Xcel Energy (XEL) 10-K 21 Feb 24 2023 FY Annual report Financial data

Cover Page

Cover Page - USD ($)	12 Months Ended
	Dec. 31, 2023	Feb. 15, 2024	Jun. 30, 2023
Cover [Abstract]
Document Type	10-K
Document Annual Report	true
Document Period End Date	Dec. 31, 2023
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			$ 34,278,999,603
Entity Common Stock, Shares Outstanding		555,155,770
Entity Registrant Name	XCEL ENERGY INC
Entity Central Index Key	0000072903
Current Fiscal Year End Date	--12-31
Document Fiscal Year Focus	2023
Document Fiscal Period Focus	FY
Amendment Flag	false
Document Financial Statement Error Correction [Flag]	false

Audit Information

Audit Information	12 Months Ended
	Dec. 31, 2023
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, 2023
Accounting Standards Update and Change in Accounting Principle [Abstract]
Accounting Pronouncements	Recently Issued Segment Reporting — In November 2023, the FASB issued ASU 2023-07 – Segment Reporting (Topic 280) – Improvements to Reportable Segment Disclosures , which extends the existing requirements for annual disclosures to quarterly periods, and requires that both annual and quarterly disclosures present segment expenses using line items consistent with information regularly provided to the chief operating decision maker. The ASU is effective for annual periods beginning after Dec. 15, 2023 and quarterly periods beginning after Dec. 15, 2024, and Xcel Energy does not expect implementation of the new disclosure guidance to have a material impact to its consolidated financial statements. Income Taxes — In December 2023, the FASB issued ASU 2023-09 – Income Taxes (Topic 740) – Improvements to Income Tax Disclosures

CONSOLIDATED STATEMENTS OF INCO

CONSOLIDATED STATEMENTS OF INCOME - USD ($) shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Operating revenues
Electric	$ 11,446	$ 12,123	$ 11,205
Natural Gas	2,645	3,080	2,132
Other	115	107	94
Total operating revenues	14,206	15,310	13,431
Operating expenses
Electric fuel and purchased power	4,278	5,005	4,733
Cost of natural gas sold and transported	1,456	1,910	1,081
Cost of sales — other	49	44	38
Operating and maintenance expenses	2,444	2,491	2,321
Conservation and demand side management expenses	286	331	304
Depreciation and amortization	2,448	2,413	2,121
Taxes (other than income taxes)	657	688	630
Loss on Comanche Unit 3 litigation	35	0	0
Workforce reduction expenses	72	0	0
Total operating expenses	11,725	12,882	11,228
Operating income	2,481	2,428	2,203
Other income (expense), net	22	(13)	5
Earnings from equity method investments	35	36	62
Allowance for funds used during construction — equity	91	75	73
Interest charges and financing costs
Interest charges — includes other financing costs of $32, $31 and $29, respectively	1,055	953	842
Allowance for funds used during construction — debt	(51)	(28)	(26)
Total interest charges and financing costs	1,004	925	816
Income before income taxes	1,625	1,601	1,527
Income tax benefit	(146)	(135)	(70)
Net income	$ 1,771	$ 1,736	$ 1,597
Weighted average common shares outstanding:
Basic	552	547	539
Diluted	552	547	540
Earnings per average common share:
Basic	$ 3.21	$ 3.18	$ 2.96
Diluted	$ 3.21	$ 3.17	$ 2.96

CONSOLIDATED STATEMENTS OF IN_2

CONSOLIDATED STATEMENTS OF INCOME (Parenthetical) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Income Statement [Abstract]
Other financing costs	$ 32	$ 31	$ 29

CONSOLIDATED STATEMENTS OF COMP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Comprehensive income:
Net income	$ 1,771	$ 1,736	$ 1,597
Pension and retiree medical benefits:
Net pension and retiree medical (losses) gains arising during the period, net of tax	(4)	5	0
Reclassification of losses to net income, net of tax	2	4	8
Derivative instruments:
Net fair value (decrease) increase, net of tax	(2)	16	4
Reclassification of losses to net income, net of tax	3	5	6
Total other comprehensive (loss) income	(1)	30	18
Total comprehensive income	$ 1,770	$ 1,766	$ 1,615

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Operating activities
Net income	$ 1,771	$ 1,736	$ 1,597
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization	2,471	2,436	2,143
Nuclear fuel amortization	96	118	114
Deferred income taxes	59	140	79
Allowance for equity funds used during construction	(91)	(75)	(73)
Earnings from equity method investments	(35)	(36)	(62)
Dividends from equity method investments	35	37	42
Provision for bad debts	79	73	60
Share-based compensation expense	25	20	31
Changes in operating assets and liabilities:
Accounts receivable	(27)	(429)	(164)
Accrued unbilled revenues	252	(243)	(149)
Inventories	(98)	(203)	(126)
Other current assets	86	(58)	(34)
Accounts payable	(149)	195	138
Net regulatory assets and liabilities	911	570	(973)
Other current liabilities	200	102	(1)
Pension and other employee benefit obligations	17	(49)	(135)
Other, net	(157)	(122)	(140)
Net Cash Provided by (Used in) Operating Activities, Total	5,327	3,932	2,189
Investing activities
Capital/construction expenditures	(5,854)	(4,638)	(4,244)
Purchase of investment securities	(994)	(1,332)	(757)
Proceeds from the sale of investment securities	959	1,297	743
Other, net	(37)	20	(29)
Net Cash Provided by (Used in) Investing Activities, Total	(5,926)	(4,653)	(4,287)
Financing activities
(Repayments of) proceeds from short-term borrowings, net	(28)	(192)	421
Proceeds from Issuance of Long-term Debt	2,630	2,164	2,710
Repayments of long-term debt	(1,151)	(601)	(417)
Proceeds from Issuance of Common Stock	270	322	366
Payments of Dividends	(1,092)	(1,012)	(935)
Proceeds from (Payments for) Other Financing Activities	(12)	(15)	(10)
Net Cash Provided by (Used in) Financing Activities, Total	617	666	2,135
Net change in cash and cash equivalents	18	(55)	37
Cash and Cash Equivalents, at Carrying Value, Beginning Balance	111	166	129
Cash and Cash Equivalents, at Carrying Value, Ending Balance	129	111	166
Supplemental disclosure of cash flow information:
Interest Paid, Excluding Capitalized Interest, Operating Activities	(945)	(887)	(788)
Income Taxes Paid, Net	92	(15)	(4)
Other Noncash Investing and Financing Items [Abstract]
Capital Expenditures Incurred but Not yet Paid	553	626	501
Inventory transfers to plant, property and equipment	197	78	87
Right-of-Use Asset Obtained in Exchange for Operating Lease Liability	238	141	8
Allowance for equity funds used during construction	91	75	73
Stock Issued	$ 64	$ 57	$ 60

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions		Dec. 31, 2023	Dec. 31, 2022
Current assets
Cash and cash equivalents		$ 129	$ 111
Accounts receivable, net		1,315	1,373
Accrued unbilled revenues		853	1,105
Inventories		711	803
Regulatory assets		611	1,059	[1]
Derivative instruments		104	279
Prepaid taxes		52	54
Prepayments and other		294	360
Total current assets		4,069	5,144
Property, plant and equipment, net		51,642	48,253
Other assets
Nuclear decommissioning fund and other investments		3,599	3,234
Regulatory assets		2,798	2,871	[1]
Derivative instruments		76	93
Operating lease right-of-use assets		1,217	1,204
Other		678	389
Total other assets		8,368	7,791
Total assets		64,079	61,188
Current liabilities
Current portion of long-term debt		552	1,151
Short-term debt		785	813
Accounts payable		1,668	1,804
Regulatory liabilities	[2]	528	418
Taxes accrued		557	569
Accrued interest		251	217
Dividends payable		289	268
Derivative instruments		74	76
Operating Lease, Liability, Current		226	217
Other		722	545
Total current liabilities		5,652	6,078
Deferred credits and other liabilities
Deferred income taxes		4,885	4,756
Deferred investment tax credits		60	48
Regulatory liabilities	[2]	5,827	5,569
Asset retirement obligations		3,218	3,380
Derivative instruments		86	113
Customer advances		167	181
Pension and employee benefit obligations		469	390
Operating lease liabilities		1,038	1,038
Other		148	147
Total deferred credits and other liabilities		15,898	15,622
Commitments and contingencies
Capitalization
Long-term debt		24,913	22,813
Common stock — 1,000,000,000 shares authorized of $2.50 par value; 554,941,703 and 549,578,018 shares outstanding at Dec. 31, 2023 and Dec. 31, 2022, respectively		$ 1,387	$ 1,374
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		554,941,703	549,578,018
Additional paid in capital		$ 8,465	$ 8,155
Retained earnings		7,858	7,239
Accumulated other comprehensive loss		(94)	(93)
Total common stockholders’ equity		17,616	16,675
Total liabilities and equity		$ 64,079	$ 61,188
[1] Prior period amounts have been reclassified to conform with current year presentation. Revenue subject to refund of $187 million and $67 million for 2023 and 2022, respectively, 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, 2020		537,438,394
Beginning 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
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
Ending balance at Dec. 31, 2021	15,612	$ 1,360	7,803	6,572	(123)
Increase (Decrease) in Stockholders' Equity
Net income	1,736
Other comprehensive income	30
Cash dividends declared per common share (in dollars per share)		$ 1.95
Dividends declared on common stock	(1,066)			(1,066)
Issuances of common stock (in shares)		5,552,749
Issuances of common stock (value)	359	$ 14	345
Share-based compensation	$ 4		7	(3)
Balance (in shares) at Dec. 31, 2022	549,578,018	549,578,018
Ending balance at Dec. 31, 2022	$ 16,675	$ 1,374	8,155	7,239	(93)
Increase (Decrease) in Stockholders' Equity
Net income	1,771
Other comprehensive income	(1)				(1)
Cash dividends declared per common share (in dollars per share)		$ 2.08
Dividends declared on common stock	(1,148)			(1,148)
Issuances of common stock (in shares)		5,363,685
Issuances of common stock (value)	308	$ 13	295
Share-based compensation	$ 11		15	(4)
Balance (in shares) at Dec. 31, 2023	554,941,703	554,941,703
Ending balance at Dec. 31, 2023	$ 17,616	$ 1,387	$ 8,465	$ 7,858	$ (94)

Summary of Significant Accounti

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2023
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 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: Nonregulated Subsidiary Purpose Eloigne Invests in rental housing projects that qualify for low-income housing tax credits. Capital Services Procures equipment for construction of renewable generation facilities at other subsidiaries. Xcel Energy Venture Holdings, Inc. 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 Minnesota community solar gardens. Xcel Energy Inc. owns the following additional direct subsidiaries, some of which are intermediate holding companies with additional subsidiaries: Direct Subsidiary Xcel Energy Wholesale Group Inc. Xcel Energy Markets Holdings Inc. Xcel Energy Ventures Inc. Xcel Energy Retail Holdings Inc. Xcel Energy Communication Group Inc. Xcel Energy International Inc. Xcel Energy Transmission Holding Company, LLC Nicollet Holdings Company, LLC Xcel Energy Nuclear Services Holdings, LLC Xcel Energy Services Inc. Xcel Energy 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. The equity method of accounting is used for its investments in EIP funds and WYCO. Investments in certain plants and transmission facilities are jointly owned with nonaffiliated utilities. A proportionate share of jointly owned facilities is recorded as property, plant and equipment on the consolidated balance sheets, and Xcel Energy’s share of operating costs associated with these facilities is included in the consolidated statements of income. The 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, 2023 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 to record 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 — The 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 and assumptions for recovery of deferred costs and refund of deferred credits are based on specific ratemaking decisions, precedent or other available information. 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. 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 consolidated financial statements. Income taxes are deferred for all temporary differences between pretax financial and taxable income and between the book and tax bases of assets and liabilities utilizing 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. Utility rate regulation has resulted in the recognition of regulatory assets and liabilities related to income taxes. 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, refundable to utility customers over the remaining life of the related assets. Xcel Energy anticipates that a tax rate increase would predominantly 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 over the book depreciable lives of related property. The requirement to defer and amortize these credits specifically applies to certain federal ITCs, as determined by tax regulations and Xcel Energy tax elections. For tax credits otherwise eligible to be recognized when earned, Xcel Energy considers the impact of rate regulation to determine if these credits and related adjustments should be deferred as regulatory assets or liabilities. 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. This evaluation includes consideration of whether tax credits are expected to be sold at a discount and impact the realization of amounts presented as deferred tax assets. Transferable tax credits are accounted for under ASC 740 Income Taxes , and valuation allowances and any adjustments for discounts incurred on sales transactions are recorded to deferred tax expense, typically recovered in the utility subsidiaries’ regulatory mechanisms. Xcel Energy measures and discloses uncertain tax positions that it has taken or expects to take in its income tax returns. A tax position is recognized in the 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. Interest and penalties related to income taxes are reported within Other income (expense), net 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 and replacement of items determined to be less than a unit of property are charged to expense as incurred. 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. Depreciation expense is recorded 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 are typically recognized at the amounts recovered in rates as authorized by the applicable regulator. 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 3.6% for 2023, 3.7% for 2022 and 3.5% for 2021. See Note 3 for further information. AROs — Xcel Energy records AROs as a liability in the period incurred (if fair value can be reasonably estimated), with the offsetting/associated 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 typically depreciated over the useful life of the long-lived asset. Changes resulting from revisions to timing or amounts 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 normally performed at least every three 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 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 amount can be reasonably estimated. Costs are deferred as a regulatory asset if it is probable 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 is performed. 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. Estimated future expenditures to restore 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. A separate financing component of collections from customers is not recognized as contract terms are short-term in nature. Revenues are 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 RTO/ISOs are also recorded on a gross basis. Other revenues and charges settled/facilitated through an RTO/ISO 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 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, 2023 and 2022, the allowance for bad debts was $128 million and $122 million, respectively. Inventory — Inventory is recorded at the lower of average cost or net realizable value and consisted of the following: (Millions of Dollars) Dec. 31, 2023 Dec. 31, 2022 Inventories Materials and supplies $ 377 $ 330 Fuel 211 201 Natural gas 123 272 Total inventories $ 711 $ 803 Equity Method Investments — The equity method of accounting is used for certain investments including WYCO and EIP funds, which requires Xcel Energy’s recognition of its share of these investees’ results, 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, rabbi trust assets, commodity derivatives, pension and postretirement plan assets and nuclear decommissioning fund assets at estimated fair values in its consolidated financial statements. For interest rate derivatives, quoted prices based primarily on observable market interest rate curves are used to estimate 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, quoted prices for similar contracts or internally prepared valuation models may be used to determine fair value. For rabbi trust assets, pension and postretirement plan assets and nuclear decommissioning fund assets, published trading data and pricing models, generally using the most observable inputs available, are utilized to determine fair value for each security. See Notes 10 and 11 for further information. Derivative Instruments — Xcel Energy uses derivative instruments in connection with its commodity trading activities, and to manage risk associated with changes in interest rates and utility commodity prices, including forward contracts, futures, swaps and options. Derivatives 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. 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 they contain a derivative, and if so, whether they may be exempted from derivative accounting if designated as normal purchases or normal sales. 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 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 and 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. Alternative Revenue — Certain rate rider mechanisms (including decoupling/sales true up and CIP/DSM programs) qualify as alternative revenue programs. These mechanisms arise from instances in which 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, 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. Emissions Allowances — Emissions allowances are recorded at cost, including broker commission fees. The inventory accounting model is utilized for all emissions allowances and any 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, 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 presented 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, 2023
Property, Plant and Equipment [Abstract]
Property, Plant and Equipment Disclosure	Major classes of property, plant and equipment (Millions of Dollars) Dec. 31, 2023 Dec. 31, 2022 Property, plant and equipment, net Electric plant $ 52,494 $ 49,639 Natural gas plant 9,080 8,514 Common and other property 3,190 2,970 Plant to be retired (a) 2,055 2,217 CWIP 2,873 2,124 Total property, plant and equipment 69,692 65,464 Less accumulated depreciation (18,399) (17,502) Nuclear fuel 3,337 3,183 Less accumulated amortization (2,988) (2,892) Property, plant and equipment, net $ 51,642 $ 48,253 (a) Amounts include Sherco 1 and 3 and A.S. King for NSP-Minnesota; Comanche Units 2 and 3, Craig Units 1 and 2, Hayden Units 1 and 2 and coal generation assets at Pawnee pending facility gas conversion for PSCo; and Tolk Unit 1 and 2 and coal generation assets at Harrington pending facility gas conversion for SPS. The Dec. 31, 2022 balance also includes Sherco 2, which was retired on Dec. 31, 2023. Amounts are presented net of accumulated depreciation. Joint Ownership of Generation, Transmission and Gas Facilities The utility subsidiaries’ jointly owned assets as of Dec. 31, 2023: (Millions of Dollars, Except Percent Owned) Plant in Service Accumulated Depreciation Percent Owned NSP-Minnesota Electric generation: Sherco Unit 3 $ 633 $ 480 59 % Sherco common facilities 185 121 80 Sherco substation 5 4 59 Electric transmission: Grand Meadow 11 4 50 Huntley Wilmarth 49 2 50 CapX2020 820 141 51 Total NSP-Minnesota (a) $ 1,703 $ 752 (a) Projects additionally include $2 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 $ 178 $ 25 37 % CapX2020 169 39 80 Total NSP-Wisconsin (a) $ 347 $ 64 (a) Projects additionally include $1 million in CWIP. (Millions of Dollars, Except Percent Owned) Plant in Service Accumulated Depreciation Percent Owned PSCo Electric generation: Hayden Unit 1 $ 157 $ 108 76 % Hayden Unit 2 151 87 37 Hayden common facilities 44 31 53 Craig Units 1 and 2 82 55 10 Craig common facilities 39 25 7 Comanche Unit 3 916 191 67 Comanche common facilities 29 4 77 Electric transmission: Transmission and other facilities 189 75 Various Gas transmission: Rifle, CO to Avon, CO 28 9 60 Gas transmission compressor 8 2 50 Total PSCo (a) $ 1,643 $ 587 (a) Projects additionally include $18 million in CWIP. Each company’s share of operating expenses and construction expenditures is included in the applicable utility accounts. Respective owners are responsible for providing their own financing.

Regulatory Assets and Liabiliti

Regulatory Assets and Liabilities	12 Months Ended
	Dec. 31, 2023
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, 2023 Dec. 31, 2022 (a) Regulatory Assets Current Noncurrent Current Noncurrent Pension and retiree medical obligations 11 Various $ 27 $ 1,106 $ 22 $ 1,069 Recoverable deferred taxes on AFUDC Plant lives — 332 — 292 Net AROs (b) 1, 12 Various — 316 — 339 Excess deferred taxes — TCJA 7 Various 10 198 13 205 Depreciation differences One 17 189 17 193 Environmental remediation costs 1, 12 Various 15 94 20 92 Deferred natural gas, electric, steam energy/fuel costs One three 239 80 581 299 Conservation programs (c) 1 One two 19 54 16 36 Purchased power contract costs Term of related contract 4 40 10 36 PI extended power uprate 11 years 4 38 4 42 Benson biomass PPA termination and asset purchase Five 10 36 10 45 Sales true-up and revenue decoupling One two 7 33 54 — State commission adjustments Plant lives 1 32 1 33 Losses on reacquired debt Term of related debt 2 30 3 32 MISO capacity revenue tracker One two 36 26 — — Gas pipeline inspection and remediation costs One two 40 25 42 13 Contract valuation adjustments (d) 1, 10 Term of related contract 18 22 28 28 Nuclear refueling outage costs 1 One two 43 19 30 12 Grid modernization costs One two 16 17 14 24 Renewable resources and environmental initiatives One two 38 5 50 6 Other Various 65 106 144 75 Total regulatory assets $ 611 $ 2,798 $ 1,059 $ 2,871 (a) Prior period amounts have been reclassified to conform with current year presentation. (b) The 2022 amount is net of the nuclear decommissioning accruals and gains from decommissioning investments. In 2023, the nuclear decommissioning accruals and gains from decommissioning investments exceeded the expected cost of AROs in NSP-Minnesota and was reclassified to a regulatory liability. (c) Includes costs for conservation programs, as well as incentives allowed in certain jurisdictions. (d) Includes the fair value of certain long-term PPAs used to meet energy capacity requirements and valuation adjustments on natural gas commodity purchases. Components of regulatory liabilities: (Millions of Dollars) See Note(s) Remaining Amortization Period Dec. 31, 2023 Dec. 31, 2022 Regulatory Liabilities Current Noncurrent Current Noncurrent Deferred income tax adjustments and TCJA refunds (a) 7 Various $ 7 $ 3,015 $ 9 $ 3,110 Plant removal costs 1, 12 Various — 1,984 — 1,819 Effects of regulation on employee benefit costs (b) Various — 253 — 247 Renewable resources and environmental initiatives Various 9 188 6 173 Net AROs (c) Various — 90 — — Sales true-up and revenue decoupling Two 18 76 — 77 ITC deferrals 1 Various 1 60 1 61 LP&L departure payment Up to 10 years 33 33 — — Formula rates One two 29 18 32 17 DOE settlement One two 18 6 12 3 Deferred natural gas, electric, steam energy/fuel costs Less than one 220 — 39 — Contract valuation adjustments (d) 1, 10 Less than one 56 — 175 1 Conservation programs (e) 1 Less than one 47 — 72 — Other Various 90 104 72 61 Total regulatory liabilities (f) $ 528 $ 5,827 $ 418 $ 5,569 (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 amounts recorded for future recovery of AROs, less amounts recovered through nuclear decommissioning accruals and gains from decommissioning investments. (d) Includes the fair value of FTR instruments utilized/intended to offset the impacts of transmission system congestion. (e) Includes costs for conservation programs, as well as incentives allowed in certain jurisdictions. (f) Revenue subject to refund of $187 million and $67 million for 2023 and 2022, respectively, is included in other current liabilities. Xcel Energy’s regulatory assets not earning a return include past expenditures of $1,085 million and $1,020 million at Dec. 31, 2023 and 2022 respectively, which predominately relate to purchased natural gas and electric energy costs (including certain costs related to Winter Storm Uri), sales true-up and revenue decoupling, various renewable resources/environmental initiatives and certain prepaid pension amounts. Additionally, the unfunded portion of pension and retiree medical obligations and net AROs (i.e. deferrals for which cash has not been disbursed) do not earn a return.

Borrowings and Other Financing

Borrowings and Other Financing Instruments Borrowings and Other Financing Instruments	12 Months Ended
	Dec. 31, 2023
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 other borrowings outstanding: (Millions of Dollars, Except Interest Rates) Three Months Ended Dec. 31, 2023 Year Ended Dec. 31 2023 2022 2021 Borrowing limit $ 3,550 $ 3,550 $ 3,550 $ 3,100 Amount outstanding at period end 785 785 813 1,005 Average amount outstanding 339 491 552 1,399 Maximum amount outstanding 785 1,241 1,357 2,054 Weighted average interest rate, computed on a daily basis 5.51 % 5.12 % 1.47 % 0.57 % Weighted average interest rate at period end 5.52 5.52 4.66 0.31 Bilateral Credit Agreement — In April 2023, 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, 2023, NSP-Minnesota had $65 million outstanding letters of credit under the $75 million 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, 2023 and 2022, there were $44 million and $43 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 — In September 2022 , Xcel Energy Inc., NSP-Minnesota, NSP-Wisconsin, PSCo and SPS each entered into an amended five-year credit agreement with a syndicate of banks. The aggregate borrowing limit is $3.55 billion. The amended credit agreements mature in September 2027. Features of the credit facilities: Debt-to-Total Capitalization Ratio (a) Amount Facility May Be Increased (millions of dollars) (b) Additional Periods for Which a One-Year Extension May Be Requested (c) 2023 2022 Xcel Energy Inc. (d) 59.8 % 59.7 % $ 350 2 NSP-Minnesota 47.7 47.7 150 2 NSP-Wisconsin 48.2 47.4 N/A 1 SPS 46.1 45.7 50 2 PSCo 44.8 44.0 100 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) Amounts authorized by state commissions in respective jurisdictions. (c) All extension requests are subject to majority bank group approval. (d) 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, 2023, 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, 2023: (Millions of Dollars) Credit Facility (a) Drawn (b) Available Xcel Energy Inc. $ 1,500 $ 165 $ 1,335 PSCo 700 349 351 NSP-Minnesota 700 180 520 SPS 500 75 425 NSP-Wisconsin 150 60 90 Total $ 3,550 $ 829 $ 2,721 (a) These credit facilities mature in September 2027. (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, 2023 and 2022. Long-Term Borrowings and Other Financing Instruments Generally, the property of NSP-Minnesota, NSP-Wisconsin, PSCo and SPS is subject to the liens of their respective first mortgage indentures for the benefit of bondholders. 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 2023 2022 Unsecured senior notes 0.50 % Oct. 15, 2023 $ — $ 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 1.75 March 15, 2027 500 500 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 3.40 June 1, 2030 600 600 Unsecured senior notes 2.35 Nov. 15, 2031 300 300 Unsecured senior notes (a) 4.60 June 1, 2032 700 700 Unsecured senior notes (b) 5.45 Aug. 15, 2033 800 — Unsecured senior notes 6.50 July 1, 2036 300 300 Unsecured senior notes 4.80 Sept. 15, 2041 250 250 Unsecured senior notes 3.50 Dec. 1, 2049 500 500 Unamortized discount (8) (7) Unamortized debt issuance cost (36) (35) Current maturities — (500) Total long-term debt $ 6,136 $ 5,338 (a) 2022 financing. (b) 2023 financing. NSP-Minnesota Financing Instrument Interest Rate Maturity Date 2023 2022 First mortgage bonds 2.60 % May 15, 2023 $ — $ 400 First mortgage bonds 7.125 July 1, 2025 250 250 First mortgage bonds 6.50 March 1, 2028 150 150 First mortgage bonds 2.25 April 1, 2031 425 425 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 Sept. 15, 2047 600 600 First mortgage bonds 2.90 March 1, 2050 600 600 First mortgage bonds 2.60 June 1, 2051 700 700 First mortgage bonds 3.20 April 1, 2052 425 425 First mortgage bonds (a) 4.50 June 1, 2052 500 500 First mortgage bonds (b) 5.10 May 15, 2053 800 — Other long-term debt 2 3 Unamortized discount (49) (45) Unamortized debt issuance cost (73) (66) Current maturities — (400) Total long-term debt $ 7,330 $ 6,542 (a) 2022 financing. (b) 2023 financing. NSP-Wisconsin Financing Instrument Interest Rate Maturity Date 2023 2022 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 3.05 May 1, 2051 100 100 First mortgage bonds 2.82 May 1, 2051 100 100 First mortgage bonds (a) 4.86 Sept. 15, 2052 100 100 First mortgage bonds (b) 5.30 June 15, 2053 125 — Unamortized discount (3) (3) Unamortized debt issuance cost (11) (11) Current maturities (200) — Total long-term debt $ 1,011 $ 1,086 (a) 2022 financing. (b) 2023 financing. PSCo Financing Instrument Interest Rate Maturity Date 2023 2022 First mortgage bonds 2.50 % March 15, 2023 $ — $ 250 First mortgage bonds 2.90 May 15, 2025 250 250 First mortgage bonds 3.70 June 15, 2028 350 350 First mortgage bonds 1.90 Jan. 15, 2031 375 375 First mortgage bonds 1.875 June 15, 2031 750 750 First mortgage bonds (a) 4.10 June 1, 2032 300 300 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 2.70 Jan. 15, 2051 375 375 First mortgage bonds (a) 4.50 June 1, 2052 400 400 First mortgage bonds (b) 5.25 April 1, 2053 850 — Unamortized discount (41) (37) Unamortized debt issuance cost (59) (53) Current maturities — (250) Total long-term debt $ 7,450 $ 6,610 (a) 2022 financing. (b) 2023 financing. SPS Financing Instrument Interest Rate Maturity Date 2023 2022 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 3.15 May 1, 2050 350 350 First mortgage bonds 3.15 May 1, 2050 250 250 First mortgage bonds (a) 5.15 June 1, 2052 200 200 First mortgage bonds (b) 6.00 Sept. 15, 2053 100 — Unamortized discount (10) (10) Unamortized debt issuance cost (29) (29) Current maturities (350) — Total long-term debt $ 2,961 $ 3,211 (a) 2022 financing. (b) 2023 financing. Other Subsidiaries Financing Instrument Interest Rate Maturity Date 2023 2022 Various Eloigne affordable housing project notes 0.00% - 8.00% 2024 - 2055 $ 27 $ 27 Current maturities (2) (1) Total long-term debt $ 25 $ 26 Maturities of long-term debt: (Millions of Dollars) 2024 $ 552 2025 1,103 2026 501 2027 501 2028 1,133 Deferred Financing Costs — Deferred financing costs of approximately $209 million and $193 million, net of amortization, are presented as a deduction from the carrying amount of long-term debt as of Dec. 31, 2023 and 2022, respectively. Equity through DRIP and Benefits Program — Xcel Energy issued $88 million of equity in 2023 and $84 million of equity in 2022 through the DRIP and benefits programs. The program allows shareholders to reinvest their dividends directly in Xcel Energy Inc. common stock. 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. In 2021, 5.33 million shares of common stock were issued (approximately $350 million in net proceeds and $3 million in transaction fees paid). In 2022, 4.30 million shares of common stock were issued (approximately $300 million in net proceeds and $3 million in transaction fees paid). In 2023, 0.90 million shares of common stock were issued ($62 million in net proceeds and $1 million in transaction fees paid). In October 2023, the 2021 ATM offering was closed. In October 2023, Xcel Energy Inc. filed a prospectus supplement under which it may sell up to $2.5 billion of its common stock through an ATM program. In the fourth quarter, through this ATM Program, Xcel Energy Inc. issued 3.12 million shares of common stock ($188 million in net proceeds and $2 million in transaction fees paid). Capital Stock — Preferred stock authorized/outstanding: Preferred Stock Authorized (Shares) Par Value of Preferred Stock Preferred Stock Outstanding (Shares) 2023 and 2022 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, 2023 Common Stock Outstanding (Shares) as of Dec. 31, 2022 1,000,000,000 $ 2.50 554,941,703 549,578,018 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, 2023: Equity to Total Equity to Total Capitalization Ratio Actual Low High 2023 NSP-Minnesota 47.2 % 57.6 % 52.3 % NSP-Wisconsin (a) 52.5 N/A 52.7 SPS (b) 45.0 55.0 54.6 (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) Excludes short-term debt. (Amounts in Millions) Unrestricted Retained Earnings Total Capitalization Limit on Total Capitalization NSP-Minnesota $ 1,508 $ 15,702 $ 16,140 NSP-Wisconsin 9 2,520 N/A SPS (a) 617 7,298 N/A (a) 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, 2023: (Millions of Dollars) Long-Term Debt Short-Term Debt NSP-Minnesota 52.8% of total capitalization (a) $ 2,400 (a) NSP-Wisconsin $ 625 150 PSCo 450 800 SPS 100 600 (a)

Revenues

Revenues	12 Months Ended
	Dec. 31, 2023
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, 2023 (Millions of Dollars) Electric Natural Gas All Other Total Major revenue types Revenue from contracts with customers: Residential $ 3,560 $ 1,560 $ 59 $ 5,179 C&I 5,703 833 30 6,566 Other 150 — 13 163 Total retail 9,413 2,393 102 11,908 Wholesale 815 — — 815 Transmission 649 — — 649 Other 63 156 — 219 Total revenue from contracts with customers 10,940 2,549 102 13,591 Alternative revenue and other 506 96 13 615 Total revenues $ 11,446 $ 2,645 $ 115 $ 14,206 Year Ended Dec. 31, 2022 (Millions of Dollars) Electric Natural Gas All Other Total Major revenue types Revenue from contracts with customers: Residential $ 3,542 $ 1,814 $ 53 $ 5,409 C&I 5,807 998 32 6,837 Other 148 — 10 158 Total retail 9,497 2,812 95 12,404 Wholesale 1,354 — — 1,354 Transmission 675 — — 675 Other 97 178 — 275 Total revenue from contracts with customers 11,623 2,990 95 14,708 Alternative revenue and other 500 90 12 602 Total revenues $ 12,123 $ 3,080 $ 107 $ 15,310 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

