10-K – 2026-02-25 – xel-20251231.htm

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.

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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.
N 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.

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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, 2025 Dec. 31, 2024
Inventories
Materials and supplies $ 489   $ 406  
Fuel 156   164  
Natural gas 116   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.

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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.

2. 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.

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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.

3. Property, Plant and Equipment

Major classes of property, plant and equipment

(Millions of Dollars) Dec. 31, 2025 Dec. 31, 2024
Property, plant and equipment, net
Electric plant $ 61,892   $ 56,791  
Natural gas plant 10,517   9,834  
Common and other property 3,790   3,515  
Plant to be retired (a)
1,595   1,793  
CWIP 8,085   4,720  
Total property, plant and equipment 85,879   76,653  
Less accumulated depreciation ( 20,710 ) ( 19,852 )
Nuclear fuel 3,678   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 Service Accumulated Depreciation Percent Owned
NSP-Minnesota
Electric generation:
Sherco Unit 3 $ 638   $ 515   59   %
Sherco common facilities 189   134   80  
Sherco substation 5   4   59  
Electric transmission:
Grand Meadow 11   4   50  
Huntley Wilmarth 49   4   50  
CapX2020 887   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 Service Accumulated Depreciation Percent Owned
NSP-Wisconsin
Electric transmission:
La Crosse, WI to Madison, WI $ 179   $ 33   37   %
CapX2020 169   46   80  
Total NSP-Wisconsin (a)
$ 348   $ 79  

(a) Projects additionally include $ 3  million in CWIP.

(Millions of Dollars, Except Percent Owned) Plant in Service Accumulated Depreciation Percent Owned
PSCo
Electric generation:
Hayden Unit 1 $ 159   $ 126   76   %
Hayden Unit 2 152   99   37  
Hayden common facilities 45   36   53  
Craig Units 1 and 2 82   60   10  
Craig common facilities 40   28   7  
Comanche Unit 3 971   233   67  
Comanche common facilities 29   6   77  
Electric transmission:
Transmission and other facilities 193   76   Various
Gas transmission:
Rifle, CO to Avon, CO 31   10   60  
Gas transmission compressor 8   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.

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4. Regulatory Assets and Liabilities

Regulatory assets and liabilities are created for amounts that regulators may allow to be collected or may require to be paid back to customers in future electric and natural gas rates. Xcel Energy would be required to recognize the write-off of regulatory assets and liabilities in net income or other comprehensive income if changes in the utility industry no longer allow for the application of regulatory accounting guidance under GAAP.
Components of regulatory assets:

(Millions of Dollars) See Note(s) Remaining Amortization Period Dec. 31, 2025 Dec. 31, 2024 (a)

Regulatory Assets Current Noncurrent Current Noncurrent
Pension and retiree medical obligations 11 Various $ 39   $ 1,121   $ 39   $ 1,167  
Recoverable deferred taxes on AFUDC Plant lives —   434   —   368  
Net AROs 1, 12 Various —   422   —   387  
Depreciation differences Various 22   320   17   250  
Excess deferred taxes — TCJA
7 Various 11   162   10   184  
Grid modernization costs Various 2   67   3   30  
Excess liability insurance costs Various 5   64   —   6  
Environmental remediation costs 1, 12 Various 9   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 costs 1 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 revenue Various 75   2   123   68  

Gas pipeline inspection and remediation costs Less than one year
31   —   47   9  
Other
Various 117   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 Period Dec. 31, 2025 Dec. 31, 2024
Regulatory Liabilities Current Noncurrent Current Noncurrent
Deferred income tax adjustments and TCJA refunds (a)
7 Various $ 7   $ 2,758   $ 7   $ 2,888  
Plant removal costs 1, 12 Various —   2,336   —   2,208  
Net AROs (b)
Various —   354   —   161  
Renewable resources and environmental initiatives Various 16   319   16   232  
Effects of regulation on employee benefit costs (c)
11 Various —   261   —   259  
ITC deferrals
1 Various —   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 Various 193   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.
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5. 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, 2025 Year Ended Dec. 31
2025 2024 2023
Borrowing limit $ 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 4.14   % 4.41   % 5.47   % 5.12   %
Weighted average interest rate at period end 3.95   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)

2025 2024
Xcel Energy Inc. (d)
59.80   % 59.80   % $ 450   2  
NSP-Minnesota 50.00   47.00   170   2  
NSP-Wisconsin 47.00   47.10   N/A 1  
SPS 47.20   46.60   60   2  
PSCo 44.90   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  
PSCo 1,200   308   892  
NSP-Minnesota 800   264   536  
SPS 600   220   380  
NSP-Wisconsin 150   —   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.

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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 Instrument Interest Rate Maturity Date 2025 2024
Unsecured senior notes 3.30   % June 1, 2025 $ —   $ 250  
Unsecured senior notes 3.30   June 1, 2025 —   350  
Unsecured senior notes 3.35   Dec. 1, 2026 500   500  
Unsecured senior notes 1.75   March 15, 2027 500   500  
Unsecured senior notes 4.00   June 15, 2028 130   130  
Unsecured senior notes (a)
4.75   March 21, 2028 350   —  
Unsecured senior notes 4.00   June 15, 2028 500   500  
Unsecured senior notes 2.60   Dec. 1, 2029 500   500  
Unsecured senior notes 3.40   June 1, 2030 600   600  
Unsecured senior notes 2.35   Nov. 15, 2031 300   300  
Unsecured senior notes 4.60   June 1, 2032 700   700  
Unsecured senior notes 5.45   Aug. 15, 2033 800   800  
Unsecured senior notes (b)
5.50   March 15, 2034 800   800  
Unsecured senior notes (a)
5.60   April 15, 2035 750   —  
Unsecured senior notes 6.50   July 1, 2036 300   300  
Unsecured senior notes 4.80   Sept. 15, 2041 250   250  
Unsecured senior notes 3.50   Dec. 1, 2049 500   500  
Junior subordinated notes (a) (c)
6.25   Oct. 15, 2085 900   —  
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 Instrument Interest Rate Maturity Date 2025 2024
First mortgage bonds 7.125   % July 1, 2025 $ —   $ 250  
First mortgage bonds 6.50   March 1, 2028 150   150  
First mortgage bonds 2.25   April 1, 2031 425   425  
First mortgage bonds (a)
5.05   May 15, 2035 600   —  
First mortgage bonds 5.25   July 15, 2035 250   250  
First mortgage bonds 6.25   June 1, 2036 400   400  
First mortgage bonds 6.20   July 1, 2037 350   350  
First mortgage bonds 5.35   Nov. 1, 2039 300   300  
First mortgage bonds 4.85   Aug. 15, 2040 250   250  
First mortgage bonds 3.40   Aug. 15, 2042 500   500  
First mortgage bonds 4.125   May 15, 2044 300   300  
First mortgage bonds 4.00   Aug. 15, 2045 300   300  
First mortgage bonds 3.60   May 15, 2046 350   350  
First mortgage bonds 3.60   Sept. 15, 2047 600   600  
First mortgage bonds 2.90   March 1, 2050 600   600  
First mortgage bonds 2.60   June 1, 2051 700   700  
First mortgage bonds 3.20   April 1, 2052 425   425  
First mortgage bonds 4.50   June 1, 2052 500   500  
First mortgage bonds 5.10   May 15, 2053 800   800  
First mortgage bonds (b)
5.40   March 15, 2054 700   700  
First mortgage bonds (a)
5.65   May 15, 2055 500   —  
Other long-term debt 1   2  
Long-term debt — related parties principal amount outstanding 2.60 - 4.125 2044 - 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 Instrument Interest Rate Maturity Date 2025 2024
First mortgage bonds 6.375   % Sept. 1, 2038 $ 200   $ 200  
First mortgage bonds 3.70   Oct. 1, 2042 100   100  
First mortgage bonds 3.75   Dec. 1, 2047 100   100  
First mortgage bonds 4.20   Sept. 1, 2048 200   200  
First mortgage bonds 3.05   May 1, 2051 100   100  
First mortgage bonds 2.82   May 1, 2051 100   100  
First mortgage bonds 4.86   Sept. 15, 2052 100   100  
First mortgage bonds 5.30   June 15, 2053 125   125  
First mortgage bonds (a)
5.65   June 15, 2054 400   400  
First mortgage bonds (b)
5.65   June 15, 2054 250   —  

