What changed in this filing

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Item 8. Financial Statements and Supplementary Data

2026-02-25 compared with 2025-02-27 · 398 added, 383 removed, 1757 unchanged (31% of the section changed)

48 unchanged sentences

Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Critical Audit Matters

The critical audit matters communicated below are matters arising from the current-period audit of the financial statements that were communicated or required to be communicated to the audit committee and that (1) relate to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments.

The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.

Critical Audit Matter

The critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that was communicated or required to be communicated to the audit committee and that (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments.

The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.

Regulatory Assets and Liabilities - Impact of Rate Regulation on the Financial Statements — Refer to Notes 4 and 12 to the consolidated financial statements.

24 unchanged sentences

• We obtained management’s analysis and correspondence from counsel, as appropriate, regarding regulatory assets or liabilities not yet addressed in a regulatory order to assess management’s assertion that amounts are probable of recovery or a future reduction in rates.

Commitments and Contingencies - Wildfires – Refer to Note 12 to the consolidated financial statements

Critical Audit Matter Description

As a result of wildfires that have occurred in the Company's service territory in Colorado and Texas, the Company is required to evaluate its exposure to potential loss contingencies arising from claims associated with the 2021 Marshall Wildfire and the 2024 Smokehouse Creek Fire Complex (the "Wildfires").

In evaluating this exposure, the Company is required to determine whether the likelihood of loss for each of the Wildfires is remote, reasonably possible or probable, which involves complex judgments based on several variables including available information regarding the cause and origin of the Wildfires, investigations, and discovery associated with lawsuits.

A provision for a loss contingency is recorded when it is probable that a liability has been incurred and the amount of loss can be reasonably estimated.

If deemed reasonably possible, the Company is required to estimate the potential loss or range of potential loss and disclose any material amounts.

A current asset for claim amounts that are recoverable from insurance related to a loss contingency is recorded when it is probable the claim will be recovered.

We identified contingencies from the Wildfires and the related disclosures as a critical audit matter due to the significant judgments made by management to determine the probability of loss and estimate the probable losses and insurance recoveries.

Auditing the reasonableness of management's judgments, estimates and disclosures related to the Wildfires required a high degree of auditor judgment and increased extent of audit effort.

How the Critical Audit Matter Was Addressed in the Audit

Our audit procedures related to management's judgments regarding the probability of loss, estimated losses and insurance recoveries, and related disclosures for contingencies related to the Wildfires included the following, among others:

• We tested the effectiveness of controls over (1) the Company's determination of whether a loss was probable and/or reasonably possible and whether recoveries were probable;

(2) the determination of the significant assumptions used in estimating the amount of probable loss and probable insurance recoveries;

and (3) the disclosures related to the Wildfires.

• We evaluated management's judgments related to whether a loss was probable or reasonably possible from the Wildfires by inquiring of management and the Company's external and internal legal counsel.

We also evaluated the potential impact of information gained through the Company and third parties' investigations into the cause of the Wildfires, information from claimants, the advice of legal counsel, and reading external information for any evidence that might contradict management's assertions.

• We evaluated management’s methodologies for assessing estimates of loss and recording a probable loss through inquiries with management and external and internal legal counsel and we tested the significant assumptions, including payments to settle claims, used in the estimates of probable loss.

• We read legal letters from the Company's external and internal legal counsel regarding known information and evaluated whether the information therein was consistent with the information obtained in our procedures.

• We evaluated management's judgments related to whether certain insurance recoveries were probable of collection by inquiring of management and the Company's internal legal counsel regarding the amounts of insurance recoveries recorded or disclosed.

We obtained and inspected relevant insurance policies to evaluate coverages as well as communication between the Company and insurers.

• We evaluated whether the Company's disclosures were appropriate and consistent with the information obtained in our procedures.

/s/ DELOITTE & TOUCHE LLP

21 unchanged sentences

Taxes (other than income taxes) 686 624 657

Marshall Wildfire litigation 296 — —

Loss on Comanche Unit 3 litigation — — 35

2 unchanged sentences

Operating income 2,583 2,386 2,481

Other income (expense), net 143 22 ( 13 )

Other income, net 235 143 22

Earnings from equity method investments 17 19 35

23 unchanged sentences

Pension and retiree medical benefits:

Net pension and retiree medical (losses) gains arising during the period, net of tax ( 3 ) ( 4 ) 5

Net pension and retiree medical losses arising during the period, net of tax ( 1 ) ( 3 ) ( 4 )

Reclassification of losses to net income, net of tax 2 5 2

40 unchanged sentences

Financing activities

Repayments of short-term borrowings, net ( 90 ) ( 28 ) ( 192 )

Proceeds (repayments) of short-term borrowings, net 855 ( 90 ) ( 28 )

Proceeds from issuances of long-term debt 5,763 3,647 2,630

9 unchanged sentences

Cash paid for interest (net of amounts capitalized) $ ( 1,262 ) $ ( 1,131 ) $ ( 945 )

Cash received (paid) for income taxes, net;

includes proceeds from tax credit transfers 588 92 ( 15 )

Supplemental disclosure of non-cash investing and financing transactions:

1 unchanged sentence

Inventory transfers to property, plant and equipment 348 258 197

Operating lease right-of-use assets 138 238 141

Operating and finance lease right-of-use assets 1,253 138 238

Allowance for equity funds used during construction 281 168 91

12 unchanged sentences

Derivative instruments 165 114

Prepaid taxes 72 52

Prepayments and other 1,075 724

5 unchanged sentences

Operating lease right-of-use assets 893 1,060

Finance lease right-of-use assets 1,348 111

Other 1,036 524

16 unchanged sentences

Deferred income taxes 6,004 5,319

Deferred investment tax credits 40 60

Regulatory liabilities 6,277 6,010

4 unchanged sentences

Operating lease liabilities 788 867

Finance lease liabilities 1,262 60

Total deferred credits and other liabilities 18,841 16,738

24 unchanged sentences

Net income 1,771 1,771

Other comprehensive income 30 30

Other comprehensive loss ( 1 ) ( 1 )

Dividends declared on common stock ($ 2.08 per share)

5 unchanged sentences

Net Income 1,936 1,936

Other comprehensive loss ( 1 ) ( 1 )

Other comprehensive income 26 26

Dividends declared on common stock ($ 2.19 per share)

20 unchanged sentences

These utility subsidiaries serve electric and natural gas customers in portions of Colorado, Michigan, Minnesota, New Mexico, North Dakota, South Dakota, Texas and Wisconsin.

Also included in regulated operations are WGI, an interstate natural gas pipeline company, and WYCO, a joint venture with CIG to develop and lease natural gas pipeline, storage and compression facilities.

Also included in regulated operations are WGI, an interstate natural gas pipeline company, and WYCO, a joint venture with CIG to develop and lease natural gas pipeline and storage facilities.

Xcel Energy Inc.’s nonregulated subsidiaries include:

1 unchanged sentence

Eloigne Invests in rental housing projects that qualify for low-income housing tax credits.

Capital Services Procures equipment for construction of renewable generation facilities at other subsidiaries.

Capital Services Procures equipment for Xcel Energy subsidiaries for construction of generation facilities and for other items with long lead times.

Xcel Energy Venture Holdings, Inc.

