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

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

For the quarterly period ended Sept. 30, 2024
or

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

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

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

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

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

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

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

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

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

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

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

Class |  | Outstanding at Oct. 28, 2024
Common Stock, $2.50 par value |  | 574,241,745 shares

TABLE OF CONTENTS

PART I | FINANCIAL INFORMATION |
Item 1 — | Financial Statements (unaudited) | 5
| Consolidated Statements of Income | 5
| Consolidated Statements of Comprehensive Income | 6
| Consolidated Statements of Cash Flows | 7
| Consolidated Balance Sheets | 8
| Consolidated Statements of Common Stockholders’ Equity | 9
| Notes to Consolidated Financial Statements | 10
Item 2 — | Management’s Discussion and Analysis of Financial Condition and Results of Operations | 24
Item 3 — | Quantitative and Qualitative Disclosures A bout Market Risk | 36
Item 4 — | Controls and Procedures | 36
PART II | OTHER INFORMATION |
Item 1 — | Legal Proceedings | 36
Item 1A — | Risk Factors | 37
Item 2 — | Unregistered Sales of Equity Securities and Use of Proceeds | 37
Item 5 — | Other Information | 37
Item 6 — | Exhibits | 37
SIGNATURES | 38

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

Definitions of Abbreviations

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

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

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

CO 2 | Carbon dioxide
CORE | CORE Electric Cooperative
CPCN | Certificate of Public Convenience and Necessity
CSPV | Crystalline Silicon Photovoltaic
DRIP | Dividend Reinvestment and Stock Purchase Program
EPS | Earnings per share
ETR | Effective tax rate
FCA | Fuel clause adjustment
FTR | Financial transmission right
GAAP | United States generally accepted accounting principles
GE | General Electric Company
HDD | Heating degree-days
IPP | Independent power producing entity
IRA | Inflation Reduction Act
IRP | Integrated Resource Plan
LLC | Limited liability company
MGP | Manufactured gas plant
MISO | Midcontinent Independent System Operator, Inc.
NAV | Net asset value
NOx | Nitrogen Oxides
O&M | Operating and maintenance
PFAS | Per- and Polyfluoroalkyl Substances
PIM | Performance incentive mechanism
PPA | Power purchase agreement
PSPS | Public safety power shutoff
PTC | Production tax credit
RFP | Request for proposal
ROE | Return on equity
RTO | Regional Transmission Organization
SMMPA | Southern Minnesota Municipal Power Agency
SPP | Southwest Power Pool, Inc.
THI | Temperature-humidity index
VaR | Value at Risk
VIE | Variable interest entity
WACC | Weighted average cost of capital
WMP | Wildfire mitigation plan

Measurements
GW | Gigawatts
MW | Megawatts

3

Forward-Looking Statements

Except for the historical statements contained in this report, the matters discussed herein are forward-looking statements that are subject to certain risks, uncertainties and assumptions. Such forward-looking statements, including those relating to 2024 and 2025 EPS guidance, long-term EPS and dividend growth rate objectives, future sales, future expenses, future tax rates, future operating performance, estimated base capital expenditures and financing plans, projected capital additions and forecasted annual revenue requirements with respect to rider filings, expected rate increases 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, 2023 and subsequent filings with the Securities and Exchange Commission, could cause actual results to differ materially from management expectations as suggested by such forward-looking information: operational safety, including our nuclear generation facilities and other utility operations; successful long-term operational planning; commodity risks associated with energy markets and production; rising energy prices and fuel costs; qualified employee workforce and third-party contractor factors; violations of our Codes of Conduct; our ability to recover costs and our subsidiaries’ ability to recover costs from customers; changes in regulation; reductions in our credit ratings and the cost of maintaining certain contractual relationships; general economic conditions, including recessionary conditions, inflation rates, monetary fluctuations, supply chain constraints and their impact on capital expenditures and/or the ability of Xcel Energy Inc. and its subsidiaries to obtain financing on favorable terms; availability or cost of capital; our customers’ and counterparties’ ability to pay their debts to us; assumptions and costs relating to funding our employee benefit plans and health care benefits; our subsidiaries’ ability to make dividend payments; tax laws; uncertainty regarding epidemics, the duration and magnitude of business restrictions including shutdowns (domestically and globally), the potential impact on the workforce, including shortages of employees or third-party contractors due to quarantine policies, vaccination requirements or government restrictions, impacts on the transportation of goods and the generalized impact on the economy; effects of geopolitical events, including war and acts of terrorism; cybersecurity threats and data security breaches; seasonal weather patterns; changes in environmental laws and regulations; climate change and other weather events; natural disaster and resource depletion, including compliance with any accompanying legislative and regulatory changes; costs of potential regulatory penalties and wildfire damages in excess of liability insurance coverage; regulatory changes and/or limitations related to the use of natural gas as an energy source; challenging labor market conditions and our ability to attract and retain a qualified workforce; and our ability to execute on our strategies or achieve expectations related to environmental, social and governance matters including as a result of evolving legal, regulatory and other standards, processes, and assumptions, the pace of scientific and technological developments, increased costs, the availability of requisite financing, and changes in carbon markets.
4

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

| Three Months Ended Sept. 30 |  | Nine Months Ended Sept. 30
| 2024 |  | 2023 |  | 2024 |  | 2023
Operating revenues |  |  |  |  |  |  |
Electric | $ | 3,393 |  |  | $ | 3,387 |  |  | $ | 8,737 |  |  | $ | 8,751 |
Natural gas | 239 |  |  | 245 |  |  | 1,535 |  |  | 1,926 |
Other | 12 |  |  | 30 |  |  | 49 |  |  | 87 |
Total operating revenues | 3,644 |  |  | 3,662 |  |  | 10,321 |  |  | 10,764 |
Operating expenses |  |  |  |  |  |  |
Electric fuel and purchased power | 1,060 |  |  | 1,181 |  |  | 2,863 |  |  | 3,328 |
Cost of natural gas sold and transported | 63 |  |  | 70 |  |  | 664 |  |  | 1,084 |
Cost of sales — other | 3 |  |  | 14 |  |  | 12 |  |  | 37 |
Operating and maintenance expenses | 655 |  |  | 586 |  |  | 1,922 |  |  | 1,864 |
Conservation and demand side management expenses | 112 |  |  | 76 |  |  | 295 |  |  | 215 |
Depreciation and amortization | 681 |  |  | 618 |  |  | 2,042 |  |  | 1,807 |
Taxes (other than income taxes) | 159 |  |  | 168 |  |  | 484 |  |  | 489 |
Loss on Comanche Unit 3 litigation | — |  |  | 34 |  |  | — |  |  | 34 |
Total operating expenses | 2,733 |  |  | 2,747 |  |  | 8,282 |  |  | 8,858 |
Operating income | 911 |  |  | 915 |  |  | 2,039 |  |  | 1,906 |
Other income, net | 39 |  |  | 3 |  |  | 75 |  |  | 19 |
Earnings from equity method investments | 3 |  |  | 7 |  |  | 19 |  |  | 27 |
Allowance for funds used during construction — equity | 44 |  |  | 26 |  |  | 119 |  |  | 63 |
Interest charges and financing costs |  |  |  |  |  |  |
Interest charges — includes other financing costs | 326 |  |  | 269 |  |  | 936 |  |  | 790 |
Allowance for funds used during construction — debt | (21) |  |  | (14) |  |  | (51) |  |  | (36) |
Total interest charges and financing costs | 305 |  |  | 255 |  |  | 885 |  |  | 754 |
Income before income taxes | 692 |  |  | 696 |  |  | 1,367 |  |  | 1,261 |
Income tax expense (benefit) | 10 |  |  | 40 |  |  | (105) |  |  | (101) |
Net income | $ | 682 |  |  | $ | 656 |  |  | $ | 1,472 |  |  | $ | 1,362 |
Weighted average common shares outstanding: |  |  |  |  |  |  |
Basic | 564 |  |  | 552 |  |  | 559 |  |  | 551 |
Diluted | 565 |  |  | 552 |  |  | 559 |  |  | 552 |
Earnings per average common share: |  |  |  |  |  |  |
Basic | $ | 1.21 |  |  | $ | 1.19 |  |  | $ | 2.63 |  |  | $ | 2.47 |
Diluted | 1.21 |  |  | 1.19 |  |  | 2.63 |  |  | 2.47 |
See Notes to Consolidated Financial Statements

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

| Three Months Ended Sept. 30 |  | Nine Months Ended Sept. 30
| 2024 |  | 2023 |  | 2024 |  | 2023
Net income | $ | 682 |  |  | $ | 656 |  |  | $ | 1,472 |  |  | $ | 1,362 |
Other comprehensive income |  |  |  |  |  |  |
Pension and retiree medical benefits: |  |  |  |  |  |  |
Reclassifications of losses to net income, net of tax | — |  |  | — |  |  | 4 |  |  | 1 |
Derivative instruments: |  |  |  |  |  |  |
Net fair value increase, net of tax | — |  |  | 3 |  |  | 22 |  |  | 11 |
Reclassification of losses to net income, net of tax | 1 |  |  | 1 |  |  | 2 |  |  | 3 |
Total other comprehensive income | 1 |  |  | 4 |  |  | 28 |  |  | 15 |
Total comprehensive income | $ | 683 |  |  | $ | 660 |  |  | $ | 1,500 |  |  | $ | 1,377 |
See Notes to Consolidated Financial Statements

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

| Nine Months Ended Sept. 30
| 2024 |  | 2023
Operating activities |  |  |
Net income | $ | 1,472 |  |  | $ | 1,362 |
Adjustments to reconcile net income to cash provided by operating activities: |  |  |
Depreciation and amortization | 2,055 |  |  | 1,824 |
Nuclear fuel amortization | 85 |  |  | 84 |
Deferred income taxes | 406 |  |  | (173) |
Allowance for equity funds used during construction | (119) |  |  | (63) |
Earnings from equity method investments | (19) |  |  | (27) |
Dividends from equity method investments | 26 |  |  | 26 |
Provision for bad debts | 47 |  |  | 58 |
Share-based compensation expense | 27 |  |  | 17 |
Changes in operating assets and liabilities: |  |  |
Accounts receivable | 81 |  |  | 95 |
Accrued unbilled revenues | 62 |  |  | 375 |
Inventories | (71) |  |  | 73 |
Other current assets | 13 |  |  | 104 |
Accounts payable | (42) |  |  | (226) |
Net regulatory assets and liabilities | 282 |  |  | 771 |
Other current liabilities | (238) |  |  | 183 |
Pension and other employee benefit obligations | (94) |  |  | (35) |
Other, net | 4 |  |  | (95) |
Net cash provided by operating activities | 3,977 |  |  | 4,353 |
Investing activities |  |  |
Capital/construction expenditures | (5,147) |  |  | (4,240) |
Purchase of investment securities | (693) |  |  | (704) |
Proceeds from the sale of investment securities | 666 |  |  | 678 |
Other, net | (23) |  |  | (26) |
Net cash used in investing activities | (5,197) |  |  | (4,292) |
Financing activities |  |  |
Repayments of short-term borrowings, net | (690) |  |  | (813) |
Proceeds from issuances of long-term debt | 3,643 |  |  | 2,631 |
Repayments of long-term debt | (550) |  |  | (651) |
Proceeds from issuance of common stock | 1,109 |  |  | 83 |
Dividends paid | (871) |  |  | (814) |
Other, net | (5) |  |  | (14) |
Net cash provided by financing activities | 2,636 |  |  | 422 |
Net change in cash, cash equivalents and restricted cash | 1,416 |  |  | 483 |
Cash, cash equivalents and restricted cash at beginning of period | 129 |  |  | 111 |
Cash, cash equivalents and restricted cash at end of period | $ | 1,545 |  |  | $ | 594 |
Supplemental disclosure of cash flow information: |  |  |
Cash paid for interest (net of amounts capitalized) | $ | (793) |  |  | $ | (652) |
Cash received (paid) for income taxes, net; includes proceeds from tax credit transfers | 484 |  |  | (68) |
Supplemental disclosure of non-cash investing and financing transactions: |  |  |
Accrued property, plant and equipment additions | $ | 741 |  |  | $ | 409 |
Inventory transfers to property, plant and equipment | 217 |  |  | 42 |
Operating lease right-of-use assets | 43 |  |  | 73 |
Allowance for equity funds used during construction | 119 |  |  | 63 |
Issuance of common stock for reinvested dividends and/or equity awards | 53 |  |  | 46 |
See Notes to Consolidated Financial Statements

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

| Sept. 30, 2024 |  | Dec. 31, 2023
Assets |  |  |
Current assets |  |  |
Cash and cash equivalents | $ | 1,545 |  |  | $ | 129 |
Accounts receivable, net | 1,187 |  |  | 1,315 |
Accrued unbilled revenues | 790 |  |  | 853 |
Inventories | 638 |  |  | 711 |
Regulatory assets | 562 |  |  | 611 |
Derivative instruments | 179 |  |  | 104 |
Prepaid taxes | 64 |  |  | 52 |
Prepayments and other | 504 |  |  | 294 |
Total current assets | 5,469 |  |  | 4,069 |
Property, plant and equipment, net | 55,321 |  |  | 51,642 |
Other assets |  |  |
Nuclear decommissioning fund and other investments | 3,947 |  |  | 3,599 |
Regulatory assets | 2,794 |  |  | 2,798 |
Derivative instruments | 63 |  |  | 76 |
Operating lease right-of-use assets | 1,096 |  |  | 1,217 |
Other | 596 |  |  | 678 |
Total other assets | 8,496 |  |  | 8,368 |
Total assets | $ | 69,286 |  |  | $ | 64,079 |
Liabilities and Equity |  |  |
Current liabilities |  |  |
Current portion of long-term debt | $ | 1,104 |  |  | $ | 552 |
Short-term debt | 95 |  |  | 785 |
Accounts payable | 1,713 |  |  | 1,668 |
Regulatory liabilities | 835 |  |  | 528 |
Taxes accrued | 488 |  |  | 557 |
Accrued interest | 329 |  |  | 251 |
Dividends payable | 312 |  |  | 289 |
Derivative instruments | 38 |  |  | 74 |
Operating lease liabilities | 226 |  |  | 226 |
Other | 718 |  |  | 722 |
Total current liabilities | 5,858 |  |  | 5,652 |
Deferred credits and other liabilities |  |  |
Deferred income taxes | 5,480 |  |  | 4,885 |
Deferred investment tax credits | 41 |  |  | 60 |
Regulatory liabilities | 6,056 |  |  | 5,827 |
Asset retirement obligations | 3,431 |  |  | 3,218 |
Derivative instruments | 68 |  |  | 86 |
Customer advances | 154 |  |  | 167 |
Pension and employee benefit obligations | 374 |  |  | 469 |
Operating lease liabilities | 908 |  |  | 1,038 |
Other | 93 |  |  | 148 |
Total deferred credits and other liabilities | 16,605 |  |  | 15,898 |
Commitments and contingencies |  |  |
Capitalization |  |  |
Long-term debt | 27,471 |  |  | 24,913 |
Common stock — 1,000,000,000 shares authorized of $2.50 par value; 574,101,713 and 554,941,703 shares outstanding at Sept. 30, 2024 and December 31, 2023, respectively | 1,435 |  |  | 1,387 |
Additional paid in capital | 9,577 |  |  | 8,465 |
Retained earnings | 8,406 |  |  | 7,858 |
Accumulated other comprehensive loss | (66) |  |  | (94) |
Total common stockholders’ equity | 19,352 |  |  | 17,616 |
Total liabilities and equity | $ | 69,286 |  |  | $ | 64,079 |
See Notes to Consolidated Financial Statements

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XCEL ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS’ EQUITY (UNAUDITED)
(amounts in millions, except per share data; shares in actual amounts)

| Common Stock Issued |  | Retained Earnings |  | Accumulated Other Comprehensive Loss |  | Total Common Stockholders' Equity
| Shares |  | Par Value |  | Additional Paid In Capital |  |  |
Three Months Ended Sept. 30, 2024 and 2023 |  |  |  |  |  |  |  |  |  |  |
Balance at June 30, 2023 | 551,375,255 |  |  | $ | 1,378 |  |  | $ | 8,247 |  |  | $ | 7,371 |  |  | $ | (82) |  |  | $ | 16,914 |
Net income |  |  |  |  |  |  | 656 |  |  |  |  | 656 |
Other comprehensive income |  |  |  |  |  |  |  |  | 4 |  |  | 4 |
Dividends declared on common stock ($0.52 per share) |  |  |  |  |  |  | (287) |  |  |  |  | (287) |
Issuances of common stock | 287,548 |  |  | 1 |  |  | 17 |  |  |  |  |  |  | 18 |
Share-based compensation |  |  |  |  | 5 |  |  | (1) |  |  |  |  | 4 |
Balance at Sept. 30, 2023 | 551,662,803 |  |  | $ | 1,379 |  |  | $ | 8,269 |  |  | $ | 7,739 |  |  | $ | (78) |  |  | $ | 17,309 |
Balance at June 30, 2024 | 557,337,051 |  |  | $ | 1,393 |  |  | $ | 8,589 |  |  | $ | 8,039 |  |  | $ | (67) |  |  | $ | 17,954 |
Net income |  |  |  |  |  |  | 682 |  |  |  |  | 682 |
Other comprehensive income |  |  |  |  |  |  |  |  | 1 |  |  | 1 |
Dividends declared on common stock ($0.5475 per share) |  |  |  |  |  |  | (312) |  |  |  |  | (312) |
Issuances of common stock | 16,764,662 |  |  | 42 |  |  | 975 |  |  |  |  |  |  | 1,017 |
Share-based compensation |  |  |  |  | 13 |  |  | (3) |  |  |  |  | 10 |
Balance at Sept. 30, 2024 | 574,101,713 |  |  | $ | 1,435 |  |  | $ | 9,577 |  |  | $ | 8,406 |  |  | $ | (66) |  |  | $ | 19,352 |
| Common Stock Issued |  | Retained Earnings |  | Accumulated Other Comprehensive Loss |  | Total Common Stockholders' Equity
| Shares |  | Par Value |  | Additional Paid In Capital |  |  |
Nine Months Ended Sept 30, 2024 and 2023 |  |  |  |  |  |  |  |  |  |  |
Balance at Dec. 31, 2022 | 549,578,018 |  |  | $ | 1,374 |  |  | $ | 8,155 |  |  | $ | 7,239 |  |  | $ | (93) |  |  | $ | 16,675 |
Net income |  |  |  |  |  |  | 1,362 |  |  |  |  | 1,362 |
Other comprehensive income |  |  |  |  |  |  |  |  | 15 |  |  | 15 |
Dividends declared on common stock ($1.56 per share) |  |  |  |  |  |  | (859) |  |  |  |  | (859) |
Issuances of common stock | 2,084,785 |  |  | 5 |  |  | 108 |  |  |  |  |  |  | 113 |
Share-based compensation |  |  |  |  | 6 |  |  | (3) |  |  |  |  | 3 |
Balance at Sept. 30, 2023 | 551,662,803 |  |  | $ | 1,379 |  |  | $ | 8,269 |  |  | $ | 7,739 |  |  | $ | (78) |  |  | $ | 17,309 |
Balance at Dec. 31, 2023 | 554,941,703 |  |  | $ | 1,387 |  |  | $ | 8,465 |  |  | $ | 7,858 |  |  | $ | (94) |  |  | $ | 17,616 |
Net income |  |  |  |  |  |  | 1,472 |  |  |  |  | 1,472 |
Other comprehensive income |  |  |  |  |  |  |  |  | 28 |  |  | 28 |
Dividends declared on common stock ($1.6425 per share) |  |  |  |  |  |  | (921) |  |  |  |  | (921) |
Issuances of common stock | 19,160,010 |  |  | 48 |  |  | 1,082 |  |  |  |  |  |  | 1,130 |
Share-based compensation |  |  |  |  | 30 |  |  | (3) |  |  |  |  | 27 |
Balance at Sept. 30, 2024 | 574,101,713 |  |  | $ | 1,435 |  |  | $ | 9,577 |  |  | $ | 8,406 |  |  | $ | (66) |  |  | $ | 19,352 |
See Notes to Consolidated Financial Statements

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XCEL ENERGY INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements (UNAUDITED)
In the opinion of management, the accompanying unaudited consolidated financial statements contain all adjustments necessary to present fairly, in accordance with GAAP, the financial position of Xcel Energy as of Sept. 30, 2024 and Dec. 31, 2023; the results of Xcel Energy’s operations, including the components of net income, comprehensive income and changes in stockholders’ equity for the three and nine months ended Sept. 30, 2024 and 2023; and Xcel Energy’s cash flows for the nine months ended Sept. 30, 2024 and 2023.
All adjustments are of a normal, recurring nature, except as otherwise disclosed. Management has also evaluated the impact of events occurring after Sept. 30, 2024, 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, 2023 balance sheet information has been derived from the audited 2023 consolidated financial statements included in the Xcel Energy Inc. Annual Report on Form 10-K for the year ended Dec. 31, 2023.
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, 2023, filed with the SEC on Feb. 21, 2024.
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, 2023 appropriately represent, in all material respects, the current status of accounting policies and are incorpora ted herein by reference.

