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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One)

☒ | QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 2025
or

☐ | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to
Commission File Number: 001-3034

Xcel Energy Inc.
(Exact Name of Registrant as Specified in its Charter)

Minnesota |  |  |  | 41-0448030
(State or Other Jurisdiction of Incorporation or Organization) |  |  |  | (I.R.S. Employer Identification No.)
414 Nicollet Mall | Minneapolis | Minnesota |  |  |  | 55401
(Address of Principal Executive Offices) |  |  |  | (Zip Code)

(612) | 330-5500
(Registrant’s Telephone Number, Including Area Code)

N/A
(Former name, former address and former fiscal year, if changed since last report)

Securities registered pursuant to Section 12(b) of the Act:

Title of each class |  | Trading Symbol(s) |  | Name of each exchange on which registered
Common Stock, $2.50 par value |  | XEL |  | Nasdaq Stock Market LLC

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. ☒ Yes ☐ No
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). ☒ Yes ☐ No
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer | ☒ |  | Accelerated filer | ☐ |
Non-accelerated filer | ☐ |  | Smaller reporting company | ☐ |
|  |  | Emerging growth company | ☐ |

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). ☐ Yes ☒ No
Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date.

Class |  | Outstanding at April 17, 2025
Common Stock, $2.50 par value |  | 576,760,613 shares

TABLE OF CONTENTS

PART I | FINANCIAL INFORMATION |
Item 1 — | Financial Statements (unaudited) | 5
| Consolidated Statements of Income | 5
| Consolidated Statements of Comprehensive Income | 6
| Consolidated Statements of Cash Flows | 7
| Consolidated Balance Sheets | 8
| Consolidated Statements of Common Stockholders’ Equity | 9
| Notes to Consolidated Financial Statements | 10
Item 2 — | Management’s Discussion and Analysis of Financial Condition and Results of Operations | 22
Item 3 — | Quantitative and Qualitative Disclosures A bout Market Risk | 32
Item 4 — | Controls and Procedures | 33
PART II | OTHER INFORMATION |
Item 1 — | Legal Proceedings | 33
Item 1A — | Risk Factors | 33
Item 2 — | Unregistered Sales of Equity Securities and Use of Proceeds | 33
Item 5 — | Other Information | 33
Item 6 — | Exhibits | 34
SIGNATURES | 35

This Form 10-Q is filed by Xcel Energy Inc. Additional information is available in various filings with the SEC. This report should be read in its entirety.
2

Definitions of Abbreviations

Xcel Energy Inc.’s Subsidiaries and Affiliates (current and former)
e prime | e prime inc.
NSP-Minnesota | Northern States Power Company, a Minnesota corporation
NSP System | The electric production and transmission system of NSP-Minnesota and NSP-Wisconsin operated on an integrated basis and managed by NSP-Minnesota
NSP-Wisconsin | Northern States Power Company, a Wisconsin corporation
PSCo | Public Service Company of Colorado
SPS | Southwestern Public Service Company
Utility subsidiaries | NSP-Minnesota, NSP-Wisconsin, PSCo and SPS
WYCO | WYCO Development, LLC
Xcel Energy | Xcel Energy Inc. and its subsidiaries

Federal and State Regulatory Agencies
CPUC | Colorado Public Utilities Commission
DOC | Minnesota Department of Commerce
EPA | United States Environmental Protection Agency
FASB | Financial Accounting Standards Board
FERC | Federal Energy Regulatory Commission
MPUC | Minnesota Public Utilities Commission
NDPSC | North Dakota Public Service Commission
NMPRC | New Mexico Public Regulation Commission
NRC | Nuclear Regulatory Commission
PSCW | Public Service Commission of Wisconsin
PUCT | Public Utility Commission of Texas
SEC | Securities and Exchange Commission

Other
AFUDC | Allowance for funds used during construction
ALJ | Administrative Law Judge
ARRR | Application for rehearing, reargument, or reconsideration
ASU | Accounting standards update
ATM | At-the-market
C&I | Commercial and Industrial
CCR | Coal combustion residuals
CCR Rule | Final rule (40 CFR 257.50 - 257.107) published by EPA regulating the management, storage and disposal of CCRs as a nonhazardous waste
CDD | Cooling degree-days
CEO | Chief executive officer

CERCLA | Comprehensive Environmental Response, Compensation, and Liability Act
CFO | Chief financial officer
CO 2 | Carbon dioxide
CPCN | Certificate of Public Convenience and Necessity
CSPV | Crystalline Silicon Photovoltaic
DRIP | Dividend Reinvestment and Stock Purchase Program
EPS | Earnings per share
ETR | Effective tax rate
FTR | Financial transmission right
GAAP | United States generally accepted accounting principles
HDD | Heating degree-days
IPP | Independent power producing entity
IRP | Integrated Resource Plan
LLC | Limited liability company
MGP | Manufactured gas plant
MISO | Midcontinent Independent System Operator, Inc.
NAV | Net asset value
NOx | Nitrogen Oxides
O&M | Operating and maintenance
PFAS | Per- and Polyfluoroalkyl Substances
PIM | Performance incentive mechanism
PPA | Power purchase agreement
PSPS | Public safety power shutoff
PTC | Production tax credit
RDF | Refuse-derived fuel
RFP | Request for proposal
ROE | Return on equity
RTO | Regional Transmission Organization
SPP | Southwest Power Pool, Inc.
SRP | System resiliency plan
THI | Temperature-humidity index
UCA | Colorado Office of the Utility Consumer Advocate
VaR | Value at Risk
VIE | Variable interest entity
WMP | Wildfire mitigation plan

Measurements
GW | Gigawatts
MW | Megawatts

3

Forward-Looking Statements

Except for the historical statements contained in this report, the matters discussed herein are forward-looking statements that are subject to certain risks, uncertainties and assumptions. Such forward-looking statements, including those relating to 2025 EPS guidance, long-term EPS and dividend growth rate objectives, future sales, future expenses, future tax rates, future operating performance, estimated base capital expenditures and financing plans, projected capital additions and forecasted annual revenue requirements with respect to rider filings, expected rate increases or refunds to customers, expectations and intentions regarding regulatory proceedings, expected pension contributions, and expected impact on our results of operations, financial condition and cash flows of interest rate changes, increased credit exposure, and legal proceeding outcomes, as well as assumptions and other statements are intended to be identified in this document by the words “anticipate,” “believe,” “could,” “estimate,” “expect,” “intend,” “may,” “objective,” “outlook,” “plan,” “project,” “possible,” “potential,” “should,” “will,” “would” and similar expressions. Actual results may vary materially. Forward-looking statements speak only as of the date they are made, and we expressly disclaim any obligation to update any forward-looking information. The following factors, in addition to those discussed in Xcel Energy’s Annual Report on Form 10-K for the fiscal year ended Dec. 31, 2024 and subsequent filings with the Securities and Exchange Commission, could cause actual results to differ materially from management expectations as suggested by such forward-looking information: operational safety, including our nuclear generation facilities and other utility operations; successful long-term operational planning; commodity risks associated with energy markets and production; rising energy prices and fuel costs; qualified employee workforce and third-party contractor factors; violations of our Codes of Conduct; our ability to recover costs and our subsidiaries’ ability to recover costs from customers; changes in regulation; reductions in our credit ratings and the cost of maintaining certain contractual relationships; general economic conditions, including recessionary conditions, inflation rates, monetary fluctuations, supply chain constraints and their impact on capital expenditures and/or the ability of Xcel Energy Inc. and its subsidiaries to obtain financing on favorable terms; availability or cost of capital; our customers’ and counterparties’ ability to pay their debts to us; assumptions and costs relating to funding our employee benefit plans and health care benefits; our subsidiaries’ ability to make dividend payments; tax laws; uncertainty regarding epidemics; effects of geopolitical events, including war and acts of terrorism; cybersecurity threats and data security breaches; seasonal weather patterns; changes in environmental laws and regulations; climate change and other weather events; natural disaster and resource depletion, including compliance with any accompanying legislative and regulatory changes; costs of potential regulatory penalties and wildfire damages in excess of liability insurance coverage; regulatory changes and/or limitations related to the use of natural gas as an energy source; challenging labor market conditions and our ability to attract and retain a qualified workforce; and our ability to execute on our strategies or achieve expectations related to environmental, social and governance matters including as a result of evolving legal, regulatory and other standards, processes, and assumptions, the pace of scientific and technological developments, increased costs, the availability of requisite financing, and changes in carbon markets.
4

Table of Contents
PART I — FINANCIAL INFORMATION
ITEM 1 — FINANCIAL STATEMENTS
XCEL ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)
(amounts in millions, except per share data)

| Three Months Ended March 31 |  |
| 2025 |  | 2024 |  |  |  |
Operating revenues |  |  |  |  |  |  |
Electric | $ | 2,835 |  |  | $ | 2,685 |  |  |  |  |
Natural gas | 1,055 |  |  | 941 |  |  |  |  |
Other | 16 |  |  | 23 |  |  |  |  |
Total operating revenues | 3,906 |  |  | 3,649 |  |  |  |  |
Operating expenses |  |  |  |  |  |  |
Electric fuel and purchased power | 1,020 |  |  | 948 |  |  |  |  |
Cost of natural gas sold and transported | 513 |  |  | 483 |  |  |  |  |
Cost of sales — other | 2 |  |  | 8 |  |  |  |  |
Operating and maintenance expenses | 686 |  |  | 605 |  |  |  |  |
Conservation and demand side management expenses | 110 |  |  | 97 |  |  |  |  |
Depreciation and amortization | 728 |  |  | 658 |  |  |  |  |
Taxes (other than income taxes) | 170 |  |  | 171 |  |  |  |  |
Total operating expenses | 3,229 |  |  | 2,970 |  |  |  |  |
Operating income | 677 |  |  | 679 |  |  |  |  |
Other income, net | 7 |  |  | 14 |  |  |  |  |
(Loss) earnings from equity method investments | (1) |  |  | 8 |  |  |  |  |
Allowance for funds used during construction — equity | 48 |  |  | 37 |  |  |  |  |
Interest charges and financing costs |  |  |  |  |  |  |
Interest charges — includes other financing costs | 332 |  |  | 291 |  |  |  |  |
Allowance for funds used during construction — debt | (23) |  |  | (14) |  |  |  |  |
Total interest charges and financing costs | 309 |  |  | 277 |  |  |  |  |
Income before income taxes | 422 |  |  | 461 |  |  |  |  |
Income tax benefit | (61) |  |  | (27) |  |  |  |  |
Net income | $ | 483 |  |  | $ | 488 |  |  |  |  |
Weighted average common shares outstanding: |  |  |  |  |  |  |
Basic | 575 |  |  | 556 |  |  |  |  |
Diluted | 577 |  |  | 556 |  |  |  |  |
Earnings per average common share: |  |  |  |  |  |  |
Basic | $ | 0.84 |  |  | $ | 0.88 |  |  |  |  |
Diluted | 0.84 |  |  | 0.88 |  |  |  |  |
See Notes to Consolidated Financial Statements

5

Table of Contents
XCEL ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
(amounts in millions)

| Three Months Ended March 31 |  |
| 2025 |  | 2024 |  |  |  |
Net income | $ | 483 |  |  | $ | 488 |  |  |  |  |
Other comprehensive (loss) income |  |  |  |  |  |  |
Derivative instruments: |  |  |  |  |  |  |
Net fair value (decrease) increase, net of tax | (5) |  |  | 22 |  |  |  |  |
Reclassification of losses to net income, net of tax | 1 |  |  | 1 |  |  |  |  |
Total other comprehensive (loss) income | (4) |  |  | 23 |  |  |  |  |
Total comprehensive income | $ | 479 |  |  | $ | 511 |  |  |  |  |
See Notes to Consolidated Financial Statements

6

Table of Contents
XCEL ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
(amounts in millions)

| Three Months Ended March 31
| 2025 |  | 2024
Operating activities |  |  |
Net income | $ | 483 |  |  | $ | 488 |
Adjustments to reconcile net income to cash provided by operating activities: |  |  |
Depreciation and amortization | 734 |  |  | 664 |
Nuclear fuel amortization | 29 |  |  | 20 |
Deferred income taxes | 13 |  |  | 154 |
Allowance for equity funds used during construction | (48) |  |  | (37) |
Loss (earnings) from equity method investments | 1 |  |  | (8) |
Dividends from equity method investments | 8 |  |  | 9 |
Provision for bad debts | 19 |  |  | 17 |
Share-based compensation expense | 9 |  |  | 6 |
Changes in operating assets and liabilities: |  |  |
Accounts receivable | (58) |  |  | 78 |
Accrued unbilled revenues | 63 |  |  | 73 |
Inventories | (4) |  |  | 50 |
Other current assets | (18) |  |  | (65) |
Accounts payable | (105) |  |  | (114) |
Net regulatory assets and liabilities | 25 |  |  | 81 |
Other current liabilities | 29 |  |  | (180) |
Pension and other employee benefit obligations | (124) |  |  | (103) |
Other, net | (28) |  |  | (83) |
Net cash provided by operating activities | 1,028 |  |  | 1,050 |
Investing activities |  |  |
Capital/construction expenditures | (1,988) |  |  | (1,537) |
Purchase of investment securities | (241) |  |  | (189) |
Proceeds from the sale of investment securities | 240 |  |  | 179 |
Other, net | (2) |  |  | (9) |
Net cash used in investing activities | (1,991) |  |  | (1,556) |
Financing activities |  |  |
Proceeds from (repayments of) short-term borrowings, net | 24 |  |  | (322) |
Proceeds from issuances of long-term debt | 2,077 |  |  | 1,478 |
Proceeds from issuance of common stock | 122 |  |  | 8 |
Dividends paid | (306) |  |  | (280) |
Other, net | (10) |  |  | (6) |
Net cash provided by financing activities | 1,907 |  |  | 878 |
Net change in cash, cash equivalents and restricted cash | 944 |  |  | 372 |
Cash, cash equivalents and restricted cash at beginning of period | 179 |  |  | 129 |
Cash, cash equivalents and restricted cash at end of period | $ | 1,123 |  |  | $ | 501 |
Supplemental disclosure of cash flow information: |  |  |
Cash paid for interest (net of amounts capitalized) | $ | (252) |  |  | $ | (230) |
Cash received for income taxes, net; includes proceeds from tax credit transfers | 64 |  |  | 131 |
Supplemental disclosure of non-cash investing and financing transactions: |  |  |
Accrued property, plant and equipment additions | $ | 891 |  |  | $ | 452 |
Inventory transfers to property, plant and equipment | 61 |  |  | 99 |
Operating lease right-of-use assets | 55 |  |  | — |
Allowance for equity funds used during construction | 48 |  |  | 37 |
Issuance of common stock for reinvested dividends and/or equity awards | 18 |  |  | 15 |
See Notes to Consolidated Financial Statements

