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Item 8. Financial Statements and Supplementary Data

2025-02-27 compared with 2024-02-21 · 358 added, 260 removed, 1782 unchanged (26% of the section changed)

24 unchanged sentences

We have audited the accompanying consolidated balance sheets of Xcel Energy Inc.

and subsidiaries (the "Company") as of December 31, 2023 and 2022, the related consolidated statements of income, comprehensive income, stockholders' equity, and cash flows, for each of the three years in the period ended December 31, 2023, and the related notes and the schedules listed in the Index at Item 15 (collectively referred to as the "financial statements").

and subsidiaries (the "Company") as of December 31, 2024 and 2023, the related consolidated statements of income, comprehensive income, common stockholders' equity, and cash flows, for each of the three years in the period ended December 31, 2024, and the related notes and the schedules listed in the Index at Item 15 (collectively referred to as the "financial statements").

We also have audited the Company’s internal control over financial reporting as of December 31, 2024, based on criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

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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 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.

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.

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

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We identified the impact of rate regulation as a critical audit matter due to the significant judgments made by management to support its assertions about impacted account balances and disclosures and the high degree of subjectivity involved in assessing the impact of future regulatory orders on the financial statements.

Management judgments include assessing the likelihood of recovery in future rates of incurred costs and refunds due to customers.

Management judgments include assessing the likelihood of recovery in future rates of incurred costs and requirements to refund amounts to customers.

Given that management’s accounting judgments are based on assumptions about the outcome of future decisions by the Commissions, auditing these judgments required specialized knowledge of accounting for rate regulation and the rate setting process due to its inherent complexities.

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• 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

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Interest charges and financing costs

Interest charges — includes other financing costs of $ 32 , $ 31 and $ 29 , respectively

1,055 953 842

Interest charges — includes other financing costs 1,255 1,055 953

Allowance for funds used during construction — debt ( 73 ) ( 51 ) ( 28 )

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Derivative instruments:

Net fair value (decrease) increase, net of tax ( 2 ) 16 4

Net fair value increase (decrease), net of tax 22 ( 2 ) 16

Reclassification of losses to net income, net of tax 2 3 5

Total other comprehensive (loss) income ( 1 ) 30 18

Total other comprehensive income (loss) 26 ( 1 ) 30

Total comprehensive income $ 1,962 $ 1,770 $ 1,766

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Financing activities

(Repayments of) proceeds from short-term borrowings, net ( 28 ) ( 192 ) 421

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

Proceeds from issuances of long-term debt 3,647 2,630 2,164

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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:

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Operating lease liabilities 867 1,038

Other 148 147

Total deferred credits and other liabilities 16,738 15,898

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Xcel Energy Venture Holdings, Inc.

Invests in limited partnerships, including EIP funds with portfolios of investments in energy technology companies.

Invests in limited partnerships, including funds with portfolios of investments in energy technology companies.

Nicollet Project Holdings Invests in nonregulated assets such as the Minnesota community solar gardens.

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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 EIP funds and WYCO.

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

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

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Use of Estimates — Xcel Energy uses estimates based on the best information available to record transactions and balances resulting from business operations.

Estimates are used for items such as plant depreciable lives or potential disallowances, AROs, certain regulatory assets and liabilities, tax provisions, uncollectible amounts, environmental costs, unbilled revenues, jurisdictional fuel and energy cost allocations and actuarially determined benefit costs.

Recorded estimates are revised when better information becomes available or actual amounts can be determined.

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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.

Due to other regulatory activity, the next decommissioning study has been deferred one year until 2024.

The latest decommissioning study was deferred one year and 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.

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If other participating potentially responsible parties exist and acknowledge their potential involvement with a site, costs are estimated and recorded only for Xcel Energy’s expected share of the cost.

Estimated future expenditures to restore sites are treated as a capitalized cost of plant retirement.

Estimated future expenditures to restore sites are generally treated as a capitalized cost of plant retirement.

The depreciation expense levels recoverable in rates include a provision for removal expenses.

Removal costs recovered in rates before the related costs are incurred are classified as a regulatory liability.

When separate mechanisms are expected to provide cost recovery or when changes in projected costs occur near the end of a facility’s useful life, regulatory accounting may be applied.

See Note 12 for further information.

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Total inventories $ 666 $ 711

Equity Method Investments — The equity method of accounting is used for certain investments including WYCO and EIP funds, which requires Xcel Energy’s recognition of its share of these investees’ results, based on Xcel Energy’s proportional ownership interest.

For investments in EIP funds, this includes Xcel Energy’s share of fund expenses and realized gains and losses, as well as unrealized gains and losses resulting from valuations of the funds’ investments in emerging energy technology companies.

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.

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Gains or losses on commodity trading transactions are recorded as a component of electric operating revenues.

Normal Purchases and Normal Sales — Xcel Energy enters into contracts for purchases and sales of commodities for use in its operations.

Normal Purchases and Normal Sales — Xcel Energy enters into contracts for purchases and sales of commodities for use and sale in its operations.

At inception, contracts are evaluated to determine whether they contain a derivative, and if so, whether they may be exempted from derivative accounting if designated as normal purchases or normal sales.

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Accounting Pronouncements

Recently Issued

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.

The adoption impacts were not material.

See Note 14 for further information.

Recently Issued

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.

The ASU is effective for annual periods beginning after Dec.

15, 2023 and quarterly periods beginning after Dec.

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

Income Taxes — In December 2023, the FASB issued ASU 2023-09 – Income Taxes (Topic 740) – Improvements to Income Tax Disclosures , with new disclosure requirements including presentation of prescribed line items in the effective tax rate reconciliation and disclosures regarding state and local tax payments.

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.

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

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

Property, Plant and Equipment

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

and Tolk Unit 1 and 2 and coal generation assets at Harrington pending facility gas conversion for SPS.

31, 2022 balance also includes Sherco 2, which was retired on Dec.

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.

Amounts are presented net of accumulated depreciation.

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(a) Projects additionally include $ 28 million in CWIP.

Each company’s share of operating expenses and construction expenditures is included in the applicable utility accounts.

Each company separately records its share of operating expenses and construction expenditures.

Respective owners are responsible for providing their own financing.