2. Accounting Pronouncements

Recently Issued
Segment Reporting — In November 2023, the FASB issued ASU 2023-07 – Segment Reporting (Topic 280) – Improvements to Reportable Segment Disclosures, which extends the existing requirements for annual disclosures to quarterly periods, and requires that both annual and quarterly disclosures present segment expenses using line items consistent with information regularly provided to the chief operating decision maker. The ASU is effective for annual periods beginning after Dec. 15, 2023 and quarterly periods beginning after Dec. 15, 2024, and Xcel Energy does not expect implementation of the new disclosure guidance to have a material impact to its consolidated financial statements.
Income Taxes — In December 2023, the FASB issued ASU 2023-09 – Income Taxes (Topic 740) – Improvements to Income Tax Disclosures, with new disclosure requirements including presentation of prescribed line items in the ETR reconciliation and disclosures regarding state and local tax payments. The ASU is effective for annual periods beginning after Dec. 15, 2024, and Xcel Energy does not expect implementation of the new disclosure guidance to have a material impact to its consolidated financial statements.
Climate-Related Disclosures — In March 2024, the SEC issued Final Rule 33-11275 – The Enhancement and Standardization of Climate-Related Disclosures for Investors. This rule requires registrants to provide standardized disclosures in Form 10-K related to climate-related risks, Scope 1 and 2 greenhouse gas emissions, as well as to include in a footnote to the consolidated financial statements the financial impact of severe weather events and other natural conditions. The rule requires implementation in phases between 2025 and 2033. In April 2024, the SEC announced that it would voluntarily stay its final climate disclosure rules pending judicial review. Xcel Energy does not expect implementation of the new guidance to have a material impact on the consolidated financial statements.

3. Selected Balance Sheet Data

(Millions of Dollars) |  | Sept. 30, 2024 |  | Dec. 31, 2023
Accounts receivable, net |  |  |  |
Accounts receivable |  | $ | 1,295 |  |  | $ | 1,443 |
Less allowance for bad debts |  | (108) |  |  | (128) |
Accounts receivable, net |  | $ | 1,187 |  |  | $ | 1,315 |

(Millions of Dollars) |  | Sept. 30, 2024 |  | Dec. 31, 2023
Inventories |  |  |  |
Materials and supplies |  | $ | 399 |  |  | $ | 377 |
Fuel |  | 149 |  |  | 211 |
Natural gas |  | 90 |  |  | 123 |
Total inventories |  | $ | 638 |  |  | $ | 711 |

(Millions of Dollars) |  | Sept. 30, 2024 |  | Dec. 31, 2023
Property, plant and equipment, net |  |  |  |
Electric plant |  | $ | 54,908 |  |  | $ | 52,494 |
Natural gas plant |  | 9,599 |  |  | 9,080 |
Common and other property |  | 3,370 |  |  | 3,190 |
Plant to be retired (a) |  | 1,846 |  |  | 2,055 |
Construction work in progress |  | 4,851 |  |  | 2,873 |
Total property, plant and equipment |  | 74,574 |  |  | 69,692 |
Less accumulated depreciation |  | (19,632) |  |  | (18,399) |
Nuclear fuel |  | 3,452 |  |  | 3,337 |
Less accumulated amortization |  | (3,073) |  |  | (2,988) |
Property, plant and equipment, net |  | $ | 55,321 |  |  | $ | 51,642 |

(a)Amounts include Sherco 1 and 3 and A.S. King for NSP-Minnesota; Comanche Units 2 and 3, Craig Units 1 and 2, Hayden Units 1 and 2 and coal generation assets at Pawnee pending facility gas conversion for PSCo; and Tolk Unit 1 and 2 and coal generation assets at Harrington pending facility gas conversion for SPS. Amounts are presented net of accumulated depreciation.
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4. Borrowings and Other Financing Instruments

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

(Amounts in Millions, Except Interest Rates) |  | Three Months Ended Sept. 30, 2024 |  | Year Ended Dec. 31, 2023
Borrowing limit |  | $ | 3,550 |  |  | $ | 3,550 |
Amount outstanding at period end |  | 95 |  |  | 785 |
Average amount outstanding |  | 644 |  |  | 491 |
Maximum amount outstanding |  | 1,080 |  |  | 1,241 |
Weighted average interest rate, computed on a daily basis |  | 5.50 | % |  | 5.12 | %
Weighted average interest rate at period end |  | 5.21 |  |  | 5.52 |

Letters of Credit — Xcel Energy Inc. and its utility subsidiaries use letters of credit, generally with terms of one year, to provide financial guarantees for certain obligations. There was $43 million and $44 million of letters of credit outstanding under the credit facilities at Sept. 30, 2024 and Dec. 31, 2023, respectively. Amounts approximate their fair value and are subject to fees.
Revolving Credit Facilities — In order to issue commercial paper, Xcel Energy Inc. and its utility subsidiaries must have revolving credit facilities equal to or greater than the commercial paper borrowing limits and cannot issue commercial paper exceeding available credit facility capacity. The lines of credit provide short-term financing in the form of notes payable to banks, letters of credit and back-up support for commercial paper borrowings.
As of Sept. 30, 2024, Xcel Energy Inc. and its utility subsidiaries had the following committed revolving credit facilities available:

(Millions of Dollars) |  | Credit Facility (a) |  | Drawn (b) |  | Available
Xcel Energy Inc. |  | $ | 1,500 |  |  | $ | 95 |  |  | $ | 1,405 |
PSCo |  | 700 |  |  | 31 |  |  | 669 |
NSP-Minnesota |  | 700 |  |  | 12 |  |  | 688 |
SPS |  | 500 |  |  | — |  |  | 500 |
NSP-Wisconsin |  | 150 |  |  | — |  |  | 150 |
Total |  | $ | 3,550 |  |  | $ | 138 |  |  | $ | 3,412 |

(a)Expires in September 2027.
(b)Includes outstanding commercial paper and letters of credit.
Xcel Energy Inc., NSP-Minnesota, PSCo, and SPS each have the right to request an extension of the credit facility termination date for two additional one-year periods. NSP-Wisconsin has the right to request an extension of the credit facility termination date for an additional one-year period. All extension requests are subject to majority bank group approval.
All credit facility bank borrowings, outstanding letters of credit and outstanding commercial paper reduce the available capacity of the credit facility. Xcel Energy Inc. and its utility subsidiaries had no direct advances on the credit facilities outstanding as of Sept. 30, 2024 and Dec. 31, 2023.
Bilateral Credit Agreement
In April 2024, NSP-Minnesota’s uncommitted bilateral credit agreement was renewed for an additional one-year term. The credit agreement is limited in use to support letters of credit.
As of Sept. 30, 2024, NSP-Minnesota had $70 million of outstanding letters of credit under the $75 million bilateral credit agreement.
Long-Term Borrowings and Other Financing Instruments
During the nine months ended Sept. 30, 2024, Xcel Energy Inc. and its utility subsidiaries issued the following:
•Xcel Energy Inc. issued $800 million of 5.50% Senior Unsecured Notes due March 15, 2034.
•NSP-Minnesota issued $700 million of 5.40% First Mortgage Bonds due March 15, 2054.
•PSCo issued $450 million of 5.35% First Mortgage Bonds due May 15, 2034 and $750 million of 5.75% First Mortgage Bonds due May 15, 2054.
•NSP-Wisconsin issued $400 million of 5.65% First Mortgage Bonds due June 15, 2054.
•SPS issued $600 million of 6.00% First Mortgage Bonds due June 1, 2054.
ATM Equity Offering — In October 2023, Xcel Energy Inc. filed a prospectus supplement under which it may sell up to $2.5 billion of its common stock through an ATM program. In 2023, Xcel Energy Inc. issued 3.12 million shares of common stock ($188 million in net proceeds and $2 million in transaction fees paid). In the nine months ended Sept. 30, 2024, 18.27 million shares ($1.1 billion in net proceeds and $9 million in transaction fees paid) were issued under the ATM program. As of Sept. 30, 2024, approximately $1.2 billion remained available for sale under the ATM program.
Equity through DRIP and Benefits Program — Xcel Energy issued $50 million and $78 million of equity through the DRIP and benefits programs during the nine months ended Sept. 30, 2024 and 2023, respectively. The programs allow shareholders to reinvest their dividends directly in Xcel Energy Inc. common stock.

5. Revenues

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

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

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|  | Three Months Ended Sept. 30, 2023
(Millions of Dollars) |  | Electric |  | Natural Gas |  | All Other |  | Total
Major revenue types |  |  |  |  |  |  |  |
Revenue from contracts with customers:
Residential |  | $ | 1,086 |  |  | $ | 125 |  |  | $ | 16 |  |  | $ | 1,227 |
C&I |  | 1,657 |  |  | 75 |  |  | 7 |  |  | 1,739 |
Other |  | 42 |  |  | — |  |  | 3 |  |  | 45 |
Total retail |  | 2,785 |  |  | 200 |  |  | 26 |  |  | 3,011 |
Wholesale |  | 244 |  |  | — |  |  | — |  |  | 244 |
Transmission |  | 178 |  |  | — |  |  | — |  |  | 178 |
Other |  | 9 |  |  | 33 |  |  | — |  |  | 42 |
Total revenue from contracts with customers |  | 3,216 |  |  | 233 |  |  | 26 |  |  | 3,475 |
Alternative revenue and other |  | 171 |  |  | 12 |  |  | 4 |  |  | 187 |
Total revenues |  | $ | 3,387 |  |  | $ | 245 |  |  | $ | 30 |  |  | $ | 3,662 |

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

|  | Nine Months Ended Sept. 30, 2023
(Millions of Dollars) |  | Electric |  | Natural Gas |  | All Other |  | Total
Major revenue types |  |  |  |  |  |  |  |
Revenue from contracts with customers:
Residential |  | $ | 2,708 |  |  | $ | 1,130 |  |  | $ | 44 |  |  | $ | 3,882 |
C&I |  | 4,347 |  |  | 622 |  |  | 27 |  |  | 4,996 |
Other |  | 115 |  |  | — |  |  | 5 |  |  | 120 |
Total retail |  | 7,170 |  |  | 1,752 |  |  | 76 |  |  | 8,998 |
Wholesale |  | 642 |  |  | — |  |  | — |  |  | 642 |
Transmission |  | 498 |  |  | — |  |  | — |  |  | 498 |
Other |  | 22 |  |  | 113 |  |  | — |  |  | 135 |
Total revenue from contracts with customers |  | 8,332 |  |  | 1,865 |  |  | 76 |  |  | 10,273 |
Alternative revenue and other |  | 419 |  |  | 61 |  |  | 11 |  |  | 491 |
Total revenues |  | $ | 8,751 |  |  | $ | 1,926 |  |  | $ | 87 |  |  | $ | 10,764 |

6. Income Taxes

Reconciliation between the statutory rate and ETR:

|  | Three Months Ended Sept. 30 |  | Nine Months Ended Sept. 30
|  | 2024 |  | 2023 |  | 2024 |  | 2023
Federal statutory rate |  | 21.0 | % |  | 21.0 | % |  | 21.0 | % |  | 21.0 | %
State tax (net of federal tax effect) |  | 4.7 |  |  | 5.0 |  |  | 4.8 |  |  | 4.9 |
(Decreases) increases: |  |  |  |  |  |  |  |
Wind PTCs (a) |  | (16.0) |  |  | (13.8) |  |  | (26.2) |  |  | (27.3) |
Plant regulatory differences (b) |  | (5.7) |  |  | (5.3) |  |  | (5.9) |  |  | (5.5) |
Other tax credits, net operating loss & tax credit allowances |  | (1.5) |  |  | (1.1) |  |  | (1.1) |  |  | (1.2) |
Other, net |  | (1.1) |  |  | (0.1) |  |  | (0.3) |  |  | 0.1 |
Effective income tax rate |  | 1.4 | % |  | 5.7 | % |  | (7.7) | % |  | (8.0) | %

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

7. Earnings Per Share

Basic EPS was computed by dividing the earnings available to common shareholders by the average weighted number of common shares outstanding. Diluted EPS was computed by dividing the earnings available to common shareholders by the diluted weighted average number of common shares outstanding.
Diluted EPS reflects the potential dilution that could occur if securities or other agreements to issue common stock (i.e., common stock equivalents) were settled. The weighted average number of potentially dilutive shares outstanding used to calculate diluted EPS is calculated using the treasury stock method.
Common Stock Equivalents — Xcel Energy Inc. has common stock equivalents related to time-based equity compensation awards.
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.
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Common shares outstanding used in the basic and diluted EPS computation:

|  | Three Months Ended Sept. 30 |  | Nine Months Ended Sept. 30
(Shares in Millions) |  | 2024 |  | 2023 |  | 2024 |  | 2023
Basic |  | 564 |  |  | 552 |  |  | 559 |  |  | 551 |
Diluted (a) |  | 565 |  |  | 552 |  |  | 559 |  |  | 552 |

(a)Diluted common shares outstanding included common stock equivalents of 0.4 million and 0.3 million for the three months ended Sept. 30, 2024 and 2023, respectively. Diluted common shares outstanding included common stock equivalents of 0.3 million and 0.2 million for the nine months ended Sept. 30, 2024 and 2023.

8. Fair Value of Financial Assets and Liabilities

Fair Value Measurements
Accounting guidance for fair value measurements and disclosures provides a hierarchical framework for disclosing the observability of the inputs utilized in measuring assets and liabilities at fair value.
•Level 1 — Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. The types of assets and liabilities included in Level 1 are actively traded instruments with observable actual trading prices.
•Level 2 — Pricing inputs are other than actual trading prices in active markets but are either directly or indirectly observable as of the reporting date. The types of assets and liabilities included in Level 2 are typically either comparable to actively traded securities or contracts or priced with models using highly observable inputs.
•Level 3 — Significant inputs to pricing have little or no observability as of the reporting date. The types of assets and liabilities included in Level 3 include those valued with models requiring significant judgment or estimation.
Specific valuation methods include:
Investments in equity securities and other funds — Equity securities are valued using quoted prices in active markets. The fair values for commingled funds are measured using NAVs. The investments in commingled funds may be redeemed for NAV with proper notice. Private equity commingled funds require approval of the fund for any unscheduled redemption, and such redemptions may be approved or denied by the fund at its sole discretion. Unscheduled distributions from real estate commingled funds may be redeemed with proper notice, however, withdrawals may be delayed or discounted as a result of fund illiquidity.
Investments in debt securities — Fair values for debt securities are determined by a third party pricing service using recent trades and observable spreads from benchmark interest rates for similar securities.
Interest rate derivatives — Fair values of interest rate derivatives are based on broker quotes that utilize current market interest rate forecasts.
Commodity derivatives — Methods used to measure the fair value of commodity derivative forwards and options utilize forward prices and volatilities, as well as pricing adjustments for specific delivery locations, and are generally assigned a Level 2 classification. When contracts relate to inactive delivery locations or extend to periods beyond those readily observable on active exchanges, the significance of the use of less observable inputs on a valuation is evaluated and may result in Level 3 classification.
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 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.
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Unrealized gains for the nuclear decommissioning fund were $1.4 billion and $1.2 billion as of Sept. 30, 2024 and Dec. 31, 2023, respectively, and unrealized losses were $23 million and $29 million as of Sept. 30, 2024 and Dec. 31, 2023, respectively.
Non-derivative instruments with recurring fair value measurements in the nuclear decommissioning fund:

|  | Sept. 30, 2024
|  |  |  | Fair Value
(Millions of Dollars) |  | Cost |  | Level 1 |  | Level 2 |  | Level 3 |  | NAV |  | Total
Nuclear decommissioning fund (a)
Cash equivalents |  | $ | 42 |  |  | $ | 42 |  |  | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | 42 |
Commingled funds |  | 711 |  |  | — |  |  | — |  |  | — |  |  | 1,046 |  |  | 1,046 |
Debt securities |  | 850 |  |  | — |  |  | 848 |  |  | 17 |  |  | — |  |  | 865 |
Equity securities |  | 521 |  |  | 1,586 |  |  | 2 |  |  | — |  |  | — |  |  | 1,588 |
Total |  | $ | 2,124 |  |  | $ | 1,628 |  |  | $ | 850 |  |  | $ | 17 |  |  | $ | 1,046 |  |  | $ | 3,541 |

(a)Reported in nuclear decommissioning fund and other investments on the consolidated balance sheets, which also includes $247 million of equity method investments and $159 million of rabbi trust assets and other miscellaneous investments.

