XCEL ENERGY INC, 10-K filed on 2/25/2026
Annual Report
v3.25.4
Cover Page - USD ($)
 12 Months Ended
Dec. 31, 2025
Feb. 19, 2026
Jun. 30, 2025
Cover [Abstract]      
Document Type 10-K    
Document Annual Report true    
Document Period End Date Dec. 31, 2025    
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    
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     $ 40,260,845,645
Entity Common Stock, Shares Outstanding   623,876,813  
Entity Registrant Name XCEL ENERGY INC    
Entity Central Index Key 0000072903    
Current Fiscal Year End Date --12-31    
Document Fiscal Year Focus 2025    
Document Fiscal Period Focus FY    
Amendment Flag false    
Document Financial Statement Error Correction [Flag] false    
Documents Incorporated by Reference
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the Registrant’s definitive Proxy Statement for its 2026 Annual Meeting of Shareholders are incorporated by reference into Part III of this Form 10-K.
    
Common stock      
Cover [Abstract]      
Title of 12(b) Security Common Stock, $2.50 par value per share    
Trading Symbol XEL    
Security Exchange Name NASDAQ    
Entity Listings [Line Items]      
Security Exchange Name NASDAQ    
Trading Symbol XEL    
Title of 12(b) Security Common Stock, $2.50 par value per share    
6.25% Junior Subordinated Notes due 2085      
Cover [Abstract]      
Title of 12(b) Security 6.25% Junior Subordinated Notes due 2085    
Trading Symbol XELLL    
Security Exchange Name NASDAQ    
Entity Listings [Line Items]      
Security Exchange Name NASDAQ    
Trading Symbol XELLL    
Title of 12(b) Security 6.25% Junior Subordinated Notes due 2085    
v3.25.4
Audit Information
 12 Months Ended
Dec. 31, 2025
Auditor Information [Abstract]  
Auditor Firm ID 34
Auditor Name DELOITTE & TOUCHE LLP
Auditor Location Minneapolis, Minnesota
v3.25.4
Accounting Pronouncements
 12 Months Ended
Dec. 31, 2025
Accounting Standards Update and Change in Accounting Principle [Abstract]  
Accounting Pronouncements
Recently Adopted
Income Taxes — In December 2023, the FASB issued ASU 2023-09 – Income Taxes (Topic 740) – Improvements to Income Tax Disclosures, with new disclosure requirements including presentation of prescribed line items in the ETR reconciliation and disclosures regarding state and local tax payments. Xcel Energy retrospectively implemented this guidance in the year ended Dec. 31, 2025. The adoption impacts were not material.
See Note 7 for further information.
Recently Issued
Government Grants — In December 2025, the FASB issued ASU 2025-10 – Government Grants (Topic 832), which includes amended recognition, measurement and presentation requirements for asset and income-related grants. The ASU is effective for annual and interim reporting periods beginning after Dec. 15, 2028. Xcel Energy is currently evaluating the new guidance, but adoption impacts are expected to be immaterial.
Disaggregation of Income Statement Expenses — In November 2024, the FASB issued ASU 2024-03 – Disaggregation of Income Statement Expenses, which requires disclosure of additional detail for certain categories of income statement expenses. The ASU is effective for annual reporting periods beginning after Dec. 15, 2026 and interim reporting periods beginning after Dec. 15, 2027. Xcel Energy is currently evaluating the impact of the new disclosure guidance.
v3.25.4
CONSOLIDATED STATEMENTS OF INCOME - USD ($)
shares in Millions, $ in Millions
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Operating revenues      
Electric $ 12,160 $ 11,147 $ 11,446
Natural Gas 2,452 2,230 2,645
Other 57 64 115
Total operating revenues 14,669 13,441 14,206
Operating expenses      
Electric fuel and purchased power 3,961 3,788 4,278
Cost of natural gas sold and transported 1,041 951 1,456
Cost of sales — other 11 14 49
Operating and maintenance expenses 2,732 2,540 2,444
Conservation and demand side management expenses 406 394 286
Depreciation and amortization 2,953 2,744 2,448
Taxes (other than income taxes) 686 624 657
Marshall Wildfire litigation 296 0 0
Gain (Loss) from Litigation Settlement 0 0 35
Workforce reduction expenses 0 0 72
Total operating expenses 12,086 11,055 11,725
Operating income 2,583 2,386 2,481
Other income, net 235 143 22
Earnings from equity method investments 17 19 35
Allowance for funds used during construction — equity 281 168 91
Interest charges and financing costs      
Interest charges — includes other financing costs 1,468 1,255 1,055
Allowance for funds used during construction — debt (125) (73) (51)
Total interest charges and financing costs 1,343 1,182 1,004
Income before income taxes 1,773 1,534 1,625
Income tax benefit (245) (402) (146)
Net income $ 2,018 $ 1,936 $ 1,771
Weighted average common shares outstanding:      
Basic 587 563 552
Diluted [1] 589 563 552
Earnings per average common share:      
Basic $ 3.44 $ 3.44 $ 3.21
Diluted $ 3.42 $ 3.44 $ 3.21
[1] Diluted common shares outstanding included common stock equivalents of 2.1 million, 0.5 million, and 0.3 million shares for 2025, 2024 and 2023, respectively.
v3.25.4
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Comprehensive income:      
Net income $ 2,018 $ 1,936 $ 1,771
Pension and retiree medical benefits:      
Net pension and retiree medical losses arising during the period, net of tax (1) (3) (4)
Reclassification of losses to net income, net of tax 2 5 2
Derivative instruments:      
Net fair value increase (decrease), net of tax 2 22 (2)
Reclassification of losses to net income, net of tax 2 2 3
Total other comprehensive income (loss) 5 26 (1)
Total comprehensive income $ 2,023 $ 1,962 $ 1,770
v3.25.4
CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Operating activities      
Net income $ 2,018 $ 1,936 $ 1,771
Adjustments to reconcile net income to cash provided by operating activities:      
Depreciation and amortization 2,968 2,769 2,471
Nuclear fuel amortization 114 106 96
Deferred income taxes 414 225 (59)
Allowance for equity funds used during construction (281) (168) (91)
Earnings from equity method investments (17) (19) (35)
Dividends from equity method investments 32 34 35
Provision for bad debts 61 47 79
Share-based compensation expense 46 33 25
Changes in operating assets and liabilities:      
Accounts receivable (129) 19 (27)
Accrued unbilled revenues (48) 21 252
Inventories (300) (140) (98)
Other current assets (122) (139) 86
Accounts payable (50) 37 (149)
Net regulatory assets and liabilities (189) 436 911
Other current liabilities (174) (317) 200
Pension and other employee benefit obligations (100) (89) 17
Other, net (160) (150) (157)
Net Cash Provided by (Used in) Operating Activities, Total 4,083 4,641 5,327
Investing activities      
Capital/construction expenditures (10,908) (7,364) (5,854)
Purchase of investment securities (1,200) (998) (994)
Proceeds from the sale of investment securities 1,197 961 959
Other, net (58) (27) (37)
Net Cash Provided by (Used in) Investing Activities, Total (10,969) (7,428) (5,926)
Financing activities      
Proceeds (repayments) of short-term borrowings, net 855 (90) (28)
Proceeds from Issuance of Long-term Debt 5,763 3,647 2,630
Repayments of long-term debt (1,713) (656) (1,151)
Proceeds from Issuance of Common Stock 3,349 1,117 270
Payments of Dividends (1,282) (1,175) (1,092)
Proceeds from (Payment for) Other Financing Activity 9 (6) (12)
Net Cash Provided by (Used in) Financing Activities, Total 6,981 2,837 617
Net change in cash and cash equivalents 95 50 18
Cash and Cash Equivalents, at Carrying Value, Beginning Balance 179 129 111
Cash and Cash Equivalents, at Carrying Value, Ending Balance 274 179 129
Supplemental disclosure of cash flow information:      
Interest Paid, Excluding Capitalized Interest, Operating Activity (1,262) (1,131) (945)
Income Taxes Paid, Net (641) (588) (92)
Other Noncash Investing and Financing Items [Abstract]      
Capital Expenditures Incurred but Not yet Paid 1,170 964 553
Inventory transfers to plant, property and equipment 348 258 197
Right-of-Use Asset Obtained in Exchange for Operating Lease Liability 1,253 138 238
Allowance for equity funds used during construction 281 168 91
Stock Issued $ 80 $ 68 $ 64
v3.25.4
CONSOLIDATED BALANCE SHEETS - USD ($)
$ in Millions
Dec. 31, 2025
Dec. 31, 2024
Current assets    
Cash and cash equivalents $ 274 $ 179
Accounts receivable, net 1,330 1,249
Accrued unbilled revenues 880 832
Inventories 761 666
Regulatory assets 529 561 [1]
Derivative instruments 165 114
Prepayments and other 1,075 724
Total current assets 5,014 4,325
Property, plant and equipment, net 65,639 57,198
Other assets    
Nuclear decommissioning fund and other investments 4,389 3,896
Regulatory assets 2,998 2,849 [1]
Derivative instruments 54 72
Operating lease right-of-use assets 893 1,060
Net finance lease ROU assets 1,348 111
Other 1,036 524
Total other assets 10,718 8,512
Total assets 81,371 70,035
Current liabilities    
Current portion of long-term debt 501 1,103
Short-term debt 1,550 695
Accounts payable 2,307 1,781
Regulatory liabilities 714 852
Taxes accrued 579 535
Accrued interest 337 280
Dividends payable 355 314
Derivative instruments 31 37
Operating Lease, Liability, Current 110 227
Other 605 635
Total current liabilities 7,089 6,459
Deferred credits and other liabilities    
Deferred income taxes 6,004 5,319
Regulatory liabilities 6,277 6,010
Asset retirement obligations 3,888 3,713
Derivative instruments 67 77
Customer advances 129 146
Pension and employee benefit obligations 365 477
Operating lease liabilities 788 867
Finance Lease, Liability, Noncurrent 1,262 [2] 60
Other 61 69
Total deferred credits and other liabilities 18,841 16,738
Commitments and contingencies
Common Stock, Shares Issued, Not Disclosed true true
Capitalization    
Long-term debt $ 31,832 $ 27,316
Common stock — 1,000,000,000 shares authorized of $2.50 par value; 623,600,715 and 574,365,598 shares outstanding at Dec. 31, 2025 and Dec. 31, 2024, respectively $ 1,559 $ 1,436
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 623,600,715 574,365,598
Additional paid in capital $ 12,906 $ 9,601
Retained earnings 9,207 8,553
Accumulated other comprehensive loss (63) (68)
Total common stockholders’ equity 23,609 19,522
Total liabilities and equity $ 81,371 $ 70,035
[1] Prior period amounts have been reclassified to conform with current year presentation.
[2] Excludes certain amounts related to Xcel Energy’s 50% ownership interest in WYCO.
v3.25.4
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, 2022   549,578,018      
Beginning 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)        
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      
Ending balance at Dec. 31, 2023 17,616 $ 1,387 8,465 7,858 (94)
Increase (Decrease) in Stockholders' Equity          
Net income 1,936        
Other comprehensive income $ 26        
Cash dividends declared per common share (in dollars per share) $ 2.19        
Dividends declared on common stock $ (1,236)     (1,236)  
Issuances of common stock (in shares)   19,423,895      
Issuances of common stock (value) 1,147 $ 49 1,098    
Share-based compensation $ 33   38 (5)  
Balance (in shares) at Dec. 31, 2024 574,365,598 574,365,598      
Ending balance at Dec. 31, 2024 $ 19,522 $ 1,436 9,601 8,553 (68)
Increase (Decrease) in Stockholders' Equity          
Net income 2,018        
Other comprehensive income $ 5       5
Cash dividends declared per common share (in dollars per share) $ 2.28        
Dividends declared on common stock $ (1,357)     (1,357)  
Issuances of common stock (in shares)   49,235,117      
Issuances of common stock (value) 3,376 $ 123 3,253    
Share-based compensation $ 45   52 (7)  
Balance (in shares) at Dec. 31, 2025 623,600,715 623,600,715      
Ending balance at Dec. 31, 2025 $ 23,609 $ 1,559 $ 12,906 $ 9,207 $ (63)
v3.25.4
Summary of Significant Accounting Policies
 12 Months Ended
Dec. 31, 2025
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 and storage facilities.
Xcel Energy Inc.’s nonregulated subsidiaries include:
Nonregulated SubsidiaryPurpose
EloigneInvests in rental housing projects that qualify for low-income housing tax credits.
Capital ServicesProcures equipment for Xcel Energy subsidiaries for construction of generation facilities and for other items with long lead times.
Xcel Energy Venture Holdings, Inc.Invests in limited partnerships, including funds with portfolios of investments in energy technology companies.
Nicollet Project HoldingsInvests 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 investments in energy technology 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 depreciation and other 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, 2025 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, actuarially determined benefit costs and wildfire contingencies. 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 reversed or 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, as determined by tax regulations and Xcel Energy tax elections. For tax credits 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, 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 assets’ commission approved useful lives. 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 3.9% for 2025, 3.8% for 2024 and 3.6% for 2023.
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.
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 years and submitted to the state commissions for approval. The latest decommissioning study was completed in 2024.
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.
Leases — Xcel Energy evaluates contracts that may contain leases, including PPAs and arrangements for the use of office space and other facilities, as well as certain contracts for the use of land, vehicles and other 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 whether the arrangement is an operating lease or a finance lease, including an assessment of whether the contract requires payments for substantially all of the value of the leased asset or whether the term of the contract is for substantially all of the expected remaining economic life of the leased asset, among other criteria for finance lease classification.
See Note 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 generally 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. When separate mechanisms are expected to provide cost recovery or when changes in projected costs occur near the end of a facility’s useful life, regulatory accounting may be applied.
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.
Xcel Energy’s subsidiaries have various rate-adjustment mechanisms that provide for the recovery of natural gas, electric fuel and purchased energy costs. Cost-adjustment tariffs may increase or decrease the level of revenue collected from customers and are revised periodically for differences between the total amount collected under the clauses and the costs incurred.
When applicable, fuel cost over-recoveries (the excess of fuel revenue billed to customers over fuel costs incurred) are deferred as regulatory liabilities and under-recoveries (the excess of fuel costs incurred over fuel revenues billed to customers) are deferred as regulatory assets.
See Note 6 for further information.
Cash and Cash Equivalents — Xcel Energy considers investments in instruments with a remaining maturity of three months or less at the time of purchase to be cash equivalents.
Accounts Receivable and Allowance for Bad Debts — Accounts receivable are stated at the actual billed amount net of an allowance for bad debts. Xcel Energy establishes an allowance for uncollectible receivables based on a policy that reflects its expected exposure to the credit risk of customers.
As of Dec. 31, 2025 and 2024, the allowance for bad debts was $89 million and $111 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, 2025Dec. 31, 2024
Inventories
Materials and supplies$489 $406 
Fuel156 164 
Natural gas116 96 
Total inventories$761 $666 
Equity Method Investments — The equity method of accounting is used for certain investments including WYCO and energy technology 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 energy technology 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.
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 that have not been designated or do not qualify 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 and sale 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 transmission and distribution cost recovery, 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 annual period in which 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.

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.
v3.25.4
Property Plant and Equipment Property Plant and Equipment
 12 Months Ended
Dec. 31, 2025
Property, Plant and Equipment [Abstract]  
Property, Plant and Equipment Disclosure
Major classes of property, plant and equipment
(Millions of Dollars)Dec. 31, 2025Dec. 31, 2024
Property, plant and equipment, net
Electric plant$61,892 $56,791 
Natural gas plant10,517 9,834 
Common and other property3,790 3,515 
Plant to be retired (a)
1,595 1,793 
CWIP8,085 4,720 
Total property, plant and equipment85,879 76,653 
Less accumulated depreciation(20,710)(19,852)
Nuclear fuel3,678 3,491 
Less accumulated amortization(3,208)(3,094)
Property, plant and equipment, net$65,639 $57,198 
(a)Amounts include Sherco 1 and 3 and A.S. King for NSP-Minnesota; Comanche Unit 3, Craig Unit 2, Hayden Units 1 and 2 for PSCo; and Tolk Unit 1 and 2 for SPS. The Dec. 31, 2024 amounts also include coal generation assets at Pawnee (assets were retired in 2025 and the conversion to natural gas is complete). Additionally, 2024 amounts included both Comanche Unit 2 and Craig Unit 1, which had planned retirement dates in 2025. Amounts are presented net of accumulated depreciation.

Joint Ownership of Generation, Transmission and Gas Facilities
The utility subsidiaries’ jointly owned assets as of Dec. 31, 2025:
(Millions of Dollars, Except Percent Owned)Plant in ServiceAccumulated DepreciationPercent Owned
NSP-Minnesota
Electric generation:
Sherco Unit 3$638 $515 59 %
Sherco common facilities189 134 80 
Sherco substation5 4 59 
Electric transmission:
Grand Meadow11 4 50 
Huntley Wilmarth49 4 50 
CapX2020887 169 51 
Total NSP-Minnesota (a)
$1,779 $830 
(a)Projects additionally include $26 million in CWIP.
(Millions of Dollars, Except Percent Owned)Plant in ServiceAccumulated DepreciationPercent Owned
NSP-Wisconsin
Electric transmission:
La Crosse, WI to Madison, WI$179 $33 37 %
CapX2020169 46 80 
Total NSP-Wisconsin (a)
$348 $79 
(a)Projects additionally include $3 million in CWIP.
(Millions of Dollars, Except Percent Owned)Plant in ServiceAccumulated DepreciationPercent Owned
PSCo
Electric generation:
Hayden Unit 1$159 $126 76 %
Hayden Unit 2152 99 37 
Hayden common facilities45 36 53 
Craig Units 1 and 282 60 10 
Craig common facilities40 28 7 
Comanche Unit 3971 233 67 
Comanche common facilities29 6 77 
Electric transmission:
Transmission and other facilities193 76 Various
Gas transmission:
Rifle, CO to Avon, CO31 10 60 
Gas transmission compressor8 3 60 
Total PSCo (a)
$1,710 $677 
(a)Projects additionally include $16 million in CWIP.
Each company separately records its share of operating expenses and construction expenditures. Respective owners are responsible for providing their own financing.
v3.25.4
Regulatory Assets and Liabilities
 12 Months Ended
Dec. 31, 2025
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 PeriodDec. 31, 2025
Dec. 31, 2024 (a)
Regulatory AssetsCurrentNoncurrentCurrentNoncurrent
Pension and retiree medical obligations11Various$39 $1,121 $39 $1,167 
Recoverable deferred taxes on AFUDCPlant lives— 434 — 368 
Net AROs1, 12Various— 422 — 387 
Depreciation differencesVarious22 320 17 250 
Excess deferred taxes — TCJA
7Various11 162 10 184 
Grid modernization costsVarious2 67 3 30 
Excess liability insurance costsVarious5 64 — 6 
Environmental remediation costs1, 12Various9 34 13 39 
Prairie Island extended power uprate
Nine years
4 30 4 34 
Conservation programs (b)
1
One to two years
18 28 20 30 
Nuclear refueling outage costs1
One to two years
58 20 51 20 
Benson biomass PPA termination and asset purchase
Three years
10 16 10 26 
Deferred natural gas, electric, steam energy/fuel costs
One to two years
88 15 99 25 
Renewable resources and environmental initiatives
One to two years
40 4 34 4 
Sales true-up and MN MISO capacity revenueVarious75 2 123 68 
Gas pipeline inspection and remediation costs
Less than one year
31 — 47 9 
Other
Various117 259 91 202 
Total regulatory assets$529 $2,998 $561 $2,849 
(a)Prior period amounts have been reclassified to conform with current year presentation.
(b)Includes costs for conservation programs, as well as incentives allowed in certain jurisdictions.

Components of regulatory liabilities:
(Millions of Dollars)See Note(s)Remaining Amortization PeriodDec. 31, 2025Dec. 31, 2024
Regulatory LiabilitiesCurrentNoncurrentCurrentNoncurrent
Deferred income tax adjustments and TCJA refunds (a)
7Various$7 $2,758 $7 $2,888 
Plant removal costs1, 12Various— 2,336 — 2,208 
Net AROs (b)
Various— 354 — 161 
Renewable resources and environmental initiativesVarious16 319 16 232 
Effects of regulation on employee benefit costs (c)
11Various— 261 — 259 
ITC deferrals
1Various— 64 — 70 
IRA deferral
One to two years
19 19 3 37 
Deferred natural gas, electric, steam energy/fuel costs
One to two years
296 13 480 12 
Contract valuation adjustments (d)
1, 10
Less than one year
144 — 89 — 
Conservation programs (e)
1
Less than one year
39 — 52 — 
Other Various193 153 205 143 
Total regulatory liabilities$714 $6,277 $852 $6,010 
(a)Includes the revaluation of recoverable/regulated plant ADIT and revaluation impact of non-plant ADIT due to the TCJA.
(b)Includes amounts recorded for future recovery of AROs, less amounts recovered through nuclear decommissioning accruals and gains from decommissioning investments.
(c)Includes regulatory amortization and certain 2018 TCJA benefits approved by the CPUC to offset the PSCo prepaid pension asset.
(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.
Xcel Energy’s regulatory assets not earning a return include past expenditures of $799 million and $892 million at Dec. 31, 2025 and 2024 respectively, which predominately relate to certain prepaid pension amounts, purchased natural gas and electric energy costs, deferred excess liability insurance costs, sales true-up and revenue decoupling and other renewable resources/environmental initiatives. 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.
v3.25.4
Borrowings and Other Financing Instruments Borrowings and Other Financing Instruments
 12 Months Ended
Dec. 31, 2025
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 its credit facilities and term loan agreements.
Commercial paper and other borrowings outstanding:
(Millions of Dollars, Except Interest Rates)Three Months Ended Dec. 31, 2025Year Ended Dec. 31
202520242023
Borrowing limit$4,750 $4,750 $3,550 $3,550 
Amount outstanding at period end1,550 1,550 695 785 
Average amount outstanding1,622 1,026 508 491 
Maximum amount outstanding2,965 2,965 1,314 1,241 
Weighted average interest rate, computed on a daily basis4.14 %4.41 %5.47 %5.12 %
Weighted average interest rate at period end3.95 3.95 4.64 5.52 
Bilateral Credit Agreement — In April 2025, 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, 2025, NSP-Minnesota had $69 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, 2025 and 2024, there were $92 million and $42 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.
In May 2025, 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 $4.75 billion. The amended credit agreements mature in December 2029.
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)
20252024
Xcel Energy Inc. (d)
59.80 %59.80 %$450 2 
NSP-Minnesota50.00 47.00 170 2 
NSP-Wisconsin47.00 47.10 N/A1 
SPS47.20 46.60 60 2 
PSCo44.90 45.20 170 2 
(a)Each credit facility has a financial covenant requiring that the debt-to-total capitalization ratio be less than or equal to 65% (70% for Xcel Energy Inc.).
(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, 2025, Xcel Energy Inc. and its subsidiaries were in compliance with the financial covenant.
Xcel Energy Inc. and its utility subsidiaries had the following committed credit facilities available as of Dec. 31, 2025:
(Millions of Dollars)
Credit Facility (a)
Drawn (b)
Available
Xcel Energy Inc.$2,000 $850 $1,150 
PSCo1,200 308 892 
NSP-Minnesota800 264 536 
SPS600 220 380 
NSP-Wisconsin150 — 150 
Total$4,750 $1,642 $3,108 
(a)These credit facilities mature in December 2029.
(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, 2025 and 2024.
Term Loan Agreement — In January 2026, Xcel Energy Inc. entered into a $1.5 billion, 364-Day Delayed Draw Term Loan Agreement and borrowed $750 million under the term loan facility. The loan is unsecured and matures Jan. 30, 2027. The term loan includes one financial covenant, requiring Xcel Energy’s consolidated funded debt to total capitalization ratio to be less than or equal to 70 percent. Interest is at a rate equal to the Term SOFR rate, plus 85.0 basis points, or an alternate base rate.
Long-Term Borrowings and Other Financing Instruments
Generally, the property of NSP-Minnesota, NSP-Wisconsin, PSCo and SPS is subject to the liens of their respective first mortgage indentures for the benefit of bondholders.
Debt premiums, discounts and expenses are amortized over the life of the related debt. The premiums, discounts and expenses for refinanced debt are deferred and amortized over the life of the new issuance.
Long-term debt obligations for Xcel Energy Inc. and its utility subsidiaries as of Dec. 31 (in millions of dollars, except interest rates):
Xcel Energy Inc.
Financing InstrumentInterest RateMaturity Date20252024
Unsecured senior notes3.30 %June 1, 2025$— $250 
Unsecured senior notes3.30 June 1, 2025— 350 
Unsecured senior notes3.35 Dec. 1, 2026500 500 
Unsecured senior notes1.75 March 15, 2027500 500 
Unsecured senior notes4.00 June 15, 2028130 130 
Unsecured senior notes (a)
4.75 March 21, 2028350 — 
Unsecured senior notes4.00 June 15, 2028500 500 
Unsecured senior notes2.60 Dec. 1, 2029500 500 
Unsecured senior notes3.40 June 1, 2030600 600 
Unsecured senior notes2.35 Nov. 15, 2031300 300 
Unsecured senior notes4.60 June 1, 2032700 700 
Unsecured senior notes5.45 Aug. 15, 2033800 800 
Unsecured senior notes (b)
5.50 March 15, 2034800 800 
Unsecured senior notes (a)
5.60 April 15, 2035750 — 
Unsecured senior notes6.50 July 1, 2036300 300 
Unsecured senior notes4.80 Sept. 15, 2041250 250 
Unsecured senior notes3.50 Dec. 1, 2049500 500 
Junior subordinated notes (a) (c)
6.25 Oct. 15, 2085900 — 
Unamortized discount(10)(9)
Unamortized debt issuance cost(38)(34)
Current maturities (500)(600)
Total long-term debt$7,832 $6,337 
(a)2025 financing.
(b)2024 financing.
(c)The notes may be redeemed at par value on or after Oct. 15, 2030.
NSP-Minnesota
Financing InstrumentInterest RateMaturity Date20252024
First mortgage bonds7.125 %July 1, 2025$— $250 
First mortgage bonds6.50 March 1, 2028150 150 
First mortgage bonds2.25 April 1, 2031425 425 
First mortgage bonds (a)
5.05 May 15, 2035600 — 
First mortgage bonds5.25 July 15, 2035250 250 
First mortgage bonds6.25 June 1, 2036400 400 
First mortgage bonds6.20 July 1, 2037350 350 
First mortgage bonds5.35 Nov. 1, 2039300 300 
First mortgage bonds4.85 Aug. 15, 2040250 250 
First mortgage bonds3.40 Aug. 15, 2042500 500 
First mortgage bonds4.125 May 15, 2044300 300 
First mortgage bonds4.00 Aug. 15, 2045300 300 
First mortgage bonds3.60 May 15, 2046350 350 
First mortgage bonds3.60 Sept. 15, 2047600 600 
First mortgage bonds2.90 March 1, 2050600 600 
First mortgage bonds2.60 June 1, 2051700 700 
First mortgage bonds3.20 April 1, 2052425 425 
First mortgage bonds4.50 June 1, 2052500 500 
First mortgage bonds5.10 May 15, 2053800 800 
First mortgage bonds (b)
5.40 March 15, 2054700 700 
First mortgage bonds (a)
5.65 May 15, 2055500 — 
Other long-term debt1 2 
Long-term debt — related parties principal amount outstanding2.60 - 4.1252044 - 2052(953)(166)
Unamortized discount(50)(49)
Unamortized debt issuance cost(90)(80)
Current maturities— (250)
Total long-term debt$7,908 $7,607 
(a)2025 financing.
(b)2024 financing.
NSP-Wisconsin
Financing InstrumentInterest RateMaturity Date20252024
First mortgage bonds6.375 %Sept. 1, 2038$200 $200 
First mortgage bonds3.70 Oct. 1, 2042100 100 
First mortgage bonds3.75 Dec. 1, 2047100 100 
First mortgage bonds4.20 Sept. 1, 2048200 200 
First mortgage bonds3.05 May 1, 2051100 100 
First mortgage bonds2.82 May 1, 2051100 100 
First mortgage bonds4.86 Sept. 15, 2052100 100 
First mortgage bonds5.30 June 15, 2053125 125 
First mortgage bonds (a)
5.65 June 15, 2054400 400 
First mortgage bonds (b)
5.65 June 15, 2054250 — 
Unamortized discount(10)(4)
Unamortized debt issuance cost(18)(15)
Total long-term debt$1,647 $1,406 
(a)2024 financing.
(b)2025 financing.
PSCo
Financing InstrumentInterest RateMaturity Date20252024
First mortgage bonds2.90 %May 15, 2025$— $250 
First mortgage bonds3.70 June 15, 2028350 350 
First mortgage bonds1.90 Jan. 15, 2031375 375 
First mortgage bonds1.875 June 15, 2031750 750 
First mortgage bonds4.10 June 1, 2032300 300 
First mortgage bonds (a)
5.35 May 15, 2034400 — 
First mortgage bonds (b)
5.35 May 15, 2034450 450 
First mortgage bonds (a)
5.15 Sep 15, 2035800 — 
First mortgage bonds6.25 Sept. 1, 2037350 350 
First mortgage bonds6.50 Aug. 1, 2038300 300 
First mortgage bonds4.75 Aug. 15, 2041250 250 
First mortgage bonds3.60 Sept. 15, 2042500 500 
First mortgage bonds3.95 March 15, 2043250 250 
First mortgage bonds4.30 March 15, 2044300 300 
First mortgage bonds3.55 June 15, 2046250 250 
First mortgage bonds3.80 June 15, 2047400 400 
First mortgage bonds4.10 June 15, 2048350 350 
First mortgage bonds4.05 Sept. 15, 2049400 400 
First mortgage bonds3.20 March 1, 2050550 550 
First mortgage bonds2.70 Jan. 15, 2051375 375 
First mortgage bonds4.50 June 1, 2052400 400 
First mortgage bonds5.25 April 1, 2053850 850 
First mortgage bonds (b)
5.75 May 15, 2054750 750 
First mortgage bonds (a)
5.85 May 15, 2055800 — 
Unamortized discount(42)(42)
Unamortized debt issuance cost(82)(67)
Current maturities— (250)
Total long-term debt$10,376 $8,391 
(a)2025 financing.
(b)2024 financing.
SPS
Financing InstrumentInterest RateMaturity Date20252024
Unsecured senior notes6.00 %Oct. 1, 2033$100 $100 
First mortgage bonds (a)
5.30 May 15, 2035500 — 
Unsecured senior notes6.00 Oct. 1, 2036250 250 
First mortgage bonds4.50 Aug. 15, 2041200 200 
First mortgage bonds4.50 Aug. 15, 2041100 100 
First mortgage bonds4.50 Aug. 15, 2041100 100 
First mortgage bonds3.40 Aug. 15, 2046300 300 
First mortgage bonds3.70 Aug. 15, 2047450 450 
First mortgage bonds4.40 Nov. 15, 2048300 300 
First mortgage bonds3.75 June 15, 2049300 300 
First mortgage bonds3.15 May 1, 2050350 350 
First mortgage bonds3.15 May 1, 2050250 250 
First mortgage bonds5.15 June 1, 2052200 200 
First mortgage bonds6.00 Sept. 15, 2053100 100 
First mortgage bonds (b)
6.00 June 1, 2054600 600 
Unamortized discount(14)(14)
Unamortized debt issuance cost(40)(35)
Total long-term debt$4,046 $3,551 
(a)2025 financing.
(b)2024 financing.
Other Subsidiaries
Financing InstrumentInterest RateMaturity Date20252024
Various Eloigne affordable housing project notes0.00% - 8.50%2026 - 2055$24 $27 
Current maturities(1)(3)
Total long-term debt$23 $24 
Maturities of long-term debt:
(Millions of Dollars)
2026$501 
2027501 
20281,483 
2029503 
2030600 
Xcel Energy Inc.’s Purchase of NSP-Minnesota’s First Mortgage Bonds — During 2024, Xcel Energy Inc. purchased $166 million in aggregate principal amounts of NSP-Minnesota’s 2.60% First Mortgage Bonds Series due June 1, 2051 for $105 million.
During 2025, Xcel Energy Inc. purchased $787 million in aggregate principal amounts of NSP-Minnesota’s 4.125% First Mortgage Bonds Series due May 15, 2044, 4.00% First Mortgage Bonds Series due August 15, 2045, 3.60% First Mortgage Bonds Series due May 15, 2046, 2.90% First Mortgage Bonds Series due March 1, 2050, 2.60% First Mortgage Bonds Series due June 1, 2051, and 3.20% First Mortgage Bonds Series due April 1, 2052, for $607 million.
On a consolidated basis, Xcel Energy Inc.’s repurchases of NSP-Minnesota first mortgage bonds were accounted for as debt extinguishments and resulted in pre-tax gains of approximately $162 million and $56 million in the years ended Dec. 31, 2025 and 2024, respectively, net of unamortized discount and debt issuance costs. Interest expense related to the repurchased bonds was $6 million and immaterial for the years ended Dec. 31, 2025 and 2024, respectively.
Deferred Financing Costs — Deferred financing costs of approximately $270 million and $235 million, net of amortization, are presented as a deduction from the carrying amount of long-term debt as of Dec. 31, 2025 and 2024, respectively.
ATM Equity Offering — 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 2023, 3.1 million shares of common stock were issued ($188 million in net proceeds and $2 million in transaction fees paid). In 2024, 18.3 million shares of common stock were issued ($1.10 billion in net proceeds and $9 million in transaction fees paid). In 2025, 16.4 million shares ($1.16 billion in net proceeds and $9 million in transaction fees paid) were issued under the ATM program. As of August 1, 2025, no further transactions will occur under this ATM program.
In August 2025, Xcel Energy Inc. filed a prospectus supplement under which it may sell up to $4 billion of its common stock through an ATM program. As of Dec. 31, 2025, Xcel Energy Inc. has issued 1.9 million shares of common stock ($142 million in net proceeds and $1 million in transaction fees paid) to or through its sales agents under the 2025 ATM program. In addition to these immediate issuances and sales of shares of common stock, Xcel Energy Inc. also may use the 2025 ATM program to enter into forward sale agreements under separate forward sale agreements between Xcel Energy Inc. and a banking counterparty. See below for information regarding shares issued or expected to be issued under forward sale agreements entered through Dec. 31, 2025.
Equity through DRIP and Benefits Program — Xcel Energy issued $67 million of equity in both 2025 and 2024 through the DRIP and benefits programs. The program allows shareholders to reinvest their dividends directly in Xcel Energy Inc. common stock.
Forward Equity Agreements — Xcel Energy Inc. has entered into multiple forward sale agreements in 2025 and 2024 in connection with completed public offerings of Xcel Energy common stock.
During the year ended Dec. 31, 2025, Xcel Energy Inc. physically settled its obligations under the following forward sale agreements (in millions of dollars, except per share data):
Agreements EnteredCommon Shares (in millions)Forward Sale Price per ShareCash Proceeds at Settlement
Forward sale agreements settled in December 2025:
2024 forward equity agreements21.1 $64.70 - 64.76$1,364 
2025 forward equity agreements8.9 71.91 - 80.97684
30.0 $2,048 
The following forward sale agreements remain outstanding as of Dec. 31, 2025:
Agreements EnteredCommon Shares (in millions)Final Maturity
Minimum Expected Proceeds (millions of dollars)
2025 forward equity agreements (a)
12.2
Feb. 2026 to Dec. 2028 (b)
935 
(c)
2025 collared forward equity agreements (a)
15.1Dec. 20261,084 
(d)
(a)Entered under the 2025 ATM prospectus supplement.
(b)Xcel Energy may settle the agreements at any time until final maturity.
(c)Actual cash proceeds will be impacted by the timing of settlement. Forward prices are based on the public offering price (net of underwriting fees), increased for the overnight bank funding rate, less a spread and less expected dividends on Xcel Energy’s common stock during the period the agreements are outstanding.
(d)Pricing for the physical delivery of common shares will be based on an average market price for Xcel Energy’s common stock during a period preceding settlement in December 2026, subject to a cap price and floor price derived from the September 2025 and December 2025 public offerings.
If settled in physical shares, stockholders’ equity equal to cash proceeds will be recorded at settlement.
The 2025 collared forward equity agreements cannot be settled until December 2026, and net cash settlement and net share settlement are generally unavailable. The 2025 forward equity agreements could have been settled at Dec. 31, 2025 with physical delivery of common shares to the banking counterparties in exchange for cash; if Xcel Energy unilaterally elected net cash or net share settlement, these agreements also could have been settled with delivery of cash or shares of common stock to the banking counterparties, as follows:
Pro-Forma/Hypothetical Transactions
Agreements EnteredNet Settlement:Physical Share Delivery Proceeds (millions of dollars)
Common Shares (in millions)Net Cash (millions of dollars)
2025 forward equity agreements0.1$7 $934 
Capital Stock — Preferred stock authorized/outstanding:
Preferred Stock Authorized (Shares)Par Value of Preferred StockPreferred Stock Outstanding (Shares) 2025 and 2024
Xcel Energy Inc.7,000,000 $100 — 
PSCo10,000,000 0.01 — 
SPS10,000,000 1.00 — 
Xcel Energy Inc. had the following common stock authorized/outstanding:
Common Stock Authorized (Shares)Par Value of Common StockCommon Stock Outstanding (Shares) as of Dec. 31, 2025Common Stock Outstanding (Shares) as of Dec. 31, 2024
1,000,000,000 $2.50 623,600,715 574,365,598 
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, 2025:
Equity to Total
Capitalization Ratio
Required Range 		Equity to Total Capitalization Ratio Actual
LowHigh2025
NSP-Minnesota47.25 %57.75 %53.16 %
NSP-Wisconsin (a)
52.50 N/A52.66 
SPS (b)
45.00 55.00 54.47 
(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 EarningsTotal CapitalizationLimit on Total Capitalization
NSP-Minnesota$2,185 $19,547 $22,607 
NSP-Wisconsin12 3,318 N/A
SPS (a)
622 8,888 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, 2025:
(Millions of Dollars)Long-Term DebtShort-Term Debt
NSP-Minnesota (a)
52.8% of total capitalization$3,391 
NSP-Wisconsin$500 150 
PSCo3,500 1,200 
SPS100 

700 
(a)NSP-Minnesota has authorization to issue long-term securities provided the equity-to-total capitalization remains within the required range, and to issue short-term debt provided it does not exceed 15% of total capitalization.
v3.25.4
Revenues
 12 Months Ended
Dec. 31, 2025
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, 2025
(Millions of Dollars)ElectricNatural GasAll OtherTotal
Major revenue types
Revenue from contracts with customers:
Residential$3,904 $1,411 $3 $5,318 
C&I5,948 742 30 6,720 
Other149 — 10 159 
Total retail10,001 2,153 43 12,197 
Wholesale715 — — 715 
Transmission705 — — 705 
Other69 174 — 243 
Total revenue from contracts with customers11,490 2,327 43 13,860 
Alternative revenue and other670 125 14 809 
Total revenues$12,160 $2,452 $57 $14,669 
Year Ended Dec. 31, 2024
(Millions of Dollars)ElectricNatural GasAll OtherTotal
Major revenue types
Revenue from contracts with customers:
Residential$3,552 $1,299 $11 $4,862 
C&I5,420 646 30 6,096 
Other142 — 9 151 
Total retail9,114 1,945 50 11,109 
Wholesale645 — — 645 
Transmission648 — — 648 
Other64 175 — 239 
Total revenue from contracts with customers10,471 2,120 50 12,641 
Alternative revenue and other676 110 14 800 
Total revenues$11,147 $2,230 $64 $13,441 
Year Ended Dec. 31, 2023
(Millions of Dollars)ElectricNatural GasAll OtherTotal
Major revenue types
Revenue from contracts with customers:
Residential$3,560 $1,560 $59 $5,179 
C&I5,703 833 30 6,566 
Other150 — 13 163 
Total retail9,413 2,393 102 11,908 
Wholesale815 — — 815 
Transmission649 — — 649 
Other63 156 — 219 
Total revenue from contracts with customers10,940 2,549 102 13,591 
Alternative revenue and other506 96 13 615 
Total revenues$11,446 $2,645 $115 $14,206 
v3.25.4
Income Taxes
 12 Months Ended
Dec. 31, 2025
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 reconciliation for years ended Dec. 31:
(Millions of Dollars)202520242023
Income before income taxes (domestic)$1,773 $1,534 $1,625 
Federal statutory rate impact372 322 341 
(Decreases) increases in tax from:
Tax credits
PTCs (a)
(569)(663)(455)
Other(14)(16)(17)
Regulatory adjustments (b)
Plant related excess deferred taxes(87)(87)(83)
AFUDC equity(58)(34)(19)
Other29 14 17 
State income taxes, net of federal tax effect (c)
78 58 73 
Other4 4 (3)
Income tax benefit$(245)$(402)$(146)
202520242023
Federal statutory rate21.0 %21.0 %21.0 %
(Decreases) increases in tax from:
Tax credits
PTCs (a)
(32.3)(43.2)(28.1)
Other(0.8)(1.1)(1.1)
Regulatory adjustments (b)
Plant related excess deferred taxes(4.9)(5.6)(5.1)
AFUDC equity(3.2)(2.2)(1.2)
Other1.6 0.9 1.0 
State income taxes, net of federal tax effect (c)
4.4 3.8 4.5 
Other0.4 0.2 — 
Effective income tax rate(13.8)%(26.2)%(9.0)%
(a)Wind, Solar and Nuclear PTCs (net of transfer discounts) are generally credited to customers (reduction to revenue) and do not materially impact earnings.
