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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 Sept. 30, 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
6.25% Junior Subordinated Notes due 2085 |  | XELLL |  | 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 Oct. 28, 2025
Common Stock, $2.50 par value |  | 591,539,773 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 | 24
Item 3 — | Quantitative and Qualitative Disclosures A bout Market Risk | 36
Item 4 — | Controls and Procedures | 36
PART II | OTHER INFORMATION |
Item 1 — | Legal Proceedings | 37
Item 1A — | Risk Factors | 37
Item 2 — | Unregistered Sales of Equity Securities and Use of Proceeds | 37
Item 5 — | Other Information | 37
Item 6 — | Exhibits | 37
SIGNATURES | 38

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
EPA | United States Environmental Protection Agency
FASB | Financial Accounting Standards Board
FERC | Federal Energy Regulatory Commission
IRS | Internal Revenue Service
MPSC | Michigan Public Service 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
SDPUC | South Dakota Public Utilities Commission

Other
AFUDC | Allowance for funds used during construction
ALJ | Administrative Law Judge
ARO | Asset retirement obligation
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
COD | Commercial Operation Date
CPCN | Certificate of Public Convenience and Necessity
CUB | Citizens Utility Board
DOC | Minnesota Department of Commerce
DRIP | Dividend Reinvestment and Stock Purchase Program
DSM | Demand side management
EPS | Earnings per share
ETR | Effective tax rate
FTR | Financial transmission right
GAAP | United States generally accepted accounting principles
GHG | Greenhouse Gas
HDD | Heating degree-days
IPP | Independent power producing entity
IRP | Integrated Resource Plan
LLC | Limited liability company
LRTP | Long Range Transmission Plan
MGP | Manufactured gas plant
MMbtu | Million British Thermal Units
MISO | Midcontinent Independent System Operator, Inc.
NAV | Net asset value
NOx | Nitrogen Oxides
O&M | Operating and maintenance
OAG | Office of the Minnesota Attorney General
OBBB | One Big Beautiful Bill Act
PFAS | Per- and Polyfluoroalkyl Substances
PIM | Performance incentive mechanism
PPA | Power purchase agreement
PTC | Production tax credit
RFP | Request for proposal
ROE | Return on equity
ROU | Right-of-use
RTO | Regional Transmission Organization
SIP | State implementation plan
SPP | Southwest Power Pool, Inc.
THI | Temperature-humidity index
VaR | Value at Risk
VIE | Variable interest entity
WMP | Wildfire mitigation plan
XLI | Xcel Large Industrials

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 and 2026 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

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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 Sept. 30 |  | Nine Months Ended Sept. 30
| 2025 |  | 2024 |  | 2025 |  | 2024
Operating revenues |  |  |  |  |  |  |
Electric | $ | 3,638 |  |  | $ | 3,393 |  |  | $ | 9,351 |  |  | $ | 8,737 |
Natural gas | 264 |  |  | 239 |  |  | 1,715 |  |  | 1,535 |
Other | 13 |  |  | 12 |  |  | 42 |  |  | 49 |
Total operating revenues | 3,915 |  |  | 3,644 |  |  | 11,108 |  |  | 10,321 |
Operating expenses |  |  |  |  |  |  |
Electric fuel and purchased power | 1,098 |  |  | 1,060 |  |  | 3,036 |  |  | 2,863 |
Cost of natural gas sold and transported | 61 |  |  | 63 |  |  | 708 |  |  | 664 |
Cost of sales — other | 5 |  |  | 3 |  |  | 8 |  |  | 12 |
Operating and maintenance expenses | 692 |  |  | 655 |  |  | 2,053 |  |  | 1,922 |
Conservation and demand side management expenses | 101 |  |  | 112 |  |  | 299 |  |  | 295 |
Depreciation and amortization | 750 |  |  | 681 |  |  | 2,200 |  |  | 2,042 |
Taxes (other than income taxes) | 172 |  |  | 159 |  |  | 514 |  |  | 484 |
Marshall Wildfire litigation | 287 |  |  | — |  |  | 287 |  |  | — |
Total operating expenses | 3,166 |  |  | 2,733 |  |  | 9,105 |  |  | 8,282 |
Operating income | 749 |  |  | 911 |  |  | 2,003 |  |  | 2,039 |
Other income, net | 46 |  |  | 39 |  |  | 121 |  |  | 75 |
Earnings (loss) from equity method investments | 6 |  |  | 3 |  |  | (3) |  |  | 19 |
Allowance for funds used during construction — equity | 79 |  |  | 44 |  |  | 196 |  |  | 119 |
Interest charges and financing costs |  |  |  |  |  |  |
Interest charges — includes other financing costs | 384 |  |  | 326 |  |  | 1,065 |  |  | 936 |
Allowance for funds used during construction — debt | (36) |  |  | (21) |  |  | (86) |  |  | (51) |
Total interest charges and financing costs | 348 |  |  | 305 |  |  | 979 |  |  | 885 |
Income before income taxes | 532 |  |  | 692 |  |  | 1,338 |  |  | 1,367 |
Income tax expense (benefit) | 8 |  |  | 10 |  |  | (113) |  |  | (105) |
Net income | $ | 524 |  |  | $ | 682 |  |  | $ | 1,451 |  |  | $ | 1,472 |
Weighted average common shares outstanding: |  |  |  |  |  |  |
Basic | 592 |  |  | 564 |  |  | 584 |  |  | 559 |
Diluted | 595 |  |  | 565 |  |  | 587 |  |  | 559 |
Earnings per average common share: |  |  |  |  |  |  |
Basic | $ | 0.88 |  |  | $ | 1.21 |  |  | $ | 2.48 |  |  | $ | 2.63 |
Diluted | 0.88 |  |  | 1.21 |  |  | 2.47 |  |  | 2.63 |
See Notes to Consolidated Financial Statements

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

| Three Months Ended Sept. 30 |  | Nine Months Ended Sept. 30
| 2025 |  | 2024 |  | 2025 |  | 2024
Net income | $ | 524 |  |  | $ | 682 |  |  | $ | 1,451 |  |  | $ | 1,472 |
Other comprehensive income |  |  |  |  |  |  |
Pension and retiree medical benefits: |  |  |  |  |  |  |
Reclassifications of losses to net income, net of tax | — |  |  | — |  |  | — |  |  | 4 |
Derivative instruments: |  |  |  |  |  |  |
Net fair value increase, net of tax | — |  |  | — |  |  | — |  |  | 22 |
Reclassification of losses to net income, net of tax | 1 |  |  | 1 |  |  | 3 |  |  | 2 |
Total other comprehensive income | 1 |  |  | 1 |  |  | 3 |  |  | 28 |
Total comprehensive income | $ | 525 |  |  | $ | 683 |  |  | $ | 1,454 |  |  | $ | 1,500 |
See Notes to Consolidated Financial Statements

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

| Nine Months Ended Sept. 30
| 2025 |  | 2024
Operating activities |  |  |
Net income | $ | 1,451 |  |  | $ | 1,472 |
Adjustments to reconcile net income to cash provided by operating activities: |  |  |
Depreciation and amortization | 2,216 |  |  | 2,055 |
Nuclear fuel amortization | 87 |  |  | 85 |
Deferred income taxes | 395 |  |  | 406 |
Allowance for equity funds used during construction | (196) |  |  | (119) |
Loss (earnings) from equity method investments | 3 |  |  | (19) |
Dividends from equity method investments | 16 |  |  | 26 |
Provision for bad debts | 47 |  |  | 47 |
Share-based compensation expense | 38 |  |  | 27 |
Changes in operating assets and liabilities: |  |  |
Accounts receivable | (32) |  |  | 81 |
Accrued unbilled revenues | 66 |  |  | 62 |
Inventories | (202) |  |  | (71) |
Other current assets | 142 |  |  | 13 |
Accounts payable | (85) |  |  | (42) |
Net regulatory assets and liabilities | (113) |  |  | 282 |
Other current liabilities | 202 |  |  | (238) |
Pension and other employee benefit obligations | (102) |  |  | (94) |
Other, net | (59) |  |  | 4 |
Net cash provided by operating activities | 3,874 |  |  | 3,977 |
Investing activities |  |  |
Capital/construction expenditures | (7,470) |  |  | (5,147) |
Purchase of investment securities | (854) |  |  | (693) |
Proceeds from the sale of investment securities | 851 |  |  | 666 |
Other, net | (19) |  |  | (23) |
Net cash used in investing activities | (7,492) |  |  | (5,197) |
Financing activities |  |  |
Proceeds (repayments) from short-term borrowings, net | 635 |  |  | (690) |
Proceeds from issuances of long-term debt | 4,883 |  |  | 3,643 |
Repayments of long-term debt | (1,223) |  |  | (550) |
Proceeds from issuance of common stock | 1,151 |  |  | 1,109 |
Dividends paid | (954) |  |  | (871) |
Other, net | (1) |  |  | (5) |
Net cash provided by financing activities | 4,491 |  |  | 2,636 |
Net change in cash, cash equivalents and restricted cash | 873 |  |  | 1,416 |
Cash, cash equivalents and restricted cash at beginning of period | 179 |  |  | 129 |
Cash, cash equivalents and restricted cash at end of period | $ | 1,052 |  |  | $ | 1,545 |
Supplemental disclosure of cash flow information: |  |  |
Cash paid for interest (net of amounts capitalized) | $ | (832) |  |  | $ | (793) |
Cash received for income taxes, net; includes proceeds from tax credit transfers | 511 |  |  | 484 |
Supplemental disclosure of non-cash investing and financing transactions: |  |  |
Accrued property, plant and equipment additions | $ | 1,250 |  |  | $ | 741 |
Inventory transfers to property, plant and equipment | 288 |  |  | 217 |
Operating lease and finance lease right-of-use assets | 1,218 |  |  | 43 |
Allowance for equity funds used during construction | 196 |  |  | 119 |
Issuance of common stock for reinvested dividends and/or equity awards | 63 |  |  | 53 |
See Notes to Consolidated Financial Statements

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

| Sept. 30, 2025 |  | Dec. 31, 2024
Assets |  |  |
Current assets |  |  |
Cash and cash equivalents | $ | 1,052 |  |  | $ | 179 |
Accounts receivable, net | 1,246 |  |  | 1,249 |
Accrued unbilled revenues | 766 |  |  | 832 |
Inventories | 723 |  |  | 666 |
Regulatory assets | 536 |  |  | 561 |
Derivative instruments | 216 |  |  | 114 |
Prepayments and other | 1,142 |  |  | 724 |
Total current assets | 5,681 |  |  | 4,325 |
Property, plant and equipment, net | 63,131 |  |  | 57,198 |
Other assets |  |  |
Nuclear decommissioning fund and other investments | 4,273 |  |  | 3,896 |
Regulatory assets | 2,907 |  |  | 2,849 |
Derivative instruments | 56 |  |  | 72 |
Operating lease right-of-use assets | 877 |  |  | 1,060 |
Finance lease right-of-use assets | 1,358 |  |  | 111 |
Other | 871 |  |  | 524 |
Total other assets | 10,342 |  |  | 8,512 |
Total assets | $ | 79,154 |  |  | $ | 70,035 |
Liabilities and Equity |  |  |
Current liabilities |  |  |
Current portion of long-term debt | $ | 1 |  |  | $ | 1,103 |
Short-term debt | 1,330 |  |  | 695 |
Accounts payable | 2,328 |  |  | 1,781 |
Regulatory liabilities | 760 |  |  | 852 |
Taxes accrued | 531 |  |  | 535 |
Accrued interest | 410 |  |  | 280 |
Dividends payable | 337 |  |  | 314 |
Derivative instruments | 31 |  |  | 37 |
Operating lease liabilities | 114 |  |  | 227 |
Other | 1,306 |  |  | 635 |
Total current liabilities | 7,148 |  |  | 6,459 |
Deferred credits and other liabilities |  |  |
Deferred income taxes | 5,927 |  |  | 5,319 |
Regulatory liabilities | 6,332 |  |  | 6,010 |
Asset retirement obligations | 3,853 |  |  | 3,713 |
Derivative instruments | 69 |  |  | 77 |
Customer advances | 130 |  |  | 146 |
Pension and employee benefit obligations | 372 |  |  | 477 |
Operating lease liabilities | 771 |  |  | 867 |
Finance lease liabilities | 1,272 |  |  | 60 |
Other | 65 |  |  | 69 |
Total deferred credits and other liabilities | 18,791 |  |  | 16,738 |
Commitments and contingencies |  |  |
Capitalization |  |  |
Long-term debt | 32,034 |  |  | 27,316 |
Common stock — 1,000,000,000 shares authorized of $2.50 par value; 591,432,101 and 574,365,598 shares outstanding at Sept. 30, 2025 and December 31, 2024, respectively | 1,479 |  |  | 1,436 |
Additional paid in capital | 10,772 |  |  | 9,601 |
Retained earnings | 8,995 |  |  | 8,553 |
Accumulated other comprehensive loss | (65) |  |  | (68) |
Total common stockholders’ equity | 21,181 |  |  | 19,522 |
Total liabilities and equity | $ | 79,154 |  |  | $ | 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 Sept. 30, 2025 and 2024 |  |  |  |  |  |  |  |  |  |  |
Balance at June 30, 2024 | 557,337,051 |  |  | $ | 1,393 |  |  | $ | 8,589 |  |  | $ | 8,039 |  |  | $ | (67) |  |  | $ | 17,954 |
Net income |  |  |  |  |  |  | 682 |  |  |  |  | 682 |
Other comprehensive income |  |  |  |  |  |  |  |  | 1 |  |  | 1 |
Dividends declared on common stock ($0.55 per share) |  |  |  |  |  |  | (312) |  |  |  |  | (312) |
Issuances of common stock | 16,764,662 |  |  | 42 |  |  | 975 |  |  |  |  |  |  | 1,017 |
Share-based compensation |  |  |  |  | 13 |  |  | (3) |  |  |  |  | 10 |
Balance at Sept. 30, 2024 | 574,101,713 |  |  | $ | 1,435 |  |  | $ | 9,577 |  |  | $ | 8,406 |  |  | $ | (66) |  |  | $ | 19,352 |
Balance at June 30, 2025 | 591,201,845 |  |  | $ | 1,478 |  |  | $ | 10,736 |  |  | $ | 8,813 |  |  | $ | (66) |  |  | $ | 20,961 |
Net income |  |  |  |  |  |  | 524 |  |  |  |  | 524 |
Other comprehensive income |  |  |  |  |  |  |  |  | 1 |  |  | 1 |
Dividends declared on common stock ($0.57 per share) |  |  |  |  |  |  | (337) |  |  |  |  | (337) |
Issuances of common stock | 230,256 |  |  | 1 |  |  | 15 |  |  |  |  |  |  | 16 |
Share-based compensation |  |  |  |  | 21 |  |  | (5) |  |  |  |  | 16 |
Balance at Sept. 30, 2025 | 591,432,101 |  |  | $ | 1,479 |  |  | $ | 10,772 |  |  | $ | 8,995 |  |  | $ | (65) |  |  | $ | 21,181 |
| Common Stock Issued |  | Retained Earnings |  | Accumulated Other Comprehensive Loss |  | Total Common Stockholders' Equity
| Shares |  | Par Value |  | Additional Paid In Capital |  |  |
Nine Months Ended Sept. 30, 2025 and 2024 |  |  |  |  |  |  |  |  |  |  |
Balance at Dec. 31, 2023 | 554,941,703 |  |  | $ | 1,387 |  |  | $ | 8,465 |  |  | $ | 7,858 |  |  | $ | (94) |  |  | $ | 17,616 |
Net income |  |  |  |  |  |  | 1,472 |  |  |  |  | 1,472 |
Other comprehensive income |  |  |  |  |  |  |  |  | 28 |  |  | 28 |
Dividends declared on common stock ($1.64 per share) |  |  |  |  |  |  | (921) |  |  |  |  | (921) |
Issuances of common stock | 19,160,010 |  |  | 48 |  |  | 1,082 |  |  |  |  |  |  | 1,130 |
Share-based compensation |  |  |  |  | 30 |  |  | (3) |  |  |  |  | 27 |
Balance at Sept. 30, 2024 | 574,101,713 |  |  | $ | 1,435 |  |  | $ | 9,577 |  |  | $ | 8,406 |  |  | $ | (66) |  |  | $ | 19,352 |
Balance at Dec. 31, 2024 | 574,365,598 |  |  | $ | 1,436 |  |  | $ | 9,601 |  |  | $ | 8,553 |  |  | $ | (68) |  |  | $ | 19,522 |
Net income |  |  |  |  |  |  | 1,451 |  |  |  |  | 1,451 |
Other comprehensive income |  |  |  |  |  |  |  |  | 3 |  |  | 3 |
Dividends declared on common stock ($1.71 per share) |  |  |  |  |  |  | (1,002) |  |  |  |  | (1,002) |
Issuances of common stock | 17,066,503 |  |  | 43 |  |  | 1,126 |  |  |  |  |  |  | 1,169 |
Share-based compensation |  |  |  |  | 45 |  |  | (7) |  |  |  |  | 38 |
Balance at Sept. 30, 2025 | 591,432,101 |  |  | $ | 1,479 |  |  | $ | 10,772 |  |  | $ | 8,995 |  |  | $ | (65) |  |  | $ | 21,181 |
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 Sept. 30, 2025 and Dec. 31, 2024; the results of Xcel Energy’s operations, including the components of net income, comprehensive income, and changes in stockholders’ equity for the three and nine months ended Sept. 30, 2025 and 2024; and Xcel Energy’s cash flows for the nine months ended Sept. 30, 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 Sept. 30, 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) |  | Sept. 30, 2025 |  | Dec. 31, 2024
Accounts receivable, net |  |  |  |
Accounts receivable |  | $ | 1,341 |  |  | $ | 1,360 |
Less allowance for bad debts |  | (95) |  |  | (111) |
Accounts receivable, net |  | $ | 1,246 |  |  | $ | 1,249 |