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2023
Income Tax Disclosure [Abstract]
Income Taxes	Total income tax expense from operations differs from the amount computed by applying the statutory federal income tax rate to income before income tax expense. Effective income tax rate for years ended Dec. 31: 2023 2022 2021 Federal statutory rate 21.0 % 21.0 % 21.0 % State income tax on pretax income, net of federal tax effect 4.9 4.9 5.0 (Decreases) increases in tax from: Wind PTCs (a) (28.1) (27.4) (23.4) Plant regulatory differences (b) (5.6) (5.5) (6.2) Other tax credits, net NOL & tax credit allowances (1.3) (1.3) (1.1) Other, net 0.1 (0.1) 0.1 Effective income tax rate (9.0) % (8.4) % (4.6) % (a) Wind PTCs net of estimated transfer discount are credited to customers (reduction to revenue) and do not materially impact net income. (b) Plant regulatory differences primarily relate to the credit of excess deferred taxes to customers through the average rate assumption method. Income tax benefits associated with the credit are offset by corresponding revenue reductions. Components of income tax expense for years ended Dec. 31: (Millions of Dollars) 2023 2022 2021 Current federal tax expense $ 113 $ 1 $ 15 Current state tax expense (benefit) 16 3 (2) Current change in unrecognized tax (benefit) expense (21) 5 1 Deferred federal tax benefit (331) (239) (183) Deferred state tax expense 75 96 99 Deferred change in unrecognized tax expense 7 3 5 Deferred ITCs (5) (4) (5) Total income tax benefit $ (146) $ (135) $ (70) Components of deferred income tax expense as of Dec. 31: (Millions of Dollars) 2023 2022 2021 Deferred tax expense (benefit) excluding items below $ 129 $ (138) $ 148 Adjustments to deferred income taxes for wind production tax credit cash transfers (a) (190) — — Amortization and adjustments to deferred income taxes on income tax regulatory assets and liabilities (188) 8 (221) Tax benefit allocated to other comprehensive income and other — (10) (6) Deferred tax benefit $ (249) $ (140) $ (79) (a) Proceeds from tax credit transfers are included in cash received (paid) for income taxes in the consolidated statement of cash flows. Components of net deferred tax liability as of Dec. 31: (Millions of Dollars) 2023 2022 (a) Deferred tax liabilities: Differences between book and tax bases of property $ 6,744 $ 6,442 Regulatory assets 538 484 Operating lease assets 327 325 Pension expense 151 159 Deferred fuel costs 67 222 Other 84 90 Total deferred tax liabilities $ 7,911 $ 7,722 Deferred tax assets: Tax credit carryforward $ 1,718 $ 1,679 Regulatory liabilities 730 718 Operating lease liabilities 327 325 Other employee benefits 117 102 Deferred investment tax credits 16 14 NOL carryforward — 57 NOL and tax credit valuation allowances (70) (62) Other 188 133 Total deferred tax assets 3,026 2,966 Net deferred tax liability $ 4,885 $ 4,756 (a) Prior periods have been reclassified to conform to current year presentation. Other Income Tax Matters — NOL amounts represent the tax loss that is carried forward and tax credits represent the deferred tax asset. NOL and tax credit carryforwards as of Dec. 31: (Millions of Dollars) 2023 2022 Federal NOL carryforward $ — $ 20 Federal tax credit carryforwards 1,644 1,593 Valuation allowances for federal credit carryforwards (10) — State NOL carryforwards 11 1,022 Valuation allowances for state NOL carryforwards (2) (3) State tax credit carryforwards, net of federal detriment (a) 74 85 Valuation allowances for state credit carryforwards, net of federal benefit (b) (60) (62) (a) State tax credit carryforwards are net of federal detriment of $20 million and $23 million as of Dec. 31, 2023 and 2022, respectively. (b) Valuation allowances for state tax credit carryforwards were net of federal benefit of $16 million as of Dec. 31, 2023 and 2022. Federal carryforward periods expire between 2037 and 2043 and state carryforward periods expire starting 2024. Unrecognized Tax Benefits Federal Audit — Statute of limitations applicable to Xcel Energy’s consolidated federal income tax returns expire as follows: Tax Year(s) Expiration 2014 - 2016 March 2025 2020 September 2024 Additionally, the statute of limitations related to the federal tax credit carryforwards will remain open until those credits are utilized in subsequent returns. Further, the statute of limitations related to the additional federal tax loss carryback claim filed in 2020 has been extended. As of Dec. 31, 2023 the IRS issued its Revenue Agent’s Report related to the federal tax loss carryback claim. The Company materially agrees with the report and re-recognized the related benefit in December 2023. State Audits — Xcel Energy files consolidated state tax returns based on income in its major operating jurisdictions and various other state income-based tax returns. As of Dec. 31, 2023, Xcel Energy’s earliest open tax years (subject to examination by state taxing authorities in its major operating jurisdictions) were as follows: State Tax Year(s) Expiration Colorado 2014 - 2016 March 2026 Colorado 2019 October 2024 Minnesota 2014 - 2016 September 2025 Minnesota 2019 May 2024 Texas 2016, 2018 May 2024 Texas 2017 July 2025 Texas 2019 August 2024 Wisconsin 2016 - 2018 May 2024 Wisconsin 2019 October 2024 • In 2020, Minnesota began an audit of tax years 2015 - 2018. In 2022, the state of Minnesota issued its audit report and in 2023, the Company agreed to the report without any material adjustments. • In 2021, Texas began an audit of tax years 2016 - 2019. As of Dec. 31, 2023, no material adjustments have been proposed. • In 2021, Wisconsin began an audit of tax years 2016-2019. As of Dec. 31, 2023, no material adjustments have been proposed. • No other state income tax audits are in progress for its major operating jurisdictions as of Dec. 31, 2023. Unrecognized tax benefit balance includes permanent tax positions, which if recognized would affect the ETR. In addition, the unrecognized tax benefit balance includes temporary tax positions for which deductibility is highly certain, but for which there is uncertainty about the timing. A change in the period of deductibility would not affect the ETR but would accelerate the payment to the taxing authority. Unrecognized tax benefits - permanent vs. temporary: (Millions of Dollars) Dec. 31, 2023 Dec. 31, 2022 Unrecognized tax benefit — Permanent tax positions $ 41 $ 55 Unrecognized tax benefit — Temporary tax positions — 12 Total unrecognized tax benefit $ 41 $ 67 Changes in unrecognized tax benefits: (Millions of Dollars) 2023 2022 2021 Balance at Jan. 1 $ 67 $ 58 $ 52 Additions based on tax positions related to the current year 5 7 5 Additions for tax positions of prior years 1 6 2 Reductions for tax positions of prior years (29) (1) (1) Reductions for tax positions related to settlements with taxing authorities (1) (1) — Reductions for tax positions related to statute of limitations (2) (2) — Balance at Dec. 31 $ 41 $ 67 $ 58 Unrecognized tax benefits were reduced by tax benefits associated with NOL and tax credit carryforwards: (Millions of Dollars) Dec. 31, 2023 Dec. 31, 2022 NOL and tax credit carryforwards $ (35) $ (40) As IRS audits resume and as state audits progress, it is reasonably possible that the amount of unrecognized tax benefit could decrease up to approximately $14 million in the next 12 months. Payable for interest related to unrecognized tax benefits is partially offset by the interest benefit associated with NOL and tax credit carryforwards. Interest payable related to unrecognized tax benefits: (Millions of Dollars) 2023 2022 2021 Payable for interest related to unrecognized tax benefits at Jan. 1 $ (4) $ (3) $ (3) Interest benefit (expense) related to unrecognized tax benefits 3 (1) — Payable for interest related to unrecognized tax benefits at Dec. 31 $ (1) $ (4) $ (3) No penalties were accrued related to unrecognized tax benefits as of Dec. 31, 2023, 2022 or 2021.

Share-Based Compensation

Share-Based Compensation	12 Months Ended
	Dec. 31, 2023
Share-Based Payment Arrangement [Abstract]
Share-Based Compensation	Incentive Plan Including Share-Based Compensation — Xcel Energy has authorized 7.0 million equity shares under an incentive plan (the Amended and Restated 2015 Omnibus Incentive Plan). Equity Awards — Xcel Energy‘s Board of Directors has granted equity awards under the 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. The total time-based equity shares granted subject only to service conditions was 0.4 million in 2023 and 0.2 million in 2022 and 2021 respectively. The performance conditions for a portion of the awards granted from 2021 to 2023 are based on relative TSR and environmental goals. Equity awards with performance conditions will be settled after three years, with payouts ranging from zero to 200% depending on achievement. Equity award units granted to employees: (Units in Thousands) 2023 2022 2021 Granted units 586 395 421 Weighted average grant date fair value $ 67.06 $ 68.43 $ 66.03 Equity awards vested: (Units in Thousands, Fair Value in Millions) 2023 2022 2021 Vested Units 329 319 392 Total Fair Value $ 20 $ 22 $ 27 Changes in the nonvested portion of equity award units: (Units in Thousands) Units Weighted Average Nonvested Units at Jan. 1, 2023 708 $ 67.35 Granted 586 67.06 Forfeited (184) 68.42 Vested (329) 66.23 Dividend equivalents 38 67.65 Nonvested Units at Dec. 31, 2023 819 67.36 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 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) 2023 2022 2021 Granted units 38 29 31 Weighted average grant date fair value $ 63.12 $ 71.97 $ 68.15 Changes in stock equivalent units: (Units in Thousands) Units Weighted Average Stock equivalent units at Jan. 1, 2023 597 $ 41.75 Granted 38 63.12 Units distributed (134) 33.90 Dividend equivalents 16 64.95 Stock equivalent units at Dec. 31, 2023 517 46.07 Liability Awards — Xcel Energy’s Board of Directors has granted TSR liability awards under the 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 Liability awards granted: (In Thousands) 2023 2022 2021 Awards granted 216 165 221 Liability awards settled: (Units In Thousands, Settlement Amount in Millions) 2023 2022 2021 Awards settled 282 411 446 Settlement amount (cash, common stock and deferred amounts) $ 19 $ 27 $ 27 TSR liability awards of $13 million were settled in cash in 2023. Share-Based Compensation Expense — Award settlement determination (permitting cash or share settlement) is made by Xcel Energy, not the participants. Equity 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 are accounted for as liabilities, as historically they are partially settled in cash. 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 award on the date the settlement date. Compensation costs related to share-based awards: (Millions of Dollars) 2023 2022 2021 Cost for share-based awards (a) $ 27 $ 36 $ 31 Tax benefit recognized in income 7 9 8 (a) Compensation costs for share-based payments are included in O&M expense. Amount for equity awards (non-cash) was $25 million in 2023. There was approximately $38 million and $37 million as of Dec. 31, 2023 and 2022, respectively, 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 1.7 years.

Earnings Per Share

Earnings Per Share	12 Months Ended
	Dec. 31, 2023
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 — 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 following the grant of these awards. 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) 2023 2022 2021 Basic 552 547 539 Diluted (a) 552 547 540 (a) Diluted common shares outstanding included common stock equivalents of 0.3 million shares for 2023, 2022 and 2021.

Fair Value of Financial Assets

Fair Value of Financial Assets and Liabilities	12 Months Ended
	Dec. 31, 2023
Fair Value Disclosures [Abstract]
Fair Value of Financial Assets and Liabilities	Fair Value Measurements Accounting guidance for fair value measurements and disclosures provides a hierarchical framework for disclosing the observability of the inputs utilized in measuring assets and liabilities at fair value. • 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 actively traded instruments with observable actual trading prices. • Level 2 — Pricing inputs are other than actual trading 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 include those valued with models requiring significant judgment or estimation. Specific valuation methods include: 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 funds require approval of the fund for any unscheduled redemption, and such redemptions may be approved or denied by the fund at its sole discretion. Unscheduled distributions from real estate commingled funds 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 contracts relate to inactive delivery locations or extend to periods beyond those readily observable on active exchanges, the significance of the use of less observable inputs 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 values of these instruments are derived from, and designed to offset, the costs of transmission congestion. In addition to overall transmission load, congestion is also influenced by the operating schedules of power plants and the consumption of electricity pertinent to a given transmission path. Unplanned plant outages, scheduled plant maintenance, changes in the relative costs of fuels used in generation, weather and overall changes in demand for electricity can each impact the operating schedules of the power plants on the transmission grid and the value of these instruments. FTRs are recognized at fair value and adjusted each period prior to settlement. Given the limited observability of certain variables underlying the reported auction values of FTRs, these fair value measurements have been assigned a Level 3 classification. Net congestion costs, including the impact of FTR settlements, are shared through fuel and purchased energy cost recovery mechanisms. As such, the fair value of the unsettled instruments (i.e., derivative asset or liability) is offset/deferred as a regulatory asset or liability. 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 $1.2 billion and $1.0 billion as of Dec. 31, 2023 and 2022, respectively, and unrealized losses were $29 million and $90 million as of Dec. 31, 2023 and 2022, respectively. Non-derivative instruments with recurring fair value measurements in the nuclear decommissioning fund: Dec. 31, 2023 Fair Value (Millions of Dollars) Cost Level 1 Level 2 Level 3 NAV Total Nuclear decommissioning fund (a) Cash equivalents $ 41 $ 41 $ — $ — $ — $ 41 Commingled funds 721 — — — 1,049 1,049 Debt securities 784 — 771 9 — 780 Equity securities 508 1,339 2 — — 1,341 Total $ 2,054 $ 1,380 $ 773 $ 9 $ 1,049 $ 3,211 (a) Reported in nuclear decommissioning fund and other investments on the consolidated balance sheets, which also includes $244 million of equity method investments and $144 million of rabbi trust assets and other miscellaneous investments. Dec. 31, 2022 Fair Value (Millions of Dollars) Cost Level 1 Level 2 Level 3 NAV Total Nuclear decommissioning fund (a) Cash equivalents $ 29 $ 29 $ — $ — $ — $ 29 Commingled funds 803 — — — 1,178 1,178 Debt securities 738 — 669 6 — 675 Equity securities 406 999 1 — — 1,000 Total $ 1,976 $ 1,028 $ 670 $ 6 $ 1,178 $ 2,882 (a) Reported in nuclear decommissioning fund and other investments on the consolidated balance sheets, which also includes $219 million of equity investments in unconsolidated subsidiaries and $133 million of rabbi trust assets and other miscellaneous investments. For the years ended Dec. 31, 2023 and 2022, 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, 2023: 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 $ 261 $ 269 $ 246 $ 780 Rabbi Trusts Xcel Energy has established rabbi trusts to provide partial funding for future deferred compensation plan distributions. The fair value of assets held in the rabbi trusts were $88 million and $80 million at Dec. 31, 2023 and 2022, respectively, comprised of cash equivalents and mutual funds (level 1 valuation methods). Amounts are reported in nuclear decommissioning fund and other investments on the consolidated balance sheet. Derivative Activities and 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, and utility commodity prices. Interest Rate Derivatives — Xcel Energy enters into contracts that effectively fix the interest rate on a specified principal amount of a hypothetical future debt issuance. These financial swaps net settle based on changes in a specified benchmark interest rate, acting as a hedge of changes in market interest rates that will impact specified anticipated debt issuances. These derivative instruments are designated as cash flow hedges for accounting purposes, with changes in fair value prior to occurrence of the hedged transactions recorded as other comprehensive income. As of Dec. 31, 2023, accumulated other comprehensive loss related to interest rate derivatives included $2 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, 2023, Xcel Energy had unsettled interest swaps outstanding with a notional amount of $420 million. These interest rate derivatives were designated as cash flow hedges, with changes in fair value recorded to other comprehensive income. See Note 13 for the financial impact of qualifying interest rate cash flow hedges on Xcel Energy’s accumulated other comprehensive loss included in the consolidated statements of common stockholder’s equity and in the consolidated statements of comprehensive income. Wholesale and Commodity Trading — 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 the activities governed by this policy. Derivative instruments entered into for trading purposes are presented in the consolidated statements of income as electric revenues, net of any sharing with customers. These activities are not intended to mitigate commodity price risk associated with regulated electric and natural gas operations. Sharing of these margins is determined through state regulatory proceedings as well as the operation of the FERC-approved joint operating agreement. 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. This could include the purchase or sale of energy or energy-related products, natural gas to generate electric energy, natural gas for resale and FTRs. The most significant derivative positions outstanding at Dec. 31, 2023 and 2022 for this purpose relate to FTR instruments administered by MISO and SPP. These instruments are intended to offset the impacts of transmission system congestion. Higher congestion costs in recent years have led to an increase in the fair value of FTRs. Settlements of FTRs are shared with electric customers through fuel and purchased energy cost-recovery mechanisms. When Xcel Energy enters into derivative instruments that mitigate commodity price risk on behalf of electric and natural gas customers, the instruments are not typically 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, 2023, Xcel Energy had no commodity contracts designated as cash flow hedges. Gross notional amounts of commodity forwards, options and FTRs: (Amounts in Millions) (a)(b) Dec. 31, 2023 Dec. 31, 2022 MWh of electricity 48 61 MMBtu of natural gas 84 131 (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, 2023, four of Xcel Energy’s ten most significant counterparties for these activities, comprising $49 million or 23% of this credit exposure, had investment grade credit ratings from S&P Global Ratings, Moody’s Investor Services or Fitch Ratings. Five of the ten most significant counterparties, comprising $78 million or 37% of this credit exposure, were not rated by these external ratings agencies, but based on Xcel Energy’s internal analysis, had credit quality consistent with investment grade. One of these significant counterparties, comprising $45 million or 21% 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. 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, 2023 and 2022, there were $12 million and $4 million, respectively, of derivative liabilities with such underlying contract provisions, respectively. Also, certain contracts may contain cross default provisions that may require the posting of collateral or settlement of the contracts if there was a failure under other financing arrangements related to payment terms or other covenants. As of Dec. 31, 2023 and 2022, there were approximately $88 million and $76 million of derivative liabilities with such underlying contract provisions, respectively. Certain derivative instruments are also subject to contract provisions that contain adequate assurance clauses. These provisions allow counterparties to seek performance assurance, including cash collateral, in the event that a given utility subsidiary’s ability to fulfill its contractual obligations is reasonably expected to be impaired. Xcel Energy had no collateral posted related to adequate assurance clauses in derivative contracts as of Dec. 31, 2023 and 2022. Recurring Derivative Fair Value Measurements Impact of derivative activity: Pre-Tax Fair Value Gains (Losses) Recognized During the Period in: (Millions of Dollars) Accumulated Other Comprehensive Loss Regulatory (Assets) and Liabilities Year Ended Dec. 31, 2023 Derivatives designated as cash flow hedges Interest rate $ (2) $ — Total $ (2) $ — Other derivative instruments Electric commodity $ — $ (137) Natural gas commodity — (13) Total $ — $ (150) Year Ended Dec. 31, 2022 Interest rate $ 22 $ — Total $ 22 $ — Other derivative instruments Electric commodity $ — $ (10) Natural gas commodity — (16) Total $ — $ (26) Year Ended Dec. 31, 2021 Interest rate $ 5 $ — Total $ 5 $ — Other derivative instruments Electric commodity $ — $ 32 Natural gas commodity — (4) Total $ — $ 28 Pre-Tax (Gains) Losses Reclassified into Income During the Period from: Pre-Tax Gains (Losses) Recognized During the Period in Income (Millions of Dollars) Accumulated Other Comprehensive Loss Regulatory Assets and (Liabilities) Year Ended Dec. 31, 2023 Derivatives designated as cash flow hedges Interest rate $ 5 (a) $ — $ — Total $ 5 $ — $ — Other derivative instruments Commodity trading $ — $ — $ (7) (b) Electric commodity — 123 (c) — Natural gas commodity — 15 (d) (27) (d)(e) Total $ — $ 138 $ (34) Year Ended Dec. 31, 2022 Derivatives designated as cash flow hedges Interest rate $ 7 (a) $ — $ — Total $ 7 $ — $ — Other derivative instruments Commodity trading $ — $ — $ 25 (b) Electric commodity — 3 (c) — Natural gas commodity — 10 (d) (27) (d)(e) Total $ — $ 13 $ (2) 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)(e) Total $ — $ (18) $ 41 (a) Recorded to interest charges. (b) Recorded to electric revenues. Presented amounts do not reflect non-derivative transactions or margin sharing with customers. (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. FTR settlements are shared with customers and do not have a material impact on net income. Presented amounts reflect changes in fair value between FTR auction and settlement dates, but exclude the original auction fair value. (d) 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. (e) Relates primarily to option premium amortization. Xcel Energy had no derivative instruments designated as fair value hedges during the years ended Dec. 31, 2023, 2022 and 2021. Derivative assets and liabilities measured at fair value on a recurring basis were as follows: Dec. 31, 2023 Dec. 31, 2022 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 $ 8 $ 51 $ 32 $ 91 $ (59) $ 32 $ 32 $ 259 $ 33 $ 324 $ (242) $ 82 Electric commodity — — 62 62 (7) 55 — — 177 177 (2) 175 Natural gas commodity — 14 — 14 — 14 — 19 — 19 — 19 Total current derivative assets $ 8 $ 65 $ 94 $ 167 $ (66) 101 $ 32 $ 278 $ 210 $ 520 $ (244) 276 PPAs (b) 3 3 Current derivative instruments $ 104 $ 279 Noncurrent derivative assets Other derivative instruments: Commodity trading $ 14 $ 51 $ 45 $ 110 $ (34) $ 76 $ 34 $ 71 $ 74 $ 179 $ (89) $ 90 Total noncurrent derivative assets $ 14 $ 51 $ 45 $ 110 $ (34) 76 $ 34 $ 71 $ 74 $ 179 $ (89) 90 PPAs (b) — 3 Noncurrent derivative instruments $ 76 $ 93 Dec. 31, 2023 Dec. 31, 2022 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 Derivatives designated as cash flow hedges: Interest rate $ — $ 17 $ — $ 17 $ — $ 17 $ — $ 1 $ — $ 1 $ — $ 1 Other derivative instruments: Commodity trading 6 86 5 97 (60) 37 29 297 6 332 (287) 45 Electric commodity — — 7 7 (7) — — — 2 2 (2) — Natural gas commodity — 12 — 12 — 12 — 13 — 13 — 13 Total current derivative liabilities $ 6 $ 115 $ 12 $ 133 $ (67) 66 $ 29 $ 311 $ 8 $ 348 $ (289) 59 PPAs (b) 8 17 Current derivative instruments $ 74 $ 76 Noncurrent derivative liabilities Other derivative instruments: Commodity trading $ 16 $ 50 $ 37 $ 103 $ (39) $ 64 $ 43 $ 97 $ 41 $ 181 $ (98) $ 83 Total noncurrent derivative liabilities $ 16 $ 50 $ 37 $ 103 $ (39) 64 $ 43 $ 97 $ 41 $ 181 $ (98) 83 PPAs (b) 22 30 Noncurrent derivative instruments $ 86 $ 113 (a) Xcel Energy nets derivative instruments and related collateral on its consolidated balance sheets when supported by a legally enforceable master netting agreement. At Dec. 31, 2023 and 2022, derivative assets and liabilities include no obligations to return cash collateral. At Dec. 31, 2023 and 2022, derivative assets and liabilities include rights to reclaim cash collateral of $7 million and $53 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) Xcel Energy currently applies the normal purchase exception to qualifying PPAs. Balance relates to specific contracts that were previously recognized at fair value prior to applying the normal purchase exception, and are 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) 2023 2022 2021 Balance at Jan. 1 $ 236 $ 19 $ (49) Purchases (a) 176 406 65 Settlements (a) (154) (350) (158) Net transactions recorded during the period: Gains recognized in earnings (b) 6 151 49 Net (losses) gains recognized as regulatory assets and liabilities (a) (174) 10 112 Balance at Dec. 31 $ 90 $ 236 $ 19 (a) Relates primarily to NSP-Minnesota and SPS FTR instruments administered by MISO and SPP. (b) Relates to commodity trading and is subject to substantial offsetting losses and gains on derivative instruments categorized as levels 1 and 2 in the income statement. See above tables for the income statement impact of derivative activity, including commodity trading gains and losses. Fair Value of Long-Term Debt As of Dec. 31, other financial instruments for which the carrying amount did not equal fair value: 2023 2022 (Millions of Dollars) Carrying Amount Fair Value Carrying Amount Fair Value Long-term debt, including current portion $ 25,465 $ 22,927 $ 23,964 $ 20,897 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, 2023 and 2022, 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, 2023
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 4.72, 4.89 and 2.03% in 2023, 2022, and 2021, 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, 2023 and 2022 were $12 million and $11 million, respectively. Xcel Energy recognized net benefit cost for the SERP and nonqualified plans of $2 million in 2023 and $17 million in 2022. Xcel Energy’s postretirement health care benefit plan is a continuation of certain welfare benefit programs for current employees. A full time employee’s date of hire or a retiree’s date of retirement determine eligibility for each of the programs. 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 the long-term projected return levels from investment experts. Pension cost determination assumes a forecasted mix of investment types over the long-term. • Investment returns in 2023 were above the assumed level of 6.93%. • Investment returns in 2022 were below the assumed level of 6.49%. • Investment returns in 2021 were above the assumed level of 6.49%. • In 2024, expected investment-return assumption is 6.93%. 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 plans for Texas and New Mexico equal to amounts collected in rates. 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, 2023 (a) Dec. 31, 2022 (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 $ 233 $ — $ — $ — $ 233 $ 129 $ — $ — $ — $ 129 Commingled funds 491 — — 1,235 1,726 935 — — 882 1,817 Debt securities — 683 4 — 687 — 682 3 — 685 Equity securities 35 — — — 35 47 — — — 47 Other — 9 — — 9 — 7 — — 7 Total $ 759 $ 692 $ 4 $ 1,235 $ 2,690 $ 1,111 $ 689 $ 3 $ 882 $ 2,685 (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, 2023 (a) Dec. 31, 2022 (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 $ 33 $ — $ — $ — $ 33 $ 31 $ — $ — $ — $ 31 Insurance contracts — 40 — — 40 — 41 — — 41 Commingled funds 22 — — 72 94 54 — — 63 117 Debt securities — 187 1 — 188 — 175 1 — 176 Other — 1 — — 1 — (1) — — (1) Total $ 55 $ 228 $ 1 $ 72 $ 356 $ 85 $ 215 $ 1 $ 63 $ 364 (a) See Note 10 for further information on fair value measurement inputs and methods. Immaterial assets were transferred in or out of Level 3 for 2023 and 2022. Funded Status — Comparisons of the actuarially computed benefit obligation, changes in plan assets and funded status of the pension and postretirement health care plans for Xcel Energy are as follows: Pension Benefits Postretirement Benefits (Millions of Dollars) 2023 2022 2023 2022 Change in Benefit Obligation: Obligation at Jan. 1 $ 2,871 $ 3,718 $ 405 $ 511 Service cost 74 97 1 2 Interest cost 158 110 22 15 Plan amendments (3) 1 — — Actuarial (gain) loss 126 (703) 14 (85) Plan participants’ contributions — — 8 8 Medicare subsidy reimbursements — — — 2 Benefit payments (a) (283) (352) (56) (48) Obligation at Dec. 31 $ 2,943 $ 2,871 $ 394 $ 405 Change in Fair Value of Plan Assets: Fair value of plan assets at Jan. 1 $ 2,685 $ 3,670 $ 364 $ 442 Actual return on plan assets 238 (683) 29 (51) Employer contributions 50 50 11 13 Plan participants’ contributions — — 8 8 Benefit payments (283) (352) (56) (48) Fair value of plan assets at Dec. 31 2,690 2,685 356 364 Funded status of plans at Dec. 31 $ (253) $ (186) $ (38) $ (41) Amounts recognized in the Consolidated Balance Sheet at Dec. 31: Noncurrent assets $ 1 $ 15 $ 28 $ 33 Current liabilities — — (3) (2) Noncurrent liabilities (254) (201) (63) (72) Net amounts recognized $ (253) $ (186) $ (38) $ (41) (a) Includes lump-sum benefit payments used in the determination of a settlement charges of $195 million of in 2022. Pension Benefits Postretirement Benefits Significant Assumptions Used to Measure Benefit Obligations: 2023 2022 2023 2022 Discount rate for year-end valuation 5.49 % 5.80 % 5.54 % 5.80 % Expected average long-term increase in compensation level 4.25 % 4.25 % 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 6.50 % 6.50 % Health care costs trend rate — initial: Post-65 N/A N/A 5.50 % 5.50 % 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 6 7 Accumulated benefit obligation for the pension plan was $2,728 million and $2,672 million as of Dec. 31, 2023 and 2022, 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) 2023 2022 2021 2023 2022 2021 Service cost $ 74 $ 97 $ 104 $ 1 $ 2 $ 2 Interest cost 158 110 104 22 15 15 Expected return on plan assets (209) (208) (206) (17) (18) (18) Amortization of prior service credit (1) (1) (1) (1) (6) (8) Amortization of net loss 22 75 107 1 2 5 Settlement charge (a) — 71 59 — — — Net periodic pension cost (credit) 44 144 167 6 (5) (4) Effects of regulation 30 (30) (46) — 3 2 Net benefit cost (credit) recognized for financial reporting $ 74 $ 114 $ 121 $ 6 $ (2) $ (2) Significant Assumptions Used to Measure Costs: Discount rate 5.80 % 3.08 % 2.71 % 5.80 % 3.09 % 2.65 % Expected average long-term increase in compensation level 4.25 3.75 3.75 — — — Expected average long-term rate of return on assets 6.93 6.49 6.49 5.00 4.10 4.10 (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. There were no settlement charges recorded for the qualified pension plans in 2023. In 2022 and 2021, as a result of lump-sum distributions during each plan year, Xcel Energy recorded a total pension settlement charge of $71 million and $59 million, respectively, the majority of which was not recognized due to the effects of regulation. A total of $9 million and $7 million was recorded in the consolidated statements of income in 2022 and 2021, respectively. Pension Benefits Postretirement Benefits (Millions of Dollars) 2023 2022 2023 2022 Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost: Net loss $ 1,096 $ 1,021 $ 64 $ 63 Prior service credit (9) (7) — (1) Total $ 1,087 $ 1,014 $ 64 $ 62 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 $ 20 $ 21 $ 2 $ — Noncurrent regulatory assets 1,014 943 79 78 Current regulatory liabilities — — (1) (1) Noncurrent regulatory liabilities — — (19) (20) Deferred income taxes 14 14 1 1 Net-of-tax accumulated other comprehensive income 39 36 2 4 Total $ 1,087 $ 1,014 $ 64 $ 62 Measurement date Dec. 31, 2023 Dec. 31, 2022 Dec. 31, 2023 Dec. 31, 2022 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 2021 - 2024 to meet minimum funding requirements. Voluntary and required pension funding contributions: • $100 million in January 2024. • $50 million in 2023. • $50 million in 2022. • $131 million in 2021. 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: • $11 million expected during 2024. • $11 million during 2023. • $13 million during 2022. • $15 million during 2021. Targeted asset allocations: Pension Benefits Postretirement Benefits 2023 2022 2023 2022 Long-duration fixed income securities 38 % 38 % — % — % Domestic and international equity securities 31 33 9 16 Alternative investments 20 18 13 12 Short-to-intermediate fixed income securities 9 9 77 71 Cash 2 2 1 1 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 2023, Xcel Energy amended the Xcel Energy Pension Plan and Xcel Energy Inc. Nonbargaining Pension Plan (South) to reduce supplemental social security benefits for all active participants on and after Jan. 1, 2024. There were no significant plan amendments made in 2022 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 2024 $ 398 $ 42 $ 2 $ 40 2025 214 40 2 38 2026 217 39 2 37 2027 223 37 2 35 2028 226 36 2 34 2029 - 2033 1,131 161 12 149 Voluntary Retirement Program Incremental to amounts presented above for postretirement benefits, Xcel Energy recognized new postemployment costs and obligations in the fourth quarter of 2023 for employees accepted to a voluntary retirement program. Utilizing employee information and the following inputs, the estimated costs of the program of $34 million for health plan subsidies and $5 million for other medical benefits, each commencing in 2024, were recognized in the fourth quarter of 2023. These unfunded obligations are presented in other current liabilities and noncurrent pension and employee benefit obligations in the consolidated balance sheet as of Dec. 31, 2023. Significant Assumptions to Measure Benefit Obligations: 2023 Discount rate for year-end valuation 5.50 % Mortality table PRI-2012 Health care costs trend rate and ultimate trend assumption 7.00 % Defined Contribution Plans Xcel Energy maintains 401(k) and other defined contribution plans that cover most employees. Total expense to these plans was approximately $49 million in 2023, $46 million in 2022 and $43 million in 2021. 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 pension 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, 2023
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.). The Court issued a ruling in June 2022 granting plaintiffs’ class certification. In April 2023, the Seventh Circuit Court of Appeals heard the defendants’ appeal challenging whether the district court properly assessed class certification. A decision relating to class certification is expected imminently. Xcel Energy considers the reasonably possible loss associated with this litigation to be immaterial. Comanche Unit 3 Litigation — In 2021, CORE filed a lawsuit in Denver County District Court, alleging PSCo breached ownership agreement terms by failing to operate Comanche Unit 3 in accordance with prudent utility practices. In April 2022, CORE filed a supplement to include damages related to a 2022 outage. Also in 2022, CORE sent notice of withdrawal from the ownership agreement based on the same alleged breaches. In February 2023, the court granted PSCo’s motion precluding CORE from seeking damages related to its withdrawal as part of the lawsuit. In October 2023, the jury ruled that CORE may not withdraw as a joint owner of the facility but awarded CORE lost power damages of $26 million. PSCo recognized a $34 million loss for the verdict in the third quarter of 2023, including estimated interest and other costs. PSCo intends to file an appeal of this decision. Marshall Wildfire Litigation — In December 2021, a wildfire ignited in Boulder County, Colorado (the “Marshall Fire”), which burned over 6,000 acres and destroyed or damaged over 1,000 structures. On June 8, 2023, the Boulder County Sheriff’s Office released its Marshall Fire Investigative Summary and Review and its supporting documents (the “Sheriff’s Report”). According to an October 2022 statement from the Colorado Insurance Commissioner, the Marshall Fire is estimated to have caused more than $2 billion in property losses. According to the Sheriff’s Report, on Dec. 30, 2021, a fire ignited on a residential property in Boulder, Colorado, located in PSCo’s service territory, for reasons unrelated to PSCo’s power lines. According to the Sheriff’s Report, approximately one hour and 20 minutes after the first ignition, a second fire ignited just south of the Marshall Mesa Trailhead in unincorporated Boulder County, Colorado, also located in PSCo’s service territory. According to the Sheriff’s Report, the second ignition started approximately 80 to 110 feet away from PSCo’s power lines in the area. The Sheriff’s Report states that the most probable cause of the second ignition was hot particles discharged from PSCo’s power lines after one of the power lines detached from its insulator in strong winds, and further states that it cannot be ruled out that the second ignition was caused by an underground coal fire. According to the Sheriff’s Report, no design, installation or maintenance defects or deficiencies were identified on PSCo’s electrical circuit in the area of the second ignition. PSCo disputes that its power lines caused the second ignition . PSCo is aware of 302 complaints, most of which have also named Xcel Energy Inc. and Xcel Energy Services, Inc. as additional defendants, relating to the Marshall Fire. The complaints are on behalf of at least 4,047 plaintiffs, and one complaint is filed on behalf of a putative class of first responders who allegedly were exposed to the threat of serious bodily injury, or smoke, soot and ash from the Marshall Fire. The complaints generally allege that PSCo’s equipment ignited the Marshall Fire and assert various causes of action under Colorado law, including negligence, premises liability, trespass, nuisance, wrongful death, willful and wanton conduct, negligent infliction of emotional distress, loss of consortium and inverse condemnation. In addition to seeking compensatory damages, certain of the complaints also seek exemplary damages. In September 2023, the Boulder County District Court Judge consolidated eight lawsuits that were pending at that time into a single action for pretrial purposes and has subsequently consolidated additional lawsuits that have been filed. At the case management conference in February 2024, a trial date was set for September 2025. Colorado courts do not apply strict liability in determining an electric utility company’s liability for fire-related damages. For inverse condemnation claims, Colorado courts assess whether a defendant acted with intent to take a plaintiff’s property or intentionally took an action which has the natural consequence of taking the property. For negligence claims, Colorado courts look to whether electric power companies have operated their system with a heightened duty of care consistent with the practical conduct of its business, and liability does not extend to occurrences that cannot be reasonably anticipated. Colorado law does not impose joint and several liability in tort actions. Instead, under Colorado law, a defendant is liable for the degree or percentage of the negligence or fault attributable to that defendant, except where the defendant conspired with another defendant. A jury’s verdict in a Colorado civil case must be unanimous. Under Colorado law, in a civil action other than a medical malpractice action, the total award for noneconomic loss is capped at $0.6 million per defendant for claims that accrued at the time of the Marshall Fire unless the court finds justification to exceed that amount by clear and convincing evidence, in which case the maximum doubles. Colorado law caps punitive or exemplary damages to an amount equal to the amount of the actual damages awarded to the injured party, except the court may increase any award of punitive damages to a sum up to three times the amount of actual damages if the conduct that is the subject of the claim has continued during the pendency of the case or the defendant has acted in a willful and wanton manner during the action which further aggravated plaintiff’s damages. In the event Xcel Energy Inc. or PSCo was found liable related to this litigation and were required to pay damages, such amounts could exceed our insurance coverage of approximately $500 million and have a material adverse effect on our financial condition, results of operations or cash flows. However, due to uncertainty as to the cause of the fire and the extent and magnitude of potential damages, Xcel Energy Inc. and PSCo are unable to estimate the amount or range of possible losses in connection with the Marshall Fire. 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. Sherco — In 2018, NSP-Minnesota and SMMPA (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. 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 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 responded 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. In July 2022, the MPUC referred the matter to the Office of Administrative Hearings to conduct a contested case on the prudence of the replacement power costs incurred by NSP-Minnesota. In 2023, NSP-Minnesota and various parties filed recommendations, including the DOC which recommended a $56 million customer refund. The Xcel Large Industrial customer group recommended a refund of $72 million. A final decision by the MPUC is expected in mid-2024. A loss related to this matter is deemed remote. 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%. The FERC subsequently issued various related orders related to ROE methodology/calculations and timing. NSP-Minnesota has processed refunds to customers for applicable complaint periods based on the ROE in the most recent applicable opinions. The MISO TOs and various other parties have filed petitions for review of the FERC’s most recent applicable opinions at the D.C. Circuit. In August 2022, the D.C. Circuit ruled that FERC had not adequately supported its conclusions, vacated FERC’s related orders and remanded the issue back to FERC for further proceedings, which remain pending. Additional exposure, if any related to this matter is expected to be immaterial. Environmental New and changing federal and state environmental mandates can create financial liabilities for Xcel Energy, which are normally recovered through the regulated rate process. Site Remediation Various federal and state environmental laws impose liability where hazardous substances or other regulated materials have been released to the environment. Xcel Energy Inc.’s subsidiaries may sometimes pay all or a portion of the cost to remediate sites where past activities of their predecessors or other parties have caused environmental contamination. Environmental contingencies could arise from various situations, including sites of former MGPs; and third-party sites, such as landfills, for which one or more of Xcel Energy Inc.’s subsidiaries are alleged to have sent wastes to that site. MGP, Landfill and Disposal Sites Xcel Energy is investigating, remediating or performing post-closure actions at 12 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 approximately $20 million 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, including the CCR Rule. As a specific requirement of the CCR Rule, utilities must complete groundwater sampling around their applicable landfills and surface impoundments as well as perform corrective actions where offsite groundwater has been impacted. If certain impacts to groundwater are detected, utilities are required to perform additional groundwater investigations and/or perform corrective actions beginning with an Assessment of Corrective Measures. Investigation and/or corrective action related to groundwater impacts are currently underway at four Xcel Energy sites under the federal CCR program at a current estimated cost of at least $40 million. A liability has been recorded and is expected to be fully recoverable through regulatory mechanisms. For required coal ash disposal, PSCo has executed an agreement with a third party that will excavate and process ash for beneficial use (at two sites) at a cost of approximately $45 million. An estimated liability has been recorded and amounts are expected to be fully recoverable through regulatory mechanisms. Federal Clean Water Act Section 316(b) — The Federal Clean Water Act requires the EPA to regulate cooling water intake structures to assure they reflect the best technology available for minimizing impingement and entrainment of aquatic species. Estimated capital expenditures of approximately $50 million may be required to comply with the requirements. Xcel Energy anticipates these costs will be recoverable through regulatory mechanisms. Environmental Requirements — Air Clean Air Act NOx Allowance Allocations — In June 2023, the EPA published final regulations for ozone under the “Good Neighbor” provisions of the Clean Air Act. The final rule applies to generation facilities in Minnesota, Texas and Wisconsin, as well as other states outside of our service territory. The rule establishes an allowance trading program for NOx that will impact subject Xcel Energy fossil fuel-fired electric generating facilities. Subject facilities will have to secure additional allowances, install NOx controls and/or develop a strategy of operations that utilizes the existing allowance allocations. Guidelines are also established for allowance banking and emission limit backstops. While the financial impacts of the final rule are uncertain and dependent on market forces and anticipated generation, Xcel Energy anticipates the annual costs could be significant, but would be recoverable through regulatory mechanisms. SPS and NSP-Minnesota have joined other companies in litigation challenging the EPA’s disapproval of Texas and Minnesota state implementation plans. Currently, the regulation is under a judicial stay for both Texas and Minnesota. The regulation may become applicable in those states in the future, depending on the outcome of the litigation. The rule is in effect in NSP-Wisconsin but has been managed without the additional need for allowances. In February 2024, the EPA proposed to partially disapprove New Mexico’s state implementation plan and bring New Mexico into the federal Good Neighbor plan. Xcel Energy continues to evaluate impacts to generation units at SPS. Regional Haze Rules — The EPA has proposed rules addressing Regional Haze compliance in Texas, which address requirements for reasonable progress at Tolk and BART at Harrington. As proposed, these rules would not require additional controls at either facility, in part due to the conversion of Harrington to gas in 2025 and the planned retirement of Tolk. These rules will be monitored until final versions are published. 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 $3.2 billion and $2.9 billion for 2023 and 2022, respectively. Xcel Energy’s AROs were as follows: (Millions Jan. 1, 2023 Amounts Incurred (a) Amounts Settled Accretion Cash Flow Revisions (b) Dec. 31, 2023 Electric Nuclear $ 2,160 $ — $ — $ 105 $ (158) $ 2,107 Wind 514 10 — 19 (17) 526 Steam, hydro and other production 348 — (1) 15 (1) 361 Distribution 48 — — 1 — 49 Natural gas Transmission and distribution 307 — 14 (149) 172 Other Miscellaneous 3 — — — — 3 Total liability $ 3,380 $ 10 $ (1) $ 154 $ (325) $ 3,218 (a) Amounts incurred relate to the Northern Wind farm placed in service in NSP-Minnesota. (b) In 2023, AROs were revised for changes in timing and estimates of cash flows. Revisions in wind and nuclear AROs were primarily incurred due to changes in useful lives. Changes in gas transmission and distribution AROs were a result of updated gas line mileage and number of services, as well as changes to inflation and discount rate assumptions. (Millions Jan. 1, 2022 Amounts Incurred (a) Accretion Cash Flow Revisions (b) Dec. 31, 2022 Electric Nuclear $ 2,056 $ — $ 104 $ — $ 2,160 Wind 478 25 19 (8) 514 Steam, hydro and other production 288 34 12 14 348 Distribution 47 — 1 — 48 Natural gas Transmission and distribution (c) 279 — 12 16 307 Other Miscellaneous 3 — — — 3 Total liability $ 3,151 $ 59 $ 148 $ 22 $ 3,380 (a) Amounts incurred related to the wind farms placed in service in 2022 for NSP-Minnesota (Dakota Range and Rock Aetna) and steam production pond remediation costs for PSCo. (b) In 2022, 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) Prior periods have been reclassified to conform with current year presentation. Indeterminate AROs — Outside of the recorded asbestos 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, 2023. 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 $16.2 billion under the Price-Anderson amendment to the Atomic Energy Act. NSP-Minnesota has $450 million of coverage for its public liability exposure with a pool of insurance companies. The remaining $15.8 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 $166 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 $25 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 $490 million and $420 million at Monticello and Prairie Island, respectively, 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 $15 million for business interruption insurance and $32 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. 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. In October 2023, a CON for additional storage at the Monticello site was approved by the MPUC to support possible life extension to 2040. The PI dry-cask storage facility currently stores 50 of the 64 authorized casks. In February 2023, NSP-Minnesota filed a CON with the MPUC for additional storage at PI to support possible life extension to 2054. Regulatory Plant Decommissioning Recovery — Decommissioning activities for NSP-Minnesota’s nuclear facilities are planned to begin at the end of each unit’s authorized retirement dates, which can be different than the currently approved NRC operating licenses. These decommissioning activities are planned to be completed at both facilities by 2101. 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. The MPUC reaffirmed a 60-year DECON scenario, where Monticello continues operations under a 10-year license extension (approved in August 2022). NRC approval of the extension is pending. In February 2023, NSP-Minnesota also filed an application with the NDPSC for an Advance Determination of Prudence for continued operation of the Monticello Plant until at least 2040. A decision is expected in 2024. Future decommissioning costs of nuclear facilities are estimated through triennial periodic studies that assess the costs and timing of planned nuclear decommissioning activities for each unit. The MPUC ordered the next triennial decommissioning study be filed by Dec. 1, 2024. Obligations for decommissioning are expected to be funded 100% by the external decommissioning trust fund. NSP-Minnesota had $3.2 billion and $2.9 billion of assets held in external decommissioning trusts at Dec. 31, 2023, and 2022, respectively. See Note 10 to the consolidated financial statements for additional discussion. Leases Xcel Energy evaluates contracts that may contain leases, including PPAs and arrangements for the use of office space and other facilities, vehicles and equipment. A contract contains a lease if it conveys the exclusive right to control the use of a specific asset. A contract determined to contain a lease is evaluated further to determine if the arrangement is a finance lease. ROU assets represent Xcel Energy's rights to use leased assets. The present value of future operating lease payments is recognized in other current liabilities and noncurrent operating lease liabilities. These amounts, adjusted for any prepayments or incentives, are recognized as operating lease ROU assets. Most of Xcel Energy’s leases do not contain a readily determinable discount rate. Therefore, the present value of future lease payments is generally calculated using the applicable Xcel Energy subsidiary’s estimated incremental borrowing rate (weighted average of 4.4%). For currently exiting asset classes, Xcel Energy has elected the practical expedient under which non-lease components, such as asset maintenance costs included in payments, are not deducted from lease payments for the purposes of lease accounting and disclosure. Leases with an initial term of 12 months or less are classified as short-term leases and are not recognized on the consolidated balance sheet. Operating lease ROU assets: (Millions of Dollars) Dec. 31, 2023 Dec. 31, 2022 PPAs $ 1,832 $ 1,669 Other 315 244 Gross operating lease ROU assets 2,147 1,913 Accumulated amortization (930) (709) Net operating lease ROU assets $ 1,217 $ 1,204 ROU assets for finance leases are included in other noncurrent assets, and the present value of future finance lease payments is included in other current liabilities and other noncurrent liabilities. Xcel Energy’s most significant finance lease activities are related to WYCO, a joint venture with CIG, to develop and lease natural gas pipeline, storage and compression facilities. Xcel Energy Inc. has a 50% ownership interest in WYCO. WYCO leases its facilities to CIG, and CIG operates the facilities, providing natural gas storage and transportation services to PSCo under separate service agreements. PSCo accounts for its Totem natural gas storage service and Front Range pipeline arrangements with CIG and WYCO, respectively, as finance leases. Xcel Energy Inc. eliminates 50% of the finance lease obligation related to WYCO in the consolidated balance sheet along with an equal amount of Xcel Energy Inc.’s equity investment in WYCO. Finance lease ROU assets: (Millions of Dollars) Dec. 31, 2023 Dec. 31, 2022 Gas storage facilities $ 160 $ 160 Gas pipeline 21 21 Gross finance lease ROU assets 181 181 Accumulated amortization (67) (64) Net finance lease ROU assets $ 114 $ 117 Components of lease expense: (Millions of Dollars) 2023 2022 2021 Operating leases PPA capacity payments $ 241 $ 241 $ 251 Other operating leases (a) 42 39 36 Total operating lease expense (b) $ 283 $ 280 $ 287 Finance leases Amortization of ROU assets $ 3 $ 4 $ 7 Interest expense on lease liability 15 16 17 Total finance lease expense $ 18 $ 20 $ 24 (a) Includes short-term lease expense of $3 million, $6 million, and $5 million for 2023, 2022 and 2021, respectively. (b) PPA capacity payments are included in electric fuel and purchased power on the consolidated statements of income. Expense for other operating leases is included in O&M expense and electric fuel and purchased power. Commitments under operating and finance leases as of Dec. 31, 2023: (Millions of Dollars) PPA (a) (b) Operating Leases Other Operating Leases Total Leases Finance Leases (c) 2024 $ 244 $ 33 $ 277 $ 10 2025 245 26 271 10 2026 216 22 238 9 2027 162 22 184 8 2028 107 22 129 8 Thereafter 259 162 421 173 Total minimum obligation 1,233 287 1,520 218 Interest component of obligation (157) (99) (256) (154) Present value of minimum obligation $ 1,076 188 1,264 64 Less current portion (226) (2) Noncurrent operating and finance lease liabilities $ 1,038 $ 62 Weighted-average remaining lease term in years 8.2 36.8 (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. PPAs and Fuel Contracts Non-Lease PPAs — NSP-Minnesota, PSCo and SPS have entered into PPAs with other utilities and energy suppliers for purchased power to meet system load and energy requirements, operating reserve obligations and as part of wholesale and commodity trading activities. In general, these agreements provide for energy payments, based on actual energy delivered, and may also include capacity payments. Certain non-lease PPAs with various expiration dates through 2033, contain minimum energy purchase commitments. Total energy payments on those contracts were $214 million, $182 million and $149 million in 2023, 2022 and 2021, respectively. Included in electric fuel and purchased power expenses for PPAs accounted for as executory contracts were payments for capacity of $77 million, $75 million and $69 million in 2023, 2022 and 2021, respectively. Capacity and energy payments are contingent on the IPPs meeting contract obligations, including plant availability requirements. Certain contractual payments are adjusted based on market indices. The effects of price adjustments on financial results are mitigated through purchased energy cost recovery mechanisms. At Dec. 31, 2023, the estimated future payments for capacity and energy that the utility subsidiaries of Xcel Energy are obligated to purchase pursuant to these non-lease contracts, subject to availability, were as follows: (Millions of Dollars) Capacity Energy (a) 2024 $ 80 $ 207 2025 45 94 2026 28 47 2027 9 10 2028 1 10 Thereafter 2 18 Total $ 165 $ 386 (a) Excludes contingent energy payments for renewable energy PPAs. Fuel Contracts — Xcel Energy has entered into various long-term commitments for the purchase and delivery of a significant portion of its coal, nuclear fuel and natural gas requirements. These contracts expire between 2024 and 2060. Xcel Energy is required to pay additional amounts depending on actual quantities delivered under these agreements. Estimated minimum purchases under these contracts as of Dec. 31, 2023: (Millions of Dollars) Coal Nuclear fuel Natural gas supply Natural gas storage and transportation 2024 $ 350 $ 142 $ 339 $ 311 2025 157 179 13 284 2026 81 63 — 276 2027 56 180 — 238 2028 21 50 — 111 Thereafter 1 177 — 442 Total $ 666 $ 791 $ 352 $ 1,662 VIEs PPAs — Under certain PPAs, NSP-Minnesota, PSCo and SPS purchase power from IPPs for which the utility subsidiaries are required to reimburse fuel costs, or to participate in tolling arrangements under which the utility subsidiaries procure the natural gas required to produce the energy that they purchase. Xcel Energy has determined that certain IPPs are VIEs, however Xcel Energy is not subject to risk of loss from the operations of these entities, and no significant financial support is required other than contractual payments for energy and capacity. In addition, certain solar PPAs provide an option to purchase emission allowances or sharing provisions related to production credits generated by the solar facility under contract. These specific PPAs create a variable interest in the IPP. Xcel Energy evaluated each of these VIEs for possible consolidation, including review of qualitative factors such as the length and terms of the contract, control over O&M, control over dispatch of electricity, historical and estimated future fuel and electricity prices and financing activities. Xcel Energy concluded that these entities are not required to be consolidated in its consolidated financial statements because Xcel Energy does not have the power to direct the activities that most significantly impact the entities’ economic performance. The utility subsidiaries had approximately 3,751 MW and 3,961 MW of capacity under long-term PPAs at Dec. 31, 2023 and 2022, respectively, with entities that have been determined to be VIEs. These agreements have expiration dates through 2041. Fuel Contracts — SPS purchases all of its coal requirements for its Harrington and Tolk plants from TUCO Inc. under contracts that will expire in December 2024 and December 2027, respectively. TUCO arranges for the purchase, receiving, transporting, unloading, handling, crushing, weighing and delivery of coal to meet SPS’ requirements. TUCO is responsible for negotiating and administering contracts with coal suppliers, transporters and handlers. SPS has not provided any significant financial support to TUCO, other than contractual payments for delivered coal. However, the fuel contracts create a variable interest in TUCO due to S