Unamortized discount ( 10 ) ( 4 )
Unamortized debt issuance cost ( 18 ) ( 15 )

Total long-term debt $ 1,647   $ 1,406  

(a) 2024 financing.
(b) 2025 financing.

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PSCo
Financing Instrument Interest Rate Maturity Date 2025 2024
First mortgage bonds 2.90   % May 15, 2025 $ —   $ 250  
First mortgage bonds 3.70   June 15, 2028 350   350  
First mortgage bonds 1.90   Jan. 15, 2031 375   375  
First mortgage bonds 1.875   June 15, 2031 750   750  
First mortgage bonds 4.10   June 1, 2032 300   300  
First mortgage bonds (a)
5.35   May 15, 2034 400   —  
First mortgage bonds (b)
5.35   May 15, 2034 450   450  
First mortgage bonds (a)
5.15   Sep 15, 2035 800   —  
First mortgage bonds 6.25   Sept. 1, 2037 350   350  
First mortgage bonds 6.50   Aug. 1, 2038 300   300  
First mortgage bonds 4.75   Aug. 15, 2041 250   250  
First mortgage bonds 3.60   Sept. 15, 2042 500   500  
First mortgage bonds 3.95   March 15, 2043 250   250  
First mortgage bonds 4.30   March 15, 2044 300   300  
First mortgage bonds 3.55   June 15, 2046 250   250  
First mortgage bonds 3.80   June 15, 2047 400   400  
First mortgage bonds 4.10   June 15, 2048 350   350  
First mortgage bonds 4.05   Sept. 15, 2049 400   400  
First mortgage bonds 3.20   March 1, 2050 550   550  
First mortgage bonds 2.70   Jan. 15, 2051 375   375  
First mortgage bonds 4.50   June 1, 2052 400   400  
First mortgage bonds 5.25   April 1, 2053 850   850  
First mortgage bonds (b)
5.75   May 15, 2054 750   750  
First mortgage bonds (a)
5.85   May 15, 2055 800   —  
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 Instrument Interest Rate Maturity Date 2025 2024
Unsecured senior notes 6.00   % Oct. 1, 2033 $ 100   $ 100  
First mortgage bonds (a)
5.30   May 15, 2035 500   —  
Unsecured senior notes 6.00   Oct. 1, 2036 250   250  
First mortgage bonds 4.50   Aug. 15, 2041 200   200  
First mortgage bonds 4.50   Aug. 15, 2041 100   100  
First mortgage bonds 4.50   Aug. 15, 2041 100   100  
First mortgage bonds 3.40   Aug. 15, 2046 300   300  
First mortgage bonds 3.70   Aug. 15, 2047 450   450  
First mortgage bonds 4.40   Nov. 15, 2048 300   300  
First mortgage bonds 3.75   June 15, 2049 300   300  
First mortgage bonds 3.15   May 1, 2050 350   350  
First mortgage bonds 3.15   May 1, 2050 250   250  
First mortgage bonds 5.15   June 1, 2052 200   200  
First mortgage bonds 6.00   Sept. 15, 2053 100   100  
First mortgage bonds (b)
6.00   June 1, 2054 600   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 Instrument Interest Rate Maturity Date 2025 2024
Various Eloigne affordable housing project notes 0.00% - 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  
2027 501  
2028 1,483  
2029 503  
2030 600  

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.

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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 Entered Common Shares (in millions) Forward Sale Price per Share Cash Proceeds at Settlement
Forward sale agreements settled in December 2025:
2024 forward equity agreements 21.1   $64.70 - 64.76 $ 1,364  

2025 forward equity agreements 8.9   71.91 - 80.97 684
30.0   $ 2,048  

The following forward sale agreements remain outstanding as of Dec. 31, 2025:

Agreements Entered Common 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)
15.1 Dec. 2026 1,084   (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 Entered Net Settlement: Physical Share Delivery Proceeds (millions of dollars)
Common Shares (in millions) Net Cash (millions of dollars)

2025 forward equity agreements 0.1 $ 7   $ 934  

Capital Stock — Preferred stock authorized/outstanding:

Preferred Stock Authorized (Shares) Par Value of Preferred Stock Preferred Stock Outstanding (Shares) 2025 and 2024
Xcel Energy Inc. 7,000,000   $ 100   —  
PSCo 10,000,000   0.01   —  
SPS 10,000,000   1.00   —  

Xcel Energy Inc. had the following common stock authorized/outstanding:

Common Stock Authorized (Shares) Par Value of Common Stock Common Stock Outstanding (Shares) as of Dec. 31, 2025 Common 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
Low High 2025
NSP-Minnesota 47.25   % 57.75   % 53.16   %
NSP-Wisconsin (a)
52.50   N/A 52.66  
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 Earnings Total Capitalization Limit on Total Capitalization
NSP-Minnesota $ 2,185   $ 19,547   $ 22,607  
NSP-Wisconsin 12   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.

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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 Debt Short-Term Debt
NSP-Minnesota (a)
52.8% of total capitalization $ 3,391  
NSP-Wisconsin $ 500   150  
PSCo 3,500   1,200  
SPS 100  

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.