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

(a)Reported in nuclear decommissioning fund and other investments on the consolidated balance sheets, which also includes $244 million of equity investments in unconsolidated subsidiaries and $144 million of rabbi trust assets and other miscellaneous investments.
For the three and nine months ended Sept. 30, 2024 and 2023, there were no transfers of Level 3 investments between levels.
Contractual maturity dates of debt securities in the nuclear decommissioning fund as of Sept. 30, 2024:

|  | Final Contractual Maturity
(Millions of Dollars) |  | Due in 1 Year or Less |  | Due in 1 to 5 Years |  | Due in 5 to 10 Years |  | Due after 10 Years |  | Total
Debt securities |  | $ | 9 |  |  | $ | 303 |  |  | $ | 277 |  |  | $ | 276 |  |  | $ | 865 |

Rabbi Trusts
Xcel Energy has established rabbi trusts to provide partial funding for future distributions of a deferred compensation plan. The fair value of assets held in the rabbi trusts were $100 million and $88 million at Sept. 30, 2024 and Dec. 31, 2023, respectively, comprised of cash equivalents and mutual funds (level 1 valuation methods). Amounts are reported in nuclear decommissioning fund and other investments on the consolidated balance sheet.
Derivative Activities and Fair Value Measurements
Xcel Energy enters into derivative instruments, including forward contracts, futures, swaps and options, for trading purposes and to manage risk in connection with changes in interest rates, and utility commodity prices.
Interest Rate Derivatives — Xcel Energy enters into contracts that effectively fix the interest rate on a specified principal amount of a hypothetical future debt issuance. These financial swaps net settle based on changes in a specified benchmark interest rate, acting as a hedge of changes in market interest rates that will impact specified anticipated debt issuances. These derivative instruments are designated as cash flow hedges for accounting purposes, with changes in fair value prior to occurrence of the hedged transactions recorded as other comprehensive income.
As of Sept. 30, 2024, accumulated other comprehensive loss related to interest rate derivatives included $1 million of net losses expected to be reclassified into earnings during the next 12 months as the hedged transactions impact earnings. As of Sept. 30, 2024, Xcel Energy had no unsettled interest rate swaps outstanding.
See Note 11 for the financial impact of qualifying interest rate cash flow hedges on Xcel Energy’s accumulated other comprehensive loss included in the consolidated statements of common stockholder’s equity and in the consolidated statements of comprehensive income.
Wholesale and Commodity Trading — Xcel Energy Inc.’s utility subsidiaries conduct various wholesale and commodity trading activities, including the purchase and sale of electric capacity, energy, energy-related instruments and natural gas-related instruments, including derivatives. Xcel Energy is allowed to conduct these activities within guidelines and limitations as approved by its risk management committee, comprised of management personnel not directly involved in the activities governed by this policy.
Results of derivative instrument transactions entered into for trading purposes are presented in the consolidated statements of income as electric revenues, net of any sharing with customers. These activities are not intended to mitigate commodity price risk associated with regulated electric and natural gas operations. Sharing of these margins is determined through state regulatory proceedings as well as the operation of the FERC-approved joint operating agreement.
Commodity Derivatives — Xcel Energy enters into derivative instruments to manage variability of future cash flows from changes in commodity prices in its electric and natural gas operations. This could include the purchase or sale of energy or energy-related products, natural gas to generate electric energy, natural gas for resale and FTRs.
The most significant derivative positions outstanding at Sept. 30, 2024 and Dec. 31, 2023 for this purpose relate to FTR instruments administered by MISO and SPP. These instruments are intended to offset the impacts of transmission system congestion.
When Xcel Energy enters into derivative instruments that mitigate commodity price risk on behalf of electric and natural gas customers, the instruments are not typically designated as qualifying hedging transactions. The classification of unrealized losses or gains on these instruments as a regulatory asset or liability, if applicable, is based on approved regulatory recovery mechanisms.
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As of Sept. 30, 2024, Xcel Energy had no commodity contracts designated as cash flow hedges.
Gross notional amounts of commodity forwards, options and FTRs:

(Amounts in Millions) (a)(b) |  | Sept. 30, 2024 |  | Dec. 31, 2023
Megawatt hours of electricity |  | 56 |  |  | 48 |
Million British thermal units of natural gas |  | 82 |  |  | 84 |

(a)Not reflective of net positions in the underlying commodities.
(b)Notional amounts for options included on a gross basis but weighted for the probability of exercise.
Consideration of Credit Risk and Concentrations — Xcel Energy continuously monitors the creditworthiness of counterparties to its interest rate derivatives and commodity derivative contracts prior to settlement and assesses each counterparty’s ability to perform on the transactions set forth in the contracts. Impact of credit risk was immaterial to the fair value of unsettled commodity derivatives presented on the consolidated balance sheets.
Xcel Energy’s utility subsidiaries’ most significant concentrations of credit risk with particular entities or industries are contracts with counterparties to their wholesale, trading and non-trading commodity activities.
As of Sept. 30, 2024, four of Xcel Energy’s ten most significant counterparties for these activities, comprising $39 million, or 23%, of this credit exposure, had investment grade credit ratings from S&P Global Ratings, Moody’s Investor Services or Fitch Ratings.
Five of the ten most significant counterparties, comprising $59 million, or 35%, 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 $36 million, or 22%, 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 Sept. 30, 2024 and Dec. 31, 2023, there were $10 million and $12 million, of derivative liabilities with such underlying contract provisions, respectively.
Certain contracts also contain cross default provisions that may require the posting of collateral or settlement of the contracts if there was a failure under other financing arrangements related to payment terms or other covenants.
As of Sept. 30, 2024 and Dec. 31, 2023, there were approximately $65 million and $88 million of derivative liabilities with such underlying contract provisions, respectively.
Certain derivative instruments are also subject to contract provisions that contain adequate assurance clauses. These provisions allow counterparties to seek performance assurance, including cash collateral, in the event that a given utility subsidiary’s ability to fulfill its contractual obligations is reasonably expected to be impaired.
Xcel Energy had no collateral posted related to adequate assurance clauses in derivative contracts as of Sept. 30, 2024 and Dec. 31, 2023.
Recurring Derivative Fair Value Measurements
Impact of derivative activity:

|  | Pre-Tax Fair Value Gains (Losses) Recognized During the Period in:
(Millions of Dollars) |  | Accumulated Other Comprehensive Loss |  | Regulatory Assets and Liabilities
Three Months Ended Sept. 30, 2024 |  |  |  |
Other derivative instruments: |  |  |  |
Natural gas commodity |  | $ | — |  |  | $ | (6) |
Total |  | $ | — |  |  | $ | (6) |
Nine Months Ended Sept. 30, 2024 |  |  |  |
Derivatives designated as cash flow hedges: |  |
Interest rate |  | $ | 29 |  |  | $ | — |
Total |  | $ | 29 |  |  | $ | — |
Other derivative instruments: |  |  |  |
Electric commodity |  | $ | — |  |  | $ | 41 |
Natural gas commodity |  | — |  |  | (3) |
Total |  | $ | — |  |  | $ | 38 |
Three Months Ended Sept. 30, 2023 |  |  |  |
Derivatives designated as cash flow hedges: |  |  |  |
Interest rate |  | $ | 4 |  |  | $ | — |
Total |  | $ | 4 |  |  | $ | — |
Other derivative instruments: |  |  |  |
Electric commodity |  | $ | — |  |  | $ | (23) |
Natural gas commodity |  | — |  |  | (5) |
Total |  | $ | — |  |  | $ | (28) |
Nine Months Ended Sept. 30, 2023 |  |  |  |
Derivatives designated as cash flow hedges: |  |
Interest rate |  | $ | 15 |  |  | $ | — |
Total |  | $ | 15 |  |  | $ | — |
Other derivative instruments: |  |  |  |
Electric commodity |  | $ | — |  |  | $ | (134) |
Natural gas commodity |  | — |  |  | (1) |
Total |  | $ | — |  |  | $ | (135) |

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|  | Pre-Tax (Gains) Losses Reclassified into Income During the Period from: |  | Pre-Tax Gains (Losses) Recognized During the Period in Income
(Millions of Dollars) |  | Accumulated Other Comprehensive Loss |  | Regulatory Assets and Liabilities |
Three Months Ended Sept. 30, 2024 |  |  |  |  |
Derivatives designated as cash flow hedges:
Interest rate |  | $ | 1 |  | (a) | $ | — |  |  | $ | — |  |
Total |  | $ | 1 |  |  | $ | — |  |  | $ | — |  |
Other derivative instruments: |  |  |  |  |
Commodity trading |  | $ | — |  |  | $ | — |  |  | $ | 3 |  | (b)
Electric commodity |  | — |  |  | (13) |  | (c) | — |  |
Total |  | $ | — |  |  | $ | (13) |  |  | $ | 3 |  |
Nine Months Ended Sept. 30, 2024 |  |  |  |  |
Derivatives designated as cash flow hedges:
Interest rate |  | $ | 3 |  | (a) | $ | — |  |  | $ | — |  |
Total |  | $ | 3 |  |  | $ | — |  |  | $ | — |  |
Other derivative instruments: |  |  |  |  |
Commodity trading |  | $ | — |  |  | $ | — |  |  | $ | (19) |  | (b)
Electric commodity |  | — |  |  | (16) |  | (c) | — |  |
Natural gas commodity |  | — |  |  | — |  |  | (14) |  | (d)(e)
Total |  | $ | — |  |  | $ | (16) |  |  | $ | (33) |  |
Three Months Ended Sept. 30, 2023 |  |  |  |  |
Derivatives designated as cash flow hedges:
Interest rate |  | $ | 1 |  | (a) | $ | — |  |  | $ | — |  |
Total |  | $ | 1 |  |  | $ | — |  |  | $ | — |  |
Other derivative instruments: |  |  |  |  |
Electric commodity |  | — |  |  | 15 |  | (c) | — |  |
Total |  | $ | — |  |  | $ | 15 |  |  | $ | — |  |
Nine Months Ended Sept. 30, 2023 |  |  |  |  |
Derivatives designated as cash flow hedges:
Interest rate |  | $ | 4 |  | (a) | $ | — |  |  | $ | — |  |
Total |  | $ | 4 |  |  | $ | — |  |  | $ | — |  |
Other derivative instruments:
Commodity trading |  | $ | — |  |  | $ | — |  |  | $ | (6) |  | (b)
Electric commodity |  | — |  |  | 109 |  | (c) | — |  |
Natural gas commodity |  | — |  |  | 11 |  | (d) | (19) |  | (d)(e)
Total |  | $ | — |  |  | $ | 120 |  |  | $ | (25) |  |

(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 2024 losses recorded to electric fuel and purchased power, amounts are recorded to cost of natural gas sold and transported. Amounts are subject to cost-recovery mechanisms and reclassified out of income to a regulatory asset, as appropriate.
(e)Relates primarily to option premium amortization.
Xcel Energy had no derivative instruments designated as fair value hedges during the nine months ended Sept. 30, 2024 and 2023.
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Derivative assets and liabilities measured at fair value on a recurring basis were as follows:

|  | Sept. 30, 2024 |  | Dec. 31, 2023
|  | Fair Value |  | Fair Value Total |  | Netting (a) |  | Total |  | Fair Value |  | Fair Value Total |  | Netting (a) |  | Total
(Millions of Dollars) |  | Level 1 |  | Level 2 |  | Level 3 |  |  |  |  | Level 1 |  | Level 2 |  | Level 3 |  |  |
Current derivative assets |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Other derivative instruments: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Commodity trading |  | $ | 5 |  |  | $ | 21 |  |  | $ | 10 |  |  | $ | 36 |  |  | $ | (25) |  |  | $ | 11 |  |  | $ | 8 |  |  | $ | 51 |  |  | $ | 32 |  |  | $ | 91 |  |  | $ | (59) |  |  | $ | 32 |
Electric commodity |  | — |  |  | — |  |  | 151 |  |  | 151 |  |  | (2) |  |  | 149 |  |  | — |  |  | — |  |  | 62 |  |  | 62 |  |  | (7) |  |  | 55 |
Natural gas commodity |  | — |  |  | 18 |  |  | — |  |  | 18 |  |  | — |  |  | 18 |  |  | — |  |  | 14 |  |  | — |  |  | 14 |  |  | — |  |  | 14 |
Total current derivative assets |  | $ | 5 |  |  | $ | 39 |  |  | $ | 161 |  |  | $ | 205 |  |  | $ | (27) |  |  | 178 |  |  | $ | 8 |  |  | $ | 65 |  |  | $ | 94 |  |  | $ | 167 |  |  | $ | (66) |  |  | 101 |
PPAs (b) |  |  |  |  |  |  |  |  |  |  |  | 1 |  |  |  |  |  |  |  |  |  |  |  |  | 3 |
Current derivative instruments |  |  |  |  |  |  |  |  |  |  |  | $ | 179 |  |  |  |  |  |  |  |  |  |  |  |  | $ | 104 |
Noncurrent derivative assets |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Other derivative instruments: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Commodity trading |  | $ | 9 |  |  | $ | 32 |  |  | $ | 43 |  |  | $ | 84 |  |  | $ | (21) |  |  | $ | 63 |  |  | $ | 14 |  |  | $ | 51 |  |  | $ | 45 |  |  | $ | 110 |  |  | $ | (34) |  |  | $ | 76 |
Total noncurrent derivative assets |  | $ | 9 |  |  | $ | 32 |  |  | $ | 43 |  |  | $ | 84 |  |  | $ | (21) |  |  | $ | 63 |  |  | $ | 14 |  |  | $ | 51 |  |  | $ | 45 |  |  | $ | 110 |  |  | $ | (34) |  |  | $ | 76 |

|  | Sept. 30, 2024 |  | Dec. 31, 2023
|  | Fair Value |  | Fair Value Total |  | Netting (a) |  | Total |  | Fair Value |  | Fair Value Total |  | Netting (a) |  | Total
(Millions of Dollars) |  | Level 1 |  | Level 2 |  | Level 3 |  |  |  |  | Level 1 |  | Level 2 |  | Level 3 |  |  |
Current derivative liabilities |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Derivatives designated as cash flow hedges: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Interest rate |  | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | 17 |  |  | $ | — |  |  | $ | 17 |  |  | $ | — |  |  | $ | 17 |
Other derivative instruments: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Commodity trading |  | $ | 6 |  |  | $ | 38 |  |  | $ | 6 |  |  | $ | 50 |  |  | $ | (25) |  |  | $ | 25 |  |  | $ | 6 |  |  | $ | 86 |  |  | $ | 5 |  |  | $ | 97 |  |  | $ | (60) |  |  | $ | 37 |
Electric commodity |  | — |  |  | — |  |  | 2 |  |  | 2 |  |  | (2) |  |  | — |  |  | — |  |  | — |  |  | 7 |  |  | 7 |  |  | (7) |  |  | — |
Natural gas commodity |  | — |  |  | 7 |  |  | — |  |  | 7 |  |  | — |  |  | 7 |  |  | — |  |  | 12 |  |  | — |  |  | 12 |  |  | — |  |  | 12 |
Total current derivative liabilities |  | $ | 6 |  |  | $ | 45 |  |  | $ | 8 |  |  | $ | 59 |  |  | $ | (27) |  |  | 32 |  |  | $ | 6 |  |  | $ | 115 |  |  | $ | 12 |  |  | $ | 133 |  |  | $ | (67) |  |  | 66 |
PPAs (b) |  |  |  |  |  |  |  |  |  |  |  | 6 |  |  |  |  |  |  |  |  |  |  |  |  | 8 |
Current derivative instruments |  |  |  |  |  |  |  |  |  |  |  | $ | 38 |  |  |  |  |  |  |  |  |  |  |  |  | $ | 74 |
Noncurrent derivative liabilities |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Other derivative instruments: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Commodity trading |  | $ | 11 |  |  | $ | 29 |  |  | $ | 34 |  |  | $ | 74 |  |  | $ | (24) |  |  | $ | 50 |  |  | $ | 16 |  |  | $ | 50 |  |  | $ | 37 |  |  | $ | 103 |  |  | $ | (39) |  |  | $ | 64 |
Total noncurrent derivative liabilities |  | $ | 11 |  |  | $ | 29 |  |  | $ | 34 |  |  | $ | 74 |  |  | $ | (24) |  |  | 50 |  |  | $ | 16 |  |  | $ | 50 |  |  | $ | 37 |  |  | $ | 103 |  |  | $ | (39) |  |  | 64 |
PPAs (b) |  |  |  |  |  |  |  |  |  |  |  | 18 |  |  |  |  |  |  |  |  |  |  |  |  | 22 |
Noncurrent derivative instruments |  |  |  |  |  |  |  |  |  |  |  | $ | 68 |  |  |  |  |  |  |  |  |  |  |  |  | $ | 86 |

(a)Xcel Energy nets derivative instruments and related collateral on its consolidated balance sheets when supported by a legally enforceable master netting agreement. At Sept. 30, 2024 and Dec. 31, 2023, derivative assets and liabilities include no obligations to return cash collateral. At Sept. 30, 2024 and Dec. 31, 2023, derivative assets and liabilities include rights to reclaim cash collateral of $3 million and $7 million, respectively. Counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements.
(b)Xcel Energy currently applies the normal purchase exception to qualifying PPAs. Balance relates to specific contracts that were previously recognized at fair value prior to applying the normal purchase exception, and are being amortized over the remaining contract lives along with the offsetting regulatory assets and liabilities.
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Changes in Level 3 commodity derivatives:

|  | Three Months Ended Sept 30
(Millions of Dollars) |  | 2024 |  | 2023
Balance at July 1 |  | $ | 239 |  |  | $ | 209 |
Purchases (a) |  | 2 |  |  | 1 |
Settlements (a) |  | (76) |  |  | (50) |
Net transactions recorded during the period: |  |  |  |
(Losses) gains recognized in earnings (b) |  | (9) |  |  | 18 |
Net gains (losses) recognized as regulatory assets and liabilities (a) |  | 6 |  |  | (36) |
Balance at Sept. 30 |  | $ | 162 |  |  | $ | 142 |
|  | Nine Months Ended Sept 30
(Millions of Dollars) |  | 2024 |  | 2023
Balance at Jan. 1 |  | $ | 90 |  |  | $ | 236 |
Purchases (a) |  | 179 |  |  | 173 |
Settlements (a) |  | (237) |  |  | (126) |
Net transactions recorded during the period: |  |  |  |
(Losses) gains recognized in earnings (b) |  | (6) |  |  | 16 |
Net gains (losses) recognized as regulatory assets and liabilities (a) |  | 136 |  |  | (157) |
Balance at Sept. 30 |  | $ | 162 |  |  | $ | 142 |

(a)Relates primarily to NSP-Minnesota and SPS FTR instruments administered by MISO and SPP.
(b)Relates to commodity trading and is subject to substantial offsetting losses and gains on derivative instruments categorized as levels 1 and 2 in the income statement. See above tables for the income statement impact of derivative activity, including commodity trading gains and losses.
Fair Value of Long-Term Debt
As of Sept. 30, 2024, other financial instruments for which the carrying amount did not equal fair value:

|  | Sept. 30, 2024 |  | Dec. 31, 2023
(Millions of Dollars) |  | Carrying Amount |  | Fair Value |  | Carrying Amount |  | Fair Value
Long-term debt, including current portion |  | $ | 28,575 |  |  | $ | 26,619 |  |  | $ | 25,465 |  |  | $ | 22,927 |

Fair value of Xcel Energy’s long-term debt is estimated based on recent trades and observable spreads from benchmark interest rates for similar securities. Fair value estimates are based on information available to management as of Sept. 30, 2024 and Dec. 31, 2023, and given the observability of the inputs, fair values presented for long-term debt were assigned as Level 2.