Other Comprehensive Income

Other Comprehensive Income	12 Months Ended
	Dec. 31, 2023
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: 2023 (Millions of Dollars) Gains and Losses on Interest Rate Cash Flow Hedges Defined Benefit Pension and Postretirement Items Total Accumulated other comprehensive loss at Jan. 1 $ (54) $ (39) $ (93) Other comprehensive loss before reclassifications (2) (4) (6) Losses reclassified from net accumulated other comprehensive loss: Amortization of interest rate hedges 3 (a) — 3 Amortization of net actuarial loss — 2 (b) 2 Net current period other comprehensive income (loss) 1 (2) (1) Accumulated other comprehensive loss at Dec. 31 $ (53) $ (41) $ (94) (a) Included in interest charges. (b) Included in the computation of net periodic pension and postretirement benefit costs. See Note 11 for further information. 2022 (Millions of Dollars) Gains and Losses on Interest Rate Cash Flow Hedges Defined Benefit Pension and Postretirement Items Total Accumulated other comprehensive loss at Jan. 1 $ (75) $ (48) $ (123) Other comprehensive gain before reclassifications 16 5 21 Losses reclassified from net accumulated other comprehensive loss: Amortization of interest rate hedges 5 (a) — 5 Amortization of net actuarial loss — 4 (b) 4 Net current period other comprehensive income 21 9 30 Accumulated other comprehensive loss at Dec. 31 $ (54) $ (39) $ (93) (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, 2023
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, purchases, transmits, distributes and sells electricity in Colorado, Michigan, Minnesota, New Mexico, North Dakota, South Dakota, Texas and Wisconsin. 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 purchases, transports, stores, distributes and sells natural gas primarily in portions of Colorado, Michigan, Minnesota, North Dakota and Wisconsin. 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 RDF, investments in rental housing projects that qualify for low-income housing tax credits and equity method investments in EIP funds. Xcel Energy had equity method investments of $244 million and $219 million as of Dec. 31, 2023 and 2022, 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) 2023 2022 2021 Regulated Electric Operating revenues — external $ 11,446 $ 12,123 $ 11,205 Intersegment revenue 2 2 2 Total revenues $ 11,448 $ 12,125 $ 11,207 Depreciation and amortization 2,111 2,122 1,855 Interest charges and financing costs 670 636 568 Income tax benefit (135) (162) (96) Net income 1,686 1,631 1,478 Regulated Natural Gas Operating revenues — external $ 2,645 $ 3,080 $ 2,132 Intersegment revenue 3 2 2 Total revenues $ 2,648 $ 3,082 $ 2,134 Depreciation and amortization 323 276 254 Interest charges and financing costs 96 86 75 Income tax expense 50 68 54 Net income 219 264 231 All Other Total revenues $ 115 $ 107 $ 94 Depreciation and amortization 14 15 12 Interest charges and financing costs 238 203 173 Income tax benefit (61) (41) (28) Net loss (134) (159) (112) Consolidated Total Total revenues $ 14,211 $ 15,314 $ 13,435 Reconciling eliminations (5) (4) (4) Total operating revenues $ 14,206 $ 15,310 $ 13,431 Depreciation and amortization 2,448 2,413 2,121 Interest charges and financing costs 1,004 925 816 Income tax benefit (146) (135) (70) Net income 1,771 1,736 1,597

Compensation Related Costs, Pos

Compensation Related Costs, Postemployment Benefits	12 Months Ended
	Dec. 31, 2023
Postemployment Benefits [Abstract]
Postemployment Benefits Disclosure	In 2023, Xcel Energy implemented workforce actions to align resources and investments with evolving business and customer needs, and streamline the organization for long-term success. In September 2023, Xcel Energy announced a voluntary retirement program to a group of eligible non-bargaining employees, with an enhanced retirement package including certain health care and cash benefits for accepted employees. Approximately 400 employees retired under this program in December 2023. In November 2023, Xcel Energy, Inc. also reduced its non-bargaining workforce by approximately 150 employees through an involuntary severance program. In the fourth quarter of 2023, Xcel Energy recorded total expense of $72 million related to these workforce actions, primarily related to the estimated cost of future health plan subsidies and other medical benefits for the voluntary retirement program, as well as severance and other employee payouts and legal and other professional fees.

Schedule I, Condensed Financial

Schedule I, Condensed Financial Statements of Xcel Energy Inc	12 Months Ended
	Dec. 31, 2023
Condensed Financial Information Disclosure [Abstract]
Schedule I, Condensed Financial Information	Year Ended Dec. 31 2023 2022 2021 Income Equity earnings of subsidiaries $ 1,948 $ 1,905 $ 1,744 Total income 1,948 1,905 1,744 Expenses and other deductions Operating expenses 25 19 21 Other (income) expenses (13) (2) 3 Interest charges and financing costs 235 206 173 Total expenses and other deductions 247 223 197 Income before income taxes 1,701 1,682 1,547 Income tax benefit (70) (54) (50) Net income $ 1,771 $ 1,736 $ 1,597 Other Comprehensive Income Pension and retiree medical benefits, net of tax $ (2) $ 9 $ 8 Derivative instruments, net of tax 1 21 10 Other comprehensive income (1) 30 18 Comprehensive income $ 1,770 $ 1,766 $ 1,615 Weighted average common shares outstanding: Basic 552 547 539 Diluted 552 547 540 Earnings per average common share: Basic $ 3.21 $ 3.18 $ 2.96 Diluted 3.21 3.17 2.96 See Notes to Condensed Financial Statements Year Ended Dec. 31 2023 2022 2021 Operating activities Net cash provided by operating activities $ 1,586 $ 1,340 $ 1,147 Investing activities Capital contributions to subsidiaries (975) (921) (1,661) Net return in the utility money pool 21 — 57 Net cash used in investing activities (954) (921) (1,604) Financing activities (Repayment of) proceeds from short-term borrowings, net (66) (407) 638 Proceeds from issuance of long-term debt 792 694 791 Repayment of long-term debt (500) — (400) Proceeds from issuance of common stock 270 322 366 Dividends paid (1,092) (1,012) (935) Other (13) (16) (16) Net cash (used in) provided by financing activities (609) (419) 444 Net change in cash, cash equivalents, and restricted cash 23 — (13) Cash, cash equivalents and restricted cash at beginning of period 1 1 14 Cash, cash equivalents and restricted cash at end of period $ 24 $ 1 $ 1 See Notes to Condensed Financial Statements Dec. 31 2023 2022 Assets Cash and cash equivalents $ 24 $ 1 Accounts receivable from subsidiaries 404 443 Derivative instruments — 1 Other current assets 5 7 Total current assets 433 452 Investment in subsidiaries 23,873 22,597 Other assets (20) (7) Total other assets 23,853 22,590 Total assets $ 24,286 $ 23,042 Liabilities and Equity Current portion of long-term debt — 500 Dividends payable 289 268 Short-term debt 165 231 Other current liabilities 66 17 Total current liabilities 520 1,016 Other liabilities 12 13 Total other liabilities 12 13 Commitments and contingencies Capitalization Long-term debt 6,137 5,338 Common stockholders' equity 17,617 16,675 Total capitalization 23,754 22,013 Total liabilities and equity $ 24,286 $ 23,042 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, 2023 and 2022, Xcel Energy Inc. had no asset s held as collateral related to guarantees, bond indemnities and indemnification agreements. Guarantees and bond indemnities issued and outstanding as of Dec. 31, 2023: (Millions of Dollars) Guarantor Guarantee Current Triggering Guarantees of Capital Services purchase contracts for wind and solar generating equipment (a) Xcel Energy Inc. 951 (b) (c) Guarantees of Xcel Energy Inc.’s utility subsidiaries’ performance on tax credit sale agreements Xcel Energy Inc. 100 (d) (c) Guarantee performance and payment of surety bonds for Xcel Energy Inc.’s utility subsidiaries (e) Xcel Energy Inc. 75 (f) (g) (a) Guarantees expire upon the satisfaction of all buyer obligations under the purchase contracts. (b) Given that the manufacturing of equipment has not yet commenced, related exposure to the performance obligations of Capital Services at Dec. 31, 2023 has been assessed as immaterial. (c) Nonperformance and/or nonpayment. (d) Exposure to the performance obligations of the utility subsidiaries has been assessed as immaterial. The tax credit sales transactions closed as scheduled in January 2024. (e) The surety bonds primarily relate to workers compensation benefits and utility projects. The workers compensation bonds are renewed annually and the project based bonds expire in conjunction with the completion of the related projects. (f) Due to the number 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. (g) Per the indemnity agreement between Xcel Energy Inc. and the various surety companies, surety companies have the discretion to demand that collateral be posted. 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) 2023 2022 NSP-Minnesota $ 120 $ 82 NSP-Wisconsin 13 17 PSCo 44 111 SPS 47 61 Xcel Energy Services Inc. 144 145 Other subsidiaries of Xcel Energy Inc. 35 27 $ 403 $ 443 Dividends — Cash dividends paid to Xcel Energy Inc. by its subsidiaries were $1,693 million, $1,503 million and $1,344 million for the years ended Dec. 31, 2023, 2022 and 2021, 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, 2023 Loan outstanding at period end $ 21 Average loan outstanding 90 Maximum loan outstanding 250 Weighted average interest rate, computed on a daily basis 1.34 % Weighted average interest rate at end of period 5.34 Money pool interest income $ 1 (Amounts in Millions, Except Interest Rates) Year Ended Dec. 31, 2023 Year Ended Dec. 31, 2022 Year Ended Dec. 31, 2021 Loan outstanding at period end $ 21 $ — $ — Average loan outstanding 27 10 16 Maximum loan outstanding 250 204 439 Weighted average interest rate, computed on a daily basis 5.33 % 0.73 % 0.08 % Weighted average interest rate at end of period 5.34 N/A N/A Money pool interest income $ 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, 2023
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) 2023 2022 2021 2023 2022 2021 Balance at Jan. 1 $ 122 $ 106 $ 79 $ 62 $ 64 $ 64 Additions charged to costs and expenses 79 73 60 26 6 5 Additions charged to other accounts 13 (a) 26 (a) 14 (a) — — — Deductions from reserves (86) (b) (83) (b) (47) (b) (18) (c) (8) (c) (5) (c) Balance at Dec. 31 $ 128 $ 122 $ 106 $ 70 $ 62 $ 64 (a) Recovery of amounts previously written-off. (b) Deductions related primarily to bad debt write-offs. (c) Primarily reversals of valuation allowances on completed tax credit sales and reductions of valuation allowances for items forecasted to be used prior to expiration.

Summary of Significant Accoun_2

Summary of Significant Accounting Policies Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2023
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 the regulated purchase, transportation, distribution and sale of natural gas. The 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.
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: Nonregulated Subsidiary Purpose Eloigne Invests in rental housing projects that qualify for low-income housing tax credits. Capital Services Procures equipment for construction of renewable generation facilities at other subsidiaries. Xcel Energy Venture Holdings, Inc. 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 Minnesota community solar gardens. Xcel Energy Inc. owns the following additional direct subsidiaries, some of which are intermediate holding companies with additional subsidiaries: Direct Subsidiary Xcel Energy Wholesale Group Inc. Xcel Energy Markets Holdings Inc. Xcel Energy Ventures Inc. Xcel Energy Retail Holdings Inc. Xcel Energy Communication Group Inc. Xcel Energy International Inc. Xcel Energy Transmission Holding Company, LLC Nicollet Holdings Company, LLC Xcel Energy Nuclear Services Holdings, LLC Xcel Energy Services Inc. Xcel Energy 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. The equity method of accounting is used for its investments in EIP funds and WYCO. Investments in certain plants and transmission facilities are jointly owned with nonaffiliated utilities. A proportionate share of jointly owned facilities is recorded as property, plant and equipment on the consolidated balance sheets, and Xcel Energy’s share of operating costs associated with these facilities is included in the consolidated statements of income. The 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.
Subsequent Events	Xcel Energy has evaluated events occurring after Dec. 31, 2023 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 to record 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 — The 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 and assumptions for recovery of deferred costs and refund of deferred credits are based on specific ratemaking decisions, precedent or other available information. 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. 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 consolidated financial statements. Income taxes are deferred for all temporary differences between pretax financial and taxable income and between the book and tax bases of assets and liabilities utilizing 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. Utility rate regulation has resulted in the recognition of regulatory assets and liabilities related to income taxes. 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, refundable to utility customers over the remaining life of the related assets. Xcel Energy anticipates that a tax rate increase would predominantly 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 over the book depreciable lives of related property. The requirement to defer and amortize these credits specifically applies to certain federal ITCs, as determined by tax regulations and Xcel Energy tax elections. For tax credits otherwise eligible to be recognized when earned, Xcel Energy considers the impact of rate regulation to determine if these credits and related adjustments should be deferred as regulatory assets or liabilities. 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. This evaluation includes consideration of whether tax credits are expected to be sold at a discount and impact the realization of amounts presented as deferred tax assets. Transferable tax credits are accounted for under ASC 740 Income Taxes , and valuation allowances and any adjustments for discounts incurred on sales transactions are recorded to deferred tax expense, typically recovered in the utility subsidiaries’ regulatory mechanisms. Xcel Energy measures and discloses uncertain tax positions that it has taken or expects to take in its income tax returns. A tax position is recognized in the 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. Interest and penalties related to income taxes are reported within Other income (expense), net 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 and replacement of items determined to be less than a unit of property are charged to expense as incurred. 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. Depreciation expense is recorded 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 are typically recognized at the amounts recovered in rates as authorized by the applicable regulator. 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 3.6% for 2023, 3.7% for 2022 and 3.5% for 2021.
Asset Retirement Obligations	AROs — Xcel Energy records AROs as a liability in the period incurred (if fair value can be reasonably estimated), with the offsetting/associated 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 typically depreciated over the useful life of the long-lived asset. Changes resulting from revisions to timing or amounts 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 normally performed at least every three 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 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 amount can be reasonably estimated. Costs are deferred as a regulatory asset if it is probable 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 is performed. 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. Estimated future expenditures to restore 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. A separate financing component of collections from customers is not recognized as contract terms are short-term in nature. Revenues are 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 RTO/ISOs are also recorded on a gross basis. Other revenues and charges settled/facilitated through an RTO/ISO 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
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 the lower of average cost or net realizable value and consisted of the following: (Millions of Dollars) Dec. 31, 2023 Dec. 31, 2022 Inventories Materials and supplies $ 377 $ 330 Fuel 211 201 Natural gas 123 272 Total inventories $ 711 $ 803
Fair Value Measurements	Fair Value Measurements — Xcel Energy presents cash equivalents, interest rate derivatives, rabbi trust assets, commodity derivatives, pension and postretirement plan assets and nuclear decommissioning fund assets at estimated fair values in its consolidated financial statements. For interest rate derivatives, quoted prices based primarily on observable market interest rate curves are used to estimate 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, quoted prices for similar contracts or internally prepared valuation models may be used to determine fair value. For rabbi trust assets, pension and postretirement plan assets and nuclear decommissioning fund assets, published trading data and pricing models, generally using the most observable inputs available, are utilized to determine 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 commodity trading activities, and to manage risk associated with changes in interest rates and utility commodity prices, including forward contracts, futures, swaps and options. Derivatives 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. 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 they contain a derivative, and if so, whether they may be exempted from derivative accounting if designated as normal purchases or normal sales. 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 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 instances in which 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, 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	Emissions Allowances — Emissions allowances are recorded at cost, including broker commission fees. The inventory accounting model is utilized for all emissions allowances and any 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, 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 presented on a net basis in electric operating revenues in the consolidated statements of income.
Equity Method Investments	Equity Method Investments —

Summary of Significant Accoun_3

Summary of Significant Accounting Policies Inventory (Tables)	12 Months Ended
	Dec. 31, 2023
Balance Sheet Related Disclosure - Inventory [Abstract]
Public Utilities, Inventory	Inventory — Inventory is recorded at the lower of average cost or net realizable value and consisted of the following: (Millions of Dollars) Dec. 31, 2023 Dec. 31, 2022 Inventories Materials and supplies $ 377 $ 330 Fuel 211 201 Natural gas 123 272 Total inventories $ 711 $ 803

Property Plant and Equipment _2

Property Plant and Equipment Property Plant and Equipment (Tables)	12 Months Ended
	Dec. 31, 2023
Property, Plant and Equipment [Line Items]
Public Utility Property, Plant, and Equipment	Major classes of property, plant and equipment (Millions of Dollars) Dec. 31, 2023 Dec. 31, 2022 Property, plant and equipment, net Electric plant $ 52,494 $ 49,639 Natural gas plant 9,080 8,514 Common and other property 3,190 2,970 Plant to be retired (a) 2,055 2,217 CWIP 2,873 2,124 Total property, plant and equipment 69,692 65,464 Less accumulated depreciation (18,399) (17,502) Nuclear fuel 3,337 3,183 Less accumulated amortization (2,988) (2,892) Property, plant and equipment, net $ 51,642 $ 48,253 (a)
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 $ 633 $ 480 59 % Sherco common facilities 185 121 80 Sherco substation 5 4 59 Electric transmission: Grand Meadow 11 4 50 Huntley Wilmarth 49 2 50 CapX2020 820 141 51 Total NSP-Minnesota (a) $ 1,703 $ 752 (a) Projects additionally include $2 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 $ 178 $ 25 37 % CapX2020 169 39 80 Total NSP-Wisconsin (a) $ 347 $ 64 (a) Projects additionally include $1 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 $ 157 $ 108 76 % Hayden Unit 2 151 87 37 Hayden common facilities 44 31 53 Craig Units 1 and 2 82 55 10 Craig common facilities 39 25 7 Comanche Unit 3 916 191 67 Comanche common facilities 29 4 77 Electric transmission: Transmission and other facilities 189 75 Various Gas transmission: Rifle, CO to Avon, CO 28 9 60 Gas transmission compressor 8 2 50 Total PSCo (a) $ 1,643 $ 587 (a) Projects additionally include $18 million in CWIP.