6. 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) Electric Natural Gas All Other Total
Major revenue types
Revenue from contracts with customers:
Residential $ 3,904   $ 1,411   $ 3   $ 5,318  
C&I 5,948   742   30   6,720  
Other 149   —   10   159  
Total retail 10,001   2,153   43   12,197  
Wholesale 715   —   —   715  
Transmission 705   —   —   705  
Other 69   174   —   243  
Total revenue from contracts with customers 11,490   2,327   43   13,860  
Alternative revenue and other 670   125   14   809  
Total revenues $ 12,160   $ 2,452   $ 57   $ 14,669  

Year Ended Dec. 31, 2024
(Millions of Dollars) Electric Natural Gas All Other Total
Major revenue types
Revenue from contracts with customers:
Residential $ 3,552   $ 1,299   $ 11   $ 4,862  
C&I 5,420   646   30   6,096  
Other 142   —   9   151  
Total retail 9,114   1,945   50   11,109  
Wholesale 645   —   —   645  
Transmission 648   —   —   648  
Other 64   175   —   239  
Total revenue from contracts with customers 10,471   2,120   50   12,641  
Alternative revenue and other 676   110   14   800  
Total revenues $ 11,147   $ 2,230   $ 64   $ 13,441  

Year Ended Dec. 31, 2023
(Millions of Dollars) Electric Natural Gas All Other Total
Major revenue types
Revenue from contracts with customers:
Residential $ 3,560   $ 1,560   $ 59   $ 5,179  
C&I 5,703   833   30   6,566  
Other 150   —   13   163  
Total retail 9,413   2,393   102   11,908  
Wholesale 815   —   —   815  
Transmission 649   —   —   649  
Other 63   156   —   219  
Total revenue from contracts with customers 10,940   2,549   102   13,591  
Alternative revenue and other 506   96   13   615  
Total revenues $ 11,446   $ 2,645   $ 115   $ 14,206  

7. 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) 2025 2024 2023
Income before income taxes (domestic) $ 1,773   $ 1,534   $ 1,625  

Federal statutory rate impact 372   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 )
Other 29   14   17  

State income taxes, net of federal tax effect (c)
78   58   73  
Other 4   4   ( 3 )
Income tax benefit $ ( 245 ) $ ( 402 ) $ ( 146 )

2025 2024 2023
Federal statutory rate 21.0   % 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 )
Other 1.6   0.9   1.0  

State income taxes, net of federal tax effect (c)
4.4   3.8   4.5  
Other 0.4   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

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Components of income tax expense for years ended Dec. 31:

(Millions of Dollars) 2025 2024 2023
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 ) —   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) 2025 2024 2023
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 assets 500   559  
Operating lease assets 232   282  
Pension expense 171   155  
Other 98   93  
Total deferred tax liabilities $ 8,588   $ 8,097  

Deferred tax assets:
Tax credit carryforward $ 1,546   $ 1,589  
Regulatory liabilities 663   744  
Operating lease liabilities 231   282  
Other employee benefits 116   102  
Deferred ITCs 10   11  
NOL carryforward 1   1  
NOL and tax credit valuation allowances ( 74 ) ( 73 )
Other 91   122  
Total deferred tax assets 2,584   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) 2025 2024 2023
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) 2025 2024
Federal tax credit carryforwards $ 1,474   $ 1,519  
Valuation allowances for federal credit carryforwards ( 10 ) ( 14 )
State NOL carryforwards 8   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 Year Expiration
2022 September 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:

State Tax Year(s) Expiration
Colorado 2014 - 2016 March 2026
Colorado 2021 October 2026
Minnesota 2021 June 2026
Texas 2020 June 2028
Texas 2021 June 2029
Texas 2022 August 2027
Texas 2023 November 2028
Wisconsin 2021 October 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.

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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, 2025 Dec. 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) 2025 2024 2023
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 years 2   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, 2025 Dec. 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) 2025 2024 2023
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.

8. 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) 2025 2024 2023
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) 2025 2024 2023
Vested Units 502   282   329  
Total Fair Value $ 37   $ 19   $ 20  

Changes in the nonvested portion of equity award units:

(Units in Thousands) Units Weighted Average
Grant Date Fair Value
Nonvested Units at Jan. 1, 2025 1,139   $ 64.55  
Granted 683   68.19  
Forfeited ( 170 ) 65.85  
Vested ( 502 ) 66.27  
Dividend equivalents 62   65.85  
Nonvested Units at Dec. 31, 2025 1,212   65.77  

Liability awards granted:

(In Thousands) 2025 2024 2023
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) 2025 2024 2023
Awards settled 74   —   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) 2025 2024 2023
Granted units 32   44   38  
Weighted average grant date fair value $ 70.68   $ 57.03   $ 63.12  

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Changes in stock equivalent units:

(Units in Thousands) Units Weighted Average
Grant Date Fair Value
Stock equivalent units at Jan. 1, 2025 528   $ 48.68  
Granted 32   70.68  
Units distributed ( 53 ) 52.88  
Dividend equivalents 16   71.79  
Stock equivalent units at Dec. 31, 2025 523   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) 2025 2024 2023
Cost for share-based awards (a)
$ 57   $ 30   $ 27  
Tax benefit recognized in income 15   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.

9. 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) 2025 2024 2023
Basic 587   563 552
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.

10. 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.

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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) Cost Level 1 Level 2 Level 3 NAV Total
Nuclear decommissioning fund (a)

Cash equivalents $ 60   $ 60   $ —   $ —   $ —   $ 60  
Commingled funds 720   —   —   —   1,072   1,072  
Debt securities 944   —   934   11   —   945  
Equity securities 505   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) Cost Level 1 Level 2 Level 3 NAV Total
Nuclear decommissioning fund (a)

Cash equivalents $ 39   $ 39   $ —   $ —   $ —   $ 39  
Commingled funds 703   —   —   —   1,025   1,025  
Debt securities 866   —   832   14   —   846  
Equity securities 522   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 Less Due in 1 to 5 Years Due in 5 to 10 Years Due after 10 Years Total
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.

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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, 2025 Dec. 31, 2024
MWh of electricity 35   38  
MMBtu of natural gas 31   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.

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Recurring Derivative Fair Value Measurements
Impact of derivative activity:

Pre-Tax Fair Value Gains (Losses) Recognized During the Period in:
(Millions of Dollars) Accumulated Other Comprehensive Loss Regulatory (Assets) and Liabilities
Year Ended Dec. 31, 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 )

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Pre-Tax (Gains) Losses Reclassified into Income During the Period from: Pre-Tax Gains (Losses) Recognized During the Period in Income
(Millions of Dollars) Accumulated Other Comprehensive Loss Regulatory Assets and (Liabilities)
Year Ended Dec. 31, 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.

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Derivative assets and liabilities measured at fair value on a recurring basis were as follows:

Dec. 31, 2025 Dec. 31, 2024
Fair Value Fair Value Total Netting (a)
Total Fair Value Fair Value Total Netting (a)
Total
(Millions of Dollars) Level 1 Level 2 Level 3 Level 1 Level 2 Level 3
Current derivative assets
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, 2025 Dec. 31, 2024
Fair Value Fair Value Total Netting (a)
Total Fair Value Fair Value Total Netting (a)
Total
(Millions of Dollars) Level 1 Level 2 Level 3 Level 1 Level 2 Level 3
Current derivative liabilities

Other derivative instruments:
Commodity trading 5   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) 2025 2024 2023
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.
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Fair Value of Long-Term Debt
As of Dec. 31, other financial instruments for which the carrying amount did not equal fair value:

2025 2024
(Millions of Dollars) Carrying Amount Fair Value Carrying Amount Fair 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.