7

Table of Contents
XCEL ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (UNAUDITED)
(amounts in millions, except share and per share data

| March 31, 2025 |  | Dec. 31, 2024
Assets |  |  |
Current assets |  |  |
Cash and cash equivalents | $ | 1,123 |  |  | $ | 179 |
Accounts receivable, net | 1,287 |  |  | 1,249 |
Accrued unbilled revenues | 769 |  |  | 832 |
Inventories | 625 |  |  | 666 |
Regulatory assets | 627 |  |  | 561 |
Derivative instruments | 113 |  |  | 114 |
Prepaid taxes | 75 |  |  | 72 |
Prepayments and other | 749 |  |  | 652 |
Total current assets | 5,368 |  |  | 4,325 |
Property, plant and equipment, net | 58,807 |  |  | 57,198 |
Other assets |  |  |
Nuclear decommissioning fund and other investments | 3,888 |  |  | 3,896 |
Regulatory assets | 2,806 |  |  | 2,849 |
Derivative instruments | 73 |  |  | 72 |
Operating lease right-of-use assets | 1,077 |  |  | 1,060 |
Other | 730 |  |  | 635 |
Total other assets | 8,574 |  |  | 8,512 |
Total assets | $ | 72,749 |  |  | $ | 70,035 |
Liabilities and Equity |  |  |
Current liabilities |  |  |
Current portion of long-term debt | $ | 1,103 |  |  | $ | 1,103 |
Short-term debt | 719 |  |  | 695 |
Accounts payable | 1,942 |  |  | 1,781 |
Regulatory liabilities | 815 |  |  | 852 |
Taxes accrued | 631 |  |  | 535 |
Accrued interest | 330 |  |  | 280 |
Dividends payable | 328 |  |  | 314 |
Derivative instruments | 37 |  |  | 37 |
Operating lease liabilities | 219 |  |  | 227 |
Other | 617 |  |  | 635 |
Total current liabilities | 6,741 |  |  | 6,459 |
Deferred credits and other liabilities |  |  |
Deferred income taxes | 5,368 |  |  | 5,319 |
Regulatory liabilities | 6,100 |  |  | 6,010 |
Asset retirement obligations | 3,756 |  |  | 3,713 |
Derivative instruments | 72 |  |  | 77 |
Customer advances | 139 |  |  | 146 |
Pension and employee benefit obligations | 352 |  |  | 477 |
Operating lease liabilities | 889 |  |  | 867 |
Other | 132 |  |  | 129 |
Total deferred credits and other liabilities | 16,808 |  |  | 16,738 |
Commitments and contingencies |  |  |
Capitalization |  |  |
Long-term debt | 29,396 |  |  | 27,316 |
Common stock — 1,000,000,000 shares authorized of $2.50 par value; 576,547,051 and 574,365,598 shares outstanding at March 31, 2025 and December 31, 2024, respectively | 1,441 |  |  | 1,436 |
Additional paid in capital | 9,729 |  |  | 9,601 |
Retained earnings | 8,706 |  |  | 8,553 |
Accumulated other comprehensive loss | (72) |  |  | (68) |
Total common stockholders’ equity | 19,804 |  |  | 19,522 |
Total liabilities and equity | $ | 72,749 |  |  | $ | 70,035 |
See Notes to Consolidated Financial Statements

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XCEL ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS’ EQUITY (UNAUDITED)
(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 |  |  |
Three Months Ended March 31, 2025 and 2024 |  |  |  |  |  |  |  |  |  |  |
Balance at Dec. 31, 2023 | 554,941,703 |  |  | $ | 1,387 |  |  | $ | 8,465 |  |  | $ | 7,858 |  |  | $ | (94) |  |  | $ | 17,616 |
Net income |  |  |  |  |  |  | 488 |  |  |  |  | 488 |
Other comprehensive income |  |  |  |  |  |  |  |  | 23 |  |  | 23 |
Dividends declared on common stock ($0.55 per share) |  |  |  |  |  |  | (304) |  |  |  |  | (304) |
Issuances of common stock | 528,599 |  |  | 2 |  |  | 10 |  |  |  |  |  |  | 12 |
Share-based compensation |  |  |  |  | 6 |  |  | — |  |  |  |  | 6 |
Balance at March 31, 2024 | 555,470,302 |  |  | $ | 1,389 |  |  | $ | 8,481 |  |  | $ | 8,042 |  |  | $ | (71) |  |  | $ | 17,841 |
Balance at Dec. 31, 2024 | 574,365,598 |  |  | $ | 1,436 |  |  | $ | 9,601 |  |  | $ | 8,553 |  |  | $ | (68) |  |  | $ | 19,522 |
Net income |  |  |  |  |  |  | 483 |  |  |  |  | 483 |
Other comprehensive income |  |  |  |  |  |  |  |  | (4) |  |  | (4) |
Dividends declared on common stock ($0.57 per share) |  |  |  |  |  |  | (328) |  |  |  |  | (328) |
Issuances of common stock | 2,181,453 |  |  | 5 |  |  | 117 |  |  |  |  |  |  | 122 |
Share-based compensation |  |  |  |  | 11 |  |  | (2) |  |  |  |  | 9 |
Balance at March 31, 2025 | 576,547,051 |  |  | $ | 1,441 |  |  | $ | 9,729 |  |  | $ | 8,706 |  |  | $ | (72) |  |  | $ | 19,804 |
See Notes to Consolidated Financial Statements

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XCEL ENERGY INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements (UNAUDITED)
In the opinion of management, the accompanying unaudited consolidated financial statements contain all adjustments necessary to present fairly, in accordance with GAAP, the financial position of Xcel Energy as of March 31, 2025 and Dec. 31, 2024; the results of Xcel Energy’s operations, including the components of net income, comprehensive income, cash flows and changes in stockholders’ equity for the three months ended March 31, 2025 and 2024.
All adjustments are of a normal, recurring nature, except as otherwise disclosed. Management has also evaluated the impact of events occurring after March 31, 2025, up to the date of issuance of these consolidated financial statements. These statements contain all necessary adjustments and disclosures resulting from that evaluation. The Dec. 31, 2024 balance sheet information has been derived from the audited 2024 consolidated financial statements included in the Xcel Energy Inc. Annual Report on Form 10-K for the year ended Dec. 31, 2024.
Notes to the consolidated financial statements have been prepared pursuant to the rules and regulations of the SEC for Quarterly Reports on Form 10-Q. Certain information and note disclosures normally included in financial statements prepared in accordance with GAAP on an annual basis have been condensed or omitted pursuant to such rules and regulations. For further information, refer to the consolidated financial statements and notes thereto included in the Xcel Energy Inc. Annual Report on Form 10-K for the year ended Dec. 31, 2024, filed with the SEC on Feb. 27, 2025.
Due to the seasonality of Xcel Energy’s electric and natural gas sales, interim results are not necessarily an appropriate base from which to project annual results.

1. Summary of Significant Accounting Policies

The significant accounting policies set forth in Note 1 to the consolidated financial statements in the Xcel Energy Inc. Annual Report on Form 10-K for the year ended Dec. 31, 2024 appropriately represent, in all material respects, the current status of accounting policies and are incorpora ted herein by reference.

2. Accounting Pronouncements

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.
Disaggregation of Income Statement Expenses — In November 2024, the FASB issued ASU 2024-03 – Disaggregation of Income Statement Expenses, which requires disclosure of additional detail for certain categories of income statement expenses. The ASU is effective for annual periods beginning after Dec. 15, 2026 and interim reporting periods beginning after Dec. 15, 2027. Xcel Energy is currently evaluating the impact of the new disclosure guidance.

3. Selected Balance Sheet Data

(Millions of Dollars) |  | March 31, 2025 |  | Dec. 31, 2024
Accounts receivable, net |  |  |  |
Accounts receivable |  | $ | 1,394 |  |  | $ | 1,360 |
Less allowance for bad debts |  | (107) |  |  | (111) |
Accounts receivable, net |  | $ | 1,287 |  |  | $ | 1,249 |

(Millions of Dollars) |  | March 31, 2025 |  | Dec. 31, 2024
Inventories |  |  |  |
Materials and supplies |  | $ | 426 |  |  | $ | 406 |
Fuel |  | 149 |  |  | 164 |
Natural gas |  | 50 |  |  | 96 |
Total inventories |  | $ | 625 |  |  | $ | 666 |

(Millions of Dollars) |  | March 31, 2025 |  | Dec. 31, 2024
Property, plant and equipment, net |  |  |  |
Electric plant |  | $ | 57,386 |  |  | $ | 56,791 |
Natural gas plant |  | 9,951 |  |  | 9,834 |
Common and other property |  | 3,559 |  |  | 3,515 |
Plant to be retired (a) |  | 1,730 |  |  | 1,793 |
Construction work in progress |  | 5,956 |  |  | 4,720 |
Total property, plant and equipment |  | 78,582 |  |  | 76,653 |
Less accumulated depreciation |  | (20,249) |  |  | (19,852) |
Nuclear fuel |  | 3,598 |  |  | 3,491 |
Less accumulated amortization |  | (3,124) |  |  | (3,094) |
Property, plant and equipment, net |  | $ | 58,807 |  |  | $ | 57,198 |

(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. Amounts are presented net of accumulated depreciation.

4. Borrowings and Other Financing Instruments

Short-Term Borrowings
Short-Term Debt — Xcel Energy Inc. and its utility subsidiaries meet their short-term liquidity requirements primarily through the issuance of commercial paper and borrowings under their credit facilities and term loan agreements.
Commercial paper and term loan borrowings outstanding for Xcel Energy:

(Amounts in Millions, Except Interest Rates) |  | Three Months Ended March 31, 2025 |  | Year Ended Dec. 31, 2024
Borrowing limit |  | $ | 3,550 |  |  | $ | 3,550 |
Amount outstanding at period end |  | 719 |  |  | 695 |
Average amount outstanding |  | 1,238 |  |  | 508 |
Maximum amount outstanding |  | 1,785 |  |  | 1,314 |
Weighted average interest rate, computed on a daily basis |  | 4.61 | % |  | 5.47 | %
Weighted average interest rate at period end |  | 4.65 |  |  | 4.64 |

Letters of Credit — Xcel Energy Inc. and its utility subsidiaries use letters of credit, generally with terms of one year, to provide financial guarantees for certain obligations. There was $41 million and $42 million of letters of credit outstanding under the credit facilities at March 31, 2025 and Dec. 31, 2024, respectively. Amounts approximate their fair value and are subject to fees.
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Revolving Credit Facilities — In order to issue commercial paper, Xcel Energy Inc. and its utility subsidiaries must have revolving credit facilities equal to or greater than the commercial paper borrowing limits and cannot issue commercial paper exceeding available credit facility capacity. 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.
As of March 31, 2025, Xcel Energy Inc. and its utility subsidiaries had the following committed revolving credit facilities available:

(Millions of Dollars) |  | Credit Facility (a) |  | Drawn (b) |  | Available
Xcel Energy Inc. |  | $ | 1,500 |  |  | $ | 420 |  |  | $ | 1,080 |
PSCo |  | 700 |  |  | 54 |  |  | 646 |
NSP-Minnesota |  | 700 |  |  | 77 |  |  | 623 |
SPS |  | 500 |  |  | 209 |  |  | 291 |
NSP-Wisconsin |  | 150 |  |  | — |  |  | 150 |
Total |  | $ | 3,550 |  |  | $ | 760 |  |  | $ | 2,790 |

(a)Expires in September 2027.
(b)Includes outstanding commercial paper and letters of credit.
Xcel Energy Inc., NSP-Minnesota, PSCo, and SPS each have the right to request an extension of the credit facility termination date for two additional one-year periods. NSP-Wisconsin has the right to request an extension of the credit facility termination date for an additional one-year period. All extension requests are subject to majority bank group approval.
All credit facility bank borrowings, outstanding letters of credit and outstanding commercial paper reduce the available capacity of the credit facility. Xcel Energy Inc. and its utility subsidiaries had no direct advances on the credit facilities outstanding as of March 31, 2025 and Dec. 31, 2024.
Bilateral Credit Agreement
In April 2025, NSP-Minnesota’s uncommitted bilateral credit agreement was renewed for an additional one-year term. The credit agreement is limited in use to support letters of credit.
As of March 31, 2025, NSP-Minnesota had $72 million of outstanding letters of credit under the $75 million bilateral credit agreement.
Long-Term Borrowings and Other Financing Instruments
During the three months ended March 31, 2025, Xcel Energy Inc. and its utility subsidiaries issued the following:
•Xcel Energy Inc. issued $350 million of 4.75% Senior Unsecured Notes due March 21, 2028 and $750 million of 5.60% Senior Unsecured Notes due April 15, 2035.
•PSCo issued $400 million of 5.35% First Mortgage Bonds due May 15, 2034 and $600 million of 5.85% First Mortgage Bonds due May 15, 2055.
ATM Equity Offering — In October 2023, Xcel Energy Inc. filed a prospectus supplement under which it may sell up to $2.5 billion of its common stock through an ATM program. In 2024, 18.3 million shares of common stock were issued ($1.1 billion in net proceeds and $9 million in transaction fees paid). In the three months ended March 31, 2025, 1.75 million shares ($122 million in net proceeds and $1 million in transaction fees paid) were issued under the ATM program. As of March 31, 2025, approximately $1.08 billion remained available for sale under the ATM program.
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 March 31, 2025, 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 $1.35 billion. The agreements could also have been settled at March 31, 2025 with delivery of approximately $116 million of cash or approximately 1.7 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.
Equity through DRIP and Benefits Program — Xcel Energy issued $30 million and $17 million of equity through the DRIP and benefits programs during the three months ended March 31, 2025 and 2024, respectively. The programs allow shareholders to reinvest their dividends directly in Xcel Energy Inc. common stock.

5. Revenues

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

|  | Three Months Ended March 31, 2025
(Millions of Dollars) |  | Electric |  | Natural Gas |  | All Other |  | Total
Major revenue types |  |  |  |  |  |  |  |
Revenue from contracts with customers:
Residential |  | $ | 924 |  |  | $ | 632 |  |  | $ | 1 |  |  | $ | 1,557 |
C&I |  | 1,333 |  |  | 320 |  |  | 10 |  |  | 1,663 |
Other |  | 35 |  |  | — |  |  | 2 |  |  | 37 |
Total retail |  | 2,292 |  |  | 952 |  |  | 13 |  |  | 3,257 |
Wholesale |  | 206 |  |  | — |  |  | — |  |  | 206 |
Transmission |  | 172 |  |  | — |  |  | — |  |  | 172 |
Other |  | 17 |  |  | 51 |  |  | — |  |  | 68 |
Total revenue from contracts with customers |  | 2,687 |  |  | 1,003 |  |  | 13 |  |  | 3,703 |
Alternative revenue and other |  | 148 |  |  | 52 |  |  | 3 |  |  | 203 |
Total revenues |  | $ | 2,835 |  |  | $ | 1,055 |  |  | $ | 16 |  |  | $ | 3,906 |

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|  | Three Months Ended March 31, 2024
(Millions of Dollars) |  | Electric |  | Natural Gas |  | All Other |  | Total
Major revenue types |  |  |  |  |  |  |  |
Revenue from contracts with customers:
Residential |  | $ | 859 |  |  | $ | 568 |  |  | $ | 10 |  |  | $ | 1,437 |
C&I |  | 1,276 |  |  | 274 |  |  | 9 |  |  | 1,559 |
Other |  | 34 |  |  | — |  |  | 2 |  |  | 36 |
Total retail |  | 2,169 |  |  | 842 |  |  | 21 |  |  | 3,032 |
Wholesale |  | 173 |  |  | — |  |  | — |  |  | 173 |
Transmission |  | 158 |  |  | — |  |  | — |  |  | 158 |
Other |  | 19 |  |  | 59 |  |  | — |  |  | 78 |
Total revenue from contracts with customers |  | 2,519 |  |  | 901 |  |  | 21 |  |  | 3,441 |
Alternative revenue and other |  | 166 |  |  | 40 |  |  | 2 |  |  | 208 |
Total revenues |  | $ | 2,685 |  |  | $ | 941 |  |  | $ | 23 |  |  | $ | 3,649 |

6. Income Taxes

Reconciliation between the statutory rate and ETR:

|  | Three Months Ended March 31 |  |
|  | 2025 |  | 2024 |  |  |  |
Federal statutory rate |  | 21.0 | % |  | 21.0 | % |  |  |  |
State income tax on pretax income, net of federal tax effect |  | 4.7 |  |  | 4.8 |  |  |  |  |
(Decreases) increases: |  |  |  |  |  |  |  |
PTCs (a) |  | (33.1) |  |  | (25.9) |  |  |  |  |
Plant regulatory differences (b) |  | (6.7) |  |  | (5.6) |  |  |  |  |
Other tax credits, net operating loss & tax credit allowances |  | (1.2) |  |  | (0.6) |  |  |  |  |
Other, net |  | 0.8 |  |  | 0.4 |  |  |  |  |
Effective income tax rate |  | (14.5) | % |  | (5.9) | % |  |  |  |

(a)Wind and solar PTCs (net of estimated transfer discounts) are generally credited to customers (reduction to revenue) and do not materially impact net income.
(b)Plant regulatory differences primarily relate to the credit of excess deferred taxes to customers. Income tax benefits associated with the credit are offset by corresponding revenue reductions.

