Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

See Item 15-1 for an index of financial statements included herein.

See Note 15 to the consolidated financial statements for further information.

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Management Report on Internal Control Over Financial Reporting

The management of Xcel Energy Inc. is responsible for establishing and maintaining adequate internal control over financial reporting. Xcel Energy Inc.’s internal control system was designed to provide reasonable assurance to Xcel Energy Inc.’s management and Board of Directors regarding the preparation and fair presentation of published financial statements.

All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation.

Xcel Energy Inc. management assessed the effectiveness of Xcel Energy Inc.’s internal control over financial reporting as of Dec. 31, 2024. In making this assessment, it used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control — Integrated Framework (2013). Based on our assessment, we believe that, as of Dec. 31, 2024, Xcel Energy Inc.’s internal control over financial reporting is effective at the reasonable assurance level based on those criteria.

Xcel Energy Inc.’s independent registered public accounting firm has issued an attestation report on Xcel Energy Inc.’s internal control over financial reporting. Its report appears herein.

/s/ ROBERT C. FRENZEL									/s/ BRIAN J. VAN ABEL
Robert C. Frenzel									Brian J. Van Abel
Chairman, President, Chief Executive Officer and Director									Executive Vice President, Chief Financial Officer
Feb. 27, 2025									Feb. 27, 2025

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the stockholders and the Board of Directors of Xcel Energy Inc.

Opinions on the Financial Statements and Internal Control over Financial Reporting

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

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2024 and 2023, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2024, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2024, based on criteria established in Internal Control — Integrated Framework (2013) issued by COSO.

Basis for Opinions

The Company’s management is responsible for these financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management Report on Internal Controls over Financial Reporting. Our responsibility is to express an opinion on these financial statements and an opinion on the Company’s internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects.

Our audits of the financial statements included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures to respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

Definition and Limitations of Internal Control over Financial Reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. 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.

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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.

Critical Audit Matter Description

The Company is subject to rate regulation by state utility regulatory agencies, which have jurisdiction with respect to the rates of electric and natural gas distribution companies in Minnesota, North Dakota, South Dakota, Wisconsin, Michigan, Colorado, New Mexico, and Texas. The Company is also subject to the jurisdiction of the Federal Energy Regulatory Commission for its wholesale electric operations, hydroelectric generation licensing, accounting practices, wholesale sales for resale, transmission of electricity in interstate commerce, compliance with North American Electric Reliability Corporation standards, asset transactions and mergers and natural gas transactions in interstate commerce, (collectively with state utility regulatory agencies, the “Commissions”). Management has determined it meets the requirements under accounting principles generally accepted in the United States of America to prepare its financial statements applying the specialized rules to account for the effects of cost-based rate regulation. Accounting for the economics of rate regulation affects multiple financial statement line items and disclosures, including property, plant and equipment, regulatory assets and liabilities, operating revenues and expenses, and income taxes.

The Company is subject to regulatory rate setting processes. Rates are determined and approved in regulatory proceedings based on an analysis of the Company’s costs to provide utility service and a return on, and recovery of, the Company’s investment in assets required to deliver services to customers. Accounting for the Company’s regulated operations provides that rate-regulated entities report assets and liabilities consistent with the recovery of those incurred costs in rates, if it is probable that such rates will be charged and collected. The Commissions’ regulation of rates is premised on the full recovery of incurred costs and a reasonable rate of return on invested capital. Decisions by the Commissions in the future will impact the accounting for regulated operations, including decisions about the amount of allowable costs and return on invested capital included in rates and any refunds that may be required. In the rate setting process, the Company’s rates result in the recording of regulatory assets and liabilities based on the probability of future cash flows. Regulatory assets generally represent incurred or accrued costs that have been deferred because future recovery from customers is probable. Regulatory liabilities generally represent amounts that are expected to be refunded to customers in future rates or amounts collected in current rates for future costs.

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 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.

How the Critical Audit Matter Was Addressed in the Audit

Our audit procedures related to the uncertainty of future decisions by the Commissions included the following, among others:

• We tested the effectiveness of management’s controls over the evaluation of the likelihood of (1) the recovery in future rates of costs deferred as regulatory assets, and (2) a refund or a future reduction in rates that should be reported as regulatory liabilities. We also tested the effectiveness of management’s controls over the recognition of regulatory assets or liabilities and the monitoring and evaluation of regulatory developments that may affect the likelihood of recovering costs in future rates or of a future reduction in rates.

• We evaluated the Company’s disclosures related to the impacts of rate regulation, including the balances recorded and regulatory developments.

• We read relevant regulatory orders issued by the Commissions for the Company, other regulatory filings, legal decisions and recommendations being evaluated by the Commissions, and other publicly available information to assess the likelihood of recovery in future rates or of a future reduction in rates. We evaluated historic orders for precedents of the Commissions’ treatment of similar costs under similar circumstances. We compared the regulatory orders, filings and other publicly available information to the Company’s recorded regulatory assets and liabilities for completeness.

• 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.

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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
Minneapolis, Minnesota
February 27, 2025
We have served as the Company’s auditor since 2002.

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XCEL ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

(amounts in millions, except per share data)

						Year Ended Dec. 31
						2024						2023						2022
Operating revenues
Electric						$	11,147					$	11,446					$	12,123
Natural gas						2,230						2,645						3,080
Other						64						115						107
Total operating revenues						13,441						14,206						15,310
Operating expenses
Electric fuel and purchased power						3,788						4,278						5,005
Cost of natural gas sold and transported						951						1,456						1,910
Cost of sales — other						14						49						44
Operating and maintenance expenses						2,540						2,444						2,491
Conservation and demand side management expenses						394						286						331
Depreciation and amortization						2,744						2,448						2,413
Taxes (other than income taxes)						624						657						688
Loss on Comanche Unit 3 litigation						—						35						—
Workforce reduction expenses						—						72						—
Total operating expenses						11,055						11,725						12,882
Operating income						2,386						2,481						2,428
Other income (expense), net						143						22						(13)
Earnings from equity method investments						19						35						36
Allowance for funds used during construction — equity						168						91						75
Interest charges and financing costs
Interest charges — includes other financing costs						1,255						1,055						953
Allowance for funds used during construction — debt						(73)						(51)						(28)
Total interest charges and financing costs						1,182						1,004						925
Income before income taxes						1,534						1,625						1,601
Income tax benefit						(402)						(146)						(135)
Net income						$	1,936					$	1,771					$	1,736
Weighted average common shares outstanding:
Basic						563						552						547
Diluted						563						552						547
Earnings per average common share:
Basic						$	3.44					$	3.21					$	3.18
Diluted						3.44						3.21						3.17
See Notes to Consolidated Financial Statements

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XCEL ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(amounts in millions)

						Year Ended Dec. 31
						2024						2023						2022
Net income						$	1,936					$	1,771					$	1,736
Other comprehensive income
Pension and retiree medical benefits:
Net pension and retiree medical (losses) gains arising during the period, net of tax						(3)						(4)						5
Reclassification of losses to net income, net of tax						5						2						4
Derivative instruments:
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 income (loss)						26						(1)						30
Total comprehensive income						$	1,962					$	1,770					$	1,766
See Notes to Consolidated Financial Statements

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XCEL ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(amounts in millions)

			Year Ended Dec. 31
			2024						2023						2022
Operating activities
Net income			$	1,936					$	1,771					$	1,736
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization			2,769						2,471						2,436
Nuclear fuel amortization			106						96						118
Deferred income taxes			225						(59)						(140)
Allowance for equity funds used during construction			(168)						(91)						(75)
Earnings from equity method investments			(19)						(35)						(36)
Dividends from equity method investments			34						35						37
Provision for bad debts			47						79						73
Share-based compensation expense			33						25						20
Changes in operating assets and liabilities:
Accounts receivable			19						(27)						(429)
Accrued unbilled revenues			21						252						(243)
Inventories			(140)						(98)						(203)
Other current assets			(139)						86						(58)
Accounts payable			37						(149)						195
Net regulatory assets and liabilities			436						911						570
Other current liabilities			(317)						200						102
Pension and other employee benefit obligations			(89)						17						(49)
Other, net			(150)						(157)						(122)
Net cash provided by operating activities			4,641						5,327						3,932
Investing activities
Capital/construction expenditures			(7,364)						(5,854)						(4,638)
Purchase of investment securities			(998)						(994)						(1,332)
Proceeds from the sale of investment securities			961						959						1,297
Other, net			(27)						(37)						20
Net cash used in investing activities			(7,428)						(5,926)						(4,653)
Financing activities
Repayments of short-term borrowings, net			(90)						(28)						(192)
Proceeds from issuances of long-term debt			3,647						2,630						2,164
Repayments of long-term debt			(656)						(1,151)						(601)
Proceeds from issuance of common stock			1,117						270						322
Dividends paid			(1,175)						(1,092)						(1,012)
Other, net			(6)						(12)						(15)
Net cash provided by financing activities			2,837						617						666
Net change in cash and cash equivalents			50						18						(55)
Cash, cash equivalents and restricted cash at beginning of period			129						111						166
Cash, cash equivalents and restricted cash at end of period			$	179					$	129					$	111
Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized)			$	(1,131)					$	(945)					$	(887)
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:
Accrued property, plant and equipment additions			$	964					$	553					$	626
Inventory transfers to property, plant and equipment			258						197						78
Operating lease right-of-use assets			138						238						141
Allowance for equity funds used during construction			168						91						75
Issuance of common stock for reinvested dividends and/or equity awards			68						64						57
See Notes to Consolidated Financial Statements

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XCEL ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(amounts in millions, except share and per share)

						Dec. 31
						2024						2023
Assets
Current assets
Cash and cash equivalents						$	179					$	129
Accounts receivable, net						1,249						1,315
Accrued unbilled revenues						832						853
Inventories						666						711
Regulatory assets						561						611
Derivative instruments						114						104
Prepaid taxes						72						52
Prepayments and other						652						294
Total current assets						4,325						4,069
Property, plant and equipment, net						57,198						51,642
Other assets
Nuclear decommissioning fund and other investments						3,896						3,599
Regulatory assets						2,849						2,798
Derivative instruments						72						76
Operating lease right-of-use assets						1,060						1,217
Other						635						678
Total other assets						8,512						8,368
Total assets						$	70,035					$	64,079
Liabilities and Equity
Current liabilities
Current portion of long-term debt						$	1,103					$	552
Short-term debt						695						785
Accounts payable						1,781						1,668
Regulatory liabilities						852						528
Taxes accrued						535						557
Accrued interest						280						251
Dividends payable						314						289
Derivative instruments						37						74
Operating lease liabilities						227						226
Other						635						722
Total current liabilities						6,459						5,652
Deferred credits and other liabilities
Deferred income taxes						5,319						4,885
Deferred investment tax credits						40						60
Regulatory liabilities						6,010						5,827
Asset retirement obligations						3,713						3,218
Derivative instruments						77						86
Customer advances						146						167
Pension and employee benefit obligations						477						469
Operating lease liabilities						867						1,038
Other						89						148
Total deferred credits and other liabilities						16,738						15,898
Commitments and contingencies
Capitalization
Long-term debt						27,316						24,913
Common stock — 1,000,000,000 shares authorized of $2.50 par value; 574,365,598 and 554,941,703 shares outstanding at Dec. 31, 2024 and Dec. 31, 2023, respectively						1,436						1,387
Additional paid in capital						9,601						8,465
Retained earnings						8,553						7,858
Accumulated other comprehensive loss						(68)						(94)
Total common stockholders’ equity						19,522						17,616
Total liabilities and equity						$	70,035					$	64,079
See Notes to Consolidated Financial Statements

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XCEL ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS’ EQUITY

(amounts in millions, except per share data; shares in actual amounts)

			Common Stock Issued																		Retained Earnings						Accumulated Other Comprehensive Loss						Total Common Stockholders’ Equity
			Shares						Par Value						Additional Paid In Capital
Balance at Dec. 31, 2021			544,025,269						$	1,360					$	7,803					$	6,572					$	(123)					$	15,612
Net income																					1,736												1,736
Other comprehensive income																											30						30
Dividends declared on common stock ($1.95 per share)																					(1,066)												(1,066)
Issuances of common stock			5,552,749						14						345																		359
Share-based compensation															7						(3)												4
Balance at Dec. 31, 2022			549,578,018						$	1,374					$	8,155					$	7,239					$	(93)					$	16,675
Net Income																					1,771												1,771
Other comprehensive loss																											(1)						(1)
Dividends declared on common stock ($2.08 per share)																					(1,148)												(1,148)
Issuances of common stock			5,363,685						13						295																		308
Share-based compensation															15						(4)												11
Balance at Dec. 31, 2023			554,941,703						$	1,387					$	8,465					$	7,858					$	(94)					$	17,616
Net income																					1,936												1,936
Other comprehensive income																											26						26
Dividends declared on common stock ($2.19 per share)																					(1,236)												(1,236)
Issuances of common stock			19,423,895						49						1,098																		1,147
Share-based compensation															38						(5)												33
Balance at Dec. 31, 2024			574,365,598						$	1,436					$	9,601					$	8,553					$	(68)					$	19,522
See Notes to Consolidated Financial Statements

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XCEL ENERGY INC. AND SUBSIDIARIES

Notes to Consolidated Financial Statements

1. Summary of Significant Accounting Policies

General — Xcel Energy Inc.’s utility subsidiaries are engaged in the regulated generation, purchase, transmission, distribution and sale of electricity and the regulated purchase, transportation, distribution and sale of natural gas.

Xcel Energy’s regulated operations include the activities of NSP-Minnesota, NSP-Wisconsin, PSCo and SPS. These utility subsidiaries serve electric and natural gas customers in portions of Colorado, Michigan, Minnesota, New Mexico, North Dakota, South Dakota, Texas and Wisconsin. Also included in regulated operations are WGI, an interstate natural gas pipeline company, and WYCO, a joint venture with CIG to develop and lease natural gas pipeline, storage and compression facilities.

Xcel Energy Inc.’s nonregulated subsidiaries include:

Nonregulated Subsidiary						Purpose
Eloigne						Invests in rental housing projects that qualify for low-income housing tax credits.
Capital Services						Procures equipment for construction of renewable generation facilities at other subsidiaries.
Xcel Energy Venture Holdings, Inc.						Invests in limited partnerships, including funds with portfolios of investments in energy technology companies.
Nicollet Project Holdings						Invests in nonregulated assets such as the Minnesota community solar gardens.

Xcel Energy Inc. owns the following additional direct subsidiaries, some of which are intermediate holding companies with additional subsidiaries:

Direct Subsidiary
Xcel Energy Wholesale Group Inc.
Xcel Energy Markets Holdings Inc.
Xcel Energy Ventures Inc.
Xcel Energy Retail Holdings Inc.
Xcel Energy Communication Group Inc.
Xcel Energy International Inc.
Xcel Energy Transmission Holding Company, LLC
Nicollet Holdings Company, LLC
Xcel Energy Nuclear Services Holdings, LLC
Xcel Energy Services Inc.

Xcel Energy and its subsidiaries collectively are referred to as Xcel Energy.

Xcel Energy’s consolidated financial statements include its wholly-owned subsidiaries and VIEs for which it is the primary beneficiary. All intercompany transactions and balances are eliminated unless a different treatment is appropriate for rate regulated transactions. The equity method of accounting is used for its investments in energy technology funds and WYCO.

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

The consolidated financial statements are presented in accordance with GAAP. All of the utility subsidiaries’ underlying accounting records also conform to the FERC uniform system of accounts.

Certain amounts in the consolidated financial statements or notes have been reclassified for comparative purposes; however, such reclassifications did not affect net income, total assets, liabilities, equity or cash flows.