9. Benefit Plans and Other Postretirement Benefits

Components of Net Periodic Benefit Cost (Credit)

|  | Three Months Ended Sept. 30
|  | 2024 |  | 2023 |  | 2024 |  | 2023
(Millions of Dollars) |  | Pension Benefits |  | Postretirement Health Care Benefits
Service cost |  | $ | 19 |  |  | $ | 18 |  |  | $ | — |  |  | $ | — |
Interest cost (a) |  | 37 |  |  | 39 |  |  | 6 |  |  | 6 |
Expected return on plan assets (a) |  | (52) |  |  | (52) |  |  | (4) |  |  | (4) |
Amortization of net loss (a) |  | 7 |  |  | 6 |  |  | — |  |  | — |
Settlement charge (b) |  | 6 |  |  | — |  |  | — |  |  | — |
Net periodic benefit cost |  | 17 |  |  | 11 |  |  | 2 |  |  | 2 |
Effects of regulation |  | (1) |  |  | 11 |  |  | — |  |  | — |
Net benefit cost recognized for financial reporting |  | $ | 16 |  |  | $ | 22 |  |  | $ | 2 |  |  | $ | 2 |

|  | Nine Months Ended Sept. 30
|  | 2024 |  | 2023 |  | 2024 |  | 2023
(Millions of Dollars) |  | Pension Benefits |  | Postretirement Health Care Benefits
Service cost |  | $ | 57 |  |  | $ | 55 |  |  | $ | 1 |  |  | $ | 1 |
Interest cost (a) |  | 113 |  |  | 119 |  |  | 16 |  |  | 17 |
Expected return on plan assets (a) |  | (155) |  |  | (157) |  |  | (13) |  |  | (13) |
Amortization of prior service credit (a) |  | (1) |  |  | (1) |  |  | — |  |  | (1) |
Amortization of net loss (a) |  | 22 |  |  | 17 |  |  | 1 |  |  | 1 |
Settlement charge (b) |  | 62 |  |  | — |  |  | — |  |  | — |
Net periodic benefit cost |  | 98 |  |  | 33 |  |  | 5 |  |  | 5 |
Effects of regulation |  | (37) |  |  | 25 |  |  | — |  |  | — |
Net benefit cost recognized for financial reporting |  | $ | 61 |  |  | $ | 58 |  |  | $ | 5 |  |  | $ | 5 |

(a)The components of net periodic cost other than the service cost component are included in the line item “Other income, net” in the consolidated statements of income or capitalized on the consolidated balance sheets as a regulatory asset.
(b)A settlement charge is required when the amount of lump-sum distributions during the year is greater than the sum of the service and interest cost components of the annual net periodic pension cost. In the three and nine months ended Sept. 30, 2024, as a result of lump-sum distributions during the 2024 plan year, Xcel Energy recorded a pension settlement charge of $6 million and $62 million, respectively, the majority of which was not recognized due to the effects of regulation. A total of $1 million and $8 million was recognized in the consolidated statement of income for the three and nine months ended Sept. 30, 2024.
In January 2024, contributions totaling $100 million were made across Xcel Energy’s pension plans. Xcel Energy does not expect additional pension contributions during 2024.

10. Commitments and Contingencies

Legal
Xcel Energy is involved in various litigation matters in the ordinary course of business. The assessment of whether a loss is probable or is a reasonable possibility, and whether the loss or a range of loss is estimable, often involves a series of complex judgments about future events. Management maintains accruals for losses probable of being incurred and subject to reasonable estimation.
Management is sometimes unable to estimate an amount or range of a reasonably possible loss in certain situations, including but not limited to when (1) the damages sought are indeterminate, (2) the proceedings are in the early stages, or (3) the matters involve novel or unsettled legal theories.
In such cases, there is considerable uncertainty regarding the timing or ultimate resolution, including a possible eventual loss. For current proceedings not specifically reported herein, management does not anticipate that the ultimate liabilities, if any, would have a material effect on Xcel Energy’s consolidated financial statements. Legal fees are generally expensed as incurred.
Gas Trading Litigation — e prime is a wholly owned subsidiary of Xcel Energy. e prime was in the business of natural gas trading and marketing but has not engaged in natural gas trading or marketing activities since 2003. Multiple lawsuits involving multiple plaintiffs seeking monetary damages were commenced against e prime and its affiliates, including Xcel Energy, between 2003 and 2009 alleging fraud and anticompetitive activities in conspiring to restrain the trade of natural gas and manipulate natural gas prices. Cases were all consolidated in the U.S. District Court in Nevada.
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One case remains active which includes a multi-district litigation matter consisting of a Wisconsin purported class (Arandell Corp.). The Court issued a ruling in June 2022 granting plaintiffs’ class certification. In April 2023, the Seventh Circuit Court of Appeals heard the defendants’ appeal challenging whether the district court properly assessed class certification. A decision relating to class certification is expected imminently. Xcel Energy considers the reasonably possible loss associated with this litigation to be immaterial.
Comanche Unit 3 Litigation — In 2021, CORE filed a lawsuit in Denver County District Court, alleging PSCo breached ownership agreement terms by failing to operate Comanche Unit 3 in accordance with prudent utility practices. In April 2022, CORE filed a supplement to include damages related to a 2022 outage. Also in 2022, CORE sent notice of withdrawal from the ownership agreement based on the same alleged breaches.
In October 2023, the jury ruled that CORE may not withdraw as a joint owner of the facility but awarded CORE lost power damages of $26 million. PSCo recognized $35 million of losses for the verdict in 2023, including estimated interest and other costs. In October 2024, PSCo and CORE reached a settlement, and parties have agreed to withdraw their appeals pending with the Colorado Court of Appeals.
Marshall Wildfire Litigation — In December 2021, a wildfire ignited in Boulder County, Colorado (Marshall Fire), which burned over 6,000 acres and destroyed or damaged over 1,000 structures. On June 8, 2023, the Boulder County Sheriff’s Office released its Marshall Fire Investigative Summary and Review and its supporting documents (Sheriff’s Report). According to an October 2022 statement from the Colorado Insurance Commissioner, the Marshall Fire is estimated to have caused more than $2 billion in property losses.
According to the Sheriff’s Report, on Dec. 30, 2021, a fire ignited on a residential property in Boulder, Colorado, located in PSCo’s service territory, for reasons unrelated to PSCo’s power lines. According to the Sheriff’s Report, approximately one hour and 20 minutes after the first ignition, a second fire ignited just south of the Marshall Mesa Trailhead in unincorporated Boulder County, Colorado, also located in PSCo’s service territory. According to the Sheriff’s Report, the second ignition started approximately 80 to 110 feet away from PSCo’s power lines in the area.
The Sheriff’s Report states that the most probable cause of the second ignition was hot particles discharged from PSCo’s power lines after one of the power lines detached from its insulator in strong winds, and further states that it cannot be ruled out that the second ignition was caused by an underground coal fire. According to the Sheriff’s Report, no design, installation or maintenance defects or deficiencies were identified on PSCo’s electrical circuit in the area of the second ignition. PSCo disputes that its power lines caused the second ignition.
PSCo is aware of 307 complaints, most of which have also named Xcel Energy Inc. and Xcel Energy Services Inc. as additional defendants, relating to the Marshall Fire. The complaints are on behalf of at least 4,087 plaintiffs. The complaints generally allege that PSCo’s equipment ignited the Marshall Fire and assert various causes of action under Colorado law, including negligence, premises liability, trespass, nuisance, wrongful death, willful and wanton conduct, negligent infliction of emotional distress, loss of consortium and inverse condemnation. In addition to seeking compensatory damages, certain of the complaints also seek exemplary damages.
In September 2023, the Boulder County District Court Judge consolidated the pending lawsuits into a single action for pretrial purposes and has subsequently consolidated additional lawsuits that have been filed. At the case management conference in February 2024, a trial date was set for September 2025. Discovery is now underway.
In September 2024, the Judge presiding over the consolidated cases in Boulder County issued an order regarding the trial that resolves, on a preliminary basis, certain disputes over the structure of the September 2025 trial. The Court ruled that all Plaintiffs should be bound by a trial on liability unless they opt-out with good cause. The Court also ruled that liability and damages should be largely or entirely tried separately, meaning that common questions of law and fact regarding liability would be decided first, and a majority or all of the damages phase will occur separately following the liability phase of trial. The individual plaintiffs filed a motion for reconsideration of the opt-out portion of this order, which is currently before the Court.
Colorado courts do not apply strict liability in determining an electric utility company’s liability for fire-related damages. For inverse condemnation claims, Colorado courts assess whether a defendant acted with intent to take a plaintiff’s property or intentionally took an action which has the natural consequence of taking the property. For negligence claims, Colorado courts look to whether electric power companies have operated their system with a heightened duty of care consistent with the practical conduct of its business, and liability does not extend to occurrences that cannot be reasonably anticipated.
Colorado law does not impose joint and several liability in tort actions. Instead, under Colorado law, a defendant is liable for the degree or percentage of the negligence or fault attributable to that defendant, except where the defendant conspired with another defendant. A jury’s verdict in a Colorado civil case must be unanimous. Under Colorado law, in a civil action filed before Jan. 1, 2025, other than a medical malpractice action, the total award for noneconomic loss is capped at $0.6 million per defendant unless the court finds justification to exceed that amount by clear and convincing evidence, in which case the maximum doubles.
Colorado law caps punitive or exemplary damages to an amount equal to the amount of the actual damages awarded to the injured party, except the court may increase any award of punitive damages to a sum up to three times the amount of actual damages if the conduct that is the subject of the claim has continued during the pendency of the case or the defendant has acted in a willful and wanton manner during the action which further aggravated plaintiff’s damages.
In the event Xcel Energy Inc. or PSCo was found liable related to this litigation and were required to pay damages, such amounts could exceed our insurance coverage of approximately $500 million and have a material adverse effect on our financial condition, results of operations or cash flows. However, due to uncertainty as to the cause of the fire and the extent and magnitude of potential damages, Xcel Energy Inc. and PSCo are unable to estimate the amount or range of possible losses in connection with the Marshall Fire.
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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 23 complaints, most of which have also named Xcel Energy Services Inc. as an additional defendant, relating to the Smokehouse Creek Fire Complex, including one putative class action on behalf of persons or entities who owned rangelands or pastures that were damaged by the fire. The complaints generally allege that SPS’ equipment ignited the Smokehouse Creek Fire Complex and seek compensation for losses resulting from the fire, asserting various causes of action under Texas law. In addition to seeking compensatory damages, certain of the complaints also seek exemplary damages. SPS has also received approximately 179 claims for losses related to the Smokehouse Creek Fire Complex through its claims process and has reached final settlements on 86 of those claims. In addition to filed complaints and claims made through SPS’ claims process, SPS has also received information from attorneys for claims related to the Smokehouse Creek Fire Complex which have not been submitted through the claims process and have also not been filed as lawsuits. SPS anticipates additional complaints and demands will be made. In July 2024, SPS reached a settlement of a complaint related to one of the two fatalities believed to be associated with the Smokehouse Creek Fire Complex.
Texas law does not apply strict liability in determining an electric utility company’s liability for fire-related damages. For negligence claims under Texas law, a public utility has a duty to exercise ordinary and reasonable care.
Potential liabilities related to the Smokehouse Creek Fire Complex depend on various factors, including the cause of the equipment failure and the extent and magnitude of potential damages, including damages to residential and commercial structures, personal property, vegetation, livestock and livestock feed (including replacement feed), personal injuries and any other damages, penalties, fines or restitution that may be imposed by courts or other governmental entities if SPS is found to have been negligent.
Based on the current state of the law and the facts and circumstances available as of the date of this filing, Xcel Energy believes it is probable that it will incur a loss in connection with the Smokehouse Creek Fire Complex and accordingly has accrued a $215 million estimated loss for the matter (before available insurance), presented in other current liabilities as of Sept. 30, 2024.
The aggregate liability of $215 million for claims in connection with the Smokehouse Creek Fire Complex (before available insurance) corresponds to the lower end of the range of Xcel Energy’s reasonably estimable range of losses, and is subject to change based on additional information. This $215 million estimate does not include, among other things, amounts for (i) potential penalties or fines that may be imposed by governmental entities on Xcel Energy, (ii) exemplary or punitive damages, (iii) compensation claims by federal, state, county and local government entities or agencies, (iv) compensation claims for damage to trees, railroad lines, or oil and gas equipment, or (v) other amounts that are not reasonably estimable.
Xcel Energy remains unable to reasonably estimate any additional loss or the upper end of the range because there are a number of unknown facts and legal considerations that may impact the amount of any potential liability. In the event that SPS or Xcel Energy Services Inc. was found liable related to the litigation related to the Smokehouse Creek Fire Complex and was required to pay damages, such amounts could exceed our insurance coverage of approximately $500 million for the annual policy period and could have a material adverse effect on our financial condition, results of operations or cash flows.
The process for estimating losses associated with potential claims related to the Smokehouse Creek Fire Complex requires management to exercise significant judgment based on a number of assumptions and subjective factors, including the factors identified above and estimates based on currently available information and prior experience with wildfires. As more information becomes available, management estimates and assumptions regarding the potential financial impact of the Smokehouse Creek Fire Complex may change.
SPS records insurance recoveries when it is deemed probable that recovery will occur, and SPS can reasonably estimate the amount or range. SPS has recorded an insurance receivable for $215 million, presented within prepayments and other current assets as of Sept. 30, 2024. While SPS plans to seek recovery of all insured losses, it is unable to predict the ultimate amount and timing of such insurance recoveries.
Rate Matters and Other
Xcel Energy’s operating subsidiaries are involved in various regulatory proceedings arising in the ordinary course of business. Until resolution, typically in the form of a rate order, uncertainties may exist regarding the ultimate rate treatment for certain activities and transactions. Amounts have been recognized for probable and reasonably estimable losses that may result. Unless otherwise disclosed, any reasonably possible range of loss in excess of any recognized amount is not expected to have a material effect on the consolidated financial statements.
Sherco — In 2018, NSP-Minnesota and SMMPA (Co-owner of Sherco Unit 3) reached a settlement with GE related to a 2011 incident, which damaged the turbine at Sherco Unit 3 and resulted in an extended outage.
In March 2019, the MPUC approved NSP-Minnesota’s settlement refund proposal. Additionally, the MPUC decided to withhold any decision as to NSP-Minnesota’s prudence in connection with the incident at Sherco Unit 3 until after conclusion of an appeal pending between GE and NSP-Minnesota’s insurers. In February 2020, the Minnesota Court of Appeals affirmed the district court’s judgment in favor of GE.
In January 2021, the Minnesota Office of Attorney General and DOC recommended that NSP-Minnesota refund approximately $17 million of replacement power costs previously recovered through the FCA. NSP-Minnesota responded that it acted prudently in connection with the Sherco Unit 3 outage, the MPUC has previously disallowed $22 million of related costs and no additional refund or disallowance is appropriate.
In July 2022, the MPUC referred the matter to the Office of Administrative Hearings to conduct a contested case on the prudence of the replacement power costs incurred by NSP-Minnesota.
In May 2024, the ALJ recommended a customer refund of $34 million (less a portion of the proceeds received from the settlement with GE). The ALJ indicated that consideration of the $22 million of previously disallowed costs was not in the scope of their recommendation. In October 2024, the MPUC ordered customer refunds of $46 million, which is presented as a charge to electric revenues in the nine months ended Sept. 30, 2024.
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Minnesota 2023 Fuel Clause Adjustment — In March 2024, NSP-Minnesota filed its annual fuel clause adjustment true-up petition to the MPUC.
In 2024, the DOC recommended customer refunds for 2023 replacement power costs incurred during an outage at the Prairie Island generating station (October 2023 through February 2024). NSP-Minnesota estimates that customer refunds would be approximately $22 million if the DOC recommendations are applied to both 2023 and 2024.
In September 2024, the MPUC ruled NSP-Minnesota was imprudent in the operation of the Prairie Island nuclear plant based on an incident that resulted in the extended outage. The MPUC declined to quantify the refund and referred the determination of the refund amount to the Office of Administrative Hearings. A procedural schedule will be determined in the fourth quarter of 2024. NSP-Minnesota has recorded an estimated liability for a customer refund.
Environmental
New and changing federal and state environmental mandates can create financial obligations for Xcel Energy, which are normally recovered through the regulated rate process.
Site Remediation
Various federal and state environmental laws impose liability where hazardous substances or other regulated materials have been released to the environment. Xcel Energy Inc.’s subsidiaries may sometimes pay all or a portion of the cost to remediate sites where past activities of their predecessors or other parties have caused environmental contamination.
Environmental contingencies could arise from various situations, including sites of former MGPs; and third-party sites, such as landfills, for which one or more of Xcel Energy Inc.’s subsidiaries are alleged to have sent wastes to that site.
MGP, Landfill and Disposal Sites
Xcel Energy is investigating, remediating or performing post-closure actions at 13 historical MGP, landfill or other disposal sites across its service territories, in addition to sites that are being addressed under current coal ash regulations (see below).
Xcel Energy has recognized approximately $20 million of costs/liabilities for resolution of these issues; however, the final outcomes 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 may be required to perform additional groundwater investigations and/or perform corrective actions, typically beginning with an Assessment of Corrective Measures.
Investigation and/or corrective action related to groundwater impacts are currently underway at certain active and closed coal-fueled generating facilities at a current estimated cost of at least $40 million. In addition, Xcel Energy expects to incur $15 million for investigations through 2028 to perform required reporting and assess whether corrective actions are necessary. Asset retirement obligations have been recorded for each of these activities, and amounts are expected to be recoverable through regulatory mechanisms.
Xcel Energy has also identified coal ash that is expected to be required to be removed from certain closed coal-fueled generating facilities at estimated costs totaling approximately $100 million. Asset retirement obligations have been recorded, with the costs expected to be recoverable through regulatory mechanisms.
Xcel Energy continues to evaluate the 2024 updates to the CCR rule, the interpretations of those updates and how they will apply to specific sites. Assessment of the recent updates to the CCR Rule and corresponding site investigation activities may result in updates to estimated costs as well as identification of additional required corrective actions.
Clean Water Act Section 316(b) — The Federal Clean Water Act requires the EPA to regulate cooling water intake structures to assure they reflect the best technology available for minimizing impingement and entrainment of aquatic species.
Estimated capital expenditures of approximately $50 million may be required to comply with the requirements. Xcel Energy anticipates these costs will be recoverable through regulatory mechanisms.
Air
Clean Air Act NOx Allowance Allocations — In June 2023, the EPA published final regulations for ozone under the “Good Neighbor” provisions of the Clean Air Act. The final rule applies to generation facilities in Minnesota, Texas and Wisconsin, as well as other states outside of our service territory. In February 2024, the EPA proposed to include New Mexico in the rule. The rule establishes an allowance trading program for NOx that will impact Xcel Energy fossil fuel-fired electric generating facilities. Subject facilities will have to secure additional allowances, install NOx controls and/or develop a strategy of operations that utilizes the existing allowance allocations.
While the financial impacts of the final rule are uncertain and dependent on market forces and anticipated generation, Xcel Energy anticipates the annual costs could be significant, but would be recoverable through regulatory mechanisms.
In June 2024, the U.S. Supreme Court issued an order granting a stay of the final rule. In response, the EPA intends to issue an administrative stay of the rule nationwide. Depending on the outcomes of the underlying legal challenges, the regulation may become applicable in the future.
Leases
Xcel Energy evaluates contracts that may contain leases, including PPAs and arrangements for the use of office space, land for solar developments and other facilities, vehicles and equipment. A contract contains a lease if it conveys the exclusive right to control the use of a specific asset.
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Components of lease expense:

|  | Three Months Ended Sept. 30
(Millions of Dollars) |  | 2024 |  | 2023
Operating leases |  |  |  |
PPA capacity payments |  | $ | 57 |  |  | $ | 61 |
Other operating leases (a) |  | 11 |  |  | 11 |
Total operating lease expense (b) |  | $ | 68 |  |  | $ | 72 |
Finance leases |  |  |  |
Amortization of ROU assets |  | $ | 1 |  |  | $ | 1 |
Interest expense on lease liability |  | 4 |  |  | 4 |
Total finance lease expense |  | $ | 5 |  |  | $ | 5 |