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 1 Level 2 Level 3 Measured at NAV Total Level 1 Level 2 Level 3 Measured at NAV Total
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 securities 23   —   —   —   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 .
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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 1 Level 2 Level 3 Measured at NAV Total Level 1 Level 2 Level 3 Measured at NAV Total
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 Benefits Postretirement Benefits
(Millions of Dollars) 2025 2024 2025 2024
Change in Benefit Obligation:
Obligation at Jan. 1 $ 2,752   $ 2,943   $ 427   $ 394  
Service cost 76   76   1   1  
Interest cost 155   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 assets 291   55   31   21  
Employer contributions 125   100   13   11  
Plan participants’ contributions —   —   9   9  
Benefit payments ( 230 ) ( 341 ) ( 55 ) ( 53 )
Fair value of plan assets at Dec. 31 2,690   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 Benefits Postretirement Benefits
Significant Assumptions Used to Measure Benefit Obligations: 2025 2024 2025 2024
Discount rate for year-end valuation 5.78   % 5.88   % 5.66   % 5.88   %
Expected average long-term increase in compensation level 4.25   % 4.25   % N/A N/A
Mortality table PRI-2012 PRI-2012 PRI-2012 PRI-2012
Health care costs trend rate — initial: Pre-65 N/A N/A 7.00   % 7.00   %
Health care costs trend rate — initial: Post-65 N/A N/A 7.50   % 7.50   %
Ultimate trend assumption — initial: Pre-65 N/A N/A 4.50   % 4.50   %
Ultimate trend assumption — initial: Post-65 N/A N/A 4.50   % 4.50   %
Years until ultimate trend is reached N/A N/A 8 9

Accumulated benefit obligation for the pension plan was $ 2,624 million and $ 2,554 million as of Dec. 31, 2025 and 2024, respectively.
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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 Benefits Postretirement Benefits
(Millions of Dollars) 2025 2024 2023 2025 2024 2023
Service cost $ 76   $ 76   $ 74   $ 1   $ 1   $ 1  
Interest cost 155   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 loss 28   30   22   4   2   1  
Settlement charge (a)
—   67   —   —   —   —  
Net periodic pension cost 49   116   44   9   7   6  
Effects of regulation 10   ( 37 ) 30   —   —   —  
Net benefit cost recognized for financial reporting $ 59   $ 79   $ 74   $ 9   $ 7   $ 6  
Significant Assumptions Used to Measure Costs:
Discount rate 5.88   % 5.49   % 5.80   % 5.88   % 5.54   % 5.80   %
Expected average long-term increase in compensation level 4.25   4.25   4.25   —   —   —  
Expected average long-term rate of return on assets 7.13   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 Benefits Postretirement Benefits
(Millions of Dollars) 2025 2024 2025 2024
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 assets 938   983   125   127  
Current regulatory liabilities —   —   ( 1 ) ( 1 )
Noncurrent regulatory liabilities —   —   ( 15 ) ( 18 )
Deferred income taxes 13   14   1   1  
Net-of-tax accumulated other comprehensive income 36   37   2   2  
Total $ 1,023   $ 1,066   $ 117   $ 113  

Measurement date Dec. 31, 2025 Dec. 31, 2024 Dec. 31, 2025 Dec. 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.

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Targeted asset allocations:

Pension Benefits Postretirement Benefits
2025 2024 2025 2024
Long-duration fixed income securities 38   % 38   % —   % —   %
Domestic and international equity securities 30   31   25   25  
Alternative investments 19   20   13   11  
Short-to-intermediate fixed income securities 11   9   61   61  
Cash 2   2   1   3  
Total 100   % 100   % 100   % 100   %

The asset allocations above reflect target allocations approved in the calendar year to take effect in the subsequent year.
Plan Amendments — 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  
2027 243   42   3   39  
2028 244   41   3   38  
2029 249   40   3   37  
2030 243   39   3   36  
2031-2035 1,165   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: 2025 2024
Discount rate for year-end valuation 4.50   % 5.00   %
Mortality table PRI-2012 PRI-2012
Health care costs trend rate 7.00   % 7.00   %
Ultimate trend assumption 4.50   % 4.50   %
Years until ultimate trend is reached 8 9

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.

12. 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.

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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.

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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.

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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 — In June 2023, the EPA published final regulations for ozone under the “Good Neighbor” provisions of the Clean Air Act that established NOx allowance budgets for fossil fuel-fired electric generating facilities in subject states. The final rule applies to generation facilities in Minnesota, Texas and Wisconsin, as well as other states outside of our service territory. In February 2024, the EPA proposed to include New Mexico in the rule. In March 2025, the 5th Circuit Court of Appeals denied petitions challenging EPA’s disapproval of Texas’s state implementation plan, affirming inclusion of Texas facilities in the EPA’s plan. However, the plan is subject to both judicial and administrative stays.
Compliance with the published plan would require subject facilities to secure additional allowances, install NOx controls and/or develop a strategy of operations that utilizes the existing allowance allocations. While the financial impacts of the final rule are uncertain and dependent on market forces and anticipated generation, if the rule is implemented, Xcel Energy anticipates the annual costs could be significant but would be recoverable through regulatory mechanisms.
In January 2026, the EPA proposed Phase 1 of its reconsideration of the “Good Neighbor” rule. Under Phase 1, the agency would approve eight State Implementation Plans, including Minnesota and New Mexico, which were partially disapproved in 2023. Xcel Energy will continue to evaluate any additional phases of the reconsideration of this rule as they are published by the EPA.

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  
Wind 509   —   18   ( 12 ) 515  
Steam, hydro and other production 495   16   21   ( 1 ) 531  
Distribution 51   —   3   —   54  
Natural gas
Transmission and distribution 179   —   9   ( 6 ) 182  

Other
Miscellaneous 3   —   —   —   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.

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(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  
Wind 526   —   —   19   ( 36 ) 509  
Steam, hydro and other production 361   109   ( 6 ) 18   13   495  
Distribution 49   —   —   2   —   51  
Natural gas
Transmission and distribution 172   —   —   8   ( 1 ) 179  
Other
Miscellaneous 3   —   —   —   —   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.

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.

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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, 2025 Dec. 31, 2024
PPAs $ 1,087   $ 1,802  
Other 462   373  
Gross operating lease ROU assets 1,549   2,175  
Accumulated amortization ( 656 ) ( 1,115 )
Net operating lease ROU assets $ 893   $ 1,060  

Finance lease ROU assets:

(Millions of Dollars) Dec. 31, 2025 Dec. 31, 2024
Generation facilities $ 1,254   $ —  
Gas storage facilities 160   160  
Gas pipeline 21   21  
Gross finance lease ROU assets 1,435   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  
2027 90   40   130   111  
2028 80   40   120   114  
2029 78   37   115   115  
2030 78   33   111   117  
Thereafter 185   446   631   1,614  
Total minimum obligation 632   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 years 11.8 18.1

(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) 2025 2024 2023
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 liability 42   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 %).