(b)Regulatory adjustments primarily relate to the credit of plant related excess deferred taxes to customers for tax rate increases as well as the capitalization of AFUDC equity for book purposes only. Income tax benefits associated with the credit of excess deferred taxes are offset by corresponding revenue reductions.
(c)State and local income taxes are primarily made up of the following jurisdictions: Minnesota, Colorado
Components of income tax expense for years ended Dec. 31:
(Millions of Dollars)202520242023
Current federal tax (benefit) expense$(6)$36 $113 
Current state tax expense2 28 16 
Current change in unrecognized tax expense (benefit)1 2 (21)
Deferred federal tax benefit(333)(510)(331)
Deferred state tax expense96 46 75 
Deferred change in unrecognized tax (benefit) expense(1)— 7 
Deferred ITCs(4)(4)(5)
Total income tax benefit$(245)$(402)$(146)
Components of deferred income tax expense as of Dec. 31:
(Millions of Dollars)202520242023
Deferred tax expense excluding items below$685 $434 $129 
Adjustments to deferred income taxes for tax credit cash transfers(652)(689)(190)
Amortization and adjustments to deferred income taxes on income tax regulatory assets and liabilities(269)(201)(188)
Tax expense allocated to other comprehensive income and other(2)(8)— 
Deferred tax benefit$(238)$(464)$(249)
Components of net deferred tax liability as of Dec. 31:
(Millions of Dollars)2025
2024(a)
Deferred tax liabilities:
Differences between book and tax bases of property$7,587 $7,008 
Regulatory assets500 559 
Operating lease assets232 282 
Pension expense171 155 
Other98 93 
Total deferred tax liabilities$8,588 $8,097 
Deferred tax assets:
Tax credit carryforward$1,546 $1,589 
Regulatory liabilities663 744 
Operating lease liabilities231 282 
Other employee benefits116 102 
Deferred ITCs10 11 
NOL carryforward1 1 
NOL and tax credit valuation allowances(74)(73)
Other91 122 
Total deferred tax assets2,584 2,778 
Net deferred tax liability$6,004 $5,319 
(a)Prior periods have been reclassified to conform to current year presentation.
Cash received (paid) for income taxes for the years ended Dec. 31:
(Millions of Dollars)202520242023
Cash received for income taxes: federal, net (a)
$671 $633 $104 
Cash paid for income taxes: state(30)(45)(12)
Total$641 $588 $92 
(a)Includes proceeds from tax credit transfers.
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)20252024
Federal tax credit carryforwards$1,474 $1,519 
Valuation allowances for federal credit carryforwards(10)(14)
State NOL carryforwards8 9 
Valuation allowances for state NOL carryforwards(5)(2)
State tax credit carryforwards, net of federal detriment (a)
71 70 
Valuation allowances for state credit carryforwards, net of federal benefit (b)
(64)(58)
(a)State tax credit carryforwards are net of federal detriment of $19 million as of Dec. 31, 2025 and 2024.
(b)Valuation allowances for state tax credit carryforwards were net of federal benefit of $17 million and $16 million as of Dec. 31, 2025 and 2024, respectively.
Federal carryforward periods expire between 2038 and 2045. State carryforward periods, not including those with indefinite carryforward periods, expire between 2026 and 2038.
Unrecognized Tax Benefits
Federal Audit — In 2023 the IRS issued its Revenue Agent’s Report related to the federal tax loss carryback claim. The Company materially agreed with the report and re-recognized the related benefit in 2023.
Statute of limitations applicable to Xcel Energy’s consolidated federal income tax returns expire as follows:
Tax YearExpiration
2022September 2026
Additionally, the statute of limitations related to federal tax credit carryforwards will remain open until those credits are utilized in subsequent returns.
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, 2025, Xcel Energy’s earliest open tax years (subject to examination by state taxing authorities in its major operating jurisdictions) were as follows:
StateTax Year(s)Expiration
Colorado2014 - 2016March 2026
Colorado2021October 2026
Minnesota2021June 2026
Texas2020June 2028
Texas2021June 2029
Texas2022August 2027
Texas2023November 2028
Wisconsin2021October 2026
•In 2025, Minnesota began an audit of tax years 2021-2023. As of Dec. 31, 2025, no material adjustments have been proposed.
•In 2021, Texas began an audit of tax years 2016 - 2019. As of Dec. 31, 2025, no material adjustments have been proposed.
•In 2021, Wisconsin began an audit of tax years 2016-2019. As of Dec. 31, 2025, no material adjustments have been proposed.
•No other state income tax audits are in progress for its major operating jurisdictions as of Dec. 31, 2025.
Unrecognized tax benefit balance may include permanent tax positions, which if recognized would affect the ETR. In addition, the unrecognized tax benefit balance may include 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, 2025Dec. 31, 2024
Unrecognized tax benefit — Permanent tax positions$43 $43 
Unrecognized tax benefit — Temporary tax positions— — 
Total unrecognized tax benefit$43 $43 
Changes in unrecognized tax benefits:
(Millions of Dollars)202520242023
Balance at Jan. 1$43 $41 $67 
Additions based on tax positions related to the current year 3 5 5 
Additions for tax positions of prior years2 2 1 
Reductions for tax positions of prior years(5)(3)(29)
Reductions for tax positions related to settlements with taxing authorities— — (1)
Reductions for tax positions related to statute of limitations— (2)(2)
Balance at Dec. 31$43 $43 $41 
Unrecognized tax benefits were reduced by tax benefits associated with NOL and tax credit carryforwards:
(Millions of Dollars)Dec. 31, 2025Dec. 31, 2024
NOL and tax credit carryforwards$(33)$(35)
Payable for interest related to unrecognized tax benefits is partially offset by the interest benefit associated with NOL and tax credit carryforwards.
Interest payable related to unrecognized tax benefits:
(Millions of Dollars)202520242023
Payable for interest related to unrecognized tax benefits at Jan. 1$(2)$(1)$(4)
Interest (expense) benefit related to unrecognized tax benefits(2)(1)3 
Payable for interest related to unrecognized tax benefits at Dec. 31$(4)$(2)$(1)
Penalties accrued related to unrecognized tax benefits as of Dec. 31, 2025 were not material. No penalties were accrued related to unrecognized tax benefits as of Dec. 31, 2024 or 2023.
v3.25.4
Share-Based Compensation
 12 Months Ended
Dec. 31, 2025
Share-Based Payment Arrangement [Abstract]  
Share-Based Compensation
Incentive Plan Including Share-Based Compensation — Xcel Energy has authorized 13.0 million shares under the Xcel Energy Inc. 2024 Equity Incentive Plan for grants made on May 22, 2024 or later and 6.0 million shares under the Amended and Restated 2015 Omnibus Incentive Plan for grants made prior to May 22, 2024.
Xcel Energy‘s Board of Directors has granted share based awards under these plans, which include various service, performance and market conditions. Following measurement at the end of a three-year restricted period settlement in shares or cash will occur if these conditions are met.
Awards granted in 2023 and 2024 with conditions incremental to service requirements contain goals based on environmental performance or Xcel Energy TSR relative to a peer group of utility companies. For 2025, awards with conditions incremental to service contain goals based on EPS, operations and environmental performance, each with adjustments for relative TSR ranking.
Equity award units granted to employees:
(Units in Thousands)202520242023
Granted units (a)
683 658 586 
Weighted average grant date fair value$68.19 $63.02 $67.06 
(a)Includes 2025, 2024 and 2023 grants of 379, 457 and 413 units (each in thousands), respectively, subject only to service conditions.
Equity awards vested:
(Units in Thousands, Fair Value in Millions)202520242023
Vested Units502 282 329 
Total Fair Value$37 $19 $20 
Changes in the nonvested portion of equity award units:
(Units in Thousands)UnitsWeighted Average
Grant Date Fair Value
Nonvested Units at Jan. 1, 20251,139 $64.55 
Granted683 68.19 
Forfeited(170)65.85 
Vested(502)66.27 
Dividend equivalents62 65.85 
Nonvested Units at Dec. 31, 20251,212 65.77 
Liability awards granted:
(In Thousands)202520242023
Awards granted (a)
109 193 216 
(a)All grants contain performance and/or market conditions.
Liability awards settled:
(Units In Thousands, Settlement Amount in Millions)202520242023
Awards settled74 — 282 
Settlement amount (cash, common stock and deferred amounts)$5 $— $19 
The amount of cash used to settle liability awards in 2025 was $2 million.
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)202520242023
Granted units32 44 38 
Weighted average grant date fair value$70.68 $57.03 $63.12 
Changes in stock equivalent units:
(Units in Thousands)UnitsWeighted Average
Grant Date Fair Value
Stock equivalent units at Jan. 1, 2025528 $48.68 
Granted32 70.68 
Units distributed(53)52.88 
Dividend equivalents16 71.79 
Stock equivalent units at Dec. 31, 2025523 50.31 
Share-Based Compensation Expense — Award settlement determination (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. The grant date fair value of equity awards is expensed over the service period.
Awards with history of past settlement in cash or features that result in normal course cash settlement are accounted for as liability awards. For liability awards, the fair value expensed over the service period is remeasured periodically based on the expected cash settlement amounts.
Compensation costs related to share-based awards:
(Millions of Dollars)202520242023
Cost for share-based awards (a)
$57 $30 $27 
Tax benefit recognized in income15 8 7 
(a)Compensation costs for share-based payments are included in O&M expense. Amount for equity awards (non-cash) was $46 million, $33 million and $25 million in 2025, 2024 and 2023, respectively.
There was approximately $52 million and $38 million as of Dec. 31, 2025 and 2024, respectively, of total unrecognized compensation cost related to nonvested share-based compensation awards. Xcel Energy expects to recognize this amount over a weighted average period of 1.7 years.
v3.25.4
Earnings Per Share
 12 Months Ended
Dec. 31, 2025
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 forward equity agreements, collared equity agreements and 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)202520242023
Basic 587 563552
Diluted (a)
589 563 552 
(a)Diluted common shares outstanding included common stock equivalents of 2.1 million, 0.5 million, and 0.3 million shares for 2025, 2024 and 2023, respectively.
v3.25.4
Fair Value of Financial Assets and Liabilities
 12 Months Ended
Dec. 31, 2025
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 and partnerships 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 or as a regulatory liability (dependent on funding status) 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/liability.
Unrealized gains for the nuclear decommissioning fund were $1.8 billion and $1.4 billion as of Dec. 31, 2025 and 2024, respectively, and unrealized losses were $47 million and $49 million as of Dec. 31, 2025 and 2024, respectively.
Non-derivative instruments with recurring fair value measurements in the nuclear decommissioning fund:
Dec. 31, 2025
Fair Value
(Millions of Dollars)CostLevel 1Level 2Level 3NAVTotal
Nuclear decommissioning fund (a)
Cash equivalents$60 $60 $— $— $— $60 
Commingled funds720 — — — 1,072 1,072 
Debt securities944 — 934 11 — 945 
Equity securities505 1,861 2 — — 1,863 
Total$2,229 $1,921 $936 $11 $1,072 $3,940 
(a)Reported in nuclear decommissioning fund and other investments on the consolidated balance sheets, which also includes $285 million of equity method investments and $164 million of rabbi trust assets and other miscellaneous investments.
Dec. 31, 2024
Fair Value
(Millions of Dollars)CostLevel 1Level 2Level 3NAVTotal
Nuclear decommissioning fund (a)
Cash equivalents$39 $39 $— $— $— $39 
Commingled funds703 — — — 1,025 1,025 
Debt securities866 — 832 14 — 846 
Equity securities522 1,583 1 — — 1,584 
Total$2,130 $1,622 $833 $14 $1,025 $3,494 
(a)Reported in nuclear decommissioning fund and other investments on the consolidated balance sheets, which also includes $246 million of equity investments in unconsolidated subsidiaries and $156 million of rabbi trust assets and other miscellaneous investments.
For the years ended Dec. 31, 2025 and 2024, 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, 2025:
Final Contractual Maturity
(Millions of Dollars)Due in 1 Year or LessDue in 1 to 5 YearsDue in 5 to 10 YearsDue after 10 YearsTotal
Debt securities$10 $344 $292 $299 $945 
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 $107 million and $96 million at Dec. 31, 2025 and 2024, 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, 2025, 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, 2025, Xcel Energy had unsettled interest rate derivatives with a notional amount of $240 million.
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.
Results of derivative instrument transactions 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, 2025 and 2024 for this purpose relate to FTR instruments administered by MISO and SPP. These instruments are intended to offset the impacts of transmission system congestion.
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, 2025, 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, 2025Dec. 31, 2024
MWh of electricity35 38 
MMBtu of natural gas31 77 
(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’ often have significant concentrations of credit risk with particular entities or industries in their wholesale, trading and non-trading commodity activities.
As of Dec. 31, 2025, three of Xcel Energy’s ten most significant counterparties for these activities, comprising $22 million or 14% of this credit exposure, had investment grade credit ratings from S&P Global Ratings, Moody’s Investor Services or Fitch Ratings.
Six of the ten most significant counterparties, comprising $92 million or 57% 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 $25 million or 15% of this credit exposure, had credit quality less than investment grade, based on internal analysis.
Nine 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, 2025 and 2024, there were $7 million and $11 million, respectively, of derivative liabilities with such underlying contract provisions, respectively.
Certain contracts also contain cross default provisions that may require the posting of collateral or settlement of the contracts if there was a failure under other financing arrangements related to payment terms or other covenants.
As of Dec. 31, 2025 and 2024, there were approximately $62 million and $69 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, 2025 and 2024.
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 LossRegulatory (Assets) and Liabilities
Year Ended Dec. 31, 2025
Derivatives designated as cash flow hedges
Interest rate$2 $— 
Total$2 $— 
Other derivative instruments
Electric commodity$— $69 
Natural gas commodity— (3)
Total$— $66 
Year Ended Dec. 31, 2024
Interest rate$29 $— 
Total$29 $— 
Other derivative instruments
Electric commodity$— $44 
Natural gas commodity— 4 
Total$— $48 
Year Ended Dec. 31, 2023
Interest rate$(2)$— 
Total$(2)$— 
Other derivative instruments
Electric commodity$— $(137)
Natural gas commodity— (13)
Total$— $(150)
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 LossRegulatory Assets and (Liabilities)
Year Ended Dec. 31, 2025
Derivatives designated as cash flow hedges
Interest rate$3 
(a)
$— $— 
Total$3 $— $— 
Other derivative instruments
Commodity trading$— $— $(3)
(b)
Electric commodity— (36)
(c)
— 
Natural gas commodity— — (22)
(d)(e)
Total$— $(36)$(25)
Year Ended Dec. 31, 2024
Derivatives designated as cash flow hedges
Interest rate$3 
(a)
$— $— 
Total$3 $— $— 
Other derivative instruments
Commodity trading$— $— $(27)
(b)
Electric commodity— (22)
(c)
— 
Natural gas commodity— — (22)
(d)(e)
Total$— $22 $(49)
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)
(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 auction and settlement dates, but exclude the original auction fair value.
(d)Other than $4 million of 2025 and $3 million of 2024 losses recorded to electric fuel and purchased power, amounts are recorded to cost of natural gas sold and transported. Amounts are subject to cost-recovery mechanisms and reclassified out of income to a regulatory asset, as appropriate.
(e)Relates primarily to option premium amortization.
Xcel Energy had no derivative instruments designated as fair value hedges during the years ended Dec. 31, 2025, 2024 and 2023.
Derivative assets and liabilities measured at fair value on a recurring basis were as follows:
Dec. 31, 2025Dec. 31, 2024
Fair ValueFair Value Total
Netting (a)
TotalFair ValueFair Value Total
Netting (a)
Total
(Millions of Dollars)Level 1Level 2Level 3Level 1Level 2Level 3
Current derivative assets
Derivatives designated as cash flow hedges:
Interest rate$— $1 $— $1 $— $1 $— $— $— $— $— $— 
Other derivative instruments:
Commodity trading$2 $13 $7 $22 $(16)$6 $6 $20 $8 $34 $(23)$11 
Electric commodity— — 147 147 (3)144 — — 90 90 (1)89 
Natural gas commodity— 14 — 14 — 14 — 14 — 14 — 14 
Total current derivative assets$2 $28 $154 $184 $(19)$165 $6 $34 $98 $138 $(24)$114 
Noncurrent derivative assets
Other derivative instruments:
Commodity trading$3 $28 $34 $65 $(11)$54 $8 $37 $47 $92 $(20)$72 
Total noncurrent derivative assets$3 $28 $34 $65 $(11)$54 $8 $37 $47 $92 $(20)$72 
Dec. 31, 2025Dec. 31, 2024
Fair ValueFair Value Total
Netting (a)
TotalFair ValueFair Value Total
Netting (a)
Total
(Millions of Dollars)Level 1Level 2Level 3Level 1Level 2Level 3
Current derivative liabilities
Other derivative instruments:
Commodity trading5 22 6 33 (18)15 7 35 5 47 (23)24 
Electric commodity— — 3 3 (3)— — — 1 1 (1)— 
Natural gas commodity— 10 — 10 — 10 — 7 — 7 — 7 
Total current derivative liabilities$5 $32 $9 $46 $(21)25 $7 $42 $6 $55 $(24)31 
PPAs (b)
6 6 
Current derivative instruments$31 $37 
Noncurrent derivative liabilities
Other derivative instruments:
Commodity trading$6 $24 $40 $70 $(13)$57 $11 $32 $40 $83 $(22)$61 
Total noncurrent derivative liabilities$6 $24 $40 $70 $(13)57 $11 $32 $40 $83 $(22)61 
PPAs (b)
10 16 
Noncurrent derivative instruments$67 $77 
    
(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, 2025 and 2024, derivative assets and liabilities include no obligations to return cash collateral. At Dec. 31, 2025 and 2024, derivative assets and liabilities include rights to reclaim cash collateral of $4 million and $2 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)202520242023
Balance at Jan. 1$99 $90 $236 
Purchases (a)
262 210 176 
Settlements (a)
(322)(303)(154)
Net transactions recorded during the period:
(Losses) gains recognized in earnings (b)
(13)(9)6 
Net gains (losses) recognized as regulatory assets and liabilities (a)
113 111 (174)
Balance at Dec. 31$139 $99 $90 
(a)Relates primarily to NSP-Minnesota and SPS FTR instruments administered by MISO and SPP, respectively.
(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:
20252024
(Millions of Dollars)Carrying AmountFair ValueCarrying AmountFair Value
Long-term debt, including current portion$32,333 $29,943 $28,419 $25,115 
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, 2025 and 2024, and given the observability of the inputs, fair values presented for long-term debt were assigned as Level 2.
v3.25.4
Benefit Plans and Other Postretirement Benefits
 12 Months Ended
Dec. 31, 2025
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 4.76, 4.90 and 4.72% in 2025, 2024, and 2023, 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 nonqualified pension plan, which 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 nonqualified plan as of Dec. 31, 2025 and 2024 were $13 million. Xcel Energy recognized net benefit cost for the nonqualified plan of $3 million in 2025 and $2 million in 2024.
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 2025 were above the assumed level of 7.13%.
•Investment returns in 2024 were below the assumed level of 6.93%.
•Investment returns in 2023 were above the assumed level of 6.93%.
•In 2026, expected investment-return assumption is 7.13%.
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, 2025 (a)
Dec. 31, 2024 (a)
(Millions of Dollars)Level 1Level 2Level 3Measured at NAVTotalLevel 1Level 2Level 3Measured at NAVTotal
Cash equivalents$110 $— $— $— $110 $117 $— $— $— $117 
Commingled funds (b)
— — — 1,097 1,097 — — — 1,015 1,015 
Debt securities— 745 3 — 748 — 656 6 — 662 
Equity securities23 — — — 23 25 — — — 25 
Partnerships (b)
— — — 704 704 — — — 679 679 
Other— 8 — — 8 — 6 — — 6 
Total$133 $753 $3 $1,801 $2,690 $142 $662 $6 $1,694 $2,504 
(a)See Note 10 for further information regarding fair value measurement inputs and methods.
(b)Prior period amounts have been reclassified to conform with current year presentation.
For each of the fair value hierarchy levels, Xcel Energy’s postretirement benefit plan assets that were measured at fair value:
Dec. 31, 2025 (a)
Dec. 31, 2024 (a)
(Millions of Dollars)Level 1Level 2Level 3Measured at NAVTotalLevel 1Level 2Level 3Measured at NAVTotal
Cash equivalents$35 $— $— $— $35 $35 $— $— $— $35 
Insurance contracts— 40 — — 40 — 40 — — 40 
Commingled funds (b)
— — — 67 67 — — — 23 23 
Debt securities— 154 — — 154 — 201 — — 201 
Partnerships (b)
— — — 45 45 — — — 45 45 
Other— 1 — — 1 — — — — — 
Total$35 $195 $— $112 $342 $35 $241 $— $68 $344 
(a)See Note 10 for further information on fair value measurement inputs and methods.
(b)Prior period amounts have been reclassified to conform with current year presentation.
Immaterial assets were transferred in or out of Level 3 for 2025 and 2024.
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 BenefitsPostretirement Benefits
(Millions of Dollars)2025202420252024
Change in Benefit Obligation:
Obligation at Jan. 1$2,752 $2,943 $427 $394 
Service cost76 76 1 1 
Interest cost155 151 24 21 
Actuarial loss (gain) 67 (77)21 55 
Plan participants’ contributions— — 9 9 
Medicare subsidy reimbursements— — 3 — 
Benefit payments(230)(341)
(a)
(55)(53)
Obligation at Dec. 31$2,820 $2,752 $430 $427 
Change in Fair Value of Plan Assets:
Fair value of plan assets at Jan. 1$2,504 $2,690 $344 $356 
Actual return on plan assets291 55 31 21 
Employer contributions125 100 13 11 
Plan participants’ contributions— — 9 9 
Benefit payments(230)(341)(55)(53)
Fair value of plan assets at Dec. 312,690 2,504 342 344 
Funded status of plans at Dec. 31$(130)$(248)$(88)$(83)
Amounts recognized in the Consolidated Balance Sheet at Dec. 31:
Noncurrent assets$— $— $7 $10 
Current liabilities— — (2)(4)
Noncurrent liabilities(130)(248)(93)(89)
Net amounts recognized$(130)$(248)$(88)$(83)
(a)Includes $168 million of lump-sum benefit payments used in the determination of settlement charges in 2024.
Pension BenefitsPostretirement Benefits
Significant Assumptions Used to Measure Benefit Obligations:2025202420252024
Discount rate for year-end valuation5.78 %5.88 %5.66 %5.88 %
Expected average long-term increase in compensation level4.25 %4.25 %N/AN/A
Mortality tablePRI-2012PRI-2012PRI-2012PRI-2012
Health care costs trend rate — initial: Pre-65N/AN/A7.00 %7.00 %
Health care costs trend rate — initial: Post-65N/AN/A7.50 %7.50 %
Ultimate trend assumption — initial: Pre-65N/AN/A4.50 %4.50 %
Ultimate trend assumption — initial: Post-65N/AN/A4.50 %4.50 %
Years until ultimate trend is reachedN/AN/A89
Accumulated benefit obligation for the pension plan was $2,624 million and $2,554 million as of Dec. 31, 2025 and 2024, respectively.
Net Periodic Benefit Cost — Net periodic benefit cost, other than the service cost component, is included in other income (expense) in the consolidated statements of income.
Components of net periodic benefit cost and amounts recognized in other comprehensive income and regulatory assets and liabilities:
Pension BenefitsPostretirement Benefits
(Millions of Dollars)202520242023202520242023
Service cost$76 $76 $74 $1 $1 $1 
Interest cost155 151 158 24 21 22 
Expected return on plan assets(208)(206)(209)(20)(17)(17)
Amortization of prior service credit(2)(2)(1)— — (1)
Amortization of net loss28 30 22 4 2 1 
Settlement charge (a)
— 67 — — — — 
Net periodic pension cost49 116 44 9 7 6 
Effects of regulation10 (37)30 — — — 
Net benefit cost recognized for financial reporting$59 $79 $74 $9 $7 $6 
Significant Assumptions Used to Measure Costs:
Discount rate5.88 %5.49 %5.80 %5.88 %5.54 %5.80 %
Expected average long-term increase in compensation level4.25 4.25 4.25 — — — 
Expected average long-term rate of return on assets7.13 6.93 6.93 6.25 5.00 5.00 
(a)A settlement charge is required when the amount of all lump-sum distributions during the year is greater than the sum of the service and interest cost components of the annual net periodic pension cost. In 2024, as a result of lump-sum distributions during the plan year, Xcel Energy recorded a total pension settlement charge of $67 million, the majority of which was not recognized due to the effects of regulation. A total of $8 million was recorded in the consolidated statements of income in 2024. There were no settlement charges recorded for the qualified pension plans in 2025 and 2023.
Pension BenefitsPostretirement Benefits
(Millions of Dollars)2025202420252024
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost:
Net loss$1,029 $1,074 $117 $113 
Prior service credit(6)(8)— — 
Total$1,023 $1,066 $117 $113 
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$36 $32 $5 $2 
Noncurrent regulatory assets938 983 125 127 
Current regulatory liabilities— — (1)(1)
Noncurrent regulatory liabilities— — (15)(18)
Deferred income taxes13 14 1 1 
Net-of-tax accumulated other comprehensive income36 37 2 2 
Total$1,023 $1,066 $117 $113 
Measurement dateDec. 31, 2025Dec. 31, 2024Dec. 31, 2025Dec. 31, 2024
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 2023 - 2026 to meet minimum funding requirements.
Voluntary and required pension funding contributions:
•$75 million in January 2026.
•$125 million in 2025.
•$100 million in 2024.
•$50 million in 2023.
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:
•$8 million expected during 2026.
•$13 million during 2025.
•$11 million during 2024.
•$11 million during 2023.
Targeted asset allocations:
Pension BenefitsPostretirement Benefits
2025202420252024
Long-duration fixed income securities38 %38 %— %— %
Domestic and international equity securities30 31 25 25 
Alternative investments19 20 13 11 
Short-to-intermediate fixed income securities11 9 61 61 
Cash2 2 1 3 
Total100 %100 %100 %100 %
The asset allocations above reflect target allocations approved in the calendar year to take effect in the subsequent year.
Plan Amendments — There were no significant plan amendments made in 2025 and 2024 which affected the pension or postretirement benefit obligation.
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.
Projected Benefit Payments
Xcel Energy’s projected benefit payments:
(Millions of  Dollars)Projected
Pension Benefit
Payments		Gross Projected
Postretirement
Health Care
Benefit Payments		Expected
Medicare Part D
Subsidies		Net Projected
Postretirement
Health Care
Benefit Payments
2026$252 $43 $3 $40 
2027243 42 3 39 
2028244 41 3 38 
2029249 40 3 37 
2030243 39 3 36 
2031-20351,165 183 16 167 
Voluntary Retirement Program
Incremental to amounts presented above for postretirement benefits, Xcel Energy has postemployment costs and obligations for its Voluntary Retirement Program, under which approximately 400 eligible non-bargaining employees retired in the fourth quarter of 2023.
Utilizing employee information and the following inputs, unfunded obligations of $22 million and $29 million for health plan subsidies and $4 million and $4 million for other medical benefits are presented in other current liabilities and noncurrent pension and employee benefit obligations in the consolidated balance sheets as of Dec. 31, 2025 and 2024, respectively.
Significant Assumptions to Measure Benefit Obligations:20252024
Discount rate for year-end valuation4.50 %5.00 %
Mortality tablePRI-2012PRI-2012
Health care costs trend rate7.00 %7.00 %
Ultimate trend assumption4.50 %4.50 %
Years until ultimate trend is reached89
Defined Contribution Plans
Xcel Energy maintains 401(k) and other defined contribution plans that cover most employees. Total expense to these plans was approximately $53 million in 2025, $50 million in 2024 and $49 million in 2023.
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.
v3.25.4
Commitments and Contingencies
 12 Months Ended
Dec. 31, 2025
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 open, which is the multi-district litigation matter consisting of a Wisconsin purported class (Arandell Corp.). In October 2025, a settlement in principle was reached, resulting in an immaterial loss consistent with previously accrued amounts. This settlement is subject to court approval.
Marshall Wildfire Litigation — In December 2021, a wildfire ignited in Boulder County, Colorado (Marshall Fire). On June 8, 2023, the Boulder County Sheriff’s Office released its Marshall Fire Investigative Summary and Review and its supporting documents (Sheriff’s Report). 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.
PSCo received notice or otherwise became aware of 307 complaints on behalf of at least 4,087 plaintiffs, most of which also named Xcel Energy Inc. and Xcel Energy Services Inc. as additional defendants, relating to the Marshall Fire. The complaints generally alleged that PSCo’s equipment ignited the Marshall Fire and asserted various causes of action under Colorado law. In addition to asserting claims against PSCo, Xcel Energy Inc. and Xcel Energy Services Inc., various plaintiffs, including insurance company plaintiffs, asserted claims against certain telecommunications companies (the Telecom Companies). In April 2025, most of the remaining plaintiffs amended their complaints to also assert claims against the Telecom Companies. In June 2025, the Boulder County District Court dismissed Xcel Energy Inc. from the complaints that named that entity as a defendant, due to lack of jurisdiction.
An initial trial on liability issues was scheduled to start in September 2025. Prior to trial, in September 2025, Xcel Energy, Qwest Corporation and Teleport Communications America, LLC reached settlement agreements in principle that resolve all claims asserted by the subrogation insurers, the public entity plaintiffs and individual plaintiffs, and require PSCo to make settlement payments of $640 million. PSCo did not admit any fault, wrongdoing or negligence in connection with these settlement agreements.
As a result of settlements as well as legal and other costs of the matter, PSCo recognized charges to earnings of $287 million and $12 million in the quarterly periods ended Sept. 30 and Dec. 31, 2025, respectively, after consideration of total costs expected to be reimbursed by insurance. As of February 2026, final settlement documentation has been executed with the subrogation insurers, the public entity plaintiffs and nearly all the individual plaintiffs, and nearly all have received payment. If complaints of the remaining individual plaintiffs who have not accepted a settlement or have otherwise stopped prosecuting their claims are not resolved, they may be subject to further litigation.
A remaining estimated liability of $5 million is presented in other current liabilities as of Dec. 31, 2025; no estimated liability was recognized as of Dec. 31, 2024. PSCo records insurance recoveries when it is deemed probable that recovery will occur, and PSCo can reasonably estimate the amount or range. Insurance receivables of $353 million related to settlements are presented in prepayments and other current assets as of Dec. 31, 2025; no such insurance receivables were recognized as of Dec. 31, 2024.
2024 Smokehouse Creek Fire Complex — On February 26, 2024, multiple wildfires began in the Texas Panhandle, including the Smokehouse Creek Fire and the 687 Reamer Fire, which burned into the perimeter of the Smokehouse Creek Fire (together, referred to herein as the “Smokehouse Creek Fire Complex”). The Texas A&M Forest Service issued incident reports that determined that the Smokehouse Creek Fire and the 687 Reamer Fire were caused by power lines owned by SPS after wooden poles near each fire origin failed. According to the Texas A&M Forest Service’s Incident Viewer and news reports, the Smokehouse Creek Fire Complex burned approximately 1,055,000 acres.
SPS is aware of approximately 56 complaints, most of which have also named Xcel Energy Services Inc. as an additional defendant, relating to the Smokehouse Creek Fire Complex. The complaints, which assert claims on behalf of one or more plaintiffs, generally allege that SPS’ equipment ignited the Smokehouse Creek Fire Complex and seek compensation for losses resulting from the fire, asserting various causes of action under Texas law. In addition to seeking compensatory damages, certain of the complaints also seek exemplary damages. Of the 56 complaints, 22 have been resolved and dismissed.
SPS has received 296 claims through its claims process, net of duplicative, withdrawn and denied claims, and has reached final settlements on 223 of those claims as of the date of this filing. In addition to filed complaints and claims made through SPS’ claims process, SPS has also received information from attorneys for approximately 101 claims which have not been submitted through the claims process and have also not been filed as lawsuits and has reached settlement of 79 of those claims through mediation.
SPS has settled claims related to both of the fatalities believed to be associated with the Smokehouse Creek Fire Complex. Settlements have also been reached with the subrogated insurer plaintiffs as well as the three largest claims asserted from the fire, as measured by fire-impacted acreage. Settlements reached as of the date of this filing total $382 million of expected loss payments, of which $374 million and $35 million were paid through Dec. 31, 2025 and 2024, respectively.
In December 2025, the Texas Attorney General’s office filed a lawsuit against SPS regarding the Smokehouse Creek Fire, seeking monetary damages and civil penalties for losses to property and wildlife resulting from the fires. In February 2026, pending resolution of the lawsuit, SPS and the Texas Attorney General’s office jointly filed a temporary injunction agreeing to certain distribution pole replacement procedures, largely consistent with current procedures.
Based on the current state of the law and the facts and circumstances available as of the date of this filing, Xcel Energy has recorded $430 million of total estimated losses for the matter (before available insurance). A remaining estimated liability of $56 million and $180 million is presented in other current liabilities as of Dec. 31, 2025 and 2024, respectively.
The cumulative estimated probable losses of $430 million for complaints and claims in connection with the Smokehouse Creek Fire Complex (before available insurance) represents the total of actual settlements reached to date plus the low end of the range for remaining reasonably estimable losses, and is subject to change as additional information becomes available. This $430 million estimate does not include amounts for (i) potential penalties or fines that may be imposed by governmental entities on Xcel Energy, (ii) exemplary or punitive damages, (iii) compensation claims by federal, state, county and local government entities or agencies, (iv) unsettled compensation claims for damage to trees and oil and gas equipment, or (v) other amounts that are not reasonably estimable.
Xcel Energy remains unable to reasonably estimate any additional loss or the upper end of the range because there are a number of unknown facts and legal considerations that may impact the amount of any potential liability, including whether additional complaints and demands may be made. In the event that SPS or Xcel Energy Services Inc. was found liable related to the litigation related to the Smokehouse Creek Fire Complex and was required to pay damages, such amounts could exceed our insurance coverage of approximately $500 million for the annual policy period and could have a material adverse effect on our financial condition, results of operations or cash flows.
The process for estimating losses associated with potential claims related to the Smokehouse Creek Fire Complex requires management to exercise significant judgment based on a number of assumptions and subjective factors, including the factors identified above and estimates based on currently available information and prior experience with wildfires. As more information becomes available, management estimates and assumptions regarding the potential financial impact of the Smokehouse Creek Fire Complex may change.
Texas law does not apply strict liability in determining an electric utility company’s liability for fire-related damages. For negligence claims under Texas law, a public utility has a duty to exercise ordinary and reasonable care.
Potential liabilities related to the Smokehouse Creek Fire Complex depend on various factors, including the cause of the equipment failure and the extent and magnitude of potential damages, including damages to residential and commercial structures, personal property, vegetation, livestock and livestock feed (including replacement feed), personal injuries and any other damages, penalties, fines or restitution that may be imposed by courts or other governmental entities if SPS is found to have been negligent.
SPS records insurance recoveries when it is deemed probable that recovery will occur, and SPS can reasonably estimate the amount or range. Insurance receivables for estimated losses of approximately $195 million and $210 million, net of recoveries received are presented in prepayments and other current assets as of Dec. 31, 2025 and 2024, respectively. While SPS plans to seek recovery of all insured losses, it is unable to predict the ultimate amount and timing of such insurance recoveries.
Nuclear Antitrust Class Action — A class action complaint was filed in federal court for the District of Maryland in July 2025, alleging violations of the Sherman Antitrust Act in establishing wages for employees at nuclear facilities since 2003. The amended complaint names 46 defendants, including 45 entities that allegedly “own and/or operate all 54 commercial nuclear power plants in the United States,” including Xcel Energy Inc., Xcel Energy Services Inc., and NSP-Minnesota. NSP-Minnesota owns and operates two nuclear facilities in Minnesota, and disputes the allegations set forth against it and the other company entities. The litigation is ongoing, and Xcel Energy assesses the risk of a material impact to its consolidated financial statements as remote.
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.
Prairie Island Outage Prudency Review — In March 2024, NSP-Minnesota filed its annual fuel clause adjustment true-up petition to the MPUC. In a response to that petition, intervenors recommended refunds for replacement power costs related to an outage at the Prairie Island generating station (October 2023 through February 2024).
In a September 2024 decision, the MPUC ruled NSP-Minnesota was imprudent in the operation of the Prairie Island nuclear plant based on an incident that resulted in the extended outage. The MPUC did not quantify the refund and referred the determination of the refund amount to the Office of Administrative Hearings. NSP-Minnesota recorded an estimated liability for a customer refund in 2024.
In May 2025, in the resulting case currently before an ALJ to determine the refund amount, NSP-Minnesota submitted direct testimony asserting that no more than $6 million of customer refunds are warranted for the outage.
Rebuttal and surrebuttal testimony were filed in August and September 2025 and final briefs were filed in January 2026. Intervenor briefs included recommendations for customer refunds of approximately $40 million to account for the total impact of the outage on 2023 and 2024. An ALJ report is expected in March 2026, with a MPUC decision expected in the second quarter of 2026.
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 11 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 approximately $15 million of remaining liabilities for resolution of these issues, however, the final outcome and timing are unknown. In addition, there may be regulatory recovery, 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 is subject to the CCR Rule, which imposes requirements for handling, storage, treatment and disposal of coal ash and other solid waste.
In May 2024, final amendments to the CCR Rule were published, widening its scope to include legacy CCR surface impoundments at inactive facilities and previously exempt areas where CCR was placed directly on land at CCR-regulated facilities, including areas of beneficial use.
As a requirement of the CCR Rule, utilities must complete facility evaluations and groundwater sampling around their subject landfills, surface impoundments and certain other areas where coal ash was placed on land.
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 certain active and closed coal-generating facilities at a current estimated cost of at least $45 million. In addition, Xcel Energy expects to incur $15 million for investigations through 2028 to perform required reporting and assess whether corrective actions are necessary. AROs have been recorded for each of these activities, and amounts are expected to be recoverable through regulatory mechanisms.