(a)Includes short-term lease expense of $1 million and $3 million for 2024 and 2023, respectively.
(b)PPA capacity payments are included in electric fuel and purchased power on the consolidated statements of income. Expense for other operating leases is included in O&M expense and electric fuel and purchased power.

|  | Nine Months Ended Sept. 30
(Millions of Dollars) |  | 2024 |  | 2023
Operating leases |  |  |  |
PPA capacity payments |  | $ | 172 |  |  | $ | 182 |
Other operating leases (a) |  | 33 |  |  | 35 |
Total operating lease expense (b) |  | $ | 205 |  |  | $ | 217 |
Finance leases |  |  |  |
Amortization of ROU assets |  | $ | 3 |  |  | $ | 2 |
Interest expense on lease liability |  | 11 |  |  | 12 |
Total finance lease expense |  | $ | 14 |  |  | $ | 14 |

(a)Includes short-term lease expense of $3 million and $5 million for 2024 and 2023, respectively.
(b)PPA capacity payments are included in electric fuel and purchased power on the consolidated statements of income. Expense for other operating leases is included in O&M expense and electric fuel and purchased power.
Commitments under operating and finance leases as of Sept. 30, 2024:

(Millions of Dollars) |  | PPA Operating Leases |  | Other Operating Leases |  | Total Operating Leases |  | Finance Leases (a)
Total minimum obligation |  | $ | 1,037 |  |  | $ | 364 |  |  | $ | 1,401 |  |  | $ | 210 |
Interest component of obligation |  | (123) |  |  | (144) |  |  | (267) |  |  | (148) |
Present value of minimum obligation |  | $ | 914 |  |  | 220 |  |  | 1,134 |  |  | 62 |
Less current portion |  |  |  |  |  | (226) |  |  | (2) |
Noncurrent operating and finance lease liabilities |  |  |  |  |  | $ | 908 |  |  | $ | 60 |

(a)Excludes certain amounts related to Xcel Energy’s 50% ownership interest in WYCO.
Variable Interest Entities
Under certain PPAs, NSP-Minnesota, PSCo and SPS purchase power from IPPs for which the utility subsidiaries are required to reimburse fuel costs, or to participate in tolling arrangements under which the utility subsidiaries procure the natural gas required to produce the energy that they purchase. Xcel Energy has determined that certain IPPs are VIEs, however Xcel Energy is not subject to risk of loss from the operations of these entities, and no significant financial support is required other than contractual payments for energy and capacity.
In addition, certain solar PPAs provide an option to purchase emission allowances or sharing provisions related to production credits generated by the solar facility under contract. These specific PPAs create a variable interest in the IPP.
Xcel Energy evaluated each of these VIEs for possible consolidation, including review of qualitative factors such as the length and terms of the contract, control over O&M, control over dispatch of electricity, historical and estimated future fuel and electricity prices and financing activities. Xcel Energy concluded that these entities are not required to be consolidated in its consolidated financial statements because Xcel Energy does not have the power to direct the activities that most significantly impact the entities’ economic performance.
The utility subsidiaries had approximately 3,751 MW of capacity under long-term PPAs as of both Sept. 30, 2024 and Dec. 31, 2023, with entities that have been determined to be variable interest entities. The PPAs have expiration dates through 2041.
Other
Guarantees and Bond Indemnifications — Xcel Energy Inc. and its subsidiaries provide guarantees and bond indemnities, which guarantee payment or performance. Xcel Energy Inc.’s exposure is based upon the net liability under the specified agreements or transactions. Most of the guarantees and bond indemnities issued by Xcel Energy Inc. and its subsidiaries have a stated maximum amount.
As of Sept. 30, 2024 and Dec. 31, 2023, 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 $88 million and $75 million at Sept. 30, 2024 and Dec. 31, 2023, respectively.
Other Indemnification Agreements — Xcel Energy Inc. and its subsidiaries provide indemnifications through various contracts. These are primarily indemnifications against adverse litigation outcomes in connection with underwriting agreements, as well as breaches of representations and warranties, including corporate existence, transaction authorization and income tax matters with respect to assets sold.
Xcel Energy Inc.’s and its subsidiaries’ obligations under these agreements may be limited in terms of duration and amount. Maximum future payments under these indemnifications cannot be reasonably estimated as the dollar amounts are often not explicitly stated.
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11. Other Comprehensive Loss

Changes in accumulated other comprehensive loss, net of tax:

|  | Three Months Ended Sept. 30, 2024 |  | Three Months Ended Sept. 30, 2023
(Millions of Dollars) |  | Gains and Losses on Cash Flow Hedges |  | Defined Benefit Pension and Postretirement Items |  | Total |  | Gains and Losses on Cash Flow Hedges |  | Defined Benefit Pension and Postretirement Items |  | Total
Accumulated other comprehensive loss at July 1 |  | $ | (30) |  |  | $ | (37) |  |  | $ | (67) |  |  | $ | (44) |  |  | $ | (38) |  |  | $ | (82) |
Other comprehensive gain before reclassifications |  | — |  |  | — |  |  | — |  |  | 3 |  |  | — |  |  | 3 |
Losses reclassified from net accumulated other comprehensive loss: |  |  |  |  |  |  |  |  |  |  |  |
Interest rate derivatives (a) | 1 |  |  | — |  |  | 1 |  |  | 1 |  |  | — |  |  | 1 |
Net current period other comprehensive income |  | 1 |  |  | — |  |  | 1 |  |  | 4 |  |  | — |  |  | 4 |
Accumulated other comprehensive loss at Sept. 30 |  | $ | (29) |  |  | $ | (37) |  |  | $ | (66) |  |  | $ | (40) |  |  | $ | (38) |  |  | $ | (78) |

|  | Nine Months Ended Sept. 30, 2024 |  | Nine Months Ended Sept. 30, 2023
(Millions of Dollars) |  | Gains and Losses on Cash Flow Hedges |  | Defined Benefit Pension and Postretirement Items |  | Total |  | Gains and Losses on Cash Flow Hedges |  | Defined Benefit Pension and Postretirement Items |  | Total
Accumulated other comprehensive loss at Jan. 1 |  | $ | (53) |  |  | $ | (41) |  |  | $ | (94) |  |  | $ | (54) |  |  | $ | (39) |  |  | $ | (93) |
Other comprehensive gain before reclassifications |  | 22 |  |  | — |  |  | 22 |  |  | 11 |  |  | — |  |  | 11 |
Losses reclassified from net accumulated other comprehensive loss: |  |  |  |  |  |  |  |  |  |  |  |
Interest rate derivatives (a) |  | 2 |  |  | — |  |  | 2 |  |  | 3 |  |  | — |  |  | 3 |
Amortization of net actuarial losses (b) |  | — |  |  | 4 |  |  | 4 |  |  | — |  |  | 1 |  |  | 1 |
Net current period other comprehensive income |  | 24 |  |  | 4 |  |  | 28 |  |  | 14 |  |  | 1 |  |  | 15 |
Accumulated other comprehensive loss at Sept. 30 |  | $ | (29) |  |  | $ | (37) |  |  | $ | (66) |  |  | $ | (40) |  |  | $ | (38) |  |  | $ | (78) |

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

12. Segment Information

Xcel Energy evaluates performance by each utility subsidiary based on profit or loss generated from the product or service provided including the regulated electric utility operating results of NSP-Minnesota, NSP-Wisconsin, PSCo and SPS, as well as the regulated natural gas utility operating results of NSP-Minnesota, NSP-Wisconsin and PSCo.
These segments are managed separately because the revenue streams are dependent upon regulated rate recovery, which is separately determined for each segment.
Xcel Energy has the following reportable segments:
•Regulated Electric — The regulated electric utility segment generates, transmits and distributes electricity in Minnesota, Wisconsin, Michigan, North Dakota, South Dakota, Colorado, Texas and New Mexico. In addition, this segment includes sales for resale and provides wholesale transmission service to various entities in the United States. The regulated electric utility segment also includes wholesale commodity and trading operations.
•Regulated Natural Gas — The regulated natural gas utility segment transports, stores and distributes natural gas primarily in portions of Minnesota, Wisconsin, North Dakota, Michigan and Colorado.
Xcel Energy also presents All Other, which includes operating segments with revenues below the necessary quantitative thresholds. Those operating segments primarily include steam revenue, appliance repair services revenues/commissions, non-utility real estate activities, revenues associated with processing solid waste into refuse-derived fuel and investments in rental housing projects that qualify for low-income housing tax credits.
Xcel Energy had equity method investments of $247 million and $244 million as of Sept. 30, 2024 and Dec. 31, 2023, respectively, included in the natural gas utility and all other segments.
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.
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Xcel Energy’s segment information:

|  | Three Months Ended Sept. 30
(Millions of Dollars) |  | 2024 |  | 2023
Regulated Electric |  |  |  |
Total revenues |  | $ | 3,393 |  |  | $ | 3,387 |
Net income |  | 752 |  |  | 706 |
Regulated Natural Gas |  |  |  |
Total revenues |  | $ | 239 |  |  | $ | 245 |
Intersegment revenue |  | — |  |  | 1 |
Total revenues |  | $ | 239 |  |  | $ | 246 |
Net loss |  | (36) |  |  | (21) |
All Other |  |  |  |
Total revenues |  | $ | 12 |  |  | $ | 30 |
Net loss |  | (34) |  |  | (29) |
Consolidated Total |  |  |  |
Total revenues |  | $ | 3,644 |  |  | $ | 3,663 |
Reconciling eliminations |  | — |  |  | (1) |
Total operating revenues |  | $ | 3,644 |  |  | $ | 3,662 |
Net income |  | 682 |  |  | 656 |

|  | Nine Months Ended Sept. 30
(Millions of Dollars) |  | 2024 |  | 2023
Regulated Electric |  |  |  |
Operating revenues |  | $ | 8,737 |  |  | $ | 8,751 |
Intersegment revenue |  | 1 |  |  | — |
Total revenues |  | $ | 8,738 |  |  | $ | 8,751 |
Net income |  | 1,463 |  |  | 1,352 |
Regulated Natural Gas |  |  |  |
Operating revenues |  | $ | 1,535 |  |  | $ | 1,926 |
Intersegment revenue |  | 1 |  |  | 3 |
Total revenues |  | $ | 1,536 |  |  | $ | 1,929 |
Net income |  | 125 |  |  | 116 |
All Other |  |  |  |
Total revenues |  | $ | 49 |  |  | $ | 87 |
Net loss |  | (116) |  |  | (106) |
Consolidated Total |  |  |  |
Total revenues |  | $ | 10,323 |  |  | $ | 10,767 |
Reconciling eliminations |  | (2) |  |  | (3) |
Total operating revenues |  | $ | 10,321 |  |  | $ | 10,764 |
Net income |  | 1,472 |  |  | 1,362 |

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

The following discussion and analysis by management focuses on those factors that had a material effect on Xcel Energy’s financial condition, results of operations and cash flows during the periods presented or are expected to have a material impact in the future. It should be read in conjunction with the accompanying unaudited consolidated financial statements and the related notes to consolidated financial statements. Due to the seasonality of Xcel Energy’s operating results, quarterly financial results are not an appropriate base from which to project annual results.
The demand for electric power and natural gas is affected by seasonal differences in the weather. In general, peak sales of electricity occur in the summer months, and peak sales of natural gas occur in the winter months. As a result, the overall operating results may fluctuate substantially on a seasonal basis. Additionally, Xcel Energy’s operations have historically generated less revenues and income when weather conditions are milder in the winter and cooler in the summer.
Non-GAAP Financial Measures
The following discussion includes financial information prepared in accordance with GAAP, as well as certain non-GAAP financial measures such as ongoing earnings and ongoing diluted EPS. Generally, a non-GAAP financial measure is a measure of a company’s financial performance, financial position or cash flows that adjusts measures calculated and presented in accordance with GAAP.
Xcel Energy’s management uses non-GAAP measures for financial planning and analysis, for reporting of results to the Board of Directors, in determining performance-based compensation and communicating its earnings outlook to analysts and investors. Non-GAAP financial measures are intended to supplement investors’ understanding of our performance and should not be considered alternatives for financial measures presented in accordance with GAAP. These measures are discussed in more detail below and may not be comparable to other companies’ similarly titled non-GAAP financial measures.
Earnings Adjusted for Certain Items (Ongoing Earnings and Ongoing Diluted EPS)
GAAP diluted EPS reflects the potential dilution that could occur if securities or other agreements to issue common stock (i.e., common stock equivalents) were settled. The weighted average number of potentially dilutive shares outstanding used to calculate Xcel Energy Inc.’s diluted EPS is calculated using the treasury stock method.
Ongoing earnings reflect adjustments to GAAP earnings (net income) for certain items. Ongoing diluted EPS for Xcel Energy is calculated by dividing net income or loss, adjusted for certain items, by the weighted average fully diluted Xcel Energy Inc. common shares outstanding for the period. Ongoing diluted EPS for each subsidiary is calculated by dividing the net income or loss for such subsidiary, adjusted for certain items, by the weighted average fully diluted Xcel Energy Inc. common shares outstanding for the period.
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.
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The following table provides a reconciliation of GAAP earnings (net income to ongoing earnings:

|  | Three Months Ended Sept. 30 |  | Nine Months Ended Sept. 30
(Millions of Dollars) |  | 2024 |  | 2023 |  | 2024 |  | 2023
GAAP net income |  | $ | 682 |  |  | $ | 656 |  |  | $ | 1,472 |  |  | $ | 1,362 |
Loss on Comanche Unit 3 litigation |  | — |  |  | 34 |  |  | — |  |  | 34 |
Sherco Unit 3 2011 outage refunds |  | 35 |  |  | — |  |  | 46 |  |  | — |
Tax effect |  | (10) |  |  | (8) |  |  | (13) |  |  | (8) |
Ongoing earnings |  | $ | 707 |  |  | $ | 682 |  |  | $ | 1,505 |  |  | $ | 1,388 |

Sherco Unit 3 2011 Outage Refunds — NSP-Minnesota’s Sherco Unit 3 experienced an extended outage following a 2011 incident which damaged its turbine. In October 2024 following contested case procedures, the MPUC ordered a customer refund of $46 million for replacement power incurred during the outage.
Comanche Unit 3 Litigation — As a result of an Oct. 25, 2023 jury verdict in Denver County District Court awarding CORE lost power damages and other costs, PSCo recognized a $34 million loss for the matter in the third quarter of 2023. Given the non-recurring nature of this specific item, it has been excluded from ongoing earnings.

Results of Operations

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

|  | Three Months Ended Sept. 30 |  | Nine Months Ended Sept. 30
Diluted Earnings (Loss) Per Share |  | 2024 |  | 2023 |  | 2024 |  | 2023
NSP-Minnesota |  | $ | 0.45 |  |  | $ | 0.47 |  |  | $ | 1.06 |  |  | $ | 0.95 |
PSCo |  | 0.45 |  |  | 0.41 |  |  | 1.06 |  |  | 0.97 |
SPS |  | 0.31 |  |  | 0.30 |  |  | 0.58 |  |  | 0.55 |
NSP-Wisconsin |  | 0.07 |  |  | 0.06 |  |  | 0.19 |  |  | 0.18 |
Earnings from equity method investments — WYCO |  | 0.01 |  |  | 0.01 |  |  | 0.02 |  |  | 0.03 |
Regulated utility |  | 1.29 |  |  | 1.25 |  |  | 2.91 |  |  | 2.68 |
Xcel Energy Inc. and Other |  | (0.08) |  |  | (0.06) |  |  | (0.28) |  |  | (0.22) |
GAAP diluted EPS (a) |  | $ | 1.21 |  |  | $ | 1.19 |  |  | $ | 2.63 |  |  | $ | 2.47 |
Loss on Comanche Unit 3 litigation |  | — |  |  | 0.05 |  |  | — |  |  | 0.05 |
Sherco Unit 3 2011 outage refunds |  | 0.04 |  |  | $ | — |  |  | 0.06 |  |  | — |
Ongoing diluted EPS (a) |  | $ | 1.25 |  |  | $ | 1.23 |  |  | $ | 2.69 |  |  | $ | 2.52 |

(a)Amounts may not add due to rounding.
Summary of Earnings
Xcel Energy — Xcel Energy’s third quarter GAAP earnings were $1.21 per share, compared with $1.19 per share in the same period in 2023 and ongoing earnings were $1.25 per share in 2024, compared with $1.23 per share in 2023. The change in earnings per share was primarily driven by increased recovery of infrastructure investments, partially offset by higher depreciation, interest charges and O&M expenses. 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).
NSP-Minnesota — GAAP earnings decreased $0.02 per share and ongoing earnings increased 0.02 per share for the third quarter. Year-to-date GAAP earnings increased $0.11 per share and ongoing earnings increased $0.17 per share. Year-to-date earnings primarily reflect increased recovery of infrastructure investments (electric and natural gas), partially offset by higher depreciation and interest charges. See Note 6 for reconciliation from GAAP to ongoing earnings.
PSCo — GAAP earnings increased $0.04 per share and ongoing earnings increased $0.01 per share for the third quarter. Year-to-date GAAP earnings increased $0.09 per share and ongoing earnings increased $0.04 per share. Year-to-date ongoing earnings primarily reflect higher recovery of electric infrastructure investments, which was partially offset by increased interest charges, depreciation and O&M expenses.
SPS — GAAP and ongoing earnings increased $0.01 per share for the third quarter of 2024 and $0.03 year-to-date. Year-to-date earnings reflect the impact of regulatory rate outcomes and sales growth, partially offset by increased depreciation and O&M expenses.
NSP-Wisconsin — GAAP and ongoing earnings increased $0.01 per share for the third quarter of 2024 and year-to-date. Year-to-date earnings reflect the impact of electric infrastructure investment recoveries, partially offset by higher depreciation and interest expenses.
Xcel Energy Inc. and Other — Primarily includes financing costs and interest income at the holding company and earnings from investment funds, which are accounted for as equity method investments. The decline in earnings is largely due to increased interest rates and higher debt levels.
Changes in GAAP and Ongoing Diluted EPS
Components significantly contributing to changes in 2024 EPS compared to 2023:

Diluted Earnings (Loss) Per Share |  | Three Months Ended Sept. 30 |  | Nine Months Ended Sept. 30
GAAP diluted EPS — 2023 |  | $ | 1.19 |  |  | $ | 2.47 |
Components of change - 2024 vs. 2023 |  |  |  |
Electric regulatory rate outcomes and riders |  | 0.24 |  |  | 0.65 |
Higher AFUDC |  | 0.04 |  |  | 0.12 |
Natural gas regulatory rate outcomes and riders |  | 0.01 |  |  | 0.06 |
Loss on Comanche Unit 3 litigation |  | 0.05 |  |  | 0.05 |
Higher depreciation and amortization |  | (0.08) |  |  | (0.31) |
Higher interest charges |  | (0.08) |  |  | (0.20) |
Higher O&M expenses |  | (0.09) |  |  | (0.08) |
Sherco Unit 3 2011 outage refunds |  | (0.04) |  |  | (0.06) |
Other, net |  | (0.03) |  |  | (0.07) |
GAAP diluted EPS — 2024 |  | 1.21 |  |  | 2.63 |
Sherco Unit 3 2011 outage refunds |  | 0.04 |  |  | 0.06 |
Ongoing diluted EPS — 2024 |  | $ | 1.25 |  |  | $ | 2.69 |

