonds 2.15 % Aug. 15, 2022 $ 300 $ 300 First mortgage bonds 2.60 May 15, 2023 400 400 First mortgage bonds 7.125 July 1, 2025 250 250 First mortgage bonds 6.50 March 1, 2028 150 150 First mortgage bonds (a) 2.25 April 1, 2031 425 — 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 4.125 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 Sep. 15, 2047 600 600 First mortgage bonds 2.90 March 1, 2050 600 600 First mortgage bonds (b) 2.60 June 1, 2051 700 700 First mortgage bonds (a) 3.20 April 1,2052 425 — Other long-term debt 3 — Unamortized discount (44) (42) Unamortized debt issuance cost (62) (54) Current maturities (300) — Total long-term debt $ 6,447 $ 5,904 (a) 2021 financing. (b) 2020 financing. NSP-Wisconsin Financing Instrument Interest Rate Maturity Date 2021 2020 City of La Crosse resource recovery bond 6.00 % Nov. 1, 2021 $ — $ 19 First mortgage bonds 3.30 June 15, 2024 100 100 First mortgage bonds 3.30 June 15, 2024 100 100 First mortgage bonds 6.375 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 4.20 Sept. 1, 2048 200 200 First mortgage bonds (b) 3.05 May 1, 2051 100 100 First mortgage bonds (a) 2.82 May 1, 2051 100 — Other long-term debt 1 — Unamortized discount (4) (4) Unamortized debt issuance cost (10) (9) Current maturities — (19) Total long-term debt $ 987 $ 887 (a) 2021 financing. (b) 2020 financing. PSCo Financing Instrument Interest Rate Maturity Date 2021 2020 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 3.70 June 15, 2028 350 350 First mortgage bonds (b) 1.90 Jan. 15, 2031 375 375 First mortgage bonds (a) 1.875 June 15, 2031 750 — 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 4.10 June 15, 2048 350 350 First mortgage bonds 4.05 Sept. 15, 2049 400 400 First mortgage bonds 3.20 March 1, 2050 550 550 First mortgage bonds (b) 2.70 Jan. 15, 2051 375 375 Unamortized discount (33) (30) Unamortized debt issuance cost (50) (46) Current maturities (300) — Total long-term debt $ 6,167 $ 5,724 (a) 2021 financing. (b) 2020 financing. SPS Financing Instrument Interest Rate Maturity Date 2021 2020 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 4.40 Nov. 15, 2048 300 300 First mortgage bonds 3.75 June 15, 2049 300 300 First mortgage bonds (b) 3.15 May 1, 2050 350 350 First mortgage bonds (a) 3.15 May 1, 2050 250 — Unamortized discount (9) (10) Unamortized debt issuance cost (28) (26) Total long-term debt $ 3,013 $ 2,764 (a) 2020 financing re-opened in 2021. (b) 2020 financing.
Schedule of Maturities of Long-term Debt	(Millions of Dollars) 2022 $ 601 2023 1,150 2024 552 2025 1,102 2026 501
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) 2021 and 2020 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, 2021 Common Stock Outstanding (Shares) as of Dec. 31, 2020 1,000,000,000 $ 2.50 544,025,269 537,438,394
Share-based Payment Arrangement, Restricted Stock and Restricted Stock Unit, Activity [Table Text Block]	Requirements and actuals as of Dec. 31, 2021: Equity to Total Equity to Total Capitalization Ratio Actual Low High 2021 NSP-Minnesota 47.2 % 57.6 % 52.9 % NSP-Wisconsin 52.5 N/A 52.8 SPS (a) 45.0 55.0 54.5 (a) Excludes short-term debt. (Amounts in Millions) Unrestricted Retained Earnings Total Capitalization Limit on Total Capitalization NSP-Minnesota $ 1,558 $ 14,321 $ 15,332 NSP-Wisconsin (a) 11 2,091 N/A SPS (b) 513 6,615 N/A (a) Cannot pay annual dividends in excess of forecasted levels if its average equity-to-total capitalization ratio falls below the commission authorized level. (b)
Other Capital Restrictions	Amounts authorized to issue as of Dec. 31, 2021: (Millions of Dollars) Long-Term Debt Short-Term Debt NSP-Minnesota 52.8% of total capitalization (a) $ 2,300 (a) NSP-Wisconsin $ 150 150 SPS — 600 PSCo 700 (b) 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) PSCo filed for additional long-term debt authorization in December 2021.

Revenues (Tables)

Revenues (Tables)	12 Months Ended
	Dec. 31, 2021
Revenue from Contract with Customer [Abstract]
Disaggregation of Revenue	Xcel Energy’s operating revenues consisted of the following: Year Ended Dec. 31, 2021 (Millions of Dollars) Electric Natural Gas All Other Total Major revenue types Revenue from contracts with customers: Residential $ 3,194 $ 1,222 $ 45 $ 4,461 C&I 5,050 640 30 5,720 Other 127 — 7 134 Total retail 8,371 1,862 82 10,315 Wholesale 1,540 — — 1,540 Transmission 604 — — 604 Other 61 148 — 209 Total revenue from contracts with customers 10,576 2,010 82 12,668 Alternative revenue and other 629 122 12 763 Total revenues $ 11,205 $ 2,132 $ 94 $ 13,431 Year Ended Dec. 31, 2020 (Millions of Dollars) Electric Natural Gas All Other Total Major revenue types Revenue from contracts with customers: Residential $ 3,066 $ 975 $ 42 $ 4,083 C&I 4,596 462 27 5,085 Other 125 — 6 131 Total retail 7,787 1,437 75 9,299 Wholesale 759 — — 759 Transmission 579 — — 579 Other 73 137 — 210 Total revenue from contracts with customers 9,198 1,574 75 10,847 Alternative revenue and other 604 62 13 679 Total revenues $ 9,802 $ 1,636 $ 88 $ 11,526 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

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2021
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 expire as follows: Tax Year(s) Expiration 2014 - 2016 December 2022 2018 September 2022
State Statute of Limitations Applicable to Open Tax Years	State Year Colorado 2014 Minnesota 2014 Texas 2016 Wisconsin 2016
Reconciliation of Unrecognized Tax Benefits	Unrecognized tax benefits - permanent vs. temporary: (Millions of Dollars) Dec. 31, 2021 Dec. 31, 2020 Unrecognized tax benefit — Permanent tax positions $ 47 $ 41 Unrecognized tax benefit — Temporary tax positions 11 11 Total unrecognized tax benefit $ 58 $ 52 Changes in unrecognized tax benefits: (Millions of Dollars) 2021 2020 2019 Balance at Jan. 1 $ 52 $ 44 $ 37 Additions based on tax positions related to the current year 5 9 10 Reductions based on tax positions related to the current year — (2) (4) Additions for tax positions of prior years 2 35 1 Reductions for tax positions of prior years (1) (34) — Balance at Dec. 31 $ 58 $ 52 $ 44
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, 2021 Dec. 31, 2020 NOL and tax credit carryforwards $ (36) $ (31)
Interest Payable related to Unrecognized Tax Benefits [Table Text Block]	(Millions of Dollars) 2021 2020 2019 Payable for interest related to unrecognized tax benefits at Jan. 1 $ (3) $ — $ — Interest expense related to unrecognized tax benefits — (3) — Payable for interest related to unrecognized tax benefits at Dec. 31 $ (3) $ (3) $ —
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) 2021 2020 Federal NOL carryforward $ 765 $ — Federal tax credit carryforwards 1,172 791 State NOL carryforwards 1,648 839 Valuation allowances for state NOL carryforwards (3) (4) State tax credit carryforwards, net of federal detriment (a) 89 89 Valuation allowances for state credit carryforwards, net of federal benefit (b) (64) (64) (a) State tax credit carryforwards are net of federal detriment of $24 million as of Dec. 31, 2021 and 2020. (b) Valuation allowances for state tax credit carryforwards were net of federal benefit of $17 million as of Dec. 31, 2021 and 2020.
Schedule of Effective Income Tax Rate Reconciliation	Effective income tax rate for years ended Dec. 31: 2021 2020 2019 Federal statutory rate 21.0 % 21.0 % 21.0 % State income tax on pretax income, net of federal tax effect 5.0 4.9 4.9 (Decreases) increases in tax from: Wind PTCs (23.4) (15.7) (9.4) Plant regulatory differences (a) (6.2) (7.6) (5.8) Other tax credits, net NOL & tax credit allowances (1.1) (1.2) (1.7) NOL Carryback — (0.9) — Change in unrecognized tax benefits 0.4 0.5 0.5 Other, net (0.3) (1.4) (1.0) Effective income tax rate (4.6) % (0.4) % 8.5 % (a) 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) 2021 2020 2019 Current federal tax expense (benefit) $ 15 $ (13) $ (16) Current state tax (benefit) expense (2) 2 4 Current change in unrecognized tax expense 1 18 2 Deferred federal tax (benefit) expense (183) (89) 55 Deferred state tax expense 99 91 83 Deferred change in unrecognized tax expense (benefit) 5 (10) 5 Deferred ITCs (5) (5) (5) Total income tax (benefit) expense $ (70) $ (6) $ 128 Components of deferred income tax expense as of Dec. 31: (Millions of Dollars) 2021 2020 2019 Deferred tax expense excluding items below $ 148 $ 237 $ 344 Amortization and adjustments to deferred income taxes on income tax regulatory assets and liabilities (221) (247) (206) Tax (benefit) expense allocated to other comprehensive income, adoption of ASC Topic 326, and other (6) 2 5 Deferred tax (benefit) expense $ (79) $ (8) $ 143
Schedule of Deferred Tax Assets and Liabilities	Components of net deferred tax liability as of Dec. 31: (Millions of Dollars) 2021 2020 (a) Deferred tax liabilities: Differences between book and tax bases of property $ 6,231 $ 5,810 Operating lease assets 351 400 Regulatory assets 598 603 Deferred fuel costs 262 (6) Pension expense 175 176 Other 93 74 Total deferred tax liabilities $ 7,710 $ 7,057 Deferred tax assets: Regulatory liabilities $ 780 $ 806 Operating lease liabilities 351 400 Tax credit carryforward 1,261 880 NOL carryforward 247 37 NOL and tax credit valuation allowances (64) (64) Other employee benefits 119 141 Deferred ITCs 15 13 Other 107 98 Total deferred tax assets $ 2,816 $ 2,311 Net deferred tax liability $ 4,894 $ 4,746 (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, 2021
Share-based Payment Arrangement [Abstract]
Restricted Stock	Shares of restricted stock granted at Dec. 31: (Shares in Thousands) 2021 2020 2019 Granted shares 2 1 13 Grant date fair value $ 61.54 $ 70.26 $ 53.46 Changes in nonvested restricted stock: (Shares in Thousands) Shares Weighted Average Nonvested restricted stock at Jan. 1, 2021 15 $ 56.68 Granted 2 61.54 Forfeited — 70.26 Vested (9) 49.71 Dividend equivalents — 66.73 Nonvested restricted stock at Dec. 31, 2021 8 67.26
Other Equity Awards	Equity award units granted to employees (excluding restricted stock): (Units in Thousands) 2021 2020 2019 Granted units 421 411 483 Weighted average grant date fair value $ 66.03 $ 62.92 $ 49.67 Equity awards vested: (Units in Thousands, Fair Value in Millions) 2021 2020 2019 Vested Units 392 442 464 Total Fair Value $ 27 $ 29 $ 29 Changes in the nonvested portion of equity award units: (Units in Thousands) Units Weighted Average Nonvested Units at Jan. 1, 2021 780 $ 55.68 Granted 421 66.03 Forfeited (146) 61.76 Vested (392) 48.91 Dividend equivalents 32 58.00 Nonvested Units at Dec. 31, 2021 695 64.59
Stock Equivalent Unit Plan	Stock equivalent units granted: (Units in Thousands) 2021 2020 2019 Granted units 31 33 29 Weighted average grant date fair value $ 68.15 $ 61.61 $ 58.44 Changes in stock equivalent units: (Units in Thousands) Units Weighted Average Stock equivalent units at Jan. 1, 2021 630 $ 36.28 Granted 31 68.15 Units distributed (73) 31.47 Dividend equivalents 16 66.98 Stock equivalent units at Dec. 31, 2021 604 39.27
TSR Liability Awards	TSR liability awards granted: (In Thousands) 2021 2020 2019 Awards granted 221 212 225 TSR liability awards settled: (Units In Thousands, Settlement Amount in Millions) 2021 2020 2019 Awards settled 446 476 466 Settlement amount (cash, common stock and deferred amounts) $ 27 $ 33 $ 25
Compensation costs related to share-based awards	Compensation costs related to share-based awards: (Millions of Dollars) 2021 2020 2019 Compensation cost for share-based awards (a) $ 31 $ 73 $ 58 Tax benefit recognized in income 8 19 15 (a) Compensation costs for share-based payments are included in O&M expense.

Earnings Per Share (Tables)

Earnings Per Share (Tables)	12 Months Ended
	Dec. 31, 2021
Earnings Per Share [Abstract]
Schedule of Weighted Average Number of Shares	Common shares outstanding used in the basic and diluted EPS computation: (Shares in Millions) 2021 2020 2019 Basic 539 527 519 Diluted (a) 540 528 520 (a) Diluted common shares outstanding included common stock equivalents of 0.3 million, 1.1 million and 1.3 million shares for 2021, 2020 and 2019, respectively.

Fair Value of Financial Asset_2

Fair Value of Financial Assets and Liabilities (Tables)	12 Months Ended
	Dec. 31, 2021
Fair Value Disclosures [Abstract]
Cost and Fair Value of Nuclear Decommissioning Fund Investments	Non-derivative instruments with recurring fair value measurements: Dec. 31, 2021 Fair Value (Millions of Dollars) Cost Level 1 Level 2 Level 3 NAV Total Nuclear decommissioning fund (a) Cash equivalents $ 64 $ 64 $ — $ — $ — $ 64 Commingled funds 856 — — — 1,294 1,294 Debt securities 631 — 666 9 — 675 Equity securities 411 1,222 1 — — 1,223 Total $ 1,962 $ 1,286 $ 667 $ 9 $ 1,294 $ 3,256 (a) Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $208 million of equity investments in unconsolidated subsidiaries and $164 million of rabbi trust assets and miscellaneous investments. Dec. 31, 2020 Fair Value (Millions of Dollars) Cost Level 1 Level 2 Level 3 NAV Total Nuclear decommissioning fund (a) Cash equivalents $ 40 $ 40 $ — $ — $ — $ 40 Commingled funds 787 — — — 1,041 1,041 Debt securities 528 — 572 13 — 585 Equity securities 446 1,109 2 — — 1,111 Total $ 1,801 $ 1,149 $ 574 $ 13 $ 1,041 $ 2,777 (a) Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $165 million of equity investments in unconsolidated subsidiaries and $154 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, 2021: 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 $ 4 $ 149 $ 208 $ 314 $ 675
Rabbi Trust Securities Amortized Cost and Fair Value Measured on Recurrring Basis [Table Text Block]	Cost and fair value of assets held in rabbi trusts: Dec. 31, 2021 Fair Value (Millions of Dollars) Cost Level 1 Level 2 Level 3 Total Rabbi Trusts (a) Cash equivalents $ 20 $ 20 $ — $ — $ 20 Mutual funds 75 89 — — 89 Total $ 95 $ 109 $ — $ — $ 109 (a) Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet. Dec. 31, 2020 Fair Value (Millions of Dollars) Cost Level 1 Level 2 Level 3 Total Rabbi Trusts (a) Cash equivalents $ 32 $ 32 $ — $ — $ 32 Mutual funds 60 70 — — 70 Total $ 92 $ 102 $ — $ — $ 102 (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 amounts of commodity forwards, options and FTRs: (Amounts in Millions) (a)(b) Dec. 31, 2021 Dec. 31, 2020 MWh of electricity 80 87 MMBtu of natural gas 156 175 (a) Not reflective of net positions in the underlying commodities. (b) Notional amounts for options 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 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) 2021 2020 2019 Accumulated other comprehensive loss related to cash flow hedges at Jan. 1 $ (85) $ (80) $ (60) After-tax net unrealized gains (losses) related to derivatives accounted for as hedges 4 (10) (23) After-tax net realized losses on derivative transactions reclassified into earnings 6 5 3 Accumulated other comprehensive loss related to cash flow hedges at Dec. 31 $ (75) $ (85) $ (80)
Derivative Instruments, Gain (Loss) [Table Text Block]	Impact of derivative activity: Pre-Tax Fair Value (Millions of Dollars) Accumulated Regulatory Year Ended Dec. 31, 2021 Derivatives designated as cash flow hedges Interest rate $ 5 $ — Total $ 5 $ — Other derivative instruments Electric commodity $ — $ 32 Natural gas commodity — (4) Total $ — $ 28 Year Ended Dec. 31, 2020 Interest rate $ (13) $ — Total $ (13) $ — Other derivative instruments Electric commodity $ — $ (5) Natural gas commodity — (13) Total $ — $ (18) Year Ended Dec. 31, 2019 Interest rate $ (30) $ — Total $ (30) $ — Other derivative instruments Electric commodity $ — $ 8 Natural gas commodity — (9) Total $ — $ (1) Pre-Tax (Gains) Losses Pre-Tax Gains (Losses) Recognized During the Period in Income (Millions of Dollars) Accumulated Regulatory Year Ended Dec. 31, 2021 Derivatives designated as cash flow hedges Interest rate $ 8 (a) $ — $ — Total $ 8 $ — $ — Other derivative instruments Commodity trading $ — $ — $ 63 (b) Electric commodity — (23) (c) — Natural gas commodity — 5 (d) (22) (d) Total $ — $ (18) $ 41 Year Ended Dec. 31, 2020 Derivatives designated as cash flow hedges Interest rate $ 7 (a) $ — $ — Total $ 7 $ — $ — Other derivative instruments Commodity trading $ — $ — $ (1) (b) Electric commodity — (3) (c) — Natural gas commodity — 10 (d) (13) (d) Total $ — $ 7 $ (14) 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) (a) Recorded to interest charges. (b) 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) 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.
Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis [Table Text Block]	Derivative assets and liabilities measured at fair value on a recurring basis were as follows: Dec. 31, 2021 Dec. 31, 2020 Fair Value Fair Value Total Netting (a) Total Fair Value Fair Value Total Netting (a) Total (Millions of Dollars) Level 1 Level 2 Level 3 Level 1 Level 2 Level 3 Current derivative assets Other derivative instruments: Commodity trading $ 22 $ 137 $ 21 $ 180 $ (134) $ 46 $ 2 $ 67 $ 1 $ 70 $ (52) $ 18 Electric commodity — — 57 57 (1) 56 — — 20 20 (1) 19 Natural gas commodity — 18 — 18 — 18 — 9 — 9 — 9 Total current derivative assets $ 22 $ 155 $ 78 $ 255 $ (135) 120 $ 2 $ 76 $ 21 $ 99 $ (53) 46 PPAs (b) 3 3 Current derivative instruments $ 123 $ 49 Noncurrent derivative assets Other derivative instruments: Commodity trading $ 16 $ 63 $ 89 $ 168 $ (107) $ 61 $ 8 $ 66 $ 8 $ 82 $ (62) $ 20 Total noncurrent derivative assets $ 16 $ 63 $ 89 $ 168 $ (107) 61 $ 8 $ 66 $ 8 $ 82 $ (62) 20 PPAs (b) 6 10 Noncurrent derivative instruments $ 67 $ 30 Dec. 31, 2021 Dec. 31, 2020 Fair Value Fair Value Total Netting (a) Total Fair Value Fair Value Total Netting (a) Total (Millions of Dollars) Level 1 Level 2 Level 3 Level 1 Level 2 Level 3 Current derivative liabilities Other derivative instruments: Commodity trading $ 19 $ 148 $ 20 $ 187 $ (143) $ 44 $ 4 $ 64 $ 17 $ 85 $ (58) $ 27 Electric commodity — — 1 1 (1) — — — 1 1 (1) — Natural gas commodity — 8 — 8 — 8 — 9 — 9 — 9 Total current derivative liabilities $ 19 $ 156 $ 21 $ 196 $ (144) 52 $ 4 $ 73 $ 18 $ 95 $ (59) 36 PPAs (b) 17 17 Current derivative instruments $ 69 $ 53 Noncurrent derivative liabilities Other derivative instruments: Commodity trading $ 18 $ 48 $ 127 $ 193 $ (128) $ 65 $ 3 $ 58 $ 60 $ 121 $ (47) $ 74 Total noncurrent derivative liabilities $ 18 $ 48 $ 127 $ 193 $ (128) 65 $ 3 $ 58 $ 60 $ 121 $ (47) 74 PPAs (b) 40 57 Noncurrent derivative instruments $ 105 $ 131 (a) Xcel Energy nets derivative instruments and related collateral on its consolidated balance sheets 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, 2021 and 2020. At Dec. 31, 2021, derivative assets and liabilities include no obligations to return cash collateral. At Dec. 31, 2020, derivative assets and liabilities include $15 million of obligations to return cash collateral. At Dec. 31, 2021 and 2020, derivative assets and liabilities include rights to reclaim cash collateral of $30 million and $6 million, respectively. Counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements.
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) 2021 2020 2019 Balance at Jan. 1 $ (49) $ 4 $ 29 Purchases 65 51 44 Settlements (158) (73) (64) Net transactions recorded during the period: Gains (losses) recognized in earnings (a) 49 (39) (8) Net gains recognized as regulatory assets and liabilities 112 8 3 Balance at Dec. 31 $ 19 $ (49) $ 4 (a) Level 3 losses recognized in earnings are subject to offsetting gains of derivative instruments categorized as levels 1 and 2 in the income statement.
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: 2021 2020 (Millions of Dollars) Carrying Amount Fair Value Carrying Amount Fair Value Long-term debt, including current portion $ 22,380 $ 25,232 $ 20,066 $ 24,412