Regulatory Assets and Liabili_2

Regulatory Assets and Liabilities (Tables)	12 Months Ended
	Dec. 31, 2023
Regulatory Assets and Liabilities Disclosure [Abstract]
Regulatory Assets	Components of regulatory assets: (Millions of Dollars) See Note(s) Remaining Amortization Period Dec. 31, 2023 Dec. 31, 2022 (a) Regulatory Assets Current Noncurrent Current Noncurrent Pension and retiree medical obligations 11 Various $ 27 $ 1,106 $ 22 $ 1,069 Recoverable deferred taxes on AFUDC Plant lives — 332 — 292 Net AROs (b) 1, 12 Various — 316 — 339 Excess deferred taxes — TCJA 7 Various 10 198 13 205 Depreciation differences One 17 189 17 193 Environmental remediation costs 1, 12 Various 15 94 20 92 Deferred natural gas, electric, steam energy/fuel costs One three 239 80 581 299 Conservation programs (c) 1 One two 19 54 16 36 Purchased power contract costs Term of related contract 4 40 10 36 PI extended power uprate 11 years 4 38 4 42 Benson biomass PPA termination and asset purchase Five 10 36 10 45 Sales true-up and revenue decoupling One two 7 33 54 — State commission adjustments Plant lives 1 32 1 33 Losses on reacquired debt Term of related debt 2 30 3 32 MISO capacity revenue tracker One two 36 26 — — Gas pipeline inspection and remediation costs One two 40 25 42 13 Contract valuation adjustments (d) 1, 10 Term of related contract 18 22 28 28 Nuclear refueling outage costs 1 One two 43 19 30 12 Grid modernization costs One two 16 17 14 24 Renewable resources and environmental initiatives One two 38 5 50 6 Other Various 65 106 144 75 Total regulatory assets $ 611 $ 2,798 $ 1,059 $ 2,871 (a) Prior period amounts have been reclassified to conform with current year presentation. (b) The 2022 amount is net of the nuclear decommissioning accruals and gains from decommissioning investments. In 2023, the nuclear decommissioning accruals and gains from decommissioning investments exceeded the expected cost of AROs in NSP-Minnesota and was reclassified to a regulatory liability. (c) Includes costs for conservation programs, as well as incentives allowed in certain jurisdictions. (d) Includes the fair value of certain long-term PPAs used to meet energy capacity requirements and valuation adjustments on natural gas commodity purchases.
Regulatory Liabilities	Components of regulatory liabilities: (Millions of Dollars) See Note(s) Remaining Amortization Period Dec. 31, 2023 Dec. 31, 2022 Regulatory Liabilities Current Noncurrent Current Noncurrent Deferred income tax adjustments and TCJA refunds (a) 7 Various $ 7 $ 3,015 $ 9 $ 3,110 Plant removal costs 1, 12 Various — 1,984 — 1,819 Effects of regulation on employee benefit costs (b) Various — 253 — 247 Renewable resources and environmental initiatives Various 9 188 6 173 Net AROs (c) Various — 90 — — Sales true-up and revenue decoupling Two 18 76 — 77 ITC deferrals 1 Various 1 60 1 61 LP&L departure payment Up to 10 years 33 33 — — Formula rates One two 29 18 32 17 DOE settlement One two 18 6 12 3 Deferred natural gas, electric, steam energy/fuel costs Less than one 220 — 39 — Contract valuation adjustments (d) 1, 10 Less than one 56 — 175 1 Conservation programs (e) 1 Less than one 47 — 72 — Other Various 90 104 72 61 Total regulatory liabilities (f) $ 528 $ 5,827 $ 418 $ 5,569 (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 amounts recorded for future recovery of AROs, less amounts recovered through nuclear decommissioning accruals and gains from decommissioning investments. (d) Includes the fair value of FTR instruments utilized/intended to offset the impacts of transmission system congestion. (e) Includes costs for conservation programs, as well as incentives allowed in certain jurisdictions. (f) Revenue subject to refund of $187 million and $67 million for 2023 and 2022, respectively, is included in other current liabilities.

Borrowings and Other Financin_2

Borrowings and Other Financing Instruments Borrowings and Other Financing Instruments (Tables)	12 Months Ended
	Dec. 31, 2023
Debt Disclosure [Abstract]
Commercial Paper	Commercial paper and other borrowings outstanding: (Millions of Dollars, Except Interest Rates) Three Months Ended Dec. 31, 2023 Year Ended Dec. 31 2023 2022 2021 Borrowing limit $ 3,550 $ 3,550 $ 3,550 $ 3,100 Amount outstanding at period end 785 785 813 1,005 Average amount outstanding 339 491 552 1,399 Maximum amount outstanding 785 1,241 1,357 2,054 Weighted average interest rate, computed on a daily basis 5.51 % 5.12 % 1.47 % 0.57 % Weighted average interest rate at period end 5.52 5.52 4.66 0.31
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) (b) Additional Periods for Which a One-Year Extension May Be Requested (c) 2023 2022 Xcel Energy Inc. (d) 59.8 % 59.7 % $ 350 2 NSP-Minnesota 47.7 47.7 150 2 NSP-Wisconsin 48.2 47.4 N/A 1 SPS 46.1 45.7 50 2 PSCo 44.8 44.0 100 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) Amounts authorized by state commissions in respective jurisdictions. (c) All extension requests are subject to majority bank group approval. (d) 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, 2023, NSP-Minnesota had $65 million outstanding letters of credit under the $75 million Bilateral Credit Agreement. Xcel Energy Inc. and its utility subsidiaries had the following committed credit facilities available as of Dec. 31, 2023: (Millions of Dollars) Credit Facility (a) Drawn (b) Available Xcel Energy Inc. $ 1,500 $ 165 $ 1,335 PSCo 700 349 351 NSP-Minnesota 700 180 520 SPS 500 75 425 NSP-Wisconsin 150 60 90 Total $ 3,550 $ 829 $ 2,721 (a) These credit facilities mature in September 2027. (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 2023 2022 Unsecured senior notes 0.50 % Oct. 15, 2023 $ — $ 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 1.75 March 15, 2027 500 500 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 3.40 June 1, 2030 600 600 Unsecured senior notes 2.35 Nov. 15, 2031 300 300 Unsecured senior notes (a) 4.60 June 1, 2032 700 700 Unsecured senior notes (b) 5.45 Aug. 15, 2033 800 — Unsecured senior notes 6.50 July 1, 2036 300 300 Unsecured senior notes 4.80 Sept. 15, 2041 250 250 Unsecured senior notes 3.50 Dec. 1, 2049 500 500 Unamortized discount (8) (7) Unamortized debt issuance cost (36) (35) Current maturities — (500) Total long-term debt $ 6,136 $ 5,338 (a) 2022 financing. (b) 2023 financing. NSP-Minnesota Financing Instrument Interest Rate Maturity Date 2023 2022 First mortgage bonds 2.60 % May 15, 2023 $ — $ 400 First mortgage bonds 7.125 July 1, 2025 250 250 First mortgage bonds 6.50 March 1, 2028 150 150 First mortgage bonds 2.25 April 1, 2031 425 425 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 Sept. 15, 2047 600 600 First mortgage bonds 2.90 March 1, 2050 600 600 First mortgage bonds 2.60 June 1, 2051 700 700 First mortgage bonds 3.20 April 1, 2052 425 425 First mortgage bonds (a) 4.50 June 1, 2052 500 500 First mortgage bonds (b) 5.10 May 15, 2053 800 — Other long-term debt 2 3 Unamortized discount (49) (45) Unamortized debt issuance cost (73) (66) Current maturities — (400) Total long-term debt $ 7,330 $ 6,542 (a) 2022 financing. (b) 2023 financing. NSP-Wisconsin Financing Instrument Interest Rate Maturity Date 2023 2022 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 3.05 May 1, 2051 100 100 First mortgage bonds 2.82 May 1, 2051 100 100 First mortgage bonds (a) 4.86 Sept. 15, 2052 100 100 First mortgage bonds (b) 5.30 June 15, 2053 125 — Unamortized discount (3) (3) Unamortized debt issuance cost (11) (11) Current maturities (200) — Total long-term debt $ 1,011 $ 1,086 (a) 2022 financing. (b) 2023 financing. PSCo Financing Instrument Interest Rate Maturity Date 2023 2022 First mortgage bonds 2.50 % March 15, 2023 $ — $ 250 First mortgage bonds 2.90 May 15, 2025 250 250 First mortgage bonds 3.70 June 15, 2028 350 350 First mortgage bonds 1.90 Jan. 15, 2031 375 375 First mortgage bonds 1.875 June 15, 2031 750 750 First mortgage bonds (a) 4.10 June 1, 2032 300 300 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 2.70 Jan. 15, 2051 375 375 First mortgage bonds (a) 4.50 June 1, 2052 400 400 First mortgage bonds (b) 5.25 April 1, 2053 850 — Unamortized discount (41) (37) Unamortized debt issuance cost (59) (53) Current maturities — (250) Total long-term debt $ 7,450 $ 6,610 (a) 2022 financing. (b) 2023 financing. SPS Financing Instrument Interest Rate Maturity Date 2023 2022 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 3.15 May 1, 2050 350 350 First mortgage bonds 3.15 May 1, 2050 250 250 First mortgage bonds (a) 5.15 June 1, 2052 200 200 First mortgage bonds (b) 6.00 Sept. 15, 2053 100 — Unamortized discount (10) (10) Unamortized debt issuance cost (29) (29) Current maturities (350) — Total long-term debt $ 2,961 $ 3,211 (a) 2022 financing. (b) 2023 financing.
Schedule of Maturities of Long-term Debt	(Millions of Dollars) 2024 $ 552 2025 1,103 2026 501 2027 501 2028 1,133
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) 2023 and 2022 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, 2023 Common Stock Outstanding (Shares) as of Dec. 31, 2022 1,000,000,000 $ 2.50 554,941,703 549,578,018
Share-based Payment Arrangement, Restricted Stock and Restricted Stock Unit, Activity [Table Text Block]	Requirements and actuals as of Dec. 31, 2023: Equity to Total Equity to Total Capitalization Ratio Actual Low High 2023 NSP-Minnesota 47.2 % 57.6 % 52.3 % NSP-Wisconsin (a) 52.5 N/A 52.7 SPS (b) 45.0 55.0 54.6 (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) Excludes short-term debt. (Amounts in Millions) Unrestricted Retained Earnings Total Capitalization Limit on Total Capitalization NSP-Minnesota $ 1,508 $ 15,702 $ 16,140 NSP-Wisconsin 9 2,520 N/A SPS (a) 617 7,298 N/A (a)
Other Capital Restrictions	Amounts authorized to issue as of Dec. 31, 2023: (Millions of Dollars) Long-Term Debt Short-Term Debt NSP-Minnesota 52.8% of total capitalization (a) $ 2,400 (a) NSP-Wisconsin $ 625 150 PSCo 450 800 SPS 100 600 (a)

Revenues (Tables)

Revenues (Tables)	12 Months Ended
	Dec. 31, 2023
Revenue from Contract with Customer [Abstract]
Disaggregation of Revenue	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, 2023 (Millions of Dollars) Electric Natural Gas All Other Total Major revenue types Revenue from contracts with customers: Residential $ 3,560 $ 1,560 $ 59 $ 5,179 C&I 5,703 833 30 6,566 Other 150 — 13 163 Total retail 9,413 2,393 102 11,908 Wholesale 815 — — 815 Transmission 649 — — 649 Other 63 156 — 219 Total revenue from contracts with customers 10,940 2,549 102 13,591 Alternative revenue and other 506 96 13 615 Total revenues $ 11,446 $ 2,645 $ 115 $ 14,206 Year Ended Dec. 31, 2022 (Millions of Dollars) Electric Natural Gas All Other Total Major revenue types Revenue from contracts with customers: Residential $ 3,542 $ 1,814 $ 53 $ 5,409 C&I 5,807 998 32 6,837 Other 148 — 10 158 Total retail 9,497 2,812 95 12,404 Wholesale 1,354 — — 1,354 Transmission 675 — — 675 Other 97 178 — 275 Total revenue from contracts with customers 11,623 2,990 95 14,708 Alternative revenue and other 500 90 12 602 Total revenues $ 12,123 $ 3,080 $ 107 $ 15,310 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

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2023
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 March 2025 2020 September 2024
State Statute of Limitations Applicable to Open Tax Years	State Tax Year(s) Expiration Colorado 2014 - 2016 March 2026 Colorado 2019 October 2024 Minnesota 2014 - 2016 September 2025 Minnesota 2019 May 2024 Texas 2016, 2018 May 2024 Texas 2017 July 2025 Texas 2019 August 2024 Wisconsin 2016 - 2018 May 2024 Wisconsin 2019 October 2024
Reconciliation of Unrecognized Tax Benefits	Unrecognized tax benefits - permanent vs. temporary: (Millions of Dollars) Dec. 31, 2023 Dec. 31, 2022 Unrecognized tax benefit — Permanent tax positions $ 41 $ 55 Unrecognized tax benefit — Temporary tax positions — 12 Total unrecognized tax benefit $ 41 $ 67 Changes in unrecognized tax benefits: (Millions of Dollars) 2023 2022 2021 Balance at Jan. 1 $ 67 $ 58 $ 52 Additions based on tax positions related to the current year 5 7 5 Additions for tax positions of prior years 1 6 2 Reductions for tax positions of prior years (29) (1) (1) Reductions for tax positions related to settlements with taxing authorities (1) (1) — Reductions for tax positions related to statute of limitations (2) (2) — Balance at Dec. 31 $ 41 $ 67 $ 58
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, 2023 Dec. 31, 2022 NOL and tax credit carryforwards $ (35) $ (40)
Interest Payable related to Unrecognized Tax Benefits [Table Text Block]	Interest payable related to unrecognized tax benefits: (Millions of Dollars) 2023 2022 2021 Payable for interest related to unrecognized tax benefits at Jan. 1 $ (4) $ (3) $ (3) Interest benefit (expense) related to unrecognized tax benefits 3 (1) — Payable for interest related to unrecognized tax benefits at Dec. 31 $ (1) $ (4) $ (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) 2023 2022 Federal NOL carryforward $ — $ 20 Federal tax credit carryforwards 1,644 1,593 Valuation allowances for federal credit carryforwards (10) — State NOL carryforwards 11 1,022 Valuation allowances for state NOL carryforwards (2) (3) State tax credit carryforwards, net of federal detriment (a) 74 85 Valuation allowances for state credit carryforwards, net of federal benefit (b) (60) (62) (a) State tax credit carryforwards are net of federal detriment of $20 million and $23 million as of Dec. 31, 2023 and 2022, respectively. (b) Valuation allowances for state tax credit carryforwards were net of federal benefit of $16 million as of Dec. 31, 2023 and 2022.
Schedule of Effective Income Tax Rate Reconciliation	Effective income tax rate for years ended Dec. 31: 2023 2022 2021 Federal statutory rate 21.0 % 21.0 % 21.0 % State income tax on pretax income, net of federal tax effect 4.9 4.9 5.0 (Decreases) increases in tax from: Wind PTCs (a) (28.1) (27.4) (23.4) Plant regulatory differences (b) (5.6) (5.5) (6.2) Other tax credits, net NOL & tax credit allowances (1.3) (1.3) (1.1) Other, net 0.1 (0.1) 0.1 Effective income tax rate (9.0) % (8.4) % (4.6) % (a) Wind PTCs net of estimated transfer discount are credited to customers (reduction to revenue) and do not materially impact net income. (b) Plant regulatory differences primarily relate to the credit of excess deferred taxes to customers through the average rate assumption method. Income tax benefits associated with the credit are offset by corresponding revenue reductions.
Schedule of Components of Income Tax Expense (Benefit)	Components of income tax expense for years ended Dec. 31: (Millions of Dollars) 2023 2022 2021 Current federal tax expense $ 113 $ 1 $ 15 Current state tax expense (benefit) 16 3 (2) Current change in unrecognized tax (benefit) expense (21) 5 1 Deferred federal tax benefit (331) (239) (183) Deferred state tax expense 75 96 99 Deferred change in unrecognized tax expense 7 3 5 Deferred ITCs (5) (4) (5) Total income tax benefit $ (146) $ (135) $ (70) Components of deferred income tax expense as of Dec. 31: (Millions of Dollars) 2023 2022 2021 Deferred tax expense (benefit) excluding items below $ 129 $ (138) $ 148 Adjustments to deferred income taxes for wind production tax credit cash transfers (a) (190) — — Amortization and adjustments to deferred income taxes on income tax regulatory assets and liabilities (188) 8 (221) Tax benefit allocated to other comprehensive income and other — (10) (6) Deferred tax benefit $ (249) $ (140) $ (79) (a) Proceeds from tax credit transfers are included in cash received (paid) for income taxes in the consolidated statement of cash flows.
Schedule of Deferred Tax Assets and Liabilities	Components of net deferred tax liability as of Dec. 31: (Millions of Dollars) 2023 2022 (a) Deferred tax liabilities: Differences between book and tax bases of property $ 6,744 $ 6,442 Regulatory assets 538 484 Operating lease assets 327 325 Pension expense 151 159 Deferred fuel costs 67 222 Other 84 90 Total deferred tax liabilities $ 7,911 $ 7,722 Deferred tax assets: Tax credit carryforward $ 1,718 $ 1,679 Regulatory liabilities 730 718 Operating lease liabilities 327 325 Other employee benefits 117 102 Deferred investment tax credits 16 14 NOL carryforward — 57 NOL and tax credit valuation allowances (70) (62) Other 188 133 Total deferred tax assets 3,026 2,966 Net deferred tax liability $ 4,885 $ 4,756 (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, 2023
Share-Based Payment Arrangement [Abstract]
Equity Awards	Equity award units granted to employees: (Units in Thousands) 2023 2022 2021 Granted units 586 395 421 Weighted average grant date fair value $ 67.06 $ 68.43 $ 66.03 Equity awards vested: (Units in Thousands, Fair Value in Millions) 2023 2022 2021 Vested Units 329 319 392 Total Fair Value $ 20 $ 22 $ 27 Changes in the nonvested portion of equity award units: (Units in Thousands) Units Weighted Average Nonvested Units at Jan. 1, 2023 708 $ 67.35 Granted 586 67.06 Forfeited (184) 68.42 Vested (329) 66.23 Dividend equivalents 38 67.65 Nonvested Units at Dec. 31, 2023 819 67.36
Stock Equivalent Unit Plan	Stock equivalent units granted: (Units in Thousands) 2023 2022 2021 Granted units 38 29 31 Weighted average grant date fair value $ 63.12 $ 71.97 $ 68.15 Changes in stock equivalent units: (Units in Thousands) Units Weighted Average Stock equivalent units at Jan. 1, 2023 597 $ 41.75 Granted 38 63.12 Units distributed (134) 33.90 Dividend equivalents 16 64.95 Stock equivalent units at Dec. 31, 2023 517 46.07
TSR Liability Awards	Liability awards granted: (In Thousands) 2023 2022 2021 Awards granted 216 165 221 Liability awards settled: (Units In Thousands, Settlement Amount in Millions) 2023 2022 2021 Awards settled 282 411 446 Settlement amount (cash, common stock and deferred amounts) $ 19 $ 27 $ 27
Compensation costs related to share-based awards	Compensation costs related to share-based awards: (Millions of Dollars) 2023 2022 2021 Cost for share-based awards (a) $ 27 $ 36 $ 31 Tax benefit recognized in income 7 9 8 (a) Compensation costs for share-based payments are included in O&M expense. Amount for equity awards (non-cash) was $25 million in 2023.

Earnings Per Share (Tables)

Earnings Per Share (Tables)	12 Months Ended
	Dec. 31, 2023
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) 2023 2022 2021 Basic 552 547 539 Diluted (a) 552 547 540 (a) Diluted common shares outstanding included common stock equivalents of 0.3 million shares for 2023, 2022 and 2021.

Fair Value of Financial Asset_2

Fair Value of Financial Assets and Liabilities (Tables)	12 Months Ended
	Dec. 31, 2023
Fair Value Disclosures [Abstract]
Cost and Fair Value of Nuclear Decommissioning Fund Investments	Non-derivative instruments with recurring fair value measurements in the nuclear decommissioning fund: Dec. 31, 2023 Fair Value (Millions of Dollars) Cost Level 1 Level 2 Level 3 NAV Total Nuclear decommissioning fund (a) Cash equivalents $ 41 $ 41 $ — $ — $ — $ 41 Commingled funds 721 — — — 1,049 1,049 Debt securities 784 — 771 9 — 780 Equity securities 508 1,339 2 — — 1,341 Total $ 2,054 $ 1,380 $ 773 $ 9 $ 1,049 $ 3,211 (a) Reported in nuclear decommissioning fund and other investments on the consolidated balance sheets, which also includes $244 million of equity method investments and $144 million of rabbi trust assets and other miscellaneous investments. Dec. 31, 2022 Fair Value (Millions of Dollars) Cost Level 1 Level 2 Level 3 NAV Total Nuclear decommissioning fund (a) Cash equivalents $ 29 $ 29 $ — $ — $ — $ 29 Commingled funds 803 — — — 1,178 1,178 Debt securities 738 — 669 6 — 675 Equity securities 406 999 1 — — 1,000 Total $ 1,976 $ 1,028 $ 670 $ 6 $ 1,178 $ 2,882 (a) Reported in nuclear decommissioning fund and other investments on the consolidated balance sheets, which also includes $219 million of equity investments in unconsolidated subsidiaries and $133 million of rabbi trust assets and other 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, 2023: 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 $ 261 $ 269 $ 246 $ 780
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, 2023 Dec. 31, 2022 MWh of electricity 48 61 MMBtu of natural gas 84 131 (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.
Derivative Instruments, Gain (Loss) [Table Text Block]	Impact of derivative activity: Pre-Tax Fair Value Gains (Losses) Recognized During the Period in: (Millions of Dollars) Accumulated Other Comprehensive Loss Regulatory (Assets) and Liabilities Year Ended Dec. 31, 2023 Derivatives designated as cash flow hedges Interest rate $ (2) $ — Total $ (2) $ — Other derivative instruments Electric commodity $ — $ (137) Natural gas commodity — (13) Total $ — $ (150) Year Ended Dec. 31, 2022 Interest rate $ 22 $ — Total $ 22 $ — Other derivative instruments Electric commodity $ — $ (10) Natural gas commodity — (16) Total $ — $ (26) Year Ended Dec. 31, 2021 Interest rate $ 5 $ — Total $ 5 $ — Other derivative instruments Electric commodity $ — $ 32 Natural gas commodity — (4) Total $ — $ 28 Pre-Tax (Gains) Losses Reclassified into Income During the Period from: Pre-Tax Gains (Losses) Recognized During the Period in Income (Millions of Dollars) Accumulated Other Comprehensive Loss Regulatory Assets and (Liabilities) Year Ended Dec. 31, 2023 Derivatives designated as cash flow hedges Interest rate $ 5 (a) $ — $ — Total $ 5 $ — $ — Other derivative instruments Commodity trading $ — $ — $ (7) (b) Electric commodity — 123 (c) — Natural gas commodity — 15 (d) (27) (d)(e) Total $ — $ 138 $ (34) Year Ended Dec. 31, 2022 Derivatives designated as cash flow hedges Interest rate $ 7 (a) $ — $ — Total $ 7 $ — $ — Other derivative instruments Commodity trading $ — $ — $ 25 (b) Electric commodity — 3 (c) — Natural gas commodity — 10 (d) (27) (d)(e) Total $ — $ 13 $ (2) 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)(e) Total $ — $ (18) $ 41 (a) Recorded to interest charges. (b) Recorded to electric revenues. Presented amounts do not reflect non-derivative transactions or margin sharing with customers. (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. FTR settlements are shared with customers and do not have a material impact on net income. Presented amounts reflect changes in fair value between FTR auction and settlement dates, but exclude the original auction fair value. (d) 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. (e)
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, 2023 Dec. 31, 2022 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 $ 8 $ 51 $ 32 $ 91 $ (59) $ 32 $ 32 $ 259 $ 33 $ 324 $ (242) $ 82 Electric commodity — — 62 62 (7) 55 — — 177 177 (2) 175 Natural gas commodity — 14 — 14 — 14 — 19 — 19 — 19 Total current derivative assets $ 8 $ 65 $ 94 $ 167 $ (66) 101 $ 32 $ 278 $ 210 $ 520 $ (244) 276 PPAs (b) 3 3 Current derivative instruments $ 104 $ 279 Noncurrent derivative assets Other derivative instruments: Commodity trading $ 14 $ 51 $ 45 $ 110 $ (34) $ 76 $ 34 $ 71 $ 74 $ 179 $ (89) $ 90 Total noncurrent derivative assets $ 14 $ 51 $ 45 $ 110 $ (34) 76 $ 34 $ 71 $ 74 $ 179 $ (89) 90 PPAs (b) — 3 Noncurrent derivative instruments $ 76 $ 93 Dec. 31, 2023 Dec. 31, 2022 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 Derivatives designated as cash flow hedges: Interest rate $ — $ 17 $ — $ 17 $ — $ 17 $ — $ 1 $ — $ 1 $ — $ 1 Other derivative instruments: Commodity trading 6 86 5 97 (60) 37 29 297 6 332 (287) 45 Electric commodity — — 7 7 (7) — — — 2 2 (2) — Natural gas commodity — 12 — 12 — 12 — 13 — 13 — 13 Total current derivative liabilities $ 6 $ 115 $ 12 $ 133 $ (67) 66 $ 29 $ 311 $ 8 $ 348 $ (289) 59 PPAs (b) 8 17 Current derivative instruments $ 74 $ 76 Noncurrent derivative liabilities Other derivative instruments: Commodity trading $ 16 $ 50 $ 37 $ 103 $ (39) $ 64 $ 43 $ 97 $ 41 $ 181 $ (98) $ 83 Total noncurrent derivative liabilities $ 16 $ 50 $ 37 $ 103 $ (39) 64 $ 43 $ 97 $ 41 $ 181 $ (98) 83 PPAs (b) 22 30 Noncurrent derivative instruments $ 86 $ 113 (a) Xcel Energy nets derivative instruments and related collateral on its consolidated balance sheets when supported by a legally enforceable master netting agreement. At Dec. 31, 2023 and 2022, derivative assets and liabilities include no obligations to return cash collateral. At Dec. 31, 2023 and 2022, derivative assets and liabilities include rights to reclaim cash collateral of $7 million and $53 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) Xcel Energy currently applies the normal purchase exception to qualifying PPAs. Balance relates to specific contracts that were previously recognized at fair value prior to applying the normal purchase exception, and are being amortized over the remaining contract lives along with the offsetting regulatory assets and liabilities.
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) 2023 2022 2021 Balance at Jan. 1 $ 236 $ 19 $ (49) Purchases (a) 176 406 65 Settlements (a) (154) (350) (158) Net transactions recorded during the period: Gains recognized in earnings (b) 6 151 49 Net (losses) gains recognized as regulatory assets and liabilities (a) (174) 10 112 Balance at Dec. 31 $ 90 $ 236 $ 19 (a) Relates primarily to NSP-Minnesota and SPS FTR instruments administered by MISO and SPP. (b) Relates to commodity trading and is subject to substantial offsetting losses and gains on derivative instruments categorized as levels 1 and 2 in the income statement. See above tables for the income statement impact of derivative activity, including commodity trading gains and losses.
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: 2023 2022 (Millions of Dollars) Carrying Amount Fair Value Carrying Amount Fair Value Long-term debt, including current portion $ 25,465 $ 22,927 $ 23,964 $ 20,897

Benefit Plans and Other Postr_2

Benefit Plans and Other Postretirement Benefits (Tables)	12 Months Ended
	Dec. 31, 2023
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, 2023 (a) Dec. 31, 2022 (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 $ 233 $ — $ — $ — $ 233 $ 129 $ — $ — $ — $ 129 Commingled funds 491 — — 1,235 1,726 935 — — 882 1,817 Debt securities — 683 4 — 687 — 682 3 — 685 Equity securities 35 — — — 35 47 — — — 47 Other — 9 — — 9 — 7 — — 7 Total $ 759 $ 692 $ 4 $ 1,235 $ 2,690 $ 1,111 $ 689 $ 3 $ 882 $ 2,685 (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, 2023 (a) Dec. 31, 2022 (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 $ 33 $ — $ — $ — $ 33 $ 31 $ — $ — $ — $ 31 Insurance contracts — 40 — — 40 — 41 — — 41 Commingled funds 22 — — 72 94 54 — — 63 117 Debt securities — 187 1 — 188 — 175 1 — 176 Other — 1 — — 1 — (1) — — (1) Total $ 55 $ 228 $ 1 $ 72 $ 356 $ 85 $ 215 $ 1 $ 63 $ 364 (a) See Note 10 for further information on fair value measurement inputs and methods. Targeted asset allocations: Pension Benefits Postretirement Benefits 2023 2022 2023 2022 Long-duration fixed income securities 38 % 38 % — % — % Domestic and international equity securities 31 33 9 16 Alternative investments 20 18 13 12 Short-to-intermediate fixed income securities 9 9 77 71 Cash 2 2 1 1 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) 2023 2022 2023 2022 Change in Benefit Obligation: Obligation at Jan. 1 $ 2,871 $ 3,718 $ 405 $ 511 Service cost 74 97 1 2 Interest cost 158 110 22 15 Plan amendments (3) 1 — — Actuarial (gain) loss 126 (703) 14 (85) Plan participants’ contributions — — 8 8 Medicare subsidy reimbursements — — — 2 Benefit payments (a) (283) (352) (56) (48) Obligation at Dec. 31 $ 2,943 $ 2,871 $ 394 $ 405 Change in Fair Value of Plan Assets: Fair value of plan assets at Jan. 1 $ 2,685 $ 3,670 $ 364 $ 442 Actual return on plan assets 238 (683) 29 (51) Employer contributions 50 50 11 13 Plan participants’ contributions — — 8 8 Benefit payments (283) (352) (56) (48) Fair value of plan assets at Dec. 31 2,690 2,685 356 364 Funded status of plans at Dec. 31 $ (253) $ (186) $ (38) $ (41) Amounts recognized in the Consolidated Balance Sheet at Dec. 31: Noncurrent assets $ 1 $ 15 $ 28 $ 33 Current liabilities — — (3) (2) Noncurrent liabilities (254) (201) (63) (72) Net amounts recognized $ (253) $ (186) $ (38) $ (41) (a) Includes lump-sum benefit payments used in the determination of a settlement charges of $195 million of in 2022. Pension Benefits Postretirement Benefits Significant Assumptions Used to Measure Benefit Obligations: 2023 2022 2023 2022 Discount rate for year-end valuation 5.49 % 5.80 % 5.54 % 5.80 % Expected average long-term increase in compensation level 4.25 % 4.25 % 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 6.50 % 6.50 % Health care costs trend rate — initial: Post-65 N/A N/A 5.50 % 5.50 % 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 6 7
Projected Benefit Payments for the Pension and Postretirement Benefit Plans	(Millions of Dollars) Projected Gross Projected Expected Net Projected 2024 $ 398 $ 42 $ 2 $ 40 2025 214 40 2 38 2026 217 39 2 37 2027 223 37 2 35 2028 226 36 2 34 2029 - 2033 1,131 161 12 149
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost	Pension Benefits Postretirement Benefits (Millions of Dollars) 2023 2022 2023 2022 Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost: Net loss $ 1,096 $ 1,021 $ 64 $ 63 Prior service credit (9) (7) — (1) Total $ 1,087 $ 1,014 $ 64 $ 62 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 $ 20 $ 21 $ 2 $ — Noncurrent regulatory assets 1,014 943 79 78 Current regulatory liabilities — — (1) (1) Noncurrent regulatory liabilities — — (19) (20) Deferred income taxes 14 14 1 1 Net-of-tax accumulated other comprehensive income 39 36 2 4 Total $ 1,087 $ 1,014 $ 64 $ 62
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) 2023 2022 2021 2023 2022 2021 Service cost $ 74 $ 97 $ 104 $ 1 $ 2 $ 2 Interest cost 158 110 104 22 15 15 Expected return on plan assets (209) (208) (206) (17) (18) (18) Amortization of prior service credit (1) (1) (1) (1) (6) (8) Amortization of net loss 22 75 107 1 2 5 Settlement charge (a) — 71 59 — — — Net periodic pension cost (credit) 44 144 167 6 (5) (4) Effects of regulation 30 (30) (46) — 3 2 Net benefit cost (credit) recognized for financial reporting $ 74 $ 114 $ 121 $ 6 $ (2) $ (2) Significant Assumptions Used to Measure Costs: Discount rate 5.80 % 3.08 % 2.71 % 5.80 % 3.09 % 2.65 % Expected average long-term increase in compensation level 4.25 3.75 3.75 — — — Expected average long-term rate of return on assets 6.93 6.49 6.49 5.00 4.10 4.10

