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Xcel Energy
XEL
#481
Rank
C$70.03 B
Marketcap
๐Ÿ‡บ๐Ÿ‡ธ United States
Country
C$112.21
Share price
-0.45%
Change (1 day)
15.66%
Change (1 year)
๐Ÿ”‹ Electricity๐Ÿšฐ Utility companies โšก Energy
Categories
  1. Xcel Energy
  2. Quarterly Reports (10-Q)
  3. Submitted on 2026-04-30

Xcel Energy - 10-Q quarterly report FY


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Xcel Energy 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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One)
☒QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended March 31, 2026
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)
Minnesota41-0448030
(State or Other Jurisdiction of Incorporation or Organization)

(I.R.S. Employer Identification No.)
414 Nicollet Mall,Minneapolis,Minnesota55401
(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 classTrading Symbol(s)Name of each exchange on which registered
Common Stock, $2.50 par valueXELNasdaq Stock Market LLC
6.25% Junior Subordinated Notes due 2085XELLLNasdaq 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.
ClassOutstanding at April. 28, 2026
Common Stock, $2.50 par value624,269,560 shares


TABLE OF CONTENTS
PART IFINANCIAL INFORMATION
Item 1 —
5
5
6
7
8
9
10
Item 2 —
22
Item 3 —
32
Item 4 —
32
PART IIOTHER INFORMATION
Item 1 —
32
Item 1A —
32
Item 2 —
33
Item 5 —
33
Item 6 —
33
34
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)
NSP-MinnesotaNorthern States Power Company, a Minnesota corporation
NSP SystemThe electric production and transmission system of NSP-Minnesota and NSP-Wisconsin operated on an integrated basis and managed by NSP-Minnesota
NSP-WisconsinNorthern States Power Company, a Wisconsin corporation
PSCoPublic Service Company of Colorado
SPSSouthwestern Public Service Company
Utility subsidiariesNSP-Minnesota, NSP-Wisconsin, PSCo and SPS
WYCOWYCO Development, LLC
Xcel EnergyXcel Energy Inc. and its subsidiaries
Federal and State Regulatory Agencies
CPUCColorado Public Utilities Commission
EPAUnited States Environmental Protection Agency
FASBFinancial Accounting Standards Board
FERCFederal Energy Regulatory Commission
MPSCMichigan Public Service Commission
MPUCMinnesota Public Utilities Commission
NDPSCNorth Dakota Public Service Commission
NMPRCNew Mexico Public Regulation Commission
NRCNuclear Regulatory Commission
PSCWPublic Service Commission of Wisconsin
PUCTPublic Utility Commission of Texas
SECSecurities and Exchange Commission
SDPUCSouth Dakota Public Utilities Commission
Other
AFUDCAllowance for funds used during construction
ALJAdministrative Law Judge
ASUAccounting standards update
ATMAt-the-market
C&ICommercial and Industrial
CCRCoal combustion residuals
CCR RuleFinal rule (40 CFR 257.50 - 257.107) published by EPA regulating the management, storage and disposal of CCRs as a nonhazardous waste
CDDCooling degree-days
CECColorado Energy Consumers
CEOChief executive officer
CERCLAComprehensive Environmental Response, Compensation, and Liability Act
CFOChief financial officer
CO2
Carbon dioxide
CUBCitizens Utility Board
DOCMinnesota Department of Commerce
DRIPDividend Reinvestment and Stock Purchase Program
DSMDemand side management
EPSEarnings per share
FEAFederal Executive Agencies
FTRFinancial transmission right
GAAPUnited States generally accepted accounting principles
GHGGreenhouse Gas
HDDHeating degree-days
IPPIndependent power producing entity
IRPIntegrated Resource Plan
LLCLimited liability company
MGPManufactured gas plant
MISOMidcontinent Independent System Operator, Inc.
NAVNet asset value
NOxNitrogen Oxides
O&MOperating and maintenance
OAG
Office of the Minnesota Attorney General
PFASPer- and Polyfluoroalkyl Substances
PPAPower purchase agreement
PTCProduction tax credit
RFPRequest for proposal
ROEReturn on equity
ROURight-of-use
RTORegional Transmission Organization
SIPState implementation plan
SPPSouthwest Power Pool, Inc.
THITemperature-humidity index
UCAColorado Office of the Utility Consumer Advocate
VaRValue at Risk
VIEVariable interest entity
XLIXcel Large Industrials
Measurements
MMbtu
Million British Thermal Units
MWMegawatts
MWhMegawatt hours

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 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, 2025 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; risks associated with wildfires; commodity risks associated with energy markets and production; rising energy prices and fuel costs; qualified employee workforce and third-party contractor factors; reputational impacts of actions by employees, directors, or third-parties; our ability to recover costs and our subsidiaries’ ability to recover costs from customers; risks associated with the growth in large load 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.
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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 March 31
20262025
Operating revenues
Electric$2,976 $2,835 
Natural gas1,030 1,055 
Other15 16 
Total operating revenues4,021 3,906 
Operating expenses
Electric fuel and purchased power1,019 1,020 
Cost of natural gas sold and transported520 513 
Cost of sales — other3 2 
Operating and maintenance expenses675 686 
Conservation and demand side management expenses121 110 
Depreciation and amortization768 728 
Taxes (other than income taxes)183 170 
Marshall Wildfire litigation (22)— 
Total operating expenses3,267 3,229 
Operating income754 677 
Other income, net22 7 
Earnings (loss) from equity method investments13 (1)
Allowance for funds used during construction — equity92 48 
Interest charges and financing costs
Interest charges — includes other financing costs 412 332 
Allowance for funds used during construction — debt(40)(23)
Total interest charges and financing costs372 309 
Income before income taxes509 422 
Income tax benefit(47)(61)
Net income$556 $483 
Weighted average common shares outstanding:
Basic624 575 
Diluted626 577 
Earnings per average common share:
Basic$0.89 $0.84 
Diluted0.89 0.84 
See Notes to Consolidated Financial Statements

5
XCEL ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
(amounts in millions)
Three Months Ended March 31
20262025
Net income$556 $483 
Other comprehensive income
Derivative instruments:
Net fair value increase (decrease), net of tax3 (5)
Reclassification of losses to net income, net of tax1 1 
Total other comprehensive income (loss)4 (4)
Total comprehensive income$560 $479 
See Notes to Consolidated Financial Statements



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XCEL ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
(amounts in millions)
 Three Months Ended March 31
 20262025
Operating activities
Net income$556 $483 
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization767 734 
Nuclear fuel amortization27 29 
Deferred income taxes(5)13 
Allowance for equity funds used during construction(92)(48)
(Earnings) loss from equity method investments(13)1 
Dividends from equity method investments7 8 
Provision for bad debts13 19 
Share-based compensation expense11 9 
Changes in operating assets and liabilities:
Accounts receivable(30)(58)
Accrued unbilled revenues134 63 
Inventories2 (4)
Other current assets415 (18)
Accounts payable(191)(105)
Net regulatory assets and liabilities87 25 
Other current liabilities110 29 
Pension and other employee benefit obligations(77)(124)
Other, net(24)(28)
Net cash provided by operating activities1,697 1,028 
Investing activities
Capital/construction expenditures(3,022)(1,988)
Purchase of investment securities(763)(241)
Proceeds from the sale of investment securities763 240 
Other, net3 (2)
Net cash used in investing activities(3,019)(1,991)
Financing activities
(Repayments) proceeds from short-term borrowings, net(70)24 
Proceeds from issuances of long-term debt3,259 2,077 
Proceeds from issuance of common stock1 122 
Dividends paid(347)(306)
Other, net(35)(10)
Net cash provided by financing activities2,808 1,907 
Net change in cash, cash equivalents and restricted cash1,486 944 
Cash, cash equivalents and restricted cash at beginning of period274 179 
Cash, cash equivalents and restricted cash at end of period$1,760 $1,123 
Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized)$(283)$(252)
Supplemental disclosure of non-cash investing and financing transactions:
Accrued property, plant and equipment additions$1,315 $891 
Inventory transfers to property, plant and equipment59 61 
Operating lease and finance lease right-of-use assets48 55 
Allowance for equity funds used during construction92 48 
Issuance of common stock for reinvested dividends and/or equity awards18 18 
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
March 31, 2026Dec. 31, 2025
Assets
Current assets
Cash and cash equivalents$1,760 $274 
Accounts receivable, net1,346 1,330 
Accrued unbilled revenues746 880 
Inventories709 761 
Regulatory assets482 529 
Derivative instruments138 165 
Prepayments and other701 1,075 
Total current assets5,882 5,014 
Property, plant and equipment, net67,808 65,639 
Other assets
Nuclear decommissioning fund and other investments4,336 4,389 
Regulatory assets3,020 2,998 
Derivative instruments66 54 
Operating lease right-of-use assets868 893 
Finance lease right-of-use assets1,431 1,348 
Other1,417 1,036 
Total other assets11,138 10,718 
Total assets$84,828 $81,371 
Liabilities and Equity
Current liabilities
Current portion of long-term debt$1,001 $501 
Short-term debt1,480 1,550 
Accounts payable2,261 2,307 
Regulatory liabilities701 714 
Taxes accrued697 579 
Accrued interest419 337 
Dividends payable370 355 
Derivative instruments20 31 
Operating lease liabilities111 110 
Other576 605 
Total current liabilities7,636 7,089 
Deferred credits and other liabilities
Deferred income taxes5,918 6,004 
Regulatory liabilities6,387 6,277 
Asset retirement obligations3,937 3,888 
Derivative instruments56 67 
Customer advances128 129 
Pension and employee benefit obligations289 365 
Operating lease liabilities761 788 
Finance lease liabilities1,298 1,262 
Other60 61 
Total deferred credits and other liabilities18,834 18,841 
Commitments and contingencies
Capitalization
Long-term debt34,552 31,832 
Common stock — 1,000,000,000 shares authorized of $2.50 par value; 624,162,780 and 623,600,715 shares outstanding at March 31, 2026 and December 31, 2025, respectively
1,560 1,559 
Additional paid in capital12,914 12,906 
Retained earnings9,391 9,207 
Accumulated other comprehensive loss(59)(63)
Total common stockholders’ equity23,806 23,609 
Total liabilities and equity$84,828 $81,371 
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 IssuedRetained EarningsAccumulated Other Comprehensive Loss Total Common Stockholders' Equity
SharesPar ValueAdditional Paid
In Capital
Three Months Ended March 31, 2026 and 2025
Balance at Dec. 31, 2024574,365,598 $1,436 $9,601 $8,553 $(68)$19,522 
Net income483 483 
Other comprehensive loss(4)(4)
Dividends declared on common stock ($0.57 per share)
(328)(328)
Issuances of common stock2,181,453 5 117 122 
Share-based compensation11 (2)9 
Balance at March 31, 2025576,547,051 $1,441 $9,729 $8,706 $(72)$19,804 
Balance at Dec. 31, 2025623,600,715 $1,559 $12,906 $9,207 $(63)$23,609 
Net income556 556 
Other comprehensive income4 4 
Dividends declared on common stock ($0.59 per share)
(370)(370)
Issuances of common stock562,065 1 10 11 
Share-based compensation(2)(2)(4)
Balance at March 31, 2026624,162,780 $1,560 $12,914 $9,391 $(59)$23,806 
See Notes to Consolidated Financial Statements