(Millions of Dollars) |  | Sept. 30, 2025 |  | Dec. 31, 2024
Inventories |  |  |  |
Materials and supplies |  | $ | 461 |  |  | $ | 406 |
Fuel |  | 145 |  |  | 164 |
Natural gas |  | 117 |  |  | 96 |
Total inventories |  | $ | 723 |  |  | $ | 666 |

(Millions of Dollars) |  | Sept. 30, 2025 |  | Dec. 31, 2024
Property, plant and equipment, net |  |  |  |
Electric plant |  | $ | 59,976 |  |  | $ | 56,791 |
Natural gas plant |  | 10,300 |  |  | 9,834 |
Common and other property |  | 3,702 |  |  | 3,515 |
Plant to be retired (a) |  | 1,640 |  |  | 1,793 |
Construction work in progress |  | 8,017 |  |  | 4,720 |
Total property, plant and equipment |  | 83,635 |  |  | 76,653 |
Less accumulated depreciation |  | (20,957) |  |  | (19,852) |
Nuclear fuel |  | 3,634 |  |  | 3,491 |
Less accumulated amortization |  | (3,181) |  |  | (3,094) |
Property, plant and equipment, net |  | $ | 63,131 |  |  | $ | 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 Sept. 30, 2025 |  | Year Ended Dec. 31, 2024
Borrowing limit |  | $ | 4,750 |  |  | $ | 3,550 |
Amount outstanding at period end |  | 1,330 |  |  | 695 |
Average amount outstanding |  | 949 |  |  | 508 |
Maximum amount outstanding |  | 1,330 |  |  | 1,314 |
Weighted average interest rate, computed on a daily basis |  | 4.55 | % |  | 5.47 | %
Weighted average interest rate at period end |  | 4.38 |  |  | 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 $74 million and $42 million of letters of credit outstanding under the credit facilities at Sept. 30, 2025 and Dec. 31, 2024. 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.
Amended Credit Agreements — In May 2025, Xcel Energy Inc., NSP-Minnesota, NSP-Wisconsin, PSCo and SPS each entered into an amended five-year credit agreement with a syndicate of banks. The aggregate borrowing limit was increased to $4.75 billion. The amended credit agreements have substantially the same terms and conditions as the prior agreements, with the following changes:
•Maturities were extended from September 2027 to December 2029.
•Borrowing limit for Xcel Energy Inc. was increased from $1.5 billion to $2 billion.
•Borrowing limit for PSCo was increased from $700 million to $1.2 billion.
•Borrowing limit for NSP-Minnesota was increased from $700 million to $800 million.
•Borrowing limit for SPS was increased from $500 million to $600 million.
As of Sept. 30, 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. |  | $ | 2,000 |  |  | $ | 1,330 |  |  | $ | 670 |
PSCo |  | 1,200 |  |  | 30 |  |  | 1,170 |
NSP-Minnesota |  | 800 |  |  | 44 |  |  | 756 |
SPS |  | 600 |  |  | — |  |  | 600 |
NSP-Wisconsin |  | 150 |  |  | — |  |  | 150 |
Total |  | $ | 4,750 |  |  | $ | 1,404 |  |  | $ | 3,346 |

(a)Expires in December 2029.
(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 Sept. 30, 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 Sept. 30, 2025, NSP-Minnesota had $69 million of outstanding letters of credit under the $75 million bilateral credit agreement.
Long-Term Borrowings and Other Financing Instruments
During the nine months ended Sept. 30, 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, $800 million of 5.85% First Mortgage Bonds due May 15, 2055, and $800 million of 5.15% First Mortgage Bonds due Sept. 15, 2035.
•NSP-Minnesota issued $600 million of 5.05% First Mortgage Bonds due May 15, 2035 and $500 million of 5.65% First Mortgage Bonds due May 15, 2055.
•SPS issued $500 million of 5.30% First Mortgage Bonds due May 15, 2035.
•NSP-Wisconsin issued $250 million of 5.65% First Mortgage Bonds due June 15, 2054.
•In October 2025, Xcel Energy Inc. issued $900 million of 6.25% Junior Subordinated Notes due Oct. 15, 2085. The notes may be redeemed at par value on or after Oct. 15, 2030.
ATM Equity Offerings — In October 2023, Xcel Energy Inc. filed a prospectus supplement under which it may sell up to $2.5 billion of its common stock through an ATM program. In 2023, 3.1 million shares of common stock were issued ($188 million in net proceeds and $2 million in transaction fees paid). In 2024, 18.3 million shares of common stock were issued ($1.10 billion in net proceeds and $9 million in transaction fees paid). In the nine months ended Sept. 30, 2025, 16.4 million shares ($1.16 billion in net proceeds and $9 million in transaction fees paid) were issued under the ATM program. As of August 1, 2025, no further transactions will occur under this ATM program.
In August 2025, Xcel Energy Inc. filed a prospectus supplement under which it may sell up to $4 billion of its common stock through an ATM program. In addition to the issuance and sale of shares of common stock to or through sales agents, Xcel Energy Inc. also may use the 2025 ATM program to enter into forward sale agreements under separate forward sale confirmations between Xcel Energy Inc. and a banking counterparty.
Forward Equity Agreements — Xcel Energy Inc. has entered into multiple forward sale agreements in 2024 and 2025 in connection with completed public offerings of Xcel Energy common stock, as follows:

Agreements Entered |  | Common Shares (in millions) |  | Final Maturity |  | Expected Proceeds (millions of dollars) |
2024 forward equity agreements |  | 21.1 |  | June 2026 (a) |  | $ | 1,364 |  | (b)
2025 forward equity agreements (c) |  | 10.0 |  | Dec. 2025 to Mar. 2027 (a) |  | 728 |  | (b)
2025 collared forward equity agreements (c) |  | 8.2 |  | Dec. 2026 |  | (d) |

(a)Xcel Energy may settle the agreements at any time until final maturity.
(b)Actual cash proceeds will be impacted by the timing of settlement. Forward prices are based on the public offering price (net of underwriting fees), increased for the overnight bank funding rate, less a spread and less expected dividends on Xcel Energy’s common stock during the period the agreements are outstanding.
(c)Entered under the 2025 ATM prospectus supplement.
(d)Pricing for the physical delivery of common shares will be based on an average market price for Xcel Energy’s common stock during a period preceding settlement in December 2026, subject to a cap price and floor price derived from the September 2025 public offerings. Minimum expected proceeds are approximately $580 million.
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No amounts have been recorded to the consolidated financial statements related to these forward sale agreements and collared forward sale agreements, which remain unsettled at Sept. 30, 2025. If settled in physical shares, stockholders’ equity equal to cash proceeds will be recorded at settlement.
The 2025 collared forward equity agreements cannot be settled until December 2026, and net cash settlement and net share settlement are generally unavailable. The 2024 and 2025 forward equity agreements could have been settled at Sept. 30, 2025 with physical delivery of common shares to the banking counterparties in exchange for cash; if Xcel Energy unilaterally elected net cash or net share settlement, these agreements also could have been settled with delivery of cash or shares of common stock to the banking counterparties, as follows:

Pro-Forma/Hypothetical Transactions
Agreements Entered |  | Net Settlement proceeds: |  | Physical Share Delivery Proceeds (millions of dollars)
| Common Shares (in millions) |  | Net Cash (millions of dollars) |
2024 forward equity agreements |  | 2.7 |  | 203 |  | $ | 1,354 |
2025 forward equity agreements |  | 0.2 |  | 16 |  | 725 |

Equity through DRIP and Benefits Program — Xcel Energy issued $48 million and $50 million of equity through the DRIP and benefits programs during the nine months ended Sept. 30, 2025 and 2024, respectively. The programs allow shareholders to reinvest their dividends directly in Xcel Energy Inc. common stock.
Xcel Energy Inc.’s Purchase of NSP-Minnesota’s First Mortgage Bonds — During the nine months ended Sept. 30, 2025, Xcel Energy Inc. purchased $190 million in aggregate principal amounts of NSP-Minnesota’s 2.90% First Mortgage Bonds Series due March 1, 2050, 2.60% First Mortgage Bonds Series due June 1, 2051 and 3.20% First Mortgage Bonds Series due April 1, 2052, for $122 million. On a consolidated basis, Xcel Energy Inc.’s repurchases of NSP-Minnesota First Mortgage Bonds were accounted for as debt extinguishments and resulted in pre-tax gains of approximately $63 million, net of unamortized discount and debt issuance costs. NSP- Minnesota’s interest expense related to the repurchased bonds was $1.4 million for the nine months ended Sept. 30, 2025.

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 Sept. 30, 2025
(Millions of Dollars) |  | Electric |  | Natural Gas |  | All Other |  | Total
Major revenue types |  |  |  |  |  |  |  |
Revenue from contracts with customers:
Residential |  | $ | 1,260 |  |  | $ | 133 |  |  | $ | 2 |  |  | $ | 1,395 |
C&I |  | 1,750 |  |  | 82 |  |  | 5 |  |  | 1,837 |
Other |  | 40 |  |  | — |  |  | 2 |  |  | 42 |
Total retail |  | 3,050 |  |  | 215 |  |  | 9 |  |  | 3,274 |
Wholesale |  | 205 |  |  | — |  |  | — |  |  | 205 |
Transmission |  | 200 |  |  | — |  |  | — |  |  | 200 |
Other |  | 22 |  |  | 33 |  |  | — |  |  | 55 |
Total revenue from contracts with customers |  | 3,477 |  |  | 248 |  |  | 9 |  |  | 3,734 |
Alternative revenue and other |  | 161 |  |  | 16 |  |  | 4 |  |  | 181 |
Total revenues |  | $ | 3,638 |  |  | $ | 264 |  |  | $ | 13 |  |  | $ | 3,915 |

|  | Three Months Ended Sept. 30, 2024
(Millions of Dollars) |  | Electric |  | Natural Gas |  | All Other |  | Total
Major revenue types |  |  |  |  |  |  |  |
Revenue from contracts with customers:
Residential |  | $ | 1,153 |  |  | $ | 126 |  |  | $ | — |  |  | $ | 1,279 |
C&I |  | 1,634 |  |  | 68 |  |  | 6 |  |  | 1,708 |
Other |  | 38 |  |  | — |  |  | 2 |  |  | 40 |
Total retail |  | 2,825 |  |  | 194 |  |  | 8 |  |  | 3,027 |
Wholesale |  | 191 |  |  | — |  |  | — |  |  | 191 |
Transmission |  | 187 |  |  | — |  |  | — |  |  | 187 |
Other |  | 1 |  |  | 32 |  |  | — |  |  | 33 |
Total revenue from contracts with customers |  | 3,204 |  |  | 226 |  |  | 8 |  |  | 3,438 |
Alternative revenue and other |  | 189 |  |  | 13 |  |  | 4 |  |  | 206 |
Total revenues |  | $ | 3,393 |  |  | $ | 239 |  |  | $ | 12 |  |  | $ | 3,644 |