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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  
2027 31   72  
2028 25   72  
2029 25   70  
2030 20   51  
Thereafter 206   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) Coal Nuclear fuel Natural gas supply Natural gas storage and transportation
2026 $ 300   $ 67   $ 365   $ 399  
2027 135   148   3   349  
2028 11   35   1   215  
2029 1   129   —   127  
2030 1   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.

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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.

13. Other Comprehensive Income

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 Hedges Defined Benefit Pension and Postretirement Items Total
Accumulated other comprehensive loss at Jan. 1 $ ( 29 ) $ ( 39 ) $ ( 68 )
Other comprehensive income (loss) before reclassifications 2   ( 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 income 4   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 Hedges Defined Benefit Pension and Postretirement Items Total
Accumulated other comprehensive loss at Jan. 1 $ ( 53 ) $ ( 41 ) $ ( 94 )
Other comprehensive income (loss) before reclassifications 22   ( 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 income 24   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.

14. 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.

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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 utility Regulated natural gas utility Total segments
Operating revenues $ 12,160   $ 2,452   $ 14,612  
Intersegment revenue 1   26   27  
Total segment revenues 12,161   2,478   14,639  
Electric fuel and purchased power 3,961   —   3,961  
Cost of natural gas sold and transported —   1,041   1,041  
O&M expenses 2,259   425   2,684  

Depreciation and amortization 2,525   413   2,938  
Other segment expenses, net (a)
925   151   1,076  
Interest charges and financing costs 886   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 revenues 57  
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 utility Regulated natural gas utility Total segments
Operating revenues $ 11,147   $ 2,230   $ 13,377  
Intersegment revenue 2   22   24  
Total segment revenues 11,149   2,252   13,401  
Electric fuel and purchased power 3,788   —   3,788  
Cost of natural gas sold and transported —   951   951  
O&M expenses 2,102   409   2,511  

Depreciation and amortization 2,373   357   2,730  
Other segment expenses, net 693   123   816  
Interest charges and financing costs 767   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 revenues 64  
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 utility Regulated natural gas utility Total segments
Operating revenues $ 11,446   $ 2,645   $ 14,091  
Intersegment revenue 2   3   5  
Total segment revenues 11,448   2,648   14,096  
Electric fuel and purchased power 4,278   —   4,278  
Cost of natural gas sold and transported —   1,456   1,456  
O&M expenses 2,011   386   2,397  

Depreciation and amortization 2,111   323   2,434  
Other segment expenses, net (a)
827   118   945  
Interest charges and financing costs 670   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 revenues 115  
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.

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15. Workforce Reduction

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.

ITEM 9 — CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A — CONTROLS AND PROCEDURES

Disclosure Controls and Procedures
Xcel Energy maintains a set of disclosure controls and procedures designed to ensure that information required to be disclosed in reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized, and reported within the time periods specified in SEC rules and forms. In addition, the disclosure controls and procedures ensure that information required to be disclosed is accumulated and communicated to management, including the CEO and CFO, allowing timely decisions regarding required disclosure.
As of Dec. 31, 2025 , based on an evaluation carried out under the supervision and with the participation of Xcel Energy’s management, including the CEO and CFO, of the effectiveness of its disclosure controls and procedures, the CEO and CFO have concluded that Xcel Energy’s disclosure controls and procedures were effective.
Internal Control Over Financial Reporting
No changes in Xcel Energy’s internal control over financial reporting occurred during the most recent fiscal quarter ended Dec. 31, 2025 that materially affected, or are reasonably likely to materially affect, Xcel Energy’s internal control over financial reporting. Xcel Energy maintains internal control over financial reporting to provide reasonable assurance regarding the reliability of the financial reporting. Xcel Energy has evaluated and documented its controls in process activities, general computer activities, and on an entity-wide level.

During the year and in preparation for issuing its report for the year ended Dec. 31, 2025 on internal controls under section 404 of the Sarbanes-Oxley Act of 2002, Xcel Energy conducted testing and monitoring of its internal control over financial reporting. Based on the control evaluation, testing and remediation performed, Xcel Energy did not identify any material control weaknesses, as defined under the standards and rules issued by the Public Company Accounting Oversight Board, as approved by the SEC and as indicated in Xcel Energy’s Management Report on Internal Controls over Financial Reporting, which is contained in Item 8 herein.

ITEM 9B — OTHER INFORMATION

None of the Company’s directors or officers adopted , modified, or terminated a Rule 10b5-1 trading arrangement or a non-Rule 10b5-1 trading arrangement during the Company’s fiscal quarter ended Dec. 31, 2025.
On Feb. 24, 2026, the Company approved a new executive severance and change in control plan. Under the plan, a participant whose employment is terminated under certain circumstances will receive severance benefits (consisting of base salary, target annual incentive and certain retirement and health benefits), which are then applied to a multiple. The multiple applied to the severance benefits is 2 for the CEO and 1.5 for the other executive officers. If the participant is terminated within two years following a change in control, the multiple applied to the severance benefits is 3 for the CEO and 2 for the other executive officers. Notwithstanding the foregoing, the severance multiple applied for a change in control termination impacting our currently serving executive vice presidents will be 3. The Xcel Energy Inc. Executive Severance and Change in Control Plan which goes into effect on March 1, 2026 is filed as Exhibit 10.33 hereto.

ITEM 9C — DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS

Not applicable.

PART III

ITEM 10 — DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Information required under this Item with respect to Directors and Corporate Governance will be set forth in Xcel Energy Inc.’s Proxy Statement for its 2026 Annual Meeting of Shareholders under the captions “Proposal No. 1 Election of Directors,” "Board Committees," "Additional Compensation Program Features and Policies -- Insider Trading Policies and Policies on Hedging and Pledging" and “Delinquent Section 16(a) Reports” and is incorporated by reference. Information with respect to Executive Officers is included in Item 1 to this report under the caption “Information about our Executive Officers”.
Our Code of Conduct applies to Xcel Energy Inc.’s board of directors and all Xcel Energy employees, including the Chief Executive Officer, Chief Financial Officer and Controller. The Code of Conduct is available on our website at www.xcelenergy.com.
If any substantive amendments to the Code of Conduct are made or any waivers are granted, including any implicit waiver, from a provision of the Code of Conduct, to our Chief Executive Officer, Chief Financial Officer or Controller, we will disclose the nature of such amendment or waiver on our website at www.xcelenergy.com, or in a report on Form 8-K.

ITEM 11 — EXECUTIVE COMPENSATION

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Information required under this Item is set forth in Xcel Energy Inc.’s Proxy Statement for its 2026 Annual Meeting of Shareholders under the captions “Compensation Discussion and Analysis,” “Report of the Compensation Committee,” “Executive Compensation” and “Director Compensation” and is incorporated by reference.

ITEM 12 — SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

Information required under this Item is contained in Xcel Energy Inc.’s Proxy Statement for its 2026 Annual Meeting of Shareholders under the captions “Ownership of Securities” and “Executive Compensation -- Securities Authorized for Issuance under Equity Compensation Plans" and is incorporated by reference.