7. Earnings Per Share

Basic EPS was computed by dividing the earnings available to common shareholders by the average weighted 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.
Common Stock Equivalents — Common stock equivalents include commitments to issue common stock related to forward equity agreements and time-based equity compensation awards. To the extent dilutive, these items are included in diluted shares outstanding using the treasury stock method.
Stock equivalent units granted to Xcel Energy Inc.’s Board of Directors are included in common shares outstanding upon grant date as there is no further service, performance or market condition associated with these awards. Restricted stock issued to employees 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 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:

|  | Three Months Ended March 31 |  |
(Shares in Millions) |  | 2025 |  | 2024 |  |  |  |
Basic |  | 575 |  |  | 556 |  |  |  |  |
Diluted (a) |  | 577 |  |  | 556 |  |  |  |  |

(a)Diluted common shares outstanding included common stock equivalents of 1.4 million and 0.2 million for the three months ended March 31, 2025 and 2024, respectively.

8. 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.
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Commodity derivatives — Methods used to measure the fair value of commodity derivative forwards and options utilize forward prices and volatilities, as well as pricing adjustments for specific delivery locations, and are generally assigned a Level 2 classification. When contracts relate to inactive delivery locations or extend to periods beyond those readily observable on active exchanges, the significance of the use of less observable inputs on a valuation is evaluated and may result in Level 3 classification.
Electric commodity derivatives held by NSP-Minnesota and SPS include transmission congestion instruments, generally referred to as FTRs. FTRs purchased from an RTO are financial instruments that entitle or obligate the holder to monthly revenues or charges based on transmission congestion across a given transmission path.
The values of these instruments are derived from, and designed to offset, the costs of transmission congestion. In addition to overall transmission load, congestion is also influenced by the operating schedules of power plants and the consumption of electricity pertinent to a given transmission path. Unplanned plant outages, scheduled plant maintenance, changes in the relative costs of fuels used in generation, weather and overall changes in demand for electricity can each impact the operating schedules of the power plants on the transmission grid and the value of these instruments.
FTRs are recognized at fair value and adjusted each period prior to settlement. Given the limited observability of certain variables underlying the reported auction values of FTRs, these fair value measurements have been assigned a Level 3 classification.
Net congestion costs, including the impact of FTR settlements, are shared through fuel and purchased energy cost recovery mechanisms. As such, the fair value of the unsettled instruments (i.e., derivative asset or liability) is offset/deferred as a regulatory asset or liability.
Non-Derivative Fair Value Measurements
Nuclear Decommissioning Fund
The NRC requires NSP-Minnesota to maintain a portfolio of investments to fund the costs of decommissioning its nuclear generating plants. Assets of the nuclear decommissioning fund are legally restricted for the purpose of decommissioning these facilities. The fund contains cash equivalents, debt securities, equity securities and other investments. NSP-Minnesota uses the MPUC approved asset allocation for the investment targets by asset class for the qualified trust.
NSP-Minnesota recognizes the costs of funding the decommissioning over the lives of the nuclear plants, assuming rate recovery of all costs. Realized and unrealized gains on fund investments over the life of the fund are deferred as an offset of NSP-Minnesota’s regulatory asset or as a regulatory liability (dependent on funding status) for nuclear decommissioning costs. Consequently, any realized and unrealized gains and losses on securities in the nuclear decommissioning fund are deferred as a component of the regulatory asset/liability.
Unrealized gains for the nuclear decommissioning fund were $1.4 billion as of both March 31, 2025 and Dec. 31, 2024, and unrealized losses were $40 million and $49 million as of March 31, 2025 and Dec. 31, 2024, respectively.
Non-derivative instruments with recurring fair value measurements in the nuclear decommissioning fund:

|  | March 31, 2025
|  |  |  | Fair Value
(Millions of Dollars) |  | Cost |  | Level 1 |  | Level 2 |  | Level 3 |  | NAV |  | Total
Nuclear decommissioning fund (a)
Cash equivalents |  | $ | 49 |  |  | $ | 49 |  |  | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | 49 |
Commingled funds |  | 703 |  |  | — |  |  | — |  |  | — |  |  | 1,015 |  |  | 1,015 |
Debt securities |  | 879 |  |  | — |  |  | 856 |  |  | 14 |  |  | — |  |  | 870 |
Equity securities |  | 529 |  |  | 1,556 |  |  | 1 |  |  | — |  |  | — |  |  | 1,557 |
Total |  | $ | 2,160 |  |  | $ | 1,605 |  |  | $ | 857 |  |  | $ | 14 |  |  | $ | 1,015 |  |  | $ | 3,491 |

(a)Reported in nuclear decommissioning fund and other investments on the consolidated balance sheets, which also includes $241 million of equity method investments and $156 million of rabbi trust assets and other miscellaneous investments.

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

(a)Reported in nuclear decommissioning fund and other investments on the consolidated balance sheets, which also includes $246 million of equity method investments and $156 million of rabbi trust assets and other miscellaneous investments.
For the three months ended March 31, 2025 and 2024, there were no transfers of Level 3 investments between levels.
Contractual maturity dates of debt securities in the nuclear decommissioning fund as of March 31, 2025:

|  | Final Contractual Maturity
(Millions of Dollars) |  | Due in 1 Year or Less |  | Due in 1 to 5 Years |  | Due in 5 to 10 Years |  | Due after 10 Years |  | Total
Debt securities |  | $ | 9 |  |  | $ | 321 |  |  | $ | 258 |  |  | $ | 282 |  |  | $ | 870 |

Rabbi Trusts
Xcel Energy has established rabbi trusts to provide partial funding for future deferred compensation plan distributions. The fair value of assets held in the rabbi trusts were $107 million and $96 million at March 31, 2025 and Dec. 31, 2024, respectively, comprised of cash equivalents and mutual funds (level 1 valuation methods). Amounts are reported in nuclear decommissioning fund and other investments on the consolidated balance sheet.
Derivative Activities and Fair Value Measurements
Xcel Energy enters into derivative instruments, including forward contracts, futures, swaps and options, for trading purposes and to manage risk in connection with changes in interest rates, and utility commodity prices.
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Interest Rate Derivatives — Xcel Energy enters into contracts that effectively fix the interest rate on a specified principal amount of a hypothetical future debt issuance. These financial swaps net settle based on changes in a specified benchmark interest rate, acting as a hedge of changes in market interest rates that will impact specified anticipated debt issuances. These derivative instruments are designated as cash flow hedges for accounting purposes, with changes in fair value prior to occurrence of the hedged transactions recorded as other comprehensive income.
As of March 31, 2025, accumulated other comprehensive loss related to interest rate derivatives included $3 million of net losses expected to be reclassified into earnings during the next 12 months as the hedged transactions impact earnings. As of March 31, 2025, Xcel Energy had unsettled interest rate derivatives with a notional amount of $390 million.
See Note 11 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 March 31, 2025 and Dec. 31, 2024 for this purpose relate to FTR instruments administered by MISO and SPP. These instruments are intended to offset the impacts of transmission system congestion.
When Xcel Energy enters into derivative instruments that mitigate commodity price risk on behalf of electric and natural gas customers, the instruments are not typically designated as qualifying hedging transactions. The classification of unrealized losses or gains on these instruments as a regulatory asset or liability, if applicable, is based on approved regulatory recovery mechanisms.
As of March 31, 2025, Xcel Energy had no commodity contracts designated as cash flow hedges.
Gross notional amounts of commodity forwards, options and FTRs:

(Amounts in Millions) (a)(b) |  | March 31, 2025 |  | Dec. 31, 2024
MWh of electricity |  | 28 |  |  | 38 |
MMBtu of natural gas |  | 59 |  |  | 77 |

(a)Not reflective of net positions in the underlying commodities.
(b)Notional amounts for options included on a gross basis but weighted for the probability of exercise.
Consideration of Credit Risk and Concentrations — Xcel Energy continuously monitors the creditworthiness of counterparties to its interest rate derivatives and commodity derivative contracts prior to settlement and assesses each counterparty’s ability to perform on the transactions set forth in the contracts. Impact of credit risk was immaterial to the fair value of unsettled commodity derivatives presented on the consolidated balance sheets.
Xcel Energy’s utility subsidiaries’ often have significant concentrations of credit risk with particular entities or industries in their wholesale, trading and non-trading commodity activities.
As of March 31, 2025, two of Xcel Energy’s ten most significant counterparties for these activities, comprising $18 million, or 11%, of this credit exposure, had investment grade credit ratings from S&P Global Ratings, Moody’s Investor Services or Fitch Ratings.
Seven of the ten most significant counterparties, comprising $79 million, or 47%, 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 $39 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 March 31, 2025 and Dec. 31, 2024, there were $11 million of derivative liabilities with such underlying contract provisions.
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 March 31, 2025 and Dec. 31, 2024, there were approximately $61 million and $69 million of derivative liabilities with such underlying contract provisions, respectively.
Certain derivative instruments are also subject to contract provisions that contain adequate assurance clauses. These provisions allow counterparties to seek performance assurance, including cash collateral, in the event that a given utility subsidiary’s ability to fulfill its contractual obligations is reasonably expected to be impaired.
Xcel Energy had no collateral posted related to adequate assurance clauses in derivative contracts as of March 31, 2025 and Dec. 31, 2024.
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Recurring Derivative Fair Value Measurements
Impact of derivative activity:

|  | Pre-Tax Fair Value Gains (Losses) Recognized During the Period in: |
(Millions of Dollars) |  | Accumulated Other Comprehensive Loss |  | Regulatory Assets and Liabilities |
Three Months Ended March 31, 2025 |  |  |  |  |
Derivatives designated as cash flow hedges: |  |  |
Interest rate |  | $ | (4) |  |  | $ | — |  |
Total |  | $ | (4) |  |  | $ | — |  |
Other derivative instruments: |  |  |  |  |
Electric commodity |  | $ | — |  |  | $ | 5 |  |
Natural gas commodity |  | $ | — |  |  | $ | 7 |  | (a)
Total |  | $ | — |  |  | $ | 12 |  |
Three Months Ended March 31, 2024 |  |  |  |  |
Derivatives designated as cash flow hedges: |  |  |
Interest rate |  | $ | 29 |  |  | $ | — |  |
Total |  | $ | 29 |  |  | $ | — |  |
Other derivative instruments: |  |  |  |  |
Electric commodity |  | $ | — |  |  | $ | (1) |  |
Natural gas commodity |  | $ | — |  |  | $ | 4 |  |
Total |  | $ | — |  |  | $ | 3 |  |

(a)Other than $2 million of 2025 gains 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.

|  | 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 |
Three Months Ended March 31, 2025 |  |  |  |  |
Derivatives designated as cash flow hedges:
Interest rate |  | $ | 1 |  | (a) | $ | — |  |  | $ | — |  |
Total |  | $ | 1 |  |  | $ | — |  |  | $ | — |  |
Other derivative instruments: |  |  |  |  |
Commodity trading |  | $ | — |  |  | $ | — |  |  | $ | (13) |  | (b)
Electric commodity |  | — |  |  | (5) |  | (c) | — |  |
Natural gas commodity |  | — |  |  | — |  |  | (13) |  | (d)(e)
Total |  | $ | — |  |  | $ | (5) |  |  | $ | (26) |  |
Three Months Ended March 31, 2024 |  |  |  |  |
Derivatives designated as cash flow hedges:
Interest rate |  | $ | 1 |  | (a) | $ | — |  |  | $ | — |  |
Total |  | $ | 1 |  |  | $ | — |  |  | $ | — |  |
Other derivative instruments: |  |  |  |  |
Commodity trading |  | $ | — |  |  | $ | — |  |  | $ | (8) |  | (b)
Electric commodity |  | — |  |  | 12 |  | (c) | — |  |
Natural gas commodity |  | — |  |  | — |  |  | (14) |  | (d)(e)
Total |  | $ | — |  |  | $ | 12 |  |  | $ | (22) |  |

(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 $2 million of 2025 and 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 three months ended March 31, 2025 and 2024.
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Derivative assets and liabilities measured at fair value on a recurring basis were as follows:

|  | March 31, 2025 |  | Dec. 31, 2024
|  | Fair Value |  | Fair Value Total |  | Netting (a) |  | Total |  | Fair Value |  | Fair Value Total |  | Netting (a) |  | Total
(Millions of Dollars) |  | Level 1 |  | Level 2 |  | Level 3 |  |  |  |  | Level 1 |  | Level 2 |  | Level 3 |  |  |
Current derivative assets |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Derivatives designated as cash flow hedges: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Interest rate |  | $ | — |  |  | $ | 1 |  |  | $ | — |  |  | $ | 1 |  |  | $ | — |  |  | $ | 1 |  |  | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | — |
Other derivative instruments: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Commodity trading |  | $ | 14 |  |  | $ | 22 |  |  | $ | 12 |  |  | $ | 48 |  |  | $ | (32) |  |  | $ | 16 |  |  | $ | 6 |  |  | $ | 20 |  |  | $ | 8 |  |  | $ | 34 |  |  | $ | (23) |  |  | $ | 11 |
Electric commodity |  | — |  |  | — |  |  | 96 |  |  | 96 |  |  | — |  |  | 96 |  |  | — |  |  | — |  |  | 90 |  |  | 90 |  |  | (1) |  |  | 89 |
Natural gas commodity |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | 14 |  |  | — |  |  | 14 |  |  | — |  |  | 14 |
Total current derivative assets |  | $ | 14 |  |  | $ | 23 |  |  | $ | 108 |  |  | $ | 145 |  |  | $ | (32) |  |  | $ | 113 |  |  | $ | 6 |  |  | $ | 34 |  |  | $ | 98 |  |  | $ | 138 |  |  | $ | (24) |  |  | $ | 114 |
Noncurrent derivative assets |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Other derivative instruments: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Commodity trading |  | $ | 11 |  |  | $ | 30 |  |  | $ | 40 |  |  | $ | 81 |  |  | $ | (22) |  |  | $ | 59 |  |  | $ | 8 |  |  | $ | 37 |  |  | $ | 47 |  |  | $ | 92 |  |  | $ | (20) |  |  | $ | 72 |
Electric commodity |  | — |  |  | — |  |  | 14 |  |  | 14 |  |  | — |  |  | 14 |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |
Total noncurrent derivative assets |  | $ | 11 |  |  | $ | 30 |  |  | $ | 54 |  |  | $ | 95 |  |  | $ | (22) |  |  | $ | 73 |  |  | $ | 8 |  |  | $ | 37 |  |  | $ | 47 |  |  | $ | 92 |  |  | $ | (20) |  |  | $ | 72 |

|  | March 31, 2025 |  | Dec. 31, 2024
|  | Fair Value |  | Fair Value Total |  | Netting (a) |  | Total |  | Fair Value |  | Fair Value Total |  | Netting (a) |  | Total
(Millions of Dollars) |  | Level 1 |  | Level 2 |  | Level 3 |  |  |  |  | Level 1 |  | Level 2 |  | Level 3 |  |  |
Current derivative liabilities |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Derivatives designated as cash flow hedges: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Interest rate |  | $ | — |  |  | $ | 4 |  |  | $ | — |  |  | $ | 4 |  |  | $ | — |  |  | $ | 4 |  |  | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | — |
Other derivative instruments: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Commodity trading |  | $ | 16 |  |  | $ | 36 |  |  | $ | 7 |  |  | $ | 59 |  |  | $ | (32) |  |  | $ | 27 |  |  | $ | 7 |  |  | $ | 35 |  |  | $ | 5 |  |  | $ | 47 |  |  | $ | (23) |  |  | $ | 24 |
Electric commodity |  | — |  |  | — |  |  | 1 |  |  | 1 |  |  | (1) |  |  | — |  |  | — |  |  | — |  |  | 1 |  |  | 1 |  |  | (1) |  |  | — |
Natural gas commodity |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | 7 |  |  | — |  |  | 7 |  |  | — |  |  | 7 |
Total current derivative liabilities |  | $ | 16 |  |  | $ | 40 |  |  | $ | 8 |  |  | $ | 64 |  |  | $ | (33) |  |  | 31 |  |  | $ | 7 |  |  | $ | 42 |  |  | $ | 6 |  |  | $ | 55 |  |  | $ | (24) |  |  | 31 |
PPAs (b) |  |  |  |  |  |  |  |  |  |  |  | 6 |  |  |  |  |  |  |  |  |  |  |  |  | 6 |
Current derivative instruments |  |  |  |  |  |  |  |  |  |  |  | $ | 37 |  |  |  |  |  |  |  |  |  |  |  |  | $ | 37 |
Noncurrent derivative liabilities |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Other derivative instruments: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Commodity trading |  | $ | 12 |  |  | $ | 34 |  |  | $ | 36 |  |  | $ | 82 |  |  | $ | (25) |  |  | $ | 57 |  |  | $ | 11 |  |  | $ | 32 |  |  | $ | 40 |  |  | $ | 83 |  |  | $ | (22) |  |  | $ | 61 |
Total noncurrent derivative liabilities |  | $ | 12 |  |  | $ | 34 |  |  | $ | 36 |  |  | $ | 82 |  |  | $ | (25) |  |  | 57 |  |  | $ | 11 |  |  | $ | 32 |  |  | $ | 40 |  |  | $ | 83 |  |  | $ | (22) |  |  | 61 |
PPAs (b) |  |  |  |  |  |  |  |  |  |  |  | 15 |  |  |  |  |  |  |  |  |  |  |  |  | 16 |
Noncurrent derivative instruments |  |  |  |  |  |  |  |  |  |  |  | $ | 72 |  |  |  |  |  |  |  |  |  |  |  |  | $ | 77 |