|  | Nine Months Ended Sept. 30, 2025
(Millions of Dollars) |  | Electric |  | Natural Gas |  | All Other |  | Total
Major revenue types |  |  |  |  |  |  |  |
Revenue from contracts with customers:
Residential |  | $ | 3,065 |  |  | $ | 977 |  |  | $ | 3 |  |  | $ | 4,045 |
C&I |  | 4,557 |  |  | 521 |  |  | 22 |  |  | 5,100 |
Other |  | 113 |  |  | — |  |  | 6 |  |  | 119 |
Total retail |  | 7,735 |  |  | 1,498 |  |  | 31 |  |  | 9,264 |
Wholesale |  | 556 |  |  | — |  |  | — |  |  | 556 |
Transmission |  | 541 |  |  | — |  |  | — |  |  | 541 |
Other |  | 61 |  |  | 129 |  |  | — |  |  | 190 |
Total revenue from contracts with customers |  | 8,893 |  |  | 1,627 |  |  | 31 |  |  | 10,551 |
Alternative revenue and other |  | 458 |  |  | 88 |  |  | 11 |  |  | 557 |
Total revenues |  | $ | 9,351 |  |  | $ | 1,715 |  |  | $ | 42 |  |  | $ | 11,108 |

|  | Nine Months Ended Sept. 30, 2024
(Millions of Dollars) |  | Electric |  | Natural Gas |  | All Other |  | Total
Major revenue types |  |  |  |  |  |  |  |
Revenue from contracts with customers:
Residential |  | $ | 2,813 |  |  | $ | 885 |  |  | $ | 10 |  |  | $ | 3,708 |
C&I |  | 4,245 |  |  | 439 |  |  | 21 |  |  | 4,705 |
Other |  | 108 |  |  | — |  |  | 7 |  |  | 115 |
Total retail |  | 7,166 |  |  | 1,324 |  |  | 38 |  |  | 8,528 |
Wholesale |  | 501 |  |  | — |  |  | — |  |  | 501 |
Transmission |  | 493 |  |  | — |  |  | — |  |  | 493 |
Other |  | 37 |  |  | 133 |  |  | — |  |  | 170 |
Total revenue from contracts with customers |  | 8,197 |  |  | 1,457 |  |  | 38 |  |  | 9,692 |
Alternative revenue and other |  | 540 |  |  | 78 |  |  | 11 |  |  | 629 |
Total revenues |  | $ | 8,737 |  |  | $ | 1,535 |  |  | $ | 49 |  |  | $ | 10,321 |

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6. Income Taxes

Reconciliation between the statutory rate and ETR:

|  | Three Months Ended Sept. 30 |  | Nine Months Ended Sept. 30
|  | 2025 |  | 2024 |  | 2025 |  | 2024
Federal statutory rate |  | 21.0 | % |  | 21.0 | % |  | 21.0 | % |  | 21.0 | %
State income tax on pretax income, net of federal tax effect |  | 5.2 |  |  | 4.7 |  |  | 4.9 |  |  | 4.8 |
(Decreases) increases: |  |  |  |  |  |  |  |
PTCs (a) |  | (17.0) |  |  | (16.0) |  |  | (27.0) |  |  | (26.2) |
Plant regulatory differences (b) |  | (8.2) |  |  | (5.7) |  |  | (7.2) |  |  | (5.9) |
Other tax credits, net operating loss & tax credit allowances |  | (0.4) |  |  | (1.5) |  |  | (0.9) |  |  | (1.1) |
Other, net |  | 0.9 |  |  | (1.1) |  |  | 0.8 |  |  | (0.3) |
Effective income tax rate |  | 1.5 | % |  | 1.4 | % |  | (8.4) | % |  | (7.7) | %

(a)Wind and solar PTCs (net of estimated transfer discounts) are generally credited to customers (reduction to revenue) and do not materially impact earnings.
(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, collared 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 Sept. 30 |  | Nine Months Ended Sept. 30
(Shares in Millions) |  | 2025 |  | 2024 |  | 2025 |  | 2024
Basic |  | 592 |  |  | 564 |  |  | 584 |  |  | 559 |
Diluted (a) |  | 595 |  |  | 565 |  |  | 587 |  |  | 559 |

(a)Diluted common shares outstanding included common stock equivalents of 3.1 million and 0.4 million for the three months ended Sept. 30, 2025 and 2024, respectively. Diluted common shares outstanding included common stock equivalents of 2.2 million and 0.3 million for the nine months ended Sept. 30, 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.
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.
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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 $1.7 billion and $1.4 billion as of Sept. 30, 2025 and Dec. 31, 2024, respectively, and unrealized losses were $44 million and $49 million as of Sept. 30, 2025 and Dec. 31, 2024, respectively.
Non-derivative instruments with recurring fair value measurements in the nuclear decommissioning fund:

|  | Sept. 30, 2025
|  |  |  | Fair Value
(Millions of Dollars) |  | Cost |  | Level 1 |  | Level 2 |  | Level 3 |  | NAV |  | Total
Nuclear decommissioning fund (a)
Cash equivalents |  | $ | 68 |  |  | $ | 68 |  |  | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | 68 |
Commingled funds |  | 696 |  |  | — |  |  | — |  |  | — |  |  | 1,041 |  |  | 1,041 |
Debt securities |  | 903 |  |  | — |  |  | 898 |  |  | 10 |  |  | — |  |  | 908 |
Equity securities |  | 541 |  |  | 1,850 |  |  | 2 |  |  | — |  |  | — |  |  | 1,852 |
Total |  | $ | 2,208 |  |  | $ | 1,918 |  |  | $ | 900 |  |  | $ | 10 |  |  | $ | 1,041 |  |  | $ | 3,869 |

(a)Reported in nuclear decommissioning fund and other investments on the consolidated balance sheets, which also includes $239 million of equity method investments and $165 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 and nine months ended Sept. 30, 2025 and 2024, there were immaterial transfers of Level 3 investments between levels.
Contractual maturity dates of debt securities in the nuclear decommissioning fund as of Sept. 30, 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 |  |  | $ | 341 |  |  | $ | 271 |  |  | $ | 287 |  |  | $ | 908 |

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 $105 million and $96 million at Sept. 30, 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 Sept. 30, 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 Sept. 30, 2025, Xcel Energy had unsettled interest rate derivatives with a notional amount of $120 million and an immaterial fair value.
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 Sept. 30, 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 Sept. 30, 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) |  | Sept. 30, 2025 |  | Dec. 31, 2024
MWh of electricity |  | 50 |  |  | 38 |
MMBtu of natural gas |  | 56 |  |  | 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 Sept. 30, 2025, two of Xcel Energy’s ten most significant counterparties for these activities, comprising $21 million, or 12%, 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 $85 million, or 51%, 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 $28 million, or 17%, of this credit exposure, had credit quality less than investment grade, based on internal analysis.
Seven 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 Sept. 30, 2025 and Dec. 31, 2024, there were $7 million and $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 Sept. 30, 2025 and Dec. 31, 2024, there were approximately $62 million and $69 million of derivative liabilities with such underlying contract provisions, respectively.
Certain derivative instruments are also subject to contract provisions that contain adequate assurance clauses. These provisions allow counterparties to seek performance assurance, including cash collateral, in the event that a given utility subsidiary’s ability to fulfill its contractual obligations is reasonably expected to be impaired.
Xcel Energy had no collateral posted related to adequate assurance clauses in derivative contracts as of Sept. 30, 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 Sept. 30, 2025
Other derivative instruments: |  |  |  |  |
Electric commodity |  | $ | — |  |  | $ | 13 |  |
Natural gas commodity |  | $ | — |  |  | $ | (8) |  |
Total |  | $ | — |  |  | $ | 5 |  |
Nine Months Ended Sept. 30, 2025
Derivatives designated as cash flow hedges: |  |  |
Interest rate |  | $ | 1 |  |  | $ | — |  |
Total |  | $ | 1 |  |  | $ | — |  |
Other derivative instruments: |  |  |  |  |
Electric commodity |  | $ | — |  |  | $ | 27 |  |
Natural gas commodity |  | — |  |  | (1) |  |
Total |  | $ | — |  |  | $ | 26 |  |
Three Months Ended Sept. 30, 2024
Other derivative instruments: |  |  |  |  |
Natural gas commodity |  | $ | — |  |  | $ | (6) |  |
Total |  | $ | — |  |  | $ | (6) |  |
Nine Months Ended Sept. 30, 2024
Derivatives designated as cash flow hedges: |  |  |
Interest rate |  | $ | 29 |  |  | $ | — |  |
Total |  | $ | 29 |  |  | $ | — |  |
Other derivative instruments: |  |  |  |  |
Electric commodity |  | $ | — |  |  | $ | 41 |  |
Natural gas commodity |  | — |  |  | (3) |  |
Total |  | $ | — |  |  | $ | 38 |  |

|  | 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 Sept. 30, 2025 |  |  |  |  |
Derivatives designated as cash flow hedges:
Interest rate |  | $ | 1 |  | (a) | $ | — |  |  | $ | — |  |
Total |  | $ | 1 |  |  | $ | — |  |  | $ | — |  |
Other derivative instruments: |  |  |  |  |
Commodity trading |  | $ | — |  |  | $ | — |  |  | $ | 2 |  | (b)
Electric commodity |  | — |  |  | (1) |  | (c) | — |  |
Total |  | $ | — |  |  | $ | (1) |  |  | $ | 2 |  |
Nine Months Ended Sept. 30, 2025 |  |  |  |  |
Derivatives designated as cash flow hedges:
Interest rate |  | $ | 3 |  | (a) | $ | — |  |  | $ | — |  |
Total |  | $ | 3 |  |  | $ | — |  |  | $ | — |  |
Other derivative instruments: |  |  |  |  |
Commodity trading |  | $ | — |  |  | $ | — |  |  | $ | (5) |  | (b)
Electric commodity |  | — |  |  | (22) |  | (c) | — |  |
Natural gas commodity |  | — |  |  | — |  |  | (13) |  | (d)(e)
Total |  | $ | — |  |  | $ | (22) |  |  | $ | (18) |  |
Three Months Ended Sept. 30, 2024 |  |  |  |  |
Derivatives designated as cash flow hedges:
Interest rate |  | $ | 1 |  | (a) | $ | — |  |  | $ | — |  |
Total |  | $ | 1 |  |  | $ | — |  |  | $ | — |  |
Other derivative instruments: |  |  |  |  |
Commodity trading |  | $ | — |  |  | $ | — |  |  | $ | 3 |  | (b)
Electric commodity |  | — |  |  | (13) |  | (c) | — |  |
Total |  | $ | — |  |  | $ | (13) |  |  | $ | 3 |  |
Nine Months Ended Sept. 30, 2024 |  |  |  |  |
Derivatives designated as cash flow hedges:
Interest rate |  | $ | 3 |  | (a) | $ | — |  |  | $ | — |  |
Total |  | $ | 3 |  |  | $ | — |  |  | $ | — |  |
Other derivative instruments:
Commodity trading |  | $ | — |  |  | $ | — |  |  | $ | (19) |  | (b)
Electric commodity |  | — |  |  | (16) |  | (c) | — |  |
Natural gas commodity |  | — |  |  | — |  |  | (14) |  | (d)(e)
Total |  | $ | — |  |  | $ | (16) |  |  | $ | (33) |  |

(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 nine months ended Sept. 30, 2025 and 2024.
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Derivative assets and liabilities measured at fair value on a recurring basis were as follows:

|  | Sept. 30, 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 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Other derivative instruments: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Commodity trading |  | $ | 4 |  |  | $ | 15 |  |  | $ | 8 |  |  | $ | 27 |  |  | $ | (18) |  |  | $ | 9 |  |  | $ | 6 |  |  | $ | 20 |  |  | $ | 8 |  |  | $ | 34 |  |  | $ | (23) |  |  | $ | 11 |
Electric commodity |  | — |  |  | — |  |  | 190 |  |  | 190 |  |  | (2) |  |  | 188 |  |  | — |  |  | — |  |  | 90 |  |  | 90 |  |  | (1) |  |  | 89 |
Natural gas commodity |  | — |  |  | 19 |  |  | — |  |  | 19 |  |  | — |  |  | 19 |  |  | — |  |  | 14 |  |  | — |  |  | 14 |  |  | — |  |  | 14 |
Total current derivative assets |  | $ | 4 |  |  | $ | 34 |  |  | $ | 198 |  |  | $ | 236 |  |  | $ | (20) |  |  | $ | 216 |  |  | $ | 6 |  |  | $ | 34 |  |  | $ | 98 |  |  | $ | 138 |  |  | $ | (24) |  |  | $ | 114 |
Noncurrent derivative assets |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Other derivative instruments: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Commodity trading |  | $ | 3 |  |  | $ | 29 |  |  | $ | 37 |  |  | $ | 69 |  |  | $ | (13) |  |  | $ | 56 |  |  | $ | 8 |  |  | $ | 37 |  |  | $ | 47 |  |  | $ | 92 |  |  | $ | (20) |  |  | $ | 72 |
Total noncurrent derivative assets |  | $ | 3 |  |  | $ | 29 |  |  | $ | 37 |  |  | $ | 69 |  |  | $ | (13) |  |  | $ | 56 |  |  | $ | 8 |  |  | $ | 37 |  |  | $ | 47 |  |  | $ | 92 |  |  | $ | (20) |  |  | $ | 72 |