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All intercompany transactions and balances are eliminated unless a different treatment is appropriate for rate regulated transactions.

The equity method of accounting is used for its investments in energy technology funds and WYCO.

The equity method of accounting is used for investments in energy technology funds and WYCO.

Investments in certain plants and transmission facilities are jointly owned with nonaffiliated utilities.

A proportionate share of jointly owned facilities is recorded as property, plant and equipment on the consolidated balance sheets, and Xcel Energy’s share of operating costs associated with these facilities is included in the consolidated statements of income.

A proportionate share of jointly owned facilities is recorded as property, plant and equipment on the consolidated balance sheets, and Xcel Energy’s share of depreciation and other operating costs associated with these facilities is included in the consolidated statements of income.

The consolidated financial statements are presented in accordance with GAAP.

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Estimates and assumptions for recovery of deferred costs and refund of deferred credits are based on specific ratemaking decisions, precedent or other available information.

Regulatory assets and liabilities are amortized consistent with the treatment in the rate setting process.

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.

9 unchanged sentences

Reversal of certain temporary differences are accounted for as current income tax expense due to the effects of past regulatory practices when deferred taxes were not required to be recorded due to the use of flow through accounting for ratemaking purposes.

Tax credits are recorded when earned unless there is a requirement to defer the benefit and amortize over the book depreciable lives of related property.

The requirement to defer and amortize these credits specifically applies to certain federal ITCs, as determined by tax regulations and Xcel Energy tax elections.

For tax credits otherwise eligible to be recognized when earned, Xcel Energy considers the impact of rate regulation to determine if these credits and related adjustments should be deferred as regulatory assets or liabilities.

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.

4 unchanged sentences

Recognition of changes in uncertain tax positions are reflected as a component of income tax expense.

Interest and penalties related to income taxes are reported within Other income (expense), net or interest charges in the consolidated statements of income.

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.

15 unchanged sentences

For investments in property, plant and equipment that are abandoned and not expected to go into service, incurred costs and related deferred tax amounts are compared to the discounted estimated future rate recovery, and a loss is recognized, if necessary.

Depreciation expense is recorded using the straight-line method over the plant’s commission approved useful life.

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.

3 unchanged sentences

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.

3 unchanged sentences

See Note 12 for further information.

Nuclear Decommissioning — Nuclear decommissioning studies that estimate NSP-Minnesota’s costs of decommissioning its nuclear power plants are normally performed at least every three years and submitted to the state commissions for approval.

The latest decommissioning study was deferred one year and completed in 2024.

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.

4 unchanged sentences

See Notes 10 and 12 for further information.

Leases — Xcel Energy evaluates contracts that may contain leases, including PPAs and arrangements for the use of office space and other facilities, as well as certain contracts for the use of land, vehicles and other equipment.

A contract contains a lease if it conveys the exclusive right to control the use of a specific asset.

A contract determined to contain a lease is evaluated further to determine whether the arrangement is an operating lease or a finance lease, including an assessment of whether the contract requires payments for substantially all of the value of the leased asset or whether the term of the contract is for substantially all of the expected remaining economic life of the leased asset, among other criteria for finance lease classification.

See Note 12 for further information.

Benefit Plans and Other Postretirement Benefits — Xcel Energy maintains pension and postretirement benefit plans for eligible employees.

22 unchanged sentences

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.

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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 in emerging energy technology companies.

Fair Value Measurements — Xcel Energy presents cash equivalents, interest rate derivatives, rabbi trust assets, commodity derivatives, pension and postretirement plan assets and nuclear decommissioning fund assets at estimated fair values in its consolidated financial statements.

5 unchanged sentences

Derivative Instruments — Xcel Energy uses derivative instruments in connection with its commodity trading activities, and to manage risk associated with changes in interest rates and utility commodity prices, including forward contracts, futures, swaps and options.

Derivatives not qualifying for the normal purchases and normal sales exception are recorded on the consolidated balance sheets at fair value as derivative instruments.

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.

13 unchanged sentences

AFUDC amounts capitalized are included in Xcel Energy’s rate base.

Alternative Revenue — Certain rate rider mechanisms (including decoupling/sales true up and CIP/DSM programs) qualify as alternative revenue programs.

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.

4 unchanged sentences

Conservation Programs — Costs incurred for DSM and CIP programs are deferred if it is probable future revenue will recover the incurred cost.

Revenues recognized for incentive programs for the recovery of lost margins and/or conservation performance incentives are limited to amounts expected to be collected within 24 months from the year they are earned.

Regulatory assets are recognized to reflect the amount of costs or earned incentives that have not yet been collected from customers.

1 unchanged sentence

The inventory accounting model is utilized for all emissions allowances and any sales of these allowances are included in electric revenues.

Nuclear Refueling Outage Costs — Xcel Energy uses a deferral and amortization method for nuclear refueling costs.

This method amortizes costs over the period between refueling outages consistent with rate recovery.

RECs — Cost of RECs that are utilized for compliance is recorded as electric fuel and purchased power expense.

6 unchanged sentences

Recently Adopted

Segment Reporting — In November 2023, the FASB issued ASU 2023-07 – Segment Reporting (Topic 280) – Improvements to Reportable Segment Disclosures , which extends the existing requirements for annual disclosures to quarterly periods, and requires that both annual and quarterly disclosures present segment expenses using line items consistent with information regularly provided to the chief operating decision maker.

Xcel Energy implemented this guidance on a retrospective basis in the year ended Dec.

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.

The adoption impacts were not material.

1 unchanged sentence

Recently Issued

The ASU is effective for annual periods beginning after Dec.

15, 2024, and Xcel Energy does not expect implementation of the new disclosure guidance to have a material impact on its consolidated financial statements.

Climate-Related Disclosures — In March 2024, the SEC issued Final Rule 33-11275 – The Enhancement and Standardization of Climate-Related Disclosures for Investors.

This rule requires registrants to provide standardized disclosures in Form 10-K related to climate-related risks, Scope 1 and 2 GHG emissions, as well as to include in a footnote to the consolidated financial statements the financial impact of severe weather events and other natural conditions.

The rule requires implementation in phases between 2025 and 2033.

In April 2024, the SEC announced that it would voluntarily stay its final climate disclosure rules pending judicial review.

Xcel Energy does not expect the potential implementation of the new guidance to have a material impact on the consolidated financial statements.

Disaggregation of Income Statement Expenses — In November 2024, the FASB issued ASU 2024-03 – Disaggregation of Income Statement Expenses , which requires disaggregated disclosure of income statement expenses for public business entities.

The ASU is effective for annual periods beginning after Dec.

Xcel Energy is currently evaluating the impact of implementing the new disclosure guidance.

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.

Xcel Energy is currently evaluating the new guidance, but adoption impacts are expected to be immaterial.

Disaggregation of Income Statement Expenses — In November 2024, the FASB issued ASU 2024-03 – Disaggregation of Income Statement Expenses , which requires disclosure of additional detail for certain categories of income statement expenses.

The ASU is effective for annual reporting periods beginning after Dec.

15, 2026 and interim reporting periods beginning after Dec.

Xcel Energy is currently evaluating the impact of the new disclosure guidance.