ITEM 13 — CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

Information required under this Item is contained in Xcel Energy Inc.’s Proxy Statement for its 2026 Annual Meeting of Shareholders under the captions “Related Person Transactions” and “Board Planning and Composition – Director Independence” and is incorporated by reference.

ITEM 14 — PRINCIPAL ACCOUNTANT FEES AND SERVICES

Information required under this Item (aggregate fees billed to us by our principal accountant, Deloitte & Touche LLP (PCAOB ID No. 34 )) is contained in Xcel Energy Inc.’s Proxy Statement for its 2026 Annual Meeting of Shareholders under the caption “Independent Auditors” and is incorporated by reference.

PART IV

ITEM 15 — EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

1 Consolidated Financial Statements
Management Report on Internal Controls Over Financial Reporting — For the year ended Dec. 31, 2025.

Report of Independent Registered Public Accounting Firm — Financial Statements and Internal Controls Over Financial Reporting
Consolidated Statements of Income — For each of the three years ended Dec. 31, 2025, 2024 and 2023.

Consolidated Statements of Comprehensive Income — For each of the three years ended Dec. 31, 2025, 2024 and 2023.

Consolidated Statements of Cash Flows — For each of the three years ended Dec. 31, 2025, 2024 and 2023.

Consolidated Balance Sheets — As of Dec. 31, 2025 and 2024.

Consolidated Statements of Common Stockholders’ Equity — For each of the three years ended Dec. 31, 2025, 2024 and 2023.

2 Schedule I — Condensed Financial Information of Registrant.
Schedule II — Valuation and Qualifying Accounts and Reserves for the years ended Dec. 31, 2025, 2024 and 2023.

3 Exhibits
* Indicates incorporation by reference
+ Executive Compensation Arrangements and Benefit Plans Covering Executive Officers and Directors

Xcel Energy Inc.
Exhibit Number Description Report or Registration Statement Exhibit Reference
3.01*
Amended and Restated Articles of Incorporation of Xcel Energy Inc.
Xcel Energy Inc. Form 8-K dated May 16, 2012 3.01
3.02*
Bylaws of Xcel Energy Inc., as Amended and Restated on August 23, 2023
Xcel Energy Inc. Form 8-K dated August 23, 2023
3.02
4.01*
Description of Securities
Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2019 4.01
4.02*
Indenture, dated as of Dec. 1, 2000, by and between Xcel Energy Inc. and U.S Bank Trust Company (as successor to Computershare Trust Company, N.A.), as Trustee
Xcel Energy Inc. Form 8-K dated Dec. 14, 2000 4.01
4.03*
Supplemental Indenture No. 3, dated as of June 1, 2006, by and between Xcel Energy Inc. and U.S. Bank Trust Company (as successor to Computershare Trust Company, N.A.), as Trustee, creating $300 million of 6.50% Senior Notes, Series due July 1, 2036
Xcel Energy Inc. Form 8-K dated June 6, 2006 4.01
4.04*
Supplemental Indenture No. 6, dated as of Sept. 1, 2011, by and between Xcel Energy Inc. and U.S Bank Trust Company (as successor to Computershare Trust Company, N.A.), as Trustee, creating $250 million of 4.80% Senior Notes, Series due Sept. 15, 2041
Xcel Energy Inc. Form 8-K dated Sept. 12, 2011 4.01
4.0 5 *
Supplemental Indenture No. 10, dated as of Dec. 1, 2016, by and between Xcel Energy Inc. and U.S Bank Trust Company (as successor to Computershare Trust Company, N.A.), as Trustee, creating $500 million aggregate principal amount of 3.35% Senior Notes, Series due Dec. 1, 2026
Xcel Energy Inc. Form 8-K dated Dec. 1, 2016 4.01
4.0 6 *
Supplemental Indenture No. 11, dated as of June 25, 2018, by and between Xcel Energy Inc. and U.S Bank Trust Company (as successor to Computershare Trust Company, N.A.), as Trustee, creating $500 million aggregate principal amount of 4.00% Senior Notes, Series due June 15, 2028
Xcel Energy Inc. Form 8-K dated June 25, 2018 4.01
4.0 7 *
Supplemental Indenture No. 12, dated as of Nov. 7, 2019 by and between Xcel Energy Inc. and U.S Bank Trust Company (as successor to Computershare Trust Company, N.A.), as Trustee, creating $500 million aggregate principal amount of 2.60% Senior Notes, Series due Dec 1. 2029 and $500 million aggregate principal amount of 3.50% Senior Notes, Series due Dec. 1, 2049
Xcel Energy Inc. Form 8-K dated Nov. 7, 2019 4.01

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4.0 8 *
Supplemental Indenture No. 13, dated as of April 1, 2020 by and between Xcel Energy Inc. and U.S Bank Trust Company (as successor to Computershare Trust Company, N.A.), as Trustee , creating $600 million aggregate principal amount of 3.40% Senior Notes, Series due June 1, 2030
Xcel Energy Inc. Form 8-K dated April 1, 2020 4.01
4. 09 *
Supplemental Indenture No. 15, dated as of Nov. 3, 2021 between Xcel Energy Inc. and U.S Bank Trust Company (as successor to Computershare Trust Company, N.A.), as Trustee , creating $500 million aggregate principal amount of 1.75% Senior Notes, Series due March 15, 2027 and $300 million aggregate principal amount of 2.35% Senior Notes, Series due Nov. 15, 2031
Xcel Energy Inc. Form 8-K dated Nov. 3, 2021
4.01
4. 10 *
Supplemental Indenture No. 16, dated as of May 6, 2022, by and between Xcel Energy Inc. and U.S Bank Trust Company (as successor to Computershare Trust Company, N.A.), as Trustee, creating $700 million aggregate principal amount of 4.60% Senior Notes, Series due June 1, 2032
Xcel Energy Form 8-K dated May 6, 2022 4.01
4.1 1 *
Supplemental Indenture No. 17, dated as of August 3, 2023, by and between Xcel Energy Inc. and U.S Bank Trust Company (as successor to Computershare Trust Company, N.A.), as Trustee , creating $800 million aggregate principal amount of 5.45% Senior Notes, Series due August 15, 2033.
Xcel Energy Form 8-K dated August 3, 2023
4.01