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XCEL ENERGY INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements (UNAUDITED)
In the opinion of management, the accompanying unaudited consolidated financial statements contain all adjustments necessary to present fairly, in accordance with GAAP, the financial position of Xcel Energy as of March 31, 2026 and Dec. 31, 2025; the results of Xcel Energy’s operations, including the components of net income, comprehensive income, cash flows and changes in stockholders’ equity for the three months ended March 31, 2026 and 2025.
All adjustments are of a normal, recurring nature, except as otherwise disclosed. Management has also evaluated the impact of events occurring after March 31, 2026, 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, 2025 balance sheet information has been derived from the audited 2025 consolidated financial statements included in the Xcel Energy Inc. Annual Report on Form 10-K for the year ended Dec. 31, 2025.
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, 2025, filed with the SEC on Feb. 25, 2026.
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, 2025 appropriately represent, in all material respects, the current status of accounting policies and are incorporated herein by reference.
2. Accounting Pronouncements
Recently Issued
Disaggregation of Income Statement Expenses — In November 2024, the FASB issued ASU 2024-03 – Expense Disaggregation Disclosures (Subtopic 220-40), which requires disclosure of additional detail for certain categories of income statement expenses. The ASU is effective for annual reporting periods beginning after Dec. 15, 2026 and interim reporting periods beginning after Dec. 15, 2027. Xcel Energy is evaluating the impact of the new disclosure guidance.
3. Selected Balance Sheet Data
(Millions of Dollars)March 31, 2026Dec. 31, 2025
Accounts receivable, net
Accounts receivable$1,429 $1,419 
Less allowance for bad debts(83)(89)
Accounts receivable, net$1,346 $1,330 
(Millions of Dollars)March 31, 2026Dec. 31, 2025
Inventories
Materials and supplies$501 $489 
Fuel147 156 
Natural gas61 116 
Total inventories$709 $761 
(Millions of Dollars)March 31, 2026Dec. 31, 2025
Property, plant and equipment, net
Electric plant$63,127 $61,892 
Natural gas plant10,663 10,517 
Common and other property3,815 3,790 
Plant to be retired (a)
1,547 1,595 
Construction work in progress9,440 8,085 
Total property, plant and equipment88,592 85,879 
Less accumulated depreciation(21,242)(20,710)
Nuclear fuel3,693 3,678 
Less accumulated amortization(3,235)(3,208)
Property, plant and equipment, net$67,808 $65,639 
(a)Amounts include Sherco Units 1 & 3 and A.S. King for NSP-Minnesota; Comanche Unit 3, Craig Unit 2, Hayden Units 1 and 2 for PSCo; and Tolk Unit 1 and 2 for SPS. Amounts are presented net of accumulated depreciation.
4. Borrowings and Other Financing Instruments
Short-Term Borrowings
Short-Term Debt — Xcel Energy Inc. and its utility subsidiaries meet their short-term liquidity requirements primarily through the issuance of commercial paper and borrowings under their credit facilities and term loan agreements.
Commercial paper and term loan borrowings outstanding for Xcel Energy:
(Amounts in Millions, Except Interest Rates)Three Months Ended March 31, 2026Year Ended Dec. 31, 2025
Borrowing limit$6,250 $4,750 
Amount outstanding at period end1,480 1,550 
Average amount outstanding2,014 1,026 
Maximum amount outstanding2,419 2,965 
Weighted average interest rate, computed on a daily basis4.05 %4.41 %
Weighted average interest rate at period end4.31 3.95 
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.
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As of March 31, 2026, 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 $675 $1,325 
PSCo1,200 48 1,152 
NSP-Minnesota800 44 756 
SPS600 55 545 
NSP-Wisconsin150 — 150 
Total$4,750 $822 $3,928 
(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 March 31, 2026 and Dec. 31, 2025.
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 were $92 million of letters of credit outstanding under the credit facilities at both March 31, 2026 and Dec. 31, 2025. Amounts approximate their fair value and are subject to fees.
Additionally, in March 2026, NSP-Minnesota, PSCo and SPS each entered into an uncommitted letter of credit agreement with overall limits of $50 million, $50 million and $150 million, respectively, to provide additional letter of credit capacity outside of the revolving credit facilities. As of March 31, 2026, no letters of credit were outstanding under these continuing letter of credit agreements.
Bilateral Credit Agreement — In April 2026, NSP-Minnesota’s uncommitted bilateral credit agreement was renewed for an additional one-year term. The credit agreement is limited in use to support letters of credit.
As of March 31, 2026 and Dec. 31, 2025, NSP-Minnesota had $69 million of outstanding letters of credit under the $75 million bilateral credit agreement.
Term Loan Agreement — In January 2026, Xcel Energy Inc. entered into a $1.5 billion, 364-Day Delayed Draw Term Loan Agreement. The loan is unsecured and matures Jan. 30, 2027. The term loan includes one financial covenant, requiring Xcel Energy’s consolidated funded debt to total capitalization ratio to be less than or equal to 70 percent. Interest is at a rate equal to the Term SOFR rate, plus 85.0 basis points, or an alternate base rate. As of March 31, 2026 there was $750 million outstanding under the term loan facility.
Long-Term Borrowings and Other Financing Instruments
During the three months ended March 31, 2026, Xcel Energy Inc. and its utility subsidiaries issued the following:
•Xcel Energy Inc. issued $800 million in aggregate principal amount of 5.75% Fixed-to-Fixed Reset Rate Junior Subordinated Notes, Series due 2056.
•PSCo issued $700 million in aggregate principal amount of 4.15% First Mortgage Bonds, Series No. 45 due March 13, 2029 and $600 million in aggregate principal amount of 5.05% First Mortgage Bonds, Series No. 46 due June 15, 2036.
•NSP-Minnesota issued $600 million in aggregate principal amount of 4.85% First Mortgage Bonds due May 15, 2036 and $600 million in aggregate principal amount of 5.55% First Mortgage Bonds due May 15, 2056.
On April 1, 2026, NSP-Wisconsin priced a private placement of $250 million of 5.48% first mortgage bonds due June 15, 2041. The closing of the sale of the bonds is subject to execution of a bond purchase agreement and customary closing conditions and is expected to occur in June 2026.
ATM Equity Offerings — 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 Sale Agreements — Xcel Energy Inc. has entered into multiple forward sale agreements in 2026 and 2025 in connection with completed public offerings of Xcel Energy common stock.
The following forward sale agreements remain outstanding as of March 31, 2026:
Agreements EnteredCommon Shares (in millions)Final Maturity
Minimum Expected Proceeds (millions of dollars)
2025 forward equity agreements (a)
12.2
Dec. 2026 to May 2027 (b)
$932 
(c)
2025 collared forward equity agreements (a)
15.1Dec. 20261,044 
(d)
2026 forward equity agreements (a)
13.6
Dec. 2027 to Dec. 2028 (b)
1,098 
(c)
(a)Entered under the 2025 ATM prospectus supplement.
(b)Final maturity date varies by agreement. Xcel Energy may settle the agreements at any time until final maturity.
(c)Actual cash proceeds will be impacted by the timing of settlement. Forward prices are based on the public offering price (net of underwriting fees), increased for the overnight bank funding rate, less a spread and less expected dividends on Xcel Energy’s common stock during the period the agreements are outstanding.
(d)Pricing for the physical delivery of common shares will be based on an average market price for Xcel Energy’s common stock during a period preceding settlement in December 2026, subject to a cap price and floor price derived from the September 2025 and December 2025 public offerings.
If settled in physical shares, stockholders’ equity equal to cash proceeds will be recorded at settlement.
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The 2025 collared forward equity agreements cannot be settled until December 2026, and net cash settlement and net share settlement are generally unavailable. The 2025 and 2026 forward equity agreements could have been settled at March 31, 2026 with physical delivery of common shares to the banking counterparties in exchange for cash; if Xcel Energy unilaterally elected net cash or net share settlement, these agreements also could have been settled with cash or shares of common stock, as follows:
Pro-Forma/Hypothetical Transactions
Agreements EnteredNet Settlement proceeds (payments):Physical Share Delivery Proceeds (millions of dollars)
Common Shares (in millions)Net Cash (millions of dollars)
2025 forward equity agreements(0.5)$(44)$934 
2026 forward equity agreements0.2 14 1,099 
Equity through DRIP and Benefits Program — Xcel Energy issued $45 million and $30 million of equity through the DRIP and benefits programs during the three months ended March 31, 2026 and 2025, 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 three months ended March 31, 2026, Xcel Energy Inc. purchased $48 million in aggregate principal amounts of NSP-Minnesota’s 3.60% First Mortgage Bonds Series due Sept. 15, 2047, 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 $31 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 $15 million, net of unamortized discount and debt issuance costs.