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Pension and retiree medical obligations 11 Various $ 39 $ 1,167 $ 27 $ 1,106

Net AROs 1, 12 Various — 387 — 316

Recoverable deferred taxes on AFUDC Plant lives — 368 — 332

1, 12 Various — 316 — 339

Depreciation differences Various 17 250 17 189

Excess deferred taxes — TCJA

7 Various 10 184 10 198

Depreciation differences One to 12 years

17 189 17 193

MISO capacity revenue tracker One to two years

Environmental remediation costs 1, 12 Various 13 39 15 94

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

239 80 581 299

Conservation programs (c)

Prairie Island extended power uprate 10 years 4 34 4 38

Conservation programs (a)

1 One to two years

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

PI extended power uprate 11 years

Benson biomass PPA termination and asset purchase Five years

Sales true-up and revenue decoupling One to two years

State commission adjustments Plant lives 1 32 1 33

Losses on reacquired debt Term of related debt 2 30 3 32

MISO capacity revenue tracker One to two years

Gas pipeline inspection and remediation costs One to two years

Contract valuation adjustments (d)

1, 10 Term of related contract 18 22 28 28

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

Grid modernization costs One to two years

Gas pipeline inspection and remediation costs One to two years

Renewable resources and environmental initiatives One to two years

Other Various 65 106 144 75

Various 89 210 102 207

Total regulatory assets $ 561 $ 2,849 $ 611 $ 2,798

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

(b) The 2022 amount is net of the nuclear decommissioning accruals and gains from decommissioning investments.

In 2023, the nuclear decommissioning accruals and gains from decommissioning investments exceeded the expected cost of AROs in NSP-Minnesota and was reclassified to a regulatory liability.

(d) Includes the fair value of certain long-term PPAs used to meet energy capacity requirements and valuation adjustments on natural gas commodity purchases.

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

Components of regulatory liabilities:

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Various — 161 — 90

Sales true-up and revenue decoupling Two years

ITC deferrals

1 Various — 70 1 60

LP&L departure payment Up to 10 years

Formula rates One to two years

DOE settlement One to two years

Deferred natural gas, electric, steam energy/fuel costs Less than one year

IRA deferral One to three years

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

Contract valuation adjustments (d)

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

(a) Includes the revaluation of recoverable/regulated plant accumulated deferred income taxes and revaluation impact of non-plant accumulated deferred income taxes due to the TCJA.

(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.

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Short-Term Borrowings

Short-Term Debt — Xcel Energy meets its short-term liquidity requirements primarily through the issuance of commercial paper and borrowings under their credit facilities and term loan agreements.

Short-Term Debt — Xcel Energy meets its short-term liquidity requirements primarily through the issuance of commercial paper and borrowings under its credit facilities and term loan agreements.

Commercial paper and other borrowings outstanding:

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The lines of credit provide short-term financing in the form of notes payable to banks, letters of credit and back-up support for commercial paper borrowings.

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

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

The aggregate borrowing limit is $ 3.55 billion.

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31, 2024, Xcel Energy Inc.

and its subsidiaries were in compliance with all financial covenants.

and its subsidiaries were in compliance with the financial covenant.

Xcel Energy Inc.

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and its utility subsidiaries as of Dec.

31 (in millions of dollars):

31 (in millions of dollars, except interest rates):

Xcel Energy Inc.

Financing Instrument Interest Rate Maturity Date 2024 2023

Unsecured senior notes 0.50 % Oct.

15, 2023 $ — $ 500

Unsecured senior notes 3.30 % June 1, 2025 250 250

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15, 2031 300 300

Unsecured senior notes 4.60 June 1, 2032 700 700

Unsecured senior notes (a)

4.60 June 1, 2032 700 700

Unsecured senior notes (b)

15, 2033 800 800

Unsecured senior notes (b)

5.50 March 15, 2034 800 —

Unsecured senior notes 6.50 July 1, 2036 300 300

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Financing Instrument Interest Rate Maturity Date 2024 2023

First mortgage bonds 2.60 % May 15, 2023 $ — $ 400

First mortgage bonds 7.125 % July 1, 2025 250 250

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First mortgage bonds 3.20 April 1, 2052 425 425

First mortgage bonds 4.50 June 1, 2052 500 500

First mortgage bonds (a)

4.50 June 1, 2052 500 500

First mortgage bonds (b)

5.10 May 15, 2053 800 800

First mortgage bonds (b)

5.40 March 15, 2054 700 —

Other long-term debt 2 2

Long-term debt — related parties principal amount outstanding 2.60 Jun 1, 2051 ( 166 ) —

Unamortized discount ( 49 ) ( 49 )

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First mortgage bonds 2.82 May 1, 2051 100 100

First mortgage bonds (a)

First mortgage bonds 4.86 Sept.

15, 2052 100 100

First mortgage bonds (a)

5.30 June 15, 2053 125 125

First mortgage bonds (b)

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Financing Instrument Interest Rate Maturity Date 2024 2023

First mortgage bonds 2.50 % March 15, 2023 $ — $ 250

First mortgage bonds 2.90 % May 15, 2025 250 250

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First mortgage bonds 1.875 June 15, 2031 750 750

First mortgage bonds 4.10 June 1, 2032 300 300

First mortgage bonds (a)

4.10 June 1, 2032 300 300

5.35 May 15, 2034 450 —

First mortgage bonds 6.25 Sept.

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15, 2051 375 375

First mortgage bonds (a)

4.50 June 1, 2052 400 400

First mortgage bonds 4.50 June 1, 2052 400 400

First mortgage bonds (b)

5.25 April 1, 2053 850 850

First mortgage bonds (a)

5.75 May 15, 2054 750 —

Unamortized discount ( 42 ) ( 41 )

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First mortgage bonds 3.15 May 1, 2050 250 250

First mortgage bonds 5.15 June 1, 2052 200 200

First mortgage bonds (a)

5.15 June 1, 2052 200 200

First mortgage bonds (b)

15, 2053 100 100

First mortgage bonds (b)

6.00 June 1, 2054 600 —

Unamortized discount ( 14 ) ( 10 )

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(Millions of Dollars)

Xcel Energy Inc.’s Purchase of NSP-Minnesota’s First Mortgage Bonds — During 2024, Xcel Energy Inc.