(a)Xcel Energy nets derivative instruments and related collateral on its consolidated balance sheets when supported by a legally enforceable master netting agreement. At March 31, 2025 and Dec. 31, 2024, derivative assets and liabilities include no obligations to return cash collateral. At March 31, 2025 and Dec. 31, 2024, derivative assets and liabilities include rights to reclaim cash collateral of $4 million and $2 million, respectively. Counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements.
(b)Xcel Energy currently applies the normal purchase exception to qualifying PPAs. Balance relates to specific contracts that were previously recognized at fair value prior to applying the normal purchase exception, and are being amortized over the remaining contract lives along with the offsetting regulatory assets and liabilities.
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Changes in Level 3 commodity derivatives:

|  | Three Months Ended March 31
(Millions of Dollars) |  | 2025 |  | 2024
Balance at Jan. 1 |  | $ | 99 |  |  | $ | 90 |
Purchases (a) |  | 66 |  |  | 3 |
Settlements (a) |  | (57) |  |  | (51) |
Net transactions recorded during the period: |  |  |  |
Losses recognized in earnings (b) |  | (2) |  |  | — |
Net gains recognized as regulatory assets and liabilities (a) |  | 12 |  |  | 49 |
Balance at March 31 |  | $ | 118 |  |  | $ | 91 |

(a)Relates primarily to NSP-Minnesota and SPS FTR instruments administered by MISO and SPP.
(b)Relates to commodity trading and is subject to substantial offsetting losses and gains on derivative instruments categorized as levels 1 and 2 in the income statement. See above tables for the income statement impact of derivative activity, including commodity trading gains and losses.
Fair Value of Long-Term Debt
As of March 31, 2025, other financial instruments for which the carrying amount did not equal fair value:

|  | March 31, 2025 |  | Dec. 31, 2024
(Millions of Dollars) |  | Carrying Amount |  | Fair Value |  | Carrying Amount |  | Fair Value
Long-term debt, including current portion |  | $ | 30,499 |  |  | $ | 27,298 |  |  | $ | 28,419 |  |  | $ | 25,115 |

Fair value of Xcel Energy’s long-term debt is estimated based on recent trades and observable spreads from benchmark interest rates for similar securities. Fair value estimates are based on information available to management as of March 31, 2025 and Dec. 31, 2024, and given the observability of the inputs, fair values presented for long-term debt were assigned as Level 2.

9. Benefit Plans and Other Postretirement Benefits

Components of Net Periodic Benefit Cost (Credit)

|  | Three Months Ended March 31
|  | 2025 |  | 2024 |  | 2025 |  | 2024
(Millions of Dollars) |  | Pension Benefits |  | Postretirement Health Care Benefits
Service cost |  | $ | 19 |  |  | $ | 19 |  |  | $ | — |  |  | $ | — |
Interest cost (a) |  | 39 |  |  | 38 |  |  | 6 |  |  | 5 |
Expected return on plan assets (a) |  | (52) |  |  | (52) |  |  | (5) |  |  | (4) |
Amortization of net loss (a) |  | 7 |  |  | 7 |  |  | 1 |  |  | 1 |
Net periodic benefit cost |  | 13 |  |  | 12 |  |  | 2 |  |  | 2 |
Effects of regulation |  | 2 |  |  | 4 |  |  | — |  |  | — |
Net benefit cost recognized for financial reporting |  | $ | 15 |  |  | $ | 16 |  |  | $ | 2 |  |  | $ | 2 |

(a)The components of net periodic cost other than the service cost component are included in the line item “Other income, net” in the consolidated statements of income or capitalized on the consolidated balance sheets as a regulatory asset.
In January 2025, contributions totaling $125 million were made across Xcel Energy’s pension plans. Xcel Energy does not expect additional pension contributions during 2025.

10. 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.
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.
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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. Certain of the complaints also seek exemplary damages. In addition to asserting claims against PSCo, Xcel Energy, Inc. and Xcel Energy Services, various Plaintiffs, including insurance company plaintiffs, asserted claims against certain telecommunications companies (the Telecom Companies). In April 2025, most of the remaining plaintiffs amended their complaints to also assert claims against the Telecom Companies.
In 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.
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.
Expert discovery in the case is ongoing. In addition to the Sheriff’s Report conclusions that PSCo’s power lines likely caused the second ignition and that an underground coal fire was a possible cause of the second ignition, two other theories about the cause of the second ignition have been put forth by various plaintiffs in expert reports that were submitted in the first quarter of 2025. The first is that partially unattached telecommunications equipment contacted PSCo’s power lines, and the second is that an unidentified flying object struck PSCo’s power lines.
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.
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 225 claims for losses related to the Smokehouse Creek Fire Complex through its claims process and has reached final settlements on 151 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. 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.
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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 $290 million of total estimated losses for the matter (before available insurance). Evaluation of the cost and other attributes of completed and anticipated claim settlements for various types of property damage, including certain previously inestimable categories of claims, resulted in an increase in total estimated losses relative to the $215 million estimate as of Dec. 31, 2024.
Settlements reached as of the date of this filing total $113 million of expected loss payments, of which $79 million and $35 million were paid through March 31, 2025 and Dec. 31, 2024, respectively. A remaining estimated liability of $211 million and $180 million is presented in other current liabilities as of March 31, 2025 and Dec. 31, 2024, respectively.
The cumulative estimated probable losses of $290 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 $290 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) unsettled compensation claims for damage to trees and oil and gas equipment, or (v) other amounts that are not reasonably estimable.
Xcel Energy remains unable to reasonably estimate any additional loss or the upper end of the range because there are a number of unknown facts and legal considerations that may impact the amount of any potential liability. 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. Insurance receivables of $285 million and $210 million, net of recoveries received, are presented in prepayments and other current assets as of March 31, 2025 and Dec. 31, 2024, respectively. While SPS plans to seek recovery of all insured losses, it is unable to predict the ultimate amount and timing of such insurance recoveries.
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.
Minnesota 2023 Fuel Clause Adjustment — In March 2024, NSP-Minnesota filed its annual fuel clause adjustment true-up petition to the MPUC.
In 2024, the DOC recommended customer refunds for 2023 replacement power costs incurred during an outage at the Prairie Island generating station (October 2023 through February 2024). NSP-Minnesota estimates that customer refunds would be approximately $22 million if the DOC recommendations are applied to both 2023 and 2024.
In September 2024, the MPUC ruled NSP-Minnesota was imprudent in the operation of the Prairie Island nuclear plant based on an incident that resulted in the extended outage. The MPUC did not quantify the refund and referred the determination of the refund amount to the Office of Administrative Hearings. NSP-Minnesota recorded an estimated liability for a customer refund in 2024. 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. In March 2025, PSCo filed its rebuttal testimony, 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.
In April 2025, PSCo and CPUC Staff filed a settlement agreement that would resolve the matter, with terms including reduced return on the upgrade project totaling $8 million, recognized over five years.
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.
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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.
Water and Waste
Coal Ash Regulation — Xcel Energy is subject to the CCR Rule, which imposes requirements for handling, storage, treatment and disposal of coal ash and other solid waste.
In May 2024, final amendments to the CCR Rule were published, widening its scope to include legacy CCR surface impoundments at inactive facilities and previously exempt areas where CCR was placed directly on land at CCR-regulated facilities, including areas of beneficial use.
As a requirement of the CCR Rule, utilities must complete facility evaluations and groundwater sampling around their subject landfills, surface impoundments and certain other areas where coal ash was placed on land.
If certain impacts to groundwater are detected, utilities are required to perform additional groundwater investigations and/or perform corrective actions, beginning with an Assessment of Corrective Measures.
Investigation and/or corrective action related to groundwater impacts are currently underway at certain active and closed coal-generating facilities at a current estimated cost of at least $45 million. In addition, Xcel Energy expects to incur $15 million for investigations through 2028 to perform required reporting and assess whether corrective actions are necessary. AROs have been recorded for each of these activities, and amounts are expected to be recoverable through regulatory mechanisms.
Xcel Energy has also identified coal ash that is expected to be required to be removed from certain closed coal-generating facilities at estimated costs totaling approximately $100 million. AROs have been recorded, with the costs expected to be recoverable through regulatory mechanisms.
Xcel Energy continues to perform site investigation activities related to the CCR Rule, which may result in updates to estimated costs as well as identification of additional required corrective actions.
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.
Air
Clean Air Act NOx Allowance Allocations — In June 2023, the EPA published final regulations for ozone under the “Good Neighbor” provisions of the Clean Air Act that established NOx allowance budgets for fossil fuel-fired electric generating facilities in subject states. The final rule applies to generation facilities in Minnesota, Texas and Wisconsin, as well as other states outside of our service territory. In February 2024, the EPA proposed to include New Mexico in the rule. Compliance would require subject facilities to secure additional allowances, install NOx controls and/or develop a strategy of operations that utilizes the existing allowance allocations.
While the financial impacts of the final rule are uncertain and dependent on market forces and anticipated generation, Xcel Energy anticipates the annual costs could be significant, but would be recoverable through regulatory mechanisms.
In March 2025, the 5th Circuit Court of Appeals denied petitions challenging EPA’s disapproval of Texas’s state implementation plan, affirming inclusion of Texas facilities in the EPA’s plan. However, the plan is subject to both judicial and administrative stays and the EPA has announced that it intends to reconsider the rule.
Leases
Xcel Energy evaluates contracts that may contain leases, including PPAs and arrangements for the use of office space, land for solar developments 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.
Components of lease expense:

|  | Three Months Ended March 31
(Millions of Dollars) |  | 2025 |  | 2024
Operating leases |  |  |  |
PPA capacity payments |  | $ | 57 |  |  | $ | 58 |
Other operating leases (a) |  | 13 |  |  | 11 |
Total operating lease expense (b) |  | $ | 70 |  |  | $ | 69 |
Finance leases |  |  |  |
Amortization of ROU assets |  | $ | 1 |  |  | $ | 1 |
Interest expense on lease liability |  | 4 |  |  | 4 |
Total finance lease expense |  | $ | 5 |  |  | $ | 5 |

(a)Includes immaterial short-term lease expense for the three months ended March 31, 2025 and 2024.
(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.
Commitments under operating and finance leases as of March 31, 2025:

(Millions of Dollars) |  | PPA Operating Leases |  | Other Operating Leases |  | Total Operating Leases |  | Finance Leases (a)
Total minimum obligation |  | $ | 1,014 |  |  | $ | 368 |  |  | $ | 1,382 |  |  | $ | 206 |
Interest component of obligation |  | (131) |  |  | (143) |  |  | (274) |  |  | (145) |
Present value of minimum obligation |  | $ | 883 |  |  | 225 |  |  | 1,108 |  |  | 61 |
Less current portion |  |  |  |  |  | (219) |  |  | (2) |
Noncurrent operating and finance lease liabilities |  |  |  |  |  | $ | 889 |  |  | $ | 59 |

(a)Excludes certain amounts related to Xcel Energy’s 50% ownership interest in WYCO.
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Variable Interest Entities
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 March 31, 2025 and Dec. 31, 2024, with entities that have been determined to be variable interest entities. The PPAs have expiration dates through 2048.
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 March 31, 2025 and Dec. 31, 2024, Xcel Energy 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 approximately $104 million and $93 million at March 31, 2025 and Dec. 31, 2024, respectively.
Other Indemnification Agreements — Xcel Energy Inc. and its subsidiaries provide indemnifications through various contracts. These are primarily indemnifications against adverse litigation outcomes in connection with underwriting agreements, as well as breaches of representations and warranties, including corporate existence, 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.