5. Revenues
Revenue is classified by the type of goods/services rendered and market/customer type. Xcel Energy’s operating revenues consisted of the following:
Three Months Ended March 31, 2026
(Millions of Dollars)ElectricNatural GasAll OtherTotal
Major revenue types
Revenue from contracts with customers:
Residential$904 $612 $1 $1,517 
C&I1,392 334 9 1,735 
Other35 — 2 37 
Total retail2,331 946 12 3,289 
Wholesale217 — — 217 
Transmission186 — — 186 
Other12 50 — 62 
Total revenue from contracts with customers2,746 996 12 3,754 
Alternative revenue and other230 34 3 267 
Total revenues$2,976 $1,030 $15 $4,021 
Three Months Ended March 31, 2025
(Millions of Dollars)ElectricNatural GasAll OtherTotal
Major revenue types
Revenue from contracts with customers:
Residential$924 $632 $1 $1,557 
C&I1,333 320 10 1,663 
Other35 — 2 37 
Total retail2,292 952 13 3,257 
Wholesale206 — — 206 
Transmission172 — — 172 
Other17 51 — 68 
Total revenue from contracts with customers2,687 1,003 13 3,703 
Alternative revenue and other148 52 3 203 
Total revenues$2,835 $1,055 $16 $3,906 

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6. Income Taxes
Total income tax expense from operations differs from the amount computed by applying the statutory federal income tax rate to income before income tax expense.
Effective income tax reconciliation:
Three Months Ended March 31
(Millions of Dollars)20262025
Income before income taxes (domestic)$509 $422 
Federal statutory rate impact107 89 
(Decreases) increases in tax from:
Tax credits
PTCs (a)
(141)(139)
Other(3)(4)
Regulatory adjustments (b)
AFUDC equity(17)(13)
Plant related excess deferred taxes(15)(14)
Other4 4 
State income taxes, net of federal tax effect (c)
22 14 
Other(4)2 
Income tax benefit$(47)$(61)
Three Months Ended March 31
20262025
Federal statutory rate21.0 %21.0 %
(Decreases) increases in tax from:
Tax credits
PTCs (a)
(27.8)(33.1)
Other(0.7)(1.0)
Regulatory adjustments (b)
AFUDC equity(3.4)(3.0)
Plant related excess deferred taxes(2.9)(3.2)
Other0.8 0.8 
State income taxes, net of federal tax effect (c)
4.3 3.3 
Other(0.5)0.7 
Effective income tax rate(9.2)%(14.5)%
(a)Wind and Solar PTCs (net of transfer discounts) are generally credited to customers (reduction to revenue) and do not materially impact earnings.
(b)Regulatory adjustments primarily relate to the credit of plant related excess deferred taxes to customers for tax rate increases as well as the capitalization of AFUDC equity for book purposes only. Income tax benefits associated with the credit of excess deferred taxes are offset by corresponding revenue reductions.
(c)State and local income taxes are primarily made up of the following jurisdictions: Minnesota, Colorado
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 March 31
(Shares in Millions)20262025
Basic 624 575 
Diluted (a)
626 577 
(a)Diluted common shares outstanding included common stock equivalents of 2.0 million and 1.4 million for the three months ended March 31, 2026 and 2025, 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.
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Investments in debt securities — Fair values for debt securities are determined by a third party pricing service using recent trades and observable spreads from benchmark interest rates for similar securities.
Interest rate derivatives — Fair values of interest rate derivatives are based on broker quotes that utilize current market interest rate forecasts.
Commodity derivatives — Methods used to measure the fair value of commodity derivative forwards and options utilize forward prices and volatilities, as well as pricing adjustments for specific delivery locations, and are generally assigned a Level 2 classification. When contracts relate to inactive delivery locations or extend to periods beyond those readily observable on active exchanges, the significance of the use of less observable inputs on a valuation is evaluated and may result in Level 3 classification.
Electric commodity derivatives held by NSP-Minnesota and SPS include transmission congestion instruments, generally referred to as FTRs. FTRs purchased from an RTO are financial instruments that entitle or obligate the holder to monthly revenues or charges based on transmission congestion across a given transmission path.
The values of these instruments are derived from, and designed to offset, the costs of transmission congestion. In addition to overall transmission load, congestion is also influenced by the operating schedules of power plants and the consumption of electricity pertinent to a given transmission path. Unplanned plant outages, scheduled plant maintenance, changes in the relative costs of fuels used in generation, weather and overall changes in demand for electricity can each impact the operating schedules of the power plants on the transmission grid and the value of these instruments.
FTRs are recognized at fair value and adjusted each period prior to settlement. Given the limited observability of certain variables underlying the reported auction values of FTRs, these fair value measurements have been assigned a Level 3 classification.
Net congestion costs, including the impact of FTR settlements, are shared through fuel and purchased energy cost recovery mechanisms. As such, the fair value of the unsettled instruments (i.e., derivative asset or liability) is offset/deferred as a regulatory asset or liability.
Non-Derivative Fair Value Measurements
Nuclear Decommissioning Fund
The NRC requires NSP-Minnesota to maintain a portfolio of investments to fund the costs of decommissioning its nuclear generating plants. Assets of the nuclear decommissioning fund are legally restricted for the purpose of decommissioning these facilities. The fund contains cash equivalents, debt securities, equity securities and other investments. NSP-Minnesota uses the MPUC approved asset allocation for the investment targets by asset class for the qualified trust.
NSP-Minnesota recognizes the costs of funding the decommissioning over the lives of the nuclear plants, assuming rate recovery of all costs. Realized and unrealized gains on fund investments over the life of the fund are deferred as an offset of NSP-Minnesota’s regulatory asset or as a regulatory liability (dependent on funding status) for nuclear decommissioning costs. Consequently, any realized and unrealized gains and losses on securities in the nuclear decommissioning fund are deferred as a component of the regulatory asset/liability.
Unrealized gains for the nuclear decommissioning fund were $1.7 billion and $1.8 billion as of March 31, 2026 and Dec. 31, 2025, respectively, and unrealized losses were $48 million and $47 million as of March 31, 2026 and Dec. 31, 2025, respectively.
Non-derivative instruments with recurring fair value measurements in the nuclear decommissioning fund:
March 31, 2026
Fair Value
(Millions of Dollars)CostLevel 1Level 2Level 3NAVTotal
Nuclear decommissioning fund (a)
Cash equivalents$54 $54 $— $— $— $54 
Commingled funds722 — — — 1,074 1,074 
Debt securities988 — 971 11 — 982 
Equity securities497 1,788 1 — — 1,789 
Total$2,261 $1,842 $972 $11 $1,074 $3,899 
(a)Reported in nuclear decommissioning fund and other investments on the consolidated balance sheets, which also includes $272 million of equity method investments and $165 million of rabbi trust assets and other miscellaneous investments.
Dec. 31, 2025
Fair Value
(Millions of Dollars)CostLevel 1Level 2Level 3NAVTotal
Nuclear decommissioning fund (a)
Cash equivalents$60 $60 $— $— $— $60 
Commingled funds720 — — — 1,072 1,072 
Debt securities944 — 934 11 — 945 
Equity securities505 1,861 2 — — 1,863 
Total$2,229 $1,921 $936 $11 $1,072 $3,940 
(a)Reported in nuclear decommissioning fund and other investments on the consolidated balance sheets, which also includes $285 million of equity method investments and $164 million of rabbi trust assets and other miscellaneous investments.
For the three months ended March 31, 2026 and 2025, there were no transfers of Level 3 investments between levels.
Contractual maturity dates of debt securities in the nuclear decommissioning fund as of March 31, 2026:
Final Contractual Maturity
(Millions of Dollars)Due in 1 Year or LessDue in 1 to 5 YearsDue in 5 to 10 YearsDue after 10 YearsTotal
Debt securities$8 $440 $339 $195 $982 
Rabbi Trusts
Xcel Energy has established rabbi trusts to provide partial funding for future deferred compensation plan distributions. The fair value of assets held in the rabbi trusts were $107 million at both March 31, 2026 and Dec. 31, 2025, comprised of cash equivalents and mutual funds (level 1 valuation methods). Amounts are reported in nuclear decommissioning fund and other investments on the consolidated balance sheet.
Derivative Activities and Fair Value Measurements
Xcel Energy enters into derivative instruments, including forward contracts, futures, swaps and options, for trading purposes and to manage risk in connection with changes in interest rates, and utility commodity prices.
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Interest Rate Derivatives — Xcel Energy enters into contracts that effectively fix the interest rate on a specified principal amount of a hypothetical future debt issuance. These financial swaps net settle based on changes in a specified benchmark interest rate, acting as a hedge of changes in market interest rates that will impact specified anticipated debt issuances. These derivative instruments are designated as cash flow hedges for accounting purposes, with changes in fair value prior to occurrence of the hedged transactions recorded as other comprehensive income.
As of March 31, 2026, accumulated other comprehensive loss related to interest rate derivatives included $3 million of net losses expected to be reclassified into earnings during the next 12 months as the hedged transactions impact earnings. As of March 31, 2026, Xcel Energy had unsettled interest rate derivatives with a notional amount of $130 million.
See Note 11 for the financial impact of qualifying interest rate cash flow hedges on Xcel Energy’s accumulated other comprehensive loss included in the consolidated statements of common stockholder’s equity and in the consolidated statements of comprehensive income.
Wholesale and Commodity Trading — Xcel Energy Inc.’s utility subsidiaries conduct various wholesale and commodity trading activities, including the purchase and sale of electric capacity, energy, energy-related instruments and natural gas-related instruments, including derivatives. Xcel Energy is allowed to conduct these activities within guidelines and limitations as approved by its risk management committee, comprised of management personnel not directly involved in the activities governed by this policy.
Results of derivative instrument transactions entered into for trading purposes are presented in the consolidated statements of income as electric revenues, net of any sharing with customers. These activities are not intended to mitigate commodity price risk associated with regulated electric and natural gas operations. Sharing of these margins is determined through state regulatory proceedings as well as the operation of the FERC-approved joint operating agreement.
Commodity Derivatives — Xcel Energy enters into derivative instruments to manage variability of future cash flows from changes in commodity prices in its electric and natural gas operations. This could include the purchase or sale of energy or energy-related products, natural gas to generate electric energy, natural gas for resale and FTRs.
The most significant derivative positions outstanding at March 31, 2026 and Dec. 31, 2025 for this purpose relate to FTR instruments administered by MISO and SPP. These instruments are intended to offset the impacts of transmission system congestion.
When Xcel Energy enters into derivative instruments that mitigate commodity price risk on behalf of electric and natural gas customers, the instruments are not typically designated as qualifying hedging transactions. The classification of unrealized losses or gains on these instruments as a regulatory asset or liability, if applicable, is based on approved regulatory recovery mechanisms.
As of March 31, 2026, Xcel Energy had no commodity contracts designated as cash flow hedges.
Gross notional amounts of commodity forwards, options and FTRs:
(Amounts in Millions) (a)(b)
March 31, 2026Dec. 31, 2025
MWh of electricity28 35 
MMBtu of natural gas40 31 
(a)Not reflective of net positions in the underlying commodities.
(b)Notional amounts for options included on a gross basis but weighted for the probability of exercise.
Consideration of Credit Risk and Concentrations — Xcel Energy continuously monitors the creditworthiness of counterparties to its interest rate derivatives and commodity derivative contracts prior to settlement and assesses each counterparty’s ability to perform on the transactions set forth in the contracts. Impact of credit risk was immaterial to the fair value of unsettled commodity derivatives presented on the consolidated balance sheets.
Xcel Energy’s utility subsidiaries’ often have significant concentrations of credit risk with particular entities or industries in their wholesale, trading and non-trading commodity activities.
As of March 31, 2026, three of Xcel Energy’s ten most significant counterparties for these activities, comprising $27 million, or 20%, of this credit exposure, had investment grade credit ratings from S&P Global Ratings, Moody’s Investor Services or Fitch Ratings.
Six of the ten most significant counterparties, comprising $69 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 $14 million, or 10%, of this credit exposure, had credit quality less than investment grade, based on internal analysis.
Nine of these significant counterparties are municipal or cooperative electric entities, RTOs or other utilities.
Credit Related Contingent Features — Contract provisions for derivative instruments that the utility subsidiaries enter, including those accounted for as normal purchase and normal sale contracts and therefore not reflected on the consolidated balance sheets, may require the posting of collateral or settlement of the contracts for various reasons, including if the applicable utility subsidiary’s credit ratings are downgraded below its investment grade credit rating by any of the major credit rating agencies.
As of March 31, 2026 and Dec. 31, 2025, there were $4 million and $7 million of derivative liabilities with such underlying contract provisions.
Certain contracts also contain cross default provisions that may require the posting of collateral or settlement of the contracts if there was a failure under other financing arrangements related to payment terms or other covenants.
As of March 31, 2026 and Dec. 31, 2025, there were approximately $42 million and $62 million of derivative liabilities with such underlying contract provisions, respectively.
Certain derivative instruments are also subject to contract provisions that contain adequate assurance clauses. These provisions allow counterparties to seek performance assurance, including cash collateral, in the event that a given utility subsidiary’s ability to fulfill its contractual obligations is reasonably expected to be impaired.
Xcel Energy had no collateral posted related to adequate assurance clauses in derivative contracts as of March 31, 2026 and Dec. 31, 2025, respectively.
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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 LossRegulatory Assets and Liabilities
Three Months Ended March 31, 2026
Derivatives designated as cash flow hedges:
Interest rate$4 $— 
Total$4 $— 
Other derivative instruments:
Electric commodity$— $(14)
Natural gas commodity— 10 
Total$— $(4)
Three Months Ended March 31, 2025
Derivatives designated as cash flow hedges:
Interest rate$(4)$— 
Total$(4)$— 
Other derivative instruments:
Electric commodity$— $5 
Natural gas commodity— 7 
Total$— $12 