Benefit Plans and Other Postr_2

Benefit Plans and Other Postretirement Benefits (Tables)	12 Months Ended
	Dec. 31, 2021
Benefit Plans and Other Postretirement Benefits [Abstract]
Target Asset Allocations and Plan Assets Measured at Fair Value	For each of the fair value hierarchy levels, Xcel Energy’s pension plan assets measured at fair value: Dec. 31, 2021 (a) Dec. 31, 2020 (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 $ 133 $ — $ — $ — $ 133 $ 209 $ — $ — $ — $ 209 Commingled funds 1,324 — — 1,143 2,467 1,462 — — 1,115 2,577 Debt securities — 959 5 — 964 — 714 4 — 718 Equity securities 67 — — — 67 77 — — — 77 Other — 7 — 32 39 13 5 — — 18 Total $ 1,524 $ 966 $ 5 $ 1,175 $ 3,670 $ 1,761 $ 719 $ 4 $ 1,115 $ 3,599 (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, 2021 (a) Dec. 31, 2020 (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 $ 28 $ — $ — $ — $ 28 $ 27 $ — $ — $ — $ 27 Insurance contracts — 52 — — 52 — 50 — — 50 Commingled funds 64 — — 77 141 72 — — 69 141 Debt securities — 218 1 — 219 — 232 — — 232 Other — 2 — — 2 — 2 — — 2 Total $ 92 $ 272 $ 1 $ 77 $ 442 $ 99 $ 284 $ — $ 69 $ 452 (a) See Note 10 for further information on fair value measurement inputs and methods. Targeted asset allocations: Pension Benefits Postretirement Benefits 2021 2020 2021 2020 Domestic and international equity securities 33 % 35 % 15 % 15 % Long-duration fixed income securities 37 35 — — Short-to-intermediate fixed income securities 11 13 71 72 Alternative investments 17 15 8 9 Cash 2 2 6 4 Total 100 % 100 % 100 % 100 %
Changes in Projected Benefit Obligations, Fair Value of Plan Assets, and Funded Status of Plan [Table Text Block]	Pension Benefits Postretirement Benefits (Millions of Dollars) 2021 2020 2021 2020 Change in Benefit Obligation: Obligation at Jan. 1 $ 3,964 $ 3,701 $ 574 $ 547 Service cost 104 95 2 1 Interest cost 104 125 15 18 Plan amendments 5 — — — Actuarial (gain) loss (94) 328 (41) 50 Plan participants’ contributions — — 8 8 Medicare subsidy reimbursements — — 2 1 Benefit payments (a) (365) (285) (49) (51) Obligation at Dec. 31 $ 3,718 $ 3,964 $ 511 $ 574 Change in Fair Value of Plan Assets: Fair value of plan assets at Jan. 1 $ 3,599 $ 3,184 $ 452 $ 449 Actual return on plan assets 305 550 16 35 Employer contributions 131 150 15 11 Plan participants’ contributions — — 8 8 Benefit payments (365) (285) (49) (51) Fair value of plan assets at Dec. 31 $ 3,670 $ 3,599 $ 442 $ 452 Funded status of plans at Dec. 31 $ (48) $ (365) $ (69) $ (122) Amounts recognized in the Consolidated Balance Sheet at Dec. 31: Noncurrent assets $ 19 $ — $ 33 $ 6 Current liabilities — — (4) (7) Noncurrent liabilities (67) (365) (98) (121) Net amounts recognized $ (48) $ (365) $ (69) $ (122) (a) Includes approximately $197 million in 2021 and $0 million in 2020 of lump-sum benefit payments used in the determination of a settlement charge. Pension Benefits Postretirement Benefits Significant Assumptions Used to Measure Benefit Obligations: 2021 2020 2021 2020 Discount rate for year-end valuation 3.08 % 2.71 % 3.09 % 2.65 % Expected average long-term increase in compensation level 3.75 3.75 N/A N/A Mortality table PRI-2012 PRI-2012 PRI-2012 PRI-2012 Health care costs trend rate — initial: Pre-65 N/A N/A 5.30 % 5.50 % Health care costs trend rate — initial: Post-65 N/A N/A 4.90 % 5.00 % 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 4 5
Projected Benefit Payments for the Pension and Postretirement Benefit Plans	(Millions of Dollars) Projected Gross Projected Expected Net Projected 2022 $ 323 $ 42 $ 2 $ 40 2023 257 41 2 39 2024 253 40 2 38 2025 251 38 2 36 2026 245 37 2 35 2027-2031 1,156 165 13 152
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost	Pension Benefits Postretirement Benefits (Millions of Dollars) 2021 2020 2021 2020 Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost: Net loss $ 978 $ 1,333 $ 81 $ 126 Prior service credit (9) (11) (7) (15) Total $ 969 $ 1,322 $ 74 $ 111 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 $ 74 $ 82 $ — $ — Noncurrent regulatory assets 846 1,181 90 125 Current regulatory liabilities — — (1) (1) Noncurrent regulatory liabilities — — (19) (18) Deferred income taxes 13 15 1 1 Net-of-tax accumulated other comprehensive income 36 44 3 4 Total $ 969 $ 1,322 $ 74 $ 111
Components of Net Periodic Benefit Costs	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) 2021 2020 2019 2021 2020 2019 Service cost $ 104 $ 95 $ 86 $ 2 $ 1 $ 2 Interest cost 104 125 145 15 18 22 Expected return on plan assets (206) (208) (203) (18) (19) (21) Amortization of prior service credit (1) (4) (5) (8) (8) (10) Amortization of net loss 107 100 87 5 4 5 Settlement charge (a) 59 — 6 — — — Net periodic pension cost (credit) 167 108 116 (4) (4) (2) Effects of regulation (46) 9 (1) 2 3 1 Net benefit cost (credit) recognized for financial reporting $ 121 $ 117 $ 115 $ (2) $ (1) $ (1) Significant Assumptions Used to Measure Costs: Discount rate 2.71 % 3.49 % 4.31 % 2.65 % 3.47 % 4.32 % Expected average long-term increase in compensation level 3.75 3.75 3.75 — — — Expected average long-term rate of return on assets 6.49 6.87 6.87 4.10 4.50 4.50

Commitments and Contingencies (

Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2021
Commitments and Contingencies Disclosure [Abstract]
Asset Retirement Obligations	Xcel Energy’s AROs were as follows: (Millions Jan. 1, 2021 Amounts Incurred (a) Accretion Cash Flow Revisions (b) Dec. 31, 2021 (c) Electric Nuclear $ 1,957 $ — $ 99 $ — $ 2,056 Wind 360 101 17 — 478 Steam, hydro and other production 264 6 10 8 288 Distribution 46 — 1 — 47 Natural gas Transmission and distribution 252 — 10 9 271 Miscellaneous 3 — — 5 8 Common Miscellaneous 1 — — — 1 Non-utility Miscellaneous 1 — 1 — 2 Total liability $ 2,884 $ 107 $ 138 $ 22 $ 3,151 (a) Amounts incurred related to the wind farms placed in service in 2021 for NSP-Minnesota (Blazing Star 2, Mower and Freeborn) and removal of a utility scale battery asset in NSP-Minnesota. (b) In 2021, AROs were revised for changes in timing and estimates of cash flows. Revisions in steam, hydro and other production AROs were primarily related to changes in cost estimates for remediation of ash containment facilities. Changes in gas transmission and distribution AROs were primarily related to changes in labor rates coupled with increased gas line mileage and number of services. (c) There were no ARO amounts settled in 2021. (Millions Jan. 1, 2020 Amounts Incurred (a) Amounts Settled (b) Accretion Cash Flow Revisions (c) Dec. 31, 2020 Electric Nuclear $ 2,068 $ — $ — $ 105 $ (216) $ 1,957 Steam, hydro and other production 202 — (5) 9 58 264 Wind 146 149 (3) 8 60 360 Distribution 44 — — 2 — 46 Natural gas Transmission and distribution 236 — — 10 6 252 Miscellaneous 3 — — — — 3 Common Miscellaneous 1 — — — — 1 Non-utility Miscellaneous 1 — — — — 1 Total liability $ 2,701 $ 149 $ (8) $ 134 $ (92) $ 2,884 (a) Amounts incurred related to the wind farms placed in service in 2020 for NSP-Minnesota (Blazing Star 1, Crowned Ridge 2, Jeffers and Community Wind North), PSCo (Cheyenne Ridge) and SPS (Sagamore). (b) Amounts settled primarily related to closure of certain ash containment facilities, removal of wind facilities and asbestos abatement projects. (c) In 2020, AROs were revised for changes in timing and estimates of cash flows. Revisions in the nuclear AROs were driven by reductions in spent fuel cooling time requirements in the nuclear triennial filing coupled with decreasing interest rates. Changes in wind AROs were driven by new dismantling studies. Revisions in steam, hydro and other production AROs were primarily related to changes in cost estimates for remediation of ash containment facilities.
Assets held in external decommissioning trust	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) 2021 2020 Estimated decommissioning cost obligation from most recently approved study (in 2014 dollars) $ 3,012 $ 3,012 Effect of escalating costs 1,006 844 Estimated decommissioning cost obligation (in current dollars) 4,018 3,856 Effect of escalating costs to payment date 7,187 7,349 Estimated future decommissioning costs (undiscounted) 11,205 11,205 Effect of discounting obligation (using average risk-free interest rate of 1.96% and 1.64% for 2021 and 2020, respectively) (4,651) (4,181) Discounted decommissioning cost obligation $ 6,554 $ 7,024 Assets held in external decommissioning trust $ 3,256 $ 2,777 Underfunding of external decommissioning fund compared to the discounted decommissioning obligation 3,298 4,247
Funded Status of Nuclear Decommissioning Obligation [Table Text Block]	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) 2021 2020 Estimated decommissioning cost obligation from most recently approved study (in 2014 dollars) $ 3,012 $ 3,012 Effect of escalating costs 1,006 844 Estimated decommissioning cost obligation (in current dollars) 4,018 3,856 Effect of escalating costs to payment date 7,187 7,349 Estimated future decommissioning costs (undiscounted) 11,205 11,205 Effect of discounting obligation (using average risk-free interest rate of 1.96% and 1.64% for 2021 and 2020, respectively) (4,651) (4,181) Discounted decommissioning cost obligation $ 6,554 $ 7,024 Assets held in external decommissioning trust $ 3,256 $ 2,777 Underfunding of external decommissioning fund compared to the discounted decommissioning obligation 3,298 4,247
Assets and Liabilities, Lessee [Table Text Block]	Operating lease ROU assets: (Millions of Dollars) Dec. 31, 2021 Dec. 31, 2020 PPAs $ 1,656 $ 1,650 Other 225 212 Gross operating lease ROU assets 1,881 1,862 Accumulated amortization (590) (372) Net operating lease ROU assets $ 1,291 $ 1,490 Finance lease ROU assets: (Millions of Dollars) Dec. 31, 2021 Dec. 31, 2020 Gas storage facilities $ 201 $ 201 Gas pipeline 21 21 Gross finance lease ROU assets 222 222 Accumulated amortization (97) (90) Net finance lease ROU assets $ 125 $ 132
Lease, Cost [Table Text Block]	Components of lease expense: (Millions of Dollars) 2021 2020 2019 Operating leases PPA capacity payments $ 251 $ 238 $ 221 Other operating leases (a) 36 26 34 Total operating lease expense (b) $ 287 $ 264 $ 255 Finance leases Amortization of ROU assets $ 7 $ 7 $ 6 Interest expense on lease liability 17 18 19 Total finance lease expense $ 24 $ 25 $ 25 (a) Includes short-term lease expense of $5 million for 2021, 2020 and 2019.
Finance Lease, Liability, Maturity [Table Text Block]	Commitments under operating and finance leases as of Dec. 31, 2021: (Millions of Dollars) PPA (a) (b) Operating Leases Other Operating Leases Total Leases Finance Leases (c) 2022 $ 229 $ 27 $ 256 $ 12 2023 221 26 247 12 2024 209 22 231 12 2025 189 16 205 10 2026 146 12 158 9 Thereafter 416 81 497 187 Total minimum obligation 1,410 184 1,594 242 Interest component of obligation (209) (34) (243) (170) Present value of minimum obligation $ 1,201 150 1,351 72 Less current portion (205) (3) Noncurrent operating and finance lease liabilities $ 1,146 $ 69 Weighted-average remaining lease term in years 8.9 36.1 (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 2039. (c) Excludes certain amounts related to Xcel Energy’s 50% ownership interest in WYCO.
Estimated Future Payments for Capacity and Energy Pursuant to Purchased Power Agreements	At Dec. 31, 2021, 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) 2022 $ 75 $ 165 2023 77 169 2024 72 174 2025 29 53 2026 12 10 Thereafter 12 38 Total $ 277 $ 609 (a) Excludes contingent energy payments for renewable energy PPAs.
Estimated Minimum Purchases Under Fuel Contracts	Estimated minimum purchases under these contracts as of Dec. 31, 2021: (Millions of Dollars) Coal Nuclear fuel Natural gas supply Natural gas supply and transportation 2022 $ 620 $ 89 $ 477 $ 292 2023 233 109 75 224 2024 147 82 4 172 2025 29 119 — 156 2026 31 29 — 149 Thereafter 34 309 — 571 Total $ 1,094 $ 737 $ 556 $ 1,564
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, 2021 Dec. 31, 2020 Current assets $ 7 $ 7 Property, plant and equipment, net 37 38 Other noncurrent assets 1 1 Total assets $ 45 $ 46 Current liabilities $ 7 $ 8 Mortgages and other long-term debt payable 27 25 Other noncurrent liabilities 1 1 Total liabilities $ 35 $ 34
Reconciliation of discounted decommissioning cost obligation - regulated basis to the ARO recordfed in	Reconciliation of the discounted decommissioning cost obligation - regulated basis to the ARO recorded in accordance with GAAP: (Millions of Dollars) 2021 2020 Discounted decommissioning cost obligation - regulated basis $ 6,554 $ 7,024 Differences in discount rate and market risk premium (2,209) (2,628) O&M costs not included for GAAP (1,584) (1,734) ARO differences between 2020 and 2014 cost studies (705) (705) Nuclear production decommissioning ARO - GAAP $ 2,056 $ 1,957
Nuclear Decommissioning Expenses Recognized as Result of Regulation	Decommissioning expenses recognized as a result of regulation: (Millions of Dollars) 2021 2020 2019 Annual decommissioning recorded as depreciation expense: (a) (b) $ 22 $ 20 $ 20 (a) Decommissioning expense does not include depreciation of the capitalized nuclear asset retirement costs. (b) Decommissioning expenses in 2021, 2020 and 2019 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, 2021
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: 2021 (Millions of Dollars) Gains and Losses on Cash Flow Hedges Defined Benefit Pension and Postretirement Items Total Accumulated other comprehensive loss at Jan. 1 $ (85) $ (56) $ (141) Other comprehensive loss before reclassifications (net of taxes of $1 and $—, respectively) 4 — 4 Losses reclassified from net accumulated other comprehensive loss: Interest rate derivatives (net of taxes of $2 and $—, respectively) 6 (a) — 6 Amortization of net actuarial loss (net of taxes of $— and $3, respectively) — 8 (b) 8 Net current period other comprehensive income 10 8 18 Accumulated other comprehensive loss at Dec. 31 $ (75) $ (48) $ (123) (a) Included in interest charges. (b) Included in the computation of net periodic pension and postretirement benefit costs. See Note 11 for further information. 2020 (Millions of Dollars) Gains and Losses on Cash Flow Hedges Defined Benefit Pension and Postretirement Items Total Accumulated other comprehensive loss at Jan. 1 $ (80) $ (61) $ (141) Other comprehensive loss before reclassifications (net of taxes of $(3) and $(2), respectively) (10) (5) (15) Losses reclassified from net accumulated other comprehensive loss: Interest rate derivatives (net of taxes of $2 and $—, respectively) 5 (a) — 5 Amortization of net actuarial loss (net of taxes of $— and $3, respectively) — 10 (b) 10 Net current period other comprehensive (loss) income (5) 5 — Accumulated other comprehensive loss at Dec. 31 $ (85) $ (56) $ (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.

Segments and Related Informat_2

Segments and Related Information (Tables)	12 Months Ended
	Dec. 31, 2021
Segment Reporting [Abstract]
Results from Operations by Reportable Segment	Xcel Energy’s segment information: (Millions of Dollars) 2021 2020 2019 Regulated Electric Operating revenues — external $ 11,205 $ 9,802 $ 9,575 Intersegment revenue 2 2 1 Total revenues $ 11,207 $ 9,804 $ 9,576 Depreciation and amortization 1,855 1,673 1,535 Interest charges and financing costs 568 534 500 Income tax (benefit) expense (96) 1 125 Net income 1,478 1,407 1,288 Regulated Natural Gas Operating revenues — external $ 2,132 $ 1,636 $ 1,868 Intersegment revenue 2 1 2 Total revenues $ 2,134 $ 1,637 $ 1,870 Depreciation and amortization 254 252 219 Interest charges and financing costs 75 71 69 Income tax expense 54 17 48 Net income 231 190 195 All Other Total revenues $ 94 $ 88 $ 86 Depreciation and amortization 12 23 11 Interest charges and financing costs 173 193 167 Income tax benefit (28) (24) (45) Net loss (112) (124) (111) Consolidated Total Total revenues $ 13,435 $ 11,529 $ 11,532 Reconciling eliminations (4) (3) (3) Total operating revenues $ 13,431 $ 11,526 $ 11,529 Depreciation and amortization 2,121 1,948 1,765 Interest charges and financing costs 816 798 736 Income tax (benefit) expense (70) (6) 128 Net income 1,597 1,473 1,372

Summarized Quarterly Financia_2

Summarized Quarterly Financial Data (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2021
Quarterly Financial Information Disclosure [Abstract]
Summarized Quarterly Financial Data (Unaudited)	Quarter Ended (Amounts in millions, except per share data) March 31, 2021 June 30, 2021 Sept. 30, 2021 Dec. 31, 2021 Operating revenues $ 2,811 $ 2,586 $ 3,182 $ 2,947 Operating income 455 422 813 426 Net income 295 287 603 288 EPS total — basic $ 0.56 $ 0.54 $ 1.15 $ 0.54 EPS total — diluted 0.56 0.54 1.14 0.54 Cash dividends declared per common share 0.43 0.43 0.43 0.43 Quarter Ended (Amounts in millions, except per share data) March 31, 2020 June 30, 2020 Sept. 30, 2020 Dec. 31, 2020 Operating revenues $ 2,811 $ 2,586 $ 3,182 $ 2,947 Operating income 455 422 813 426 Net income 295 287 603 288 EPS total — basic $ 0.56 $ 0.54 $ 1.15 $ 0.54 EPS total — diluted 0.56 0.54 1.14 0.54 Cash dividends declared per common share 0.43 0.43 0.43 0.43

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, 2021
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) 2021 2020 2019 2021 2020 2019 Balance at Jan. 1 $ 79 $ 55 $ 55 $ 64 $ 67 $ 79 Additions charged to costs and expenses 60 60 42 5 6 9 Additions charged to other accounts 14 (a) 12 (a) 16 (a) — — — Deductions from reserves (47) (b) (48) (b) (58) (b) (5) (d) (9) (c) (21) (d) Balance at Dec. 31 $ 106 $ 79 $ 55 $ 64 $ 64 $ 67 (a) Recovery of amounts previously written-off. (b) Deductions related primarily to bad debt write-offs. (c) Primarily the reduction of valuation allowances for North Dakota ITC, net of federal income tax benefit, that is offset to a regulatory liability forecasted to be used prior to expiration along with valuation allowances that expired.

Summary of Significant Accoun_4

Summary of Significant Accounting Policies Summary of Significant Accounting Policies (Details) - USD ($)	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Property, Plant and Equipment [Abstract]
Depreciation expense expressed as a percentage of average depreciable property	3.50%	3.40%	3.30%
Nuclear Decommissioning [Abstract]
Studies time periods	$ 3
Cash and Cash Equivalents [Abstract]
maturity period	3
Accounts, Notes, Loans and Financing Receivable
Allowance for bad debts	106,000,000	$ 79,000,000
Alternative Revenue Programs [Abstract]
maximum number of months following end of annual period in which revenues are earned to be included in	24
Inventories	631,000,000	535,000,000
Supplies [Member]
Inventories	289,000,000	275,000,000
Public Utilities, Inventory, Fuel [Member]
Inventories	182,000,000	176,000,000
Public Utilities, Inventory, Natural Gas [Member]
Inventories	$ 160,000,000	$ 84,000,000

Accounting Pronouncements - Rec

Accounting Pronouncements - Recently Adopted (Details) - USD ($) $ in Millions	Jan. 01, 2020	Dec. 31, 2020
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Credit Losses, Topic 326 (ASC Topic 326)		$ (2)
Retained Earnings
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Credit Losses, Topic 326 (ASC Topic 326)	$ 2	$ (2)

Property Plant and Equipment Ma

Property Plant and Equipment Major classes of property, plant and equipment (Details) - USD ($) $ in Millions		Dec. 31, 2021	Dec. 31, 2020
Property, Plant and Equipment [Line Items]
Property, plant and equipment		$ 62,209	$ 59,296
Accumulated depreciation and amortization		(17,060)	(16,657)
Property, plant and equipment, net		45,457	42,950
Electric plant
Property, Plant and Equipment [Line Items]
Property, plant and equipment		48,680	47,104
Natural gas plant
Property, Plant and Equipment [Line Items]
Property, plant and equipment		7,758	7,135
Common and other property
Property, Plant and Equipment [Line Items]
Property, plant and equipment		2,602	2,503
Plant to be retired
Property, Plant and Equipment [Line Items]
Property, plant and equipment	[1]	1,200	677
CWIP
Property, Plant and Equipment [Line Items]
Property, plant and equipment		1,969	1,877
Nuclear fuel
Property, Plant and Equipment [Line Items]
Property, plant and equipment		3,081	2,970
Accumulated depreciation and amortization		$ (2,773)	$ (2,659)
[1]	Includes regulator-approved retirements of Comanche Units 1 and 2 and jointly owned Craig Unit 1 for PSCo, and Sherco Units 1, 2 and 3 and A.S. King for NSP-Minnesota. Also includes SPS’ expected retirement of Tolk and conversion of Harrington to natural gas, and PSCo’s planned retirement of jointly owned Craig Unit 2.