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

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.

Deferred Financing Costs — Deferred financing costs of approximately $ 235 million and $ 209 million, net of amortization, are presented as a deduction from the carrying amount of long-term debt as of Dec.

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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 2022, 4.30 million shares of common stock were issued (approximately $ 300 million in net proceeds and $ 3 million in transaction fees paid).

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

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filed a prospectus supplement under which it may sell up to $ 2.5 billion of its common stock through an ATM program.

In the fourth quarter, through this ATM Program, Xcel Energy Inc.

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 2024, 18.3 million shares of common stock were issued ($ 1.1 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.

Capital Stock — Preferred stock authorized/outstanding:

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(Millions of Dollars) Long-Term Debt Short-Term Debt

NSP-Minnesota 52.8% of total capitalization (a)

NSP-Minnesota (a)

52.4% of total capitalization $ 2,670

NSP-Wisconsin $ 225 150

PSCo 1,300 1,200

(a) NSP-Minnesota has authorization to issue long-term securities provided the equity-to-total capitalization remains within the required range, and to issue short-term debt provided it does not exceed 15 % of total capitalization.

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Effective income tax rate for years ended Dec.

2024 2023 2022

Federal statutory rate 21.0 % 21.0 % 21.0 %

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(Decreases) increases in tax from:

Wind PTCs (a)

( 43.2 ) ( 28.1 ) ( 27.4 )

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Effective income tax rate ( 26.2 ) % ( 9.0 ) % ( 8.4 ) %

(a) Wind PTCs net of estimated transfer discount are credited to customers (reduction to revenue) and do not materially impact net income.

(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.

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Current federal tax expense $ 36 $ 113 $ 1

Current state tax expense (benefit) 16 3 ( 2 )

Current change in unrecognized tax (benefit) expense ( 21 ) 5 1

Current state tax expense 28 16 3

Current change in unrecognized tax expense (benefit) 2 ( 21 ) 5

Deferred federal tax benefit ( 510 ) ( 331 ) ( 239 )

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

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

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

( 689 ) ( 190 ) —

Amortization and adjustments to deferred income taxes on income tax regulatory assets and liabilities ( 201 ) ( 188 ) 8

Tax benefit allocated to other comprehensive income and other — ( 10 ) ( 6 )

Tax expense allocated to other comprehensive income and other ( 8 ) — ( 10 )

Deferred tax benefit $ ( 464 ) $ ( 249 ) $ ( 140 )

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Other employee benefits 102 117

Deferred investment tax credits 16 14

Deferred ITCs 11 16

NOL carryforward 1 —

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(Millions of Dollars) 2024 2023

Federal NOL carryforward $ — $ 20

Federal tax credit carryforwards $ 1,519 $ 1,644

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31, 2024 and 2023.

Federal carryforward periods expire between 2037 and 2043 and state carryforward periods expire starting 2024.

Federal carryforward periods expire between 2038 and 2044.

State carryforward periods, not including those with indefinite carryforward periods, expire between 2025 and 2037.

Unrecognized Tax Benefits

2 unchanged sentences

2014 - 2016 March 2025

2020 September 2024

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.

31, 2023 the IRS issued its Revenue Agent’s Report related to the federal tax loss carryback claim.

The Company materially agrees with the report and re-recognized the related benefit in December 2023.

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.

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 2019 October 2024

Colorado 2020 September 2025

Minnesota 2014 - 2016 September 2025

Minnesota 2019 May 2024

Texas 2016, 2018 May 2024

Texas 2017 July 2025

Texas 2019 August 2024

Minnesota 2020 June 2025

Texas 2016 - 2019 December 2025

Wisconsin 2016 - 2019 May 2025

Wisconsin 2019 October 2024

• In 2020, Minnesota began an audit of tax years 2015 - 2018.

In 2022, the state of Minnesota issued its audit report and in 2023, the Company agreed to the report without any material adjustments.

Wisconsin 2020 September 2025

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

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• No other state income tax audits are in progress for its major operating jurisdictions as of Dec.

Unrecognized tax benefit balance includes permanent tax positions, which if recognized would affect the ETR.

In addition, the unrecognized tax benefit balance includes temporary tax positions for which deductibility is highly certain, but for which there is uncertainty about the timing.

Unrecognized tax benefit balance may include permanent tax positions, which if recognized would affect the ETR.

In addition, the unrecognized tax benefit balance may include temporary tax positions for which deductibility is highly certain, but for which there is uncertainty about the timing.

A change in the period of deductibility would not affect the ETR but would accelerate the payment to the taxing authority.

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

As IRS audits resume and as state audits progress, it is reasonably possible that the amount of unrecognized tax benefit could decrease up to approximately $ 14 million in the next 12 months.

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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1 $ ( 1 ) $ ( 4 ) $ ( 3 )

Interest benefit (expense) related to unrecognized tax benefits 3 ( 1 ) —

Interest (expense) benefit related to unrecognized tax benefits ( 1 ) 3 ( 1 )

Payable for interest related to unrecognized tax benefits at Dec.

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Share-Based Compensation

Incentive Plan Including Share-Based Compensation — Xcel Energy has authorized 7.0 million equity shares under an incentive plan (the Amended and Restated 2015 Omnibus Incentive Plan).

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

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 0.4 million in 2023 and 0.2 million in 2022 and 2021 respectively.

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.

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31, 2024 528 48.68

Liability Awards — Xcel Energy’s Board of Directors has granted TSR liability awards under the 2015 Omnibus Incentive Plan.

This plan allows Xcel Energy to attach various performance goals to the awards granted.

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.

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

TSR liability awards of $ 13 million were settled in cash in 2023.

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.

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

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

Compensation costs related to share-based awards:

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(a) Compensation costs for share-based payments are included in O&M expense.

Amount for equity awards (non-cash) was $ 25 million in 2023.

There was approximately $ 38 million and $ 37 million as of Dec.

31, 2023 and 2022, respectively, of total unrecognized compensation cost related to nonvested share-based compensation awards.

Amount for equity awards (non-cash) was $ 33 million, $ 25 million and $ 20 million in 2024, 2023 and 2022, 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.