Xcel Energy has also identified coal ash that is expected to be required to be removed from certain closed coal generating facilities at estimated costs totaling approximately $105 million. AROs have been recorded, with the costs expected to be recoverable through regulatory mechanisms.
Xcel Energy continues to perform site investigation activities related to the CCR Rule, which may result in updates to estimated costs as well as identification of additional required corrective actions.
In February 2026, the EPA issued a final rule amending the CCR Legacy rule. The ruling extends deadlines for various regulatory actions and clarifies previous information regarding implementation of the rule. Xcel Energy is still evaluating the final rule, but anticipates impacts to be consistent with prior accruals.
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 —
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 $3.9 billion and $3.5 billion for 2025 and 2024, respectively.
Xcel Energy’s AROs were as follows:
(Millions 
of Dollars)		Jan. 1, 2025
Amounts Incurred (a)
Accretion
Cash Flow Revisions (b)
Dec. 31, 2025
Electric
Nuclear$2,476 $— $127 $— $2,603 
Wind509 — 18 (12)515 
Steam, hydro and other production495 16 21 (1)531 
Distribution51 — 3 — 54 
Natural gas
Transmission and distribution179 — 9 (6)182 
Other
Miscellaneous3 — — — 3 
Total liability$3,713 $16 $178 $(19)$3,888 
(a)Amounts incurred largely pertain to obligations associated with new solar facilities.
(b)In 2025, AROs were revised for changes in timing and estimates of cash flows. Wind was revised due to the repowering of two wind facilities in NSP-Minnesota.
(Millions 
of Dollars)		Jan. 1, 2024
Amounts Incurred (a)
Amounts
Settled 		Accretion
Cash Flow Revisions (b)
Dec. 31, 2024
Electric
Nuclear$2,107 $— $— $106 $263 $2,476 
Wind526 — — 19 (36)509 
Steam, hydro and other production361 109 (6)18 13 495 
Distribution49 — — 2 — 51 
Natural gas
Transmission and distribution 172 — — 8 (1)179 
Other
Miscellaneous3 — — — — 3 
Total liability$3,218 $109 $(6)$153 $239 $3,713 
(a)Amounts incurred largely pertain to CCR coal ash regulations and new obligations associated with Sherco Solar Unit 1, which was placed in service in 2024.
(b)In 2024, AROs were revised for changes in timing and estimates of cash flows. Changes were driven by updated assumptions in the NSP-Minnesota nuclear decommissioning triennial filing coupled with discount rate and escalation rate changes. Wind, steam, hydro and other production AROs were revised due to the results of the 2024 dismantling studies and changes in cost estimates to remediate ash containment facilities.
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, 2025. 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 $16.3 billion under the Price-Anderson amendment to the Atomic Energy Act. NSP-Minnesota has $500 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 for each of NSP-Minnesota’s two nuclear plant sites. The coverage limits are $2.8 billion for both Monticello and Prairie Island. 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 $21 million for business interruption insurance and $38 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 Prairie Island nuclear plants, which consist of storage pools and dry cask facilities. In October 2023, the MPUC approved additional storage at the Monticello site to support extended operations to 2040. The decommissioning plan addresses the disposition of spent fuel at the end of the licensed life in 2050.
In October 2025, the MPUC approved additional storage at the Prairie Island site to support extended operations 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 2050 and its Prairie Island nuclear plant until 2033 for Unit 1 and 2034 for Unit 2. NSP-Minnesota's authorized retirement dates are 2040 for Monticello, 2033 for Prairie Island Unit 1 and 2034 for Prairie Island Unit 2. As of Dec. 31, 2025, the planned retirement dates of the Prairie Island Unit 1 and Unit 2 and Monticello were 2053, 2054 and 2050, based off the approved 2024-2040 Upper Midwest Resource Plan. These will be incorporated in decommissioning estimates once additional approvals have been received. Approvals are expected in the third quarter of 2026.
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 most recent triennial decommissioning study was filed in November 2024 and approved by the MPUC in May 2025.
Obligations for decommissioning are expected to be funded 100% by the external decommissioning trust fund. NSP-Minnesota had $3.9 billion and $3.5 billion of assets held in external decommissioning trusts at Dec. 31, 2025 and 2024, respectively.
See Note 10 to the consolidated financial statements for additional discussion.
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 2040, contain minimum energy purchase commitments. Total energy payments on those contracts were $111 million, $212 million and $214 million in 2025, 2024 and 2023, respectively.
Included in electric fuel and purchased power expenses for PPAs accounted for as executory contracts were payments for capacity of $49 million, $81 million and $77 million in 2025, 2024 and 2023, 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, 2025, 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)
2026$34 $99 
202731 72 
202825 72 
202925 70 
203020 51 
Thereafter206 411 
Total$341 $775 
(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 2026 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, 2025:
(Millions of Dollars)CoalNuclear fuelNatural gas supplyNatural gas storage and transportation
2026$300 $67 $365 $399 
2027135 148 3 349 
202811 35 1 215 
20291 129 — 127 
20301 24 — 72 
Thereafter— 49 — 717 
Total$448 $452 $369 $1,879 
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 3,476 MW and 3,751 MW of capacity under long-term PPAs at Dec. 31, 2025 and 2024, respectively, with entities that have been determined to be VIEs. These agreements have expiration dates through 2048.
Fuel Contracts — SPS purchases all of its coal requirements for its Tolk plant from TUCO Inc. under contracts that will expire in December 2027. 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 SPS’ reimbursement of fuel procurement costs.
SPS has determined that TUCO is a VIE, however it has concluded that SPS is not the primary beneficiary because it does not have the power to direct the activities that most significantly impact TUCO’s economic performance.
Low-Income Housing Limited Partnerships — Eloigne and NSP-Wisconsin have entered into limited partnerships with affordable rental housing activities that qualify for low-income housing tax credits.
Eloigne and NSP-Wisconsin, as primary beneficiaries of these activities, consolidate these limited partnerships in their consolidated financial statements.
Amounts reflected in Xcel Energy’s consolidated balance sheets for these investments include $39 million of assets and $34 million of liabilities at Dec. 31, 2025, and $40 million of assets and $34 million of liabilities at Dec. 31, 2024.
Other
Guarantees and Bond Indemnifications — Xcel Energy Inc. and its subsidiaries provide guarantees and bond indemnities, which guarantee payment or performance. Xcel Energy Inc.’s exposure is based upon the net liability under the specified agreements or transactions. Most of the guarantees and bond indemnities issued by Xcel Energy Inc. and its subsidiaries have a stated maximum amount.
As of Dec. 31, 2025 and 2024, Xcel Energy Inc. and its subsidiaries had no assets held as collateral related to their guarantees, bond indemnities and indemnification agreements. Guarantees and bond indemnities issued and outstanding for Xcel Energy were $120 million and $93 million at Dec. 31, 2025 and 2024, respectively.
Other Indemnification Agreements — Xcel Energy Inc. and its subsidiaries provide indemnifications through various contracts. These are primarily indemnifications against adverse litigation outcomes in connection with underwriting agreements, as well as breaches of representations and warranties, including corporate existence and transaction authorization. Additionally, Xcel Energy Inc. and its subsidiaries have agreed to reimburse purchasers of the subsidiaries’ transferable tax credits for any unexpected reductions or IRS disallowances.
Xcel Energy Inc.’s and its subsidiaries’ obligations under these agreements may be limited in terms of duration and amount. Maximum future payments under these indemnifications cannot be reasonably estimated as the dollar amounts are often not explicitly stated.
v3.25.4
Other Comprehensive Income
 12 Months Ended
Dec. 31, 2025
Stockholders' Equity Note [Abstract]  
Comprehensive Income (Loss) Note [Text Block]
Changes in accumulated other comprehensive loss, net of tax, for the years ended Dec. 31:
2025
(Millions of Dollars)Gains and Losses on Interest Rate Cash Flow HedgesDefined Benefit Pension and Postretirement ItemsTotal
Accumulated other comprehensive loss at Jan. 1$(29)$(39)$(68)
Other comprehensive income (loss) before reclassifications2 (1)1 
Losses reclassified from net accumulated other comprehensive loss:
Interest rate derivatives (a)
2 

— 2 
Amortization of net actuarial losses (b)
— 2 2 
Net current period other comprehensive income4 1 5 
Accumulated other comprehensive loss at Dec. 31$(25)$(38)$(63)
(a)Included in interest charges.
(b)Included in the computation of net periodic pension and postretirement benefit costs. See Note 11 for further information.
2024
(Millions of Dollars)Gains and Losses on Interest Rate Cash Flow HedgesDefined Benefit Pension and Postretirement ItemsTotal
Accumulated other comprehensive loss at Jan. 1$(53)$(41)$(94)
Other comprehensive income (loss) before reclassifications22 (3)19 
Losses reclassified from net accumulated other comprehensive loss:
Interest rate derivatives (a)
2 — 2 
Amortization of net actuarial losses (b)
— 5 5 
Net current period other comprehensive income24 2 26 
Accumulated other comprehensive loss at Dec. 31$(29)$(39)$(68)
(a)Included in interest charges.
(b)Included in the computation of net periodic pension and postretirement benefit costs. See Note 11 for further information.
v3.25.4
Segments and Related Information
 12 Months Ended
Dec. 31, 2025
Segment Reporting [Abstract]  
Segment Information
Xcel Energy’s chief operating decision maker, the CEO, sets financial performance objectives and budgets and establishes separate targets for the regulated electric utility net income of NSP-Minnesota, NSP-Wisconsin, PSCo and SPS, as well as the regulated natural gas utility net income of NSP-Minnesota, NSP-Wisconsin and PSCo.
The regulated electric utility and regulated natural gas utility segments are managed separately because of inherent differences between activities to serve electric customers and those required to serve natural gas customers, and as the revenue streams are dependent upon regulated rate recovery, which is separately determined for each segment. The CEO assesses financial performance, including quarterly and annual budget-to-actual and year-over-year variances in revenues and expenses, to inform operating decisions, capital investments and cost recovery strategies.
Xcel Energy has the following reportable segments:
•Regulated Electric Utility — 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; each state’s regulated electric utility activities qualify as an operating segment, and is aggregated into Xcel Energy’s regulated electric utility segment. 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 Utility — 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; each state’s regulated natural gas utility activities qualify as an operating segment, and is aggregated into Xcel Energy’s regulated natural gas utility segment.
Equity method investments in the regulated natural gas utility segment of $81 million and $85 million at Dec. 31, 2025 and 2024, respectively, primarily relate to WYCO. Non-segment equity method investments of $204 million and $161 million as of Dec. 31, 2025 and 2024, respectively, relate to investments in energy technology funds.
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.
Other segment expenses, net, for the reportable segments includes conservation and DSM expenses, taxes (other than income taxes), other income (expense), net, earnings from equity method investments, intersegment expenses and AFUDC - equity.
Non-segment revenues include steam, appliance repair and non-utility real estate activities and revenues associated with processing solid waste into RDF and from investments in rental housing projects that qualify for low-income housing tax credits. Non-segment net loss also includes costs associated with these activities as well as unallocated corporate O&M expenses, interest charges and income taxes as well as earnings from equity method investments in energy technology funds.
Segment information and reconciliations to Xcel Energy’s consolidated operating revenues and net income:
2025
(Millions of Dollars)Regulated electric utilityRegulated natural gas utilityTotal segments
Operating revenues$12,160 $2,452 $14,612 
Intersegment revenue1 26 27 
Total segment revenues12,161 2,478 14,639 
Electric fuel and purchased power3,961 — 3,961 
Cost of natural gas sold and transported— 1,041 1,041 
O&M expenses2,259 425 2,684 
Depreciation and amortization2,525 413 2,938 
Other segment expenses, net (a)
925 151 1,076 
Interest charges and financing costs886 125 1,011 
Income tax (benefit) expense(265)67 (198)
Net income$1,870 $256 $2,126 
Total segment revenues$14,639 
Eliminate intersegment revenue(27)
Non-segment revenues57 
Consolidated operating revenues$14,669 
Total segment net income$2,126 
Non-segment net loss(108)
Consolidated net income$2,018 
(a)Other segment expenses, net, for 2025 additionally includes Marshall Wildfire litigation expense.
2024
(Millions of Dollars)Regulated electric utilityRegulated natural gas utilityTotal segments
Operating revenues$11,147 $2,230 $13,377 
Intersegment revenue2 22 24 
Total segment revenues11,149 2,252 13,401 
Electric fuel and purchased power3,788 — 3,788 
Cost of natural gas sold and transported— 951 951 
O&M expenses2,102 409 2,511 
Depreciation and amortization2,373 357 2,730 
Other segment expenses, net693 123 816 
Interest charges and financing costs767 113 880 
Income tax (benefit) expense(420)62 (358)
Net income$1,846 $237 $2,083 
Total segment revenues$13,401 
Eliminate intersegment revenue(24)
Non-segment revenues64 
Consolidated operating revenues$13,441 
Total segment net income$2,083 
Non-segment net loss(147)
Consolidated net income$1,936 

2023
(Millions of Dollars)Regulated electric utilityRegulated natural gas utilityTotal segments
Operating revenues$11,446 $2,645 $14,091 
Intersegment revenue2 3 5 
Total segment revenues11,448 2,648 14,096 
Electric fuel and purchased power4,278 — 4,278 
Cost of natural gas sold and transported— 1,456 1,456 
O&M expenses2,011 386 2,397 
Depreciation and amortization2,111 323 2,434 
Other segment expenses, net (a)
827 118 945 
Interest charges and financing costs670 96 766 
Income tax (benefit) expense(135)50 (85)
Net income$1,686 $219 $1,905 
Total segment revenues$14,096 
Eliminate intersegment revenue(5)
Non-segment revenues115 
Consolidated operating revenues$14,206 
Total segment net income$1,905 
Non-segment net loss(134)
Consolidated net income$1,771 
(a)Other segment expenses, net, for 2023 additionally includes loss on Comanche Unit 3 litigation with CORE Electric Cooperative related to lost power damages and other costs and workforce reduction expenses.
v3.25.4
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.
No such activities occurred in 2024 or 2025.
For further information on the estimated costs and obligations for future health plan subsidies and other medical benefits, see Note 11 to the consolidated financial statements.
v3.25.4
Schedule I, Condensed Financial Statements of Xcel Energy Inc
 12 Months Ended
Dec. 31, 2025
Condensed Financial Information Disclosure [Abstract]  
Schedule I, Condensed Financial Information
Year Ended Dec. 31
202520242023
Income
Equity earnings of subsidiaries$2,173 $2,122 $1,948 
Total income2,173 2,122 1,948 
Expenses and other deductions
Operating expenses38 24 25 
Other income(179)(76)(13)
Interest charges and financing costs366 300 235 
Total expenses and other deductions225 248 247 
Income before income taxes1,948 1,874 1,701 
Income tax benefit(70)(62)(70)
Net income$2,018 $1,936 $1,771 
Other Comprehensive Income
Pension and retiree medical benefits, net of tax $1 $2 $(2)
Derivative instruments, net of tax4 24 1 
Other comprehensive income (loss)5 26 (1)
Comprehensive income$2,023 $1,962 $1,770 
Weighted average common shares outstanding:
Basic587 563 552 
Diluted589 563 552 
Earnings per average common share:
Basic$3.44 $3.44 $3.21 
Diluted3.42 3.44 3.21 
See Notes to Condensed Financial Statements
Year Ended Dec. 31
202520242023
Operating activities
Net cash provided by operating activities$878 $1,459 $1,586 
Investing activities
Capital contributions to subsidiaries(4,067)(2,184)(975)
Investment in debt securities — intercompany(607)(105)— 
Net return in the utility money pool(171)21 21 
Net cash used in investing activities(4,845)(2,268)(954)
Financing activities
 Proceeds from (repayment of) short-term borrowings, net615 70 (66)
Proceeds from issuance of long-term debt1,970 795 792 
Repayment of long-term debt(600)— (500)
Proceeds from issuance of common stock3,349 1,117 270 
Dividends paid(1,282)(1,175)(1,092)
Other(6)(6)(13)
Net cash provided by (used in) financing activities4,046 801 (609)
Net change in cash, cash equivalents, and restricted cash79 (8)23 
Cash, cash equivalents and restricted cash at beginning of period16 24 1 
Cash, cash equivalents and restricted cash at end of period$95 $16 $24 
See Notes to Condensed Financial Statements
Dec. 31
20252024
Assets
Cash and cash equivalents$95 $16 
Accounts receivable from subsidiaries, net678 410 
Other current assets14 9 
Total current assets787 435 
Investment in subsidiaries31,496 26,519 
Investment in debt securities — intercompany953 166 
Other assets6 6 
Total other assets32,455 26,691 
Total assets$33,242 $27,126 
Liabilities and Equity
Current portion of long-term debt500 600 
Dividends payable355 314 
Short-term debt850 235 
Other current liabilities78 90 
Total current liabilities1,783 1,239 
Other liabilities18 28 
Total other liabilities18 28 
Commitments and contingencies
Capitalization
Long-term debt7,832 6,337 
Common stockholders' equity23,609 19,522 
Total capitalization31,441 25,859 
Total liabilities and equity$33,242 $27,126 
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, 2025 and 2024, Xcel Energy Inc. had no assets held as collateral related to guarantees, bond indemnities and indemnification agreements.
Guarantees and bond indemnities issued and outstanding as of Dec. 31, 2025:
(Millions of Dollars)GuarantorGuarantee
Amount		Current
Exposure		Triggering
Event
Guarantees of Capital Services equipment purchase contractsXcel Energy Inc. 1,173 
(a)
(b)
Guarantees of Xcel Energy Services Inc. performance and payments on operating lease agreementsXcel Energy Inc.43 43 
(b)
Guarantee performance and payment of surety bonds for Xcel Energy Inc.’s utility subsidiaries (c)
Xcel Energy Inc.120 
(d)
(e)
(a)Relative to the guaranteed performance obligations of Capital Services, vendors have completed approximately 60% of the manufacturing required to deliver completed equipment.
(b)Nonperformance and/or nonpayment.
(c)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.
(d)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.
(e)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 and notes receivable net of payables with affiliates at Dec. 31:
(Millions of Dollars)20252024
NSP-Minnesota$113 $79 
NSP-Wisconsin4 11 
PSCo83 77 
SPS29 41 
Xcel Energy Services Inc.434 163 
Other subsidiaries of Xcel Energy Inc.15 39 
$678 $410 
Dividends — Cash dividends paid to Xcel Energy Inc. by its subsidiaries were $1,258 million, $1,685 million and $1,693 million for the years ended Dec. 31, 2025, 2024 and 2023, 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, 2025Year Ended
202520242023
Loan outstanding at period end$171 $171 $— $21 
Average loan outstanding27 14 18 27 
Maximum loan outstanding253 253 209 250 
Weighted average interest rate, computed on a daily basis3.89 %4.11 %5.34 %5.33 %
Weighted average interest rate at end of period3.88 3.88 5.34 N/A
Money pool interest income$— $1 $1 $1 
During 2024, Xcel Energy Inc. purchased $166 million in aggregate principal amounts of NSP-Minnesota’s 2.60% First Mortgage Bonds Series due June 1, 2051 for $105 million.
During 2025, Xcel Energy Inc. purchased $787 million in aggregate principal amounts of NSP-Minnesota’s 4.125% First Mortgage Bonds Series due May 15, 2044, 4.00% First Mortgage Bonds Series due August 15, 2045, 3.60% First Mortgage Bonds Series due May 15, 2046, 2.90% First Mortgage Bonds Series due March 1, 2050, 2.60% First Mortgage Bonds Series due June 1, 2051, and 3.20% First Mortgage Bonds Series due April 1, 2052, for $607 million.
See notes to the consolidated financial statements in Part II, Item 8.
v3.25.4
Schedule II, Valuation and Qualifying Accounts
 12 Months Ended
Dec. 31, 2025
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 debtsNOL and tax credit valuation allowances
(Millions of Dollars)202520242023202520242023
Balance at Jan. 1$111 $128 $122 $73 $70 $62 
Additions charged to costs and expenses64 64 79 37 45 26 
Additions charged to other accounts15 
(a)
16 
(a)
13 
(a)
— — — 
Deductions from reserves(101)
(b)
(97)
(b)
(86)
(b)
(36)
(c)
(42)
(c)
(18)
(c)
Balance at Dec. 31$89 $111 $128 $74 $73 $70 
(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.
v3.25.4
Insider Trading Arrangements
 12 Months Ended
Dec. 31, 2025
Trading Arrangements, by Individual  
Rule 10b5-1 Arrangement Adopted false
Non-Rule 10b5-1 Arrangement Adopted false
Rule 10b5-1 Arrangement Terminated false
Non-Rule 10b5-1 Arrangement Terminated false
v3.25.4
Insider Trading Policies and Procedures
 12 Months Ended
Dec. 31, 2025
Insider Trading Policies and Procedures [Line Items]  
Insider Trading Policies and Procedures Adopted true
v3.25.4
Cybersecurity Risk Management and Strategy Disclosure
 12 Months Ended
Dec. 31, 2025
Cybersecurity Risk Management, Strategy, and Governance [Line Items]  
Cybersecurity Risk Management Processes for Assessing, Identifying, and Managing Threats [Text Block]
As described in Item 1A – Risk Factors, Xcel Energy operates in an industry that requires the continued operation of sophisticated information technology, control systems and network infrastructure, as such, our business is subject to the risk of interruption by cybersecurity incidents that range from attacks common to most industries, such as phishing and denial-of-service, to attacks from more sophisticated adversaries, including nation state actors, that target the critical infrastructure used in the operation of our business.
The Company has a security risk program in place to identify, assess, manage and report material risks from cybersecurity incidents. As a utility provider, Xcel Energy complies with reliability standards imposed by NERC, including critical infrastructure protection standards related to both cybersecurity and physical security. These standards imposed by NERC, in alignment with the NIST Cybersecurity Framework, are the basis for which
Xcel Energy has designed the cybersecurity control framework within its security risk program.
Biennially, as part of Xcel Energy’s enterprise risk program, an integrated cybersecurity risk identification and assessment is completed across Xcel Energy’s business, including generation, transmission, distribution and fuel storage facilities, information technology systems and other infrastructure or physical assets as well as information processed in our systems (including systems hosted by third parties) that could be affected by cybersecurity incidents. This analysis includes the impact, likelihood, timeframe and controllability of cybersecurity risks and is presented to the Board of Directors. Management monitors and reviews the results of this analysis, integrating them into the enterprise risk assessment processes and implements appropriate mitigating actions as needed.
Xcel Energy’s cybersecurity policies, standards, practices, annual cybersecurity training content and readiness are regularly assessed by third-party consultants. These partners are engaged to perform independent penetration testing and other security related services to assist in the prevention, detection, monitoring, mitigation and remediation of cybersecurity incidents and risks. The results of these assessments are communicated to management and the Board of Directors by the Chief Security Officer.
Xcel Energy employs a comprehensive risk based approach to assess the magnitude and significance of a vendor’s risk to the Company. Certain third-party service providers are subject to vendor security risk assessments at the time of integration, contract execution/renewal, and upon detection of any increase in risk profile. Xcel Energy uses a variety of inputs in such risk assessments, including information supplied by providers and third parties (including information analysis centers that share daily threat intelligence and improve organizational agility associated with management of cybersecurity risks). In addition, the Company requires certain third-party service providers to meet appropriate security requirements, controls and responsibilities. The Company deploys periodic monitoring activities to assess compliance with our cybersecurity control framework and investigates security incidents that have impacted our third-party service providers as appropriate.
Cybersecurity Risk Management Processes Integrated [Flag] true
Cybersecurity Risk Management Processes Integrated [Text Block] Biennially, as part of Xcel Energy’s enterprise risk program, an integrated cybersecurity risk identification and assessment is completed across Xcel Energy’s business, including generation, transmission, distribution and fuel storage facilities, information technology systems and other infrastructure or physical assets as well as information processed in our systems (including systems hosted by third parties) that could be affected by cybersecurity incidents.
Cybersecurity Risk Management Third Party Engaged [Flag] true
Cybersecurity Risk Third Party Oversight and Identification Processes [Flag] true
Cybersecurity Risk Materially Affected or Reasonably Likely to Materially Affect Registrant [Flag] true
Cybersecurity Risk Materially Affected or Reasonably Likely to Materially Affect Registrant [Text Block]
Cybersecurity risks are a part of Xcel Energy’s normal course of business. To date, no cybersecurity incident or attack affecting us or our vendors has had a material impact on our business or results of operations. As of Feb. 25, 2026 there have been no material cybersecurity incidents to report.
Cybersecurity Risk Board of Directors Oversight [Text Block]
The Chief Security Officer or members of management brief the Board on routine and regular cybersecurity risk and threat updates, typically on an annual basis. In the event of a significant threat or incident, management and the Chief Security Officer leverage Xcel Energy’s incident response processes to assess impacts and resolve incidents. When a significant cybersecurity incident occurs, management communicates with the Board of Directors and relevant committees.
The Board of Directors oversees the risks associated with cybersecurity and the physical security of our assets, with information security matters being discussed at board meetings as well as at the ONES and Audit Committee meetings throughout the year.
While the ONES Committee has primary committee responsibility for cybersecurity due to the operational issues involved, the Board of Directors has determined that the topic is of sufficient importance to warrant this comprehensive oversight approach. Augmenting such oversight efforts, the enterprise has the ability to notify and update the Board of Directors in the event of a possible crisis situation.
Cybersecurity Risk Board Committee or Subcommittee Responsible for Oversight [Text Block] The Board of Directors oversees the risks associated with cybersecurity and the physical security of our assets, with information security matters being discussed at board meetings as well as at the ONES and Audit Committee meetings throughout the year.
Cybersecurity Risk Process for Informing Board Committee or Subcommittee Responsible for Oversight [Text Block]
The Chief Security Officer or members of management brief the Board on routine and regular cybersecurity risk and threat updates, typically on an annual basis. In the event of a significant threat or incident, management and the Chief Security Officer leverage Xcel Energy’s incident response processes to assess impacts and resolve incidents. When a significant cybersecurity incident occurs, management communicates with the Board of Directors and relevant committees.
Cybersecurity Risk Role of Management [Text Block]
Management has assigned responsibility for the security risk program to the Chief Security Officer who has multiple years of experience in the Defense Industrial Base. The Chief Security Officer is informed about and monitors prevention, detection, mitigation and remediation efforts through a team of security professionals, many of whom are Certified Information Systems Security Professionals, Certified Information Security Managers or have received other cybersecurity certifications. The team has extensive experience selecting, deploying and operating cybersecurity technologies, initiatives and processes that aid in preventing, remediating and mitigating known and unknown security threats.
The Chief Security Officer or members of management brief the Board on routine and regular cybersecurity risk and threat updates, typically on an annual basis. In the event of a significant threat or incident, management and the Chief Security Officer leverage Xcel Energy’s incident response processes to assess impacts and resolve incidents. When a significant cybersecurity incident occurs, management communicates with the Board of Directors and relevant committees.
Cybersecurity Risk Management Positions or Committees Responsible [Flag] true
Cybersecurity Risk Management Positions or Committees Responsible [Text Block]
Management has assigned responsibility for the security risk program to the Chief Security Officer who has multiple years of experience in the Defense Industrial Base. The Chief Security Officer is informed about and monitors prevention, detection, mitigation and remediation efforts through a team of security professionals, many of whom are Certified Information Systems Security Professionals, Certified Information Security Managers or have received other cybersecurity certifications. The team has extensive experience selecting, deploying and operating cybersecurity technologies, initiatives and processes that aid in preventing, remediating and mitigating known and unknown security threats.
Cybersecurity Risk Management Expertise of Management Responsible [Text Block] Management has assigned responsibility for the security risk program to the Chief Security Officer who has multiple years of experience in the Defense Industrial Base.
Cybersecurity Risk Process for Informing Management or Committees Responsible [Text Block] The results of these assessments are communicated to management and the Board of Directors by the Chief Security Officer.
Cybersecurity Risk Management Positions or Committees Responsible Report to Board [Flag] true
v3.25.4
Summary of Significant Accounting Policies Summary of Significant Accounting Policies (Policies)
 12 Months Ended
Dec. 31, 2025
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 and storage facilities.
Xcel Energy Inc.’s nonregulated subsidiaries include:
Nonregulated SubsidiaryPurpose
EloigneInvests in rental housing projects that qualify for low-income housing tax credits.
Capital ServicesProcures equipment for Xcel Energy subsidiaries for construction of generation facilities and for other items with long lead times.
Xcel Energy Venture Holdings, Inc.Invests in limited partnerships, including funds with portfolios of investments in energy technology companies.
Nicollet Project HoldingsInvests 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 investments in energy technology 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 depreciation and other 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, 2025 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, actuarially determined benefit costs and wildfire contingencies. 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 reversed or 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, as determined by tax regulations and Xcel Energy tax elections. For tax credits 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, 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 assets’ commission approved useful lives. 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 3.9% for 2025, 3.8% for 2024 and 3.6% for 2023.
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.
See Note 3 for further information.
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 uclear Decommissioning — Nuclear decommissioning studies that estimate NSP-Minnesota’s costs of decommissioning its nuclear power plants are normally performed at least every three years and submitted to the state commissions for approval. The latest decommissioning study was completed in 2024.
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 generally 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. When separate mechanisms are expected to provide cost recovery or when changes in projected costs occur near the end of a facility’s useful life, regulatory accounting may be applied.
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.
Xcel Energy’s subsidiaries have various rate-adjustment mechanisms that provide for the recovery of natural gas, electric fuel and purchased energy costs. Cost-adjustment tariffs may increase or decrease the level of revenue collected from customers and are revised periodically for differences between the total amount collected under the clauses and the costs incurred.
When applicable, fuel cost over-recoveries (the excess of fuel revenue billed to customers over fuel costs incurred) are deferred as regulatory liabilities and under-recoveries (the excess of fuel costs incurred over fuel revenues billed to customers) are deferred as regulatory assets.
See Note 6 for further information.
Cash and Cash Equivalents
Cash and Cash Equivalents — Xcel Energy considers investments in instruments with a remaining maturity of three months or less at the time of purchase to be cash equivalents.
Accounts Receivable and Allowance for Bad Debts
Accounts Receivable and Allowance for Bad Debts — Accounts receivable are stated at the actual billed amount net of an allowance for bad debts. Xcel Energy establishes an allowance for uncollectible receivables based on a policy that reflects its expected exposure to the credit risk of customers.
As of Dec. 31, 2025 and 2024, the allowance for bad debts was $89 million and $111 million, respectively.
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, 2025Dec. 31, 2024
Inventories
Materials and supplies$489 $406 
Fuel156 164 
Natural gas116 96 
Total inventories$761 $666 
Equity Method Investments Equity Method Investments — The equity method of accounting is used for certain investments including WYCO and energy technology 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 energy technology 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.
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 that have not been designated or do not qualify 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 and sale 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 — 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 Programs
Alternative Revenue — Certain rate rider mechanisms (including transmission and distribution cost recovery, 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 annual period in which 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.
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.
Lessee, Leases
Leases — Xcel Energy evaluates contracts that may contain leases, including PPAs and arrangements for the use of office space and other facilities, as well as certain contracts for the use of land, vehicles and other 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 whether the arrangement is an operating lease or a finance lease, including an assessment of whether the contract requires payments for substantially all of the value of the leased asset or whether the term of the contract is for substantially all of the expected remaining economic life of the leased asset, among other criteria for finance lease classification.
See Note 12 for further information.
v3.25.4
Summary of Significant Accounting Policies Inventory (Tables)
 12 Months Ended
Dec. 31, 2025
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, 2025Dec. 31, 2024
Inventories
Materials and supplies$489 $406 
Fuel156 164 
Natural gas116 96 
Total inventories$761 $666 
v3.25.4
Property Plant and Equipment Property Plant and Equipment (Tables)
 12 Months Ended
Dec. 31, 2025
Property, Plant and Equipment [Line Items]  
Public Utility Property, Plant, and Equipment
Major classes of property, plant and equipment
(Millions of Dollars)Dec. 31, 2025Dec. 31, 2024
Property, plant and equipment, net
Electric plant$61,892 $56,791 
Natural gas plant10,517 9,834 
Common and other property3,790 3,515 
Plant to be retired (a)
1,595 1,793 
CWIP8,085 4,720 
Total property, plant and equipment85,879 76,653 
Less accumulated depreciation(20,710)(19,852)
Nuclear fuel3,678 3,491 
Less accumulated amortization(3,208)(3,094)
Property, plant and equipment, net$65,639 $57,198 
(a)Amounts include Sherco 1 and 3 and A.S. King for NSP-Minnesota; Comanche Unit 3, Craig Unit 2, Hayden Units 1 and 2 for PSCo; and Tolk Unit 1 and 2 for SPS. The Dec. 31, 2024 amounts also include coal generation assets at Pawnee (assets were retired in 2025 and the conversion to natural gas is complete). Additionally, 2024 amounts included both Comanche Unit 2 and Craig Unit 1, which had planned retirement dates in 2025. Amounts are presented net of accumulated depreciation.
NSP Minnesota  
Property, Plant and Equipment [Line Items]  
Schedule of Jointly Owned Utility Plants
(Millions of Dollars, Except Percent Owned)Plant in ServiceAccumulated DepreciationPercent Owned
NSP-Minnesota
Electric generation:
Sherco Unit 3$638 $515 59 %
Sherco common facilities189 134 80 
Sherco substation5 4 59 
Electric transmission:
Grand Meadow11 4 50 
Huntley Wilmarth49 4 50 
CapX2020887 169 51 
Total NSP-Minnesota (a)
$1,779 $830 
(a)Projects additionally include $26 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 ServiceAccumulated DepreciationPercent Owned
NSP-Wisconsin
Electric transmission:
La Crosse, WI to Madison, WI$179 $33 37 %
CapX2020169 46 80 
Total NSP-Wisconsin (a)
$348 $79 
(a)Projects additionally include $3 million in CWIP.
PSCo  
Property, Plant and Equipment [Line Items]  
Schedule of Jointly Owned Utility Plants
(Millions of Dollars, Except Percent Owned)Plant in ServiceAccumulated DepreciationPercent Owned
PSCo
Electric generation:
Hayden Unit 1$159 $126 76 %
Hayden Unit 2152 99 37 
Hayden common facilities45 36 53 
Craig Units 1 and 282 60 10 
Craig common facilities40 28 7 
Comanche Unit 3971 233 67 
Comanche common facilities29 6 77 
Electric transmission:
Transmission and other facilities193 76 Various
Gas transmission:
Rifle, CO to Avon, CO31 10 60 
Gas transmission compressor8 3 60 
Total PSCo (a)
$1,710 $677 
(a)Projects additionally include $16 million in CWIP.
v3.25.4
Regulatory Assets and Liabilities (Tables)
 12 Months Ended
Dec. 31, 2025
Regulatory Assets and Liabilities Disclosure [Abstract]  
Regulatory Assets
Components of regulatory assets:
(Millions of Dollars)See Note(s)Remaining Amortization PeriodDec. 31, 2025
Dec. 31, 2024 (a)
Regulatory AssetsCurrentNoncurrentCurrentNoncurrent
Pension and retiree medical obligations11Various$39 $1,121 $39 $1,167 
Recoverable deferred taxes on AFUDCPlant lives— 434 — 368 
Net AROs1, 12Various— 422 — 387 
Depreciation differencesVarious22 320 17 250 
Excess deferred taxes — TCJA
7Various11 162 10 184 
Grid modernization costsVarious2 67 3 30 
Excess liability insurance costsVarious5 64 — 6 
Environmental remediation costs1, 12Various9 34 13 39 
Prairie Island extended power uprate
Nine years
4 30 4 34 
Conservation programs (b)
1
One to two years
18 28 20 30 
Nuclear refueling outage costs1
One to two years
58 20 51 20 
Benson biomass PPA termination and asset purchase
Three years
10 16 10 26 
Deferred natural gas, electric, steam energy/fuel costs
One to two years
88 15 99 25 
Renewable resources and environmental initiatives
One to two years
40 4 34 4 
Sales true-up and MN MISO capacity revenueVarious75 2 123 68 
Gas pipeline inspection and remediation costs
Less than one year
31 — 47 9 
Other
Various117 259 91 202 
Total regulatory assets$529 $2,998 $561 $2,849 
(a)Prior period amounts have been reclassified to conform with current year presentation.
(b)Includes costs for conservation programs, as well as incentives allowed in certain jurisdictions.
Regulatory Liabilities
Components of regulatory liabilities:
(Millions of Dollars)See Note(s)Remaining Amortization PeriodDec. 31, 2025Dec. 31, 2024
Regulatory LiabilitiesCurrentNoncurrentCurrentNoncurrent
Deferred income tax adjustments and TCJA refunds (a)
7Various$7 $2,758 $7 $2,888 
Plant removal costs1, 12Various— 2,336 — 2,208 
Net AROs (b)
Various— 354 — 161 
Renewable resources and environmental initiativesVarious16 319 16 232 
Effects of regulation on employee benefit costs (c)
11Various— 261 — 259 
ITC deferrals
1Various— 64 — 70 
IRA deferral
One to two years
19 19 3 37 
Deferred natural gas, electric, steam energy/fuel costs
One to two years
296 13 480 12 
Contract valuation adjustments (d)
1, 10
Less than one year
144 — 89 — 
Conservation programs (e)
1
Less than one year
39 — 52 — 
Other Various193 153 205 143 
Total regulatory liabilities$714 $6,277 $852 $6,010 
(a)Includes the revaluation of recoverable/regulated plant ADIT and revaluation impact of non-plant ADIT due to the TCJA.
(b)Includes amounts recorded for future recovery of AROs, less amounts recovered through nuclear decommissioning accruals and gains from decommissioning investments.
(c)Includes regulatory amortization and certain 2018 TCJA benefits approved by the CPUC to offset the PSCo prepaid pension asset.
(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.
v3.25.4
Borrowings and Other Financing Instruments Borrowings and Other Financing Instruments (Tables)
 12 Months Ended
Dec. 31, 2025
Debt Disclosure [Abstract]  
Commercial Paper
Commercial paper and other borrowings outstanding:
(Millions of Dollars, Except Interest Rates)Three Months Ended Dec. 31, 2025Year Ended Dec. 31
202520242023
Borrowing limit$4,750 $4,750 $3,550 $3,550 
Amount outstanding at period end1,550 1,550 695 785 
Average amount outstanding1,622 1,026 508 491 
Maximum amount outstanding2,965 2,965 1,314 1,241 
Weighted average interest rate, computed on a daily basis4.14 %4.41 %5.47 %5.12 %
Weighted average interest rate at period end3.95 3.95 4.64 5.52 
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)
20252024
Xcel Energy Inc. (d)
59.80 %59.80 %$450 2 
NSP-Minnesota50.00 47.00 170 2 
NSP-Wisconsin47.00 47.10 N/A1 
SPS47.20 46.60 60 2 
PSCo44.90 45.20 170 2 
(a)Each credit facility has a financial covenant requiring that the debt-to-total capitalization ratio be less than or equal to 65% (70% for Xcel Energy Inc.).
(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, 2025, NSP-Minnesota had $69 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, 2025:
(Millions of Dollars)
Credit Facility (a)
Drawn (b)
Available
Xcel Energy Inc.$2,000 $850 $1,150 
PSCo1,200 308 892 
NSP-Minnesota800 264 536 
SPS600 220 380 
NSP-Wisconsin150 — 150 
Total$4,750 $1,642 $3,108 
(a)These credit facilities mature in December 2029.
(b)Includes outstanding commercial paper and letters of credit.
Schedule of Long Term Debt Instruments
Long-term debt obligations for Xcel Energy Inc. and its utility subsidiaries as of Dec. 31 (in millions of dollars, except interest rates):
Xcel Energy Inc.