Xcel Energy has evaluated events occurring after Dec. 31, 2024 up to the date of issuance of these consolidated financial statements. These statements contain all necessary adjustments and disclosures resulting from that evaluation.

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

Estimates are used for items such as plant depreciable lives or potential disallowances, AROs, certain regulatory assets and liabilities, tax provisions, uncollectible amounts, environmental costs, unbilled revenues, jurisdictional fuel and energy cost allocations, actuarially determined benefit costs and wildfire contingencies. Recorded estimates are revised when better information becomes available or actual amounts can be determined. Revisions can affect operating results.

Regulatory Accounting — The regulated utility subsidiaries account for income and expense items in accordance with accounting guidance for regulated operations. Under this guidance:

• Certain costs, which would otherwise be charged to expense or other comprehensive income, are deferred as regulatory assets based on the expected ability to recover the costs in future rates.

• Certain credits, which would otherwise be reflected as income or other comprehensive income, are deferred as regulatory liabilities based on the expectation the amounts will be returned to customers in future rates, or because the amounts were collected in rates prior to the costs being incurred.

Estimates and assumptions for recovery of deferred costs and refund of deferred credits are based on specific ratemaking decisions, precedent or other available information. Regulatory assets and liabilities are amortized consistent with the treatment in the rate setting process.

If changes in the regulatory environment occur, the utility subsidiaries may no longer be eligible to apply this accounting treatment and may be required to eliminate regulatory assets and liabilities. Such changes could have a material effect on Xcel Energy’s results of operations, financial condition and cash flows.

See Note 4 for further information.

Income Taxes — Xcel Energy accounts for income taxes using the asset and liability method, which requires recognition of deferred tax assets and liabilities for the expected future tax consequences of events that have been included in the consolidated financial statements. Income taxes are deferred for all temporary differences between pretax financial and taxable income and between the book and tax bases of assets and liabilities utilizing rates that are scheduled to be in effect when the temporary differences are expected to reverse. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in the period that includes the enactment date.

Utility rate regulation has resulted in the recognition of regulatory assets and liabilities related to income taxes. The effects of tax rate changes that are attributable to the utility subsidiaries are generally subject to a normalization method of accounting. Therefore, the revaluation of most of the utility subsidiaries’ net deferred taxes upon a tax rate reduction results in the establishment of a net regulatory liability, refundable to utility customers over the remaining life of the related assets.

Xcel Energy anticipates that a tax rate increase would predominantly result in the establishment of a regulatory asset, subject to an evaluation of whether future recovery is expected.

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

Tax credits are recorded when earned unless there is a requirement to defer the benefit and amortize over the book depreciable lives of related property. The requirement to defer and amortize these credits specifically applies to certain federal ITCs, as determined by tax regulations and Xcel Energy tax elections. For tax credits otherwise eligible to be recognized when earned, Xcel Energy considers the impact of rate regulation to determine if these credits and related adjustments should be deferred as regulatory assets or liabilities.

Deferred tax assets are reduced by a valuation allowance if it is more likely than not that some portion or all of the deferred tax asset will not be realized. This evaluation includes consideration of whether tax credits are expected to be sold at a discount and impact the realization of amounts presented as deferred tax assets. Transferable tax credits are accounted for under ASC 740, Income Taxes, and valuation allowances and any adjustments for discounts incurred on sales transactions are recorded to deferred tax expense, typically recovered in the utility subsidiaries’ regulatory mechanisms.

Xcel Energy measures and discloses uncertain tax positions that it has taken or expects to take in its income tax returns. A tax position is recognized in the consolidated financial statements when it is more likely than not that the position will be sustained upon examination based on the technical merits of the position. Recognition of changes in uncertain tax positions are reflected as a component of income tax expense.

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

Xcel Energy Inc. and its subsidiaries file consolidated federal income tax returns as well as consolidated or separate state income tax returns. Federal income taxes paid by Xcel Energy Inc. are allocated to its subsidiaries based on separate company computations. A similar allocation is made for state income taxes paid by Xcel Energy Inc. in connection with consolidated state filings. Xcel Energy Inc. also allocates its own income tax benefits to its direct subsidiaries.

See Note 7 for further information.

Property, Plant and Equipment and Depreciation in Regulated Operations — Property, plant and equipment is stated at original cost. The cost of plant includes direct labor and materials, contracted work, overhead costs and AFUDC. The cost of plant retired is charged to accumulated depreciation and amortization. Amounts recovered in rates for future removal costs are recorded as regulatory liabilities. Significant additions or improvements extending asset lives are capitalized, while repairs and maintenance costs and replacement of items determined to be less than a unit of property are charged to expense as incurred.

Property, plant and equipment is tested for impairment when it is determined that the carrying value of the assets may not be recoverable. A loss is recognized in the current period if it becomes probable that part of a cost of a plant under construction or recently completed plant will be disallowed for recovery from customers and a reasonable estimate of the disallowance can be made.

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

Depreciation expense is recorded using the straight-line method over the plant’s commission approved useful life. Actuarial life studies are performed and submitted to the state and federal commissions for review. Upon acceptance by the various commissions, the resulting lives and net salvage rates are used to calculate depreciation. Plant removal costs are typically recognized at the amounts recovered in rates as authorized by the applicable regulator. Accumulated removal costs are reflected in the consolidated balance sheet as a regulatory liability. Depreciation expense, expressed as a percentage of average depreciable property, was approximately 3.8% for 2024, 3.6% for 2023 and 3.7% for 2022.

See Note 3 for further information.

AROs — Xcel Energy records AROs as a liability in the period incurred (if fair value can be reasonably estimated), with the offsetting/associated costs capitalized as a long-lived asset. The liability is generally increased over time by applying the effective interest method of accretion and the capitalized costs are typically depreciated over the useful life of the long-lived asset. Changes resulting from revisions to timing or amounts of expected asset retirement cash flows are recognized as an increase or a decrease in the ARO.

See Note 12 for further information.

Nuclear Decommissioning — Nuclear decommissioning studies that estimate NSP-Minnesota’s costs of decommissioning its nuclear power plants are normally performed at least every three years and submitted to the state commissions for approval. The latest decommissioning study was 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. The studies consider estimated future costs of decommissioning and the market value of investments in trust funds and recommend annual funding amounts. Amounts collected in rates are deposited in the trust funds. For financial reporting purposes, NSP-Minnesota accounts for nuclear decommissioning as an ARO.

Restricted funds for future decommissioning expenditures for NSP-Minnesota’s nuclear facilities are included in nuclear decommissioning fund and other assets on the consolidated balance sheets.

See Notes 10 and 12 for further information.

Benefit Plans and Other Postretirement Benefits — Xcel Energy maintains pension and postretirement benefit plans for eligible employees. Recognizing the cost of providing benefits and measuring the projected benefit obligation of these plans requires management to make various assumptions and estimates.

Certain unrecognized actuarial gains and losses and unrecognized prior service costs or credits are deferred as regulatory assets and liabilities, rather than recorded as other comprehensive income, based on regulatory recovery mechanisms.

See Note 11 for further information.

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Environmental Costs — Environmental costs are recorded when it is probable Xcel Energy is liable for remediation costs and the amount can be reasonably estimated. Costs are deferred as a regulatory asset if it is probable the costs will be recovered from customers in future rates. Otherwise, the costs are expensed. For certain environmental costs related to facilities currently in use, such as for emission-control equipment, the cost is capitalized and depreciated over the life of the plant.

Estimated remediation costs are regularly adjusted as estimates are revised and remediation is performed. If other participating potentially responsible parties exist and acknowledge their potential involvement with a site, costs are estimated and recorded only for Xcel Energy’s expected share of the cost.

Estimated future expenditures to restore sites are generally treated as a capitalized cost of plant retirement. The depreciation expense levels recoverable in rates include a provision for removal expenses. Removal costs recovered in rates before the related costs are incurred are classified as a regulatory liability. When separate mechanisms are expected to provide cost recovery or when changes in projected costs occur near the end of a facility’s useful life, regulatory accounting may be applied.

See Note 12 for further information.

Revenue from Contracts with Customers — Performance obligations related to the sale of energy are satisfied as energy is delivered to customers. Xcel Energy recognizes revenue that corresponds to the price of the energy delivered to the customer. The measurement of energy sales to customers is generally based on the reading of their meters, which occurs systematically throughout the month. At the end of each month, amounts of energy delivered to customers since the date of the last meter reading are estimated, and the corresponding unbilled revenue is recognized.

A separate financing component of collections from customers is not recognized as contract terms are short-term in nature. Revenues are net of any excise or sales taxes or fees. The utility subsidiaries recognize physical sales to customers (native load and wholesale) on a gross basis in electric revenues and cost of sales. Revenues and charges for short-term physical wholesale sales of excess energy transacted through RTO/ISOs are also recorded on a gross basis. Other revenues and charges settled/facilitated through an RTO/ISO are recorded on a net basis in cost of sales.

See Note 6 for further information.

Cash and Cash Equivalents — Xcel Energy considers investments in instruments with a remaining maturity of three months or less at the time of purchase to be cash equivalents.

Accounts Receivable and Allowance for Bad Debts — Accounts receivable are stated at the actual billed amount net of an allowance for bad debts. Xcel Energy establishes an allowance for uncollectible receivables based on a policy that reflects its expected exposure to the credit risk of customers.

As of Dec. 31, 2024 and 2023, the allowance for bad debts was $111 million and $128 million, respectively.

Inventory — Inventory is recorded at the lower of average cost or net realizable value and consisted of the following:

(Millions of Dollars)						Dec. 31, 2024						Dec. 31, 2023
Inventories
Materials and supplies						$	406					$	377
Fuel						164						211
Natural gas						96						123
Total inventories						$	666					$	711

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.

For interest rate derivatives, quoted prices based primarily on observable market interest rate curves are used to estimate fair value. For commodity derivatives, the most observable inputs available are generally used to determine the fair value of each contract. In the absence of a quoted price, quoted prices for similar contracts or internally prepared valuation models may be used to determine fair value.

For rabbi trust assets, pension and postretirement plan assets and nuclear decommissioning fund assets, published trading data and pricing models, generally using the most observable inputs available, are utilized to determine fair value for each security.

See Notes 10 and 11 for further information.

Derivative Instruments — Xcel Energy uses derivative instruments in connection with its commodity trading activities, and to manage risk associated with changes in interest rates and utility commodity prices, including forward contracts, futures, swaps and options. Derivatives not qualifying for the normal purchases and normal sales exception are recorded on the consolidated balance sheets at fair value as derivative instruments. Classification of changes in fair value for those derivative instruments is dependent on the designation of a qualifying hedging relationship.

Changes in fair value of derivative instruments not designated in a qualifying hedging relationship are reflected in current earnings or as a regulatory asset or liability. Classification as a regulatory asset or liability is based on commission approved regulatory recovery mechanisms.

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

Normal Purchases and Normal Sales — Xcel Energy enters into contracts for purchases and sales of commodities for use and sale in its operations. At inception, contracts are evaluated to determine whether they contain a derivative, and if so, whether they may be exempted from derivative accounting if designated as normal purchases or normal sales.

See Note 10 for further information.

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Commodity Trading Operations — All applicable gains and losses related to commodity trading activities are shown on a net basis in electric operating revenues in the consolidated statements of income.

Commodity trading activities are not associated with energy produced from generation assets or energy and capacity purchased to serve native load. Commodity trading contracts are recorded at fair market value and commodity trading results include the impact of all margin-sharing mechanisms.

See Note 10 for further information.

Other Utility Items

AFUDC — AFUDC represents the cost of capital used to finance utility construction activity and is computed by applying a composite financing rate to qualified CWIP. The amount of AFUDC capitalized as a utility construction cost is credited to other nonoperating income (for equity capital) and interest charges (for debt capital). AFUDC amounts capitalized are included in Xcel Energy’s rate base.

Alternative Revenue — Certain rate rider mechanisms (including decoupling/sales true up and CIP/DSM programs) qualify as alternative revenue programs. These mechanisms arise from instances in which the regulator authorizes a future surcharge in response to past activities or completed events. When certain criteria are met, including expected collection within 24 months, revenue is recognized, which may include incentives and return on rate base items.

Billing amounts are revised periodically for differences between total amount collected and revenue earned, which may increase or decrease the level of revenue collected from customers. Alternative revenues arising from these programs are presented on a gross basis and disclosed separately from revenue from contracts with customers.

See Note 6 for further information.

Conservation Programs — Costs incurred for DSM and CIP programs are deferred if it is probable future revenue will recover the incurred cost. Revenues recognized for incentive programs for the recovery of lost margins and/or conservation performance incentives are limited to amounts expected to be collected within 24 months from the year they are earned. Regulatory assets are recognized to reflect the amount of costs or earned incentives that have not yet been collected from customers.

Emissions Allowances — Emissions allowances are recorded at cost, including broker commission fees. The inventory accounting model is utilized for all emissions allowances and any sales of these allowances are included in electric revenues.

Nuclear Refueling Outage Costs — Xcel Energy uses a deferral and amortization method for nuclear refueling costs. This method amortizes costs over the period between refueling outages consistent with rate recovery.

RECs — Cost of RECs that are utilized for compliance is recorded as electric fuel and purchased power expense. In certain jurisdictions, Xcel Energy reduces recoverable fuel and purchased power costs for the cost of RECs received.

An inventory accounting model is used to account for RECs, however these assets are classified as regulatory assets if amounts are recoverable in future rates.

Sales of RECs are recorded in electric revenues on a gross basis. The cost of these RECs and amounts credited to customers under margin-sharing mechanisms are recorded in electric fuel and purchased power expense.

Cost of RECs that are utilized to support commodity trading activities are recorded in a similar manner as the associated commodities and are presented on a net basis in electric operating revenues in the consolidated statements of income.

2. Accounting Pronouncements

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. 31, 2024. 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, 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, 2026. Xcel Energy is currently evaluating the impact of implementing the new disclosure guidance.

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3. Property, Plant and Equipment

Major classes of property, plant and equipment

(Millions of Dollars)						Dec. 31, 2024						Dec. 31, 2023
Property, plant and equipment, net
Electric plant						$	56,791					$	52,494
Natural gas plant						9,834						9,080
Common and other property						3,515						3,190
Plant to be retired (a)						1,793						2,055
CWIP						4,720						2,873
Total property, plant and equipment						76,653						69,692
Less accumulated depreciation						(19,852)						(18,399)
Nuclear fuel						3,491						3,337
Less accumulated amortization						(3,094)						(2,988)
Property, plant and equipment, net						$	57,198					$	51,642

(a)Amounts include Sherco 1 and 3 and A.S. King for NSP-Minnesota; Comanche Units 2 and 3, Craig Units 1 and 2, Hayden Units 1 and 2 and coal generation assets at Pawnee pending facility gas conversion for PSCo; and Tolk Unit 1 and 2 for SPS. The Dec. 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.

Joint Ownership of Generation, Transmission and Gas Facilities

The utility subsidiaries’ jointly owned assets as of Dec. 31, 2024:

(Millions of Dollars, Except Percent Owned)						Plant in Service						Accumulated Depreciation												Percent Owned
NSP-Minnesota
Electric generation:
Sherco Unit 3						$	636					$	499											59		%
Sherco common facilities						189						128												80
Sherco substation						5						4												59
Electric transmission:
Grand Meadow						11						4												50
Huntley Wilmarth						49						3												50
CapX2020						855						160												51
Total NSP-Minnesota (a)						$	1,745					$	798

(a)Projects additionally include $10 million in CWIP.

