Xcel Energy (NASDAQ: XEL) maps $60B grid investment and clean energy push
Filing Impact
Filing Sentiment
Form Type
10-K
Rhea-AI Filing Summary
Xcel Energy Inc. presents an overview of its regulated electric and natural gas business, serving 3.9 million electric and 2.2 million natural gas customers across eight states with total assets of
The company highlights a five-year capital plan of
Xcel notes a long record of meeting or exceeding ongoing EPS guidance for 21 consecutive years and delivering 23 straight years of dividend growth, while detailing extensive ESG initiatives, wildfire mitigation efforts, workforce diversity data and a broad set of operational, financial, regulatory, climate and cybersecurity risks that could affect future performance.
Positive
- None.
Negative
- None.
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(Mark One)
| ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 | |||||
For the fiscal year ended December 31, 2025 or
| TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 | |||||
For the transition period from _____ to _____
| (Commission File Number) | ||
| Xcel Energy Inc. | ||||||||
| (Exact name of registrant as specified in its charter) | ||||||||
| (State or Other Jurisdiction of Incorporation or Organization) | (IRS Employer Identification No.) | |||||||||||||
| (Address of Principal Executive Offices) | (Zip Code) | |||||||||||||
| (Registrant’s Telephone Number, Including Area Code) | |||||
Securities registered pursuant to Section 12(b) of the Act:
| Title of each class | Trading Symbol(s) | Name of each exchange on which registered | ||||||||||||
Securities registered pursuant to section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. ☒ Yes ☐ No
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. ☐ Yes ☒ No
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 has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C.7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☒
If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements. ☐
Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant’s executive officers during the relevant recovery period pursuant to §240.10D-1(b). ☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). ☐ Yes ☒ No
As of June 30, 2025, the aggregate market value of the voting common stock held by non-affiliates of the Registrant was $40,260,845,645 .
As of Feb. 19, 2026, there were 623,876,813 shares of common stock outstanding, $2.50 par value.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the Registrant’s definitive Proxy Statement for its 2026 Annual Meeting of Shareholders are incorporated by reference into Part III of this Form 10-K.
1
TABLE OF CONTENTS
| PART I | ||||||||
| Item 1 — | Business | 3 | ||||||
| Item 1A — | Risk Factors | 15 | ||||||
| Item 1B — | Unresolved Staff Comments | 21 | ||||||
| Item 1C — | Cybersecurity | 21 | ||||||
| Item 2 — | Properties | 23 | ||||||
| Item 3 — | Legal Proceedings | 24 | ||||||
| Item 4 — | Mine Safety Disclosures | 24 | ||||||
| PART II | ||||||||
| Item 5 — | Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities | 24 | ||||||
| Item 6 — | [Reserved] | 25 | ||||||
| Item 7 — | Management’s Discussion and Analysis of Financial Condition and Results of Operations | 25 | ||||||
| Item 7A — | Quantitative and Qualitative Disclosures About Market Risk | 43 | ||||||
| Item 8 — | Financial Statements and Supplementary Data | 43 | ||||||
| Item 9 — | Changes in and Disagreements With Accountants on Accounting and Financial Disclosure | 83 | ||||||
| Item 9A — | Controls and Procedures | 83 | ||||||
| Item 9B — | Other Information | 83 | ||||||
| Item 9C — | Disclosure Regarding Foreign Jurisdictions that Prevent Inspections | 83 | ||||||
| PART III | ||||||||
| Item 10 — | Directors, Executive Officers and Corporate Governance | 83 | ||||||
| Item 11 — | Executive Compensation | 83 | ||||||
| Item 12 — | Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters | 84 | ||||||
| Item 13 — | Certain Relationships and Related Transactions, and Director Independence | 84 | ||||||
| Item 14 — | Principal Accountant Fees and Services | 84 | ||||||
| PART IV | ||||||||
| Item 15 — | Exhibits and Financial Statement Schedules | 84 | ||||||
| Item 16 — | Form 10-K Summary | 91 | ||||||
Signatures | 92 | |||||||
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PART I
ITEM 1 — BUSINESS | ||
Definitions of Abbreviations
| Xcel Energy Inc.’s Subsidiaries and Affiliates (current and former) | |||||
| Capital Services | Capital Services, LLC | ||||
| Eloigne | Eloigne Company | ||||
| e prime | e prime inc. | ||||
| Nicollet Project Holdings | Nicollet Project Holdings, LLC | ||||
| 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 Co. | ||||
| Utility subsidiaries | NSP-Minnesota, NSP-Wisconsin, PSCo and SPS | ||||
| WGI | WestGas InterState, Inc. | ||||
| 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 | ||||
| DOE | United States Department of Energy | ||||
| DOT | United States Department of Transportation | ||||
| EIA | United States Energy Information Administration | ||||
| EPA | United States Environmental Protection Agency | ||||
| ERCOT | Electric Reliability Council of Texas | ||||
| FASB | Financial accounting standards board | ||||
| FERC | Federal Energy Regulatory Commission | ||||
| IRS | Internal Revenue Service | ||||
| MPUC | Minnesota Public Utilities Commission | ||||
| MPSC | Michigan Public Service Commission | ||||
| NDPSC | North Dakota Public Service Commission | ||||
| NERC | North American Electric Reliability Corporation | ||||
| NIST | National Institute of Standards and Technology | ||||
| NMPRC | New Mexico Public Regulation Commission | ||||
| NRC | Nuclear Regulatory Commission | ||||
| OAG | Minnesota Office of Attorney General | ||||
| PHMSA | Pipeline and Hazardous Materials Safety Administration | ||||
| PSCW | Public Service Commission of Wisconsin | ||||
| PUCT | Public Utility Commission of Texas | ||||
| SDPUC | South Dakota Public Utility Commission | ||||
| SEC | Securities and Exchange Commission | ||||
| Electric, Purchased Gas and Resource Adjustment Clauses | |||||
| CIP | Conservation improvement program | ||||
| DSM | Demand side management | ||||
| FCA | Fuel clause adjustment | ||||
| GCA | Gas cost adjustment | ||||
| GMAC | Grid modernization adjustment clause | ||||
| RES | Renewable energy standard | ||||
| Other | |||||
| ADIT | Accumulated deferred income taxes | ||||
| AFUDC | Allowance for funds used during construction | ||||
| ALJ | Administrative law judge | ||||
| ARO | Asset retirement obligation | ||||
| ARRR | Application for rehearing, reargument or reconsideration | ||||
| ASC | Financial Accounting Standards Board Accounting Standards Codification | ||||
| ASU | Accounting standards update | ||||
| ATM | At-the-market | ||||
| C&I | Commercial and industrial | ||||
| CapX2020 | Alliance of electric cooperatives, municipals and investor-owned utilities in the upper Midwest involved in a joint transmission line planning and construction effort | ||||
| CCR | Coal combustion residuals | ||||
| CCR Rule | Final rule (40 CFR 257.50 - 257.107) published by the 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 | ||||
| CIG | Colorado Interstate Gas Company, LLC | ||||
CO2 | Carbon dioxide | ||||
| COD | Commercial operation date | ||||
| CPCN | Certificate of public convenience and necessity | ||||
| CWIP | Construction work in progress | ||||
| DECON | Decommissioning method where radioactive contamination is removed and safely disposed of at a requisite facility or decontaminated to a permitted level | ||||
| DRIP | Dividend Reinvestment Program | ||||
| EEI | Edison Electric Institute | ||||
| EMANI | European Mutual Association for Nuclear Insurance | ||||
| EPS | Earnings per share | ||||
| ETR | Effective tax rate | ||||
| FTR | Financial transmission right | ||||
| GAAP | Generally accepted accounting principles | ||||
| GHG | Greenhouse gas | ||||
| HDD | Heating degree-days | ||||
| INPO | Institute of Nuclear Power Operations | ||||
| IRA | Inflation Reduction Act | ||||
| IPP | Independent power producing entity | ||||
| IRP | Integrated resource plan | ||||
| ISO | Independent system operator | ||||
| ITC | Investment tax credit | ||||
| MGP | Manufactured gas plant | ||||
| MISO | Midcontinent Independent System Operator, Inc. | ||||
| Native load | Demand of retail and wholesale customers that a utility has an obligation to serve under statute or contract | ||||
| NAV | Net asset value | ||||
| NEIL | Nuclear Electric Insurance Ltd. | ||||
| NOL | Net operating loss | ||||
| NOx | Nitrogen oxides | ||||
| O&M | Operating and maintenance | ||||
| OBBB | One Big Beautiful Bill Act | ||||
| ONES | Operations, Nuclear, Environmental and Safety | ||||
| PFAS | Per- and polyfluoroalkyl substances | ||||
| PIM | Performance incentive mechanism | ||||
| Post-65 | Post-Medicare | ||||
| PPA | Power purchase agreement | ||||
| Pre-65 | Pre-Medicare | ||||
| PTC | Production tax credit | ||||
| RDF | Refuse-derived fuel | ||||
| REC | Renewable energy credit | ||||
| RFP | Request for proposal | ||||
| ROE | Return on equity | ||||
| ROU | Right-of-use | ||||
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Table of Contents
| RTO | Regional transmission organization | ||||
| S&P | Standard & Poor’s Global Ratings | ||||
| SIP | State implementation plan | ||||
| SOFR | Secured overnight financing rate | ||||
| SPP | Southwest Power Pool, Inc. | ||||
| SRP | System resiliency plan | ||||
| TCJA | 2017 federal tax reform enacted as Public Law No: 115-97, commonly referred to as the Tax Cuts and Jobs Act | ||||
| THI | Temperature-humidity index | ||||
| TSR | Total shareholder return | ||||
| VaR | Value at risk | ||||
| VIE | Variable interest entity | ||||
| XLI | Xcel Large Industrials | ||||
| Measurements | |||||
| Bcf | Billion cubic feet | ||||
| KV | Kilovolts | ||||
| KWh | Kilowatt hours | ||||
| MMBtu | Million British thermal units | ||||
| MW | Megawatts | ||||
| MWh | Megawatt hours | ||||
Where to Find More Information | ||
Xcel Energy’s website address is www.xcelenergy.com. Xcel Energy makes available through its website, free of charge, its annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and all amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 as soon as reasonably practicable after the reports are electronically filed with or furnished to the SEC.
The SEC maintains an internet site that contains reports, proxy and information statements, and other information regarding issuers that file electronically at http://www.sec.gov. The information on Xcel Energy’s website is not a part of, or incorporated by reference in, this annual report on Form 10-K. Xcel Energy intends to make future announcements regarding Company developments and financial performance through its website, www.xcelenergy.com, as well as through press releases, filings with the SEC, conference calls and webcasts.
Forward-Looking Statements | ||
Except for the historical statements contained in this report, the matters discussed herein are forward-looking statements that are subject to certain risks, uncertainties and assumptions. Such forward-looking statements, including those relating to 2026 EPS guidance, long-term EPS and dividend growth rate objectives, future sales, future expenses, future tax rates, future operating performance, estimated base capital expenditures and financing plans, projected capital additions and forecasted annual revenue requirements with respect to rider filings, expected rate increases 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 elsewhere in this Annual Report on Form 10-K for the fiscal year ended Dec. 31, 2025 (including risk factors listed from time to time by Xcel Energy Inc. in reports filed with the SEC, including “Risk Factors” in Item 1A of this Annual Report on Form 10-K), could cause actual results to differ materially from management expectations as suggested by such forward-looking information: operational safety, including our nuclear generation facilities and other utility operations; successful long-term operational planning; risks associated with wildfires; commodity risks associated with energy markets and production; rising energy prices and fuel costs; qualified employee workforce and third-party contractor factors; reputational impacts of actions by employees, directors, or third-parties; our ability to recover costs and our subsidiaries’ ability to recover costs from customers; risks associated with the growth in large load customers; changes in regulation; reductions in our credit ratings and the cost of maintaining certain contractual relationships; general economic conditions, including recessionary conditions, inflation rates, monetary fluctuations, supply chain constraints and their impact on capital expenditures and/or the ability of Xcel Energy Inc. and its subsidiaries to obtain financing on favorable terms; availability or cost of capital; our customers’ and counterparties’ ability to pay their debts to us; assumptions and costs relating to funding our employee benefit plans and health care benefits; our subsidiaries’ ability to make dividend payments; tax laws; uncertainty regarding epidemics; effects of geopolitical events, including war and acts of terrorism; cybersecurity threats and data security breaches; seasonal weather patterns; changes in environmental laws and regulations; climate change and other weather events; natural disaster and resource depletion, including compliance with any accompanying legislative and regulatory changes; costs of potential regulatory penalties and wildfire damages in excess of liability insurance coverage; regulatory changes and/or limitations related to the use of natural gas as an energy source; challenging labor market conditions and our ability to attract and retain a qualified workforce; and our ability to execute on our strategies or achieve expectations related to environmental, social and governance matters including as a result of evolving legal, regulatory and other standards, processes, and assumptions, the pace of scientific and technological developments, increased costs, the availability of requisite financing, and changes in carbon markets.
Overview | ||
Xcel Energy (the “Company”) is a major U.S. regulated electric and natural gas delivery company headquartered in Minneapolis, Minnesota (incorporated in Minnesota in 1909). The Company serves customers in eight states, including portions of Colorado, Michigan, Minnesota, New Mexico, North Dakota, South Dakota, Texas and Wisconsin. Xcel Energy provides a comprehensive portfolio of energy-related products and services to approximately 3.9 million electric customers and 2.2 million natural gas customers through four utility subsidiaries (NSP-Minnesota, NSP-Wisconsin, PSCo and SPS). Along with the utility subsidiaries, the transmission-only subsidiaries, WYCO (a joint venture formed with CIG to develop and lease natural gas pipelines and storage facilities) and WGI (an interstate natural gas pipeline company) comprise the regulated utility operations. The Company’s nonregulated subsidiaries include Eloigne, Capital Services, Venture Holdings and Nicollet Project Holdings.
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| Subsidiary / Affiliate | Function | |||||||
| NSP-Minnesota | Electric & Gas | |||||||
| NSP-Wisconsin | Electric & Gas | |||||||
| PSCo | Electric & Gas | |||||||
| SPS | Electric | |||||||
| WGI | Interstate gas pipeline | |||||||
| WYCO | Gas storage and transportation | |||||||
| Other Subsidiaries | See Note 1 to the consolidated financial statements for further information. | |||||||
| Utility Subsidiary Overview | ||||||||
| Electric customers | 3.9 million | |||||||
| Natural gas customers | 2.2 million | |||||||
| Total assets | $81.4 billion | |||||||
| Electric generating capacity (owned) | 20,800 MW | |||||||
| Natural gas storage capacity | 53.3 Bcf | |||||||
| Electric transmission lines (conductor miles) | 115,000 miles | |||||||
| Electric distribution lines (conductor miles) | 225,000 miles | |||||||
| Natural gas transmission lines | 2,100 miles | |||||||
| Natural gas distribution lines | 38,000 miles | |||||||
| Service Territory | |||||||||||
Strategy | ||
Xcel Energy’s vision is to be the preferred and trusted provider of the energy our customers need. We will deliver on this vision while offering a competitive total return to our shareholders. Our mission is to make energy work better for our customers, helping them thrive every day.
We execute on our vision and mission through three strategic priorities.
| OUR CUSTOMERS | OUR PEOPLE | OUR PERFORMANCE | ||||||
| Enhance their experience with Xcel Energy and keep their bills as low as possible | Provide a rewarding employee experience, with development, engagement and growth | Deliver excellent operational, financial and clean energy performance | ||||||
Our employees are guided by four corporate values: Connected, Committed, Safe and Trustworthy.
Our values, culture and Code of Conduct serve as the foundation upon which Xcel Energy’s employees, Board of Directors, contractors and suppliers approach their work in delivering on our three strategic priorities.
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Table of Contents
OUR CUSTOMERS
Xcel Energy is leading the ongoing clean energy transition while remaining focused on what matters most: providing reliable, affordable energy that meets the increasing demands of our customers as they electrify more parts of their lives. Customer affordability remains central to our strategy. Through disciplined infrastructure investment and the advantages of our geographic footprint, we continue to deliver some of the lowest energy bills in the nation.
Xcel Energy has invested more than $2 billion over the past decade in a portfolio of renewable and conservation programs that provide customers with clean energy options and help keep bills low. New demand remains robust in our territories as we fuel the rapid growth from AI and data centers, industrial electrification and electric vehicle adoption. As such, we are transforming and expanding our electric grid to accommodate this load growth, and supporting our expanded portfolio of renewable energy and distributed energy resources.
Since 2020, our lean operating program has generated $1.5 billion of cumulative savings for our customers, while improving operating outcomes and reducing enterprise risk. At the same time, our Steel for Fuel strategy has saved customers nearly $6 billion since 2017 in avoided fuel costs and PTCs.
In turn, our residential customers in Colorado have the lowest share of wallet out of all 50 states, and average bills in our other states occupy 5 of the next 11 spots. Based on available EIA data, the five-year average residential electric and natural gas bills for an Xcel Energy customer are 28% and 12% below the national average. We continue to support critical programs to help our customers who may need assistance with their energy bills and reached nearly 200,000 customers and provided over $180 million in funding in 2025.
Going forward, our goal is to enable the clean energy transition while keeping long-term customer bill growth at inflation through initiatives including conservation programs, O&M cost control, our One Xcel Energy Way lean management initiative, advanced operational technologies and our Steel for Fuel program.
Investing in our communities means supporting a wide array of industries that strengthen local economies. In 2025, Xcel Energy initiated 15 economic development projects across our communities. Collectively, these projects are projected to generate more than $7 billion in capital investments and nearly 1,400 jobs. Nearly 53% of our supply chain spend was local and we spent nearly $1 billion with small or diverse suppliers.
In 2025, the Xcel Energy Foundation contributed $5 million in grant funding nearly 400 nonprofit organizations. Through our 2025 Power Your Purpose Giving Campaign, Xcel Energy employees, contractors and retirees donated nearly $3 million to over 1,400 nonprofit and community organizations – exceeding our fundraising goal. Combined with the Xcel Energy Foundation match to local United Way chapters, this campaign raised over $5 million for our communities. In 2025, employees volunteered nearly 100,000 hours in their communities. Our annual Day of Service attracted over 2,900 volunteers who committed nearly 8,900 hours at over 100 nonprofit projects across the company’s service footprint.
OUR PEOPLE
Champion Safety
Continuously elevating the quality and safety of the workplace is a top priority. We are considered a leader in safety for our Safety Always approach, focused on eliminating life-altering injuries through a trusted, transparent culture and the use of critical controls. All employees have “stop work authority” and are expected to keep each other, our customers and the public safe. Employees are encouraged to speak up, share experiences and learn from events to help protect themselves, their coworkers and the public.
The Board of Directors has oversight for employee and public safety through the Operations, Nuclear, Environmental and Safety committee, which is tied to annual incentive compensation.
Cultivate an Inclusive, Best-in-Class Workforce
We aim to create an inclusive work culture where employees are empowered to create innovative solutions, everyone is respected and there is a collective sense of belonging. We are building a workforce that reflects the broad range of backgrounds, experiences and perspectives within our communities and among our customers. This starts with our Board of Directors.
The Board of Directors has oversight for workforce strategy, through the Governance, Compensation and Nominating Committee, including our inclusion initiatives, employee safety and inclusion KPIs tied to annual incentive compensation.
In 2025, a total of 70% of annual incentive compensation was tied to safety, system reliability and inclusion metrics.
Management evaluates compensation and benefits to maintain a market-competitive, performance-based, shareholder-aligned total rewards package that supports our ability to attract, engage and retain a talented workforce.
We partner with educational and community organizations to recruit employees who reflect the communities we serve and live our values. Xcel Energy had 11,534 full-time employees and workforce demographics as of December 2025 were as follows:
| Female | Ethnically Diverse | |||||||
| Board of Directors | 33 | % | 8 | % | ||||
| CEO direct reports | 25 | 13 | ||||||
| Management | 24 | 12 | ||||||
| Employees | 23 | 19 | ||||||
| New hires | 41 | 28 | ||||||
| Interns (hired throughout 2025) | 41 | 42 | ||||||
Xcel Energy respects employees’ freedom of association and their right to collectively organize. As of Dec. 31, 2025, approximately 44% of our employees (5,036) were covered by collective bargaining agreements.
We are committed to the advancement and protection of human rights, consistent with U.S. human rights laws and the general principles in the International Labour Organization Conventions.
Annual Code of Conduct training is required for all employees and the Board of Directors. We do not tolerate Code of Conduct violations or other unacceptable behaviors. We expect and offer employees multiple avenues to raise concerns or report wrong-doing and do not permit any retaliation.
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OUR PERFORMANCE
Deliver a Competitive Total Return to Investors
Successful strategy execution, along with our disciplined approach to growth, operations and management of environmental, social and governance issues, positions us to continue delivering a competitive TSR.
We have consistently achieved our financial objectives, meeting or exceeding our initial ongoing earnings guidance range for 21 consecutive years and delivering dividend growth for 23 consecutive years.
Leading the Clean Energy Transition
Xcel Energy is committed to providing our customers with safe, reliable service at the lowest cost possible, while leading the clean energy transition. Over the next five years, we plan to make $60 billion of capital investments to improve reliability, resiliency and sustainability and support demand growth across our system. Significant investment in our transmission and distribution systems is essential to ensure resiliency and reliability for customers, we have approximately $29 billion in our 2026 - 2030 capital plan focused specifically on this.
Our current sustainability commitments are summarized as follows:
See Item 1A for risks and uncertainties related to strategic and sustainability goals and objectives.
Zero-Carbon Electricity by 2050
Xcel Energy’s operating footprint includes some of the best wind and solar resources in the country, providing for higher capacity factors and lower electricity costs.
Xcel Energy’s wind capacity is now approximately 11,000 MW, including nearly 4,500 MW of owned wind. In 2025, we completed the second phase of our Sherco Solar project in Minnesota, with a third phase coming online in 2026, making it the largest solar facility in the upper Midwest. We are also proposing to add a fourth phase, which would bring the facility’s total generating capacity to 910 MW by 2029, providing enough clean energy to power 190,000 homes across the upper Midwest.
In our base 2026 - 2030 capital investment plan, we have ~9,500 MW of new and repowered wind, solar, and battery storage resources included and ~3,000 MW of new natural gas generation to ensure reliability.
Through 2025, we reduced carbon emissions from generation serving customers by an estimated 58% (from 2005 levels) and remain on track to fully exit coal by the end of 2030.
Natural Gas Use in Buildings – Net-Zero GHG by 2050
Xcel Energy continues on the path to achieve our 2050 goal to provide net-zero natural gas service to our customers. Our net-zero natural gas frameworks include the following priorities:
•Operating a safe, reliable gas system with net-zero methane gas service by 2030.
•Optimizing the energy system with voluntary electrification-first approaches for new growth.
•Providing customers with a portfolio of energy solutions while ensuring we meet requirements of our regulators.
Electrification of the Transportation Sector
We are also helping reduce carbon emissions in other sectors, including transportation. By 2035, Xcel Energy aims to enable the charging infrastructure for 1.5 million electric vehicles across the areas we serve. We have approved clean transportation programs and plans in Colorado, New Mexico, Minnesota and Wisconsin.
Wildfire Resiliency and Mitigation
Protecting our customers and our system from the threats of extreme weather is a top priority for Xcel Energy. In 2025, we received commission approvals from both the Colorado and Texas commissions for our wildfire mitigation and system resiliency plans, as well as have public facing wildfire mitigation plans in each of our states. This includes investments in advanced camera and weather station technologies, enhanced powerline safety setting installations, pole inspections and replacements, and operational measures such as wildfire safety operations and public safety power shutoffs.
In 2025, supportive utility wildfire legislation also passed in Texas and North Dakota, and we continue to explore similar structures in our other states.
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Utility Subsidiaries
NSP-Minnesota | |||||||||||||||||
 | |||||||||||||||||
| Electric customers | 1.6 million | NSP-Minnesota conducts business in Minnesota, North Dakota and South Dakota and has electric operations in all three states including the generation, purchase, transmission, distribution and sale of electricity. NSP-Minnesota and NSP-Wisconsin electric operations are managed on the NSP System. NSP-Minnesota also purchases, transports, distributes and sells natural gas to retail customers and transports customer-owned natural gas in Minnesota and North Dakota. | |||||||||||||||
| Natural gas customers | 0.6 million | ||||||||||||||||
| Total assets | $31.0 billion | ||||||||||||||||
| Rate Base (estimated) | $19.4 billion | ||||||||||||||||
| GAAP ROE | 9.19% | ||||||||||||||||
| Electric generating capacity (owned) | 8,700 MW | ||||||||||||||||
| Gas storage capacity | 16.9 Bcf | ||||||||||||||||
| Electric transmission lines (conductor miles) | 34,000 miles | ||||||||||||||||
| Electric distribution lines (conductor miles) | 87,000 miles | ||||||||||||||||
| Natural gas transmission lines | 78 miles | ||||||||||||||||
| Natural gas distribution lines | 11,000 miles | ||||||||||||||||
NSP-Wisconsin | |||||||||||||||||
 | |||||||||||||||||
| Electric customers | 0.3 million | NSP-Wisconsin conducts business in Wisconsin and Michigan and generates, purchases, transmits, distributes and sells electricity. NSP-Minnesota and NSP-Wisconsin electric operations are managed on the NSP System. NSP-Wisconsin also purchases, transports, distributes and sells natural gas to retail customers and transports customer-owned natural gas. | |||||||||||||||
| Natural gas customers | 0.1 million | ||||||||||||||||
| Total assets | $4.7 billion | ||||||||||||||||
| Rate Base (estimated) | $3.5 billion | ||||||||||||||||
| GAAP ROE | 9.09% | ||||||||||||||||
| Electric generating capacity (owned) | 500 MW | ||||||||||||||||
| Gas storage capacity | 4.3 Bcf | ||||||||||||||||
| Electric transmission lines (conductor miles) | 12,000 miles | ||||||||||||||||
| Electric distribution lines (conductor miles) | 29,000 miles | ||||||||||||||||
| Natural gas transmission lines | 3 miles | ||||||||||||||||
| Natural gas distribution lines | 3,000 miles | ||||||||||||||||
PSCo | |||||||||||||||||
 | |||||||||||||||||
| Electric customers | 1.6 million | PSCo conducts business in Colorado and generates, purchases, transmits, distributes and sells electricity. PSCo also purchases, transports, distributes and sells natural gas to retail customers and transports customer-owned natural gas. | |||||||||||||||
| Natural gas customers | 1.5 million | ||||||||||||||||
| Total assets | $31.8 billion | ||||||||||||||||
| Rate Base (estimated) | $23.8 billion | ||||||||||||||||
| GAAP ROE | 5.66% | ||||||||||||||||
| Ongoing ROE (See Item 7) | 7.55% | ||||||||||||||||
| Electric generating capacity (owned) | 6,500 MW | ||||||||||||||||
| Gas storage capacity | 32.1 Bcf | ||||||||||||||||
| Electric transmission lines (conductor miles) | 27,000 miles | ||||||||||||||||
| Electric distribution lines (conductor miles) | 84,000 miles | ||||||||||||||||
| Natural gas transmission lines | 2,000 miles | ||||||||||||||||
| Natural gas distribution lines | 24,000 miles | ||||||||||||||||
| SPS | |||||||||||||||||
 | |||||||||||||||||
SPS conducts business in Texas and New Mexico and generates, purchases, transmits, distributes and sells electricity. | |||||||||||||||||
| Electric customers | 0.4 million | ||||||||||||||||
| Total assets | $12.0 billion | ||||||||||||||||
| Rate Base (estimated) | $9.1 billion | ||||||||||||||||
| GAAP ROE | 8.70% | ||||||||||||||||
| Electric generating capacity (owned) | 5,100 MW | ||||||||||||||||
| Electric transmission lines (conductor miles) | 41,000 miles | ||||||||||||||||
| Electric distribution lines (conductor miles) | 25,000 miles | ||||||||||||||||
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Operations Overview | ||
Utility operations are generally conducted as either electric or gas utilities in our four utility subsidiaries.
Electric Operations | ||
Electric operations consist of energy supply, generation, transmission and distribution activities across all four utility subsidiaries. Xcel Energy had electric sales volume of 109,401 (millions of KWh), 3.9 million customers and electric revenues of $12,160 million for 2025.
| Electric Operations (percentage of total) | Sales Volume | Number of Customers | Revenues | |||||||||||||||||
| Residential | 24 | % | 86 | % | 32 | % | ||||||||||||||
| C&I | 61 | 12 | 49 | |||||||||||||||||
| Other | 15 | 2 | 19 | |||||||||||||||||
Retail Sales/Revenue Statistics (a)
| 2025 | 2024 | |||||||||||||
| KWh sales per retail customer | 24,177 | 23,908 | ||||||||||||
| Revenue per retail customer | $ | 2,568 | $ | 2,357 | ||||||||||
| Residential revenue per KWh | 14.91 | ¢ | 13.82 | ¢ | ||||||||||
| C&I revenue per KWh | 8.87 | ¢ | 8.24 | ¢ | ||||||||||
| Total retail revenue per KWh | 10.62 | ¢ | 9.86 | ¢ | ||||||||||
(a)See Note 6 to the consolidated financial statements for further information.
Owned and Purchased Energy Generation — 2025
Electric Energy Sources
Total electric energy generation by source for the year ended Dec. 31:
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Carbon-Free
Xcel Energy’s carbon-free energy portfolio includes wind, nuclear, hydroelectric, biomass and solar power from both owned generation facilities and PPAs. Carbon-free percentages will vary year-over-year based on system additions, commodity costs, weather, system demand and transmission constraints.
See Item 2 — Properties for further information.
Wind
Wind capacity is shown as net maximum capacity. Net maximum capacity is attainable only when wind conditions are sufficiently available.
Owned — Owned and operated wind farms with corresponding capacity:
| Utility Subsidiary | 2025 | 2024 | ||||||||||||||||||||||||
| Wind Farms | Capacity (MW) | Wind Farms | Capacity (MW) | |||||||||||||||||||||||
| NSP System | 17 | 2,451 | 17 | 2,445 | ||||||||||||||||||||||
| PSCo | 2 | 1,059 | 2 | 1,059 | ||||||||||||||||||||||
| SPS | 2 | 986 | 2 | 985 | ||||||||||||||||||||||
| Total | 21 | 4,496 | 21 | 4,489 | ||||||||||||||||||||||
PPAs — Number of PPAs with capacity range:
| Utility Subsidiary | 2025 | 2024 | ||||||||||||||||||||||||
| PPAs | Range (MW) | PPAs | Range (MW) | |||||||||||||||||||||||
| NSP System | 95 | 1 — 206 | 116 | 1 — 206 | ||||||||||||||||||||||
| PSCo | 16 | 23 — 301 | 16 | 23 — 301 | ||||||||||||||||||||||
| SPS | 15 | 1 — 250 | 16 | 1 — 250 | ||||||||||||||||||||||
PPAs — Contracted wind capacity (MW) for PPAs:
| Utility Subsidiary | 2025 | 2024 | ||||||||||||
| NSP System | 2,026 | 2,061 | ||||||||||||
| PSCo | 2,996 | 2,996 | ||||||||||||
| SPS | 1,482 | 1,562 | ||||||||||||
Average Cost — Average cost per MWh of wind energy from owned generation and existing PPAs:
| Type | Utility Subsidiary | 2025 | 2024 | |||||||||||||||||
Owned Generation (a) | NSP System | $ | 6 | $ | 7 | |||||||||||||||
| PPA | NSP System | 33 | 32 | |||||||||||||||||
Owned Generation (a) | PSCo | 2 | 4 | |||||||||||||||||
| PPA | PSCo | 44 | 43 | |||||||||||||||||
Owned Generation (a) | SPS | 3 | 1 | |||||||||||||||||
| PPA | SPS | 27 | 28 | |||||||||||||||||
(a)Includes the impact of PTCs.