|  | Sept. 30, 2025 |  | Dec. 31, 2024
|  | Fair Value |  | Fair Value Total |  | Netting (a) |  | Total |  | Fair Value |  | Fair Value Total |  | Netting (a) |  | Total
(Millions of Dollars) |  | Level 1 |  | Level 2 |  | Level 3 |  |  |  |  | Level 1 |  | Level 2 |  | Level 3 |  |  |
Current derivative liabilities |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Other derivative instruments: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Commodity trading |  | $ | 6 |  |  | $ | 23 |  |  | $ | 6 |  |  | $ | 35 |  |  | $ | (19) |  |  | $ | 16 |  |  | $ | 7 |  |  | $ | 35 |  |  | $ | 5 |  |  | $ | 47 |  |  | $ | (23) |  |  | $ | 24 |
Electric commodity |  | — |  |  | — |  |  | 2 |  |  | 2 |  |  | (2) |  |  | — |  |  | — |  |  | — |  |  | 1 |  |  | 1 |  |  | (1) |  |  | — |
Natural gas commodity |  | — |  |  | 9 |  |  | — |  |  | 9 |  |  | — |  |  | 9 |  |  | — |  |  | 7 |  |  | — |  |  | 7 |  |  | — |  |  | 7 |
Total current derivative liabilities |  | $ | 6 |  |  | $ | 32 |  |  | $ | 8 |  |  | $ | 46 |  |  | $ | (21) |  |  | 25 |  |  | $ | 7 |  |  | $ | 42 |  |  | $ | 6 |  |  | $ | 55 |  |  | $ | (24) |  |  | 31 |
PPAs (b) |  |  |  |  |  |  |  |  |  |  |  | 6 |  |  |  |  |  |  |  |  |  |  |  |  | 6 |
Current derivative instruments |  |  |  |  |  |  |  |  |  |  |  | $ | 31 |  |  |  |  |  |  |  |  |  |  |  |  | $ | 37 |
Noncurrent derivative liabilities |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Other derivative instruments: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Commodity trading |  | $ | 8 |  |  | $ | 25 |  |  | $ | 40 |  |  | $ | 73 |  |  | $ | (15) |  |  | $ | 58 |  |  | $ | 11 |  |  | $ | 32 |  |  | $ | 40 |  |  | $ | 83 |  |  | $ | (22) |  |  | $ | 61 |
Total noncurrent derivative liabilities |  | $ | 8 |  |  | $ | 25 |  |  | $ | 40 |  |  | $ | 73 |  |  | $ | (15) |  |  | 58 |  |  | $ | 11 |  |  | $ | 32 |  |  | $ | 40 |  |  | $ | 83 |  |  | $ | (22) |  |  | 61 |
PPAs (b) |  |  |  |  |  |  |  |  |  |  |  | 11 |  |  |  |  |  |  |  |  |  |  |  |  | 16 |
Noncurrent derivative instruments |  |  |  |  |  |  |  |  |  |  |  | $ | 69 |  |  |  |  |  |  |  |  |  |  |  |  | $ | 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 Sept. 30, 2025 and Dec. 31, 2024, derivative assets and liabilities include no obligations to return cash collateral. At Sept. 30, 2025 and Dec. 31, 2024, derivative assets and liabilities include rights to reclaim cash collateral of $3 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 Sept 30
(Millions of Dollars) |  | 2025 |  | 2024
Balance at July 1 |  | $ | 243 |  |  | $ | 239 |
Purchases (a) |  | — |  |  | 2 |
Settlements (a) |  | (66) |  |  | (76) |
Net transactions recorded during the period: |  |  |  |
Losses recognized in earnings (b) |  | (1) |  |  | (9) |
Net gains recognized as regulatory assets and liabilities (a) |  | 11 |  |  | 6 |
Balance at Sept. 30 |  | $ | 187 |  |  | $ | 162 |
|  | Nine Months Ended Sept 30
(Millions of Dollars) |  | 2025 |  | 2024
Balance at Jan. 1 |  | $ | 99 |  |  | $ | 90 |
Purchases (a) |  | 260 |  |  | 179 |
Settlements (a) |  | (209) |  |  | (237) |
Net transactions recorded during the period: |  |  |  |
Losses recognized in earnings (b) |  | (10) |  |  | (6) |
Net gains recognized as regulatory assets and liabilities (a) |  | 47 |  |  | 136 |
Balance at Sept. 30 |  | $ | 187 |  |  | $ | 162 |

(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 Sept. 30, 2025, other financial instruments for which the carrying amount did not equal fair value:

|  | Sept. 30, 2025 |  | Dec. 31, 2024
(Millions of Dollars) |  | Carrying Amount |  | Fair Value |  | Carrying Amount |  | Fair Value
Long-term debt, including current portion |  | $ | 32,035 |  |  | $ | 29,744 |  |  | $ | 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 Sept. 30, 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 Sept. 30
|  | 2025 |  | 2024 |  | 2025 |  | 2024
(Millions of Dollars) |  | Pension Benefits |  | Postretirement Health Care Benefits
Service cost |  | $ | 19 |  |  | $ | 19 |  |  | $ | 1 |  |  | $ | — |
Interest cost (a) |  | 38 |  |  | 37 |  |  | 6 |  |  | 6 |
Expected return on plan assets (a) |  | (52) |  |  | (52) |  |  | (5) |  |  | (4) |
Amortization of prior service credit (a) |  | (1) |  |  | — |  |  | — |  |  | — |
Amortization of net loss (a) |  | 7 |  |  | 7 |  |  | 1 |  |  | — |
Settlement charge (b) |  | — |  |  | 6 |  |  | — |  |  | — |
Net periodic benefit cost |  | 11 |  |  | 17 |  |  | 3 |  |  | 2 |
Effects of regulation |  | 3 |  |  | (1) |  |  | — |  |  | — |
Net benefit cost recognized for financial reporting |  | $ | 14 |  |  | $ | 16 |  |  | $ | 3 |  |  | $ | 2 |

|  | Nine Months Ended Sept. 30
|  | 2025 |  | 2024 |  | 2025 |  | 2024
(Millions of Dollars) |  | Pension Benefits |  | Postretirement Health Care Benefits
Service cost |  | $ | 57 |  |  | $ | 57 |  |  | $ | 1 |  |  | $ | 1 |
Interest cost (a) |  | 116 |  |  | 113 |  |  | 18 |  |  | 16 |
Expected return on plan assets (a) |  | (156) |  |  | (155) |  |  | (15) |  |  | (13) |
Amortization of prior service credit (a) |  | (1) |  |  | (1) |  |  | — |  |  | — |
Amortization of net loss (a) |  | 21 |  |  | 22 |  |  | 3 |  |  | 1 |
Settlement charge (b) |  | — |  |  | 62 |  |  | — |  |  | — |
Net periodic benefit cost |  | 37 |  |  | 98 |  |  | 7 |  |  | 5 |
Effects of regulation |  | 7 |  |  | (37) |  |  | — |  |  | — |
Net benefit cost recognized for financial reporting |  | $ | 44 |  |  | $ | 61 |  |  | $ | 7 |  |  | $ | 5 |

(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.
(b)A settlement charge is required when the amount of lump-sum distributions during the year is greater than the sum of the service and interest cost components of the annual net periodic pension cost. In the three and nine months ended Sept. 30, 2024, as a result of lump-sum distributions during the 2024 plan year, Xcel Energy recorded a pension settlement charge of $6 million and $62 million, respectively, the majority of which was not recognized due to the effects of regulation. A total of $1 million and $8 million was recognized in the consolidated statement of income for the three and nine months ended Sept. 30, 2024.
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.
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In such cases, there is considerable uncertainty regarding the timing or ultimate resolution, including a possible eventual loss. For current proceedings not specifically reported herein, management does not anticipate that the ultimate liabilities, if any, would have a material effect on Xcel Energy’s consolidated financial statements. Legal fees are generally expensed as incurred.
Gas Trading Litigation — e prime is a wholly owned subsidiary of Xcel Energy. e prime was in the business of natural gas trading and marketing but has not engaged in natural gas trading or marketing activities since 2003. Multiple lawsuits involving multiple plaintiffs seeking monetary damages were commenced against e prime and its affiliates, including Xcel Energy, between 2003 and 2009 alleging fraud and anticompetitive activities in conspiring to restrain the trade of natural gas and manipulate natural gas prices. Cases were all consolidated in the U.S. District Court in Nevada.
One case remains open, which is the multi-district litigation matter consisting of a Wisconsin purported class (Arandell Corp.). In October 2025, a settlement in principle was reached, resulting in an immaterial loss consistent with previously accrued amounts. This settlement is subject to court approval.
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. 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.
On June 8, 2023, the Boulder County Sheriff’s Office released its Marshall Fire Investigative Summary and Review and its supporting documents (Sheriff’s Report). According to the Sheriff’s Report, on Dec. 30, 2021, a fire ignited on a residential property in Boulder, Colorado, located in PSCo’s service territory, for reasons unrelated to PSCo’s power lines. According to the Sheriff’s Report, approximately one hour and 20 minutes after the first ignition, a second fire ignited just south of the Marshall Mesa Trailhead in unincorporated Boulder County, Colorado, also located in PSCo’s service territory. According to the Sheriff’s Report, the second ignition started approximately 80 to 110 feet away from PSCo’s power lines in the area.
PSCo 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 June 2025, the Boulder County District Court dismissed Xcel Energy Inc. from the complaints that named that entity as a defendant, due to lack of jurisdiction.
An initial trial on liability issues was scheduled to start in September 2025. Prior to trial, in September 2025, Xcel Energy, Qwest Corporation and Teleport Communications America, LLC reached settlement agreements in principle that resolve all claims asserted by the subrogation insurers, the public entity plaintiffs and individual plaintiffs. PSCo did not admit any fault, wrongdoing or negligence in connection with these settlement agreements.
PSCo expects to pay approximately $640 million related to these settlements, with approximately $353 million expected to be reimbursed to PSCo by remaining insurance coverage (after consideration of legal costs incurred to date). PSCo recognized a $287 million charge to earnings as a result of these settlement agreements in the quarterly period ended Sept. 30, 2025.
A remaining estimated liability of $640 million is presented in other current liabilities as of Sept. 30, 2025; no estimated liability was recognized as of Dec. 31, 2024. PSCo records insurance recoveries when it is deemed probable that recovery will occur, and PSCo can reasonably estimate the amount or range. Insurance receivables of $353 million related to the settlement are presented in prepayments and other current assets as of Sept. 30, 2025; no such insurance receivables were recognized as of Dec. 31, 2024.
The agreements in principle remain subject to final documentation and individual plaintiffs opting in to the agreements negotiated and recommended by their counsel. The trial that was scheduled to begin in September 2025 has been vacated to allow the parties time to execute definitive settlement agreements. To the extent any individual plaintiffs choose to opt out of the agreements negotiated and recommended by their counsel and such cases are not otherwise resolved, they will be subject to further litigation.
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. In August 2025, the Texas Attorney General’s office announced that it was opening a civil investigation into utilities, including Xcel Energy and SPS, connected to the Smokehouse Creek and Windy Deuce fires. The company is cooperating with that investigation.
SPS is aware of approximately 34 complaints, most of which have also named Xcel Energy Services Inc. as an additional defendant, relating to the Smokehouse Creek Fire Complex. The complaints, which assert claims on behalf of one or more plaintiffs, generally allege that SPS’ equipment ignited the Smokehouse Creek Fire Complex and seek compensation for losses resulting from the fire, asserting various causes of action under Texas law. In addition to seeking compensatory damages, certain of the complaints also seek exemplary damages. Of the 34 complaints, 12 have been resolved and dismissed to date, with nine others settled or settled in principle, and pending dismissal.
SPS has received 254 claims through its claims process and has reached final settlements on 212 of those claims as of the date of this filing. In addition to filed complaints and claims made through SPS’ claims process, SPS has also received information from attorneys for approximately 83 claims which have not been submitted through the claims process and have also not been filed as lawsuits, and has reached settlement of 71 of those claims through mediation.
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SPS has settled claims related to both of the fatalities believed to be associated with the Smokehouse Creek Fire Complex. Settlements have also been reached with the subrogated insurer plaintiffs as well as the three largest claims that have been asserted from the fire, as measured by fire-impacted acreage. Settlements reached as of the date of this filing total $361 million of expected loss payments, of which $219 million and $35 million were paid through Sept. 30, 2025 and Dec. 31, 2024, respectively.
Based on the current state of the law and the facts and circumstances available as of the date of this filing, Xcel Energy has recorded $410 million of total estimated losses for the matter (before available insurance). This represents a $120 million increase from the estimated losses as of June 30, 2025, largely driven by actual settlement activity for large claims and previously inestimable categories, such as damage to trees. A remaining estimated liability of $191 million and $180 million is presented in other current liabilities as of Sept. 30, 2025 and Dec. 31, 2024, respectively.
The cumulative estimated probable losses of $410 million for complaints and claims in connection with the Smokehouse Creek Fire Complex (before available insurance) represents the total of actual settlements reached to date plus the low end of the range for remaining reasonably estimable losses, and is subject to change as additional information becomes available. This $410 million estimate does not include amounts for (i) potential penalties or fines that may be imposed by governmental entities on Xcel Energy, (ii) exemplary or punitive damages, (iii) compensation claims by federal, state, county and local government entities or agencies, (iv) unsettled compensation claims for damage to trees and oil and gas equipment, or (v) other amounts that are not reasonably estimable.
Xcel Energy remains unable to reasonably estimate any additional loss or the upper end of the range because there are a number of unknown facts and legal considerations that may impact the amount of any potential liability, including whether additional complaints and demands may be made. In the event that SPS or Xcel Energy Services Inc. was found liable related to the litigation related to the Smokehouse Creek Fire Complex and was required to pay damages, such amounts could exceed our insurance coverage of approximately $500 million for the annual policy period and could have a material adverse effect on our financial condition, results of operations or cash flows.
The process for estimating losses associated with potential claims related to the Smokehouse Creek Fire Complex requires management to exercise significant judgment based on a number of assumptions and subjective factors, including the factors identified above and estimates based on currently available information and prior experience with wildfires. As more information becomes available, management estimates and assumptions regarding the potential financial impact of the Smokehouse Creek Fire Complex may change.
Texas law does not apply strict liability in determining an electric utility company’s liability for fire-related damages. For negligence claims under Texas law, a public utility has a duty to exercise ordinary and reasonable care.
Potential liabilities related to the Smokehouse Creek Fire Complex depend on various factors, including the cause of the equipment failure and the extent and magnitude of potential damages, including damages to residential and commercial structures, personal property, vegetation, livestock and livestock feed (including replacement feed), personal injuries and any other damages, penalties, fines or restitution that may be imposed by courts or other governmental entities if SPS is found to have been negligent.
SPS records insurance recoveries when it is deemed probable that recovery will occur, and SPS can reasonably estimate the amount or range. Insurance receivables of $341 million and $210 million, net of recoveries received, are presented in prepayments and other current assets as of Sept. 30, 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.
Prairie Island Outage Prudency Review — In March 2024, NSP-Minnesota filed its annual fuel clause adjustment true-up petition to the MPUC. In a response to that petition, intervenors recommended refunds for replacement power costs related to an outage at the Prairie Island generating station (October 2023 through February 2024).
In a September 2024 decision, the MPUC ruled NSP-Minnesota was imprudent in the operation of the Prairie Island nuclear plant based on an incident that resulted in the extended outage. The MPUC did not quantify the refund and referred the determination of the refund amount to the Office of Administrative Hearings. NSP-Minnesota recorded an estimated liability for a customer refund in 2024.
In May 2025, in the resulting case currently before an ALJ to determine the refund amount, NSP-Minnesota submitted direct testimony asserting that no more than $6 million of customer refunds are warranted for the outage.
In July 2025, intervenor direct testimony was filed by the DOC, OAG, and XLI. These parties, together with the CUB, also filed a joint motion requesting the ALJ rule that customer refunds cannot be adjusted as proposed by NSP-Minnesota, including certain reductions for avoided future outages. If NSP-Minnesota’s proposed adjustments were rejected, and other DOC and OAG direct testimony recommendations were applied to both 2023 and 2024, NSP-Minnesota estimates that the customer refunds would be approximately $34 million. The joint motion was denied in August 2025, and the application of the adjustments will be addressed in the case before the ALJ.
Rebuttal and surrebuttal testimony were filed in August and September 2025. An ALJ report is expected in March 2026, with a MPUC decision expected in the second quarter of 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 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. In August 2025, the CPUC approved the settlement agreement.
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Environmental
New and changing federal and state environmental mandates can create financial liabilities for Xcel Energy, which are normally recovered through the regulated rate process.
Site Remediation
Various federal and state environmental laws impose liability where hazardous substances or other regulated materials have been released to the environment. Xcel Energy Inc.’s subsidiaries may sometimes pay all or a portion of the cost to remediate sites where past activities of their predecessors or other parties have caused environmental contamination.
Environmental contingencies could arise from various situations, including sites of former MGPs; and third-party sites, such as landfills, for which one or more of Xcel Energy Inc.’s subsidiaries are alleged to have sent wastes to that site.
MGP, Landfill and Disposal Sites
Xcel Energy is investigating, remediating or performing post-closure actions at 14 historical MGP, landfill or other disposal sites across its service territories, excluding sites that are being addressed under current coal ash regulations (see below).
Xcel Energy has approximately $15 million of remaining liabilities for resolution of these issues, however, the final outcome and timing are unknown. In addition, there may be regulatory recovery, insurance recovery and/or recovery from other potentially responsible parties, offsetting a portion of costs incurred.
Water and Waste
Coal Ash Regulation — Xcel Energy is subject to the CCR Rule, which imposes requirements for handling, storage, treatment and disposal of coal ash and other solid waste.
In May 2024, final amendments to the CCR Rule were published, widening its scope to include legacy CCR surface impoundments at inactive facilities and previously exempt areas where CCR was placed directly on land at CCR-regulated facilities, including areas of beneficial use.
As a requirement of the CCR Rule, utilities must complete facility evaluations and groundwater sampling around their subject landfills, surface impoundments and certain other areas where coal ash was placed on land.
If certain impacts to groundwater are detected, utilities are required to perform additional groundwater investigations and/or perform corrective actions, beginning with an Assessment of Corrective Measures.
Investigation and/or corrective action related to groundwater impacts are currently underway at certain active and closed coal-generating facilities at a current estimated cost of at least $45 million. In addition, Xcel Energy expects to incur $15 million for investigations through 2028 to perform required reporting and assess whether corrective actions are necessary. AROs have been recorded for each of these activities, and amounts are expected to be recoverable through regulatory mechanisms.
Xcel Energy has also identified coal ash that is expected to be required to be removed from certain closed coal-generating facilities at estimated costs totaling approximately $105 million. AROs have been recorded, with the costs expected to be recoverable through regulatory mechanisms.
Xcel Energy continues to perform site investigation activities related to the CCR Rule, which may result in updates to estimated costs as well as identification of additional required corrective actions.
In July 2025, the EPA issued a proposed rule amending the CCR Legacy rule. The proposal seeks to extend deadlines for various regulatory actions and clarify previous information regarding implementation of the rule. Xcel Energy will monitor the proposed rule and evaluate the impacts of any final rule.
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. 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.
Compliance with the published plan would require subject facilities to secure additional allowances, install NOx controls and/or develop a strategy of operations that utilizes the existing allowance allocations. While the financial impacts of the final rule are uncertain and dependent on market forces and anticipated generation, if the rule is implemented, Xcel Energy anticipates the annual costs could be significant but would be recoverable through regulatory mechanisms.
Leases
Xcel Energy evaluates contracts that may contain leases, including PPAs and arrangements for the use of office space and other facilities, as well as certain contracts for the use of land, vehicles and other equipment. A contract contains a lease if it conveys the exclusive right to control the use of a specific asset.
In the third quarter of 2025, certain PPAs for natural gas fueled generating facilities were amended, extending NSP-Minnesota’s use of these plants to 2039 and 2048. The amended agreements qualify for classification as finance leases. As of Sept. 30, 2025, other current liabilities and non-current finance lease liabilities include $37 million and $1.2 billion of finance lease obligations for these amended PPAs, respectively. Prior to these amendments, the agreements were classified as operating leases.
PPA finance lease payments are allocated between interest charges and depreciation and amortization on the consolidated statements of income. PPA operating lease payments are included in electric fuel and purchased power, and expense for other operating leases is included in O&M expense and electric fuel and purchased power.
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Components of lease expense:

|  | Three Months Ended Sept. 30
(Millions of Dollars) |  | 2025 |  | 2024
Operating leases |  |  |  |
PPA capacity payments |  | $ | 47 |  |  | $ | 57 |
Other operating leases (a) |  | 9 |  |  | 11 |
Total operating lease expense |  | $ | 56 |  |  | $ | 68 |
Finance leases |  |  |  |
Amortization of ROU assets |  | $ | 4 |  |  | $ | 1 |
Interest expense on lease liability |  | 14 |  |  | 4 |
Total finance lease expense |  | $ | 18 |  |  | $ | 5 |

(a)Includes immaterial short-term lease expense.

|  | Nine Months Ended Sept. 30
(Millions of Dollars) |  | 2025 |  | 2024
Operating leases |  |  |  |
PPA capacity payments |  | $ | 158 |  |  | $ | 172 |
Other operating leases (a) |  | 32 |  |  | 33 |
Total operating lease expense |  | $ | 190 |  |  | $ | 205 |
Finance leases |  |  |  |
Amortization of ROU assets |  | $ | 6 |  |  | $ | 3 |
Interest expense on lease liability |  | 22 |  |  | 11 |
Total finance lease expense |  | $ | 28 |  |  | $ | 14 |

(a)Includes immaterial short-term lease expense.
Commitments under operating and finance leases as of Sept. 30, 2025:

(Millions of Dollars) |  | PPA Operating Leases |  | Other Operating Leases |  | Total Operating Leases |  | Finance Leases (a)
Total minimum obligation |  | $ | 667 |  |  | $ | 516 |  |  | $ | 1,183 |  |  | $ | 2,211 |
Interest component of obligation |  | (98) |  |  | (200) |  |  | (298) |  |  | (900) |
Present value of minimum obligation |  | $ | 569 |  |  | $ | 316 |  |  | 885 |  |  | 1,311 |
Less current portion |  |  |  |  |  | (114) |  |  | (39) |
Noncurrent operating and finance lease liabilities |  |  |  |  |  | $ | 771 |  |  | $ | 1,272 |

(a)Excludes certain amounts related to PSCo’s lease obligations given Xcel Energy’s 50% ownership interest in WYCO.
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 3,661 MW and 3,751 MW of capacity under long-term PPAs at Sept. 30, 2025 and Dec. 31, 2024, respectively, 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 Sept. 30, 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 $111 million and $93 million at Sept. 30, 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, breaches of representations and warranties, including corporate existence, transaction authorization and income tax matters with respect to assets sold, as well as disallowances or reductions to the contractual amounts of tax credit transfers.
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.
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11. Other Comprehensive Loss

Changes in accumulated other comprehensive loss, net of tax:

|  | Three Months Ended Sept. 30, 2025 |  | Three Months Ended Sept. 30, 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 July 1 |  | $ | (27) |  |  | $ | (39) |  |  | $ | (66) |  |  | $ | (30) |  |  | $ | (37) |  |  | $ | (67) |
Losses reclassified from net accumulated other comprehensive loss: |  |  |  |  |  |  |  |  |  |  |  |
Interest rate derivatives (a) | 1 |  |  | — |  |  | 1 |  |  | 1 |  |  | — |  |  | 1 |
Net current period other comprehensive income |  | 1 |  |  | — |  |  | 1 |  |  | 1 |  |  | — |  |  | 1 |
Accumulated other comprehensive loss at Sept. 30 |  | $ | (26) |  |  | $ | (39) |  |  | $ | (65) |  |  | $ | (29) |  |  | $ | (37) |  |  | $ | (66) |

|  | Nine Months Ended Sept. 30, 2025 |  | Nine Months Ended Sept. 30, 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 gain before reclassifications |  | — |  |  | — |  |  | — |  |  | 22 |  |  | — |  |  | 22 |
Losses reclassified from net accumulated other comprehensive loss: |  |  |  |  |  |  |  |  |  |  |  |
Interest rate derivatives (a) | 3 |  |  | — |  |  | 3 |  |  | 2 |  |  | — |  |  | 2 |
Amortization of net actuarial losses (b) |  | — |  |  | — |  |  | — |  |  | — |  |  | 4 |  |  | 4 |
Net current period other comprehensive income |  | 3 |  |  | — |  |  | 3 |  |  | 24 |  |  | 4 |  |  | 28 |
Accumulated other comprehensive loss at Sept. 30 |  | $ | (26) |  |  | $ | (39) |  |  | $ | (65) |  |  | $ | (29) |  |  | $ | (37) |  |  | $ | (66) |

(a)Included in interest charges.
(b)Included in the computation of net periodic pension and postretirement benefit costs. See Note 9 for further information.

12. Segment Information

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

|  | Three Months Ended Sept. 30, 2025
(Millions of Dollars) |  | Regulated electric utility |  | Regulated natural gas utility |  | Total segments
Operating revenues |  | $ | 3,638 |  |  | $ | 264 |  |  | $ | 3,902 |
Intersegment revenue |  | — |  |  | 8 |  |  | 8 |
Total segment revenues |  | 3,638 |  |  | 272 |  |  | 3,910 |
Electric fuel and purchased power |  | 1,098 |  |  | — |  |  | 1,098 |
Cost of natural gas sold and transported |  | — |  |  | 61 |  |  | 61 |
O&M expenses |  | 582 |  |  | 105 |  |  | 687 |
Depreciation and amortization |  | 640 |  |  | 106 |  |  | 746 |
Other segment expenses, net |  | 443 |  |  | 28 |  |  | 471 |
Interest charges and financing costs |  | 228 |  |  | 31 |  |  | 259 |
Income tax expense (benefit) |  | 55 |  |  | (20) |  |  | 35 |
Net income (loss) |  | $ | 592 |  |  | $ | (39) |  |  | $ | 553 |
Total segment net income |  |  |  |  |  | $ | 553 |
Non-segment net loss |  |  |  |  |  | (29) |
Consolidated net income |  |  |  |  |  | $ | 524 |

|  | Three Months Ended Sept. 30, 2024
(Millions of Dollars) |  | Regulated electric utility |  | Regulated natural gas utility |  | Total segments
Operating revenues |  | $ | 3,393 |  |  | $ | 239 |  |  | $ | 3,632 |
Electric fuel and purchased power |  | 1,060 |  |  | — |  |  | 1,060 |
Cost of natural gas sold and transported |  | — |  |  | 63 |  |  | 63 |
O&M expenses |  | 540 |  |  | 100 |  |  | 640 |
Depreciation and amortization |  | 591 |  |  | 87 |  |  | 678 |
Other segment expenses, net |  | 197 |  |  | 14 |  |  | 211 |
Interest charges and financing costs |  | 198 |  |  | 29 |  |  | 227 |
Income tax expense (benefit) |  | 55 |  |  | (18) |  |  | 37 |
Net income (loss) |  | $ | 752 |  |  | $ | (36) |  |  | $ | 716 |
Total segment net income |  |  |  |  |  | $ | 716 |
Non-segment net loss |  |  |  |  |  | (34) |
Consolidated net income |  |  |  |  |  | $ | 682 |

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|  | Nine Months Ended Sept. 30, 2025
(Millions of Dollars) |  | Regulated electric utility |  | Regulated natural gas utility |  | Total segments
Operating revenues |  | $ | 9,351 |  |  | $ | 1,715 |  |  | $ | 11,066 |
Intersegment revenue |  | — |  |  | 19 |  |  | 19 |
Total segment revenues |  | 9,351 |  |  | 1,734 |  |  | 11,085 |
Electric fuel and purchased power |  | 3,036 |  |  | — |  |  | 3,036 |
Cost of natural gas sold and transported |  | — |  |  | 708 |  |  | 708 |
O&M expenses |  | 1,704 |  |  | 316 |  |  | 2,020 |
Depreciation and amortization |  | 1,883 |  |  | 306 |  |  | 2,189 |
Other segment expenses, net |  | 770 |  |  | 112 |  |  | 882 |
Interest charges and financing costs |  | 645 |  |  | 92 |  |  | 737 |
Income tax (benefit) expense |  | (88) |  |  | 37 |  |  | (51) |
Net income |  | $ | 1,401 |  |  | $ | 163 |  |  | $ | 1,564 |
Total segment net income |  |  |  |  |  | $ | 1,564 |
Non-segment net loss |  |  |  |  |  | (113) |
Consolidated net income |  |  |  |  |  | $ | 1,451 |

|  | Nine Months Ended Sept. 30, 2024
(Millions of Dollars) |  | Regulated electric utility |  | Regulated natural gas utility |  | Total segments
Operating revenues |  | $ | 8,737 |  |  | $ | 1,535 |  |  | $ | 10,272 |
Intersegment revenue |  | 1 |  |  | 1 |  |  | 2 |
Total segment revenues |  | 8,738 |  |  | 1,536 |  |  | 10,274 |
Electric fuel and purchased power |  | 2,863 |  |  | — |  |  | 2,863 |
Cost of natural gas sold and transported |  | — |  |  | 664 |  |  | 664 |
O&M expenses |  | 1,596 |  |  | 306 |  |  | 1,902 |
Depreciation and amortization |  | 1,772 |  |  | 260 |  |  | 2,032 |
Other segment expenses, net |  | 547 |  |  | 67 |  |  | 614 |
Interest charges and financing costs |  | 582 |  |  | 86 |  |  | 668 |
Income tax (benefit) expense |  | (85) |  |  | 28 |  |  | (57) |
Net income |  | $ | 1,463 |  |  | $ | 125 |  |  | $ | 1,588 |
Total segment net income |  |  |  |  |  | $ | 1,588 |
Non-segment net loss |  |  |  |  |  | (116) |
Consolidated net income |  |  |  |  |  | $ | 1,472 |

Equity method investments in the regulated natural gas utility segment of $90 million and $85 million at Sept. 30, 2025 and Dec. 31, 2024, respectively, primarily relate to WYCO. Non-segment equity method investments of $149 million and $161 million as of Sept. 30, 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 wildfire litigation expense, conservation and DSM expenses, taxes (other than income taxes), other income, 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.
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.
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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.
The following table provides a reconciliation of GAAP earnings (net income) to ongoing earnings:

|  | Three Months Ended Sept. 30 |  | Nine Months Ended Sept. 30
(Millions of Dollars) |  | 2025 |  | 2024 |  | 2025 |  | 2024
GAAP net income |  | $ | 524 |  |  | $ | 682 |  |  | $ | 1,451 |  |  | $ | 1,472 |
Sherco Unit 3 2011 outage refunds |  | — |  |  | 35 |  |  | — |  |  | 46 |
Marshall Wildfire litigation |  | 287 |  |  | — |  |  | 287 |  |  | — |
Tax effect |  | (74) |  |  | (10) |  |  | (74) |  |  | (13) |
Ongoing earnings |  | $ | 737 |  |  | $ | 707 |  |  | $ | 1,664 |  |  | $ | 1,505 |

Sherco Unit 3 2011 Outage Refunds — NSP-Minnesota’s Sherco Unit 3 experienced an extended outage following a 2011 incident which damaged its turbine. In October 2024 following contested case procedures, the MPUC ordered a customer refund of $46 million for replacement power incurred during the outage, which is presented as a non-recurring charge to electric revenues.
Marshall Wildfire Litigation — In the third quarter of 2025, PSCo recognized a non-recurring $287 million charge as a result of a settlement reached with the plaintiffs in the Marshall Wildfire litigation.