Financing InstrumentInterest RateMaturity Date20252024
Unsecured senior notes3.30 %June 1, 2025$— $250 
Unsecured senior notes3.30 June 1, 2025— 350 
Unsecured senior notes3.35 Dec. 1, 2026500 500 
Unsecured senior notes1.75 March 15, 2027500 500 
Unsecured senior notes4.00 June 15, 2028130 130 
Unsecured senior notes (a)
4.75 March 21, 2028350 — 
Unsecured senior notes4.00 June 15, 2028500 500 
Unsecured senior notes2.60 Dec. 1, 2029500 500 
Unsecured senior notes3.40 June 1, 2030600 600 
Unsecured senior notes2.35 Nov. 15, 2031300 300 
Unsecured senior notes4.60 June 1, 2032700 700 
Unsecured senior notes5.45 Aug. 15, 2033800 800 
Unsecured senior notes (b)
5.50 March 15, 2034800 800 
Unsecured senior notes (a)
5.60 April 15, 2035750 — 
Unsecured senior notes6.50 July 1, 2036300 300 
Unsecured senior notes4.80 Sept. 15, 2041250 250 
Unsecured senior notes3.50 Dec. 1, 2049500 500 
Junior subordinated notes (a) (c)
6.25 Oct. 15, 2085900 — 
Unamortized discount(10)(9)
Unamortized debt issuance cost(38)(34)
Current maturities (500)(600)
Total long-term debt$7,832 $6,337 
(a)2025 financing.
(b)2024 financing.
(c)The notes may be redeemed at par value on or after Oct. 15, 2030.
NSP-Minnesota
Financing InstrumentInterest RateMaturity Date20252024
First mortgage bonds7.125 %July 1, 2025$— $250 
First mortgage bonds6.50 March 1, 2028150 150 
First mortgage bonds2.25 April 1, 2031425 425 
First mortgage bonds (a)
5.05 May 15, 2035600 — 
First mortgage bonds5.25 July 15, 2035250 250 
First mortgage bonds6.25 June 1, 2036400 400 
First mortgage bonds6.20 July 1, 2037350 350 
First mortgage bonds5.35 Nov. 1, 2039300 300 
First mortgage bonds4.85 Aug. 15, 2040250 250 
First mortgage bonds3.40 Aug. 15, 2042500 500 
First mortgage bonds4.125 May 15, 2044300 300 
First mortgage bonds4.00 Aug. 15, 2045300 300 
First mortgage bonds3.60 May 15, 2046350 350 
First mortgage bonds3.60 Sept. 15, 2047600 600 
First mortgage bonds2.90 March 1, 2050600 600 
First mortgage bonds2.60 June 1, 2051700 700 
First mortgage bonds3.20 April 1, 2052425 425 
First mortgage bonds4.50 June 1, 2052500 500 
First mortgage bonds5.10 May 15, 2053800 800 
First mortgage bonds (b)
5.40 March 15, 2054700 700 
First mortgage bonds (a)
5.65 May 15, 2055500 — 
Other long-term debt1 2 
Long-term debt — related parties principal amount outstanding2.60 - 4.1252044 - 2052(953)(166)
Unamortized discount(50)(49)
Unamortized debt issuance cost(90)(80)
Current maturities— (250)
Total long-term debt$7,908 $7,607 
(a)2025 financing.
(b)2024 financing.
NSP-Wisconsin
Financing InstrumentInterest RateMaturity Date20252024
First mortgage bonds6.375 %Sept. 1, 2038$200 $200 
First mortgage bonds3.70 Oct. 1, 2042100 100 
First mortgage bonds3.75 Dec. 1, 2047100 100 
First mortgage bonds4.20 Sept. 1, 2048200 200 
First mortgage bonds3.05 May 1, 2051100 100 
First mortgage bonds2.82 May 1, 2051100 100 
First mortgage bonds4.86 Sept. 15, 2052100 100 
First mortgage bonds5.30 June 15, 2053125 125 
First mortgage bonds (a)
5.65 June 15, 2054400 400 
First mortgage bonds (b)
5.65 June 15, 2054250 — 
Unamortized discount(10)(4)
Unamortized debt issuance cost(18)(15)
Total long-term debt$1,647 $1,406 
(a)2024 financing.
(b)2025 financing.
PSCo
Financing InstrumentInterest RateMaturity Date20252024
First mortgage bonds2.90 %May 15, 2025$— $250 
First mortgage bonds3.70 June 15, 2028350 350 
First mortgage bonds1.90 Jan. 15, 2031375 375 
First mortgage bonds1.875 June 15, 2031750 750 
First mortgage bonds4.10 June 1, 2032300 300 
First mortgage bonds (a)
5.35 May 15, 2034400 — 
First mortgage bonds (b)
5.35 May 15, 2034450 450 
First mortgage bonds (a)
5.15 Sep 15, 2035800 — 
First mortgage bonds6.25 Sept. 1, 2037350 350 
First mortgage bonds6.50 Aug. 1, 2038300 300 
First mortgage bonds4.75 Aug. 15, 2041250 250 
First mortgage bonds3.60 Sept. 15, 2042500 500 
First mortgage bonds3.95 March 15, 2043250 250 
First mortgage bonds4.30 March 15, 2044300 300 
First mortgage bonds3.55 June 15, 2046250 250 
First mortgage bonds3.80 June 15, 2047400 400 
First mortgage bonds4.10 June 15, 2048350 350 
First mortgage bonds4.05 Sept. 15, 2049400 400 
First mortgage bonds3.20 March 1, 2050550 550 
First mortgage bonds2.70 Jan. 15, 2051375 375 
First mortgage bonds4.50 June 1, 2052400 400 
First mortgage bonds5.25 April 1, 2053850 850 
First mortgage bonds (b)
5.75 May 15, 2054750 750 
First mortgage bonds (a)
5.85 May 15, 2055800 — 
Unamortized discount(42)(42)
Unamortized debt issuance cost(82)(67)
Current maturities— (250)
Total long-term debt$10,376 $8,391 
(a)2025 financing.
(b)2024 financing.
SPS
Financing InstrumentInterest RateMaturity Date20252024
Unsecured senior notes6.00 %Oct. 1, 2033$100 $100 
First mortgage bonds (a)
5.30 May 15, 2035500 — 
Unsecured senior notes6.00 Oct. 1, 2036250 250 
First mortgage bonds4.50 Aug. 15, 2041200 200 
First mortgage bonds4.50 Aug. 15, 2041100 100 
First mortgage bonds4.50 Aug. 15, 2041100 100 
First mortgage bonds3.40 Aug. 15, 2046300 300 
First mortgage bonds3.70 Aug. 15, 2047450 450 
First mortgage bonds4.40 Nov. 15, 2048300 300 
First mortgage bonds3.75 June 15, 2049300 300 
First mortgage bonds3.15 May 1, 2050350 350 
First mortgage bonds3.15 May 1, 2050250 250 
First mortgage bonds5.15 June 1, 2052200 200 
First mortgage bonds6.00 Sept. 15, 2053100 100 
First mortgage bonds (b)
6.00 June 1, 2054600 600 
Unamortized discount(14)(14)
Unamortized debt issuance cost(40)(35)
Total long-term debt$4,046 $3,551 
(a)2025 financing.
(b)2024 financing.
Other Subsidiaries
Financing InstrumentInterest RateMaturity Date20252024
Various Eloigne affordable housing project notes0.00% - 8.50%2026 - 2055$24 $27 
Current maturities(1)(3)
Total long-term debt$23 $24 
Schedule of Maturities of Long-term Debt
Maturities of long-term debt:
(Millions of Dollars)
2026$501 
2027501 
20281,483 
2029503 
2030600 
Schedule of Stock by Class [Table Text Block]
Capital Stock — Preferred stock authorized/outstanding:
Preferred Stock Authorized (Shares)Par Value of Preferred StockPreferred Stock Outstanding (Shares) 2025 and 2024
Xcel Energy Inc.7,000,000 $100 — 
PSCo10,000,000 0.01 — 
SPS10,000,000 1.00 — 
Xcel Energy Inc. had the following common stock authorized/outstanding:
Common Stock Authorized (Shares)Par Value of Common StockCommon Stock Outstanding (Shares) as of Dec. 31, 2025Common Stock Outstanding (Shares) as of Dec. 31, 2024
1,000,000,000 $2.50 623,600,715 574,365,598 
Share-based Payment Arrangement, Restricted Stock and Restricted Stock Unit, Activity [Table Text Block]
Requirements and actuals as of Dec. 31, 2025:
Equity to Total
Capitalization Ratio
Required Range 		Equity to Total Capitalization Ratio Actual
LowHigh2025
NSP-Minnesota47.25 %57.75 %53.16 %
NSP-Wisconsin (a)
52.50 N/A52.66 
SPS (b)
45.00 55.00 54.47 
(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 EarningsTotal CapitalizationLimit on Total Capitalization
NSP-Minnesota$2,185 $19,547 $22,607 
NSP-Wisconsin12 3,318 N/A
SPS (a)
622 8,888 N/A
(a)May not pay a dividend that would cause a loss of its investment grade bond rating.
Other Capital Restrictions
Amounts authorized to issue as of Dec. 31, 2025:
(Millions of Dollars)Long-Term DebtShort-Term Debt
NSP-Minnesota (a)
52.8% of total capitalization$3,391 
NSP-Wisconsin$500 150 
PSCo3,500 1,200 
SPS100 

700 
(a)NSP-Minnesota has authorization to issue long-term securities provided the equity-to-total capitalization remains within the required range, and to issue short-term debt provided it does not exceed 15% of total capitalization.
Pro-Forma/Hypothetical Transactions
Pro-Forma/Hypothetical Transactions
Agreements EnteredNet Settlement:Physical Share Delivery Proceeds (millions of dollars)
Common Shares (in millions)Net Cash (millions of dollars)
2025 forward equity agreements0.1$7 $934 
Schedule of Forward Contracts Indexed to Issuer's Equity
Agreements EnteredCommon Shares (in millions)Final Maturity
Minimum Expected Proceeds (millions of dollars)
2025 forward equity agreements (a)
12.2
Feb. 2026 to Dec. 2028 (b)
935 
(c)
2025 collared forward equity agreements (a)
15.1Dec. 20261,084 
(d)
(a)Entered under the 2025 ATM prospectus supplement.
(b)Xcel Energy may settle the agreements at any time until final maturity.
(c)Actual cash proceeds will be impacted by the timing of settlement. Forward prices are based on the public offering price (net of underwriting fees), increased for the overnight bank funding rate, less a spread and less expected dividends on Xcel Energy’s common stock during the period the agreements are outstanding.
(d)Pricing for the physical delivery of common shares will be based on an average market price for Xcel Energy’s common stock during a period preceding settlement in December 2026, subject to a cap price and floor price derived from the September 2025 and December 2025 public offerings.
Settled Forwards [Table]
Agreements EnteredCommon Shares (in millions)Forward Sale Price per ShareCash Proceeds at Settlement
Forward sale agreements settled in December 2025:
2024 forward equity agreements21.1 $64.70 - 64.76$1,364 
2025 forward equity agreements8.9 71.91 - 80.97684
30.0 $2,048 
v3.25.4
Revenues (Tables)
 12 Months Ended
Dec. 31, 2025
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, 2025
(Millions of Dollars)ElectricNatural GasAll OtherTotal
Major revenue types
Revenue from contracts with customers:
Residential$3,904 $1,411 $3 $5,318 
C&I5,948 742 30 6,720 
Other149 — 10 159 
Total retail10,001 2,153 43 12,197 
Wholesale715 — — 715 
Transmission705 — — 705 
Other69 174 — 243 
Total revenue from contracts with customers11,490 2,327 43 13,860 
Alternative revenue and other670 125 14 809 
Total revenues$12,160 $2,452 $57 $14,669 
Year Ended Dec. 31, 2024
(Millions of Dollars)ElectricNatural GasAll OtherTotal
Major revenue types
Revenue from contracts with customers:
Residential$3,552 $1,299 $11 $4,862 
C&I5,420 646 30 6,096 
Other142 — 9 151 
Total retail9,114 1,945 50 11,109 
Wholesale645 — — 645 
Transmission648 — — 648 
Other64 175 — 239 
Total revenue from contracts with customers10,471 2,120 50 12,641 
Alternative revenue and other676 110 14 800 
Total revenues$11,147 $2,230 $64 $13,441 
Year Ended Dec. 31, 2023
(Millions of Dollars)ElectricNatural GasAll OtherTotal
Major revenue types
Revenue from contracts with customers:
Residential$3,560 $1,560 $59 $5,179 
C&I5,703 833 30 6,566 
Other150 — 13 163 
Total retail9,413 2,393 102 11,908 
Wholesale815 — — 815 
Transmission649 — — 649 
Other63 156 — 219 
Total revenue from contracts with customers10,940 2,549 102 13,591 
Alternative revenue and other506 96 13 615 
Total revenues$11,446 $2,645 $115 $14,206 
v3.25.4
Income Taxes (Tables)
 12 Months Ended
Dec. 31, 2025
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 YearExpiration
2022September 2026
State Statute of Limitations Applicable to Open Tax Years
StateTax Year(s)Expiration
Colorado2014 - 2016March 2026
Colorado2021October 2026
Minnesota2021June 2026
Texas2020June 2028
Texas2021June 2029
Texas2022August 2027
Texas2023November 2028
Wisconsin2021October 2026
Reconciliation of Unrecognized Tax Benefits
Unrecognized tax benefits - permanent vs. temporary:
(Millions of Dollars)Dec. 31, 2025Dec. 31, 2024
Unrecognized tax benefit — Permanent tax positions$43 $43 
Unrecognized tax benefit — Temporary tax positions— — 
Total unrecognized tax benefit$43 $43 
Changes in unrecognized tax benefits:
(Millions of Dollars)202520242023
Balance at Jan. 1$43 $41 $67 
Additions based on tax positions related to the current year 3 5 5 
Additions for tax positions of prior years2 2 1 
Reductions for tax positions of prior years(5)(3)(29)
Reductions for tax positions related to settlements with taxing authorities— — (1)
Reductions for tax positions related to statute of limitations— (2)(2)
Balance at Dec. 31$43 $43 $41 
Tax Benefits Associated with NOL and Tax Credit Carryforwards
Unrecognized tax benefits were reduced by tax benefits associated with NOL and tax credit carryforwards:
(Millions of Dollars)Dec. 31, 2025Dec. 31, 2024
NOL and tax credit carryforwards$(33)$(35)
Interest Payable related to Unrecognized Tax Benefits [Table Text Block]
Interest payable related to unrecognized tax benefits:
(Millions of Dollars)202520242023
Payable for interest related to unrecognized tax benefits at Jan. 1$(2)$(1)$(4)
Interest (expense) benefit related to unrecognized tax benefits(2)(1)3 
Payable for interest related to unrecognized tax benefits at Dec. 31$(4)$(2)$(1)
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)20252024
Federal tax credit carryforwards$1,474 $1,519 
Valuation allowances for federal credit carryforwards(10)(14)
State NOL carryforwards8 9 
Valuation allowances for state NOL carryforwards(5)(2)
State tax credit carryforwards, net of federal detriment (a)
71 70 
Valuation allowances for state credit carryforwards, net of federal benefit (b)
(64)(58)
(a)State tax credit carryforwards are net of federal detriment of $19 million as of Dec. 31, 2025 and 2024.
(b)Valuation allowances for state tax credit carryforwards were net of federal benefit of $17 million and $16 million as of Dec. 31, 2025 and 2024, respectively.
Schedule of Effective Income Tax Rate Reconciliation
Effective income tax reconciliation for years ended Dec. 31:
(Millions of Dollars)202520242023
Income before income taxes (domestic)$1,773 $1,534 $1,625 
Federal statutory rate impact372 322 341 
(Decreases) increases in tax from:
Tax credits
PTCs (a)
(569)(663)(455)
Other(14)(16)(17)
Regulatory adjustments (b)
Plant related excess deferred taxes(87)(87)(83)
AFUDC equity(58)(34)(19)
Other29 14 17 
State income taxes, net of federal tax effect (c)
78 58 73 
Other4 4 (3)
Income tax benefit$(245)$(402)$(146)
202520242023
Federal statutory rate21.0 %21.0 %21.0 %
(Decreases) increases in tax from:
Tax credits
PTCs (a)
(32.3)(43.2)(28.1)
Other(0.8)(1.1)(1.1)
Regulatory adjustments (b)
Plant related excess deferred taxes(4.9)(5.6)(5.1)
AFUDC equity(3.2)(2.2)(1.2)
Other1.6 0.9 1.0 
State income taxes, net of federal tax effect (c)
4.4 3.8 4.5 
Other0.4 0.2 — 
Effective income tax rate(13.8)%(26.2)%(9.0)%
(a)Wind, Solar and Nuclear PTCs (net of transfer discounts) are generally credited to customers (reduction to revenue) and do not materially impact earnings.
(b)Regulatory adjustments primarily relate to the credit of plant related excess deferred taxes to customers for tax rate increases as well as the capitalization of AFUDC equity for book purposes only. Income tax benefits associated with the credit of excess deferred taxes are offset by corresponding revenue reductions.
(c)State and local income taxes are primarily made up of the following jurisdictions: Minnesota, Colorado
Schedule of Components of Income Tax Expense (Benefit)
Components of income tax expense for years ended Dec. 31:
(Millions of Dollars)202520242023
Current federal tax (benefit) expense$(6)$36 $113 
Current state tax expense2 28 16 
Current change in unrecognized tax expense (benefit)1 2 (21)
Deferred federal tax benefit(333)(510)(331)
Deferred state tax expense96 46 75 
Deferred change in unrecognized tax (benefit) expense(1)— 7 
Deferred ITCs(4)(4)(5)
Total income tax benefit$(245)$(402)$(146)
Components of deferred income tax expense as of Dec. 31:
(Millions of Dollars)202520242023
Deferred tax expense excluding items below$685 $434 $129 
Adjustments to deferred income taxes for tax credit cash transfers(652)(689)(190)
Amortization and adjustments to deferred income taxes on income tax regulatory assets and liabilities(269)(201)(188)
Tax expense allocated to other comprehensive income and other(2)(8)— 
Deferred tax benefit$(238)$(464)$(249)
Schedule of Deferred Tax Assets and Liabilities
Components of net deferred tax liability as of Dec. 31:
(Millions of Dollars)2025
2024(a)
Deferred tax liabilities:
Differences between book and tax bases of property$7,587 $7,008 
Regulatory assets500 559 
Operating lease assets232 282 
Pension expense171 155 
Other98 93 
Total deferred tax liabilities$8,588 $8,097 
Deferred tax assets:
Tax credit carryforward$1,546 $1,589 
Regulatory liabilities663 744 
Operating lease liabilities231 282 
Other employee benefits116 102 
Deferred ITCs10 11 
NOL carryforward1 1 
NOL and tax credit valuation allowances(74)(73)
Other91 122 
Total deferred tax assets2,584 2,778 
Net deferred tax liability$6,004 $5,319 
(a)Prior periods have been reclassified to conform to current year presentation.
Schedule of Cash Flow, Supplemental Disclosures
Cash received (paid) for income taxes for the years ended Dec. 31:
(Millions of Dollars)202520242023
Cash received for income taxes: federal, net (a)
$671 $633 $104 
Cash paid for income taxes: state(30)(45)(12)
Total$641 $588 $92 
(a)Includes proceeds from tax credit transfers.
v3.25.4
Share-Based Compensation (Tables)
 12 Months Ended
Dec. 31, 2025
Share-Based Payment Arrangement [Abstract]  
Equity Awards
Equity award units granted to employees:
(Units in Thousands)202520242023
Granted units (a)
683 658 586 
Weighted average grant date fair value$68.19 $63.02 $67.06 
(a)Includes 2025, 2024 and 2023 grants of 379, 457 and 413 units (each in thousands), respectively, subject only to service conditions.
Equity awards vested:
(Units in Thousands, Fair Value in Millions)202520242023
Vested Units502 282 329 
Total Fair Value$37 $19 $20 
Changes in the nonvested portion of equity award units:
(Units in Thousands)UnitsWeighted Average
Grant Date Fair Value
Nonvested Units at Jan. 1, 20251,139 $64.55 
Granted683 68.19 
Forfeited(170)65.85 
Vested(502)66.27 
Dividend equivalents62 65.85 
Nonvested Units at Dec. 31, 20251,212 65.77 
TSR Liability Awards
Liability awards granted:
(In Thousands)202520242023
Awards granted (a)
109 193 216 
(a)All grants contain performance and/or market conditions.
Liability awards settled:
(Units In Thousands, Settlement Amount in Millions)202520242023
Awards settled74 — 282 
Settlement amount (cash, common stock and deferred amounts)$5 $— $19 
Compensation costs related to share-based awards
Compensation costs related to share-based awards:
(Millions of Dollars)202520242023
Cost for share-based awards (a)
$57 $30 $27 
Tax benefit recognized in income15 8 7 
(a)Compensation costs for share-based payments are included in O&M expense. Amount for equity awards (non-cash) was $46 million, $33 million and $25 million in 2025, 2024 and 2023, respectively.
v3.25.4
Earnings Per Share (Tables)
 12 Months Ended
Dec. 31, 2025
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)202520242023
Basic 587 563552
Diluted (a)
589 563 552 
(a)Diluted common shares outstanding included common stock equivalents of 2.1 million, 0.5 million, and 0.3 million shares for 2025, 2024 and 2023, respectively.
v3.25.4
Fair Value of Financial Assets and Liabilities (Tables)
 12 Months Ended
Dec. 31, 2025
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, 2025
Fair Value
(Millions of Dollars)CostLevel 1Level 2Level 3NAVTotal
Nuclear decommissioning fund (a)
Cash equivalents$60 $60 $— $— $— $60 
Commingled funds720 — — — 1,072 1,072 
Debt securities944 — 934 11 — 945 
Equity securities505 1,861 2 — — 1,863 
Total$2,229 $1,921 $936 $11 $1,072 $3,940 
(a)Reported in nuclear decommissioning fund and other investments on the consolidated balance sheets, which also includes $285 million of equity method investments and $164 million of rabbi trust assets and other miscellaneous investments.
Dec. 31, 2024
Fair Value
(Millions of Dollars)CostLevel 1Level 2Level 3NAVTotal
Nuclear decommissioning fund (a)
Cash equivalents$39 $39 $— $— $— $39 
Commingled funds703 — — — 1,025 1,025 
Debt securities866 — 832 14 — 846 
Equity securities522 1,583 1 — — 1,584 
Total$2,130 $1,622 $833 $14 $1,025 $3,494 
(a)Reported in nuclear decommissioning fund and other investments on the consolidated balance sheets, which also includes $246 million of equity investments in unconsolidated subsidiaries and $156 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, 2025:
Final Contractual Maturity
(Millions of Dollars)Due in 1 Year or LessDue in 1 to 5 YearsDue in 5 to 10 YearsDue after 10 YearsTotal
Debt securities$10 $344 $292 $299 $945 
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, 2025Dec. 31, 2024
MWh of electricity35 38 
MMBtu of natural gas31 77 
(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 LossRegulatory (Assets) and Liabilities
Year Ended Dec. 31, 2025
Derivatives designated as cash flow hedges
Interest rate$2 $— 
Total$2 $— 
Other derivative instruments
Electric commodity$— $69 
Natural gas commodity— (3)
Total$— $66 
Year Ended Dec. 31, 2024
Interest rate$29 $— 
Total$29 $— 
Other derivative instruments
Electric commodity$— $44 
Natural gas commodity— 4 
Total$— $48 
Year Ended Dec. 31, 2023
Interest rate$(2)$— 
Total$(2)$— 
Other derivative instruments
Electric commodity$— $(137)
Natural gas commodity— (13)
Total$— $(150)
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 LossRegulatory Assets and (Liabilities)
Year Ended Dec. 31, 2025
Derivatives designated as cash flow hedges
Interest rate$3 
(a)
$— $— 
Total$3 $— $— 
Other derivative instruments
Commodity trading$— $— $(3)
(b)
Electric commodity— (36)
(c)
— 
Natural gas commodity— — (22)
(d)(e)
Total$— $(36)$(25)
Year Ended Dec. 31, 2024
Derivatives designated as cash flow hedges
Interest rate$3 
(a)
$— $— 
Total$3 $— $— 
Other derivative instruments
Commodity trading$— $— $(27)
(b)
Electric commodity— (22)
(c)
— 
Natural gas commodity— — (22)
(d)(e)
Total$— $22 $(49)
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)
(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 auction and settlement dates, but exclude the original auction fair value.
(d)Other than $4 million of 2025 and $3 million of 2024 losses recorded to electric fuel and purchased power, amounts are recorded to cost of natural gas sold and transported. Amounts are subject to cost-recovery mechanisms and reclassified out of income to a regulatory asset, as appropriate.
(e)Relates primarily to option premium amortization.
Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis [Table Text Block]
Derivative assets and liabilities measured at fair value on a recurring basis were as follows:
Dec. 31, 2025Dec. 31, 2024
Fair ValueFair Value Total
Netting (a)
TotalFair ValueFair Value Total
Netting (a)
Total
(Millions of Dollars)Level 1Level 2Level 3Level 1Level 2Level 3
Current derivative assets
Derivatives designated as cash flow hedges:
Interest rate$— $1 $— $1 $— $1 $— $— $— $— $— $— 
Other derivative instruments:
Commodity trading$2 $13 $7 $22 $(16)$6 $6 $20 $8 $34 $(23)$11 
Electric commodity— — 147 147 (3)144 — — 90 90 (1)89 
Natural gas commodity— 14 — 14 — 14 — 14 — 14 — 14 
Total current derivative assets$2 $28 $154 $184 $(19)$165 $6 $34 $98 $138 $(24)$114 
Noncurrent derivative assets
Other derivative instruments:
Commodity trading$3 $28 $34 $65 $(11)$54 $8 $37 $47 $92 $(20)$72 
Total noncurrent derivative assets$3 $28 $34 $65 $(11)$54 $8 $37 $47 $92 $(20)$72 
Dec. 31, 2025Dec. 31, 2024
Fair ValueFair Value Total
Netting (a)
TotalFair ValueFair Value Total
Netting (a)
Total
(Millions of Dollars)Level 1Level 2Level 3Level 1Level 2Level 3
Current derivative liabilities
Other derivative instruments:
Commodity trading5 22 6 33 (18)15 7 35 5 47 (23)24 
Electric commodity— — 3 3 (3)— — — 1 1 (1)— 
Natural gas commodity— 10 — 10 — 10 — 7 — 7 — 7 
Total current derivative liabilities$5 $32 $9 $46 $(21)25 $7 $42 $6 $55 $(24)31 
PPAs (b)
6 6 
Current derivative instruments$31 $37 
Noncurrent derivative liabilities
Other derivative instruments:
Commodity trading$6 $24 $40 $70 $(13)$57 $11 $32 $40 $83 $(22)$61 
Total noncurrent derivative liabilities$6 $24 $40 $70 $(13)57 $11 $32 $40 $83 $(22)61 
PPAs (b)
10 16 
Noncurrent derivative instruments$67 $77 
    
(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, 2025 and 2024, derivative assets and liabilities include no obligations to return cash collateral. At Dec. 31, 2025 and 2024, derivative assets and liabilities include rights to reclaim cash collateral of $4 million and $2 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)202520242023
Balance at Jan. 1$99 $90 $236 
Purchases (a)
262 210 176 
Settlements (a)
(322)(303)(154)
Net transactions recorded during the period:
(Losses) gains recognized in earnings (b)
(13)(9)6 
Net gains (losses) recognized as regulatory assets and liabilities (a)
113 111 (174)
Balance at Dec. 31$139 $99 $90 
(a)Relates primarily to NSP-Minnesota and SPS FTR instruments administered by MISO and SPP, respectively.
(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:
20252024
(Millions of Dollars)Carrying AmountFair ValueCarrying AmountFair Value
Long-term debt, including current portion$32,333 $29,943 $28,419 $25,115 
v3.25.4
Benefit Plans and Other Postretirement Benefits (Tables)
 12 Months Ended
Dec. 31, 2025
Retirement 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, 2025 (a)
Dec. 31, 2024 (a)
(Millions of Dollars)Level 1Level 2Level 3Measured at NAVTotalLevel 1Level 2Level 3Measured at NAVTotal
Cash equivalents$110 $— $— $— $110 $117 $— $— $— $117 
Commingled funds (b)
— — — 1,097 1,097 — — — 1,015 1,015 
Debt securities— 745 3 — 748 — 656 6 — 662 
Equity securities23 — — — 23 25 — — — 25 
Partnerships (b)
— — — 704 704 — — — 679 679 
Other— 8 — — 8 — 6 — — 6 
Total$133 $753 $3 $1,801 $2,690 $142 $662 $6 $1,694 $2,504 
(a)See Note 10 for further information regarding fair value measurement inputs and methods.
(b)Prior period amounts have been reclassified to conform with current year presentation.
For each of the fair value hierarchy levels, Xcel Energy’s postretirement benefit plan assets that were measured at fair value:
Dec. 31, 2025 (a)
Dec. 31, 2024 (a)
(Millions of Dollars)Level 1Level 2Level 3Measured at NAVTotalLevel 1Level 2Level 3Measured at NAVTotal
Cash equivalents$35 $— $— $— $35 $35 $— $— $— $35 
Insurance contracts— 40 — — 40 — 40 — — 40 
Commingled funds (b)
— — — 67 67 — — — 23 23 
Debt securities— 154 — — 154 — 201 — — 201 
Partnerships (b)
— — — 45 45 — — — 45 45 
Other— 1 — — 1 — — — — — 
Total$35 $195 $— $112 $342 $35 $241 $— $68 $344 
(a)See Note 10 for further information on fair value measurement inputs and methods.
(b)Prior period amounts have been reclassified to conform with current year presentation.
Targeted asset allocations:
Pension BenefitsPostretirement Benefits
2025202420252024
Long-duration fixed income securities38 %38 %— %— %
Domestic and international equity securities30 31 25 25 
Alternative investments19 20 13 11 
Short-to-intermediate fixed income securities11 9 61 61 
Cash2 2 1 3 
Total100 %100 %100 %100 %
Changes in Projected Benefit Obligations, Fair Value of Plan Assets, and Funded Status of Plan [Table Text Block]
Pension BenefitsPostretirement Benefits
(Millions of Dollars)2025202420252024
Change in Benefit Obligation:
Obligation at Jan. 1$2,752 $2,943 $427 $394 
Service cost76 76 1 1 
Interest cost155 151 24 21 
Actuarial loss (gain) 67 (77)21 55 
Plan participants’ contributions— — 9 9 
Medicare subsidy reimbursements— — 3 — 
Benefit payments(230)(341)
(a)
(55)(53)
Obligation at Dec. 31$2,820 $2,752 $430 $427 
Change in Fair Value of Plan Assets:
Fair value of plan assets at Jan. 1$2,504 $2,690 $344 $356 
Actual return on plan assets291 55 31 21 
Employer contributions125 100 13 11 
Plan participants’ contributions— — 9 9 
Benefit payments(230)(341)(55)(53)
Fair value of plan assets at Dec. 312,690 2,504 342 344 
Funded status of plans at Dec. 31$(130)$(248)$(88)$(83)
Amounts recognized in the Consolidated Balance Sheet at Dec. 31:
Noncurrent assets$— $— $7 $10 
Current liabilities— — (2)(4)
Noncurrent liabilities(130)(248)(93)(89)
Net amounts recognized$(130)$(248)$(88)$(83)
(a)Includes $168 million of lump-sum benefit payments used in the determination of settlement charges in 2024.
Pension BenefitsPostretirement Benefits
Significant Assumptions Used to Measure Benefit Obligations:2025202420252024
Discount rate for year-end valuation5.78 %5.88 %5.66 %5.88 %
Expected average long-term increase in compensation level4.25 %4.25 %N/AN/A
Mortality tablePRI-2012PRI-2012PRI-2012PRI-2012
Health care costs trend rate — initial: Pre-65N/AN/A7.00 %7.00 %
Health care costs trend rate — initial: Post-65N/AN/A7.50 %7.50 %
Ultimate trend assumption — initial: Pre-65N/AN/A4.50 %4.50 %
Ultimate trend assumption — initial: Post-65N/AN/A4.50 %4.50 %
Years until ultimate trend is reachedN/AN/A89
Projected Benefit Payments for the Pension and Postretirement Benefit Plans
(Millions of  Dollars)Projected
Pension Benefit
Payments		Gross Projected
Postretirement
Health Care
Benefit Payments		Expected
Medicare Part D
Subsidies		Net Projected
Postretirement
Health Care
Benefit Payments
2026$252 $43 $3 $40 
2027243 42 3 39 
2028244 41 3 38 
2029249 40 3 37 
2030243 39 3 36 
2031-20351,165 183 16 167 
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost
Pension BenefitsPostretirement Benefits
(Millions of Dollars)2025202420252024
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost:
Net loss$1,029 $1,074 $117 $113 
Prior service credit(6)(8)— — 
Total$1,023 $1,066 $117 $113 
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$36 $32 $5 $2 
Noncurrent regulatory assets938 983 125 127 
Current regulatory liabilities— — (1)(1)
Noncurrent regulatory liabilities— — (15)(18)
Deferred income taxes13 14 1 1 
Net-of-tax accumulated other comprehensive income36 37 2 2 
Total$1,023 $1,066 $117 $113 
Components of Net Periodic Benefit Costs
Components of net periodic benefit cost and amounts recognized in other comprehensive income and regulatory assets and liabilities:
Pension BenefitsPostretirement Benefits
(Millions of Dollars)202520242023202520242023
Service cost$76 $76 $74 $1 $1 $1 
Interest cost155 151 158 24 21 22 
Expected return on plan assets(208)(206)(209)(20)(17)(17)
Amortization of prior service credit(2)(2)(1)— — (1)
Amortization of net loss28 30 22 4 2 1 
Settlement charge (a)
— 67 — — — — 
Net periodic pension cost49 116 44 9 7 6 
Effects of regulation10 (37)30 — — — 
Net benefit cost recognized for financial reporting$59 $79 $74 $9 $7 $6 
Significant Assumptions Used to Measure Costs:
Discount rate5.88 %5.49 %5.80 %5.88 %5.54 %5.80 %
Expected average long-term increase in compensation level4.25 4.25 4.25 — — — 
Expected average long-term rate of return on assets7.13 6.93 6.93 6.25 5.00 5.00 
Voluntary Retirement Program, Significant Assumptions to Measure Benefit Obligation
Significant Assumptions to Measure Benefit Obligations:20252024
Discount rate for year-end valuation4.50 %5.00 %
Mortality tablePRI-2012PRI-2012
Health care costs trend rate7.00 %7.00 %
Ultimate trend assumption4.50 %4.50 %
Years until ultimate trend is reached89
v3.25.4
Commitments and Contingencies (Tables)
 12 Months Ended
Dec. 31, 2025
Commitments and Contingencies Disclosure [Abstract]  
Asset Retirement Obligations
Xcel Energy’s AROs were as follows:
(Millions 
of Dollars)		Jan. 1, 2025
Amounts Incurred (a)
Accretion
Cash Flow Revisions (b)
Dec. 31, 2025
Electric
Nuclear$2,476 $— $127 $— $2,603 
Wind509 — 18 (12)515 
Steam, hydro and other production495 16 21 (1)531 
Distribution51 — 3 — 54 
Natural gas
Transmission and distribution179 — 9 (6)182 
Other
Miscellaneous3 — — — 3 
Total liability$3,713 $16 $178 $(19)$3,888 
(a)Amounts incurred largely pertain to obligations associated with new solar facilities.
(b)In 2025, AROs were revised for changes in timing and estimates of cash flows. Wind was revised due to the repowering of two wind facilities in NSP-Minnesota.
(Millions 
of Dollars)		Jan. 1, 2024
Amounts Incurred (a)
Amounts
Settled 		Accretion
Cash Flow Revisions (b)
Dec. 31, 2024
Electric
Nuclear$2,107 $— $— $106 $263 $2,476 
Wind526 — — 19 (36)509 
Steam, hydro and other production361 109 (6)18 13 495 
Distribution49 — — 2 — 51 
Natural gas
Transmission and distribution 172 — — 8 (1)179 
Other
Miscellaneous3 — — — — 3 
Total liability$3,218 $109 $(6)$153 $239 $3,713 
(a)Amounts incurred largely pertain to CCR coal ash regulations and new obligations associated with Sherco Solar Unit 1, which was placed in service in 2024.
(b)In 2024, AROs were revised for changes in timing and estimates of cash flows. Changes were driven by updated assumptions in the NSP-Minnesota nuclear decommissioning triennial filing coupled with discount rate and escalation rate changes. Wind, steam, hydro and other production AROs were revised due to the results of the 2024 dismantling studies and changes in cost estimates to remediate ash containment facilities.
Assets and Liabilities, Lessee [Table Text Block]
Operating lease ROU assets:
(Millions of Dollars)Dec. 31, 2025Dec. 31, 2024
PPAs$1,087 $1,802 
Other462 373 
Gross operating lease ROU assets1,549 2,175 
Accumulated amortization(656)(1,115)
Net operating lease ROU assets$893 $1,060 
Finance lease ROU assets:
(Millions of Dollars)Dec. 31, 2025Dec. 31, 2024
Generation facilities$1,254 $— 
Gas storage facilities160 160 
Gas pipeline21 21 
Gross finance lease ROU assets1,435 181 
Accumulated amortization(87)(70)
Net finance lease ROU assets$1,348 $111 
Lease, Cost [Table Text Block]
Leases
ROU assets represent Xcel Energy's rights to use leased assets. The present value of future operating lease payments is recognized in other current operating lease liabilities and noncurrent operating lease liabilities. The present value of future finance lease payments is included in other current liabilities and noncurrent finance lease liabilities. These amounts, adjusted for any prepayments or incentives, are recognized as ROU assets.
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, 2025Dec. 31, 2024
PPAs$1,087 $1,802 
Other462 373 
Gross operating lease ROU assets1,549 2,175 
Accumulated amortization(656)(1,115)
Net operating lease ROU assets$893 $1,060 
Finance lease ROU assets:
(Millions of Dollars)Dec. 31, 2025Dec. 31, 2024
Generation facilities$1,254 $— 
Gas storage facilities160 160 
Gas pipeline21 21 
Gross finance lease ROU assets1,435 181 
Accumulated amortization(87)(70)
Net finance lease ROU assets$1,348 $111 
In the third quarter of 2025, certain PPAs for natural gas fueled generating facilities were amended, extending NSP-Minnesota’s use of these plants to 2039 and 2048. The amended agreements qualify for classification as finance leases. As of Dec. 31, 2025, other current liabilities and non-current finance lease liabilities include $37 million and $1.2 billion of finance lease obligations for these amended PPAs, respectively. Prior to these amendments, the agreements were classified as operating leases.
Certain of Xcel Energy’s finance lease activities are related to WYCO, a joint venture with CIG, to develop and lease natural gas pipeline and storage 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.
Commitments under operating and finance leases as of Dec. 31, 2025:
(Millions of Dollars)
PPA (a) (b)
Operating
Leases
Other Operating
Leases
Total
Operating
Leases
Finance
 Leases (c)
2026$121 $31 $152 $112 
202790 40 130 111 
202880 40 120 114 
202978 37 115 115 
203078 33 111 117 
Thereafter185 446 631 1,614 
Total minimum obligation632 627 1,259 2,183 
Interest component of obligation(91)(270)(361)(882)
Present value of minimum obligation$541 357 898 1,301 
Less current portion(110)(39)
Noncurrent operating and finance lease liabilities$788 $1,262 
Weighted-average remaining lease term in years11.818.1
(a)Amounts do not include PPAs accounted for as executory contracts and/or contingent payments, such as energy payments on renewable PPAs.
(b)PPA operating leases contractually expire at various dates through 2033.