Solar
Owned — Owned and operated solar projects with corresponding capacity:
| Utility Subsidiary | 2025 | 2024 | ||||||||||||||||||||||||
| Solar Projects | Capacity (MW) | Solar Projects | Capacity (MW) | |||||||||||||||||||||||
| NSP System | 1 | 460 | 1 | 223 | ||||||||||||||||||||||
| PSCo | 1 | 325 | — | — | ||||||||||||||||||||||
| Total | 2 | 785 | 1 | 223 | ||||||||||||||||||||||
PPAs — Solar PPAs capacity by type:
| Type | Utility Subsidiary | Capacity (MW) | ||||||||||||
| Distributed Generation | NSP System | 1,405 | ||||||||||||
| Utility-Scale | NSP System | 454 | ||||||||||||
| Distributed Generation | PSCo | 1,184 | ||||||||||||
Utility-Scale (a) | PSCo | 1,530 | ||||||||||||
| Distributed Generation | SPS | 57 | ||||||||||||
| Utility-Scale | SPS | 192 | ||||||||||||
| Total | 4,822 | |||||||||||||
(a)Includes battery storage capacity of 225 MW.
Average Cost — Average cost per MWh of solar energy under existing distributed and utility-scale generation PPAs:
| Type | Utility Subsidiary | 2025 | 2024 | ||||||||||||||
Owned Generation (a) (b) | NSP System | $ | 54 | N/A | |||||||||||||
| PPA | NSP System | 97 | 100 | ||||||||||||||
| PPA | PSCo | 31 | 31 | ||||||||||||||
| PPA | SPS | 69 | 68 | ||||||||||||||
(a)Average cost per MWh includes projects placed in service in 2024. For projects placed in service in 2025, cost per MWh will be available after a full year of operations.
(b)Includes the impact of PTCs.
Nuclear
Xcel Energy has two nuclear plants with approximately 1,700 MW of total 2025 net summer dependable capacity that safely and reliably generates carbon free electricity for the NSP System. Xcel Energy secures contracts for uranium concentrates, uranium conversion, uranium enrichment and fuel fabrication to operate its nuclear plants. We use varying contract lengths as well as multiple producers for uranium concentrates, conversion services and enrichment services to minimize potential impacts caused by supply interruptions due to geographical and world political issues.
Nuclear Fuel Cost — Delivered cost per MMBtu of nuclear fuel consumed for owned electric generation and the percentage of total fuel requirements (nuclear, natural gas and coal):
| Utility Subsidiary | Nuclear | |||||||||||||
| NSP System | Cost | Percent | ||||||||||||
| 2025 | $ | 0.82 | 54 | % | ||||||||||
| 2024 | $ | 0.83 | 43 | % | ||||||||||
Other — Xcel Energy’s other carbon-free energy portfolio includes hydro from owned generating facilities.
See Item 2 — Properties for further information.
Fossil Fuel
Xcel Energy’s fossil fuel energy portfolio includes coal and natural gas power from both owned generating facilities and PPAs.
Coal
Xcel Energy owned and operated coal units with approximately 4,500 MW of total 2025 net summer dependable capacity. This amount includes the coal unit at Pawnee, which is in the process of being converted to natural gas (net summer dependable capacity of 505 MW) and approximately 100 MW derived from RDF and wood fuel sources.
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Xcel Energy has plans to retire or convert to natural gas all of its existing coal generation by the end of 2030. Approved early coal plant retirements:
| Year | Utility Subsidiary | Plant Unit | Capacity (MW) | ||||||||||||||||||||
| 2026 | PSCo | Craig 1 (a) | 42 | (b) | |||||||||||||||||||
| 2026 | PSCo | Comanche 2 (c) | 330 | ||||||||||||||||||||
| 2026 | NSP-Minnesota | Sherco 1 | 680 | ||||||||||||||||||||
| 2027 | PSCo | Hayden 2 | 98 | (b) | |||||||||||||||||||
| 2028 | PSCo | Hayden 1 | 135 | (b) | |||||||||||||||||||
| 2028 | PSCo | Craig 2 | 40 | (b) | |||||||||||||||||||
| 2028 | NSP-Minnesota | A.S. King | 511 | ||||||||||||||||||||
| 2028 | SPS | Tolk 1 | 532 | ||||||||||||||||||||
| 2028 | SPS | Tolk 2 | 535 | ||||||||||||||||||||
| 2030 | NSP-Minnesota | Sherco 3 | 517 | (b) | |||||||||||||||||||
| 2030 | PSCo | Comanche 3 | 500 | (b) | |||||||||||||||||||
(a)In December 2025, the DOE issued an emergency order pursuant to section 202(c) of the Federal Power Act to Tri-State Generation and Transmission Association and other co-owners – including Xcel Energy – directing the co-owners to take all measures necessary to ensure that Unit 1 at the Craig Station in Craig, Colorado is available to operate. This order is in effect from December 30, 2025 through March 30, 2026. PSCo is working with Tri-State and the other partners in complying with the order.
(b)Based on Xcel Energy’s ownership interest.
(c)In December 2025, the CPUC issued a decision approving a variance that allows for the continued operation of Comanche Unit 2 in 2026, past the previously established retirement date of Dec. 31, 2025. The decision was issued in response to a joint petition filed by the trial staff of the CPUC, the Colorado Energy Office, the Colorado Office of the Utility Consumer Advocate, and PSCo seeking to modify the Comanche Unit 2 retirement date. PSCo also entered into an agreement with the Colorado Department of Public Health and Environment that establishes compliance obligations for continued operation of the unit through 2026.
Coal Fuel Cost — Delivered cost per MMBtu of coal consumed for owned electric generation and the percentage of fuel requirements (nuclear, natural gas and coal):
Coal (a) | ||||||||||||||
| Utility Subsidiary | Cost | Percent | ||||||||||||
| NSP System | ||||||||||||||
| 2025 | $ | 1.97 | 31 | % | ||||||||||
| 2024 | 2.24 | 22 | ||||||||||||
| PSCo | ||||||||||||||
| 2025 | 1.71 | 42 | ||||||||||||
| 2024 | 1.91 | 44 | ||||||||||||
| SPS | ||||||||||||||
| 2025 | 2.95 | 21 | ||||||||||||
| 2024 | 2.87 | 34 | ||||||||||||
(a)Includes RDF and wood for the NSP System.
Natural Gas
Xcel Energy owned and operated natural gas plants with approximately 9,000 MW of total 2025 net summer dependable capacity.
Natural gas supplies, transportation and storage services for power plants are procured to provide an adequate supply of fuel. Remaining requirements are procured through a liquid spot market. Generally, natural gas supply contracts have variable pricing that is tied to natural gas indices. Natural gas supply and transportation agreements include obligations for the purchase and/or delivery of specified volumes or payments in lieu of delivery.
Natural Gas Cost — Delivered cost per MMBtu of natural gas consumed for owned electric generation and the percentage of total fuel requirements (nuclear, natural gas and coal):
| Natural Gas | ||||||||||||||
| Utility Subsidiary | Cost | Percent | ||||||||||||
| NSP System | ||||||||||||||
| 2025 | $ | 4.46 | 15 | % | ||||||||||
| 2024 | 1.94 | 35 | ||||||||||||
| PSCo | ||||||||||||||
| 2025 | 3.63 | 58 | ||||||||||||
| 2024 | 2.77 | 56 | ||||||||||||
| SPS | ||||||||||||||
| 2025 | 1.99 | 79 | ||||||||||||
| 2024 | 0.94 | 66 | ||||||||||||
Capacity and Demand
Uninterrupted system peak demand and occurrence date:
| 2025 | 2024 | |||||||||||||||||||||||||
| Utility Subsidiary | MW | Date | MW | Date | ||||||||||||||||||||||
NSP System | 8,445 | July 15 | 8,822 | Aug. 26 | ||||||||||||||||||||||
| PSCo | 7,010 | July 28 | 7,084 | Aug. 1 | ||||||||||||||||||||||
| SPS | 4,519 | Aug. 8 | 4,437 | Aug. 19 | ||||||||||||||||||||||
Transmission
Transmission lines deliver electricity at high voltages and over long distances from power sources to substations closer to customers. A strong transmission system ensures continued reliable and affordable service, ability to meet state and regional energy policy goals, and support for a diverse generation mix, including renewable energy. Xcel Energy owns approximately 115,000 conductor miles of transmission lines across its service territory.
See Item 2 - Properties for further information.
Distribution
Distribution lines allow electricity to travel at lower voltages from substations directly to customers. Xcel Energy has a vast distribution network, owning and operating approximately 225,000 conductor miles of distribution lines across our eight-state service territory.
See Item 2 - Properties for further information.
| Natural Gas Operations | ||
Natural gas operations consist of purchase, transportation and distribution of natural gas to end-use residential, C&I and transport customers in NSP-Minnesota, NSP-Wisconsin and PSCo. Xcel Energy had natural gas deliveries of 400,982 (thousands of MMBtu), 2.2 million customers and natural gas revenues of $2,452 million for 2025.
| Natural Gas (percentage of total) | Deliveries | Number of Customers | Revenues | |||||||||||||||||
| Residential | 35 | % | 92 | % | 58 | % | ||||||||||||||
| C&I | 24 | 8 | 30 | |||||||||||||||||
| Transportation and other | 41 | <1 | 12 | |||||||||||||||||
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Sales/Revenue Statistics (a)(b)
| 2025 | 2024 | |||||||||||||
| MMBtu sales per retail customer | 108 | 105 | ||||||||||||
| Revenue per retail customer | $ | 981 | $ | 896 | ||||||||||
| Residential revenue per MMBtu | 10.02 | 9.48 | ||||||||||||
| C&I revenue per MMBtu | 7.78 | 7.04 | ||||||||||||
| Transportation and other revenue per MMBtu | 1.06 | 1.10 | ||||||||||||
(a)See Note 6 to the consolidated financial statements for further information.
(b)Fluctuations in natural gas revenues associated with changes in natural gas sold and transported generally do not significantly impact earnings.
Capability and Demand
Natural gas supply requirements are categorized as firm or interruptible.
Maximum daily output (firm and interruptible) and occurrence date:
| 2025 | 2024 | |||||||||||||||||||||||||
| Utility Subsidiary | MMBtu | Date | MMBtu | Date | ||||||||||||||||||||||
| NSP-Minnesota | 927,557 | Dec. 12 | 841,164 | Jan. 19 | ||||||||||||||||||||||
| NSP-Wisconsin | 177,201 | Jan. 20 | 163,246 | Jan.17 | ||||||||||||||||||||||
| PSCo | 2,148,039 | Jan. 20 | 2,357,931 | Jan.15 | ||||||||||||||||||||||
Natural Gas Supply and Cost
Xcel Energy seeks natural gas supply, transportation and storage alternatives to yield a diversified portfolio, which increases flexibility and decreases interruption, financial risks and customer rates. In addition, the utility subsidiaries conduct natural gas price hedging activities approved by their states’ commissions.
Average delivered cost per MMBtu of natural gas for regulated retail distribution:
| Utility Subsidiary | 2025 | 2024 | ||||||||||||
| NSP-Minnesota | $ | 4.31 | $ | 3.97 | ||||||||||
| NSP-Wisconsin | 4.31 | 3.77 | ||||||||||||
| PSCo | 3.68 | 3.36 | ||||||||||||
NSP-Minnesota, NSP-Wisconsin and PSCo have natural gas supply transportation and storage agreements that include obligations for purchase and/or delivery of specified volumes or to make payments in lieu of delivery.
| General | ||
General Economic Conditions
Economic conditions may have a material impact on Xcel Energy’s operating results. Management cannot predict the impact of fluctuating energy or commodity prices, pandemics, terrorist activity, war or the threat of war. We could experience a material impact to our results of operations, future growth or ability to raise capital resulting from a sustained general slowdown in economic growth or a significant increase in interest rates or inflation.
Seasonality
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 warmer in the winter and cooler in the summer. Sales true-up and decoupling mechanisms mitigate the impacts of weather in certain jurisdictions.
Competition
Xcel Energy is subject to public policies that promote competition and development of energy markets. Xcel Energy’s industrial and large commercial customers have the ability to generate their own electricity. In addition, customers may have the option of substituting other fuels or relocating their facilities to a lower cost region.
Customers have the opportunity to supply their own power with distributed generation including solar generation and can currently avoid paying for most of the fixed production, transmission and distribution costs incurred to serve them in most jurisdictions.
Several states have incentives for the development of rooftop solar, community solar gardens and other distributed energy resources. Distributed generating resources are potential competitors to Xcel Energy’s electric service business with these incentives and federal tax subsidies.
The FERC has continued to promote competitive wholesale markets through open access transmission and other means. Xcel Energy’s wholesale customers can purchase energy from other generation resources and transmission services from other service providers to serve their native load.
FERC Order No. 1000 established competition for ownership of certain new electric transmission facilities under Federal regulations. Some states have state laws that allow the incumbent a Right of First Refusal to own these transmission facilities.
FERC Order 2222 requires that RTO and ISO markets allow participation of aggregations of distributed energy resources. This order is expected to incentivize distributed energy resource adoption, however implementation is expected to vary by RTO/ISO and the near, medium, and long-term impacts of Order 2222 remain unclear.
Xcel Energy Inc.’s utility subsidiaries have franchise agreements with cities subject to periodic renewal; however, a city could seek alternative means to access electric power or gas, such as municipalization. No municipalization activities are occurring presently.
While each utility subsidiary faces these challenges, Xcel Energy believes their rates and services are competitive with alternatives currently available.
| Governmental Regulations | ||
Public Utility Regulation
See Item 7 for discussion of public utility regulation.
Environmental Regulation
Our facilities are regulated by federal and state agencies that have jurisdiction over air emissions, water quality, wastewater discharges, solid and hazardous wastes or substances. Certain Xcel Energy activities require registrations, permits, licenses, inspections and approvals from these agencies.
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Xcel Energy has received necessary authorizations for the construction and continued operation of its generation, transmission and distribution systems. Our facilities strive to operate in compliance with applicable environmental standards and related monitoring and reporting requirements.
There are significant environmental regulations to encourage use of clean energy technologies and regulate emissions of GHGs. We have undertaken numerous initiatives to meet current requirements and prepare for potential future regulations, reduce GHG emissions and respond to state renewable and energy efficiency goals. Future environmental regulations may result in substantial costs. However, costs to comply with past environmental regulations have largely been recoverable through rates.
Emerging Environmental Regulation
Throughout 2025, the EPA has announced various regulatory actions addressing a wide range of environmental regulations. Xcel Energy will continue to monitor these proposed rules as they move toward final action. Additionally, any other amendments and changes to rules will be evaluated as proposed by the EPA.
Clean Air Act
Power Plant Greenhouse Gas Regulations — In April 2024, the EPA published final rules addressing control of CO2 emissions from the power sector. The rules regulate new natural gas generating units and emission guidelines for existing coal and certain natural gas generation.
Based on current estimates and assumptions, Xcel Energy has determined that due to scheduled plant retirements, there is minimal financial or operational impact associated with these requirements and believes that the cost of these initiatives or replacement generation would be recoverable through rates based on prior state commission practices.
In June 2025, the EPA proposed to repeal these and all other GHG emissions standards for the power sector. In the alternative, the EPA proposed to repeal a narrower subset of the 2024 regulations.
In February 2026, the EPA issued a final rule repealing the 2009 Endangerment Finding and associated regulations addressing GHG emissions from the transportation sector under the Clean Air Act. Xcel Energy will monitor any additional proposed rules and evaluate the impacts of any final rule on the utility sector.
Waste-to-Energy Air Regulations — In January 2024, the EPA proposed air regulations addressing new and existing large municipal waste combustors. The proposed rules lower current emission standards for certain pollutants and would require installation of new pollution controls and/or more intense use of existing pollution controls at French Island Generating Station, Red Wing Generating Plant and Wilmarth Generating Plant. Until final rules are issued, it is not certain what the impact will be on Xcel Energy. Xcel Energy believes that the cost of these initiatives or replacement generation would be recoverable through rates based on prior state commission practices.
Regional Haze — In July 2025, the EPA proposed to partially approve and partially disapprove the 2022 Colorado SIP revision implementing the Regional Haze rule in Colorado. The proposal sought to remove mandatory retirement dates as enforceable provisions in the SIP.
In January 2026, the EPA issued a final rule fully disapproving the 2022 Colorado SIP revision, thereby removing the mandatory retirement dates. The removal of the retirement dates from a federally approved SIP would only impact whether the SIP provisions become federally enforceable. Colorado has a state regulation that reflects the SIP requirements, including retirement dates for Cherokee Unit 4, Comanche Unit 2, Craig Units 1 and 2, and Hayden Units 1 and 2 at a state level and would require amendment to modify or remove retirement dates.
Emerging Contaminants of Concern
PFAS are man-made chemicals that are widely used in consumer products and can persist and bio-accumulate in the environment. Xcel Energy does not manufacture PFAS, but because PFAS are so ubiquitous in products and the environment, it may impact our operations.
In June 2024, the EPA finalized a rule that designated certain PFAS as hazardous substances under CERCLA. In July 2024, the EPA finalized another rule that set enforceable drinking water standards for certain PFAS.
Potential costs for these rules and any additional proposed regulations related to PFAS are uncertain and will be determined on a site specific basis where applicable. If costs are incurred, Xcel Energy believes the costs will be recoverable through rates based on prior state commission practices.
Effluent Limitation Guidelines
In April 2024, the EPA published final rules under the Clean Water Act, setting Effluent Limitations Guidelines and Standards for steam generating coal plants. This rule establishes more stringent wastewater discharge standards for bottom ash transport water, flue-gas desulfurization wastewater, and combustion residuals leachate from steam electric power plants, particularly coal-fired power plants. Based on current estimates and assumptions, Xcel Energy has determined that there is minimal financial or operational impact associated with these requirements and that any costs would be recoverable through rates based on prior state commission practices.
Environmental Costs
Environmental costs include amounts for nuclear plant decommissioning and payments for storage of spent nuclear fuel, disposal of hazardous materials and waste, remediation of contaminated sites, monitoring of discharges to the environment and compliance with laws and permits with respect to emissions.
Costs charged to operating expenses for spent nuclear fuel disposal, environmental monitoring and remediation and disposal of hazardous materials and waste and depreciation of previously incurred capital expenditures for environmental improvements were approximately:
•$280 million in 2025.
•$290 million in 2024.
•$275 million in 2023.
Average annual expense of approximately $295 million from 2026 – 2030 is estimated for similar costs. The precise timing and amount of environmental costs, including those for site remediation and disposal of hazardous materials, are unknown. Additionally, the extent to which environmental costs will be recovered through rates may fluctuate.
Capital expenditures for environmental improvements were approximately:
•$35 million in 2025.
•$25 million in 2024.
•$20 million in 2023.
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Certain previously collected nuclear storage costs for the federal nuclear waste program are reimbursed to customers by the federal government as a result of a settlement we pursued regarding the government’s failure to deliver a disposal program. Installments received are reimbursed to customers as approved by the MPUC and other state regulators.
Other
Our operations are subject to workplace safety standards under the Federal Occupational Safety and Health Act of 1970 (“OSHA”) and comparable state laws that regulate the protection of worker health and safety. In addition, the Company is subject to other government regulations impacting such matters as labor, competition, data privacy, etc. Based on information to date and because our policies and business practices are designed to comply with all applicable laws, we do not believe the effects of compliance on our operations, financial condition or cash flows are material.
| Capital Spending and Financing | ||
See Item 7 for discussion of capital expenditures and funding sources.
Information about our Executive Officers (a) | ||||||||||||||||||||
| Name | Age | Current and Recent Positions | Time in Position | |||||||||||||||||
| Robert C. Frenzel | 55 | Chairman of the Board of Directors, Xcel Energy Inc. | December 2021 — Present | |||||||||||||||||
| President and Chief Executive Officer and Director, Xcel Energy Inc. | August 2021 — Present | |||||||||||||||||||
| Chief Executive Officer, NSP-Minnesota, NSP-Wisconsin, PSCo and SPS | August 2021 — Present | |||||||||||||||||||
| President and Chief Operating Officer, Xcel Energy Inc. | March 2020 — August 2021 | |||||||||||||||||||
| Executive Vice President, Chief Financial Officer, Xcel Energy Inc. | May 2016 — March 2020 | |||||||||||||||||||
| Patricia Correa | 52 | Senior Vice President, Chief Human Resources Officer, Xcel Energy Inc. | February 2022 — Present | |||||||||||||||||
| Senior Vice President, Human Resources, Eaton Corporation, a power management company | July 2019 — January 2022 | |||||||||||||||||||
| Michael Lamb | 61 | Executive Vice President, Chief Delivery Officer Xcel Energy Inc. | May 2025 — Present | |||||||||||||||||
| Senior Vice President, Customer Delivery, Xcel Energy Inc. | September 2024 — April 2025 | |||||||||||||||||||
| Senior Vice President, Distribution and Gas, Xcel Energy Inc. | June 2023 — August 2024 | |||||||||||||||||||
| Senior Vice President, Transmission, Xcel Energy Inc. | April 2018 — May 2023 | |||||||||||||||||||
| Mr. Lamb has been with Xcel Energy since 1985 | ||||||||||||||||||||
| Ryan Long | 41 | Executive Vice President, Chief Legal and Compliance Officer, Xcel Energy Inc. | June 2025 — Present | |||||||||||||||||
| Interim President, NSP-Minnesota | June 2025 — October 2025 | |||||||||||||||||||
| President, NSP-Minnesota | January 2024 — June 2025 | |||||||||||||||||||
| Interim General Counsel, Xcel Energy Inc. | October 2023 — January 2024 | |||||||||||||||||||
| Vice President, Deputy General Counsel, Xcel Energy Services Inc. | May 2021 — October 2023 | |||||||||||||||||||
| Managing Attorney, Xcel Energy Services Inc. | June 2020 — May 2021 | |||||||||||||||||||
| Mr. Long has been with Xcel Energy since 2015 | ||||||||||||||||||||
| Amanda Rome | 45 | Executive Vice President, Group President, Utilities, and Chief Customer Officer, Xcel Energy Inc. | October 2023 — Present | |||||||||||||||||
| Interim General Counsel, Xcel Energy Inc. | January 2024 — May 2024 | |||||||||||||||||||
| Executive Vice President, Chief Legal and Compliance Officer, Xcel Energy Inc. | June 2022 — October 2023 | |||||||||||||||||||
| Executive Vice President, General Counsel, Xcel Energy Inc. | June 2020 — June 2022 | |||||||||||||||||||
| Ms. Rome has been with Xcel Energy since 2015 | ||||||||||||||||||||
| Scott Sharp | 57 | Executive Vice President, Chief Generation Officer, Xcel Energy Inc. | May 2025 — Present | |||||||||||||||||
| Senior Vice President, Energy Supply and Commercial Operations, Xcel Energy Inc. | April 2023 — April 2025 | |||||||||||||||||||
| Vice President, Energy Supply Operations, Xcel Energy Inc. | October 2020 — April 2023 | |||||||||||||||||||
| Mr. Sharp has been with Xcel Energy since 2014 | ||||||||||||||||||||
| Brian J. Van Abel | 44 | Executive Vice President, Chief Financial Officer, Xcel Energy Inc. | March 2020 — Present | |||||||||||||||||
| Senior Vice President, Finance and Corporate Development, Xcel Energy Services Inc. | September 2018 — March 2020 | |||||||||||||||||||
| Mr. Van Abel has been with Xcel Energy since 2010 | ||||||||||||||||||||
(a) No family relationships exist between any of the executive officers or directors.
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ITEM 1A — RISK FACTORS | ||
Xcel Energy is subject to a variety of risks, many of which are beyond our control. Risks that may adversely affect the business, financial condition, results of operations or cash flows are described below. Although the risks are organized by heading, and each risk is described separately, many of the risks are interrelated. These risks should be carefully considered together with the other information set forth in this report and future reports that Xcel Energy files with the SEC.
While we believe we have identified and discussed below the key risk factors affecting our business, there may be additional risks and uncertainties that are not presently known or that are not currently believed to be significant that may adversely affect our business, financial condition, results of operations or cash flows in the future.
Risks Associated with Our Business
Operational Risks
Our natural gas and electric generation/transmission and distribution operations involve numerous risks that may result in accidents and other operating risks and costs.
Our natural gas transmission and distribution activities include inherent hazards and operating risks, such as leaks, explosions, outages and mechanical problems. Our electric generation, transmission and distribution activities include inherent hazards and operating risks such as contact, fire and outages.
These risks could result in loss of life, significant property damage, environmental pollution, impairment of our operations and substantial financial losses to customers, the public, employees or third-party contractors. We maintain insurance against most, but not all, of these risks and losses.
The occurrence of these events, if not fully covered by insurance, could have a material effect on our financial condition, results of operations and cash flows as well as potential reputational impact.
Additionally, compliance with existing and potential new regulations related to the operation and maintenance of our natural gas infrastructure could result in significant costs. The PHMSA is responsible for administering the DOT’s national regulatory program to assure the safe transportation of natural gas, petroleum and other hazardous materials by pipelines. The PHMSA continues to develop regulations and other approaches to risk management to assure safety in design, construction, testing, operation, maintenance and emergency response of natural gas pipeline infrastructure. We have programs in place to comply with these regulations, however, a significant incident or material finding of non-compliance could result in penalties and higher costs of operations.
Our natural gas and electric transmission and distribution operations are dependent upon complex information technology systems and network infrastructure, the failure of which could disrupt our normal business operations, which could have a material adverse effect on our ability to process transactions and provide services.
Other uncertainties and risks inherent in operating and maintaining Xcel Energy's facilities include, but are not limited to:
•Risks associated with facility start-up operations, such as whether the facility will achieve projected operating performance on schedule and otherwise as planned.
•Failures in the availability, acquisition or transportation of fuel or other supplies.
•Impact of adverse weather conditions and natural disasters, including, wildfires, tornadoes, avalanches, icing events, floods, high winds, droughts and the availability or changes to wind patterns.
•Performance below expected or contracted levels of output or efficiency.
•Availability of replacement or new equipment.
•Availability of adequate water resources and ability to satisfy water intake and discharge requirements.
•Inability to identify, manage properly or mitigate equipment defects.
•Use of new or unproven technology.
•Inability to use information effectively given the rapidly increasing volume of data.
•Risks associated with dependence on a specific type of fuel or fuel source, such as commodity price risk, availability of adequate fuel supply and transportation and lack of available alternative fuel sources.
•Risks associated with increased reliance on natural gas generation, including gas price volatility and supply constraints during extreme weather events.
•Increased competition due to, among other factors, new facilities, excess supply, shifting demand and regulatory changes.
•Risks of thermal runaway incidents associated with large battery storage facilities
•Risks associated with aging infrastructure.
•Risks associated with failures of other business processes and systems.
•Risks associated with regulatory requirements that may extend the operation of our coal facilities beyond planned retirement dates and require additional investments.
•Inability to deliver energy across transmission facilities, including due to congestion, outages, extreme weather, physical or cyber events, delays in construction or upgrades, permitting or siting challenges, or interconnection constraints.
Our utility operations, resource adequacy and system reliability are subject to long-term planning and project risks.
Our ability to reliably serve customer demand depends on the availability of sufficient generation and capacity resources. Changes in load growth, resource retirements, accreditation of resources, generation performance, extreme weather events, or delays in development or delivery of new resources, including the necessary transmission infrastructure, could affect resource adequacy and system reliability.
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Most utility investments are planned to be used for decades. Transmission and generation investments typically have long lead times and are planned well in advance of in-service dates and typically subject to long-term resource plans. These plans are based on numerous assumptions such as: sales growth, customer usage, commodity prices, economic activity, costs, regulatory mechanisms, customer behavior, available technology, equipment availability and public policy. Xcel Energy’s long-term resource plan is dependent on our ability to obtain required approvals (including regulatory approval in jurisdictions where Xcel Energy operates), develop necessary technical expertise, allocate and coordinate sufficient resources and adhere to budgets and timelines.
In addition, the long-term nature of both our planning processes and our asset lives are subject to risk. The utility sector is undergoing significant change (e.g., the addition of large loads, increases in energy efficiency, wider adoption of distributed generation and shifts away from fossil fuel generation to renewable generation). Customer adoption of these technologies and increased energy efficiency or other reductions in expected sales growth could result in excess transmission and generation resources, downward pressure on sales growth, and potentially stranded costs if we are not able to fully recover costs and investments. Additionally, increasing uncertainty surrounding federal policy to renewable deployment could negatively impact wind, solar and storage development.
The magnitude and timing of resource additions and changes in customer demand may not coincide with evolving customer preference for generation resources and end-uses, which introduces further uncertainty into long-term planning. Efforts to electrify the transportation and building sectors to reduce GHG emissions may result in higher electric demand and lower natural gas demand over time. New data centers and crypto mining facilities could generate significant increase in demand. Higher electric demand may require us to adopt new technologies and make significant generation, transmission and distribution investments including advanced grid infrastructure, which increases exposure to overall grid instability and technology obsolescence. Enterprise level financial and customer billing technology systems may be unable to support the increasing customer complexity. Evolving stakeholder preference for lower emissions from generation sources and end-uses, like heating, may impact our resource mix and put pressure on our ability to recover capital investments in natural gas generation and delivery. Multiple states may not agree as to the appropriate resource mix, which may lead to costs to comply with one jurisdiction that are not recoverable across all jurisdictions served by the same assets.
We require inputs such as coal, natural gas, uranium and water. Lack of availability of these resources could jeopardize long-term operations of our facilities or make them uneconomic to operate.
Our utilities are highly dependent on suppliers to deliver components in accordance with short and long-term project schedules.
Our products contain components that are globally sourced from suppliers. A shortage of key components in which an alternative supplier is not identified could significantly impact operations and project plans for Xcel Energy and our customers. Such impacts could include timing of projects and the potential for project cancellation. Failure to adhere to project budgets and timelines could adversely impact our results of operations, financial condition or cash flows.
We are subject to physical and financial risks associated with climate change and other weather, natural disaster and resource depletion impacts.
Climate change can create physical and financial risk. Physical risks include changes in weather conditions and extreme weather events. Our customers’ energy needs vary with weather. To the extent weather conditions are affected by climate change, customers’ energy use could increase or decrease. Increased energy use due to weather changes over the long-term may require us to invest in generating assets, transmission and infrastructure. Decreased energy use due to weather changes may result in decreased revenues.
Severe weather impacts our service territories, primarily when thunderstorms, flooding, tornadoes, wildfires, snow, ice storms or extreme temperatures (high heating/cooling days) occur. Extreme weather conditions in general require system backup and can contribute to increased system stress, including service interruptions. Extreme weather conditions creating high energy demand may raise electricity prices, increasing the cost of energy we provide to our customers.
To the extent the frequency of extreme weather events increases, this could increase our cost of providing service and result in more frequent service interruptions. Periods of extreme temperatures could also impact our ability to meet demand.