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 LossRegulatory Assets and Liabilities
Three Months Ended March 31, 2026
Derivatives designated as cash flow hedges:
Interest rate$1 
(a)
$— $— 
Total$1 $— $— 
Other derivative instruments:
Commodity trading$— $— $4 
(b)
Electric commodity— (25)
(c)
— 
Natural gas commodity— — 

(14)
(d)(e)
Total$— $(25)$(10)
Three Months Ended March 31, 2025
Derivatives designated as cash flow hedges:
Interest rate$1 
(a)
$— $— 
Total$1 $— $— 
Other derivative instruments:
Commodity trading$— $— $(13)
(b)
Electric commodity— (5)
(c)
— 
Natural gas commodity— — (13)
(d)(e)
Total$— $(5)$(26)
(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 $2 million of 2026 and 2025 losses recorded to electric fuel and purchased power, amounts are recorded to cost of natural gas sold and transported. Amounts are subject to cost-recovery mechanisms and reclassified out of income to a regulatory asset, as appropriate.
(e)Relates primarily to option premium amortization.
Xcel Energy had no derivative instruments designated as fair value hedges during the three months ended March 31, 2026 and 2025.
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Derivative assets and liabilities measured at fair value on a recurring basis were as follows:
March 31, 2026Dec. 31, 2025
Fair ValueFair Value Total
Netting (a)
TotalFair ValueFair Value Total
Netting (a)
Total
(Millions of Dollars)Level 1Level 2Level 3Level 1Level 2Level 3
Current derivative assets
Derivatives designated as cash flow hedges:
Interest rate$— $4 $— $4 $— $4 $— $1 $— $1 $— $1 
Other derivative instruments:
Commodity trading$3 $9 $4 $16 $(12)$4 $2 $13 $7 $22 $(16)$6 
Electric commodity— — 131 131 (1)130 — — 147 147 (3)144 
Natural gas commodity— — — — — — — 14 — 14 — 14 
Total current derivative assets$3 $13 $135 $151 $(13)$138 $2 $28 $154 $184 $(19)$165 
Noncurrent derivative assets
Other derivative instruments:
Commodity trading$3 $25 $25 $53 $(7)$46 $3 $28 $34 $65 $(11)$54 
Electric commodity— — 20 20 — 20 — — — — — — 
Total noncurrent derivative assets$3 $25 $45 $73 $(7)$66 $3 $28 $34 $65 $(11)$54 
March 31, 2026Dec. 31, 2025
Fair ValueFair Value Total
Netting (a)
TotalFair ValueFair Value Total
Netting (a)
Total
(Millions of Dollars)Level 1Level 2Level 3Level 1Level 2Level 3
Current derivative liabilities
Other derivative instruments:
Commodity trading$5 $17 $6 $28 $(14)$14 $5 $22 $6 $33 $(18)$15 
Electric commodity— — 1 1 (1)— — — 3 3 (3)— 
Natural gas commodity— — — — — — — 10 — 10 — 10 
Total current derivative liabilities$5 $17 $7 $29 $(15)14 $5 $32 $9 $46 $(21)25 
PPAs (b)
6 6 
Current derivative instruments$20 $31 
Noncurrent derivative liabilities
Other derivative instruments:
Commodity trading$4 $18 $34 $56 $(9)$47 $6 $24 $40 $70 $(13)$57 
Total noncurrent derivative liabilities$4 $18 $34 $56 $(9)47 $6 $24 $40 $70 $(13)57 
PPAs (b)
9 10 
Noncurrent derivative instruments$56 $67 
(a)Xcel Energy nets derivative instruments and related collateral on its consolidated balance sheets when supported by a legally enforceable master netting agreement. At March 31, 2026 and Dec. 31, 2025, derivative assets and liabilities include no obligations to return cash collateral. At both March 31, 2026 and Dec. 31, 2025, derivative assets and liabilities include rights to reclaim cash collateral of $4 million. Counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements.
(b)Xcel Energy currently applies the normal purchase exception to qualifying PPAs. Balance relates to specific contracts that were previously recognized at fair value prior to applying the normal purchase exception, and are being amortized over the remaining contract lives along with the offsetting regulatory assets and liabilities.
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Changes in Level 3 commodity derivatives:
Three Months Ended March 31
(Millions of Dollars)20262025
Balance at Jan. 1$139 $99 
Purchases (a)
105 66 
Settlements (a)
(47)(57)
Net transactions recorded during the period:
Losses recognized in earnings (b)
(7)(2)
Net (losses) gains recognized as regulatory assets and liabilities (a)
(51)12 
Balance at March 31$139 $118 
(a)Relates primarily to NSP-Minnesota and SPS FTR instruments administered by MISO and SPP.
(b)Relates to commodity trading and is subject to 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
Other financial instruments for which the carrying amount did not equal fair value:
March 31, 2026Dec. 31, 2025
(Millions of Dollars)Carrying AmountFair ValueCarrying AmountFair Value
Long-term debt, including current portion$35,553 $32,563 $32,333 $29,943 
Fair value of Xcel Energy’s long-term debt is estimated based on recent trades and observable spreads from benchmark interest rates for similar securities. Fair value estimates are based on information available to management as of March 31, 2026 and Dec. 31, 2025, and given the observability of the inputs, fair values presented for long-term debt were assigned as Level 2.
9. Benefit Plans and Other Postretirement Benefits
Components of Net Periodic Benefit Cost (Credit)
Three Months Ended March 31
2026202520262025
(Millions of Dollars)Pension BenefitsPostretirement Health
Care Benefits
Service cost$20 $19 $— $— 
Interest cost (a)
39 39 6 6 
Expected return on plan assets (a)
(50)(52)(5)(5)
Amortization of net loss (a)
11 7 1 1 
Net periodic benefit cost20 13 2 2 
Effects of regulation(1)2 — — 
Net benefit cost recognized for financial reporting$19 $15 $2 $2 
(a)The components of net periodic cost other than the service cost component are included in the line item “Other income, net” in the consolidated statements of income or capitalized on the consolidated balance sheets as a regulatory asset.
In January 2026, contributions totaling $75 million were made across Xcel Energy’s pension plans. Xcel Energy does not expect additional pension contributions during 2026.