(c)Excludes certain amounts related to Xcel Energy’s 50% ownership interest in WYCO.
PPA finance lease payments are allocated between interest charges and depreciation and amortization on the consolidated statements of income. PPA operating lease payments are included in electric fuel and purchased power, and expense for other operating leases is included in O&M expense and electric fuel and purchased power.
Components of lease expense:
(Millions of Dollars)202520242023
Operating leases
PPA capacity payments$192 $228 $241 
Other operating leases (a)
43 43 42 
Total operating lease expense$235 $271 $283 
Finance leases
Amortization of ROU assets$16 $3 $3 
Interest expense on lease liability42 15 15 
Total finance lease expense$58 $18 $18 
(a)Includes immaterial short-term lease expense.
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 at commencement of each lease (weighted average of 5.1%).
Finance Lease, Liability, Maturity [Table Text Block]
Commitments under operating and finance leases as of Dec. 31, 2025:
(Millions of Dollars)
PPA (a) (b)
Operating
Leases
Other Operating
Leases
Total
Operating
Leases
Finance
 Leases (c)
2026$121 $31 $152 $112 
202790 40 130 111 
202880 40 120 114 
202978 37 115 115 
203078 33 111 117 
Thereafter185 446 631 1,614 
Total minimum obligation632 627 1,259 2,183 
Interest component of obligation(91)(270)(361)(882)
Present value of minimum obligation$541 357 898 1,301 
Less current portion(110)(39)
Noncurrent operating and finance lease liabilities$788 $1,262 
Weighted-average remaining lease term in years11.818.1
(a)Amounts do not include PPAs accounted for as executory contracts and/or contingent payments, such as energy payments on renewable PPAs.
(b)PPA operating leases contractually expire at various dates through 2033.
(c)Excludes certain amounts related to Xcel Energy’s 50% ownership interest in WYCO.
PPA finance lease payments are allocated between interest charges and depreciation and amortization on the consolidated statements of income. PPA operating lease payments are included in electric fuel and purchased power, and expense for other operating leases is included in O&M expense and electric fuel and purchased power.
Components of lease expense:
(Millions of Dollars)202520242023
Operating leases
PPA capacity payments$192 $228 $241 
Other operating leases (a)
43 43 42 
Total operating lease expense$235 $271 $283 
Finance leases
Amortization of ROU assets$16 $3 $3 
Interest expense on lease liability42 15 15 
Total finance lease expense$58 $18 $18 
(a)Includes immaterial short-term lease expense.
Estimated Future Payments for Capacity and Energy Pursuant to Purchased Power Agreements
At Dec. 31, 2025, 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)
2026$34 $99 
202731 72 
202825 72 
202925 70 
203020 51 
Thereafter206 411 
Total$341 $775 
(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, 2025:
(Millions of Dollars)CoalNuclear fuelNatural gas supplyNatural gas storage and transportation
2026$300 $67 $365 $399 
2027135 148 3 349 
202811 35 1 215 
20291 129 — 127 
20301 24 — 72 
Thereafter— 49 — 717 
Total$448 $452 $369 $1,879 
v3.25.4
Other Comprehensive Income (Tables)
 12 Months Ended
Dec. 31, 2025
Stockholders' Equity Note [Abstract]  
Changes in Accumulated Other Comprehensive Income (Loss), Net of Tax
Changes in accumulated other comprehensive loss, net of tax, for the years ended Dec. 31:
2025
(Millions of Dollars)Gains and Losses on Interest Rate Cash Flow HedgesDefined Benefit Pension and Postretirement ItemsTotal
Accumulated other comprehensive loss at Jan. 1$(29)$(39)$(68)
Other comprehensive income (loss) before reclassifications2 (1)1 
Losses reclassified from net accumulated other comprehensive loss:
Interest rate derivatives (a)
2 

— 2 
Amortization of net actuarial losses (b)
— 2 2 
Net current period other comprehensive income4 1 5 
Accumulated other comprehensive loss at Dec. 31$(25)$(38)$(63)
(a)Included in interest charges.
(b)Included in the computation of net periodic pension and postretirement benefit costs. See Note 11 for further information.
2024
(Millions of Dollars)Gains and Losses on Interest Rate Cash Flow HedgesDefined Benefit Pension and Postretirement ItemsTotal
Accumulated other comprehensive loss at Jan. 1$(53)$(41)$(94)
Other comprehensive income (loss) before reclassifications22 (3)19 
Losses reclassified from net accumulated other comprehensive loss:
Interest rate derivatives (a)
2 — 2 
Amortization of net actuarial losses (b)
— 5 5 
Net current period other comprehensive income24 2 26 
Accumulated other comprehensive loss at Dec. 31$(29)$(39)$(68)
(a)Included in interest charges.
(b)Included in the computation of net periodic pension and postretirement benefit costs. See Note 11 for further information.
v3.25.4
Segments and Related Information (Tables)
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Segment Reporting [Abstract]      
Results from Operations by Reportable Segment
Segment information and reconciliations to Xcel Energy’s consolidated operating revenues and net income:
2025
(Millions of Dollars)Regulated electric utilityRegulated natural gas utilityTotal segments
Operating revenues$12,160 $2,452 $14,612 
Intersegment revenue1 26 27 
Total segment revenues12,161 2,478 14,639 
Electric fuel and purchased power3,961 — 3,961 
Cost of natural gas sold and transported— 1,041 1,041 
O&M expenses2,259 425 2,684 
Depreciation and amortization2,525 413 2,938 
Other segment expenses, net (a)
925 151 1,076 
Interest charges and financing costs886 125 1,011 
Income tax (benefit) expense(265)67 (198)
Net income$1,870 $256 $2,126 
Total segment revenues$14,639 
Eliminate intersegment revenue(27)
Non-segment revenues57 
Consolidated operating revenues$14,669 
Total segment net income$2,126 
Non-segment net loss(108)
Consolidated net income$2,018 
(a)Other segment expenses, net, for 2025 additionally includes Marshall Wildfire litigation expense.
2024
(Millions of Dollars)Regulated electric utilityRegulated natural gas utilityTotal segments
Operating revenues$11,147 $2,230 $13,377 
Intersegment revenue2 22 24 
Total segment revenues11,149 2,252 13,401 
Electric fuel and purchased power3,788 — 3,788 
Cost of natural gas sold and transported— 951 951 
O&M expenses2,102 409 2,511 
Depreciation and amortization2,373 357 2,730 
Other segment expenses, net693 123 816 
Interest charges and financing costs767 113 880 
Income tax (benefit) expense(420)62 (358)
Net income$1,846 $237 $2,083 
Total segment revenues$13,401 
Eliminate intersegment revenue(24)
Non-segment revenues64 
Consolidated operating revenues$13,441 
Total segment net income$2,083 
Non-segment net loss(147)
Consolidated net income$1,936 
2023
(Millions of Dollars)Regulated electric utilityRegulated natural gas utilityTotal segments
Operating revenues$11,446 $2,645 $14,091 
Intersegment revenue2 3 5 
Total segment revenues11,448 2,648 14,096 
Electric fuel and purchased power4,278 — 4,278 
Cost of natural gas sold and transported— 1,456 1,456 
O&M expenses2,011 386 2,397 
Depreciation and amortization2,111 323 2,434 
Other segment expenses, net (a)
827 118 945 
Interest charges and financing costs670 96 766 
Income tax (benefit) expense(135)50 (85)
Net income$1,686 $219 $1,905 
Total segment revenues$14,096 
Eliminate intersegment revenue(5)
Non-segment revenues115 
Consolidated operating revenues$14,206 
Total segment net income$1,905 
Non-segment net loss(134)
Consolidated net income$1,771 
(a)Other segment expenses, net, for 2023 additionally includes loss on Comanche Unit 3 litigation with CORE Electric Cooperative related to lost power damages and other costs and workforce reduction expenses.
v3.25.4
Schedule II, Valuation and Qualifying Accounts SEC Schedule, 12-09, Schedule of Valuation and Qualifying Accounts (Tables)
 12 Months Ended
Dec. 31, 2025
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 debtsNOL and tax credit valuation allowances
(Millions of Dollars)202520242023202520242023
Balance at Jan. 1$111 $128 $122 $73 $70 $62 
Additions charged to costs and expenses64 64 79 37 45 26 
Additions charged to other accounts15 
(a)
16 
(a)
13 
(a)
— — — 
Deductions from reserves(101)
(b)
(97)
(b)
(86)
(b)
(36)
(c)
(42)
(c)
(18)
(c)
Balance at Dec. 31$89 $111 $128 $74 $73 $70 
(a)Recovery of amounts previously written-off.
(b)Deductions related primarily to bad debt write-offs.
(c)Primarily reversals of valuation allowances on completed tax credit sales and reductions of valuation allowances for items forecasted to be used prior to expiration.
v3.25.4
Summary of Significant Accounting Policies Summary of Significant Accounting Policies (Details) - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Property, Plant and Equipment [Abstract]      
Depreciation expense expressed as a percentage of average depreciable property 3.90% 3.80% 3.60%
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 $ 89 $ 111  
Alternative Revenue Programs [Abstract]      
maximum number of months following end of annual period in which revenues are earned to be included in 24 months    
Public Utilities, Inventory      
Inventories $ 761 666  
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]      
Public Utilities, Inventory      
Inventories $ 489 406  
Public Utilities, Inventory, Fuel [Member]      
Public Utilities, Inventory      
Inventories 156 164  
Public Utilities, Inventory, Natural Gas [Member]      
Public Utilities, Inventory      
Inventories $ 116 $ 96  
v3.25.4
Property Plant and Equipment Major classes of property, plant and equipment (Details) - USD ($)
$ in Millions
Dec. 31, 2025
Dec. 31, 2024
Property, Plant and Equipment [Line Items]    
Property, plant and equipment $ 85,879 $ 76,653
Accumulated depreciation and amortization (20,710) (19,852)
Property, Plant and Equipment, Gross, Including Nuclear Fuel 3,678 3,491
Accumulated Depreciation, Depletion and Amortization, Property, Plant, and Equipment, Nuclear Fuel (3,208) (3,094)
Property, plant and equipment, net 65,639 57,198
Electric plant    
Property, Plant and Equipment [Line Items]    
Property, plant and equipment 61,892 56,791
Natural gas plant    
Property, Plant and Equipment [Line Items]    
Property, plant and equipment 10,517 9,834
Common and other property    
Property, Plant and Equipment [Line Items]    
Property, plant and equipment 3,790 3,515
Plant to be retired    
Property, Plant and Equipment [Line Items]    
Property, plant and equipment [1] 1,595 1,793
CWIP    
Property, Plant and Equipment [Line Items]    
Property, plant and equipment $ 8,085 $ 4,720
[1] Amounts include Sherco 1 and 3 and A.S. King for NSP-Minnesota; Comanche Unit 3, Craig Unit 2, Hayden Units 1 and 2 for PSCo; and Tolk Unit 1 and 2 for SPS. The Dec. 31, 2024 amounts also include coal generation assets at Pawnee (assets were retired in 2025 and the conversion to natural gas is complete). Additionally, 2024 amounts included both Comanche Unit 2 and Craig Unit 1, which had planned retirement dates in 2025. Amounts are presented net of accumulated depreciation.
v3.25.4
Property Plant and Equipment Joint Ownership of Generation, Transmission and Gas Facilities (Details)
$ in Millions
Dec. 31, 2025
USD ($)
NSP Minnesota  
Jointly Owned Utility Plant Interests [Line Items]  
Plant in Service $ 1,779 [1]
Accumulated Depreciation 830 [1]
CWIP 26
NSP Minnesota | Electric Generation | Sherco Unit 3  
Jointly Owned Utility Plant Interests [Line Items]  
Plant in Service 638
Accumulated Depreciation $ 515
Percent Owned 59.00%
NSP Minnesota | Electric Generation | Sherco Common Facilities  
Jointly Owned Utility Plant Interests [Line Items]  
Plant in Service $ 189
Accumulated Depreciation $ 134
Percent Owned 80.00%
NSP Minnesota | Electric Generation | Sherco substation  
Jointly Owned Utility Plant Interests [Line Items]  
Plant in Service $ 5
Accumulated Depreciation $ 4
Percent Owned 59.00%
NSP Minnesota | Electric Transmission | Grand Meadow  
Jointly Owned Utility Plant Interests [Line Items]  
Plant in Service $ 11
Accumulated Depreciation $ 4
Percent Owned 50.00%
NSP Minnesota | Electric Transmission | Huntley Wilmarth  
Jointly Owned Utility Plant Interests [Line Items]  
Plant in Service $ 49
Accumulated Depreciation $ 4
Percent Owned 50.00%
NSP Minnesota | Electric Transmission | CapX2020  
Jointly Owned Utility Plant Interests [Line Items]  
Plant in Service $ 887
Accumulated Depreciation $ 169
Percent Owned 51.00%
NSP-Wisconsin  
Jointly Owned Utility Plant Interests [Line Items]  
Plant in Service $ 348 [2]
Accumulated Depreciation 79 [2]
CWIP 3
NSP-Wisconsin | Electric Transmission | La Crosse, WI to Madison, WI  
Jointly Owned Utility Plant Interests [Line Items]  
Plant in Service 179
Accumulated Depreciation $ 33
Percent Owned 37.00%
NSP-Wisconsin | Electric Transmission | CapX2020  
Jointly Owned Utility Plant Interests [Line Items]  
Plant in Service $ 169
Accumulated Depreciation $ 46
Percent Owned 80.00%
PSCo  
Jointly Owned Utility Plant Interests [Line Items]  
Plant in Service $ 1,710 [3]
Accumulated Depreciation 677 [3]
CWIP 16
PSCo | Electric Generation | Hayden Unit 1  
Jointly Owned Utility Plant Interests [Line Items]  
Plant in Service 159
Accumulated Depreciation $ 126
Percent Owned 76.00%
PSCo | Electric Generation | Hayden Unit 2  
Jointly Owned Utility Plant Interests [Line Items]  
Plant in Service $ 152
Accumulated Depreciation $ 99
Percent Owned 37.00%
PSCo | Electric Generation | Hayden Common Facilities  
Jointly Owned Utility Plant Interests [Line Items]  
Plant in Service $ 45
Accumulated Depreciation $ 36
Percent Owned 53.00%
PSCo | Electric Generation | Craig Units 1 and 2  
Jointly Owned Utility Plant Interests [Line Items]  
Plant in Service $ 82
Accumulated Depreciation $ 60
Percent Owned 10.00%
PSCo | Electric Generation | Craig Common Facilities  
Jointly Owned Utility Plant Interests [Line Items]  
Plant in Service $ 40
Accumulated Depreciation $ 28
Percent Owned 7.00%
PSCo | Electric Generation | Comanche Unit 3  
Jointly Owned Utility Plant Interests [Line Items]  
Plant in Service $ 971
Accumulated Depreciation $ 233
Percent Owned 67.00%
PSCo | Electric Generation | Comanche Common Facilities  
Jointly Owned Utility Plant Interests [Line Items]  
Plant in Service $ 29
Accumulated Depreciation $ 6
Percent Owned 77.00%
PSCo | Electric Transmission | Transmission and other facilities  
Jointly Owned Utility Plant Interests [Line Items]  
Plant in Service $ 193
Accumulated Depreciation 76
PSCo | Gas Transportation | Rifle, CO to Avon, CO  
Jointly Owned Utility Plant Interests [Line Items]  
Plant in Service 31
Accumulated Depreciation $ 10
Percent Owned 60.00%
PSCo | Gas Transportation | Gas Transportation Compressor  
Jointly Owned Utility Plant Interests [Line Items]  
Plant in Service $ 8
Accumulated Depreciation $ 3
Percent Owned 60.00%
[1] Projects additionally include $26 million in CWIP.
[2] Projects additionally include $3 million in CWIP.
[3] Projects additionally include $16 million in CWIP.
v3.25.4
Regulatory Assets and Liabilities, Regulatory Assets (Details) - USD ($)
$ in Millions
Dec. 31, 2025
Dec. 31, 2024
Regulatory Assets [Line Items]    
Regulatory Asset, Current $ 529 $ 561 [1]
Regulatory Asset, Noncurrent 2,998 2,849 [1]
Regulatory assets not currently earning a return 799 892
Pension and retiree medical obligations    
Regulatory Assets [Line Items]    
Regulatory Asset, Current 39 39 [1]
Regulatory Asset, Noncurrent 1,121 1,167 [1]
Recoverable deferred taxes on AFUDC recorded in plant    
Regulatory Assets [Line Items]    
Regulatory Asset, Current 0 0 [1]
Regulatory Asset, Noncurrent 434 368 [1]
Net AROs    
Regulatory Assets [Line Items]    
Regulatory Asset, Current 0 0 [1]
Regulatory Asset, Noncurrent 422 387 [1]
Excess deferred taxes - TCJA    
Regulatory Assets [Line Items]    
Regulatory Asset, Current 11 10 [1]
Regulatory Asset, Noncurrent 162 184 [1]
Depreciation differences    
Regulatory Assets [Line Items]    
Regulatory Asset, Current 22 17 [1]
Regulatory Asset, Noncurrent 320 250 [1]
Environmental remediation costs    
Regulatory Assets [Line Items]    
Regulatory Asset, Current 9 13 [1]
Regulatory Asset, Noncurrent 34 39 [1]
Deferred purchased natural gas and electric energy costs    
Regulatory Assets [Line Items]    
Regulatory Asset, Current 88 99 [1]
Regulatory Asset, Noncurrent $ 15 25 [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 2 years  
Conservation programs    
Regulatory Assets [Line Items]    
Regulatory Asset, Current [2] $ 18 20 [1]
Regulatory Asset, Noncurrent [2] $ 28 30 [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  
PI extended power update    
Regulatory Assets [Line Items]    
Regulatory Asset, Current $ 4 4 [1]
Regulatory Asset, Noncurrent $ 30 34 [1]
Regulatory Asset, Remaining Amortization Period 9 years  
Benson Biomass PPA termination and asset purchase    
Regulatory Assets [Line Items]    
Regulatory Asset, Current $ 10 10 [1]
Regulatory Asset, Noncurrent $ 16 26 [1]
Regulatory Asset, Remaining Amortization Period 3 years  
Sales true-up and revenue decoupling    
Regulatory Assets [Line Items]    
Regulatory Asset, Current $ 75 123 [1]
Regulatory Asset, Noncurrent 2 68 [1]
Gas pipeline inspection and remediation costs    
Regulatory Assets [Line Items]    
Regulatory Asset, Current 31 47 [1]
Regulatory Asset, Noncurrent $ 0 9 [1]
Gas pipeline inspection and remediation costs | Minimum    
Regulatory Assets [Line Items]    
Regulatory Asset, Remaining Amortization Period 1 year  
Nuclear refueling outage costs    
Regulatory Assets [Line Items]    
Regulatory Asset, Current $ 58 51 [1]
Regulatory Asset, Noncurrent $ 20 20 [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 $ 2 3 [1]
Regulatory Asset, Noncurrent 67 30 [1]
Renewable resources and environmental initiatives    
Regulatory Assets [Line Items]    
Regulatory Asset, Current 40 34 [1]
Regulatory Asset, Noncurrent $ 4 4 [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 $ 117 91 [1]
Regulatory Asset, Noncurrent 259 202 [1]
Excess liability insurance costs    
Regulatory Assets [Line Items]    
Regulatory Asset, Current 5 0 [1]
Regulatory Asset, Noncurrent $ 64 $ 6 [1]
[1] Prior period amounts have been reclassified to conform with current year presentation.
[2] Includes costs for conservation programs, as well as incentives allowed in certain jurisdictions.
v3.25.4
Regulatory Assets and Liabilities, Regulatory Liabilities (Details) - USD ($)
$ in Millions
Dec. 31, 2025
Dec. 31, 2024
Regulatory Liabilities [Line Items]    
Regulatory Liability, Current $ 714 $ 852
Regulatory Liability, Noncurrent 6,277 6,010
Regulatory assets not currently earning a return 799 892
Regulatory assets not currently earning a return 799 892
Deferred income tax adjustment and TCJA refunds    
Regulatory Liabilities [Line Items]    
Regulatory Liability, Current [1] 7 7
Regulatory Liability, Noncurrent [1] 2,758 2,888
Plant removal costs    
Regulatory Liabilities [Line Items]    
Regulatory Liability, Current 0 0
Regulatory Liability, Noncurrent 2,336 2,208
Effects of regulation on employee benefit costs    
Regulatory Liabilities [Line Items]    
Regulatory Liability, Current [2] 0 0
Regulatory Liability, Noncurrent [2] 261 259
Renewable resources and environmental initiatives    
Regulatory Liabilities [Line Items]    
Regulatory Liability, Current 16 16
Regulatory Liability, Noncurrent 319 232
Net AROs    
Regulatory Liabilities [Line Items]    
Regulatory Liability, Current [3] 0 0
Regulatory Liability, Noncurrent [3] 354 161
ITC deferrals    
Regulatory Liabilities [Line Items]    
Regulatory Liability, Current 0 0
Regulatory Liability, Noncurrent 64 70
Contract valuation adjustments    
Regulatory Liabilities [Line Items]    
Regulatory Liability, Current [4] 144 89
Regulatory Liability, Noncurrent [4] $ 0 0
Contract valuation adjustments | Minimum    
Regulatory Liabilities [Line Items]    
Regulatory Liability, Amortization Period 1 year  
Deferred electric, natural gas and steam production costs    
Regulatory Liabilities [Line Items]    
Regulatory Liability, Current $ 296 480
Regulatory Liability, Noncurrent $ 13 12
Deferred electric, natural gas and steam production costs | Minimum    
Regulatory Liabilities [Line Items]    
Regulatory Liability, Amortization Period 1 year  
Deferred electric, natural gas and steam production costs | Maximum    
Regulatory Liabilities [Line Items]    
Regulatory Asset, Remaining Amortization Period 2 years  
Conservation programs    
Regulatory Liabilities [Line Items]    
Regulatory Liability, Current [5] $ 39 52
Regulatory Liability, Noncurrent [5] $ 0 0
Conservation programs | Minimum    
Regulatory Liabilities [Line Items]    
Regulatory Liability, Amortization Period 1 year  
Other    
Regulatory Liabilities [Line Items]    
Regulatory Liability, Current $ 193 205
Regulatory Liability, Noncurrent 153 143
Inflation Reduction Act deferral    
Regulatory Liabilities [Line Items]    
Regulatory Liability, Current 19 3
Regulatory Liability, Noncurrent $ 19 $ 37
Inflation Reduction Act deferral | Minimum    
Regulatory Liabilities [Line Items]    
Regulatory Liability, Amortization Period 1 year  
Inflation Reduction Act deferral | Maximum    
Regulatory Liabilities [Line Items]    
Regulatory Liability, Amortization Period 2 years  
[1] Includes the revaluation of recoverable/regulated plant ADIT and revaluation impact of non-plant ADIT due to the TCJA.
[2] Includes regulatory amortization and certain 2018 TCJA benefits approved by the CPUC to offset the PSCo prepaid pension asset.
[3] Includes amounts recorded for future recovery of AROs, less amounts recovered through nuclear decommissioning accruals and gains from decommissioning investments.
[4] Includes the fair value of FTR instruments utilized/intended to offset the impacts of transmission system congestion.
[5] Includes costs for conservation programs, as well as incentives allowed in certain jurisdictions.
v3.25.4
Borrowings and Other Financing Instruments Short-Term Debt (Details) - USD ($)
$ in Millions
 3 Months Ended 12 Months Ended
Dec. 31, 2025
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Short-term Debt [Line Items]        
Amount outstanding at period end $ 1,550 $ 1,550 $ 695  
Commercial Paper        
Short-term Debt [Line Items]        
Line of Credit Facility, Maximum Borrowing Capacity 4,750 4,750 3,550 $ 3,550
Amount outstanding at period end 1,550 1,550 695 785
Average amount outstanding 1,622 1,026 508 491
Maximum amount outstanding $ 2,965 $ 2,965 $ 1,314 $ 1,241
Weighted average interest rate, computed on a daily basis (percentage) 4.14% 4.41% 5.47% 5.12%
Weighted average interest rate at period end (percentage) 3.95% 3.95% 4.64% 5.52%
v3.25.4
Borrowings and Other Financing Instruments Term Loan Agreement (Details) - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Short-term Debt [Line Items]    
Amount outstanding at period end $ 1,550 $ 695
364-Day Term Loan | Xcel Energy Inc.    
Short-term Debt [Line Items]    
Line of Credit Facility, Expiration Period 364 days  
Short-term Debt [Member] | 364-Day Term Loan | Xcel Energy Inc.    
Short-term Debt [Line Items]    
Line of Credit Facility, Maximum Borrowing Capacity $ 1,500  
Letter of Credit    
Short-term Debt [Line Items]    
Amount outstanding at period end 92 42
Letter of Credit | 364-Day Term Loan | Xcel Energy Inc.    
Short-term Debt [Line Items]    
Amount outstanding at period end 750  
Xcel Energy Inc.    
Short-term Debt [Line Items]    
Amount outstanding at period end $ 850 $ 235
v3.25.4
Borrowings and Other Financing Instruments Bilateral Credit Agreement (Details) - USD ($)
$ in Millions
Dec. 31, 2025
Dec. 31, 2024
Short-term Debt [Line Items]    
Amount outstanding at period end $ 1,550 $ 695
Revolving Credit Facility [Member]    
Short-term Debt [Line Items]    
Line of Credit Facility, Maximum Borrowing Capacity [1] 4,750  
Letter of Credit    
Short-term Debt [Line Items]    
Amount outstanding at period end 92 $ 42
NSP Minnesota | Revolving Credit Facility [Member]    
Short-term Debt [Line Items]    
Line of Credit Facility, Maximum Borrowing Capacity [1] 800  
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 $ 69  
[1] These credit facilities mature in December 2029.
v3.25.4
Borrowings and Other Financing Instruments Letters of Credit (Details) - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Line of Credit Facility [Line Items]    
Amount outstanding at period end $ 1,550 $ 695
Xcel Energy Inc.    
Line of Credit Facility [Line Items]    
Amount outstanding at period end $ 850 $ 235
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] $ 4,750  
Revolving Credit Facility [Member] | Xcel Energy Inc.    
Line of Credit Facility [Line Items]    
Line of Credit Facility, Maximum Borrowing Capacity [1] $ 2,000  
[1] These credit facilities mature in December 2029.
v3.25.4
Borrowings and Other Financing Instruments Credit Facilities (Details)
$ in Millions
 12 Months Ended
Dec. 31, 2025
USD ($)
Dec. 31, 2024
USD ($)
Line of Credit Facility [Line Items]    
Amount outstanding at period end $ 1,550 $ 695
Letter of Credit    
Line of Credit Facility [Line Items]    
Amount outstanding at period end 92 42
Revolving Credit Facility [Member]    
Line of Credit Facility [Line Items]    
Line of Credit Facility, Maximum Borrowing Capacity [1] 4,750  
Drawn [2] 1,642  
Available 3,108  
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 65.00%  
Line Of Credit Facility Minimum Threshhold Percentage Of Subsidiary Assets To Consolidated Assets Required To Initiate Cross Default Provisions 15.00%  
Line of Credit Facility, Minimum Amount of Indebtedness in Default to Initiate Cross Default Provisions $ 75  
Xcel Energy Inc.    
Line of Credit Facility [Line Items]    
Amount outstanding at period end 850 $ 235
Xcel Energy Inc. | Revolving Credit Facility [Member]    
Line of Credit Facility [Line Items]    
Line of Credit Facility, Maximum Borrowing Capacity [1] 2,000  
Drawn [2] 850  
Available $ 1,150  
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% 59.80%
Line Of Credit Facility Maximum Amount Credit Facility May Be Increased [4],[5] $ 450  
Number Of Additional Periods Revolving Termination Date Can Be Extended Subject To Majority Bank Group Approval [4],[6] 2  
Xcel Energy Inc. | Parent [Member] | Revolving Credit Facility [Member]    
Line of Credit Facility [Line Items]    
Line Of Credit Facility Maximum Debt To Total Capitalization Ratio Allowed 70.00%  
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] 47.00% 47.10%
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] 0  
Available $ 150  
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] 50.00% 47.00%
Line Of Credit Facility Maximum Amount Credit Facility May Be Increased [5] $ 170  
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] $ 800  
Drawn [2] 264  
Available $ 536  
SPS | Revolving Credit Facility [Member]    
Line of Credit Facility [Line Items]    
Line Of Credit Facility Debt To Total Capitalization Ratio (as a percent) [3] 47.20% 46.60%
Line Of Credit Facility Maximum Amount Credit Facility May Be Increased [5] $ 60  
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] $ 600  
Drawn [2] 220  
Available $ 380  
PSCo | Revolving Credit Facility [Member]    
Line of Credit Facility [Line Items]    
Line Of Credit Facility Debt To Total Capitalization Ratio (as a percent) [3] 44.90% 45.20%
Line Of Credit Facility Maximum Amount Credit Facility May Be Increased [5] $ 170  
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] $ 1,200  
Drawn [2] 308  
Available $ 892  
[1] These credit facilities mature in December 2029.
[2] Includes outstanding commercial paper and letters of credit.
[3] Each credit facility has a financial covenant requiring that the debt-to-total capitalization ratio be less than or equal to 65% (70% for Xcel Energy Inc.).
[4] The Xcel Energy Inc. credit facility has a cross-default provision that Xcel Energy Inc. would be in default on its borrowings under the facility if it or any of its subsidiaries (except NSP-Wisconsin as long as its total assets do not comprise more than 15% of Xcel Energy’s consolidated total assets) default on indebtedness in an aggregate principal amount exceeding $75 million.
[5] Amounts authorized by state commissions in respective jurisdictions.
[6] All extension requests are subject to majority bank group approval.
v3.25.4
Borrowings and Other Financing Instruments Amended Credit Agreements (Details) - Revolving Credit Facility [Member] - USD ($)
$ in Millions
Dec. 31, 2025
Dec. 31, 2024
Line of Credit Facility [Line Items]    
Line of Credit Facility, Maximum Borrowing Capacity [1] $ 4,750  
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] 800  
Xcel Energy Inc.    
Line of Credit Facility [Line Items]    
Line of Credit Facility, Maximum Borrowing Capacity [1] $ 2,000  
[1] These credit facilities mature in December 2029.
v3.25.4
Borrowings and Other Financing Instruments Long-Term Borrowings and Other Financing Instruments (Details) - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Long-Term Borrowings and Other Financing Instruments    
Long-term Debt, Gross $ 32,333.0 $ 28,419.0
2026 501.0  
2027 501.0  
2028 1,483.0  
2029 503.0  
2030 600.0  
Long-term Debt 31,832.0 27,316.0
NSP Minnesota    
Long-Term Borrowings and Other Financing Instruments    
Debt Instrument, Repurchased Face Amount 787.0 166.0
Debt Instrument, Repurchase Amount 607.0 105.0
Gain (Loss) on Repurchase of Debt Instrument 162.0 56.0
Interest Expense, Debt $ 6.0  
Series Due May 15, 2044 [Member] | NSP Minnesota    
Long-Term Borrowings and Other Financing Instruments    
Debt Instrument, Interest Rate, Stated Percentage 4.125%  
Series Due Aug. 15, 2045 [Member] | NSP Minnesota    
Long-Term Borrowings and Other Financing Instruments    
Debt Instrument, Interest Rate, Stated Percentage 4.00%  
Series Due May 15, 2046 [Member] | NSP Minnesota    
Long-Term Borrowings and Other Financing Instruments    
Debt Instrument, Interest Rate, Stated Percentage 3.60%  
Series Due March 1, 2050 | NSP Minnesota    
Long-Term Borrowings and Other Financing Instruments    
Debt Instrument, Interest Rate, Stated Percentage 2.90%  
Series Due June 1, 2051 | NSP Minnesota    
Long-Term Borrowings and Other Financing Instruments    
Debt Instrument, Interest Rate, Stated Percentage 2.60%  
Series Due April 1, 2052 | NSP Minnesota    
Long-Term Borrowings and Other Financing Instruments    
Debt Instrument, Interest Rate, Stated Percentage 3.20%  
Xcel Energy Inc.    
Long-Term Borrowings and Other Financing Instruments    
Unamortized discount $ (10.0) (9.0)
Unamortized Debt Issuance Expense (38.0) (34.0)
Current Maturities (500.0) (600.0)
Long-term Debt 7,832.0 6,337.0
Xcel Energy Inc. | Unsecured Debt [Member] | Series Due June 1, 2025 [Member]    
Long-Term Borrowings and Other Financing Instruments    
Face Amount $ 0.0 (350.0)
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 $ 0.0 (250.0)
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 $ (500.0) (500.0)
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 $ (500.0) (500.0)
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 $ (130.0) (130.0)
Debt Instrument, Interest Rate, Stated Percentage 4.00%  
Xcel Energy Inc. | Unsecured Debt [Member] | Series Due June 15, 2028 2 [Member]    
Long-Term Borrowings and Other Financing Instruments    
Face Amount $ (500.0) (500.0)
Debt Instrument, Interest Rate, Stated Percentage 4.00%  
Xcel Energy Inc. | Unsecured Debt [Member] | Series Due Dec. 1, 2029 [Member]    
Long-Term Borrowings and Other Financing Instruments    
Face Amount $ (500.0) (500.0)
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 $ (600.0) (600.0)
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 $ (300.0) (300.0)
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 $ (300.0) (300.0)
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 $ (250.0) (250.0)
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 $ (500.0) (500.0)
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 $ (700.0) (700.0)
Debt Instrument, Interest Rate, Stated Percentage 4.60%  
Xcel Energy Inc. | Unsecured Debt [Member] | Series Due Aug. 15, 2033    
Long-Term Borrowings and Other Financing Instruments    
Face Amount $ (800.0) (800.0)
Debt Instrument, Interest Rate, Stated Percentage 5.45%  
Xcel Energy Inc. | Unsecured Debt [Member] | Series Due Mar. 15, 2034    
Long-Term Borrowings and Other Financing Instruments    
Face Amount [1] $ (800.0) (800.0)
Debt Instrument, Interest Rate, Stated Percentage [1] 5.50%  
Xcel Energy Inc. | Unsecured Debt [Member] | Series Due March 21, 2028    
Long-Term Borrowings and Other Financing Instruments    
Face Amount [2] $ (350.0) 0.0
Debt Instrument, Interest Rate, Stated Percentage [2] 4.75%  
Xcel Energy Inc. | Unsecured Debt [Member] | Series Due April 15, 2035    
Long-Term Borrowings and Other Financing Instruments    
Face Amount [2] $ (750.0) 0.0
Debt Instrument, Interest Rate, Stated Percentage [2] 5.60%  
Xcel Energy Inc. | Junior Subordinated Debt | Series Due Oct 15, 2085    
Long-Term Borrowings and Other Financing Instruments    
Face Amount [2],[3] $ (900.0) 0.0
Debt Instrument, Interest Rate, Stated Percentage [2],[3] 6.25%  
NSP Minnesota    
Long-Term Borrowings and Other Financing Instruments    
Unamortized discount $ (50.0) (49.0)
Unamortized Debt Issuance Expense (90.0) (80.0)
Current Maturities 0.0 (250.0)
Long-term Debt 7,908.0 7,607.0
NSP Minnesota | Mortgage bonds | Xcel Energy [Member]    
Long-Term Borrowings and Other Financing Instruments    
Face Amount (953.0) (166.0)
NSP Minnesota | Mortgage bonds | Series Due July 1, 2025 [Member]    
Long-Term Borrowings and Other Financing Instruments    
Face Amount $ 0.0 (250.0)
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 $ (150.0) (150.0)
Debt Instrument, Interest Rate, Stated Percentage 6.50%  
NSP Minnesota | Mortgage bonds | Series Due April 1, 2031    
Long-Term Borrowings and Other Financing Instruments    
Face Amount $ (425.0) (425.0)
Debt Instrument, Interest Rate, Stated Percentage 2.25%  
NSP Minnesota | Mortgage bonds | Series Due July 15, 2035 [Member]    
Long-Term Borrowings and Other Financing Instruments    
Face Amount $ (250.0) (250.0)
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 $ (400.0) (400.0)
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 $ (350.0) (350.0)
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 $ (300.0) (300.0)
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 $ (250.0) (250.0)
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 $ (500.0) (500.0)
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 $ (300.0) (300.0)
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 $ (300.0) (300.0)
Debt Instrument, Interest Rate, Stated Percentage 4.00%  
NSP Minnesota | Mortgage bonds | Series Due May 15, 2046 [Member]    
Long-Term Borrowings and Other Financing Instruments    
Face Amount $ (350.0) (350.0)
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 $ (600.0) (600.0)
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 $ (600.0) (600.0)
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 $ (700.0) (700.0)
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 $ (425.0) (425.0)
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 $ (500.0) (500.0)
Debt Instrument, Interest Rate, Stated Percentage 4.50%  
NSP Minnesota | Mortgage bonds | Series Due May 15, 2053    
Long-Term Borrowings and Other Financing Instruments    
Face Amount $ (800.0) (800.0)
Debt Instrument, Interest Rate, Stated Percentage 5.10%  
NSP Minnesota | Mortgage bonds | Series Due Mar. 15, 2054    
Long-Term Borrowings and Other Financing Instruments    
Face Amount [4] $ (700.0) (700.0)
Debt Instrument, Interest Rate, Stated Percentage [4] 5.40%  
NSP Minnesota | Mortgage bonds | Series Due May 15, 2035    
Long-Term Borrowings and Other Financing Instruments    
Face Amount [5] $ (600.0) 0.0
Debt Instrument, Interest Rate, Stated Percentage [5] 5.05%  
NSP Minnesota | Mortgage bonds | Series Due May 15, 2055    
Long-Term Borrowings and Other Financing Instruments    
Face Amount [5] $ (500.0) 0.0
Debt Instrument, Interest Rate, Stated Percentage [5] 5.65%  
NSP Minnesota | Long-term Debt    
Long-Term Borrowings and Other Financing Instruments    
Face Amount $ (1.0) (2.0)
NSP-Wisconsin    
Long-Term Borrowings and Other Financing Instruments    
Unamortized discount (10.0) (4.0)
Unamortized Debt Issuance Expense (18.0) (15.0)
Long-term Debt 1,647.0 1,406.0
NSP-Wisconsin | Mortgage bonds | Series Due Sept. 1, 2038 [Member]    
Long-Term Borrowings and Other Financing Instruments    
Face Amount $ (200.0) (200.0)
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 $ (100.0) (100.0)
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 $ (100.0) (100.0)
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 $ (200.0) (200.0)
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 $ (100.0) (100.0)
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 $ (100.0) (100.0)
Debt Instrument, Interest Rate, Stated Percentage 2.82%  
NSP-Wisconsin | Mortgage bonds | Series Due Sept. 15, 2052    
Long-Term Borrowings and Other Financing Instruments    
Face Amount $ (100.0) (100.0)
Debt Instrument, Interest Rate, Stated Percentage 4.86%  
NSP-Wisconsin | Mortgage bonds | Series Due June 15, 2053    
Long-Term Borrowings and Other Financing Instruments    
Face Amount $ (125.0) (125.0)
Debt Instrument, Interest Rate, Stated Percentage 5.30%  
NSP-Wisconsin | Mortgage bonds | Series Due June 15, 2054    
Long-Term Borrowings and Other Financing Instruments    
Face Amount [6] $ (400.0) (400.0)
Debt Instrument, Interest Rate, Stated Percentage [6] 5.65%  
NSP-Wisconsin | Mortgage bonds | Series Due June 15, 2054 2    
Long-Term Borrowings and Other Financing Instruments    
Face Amount [7] $ (250.0) 0.0
Debt Instrument, Interest Rate, Stated Percentage [7] 5.65%  
PSCo    
Long-Term Borrowings and Other Financing Instruments    
Unamortized discount $ (42.0) (42.0)
Unamortized Debt Issuance Expense (82.0) (67.0)
Current Maturities 0.0 (250.0)
Long-term Debt 10,376.0 8,391.0
PSCo | Mortgage bonds | Series Due June 15, 2028    
Long-Term Borrowings and Other Financing Instruments    
Face Amount $ (350.0) (350.0)
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 $ (550.0) (550.0)
Debt Instrument, Interest Rate, Stated Percentage 3.20%  
PSCo | Mortgage bonds | Series Due May 15, 2025 [Member]    
Long-Term Borrowings and Other Financing Instruments    
Face Amount $ 0.0 (250.0)
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 $ (375.0) (375.0)
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 $ (750.0) (750.0)
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 $ (350.0) (350.0)
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 $ (300.0) (300.0)
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 $ (250.0) (250.0)
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 $ (500.0) (500.0)
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 $ (250.0) (250.0)
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 $ (300.0) (300.0)
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 $ (250.0) (250.0)
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 $ (400.0) (400.0)
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 $ (350.0) (350.0)
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 $ (400.0) (400.0)
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 $ (375.0) (375.0)
Debt Instrument, Interest Rate, Stated Percentage 2.70%  
PSCo | Mortgage bonds | Series Due June 1, 2032    
Long-Term Borrowings and Other Financing Instruments    
Face Amount $ (300.0) (300.0)
Debt Instrument, Interest Rate, Stated Percentage 4.10%  
PSCo | Mortgage bonds | Series Due June 1, 2052    
Long-Term Borrowings and Other Financing Instruments    
Face Amount $ (400.0) (400.0)
Debt Instrument, Interest Rate, Stated Percentage 4.50%  
PSCo | Mortgage bonds | Series Due April 1, 2053    
Long-Term Borrowings and Other Financing Instruments    
Face Amount $ (850.0) (850.0)
Debt Instrument, Interest Rate, Stated Percentage 5.25%  
PSCo | Mortgage bonds | Series Due May 15, 2034    
Long-Term Borrowings and Other Financing Instruments    
Face Amount [8] $ (400.0) 0.0
Debt Instrument, Interest Rate, Stated Percentage [8] 5.35%  
PSCo | Mortgage bonds | Series Due May 15, 2054    
Long-Term Borrowings and Other Financing Instruments    
Face Amount [9] $ (750.0) (750.0)
Debt Instrument, Interest Rate, Stated Percentage [9] 5.75%  
PSCo | Mortgage bonds | Series Due May 15, 2055    
Long-Term Borrowings and Other Financing Instruments    
Face Amount [8] $ (800.0) 0.0
Debt Instrument, Interest Rate, Stated Percentage [8] 5.85%  
PSCo | Mortgage bonds | Series Due May 15, 2034 2    
Long-Term Borrowings and Other Financing Instruments    
Face Amount [9] $ (450.0) (450.0)
Debt Instrument, Interest Rate, Stated Percentage [9] 5.35%  
PSCo | Mortgage bonds | Series Due Sept. 15, 2035    
Long-Term Borrowings and Other Financing Instruments    
Face Amount [8] $ (800.0) 0.0
Debt Instrument, Interest Rate, Stated Percentage [8] 5.15%  
SPS    
Long-Term Borrowings and Other Financing Instruments    
Unamortized discount $ (14.0) (14.0)
Unamortized Debt Issuance Expense (40.0) (35.0)
Long-term Debt 4,046.0 3,551.0
SPS | Mortgage bonds | Series Due Aug. 15, 2041 4    
Long-Term Borrowings and Other Financing Instruments    
Face Amount $ (200.0) (200.0)
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 $ (100.0) (100.0)
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 $ (100.0) (100.0)
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 $ (300.0) (300.0)
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 $ (450.0) (450.0)
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 $ (300.0) (300.0)
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 $ (300.0) (300.0)
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 $ (350.0) (350.0)
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 $ (250.0) (250.0)
Debt Instrument, Interest Rate, Stated Percentage 3.15%  
SPS | Mortgage bonds | Series Due June 1, 2052    
Long-Term Borrowings and Other Financing Instruments    
Face Amount $ (200.0) (200.0)
Debt Instrument, Interest Rate, Stated Percentage 5.15%  
SPS | Mortgage bonds | Series Due Sept. 15, 2053    
Long-Term Borrowings and Other Financing Instruments    
Face Amount $ (100.0) (100.0)
Debt Instrument, Interest Rate, Stated Percentage 6.00%  
SPS | Mortgage bonds | Series Due June 15, 2054    
Long-Term Borrowings and Other Financing Instruments    
Face Amount [10] $ (600.0) (600.0)
Debt Instrument, Interest Rate, Stated Percentage [10] 6.00%  
SPS | Mortgage bonds | Series Due May 15, 2035    
Long-Term Borrowings and Other Financing Instruments    
Face Amount [11] $ (500.0) 0.0
Debt Instrument, Interest Rate, Stated Percentage [11] 5.30%  
SPS | Unsecured Debt [Member] | Senior C and D Due Oct. 1, 2033 [Member]    
Long-Term Borrowings and Other Financing Instruments    
Face Amount $ (100.0) (100.0)
Debt Instrument, Interest Rate, Stated Percentage 6.00%  
SPS | Unsecured Debt [Member] | Senior F Due Oct. 1, 2036 [Member]    
Long-Term Borrowings and Other Financing Instruments    
Face Amount $ (250.0) (250.0)
Debt Instrument, Interest Rate, Stated Percentage 6.00%  
Other Subsidiaries    
Long-Term Borrowings and Other Financing Instruments    
Current Maturities $ (1.0) (3.0)
Long-term Debt 23.0 24.0
Other Subsidiaries | Various Eloigne Co. affordable housing project notes    
Long-Term Borrowings and Other Financing Instruments    
Long-term Debt, Gross $ 24.0 $ 27.0
[1] 2024 financing
[2] 2025 financing
[3] The notes may be redeemed at par value on or after Oct. 15, 2030
[4] 2024 financing.