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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 time-based equity compensation awards.

Common Stock Equivalents — Common stock equivalents include commitments to issue common stock related to forward 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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Basic 563 552 547

(a) Diluted common shares outstanding included common stock equivalents of 0.3 million shares for 2023, 2022 and 2021.

(a) Diluted common shares outstanding included common stock equivalents of 0.5 million, 0.3 million, and 0.3 million shares for 2024, 2023 and 2022, respectively.

Fair Value of Financial Assets and Liabilities

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NSP-Minnesota recognizes the costs of funding the decommissioning over the lives of the nuclear plants, assuming rate recovery of all costs.

Realized and unrealized gains on fund investments over the life of the fund are deferred as an offset of NSP-Minnesota’s regulatory asset for nuclear decommissioning costs.

Consequently, any realized and unrealized gains and losses on securities in the nuclear decommissioning fund are deferred as a component of the regulatory asset.

Realized and unrealized gains on fund investments over the life of the fund are deferred as an offset of NSP-Minnesota’s regulatory asset or as a regulatory liability (dependent on funding status) for nuclear decommissioning costs.

Consequently, any realized and unrealized gains and losses on securities in the nuclear decommissioning fund are deferred as a component of the regulatory asset/liability.

Unrealized gains for the nuclear decommissioning fund were $ 1.4 billion and $ 1.2 billion as of Dec.

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31, 2024, 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, 2023, Xcel Energy had unsettled interest swaps outstanding with a notional amount of $ 420 million.

These interest rate derivatives were designated as cash flow hedges, with changes in fair value recorded to other comprehensive income.

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

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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Xcel Energy is allowed to conduct these activities within guidelines and limitations as approved by its risk management committee, comprised of management personnel not directly involved in the activities governed by this policy.

Derivative instruments entered into for trading purposes are presented in the consolidated statements of income as electric revenues, net of any sharing with customers.

Results of derivative instrument transactions entered into for trading purposes are presented in the consolidated statements of income as electric revenues, net of any sharing with customers.

These activities are not intended to mitigate commodity price risk associated with regulated electric and natural gas operations.

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These instruments are intended to offset the impacts of transmission system congestion.

Higher congestion costs in recent years have led to an increase in the fair value of FTRs.

Settlements of FTRs are shared with electric customers through fuel and purchased energy cost-recovery mechanisms.

When Xcel Energy enters into derivative instruments that mitigate commodity price risk on behalf of electric and natural gas customers, the instruments are not typically designated as qualifying hedging transactions.

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Impact of credit risk was immaterial to the fair value of unsettled commodity derivatives presented on the consolidated balance sheets.

Xcel Energy’s utility subsidiaries’ most significant concentrations of credit risk with particular entities or industries are contracts with counterparties to their wholesale, trading and non-trading commodity activities.

31, 2023, four of Xcel Energy’s ten most significant counterparties for these activities, comprising $ 49 million or 23 % of this credit exposure, had investment grade credit ratings from S&P Global Ratings, Moody’s Investor Services or Fitch Ratings.

Five of the ten most significant counterparties, comprising $ 78 million or 37 % of this credit exposure, were not rated by these external ratings agencies, but based on Xcel Energy’s internal analysis, had credit quality consistent with investment grade.

Xcel Energy’s utility subsidiaries’ often have significant concentrations of credit risk with particular entities or industries in their wholesale, trading and non-trading commodity activities.

31, 2024, three of Xcel Energy’s ten most significant counterparties for these activities, comprising $ 34 million or 18 % of this credit exposure, had investment grade credit ratings from S&P Global Ratings, Moody’s Investor Services or Fitch Ratings.

Six of the ten most significant counterparties, comprising $ 74 million or 40 % of this credit exposure, were not rated by these external ratings agencies, but based on Xcel Energy’s internal analysis, had credit quality consistent with investment grade.

One of these significant counterparties, comprising $ 43 million or 23 % of this credit exposure, had credit quality less than investment grade, based on internal analysis.

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31, 2024 and 2023, there were $ 11 million and $ 12 million, respectively, of derivative liabilities with such underlying contract provisions, respectively.

Also, certain contracts may contain cross default provisions that may require the posting of collateral or settlement of the contracts if there was a failure under other financing arrangements related to payment terms or other covenants.

Certain contracts also contain cross default provisions that may require the posting of collateral or settlement of the contracts if there was a failure under other financing arrangements related to payment terms or other covenants.

31, 2024 and 2023, there were approximately $ 69 million and $ 88 million of derivative liabilities with such underlying contract provisions, respectively.

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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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FTR settlements are shared with customers and do not have a material impact on net income.

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

(d) Recorded to cost of natural gas sold and transported.

These losses are subject to cost-recovery mechanisms and reclassified out of income to a regulatory asset, as appropriate.

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.

Amounts are subject to cost-recovery mechanisms and reclassified out of income to a regulatory asset, as appropriate.

(e) Relates primarily to option premium amortization.

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Total noncurrent derivative assets $ 8 $ 37 $ 47 $ 92 $ ( 20 ) $ 72 $ 14 $ 51 $ 45 $ 110 $ ( 34 ) $ 76

Noncurrent derivative instruments $ 76 $ 93

31, 2024 Dec.

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Net transactions recorded during the period:

Gains recognized in earnings (b)

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

(Losses) gains recognized in earnings (b)

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

111 ( 174 ) 10

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31 $ 99 $ 90 $ 236

(a) Relates primarily to NSP-Minnesota and SPS FTR instruments administered by MISO and SPP.

(a) Relates primarily to NSP-Minnesota and SPS FTR instruments administered by MISO and SPP, respectively.

(b) Relates to commodity trading and is subject to substantial offsetting losses and gains on derivative instruments categorized as levels 1 and 2 in the income statement.

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

• Investment returns in 2023 were above the assumed level of 6.93 %.

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

• Investment returns in 2023 were above the assumed level of 6.93 %.

• Investment returns in 2022 were below the assumed level of 6.49 %.

• In 2025, expected investment-return assumption is 7.13 %.