Commitments and Contingencies (

Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2023
Commitments and Contingencies Disclosure [Abstract]
Asset Retirement Obligations	Xcel Energy’s AROs were as follows: (Millions Jan. 1, 2023 Amounts Incurred (a) Amounts Settled Accretion Cash Flow Revisions (b) Dec. 31, 2023 Electric Nuclear $ 2,160 $ — $ — $ 105 $ (158) $ 2,107 Wind 514 10 — 19 (17) 526 Steam, hydro and other production 348 — (1) 15 (1) 361 Distribution 48 — — 1 — 49 Natural gas Transmission and distribution 307 — 14 (149) 172 Other Miscellaneous 3 — — — — 3 Total liability $ 3,380 $ 10 $ (1) $ 154 $ (325) $ 3,218 (a) Amounts incurred relate to the Northern Wind farm placed in service in NSP-Minnesota. (b) In 2023, AROs were revised for changes in timing and estimates of cash flows. Revisions in wind and nuclear AROs were primarily incurred due to changes in useful lives. Changes in gas transmission and distribution AROs were a result of updated gas line mileage and number of services, as well as changes to inflation and discount rate assumptions. (Millions Jan. 1, 2022 Amounts Incurred (a) Accretion Cash Flow Revisions (b) Dec. 31, 2022 Electric Nuclear $ 2,056 $ — $ 104 $ — $ 2,160 Wind 478 25 19 (8) 514 Steam, hydro and other production 288 34 12 14 348 Distribution 47 — 1 — 48 Natural gas Transmission and distribution (c) 279 — 12 16 307 Other Miscellaneous 3 — — — 3 Total liability $ 3,151 $ 59 $ 148 $ 22 $ 3,380 (a) Amounts incurred related to the wind farms placed in service in 2022 for NSP-Minnesota (Dakota Range and Rock Aetna) and steam production pond remediation costs for PSCo. (b) In 2022, 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) Prior periods have been reclassified to conform with current year presentation.
Assets and Liabilities, Lessee [Table Text Block]	Operating lease ROU assets: (Millions of Dollars) Dec. 31, 2023 Dec. 31, 2022 PPAs $ 1,832 $ 1,669 Other 315 244 Gross operating lease ROU assets 2,147 1,913 Accumulated amortization (930) (709) Net operating lease ROU assets $ 1,217 $ 1,204 Finance lease ROU assets: (Millions of Dollars) Dec. 31, 2023 Dec. 31, 2022 Gas storage facilities $ 160 $ 160 Gas pipeline 21 21 Gross finance lease ROU assets 181 181 Accumulated amortization (67) (64) Net finance lease ROU assets $ 114 $ 117
Lease, Cost [Table Text Block]	Components of lease expense: (Millions of Dollars) 2023 2022 2021 Operating leases PPA capacity payments $ 241 $ 241 $ 251 Other operating leases (a) 42 39 36 Total operating lease expense (b) $ 283 $ 280 $ 287 Finance leases Amortization of ROU assets $ 3 $ 4 $ 7 Interest expense on lease liability 15 16 17 Total finance lease expense $ 18 $ 20 $ 24 (a) Includes short-term lease expense of $3 million, $6 million, and $5 million for 2023, 2022 and 2021, respectively. (b)
Finance Lease, Liability, Maturity [Table Text Block]	Commitments under operating and finance leases as of Dec. 31, 2023: (Millions of Dollars) PPA (a) (b) Operating Leases Other Operating Leases Total Leases Finance Leases (c) 2024 $ 244 $ 33 $ 277 $ 10 2025 245 26 271 10 2026 216 22 238 9 2027 162 22 184 8 2028 107 22 129 8 Thereafter 259 162 421 173 Total minimum obligation 1,233 287 1,520 218 Interest component of obligation (157) (99) (256) (154) Present value of minimum obligation $ 1,076 188 1,264 64 Less current portion (226) (2) Noncurrent operating and finance lease liabilities $ 1,038 $ 62 Weighted-average remaining lease term in years 8.2 36.8 (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, 2023, the estimated future payments for capacity and energy that the utility subsidiaries of Xcel Energy are obligated to purchase pursuant to these non-lease contracts, subject to availability, were as follows: (Millions of Dollars) Capacity Energy (a) 2024 $ 80 $ 207 2025 45 94 2026 28 47 2027 9 10 2028 1 10 Thereafter 2 18 Total $ 165 $ 386 (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, 2023: (Millions of Dollars) Coal Nuclear fuel Natural gas supply Natural gas storage and transportation 2024 $ 350 $ 142 $ 339 $ 311 2025 157 179 13 284 2026 81 63 — 276 2027 56 180 — 238 2028 21 50 — 111 Thereafter 1 177 — 442 Total $ 666 $ 791 $ 352 $ 1,662
Other Commitments	Committed minimum payments under these obligations as follows: (Millions of Dollars) Minimum Payments 2024 $ 18 2025 14 2026 13 2027 12 2028 — Thereafter —

Other Comprehensive Income (Tab

Other Comprehensive Income (Tables)	12 Months Ended
	Dec. 31, 2023
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: 2023 (Millions of Dollars) Gains and Losses on Interest Rate Cash Flow Hedges Defined Benefit Pension and Postretirement Items Total Accumulated other comprehensive loss at Jan. 1 $ (54) $ (39) $ (93) Other comprehensive loss before reclassifications (2) (4) (6) Losses reclassified from net accumulated other comprehensive loss: Amortization of interest rate hedges 3 (a) — 3 Amortization of net actuarial loss — 2 (b) 2 Net current period other comprehensive income (loss) 1 (2) (1) Accumulated other comprehensive loss at Dec. 31 $ (53) $ (41) $ (94) (a) Included in interest charges. (b) Included in the computation of net periodic pension and postretirement benefit costs. See Note 11 for further information. 2022 (Millions of Dollars) Gains and Losses on Interest Rate Cash Flow Hedges Defined Benefit Pension and Postretirement Items Total Accumulated other comprehensive loss at Jan. 1 $ (75) $ (48) $ (123) Other comprehensive gain before reclassifications 16 5 21 Losses reclassified from net accumulated other comprehensive loss: Amortization of interest rate hedges 5 (a) — 5 Amortization of net actuarial loss — 4 (b) 4 Net current period other comprehensive income 21 9 30 Accumulated other comprehensive loss at Dec. 31 $ (54) $ (39) $ (93) (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, 2023
Segment Reporting [Abstract]
Results from Operations by Reportable Segment	Xcel Energy’s segment information: (Millions of Dollars) 2023 2022 2021 Regulated Electric Operating revenues — external $ 11,446 $ 12,123 $ 11,205 Intersegment revenue 2 2 2 Total revenues $ 11,448 $ 12,125 $ 11,207 Depreciation and amortization 2,111 2,122 1,855 Interest charges and financing costs 670 636 568 Income tax benefit (135) (162) (96) Net income 1,686 1,631 1,478 Regulated Natural Gas Operating revenues — external $ 2,645 $ 3,080 $ 2,132 Intersegment revenue 3 2 2 Total revenues $ 2,648 $ 3,082 $ 2,134 Depreciation and amortization 323 276 254 Interest charges and financing costs 96 86 75 Income tax expense 50 68 54 Net income 219 264 231 All Other Total revenues $ 115 $ 107 $ 94 Depreciation and amortization 14 15 12 Interest charges and financing costs 238 203 173 Income tax benefit (61) (41) (28) Net loss (134) (159) (112) Consolidated Total Total revenues $ 14,211 $ 15,314 $ 13,435 Reconciling eliminations (5) (4) (4) Total operating revenues $ 14,206 $ 15,310 $ 13,431 Depreciation and amortization 2,448 2,413 2,121 Interest charges and financing costs 1,004 925 816 Income tax benefit (146) (135) (70) Net income 1,771 1,736 1,597

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, 2023
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) 2023 2022 2021 2023 2022 2021 Balance at Jan. 1 $ 122 $ 106 $ 79 $ 62 $ 64 $ 64 Additions charged to costs and expenses 79 73 60 26 6 5 Additions charged to other accounts 13 (a) 26 (a) 14 (a) — — — Deductions from reserves (86) (b) (83) (b) (47) (b) (18) (c) (8) (c) (5) (c) Balance at Dec. 31 $ 128 $ 122 $ 106 $ 70 $ 62 $ 64 (a) Recovery of amounts previously written-off. (b) Deductions related primarily to bad debt write-offs. (c) Primarily reversals of valuation allowances on completed tax credit sales and reductions of valuation allowances for items forecasted to be used prior to expiration.

Summary of Significant Accoun_4

Summary of Significant Accounting Policies Summary of Significant Accounting Policies (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Property, Plant and Equipment [Abstract]
Depreciation expense expressed as a percentage of average depreciable property	3.60%	3.70%	3.50%
Nuclear Decommissioning [Abstract]
Studies time periods	3 years
Cash and Cash Equivalents [Abstract]
maturity period	3 months
Accounts, Notes, Loans and Financing Receivable
Allowance for bad debts	$ 128	$ 122
Alternative Revenue Programs [Abstract]
maximum number of months following end of annual period in which revenues are earned to be included in	24 months
Inventories	$ 711	803
Studies time periods	3 years
maximum number of months following end of annual period in which revenues are earned to be included in	24 months
maturity period	3 months
Supplies [Member]
Inventories	$ 377	330
Public Utilities, Inventory, Fuel [Member]
Inventories	211	201
Public Utilities, Inventory, Natural Gas [Member]
Inventories	$ 123	$ 272

Property Plant and Equipment Ma

Property Plant and Equipment Major classes of property, plant and equipment (Details) - USD ($) $ in Millions		Dec. 31, 2023	Dec. 31, 2022
Property, Plant and Equipment [Line Items]
Property, plant and equipment		$ 69,692	$ 65,464
Accumulated depreciation and amortization		(18,399)	(17,502)
Property, plant and equipment, net		51,642	48,253
Electric plant
Property, Plant and Equipment [Line Items]
Property, plant and equipment		52,494	49,639
Natural gas plant
Property, Plant and Equipment [Line Items]
Property, plant and equipment		9,080	8,514
Common and other property
Property, Plant and Equipment [Line Items]
Property, plant and equipment		3,190	2,970
Plant to be retired
Property, Plant and Equipment [Line Items]
Property, plant and equipment	[1]	2,055	2,217
CWIP
Property, Plant and Equipment [Line Items]
Property, plant and equipment		2,873	2,124
Nuclear fuel
Property, Plant and Equipment [Line Items]
Property, plant and equipment		3,337	3,183
Accumulated depreciation and amortization		$ (2,988)	$ (2,892)
[1]Amounts include Sherco 1 and 3 and A.S. King for NSP-Minnesota; Comanche Units 2 and 3, Craig Units 1 and 2, Hayden Units 1 and 2 and coal generation assets at Pawnee pending facility gas conversion for PSCo; and Tolk Unit 1 and 2 and coal generation assets at Harrington pending facility gas conversion for SPS. The Dec. 31, 2022 balance also includes Sherco 2, which was retired on Dec. 31, 2023. Amounts are presented net of accumulated depreciation.

Property Plant and Equipment Jo

Property Plant and Equipment Joint Ownership of Generation, Transmission and Gas Facilities (Details) $ in Millions	Dec. 31, 2023 USD ($)
NSP Minnesota
Jointly Owned Utility Plant Interests [Line Items]
Plant in Service	$ 1,703	[1]
Accumulated Depreciation	752	[1]
CWIP	2
NSP Minnesota | Electric Generation | Sherco Unit 3
Jointly Owned Utility Plant Interests [Line Items]
Plant in Service	633
Accumulated Depreciation	$ 480
Percent Owned	59%
NSP Minnesota | Electric Generation | Sherco Common Facilities
Jointly Owned Utility Plant Interests [Line Items]
Plant in Service	$ 185
Accumulated Depreciation	$ 121
Percent Owned	80%
NSP Minnesota | Electric Generation | Sherco substation
Jointly Owned Utility Plant Interests [Line Items]
Plant in Service	$ 5
Accumulated Depreciation	$ 4
Percent Owned	59%
NSP Minnesota | Electric Transmission | Grand Meadow
Jointly Owned Utility Plant Interests [Line Items]
Plant in Service	$ 11
Accumulated Depreciation	$ 4
Percent Owned	50%
NSP Minnesota | Electric Transmission | Huntley Wilmarth
Jointly Owned Utility Plant Interests [Line Items]
Plant in Service	$ 49
Accumulated Depreciation	$ 2
Percent Owned	50%
NSP Minnesota | Electric Transmission | CapX2020
Jointly Owned Utility Plant Interests [Line Items]
Plant in Service	$ 820
Accumulated Depreciation	$ 141
Percent Owned	51%
NSP-Wisconsin
Jointly Owned Utility Plant Interests [Line Items]
Plant in Service	$ 347	[2]
Accumulated Depreciation	64	[2]
CWIP	1
NSP-Wisconsin | Electric Transmission | La Crosse, WI to Madison, WI
Jointly Owned Utility Plant Interests [Line Items]
Plant in Service	178
Accumulated Depreciation	$ 25
Percent Owned	37%
NSP-Wisconsin | Electric Transmission | CapX2020
Jointly Owned Utility Plant Interests [Line Items]
Plant in Service	$ 169
Accumulated Depreciation	$ 39
Percent Owned	80%
PSCo
Jointly Owned Utility Plant Interests [Line Items]
Plant in Service	$ 1,643	[3]
Accumulated Depreciation	587	[3]
CWIP	18
PSCo | Electric Generation | Hayden Unit 1
Jointly Owned Utility Plant Interests [Line Items]
Plant in Service	157
Accumulated Depreciation	$ 108
Percent Owned	76%
PSCo | Electric Generation | Hayden Unit 2
Jointly Owned Utility Plant Interests [Line Items]
Plant in Service	$ 151
Accumulated Depreciation	$ 87
Percent Owned	37%
PSCo | Electric Generation | Hayden Common Facilities
Jointly Owned Utility Plant Interests [Line Items]
Plant in Service	$ 44
Accumulated Depreciation	$ 31
Percent Owned	53%
PSCo | Electric Generation | Craig Units 1 and 2
Jointly Owned Utility Plant Interests [Line Items]
Plant in Service	$ 82
Accumulated Depreciation	$ 55
Percent Owned	10%
PSCo | Electric Generation | Craig Common Facilities
Jointly Owned Utility Plant Interests [Line Items]
Plant in Service	$ 39
Accumulated Depreciation	$ 25
Percent Owned	7%
PSCo | Electric Generation | Comanche Unit 3
Jointly Owned Utility Plant Interests [Line Items]
Plant in Service	$ 916
Accumulated Depreciation	$ 191
Percent Owned	67%
PSCo | Electric Generation | Comanche Common Facilities
Jointly Owned Utility Plant Interests [Line Items]
Plant in Service	$ 29
Accumulated Depreciation	$ 4
Percent Owned	77%
PSCo | Electric Transmission | Transmission and other facilities
Jointly Owned Utility Plant Interests [Line Items]
Plant in Service	$ 189
Accumulated Depreciation	75
PSCo | Gas Transportation | Rifle, CO to Avon, CO
Jointly Owned Utility Plant Interests [Line Items]
Plant in Service	28
Accumulated Depreciation	$ 9
Percent Owned	60%
PSCo | Gas Transportation | Gas Transportation Compressor
Jointly Owned Utility Plant Interests [Line Items]
Plant in Service	$ 8
Accumulated Depreciation	$ 2
Percent Owned	50%
[1] Projects additionally include $2 million in CWIP. Projects additionally include $1 million in CWIP. Projects additionally include $18 million in CWIP.

Regulatory Assets and Liabili_3

Regulatory Assets and Liabilities, Regulatory Assets (Details) - USD ($) $ in Millions		Dec. 31, 2023	Dec. 31, 2022
Regulatory Assets [Line Items]
Regulatory Asset, Current		$ 611	$ 1,059	[1]
Regulatory Asset, Noncurrent		2,798	2,871	[1]
Regulatory assets not currently earning a return		1,085	1,020
Pension and retiree medical obligations
Regulatory Assets [Line Items]
Regulatory Asset, Current		27	22	[1]
Regulatory Asset, Noncurrent		1,106	1,069	[1]
Recoverable deferred taxes on AFUDC recorded in plant
Regulatory Assets [Line Items]
Regulatory Asset, Current		0	0	[1]
Regulatory Asset, Noncurrent		332	292	[1]
Net AROs
Regulatory Assets [Line Items]
Regulatory Asset, Current	[2]	0	0	[1]
Regulatory Asset, Noncurrent	[2]	316	339	[1]
Excess deferred taxes - TCJA
Regulatory Assets [Line Items]
Regulatory Asset, Current		10	13	[1]
Regulatory Asset, Noncurrent		198	205	[1]
Depreciation differences
Regulatory Assets [Line Items]
Regulatory Asset, Current		17	17	[1]
Regulatory Asset, Noncurrent		$ 189	193	[1]
Depreciation differences | Minimum
Regulatory Assets [Line Items]
Regulatory Asset, Remaining Amortization Period		1 year
Depreciation differences | Maximum
Regulatory Assets [Line Items]
Regulatory Asset, Remaining Amortization Period		12 years
Environmental remediation costs
Regulatory Assets [Line Items]
Regulatory Asset, Current		$ 15	20	[1]
Regulatory Asset, Noncurrent		94	92	[1]
Deferred purchased natural gas and electric energy costs
Regulatory Assets [Line Items]
Regulatory Asset, Current		239	581	[1]
Regulatory Asset, Noncurrent		$ 80	299	[1]
Deferred purchased natural gas and electric energy costs | Minimum
Regulatory Assets [Line Items]
Regulatory Asset, Remaining Amortization Period		1 year
Deferred purchased natural gas and electric energy costs | Maximum
Regulatory Assets [Line Items]
Regulatory Asset, Remaining Amortization Period		3 years
Conservation programs
Regulatory Assets [Line Items]
Regulatory Asset, Current	[3]	$ 19	16	[1]
Regulatory Asset, Noncurrent	[3]	$ 54	36	[1]
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
Purchased power contract costs
Regulatory Assets [Line Items]
Regulatory Asset, Current		$ 4	10	[1]
Regulatory Asset, Noncurrent		40	36	[1]
PI extended power update
Regulatory Assets [Line Items]
Regulatory Asset, Current		4	4	[1]
Regulatory Asset, Noncurrent		$ 38	42	[1]
Regulatory Asset, Remaining Amortization Period		11 years
Benson Biomass PPA termination and asset purchase
Regulatory Assets [Line Items]
Regulatory Asset, Current		$ 10	10	[1]
Regulatory Asset, Noncurrent		$ 36	45	[1]
Regulatory Asset, Remaining Amortization Period		5 years
Sales true-up and revenue decoupling
Regulatory Assets [Line Items]
Regulatory Asset, Current		$ 7	54	[1]
Regulatory Asset, Noncurrent		33	0	[1]
State commission adjustments
Regulatory Assets [Line Items]
Regulatory Asset, Current		1	1	[1]
Regulatory Asset, Noncurrent		32	33	[1]
Losses on reacquired debt
Regulatory Assets [Line Items]
Regulatory Asset, Current		2	3	[1]
Regulatory Asset, Noncurrent		30	32	[1]
MISO capacity revenue tracker
Regulatory Assets [Line Items]
Regulatory Asset, Current		36	0	[1]
Regulatory Asset, Noncurrent		$ 26	0	[1]
MISO capacity revenue tracker | Minimum
Regulatory Assets [Line Items]
Regulatory Asset, Remaining Amortization Period		1 year
MISO capacity revenue tracker | Maximum
Regulatory Assets [Line Items]
Regulatory Asset, Remaining Amortization Period		2 years
Gas pipeline inspection and remediation costs
Regulatory Assets [Line Items]
Regulatory Asset, Current		$ 40	42	[1]
Regulatory Asset, Noncurrent		$ 25	13	[1]
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
Contract valuation adjustments
Regulatory Assets [Line Items]
Regulatory Asset, Current	[4]	$ 18	28	[1]
Regulatory Asset, Noncurrent	[4]	22	28	[1]
Nuclear refueling outage costs
Regulatory Assets [Line Items]
Regulatory Asset, Current		43	30	[1]
Regulatory Asset, Noncurrent		$ 19	12	[1]
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
Grid modernization costs
Regulatory Assets [Line Items]
Regulatory Asset, Current		$ 16	14	[1]
Regulatory Asset, Noncurrent		$ 17	24	[1]
Grid modernization costs | Minimum
Regulatory Assets [Line Items]
Regulatory Asset, Remaining Amortization Period		1 year
Grid modernization costs | Maximum
Regulatory Assets [Line Items]
Regulatory Asset, Remaining Amortization Period		2 years
Renewable resources and environmental initiatives
Regulatory Assets [Line Items]
Regulatory Asset, Current		$ 38	50	[1]
Regulatory Asset, Noncurrent		$ 5	6	[1]
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
Other
Regulatory Assets [Line Items]
Regulatory Asset, Current		$ 65	144	[1]
Regulatory Asset, Noncurrent		$ 106	$ 75	[1]
Texas revenue surcharges | Minimum
Regulatory Assets [Line Items]
Regulatory Asset, Remaining Amortization Period		1 year
[1] Prior period amounts have been reclassified to conform with current year presentation. The 2022 amount is net of the nuclear decommissioning accruals and gains from decommissioning investments. In 2023, the nuclear decommissioning accruals and gains from decommissioning investments exceeded the expected cost of AROs in NSP-Minnesota and was reclassified to a regulatory liability. Includes costs for conservation programs, as well as incentives allowed in certain jurisdictions. Includes the fair value of certain long-term PPAs used to meet energy capacity requirements and valuation adjustments on natural gas commodity purchases.

Regulatory Assets and Liabili_4

Regulatory Assets and Liabilities, Regulatory Liabilities (Details) - USD ($) $ in Millions		Dec. 31, 2023	Dec. 31, 2022
Regulatory Liabilities [Line Items]
Regulatory Liability, Current	[1]	$ 528	$ 418
Regulatory Liability, Noncurrent	[1]	5,827	5,569
Regulatory assets not currently earning a return		1,085	1,020
Regulatory assets not currently earning a return		1,085	1,020
Other Current Liabilities
Regulatory Liabilities [Line Items]
Entity's Recorded Provision for Revenue Subject To Refund		187	67
Deferred income tax adjustment and TCJA refunds
Regulatory Liabilities [Line Items]
Regulatory Liability, Current	[2]	7	9
Regulatory Liability, Noncurrent	[2]	3,015	3,110
Plant removal costs
Regulatory Liabilities [Line Items]
Regulatory Liability, Current		0	0
Regulatory Liability, Noncurrent		1,984	1,819
Effects of regulation on employee benefit costs
Regulatory Liabilities [Line Items]
Regulatory Liability, Current	[3]	0	0
Regulatory Liability, Noncurrent	[3]	253	247
Renewable resources and environmental initiatives
Regulatory Liabilities [Line Items]
Regulatory Liability, Current		9	6
Regulatory Liability, Noncurrent		188	173
Net AROs
Regulatory Liabilities [Line Items]
Regulatory Liability, Current	[4]	0	0
Regulatory Liability, Noncurrent	[4]	90	0
Sales true-up and revenue decoupling
Regulatory Liabilities [Line Items]
Regulatory Liability, Current		18	0
Regulatory Liability, Noncurrent		$ 76	77
Sales true-up and revenue decoupling | Maximum
Regulatory Liabilities [Line Items]
Regulatory Liability, Amortization Period		2 years
ITC deferrals
Regulatory Liabilities [Line Items]
Regulatory Liability, Current		$ 1	1
Regulatory Liability, Noncurrent		60	61
LP&L Departure Payment
Regulatory Liabilities [Line Items]
Regulatory Liability, Current		33	0
Regulatory Liability, Noncurrent		$ 33	0
LP&L Departure Payment | Maximum
Regulatory Liabilities [Line Items]
Regulatory Liability, Amortization Period		10 years
Formula rates
Regulatory Liabilities [Line Items]
Regulatory Liability, Current		$ 29	32
Regulatory Liability, Noncurrent		$ 18	17
Formula rates | Minimum
Regulatory Liabilities [Line Items]
Regulatory Liability, Amortization Period		1 year
Formula rates | Maximum
Regulatory Liabilities [Line Items]
Regulatory Liability, Amortization Period		2 years
DOE settlement
Regulatory Liabilities [Line Items]
Regulatory Liability, Current		$ 18	12
Regulatory Liability, Noncurrent		$ 6	3
DOE settlement | Minimum
Regulatory Liabilities [Line Items]
Regulatory Liability, Amortization Period		1 year
DOE settlement | Maximum
Regulatory Liabilities [Line Items]
Regulatory Liability, Amortization Period		2 years
Contract valuation adjustments
Regulatory Liabilities [Line Items]
Regulatory Liability, Current	[5]	$ 56	175
Regulatory Liability, Noncurrent	[5]	0	1
Deferred electric, natural gas and steam production costs
Regulatory Liabilities [Line Items]
Regulatory Liability, Current		220	39
Regulatory Liability, Noncurrent		0	0
Conservation programs
Regulatory Liabilities [Line Items]
Regulatory Liability, Current	[6]	47	72
Regulatory Liability, Noncurrent	[6]	$ 0	0
Conservation programs | Minimum
Regulatory Liabilities [Line Items]
Regulatory Liability, Amortization Period		1 year
Other
Regulatory Liabilities [Line Items]
Regulatory Liability, Current		$ 90	72
Regulatory Liability, Noncurrent		$ 104	$ 61
[1] Revenue subject to refund of $187 million and $67 million for 2023 and 2022, respectively, is included in other current liabilities. 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. Includes regulatory amortization and certain 2018 TCJA benefits approved by the CPUC to offset the PSCo prepaid pension asset. Includes amounts recorded for future recovery of AROs, less amounts recovered through nuclear decommissioning accruals and gains from decommissioning investments. Includes the fair value of FTR instruments utilized/intended to offset the impacts of transmission system congestion. 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, 2023	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Short-term Debt [Line Items]
Amount outstanding at period end	$ 785	$ 785	$ 813
Commercial Paper
Short-term Debt [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	3,550	3,550	3,550	$ 3,100
Amount outstanding at period end	785	785	813	1,005
Average amount outstanding	339	491	552	1,399
Maximum amount outstanding	$ 785	$ 1,241	$ 1,357	$ 2,054
Weighted average interest rate, computed on a daily basis (percentage)	5.51%	5.12%	1.47%	0.57%
Weighted average interest rate at period end (percentage)	5.52%	5.52%	4.66%	0.31%

Borrowings and Other Financin_4

Borrowings and Other Financing Instruments Term Loan Agreement (Details) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Short-term Debt [Line Items]
Amount outstanding at period end	$ 785	$ 813
Xcel Energy Inc.
Short-term Debt [Line Items]
Amount outstanding at period end	$ 165	$ 231

Borrowings and Other Financin_5

Borrowings and Other Financing Instruments Bilateral Credit Agreement (Details) - USD ($) $ in Millions		Dec. 31, 2023	Dec. 31, 2022
Short-term Debt [Line Items]
Amount outstanding at period end		$ 785	$ 813
Revolving Credit Facility [Member]
Short-term Debt [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	[1]	3,550
Letter of Credit
Short-term Debt [Line Items]
Amount outstanding at period end		44	$ 43
NSP Minnesota | Revolving Credit Facility [Member]
Short-term Debt [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	[1]	700
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		$ 65
[1] These credit facilities mature in September 2027.

Borrowings and Other Financin_6

Borrowings and Other Financing Instruments Letters of Credit (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2023	Dec. 31, 2022
Line of Credit Facility [Line Items]
Amount outstanding at period end		$ 785	$ 813
Xcel Energy Inc.
Line of Credit Facility [Line Items]
Amount outstanding at period end		$ 165	$ 231
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	[1]	$ 3,550
Revolving Credit Facility [Member] | Xcel Energy Inc.
Line of Credit Facility [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	[1]	$ 1,500
[1] These credit facilities mature in September 2027.

Borrowings and Other Financin_7

Borrowings and Other Financing Instruments Credit Facilities (Details) $ in Millions		12 Months Ended
		Dec. 31, 2023 USD ($)	Dec. 31, 2022 USD ($)
Line of Credit Facility [Line Items]
Amount outstanding at period end		$ 785	$ 813
Letter of Credit
Line of Credit Facility [Line Items]
Amount outstanding at period end		44	43
Revolving Credit Facility [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	[1]	3,550
Drawn	[2]	829
Available		2,721
Direct advances on the credit facility outstanding		$ 0	0
Parent [Member] | Revolving Credit Facility [Member]
Line of Credit Facility [Line Items]
Line Of Credit Facility Maximum Debt To Total Capitalization Ratio Allowed		65%
Line Of Credit Facility Minimum Threshhold Percentage Of Subsidiary Assets To Consolidated Assets Required To Initiate Cross Default Provisions		15%
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		165	$ 231
Xcel Energy Inc. | Revolving Credit Facility [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	[1]	1,500
Drawn	[2]	165
Available		$ 1,335
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]	59.80%	59.70%
Line Of Credit Facility Maximum Amount Credit Facility May Be Increased	[4],[5]	$ 350
Number Of Additional Periods Revolving Termination Date Can Be Extended Subject To Majority Bank Group Approval	[4],[6]	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]	48.20%	47.40%
Number Of Additional Periods Revolving Termination Date Can Be Extended Subject To Majority Bank Group Approval	[6]	1
Line of Credit Facility, Maximum Borrowing Capacity	[1]	$ 150
Drawn	[2]	60
Available		$ 90
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]	47.70%	47.70%
Line Of Credit Facility Maximum Amount Credit Facility May Be Increased	[5]	$ 150
Number Of Additional Periods Revolving Termination Date Can Be Extended Subject To Majority Bank Group Approval	[6]	2
Line of Credit Facility, Maximum Borrowing Capacity	[1]	$ 700
Drawn	[2]	180
Available		$ 520
SPS | Revolving Credit Facility [Member]
Line of Credit Facility [Line Items]
Line Of Credit Facility Debt To Total Capitalization Ratio (as a percent)	[3]	46.10%	45.70%
Line Of Credit Facility Maximum Amount Credit Facility May Be Increased	[5]	$ 50
Number Of Additional Periods Revolving Termination Date Can Be Extended Subject To Majority Bank Group Approval	[6]	2
Line of Credit Facility, Maximum Borrowing Capacity	[1]	$ 500
Drawn	[2]	75
Available		$ 425
PSCo | Revolving Credit Facility [Member]
Line of Credit Facility [Line Items]
Line Of Credit Facility Debt To Total Capitalization Ratio (as a percent)	[3]	44.80%	44%
Line Of Credit Facility Maximum Amount Credit Facility May Be Increased	[5]	$ 100
Number Of Additional Periods Revolving Termination Date Can Be Extended Subject To Majority Bank Group Approval	[6]	2
Line of Credit Facility, Maximum Borrowing Capacity	[1]	$ 700
Drawn	[2]	349
Available		$ 351
[1] These credit facilities mature in September 2027. Includes outstanding commercial paper and letters of credit. Each credit facility has a financial covenant requiring that the debt-to-total capitalization ratio be less than or equal to 65%. 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. Amounts authorized by state commissions in respective jurisdictions. All extension requests are subject to majority bank group approval.

Borrowings and Other Financin_8

Borrowings and Other Financing Instruments Amended Credit Agreements (Details) - Revolving Credit Facility [Member] - USD ($) $ in Millions		Dec. 31, 2023	Dec. 31, 2022
Line of Credit Facility [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	[1]	$ 3,550
Direct advances on the credit facility outstanding		0	$ 0
NSP Minnesota
Line of Credit Facility [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	[1]	700
Xcel Energy Inc.
Line of Credit Facility [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	[1]	$ 1,500
[1] These credit facilities mature in September 2027.