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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 mechanism in Minnesota predominately mitigate the positive and adverse impacts of weather in that jurisdiction.
Degree-day or THI data is used to estimate amounts of energy required to maintain comfortable indoor temperature levels based on each day’s average temperature and humidity. HDD is the measure of the variation in the weather based on the extent to which the average daily temperature falls below 65° Fahrenheit. CDD is the measure of the variation in the weather based on the extent to which the average daily temperature rises above 65° Fahrenheit.
Each degree of temperature above 65° Fahrenheit is counted as one CDD, and each degree of temperature below 65° Fahrenheit is counted as one HDD. In Xcel Energy’s more humid service territories, a THI is used in place of CDD, which adds a humidity factor to CDD. HDD, CDD and THI are most likely to impact the usage of Xcel Energy’s residential and commercial customers. Industrial customers are less sensitive to weather. Typically, sales are not impacted in the first or fourth quarter due to THI or CDD.
Normal weather conditions are defined as either the 10, 20 or 30 year average of actual historical weather conditions. The historical period of time used in the calculation of normal weather differs by jurisdiction, based on regulatory practice. To calculate the impact of weather on demand, a demand factor is applied to the weather impact on sales. Extreme weather variations, windchill and cloud cover may not be reflected in weather-normalized estimates.
Percentage increase (decrease) in normal and actual HDD, CDD and THI:

| Three Months Ended Sept. 30 |  | Nine Months Ended Sept. 30
| 2024 vs. Normal |  | 2023 vs. Normal |  | 2024 vs. 2023 |  | 2024 vs. Normal |  | 2023 vs. Normal |  | 2024 vs. 2023
HDD | (72.7) | % |  | (66.7) | % |  | (24.0) | % |  | (14.7) | % |  | (2.1) | % |  | (13.4) | %
CDD | 20.1 |  |  | 15.2 |  |  | 5.9 |  |  | 24.7 |  |  | 3.2 |  |  | 21.7 |
THI | (1.8) |  |  | 2.6 |  |  | (4.4) |  |  | (10.8) |  |  | 12.7 |  |  | (20.1) |

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

| Three Months Ended Sept. 30 |  | Nine Months Ended Sept. 30
| 2024 vs. Normal |  | 2023 vs. Normal |  | 2024 vs. 2023 |  | 2024 vs. Normal |  | 2023 vs. Normal |  | 2024 vs. 2023
Retail electric | $ | 0.038 |  |  | $ | 0.032 |  |  | $ | 0.006 |  |  | $ | 0.015 |  |  | $ | 0.035 |  |  | $ | (0.020) |
Decoupling and sales true-up | (0.001) |  |  | 0.007 |  |  | (0.008) |  |  | 0.040 |  |  | (0.015) |  |  | 0.055 |
Electric total | $ | 0.037 |  |  | $ | 0.039 |  |  | $ | (0.002) |  |  | $ | 0.055 |  |  | $ | 0.020 |  |  | $ | 0.035 |
Firm natural gas | (0.002) |  |  | (0.002) |  |  | — |  |  | (0.040) |  |  | 0.024 |  |  | (0.064) |
Decoupling | (0.001) |  |  | 0.001 |  |  | (0.002) |  |  | 0.017 |  |  | 0.001 |  |  | 0.016 |
Natural gas total | $ | (0.003) |  |  | $ | (0.001) |  |  | $ | (0.002) |  |  | $ | (0.023) |  |  | $ | 0.025 |  |  | $ | (0.048) |
Total | $ | 0.034 |  |  | $ | 0.038 |  |  | $ | (0.004) |  |  | $ | 0.032 |  |  | $ | 0.045 |  |  | $ | (0.013) |

Sales — Sales growth (decline) for actual and weather-normalized sales in 2024 compared to 2023:

|  | Three Months Ended Sept. 30
|  | PSCo |  | NSP-Minnesota |  | SPS |  | NSP-Wisconsin |  | Xcel Energy
Actual |  |  |  |  |  |  |  |  |  |
Electric residential |  | 4.1 | % |  | (2.7) | % |  | (2.3) | % |  | (1.0) | % |  | — | %
Electric C&I |  | 1.2 |  |  | (2.2) |  |  | 9.4 |  |  | (0.6) |  |  | 2.3 |
Total retail electric sales |  | 2.1 |  |  | (2.4) |  | 7.0 |  |  | (0.7) |  |  | 1.5 |
Firm natural gas sales |  | (3.4) |  |  | (3.8) |  |  | N/A |  | 6.6 |  |  | (3.0) |

|  | Three Months Ended Sept. 30
|  | PSCo |  | NSP-Minnesota |  | SPS |  | NSP-Wisconsin |  | Xcel Energy
Weather-Normalized |  |  |  |  |  |  |  |
Electric residential |  | — | % |  | (0.8) | % |  | (0.1) | % |  | (1.3) | % |  | (0.5) | %
Electric C&I |  | (0.4) |  |  | (1.6) |  |  | 9.8 |  |  | (0.6) |  |  | 2.2 |
Total retail electric sales |  | (0.3) |  |  | (1.4) |  |  | 8.0 |  |  | (0.8) |  |  | 1.3 |
Firm natural gas sales |  | (2.7) |  |  | (3.5) |  |  | N/A |  | 6.7 |  |  | (2.4) |

|  | Nine Months Ended Sept. 30
|  | PSCo |  | NSP-Minnesota |  | SPS |  | NSP-Wisconsin |  | Xcel Energy
Actual |  |  |  |  |  |  |  |
Electric residential |  | 4.1 | % |  | (6.2) | % |  | 1.5 | % |  | (4.8) | % |  | (1.2) | %
Electric C&I |  | 0.3 |  |  | (3.7) |  |  | 8.0 |  |  | (1.9) |  |  | 1.0 |
Total retail electric sales |  | 1.6 |  |  | (4.5) |  |  | 6.7 |  |  | (2.7) |  |  | 0.3 |
Firm natural gas sales |  | (8.7) |  |  | (12.7) |  |  | N/A |  | (11.5) |  |  | (10.1) |

|  | Nine Months Ended Sept. 30
|  | PSCo |  | NSP-Minnesota |  | SPS |  | NSP-Wisconsin |  | Xcel Energy
Weather-Normalized
Electric residential |  | 0.2 | % |  | (0.3) | % |  | (1.1) | % |  | (1.9) | % |  | (0.4) | %
Electric C&I |  | (1.1) |  |  | (2.5) |  |  | 7.9 |  |  | (1.5) |  |  | 1.0 |
Total retail electric sales |  | (0.7) |  |  | (1.8) |  |  | 6.3 |  |  | (1.6) |  |  | 0.6 |
Firm natural gas sales |  | 1.7 |  |  | 0.4 |  |  | N/A |  | (2.3) |  |  | 1.0 |

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|  | Nine Months Ended Sept 30 (Leap Year Adjusted)
|  | PSCo |  | NSP-Minnesota |  | SPS |  | NSP-Wisconsin |  | Xcel Energy
Weather-Normalized
Electric residential |  | (0.2) | % |  | (0.7) | % |  | (1.5) | % |  | (2.3) | % |  | (0.7) | %
Electric C&I |  | (1.5) |  |  | (2.8) |  |  | 7.5 |  |  | (1.9) |  |  | 0.7 |
Total retail electric sales |  | (1.1) |  |  | (2.1) |  |  | 5.9 |  |  | (2.0) |  |  | 0.2 |
Firm natural gas sales |  | 0.8 |  |  | (0.5) |  |  | N/A |  | (3.1) |  |  | 0.1 |

Weather-normalized and leap-year adjusted electric sales growth (decline) — year-to-date
•PSCo — Residential sales declined due to a 1.5% decrease in use per customer, partially offset by customer growth of 1.4%. The C&I sales decline was related to decreased use per customer, primarily in the information sector.
•NSP-Minnesota — Residential sales declined due to a 2.2% decrease in use per customer, partially offset by a 1.5% increase in customers. C&I sales declined due to decreased use per customer, largely in the manufacturing, retail trade and education sectors.
•SPS — Residential sales declined as a result of a 2.2% decrease in use per customer, partially offset by 0.6% customer growth. C&I sales increased due to higher use per customer, primarily driven by the energy sector and cryptocurrency mining.
•NSP-Wisconsin — Residential sales declined due to a 3.2% decrease in use per customer, partially offset by 0.9% increase in customers. C&I sales decline was associated with decreased use per customer, experienced largely in the manufacturing and professional services sectors.
Weather-normalized and leap-year adjusted natural gas sales growth (decline) — year-to-date
•Increase in natural gas sales was driven by residential and C&I customer growth in all jurisdictions and increased residential use per customer in PSCo offset by decreased use per customer in PSCo C&I and other jurisdictions.
Electric Revenues
Electric revenues are impacted by fluctuations in the price of natural gas, coal and uranium, regulatory outcomes, market prices and seasonality. In addition, electric customers receive a credit for PTCs generated, which reduce electric revenue and income taxes.

(Millions of Dollars) |  | Three Months Ended Sept. 30, 2024 vs. 2023 |  | Nine Months Ended Sept. 30, 2024 vs. 2023
Recovery of lower cost of electric fuel and purchased power |  | $ | (83) |  |  | $ | (418) |
Wholesale generation revenues |  | (45) |  |  | (76) |
Sherco Unit 3 2011 outage refunds |  | (35) |  |  | (46) |
PTCs flowed back to customers (offset by lower ETR) |  | (23) |  |  | (35) |
Regulatory rate outcomes (MN, CO, TX, NM, & WI) |  | 130 |  |  | 363 |
Non-fuel riders |  | 43 |  |  | 112 |
Conservation and demand side management (offset in expense) |  | 39 |  |  | 82 |
Revenue recognition for the Texas rate case surcharge (a) |  | 2 |  |  | 39 |
Estimated impact of weather (net of sales true-up) |  | (2) |  |  | 25 |
Other, net |  | (20) |  |  | (60) |
Total increase |  | $ | 6 |  |  | $ | (14) |

(a)Recognition of revenue from the Texas rate case outcome is largely offset by recognition of previously deferred costs.
Natural Gas Revenues
Natural gas revenues vary with changing sales, the cost of natural gas and regulatory outcomes.

(Millions of Dollars) |  | Three Months Ended Sept. 30, 2024 vs. 2023 |  | Nine Months Ended Sept. 30, 2024 vs. 2023
Recovery of lower cost of natural gas |  | $ | (8) |  |  | $ | (418) |
Estimated impact of weather (net of decoupling) |  | (2) |  |  | (35) |
Regulatory rate outcomes (MN, WI & ND) |  | 6 |  |  | 41 |
Retail sales growth (net of decoupling) |  | 1 |  |  | 10 |
Infrastructure and integrity riders |  | 1 |  |  | 6 |
Other, net |  | (4) |  |  | 5 |
Total decrease |  | $ | (6) |  |  | $ | (391) |

Electric Fuel and Purchased Power — Expenses incurred for electric fuel and purchased power are impacted by fluctuations in market prices of 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 $121 million for the third quarter and $465 million year-to-date. The decrease is primarily due to timing of fuel recovery mechanisms and lower commodity prices.
Cost of Natural Gas Sold and Transported — Expenses incurred for the cost of natural gas sold are impacted by market prices and seasonality. These costs are generally recovered through various regulatory recovery mechanisms. As a result, changes in these expenses are largely offset in operating revenues and have minimal earnings impact.
Natural gas sold and transported decreased $7 million for the third quarter and $420 million year-to-date. The decrease is primarily due to lower commodity prices and volumes.
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Non-Fuel Operating Expenses and Other Items
O&M Expenses — O&M expenses increased $69 million for the third quarter and increased $58 million year-to-date. The year-to-date increase was primarily due to operational activities (generation maintenance, damage prevention, storm response and wildfire mitigation) and recognition of previously deferred costs associated with the Texas Electric Rate Case, partially offset by gain on land sale in the first quarter and lower bad debt expense.
Depreciation and Amortization — Depreciation and amortization increased $63 million for the third quarter and $235 million year-to-date. The year-to-date increase was largely the result of system expansion partially offset by recognition of previously deferred costs and depreciation rate changes associated with various rate cases.
Interest Charges — Interest charges increased $57 million for the third quarter and $146 million year-to-date, largely due to increased debt levels and higher interest rates.
Other Income — Other income increased $36 million for the third quarter and $56 million year-to-date. The year-to-date increase was primarily due to interest earned and rabbi trust performance, which is partially offset in O&M expenses.
AFUDC, Equity and Debt — AFUDC increased $25 million for the third quarter and $71 million year-to-date, driven by increased investment in renewable and transmission projects.

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, 2023 appropriately represent, in all material respects, the current status of public utility regulation and are incorporated herein by reference.
NSP-Minnesota
Pending and Recently Concluded Regulatory Proceedings
2024 Minnesota Natural Gas Rate Case — In November 2023, NSP-Minnesota filed a request with the MPUC for a natural gas rate increase of approximately $59 million, or 9.6%. The request was based on a ROE of 10.2%, a 52.5% equity ratio and a 2024 forward test year with rate base of approximately $1.27 billion. In December 2023, the MPUC approved NSP-Minnesota’s request for interim rates, subject to refund, of approximately $51 million (implemented on Jan. 1, 2024).
In June 2024, NSP-Minnesota and various parties filed an uncontested settlement, which includes the following terms:
•Natural gas rate increase of $46 million, or 7.5%.
•ROE of 9.6%.
•Equity ratio of 52.5%.
•Rate base of $1.25 billion.
•No change to Commission approved decoupling.
In October 2024, an ALJ recommended the MPUC approve the rate case settlement. A MPUC decision and order is expected in the first quarter of 2025.
2024 North Dakota Natural Gas Rate Case — In December 2023, NSP-Minnesota filed a request with the NDPSC seeking an increase in natural gas rates of $8.5 million (9.4%), based on a ROE of 10.20%, an equity ratio of 52.5%, 2024 test year and rate base of $168 million. In February 2024, the NDPSC approved interim rates of $8 million, effective March 1, 2024.
In August 2024, NSP-Minnesota filed a settlement agreement with NDPSC Staff and AARP. Key terms of the settlement included an increase in natural gas rates of $7.3 million (8.1%), based on a ROE of 9.9% and an equity ratio of 52.5%.
A NDPSC decision and order is expected by the end of 2024.
2022 Minnesota Electric Rate Case — In October 2021, NSP-Minnesota filed a three-year electric rate case with the MPUC.
In July 2023, the MPUC approved a three-year rate increase of approximately $332 million for 2022-2024, based on a ROE of 9.25% and an equity ratio of 52.5%. The MPUC also approved a continuation of the sales true-up mechanism.
In November 2023, NSP-Minnesota filed an appeal to the Minnesota Court of Appeals regarding MPUC decisions relating to executive compensation, insurance expense and treatment of prepaid pension assets. The appeal is pending a court decision expected in the first quarter of 2025.
2024 Minnesota Electric Rate Case — In early November 2024, NSP-Minnesota plans to file an electric rate case in Minnesota, seeking a total revenue increase of $491 million (13.2%) over two years, based on an ROE of 10.3%, a 52.5% equity ratio and rate base of $13.2 billion in 2025 and $14 billion in 2026. NSP-Minnesota will also request interim rates of $224 million to go into effect in January 2025. A decision is expected in 2026.
Nuclear Power Operations
NSP-Minnesota owns two nuclear generating plants: the Monticello plant and the Prairie Island plant. See Note 12 to the consolidated financial statements of Xcel Energy’s Annual Report on Form 10-K for the year ended Dec. 31, 2023 for further information. The circumstances set forth in Nuclear Power Operations included in Item 7 of Xcel Energy’s Annual Report on Form 10-K for the year ended Dec. 31, 2023, appropriately represent, in all material respects, the current status of nuclear power operations.
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NSP-Wisconsin
Pending Regulatory Proceedings
Michigan Electric Rate Case — In July 2024, NSP-Wisconsin filed a Michigan electric rate case, seeking a $2.9 million (16.7%) rate increase for 2025, based on a ROE of 10.0% and an equity ratio of 52%. In addition, NSP-Wisconsin proposed an Investment Recovery Mechanism which would result in increases of $2.0 million (9.8%) in 2026 and $0.8 million (3.7%) in 2027 for recovery of costs associated with distribution and generation investment. A decision is expected in the first half of 2025.
Wisconsin 2025 Stay-Out Proposal — In June 2024, NSP-Wisconsin filed a 2025 stay-out proposal with the PSCW. The filing proposes to offset 2025 revenue deficiencies of $28 million for electric and $3 million for natural gas, by amortizing IRA deferrals, stopping a deferral related to IRA benefits ordered in a previous rate case, and deferring revenue requirement impacts of two natural gas capital projects. NSP-Wisconsin expects to have a PSCW decision by year-end 2024.
NSP System
2022 Upper Midwest IRP Resource Acquisition — NSP-Minnesota and NSP-Wisconsin are actively engaged in multiple processes and proceedings to acquire resources to meet their identified generation resource needs.
•In the second quarter of 2023, NSP-Minnesota initiated the process with the MPUC for acquisition of firm dispatchable resources. In October 2024, a settlement was reached with various parties, pending MPUC approval. See below for more details.
•In October 2023, NSP-Minnesota issued an RFP seeking 1,200 MW of wind assets to replace capacity and reutilize interconnection rights associated with the retiring Sherco coal facilities. The RFP closed in December 2023. NSP-Minnesota expects to file for approval of recommended projects by the fourth quarter of 2024.
•In 2024, NSP-Minnesota and NSP-Wisconsin each issued an RFP collectively seeking up to 1,600 MW of wind, solar, storage or hybrid resources to interconnect to the NSP System, including reutilization of the interconnection rights associated with the retiring Sherco coal units, and 650 MW of solar and storage resources to specifically reutilize the interconnection rights associated with the retiring King coal unit. Bids are currently under evaluation; NSP-Minnesota and NSP-Wisconsin expect to announce short listed projects in December 2024 and plan to file for the requisite approvals of the selected resources with the MPUC and PSCW, respectively, in the second quarter of 2025.
2024 Upper Midwest Resource Plan — In February 2024, NSP filed its Upper Midwest Resource Plan with the MPUC. In October 2024, NSP-Minnesota filed a settlement with several parties reaching agreement on the targeted resource additions for the 5-year Action Plan and the process under which those resources will be secured, as well as the proposed projects to be approved in the pending 800 MW firm dispatchable resource acquisition.
NSP-Minnesota anticipates a MPUC decision in 2025 and will file a RFP for remaining resource needs upon approval. The settlement included the following key items:
•The selection of the company-owned 420 MW Lyon County combustion turbine.
•The selection of the company-owned 300 MW 4-hour Sherco battery energy storage system.
•Multiple PPAs to proceed to the negotiation stage.
•3,200 MW of wind, 400 MW of solar and 600 MW of stand-alone storage to be added through 2030 based on an RFP process (a portion of which is expected to be fulfilled with the resources acquired as part of the June and July 2024 RFPs). Of these amounts, approximately 2,800 MW of wind are projected to utilize the Minnesota Energy Connection transmission line.
•Planned life extensions of the Prairie Island and Monticello nuclear plants through the early 2050s.
PSCo
Pending and Recently Concluded Regulatory Proceedings
Colorado Natural Gas Rate Case — In January 2024, PSCo, filed a request with the CPUC seeking an increase to retail natural gas rates of $171 million (9.5%). The request was based on a 10.25% ROE, an equity ratio of 55%, a 2023 test year and a $4.2 billion year-end rate base.
In October 2024, the CPUC issued an order including the following key decisions:
•Use of a historic 2023 test year, with a 13-month average rate base.
•Weighted-average cost of capital of 7.0%, based on an ROE range of 9.2%-9.5% and an equity ratio range of 52%-55%.
•Acceleration of $15 million per year of depreciation expense (incremental to PSCo’s original rate request), to be held in an external trust for future decommissioning costs.
•Modifications to recoverability of certain operating expenses.
•Denial of PSCo’s decoupling proposal.
Based on the CPUC order, PSCo estimates an annual revenue increase of approximately $130 million, inclusive of $15 million of accelerated depreciation, with rates expected to be effective Nov. 5, 2024.
Colorado Resource Plan — In December 2023, the CPUC approved a portfolio of 5,835 MW, which includes approximately 3,100 MW of company owned resources and 2,700 MW of PPAs.
In December 2023, the CPUC approved two PIMs associated with the generation projects in the portfolio, including a PIM related to capital construction costs and another related to ongoing levelized energy costs. These PIMs will be further defined in related proceedings throughout 2024. In September 2024, PSCo filed a proposed framework for CPUC review of pricing adjustments for both company owned and PPA resources to enable delivery of the approved portfolio in light of supply chain and geopolitical developments. A decision is expected in the fourth quarter of 2024.
PSCo filed or expects to file generation and transmission CPCNs throughout 2024 and early 2025.
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2024 Colorado Electric Resource Plan — In October 2024, PSCo filed its electric resource plan, known as the Just Transition Solicitation, with the CPUC. The filing reflects the expected growth on the system, the generation resources needed to meet the projected growth and the future evaluation of competitive bids for new generation resources.
•The plan reflects a base sales forecast with 7% compound annual sales growth through 2031.
•The plan also presents a low sales forecast with a 3% compound annual sales growth through 2031.
•The resource plan includes forecasted need of 5-14 GW of new generation capacity through 2031, including renewables and firm dispatchable resources to meet the two different scenarios. The acquisitions of generation resources will be determined through a competitive solicitation after the CPUC determines the portfolio. The table below summarizes two of the proposed portfolios based on the different sales scenarios:

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

A CPUC decision on the resource plan is expected by the fall of 2025 (Phase I) with the competitive solicitation for resource additions expected in early 2026.
Wildfire Mitigation Plan — In June 2024, PSCo filed an updated WMP and request for recovery of costs covering the years 2025 to 2027 with the CPUC. The estimated total cost for this plan is approximately $1.9 billion. A CPUC decision is expected in the third quarter of 2025.
The WMP is a key component of keeping our customers and communities safe while providing reliable and affordable electric service. The WMP integrates industry experience; incorporates evolving risk assessment methodologies; adds new technology; and expands the scope, pace and scale of our work to reduce wildfire risk in a comprehensive and efficient manner under four core programs that include the following:
•Situational awareness — Meteorology, area risk mapping and modeling, artificial intelligence cameras and continuous monitoring.
•Operational mitigations – Enhanced powerline safety settings and PSPS.
•System resiliency — Asset assessment and remediations, pole replacements, line rebuilds, targeted undergrounding and vegetation management.
•Customer support — Coordination and real-time data sharing with customers and other stakeholders and PSPS resiliency rebates.
The CPUC requested that PSCo file supplemental testimony including the impacts of potential securitization of the proposed wildfire mitigation plan investments. Total capital investments and O&M expenses associated with the proposed plan are estimated at the following:

(Millions of Dollars) |  | 2025 |  | 2026 |  | 2027 |  | Total
Capital investments |  |  |  |  |  |  |  |
Situational awareness |  | $ | 24 |  |  | $ | 17 |  |  | $ | 10 |  |  | $ | 51 |
Operational mitigations |  | 58 |  | 66 |  | 83 |  | 207 |
System resiliency |  | 368 |  |  | 411 |  |  | 565 |  |  | 1,344 |
Total capital investments |  | $ | 450 |  |  | $ | 494 |  |  | $ | 658 |  |  | $ | 1,602 |
O&M expenses |  |  |  |  |  |  |  |
Situational awareness |  | $ | 9 |  |  | $ | 10 |  |  | $ | 10 |  |  | $ | 29 |
Operational mitigations |  | 3 |  | 3 |  | 4 |  | 10
System resiliency |  | 44 |  | 69 |  | 77 |  | 190
Customer support |  | 7 |  | 8 |  | 9 |  | 24
Total O&M expenses |  | 63 |  |  | 90 |  |  | 100 |  |  | 253 |
Total expenditures |  | $ | 513 |  |  | $ | 584 |  |  | $ | 758 |  |  | $ | 1,855 |

The procedural schedule is as follows:
•Answer testimony: Feb. 14, 2025
•Rebuttal testimony: March 21, 2025
•Settlement deadline: April 11, 2025
•Hearing: May 5-15, 2025
•Decision deadline: Aug. 28, 2025
CPUC Proactive Line De-Energization Investigation — In April 2024, PSCo proactively de-energized certain lines in Colorado due to winds that were over 90 miles per hour to reduce potential wildfire risk.
The CPUC opened a docket related to the proactive de-energizing of power lines to evaluate potential improvements to the process. The CPUC plans to continue evaluation of PSCo’s policies for proactive line de-energizations through its ongoing review of the 2025-2027 wildfire mitigation plan and, in the interim, will require PSCo to file additional information to the CPUC, hold work sessions with emergency responders, test customer communication protocols, and provide monthly progress updates to the CPUC.
Colorado Senate Bill 23-291 — In May 2023, Colorado Senate Bill 23-291 was signed into law. The bill includes a number of topics including natural gas and electric fuel incentive mechanisms, natural gas planning rules, regulatory filing requirements, and non-recovery of certain expenses (e.g., certain organizational or membership dues, tax penalties or fines).
In November 2023, the CPUC approved PSCo’s natural gas price risk plan to manage customer bill volatility from commodity price changes, establishing upper and lower limits for changes in the gas cost adjustment rate. As a result, costs above the upper limit are deferred for future recovery, with interest, and costs below the lower limit deferred as a reserve against future cost increases.
The legislation also calls for the CPUC to adopt rules to establish fuel cost mechanisms to align the financial incentives of a utility with the interests of the utility’s customers by Jan. 1, 2025. In September 2024, the CPUC issued a recommended decision in adopting rules to implement a natural gas PIM prior to Jan. 1, 2025. Per the recommended decision, natural gas costs incurred will be compared to the prior year to determine any incentive/penalty. In October 2024, PSCo filed targeted exceptions. A final decision is expected in fourth quarter of 2024.
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In October 2024, the CPUC also issued a proposed PIM for electric utilities. Similar to the natural gas PIM, it would determine any incentive/penalty by comparing the year-over-year change in the price of natural gas procured for electric generation. PSCo filed comments in October 2024 and a hearing is expected to occur in November 2024. A CPUC decision is expected by the end of 2024.
Colorado Senate Bill 24-218 — In May 2024, Colorado Senate Bill 24-218 was signed into law. The bill includes a suite of policy changes to accelerate investment in electric distribution, including a framework to develop distribution planning and performance requirements and the opportunity for current cost recovery through a rider for distribution investments. In July 2024, the CPUC approved PSCo’s request to collect $17 million through a rider, over the remainder of 2024, subject to true-up, associated with forecasted capital investments covered by the new legislation. PSCo expects to file an updated 2025 rider in November 2024.
Cabin Creek Prudency Review — In 2015, the CPUC granted a CPCN for an $88 million upgrade project to increase the generating and storage capacity of the Cabin Creek hydroelectric storage facility, which anticipated project completion in 2020. Due to significant and unforeseen challenges, the project was not completed until 2023 and cost approximately $110 million. In July 2024, PSCo filed a prudency review for the upgrade project, which reviews the project’s timelines, costs, benefits and challenges.
Procedural schedule:
•Answer testimony: Feb. 3, 2025
•Rebuttal testimony: March 14, 2025
•Settlement testimony: April 4, 2025
•Hearing: April 17-18, 2025
•Statements of position: May 9, 2025
A final CPUC decision is expected in the second quarter of 2025.
Excess Liability Insurance Deferral — In August 2024, PSCo filed a request with the CPUC to establish a tracker to defer differences in excess liability insurance premiums after the October 2024 policy renewal (reflecting significantly rising premiums, largely associated with wildfire risks throughout the United States) and amounts currently recovered. In October 2024, the CPUC approved an accelerated procedural schedule which is as follows:
•Rebuttal testimony: Nov. 1, 2024
•Settlement deadline: Nov. 12, 2024
•Hearing: Nov. 21, 2024
•Target decision date: Dec. 31, 2024
SPS
Pending and Recently Concluded Regulatory Proceedings
2023 Texas Electric Rate Case — In 2023, SPS filed an electric rate case with the PUCT seeking an increase in base rate revenue of $158 million (14%). Interim rates went into effect on Feb. 1, 2024.
In April 2024, the PUCT approved a black box settlement between SPS and intervening parties, which reflect the following terms:
•A base rate increase of $65 million effective back to July 13, 2023.
•A 9.55% ROE, a 54.51% equity ratio and a 7.11% WACC for purposes of calculating SPS’ AFUDC and in other proceedings filed before the PUCT where a stated WACC is required.
•The reflection in rates of the retirement of Tolk Generation Station from 2034 to 2028.
•Establishment of a rate rider of approximately $18 million to be r ecovered over a three-year period for various deferred expenses.
In July 2024, SPS filed to surcharge the final under-recovered amount, estimated to be $37 million. This will be largely offset by previously deferred costs. A PUCT decision is expected in the fourth quarter of 2024.
2022 All-Source RFP — In July 2023, SPS filed for approval of a CPCN for a recommended generation portfolio, which includes 418 MW of self-build solar projects and a 36 MW battery. The NMPRC approved the projects in May 2024. In July 2024, the PUCT approved the solar projects and denied the battery project. The PUCT’s approval included minimum production and PTC guarantees.
New Mexico Resource Plan (IRP) — In October 2023, SPS filed its IRP with the NMPRC, which supports projected load growth and increasing reliability requirements, and secures replacement energy and capacity for retiring resources. SPS’ projected resource needs ranging from approximately 5,300 MW to 10,200 MW by 2030. In February 2024, the NMPRC accepted the IRP.
In July 2024, SPS issued a RFP, seeking approximately 3,200 MW of accredited generation capacity by 2030. The total capacity to be added to the system is expected to align with the range identified in the SPS IRP, depending on the types of resources proposed in the RFP and their accredited capacity factors.
The RFP will be evaluated in the first quarter of 2025. SPS is expected to file for a certificate of need for the recommended portfolio in the summer of 2025. The Texas and New Mexico Commissions are expected to rule on the portfolio in 2026.
Other
Supply Chain
Xcel Energy’s ability to meet customer energy requirements, execute our capital expenditure program and respond to storm-related disruptions are dependent on maintaining an efficient supply chain. Manufacturing processes have experienced disruptions related to scarcity of certain raw materials and interruptions in production and shipping. These disruptions have been further exacerbated by inflationary pressures, labor shortages and the impact of international conflicts/issues. Xcel Energy continues to monitor the situation as it remains fluid and seeks to mitigate the impacts by securing alternative suppliers, modifying design standards, and adjusting the timing of work.
Large global demand for energy-related infrastructure (renewables and gas generation, data centers, etc.) has stretched equipment supply chains, extended delivery dates and increased prices for items like combustion turbines, transformers and other large electrical equipment. The labor market for skilled engineering and construction resources to build renewables and gas generation has also been strained, impacting cost and availability.
Tariffs and Trade Complaints
In May 2024, the U.S. Department of Commerce announced the initiation of anti-dumping and countervailing duty investigations of CSPV cells from Cambodia, Malaysia, Thailand and Vietnam, whether or not assembled into modules.
In October 2024, the U.S. Department of Commerce announced its preliminary determination in the countervailing duty circumvention investigation, which is not expected to impact Xcel Energy projects. A preliminary decision related to the anti-dumping portion of the matter is anticipated in November 2024.
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In May 2024, the White House imposed a new 25% tariff on Lithium-Ion storage along with other trade measures. The tariff went into immediate effect for EV batteries but has a grace period until January 2026 for stationary energy storage applications.
Xcel Energy continues to assess the impacts of these tariffs and trade complaints on its business, including company-owned projects and PPAs. Xcel Energy may seek regulatory relief for tariffs, if required, in its jurisdictions.
Further policy actions or other restrictions on solar and storage imports, disruptions in imports from key suppliers, or any new trade complaint could impact project timelines and costs of various generation projects and PPAs.
Excess Liability Insurance Coverage
Xcel Energy maintains excess liability coverage, which is intended to insure against liability to third parties. During 2024, Xcel Energy had approximately $600 million of excess liability coverage; including $520 million of wildfire coverage with an annual premium of approximately $40 million. Examples of claims paid under this policy include property damage or bodily injury to members of the public caused by Xcel Energy’s employees, equipment or facilities. The increased wildfire liability risk and claims are driving a significant increase of premiums and reductions in insurance coverage in the excess liability markets, especially in the western United States. In October 2024, Xcel Energy renewed its excess liability coverage and now has $450 million of total coverage; including $450 million of wildfire coverage for the NSP System and $300 million of wildfire coverage for PSCo and SPS. The annual premium for this excess liability insurance is approximately $130 million. Xcel Energy is seeking to recover these increased costs through various regulatory proceedings, including a deferral request at PSCo and planned deferral requests or rate filings in other states.

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, in addition to the matter noted below, are included within the Xcel Energy Inc. Annual Report on Form 10-K for the year ended Dec. 31, 2023.
Loss Contingencies – Wildfires
The outcomes of legal proceedings and claims brought against Xcel Energy related to the Marshall Fire, Smokehouse Creek Fire Complex or any future wildfire are subject to uncertainty. An estimated loss from a loss contingency such as a legal proceeding or claim is accrued if it is probable of being incurred and the amount of the loss can be reasonably estimated. Each reporting period we evaluate, among other factors, the degree of probability of unfavorable outcomes and the ability to make reasonable estimates of potential losses. The process for evaluating any wildfire-related liabilities requires a series of complex judgments about past and future events. Factors such as the cause of a wildfire, the extent and magnitude of potential damages and the status of investigations and legal proceedings are considered. See Note 10 accompanying the consolidated financial statements for additional information.

Environmental Regulation

Clean Air Act
Power Plant Greenhouse Gas Regulations — In April 2024, the EPA published final rules addressing control of CO 2 emissions from the power sector. The rules regulate new natural gas generating units and emission guidelines for existing coal and certain natural gas generation. The rules create subcategories of coal units based on planned retirement date and subcategories of natural gas combustion turbines and combined cycle units based on utilization. The CO 2 control requirements vary by subcategory. Based on current estimates and assumptions, Xcel Energy has determined that due to scheduled plant retirements, there is minimal financial or operational impact associated with these requirements and believes that the cost of these initiatives or replacement generation would be recoverable through rates based on prior state commission practices.
Waste-to-Energy Air Regulations — In January 2024, the EPA proposed air regulations addressing new and existing large municipal waste combustors. The proposed rules lower current emission standards for certain pollutants and would require installation of new pollution controls and/or more intense use of existing pollution controls at French Island Generating Station, Red Wing Generating Plant and Wilmarth Generating Plant. Until final rules are issued, it is not certain what the impact will be on Xcel Energy. Xcel Energy believes that the cost of these initiatives or replacement generation would be recoverable through rates based on prior state commission practices.
Emerging Contaminants of Concern
PFAS are man-made chemicals that are widely used in consumer products and can persist and bio-accumulate in the environment. Xcel Energy does not manufacture PFAS, but because PFAS are so ubiquitous in products and the environment, it may impact our operations.
In June 2024, the EPA finalized a rule that designated certain PFAS as hazardous substances under CERCLA. In July 2024, the EPA finalized another rule that set enforceable drinking water standards for certain PFAS.
Potential costs for these rules and any additional proposed regulations related to PFAS are uncertain and will be determined on a site specific basis where applicable. If costs are incurred, Xcel Energy believes the costs will be recoverable through rates based on prior state commission practices.
Effluent Limitation Guidelines
In April 2024, the EPA published final rules under the Clean Water Act, setting Effluent Limitations Guidelines and Standards for steam generating coal plants. This rule establishes more stringent wastewater discharge standards for bottom ash transport water, flue-gas desulfurization wastewater, and combustion residuals leachate from steam electric power plants, particularly coal-fired power plants. Based on current estimates and assumptions, Xcel Energy has determined that there is minimal financial or operational impact associated with these requirements and that any costs would be recoverable through rates based on prior state commission practices.