(Millions of Dollars, Except Percent Owned)						Plant in Service						Accumulated Depreciation												Percent Owned
NSP-Wisconsin
Electric transmission:
La Crosse, WI to Madison, WI						$	179					$	30											37		%
CapX2020						169						44												80
Total NSP-Wisconsin (a)						$	348					$	74

(a)Projects additionally include $1 million in CWIP.

(Millions of Dollars, Except Percent Owned)						Plant in Service						Accumulated Depreciation												Percent Owned
PSCo
Electric generation:
Hayden Unit 1						$	158					$	117											76		%
Hayden Unit 2						152						93												37
Hayden common facilities						45						33												53
Craig Units 1 and 2						82						58												10
Craig common facilities						40						27												7
Comanche Unit 3						933						212												67
Comanche common facilities						29						5												77
Electric transmission:
Transmission and other facilities						190						75												Various
Gas transmission:
Rifle, CO to Avon, CO						28						10												60
Gas transmission compressor						8						3												50
Total PSCo (a)						$	1,665					$	633

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

Each company separately records its share of operating expenses and construction expenditures. Respective owners are responsible for providing their own financing.

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4. Regulatory Assets and Liabilities

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

Components of regulatory assets:

(Millions of Dollars)						See Note(s)						Remaining Amortization Period						Dec. 31, 2024												Dec. 31, 2023
Regulatory Assets																		Current						Noncurrent						Current						Noncurrent
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
Depreciation differences												Various						17						250						17						189
Excess deferred taxes — TCJA						7						Various						10						184						10						198
MISO capacity revenue tracker												One to two years						63						45						36						26
Environmental remediation costs						1, 12						Various						13						39						15						94
Prairie Island extended power uprate												10 years						4						34						4						38
Conservation programs (a)						1						One to two years						20						30						19						54
Purchased power contract costs												Term of related contract						5						28						4						40
Benson biomass PPA termination and asset purchase												Four years						10						26						10						36
Deferred natural gas, electric, steam energy/fuel costs												One to two years						99						25						239						80
Sales true-up and revenue decoupling												Various						60						23						7						33
Nuclear refueling outage costs						1						One to two years						51						20						43						19
Gas pipeline inspection and remediation costs												One to two years						47						9						40						25
Renewable resources and environmental initiatives												One to two years						34						4						38						5
Other												Various						89						210						102						207
Total regulatory assets																		$	561					$	2,849					$	611					$	2,798

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

Components of regulatory liabilities:

(Millions of Dollars)						See Note(s)						Remaining Amortization Period						Dec. 31, 2024												Dec. 31, 2023
Regulatory Liabilities																		Current						Noncurrent						Current						Noncurrent
Deferred income tax adjustments and TCJA refunds (a)						7						Various						$	7					$	2,888					$	7					$	3,015
Plant removal costs						1, 12						Various						—						2,208						—						1,984
Effects of regulation on employee benefit costs (b)						11						Various						—						259						—						253
Renewable resources and environmental initiatives												Various						16						232						9						188
Net AROs (c)												Various						—						161						—						90
ITC deferrals						1						Various						—						70						1						60
IRA deferral												One to three years						3						37						—						—
Deferred natural gas, electric, steam energy/fuel costs												One to two years						480						12						220						—
Contract valuation adjustments (d)						1, 10						Less than one year						89						—						56						—
Conservation programs (e)						1						Less than one year						52						—						47						—
Other												Various						205						143						188						237
Total regulatory liabilities (f)																		$	852					$	6,010					$	528					$	5,827

(a)Includes the revaluation of recoverable/regulated plant ADIT and revaluation impact of non-plant ADIT due to the TCJA.

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

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

(d)Includes the fair value of FTR instruments utilized/intended to offset the impacts of transmission system congestion.

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

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

Xcel Energy’s regulatory assets not earning a return include past expenditures of $892 million and $1,085 million at Dec. 31, 2024 and 2023 respectively, which predominately relate to purchased natural gas and electric energy costs (including certain costs related to Winter Storm Uri), sales true-up and revenue decoupling, various renewable resources/environmental initiatives and certain prepaid pension amounts. Additionally, the unfunded portion of pension and retiree medical obligations and net AROs (i.e. deferrals for which cash has not been disbursed) do not earn a return.

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5. Borrowings and Other Financing Instruments

Short-Term Borrowings

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

Commercial paper and other borrowings outstanding:

(Millions of Dollars, Except Interest Rates)						Three Months Ended Dec. 31, 2024						Year Ended Dec. 31
						2024						2023						2022
Borrowing limit						$	3,550					$	3,550					$	3,550					$	3,550
Amount outstanding at period end						695						695						785						813
Average amount outstanding						133						508						491						552
Maximum amount outstanding						695						1,314						1,241						1,357
Weighted average interest rate, computed on a daily basis						4.77		%				5.47		%				5.12		%				1.47		%
Weighted average interest rate at period end						4.64						4.64						5.52						4.66

Bilateral Credit Agreement — In April 2024, NSP-Minnesota’s uncommitted bilateral credit agreement was renewed for an additional one-year term. The credit agreement is limited in use to support letters of credit.

As of Dec. 31, 2024, NSP-Minnesota had $74 million outstanding letters of credit under the $75 million Bilateral Credit Agreement.

Letters of Credit — Xcel Energy uses letters of credit, typically with terms of one year, to provide financial guarantees for certain operating obligations. As of Dec. 31, 2024 and 2023, there were $42 million and $44 million of letters of credit outstanding under the credit facilities, respectively. Amounts approximate their fair value.

Credit Facilities — In order to use commercial paper programs to fulfill short-term funding needs, Xcel Energy Inc. and its utility subsidiaries must have revolving credit facilities in place at least equal to the amount of their respective commercial paper borrowing limits and cannot issue commercial paper exceeding available capacity under these credit facilities.

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

In September 2022*,* Xcel Energy Inc., NSP-Minnesota, NSP-Wisconsin, PSCo and SPS each entered into an amended five-year credit agreement with a syndicate of banks. The aggregate borrowing limit is $3.55 billion. The amended credit agreements mature in September 2027.

Features of the credit facilities:

						Debt-to-Total Capitalization Ratio (a)												Amount Facility May Be Increased (millions of dollars) (b)						Additional Periods for Which a One-Year Extension May Be Requested (c)
						2024						2023
Xcel Energy Inc. (d)						59.8		%				59.8		%				$	350					2
NSP-Minnesota						47.0						47.7						150						2
NSP-Wisconsin						47.1						48.2						N/A						1
SPS						46.6						46.1						50						2
PSCo						45.2						44.8						100						2

(a)Each credit facility has a financial covenant requiring that the debt-to-total capitalization ratio be less than or equal to 65%.

(b)Amounts authorized by state commissions in respective jurisdictions.

(c)All extension requests are subject to majority bank group approval.

(d)The Xcel Energy Inc. credit facility has a cross-default provision that Xcel Energy Inc. would be in default on its borrowings under the facility if it or any of its subsidiaries (except NSP-Wisconsin as long as its total assets do not comprise more than 15% of Xcel Energy’s consolidated total assets) default on indebtedness in an aggregate principal amount exceeding $75 million.

If Xcel Energy Inc. or its utility subsidiaries do not comply with the covenant, an event of default may be declared, and if not remedied, any outstanding amounts due under the facility can be declared due by the lender. As of Dec. 31, 2024, Xcel Energy Inc. and its subsidiaries were in compliance with the financial covenant.

Xcel Energy Inc. and its utility subsidiaries had the following committed credit facilities available as of Dec. 31, 2024:

(Millions of Dollars)						Credit Facility (a)						Drawn (b)						Available
Xcel Energy Inc.						$	1,500					$	235					$	1,265
PSCo						700						115						585
NSP-Minnesota						700						207						493
SPS						500						145						355
NSP-Wisconsin						150						35						115
Total						$	3,550					$	737					$	2,813

(a)These credit facilities mature in September 2027.

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

All credit facility bank borrowings, outstanding letters of credit and outstanding commercial paper reduce the available capacity under the credit facilities. Xcel Energy Inc. and its utility subsidiaries had no direct advances on facilities outstanding as of Dec. 31, 2024 and 2023.

Long-Term Borrowings and Other Financing Instruments

Generally, the property of NSP-Minnesota, NSP-Wisconsin, PSCo and SPS is subject to the liens of their respective first mortgage indentures for the benefit of bondholders.

Debt premiums, discounts and expenses are amortized over the life of the related debt. The premiums, discounts and expenses for refinanced debt are deferred and amortized over the life of the new issuance.

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Long-term debt obligations for Xcel Energy Inc. and its utility subsidiaries as of Dec. 31 (in millions of dollars, except interest rates):

Xcel Energy Inc.
Financing Instrument						Interest Rate						Maturity Date						2024						2023
Unsecured senior notes						3.30		%				June 1, 2025						250						250
Unsecured senior notes						3.30						June 1, 2025						350						350
Unsecured senior notes						3.35						Dec. 1, 2026						500						500
Unsecured senior notes						1.75						March 15, 2027						500						500
Unsecured senior notes						4.00						June 15, 2028						130						130
Unsecured senior notes						4.00						June 15, 2028						500						500
Unsecured senior notes						2.60						Dec. 1, 2029						500						500
Unsecured senior notes						3.40						June 1, 2030						600						600
Unsecured senior notes						2.35						Nov. 15, 2031						300						300
Unsecured senior notes						4.60						June 1, 2032						700						700
Unsecured senior notes (a)						5.45						Aug. 15, 2033						800						800
Unsecured senior notes (b)						5.50						March 15, 2034						800						—
Unsecured senior notes						6.50						July 1, 2036						300						300
Unsecured senior notes						4.80						Sept. 15, 2041						250						250
Unsecured senior notes						3.50						Dec. 1, 2049						500						500
Unamortized discount																		(9)						(8)
Unamortized debt issuance cost																		(34)						(36)
Current maturities																		(600)						—
Total long-term debt																		$	6,337					$	6,136

(a)2023 financing.

(b)2024 financing.

NSP-Minnesota
Financing Instrument						Interest Rate						Maturity Date						2024						2023
First mortgage bonds						7.125		%				July 1, 2025						250						250
First mortgage bonds						6.50						March 1, 2028						150						150
First mortgage bonds						2.25						April 1, 2031						425						425
First mortgage bonds						5.25						July 15, 2035						250						250
First mortgage bonds						6.25						June 1, 2036						400						400
First mortgage bonds						6.20						July 1, 2037						350						350
First mortgage bonds						5.35						Nov. 1, 2039						300						300
First mortgage bonds						4.85						Aug. 15, 2040						250						250
First mortgage bonds						3.40						Aug. 15, 2042						500						500
First mortgage bonds						4.125						May 15, 2044						300						300
First mortgage bonds						4.00						Aug. 15, 2045						300						300
First mortgage bonds						3.60						May 15, 2046						350						350
First mortgage bonds						3.60						Sept. 15, 2047						600						600
First mortgage bonds						2.90						March 1, 2050						600						600
First mortgage bonds						2.60						June 1, 2051						700						700
First mortgage bonds						3.20						April 1, 2052						425						425
First mortgage bonds						4.50						June 1, 2052						500						500
First mortgage bonds (a)						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)
Unamortized debt issuance cost																		(80)						(73)
Current maturities																		(250)						—
Total long-term debt																		$	7,607					$	7,330

(a)2023 financing.

(b)2024 financing.

NSP-Wisconsin
Financing Instrument						Interest Rate						Maturity Date						2024						2023
First mortgage bonds						3.30		%				June 15, 2024						$	—					$	100
First mortgage bonds						3.30						June 15, 2024						—						100
First mortgage bonds						6.375						Sept. 1, 2038						200						200
First mortgage bonds						3.70						Oct. 1, 2042						100						100
First mortgage bonds						3.75						Dec. 1, 2047						100						100
First mortgage bonds						4.20						Sept. 1, 2048						200						200
First mortgage bonds						3.05						May 1, 2051						100						100
First mortgage bonds						2.82						May 1, 2051						100						100
First mortgage bonds						4.86						Sept. 15, 2052						100						100
First mortgage bonds (a)						5.30						June 15, 2053						125						125
First mortgage bonds (b)						5.65						June 15, 2054						400						—
Unamortized discount																		(4)						(3)
Unamortized debt issuance cost																		(15)						(11)
Current maturities																		—						(200)
Total long-term debt																		$	1,406					$	1,011

(a)2023 financing.

(b)2024 financing.

PSCo
Financing Instrument						Interest Rate						Maturity Date						2024						2023
First mortgage bonds						2.90		%				May 15, 2025						250						250
First mortgage bonds						3.70						June 15, 2028						350						350
First mortgage bonds						1.90						Jan. 15, 2031						375						375
First mortgage bonds						1.875						June 15, 2031						750						750
First mortgage bonds						4.10						June 1, 2032						300						300
First mortgage bonds (a)						5.35						May 15, 2034						450						—
First mortgage bonds						6.25						Sept. 1, 2037						350						350
First mortgage bonds						6.50						Aug. 1, 2038						300						300
First mortgage bonds						4.75						Aug. 15, 2041						250						250
First mortgage bonds						3.60						Sept. 15, 2042						500						500
First mortgage bonds						3.95						March 15, 2043						250						250
First mortgage bonds						4.30						March 15, 2044						300						300
First mortgage bonds						3.55						June 15, 2046						250						250
First mortgage bonds						3.80						June 15, 2047						400						400
First mortgage bonds						4.10						June 15, 2048						350						350
First mortgage bonds						4.05						Sept. 15, 2049						400						400
First mortgage bonds						3.20						March 1, 2050						550						550
First mortgage bonds						2.70						Jan. 15, 2051						375						375
First mortgage bonds						4.50						June 1, 2052						400						400
First mortgage bonds (b)						5.25						April 1, 2053						850						850
First mortgage bonds (a)						5.75						May 15, 2054						750						—
Unamortized discount																		(42)						(41)
Unamortized debt issuance cost																		(67)						(59)
Current maturities																		(250)						—
Total long-term debt																		$	8,391					$	7,450

(a)2024 financing.

(b)2023 financing.

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SPS
Financing Instrument						Interest Rate						Maturity Date						2024						2023
First mortgage bonds						3.30		%				June 15, 2024						$	—					$	150
First mortgage bonds						3.30						June 15, 2024						—						200
Unsecured senior notes						6.00						Oct. 1, 2033						100						100
Unsecured senior notes						6.00						Oct. 1, 2036						250						250
First mortgage bonds						4.50						Aug. 15, 2041						200						200
First mortgage bonds						4.50						Aug. 15, 2041						100						100
First mortgage bonds						4.50						Aug. 15, 2041						100						100
First mortgage bonds						3.40						Aug. 15, 2046						300						300
First mortgage bonds						3.70						Aug. 15, 2047						450						450
First mortgage bonds						4.40						Nov. 15, 2048						300						300
First mortgage bonds						3.75						June 15, 2049						300						300
First mortgage bonds						3.15						May 1, 2050						350						350
First mortgage bonds						3.15						May 1, 2050						250						250
First mortgage bonds						5.15						June 1, 2052						200						200
First mortgage bonds (a)						6.00						Sept. 15, 2053						100						100
First mortgage bonds (b)						6.00						June 1, 2054						600						—
Unamortized discount																		(14)						(10)
Unamortized debt issuance cost																		(35)						(29)
Current maturities																		—						(350)
Total long-term debt																		$	3,551					$	2,961

(a)2023 financing.

(b)2024 financing.

Other Subsidiaries
Financing Instrument						Interest Rate						Maturity Date						2024						2023
Various Eloigne affordable housing project notes						0.00% - 8.00%						2024 - 2055						$	27					$	27
Current maturities																		(3)						(2)
Total long-term debt																		$	24					$	25

Maturities of long-term debt:

(Millions of Dollars)
2025						$	1,103
2026						501
2027						501
2028						1,133
2029						503

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. 31, 2024.