4.1 2 *
Supplemental Indenture No. 18, dated as of February 29, 2024 by and between Xcel Energy Inc. and U.S. Bank Trust Company, National Association (as successor to Computershare Trust Company, N.A.), as trustee, creating $800,000,000 aggregate principal amount of 5.50% Senior Notes, Series due March 15, 2034.
Xcel Energy Inc Form 8-K dated February 29, 2024 4.01
4. 1 3*
Supplemental Indenture No. 19, dated as of March 21, 2025 by and between Xcel Energy Inc. and U.S. Bank Trust Company, National Association (as successor to Computershare Trust Company, N.A.), as trustee, creating $350,000,000 aggregate principal amount of 4.75% Senior Notes, Series due March 21, 2028 and $750,000,000 aggregate principal amount of 5.60% Senior Notes, Series due April 15, 2035.
Xcel Energy Inc. Form 8-K dated March 21, 2025 4.01
4. 14 *
Junior Subordinated Indenture, dated as of October 1, 2025, by and between Xcel Energy Inc. and U.S. Bank Trust Company, National Association, as trustee.
Xcel Energy Inc. Form 8-K dated October 7, 2025 4.01
4. 15 *
Supplemental Indenture No. 1, dated as of October 7, 2025, by and between Xcel Energy Inc. and U.S. Bank Trust Company, National Association, as trustee, creating $900,000,000 aggregate principal amount of 6.25% Junior Subordinated Notes, Series due 2085.
Xcel Energy Inc. Form 8-K dated October 7, 2025 4.02
10.01*+
Xcel Energy Inc. Nonqualified Pension Plan (2009 Restatement)
Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2008 10.02
10.02*+
Xcel Energy Senior Executive Severance and Change-in-Control Policy (2009 Restatement)
Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2008 10.05
10.03*+
Second Amendment to Exhibit 10.02 dated Oct. 26, 2011
Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2011 10.18
10.04*+
Fifth Amendment to Exhibit 10.02 dated May 3, 2016
Xcel Energy Inc. Form 10-Q for the quarter ended June 30, 2016 10.01
10.05*+
Seventh Amendment to Exhibit 10.02 dated May 7, 2018
Xcel Energy Inc. Form 10-Q for the quarter ended June 30, 2018 10.01
10.06*+
Eighth Amendment to Exhibit 10.02 dated March 31, 2020
Xcel Energy Inc. Form 10-Q for the quarter ended March 31, 2020 10.02
10.07*+
Ninth Amendment to Exhibit 10.02 dated May 22, 2020
Xcel Energy Inc. Form 10-Q for the quarter ended June 30, 2020 10.01
10.0 8 * +
Tenth Amendment to Exhibit 10.02 dated May 20, 2024
Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2024 10.08
10.0 9 * +
Eleventh Amendment to the Xcel Energy Senior Executive Severance and Change in Control Policy
Xcel Energy Inc. Form 10-Q for the quarter ended June 30, 2025 10.01
10. 10 * +
Twelfth Amendment to the Xcel Energy Senior Executive Severance and Change in Control Policy
Xcel Energy Inc. Form 10-Q for the quarter ended June 30, 2025 10.02
10. 11 *+
Xcel Energy Inc. Supplemental Executive Retirement Plan as amended and restated Jan. 1, 2009
Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2008 10.17

10.1 2 *+
Xcel Energy Inc. Nonqualified Deferred Compensation Plan (2009 Restatement)
Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2008 10.07
10.1 3 *+
First Amendment to Exhibit 10.1 2 effective Nov. 29, 2011
Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2011 10.17
10.1 4 *+
Second Amendment to Exhibit 10.1 2 dated May 21, 2013
Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2013 10.22
10.1 5 *+
Third Amendment to Exhibit 10.1 2 dated Sept. 30, 2016
Xcel Energy Inc. Form 10-Q for the quarter ended Sept. 30, 2016 10.01
10.1 6 *+
Fourth Amendment to Exhibit 10.1 2 dated Oct. 23, 2017
Xcel Energy Inc. Form 10-Q for the quarter ended Sept. 30, 2017 10.1
10.1 7 *+
Xcel Energy Inc. Amended and Restated 2015 Omnibus Incentive Plan
Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2018 10.34
10.1 8 *+
Form of Award Agreement for Restricted Stock Units and/or Performance Share Units under the Xcel Energy Inc. 2015 Omnibus Incentive Plan for awards between 2020-2023
Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2019 10.32
10.1 9 *+
Form of Award Agreement for Restricted Stock Units and/or Performance Share Units under the Xcel Energy Inc. 2015 Omnibus Incentive Plan for awards in 2024
Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2023 10.16
10.20*+
Form of Award Agreement for Retention-Based Restricted Stock Units under the Xcel Energy Inc. Amended and Restated 2015 Omnibus Incentive Plan
Xcel Energy Inc. Form 8-K dated Dec. 10, 2021
10.01
10. 21 *+
Xcel Energy Inc. Annual Incentive Plan, effective Feb. 21, 2024
Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2023 10.18
10.2 2 *+
Summary of Non-Employee Director Compensation, effective as of May 24, 2023
Xcel Energy Inc. Form 8-K dated Jan. 20, 2025 10.01
10.2 3 *+
Stock Equivalent Plan for Non-Employee Directors of Xcel Energy Inc. as amended and restated effective Feb. 23, 2011
Xcel Energy Inc. Definitive Proxy Statement dated April 5, 2011 Appendix A
10.2 4 *+
Stock Program for Non-Employee Directors of Xcel Energy Inc. as Amended and Restated on Dec. 12, 2017 under the 2015 Omnibus Incentive Plan
Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2018 10.36

85

Table of Contents     

10.2 5 *+
Xcel Energy Inc. 2024 Equity Incentive Plan
Xcel Energy Inc. Form S-8 dated May 22, 2024 4.03
10.2 6 *+
Xcel Energy Inc. Stock Program for Non-Employee Directors (Effective May 22, 2024) under the 2024 Equity Incentive Plan
Xcel Energy Inc. Form 8-K dated May 22, 2024 10.01
10.2 7 +
Form of Award Agreement for Restricted Stock Units under the Xcel Energy Inc. 2024 Equity Incentive Plan for awards since 2025.

10.2 8 +
Form of Award Agreement for Performance Stock Units under the Xcel Energy Inc. 2024 Equity Incentive Plan for awards since 2025.

10.2 9 *+
Form of Award Agreement for Retention-Based Restricted Stock Units under the Xcel Energy Inc. 2024 Equity Incentive Plan
Xcel Energy Inc. Form 8-K dated May 22, 2024 10.03
10. 30 *+
Form of Award Agreement for Restricted Stock under the Xcel Energy Inc. Equity Incentive Plan
Xcel Energy Inc. Form 8-K dated May 22, 2024 10.04
10. 31 *
Form of Services Agreement between Xcel Energy Services Inc. and utility companies
Xcel Energy Inc. Form U5B dated Nov. 16, 2000 H-1
10. 32 * +
Aircraft Time Sharing Agreement, effective Feb. 25, 2025, between Xcel Energy Services Inc., as Operator, and the Chief Executive Officer of Operator
Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2024 10.30
10.33+
Xcel Energy Inc. Executive Severance and Change in Control Plan (Effective March 1, 2026)