Property Plant and Equipment Jo

Property Plant and Equipment Joint Ownership of Generation, Transmission and Gas Facilities (Details) $ in Millions	Dec. 31, 2021USD ($)
NSP Minnesota
Jointly Owned Utility Plant Interests [Line Items]
Plant in Service	$ 1,814	[1]
Accumulated Depreciation	694	[1]
CWIP	7
NSP Minnesota | Electric Generation | Sherco Unit 3
Jointly Owned Utility Plant Interests [Line Items]
Plant in Service	620
Accumulated Depreciation	$ 451
Percent Owned	59.00%
NSP Minnesota | Electric Generation | Sherco Common Facilities
Jointly Owned Utility Plant Interests [Line Items]
Plant in Service	$ 178
Accumulated Depreciation	$ 108
Percent Owned	80.00%
NSP Minnesota | Electric Generation | Sherco substation
Jointly Owned Utility Plant Interests [Line Items]
Plant in Service	$ 5
Accumulated Depreciation	$ 4
Percent Owned	59.00%
NSP Minnesota | Electric Transmission | Grand Meadow
Jointly Owned Utility Plant Interests [Line Items]
Plant in Service	$ 11
Accumulated Depreciation	$ 3
Percent Owned	50.00%
NSP Minnesota | Electric Transmission | Huntley Wilmarth
Jointly Owned Utility Plant Interests [Line Items]
Plant in Service	$ 48
Accumulated Depreciation	$ 1
Percent Owned	50.00%
NSP Minnesota | Electric Transmission | CapX2020
Jointly Owned Utility Plant Interests [Line Items]
Plant in Service	$ 952
Accumulated Depreciation	$ 127
Percent Owned	51.00%
NSP-Wisconsin
Jointly Owned Utility Plant Interests [Line Items]
Plant in Service	$ 346	[2]
Accumulated Depreciation	43	[2]
CWIP	2
NSP-Wisconsin | Electric Transmission | CapX2020
Jointly Owned Utility Plant Interests [Line Items]
Plant in Service	169
Accumulated Depreciation	$ 28
Percent Owned	80.00%
NSP-Wisconsin | Electric Transmission | La Crosse, WI to Madison, WI
Jointly Owned Utility Plant Interests [Line Items]
Plant in Service	$ 177
Accumulated Depreciation	$ 15
Percent Owned	37.00%
PSCo
Jointly Owned Utility Plant Interests [Line Items]
Plant in Service	$ 1,626	[3]
Accumulated Depreciation	506	[3]
CWIP	4
PSCo | Electric Generation | Hayden Unit 1
Jointly Owned Utility Plant Interests [Line Items]
Plant in Service	156
Accumulated Depreciation	$ 99
Percent Owned	76.00%
PSCo | Electric Generation | Hayden Unit 2
Jointly Owned Utility Plant Interests [Line Items]
Plant in Service	$ 151
Accumulated Depreciation	$ 78
Percent Owned	37.00%
PSCo | Electric Generation | Hayden Common Facilities
Jointly Owned Utility Plant Interests [Line Items]
Plant in Service	$ 42
Accumulated Depreciation	$ 27
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	$ 48
Percent Owned	10.00%
PSCo | Electric Generation | Craig Common Facilities
Jointly Owned Utility Plant Interests [Line Items]
Plant in Service	$ 39
Accumulated Depreciation	$ 25
Percent Owned	7.00%
PSCo | Electric Generation | Comanche Unit 3
Jointly Owned Utility Plant Interests [Line Items]
Plant in Service	$ 917
Accumulated Depreciation	$ 154
Percent Owned	67.00%
PSCo | Electric Generation | Comanche Common Facilities
Jointly Owned Utility Plant Interests [Line Items]
Plant in Service	$ 28
Accumulated Depreciation	$ 2
Percent Owned	82.00%
PSCo | Electric Transmission | Transmission and other facilities
Jointly Owned Utility Plant Interests [Line Items]
Plant in Service	$ 182
Accumulated Depreciation	63
PSCo | Gas Transportation | Rifle, CO to Avon, CO
Jointly Owned Utility Plant Interests [Line Items]
Plant in Service	22
Accumulated Depreciation	$ 8
Percent Owned	60.00%
PSCo | Gas Transportation | Gas Transportation Compressor
Jointly Owned Utility Plant Interests [Line Items]
Plant in Service	$ 8
Accumulated Depreciation	$ 2
Percent Owned	50.00%
[1]	Projects additionally include $7 million in CWIP.
[2]	Projects additionally include $2 million in CWIP.
[3]	Projects additionally include $4 million in CWIP.

Regulatory Assets and Liabili_3

Regulatory Assets and Liabilities, Regulatory Assets (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2021	Dec. 31, 2020
Regulatory Assets [Line Items]
Regulatory Asset, Current		$ 1,106	$ 640
Regulatory Asset, Noncurrent		2,738	2,737
Regulatory assets not currently earning a return		1,718	812
Pension and retiree medical obligations
Regulatory Assets [Line Items]
Regulatory Asset, Current		77	82
Regulatory Asset, Noncurrent		944	1,268
Deferred purchased natural gas and electric energy costs
Regulatory Assets [Line Items]
Regulatory Asset, Current		504	14
Regulatory Asset, Noncurrent		$ 543	18
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		5 years
Recoverable deferred taxes on AFUDC recorded in plant
Regulatory Assets [Line Items]
Regulatory Asset, Current		$ 0	0
Regulatory Asset, Noncurrent		289	283
Excess deferred taxes - TCJA
Regulatory Assets [Line Items]
Regulatory Asset, Current		14	16
Regulatory Asset, Noncurrent		219	229
Depreciation differences
Regulatory Assets [Line Items]
Regulatory Asset, Current		16	16
Regulatory Asset, Noncurrent		$ 173	154
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		10 years
Environmental remediation costs
Regulatory Assets [Line Items]
Regulatory Asset, Current		$ 14	16
Regulatory Asset, Noncurrent		92	113
Texas revenue surcharges
Regulatory Assets [Line Items]
Regulatory Asset, Current		20	54
Regulatory Asset, Noncurrent		$ 64	17
Texas revenue surcharges | Minimum
Regulatory Assets [Line Items]
Regulatory Asset, Remaining Amortization Period		1 year
Texas revenue surcharges | Maximum
Regulatory Assets [Line Items]
Regulatory Asset, Remaining Amortization Period		2 years
Sales true-up and revenue decoupling
Regulatory Assets [Line Items]
Regulatory Asset, Current		$ 33	101
Regulatory Asset, Noncurrent		$ 56	28
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
Benson Biomass PPA termination and asset purchase
Regulatory Assets [Line Items]
Regulatory Asset, Current		$ 10	10
Regulatory Asset, Noncurrent		$ 55	65
Regulatory Asset, Remaining Amortization Period		8 years
Renewable resources and environmental initiatives
Regulatory Assets [Line Items]
Regulatory Asset, Current		$ 170	129
Regulatory Asset, Noncurrent		$ 48	12
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
PI extended power update
Regulatory Assets [Line Items]
Regulatory Asset, Current		$ 4	3
Regulatory Asset, Noncurrent		$ 46	49
Regulatory Asset, Remaining Amortization Period		13 years
Purchased power contract costs
Regulatory Assets [Line Items]
Regulatory Asset, Current		$ 9	7
Regulatory Asset, Noncurrent		45	54
Conservation programs
Regulatory Assets [Line Items]
Regulatory Asset, Current	[1]	21	26
Regulatory Asset, Noncurrent	[1]	$ 35	36
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
Losses on reacquired debt
Regulatory Assets [Line Items]
Regulatory Asset, Current		$ 3	4
Regulatory Asset, Noncurrent		35	38
Contract valuation adjustments
Regulatory Assets [Line Items]
Regulatory Asset, Current	[2]	22	23
Regulatory Asset, Noncurrent	[2]	34	48
State commission adjustments
Regulatory Assets [Line Items]
Regulatory Asset, Current		1	1
Regulatory Asset, Noncurrent		32	32
Laurentian biomass PPA termination
Regulatory Assets [Line Items]
Regulatory Asset, Current		18	18
Regulatory Asset, Noncurrent		$ 18	36
Regulatory Asset, Remaining Amortization Period		2 years
Nuclear refueling outage costs
Regulatory Assets [Line Items]
Regulatory Asset, Current		$ 37	28
Regulatory Asset, Noncurrent		$ 16	10
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
Property tax
Regulatory Assets [Line Items]
Regulatory Asset, Current		$ 16	16
Regulatory Asset, Noncurrent		16	21
Gas pipeline inspection and remediation costs
Regulatory Assets [Line Items]
Regulatory Asset, Current		33	26
Regulatory Asset, Noncurrent		$ 12	9
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
Net AROs
Regulatory Assets [Line Items]
Regulatory Asset, Current	[3]	$ 0	0
Regulatory Asset, Noncurrent	[3]	(112)	139
Other
Regulatory Assets [Line Items]
Regulatory Asset, Current		84	50
Regulatory Asset, Noncurrent		$ 78	$ 78
[1]	Includes costs for conservation programs, as well as incentives allowed in certain jurisdictions.
[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 amounts recorded for future recovery of AROs, less amounts recovered through nuclear decommissioning accruals and gains from decommissioning investments.

Regulatory Assets and Liabili_4

Regulatory Assets and Liabilities, Regulatory Liabilities (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2021	Dec. 31, 2020
Regulatory Liabilities [Line Items]
Regulatory Liability, Current	[1]	$ 271	$ 311
Regulatory Liability, Noncurrent	[1]	5,405	5,302
Regulatory assets not currently earning a return		1,718	812
Other Current Liabilities
Regulatory Liabilities [Line Items]
Entity's Recorded Provision for Revenue Subject To Refund		17	17
Deferred income tax adjustment and TCJA refunds
Regulatory Liabilities [Line Items]
Regulatory Liability, Current	[2]	26	20
Regulatory Liability, Noncurrent	[2]	3,230	3,368
Plant removal costs
Regulatory Liabilities [Line Items]
Regulatory Liability, Current		0	0
Regulatory Liability, Noncurrent		1,655	1,520
Effects of regulation on employee benefit costs
Regulatory Liabilities [Line Items]
Regulatory Liability, Current	[3]	0	0
Regulatory Liability, Noncurrent	[3]	235	221
Renewable resources and environmental initiatives
Regulatory Liabilities [Line Items]
Regulatory Liability, Current		1	5
Regulatory Liability, Noncurrent		101	59
ITC deferrals
Regulatory Liabilities [Line Items]
Regulatory Liability, Current		0	0
Regulatory Liability, Noncurrent		53	51
Sales true-up and revenue decoupling
Regulatory Liabilities [Line Items]
Regulatory Liability, Current		9	10
Regulatory Liability, Noncurrent		$ 41	41
Sales true-up and revenue decoupling | Minimum
Regulatory Liabilities [Line Items]
Regulatory Liability, Amortization Period		1 year
Sales true-up and revenue decoupling | Maximum
Regulatory Liabilities [Line Items]
Regulatory Liability, Amortization Period		2 years
Contract valuation adjustments
Regulatory Liabilities [Line Items]
Regulatory Liability, Current	[4]	$ 56	19
Regulatory Liability, Noncurrent	[4]	$ 1	0
Contract valuation adjustments | Minimum
Regulatory Liabilities [Line Items]
Regulatory Liability, Amortization Period		1 year
Contract valuation adjustments | Maximum
Regulatory Liabilities [Line Items]
Regulatory Liability, Amortization Period		3 years
Deferred electric, natural gas and steam production costs
Regulatory Liabilities [Line Items]
Regulatory Liability, Current		$ 50	84
Regulatory Liability, Noncurrent		0	0
Conservation programs
Regulatory Liabilities [Line Items]
Regulatory Liability, Current	[5]	42	49
Regulatory Liability, Noncurrent	[5]	0	0
DOE settlement
Regulatory Liabilities [Line Items]
Regulatory Liability, Current		14	23
Regulatory Liability, Noncurrent		14	0
Other
Regulatory Liabilities [Line Items]
Regulatory Liability, Current		73	101
Regulatory Liability, Noncurrent		$ 75	$ 42
[1]	Revenue subject to refund of $17 million for both 2021 and 2020 is included in other current liabilities.
[2]	Includes the revaluation of recoverable/regulated plant accumulated deferred income taxes and revaluation impact of non-plant accumulated deferred income taxes 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 the fair value of certain long-term PPAs used to meet energy capacity requirements and valuation adjustments on natural gas commodity purchases.
[5]	Includes costs for conservation programs, as well as incentives allowed in certain jurisdictions.

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, 2021	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Short-term Debt [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	$ 75	$ 75
Amount outstanding at period end	1,005	1,005	$ 584
Commercial Paper
Short-term Debt [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	3,100	3,100	3,100	$ 3,600
Amount outstanding at period end	1,005	1,005	584	595
Average amount outstanding	1,200	1,399	1,126	1,115
Maximum amount outstanding	$ 1,774	$ 2,054	$ 2,080	$ 1,780
Weighted average interest rate, computed on a daily basis (percentage)	0.54%	0.57%	1.45%	2.72%
Weighted average interest rate at period end (percentage)	0.31%	0.31%	0.23%	2.34%

Borrowings and Other Financin_4

Borrowings and Other Financing Instruments Term Loan Agreement (Details) - USD ($) $ in Millions	Feb. 17, 2021	Dec. 31, 2021	Dec. 31, 2020
Short-term Debt [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity		$ 75
Amount outstanding at period end		1,005	$ 584
364-Day Term Loan
Short-term Debt [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity		1,200
Expiration Period, Line of Credit	364 days
Expiration Period, Line of Credit	364 days
Xcel Energy Inc.
Short-term Debt [Line Items]
Amount outstanding at period end		$ 638	$ 0

Borrowings and Other Financin_5

Borrowings and Other Financing Instruments Bilateral Credit Agreement (Details) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Short-term Debt [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	$ 75
Amount outstanding at period end	1,005	$ 584
Letter of Credit
Short-term Debt [Line Items]
Amount outstanding at period end	20	$ 20
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	$ 45

Borrowings and Other Financin_6

Borrowings and Other Financing Instruments Letters of Credit (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2021	Dec. 31, 2020
Line of Credit Facility [Line Items]
Amount outstanding at period end		$ 1,005	$ 584
Line of Credit Facility, Maximum Borrowing Capacity		75
Xcel Energy Inc.
Line of Credit Facility [Line Items]
Amount outstanding at period end		$ 638	$ 0
Letter of Credit
Line of Credit Facility [Line Items]
Line of Credit Facility, Expiration Period		1 year
Revolving Credit Facility [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity		$ 3,100
Revolving Credit Facility [Member] | Xcel Energy Inc.
Line of Credit Facility [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	[1]	$ 1,250
[1]	These credit facilities mature in June 2024.

Borrowings and Other Financin_7

Borrowings and Other Financing Instruments Credit Facilities (Details) $ in Millions		12 Months Ended
		Dec. 31, 2021USD ($)	Dec. 31, 2020USD ($)
Line of Credit Facility [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity		$ 75
Amount outstanding at period end		1,005	$ 584
Letter of Credit
Line of Credit Facility [Line Items]
Amount outstanding at period end		20	20
Revolving Credit Facility [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity		3,100
Drawn		1,024
Available		2,076
Direct advances on the credit facility outstanding		0	0
364-Day Term Loan
Line of Credit Facility [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity		$ 1,200
Parent [Member] | Revolving Credit Facility [Member]
Line of Credit Facility [Line Items]
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
Xcel Energy Inc.
Line of Credit Facility [Line Items]
Amount outstanding at period end		638	$ 0
Xcel Energy Inc. | Revolving Credit Facility [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	[1]	1,250
Drawn	[2]	638
Available		$ 612
Xcel Energy Inc. | Revolving Credit Facility [Member]
Line of Credit Facility [Line Items]
Line Of Credit Facility Debt To Total Capitalization Ratio (as a percent)	[3],[4]	60.00%	59.00%
Line Of Credit Facility Maximum Amount Credit Facility May Be Increased	[4]	$ 250
Number Of Additional Periods Revolving Termination Date Can Be Extended Subject To Majority Bank Group Approval	[4],[5]	2
NSP-Wisconsin | Revolving Credit Facility [Member]
Line of Credit Facility [Line Items]
Line Of Credit Facility Debt To Total Capitalization Ratio (as a percent)	[3]	49.00%	46.00%
Number Of Additional Periods Revolving Termination Date Can Be Extended Subject To Majority Bank Group Approval	[5]	1
Line of Credit Facility, Maximum Borrowing Capacity	[1]	$ 150
Drawn	[2]	83
Available		$ 67
NSP Minnesota | Revolving Credit Facility [Member]
Line of Credit Facility [Line Items]
Line Of Credit Facility Debt To Total Capitalization Ratio (as a percent)	[3]	47.00%	47.00%
Line Of Credit Facility Maximum Amount Credit Facility May Be Increased		$ 100
Number Of Additional Periods Revolving Termination Date Can Be Extended Subject To Majority Bank Group Approval	[5]	2
Line of Credit Facility, Maximum Borrowing Capacity	[1]	$ 500
Drawn	[2]	9
Available		$ 491
SPS | Revolving Credit Facility [Member]
Line of Credit Facility [Line Items]
Line Of Credit Facility Debt To Total Capitalization Ratio (as a percent)	[3]	47.00%	48.00%
Line Of Credit Facility Maximum Amount Credit Facility May Be Increased		$ 50
Number Of Additional Periods Revolving Termination Date Can Be Extended Subject To Majority Bank Group Approval	[5]	2
Line of Credit Facility, Maximum Borrowing Capacity	[1]	$ 500
Drawn	[2]	139
Available		$ 361
PSCo | Revolving Credit Facility [Member]
Line of Credit Facility [Line Items]
Line Of Credit Facility Debt To Total Capitalization Ratio (as a percent)	[3]	44.00%	44.00%
Line Of Credit Facility Maximum Amount Credit Facility May Be Increased		$ 100
Number Of Additional Periods Revolving Termination Date Can Be Extended Subject To Majority Bank Group Approval	[5]	2
Line of Credit Facility, Maximum Borrowing Capacity	[1]	$ 700
Drawn	[2]	155
Available		$ 545
[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. would 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, 2021	Dec. 31, 2020
Line of Credit Facility [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity		$ 75
Revolving Credit Facility [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity		3,100
Direct advances on the credit facility outstanding		0	$ 0
Xcel Energy Inc. | Revolving Credit Facility [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	[1]	$ 1,250
[1]	These credit facilities mature in June 2024.