Property, Plant and Equipment

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King for NSP-Minnesota;

Comanche Units 2 and 3, Craig Units 1 and 2, Hayden Units 1 and 2 and coal generation assets at Pawnee pending facility gas conversion for PSCo;

Comanche Unit 3, Craig Unit 2, Hayden Units 1 and 2 for PSCo;

and Tolk Unit 1 and 2 for SPS.

31, 2023 amounts also include coal generation assets at Harrington, which were retired in 2024 and the conversion to natural gas is in process.

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.

48 unchanged sentences

Pension and retiree medical obligations 11 Various $ 39 $ 1,121 $ 39 $ 1,167

Net AROs 1, 12 Various — 387 — 316

Recoverable deferred taxes on AFUDC Plant lives — 434 — 368

Net AROs 1, 12 Various — 422 — 387

Depreciation differences Various 22 320 17 250

1 unchanged sentence

7 Various 11 162 10 184

MISO capacity revenue tracker One to two years

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 10 years 4 34 4 38

Conservation programs (a)

Prairie Island extended power uprate Nine years

Conservation programs (b)

1 One to two years

Purchased power contract costs Term of related contract 5 28 4 40

Benson biomass PPA termination and asset purchase Four years

Deferred natural gas, electric, steam energy/fuel costs One to two years

Sales true-up and revenue decoupling Various 60 23 7 33

Nuclear refueling outage costs 1 One to two years

Gas pipeline inspection and remediation costs One to two years

Benson biomass PPA termination and asset purchase Three years

Deferred natural gas, electric, steam energy/fuel costs One to two years

Renewable resources and environmental initiatives One to two years

Sales true-up and MN MISO capacity revenue Various 75 2 123 68

Gas pipeline inspection and remediation costs Less than one year

Various 117 259 91 202

Total regulatory assets $ 529 $ 2,998 $ 561 $ 2,849

(a) Includes costs for conservation programs, as well as incentives allowed in certain jurisdictions.

(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:

5 unchanged sentences

Plant removal costs 1, 12 Various — 2,336 — 2,208

Effects of regulation on employee benefit costs (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

1 unchanged sentence

1 Various — 64 — 70

IRA deferral One to three years

IRA deferral One to two years

Deferred natural gas, electric, steam energy/fuel costs One to two years

296 13 480 12

Contract valuation adjustments (d)

3 unchanged sentences

Other Various 193 153 205 143

Total regulatory liabilities (f)

$ 852 $ 6,010 $ 528 $ 5,827

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 regulatory amortization and certain 2018 TCJA benefits approved by the CPUC to offset the PSCo prepaid pension asset.

(c) Includes amounts recorded for future recovery of AROs, less amounts recovered through nuclear decommissioning accruals and gains from decommissioning investments.

(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.

(f) Revenue subject to refund of $ 3 million and $ 187 million for 2024 and 2023, respectively, is included in other current liabilities.

Xcel Energy’s regulatory assets not earning a return include past expenditures of $ 799 million and $ 892 million at Dec.

31, 2024 and 2023 respectively, which predominately relate to purchased natural gas and electric energy costs (including certain costs related to Winter Storm Uri), sales true-up and revenue decoupling, various renewable resources/environmental initiatives and certain prepaid pension amounts.

Additionally, the unfunded portion of pension and retiree medical obligations and net AROs (i.e.

deferrals for which cash has not been disbursed) do not earn a return.

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.

Borrowings and Other Financing Instruments

20 unchanged sentences

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 September 2022 , Xcel Energy Inc., NSP-Minnesota, NSP-Wisconsin, PSCo and SPS each entered into an amended five-year credit agreement with a syndicate of banks.

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 September 2027.

The amended credit agreements mature in December 2029.

Features of the credit facilities:

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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 %.

(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.

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Total $ 4,750 $ 1,642 $ 3,108

(a) These credit facilities mature in September 2027.

(a) These credit facilities mature in December 2029.

(b) Includes outstanding commercial paper and letters of credit.

3 unchanged sentences

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.

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

13 unchanged sentences

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

2 unchanged sentences

Unsecured senior notes 3.40 June 1, 2030 600 600

Unsecured senior notes

Unsecured senior notes 2.35 Nov.

15, 2031 300 300

Unsecured senior notes 4.60 June 1, 2032 700 700

Unsecured senior notes (a)

Unsecured senior notes 5.45 Aug.

15, 2033 800 800

1 unchanged sentence

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

3 unchanged sentences

1, 2049 500 500

Junior subordinated notes (a) (c)

15, 2085 900 —

Unamortized discount ( 10 ) ( 9 )

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(b) 2024 financing .

NSP-Minnesota

3 unchanged sentences

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

17 unchanged sentences

First mortgage bonds 4.50 June 1, 2052 500 500

First mortgage bonds (a)

5.10 May 15, 2053 800 800

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 Jun 1, 2051 ( 166 ) —

Long-term debt — related parties principal amount outstanding 2.60 - 4.125 2044 - 2052 ( 953 ) ( 166 )

Unamortized discount ( 50 ) ( 49 )

6 unchanged sentences

Financing Instrument Interest Rate Maturity Date 2025 2024

First mortgage bonds 3.30 % June 15, 2024 $ — $ 100

First mortgage bonds 3.30 June 15, 2024 — 100

First mortgage bonds 6.375 % Sept.

10 unchanged sentences

15, 2052 100 100

First mortgage bonds 5.30 June 15, 2053 125 125

First mortgage bonds (a)

4 unchanged sentences

Unamortized debt issuance cost ( 18 ) ( 15 )

Current maturities — ( 200 )

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

10 unchanged sentences

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.

17 unchanged sentences

First mortgage bonds 4.50 June 1, 2052 400 400

First mortgage bonds 5.25 April 1, 2053 850 850

First mortgage bonds (b)

5.25 April 1, 2053 850 850

5.75 May 15, 2054 750 750

First mortgage bonds (a)

7 unchanged sentences

Financing Instrument Interest Rate Maturity Date 2025 2024

First mortgage bonds 3.30 % June 15, 2024 $ — $ 150

First mortgage bonds 3.30 June 15, 2024 — 200

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.

16 unchanged sentences

First mortgage bonds 5.15 June 1, 2052 200 200

First mortgage bonds (a)

First mortgage bonds 6.00 Sept.

15, 2053 100 100

3 unchanged sentences

Unamortized debt issuance cost ( 40 ) ( 35 )

Current maturities — ( 350 )

Total long-term debt $ 4,046 $ 3,551

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purchased $ 166 million in aggregate principal amounts of NSP-Minnesota’s 2.60 % First Mortgage Bonds Series due June 1, 2051 for $ 105 million.

On a consolidated basis, Xcel Energy Inc.’s repurchase of NSP-Minnesota first mortgage bonds was accounted for as a debt extinguishment and resulted in a pre-tax gain of approximately $ 56 million, net of unamortized discount and debt issuance costs.

Interest expense related to the repurchased bonds was immaterial for the year ended Dec.

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.

Equity through DRIP and Benefits Program — Xcel Energy issued $ 67 million of equity in 2024 and $ 88 million of equity in 2023 through the DRIP and benefits programs.

The program allows shareholders to reinvest their dividends directly in Xcel Energy Inc.

common stock.

ATM Equity Offering — In November 2021, Xcel Energy Inc.

filed a prospectus supplement under which it may sell up to $ 800 million of its common stock through an ATM program.