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. 31, 2024 and 2023, respectively.

Equity through DRIP and Benefits Program — Xcel Energy issued $67 million of equity in 2024 and $88 million of equity in 2023 through the DRIP and benefits programs. The program allows shareholders to reinvest their dividends directly in Xcel Energy Inc. common stock.

ATM Equity Offering — In November 2021, Xcel Energy Inc. filed a prospectus supplement under which it may sell up to $800 million of its common stock through an ATM program. In 2022, 4.3 million shares of common stock were issued (approximately $300 million in net proceeds and $3 million in transaction fees paid). In 2023, 0.9 million shares of common stock were issued ($62 million in net proceeds and $1 million in transaction fees paid). In October 2023, the 2021 ATM offering was closed.

In October 2023, Xcel Energy Inc. filed a prospectus supplement under which it may sell up to $2.5 billion of its common stock through an ATM program. In 2023, through this ATM program, Xcel Energy Inc. issued 3.1 million shares of common stock ($188 million in net proceeds and $2 million in transaction fees paid). In 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.

At Dec. 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:

						Preferred Stock Authorized (Shares)						Par Value of Preferred Stock						Preferred Stock Outstanding (Shares) 2024 and 2023
Xcel Energy Inc.						7,000,000						$	100					—
PSCo						10,000,000						0.01						—
SPS						10,000,000						1.00						—

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

Common Stock Authorized (Shares)						Par Value of Common Stock						Common Stock Outstanding (Shares) as of Dec. 31, 2024						Common Stock Outstanding (Shares) as of Dec. 31, 2023
1,000,000,000						$	2.50					574,365,598						554,941,703

Dividend and Other Capital-Related Restrictions — Xcel Energy depends on its utility subsidiaries to pay dividends. Xcel Energy Inc.’s utility subsidiaries’ dividends are subject to the FERC’s jurisdiction, which prohibits the payment of dividends out of capital accounts. Dividends are solely to be paid from retained earnings. Certain covenants also require Xcel Energy Inc. to be current on interest payments prior to dividend disbursements.

State regulatory commissions impose dividend limitations for NSP-Minnesota, NSP-Wisconsin and SPS, which are more restrictive than those imposed by the FERC.

Requirements and actuals as of Dec. 31, 2024:

						Equity to Total Capitalization Ratio Required Range												Equity to Total Capitalization Ratio Actual
						Low						High						2024
NSP-Minnesota						47.6		%				58.2		%				53.0		%
NSP-Wisconsin (a)						52.5						N/A						52.7
SPS (b)						45.0						55.0						54.4

(a) Cannot pay annual dividends in excess of forecasted levels if its average equity-to-total capitalization ratio falls below the commission authorized level.

(b) Excludes short-term debt.

(Amounts in Millions)						Unrestricted Retained Earnings						Total Capitalization						Limit on Total Capitalization
NSP-Minnesota						$	1,809					$	17,490					$	17,800
NSP-Wisconsin						12						2,922						N/A
SPS (a)						592						7,789						N/A

(a)May not pay a dividend that would cause a loss of its investment grade bond rating.

Issuance of securities by Xcel Energy Inc. is not generally subject to regulatory approval. However, utility financings and intra-system financings are subject to the jurisdiction of state regulatory commissions and/or the FERC. Xcel Energy may seek additional authorization as necessary.

Amounts authorized to issue as of Dec. 31, 2024:

(Millions of Dollars)						Long-Term Debt						Short-Term Debt
NSP-Minnesota (a)						52.4% of total capitalization						$	2,670
NSP-Wisconsin						$	225					150
PSCo						1,300						1,200
SPS						150						700

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

6. Revenues

Revenue is classified by the type of goods/services rendered and market/customer type. Xcel Energy’s operating revenues consisted of the following:

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

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

						Year Ended Dec. 31, 2022
(Millions of Dollars)						Electric						Natural Gas						All Other						Total
Major revenue types
Revenue from contracts with customers:
Residential						$	3,542					$	1,814					$	53					$	5,409
C&I						5,807						998						32						6,837
Other						148						—						10						158
Total retail						9,497						2,812						95						12,404
Wholesale						1,354						—						—						1,354
Transmission						675						—						—						675
Other						97						178						—						275
Total revenue from contracts with customers						11,623						2,990						95						14,708
Alternative revenue and other						500						90						12						602
Total revenues						$	12,123					$	3,080					$	107					$	15,310

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7. Income Taxes

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

Effective income tax rate for years ended Dec. 31:

						2024						2023						2022
Federal statutory rate						21.0		%				21.0		%				21.0		%
State income tax on pretax income, net of federal tax effect						4.8						4.9						4.9
(Decreases) increases in tax from:
PTCs (a)						(43.2)						(28.1)						(27.4)
Plant regulatory differences (b)						(7.3)						(5.6)						(5.5)
Other tax credits, net NOL & tax credit allowances						(1.3)						(1.3)						(1.3)
Other, net						(0.2)						0.1						(0.1)
Effective income tax rate						(26.2)		%				(9.0)		%				(8.4)		%

(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. 31, 2024.

(b)Plant regulatory differences primarily relate to the credit of excess deferred taxes to customers through the average rate assumption method. Income tax benefits associated with the credit are offset by corresponding revenue reductions.

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

(Millions of Dollars)						2024						2023						2022
Current federal tax expense						$	36					$	113					$	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)
Deferred state tax expense						46						75						96
Deferred change in unrecognized tax expense						—						7						3
Deferred ITCs						(4)						(5)						(4)
Total income tax benefit						$	(402)					$	(146)					$	(135)

Components of deferred income tax expense as of Dec. 31:

(Millions of Dollars)						2024						2023						2022
Deferred tax expense (benefit) excluding items below						$	434					$	129					$	(138)
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 expense allocated to other comprehensive income and other						(8)						—						(10)
Deferred tax benefit						$	(464)					$	(249)					$	(140)

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

Components of net deferred tax liability as of Dec. 31:

(Millions of Dollars)						2024						2023 (a)
Deferred tax liabilities:
Differences between book and tax bases of property						$	7,008					$	6,744
Regulatory assets						566						523
Operating lease assets						282						327
Pension expense						155						151
Deferred fuel costs						—						67
Other						97						80
Total deferred tax liabilities						$	8,108					$	7,892
Deferred tax assets:
Tax credit carryforward						$	1,589					$	1,718
Regulatory liabilities						751						715
Operating lease liabilities						282						327
Other employee benefits						102						117
Deferred ITCs						11						16
NOL carryforward						1						—
NOL and tax credit valuation allowances						(73)						(70)
Other						126						184
Total deferred tax assets						2,789						3,007
Net deferred tax liability						$	5,319					$	4,885

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

Other Income Tax Matters — NOL amounts represent the tax loss that is carried forward and tax credits represent the deferred tax asset. NOL and tax credit carryforwards as of Dec. 31:

(Millions of Dollars)						2024						2023
Federal tax credit carryforwards						$	1,519					$	1,644
Valuation allowances for federal credit carryforwards						(14)						(10)
State NOL carryforwards						9						11
Valuation allowances for state NOL carryforwards						(2)						(2)
State tax credit carryforwards, net of federal detriment (a)						70						74
Valuation allowances for state credit carryforwards, net of federal benefit (b)						(58)						(60)

(a)State tax credit carryforwards are net of federal detriment of $19 million and $20 million as of Dec. 31, 2024 and 2023, respectively.

(b)Valuation allowances for state tax credit carryforwards were net of federal benefit of $16 million as of Dec. 31, 2024 and 2023.

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

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

Tax Year(s)						Expiration
2014 - 2016						March 2025
2021						October 2025

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Additionally, the statute of limitations related to the federal tax credit carryforwards will remain open until those credits are utilized in subsequent returns. Further, the statute of limitations related to the additional federal tax loss carryback claim filed in 2020 has been extended. In 2023 the IRS issued its Revenue Agent’s Report related to the federal tax loss carryback claim. 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.

As of Dec. 31, 2024, Xcel Energy’s earliest open tax years (subject to examination by state taxing authorities in its major operating jurisdictions) were as follows:

State						Tax Year(s)						Expiration
Colorado						2014 - 2016						March 2026
Colorado						2020						September 2025
Minnesota						2014 - 2016						September 2025
Minnesota						2020						June 2025
Texas						2016 - 2019						December 2025
Wisconsin						2016 - 2019						May 2025
Wisconsin						2020						September 2025

• In 2021, Texas began an audit of tax years 2016 - 2019. As of Dec. 31, 2024, no material adjustments have been proposed.

• In 2021, Wisconsin began an audit of tax years 2016-2019. As of Dec. 31, 2024, no material adjustments have been proposed.

• No other state income tax audits are in progress for its major operating jurisdictions as of Dec. 31, 2024.

Unrecognized tax benefit balance may include permanent tax positions, which if recognized would affect the ETR. In addition, the unrecognized tax benefit balance may include temporary tax positions for which deductibility is highly certain, but for which there is uncertainty about the timing. A change in the period of deductibility would not affect the ETR but would accelerate the payment to the taxing authority.

Unrecognized tax benefits - permanent vs. temporary:

(Millions of Dollars)						Dec. 31, 2024						Dec. 31, 2023
Unrecognized tax benefit — Permanent tax positions						$	43					$	41
Unrecognized tax benefit — Temporary tax positions						—						—
Total unrecognized tax benefit						$	43					$	41

Changes in unrecognized tax benefits:

(Millions of Dollars)						2024						2023						2022
Balance at Jan. 1						$	41					$	67					$	58
Additions based on tax positions related to the current year						5						5						7
Additions for tax positions of prior years						2						1						6
Reductions for tax positions of prior years						(3)						(29)						(1)
Reductions for tax positions related to settlements with taxing authorities						—						(1)						(1)
Reductions for tax positions related to statute of limitations						(2)						(2)						(2)
Balance at Dec. 31						$	43					$	41					$	67

Unrecognized tax benefits were reduced by tax benefits associated with NOL and tax credit carryforwards:

(Millions of Dollars)						Dec. 31, 2024						Dec. 31, 2023
NOL and tax credit carryforwards						$	(35)					$	(35)

As state audits progress, it is reasonably possible that the amount of current liabilities related to unrecognized tax benefits could decrease up to approximately $2 million in the next 12 months. Additionally, there exists approximately $41 million of noncurrent liabilities related to unrecognized tax benefits for which there is uncertainty about if or when these liabilities will significantly increase or decrease.

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

Interest payable related to unrecognized tax benefits:

(Millions of Dollars)						2024						2023						2022
Payable for interest related to unrecognized tax benefits at Jan. 1						$	(1)					$	(4)					$	(3)
Interest (expense) benefit related to unrecognized tax benefits						(1)						3						(1)
Payable for interest related to unrecognized tax benefits at Dec. 31						$	(2)					$	(1)					$	(4)

No penalties were accrued related to unrecognized tax benefits as of Dec. 31, 2024, 2023 or 2022.

8. Share-Based Compensation

Incentive Plan Including Share-Based Compensation — Xcel Energy has authorized 13.0 million equity shares under the Xcel Energy Inc. 2024 Equity Incentive Plan for grants made on May 22, 2024 or later and 6.0 million equity shares under the Amended and Restated 2015 Omnibus Incentive Plan for grants made prior to May 22, 2024.

Equity Awards — Xcel Energy‘s Board of Directors has granted equity awards under the 2024 Equity Incentive Plan and 2015 Omnibus Incentive Plan, determined by grant date, which includes various vesting conditions and performance goals. At the end of the restricted period, such grants will be awarded if vesting conditions and/or performance goals are met.

Certain employees are granted equity awards with a portion subject only to service conditions, and the other portion subject to performance conditions. The total time-based equity shares granted subject only to service conditions was 0.5 million in 2024, 0.4 million in 2023 and 0.2 million in 2022.

The performance conditions for a portion of the awards granted from 2022 to 2024 are based on relative TSR and environmental goals. Equity awards with performance conditions will be settled after three years, with payouts ranging from zero to 200% depending on achievement.

Equity award units granted to employees:

(Units in Thousands)						2024						2023						2022
Granted units						658						586						395
Weighted average grant date fair value						$	63.02					$	67.06					$	68.43

Equity awards vested:

(Units in Thousands, Fair Value in Millions)						2024						2023						2022
Vested Units						282						329						319
Total Fair Value						$	19					$	20					$	22

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Changes in the nonvested portion of equity award units:

(Units in Thousands)						Units						Weighted Average Grant Date Fair Value
Nonvested Units at Jan. 1, 2024						819						$	67.36
Granted						658						63.02
Forfeited						(111)						66.77
Vested						(282)						68.58
Dividend equivalents						55						66.16
Nonvested Units at Dec. 31, 2024						1,139						64.55

Stock Equivalent Units — Non-employee members of Xcel Energy‘s Board of Directors may elect to receive their annual equity grant as stock equivalent units in lieu of common stock. Each unit’s value is equal to one share of common stock. The annual equity grant is vested as of the date of each member’s election to the Board of Directors; there is no further service or other condition. Directors may also elect to receive their fees as stock equivalent units in lieu of cash. Stock equivalent units are payable as a distribution of common stock upon a director’s termination of service.

Stock equivalent units granted:

(Units in Thousands)						2024						2023						2022
Granted units						44						38						29
Weighted average grant date fair value						$	57.03					$	63.12					$	71.97

Changes in stock equivalent units:

(Units in Thousands)						Units						Weighted Average Grant Date Fair Value
Stock equivalent units at Jan. 1, 2024						517						$	46.07
Granted						44						57.03
Units distributed						(52)						33.19
Dividend equivalents						19						58.15
Stock equivalent units at Dec. 31, 2024						528						48.68

Liability Awards — Xcel Energy’s Board of Directors has granted TSR liability awards under the 2024 Equity Incentive Plan and 2015 Omnibus Incentive Plan, determined by grant date. These plans allow Xcel Energy to attach various performance goals to the awards granted. The liability awards have been historically dependent on relative TSR measured over a three-year period. Xcel Energy Inc.’s TSR is compared to a peer group of other utility companies. Potential payouts of the awards range from zero to 200%.

Liability awards granted:

(In Thousands)						2024						2023						2022
Awards granted						193						216						165

Liability awards settled:

(Units In Thousands, Settlement Amount in Millions)						2024						2023						2022
Awards settled						—						282						411
Settlement amount (cash, common stock and deferred amounts)						$	—					$	19					$	27

There were no TSR liability awards settled in 2024.

Share-Based Compensation Expense — Award settlement determination (permitting cash or share settlement) is made by Xcel Energy, not the participants. Equity awards have not been previously settled in cash and Xcel Energy plans to continue electing share settlement. Grant date fair value of equity awards is expensed over the service period.

TSR liability awards are accounted for as liabilities, as historically they are partially settled in cash. As liability awards, the fair value on which ratable expense is based, as employees vest in their rights to those awards, is remeasured each period based on the current stock price and performance achievement, and final expense is based on the market value of the award on the settlement date.

Compensation costs related to share-based awards:

(Millions of Dollars)						2024						2023						2022
Cost for share-based awards (a)						$	30					$	27					$	36
Tax benefit recognized in income						8						7						9

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

9. Earnings Per Share

Basic EPS was computed by dividing the earnings available to common shareholders by the weighted average number of common shares outstanding. Diluted EPS was computed by dividing the earnings available to common shareholders by the diluted weighted average number of common shares outstanding.

Diluted EPS reflects the potential dilution that could occur if securities or other agreements to issue common stock (i.e., common stock equivalents) were settled. The weighted average number of potentially dilutive shares outstanding used to calculate diluted EPS is calculated using the treasury stock method.