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Plan participants’ contributions — — 9 8

Medicare subsidy reimbursements — — — 2

Benefit payments (a)

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Net amounts recognized $ ( 248 ) $ ( 253 ) $ ( 83 ) $ ( 38 )

(a) Includes lump-sum benefit payments used in the determination of a settlement charges of $ 195 million of in 2022.

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

Pension Benefits Postretirement Benefits

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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.

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

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.

Pension Benefits Postretirement Benefits

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The asset allocations above reflect target allocations approved in the calendar year to take effect in the subsequent year.

Plan Amendments — In 2023, Xcel Energy amended the Xcel Energy Pension Plan and Xcel Energy Inc.

Nonbargaining Pension Plan (South) to reduce supplemental social security benefits for all active participants on and after Jan.

There were no significant plan amendments made in 2022 which affected the postretirement benefit obligation.

Plan Amendments — There were no significant plan amendments made in 2024 and 2022 which affected the pension or postretirement benefit obligation.

In 2023, Xcel Energy amended the Xcel Energy Pension Plan and Xcel Energy Inc.

Nonbargaining Pension Plan (South) to reduce supplemental benefits for non-bargaining participants as well as to allow the transfer of a portion of non-qualified pension obligations into the qualified plans.

Nonbargaining Pension Plan (South) to reduce supplemental social security benefits for all active participants on and after Jan.

Projected Benefit Payments

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Voluntary Retirement Program

Incremental to amounts presented above for postretirement benefits, Xcel Energy recognized new postemployment costs and obligations in the fourth quarter of 2023 for employees accepted to a voluntary retirement program.

Utilizing employee information and the following inputs, the estimated costs of the program of $ 34 million for health plan subsidies and $ 5 million for other medical benefits, each commencing in 2024, were recognized in the fourth quarter of 2023.

These unfunded obligations are presented in other current liabilities and noncurrent pension and employee benefit obligations in the consolidated balance sheet as of Dec.

Incremental to amounts presented above for postretirement benefits, Xcel Energy has postemployment costs and obligations for its Voluntary Retirement Program, under which approximately 400 eligible non-bargaining employees retired in the fourth quarter of 2023.

Utilizing employee information and the following inputs, unfunded obligations of $ 29 million and $ 34 million for health plan subsidies and $ 4 million and $ 5 million for other medical benefits are presented in other current liabilities and noncurrent pension and employee benefit obligations in the consolidated balance sheets as of Dec.

31, 2024 and 2023, respectively.

Significant Assumptions to Measure Benefit Obligations:

Discount rate for year-end valuation 5.00 % 5.50 %

Mortality table PRI-2012

Health care costs trend rate and ultimate trend assumption 7.00 %

Mortality table PRI-2012 PRI-2012

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

Defined Contribution Plans

Xcel Energy maintains 401(k) and other defined contribution plans that cover most employees.

Total expense to these plans was approximately

$49 million in 2023, $ 46 million in 2022 and $ 43 million in 2021.

Total expense to these plans was approximately $ 50 million in 2024, $ 49 million in 2023 and $ 46 million in 2022.

Multiemployer Plans

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

A decision relating to class certification is expected imminently.

A decision relating to class certification is forthcoming.

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

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

In February 2023, the court granted PSCo’s motion precluding CORE from seeking damages related to its withdrawal as part of the lawsuit.

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

PSCo recognized a $ 34 million loss for the verdict in the third quarter of 2023, including estimated interest and other costs.

PSCo intends to file an appeal of this decision.

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

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

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.

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.

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as additional defendants, relating to the Marshall Fire.

The complaints are on behalf of at least 4,047 plaintiffs, and one complaint is filed on behalf of a putative class of first responders who allegedly were exposed to the threat of serious bodily injury, or smoke, soot and ash from the Marshall Fire.

The complaints 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 eight lawsuits that were pending at that time into a single action for pretrial purposes and has subsequently consolidated additional lawsuits that have been filed.

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.

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

Under Colorado law, in a civil action other than a medical malpractice action, the total award for noneconomic loss is capped at $ 0.6 million per defendant for claims that accrued at the time of the Marshall Fire unless the court finds justification to exceed that amount by clear and convincing evidence, in which case the maximum doubles.

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.

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

2024 Smokehouse Creek Fire Complex — On February 26, 2024, multiple wildfires began in the Texas Panhandle, including the Smokehouse Creek Fire and the 687 Reamer Fire, which burned into the perimeter of the Smokehouse Creek Fire (together, referred to herein as the “Smokehouse Creek Fire Complex”).

The Texas A&M Forest Service issued incident reports that determined that the Smokehouse Creek Fire and the 687 Reamer Fire were caused by power lines owned by SPS after wooden poles near each fire origin failed.

According to the Texas A&M Forest Service’s Incident Viewer and news reports, the Smokehouse Creek Fire Complex burned approximately 1,055,000 acres.

SPS is aware of approximately 25 complaints, most of which have also named Xcel Energy Services Inc.

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.

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.

In the event that SPS or Xcel Energy Services Inc.

was found liable related to the litigation related to the Smokehouse Creek Fire Complex and was required to pay damages, such amounts could exceed our insurance coverage of approximately $ 500 million for the annual policy period and could have a material adverse effect on our financial condition, results of operations or cash flows.

The process for estimating losses associated with potential claims related to the Smokehouse Creek Fire Complex requires management to exercise significant judgment based on a number of assumptions and subjective factors, including the factors identified above and estimates based on currently available information and prior experience with wildfires.

As more information becomes available, management estimates and assumptions regarding the potential financial impact of the Smokehouse Creek Fire Complex may change.

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.

While SPS plans to seek recovery of all insured losses, it is unable to predict the ultimate amount and timing of such insurance recoveries.

Rate Matters and Other

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

In January 2021, the OAG and DOC recommended that NSP-Minnesota refund approximately $ 17 million of replacement power costs previously recovered through the FCA.

NSP-Minnesota responded that it acted prudently in connection with the Sherco Unit 3 outage, the MPUC has previously disallowed $ 22 million of related costs and no additional refund or disallowance is appropriate.

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

In 2023, NSP-Minnesota and various parties filed recommendations, including the DOC which recommended a $ 56 million customer refund.

The Xcel Large Industrial customer group recommended a refund of $ 72 million.