Drought or water depletion could adversely impact our ability to provide electricity to customers, cause early retirement of power plants that require water or increase the cost for energy.
Adverse events may result in increased insurance costs and/or decreased insurance availability. We may not recover all costs related to mitigating these physical and financial risks.
Our utilities have significant risks associated with wildfires.
In recent years, wildfires have impacted the utility industry. More frequent and severe drought conditions, extreme swings in amount and timing of precipitation, changes in availability of vegetation, unseasonably warm temperatures, very low humidity, stronger winds and other environmental factors have increased both the frequency and duration of fire weather conditions and the potential impact of an event. The expansion of the wildland urban interface increases the wildfire risk to surrounding communities and Xcel Energy's electric and natural gas infrastructure. Also, wildfires could jeopardize Xcel Energy’s electric and gas infrastructure and third-party property and result in temporary power outages or shortages in our service territories. Our current wildfire mitigation initiatives may not be effective in preventing or reducing ignitions and wildfire-related losses.
Other potential risks associated with wildfires and other climate events include the inability to secure sufficient insurance coverage, increased costs of insurance, or ability for insurers to meet their obligations, regulatory recovery risk, and the potential for a credit downgrade and subsequent additional costs to access capital markets.
While we carry liability insurance, given an extreme event, damage amounts could exceed our coverage (as experienced with the Marshall Wildfire settlement in 2025) and negatively impact our results of operations, financial condition or cash flows.
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We are subject to commodity risks and other risks associated with energy markets and energy production.
A significant increase in fuel costs could cause a decline in customer demand, adverse regulatory outcomes and an increase in bad debt expense which may have a material impact on our results of operations. Despite existing fuel cost recovery mechanisms in most of our states, higher fuel costs could significantly impact our results of operations if costs are not recovered. Delays in the timing of the collection of fuel cost recoveries could impact our cash flows and liquidity.
A significant disruption in supply could cause us to seek alternatives at potentially higher costs. Additionally, supply shortages may not be fully resolved, which negatively impacts our ability to provide services to our customers. Failure to provide service due to disruptions may also result in fines, penalties or cost disallowances through the regulatory process.
We also engage in wholesale sales and purchases of electric capacity, energy and energy-related products as well as natural gas. In many markets, emission allowances and/or RECs are also needed to comply with various statutes and commission rulings. As a result, we are subject to market supply and commodity price risk.
Commodity price changes can affect the value of our commodity trading derivatives. We mark certain derivatives to estimated fair market value on a daily basis. Settlements can vary significantly from estimated fair values recorded and significant changes from the assumptions underlying our fair value estimates could cause earnings variability. The management of risks associated with hedging and trading is based, in part, on programs and procedures which utilize historical prices and trends.
Public perception often does not distinguish between pass through commodity costs and base rates. High commodity prices that are passed through to customer bills could impact our ability to recover costs for other improvements and operations.
Additionally, due to the uncertainty involved in price movements and potential deviation from historical pricing, our risk management programs may not be effective to protect against significant adverse market fluctuations and our results of operations, financial condition or cash flows could be materially impacted.
Failure to attract and retain a qualified workforce could have an adverse effect on operations.
The competition for talent has become increasingly prevalent, and we have experienced increased employee turnover due to the condition of the labor market and decisions related to strategic workforce planning. In addition, specialized knowledge and skills are required for many of our positions, which may pose additional difficulty for us as we work to recruit, retain and motivate employees in this climate.
Failure to hire, adequately train replacement employees, transfer knowledge/expertise or future availability and cost of contract labor may adversely affect the ability to manage and operate our business. Inability to attract and retain these employees could adversely impact our results of operations, financial condition or cash flows.
Our businesses have collective bargaining agreements with labor unions. Failure to renew or renegotiate these contracts could lead to labor disruptions, including strikes or boycotts. Such disruptions or any negotiated wage or benefit increases could have a material adverse impact to our results of operations, financial condition or cash flows.
National unionization efforts could affect our business, as an increase in unionized workers could challenge our operational efficiency and increase costs.
Our operations use third-party contractors in addition to employees to perform periodic and ongoing work.
We rely on third-party contractors to perform operations, maintenance and construction work. Poor vendor performance or contractor unavailability could impact ongoing operations, restoration operations, regulatory recovery and our reputation and could introduce financial risk or risks of fines. Also, suppliers of key assets critical to long-term planning may be limited, creating vendor concentration risk that could increase costs and negatively impact investment execution.
Actions of our employees, directors, third-party contractors or suppliers could expose us to reputational risks.
We could suffer negative impacts to our reputation as a result of actual or perceived fraud, misconduct, legal or regulatory violations, violations of corporate policies, inappropriate use of social media, or other actions by our employees, directors, third-party contractors or suppliers. Reputational damage could have a material adverse effect and could result in negative customer perception, litigation and increased regulatory oversight.
Our subsidiary, NSP-Minnesota, is subject to the risks of nuclear generation.
NSP-Minnesota has two nuclear generation plants, Prairie Island and Monticello. Risks of nuclear generation include:
•Hazards associated with the use of radioactive material in energy production, including management, handling, storage and disposal.
•Limitations on insurance available to cover losses that may arise in connection with nuclear operations, as well as obligations to contribute to an insurance pool in the event of damages at a covered U.S. reactor.
•Technological and financial uncertainties related to the costs of decommissioning nuclear plants may cause our funding obligations to change.
The NRC has authority to impose licensing and safety-related requirements for the operation of nuclear generation facilities, including the ability to impose fines and/or shut down a unit until compliance is achieved. NRC safety requirements could necessitate substantial capital expenditures or an increase in operating expenses. In addition, the INPO reviews NSP-Minnesota’s nuclear operations. Compliance with the INPO’s recommendations could result in substantial capital expenditures or a substantial increase in operating expenses.
If a nuclear incident did occur, it could have a material impact on our results of operations, financial condition or cash flows. Furthermore, non-compliance or the occurrence of a serious incident at other nuclear facilities could result in increased industry regulation, which may increase NSP-Minnesota’s compliance costs.
Financial Risks
Our profitability depends on the ability of our utility subsidiaries to recover their costs and changes in regulation may impair the ability of our utility subsidiaries to recover costs from their customers.
We are subject to comprehensive regulation by federal and state utility regulatory agencies, including siting and construction of facilities, customer service and the rates that we can charge customers.
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The profitability of our utility operations is dependent on our ability to recover the costs of providing energy and utility services and earn a return on capital investment. Our rates are generally regulated and are based on an analysis of the utility’s costs incurred in a test year. The utility subsidiaries are subject to both future and historical test years depending upon the regulatory jurisdiction. Thus, the rates a utility is allowed to charge may or may not match its costs at any given time. Rate regulation is premised on providing an opportunity to earn a reasonable rate of return on invested capital.
There can also be no assurance that our regulatory commissions will judge all the costs of our utility subsidiaries to be prudent, which could result in disallowances, or that the regulatory process will always result in rates that will produce full recovery.
Overall, management believes prudently incurred costs are recoverable given the existing regulatory framework. However, there may be changes in the regulatory environment that could impair the ability of our utility subsidiaries to recover costs historically collected from customers, or these subsidiaries could exceed caps on capital costs required by commissions and result in less than full recovery.
Changes in the long-term cost-effectiveness or to the operating conditions of our assets may result in early retirements of utility facilities. While regulation typically provides cost recovery for these types of changes, there is no assurance that regulators would allow full recovery of all remaining costs.
Higher than expected inflation, shortages of skilled labor, tariffs or federal policies may increase costs of construction and operations. Also, rising fuel costs could increase prices to consumers, all of which could increase the risk that our utility subsidiaries will not be able to fully recover their costs from their customers.
Regulators may challenge rate increases due to increased customer affordability pressures. Public policy developments, including legislative actions and electoral changes at the state level, may affect recovery mechanisms or allowed returns and may limit recovery timing or cost allocation, negatively impacting our results of operations, financial condition or cash flows.
Growth in large load customers, including data centers, may increase customer concentration, capital requirements and revenue variability risks.
Additional demand from a limited number of customers may increase our credit risk exposure and require incremental infrastructure investment. If anticipated load growth does not materialize as expected or regulatory cost allocation mechanisms evolve, it could negatively impact our results of operations, financial condition or cash flows.
Any reductions in our credit ratings could increase our financing costs and the cost of maintaining certain contractual relationships.
Our credit ratings are subject to change, and our credit ratings may be lowered or withdrawn by a rating agency. Significant events including disallowance of costs, use of historic test years, elimination of riders or interim rates, increasing depreciation lives, lower returns on equity, changes to equity ratios, impacts of tax policy and unfavorable litigation outcomes may impact our cash flows and credit metrics, potentially resulting in a change in our credit ratings. In addition, our credit ratings may change as a result of the differing methodologies or change in the methodologies used by the various rating agencies.
Any credit ratings downgrade could lead to higher borrowing costs or lower proceeds from equity issuances. It could also impact our ability to access capital markets. Also, our utility subsidiaries may enter into contracts that require posting of collateral or settlement if credit ratings fall below investment grade. The credit rating agencies may change their assessment or our regulatory or business risk, such as with the increase of climate events, which could negatively impact our credit ratings.
We are subject to capital market and interest rate risks.
Utility operations require significant capital investment. As a result, we frequently need to access capital markets. Any disruption in capital markets could have a material impact on our ability to fund our operations. Capital market disruption and financial market distress could prevent us from issuing commercial paper, issuing new securities or cause us to issue securities with unfavorable terms and conditions, such as higher interest rates or lower proceeds from equity issuances. Higher interest rates on short-term borrowings with variable interest rates could also have an adverse effect on our operating results.
The performance of capital markets impacts the value of assets held in trusts to satisfy future obligations to decommission NSP-Minnesota’s nuclear plants and satisfy our defined benefit pension and postretirement benefit plan obligations. These assets are subject to market fluctuations and yield uncertain returns, which may fall below expected returns. A decline in the market value of these assets may increase funding requirements. Additionally, the fair value of the debt securities held in the nuclear decommissioning and/or pension trusts may be impacted by changes in interest rates.
We are subject to credit risks.
Credit risk includes the risk that our customers will not pay their bills, which may lead to a reduction in our cash flows and liquidity and an increase in bad debt expense. Credit risk is comprised of numerous factors including the price of products and services provided, the overall economy and unemployment rates.
Credit risk also includes the risk that counterparties that owe us money or product will become insolvent and may breach their obligations. Should the counterparties fail to perform, we may be forced to enter into alternative arrangements. In that event, our financial results could be adversely affected and we may incur losses. This could be particularly impactful for long-lead time equipment contracts that require significant deposits and milestone payments, for items that may be difficult to procure elsewhere in the event of non-performance.
Xcel Energy may have direct credit exposure in our short-term wholesale and commodity trading activity to financial institutions trading for their own accounts or issuing collateral support on behalf of other counterparties. We may also have some indirect credit exposure due to participation in organized markets, (e.g., MISO, SPP, ERCOT and California ISO), in which any credit losses are socialized to all market participants.
We have additional indirect credit exposure to financial institutions from letters of credit provided as security by power suppliers under various purchased power contracts. If any of the credit ratings of the letter of credit issuers were to drop below investment grade, the supplier would need to replace that security with an acceptable substitute. If the security were not replaced, the party could be in default under the contract.
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Increasing costs of our defined benefit retirement plans and employee benefits may adversely affect our results of operations, financial condition or cash flows.
We have defined benefit pension and postretirement plans that cover most of our employees. Assumptions related to future costs, return on investments, interest rates and other actuarial assumptions have a significant impact on our funding requirements of these plans. Estimates and assumptions may change. In addition, the Pension Protection Act sets the minimum funding requirements for defined benefit pension plans. Therefore, our funding requirements and contributions may change in the future.
Also, the payout of a significant percentage of pension plan liabilities in a single year, due to high numbers of retirements or employees leaving, would trigger settlement accounting and could require Xcel Energy to recognize incremental pension expense related to unrecognized plan losses in the year liabilities are paid. Changes in industry standards utilized in key assumptions (e.g., mortality tables) could have a significant impact on future obligations and benefit costs.
Increasing costs associated with health care plans may adversely affect our results of operations.
Increasing levels of large individual health care claims and overall health care claims could have an adverse impact on our results of operations, financial condition or cash flows. Health care legislation could also significantly impact our benefit programs and costs.
We must rely on cash from our subsidiaries to make dividend payments.
Investments in our subsidiaries are our primary assets. Substantially all our operations are conducted by our subsidiaries. Consequently, our operating cash flows and ability to service our debt and pay dividends depends upon the operating cash flows of our subsidiaries and their payment of dividends.
Our subsidiaries are separate legal entities that have no obligation to pay any amounts due pursuant to our obligations or to make any funds available for dividends on our common stock. In addition, each subsidiary’s ability to pay dividends depends on statutory and/or contractual restrictions which may include requirements to maintain minimum levels of equity ratios, working capital or assets.
If the utility subsidiaries were to cease making dividend payments, our ability to pay dividends on our common stock or otherwise meet our financial obligations could be adversely affected. Our utility subsidiaries are regulated by state utility commissions, which possess broad powers to prioritize that the needs of the utility customers are met. We may be negatively impacted by the actions of state commissions that limit the payment of dividends by our utility subsidiaries.
Federal tax law may significantly impact our business.
Our utility subsidiaries collect estimated federal, state and local tax payments through their regulated rates. Changes to federal tax law may benefit or adversely affect our earnings and customer costs. Tax depreciable lives and the value/availability of various tax credits or the timeliness of their utilization may impact the economics or selection of resources. If tax rates are increased, there could be timing delays before regulated rates provide for recovery of such tax increases in revenues. In addition, certain IRS tax policies, such as tax normalization, may impact our ability to economically deliver certain types of resources relative to market prices. Changes to the availability of tax credit transferability could impact our cash flows and the cost of certain types of resources.
Macroeconomic Risks
Economic conditions impact our business.
Xcel Energy’s operations are affected by economic conditions, which correlates to customers/sales growth (decline). Economic conditions may be impacted by recessionary factors, rising interest rates, inflation, the impacts of federal policy and insufficient financial sector liquidity leading to potential increased unemployment, which may impact customers’ ability to pay their bills, which could lead to additional bad debt expense.
Our utility subsidiaries face competitive factors, which could have an adverse impact on our financial condition, results of operations and cash flows. Further, worldwide economic activity impacts the demand for basic commodities necessary for utility infrastructure, which may inhibit our ability to acquire sufficient supplies. We operate in a capital-intensive industry and federal trade policy could significantly impact the cost of materials we use. There may be delays before these additional material costs can be recovered in rates.
The oil and gas industry represents our largest C&I customer base. Oil and natural gas prices are sensitive to market risk factors which may impact demand.
We face risks related to health epidemics and other outbreaks, which may have a material effect on our financial condition, results of operations and cash flows.
Health epidemics impact countries, communities, supply chains and markets. Uncertainty continues to exist regarding epidemics; the duration and magnitude of business restrictions including shutdowns (domestically and globally); the potential impact on the workforce including shortages of employees and 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.
We cannot ultimately predict whether an epidemic will have a material impact on our future liquidity, financial condition or results of operations. Nor can we predict the impact on the health of our employees, our supply chain or our ability to recover higher costs associated with managing an outbreak.
Operations could be impacted by war, terrorism or other events.
Our generation plants, fuel storage facilities, transmission and distribution facilities and information and control systems may be targets of terrorist activities. Any disruption could impact operations or result in a decrease in revenues and additional costs to repair and insure our assets. These disruptions could have a material impact on our financial condition, results of operations or cash flows.
The potential for terrorism has subjected our operations to increased risks and could have a material effect on our business. We have incurred increased costs for security and capital expenditures in response to these risks. The insurance industry has also been affected by these events and the availability of insurance may decrease. In addition, insurance may have higher deductibles, higher premiums and more restrictive policy terms.
A disruption of the regional electric transmission grid, interstate natural gas pipeline infrastructure or other fuel sources, could negatively impact our business, brand and reputation. Because our facilities are part of an interconnected system, we face the risk of possible loss of business due to a disruption caused by the actions of a neighboring utility.
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We also face the risks of possible loss of business due to significant events such as severe storms, temperature extremes, wildfires, widespread pandemic, generator or transmission facility outage, pipeline rupture, railroad disruption, operator error, sudden and significant increase or decrease in wind generation or a workforce disruption.
In addition, major catastrophic events throughout the world may disrupt our business. While we have business continuity plans in place, our ability to recover may be prolonged due to the type and extent of the event. Xcel Energy participates in a global supply chain, which includes materials and components that are globally sourced. A prolonged disruption could result in the delay of equipment and materials that may impact our ability to connect, restore and reliably serve our customers.
A major disruption could result in a significant decrease in revenues, additional costs to repair assets, and an adverse impact on the cost and availability of insurance, which could have a material impact on our results of operations, financial condition or cash flows.
A cybersecurity incident or security breach could have a material effect on our business.
We operate in an industry that requires the continued operation of sophisticated information technology, control systems and network infrastructure. In addition, we use our systems and infrastructure to create, collect, use, disclose, store, dispose of and otherwise process sensitive information, including Company data, customer energy usage data, and personal information regarding customers, employees and their dependents, contractors, shareholders and other individuals.
Xcel Energy’s generation, transmission, distribution and fuel storage facilities, information technology systems and other infrastructure or physical assets as well as information processed in our systems (e.g., information regarding our customers, employees, operations, infrastructure and assets) could be affected by cybersecurity incidents, including those caused by human error.
The utility industry has been the target of several attacks on operational systems and has seen an increased volume and sophistication of cybersecurity incidents from international activist organizations, other countries and individuals. We expect to continue to experience attempts to compromise our information technology and control systems, network infrastructure and other assets.
Cybersecurity incidents could harm our businesses by limiting our generation, transmission and distribution capabilities, delaying our development and construction of new facilities or capital improvement projects to existing facilities, disrupting our customer operations or causing the release of customer information, all of which would likely receive state and federal regulatory scrutiny and could expose us to liability.
Xcel Energy’s generation, transmission systems and natural gas pipelines are part of an interconnected system. Therefore, a disruption caused by the impact of a cybersecurity incident on the regional electric transmission grid, natural gas pipeline infrastructure or other fuel sources of our third-party service providers’ operations, could also negatively impact our business.
Advancements in artificial intelligence and large language models may increase cybersecurity threats and operational risks. Threat actors may use artificial intelligence to enhance their attacks, increasing the frequency, sophistication and potential impact of cyber incidents affecting our IT and OT environment.
Our supply chain for procurement of digital equipment and services may expose software or hardware to these risks and could result in a breach or significant costs of remediation. We are unable to quantify the potential impact of cybersecurity threats or subsequent related actions. Cybersecurity incidents and regulatory action could result in a material decrease in revenues and may cause significant additional costs (e.g., penalties, third-party claims, repairs, insurance or compliance) and potentially disrupt our supply and markets for natural gas, oil and other fuels.
We maintain security measures to protect our information technology and control systems, network infrastructure and other assets. However, these assets and the information they process may be vulnerable to cybersecurity incidents, including asset failure or unauthorized access to assets or information.
A failure or breach of our technology systems or those of our third-party service providers could disrupt critical business functions and may negatively impact our business, our brand, and our reputation. The cybersecurity threat is dynamic and evolves continually, and our efforts to prioritize network protection may not be effective given the constant changes to threat vulnerability.
While the Company maintains insurance relating to cybersecurity events, such insurance is subject to a number of exclusions and may be insufficient to offset any losses, costs or damages experienced. Also, the market for cybersecurity insurance is relatively new and coverage available for cybersecurity events is evolving as the industry matures.
Our operating results may fluctuate on a seasonal and quarterly basis and can be adversely affected by milder weather.
Our electric and natural gas utility businesses are seasonal, and weather patterns can have a material impact on our operating performance. Demand for electricity is often greater in the summer and winter months associated with cooling and heating. Because natural gas is heavily used for residential and commercial heating, the demand depends heavily upon weather patterns. A significant amount of natural gas revenues are recognized in the first and fourth quarters related to the heating season. Accordingly, our operations have historically generated less revenues and income when weather conditions are milder in the winter and cooler in the summer. Unusually mild winters and summers could have an adverse effect on our financial condition, results of operations or cash flows.
Public Policy Risks
Increased risks of regulatory penalties could negatively impact our business.
The Energy Act increased civil penalty authority for violation of FERC statutes, rules and orders. FERC can impose penalties of up to $1.5 million per violation per day, particularly as it relates to energy trading activities for both electricity and natural gas. In addition, NERC electric reliability standards and critical infrastructure protection requirements are mandatory and subject to potential financial penalties. Also, the PHMSA, Occupational Safety and Health Administration and other federal agencies have the authority to assess penalties.
In the event of serious incidents, these agencies may pursue penalties. In addition, certain states have the authority to impose substantial penalties. If a serious reliability, cybersecurity or safety incident did occur, it could have a material effect on our results of operations, financial condition or cash flows.
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The continued use of natural gas for both power generation and gas distribution have increasingly become a public policy advocacy target. These efforts may result in a limitation of natural gas as an energy source for both power generation and heating, which could impact our ability to reliably and affordably serve our customers.
In recent years, there have been various local and state agency proposals within and outside our service territories that would attempt to restrict the use and availability of natural gas. If such policies were to prevail, we may be forced to make new resource investment decisions which could potentially result in stranded costs if we are not able to fully recover costs and investments and impact the overall reliability of our service.
Environmental Policy Risks
We may be subject to legislative and regulatory responses to climate change, with which compliance could be difficult and costly.
Legislative and regulatory responses related to climate change may create financial risk as our facilities may be subject to additional regulation at either the state or federal level in the future. International agreements could additionally lead to future federal or state regulations.
In 2015, the United Nations Framework Convention on Climate Change reached consensus among 190 nations on an agreement (the Paris Agreement) that establishes a framework for GHG mitigation actions by all countries, with a goal of holding the increase in global average temperature to below 2º Celsius above pre-industrial levels and an aspiration to limit the increase to 1.5º Celsius. Although the United States has withdrawn from the Paris Agreement, many states and localities continue to pursue their own climate policies which could result in future additional GHG reductions.
The steps Xcel Energy has taken to date to reduce GHG emissions, including energy efficiency measures, adding renewable generation and retiring or converting coal plants to natural gas, occurred under state-endorsed resource plans, renewable energy standards and other state policies.
We may be subject to climate change lawsuits. An adverse outcome could require substantial capital expenditures and possibly require payment of substantial penalties or damages. Defense costs associated with such litigation can also be significant and could affect results of operations, financial condition or cash flows if such costs are not recovered through regulated rates.
If our regulators do not allow us to recover the costs incurred to comply with the mandates, it could have a material effect on our results of operations, financial condition or cash flows.
We are subject to environmental laws and regulations, with which compliance could be difficult and costly.
We are subject to environmental laws and regulations that affect many aspects of our operations, including air emissions, water quality, wastewater discharges and the generation, transport and disposal of solid wastes and hazardous substances. Laws and regulations require us to obtain permits, licenses, and approvals and to comply with a variety of environmental requirements.
Environmental laws and regulations can also require us to restrict or limit the output of facilities or the use of certain fuels, shift generation to lower-emitting facilities, install pollution control equipment, clean up spills and other contamination and correct environmental hazards. Failure to meet requirements of environmental mandates may result in fines or penalties. We may be required to pay all or a portion of the cost to remediate sites where our past activities, or the activities of other parties, caused environmental contamination.
Changes in environmental policies and regulations or regulatory decisions may result in early retirements of our operational facilities. While regulation typically provides relief for these types of changes, there is no assurance that regulators would allow full recovery of all remaining costs.
We are subject to mandates to provide customers with clean energy, renewable energy and energy conservation offerings. It could have a material effect on our results of operations, financial condition or cash flows if our regulators do not allow us to recover the cost of capital investment or O&M costs incurred to comply with the requirements. Additionally, the impact of environmental laws and regulations may impact the economic health of consumers through higher prices of energy and purchased goods.
While we establish strategies and expectations related to climate change and other environmental matters, our ability to achieve any such strategies or expectations is subject to numerous factors and conditions, many of which are outside of our control. Examples of such factors include, but are not limited to, 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. The potential for unprecedented load growth and the need for additional generation resources to support such growth may further impact the timing or achievement of our climate goals. Failures or delays (whether actual or perceived) in achieving our strategies or expectations related to climate change and other environmental matters could adversely affect our business, operations, and reputation, and increase risk of litigation.
In addition, existing environmental laws or regulations may be revised and new laws or regulations may be adopted. We may also incur additional unanticipated obligations or liabilities under existing environmental laws and regulations.
ITEM 1B — UNRESOLVED STAFF COMMENTS | ||
None.
| ITEM 1C — CYBERSECURITY | ||
As described in Item 1A – Risk Factors, Xcel Energy operates in an industry that requires the continued operation of sophisticated information technology, control systems and network infrastructure, as such, our business is subject to the risk of interruption by cybersecurity incidents that range from attacks common to most industries, such as phishing and denial-of-service, to attacks from more sophisticated adversaries, including nation state actors, that target the critical infrastructure used in the operation of our business.
The Company has a security risk program in place to identify, assess, manage and report material risks from cybersecurity incidents. As a utility provider, Xcel Energy complies with reliability standards imposed by NERC, including critical infrastructure protection standards related to both cybersecurity and physical security. These standards imposed by NERC, in alignment with the NIST Cybersecurity Framework, are the basis for which
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Xcel Energy has designed the cybersecurity control framework within its security risk program.
Xcel Energy employs a comprehensive risk based approach to assess the magnitude and significance of a vendor’s risk to the Company. Certain third-party service providers are subject to vendor security risk assessments at the time of integration, contract execution/renewal, and upon detection of any increase in risk profile. Xcel Energy uses a variety of inputs in such risk assessments, including information supplied by providers and third parties (including information analysis centers that share daily threat intelligence and improve organizational agility associated with management of cybersecurity risks). In addition, the Company requires certain third-party service providers to meet appropriate security requirements, controls and responsibilities. The Company deploys periodic monitoring activities to assess compliance with our cybersecurity control framework and investigates security incidents that have impacted our third-party service providers as appropriate .
The Chief Security Officer or members of management brief the Board on routine and regular cybersecurity risk and threat updates, typically on an annual basis. In the event of a significant threat or incident, management and the Chief Security Officer leverage Xcel Energy’s incident response processes to assess impacts and resolve incidents. When a significant cybersecurity incident occurs, management communicates with the Board of Directors and relevant committees.
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ITEM 2 — PROPERTIES | ||
Virtually all of the utility plant property of the utility subsidiaries is subject to the lien of their respective first mortgage bond indentures.
NSP-Minnesota Station, Location and Unit at Dec. 31, 2025 | Fuel | Installed | MW (a) | ||||||||||||||||||||
| Steam: | |||||||||||||||||||||||
| A.S. King-Bayport, MN, 1 Unit | Coal | 1968 | 511 | ||||||||||||||||||||
| Sherco-Becker, MN | |||||||||||||||||||||||
| Unit 1 | Coal | 1976 | 680 | ||||||||||||||||||||
| Unit 3 | Coal | 1987 | 517 | (b) | |||||||||||||||||||
| Monticello, MN, 1 Unit | Nuclear | 1971 | 617 | ||||||||||||||||||||
| Prairie Island-Welch, MN | |||||||||||||||||||||||
| Unit 1 | Nuclear | 1973 | 521 | ||||||||||||||||||||
| Unit 2 | Nuclear | 1974 | 519 | ||||||||||||||||||||
| Various locations, 4 Units | Wood/RDF | Various | 36 | (c) | |||||||||||||||||||
| Combustion Turbine: | |||||||||||||||||||||||
| Angus Anson-Sioux Falls, SD, 3 Units | Natural Gas | 1994 - 2005 | 343 | ||||||||||||||||||||
| Black Dog-Burnsville, MN, 3 Units | Natural Gas | 1987 - 2018 | 491 | ||||||||||||||||||||
| Blue Lake-Shakopee, MN, 2 Units | Natural Gas | 2005 | 300 | (d) | |||||||||||||||||||
| High Bridge-St. Paul, MN, 3 Units | Natural Gas | 2008 | 530 | ||||||||||||||||||||
| Inver Hills-Inver Grove Heights, MN, 6 Units | Natural Gas | 1972 - 1996 | 272 | ||||||||||||||||||||
| Riverside-Minneapolis, MN, 3 Units | Natural Gas | 2009 | 454 | ||||||||||||||||||||
| Reciprocating Generation: | |||||||||||||||||||||||
| Blue Lake-Shakopee, MN 3 Units | Natural Gas | Various | 24 | ||||||||||||||||||||
| Hydro: | |||||||||||||||||||||||
| Hennepin Island-Minneapolis, MN 5 Units | Hydro | 1954-1955 | 6 | ||||||||||||||||||||
| Wind: | |||||||||||||||||||||||
| Blazing Star 1-Lincoln County, MN, 100 Units | Wind | 2020 | 200 | (e) | |||||||||||||||||||
| Blazing Star 2-Lincoln County, MN, 100 Units | Wind | 2021 | 200 | (e) | |||||||||||||||||||
Border-Rolette County, ND, 75 Units (f) | Wind | 2015 | 150 | (e) | |||||||||||||||||||
| Community Wind North-Lincoln County, MN, 12 Units | Wind | 2020 | 26 | (e) | |||||||||||||||||||
| Courtenay Wind-Stutsman County, ND, 100 Units | Wind | 2016 | 190 | (e) | |||||||||||||||||||
| Crowned Ridge 2-Grant County, SD, 88 Units | Wind | 2020 | 192 | (e) | |||||||||||||||||||
| Dakota Range, SD, 72 Units | Wind | 2022 | 298 | (e) | |||||||||||||||||||
| Foxtail-Dickey County, ND, 75 Units | Wind | 2019 | 150 | (e) | |||||||||||||||||||
| Freeborn-Freeborn County, MN, 100 Units | Wind | 2021 | 200 | (e) | |||||||||||||||||||
Grand Meadow-Mower County, MN, 67 Units | Wind | 2008 | 100 | (e) | |||||||||||||||||||
| Jeffers-Cottonwood County, MN, 20 Units | Wind | 2020 | 43 | (e) | |||||||||||||||||||
| Lake Benton-Pipestone County, MN, 44 Units | Wind | 2019 | 99 | (e) | |||||||||||||||||||
| Mower-Mower County, MN, 43 Units | Wind | 2021 | 91 | (e) | |||||||||||||||||||
| Nobles-Nobles County, MN, 133 Units | Wind | 2010 | 200 | (e) | |||||||||||||||||||
| Northern Wind-Murray County, MN, 37 Units | Wind | 2023 | 92 | (e) | |||||||||||||||||||
Pleasant Valley-Mower County, MN, 100 Units (f) | Wind | 2015 | 200 | (e) | |||||||||||||||||||
| Rock Aetna-Murray County, MN, 8 Units | Wind | 2022 | 20 | (e) | |||||||||||||||||||
| Solar: | |||||||||||||||||||||||
| Sherco Solar 1 and 2-Becker, MN, 130 units | Solar | 2024 - 2025 | 460 | (e) | |||||||||||||||||||
| Total | 8,732 | ||||||||||||||||||||||
(a)Summer 2025 net dependable capacity. Wind and solar is presented as net maximum capacity.
(b)Based on NSP-Minnesota’s ownership of 59%.