In 2022, 4.3 million shares of common stock were issued (approximately $ 300 million in net proceeds and $ 3 million in transaction fees paid).

In 2023, 0.9 million shares of common stock were issued ($ 62 million in net proceeds and $ 1 million in transaction fees paid).

In October 2023, the 2021 ATM offering was closed.

In October 2023, Xcel Energy Inc.

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, through this ATM program, Xcel Energy Inc.

issued 3.1 million shares of common stock ($ 188 million in net proceeds and $ 2 million in transaction fees paid).

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).

Forward Equity Agreements — In November 2024, Xcel Energy Inc.

entered into forward sale agreements in connection with completed public offerings of 21.1 million shares of Xcel Energy common stock.

The initial forward agreements were for 18.3 million shares with additional agreements for 2.8 million shares exercised at the option of the banking counterparties.

31, 2024, the forward agreements could have been settled with physical delivery of 21.1 million common shares to the banking counterparties in exchange for cash of $ 1.37 billion.

The agreements could also have been settled at Dec.

31, 2024 with delivery of approximately $ 94 million of cash or approximately 1.4 million shares of common stock to the banking counterparties, if Xcel Energy unilaterally elected net cash or net share settlement, respectively.

The forward price used to determine amounts due at settlement is calculated based on the November 2024 public offering price of $ 64.44 (net of underwriting fees), increased for the overnight bank funding rate, less a spread of 0.75% and less expected dividends on Xcel Energy’s common stock during the period the agreements are outstanding.

Xcel Energy may settle the forward agreements at any time up to the maturity date of June 30, 2026.

The cash proceeds, depending on the timing of future settlement, are expected to be approximately $ 1.36 billion.

As initial pricing terms were based on market prices for Xcel Energy common stock, no amounts were recorded at the execution of the forward agreements.

Stockholders’ equity equal to cash proceeds will be recorded at settlement.

In 2025, 16.4 million shares ($ 1.16 billion in net proceeds and $ 9 million in transaction fees paid) were issued under the ATM program.

As of August 1, 2025, no further transactions will occur under this ATM program.

In August 2025, Xcel Energy Inc.

filed a prospectus supplement under which it may sell up to $ 4 billion of its common stock through an ATM program.

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.

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

The following forward sale agreements remain outstanding as of Dec.

Agreements Entered Common Shares (in millions) Final Maturity Minimum Expected Proceeds (millions of dollars)

2025 forward equity agreements (a)

2025 collared forward equity agreements (a)

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.

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:

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Total income tax expense from operations differs from the amount computed by applying the statutory federal income tax rate to income before income tax expense.

Effective income tax rate for years ended Dec.

Effective income tax reconciliation for years ended Dec.

(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:

( 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)

Other 4 4 ( 3 )

Income tax benefit $ ( 245 ) $ ( 402 ) $ ( 146 )

2025 2024 2023

Federal statutory rate 21.0 % 21.0 % 21.0 %

State income tax on pretax income, net of federal tax effect 4.8 4.9 4.9

(Decreases) increases in tax from:

( 32.3 ) ( 43.2 ) ( 28.1 )

Plant regulatory differences (b)

( 7.3 ) ( 5.6 ) ( 5.5 )

Other tax credits, net NOL & tax credit allowances ( 1.3 ) ( 1.3 ) ( 1.3 )

Other, net ( 0.2 ) 0.1 ( 0.1 )

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)

Other 0.4 0.2 —

Effective income tax rate ( 13.8 ) % ( 26.2 ) % ( 9.0 ) %

(a) Wind, Solar and Nuclear PTCs (net of estimated transfer discounts) are generally credited to customers (reduction to revenue) and do not materially impact earnings.

Nuclear PTCs, newly available in 2024, resulted in benefits of 11.3% to the ETR for the year ended Dec.

(b) Plant regulatory differences primarily relate to the credit of excess deferred taxes to customers through the average rate assumption method.

Income tax benefits associated with the credit are offset by corresponding revenue reductions .

(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.

Minnesota, Colorado

Components of income tax expense for years ended Dec.

(Millions of Dollars) 2025 2024 2023

Current federal tax expense $ 36 $ 113 $ 1

Current federal tax (benefit) expense $ ( 6 ) $ 36 $ 113

Current state tax expense 2 28 16

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Deferred state tax expense 96 46 75

Deferred change in unrecognized tax expense — 7 3

Deferred change in unrecognized tax (benefit) expense ( 1 ) — 7

Deferred ITCs ( 4 ) ( 4 ) ( 5 )

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(Millions of Dollars) 2025 2024 2023

Deferred tax expense (benefit) excluding items below $ 434 $ 129 $ ( 138 )

Adjustments to deferred income taxes for tax credit cash transfers (a)

( 689 ) ( 190 ) —

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 )

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Deferred tax benefit $ ( 238 ) $ ( 464 ) $ ( 249 )

(a) Proceeds from tax credit transfers are included in cash received (paid) for income taxes in the consolidated statement of cash flows.

Components of net deferred tax liability as of Dec.

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Pension expense 171 155

Deferred fuel costs — 67

Total deferred tax liabilities $ 8,588 $ 8,097

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NOL and tax credit valuation allowances ( 74 ) ( 73 )

Other 126 184

Total deferred tax assets 2,584 2,778

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(a) Prior periods have been reclassified to conform to current year presentation .

Cash received (paid) for income taxes for the years ended Dec.

(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.

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( 64 ) ( 58 )

(a) State tax credit carryforwards are net of federal detriment of $ 19 million and $ 20 million as of Dec.

31, 2024 and 2023, respectively.

(b) Valuation allowances for state tax credit carryforwards were net of federal benefit of $ 16 million as of Dec.

(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.

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Unrecognized Tax Benefits

Federal Audit — Statute of limitations applicable to Xcel Energy’s consolidated federal income tax returns expire as follows:

Tax Year(s) Expiration

2014 - 2016 March 2025

2021 October 2025

Additionally, the statute of limitations related to the federal tax credit carryforwards will remain open until those credits are utilized in subsequent returns.

Further, the statute of limitations related to the additional federal tax loss carryback claim filed in 2020 has been extended.

In 2023 the IRS issued its Revenue Agent’s Report related to the federal tax loss carryback claim.

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.

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Colorado 2014 - 2016 March 2026

Colorado 2020 September 2025

Minnesota 2014 - 2016 September 2025

Colorado 2021 October 2026

Minnesota 2021 June 2026

Texas 2016 - 2019 December 2025

Wisconsin 2016 - 2019 May 2025

Wisconsin 2020 September 2025

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.

31, 2025, no material adjustments have been proposed.

• In 2021, Texas began an audit of tax years 2016 - 2019.

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NOL and tax credit carryforwards $ ( 33 ) $ ( 35 )

As state audits progress, it is reasonably possible that the amount of current liabilities related to unrecognized tax benefits could decrease up to approximately $ 2 million in the next 12 months.

Additionally, there exists approximately $ 41 million of noncurrent liabilities related to unrecognized tax benefits for which there is uncertainty about if or when these liabilities will significantly increase or decrease.

Payable for interest related to unrecognized tax benefits is partially offset by the interest benefit associated with NOL and tax credit carryforwards.

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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.