11. Other Comprehensive Loss

Changes in accumulated other comprehensive loss, net of tax:

|  | Three Months Ended March 31, 2025 |  | Three Months Ended March 31, 2024
(Millions of Dollars) |  | Gains and Losses on Cash Flow Hedges |  | Defined Benefit Pension and Postretirement Items |  | Total |  | Gains and Losses on Cash Flow Hedges |  | Defined Benefit Pension and Postretirement Items |  | Total
Accumulated other comprehensive loss at Jan 1 |  | $ | (29) |  |  | $ | (39) |  |  | $ | (68) |  |  | $ | (53) |  |  | $ | (41) |  |  | $ | (94) |
Other comprehensive (loss) gain before reclassifications |  | (5) |  |  | — |  |  | (5) |  |  | 22 |  |  | — |  |  | 22 |
Losses reclassified from net accumulated other comprehensive loss: |  |  |  |  |  |  |  |  |  |  |  |
Interest rate derivatives (a) | 1 |  |  | — |  |  | 1 |  |  | 1 |  |  | — |  |  | 1 |
Net current period other comprehensive (loss) income |  | (4) |  |  | — |  |  | (4) |  |  | 23 |  |  | — |  |  | 23 |
Accumulated other comprehensive loss at March 31 |  | $ | (33) |  |  | $ | (39) |  |  | $ | (72) |  |  | $ | (30) |  |  | $ | (41) |  |  | $ | (71) |

(a)Included in interest charges.
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12. Segment Information

Segment information and reconciliation to Xcel Energy’s consolidated net income:

|  | Three Months Ended March 31, 2025
(Millions of Dollars) |  | Regulated electric utility |  | Regulated natural gas utility |  | Total segments |  |  |  |
Operating revenues |  | $ | 2,835 |  |  | $ | 1,055 |  |  | $ | 3,890 |  |  |  |  |
Intersegment revenue |  | — |  |  | 5 |  |  | 5 |  |  |  |  |
Total segment revenues |  | 2,835 |  |  | 1,060 |  |  | 3,895 |  |  |  |  |
Electric fuel and purchased power |  | 1,020 |  |  | — |  |  | 1,020 |  |  |  |  |
Cost of natural gas sold and transported |  | — |  |  | 513 |  |  | 513 |  |  |  |  |
O&M expenses |  | 567 |  |  | 106 |  |  | 673 |  |  |  |  |
Depreciation and amortization |  | 625 |  |  | 99 |  |  | 724 |  |  |  |  |
Other segment expenses, net |  | 172 |  |  | 56 |  |  | 228 |  |  |  |  |
Interest charges and financing costs |  | 204 |  |  | 30 |  |  | 234 |  |  |  |  |
Income tax (benefit) expense |  | (95) |  |  | 61 |  |  | (34) |  |  |  |  |
Net income |  | $ | 342 |  |  | $ | 195 |  |  | $ | 537 |  |  |  |  |
Total segment net income |  |  |  |  |  | $ | 537 |  |  |  |  |
Non-segment net loss |  |  |  |  |  | (54) |  |  |  |  |
Consolidated net income |  |  |  |  |  | $ | 483 |  |  |  |  |

|  | Three Months Ended March 31, 2024
(Millions of Dollars) |  | Regulated electric utility |  | Regulated natural gas utility |  | Total segments |  |  |  |
Operating revenues |  | $ | 2,685 |  |  | $ | 941 |  |  | $ | 3,626 |  |  |  |  |
Intersegment revenue |  | 1 |  |  | 1 |  |  | 2 |  |  |  |  |
Total segment revenues |  | 2,686 |  |  | 942 |  |  | 3,628 |  |  |  |  |
Electric fuel and purchased power |  | 948 |  |  | — |  |  | 948 |  |  |  |  |
Cost of natural gas sold and transported |  | — |  |  | 483 |  |  | 483 |  |  |  |  |
O&M expenses |  | 503 |  |  | 105 |  |  | 608 |  |  |  |  |
Depreciation and amortization |  | 568 |  |  | 87 |  |  | 655 |  |  |  |  |
Other segment expenses, net |  | 190 |  |  | 33 |  |  | 223 |  |  |  |  |
Interest charges and financing costs |  | 186 |  |  | 27 |  |  | 213 |  |  |  |  |
Income tax (benefit) expense |  | (67) |  |  | 49 |  |  | (18) |  |  |  |  |
Net income |  | $ | 358 |  |  | $ | 158 |  |  | $ | 516 |  |  |  |  |
Total segment net income |  |  |  |  |  | $ | 516 |  |  |  |  |
Non-segment net loss |  |  |  |  |  | (28) |  |  |  |  |
Consolidated net income |  |  |  |  |  | $ | 488 |  |  |  |  |

Equity method investments in the regulated natural gas utility segment of $85 million at both March 31, 2025 and Dec. 31, 2024, primarily relate to WYCO. Non-segment equity method investments of $156 million and $161 million as of March 31, 2025 and Dec. 31, 2024, respectively, relate to investments in energy technology funds.
Asset and capital expenditure information is not provided for Xcel Energy’s reportable segments. As an integrated electric and natural gas utility, Xcel Energy operates significant assets that are not dedicated to a specific business segment.
Reporting assets and capital expenditures by business segment would require arbitrary and potentially misleading allocations, which may not necessarily reflect the assets that would be required for the operation of the business segments on a stand-alone basis.
Certain costs, such as common depreciation, common O&M expenses and interest expense are allocated based on cost causation allocators across each segment. In addition, a general allocator is used for certain general and administrative expenses, including office supplies, rent, property insurance and general advertising.
Other segment expenses, net, for the reportable segments includes conservation and DSM expenses, taxes (other than income taxes), other income (expense), net, earnings from equity method investments, intersegment expenses and AFUDC - equity.

ITEM 2 — MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion and analysis by management focuses on those factors that had a material effect on Xcel Energy’s financial condition, results of operations and cash flows during the periods presented or are expected to have a material impact in the future. It should be read in conjunction with the accompanying unaudited consolidated financial statements and the related notes to consolidated financial statements. Due to the seasonality of Xcel Energy’s operating results, quarterly financial results are not an appropriate base from which to project annual results.
The demand for electric power and natural gas is affected by seasonal differences in the weather. In general, peak sales of electricity occur in the summer months, and peak sales of natural gas occur in the winter months. As a result, the overall operating results may fluctuate substantially on a seasonal basis. Additionally, Xcel Energy’s operations have historically generated less revenues and income when weather conditions are milder in the winter and cooler in the summer.
Non-GAAP Financial Measures
The following discussion includes financial information prepared in accordance with GAAP, as well as certain non-GAAP financial measures such as ongoing earnings and ongoing diluted EPS. Generally, a non-GAAP financial measure is a measure of a company’s financial performance, financial position or cash flows that adjusts measures calculated and presented in accordance with GAAP.
Xcel Energy’s management uses non-GAAP measures for financial planning and analysis, for reporting of results to the Board of Directors, in determining performance-based compensation and communicating its earnings outlook to analysts and investors. Non-GAAP financial measures are intended to supplement investors’ understanding of our performance and should not be considered alternatives for financial measures presented in accordance with GAAP. These measures are discussed in more detail below and may not be comparable to other companies’ similarly titled non-GAAP financial measures.
Earnings Adjusted for Certain Items (Ongoing Earnings and Ongoing Diluted EPS)
GAAP 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 Xcel Energy Inc.’s diluted EPS is calculated using the treasury stock method.
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Ongoing earnings reflect adjustments to GAAP earnings (net income) for certain items. Ongoing diluted EPS for Xcel Energy is calculated by dividing net income or loss, adjusted for certain items, by the weighted average fully diluted Xcel Energy Inc. common shares outstanding for the period. Ongoing diluted EPS for each subsidiary is calculated by dividing the net income or loss for such subsidiary, adjusted for certain items, by the weighted average fully diluted Xcel Energy Inc. common shares outstanding for the period.
We use these non-GAAP financial measures to evaluate and provide details of Xcel Energy’s core earnings and underlying performance. For instance, to present ongoing earnings and ongoing diluted EPS, we may adjust the related GAAP amounts for certain items that are non-recurring in nature. We believe these measurements are useful to investors to evaluate the actual and projected financial performance and contribution of our subsidiaries. These non-GAAP financial measures should not be considered as an alternative to measures calculated and reported in accordance with GAAP.

Results of Operations

The only common equity securities that are publicly traded are common shares of Xcel Energy Inc. Diluted earnings and EPS of each subsidiary discussed below do not represent a direct legal interest in the assets and liabilities allocated to such subsidiary but rather represent a direct interest in our assets and liabilities as a whole.
Summarized diluted EPS for Xcel Energy:

|  | Three Months Ended March 31 |  |
Diluted Earnings (Loss) Per Share |  | 2025 |  | 2024 |  |  |  |
PSCo |  | $ | 0.45 |  |  | $ | 0.39 |  |  |  |  |
NSP-Minnesota |  | 0.32 |  |  | 0.38 |  |  |  |  |
SPS |  | 0.10 |  |  | 0.10 |  |  |  |  |
NSP-Wisconsin |  | 0.07 |  |  | 0.08 |  |  |  |  |
Earnings from equity method investments — WYCO |  | 0.01 |  |  | 0.01 |  |  |  |  |
Regulated utility |  | 0.95 |  |  | 0.96 |  |  |  |  |
Xcel Energy Inc. and Other |  | (0.11) |  |  | (0.08) |  |  |  |  |
GAAP and ongoing diluted EPS |  | $ | 0.84 |  |  | $ | 0.88 |  |  |  |  |

(a)Amounts may not add due to rounding.
Summary of Earnings
Xcel Energy — Xcel Energy’s first quarter GAAP and ongoing diluted earnings were $0.84 per share compared with $0.88 per share in the same period in 2024. The change in earnings per share was primarily driven by higher O&M expenses, depreciation and interest charges, partially offset by increased recovery of infrastructure investments. Fluctuations in electric and natural gas revenues associated with changes in fuel and purchased power and/or natural gas sold and transported generally do not significantly impact earnings (changes in costs are offset by the related variation in revenues).
PSCo — GAAP and ongoing earnings increased $0.06 per share for the first quarter of 2025. The change was driven by higher recovery of electric and natural gas infrastructure investments, which was partially offset by increased depreciation and interest charges.
NSP-Minnesota — GAAP and ongoing earnings decreased $0.06 per share for the first quarter of 2025. The change was driven by increased O&M expenses and depreciation, partially offset by higher recovery of electric and natural gas infrastructure investments.
SPS — GAAP and ongoing earnings were flat for the first quarter of 2025 largely due to higher recovery of electric infrastructure investments and sales growth, offset by increased depreciation and O&M expenses.
NSP-Wisconsin — GAAP and ongoing earnings decreased $0.01 per share for the first quarter of 2025. The change was driven by higher O&M expenses, depreciation and interest charges.
Xcel Energy Inc. and Other — Primarily includes financing costs and interest income at the holding company and earnings from investment funds, which are accounted for as equity method investments. The decline in earnings was largely due to higher debt levels and the performance of the equity method investments, which primarily invest in energy technology companies.
Changes in GAAP and Ongoing EPS
Components significantly contributing to changes in 2025 EPS compared to 2024:

Diluted Earnings (Loss) Per Share |  | Three Months Ended March 31 |  |
GAAP and ongoing EPS — 2024 |  | $ | 0.88 |  |  |
Components of change - 2025 vs. 2024 |  |  |  |
Higher electric revenues |  | 0.20 |  |  |
Higher natural gas revenues |  | 0.15 |  |  |
Higher O&M expenses |  | (0.11) |  |  |
Higher electric fuel and purchased power (a) |  | (0.10) |  |  |
Higher depreciation and amortization |  | (0.09) |  |  |
Higher interest charges |  | (0.06) |  |  |
Higher costs of natural gas sold and transported (a) |  | (0.04) |  |  |
Other, net |  | 0.01 |  |  |
GAAP and ongoing EPS — 2025 |  | $ | 0.84 |  |  |

(a)Cost of electric fuel and purchased power and natural gas sold and transported are generally recovered through regulatory recovery mechanisms and offset in revenue.
Statement of Income Analysis
The following summarizes the items that affected the individual revenue and expense items reported in the consolidated statements of income.
Estimated Impact of Temperature Changes on Regulated Earnings —Unusually hot summers or cold winters increase electric and natural gas sales, while mild weather reduces electric and natural gas sales. The estimated impact of weather on earnings is based on the number of customers, temperature variances, the amount of natural gas or electricity historically used per degree of temperature and excludes any incremental related operating expenses that could result due to storm activity or vegetation management requirements.
As a result, weather deviations from normal levels can affect Xcel Energy’s financial performance. However, electric sales true-up and gas decoupling mechanisms in Minnesota predominately mitigate the positive and adverse impacts of weather in that jurisdiction.
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Degree-day or THI data is used to estimate amounts of energy required to maintain comfortable indoor temperature levels based on each day’s average temperature and humidity. HDD is the measure of the variation in the weather based on the extent to which the average daily temperature falls below 65° Fahrenheit. CDD is the measure of the variation in the weather based on the extent to which the average daily temperature rises above 65° Fahrenheit.
Each degree of temperature above 65° Fahrenheit is counted as one CDD, and each degree of temperature below 65° Fahrenheit is counted as one HDD. In Xcel Energy’s more humid service territories, a THI is used in place of CDD, which adds a humidity factor to CDD. HDD, CDD and THI are most likely to impact the usage of Xcel Energy’s residential and commercial customers. Industrial customers are less sensitive to weather. Typically, sales are not impacted in the first or fourth quarter due to THI or CDD.
Normal weather conditions are defined as either the 10, 20 or 30 year average of actual historical weather conditions. The historical period of time used in the calculation of normal weather differs by jurisdiction, based on regulatory practice. To calculate the impact of weather on demand, a demand factor is applied to the weather impact on sales. Extreme weather variations, windchill and cloud cover may not be reflected in weather-normalized estimates.
Percentage increase (decrease) in normal and actual HDD:

| Three Months Ended March 31 |  |
| 2025 vs. Normal |  | 2024 vs. Normal |  | 2025 vs. 2024 |  |  |  |  |  |
HDD | — | % |  | (11.4) | % |  | 10.7 | % |  |  |  |  |  |

Weather — Estimated impact of temperature variations on EPS compared with normal weather conditions:

| Three Months Ended March 31 |  |
| 2025 vs. Normal |  | 2024 vs. Normal |  | 2025 vs. 2024 |  |  |  |  |  |
Retail electric | $ | 0.006 |  |  | $ | (0.029) |  |  | $ | 0.035 |  |  |  |  |  |  |
Sales true-up | — |  |  | 0.016 |  |  | (0.016) |  |  |  |  |  |  |
Electric total | $ | 0.006 |  |  | $ | (0.013) |  |  | $ | 0.019 |  |  |  |  |  |  |
Firm natural gas | 0.005 |  |  | (0.027) |  |  | 0.032 |  |  |  |  |  |  |
Decoupling | 0.002 |  |  | 0.017 |  |  | (0.015) |  |  |  |  |  |  |
Natural gas total | $ | 0.007 |  |  | $ | (0.010) |  |  | $ | 0.017 |  |  |  |  |  |  |
Total | $ | 0.013 |  |  | $ | (0.023) |  |  | $ | 0.036 |  |  |  |  |  |  |

Sales — Sales growth (decline) for actual and weather-normalized sales in 2025 compared to 2024:

|  | Three Months Ended March 31
|  | PSCo |  | NSP-Minnesota |  | SPS |  | NSP-Wisconsin |  | Xcel Energy
Actual |  |  |  |  |  |  |  |  |  |
Electric residential |  | 1.3 | % |  | 5.5 | % |  | 6.2 | % |  | 9.3 | % |  | 4.3 | %
Electric C&I |  | (1.0) |  |  | 1.1 |  |  | 3.9 |  |  | 0.2 |  |  | 1.3 |
Total retail electric sales |  | (0.3) |  |  | 2.5 |  | 4.1 |  |  | 2.9 |  |  | 2.1 |
Firm natural gas sales |  | 3.2 |  |  | 17.4 |  |  | N/A |  | 26.0 |  |  | 8.8 |

|  | Three Months Ended March 31
|  | PSCo |  | NSP-Minnesota |  | SPS |  | NSP-Wisconsin |  | Xcel Energy
Weather-Normalized |  |  |  |  |  |  |  |
Electric residential |  | (0.1) | % |  | 0.2 | % |  | 3.3 | % |  | 1.9 | % |  | 0.7 | %
Electric C&I |  | (1.3) |  |  | 0.2 |  |  | 3.9 |  |  | (0.4) |  |  | 0.8 |
Total retail electric sales |  | (1.0) |  |  | 0.2 |  |  | 3.7 |  |  | 0.3 |  |  | 0.7 |
Firm natural gas sales |  | (1.7) |  |  | (0.3) |  |  | N/A |  | 5.1 |  |  | (0.8) |

|  | Three Months Ended March 31 (Leap Year Adjusted)
|  | PSCo |  | NSP-Minnesota |  | SPS |  | NSP-Wisconsin |  | Xcel Energy
Weather-Normalized
Electric residential |  | 1.1 | % |  | 1.3 | % |  | 4.5 | % |  | 3.1 | % |  | 1.8 | %
Electric C&I |  | (0.2) |  |  | 1.3 |  |  | 5.0 |  |  | 0.7 |  |  | 1.9 |
Total retail electric sales |  | 0.1 |  |  | 1.3 |  |  | 4.8 |  |  | 1.4 |  |  | 1.9 |
Firm natural gas sales |  | (0.4) |  |  | 1.0 |  |  | N/A |  | 6.4 |  |  | 0.5 |

Weather-normalized and leap-year adjusted electric sales growth (decline) — year-to-date
•PSCo — Residential sales increased due to customer growth of 1.4%, partially offset by a 0.3% decrease in use per customer. The C&I sales decline was related to lower use per customer, primarily in the wholesale trade and transportation sectors.
•NSP-Minnesota — Residential sales increased due to customer growth of 1.2% and a 0.1% increase in use per customer. C&I sales increased due to customer growth and higher use per customer, largely in the manufacturing sector.
•SPS — Residential sales increased as a result of a 3.7% increase in use per customer and customer growth of 0.8%. C&I sales increased due to higher use per customer, primarily driven by the energy sector.
•NSP-Wisconsin — Residential sales increased due to a 2.0% increase in use per customer and customer growth of 1.0%. C&I sales increased due to customer growth, experienced largely in the professional services and manufacturing sectors.
Weather-normalized and leap-year adjusted natural gas sales growth (decline) — year-to-date
•Increase in natural gas sales was driven primarily by residential and C&I customer growth in all jurisdictions and higher residential use per customer in NSP-Minnesota and NSP-Wisconsin. This was offset by decreased use per customer in PSCo residential and NSP-Minnesota C&I.
Electric Revenues
Electric revenues are impacted by fluctuations in the price of natural gas, coal and uranium, regulatory outcomes, market prices and seasonality. In addition, electric customers receive a credit for PTCs generated, which reduce electric revenue and income taxes.
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(Millions of Dollars) |  | Three Months Ended March 31, 2025 vs. 2024 |  |
Recovery of higher cost of electric fuel and purchased power |  | $ | 61 |  |  |
Non-fuel riders |  | 58 |  |  |
Regulatory rate outcomes (MN, TX and ND) |  | 29 |  |  |
Estimated impact of weather |  | 14 |  |  |
PTCs flowed back to customers (offset by lower ETR) |  | (16) |  |  |
Conservation and demand side management (offset in expense) |  | (7) |  |  |
Other, net |  | 11 |  |  |
Total increase |  | $ | 150 |  |  |

Natural Gas Revenues
Natural gas revenues vary with changing sales, the cost of natural gas and regulatory outcomes.