(c)RDF is made from municipal solid waste.
(d)Four units were retired in 2025.
(e)Net maximum capacity is attainable only when conditions are sufficiently available. Typical average capacity factors are 35-50% for wind facilities. For the year ended Dec. 31, 2025, wind facilities had a weighted-average capacity factor of 44%. For solar projects placed in service in 2025, factors will be available after a full year of operations.
(f)Repowered in 2025.
NSP-Wisconsin Station, Location and Unit at Dec. 31, 2025 | Fuel | Installed | MW (a) | ||||||||||||||||||||
| Steam: | |||||||||||||||||||||||
| Bay Front-Ashland, WI, 2 Units | Wood/Natural Gas | 1948 - 1956 | 41 | ||||||||||||||||||||
| French Island-La Crosse, WI, 2 Units | Wood/RDF | 1940 - 1948 | 16 | (b) | |||||||||||||||||||
| Combustion Turbine: | |||||||||||||||||||||||
| French Island-La Crosse, WI, 2 Units | Oil | 1974 | 119 | ||||||||||||||||||||
| Wheaton-Eau Claire, WI, 1 Unit | Natural Gas | 2025 | 206 | (c) | |||||||||||||||||||
| Reciprocating Generation: | |||||||||||||||||||||||
| Wheaton-Eau Claire, WI, 5 Units | Natural Gas | 2025 | 40 | (c) | |||||||||||||||||||
| Hydro: | |||||||||||||||||||||||
| Various locations, 62 Units | Hydro | Various | 135 | ||||||||||||||||||||
| Total | 557 | ||||||||||||||||||||||
(a)Summer 2025 net dependable capacity.
(b)RDF is made from municipal solid waste.
(c)Four combustion turbine units were retired in 2025 and replaced with one new combustion turbine and five reciprocating generation units.
PSCo Station, Location and Unit at Dec. 31, 2025 | Fuel | Installed | MW (a) | ||||||||||||||||||||
| Steam: | |||||||||||||||||||||||
| Comanche-Pueblo, CO | |||||||||||||||||||||||
| Unit 2 | Coal | 1975 | 330 | ||||||||||||||||||||
| Unit 3 | Coal | 2010 | 500 | (b) | |||||||||||||||||||
| Craig-Craig, CO, 2 Units | Coal | 1979 - 1980 | 82 | (c) | |||||||||||||||||||
Hayden-Hayden, CO, 2 Units | Coal | 1965 - 1976 | 233 | (d) | |||||||||||||||||||
| Pawnee-Brush, CO, 1 Unit | Coal | 1981 | 505 | (e) | |||||||||||||||||||
| Cherokee-Denver, CO, 1 Unit | Natural Gas | 1968 | 310 | ||||||||||||||||||||
| Combustion Turbine: | |||||||||||||||||||||||
| Blue Spruce-Aurora, CO, 2 Units | Natural Gas | 2003 | 264 | ||||||||||||||||||||
| Cherokee-Denver, CO, 3 Units | Natural Gas | 2015 | 576 | ||||||||||||||||||||
| Fort St. Vrain-Platteville, CO, 6 Units | Natural Gas | 1972 - 2009 | 1,022 | ||||||||||||||||||||
| Manchief-Brush, CO, 2 Units | Natural Gas | 2000 | 250 | ||||||||||||||||||||
| Rocky Mountain-Keenesburg, CO, 3 Units | Natural Gas | 2004 | 592 | ||||||||||||||||||||
| Valmont-Boulder, CO, 3 units | Natural Gas | 1973 - 2001 | 119 | ||||||||||||||||||||
| Various locations, 5 Units | Natural Gas | Various | 128 | ||||||||||||||||||||
| Hydro: | |||||||||||||||||||||||
| Cabin Creek-Georgetown, CO | |||||||||||||||||||||||
| Pumped Storage, 2 Units | Hydro | 1967 | 210 | ||||||||||||||||||||
| Various locations, 6 Units | Hydro | Various | 23 | ||||||||||||||||||||
| Wind: | |||||||||||||||||||||||
| Rush Creek, CO, 300 units | Wind | 2018 | 582 | (f) | |||||||||||||||||||
| Cheyenne Ridge, CO, 229 units | Wind | 2020 | 477 | (f) | |||||||||||||||||||
| Solar: | |||||||||||||||||||||||
| Rocky Mountain Solar-Keenesburg, CO, 87 units | Solar | 2025 | 325 | (f) | |||||||||||||||||||
| Total | 6,528 | ||||||||||||||||||||||
(a)Summer 2025 net dependable capacity. Wind and solar is presented as net maximum capacity.
(b)Based on PSCo’s ownership of 67%.
(c)Based on PSCo’s ownership of 10%.
(d)Based on PSCo’s ownership of 76% of Unit 1 and 37% of Unit 2.
(e)Pawnee coal plant was retired in 2025 and completed conversion to natural gas in 2026.
(f)Net maximum capacity is attainable only when conditions are sufficiently available. Typical average capacity factors are 35-50% for wind facilities. For the year ended Dec. 31, 2025, wind facilities had a weighted-average capacity factor of 41%. For solar projects placed in service in 2025, factors will be available after a full year of operations.
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SPS Station, Location and Unit at Dec. 31, 2025 | Fuel | Installed | MW (a) | ||||||||||||||||||||
| Steam: | |||||||||||||||||||||||
| Cunningham-Hobbs, NM, 1 Unit | Natural Gas | 1957 - 1965 | 183 | ||||||||||||||||||||
| Harrington-Amarillo, TX 3 Units | Natural Gas | 2024 - 2025 | 1,018 | ||||||||||||||||||||
| Jones-Lubbock, TX, 2 Units | Natural Gas | 1971 - 1974 | 486 | ||||||||||||||||||||
| Maddox-Hobbs, NM, 1 Unit | Natural Gas | 1967 | 112 | ||||||||||||||||||||
| Nichols-Amarillo, TX, 3 Units | Natural Gas | 1960 - 1968 | 457 | ||||||||||||||||||||
| Plant X-Earth, TX, 1 Unit | Natural Gas | 1952 - 1964 | 190 | ||||||||||||||||||||
| Tolk-Muleshoe, TX, 2 Units | Coal | 1982 - 1985 | 1,067 | ||||||||||||||||||||
| Combustion Turbine: | |||||||||||||||||||||||
| Cunningham-Hobbs, NM, 2 Units | Natural Gas | 1997 | 207 | ||||||||||||||||||||
| Jones-Lubbock, TX, 2 Units | Natural Gas | 2011 - 2013 | 334 | ||||||||||||||||||||
| Maddox-Hobbs, NM, 1 Unit | Natural Gas | 1963 - 1976 | 61 | ||||||||||||||||||||
| Wind: | |||||||||||||||||||||||
| Hale-Plainview, TX, 239 Units | Wind | 2019 | 478 | (b) | |||||||||||||||||||
| Sagamore-Dora, NM, 240 Units | Wind | 2020 | 508 | (b) | |||||||||||||||||||
| Total | 5,101 | ||||||||||||||||||||||
(a)Summer 2025 net dependable capacity. Wind is presented as net maximum capacity.
(b)Net maximum capacity is attainable only when conditions are sufficiently available. Typical average capacity factors are 35-50% for wind facilities. For the year ended Dec. 31, 2025 SPS’ wind facilities had a weighted-average capacity factor of 47%.
Electric utility overhead and underground transmission and distribution lines at Dec. 31, 2025:
| Conductor Miles | NSP-Minnesota | NSP-Wisconsin | PSCo | SPS | ||||||||||||||||||||||
| Transmission | ||||||||||||||||||||||||||
| 500 KV | 2,921 | — | — | — | ||||||||||||||||||||||
| 345 KV | 13,394 | 3,019 | 8,233 | 11,668 | ||||||||||||||||||||||
| 230 KV | 2,299 | — | 12,393 | 9,863 | ||||||||||||||||||||||
| 161 KV | 610 | 1,816 | — | — | ||||||||||||||||||||||
| 138 KV | — | — | 92 | — | ||||||||||||||||||||||
| 115 KV | 8,137 | 1,860 | 5,004 | 15,044 | ||||||||||||||||||||||
| Less than 115 KV | 6,569 | 5,666 | 1,717 | 4,546 | ||||||||||||||||||||||
| Total Transmission | 33,930 | 12,361 | 27,439 | 41,121 | ||||||||||||||||||||||
| Distribution | ||||||||||||||||||||||||||
| Less than 115 KV | 87,271 | 28,582 | 84,079 | 25,261 | ||||||||||||||||||||||
| Total | 121,201 | 40,943 | 111,518 | 66,382 | ||||||||||||||||||||||
Electric utility transmission and distribution substations at Dec. 31, 2025:
| NSP-Minnesota | NSP-Wisconsin | PSCo | SPS | |||||||||||||||||||||||
| Substations | 352 | 208 | 236 | 466 | ||||||||||||||||||||||
Natural gas utility mains at Dec. 31, 2025:
| Miles | NSP-Minnesota | NSP-Wisconsin | PSCo | SPS | WGI | |||||||||||||||||||||||||||
| Transmission | 78 | 3 | 2,022 | 38 | 11 | |||||||||||||||||||||||||||
| Distribution | 11,117 | 2,628 | 24,291 | — | — | |||||||||||||||||||||||||||
ITEM 3 — LEGAL PROCEEDINGS | ||
Xcel Energy is involved in various litigation matters in the ordinary course of business. The assessment of whether a loss is probable or is a reasonable possibility, and whether the loss or a range of loss is estimable, often involves a series of complex judgments about future events. Management maintains accruals for losses probable of being incurred and subject to reasonable estimation.
Management is sometimes unable to estimate an amount or range of a reasonably possible loss in certain situations, including but not limited to when (1) the damages sought are indeterminate, (2) the proceedings are in the early stages, or (3) the matters involve novel or unsettled legal theories. In such cases, there is considerable uncertainty regarding the timing or ultimate resolution of such matters, including a possible eventual loss.
For current proceedings not specifically reported herein, management does not anticipate that the ultimate liabilities, if any, would have a material effect on Xcel Energy’s consolidated financial statements. Legal fees are generally expensed as incurred.
See Note 12 to the consolidated financial statements, Item 1 and Item 7 for further information.
ITEM 4 — MINE SAFETY DISCLOSURES | ||
None.
PART II
ITEM 5 — MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES. | ||
Stock Data
Xcel Energy Inc.’s common stock is listed on the Nasdaq Global Select Market (Nasdaq). The trading symbol is XEL. The number of common stockholders of record as of Feb. 23, 2026 was 40,984.
The following compares our cumulative TSR on common stock with the cumulative TSR of the EEI Investor-Owned Electrics Index and the S&P 500 Composite Stock Price Index over the last five years.
The EEI Investor-Owned Electrics Index (market capitalization-weighted) included 37 companies at year-end and is a broad measure of industry performance.
Comparison of Five Year Cumulative Total Return*
* $100 invested on Dec. 31, 2020 in stock or index — including reinvestment of dividends. Fiscal years ended Dec. 31.
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Purchases of Equity Securities by Issuer and Affiliated Purchasers
For the quarter ended Dec. 31, 2025, no equity securities that are registered by Xcel Energy Inc. pursuant to Section 12 of the Securities Exchange Act of 1934 were purchased by or on behalf of us or any of our affiliated purchasers.
ITEM 6 — [RESERVED] | ||
| ITEM 7 — MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS | ||
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 ROE, 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.
Ongoing ROE
Ongoing ROE is calculated by dividing the net income or loss of Xcel Energy or each subsidiary, adjusted for certain nonrecurring items, by each entity’s average stockholders’ equity. We use these non-GAAP financial measures to evaluate and provide details of earnings results.
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.
The following table provides a reconciliation of GAAP earnings (net income) to ongoing earnings:
| (Millions of Dollars) | 2025 | 2024 | ||||||||||||
| GAAP net income | $ | 2,018 | $ | 1,936 | ||||||||||
| Sherco Unit 3 2011 outage refunds | — | 47 | ||||||||||||
Marshall Wildfire litigation (a) | 298 | — | ||||||||||||
| Less: tax effect of adjustments | (77) | (13) | ||||||||||||
Ongoing earnings (b) | $ | 2,239 | $ | 1,969 | ||||||||||
(a)Includes $2 million of interest costs associated with short-term debt used to pay settlement, which is presented as interest expense on the consolidated statements of income.
(b)Amounts may not add due to rounding.
| Twelve Months Ended Dec. 31, 2025 | ||||||||||||||||||||
| Diluted Earnings (Loss) Per Share | GAAP Diluted EPS | Impact of Adjustments | Ongoing Diluted EPS | |||||||||||||||||
| NSP-Minnesota | $ | 1.53 | $ | — | $ | 1.53 | ||||||||||||||
| PSCo | 1.15 | 0.38 | 1.53 | |||||||||||||||||
| SPS | 0.67 | — | 0.67 | |||||||||||||||||
| NSP-Wisconsin | 0.27 | — | 0.27 | |||||||||||||||||
| Earnings from equity method investments — WYCO | 0.03 | — | 0.03 | |||||||||||||||||
Regulated utility (a) | 3.65 | 0.38 | 4.03 | |||||||||||||||||
| Xcel Energy Inc. and Other | (0.23) | — | (0.23) | |||||||||||||||||
Total (a) | $ | 3.42 | 0.38 | $ | 3.80 | |||||||||||||||
| Twelve Months Ended Dec. 31, 2024 | ||||||||||||||||||||
| Diluted Earnings (Loss) Per Share | GAAP Diluted EPS | Impact of Adjustments | Ongoing Diluted EPS | |||||||||||||||||
| NSP-Minnesota | $ | 1.41 | $ | 0.06 | $ | 1.47 | ||||||||||||||
| PSCo | 1.39 | — | 1.39 | |||||||||||||||||
| SPS | 0.70 | — | 0.70 | |||||||||||||||||
| NSP-Wisconsin | 0.24 | — | 0.24 | |||||||||||||||||
| Earnings from equity method investments — WYCO | 0.03 | — | 0.03 | |||||||||||||||||
Regulated utility (a) | 3.76 | 0.06 | 3.83 | |||||||||||||||||
| Xcel Energy Inc. and Other | (0.33) | — | (0.33) | |||||||||||||||||
Total (a) | $ | 3.44 | 0.06 | $ | 3.50 | |||||||||||||||
(a)Amounts may not add due to rounding.
Adjustments to GAAP net income include:
Sherco Unit 3 2011 Outage Refunds — NSP-Minnesota’s Sherco Unit 3 experienced an extended outage following a 2011 incident which damaged its turbine. In October 2024 following contested case procedures, the MPUC ordered a customer refund of $46 million for replacement power incurred during the outage, which is presented as a non-recurring charge to electric revenues.
Marshall Wildfire Litigation — In the third quarter of 2025, PSCo recognized a non-recurring $287 million charge as a result of a settlement reached with the plaintiffs in the Marshall Wildfire litigation. In the fourth quarter of 2025, an additional $12 million was recognized for estimated remaining settlement costs as well as legal and other costs.
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Results of Operations | ||
Diluted EPS for Xcel Energy at Dec. 31:
| Diluted Earnings (Loss) Per Share | 2025 | 2024 | ||||||||||||
| NSP-Minnesota | $ | 1.53 | $ | 1.41 | ||||||||||
| PSCo | 1.15 | 1.39 | ||||||||||||
| SPS | 0.67 | 0.70 | ||||||||||||
| NSP-Wisconsin | 0.27 | 0.24 | ||||||||||||
| Earnings from equity method investments — WYCO | 0.03 | 0.03 | ||||||||||||
Regulated utility (a) | 3.65 | 3.76 | ||||||||||||
| Xcel Energy Inc. and Other | (0.23) | (0.33) | ||||||||||||
GAAP diluted EPS (a) | $ | 3.42 | $ | 3.44 | ||||||||||
| Sherco Unit 3 2011 outage refunds | — | 0.06 | ||||||||||||
| Marshall Wildfire settlement | 0.38 | — | ||||||||||||
Ongoing diluted EPS (a) | $ | 3.80 | $ | 3.50 | ||||||||||
(a)Amounts may not add due to rounding.
Xcel Energy’s management believes that ongoing earnings reflects management’s performance in operating Xcel Energy and provides a meaningful representation of the performance of Xcel Energy’s core business. In addition, Xcel Energy’s management uses ongoing earnings internally for financial planning and analysis, reporting results to the Board of Directors and when communicating its earnings outlook to analysts and investors.
2025 Comparison with 2024
Xcel Energy — GAAP diluted earnings were $3.42 per share compared to $3.44 per share in 2024 and ongoing diluted earnings were $3.80 per share in 2025, compared with $3.50 per share in 2024. The change in ongoing EPS was driven by increased recovery of infrastructure investments and electric sales growth, partially offset by higher interest, depreciation 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 increased $0.12 per share and ongoing earnings increased $0.06 per share for 2025 compared to 2024. Ongoing earnings increased due to higher recovery of electric infrastructure investments, partially offset by increased O&M expenses, depreciation and interest charges.
PSCo — GAAP earnings decreased $0.24 per share and ongoing earnings increased $0.14 per share for 2025 (difference in GAAP and ongoing due to Marshall Wildfire settlement in 2025, see Non-GAAP Financial Measures for reconciliation from GAAP to ongoing earnings). Ongoing earnings increased due to higher recovery of electric and natural gas infrastructure investments and increased AFUDC, which was partially offset by increased depreciation, interest and O&M charges.
SPS — GAAP and ongoing earnings decreased $0.03 per share for 2025 . The decrease was driven by increased interest charges, O&M expenses and the negative impact of weather, partially offset by sales growth and higher recovery of electric infrastructure investments.
NSP-Wisconsin — GAAP and ongoing earnings increased $0.03 per share for 2025. The increase was driven by higher recovery of electric and natural gas infrastructure investments, which was partially offset by increased depreciation and O&M expenses.
Xcel Energy Inc. and Other — Primarily includes financing costs and interest income at the holding company and earnings from investment funds, which are accounted for as equity method investments. The change in earnings was due to gains on debt repurchases, partially offset by higher interest rates and debt levels.
Changes in Diluted EPS
Components significantly contributing to changes in 2025 EPS compared with 2024:
| Diluted Earnings (Loss) Per Share | Twelve Months Ended Dec. 31 | |||||||
| GAAP diluted EPS — 2024 | $ | 3.44 | ||||||
| Components of change — 2025 vs. 2024 | ||||||||
| Higher electric revenues | 1.27 | |||||||
| Higher natural gas revenues | 0.29 | |||||||
| Higher AFUDC equity & debt | 0.27 | |||||||
| Marshall Wildfire settlement | (0.38) | |||||||
| Higher interest charges | (0.28) | |||||||
| Higher depreciation and amortization | (0.28) | |||||||
| Higher O&M expenses | (0.25) | |||||||
Higher electric fuel and purchased power (a) | (0.23) | |||||||
| Common equity financing | (0.18) | |||||||
Higher costs of natural gas sold and transported (a) | (0.12) | |||||||
| Other, net | (0.13) | |||||||
| GAAP diluted EPS — 2025 | $ | 3.42 | ||||||
| Marshall Wildfire settlement | 0.38 | |||||||
| Ongoing diluted EPS — 2025 | $ | 3.80 | ||||||
(a)Cost of electric fuel and purchased power and natural gas sold and transported are generally recovered through regulatory recovery mechanisms and offset in revenue.
ROE for Xcel Energy and its utility subsidiaries:
| 2025 | 2024 | |||||||||||||||||||||||||
| ROE | GAAP ROE | Ongoing ROE | GAAP ROE | Ongoing ROE | ||||||||||||||||||||||
| NSP-Minnesota | 9.19 | % | 9.19 | % | 9.07 | % | 9.46 | % | ||||||||||||||||||
| PSCo | 5.66 | 7.55 | 7.63 | 7.63 | ||||||||||||||||||||||
| SPS | 8.70 | 8.70 | 9.57 | 9.57 | ||||||||||||||||||||||
| NSP-Wisconsin | 9.09 | 9.09 | 8.98 | 8.98 | ||||||||||||||||||||||
| Utility Subsidiaries | 7.60 | 8.40 | 8.55 | 8.69 | ||||||||||||||||||||||
| Xcel Energy | 9.36 | 10.38 | 10.42 | 10.61 | ||||||||||||||||||||||
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.
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As a result, weather deviations from normal levels can affect Xcel Energy’s financial performance. Gas decoupling mechanisms (and electric sales true-up in 2024) in Minnesota predominately mitigate the positive and adverse impacts of weather in that jurisdiction.
Degree-day or THI data is used to estimate amounts of energy required to maintain comfortable indoor temperature levels based on each day’s average temperature and humidity. HDD is the measure of the variation in the weather based on the extent to which the average daily temperature falls below 65° Fahrenheit. CDD is the measure of the variation in the weather based on the extent to which the average daily temperature rises above 65° Fahrenheit.
Each degree of temperature above 65° Fahrenheit is counted as one CDD, and each degree of temperature below 65° Fahrenheit is counted as one HDD. In Xcel Energy’s more humid service territories, a THI is used in place of CDD, which adds a humidity factor to CDD. HDD, CDD and THI are most likely to impact the usage of Xcel Energy’s residential and commercial customers. Industrial customers are less sensitive to weather.
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:
| 2025 vs. Normal | 2024 vs. Normal | 2025 vs. 2024 | |||||||||||||||
| HDD | (6.2) | % | (15.4) | % | 8.7 | % | |||||||||||
| CDD | (4.9) | 28.1 | (23.5) | ||||||||||||||
| THI | 11.2 | (11.2) | 26.8 | ||||||||||||||
Weather — Estimated impact of temperature variations on EPS compared with normal weather conditions:
| 2025 vs. Normal | 2024 vs. Normal | 2025 vs. 2024 | |||||||||||||||
| Retail electric | $ | (0.015) | $ | (0.008) | $ | (0.007) | |||||||||||
| Decoupling and sales true-up | — | 0.047 | (0.047) | ||||||||||||||
| Electric total | $ | (0.015) | $ | 0.039 | $ | (0.054) | |||||||||||
| Firm natural gas | (0.033) | (0.070) | 0.037 | ||||||||||||||
| Decoupling | 0.005 | 0.027 | (0.022) | ||||||||||||||
| Gas total | $ | (0.028) | $ | (0.043) | $ | 0.015 | |||||||||||
| Total | $ | (0.043) | $ | (0.004) | $ | (0.039) | |||||||||||
Sales — Sales growth (decline) for actual and weather-normalized sales:
| 2025 vs. 2024 | ||||||||||||||||||||||||||||||||
| NSP-Minnesota | PSCo | SPS | NSP-Wisconsin | Xcel Energy | ||||||||||||||||||||||||||||
| Actual | ||||||||||||||||||||||||||||||||
| Electric residential | 5.7 | % | (1.6) | % | (1.5) | % | 6.0 | % | 1.9 | % | ||||||||||||||||||||||
| Electric C&I | 0.3 | 0.1 | 5.5 | 0.7 | 2.0 | |||||||||||||||||||||||||||
| Total retail electric sales | 2.0 | (0.5) | 4.2 | 2.2 | 1.9 | |||||||||||||||||||||||||||
| Firm natural gas sales | 12.6 | (2.1) | N/A | 16.2 | 3.4 | |||||||||||||||||||||||||||
2025 vs. 2024 | ||||||||||||||||||||||||||||||||
| NSP-Minnesota | PSCo | SPS | NSP-Wisconsin | Xcel Energy | ||||||||||||||||||||||||||||
| Weather-normalized | ||||||||||||||||||||||||||||||||
| Electric residential | 1.3 | % | 1.4 | % | 3.9 | % | 1.7 | % | 1.7 | % | ||||||||||||||||||||||
| Electric C&I | (0.6) | 1.4 | 6.1 | 0.1 | 2.1 | |||||||||||||||||||||||||||
| Total retail electric sales | — | 1.3 | 5.6 | 0.6 | 2.0 | |||||||||||||||||||||||||||
| Firm natural gas sales | — | (2.9) | N/A | 2.0 | (1.7) | |||||||||||||||||||||||||||
| 2025 vs. 2024 (Leap Year Adjusted) | ||||||||||||||||||||||||||||||||
| NSP-Minnesota | PSCo | SPS | NSP-Wisconsin | Xcel Energy | ||||||||||||||||||||||||||||
| Weather-normalized | ||||||||||||||||||||||||||||||||
| Electric residential | 1.5 | % | 1.7 | % | 4.3 | % | 2.1 | % | 2.0 | % | ||||||||||||||||||||||
| Electric C&I | (0.3) | 1.6 | 6.3 | 0.4 | 2.4 | |||||||||||||||||||||||||||
| Total retail electric sales | 0.3 | 1.6 | 5.8 | 0.9 | 2.2 | |||||||||||||||||||||||||||
| Firm natural gas sales | 0.6 | (2.4) | N/A | 2.6 | (1.2) | |||||||||||||||||||||||||||
Annual weather-normalized and leap year adjusted electric sales growth (decline)
•NSP-Minnesota — Residential sales increased due to customer growth (1.1%) and use per customer (0.4%). The decrease in C&I sales was due to lower use per customer.
•PSCo — Residential sales increased due to customer growth (1.1%) and use per customer (0.6%). The increase in C&I sales was due to higher use per customer, particularly in the information and energy sectors.
•SPS — Residential sales increased due to increased use per customer (3.6%) and customer growth (0.7%). The increase in C&I sales was due to higher use per customer, primarily driven by the energy sector.
•NSP-Wisconsin — Residential sales increased due to increased use per customer (1.1%) and customer growth (0.9%). The increase in C&I sales was due to customer growth.
Annual weather-normalized and leap year adjusted natural gas sales growth (decline)
•Decrease in natural gas sales was driven primarily by decreased use per customer in PSCo residential and C&I, partially offset by customer growth in all 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 (wind, nuclear and solar), which reduce electric revenue and income taxes.
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| (Millions of Dollars) | 2025 vs. 2024 | |||||||
| Non-fuel riders | $ | 250 | ||||||
| Recovery of higher cost of electric fuel and purchased power | 214 | |||||||
| PTCs flowed back to customers (offset by lower ETR) | 172 | |||||||
| Regulatory rate outcomes (MN, ND) | 116 | |||||||
Sales and demand | 97 | |||||||
| Transmission revenues | 79 | |||||||
| Sherco Unit 3 2011 outage refunds | 47 | |||||||
| Estimated impact of weather | (39) | |||||||
| Conservation and demand side management (offset in expense) | (38) | |||||||
| Other, net | 115 | |||||||
| Total increase | $ | 1,013 | ||||||
Natural Gas Revenues
Natural gas revenues vary with changing sales, the cost of natural gas and regulatory outcomes.
| (Millions of Dollars) | 2025 vs. 2024 | |||||||
| Recovery of higher cost of natural gas | $ | 92 | ||||||
| Regulatory rate outcomes (CO) | 84 | |||||||
| Conservation revenue (offset in expense) | 47 | |||||||
| Estimated impact of weather (net of decoupling) | 11 | |||||||
| Retail sales decline (net of decoupling) | (13) | |||||||
| Other, net | 1 | |||||||
| Total increase | $ | 222 | ||||||
Electric Fuel and Purchased Power — Expenses incurred for electric fuel and purchased power are impacted by fluctuations in market prices of electricity, natural gas, coal and uranium, as well as seasonality. These incurred expenses are generally recovered through various regulatory recovery mechanisms. As a result, changes in these expenses are largely offset in operating revenues and have minimal earnings impact.
Electric fuel and purchased power expenses increased $173 million in 2025. The increase is primarily due to increased commodity prices and transmission expense.
Cost of Natural Gas Sold and Transported — Expenses incurred for the cost of natural gas sold are impacted by market prices and seasonality. These costs are generally recovered through various regulatory recovery mechanisms. As a result, changes in these expenses are largely offset in operating revenues and have minimal earnings impact.
Natural gas sold and transported increased $90 million in 2025. The increase is primarily due to increased commodity prices and volumes, partially offset by timing of fuel recovery mechanisms.
Non-Fuel Operating Expenses and Other Items
O&M Expenses — O&M expenses increased $192 million in 2025 primarily due to increased benefits and healthcare costs, wildfire mitigation (largely offset in non-fuel rider revenue), nuclear generation costs and insurance costs.
Depreciation and Amortization — Depreciation and amortization increased $209 million for the year, primarily related to system investment.
Other Income — Other income increased $92 million for the year, primarily related to gains on debt repurchases.
Interest Charges — Interest charges increased $213 million in 2025. The increase was largely due to higher long-term and short-term debt levels and higher interest rates.
AFUDC, Equity and Debt — AFUDC increased $165 million in 2025, due to system investment.
Xcel Energy Inc. and Other Results
Net income and diluted EPS contributions of Xcel Energy Inc. and its nonregulated businesses:
| (Millions of Dollars) | 2025 | 2024 | ||||||||||||
| Xcel Energy Inc. financing costs | $ | (271) | $ | (223) | ||||||||||
Xcel Energy Inc. other results (a) | 135 | 38 | ||||||||||||
| Total Xcel Energy Inc. and other | $ | (136) | $ | (185) | ||||||||||
| (Diluted Earnings (Loss) Per Share) | 2025 | 2024 | ||||||||||||
| Xcel Energy Inc. financing costs | $ | (0.46) | $ | (0.40) | ||||||||||
Xcel Energy Inc. other results (a) | 0.23 | 0.07 | ||||||||||||
| Total Xcel Energy Inc. and other costs | $ | (0.23) | $ | (0.33) | ||||||||||
(a)Amounts primarily include gains from debt repurchases, partially offset by taxes.
Xcel Energy Inc.’s results include interest charges, which are incurred at Xcel Energy Inc. and are not directly assigned to individual subsidiaries.
2024 Comparison with 2023
A discussion of changes in Xcel Energy’s results of operations, cash flows and liquidity and capital resources from the year ended Dec. 31, 2023 to Dec. 31, 2024 can be found in Part II, “Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations” of our Annual Report on Form 10-K for the fiscal year 2024, which was filed with the SEC on Feb. 27, 2025. However, such discussion is not incorporated by reference into, and does not constitute a part of, this Annual Report on Form 10-K.
| Public Utility Regulation | ||
The FERC and various state and local regulatory commissions regulate Xcel Energy Inc.’s utility subsidiaries and WGI. 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 DSM 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 and credit quality.
See Rate Matters and Other within Note 12 to the consolidated financial statements for further information.