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Share-Based Compensation

Incentive Plan Including Share-Based Compensation — Xcel Energy has authorized 13.0 million equity shares under the Xcel Energy Inc.

2024 Equity Incentive Plan for grants made on May 22, 2024 or later and 6.0 million equity shares under the Amended and Restated 2015 Omnibus Incentive Plan for grants made prior to May 22, 2024.

Equity Awards — Xcel Energy‘s Board of Directors has granted equity awards under the 2024 Equity Incentive Plan and 2015 Omnibus Incentive Plan, determined by grant date, which includes various vesting conditions and performance goals.

At the end of the restricted period, such grants will be awarded if vesting conditions and/or performance goals are met.

Certain employees are granted equity awards with a portion subject only to service conditions, and the other portion subject to performance conditions.

The total time-based equity shares granted subject only to service conditions was 0.5 million in 2024, 0.4 million in 2023 and 0.2 million in 2022.

The performance conditions for a portion of the awards granted from 2022 to 2024 are based on relative TSR and environmental goals.

Equity awards with performance conditions will be settled after three years , with payouts ranging from zero to 200 % depending on achievement.

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 658 586 395

Granted units (a)

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:

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31, 2025 1,212 65.77

Liability awards granted:

(In Thousands) 2025 2024 2023

Awards granted (a)

(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.

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31, 2025 523 50.31

Liability Awards — Xcel Energy’s Board of Directors has granted TSR liability awards under the 2024 Equity Incentive Plan and 2015 Omnibus Incentive Plan, determined by grant date.

These plans allow Xcel Energy to attach various performance goals to the awards granted.

The liability awards have been historically dependent on relative TSR measured over a three -year period.

Xcel Energy Inc.’s TSR is compared to a peer group of other utility companies.

Potential payouts of the awards range from zero to 200 %.

Liability awards granted:

(In Thousands) 2024 2023 2022

Awards granted 193 216 165

Liability awards settled:

(Units In Thousands, Settlement Amount in Millions) 2024 2023 2022

Awards settled — 282 411

Settlement amount (cash, common stock and deferred amounts) $ — $ 19 $ 27

There were no TSR liability awards settled in 2024.

Share-Based Compensation Expense — Award settlement determination (permitting cash or share settlement) is made by Xcel Energy, not the participants.

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.

Grant date fair value of equity awards is expensed over the service period.

TSR liability awards are accounted for as liabilities, as historically they are partially settled in cash.

As liability awards, the fair value on which ratable expense is based, as employees vest in their rights to those awards, is remeasured each period based on the current stock price and performance achievement, and final expense is based on the market value of the award on the settlement date.

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:

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Amount for equity awards (non-cash) was $ 46 million, $ 33 million and $ 25 million in 2025, 2024 and 2023, respectively.

There was approximately $ 38 million as of both Dec.

31, 2024 and 2023, of total unrecognized compensation cost related to nonvested share-based compensation awards.

Xcel Energy expects to recognize the unrecognized amount over a weighted average period of 1.7 years.

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.

Earnings Per Share

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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 and time-based equity compensation awards.

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.

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Investments in equity securities and other funds — Equity securities are valued using quoted prices in active markets.

The fair values for commingled funds are measured using NAVs.

The fair values for commingled funds and partnerships are measured using NAVs.

The investments in commingled funds may be redeemed for NAV with proper notice.

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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.

31, 2024, Xcel Energy had no unsettled interest rate swaps outstanding.

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.

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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.

Eight of these significant counterparties are municipal or cooperative electric entities, RTOs or other utilities.

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.

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Electric commodity — ( 22 ) (c)

Natural gas commodity — 15 (d)

( 27 ) (d)(e)

Natural gas commodity — — ( 22 ) (d)(e)

Total $ — $ 22 $ ( 49 )

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Presented amounts reflect changes in fair value between auction and settlement dates, but exclude the original auction fair value.

(d) Other than $ 3 million of 2024 losses recorded to electric fuel and purchased power, amounts are recorded to cost of natural gas sold and transported.

(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.

8 unchanged sentences

Current derivative assets

Derivatives designated as cash flow hedges:

Interest rate $ — $ 1 $ — $ 1 $ — $ 1 $ — $ — $ — $ — $ — $ —

Other derivative instruments:

3 unchanged sentences

Total current derivative assets $ 2 $ 28 $ 154 $ 184 $ ( 19 ) $ 165 $ 6 $ 34 $ 98 $ 138 $ ( 24 ) $ 114

Current derivative instruments $ 114 $ 104

Noncurrent derivative assets

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Current derivative liabilities

Derivatives designated as cash flow hedges:

Interest rate $ — $ — $ — $ — $ — $ — $ — $ 17 $ — $ 17 $ — $ 17

Other derivative instruments:

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(Losses) gains recognized in earnings (b)

( 13 ) ( 9 ) 6

Net gains (losses) recognized as regulatory assets and liabilities (a)

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Xcel Energy’s policy is to fully fund into an external trust the actuarially determined pension costs subject to the limitations of applicable employee benefit and tax laws.

In addition to the qualified pension plans, Xcel Energy maintains a SERP and a nonqualified pension plan.

The SERP is maintained for certain executives who participated in the plan in 2008, when the SERP was closed to new participants.

The nonqualified pension plan provides benefits for compensation that is in excess of the limits applicable to the qualified pension plans, with distributions funded by Xcel Energy’s consolidated operating cash flows.

Obligations of the SERP and nonqualified plan as of Dec.

31, 2024 and 2023 were $ 13 million and $ 12 million, respectively.

Xcel Energy recognized net benefit cost for the SERP and nonqualified plans of $ 2 million in 2024 and $ 2 million in 2023.

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.

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Pension cost determination assumes a forecasted mix of investment types over the long-term.

• Investment returns in 2024 were below the assumed level of 6.93 %.

• 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 %.

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Cash equivalents $ 110 $ — $ — $ — $ 110 $ 117 $ — $ — $ — $ 117

Commingled funds — — — 1,694 1,694 491 — — 1,235 1,726

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

1 unchanged sentence

(a) See Note 10 for further information regarding fair value measurement inputs and methods.

(b) Prior period amounts have been reclassified to conform with current year presentation .

For each of the fair value hierarchy levels, Xcel Energy’s postretirement benefit plan assets that were measured at fair value:

2 unchanged sentences

Insurance contracts — 40 — — 40 — 40 — — 40

Commingled funds — — — 68 68 22 — — 72 94

Commingled funds (b)

— — — 67 67 — — — 23 23

Debt securities — 154 — — 154 — 201 — — 201

Partnerships (b)

— — — 45 45 — — — 45 45

Other — 1 — — 1 — — — — —

1 unchanged sentence

(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.

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Interest cost 155 151 24 21

Plan amendments — ( 3 ) — —

Actuarial (gain) loss ( 77 ) 126 55 14

Actuarial loss (gain) 67 ( 77 ) 21 55

Plan participants’ contributions — — 9 9

Medicare subsidy reimbursements — — 3 —

Benefit payments ( 230 ) ( 341 ) (a)

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Net amounts recognized $ ( 130 ) $ ( 248 ) $ ( 88 ) $ ( 83 )

(a) Includes lump-sum benefit payments used in the determination of settlement charges of $ 168 million in 2024.

(a) Includes $ 168 million of lump-sum benefit payments used in the determination of settlement charges in 2024.