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.
Xcel Energy’s third quarter GAAP diluted earnings were $0.88 per share compared with $1.21 per share in the same period in 2024 and ongoing earnings were $1.24 compared with $1.25 per share in 2024. The change in ongoing earnings per share was primarily driven by higher depreciation, interest charges and O&M expenses 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).
Summarized diluted EPS for Xcel Energy:

|  | Three Months Ended Sept. 30 |  | Nine Months Ended Sept. 30
Diluted Earnings (Loss) Per Share |  | 2025 |  | 2024 |  | 2025 |  | 2024
NSP-Minnesota |  | $ | 0.53 |  |  | $ | 0.45 |  |  | $ | 1.17 |  |  | $ | 1.06 |
PSCo |  | 0.08 |  |  | 0.45 |  |  | 0.79 |  |  | 1.06 |
SPS |  | 0.27 |  |  | 0.31 |  |  | 0.55 |  |  | 0.58 |
NSP-Wisconsin |  | 0.07 |  |  | 0.07 |  |  | 0.19 |  |  | 0.19 |
Earnings from equity method investments — WYCO |  | 0.01 |  |  | 0.01 |  |  | 0.02 |  |  | 0.02 |
Regulated utility |  | 0.96 |  |  | 1.29 |  |  | 2.72 |  |  | 2.91 |
Xcel Energy Inc. and Other |  | (0.07) |  |  | (0.08) |  |  | (0.24) |  |  | (0.28) |
GAAP diluted EPS (a) |  | $ | 0.88 |  |  | $ | 1.21 |  |  | $ | 2.47 |  |  | $ | 2.63 |
Sherco Unit 3 2011 outage refunds |  | — |  |  | 0.04 |  |  | — |  |  | 0.06 |
Marshall Wildfire settlement |  | 0.36 |  |  | — |  |  | 0.36 |  |  | — |
Ongoing diluted EPS (a) |  | $ | 1.24 |  |  | $ | 1.25 |  |  | $ | 2.84 |  |  | $ | 2.69 |

(a)Amounts may not add due to rounding.
Summary of Earnings
NSP-Minnesota — GAAP earnings increased $0.08 per share and ongoing earnings increased $0.04 for the third quarter. Year-to-date GAAP earnings increased $0.11 per share and ongoing earnings increased $0.05 per share. The year-to-date ongoing earnings increase was driven by higher recovery of electric infrastructure investments, which was partially offset by increased O&M expenses, depreciation and interest charges.
PSCo — GAAP earnings decreased $0.37 per share and ongoing earnings decreased $0.01 for the third quarter of 2025. Year-to-date GAAP earnings decreased $0.27 and ongoing earnings increased $0.09. The year-to-date ongoing earnings increase was driven by higher recovery of electric and natural gas infrastructure investments, which was partially offset by increased depreciation and interest charges.
SPS — GAAP and ongoing earnings decreased $0.04 per share for the third quarter and decreased $0.03 year-to-date. The year-to-date change was driven by unfavorable weather, increased interest charges and O&M expenses, partially offset by higher recovery of electric infrastructure investments and sales growth.
NSP-Wisconsin — GAAP and ongoing earnings per share were flat for the third quarter of 2025 and year-to-date. The year-to-date change was driven by higher recovery of electric and natural gas infrastructure investments, which was offset by increased depreciation and O&M expenses.
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 change in earnings was largely due to gains on debt repurchases, partially offset by higher interest rates and debt levels and the performance of the equity method investments, which primarily invest in energy technology companies.
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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 Sept. 30 |  | Nine Months Ended Sept. 30
GAAP EPS — 2024 |  | $ | 1.21 |  |  | $ | 2.63 |
Components of change - 2025 vs. 2024 |  |  |  |
Higher electric revenues |  | 0.28 |  |  | 0.76 |
Higher natural gas revenues |  | 0.03 |  |  | 0.24 |
Higher AFUDC equity & debt |  | 0.08 |  |  | 0.18 |
Sherco Unit 3 2011 outage refunds |  | 0.04 |  |  | 0.06 |
Marshall Wildfire settlement |  | (0.36) |  |  | (0.36) |
Higher electric fuel and purchased power (a) |  | (0.05) |  |  | (0.23) |
Higher depreciation |  | (0.09) |  |  | (0.21) |
Higher O&M expenses |  | (0.05) |  |  | (0.17) |
Higher interest charges |  | (0.08) |  |  | (0.17) |
Higher costs of natural gas sold and transported (a) |  | — |  |  | (0.06) |
Common stock equity dilution |  | (0.07) |  |  | (0.14) |
Other, net |  | (0.06) |  |  | (0.06) |
GAAP EPS — 2025 |  | $ | 0.88 |  |  | $ | 2.47 |
Marshall Wildfire settlement |  | 0.36 |  |  | 0.36 |
Ongoing EPS — 2025 (b) |  | $ | 1.24 |  |  | $ | 2.84 |

(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.
(b)Amounts may not add due to rounding.
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. Gas decoupling mechanisms (and electric sales true-up in 2024) in Minnesota predominately mitigate the positive and adverse impacts of weather in that jurisdiction.
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, CDD and THI:

| Three Months Ended Sept. 30 |  | Nine Months Ended Sept. 30
| 2025 vs. Normal |  | 2024 vs. Normal |  | 2025 vs. 2024 |  | 2025 vs. Normal |  | 2024 vs. Normal |  | 2025 vs. 2024
HDD | (30.6) | % |  | (72.7) | % |  | 135.7 | % |  | (1.9) | % |  | (14.7) | % |  | 12.3 | %
CDD | (7.2) |  |  | 20.1 |  |  | (20.8) |  |  | (6.8) |  |  | 24.7 |  |  | (23.0) |
THI | 12.3 |  |  | (1.8) |  |  | 15.9 |  |  | 7.3 |  |  | (10.8) |  |  | 21.9 |

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

| Three Months Ended Sept. 30 |  | Nine Months Ended Sept. 30
| 2025 vs. Normal |  | 2024 vs. Normal |  | 2025 vs. 2024 |  | 2025 vs. Normal |  | 2024 vs. Normal |  | 2025 vs. 2024
Retail electric | $ | 0.006 |  |  | $ | 0.038 |  |  | $ | (0.032) |  |  | $ | (0.001) |  |  | $ | 0.015 |  |  | $ | (0.016) |
Sales true-up (a) | — |  |  | (0.001) |  |  | 0.001 |  |  | — |  |  | 0.040 |  |  | (0.040) |
Electric total | $ | 0.006 |  |  | $ | 0.037 |  |  | $ | (0.031) |  |  | $ | (0.001) |  |  | $ | 0.055 |  |  | $ | (0.056) |
Firm natural gas | — |  |  | (0.002) |  |  | 0.002 |  |  | — |  |  | (0.040) |  |  | 0.040 |
Decoupling | 0.001 |  |  | (0.001) |  |  | 0.002 |  |  | 0.003 |  |  | 0.017 |  |  | (0.014) |
Natural gas total | $ | 0.001 |  |  | $ | (0.003) |  |  | $ | 0.004 |  |  | $ | 0.003 |  |  | $ | (0.023) |  |  | $ | 0.026 |
Total | $ | 0.007 |  |  | $ | 0.034 |  |  | $ | (0.027) |  |  | $ | 0.002 |  |  | $ | 0.032 |  |  | $ | (0.030) |

(a)The sales true-up mechanism in NSP-Minnesota expired in 2024 and is proposed in the pending Minnesota electric rate case to be reestablished in 2026.
Sales — Sales growth (decline) for actual and weather-normalized sales in 2025 compared to 2024:

|  | Three Months Ended Sept. 30
|  | NSP-Minnesota |  | PSCo |  | SPS |  | NSP-Wisconsin |  | Xcel Energy
Actual |  |  |  |  |  |  |  |  |  |
Electric residential |  | 6.4 | % |  | (0.1) | % |  | (7.5) | % |  | 3.5 | % |  | 1.6 | %
Electric C&I |  | (0.8) |  |  | (1.5) |  |  | 5.4 |  |  | 0.1 |  |  | 1.0 |
Total retail electric sales |  | 1.7 |  | (0.9) |  |  | 2.8 |  |  | 1.0 |  |  | 1.1 |
Firm natural gas sales |  | 3.7 |  |  | 4.9 |  |  | N/A |  | (4.5) |  |  | 4.0 |

|  | Three Months Ended Sept. 30
|  | NSP-Minnesota |  | PSCo |  | SPS |  | NSP-Wisconsin |  | Xcel Energy
Weather-Normalized |  |  |  |  |  |  |  |
Electric residential |  | 1.9 | % |  | 5.2 | % |  | 3.3 | % |  | 1.9 | % |  | 3.3 | %
Electric C&I |  | (1.9) |  |  | 1.5 |  |  | 6.5 |  |  | (0.1) |  |  | 1.9 |
Total retail electric sales |  | (0.6) |  |  | 2.9 |  |  | 5.7 |  |  | 0.4 |  |  | 2.2 |
Firm natural gas sales |  | 1.7 |  |  | 1.7 |  |  | N/A |  | (6.2) |  |  | 1.2 |

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|  | Nine Months Ended Sept. 30
|  | NSP-Minnesota |  | PSCo |  | SPS |  | NSP-Wisconsin |  | Xcel Energy
Actual |  |  |  |  |  |  |  |  |  |
Electric residential |  | 6.0 | % |  | (0.9) | % |  | (2.1) | % |  | 6.1 | % |  | 2.2 | %
Electric C&I |  | 0.1 |  |  | (0.3) |  |  | 6.3 |  |  | 0.2 |  |  | 1.9 |
Total retail electric sales |  | 2.0 |  |  | (0.5) |  |  | 4.7 |  |  | 1.8 |  |  | 1.9 |
Firm natural gas sales |  | 15.0 |  |  | 2.2 |  |  | N/A |  | 18.5 |  |  | 7.0 |

|  | Nine Months Ended Sept. 30
|  | NSP-Minnesota |  | PSCo |  | SPS |  | NSP-Wisconsin |  | Xcel Energy
Weather-Normalized |  |  |  |  |  |  |  |
Electric residential |  | 1.2 | % |  | 2.4 | % |  | 4.4 | % |  | 1.7 | % |  | 2.2 | %
Electric C&I |  | (0.9) |  |  | 1.2 |  |  | 7.0 |  |  | (0.2) |  |  | 2.2 |
Total retail electric sales |  | (0.2) |  |  | 1.6 |  |  | 6.4 |  |  | 0.3 |  |  | 2.1 |
Firm natural gas sales |  | — |  |  | (2.0) |  |  | N/A |  | 2.4 |  |  | (1.1) |

|  | Nine Months Ended Sept. 30 (Leap Year Adjusted)
|  | NSP-Minnesota |  | PSCo |  | SPS |  | NSP-Wisconsin |  | Xcel Energy
Weather-Normalized
Electric residential |  | 1.6 | % |  | 2.8 | % |  | 4.8 | % |  | 2.1 | % |  | 2.5 | %
Electric C&I |  | (0.5) |  |  | 1.6 |  |  | 7.4 |  |  | 0.1 |  |  | 2.6 |
Total retail electric sales |  | 0.2 |  |  | 2.0 |  |  | 6.8 |  |  | 0.6 |  |  | 2.5 |
Firm natural gas sales |  | 0.9 |  |  | (1.2) |  |  | N/A |  | 3.3 |  |  | (0.3) |

Weather-normalized and leap-year adjusted electric sales growth (decline) — year-to-date
•NSP-Minnesota — Residential sales increased due to customer growth (1.1%) and increase in use per customer (0.4%). C&I sales decreased due to lower use per customer.
•PSCo — Residential sales increased due to increased use per customer (1.6%) and customer growth (1.2%). C&I sales increased due to higher use per customer and customer growth, primarily in the information and energy sectors.
•SPS — Residential sales increased due to higher use per customer (4.1%) and customer growth (0.7%). C&I sales increased due to higher use per customer, primarily driven by the energy sector.
•NSP-Wisconsin — Residential sales increased due to both increased use per customer (1.1%) and customer growth (1.0%).
Weather-normalized and leap-year adjusted natural gas sales growth (decline) — year-to-date
•Decrease in natural gas sales was driven primarily by decreased use per customer in PSCo residential, partially offset by growth in other jurisdictions.
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.