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NSP-Minnesota
Summary of Regulatory Agencies / RTO and Areas of Jurisdiction
| Regulatory Body / RTO | Additional Information | |||||||
| MPUC | Retail rates, services, security issuances, property transfers, mergers, disposition of assets, affiliate transactions, and other aspects of electric and natural gas operations. Reviews and approves Integrated Resource Plans for meeting future energy needs. Certifies the need and siting for generating plants greater than 50 MW and transmission lines greater than 100 KV in Minnesota. Reviews and approves natural gas supply plans. | |||||||
| NDPSC | Retail rates, services and other aspects of electric and natural gas operations. Reviews and approves Integrated Resource Plans for meeting future energy needs. Regulatory authority over generation and transmission facilities, along with the siting and routing of new generation and transmission facilities in North Dakota. Pipeline safety compliance. | |||||||
| SDPUC | Retail rates, services and other aspects of electric operations. Regulatory authority over generation and transmission facilities, along with the siting and routing of new generation and transmission facilities in South Dakota. Pipeline safety compliance. | |||||||
| FERC | Wholesale electric operations, hydroelectric licensing, accounting practices, wholesale sales for resale, transmission of electricity in interstate commerce, compliance with NERC electric reliability standards, asset transfers and mergers, and natural gas transactions in interstate commerce. | |||||||
| MISO | NSP-Minnesota is a transmission owning member of the MISO RTO and operates within the MISO RTO and wholesale markets. NSP-Minnesota makes wholesale sales in other RTO markets at market-based rates. NSP-Minnesota and NSP-Wisconsin also make wholesale electric sales at market-based prices to customers outside of their balancing authority as jointly authorized by the FERC. | |||||||
| DOT | Pipeline safety compliance. | |||||||
| Minnesota Office of Pipeline Safety | Pipeline safety compliance. | |||||||
Recovery Mechanisms
| Mechanism | Additional Information | |||||||
| CIP Rider | Recovers costs of conservation and DSM programs. Minnesota state law requires NSP-Minnesota to spend no less than 1.75 percent gross annual electric retail energy sales and no less than 1.0 percent gross annual natural gas retail energy sales on CIP. These costs are recovered through an annual cost-recovery mechanism. | |||||||
| Customer Protection Mechanisms | MISO capacity revenue tracker, property tax tracker, annual incentive plan, capital true-up, deferred tax asset refund and credit card fee tracker are all mechanisms that mitigate the impact of changes to costs as compared to a baseline for NSP-Minnesota customers. | |||||||
| Decoupling | Measures natural gas revenues against a baseline revenue per-customer for all Minnesota gas customers in classes with more than 50 customers. | |||||||
| FCA | Recovers prudently incurred costs of fuel related items and purchased energy (Minnesota, North Dakota and South Dakota). | |||||||
| Gas Utility Infrastructure Cost Rider | Recovers costs for transmission and distribution pipeline integrity management programs, including funding for pipeline assessments, deferred costs for sewer separation and pipeline integrity management programs in Minnesota. | |||||||
| Infrastructure Rider | Returns benefits and recovers costs from investments benefiting customers in South Dakota. | |||||||
| Natural Gas Innovation Act Rider | Recovers costs for pilot projects and research programs aimed at innovative technologies and emission-reducing gas initiatives in Minnesota. The approved plan spans a five-year period beginning in 2025. | |||||||
| Purchased Gas Adjustment | Provides for prospective monthly rate adjustments in Minnesota and North Dakota for costs of purchased natural gas, transportation and storage service. Includes a true-up process for difference between projected and actual costs. | |||||||
| Renewable Development Fund Rider | Allocates money collected from customers for Minnesota solar energy incentive programs, renewable energy projects, payments to the MN Office of Management and Budget, and other legislative mandates. | |||||||
| Renewable Energy Rider | Recovers cost of renewable generation in North Dakota. | |||||||
| RES Rider | Recovers cost of renewable generation in Minnesota. | |||||||
| Sales True-up | Mitigates the impact of changes to sales levels as compared to a baseline for all Minnesota electric customers. | |||||||
| Transmission Cost Recovery Rider | Recovers costs for investments in Minnesota, North Dakota, and South Dakota for electric transmission and distribution grid modernization. | |||||||
Pending and Recently Concluded Regulatory Proceedings
2025 Minnesota Natural Gas Rate Case — In October 2025, NSP-Minnesota filed a natural gas rate case in Minnesota, seeking a total revenue increase of $63 million (8.2%). The filing is based on a 2026 forecast test year and includes an ROE of 10.65%, a 52.5% equity ratio and rate base of $1.5 billion. NSP-Minnesota requested interim rates of $51 million effective January 1, 2026, which were approved by the MPUC. An MPUC decision is expected in the fourth quarter of 2026.
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.
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In January 2025, the Court issued its opinion, which upheld the commission's determination on insurance expense, but reversed and remanded the executive compensation and prepaid pension asset decisions back to the MPUC. In June 2025, the MPUC ordered proceedings to reconsider the treatment of prepaid pension assets and executive compensation, with a decision expected in 2026.
2024 Minnesota Electric Rate Case — In November 2024, NSP-Minnesota filed an electric rate case in Minnesota based on an ROE of 10.3%, a 52.5% equity ratio and rate base of $13.2 billion in 2025 and $14 billion in 2026. In December 2024, the MPUC approved interim rates of $192 million, effective Jan. 1, 2025. In March 2025, NSP-Minnesota filed supplemental direct testimony, updating its total revenue request to $473 million.
In August 2025, eight parties filed testimony. The DOC, OAG, XLI, the CUB, Walmart and Joint Intervenors were the only parties to quantify recommended financial adjustments. The DOC and XLI recommended $306 million and $190 million of adjustments, respectively, largely based on a reduction in ROE, certain O&M expenses and other costs offset in trackers. Other parties recommended adjustments based on reduced ROE and issue specific recommendations.
In October 2025, NSP-Minnesota filed rebuttal testimony, updating its total revenue request to $365 million. Of NSP-Minnesota’s proposed adjustments, approximately $100 million relates to depreciation expense and $50 million are largely offset in trackers. In November 2025, the DOC filed surrebuttal testimony, re-asserting their proposed ROE of 9.25%.
An ALJ report is expected in April 2026, with a MPUC decision expected in the third quarter of 2026.
2025 South Dakota Electric Rate Case — In June 2025, NSP-Minnesota filed a request with the SDPUC for a net annual electric rate increase of $44 million (15%). The filing is based on a 2024 historic test year, a requested ROE of 10.3%, rate base of approximately $1.2 billion and an equity ratio of 52.87%. Interim rates were implemented on Jan. 1, 2026. If approved as filed, this rate request would result in an average annual residential bill increase of 3% over the period from 2016-2026.
The procedural schedule is as follows:
•Intervenor direct testimony: March 20, 2026
•Rebuttal testimony: April 14, 2026
•Evidentiary Hearing: April 28-30, 2026
A SDPUC decision is expected in the first half of 2026.
2024 North Dakota Electric Rate Case — In December 2024, NSP-Minnesota filed a request with the NDPSC for an annual electric rate increase of $45 million (19.3% over current rates established in 2021). The filing is based on a 2025 forecast test year and includes a requested ROE of 10.3%, rate base of approximately $817 million and an equity ratio of 52.5%. In January 2025, the NDPSC approved interim rates, subject to refund, of approximately $27 million (implemented on Feb. 1, 2025).
In February 2026, the NDPSC approved a settlement agreement filed by NSP-Minnesota and NDPSC Staff, effective April 1st, 2026, including a base revenue increase of $24 million, based on a ROE of 9.8% and equity ratio of 52.5%.
2026 North Dakota Natural Gas Rate Case — In January 2026, NSP-Minnesota filed a natural gas rate case in North Dakota, for an annual rate increase of $14 million (11.9%). The filing is based on a 2026 forecast test year and includes an ROE of 10.85%, a 52.5% equity ratio and rate base of $235 million. NSP-Minnesota requested interim rates of $12 million effective April 1, 2026.
Nuclear Power Operations
Nuclear power plant operations produce gaseous, liquid and solid radioactive wastes, which are covered by federal regulation. High-level radioactive wastes primarily include used nuclear fuel. Low-level waste consists primarily of demineralizer resins, paper, protective clothing, rags, tools and equipment contaminated through use.
NRC Regulation — The NRC regulates nuclear operations. Costs of complying with NRC requirements can affect both operating expenses and capital investments of the plants. NSP-Minnesota has obtained recovery of these compliance costs and expects to recover future compliance costs.
Low-Level Waste Disposal — Low level waste from Monticello and Prairie Island is disposed of at the Clive facility located in Utah and the Waste Control Specialists facility in Texas. NSP-Minnesota has storage capacity available on-site through 2033 at Prairie Island Unit 1, 2034 at Prairie Island Unit 2, and 2040 at Monticello, which would allow both plants to continue to operate if off-site low-level waste disposal facilities become unavailable.
High-Level Radioactive Waste Disposal — The federal government has responsibility to permanently dispose of domestic spent nuclear fuel and other high-level radioactive wastes. The Nuclear Waste Policy Act requires the DOE to implement a program for nuclear high-level waste management.
This includes the siting, licensing, construction and operation of a repository for spent nuclear fuel from civilian nuclear power reactors and other high-level radioactive wastes at a permanent federal storage or disposal facility. Currently, there are no definitive plans for a permanent federal storage facility site.
Nuclear Spent Fuel Storage — NSP-Minnesota has interim on-site storage for spent nuclear fuel at its Monticello and Prairie Island nuclear generating plants. Authorized storage capacity is sufficient to allow NSP-Minnesota to operate until 2040 for Monticello, and 2054 for Prairie Island.
In December 2024, the NRC approved a Subsequent License Renewal application for extended Monticello Plant operation through 2050 (Subsequent Renewed Facility Operating License No. DPR-22, Accession No. ML24310A345). NSP-Minnesota will need authorization from the MPUC for additional storage capacity through 2050.
NSP-Minnesota has notified the NRC of intent to apply for Prairie Island Subsequent License Renewal which would extend operation of Unit 1 to 2053 and Unit 2 to 2054.
Authorizations for additional spent fuel storage capacity may be required at each site to support either continued operation or decommissioning if the federal government does not commence storage operations.
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NSP-Wisconsin
Summary of Regulatory Agencies / RTO and Areas of Jurisdiction
| Regulatory Body / RTO | Additional Information | |||||||
| PSCW | Retail rates, services and other aspects of electric and natural gas operations. Certifies the need for new generating plants and electric transmission lines before the facilities may be sited and built. The PSCW has a biennial base rate filing requirement. By April of each odd numbered year, NSP-Wisconsin must submit a rate filing for the test year beginning the following January. Pipeline safety compliance. | |||||||
| MPSC | Retail rates, services and other aspects of electric and natural gas operations. Certifies the need for new generating plants and electric transmission lines before the facilities may be sited and built. Pipeline safety compliance. | |||||||
| FERC | Wholesale electric operations, hydroelectric generation licensing, accounting practices, wholesale sales for resale, transmission of electricity in interstate commerce, compliance with NERC electric reliability standards, asset transactions and mergers and natural gas transactions in interstate commerce. | |||||||
| MISO | NSP-Wisconsin is a transmission owning member of the MISO RTO that operates within the MISO RTO and wholesale energy market. NSP-Wisconsin and NSP-Minnesota are jointly authorized by the FERC to make wholesale electric sales at market-based prices. | |||||||
| DOT | Pipeline safety compliance. | |||||||
Recovery Mechanisms
| Mechanism | Additional Information | |||||||
| Annual Fuel Cost Plan | NSP-Wisconsin does not have an automatic electric fuel adjustment clause. Under Wisconsin rules, utilities submit a forward-looking annual fuel cost plan to the PSCW. Once the PSCW approves the plan, utilities defer the amount of any fuel cost under-recovery or over-recovery in excess of a 2% annual tolerance band, for future rate recovery or refund. Approval of a fuel cost plan and any rate adjustment for refund or recovery of deferred costs is determined by the PSCW. Rate recovery of deferred fuel cost is subject to an earnings test based on the most recently authorized ROE. Under-collections that exceed the 2% annual tolerance band may not be recovered if the utility earnings for that year exceed the authorized ROE. | |||||||
| Natural Gas Cost-Recovery Factor (MI) | NSP-Wisconsin’s natural gas rates for Michigan customers include a natural gas cost-recovery factor, based on 12-month projections and trued-up to actual amounts on an annual basis. | |||||||
| Power Supply Cost Recovery Factors | NSP-Wisconsin’s retail electric rate schedules for Michigan customers include power supply cost recovery factors, based on 12-month projections. After each 12-month period, a reconciliation is submitted whereby over-recoveries are refunded and any under-recoveries are collected from customers. | |||||||
| Purchased Gas Adjustment (WI) | A retail cost-recovery mechanism to recover the actual cost of natural gas, transportation and storage services. | |||||||
Pending Regulatory Proceedings
Excess Liability Insurance Deferral – In February 2025, NSP-Wisconsin filed a request with the PSCW for deferred accounting treatment for excess liability insurance expense of $9.6 million incurred as a result of the October 2024 policy renewal. The PSCW issued a written approval in November 2025 and authorized recovery of the deferral over 2026 and 2027 in the Wisconsin Electric and Natural Gas Rate Case described below.
Wisconsin Electric and Natural Gas Rate Case – In March 2025, NSP-Wisconsin filed a request with the PSCW for a multi-year electric and natural gas rate increase. Both the electric and natural gas rate requests were based on forward-looking 2026 and 2027 test years, with a 10.0% ROE and an equity ratio of 53.5%.
In December 2025, the PSCW issued final written approval on NSP-Wisconsin’s request, with a final rate increase of $126 million for the electric utility ($68 million in 2026, with an incremental $58 million in 2027) and $22 million for the natural gas utility ($18 million in 2026, with an incremental $4 million in 2027), based on a ROE of 9.8% and an equity ratio of 52.5%.
(Millions of Dollars) | Electric | Natural Gas | ||||||||||||
NSP-Wisconsin’s filed two-year rate request | $ | 151 | $ | 24 | ||||||||||
PSCW decision: | ||||||||||||||
Capital investments | (8) | (1) | ||||||||||||
ROE adjustment | (7) | (1) | ||||||||||||
O&M expenses | (5) | (1) | ||||||||||||
Nuclear decommissioning accrual update (a) | (6) | — | ||||||||||||
| Excess liability insurance deferral recovery | 4 | 1 | ||||||||||||
Other, net | (3) | — | ||||||||||||
Total revenue change | $ | 126 | $ | 22 | ||||||||||
(a)Since filing the case, the MPUC authorized a reduction to the annual nuclear decommissioning accrual. This reduction, which flows to NSP-Wisconsin through the interchange agreement, reduced the NSP-Wisconsin rate request and is earnings neutral.
Michigan Natural Gas Rate Case – In July 2025, NSP-Wisconsin filed a natural gas rate case in Michigan, seeking a revenue increase of $2.2 million. In December 2025, the MPSC issued a final written approval of the settlement order, with a final rate increase of $1.6 million ($0.7 million in 2026, with an incremental $0.9 million in 2027) based on a ROE of 9.8% and an equity ratio of 50%.
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NSP System
Pending and Recently Concluded Regulatory Proceedings
NSP-Minnesota and NSP-Wisconsin are actively engaged in multiple processes and proceedings to acquire resources to meet their identified generation resource needs.
•In October 2023, NSP-Minnesota issued an RFP seeking 1,200 MW of wind assets to replace capacity and reutilize interconnection rights associated with the retiring Sherco coal facilities. The RFP closed in December 2023. NSP-Minnesota expects to file for approval of recommended projects in early 2026.
•In 2024, NSP-Minnesota and NSP-Wisconsin each issued an RFP collectively seeking up to 1,600 MW of wind, solar, storage or hybrid resources to interconnect to the NSP System, including reutilization of the interconnection rights associated with the retiring Sherco coal units, and 650 MW of solar and storage resources to specifically reutilize the interconnection rights associated with the retiring King coal unit. NSP-Minnesota and NSP-Wisconsin announced the short listed projects in January 2025. NSP-Minnesota filed for requisite approvals of the selected resources with the MPUC in the fourth quarter of 2025 (decision expected in early 2026); NSP-Wisconsin expects to file for approvals with the PSCW in 2026.
•In December 2025, NSP-Minnesota and NSP-Wisconsin jointly issued an RFP seeking up to 3,500 MW of wind, solar, hydro, standalone storage, or hybrid capacity that will achieve commercial operation by December 31, 2030. Additionally, NSP-Minnesota is seeking to procure up to 600 MW of solar or solar + storage capacity that will achieve commercial operation by December 31, 2029, and meet Minnesota’s Distributed Solar Energy Standard eligibility requirements. Bids are due in March 2026, and filing for MPUC approval is expected by the end of 2026, ahead of the established procedural schedule.
•NSP-Minnesota and NSP-Wisconsin may continue to file additional RFPs throughout 2026 and 2027 for resource needs as part of its Upper Midwest resource planning efforts.
Large Load Agreement — In the first quarter of 2026, NSP-Minnesota entered into an electric service agreement to power a new Google data center in Minnesota. Under the agreement, Google will pay all costs for its new service for the duration of the agreement, in accordance with Minnesota’s regulatory and legislative requirements for large loads. Requests for approval of the Electric Service Agreement and 1,900 MW of proposed renewable generation to support the data center is expected to be filed with the MPUC by April 2026.
Purchased Power and Transmission Services
The NSP System expects to use power plants, power purchases, conservation and DSM options, new generation facilities and expansion of power plants to meet its system capacity requirements.
Purchased Power — Through the Interchange Agreement, NSP-Wisconsin receives power purchased by NSP-Minnesota from other utilities and independent power producers. Long-term purchased power contracts for dispatchable resources typically require a capacity charge and an energy charge. NSP-Minnesota makes short-term purchases to meet system requirements, replace company owned generation, meet operating reserve obligations or obtain energy at a lower cost.
Purchased Transmission Services — NSP-Minnesota and NSP-Wisconsin have contracts with MISO and other regional transmission service providers to deliver power and energy to their customers.
Wholesale and Commodity Marketing Operations
NSP-Minnesota conducts wholesale marketing operations, including the purchase and sale of electric capacity, energy, ancillary services and energy-related products. NSP-Minnesota uses physical and financial instruments to minimize commodity price risk and to hedge sales and purchases.
NSP-Minnesota also engages in trading activity unrelated to these hedging activities. Sharing of any margins is determined through state regulatory proceedings as well as the operation of the FERC approved joint operating agreement. NSP-Minnesota and NSP-Wisconsin do not serve any wholesale requirements customers at cost-based regulated rates.
PSCo
Summary of Regulatory Agencies / RTO and Areas of Jurisdiction
| Regulatory Body / RTO | Additional Information on Regulatory Authority | |||||||
| CPUC | Retail rates, accounts, services, issuance of securities and other aspects of electric, natural gas and steam operations. Reviews and approves Integrated Resource Plans for meeting future energy needs. Certifies the need and siting for generating plans greater than 50 MW. Pipeline safety compliance. | |||||||
| FERC | Wholesale electric operations, accounting practices, hydroelectric licensing, wholesale sales for resale, transmission of electricity in interstate commerce, compliance with the NERC electric reliability standards, asset transactions and mergers and natural gas transactions in interstate commerce. Wholesale electric sales at cost-based prices to customers inside PSCo’s balancing authority area and at market-based prices to customers outside PSCo’s balancing authority area. PSCo holds a FERC certificate that allows it to transport natural gas in interstate commerce without PSCo becoming subject to full FERC jurisdiction. | |||||||
| RTO | PSCo is not presently a member of an RTO and does not operate within an RTO energy market. However, PSCo does make certain sales to other RTO’s, including SPP and participates in the SPP Western Energy Imbalance Service market, an energy imbalance market. | |||||||
| DOT | Pipeline safety compliance. | |||||||
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Recovery Mechanisms
| Mechanism | Additional Information | |||||||
| Colorado Energy Plan Adjustment | Recovers the early retirement costs of Comanche Units 1 and 2 to a maximum of 1% of the customer’s bill. | |||||||
| Clean Energy Plan Revenue | Recovers projects approved through the Clean Energy Plan to a maximum of 1.25% of the customer’s bill. | |||||||
| DSM Cost Adjustment | Recovers electric and gas DSM and CHP, interruptible service costs and performance incentives for achieving energy savings goals. | |||||||
| Electric Commodity Adjustment | Recovers fuel, purchased energy costs and certain owned renewable generating assets. Short-term sales margins are shared with customers. PTCs earned for owned wind and solar generation are returned to customers. | |||||||
| FCA | PSCo recovers fuel and purchased energy costs from wholesale electric customers through a fuel cost adjustment clause approved by the FERC. Wholesale customers pay production costs through a forecasted formula rate subject to true-up. | |||||||
| GCA | Recovers costs of purchased natural gas and transportation and is revised quarterly to allow for changes in natural gas rates. Gas Price Risk Management Plan reserves are also collected in this mechanism as gas prices permit. | |||||||
| GMAC | Recovers select categories of distribution costs. | |||||||
| Purchased Capacity Cost Adjustment | Recovers purchased capacity payments. | |||||||
| RES Adjustment | Recovers the incremental costs of compliance with the RES with a maximum of 1% of the customer’s bill. | |||||||
| Steam Cost Adjustment | Recovers fuel costs to operate the steam system. The Steam Cost Adjustment rate is revised quarterly. | |||||||
| Transmission Cost Adjustment | Recovers costs between rate cases for transmission projects that result in a net increase in capacity or are part of an approved wildfire mitigation plan. Distribution projects are recoverable for 2024 and 2025, subject to a cap of 0.5% and 1.25% of electric distribution retail revenues, respectively. | |||||||
| Transportation Electrification Plan | Recovers costs associated with the investment in and adoption of transportation electrification infrastructure. | |||||||
| Wildfire Mitigation Adjustment | Recovers actual 2025-2027 costs associated with wildfire mitigation. | |||||||
Pending and Recently Concluded Regulatory Proceedings
2025 Colorado Electric Rate Case — In November 2025, PSCo filed an electric rate case with the CPUC seeking an increase in revenue of $356 million (9.9%) ($526 million inclusive of rider roll-ins). The request is based on a 9.8% ROE, an equity ratio of 55% and a 2025 test year with a projected rate base of $13 billion.
| PSCo’s base rate request (millions of dollars): | ||||||||
| Distribution system investment | $ | 294 | ||||||
| Liability insurance | 65 | |||||||
| Operating costs | 51 | |||||||
| Changes in cost of capital | 49 | |||||||
Coal retirements (a) | (120) | |||||||
| Other | 17 | |||||||
| Rate request, net of rider roll-ins | $ | 356 | ||||||
(a)The case includes request for rider recovery of any costs associated with extending operations at Comanche Unit 2.
A CPUC decision and implementation of final rates is anticipated in the third quarter of 2026.
2025 Colorado Natural Gas Rate Case — In December 2025, PSCo filed a natural gas rate case with the CPUC seeking an increase in revenue of $190 million (11.6%). The request is based on a 10.75% ROE, an equity ratio of 55% and a 2025 test year with a projected rate base of $4.7 billion.
| PSCo’s base rate request (millions of dollars): | ||||||||
| Capital investments | $ | 90 | ||||||
| Changes in cost of capital | 53 | |||||||
| Operating costs | 42 | |||||||
| Sales/revenue growth | (7) | |||||||
| Other | 12 | |||||||
| Total rate request | $ | 190 | ||||||
A CPUC decision and implementation of final rates is anticipated in the third quarter of 2026.
2024 Colorado Natural Gas Rate Case — In January 2024, PSCo filed a natural gas rate case with the CPUC. In October 2024, as modified on ARRR in January 2025, the CPUC issued an order including an annual revenue increase of approximately $125 million, inclusive of $15 million of accelerated depreciation.
In May 2025, PSCo filed an appeal with the Denver District Court seeking review of the CPUC’s decisions related to recovery of certain operating expenses, cost of capital and capital structure, and the treatment of gas storage inventory costs. Briefing was completed in the fourth quarter of 2025. In the first quarter of 2026, the Denver District Court affirmed the CPUC’s decision on all counts appealed by PSCo.
Colorado Resource Plan — In December 2023, the CPUC approved a portfolio of 5,835 MW, which includes approximately 3,100 MW of company owned resources and 2,700 MW of PPAs.
In September 2025, the CPUC authorized a process for company-owned and PPA resources to seek up to 15% relief for tariff impacts to projects. Relief requests are due by Dec. 31, 2025 or 18 months prior to COD. The CPUC will ultimately review and approve/deny requests.
PSCo has filed all generation CPCNs associated with company-owned generation from the Colorado Resource Plan and expects to continue filing transmission CPCNs throughout 2026.
2024 Colorado Electric Resource Plan — In October 2024, PSCo filed its Phase I electric resource plan with the CPUC. In November 2025, the CPUC approved a load forecast that reflects a 3% compound annual sales growth through 2031 and generation capacity need of approximately 5,400 MW.
PSCo filed a request for reconsideration of various aspects of the decision which were verbally approved in January 2026 (with a written decision related to those reconsideration requests expected in the first quarter of 2026). This decision is expected to initiate the Phase II competitive solicitation process with an RFP expected to be issued in the third quarter of 2026. This RFP will seek to acquire the balance of resource needs through 2031 (after consideration of any approved acquisitions from the Near-Term Procurement RFP).
Near-Term Procurement — In August 2025, PSCo filed a joint motion with state agencies to initiate a “fast-tracked” solution for tax-advantaged new generation resources. The CPUC approved the request in September 2025 with bids submitted in October 2025. The procurement seeks to accelerate development of up to 4,000 nameplate MW of clean energy resources, 200 accredited MW of firm, dispatchable resources, and up to 300 accredited MW of other dispatchable resources.
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The table below summarizes the recommended portfolio of resources filed in December 2025 (a decision is expected in February 2026):
| (Nameplate MW) | Company Owned | PPA | Total | |||||||||||||||||
| Wind | 1,600 | 1,100 | 2,700 | |||||||||||||||||
| Solar | — | 1,100 | 1,100 | |||||||||||||||||
| Natural gas combustion turbine | 200 | — | 200 | |||||||||||||||||
| Other storage | 300 | 600 | 900 | |||||||||||||||||
| Total | 2,100 | 2,800 | 4,900 | |||||||||||||||||
In February 2026, the CPUC approved 3,200 MW of resources, which included PPAs and a 200 MW company-owned natural gas combustion turbine. Additionally, in March 2026 PSCo will file additional information related to 600-1,500 MW of company-owned wind, solar and storage resources that have been conditionally approved.
Grid Modernization Adjustment Clause (GMAC) — In December 2024, PSCo filed its 2025-2029 Distribution System Plan which included a request to implement the GMAC for recovery of distribution investments. The CPUC issued their decision in December 2025, as modified by an ARRR in February 2026, approving the inclusion of capacity expansion projects and certain other related costs. The CPUC indicated other categories of distribution costs may be considered for recovery within the GMAC in a future regulatory process, expected in late 2026 or 2027.
Colorado Senate Bill 23-291 — In May 2023, Colorado Senate Bill 23-291 was signed into law. The legislation included a number of topics including for the CPUC to adopt rules to establish fuel cost mechanisms to align the financial incentives of a utility with the interests of the utility’s customers.
In December 2024, the CPUC adopted final rules applicable to PSCo’s natural gas utility that would assign to the Company four percent of the change in the price per MMbtu of natural gas compared to the three-year average, subject to rolling 12-month cap based on a percentage of rate base, currently estimated at $7 million. PSCo made a filing in June 2025 to implement the mechanism and filed an unopposed settlement agreement in November 2025. In December 2025, a CPUC ALJ approved the settlement agreement, and PSCo implemented the gas fuel cost mechanism in January 2026.
In December 2024, the CPUC also adopted rules for electric utilities but did not adopt a specific PIM framework. PSCo made a filing in November 2025 to the CPUC to implement an electric fuel cost mechanism based on a current market-based index rather than a historical index as required for PSCo’s natural gas utility, subject to a cap currently estimated at $3 million. PSCo expects to implement the electric fuel cost mechanism in the second quarter of 2026.
Purchased Power and Transmission Service Providers
PSCo meets its system capacity and energy requirements through its fleet of owned and purchased electric generation resources and, when required, the use of demand-side management programs.
Purchased Power — PSCo purchases power from other utilities, energy marketers and independent power producers. Long-term purchased power contracts for dispatchable resources typically require capacity and energy charges. Much of PSCo’s long-term purchased power is for wind, solar and storage resources. PSCo makes short-term purchases to meet system load and energy requirements, replace generation out of service for maintenance, meet operating reserve obligations, or obtain energy at a lower cost.
Purchased Transmission Services — In addition to using its own transmission system, PSCo has contracts with regional transmission service providers to deliver energy to its customers.
Wholesale and Commodity Marketing Operations
PSCo conducts various wholesale marketing operations, including the purchase and sale of electric capacity, energy, ancillary services and energy related products. PSCo uses physical and financial instruments to minimize commodity price risk and hedge sales and purchases. PSCo also engages in trading activity unrelated to these hedging activities.
Sharing of any margin is determined through state regulatory proceedings as well as the operation of the FERC approved joint operating agreement.
SPS
Summary of Regulatory Agencies / RTO and Areas of Jurisdiction
| Regulatory Body / RTO | Additional Information | |||||||
| PUCT | Retail electric operations, rates, services, construction of transmission or generation and other aspects of SPS’ electric operations. The municipalities in which SPS operates in Texas have original jurisdiction over rates in those communities. The municipalities’ rate setting decisions are subject to PUCT review. | |||||||
| NMPRC | Retail electric operations, retail rates and services and the construction of transmission or generation. Reviews Integrated Resource Plans for meeting future energy needs. | |||||||
| FERC | Wholesale electric operations, accounting practices, wholesale sales for resale, the transmission of electricity in interstate commerce, compliance with NERC electric reliability standards, asset transactions and mergers, and natural gas transactions in interstate commerce. | |||||||
| SPP RTO and SPP Integrated and Wholesale Markets | SPS is a transmission owning member of the SPP RTO and operates within the SPP RTO and SPP integrated and wholesale markets. SPS is authorized to make wholesale electric sales at market-based prices. | |||||||
| DOT | Pipeline safety compliance. | |||||||
Recovery Mechanisms
| Mechanism | Additional Information | |||||||
| Advanced Metering System Surcharge | Recovers costs incurred in deployment of the Advanced Metering System in Texas. | |||||||
| Consulting Fee Rider | Recovers consulting fees and carrying charges incurred by SPS on behalf of the PUCT. | |||||||
| Distribution Cost Recovery Factor | Recovers distribution costs not included in rates in Texas, including recovery of deferred Texas System Resiliency Plan costs. | |||||||
| Electric Vehicle Rider | Recovers costs of the Transportation Electrification Plan in New Mexico. | |||||||
| Energy Efficiency Cost Recovery Factor | Recovers costs for energy efficiency programs in Texas. | |||||||
| Energy Efficiency Rider | Recovers costs for energy efficiency programs in New Mexico. | |||||||
| Fixed Fuel and Purchased Recovery Factor | Provides for the over- or under-recovery of energy expenses in Texas. Regulations require refunding or surcharging over- or under- recovery amounts, including interest, when they exceed 4% of the utility’s annual fuel and purchased energy costs on a rolling 12-month basis if this condition is expected to continue. | |||||||
| Fuel and Purchased Power Cost Adjustment Clause | Adjusts monthly to recover actual fuel and purchased power costs in New Mexico. | |||||||
| Grid Modernization Rider | Recovers costs incurred in the implementation of Grid Modernization Components in New Mexico. | |||||||
| Generation Cost Recovery Rider | Recovers investments in a power generation facility outside of a base rate proceeding | |||||||
| Renewable Portfolio Standards | Recovers deferred costs for renewable energy programs in New Mexico. | |||||||
| Transmission Cost Recovery Factor | Recovers certain transmission infrastructure improvement costs and changes in wholesale transmission charges not included in Texas base rates. | |||||||
| Wholesale Fuel and Purchased Energy Cost Adjustment | SPS recovers fuel and purchased energy costs from its wholesale customers through a monthly wholesale fuel and purchased energy cost adjustment clause accepted by the FERC. Wholesale customers also pay the jurisdictional allocation of production costs. | |||||||
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Pending and Recently Concluded Regulatory Proceedings
2025 New Mexico Electric Rate Case — In November 2025, SPS filed an electric rate case with the NMPRC seeking a revenue increase of $175 million (16.7%). The request is based on a future test year period ending November 30, 2027, a ROE of 10.5%, an equity ratio of 56% and retail rate base of $3.9 billion.