[5] 2025 financing.
[6] 2024 financing.
[7] 2025 financing.
[8] 2025 financing
[9] 2024 financing.
[10] 2024 financing
[11] 2025 financing.
v3.25.4
Borrowings and Other Financing Instruments Deferred Financing Costs (Details) - USD ($)
$ in Millions
Dec. 31, 2025
Dec. 31, 2024
Deferred Financing Costs [Abstract]    
Deferred Finance Costs, Noncurrent, Net $ 270 $ 235
v3.25.4
Borrowings and Other Financing Instruments Forward Equity Agreements (Details)
Dec. 31, 2025
USD ($)
shares
Forward Contract Indexed to Issuer's Equity [Line Items]  
Common Stock, Shares Issued through Forward Equity Agreement | shares 30,000,000.0
Cash Proceeds at Settlement $ 2,048,000,000
Cash Proceeds at Settlement $ 2,048,000,000
2024 Forward Equity Agreements  
Forward Contract Indexed to Issuer's Equity [Line Items]  
Common Stock, Shares Issued through Forward Equity Agreement | shares 21,100,000
Cash Proceeds at Settlement $ 1,364,000,000
Cash Proceeds at Settlement $ 1,364,000,000
2025 Forward Equity Agreements  
Forward Contract Indexed to Issuer's Equity [Line Items]  
Common stock, shares to be issued through Forward Equity Agreement | shares 12,200,000 [1],[2]
Common Stock, Shares Issued through Forward Equity Agreement | shares 8,900,000
Period End Settlement Price, in Cash $ 934,000,000
Period End Net Cash Settlement Price 7,000,000
Expected Settlement Price 935,000,000 [3]
Cash Proceeds at Settlement $ 684,000,000
Period End Net Share Settlement Price | shares 100,000
Cash Proceeds at Settlement $ 684,000,000
2025 Collared Forward Equity Agreements  
Forward Contract Indexed to Issuer's Equity [Line Items]  
Common stock, shares to be issued through Forward Equity Agreement | shares 15,100,000 [1]
Expected Settlement Price $ 1,084,000,000 [4]
[1] Entered under the 2025 ATM prospectus supplement.
[2] Xcel Energy may settle the agreements at any time until final maturity.
[3] Actual cash proceeds will be impacted by the timing of settlement. Forward prices are based on the public offering price (net of underwriting fees), increased for the overnight bank funding rate, less a spread and less expected dividends on Xcel Energy’s common stock during the period the agreements are outstanding.
[4] Pricing for the physical delivery of common shares will be based on an average market price for Xcel Energy’s common stock during a period preceding settlement in December 2026, subject to a cap price and floor price derived from the September 2025 and December 2025 public offerings.
v3.25.4
Borrowings and Other Financing Instruments Other Equity (Details) - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Dividend Reinvestment Program [Line Items]      
Proceeds from Issuance of Common Stock $ 3,349 $ 1,117 $ 270
DividendReinvestmentProgram [Member]      
Dividend Reinvestment Program [Line Items]      
Proceeds from Issuance of Common Stock $ 67 $ 67  
v3.25.4
Borrowings and Other Financing Instruments Capital Stock (Details) - $ / shares
Dec. 31, 2025
Dec. 31, 2024
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) 623,600,715 574,365,598
Xcel Energy Inc.    
Debt Instrument [Line Items]    
Preferred Stock, Shares Authorized (in shares) 7,000,000 7,000,000
Preferred Stock, Par Value (in dollars per share) $ 100 $ 100
Preferred Stock, Shares Outstanding (in shares) 0 0
PSCo    
Debt Instrument [Line Items]    
Preferred Stock, Shares Authorized (in shares) 10,000,000 10,000,000
Preferred Stock, Par Value (in dollars per share) $ 0.01 $ 0.01
Preferred Stock, Shares Outstanding (in shares) 0 0
SPS    
Debt Instrument [Line Items]    
Preferred Stock, Shares Authorized (in shares) 10,000,000 10,000,000
Preferred Stock, Par Value (in dollars per share) $ 1.00 $ 1.00
Preferred Stock, Shares Outstanding (in shares) 0 0
v3.25.4
Borrowings and Other Financing Instruments Dividend and Other Capital-Related Restrictions (Details)
$ in Millions
Dec. 31, 2025
USD ($)
NSP Minnesota  
Debt Instrument [Line Items]  
Equity to total capitalization ratio, low end of range (in hundredths) 47.25%
Equity to total capitalization ratio, high end of range (in hundredths) 57.75%
Equity to total capitalization ratio 53.16%
Unrestricted Retained Earnings Per State Regulatory Commissions Dividend Restrictions $ 2,185
Capitalization, Short term debt, long term debt and equity 19,547
Maximum total capitalization 22,607
Maximum additional short term debt authorized for issuance $ 3,391 [1]
Maximum percentage of short term debt to total capitalization (in hundredths) 15.00%
NSP-Wisconsin  
Debt Instrument [Line Items]  
Minimum calendar year average equity to total capitalization ratio authorized by state commission 52.50% [2]
Equity to total capitalization ratio 52.66% [2]
Unrestricted Retained Earnings Per State Regulatory Commissions Dividend Restrictions $ 12
Capitalization, Short term debt, long term debt and equity 3,318
Maximum additional long term debt authorized for issuance 500
Maximum additional short term debt authorized for issuance $ 150
SPS  
Debt Instrument [Line Items]  
Equity to total capitalization ratio (excluding short-term debt), low end of range (in hundredths) 45.00% [3]
Equity to total capitalization ratio (excluding short-term debt), high end of range (in hundredths) 55.00% [3]
Equity to total capitalization ratio (excluding short-term debt) (in hundredths) 54.47% [3]
Unrestricted Retained Earnings Per State Regulatory Commissions Dividend Restrictions $ 622 [4]
Capitalization, Short term debt, long term debt and equity 8,888 [4]
Maximum additional long term debt authorized for issuance 100
Maximum additional short term debt authorized for issuance 700
PSCo  
Debt Instrument [Line Items]  
Maximum additional long term debt authorized for issuance 3,500
Maximum additional short term debt authorized for issuance $ 1,200
[1] NSP-Minnesota has authorization to issue long-term securities provided the equity-to-total capitalization remains within the required range, and to issue short-term debt provided it does not exceed 15% of total capitalization.
[2] Cannot pay annual dividends in excess of forecasted levels if its average equity-to-total capitalization ratio falls below the commission authorized level.
[3] Excludes short-term debt.
[4] May not pay a dividend that would cause a loss of its investment grade bond rating.
v3.25.4
ATM Program (Details) - USD ($)
shares in Thousands, $ in Millions
 5 Months Ended 7 Months Ended 12 Months Ended 22 Months Ended
Dec. 31, 2025
Jul. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Jul. 31, 2025
Debt Disclosure [Abstract]          
ATM Shares Issued 1,900 16,400 18,300 3,100  
ATM Transaction Fee $ 1 $ 9 $ 9 $ 2  
ATM Program Total Available Proceeds 4,000       $ 2,500
ATM Net Proceeds $ 142 $ 1,160 $ 1,100 $ 188  
v3.25.4
Revenues (Details) - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Total revenue from contracts with customers      
Disaggregation of Revenue [Line Items]      
Revenue from Contracts with Customers $ 13,860 $ 12,641 $ 13,591
Total revenue from contracts with customers | Regulated Electric      
Disaggregation of Revenue [Line Items]      
Revenue from Contracts with Customers 11,490 10,471 10,940
Total revenue from contracts with customers | Natural Gas      
Disaggregation of Revenue [Line Items]      
Revenue from Contracts with Customers 2,327 2,120 2,549
Total revenue from contracts with customers | All Other      
Disaggregation of Revenue [Line Items]      
Revenue from Contracts with Customers 43 50 102
Retail      
Disaggregation of Revenue [Line Items]      
Revenue from Contracts with Customers 12,197 11,109 11,908
Retail | Residential      
Disaggregation of Revenue [Line Items]      
Revenue from Contracts with Customers 5,318 4,862 5,179
Retail | C&I      
Disaggregation of Revenue [Line Items]      
Revenue from Contracts with Customers 6,720 6,096 6,566
Retail | Other      
Disaggregation of Revenue [Line Items]      
Revenue from Contracts with Customers 159 151 163
Retail | Regulated Electric      
Disaggregation of Revenue [Line Items]      
Revenue from Contracts with Customers 10,001 9,114 9,413
Retail | Regulated Electric | Residential      
Disaggregation of Revenue [Line Items]      
Revenue from Contracts with Customers 3,904 3,552 3,560
Retail | Regulated Electric | C&I      
Disaggregation of Revenue [Line Items]      
Revenue from Contracts with Customers 5,948 5,420 5,703
Retail | Regulated Electric | Other      
Disaggregation of Revenue [Line Items]      
Revenue from Contracts with Customers 149 142 150
Retail | Natural Gas      
Disaggregation of Revenue [Line Items]      
Revenue from Contracts with Customers 2,153 1,945 2,393
Retail | Natural Gas | Residential      
Disaggregation of Revenue [Line Items]      
Revenue from Contracts with Customers 1,411 1,299 1,560
Retail | Natural Gas | C&I      
Disaggregation of Revenue [Line Items]      
Revenue from Contracts with Customers 742 646 833
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 43 50 102
Retail | All Other | Residential      
Disaggregation of Revenue [Line Items]      
Revenue from Contracts with Customers 3 11 59
Retail | All Other | C&I      
Disaggregation of Revenue [Line Items]      
Revenue from Contracts with Customers 30 30 30
Retail | All Other | Other      
Disaggregation of Revenue [Line Items]      
Revenue from Contracts with Customers 10 9 13
Wholesale      
Disaggregation of Revenue [Line Items]      
Revenue from Contracts with Customers 715 645 815
Wholesale | Regulated Electric      
Disaggregation of Revenue [Line Items]      
Revenue from Contracts with Customers 715 645 815
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 705 648 649
Transmission | Regulated Electric      
Disaggregation of Revenue [Line Items]      
Revenue from Contracts with Customers 705 648 649
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 243 239 219
Other | Regulated Electric      
Disaggregation of Revenue [Line Items]      
Revenue from Contracts with Customers 69 64 63
Other | Natural Gas      
Disaggregation of Revenue [Line Items]      
Revenue from Contracts with Customers 174 175 156
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 809 800 615
Alternative revenue and other | Regulated Electric      
Disaggregation of Revenue [Line Items]      
Alternative revenue and other 670 676 506
Alternative revenue and other | Natural Gas      
Disaggregation of Revenue [Line Items]      
Alternative revenue and other 125 110 96
Alternative revenue and other | All Other      
Disaggregation of Revenue [Line Items]      
Alternative revenue and other 14 14 13
Operating Segments [Member]      
Disaggregation of Revenue [Line Items]      
Total revenues 14,669 13,441 14,206
Operating Segments [Member] | Regulated Electric      
Disaggregation of Revenue [Line Items]      
Total revenues 12,160 11,147 11,446
Operating Segments [Member] | Natural Gas      
Disaggregation of Revenue [Line Items]      
Total revenues 2,452 2,230 2,645
Operating Segments [Member] | All Other      
Disaggregation of Revenue [Line Items]      
Total revenues $ 57 $ 64 $ 115
v3.25.4
Income Taxes (Details) - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Income Tax [Line Items]    
Federal detriment $ 19 $ 19
Federal Benefit 17 16
Tax Credit Carryforward [Line Items]    
Federal Benefit 17 16
Federal detriment 19 $ 19
Xcel Energy [Member]    
Income Tax [Line Items]    
Potential Tax Adjustments $ 0  
v3.25.4
State Audits (Details)
$ in Millions
 12 Months Ended
Dec. 31, 2025
USD ($)
Xcel Energy [Member]  
Income Tax [Line Items]  
Potential Tax Adjustments $ 0
v3.25.4
Income Taxes Unrecognized Tax Benefit (Details) - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Dec. 31, 2022
Income Tax Disclosure [Abstract]        
Unrecognized tax benefit — Permanent tax positions $ 43 $ 43    
Unrecognized tax benefit — Temporary tax positions 0 0    
Total unrecognized tax benefit 43 43 $ 41 $ 67
Additions based on tax positions related to the current year 3 5 5  
Additions for tax positions of prior years 2 2 1  
Reductions for tax positions of prior years 5 3 29  
Unrecognized Tax Benefits, Decrease Resulting from Settlements with Taxing Authorities 0 0 (1)  
Unrecognized Tax Benefits, Reduction Resulting from Lapse of Applicable Statute of Limitations 0 (2) (2)  
NOL and tax credit carryforwards 33 35    
Payable for interest related to unrecognized tax benefits at Jan. 1 (4) (2) (1) $ (4)
Interest (expense) benefit related to unrecognized tax benefits (2) (1) 3  
Unrecognized Tax Benefits, Income Tax Penalties Expense $ 0 $ 0 $ 0  
v3.25.4
Income Taxes Other Income Tax Matters (Details) - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Income Tax [Line Items]      
Tax Credit Carryforward, Amount $ 1,474 $ 1,519  
State NOL carryforwards 8 9  
Valuation allowances for state NOL carryforwards (5) (2)  
state tax credit carryforward, net of federal detirment [1] 71 70  
valuation allowances for state credit carryforwards, net of federal benefit [2] (64) (58)  
Federal detriment 19 19  
Federal Benefit $ 17 $ 16  
Federal statutory rate 21.00% 21.00% 21.00%
Effective Income Tax Rate Reconciliation, Tax Credit, Percent [3] (32.30%) (43.20%) (28.10%)
Effective Income Tax Rate Reconciliation, State and Local Income Taxes, Percent [4] 4.40% 3.80% 4.50%
Plant related excess deferred taxes 0.40% 0.20% 0.00%
Effective Income Tax Rate Reconciliation, Percent (13.80%) (26.20%) (9.00%)
Total income tax benefit $ (245) $ (402) $ (146)
Deferred tax expense excluding items below 685 434 129
Amortization and adjustments to deferred income taxes on income tax regulatory assets and liabilities (269) (201) (188)
Income Tax Expense (Benefit), Intraperiod Tax Allocation (2) (8) 0
Deferred tax benefit (238) (464) (249)
Tax Credit Carryforward, Valuation Allowance (10) (14)  
Adjustments to deferred income taxes for wind production tax credit cash transfers (652) (689) (190)
income tax expense      
Income Tax [Line Items]      
Current federal tax (benefit) expense (6) 36 113
Current state tax expense 2 28 16
Current change in unrecognized tax expense (benefit) 1 2 (21)
Deferred federal tax benefit (333) (510) (331)
Deferred state tax expense 96 46 75
Deferred change in unrecognized tax (benefit) expense (1) 0 7
Deferred ITCs 4 4 5
Total income tax benefit (245) (402) $ (146)
Net Deferred Tax Liablility [Member]      
Income Tax [Line Items]      
Tax Credit Carryforward, Amount 1,546 1,589 [5]  
Operating Lease Assets 232 282 [5]  
Regulatory Asset 500 559 [5]  
Deferred tax liability - Pension expense 171 155 [5]  
Other 98 93 [5]  
Total deferred tax liabilities 8,588 8,097 [5]  
Regulatory Liability 663 744 [5]  
Operating Loss Carryforwards 1 1 [5]  
Tax Credit Carryforward, Valuation Allowance (74) (73) [5]  
other employee benefits 116 102 [5]  
Other 91 122 [5]  
Total deferred tax assets 2,584 2,778 [5]  
Net deferred tax liability 6,004 5,319 [5]  
Operating lease liabilities 231 282 [5]  
Deferred investment tax credits 10 11 [5]  
Differences between book and tax bases of property $ 7,587 $ 7,008 [5]  
[1] State tax credit carryforwards are net of federal detriment of $19 million as of Dec. 31, 2025 and 2024.
[2] Valuation allowances for state tax credit carryforwards were net of federal benefit of $17 million and $16 million as of Dec. 31, 2025 and 2024, respectively.
[3] Wind, Solar and Nuclear PTCs (net of transfer discounts) are generally credited to customers (reduction to revenue) and do not materially impact earnings.
[4] State and local income taxes are primarily made up of the following jurisdictions: Minnesota, Colorado
[5] Prior periods have been reclassified to conform to current year presentation
v3.25.4
Effective Income Tax Rate Reconciliation (Details) - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Effective Income Tax Rate Reconciliation [Line Items]      
Income (Loss) from Continuing Operations before Income Taxes, Noncontrolling Interest $ 1,773 $ 1,534 $ 1,625
Effective Income Tax Rate Reconciliation at Federal Statutory Income Tax Rate, Amount 372 322 341
Effective Income Tax Rate Reconciliation, Tax Credit, Amount [1] (569) (663) (455)
Effective Income Tax Rate Reconciliation, Tax Credit, Other, Amount (14) (16) (17)
Effective Income Tax Rate Reconciliation, Plant Related Excess Deferred Taxes, Amount [2] (87) (87) (83)
Effective Income Tax Rate Reconciliation, AFUDC Equity, Amount [2] (58) (34) (19)
Effective Income Tax Rate Reconciliation, Other Regulatory Adjustments, Amount [2] 29 14 17
Effective Income Tax Rate Reconciliation, State and Local Income Taxes, Amount [3] 78 58 73
Effective Income Tax Rate Reconciliation, Other Adjustments, Amount 4 4 (3)
Income Tax Expense (Benefit) $ (245) $ (402) $ (146)
Federal statutory rate 21.00% 21.00% 21.00%
Effective Income Tax Rate Reconciliation, Tax Credit, Percent [1] (32.30%) (43.20%) (28.10%)
Effective Income Tax Rate Reconciliation, Tax Credit, Other, Percent (0.80%) (1.10%) (1.10%)
Effective Income Tax Rate Reconciliation, Plant Related Excess Deferred Taxes, Percent [2] (4.90%) (5.60%) (5.10%)
Effective Income Tax Rate Reconciliation, AFUDC Equity, Percent [2] (3.20%) (2.20%) (1.20%)
Effective Income Tax Rate Reconciliation, Other Regulatory Adjustments, Percent [2] 1.60% 0.90% 1.00%
Effective Income Tax Rate Reconciliation, State and Local Income Taxes, Percent [3] 4.40% 3.80% 4.50%
Plant related excess deferred taxes 0.40% 0.20% 0.00%
Effective Income Tax Rate Reconciliation, Percent (13.80%) (26.20%) (9.00%)
[1] Wind, Solar and Nuclear PTCs (net of transfer discounts) are generally credited to customers (reduction to revenue) and do not materially impact earnings.
[2] Regulatory adjustments primarily relate to the credit of plant related excess deferred taxes to customers for tax rate increases as well as the capitalization of AFUDC equity for book purposes only. Income tax benefits associated with the credit of excess deferred taxes are offset by corresponding revenue reductions.
[3] State and local income taxes are primarily made up of the following jurisdictions: Minnesota, Colorado
v3.25.4
Cash Paid for Income Taxes (Details) - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Cash Paid for Income Taxes [Line Items]      
Income Tax Paid, Federal, after Refund Received [1] $ 671 $ 633 $ 104
Income Tax Paid, State and Local, after Refund Received (30) (45) (12)
Income Taxes Paid, Net $ 641 $ 588 $ 92
[1] Includes proceeds from tax credit transfers.
v3.25.4
Incentive Plans Including Share-Based Compensation (Details) - USD ($)
$ / shares in Units, shares in Thousands, $ in Millions
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Equity Instruments Other than Options Activity [Roll Forward]      
Balance at January 1 (in shares) 1,139    
Granted (in shares) [1] 683 658 586
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Forfeited in Period (in shares) (170)    
Vested (in shares) (502) (282) (329)
Dividend equivalents (in shares) 62    
Balance at December 31 (in shares) 1,212 1,139  
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) $ 64.55    
Granted, weighted average grant date fair value (in dollars per share) 68.19 $ 63.02 $ 67.06
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) $ 65.85    
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Fair Value $ 37 $ 19 $ 20
Vested, weighted average grant date fair value (in dollars per share) $ 66.27    
Dividend equivalents, weighted average grant date fair value (in dollars per share) 65.85    
Balance at December 31, weighted average grant date fair value (in dollars per share) $ 65.77 $ 64.55  
TSR Liability Awards      
Equity Instruments Other than Options Activity [Roll Forward]      
Granted (in shares) [2] 109 193 216
Equity Instruments Other than Options, Weighted Average Grant Date Fair Value [Abstract]      
Employee Service Share Based Compensation Cash Used To Settle Awards $ 2    
Service-based awards [Member]      
Equity Instruments Other than Options Activity [Roll Forward]      
Granted (in shares) 379 457 413
Service-based awards [Member] | Xcel Energy Inc. 2015 Omnibus Incentive Plan [Member]      
Equity Instruments Other than Options, Weighted Average Grant Date Fair Value [Abstract]      
Share-Based Compensation Arrangement by Share-Based Payment Award, Number of Shares Authorized 6,000    
Service-based awards [Member] | Xcel Energy Inc. 2024 Equity Incentive Plan      
Equity Instruments Other than Options Activity [Roll Forward]      
Granted (in shares) 13,000    
[1] Includes 2025, 2024 and 2023 grants of 379, 457 and 413 units (each in thousands), respectively, subject only to service conditions.
[2] All grants contain performance and/or market conditions.
v3.25.4
Share-Based Compensation Restricted Stock (Details) - USD ($)
shares in Thousands, $ in Millions
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]      
Granted (in shares) [1] 683 658 586
Compensation costs for share-based payments included in O&M $ 46 $ 33 $ 25
[1] Includes 2025, 2024 and 2023 grants of 379, 457 and 413 units (each in thousands), respectively, subject only to service conditions.
v3.25.4
Other Equity Awards (Details) - USD ($)
$ / shares in Units, shares in Thousands, $ in Millions
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Equity Instruments Other than Options Activity [Roll Forward]      
Balance at January 1 (in shares) 1,139    
Granted (in shares) [1] 683 658 586
Forfeited (in shares) (170)    
Vested (in shares) (502) (282) (329)
Dividend equivalents (in shares) 62    
Balance at December 31 (in shares) 1,212 1,139  
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) $ 64.55    
Granted, weighted average grant date fair value (in dollars per share) 68.19 $ 63.02 $ 67.06
Forfeited, weighted average grant date fair value (in dollars per share) 65.85    
Vested, weighted average grant date fair value (in dollars per share) 66.27    
Dividend equivalents, weighted average grant date fair value (in dollars per share) 65.85    
Balance at December 31, weighted average grant date fair value (in dollars per share) $ 65.77 $ 64.55  
Equity Instruments Other than Options, Additional Disclosures [Abstract]      
Total fair value of equity awards vested during the period $ 37 $ 19 $ 20
Service-based awards [Member]      
Equity Instruments Other than Options Activity [Roll Forward]      
Granted (in shares) 379 457 413
[1] Includes 2025, 2024 and 2023 grants of 379, 457 and 413 units (each in thousands), respectively, subject only to service conditions.
v3.25.4
Stock Equivalent Units (Details) - $ / shares
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Equity Instruments Other than Options Activity [Roll Forward]      
Balance at January 1 (in shares) 1,139,000    
Granted (in shares) [1] 683,000 658,000 586,000
Dividend equivalents (in shares) 62,000    
Balance at December 31 (in shares) 1,212,000 1,139,000  
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) $ 64.55    
Granted, weighted average grant date fair value (in dollars per share) 68.19 $ 63.02 $ 67.06
Dividend equivalents, weighted average grant date fair value (in dollars per share) 65.85    
Balance at December 31, weighted average grant date fair value (in dollars per share) $ 65.77 $ 64.55  
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    
Stock Equivalent Units [Member]      
Equity Instruments Other than Options Activity [Roll Forward]      
Balance at January 1 (in shares) 528,000    
Granted (in shares) 32,000 44,000 38,000
Units distributed (in shares) (53,000)    
Dividend equivalents (in shares) 16,000    
Balance at December 31 (in shares) 523,000 528,000  
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) $ 48.68    
Granted, weighted average grant date fair value (in dollars per share) 70.68 $ 57.03 $ 63.12
Units distributed, weighted average grant date fair value (in dollars per share) 52.88    
Dividend equivalents, weighted average grant date fair value (in dollars per share) 71.79    
Balance at December 31, weighted average grant date fair value (in dollars per share) $ 50.31 $ 48.68  
[1] Includes 2025, 2024 and 2023 grants of 379, 457 and 413 units (each in thousands), respectively, subject only to service conditions.
v3.25.4
TSR Liability Awards (Details) - USD ($)
shares in Thousands, $ in Millions
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Equity Instruments Other than Options Activity [Roll Forward]      
Granted (in shares) [1] 683 658 586
TSR Liability Awards      
Equity Instruments Other than Options Activity [Roll Forward]      
Granted (in shares) [2] 109 193 216
Equity Instruments Other than Options, Additional Disclosures [Abstract]      
Awards settled (in shares) 74 0 282
Settlement amount (cash and common stock) $ 5 $ 0 $ 19
Amount of cash used to settle TSR liability awards $ 2    
[1] Includes 2025, 2024 and 2023 grants of 379, 457 and 413 units (each in thousands), respectively, subject only to service conditions.
[2] All grants contain performance and/or market conditions.
v3.25.4
Share-Based Compensation Expense (Details) - USD ($)
shares in Thousands, $ in Millions
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Share-Based Compensation Expense [Abstract]      
Granted (in shares) [1] 683 658 586
Compensation cost for share-based awards [2] $ 57 $ 30 $ 27
Tax benefit recognized in income 15 8 7
Unrecognized compensation cost related to nonvested share-based compensation awards $ 52 38  
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 $ 46 33 25
Compensation costs for share-based payments included in O&M $ 46 $ 33 $ 25
Service-based awards [Member]      
Share-Based Compensation Expense [Abstract]      
Granted (in shares) 379 457 413
Service-based awards [Member] | Xcel Energy Inc. 2015 Omnibus Incentive Plan [Member]      
Compensation Related Costs [Abstract]      
Share-Based Compensation Arrangement by Share-Based Payment Award, Number of Shares Authorized 6,000    
[1] Includes 2025, 2024 and 2023 grants of 379, 457 and 413 units (each in thousands), respectively, subject only to service conditions.
[2] Compensation costs for share-based payments are included in O&M expense. Amount for equity awards (non-cash) was $46 million, $33 million and $25 million in 2025, 2024 and 2023, respectively.
v3.25.4
Share-Based Compensation Share-Based Compensation Phantom (Details) - $ / shares
shares in Thousands
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]      
Granted (in shares) [1] 683 658 586
Granted, weighted average grant date fair value (in dollars per share) $ 68.19 $ 63.02 $ 67.06
Service-based awards [Member]      
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]      
Granted (in shares) 379 457 413
[1] Includes 2025, 2024 and 2023 grants of 379, 457 and 413 units (each in thousands), respectively, subject only to service conditions.
v3.25.4
Common Stock Equivalent (Details) - shares
shares in Millions
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Earnings Per Share [Abstract]      
Weighted Average Number of Shares Outstanding, Basic 587.0 563.0 552.0
Diluted [1] 589.0 563.0 552.0
Dilutive Effect of Contingently Issuable Shares 2.1 0.5 0.3
[1] Diluted common shares outstanding included common stock equivalents of 2.1 million, 0.5 million, and 0.3 million shares for 2025, 2024 and 2023, respectively.
v3.25.4
Nuclear Decommissioning Fund (Details) - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Debt Securities, Available-for-Sale, Unrealized Gain $ 1,800 $ 1,400
Debt Securities, Available-for-Sale, Unrealized Loss 47 49
Equity investments in unconsolidated subsidiaries 285 246
Miscellaneous investments 164 156
Final Contractual Maturity [Abstract]    
Due in 1 Year or Less 10  
Due in 1 to 5 Years 344  
Due in 5 to 10 Years 292  
Due after 10 Years 299  
Total 945  
Fair Value Measured on a Recurring Basis | Cost    
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Decommissioning fund investments 2,229 [1] 2,130 [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 60 [1] 39 [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 720 [1] 703 [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 944 [1] 866 [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 505 [1] 522 [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 1,072 [1] 1,025 [2]
Decommissioning fund investments 3,940 [1] 3,494 [2]
Final Contractual Maturity [Abstract]    
Total 107 96
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 60 [1] 39 [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 1,072 [1] 1,025 [2]
Investments, Fair Value Disclosure 1,072 [1] 1,025 [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 945 [1] 846 [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 1,863 [1] 1,584 [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 1,921 [1] 1,622 [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 60 [1] 39 [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 1,861 [1] 1,583 [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 936 [1] 833 [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 934 [1] 832 [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 11 [1] 14 [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 11 [1] 14 [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 $285 million of equity method investments and $164 million of rabbi trust assets and other miscellaneous investments.
[2] Reported in nuclear decommissioning fund and other investments on the consolidated balance sheets, which also includes $246 million of equity investments in unconsolidated subsidiaries and $156 million of rabbi trust assets and other miscellaneous investments.
v3.25.4
Interest Rate Derivatives (Details) - Interest Rate Swap
$ in Millions
Dec. 31, 2025
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 $ 240
v3.25.4
Commodity Derivatives (Details)
MWh in Millions, MMBTU in Millions, $ in Millions
Dec. 31, 2025
USD ($)
MWh
MMBTU
Dec. 31, 2024
USD ($)
MWh
MMBTU
Derivative [Line Items]    
Reclaim Cash Collateral $ 4 $ 2
Cash Flow Hedges    
Derivative [Line Items]    
Commodity contracts designated as cash flow hedges $ 0  
Electric Commodity    
Derivative [Line Items]    
Notional Amount | MWh [1],[2] 35 38
Natural Gas Commodity    
Derivative [Line Items]    
Notional Amount | MMBTU [1],[2] 31 77
[1] Not reflective of net positions in the underlying commodities.
[2] Notional amounts for options included on a gross basis but weighted for the probability of exercise.
v3.25.4
Consideration of Credit Risk and Concentrations (Details) - Credit Concentration Risk
$ in Millions
Dec. 31, 2025
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 9
External Credit Rating, Investment Grade  
Derivative [Line Items]  
Number of most significant counterparties 3
Credit exposure for the most significant counterparties | $ $ 22
Percentage of credit exposure for the most significant counterparties 14.00%
Internal Investment Grade  
Derivative [Line Items]  
Number of most significant counterparties 6
Credit exposure for the most significant counterparties | $ $ 92
Percentage of credit exposure for the most significant counterparties 57.00%
External Credit Rating, Noninvestment Grade [Member]  
Derivative [Line Items]  
Number of most significant counterparties 1
Credit exposure for the most significant counterparties | $ $ 25
Percentage of credit exposure for the most significant counterparties 15.00%
v3.25.4
Qualifying Cash Flow Hedges (Details) - USD ($)
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
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 66,000,000 48,000,000 (150,000,000)
Derivative Instruments, Gain (Loss) Reclassification from Accumulated OCI to Income, Estimated Net Amount to be Transferred 0 0 0
Pre-tax gains (losses) reclassified into income during the period from regulatory assets and (liabilities) (36,000,000) (22,000,000) (138,000,000)
Derivative, Gain (Loss) on Derivative, Net (25,000,000) (49,000,000) (34,000,000)
Not Designated as Hedging Instrument | Commodity Trading Contract      
Impact of Derivative Activity      
Derivative Instruments, Gain (Loss) Reclassification from Accumulated OCI to Income, Estimated Net Amount to be Transferred 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] (3,000,000) (27,000,000) (7,000,000)
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 69,000,000 44,000,000 (137,000,000)
Derivative Instruments, Gain (Loss) Reclassification from Accumulated OCI to Income, Estimated Net Amount to be Transferred 0 0 0
Pre-tax gains (losses) reclassified into income during the period from regulatory assets and (liabilities) [2] 36,000,000 22,000,000 (123,000,000)
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 (3,000,000) 4,000,000 (13,000,000)
Derivative Instruments, Gain (Loss) Reclassification from Accumulated OCI to Income, Estimated Net Amount to be Transferred 0 0 0
Pre-tax gains (losses) reclassified into income during the period from regulatory assets and (liabilities) 0 0 [3] (15,000,000) [3]
Derivative, Gain (Loss) on Derivative, Net [3],[4] (22,000,000) (22,000,000) (27,000,000)
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 29,000,000 (2,000,000)
Derivative Instruments Gain (Loss) Reclassified To Regulatory Assets And Liabilities Net 0 0 0
Derivative Instruments, Gain (Loss) Reclassification from Accumulated OCI to Income, Estimated Net Amount to be Transferred (3,000,000) (3,000,000) (5,000,000)
Pre-tax gains (losses) reclassified into income during the period from regulatory assets and (liabilities) 0 0 0
Derivative, Gain (Loss) on Derivative, Net 0 0 0
Cash Flow Hedges | Designated as Hedging Instrument | Interest Rate Contract      
Impact of Derivative Activity      
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, before Tax 2,000,000 29,000,000 (2,000,000)
Derivative Instruments Gain (Loss) Reclassified To Regulatory Assets And Liabilities Net 0 0 0
Derivative Instruments, Gain (Loss) Reclassification from Accumulated OCI to Income, Estimated Net Amount to be Transferred [5] (3,000,000) (3,000,000) (5,000,000)
Pre-tax gains (losses) reclassified into income during the period from regulatory assets and (liabilities) 0 0 0
Derivative, Gain (Loss) on Derivative, Net $ 0 $ 0 $ 0
[1] Recorded to electric revenues. Presented amounts do not reflect non-derivative transactions or margin sharing with customers.
[2] Recorded to electric fuel and purchased power. These derivative settlement gains and losses are shared with electric customers through fuel and purchased energy cost-recovery mechanisms and reclassified out of income as regulatory assets or liabilities, as appropriate. FTR settlements are shared with customers and do not have a material impact on net income. Presented amounts reflect changes in fair value between auction and settlement dates, but exclude the original auction fair value.
[3] Other than $4 million of 2025 and $3 million of 2024 losses recorded to electric fuel and purchased power, amounts are recorded to cost of natural gas sold and transported. Amounts are subject to cost-recovery mechanisms and reclassified out of income to a regulatory asset, as appropriate.