Borrowings and Other Financin_9

Borrowings and Other Financing Instruments Long-Term Borrowings and Other Financing Instruments (Details) - USD ($) $ in Millions		Dec. 31, 2021	Dec. 31, 2020
Long-Term Borrowings and Other Financing Instruments
Long-term Debt, Gross		$ 22,380	$ 20,066
2021		601
2022		1,150
2023		552
2024		1,102
2025		501
NSP Minnesota
Long-Term Borrowings and Other Financing Instruments
Unamortized discount		(44)	(42)
Unamortized Debt Issuance Expense		(62)	(54)
Current Maturities		(300)	0
Long-term Debt		6,447	5,904
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 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, 2025 [Member]
Long-Term Borrowings and Other Financing Instruments
Face Amount		$ 250	250
Debt Instrument, Interest Rate, Stated Percentage		7.125%
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 April 1, 2031
Long-Term Borrowings and Other Financing Instruments
Face Amount		$ 425	0
Debt Instrument, Interest Rate, Stated Percentage		2.25%
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 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		4.125%
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 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 March 1, 2050
Long-Term Borrowings and Other Financing Instruments
Face Amount		$ 600	600
Debt Instrument, Interest Rate, Stated Percentage		2.90%
NSP Minnesota | Mortgage bonds | Series Due June 1, 2051
Long-Term Borrowings and Other Financing Instruments
Face Amount	[1]	$ 700	700
Debt Instrument, Interest Rate, Stated Percentage	[1]	2.60%
NSP Minnesota | Mortgage bonds | Series Due April 1, 2052
Long-Term Borrowings and Other Financing Instruments
Face Amount		$ 425	0
Debt Instrument, Interest Rate, Stated Percentage		3.20%
NSP Minnesota | Long-term Debt
Long-Term Borrowings and Other Financing Instruments
Face Amount		$ 3	0
Other Subsidiaries
Long-Term Borrowings and Other Financing Instruments
Current Maturities		(1)	(2)
Long-term Debt		26	25
Other Subsidiaries | Various Eloigne Co. affordable housing project notes
Long-Term Borrowings and Other Financing Instruments
Long-term Debt, Gross		27	27
Xcel Energy Inc.
Long-Term Borrowings and Other Financing Instruments
Unamortized discount		(8)	(7)
Unamortized Debt Issuance Expense		(33)	(32)
Current Maturities		0	(400)
Long-term Debt		5,139	4,341
Xcel Energy Inc. | Unsecured Debt [Member] | Series Due March 15, 2021 [Member]
Long-Term Borrowings and Other Financing Instruments
Face Amount		$ 0	400
Debt Instrument, Interest Rate, Stated Percentage		2.40%
Xcel Energy Inc. | Unsecured Debt [Member] | Series Due Oct. 15, 2023 [Member]
Long-Term Borrowings and Other Financing Instruments
Face Amount	[2]	$ 500	500
Debt Instrument, Interest Rate, Stated Percentage	[2]	0.50%
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 March 15, 2027
Long-Term Borrowings and Other Financing Instruments
Face Amount	[3]	$ 500	0
Debt Instrument, Interest Rate, Stated Percentage	[3]	1.75%
Xcel Energy Inc. | Unsecured Debt [Member] | Series Due June 15, 2028
Long-Term Borrowings and Other Financing Instruments
Face Amount		$ 130	130
Debt Instrument, Interest Rate, Stated Percentage		4.00%
Xcel Energy Inc. | Unsecured Debt [Member] | Series Due June 15, 2028 2 [Member]
Long-Term Borrowings and Other Financing Instruments
Face Amount		$ 500	500
Debt Instrument, Interest Rate, Stated Percentage		4.00%
Xcel Energy Inc. | Unsecured Debt [Member] | Series Due Dec. 1, 2029 [Member]
Long-Term Borrowings and Other Financing Instruments
Face Amount		$ 500	500
Debt Instrument, Interest Rate, Stated Percentage		2.60%
Xcel Energy Inc. | Unsecured Debt [Member] | Series Due June 1, 2030
Long-Term Borrowings and Other Financing Instruments
Face Amount	[2]	$ 600	600
Debt Instrument, Interest Rate, Stated Percentage	[2]	3.40%
Xcel Energy Inc. | Unsecured Debt [Member] | Series Due Nov. 15, 2031
Long-Term Borrowings and Other Financing Instruments
Face Amount	[3]	$ 300	0
Debt Instrument, Interest Rate, Stated Percentage	[3]	2.35%
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		$ 500	500
Debt Instrument, Interest Rate, Stated Percentage		3.50%
NSP-Wisconsin
Long-Term Borrowings and Other Financing Instruments
Unamortized discount		$ (4)	(4)
Unamortized Debt Issuance Expense		(10)	(9)
Current Maturities		0	(19)
Long-term Debt		987	887
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		6.375%
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 | 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 September 1, 2048 [Member]
Long-Term Borrowings and Other Financing Instruments
Face Amount		$ 200	200
Debt Instrument, Interest Rate, Stated Percentage		4.20%
NSP-Wisconsin | Mortgage bonds | Series Due May 1, 2051
Long-Term Borrowings and Other Financing Instruments
Face Amount	[4]	$ 100	100
Debt Instrument, Interest Rate, Stated Percentage	[4]	3.05%
NSP-Wisconsin | Mortgage bonds | Series Due May 1, 2051 2
Long-Term Borrowings and Other Financing Instruments
Face Amount	[5]	$ 100	0
Debt Instrument, Interest Rate, Stated Percentage	[5]	2.82%
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 | City of La Crosse resource recovery bond | Series Due Nov. 1, 2021 [Member]
Long-Term Borrowings and Other Financing Instruments
Face Amount		$ 0	19
Debt Instrument, Interest Rate, Stated Percentage		6.00%
NSP-Wisconsin | Long-term Debt
Long-Term Borrowings and Other Financing Instruments
Face Amount		$ 1	0
PSCo
Long-Term Borrowings and Other Financing Instruments
Unamortized discount		(33)	(30)
Unamortized Debt Issuance Expense		(50)	(46)
Current Maturities		(300)	0
Long-term Debt		6,167	5,724
PSCo | Mortgage bonds | Series Due June 15, 2028
Long-Term Borrowings and Other Financing Instruments
Face Amount		$ 350	350
Debt Instrument, Interest Rate, Stated Percentage		3.70%
PSCo | Mortgage bonds | Series Due March 1, 2050
Long-Term Borrowings and Other Financing Instruments
Face Amount		$ 550	550
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 Jan. 15, 2031
Long-Term Borrowings and Other Financing Instruments
Face Amount	[6]	$ 375	375
Debt Instrument, Interest Rate, Stated Percentage	[6]	1.90%
PSCo | Mortgage bonds | Series Due June 15, 2031
Long-Term Borrowings and Other Financing Instruments
Face Amount	[7]	$ 750	0
Debt Instrument, Interest Rate, Stated Percentage	[7]	1.875%
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 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 June 15, 2048
Long-Term Borrowings and Other Financing Instruments
Face Amount		$ 350	350
Debt Instrument, Interest Rate, Stated Percentage		4.10%
PSCo | Mortgage bonds | Series Due September 15, 2049
Long-Term Borrowings and Other Financing Instruments
Face Amount		$ 400	400
Debt Instrument, Interest Rate, Stated Percentage		4.05%
PSCo | Mortgage bonds | Series Due Jan. 15, 2051
Long-Term Borrowings and Other Financing Instruments
Face Amount	[6]	$ 375	375
Debt Instrument, Interest Rate, Stated Percentage	[6]	2.70%
SPS
Long-Term Borrowings and Other Financing Instruments
Unamortized discount		$ (9)	(10)
Unamortized Debt Issuance Expense		(28)	(26)
Long-term Debt		3,013	2,764
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 4
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 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 Nov. 15, 2048 [Member]
Long-Term Borrowings and Other Financing Instruments
Face Amount		$ 300	300
Debt Instrument, Interest Rate, Stated Percentage		4.40%
SPS | Mortgage bonds | Series Due June 15, 2049
Long-Term Borrowings and Other Financing Instruments
Face Amount		$ 300	300
Debt Instrument, Interest Rate, Stated Percentage		3.75%
SPS | Mortgage bonds | Series due May 1, 2050
Long-Term Borrowings and Other Financing Instruments
Face Amount	[8]	$ 350	350
Debt Instrument, Interest Rate, Stated Percentage	[8]	3.15%
SPS | Mortgage bonds | Series due May 1, 2050 2
Long-Term Borrowings and Other Financing Instruments
Face Amount	[9]	$ 250	0
Debt Instrument, Interest Rate, Stated Percentage	[9]	3.15%
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]	2020 financing.
[2]	2020 financing
[3]	2021 financing
[4]	2020 financing
[5]	2021 financing
[6]	2020 financing.
[7]	2021 financing
[8]	2020 financing
[9]	2020 financing re-opened in 2021

Borrowings and Other Financi_10

Borrowings and Other Financing Instruments Deferred Financing Costs (Details) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Deferred Financing Costs [Abstract]
Deferred Finance Costs, Noncurrent, Net	$ 184	$ 167

Borrowings and Other Financi_11

Borrowings and Other Financing Instruments Other Equity (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Dividend Reinvestment Program [Line Items]
Proceeds from Issuance of Common Stock	$ 366	$ 727	$ 458

Borrowings and Other Financi_12

Borrowings and Other Financing Instruments Capital Stock (Details) - $ / shares	Dec. 31, 2021	Dec. 31, 2020
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)	544,025,269	537,438,394
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	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_13

Borrowings and Other Financing Instruments Dividend and Other Capital-Related Restrictions (Details) $ in Millions	Dec. 31, 2021USD ($)
NSP Minnesota
Debt Instrument [Line Items]
Equity to total capitalization ratio, low end of range (in hundredths)	47.20%
Equity to total capitalization ratio, high end of range (in hundredths)	57.60%
Equity to total capitalization ratio	52.90%
Unrestricted Retained Earnings Per State Regulatory Commissions Dividend Restrictions	$ 1,558
Capitalization, Short term debt, long term debt and equity	14,321
Maximum total capitalization	15,332
Maximum additional short term debt authorized for issuance	$ 2,300	[1]
Maximum percentage of short term debt to total capitalization (in hundredths)	15.00%
NSP-Wisconsin
Debt Instrument [Line Items]
Minimum calendar year average equity to total capitalization ratio authorized by state commission	52.50%
Equity to total capitalization ratio	52.80%
Unrestricted Retained Earnings Per State Regulatory Commissions Dividend Restrictions	$ 11	[2]
Capitalization, Short term debt, long term debt and equity	2,091	[2]
Maximum additional long term debt authorized for issuance	150
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%	[3]
Equity to total capitalization ratio (excluding short-term debt), high end of range (in hundredths)	55.00%	[3]
Equity to total capitalization ratio (excluding short-term debt) (in hundredths)	54.50%	[3]
Unrestricted Retained Earnings Per State Regulatory Commissions Dividend Restrictions	$ 513	[4]
Capitalization, Short term debt, long term debt and equity	6,615,000	[4]
Maximum additional long term debt authorized for issuance	0
Maximum additional short term debt authorized for issuance	600
PSCo
Debt Instrument [Line Items]
Maximum additional long term debt authorized for issuance	700
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 forecasted levels if its average equity-to-total capitalization ratio falls below the commission authorized level.
[3]	Excludes short-term debt.
[4]	May not pay a dividend that would cause a loss of its investment grade bond rating.

Revenues (Details)

Revenues (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Total revenue from contracts with customers
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers	$ 12,668	$ 10,847	$ 11,032
Total revenue from contracts with customers | Regulated Electric
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers	10,576	9,198	9,144
Total revenue from contracts with customers | Natural Gas
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers	2,010	1,574	1,814
Total revenue from contracts with customers | All Other
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers	82	75	74
Retail
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers	10,315	9,299	9,619
Retail | Residential
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers	4,461	4,083	4,045
Retail | C&I
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers	5,720	5,085	5,440
Retail | Other
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers	134	131	134
Retail | Regulated Electric
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers	8,371	7,787	7,851
Retail | Regulated Electric | Residential
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers	3,194	3,066	2,877
Retail | Regulated Electric | C&I
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers	5,050	4,596	4,844
Retail | Regulated Electric | Other
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers	127	125	130
Retail | Natural Gas
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers	1,862	1,437	1,694
Retail | Natural Gas | Residential
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers	1,222	975	1,127
Retail | Natural Gas | C&I
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers	640	462	567
Retail | Natural Gas | Other
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers	0	0	0
Retail | All Other
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers	82	75	74
Retail | All Other | Residential
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers	45	42	41
Retail | All Other | C&I
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers	30	27	29
Retail | All Other | Other
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers	7	6	4
Wholesale
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers	1,540	759	737
Wholesale | Regulated Electric
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers	1,540	759	737
Wholesale | Natural Gas
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers	0	0	0
Wholesale | All Other
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers	0	0	0
Transmission
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers	604	579	507
Transmission | Regulated Electric
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers	604	579	507
Transmission | Natural Gas
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers	0	0	0
Transmission | All Other
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers	0	0	0
Other
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers	209	210	169
Other | Regulated Electric
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers	61	73	49
Other | Natural Gas
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers	148	137	120
Other | All Other
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers	0	0	0
Alternative revenue and other
Disaggregation of Revenue [Line Items]
Alternative revenue and other	763	679	497
Alternative revenue and other | Regulated Electric
Disaggregation of Revenue [Line Items]
Alternative revenue and other	629	604	431
Alternative revenue and other | Natural Gas
Disaggregation of Revenue [Line Items]
Alternative revenue and other	122	62	54
Alternative revenue and other | All Other
Disaggregation of Revenue [Line Items]
Alternative revenue and other	12	13	12
Total revenues
Disaggregation of Revenue [Line Items]
Total revenues	13,431	11,526	11,529
Total revenues | Regulated Electric
Disaggregation of Revenue [Line Items]
Total revenues	11,205	9,802	9,575
Total revenues | Natural Gas
Disaggregation of Revenue [Line Items]
Total revenues	2,132	1,636	1,868
Total revenues | All Other
Disaggregation of Revenue [Line Items]
Total revenues	$ 94	$ 88	$ 86

Income Taxes (Details)

Income Taxes (Details) $ in Millions	12 Months Ended
	Dec. 31, 2021USD ($)
Income Tax Disclosure [Abstract]
Tax Adjustments, Settlements, and Unusual Provisions	$ 13
Xcel Energy [Member]
Income Tax [Line Items]
Potential Tax Adjustments	0
SPS
Income Tax [Line Items]
Potential Tax Adjustments	$ 0

Income Taxes Federal Audit (Det

Income Taxes Federal Audit (Details) $ in Millions	12 Months Ended
	Dec. 31, 2021USD ($)
Income Tax [Line Items]
Tax Adjustments, Settlements, and Unusual Provisions	$ 13

State Audits (Details)

State Audits (Details)	12 Months Ended
	Dec. 31, 2021USD ($)
SPS
Income Tax [Line Items]
Potential Tax Adjustments	$ 0
WISCONSIN
Income Tax [Line Items]
Potential Tax Adjustments	0
NSP Minnesota
Income Tax [Line Items]
Potential Tax Adjustments	0
Xcel Energy [Member]
Income Tax [Line Items]
Potential Tax Adjustments	$ 0

Income Taxes Unrecognized Tax B

Income Taxes Unrecognized Tax Benefit (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019	Jan. 01, 2021	Jan. 01, 2020	Jan. 01, 2019
Income Tax [Line Items]
Unrecognized tax benefit — Permanent tax positions	$ 47	$ 41
Unrecognized tax benefit — Temporary tax positions	11	11
Total unrecognized tax benefit	58	52	$ 44	$ 52	$ 44	$ 37
Additions based on tax positions related to the current year	5	9	10
Reductions based on tax positions related to the current year	0	2	4
Additions for tax positions of prior years	2	35	1
Reductions for tax positions of prior years	1	34	0
NOL and tax credit carryforwards	36	31
Upper bound of decrease in unrecognized tax benefit that is reasonably possible	28
Payable for interest related to unrecognized tax benefits at Jan. 1	(3)	(3)	0	$ (3)	$ 0	$ 0
Interest expense related to unrecognized tax benefits	0	(3)	0
Unrecognized Tax Benefits, Income Tax Penalties Expense	$ 0	$ 0	$ 0

Income Taxes Other Income Tax M

Income Taxes Other Income Tax Matters (Details) - USD ($) $ in Millions		3 Months Ended	12 Months Ended
		Dec. 31, 2021	Dec. 31, 2021	Dec. 31, 2020		Dec. 31, 2019
Income Tax [Line Items]
Federal NOL carryforward		$ 765	$ 765	$ 0
Federal tax credit carryforwards		1,172	1,172	791
State NOL carryforwards		1,648	1,648	839
Valuation allowances for state NOL carryforwards		(3)	(3)	(4)
State tax credit carryforwards, net of federal detriment (a)	[1]	89	89	89
Valuation allowances for state credit carryforwards, net of federal benefit (b)	[2]	$ (64)	$ (64)	$ (64)
Federal statutory rate			21.00%	21.00%		21.00%
State income tax on pretax income, net of federal tax effect			5.00%	4.90%		4.90%
Wind PTCs			(23.40%)	(15.70%)		(9.40%)
Plant regulatory differences (a)	[3]		(6.20%)	(7.60%)		(5.80%)
Other tax credits, net NOL & tax credit allowances			(1.10%)	(1.20%)		(1.70%)
NOL Carryback		0.00%		(0.90%)		0.00%
Change in unrecognized tax benefits			0.40%	0.50%		0.50%
Other, net			(0.30%)	(1.40%)		(1.00%)
Effective income tax rate			(4.60%)	(0.40%)		8.50%
Total income tax (benefit) expense			$ (70)	$ (6)		$ 128
Deferred tax expense excluding items below			148	237		344
Amortization and adjustments to deferred income taxes on income tax regulatory assets and liabilities			(221)	(247)		(206)
Tax (benefit) expense allocated to other comprehensive income, adoption of ASC Topic 326, and other			(6)	2		5
Deferred tax (benefit) expense		$ (79)	(79)			143
Deferred fuel costs		262	262	(6)	[4]
Operating lease liabilities		1,351	1,351
Total deferred tax assets				(8)
State and Local Jurisdiction [Member]
Income Tax [Line Items]
Federal detriment		24	24	24
Federal Benefit		17	17	17
income tax expense
Income Tax [Line Items]
Current federal tax expense (benefit)			15	(13)		(16)
Current state tax (benefit) expense			(2)	2		4
Current change in unrecognized tax expense			1	18		2
Deferred federal tax (benefit) expense			(183)	(89)		55
Deferred state tax expense			99	91		83
Deferred change in unrecognized tax expense (benefit)			5	(10)		5
Deferred ITCs			(5)	(5)		(5)
Total income tax (benefit) expense			(70)	(6)		$ 128
Net Deferred Tax Liablility [Member]
Income Tax [Line Items]
Federal tax credit carryforwards		1,261	1,261	880	[4]
Deferred ITCs			15	13	[4]
Differences between book and tax bases of property			6,231	5,810	[4]
Operating lease assets		351	351	400	[4]
Regulatory assets		598	598	603	[4]
Pension expense		175	175	176	[4]
Other		93	93	74	[4]
Total deferred tax liabilities		7,710	7,710	7,057	[4]
Regulatory liabilities		780	780	806	[4]
Operating lease liabilities		351	351	400	[4]
NOL carryforward		247	247	37	[4]
NOL and tax credit valuation allowances		(64)	(64)	(64)	[4]
Other employee benefits		119	119	141	[4]
Other		107	107	98	[4]
Total deferred tax assets		2,816	2,816	2,311	[4]
Net deferred tax liability		$ 4,894	$ 4,894	$ 4,746	[4]
[1]	State tax credit carryforwards are net of federal detriment of $24 million as of Dec. 31, 2021 and 2020.
[2]	Valuation allowances for state tax credit carryforwards were net of federal benefit of $17 million as of Dec. 31, 2021 and 2020.
[3]	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.
[4]	Prior periods have been reclassified to conform to current year presentation.

Incentive Plans Including Share

Incentive Plans Including Share-Based Compensation (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Equity Instruments Other than Options, Additional Disclosures [Abstract]
Award Vesting Period (in years)	3 years
Equity Instruments Other than Options Activity [Roll Forward]
Balance at January 1 (in shares)	780
Granted (in shares)	421	411	483
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Forfeited in Period (in shares)	(146)
Vested (in shares)	(392)	(442)	(464)
Dividend equivalents (in shares)	32
Balance at December 31 (in shares)	695	780
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)	$ 55.68
Granted, weighted average grant date fair value (in dollars per share)	66.03	$ 62.92	$ 49.67
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)	$ 61.76
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Fair Value	$ 27	$ 29	$ 29
Vested, weighted average grant date fair value (in dollars per share)	$ 48.91
Dividend equivalents, weighted average grant date fair value (in dollars per share)	58
Balance at December 31, weighted average grant date fair value (in dollars per share)	$ 64.59	$ 55.68
Restricted Stock [Member]
Equity Instruments Other than Options, Additional Disclosures [Abstract]
Award Vesting Period (in years)	3 years
Equity Instruments Other than Options Activity [Roll Forward]
Balance at January 1 (in shares)	15
Granted (in shares)	2	1	13
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Forfeited in Period (in shares)	0
Vested (in shares)	(9)
Dividend equivalents (in shares)	0
Balance at December 31 (in shares)	8	15
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)	$ 56.68
Granted, weighted average grant date fair value (in dollars per share)	61.54	$ 70.26	$ 53.46
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)	70.26
Vested, weighted average grant date fair value (in dollars per share)	49.71
Dividend equivalents, weighted average grant date fair value (in dollars per share)	66.73
Balance at December 31, weighted average grant date fair value (in dollars per share)	$ 67.26	$ 56.68
Service-based awards [Member]
Equity Instruments Other than Options Activity [Roll Forward]
Granted (in shares)	200	200	300

Share-Based Compensation Restri

Share-Based Compensation Restricted Stock (Details) - shares shares in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Granted (in shares)	421	411	483
Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Granted (in shares)	2	1	13

Other Equity Awards (Details)

Other Equity Awards (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Equity Instruments Other than Options Activity [Roll Forward]
Balance at January 1 (in shares)	780
Granted (in shares)	421	411	483
Forfeited (in shares)	(146)
Vested (in shares)	(392)	(442)	(464)
Dividend equivalents (in shares)	32
Balance at December 31 (in shares)	695	780
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)	$ 55.68
Granted, weighted average grant date fair value (in dollars per share)	66.03	$ 62.92	$ 49.67
Forfeited, weighted average grant date fair value (in dollars per share)	61.76
Vested, weighted average grant date fair value (in dollars per share)	48.91
Dividend equivalents, weighted average grant date fair value (in dollars per share)	58
Balance at December 31, weighted average grant date fair value (in dollars per share)	$ 64.59	$ 55.68
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	$ 27	$ 29	$ 29
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)	200	200	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 2015 and 2018 | 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 2015 and 2018 | Performance-based awards [Member] | Maximum
Equity Instruments Other than Options, Additional Disclosures [Abstract]
Percentage payout for performance-based equity awards	200.00%

Stock Equivalent Units (Details

Stock Equivalent Units (Details) - $ / shares	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Equity Instruments Other than Options Activity [Roll Forward]
Balance at January 1 (in shares)	780,000
Granted (in shares)	421,000	411,000	483,000
Dividend equivalents (in shares)	32,000
Balance at December 31 (in shares)	695,000	780,000
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)	$ 55.68
Granted, weighted average grant date fair value (in dollars per share)	66.03	$ 62.92	$ 49.67
Dividend equivalents, weighted average grant date fair value (in dollars per share)	58
Balance at December 31, weighted average grant date fair value (in dollars per share)	$ 64.59	$ 55.68
Stock Equivalent Units [Member]
Equity Instruments Other than Options Activity [Roll Forward]
Balance at January 1 (in shares)	630,000
Granted (in shares)	31,000	33,000	29,000
Units distributed (in shares)	73,000
Dividend equivalents (in shares)	16,000
Balance at December 31 (in shares)	604,000	630,000
Equity Instruments Other than Options, Weighted Average Grant Date Fair Value [Abstract]
Balance at January 1, weighted average grant date fair value (in dollars per share)	$ 36.28
Granted, weighted average grant date fair value (in dollars per share)	68.15	$ 61.61	$ 58.44
Units distributed, weighted average grant date fair value (in dollars per share)	31.47
Dividend equivalents, weighted average grant date fair value (in dollars per share)	66.98
Balance at December 31, weighted average grant date fair value (in dollars per share)	$ 39.27	$ 36.28
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) - USD ($) shares in Thousands, $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Equity Instruments Other than Options Activity [Roll Forward]
Granted (in shares)	421	411	483
Equity Instruments Other than Options, Additional Disclosures [Abstract]
Award Vesting Period (in years)	3 years
TSR Liability Awards
Equity Instruments Other than Options Activity [Roll Forward]
Granted (in shares)	221	212	225
Equity Instruments Other than Options, Additional Disclosures [Abstract]
Award Vesting Period (in years)	3 years
Awards settled (in shares)	446	476	466
Settlement amount (cash and common stock)	$ 27	$ 33	$ 25
Amount of cash used to settle TSR liability awards	$ 22
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, 2021	Dec. 31, 2020	Dec. 31, 2019
Share-Based Compensation Expense [Abstract]
Granted (in shares)		421	411	483
Compensation cost for share-based awards	[1]	$ 31	$ 73	$ 58
Tax benefit recognized in income		8	19	$ 15
Unrecognized compensation cost related to nonvested share-based compensation awards		$ 28	$ 51
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)		200	200	300
[1]	Compensation costs for share-based payments 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, 2021	Dec. 31, 2020	Dec. 31, 2019
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Granted (in shares)	421	411	483
Granted, weighted average grant date fair value (in dollars per share)	$ 66.03	$ 62.92	$ 49.67
Service-based awards [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Granted (in shares)	200	200	300

Common Stock Equivalent (Detail

Common Stock Equivalent (Details) - shares shares in Thousands		12 Months Ended
		Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Earnings Per Share [Abstract]
Weighted Average Number of Shares Outstanding, Basic		539,000	527,000	519,000
Diluted	[1]	540,000	528,000	520,000
Dilutive Effect of Contingently Issuable Shares		300	1,100	1,300
[1]	Diluted common shares outstanding included common stock equivalents of 0.3 million, 1.1 million and 1.3 million shares for 2021, 2020 and 2019, respectively.