Pension Benefits Postretirement Benefits

15 unchanged sentences

31, 2025 and 2024, respectively.

Net Periodic Benefit Cost (Credit) — Net periodic benefit cost (credit), other than the service cost component, is included in other income (expense) in the consolidated statements of income.

Components of net periodic benefit cost (credit) and amounts recognized in other comprehensive income and regulatory assets and liabilities:

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

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Settlement charge (a)

67 — 71 — — —

Net periodic pension cost (credit) 116 44 144 7 6 ( 5 )

Net periodic pension cost 49 116 44 9 7 6

Effects of regulation 10 ( 37 ) 30 — — —

Net benefit cost (credit) recognized for financial reporting $ 79 $ 74 $ 114 $ 7 $ 6 $ ( 2 )

Net benefit cost recognized for financial reporting $ 59 $ 79 $ 74 $ 9 $ 7 $ 6

Significant Assumptions Used to Measure Costs:

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(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 and 2022, as a result of lump-sum distributions during each plan year, Xcel Energy recorded a total pension settlement charge of $ 67 million and $ 71 million, respectively, the majority of which was not recognized due to the effects of regulation.

A total of $ 8 million and $ 9 million was recorded in the consolidated statements of income in 2024 and 2022, respectively.

There were no settlement charges recorded for the qualified pension plans in 2023.

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

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Health care costs trend rate 7.00 % 7.00 %

Ultimate trend assumption 4.50 % N/A

Years until ultimate trend is reached 9 N/A

Ultimate trend assumption 4.50 % 4.50 %

Years until ultimate trend is reached 8 9

Defined Contribution Plans

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District Court in Nevada.

One case remains active which includes a multi-district litigation matter consisting of a Wisconsin purported class (Arandell Corp.).

The Court issued a ruling in June 2022 granting plaintiffs’ class certification.

In April 2023, the Seventh Circuit Court of Appeals heard the defendants’ appeal challenging whether the district court properly assessed class certification.

A decision relating to class certification is forthcoming.

Xcel Energy considers the reasonably possible loss associated with this litigation to be immaterial.

Comanche Unit 3 Litigation — In 2021, CORE filed a lawsuit in Denver County District Court, alleging PSCo breached ownership agreement terms by failing to operate Comanche Unit 3 in accordance with prudent utility practices.

In April 2022, CORE filed a supplement to include damages related to a 2022 outage.

Also in 2022, CORE sent notice of withdrawal from the ownership agreement based on the same alleged breaches.

In October 2023, the jury ruled that CORE may not withdraw as a joint owner of the facility but awarded CORE lost power damages of $ 26 million.

PSCo recognized $ 35 million of losses for the verdict in 2023, including estimated interest and other costs.

In the fourth quarter of 2024, PSCo and CORE reached a settlement, PSCo paid CORE the agreed to amounts and all appeals and related actions have been dismissed.

Marshall Wildfire Litigation — In December 2021, a wildfire ignited in Boulder County, Colorado (Marshall Fire), which burned over 6,000 acres and destroyed or damaged over 1,000 structures.

One case remains open, which is the multi-district litigation matter consisting of a Wisconsin purported class (Arandell Corp.).

In October 2025, a settlement in principle was reached, resulting in an immaterial loss consistent with previously accrued amounts.

This settlement is subject to court approval.

Marshall Wildfire Litigation — In December 2021, a wildfire ignited in Boulder County, Colorado (Marshall Fire).

On June 8, 2023, the Boulder County Sheriff’s Office released its Marshall Fire Investigative Summary and Review and its supporting documents (Sheriff’s Report).

According to an October 2022 statement from the Colorado Insurance Commissioner, the Marshall Fire is estimated to have caused more than $ 2 billion in property losses.

According to the Sheriff’s Report, on Dec.

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According to the Sheriff’s Report, the second ignition started approximately 80 to 110 feet away from PSCo’s power lines in the area.

The Sheriff’s Report states that the most probable cause of the second ignition was hot particles discharged from PSCo’s power lines after one of the power lines detached from its insulator in strong winds, and further states that it cannot be ruled out that the second ignition was caused by an underground coal fire.

According to the Sheriff’s Report, no design, installation or maintenance defects or deficiencies were identified on PSCo’s electrical circuit in the area of the second ignition.

PSCo disputes that its power lines caused the second ignition .

PSCo is aware of 307 complaints, most of which have also named Xcel Energy Inc.

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 are on behalf of at least 4,087 plaintiffs.

The complaints generally allege that PSCo’s equipment ignited the Marshall Fire and assert various causes of action under Colorado law, including negligence, premises liability, trespass, nuisance, wrongful death, willful and wanton conduct, negligent infliction of emotional distress, loss of consortium and inverse condemnation.

In addition to seeking compensatory damages, certain of the complaints also seek exemplary damages.

In September 2023, the Boulder County District Court Judge consolidated the pending lawsuits into a single action for pretrial purposes and has subsequently consolidated additional lawsuits that have been filed.

At the case management conference in February 2024, a trial date was set for September 2025.

Discovery is now underway.

In September 2024, the Judge presiding over the consolidated cases in Boulder County issued an order regarding the trial that resolves, on a preliminary basis, certain disputes over the structure of the September 2025 trial.

The Court ruled that all Plaintiffs should be bound by a trial on liability unless they opt-out with good cause.

The Court also ruled that liability and damages should be largely or entirely tried separately, meaning that common questions of law and fact regarding liability would be decided first, and a majority or all of the damages phase will occur separately following the liability phase of trial.

The individual plaintiffs filed a motion for reconsideration of the opt-out portion of this order, which the Court denied in November 2024, confirming that plaintiffs will have to demonstrate good cause in order to opt out of the trial.

The Court also denied PSCo’s request for a change in venue, ruling that the trial will take place in Boulder County.

Colorado courts do not apply strict liability in determining an electric utility company’s liability for fire-related damages.

For inverse condemnation claims, Colorado courts assess whether a defendant acted with intent to take a plaintiff’s property or intentionally took an action which has the natural consequence of taking the property.

For negligence claims, Colorado courts look to whether electric power companies have operated their system with a heightened duty of care consistent with the practical conduct of its business, and liability does not extend to occurrences that cannot be reasonably anticipated.

Colorado law does not impose joint and several liability in tort actions.

Instead, under Colorado law, a defendant is liable for the degree or percentage of the negligence or fault attributable to that defendant, except where the defendant conspired with another defendant.

A jury’s verdict in a Colorado civil case must be unanimous.

Under Colorado law, in a civil action filed before Jan.

1, 2025, other than a medical malpractice action, the total award for noneconomic loss is capped at $ 0.6 million per defendant unless the court finds justification to exceed that amount by clear and convincing evidence, in which case the maximum doubles.

Colorado law caps punitive or exemplary damages to an amount equal to the amount of the actual damages awarded to the injured party, except the court may increase any award of punitive damages to a sum up to three times the amount of actual damages if the conduct that is the subject of the claim has continued during the pendency of the case or the defendant has acted in a willful and wanton manner during the action which further aggravated plaintiff’s damages.

In the event Xcel Energy Inc.

or PSCo was found liable related to this litigation and were required to pay damages, such amounts could exceed our insurance coverage of approximately $ 500 million and have a material adverse effect on our financial condition, results of operations or cash flows.