[4] Relates primarily to option premium amortization.
[5] Recorded to interest charges.
v3.25.4
Credit Related Contingent Features (Details) - USD ($)
$ in Millions
Dec. 31, 2025
Dec. 31, 2024
Fair Value Disclosures [Abstract]    
Derivative instruments in a gross liability position $ 7 $ 11
Derivative, Gross Liability with Cross Default Position, Aggregate Fair Value 62 69
Collateral posted related to adequate assurance clauses in derivative contracts $ 0 $ 0
v3.25.4
Recurring Fair Value Measurements (Details) - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Derivatives, Fair Value [Line Items]      
Derivative instruments $ 165 $ 114  
Derivative instruments 54 72  
Derivative Liability, Net 67 77  
Return Cash Collateral 0 0  
Derivative Liability, Noncurrent 31 37  
Reclaim Cash Collateral 4 2  
Commodity Contract      
Changes in Level 3 Commodity Derivatives      
Balance at Jan. 1 99 90 $ 236
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Inputs Reconciliation, Purchases [1] 262 210 176
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Inputs Reconciliation, Settlements [1] (322) (303) (154)
(Losses) gains recognized in earnings [2] (13) (9) 6
Fair Value Measurement With Unobservable Inputs Reconciliation Recurring Basis Asset Liability Net Losses Gains Recognized As Regulatory Assets And Liabilities [1] 113 111 (174)
Balance at Dec. 31 139 99 90
Other Derivative Instruments      
Changes in Level 3 Commodity Derivatives      
Pre-tax gains (losses) reclassified into income during the period from regulatory assets and (liabilities) 36 22 138
Other Derivative Instruments | Electric Commodity      
Changes in Level 3 Commodity Derivatives      
Pre-tax gains (losses) reclassified into income during the period from regulatory assets and (liabilities) [3] (36) (22) 123
Other Derivative Instruments | Natural Gas Commodity      
Changes in Level 3 Commodity Derivatives      
Pre-tax gains (losses) reclassified into income during the period from regulatory assets and (liabilities) 0 0 [4] 15 [4]
Other Derivative Instruments | Natural Gas Commodity | Electric fuel and purchased power      
Changes in Level 3 Commodity Derivatives      
Pre-tax gains (losses) reclassified into income during the period from regulatory assets and (liabilities) 4 3  
Designated as Hedging Instrument | Cash Flow Hedges      
Changes in Level 3 Commodity Derivatives      
Pre-tax gains (losses) reclassified into income during the period from regulatory assets and (liabilities) 0 0 $ 0
Fair Value Measured on a Recurring Basis      
Derivatives, Fair Value [Line Items]      
Derivative instruments 165 114  
Derivative instruments 54 72  
Derivative Liability, Net 57 61  
Derivative Liability, Noncurrent 25 31  
Fair Value Measured on a Recurring Basis | Other Derivative Instruments | Commodity Contract      
Derivatives, Fair Value [Line Items]      
Derivative instruments 6 11  
Derivative instruments 54 72  
Derivative Liability, Net 57 61  
Derivative Liability, Noncurrent 15 24  
Fair Value Measured on a Recurring Basis | Other Derivative Instruments | Electric Commodity      
Derivatives, Fair Value [Line Items]      
Derivative Asset, Gross 147 90  
Netting [5] (3) (1)  
Derivative instruments 144 89  
Derivative Liability, Gross 3 1  
Netting [5] (3) (1)  
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 147 90  
Derivative Liability, Gross 3 1  
Fair Value Measured on a Recurring Basis | Other Derivative Instruments | Natural Gas Commodity      
Derivatives, Fair Value [Line Items]      
Derivative Asset, Gross 14 14  
Netting [5] 0 0  
Derivative instruments 14 14  
Derivative Liability, Gross 10 7  
Netting [5] 0 0  
Derivative Liability, Noncurrent 10 7  
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 14  
Derivative Liability, Gross 10 7  
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      
Changes in Level 3 Commodity Derivatives      
Derivative Asset, Current 1 0  
Fair Value Measured on a Recurring Basis | Other Current Assets      
Derivatives, Fair Value [Line Items]      
Derivative Asset, Gross 184 138  
Netting [5] (19) (24)  
Fair Value Measured on a Recurring Basis | Other Current Assets | Level 1      
Derivatives, Fair Value [Line Items]      
Derivative Asset, Gross 2 6  
Fair Value Measured on a Recurring Basis | Other Current Assets | Level 2      
Derivatives, Fair Value [Line Items]      
Derivative Asset, Gross 28 34  
Fair Value Measured on a Recurring Basis | Other Current Assets | Level 3      
Derivatives, Fair Value [Line Items]      
Derivative Asset, Gross 154 98  
Fair Value Measured on a Recurring Basis | Other Current Assets | Other Derivative Instruments | Commodity Contract      
Derivatives, Fair Value [Line Items]      
Derivative Asset, Gross 22 34  
Netting [5] (16) (23)  
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 2 6  
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 13 20  
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 7 8  
Fair Value Measured on a Recurring Basis | Other Current Assets | Designated as Hedging Instrument | Interest Rate Swap | Cash Flow Hedges      
Derivatives, Fair Value [Line Items]      
Derivative Asset, Gross 1 0  
Netting [5] 0 0  
Fair Value Measured on a Recurring Basis | Other Current Assets | Designated as Hedging Instrument | Interest Rate Swap | Level 1 | Cash Flow Hedges      
Derivatives, Fair Value [Line Items]      
Derivative Asset, Gross 0 0  
Fair Value Measured on a Recurring Basis | Other Current Assets | Designated as Hedging Instrument | Interest Rate Swap | Level 2 | Cash Flow Hedges      
Derivatives, Fair Value [Line Items]      
Derivative Asset, Gross 1 0  
Fair Value Measured on a Recurring Basis | Other Current Assets | Designated as Hedging Instrument | Interest Rate Swap | Level 3 | Cash Flow Hedges      
Derivatives, Fair Value [Line Items]      
Derivative Asset, Gross 0 0  
Fair Value Measured on a Recurring Basis | Other Noncurrent Assets      
Derivatives, Fair Value [Line Items]      
Derivative Asset, Gross 65 92  
Netting [5] (11) (20)  
Fair Value Measured on a Recurring Basis | Other Noncurrent Assets | Level 1      
Derivatives, Fair Value [Line Items]      
Derivative Asset, Gross 3 8  
Fair Value Measured on a Recurring Basis | Other Noncurrent Assets | Level 2      
Derivatives, Fair Value [Line Items]      
Derivative Asset, Gross 28 37  
Fair Value Measured on a Recurring Basis | Other Noncurrent Assets | Level 3      
Derivatives, Fair Value [Line Items]      
Derivative Asset, Gross 34 47  
Fair Value Measured on a Recurring Basis | Other Noncurrent Assets | Other Derivative Instruments | Commodity Contract      
Derivatives, Fair Value [Line Items]      
Derivative Asset, Gross 65 92  
Netting [5] (11) (20)  
Fair Value Measured on a Recurring Basis | Other Noncurrent Assets | Other Derivative Instruments | Commodity Contract | Level 1      
Derivatives, Fair Value [Line Items]      
Derivative Asset, Gross 3 8  
Fair Value Measured on a Recurring Basis | Other Noncurrent Assets | Other Derivative Instruments | Commodity Contract | Level 2      
Derivatives, Fair Value [Line Items]      
Derivative Asset, Gross 28 37  
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 34 47  
Fair Value Measured on a Recurring Basis | Other Current Liabilities      
Derivatives, Fair Value [Line Items]      
Derivative Liability, Gross 46 55  
Netting [5] (21) (24)  
Fair Value Measured on a Recurring Basis | Other Current Liabilities | Level 1      
Derivatives, Fair Value [Line Items]      
Derivative Liability, Gross 5 7  
Fair Value Measured on a Recurring Basis | Other Current Liabilities | Level 2      
Derivatives, Fair Value [Line Items]      
Derivative Liability, Gross 32 42  
Fair Value Measured on a Recurring Basis | Other Current Liabilities | Level 3      
Derivatives, Fair Value [Line Items]      
Derivative Liability, Gross 9 6  
Fair Value Measured on a Recurring Basis | Other Current Liabilities | Other Derivative Instruments | Commodity Contract      
Derivatives, Fair Value [Line Items]      
Derivative Liability, Gross 33 47  
Netting [5] (18) (23)  
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 5 7  
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 22 35  
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 6 5  
Fair Value Measured on a Recurring Basis | Other Noncurrent Liabilities      
Derivatives, Fair Value [Line Items]      
Derivative Liability, Gross 70 83  
Netting [5] (13) (22)  
Fair Value Measured on a Recurring Basis | Other Noncurrent Liabilities | Level 1      
Derivatives, Fair Value [Line Items]      
Derivative Liability, Gross 6 11  
Fair Value Measured on a Recurring Basis | Other Noncurrent Liabilities | Level 2      
Derivatives, Fair Value [Line Items]      
Derivative Liability, Gross 24 32  
Fair Value Measured on a Recurring Basis | Other Noncurrent Liabilities | Level 3      
Derivatives, Fair Value [Line Items]      
Derivative Liability, Gross 40 40  
Fair Value Measured on a Recurring Basis | Other Noncurrent Liabilities | Other Derivative Instruments | Commodity Contract      
Derivatives, Fair Value [Line Items]      
Derivative Liability, Gross 70 83  
Netting [5] (13) (22)  
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 6 11  
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 24 32  
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 40 40  
Fair Value, Measurements, Nonrecurring | Purchased Power Agreements      
Derivatives, Fair Value [Line Items]      
Derivative Liability, Net [6] 10 16  
Derivative Liability, Noncurrent [6] $ 6 $ 6  
[1] Relates primarily to NSP-Minnesota and SPS FTR instruments administered by MISO and SPP, respectively.
[2] 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.
[3] 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 auction and settlement dates, but exclude the original auction fair value.
[4] Other than $4 million of 2025 and $3 million of 2024 losses recorded to electric fuel and purchased power, amounts are recorded to cost of natural gas sold and transported. Amounts are subject to cost-recovery mechanisms and reclassified out of income to a regulatory asset, as appropriate.
[5] 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, 2025 and 2024, derivative assets and liabilities include no obligations to return cash collateral. At Dec. 31, 2025 and 2024, derivative assets and liabilities include rights to reclaim cash collateral of $4 million and $2 million, respectively. Counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements.
[6] Xcel Energy currently applies the normal purchase exception to qualifying PPAs. Balance relates to specific contracts that were previously recognized at fair value prior to applying the normal purchase exception, and are being amortized over the remaining contract lives along with the offsetting regulatory assets and liabilities.
v3.25.4
Fair Value of Long-Term Debt (Details) - USD ($)
$ in Millions
Dec. 31, 2025
Dec. 31, 2024
Financial Liabilities, Balance Sheet Groupings [Abstract]    
Long-term Debt, Carrying Amount $ 32,333 $ 28,419
Long-term debt, Fair Value $ 29,943 $ 25,115
v3.25.4
Pension and Postretirement Health Care Benefits (Details)
$ in Millions
 12 Months Ended
Dec. 31, 2026
Dec. 31, 2025
USD ($)
Dec. 31, 2024
USD ($)
Dec. 31, 2023
USD ($)
Pension Benefits [Abstract]        
annual interest crediting rates   4.76 4.90 4.72
Target Pension Asset Allocations [Abstract]        
transferred   $ 0 $ 0  
Supplemental Executive Retirement Plan (SERP) and Nonqualified Pension Plan        
Pension Benefits [Abstract]        
Total benefit obligation   13    
Net benefit cost recognized for financial reporting   3 2  
Pension Plan [Member]        
Pension Benefits [Abstract]        
Total benefit obligation   2,820 2,752 $ 2,943
Defined Benefit Plan, Plan Assets, Amount   2,690 [1] 2,504 [1] 2,690
Net benefit cost recognized for financial reporting   $ 59 $ 79 $ 74
Expected average long-term rate of return on assets (as a percent)   7.13% 6.93% 6.93%
Target Pension Asset Allocations [Abstract]        
Target pension asset allocations (as a percent)   100.00% 100.00%  
Pension Plan [Member] | Level 1        
Pension Benefits [Abstract]        
Defined Benefit Plan, Plan Assets, Amount [1]   $ 133 $ 142  
Pension Plan [Member] | Level 2        
Pension Benefits [Abstract]        
Defined Benefit Plan, Plan Assets, Amount [1]   753 662  
Pension Plan [Member] | Level 3        
Pension Benefits [Abstract]        
Defined Benefit Plan, Plan Assets, Amount [1]   3 6  
Pension Plan [Member] | Fair Value Measured at Net Asset Value Per Share        
Pension Benefits [Abstract]        
Defined Benefit Plan, Plan Assets, Amount [1]   1,801 1,694  
Pension Plan [Member] | Cash        
Pension Benefits [Abstract]        
Defined Benefit Plan, Plan Assets, Amount [1]   $ 110 $ 117  
Target Pension Asset Allocations [Abstract]        
Target pension asset allocations (as a percent)   2.00% 2.00%  
Pension Plan [Member] | Cash | Level 1        
Pension Benefits [Abstract]        
Defined Benefit Plan, Plan Assets, Amount [1]   $ 110 $ 117  
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],[2]   1,097 1,015  
Pension Plan [Member] | Commingled Funds | Level 1        
Pension Benefits [Abstract]        
Defined Benefit Plan, Plan Assets, Amount [1],[2]   0 0  
Pension Plan [Member] | Commingled Funds | Level 2        
Pension Benefits [Abstract]        
Defined Benefit Plan, Plan Assets, Amount [1],[2]   0 0  
Pension Plan [Member] | Commingled Funds | Level 3        
Pension Benefits [Abstract]        
Defined Benefit Plan, Plan Assets, Amount [1],[2]   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],[2]   1,097 1,015  
Pension Plan [Member] | Debt Securities        
Pension Benefits [Abstract]        
Defined Benefit Plan, Plan Assets, Amount [1]   748 662  
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]   745 656  
Pension Plan [Member] | Debt Securities | Level 3        
Pension Benefits [Abstract]        
Defined Benefit Plan, Plan Assets, Amount [1]   3 6  
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]   $ 23 $ 25  
Target Pension Asset Allocations [Abstract]        
Target pension asset allocations (as a percent)   30.00% 31.00%  
Pension Plan [Member] | Equity Securities | Level 1        
Pension Benefits [Abstract]        
Defined Benefit Plan, Plan Assets, Amount [1]   $ 23 $ 25  
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]   8 6  
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]   8 6  
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)   38.00% 38.00%  
Pension Plan [Member] | Alternative investments        
Target Pension Asset Allocations [Abstract]        
Target pension asset allocations (as a percent)   19.00% 20.00%  
Pension Plan [Member] | Short-to-intermediate fixed income securities        
Target Pension Asset Allocations [Abstract]        
Target pension asset allocations (as a percent)   11.00% 9.00%  
Pension Plan [Member] | Partnership        
Pension Benefits [Abstract]        
Defined Benefit Plan, Plan Assets, Amount [1],[2]   $ 704 $ 679  
Pension Plan [Member] | Partnership | Level 1        
Pension Benefits [Abstract]        
Defined Benefit Plan, Plan Assets, Amount [1],[2]   0 0  
Pension Plan [Member] | Partnership | Level 2        
Pension Benefits [Abstract]        
Defined Benefit Plan, Plan Assets, Amount [1],[2]   0 0  
Pension Plan [Member] | Partnership | Level 3        
Pension Benefits [Abstract]        
Defined Benefit Plan, Plan Assets, Amount [1],[2]   0 0  
Pension Plan [Member] | Partnership | Fair Value Measured at Net Asset Value Per Share        
Pension Benefits [Abstract]        
Defined Benefit Plan, Plan Assets, Amount [1],[2]   704 679  
Other Postretirement Benefits Plan [Member]        
Pension Benefits [Abstract]        
Total benefit obligation   430 427 $ 394
Defined Benefit Plan, Plan Assets, Amount   342 [3] 344 [3] 356
Net benefit cost recognized for financial reporting   $ 9 $ 7 $ 6
Expected average long-term rate of return on assets (as a percent)   6.25% 5.00% 5.00%
Target Pension Asset Allocations [Abstract]        
Target pension asset allocations (as a percent)   100.00% 100.00%  
Other Postretirement Benefits Plan [Member] | Level 1        
Pension Benefits [Abstract]        
Defined Benefit Plan, Plan Assets, Amount [3]   $ 35 $ 35  
Other Postretirement Benefits Plan [Member] | Level 2        
Pension Benefits [Abstract]        
Defined Benefit Plan, Plan Assets, Amount [3]   195 241  
Other Postretirement Benefits Plan [Member] | Level 3        
Pension Benefits [Abstract]        
Defined Benefit Plan, Plan Assets, Amount [3]   0 0  
Other Postretirement Benefits Plan [Member] | Fair Value Measured at Net Asset Value Per Share        
Pension Benefits [Abstract]        
Defined Benefit Plan, Plan Assets, Amount [3]   112 68  
Other Postretirement Benefits Plan [Member] | Cash        
Pension Benefits [Abstract]        
Defined Benefit Plan, Plan Assets, Amount [3]   $ 35 $ 35  
Target Pension Asset Allocations [Abstract]        
Target pension asset allocations (as a percent)   1.00% 3.00%  
Other Postretirement Benefits Plan [Member] | Cash | Level 1        
Pension Benefits [Abstract]        
Defined Benefit Plan, Plan Assets, Amount [3]   $ 35 $ 35  
Other Postretirement Benefits Plan [Member] | Cash | Level 2        
Pension Benefits [Abstract]        
Defined Benefit Plan, Plan Assets, Amount [3]   0 0  
Other Postretirement Benefits Plan [Member] | Cash | Level 3        
Pension Benefits [Abstract]        
Defined Benefit Plan, Plan Assets, Amount [3]   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 [3]   0 0  
Other Postretirement Benefits Plan [Member] | Commingled Funds        
Pension Benefits [Abstract]        
Defined Benefit Plan, Plan Assets, Amount [3],[4]   67 23  
Other Postretirement Benefits Plan [Member] | Commingled Funds | Level 1        
Pension Benefits [Abstract]        
Defined Benefit Plan, Plan Assets, Amount [3],[4]   0 0  
Other Postretirement Benefits Plan [Member] | Commingled Funds | Level 2        
Pension Benefits [Abstract]        
Defined Benefit Plan, Plan Assets, Amount [3],[4]   0 0  
Other Postretirement Benefits Plan [Member] | Commingled Funds | Level 3        
Pension Benefits [Abstract]        
Defined Benefit Plan, Plan Assets, Amount [3],[4]   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 [3],[4]   67 23  
Other Postretirement Benefits Plan [Member] | Debt Securities        
Pension Benefits [Abstract]        
Defined Benefit Plan, Plan Assets, Amount [3]   154 201  
Other Postretirement Benefits Plan [Member] | Debt Securities | Level 1        
Pension Benefits [Abstract]        
Defined Benefit Plan, Plan Assets, Amount [3]   0 0  
Other Postretirement Benefits Plan [Member] | Debt Securities | Level 2        
Pension Benefits [Abstract]        
Defined Benefit Plan, Plan Assets, Amount [3]   154 201  
Other Postretirement Benefits Plan [Member] | Debt Securities | Level 3        
Pension Benefits [Abstract]        
Defined Benefit Plan, Plan Assets, Amount [3]   0 0  
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 [3]   $ 0 $ 0  
Other Postretirement Benefits Plan [Member] | Equity Securities        
Target Pension Asset Allocations [Abstract]        
Target pension asset allocations (as a percent)   25.00% 25.00%  
Other Postretirement Benefits Plan [Member] | Other        
Pension Benefits [Abstract]        
Defined Benefit Plan, Plan Assets, Amount [3]   $ 1 $ 0  
Other Postretirement Benefits Plan [Member] | Other | Level 1        
Pension Benefits [Abstract]        
Defined Benefit Plan, Plan Assets, Amount [3]   0 0  
Other Postretirement Benefits Plan [Member] | Other | Level 2        
Pension Benefits [Abstract]        
Defined Benefit Plan, Plan Assets, Amount [3]   1 0  
Other Postretirement Benefits Plan [Member] | Other | Level 3        
Pension Benefits [Abstract]        
Defined Benefit Plan, Plan Assets, Amount [3]   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 [3]   $ 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)   0.00% 0.00%  
Other Postretirement Benefits Plan [Member] | Alternative investments        
Target Pension Asset Allocations [Abstract]        
Target pension asset allocations (as a percent)   13.00% 11.00%  
Other Postretirement Benefits Plan [Member] | Short-to-intermediate fixed income securities        
Target Pension Asset Allocations [Abstract]        
Target pension asset allocations (as a percent)   61.00% 61.00%  
Other Postretirement Benefits Plan [Member] | Insurance contracts        
Pension Benefits [Abstract]        
Defined Benefit Plan, Plan Assets, Amount [3]   $ 40 $ 40  
Other Postretirement Benefits Plan [Member] | Insurance contracts | Level 1        
Pension Benefits [Abstract]        
Defined Benefit Plan, Plan Assets, Amount [3]   0 0  
Other Postretirement Benefits Plan [Member] | Insurance contracts | Level 2        
Pension Benefits [Abstract]        
Defined Benefit Plan, Plan Assets, Amount [3]   40 40  
Other Postretirement Benefits Plan [Member] | Insurance contracts | Level 3        
Pension Benefits [Abstract]        
Defined Benefit Plan, Plan Assets, Amount [3]   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 [3]   0 0  
Other Postretirement Benefits Plan [Member] | Partnership        
Pension Benefits [Abstract]        
Defined Benefit Plan, Plan Assets, Amount [3],[4]   45 45  
Other Postretirement Benefits Plan [Member] | Partnership | Level 1        
Pension Benefits [Abstract]        
Defined Benefit Plan, Plan Assets, Amount [3],[4]   0 0  
Other Postretirement Benefits Plan [Member] | Partnership | Level 2        
Pension Benefits [Abstract]        
Defined Benefit Plan, Plan Assets, Amount [3],[4]   0 0  
Other Postretirement Benefits Plan [Member] | Partnership | Level 3        
Pension Benefits [Abstract]        
Defined Benefit Plan, Plan Assets, Amount [3],[4]   0 0  
Other Postretirement Benefits Plan [Member] | Partnership | Fair Value Measured at Net Asset Value Per Share        
Pension Benefits [Abstract]        
Defined Benefit Plan, Plan Assets, Amount [3],[4]   $ 45 $ 45  
Forecast | Pension Plan [Member]        
Pension Benefits [Abstract]        
Expected average long-term rate of return on assets for next fiscal year (as a percent) 7.13%      
[1] See Note 10 for further information regarding fair value measurement inputs and methods.
[2] Prior period amounts have been reclassified to conform with current year presentation
[3] See Note 10 for further information on fair value measurement inputs and methods.
[4] Prior period amounts have been reclassified to conform with current year presentation
v3.25.4
Funded Status (Details) - USD ($)
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Change in Fair Value of Plan Assets [Roll Forward]      
Defined Benefit Plan, Plan Assets, Payment for Settlement   $ 168,000,000  
Funded Status of Plans at Dec. 31 [Abstract]      
Liability, Defined Benefit Plan, Noncurrent $ (365,000,000) (477,000,000)  
Components of Net Periodic Benefit Cost (Credit) [Abstract]      
Settlement Charge Recognized in Operating and Maintenance Expenses 2,732,000,000 2,540,000,000 $ 2,444,000,000
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 2,624,000,000 2,554,000,000  
Change in Projected Benefit Obligation [Roll Forward]      
Obligation at Jan. 1 2,752,000,000 2,943,000,000  
Service cost 76,000,000 76,000,000 74,000,000
Interest cost 155,000,000 151,000,000 158,000,000
Actuarial loss 67,000,000 (77,000,000)  
Defined Benefit Plan, Benefit Obligation, Contributions by Plan Participant 0 0  
Defined Benefit Plan, Benefit Obligation, Prescription Drug Subsidy Receipt 0 0  
Benefit payments (230,000,000) (341,000,000) [1]  
Obligation at Dec. 31 2,820,000,000 2,752,000,000 2,943,000,000
Change in Fair Value of Plan Assets [Roll Forward]      
Fair value of plan assets at Jan. 1 2,504,000,000 [2] 2,690,000,000  
Actual return (loss) on plan assets 291,000,000 55,000,000  
Employer contributions 125,000,000 100,000,000  
Benefit payments (230,000,000) (341,000,000)  
Fair value of plan assets at Dec. 31 2,690,000,000 [2] 2,504,000,000 [2] 2,690,000,000
Funded Status of Plans at Dec. 31 [Abstract]      
Funded status (130,000,000) (248,000,000)  
Liability, Defined Benefit Plan, Current 0 0  
Liability, Defined Benefit Plan, Noncurrent (130,000,000) (248,000,000)  
Defined Benefit Plan, Amounts for Asset (Liability) Recognized in Statement of Financial Position (130,000,000) (248,000,000)  
Assets for Plan Benefits, Defined Benefit Plan 0 0  
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost [Abstract]      
Net loss 1,029,000,000 1,074,000,000  
Prior service (credit) cost (6,000,000) (8,000,000)  
Total 1,023,000,000 1,066,000,000  
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 36,000,000 32,000,000  
Noncurrent regulatory assets 938,000,000 983,000,000  
Deferred income taxes 13,000,000 14,000,000  
Net-of-tax accumulated other comprehensive income 36,000,000 37,000,000  
Total $ 1,023,000,000 $ 1,066,000,000  
Significant Assumptions Used to Measure Benefit Obligations [Abstract]      
Discount rate for year-end valuation (as a percent) 5.78% 5.88%  
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 $ 76,000,000 $ 76,000,000 74,000,000
Interest cost 155,000,000 151,000,000 158,000,000
Expected return on plan assets (208,000,000) (206,000,000) (209,000,000)
Amortization of prior service cost (credit) (2,000,000) (2,000,000) (1,000,000)
Amortization of net loss 28,000,000 30,000,000 22,000,000
Settlement charge [3] 0 67,000,000 0
Net periodic benefit cost 49,000,000 116,000,000 44,000,000
Costs not recognized due to regulation 10,000,000 (37,000,000) 30,000,000
Net benefit cost recognized for financial reporting 59,000,000 79,000,000 74,000,000
Settlement Charge Recognized in Operating and Maintenance Expenses $ 0 $ 8,000,000 $ 0
Significant Assumptions Used to Measure Costs [Abstract]      
Discount rate (as a percent) 5.88% 5.49% 5.80%
Expected average long-term increase in compensation level (as a percent) 4.25% 4.25% 4.25%
Expected average long-term rate of return on assets (as a percent) 7.13% 6.93% 6.93%
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. 1 427,000,000 394,000,000  
Service cost 1,000,000 1,000,000 $ 1,000,000
Interest cost 24,000,000 21,000,000 22,000,000
Actuarial loss 21,000,000 55,000,000  
Defined Benefit Plan, Benefit Obligation, Contributions by Plan Participant 9,000,000 9,000,000  
Defined Benefit Plan, Benefit Obligation, Prescription Drug Subsidy Receipt 3,000,000 0  
Benefit payments (55,000,000) (53,000,000)  
Obligation at Dec. 31 430,000,000 427,000,000 394,000,000
Change in Fair Value of Plan Assets [Roll Forward]      
Fair value of plan assets at Jan. 1 344,000,000 [4] 356,000,000  
Actual return (loss) on plan assets 31,000,000 21,000,000  
Employer contributions 13,000,000 11,000,000  
Benefit payments (55,000,000) (53,000,000)  
Fair value of plan assets at Dec. 31 342,000,000 [4] 344,000,000 [4] 356,000,000
Funded Status of Plans at Dec. 31 [Abstract]      
Funded status (88,000,000) (83,000,000)  
Liability, Defined Benefit Plan, Current (2,000,000) (4,000,000)  
Liability, Defined Benefit Plan, Noncurrent (93,000,000) (89,000,000)  
Defined Benefit Plan, Amounts for Asset (Liability) Recognized in Statement of Financial Position (88,000,000) (83,000,000)  
Assets for Plan Benefits, Defined Benefit Plan 7,000,000 10,000,000  
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost [Abstract]      
Net loss 117,000,000 113,000,000  
Prior service (credit) cost 0 0  
Total 117,000,000 113,000,000  
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 5,000,000 2,000,000  
Noncurrent regulatory assets 125,000,000 127,000,000  
Deferred income taxes 1,000,000 1,000,000  
Net-of-tax accumulated other comprehensive income 2,000,000 2,000,000  
Total $ 117,000,000 $ 113,000,000  
Significant Assumptions Used to Measure Benefit Obligations [Abstract]      
Discount rate for year-end valuation (as a percent) 5.66% 5.88%  
Defined Benefit Plan, Health Care Cost Trend Rate Assumed, Pre-65 7.00% 7.00%  
Defined Benefit Plan, Health Care Cost Trend Rate Assumed, Post-65 7.50% 7.50%  
Components of Net Periodic Benefit Cost (Credit) [Abstract]      
Service cost $ 1,000,000 $ 1,000,000 1,000,000
Interest cost 24,000,000 21,000,000 22,000,000
Expected return on plan assets (20,000,000) (17,000,000) (17,000,000)
Amortization of prior service cost (credit) 0 0 (1,000,000)
Amortization of net loss 4,000,000 2,000,000 1,000,000
Settlement charge [3] 0 0 0
Net periodic benefit cost 9,000,000 7,000,000 6,000,000
Costs not recognized due to regulation 0 0 0
Net benefit cost recognized for financial reporting $ 9,000,000 $ 7,000,000 $ 6,000,000
Significant Assumptions Used to Measure Costs [Abstract]      
Discount rate (as a percent) 5.88% 5.54% 5.80%
Expected average long-term increase in compensation level (as a percent) 0.00% 0.00% 0.00%
Expected average long-term rate of return on assets (as a percent) 6.25% 5.00% 5.00%
Defined Benefit Plan, Plan Assets, Contributions by Plan Participant $ 9,000,000 $ 9,000,000  
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 $ 15,000,000 $ 18,000,000  
Ultimate health care trend assumption rate (as a percent) 4.50% 4.50%  
[1] Includes $168 million of lump-sum benefit payments used in the determination of settlement charges in 2024.
[2] See Note 10 for further information regarding fair value measurement inputs and methods.
[3] A settlement charge is required when the amount of all lump-sum distributions during the year is greater than the sum of the service and interest cost components of the annual net periodic pension cost. In 2024, as a result of lump-sum distributions during the plan year, Xcel Energy recorded a total pension settlement charge of $67 million, the majority of which was not recognized due to the effects of regulation. A total of $8 million was recorded in the consolidated statements of income in 2024. There were no settlement charges recorded for the qualified pension plans in 2025 and 2023.
[4] See Note 10 for further information on fair value measurement inputs and methods.
v3.25.4
Benefit Plans and Other Postretirement Benefits Net Periodic Benefit Cost (Credit) (Details) - USD ($)
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Defined Benefit Plan Disclosure [Line Items]      
Operating and maintenance expenses $ 2,732,000,000 $ 2,540,000,000 $ 2,444,000,000
transferred 0 0  
Pension Plan [Member]      
Defined Benefit Plan Disclosure [Line Items]      
Service cost 76,000,000 76,000,000 74,000,000
Operating and maintenance expenses 0 8,000,000 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]      
Defined Benefit Plan Disclosure [Line Items]      
Service cost 1,000,000 1,000,000 $ 1,000,000
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 $ (15,000,000) $ (18,000,000)  
v3.25.4
Benefit Plans and Other Postretirement Benefits, Postretirement Health Care Benefits (Details)
$ in Millions
 12 Months Ended
Dec. 31, 2025
USD ($)
Dec. 31, 2024
USD ($)
Postretirement Health Care Benefits [Abstract]    
Estimated costs of health plan subsidies - VRP $ 22 $ 29
Estimated cost of other medical benefits - VRP $ 4 $ 4
Defined Benefit Plan, Health Care Cost Trend Rate Assumed and Ultimate Trend Assumption, Ultimate Trend Assumption 0.0450 0.0450
Years until ultimate trend is reached 8 years 9 years
Other Postretirement Benefits Plan [Member]    
Postretirement Health Care Benefits [Abstract]    
Target pension asset allocations (as a percent) 100.00% 100.00%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate, VRP 0.0450 0.0500
Defined Benefit Plan, Health Care Cost Trend Rate Assumed and Ultimate Trend Assumption, VRP 0.0700 0.0700
Pension Plan [Member]    
Postretirement Health Care Benefits [Abstract]    
Target pension asset allocations (as a percent) 100.00% 100.00%
Equity Securities | Other Postretirement Benefits Plan [Member]    
Postretirement Health Care Benefits [Abstract]    
Target pension asset allocations (as a percent) 25.00% 25.00%
Equity Securities | Pension Plan [Member]    
Postretirement Health Care Benefits [Abstract]    
Target pension asset allocations (as a percent) 30.00% 31.00%
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) 0.00% 0.00%
Long-duration fixed income and interest rate swap securities | Pension Plan [Member]    
Postretirement Health Care Benefits [Abstract]    
Target pension asset allocations (as a percent) 38.00% 38.00%
Short-to-intermediate fixed income securities | Other Postretirement Benefits Plan [Member]    
Postretirement Health Care Benefits [Abstract]    
Target pension asset allocations (as a percent) 61.00% 61.00%
Short-to-intermediate fixed income securities | Pension Plan [Member]    
Postretirement Health Care Benefits [Abstract]    
Target pension asset allocations (as a percent) 11.00% 9.00%
Alternative investments | Other Postretirement Benefits Plan [Member]    
Postretirement Health Care Benefits [Abstract]    
Target pension asset allocations (as a percent) 13.00% 11.00%
Alternative investments | Pension Plan [Member]    
Postretirement Health Care Benefits [Abstract]    
Target pension asset allocations (as a percent) 19.00% 20.00%
Cash | Other Postretirement Benefits Plan [Member]    
Postretirement Health Care Benefits [Abstract]    
Target pension asset allocations (as a percent) 1.00% 3.00%
Cash | Pension Plan [Member]    
Postretirement Health Care Benefits [Abstract]    
Target pension asset allocations (as a percent) 2.00% 2.00%
v3.25.4
Benefit Plans and Other Postretirement Benefits, Postretirement Benefit Plan Benefit Obligations, Cash Flows and Benefit Costs (Details) - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Change in Projected Benefit Obligation [Roll Forward]      
Defined Benefit Plan, Plan Assets, Payment for Settlement   $ 168  
Funded Status of Plans at Dec. 31 [Abstract]      
Noncurrent liabilities $ (365) (477)  
Pension Plan [Member]      
Change in Projected Benefit Obligation [Roll Forward]      
Obligation at Jan. 1 2,752 2,943  
Service cost 76 76 $ 74
Interest cost 155 151 158
Actuarial loss 67 (77)  
Plan participants' contributions 0 0  
Medicare subsidy reimbursements 0 0  
Benefit payments (230) (341) [1]  
Obligation at Dec. 31 2,820 2,752 2,943
Change in Fair Value of Plan Assets [Roll Forward]      
Fair value of plan assets at Jan. 1 2,504 [2] 2,690  
Actual return (loss) on plan assets 291 55  
Employer contributions 125 100  
Participant contributions 0 0  
Benefit payments (230) (341)  
Fair value of plan assets at Dec. 31 2,690 [2] 2,504 [2] 2,690
Funded status (130) (248)  
Funded Status of Plans at Dec. 31 [Abstract]      
Assets for Plan Benefits, Defined Benefit Plan 0 0  
Current liabilities 0 0  
Noncurrent liabilities (130) (248)  
Net postretirement amounts recognized on consolidated balance sheets (130) (248)  
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost [Abstract]      
Net loss 1,029 1,074  
Prior service (credit) cost (6) (8)  
Total 1,023 1,066  
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 36 32  
Noncurrent regulatory assets 938 983  
Current regulatory liabilities 0 0  
Noncurrent regulatory liabilities 0 0  
Deferred income taxes 13 14  
Net-of-tax accumulated other comprehensive income 36 37  
Total $ 1,023 $ 1,066  
Significant Assumptions Used to Measure Benefit Obligations [Abstract]      
Discount rate for year-end valuation (as a percent) 5.78% 5.88%  
Components of Net Periodic Benefit Cost (Credit) [Abstract]      
Service cost $ 76 $ 76 74
Interest cost 155 151 158
Expected return on plan assets (208) (206) (209)
Amortization of prior service cost (credit) (2) (2) (1)
Amortization of net loss 28 30 22
Defined Benefit Plan, Net Periodic Benefit Cost (Credit), Gain (Loss) Due to Settlement [3] 0 (67) 0
Net periodic benefit cost $ 49 $ 116 $ 44
Significant Assumptions Used to Measure Costs [Abstract]      
Discount rate (as a percent) 5.88% 5.49% 5.80%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Rate of Compensation Increase 4.25% 4.25% 4.25%
Expected average long-term rate of return on assets (as a percent) 7.13% 6.93% 6.93%
Defined Benefit Plan, Costs Not Recognized Due To Regulation $ 10 $ (37) $ 30
Net benefit cost recognized for financial reporting 59 79 74
Other Postretirement Benefits Plan [Member]      
Change in Projected Benefit Obligation [Roll Forward]      
Obligation at Jan. 1 427 394  
Service cost 1 1 1
Interest cost 24 21 22
Actuarial loss 21 55  
Plan participants' contributions 9 9  
Medicare subsidy reimbursements 3 0  
Benefit payments (55) (53)  
Obligation at Dec. 31 430 427 394
Change in Fair Value of Plan Assets [Roll Forward]      
Fair value of plan assets at Jan. 1 344 [4] 356  
Actual return (loss) on plan assets 31 21  
Employer contributions 13 11  
Participant contributions 9 9  
Benefit payments (55) (53)  
Fair value of plan assets at Dec. 31 342 [4] 344 [4] 356
Funded status (88) (83)  
Funded Status of Plans at Dec. 31 [Abstract]      
Assets for Plan Benefits, Defined Benefit Plan 7 10  
Current liabilities (2) (4)  
Noncurrent liabilities (93) (89)  
Net postretirement amounts recognized on consolidated balance sheets (88) (83)  
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost [Abstract]      
Net loss 117 113  
Prior service (credit) cost 0 0  
Total 117 113  
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 5 2  
Noncurrent regulatory assets 125 127  
Current regulatory liabilities (1) (1)  
Noncurrent regulatory liabilities (15) (18)  
Deferred income taxes 1 1  
Net-of-tax accumulated other comprehensive income 2 2  
Total $ 117 $ 113  
Significant Assumptions Used to Measure Benefit Obligations [Abstract]      
Discount rate for year-end valuation (as a percent) 5.66% 5.88%  
Defined Benefit Plan, Health Care Cost Trend Rate Assumed, Pre-65 7.00% 7.00%  
Defined Benefit Plan, Health Care Cost Trend Rate Assumed, Post-65 7.50% 7.50%  
Ultimate health care trend assumption rate (as a percent) 4.50% 4.50%  
Defined Benefit Plan, Ultimate Health Care Cost Trend Rate; Post - 65 4.50% 4.50%  
Period until ultimate trend rate is reached (in years) 8 years 9 years  
Components of Net Periodic Benefit Cost (Credit) [Abstract]      
Service cost $ 1 $ 1 1
Interest cost 24 21 22
Expected return on plan assets (20) (17) (17)
Amortization of prior service cost (credit) 0 0 (1)
Amortization of net loss 4 2 1
Defined Benefit Plan, Net Periodic Benefit Cost (Credit), Gain (Loss) Due to Settlement [3] 0 0 0
Net periodic benefit cost $ 9 $ 7 $ 6
Significant Assumptions Used to Measure Costs [Abstract]      
Discount rate (as a percent) 5.88% 5.54% 5.80%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Rate of Compensation Increase 0.00% 0.00% 0.00%
Expected average long-term rate of return on assets (as a percent) 6.25% 5.00% 5.00%
Defined Benefit Plan, Costs Not Recognized Due To Regulation $ 0 $ 0 $ 0
Net benefit cost recognized for financial reporting $ 9 $ 7 $ 6
[1] Includes $168 million of lump-sum benefit payments used in the determination of settlement charges in 2024.