Nuclear Decommissioning Fund (D

Nuclear Decommissioning Fund (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021		Dec. 31, 2020
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Equity investments in unconsolidated subsidiaries	$ 208		$ 165
Miscellaneous investments	164		154
Final Contractual Maturity [Abstract]
Due in 1 Year or Less	(4)
Due in 1 to 5 Years	149
Due in 5 to 10 Years	208
Due after 10 Years	314
Total	675
Unrealized Gain on Securities	1,300		981
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	1,962	[1]	1,801	[2]
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	64	[1]	40	[2]
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]
Commingled funds	856	[1]	787	[2]
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	631	[1]	528	[2]
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]
Equity securities	411	[1]	446	[2]
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	1,294	[1]	1,041	[2]
Decommissioning fund investments	3,256		2,777
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	64	[1]	40	[2]
Alternative Investment	0	[1]	0	[2]
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]
Commingled funds	1,294	[1]	1,041	[2]
Alternative Investment	1,294	[1]	1,041	[2]
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]
Debt securities	675	[1]	585	[2]
Alternative Investment	0	[1]	0	[2]
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]
Equity securities	1,223	[1]	1,111	[2]
Alternative Investment	0	[1]	0	[2]
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Decommissioning fund investments	1,286	[1]	1,149	[2]
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	64	[1]	40	[2]
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]
Commingled funds	0	[1]	0	[2]
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	0	[1]	0	[2]
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]
Equity securities	1,222	[1]	1,109	[2]
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Decommissioning fund investments	667	[1]	574	[2]
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	0	[1]	0	[2]
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]
Commingled funds	0	[1]	0	[2]
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	666	[1]	572	[2]
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]
Equity securities	1	[1]	2	[2]
Nuclear Decommissioning Fund | Fair Value Measured on a Recurring Basis | Fair Value | Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Decommissioning fund investments	9	[1]	13	[2]
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	0	[1]	0	[2]
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]
Commingled funds	0	[1]	0	[2]
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	9	[1]	13	[2]
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]
Equity securities	$ 0	[1]	$ 0	[2]
[1]	Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $208 million of equity investments in unconsolidated subsidiaries and $164 million of rabbi trust assets and miscellaneous investments.
[2]	Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $165 million of equity investments in unconsolidated subsidiaries and $154 million of rabbi trust assets and miscellaneous investments.

Rabbi Trusts (Details)

Rabbi Trusts (Details) - Rabbi Trust [Member] - Fair Value Measured on a Recurring Basis - USD ($) $ in Millions	Dec. 31, 2021	[1]	Dec. 31, 2020	[2]
Cost
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total	$ 95		$ 92
Cost | Cash equivalents
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash Equivalents	20		32
Cost | Mutual Fund
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Mutual funds	75		60
Fair Value
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total	109		102
Fair Value | Cash equivalents
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash Equivalents	20		32
Fair Value | Mutual Fund
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Mutual funds	89		70
Fair Value | Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total	109		102
Fair Value | Level 1 | Cash equivalents
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash Equivalents	20		32
Fair Value | Level 1 | Mutual Fund
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Mutual funds	89		70
Fair Value | Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total	0		0
Fair Value | Level 2 | Cash equivalents
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash Equivalents	0		0
Fair Value | Level 2 | Mutual Fund
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Mutual funds	0		0
Fair Value | Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total	0		0
Fair Value | Level 3 | Cash equivalents
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash Equivalents	0		0
Fair Value | Level 3 | Mutual Fund
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Mutual funds	$ 0		$ 0
[1]	Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet.
[2]	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, 2021USD ($)
Interest Rate Derivatives [Abstract]
Interest rate cash low hedge gain (loss) to be reclassified during the next 12 months	$ 5
Derivative Liability, Notional Amount	$ 0

Commodity Derivatives (Details)

Commodity Derivatives (Details) MWh in Millions, MMBTU in Millions, $ in Millions		Dec. 31, 2021USD ($)MMBTUMWh	Dec. 31, 2020MMBTUMWh
Cash Flow Hedges
Derivative [Line Items]
Commodity contracts designated as cash flow hedges | $		$ 0
Electric Commodity
Derivative [Line Items]
Notional Amount | MWh	[1],[2]	80	87
Natural Gas Commodity
Derivative [Line Items]
Notional Amount | MMBTU	[1],[2]	156	175
[1]	Not reflective of net positions in the underlying commodities.
[2]	Notional amounts for options included on a gross basis but weighted for the probability of exercise.

Consideration of Credit Risk an

Consideration of Credit Risk and Concentrations (Details) - Credit Concentration Risk $ in Millions	Dec. 31, 2021USD ($)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	8
External Credit Rating, Investment Grade
Derivative [Line Items]
Number of most significant counterparties	6
Credit exposure for the most significant counterparties | $	$ 83
Percentage of credit exposure for the most significant counterparties	38.00%
Internal Investment Grade
Derivative [Line Items]
Number of most significant counterparties	3
Credit exposure for the most significant counterparties | $	$ 44
Percentage of credit exposure for the most significant counterparties	20.00%
External Credit Rating, Non Investment Grade [Member]
Derivative [Line Items]
Number of most significant counterparties	1
Credit exposure for the most significant counterparties | $	$ 38
Percentage of credit exposure for the most significant counterparties	18.00%

Qualifying Cash Flow Hedges (De

Qualifying Cash Flow Hedges (Details) - USD ($)		12 Months Ended
		Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
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		$ (85,000,000)	$ (80,000,000)	$ (60,000,000)
After-tax net unrealized gains (losses) related to derivatives accounted for as hedges		4,000,000	(10,000,000)	(23,000,000)
After-tax net realized losses on derivative transactions reclassified into earnings		(6,000,000)	(5,000,000)	(3,000,000)
Accumulated other comprehensive loss related to cash flow hedges at Dec. 31		(75,000,000)	(85,000,000)	(80,000,000)
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		28,000,000	(18,000,000)	(1,000,000)
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)		(18,000,000)	(7,000,000)	3,000,000
Derivative, Gain (Loss) on Derivative, Net		41,000,000	(14,000,000)	(5,000,000)
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	[1]	63,000,000	(1,000,000)	2,000,000
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		32,000,000	(5,000,000)	8,000,000
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)	[2]	23,000,000	3,000,000	5,000,000
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		(4,000,000)	(13,000,000)	(9,000,000)
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	10,000,000	(2,000,000)
Derivative, Gain (Loss) on Derivative, Net	[3]	(22,000,000)	(13,000,000)	(7,000,000)
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		5,000,000	(13,000,000)	(30,000,000)
Derivative Instruments Gain (Loss) Reclassified To Regulatory Assets And Liabilities Net		0	0	0
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net		(8,000,000)	(7,000,000)	(4,000,000)
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		5,000,000	(13,000,000)	(30,000,000)
Derivative Instruments Gain (Loss) Reclassified To Regulatory Assets And Liabilities Net		0	0	0
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	[4]	(8,000,000)	(7,000,000)	(4,000,000)
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]	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.
[2]	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
[3]	Settlement losses related to natural gas operations are recorded to cost of natural gas sold and transported. These losses are subject to cost-recovery mechanisms and reclassified out of income to a regulatory asset, as appropriate.
[4]	Recorded to interest charges.

Credit Related Contingent Featu

Credit Related Contingent Features (Details) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Fair Value Disclosures [Abstract]
Derivative instruments in a gross liability position	$ 3	$ 4
Derivative, Gross Liability with Cross Default Position, Aggregate Fair Value	64	60
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, 2021	Dec. 31, 2020	Dec. 31, 2019
Derivatives, Fair Value [Line Items]
Return Cash Collateral		$ 0	$ 15
Reclaim Cash Collateral		30	6
Changes in Level 3 Commodity Derivatives
Unrealized Gain on Securities		1,300	981
Unrealized Loss on Securities		7	5
Commodity Contract
Changes in Level 3 Commodity Derivatives
Balance at Jan. 1		(49)	4	$ 29
Purchases		65	51	44
Settlements		(158)	(73)	(64)
(Losses) gains recognized in earnings		49	(39)	(8)
Net gains recognized as regulatory assets and liabilities		112	8	3
Balance at Dec. 31		19	(49)	4
Transfers Between Levels, Net		0	0	$ 0
Other Current Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Net		123	49
Other Noncurrent Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Net		67	30
Other Current Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Net		69	53
Other Noncurrent Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Net		105	131
Fair Value Measured on a Recurring Basis | Other Current Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Gross		255	99
Netting	[1]	(135)	(53)
Derivative Asset, Net		120	46
Fair Value Measured on a Recurring Basis | Other Current Assets | Level 1
Derivatives, Fair Value [Line Items]
Derivative Asset, Gross		22	2
Fair Value Measured on a Recurring Basis | Other Current Assets | Level 2
Derivatives, Fair Value [Line Items]
Derivative Asset, Gross		155	76
Fair Value Measured on a Recurring Basis | Other Current Assets | Level 3
Derivatives, Fair Value [Line Items]
Derivative Asset, Gross		78	21
Fair Value Measured on a Recurring Basis | Other Current Assets | Other Derivative Instruments | Commodity Contract
Derivatives, Fair Value [Line Items]
Derivative Asset, Gross		180	70
Netting	[1]	(134)	(52)
Derivative Asset, Net		46	18
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		22	2
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		137	67
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		21	1
Fair Value Measured on a Recurring Basis | Other Current Assets | Other Derivative Instruments | Electric Commodity
Derivatives, Fair Value [Line Items]
Derivative Asset, Gross		57	20
Netting	[1]	(1)	(1)
Derivative Asset, Net		56	19
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		57	20
Fair Value Measured on a Recurring Basis | Other Current Assets | Other Derivative Instruments | Natural Gas Commodity
Derivatives, Fair Value [Line Items]
Derivative Asset, Gross		18	9
Netting	[1]	0	0
Derivative Asset, Net		18	9
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		18	9
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		168	82
Netting	[1]	(107)	(62)
Derivative Asset, Net		61	20
Fair Value Measured on a Recurring Basis | Other Noncurrent Assets | Level 1
Derivatives, Fair Value [Line Items]
Derivative Asset, Gross		16	8
Fair Value Measured on a Recurring Basis | Other Noncurrent Assets | Level 2
Derivatives, Fair Value [Line Items]
Derivative Asset, Gross		63	66
Fair Value Measured on a Recurring Basis | Other Noncurrent Assets | Level 3
Derivatives, Fair Value [Line Items]
Derivative Asset, Gross		89	8
Fair Value Measured on a Recurring Basis | Other Noncurrent Assets | Other Derivative Instruments | Commodity Contract
Derivatives, Fair Value [Line Items]
Derivative Asset, Gross		168	82
Netting	[1]	(107)	(62)
Derivative Asset, Net		61	20
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		16	8
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		63	66
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		89	8
Fair Value Measured on a Recurring Basis | Other Current Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Gross		196	95
Netting	[1]	(144)	(59)
Derivative Liability, Net		52	36
Fair Value Measured on a Recurring Basis | Other Current Liabilities | Level 1
Derivatives, Fair Value [Line Items]
Derivative Liability, Gross		19	4
Fair Value Measured on a Recurring Basis | Other Current Liabilities | Level 2
Derivatives, Fair Value [Line Items]
Derivative Liability, Gross		156	73
Fair Value Measured on a Recurring Basis | Other Current Liabilities | Level 3
Derivatives, Fair Value [Line Items]
Derivative Liability, Gross		21	18
Fair Value Measured on a Recurring Basis | Other Current Liabilities | Other Derivative Instruments | Commodity Contract
Derivatives, Fair Value [Line Items]
Derivative Liability, Gross		187	85
Netting	[1]	(143)	(58)
Derivative Liability, Net		44	27
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		19	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		148	64
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		20	17
Fair Value Measured on a Recurring Basis | Other Current Liabilities | Other Derivative Instruments | Electric Commodity
Derivatives, Fair Value [Line Items]
Derivative Liability, Gross		1	1
Netting	[1]	(1)	(1)
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	1
Fair Value Measured on a Recurring Basis | Other Current Liabilities | Other Derivative Instruments | Natural Gas Commodity
Derivatives, Fair Value [Line Items]
Derivative Liability, Gross		8	9
Netting	[1]	0	0
Derivative Liability, Net		8	9
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		8	9
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 Noncurrent Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Gross		193	121
Netting	[1]	(128)	(47)
Derivative Liability, Net		65	74
Fair Value Measured on a Recurring Basis | Other Noncurrent Liabilities | Level 1
Derivatives, Fair Value [Line Items]
Derivative Liability, Gross		18	3
Fair Value Measured on a Recurring Basis | Other Noncurrent Liabilities | Level 2
Derivatives, Fair Value [Line Items]
Derivative Liability, Gross		48	58
Fair Value Measured on a Recurring Basis | Other Noncurrent Liabilities | Level 3
Derivatives, Fair Value [Line Items]
Derivative Liability, Gross		127	60
Fair Value Measured on a Recurring Basis | Other Noncurrent Liabilities | Other Derivative Instruments | Commodity Contract
Derivatives, Fair Value [Line Items]
Derivative Liability, Gross		193	121
Netting	[1]	(128)	(47)
Derivative Liability, Net		65	74
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		18	3
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		48	58
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		127	60
Fair Value, Measurements, Nonrecurring | Other Current Assets | Purchased Power Agreements
Derivatives, Fair Value [Line Items]
Derivative Asset, Net	[2]	3	3
Fair Value, Measurements, Nonrecurring | Other Noncurrent Assets | Purchased Power Agreements
Derivatives, Fair Value [Line Items]
Derivative Asset, Net	[2]	6	10
Fair Value, Measurements, Nonrecurring | Other Current Liabilities | Purchased Power Agreements
Derivatives, Fair Value [Line Items]
Derivative Liability, Net	[2]	17	17
Fair Value, Measurements, Nonrecurring | Other Noncurrent Liabilities | Purchased Power Agreements
Derivatives, Fair Value [Line Items]
Derivative Liability, Net	[2]	$ 40	$ 57
[1]	Xcel Energy nets derivative instruments and related collateral on its consolidated balance sheets 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, 2021 and 2020. At Dec. 31, 2021, derivative assets and liabilities include no obligations to return cash collateral. At Dec. 31, 2020, derivative assets and liabilities include $15 million of obligations to return cash collateral. At Dec. 31, 2021 and 2020, derivative assets and liabilities include rights to reclaim cash collateral of $30 million and $6 million, respectively. Counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements.
[2]	During 2006, Xcel Energy qualified these contracts under the normal purchase exception. Based on this qualification, contracts are no longer adjusted to fair value and the previous carrying value of these contracts is being 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, 2021	Dec. 31, 2020
Financial Liabilities, Balance Sheet Groupings [Abstract]
Long-term Debt, Carrying Amount	$ 22,380	$ 20,066
Long-term debt, Fair Value	$ 25,232	$ 24,412