10.3 4 *
Fifth Amended and Restated Credit Agreement, dated as of May 6, 2025, among Xcel Energy Inc., as Borrower, the several lenders from time to time parties thereto, JPMorgan Chase Bank, N.A., as Administrative Agent, Bank of America, N.A. and Barclays Bank PLC, as Syndication Agents, Citibank, N.A., Mizuho Bank, Ltd., Morgan Stanley Senior Funding, Inc., MUFG Bank, Ltd. and Wells Fargo Bank, National Association, as Documentation Agents and the several lenders party thereto.
Xcel Energy Inc. Form 8-K dated May 6, 2025 99.01
10.35*
364-Day Delayed Draw Term Loan Agreement dated as of January 30, 2026 among Xcel Energy Inc., as Borrower, the several lenders from time to time parties thereto, and U.S. Bank National Association, as Administrative Agent.
Xcel Energy Inc. Form 8-K dated February 2, 2026 10.01
19.1*
Securities Trading Overall Policy
Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2024 19.1
19.2*
Securities Trading for Pre-Clearance Persons Policy
Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2024 19.2
NSP-Minnesota
4.1 6 *
Supplemental and Restated Trust Indenture, dated May 1, 1988, from NSP-Minnesota to Harris Trust and Savings Bank, as Trustee, providing for the issuance of First Mortgage Bonds, Supplemental Indentures between NSP-Minnesota and said Trustee
Xcel Energy Inc. Form S-3 dated April 18, 2018 4(b)(3)
4.17*
Supplemental Trust Indenture, dated as of March 1, 1998, from NSP-Minnesota to Harris Trust and Savings Bank, as Trustee, creating $150 million aggregate principal amount of 6.5% First Mortgage Bonds, Series due March 1, 2028
Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2017 4.12
4.1 8 *
Supplemental Trust Indenture, dated as of Aug. 1, 2000 (Assignment and Assumption of Trust Indenture)
NSP-Minnesota Form 10-12G dated Oct. 5, 2000 4.51
4.1 9 *
Supplemental Trust Indenture, dated as of July 1, 2005, by and between NSP-Minnesota and The Bank of New York Mellon Trust Company, NA (as successor to BNY Midwest Trust Company), as Trustee, creating $250 million aggregate principal amount of 5.25% First Mortgage Bonds, Series due July 15, 2035
NSP-Minnesota Form 8-K dated July 14, 2005 4.01
4. 20 *
Supplemental Trust Indenture, dated as of May 1, 2006, by and between NSP-Minnesota and The Bank of New York Mellon Trust Company, NA (as successor to BNY Midwest Trust Company), as Trustee, creating $400 million aggregate principal amount of 6.25% First Mortgage Bonds, Series due June 1, 2036
NSP-Minnesota Form 8-K dated May 18, 2006 4.01
4. 21 *
Supplemental Trust Indenture, dated as of June 1, 2007, by and between NSP-Minnesota and The Bank of New York Mellon Trust Company, NA (as successor to BNY Midwest Trust Company), as Trustee, creating $350 million aggregate principal amount of 6.20% First Mortgage Bonds, Series due July 1, 2037
NSP-Minnesota Form 8-K dated June 19, 2007 4.01
4. 22 *
Supplemental Trust Indenture, dated as of Nov. 1, 2009, by and between NSP-Minnesota and The Bank of New York Mellon Trust Company., NA, as Trustee, creating $300 million aggregate principal amount of 5.35% First Mortgage Bonds, Series due Nov. 1, 2039
NSP-Minnesota Form 8-K dated Nov. 16, 2009 4.01
4. 23 *
Supplemental Trust Indenture, dated as of Aug. 1, 2010, by and between NSP-Minnesota and The Bank of New York Mellon Trust Company, NA, as Trustee, creating $250 million aggregate principal amount of 4.85% First Mortgage Bonds, Series due Aug. 15, 2040
NSP-Minnesota Form 8-K dated Aug. 4, 2010 4.01
4.2 4 *
Supplemental Trust Indenture, dated as of Aug. 1, 2012, by and between NSP-Minnesota and The Bank of New York Mellon Trust Company, NA, as Trustee, creating $500 million aggregate principal amount of 3.40% First Mortgage Bonds, Series due Aug. 15, 2042
NSP-Minnesota Form 8-K dated Aug. 13, 2012 4.01
4.2 5 *
Supplemental Trust Indenture, dated as of May 1, 2014, by and between NSP-Minnesota and The Bank of New York Mellon Trust Company, N.A., as Trustee, creating $300 million aggregate principal amount of 4.125% First Mortgage Bonds, Series due May 15, 2044
NSP-Minnesota Form 8-K dated May 13, 2014 4.01
4.2 6 *
Supplemental Trust Indenture, dated as of Aug. 1, 2015, by and between NSP-Minnesota and The Bank of New York Mellon Company, N.A., as Trustee, creating $300 million aggregate principal amount of 4.00% First Mortgage Bonds, Series due Aug. 15, 2045
NSP-Minnesota Form 8-K dated Aug. 11, 2015 4.01
4.2 7 *
Supplemental Trust Indenture, dated as of May 1, 2016, by and between NSP-Minnesota and The Bank of NY Mellon Trust Company, N.A., as Trustee, creating $350 million aggregate principal amount of 3.60% First Mortgage Bonds, Series due May 15, 2046
NSP-Minnesota Form 8-K dated May 31, 2016 4.01
4.2 8 *
Supplemental Trust Indenture, dated as of Sept. 1, 2017, by and between NSP-Minnesota and The Bank of New York Mellon Trust Company, N.A., as Trustee, creating $600 million aggregate principal amount of 3.60% First Mortgage Bonds, Series due Sept. 15, 2047
NSP-Minnesota Form 8-K dated Sept. 13, 2017 4.01
4.29*
Supplemental Trust Indenture, dated as of Sept. 1, 2019, by and between NSP-Minnesota and The Bank of New York Mellon Trust Company, N.A., as Trustee, creating $600 million aggregate principal amount of 2.90% First Mortgage Bonds, Series due March 1, 2050
NSP-Minnesota Form 8-K dated Sept. 10, 2019 4.01
4. 30 *
Supplemental Indenture, dated as of June 8, 2020, by and between NSP-Minnesota and The Bank of New York Mellon Trust Company, N.A., as Trustee, creating $700 million aggregate principal amount of 2.60% First Mortgage Bonds, Series due June 1, 2051
NSP-Minnesota 8-K dated June 15, 2020 4.01
4.3 1 *
Supplemental Indenture, dated as of March 1, 2021, by and between NSP-Minnesota and The Bank of New York Mellon Trust Company, N.A., as Trustee, creating $425 million principal amount of 2.25% First Mortgage Bonds, Series due April 1, 2031 and $425 million principal amount of 3.20% First Mortgage Bonds, Series due April 1, 2052
NSP-Minnesota 8-K dated March 30, 2021
4.01

86

Table of Contents     

4.3 2 *
Supplemental Indenture, dated as of May 1, 2022, by and between NSP-Minnesota and The Bank of New York Mellon Trust Company, N.A., as Trustee, creating $500 million aggregate principal amount of 4.50% First Mortgage Bonds, Series due June 1, 2052
NSP-Minnesota 8-K dated May 9, 2022 4.01
4.3 3 *
Supplemental Trust Indenture dated as of May 1, 2023 between NSP-Minnesota and The Bank of New York Mellon Trust Company, N.A., as successor Trustee, creating $800 million aggregate principal amount of 5.10% First Mortgage Bonds, Series due May 15, 2053.
NSP-Minnesota 8-K dated May 8, 2023
4.01