A final decision by the MPUC is expected in mid-2024.

A loss related to this matter is deemed remote.

MISO ROE Complaints — In November 2013 and February 2015, customer groups filed two ROE complaints against MISO TOs, which includes NSP-Minnesota and NSP-Wisconsin.

The first complaint requested a reduction in base ROE transmission formula rates from 12.38 % to 9.15 % for the time period of Nov.

12, 2013 to Feb.

11, 2015, and removal of ROE adders (including those for RTO membership).

The second complaint requested, for a subsequent time period, a base ROE reduction from 12.38 % to 8.67 %.

The FERC subsequently issued various related orders related to ROE methodology/calculations and timing.

NSP-Minnesota has processed refunds to customers for applicable complaint periods based on the ROE in the most recent applicable opinions.

The MISO TOs and various other parties have filed petitions for review of the FERC’s most recent applicable opinions at the D.C.

In August 2022, the D.C.

Circuit ruled that FERC had not adequately supported its conclusions, vacated FERC’s related orders and remanded the issue back to FERC for further proceedings, which remain pending.

Additional exposure, if any related to this matter is expected to be immaterial.

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.

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.

Environmental

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Xcel Energy is investigating, remediating or performing post-closure actions at 13 historical MGP, landfill or other disposal sites across its service territories, excluding sites that are being addressed under current coal ash regulations (see below).

Xcel Energy has recognized approximately $ 20 million of costs/liabilities from final resolution of these issues;

however, the outcome and timing are unknown.

In addition, there may be insurance recovery and/or recovery from other potentially responsible parties, offsetting a portion of costs incurred.

Xcel Energy has approximately $ 20 million of remaining liabilities for resolution of these issues, however, the final outcome and timing are unknown.

In addition, there may be regulatory recovery, insurance recovery and/or recovery from other potentially responsible parties, offsetting a portion of costs incurred.

Environmental Requirements — Water and Waste

Coal Ash Regulation — Xcel Energy’s operations are subject to federal and state regulations that impose requirements for handling, storage, treatment and disposal of solid waste, including the CCR Rule.

As a specific requirement of the CCR Rule, utilities must complete groundwater sampling around their applicable landfills and surface impoundments as well as perform corrective actions where offsite groundwater has been impacted.

Coal Ash Regulation — Xcel Energy is subject to the CCR Rule, which imposes requirements for handling, storage, treatment and disposal of coal ash and other solid waste.

In May 2024, final amendments to the CCR Rule were published, widening its scope to include legacy CCR surface impoundments at inactive facilities and previously exempt areas where CCR was placed directly on land at CCR-regulated facilities, including areas of beneficial use.

As a requirement of the CCR Rule, utilities must complete facility evaluations and groundwater sampling around their subject landfills, surface impoundments and certain other areas where coal ash was placed on land.

If certain impacts to groundwater are detected, utilities are required to perform additional groundwater investigations and/or perform corrective actions beginning with an Assessment of Corrective Measures.

Investigation and/or corrective action related to groundwater impacts are currently underway at four Xcel Energy sites under the federal CCR program at a current estimated cost of at least $ 40 million.

A liability has been recorded and is expected to be fully recoverable through regulatory mechanisms.

For required coal ash disposal, PSCo has executed an agreement with a third party that will excavate and process ash for beneficial use (at two sites) at a cost of approximately $ 45 million.

An estimated liability has been recorded and amounts are expected to be fully recoverable through regulatory mechanisms.

Federal Clean Water Act Section 316(b) — The Federal Clean Water Act requires the EPA to regulate cooling water intake structures to assure they reflect the best technology available for minimizing impingement and entrainment of aquatic species.

Investigation and/or corrective action related to groundwater impacts are currently underway at certain active and closed coal-generating facilities at a current estimated cost of at least $ 45 million.

In addition, Xcel Energy expects to incur $ 15 million for investigations through 2028 to perform required reporting and assess whether corrective actions are necessary.

AROs have been recorded for each of these activities, and amounts are expected to be recoverable through regulatory mechanisms.

Xcel Energy has also identified coal ash that is expected to be required to be removed from certain closed coal-fueled generating facilities at estimated costs totaling approximately $ 100 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.

Clean Water Act Section 316(b) — The Federal Clean Water Act requires the EPA to regulate cooling water intake structures to assure they reflect the best technology available for minimizing impingement and entrainment of aquatic species.

Estimated capital expenditures of approximately $ 50 million may be required to comply with the requirements.

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The final rule applies to generation facilities in Minnesota, Texas and Wisconsin, as well as other states outside of our service territory.

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

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.

Guidelines are also established for allowance banking and emission limit backstops.

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

SPS and NSP-Minnesota have joined other companies in litigation challenging the EPA’s disapproval of Texas and Minnesota state implementation plans.

Currently, the regulation is under a judicial stay for both Texas and Minnesota.

The regulation may become applicable in those states in the future, depending on the outcome of the litigation.

The rule is in effect in NSP-Wisconsin but has been managed without the additional need for allowances.

In February 2024, the EPA proposed to partially disapprove New Mexico’s state implementation plan and bring New Mexico into the federal Good Neighbor plan.

Xcel Energy continues to evaluate impacts to generation units at SPS.

Regional Haze Rules — The EPA has proposed rules addressing Regional Haze compliance in Texas, which address requirements for reasonable progress at Tolk and BART at Harrington.

As proposed, these rules would not require additional controls at either facility, in part due to the conversion of Harrington to gas in 2025 and the planned retirement of Tolk.

These rules will be monitored until final versions are published.

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.

AROs — AROs have been recorded for Xcel Energy’s assets.

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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.

of Dollars) Jan.

1, 2023 Amounts Incurred (a)

Accretion Cash Flow Revisions (b)

Settled Accretion Cash Flow Revisions (b)

Nuclear $ 2,160 $ — $ — $ 105 $ ( 158 ) $ 2,107

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Distribution 48 — — 1 — 49

Transmission and distribution (c)

279 — 12 16 307

Transmission and distribution 307 — — 14 ( 149 ) 172

Miscellaneous 3 — — — — 3

Total liability $ 3,380 $ 10 $ ( 1 ) $ 154 $ ( 325 ) $ 3,218

(a) Amounts incurred related to the wind farms placed in service in 2022 for NSP-Minnesota (Dakota Range and Rock Aetna) and steam production pond remediation costs for PSCo.