10. Commitments and Contingencies
Legal
Xcel Energy is involved in various litigation matters in the ordinary course of business. The assessment of whether a loss is probable or is a reasonable possibility, and whether the loss or a range of loss is estimable, often involves a series of complex judgments about future events. Management maintains accruals for losses probable of being incurred and subject to reasonable estimation. 
Management is sometimes unable to estimate an amount or range of a reasonably possible loss in certain situations, including but not limited to when (1) the damages sought are indeterminate, (2) the proceedings are in the early stages, or (3) the matters involve novel or unsettled legal theories.
In such cases, there is considerable uncertainty regarding the timing or ultimate resolution, including a possible eventual loss. For current proceedings not specifically reported herein, management does not anticipate that the ultimate liabilities, if any, would have a material effect on Xcel Energy’s consolidated financial statements. Legal fees are generally expensed as incurred.
2024 Smokehouse Creek Fire Complex — On February 26, 2024, multiple wildfires began in the Texas Panhandle, including the Smokehouse Creek Fire and the 687 Reamer Fire, which burned into the perimeter of the Smokehouse Creek Fire (together, referred to herein as the “Smokehouse Creek Fire Complex”). The Texas A&M Forest Service issued incident reports that determined that the Smokehouse Creek Fire and the 687 Reamer Fire were caused by power lines owned by SPS after wooden poles near each fire origin failed. According to the Texas A&M Forest Service’s Incident Viewer and news reports, the Smokehouse Creek Fire Complex burned approximately 1,055,000 acres.
SPS is aware of approximately 73 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 73 complaints, 26 have been resolved.
SPS has received 304 claims through its claims process, net of duplicative, withdrawn and denied claims, and has reached final settlements on 231 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 107 claims which have not been submitted through the claims process and have also not been filed as lawsuits and has reached settlement of 79 of those claims through mediation.
A higher amount of claims was received in the first quarter of 2026, relative to recent months, which SPS believes is due to the generally applicable two-year statute of limitations for claims for property damage in Texas.
In December 2025, the Texas Attorney General’s office filed a lawsuit against SPS regarding the Smokehouse Creek Fire, seeking monetary damages and civil penalties for losses to property and wildlife resulting from the fires. In February 2026, pending resolution of the lawsuit, SPS and the Texas Attorney General’s office jointly filed a temporary injunction agreeing to certain distribution pole replacement procedures, largely consistent with current procedures.
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SPS has settled claims related to both fatalities believed to be associated with the Smokehouse Creek Fire Complex. Settlements have also been reached with the subrogated insurer plaintiffs as well as the three largest claims asserted from the fire, as measured by fire-impacted acreage. Settlements reached as of the date of this filing total $397 million of expected loss payments, of which $385 million and $374 million were paid through March 31, 2026 and Dec. 31, 2025, 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 $63 million of remaining estimated probable losses for the matter (before available insurance), for a total estimated loss of $460 million. Additionally, approximately $40 million in legal costs have been incurred as of March 31, 2026, resulting in total estimated losses and incurred costs related to this proceeding of $500 million as of March 31, 2026. An estimated liability of $75 million and $56 million for estimated losses is presented in other current liabilities as of March 31, 2026 and Dec. 31, 2025, respectively.
The estimated remaining probable losses for complaints and claims in connection with the Smokehouse Creek Fire Complex (before available insurance) represents the low end of the range for remaining reasonably estimable losses and is subject to change as additional information becomes available. This 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 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 the nature of demands that may be made. Resolution of remaining complaints and claims associated with the Smokehouse Creek Fire Complex could exceed our insurance coverage of $525 million for the annual policy period (of which approximately $90 million of coverage remains after consideration of settlements reached and legal costs incurred through March 31, 2026) 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 for estimated losses of approximately $185 million and $195 million, net of recoveries received are presented in prepayments and other current assets as of March 31, 2026 and Dec. 31, 2025, 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.
Marshall Wildfire Litigation — In December 2021, a wildfire occurred in Boulder County, Colorado (Marshall Fire). According to a 2023 report of the Boulder County Sheriff, on Dec. 30, 2021, a fire ignited on a residential property in Boulder, Colorado for reasons unrelated to PSCo’s power lines. Also according to the 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, approximately 80 to 110 feet away from PSCo’s power lines in the area.
PSCo received complaints alleging that PSCo’s equipment ignited the Marshall Fire and asserted various causes of action under Colorado law. In addition to asserting claims against PSCo and certain of its affiliates, various plaintiffs asserted claims against certain telecommunications companies.
In September 2025, Xcel Energy, Qwest Corporation and Teleport Communications America, LLC reached settlement agreements in principle that resolve all claims asserted by the subrogation insurers, the public entity plaintiffs and individual plaintiffs, and required PSCo to make settlement payments of $640 million. PSCo did not admit any fault, wrongdoing or negligence in connection with these settlement agreements.
As a result of settlements as well as legal and other costs of the matter, PSCo recognized charges to earnings of $298 million in the year ended Dec. 31, 2025, after consideration of total costs expected to be reimbursed by insurance. In the first quarter of 2026, PSCo increased its estimated amount recoverable from insurance resulting in a $22 million credit to earnings. As of April 2026, final settlement documentation has been executed with the subrogation insurers, the public entity plaintiffs and nearly all the individual plaintiffs, and these parties have received payment. The only remaining litigation concerns three related individual plaintiffs who continue to prosecute their claims.
Remaining estimated liabilities of $7 million and $5 million are presented in other current liabilities as of March 31, 2026 and Dec. 31, 2025, respectively.
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 $25 million and $353 million related to settlements are presented in prepayments and other current assets as of March 31, 2026 and Dec. 31, 2025, respectively.
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.
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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 March 2026, the ALJ recommended a $41 million disallowance of estimated replacement power costs. As a result, in the first quarter of 2026, NSP-Minnesota recognized an incremental $37 million in customer refunds, including interest, to electric revenues. A MPUC decision is expected in the second quarter of 2026.
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 15 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.
Xcel Energy continues to perform site investigation activities related to the CCR Rule, which may result in updates to estimated costs as well as identification of additional required corrective actions.
In February 2026, the EPA issued a final rule amending the CCR Legacy rule. The ruling extends deadlines for various regulatory actions and clarifies previous information regarding implementation of the rule. Xcel Energy anticipates impacts to be consistent with prior accruals.
In April 2026, the EPA published a new proposed rule with additional amendments to the CCR Legacy Rule. Xcel Energy is evaluating this proposed rule and its potential impacts. 
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 establishes a federal plan and applies to generation facilities in Minnesota, Texas, and Wisconsin, as well as other states outside of our service territory. The EPA later proposed to include New Mexico in the federal plan.
If the rule is implemented, Xcel Energy anticipates the annual costs could be significant but would be recoverable through regulatory mechanisms. However, the plan is subject to both judicial and administrative stays while the EPA reconsiders the rule. In January 2026, the EPA proposed Phase 1 of its reconsideration of the “Good Neighbor” rule. Xcel Energy will continue to evaluate any additional phases of the reconsideration of this rule as they are published by the EPA.
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.
Components of lease expense:
Three Months Ended March 31
(Millions of Dollars)20262025
Operating leases
PPA capacity payments$29 $57 
Other operating leases (a)
13 13 
Total operating lease expense$42 $70 
Finance leases
Amortization of ROU assets$10 $1 
Interest expense on lease liability22 4 
Total finance lease expense$32 $5 
(a)Includes immaterial short-term lease expense.
20
Commitments under operating and finance leases as of March 31, 2026:
(Millions of Dollars)PPA Operating
Leases		Other Operating
Leases		Total Operating
Leases
Finance
 Leases (a)
Total minimum obligation$603 $620 $1,223 $2,223 
Interest component of obligation(86)(265)(351)(885)
Present value of minimum obligation$517 $355 872 1,338 
Less current portion(111)(40)
Noncurrent operating and finance lease liabilities$761 $1,298 
(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 directly subject to risk of loss from the operations of these entities, and no additional 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 for specified transactions. These specific PPAs create a variable interest in the IPP.
Xcel Energy evaluated each of these VIEs for possible consolidation and 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 3,476 MW of capacity under long-term PPAs at both March 31, 2026 and Dec. 31, 2025 with entities that have been determined to be variable interest entities. The PPAs have expiration dates through 2048.
Other
Guarantees and Bond Indemnifications — Xcel Energy Inc. and its subsidiaries provide guarantees and bond indemnities, which guarantee payment or performance. Xcel Energy Inc.’s exposure is based upon the net liability under the specified agreements or transactions. Most of the guarantees and bond indemnities issued by Xcel Energy Inc. and its subsidiaries have a stated maximum amount.
As of March 31, 2026 and Dec. 31, 2025, 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 $120 million at March 31, 2026 and Dec. 31, 2025.
Other Indemnification Agreements — Xcel Energy Inc. and its subsidiaries provide indemnifications through various contracts. These are primarily indemnifications against adverse litigation outcomes in connection with underwriting agreements, breaches of representations and warranties, including corporate existence, transaction authorization and income tax matters with respect to assets sold, as well as disallowances or reductions to the contractual amounts of tax credit transfers.
Xcel Energy Inc.’s and its subsidiaries’ obligations under these agreements may be limited in terms of duration and amount. Maximum future payments under these indemnifications cannot be reasonably estimated as the dollar amounts are often not explicitly stated.
11. Other Comprehensive Loss
Changes in accumulated other comprehensive loss, net of tax:
Three Months Ended March 31, 2026Three Months Ended March 31, 2025
(Millions of Dollars)Gains and Losses on Cash Flow HedgesDefined Benefit Pension and Postretirement ItemsTotalGains and Losses on Cash Flow HedgesDefined Benefit Pension and Postretirement ItemsTotal
Accumulated other comprehensive loss at Jan. 1$(25)$(38)$(63)$(29)$(39)$(68)
Other comprehensive gain (loss) before reclassifications
3 — 3 (5)— (5)
Losses reclassified from net accumulated other comprehensive loss:
Interest rate derivatives (a)
1 — 1 1 — 1 
Net current period other comprehensive income (loss)4 — 4 (4)— (4)
Accumulated other comprehensive loss at March 31$(21)$(38)$(59)$(33)$(39)$(72)
(a)Included in interest charges.
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12. Segment Information
Segment information and reconciliation to Xcel Energy’s consolidated net income:
Three Months Ended March 31, 2026
(Millions of Dollars)Regulated electric utilityRegulated natural gas utilityTotal segments
Operating revenues$2,976 $1,030 $4,006 
Intersegment revenue— 4 4 
Total segment revenues2,976 1,034 4,010 
Electric fuel and purchased power1,019 — 1,019 
Cost of natural gas sold and transported— 520 520 
O&M expenses558 106 664 
Depreciation and amortization653 110 763 
Other segment expenses, net144 42 186 
Interest charges and financing costs250 34 284 
Income tax (benefit) expense (77)52 (25)
Net income$429 $170 $599 
Total segment net income$599 
Non-segment net loss(43)
Consolidated net income$556 
Three Months Ended March 31, 2025
(Millions of Dollars)Regulated electric utilityRegulated natural gas utilityTotal segments
Operating revenues$2,835 $1,055 $3,890 
Intersegment revenue— 5 5 
Total segment revenues2,835 1,060 3,895 
Electric fuel and purchased power1,020 — 1,020 
Cost of natural gas sold and transported— 513 513 
O&M expenses567 106 673 
Depreciation and amortization625 99 724 
Other segment expenses, net172 56 228 
Interest charges and financing costs204 30 234 
Income tax (benefit) expense (95)61 (34)
Net income$342 $195 $537 
Total segment net income$537 
Non-segment net loss(54)
Consolidated net income$483 
Equity method investments in the regulated natural gas utility segment of $66 million and $81 million at March 31, 2026 and Dec. 31, 2025, respectively, primarily relate to WYCO. Non-segment equity method investments of $206 million and $204 million as of March 31, 2026 and Dec. 31, 2025, 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.
22
Ongoing earnings reflect adjustments to GAAP earnings (net income) for certain items. Ongoing diluted EPS for Xcel Energy is calculated by dividing net income or loss, adjusted for certain items, by the weighted average fully diluted Xcel Energy Inc. common shares outstanding for the period. Ongoing diluted EPS for each subsidiary is calculated by dividing the net income or loss for such subsidiary, adjusted for certain items, by the weighted average fully diluted Xcel Energy Inc. common shares outstanding for the period.
We use these non-GAAP financial measures to evaluate and provide details of Xcel Energy’s core earnings and underlying performance. For instance, to present ongoing earnings and ongoing diluted EPS, we may adjust the related GAAP amounts for certain items that are non-recurring in nature. We believe these measurements are useful to investors to evaluate the actual and projected financial performance and contribution of our subsidiaries. These non-GAAP financial measures should not be considered as an alternative to measures calculated and reported in accordance with GAAP.
The following table provides a reconciliation of GAAP earnings (net income) to ongoing earnings:
Three Months Ended March 31
(Millions of Dollars)20262025
GAAP net income$556 $483 
Prairie Island outage refunds37 — 
Marshall Wildfire litigation(22)— 
Tax effect(4)— 
Ongoing earnings$567 $483 
Prairie Island Outage Refunds — In March 2026, the ALJ recommended a disallowance of $41 million for estimated replacement power costs incurred during a 2023-2024 outage at NSP-Minnesota’s Prairie Island nuclear facility. A non-recurring charge of $37 million was recorded to electric revenues in the first quarter of 2026 for incremental customer refunds, including interest.
Marshall Wildfire Litigation — In the first quarter of 2026, PSCo recognized a $22 million reduction to operating expenses due to an increase in the estimated amount recoverable from insurance for non-recurring Marshall Wildfire costs.
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 first quarter GAAP earnings were $0.89 per share compared with $0.84 per share in the same period in 2025 and ongoing earnings were $0.91 compared with $0.84 per share in 2025. Despite the impact of unseasonably warm weather in the first quarter, ongoing earnings per share was primarily driven by increased recovery of electric infrastructure investments and electric sales growth, partially offset by higher financing costs and increased depreciation expense. 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 March 31
Diluted Earnings (Loss) Per Share20262025
PSCo$0.42 $0.45 
NSP-Minnesota0.30 0.32 
SPS0.13 0.10 
NSP-Wisconsin0.10 0.07 
Earnings from equity method investments — WYCO0.01 0.01 
Regulated utility (a)
0.97 0.95 
Xcel Energy Inc. and Other(0.08)(0.11)
GAAP diluted EPS (a)
$0.89 $0.84 
Prairie Island outage refunds0.04 — 
Marshall Wildfire litigation(0.03)— 
Ongoing diluted EPS (a)
$0.91 $0.84 
(a)Amounts may not add due to rounding.
Summary of Earnings
PSCo — GAAP earnings decreased $0.03 per share and ongoing earnings decreased $0.06 per share for the first quarter of 2026. The change was driven by unfavorable weather, which was partially offset by higher recovery of electric infrastructure investments. The difference between GAAP and ongoing earnings was driven by the increase in estimated Marshall Wildfire insurance amounts recoverable.
NSP-Minnesota — GAAP earnings decreased $0.02 per share and ongoing earnings increased $0.02 per share for the first quarter of 2026. The ongoing earnings increase was driven by higher recovery of electric and natural gas infrastructure investments, which was partially offset by increased interest charges. The difference between GAAP and ongoing earnings was driven by recognition of customer refunds related to the 2023-2024 Prairie Island nuclear facility outage.
SPS — GAAP and ongoing earnings increased $0.03 per share for the first quarter of 2026. The change was driven by sales growth, partially offset by increased depreciation expense and unfavorable weather.
NSP-Wisconsin — GAAP and ongoing earnings increased $0.03 per share for the first quarter of 2026. The change was driven by higher recovery of electric and natural gas infrastructure investments, partially offset by increased depreciation expense.
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.
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Changes in GAAP and Ongoing EPS
Components significantly contributing to changes in 2026 EPS compared to 2025:
Diluted Earnings (Loss) Per ShareThree Months Ended March 31
GAAP EPS — 2025$0.84 
Components of change - 2026 vs. 2025
Higher electric revenues0.23 
Higher AFUDC equity & debt0.10 
Marshall Wildfire litigation0.03 
Higher interest charges(0.10)
Common equity financing(0.08)
Higher depreciation and amortization(0.05)
Prairie Island outage refunds (0.04)
Lower natural gas revenues(0.03)
Other, net(0.01)
GAAP EPS — 2026$0.89 
Prairie Island outage refunds0.04 
Marshall Wildfire litigation(0.03)
Ongoing EPS — 2026 (a)
$0.91 
(a)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. However, electric sales true-up and gas decoupling mechanisms 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:
Three Months Ended March 31
2026 vs. Normal2025 vs. Normal2026 vs. 2025
HDD(15.2)%— %(15.3)%
Weather — Estimated impact of temperature variations on EPS compared with normal weather conditions:
Three Months Ended March 31
2026 vs. Normal2025 vs. Normal2026 vs. 2025
Retail electric$(0.029)$0.006 $(0.035)
Sales true-up (a)
0.006 — 0.006 
Electric total$(0.023)$0.006 $(0.029)
Firm natural gas(0.074)0.005 (0.079)
Decoupling0.008 0.002 0.006 
Natural gas total$(0.066)$0.007 $(0.073)
Total$(0.089)$0.013 $(0.102)
(a)The sales true-up mechanism in NSP-Minnesota 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 2026 compared to 2025:
Three Months Ended March 31
PSCoNSP-MinnesotaSPSNSP-WisconsinXcel Energy
Actual
Electric residential(7.6)%0.3 %(13.0)%0.1 %(4.6)%
Electric C&I(1.2)1.9 10.7 0.2 3.7 
Total retail electric sales(3.4)1.36.7 0.2 1.2 
Firm natural gas sales(25.1)(4.0)N/A(3.5)(16.8)
Three Months Ended March 31
PSCoNSP-MinnesotaSPSNSP-WisconsinXcel Energy
Weather-Normalized
Electric residential(1.9)%1.8 %(5.4)%1.3 %(0.7)%
Electric C&I0.3 2.2 10.8 0.3 4.3 
Total retail electric sales(0.5)2.1 8.1 0.6 2.8 
Firm natural gas sales(0.4)1.2 N/A(0.4)0.1 