(Millions of Dollars) |  | Three Months Ended Sept. 30, 2025 vs. 2024 |  | Nine Months Ended Sept. 30, 2025 vs. 2024
Recovery of higher cost of electric fuel and purchased power |  | $ | 28 |  |  | $ | 160 |
Non-fuel riders |  | 35 |  |  | 151 |
Regulatory rate outcomes (MN and ND) |  | 46 |  |  | 98 |
Sales and demand |  | 44 |  |  | 98 |
Transmission revenues |  | 14 |  |  | 48 |
Sherco Unit 3 2011 outage refunds |  | 35 |  |  | 46 |
PTCs flowed back to customers (offset in ETR) |  | 32 |  |  | 17 |
Estimated impact of weather |  | (21) |  |  | (39) |
Conservation and demand side management (offset in expense) |  | (19) |  |  | (34) |
Other, net |  | 51 |  |  | 69 |
Total increase |  | $ | 245 |  |  | $ | 614 |

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

(Millions of Dollars) |  | Three Months Ended Sept. 30, 2025 vs. 2024 |  | Nine Months Ended Sept. 30, 2025 vs. 2024
Regulatory rate outcomes (CO) |  | $ | 10 |  |  | $ | 82 |
Recovery of higher cost of natural gas |  | 5 |  |  | 53 |
Conservation revenue (offset in expense) |  | 6 |  |  | 34 |
Estimated impact of weather (net of decoupling) |  | 3 |  |  | 19 |
Retail sales decline (net of decoupling) |  | (3) |  |  | (13) |
Other, net |  | 4 |  |  | 5 |
Total increase |  | $ | 25 |  |  | $ | 180 |

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 $38 million for the third quarter of 2025 and $173 million year-to-date. The year-to-date increase was primarily due to increased commodity prices and transmission expense partially offset by decreased volumes and 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 decreased $2 million for the third quarter of 2025 and increased $44 million year-to-date. The year-to-date increase was primarily due to higher commodity prices and volumes, partially offset by timing of fuel recovery mechanisms.
Non-Fuel Operating Expenses and Other Items
O&M Expenses — O&M expenses increased $37 million for the third quarter of 2025 and $131 million year-to-date. The year-to-date increase was primarily due to increased benefits and healthcare costs, nuclear generation costs and insurance costs.
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Depreciation and Amortization — Depreciation and amortization increased $69 million for the third quarter of 2025 and $158 million year-to-date. The year-to-date increase was largely the result of system investment.
Other Income — Other income increased $7 million for the third quarter of 2025 and $46 million year-to-date, largely due to gains on debt repurchases in the second quarter of 2025.
Interest Charges — Interest charges increased $58 million for the third quarter of 2025 and $129 million year-to-date, largely due to higher debt levels and interest rates.
AFUDC, Equity and Debt — AFUDC increased $50 million for the third quarter of 2025 and $112 million year-to-date, largely the result of system investment.

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
Upcoming, Pending and Recently Concluded Regulatory Proceedings
2025 Minnesota Natural Gas Rate Case — On Oct. 31, 2025, NSP-Minnesota plans to file a natural gas rate case in Minnesota, seeking a total revenue increase of $63 million (8.2%). The filing is based on a 2026 forecast test year and includes an ROE of 10.65%, a 52.5% equity ratio and rate base of $1.5 billion. NSP-Minnesota will also request interim rates of $51 million to go into effect on Jan. 1, 2026. As part of the request, NSP-Minnesota plans to file an option for a stay-out alternative.
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. In June 2025, the MPUC ordered proceedings to reconsider the treatment of prepaid pension assets and executive compensation, with the procedural schedule expected to be established in the fourth quarter of 2025.
2024 Minnesota Electric Rate Case — In November 2024, NSP-Minnesota filed an electric rate case in Minnesota 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. In December 2024, the MPUC approved interim rates of $192 million, effective Jan. 1, 2025. In March 2025, NSP-Minnesota filed supplemental direct testimony, updating its total revenue request to $473 million.
In August 2025, eight parties filed testimony. The DOC, OAG, XLI, the CUB, Walmart and Joint Intervenors were the only parties to quantify recommended financial adjustments. XLI recommended $190 million in proposed adjustments, based on a reduced ROE and a reduction in certain O&M expenses. CUB recommended proposed adjustments based on a reduced ROE and elimination of reconnection and late fee revenues. Walmart recommended an adjustment based on a reduced ROE. Other parties provided issue specific recommendations.
Proposed DOC modifications to NSP-Minnesota’s request are summarized below:

(Millions of Dollars) |  | 2025 |  | 2026
NSP-Minnesota’s filed base revenue request |  | $ | 344 |  |  | $ | 473 |
Recommended adjustments: |  |  |  |
Rate of return |  | (101) |  |  | (107) |
O&M expenses |  | (62) |  |  | (56) |
Generation capacity revenue (a) |  | (39) |  |  | (40) |
Depreciation |  | (29) |  |  | (32) |
Federal production tax credits (a) |  | (22) |  |  | (10) |
Riverside Generating Plant outage (b) |  | (18) |  |  | (13) |
Prepaid pension assets and liability |  | (11) |  |  | (11) |
Property tax (a) |  | (4) |  |  | (12) |
Other, net |  | (9) |  |  | (25) |
Total adjustments |  | (295) |  |  | (306) |
Total proposed revenue change |  | $ | 49 |  |  | $ | 167 |

(a)Adjustments largely offset in trackers.
(b)Riverside Generating Plant experienced a mechanical failure in April 2025 that resulted in an extended outage.
Positions on NSP-Minnesota’s filed rate request:

Recommended Position |  | DOC |  | XLI |  | CUB |  | Walmart
ROE |  | 9.25% |  | 8.96% |  | 9.00% |  | 9.25%
Equity |  | 52.50% |  | N/A |  | N/A |  | N/A

In October 2025, NSP-Minnesota filed rebuttal testimony, updating its total revenue request to $365 million. Of NSP-Minnesota’s proposed adjustments, approximately $100 million relates to depreciation expense and $50 million are largely offset in trackers.
An ALJ report is expected in April 2026, with a MPUC decision expected in the third quarter of 2026.
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2025 South Dakota Electric Rate Case — In June 2025, NSP-Minnesota filed a request with the SDPUC for a net annual electric rate increase of $44 million (15%). The filing is based on a 2024 historic test year, a requested ROE of 10.3%, rate base of approximately $1.2 billion and an equity ratio of 52.87%. NSP-Minnesota will request interim rates to begin on Jan. 1, 2026. If approved as filed, this rate request would result in an average annual residential bill increase of 3% over the period from 2016-2026.
The procedural schedule is as follows:
•Intervenor direct testimony: March 20, 2026
•Rebuttal testimony: April 14, 2026
•Evidentiary Hearing: April 28-30, 2026
A SDPUC decision is expected in the second quarter of 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).
On July 8, 2025, two intervenors filed testimony with a range of recommendations. NDPSC Staff recommended an increase of approximately $30 million, with a 9.41% ROE and a 50% equity ratio, along with other proposed adjustments that were not quantified. NSP-Minnesota estimates the NDPSC Staff recommendation would result in a rate increase of $20 million to $25 million. A NDPSC decision is expected in early 2026.
NSP-Wisconsin
Pending and Recently Concluded 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. The PSCW verbally approved the request in August 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%.
On August 8, 2025, the PSCW Staff and intervenors filed their direct testimony. The PSCW Staff recommended an electric base rate increase of $115 million or 14.4% over the two-year period. The PSCW Staff additionally recommended a natural gas rate increase of $21 million, or 12.3% over the two-year period, all based on a ROE of 9.7% and an equity ratio of 53.5%.
Intervenors mainly limited their comments on revenue requirements to ROE focusing the majority of their testimony on cost of service, rate design and other policy issues.
The major components of the PSCW Staff recommendation are summarized below:

(Millions of Dollars) |  | Electric |  | Natural Gas
NSP-Wisconsin’s filed two-year rate request |  | $ | 151 |  |  | $ | 24 |
PSCW Staff recommended adjustments: |  |  |  |
Capital investments (a) |  | (15) |  | (1)
ROE adjustment |  | (7) |  | (1)
O&M expenses |  | (6) |  | (1)
Nuclear decommissioning accrual update (b) |  | (6) |  | —
Other, net |  | (2) |  | —
Proposed revenue change |  | $ | 115 |  |  | $ | 21 |

(a)Capital investment adjustment includes $7 million associated with two MISO LRTP projects that are pending PSCW approval (Grid Forward and Western Wisconsin Transmission Connection). It is PSCW Staff historic practice to recommend adjustments for projects until Commission approval is received. Approval of both LRTP projects is anticipated in the fourth quarter of 2025.
(b)Since filing the case, the Minnesota Public Utilities Commission authorized a reduction to the annual nuclear decommissioning accrual. This reduction, which flows to NSP-Wisconsin through the interchange agreement, reduced the NSP-Wisconsin rate request and is earnings neutral.
A PSCW decision is anticipated in the fourth quarter of 2025.
Michigan Natural Gas Rate Case – In July 2025, NSP-Wisconsin filed a natural gas rate case in Michigan, seeking a revenue increase of $2.2 million. An MPSC decision is expected in early 2026.
NSP System
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 early 2026.
•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 fourth quarter of 2025.
•NSP-Minnesota and NSP-Wisconsin will continue to file additional RFPs throughout 2025 and 2026 for resource needs approved as part of the 2024 Upper Midwest Resource Plan.
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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 potentially 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. In May 2025, PSCo filed an appeal with the Denver District Court seeking review of the CPUC’s decisions related to recovery of certain operating expenses, cost of capital and capital structure, and the treatment of gas storage inventory costs. Briefing will be completed in the fourth quarter of 2025.
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 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. In September 2025, the CPUC authorized the process for company-owned and PPA resources to seek up to 15% relief for tariff impacts to projects. Relief requests are due by Dec. 31, 2025 or 18 months prior to COD. The CPUC will ultimately review and approve/deny requests.
PSCo has filed all generation CPCNs associated with company-owned generation from the Colorado Energy Plan and expects to continue filing transmission CPCNs throughout 2025 and 2026.
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 |

A hearing was held in June 2025 and a CPUC decision on the resource need is expected in the fourth quarter of 2025 with the competitive solicitation for resource additions expected in early 2026.
Near-Term Procurement — In August 2025, PSCo filed a joint motion with state agencies to initiate a “fast-tracked” solution for tax-advantaged new generation resources. The CPUC approved the request in September 2025 with bids submitted in October 2025. The procurement seeks to accelerate development of up to 4,000 MW of clean energy resources, 200 MW of firm, dispatchable resources, and up to 300 MW of other dispatchable resources. A recommended portfolio of resources will be filed December 2025 and a decision is expected in February 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.
In August 2025, the CPUC issued a written approval of the settlement agreement.
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.
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. PSCo made a filing in June 2025 to implement the mechanism with a CPUC decision expected in late 2025 or early 2026.
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 expected to commence in the fourth quarter of 2025.
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SPS
Pending and Recently Concluded Regulatory Proceedings
SPS 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 range from approximately 5,300 MW to 10,200 MW of nameplate capacity by 2030. In February 2024, the NMPRC accepted the IRP.
In July 2024, SPS issued a RFP, seeking approximately 3,200 MW of accredited 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.
In July 2025, the portfolio selection report was publicly filed with the NMPRC with 3,121 MW of accredited capacity resources, including the following:

Generation Resource Nameplate Capacity (in MW) | Company Owned | PPAs | Total
Wind Resources | 1,273 |  | — |  | 1,273 |
Solar | 695 |  | — |  | 695 |
Storage | 472 |  | 640 |  | 1,112 |
Natural Gas | 2,088 |  | — |  | 2,088 |
Total | 4,528 |  | 640 |  | 5,168 |

SPS filed or expects to file Certificate of Convenience and Necessity filings for the specific assets with the PUCT and NMPRC in 2025, with approvals expected in 2026.
In October 2025, SPS issued a second RFP to solicit 870 MW of accredited capacity (approximately 1,500 MW to 3,000 MW nameplate capacity) through 2032. Additional resources will be evaluated to meet the New Mexico Renewable Portfolio Standard compliance need. Bids are due in January 2026, and the portfolio is expected to be filed in the second half of 2026.
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. In October 2025, the NMPRC approved the request, resulting in a deferral of approximately $15 million of incremental excess liability insurance costs in 2025. A PUCT decision is expected in the first quarter of 2026.
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, Trade Complaints and Federal Actions
Several trade cases related to anti-dumping and countervailing duty investigations are ongoing and we continue to monitor the potential impacts of these cases.
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. Additionally, executive orders and actions from government agencies may impact the permitting of wind and solar facilities 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.
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.
Tax Law Changes
On July 4, 2025, the President signed into law Public Law No. 119-21 (the “OBBB”). The OBBB modifies certain clean energy tax provisions included in the Inflation Reduction Act. The provisions include:
•Eliminating production and investment tax credits for wind and solar facilities placed in service after 2027, for facilities that begin construction after July 4, 2026.
•The addition of foreign entity of concern rules that apply to projects commencing construction after 2025.
In August 2025, the U.S. Treasury issued further guidance related to the beginning of construction for clean energy projects.
Xcel Energy does not expect these provisions to have an impact on our 2026-2030 base capital plan, as steps have been taken to begin construction under the IRS’ safe harbor guidance.
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.
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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. In October 2025, Xcel Energy renewed its excess liability coverage for the same level with an annual premium of approximately $135 million. Xcel Energy has received approved deferrals in Colorado, Wisconsin and New Mexico and has filed for recovery through a deferral request or rate filings in other jurisdictions.
Nuclear Antitrust Class Action
A class action complaint was filed in federal court for the District of Maryland in July 2025, alleging violations of the Sherman Antitrust Act in establishing wages for employees at nuclear facilities since 2003. The complaint names 28 defendants, including all 26 owner operators of nuclear facilities in the United States, or affiliated entities, including Xcel Energy Inc. NSP-Minnesota owns and operates two nuclear facilities in Minnesota, and is assessing the complaint.