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

(b) In 2023, AROs were revised for changes in timing and estimates of cash flows.

Revisions in steam, hydro and other production AROs were primarily related to changes in cost estimates for remediation of ash containment facilities.

Changes in gas transmission and distribution AROs were primarily related to changes in labor rates coupled with increased gas line mileage and number of services.

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.

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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Maximum assessments are subject to inflation adjustments.

NSP-Minnesota purchases insurance for property damage and site decontamination cleanup costs from NEIL and EMANI.

The coverage limits are $ 2.8 billion for each of NSP-Minnesota’s two nuclear plant sites.

NSP-Minnesota purchases insurance for property damage and site decontamination cleanup costs from NEIL and EMANI for each of NSP-Minnesota’s two nuclear plant sites.

The coverage limits are $ 2.8 billion for both Monticello and Prairie Island.

NEIL also provides business interruption insurance coverage up to $ 490 million and $ 420 million at Monticello and Prairie Island, respectively, including the cost of replacement power during prolonged accidental outages of nuclear generating units.

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nuclear plants, but no such facility is yet available.

NSP-Minnesota owns temporary on-site storage facilities for spent fuel at its Monticello and PI nuclear plants, which consist of storage pools and dry cask facilities.

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.

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

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

The PI dry-cask storage facility currently stores 50 of the 64 authorized casks.

In February 2023, NSP-Minnesota filed a CON with the MPUC for additional storage at PI to support possible life extension to 2054.

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.

Regulatory Plant Decommissioning Recovery — Decommissioning activities for NSP-Minnesota’s nuclear facilities are planned to begin at the end of each unit’s authorized retirement dates, which can be different than the currently approved NRC operating licenses.

These decommissioning activities are planned to be completed at both facilities by 2101.

NSP-Minnesota’s current operating licenses allow continued use of its Monticello nuclear plant until 2030 and its PI nuclear plant until 2033 for Unit 1 and 2034 for Unit 2.

The MPUC reaffirmed a 60-year DECON scenario, where Monticello continues operations under a 10-year license extension (approved in August 2022).

NRC approval of the extension is pending.

In February 2023, NSP-Minnesota also filed an application with the NDPSC for an Advance Determination of Prudence for continued operation of the Monticello Plant until at least 2040.

A decision is expected in 2024.

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.

Future decommissioning costs of nuclear facilities are estimated through triennial periodic studies that assess the costs and timing of planned nuclear decommissioning activities for each unit.

The MPUC ordered the next triennial decommissioning study be filed by Dec.

The most recent triennial decommissioning study was filed in December 2024.

Obligations for decommissioning are expected to be funded 100 % by the external decommissioning trust fund.

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

A contract determined to contain a lease is evaluated further to determine if the arrangement is a finance lease.

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 liabilities and noncurrent operating lease liabilities.

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.

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

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.

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

The utility subsidiaries had approximately 3,751 MW and 3,961 MW of capacity under long-term PPAs at Dec.

31, 2023 and 2022, respectively, with entities that have been determined to be VIEs.

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.

These agreements have expiration dates through 2048.

Fuel Contracts — SPS purchases all of its coal requirements for its Harrington and Tolk plants from TUCO Inc.

under contracts that will expire in December 2024 and December 2027, respectively.

Fuel Contracts — SPS purchases all of its coal requirements for its Tolk plant from TUCO Inc.

under contracts that will expire in December 2027.

TUCO arranges for the purchase, receiving, transporting, unloading, handling, crushing, weighing and delivery of coal to meet SPS’ requirements.

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31, 2024, and $ 41 million of assets and $ 35 million of liabilities at Dec.

Technology Agreements — Xcel Energy has several contracts for information technology services that extend through 2027.

The contracts are cancelable, although there are financial penalties for early termination.

Xcel Energy capitalized or expensed $ 28 million, $ 181 million and $ 103 million associated with these vendors in 2023, 2022 and 2021, respectively.

Committed minimum payments under these obligations as follows:

(Millions of Dollars) Minimum Payments

Guarantees and Bond Indemnifications — Xcel Energy Inc.

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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:

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Amortization of net actuarial loss — 5 (b)

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

Net current period other comprehensive income 24 2 26

Accumulated other comprehensive loss at Dec.

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1 $ ( 54 ) $ ( 39 ) $ ( 93 )

Other comprehensive gain before reclassifications 16 5 21

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

Losses reclassified from net accumulated other comprehensive loss:

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Amortization of net actuarial loss — 2 (b)

Net current period other comprehensive income 21 9 30

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

Accumulated other comprehensive loss at Dec.

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Segment Information

Xcel Energy evaluates performance by each utility subsidiary based on profit or loss generated from the product or service provided, including the regulated electric utility operating results of NSP-Minnesota, NSP-Wisconsin, PSCo and SPS, as well as the regulated natural gas utility operating results of NSP-Minnesota, NSP-Wisconsin and PSCo.

These segments are managed separately because the revenue streams are dependent upon regulated rate recovery, which is separately determined for each segment.

Xcel Energy’s chief operating decision maker, the CEO, sets financial performance objectives and budgets and establishes separate targets for the regulated electric utility net income of NSP-Minnesota, NSP-Wisconsin, PSCo and SPS, as well as the regulated natural gas utility net income of NSP-Minnesota, NSP-Wisconsin and PSCo.

The regulated electric utility and regulated natural gas utility segments are managed separately because of inherent differences between activities to serve electric customers and those required to serve natural gas customers, and as the revenue streams are dependent upon regulated rate recovery, which is separately determined for each segment.

The CEO assesses financial performance, including quarterly and annual budget-to-actual and year-over-year variances in revenues and expenses, to inform operating decisions, capital investments and cost recovery strategies.

Xcel Energy has the following reportable segments:

• Regulated Electric — The regulated electric utility segment generates, purchases, transmits, distributes and sells electricity in Colorado, Michigan, Minnesota, New Mexico, North Dakota, South Dakota, Texas and Wisconsin.