Pension and Postretirement Heal

Pension and Postretirement Health Care Benefits (Details) - USD ($)		12 Months Ended
		Dec. 31, 2022	Dec. 31, 2021		Dec. 31, 2020		Dec. 31, 2019
Pension Benefits [Abstract]
annual interest crediting rates			$ 2.03		$ 1.89		$ 2.82
Supplemental Executive Retirement Plan (SERP) and Nonqualified Pension Plan
Pension Benefits [Abstract]
Total benefit obligation			43,000,000		43,000,000
Net benefit cost recognized for financial reporting			4,000,000		6,000,000
Pension Plan [Member]
Pension Benefits [Abstract]
Total benefit obligation			3,718,000,000		3,964,000,000		3,701,000,000
Defined Benefit Plan, Plan Assets, Amount			3,670,000,000	[1]	3,599,000,000	[1]	3,184,000,000
Defined Benefit Plan, Alternative Investments, Fair Value Of Plan Assets	[1]		(1,175,000,000)		(1,115,000,000)
Net benefit cost recognized for financial reporting			$ 121,000,000		$ 117,000,000		$ 115,000,000
Expected average long-term rate of return on assets (as a percent)			6.49%		6.87%		6.87%
Target Pension Asset Allocations [Abstract]
Target pension asset allocations (as a percent)			100.00%		100.00%
Pension Plan [Member] | Level 1
Pension Benefits [Abstract]
Defined Benefit Plan, Plan Assets, Amount	[1]		$ 1,524,000,000		$ 1,761,000,000
Pension Plan [Member] | Level 2
Pension Benefits [Abstract]
Defined Benefit Plan, Plan Assets, Amount	[1]		966,000,000		719,000,000
Pension Plan [Member] | Level 3
Pension Benefits [Abstract]
Defined Benefit Plan, Plan Assets, Amount	[1]		5,000,000		4,000,000
Pension Plan [Member] | Equity Securities
Pension Benefits [Abstract]
Defined Benefit Plan, Plan Assets, Amount	[1]		67,000,000		77,000,000
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)			33.00%		35.00%
Pension Plan [Member] | Equity Securities | Level 1
Pension Benefits [Abstract]
Defined Benefit Plan, Plan Assets, Amount	[1]		$ 67,000,000		$ 77,000,000
Pension Plan [Member] | Equity Securities | Level 2
Pension Benefits [Abstract]
Defined Benefit Plan, Plan Assets, Amount	[1]		0		0
Pension Plan [Member] | Equity Securities | Level 3
Pension Benefits [Abstract]
Defined Benefit Plan, Plan Assets, Amount	[1]		$ 0		$ 0
Pension Plan [Member] | Long-duration fixed income and interest rate swap securities
Target Pension Asset Allocations [Abstract]
Target pension asset allocations (as a percent)			37.00%		35.00%
Pension Plan [Member] | Short-to-intermediate fixed income securities
Target Pension Asset Allocations [Abstract]
Target pension asset allocations (as a percent)			11.00%		13.00%
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
Pension Benefits [Abstract]
Defined Benefit Plan, Plan Assets, Amount	[1]		$ 133,000,000		$ 209,000,000
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%
Pension Plan [Member] | Cash | Level 1
Pension Benefits [Abstract]
Defined Benefit Plan, Plan Assets, Amount	[1]		$ 133,000,000		$ 209,000,000
Pension Plan [Member] | Cash | Level 2
Pension Benefits [Abstract]
Defined Benefit Plan, Plan Assets, Amount	[1]		0		0
Pension Plan [Member] | Cash | Level 3
Pension Benefits [Abstract]
Defined Benefit Plan, Plan Assets, Amount	[1]		0		0
Pension Plan [Member] | Commingled Funds
Pension Benefits [Abstract]
Defined Benefit Plan, Plan Assets, Amount	[1]		2,467,000,000		2,577,000,000
Defined Benefit Plan, Alternative Investments, Fair Value Of Plan Assets	[1]		(1,143,000,000)		(1,115,000,000)
Pension Plan [Member] | Commingled Funds | Level 1
Pension Benefits [Abstract]
Defined Benefit Plan, Plan Assets, Amount	[1]		1,324,000,000		1,462,000,000
Pension Plan [Member] | Commingled Funds | Level 2
Pension Benefits [Abstract]
Defined Benefit Plan, Plan Assets, Amount	[1]		0		0
Pension Plan [Member] | Commingled Funds | Level 3
Pension Benefits [Abstract]
Defined Benefit Plan, Plan Assets, Amount	[1]		0		0
Pension Plan [Member] | Debt Securities
Pension Benefits [Abstract]
Defined Benefit Plan, Plan Assets, Amount	[1]		964,000,000		718,000,000
Defined Benefit Plan, Alternative Investments, Fair Value Of Plan Assets	[1]		0		0
Pension Plan [Member] | Debt Securities | Level 1
Pension Benefits [Abstract]
Defined Benefit Plan, Plan Assets, Amount	[1]		0		0
Pension Plan [Member] | Debt Securities | Level 2
Pension Benefits [Abstract]
Defined Benefit Plan, Plan Assets, Amount	[1]		959,000,000		714,000,000
Pension Plan [Member] | Debt Securities | Level 3
Pension Benefits [Abstract]
Defined Benefit Plan, Plan Assets, Amount	[1]		5,000,000		4,000,000
Pension Plan [Member] | Other
Pension Benefits [Abstract]
Defined Benefit Plan, Plan Assets, Amount	[1]		39,000,000		18,000,000
Defined Benefit Plan, Alternative Investments, Fair Value Of Plan Assets	[1]		32,000,000		0
Pension Plan [Member] | Other | Level 1
Pension Benefits [Abstract]
Defined Benefit Plan, Plan Assets, Amount	[1]		0		13,000,000
Pension Plan [Member] | Other | Level 2
Pension Benefits [Abstract]
Defined Benefit Plan, Plan Assets, Amount	[1]		7,000,000		5,000,000
Pension Plan [Member] | Other | Level 3
Pension Benefits [Abstract]
Defined Benefit Plan, Plan Assets, Amount	[1]		0		0
Other Postretirement Benefits Plan [Member]
Pension Benefits [Abstract]
Total benefit obligation			511,000,000		574,000,000		$ 547,000,000
Defined Benefit Plan, Plan Assets, Amount			442,000,000	[2]	452,000,000	[2]	449,000,000
Defined Benefit Plan, Alternative Investments, Fair Value Of Plan Assets	[2]		(77,000,000)		(69,000,000)
Net benefit cost recognized for financial reporting			$ (2,000,000)		$ (1,000,000)		$ (1,000,000)
Expected average long-term rate of return on assets (as a percent)			4.10%		4.50%		4.50%
Target Pension Asset Allocations [Abstract]
Target pension asset allocations (as a percent)			100.00%		100.00%
Other Postretirement Benefits Plan [Member] | Level 1
Pension Benefits [Abstract]
Defined Benefit Plan, Plan Assets, Amount	[2]		$ 92,000,000		$ 99,000,000
Other Postretirement Benefits Plan [Member] | Level 2
Pension Benefits [Abstract]
Defined Benefit Plan, Plan Assets, Amount	[2]		272,000,000		284,000,000
Other Postretirement Benefits Plan [Member] | Level 3
Pension Benefits [Abstract]
Defined Benefit Plan, Plan Assets, Amount	[2]		$ 1,000,000		$ 0
Other Postretirement Benefits Plan [Member] | Equity Securities
Target Pension Asset Allocations [Abstract]
Target pension asset allocations (as a percent)			15.00%		15.00%
Other Postretirement Benefits Plan [Member] | Long-duration fixed income and interest rate swap securities
Target Pension Asset Allocations [Abstract]
Target pension asset allocations (as a percent)			0.00%		0.00%
Other Postretirement Benefits Plan [Member] | Short-to-intermediate fixed income securities
Target Pension Asset Allocations [Abstract]
Target pension asset allocations (as a percent)			71.00%		72.00%
Other Postretirement Benefits Plan [Member] | Alternative investments
Target Pension Asset Allocations [Abstract]
Target pension asset allocations (as a percent)			8.00%		9.00%
Other Postretirement Benefits Plan [Member] | Cash
Pension Benefits [Abstract]
Defined Benefit Plan, Plan Assets, Amount	[2]		$ 28,000,000		$ 27,000,000
Defined Benefit Plan, Alternative Investments, Fair Value Of Plan Assets	[2]		$ 0		$ 0
Target Pension Asset Allocations [Abstract]
Target pension asset allocations (as a percent)			6.00%		4.00%
Other Postretirement Benefits Plan [Member] | Cash | Level 1
Pension Benefits [Abstract]
Defined Benefit Plan, Plan Assets, Amount	[2]		$ 28,000,000		$ 27,000,000
Other Postretirement Benefits Plan [Member] | Cash | Level 2
Pension Benefits [Abstract]
Defined Benefit Plan, Plan Assets, Amount	[2]		0		0
Other Postretirement Benefits Plan [Member] | Cash | Level 3
Pension Benefits [Abstract]
Defined Benefit Plan, Plan Assets, Amount	[2]		0		0
Other Postretirement Benefits Plan [Member] | Commingled Funds
Pension Benefits [Abstract]
Defined Benefit Plan, Plan Assets, Amount	[2]		141,000,000		141,000,000
Defined Benefit Plan, Alternative Investments, Fair Value Of Plan Assets	[2]		(77,000,000)		(69,000,000)
Other Postretirement Benefits Plan [Member] | Commingled Funds | Level 1
Pension Benefits [Abstract]
Defined Benefit Plan, Plan Assets, Amount	[2]		64,000,000		72,000,000
Other Postretirement Benefits Plan [Member] | Commingled Funds | Level 2
Pension Benefits [Abstract]
Defined Benefit Plan, Plan Assets, Amount	[2]		0		0
Other Postretirement Benefits Plan [Member] | Commingled Funds | Level 3
Pension Benefits [Abstract]
Defined Benefit Plan, Plan Assets, Amount	[2]		0		0
Other Postretirement Benefits Plan [Member] | Debt Securities
Pension Benefits [Abstract]
Defined Benefit Plan, Plan Assets, Amount	[2]		219,000,000		232,000,000
Defined Benefit Plan, Alternative Investments, Fair Value Of Plan Assets	[2]		0		0
Other Postretirement Benefits Plan [Member] | Debt Securities | Level 1
Pension Benefits [Abstract]
Defined Benefit Plan, Plan Assets, Amount	[2]		0		0
Other Postretirement Benefits Plan [Member] | Debt Securities | Level 2
Pension Benefits [Abstract]
Defined Benefit Plan, Plan Assets, Amount	[2]		218,000,000		232,000,000
Other Postretirement Benefits Plan [Member] | Debt Securities | Level 3
Pension Benefits [Abstract]
Defined Benefit Plan, Plan Assets, Amount	[2]		1,000,000		0
Other Postretirement Benefits Plan [Member] | Other
Pension Benefits [Abstract]
Defined Benefit Plan, Plan Assets, Amount	[2]		2,000,000		2,000,000
Defined Benefit Plan, Alternative Investments, Fair Value Of Plan Assets	[2]		0		0
Other Postretirement Benefits Plan [Member] | Other | Level 1
Pension Benefits [Abstract]
Defined Benefit Plan, Plan Assets, Amount	[2]		0		0
Other Postretirement Benefits Plan [Member] | Other | Level 2
Pension Benefits [Abstract]
Defined Benefit Plan, Plan Assets, Amount	[2]		2,000,000		2,000,000
Other Postretirement Benefits Plan [Member] | Other | Level 3
Pension Benefits [Abstract]
Defined Benefit Plan, Plan Assets, Amount	[2]		0		0
Other Postretirement Benefits Plan [Member] | Insurance contracts
Pension Benefits [Abstract]
Defined Benefit Plan, Plan Assets, Amount	[2]		52,000,000		50,000,000
Defined Benefit Plan, Alternative Investments, Fair Value Of Plan Assets	[2]		0		0
Other Postretirement Benefits Plan [Member] | Insurance contracts | Level 1
Pension Benefits [Abstract]
Defined Benefit Plan, Plan Assets, Amount	[2]		0		0
Other Postretirement Benefits Plan [Member] | Insurance contracts | Level 2
Pension Benefits [Abstract]
Defined Benefit Plan, Plan Assets, Amount	[2]		52,000,000		50,000,000
Other Postretirement Benefits Plan [Member] | Insurance contracts | Level 3
Pension Benefits [Abstract]
Defined Benefit Plan, Plan Assets, Amount	[2]		$ 0		$ 0
Forecast | Pension Plan [Member]
Pension Benefits [Abstract]
Expected average long-term rate of return on assets for next fiscal year (as a percent)		6.49%
[1]	See Note 10 for further information regarding fair value measurement inputs and methods.
[2]	See Note 10 for further information on fair value measurement inputs and methods.

Funded Status (Details)

Funded Status (Details) - USD ($)		12 Months Ended
		Dec. 31, 2021		Dec. 31, 2020		Dec. 31, 2019
Change in Fair Value of Plan Assets [Roll Forward]
Defined Benefit Plan, Plan Assets, Payment for Settlement		$ 197,000,000		$ 0
Components of Net Periodic Benefit Cost (Credit) [Abstract]
Settlement Charge Recognized in Operating and Maintenance Expenses		2,321,000,000		2,324,000,000		$ 2,338,000,000
Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Accumulated Benefit Obligation at Dec. 31		3,469,000,000		3,693,000,000
Change in Projected Benefit Obligation [Roll Forward]
Obligation at Jan. 1		3,964,000,000		3,701,000,000
Service cost		104,000,000		95,000,000		86,000,000
Interest cost		104,000,000		125,000,000		145,000,000
Plan amendments		5,000,000		0
Actuarial loss		(94,000,000)		328,000,000
Defined Benefit Plan, Benefit Obligation, Contributions by Plan Participant		0		0
Defined Benefit Plan, Benefit Obligation, Prescription Drug Subsidy Receipt		0		0
Benefit payments	[1]	(365,000,000)		(285,000,000)
Obligation at Dec. 31		3,718,000,000		3,964,000,000		3,701,000,000
Change in Fair Value of Plan Assets [Roll Forward]
Fair value of plan assets at Jan. 1		3,599,000,000	[2]	3,184,000,000
Actual return (loss) on plan assets		305,000,000		550,000,000
Employer contributions		131,000,000		150,000,000
Benefit payments		(365,000,000)		(285,000,000)
Fair value of plan assets at Dec. 31		3,670,000,000	[2]	3,599,000,000	[2]	3,184,000,000
Funded Status of Plans at Dec. 31 [Abstract]
Funded status		(48,000,000)		(365,000,000)
Assets for Plan Benefits, Defined Benefit Plan		19,000,000		0
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost [Abstract]
Net loss		978,000,000		1,333,000,000
Prior service (credit) cost		(9,000,000)		(11,000,000)
Total		969,000,000		1,322,000,000
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		74,000,000		82,000,000
Noncurrent regulatory assets		846,000,000		1,181,000,000
Deferred income taxes		13,000,000		15,000,000
Net-of-tax accumulated other comprehensive income		36,000,000		44,000,000
Total		$ 969,000,000		$ 1,322,000,000
Significant Assumptions Used to Measure Benefit Obligations [Abstract]
Discount rate for year-end valuation (as a percent)		3.08%		2.71%
Expected average long-term increase in compensation level (as a percent)		3.75%		3.75%
Components of Net Periodic Benefit Cost (Credit) [Abstract]
Service cost		$ 104,000,000		$ 95,000,000		86,000,000
Interest cost		104,000,000		125,000,000		145,000,000
Expected return on plan assets		(206,000,000)		(208,000,000)		(203,000,000)
Amortization of prior service cost (credit)		(1,000,000)		(4,000,000)		(5,000,000)
Amortization of net loss		107,000,000		100,000,000		87,000,000
Settlement charge	[3]	59,000,000		0		6,000,000
Net periodic benefit cost		167,000,000		108,000,000		116,000,000
Costs not recognized due to regulation		(46,000,000)		9,000,000		(1,000,000)
Net benefit cost recognized for financial reporting		121,000,000		117,000,000		115,000,000
Settlement Charge Recognized in Operating and Maintenance Expenses		$ 7,000,000		$ 0		$ 1
Significant Assumptions Used to Measure Costs [Abstract]
Discount rate (as a percent)		2.71%		3.49%		4.31%
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)		6.49%		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		574,000,000		547,000,000
Service cost		2,000,000		1,000,000		$ 2,000,000
Interest cost		15,000,000		18,000,000		22,000,000
Plan amendments		0		0
Actuarial loss		(41,000,000)		50,000,000
Defined Benefit Plan, Benefit Obligation, Contributions by Plan Participant		8,000,000		8,000,000
Defined Benefit Plan, Benefit Obligation, Prescription Drug Subsidy Receipt		2,000,000		1,000,000
Benefit payments	[1]	(49,000,000)		(51,000,000)
Obligation at Dec. 31		511,000,000		574,000,000		547,000,000
Change in Fair Value of Plan Assets [Roll Forward]
Fair value of plan assets at Jan. 1		452,000,000	[4]	449,000,000
Actual return (loss) on plan assets		16,000,000		35,000,000
Employer contributions		15,000,000		11,000,000
Benefit payments		(49,000,000)		(51,000,000)
Fair value of plan assets at Dec. 31		442,000,000	[4]	452,000,000	[4]	449,000,000
Funded Status of Plans at Dec. 31 [Abstract]
Funded status		(69,000,000)		(122,000,000)
Assets for Plan Benefits, Defined Benefit Plan		33,000,000		6,000,000
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost [Abstract]
Net loss		81,000,000		126,000,000
Prior service (credit) cost		(7,000,000)		(15,000,000)
Total		74,000,000		111,000,000
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		90,000,000		125,000,000
Deferred income taxes		1,000,000		1,000,000
Net-of-tax accumulated other comprehensive income		3,000,000		4,000,000
Total		$ 74,000,000		$ 111,000,000
Significant Assumptions Used to Measure Benefit Obligations [Abstract]
Discount rate for year-end valuation (as a percent)		3.09%		2.65%
Defined Benefit Plan, Health Care Cost Trend Rate Assumed, Pre-65		5.30%		5.50%
Defined Benefit Plan, Health Care Cost Trend Rate Assumed, Post-65		4.90%		5.00%
Components of Net Periodic Benefit Cost (Credit) [Abstract]
Service cost		$ 2,000,000		$ 1,000,000		2,000,000
Interest cost		15,000,000		18,000,000		22,000,000
Expected return on plan assets		(18,000,000)		(19,000,000)		(21,000,000)
Amortization of prior service cost (credit)		(8,000,000)		(8,000,000)		(10,000,000)
Amortization of net loss		5,000,000		4,000,000		5,000,000
Settlement charge	[3]	0		0		0
Net periodic benefit cost		(4,000,000)		(4,000,000)		(2,000,000)
Costs not recognized due to regulation		2,000,000		3,000,000		1,000,000
Net benefit cost recognized for financial reporting		$ (2,000,000)		$ (1,000,000)		$ (1,000,000)
Significant Assumptions Used to Measure Costs [Abstract]
Discount rate (as a percent)		2.65%		3.47%		4.32%
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)		4.10%		4.50%		4.50%
Defined Benefit Plan, Plan Assets, Contributions by Plan Participant		$ 8,000,000		$ 8,000,000
Amounts Not Yet Recognized As Components Of Net Periodic Benefit Cost Recorded As Current Regulatory Liabilities		1,000,000		1,000,000
Amounts Not Yet Recognized As Components Of Net Periodic Benefit Cost Recorded As Noncurrent Regulatory Liabilities		$ 19,000,000		$ 18,000,000
Ultimate health care trend assumption rate (as a percent)		4.50%		4.50%
Period until ultimate trend rate is reached (in years)		$ 4		$ 5
[1]	ncludes approximately $197 million in 2021 and $0 million in 2020 of lump-sum benefit payments used in the determination of a settlement charge.
[2]	See Note 10 for further information regarding fair value measurement inputs and methods.
[3]	A settlement charge is required when the amount of all lump-sum distributions during the year is greater than the sum of the service and interest cost components of the annual net periodic pension cost. In 2021 and 2019, as a result of lump-sum distributions during each plan year, Xcel Energy recorded a total pension settlement charge of $59 million and $6 million, respectively, the majority of which was not recognized due to the effects of regulation. A total of $7 million and $1 million was recorded in the consolidated statements of income in 2021 and 2019, respectively. There were no settlement charges recorded for the qualified pension plans in 2020.
[4]	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 ($)	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Defined Benefit Plan Disclosure [Line Items]
Operating and maintenance expenses	$ 2,321,000,000	$ 2,324,000,000	$ 2,338,000,000
transferred	0	0
Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	104,000,000	95,000,000	86,000,000
Operating and maintenance expenses	$ 7,000,000	$ 0	$ 1

Benefit Plans and Other Postr_4

Benefit Plans and Other Postretirement Benefits, Postretirement Health Care Benefits (Details) - Other Postretirement Benefits Plan [Member]	Dec. 31, 2021	Dec. 31, 2020
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%	15.00%
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)	71.00%	72.00%
Alternative investments
Postretirement Health Care Benefits [Abstract]
Target pension asset allocations (as a percent)	8.00%	9.00%
Cash
Postretirement Health Care Benefits [Abstract]
Target pension asset allocations (as a percent)	6.00%	4.00%

Benefit Plans and Other Postr_5

Benefit Plans and Other Postretirement Benefits, Postretirement Benefit Plan Benefit Obligations, Cash Flows and Benefit Costs (Details) - USD ($)		12 Months Ended
		Dec. 31, 2021		Dec. 31, 2020		Dec. 31, 2019
Change in Projected Benefit Obligation [Roll Forward]
Defined Benefit Plan, Plan Assets, Payment for Settlement		$ 197,000,000		$ 0
Funded Status of Plans at Dec. 31 [Abstract]
Noncurrent liabilities		(306,000,000)		(666,000,000)
Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Plan amendments		5,000,000		0
Change in Projected Benefit Obligation [Roll Forward]
Obligation at Jan. 1		3,964,000,000		3,701,000,000
Service cost		104,000,000		95,000,000		$ 86,000,000
Interest cost		104,000,000		125,000,000		145,000,000
Actuarial loss		(94,000,000)		328,000,000
Plan participants' contributions		0		0
Medicare subsidy reimbursements		0		0
Benefit payments	[1]	(365,000,000)		(285,000,000)
Obligation at Dec. 31		3,718,000,000		3,964,000,000		3,701,000,000
Change in Fair Value of Plan Assets [Roll Forward]
Fair value of plan assets at Jan. 1		3,599,000,000	[2]	3,184,000,000
Actual return (loss) on plan assets		305,000,000		550,000,000
Employer contributions		131,000,000		150,000,000
Participant contributions		0		0
Benefit payments		(365,000,000)		(285,000,000)
Fair value of plan assets at Dec. 31		3,670,000,000	[2]	3,599,000,000	[2]	3,184,000,000
Funded status		(48,000,000)		(365,000,000)
Funded Status of Plans at Dec. 31 [Abstract]
Assets for Plan Benefits, Defined Benefit Plan		19,000,000		0
Current liabilities		0		0
Noncurrent liabilities		(67,000,000)		(365,000,000)
Net postretirement amounts recognized on consolidated balance sheets		(48,000,000)		(365,000,000)
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost [Abstract]
Net loss		978,000,000		1,333,000,000
Prior service (credit) cost		(9,000,000)		(11,000,000)
Total		969,000,000		1,322,000,000
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		74,000,000		82,000,000
Noncurrent regulatory assets		846,000,000		1,181,000,000
Current regulatory liabilities		0		0
Noncurrent regulatory liabilities		0		0
Deferred income taxes		13,000,000		15,000,000
Net-of-tax accumulated other comprehensive income		36,000,000		44,000,000
Total		$ 969,000,000		$ 1,322,000,000
Significant Assumptions Used to Measure Benefit Obligations [Abstract]
Discount rate for year-end valuation (as a percent)		3.08%		2.71%
Components of Net Periodic Benefit Cost (Credit) [Abstract]
Service cost		$ 104,000,000		$ 95,000,000		86,000,000
Interest cost		104,000,000		125,000,000		145,000,000
Expected return on plan assets		(206,000,000)		(208,000,000)		(203,000,000)
Amortization of prior service cost (credit)		(1,000,000)		(4,000,000)		(5,000,000)
Amortization of net loss		107,000,000		100,000,000		87,000,000
Defined Benefit Plan, Net Periodic Benefit Cost (Credit), Gain (Loss) Due to Settlement	[3]	(59,000,000)		0		(6,000,000)
Net periodic benefit cost		$ 167,000,000		$ 108,000,000		$ 116,000,000
Significant Assumptions Used to Measure Costs [Abstract]
Discount rate (as a percent)		2.71%		3.49%		4.31%
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)		6.49%		6.87%		6.87%
Defined Benefit Plan, Costs Not Recognized Due To Regulation		$ (46,000,000)		$ 9,000,000		$ (1,000,000)
Net benefit cost recognized for financial reporting		121,000,000		117,000,000		115,000,000
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		574,000,000		547,000,000
Service cost		2,000,000		1,000,000		2,000,000
Interest cost		15,000,000		18,000,000		22,000,000
Actuarial loss		(41,000,000)		50,000,000
Plan participants' contributions		8,000,000		8,000,000
Medicare subsidy reimbursements		2,000,000		1,000,000
Benefit payments	[1]	(49,000,000)		(51,000,000)
Obligation at Dec. 31		511,000,000		574,000,000		547,000,000
Change in Fair Value of Plan Assets [Roll Forward]
Fair value of plan assets at Jan. 1		452,000,000	[4]	449,000,000
Actual return (loss) on plan assets		16,000,000		35,000,000
Employer contributions		15,000,000		11,000,000
Participant contributions		8,000,000		8,000,000
Benefit payments		(49,000,000)		(51,000,000)
Fair value of plan assets at Dec. 31		442,000,000	[4]	452,000,000	[4]	449,000,000
Funded status		(69,000,000)		(122,000,000)
Funded Status of Plans at Dec. 31 [Abstract]
Assets for Plan Benefits, Defined Benefit Plan		33,000,000		6,000,000
Current liabilities		(4,000,000)		(7,000,000)
Noncurrent liabilities		(98,000,000)		(121,000,000)
Net postretirement amounts recognized on consolidated balance sheets		(69,000,000)		(122,000,000)
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost [Abstract]
Net loss		81,000,000		126,000,000
Prior service (credit) cost		(7,000,000)		(15,000,000)
Total		74,000,000		111,000,000
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		90,000,000		125,000,000
Current regulatory liabilities		(1,000,000)		(1,000,000)
Noncurrent regulatory liabilities		(19,000,000)		(18,000,000)
Deferred income taxes		1,000,000		1,000,000
Net-of-tax accumulated other comprehensive income		3,000,000		4,000,000
Total		$ 74,000,000		$ 111,000,000
Significant Assumptions Used to Measure Benefit Obligations [Abstract]
Discount rate for year-end valuation (as a percent)		3.09%		2.65%
Defined Benefit Plan, Health Care Cost Trend Rate Assumed, Pre-65		5.30%		5.50%
Defined Benefit Plan, Health Care Cost Trend Rate Assumed, Post-65		4.90%		5.00%
Ultimate health care trend assumption rate (as a percent)		4.50%		4.50%
Period until ultimate trend rate is reached (in years)		$ 4		$ 5
Components of Net Periodic Benefit Cost (Credit) [Abstract]
Service cost		2,000,000		1,000,000		2,000,000
Interest cost		15,000,000		18,000,000		22,000,000
Expected return on plan assets		(18,000,000)		(19,000,000)		(21,000,000)
Amortization of prior service cost (credit)		(8,000,000)		(8,000,000)		(10,000,000)
Amortization of net loss		5,000,000		4,000,000		5,000,000
Defined Benefit Plan, Net Periodic Benefit Cost (Credit), Gain (Loss) Due to Settlement	[3]	0		0		0
Net periodic benefit cost		$ (4,000,000)		$ (4,000,000)		$ (2,000,000)
Significant Assumptions Used to Measure Costs [Abstract]
Discount rate (as a percent)		2.65%		3.47%		4.32%
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)		4.10%		4.50%		4.50%
Defined Benefit Plan, Costs Not Recognized Due To Regulation		$ 2,000,000		$ 3,000,000		$ 1,000,000
Net benefit cost recognized for financial reporting		$ (2,000,000)		$ (1,000,000)		$ (1,000,000)
[1]	ncludes approximately $197 million in 2021 and $0 million in 2020 of lump-sum benefit payments used in the determination of a settlement charge.
[2]	See Note 10 for further information regarding fair value measurement inputs and methods.
[3]	A settlement charge is required when the amount of all lump-sum distributions during the year is greater than the sum of the service and interest cost components of the annual net periodic pension cost. In 2021 and 2019, as a result of lump-sum distributions during each plan year, Xcel Energy recorded a total pension settlement charge of $59 million and $6 million, respectively, the majority of which was not recognized due to the effects of regulation. A total of $7 million and $1 million was recorded in the consolidated statements of income in 2021 and 2019, respectively. There were no settlement charges recorded for the qualified pension plans in 2020.
[4]	See Note 10 for further information on fair value measurement inputs and methods.