(Millions of Dollars) |  | Three Months Ended March 31, 2025 vs. 2024 |  |
Regulatory rate outcomes (CO and ND) |  | $ | 57 |  |  |
Recovery of higher cost of natural gas |  | 30 |  |  |
Conservation revenue (offset in expense) |  | 20 |  |  |
Estimated impact of weather (net of decoupling) |  | 13 |  |  |
Retail sales growth (net of decoupling) |  | (4) |  |  |
Other, net |  | (2) |  |  |
Total increase |  | $ | 114 |  |  |

Electric Fuel and Purchased Power — Expenses incurred for electric fuel and purchased power are impacted by fluctuations in market prices of electricity, natural gas, coal and uranium, as well as seasonality. These incurred expenses are generally recovered through various regulatory recovery mechanisms. As a result, changes in these expenses are largely offset in operating revenues and have minimal earnings impact.
Electric fuel and purchased power expenses increased $72 million for the first quarter of 2025. The increase was primarily due to increased volumes and commodity prices partially offset by timing of fuel recovery mechanisms.
Cost of Natural Gas Sold and Transported — Expenses incurred for the cost of natural gas sold are impacted by market prices and seasonality. These costs are generally recovered through various regulatory recovery mechanisms. As a result, changes in these expenses are largely offset in operating revenues and have minimal earnings impact.
Natural gas sold and transported increased $30 million for the first quarter of 2025. The increase was primarily due to higher volumes and commodity prices, partially offset by timing of fuel recovery mechanisms.
Non-Fuel Operating Expenses and Other Items
O&M Expenses — O&M expenses increased $81 million for the first quarter of 2025. The increase was primarily due to operational activities, including higher nuclear generation costs and distribution system maintenance (vegetation management, storm response and wildfire mitigation), the impact of a 2024 gain on land sale and increased insurance and benefits costs.
Depreciation and Amortization — Depreciation and amortization increased $70 million for the first quarter of 2025. The increase was largely the result of system investment as well as depreciation rate updates through regulatory proceedings.
Interest Charges — Interest charges increased $41 million for the first quarter of 2025, largely due to increased debt levels and higher interest rates.

Public Utility Regulation and Other

The FERC and various state and local regulatory commissions regulate Xcel Energy Inc.’s utility subsidiaries and West Gas Interstate. Xcel Energy 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.
Rates are designed to recover plant investment, operating costs and an allowed return on investment. Our utility subsidiaries request changes in utility rates through commission filings. Changes in operating costs can affect Xcel Energy’s financial results, depending on the timing of rate cases and implementation of final rates. Other factors affecting rate filings are new investments, sales, conservation and demand side management efforts, and the cost of capital.
In addition, the regulatory commissions authorize the ROE, capital structure and depreciation rates in rate proceedings. Decisions by these regulators can significantly impact Xcel Energy’s results of operations.
Except to the extent noted below, the circumstances set forth in Public Utility Regulation included in Item 7 of Xcel Energy’s Annual Report on Form 10-K for the year ended Dec. 31, 2024 appropriately represent, in all material respects, the current status of public utility regulation and are incorporated herein by reference.
NSP-Minnesota
Pending and Recently Concluded Regulatory Proceedings
2024 Minnesota Natural Gas Rate Case — In November 2023, NSP-Minnesota filed a request with the MPUC for a natural gas rate increase of approximately $59 million, or 9.6%. The request was based on a ROE of 10.2%, a 52.5% equity ratio and a 2024 forward test year with rate base of approximately $1.27 billion. In December 2023, the MPUC approved NSP-Minnesota’s request for interim rates, subject to refund, of approximately $51 million (implemented on Jan. 1, 2024).
In February 2025, the MPUC verbally approved the uncontested settlement agreement filed by NSP-Minnesota and various parties, which includes the following terms:
•Natural gas rate increase of $46 million, or 7.5%.
•ROE of 9.6%.
•Equity ratio of 52.5%.
•Rate base of $1.25 billion.
•No change to Commission approved decoupling.
2022 Minnesota Electric Rate Case — In October 2021, NSP-Minnesota filed a three-year electric rate case with the MPUC.
In July 2023, the MPUC approved a three-year rate increase of approximately $332 million for 2022-2024, based on a ROE of 9.25% and an equity ratio of 52.5%. The MPUC also approved a continuation of the sales true-up mechanism.
In November 2023, NSP-Minnesota filed an appeal to the Minnesota Court of Appeals regarding MPUC decisions relating to executive compensation, insurance expense and treatment of prepaid pension assets.
In January 2025, the Court issued its opinion, which upheld the commission's determination on insurance expense, but reversed and remanded the executive compensation and prepaid pension asset decisions back to the MPUC. The opinion is currently pending further action from the MPUC.
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2024 Minnesota Electric Rate Case — In November 2024, NSP-Minnesota filed an electric rate case in Minnesota, seeking a total revenue increase of $491 million (13.2%) over two years, based on an ROE of 10.3%, a 52.5% equity ratio and rate base of $13.2 billion in 2025 and $14 billion in 2026. NSP-Minnesota also requested interim rates of $224 million for 2025. In December 2024, the MPUC reduced the interim rate request for wildfire mitigation costs (as these costs were deemed as new costs not previously approved in a rate case) and approved interim rates of $192 million, effective January 1, 2025.
In March 2025, NSP-Minnesota filed supplemental direct testimony, updating its total revenue request to $473 million. The procedural schedule is as follows:
•Intervenor direct testimony: August 22, 2025
•Rebuttal testimony: October 10, 2025
•ALJ Report: April 30, 2026
•MPUC Decision: July 31, 2026
2024 North Dakota Electric Rate Case — In December 2024, NSP-Minnesota filed a request with the NDPSC for an annual electric rate increase of approximately $45 million, or 19.3% over current rates established in 2021. The filing is based on a 2025 forecast test year and includes a requested ROE of 10.3%, rate base of approximately $817 million and an equity ratio of 52.5%. In January 2025, the NDPSC approved interim rates, subject to refund, of approximately $27 million (implemented on Feb. 1, 2025). A NDPSC decision is expected in late 2025.
NSP-Wisconsin
Pending Regulatory Proceedings
Excess Liability Insurance Deferral – In February 2025, NSP-Wisconsin filed a request with the PSCW for deferred accounting treatment for excess liability insurance expense of $9.6 million incurred as a result of the October 2024 policy renewal. A PSCW decision is expected in the third quarter of 2025.
Wisconsin Electric and Natural Gas Rate Case – In March 2025, NSP-Wisconsin filed a request with the PSCW for a multi-year electric and natural gas rate increase.
For the electric utility, NSP-Wisconsin is seeking a total electric revenue increase of $94 million (11.8%) in 2026 and an incremental $57 million (7.1%) in 2027, for a total of $151 million over the two-year period of 2026 and 2027. The electric rate increase is based on electric rate base of $2.9 billion in 2026 and $3.2 billion in 2027. For the natural gas utility, NSP-Wisconsin requested a total natural gas revenue increase of $20 million (12.7%) in 2026 and an incremental $4 million (1.5%) in 2027, for a total of $24 million (14.2%) over the two-year period of 2026 and 2027. The natural gas rate increase is based on natural gas rate base of $0.3 billion in 2026 and $0.4 billion in 2027. Both the electric and natural gas rate requests are based on forward-looking test years, with a 10.0% ROE and an equity ratio of 53.5%.
The rate request is primarily driven by investments in NSP-Wisconsin’s electric and natural gas systems to enhance reliability and resiliency while ensuring safe operation. The investments also enable additional clean energy generation; the benefits of wind, solar and nuclear tax credits are incorporated in the table below.
A PSCW decision is anticipated in the fourth quarter of 2025.

(Millions of Dollars) |  | Electric |  | Natural Gas
NSPW rate base-related investment |  | $ | 176 |  |  | $ | 17 |
Interchange agreement billings (a) |  | (72) |  |  | — |
O&M expenses |  | 30 |  |  | 10 |
Sales |  | 18 |  |  | (1) |
Other |  | (1) |  |  | (2) |
NSP-Wisconsin’s filed rate request |  | $ | 151 |  |  | $ | 24 |

(a)The Interchange Agreement is a FERC cost sharing tariff under which NSP-Wisconsin and its affiliate, NSP-Minnesota allocate the costs of the integrated electric generation and transmission system.
NSP System
Resource Acquisition — In February 2024, NSP filed its Upper Midwest Resource Plan with the MPUC. In October 2024, NSP-Minnesota filed a settlement with several parties reaching agreement on the resource plan, as well as the proposed projects to be approved in the pending 800 MW firm dispatchable resource acquisition.
In February 2025, the MPUC approved the terms of the settlement agreement, including:
•The selection of the company owned 420 MW Lyon County combustion turbine.
•The selection of the company owned 300 MW 4-hour Sherco battery energy storage system.
•Multiple PPAs to proceed to the negotiation stage.
•The addition of 3,200 MW of wind, 400 MW of solar and 600 MW of stand-alone storage to be added through 2030 based on an RFP process (a portion of which is expected to be fulfilled with the resources acquired as part of the 2024 RFPs). Of these amounts, approximately 2,800 MW of wind are projected to utilize the Minnesota Energy Connection transmission line.
•Planned life extensions of the Prairie Island and Monticello nuclear plants through the early 2050s.
Additionally, the MPUC approved life extensions of the Red Wing and Mankato RDF plants to 2037 and ordered NSP-Minnesota to file a proposed tariff for customers with super-large load, largely data centers, by July 15, 2025.
NSP-Minnesota will file additional RFPs for approved resource needs beginning in late 2025 or early 2026.
NSP-Minnesota and NSP-Wisconsin are actively engaged in multiple processes and proceedings to acquire resources to meet their identified generation resource needs.
•In October 2023, NSP-Minnesota issued an RFP seeking 1,200 MW of wind assets to replace capacity and reutilize interconnection rights associated with the retiring Sherco coal facilities. The RFP closed in December 2023. NSP-Minnesota expects to file for approval of recommended projects in summer 2025.
•In 2024, NSP-Minnesota and NSP-Wisconsin each issued an RFP collectively seeking up to 1,600 MW of wind, solar, storage or hybrid resources to interconnect to the NSP System, including reutilization of the interconnection rights associated with the retiring Sherco coal units, and 650 MW of solar and storage resources to specifically reutilize the interconnection rights associated with the retiring King coal unit. NSP-Minnesota and NSP-Wisconsin announced the short listed projects in January 2025 and plan to file for the requisite approvals of the selected resources with the MPUC and PSCW, respectively, in the second half of 2025.
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PSCo
Pending and Recently Concluded Regulatory Proceedings
Colorado Natural Gas Rate Case — In January 2024, PSCo, filed a request with the CPUC seeking an increase to retail natural gas rates of $171 million (9.5%). The request was based on a 10.25% ROE, an equity ratio of 55%, a 2023 test year and a $4.2 billion year-end rate base.
In October 2024, as modified on ARRR in January 2025, the CPUC issued an order including the following key decisions:
•Use of a historic 2023 test year, with a 13-month average rate base.
•Weighted-average cost of capital of 7.0%, based on an ROE range of 9.2%-9.5% and an equity ratio range of 52%-55%.
•Acceleration of $15 million per year of depreciation expense (incremental to PSCo’s original rate request), to be held in an external trust for future decommissioning costs.
•Modifications to recoverability of certain operating expenses.
•Denial of PSCo’s decoupling proposal.
PSCo placed new rates into effect in November, as modified on ARRR in February 2025, with an annual revenue increase of approximately $125 million, inclusive of $15 million of accelerated depreciation. The UCA filed a second ARRR in February 2025. The CPUC held deliberations in April 2025 and did not order changes to the approved annual revenue increase. A written decision remains pending.
Colorado Resource Plan — In December 2023, the CPUC approved a portfolio of 5,835 MW, which includes approximately 3,100 MW of company owned resources and 2,700 MW of PPAs.
In December 2023, the CPUC approved a framework for PIMs associated with the generation projects in the portfolio. In September 2024, PSCo filed a proposal for implementation of the PIMs. In April 2025, PSCo filed an unopposed settlement, which establishes key details of the various symmetrical PIMs. Key terms include:
•A cost-to-construct PIM, in which costs over or under a deadband will be used to calculate a PIM to be shared with customers over 10 years, beginning after the in-service date.
•An operational PIM on wind and solar projects based on annual weather-normalized, curtailment-adjusted energy amounts, subject to a cap of approximately $8 million per year.
•An availability PIM on new gas generation approved in the resource plan, subject to a cap of $1 million per year.
A CPUC decision on the settlement is expected by the third quarter of 2025.
In September 2024, PSCo filed a proposed framework for CPUC review of pricing adjustments for both company owned and PPA resources to enable delivery of the approved portfolio in light of supply chain and geopolitical developments. In January 2025, the CPUC issued a decision granting limited potential pricing relief including potential tariff impacts, subject to evaluation in future CPCN proceedings for company owned projects.
PSCo filed or expects to file generation and transmission CPCNs throughout 2024 and 2025.
2024 Colorado Electric Resource Plan — In October 2024, PSCo filed its electric resource plan with the CPUC. The filing reflects the expected growth on the system, the generation resources needed to meet the projected growth and the future evaluation of competitive bids for new generation resources.
•The plan reflects a base sales forecast with 7% compound annual sales growth through 2031.
•The plan also presents a low sales forecast with a 3% compound annual sales growth through 2031.
•The resource plan includes forecasted need of 5-14 GW of new generation capacity through 2031, including renewables and firm dispatchable resources to meet the two different scenarios. The acquisitions of generation resources will be determined through a competitive solicitation after the CPUC determines the portfolio. The table below summarizes two of the proposed portfolios based on the different sales scenarios:

(Megawatts) |  | Base Plan |  | Low Load
Wind |  | 7,250 |  |  | 2,800 |
Solar |  | 3,077 |  |  | 1,200 |
Natural gas combustion turbine |  | 1,575 |  |  | 1,400 |
Storage (long duration) |  | 1,600 |  |  | — |
Other storage |  | 450 |  |  | — |
Total |  | 13,952 |  |  | 5,400 |