The request reflects:
•Significant retail revenue growth.
•Continued capital investment primarily to support the clean energy transition and load growth.
•Planned roll-off of 100 MW of wholesale load in 2026.
SPS’ base rate request (millions of dollars):
| Retail revenue growth | $ | (204) | ||||||
| Increase in allocation of assets and costs to New Mexico retail, including impact of wholesale load roll-off | 148 | |||||||
| Capital investment | 133 | |||||||
| O&M expenses | 36 | |||||||
| Depreciation rate changes and amortization | 34 | |||||||
| Increase in requested ROE | 28 | |||||||
| Total rate request | $ | 175 | ||||||
The procedural schedule is as follows:
•Intervenor direct testimony: March 27, 2026
•Rebuttal testimony: April 17, 2026
•Public Evidentiary Hearing: May 26 - June 5, 2026
A NMPRC decision and implementation of final rates is anticipated in the second half of 2026.
SPS Resource Plan (IRP) — In October 2023, SPS filed its IRP with the NMPRC, which supports projected load growth and increasing reliability requirements, and secures replacement energy and capacity for retiring resources.
In July 2024, SPS issued a RFP, seeking approximately 3,200 MW of accredited capacity by 2030. In July 2025, the portfolio selection report was publicly filed with the NMPRC with 3,121 MW of accredited capacity resources, including the following:
| Generation Resource Nameplate Capacity (in MW) | Company Owned | PPAs | Total | ||||||||
| Wind Resources | 1,273 | — | 1,273 | ||||||||
| Solar | 695 | — | 695 | ||||||||
| Storage | 472 | 640 | 1,112 | ||||||||
| Natural Gas | 2,088 | — | 2,088 | ||||||||
| Total | 4,528 | 640 | 5,168 | ||||||||
SPS filed or expects to file Certificate of Convenience and Necessity filings for the specific assets with the PUCT and NMPRC in 2025 and 2026, with approvals expected in 2026 and 2027.
2025 Resource Acquisition – In October 2025, SPS issued a RFP to solicit 870 MW of accredited capacity (approximately 1,500 MW to 3,000 MW nameplate capacity) through 2032. Additional resources will be evaluated to meet the New Mexico Renewable Portfolio Standard compliance need. Bids were received in January 2026, and the portfolio is expected to be filed in the second half of 2026.
Excess Liability Insurance Deferral – In March 2025, SPS filed a request with the PUCT and in April 2025, SPS filed a request with the NMPRC for deferred accounting treatment for incremental excess liability insurance expense incurred as a result of the October 2024 policy renewal, estimated at approximately $30 million across the two jurisdictions. In October 2025, the NMPRC approved the request, resulting in a deferral of approximately $15 million of incremental excess liability insurance costs in 2025. In January 2026, SPS, PUCT Staff and other intervenors filed a black box settlement expected to result in annual deferrals of approximately $8 million in 2026 and 2027. A PUCT decision is expected in the first half of 2026.
Texas System Resiliency Plan — In December 2024, SPS filed its Texas SRP with the PUCT. Consistent with PUCT requirements, SPS’ proposed plan discusses resiliency-related risks and the five measures that have been designed to help SPS prevent, withstand, mitigate or more promptly recover from resiliency events, including wildfire. The proposed SRP covers 2025-2028 and includes a proposed $538 million of investment.
In April 2025, SPS filed a unanimous stipulation and settlement agreement. The settlement includes approximately $490 million of spend over the plan period, adjusted largely to reflect the removal of the operational flexibility measure for investment in the normal course of business. The settlement also includes the deferral of distribution-related costs, including depreciation expense and carrying costs at SPS’ weighted average cost of capital.
In July 2025, the PUCT approved the SRP, authorizing approximately $495 million of spend over the plan period, including reinstating previously removed distribution hardening projects.
Purchased Power Arrangements and Transmission Service Providers
SPS expects to use electric generating stations, power purchases, DSM and new generation options to meet its system capacity requirements.
Purchased Power — SPS purchases power from other utilities and IPPs. Long-term purchased power contracts typically require periodic capacity and energy charges. SPS also makes short-term purchases to meet system load and energy requirements to replace owned generation, meet operating reserve obligations or obtain energy at a lower cost.
Purchased Transmission Services — SPS has contractual arrangements with SPP and regional transmission service providers to deliver power and energy to its native load customers.
Natural Gas
SPS does not provide retail natural gas service, but purchases and transports natural gas for its generation facilities and operates limited natural gas pipeline facilities connecting the generation facilities to interstate natural gas pipelines, subject in certain cases to the regulation of the Railroad Commission of Texas. SPS is subject to the jurisdiction of the FERC with respect to natural gas transactions in interstate commerce and the PHMSA, DOT and PUCT for pipeline safety compliance.
Wholesale and Commodity Marketing Operations
SPS conducts various wholesale marketing operations, including the purchase and sale of electric capacity, energy, ancillary services and energy related products. SPS uses physical and financial instruments to minimize commodity price risk and to hedge sales and purchases. Sharing of any margin is determined through state regulatory proceedings as well as the operation of the FERC approved joint operating agreement.
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| Other | ||
Supply Chain
Xcel Energy’s ability to meet customer energy requirements, growing customer demand, respond to storm-related disruptions, and execute our capital expenditure program are dependent on maintaining an efficient supply chain.
Large global demand for energy-related infrastructure has stretched equipment supply chains, extended delivery dates and increased prices for items like combustion turbines, transformers and other large electrical equipment. The labor market for skilled engineering and construction resources to build renewables and gas generation has also been strained, impacting cost and availability.
In addition, manufacturing processes have experienced disruptions related to the scarcity of certain raw materials and interruptions in production and shipping. The impact of inflationary pressures, geopolitical events and federal policies have exacerbated the situation. Xcel Energy continues to monitor the situation as it remains fluid and seeks to mitigate the impacts by securing alternative suppliers and key vendor partners, increasing procurement lead times, modifying design standards, and adjusting the timing of work.
Tariffs, Trade Complaints and Federal Actions
Several trade cases related to anti-dumping and countervailing duty investigations are ongoing and we continue to monitor the potential impacts of these cases.
In 2025, several executive orders have been issued imposing new global and country-specific tariffs on many imports, which may impact our procurement and development activities. Additionally, executive orders and actions from government agencies may impact the permitting of wind and solar facilities and the retirement of coal facilities.
Xcel Energy continues to assess the impacts of these tariffs, executive orders, trade complaints and federal policies on its business, including company owned projects and PPAs. Xcel Energy may seek regulatory relief, if required, in its jurisdictions.
Continued and/or further policy actions or other restrictions, disruptions in imports from key suppliers, or any new trade complaint could impact viability, timelines and costs of various projects and PPAs.
Tax Law Changes
On July 4, 2025, the President signed into law Public Law No. 119-21 (the “OBBB”). The OBBB modifies certain clean energy tax provisions included in the Inflation Reduction Act. The provisions include:
•Eliminating production and investment tax credits for wind and solar facilities placed in service after 2027, for facilities that begin construction after July 4, 2026.
•The addition of foreign entity of concern rules that apply to projects commencing construction after 2025.
In August 2025, the U.S. Treasury issued further guidance related to the beginning of construction for clean energy projects. In February 2026, the U.S. Treasury and IRS released initial guidance regarding foreign entities of concern. The notice includes interim safe harbor guidance for the purposes of assessing material assistance from a prohibited foreign entity for wind, solar and storage tax credits. Further guidance is expected to be released throughout 2026 related to such rules.
Xcel Energy does not expect these provisions to have an impact on our 2026-2030 base capital plan, as steps have been taken to begin construction under the IRS’ safe harbor guidance.
Excess Liability Insurance Coverage
Xcel Energy maintains excess liability coverage, which is intended to insure against liability to third parties. Through the third quarter of 2024, Xcel Energy had approximately $600 million of excess liability coverage; including $520 million of wildfire coverage with an annual premium of approximately $40 million. Examples of claims paid under this policy include property damage or bodily injury to members of the public caused by Xcel Energy’s employees, equipment or facilities. The increased wildfire liability risk and claims are driving a significant increase of premiums and reductions in insurance coverage in the excess liability markets, especially in the western United States.
In October 2024, Xcel Energy renewed its excess liability coverage and now has $450 million of total coverage; including $450 million of wildfire coverage for the NSP System and $300 million of wildfire coverage for PSCo and SPS. The annual premium for this excess liability insurance is approximately $130 million. In October 2025, Xcel Energy renewed its excess liability coverage for the same level with an annual premium of approximately $135 million. Xcel Energy has received approval to defer incremental costs in Colorado, Wisconsin and New Mexico and is awaiting approval of a settlement agreement allowing deferral of certain costs in Texas.
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. In addition, the financial and operating environment also may have a significant effect on the operation of the business and results reported.
Accounting policies and estimates that are most significant to Xcel Energy’s results of operations, financial condition or cash flows, and require management’s most difficult, subjective or complex judgments are outlined below. Each of these has a higher likelihood of resulting in materially different reported amounts under different conditions or using different assumptions. Each critical accounting policy has been reviewed and discussed with the Audit Committee of Xcel Energy Inc.’s Board of Directors on a quarterly basis.
Regulatory Accounting
Xcel Energy is subject to the accounting for Regulated Operations, which provides that rate-regulated entities report assets and liabilities consistent with the recovery of those incurred costs in rates, if it is probable that such rates will be charged and collected. Our rates are derived through the ratemaking process, which results in the recording of regulatory assets and liabilities based on the probability of future cash flows.
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Regulatory assets generally represent incurred or accrued costs that have been deferred because future recovery from customers is probable. Regulatory liabilities generally represent amounts that are expected to be refunded to customers in future rates or amounts collected in current rates for future costs. In other businesses or industries, regulatory assets and regulatory liabilities would generally be charged to net income or other comprehensive income.
Each reporting period we assess the probability of future recoveries and obligations associated with regulatory assets and liabilities. Factors such as the current regulatory environment, recently issued rate orders and historical precedents are considered. Decisions made by regulatory agencies can directly impact the amount and timing of cost recovery as well as the rate of return on invested capital, and may materially impact our results of operations, financial condition or cash flows.
As of Dec. 31, 2025 and 2024, Xcel Energy had regulatory assets of $3.5 billion and $3.4 billion, respectively and regulatory liabilities of $7.0 billion and $6.9 billion, respectively. Each subsidiary is subject to regulation that varies from jurisdiction to jurisdiction. If future recovery of costs in any such jurisdiction is no longer probable, Xcel Energy would be required to charge these assets to current net income or other comprehensive income.
At Dec. 31, 2025, in assessing the probability of recovery of recognized regulatory assets, unless otherwise disclosed, Xcel Energy noted no current or anticipated proposals or changes in the regulatory environment that it expects will materially impact the recovery of the assets.
See Notes 4 and 12 to the consolidated financial statements for further information.
Income Tax Accruals
Judgment, uncertainty and estimates are a significant aspect of the income tax accrual process that accounts for the effects of current and deferred income taxes. Uncertainty associated with the application of tax statutes and regulations and outcomes of tax audits and appeals require that judgment and estimates be made in the accrual process and in the calculation of the ETR.
Changes in tax laws and rates may affect recorded deferred tax assets and liabilities and our future ETR. ETR calculations are revised every quarter based on best available year-end tax assumptions, adjusted in the following year after returns are filed. Tax accrual estimates are trued-up to the actual amounts claimed on the tax returns and further adjusted after examinations by taxing authorities, as needed.
In accordance with the interim period reporting guidance, income tax expense for the first three quarters in a year is based on the forecasted annual ETR. The forecasted ETR reflects a number of estimates, including forecasted annual income, permanent tax adjustments and tax credits.
Valuation allowances are applied to deferred tax assets if it is more likely than not that at least a portion may not be realized. Accounting for income taxes also requires that only tax benefits that meet the more likely than not recognition threshold can be recognized or continue to be recognized.
We may adjust our unrecognized tax benefits and interest accruals as disputes with the IRS and state tax authorities are resolved, and as new developments occur. These adjustments may increase or decrease earnings.
See Note 7 to the consolidated financial statements for further information.
Employee Benefits
We sponsor several noncontributory, defined benefit pension plans and other postretirement benefit plans that cover almost all employees and certain retirees. Projected benefit costs are based on historical information and actuarial calculations that include key assumptions (annual return level on pension and postretirement health care investment assets, discount rates, mortality rates and health care cost trend rates, etc.). In addition, the pension cost calculation uses a methodology to reduce the volatility of investment performance over time. Pension assumptions are continually reviewed.
At Dec. 31, 2025, Xcel Energy set the rate of return on assets used to measure pension costs at 7.13%, which remains unchanged from the rate set at Dec. 31, 2024. The rate of return used to measure postretirement health care costs is 6.25% at Dec. 31, 2025, which remains unchanged from the rate set in 2024. Xcel Energy’s pension investment strategy includes plan-specific investments that seek to align the investment allocations to optimize risk adjusted return and interest rate risk management based on factors that include the plan’s funded status. This strategy generally results in a greater percentage of interest rate sensitive securities being allocated to plans with higher funded status ratios and a greater percentage of growth assets being allocated to plans having lower funded status ratios.
Xcel Energy set the discount rates used to value the pension obligations and postretirement health care obligations at 5.78% and 5.66% at Dec. 31, 2025, respectively. This represents a 10 basis point and 22 basis point decrease, respectively, from 2024. Xcel Energy uses a bond matching study as its primary basis for determining the discount rate used to value pension and postretirement health care obligations. The bond matching study utilizes a portfolio of high grade (Aa or higher) bonds that matches the expected cash flows of Xcel Energy’s benefit plans in amount and duration.
The effective yield on this cash flow matched bond portfolio determines the discount rate for the individual plans. The bond matching study is validated for reasonableness against the Bank of America US Corporate 15+ Bond Index. In addition, Xcel Energy reviews general actuarial survey data to assess the reasonableness of the discount rate selected.
If Xcel Energy were to use alternative assumptions, a 1% change would result in the following impact on 2026 pension costs, net of the effects of regulation:
| Pension Costs | ||||||||||||||
| (Millions of Dollars) | +1% | -1% | ||||||||||||
| Rate of return | $ | (12) | $ | 22 | ||||||||||
Discount rate | (4) | — | ||||||||||||
Mortality rates are developed from actual and projected plan experience for pension plan and postretirement benefits. Xcel Energy’s actuary conducts an experience study periodically to determine an estimate of mortality. Xcel Energy considers standard mortality tables, improvement factors and the plans actual experience when selecting a best estimate.
As of Dec. 31, 2025, the initial medical trend cost claim assumptions for Pre-65 was 7.0% and Post-65 was 7.5%. The ultimate trend assumption remained at 4.5% for both Pre-65 and Post-65 claims costs. Xcel Energy bases its medical trend assumption on the long-term cost inflation expected in the health care market, considering the levels projected and recommended by industry experts, as well as recent actual medical cost experienced by Xcel Energy’s retiree medical plan.
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Funding contributions in 2025 were $125 million and will be $75 million in 2026. In future years contributions will remain relatively consistent. Investment returns were more than the assumed levels in 2025 and 2023, but were less than the assumed levels in 2024.
The pension cost calculation uses a market-related valuation of pension assets. Xcel Energy uses a calculated value method to determine the market-related value of the plan assets. The market-related value is determined by adjusting the fair market value of assets at the beginning of the year to reflect the investment gains and losses (the difference between the actual investment return and the expected investment return on the market-related value) during each of the previous five years at the rate of 20% per year.
As differences between actual and expected investment returns are incorporated into the market-related value, amounts are recognized in pension cost over the expected average remaining years of service for active employees (approximately 14 years in 2025).
Xcel Energy currently projects the pension costs recognized for financial reporting purposes will be $85 million in 2026, while the actual pension costs were $59 million in 2025 and $79 million in 2024.
Pension funding contributions across all four of Xcel Energy’s pension plans, both voluntary and required, for 2023 - 2026:
•$75 million in January 2026.
•$125 million in 2025.
•$100 million in 2024.
•$50 million in 2023.
Future amounts may change based on actual market performance, changes in interest rates and any changes in governmental regulations. Therefore, additional contributions could be required in the future. Xcel Energy contributed $13 million in 2025 and $11 million during 2024 and 2023, to the postretirement health care plans. Xcel Energy expects to contribute approximately $8 million during 2026.
Xcel Energy recovers employee benefits costs in its utility operations consistent with accounting guidance with the exception of the areas noted below.
•NSP-Minnesota recognizes pension expense in all regulatory jurisdictions using the aggregate normal cost actuarial method. Differences between aggregate normal cost and expense as calculated by pension accounting standards are deferred as a regulatory liability.
•PSCo and SPS recognize pension expense in all regulatory jurisdictions based on GAAP. The Texas and Colorado electric retail jurisdictions and the Colorado gas retail jurisdiction, each record the difference between annual recognized pension expense and the annual amount of pension expense approved in their last respective general rate case as a deferral to a regulatory asset.
•Regulatory Commissions in Texas, New Mexico and FERC jurisdictions allow the recovery of other postretirement benefit costs only to the extent that recognized expense is matched by cash contributions to an irrevocable trust. Xcel Energy has consistently funded at a level to allow full recovery of costs in these jurisdictions.
•PSCo is required to create a regulatory liability to the extent expense is less than that included in rates. No adjustment was needed in 2025.
See Note 11 to the consolidated financial statements for further information.
Nuclear Decommissioning
Xcel Energy recognizes liabilities for the expected cost of retiring tangible long-lived assets for which a legal obligation exists. These AROs are recognized at fair value as incurred and are capitalized as part of the cost of the related long-lived assets. In the absence of quoted market prices, Xcel Energy estimates the fair value of its AROs using present value techniques, in which it makes assumptions including estimates of the amounts and timing of future cash flows associated with retirement activities, credit-adjusted risk free rates and cost escalation rates. When Xcel Energy revises any assumptions, it adjusts the carrying amount of both the ARO liability and related long-lived asset. ARO liabilities are accreted to reflect the passage of time using the interest method.
A significant portion of Xcel Energy’s AROs relates to the future decommissioning of NSP-Minnesota’s nuclear facilities. The nuclear decommissioning obligation is funded by the external decommissioning trust fund. Difference between regulatory funding (including depreciation expense less returns from the external trust fund) and expense recognized is deferred as a regulatory liability. The amounts recorded for AROs related to future nuclear decommissioning were $2.6 billion in 2025 and $2.5 billion in 2024.
NSP-Minnesota obtains periodic independent cost studies to estimate the cost and timing of planned nuclear decommissioning activities. Estimates of future cash flows are highly uncertain and may vary significantly from actual results. NSP-Minnesota is required to file a nuclear decommissioning filing every three years. The filing covers all expenses for the decommissioning of the nuclear plants, including decontamination and removal of radioactive material. In November 2024, the 2025-2027 Triennial Nuclear Plant Decommissioning Study was filed and was approved by the MPUC in May 2025.
The following assumptions have a significant effect on the estimated nuclear obligation:
Timing — Decommissioning cost estimates are impacted by each facility’s retirement date and timing of the actual decommissioning activities. Estimated retirement dates coincide with the retirement dates approved by the MPUC, which can be different than the expiration dates of each unit’s operating license with the NRC.
NSP-Minnesota’s current operating licenses allow continued use of its Monticello nuclear plant until 2050 and its Prairie Island nuclear plant until 2033 for Unit 1 and 2034 for Unit 2. NSP-Minnesota's authorized retirement dates are 2040 for Monticello, 2033 for Prairie Island Unit 1 and 2034 for Prairie Island Unit 2. During 2025, the Commission approved extended lives for Prairie Island Unit 1 and Unit 2 and Monticello (2053, 2054, and 2050, respectively) in the Upper Midwest Resource Plan. A request to update authorized retirement dates and related decommissioning estimates to incorporate the extended lives are pending with the Commission. These will be incorporated in decommissioning estimates once additional approvals have been received.
The estimated timing of the decommissioning activities is based upon the 60 year DECON method, which assumes prompt removal and dismantlement. Decommissioning activities are expected to begin at the commission approved retirement date and be completed for both facilities by approximately 2101.
Technology and Regulation — There is limited experience with actual decommissioning of large nuclear facilities. Changes in technology, experience and regulations could cause cost estimates to change significantly.
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Escalation Rates — Escalation rates represent projected cost increases due to general inflation and increases in the cost of decommissioning activities. NSP-Minnesota used escalation rates of 3.30% and 4.50%, for non-labor and labor expenses respectively, in calculating the ARO for nuclear decommissioning of its nuclear facilities.
Discount Rates — Changes in timing or estimated cash flows that result in upward revisions to the ARO are calculated using the then-current credit-adjusted risk-free interest rate. The credit-adjusted risk-free rate in effect when the change occurs is used to discount the revised estimate of the incremental expected cash flows of the retirement activity.
If the change in timing or estimated expected cash flows results in a downward revision of the ARO, the undiscounted revised estimate of expected cash flows is discounted using the credit-adjusted risk-free rate in effect at the date of initial measurement and recognition of the original ARO. Discount rates ranging from approximately 3% to 7% have been used to calculate the net present value of the expected future cash flows over time.
Significant uncertainties exist in estimating future costs including the method to be utilized, ultimate costs to decommission and planned method of disposing spent fuel. If different cost estimates, life assumptions or cost escalation rates were utilized, the AROs could change materially.
However, changes in estimates have minimal impact on results of operations as NSP-Minnesota expects to continue to recover all costs in future rates.
NSP-Minnesota continually makes judgments and estimates related to these critical accounting policy areas, based on an evaluation of the assumptions and uncertainties for each area. The information and assumptions of these judgments and estimates will be affected by events beyond the control of Xcel Energy, or otherwise change over time.
This may require adjustments to recorded results to better reflect updated information that becomes available. The accompanying financial statements reflect management’s best estimates and judgments of the impact of these factors as of Dec. 31, 2025.
See Note 12 to the consolidated financial statements for further information.
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 investigation, legal proceedings, mediations and settlements are considered. See Note 12 accompanying the consolidated financial statements for additional information.
Derivatives, Risk Management and Market Risk | ||
We are exposed to a variety of market risks in the normal course of business. Market risk is the potential loss that may occur as a result of adverse changes in the market or fair value for a particular instrument or commodity. All financial and commodity-related instruments, including derivatives, are subject to market risk.
Xcel Energy is exposed to the impact of adverse changes in price for energy and energy-related products, which is partially mitigated by the use of commodity derivatives. In addition to ongoing monitoring and maintaining credit policies intended to minimize overall credit risk, management takes steps to mitigate changes in credit and concentration risks associated with its derivatives and other contracts, including parental guarantees and requests of collateral. While we expect that the counterparties will perform on the contracts underlying our derivatives, the contracts expose us to credit and non-performance risk.
Distress in the financial markets may impact counterparty risk and the fair value of the securities in the nuclear decommissioning fund and pension fund.
Commodity Price Risk — We are exposed to commodity price risk in our electric and natural gas operations. Commodity price risk is managed by entering into long and short-term physical purchase and sales contracts for electric capacity, energy and energy-related products and fuels used in generation and distribution activities.
Commodity price risk is also managed through the use of financial derivative instruments. Our risk management policy allows us to manage commodity price risk within each rate-regulated operation per commission approved hedge plans.
Wholesale and Commodity Trading Risk — Xcel Energy conducts various wholesale and commodity trading activities, including the purchase and sale of electric capacity, energy, energy-related instruments and natural gas-related instruments, including derivatives. Our risk management policy allows management to conduct these activities within guidelines and limitations as approved by our risk management committee.
Fair value of net commodity trading contracts as of Dec. 31, 2025:
| Futures / Forwards Maturity | ||||||||||||||||||||||||||||||||
| (Millions of Dollars) | Less Than 1 Year | 1 to 3 Years | 4 to 5 Years | Greater Than 5 Years | Total Fair Value | |||||||||||||||||||||||||||
NSP-Minnesota (a) | $ | (10) | $ | (15) | $ | (3) | $ | (1) | $ | (29) | ||||||||||||||||||||||
NSP-Minnesota (b) | 1 | (2) | — | (4) | (5) | |||||||||||||||||||||||||||
PSCo (a) | (1) | — | — | — | (1) | |||||||||||||||||||||||||||
| $ | (10) | $ | (17) | $ | (3) | $ | (5) | $ | (35) | |||||||||||||||||||||||
| 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) | $ | — | $ | 10 | $ | 10 | $ | — | $ | 20 | ||||||||||||||||||||||
(a)Prices actively quoted or based on actively quoted prices.
(b)Prices based on models and other valuation methods.
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Changes in the fair value of commodity trading contracts before the impacts of margin-sharing for the years ended Dec. 31:
| (Millions of Dollars) | 2025 | 2024 | ||||||||||||
| Fair value of commodity trading net contracts outstanding at Jan. 1 | $ | (2) | $ | 1 | ||||||||||
| Contracts realized or settled during the period | (1) | — | ||||||||||||
| Commodity trading contract additions and changes during the period | (12) | (3) | ||||||||||||
| Fair value of commodity trading net contracts outstanding at Dec. 31 | $ | (15) | $ | (2) | ||||||||||
A 10% increase and 10% decrease in forward market prices for Xcel Energy’s commodity trading contracts would have likewise increased and decreased pretax income from continuing operations, by approximately $2 million at Dec. 31, 2025 and Dec. 31, 2024.
The utility subsidiaries’ commodity trading operations measure the outstanding risk exposure to price changes on contracts and obligations using an industry standard methodology known as VaR. VaR expresses the potential change in fair value of the outstanding contracts and obligations over a particular period of time under normal market conditions.
The VaRs for the NSP-Minnesota and PSCo commodity trading operations, excluding both non-derivative transactions and derivative transactions designated as normal purchases and normal sales, calculated on a consolidated basis using a Monte Carlo simulation with a 95% confidence level and a one-day holding period, were as follows:
| (Millions of Dollars) | Year Ended Dec. 31 | Average | High | Low | ||||||||||||||||||||||
| 2025 | $ | — | $ | — | $ | 1 | $ | — | ||||||||||||||||||
| 2024 | — | — | 1 | — | ||||||||||||||||||||||
Interest Rate Risk — Xcel Energy is subject to interest rate risk. Our risk management policy allows interest rate risk to be managed through the use of fixed rate debt, floating rate debt and interest rate derivatives.
A 100 basis point change in the benchmark rate on Xcel Energy’s variable rate debt would impact pretax interest expense annually by approximately $17 million and $7 million in 2025 and 2024, respectively.
NSP-Minnesota maintains a nuclear decommissioning fund, as required by the NRC. The nuclear decommissioning fund is subject to interest rate and equity price risk. The fund is invested in a diversified portfolio of debt securities, equity securities and other investments. These investments may be used only for the purpose of decommissioning NSP-Minnesota’s nuclear generating plants.
Fluctuations in equity prices or interest rates affecting the nuclear decommissioning fund do not have a direct impact on earnings due to the application of regulatory accounting. Realized and unrealized gains on the decommissioning fund investments are deferred as an offset of NSP-Minnesota’s regulatory asset for nuclear decommissioning costs.
The value of pension and postretirement plan assets and benefit costs are impacted by changes in discount rates and expected return on plan assets. Xcel Energy’s ongoing pension and postretirement investment strategy is based on plan-specific investment recommendations that seek to optimize potential investment risk and minimize interest rate risk associated with changes in the obligations as a plan’s funded status increases over time. The impacts of fluctuations in interest rates on pension and postretirement costs are mitigated by pension cost calculation methodologies and regulatory mechanisms that minimize the earnings impacts of such changes.
Credit Risk — Xcel Energy is also exposed to credit risk. Credit risk relates to the risk of loss resulting from counterparties’ nonperformance on their contractual obligations. Xcel Energy maintains credit policies intended to minimize overall credit risk and actively monitors these policies to reflect changes and scope of operations.
Credit exposure is monitored, and when necessary, the activity with a specific counterparty is limited until credit enhancement is provided. Distress in the financial markets could increase our credit risk.
Xcel Energy’s subsidiaries are subject to credit risk from contracts with generating equipment manufacturers and other suppliers that require deposits or milestone payments. In the event of non-performance by these counterparties, the Xcel Energy subsidiaries could experience credit losses, increased costs or project delays. Xcel Energy frequently seeks to mitigate this risk by requiring parent guarantees, letters of credit or other types of credit support.
Xcel Energy is also subject to credit risk for all wholesale, trading and non-trading commodity counterparties and employs credit risk controls, such as letters of credit, parental guarantees, master netting agreements and termination provisions.
At Dec. 31, 2025, a 10% increase or decrease in commodity prices would have resulted in an increase or decrease in credit exposure of $27 million. At Dec. 31, 2024, a 10% increase in commodity prices would have resulted in an increase in credit exposure of $26 million, while a decrease in prices of 10% would have resulted in an decrease in credit exposure of $25 million.
Fair Value Measurements
Derivative contracts, with the exception of those designated as normal purchases and normal sales, are reported at fair value. Xcel Energy’s investments held in the nuclear decommissioning fund, rabbi trusts, pension and other postretirement funds are also subject to fair value accounting. See Notes 10 and 11 to the consolidated financial statements for further information.
Liquidity and Capital Resources | ||
Cash Flows
Operating Cash Flows
| (Millions of Dollars) | Twelve Months Ended Dec. 31 | |||||||
| Cash provided by operating activities — 2024 | $ | 4,641 | ||||||
| Components of change — 2025 vs. 2024 | ||||||||
| Higher net income | 82 | |||||||
| Non-cash transactions | 121 | |||||||
| Changes in deferred taxes | 189 | |||||||
| Changes in working capital | (304) | |||||||
| Changes in net regulatory and other assets and liabilities | (646) | |||||||
| Cash provided by operating activities — 2025 | $ | 4,083 | ||||||
Net cash provided by operating activities decreased by $558 million for 2025 as compared to 2024. The decrease was largely due to the payment of the Marshall Wildfire settlement and timing of regulatory recovery, including deferred fuel costs.
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Investing Cash Flows
| (Millions of Dollars) | Twelve Months Ended Dec. 31 | |||||||
| Cash used in investing activities — 2024 | $ | (7,428) | ||||||
| Components of change — 2025 vs. 2024 | ||||||||
| Increased capital expenditures | (3,544) | |||||||
| Other investing activities | 3 | |||||||
| Cash used in investing activities — 2025 | $ | (10,969) | ||||||
Net cash used in investing activities increased by $3,541 million for 2025 as compared to 2024. 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) | Twelve Months Ended Dec. 31 | |||||||
| Cash provided by financing activities —2024 | $ | 2,837 | ||||||
| Components of change — 2025 vs. 2024 | ||||||||
| Higher long-term debt issuances, net of repayments | 1,059 | |||||||
| Higher net short-term debt proceeds | 945 | |||||||
| Higher proceeds from issuance of common stock | 2,232 | |||||||
| Other financing activities | (92) | |||||||
| Cash provided by financing activities — 2025 | $ | 6,981 | ||||||
Net cash provided by financing activities increased by $4,144 million for 2025 as compared to 2024. The increase was largely related to additional debt and common stock issuances to fund capital investment.