Common Stock Equivalents — Common stock equivalents include commitments to issue common stock related to forward equity agreements and time-based equity compensation awards.

Stock equivalent units granted to Xcel Energy’s Board of Directors are included in common shares outstanding upon grant date as there is no further service, performance or market condition following the grant of these awards. Restricted stock issued to employees under the Executive Annual Incentive Award Plan is included in common shares outstanding when granted.

Share-based compensation arrangements for which there is currently no dilutive impact to EPS include the following:

• Equity awards subject to a performance condition; included in common shares outstanding when all necessary conditions for settlement have been satisfied by the end of the reporting period.

• Liability awards subject to a performance condition; any portions settled in shares are included in common shares outstanding upon settlement.

Common shares outstanding used in the basic and diluted EPS computation:

(Shares in Millions)						2024						2023						2022
Basic						563						552						547
Diluted (a)						563						552						547

(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.

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10. Fair Value of Financial Assets and Liabilities

Fair Value Measurements

Accounting guidance for fair value measurements and disclosures provides a hierarchical framework for disclosing the observability of the inputs utilized in measuring assets and liabilities at fair value.

• Level 1 — Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. The types of assets and liabilities included in Level 1 are actively traded instruments with observable actual trading prices.

• Level 2 — Pricing inputs are other than actual trading prices in active markets but are either directly or indirectly observable as of the reporting date. The types of assets and liabilities included in Level 2 are typically either comparable to actively traded securities or contracts or priced with models using highly observable inputs.

• Level 3 — Significant inputs to pricing have little or no observability as of the reporting date. The types of assets and liabilities included in Level 3 include those valued with models requiring significant judgment or estimation.

Specific valuation methods include:

Investments in equity securities and other funds — Equity securities are valued using quoted prices in active markets. The fair values for commingled funds are measured using NAVs. The investments in commingled funds may be redeemed for NAV with proper notice. Private equity commingled funds require approval of the fund for any unscheduled redemption, and such redemptions may be approved or denied by the fund at its sole discretion. Unscheduled distributions from real estate commingled funds may be redeemed with proper notice, however, withdrawals may be delayed or discounted as a result of fund illiquidity.

Investments in debt securities — Fair values for debt securities are determined by a third party pricing service using recent trades and observable spreads from benchmark interest rates for similar securities.

Interest rate derivatives — Fair values of interest rate derivatives are based on broker quotes that utilize current market interest rate forecasts.

Commodity derivatives — Methods used to measure the fair value of commodity derivative forwards and options utilize forward prices and volatilities, as well as pricing adjustments for specific delivery locations, and are generally assigned a Level 2 classification. When contracts relate to inactive delivery locations or extend to periods beyond those readily observable on active exchanges, the significance of the use of less observable inputs on a valuation is evaluated and may result in Level 3 classification.

Electric commodity derivatives held by NSP-Minnesota and SPS include transmission congestion instruments, generally referred to as FTRs. FTRs purchased from an RTO are financial instruments that entitle or obligate the holder to monthly revenues or charges based on transmission congestion across a given transmission path.

The values of these instruments are derived from, and designed to offset, the costs of transmission congestion. In addition to overall transmission load, congestion is also influenced by the operating schedules of power plants and the consumption of electricity pertinent to a given transmission path. Unplanned plant outages, scheduled plant maintenance, changes in the relative costs of fuels used in generation, weather and overall changes in demand for electricity can each impact the operating schedules of the power plants on the transmission grid and the value of these instruments.

FTRs are recognized at fair value and adjusted each period prior to settlement. Given the limited observability of certain variables underlying the reported auction values of FTRs, these fair value measurements have been assigned a Level 3 classification.

Net congestion costs, including the impact of FTR settlements, are shared through fuel and purchased energy cost recovery mechanisms. As such, the fair value of the unsettled instruments (i.e., derivative asset or liability) is offset/deferred as a regulatory asset or liability.

Non-Derivative Fair Value Measurements

Nuclear Decommissioning Fund

The NRC requires NSP-Minnesota to maintain a portfolio of investments to fund the costs of decommissioning its nuclear generating plants. Assets of the nuclear decommissioning fund are legally restricted for the purpose of decommissioning these facilities. The fund contains cash equivalents, debt securities, equity securities and other investments. NSP-Minnesota uses the MPUC approved asset allocation for the investment targets by asset class for the qualified trust.

NSP-Minnesota recognizes the costs of funding the decommissioning over the lives of the nuclear plants, assuming rate recovery of all costs. Realized and unrealized gains on fund investments over the life of the fund are deferred as an offset of NSP-Minnesota’s regulatory asset or as a regulatory liability (dependent on funding status) for nuclear decommissioning costs. Consequently, any realized and unrealized gains and losses on securities in the nuclear decommissioning fund are deferred as a component of the regulatory asset/liability.

Unrealized gains for the nuclear decommissioning fund were $1.4 billion and $1.2 billion as of Dec. 31, 2024 and 2023, respectively, and unrealized losses were $49 million and $29 million as of Dec. 31, 2024 and 2023, respectively.

Non-derivative instruments with recurring fair value measurements in the nuclear decommissioning fund:

						Dec. 31, 2024
												Fair Value
(Millions of Dollars)						Cost						Level 1						Level 2						Level 3						NAV						Total
Nuclear decommissioning fund (a)
Cash equivalents						$	39					$	39					$	—					$	—					$	—					$	39
Commingled funds						703						—						—						—						1,025						1,025
Debt securities						866						—						832						14						—						846
Equity securities						522						1,583						1						—						—						1,584
Total						$	2,130					$	1,622					$	833					$	14					$	1,025					$	3,494

(a)Reported in nuclear decommissioning fund and other investments on the consolidated balance sheets, which also includes $246 million of equity method investments and $156 million of rabbi trust assets and other miscellaneous investments.

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						Dec. 31, 2023
												Fair Value
(Millions of Dollars)						Cost						Level 1						Level 2						Level 3						NAV						Total
Nuclear decommissioning fund (a)
Cash equivalents						$	41					$	41					$	—					$	—					$	—					$	41
Commingled funds						721						—						—						—						1,049						1,049
Debt securities						784						—						771						9						—						780
Equity securities						508						1,339						2						—						—						1,341
Total						$	2,054					$	1,380					$	773					$	9					$	1,049					$	3,211

(a)Reported in nuclear decommissioning fund and other investments on the consolidated balance sheets, which also includes $244 million of equity investments in unconsolidated subsidiaries and $144 million of rabbi trust assets and other miscellaneous investments.

For the years ended Dec. 31, 2024 and 2023, there were immaterial Level 3 nuclear decommissioning fund investments or transfer of amounts between levels.

Contractual maturity dates of debt securities in the nuclear decommissioning fund as of Dec. 31, 2024:

						Final Contractual Maturity
(Millions of Dollars)						Due in 1 Year or Less						Due in 1 to 5 Years						Due in 5 to 10 Years						Due after 10 Years						Total
Debt securities						$	7					$	308					$	269					$	262					$	846

Rabbi Trusts

Xcel Energy has established rabbi trusts to provide partial funding for future deferred compensation plan distributions. The fair value of assets held in the rabbi trusts were $96 million and $88 million at Dec. 31, 2024 and 2023, respectively, comprised of cash equivalents and mutual funds (level 1 valuation methods). Amounts are reported in nuclear decommissioning fund and other investments on the consolidated balance sheet.

Derivative Activities and Fair Value Measurements

Xcel Energy enters into derivative instruments, including forward contracts, futures, swaps and options, for trading purposes and to manage risk in connection with changes in interest rates, and utility commodity prices.

Interest Rate Derivatives — Xcel Energy enters into contracts that effectively fix the interest rate on a specified principal amount of a hypothetical future debt issuance. These financial swaps net settle based on changes in a specified benchmark interest rate, acting as a hedge of changes in market interest rates that will impact specified anticipated debt issuances. These derivative instruments are designated as cash flow hedges for accounting purposes, with changes in fair value prior to occurrence of the hedged transactions recorded as other comprehensive income.

As of Dec. 31, 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. As of Dec. 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.

Wholesale and Commodity Trading — Xcel Energy Inc.’s utility subsidiaries conduct various wholesale and commodity trading activities, including the purchase and sale of electric capacity, energy, energy-related instruments and natural gas-related instruments, including derivatives. Xcel Energy is allowed to conduct these activities within guidelines and limitations as approved by its risk management committee, comprised of management personnel not directly involved in the activities governed by this policy.

Results of derivative instrument transactions entered into for trading purposes are presented in the consolidated statements of income as electric revenues, net of any sharing with customers. These activities are not intended to mitigate commodity price risk associated with regulated electric and natural gas operations. Sharing of these margins is determined through state regulatory proceedings as well as the operation of the FERC-approved joint operating agreement.

Commodity Derivatives — Xcel Energy enters into derivative instruments to manage variability of future cash flows from changes in commodity prices in its electric and natural gas operations. This could include the purchase or sale of energy or energy-related products, natural gas to generate electric energy, natural gas for resale and FTRs.

The most significant derivative positions outstanding at Dec. 31, 2024 and 2023 for this purpose relate to FTR instruments administered by MISO and SPP. These instruments are intended to offset the impacts of transmission system congestion.

When Xcel Energy enters into derivative instruments that mitigate commodity price risk on behalf of electric and natural gas customers, the instruments are not typically designated as qualifying hedging transactions. The classification of unrealized losses or gains on these instruments as a regulatory asset or liability, if applicable, is based on approved regulatory recovery mechanisms.

As of Dec. 31, 2024, Xcel Energy had no commodity contracts designated as cash flow hedges.

Gross notional amounts of commodity forwards, options and FTRs:

(Amounts in Millions) (a)(b)						Dec. 31, 2024						Dec. 31, 2023
MWh of electricity						38						48
MMBtu of natural gas						77						84

(a)Not reflective of net positions in the underlying commodities.

(b)Notional amounts for options included on a gross basis but weighted for the probability of exercise.

Consideration of Credit Risk and Concentrations — Xcel Energy continuously monitors the creditworthiness of counterparties to its interest rate derivatives and commodity derivative contracts prior to settlement and assesses each counterparty’s ability to perform on the transactions set forth in the contracts. Impact of credit risk was immaterial to the fair value of unsettled commodity derivatives presented on the consolidated balance sheets.

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

As of Dec. 31, 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.

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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.

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

Credit Related Contingent Features — Contract provisions for derivative instruments that the utility subsidiaries enter, including those accounted for as normal purchase and normal sale contracts and therefore not reflected on the consolidated balance sheets, may require the posting of collateral or settlement of the contracts for various reasons, including if the applicable utility subsidiary’s credit ratings are downgraded below its investment grade credit rating by any of the major credit rating agencies.

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

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

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

Certain derivative instruments are also subject to contract provisions that contain adequate assurance clauses. These provisions allow counterparties to seek performance assurance, including cash collateral, in the event that a given utility subsidiary’s ability to fulfill its contractual obligations is reasonably expected to be impaired.

Xcel Energy had no collateral posted related to adequate assurance clauses in derivative contracts as of Dec. 31, 2024 and 2023.

Recurring Derivative Fair Value Measurements

Impact of derivative activity:

						Pre-Tax Fair Value Gains (Losses) Recognized During the Period in:
(Millions of Dollars)						Accumulated Other Comprehensive Loss						Regulatory (Assets) and Liabilities
Year Ended Dec. 31, 2024
Derivatives designated as cash flow hedges
Interest rate						$	29					$	—
Total						$	29					$	—
Other derivative instruments
Electric commodity						$	—					$	44
Natural gas commodity						—						4
Total						$	—					$	48
Year Ended Dec. 31, 2023
Interest rate						$	(2)					$	—
Total						$	(2)					$	—
Other derivative instruments
Electric commodity						$	—					$	(137)
Natural gas commodity						—						(13)
Total						$	—					$	(150)
Year Ended Dec. 31, 2022
Interest rate						$	22					$	—
Total						$	22					$	—
Other derivative instruments
Electric commodity						$	—					$	(10)
Natural gas commodity						—						(16)
Total						$	—					$	(26)

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						Pre-Tax (Gains) Losses Reclassified into Income During the Period from:												Pre-Tax Gains (Losses) Recognized During the Period in Income
(Millions of Dollars)						Accumulated Other Comprehensive Loss						Regulatory Assets and (Liabilities)
Year Ended Dec. 31, 2024
Derivatives designated as cash flow hedges
Interest rate						$	3		(a)			$	—					$	—
Total						$	3					$	—					$	—
Other derivative instruments
Commodity trading						$	—					$	—					$	(27)		(b)
Electric commodity						—						(22)			(c)			—
Natural gas commodity						—						—						(22)			(d)(e)
Total						$	—					$	(22)					$	(49)
Year Ended Dec. 31, 2023
Derivatives designated as cash flow hedges
Interest rate						$	5		(a)			$	—					$	—
Total						$	5					$	—					$	—
Other derivative instruments
Commodity trading						$	—					$	—					$	(7)		(b)
Electric commodity						—						123			(c)			—
Natural gas commodity						—						15			(d)			(27)			(d)(e)
Total						$	—					$	138					$	(34)
Year Ended Dec. 31, 2022
Derivatives designated as cash flow hedges
Interest rate						$	7		(a)			$	—					$	—
Total						$	7					$	—					$	—
Other derivative instruments
Commodity trading						$	—					$	—					$	25		(b)
Electric commodity						—						3			(c)			—
Natural gas commodity						—						10			(d)			(27)			(d)(e)
Total						$	—					$	13					$	(2)

(a)Recorded to interest charges.

(b)Recorded to electric revenues. Presented amounts do not reflect non-derivative transactions or margin sharing with customers.

(c)Recorded to electric fuel and purchased power. These derivative settlement gains and losses are shared with electric customers through fuel and purchased energy cost-recovery mechanisms and reclassified out of income as regulatory assets or liabilities, as appropriate. FTR settlements are shared with customers and do not have a material impact on net income. Presented amounts reflect changes in fair value between auction and settlement dates, but exclude the original auction fair value.

(d)Other than $3 million of 2024 losses recorded to electric fuel and purchased power, amounts are recorded to cost of natural gas sold and transported. Amounts are subject to cost-recovery mechanisms and reclassified out of income to a regulatory asset, as appropriate.

(e)Relates primarily to option premium amortization.

Xcel Energy had no derivative instruments designated as fair value hedges during the years ended Dec. 31, 2024, 2023 and 2022.