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

Throughout 2025, the EPA has announced various regulatory actions addressing a wide range of environmental regulations. Xcel Energy will continue to monitor these proposed rules as they move toward final action. Additionally, any other amendments and changes to rules will be evaluated as proposed by the EPA.
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.
In June 2025, the EPA proposed to repeal these and all other GHG emissions standards for the power sector. In the alternative, the EPA proposed to repeal a narrower subset of the 2024 regulations.
In July 2025, the EPA additionally proposed to repeal the 2009 Endangerment Finding and associated regulations addressing GHG emissions under the Clean Air Act. Xcel Energy will monitor the proposed rules and evaluate the impacts of any final rule.
In September 2025, the EPA proposed to amend the Clean Air Act GHG Reporting Program to scale back reporting and recordkeeping requirements. Under the amended program, Xcel Energy would no longer be required to report GHG emissions to the federal program. Xcel Energy will continue to report GHG emissions as required under state programs. Xcel Energy will monitor the proposed rule and evaluate the impacts of any final rule upon state reporting programs.
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.
Regional Haze — On July 16, 2025, EPA proposed to partially approve and partially disapprove the Colorado SIP implementing the Regional Haze rule in Colorado. The proposal seeks to remove mandatory retirement dates as enforceable provisions in the SIP. For PSCo, this includes the SIP retirement dates for Cherokee Unit 4, Comanche Unit 2, Craig Units 1 and 2, and Hayden Units 1 and 2. The comment period for the proposal has concluded, but the EPA has yet to make a final decision. If adopted, the removal of these retirement dates from the federally approved SIP would only impact federal requirements for retirement of these facilities. Colorado has a state regulation that incorporates these retirements at a state level and would require amendment to modify or remove the retirement dates.
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.
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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.
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 Sept. 30, 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) |  | $ | (10) |  |  | $ | (15) |  |  | $ | (4) |  |  | $ | (1) |  |  | $ | (30) |
NSP-Minnesota (b) |  | 1 |  |  | 1 |  |  | — |  |  | (3) |  |  | (1) |
PSCo (a) |  | — |  |  | 1 |  |  | — |  |  | — |  |  | 1 |
|  | $ | (9) |  |  | $ | (13) |  |  | $ | (4) |  |  | $ | (4) |  |  | $ | (30) |

|  | 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) |  | $ | — |  |  | $ | 6 |  |  | $ | 12 |  |  | $ | — |  |  | $ | 18 |
|  | $ | — |  |  | $ | 6 |  |  | $ | 12 |  |  | $ | — |  |  | $ | 18 |

(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 nine months ended Sept. 30:

(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 |  | (1) |  |  | 2 |
Commodity trading contract additions and changes during the period |  | (9) |  |  | (7) |
Fair value of commodity trading net contracts outstanding at Sept. 30 |  | $ | (12) |  |  | $ | (4) |

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 $2 million at Sept. 30, 2025 and Sept. 30, 2024.
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 Sept. 30 |  | Average |  | High |  | Low
2025 |  | $ | — |  |  | $ | — |  |  | $ | 1 |  |  | $ | — |
2024 |  | — |  |  | — |  |  | 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 $13 million and $1 million at Sept. 30, 2025 and 2024, respectively
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.
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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.
At Sept. 30, 2025, a 10% increase in commodity prices would have resulted in an increase in credit exposure of $33 million, while a decrease in prices of 10% would have resulted in a decrease in credit exposure of $32 million. At Sept. 30, 2024, a 10% increase in commodity prices would have resulted in an increase in credit exposure of $31 million, while a decrease in prices of 10% would have resulted in a decrease in credit exposure of $30 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) |  | Nine Months Ended Sept 30
Cash provided by operating activities — 2024 |  | $ | 3,977 |
Components of change — 2025 vs. 2024 |  |
Lower net income |  | (21) |
Non-cash transactions |  | 109 |
Changes in deferred income taxes |  | (11) |
Changes in working capital |  | 286 |
Changes in net regulatory and other assets and liabilities |  | (466) |
Cash provided by operating activities — 2025 |  | $ | 3,874 |

Net cash provided by operating activities decreased $103 million for the nine months ended Sept. 30, 2025 compared with the prior year. The decrease was largely due to the timing of regulatory recovery, including deferred net natural gas, fuel and purchased energy costs.
Investing Cash Flows

(Millions of Dollars) |  | Nine Months Ended Sept 30
Cash used in investing activities — 2024 |  | $ | (5,197) |
Components of change — 2025 vs. 2024 |  |
Increased capital expenditures |  | (2,323) |
Other investing activities |  | 28 |
Cash used in investing activities — 2025 |  | $ | (7,492) |

Net cash used in investing activities increased $2,295 million for the nine months ended Sept. 30, 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) |  | Nine Months Ended Sept 30
Cash provided by financing activities — 2024 |  | $ | 2,636 |
Components of change — 2025 vs. 2024 |  |
Higher net short-term debt proceeds |  | 1,325 |
Higher long-term debt issuances, net of repayments |  | 567 |
Higher proceeds from issuance of common stock |  | 42 |
Other financing activities |  | (79) |
Cash provided by financing activities — 2025 |  | $ | 4,491 |

Net cash provided by financing activities increased $1,855 million for the nine months ended Sept. 30, 2025 compared with the prior year. The increase was largely related to additional debt 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.
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As of Oct. 27, 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. |  | $ | 2,000 |  |  | $ | 620 |  |  | $ | 1,380 |  |  | $ | 16 |  |  | $ | 1,396 |
PSCo |  | 1,200 |  |  | 48 |  |  | 1,152 |  |  | 65 |  |  | 1,217 |
NSP-Minnesota |  | 800 |  |  | 44 |  |  | 756 |  |  | 13 |  |  | 769 |
SPS |  | 600 |  |  | — |  |  | 600 |  |  | 2 |  |  | 602 |
NSP-Wisconsin |  | 150 |  |  | — |  |  | 150 |  |  | 113 |  |  | 263 |
Total |  | $ | 4,750 |  |  | $ | 712 |  |  | $ | 4,038 |  |  | $ | 209 |  |  | $ | 4,247 |

(a)Credit facilities expire in December 2029.
(b)Includes outstanding commercial paper and letters of credit.
Short-Term Debt — Xcel Energy Inc., NSP-Minnesota, NSP-Wisconsin, PSCo and SPS each have individual commercial paper programs. As of Sept. 30, 2025, the authorized levels for these commercial paper programs are:
•$2 billion for Xcel Energy Inc.
•$1.2 billion for PSCo.
•$800 million for NSP-Minnesota.
•$600 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.
Capital Expenditures — Base capital expenditures for Xcel Energy for 2026 through 2030 are as follows:

|  | Base Capital Forecast (Millions of Dollars)
By Regulated Utility |  | 2026 |  | 2027 |  | 2028 |  | 2029 |  | 2030 |  | Total
NSP-Minnesota |  | $ | 3,740 |  |  | $ | 4,870 |  |  | $ | 4,210 |  |  | $ | 3,660 |  |  | $ | 3,650 |  |  | $ | 20,130 |
SPS |  | 3,050 |  |  | 5,120 |  |  | 5,350 |  |  | 3,240 |  |  | 2,270 |  |  | 19,030 |
PSCo |  | 5,980 |  |  | 3,940 |  |  | 2,960 |  |  | 1,760 |  |  | 2,960 |  |  | 17,600 |
NSP-Wisconsin |  | 910 |  |  | 1,210 |  |  | 760 |  |  | 570 |  |  | 580 |  |  | 4,030 |
Other (a) |  | 110 |  |  | (10) |  |  | (630) |  |  | (210) |  |  | (50) |  |  | (790) |
Total base capital expenditures |  | $ | 13,790 |  |  | $ | 15,130 |  |  | $ | 12,650 |  |  | $ | 9,020 |  |  | $ | 9,410 |  |  | $ | 60,000 |

(a)Other category includes intercompany transfers for equipment with long lead times.

|  | Base Capital Forecast (Millions of Dollars)
By Function |  | 2026 |  | 2027 |  | 2028 |  | 2029 |  | 2030 |  | Total
Electric transmission |  | $ | 3,060 |  |  | $ | 2,930 |  |  | $ | 2,890 |  |  | $ | 3,190 |  |  | $ | 3,370 |  |  | $ | 15,440 |
Renewables |  | 3,560 |  |  | 4,620 |  |  | 3,380 |  |  | 1,150 |  |  | 1,210 |  |  | 13,920 |
Electric distribution |  | 2,920 |  |  | 3,250 |  |  | 2,930 |  |  | 1,680 |  |  | 2,930 |  |  | 13,710 |
Electric generation |  | 2,220 |  |  | 2,420 |  |  | 2,500 |  |  | 1,810 |  |  | 590 |  |  | 9,540 |
Natural gas |  | 860 |  |  | 830 |  |  | 700 |  |  | 650 |  |  | 680 |  |  | 3,720 |
Other |  | 1,170 |  |  | 1,080 |  |  | 250 |  |  | 540 |  |  | 630 |  |  | 3,670 |
Total base capital expenditures |  | $ | 13,790 |  |  | $ | 15,130 |  |  | $ | 12,650 |  |  | $ | 9,020 |  |  | $ | 9,410 |  |  | $ | 60,000 |

The plan does not include any potential incremental generation from the current Colorado Near-Term Procurement and Resource Plan, additional future generation RFPs across jurisdictions to fund growth, or additional transmission investments that may come from future planning processes including MISO and SPP. Xcel Energy expects to fund additional capital investment with approximately 40% equity and 60% debt.
Xcel Energy’s capital expenditure forecast is subject to continuing review and modification. Actual capital expenditures may vary from estimates due to changes in electric and natural gas projected load growth, safety and reliability needs, regulatory decisions, legislative initiatives, tax policy, reserve requirements, availability of purchased power, alternative plans for meeting long-term energy needs, environmental initiatives and regulation, and merger, acquisition and divestiture opportunities.
Financing for Capital Expenditures through 2030 — Xcel Energy issues debt and equity securities to refinance retiring debt maturities, reduce short-term debt, fund capital programs, infuse equity in subsidiaries, fund asset acquisitions and for general corporate purposes. Current estimated financing plans of Xcel Energy for 2026-2030 (includes the impact of tax credit transferability):

(Millions of Dollars) |  |
Funding Capital Expenditures |  |
Cash from operations (a) |  | $ | 30,180 |
New debt (b) |  | 22,820 |
Equity issuances (c) |  | 7,000 |
Base capital expenditures 2026-2030 |  | $ | 60,000 |
Maturing debt |  | $ | 3,580 |

(a)Net of dividends and pension funding.
(b)Reflects a combination of short and long-term debt; net of refinancing.
(c)Amount could include other financing instruments that receive equity credit from the credit rating agencies.
2025 Financing Activity — Xcel Energy and its utility subsidiaries issued the following long-term debt:

Issuer |  | Security |  | Amount |  |  |  | Tenor |  | Coupon
Xcel Energy Inc. |  | Senior Unsecured Notes |  | $ | 1,100 | million |  |  |  | 3 Year & 10 Year |  | 4.75% & 5.60%
PSCo |  | First Mortgage Bonds |  | 1,000 | million |  |  |  | 9 Year & 30 Year |  | 5.35% & 5.85%
NSP-Minnesota |  | First Mortgage Bonds |  | 1,100 | million |  |  |  | 10 Year & 30 Year |  | 5.05% & 5.65%
SPS |  | First Mortgage Bonds |  | 500 | million |  |  |  | 10 Year |  | 5.30%
NSP-Wisconsin |  | First Mortgage Bonds |  | 250 | million |  |  |  | 29 Year |  | 5.65%
PSCo |  | First Mortgage Bonds |  | 1,000 | million |  |  |  | 10 Year & 30 Year |  | 5.15% & 5.85%
Xcel Energy Inc. (a) |  | Junior Subordinated Debt |  | 900 | million |  |  |  | 60 Year |  | 6.25%

(a)Junior subordinated debt was issued on Oct. 7, 2025.
Xcel Energy issued 16.4 million shares ($1.16 billion in net proceeds and $9 million in transaction fees paid) through its ATM programs in the nine months ended Sept. 30, 2025. Xcel Energy also entered forward equity agreements and collared forward equity agreements under these programs totaling 18.2 million shares, which have not been settled.
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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 be flat.
•Capital rider revenue is projected to increase $255 million to $265 million (net of PTCs).
•O&M expenses are projected to increase ~5%. The increase from prior guidance is primarily due to increasing benefit costs in the third quarter of 2025.
•Depreciation expense is projected to increase approximately $210 million to $220 million. The increase from prior guidance is largely earnings neutral and is offset by changes in electric fuel and purchased power.
•Property taxes are projected to increase $45 million to $55 million.
•Interest expense (net of AFUDC - debt) is projected to increase $160 million to $170 million, net of interest income. The increase from prior guidance is largely earnings neutral and is offset by changes in electric fuel and purchased power.
•AFUDC - equity is projected to increase $110 million to $120 million.
Xcel Energy 2026 Earnings Guidance — Xcel Energy’s 2026 ongoing earnings guidance is a range of $4.04 to $4.16 per share. (a)
Key assumptions as compared with 2025 actual levels unless noted:
•Constructive outcomes in all pending rate case and regulatory proceedings.
•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 $550 million to $560 million.
•O&M expenses are projected to increase ~3%.
•Depreciation expense is projected to increase approximately $370 million to $380 million.
•Property taxes are projected to increase $30 million to $40 million.
•Interest expense (net of AFUDC - debt) is projected to increase $290 million to $300 million, net of interest income.
•AFUDC - equity is projected to increase $140 million to $150 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 $3.80 per share (the mid-point of 2025 original ongoing earnings guidance of $3.75 to $3.85 per share).
• Deliver annual dividend increases of 4% to 6%.
• Target a dividend payout ratio of 45% to 55%.
• 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.”

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.
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As of Sept. 30, 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.
PART II — OTHER INFORMATION

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 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:
For the quarter ended Sept. 30, 2025, no equity securities that are registered by Xcel Energy Inc. pursuant to Section 12 of the Securities Exchange Act of 1934 were purchased by or on behalf of us or any of our affiliated purchasers.

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 Sept. 30, 2025.

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* | Junior Subordinated Indenture, dated as of October 1, 2025, by and between Xcel Energy Inc. and U.S. Bank Trust Company, National Association, as trustee. | Xcel Energy Inc. Form 8-K dated October 7, 2025 | 4.01
4.02* | Supplemental Indenture No. 1, dated as of October 7, 2025, by and between Xcel Energy Inc. and U.S. Bank Trust Company, National Association, as trustee, creating $900,000,000 aggregate principal amount of 6.25% Junior Subordinated Notes, Series due 2085. | Xcel Energy Inc. Form 8-K dated October 7, 2025 | 4.02
4.03* | Supplemental Indenture No. 37 dated as of August 1, 2025, between Public Service Company of Colorado and U.S. Bank Trust Company, National Association, as successor Trustee, creating $800,000,000 million principal amount of 5.15% First Mortgage Bonds, Series No. 44 due 2035. | PSCo Form 8-K dated August 7, 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.
October 30, 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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