Borrowings and Other Financin_9

Borrowings and Other Financing Instruments Long-Term Borrowings and Other Financing Instruments (Details) - USD ($) $ in Millions		Dec. 31, 2023	Dec. 31, 2022
Long-Term Borrowings and Other Financing Instruments
Long-term Debt, Gross		$ 25,465	$ 23,964
2024		552
2025		1,103
2026		501
2027		501
2028		1,133
Xcel Energy Inc.
Long-Term Borrowings and Other Financing Instruments
Unamortized discount		(8)	(7)
Unamortized Debt Issuance Expense		(36)	(35)
Current Maturities		0	(500)
Long-term Debt		6,136	5,338
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		$ 500	500
Debt Instrument, Interest Rate, Stated Percentage		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%
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%
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		$ 600	600
Debt Instrument, Interest Rate, Stated Percentage		3.40%
Xcel Energy Inc. | Unsecured Debt [Member] | Series Due Nov. 15, 2031
Long-Term Borrowings and Other Financing Instruments
Face Amount		$ 300	300
Debt Instrument, Interest Rate, Stated Percentage		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%
Xcel Energy Inc. | Unsecured Debt [Member] | Series Due June 1, 2032
Long-Term Borrowings and Other Financing Instruments
Face Amount	[1]	$ 700	700
Debt Instrument, Interest Rate, Stated Percentage	[1]	4.60%
Xcel Energy Inc. | Unsecured Debt [Member] | Series Due Aug. 15, 2033
Long-Term Borrowings and Other Financing Instruments
Face Amount	[2]	$ 800	0
Debt Instrument, Interest Rate, Stated Percentage	[2]	5.45%
Xcel Energy Inc. | Unsecured Debt [Member] | Series Due Oct. 15, 2023
Long-Term Borrowings and Other Financing Instruments
Face Amount		$ 0	500
Debt Instrument, Interest Rate, Stated Percentage		0.50%
NSP Minnesota
Long-Term Borrowings and Other Financing Instruments
Unamortized discount		$ (49)	(45)
Unamortized Debt Issuance Expense		(73)	(66)
Current Maturities		0	(400)
Long-term Debt		7,330	6,542
NSP Minnesota | Mortgage bonds | Series Due May 15, 2023 [Member]
Long-Term Borrowings and Other Financing Instruments
Face Amount		$ 0	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	425
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%
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		$ 700	700
Debt Instrument, Interest Rate, Stated Percentage		2.60%
NSP Minnesota | Mortgage bonds | Series Due April 1, 2052
Long-Term Borrowings and Other Financing Instruments
Face Amount		$ 425	425
Debt Instrument, Interest Rate, Stated Percentage		3.20%
NSP Minnesota | Mortgage bonds | Series Due June 1, 2052
Long-Term Borrowings and Other Financing Instruments
Face Amount	[3]	$ 500	500
Debt Instrument, Interest Rate, Stated Percentage	[3]	4.50%
NSP Minnesota | Mortgage bonds | Series Due May 15, 2053
Long-Term Borrowings and Other Financing Instruments
Face Amount	[4]	$ 800	0
Debt Instrument, Interest Rate, Stated Percentage	[4]	5.10%
NSP Minnesota | Long-term Debt
Long-Term Borrowings and Other Financing Instruments
Face Amount		$ 2	3
NSP-Wisconsin
Long-Term Borrowings and Other Financing Instruments
Unamortized discount		(3)	(3)
Unamortized Debt Issuance Expense		(11)	(11)
Current Maturities		(200)	0
Long-term Debt		1,011	1,086
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		$ 100	100
Debt Instrument, Interest Rate, Stated Percentage		3.05%
NSP-Wisconsin | Mortgage bonds | Series Due May 1, 2051 2
Long-Term Borrowings and Other Financing Instruments
Face Amount		$ 100	100
Debt Instrument, Interest Rate, Stated Percentage		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 | Mortgage bonds | Series Due Sept. 15, 2052
Long-Term Borrowings and Other Financing Instruments
Face Amount	[5]	$ 100	100
Debt Instrument, Interest Rate, Stated Percentage	[5]	4.86%
NSP-Wisconsin | Mortgage bonds | Series Due June 15, 2053
Long-Term Borrowings and Other Financing Instruments
Face Amount	[6]	$ 125	0
Debt Instrument, Interest Rate, Stated Percentage	[6]	5.30%
PSCo
Long-Term Borrowings and Other Financing Instruments
Unamortized discount		$ (41)	(37)
Unamortized Debt Issuance Expense		(59)	(53)
Current Maturities		0	(250)
Long-term Debt		7,450	6,610
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 March 15, 2023 [Member]
Long-Term Borrowings and Other Financing Instruments
Face Amount		$ 0	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		$ 375	375
Debt Instrument, Interest Rate, Stated Percentage		1.90%
PSCo | Mortgage bonds | Series Due June 15, 2031
Long-Term Borrowings and Other Financing Instruments
Face Amount		$ 750	750
Debt Instrument, Interest Rate, Stated Percentage		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		$ 375	375
Debt Instrument, Interest Rate, Stated Percentage		2.70%
PSCo | Mortgage bonds | Series Due June 1, 2052
Long-Term Borrowings and Other Financing Instruments
Face Amount	[7]	$ 400	400
Debt Instrument, Interest Rate, Stated Percentage	[7]	4.50%
PSCo | Mortgage bonds | Series Due June 1, 2032 2
Long-Term Borrowings and Other Financing Instruments
Face Amount	[7]	$ 300	300
Debt Instrument, Interest Rate, Stated Percentage	[7]	4.10%
PSCo | Mortgage bonds | Series Due April 1, 2053
Long-Term Borrowings and Other Financing Instruments
Face Amount	[8]	$ 850	0
Debt Instrument, Interest Rate, Stated Percentage	[8]	5.25%
SPS
Long-Term Borrowings and Other Financing Instruments
Unamortized discount		$ (10)	(10)
Unamortized Debt Issuance Expense		(29)	(29)
Current Maturities		(350)	0
Long-term Debt		2,961	3,211
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		$ 350	350
Debt Instrument, Interest Rate, Stated Percentage		3.15%
SPS | Mortgage bonds | Series due May 1, 2050 2
Long-Term Borrowings and Other Financing Instruments
Face Amount	[9]	$ 250	250
Debt Instrument, Interest Rate, Stated Percentage	[9]	3.15%
SPS | Mortgage bonds | Series Due June 1, 2052
Long-Term Borrowings and Other Financing Instruments
Face Amount	[10]	$ 200	200
Debt Instrument, Interest Rate, Stated Percentage	[10]	5.15%
SPS | Mortgage bonds | Series Due Sept. 15, 2053
Long-Term Borrowings and Other Financing Instruments
Face Amount		$ 100	0
Debt Instrument, Interest Rate, Stated Percentage		6%
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%
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%
Other Subsidiaries
Long-Term Borrowings and Other Financing Instruments
Current Maturities		$ (2)	(1)
Long-term Debt		25	26
Other Subsidiaries | Various Eloigne Co. affordable housing project notes
Long-Term Borrowings and Other Financing Instruments
Long-term Debt, Gross		$ 27	$ 27
[1]2022 financing[2]2023 financing[3] 2022 financing. 2022 financing. 2023 financing. 2023 financing. 2022 financing.

Borrowings and Other Financi_10

Borrowings and Other Financing Instruments Deferred Financing Costs (Details) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Deferred Financing Costs [Abstract]
Deferred Finance Costs, Noncurrent, Net	$ 209	$ 193

Borrowings and Other Financi_11

Borrowings and Other Financing Instruments Other Equity (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Dividend Reinvestment Program [Line Items]
Proceeds from Issuance of Common Stock	$ 270	$ 322	$ 366
DividendReinvestmentProgram [Member]
Dividend Reinvestment Program [Line Items]
Proceeds from Issuance of Common Stock	$ 88	$ 84

Borrowings and Other Financi_12

Borrowings and Other Financing Instruments Capital Stock (Details) - $ / shares	Dec. 31, 2023	Dec. 31, 2022
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)	554,941,703	549,578,018
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, 2023 USD ($)
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	52.30%
Unrestricted Retained Earnings Per State Regulatory Commissions Dividend Restrictions	$ 1,508
Capitalization, Short term debt, long term debt and equity	15,702
Maximum total capitalization	16,140
Maximum additional short term debt authorized for issuance	$ 2,400	[1]
Maximum percentage of short term debt to total capitalization (in hundredths)	15%
NSP-Wisconsin
Debt Instrument [Line Items]
Minimum calendar year average equity to total capitalization ratio authorized by state commission	52.50%	[2]
Equity to total capitalization ratio	52.70%	[2]
Unrestricted Retained Earnings Per State Regulatory Commissions Dividend Restrictions	$ 9
Capitalization, Short term debt, long term debt and equity	2,520
Maximum additional long term debt authorized for issuance	625
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%	[3]
Equity to total capitalization ratio (excluding short-term debt), high end of range (in hundredths)	55%	[3]
Equity to total capitalization ratio (excluding short-term debt) (in hundredths)	54.60%	[3]
Unrestricted Retained Earnings Per State Regulatory Commissions Dividend Restrictions	$ 617	[4]
Capitalization, Short term debt, long term debt and equity	7,298	[4]
Maximum additional long term debt authorized for issuance	100
Maximum additional short term debt authorized for issuance	600
PSCo
Debt Instrument [Line Items]
Maximum additional long term debt authorized for issuance	450
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. Cannot pay annual dividends in excess of forecasted levels if its average equity-to-total capitalization ratio falls below the commission authorized level. Excludes short-term debt.

ATM Program (Details)

ATM Program (Details) - USD ($) shares in Thousands, $ in Millions	3 Months Ended	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
ATM Program [Line Items]
ATM Program Total Available Shares	$ 2,500			$ 800
ATM Shares Issued	3,120	900	4,300	5,330
ATM Total Shares Issued	$ 188	$ 62	$ 300	$ 350
ATM Transaction Fee	$ 2	$ 1	$ 3	$ 3

Revenues (Details)

Revenues (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Total revenue from contracts with customers
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers	$ 13,591	$ 14,708	$ 12,668
Total revenue from contracts with customers | Regulated Electric
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers	10,940	11,623	10,576
Total revenue from contracts with customers | Natural Gas
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers	2,549	2,990	2,010
Total revenue from contracts with customers | All Other
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers	102	95	82
Retail
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers	11,908	12,404	10,315
Retail | Residential
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers	5,179	5,409	4,461
Retail | C&I
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers	6,566	6,837	5,720
Retail | Other
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers	163	158	134
Retail | Regulated Electric
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers	9,413	9,497	8,371
Retail | Regulated Electric | Residential
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers	3,560	3,542	3,194
Retail | Regulated Electric | C&I
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers	5,703	5,807	5,050
Retail | Regulated Electric | Other
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers	150	148	127
Retail | Natural Gas
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers	2,393	2,812	1,862
Retail | Natural Gas | Residential
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers	1,560	1,814	1,222
Retail | Natural Gas | C&I
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers	833	998	640
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	102	95	82
Retail | All Other | Residential
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers	59	53	45
Retail | All Other | C&I
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers	30	32	30
Retail | All Other | Other
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers	13	10	7
Wholesale
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers	815	1,354	1,540
Wholesale | Regulated Electric
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers	815	1,354	1,540
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	649	675	604
Transmission | Regulated Electric
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers	649	675	604
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	219	275	209
Other | Regulated Electric
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers	63	97	61
Other | Natural Gas
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers	156	178	148
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	615	602	763
Alternative revenue and other | Regulated Electric
Disaggregation of Revenue [Line Items]
Alternative revenue and other	506	500	629
Alternative revenue and other | Natural Gas
Disaggregation of Revenue [Line Items]
Alternative revenue and other	96	90	122
Alternative revenue and other | All Other
Disaggregation of Revenue [Line Items]
Alternative revenue and other	13	12	12
Total revenues
Disaggregation of Revenue [Line Items]
Total revenues	14,206	15,310	13,431
Total revenues | Regulated Electric
Disaggregation of Revenue [Line Items]
Total revenues	11,446	12,123	11,205
Total revenues | Natural Gas
Disaggregation of Revenue [Line Items]
Total revenues	2,645	3,080	2,132
Total revenues | All Other
Disaggregation of Revenue [Line Items]
Total revenues	$ 115	$ 107	$ 94

Income Taxes (Details)

Income Taxes (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Income Tax [Line Items]
Federal detriment	$ 20	$ 23
Tax Credit Carryforward [Line Items]
Federal detriment	20	23
Xcel Energy [Member]
Income Tax [Line Items]
Potential Tax Adjustments	$ 0
State and Local Jurisdiction [Member]
Income Tax [Line Items]
Federal Benefit		16
Tax Credit Carryforward [Line Items]
Federal Benefit		$ 16

State Audits (Details)

State Audits (Details) $ in Millions	12 Months Ended
	Dec. 31, 2023 USD ($)
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, 2023	Dec. 31, 2022	Dec. 31, 2021	Jan. 01, 2023	Jan. 01, 2022	Jan. 01, 2021
Income Tax [Line Items]
Unrecognized tax benefit — Permanent tax positions	$ 41	$ 55
Unrecognized tax benefit — Temporary tax positions	0	12
Total unrecognized tax benefit	41	67	$ 58	$ 67	$ 58	$ 52
Additions based on tax positions related to the current year	5	7	5
Additions for tax positions of prior years	1	6	2
Reductions for tax positions of prior years	29	1	1
Unrecognized Tax Benefits, Decrease Resulting from Settlements with Taxing Authorities	(1)	(1)	0
Unrecognized Tax Benefits, Reduction Resulting from Lapse of Applicable Statute of Limitations	(2)	(2)	0
NOL and tax credit carryforwards	35	40
Upper bound of decrease in unrecognized tax benefit that is reasonably possible	14
Payable for interest related to unrecognized tax benefits at Jan. 1	(1)	(4)	(3)	$ (4)	$ (3)	$ (3)
Interest benefit (expense) related to unrecognized tax benefits	3	(1)	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		12 Months Ended
		Dec. 31, 2023	Dec. 31, 2022		Dec. 31, 2021
Income Tax [Line Items]
Federal NOL carryforward		$ 0	$ 20
Tax Credit Carryforward, Amount		1,644	1,593
State NOL carryforwards		11	1,022
Valuation allowances for state NOL carryforwards		(2)	(3)
state tax credit carryforward, net of federal detirment	[1]	74	85
valuation allowances for state credit carryforwards, net of federal benefit	[2]	(60)	(62)
Federal detriment		$ 20	$ 23
Federal statutory rate		21%	21%		21%
State income tax on pretax income, net of federal tax effect		4.90%	4.90%		5%
Effective Income Tax Rate Reconciliation, Tax Credit, Percent	[3]	(28.10%)	(27.40%)		(23.40%)
Effective Income Tax Rate Reconciliation, Other Regulatory Items, Percent	[4]	(5.60%)	(5.50%)		(6.20%)
Other tax credits, net NOL & tax credit allowances		(1.30%)	(1.30%)		(1.10%)
Other, net		0.10%	(0.10%)		0.10%
Effective income tax rate		(9.00%)	(8.40%)		(4.60%)
Total income tax benefit		$ (146)	$ (135)		$ (70)
Deferred tax expense (benefit) excluding items below		129	(138)		148
Amortization and adjustments to deferred income taxes on income tax regulatory assets and liabilities		(188)	8		(221)
Income Tax Expense (Benefit), Intraperiod Tax Allocation		0	(10)		(6)
Deferred tax benefit		(249)	(140)		(79)
Regulatory liabilities		1,264
Tax Credit Carryforward, Valuation Allowance		(10)	0
Adjustments to deferred income taxes for wind production tax credit cash transfers	[5]	(190)	0		0
State and Local Jurisdiction [Member]
Income Tax [Line Items]
Federal Benefit			16
income tax expense
Income Tax [Line Items]
Current federal tax expense		113	1		15
Current state tax expense (benefit)		16	3		(2)
Current change in unrecognized tax (benefit) expense		(21)	5		1
Deferred federal tax benefit		(331)	(239)		(183)
Deferred state tax expense		75	96		99
Deferred change in unrecognized tax expense		7	3		5
Deferred ITCs		(5)	(4)		(5)
Total income tax benefit		(146)	(135)		$ (70)
Net Deferred Tax Liablility [Member]
Income Tax [Line Items]
Tax Credit Carryforward, Amount		1,718	1,679	[6]
Differences between book and tax bases of property		6,744	6,442	[6]
Operating Lease Assets		327	325	[6]
Regulatory Asset		538	484	[6]
Deferred fuel costs		67	222	[6]
Deferred tax liability - Pension expense		151	159	[6]
Other		84	90	[6]
Total deferred tax liabilities		7,911	7,722	[6]
Regulatory Liability		730	718	[6]
Operating Loss Carryforwards		0	57	[6]
Tax Credit Carryforward, Valuation Allowance		(70)	(62)	[6]
other employee benefits		117	102	[6]
Other		188	133	[6]
Total deferred tax assets		3,026	2,966	[6]
Net deferred tax liability		4,885	4,756	[6]
Operating lease liabilities		327	325	[6]
Deferred investment tax credits		$ 16	$ 14	[6]
[1] State tax credit carryforwards are net of federal detriment of $20 million and $23 million as of Dec. 31, 2023 and 2022, respectively. Valuation allowances for state tax credit carryforwards were net of federal benefit of $16 million as of Dec. 31, 2023 and 2022. Wind PTCs net of estimated transfer discount are credited to customers (reduction to revenue) and do not materially impact net income. Proceeds from tax credit transfers are included in cash received (paid) for income taxes in the consolidated statement of cash flows.

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, 2023	Dec. 31, 2022	Dec. 31, 2021
Equity Instruments Other than Options Activity [Roll Forward]
Balance at January 1 (in shares)	708
Granted (in shares)	586	395	421
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Forfeited in Period (in shares)	(184)
Vested (in shares)	(329)	(319)	(392)
Dividend equivalents (in shares)	38
Balance at December 31 (in shares)	819	708
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)	$ 67.35
Granted, weighted average grant date fair value (in dollars per share)	67.06	$ 68.43	$ 66.03
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)	$ 68.42
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Fair Value	$ 20	$ 22	$ 27
Vested, weighted average grant date fair value (in dollars per share)	$ 66.23
Dividend equivalents, weighted average grant date fair value (in dollars per share)	67.65
Balance at December 31, weighted average grant date fair value (in dollars per share)	$ 67.36	$ 67.35
Service-based awards [Member]
Equity Instruments Other than Options Activity [Roll Forward]
Granted (in shares)	400	200	200

Share-Based Compensation Restri

Share-Based Compensation Restricted Stock (Details) - USD ($) shares in Thousands, $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Granted (in shares)	586	395	421
Compensation costs for share-based payments included in O&M	$ 25

Other Equity Awards (Details)

Other Equity Awards (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Equity Instruments Other than Options Activity [Roll Forward]
Balance at January 1 (in shares)	708
Granted (in shares)	586	395	421
Forfeited (in shares)	(184)
Vested (in shares)	(329)	(319)	(392)
Dividend equivalents (in shares)	38
Balance at December 31 (in shares)	819	708
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)	$ 67.35
Granted, weighted average grant date fair value (in dollars per share)	67.06	$ 68.43	$ 66.03
Forfeited, weighted average grant date fair value (in dollars per share)	68.42
Vested, weighted average grant date fair value (in dollars per share)	66.23
Dividend equivalents, weighted average grant date fair value (in dollars per share)	67.65
Balance at December 31, weighted average grant date fair value (in dollars per share)	$ 67.36	$ 67.35
Equity Instruments Other than Options, Additional Disclosures [Abstract]
Total fair value of equity awards vested during the period	$ 20	$ 22	$ 27
Performance-based awards [Member]
Equity Instruments Other than Options, Additional Disclosures [Abstract]
Award Vesting Period (in years)	3 years
Service-based awards [Member]
Equity Instruments Other than Options Activity [Roll Forward]
Granted (in shares)	400	200	200
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%
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%

Stock Equivalent Units (Details

Stock Equivalent Units (Details) - $ / shares	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Equity Instruments Other than Options Activity [Roll Forward]
Balance at January 1 (in shares)	708,000
Granted (in shares)	586,000	395,000	421,000
Dividend equivalents (in shares)	38,000
Balance at December 31 (in shares)	819,000	708,000
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)	$ 67.35
Granted, weighted average grant date fair value (in dollars per share)	67.06	$ 68.43	$ 66.03
Dividend equivalents, weighted average grant date fair value (in dollars per share)	67.65
Balance at December 31, weighted average grant date fair value (in dollars per share)	$ 67.36	$ 67.35
Stock Equivalent Units [Member]
Equity Instruments Other than Options Activity [Roll Forward]
Balance at January 1 (in shares)	597,000
Granted (in shares)	38,000	29,000	31,000
Units distributed (in shares)	(134,000)
Dividend equivalents (in shares)	16,000
Balance at December 31 (in shares)	517,000	597,000
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)	$ 41.75
Granted, weighted average grant date fair value (in dollars per share)	63.12	$ 71.97	$ 68.15
Units distributed, weighted average grant date fair value (in dollars per share)	33.90
Dividend equivalents, weighted average grant date fair value (in dollars per share)	64.95
Balance at December 31, weighted average grant date fair value (in dollars per share)	$ 46.07	$ 41.75
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, 2023	Dec. 31, 2022	Dec. 31, 2021
Equity Instruments Other than Options Activity [Roll Forward]
Granted (in shares)	586	395	421
TSR Liability Awards
Equity Instruments Other than Options Activity [Roll Forward]
Granted (in shares)	216	165	221
Equity Instruments Other than Options, Additional Disclosures [Abstract]
Award Vesting Period (in years)	3 years
Awards settled (in shares)	282	411	446
Settlement amount (cash and common stock)	$ 19	$ 27	$ 27
Amount of cash used to settle TSR liability awards	$ 13
TSR Liability Awards | Minimum
Equity Instruments Other than Options, Additional Disclosures [Abstract]
Percentage payout for TSR liability awards	0%
TSR Liability Awards | Maximum
Equity Instruments Other than Options, Additional Disclosures [Abstract]
Percentage payout for TSR liability awards	200%

Share-Based Compensation Expens

Share-Based Compensation Expense (Details) - USD ($) shares in Thousands, $ in Millions		12 Months Ended
		Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Share-Based Compensation Expense [Abstract]
Granted (in shares)		586	395	421
Compensation cost for share-based awards	[1]	$ 27	$ 36	$ 31
Tax benefit recognized in income		7	9	$ 8
Unrecognized compensation cost related to nonvested share-based compensation awards		$ 38	$ 37
Weighted-average period for recognition of unrecognized compensation cost related to nonvested share-based compensation awards (in years)		1 year 8 months 12 days
Compensation Related Costs [Abstract]
Compensation costs for share-based payments included in O&M		$ 25
Service-based awards [Member]
Share-Based Compensation Expense [Abstract]
Granted (in shares)		400	200	200
[1] Compensation costs for share-based payments are included in O&M expense. Amount for equity awards (non-cash) was $25 million in 2023.

Share-Based Compensation Share-

Share-Based Compensation Share-Based Compensation Phantom (Details) - $ / shares shares in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Granted (in shares)	586	395	421
Granted, weighted average grant date fair value (in dollars per share)	$ 67.06	$ 68.43	$ 66.03
Service-based awards [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Granted (in shares)	400	200	200

Common Stock Equivalent (Detail

Common Stock Equivalent (Details) - shares shares in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Earnings Per Share [Abstract]
Weighted Average Number of Shares Outstanding, Basic	552,000	547,000	539,000
Diluted	552,000	547,000	540,000
Dilutive Effect of Contingently Issuable Shares	300	300	300

Nuclear Decommissioning Fund (D

Nuclear Decommissioning Fund (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023		Dec. 31, 2022
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Debt Securities, Available-for-Sale, Unrealized Gain	$ 1,200		$ 1,000
Debt Securities, Available-for-Sale, Unrealized Loss	29		90
Equity investments in unconsolidated subsidiaries	244		219
Miscellaneous investments	144		133
Final Contractual Maturity [Abstract]
Due in 1 Year or Less	4
Due in 1 to 5 Years	261
Due in 5 to 10 Years	269
Due after 10 Years	246
Total	780
Fair Value Measured on a Recurring Basis | Cost
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Decommissioning fund investments	2,054	[1]	1,976	[2]
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	41	[1]	29	[2]
Fair Value Measured on a Recurring Basis | Cost | Commingled Funds
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments, Fair Value Disclosure	721	[1]	803	[2]
Fair Value Measured on a Recurring Basis | Cost | Debt Securities
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Debt Securities, Available-for-Sale, Excluding Accrued Interest	784	[1]	738	[2]
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, FV-NI, Current	508	[1]	406	[2]
Fair Value Measured on a Recurring Basis | Fair Value
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Alternative Investment	1,049	[1]	1,178	[2]
Decommissioning fund investments	3,211		2,882
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	41	[1]	29	[2]
Alternative Investment	0	[1]	0	[2]
Fair Value Measured on a Recurring Basis | Fair Value | Commingled Funds
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Alternative Investment	1,049	[1]	1,178	[2]
Investments, Fair Value Disclosure	1,049	[1]	1,178	[2]
Fair Value Measured on a Recurring Basis | Fair Value | Debt Securities
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Alternative Investment	0	[1]	0	[2]
Debt Securities, Available-for-Sale, Excluding Accrued Interest	780	[1]	675	[2]
Fair Value Measured on a Recurring Basis | Fair Value | Equity Securities
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Alternative Investment	0	[1]	0	[2]
Equity Securities, FV-NI, Current	1,341	[1]	1,000	[2]
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	1,380	[1]	1,028	[2]
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	41	[1]	29	[2]
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]
Investments, Fair Value Disclosure	0	[1]	0	[2]
Fair Value Measured on a Recurring Basis | Fair Value | Level 1 | Debt Securities
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Debt Securities, Available-for-Sale, Excluding Accrued Interest	0	[1]	0	[2]
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, FV-NI, Current	1,339	[1]	999	[2]
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	773	[1]	670	[2]
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]
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]
Investments, Fair Value Disclosure	0	[1]	0	[2]
Fair Value Measured on a Recurring Basis | Fair Value | Level 2 | Debt Securities
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Debt Securities, Available-for-Sale, Excluding Accrued Interest	771	[1]	669	[2]
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, FV-NI, Current	2	[1]	1	[2]
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]	6	[2]
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]
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]
Investments, Fair Value Disclosure	0	[1]	0	[2]
Fair Value Measured on a Recurring Basis | Fair Value | Level 3 | Debt Securities
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Debt Securities, Available-for-Sale, Excluding Accrued Interest	9	[1]	6	[2]
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, FV-NI, Current	$ 0	[1]	$ 0	[2]
[1] Reported in nuclear decommissioning fund and other investments on the consolidated balance sheets, which also includes $244 million of equity method investments and $144 million of rabbi trust assets and other miscellaneous investments. Reported in nuclear decommissioning fund and other investments on the consolidated balance sheets, which also includes $219 million of equity investments in unconsolidated subsidiaries and $133 million of rabbi trust assets and other miscellaneous investments.

Rabbi Trusts (Details)

Rabbi Trusts (Details) - Fair Value Measured on a Recurring Basis - USD ($) $ in Millions	Dec. 31, 2023		Dec. 31, 2022
Cost | Cash equivalents
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash Equivalents	$ 41	[1]	$ 29	[2]
Fair Value
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total	88		80
Fair Value | Cash equivalents
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash Equivalents	41	[1]	29	[2]
Fair Value | Level 1 | Cash equivalents
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash Equivalents	41	[1]	29	[2]
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]
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]
[1] Reported in nuclear decommissioning fund and other investments on the consolidated balance sheets, which also includes $244 million of equity method investments and $144 million of rabbi trust assets and other miscellaneous investments. Reported in nuclear decommissioning fund and other investments on the consolidated balance sheets, which also includes $219 million of equity investments in unconsolidated subsidiaries and $133 million of rabbi trust assets and other miscellaneous investments.

Interest Rate Derivatives (Deta

Interest Rate Derivatives (Details) - Interest Rate Swap $ in Millions	Dec. 31, 2023 USD ($)
Interest Rate Derivatives [Abstract]
Interest rate cash low hedge gain (loss) to be reclassified during the next 12 months	$ 2
Derivative Liability, Notional Amount	$ 420

Commodity Derivatives (Details)

Commodity Derivatives (Details) MWh in Millions, MMBTU in Millions, $ in Millions		Dec. 31, 2023 USD ($) MWh MMBTU	Dec. 31, 2022 USD ($) MWh MMBTU
Derivative [Line Items]
Reclaim Cash Collateral		$ 7	$ 53
Cash Flow Hedges
Derivative [Line Items]
Commodity contracts designated as cash flow hedges		$ 0
Electric Commodity
Derivative [Line Items]
Notional Amount | MWh	[1],[2]	48	61
Natural Gas Commodity
Derivative [Line Items]
Notional Amount | MMBTU	[1],[2]	84	131
[1] Not reflective of net positions in the underlying commodities. 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, 2023 USD ($) 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	4
Credit exposure for the most significant counterparties | $	$ 49
Percentage of credit exposure for the most significant counterparties	23%
Internal Investment Grade
Derivative [Line Items]
Number of most significant counterparties	5
Credit exposure for the most significant counterparties | $	$ 78
Percentage of credit exposure for the most significant counterparties	37%
External Credit Rating, Non Investment Grade [Member]
Derivative [Line Items]
Number of most significant counterparties	1
Credit exposure for the most significant counterparties | $	$ 45
Percentage of credit exposure for the most significant counterparties	21%

Qualifying Cash Flow Hedges (De

Qualifying Cash Flow Hedges (Details) - USD ($)		12 Months Ended
		Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
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		(150,000,000)	(26,000,000)	28,000,000
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)		138,000,000	(13,000,000)	18,000,000
Derivative, Gain (Loss) on Derivative, Net		(34,000,000)	(2,000,000)	41,000,000
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]	(7,000,000)	25,000,000	63,000,000
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		(137,000,000)	(10,000,000)	32,000,000
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]	(123,000,000)	(3,000,000)	23,000,000
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		(13,000,000)	(16,000,000)	(4,000,000)
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]	15,000,000	10,000,000	(5,000,000)
Derivative, Gain (Loss) on Derivative, Net	[3],[4]	(27,000,000)	(27,000,000)	(22,000,000)
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		(2,000,000)	22,000,000	5,000,000
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		(5,000,000)	(7,000,000)	(8,000,000)
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		(2,000,000)	22,000,000	5,000,000
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	[5]	(5,000,000)	(7,000,000)	(8,000,000)
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 revenues. Presented amounts do not reflect non-derivative transactions or margin sharing with customers. 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. FTR settlements are shared with customers and do not have a material impact on net income. Presented amounts reflect changes in fair value between FTR auction and settlement dates, but exclude the original auction fair value. 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. Recorded to interest charges.