• Regulated Electric Utility — The regulated electric utility segment generates, purchases, transmits, distributes and sells electricity in Colorado, Michigan, Minnesota, New Mexico, North Dakota, South Dakota, Texas and Wisconsin;

each state’s regulated electric utility activities qualify as an operating segment, and is aggregated into Xcel Energy’s regulated electric utility segment.

In addition, this segment includes sales for resale and provides wholesale transmission service to various entities in the United States.

The regulated electric utility segment also includes wholesale commodity and trading operations.

• Regulated Natural Gas — The regulated natural gas utility segment purchases, transports, stores, distributes and sells natural gas primarily in portions of Colorado, Michigan, Minnesota, North Dakota and Wisconsin.

Xcel Energy also presents All Other, which includes operating segments with revenues below the necessary quantitative thresholds.

Those operating segments primarily include steam revenue, appliance repair services, non-utility real estate activities, revenues associated with processing solid waste into RDF, investments in rental housing projects that qualify for low-income housing tax credits and equity method investments in EIP funds.

Xcel Energy had equity method investments of $ 244 million and $ 219 million as of Dec.

31, 2023 and 2022, respectively, included in the natural gas utility and all other segments.

• Regulated Natural Gas Utility — The regulated natural gas utility segment purchases, transports, stores, distributes and sells natural gas primarily in portions of Colorado, Michigan, Minnesota, North Dakota and Wisconsin;

each state’s regulated natural gas utility activities qualify as an operating segment, and is aggregated into Xcel Energy’s regulated natural gas utility segment.

Equity method investments in the regulated natural gas utility segment of $85 million and $92 million at Dec.

31, 2024 and 2023, respectively, primarily relate to WYCO.

Non-segment equity method investments of $161 million and $152 million as of Dec.

31, 2024 and 2023, respectively, relate to investments in energy technology funds.

Asset and capital expenditure information is not provided for Xcel Energy’s reportable segments.

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In addition, a general allocator is used for certain general and administrative expenses, including office supplies, rent, property insurance and general advertising.

Xcel Energy’s segment information:

(Millions of Dollars) 2023 2022 2021

Regulated Electric

Operating revenues — external $ 11,446 $ 12,123 $ 11,205

Other segment expenses, net, for the reportable segments includes conservation and DSM expenses, taxes (other than income taxes), other income (expense), net, earnings from equity method investments, intersegment expenses and AFUDC - equity.

Non-segment revenues include steam, appliance repair and non-utility real estate activities and revenues associated with processing solid waste into RDF and from investments in rental housing projects that qualify for low-income housing tax credits.

Non-segment net loss also includes costs associated with these activities as well as unallocated corporate O&M expenses, interest charges and income taxes as well as earnings from equity method investments in energy technology funds.

Segment information and reconciliations to Xcel Energy’s consolidated operating revenues and net income:

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

Operating revenues $ 11,147 $ 2,230 $ 13,377

Intersegment revenue 2 22 24

Total revenues $ 11,448 $ 12,125 $ 11,207

Total segment revenues 11,149 2,252 13,401

Electric fuel and purchased power 3,788 — 3,788

Cost of natural gas sold and transported — 951 951

O&M expenses 2,102 409 2,511

Depreciation and amortization 2,373 357 2,730

Other segment expenses, net 693 123 816

Interest charges and financing costs 767 113 880

Income tax benefit ( 135 ) ( 162 ) ( 96 )

Income tax (benefit) expense ( 420 ) 62 ( 358 )

Net income $ 1,846 $ 237 $ 2,083

Regulated Natural Gas

Operating revenues — external $ 2,645 $ 3,080 $ 2,132

Total segment revenues $ 13,401

Eliminate intersegment revenue ( 24 )

Non-segment revenues 64

Consolidated operating revenues $ 13,441

Total segment net income $ 2,083

Non-segment net loss ( 147 )

Consolidated net income $ 1,936

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

Operating revenues $ 11,446 $ 2,645 $ 14,091

Intersegment revenue 2 3 5

Total revenues $ 2,648 $ 3,082 $ 2,134

Total segment revenues 11,448 2,648 14,096

Electric fuel and purchased power 4,278 — 4,278

Cost of natural gas sold and transported — 1,456 1,456

O&M expenses 2,011 386 2,397

Depreciation and amortization 2,111 323 2,434

Other segment expenses, net (a)

Interest charges and financing costs 670 96 766

Income tax expense 50 68 54

Income tax (benefit) expense ( 135 ) 50 ( 85 )

Net income $ 1,686 $ 219 $ 1,905

Total revenues $ 115 $ 107 $ 94

Depreciation and amortization 14 15 12

Interest charges and financing costs 238 203 173

Income tax benefit ( 61 ) ( 41 ) ( 28 )

Net loss ( 134 ) ( 159 ) ( 112 )

Consolidated Total

Total revenues $ 14,211 $ 15,314 $ 13,435

Reconciling eliminations ( 5 ) ( 4 ) ( 4 )

Total operating revenues $ 14,206 $ 15,310 $ 13,431

Total segment revenues $ 14,096

Eliminate intersegment revenue ( 5 )

Non-segment revenues 115

Consolidated operating revenues $ 14,206

Total segment net income $ 1,905

Non-segment net loss ( 134 )

Consolidated net income $ 1,771

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

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

Operating revenues $ 12,123 $ 3,080 $ 15,203

Intersegment revenue 2 2 4

Total segment revenues 12,125 3,082 15,207

Electric fuel and purchased power 5,005 — 5,005

Cost of natural gas sold and transported — 1,910 1,910

O&M expenses 2,069 370 2,439

Depreciation and amortization 2,122 276 2,398

Other segment expenses, net 824 108 932

Interest charges and financing costs 636 86 722

Income tax benefit ( 146 ) ( 135 ) ( 70 )

Income tax (benefit) expense ( 162 ) 68 ( 94 )

Net income $ 1,631 $ 264 $ 1,895

Total segment revenues $ 15,207

Eliminate intersegment revenue ( 4 )

Non-segment revenues 107

Consolidated operating revenues $ 15,310

Total segment net income $ 1,895

Non-segment net loss ( 159 )

Consolidated net income $ 1,736

Workforce Reduction

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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.

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.

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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