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Weather-normalized electric sales growth (decline) — year-to-date
•Residential sales — Decrease is due to lower use per customer in SPS (6.1%) and PSCo (2.5%), partially offset by customer growth in all jurisdictions.
•C&I sales — Increase is due to higher use per customer in SPS (10.6%) and NSP-Minnesota (1.8%) and customer growth in NSP-Wisconsin (1.1%). Increased activity in the energy sector in SPS and various sectors in all jurisdictions contributed to the sales growth.
Weather-normalized natural gas sales growth (decline) — year-to-date
•Increase in natural gas sales was driven primarily by customer growth in all jurisdictions, partially offset by decreased use per customer for C&I and residential customers in PSCo and NSP-Wisconsin.
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 March 31, 2026 vs. 2025
Non-fuel riders$84 
Sales and demand36 
Recovery of higher cost of electric fuel and purchased power35 
Regulatory rate outcomes (WI and SD)21 
Conservation and demand side management (offset in expense)20 
Wholesale transmission15 
Prairie Island outage refunds(37)
Estimated impact of weather(23)
PTCs flowed back to customers (offset in ETR)(17)
Other, net 7 
Total increase $141 
Natural Gas Revenues
Natural gas revenues vary with changing sales, the cost of natural gas and regulatory outcomes.
(Millions of Dollars)Three Months Ended March 31, 2026 vs. 2025
Estimated impact of weather (net of decoupling)$(61)
Regulatory rate outcomes (MN and WI)28 
Recovery of higher cost of natural gas4 
Other, net4 
Total decrease$(25)
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 decreased $1 million for the first quarter of 2026.
Cost of Natural Gas Sold and Transported — Expenses incurred for the cost of natural gas sold are impacted by market prices and seasonality. These costs are generally recovered through various regulatory recovery mechanisms. As a result, changes in these expenses are largely offset in operating revenues and have minimal earnings impact.
Natural gas sold and transported increased $7 million for the first quarter of 2026. The change was primarily due to higher commodity prices partially offset by decreased volumes in PSCo.
Non-Fuel Operating Expenses and Other Items
O&M Expenses — O&M expenses decreased $11 million for the first quarter of 2026. The change was primarily due to lower benefits and bad debt expenses.
Depreciation and Amortization — Depreciation and amortization increased $40 million for the first quarter of 2026. The change was largely the result of system investment.
Interest Charges — Interest charges increased $80 million for the first quarter of 2026, largely due to higher debt levels and interest rates.
AFUDC, Equity and Debt — AFUDC increased $61 million for the first quarter of 2026, 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, 2025 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
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. The DOC and XLI recommended $306 million and $190 million of adjustments, respectively, largely based on a reduction in ROE, certain O&M expenses and other costs offset in trackers. Other parties recommended adjustments based on reduced ROE and issue specific recommendations.
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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 about $50 million is expected to be addressed through trackers. In November 2025, the DOC filed surrebuttal testimony, re-asserting their proposed ROE of 9.25%.
On April 29, 2026, the ALJ report was issued. NSP-Minnesota estimates that the ALJ recommendation would result in a rate increase of approximately $248 million, based on a ROE of 9.8% and an equity ratio of 52.5%.
Proposed ALJ modifications to NSP-Minnesota’s request were as follows:
(Millions of Dollars)20252026
NSP-Minnesota’s rebuttal testimony revenue request$208 $365 
ALJ recommended adjustments:
Rate of return(48)(51)
O&M expenses(35)(37)
Property tax (a)
(3)(12)
Other, net(5)(17)
Total adjustments(91)(117)
Proposed revenue change$117 $248 
(a)Adjustments largely offset in trackers.
A MPUC decision is expected in the third quarter of 2026.
2025 Minnesota Natural Gas Rate Case — In October 2025, NSP-Minnesota filed a natural gas rate case in Minnesota, seeking a total revenue increase of $62 million (8.2%) as updated in April 2026. 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 requested interim rates of $51 million effective January 1, 2026, which were approved by the MPUC.
In March 2026, the DOC, OAG and CUB filed direct testimony and recommended financial adjustments. The DOC recommended a total rate increase of $31 million, and an ROE of 9.3%. The OAG and CUB provided limited comments, with the OAG recommending a reduction of approximately $6 million in O&M expenses and CUB recommending an ROE of 9.0%.
Next steps in the procedural schedule are as follows:
•Surrebuttal testimony: May 1, 2026
•Evidentiary hearing: May 11-12, 2026
•ALJ Report: September 1, 2026
A MPUC decision is expected in November 2026.
2022 Minnesota Electric Rate Case — 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%.
NSP-Minnesota appealed certain aspects of the MPUC decision. In January 2025, the Minnesota Court of Appeals issued its opinion, which included reversing and remanding decisions related to executive compensation and prepaid pension asset back to the MPUC. In March 2026, the MPUC declined to modify the treatment of executive compensation. A commission decision on prepaid pension asset is expected in mid-2026.
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%, an equity ratio of 52.87% and rate base of approximately $1.2 billion. Interim rates were implemented 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.
In April 2026, NSP-Minnesota and SDPUC Staff filed a black box settlement agreement with the SDPUC, including a net annual electric rate increase of $26 million. A SDPUC decision is expected in the second quarter of 2026.
2026 North Dakota Natural Gas Rate Case — In January 2026, NSP-Minnesota filed a natural gas rate case in North Dakota, for an annual rate increase of $14 million (11.9%). The filing is based on a 2026 forecast test year and includes an ROE of 10.85%, a 52.5% equity ratio and rate base of $235 million. In March 2026, the NDPSC approved interim rates of $12 million effective April 1, 2026.
NSP System
Pending and Recently Concluded Regulatory Proceedings
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. NSP-Minnesota filed for approval of recommended projects in March 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 retirement of Sherco and A.S King coal units. NSP-Minnesota and NSP-Wisconsin announced the short listed projects in January 2025. NSP-Minnesota received MPUC approval of the selected resources in March 2026 and NSP-Wisconsin expects to file for approvals with the PSCW in the second quarter of 2026.
•In December 2025, NSP-Minnesota and NSP-Wisconsin jointly issued an RFP seeking up to 3,500 MW of wind, solar, hydro, standalone storage, or hybrid capacity that will achieve commercial operation by December 31, 2030. Additionally, NSP-Minnesota is seeking to procure up to 600 MW of solar or solar plus storage capacity that will achieve commercial operation by December 31, 2029, and meet Minnesota’s Distributed Solar Energy Standard eligibility requirements. Bids were submitted in March 2026, and filing for requisite regulatory approval is expected by the end of 2026.
•NSP-Minnesota and NSP-Wisconsin may continue to file additional RFPs throughout 2026 and 2027 for resource needs as part of its Upper Midwest resource planning efforts.
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Large Load Agreement — In the first quarter of 2026, NSP-Minnesota entered into an electric service agreement to power a new Google data center in Minnesota. Under the agreement, Google will pay all costs for its new service for the duration of the agreement, in accordance with Minnesota’s regulatory and legislative requirements for large loads. If approved, the agreement is expected to result in approximately $1.1 billion of benefits to NSP-Minnesota’s customers. A request for approval of the Electric Service Agreement, including a proposed Clean Energy Accelerator Charge for 1,900 MW of clean energy resources, was filed with the MPUC in April 2026. Approvals for 1,000 MW of resources for the Clean Energy Accelerator program are pending as part of existing resource acquisition processes. The remaining resources are expected to be requested in those processes by the end of 2026.
PSCo
Pending and Recently Concluded Regulatory Proceedings
2025 Colorado Electric Rate Case — In November 2025, PSCo filed an electric rate case with the CPUC seeking an increase in revenue of $356 million (9.9%) ($526 million inclusive of rider roll-ins). The request is based on a 9.8% ROE, an equity ratio of 55% and a 2025 test year with a projected rate base of $13 billion.
On April 28, 2026, eight intervenors filed testimony, with CPUC Staff, UCA, and CEC filing comprehensive testimony. The FEA additionally proposed certain financial adjustments.
The following modifications were proposed:
(Millions of Dollars)CPUC StaffUCACECFEA
PSCo rate request, net of rider roll-ins$356 $356 $356 $356 
Recommended adjustments:
Cost of capital(93)(101)(255)(34)
Test year/rate base methodology(83)(71)(23)— 
O&M adjustments(24)(20)(15)(3)
Rate base adjustments(13)(23)(10)— 
Depreciation expense adjustments21 — (18)(13)
Other, net3 (2)— — 
Total adjustments(189)(217)(321)(50)
Proposed revenue change$167 $139 $35 $306 
ROE9.00 %9.20 %8.10 %9.45 %
Equity ratio52.50 %50.00 %42.00 %55.00 %
Rate base convention13 month average13 month averageYear endN/A
The remaining procedural schedule is as follows::
•Rebuttal testimony: May 20, 2026
•Settlement deadline: May 28, 2026
•Hearing: June 11-18, 2026
A CPUC decision and implementation of final rates is anticipated in the third quarter of 2026.
2025 Colorado Natural Gas Rate Case — In December 2025, PSCo filed a natural gas rate case with the CPUC seeking an increase in revenue of $190 million (11.6%). The request is based on a 10.75% ROE, an equity ratio of 55% and a 2025 test year with a projected rate base of $4.7 billion.
The procedural schedule is as follows:
•Answer testimony: June 5, 2026
•Rebuttal testimony: July 2, 2026
•Settlement deadline: July 8, 2026
•Hearing: July 23-30, 2026
A CPUC decision and implementation of final rates is anticipated in the fourth quarter of 2026.
2024 Colorado Electric Resource Plan — In October 2024, PSCo filed its Phase I electric resource plan with the CPUC. In November 2025, the CPUC approved a load forecast that reflects a 3% compound annual sales growth through 2031 and generation capacity need of approximately 5,400 MW.
PSCo filed a request for reconsideration of various aspects of the decision which were approved in February 2026. This decision is expected to initiate the Phase II competitive solicitation process with an RFP expected to be issued in the third quarter of 2026. This RFP will seek to acquire the balance of resource needs through 2031 (after consideration of any approved acquisitions from the Near-Term Procurement RFP).
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 nameplate MW of clean energy resources, 200 accredited MW of firm, dispatchable resources, and up to 300 accredited MW of other dispatchable resources.
In February 2026, the CPUC approved 3,200 MW of resources, which included PPAs and a 200 MW company-owned natural gas combustion turbine. In April 2026, the CPUC verbally approved an additional 600 MW company-owned wind facility.
SPS
Pending and Recently Concluded Regulatory Proceedings
2025 New Mexico Electric Rate Case — In November 2025, SPS filed an electric rate case with the NMPRC seeking a revenue increase of $168 million (16.0%) as updated in March 2026. The request is based on a future test year period ending Nov. 30, 2027, a ROE of 10.5%, an equity ratio of 56% and retail rate base of $3.9 billion.
The procedural schedule is as follows:
•Staff and Intervenor direct testimony: May 1, 2026
•Rebuttal testimony: May 29, 2026
•Public Evidentiary Hearing: July 7, 2026
A NMPRC decision and implementation of final rates is anticipated in the fourth quarter of 2026.
SPS Resource Acquisition — 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.
27