Derivatives, Risk Management and Market Risk

We are exposed to a variety of market risks in the normal course of business. Market risk is the potential loss that may occur as a result of adverse changes in the market or fair value for a particular instrument or commodity. All financial and commodity-related instruments, including derivatives, are subject to market risk.
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Xcel Energy is exposed to the impact of adverse changes in price for energy and energy-related products, which is partially mitigated by the use of commodity derivatives. In addition to ongoing monitoring and maintaining credit policies intended to minimize overall credit risk, management takes steps to mitigate changes in credit and concentration risks associated with its derivatives and other contracts, including parental guarantees and requests of collateral. While we expect that the counterparties will perform on the contracts underlying our derivatives, the contracts expose us to credit and non-performance risk.
Distress in the financial markets may impact counterparty risk and the fair value of the securities in the nuclear decommissioning fund and pension fund.
Commodity Price Risk — We are exposed to commodity price risk in our electric and natural gas operations. Commodity price risk is managed by entering into long and short-term physical purchase and sales contracts for electric capacity, energy and energy-related products and fuels used in generation and distribution activities.
Commodity price risk is also managed through the use of financial derivative instruments. Our risk management policy allows us to manage commodity price risk within each rate-regulated operation per commission approved hedge plans.
Wholesale and Commodity Trading Risk — Xcel Energy conducts various wholesale and commodity trading activities, including the purchase and sale of electric capacity, energy, energy-related instruments and natural gas-related instruments, including derivatives. Our risk management policy allows management to conduct these activities within guidelines and limitations as approved by our risk management committee.
Fair value of net commodity trading contracts as of Sept. 30, 2024:

|  | Futures / Forwards Maturity
(Millions of Dollars) |  | Less Than 1 Year |  | 1 to 3 Years |  | 4 to 5 Years |  | Greater Than 5 Years |  | Total Fair Value
NSP-Minnesota (a) |  | $ | (2) |  |  | $ | (4) |  |  | $ | (1) |  |  | $ | — |  |  | $ | (7) |
NSP- Minnesota (b) |  | (11) |  |  | (4) |  |  | (3) |  |  | 2 |  |  | (16) |
PSCo (a) |  | 1 |  |  | 2 |  |  | 1 |  |  | — |  |  | 4 |
PSCo (b) |  | (2) |  |  | 3 |  |  | — |  |  | — |  |  | 1 |
|  | $ | (14) |  |  | $ | (3) |  |  | $ | (3) |  |  | $ | 2 |  |  | $ | (18) |

|  | Options Maturity
(Millions of Dollars) |  | Less Than 1 Year |  | 1 to 3 Years |  | 4 to 5 Years |  | Greater Than 5 Years |  | Total Fair Value
NSP-Minnesota (b) |  | $ | — |  |  | $ | — |  |  | $ | 12 |  |  | $ | 2 |  |  | $ | 14 |
|  | $ | — |  |  | $ | — |  |  | $ | 12 |  |  | $ | 2 |  |  | $ | 14 |

(a)Prices actively quoted or based on actively quoted prices.
(b)Prices based on models and other valuation methods.
Changes in the fair value of commodity trading contracts before the impacts of margin-sharing for the nine months ended Sept. 30:

(Millions of Dollars) |  | 2024 |  | 2023
Fair value of commodity trading net contracts outstanding at Jan. 1 |  | $ | 1 |  |  | $ | (33) |
Contracts realized or settled during the period |  | 2 |  |  | 1 |
Commodity trading contract additions and changes during the period |  | (7) |  |  | 33 |
Fair value of commodity trading net contracts outstanding at Sept. 30 |  | $ | (4) |  |  | $ | 1 |

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 $4 million at Sept. 30, 2024 and Sept. 30, 2023, respectively.
The utility subsidiaries’ commodity trading operations measure the outstanding risk exposure to price changes on contracts and obligations using an industry standard methodology known as VaR. VaR expresses the potential change in fair value of the outstanding contracts and obligations over a particular period of time under normal market conditions.
The VaRs for the NSP-Minnesota and PSCo commodity trading operations, excluding both non-derivative transactions and derivative transactions designated as normal purchases and normal sales, calculated on a consolidated basis using a Monte Carlo simulation with a 95% confidence level and a one-day holding period, were as follows:

(Millions of Dollars) |  | Three Months Ended Sept. 30 |  | Average |  | High |  | Low
2024 |  | $ | — |  |  | $ | — |  |  | $ | 1 |  |  | $ | — |
2023 |  | 1 |  |  | 1 |  |  | 2 |  |  | 1 |

Nuclear Fuel Supply — In May 2024, the Prohibiting Russian Uranium Imports Act was signed into law. As such, NSP-Minnesota will no longer be permitted to accept deliveries of enriched nuclear material from Russia beginning in August 2024, unless specific waivers are requested and received. NSP-Minnesota has secured its enriched nuclear material requirements through 2029 with non-Russian material, which are in various stages of processing in Canada, Europe and the United States. NSP-Minnesota continues to assess the impacts of this legislation on its existing contracts related to Russian-sourced nuclear material.
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 $1 million and $2 million in Sept. 30, 2024 and 2023, 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.
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At Sept. 30, 2024, a 10% increase in commodity prices would have resulted in an increase in credit exposure of $31 million, while a decrease in prices of 10% would have resulted in a decrease in credit exposure of $30 million. At Sept. 30, 2023, a 10% increase in commodity prices would have resulted in an increase in credit exposure of $32 million, while a decrease in prices of 10% would have resulted in a decrease in credit exposure of $28 million.
Xcel Energy conducts credit reviews 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.
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.

Fair Value Measurements

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

Liquidity and Capital Resources

Cash Flows
Operating Cash Flows

(Millions of Dollars) |  | Nine Months Ended Sept 30
Cash provided by operating activities — 2023 |  | $ | 4,353 |
Components of change — 2024 vs. 2023 |  |
Higher net income |  | 110 |
Non-cash transactions |  | 183 |
Changes in deferred income taxes |  | 579 |
Changes in working capital |  | (799) |
Changes in net regulatory and other assets and liabilities |  | (449) |
Cash provided by operating activities — 2024 |  | $ | 3,977 |

Net cash provided by operating activities decreased $376 million for the nine months ended Sept. 30, 2024 compared with the prior year. The decrease was largely due to interim rate refunds in Minnesota and timing of recovery of deferred fuel costs, partially offset by the change in deferred income taxes, which includes the impact of proceeds for tax credit transfers.
Investing Cash Flows

(Millions of Dollars) |  | Nine Months Ended Sept 30
Cash used in investing activities — 2023 |  | $ | (4,292) |
Components of change — 2024 vs. 2023 |  |
Increased capital expenditures |  | (907) |
Other investing activities |  | 2 |
Cash used in investing activities — 2024 |  | $ | (5,197) |

Net cash used in investing activities increased $905 million for the nine months ended Sept. 30, 2024 compared with the prior year. The increase in capital expenditures was largely due to continued system expansion and increased investment in renewable and transmission projects.
Financing Cash Flows

(Millions of Dollars) |  | Nine Months Ended Sept 30
Cash provided by financing activities — 2023 |  | $ | 422 |
Components of change — 2024 vs. 2023 |  |
Lower net short-term repayments |  | 123 |
Higher long-term debt issuances, net of repayments |  | 1,113 |
Higher proceeds from issuance of common stock |  | 1,026 |
Other financing activities |  | (48) |
Cash provided by financing activities — 2024 |  | $ | 2,636 |

Net cash provided by financing activities increased $2,214 million for the nine months ended Sept. 30, 2024 compared with the prior year. The increase was largely related to additional debt and common stock issuances to fund capital investment and the repayment of maturing debt issuances.
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 2024, contributions of $100 million were made across four of Xcel Energy’s pension plans.
•In 2023, contributions of $50 million were made across four of Xcel Energy’s pension plans.
•For future years, contributions will be made as deemed appropriate based on evaluation of various factors including the funded status of the plans, minimum funding requirements, interest rates and expected investment returns.
Capital Sources
Short-Term Funding Sources — Xcel Energy uses a number of sources to fulfill short-term funding needs, including operating cash flow, notes payable, commercial paper and bank lines of credit. The amount and timing of short-term funding needs depend on financing needs for construction expenditures, working capital and dividend payments.
Short-Term Investments — Xcel Energy Inc., NSP-Minnesota, NSP-Wisconsin, PSCo and SPS maintain cash operating and short-term investment accounts.
Revolving Credit Facilities — Xcel Energy Inc., NSP-Minnesota, PSCo and SPS each have the right to request an extension of their revolving credit facility termination date for two additional one-year periods beyond the September 2027 termination date. NSP-Wisconsin has the right to request an extension of the revolving credit facility termination date for an additional one-year period. All extension requests are subject to majority bank group approval.
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As of Oct. 28, 2024, Xcel Energy Inc. and its utility subsidiaries had the following committed credit facilities available to meet liquidity needs:

(Millions of Dollars) |  | Credit Facility (a) |  | Drawn (b) |  | Available |  | Cash |  | Liquidity
Xcel Energy Inc. |  | $ | 1,500 |  |  | $ | 45 |  |  | $ | 1,455 |  |  | $ | 31 |  |  | $ | 1,486 |
PSCo |  | 700 |  |  | 31 |  |  | 669 |  |  | 536 |  |  | 1,205 |
NSP-Minnesota |  | 700 |  |  | 12 |  |  | 688 |  |  | 198 |  |  | 886 |
SPS |  | 500 |  |  | — |  |  | 500 |  |  | 115 |  |  | 615 |
NSP-Wisconsin |  | 150 |  |  | — |  |  | 150 |  |  | 104 |  |  | 254 |
Total |  | $ | 3,550 |  |  | $ | 88 |  |  | $ | 3,462 |  |  | $ | 984 |  |  | $ | 4,446 |

(a)Credit facilities expire in September 2027.
(b)Includes outstanding commercial paper and letters of credit.
Short-Term Debt — Xcel Energy Inc., NSP-Minnesota, NSP-Wisconsin, PSCo and SPS each have individual commercial paper programs. As of Sept. 30, 2024, the authorized levels for these commercial paper programs are:
•$1.5 billion for Xcel Energy Inc.
•$700 million for PSCo.
•$700 million for NSP-Minnesota.
•$500 million for SPS.
•$150 million for NSP-Wisconsin.
Money Pool — Xcel Energy received FERC approval to establish a utility money pool arrangement with the utility subsidiaries, subject to receipt of required state regulatory approvals. The utility money pool allows for short-term investments in and borrowings between the utility subsidiaries.
Xcel Energy may make investments in the utility subsidiaries at market-based interest rates; however, the money pool arrangement does not allow the utility subsidiaries to make investments in Xcel Energy. The money pool balances are eliminated in consolidation. NSP-Minnesota, NSP-Wisconsin, PSCo and SPS participate in the money pool pursuant to approval from their respective state regulatory commissions.
Capital Expenditures — Base capital expenditures and incremental capital forecasts for Xcel Energy for 2025 through 2029 are as follows:

|  | Base Capital Forecast (Millions of Dollars)
By Regulated Utility |  | 2025 |  | 2026 |  | 2027 |  | 2028 |  | 2029 |  | Total
PSCo |  | $ | 5,820 |  |  | $ | 5,190 |  |  | $ | 3,940 |  |  | $ | 3,780 |  |  | $ | 3,550 |  |  | $ | 22,280 |
NSP-Minnesota |  | 3,240 |  |  | 2,500 |  |  | 2,830 |  |  | 2,080 |  |  | 2,570 |  |  | 13,220 |
SPS |  | 1,400 |  |  | 1,540 |  |  | 1,280 |  |  | 1,040 |  |  | 1,040 |  |  | 6,300 |
NSP-Wisconsin |  | 640 |  |  | 650 |  |  | 690 |  |  | 660 |  |  | 670 |  |  | 3,310 |
Other (a) |  | (100) |  |  | (40) |  |  | 10 |  |  | 10 |  |  | 10 |  |  | (110) |
Total base capital expenditures |  | $ | 11,000 |  |  | $ | 9,840 |  |  | $ | 8,750 |  |  | $ | 7,570 |  |  | $ | 7,840 |  |  | $ | 45,000 |

(a)Other category includes intercompany transfers for safe harbor wind turbines.

|  | Base Capital Forecast (Millions of Dollars)
By Function |  | 2025 |  | 2026 |  | 2027 |  | 2028 |  | 2029 |  | Total
Electric distribution |  | $ | 2,570 |  |  | $ | 3,000 |  |  | $ | 3,400 |  |  | $ | 3,320 |  |  | $ | 3,540 |  |  | $ | 15,830 |
Electric transmission |  | 2,260 |  |  | 2,860 |  |  | 2,740 |  |  | 2,390 |  |  | 2,310 |  |  | 12,560 |
Renewables |  | 3,360 |  |  | 1,400 |  |  | 260 |  |  | — |  |  | — |  |  | 5,020 |
Electric generation |  | 1,210 |  |  | 1,150 |  |  | 910 |  |  | 580 |  |  | 620 |  |  | 4,470 |
Natural gas |  | 800 |  |  | 680 |  |  | 690 |  |  | 630 |  |  | 620 |  |  | 3,420 |
Other |  | 800 |  |  | 750 |  |  | 750 |  |  | 650 |  |  | 750 |  |  | 3,700 |
Total base capital expenditures |  | $ | 11,000 |  |  | $ | 9,840 |  |  | $ | 8,750 |  |  | $ | 7,570 |  |  | $ | 7,840 |  |  | $ | 45,000 |

The base plan does not include any potential incremental generation or transmission assets that are pending commission approval through a RFP, a resource plan, or from additional data center load, which could result in additional capital expenditures of approximately $10 billion or greater. Xcel Energy generally expects to fund additional capital investment with approximately 40% equity and 60% debt.
Xcel Energy’s capital expenditure forecast is subject to continuing review and modification. Actual capital expenditures may vary from estimates due to changes in electric and natural gas projected load growth, safety and reliability needs, regulatory decisions, legislative initiatives, tax policy, reserve requirements, availability of purchased power, alternative plans for meeting long-term energy needs, environmental initiatives and regulation, and merger, acquisition and divestiture opportunities.
Financing for Capital Expenditures through 2029 — Xcel Energy issues debt and equity securities to refinance retiring debt maturities, reduce short-term debt, fund capital programs, infuse equity in subsidiaries, fund asset acquisitions and for general corporate purposes. Current estimated financing plans of Xcel Energy for 2025-2029 (includes the impact of tax credit transferability):

(Millions of Dollars) |  |
Funding Capital Expenditures |  |
Cash from operations (a) |  | $ | 25,320 |
New debt (b) |  | 15,180 |
Equity through the DRIP and benefit program |  | 500 |
Other equity |  | 4,000 |
Base capital expenditures 2025-2029 |  | $ | 45,000 |
Maturing debt |  | $ | 3,730 |

(a)Net of dividends and pension funding.
(b)Reflects a combination of short and long-term debt; net of refinancing.
2024 Financing Activity — Xcel Energy and its utility subsidiaries issued the following long-term debt:

Issuer |  | Security |  | Amount |  |  |  | Tenor |  | Coupon
Xcel Energy Inc. |  | Senior Unsecured Notes |  | $ | 800 | million |  |  |  | 10 Year |  | 5.50 | %
NSP-Minnesota |  | First Mortgage Bonds |  | 700 | million |  |  |  | 30 Year |  | 5.40 |
PSCo |  | First Mortgage Bonds |  | 1,200 | million |  |  |  | 10 Year & 30 Year |  | 5.35 & 5.75
SPS |  | First Mortgage Bonds |  | 600 | million |  |  |  | 30 Year |  | 6.00 |
NSP-Wisconsin |  | First Mortgage Bonds |  | 400 | million |  |  |  | 30 Year |  | 5.65 |

In the nine months ended Sept. 30, 2024, 18.27 million shares ($1.1 billion in net proceeds) were issued under an ATM program.
Long-Term Borrowings, Equity Issuances and Other Financing Instruments — Xcel Energy may issue equity through its ATM program or other offerings. Financing plans are subject to change, depending on capital expenditures, regulatory outcomes, internal cash generation, market conditions, changes in tax policies and other factors.
See Note 4 to the consolidated financial statements for further information.
Off-Balance-Sheet Arrangements
Xcel Energy does not have any off-balance-sheet arrangements, other than those currently disclosed, that have or are reasonably likely to have a current or future effect on financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources that is material to investors.
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Earnings Guidance and Long-Term EPS and Dividend Growth Rate Objectives
Xcel Energy 2024 Earnings Guidance — Xcel Energy’s 2024 ongoing earnings guidance is a range of $3.50 to $3.60 per share.(a)
Key assumptions as compared with 2023 actual levels unless noted:
•Constructive outcomes in all pending rate case and regulatory proceedings, including requests for deferral of incremental insurance costs associated with wildfire risk.
•Normal weather patterns for the remainder of the year.
•Weather-normalized retail electric sales are projected to increase ~1%.
•Weather-normalized retail firm natural gas sales are projected to decline by ~1%.
•Capital rider revenue is projected to increase $60 million to $70 million (net of PTCs).
•O&M expenses are projected to increase 3% to 4%.
•Depreciation expense is projected to increase approximately $290 million to $300 million.
•Property taxes are expected to decline $10 to $20 million.
•Interest expense (net of AFUDC - debt) is projected to increase $130 million to $140 million, net of interest income.
•AFUDC - equity is projected to increase $70 million to $80 million.
Xcel Energy 2025 Earnings Guidance — Xcel Energy’s 2025 ongoing earnings guidance is a range of $3.75 to $3.85 per share.(a)
Key assumptions as compared with 2024 projected levels unless noted:
•Constructive outcomes in all pending rate case and regulatory proceedings, including requests for deferral of incremental insurance costs associated with wildfire risk and recovery of O&M costs associated with wildfire mitigation plans.
•Normal weather patterns for the year.
•Weather-normalized retail electric sales are projected to increase ~3%.
•Weather-normalized retail firm natural gas sales are projected to increase ~1%.
•Capital rider revenue is projected to increase $240 million to $250 million (net of PTCs).
•O&M expenses are projected to increase ~3%.
•Depreciation expense is projected to increase approximately $210 million to $220 million.
•Property taxes are projected to increase $40 million to $50 million.
•Interest expense (net of AFUDC - debt) is projected to increase $130 million to $140 million, net of interest income.
•AFUDC - equity is projected to increase $120 million to $130 million.
(a)Ongoing earnings is calculated using net income and adjusting for certain nonrecurring or infrequent items that are, in management’s view, not reflective of ongoing operations. Ongoing earnings could differ from those prepared in accordance with GAAP for unplanned and/or unknown adjustments. As Xcel Energy is unable to quantify the financial impacts of any additional adjustments that may occur for the year, we are unable to provide a quantitative reconciliation of the guidance for ongoing EPS to corresponding GAAP EPS.
Long-Term EPS and Dividend Growth Rate Objectives — Xcel Energy expects to deliver an attractive total return to our shareholders through a combination of earnings growth and dividend yield, based on the following long-term objectives:
• Deliver long-term annual EPS growth of 6% to 8% based off of $3.55 per share (the mid-point of 2024 original ongoing earnings guidance of $3.50 to $3.60 per share).
• Deliver annual dividend increases of 4% to 6%.
• Target a dividend payout ratio of 50% to 60%.
• Maintain senior secured debt credit ratings in the A range.

ITEM 3 — QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

There have been no material changes to the market risk disclosure included in our Annual Report on Form 10-K for the year ended Dec. 31, 2023 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 Sept. 30, 2024, 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.
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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, 2023, which is incorporated herein by reference. There have been no material changes from the risk factors previously disclosed in the Form 10-K.

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

Purchases of Equity Securities by the Issuer and Affiliated Purchaser:
For the quarter ended Sept. 30, 2024, no equity securities that are registered by Xcel Energy Inc. pursuant to Section 12 of the Securities Exchange Act of 1934 were purchased by or on behalf of us or any of our affiliated purchasers.

ITEM 5 — OTHER INFORMATION

None of the Company’s directors or officers adopted, modified, or terminated a Rule 10b5-1 trading arrangement or a non-Rule 10b5-1 trading arrangement during the Company’s fiscal quarter ended Sept. 30, 2024.

ITEM 6 — EXHIBITS

* | Indicates incorporation by reference

Exhibit Number | Description | Report or Registration Statement | Exhibit Reference
3.01* | Amended and Restated Articles of Incorporation of Xcel Energy Inc., dated May 17, 2012 | Xcel Energy Inc. Form 8-K dated May 16, 2012 | 3.01
3.02* | Bylaws of Xcel Energy Inc., as Amended and Restated on August 23, 2023 | Xcel Energy Inc Form 8-K dated August 23, 2023 | 3.02
31.01 | Principal Executive Officer’s certifications pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 |  |
31.02 | Principal Financial Officer’s certifications pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 |  |
32.01 | Certifications pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 |  |
101.INS | Inline XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document |  |
101.SCH | Inline XBRL Schema |  |
101.CAL | Inline XBRL Calculation |  |
101.DEF | Inline XBRL Definition |  |
101.LAB | Inline XBRL Label |  |
101.PRE | Inline XBRL Presentation |  |
104 | Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101) |  |

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Table of Contents
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.
10/31/2024 | By: | /s/ MELISSA L. OSTROM
|  | Melissa L. Ostrom
|  | Senior Vice President, Controller
|  | (Principal Accounting Officer)
| By: | /s/ BRIAN J. VAN ABEL
|  | Brian J. Van Abel
|  | Executive Vice President, Chief Financial Officer
|  | (Principal Financial Officer)

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