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

						Dec. 31, 2024																																				Dec. 31, 2023
						Fair Value																		Fair Value Total						Netting (a)						Total						Fair Value																		Fair Value Total						Netting (a)						Total
(Millions of Dollars)						Level 1						Level 2						Level 3															Level 1						Level 2						Level 3
Current derivative assets
Other derivative instruments:
Commodity trading						$	6					$	20					$	8					$	34					$	(23)					$	11					$	8					$	51					$	32					$	91					$	(59)					$	32
Electric commodity						—						—						90						90						(1)						89						—						—						62						62						(7)						55
Natural gas commodity						—						14						—						14						—						14						—						14						—						14						—						14
Total current derivative assets						$	6					$	34					$	98					$	138					$	(24)					114						$	8					$	65					$	94					$	167					$	(66)					101
PPAs (b)																																				—																																				3
Current derivative instruments																																				$	114																																			$	104
Noncurrent derivative assets
Other derivative instruments:
Commodity trading						$	8					$	37					$	47					$	92					$	(20)					$	72					$	14					$	51					$	45					$	110					$	(34)					$	76
Total noncurrent derivative assets						$	8					$	37					$	47					$	92					$	(20)					$	72					$	14					$	51					$	45					$	110					$	(34)					$	76

						Dec. 31, 2024																																				Dec. 31, 2023
						Fair Value																		Fair Value Total						Netting (a)						Total						Fair Value																		Fair Value Total						Netting (a)						Total
(Millions of Dollars)						Level 1						Level 2						Level 3															Level 1						Level 2						Level 3
Current derivative liabilities
Derivatives designated as cash flow hedges:
Interest rate						$	—					$	—					$	—					$	—					$	—					$	—					$	—					$	17					$	—					$	17					$	—					$	17
Other derivative instruments:
Commodity trading						7						35						5						47						(23)						24						6						86						5						97						(60)						37
Electric commodity						—						—						1						1						(1)						—						—						—						7						7						(7)						—
Natural gas commodity						—						7						—						7						—						7						—						12						—						12						—						12
Total current derivative liabilities						$	7					$	42					$	6					$	55					$	(24)					31						$	6					$	115					$	12					$	133					$	(67)					66
PPAs (b)																																				6																																				8
Current derivative instruments																																				$	37																																			$	74
Noncurrent derivative liabilities
Other derivative instruments:
Commodity trading						$	11					$	32					$	40					$	83					$	(22)					$	61					$	16					$	50					$	37					$	103					$	(39)					$	64
Total noncurrent derivative liabilities						$	11					$	32					$	40					$	83					$	(22)					61						$	16					$	50					$	37					$	103					$	(39)					64
PPAs (b)																																				16																																				22
Noncurrent derivative instruments																																				$	77																																			$	86

(a)Xcel Energy nets derivative instruments and related collateral on its consolidated balance sheets when supported by a legally enforceable master netting agreement. At Dec. 31, 2024 and 2023, derivative assets and liabilities include no obligations to return cash collateral. At Dec. 31, 2024 and 2023, derivative assets and liabilities include rights to reclaim cash collateral of $2 million and $7 million, respectively. Counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements.

(b)Xcel Energy currently applies the normal purchase exception to qualifying PPAs. Balance relates to specific contracts that were previously recognized at fair value prior to applying the normal purchase exception, and are being amortized over the remaining contract lives along with the offsetting regulatory assets and liabilities.

Changes in Level 3 commodity derivatives:

						Year Ended Dec. 31
(Millions of Dollars)						2024						2023						2022
Balance at Jan. 1						$	90					$	236					$	19
Purchases (a)						210						176						406
Settlements (a)						(303)						(154)						(350)
Net transactions recorded during the period:
(Losses) gains recognized in earnings (b)						(9)						6						151
Net gains (losses) recognized as regulatory assets and liabilities (a)						111						(174)						10
Balance at Dec. 31						$	99					$	90					$	236

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

(b)Relates to commodity trading and is subject to substantial offsetting losses and gains on derivative instruments categorized as levels 1 and 2 in the income statement. See above tables for the income statement impact of derivative activity, including commodity trading gains and losses.

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Fair Value of Long-Term Debt

As of Dec. 31, other financial instruments for which the carrying amount did not equal fair value:

						2024												2023
(Millions of Dollars)						Carrying Amount						Fair Value						Carrying Amount						Fair Value
Long-term debt, including current portion						$	28,419					$	25,115					$	25,465					$	22,927

Fair value of Xcel Energy’s long-term debt is estimated based on recent trades and observable spreads from benchmark interest rates for similar securities. Fair value estimates are based on information available to management as of Dec. 31, 2024 and 2023, and given the observability of the inputs, fair values presented for long-term debt were assigned as Level 2.

11. Benefit Plans and Other Postretirement Benefits

Pension and Postretirement Health Care Benefits

Xcel Energy has several noncontributory, qualified, defined benefit pension plans that cover almost all employees. All newly hired or rehired employees participate under the Cash Balance formula, which is based on pay credits using a percentage of annual eligible pay and annual interest credits.

The average annual interest crediting rates for these plans was 4.90, 4.72 and 4.89% in 2024, 2023, and 2022, respectively.

Some employees may participate under legacy formulas such as the traditional final average pay or pension equity. Xcel Energy’s policy is to fully fund into an external trust the actuarially determined pension costs subject to the limitations of applicable employee benefit and tax laws.

In addition to the qualified pension plans, Xcel Energy maintains a SERP and a nonqualified pension plan. The SERP is maintained for certain executives who participated in the plan in 2008, when the SERP was closed to new participants.

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

Obligations of the SERP and nonqualified plan as of Dec. 31, 2024 and 2023 were $13 million and $12 million, respectively. Xcel Energy recognized net benefit cost for the SERP and nonqualified plans of $2 million in 2024 and $2 million in 2023.

Xcel Energy’s postretirement health care benefit plan is a continuation of certain welfare benefit programs for current employees. A full-time employee’s date of hire or a retiree’s date of retirement determine eligibility for each of the programs.

Xcel Energy’s investment-return assumption considers the expected long-term performance for each of the asset classes in its pension and postretirement health care portfolio. Xcel Energy considers the historical returns achieved by its asset portfolios over long time periods, as well as the long-term projected return levels from investment experts.

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

• Investment returns in 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%.

Pension plan and postretirement benefit assets are invested in a portfolio according to Xcel Energy’s return, liquidity and diversification objectives to provide a source of funding for plan obligations and minimize contributions to the plan, within appropriate levels of risk.

The principal mechanism for achieving these objectives is the asset allocation given the long-term risk, return, correlation and liquidity characteristics of each particular asset class.

There were no significant concentrations of risk in any industry, index, or entity. Market volatility can impact even well-diversified portfolios and significantly affect the return levels achieved by the assets in any year.

State agencies also have issued guidelines to the funding of postretirement benefit costs. SPS is required to fund postretirement benefit plans for Texas and New Mexico equal to amounts collected in rates. These assets are invested in a manner consistent with the investment strategy for the pension plan.

Xcel Energy’s ongoing investment strategy is based on plan-specific investment recommendations that seek to minimize potential investment and interest rate risk as a plan’s funded status increases over time.

The investment recommendations consider many factors and generally result in a greater percentage of long-duration fixed income securities being allocated to specific plans having relatively higher funded status ratios and a greater percentage of growth assets being allocated to plans having relatively lower funded status ratios.

Plan Assets

For each of the fair value hierarchy levels, Xcel Energy’s pension plan assets measured at fair value:

						Dec. 31, 2024 (a)																														Dec. 31, 2023 (a)
(Millions of Dollars)						Level 1						Level 2						Level 3						Measured at NAV						Total						Level 1						Level 2						Level 3						Measured at NAV						Total
Cash equivalents						$	117					$	—					$	—					$	—					$	117					$	233					$	—					$	—					$	—					$	233
Commingled funds						—						—						—						1,694						1,694						491						—						—						1,235						1,726
Debt securities						—						656						6						—						662						—						683						4						—						687
Equity securities						25						—						—						—						25						35						—						—						—						35
Other						—						6						—						—						6						—						9						—						—						9
Total						$	142					$	662					$	6					$	1,694					$	2,504					$	759					$	692					$	4					$	1,235					$	2,690

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

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

						Dec. 31, 2024 (a)																														Dec. 31, 2023 (a)
(Millions of Dollars)						Level 1						Level 2						Level 3						Measured at NAV						Total						Level 1						Level 2						Level 3						Measured at NAV						Total
Cash equivalents						$	35					$	—					$	—					$	—					$	35					$	33					$	—					$	—					$	—					$	33
Insurance contracts						—						40						—						—						40						—						40						—						—						40
Commingled funds						—						—						—						68						68						22						—						—						72						94
Debt securities						—						201						—						—						201						—						187						1						—						188
Other						—						—						—						—						—						—						1						—						—						1
Total						$	35					$	241					$	—					$	68					$	344					$	55					$	228					$	1					$	72					$	356

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

Immaterial assets were transferred in or out of Level 3 for 2024 and 2023.

Funded Status — Comparisons of the actuarially computed benefit obligation, changes in plan assets and funded status of the pension and postretirement health care plans for Xcel Energy are as follows:

						Pension Benefits												Postretirement Benefits
(Millions of Dollars)						2024						2023						2024						2023
Change in Benefit Obligation:
Obligation at Jan. 1						$	2,943					$	2,871					$	394					$	405
Service cost						76						74						1						1
Interest cost						151						158						21						22
Plan amendments						—						(3)						—						—
Actuarial (gain) loss						(77)						126						55						14
Plan participants’ contributions						—						—						9						8
Benefit payments (a)						(341)						(283)						(53)						(56)
Obligation at Dec. 31						$	2,752					$	2,943					$	427					$	394
Change in Fair Value of Plan Assets:
Fair value of plan assets at Jan. 1						$	2,690					$	2,685					$	356					$	364
Actual return on plan assets						55						238						21						29
Employer contributions						100						50						11						11
Plan participants’ contributions						—						—						9						8
Benefit payments						(341)						(283)						(53)						(56)
Fair value of plan assets at Dec. 31						2,504						2,690						344						356
Funded status of plans at Dec. 31						$	(248)					$	(253)					$	(83)					$	(38)
Amounts recognized in the Consolidated Balance Sheet at Dec. 31:
Noncurrent assets						$	—					$	1					$	10					$	28
Current liabilities						—						—						(4)						(3)
Noncurrent liabilities						(248)						(254)						(89)						(63)
Net amounts recognized						$	(248)					$	(253)					$	(83)					$	(38)

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

						Pension Benefits												Postretirement Benefits
Significant Assumptions Used to Measure Benefit Obligations:						2024						2023						2024						2023
Discount rate for year-end valuation						5.88		%				5.49		%				5.88		%				5.54		%
Expected average long-term increase in compensation level						4.25		%				4.25		%				N/A						N/A
Mortality table						PRI-2012						PRI-2012						PRI-2012						PRI-2012
Health care costs trend rate — initial: Pre-65						N/A						N/A						7.00		%				6.50		%
Health care costs trend rate — initial: Post-65						N/A						N/A						7.50		%				5.50		%
Ultimate trend assumption — initial: Pre-65						N/A						N/A						4.50		%				4.50		%
Ultimate trend assumption — initial: Post-65						N/A						N/A						4.50		%				4.50		%
Years until ultimate trend is reached						N/A						N/A						9						6

Accumulated benefit obligation for the pension plan was $2,554 million and $2,728 million as of Dec. 31, 2024 and 2023, respectively.

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

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

						Pension Benefits																		Postretirement Benefits
(Millions of Dollars)						2024						2023						2022						2024						2023						2022
Service cost						$	76					$	74					$	97					$	1					$	1					$	2
Interest cost						151						158						110						21						22						15
Expected return on plan assets						(206)						(209)						(208)						(17)						(17)						(18)
Amortization of prior service credit						(2)						(1)						(1)						—						(1)						(6)
Amortization of net loss						30						22						75						2						1						2
Settlement charge (a)						67						—						71						—						—						—
Net periodic pension cost (credit)						116						44						144						7						6						(5)
Effects of regulation						(37)						30						(30)						—						—						3
Net benefit cost (credit) recognized for financial reporting						$	79					$	74					$	114					$	7					$	6					$	(2)
Significant Assumptions Used to Measure Costs:
Discount rate						5.49		%				5.80		%				3.08		%				5.54		%				5.80		%				3.09		%
Expected average long-term increase in compensation level						4.25						4.25						3.75						—						—						—
Expected average long-term rate of return on assets						6.93						6.93						6.49						5.00						5.00						4.10

(a)A settlement charge is required when the amount of all lump-sum distributions during the year is greater than the sum of the service and interest cost components of the annual net periodic pension cost. 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
(Millions of Dollars)						2024						2023						2024						2023
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost:
Net loss						$	1,074					$	1,096					$	113					$	64
Prior service credit						(8)						(9)						—						—
Total						$	1,066					$	1,087					$	113					$	64
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost Have Been Recorded as Follows Based Upon Expected Recovery in Rates:
Current regulatory assets						$	32					$	20					$	2					$	2
Noncurrent regulatory assets						983						1,014						127						79
Current regulatory liabilities						—						—						(1)						(1)
Noncurrent regulatory liabilities						—						—						(18)						(19)
Deferred income taxes						14						14						1						1
Net-of-tax accumulated other comprehensive income						37						39						2						2
Total						$	1,066					$	1,087					$	113					$	64

Measurement date						Dec. 31, 2024						Dec. 31, 2023						Dec. 31, 2024						Dec. 31, 2023

Cash Flows — Funding requirements can be impacted by changes to actuarial assumptions, actual asset levels and other calculations prescribed by the requirements of income tax and other pension-related regulations. Required contributions were made in 2022 - 2025 to meet minimum funding requirements.

Voluntary and required pension funding contributions:

• $125 million in January 2025.

• $100 million in 2024.

• $50 million in 2023.

• $50 million in 2022.

The postretirement health care plans have no funding requirements other than fulfilling benefit payment obligations when claims are presented and approved. Additional cash funding requirements are prescribed by certain state and federal rate regulatory authorities.

Voluntary postretirement funding contributions:

• $8 million expected during 2025.

• $11 million during 2024.

• $11 million during 2023.

• $13 million during 2022.

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Targeted asset allocations:

						Pension Benefits												Postretirement Benefits
						2024						2023						2024						2023
Long-duration fixed income securities						38		%				38		%				—		%				—		%
Domestic and international equity securities						31						31						25						9
Alternative investments						20						20						11						13
Short-to-intermediate fixed income securities						9						9						61						77
Cash						2						2						3						1
Total						100		%				100		%				100		%				100		%

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

Plan Amendments — 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 social security benefits for all active participants on and after Jan. 1, 2024.

Projected Benefit Payments

Xcel Energy’s projected benefit payments:

(Millions of Dollars)						Projected Pension Benefit Payments						Gross Projected Postretirement Health Care Benefit Payments						Expected Medicare Part D Subsidies						Net Projected Postretirement Health Care Benefit Payments
2025						$	235					$	44					$	3					$	41
2026						226						43						3						40
2027						229						42						3						39
2028						231						42						3						39
2029						237						40						3						37
2030-2034						1,137						187						18						169

Voluntary Retirement Program

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

Utilizing employee information and the following inputs, unfunded obligations of $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:						2024						2023
Discount rate for year-end valuation						5.00		%				5.50		%
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 $50 million in 2024, $49 million in 2023 and $46 million in 2022.

Multiemployer Plans

NSP-Minnesota and NSP-Wisconsin each contribute to several union multiemployer pension and other postretirement benefit plans, none of which are individually significant. These plans provide pension and postretirement health care benefits to certain union employees who may perform services for multiple employers and do not participate in the NSP-Minnesota and NSP-Wisconsin sponsored pension and postretirement health care plans.

Contributing to these types of plans creates risk that differs from providing benefits under NSP-Minnesota and NSP-Wisconsin sponsored plans, in that if another participating employer ceases to contribute to a multiemployer pension plan, additional unfunded obligations may need to be funded over time by remaining participating employers.

12. Commitments and Contingencies

Legal

Xcel Energy is involved in various litigation matters in the ordinary course of business. The assessment of whether a loss is probable or is a reasonable possibility, and whether the loss or a range of loss is estimable, often involves a series of complex judgments about future events. Management maintains accruals for losses probable of being incurred and subject to reasonable estimation.

Management is sometimes unable to estimate an amount or range of a reasonably possible loss in certain situations, including but not limited to when (1) the damages sought are indeterminate, (2) the proceedings are in the early stages, or (3) the matters involve novel or unsettled legal theories.

In such cases, there is considerable uncertainty regarding the timing or ultimate resolution, including a possible eventual loss. For current proceedings not specifically reported herein, management does not anticipate that the ultimate liabilities, if any, would have a material effect on Xcel Energy’s consolidated financial statements. Legal fees are generally expensed as incurred.