In July 2024, SPS issued a RFP, seeking approximately 3,200 MW of accredited capacity by 2030. 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 OwnedPPAsTotal
Wind Resources1,273 — 1,273 
Solar695 — 695 
Storage472 640 1,112 
Natural Gas2,088 — 2,088 
Total4,528 640 5,168 
SPS filed 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 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 were received in January 2026, and the portfolio is expected to be filed in the second half of 2026.
Excess Liability Insurance Deferral – In early 2025, SPS filed requests with the NMPRC and PUCT 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 and $3 million in the first quarter of 2026. In January 2026, SPS, PUCT Staff and other intervenors filed a black box settlement expected to result in annual deferrals of approximately $8 million in 2026 and 2027. A PUCT decision is expected in the first half of 2026.
Other
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.
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.
Large Load/Data Center Tariffs
In several of our jurisdictions, we have proposed tariffs applicable to large load customers. These tariffs are designed to allow us to serve these new customers and support local economic development while protecting existing customers from bearing the incremental costs to serve these loads.
While the details of these tariffs vary by jurisdiction, they generally include provisions to ensure data center customers pay the incremental costs to serve them, minimum demand or revenue requirements, termination or exit fees and customer security provisions. These tariffs and contracts are subject to approval by state regulatory commissions. The status of the filings in each jurisdiction is as follows.
NSP-Minnesota —The proposed tariff, filed in the third quarter of 2025, would be mandatory for new loads over 100 MW and includes an incremental cost test, minimum initial term of 15 years, minimum bill provisions, termination and exit fees, and credit requirements. A MPUC decision is expected in the second quarter of 2026.
PSCo — The proposed tariff, filed in the second quarter of 2026, would be mandatory for new loads over 50 MW and requires the customer pay for generation and other infrastructure costs needed to serve the load. The proposed tariff also includes a minimum initial term of 15 years, minimum bill provisions, termination and exit fees, and credit requirements. A CPUC decision is expected in late 2026 or early 2027.
Similar large load tariff requests are expected to be filed in Wisconsin, New Mexico, and Texas in the second quarter of 2026.
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, 2025.
Environmental Regulation
Throughout 2025 and 2026, 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 CO2 emissions from the power sector. The rules regulate new natural gas generating units and emission guidelines for existing coal and certain natural gas generation.
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.
Endangerment Finding — In February 2026, the EPA issued a final rule repealing the 2009 Endangerment Finding and associated regulations addressing GHG emissions from new motor vehicles and engines under the Clean Air Act. Xcel Energy will monitor any additional proposed rules and evaluate the impacts of any final rule on the utility sector.
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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.
In March 2026, the EPA issued a final rule tightening the emission limit for several pollutants from large municipal waste combustors. Xcel Energy is assessing whether and what additional controls may be required to comply, but believes that the cost of these initiatives or replacement generation would be recoverable through rates based on prior state commission practices.
Regional Haze — In January 2026, the EPA issued a final rule fully disapproving the 2022 Colorado SIP revision, thereby removing the mandatory retirement dates. The removal of the retirement dates from a federally approved SIP would only impact whether the SIP provisions become federally enforceable. Colorado has a state regulation that reflects the SIP requirements, including retirement dates for Cherokee Unit 4, Comanche Unit 2, Craig Units 1 and 2, and Hayden Units 1 and 2 at a state level and would require amendment to modify or remove 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.
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 March 31, 2026:
Futures / Forwards Maturity
(Millions of Dollars)Less Than 1 Year1 to 3 Years4 to 5 YearsGreater Than 5 YearsTotal Fair Value
NSP-Minnesota (a)
$(9)$(13)$(1)$(1)$(24)
NSP-Minnesota (b)
(2)(6)— (2)(10)
PSCo (a)
(1)— — — (1)
$(12)$(19)$(1)$(3)$(35)
Options Maturity
(Millions of Dollars)Less Than 1 Year1 to 3 Years4 to 5 YearsGreater Than 5 YearsTotal Fair Value
NSP-Minnesota (b)
$— $13 $7 $— $20 
$— $13 $7 $— $20 
(a)Prices actively quoted or based on actively quoted prices.
(b)Prices based on models and other valuation methods.
Changes in the fair value of commodity trading contracts before the impacts of margin-sharing for the three months ended March 31:
(Millions of Dollars)20262025
Fair value of commodity trading net contracts outstanding at Jan. 1$(15)$(2)
Contracts realized or settled during the period2 3 
Commodity trading contract additions and changes during the period(2)(13)
Fair value of commodity trading net contracts outstanding at March 31$(15)$(12)
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 and $3 million at March 31, 2026 and March 31, 2025.
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The utility subsidiaries’ commodity trading operations measure the outstanding risk exposure to price changes on contracts and obligations using an industry standard methodology known as VaR. VaR expresses the potential change in fair value of the outstanding contracts and obligations over a particular period of time under normal market conditions.
The VaRs for the NSP-Minnesota and PSCo commodity trading operations, excluding both non-derivative transactions and derivative transactions designated as normal purchases and normal sales, calculated on a consolidated basis using a Monte Carlo simulation with a 95% confidence level and a one-day holding period, were as follows:
(Millions of Dollars)Three Months Ended March 31AverageHighLow
2026$1 $1 $1 $— 
20251 — 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 $15 million and $8 million at March 31, 2026 and 2025, 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.
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 March 31, 2026, a 10% increase in commodity prices would have resulted in an increase in credit exposure of $26 million, while a decrease in prices of 10% would have resulted in a decrease in credit exposure of $26 million. At March 31, 2025, a 10% increase in commodity prices would have resulted in an increase in credit exposure of $28 million, while a decrease in prices of 10% would have resulted in a decrease in credit exposure of $27 million.
Fair Value Measurements
Derivative contracts, with the exception of those designated as normal purchases and normal sales, are reported at fair value. Xcel Energy’s investments held in the nuclear decommissioning fund, rabbi trusts, pension and other postretirement funds are also subject to fair value accounting. See Note 8 to the consolidated financial statements for further information.
Liquidity and Capital Resources
Cash Flows
Operating Cash Flows
(Millions of Dollars)Three Months Ended March 31
Cash provided by operating activities — 2025$1,028 
Components of change — 2026 vs. 2025
Higher net income73 
Non-cash transactions(32)
Changes in deferred income taxes (18)
Changes in working capital533 
Changes in net regulatory and other assets and liabilities113 
Cash provided by operating activities — 2026$1,697 
Net cash provided by operating activities increased $669 million for the three months ended March 31, 2026 compared with the prior year. The increase was largely due to insurance reimbursement for the Marshall Wildfire settlement and timing of regulatory recovery, including deferred net natural gas, fuel and purchased energy costs.
Investing Cash Flows
(Millions of Dollars)Three Months Ended March 31
Cash used in investing activities — 2025$(1,991)
Components of change — 2026 vs. 2025
Increased capital expenditures(1,034)
Other investing activities6 
Cash used in investing activities — 2026$(3,019)
Net cash used in investing activities increased $1,028 million for the three months ended March 31, 2026 compared with the prior year. The increase in capital expenditures was largely due to continued system investment in renewable and transmission projects.
30
Financing Cash Flows
(Millions of Dollars)Three Months Ended March 31
Cash provided by financing activities — 2025$1,907 
Components of change — 2026 vs. 2025
Lower net short-term repayments(94)
Higher long-term debt issuances, net of repayments1,182 
Lower proceeds from issuance of common stock(121)
Other financing activities(66)
Cash provided by financing activities — 2026$2,808 
Net cash provided by financing activities increased $901 million for the three months ended March 31, 2026 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 2026, contributions of $75 million were made to Xcel Energy’s pension plans.
•In 2025, contributions of $125 million were made to 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.
Credit Facilities — As of April 27, 2026, 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)
AvailableCashLiquidity
Xcel Energy Inc.$2,000 $340 $1,660 $26 $1,686 
PSCo1,200 48 1,152 471 1,623 
NSP-Minnesota800 44 756 564 1,320 
SPS600 98 502 4 506 
NSP-Wisconsin150 — 150 2 152 
Total$4,750 $530 $4,220 $1,067 $5,287 
(a)Credit facilities expire in December 2029.
(b)Includes outstanding commercial paper and letters of credit.
Term Loan Agreement — In January 2026, Xcel Energy Inc. entered into a $1.5 billion, 364-Day Delayed Draw Term Loan Agreement and as of April 27, 2026 had borrowed $1.15 billion under the term loan facility.
Short-Term Debt — Xcel Energy Inc., NSP-Minnesota, NSP-Wisconsin, PSCo and SPS each have individual commercial paper programs. As of March 31, 2026, 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.
2026 Financing Activity — Xcel Energy and its utility subsidiaries issued or plan to issue the following long-term debt:
IssuerSecurityAmountStatusTenorCoupon
Xcel Energy Inc.Junior subordinated notes$800 millionCompleted30 year5.75% fixed-to-fixed reset rate
PSCoFirst mortgage bonds1,300 millionCompleted3 year & 10 year4.15% & 5.05%
NSP-MinnesotaFirst mortgage bonds1,200 millionCompleted10 year & 30 year4.85% & 5.55%
NSP-WisconsinFirst mortgage bonds250 million
Pending (a)
15 year5.48%
PSCoFirst mortgage bonds1,100 millionUpcomingN/AN/A
SPSFirst mortgage bonds1,000 millionUpcomingN/AN/A
(a)NSP-Wisconsin priced a 15 year first mortgage bond on April 1, 2026 and expects to close and fund the transaction in June 2026.
During the quarter ended March 31, 2026, Xcel Energy Inc. entered forward sale agreements for shares of common stock totaling 13.6 million shares (minimum expected proceeds of $1.1 billion). There were no shares issued in at-the-market cash transactions or settlements of forward sale agreements during the period. As of March 31, 2026, 40.9 million shares remain unsettled on forward equity agreements and collared forward equity agreements (minimum expected proceeds of $3.1 billion).
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.
31