Answer testimony was received in April 2025. The remaining procedural schedule is as follows:
•Rebuttal testimony: May 23, 2025
•Settlement deadline: June 2, 2025
•Hearing: June 10-20, 2025
•Statements of position: July 14, 2025
A CPUC decision on the resource plan is expected by the fall of 2025 (Phase I) with the competitive solicitation for resource additions expected in early 2026.
Wildfire Mitigation Plan — In June 2024, PSCo filed an updated WMP and request for recovery of costs covering the years 2025 to 2027 with the CPUC. The estimated total cost for this plan is approximately $1.9 billion.
The WMP integrates industry experience; incorporates evolving risk assessment methodologies; adds new technology; and expands the scope, pace and scale of our work to reduce wildfire risk in a comprehensive and efficient manner.
In April 2025, PSCo filed with the CPUC a comprehensive and unanimous settlement. Key terms include:
•Approval of the updated WMP, including scope of mitigation activities and the Public Safety Power Shutoffs plan, with certain modifications.
•Cost recovery of proposed investments through a Wildfire Mitigation Adjustment rider and recovery of transmission investments through the Transmission Cost Adjustment rider.
•PSCo agrees to request approval to pursue securitization of an estimated $1.2 billion of proposed WMP investments, with a target to complete the transaction by Jan. 1, 2029.
•Extension of the excess liability insurance deferral, with a cap of $50 million after PSCo’s current policy year, which ends October 2025.
A CPUC decision is expected by the third quarter of 2025.
Colorado Senate Bill 23-291 — In May 2023, Colorado Senate Bill 23-291 was signed into law. The legislation included a number of topics including for the CPUC to adopt rules to establish fuel cost mechanisms to align the financial incentives of a utility with the interests of the utility’s customers.
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In December 2024, the CPUC adopted final rules applicable to PSCo’s natural gas utility that would assign to the Company four percent of the change in the price per MMbtu of natural gas compared to the three-year average, subject to rolling 12-month cap based on a percentage of rate base, currently estimated at $7 million. The rules require PSCo to make a filing to implement the mechanism within sixty days of becoming effective, expected later in 2025.
In December 2024, the CPUC also adopted rules for electric utilities but did not adopt a specific PIM framework, which will be further considered through additional proceedings in 2025.
SPS
Pending and Recently Concluded Regulatory Proceedings
New Mexico Resource Plan (IRP) — In October 2023, SPS filed its IRP with the NMPRC, which supports projected load growth and increasing reliability requirements, and secures replacement energy and capacity for retiring resources. SPS’ projected resource needs ranging from approximately 5,300 MW to 10,200 MW by 2030. In February 2024, the NMPRC accepted the IRP.
In July 2024, SPS issued a RFP, seeking approximately 3,200 MW of accredited generation capacity by 2030. The total capacity to be added to the system is expected to align with the range identified in the SPS IRP, depending on the types of resources proposed in the RFP and their accredited capacity factors.
Bids from the RFP were received in January and are currently being evaluated. A portfolio selection filing is expected in the second quarter of 2025 followed by a certificate of need filing for the specific assets in the third quarter of 2025. The PUCT and NMPRC are expected to rule on the portfolio in 2026.
Texas System Resiliency Plan — In December 2024, SPS filed its Texas SRP with the PUCT. Consistent with PUCT requirements, SPS’ proposed plan discusses resiliency-related risks and the five measures that have been designed to help SPS prevent, withstand, mitigate or more promptly recover from resiliency events, including wildfire.
The proposed SRP covers 2025-2028 and includes a proposed $538 million of investment across the following measures:
•Distribution overhead hardening — Replacing and reinforcing key components of the distribution overhead system.
•Distribution system protection modernization — Installing enhanced reclosers, communications equipment and replacing substation relay panels and breakers.
•Communication modernization — Building out a private LTE network, installing fiber optic cable and adding remote terminal units.
•Operational flexibility — Procuring mobile substation equipment and installing additional switching devices.
•Wildfire mitigation — Weather stations, modeling, deploying artificial intelligence and vegetation management.
In April 2025, SPS filed a unanimous stipulation and settlement agreement which includes approximately $490 million of spend over the plan period, adjusted largely to reflect the removal of the operational flexibility measure for investment in the normal course of business. The settlement also includes the deferral of distribution-related costs, including depreciation expense and carrying costs at SPS’ weighted average cost of capital.
SPS expects a PUCT decision on the settlement by the third quarter of 2025.
Excess Liability Insurance Deferral – In March 2025, SPS filed a request with the PUCT and in April 2025, SPS filed a request with the NMPRC for deferred accounting treatment for incremental excess liability insurance expense incurred as a result of the October 2024 policy renewal, estimated at approximately $30 million across the two jurisdictions. SPS has requested commission decisions by September 2025.
Other
Supply Chain
Xcel Energy’s ability to meet customer energy requirements and growing customer demand, respond to storm-related disruptions, and execute our capital expenditure program are dependent on maintaining an efficient supply chain.
Large global demand for energy-related infrastructure has stretched equipment supply chains, extended delivery dates and increased prices for items like combustion turbines, transformers and other large electrical equipment. The labor market for skilled engineering and construction resources to build renewables and gas generation has also been strained, impacting cost and availability.
In addition, manufacturing processes have experienced disruptions related to the scarcity of certain raw materials and interruptions in production and shipping. The impact of inflationary pressures, geopolitical events and federal policies have exacerbated the situation. Xcel Energy continues to monitor the situation as it remains fluid and seeks to mitigate the impacts by securing alternative suppliers and key vendor partners, increasing procurement lead times, modifying design standards, and adjusting the timing of work.
Tariffs and Trade Complaints
In May 2024, the U.S. Department of Commerce announced the initiation of anti-dumping and countervailing duty investigations of CSPV cells from Cambodia, Malaysia, Thailand and Vietnam, whether or not assembled into modules.
In April 2025, the U.S. Department of Commerce announced its final determination in the countervailing duty circumvention and anti-dumping investigations. The rates will go into effect after the U.S. International Trade Commission makes its final determination, expected in the second quarter of 2025. Xcel Energy does not expect these determinations to impact its projects.
In January of 2025, the U.S. International Trade Commission made an affirmative determination in the preliminary phase of the anti-dumping and countervailing duty investigations concerning Active Anode Material, a component of lithium-ion batteries, from China. This case will be reviewed by the U.S. Department of Commerce and the International Trade Commission over the course of 2025.
In 2025, several executive orders have been issued imposing new global and country-specific tariffs on many imports, which may impact our procurement and development activities. Due to the current tariff level on Chinese products, utility-scale battery projects are at most risk to be impacted in terms of cost and/or schedule. Additionally, executive orders have been issued relating to the permitting of wind projects and the retirement of coal facilities.
Xcel Energy continues to assess the impacts of these tariffs, executive orders, trade complaints and federal policies on its business, including company owned projects and PPAs. Xcel Energy may seek regulatory relief, if required, in its jurisdictions.
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Continued and/or further policy actions or other restrictions, disruptions in imports from key suppliers, or any new trade complaint could impact viability, timelines and costs of various projects and PPAs.
Excess Liability Insurance Coverage
Xcel Energy maintains excess liability coverage, which is intended to insure against liability to third parties. Through the third quarter of 2024, Xcel Energy had approximately $600 million of excess liability coverage; including $520 million of wildfire coverage with an annual premium of approximately $40 million. Examples of claims paid under this policy include property damage or bodily injury to members of the public caused by Xcel Energy’s employees, equipment or facilities. The increased wildfire liability risk and claims are driving a significant increase of premiums and reductions in insurance coverage in the excess liability markets, especially in the western United States. In October 2024, Xcel Energy renewed its excess liability coverage and now has $450 million of total coverage; including $450 million of wildfire coverage for the NSP System and $300 million of wildfire coverage for PSCo and SPS. The annual premium for this excess liability insurance is approximately $130 million. Xcel Energy has received an approved deferral at PSCo, and has filed for recovery through a deferral request or rate filings in other jurisdictions.

Critical Accounting Policies and Estimates

Preparation of the consolidated financial statements requires the application of accounting rules and guidance, as well as the use of estimates. Application of these policies involves judgments regarding future events, including the likelihood of success of particular projects, legal and regulatory challenges and anticipated recovery of costs. These judgments could materially impact the consolidated financial statements, based on varying assumptions. The financial and operating environment also may have a significant effect on the operation of the business and results reported. Items considered critical are included within the Xcel Energy Inc. Annual Report on Form 10-K for the year ended Dec. 31, 2024.

Environmental Regulation

In March 2025, the EPA announced that the agency will undertake various regulatory actions addressing a wide range of environmental regulations. This includes action on the 2024 power plant greenhouse gas regulations, Effluent Limitation Guidelines, the 2024 amendments to the CCR Rule and the 2023 Good Neighbor Plan, though no formal actions have been taken on these regulations to date. We will continue to monitor and respond as appropriate to EPA’s administrative efforts to take action.
Clean Air Act
Power Plant Greenhouse Gas Regulations — In April 2024, the EPA published final rules addressing control of CO 2 emissions from the power sector. The rules regulate new natural gas generating units and emission guidelines for existing coal and certain natural gas generation. The rules create subcategories of coal units based on planned retirement date and subcategories of natural gas combustion turbines and combined cycle units based on utilization. The CO 2 control requirements vary by subcategory. Based on current estimates and assumptions, Xcel Energy has determined that due to scheduled plant retirements, there is minimal financial or operational impact associated with these requirements and believes that the cost of these initiatives or replacement generation would be recoverable through rates based on prior state commission practices.
Waste-to-Energy Air Regulations — In January 2024, the EPA proposed air regulations addressing new and existing large municipal waste combustors. The proposed rules lower current emission standards for certain pollutants and would require installation of new pollution controls and/or more intense use of existing pollution controls at French Island Generating Station, Red Wing Generating Plant and Wilmarth Generating Plant. Until final rules are issued, it is not certain what the impact will be on Xcel Energy. Xcel Energy believes that the cost of these initiatives or replacement generation would be recoverable through rates based on prior state commission practices.
Emerging Contaminants of Concern
PFAS are man-made chemicals that are widely used in consumer products and can persist and bio-accumulate in the environment. Xcel Energy does not manufacture PFAS, but because PFAS are so ubiquitous in products and the environment, it may impact our operations.
In June 2024, the EPA finalized a rule that designated certain PFAS as hazardous substances under CERCLA. In July 2024, the EPA finalized another rule that set enforceable drinking water standards for certain PFAS.
Potential costs for these rules and any additional proposed regulations related to PFAS are uncertain and will be determined on a site specific basis where applicable. If costs are incurred, Xcel Energy believes the costs will be recoverable through rates based on prior state commission practices.
Effluent Limitation Guidelines
In April 2024, the EPA published final rules under the Clean Water Act, setting Effluent Limitations Guidelines and Standards for steam generating coal plants. This rule establishes more stringent wastewater discharge standards for bottom ash transport water, flue-gas desulfurization wastewater, and combustion residuals leachate from steam electric power plants, particularly coal-fired power plants. Based on current estimates and assumptions, Xcel Energy has determined that there is minimal financial or operational impact associated with these requirements and that any costs would be recoverable through rates based on prior state commission practices.

Derivatives, Risk Management and Market Risk

We are exposed to a variety of market risks in the normal course of business. Market risk is the potential loss that may occur as a result of adverse changes in the market or fair value for a particular instrument or commodity. All financial and commodity-related instruments, including derivatives, are subject to market risk.
Xcel Energy is exposed to the impact of adverse changes in price for energy and energy-related products, which is partially mitigated by the use of commodity derivatives. In addition to ongoing monitoring and maintaining credit policies intended to minimize overall credit risk, management takes steps to mitigate changes in credit and concentration risks associated with its derivatives and other contracts, including parental guarantees and requests of collateral. While we expect that the counterparties will perform on the contracts underlying our derivatives, the contracts expose us to credit and non-performance risk.
Distress in the financial markets may impact counterparty risk and the fair value of the securities in the nuclear decommissioning fund and pension fund.
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Commodity Price Risk — We are exposed to commodity price risk in our electric and natural gas operations. Commodity price risk is managed by entering into long and short-term physical purchase and sales contracts for electric capacity, energy and energy-related products and fuels used in generation and distribution activities.
Commodity price risk is also managed through the use of financial derivative instruments. Our risk management policy allows us to manage commodity price risk within each rate-regulated operation per commission approved hedge plans.
Wholesale and Commodity Trading Risk — Xcel Energy conducts 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. Our risk management policy allows management to conduct these activities within guidelines and limitations as approved by our risk management committee.
Fair value of net commodity trading contracts as of March 31, 2025:

|  | Futures / Forwards Maturity
(Millions of Dollars) |  | Less Than 1 Year |  | 1 to 3 Years |  | 4 to 5 Years |  | Greater Than 5 Years |  | Total Fair Value
NSP-Minnesota (a) |  | $ | (17) |  |  | $ | (20) |  |  | $ | (4) |  |  | $ | — |  |  | $ | (41) |
NSP- Minnesota (b) |  | 5 |  |  | 5 |  |  | (3) |  |  | 2 |  |  | 9 |
PSCo (a) |  | 1 |  |  | 4 |  |  | — |  |  | — |  |  | 5 |
|  | $ | (11) |  |  | $ | (11) |  |  | $ | (7) |  |  | $ | 2 |  |  | $ | (27) |

|  | Options Maturity
(Millions of Dollars) |  | Less Than 1 Year |  | 1 to 3 Years |  | 4 to 5 Years |  | Greater Than 5 Years |  | Total Fair Value
NSP-Minnesota (b) |  | $ | — |  |  | $ | 2 |  |  | $ | 13 |  |  | $ | — |  |  | $ | 15 |
|  | $ | — |  |  | $ | 2 |  |  | $ | 13 |  |  | $ | — |  |  | $ | 15 |

(a)Prices actively quoted or based on actively quoted prices.
(b)Prices based on models and other valuation methods.
Changes in the fair value of commodity trading contracts before the impacts of margin-sharing for the three months ended March 31:

(Millions of Dollars) |  | 2025 |  | 2024
Fair value of commodity trading net contracts outstanding at Jan. 1 |  | $ | (2) |  |  | $ | 1 |
Contracts realized or settled during the period |  | 3 |  |  | (1) |
Commodity trading contract additions and changes during the period |  | (13) |  |  | 2 |
Fair value of commodity trading net contracts outstanding at March 31 |  | $ | (12) |  |  | $ | 2 |

A 10% increase and 10% decrease in forward market prices for Xcel Energy’s commodity trading contracts would have likewise increased and decreased pretax income from continuing operations, by approximately $3 million and $4 million at March 31, 2025 and March 31, 2024, respectively.
The utility subsidiaries’ commodity trading operations measure the outstanding risk exposure to price changes on contracts and obligations using an industry standard methodology known as VaR. VaR expresses the potential change in fair value of the outstanding contracts and obligations over a particular period of time under normal market conditions.
The VaRs for the NSP-Minnesota and PSCo commodity trading operations, excluding both non-derivative transactions and derivative transactions designated as normal purchases and normal sales, calculated on a consolidated basis using a Monte Carlo simulation with a 95% confidence level and a one-day holding period, were as follows:

(Millions of Dollars) |  | Three Months Ended March 31 |  | Average |  | High |  | Low
2025 |  | $ | 1 |  |  | $ | — |  |  | $ | 1 |  |  | $ | — |
2024 |  | 1 |  |  | — |  |  | 1 |  |  | — |

Interest Rate Risk — Xcel Energy is subject to interest rate risk. Our risk management policy allows interest rate risk to be managed through the use of fixed rate debt, floating rate debt and interest rate derivatives.
A 100-basis point change in the benchmark rate on Xcel Energy’s variable rate debt would impact pretax interest expense annually by approximately $8 million in March 31, 2025 and 2024.
NSP-Minnesota maintains a nuclear decommissioning fund, as required by the NRC. The nuclear decommissioning fund is subject to interest rate and equity price risk. The fund is invested in a diversified portfolio of debt securities, equity securities and other investments. These investments may be used only for the purpose of decommissioning NSP-Minnesota’s nuclear generating plants.
Fluctuations in equity prices or interest rates affecting the nuclear decommissioning fund do not have a direct impact on earnings due to the application of regulatory accounting. Realized and unrealized gains on the decommissioning fund investments are deferred as an offset of NSP-Minnesota’s regulatory asset for nuclear decommissioning costs.
The value of pension and postretirement plan assets and benefit costs are impacted by changes in discount rates and expected return on plan assets. Xcel Energy’s ongoing pension and postretirement investment strategy is based on plan-specific investment recommendations that seek to optimize potential investment risk and minimize interest rate risk associated with changes in the obligations as a plan’s funded status increases over time. The impacts of fluctuations in interest rates on pension and postretirement costs are mitigated by pension cost calculation methodologies and regulatory mechanisms that minimize the earnings impacts of such changes.
Credit Risk — Xcel Energy is also exposed to credit risk. Credit risk relates to the risk of loss resulting from counterparties’ nonperformance on their contractual obligations. Xcel Energy maintains credit policies intended to minimize overall credit risk and actively monitors these policies to reflect changes and scope of operations.
Credit exposure is monitored, and when necessary, the activity with a specific counterparty is limited until credit enhancement is provided. Distress in the financial markets could increase our credit risk.
Xcel Energy’s subsidiaries are subject to credit risk from contracts with generating equipment manufacturers and other suppliers that require deposits or milestone payments. In the event of non-performance by these counterparties, the Xcel Energy subsidiaries could experience credit losses, increased costs or project delays. Xcel Energy frequently seeks to mitigate this risk by requiring parent guarantees, letters of credit or other types of credit support.
Xcel Energy is also subject to credit risk for all wholesale, trading and non-trading commodity counterparties and employs credit risk controls, such as letters of credit, parental guarantees, master netting agreements and termination provisions.
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At March 31, 2025, a 10% increase in commodity prices would have resulted in an increase in credit exposure of $28 million, while a decrease in prices of 10% would have resulted in a decrease in credit exposure of $27 million. At March 31, 2024, a 10% increase in commodity prices would have resulted in an increase in credit exposure of $25 million, while a decrease in prices of 10% would have resulted in a decrease in credit exposure of $25 million.