See Note 5 to the consolidated financial statements for further information.
Capital Requirements
Xcel Energy has contractual obligations and other commitments that will need to be funded in the future. Xcel Energy expects to have adequate amounts of cash from operating and financing activities to meet both its short-term and long-term cash requirements. Xcel Energy’s financing requirements are dependent on both existing contractual obligations and other commitments, as well as projected capital forecasts. 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. Projected future financing requirements can be impacted by various factors including constraints to supply chain and labor, regulatory lag and inflation.
Material Cash Requirements and Other Commitments
| Payments Due by Period (as of Dec. 31, 2025) | ||||||||||||||||||||||||||||||||
| (Millions of Dollars) | Total | Less than 1 Year | 1 to 3 Years | 3 to 5 Years | After 5 Years | |||||||||||||||||||||||||||
| Long-term debt, principal and interest payments | $ | 57,743 | $ | 1,937 | $ | 4,766 | $ | 3,793 | $ | 47,247 | ||||||||||||||||||||||
| Finance lease obligations | 2,183 | 112 | 225 | 232 | 1,614 | |||||||||||||||||||||||||||
Operating leases obligations (a) | 1,259 | 152 | 250 | 226 | 631 | |||||||||||||||||||||||||||
Unconditional purchase obligations (b) | 4,264 | 1,264 | 1,097 | 520 | 1,383 | |||||||||||||||||||||||||||
| Short-term debt | 1,550 | 1,550 | — | — | — | |||||||||||||||||||||||||||
| Other | 587 | 574 | 13 | — | — | |||||||||||||||||||||||||||
| Total contractual cash obligations | $ | 67,586 | $ | 5,589 | $ | 6,351 | $ | 4,771 | $ | 50,875 | ||||||||||||||||||||||
(a)Included in operating lease obligations are $121 million, $170 million, $156 million and $185 million, for the less than 1 year, 1 - 3 years, 3 - 5 years and after 5 years categories, respectively, pertaining to PPAs that are accounted for as operating leases.
(b)Xcel Energy Inc. and its subsidiaries have contracts providing for the purchase and delivery of a significant portion of its fuel (nuclear, natural gas and coal) requirements. Additionally, the utility subsidiaries of Xcel Energy Inc. have entered into non-lease purchase power agreements. Certain contractual purchase obligations are adjusted on indices. Effects of price changes are mitigated through cost of energy adjustment mechanisms.
Capital Expenditures — Base capital expenditures for Xcel Energy for 2026 through 2030:
| Actual | Base Capital Forecast (Millions of Dollars) | |||||||||||||||||||||||||||||||||||||||||||
| By Regulated Utility | 2025 | 2026 | 2027 | 2028 | 2029 | 2030 | 2026 - 2030 Total | |||||||||||||||||||||||||||||||||||||
| NSP-Minnesota | $ | 3,380 | $ | 3,740 | $ | 4,870 | $ | 4,210 | $ | 3,660 | $ | 3,650 | $ | 20,130 | ||||||||||||||||||||||||||||||
| SPS | 1,610 | 3,050 | 5,120 | 5,350 | 3,240 | 2,270 | 19,030 | |||||||||||||||||||||||||||||||||||||
| PSCo | 5,440 | 5,980 | 3,940 | 2,960 | 1,760 | 2,960 | 17,600 | |||||||||||||||||||||||||||||||||||||
| NSP-Wisconsin | 710 | 910 | 1,210 | 760 | 570 | 580 | 4,030 | |||||||||||||||||||||||||||||||||||||
Other (a) | 470 | 110 | (10) | (630) | (210) | (50) | (790) | |||||||||||||||||||||||||||||||||||||
| Total base capital expenditures | $ | 11,610 | $ | 13,790 | $ | 15,130 | $ | 12,650 | $ | 9,020 | $ | 9,410 | $ | 60,000 | ||||||||||||||||||||||||||||||
(a)Other category includes intercompany transfers for equipment with long lead times.
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| Actual | Base Capital Forecast (Millions of Dollars) | |||||||||||||||||||||||||||||||||||||||||||
| By Function | 2025 | 2026 | 2027 | 2028 | 2029 | 2030 | 2026 - 2030 Total | |||||||||||||||||||||||||||||||||||||
| Electric transmission | $ | 2,250 | $ | 3,060 | $ | 2,930 | $ | 2,890 | $ | 3,190 | $ | 3,370 | $ | 15,440 | ||||||||||||||||||||||||||||||
| Renewables | 3,190 | 3,560 | 4,620 | 3,380 | 1,150 | 1,210 | 13,920 | |||||||||||||||||||||||||||||||||||||
| Electric distribution | 2,690 | 2,920 | 3,250 | 2,930 | 1,680 | 2,930 | 13,710 | |||||||||||||||||||||||||||||||||||||
| Electric generation | 1,250 | 2,220 | 2,420 | 2,500 | 1,810 | 590 | 9,540 | |||||||||||||||||||||||||||||||||||||
| Natural gas | 740 | 860 | 830 | 700 | 650 | 680 | 3,720 | |||||||||||||||||||||||||||||||||||||
| Other | 1,490 | 1,170 | 1,080 | 250 | 540 | 630 | 3,670 | |||||||||||||||||||||||||||||||||||||
| Total base capital expenditures | $ | 11,610 | $ | 13,790 | $ | 15,130 | $ | 12,650 | $ | 9,020 | $ | 9,410 | $ | 60,000 | ||||||||||||||||||||||||||||||
The plan does not include any potential incremental generation from the current Colorado Near-Term Procurement and Resource Plan, additional future generation RFPs across jurisdictions to fund growth, or additional transmission investments that may come from future planning processes including MISO and SPP. Xcel Energy expects to fund additional capital investment with approximately 40% equity and 60% debt.
Xcel Energy’s capital expenditure forecast is subject to continuing review and modification. Actual capital expenditures may vary from estimates due to changes in electric and natural gas projected load growth, safety and reliability needs, regulatory decisions, legislative initiatives, tax policy, reserve requirements, availability of purchased power, alternative plans for meeting long-term energy needs, environmental initiatives and regulation, and merger, acquisition and divestiture opportunities.
Financing for Capital Expenditures through 2030 — Xcel Energy issues debt and equity securities to refinance retiring debt maturities, reduce short-term debt, fund capital programs, infuse equity in subsidiaries, fund asset acquisitions and for general corporate purposes.
Current estimated financing plans of Xcel Energy for 2026 through 2030 (includes the impact of tax credit transferability):
| (Millions of Dollars) | ||||||||
| Funding Capital Expenditures | ||||||||
Cash from operations (a) | $ | 30,180 | ||||||
New debt (b) | 22,820 | |||||||
Equity issuances (c) | 7,000 | |||||||
| Base capital expenditures 2026 - 2030 | $ | 60,000 | ||||||
| Maturing debt | $ | 3,580 | ||||||
(a)Net of dividends and pension funding.
(b)Reflects a combination of short and long-term debt; net of refinancing.
(c)Amount could include other financing instruments that receive equity credit from the credit rating agencies.
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.
Common Stock Dividends — Future dividend levels will be dependent on Xcel Energy’s results of operations, financial condition, cash flows, reinvestment opportunities and other factors, and will be evaluated by the Xcel Energy Inc. Board of Directors. In February 2026, Xcel Energy announced an increase in the annual dividend of 9 cents per share, which represents an increase of 4.0%.
Xcel Energy’s dividend policy balances the following:
•Projected cash generation.
•Projected capital investment.
•A reasonable rate of return on shareholder investment.
•The impact on Xcel Energy’s capital structure and credit ratings.
In addition, there are certain statutory limitations that could affect dividend levels. Federal law places limits on the ability of public utilities within a holding company to declare dividends. Under the Federal Power Act, a public utility may not pay dividends from any funds properly included in a capital account. The utility subsidiaries’ dividends may be limited directly or indirectly by state regulatory commissions or bond indenture covenants.
See Note 5 to the consolidated financial statements for further information.
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.
Funded status and pension assumptions:
| (Millions of Dollars) | Dec. 31, 2025 | Dec. 31, 2024 | ||||||||||||
| Fair value of pension assets | $ | 2,690 | $ | 2,504 | ||||||||||
Projected pension obligation (a) | 2,820 | 2,752 | ||||||||||||
| Funded status | $ | (130) | $ | (248) | ||||||||||
(a)Excludes non-qualified plan of $13 million at both Dec. 31, 2025 and 2024.
| Pension Assumptions | 2025 | 2024 | ||||||||||||
| Discount rate for year-end valuation | 5.78 | % | 5.88 | % | ||||||||||
| Expected long-term rate of return | 7.13 | 7.13 | ||||||||||||
Capital Sources
Short-Term Funding Sources — Xcel Energy generally funds short-term needs, through operating cash flows, notes payable, commercial paper and bank lines of credit. The amount and timing of short-term funding needs depend on construction expenditures, working capital and dividend payments.
Short-Term Investments — Xcel Energy Inc., NSP-Minnesota, NSP-Wisconsin, PSCo and SPS maintain cash and short-term investment accounts.
Short-Term Debt — Xcel Energy Inc., NSP-Minnesota, NSP-Wisconsin, PSCo and SPS each have individual commercial paper programs. Authorized levels for these commercial paper programs are:
•$2 billion for Xcel Energy Inc.
•$1.2 billion for PSCo.
•$800 million for NSP-Minnesota.
•$600 million for SPS.
•$150 million for NSP-Wisconsin.
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See Note 5 to the consolidated financial statements for further information.
Credit Facility Agreements — As of Feb. 23, 2026, Xcel Energy Inc. and its utility subsidiaries had the following committed credit facilities available to meet liquidity needs:
| (Millions of Dollars) | Facility (a) | Drawn (b) | Available | Cash | Liquidity | |||||||||||||||||||||||||||
| Xcel Energy Inc. | $ | 2,000 | $ | 790 | $ | 1,210 | $ | 21 | $ | 1,231 | ||||||||||||||||||||||
| PSCo | 1,200 | 308 | 892 | 9 | 901 | |||||||||||||||||||||||||||
| NSP-Minnesota | 800 | 329 | 471 | 3 | 474 | |||||||||||||||||||||||||||
| SPS | 600 | 213 | 387 | 11 | 398 | |||||||||||||||||||||||||||
| NSP-Wisconsin | 150 | — | 150 | 2 | 152 | |||||||||||||||||||||||||||
| Total | $ | 4,750 | $ | 1,640 | $ | 3,110 | $ | 46 | $ | 3,156 | ||||||||||||||||||||||
Term Loan (c) | 1,500 | 750 | 750 | — | 750 | |||||||||||||||||||||||||||
(a)Credit facilities expire in December 2029.
(b)Includes outstanding commercial paper and letters of credit.
(c)Xcel Energy Inc.’s $1.5 billion term loan (entered into in January 2026) matures in January 2027.
Xcel Energy Inc., NSP-Minnesota, PSCo and SPS each have the right to request an extension of the revolving credit facility for two additional one-year periods. NSP-Wisconsin has the right to request an extension of the revolving credit facility for an additional year. All extension requests are subject to majority bank group approval.
Registration Statements — Xcel Energy Inc.’s Articles of Incorporation authorize the issuance of one billion shares of $2.50 par value common stock. As of Dec. 31, 2025 and 2024, Xcel Energy had approximately 624 million shares and 574 million shares of common stock outstanding, respectively.
Xcel Energy Inc. and its utility subsidiaries have registration statements on file with the SEC which are uncapped, permitting Xcel Energy Inc. and its utility subsidiaries to issue debt, equity and other securities. Debt issuance at our utility subsidiaries are subject to commission approval.
Planned Financing Activity — Xcel Energy’s 2026 financing plans reflect the following:
| Issuer | Security | Amount (Millions of Dollars) | ||||||||||||
| Xcel Energy Inc. | Senior Unsecured Notes | $ | 1,000 | |||||||||||
| PSCo | First Mortgage Bonds | 2,400 | ||||||||||||
| NSP-Minnesota | First Mortgage Bonds | 1,000 | ||||||||||||
| SPS | First Mortgage Bonds | 1,000 | ||||||||||||
| NSP-Wisconsin | First Mortgage Bonds | 250 | ||||||||||||
In addition, Xcel Energy plans to issue incremental equity throughout 2026 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.
In January 2026, Xcel Energy Inc. entered into a $1.5 billion, 364-Day Delayed Draw Term Loan Agreement and borrowed $750 million under the term loan facility.
See Note 5 to the consolidated financial statements for further information.
Earnings Guidance and Long-Term EPS and Dividend Growth Rate Objectives
Xcel Energy 2026 Earnings Guidance — Xcel Energy’s 2026 ongoing earnings guidance is a range of $4.04 to $4.16 per share. (a)
Key assumptions as compared with 2025 actual levels unless noted:
•Constructive outcomes in all pending rate case and regulatory proceedings.
•Normal weather patterns for the 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 $535 million to $545 million.
•O&M expenses are projected to increase ~3%.
•Depreciation expense is projected to increase approximately $350 million to $360 million.
•Property taxes are projected to increase $30 million to $40 million.
•Interest expense (net of AFUDC - debt) is projected to increase $300 million to $310 million, net of interest income.
•AFUDC - equity is projected to increase $140 million to $150 million.
(a)Ongoing earnings is calculated using net income and adjusting for certain nonrecurring or infrequent items that are, in management’s view, not reflective of ongoing operations. Ongoing earnings could differ from those prepared in accordance with GAAP for unplanned and/or unknown adjustments. As Xcel Energy is unable to quantify the financial impacts of any additional adjustments that may occur for the year, we are unable to provide a quantitative reconciliation of the guidance for ongoing EPS to corresponding GAAP EPS.
Long-Term EPS and Dividend Growth Rate Objectives — Xcel Energy expects to deliver an attractive total return to our shareholders through a combination of earnings growth and dividend yield, based on the following long-term objectives:
• Deliver long-term annual EPS growth of 6% to 8+% based off of $3.80 per share.
• Deliver annual dividend increases of 4% to 6%.
• Target a dividend payout ratio of 45% to 55%.
• Maintain senior secured debt credit ratings in the A range.
ITEM 7A — QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK | ||
See the “Derivatives, Risk Management and Market Risk” section in Item 7, incorporated by reference.
ITEM 8 — FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA | ||
See Item 15-1 for an index of financial statements included herein.
See Note 15 to the consolidated financial statements for further information.
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Management Report on Internal Control Over Financial Reporting
The management of Xcel Energy Inc. is responsible for establishing and maintaining adequate internal control over financial reporting. Xcel Energy Inc.’s internal control system was designed to provide reasonable assurance to Xcel Energy Inc.’s management and Board of Directors regarding the preparation and fair presentation of published financial statements.
All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation.
Xcel Energy Inc. management assessed the effectiveness of Xcel Energy Inc.’s internal control over financial reporting as of Dec. 31, 2025. In making this assessment, it used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control — Integrated Framework (2013). Based on our assessment, we believe that, as of Dec. 31, 2025, Xcel Energy Inc.’s internal control over financial reporting is effective at the reasonable assurance level based on those criteria.
Xcel Energy Inc.’s independent registered public accounting firm has issued an attestation report on Xcel Energy Inc.’s internal control over financial reporting. Its report appears herein.
| /s/ ROBERT C. FRENZEL | /s/ BRIAN J. VAN ABEL | |||||||||||||
| Robert C. Frenzel | Brian J. Van Abel | |||||||||||||
| Chairman, President, Chief Executive Officer and Director | Executive Vice President, Chief Financial Officer | |||||||||||||
| Feb. 25, 2026 | Feb. 25, 2026 | |||||||||||||
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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the stockholders and the Board of Directors of Xcel Energy Inc.
Opinions on the Financial Statements and Internal Control over Financial Reporting
We have audited the accompanying consolidated balance sheets of Xcel Energy Inc. and subsidiaries (the "Company") as of December 31, 2025 and 2024, the related consolidated statements of income, comprehensive income, common stockholders' equity, and cash flows, for each of the three years in the period ended December 31, 2025, and the related notes and the schedules listed in the Index at Item 15 (collectively referred to as the "financial statements"). We also have audited the Company’s internal control over financial reporting as of December 31, 2025, based on criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2025 and 2024, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2025, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2025, based on criteria established in Internal Control — Integrated Framework (2013) issued by COSO.
Basis for Opinions
The Company’s management is responsible for these financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management Report on Internal Controls over Financial Reporting. Our responsibility is to express an opinion on these financial statements and an opinion on the Company’s internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects.
Our audits of the financial statements included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures to respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
Definition and Limitations of Internal Control over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Critical Audit Matter
The critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that was communicated or required to be communicated to the audit committee and that (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
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Regulatory Assets and Liabilities - Impact of Rate Regulation on the Financial Statements — Refer to Notes 4 and 12 to the consolidated financial statements.
Critical Audit Matter Description
The Company is subject to rate regulation by state utility regulatory agencies, which have jurisdiction with respect to the rates of electric and natural gas distribution companies in Minnesota, North Dakota, South Dakota, Wisconsin, Michigan, Colorado, New Mexico, and Texas. The Company is also subject to the jurisdiction of the Federal Energy Regulatory Commission for its wholesale electric operations, hydroelectric generation licensing, accounting practices, wholesale sales for resale, transmission of electricity in interstate commerce, compliance with North American Electric Reliability Corporation standards, asset transactions and mergers and natural gas transactions in interstate commerce, (collectively with state utility regulatory agencies, the “Commissions”). Management has determined it meets the requirements under accounting principles generally accepted in the United States of America to prepare its financial statements applying the specialized rules to account for the effects of cost-based rate regulation. Accounting for the economics of rate regulation affects multiple financial statement line items and disclosures, including property, plant and equipment, regulatory assets and liabilities, operating revenues and expenses, and income taxes.
The Company is subject to regulatory rate setting processes. Rates are determined and approved in regulatory proceedings based on an analysis of the Company’s costs to provide utility service and a return on, and recovery of, the Company’s investment in assets required to deliver services to customers. Accounting for the Company’s regulated operations provides that rate-regulated entities report assets and liabilities consistent with the recovery of those incurred costs in rates, if it is probable that such rates will be charged and collected. The Commissions’ regulation of rates is premised on the full recovery of incurred costs and a reasonable rate of return on invested capital. Decisions by the Commissions in the future will impact the accounting for regulated operations, including decisions about the amount of allowable costs and return on invested capital included in rates and any refunds that may be required. In the rate setting process, the Company’s rates result in the recording of regulatory assets and liabilities based on the probability of future cash flows. Regulatory assets generally represent incurred or accrued costs that have been deferred because future recovery from customers is probable. Regulatory liabilities generally represent amounts that are expected to be refunded to customers in future rates or amounts collected in current rates for future costs.
We identified the impact of rate regulation as a critical audit matter due to the significant judgments made by management to support its assertions about impacted account balances and disclosures and the high degree of subjectivity involved in assessing the impact of future regulatory orders on the financial statements. Management judgments include assessing the likelihood of recovery in future rates of incurred costs and requirements to refund amounts to customers. Given that management’s accounting judgments are based on assumptions about the outcome of future decisions by the Commissions, auditing these judgments required specialized knowledge of accounting for rate regulation and the rate setting process due to its inherent complexities.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the uncertainty of future decisions by the Commissions included the following, among others:
•We tested the effectiveness of management’s controls over the evaluation of the likelihood of (1) the recovery in future rates of costs deferred as regulatory assets, and (2) a refund or a future reduction in rates that should be reported as regulatory liabilities. We also tested the effectiveness of management’s controls over the recognition of regulatory assets or liabilities and the monitoring and evaluation of regulatory developments that may affect the likelihood of recovering costs in future rates or of a future reduction in rates.
•We evaluated the Company’s disclosures related to the impacts of rate regulation, including the balances recorded and regulatory developments.
•We read relevant regulatory orders issued by the Commissions for the Company, other regulatory filings, legal decisions and recommendations being evaluated by the Commissions, and other publicly available information to assess the likelihood of recovery in future rates or of a future reduction in rates. We evaluated historic orders for precedents of the Commissions’ treatment of similar costs under similar circumstances. We compared the regulatory orders, filings and other publicly available information to the Company’s recorded regulatory assets and liabilities for completeness.
•We obtained management’s analysis and correspondence from counsel, as appropriate, regarding regulatory assets or liabilities not yet addressed in a regulatory order to assess management’s assertion that amounts are probable of recovery or a future reduction in rates.
/s/ | ||
| February 25, 2026 | ||
| We have served as the Company’s auditor since 2002. | ||
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XCEL ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(amounts in millions, except per share data)
| Year Ended Dec. 31 | ||||||||||||||||||||
| 2025 | 2024 | 2023 | ||||||||||||||||||
| Operating revenues | ||||||||||||||||||||
| Electric | $ | $ | $ | |||||||||||||||||
| Natural gas | ||||||||||||||||||||
| Other | ||||||||||||||||||||
| Total operating revenues | ||||||||||||||||||||
| Operating expenses | ||||||||||||||||||||
| Electric fuel and purchased power | ||||||||||||||||||||
| Cost of natural gas sold and transported | ||||||||||||||||||||
| Cost of sales — other | ||||||||||||||||||||
| Operating and maintenance expenses | ||||||||||||||||||||
| Conservation and demand side management expenses | ||||||||||||||||||||
| Depreciation and amortization | ||||||||||||||||||||
| Taxes (other than income taxes) | ||||||||||||||||||||
| Marshall Wildfire litigation | ||||||||||||||||||||
| Loss on Comanche Unit 3 litigation | ||||||||||||||||||||
| Workforce reduction expenses | ||||||||||||||||||||
| Total operating expenses | ||||||||||||||||||||
| Operating income | ||||||||||||||||||||
| Other income, net | ||||||||||||||||||||
| Earnings from equity method investments | ||||||||||||||||||||
| Allowance for funds used during construction — equity | ||||||||||||||||||||
| Interest charges and financing costs | ||||||||||||||||||||
| Interest charges — includes other financing costs | ||||||||||||||||||||
| Allowance for funds used during construction — debt | ( | ( | ( | |||||||||||||||||
| Total interest charges and financing costs | ||||||||||||||||||||
| Income before income taxes | ||||||||||||||||||||
| Income tax benefit | ( | ( | ( | |||||||||||||||||
| Net income | $ | $ | $ | |||||||||||||||||
| Weighted average common shares outstanding: | ||||||||||||||||||||
| Basic | ||||||||||||||||||||
| Diluted | ||||||||||||||||||||
| Earnings per average common share: | ||||||||||||||||||||
| Basic | $ | $ | $ | |||||||||||||||||
| Diluted | ||||||||||||||||||||
| See Notes to Consolidated Financial Statements | ||||||||||||||||||||
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XCEL ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(amounts in millions)
| Year Ended Dec. 31 | ||||||||||||||||||||
| 2025 | 2024 | 2023 | ||||||||||||||||||
| Net income | $ | $ | $ | |||||||||||||||||
| Other comprehensive income | ||||||||||||||||||||
| Pension and retiree medical benefits: | ||||||||||||||||||||
| Net pension and retiree medical losses arising during the period, net of tax | ( | ( | ( | |||||||||||||||||
| Reclassification of losses to net income, net of tax | ||||||||||||||||||||
| Derivative instruments: | ||||||||||||||||||||
| Net fair value increase (decrease), net of tax | ( | |||||||||||||||||||
| Reclassification of losses to net income, net of tax | ||||||||||||||||||||
| Total other comprehensive income (loss) | ( | |||||||||||||||||||
| Total comprehensive income | $ | $ | $ | |||||||||||||||||
| See Notes to Consolidated Financial Statements | ||||||||||||||||||||
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XCEL ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(amounts in millions)
| Year Ended Dec. 31 | |||||||||||||||||
| 2025 | 2024 | 2023 | |||||||||||||||
| Operating activities | |||||||||||||||||
| Net income | $ | $ | $ | ||||||||||||||
| Adjustments to reconcile net income to cash provided by operating activities: | |||||||||||||||||
| Depreciation and amortization | |||||||||||||||||
| Nuclear fuel amortization | |||||||||||||||||
| Deferred income taxes | ( | ||||||||||||||||
| Allowance for equity funds used during construction | ( | ( | ( | ||||||||||||||
| Earnings from equity method investments | ( | ( | ( | ||||||||||||||
| Dividends from equity method investments | |||||||||||||||||
| Provision for bad debts | |||||||||||||||||
| Share-based compensation expense | |||||||||||||||||
| Changes in operating assets and liabilities: | |||||||||||||||||
| Accounts receivable | ( | ( | |||||||||||||||
| Accrued unbilled revenues | ( | ||||||||||||||||
| Inventories | ( | ( | ( | ||||||||||||||
| Other current assets | ( | ( | |||||||||||||||
| Accounts payable | ( | ( | |||||||||||||||
| Net regulatory assets and liabilities | ( | ||||||||||||||||
| Other current liabilities | ( | ( | |||||||||||||||
| Pension and other employee benefit obligations | ( | ( | |||||||||||||||
| Other, net | ( | ( | ( | ||||||||||||||
| Net cash provided by operating activities | |||||||||||||||||
| Investing activities | |||||||||||||||||
| Capital/construction expenditures | ( | ( | ( | ||||||||||||||
| Purchase of investment securities | ( | ( | ( | ||||||||||||||
| Proceeds from the sale of investment securities | |||||||||||||||||
| Other, net | ( | ( | ( | ||||||||||||||
| Net cash used in investing activities | ( | ( | ( | ||||||||||||||
| Financing activities | |||||||||||||||||
| Proceeds (repayments) of short-term borrowings, net | ( | ( | |||||||||||||||
| Proceeds from issuances of long-term debt | |||||||||||||||||
| Repayments of long-term debt | ( | ( | ( | ||||||||||||||
| Proceeds from issuance of common stock | |||||||||||||||||
| Dividends paid | ( | ( | ( | ||||||||||||||
| Other, net | ( | ( | |||||||||||||||
| Net cash provided by financing activities | |||||||||||||||||
| Net change in cash and cash equivalents | |||||||||||||||||
| Cash, cash equivalents and restricted cash at beginning of period | |||||||||||||||||
| Cash, cash equivalents and restricted cash at end of period | $ | $ | $ | ||||||||||||||
| Supplemental disclosure of cash flow information: | |||||||||||||||||
| Cash paid for interest (net of amounts capitalized) | $ | ( | $ | ( | $ | ( | |||||||||||
| Supplemental disclosure of non-cash investing and financing transactions: | |||||||||||||||||
| Accrued property, plant and equipment additions | $ | $ | $ | ||||||||||||||
| Inventory transfers to property, plant and equipment | |||||||||||||||||
| Operating and finance lease right-of-use assets | |||||||||||||||||
| Allowance for equity funds used during construction | |||||||||||||||||
| Issuance of common stock for reinvested dividends and/or equity awards | |||||||||||||||||
| See Notes to Consolidated Financial Statements | |||||||||||||||||
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XCEL ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(amounts in millions, except share and per share)
| Dec. 31 | ||||||||||||||
| 2025 | 2024 | |||||||||||||
| Assets | ||||||||||||||
| Current assets | ||||||||||||||
| Cash and cash equivalents | $ | $ | ||||||||||||
| Accounts receivable, net | ||||||||||||||
| Accrued unbilled revenues | ||||||||||||||
| Inventories | ||||||||||||||
| Regulatory assets | ||||||||||||||
| Derivative instruments | ||||||||||||||
| Prepayments and other | ||||||||||||||
| Total current assets | ||||||||||||||
| Property, plant and equipment, net | ||||||||||||||
| Other assets | ||||||||||||||
| Nuclear decommissioning fund and other investments | ||||||||||||||
| Regulatory assets | ||||||||||||||
| Derivative instruments | ||||||||||||||
| Operating lease right-of-use assets | ||||||||||||||
| Finance lease right-of-use assets | ||||||||||||||
| Other | ||||||||||||||
| Total other assets | ||||||||||||||
| Total assets | $ | $ | ||||||||||||
| Liabilities and Equity | ||||||||||||||
| Current liabilities | ||||||||||||||
| Current portion of long-term debt | $ | $ | ||||||||||||
| Short-term debt | ||||||||||||||
| Accounts payable | ||||||||||||||
| Regulatory liabilities | ||||||||||||||
| Taxes accrued | ||||||||||||||
| Accrued interest | ||||||||||||||
| Dividends payable | ||||||||||||||
| Derivative instruments | ||||||||||||||
| Operating lease liabilities | ||||||||||||||
| Other | ||||||||||||||
| Total current liabilities | ||||||||||||||
| Deferred credits and other liabilities | ||||||||||||||
| Deferred income taxes | ||||||||||||||
| Regulatory liabilities | ||||||||||||||
| Asset retirement obligations | ||||||||||||||
| Derivative instruments | ||||||||||||||
| Customer advances | ||||||||||||||
| Pension and employee benefit obligations | ||||||||||||||
| Operating lease liabilities | ||||||||||||||
| Finance lease liabilities | ||||||||||||||
| Other | ||||||||||||||
| Total deferred credits and other liabilities | ||||||||||||||
| Commitments and contingencies | ||||||||||||||
| Long-term debt | ||||||||||||||
Common stock — | ||||||||||||||
| Additional paid in capital | ||||||||||||||
| Retained earnings | ||||||||||||||
| Accumulated other comprehensive loss | ( | ( | ||||||||||||
| Total common stockholders’ equity | ||||||||||||||
| Total liabilities and equity | $ | $ | ||||||||||||
| See Notes to Consolidated Financial Statements | ||||||||||||||
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XCEL ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS’ EQUITY
(amounts in millions, except per share data; shares in actual amounts)
| Common Stock Issued | Retained Earnings | Accumulated Other Comprehensive Loss | Total Common Stockholders’ Equity | ||||||||||||||||||||||||||||||||
| Shares | Par Value | Additional Paid In Capital | |||||||||||||||||||||||||||||||||
| Balance at Dec. 31, 2022 | $ | $ | $ | $ | ( | $ | |||||||||||||||||||||||||||||
| Net income | |||||||||||||||||||||||||||||||||||
| Other comprehensive loss | ( | ( | |||||||||||||||||||||||||||||||||
Dividends declared on common stock ($ | ( | ( | |||||||||||||||||||||||||||||||||
| Issuances of common stock | |||||||||||||||||||||||||||||||||||
| Share-based compensation | ( | ||||||||||||||||||||||||||||||||||
| Balance at Dec. 31, 2023 | $ | $ | $ | $ | ( | $ | |||||||||||||||||||||||||||||
| Net Income | |||||||||||||||||||||||||||||||||||
| Other comprehensive income | |||||||||||||||||||||||||||||||||||
Dividends declared on common stock ($ | ( | ( | |||||||||||||||||||||||||||||||||
| Issuances of common stock | |||||||||||||||||||||||||||||||||||
| Share-based compensation | ( | ||||||||||||||||||||||||||||||||||
| Balance at Dec. 31, 2024 | $ | $ | $ | $ | ( | $ | |||||||||||||||||||||||||||||
| Net income | |||||||||||||||||||||||||||||||||||
| Other comprehensive income | |||||||||||||||||||||||||||||||||||
Dividends declared on common stock ($ | ( | ( | |||||||||||||||||||||||||||||||||
| Issuances of common stock | |||||||||||||||||||||||||||||||||||
| Share-based compensation | ( | ||||||||||||||||||||||||||||||||||
| Balance at Dec. 31, 2025 | $ | $ | $ | $ | ( | $ | |||||||||||||||||||||||||||||
| See Notes to Consolidated Financial Statements | |||||||||||||||||||||||||||||||||||
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XCEL ENERGY INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements
1. Summary of Significant Accounting Policies | ||
General — Xcel Energy Inc.’s utility subsidiaries are engaged in the regulated generation, purchase, transmission, distribution and sale of electricity and the regulated purchase, transportation, distribution and sale of natural gas.