However, due to uncertainty as to the cause of the fire and the extent and magnitude of potential damages, Xcel Energy Inc.

and PSCo are unable to estimate the amount or range of possible losses in connection with the Marshall Fire.

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.

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.

no estimated liability was recognized as of Dec.

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.

no such insurance receivables were recognized as of Dec.

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”).

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as an additional defendant, relating to the Smokehouse Creek Fire Complex.

The complaints 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.

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.

SPS has also received approximately 205 claims for losses related to the Smokehouse Creek Fire Complex through its claims process and has reached final settlements on 129 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 claims related to the Smokehouse Creek Fire Complex which have not been submitted through the claims process and have also not been filed as lawsuits, and has reached settlement of a portion of those claims.

SPS anticipates additional complaints and demands will be made.

As of December 2024, SPS has settled claims related to both of the fatalities believed to be associated with the Smokehouse Creek Fire Complex.

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.

Based on the current state of the law and the facts and circumstances available as of the date of this filing, Xcel Energy believes it is probable that it will incur a loss in connection with the Smokehouse Creek Fire Complex and accordingly has recorded a total of $ 215 million of estimated losses for the matter (before available insurance).

Settlements reached as of the date of this filing total $ 76 million of expected loss payments, of which $ 35 million were paid in 2024, resulting in a remaining estimated liability of $ 180 million presented in other current liabilities as of Dec.

The cumulative estimated probable losses of $ 215 million for complaints and claims in connection with the Smokehouse Creek Fire Complex (before available insurance) corresponds to the lower end of the range of Xcel Energy’s reasonably estimable range of losses, and is subject to change based on additional information.

This $ 215 million estimate does not include, among other things, 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) compensation claims for damage to trees, railroad lines, or oil and gas equipment, or (v) other amounts that are not reasonably estimable.

Xcel Energy remains unable to reasonably estimate any additional loss or the upper end of the range because there are a number of unknown facts and legal considerations that may impact the amount of any potential liability.

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.

In the event that SPS or Xcel Energy Services Inc.

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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.

SPS records insurance recoveries when it is deemed probable that recovery will occur, and SPS can reasonably estimate the amount or range.

SPS has recorded an insurance receivable, net of recoveries received, for $ 210 million, presented within prepayments and other current assets as of Dec.

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

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Unless otherwise disclosed, any reasonably possible range of loss in excess of any recognized amount is not expected to have a material effect on the consolidated financial statements.

Sherco — In 2018, NSP-Minnesota and SMMPA (Co-owner of Sherco Unit 3) reached a settlement with GE related to a 2011 incident, which damaged the turbine at Sherco Unit 3 and resulted in an extended outage.

NSP-Minnesota notified the MPUC of its proposal to refund settlement proceeds to customers through the FCA.

In March 2019, the MPUC approved NSP-Minnesota’s settlement refund proposal.

Additionally, the MPUC decided to withhold any decision as to NSP-Minnesota’s prudence in connection with the incident at Sherco Unit 3 until after conclusion of an appeal pending between GE and NSP-Minnesota’s insurers.

In February 2020, the Minnesota Court of Appeals affirmed the district court’s judgment in favor of GE.

In July 2022, the MPUC referred the matter to the Office of Administrative Hearings to conduct a contested case on the prudence of the replacement power costs incurred by NSP-Minnesota.

In May 2024, the ALJ recommended a customer refund of $ 34 million (less a portion of the proceeds received from the settlement with GE).

The ALJ indicated that consideration of the $ 22 million of previously disallowed costs was not in the scope of their recommendation.

In 2024, following contested case procedures, Xcel recognized a customer refund of $ 47 million for replacement power incurred during the outage.

Minnesota 2023 Fuel Clause Adjustment — In March 2024, NSP-Minnesota filed its annual FCA true-up petition to the MPUC.

In 2024, the DOC recommended customer refunds for 2023 replacement power costs incurred during an outage at the Prairie Island generating station (October 2023 through February 2024).

NSP-Minnesota estimates that customer refunds would be approximately $ 22 million if the DOC recommendations are applied to both 2023 and 2024.

In September 2024, 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.

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 has recorded an estimated liability for a customer refund.

The procedural schedule is as follows:

• Xcel Energy testimony:

• Intervenor direct testimony:

• Rebuttal testimony:

August 13, 2025

• ALJ Report:

March 16, 2026

Cabin Creek Prudency Review — In 2015, the CPUC granted a CPCN for an $ 88 million upgrade project to increase the generating and storage capacity of the Cabin Creek hydroelectric storage facility, which anticipated project completion in 2020.

Due to significant and unforeseen challenges, the project was not completed until 2023 and cost approximately $ 110 million.

In July 2024, PSCo filed direct testimony in a prudency review for the upgrade project, outlining the project’s timelines, costs, benefits and challenges.

In February 2025, PSCo received answer testimony from CPUC Staff and UCA including proposed disallowances, primarily for replacement power and lost capacity.

CPUC Staff recommended a disallowance of $ 21 million and UCA’s testimony included recommendations for total disallowances ranging from $ 71 million to $ 138 million.

PSCo will file its rebuttal testimony in March 2025, responding to answer testimony and continuing to assert that its actions related to the project were prudent, and that therefore no disallowance should be granted.

The remainder of the procedural schedule includes:

• Settlement testimony:

April 4, 2025

April 17-18, 2025

• Statements of position:

A final CPUC decision is expected in the second half of 2025.

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

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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-fueled generating facilities at estimated costs totaling approximately $ 100 million.

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 evaluate the 2024 updates to the CCR Rule, the interpretations of those updates and how they will apply to specific sites.

Assessment of the recent updates to the CCR Rule and corresponding site investigation activities may result in updates to estimated costs as well as identification of additional required corrective actions.

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.

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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.

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.

The rule establishes an allowance trading program for NOx that will impact Xcel Energy fossil fuel-fired electric generating facilities.

Subject facilities will have to secure additional allowances, install NOx controls and/or develop a strategy of operations that utilizes the existing allowance allocations.

While the financial impacts of the final rule are uncertain and dependent on market forces and anticipated generation, Xcel Energy anticipates the annual costs could be significant, but would be recoverable through regulatory mechanisms.

In June 2024, the U.S.

Supreme Court issued an order granting a stay of the final rule.

In response, the EPA issued a nationwide administrative stay of the rule.

Depending on the outcomes of the underlying legal challenges, the regulation may become applicable in the future.

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.

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1, 2025 Amounts Incurred (a)

Amounts Settled Accretion Cash Flow Revisions (b)

Accretion Cash Flow Revisions (b)

Nuclear $ 2,476 $ — $ 127 $ — $ 2,603

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Total liability $ 3,713 $ 16 $ 178 $ ( 19 ) $ 3,888

(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.

(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.

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.

Wind was revised due to the repowering of two wind facilities in NSP-Minnesota.

of Dollars) Jan.

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Total liability $ 3,218 $ 109 $ ( 6 ) $ 153 $ 239 $ 3,713

(a) Amounts incurred relate to the Northern Wind farm placed in service in NSP-Minnesota.

(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.

Revisions in wind and nuclear AROs were primarily incurred due to changes in useful lives.