Projected Benefit Payments (Det

Projected Benefit Payments (Details) - USD ($)	1 Months Ended	12 Months Ended
	Jan. 31, 2022	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Defined Benefit Plan, Net Projected Benefit Payments [Abstract]
plan ammendment			$ 0
Pension Plan [Member]
Defined Benefit Plan, Gross Projected Benefit Payments [Abstract]
2022		$ 323,000,000
2023		257,000,000
2024		253,000,000
2025		251,000,000
2026		245,000,000
2027-2031		$ 1,156,000,000
Defined Benefit Plan, Net Projected Benefit Payments [Abstract]
Target pension asset allocations (as a percent)		100.00%	100.00%
Pension Plan [Member] | Equity Securities [Member]
Defined Benefit Plan, Net Projected Benefit Payments [Abstract]
Target pension asset allocations (as a percent)		33.00%	35.00%
Pension Plan [Member] | Long-duration fixed income and interest rate swap securities
Defined Benefit Plan, Net Projected Benefit Payments [Abstract]
Target pension asset allocations (as a percent)		37.00%	35.00%
Pension Plan [Member] | Short-to-intermediate fixed income securities
Defined Benefit Plan, Net Projected Benefit Payments [Abstract]
Target pension asset allocations (as a percent)		11.00%	13.00%
Pension Plan [Member] | Alternative investments
Defined Benefit Plan, Net Projected Benefit Payments [Abstract]
Target pension asset allocations (as a percent)		17.00%	15.00%
Pension Plan [Member] | Cash equivalents
Defined Benefit Plan, Net Projected Benefit Payments [Abstract]
Target pension asset allocations (as a percent)		2.00%	2.00%
Pension Plan [Member] | Xcel Energy [Member]
Defined Benefit Plan, Net Projected Benefit Payments [Abstract]
Payment for Pension Benefits		$ 131,000,000	$ 150,000,000	$ 154,000,000
Pension Plan [Member] | Xcel Energy [Member] | Subsequent Event
Defined Benefit Plan, Net Projected Benefit Payments [Abstract]
Payment for Pension Benefits	$ 50,000,000
Other Postretirement Benefits Plan [Member]
Defined Benefit Plan, Gross Projected Benefit Payments [Abstract]
2022		42,000,000
2023		41,000,000
2024		40,000,000
2025		38,000,000
2026		37,000,000
2027-2031		165,000,000
Expected Medicare Part D Subsidies [Abstract]
2022		2,000,000
2023		2,000,000
2024		2,000,000
2025		2,000,000
2026		2,000,000
2027-2031		13,000,000
Defined Benefit Plan, Net Projected Benefit Payments [Abstract]
2022		40,000,000
2023		39,000,000
2024		38,000,000
2025		36,000,000
2026		35,000,000
2027-2031		$ 152,000,000
Target pension asset allocations (as a percent)		100.00%	100.00%
Other Postretirement Benefits Plan [Member] | Equity Securities [Member]
Defined Benefit Plan, Net Projected Benefit Payments [Abstract]
Target pension asset allocations (as a percent)		15.00%	15.00%
Other Postretirement Benefits Plan [Member] | Long-duration fixed income and interest rate swap securities
Defined Benefit Plan, Net Projected Benefit Payments [Abstract]
Target pension asset allocations (as a percent)		0.00%	0.00%
Other Postretirement Benefits Plan [Member] | Short-to-intermediate fixed income securities
Defined Benefit Plan, Net Projected Benefit Payments [Abstract]
Target pension asset allocations (as a percent)		71.00%	72.00%
Other Postretirement Benefits Plan [Member] | Alternative investments
Defined Benefit Plan, Net Projected Benefit Payments [Abstract]
Target pension asset allocations (as a percent)		8.00%	9.00%
Other Postretirement Benefits Plan [Member] | Cash equivalents
Defined Benefit Plan, Net Projected Benefit Payments [Abstract]
Target pension asset allocations (as a percent)		6.00%	4.00%
Defined Benefit Plan, Overfunded Plan [Member] | Xcel Energy [Member]
Defined Benefit Plan, Net Projected Benefit Payments [Abstract]
Payment for Pension Benefits		$ 15,000,000	$ 11,000,000	$ 15,000,000
Defined Benefit Plan, Overfunded Plan [Member] | Xcel Energy [Member] | Subsequent Event
Defined Benefit Plan, Net Projected Benefit Payments [Abstract]
Payment for Pension Benefits	$ 9,000,000

Benefit Plans and Other Postr_6

Benefit Plans and Other Postretirement Benefits Defined Contribution Plans (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Retirement Benefits [Abstract]
Defined Contribution Plan, Cost	$ 43	$ 42	$ 39
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Contribution Plan, Cost	$ 43	$ 42	$ 39

Benefit Plans and Other Postr_7

Benefit Plans and Other Postretirement Benefits Plan Amendments (Details)	Dec. 31, 2020USD ($)
Defined Benefit Plan Disclosure [Line Items]
plan ammendment	$ 0

Commitments and Contingencies G

Commitments and Contingencies Gas Trading Litigation (Details) $ in Millions	12 Months Ended
	Dec. 31, 2021USD ($)
Loss Contingencies [Line Items]
Breckenridge Litigation	$ 3
Gas Trading Litigation [Member]
Loss Contingencies [Line Items]
Loss Contingency, Pending Claims, Number	1

Winter Storm Uri (Details)

Winter Storm Uri (Details) $ in Millions	Dec. 31, 2021USD ($)
Guarantees and Product Warranties [Abstract]
Winter Storm Uri Costs	$ 179

Commitments and Contingencies S

Commitments and Contingencies Sherco (Details) - USD ($) $ in Millions	1 Months Ended
	Jan. 31, 2021	Jan. 27, 2021
Public Utilities, General Disclosures [Line Items]
Amount MPUC previously disallowed related to Sherco outage		$ 22
NSP Minnesota
Public Utilities, General Disclosures [Line Items]
Customer refund of previously recovered purchased power costs	$ 17

Westmoreland Arbitration (Detai

Westmoreland Arbitration (Details) $ in Millions	12 Months Ended
	Dec. 31, 2021USD ($)
Guarantees and Product Warranties [Abstract]
Gain (Loss) Related to Litigation Settlement	$ 36

Commitments and Contingencies M

Commitments and Contingencies MISO ROE Complaints (Details) - Federal Energy Regulatory Commission (FERC) [Member] - NSP Minnesota and NSP Wisconsin [Member] [Member] - FERC Proceeding, MISO ROE Complaint [Member]	1 Months Ended		7 Months Ended	8 Months Ended	9 Months Ended
	Feb. 28, 2015	Nov. 30, 2013	Dec. 31, 2020	Dec. 31, 2020	Sep. 30, 2018
Public Utilities, General Disclosures [Line Items]
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, Approved					10.32%
Public Utilities, ROE New Base, Complaint Number 1				10.02%
Basis Point Reduction			1000.00%
Basis Point Reduction - First Complaint			100000000.00%
Basis Point Reduction - Second Complaint			100000000.00%
Basis Point Reduction - Third Complaint			200000000.00%

Commitments and Contingencies_2

Commitments and Contingencies SPP OATT Upgrade Costs (Details) $ in Millions	12 Months Ended
	Dec. 31, 2018USD ($)
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

Commitment and Contingencies Wi

Commitment and Contingencies Wind Operating Commitments (Details)	Dec. 31, 2021
SPS
Loss Contingencies [Line Items]
Wind Operating Commitments, minimum net capacity factor	48.00%

Commitment and Contingencies Co

Commitment and Contingencies Contract Termination (Details) $ in Millions	12 Months Ended
	Dec. 31, 2021USD ($)MW
Loss Contingencies [Line Items]
Settlement Agreement Payment, Lubbock Power and Light Contract | $	$ 78
SPS
Loss Contingencies [Line Items]
Lubbock Power and Light Contract Length	25 years
Megawatts, Lubbock Power and Light contract | MW	170

Commitments and Contingencies_3

Commitments and Contingencies MGP Sites (Details)	Dec. 31, 2021Site
Other MGP, Landfill, or Disposal Sites [Member]
Loss Contingencies [Line Items]
Number of identified MGP, landfill, or disposal sites under current investigation and/or remediation	16

Environmental Requirements - Wa

Environmental Requirements - Water and Waste (Details) $ in Millions	12 Months Ended
	Dec. 31, 2021USD ($)Plant
Federal Coal Ash Regulation [Member]
Loss Contingencies [Line Items]
Number of sites where regulated ash units will still be in operation at a specified date	8
Number of impoundments where closure plans will be expedited	2
Federal Coal Ash Regulation [Member] | NSP Minnesota
Loss Contingencies [Line Items]
Number of sites where statistically significant increases over established groundwater standards exist	0
Estimated cost of closure of an impoundment	$ 4
Time period of existing ash pond closure completion in accordance with the CCR rule	5 years
Federal Coal Ash Regulation [Member] | PSCo
Loss Contingencies [Line Items]
Number of sites where statistically significant increases over established groundwater standards exist	4
Number of sites where corrective action options are being evaluated for locations with statistically significant increases above background concentrations	2
Number of sites where monitoring results indicate potential offsite impacts to groundwater	1
Estimated cost to remediate groundwater sampling results	$ 35
Estimated cost of construction of an alternative collection and treatment system	25
Estimated cost to close Comanche station bottom ash pond	3
Federal Clean Water Act Section 316 (b) | Capital Addition Purchase Commitments [Member]
Loss Contingencies [Line Items]
Liability for estimated cost to comply with regulation	39
Liability for estimated cost to comply with impingement and entrainment regulation	$ 192
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

Environmental Requirements - Ai

Environmental Requirements - Air (Details) - SPS $ in Millions	12 Months Ended
	Dec. 31, 2021USD ($)Site
Implementation of the National Ambient Air Quality Standard for sulfur dioxide [Member] | Harrington Units 1 and 2 [Member]
Loss Contingencies [Line Items]
Exception to areas near generating plants attaining the SO2 NAAQS | Site	1
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

AROs (Details)

AROs (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2021		Dec. 31, 2020
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance		$ 2,884		$ 2,701
Amounts Incurred		107	[1]	149	[2]
Amounts Settled		0		(8)	[3]
Accretion		138		134
Cash flow revisions		22	[4]	(92)	[5]
Ending balance		3,151	[6]	2,884
Fair Value, Recurring [Member] | Nuclear Decommissioning Fund | Estimate of Fair Value Measurement [Member]
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Decommissioning fund investments		3,256		2,777
Fair Value, Recurring [Member] | Nuclear Decommissioning Fund | Estimate of Fair Value Measurement [Member] | NSP Minnesota
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Decommissioning fund investments		3,300		2,800
Electric Plant Nuclear Production Decommissioning
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance		1,957		2,068
Amounts Incurred		0	[1]	0	[2]
Amounts Settled	[3]			0
Accretion		99		105
Cash flow revisions		0	[4]	(216)	[5]
Ending balance		2,056	[6]	1,957
Electric Plant Nuclear Production Decommissioning | NSP Minnesota
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance		1,957
Ending balance		2,056		1,957
Electric Plant Wind Production
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance		360		146
Amounts Incurred		101	[1]	149	[2]
Amounts Settled	[3]			3
Accretion		17		8
Cash flow revisions		0	[4]	60	[5]
Ending balance		478	[6]	360
Electric Plant Steam, Hydro and Other Production Asbestos
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance		264		202
Amounts Incurred		6	[1]	0	[2]
Amounts Settled	[3]			(5)
Accretion		10		9
Cash flow revisions		8	[4]	58	[5]
Ending balance		288	[6]	264
Electric Plant Electric Distribution
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance		46		44
Amounts Incurred		0	[1]	0	[2]
Amounts Settled	[3]			0
Accretion		1		2
Cash flow revisions		0	[4]	0	[5]
Ending balance		47	[6]	46
Natural Gas Plant Gas Transmission and Distribution
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance		252		236
Amounts Incurred		0	[1]	0	[2]
Amounts Settled	[3]			0
Accretion		10		10
Cash flow revisions		9	[4]	6	[5]
Ending balance		271	[6]	252
Natural Gas Plant Miscellaneous
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance		3		3
Amounts Incurred		0	[1]	0	[2]
Amounts Settled	[3]			0
Accretion		0		0
Cash flow revisions		5	[4]	0	[5]
Ending balance		8	[6]	3
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	[3]			0
Accretion		0		0
Cash flow revisions		0	[4]	0	[5]
Ending balance		1	[6]	1
Non utility and other
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance		1		1
Amounts Incurred		0	[1]	0	[2]
Amounts Settled	[3]			0
Accretion		1		0
Cash flow revisions		0	[4]	0	[5]
Ending balance		$ 2	[6]	$ 1
[1]	Amounts incurred related to the wind farms placed in service in 2021 for NSP-Minnesota (Blazing Star 2, Mower and Freeborn) and removal of a utility scale battery asset in NSP-Minnesota.
[2]	Amounts incurred related to the wind farms placed in service in 2020 for NSP-Minnesota (Blazing Star 1, Crowned Ridge 2, Jeffers and Community Wind North), PSCo (Cheyenne Ridge) and SPS (Sagamore).
[3]	Amounts settled primarily related to closure of certain ash containment facilities, removal of wind facilities and asbestos abatement projects.
[4]	In 2021, AROs were revised for changes in timing and estimates of cash flows. Revisions in steam, hydro and other production AROs were primarily related to changes in cost estimates for remediation of ash containment facilities. Changes in gas transmission and distribution AROs were primarily related to changes in labor rates coupled with increased gas line mileage and number of services.
[5]	In 2020, AROs were revised for changes in timing and estimates of cash flows. Revisions in the nuclear AROs were driven by reductions in spent fuel cooling time requirements in the nuclear triennial filing coupled with decreasing interest rates. Changes in wind AROs were driven by new dismantling studies. Revisions in steam, hydro and other production AROs were primarily related to changes in cost estimates for remediation of ash containment facilities.
[6]	There were no ARO amounts settled in 2021.

Indeterminate AROs (Details)

Indeterminate AROs (Details) $ in Millions	Dec. 31, 2021USD ($)
Asset Retirement Obligations [Line Items]
Indeterminate Costs Incurred, Asset Retirement Obligation Due to Asbestos	$ 0

Nuclear Insurance (Details)

Nuclear Insurance (Details) - NSP Minnesota - Nuclear Insurance $ in Millions	12 Months Ended
	Dec. 31, 2021USD ($)PlantReactor
Nuclear Insurance [Abstract]
Nuclear insurance coverage secured for the Company's public liability exposure	$ 450
Nuclear insurance coverage exposure funded by the Secondary Financial Protection Program	13,000
Maximum assessments per reactor per accident	$ 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	$ 11
Maximum assessment for property damage insurance NSP-Minnesota is subject to each calendar year	33
Maximum
Nuclear Insurance [Abstract]
Loss Contingency, Estimate of Possible Loss	13,500
Insurance coverage limits for NSP-Minnesota's nuclear plant sites	2,800
Business Interruption Insurance Coverage Provided by NEIL	$ 350

Nuclear Fuel Disposal (Details)

Nuclear Fuel Disposal (Details) - NSP Minnesota	Dec. 31, 2021Canister
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	47
Number Of Authorized Canisters In Dry Cask Nuclear Storage Facility	64

Regulatory Plant Decommissionin

Regulatory Plant Decommissioning Recovery (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2021		Dec. 31, 2020	Dec. 31, 2019
Regulatory Basis to GAAP Basis Reconciliation [Abstract]
Asset Retirement Obligation		$ 3,151	[1]	$ 2,884	$ 2,701
Annual Decommissioning Recorded As Depreciation Expense [Abstract]
Approved annual accrual for decommissioning costs		14		14	14
Nuclear Plant [Member]
Regulatory Basis to GAAP Basis Reconciliation [Abstract]
Asset Retirement Obligation		2,056	[1]	1,957	2,068
Nuclear Decommissioning Fund | Estimate of Fair Value Measurement [Member] | Fair Value, Recurring [Member]
Funded Status of Nuclear Decommissioning Obligation [Abstract]
Decommissioning fund investments		$ 3,256		$ 2,777
NSP Minnesota
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%
Assumed annual escalation rate during spent fuel management and site restoration activities		3.36%
Funded Status of Nuclear Decommissioning Obligation [Abstract]
Average risk-free interest rate		1.96%		1.64%
Annual Decommissioning Recorded As Depreciation Expense [Abstract]
Annual decommissioning recorded as depreciation expense: (a) (b)	[2],[3]	$ 22		$ 20	$ 20
NSP Minnesota | Nuclear Plant [Member]
Funded Status of Nuclear Decommissioning Obligation [Abstract]
Discounted decommissioning cost obligation		6,554		7,024
Regulatory Basis to GAAP Basis Reconciliation [Abstract]
Differences in Discount Rate and Market Risk Premium		2,209		2,628
Operating and Maintenance Costs Not Included for GAAP		1,584		1,734
ARO differences between 2020 and 2014 cost studies		(705)		(705)
Asset Retirement Obligation		$ 2,056		1,957
NSP Minnesota | Minimum
Regulatory Plant Decommissioning Recovery [Abstract]
Assumed after tax rate of return used to determine funding for external decommissioning trust fund		5.23%
NSP Minnesota | Maximum
Regulatory Plant Decommissioning Recovery [Abstract]
Assumed after tax rate of return used to determine funding for external decommissioning trust fund		6.30%
NSP Minnesota | Nuclear Decommissioning Fund | Estimate of Fair Value Measurement [Member] | Fair Value, Recurring [Member]
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		1,006		844
Estimated decommissioning cost obligation (in current dollars)		4,018		3,856
Effect of escalating costs to payment date		7,187		7,349
Estimated future decommissioning costs (undiscounted)		11,205		11,205
Effect Of Discounting Obligation Using Risk Free Interest Rate		4,651		4,181
Discounted decommissioning cost obligation		6,554		7,024
Decommissioning fund investments		3,300		2,800
Underfunding of external decommissioning fund compared to the discounted decommissioning obligation		$ (3,298)		$ (4,247)
[1]	There were no ARO amounts settled in 2021.
[2]	Decommissioning expense does not include depreciation of the capitalized nuclear asset retirement costs.
[3]	Decommissioning expenses in 2021, 2020 and 2019 include Minnesota’s retail jurisdiction annual funding requirement of approximately $14 million.