Credit Related Contingent Featu

Credit Related Contingent Features (Details) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Fair Value Disclosures [Abstract]
Derivative instruments in a gross liability position	$ 12	$ 4
Derivative, Gross Liability with Cross Default Position, Aggregate Fair Value	88	76
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, 2023	Dec. 31, 2022	Dec. 31, 2021
Derivatives, Fair Value [Line Items]
Derivative Asset, Net		$ 104	$ 279
Derivative Asset, Current, Statement of Financial Position [Extensible Enumeration]		Assets, Current	Assets, Current
Derivative Asset, Noncurrent		$ 76	$ 93
Derivative Liability, Net		$ 86	$ 113
Derivative Liability, Noncurrent, Statement of Financial Position [Extensible Enumeration]		Total deferred credits and other liabilities	Total deferred credits and other liabilities
Return Cash Collateral		$ 0	$ 0
Derivative Liability, Noncurrent		74	76
Reclaim Cash Collateral		$ 7	$ 53
Changes in Level 3 Commodity Derivatives
Derivative Asset, Noncurrent, Statement of Financial Position [Extensible Enumeration]		Other assets	Other assets
Derivative Liability, Current, Statement of Financial Position [Extensible Enumeration]		Total current liabilities	Total current liabilities
Commodity Contract
Changes in Level 3 Commodity Derivatives
Balance at Jan. 1		$ 236	$ 19	$ (49)
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Inputs Reconciliation, Purchases	[1]	176	406	65
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Inputs Reconciliation, Settlements	[1]	(154)	(350)	(158)
(Losses) gains recognized in earnings	[2]	6	151	49
Fair Value Measurement With Unobservable Inputs Reconciliation Recurring Basis Asset Liability Net Losses Gains Recognized As Regulatory Assets And Liabilities	[1]	(174)	10	112
Balance at Dec. 31		90	236	$ 19
Fair Value Measured on a Recurring Basis
Derivatives, Fair Value [Line Items]
Derivative Asset, Net		101	276
Derivative Asset, Noncurrent		76	90
Derivative Liability, Net		64	83
Derivative Liability, Noncurrent		66	59
Fair Value Measured on a Recurring Basis | Other Derivative Instruments | Commodity Contract
Derivatives, Fair Value [Line Items]
Derivative Asset, Net		32	82
Derivative Asset, Noncurrent		76	90
Derivative Liability, Net		64	83
Derivative Liability, Noncurrent		37	45
Fair Value Measured on a Recurring Basis | Other Derivative Instruments | Electric Commodity
Derivatives, Fair Value [Line Items]
Derivative Asset, Gross		62	177
Netting	[3]	(7)	(2)
Derivative Asset, Net		55	175
Derivative Liability, Gross		7	2
Netting	[3]	(7)	(2)
Derivative Liability, Noncurrent		0	0
Fair Value Measured on a Recurring Basis | Other Derivative Instruments | Electric Commodity | Level 1
Derivatives, Fair Value [Line Items]
Derivative Asset, Gross		0	0
Derivative Liability, Gross		0	0
Fair Value Measured on a Recurring Basis | Other Derivative Instruments | Electric Commodity | Level 2
Derivatives, Fair Value [Line Items]
Derivative Asset, Gross		0	0
Derivative Liability, Gross		0	0
Fair Value Measured on a Recurring Basis | Other Derivative Instruments | Electric Commodity | Level 3
Derivatives, Fair Value [Line Items]
Derivative Asset, Gross		62	177
Derivative Liability, Gross		7	2
Fair Value Measured on a Recurring Basis | Other Derivative Instruments | Natural Gas Commodity
Derivatives, Fair Value [Line Items]
Derivative Asset, Gross		14	19
Netting	[3]	0	0
Derivative Asset, Net		14	19
Derivative Liability, Gross		12	13
Netting	[3]	0	0
Derivative Liability, Noncurrent		12	13
Fair Value Measured on a Recurring Basis | Other Derivative Instruments | Natural Gas Commodity | Level 1
Derivatives, Fair Value [Line Items]
Derivative Asset, Gross		0	0
Derivative Liability, Gross		0	0
Fair Value Measured on a Recurring Basis | Other Derivative Instruments | Natural Gas Commodity | Level 2
Derivatives, Fair Value [Line Items]
Derivative Asset, Gross		14	19
Derivative Liability, Gross		12	13
Fair Value Measured on a Recurring Basis | Other Derivative Instruments | Natural Gas Commodity | Level 3
Derivatives, Fair Value [Line Items]
Derivative Asset, Gross		0	0
Derivative Liability, Gross		0	0
Fair Value Measured on a Recurring Basis | Designated as Hedging Instrument | Interest Rate Swap | Cash Flow Hedges
Derivatives, Fair Value [Line Items]
Derivative Liability, Noncurrent		17	1
Fair Value Measured on a Recurring Basis | Other Current Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Gross		167	520
Netting	[3]	(66)	(244)
Fair Value Measured on a Recurring Basis | Other Current Assets | Level 1
Derivatives, Fair Value [Line Items]
Derivative Asset, Gross		8	32
Fair Value Measured on a Recurring Basis | Other Current Assets | Level 2
Derivatives, Fair Value [Line Items]
Derivative Asset, Gross		65	278
Fair Value Measured on a Recurring Basis | Other Current Assets | Level 3
Derivatives, Fair Value [Line Items]
Derivative Asset, Gross		94	210
Fair Value Measured on a Recurring Basis | Other Current Assets | Other Derivative Instruments | Commodity Contract
Derivatives, Fair Value [Line Items]
Derivative Asset, Gross		91	324
Netting	[3]	(59)	(242)
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		8	32
Fair Value Measured on a Recurring Basis | Other Current Assets | Other Derivative Instruments | Commodity Contract | Level 2
Derivatives, Fair Value [Line Items]
Derivative Asset, Gross		51	259
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		32	33
Fair Value Measured on a Recurring Basis | Other Noncurrent Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Gross		110	179
Netting	[3]	(34)	(89)
Fair Value Measured on a Recurring Basis | Other Noncurrent Assets | Level 1
Derivatives, Fair Value [Line Items]
Derivative Asset, Gross		14	34
Fair Value Measured on a Recurring Basis | Other Noncurrent Assets | Level 2
Derivatives, Fair Value [Line Items]
Derivative Asset, Gross		51	71
Fair Value Measured on a Recurring Basis | Other Noncurrent Assets | Level 3
Derivatives, Fair Value [Line Items]
Derivative Asset, Gross		45	74
Fair Value Measured on a Recurring Basis | Other Noncurrent Assets | Other Derivative Instruments | Commodity Contract
Derivatives, Fair Value [Line Items]
Derivative Asset, Gross		110	179
Netting	[3]	(34)	(89)
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		14	34
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		51	71
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		45	74
Fair Value Measured on a Recurring Basis | Other Current Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Gross		133	348
Netting	[3]	(67)	(289)
Fair Value Measured on a Recurring Basis | Other Current Liabilities | Level 1
Derivatives, Fair Value [Line Items]
Derivative Liability, Gross		6	29
Fair Value Measured on a Recurring Basis | Other Current Liabilities | Level 2
Derivatives, Fair Value [Line Items]
Derivative Liability, Gross		115	311
Fair Value Measured on a Recurring Basis | Other Current Liabilities | Level 3
Derivatives, Fair Value [Line Items]
Derivative Liability, Gross		12	8
Fair Value Measured on a Recurring Basis | Other Current Liabilities | Other Derivative Instruments | Commodity Contract
Derivatives, Fair Value [Line Items]
Derivative Liability, Gross		97	332
Netting	[3]	(60)	(287)
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		6	29
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		86	297
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		5	6
Fair Value Measured on a Recurring Basis | Other Current Liabilities | Designated as Hedging Instrument | Interest Rate Swap
Derivatives, Fair Value [Line Items]
Netting	[3]	0	0
Fair Value Measured on a Recurring Basis | Other Current Liabilities | Designated as Hedging Instrument | Interest Rate Swap | Cash Flow Hedges
Derivatives, Fair Value [Line Items]
Derivative Liability, Gross		17	1
Fair Value Measured on a Recurring Basis | Other Current Liabilities | Designated as Hedging Instrument | Interest Rate Swap | Level 1 | Cash Flow Hedges
Derivatives, Fair Value [Line Items]
Derivative Liability, Gross		0	0
Fair Value Measured on a Recurring Basis | Other Current Liabilities | Designated as Hedging Instrument | Interest Rate Swap | Level 2 | Cash Flow Hedges
Derivatives, Fair Value [Line Items]
Derivative Liability, Gross		17	1
Fair Value Measured on a Recurring Basis | Other Current Liabilities | Designated as Hedging Instrument | Interest Rate Swap | Level 3 | Cash Flow Hedges
Derivatives, Fair Value [Line Items]
Derivative Liability, Gross		0	0
Fair Value Measured on a Recurring Basis | Other Noncurrent Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Gross		103	181
Netting	[3]	(39)	(98)
Fair Value Measured on a Recurring Basis | Other Noncurrent Liabilities | Level 1
Derivatives, Fair Value [Line Items]
Derivative Liability, Gross		16	43
Fair Value Measured on a Recurring Basis | Other Noncurrent Liabilities | Level 2
Derivatives, Fair Value [Line Items]
Derivative Liability, Gross		50	97
Fair Value Measured on a Recurring Basis | Other Noncurrent Liabilities | Level 3
Derivatives, Fair Value [Line Items]
Derivative Liability, Gross		37	41
Fair Value Measured on a Recurring Basis | Other Noncurrent Liabilities | Other Derivative Instruments | Commodity Contract
Derivatives, Fair Value [Line Items]
Derivative Liability, Gross		103	181
Netting	[3]	(39)	(98)
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		16	43
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		50	97
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		37	41
Fair Value, Measurements, Nonrecurring | Purchased Power Agreements
Derivatives, Fair Value [Line Items]
Derivative Asset, Net	[4]	3	3
Derivative Asset, Noncurrent	[4]	0	3
Derivative Liability, Net	[4]	22	30
Derivative Liability, Noncurrent	[4]	$ 8	$ 17
[1] Relates primarily to NSP-Minnesota and SPS FTR instruments administered by MISO and SPP. Relates to commodity trading and is subject to substantial offsetting losses and gains on derivative instruments categorized as levels 1 and 2 in the income statement. See above tables for the income statement impact of derivative activity, including commodity trading gains and losses. Xcel Energy nets derivative instruments and related collateral on its consolidated balance sheets when supported by a legally enforceable master netting agreement. At Dec. 31, 2023 and 2022, derivative assets and liabilities include no obligations to return cash collateral. At Dec. 31, 2023 and 2022, derivative assets and liabilities include rights to reclaim cash collateral of $7 million and $53 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. Xcel Energy currently applies the normal purchase exception to qualifying PPAs. Balance relates to specific contracts that were previously recognized at fair value prior to applying the normal purchase exception, and are 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, 2023	Dec. 31, 2022
Financial Liabilities, Balance Sheet Groupings [Abstract]
Long-term Debt, Carrying Amount	$ 25,465	$ 23,964
Long-term debt, Fair Value	$ 22,927	$ 20,897

Pension and Postretirement Heal

Pension and Postretirement Health Care Benefits (Details) $ in Millions		12 Months Ended
		Dec. 31, 2024	Dec. 31, 2023 USD ($)		Dec. 31, 2022 USD ($)		Dec. 31, 2021 USD ($)
Pension Benefits [Abstract]
annual interest crediting rates			4.72		4.89		2.03
Target Pension Asset Allocations [Abstract]
transferred			$ 0		$ 0
Supplemental Executive Retirement Plan (SERP) and Nonqualified Pension Plan
Pension Benefits [Abstract]
Total benefit obligation			12		11
Net benefit cost recognized for financial reporting			2		17
Pension Plan [Member]
Pension Benefits [Abstract]
Total benefit obligation			2,943		2,871		$ 3,718
Defined Benefit Plan, Plan Assets, Amount			2,690	[1]	2,685	[1]	3,670
Net benefit cost recognized for financial reporting			$ 74		$ 114		$ 121
Expected average long-term rate of return on assets (as a percent)			6.93%		6.49%		6.49%
Target Pension Asset Allocations [Abstract]
Target pension asset allocations (as a percent)			100%		100%
Pension Plan [Member] | Level 1
Pension Benefits [Abstract]
Defined Benefit Plan, Plan Assets, Amount	[1]		$ 759		$ 1,111
Pension Plan [Member] | Level 2
Pension Benefits [Abstract]
Defined Benefit Plan, Plan Assets, Amount	[1]		692		689
Pension Plan [Member] | Level 3
Pension Benefits [Abstract]
Defined Benefit Plan, Plan Assets, Amount	[1]		4		3
Pension Plan [Member] | Fair Value Measured at Net Asset Value Per Share
Pension Benefits [Abstract]
Defined Benefit Plan, Plan Assets, Amount	[1]		1,235		882
Pension Plan [Member] | Cash
Pension Benefits [Abstract]
Defined Benefit Plan, Plan Assets, Amount	[1]		$ 233		$ 129
Target Pension Asset Allocations [Abstract]
Target pension asset allocations (as a percent)			2%		2%
Pension Plan [Member] | Cash | Level 1
Pension Benefits [Abstract]
Defined Benefit Plan, Plan Assets, Amount	[1]		$ 233		$ 129
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] | Cash | Fair Value Measured at Net Asset Value Per Share
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]		1,726		1,817
Pension Plan [Member] | Commingled Funds | Level 1
Pension Benefits [Abstract]
Defined Benefit Plan, Plan Assets, Amount	[1]		491		935
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] | Commingled Funds | Fair Value Measured at Net Asset Value Per Share
Pension Benefits [Abstract]
Defined Benefit Plan, Plan Assets, Amount	[1]		1,235		882
Pension Plan [Member] | Debt Securities
Pension Benefits [Abstract]
Defined Benefit Plan, Plan Assets, Amount	[1]		687		685
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]		683		682
Pension Plan [Member] | Debt Securities | Level 3
Pension Benefits [Abstract]
Defined Benefit Plan, Plan Assets, Amount	[1]		4		3
Pension Plan [Member] | Debt Securities | Fair Value Measured at Net Asset Value Per Share
Pension Benefits [Abstract]
Defined Benefit Plan, Plan Assets, Amount	[1]		0		0
Pension Plan [Member] | Equity Securities
Pension Benefits [Abstract]
Defined Benefit Plan, Plan Assets, Amount	[1]		$ 35		$ 47
Target Pension Asset Allocations [Abstract]
Target pension asset allocations (as a percent)			31%		33%
Pension Plan [Member] | Equity Securities | Level 1
Pension Benefits [Abstract]
Defined Benefit Plan, Plan Assets, Amount	[1]		$ 35		$ 47
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] | Equity Securities | Fair Value Measured at Net Asset Value Per Share
Pension Benefits [Abstract]
Defined Benefit Plan, Plan Assets, Amount	[1]		0		0
Pension Plan [Member] | Other
Pension Benefits [Abstract]
Defined Benefit Plan, Plan Assets, Amount	[1]		9		7
Pension Plan [Member] | Other | Level 1
Pension Benefits [Abstract]
Defined Benefit Plan, Plan Assets, Amount	[1]		0		0
Pension Plan [Member] | Other | Level 2
Pension Benefits [Abstract]
Defined Benefit Plan, Plan Assets, Amount	[1]		9		7
Pension Plan [Member] | Other | Level 3
Pension Benefits [Abstract]
Defined Benefit Plan, Plan Assets, Amount	[1]		0		0
Pension Plan [Member] | Other | Fair Value Measured at Net Asset Value Per Share
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)			38%		38%
Pension Plan [Member] | Alternative investments
Target Pension Asset Allocations [Abstract]
Target pension asset allocations (as a percent)			20%		18%
Pension Plan [Member] | Short-to-intermediate fixed income securities
Target Pension Asset Allocations [Abstract]
Target pension asset allocations (as a percent)			9%		9%
Other Postretirement Benefits Plan [Member]
Pension Benefits [Abstract]
Total benefit obligation			$ 394		$ 405		$ 511
Defined Benefit Plan, Plan Assets, Amount			356	[2]	364	[2]	442
Net benefit cost recognized for financial reporting			$ 6		$ (2)		$ (2)
Expected average long-term rate of return on assets (as a percent)			5%		4.10%		4.10%
Target Pension Asset Allocations [Abstract]
Target pension asset allocations (as a percent)			100%		100%
Other Postretirement Benefits Plan [Member] | Level 1
Pension Benefits [Abstract]
Defined Benefit Plan, Plan Assets, Amount	[2]		$ 55		$ 85
Other Postretirement Benefits Plan [Member] | Level 2
Pension Benefits [Abstract]
Defined Benefit Plan, Plan Assets, Amount	[2]		228		215
Other Postretirement Benefits Plan [Member] | Level 3
Pension Benefits [Abstract]
Defined Benefit Plan, Plan Assets, Amount	[2]		1		1
Other Postretirement Benefits Plan [Member] | Fair Value Measured at Net Asset Value Per Share
Pension Benefits [Abstract]
Defined Benefit Plan, Plan Assets, Amount	[2]		72		63
Other Postretirement Benefits Plan [Member] | Cash
Pension Benefits [Abstract]
Defined Benefit Plan, Plan Assets, Amount	[2]		$ 33		$ 31
Target Pension Asset Allocations [Abstract]
Target pension asset allocations (as a percent)			1%		1%
Other Postretirement Benefits Plan [Member] | Cash | Level 1
Pension Benefits [Abstract]
Defined Benefit Plan, Plan Assets, Amount	[2]		$ 33		$ 31
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] | Cash | Fair Value Measured at Net Asset Value Per Share
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]		94		117
Other Postretirement Benefits Plan [Member] | Commingled Funds | Level 1
Pension Benefits [Abstract]
Defined Benefit Plan, Plan Assets, Amount	[2]		22		54
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] | Commingled Funds | Fair Value Measured at Net Asset Value Per Share
Pension Benefits [Abstract]
Defined Benefit Plan, Plan Assets, Amount	[2]		72		63
Other Postretirement Benefits Plan [Member] | Debt Securities
Pension Benefits [Abstract]
Defined Benefit Plan, Plan Assets, Amount	[2]		188		176
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]		187		175
Other Postretirement Benefits Plan [Member] | Debt Securities | Level 3
Pension Benefits [Abstract]
Defined Benefit Plan, Plan Assets, Amount	[2]		1		1
Other Postretirement Benefits Plan [Member] | Debt Securities | Fair Value Measured at Net Asset Value Per Share
Pension Benefits [Abstract]
Defined Benefit Plan, Plan Assets, Amount	[2]		$ 0		$ 0
Other Postretirement Benefits Plan [Member] | Equity Securities
Target Pension Asset Allocations [Abstract]
Target pension asset allocations (as a percent)			9%		16%
Other Postretirement Benefits Plan [Member] | Other
Pension Benefits [Abstract]
Defined Benefit Plan, Plan Assets, Amount	[2]		$ 1		$ (1)
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]		1		(1)
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] | Other | Fair Value Measured at Net Asset Value Per Share
Pension Benefits [Abstract]
Defined Benefit Plan, Plan Assets, Amount	[2]		$ 0		$ 0
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%		0%
Other Postretirement Benefits Plan [Member] | Alternative investments
Target Pension Asset Allocations [Abstract]
Target pension asset allocations (as a percent)			13%		12%
Other Postretirement Benefits Plan [Member] | Short-to-intermediate fixed income securities
Target Pension Asset Allocations [Abstract]
Target pension asset allocations (as a percent)			77%		71%
Other Postretirement Benefits Plan [Member] | Insurance contracts
Pension Benefits [Abstract]
Defined Benefit Plan, Plan Assets, Amount	[2]		$ 40		$ 41
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]		40		41
Other Postretirement Benefits Plan [Member] | Insurance contracts | Level 3
Pension Benefits [Abstract]
Defined Benefit Plan, Plan Assets, Amount	[2]		0		0
Other Postretirement Benefits Plan [Member] | Insurance contracts | Fair Value Measured at Net Asset Value Per Share
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)		6.93%
[1] See Note 10 for further information regarding fair value measurement inputs and methods. 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, 2023		Dec. 31, 2022		Dec. 31, 2021
Change in Fair Value of Plan Assets [Roll Forward]
Defined Benefit Plan, Plan Assets, Payment for Settlement				$ 195,000,000
Components of Net Periodic Benefit Cost (Credit) [Abstract]
Settlement Charge Recognized in Operating and Maintenance Expenses		$ 2,444,000,000		2,491,000,000		$ 2,321,000,000
Significant Assumptions Used to Measure Costs [Abstract]
transferred		0		0
Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Accumulated Benefit Obligation at Dec. 31		2,728,000,000		2,672,000,000
Change in Projected Benefit Obligation [Roll Forward]
Obligation at Jan. 1		2,871,000,000		3,718,000,000
Service cost		74,000,000		97,000,000		104,000,000
Interest cost		158,000,000		110,000,000		104,000,000
Plan amendments		(3,000,000)		1,000,000
Actuarial loss		126,000,000		(703,000,000)
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]	(283,000,000)		(352,000,000)
Obligation at Dec. 31		2,943,000,000		2,871,000,000		3,718,000,000
Change in Fair Value of Plan Assets [Roll Forward]
Fair value of plan assets at Jan. 1		2,685,000,000	[2]	3,670,000,000
Actual return (loss) on plan assets		238,000,000		(683,000,000)
Employer contributions		50,000,000		50,000,000
Benefit payments		(283,000,000)		(352,000,000)
Fair value of plan assets at Dec. 31		2,690,000,000	[2]	2,685,000,000	[2]	3,670,000,000
Funded Status of Plans at Dec. 31 [Abstract]
Funded status		(253,000,000)		(186,000,000)
Assets for Plan Benefits, Defined Benefit Plan		1,000,000		15,000,000
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost [Abstract]
Net loss		1,096,000,000		1,021,000,000
Prior service (credit) cost		(9,000,000)		(7,000,000)
Total		1,087,000,000		1,014,000,000
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		20,000,000		21,000,000
Noncurrent regulatory assets		1,014,000,000		943,000,000
Deferred income taxes		14,000,000		14,000,000
Net-of-tax accumulated other comprehensive income		39,000,000		36,000,000
Total		$ 1,087,000,000		$ 1,014,000,000
Significant Assumptions Used to Measure Benefit Obligations [Abstract]
Discount rate for year-end valuation (as a percent)		5.49%		5.80%
Expected average long-term increase in compensation level (as a percent)		4.25%		4.25%
Components of Net Periodic Benefit Cost (Credit) [Abstract]
Service cost		$ 74,000,000		$ 97,000,000		104,000,000
Interest cost		158,000,000		110,000,000		104,000,000
Expected return on plan assets		(209,000,000)		(208,000,000)		(206,000,000)
Amortization of prior service cost (credit)		(1,000,000)		(1,000,000)		(1,000,000)
Amortization of net loss		22,000,000		75,000,000		107,000,000
Settlement charge	[3]	0		71,000,000		59,000,000
Net periodic benefit cost		44,000,000		144,000,000		167,000,000
Costs not recognized due to regulation		30,000,000		(30,000,000)		(46,000,000)
Net benefit cost recognized for financial reporting		74,000,000		114,000,000		121,000,000
Settlement Charge Recognized in Operating and Maintenance Expenses		$ 0		$ 9,000,000		$ 7
Significant Assumptions Used to Measure Costs [Abstract]
Discount rate (as a percent)		5.80%		3.08%		2.71%
Expected average long-term increase in compensation level (as a percent)		4.25%		3.75%		3.75%
Expected average long-term rate of return on assets (as a percent)		6.93%		6.49%		6.49%
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		405,000,000		511,000,000
Service cost		1,000,000		2,000,000		$ 2,000,000
Interest cost		22,000,000		15,000,000		15,000,000
Plan amendments		0		0
Actuarial loss		14,000,000		(85,000,000)
Defined Benefit Plan, Benefit Obligation, Contributions by Plan Participant		8,000,000		8,000,000
Defined Benefit Plan, Benefit Obligation, Prescription Drug Subsidy Receipt		0		2,000,000
Benefit payments	[1]	(56,000,000)		(48,000,000)
Obligation at Dec. 31		394,000,000		405,000,000		511,000,000
Change in Fair Value of Plan Assets [Roll Forward]
Fair value of plan assets at Jan. 1		364,000,000	[4]	442,000,000
Actual return (loss) on plan assets		29,000,000		(51,000,000)
Employer contributions		11,000,000		13,000,000
Benefit payments		(56,000,000)		(48,000,000)
Fair value of plan assets at Dec. 31		356,000,000	[4]	364,000,000	[4]	442,000,000
Funded Status of Plans at Dec. 31 [Abstract]
Funded status		(38,000,000)		(41,000,000)
Assets for Plan Benefits, Defined Benefit Plan		28,000,000		33,000,000
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost [Abstract]
Net loss		64,000,000		63,000,000
Prior service (credit) cost		0		(1,000,000)
Total		64,000,000		62,000,000
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		2,000,000		0
Noncurrent regulatory assets		79,000,000		78,000,000
Deferred income taxes		1,000,000		1,000,000
Net-of-tax accumulated other comprehensive income		2,000,000		4,000,000
Total		$ 64,000,000		$ 62,000,000
Significant Assumptions Used to Measure Benefit Obligations [Abstract]
Discount rate for year-end valuation (as a percent)		5.54%		5.80%
Defined Benefit Plan, Health Care Cost Trend Rate Assumed, Pre-65		6.50%		6.50%
Defined Benefit Plan, Health Care Cost Trend Rate Assumed, Post-65		5.50%		5.50%
Components of Net Periodic Benefit Cost (Credit) [Abstract]
Service cost		$ 1,000,000		$ 2,000,000		2,000,000
Interest cost		22,000,000		15,000,000		15,000,000
Expected return on plan assets		(17,000,000)		(18,000,000)		(18,000,000)
Amortization of prior service cost (credit)		(1,000,000)		(6,000,000)		(8,000,000)
Amortization of net loss		1,000,000		2,000,000		5,000,000
Settlement charge	[3]	0		0		0
Net periodic benefit cost		6,000,000		(5,000,000)		(4,000,000)
Costs not recognized due to regulation		0		3,000,000		2,000,000
Net benefit cost recognized for financial reporting		$ 6,000,000		$ (2,000,000)		$ (2,000,000)
Significant Assumptions Used to Measure Costs [Abstract]
Discount rate (as a percent)		5.80%		3.09%		2.65%
Expected average long-term increase in compensation level (as a percent)		0%		0%		0%
Expected average long-term rate of return on assets (as a percent)		5%		4.10%		4.10%
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		$ 20,000,000
Ultimate health care trend assumption rate (as a percent)		4.50%		4.50%
Period until ultimate trend rate is reached (in years)		$ 6		$ 7
[1] Includes lump-sum benefit payments used in the determination of a settlement charges of $195 million of in 2022. See Note 10 for further information regarding fair value measurement inputs and methods. 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. There were no settlement charges recorded for the qualified pension plans in 2023. In 2022 and 2021, as a result of lump-sum distributions during each plan year, Xcel Energy recorded a total pension settlement charge of $71 million and $59 million, respectively, the majority of which was not recognized due to the effects of regulation. A total of $9 million and $7 million was recorded in the consolidated statements of income in 2022 and 2021, respectively. 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, 2023	Dec. 31, 2022	Dec. 31, 2021
Defined Benefit Plan Disclosure [Line Items]
Operating and maintenance expenses	$ 2,444,000,000	$ 2,491,000,000	$ 2,321,000,000
transferred	0	0
Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	74,000,000	97,000,000	104,000,000
Operating and maintenance expenses	$ 0	$ 9,000,000	$ 7

Benefit Plans and Other Postr_4

Benefit Plans and Other Postretirement Benefits, Postretirement Health Care Benefits (Details) $ in Millions	12 Months Ended
	Dec. 31, 2023 USD ($)	Dec. 31, 2022 USD ($)
Postretirement Health Care Benefits [Abstract]
Estimated costs of health plan subsidies - VRP	$ 34
Estimated cost of other medical benefits - VRP		$ 5
Other Postretirement Benefits Plan [Member]
Postretirement Health Care Benefits [Abstract]
Target pension asset allocations (as a percent)	100%	100%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate, VRP	0.0550
Defined Benefit Plan, Health Care Cost Trend Rate Assumed and Ultimate Trend Assumption, VRP	0.0700
Pension Plan [Member]
Postretirement Health Care Benefits [Abstract]
Target pension asset allocations (as a percent)	100%	100%
Equity Securities | Other Postretirement Benefits Plan [Member]
Postretirement Health Care Benefits [Abstract]
Target pension asset allocations (as a percent)	9%	16%
Equity Securities | Pension Plan [Member]
Postretirement Health Care Benefits [Abstract]
Target pension asset allocations (as a percent)	31%	33%
Long-duration fixed income and interest rate swap securities | Other Postretirement Benefits Plan [Member]
Postretirement Health Care Benefits [Abstract]
Target pension asset allocations (as a percent)	0%	0%
Long-duration fixed income and interest rate swap securities | Pension Plan [Member]
Postretirement Health Care Benefits [Abstract]
Target pension asset allocations (as a percent)	38%	38%
Short-to-intermediate fixed income securities | Other Postretirement Benefits Plan [Member]
Postretirement Health Care Benefits [Abstract]
Target pension asset allocations (as a percent)	77%	71%
Short-to-intermediate fixed income securities | Pension Plan [Member]
Postretirement Health Care Benefits [Abstract]
Target pension asset allocations (as a percent)	9%	9%
Alternative investments | Other Postretirement Benefits Plan [Member]
Postretirement Health Care Benefits [Abstract]
Target pension asset allocations (as a percent)	13%	12%
Alternative investments | Pension Plan [Member]
Postretirement Health Care Benefits [Abstract]
Target pension asset allocations (as a percent)	20%	18%
Cash | Other Postretirement Benefits Plan [Member]
Postretirement Health Care Benefits [Abstract]
Target pension asset allocations (as a percent)	1%	1%
Cash | Pension Plan [Member]
Postretirement Health Care Benefits [Abstract]
Target pension asset allocations (as a percent)	2%	2%

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, 2023		Dec. 31, 2022		Dec. 31, 2021
Change in Projected Benefit Obligation [Roll Forward]
Defined Benefit Plan, Plan Assets, Payment for Settlement				$ 195,000,000
Funded Status of Plans at Dec. 31 [Abstract]
Noncurrent liabilities		$ (469,000,000)		(390,000,000)
Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Plan amendments		(3,000,000)		1,000,000
Change in Projected Benefit Obligation [Roll Forward]
Obligation at Jan. 1		2,871,000,000		3,718,000,000
Service cost		74,000,000		97,000,000		$ 104,000,000
Interest cost		158,000,000		110,000,000		104,000,000
Actuarial loss		126,000,000		(703,000,000)
Plan participants' contributions		0		0
Medicare subsidy reimbursements		0		0
Benefit payments	[1]	(283,000,000)		(352,000,000)
Obligation at Dec. 31		2,943,000,000		2,871,000,000		3,718,000,000
Change in Fair Value of Plan Assets [Roll Forward]
Fair value of plan assets at Jan. 1		2,685,000,000	[2]	3,670,000,000
Actual return (loss) on plan assets		238,000,000		(683,000,000)
Employer contributions		50,000,000		50,000,000
Participant contributions		0		0
Benefit payments		(283,000,000)		(352,000,000)
Fair value of plan assets at Dec. 31		2,690,000,000	[2]	2,685,000,000	[2]	3,670,000,000
Funded status		(253,000,000)		(186,000,000)
Funded Status of Plans at Dec. 31 [Abstract]
Assets for Plan Benefits, Defined Benefit Plan		1,000,000		15,000,000
Current liabilities		0		0
Noncurrent liabilities		(254,000,000)		(201,000,000)
Net postretirement amounts recognized on consolidated balance sheets		(253,000,000)		(186,000,000)
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost [Abstract]
Net loss		1,096,000,000		1,021,000,000
Prior service (credit) cost		(9,000,000)		(7,000,000)
Total		1,087,000,000		1,014,000,000
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		20,000,000		21,000,000
Noncurrent regulatory assets		1,014,000,000		943,000,000
Current regulatory liabilities		0		0
Noncurrent regulatory liabilities		0		0
Deferred income taxes		14,000,000		14,000,000
Net-of-tax accumulated other comprehensive income		39,000,000		36,000,000
Total		$ 1,087,000,000		$ 1,014,000,000
Significant Assumptions Used to Measure Benefit Obligations [Abstract]
Discount rate for year-end valuation (as a percent)		5.49%		5.80%
Components of Net Periodic Benefit Cost (Credit) [Abstract]
Service cost		$ 74,000,000		$ 97,000,000		104,000,000
Interest cost		158,000,000		110,000,000		104,000,000
Expected return on plan assets		(209,000,000)		(208,000,000)		(206,000,000)
Amortization of prior service cost (credit)		(1,000,000)		(1,000,000)		(1,000,000)
Amortization of net loss		22,000,000		75,000,000		107,000,000
Defined Benefit Plan, Net Periodic Benefit Cost (Credit), Gain (Loss) Due to Settlement	[3]	0		(71,000,000)		(59,000,000)
Net periodic benefit cost		$ 44,000,000		$ 144,000,000		$ 167,000,000
Significant Assumptions Used to Measure Costs [Abstract]
Discount rate (as a percent)		5.80%		3.08%		2.71%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Rate of Compensation Increase		4.25%		3.75%		3.75%
Expected average long-term rate of return on assets (as a percent)		6.93%		6.49%		6.49%
Defined Benefit Plan, Costs Not Recognized Due To Regulation		$ 30,000,000		$ (30,000,000)		$ (46,000,000)
Net benefit cost recognized for financial reporting		74,000,000		114,000,000		121,000,000
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		405,000,000		511,000,000
Service cost		1,000,000		2,000,000		2,000,000
Interest cost		22,000,000		15,000,000		15,000,000
Actuarial loss		14,000,000		(85,000,000)
Plan participants' contributions		8,000,000		8,000,000
Medicare subsidy reimbursements		0		2,000,000
Benefit payments	[1]	(56,000,000)		(48,000,000)
Obligation at Dec. 31		394,000,000		405,000,000		511,000,000
Change in Fair Value of Plan Assets [Roll Forward]
Fair value of plan assets at Jan. 1		364,000,000	[4]	442,000,000
Actual return (loss) on plan assets		29,000,000		(51,000,000)
Employer contributions		11,000,000		13,000,000
Participant contributions		8,000,000		8,000,000
Benefit payments		(56,000,000)		(48,000,000)
Fair value of plan assets at Dec. 31		356,000,000	[4]	364,000,000	[4]	442,000,000
Funded status		(38,000,000)		(41,000,000)
Funded Status of Plans at Dec. 31 [Abstract]
Assets for Plan Benefits, Defined Benefit Plan		28,000,000		33,000,000
Current liabilities		(3,000,000)		(2,000,000)
Noncurrent liabilities		(63,000,000)		(72,000,000)
Net postretirement amounts recognized on consolidated balance sheets		(38,000,000)		(41,000,000)
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost [Abstract]
Net loss		64,000,000		63,000,000
Prior service (credit) cost		0		(1,000,000)
Total		64,000,000		62,000,000
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		2,000,000		0
Noncurrent regulatory assets		79,000,000		78,000,000
Current regulatory liabilities		(1,000,000)		(1,000,000)
Noncurrent regulatory liabilities		(19,000,000)		(20,000,000)
Deferred income taxes		1,000,000		1,000,000
Net-of-tax accumulated other comprehensive income		2,000,000		4,000,000
Total		$ 64,000,000		$ 62,000,000
Significant Assumptions Used to Measure Benefit Obligations [Abstract]
Discount rate for year-end valuation (as a percent)		5.54%		5.80%
Defined Benefit Plan, Health Care Cost Trend Rate Assumed, Pre-65		6.50%		6.50%
Defined Benefit Plan, Health Care Cost Trend Rate Assumed, Post-65		5.50%		5.50%
Ultimate health care trend assumption rate (as a percent)		4.50%		4.50%
Period until ultimate trend rate is reached (in years)		$ 6		$ 7
Components of Net Periodic Benefit Cost (Credit) [Abstract]
Service cost		1,000,000		2,000,000		2,000,000
Interest cost		22,000,000		15,000,000		15,000,000
Expected return on plan assets		(17,000,000)		(18,000,000)		(18,000,000)
Amortization of prior service cost (credit)		(1,000,000)		(6,000,000)		(8,000,000)
Amortization of net loss		1,000,000		2,000,000		5,000,000
Defined Benefit Plan, Net Periodic Benefit Cost (Credit), Gain (Loss) Due to Settlement	[3]	0		0		0
Net periodic benefit cost		$ 6,000,000		$ (5,000,000)		$ (4,000,000)
Significant Assumptions Used to Measure Costs [Abstract]
Discount rate (as a percent)		5.80%		3.09%		2.65%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Rate of Compensation Increase		0%		0%		0%
Expected average long-term rate of return on assets (as a percent)		5%		4.10%		4.10%
Defined Benefit Plan, Costs Not Recognized Due To Regulation		$ 0		$ 3,000,000		$ 2,000,000
Net benefit cost recognized for financial reporting		$ 6,000,000		$ (2,000,000)		$ (2,000,000)
[1] Includes lump-sum benefit payments used in the determination of a settlement charges of $195 million of in 2022. See Note 10 for further information regarding fair value measurement inputs and methods. 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. There were no settlement charges recorded for the qualified pension plans in 2023. In 2022 and 2021, as a result of lump-sum distributions during each plan year, Xcel Energy recorded a total pension settlement charge of $71 million and $59 million, respectively, the majority of which was not recognized due to the effects of regulation. A total of $9 million and $7 million was recorded in the consolidated statements of income in 2022 and 2021, respectively. 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, 2024	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Defined Benefit Plan, Net Projected Benefit Payments [Abstract]
plan ammendment			$ 0
Pension Plan [Member]
Defined Benefit Plan, Gross Projected Benefit Payments [Abstract]
2024			398,000,000
2025			214,000,000
2026			217,000,000
2027			223,000,000
2028			226,000,000
2029 - 2033			$ 1,131,000,000
Defined Benefit Plan, Net Projected Benefit Payments [Abstract]
Target pension asset allocations (as a percent)			100%	100%
Pension Plan [Member] | Equity Securities [Member]
Defined Benefit Plan, Net Projected Benefit Payments [Abstract]
Target pension asset allocations (as a percent)			31%	33%
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)			38%	38%
Pension Plan [Member] | Short-to-intermediate fixed income securities
Defined Benefit Plan, Net Projected Benefit Payments [Abstract]
Target pension asset allocations (as a percent)			9%	9%
Pension Plan [Member] | Alternative investments
Defined Benefit Plan, Net Projected Benefit Payments [Abstract]
Target pension asset allocations (as a percent)			20%	18%
Pension Plan [Member] | Cash equivalents
Defined Benefit Plan, Net Projected Benefit Payments [Abstract]
Target pension asset allocations (as a percent)			2%	2%
Pension Plan [Member] | Xcel Energy [Member]
Defined Benefit Plan, Net Projected Benefit Payments [Abstract]
Payment for Pension Benefits			$ 50,000,000	$ 50,000,000	$ 131,000,000
Pension Plan [Member] | Xcel Energy [Member] | Subsequent Event
Defined Benefit Plan, Net Projected Benefit Payments [Abstract]
Payment for Pension Benefits	$ 100,000,000
Other Postretirement Benefits Plan [Member]
Defined Benefit Plan, Gross Projected Benefit Payments [Abstract]
2024			42,000,000
2025			40,000,000
2026			39,000,000
2027			37,000,000
2028			36,000,000
2029 - 2033			161,000,000
Expected Medicare Part D Subsidies [Abstract]
2023			2,000,000
2024			2,000,000
2025			2,000,000
2026			2,000,000
2027			2,000,000
2028-2032			12,000,000
Defined Benefit Plan, Net Projected Benefit Payments [Abstract]
2023			40,000,000
2025			38,000,000
2026			37,000,000
2027			35,000,000
2028			34,000,000
2029 - 2033			$ 149,000,000
Target pension asset allocations (as a percent)			100%	100%
Other Postretirement Benefits Plan [Member] | Equity Securities [Member]
Defined Benefit Plan, Net Projected Benefit Payments [Abstract]
Target pension asset allocations (as a percent)			9%	16%
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%	0%
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)			77%	71%
Other Postretirement Benefits Plan [Member] | Alternative investments
Defined Benefit Plan, Net Projected Benefit Payments [Abstract]
Target pension asset allocations (as a percent)			13%	12%
Other Postretirement Benefits Plan [Member] | Cash equivalents
Defined Benefit Plan, Net Projected Benefit Payments [Abstract]
Target pension asset allocations (as a percent)			1%	1%
Defined Benefit Plan, Overfunded Plan [Member] | Xcel Energy [Member]
Defined Benefit Plan, Net Projected Benefit Payments [Abstract]
Payment for Pension Benefits			$ 11,000,000	$ 13,000,000	$ 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		$ 11,000,000