Changes in gas transmission and distribution AROs were a result of updated gas line mileage and number of services, as well as changes to inflation and discount rate assumptions.

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.

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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.

The Monticello dry-cask storage facility currently stores all 30 of the authorized canisters.

Monticello’s future spent fuel will continue to be placed in its spent fuel pool.

The decommissioning plan addresses the disposition of spent fuel at the end of the licensed life.

In October 2023, a CON for additional storage at the Monticello site was approved by the MPUC to support extended operations to 2040.

The Prairie Island dry-cask storage facility currently stores 52 of the 64 authorized casks.

In February 2024, NSP-Minnesota filed a CON with the MPUC for additional storage at Prairie Island to support possible life extension to 2054.

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.

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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 PI Unit 1 and 2034 for PI Unit 2.

In February 2025, the MPUC approved a settlement agreement which extends the retirement dates for planning purposes to 2050, 2053, and 2054 for Monticello, PI Unit 1, and PI Unit 2, respectively.

Requests to update the authorized retirement dates are expected to be submitted to the MPUC in 2025.

NSP-Minnesota's authorized retirement dates are 2040 for Monticello, 2033 for Prairie Island Unit 1 and 2034 for Prairie Island Unit 2.

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 December 2024.

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.

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See Note 10 to the consolidated financial statements for additional discussion.

Xcel Energy evaluates contracts that may contain leases, including PPAs and arrangements for the use of office space and other facilities, vehicles and equipment.

A contract contains a lease if it conveys the exclusive right to control the use of a specific asset.

A contract determined to contain a lease is evaluated further to determine whether the arrangement is an operating lease or a finance lease.

ROU assets represent Xcel Energy's rights to use leased assets.

The present value of future operating lease payments is recognized in other current operating lease liabilities and noncurrent operating lease liabilities.

These amounts, adjusted for any prepayments or incentives, are recognized as operating lease ROU assets.

Most of Xcel Energy’s leases do not contain a readily determinable discount rate.

Therefore, the present value of future lease payments is generally calculated using the applicable Xcel Energy subsidiary’s estimated incremental borrowing rate (weighted average of 4.6 %).

For currently existing asset classes, Xcel Energy has elected the practical expedient under which non-lease components, such as asset maintenance costs included in payments, are not deducted from lease payments for the purposes of lease accounting and disclosure.

The present value of future finance lease payments is included in other current liabilities and noncurrent finance lease liabilities.

These amounts, adjusted for any prepayments or incentives, are recognized as ROU assets.

Leases with an initial term of 12 months or less are classified as short-term leases and are not recognized on the consolidated balance sheet.

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Net operating lease ROU assets $ 893 $ 1,060

ROU assets for finance leases are included in other noncurrent assets, and the present value of future finance lease payments is included in other current liabilities and other noncurrent liabilities.

Xcel Energy’s most significant finance lease activities are related to WYCO, a joint venture with CIG, to develop and lease natural gas pipeline, storage and compression facilities.

Xcel Energy Inc.

has a 50 % ownership interest in WYCO.

WYCO leases its facilities to CIG, and CIG operates the facilities, providing natural gas storage and transportation services to PSCo under separate service agreements.

PSCo accounts for its Totem natural gas storage service and Front Range pipeline arrangements with CIG and WYCO, respectively, as finance leases.

Xcel Energy Inc.

eliminates 50 % of the finance lease obligation related to WYCO in the consolidated balance sheet along with an equal amount of Xcel Energy Inc.’s equity investment in WYCO.

Finance lease ROU assets:

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31, 2025 Dec.

Generation facilities $ 1,254 $ —

Gas storage facilities 160 160

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Net finance lease ROU assets $ 1,348 $ 111

Components of lease expense:

(Millions of Dollars) 2024 2023 2022

Operating leases

PPA capacity payments $ 228 $ 241 $ 241

Other operating leases (a)

Total operating lease expense (b)

$ 271 $ 283 $ 280

Finance leases

Amortization of ROU assets $ 3 $ 3 $ 4

Interest expense on lease liability 15 15 16

Total finance lease expense $ 18 $ 18 $ 20

(a) Includes short-term lease expense of $ 4 million, $ 3 million, and $ 6 million for 2024, 2023 and 2022, respectively.

(b) PPA capacity payments are included in electric fuel and purchased power on the consolidated statements of income.

Expense for other operating leases is included in O&M expense and electric fuel and purchased power.

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.

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.

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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)

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 %).

PPAs and Fuel Contracts

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Xcel Energy concluded that these entities are not required to be consolidated in its consolidated financial statements because Xcel Energy does not have the power to direct the activities that most significantly impact the entities’ economic performance.

The utility subsidiaries had approximately 3,751 MW of capacity under long-term PPAs as of both Dec.

31, 2024 and 2023, with entities that have been determined to be VIEs.

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.

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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, transaction authorization and income tax matters with respect to assets sold.

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.

7 unchanged sentences

Losses reclassified from net accumulated other comprehensive loss:

Amortization of interest rate hedges 2 (a)

Amortization of net actuarial loss — 5 (b)

Interest rate derivatives (a)

Amortization of net actuarial losses (b)

Net current period other comprehensive income 4 1 5

7 unchanged sentences

1 $ ( 53 ) $ ( 41 ) $ ( 94 )

Other comprehensive loss before reclassifications ( 2 ) ( 4 ) ( 6 )

Other comprehensive income (loss) before reclassifications 22 ( 3 ) 19

Losses reclassified from net accumulated other comprehensive loss:

Amortization of interest rate hedges 3 (a)

Amortization of net actuarial loss — 2 (b)

Net current period other comprehensive income (loss) 1 ( 2 ) ( 1 )

Interest rate derivatives (a)

Amortization of net actuarial losses (b)

Net current period other comprehensive income 24 2 26

Accumulated other comprehensive loss at Dec.

35 unchanged sentences

Depreciation and amortization 2,525 413 2,938

Other segment expenses, net 693 123 816

Other segment expenses, net (a)

925 151 1,076

Interest charges and financing costs 886 125 1,011

8 unchanged sentences

Consolidated net income $ 2,018

(a) Other segment expenses, net, for 2025 additionally includes Marshall Wildfire litigation expense.

(Millions of Dollars) Regulated electric utility Regulated natural gas utility Total segments

6 unchanged sentences

Depreciation and amortization 2,373 357 2,730

Other segment expenses, net (a)

Other segment expenses, net 693 123 816

Interest charges and financing costs 767 113 880

8 unchanged sentences

Consolidated net income $ 1,936

(a) Other segment expenses, net, for 2023 additionally includes loss on Comanche Unit 3 litigation and workforce reduction expenses.

(Millions of Dollars) Regulated electric utility Regulated natural gas utility Total segments

6 unchanged sentences

Depreciation and amortization 2,111 323 2,434

Other segment expenses, net 824 108 932

Other segment expenses, net (a)

Interest charges and financing costs 670 96 766

8 unchanged sentences

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.

Workforce Reduction

5 unchanged sentences

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.

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.

1 unchanged sentence

Compared sentence by sentence after normalising whitespace, quotation marks, case and digits, so re-formatting and restated figures do not read as changed language. Wording changes appear as one removal and one addition. The current filing and the prior one are authoritative.

What changed 10-K

Item 8. Financial Statements and Supplementary Data