Gas Trading Litigation — e prime is a wholly owned subsidiary of Xcel Energy. e prime was in the business of natural gas trading and marketing but has not engaged in natural gas trading or marketing activities since 2003. Multiple lawsuits involving multiple plaintiffs seeking monetary damages were commenced against e prime and its affiliates, including Xcel Energy, between 2003 and 2009 alleging fraud and anticompetitive activities in conspiring to restrain the trade of natural gas and manipulate natural gas prices. Cases were all consolidated in the U.S. District Court in Nevada.

One case remains active which includes a multi-district litigation matter consisting of a Wisconsin purported class (Arandell Corp.). The Court issued a ruling in June 2022 granting plaintiffs’ class certification. In April 2023, the Seventh Circuit Court of Appeals heard the defendants’ appeal challenging whether the district court properly assessed class certification. A decision relating to class certification is forthcoming. Xcel Energy considers the reasonably possible loss associated with this litigation to be immaterial.

Comanche Unit 3 Litigation — In 2021, CORE filed a lawsuit in Denver County District Court, alleging PSCo breached ownership agreement terms by failing to operate Comanche Unit 3 in accordance with prudent utility practices. In April 2022, CORE filed a supplement to include damages related to a 2022 outage. Also in 2022, CORE sent notice of withdrawal from the ownership agreement based on the same alleged breaches.

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In October 2023, the jury ruled that CORE may not withdraw as a joint owner of the facility but awarded CORE lost power damages of $26 million. PSCo recognized $35 million of losses for the verdict in 2023, including estimated interest and other costs. In the fourth quarter of 2024, PSCo and CORE reached a settlement, PSCo paid CORE the agreed to amounts and all appeals and related actions have been dismissed.

Marshall Wildfire Litigation — In December 2021, a wildfire ignited in Boulder County, Colorado (Marshall Fire), which burned over 6,000 acres and destroyed or damaged over 1,000 structures. On June 8, 2023, the Boulder County Sheriff’s Office released its Marshall Fire Investigative Summary and Review and its supporting documents (Sheriff’s Report). According to an October 2022 statement from the Colorado Insurance Commissioner, the Marshall Fire is estimated to have caused more than $2 billion in property losses.

According to the Sheriff’s Report, on Dec. 30, 2021, a fire ignited on a residential property in Boulder, Colorado, located in PSCo’s service territory, for reasons unrelated to PSCo’s power lines. According to the Sheriff’s Report, approximately one hour and 20 minutes after the first ignition, a second fire ignited just south of the Marshall Mesa Trailhead in unincorporated Boulder County, Colorado, also located in PSCo’s service territory. According to the Sheriff’s Report, the second ignition started approximately 80 to 110 feet away from PSCo’s power lines in the area.

The Sheriff’s Report states that the most probable cause of the second ignition was hot particles discharged from PSCo’s power lines after one of the power lines detached from its insulator in strong winds, and further states that it cannot be ruled out that the second ignition was caused by an underground coal fire. According to the Sheriff’s Report, no design, installation or maintenance defects or deficiencies were identified on PSCo’s electrical circuit in the area of the second ignition. PSCo disputes that its power lines caused the second ignition*.*

PSCo is aware of 307 complaints, most of which have also named Xcel Energy Inc. and Xcel Energy Services Inc. as additional defendants, relating to the Marshall Fire. The complaints are on behalf of at least 4,087 plaintiffs. The complaints generally allege that PSCo’s equipment ignited the Marshall Fire and assert various causes of action under Colorado law, including negligence, premises liability, trespass, nuisance, wrongful death, willful and wanton conduct, negligent infliction of emotional distress, loss of consortium and inverse condemnation. In addition to seeking compensatory damages, certain of the complaints also seek exemplary damages.

In September 2023, the Boulder County District Court Judge consolidated the pending lawsuits into a single action for pretrial purposes and has subsequently consolidated additional lawsuits that have been filed. At the case management conference in February 2024, a trial date was set for September 2025. Discovery is now underway.

In September 2024, the Judge presiding over the consolidated cases in Boulder County issued an order regarding the trial that resolves, on a preliminary basis, certain disputes over the structure of the September 2025 trial. The Court ruled that all Plaintiffs should be bound by a trial on liability unless they opt-out with good cause. The Court also ruled that liability and damages should be largely or entirely tried separately, meaning that common questions of law and fact regarding liability would be decided first, and a majority or all of the damages phase will occur separately following the liability phase of trial. The individual plaintiffs filed a motion for reconsideration of the opt-out portion of this order, which the Court denied in November 2024, confirming that plaintiffs will have to demonstrate good cause in order to opt out of the trial. The Court also denied PSCo’s request for a change in venue, ruling that the trial will take place in Boulder County.

Colorado courts do not apply strict liability in determining an electric utility company’s liability for fire-related damages. For inverse condemnation claims, Colorado courts assess whether a defendant acted with intent to take a plaintiff’s property or intentionally took an action which has the natural consequence of taking the property. For negligence claims, Colorado courts look to whether electric power companies have operated their system with a heightened duty of care consistent with the practical conduct of its business, and liability does not extend to occurrences that cannot be reasonably anticipated.

Colorado law does not impose joint and several liability in tort actions. Instead, under Colorado law, a defendant is liable for the degree or percentage of the negligence or fault attributable to that defendant, except where the defendant conspired with another defendant. A jury’s verdict in a Colorado civil case must be unanimous. Under Colorado law, in a civil action filed before Jan. 1, 2025, other than a medical malpractice action, the total award for noneconomic loss is capped at $0.6 million per defendant unless the court finds justification to exceed that amount by clear and convincing evidence, in which case the maximum doubles.

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

In the event Xcel Energy Inc. or PSCo was found liable related to this litigation and were required to pay damages, such amounts could exceed our insurance coverage of approximately $500 million and have a material adverse effect on our financial condition, results of operations or cash flows. However, due to uncertainty as to the cause of the fire and the extent and magnitude of potential damages, Xcel Energy Inc. and PSCo are unable to estimate the amount or range of possible losses in connection with the Marshall Fire.

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.

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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. 31, 2024.

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. 31, 2024. 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

Xcel Energy’s operating subsidiaries are involved in various regulatory proceedings arising in the ordinary course of business. Until resolution, typically in the form of a rate order, uncertainties may exist regarding the ultimate rate treatment for certain activities and transactions. Amounts have been recognized for probable and reasonably estimable losses that may result. Unless otherwise disclosed, any reasonably possible range of loss in excess of any recognized amount is not expected to have a material effect on the consolidated financial statements.

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

In March 2019, the MPUC approved NSP-Minnesota’s settlement refund proposal. Additionally, the MPUC decided to withhold any decision as to NSP-Minnesota’s prudence in connection with the incident at Sherco Unit 3 until after conclusion of an appeal pending between GE and NSP-Minnesota’s insurers. In February 2020, the Minnesota Court of Appeals affirmed the district court’s judgment in favor of GE.

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

In May 2024, the ALJ recommended a customer refund of $34 million (less a portion of the proceeds received from the settlement with GE). The ALJ indicated that consideration of the $22 million of previously disallowed costs was not in the scope of their recommendation. In 2024, following contested case procedures, Xcel recognized a customer refund of $47 million for replacement power incurred during the outage.

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

In 2024, the DOC recommended customer refunds for 2023 replacement power costs incurred during an outage at the Prairie Island generating station (October 2023 through February 2024). NSP-Minnesota estimates that customer refunds would be approximately $22 million if the DOC recommendations are applied to both 2023 and 2024.

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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: May 1, 2025

• Intervenor direct testimony: July 2, 2025

• 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

• Hearing: April 17-18, 2025

• Statements of position: May 9, 2025

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

Environmental

New and changing federal and state environmental mandates can create financial liabilities for Xcel Energy, which are normally recovered through the regulated rate process.

Site Remediation

Various federal and state environmental laws impose liability where hazardous substances or other regulated materials have been released to the environment. Xcel Energy Inc.’s subsidiaries may sometimes pay all or a portion of the cost to remediate sites where past activities of their predecessors or other parties have caused environmental contamination.

Environmental contingencies could arise from various situations, including sites of former MGPs; and third-party sites, such as landfills, for which one or more of Xcel Energy Inc.’s subsidiaries are alleged to have sent wastes to that site.

MGP, Landfill and Disposal Sites

Xcel Energy is investigating, remediating or performing post-closure actions at 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 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 is subject to the CCR Rule, which imposes requirements for handling, storage, treatment and disposal of coal ash and other solid waste.

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

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

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

Investigation and/or corrective action related to groundwater impacts are currently underway at certain active and closed coal-generating facilities at a current estimated cost of at least $45 million. In addition, Xcel Energy expects to incur $15 million for investigations through 2028 to perform required reporting and assess whether corrective actions are necessary. AROs have been recorded for each of these activities, and amounts are expected to be recoverable through regulatory mechanisms.

Xcel Energy has also identified coal ash that is expected to be required to be removed from certain closed coal-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. Xcel Energy anticipates these costs will be recoverable through regulatory mechanisms.

Environmental Requirements — Air

Clean Air Act NOx Allowance Allocations — In June 2023, the EPA published final regulations for ozone under the “Good Neighbor” provisions of the Clean Air Act. The final rule applies to generation facilities in Minnesota, Texas and Wisconsin, as well as other states outside of our service territory. 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.

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

In June 2024, the U.S. Supreme Court issued an order granting a stay of the final rule. In response, the EPA issued a nationwide administrative stay of the rule. Depending on the outcomes of the underlying legal challenges, the regulation may become applicable in the future.

AROs — AROs have been recorded for Xcel Energy’s assets. For nuclear assets, the ARO is associated with the decommissioning of NSP-Minnesota nuclear generating plants.

Aggregate fair value of NSP-Minnesota’s legally restricted assets, for funding future nuclear decommissioning was $3.5 billion and $3.2 billion for 2024 and 2023, respectively.

Xcel Energy’s AROs were as follows:

(Millions of Dollars)						Jan. 1, 2024						Amounts Incurred (a)						Amounts Settled						Accretion						Cash Flow Revisions (b)						Dec. 31, 2024
Electric
Nuclear						$	2,107					$	—					$	—					$	106					$	263					$	2,476
Wind						526						—						—						19						(36)						509
Steam, hydro and other production						361						109						(6)						18						13						495
Distribution						49						—						—						2						—						51
Natural gas
Transmission and distribution						172						—						—						8						(1)						179
Other
Miscellaneous						3						—						—						—						—						3
Total liability						$	3,218					$	109					$	(6)					$	153					$	239					$	3,713

(a)Amounts incurred largely pertain to CCR coal ash regulations and new obligations associated with Sherco Solar Unit 1 , which was placed in service in 2024.

(b)In 2024, AROs were revised for changes in timing and estimates of cash flows. Changes were driven by updated assumptions in the NSP-Minnesota nuclear decommissioning triennial filing coupled with discount rate and escalation rate changes. Wind, steam, hydro and other production AROs were revised due to the results of the 2024 dismantling studies and changes in cost estimates to remediate ash containment facilities.

(Millions of Dollars)						Jan. 1, 2023						Amounts Incurred (a)						Amounts Settled						Accretion						Cash Flow Revisions (b)						Dec. 31, 2023
Electric
Nuclear						$	2,160					$	—					$	—					$	105					$	(158)					$	2,107
Wind						514						10						—						19						(17)						526
Steam, hydro and other production						348						—						(1)						15						(1)						361
Distribution						48						—						—						1						—						49
Natural gas
Transmission and distribution						307						—						—						14						(149)						172
Other
Miscellaneous						3						—						—						—						—						3
Total liability						$	3,380					$	10					$	(1)					$	154					$	(325)					$	3,218

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

(b)In 2023, AROs were revised for changes in timing and estimates of cash flows. Revisions in wind and nuclear AROs were primarily incurred due to changes in useful lives. Changes in gas transmission and distribution AROs were a result of updated gas line mileage and number of services, as well as changes to inflation and discount rate assumptions.

Indeterminate AROs — Outside of the recorded asbestos AROs, other plants or buildings may contain asbestos due to the age of many of Xcel Energy’s facilities, but no confirmation or measurement of the cost of removal could be determined as of Dec. 31, 2024. Therefore, an ARO was not recorded for these facilities.

Nuclear

Nuclear Insurance — NSP-Minnesota’s public liability for claims from any nuclear incident is limited to $16.3 billion under the Price-Anderson amendment to the Atomic Energy Act. NSP-Minnesota has $500 million of coverage for its public liability exposure with a pool of insurance companies. The remaining $15.8 billion of exposure is funded by the Secondary Financial Protection Program available from assessments by the federal government.

NSP-Minnesota is subject to assessments of up to $166 million per reactor-incident for each of its three reactors, for public liability arising from a nuclear incident at any licensed nuclear facility in the United States. The maximum funding requirement is $25 million per reactor-incident during any one year. Maximum assessments are subject to inflation adjustments.

NSP-Minnesota purchases insurance for property damage and site decontamination cleanup costs from NEIL and EMANI for each of NSP-Minnesota’s two nuclear plant sites. The coverage limits are $2.8 billion for both Monticello and Prairie Island. NEIL also provides business interruption insurance coverage up to $490 million and $420 million at Monticello and Prairie Island, respectively, including the cost of replacement power during prolonged accidental outages of nuclear generating units. Premiums are expensed over the policy term.

All companies insured with NEIL are subject to retroactive premium adjustments if losses exceed accumulated reserve funds. Capital has been accumulated in the reserve funds of NEIL and EMANI to the extent that NSP-Minnesota would have no exposure for retroactive premium assessments in case of a single incident under the business interruption and the property damage insurance coverage. NSP-Minnesota could be subject to annual maximum assessments of $19 million for business interruption insurance and $34 million for property damage insurance if losses exceed accumulated reserve funds.

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Nuclear Fuel Disposal — NSP-Minnesota is responsible for temporarily storing spent nuclear fuel from its nuclear plants. The DOE is responsible for permanently storing spent fuel from U.S. nuclear plants, but no such facility is yet available.

NSP-Minnesota owns temporary on-site storage facilities for spent fuel at its Monticello and Prairie Island nuclear plants, which consist of storage pools and dry cask facilities. The Monticello dry-cask storage facility currently stores all 30 of the authorized canisters. Monticello’s future spent fuel will continue to be placed in its spent fuel pool. The decommissioning plan addresses the disposition of spent fuel at the end of the licensed life. In October 2023, a CON for additional storage at the Monticello site was approved by the MPUC to support extended operations to 2040.

The Prairie Island dry-cask storage facility currently stores 52 of the 64 authorized casks. In February 2024, NSP-Minnesota filed a CON with the MPUC for additional storage at Prairie Island to support possible life extension to 2054.

Regulatory Plant Decommissioning Recovery — Decommissioning activities for NSP-Minnesota’s nuclear facilities are planned to begin at the end of each unit’s authorized retirement dates, which can be different than the currently approved NRC operating licenses. These decommissioning activities are planned to be completed at both facilities by 2101.

NSP-Minnesota’s current operating licenses allow continued use of its Monticello nuclear plant until 2050 and its Prairie Island nuclear plant until 2033 for Unit 1 and 2034 for Unit 2. NSP-Minnesota's authorized retirement dates are 2040 for Monticello, 2033 for 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 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. NSP-Minnesota had $3.5 billion and $3.2 billion of assets held in external decommissioning trusts at Dec. 31, 2024 and 2023, respectively.

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

Leases

Xcel Energy evaluates contracts that may contain leases, including PPAs and arrangements for the use of office space and other facilities, vehicles and equipment. A contract contains a lease if it conveys the exclusive right to control the use of a specific asset. A contract determined to contain a lease is evaluated further to determine whether the arrangement is an operating lease or a finance lease.