[2] See Note 10 for further information regarding fair value measurement inputs and methods.
[3] A settlement charge is required when the amount of all lump-sum distributions during the year is greater than the sum of the service and interest cost components of the annual net periodic pension cost. In 2024, as a result of lump-sum distributions during the plan year, Xcel Energy recorded a total pension settlement charge of $67 million, the majority of which was not recognized due to the effects of regulation. A total of $8 million was recorded in the consolidated statements of income in 2024. There were no settlement charges recorded for the qualified pension plans in 2025 and 2023.
[4] See Note 10 for further information on fair value measurement inputs and methods.
v3.25.4
Projected Benefit Payments (Details) - USD ($)
$ in Millions
 1 Months Ended 12 Months Ended
Jan. 31, 2026
Dec. 31, 2026
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Pension Plan [Member]          
Defined Benefit Plan, Gross Projected Benefit Payments [Abstract]          
2026     $ 252    
2027     243    
2028     244    
2029     249    
2030     243    
2031-2035     $ 1,165    
Defined Benefit Plan, Net Projected Benefit Payments [Abstract]          
Target pension asset allocations (as a percent)     100.00% 100.00%  
Pension Plan [Member] | Equity Securities [Member]          
Defined Benefit Plan, Net Projected Benefit Payments [Abstract]          
Target pension asset allocations (as a percent)     30.00% 31.00%  
Pension Plan [Member] | Long-duration fixed income and interest rate swap securities          
Defined Benefit Plan, Net Projected Benefit Payments [Abstract]          
Target pension asset allocations (as a percent)     38.00% 38.00%  
Pension Plan [Member] | Short-to-intermediate fixed income securities          
Defined Benefit Plan, Net Projected Benefit Payments [Abstract]          
Target pension asset allocations (as a percent)     11.00% 9.00%  
Pension Plan [Member] | Alternative investments          
Defined Benefit Plan, Net Projected Benefit Payments [Abstract]          
Target pension asset allocations (as a percent)     19.00% 20.00%  
Pension Plan [Member] | Cash equivalents          
Defined Benefit Plan, Net Projected Benefit Payments [Abstract]          
Target pension asset allocations (as a percent)     2.00% 2.00%  
Pension Plan [Member] | Xcel Energy [Member]          
Defined Benefit Plan, Net Projected Benefit Payments [Abstract]          
Payment for Pension Benefits     $ 125 $ 100 $ 50
Pension Plan [Member] | Xcel Energy [Member] | Subsequent Event          
Defined Benefit Plan, Net Projected Benefit Payments [Abstract]          
Payment for Pension Benefits $ 75        
Other Postretirement Benefits Plan [Member]          
Defined Benefit Plan, Gross Projected Benefit Payments [Abstract]          
2026     43    
2027     42    
2028     41    
2029     40    
2030     39    
2031-2035     183    
Expected Medicare Part D Subsidies [Abstract]          
2026     3    
2027     3    
2028     3    
2029     3    
2030     3    
2031-2035     16    
Defined Benefit Plan, Net Projected Benefit Payments [Abstract]          
2026     40    
2027     39    
2028     38    
2029     37    
2030     36    
2031-2035     $ 167    
Target pension asset allocations (as a percent)     100.00% 100.00%  
Other Postretirement Benefits Plan [Member] | Equity Securities [Member]          
Defined Benefit Plan, Net Projected Benefit Payments [Abstract]          
Target pension asset allocations (as a percent)     25.00% 25.00%  
Other Postretirement Benefits Plan [Member] | Long-duration fixed income and interest rate swap securities          
Defined Benefit Plan, Net Projected Benefit Payments [Abstract]          
Target pension asset allocations (as a percent)     0.00% 0.00%  
Other Postretirement Benefits Plan [Member] | Short-to-intermediate fixed income securities          
Defined Benefit Plan, Net Projected Benefit Payments [Abstract]          
Target pension asset allocations (as a percent)     61.00% 61.00%  
Other Postretirement Benefits Plan [Member] | Alternative investments          
Defined Benefit Plan, Net Projected Benefit Payments [Abstract]          
Target pension asset allocations (as a percent)     13.00% 11.00%  
Other Postretirement Benefits Plan [Member] | Cash equivalents          
Defined Benefit Plan, Net Projected Benefit Payments [Abstract]          
Target pension asset allocations (as a percent)     1.00% 3.00%  
Defined Benefit Plan, Overfunded Plan [Member] | Xcel Energy [Member]          
Defined Benefit Plan, Net Projected Benefit Payments [Abstract]          
Payment for Pension Benefits     $ 13 $ 11 $ 11
Defined Benefit Plan, Overfunded Plan [Member] | Xcel Energy [Member] | Forecast          
Defined Benefit Plan, Net Projected Benefit Payments [Abstract]          
Payment for Pension Benefits   $ 8      
v3.25.4
Benefit Plans and Other Postretirement Benefits Defined Contribution Plans (Details) - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Retirement Benefits [Abstract]      
Defined Contribution Plan, Cost $ 53 $ 50 $ 49
Estimated costs of health plan subsidies - VRP 22 29  
Estimated cost of other medical benefits - VRP $ 4 $ 4  
v3.25.4
Commitments and Contingencies Gas Trading Litigation (Details)
Dec. 31, 2025
Gas Trading Litigation [Member]  
Loss Contingencies [Line Items]  
Loss Contingency, Pending Claims, Number 1
v3.25.4
Commitments and Contingencies Litigation (Details)
$ in Millions
 3 Months Ended 12 Months Ended
Dec. 31, 2025
USD ($)
numberOfPlaintiffs
complaint
Sep. 30, 2025
USD ($)
Dec. 31, 2025
USD ($)
numberOfPlaintiffs
complaint
Dec. 31, 2024
USD ($)
Dec. 31, 2023
USD ($)
Guarantees and Product Warranties [Abstract]          
Number of complaints related to the Marshall Wildfire | complaint 307   307    
Number of plaintiffs related to the Marshall Wildfire | numberOfPlaintiffs 4,087   4,087    
Amount of insurance coverage $ 500   $ 500    
Settlement Liabilities, Current 5   5    
Gain (Loss) from Litigation Settlement     0 $ 0 $ 35
Insurance Settlements Receivable 353   353    
Marshall Settlements Reached 640   640    
Loss Contingencies [Line Items]          
Gain (Loss) from Litigation Settlement     $ 0 $ 0 $ (35)
Marshall Wildfire Settlement          
Guarantees and Product Warranties [Abstract]          
Gain (Loss) from Litigation Settlement 12 $ 287      
Loss Contingencies [Line Items]          
Gain (Loss) from Litigation Settlement $ (12) $ (287)      
v3.25.4
Commitments and Contingencies MGP Sites (Details) - Other MGP, Landfill, or Disposal Sites [Member]
Dec. 31, 2025
USD ($)
Site
Loss Contingencies [Line Items]  
Number of identified MGP, landfill, or disposal sites under current investigation and/or remediation | Site 11
Cost of identified MGP, landfill, or disposal sites under current investigation and/or remediation | $ $ 15,000,000
v3.25.4
Environmental Requirements - Water and Waste (Details)
$ in Millions
Dec. 31, 2025
USD ($)
Loss Contingencies [Line Items]  
Accrued liability of sites under investigation as part of federal CCR program $ 45
Cost of Coal Ash Removal Projects 105
Legacy CCR Investigation and Remediation Costs 15
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
v3.25.4
AROs (Details) - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]    
Beginning balance $ 3,713 $ 3,218
Amounts Incurred 16 [1] 109 [2]
Amounts Settled   (6)
Accretion 178 153
Cash flow revisions (19) [3] 239 [4]
Ending balance 3,888 3,713
Fair Value, Recurring [Member] | Estimate of Fair Value Measurement [Member]    
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]    
Decommissioning fund investments 3,940 [5] 3,494 [6]
Fair Value, Recurring [Member] | Estimate of Fair Value Measurement [Member] | NSP Minnesota    
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]    
Decommissioning fund investments 3,900 3,500
Electric Plant Nuclear Production Decommissioning    
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]    
Beginning balance 2,476 2,107
Amounts Incurred 0 [1] 0 [2]
Amounts Settled   0
Accretion 127 106
Cash flow revisions 0 [3] 263 [4]
Ending balance 2,603 2,476
Electric Plant Wind Production    
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]    
Beginning balance 509 526
Amounts Incurred 0 [1] 0 [2]
Amounts Settled   0
Accretion 18 19
Cash flow revisions (12) [3] (36) [4]
Ending balance 515 509
Electric Plant Steam, Hydro and Other Production Asbestos    
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]    
Beginning balance 495 361
Amounts Incurred 16 [1] 109 [2]
Amounts Settled   (6)
Accretion 21 18
Cash flow revisions (1) [3] 13 [4]
Ending balance 531 495
Electric Plant Electric Distribution    
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]    
Beginning balance 51 49
Amounts Incurred 0 [1] 0 [2]
Amounts Settled   0
Accretion 3 2
Cash flow revisions 0 [3] 0 [4]
Ending balance 54 51
Natural Gas Plant Gas Transmission and Distribution    
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]    
Beginning balance 179 172
Amounts Incurred 0 [1] 0 [2]
Amounts Settled   0
Accretion 9 8
Cash flow revisions (6) [3] (1) [4]
Ending balance 182 179
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 largely pertain to obligations associated with new solar facilities.
[2] Amounts incurred largely pertain to CCR coal ash regulations and new obligations associated with Sherco Solar Unit 1, which was placed in service in 2024.
[3] In 2025, AROs were revised for changes in timing and estimates of cash flows. Wind was revised due to the repowering of two wind facilities in NSP-Minnesota.
[4] In 2024, AROs were revised for changes in timing and estimates of cash flows. Changes were driven by updated assumptions in the NSP-Minnesota nuclear decommissioning triennial filing coupled with discount rate and escalation rate changes. Wind, steam, hydro and other production AROs were revised due to the results of the 2024 dismantling studies and changes in cost estimates to remediate ash containment facilities
[5] Reported in nuclear decommissioning fund and other investments on the consolidated balance sheets, which also includes $285 million of equity method investments and $164 million of rabbi trust assets and other miscellaneous investments.
[6] Reported in nuclear decommissioning fund and other investments on the consolidated balance sheets, which also includes $246 million of equity investments in unconsolidated subsidiaries and $156 million of rabbi trust assets and other miscellaneous investments.
v3.25.4
Indeterminate AROs (Details)
$ in Millions
Dec. 31, 2025
USD ($)
Guarantees and Product Warranties [Abstract]  
Indeterminate Costs Incurred, Asset Retirement Obligation Due to Asbestos $ 0
v3.25.4
Nuclear Insurance (Details) - NSP Minnesota - Nuclear Insurance
$ in Millions
 12 Months Ended
Dec. 31, 2025
USD ($)
Reactor
Nuclear Insurance [Abstract]  
Nuclear insurance coverage secured for the Company's public liability exposure $ 500
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
Maximum assessments for business interruption insurance each calendar year 21
Maximum assessment for property damage insurance NSP-Minnesota is subject to each calendar year 38
Maximum  
Nuclear Insurance [Abstract]  
Loss Contingency, Estimate of Possible Loss 16,300
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
v3.25.4
Regulatory Plant Decommissioning Recovery (Details) - USD ($)
$ in Millions
Dec. 31, 2025
Dec. 31, 2024
Estimate of Fair Value Measurement [Member] | Fair Value, Recurring [Member]    
Funded Status of Nuclear Decommissioning Obligation [Abstract]    
Decommissioning fund investments $ 3,940 [1] $ 3,494 [2]
NSP Minnesota    
Regulatory Plant Decommissioning Recovery [Abstract]    
Percentage Of Total Obligation For Decommissioning Expected To Be Funded By External Funds 100.00%  
NSP Minnesota | Estimate of Fair Value Measurement [Member] | Fair Value, Recurring [Member]    
Funded Status of Nuclear Decommissioning Obligation [Abstract]    
Decommissioning fund investments $ 3,900 $ 3,500
[1] Reported in nuclear decommissioning fund and other investments on the consolidated balance sheets, which also includes $285 million of equity method investments and $164 million of rabbi trust assets and other miscellaneous investments.
[2] Reported in nuclear decommissioning fund and other investments on the consolidated balance sheets, which also includes $246 million of equity investments in unconsolidated subsidiaries and $156 million of rabbi trust assets and other miscellaneous investments.
v3.25.4
Leases (Details) - USD ($)
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Lessee, Lease, Description [Line Items]      
Maximum Length - Short-Term Leases 12 months    
Operating Lease, Weighted Average Discount Rate, Percent 5.10%    
Operating Lease ROU Assets      
Gross operating lease ROU assets $ 1,549,000,000 $ 2,175,000,000  
Accumulated amortization (656,000,000) (1,115,000,000)  
Net operating lease ROU assets 893,000,000 1,060,000,000  
Finance Lease ROU Assets      
Gross finance lease ROU assets 1,435,000,000 181,000,000  
Accumulated amortization (87,000,000) (70,000,000)  
Net finance lease ROU assets 1,348,000,000 111,000,000  
Components of Lease Expense      
Operating Lease, Cost 235,000,000 271,000,000 $ 283,000,000
Finance Lease, Right-of-Use Asset, Amortization 16,000,000 3,000,000 3,000,000
Finance Lease, Interest Expense 42,000,000 15,000,000 15,000,000
Finance Lease, Cost 58,000,000 18,000,000 18,000,000
Operating Lease Commitments      
2026 152,000,000    
2027 130,000,000    
2028 120,000,000    
2029 115,000,000    
2030 111,000,000    
Thereafter 631,000,000    
Total minimum obligation 1,259,000,000    
Interest component of obligation (361,000,000)    
Present value of minimum obligation $ 898,000,000    
Finance Lease, Liability, Current, Statement of Financial Position [Extensible Enumeration] Other current liabilities    
Less current portion $ (110,000,000) (227,000,000)  
Noncurrent operating and finance lease liabilities 788,000,000 867,000,000  
Operating Lease, Weighted Average Remaining Lease Term 11.8    
Finance Lease, Liability, Payment, Due [Abstract]      
2026 [1] 112,000,000    
2027 [1] 111,000,000    
2028 [1] 114,000,000    
2029 [1] 115,000,000    
2030 [1] 117,000,000    
Thereafter [1] 1,614,000,000    
Total minimum obligation [1] 2,183,000,000    
Interest component of obligation [1] (882,000,000)    
Present value of minimum obligation [1] 1,301,000,000    
Finance Lease, Liability, Current [1] (39,000,000)    
Finance Lease, Liability, Noncurrent 1,262,000,000 [1] 60,000,000  
Finance Lease, Weighted Average Remaining Lease Term [1] $ 18.1    
WYCO, Inc. [Member]      
Operating Lease ROU Assets      
Equity Method Investment, Ownership Percentage 50.00%    
Purchased Power Agreements      
Operating Lease ROU Assets      
Gross operating lease ROU assets $ 1,087,000,000 1,802,000,000  
Components of Lease Expense      
Operating Lease, Cost 192,000,000 228,000,000 241,000,000
Operating Lease Commitments      
2026 [2],[3] 121,000,000    
2027 [2],[3] 90,000,000    
2028 [2],[3] 80,000,000    
2029 [2],[3] 78,000,000    
2030 [2],[3] 78,000,000    
Thereafter [2],[3] 185,000,000    
Total minimum obligation [2],[3] 632,000,000    
Interest component of obligation [2],[3] (91,000,000)    
Present value of minimum obligation [2],[3] 541,000,000    
Other Operating Lease [Domain]      
Operating Lease ROU Assets      
Gross operating lease ROU assets 462,000,000 373,000,000  
Components of Lease Expense      
Operating Lease, Cost [4] 43,000,000 43,000,000 $ 42,000,000
Operating Lease Commitments      
2026 31,000,000    
2027 40,000,000    
2028 40,000,000    
2029 37,000,000    
2030 33,000,000    
Thereafter 446,000,000    
Total minimum obligation 627,000,000    
Interest component of obligation (270,000,000)    
Present value of minimum obligation 357,000,000    
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  
Generation Facilities      
Finance Lease ROU Assets      
Gross finance lease ROU assets 1,254,000,000 $ 0  
Amended Purchased Power Agreements      
Finance Lease, Liability, Payment, Due [Abstract]      
Finance Lease, Liability, Current (37,000,000)    
Finance Lease, Liability, Noncurrent $ 1,200,000,000    
[1] Excludes certain amounts related to Xcel Energy’s 50% ownership interest in WYCO.
[2] Amounts do not include PPAs accounted for as executory contracts and/or contingent payments, such as energy payments on renewable PPAs.
[3] PPA operating leases contractually expire at various dates through 2033.
[4] Includes immaterial short-term lease expense.
v3.25.4
Non Lease PPAs (Details) - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Capacity      
Purchased Power Agreements (PPAs) [Abstract]      
Purchased power expense $ 49 $ 81 $ 77
Estimated Future Payments Under PPAs [Abstract]      
2026 34    
2027 31    
2028 25    
2029 25    
2030 20    
Thereafter 206    
Total 341    
Energy      
Purchased Power Agreements (PPAs) [Abstract]      
Purchased power expense 111 $ 212 $ 214
Estimated Future Payments Under PPAs [Abstract]      
2026 [1] 99    
2027 [1] 72    
2028 [1] 72    
2029 [1] 70    
2030 [1] 51    
Thereafter [1] 411    
Total [1] $ 775    
[1] Excludes contingent energy payments for renewable energy PPAs.
v3.25.4
Fuel Contracts (Details)
$ in Millions
Dec. 31, 2025
USD ($)
Coal  
Fuel Contracts [Abstract]  
2026 $ 300
2027 135
2028 11
2029 1
2030 1
Thereafter 0
Total 448
Nuclear Fuel  
Fuel Contracts [Abstract]  
2026 67
2027 148
2028 35
2029 129
2030 24
Thereafter 49
Total 452
Natural Gas Supply  
Fuel Contracts [Abstract]  
2026 365
2027 3
2028 1
2029 0
2030 0
Thereafter 0
Total 369
Natural Gas Storage and Transportation  
Fuel Contracts [Abstract]  
2026 399
2027 349
2028 215
2029 127
2030 72
Thereafter 717
Total $ 1,879
v3.25.4
VIEs - PPAs (Details) - MW
Dec. 31, 2025
Dec. 31, 2024
Equity Method Investment, Nonconsolidated Investee or Group of Investees [Member]    
Purchased Power Agreements [Abstract]    
Generating capacity (in MW) 3,476 3,751
v3.25.4
Low-Income Housing Limited Partnerships (Details) - USD ($)
$ in Millions
Dec. 31, 2025
Dec. 31, 2024
Variable Interest Entity [Line Items]    
Total assets $ 81,371 $ 70,035
Variable Interest Entity, Primary Beneficiary    
Variable Interest Entity [Line Items]    
Total assets 39 40
Variable Interest Entity, Consolidated, Carrying Amount, Liabilities $ 34 $ 34
v3.25.4
Guarantees and Bond Indemnifications (Details) - USD ($)
Dec. 31, 2025
Dec. 31, 2024
Commitments and Contingencies Disclosure [Abstract]    
Assets Held As Collateral For Guarantor Obligations $ 0 $ 0
Guarantor Obligations, Maximum Exposure, Undiscounted $ 120,000,000 $ 93,000,000
v3.25.4
Commitments and Contingencies - Smokehouse Creek Fire Complex (Details)
$ in Millions
Dec. 31, 2025
USD ($)
Claims
complaint
Dec. 31, 2024
USD ($)
Guarantees and Product Warranties [Abstract]    
Number of complaints related to the Smokehouse Creek Complex | complaint 56  
Number of claims related to the Smokehouse Creek Complex | Claims 296  
Number of claims settled related to the Smokehouse Creek Complex | Claims 223  
Smokehouse probable loss | $ $ 430  
Smokehouse settlements reached | $ 382  
Smokehouse settlements paid | $ 374 $ 35
Smokehouse remaining liability | $ 56 180
Amount of insurance coverage | $ 500  
Smokehouse Creek Insurance Receivable | $ $ 195 $ 210
Loss Contingencies [Line Items]    
Number of complaints related to the Smokehouse Creek Complex | complaint 56  
Number of claims related to the Smokehouse Creek Complex | Claims 296  
Number of claims settled related to the Smokehouse Creek Complex | Claims 223  
Number of claims resolved related to the Smokehouse Creek Complex 22  
Number of unsubmitted claims settled related to the Smokehouse Creek Fire Complex | Claims 79  
Unsubmitted Claims related to the Smokehouse Creek Fire Complex | Claims 101  
v3.25.4
Commitments and Contingencies - PI Prudency Review (Details) - USD ($)
$ in Millions
Dec. 31, 2025
May 25, 2025
Postemployment Benefits [Abstract]    
Customer Refunds, Maximum Amount Approved $ 40 $ 6
v3.25.4
Other Comprehensive Income (Details) - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
AOCI Attributable to Parent, Net of Tax [Roll Forward]      
Accumulated other comprehensive income (loss) at beginning of period $ 19,522    
Total income tax benefit (245) $ (402) $ (146)
Accumulated other comprehensive income (loss) at end of period 23,609 19,522  
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 (29) (53)  
Other comprehensive loss before reclassifications, net of tax 2 22  
Amortization of net actuarial loss 0 0  
Net current period other comprehensive income (loss) 4 24  
Accumulated other comprehensive income (loss) at end of period (25) (29) (53)
Gains and Losses on Cash Flow Hedges | Interest Rate Swap      
AOCI Attributable to Parent, Net of Tax [Roll Forward]      
Amortization of net actuarial loss 2 [1] (2) [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) (41)  
Other comprehensive loss before reclassifications, net of tax (1) (3)  
Amortization of net actuarial loss 2 [3] (5) [4]  
Net current period other comprehensive income (loss) 1 2  
Accumulated other comprehensive income (loss) at end of period (38) (39) (41)
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 (68) (94)  
Other comprehensive loss before reclassifications, net of tax 1 19  
Amortization of net actuarial loss 2 (5)  
Net current period other comprehensive income (loss) 5 26  
Accumulated other comprehensive income (loss) at end of period (63) (68) $ (94)
Total | Interest Rate Swap      
AOCI Attributable to Parent, Net of Tax [Roll Forward]      
Amortization of net actuarial loss $ 2 $ (2)  
[1] Included in interest charges.
[2] Included in interest charges.
[3] Included in the computation of net periodic pension and postretirement benefit costs. See Note 11 for further information.
[4] Included in the computation of net periodic pension and postretirement benefit costs. See Note 11 for further information.
v3.25.4
Segments and Related Information (Details) - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Segment Reporting Information [Line Items]      
Investment in subsidiaries $ 285 $ 246  
Natural Gas 2,452 2,230 $ 2,645
Other 57 64 115
Revenues Including Intersegment Revenues 14,639 13,401 14,096
Regulated and Unregulated Operating Revenue 14,669 13,441 14,206
Depreciation and amortization 2,953 2,744 2,448
Interest charges and financing costs 1,343 1,182 1,004
Total income tax benefit (245) (402) (146)
Net income (loss) 2,018 1,936 1,771
Electric fuel and purchased power 3,961 3,788 4,278
Cost of natural gas sold and transported 1,041 951 1,456
Operating and maintenance expenses 2,732 2,540 2,444
Other income, net 235 143 22
Electric $ 12,160 11,147 11,446
Number Of Reportable Segments, Not Disclosed, Flag reportable segments    
Regulated Electric      
Segment Reporting Information [Line Items]      
Revenues Including Intersegment Revenues $ 12,161 11,149 11,448
Regulated Natural Gas      
Segment Reporting Information [Line Items]      
Investment in subsidiaries 81 85  
Revenues Including Intersegment Revenues 2,478 2,252 2,648
All Other      
Segment Reporting Information [Line Items]      
Investment in subsidiaries 204 161  
Net income (loss) (108) (147) (134)
Operating Segments [Member]      
Segment Reporting Information [Line Items]      
Depreciation and amortization 2,938 2,730 2,434
Interest charges and financing costs 1,011 880 766
Total income tax benefit (198) (358) (85)
Net income (loss) 2,126 2,083 1,905
Regulated Operating Revenue (14,612) (13,377) (14,091)
Electric fuel and purchased power 3,961 3,788 4,278
Cost of natural gas sold and transported 1,041 951 1,456
Operating and maintenance expenses 2,684 2,511 2,397
Other income, net 1,076 [1] 816 945 [2]
Operating Segments [Member] | Regulated Electric      
Segment Reporting Information [Line Items]      
Depreciation and amortization 2,525 2,373 2,111
Interest charges and financing costs 886 767 670
Total income tax benefit (265) (420) (135)
Net income (loss) 1,870 1,846 1,686
Electric fuel and purchased power 3,961 3,788 4,278
Cost of natural gas sold and transported 0 0 0
Operating and maintenance expenses 2,259 2,102 2,011
Other income, net 925 [1] 693 827 [2]
Electric 12,160 11,147 11,446
Operating Segments [Member] | Regulated Natural Gas      
Segment Reporting Information [Line Items]      
Natural Gas 2,452 2,230 2,645
Depreciation and amortization 413 357 323
Interest charges and financing costs 125 113 96
Total income tax benefit 67 62 50
Net income (loss) 256 237 219
Electric fuel and purchased power 0 0 0
Cost of natural gas sold and transported 1,041 951 1,456
Operating and maintenance expenses 425 409 386
Other income, net 151 [1] 123 118 [2]
Operating Segments [Member] | All Other      
Segment Reporting Information [Line Items]      
Other 57 64 115
Intersegment Eliminations      
Segment Reporting Information [Line Items]      
Regulated Operating Revenue (27) (24) (5)
Intersegment Eliminations | Regulated Electric      
Segment Reporting Information [Line Items]      
Electric 1 2 2
Intersegment Eliminations | Regulated Natural Gas      
Segment Reporting Information [Line Items]      
Natural Gas $ 26 $ 22 $ 3
[1] Other segment expenses, net, for 2025 additionally includes Marshall Wildfire litigation expense.
[2] Other segment expenses, net, for 2023 additionally includes loss on Comanche Unit 3 litigation with CORE Electric Cooperative related to lost power damages and other costs and workforce reduction expenses.
v3.25.4
Workforce Reduction (Details)
$ 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
v3.25.4
Condensed Statements of Income and Comprehensive Income (Details) - USD ($)
$ / shares in Units, shares in Millions, $ in Millions
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Income      
Income (Loss) from Equity Method Investments $ 17 $ 19 $ 35
Expenses and other deductions      
Other income (235) (143) (22)
Interest charges and financing costs 1,468 1,255 1,055
Income before income taxes 1,773 1,534 1,625
Income tax benefit (245) (402) (146)
Net income 2,018 1,936 1,771
Other Comprehensive Income (Loss), Net of Tax [Abstract]      
Total comprehensive income $ 2,023 $ 1,962 $ 1,770
Weighted average common shares outstanding:      
Basic 587 563 552
Diluted [1] 589 563 552
Earnings per average common share:      
Basic $ 3.44 $ 3.44 $ 3.21
Diluted $ 3.42 $ 3.44 $ 3.21
Xcel Energy Inc.      
Income      
Income (Loss) from Equity Method Investments $ 2,173 $ 2,122 $ 1,948
Total income 2,173 2,122 1,948
Expenses and other deductions      
Operating expenses 38 24 25
Other income (179) (76) (13)
Interest charges and financing costs 366 300 235
Total expenses and other deductions 225 248 247
Income before income taxes 1,948 1,874 1,701
Income tax benefit (70) (62) (70)
Net income 2,018 1,936 1,771
Other Comprehensive Income (Loss), Net of Tax [Abstract]      
Net pension and retiree medical losses arising during the period, net of tax 1 2 (2)
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, before Tax 4 24 1
Other Comprehensive Income (Loss), Net of Tax 5 26 (1)
Total comprehensive income $ 2,023 $ 1,962 $ 1,770
[1] Diluted common shares outstanding included common stock equivalents of 2.1 million, 0.5 million, and 0.3 million shares for 2025, 2024 and 2023, respectively.
v3.25.4
Condensed Statement of Cash Flows (Details) - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Operating activities      
Other, net $ (160) $ (150) $ (157)
Net cash provided by (used in) operating activities 4,083 4,641 5,327
Investing activities      
Debt Securities, Held-to-Maturity, Purchase (607) (105) 0
Net (investments) return in the utility money pool (171) 21 21
Net cash provided by (used in) investing activities (10,969) (7,428) (5,926)
Financing activities      
Proceeds from (repayment of) short-term borrowings, net 855 (90) (28)
Proceeds from Issuance of Long-term Debt 5,763 3,647 2,630
Repayment of long-term debt (1,713) (656) (1,151)
Proceeds from Issuance of Common Stock 3,349 1,117 270
Payments of Dividends (1,282) (1,175) (1,092)
Proceeds from (Payment for) Other Financing Activity 9 (6) (12)
Net cash provided by (used in) financing activities 6,981 2,837 617
Net change in cash and cash equivalents 95 50 18
Cash and Cash Equivalents, at Carrying Value, Beginning Balance 179 129 111
Cash and Cash Equivalents, at Carrying Value, Ending Balance 274 179 129
Xcel Energy Inc.      
Operating activities      
Net cash provided by (used in) operating activities 878 1,459 1,586
Investing activities      
Capital contributions to subsidiaries (4,067) (2,184) (975)
Net cash provided by (used in) investing activities (4,845) (2,268) (954)
Financing activities      
Proceeds from (repayment of) short-term borrowings, net 615 70 (66)
Proceeds from Issuance of Long-term Debt 1,970 795 792
Repayment of long-term debt (600) 0 (500)
Proceeds from Issuance of Common Stock 3,349 1,117 270
Payments of Dividends (1,282) (1,175) (1,092)
Proceeds from (Payment for) Other Financing Activity (6) (6) (13)
Net cash provided by (used in) financing activities 4,046 801 (609)
Net change in cash and cash equivalents 79 (8) 23
Cash and Cash Equivalents, at Carrying Value, Beginning Balance 16 24 1
Cash and Cash Equivalents, at Carrying Value, Ending Balance $ 95 $ 16 $ 24
v3.25.4
Condensed Balance Sheet (Details) - USD ($)
$ in Millions
Dec. 31, 2025
Dec. 31, 2024
Assets    
Accounts receivable, net $ 1,330 $ 1,249
Derivative instruments 165 114
Total current assets 5,014 4,325
Investment in subsidiaries 285 246
Other assets 1,036 524
Total other assets 10,718 8,512
Total assets 81,371 70,035
Liabilities and Equity    
Dividends payable 355 314
Short-term debt 1,550 695
Other current liabilities 605 635
Total current liabilities 7,089 6,459
Other liabilities 61 69
Capitalization    
Total common stockholders’ equity 23,609 19,522
Total liabilities and equity 81,371 70,035
NSP Minnesota    
Liabilities and Equity    
Long-term Debt, Current Maturities 0 250
Xcel Energy Inc.    
Assets    
Accounts receivable, net 678 410
Xcel Energy [Member] | Mortgage bonds | NSP Minnesota    
Assets    
Face Amount 953 166
Xcel Energy Inc.    
Assets    
Cash and cash equivalents 95 16
Other current assets 14 9
Total current assets 787 435
Investment in subsidiaries 31,496 26,519
Other assets 6 6
Total other assets 32,455 26,691
Total assets 33,242 27,126
Liabilities and Equity    
Long-term Debt, Current Maturities 500 600
Dividends payable 355 314
Short-term debt 850 235
Other current liabilities 78 90
Total current liabilities 1,783 1,239
Other liabilities 18 28
Total deferred credits and other liabilities 18 28
Capitalization    
Long-term debt, noncurrent 7,832 6,337
Total common stockholders’ equity 23,609 19,522
Total capitalization 31,441 25,859
Total liabilities and equity $ 33,242 $ 27,126
v3.25.4
Condensed Notes to the Financial Statements (Details) - USD ($)
 3 Months Ended 12 Months Ended
Dec. 31, 2025
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Money Pool [Abstract]        
Guarantor Obligations, Maximum Exposure, Undiscounted $ 120,000,000 $ 120,000,000 $ 93,000,000  
Schedule of Guarantor Obligations  
Guarantees and bond indemnities issued and outstanding as of Dec. 31, 2025:
(Millions of Dollars)GuarantorGuarantee
Amount		Current
Exposure		Triggering
Event
Guarantees of Capital Services equipment purchase contractsXcel Energy Inc. 1,173 
(a)
(b)
Guarantees of Xcel Energy Services Inc. performance and payments on operating lease agreementsXcel Energy Inc.43 43 
(b)
Guarantee performance and payment of surety bonds for Xcel Energy Inc.’s utility subsidiaries (c)
Xcel Energy Inc.120 
(d)
(e)
(a)Relative to the guaranteed performance obligations of Capital Services, vendors have completed approximately 60% of the manufacturing required to deliver completed equipment.
(b)Nonperformance and/or nonpayment.
(c)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.
(d)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.
(e)Per the indemnity agreement between Xcel Energy Inc. and the various surety companies, surety companies have the discretion to demand that collateral be posted.
    
Assets Held As Collateral For Guarantor Obligations 0 $ 0 0  
NSP Minnesota        
Money Pool [Abstract]        
Debt Instrument, Repurchased Face Amount 787,000,000 787,000,000 166,000,000  
Debt Instrument, Repurchased Face Amount 787,000,000 787,000,000 166,000,000  
Debt Instrument, Repurchase Amount $ 607,000,000 $ 607,000,000 105,000,000  
NSP Minnesota | Series Due June 1, 2051        
Money Pool [Abstract]        
Debt Instrument, Interest Rate, Stated Percentage 2.60% 2.60%    
Debt Instrument, Interest Rate, Stated Percentage 2.60% 2.60%    
NSP Minnesota | Series Due May 15, 2044 [Member]        
Money Pool [Abstract]        
Debt Instrument, Interest Rate, Stated Percentage 4.125% 4.125%    
Debt Instrument, Interest Rate, Stated Percentage 4.125% 4.125%    
NSP Minnesota | Series Due Aug. 15, 2045 [Member]        
Money Pool [Abstract]        
Debt Instrument, Interest Rate, Stated Percentage 4.00% 4.00%    
Debt Instrument, Interest Rate, Stated Percentage 4.00% 4.00%    
NSP Minnesota | Series Due May 15, 2046 [Member]        
Money Pool [Abstract]        
Debt Instrument, Interest Rate, Stated Percentage 3.60% 3.60%    
Debt Instrument, Interest Rate, Stated Percentage 3.60% 3.60%    
NSP Minnesota | Series Due March 1, 2050        
Money Pool [Abstract]        
Debt Instrument, Interest Rate, Stated Percentage 2.90% 2.90%    
Debt Instrument, Interest Rate, Stated Percentage 2.90% 2.90%    
NSP Minnesota | Series Due April 1, 2052        
Money Pool [Abstract]        
Debt Instrument, Interest Rate, Stated Percentage 3.20% 3.20%    
Debt Instrument, Interest Rate, Stated Percentage 3.20% 3.20%    
Payment or Performance Guarantee | Guarantee of Capital Services purchase contract for solar generating equipment        
Money Pool [Abstract]        
Guarantor Obligations, Maximum Exposure, Undiscounted [1],[2] $ 1,173,000,000 $ 1,173,000,000    
Payment or Performance Guarantee | Guarantees of Xcel Energy Inc.'s utility subsidiaries' performance on tax credit sale agreements        
Money Pool [Abstract]        
Operating Lease, Residual Value of Leased Asset [1] 43,000,000 43,000,000    
Payment or Performance Guarantee | Surety Bonds        
Money Pool [Abstract]        
Guarantor Obligations, Maximum Exposure, Undiscounted [3],[4],[5] 120,000,000 120,000,000    
Xcel Energy Inc.        
Dividends [Abstract]        
Cash dividends paid to Xcel Energy by subsidiaries   1,258,000,000 1,685,000,000 $ 1,693,000,000
Money Pool [Abstract]        
Loan outstanding at period end 171,000,000 171,000,000 0 21,000,000
Average loan outstanding 27,000,000 14,000,000 18,000,000 27,000,000
Maximum loan outstanding $ 253,000,000 $ 253,000,000 $ 209,000,000 $ 250,000,000
Weighted average interest rate, computed on a daily basis (percentage) 3.89% 4.11% 5.34% 5.33%
Line of Credit Facility, Interest Rate at Period End 3.88% 3.88%    
Interest Income, Other $ 0 $ 1,000,000 $ 1,000,000 $ 1,000,000
Weighted average interest rate at period end (percentage) 3.88% 3.88% 5.34%  
Other Receivable, after Allowance for Credit Loss, Current, Related and Nonrelated Party Status [Extensible Enumeration] $ 678,000,000 $ 678,000,000 $ 410,000,000  
Xcel Energy Inc. | NSP Minnesota        
Money Pool [Abstract]        
Other Receivable, after Allowance for Credit Loss, Current, Related and Nonrelated Party Status [Extensible Enumeration] 113,000,000 113,000,000 79,000,000  
Xcel Energy Inc. | NSP-Wisconsin        
Money Pool [Abstract]        
Other Receivable, after Allowance for Credit Loss, Current, Related and Nonrelated Party Status [Extensible Enumeration] 4,000,000 4,000,000 11,000,000  
Xcel Energy Inc. | PSCo        
Money Pool [Abstract]        
Other Receivable, after Allowance for Credit Loss, Current, Related and Nonrelated Party Status [Extensible Enumeration] 83,000,000 83,000,000 77,000,000  
Xcel Energy Inc. | SPS        
Money Pool [Abstract]        
Other Receivable, after Allowance for Credit Loss, Current, Related and Nonrelated Party Status [Extensible Enumeration] 29,000,000 29,000,000 41,000,000  
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] 434,000,000 434,000,000 163,000,000  
Xcel Energy Inc. | Other Subsidiaries        
Money Pool [Abstract]        
Other Receivable, after Allowance for Credit Loss, Current, Related and Nonrelated Party Status [Extensible Enumeration] $ 15,000,000 $ 15,000,000 $ 39,000,000  
[1] Nonperformance and/or nonpayment.
[2] Relative to the guaranteed performance obligations of Capital Services, vendors have completed approximately 60% of the manufacturing required to deliver completed equipment.
[3] 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.
[4] Per the indemnity agreement between Xcel Energy Inc. and the various surety companies, surety companies have the discretion to demand that collateral be posted.
[5] 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.
v3.25.4
Schedule II (Details) - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Allowance for Bad Debts      
SEC Schedule, 12-09, Movement in Valuation Allowances and Reserves [Roll Forward]      
Balance at Jan. 1 $ 111 $ 128 $ 122
Charged to costs and expenses 64 64 79
Charged to other accounts [1] 15 16 13
Deductions from reserves [2] (101) (97) (86)
Balance at Dec. 31 89 111 128
NOL and Tax Credit Valuation Allowances      
SEC Schedule, 12-09, Movement in Valuation Allowances and Reserves [Roll Forward]      
Balance at Jan. 1 73 70 62
Charged to costs and expenses 37 45 26
Charged to other accounts 0 0 0
Deductions from reserves [3] (36) (42) (18)
Balance at Dec. 31 $ 74 $ 73 $ 70
[1] Recovery of amounts previously written-off.
[2] Deductions related primarily to bad debt write-offs.
[3] Primarily reversals of valuation allowances on completed tax credit sales and reductions of valuation allowances for items forecasted to be used prior to expiration