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 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 remainder of 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 $505 million to $515 million.
•O&M expenses are projected to increase ~3%.
•Depreciation expense is projected to increase approximately $330 million to $340 million.
•Property taxes are projected to increase $30 million to $40 million.
•Interest expense (net of AFUDC - debt) is projected to increase $270 million to $280 million, net of interest income.
•AFUDC - equity is projected to increase $130 million to $140 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, 2025 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.
As of March 31, 2026, 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, 2025, which is incorporated herein by reference. There have been no material changes from the risk factors previously disclosed in the Form 10-K.
32
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 March 31, 2026, 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 March 31, 2026.
ITEM 6 — EXHIBITS
*Indicates incorporation by reference
Exhibit NumberDescriptionReport or Registration StatementExhibit Reference
Xcel Energy Inc. Form 8-K dated May 16, 20123.01
Xcel Energy Inc Form 8-K dated August 23, 20233.02
Xcel Energy Inc. Form 8-K dated March 3, 20264.01
NSP-Minnesota Form 8-K dated March 12, 20264.01
PSCo Form 8-K dated March 13, 20264.02
Xcel Energy Inc. Form 8-K dated February 2, 202610.01
101.INSInline 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.SCHInline XBRL Schema
101.CALInline XBRL Calculation
101.DEFInline XBRL Definition
101.LABInline XBRL Label
101.PREInline XBRL Presentation
104Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)
33

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.
April 30, 2026By:/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)
34

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