Leases (Details)

Leases (Details) - USD ($)		12 Months Ended
		Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Lessee, Lease, Description [Line Items]
Maximum Length - Short-Term Leases		12 months
Operating Lease, Weighted Average Discount Rate, Percent		4.00%
Operating Lease ROU Assets
Gross operating lease ROU assets		$ 1,881,000,000	$ 1,862,000,000
Accumulated amortization		(590,000,000)	(372,000,000)
Net operating lease ROU assets		1,291,000,000	1,490,000,000
Finance Lease ROU Assets
Gross finance lease ROU assets		222,000,000	222,000,000
Accumulated amortization		(97,000,000)	(90,000,000)
Net finance lease ROU assets		125,000,000	132,000,000
Components of Lease Expense
Operating Lease, Cost	[1]	287,000,000	264,000,000	$ 255,000,000
Finance Lease, Right-of-Use Asset, Amortization		7,000,000	7,000,000	6,000,000
Finance Lease, Interest Expense		17,000,000	18,000,000	19,000,000
Finance Lease, Cost		24,000,000	25,000,000	25,000,000
Short-term Lease, Cost		5,000,000	5,000,000	5,000,000
Operating Lease Commitments
2022		256,000,000
2023		247,000,000
2024		231,000,000
2025		205,000,000
2026		158,000,000
Thereafter		497,000,000
Total minimum obligation		1,594,000,000
Interest component of obligation		(243,000,000)
Operating lease liabilities		1,351,000,000
Less current portion		(205,000,000)	(214,000,000)
Noncurrent operating and finance lease liabilities		1,146,000,000	1,344,000,000
Operating Lease, Weighted Average Remaining Lease Term		8.9
Finance Lease, Liability, Payment, Due [Abstract]
2022	[2]	12,000,000
2023	[2]	12,000,000
2024	[2]	12,000,000
2025	[2]	10,000,000
2026	[2]	9,000,000
Thereafter	[2]	187,000,000
Total minimum obligation	[2]	242,000,000
Interest component of obligation	[2]	(170,000,000)
Present value of minimum obligation	[2]	72,000,000
Finance Lease, Liability, Current	[2]	(3,000,000)
Finance Lease, Liability, Noncurrent	[2]	$ 69,000,000
Finance Lease, Weighted Average Remaining Lease Term	[2]	36 years 1 month 6 days
WYCO, Inc. [Member]
Operating Lease ROU Assets
Equity Method Investment, Ownership Percentage		50.00%
Purchased Power Agreements
Operating Lease ROU Assets
Gross operating lease ROU assets		$ 1,656,000,000	1,650,000,000
Components of Lease Expense
Operating Lease, Cost		251,000,000	238,000,000	221,000,000
Operating Lease Commitments
2022	[3],[4]	229,000,000
2023	[3],[4]	221,000,000
2024	[3],[4]	209,000,000
2025	[3],[4]	189,000,000
2026	[3],[4]	146,000,000
Thereafter	[3],[4]	416,000,000
Total minimum obligation	[3],[4]	1,410,000,000
Interest component of obligation	[3],[4]	(209,000,000)
Operating lease liabilities	[3],[4]	1,201,000,000
Other Operating Lease [Domain]
Operating Lease ROU Assets
Gross operating lease ROU assets		225,000,000	212,000,000
Components of Lease Expense
Operating Lease, Cost	[5]	36,000,000	26,000,000	$ 34,000,000
Operating Lease Commitments
2022		27,000,000
2023		26,000,000
2024		22,000,000
2025		16,000,000
2026		12,000,000
Thereafter		81,000,000
Total minimum obligation		184,000,000
Interest component of obligation		(34,000,000)
Operating lease liabilities		150,000,000
Gas Storage Facilities [Member]
Finance Lease ROU Assets
Gross finance lease ROU assets		201,000,000	201,000,000
Pipelines [Member]
Finance Lease ROU Assets
Gross finance lease ROU assets		$ 21,000,000	$ 21,000,000
[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 2039.
[5]	Includes short-term lease expense of $5 million for 2021, 2020 and 2019.

Non Lease PPAs (Details)

Non Lease PPAs (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Capacity
Purchased Power Agreements (PPAs) [Abstract]
Purchased power expense		$ 69	$ 75	$ 86
Estimated Future Payments Under PPAs [Abstract]
2022		75
2023		77
2024		72
2025		29
2026		12
Thereafter		12
Total		277
Energy
Purchased Power Agreements (PPAs) [Abstract]
Purchased power expense		149	$ 112	$ 102
Estimated Future Payments Under PPAs [Abstract]
2022	[1]	165
2023	[1]	169
2024	[1]	174
2025	[1]	53
2026	[1]	10
Thereafter	[1]	38
Total	[1]	$ 609
[1]	Excludes contingent energy payments for renewable energy PPAs.

Fuel Contracts (Details)

Fuel Contracts (Details) $ in Millions	Dec. 31, 2021USD ($)
Coal
Fuel Contracts [Abstract]
2022	$ 620
2023	233
2024	147
2025	29
2026	31
Thereafter	34
Total	1,094
Nuclear Fuel
Fuel Contracts [Abstract]
2022	89
2023	109
2024	82
2025	119
2026	29
Thereafter	309
Total	737
Natural Gas Supply
Fuel Contracts [Abstract]
2022	477
2023	75
2024	4
2025	0
2026	0
Thereafter	0
Total	556
Natural Gas Storage and Transportation
Fuel Contracts [Abstract]
2022	292
2023	224
2024	172
2025	156
2026	149
Thereafter	571
Total	$ 1,564

VIEs - PPAs (Details)

VIEs - PPAs (Details) - MW	Dec. 31, 2021	Dec. 31, 2020
Equity Method Investment, Nonconsolidated Investee or Group of Investees [Member]
Purchased Power Agreements [Abstract]
Generating capacity (in MW)	4,062	4,062

Low-Income Housing Limited Part

Low-Income Housing Limited Partnerships (Details) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Variable Interest Entity [Line Items]
Total assets	$ 57,851	$ 53,957
Variable Interest Entity, Primary Beneficiary
Variable Interest Entity [Line Items]
Current assets	7	7
Property, plant and equipment, net	37	38
Other noncurrent assets	1	1
Total assets	45	46
Current liabilities	7	8
Mortgages and other long-term debt payable	27	25
Other noncurrent liabilities	1	1
Variable Interest Entity, Consolidated, Carrying Amount, Liabilities	$ 35	$ 34

Technology Agreements (Details)

Technology Agreements (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Technology Agreements [Abstract]
Technology Agreement Expiration	2022
Information Technology and Data Processing	$ 103	$ 110	$ 101
Minimum
Technology Agreements, Minimum Payments Due [Abstract]
2022	$ 15

Guarantees and Bond Indemnifica

Guarantees and Bond Indemnifications (Details) - USD ($)	Dec. 31, 2021	Dec. 31, 2020
Commitments and Contingencies Disclosure [Abstract]
Assets Held As Collateral For Guarantor Obligations	$ 0	$ 0
Guarantor Obligations, Maximum Exposure, Undiscounted	60,000,000	62,000,000
Guarantor Obligations, Maximum Exposure, Undiscounted	$ 60,000,000	$ 62,000,000

Other Comprehensive Income (Det

Other Comprehensive Income (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021		Dec. 31, 2020		Dec. 31, 2019
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Accumulated other comprehensive income (loss) at beginning of period	$ 14,575
Derivative fair value decrease, tax	1		$ (3)		$ (8)
Total income tax (benefit) expense	(70)		(6)		128
Accumulated other comprehensive income (loss) at end of period	15,612		14,575
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	(85)		(80)
Other comprehensive loss before reclassifications, net of tax	4		(10)
Amortization of net actuarial loss	0		0
Net current period other comprehensive income (loss)	10		(5)
Accumulated other comprehensive income (loss) at end of period	(75)		(85)		(80)
Gains and Losses on Cash Flow Hedges | Reclassification out of Accumulated Other Comprehensive Income
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Derivative fair value decrease, tax	1		(3)
Total income tax (benefit) expense	2		2
Reclassification from AOCI, Current Period, Tax	0		0
Gains and Losses on Cash Flow Hedges | Interest Rate Swap
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Amortization of net actuarial loss	(6)	[1]	(5)	[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	(56)		(61)
Other comprehensive loss before reclassifications, net of tax	0		(5)
Amortization of net actuarial loss	(8)	[3]	(10)	[4]
Net current period other comprehensive income (loss)	8		5
Accumulated other comprehensive income (loss) at end of period	(48)		(56)		(61)
Defined Benefit Pension and Postretirement Items | Reclassification out of Accumulated Other Comprehensive Income
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Derivative fair value decrease, tax	0		(2)
Total income tax (benefit) expense	0		0
Reclassification from AOCI, Current Period, Tax	3		3
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	(141)		(141)
Other comprehensive loss before reclassifications, net of tax	4		(15)
Amortization of net actuarial loss	(8)		(10)
Net current period other comprehensive income (loss)	18		0
Accumulated other comprehensive income (loss) at end of period	(123)		(141)		$ (141)
Total | Interest Rate Swap
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Amortization of net actuarial loss	$ (6)		$ (5)
[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. See Note 11 for further information.

Segments and Related Informat_3

Segments and Related Information (Details) - USD ($) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2021	Sep. 30, 2021	Jun. 30, 2021	Mar. 31, 2021	Dec. 31, 2020	Sep. 30, 2020	Jun. 30, 2020	Mar. 31, 2020	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Segment Reporting Information [Line Items]
Investment in subsidiaries	$ 208				$ 165				$ 208	$ 165
Regulated Electric									11,205	9,802	$ 9,575
Natural Gas									2,132	1,636	1,868
Other									94	88	86
Regulated and Unregulated Operating Revenue	2,947	$ 3,182	$ 2,586	$ 2,811	2,947	$ 3,182	$ 2,586	$ 2,811	13,431	11,526	11,529
Depreciation and amortization									2,121	1,948	1,765
Interest charges and financing costs									816	798	736
Total income tax (benefit) expense									(70)	(6)	128
Net income (loss)	$ 288	$ 603	$ 287	$ 295	$ 288	$ 603	$ 287	$ 295	1,597	1,473	1,372
Regulated Electric
Segment Reporting Information [Line Items]
Revenues Including Intersegment Revenues									11,207	9,804	9,576
Depreciation and amortization									1,855	1,673	1,535
Interest charges and financing costs									568	534	500
Total income tax (benefit) expense									(96)	1	125
Net income (loss)									1,478	1,407	1,288
Regulated Natural Gas
Segment Reporting Information [Line Items]
Revenues Including Intersegment Revenues									2,134	1,637	1,870
Depreciation and amortization									254	252	219
Interest charges and financing costs									75	71	69
Total income tax (benefit) expense									54	17	48
Net income (loss)									231	190	195
All Other
Segment Reporting Information [Line Items]
Depreciation and amortization									12	23	11
Interest charges and financing costs									173	193	167
Total income tax (benefit) expense									(28)	(24)	(45)
Net income (loss)									(112)	(124)	(111)
Total revenues
Segment Reporting Information [Line Items]
Regulated and Unregulated Operating Revenue									13,435	11,529	11,532
Total revenues | Regulated Electric
Segment Reporting Information [Line Items]
Regulated Electric									11,205	9,802	9,575
Total revenues | Regulated Natural Gas
Segment Reporting Information [Line Items]
Natural Gas									2,132	1,636	1,868
Total revenues | All Other
Segment Reporting Information [Line Items]
Other									94	88	86
Intersegment Eliminations
Segment Reporting Information [Line Items]
Regulated and Unregulated Operating Revenue									(4)	(3)	(3)
Intersegment Eliminations | Regulated Electric
Segment Reporting Information [Line Items]
Regulated Electric									2	2	1
Intersegment Eliminations | Regulated Natural Gas
Segment Reporting Information [Line Items]
Natural Gas									$ 2	$ 1	$ 2

Summarized Quarterly Financia_3

Summarized Quarterly Financial Data (Unaudited) (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2021	Sep. 30, 2021	Jun. 30, 2021	Mar. 31, 2021	Dec. 31, 2020	Sep. 30, 2020	Jun. 30, 2020	Mar. 31, 2020	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Quarterly Financial Information Disclosure [Abstract]
Regulated and Unregulated Operating Revenue	$ 2,947	$ 3,182	$ 2,586	$ 2,811	$ 2,947	$ 3,182	$ 2,586	$ 2,811	$ 13,431	$ 11,526	$ 11,529
Operating income	426	813	422	455	426	813	422	455	2,203	2,116	2,104
Net income	$ 288	$ 603	$ 287	$ 295	$ 288	$ 603	$ 287	$ 295	$ 1,597	$ 1,473	$ 1,372
Basic	$ 0.54	$ 1.15	$ 0.54	$ 0.56	$ 0.54	$ 1.15	$ 0.54	$ 0.56	$ 2.96	$ 2.79	$ 2.64
Diluted	0.54	1.14	0.54	0.56	0.54	1.14	0.54	0.56	$ 2.96	$ 2.79	$ 2.64
Cash dividends declared per common share (in dollars per share)	$ 0.43	$ 0.43	$ 0.43	$ 0.43	$ 0.43	$ 0.43	$ 0.43	$ 0.43

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, 2021	Sep. 30, 2021	Jun. 30, 2021	Mar. 31, 2021	Dec. 31, 2020	Sep. 30, 2020	Jun. 30, 2020	Mar. 31, 2020	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Income
Income (Loss) from Equity Method Investments										$ 62	$ 40	$ 39
Expenses and other deductions
Other income										(5)	6	(16)
Interest charges and financing costs										842	840	773
Income before income taxes										1,527	1,467	1,500
Income tax benefit										(70)	(6)	128
Net income		$ 288	$ 603	$ 287	$ 295	$ 288	$ 603	$ 287	$ 295	1,597	1,473	1,372
Other Comprehensive Income (Loss), Net of Tax [Abstract]
Net pension and retiree medical losses arising during the period, net of tax of $—, $(2) and $—, respectively										0	(5)	0
Pension and retiree medical benefits, tax expense(benefit)										1	1	1
Derivative instruments, tax expense(benefit)										3	(1)	(7)
Total comprehensive income										$ 1,615	$ 1,473	$ 1,355
Weighted average common shares outstanding:
Basic										539	527	519
Diluted	[1]									540	528	520
Earnings per average common share:
Basic		$ 0.54	$ 1.15	$ 0.54	$ 0.56	$ 0.54	$ 1.15	$ 0.54	$ 0.56	$ 2.96	$ 2.79	$ 2.64
Diluted		$ 0.54	$ 1.14	$ 0.54	$ 0.56	$ 0.54	$ 1.14	$ 0.54	$ 0.56	$ 2.96	$ 2.79	$ 2.64
Xcel Energy Inc.
Income
Income (Loss) from Equity Method Investments										$ 1,744	$ 1,646	$ 1,505
Total income										1,744	1,646	1,505
Expenses and other deductions
Operating expenses										21	43	23
Other income										(3)	4	9
Interest charges and financing costs										173	198	173
Total expenses and other deductions										197	237	187
Income before income taxes										1,547	1,409	1,318
Income tax benefit										(50)	(64)	(54)
Net income										1,597	1,473	1,372
Other Comprehensive Income (Loss), Net of Tax [Abstract]
Net pension and retiree medical losses arising during the period, net of tax of $—, $(2) and $—, respectively										8	5	3
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, before Tax										10	(5)	(20)
Other Comprehensive Income (Loss), Net of Tax										18	0	(17)
Total comprehensive income										$ 1,615	$ 1,473	$ 1,355
[1]	Diluted common shares outstanding included common stock equivalents of 0.3 million, 1.1 million and 1.3 million shares for 2021, 2020 and 2019, respectively.

Condensed Statement of Cash Flo

Condensed Statement of Cash Flows (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Operating activities
Net cash provided by (used in) operating activities	$ 2,189	$ 2,848	$ 3,263
Investing activities
Net (investments) return in the utility money pool	(57)	18	39
Other, net	(83)	(137)	40
Net cash provided by (used in) investing activities	(4,287)	(4,740)	(4,343)
Financing activities
Proceeds from (repayment of) short-term borrowings, net	421	(11)	(443)
Proceeds from Issuance of Long-term Debt	2,710	2,940	2,920
Repayment of long-term debt	(417)	(1,001)	(949)
Proceeds from Issuance of Common Stock	366	727	458
Payments of Dividends	(935)	(856)	(791)
Proceeds from (Payments for) Other Financing Activities	(10)	(26)	(14)
Net cash provided by (used in) financing activities	2,135	1,773	1,181
Net change in cash and cash equivalents	37	(119)	101
Cash and Cash Equivalents, at Carrying Value, Beginning Balance	129	248	147
Cash and Cash Equivalents, at Carrying Value, Ending Balance	166	129	248
Xcel Energy Inc.
Operating activities
Net cash provided by (used in) operating activities	1,147	2,377	1,389
Investing activities
Capital contributions to subsidiaries	1,661	2,553	1,594
Other, net	0	(1)	0
Net cash provided by (used in) investing activities	(1,604)	(2,572)	(1,555)
Financing activities
Proceeds from (repayment of) short-term borrowings, net	638	(500)	12
Proceeds from Issuance of Long-term Debt	791	1,089	1,120
Repayment of long-term debt	400	300	550
Proceeds from Issuance of Common Stock	366	727	458
Repurchases of common stock	0	4	0
Payments of Dividends	935	856	791
Proceeds from (Payments for) Other Financing Activities	(16)	(17)	(14)
Net cash provided by (used in) financing activities	444	139	235
Net change in cash and cash equivalents	(13)	(56)	69
Cash and Cash Equivalents, at Carrying Value, Beginning Balance	14	70	1
Cash and Cash Equivalents, at Carrying Value, Ending Balance	$ 1	$ 14	$ 70

Condensed Balance Sheet (Detail

Condensed Balance Sheet (Details) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Assets
Total current assets	$ 4,239	$ 3,275
Investment in subsidiaries	208	165
Other assets	431	379
Total other assets	8,155	7,732
Total assets	57,851	53,957
Liabilities and Equity
Dividends payable	249	231
Short-term debt	1,005	584
Other current liabilities	459	407
Total current liabilities	5,046	4,239
Other liabilities	158	183
Total deferred credits and other liabilities	15,414	15,498
Capitalization
Total common stockholders’ equity	15,612	14,575
Total liabilities and equity	57,851	53,957
Xcel Energy Inc.
Assets
Cash and cash equivalents	1	14
Accounts receivable from subsidiaries	430	424
Other current assets	6	6
Total current assets	437	444
Investment in subsidiaries	21,167	19,102
Other assets	71	40
Total other assets	21,238	19,142
Total assets	21,675	19,586
Liabilities and Equity
Long-term Debt, Current Maturities	0	400
Dividends payable	249	231
Short-term debt	638	0
Other current liabilities	29	21
Total current liabilities	916	652
Other liabilities	10	17
Total deferred credits and other liabilities	10	17
Capitalization
Long-term debt, noncurrent	5,137	4,342
Total common stockholders’ equity	15,612	14,575
Total capitalization	20,749	18,917
Total liabilities and equity	$ 21,675	$ 19,586

Condensed Notes to the Financia

Condensed Notes to the Financial Statements (Details) - USD ($) $ in Millions		3 Months Ended	12 Months Ended
		Dec. 31, 2021	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Money Pool [Abstract]
Schedule of Guarantor Obligations			Guarantees and bond indemnities issued and outstanding as of Dec. 31, 2021: (Millions of Dollars) Guarantor Guarantee Current Triggering Guarantee of loan for Hiawatha Collegiate High School (a) Xcel Energy Inc. $ 1 — (c) Guarantee performance and payment of surety bonds for Xcel Energy Inc.’s utility subsidiaries (b) Xcel Energy Inc. 59 (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.
Guarantor Obligations [Line Items]
Guarantees issued and outstanding		$ 60	$ 60	$ 62
Payment or Performance Guarantee | Loan for Hiawatha Collegiate High School [Member]
Guarantor Obligations [Line Items]
Guarantees issued and outstanding	[1]	1	1
Current exposure under these guarantees	[1]	0	0
Payment or Performance Guarantee | Surety Bonds
Guarantor Obligations [Line Items]
Guarantees issued and outstanding	[2]	59	59
Xcel Energy Inc.
Accounts Receivable and Payable with Affiliates [Abstract]
Accounts Receivable		430	430	424
Dividends [Abstract]
Cash dividends paid to Xcel Energy by subsidiaries			1,344	2,527	$ 2,987
Money Pool [Abstract]
Loan outstanding at period end		0	0	57	39
Average loan outstanding		0	16	104	47
Maximum loan outstanding		0	$ 439	$ 350	$ 250
Weighted average interest rate, computed on a daily basis (percentage)			0.08%	0.60%	2.15%
Weighted average interest rate at period end (percentage)				0.07%	1.63%
Interest Income Money Pool		0
Money pool interest income			$ 0	$ 1	$ 1
Xcel Energy Inc. | NSP Minnesota
Accounts Receivable and Payable with Affiliates [Abstract]
Accounts Receivable		104	104	81
Xcel Energy Inc. | NSP-Wisconsin
Accounts Receivable and Payable with Affiliates [Abstract]
Accounts Receivable		25	25	9
Xcel Energy Inc. | PSCo
Accounts Receivable and Payable with Affiliates [Abstract]
Accounts Receivable		91	91	98
Xcel Energy Inc. | SPS
Accounts Receivable and Payable with Affiliates [Abstract]
Accounts Receivable		58	58	55
Xcel Energy Inc. | Xcel Energy Services Inc.
Accounts Receivable and Payable with Affiliates [Abstract]
Accounts Receivable		125	125	159
Xcel Energy Inc. | Other Subsidiaries
Accounts Receivable and Payable with Affiliates [Abstract]
Accounts Receivable		$ 27	$ 27	$ 22
[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, 2021		Dec. 31, 2020		Dec. 31, 2019
Allowance for Bad Debts
SEC Schedule, 12-09, Movement in Valuation Allowances and Reserves [Roll Forward]
Balance at Jan. 1		$ 79		$ 55		$ 55
Charged to costs and expenses		60		60		42
Charged to other accounts	[1]	14		12		16
Deductions from reserves	[2]	47		48		58
Balance at Dec. 31		106		79		55
NOL and Tax Credit Valuation Allowances
SEC Schedule, 12-09, Movement in Valuation Allowances and Reserves [Roll Forward]
Balance at Jan. 1		64		67		79
Charged to costs and expenses		5		6		9
Charged to other accounts		0		0		0
Deductions from reserves		5	[3]	9	[4]	21	[3]
Balance at Dec. 31		$ 64		$ 64		$ 67
[1]	Recovery of amounts previously written-off.
[2]	Deductions related primarily to bad debt write-offs.
[3]	Primarily reductions to valuation allowances due to additional NOLs and tax credits forecasted to be used prior to expiration.
[4]	Primarily the reduction of valuation allowances for North Dakota ITC, net of federal income tax benefit, that is offset to a regulatory liability forecasted to be used prior to expiration along with valuation allowances that expired.