Fair Value Measurements

Derivative contracts, with the exception of those designated as normal purchases and normal sales, are reported at fair value. Xcel Energy’s investments held in the nuclear decommissioning fund, rabbi trusts, pension and other postretirement funds are also subject to fair value accounting. See Note 8 to the consolidated financial statements for further information.

Liquidity and Capital Resources

Cash Flows
Operating Cash Flows

(Millions of Dollars) |  | Three Months Ended March 31
Cash provided by operating activities — 2024 |  | $ | 1,050 |
Components of change — 2025 vs. 2024 |  |
Lower net income |  | (5) |
Non-cash transactions |  | 81 |
Changes in deferred income taxes |  | (141) |
Changes in working capital |  | 65 |
Changes in net regulatory and other assets and liabilities |  | (22) |
Cash provided by operating activities — 2025 |  | $ | 1,028 |

Net cash provided by operating activities decreased $22 million for the three months ended March 31, 2025 compared with the prior year. The decrease was largely due to the change in deferred income taxes due to PTC transfers and the timing of working capital payments, partially offset by interim rate refunds in Minnesota in the prior year.
Investing Cash Flows

(Millions of Dollars) |  | Three Months Ended March 31
Cash used in investing activities — 2024 |  | $ | (1,556) |
Components of change — 2025 vs. 2024 |  |
Increased capital expenditures |  | (451) |
Other investing activities |  | 16 |
Cash used in investing activities — 2025 |  | $ | (1,991) |

Net cash used in investing activities increased $435 million for the three months ended March 31, 2025 compared with the prior year. The increase in capital expenditures was largely due to continued system investment in renewable and transmission projects.
Financing Cash Flows

(Millions of Dollars) |  | Three Months Ended March 31
Cash provided by financing activities — 2024 |  | $ | 878 |
Components of change — 2025 vs. 2024 |  |
Lower net short-term repayments |  | 346 |
Higher long-term debt issuances, net of repayments |  | 599 |
Higher proceeds from issuance of common stock |  | 114 |
Other financing activities |  | (30) |
Cash provided by financing activities — 2025 |  | $ | 1,907 |

Net cash provided by financing activities increased $1,029 million for the three months ended March 31, 2025 compared with the prior year. The increase was largely related to additional debt and common stock issuances to fund capital investment.
Capital Requirements
Xcel Energy expects to meet future financing requirements by periodically issuing short-term debt, long-term debt, common stock, hybrid and other securities to maintain desired capitalization ratios.
Pension Fund — Xcel Energy’s pension assets are invested in a diversified portfolio of domestic and international equity securities, short-term to long-duration fixed income securities, and alternative investments, including private equity, real estate and hedge funds.
•In January 2025, contributions of $125 million were made to Xcel Energy’s pension plans.
•In 2024, contributions of $100 million were made across four of Xcel Energy’s pension plans.
•For future years, contributions will be made as deemed appropriate based on evaluation of various factors including the funded status of the plans, minimum funding requirements, interest rates and expected investment returns.
Capital Sources
Short-Term Funding Sources — Xcel Energy uses a number of sources to fulfill short-term funding needs, including operating cash flow, notes payable, commercial paper and bank lines of credit. The amount and timing of short-term funding needs depend on financing needs for construction expenditures, working capital and dividend payments.
Short-Term Investments — Xcel Energy Inc., NSP-Minnesota, NSP-Wisconsin, PSCo and SPS maintain cash operating and short-term investment accounts.
As of Apr. 21, 2025, Xcel Energy Inc. and its utility subsidiaries had the following committed credit facilities available to meet liquidity needs:

(Millions of Dollars) |  | Credit Facility (a) |  | Drawn (b) |  | Available |  | Cash |  | Liquidity
Xcel Energy Inc. |  | $ | 1,500 |  |  | $ | 200 |  |  | $ | 1,300 |  |  | $ | 115 |  |  | $ | 1,415 |
PSCo |  | 700 |  |  | 30 |  |  | 670 |  |  | 377 |  |  | 1,047 |
NSP-Minnesota |  | 700 |  |  | 72 |  |  | 628 |  |  | 19 |  |  | 647 |
SPS |  | 500 |  |  | 255 |  |  | 245 |  |  | 10 |  |  | 255 |
NSP-Wisconsin |  | 150 |  |  | — |  |  | 150 |  |  | 23 |  |  | 173 |
Total |  | $ | 3,550 |  |  | $ | 557 |  |  | $ | 2,993 |  |  | $ | 544 |  |  | $ | 3,537 |

(a)Credit facilities expire in September 2027.
(b)Includes outstanding commercial paper and letters of credit.
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Short-Term Debt — Xcel Energy Inc., NSP-Minnesota, NSP-Wisconsin, PSCo and SPS each have individual commercial paper programs. As of March 31, 2025, the authorized levels for these commercial paper programs are:
•$1.5 billion for Xcel Energy Inc.
•$700 million for PSCo.
•$700 million for NSP-Minnesota.
•$500 million for SPS.
•$150 million for NSP-Wisconsin.
Money Pool — Xcel Energy received FERC approval to establish a utility money pool arrangement with the utility subsidiaries, subject to receipt of required state regulatory approvals. The utility money pool allows for short-term investments in and borrowings between the utility subsidiaries.
Xcel Energy may make investments in the utility subsidiaries at market-based interest rates; however, the money pool arrangement does not allow the utility subsidiaries to make investments in Xcel Energy. The money pool balances are eliminated in consolidation. NSP-Minnesota, NSP-Wisconsin, PSCo and SPS participate in the money pool pursuant to approval from their respective state regulatory commissions.
2025 Planned Financing Activity — Xcel Energy and its utility subsidiaries issued or plan to issue the following long-term debt:

Issuer |  | Security |  | Amount |  | Status |  | Tenor |  | Coupon
Xcel Energy Inc. |  | Senior Unsecured Notes |  | $ | 1,100 | million |  | Completed |  | 3 Year & 10 Year |  | 4.75% & 5.60%
PSCo |  | First Mortgage Bonds |  | 1,000 | million |  | Completed |  | 9 Year & 30 Year |  | 5.35% & 5.85%
NSP-Minnesota |  | First Mortgage Bonds |  | 1,100 | million |  | Second Quarter |  | 10 Year & 30 Year |  | N/A
SPS |  | First Mortgage Bonds |  | 450 | million |  | Second Quarter |  | 30 Year |  | N/A
NSP-Wisconsin |  | First Mortgage Bonds |  | 250 | million |  | Second Quarter |  | 30 Year |  | N/A
PSCo |  | First Mortgage Bonds |  | 1,000 | million |  | Third Quarter |  | 10 Year & 30 Year |  | N/A

In the three months ended March 31, 2025, 1.75 million shares ($122 million in net proceeds) were issued under an ATM program.
Long-Term Borrowings, Equity Issuances and Other Financing Instruments — Xcel Energy may issue equity through its ATM program or other offerings. Financing plans are subject to change, depending on capital expenditures, regulatory outcomes, internal cash generation, market conditions, changes in tax policies and other factors.
See Note 4 to the consolidated financial statements for further information.
Off-Balance-Sheet Arrangements
Xcel Energy does not have any off-balance-sheet arrangements, other than those currently disclosed, that have or are reasonably likely to have a current or future effect on financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources that is material to investors.
Earnings Guidance and Long-Term EPS and Dividend Growth Rate Objectives
Xcel Energy 2025 Earnings Guidance — Xcel Energy’s 2025 ongoing earnings guidance is a range of $3.75 to $3.85 per share.(a)
Key assumptions as compared with 2024 actual levels unless noted:
•Constructive outcomes in all pending rate case and regulatory proceedings, including requests for deferral of incremental insurance costs associated with wildfire risk and recovery of O&M costs associated with wildfire mitigation plans.
•Normal weather patterns for the year.
•Weather-normalized retail electric sales are projected to increase ~3%.
•Weather-normalized retail firm natural gas sales are projected to increase ~1%.
•Capital rider revenue is projected to increase $200 million to $210 million (net of PTCs). The update is primarily driven by earnings neutral changes, including PTC updates.
•O&M expenses are projected to increase ~3%.
•Depreciation expense is projected to increase approximately $210 million to $220 million.
•Property taxes are projected to increase $45 million to $55 million.
•Interest expense (net of AFUDC - debt) is projected to increase $165 million to $175 million, net of interest income.
•AFUDC - equity is projected to increase $110 million to $120 million.
(a)Ongoing earnings is calculated using net income and adjusting for certain nonrecurring or infrequent items that are, in management’s view, not reflective of ongoing operations. Ongoing earnings could differ from those prepared in accordance with GAAP for unplanned and/or unknown adjustments. As Xcel Energy is unable to quantify the financial impacts of any additional adjustments that may occur for the year, we are unable to provide a quantitative reconciliation of the guidance for ongoing EPS to corresponding GAAP EPS.
Long-Term EPS and Dividend Growth Rate Objectives — Xcel Energy expects to deliver an attractive total return to our shareholders through a combination of earnings growth and dividend yield, based on the following long-term objectives:
• Deliver long-term annual EPS growth of 6% to 8% based off of $3.55 per share (the mid-point of 2024 original ongoing earnings guidance of $3.50 to $3.60 per share).
• Deliver annual dividend increases of 4% to 6%.
• Target a dividend payout ratio of 50% to 60%.
• Maintain senior secured debt credit ratings in the A range.

ITEM 3 — QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

There have been no material changes to the market risk disclosure included in our Annual Report on Form 10-K for the year ended Dec. 31, 2024 under “Derivatives, Risk Management and Market Risk.”
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PART II — OTHER INFORMATION

ITEM 1A — RISK FACTORS

Xcel Energy’s risk factors are documented in Item 1A of Part I of its Annual Report on Form 10-K for the year ended Dec. 31, 2024, which is incorporated herein by reference. There have been no material changes from the risk factors previously disclosed in the Form 10-K.

ITEM 2 — UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

Purchases of Equity Securities by the Issuer and Affiliated Purchaser:
The following table provides information about our purchases of equity securities that are registered by Xcel Energy Inc. pursuant to Section 12 of the Exchange Act for the quarter ended March 31, 2025.

|  | Issuer Purchases of Equity Securities
Period |  | Total Number of Shares Purchased |  | Average Price Paid per Share |  | Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs |  | Maximum Number (or Approximate Dollar Value) of Shares That May Yet Be Purchased Under the Plans or Programs
Jan. 1, 2025 - Jan. 31, 2025 |  | — |  |  | $ | — |  |  | — |  |  | — |
Feb. 1, 2025 - Feb. 28, 2025 |  | — |  |  | — |  |  | — |  |  | — |
March 1, 2025 - March 31, 2025 (a) |  | 312 |  |  | 72.10 |  |  | — |  |  | — |
|  | 312 |  |  |  |  | — |  |  | — |

(a)Xcel Energy Inc. or one of its agents periodically purchases common shares in open-market transactions in order to satisfy obligations under the Stock Equivalent Plan for Non-Employee Directors.

ITEM 4 — CONTROLS AND PROCEDURES

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

ITEM 1 — LEGAL PROCEEDINGS

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 of such matters, 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.
See Note 10 to the consolidated financial statements and Part I Item 2 for further information.

ITEM 5 — OTHER INFORMATION

None of the Company’s directors or officers adopted, modified, or terminated a Rule 10b5-1 trading arrangement or a non-Rule 10b5-1 trading arrangement during the Company’s fiscal quarter ended March 31, 2025.
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ITEM 6 — EXHIBITS

* | Indicates incorporation by reference

Exhibit Number | Description | Report or Registration Statement | Exhibit Reference
3.01* | Amended and Restated Articles of Incorporation of Xcel Energy Inc., dated May 17, 2012 | Xcel Energy Inc. Form 8-K dated May 16, 2012 | 3.01
3.02* | Bylaws of Xcel Energy Inc., as Amended and Restated on August 23, 2023 | Xcel Energy Inc Form 8-K dated August 23, 2023 | 3.02
4.01 | Supplemental Indenture No. 19, dated as of March 21, 2025 by and between Xcel Energy Inc. and U.S. Bank Trust Company, National Association (as successor to Computershare Trust Company, N.A.), as trustee, creating $350,000,000 aggregate principal amount of 4.75% Senior Notes, Series due March 21, 2028 and $750,000,000 aggregate principal amount of 5.60% Senior Notes, Series due April 15, 2035. | Xcel Energy Inc. Form 8-K dated March 21, 2025 | 4.01
4.02 | Supplemental Indenture No. 36 dated as of March 1, 2025, between Public Service Company of Colorado and U.S. Bank Trust Company, National Association, as successor Trustee, creating $600 million principal amount of 5.85% First Mortgage Bonds, Series No. 43 due 2055. | PSCo Form 8-K dated March 20, 2025 | 4.03
31.01 | Principal Executive Officer’s certifications pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 |  |
31.02 | Principal Financial Officer’s certifications pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 |  |
32.01 | Certifications pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 |  |
101.INS | Inline XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document |  |
101.SCH | Inline XBRL Schema |  |
101.CAL | Inline XBRL Calculation |  |
101.DEF | Inline XBRL Definition |  |
101.LAB | Inline XBRL Label |  |
101.PRE | Inline XBRL Presentation |  |
104 | Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101) |  |

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SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

|  | XCEL ENERGY INC.
04/24/2025 | By: | /s/ MELISSA L. OSTROM
|  | Melissa L. Ostrom
|  | Senior Vice President, Controller
|  | (Principal Accounting Officer)
| By: | /s/ BRIAN J. VAN ABEL
|  | Brian J. Van Abel
|  | Executive Vice President, Chief Financial Officer
|  | (Principal Financial Officer)

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