ROU assets represent Xcel Energy's rights to use leased assets. The present value of future operating lease payments is recognized in other current operating lease liabilities and noncurrent operating lease liabilities. These amounts, adjusted for any prepayments or incentives, are recognized as operating lease ROU assets.

Most of Xcel Energy’s leases do not contain a readily determinable discount rate. Therefore, the present value of future lease payments is generally calculated using the applicable Xcel Energy subsidiary’s estimated incremental borrowing rate (weighted average of 4.6%). For currently existing asset classes, Xcel Energy has elected the practical expedient under which non-lease components, such as asset maintenance costs included in payments, are not deducted from lease payments for the purposes of lease accounting and disclosure.

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

Operating lease ROU assets:

(Millions of Dollars)						Dec. 31, 2024						Dec. 31, 2023
PPAs						$	1,802					$	1,832
Other						373						315
Gross operating lease ROU assets						2,175						2,147
Accumulated amortization						(1,115)						(930)
Net operating lease ROU assets						$	1,060					$	1,217

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

Xcel Energy’s most significant finance lease activities are related to WYCO, a joint venture with CIG, to develop and lease natural gas pipeline, storage and compression facilities. Xcel Energy Inc. has a 50% ownership interest in WYCO. WYCO leases its facilities to CIG, and CIG operates the facilities, providing natural gas storage and transportation services to PSCo under separate service agreements.

PSCo accounts for its Totem natural gas storage service and Front Range pipeline arrangements with CIG and WYCO, respectively, as finance leases. Xcel Energy Inc. eliminates 50% of the finance lease obligation related to WYCO in the consolidated balance sheet along with an equal amount of Xcel Energy Inc.’s equity investment in WYCO.

Finance lease ROU assets:

(Millions of Dollars)						Dec. 31, 2024						Dec. 31, 2023
Gas storage facilities						$	160					$	160
Gas pipeline						21						21
Gross finance lease ROU assets						181						181
Accumulated amortization						(70)						(67)
Net finance lease ROU assets						$	111					$	114

Components of lease expense:

(Millions of Dollars)						2024						2023						2022
Operating leases
PPA capacity payments						$	228					$	241					$	241
Other operating leases (a)						43						42						39
Total operating lease expense (b)						$	271					$	283					$	280
Finance leases
Amortization of ROU assets						$	3					$	3					$	4
Interest expense on lease liability						15						15						16
Total finance lease expense						$	18					$	18					$	20

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

(b)PPA capacity payments are included in electric fuel and purchased power on the consolidated statements of income. Expense for other operating leases is included in O&M expense and electric fuel and purchased power.

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Commitments under operating and finance leases as of Dec. 31, 2024:

(Millions of Dollars)						PPA (a) (b) Operating Leases						Other Operating Leases						Total Operating Leases						Finance Leases (c)
2025						$	240					$	31					$	271					$	10
2026						210						33						243						9
2027						162						27						189						8
2028						107						27						134						8
2029						59						22						81						8
Thereafter						199						238						437						165
Total minimum obligation						977						378						1,355						208
Interest component of obligation						(115)						(146)						(261)						(146)
Present value of minimum obligation						$	862					232						1,094						62
Less current portion																		(227)						(2)
Noncurrent operating and finance lease liabilities																		$	867					$	60
Weighted-average remaining lease term in years																		8.7						35.8

(a)Amounts do not include PPAs accounted for as executory contracts and/or contingent payments, such as energy payments on renewable PPAs.

(b)PPA operating leases contractually expire at various dates through 2039.

(c)Excludes certain amounts related to Xcel Energy’s 50% ownership interest in WYCO.

PPAs and Fuel Contracts

Non-Lease PPAs — NSP-Minnesota, PSCo and SPS have entered into PPAs with other utilities and energy suppliers for purchased power to meet system load and energy requirements, operating reserve obligations and as part of wholesale and commodity trading activities. In general, these agreements provide for energy payments, based on actual energy delivered, and may also include capacity payments. Certain non-lease PPAs with various expiration dates through 2041, contain minimum energy purchase commitments. Total energy payments on those contracts were $212 million, $214 million and $182 million in 2024, 2023 and 2022, respectively.

Included in electric fuel and purchased power expenses for PPAs accounted for as executory contracts were payments for capacity of $81 million, $77 million and $75 million in 2024, 2023 and 2022, respectively.

Capacity and energy payments are contingent on the IPPs meeting contract obligations, including plant availability requirements. Certain contractual payments are adjusted based on market indices. The effects of price adjustments on financial results are mitigated through purchased energy cost recovery mechanisms.

At Dec. 31, 2024, the estimated future payments for capacity and energy that the utility subsidiaries of Xcel Energy are obligated to purchase pursuant to these non-lease contracts, subject to availability, were as follows:

(Millions of Dollars)						Capacity						Energy (a)
2025						$	51					$	111
2026						34						64
2027						14						21
2028						6						22
2029						6						22
Thereafter						2						—
Total						$	113					$	240

(a)Excludes contingent energy payments for renewable energy PPAs.

Fuel Contracts — Xcel Energy has entered into various long-term commitments for the purchase and delivery of a significant portion of its coal, nuclear fuel and natural gas requirements. These contracts expire between 2025 and 2060. Xcel Energy is required to pay additional amounts depending on actual quantities delivered under these agreements.

Estimated minimum purchases under these contracts as of Dec. 31, 2024:

(Millions of Dollars)						Coal						Nuclear fuel						Natural gas supply						Natural gas storage and transportation
2025						$	337					$	168					$	420					$	345
2026						130						62						11						350
2027						76						133						—						312
2028						1						19						—						185
2029						1						67						—						103
Thereafter						1						49						—						632
Total						$	546					$	498					$	431					$	1,927

VIEs

PPAs — Under certain PPAs, NSP-Minnesota, PSCo and SPS purchase power from IPPs for which the utility subsidiaries are required to reimburse fuel costs, or to participate in tolling arrangements under which the utility subsidiaries procure the natural gas required to produce the energy that they purchase. Xcel Energy has determined that certain IPPs are VIEs, however Xcel Energy is not subject to risk of loss from the operations of these entities, and no significant financial support is required other than contractual payments for energy and capacity.

In addition, certain solar PPAs provide an option to purchase emission allowances or sharing provisions related to production credits generated by the solar facility under contract. These specific PPAs create a variable interest in the IPP.

Xcel Energy evaluated each of these VIEs for possible consolidation, including review of qualitative factors such as the length and terms of the contract, control over O&M, control over dispatch of electricity, historical and estimated future fuel and electricity prices and financing activities. Xcel Energy concluded that these entities are not required to be consolidated in its consolidated financial statements because Xcel Energy does not have the power to direct the activities that most significantly impact the entities’ economic performance.

The utility subsidiaries had approximately 3,751 MW 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 Tolk plant from TUCO Inc. under contracts that will expire in December 2027. TUCO arranges for the purchase, receiving, transporting, unloading, handling, crushing, weighing and delivery of coal to meet SPS’ requirements. TUCO is responsible for negotiating and administering contracts with coal suppliers, transporters and handlers.

SPS has not provided any significant financial support to TUCO, other than contractual payments for delivered coal. However, the fuel contracts create a variable interest in TUCO due to SPS’ reimbursement of fuel procurement costs.

SPS has determined that TUCO is a VIE, however it has concluded that SPS is not the primary beneficiary because it does not have the power to direct the activities that most significantly impact TUCO’s economic performance.

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Low-Income Housing Limited Partnerships — Eloigne and NSP-Wisconsin have entered into limited partnerships with affordable rental housing activities that qualify for low-income housing tax credits.

Eloigne and NSP-Wisconsin, as primary beneficiaries of these activities, consolidate these limited partnerships in their consolidated financial statements.

Amounts reflected in Xcel Energy’s consolidated balance sheets for these investments include $40 million of assets and $34 million of liabilities at Dec. 31, 2024, and $41 million of assets and $35 million of liabilities at Dec. 31, 2023.

Other

Guarantees and Bond Indemnifications — Xcel Energy Inc. and its subsidiaries provide guarantees and bond indemnities, which guarantee payment or performance. Xcel Energy Inc.’s exposure is based upon the net liability under the specified agreements or transactions. Most of the guarantees and bond indemnities issued by Xcel Energy Inc. and its subsidiaries have a stated maximum amount.

As of Dec. 31, 2024 and 2023, Xcel Energy Inc. and its subsidiaries had no assets held as collateral related to their guarantees, bond indemnities and indemnification agreements. Guarantees and bond indemnities issued and outstanding for Xcel Energy were $93 million and $75 million at Dec. 31, 2024 and 2023, respectively.

Other Indemnification Agreements — Xcel Energy Inc. and its subsidiaries provide indemnifications through various contracts. These are primarily indemnifications against adverse litigation outcomes in connection with underwriting agreements, as well as breaches of representations and warranties, including corporate existence, transaction authorization and income tax matters with respect to assets sold.

Xcel Energy Inc.’s and its subsidiaries’ obligations under these agreements may be limited in terms of duration and amount. Maximum future payments under these indemnifications cannot be reasonably estimated as the dollar amounts are often not explicitly stated.

13. Other Comprehensive Income

Changes in accumulated other comprehensive loss, net of tax, for the years ended Dec. 31:

						2024
(Millions of Dollars)						Gains and Losses on Interest Rate Cash Flow Hedges						Defined Benefit Pension and Postretirement Items						Total
Accumulated other comprehensive loss at Jan. 1						$	(53)					$	(41)					$	(94)
Other comprehensive income (loss) before reclassifications						22						(3)						19
Losses reclassified from net accumulated other comprehensive loss:
Amortization of interest rate hedges						2			(a)			—						2
Amortization of net actuarial loss						—						5			(b)			5
Net current period other comprehensive income						24						2						26
Accumulated other comprehensive loss at Dec. 31						$	(29)					$	(39)					$	(68)

(a)Included in interest charges.

(b)Included in the computation of net periodic pension and postretirement benefit costs. See Note 11 for further information.

						2023
(Millions of Dollars)						Gains and Losses on Interest Rate Cash Flow Hedges						Defined Benefit Pension and Postretirement Items						Total
Accumulated other comprehensive loss at Jan. 1						$	(54)					$	(39)					$	(93)
Other comprehensive loss before reclassifications						(2)						(4)						(6)
Losses reclassified from net accumulated other comprehensive loss:
Amortization of interest rate hedges						3			(a)			—						3
Amortization of net actuarial loss						—						2			(b)			2
Net current period other comprehensive income (loss)						1						(2)						(1)
Accumulated other comprehensive loss at Dec. 31						$	(53)					$	(41)					$	(94)

(a)Included in interest charges.

(b)Included in the computation of net periodic pension and postretirement benefit costs. See Note 11 for further information.

14. Segment Information

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

The regulated electric utility and regulated natural gas utility segments are managed separately because of inherent differences between activities to serve electric customers and those required to serve natural gas customers, and as the revenue streams are dependent upon regulated rate recovery, which is separately determined for each segment. The CEO assesses financial performance, including quarterly and annual budget-to-actual and year-over-year variances in revenues and expenses, to inform operating decisions, capital investments and cost recovery strategies.

Xcel Energy has the following reportable segments:

• Regulated Electric Utility** — The regulated electric utility segment generates, purchases, transmits, distributes and sells electricity in Colorado, Michigan, Minnesota, New Mexico, North Dakota, South Dakota, Texas and Wisconsin; each state’s regulated electric utility activities qualify as an operating segment, and is aggregated into Xcel Energy’s regulated electric utility segment. In addition, this segment includes sales for resale and provides wholesale transmission service to various entities in the United States. The regulated electric utility segment also includes wholesale commodity and trading operations.

• Regulated Natural Gas Utility** — The regulated natural gas utility segment purchases, transports, stores, distributes and sells natural gas primarily in portions of Colorado, Michigan, Minnesota, North Dakota and Wisconsin; each state’s regulated natural gas utility activities qualify as an operating segment, and is aggregated into Xcel Energy’s regulated natural gas utility segment.

Equity method investments in the regulated natural gas utility segment of $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.

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Asset and capital expenditure information is not provided for Xcel Energy’s reportable segments. As an integrated electric and natural gas utility, Xcel Energy operates significant assets that are not dedicated to a specific business segment.

Reporting assets and capital expenditures by business segment would require arbitrary and potentially misleading allocations, which may not necessarily reflect the assets that would be required for the operation of the business segments on a stand-alone basis.

Certain costs, such as common depreciation, common O&M expenses and interest expense are allocated based on cost causation allocators across each segment. In addition, a general allocator is used for certain general and administrative expenses, including office supplies, rent, property insurance and general advertising.

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

Non-segment revenues include steam, appliance repair and non-utility real estate activities and revenues associated with processing solid waste into RDF and from investments in rental housing projects that qualify for low-income housing tax credits. Non-segment net loss also includes costs associated with these activities as well as unallocated corporate O&M expenses, interest charges and income taxes as well as earnings from equity method investments in energy technology funds.

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

						2024
(Millions of Dollars)						Regulated electric utility						Regulated natural gas utility						Total segments
Operating revenues						$	11,147					$	2,230					$	13,377
Intersegment revenue						2						22						24
Total segment revenues						11,149						2,252						13,401
Electric fuel and purchased power						3,788						—						3,788
Cost of natural gas sold and transported						—						951						951
O&M expenses						2,102						409						2,511
Depreciation and amortization						2,373						357						2,730
Other segment expenses, net						693						123						816
Interest charges and financing costs						767						113						880
Income tax (benefit) expense						(420)						62						(358)
Net income						$	1,846					$	237					$	2,083
Total segment revenues																		$	13,401
Eliminate intersegment revenue																		(24)
Non-segment revenues																		64
Consolidated operating revenues																		$	13,441
Total segment net income																		$	2,083
Non-segment net loss																		(147)
Consolidated net income																		$	1,936

						2023
(Millions of Dollars)						Regulated electric utility						Regulated natural gas utility						Total segments
Operating revenues						$	11,446					$	2,645					$	14,091
Intersegment revenue						2						3						5
Total segment revenues						11,448						2,648						14,096
Electric fuel and purchased power						4,278						—						4,278
Cost of natural gas sold and transported						—						1,456						1,456
O&M expenses						2,011						386						2,397
Depreciation and amortization						2,111						323						2,434
Other segment expenses, net (a)						827						118						945
Interest charges and financing costs						670						96						766
Income tax (benefit) expense						(135)						50						(85)
Net income						$	1,686					$	219					$	1,905
Total segment revenues																		$	14,096
Eliminate intersegment revenue																		(5)
Non-segment revenues																		115
Consolidated operating revenues																		$	14,206
Total segment net income																		$	1,905
Non-segment net loss																		(134)
Consolidated net income																		$	1,771

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

						2022
(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) 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

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15. Workforce Reduction

In 2023, Xcel Energy implemented workforce actions to align resources and investments with evolving business and customer needs, and streamline the organization for long-term success.

In September 2023, Xcel Energy announced a voluntary retirement program to a group of eligible non-bargaining employees, with an enhanced retirement package including certain health care and cash benefits for accepted employees. Approximately 400 employees retired under this program in December 2023.

In November 2023, Xcel Energy, Inc. also reduced its non-bargaining workforce by approximately 150 employees through an involuntary severance program.

In the fourth quarter of 2023, Xcel Energy recorded total expense of $72 million related to these workforce actions, primarily related to the estimated cost of future health plan subsidies and other medical benefits for the voluntary retirement program, as well as severance and other employee payouts and legal and other professional fees.

No such activities occurred in 2024.

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.