Benefit Plans and Other Postr_6

Benefit Plans and Other Postretirement Benefits Defined Contribution Plans (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Retirement Benefits [Abstract]
Defined Contribution Plan, Cost	$ 46	$ 43
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Contribution Plan, Cost	$ 46	$ 43

Benefit Plans and Other Postr_7

Benefit Plans and Other Postretirement Benefits Plan Amendments (Details)	Dec. 31, 2023 USD ($)
Defined Benefit Plan Disclosure [Line Items]
plan ammendment	$ 0

Commitments and Contingencies G

Commitments and Contingencies Gas Trading Litigation (Details)	Dec. 31, 2023
Gas Trading Litigation [Member]
Loss Contingencies [Line Items]
Loss Contingency, Pending Claims, Number	1

Commitments and Contingencies C

Commitments and Contingencies Comanche Unit 3 Litigation $ in Millions	12 Months Ended
	Dec. 31, 2023 USD ($)
Loss Contingencies [Line Items]
CORE outcome total	$ 34
CORE outcome excluding interest	$ 26

Commitments and Contingencies M

Commitments and Contingencies Marshall Wild Fire (Details) $ in Millions	Dec. 31, 2023 USD ($) numberOfPlaintiffs complaint
Guarantees and Product Warranties [Abstract]
Estimated property losses caused by Marshall Wildfire	$ 2,000
Number of complaints related to the Marshall Wildfire | complaint	302
Number of plaintiffs related to the Marshall Wildfire | numberOfPlaintiffs	4,047
Cap of noneconomic loss in a civil action other than a medical malpractice under Colorado law	$ 0.6
Amount of insurance coverage	$ 500

Commitments and Contingencies S

Commitments and Contingencies Sherco (Details) - USD ($) $ in Millions	1 Months Ended
	Jan. 31, 2021	Dec. 31, 2023	Jan. 27, 2021
Public Utilities, General Disclosures [Line Items]
Customer refund of previously recovered purchased power costs	$ 17
Amount MPUC previously disallowed related to Sherco outage			$ 22
DOC recommended refund		$ 56
Recommended refund		$ 72

Commitments and Contingencies_2

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
	Feb. 28, 2015	Nov. 30, 2013
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%

Commitments and Contingencies_3

Commitments and Contingencies MGP Sites (Details) - Other MGP, Landfill, or Disposal Sites [Member]	Dec. 31, 2023 USD ($) Site
Loss Contingencies [Line Items]
Number of identified MGP, landfill, or disposal sites under current investigation and/or remediation | Site	12
Cost of identified MGP, landfill, or disposal sites under current investigation and/or remediation | $	$ 20,000,000

Environmental Requirements - Wa

Environmental Requirements - Water and Waste (Details) $ in Millions	Dec. 31, 2023 USD ($) sites
Loss Contingencies [Line Items]
Number of sites under investigation as part of federal CCR program	4
Accrued liability of sites under investigation as part of federal CCR program	$ 40
Federal Coal Ash Regulation [Member] | PSCo
Loss Contingencies [Line Items]
Number of sites that will excavate and process ash for beneficial use | sites	2
Federal Coal Ash Regulation [Member] | PSCo | Maximum
Loss Contingencies [Line Items]
Cost of Beneficial Use Coal Ash Project	$ 45
Federal Clean Water Act Section 316 (b) | Capital Addition Purchase Commitments [Member]
Loss Contingencies [Line Items]
Liability for estimated cost to comply with regulation	$ 50

AROs (Details)

AROs (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2023		Dec. 31, 2022
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance		$ 3,380		$ 3,151
Amounts Incurred		10	[1]	59	[2]
Amounts Settled		(1)
Accretion		154		148
Cash flow revisions		(325)	[3]	22	[4]
Ending balance		3,218		3,380
Fair Value, Recurring [Member] | Estimate of Fair Value Measurement [Member]
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Decommissioning fund investments		3,211		2,882
Fair Value, Recurring [Member] | Estimate of Fair Value Measurement [Member] | NSP Minnesota
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Decommissioning fund investments		3,200		2,900
Electric Plant Nuclear Production Decommissioning
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance		2,160		2,056
Amounts Incurred		0	[1]	0	[2]
Amounts Settled		0
Accretion		105		104
Cash flow revisions		(158)	[3]	0	[4]
Ending balance		2,107		2,160
Electric Plant Wind Production
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance		514		478
Amounts Incurred		10	[1]	25	[2]
Amounts Settled		0
Accretion		19		19
Cash flow revisions		(17)	[3]	(8)	[4]
Ending balance		526		514
Electric Plant Steam, Hydro and Other Production Asbestos
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance		348		288
Amounts Incurred		0	[1]	34	[2]
Amounts Settled		(1)
Accretion		15		12
Cash flow revisions		(1)	[3]	14	[4]
Ending balance		361		348
Electric Plant Electric Distribution
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance		48		47
Amounts Incurred		0	[1]	0	[2]
Amounts Settled		0
Accretion		1		1
Cash flow revisions		0	[3]	0	[4]
Ending balance		49		48
Natural Gas Plant Gas Transmission and Distribution
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance	[5]	307		279
Amounts Incurred		0	[1]	0	[2],[5]
Amounts Settled
Accretion		14		12	[5]
Cash flow revisions		(149)	[3]	16	[4],[5]
Ending balance		172		307	[5]
Common and Other Property Common Miscellaneous
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance		3		3
Amounts Incurred		0	[1]	0	[2]
Amounts Settled		0
Accretion		0		0
Cash flow revisions		0	[3]	0	[4]
Ending balance		$ 3		$ 3
[1] Amounts incurred relate to the Northern Wind farm placed in service in NSP-Minnesota. Amounts incurred related to the wind farms placed in service in 2022 for NSP-Minnesota (Dakota Range and Rock Aetna) and steam production pond remediation costs for PSCo. In 2022, 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. Prior periods have been reclassified to conform with current year presentation.

Indeterminate AROs (Details)

Indeterminate AROs (Details) $ in Millions	Dec. 31, 2023 USD ($)
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, 2023 USD ($) Plant Reactor
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	15,800
Maximum assessments per reactor per accident	$ 166
Number of owned and licensed reactors | Reactor	3
Maximum funding requirement per reactor for any one year	$ 25
Number of nuclear plant sites operated by NSP-Minnesota | Plant	2
Maximum assessments for business interruption insurance each calendar year	$ 15
Maximum assessment for property damage insurance NSP-Minnesota is subject to each calendar year	32
Maximum
Nuclear Insurance [Abstract]
Loss Contingency, Estimate of Possible Loss	16,200
Insurance coverage limits for NSP-Minnesota's nuclear plant sites	2,800
Business Interruption Insurance Coverage Provided by NEIL	490
Business Interruption Insurance Coverage Provided by NEIL - Prairie Island	$ 420

Nuclear Fuel Disposal (Details)

Nuclear Fuel Disposal (Details) - NSP Minnesota	Dec. 31, 2023 Canister
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	50
Number Of Authorized Canisters In Dry Cask Nuclear Storage Facility	64

Regulatory Plant Decommissionin

Regulatory Plant Decommissioning Recovery (Details) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Regulatory Basis to GAAP Basis Reconciliation [Abstract]
Asset Retirement Obligation	$ 3,218	$ 3,380	$ 3,151
Nuclear Plant [Member]
Regulatory Basis to GAAP Basis Reconciliation [Abstract]
Asset Retirement Obligation	2,107	2,160	$ 2,056
Estimate of Fair Value Measurement [Member] | Fair Value, Recurring [Member]
Funded Status of Nuclear Decommissioning Obligation [Abstract]
Decommissioning fund investments	$ 3,211	2,882
NSP Minnesota
Regulatory Plant Decommissioning Recovery [Abstract]
Percentage Of Total Obligation For Decommissioning Expected To Be Funded By External Funds	100%
NSP Minnesota | Estimate of Fair Value Measurement [Member] | Fair Value, Recurring [Member]
Funded Status of Nuclear Decommissioning Obligation [Abstract]
Decommissioning fund investments	$ 3,200	$ 2,900

Leases (Details)

Leases (Details) - USD ($)		12 Months Ended
		Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Lessee, Lease, Description [Line Items]
Maximum Length - Short-Term Leases		12 months
Operating Lease, Weighted Average Discount Rate, Percent		4.40%
Operating Lease ROU Assets
Gross operating lease ROU assets		$ 2,147,000,000	$ 1,913,000,000
Accumulated amortization		(930,000,000)	(709,000,000)
Net operating lease ROU assets		1,217,000,000	1,204,000,000
Finance Lease ROU Assets
Gross finance lease ROU assets		181,000,000	181,000,000
Accumulated amortization		$ (67,000,000)	$ (64,000,000)
Finance Lease, Right-of-Use Asset, Statement of Financial Position [Extensible Enumeration]		Other assets	Other assets
Net finance lease ROU assets		$ 114,000,000	$ 117,000,000
Components of Lease Expense
Operating Lease, Cost	[1]	283,000,000	280,000,000	$ 287,000,000
Finance Lease, Right-of-Use Asset, Amortization		3,000,000	4,000,000	7,000,000
Finance Lease, Interest Expense		15,000,000	16,000,000	17,000,000
Finance Lease, Cost		18,000,000	20,000,000	24,000,000
Short-term Lease, Cost		3,000,000	$ 6,000,000	5,000,000
Operating Lease Commitments
2024		277,000,000
2025		271,000,000
2026		238,000,000
2027		184,000,000
2028		129,000,000
Thereafter		421,000,000
Total minimum obligation		1,520,000,000
Interest component of obligation		(256,000,000)
Regulatory liabilities		$ 1,264,000,000
Finance Lease, Liability, Current, Statement of Financial Position [Extensible Enumeration]		Other current liabilities	Other current liabilities
Less current portion		$ (226,000,000)	$ (217,000,000)
Finance Lease, Liability, Noncurrent, Statement of Financial Position [Extensible Enumeration]		Other liabilities	Other liabilities
Noncurrent operating and finance lease liabilities		$ 1,038,000,000	$ 1,038,000,000
Operating Lease, Weighted Average Remaining Lease Term		8.2
Finance Lease, Liability, Payment, Due [Abstract]
2024	[2]	10,000,000
2025	[2]	10,000,000
2026	[2]	9,000,000
2027	[2]	8,000,000
2028	[2]	8,000,000
Thereafter	[2]	173,000,000
Total minimum obligation	[2]	218,000,000
Interest component of obligation	[2]	(154,000,000)
Present value of minimum obligation	[2]	64,000,000
Finance Lease, Liability, Current	[2]	(2,000,000)
Finance Lease, Liability, Noncurrent	[2]	62,000,000
Finance Lease, Weighted Average Remaining Lease Term	[2]	$ 36.8
WYCO, Inc. [Member]
Operating Lease ROU Assets
Equity Method Investment, Ownership Percentage		50%
Purchased Power Agreements
Operating Lease ROU Assets
Gross operating lease ROU assets		$ 1,832,000,000	1,669,000,000
Components of Lease Expense
Operating Lease, Cost		241,000,000	241,000,000	251,000,000
Operating Lease Commitments
2024	[3],[4]	244,000,000
2025	[3],[4]	245,000,000
2026	[3],[4]	216,000,000
2027	[3],[4]	162,000,000
2028	[3],[4]	107,000,000
Thereafter	[3],[4]	259,000,000
Total minimum obligation	[3],[4]	1,233,000,000
Interest component of obligation	[3],[4]	(157,000,000)
Regulatory liabilities	[3],[4]	1,076,000,000
Other Operating Lease [Domain]
Operating Lease ROU Assets
Gross operating lease ROU assets		315,000,000	244,000,000
Components of Lease Expense
Operating Lease, Cost	[5]	42,000,000	39,000,000	$ 36,000,000
Operating Lease Commitments
2024		33,000,000
2025		26,000,000
2026		22,000,000
2027		22,000,000
2028		22,000,000
Thereafter		162,000,000
Total minimum obligation		287,000,000
Interest component of obligation		(99,000,000)
Regulatory liabilities		188,000,000
Gas Storage Facilities [Member]
Finance Lease ROU Assets
Gross finance lease ROU assets		160,000,000	160,000,000
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. Excludes certain amounts related to Xcel Energy’s 50% ownership interest in WYCO. Amounts do not include PPAs accounted for as executory contracts and/or contingent payments, such as energy payments on renewable PPAs. PPA operating leases contractually expire at various dates through 2039. Includes short-term lease expense of $3 million, $6 million, and $5 million for 2023, 2022 and 2021, respectively.

Non Lease PPAs (Details)

Non Lease PPAs (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Capacity
Purchased Power Agreements (PPAs) [Abstract]
Purchased power expense		$ 77	$ 75	$ 69
Estimated Future Payments Under PPAs [Abstract]
2024		80
2025		45
2026		28
2027		9
2028		1
Thereafter		2
Total		165
Energy
Purchased Power Agreements (PPAs) [Abstract]
Purchased power expense		214	$ 182	$ 149
Estimated Future Payments Under PPAs [Abstract]
2024	[1]	207
2025	[1]	94
2026	[1]	47
2027	[1]	10
2028	[1]	10
Thereafter	[1]	18
Total	[1]	$ 386
[1] Excludes contingent energy payments for renewable energy PPAs.

Fuel Contracts (Details)

Fuel Contracts (Details) $ in Millions	Dec. 31, 2023 USD ($)
Coal
Fuel Contracts [Abstract]
2024	$ 350
2025	157
2026	81
2027	56
2028	21
Thereafter	1
Total	666
Nuclear Fuel
Fuel Contracts [Abstract]
2024	142
2025	179
2026	63
2027	180
2028	50
Thereafter	177
Total	791
Natural Gas Supply
Fuel Contracts [Abstract]
2024	339
2025	13
2026	0
2027	0
2028	0
Thereafter	0
Total	352
Natural Gas Storage and Transportation
Fuel Contracts [Abstract]
2024	311
2025	284
2026	276
2027	238
2028	111
Thereafter	442
Total	$ 1,662

VIEs - PPAs (Details)

VIEs - PPAs (Details) - MW	Dec. 31, 2023	Dec. 31, 2022
Equity Method Investment, Nonconsolidated Investee or Group of Investees [Member]
Purchased Power Agreements [Abstract]
Generating capacity (in MW)	3,751	3,961

Low-Income Housing Limited Part

Low-Income Housing Limited Partnerships (Details) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Variable Interest Entity [Line Items]
Total assets	$ 64,079	$ 61,188
Variable Interest Entity, Primary Beneficiary
Variable Interest Entity [Line Items]
Total assets	41	44
Variable Interest Entity, Consolidated, Carrying Amount, Liabilities	$ 35	$ 35

Technology Agreements (Details)

Technology Agreements (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Technology Agreements [Abstract]
Information Technology and Data Processing	$ 28	$ 181	$ 103
Technology Agreements
Technology Agreements, Minimum Payments Due [Abstract]
Long Term Purchase Commitment Technology Agreement - Current	18
Long Term Purchase Commitment Technology Agreement Future Minimum Payments Due, Year 2	14
Long Term Purchase Commitment Technology Agreement Future Minimum Payments Due, Year 3	13
Long Term Purchase Commitment Technology Agreement Future Minimum Payments Due, Year 4	12
Long Term Purchase Commitment Technology Agreement Future Minimum Payments Due, Year 5	0
Long Term Purchase Commitment Technology Agreement Future Minimum Payments Due, Thereafter	$ 0

Guarantees and Bond Indemnifica

Guarantees and Bond Indemnifications (Details) - USD ($)	Dec. 31, 2023	Dec. 31, 2022
Commitments and Contingencies Disclosure [Abstract]
Assets Held As Collateral For Guarantor Obligations	$ 0	$ 0
Guarantor Obligations, Maximum Exposure, Undiscounted	75,000,000	62,000,000
Guarantor Obligations, Maximum Exposure, Undiscounted	$ 75,000,000	$ 62,000,000

Other Comprehensive Income (Det

Other Comprehensive Income (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023		Dec. 31, 2022		Dec. 31, 2021
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Accumulated other comprehensive income (loss) at beginning of period	$ 16,675
Total income tax benefit	(146)		$ (135)		$ (70)
Accumulated other comprehensive income (loss) at end of period	17,616		16,675
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	(54)		(75)
Other comprehensive loss before reclassifications, net of tax	(2)		16
Amortization of net actuarial loss	0		0
Net current period other comprehensive income (loss)	1		21
Accumulated other comprehensive income (loss) at end of period	(53)		(54)		(75)
Gains and Losses on Cash Flow Hedges | Interest Rate Swap
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Amortization of net actuarial loss	(3)	[1]	(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	(39)		(48)
Other comprehensive loss before reclassifications, net of tax	(4)		5
Amortization of net actuarial loss	(2)	[3]	(4)	[4]
Net current period other comprehensive income (loss)	(2)		9
Accumulated other comprehensive income (loss) at end of period	(41)		(39)		(48)
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	(93)		(123)
Other comprehensive loss before reclassifications, net of tax	(6)		21
Amortization of net actuarial loss	(2)		(4)
Net current period other comprehensive income (loss)	(1)		30
Accumulated other comprehensive income (loss) at end of period	(94)		(93)		$ (123)
Total | Interest Rate Swap
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Amortization of net actuarial loss	$ (3)		$ (5)
[1] Included in interest charges. Included in interest charges. Included in the computation of net periodic pension and postretirement benefit costs. See Note 11 for further information. 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	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Segment Reporting Information [Line Items]
Investment in subsidiaries	$ 244	$ 219
Regulated Electric	11,446	12,123	$ 11,205
Natural Gas	2,645	3,080	2,132
Other	115	107	94
Regulated and Unregulated Operating Revenue	14,206	15,310	13,431
Depreciation and amortization	2,448	2,413	2,121
Interest charges and financing costs	1,004	925	816
Total income tax benefit	(146)	(135)	(70)
Net income (loss)	1,771	1,736	1,597
Regulated Electric
Segment Reporting Information [Line Items]
Revenues Including Intersegment Revenues	11,448	12,125	11,207
Depreciation and amortization	2,111	2,122	1,855
Interest charges and financing costs	670	636	568
Total income tax benefit	(135)	(162)	(96)
Net income (loss)	1,686	1,631	1,478
Regulated Natural Gas
Segment Reporting Information [Line Items]
Revenues Including Intersegment Revenues	2,648	3,082	2,134
Depreciation and amortization	323	276	254
Interest charges and financing costs	96	86	75
Total income tax benefit	50	68	54
Net income (loss)	219	264	231
All Other
Segment Reporting Information [Line Items]
Depreciation and amortization	14	15	12
Interest charges and financing costs	238	203	173
Total income tax benefit	(61)	(41)	(28)
Net income (loss)	(134)	(159)	(112)
Total revenues
Segment Reporting Information [Line Items]
Regulated and Unregulated Operating Revenue	14,211	15,314	13,435
Total revenues | Regulated Electric
Segment Reporting Information [Line Items]
Regulated Electric	11,446	12,123	11,205
Total revenues | Regulated Natural Gas
Segment Reporting Information [Line Items]
Natural Gas	2,645	3,080	2,132
Total revenues | All Other
Segment Reporting Information [Line Items]
Other	115	107	94
Intersegment Eliminations
Segment Reporting Information [Line Items]
Regulated and Unregulated Operating Revenue	(5)	(4)	(4)
Intersegment Eliminations | Regulated Electric
Segment Reporting Information [Line Items]
Regulated Electric	2	2	2
Intersegment Eliminations | Regulated Natural Gas
Segment Reporting Information [Line Items]
Natural Gas	$ 3	$ 2	$ 2

Workforce Reduction

Workforce Reduction $ in Millions	12 Months Ended
	Dec. 31, 2023 USD ($) Employees
Postemployment Benefits [Abstract]
Other Postretirement Benefits Cost (Reversal of Cost) | $	$ 72
Voluntary Retirement Program
Postemployment Benefits [Abstract]
Entity Number of Employees	400
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Entity Number of Employees	400
Employee Severance
Postemployment Benefits [Abstract]
Entity Number of Employees	150
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Entity Number of Employees	150

Condensed Statements of Income

Condensed Statements of Income and Comprehensive Income (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Income
Income (Loss) from Equity Method Investments	$ 35	$ 36	$ 62
Expenses and other deductions
Other income	(22)	13	(5)
Interest charges and financing costs	1,055	953	842
Income before income taxes	1,625	1,601	1,527
Income tax benefit	(146)	(135)	(70)
Net income	1,771	1,736	1,597
Other Comprehensive Income (Loss), Net of Tax [Abstract]
Total comprehensive income	$ 1,770	$ 1,766	$ 1,615
Weighted average common shares outstanding:
Basic	552	547	539
Diluted	552	547	540
Earnings per average common share:
Basic	$ 3.21	$ 3.18	$ 2.96
Diluted	$ 3.21	$ 3.17	$ 2.96
Xcel Energy Inc.
Income
Income (Loss) from Equity Method Investments	$ 1,948	$ 1,905	$ 1,744
Total income	1,948	1,905	1,744
Expenses and other deductions
Operating expenses	25	19	21
Other income	13	2	(3)
Interest charges and financing costs	235	206	173
Total expenses and other deductions	247	223	197
Income before income taxes	1,701	1,682	1,547
Income tax benefit	(70)	(54)	(50)
Net income	1,771	1,736	1,597
Other Comprehensive Income (Loss), Net of Tax [Abstract]
Net pension and retiree medical (losses) gains arising during the period, net of tax	(2)	9	8
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, before Tax	1	21	10
Other Comprehensive Income (Loss), Net of Tax	(1)	30	18
Total comprehensive income	$ 1,770	$ 1,766	$ 1,615

Condensed Statement of Cash Flo

Condensed Statement of Cash Flows (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Operating activities
Other, net	$ (157)	$ (122)	$ (140)
Net cash provided by (used in) operating activities	5,327	3,932	2,189
Investing activities
Net (investments) return in the utility money pool	(21)	0	57
Net cash provided by (used in) investing activities	(5,926)	(4,653)	(4,287)
Financing activities
Proceeds from (repayment of) short-term borrowings, net	(28)	(192)	421
Proceeds from Issuance of Long-term Debt	2,630	2,164	2,710
Repayment of long-term debt	(1,151)	(601)	(417)
Proceeds from Issuance of Common Stock	270	322	366
Payments of Dividends	(1,092)	(1,012)	(935)
Proceeds from (Payments for) Other Financing Activities	(12)	(15)	(10)
Net cash provided by (used in) financing activities	617	666	2,135
Net change in cash and cash equivalents	18	(55)	37
Cash and Cash Equivalents, at Carrying Value, Beginning Balance	111	166	129
Cash and Cash Equivalents, at Carrying Value, Ending Balance	129	111	166
Xcel Energy Inc.
Operating activities
Net cash provided by (used in) operating activities	1,586	1,340	1,147
Investing activities
Capital contributions to subsidiaries	975	921	1,661
Net cash provided by (used in) investing activities	(954)	(921)	(1,604)
Financing activities
Proceeds from (repayment of) short-term borrowings, net	(66)	(407)	638
Proceeds from Issuance of Long-term Debt	792	694	791
Repayment of long-term debt	500	0	400
Proceeds from Issuance of Common Stock	270	322	366
Payments of Dividends	1,092	1,012	935
Proceeds from (Payments for) Other Financing Activities	(13)	(16)	(16)
Net cash provided by (used in) financing activities	(609)	(419)	444
Net change in cash and cash equivalents	23	0	(13)
Cash and Cash Equivalents, at Carrying Value, Beginning Balance	1	1	14
Cash and Cash Equivalents, at Carrying Value, Ending Balance	$ 24	$ 1	$ 1

Condensed Balance Sheet (Detail

Condensed Balance Sheet (Details) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Assets
Accounts receivable, net	$ 1,315	$ 1,373
Derivative instruments	104	279
Total current assets	4,069	5,144
Investment in subsidiaries	244	219
Other assets	678	389
Total other assets	8,368	7,791
Total assets	64,079	61,188
Liabilities and Equity
Dividends payable	289	268
Short-term debt	785	813
Other current liabilities	722	545
Total current liabilities	5,652	6,078
Other liabilities	148	147
Total deferred credits and other liabilities	15,898	15,622
Capitalization
Total common stockholders’ equity	17,616	16,675
Total liabilities and equity	64,079	61,188
Xcel Energy Inc.
Assets
Accounts receivable, net	404	443
Xcel Energy Inc.
Assets
Cash and cash equivalents	24	1
Derivative instruments	0	1
Other current assets	5	7
Total current assets	433	452
Investment in subsidiaries	23,873	22,597
Other assets	(20)	(7)
Total other assets	23,853	22,590
Total assets	24,286	23,042
Liabilities and Equity
Long-term Debt, Current Maturities	0	500
Dividends payable	289	268
Short-term debt	165	231
Other current liabilities	66	17
Total current liabilities	520	1,016
Other liabilities	12	13
Total deferred credits and other liabilities	12	13
Capitalization
Long-term debt, noncurrent	6,137	5,338
Total common stockholders’ equity	17,617	16,675
Total capitalization	23,754	22,013
Total liabilities and equity	$ 24,286	$ 23,042

Condensed Notes to the Financia

Condensed Notes to the Financial Statements (Details) - USD ($) $ in Millions		3 Months Ended	12 Months Ended
		Dec. 31, 2023	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Money Pool [Abstract]
Guarantor Obligations, Maximum Exposure, Undiscounted		$ 75	$ 75	$ 62
Schedule of Guarantor Obligations			Guarantees and bond indemnities issued and outstanding as of Dec. 31, 2023: (Millions of Dollars) Guarantor Guarantee Current Triggering Guarantees of Capital Services purchase contracts for wind and solar generating equipment (a) Xcel Energy Inc. 951 (b) (c) Guarantees of Xcel Energy Inc.’s utility subsidiaries’ performance on tax credit sale agreements Xcel Energy Inc. 100 (d) (c) Guarantee performance and payment of surety bonds for Xcel Energy Inc.’s utility subsidiaries (e) Xcel Energy Inc. 75 (f) (g) (a) Guarantees expire upon the satisfaction of all buyer obligations under the purchase contracts. (b) Given that the manufacturing of equipment has not yet commenced, related exposure to the performance obligations of Capital Services at Dec. 31, 2023 has been assessed as immaterial. (c) Nonperformance and/or nonpayment. (d) Exposure to the performance obligations of the utility subsidiaries has been assessed as immaterial. The tax credit sales transactions closed as scheduled in January 2024. (e) The surety bonds primarily relate to workers compensation benefits and utility projects. The workers compensation bonds are renewed annually and the project based bonds expire in conjunction with the completion of the related projects. (f) Due to the number 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. (g) Per the indemnity agreement between Xcel Energy Inc. and the various surety companies, surety companies have the discretion to demand that collateral be posted.
Payment or Performance Guarantee | Guarantee of Capital Services purchase contract for solar generating equipment
Money Pool [Abstract]
Guarantor Obligations, Maximum Exposure, Undiscounted	[1],[2],[3]	951	$ 951
Payment or Performance Guarantee | Guarantees of Xcel Energy Inc.'s utility subsidiaries' performance on tax credit sale agreements
Money Pool [Abstract]
Guarantor Obligations, Maximum Exposure, Undiscounted	[3],[4]	100	100
Payment or Performance Guarantee | Surety Bonds
Money Pool [Abstract]
Guarantor Obligations, Maximum Exposure, Undiscounted	[5],[6],[7]	75	75
Xcel Energy Inc.
Dividends [Abstract]
Cash dividends paid to Xcel Energy by subsidiaries			1,693	1,503	$ 1,344
Money Pool [Abstract]
Loan outstanding at period end		21	21	0	0
Average loan outstanding		90	27	10	16
Maximum loan outstanding		$ 250	$ 250	$ 204	$ 439
Weighted average interest rate, computed on a daily basis (percentage)		1.34%	5.33%	0.73%	0.08%
Line of Credit Facility, Interest Rate at Period End		5.34%	5.34%
Interest Income, Other		$ 1	$ 1	$ 0	$ 0
Weighted average interest rate at period end (percentage)		5.34%	5.34%
Other Receivable, after Allowance for Credit Loss, Current, Related and Nonrelated Party Status [Extensible Enumeration]		$ 403	$ 403	443
Xcel Energy Inc. | NSP Minnesota
Money Pool [Abstract]
Other Receivable, after Allowance for Credit Loss, Current, Related and Nonrelated Party Status [Extensible Enumeration]		120	120	82
Xcel Energy Inc. | NSP-Wisconsin
Money Pool [Abstract]
Other Receivable, after Allowance for Credit Loss, Current, Related and Nonrelated Party Status [Extensible Enumeration]		13	13	17
Xcel Energy Inc. | PSCo
Money Pool [Abstract]
Other Receivable, after Allowance for Credit Loss, Current, Related and Nonrelated Party Status [Extensible Enumeration]		44	44	111
Xcel Energy Inc. | SPS
Money Pool [Abstract]
Other Receivable, after Allowance for Credit Loss, Current, Related and Nonrelated Party Status [Extensible Enumeration]		47	47	61
Xcel Energy Inc. | Xcel Energy Services Inc.
Money Pool [Abstract]
Other Receivable, after Allowance for Credit Loss, Current, Related and Nonrelated Party Status [Extensible Enumeration]		144	144	145
Xcel Energy Inc. | Other Subsidiaries
Money Pool [Abstract]
Other Receivable, after Allowance for Credit Loss, Current, Related and Nonrelated Party Status [Extensible Enumeration]		$ 35	$ 35	$ 27
[1] Given that the manufacturing of equipment has not yet commenced, related exposure to the performance obligations of Capital Services at Dec. 31, 2023 has been assessed as immaterial. Guarantees expire upon the satisfaction of all buyer obligations under the purchase contracts. Nonperformance and/or nonpayment. Exposure to the performance obligations of the utility subsidiaries has been assessed as immaterial. The tax credit sales transactions closed as scheduled in January 2024. Per the indemnity agreement between Xcel Energy Inc. and the various surety companies, surety companies have the discretion to demand that collateral be posted. 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. Due to the number 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.

Schedule II (Details)

Schedule II (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Allowance for Bad Debts
SEC Schedule, 12-09, Movement in Valuation Allowances and Reserves [Roll Forward]
Balance at Jan. 1		$ 122	$ 106	$ 79
Charged to costs and expenses		79	73	60
Charged to other accounts	[1]	13	26	14
Deductions from reserves	[2]	86	83	47
Balance at Dec. 31		128	122	106
NOL and Tax Credit Valuation Allowances
SEC Schedule, 12-09, Movement in Valuation Allowances and Reserves [Roll Forward]
Balance at Jan. 1		62	64	64
Charged to costs and expenses		26	6	5
Charged to other accounts		0	0	0
Deductions from reserves	[3]	18	8	5
Balance at Dec. 31		$ 70	$ 62	$ 64
[1] Recovery of amounts previously written-off. Deductions related primarily to bad debt write-offs.