Xcel Energy’s regulated operations include the activities of NSP-Minnesota, NSP-Wisconsin, PSCo and SPS. These utility subsidiaries serve electric and natural gas customers in portions of Colorado, Michigan, Minnesota, New Mexico, North Dakota, South Dakota, Texas and Wisconsin. Also included in regulated operations are WGI, an interstate natural gas pipeline company, and WYCO, a joint venture with CIG to develop and lease natural gas pipeline and storage facilities.
Xcel Energy Inc.’s nonregulated subsidiaries include:
| Nonregulated Subsidiary | Purpose | |||||||
| Eloigne | Invests in rental housing projects that qualify for low-income housing tax credits. | |||||||
| Capital Services | Procures equipment for Xcel Energy subsidiaries for construction of generation facilities and for other items with long lead times. | |||||||
| Xcel Energy Venture Holdings, Inc. | Invests in limited partnerships, including funds with portfolios of investments in energy technology companies. | |||||||
| Nicollet Project Holdings | Invests in nonregulated assets such as the Minnesota community solar gardens. | |||||||
Xcel Energy Inc. owns the following additional direct subsidiaries, some of which are intermediate holding companies with additional subsidiaries:
| Direct Subsidiary | ||
| Xcel Energy Wholesale Group Inc. | ||
| Xcel Energy Markets Holdings Inc. | ||
| Xcel Energy Ventures Inc. | ||
| Xcel Energy Retail Holdings Inc. | ||
| Xcel Energy Communication Group Inc. | ||
| Xcel Energy International Inc. | ||
| Xcel Energy Transmission Holding Company, LLC | ||
| Nicollet Holdings Company, LLC | ||
| Xcel Energy Nuclear Services Holdings, LLC | ||
| Xcel Energy Services Inc. | ||
Xcel Energy and its subsidiaries collectively are referred to as Xcel Energy.
Xcel Energy’s consolidated financial statements include its wholly-owned subsidiaries and VIEs for which it is the primary beneficiary. All intercompany transactions and balances are eliminated unless a different treatment is appropriate for rate regulated transactions. The equity method of accounting is used for investments in energy technology funds and WYCO.
Investments in certain plants and transmission facilities are jointly owned with nonaffiliated utilities. A proportionate share of jointly owned facilities is recorded as property, plant and equipment on the consolidated balance sheets, and Xcel Energy’s share of depreciation and other operating costs associated with these facilities is included in the consolidated statements of income.
The consolidated financial statements are presented in accordance with GAAP. All of the utility subsidiaries’ underlying accounting records also conform to the FERC uniform system of accounts.
Certain amounts in the consolidated financial statements or notes have been reclassified for comparative purposes; however, such reclassifications did not affect net income, total assets, liabilities, equity or cash flows.
Xcel Energy has evaluated events occurring after Dec. 31, 2025 up to the date of issuance of these consolidated financial statements. These statements contain all necessary adjustments and disclosures resulting from that evaluation.
Use of Estimates — Xcel Energy uses estimates based on the best information available to record transactions and balances resulting from business operations.
Estimates are used for items such as plant depreciable lives or potential disallowances, AROs, certain regulatory assets and liabilities, tax provisions, uncollectible amounts, environmental costs, unbilled revenues, jurisdictional fuel and energy cost allocations, actuarially determined benefit costs and wildfire contingencies. Recorded estimates are revised when better information becomes available or actual amounts can be determined. Revisions can affect operating results.
Regulatory Accounting — The regulated utility subsidiaries account for income and expense items in accordance with accounting guidance for regulated operations. Under this guidance:
•Certain costs, which would otherwise be charged to expense or other comprehensive income, are deferred as regulatory assets based on the expected ability to recover the costs in future rates.
•Certain credits, which would otherwise be reflected as income or other comprehensive income, are deferred as regulatory liabilities based on the expectation the amounts will be returned to customers in future rates, or because the amounts were collected in rates prior to the costs being incurred.
Estimates and assumptions for recovery of deferred costs and refund of deferred credits are based on specific ratemaking decisions, precedent or other available information. Regulatory assets and liabilities are reversed or amortized consistent with the treatment in the rate setting process.
If changes in the regulatory environment occur, the utility subsidiaries may no longer be eligible to apply this accounting treatment and may be required to eliminate regulatory assets and liabilities. Such changes could have a material effect on Xcel Energy’s results of operations, financial condition and cash flows.
See Note 4 for further information.
Income Taxes — Xcel Energy accounts for income taxes using the asset and liability method, which requires recognition of deferred tax assets and liabilities for the expected future tax consequences of events that have been included in the consolidated financial statements. Income taxes are deferred for all temporary differences between pretax financial and taxable income and between the book and tax bases of assets and liabilities utilizing rates that are scheduled to be in effect when the temporary differences are expected to reverse. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in the period that includes the enactment date.
Utility rate regulation has resulted in the recognition of regulatory assets and liabilities related to income taxes. The effects of tax rate changes that are attributable to the utility subsidiaries are generally subject to a normalization method of accounting. Therefore, the revaluation of most of the utility subsidiaries’ net deferred taxes upon a tax rate reduction results in the establishment of a net regulatory liability, refundable to utility customers over the remaining life of the related assets.
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Xcel Energy anticipates that a tax rate increase would predominantly result in the establishment of a regulatory asset, subject to an evaluation of whether future recovery is expected.
Reversal of certain temporary differences are accounted for as current income tax expense due to the effects of past regulatory practices when deferred taxes were not required to be recorded due to the use of flow through accounting for ratemaking purposes.
Tax credits are recorded when earned unless there is a requirement to defer the benefit and amortize over the book depreciable lives of related property, as determined by tax regulations and Xcel Energy tax elections. For tax credits eligible to be recognized when earned, Xcel Energy considers the impact of rate regulation to determine if these credits and related adjustments should be deferred as regulatory assets or liabilities.
Deferred tax assets are reduced by a valuation allowance if it is more likely than not that some portion or all of the deferred tax asset will not be realized. This evaluation includes consideration of whether tax credits are expected to be sold at a discount and impact the realization of amounts presented as deferred tax assets. Transferable tax credits are accounted for under ASC 740, Income Taxes, and valuation allowances and any adjustments for discounts incurred on sales transactions are recorded to deferred tax expense, typically recovered in the utility subsidiaries’ regulatory mechanisms.
Xcel Energy measures and discloses uncertain tax positions that it has taken or expects to take in its income tax returns. A tax position is recognized in the consolidated financial statements when it is more likely than not that the position will be sustained upon examination based on the technical merits of the position. Recognition of changes in uncertain tax positions are reflected as a component of income tax expense.
Interest and penalties related to income taxes are reported within other income, net or interest charges in the consolidated statements of income.
Xcel Energy Inc. and its subsidiaries file consolidated federal income tax returns as well as consolidated or separate state income tax returns. Federal income taxes paid by Xcel Energy Inc. are allocated to its subsidiaries based on separate company computations. A similar allocation is made for state income taxes paid by Xcel Energy Inc. in connection with consolidated state filings. Xcel Energy Inc. also allocates its own income tax benefits to its direct subsidiaries.
See Note 7 for further information.
Property, Plant and Equipment and Depreciation in Regulated Operations — Property, plant and equipment is stated at original cost. The cost of plant includes direct labor and materials, contracted work, overhead costs and AFUDC. The cost of plant retired is charged to accumulated depreciation and amortization. Amounts recovered in rates for future removal costs are recorded as regulatory liabilities. Significant additions or improvements extending asset lives are capitalized, while repairs and maintenance costs and replacement of items determined to be less than a unit of property are charged to expense as incurred.
Property, plant and equipment is tested for impairment when it is determined that the carrying value of the assets may not be recoverable. A loss is recognized in the current period if it becomes probable that part of a cost of a plant under construction or recently completed plant will be disallowed for recovery from customers and a reasonable estimate of the disallowance can be made.
For investments in property, plant and equipment that are abandoned and not expected to go into service, incurred costs and related deferred tax amounts are compared to the discounted estimated future rate recovery, and a loss is recognized, if necessary.
Depreciation expense is recorded using the straight-line method over assets’ commission approved useful lives. Actuarial life studies are performed and submitted to the state and federal commissions for review. Upon acceptance by the various commissions, the resulting lives and net salvage rates are used to calculate depreciation. Plant removal costs are typically recognized at the amounts recovered in rates as authorized by the applicable regulator. Accumulated removal costs are reflected in the consolidated balance sheet as a regulatory liability. Depreciation expense, expressed as a percentage of average depreciable property, was approximately 3.9 % for 2025, 3.8 % for 2024 and 3.6 % for 2023.
Nuclear Refueling Outage Costs — Xcel Energy uses a deferral and amortization method for nuclear refueling costs. This method amortizes costs over the period between refueling outages.
See Note 3 for further information.
AROs — Xcel Energy records AROs as a liability in the period incurred (if fair value can be reasonably estimated), with the offsetting/associated costs capitalized as a long-lived asset. The liability is generally increased over time by applying the effective interest method of accretion and the capitalized costs are typically depreciated over the useful life of the long-lived asset. Changes resulting from revisions to timing or amounts of expected asset retirement cash flows are recognized as an increase or a decrease in the ARO.
See Note 12 for further information.
Nuclear Decommissioning — Nuclear decommissioning studies that estimate NSP-Minnesota’s costs of decommissioning its nuclear power plants are normally performed at least every years and submitted to the state commissions for approval. The latest decommissioning study was completed in 2024.
NSP-Minnesota recovers regulator-approved decommissioning costs of its nuclear power plants over each facility’s expected service life, typically based on the triennial decommissioning studies. The studies consider estimated future costs of decommissioning and the market value of investments in trust funds and recommend annual funding amounts. Amounts collected in rates are deposited in the trust funds. For financial reporting purposes, NSP-Minnesota accounts for nuclear decommissioning as an ARO.
Restricted funds for future decommissioning expenditures for NSP-Minnesota’s nuclear facilities are included in nuclear decommissioning fund and other assets on the consolidated balance sheets.
See Notes 10 and 12 for further information.
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Leases — Xcel Energy evaluates contracts that may contain leases, including PPAs and arrangements for the use of office space and other facilities, as well as certain contracts for the use of land, vehicles and other equipment. A contract contains a lease if it conveys the exclusive right to control the use of a specific asset. A contract determined to contain a lease is evaluated further to determine whether the arrangement is an operating lease or a finance lease, including an assessment of whether the contract requires payments for substantially all of the value of the leased asset or whether the term of the contract is for substantially all of the expected remaining economic life of the leased asset, among other criteria for finance lease classification.
See Note 12 for further information.
Benefit Plans and Other Postretirement Benefits — Xcel Energy maintains pension and postretirement benefit plans for eligible employees. Recognizing the cost of providing benefits and measuring the projected benefit obligation of these plans requires management to make various assumptions and estimates.
Certain unrecognized actuarial gains and losses and unrecognized prior service costs or credits are deferred as regulatory assets and liabilities, rather than recorded as other comprehensive income, based on regulatory recovery mechanisms.
See Note 11 for further information.
Environmental Costs — Environmental costs are recorded when it is probable Xcel Energy is liable for remediation costs and the amount can be reasonably estimated. Costs are deferred as a regulatory asset if it is probable the costs will be recovered from customers in future rates. Otherwise, the costs are expensed. For certain environmental costs related to facilities currently in use, such as for emission-control equipment, the cost is capitalized and depreciated over the life of the plant.
Estimated remediation costs are regularly adjusted as estimates are revised and remediation is performed. If other participating potentially responsible parties exist and acknowledge their potential involvement with a site, costs are estimated and recorded only for Xcel Energy’s expected share of the cost.
Estimated future expenditures to restore sites are generally treated as a capitalized cost of plant retirement. The depreciation expense levels recoverable in rates include a provision for removal expenses. Removal costs recovered in rates before the related costs are incurred are classified as a regulatory liability. When separate mechanisms are expected to provide cost recovery or when changes in projected costs occur near the end of a facility’s useful life, regulatory accounting may be applied.
See Note 12 for further information.
Revenue from Contracts with Customers — Performance obligations related to the sale of energy are satisfied as energy is delivered to customers. Xcel Energy recognizes revenue that corresponds to the price of the energy delivered to the customer. The measurement of energy sales to customers is generally based on the reading of their meters, which occurs systematically throughout the month. At the end of each month, amounts of energy delivered to customers since the date of the last meter reading are estimated, and the corresponding unbilled revenue is recognized.
A separate financing component of collections from customers is not recognized as contract terms are short-term in nature. Revenues are net of any excise or sales taxes or fees. The utility subsidiaries recognize physical sales to customers (native load and wholesale) on a gross basis in electric revenues and cost of sales. Revenues and charges for short-term physical wholesale sales of excess energy transacted through RTO/ISOs are also recorded on a gross basis. Other revenues and charges settled/facilitated through an RTO/ISO are recorded on a net basis in cost of sales.
Xcel Energy’s subsidiaries have various rate-adjustment mechanisms that provide for the recovery of natural gas, electric fuel and purchased energy costs. Cost-adjustment tariffs may increase or decrease the level of revenue collected from customers and are revised periodically for differences between the total amount collected under the clauses and the costs incurred.
When applicable, fuel cost over-recoveries (the excess of fuel revenue billed to customers over fuel costs incurred) are deferred as regulatory liabilities and under-recoveries (the excess of fuel costs incurred over fuel revenues billed to customers) are deferred as regulatory assets.
See Note 6 for further information.
Cash and Cash Equivalents — Xcel Energy considers investments in instruments with a remaining maturity of months or less at the time of purchase to be cash equivalents.
Accounts Receivable and Allowance for Bad Debts — Accounts receivable are stated at the actual billed amount net of an allowance for bad debts. Xcel Energy establishes an allowance for uncollectible receivables based on a policy that reflects its expected exposure to the credit risk of customers.
Inventory — Inventory is recorded at the lower of average cost or net realizable value and consisted of the following:
| (Millions of Dollars) | Dec. 31, 2025 | Dec. 31, 2024 | ||||||||||||
| Inventories | ||||||||||||||
| Materials and supplies | $ | $ | ||||||||||||
| Fuel | ||||||||||||||
| Natural gas | ||||||||||||||
| Total inventories | $ | $ | ||||||||||||
Fair Value Measurements — Xcel Energy presents cash equivalents, interest rate derivatives, rabbi trust assets, commodity derivatives, pension and postretirement plan assets and nuclear decommissioning fund assets at estimated fair values in its consolidated financial statements.
For interest rate derivatives, quoted prices based primarily on observable market interest rate curves are used to estimate fair value. For commodity derivatives, the most observable inputs available are generally used to determine the fair value of each contract. In the absence of a quoted price, quoted prices for similar contracts or internally prepared valuation models may be used to determine fair value.
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For rabbi trust assets, pension and postretirement plan assets and nuclear decommissioning fund assets, published trading data and pricing models, generally using the most observable inputs available, are utilized to determine fair value for each security.
See Notes 10 and 11 for further information.
Derivative Instruments — Xcel Energy uses derivative instruments in connection with its commodity trading activities, and to manage risk associated with changes in interest rates and utility commodity prices, including forward contracts, futures, swaps and options. Derivatives that have not been designated or do not qualify for the normal purchases and normal sales exception are recorded on the consolidated balance sheets at fair value as derivative instruments. Classification of changes in fair value for those derivative instruments is dependent on the designation of a qualifying hedging relationship.
Changes in fair value of derivative instruments not designated in a qualifying hedging relationship are reflected in current earnings or as a regulatory asset or liability. Classification as a regulatory asset or liability is based on commission approved regulatory recovery mechanisms.
Gains or losses on commodity trading transactions are recorded as a component of electric operating revenues.
Normal Purchases and Normal Sales — Xcel Energy enters into contracts for purchases and sales of commodities for use and sale in its operations. At inception, contracts are evaluated to determine whether they contain a derivative, and if so, whether they may be exempted from derivative accounting if designated as normal purchases or normal sales.
See Note 10 for further information.
Commodity Trading Operations — All applicable gains and losses related to commodity trading activities are shown on a net basis in electric operating revenues in the consolidated statements of income.
Commodity trading activities are not associated with energy produced from generation assets or energy and capacity purchased to serve native load. Commodity trading contracts are recorded at fair market value and commodity trading results include the impact of all margin-sharing mechanisms.
See Note 10 for further information.
Other Utility Items
Alternative Revenue — Certain rate rider mechanisms (including transmission and distribution cost recovery, decoupling/sales true up and CIP/DSM programs) qualify as alternative revenue programs. These mechanisms arise from instances in which the regulator authorizes a future surcharge in response to past activities or completed events. When certain criteria are met, including expected collection within 24 months, revenue is recognized, which may include incentives and return on rate base items.
Billing amounts are revised periodically for differences between total amount collected and revenue earned, which may increase or decrease the level of revenue collected from customers. Alternative revenues arising from these programs are presented on a gross basis and disclosed separately from revenue from contracts with customers.
See Note 6 for further information.
Conservation Programs — Costs incurred for DSM and CIP programs are deferred if it is probable future revenue will recover the incurred cost. Revenues recognized for incentive programs for the recovery of lost margins and/or conservation performance incentives are limited to amounts expected to be collected within 24 months from the annual period in which they are earned. Regulatory assets are recognized to reflect the amount of costs or earned incentives that have not yet been collected from customers.
Emissions Allowances — Emissions allowances are recorded at cost, including broker commission fees. The inventory accounting model is utilized for all emissions allowances and any sales of these allowances are included in electric revenues.
RECs — Cost of RECs that are utilized for compliance is recorded as electric fuel and purchased power expense. In certain jurisdictions, Xcel Energy reduces recoverable fuel and purchased power costs for the cost of RECs received.
An inventory accounting model is used to account for RECs, however these assets are classified as regulatory assets if amounts are recoverable in future rates.
Sales of RECs are recorded in electric revenues on a gross basis. The cost of these RECs and amounts credited to customers under margin-sharing mechanisms are recorded in electric fuel and purchased power expense.
Cost of RECs that are utilized to support commodity trading activities are recorded in a similar manner as the associated commodities and are presented on a net basis in electric operating revenues in the consolidated statements of income.
2. Accounting Pronouncements | ||
Recently Adopted
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. Xcel Energy retrospectively implemented this guidance in the year ended Dec. 31, 2025. The adoption impacts were not material.
See Note 7 for further information.
Recently Issued
Government Grants — In December 2025, the FASB issued ASU 2025-10 – Government Grants (Topic 832), which includes amended recognition, measurement and presentation requirements for asset and income-related grants. The ASU is effective for annual and interim reporting periods beginning after Dec. 15, 2028. Xcel Energy is currently evaluating the new guidance, but adoption impacts are expected to be immaterial.
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Disaggregation of Income Statement Expenses — In November 2024, the FASB issued ASU 2024-03 – Disaggregation of Income Statement Expenses, which requires disclosure of additional detail for certain categories of income statement expenses. The ASU is effective for annual reporting periods beginning after Dec. 15, 2026 and interim reporting periods beginning after Dec. 15, 2027. Xcel Energy is currently evaluating the impact of the new disclosure guidance.
3. Property, Plant and Equipment | ||
Major classes of property, plant and equipment
| (Millions of Dollars) | Dec. 31, 2025 | Dec. 31, 2024 | ||||||||||||
| Property, plant and equipment, net | ||||||||||||||
| Electric plant | $ | $ | ||||||||||||
| Natural gas plant | ||||||||||||||
| Common and other property | ||||||||||||||
Plant to be retired (a) | ||||||||||||||
| CWIP | ||||||||||||||
| Total property, plant and equipment | ||||||||||||||
| Less accumulated depreciation | ( | ( | ||||||||||||
| Nuclear fuel | ||||||||||||||
| Less accumulated amortization | ( | ( | ||||||||||||
| Property, plant and equipment, net | $ | $ | ||||||||||||
(a)Amounts include Sherco 1 and 3 and A.S. King for NSP-Minnesota; Comanche Unit 3, Craig Unit 2, Hayden Units 1 and 2 for PSCo; and Tolk Unit 1 and 2 for SPS. The Dec. 31, 2024 amounts also include coal generation assets at Pawnee (assets were retired in 2025 and the conversion to natural gas is complete). Additionally, 2024 amounts included both Comanche Unit 2 and Craig Unit 1, which had planned retirement dates in 2025. Amounts are presented net of accumulated depreciation.
Joint Ownership of Generation, Transmission and Gas Facilities
The utility subsidiaries’ jointly owned assets as of Dec. 31, 2025:
| (Millions of Dollars, Except Percent Owned) | Plant in Service | Accumulated Depreciation | Percent Owned | |||||||||||||||||
| NSP-Minnesota | ||||||||||||||||||||
| Electric generation: | ||||||||||||||||||||
| Sherco Unit 3 | $ | $ | % | |||||||||||||||||
| Sherco common facilities | ||||||||||||||||||||
| Sherco substation | ||||||||||||||||||||
| Electric transmission: | ||||||||||||||||||||
| Grand Meadow | ||||||||||||||||||||
| Huntley Wilmarth | ||||||||||||||||||||
| CapX2020 | ||||||||||||||||||||
Total NSP-Minnesota (a) | $ | $ | ||||||||||||||||||
(a)Projects additionally include $26 million in CWIP.
| (Millions of Dollars, Except Percent Owned) | Plant in Service | Accumulated Depreciation | Percent Owned | |||||||||||||||||
| NSP-Wisconsin | ||||||||||||||||||||
| Electric transmission: | ||||||||||||||||||||
| La Crosse, WI to Madison, WI | $ | $ | % | |||||||||||||||||
| CapX2020 | ||||||||||||||||||||
Total NSP-Wisconsin (a) | $ | $ | ||||||||||||||||||
(a)Projects additionally include $3 million in CWIP.
| (Millions of Dollars, Except Percent Owned) | Plant in Service | Accumulated Depreciation | Percent Owned | |||||||||||||||||
| PSCo | ||||||||||||||||||||
| Electric generation: | ||||||||||||||||||||
| Hayden Unit 1 | $ | $ | % | |||||||||||||||||
| Hayden Unit 2 | ||||||||||||||||||||
| Hayden common facilities | ||||||||||||||||||||
| Craig Units 1 and 2 | ||||||||||||||||||||
| Craig common facilities | ||||||||||||||||||||
| Comanche Unit 3 | ||||||||||||||||||||
| Comanche common facilities | ||||||||||||||||||||
| Electric transmission: | ||||||||||||||||||||
| Transmission and other facilities | Various | |||||||||||||||||||
| Gas transmission: | ||||||||||||||||||||
| Rifle, CO to Avon, CO | ||||||||||||||||||||
| Gas transmission compressor | ||||||||||||||||||||
Total PSCo (a) | $ | $ | ||||||||||||||||||
(a)Projects additionally include $16 million in CWIP.
Each company separately records its share of operating expenses and construction expenditures. Respective owners are responsible for providing their own financing.
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4. Regulatory Assets and Liabilities | ||
Regulatory assets and liabilities are created for amounts that regulators may allow to be collected or may require to be paid back to customers in future electric and natural gas rates. Xcel Energy would be required to recognize the write-off of regulatory assets and liabilities in net income or other comprehensive income if changes in the utility industry no longer allow for the application of regulatory accounting guidance under GAAP.
Components of regulatory assets:
| (Millions of Dollars) | See Note(s) | Remaining Amortization Period | Dec. 31, 2025 | Dec. 31, 2024 (a) | ||||||||||||||||||||||||||||||||||
| Regulatory Assets | Current | Noncurrent | Current | Noncurrent | ||||||||||||||||||||||||||||||||||
| Pension and retiree medical obligations | 11 | Various | $ | $ | $ | $ | ||||||||||||||||||||||||||||||||
| Recoverable deferred taxes on AFUDC | Plant lives | |||||||||||||||||||||||||||||||||||||
| Net AROs | 1, 12 | Various | ||||||||||||||||||||||||||||||||||||
| Depreciation differences | Various | |||||||||||||||||||||||||||||||||||||
Excess deferred taxes — TCJA | 7 | Various | ||||||||||||||||||||||||||||||||||||
| Grid modernization costs | Various | |||||||||||||||||||||||||||||||||||||
| Excess liability insurance costs | Various | |||||||||||||||||||||||||||||||||||||
| Environmental remediation costs | 1, 12 | Various | ||||||||||||||||||||||||||||||||||||
| Prairie Island extended power uprate | years | |||||||||||||||||||||||||||||||||||||
Conservation programs (b) | 1 | to years | ||||||||||||||||||||||||||||||||||||
| Nuclear refueling outage costs | 1 | to years | ||||||||||||||||||||||||||||||||||||
| Benson biomass PPA termination and asset purchase | years | |||||||||||||||||||||||||||||||||||||
| Deferred natural gas, electric, steam energy/fuel costs | to years | |||||||||||||||||||||||||||||||||||||
| Renewable resources and environmental initiatives | to years | |||||||||||||||||||||||||||||||||||||
| Sales true-up and MN MISO capacity revenue | Various | |||||||||||||||||||||||||||||||||||||
| Gas pipeline inspection and remediation costs | Less than year | |||||||||||||||||||||||||||||||||||||
Other | Various | |||||||||||||||||||||||||||||||||||||
| Total regulatory assets | $ | $ | $ | $ | ||||||||||||||||||||||||||||||||||
(a)Prior period amounts have been reclassified to conform with current year presentation.
(b)Includes costs for conservation programs, as well as incentives allowed in certain jurisdictions.
Components of regulatory liabilities:
| (Millions of Dollars) | See Note(s) | Remaining Amortization Period | Dec. 31, 2025 | Dec. 31, 2024 | ||||||||||||||||||||||||||||||||||
| Regulatory Liabilities | Current | Noncurrent | Current | Noncurrent | ||||||||||||||||||||||||||||||||||
Deferred income tax adjustments and TCJA refunds (a) | 7 | Various | $ | $ | $ | $ | ||||||||||||||||||||||||||||||||
| Plant removal costs | 1, 12 | Various | ||||||||||||||||||||||||||||||||||||
Net AROs (b) | Various | |||||||||||||||||||||||||||||||||||||
| Renewable resources and environmental initiatives | Various | |||||||||||||||||||||||||||||||||||||
Effects of regulation on employee benefit costs (c) | 11 | Various | ||||||||||||||||||||||||||||||||||||
ITC deferrals | 1 | Various | ||||||||||||||||||||||||||||||||||||
| IRA deferral | to years | |||||||||||||||||||||||||||||||||||||
| Deferred natural gas, electric, steam energy/fuel costs | to years | |||||||||||||||||||||||||||||||||||||
Contract valuation adjustments (d) | 1, 10 | Less than year | ||||||||||||||||||||||||||||||||||||
Conservation programs (e) | 1 | Less than year | ||||||||||||||||||||||||||||||||||||
| Other | Various | |||||||||||||||||||||||||||||||||||||
| Total regulatory liabilities | $ | $ | $ | $ | ||||||||||||||||||||||||||||||||||
(a)Includes the revaluation of recoverable/regulated plant ADIT and revaluation impact of non-plant ADIT due to the TCJA.
(b)Includes amounts recorded for future recovery of AROs, less amounts recovered through nuclear decommissioning accruals and gains from decommissioning investments.
(c)Includes regulatory amortization and certain 2018 TCJA benefits approved by the CPUC to offset the PSCo prepaid pension asset.
(d)Includes the fair value of FTR instruments utilized/intended to offset the impacts of transmission system congestion.
(e)Includes costs for conservation programs, as well as incentives allowed in certain jurisdictions.
Xcel Energy’s regulatory assets not earning a return include past expenditures of $799 million and $892 million at Dec. 31, 2025 and 2024 respectively, which predominately relate to certain prepaid pension amounts, purchased natural gas and electric energy costs, deferred excess liability insurance costs, sales true-up and revenue decoupling and other renewable resources/environmental initiatives. Additionally, the unfunded portion of pension and retiree medical obligations and net AROs (i.e., deferrals for which cash has not been disbursed) do not earn a return.
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5. Borrowings and Other Financing Instruments | ||
Short-Term Borrowings
Short-Term Debt — Xcel Energy meets its short-term liquidity requirements primarily through the issuance of commercial paper and borrowings under its credit facilities and term loan agreements.
Commercial paper and other borrowings outstanding:
| (Millions of Dollars, Except Interest Rates) | Three Months Ended Dec. 31, 2025 | Year Ended Dec. 31 | ||||||||||||||||||||||||
| 2025 | 2024 | 2023 | ||||||||||||||||||||||||
| Borrowing limit | $ | $ | $ | $ | ||||||||||||||||||||||
| Amount outstanding at period end | ||||||||||||||||||||||||||
| Average amount outstanding | ||||||||||||||||||||||||||
| Maximum amount outstanding | ||||||||||||||||||||||||||
| Weighted average interest rate, computed on a daily basis | % | % | % | % | ||||||||||||||||||||||
| Weighted average interest rate at period end | ||||||||||||||||||||||||||
Bilateral Credit Agreement — In April 2025, NSP-Minnesota’s uncommitted bilateral credit agreement was renewed for an additional one-year term. The credit agreement is limited in use to support letters of credit.
As of Dec. 31, 2025, NSP-Minnesota had $69 million outstanding letters of credit under the $75 million Bilateral Credit Agreement.
Letters of Credit — Xcel Energy uses letters of credit, typically with terms of one year , to provide financial guarantees for certain operating obligations. As of Dec. 31, 2025 and 2024, there were $92 million and $42 million of letters of credit outstanding under the credit facilities, respectively. Amounts approximate their fair value.
Credit Facilities — In order to use commercial paper programs to fulfill short-term funding needs, Xcel Energy Inc. and its utility subsidiaries must have revolving credit facilities in place at least equal to the amount of their respective commercial paper borrowing limits and cannot issue commercial paper exceeding available capacity under these credit facilities.
The lines of credit provide short-term financing in the form of notes payable to banks, letters of credit and back-up support for commercial paper borrowings.
In May 2025, Xcel Energy Inc., NSP-Minnesota, NSP-Wisconsin, PSCo and SPS each entered into an amended five-year credit agreement with a syndicate of banks. The aggregate borrowing limit is $4.75 billion. The amended credit agreements mature in December 2029.
Features of the credit facilities:
Debt-to-Total Capitalization Ratio (a) | Amount Facility May Be Increased (millions of dollars) (b) | Additional Periods for Which a One-Year Extension May Be Requested (c) | ||||||||||||||||||||||||
| 2025 | 2024 | |||||||||||||||||||||||||
Xcel Energy Inc. (d) | % | % | $ | |||||||||||||||||||||||
| NSP-Minnesota | ||||||||||||||||||||||||||
| NSP-Wisconsin | N/A | |||||||||||||||||||||||||
| SPS | ||||||||||||||||||||||||||
| PSCo | ||||||||||||||||||||||||||
(a)Each credit facility has a financial covenant requiring that the debt-to-total capitalization ratio be less than or equal to 65 % (70 % for Xcel Energy Inc.).
(b)Amounts authorized by state commissions in respective jurisdictions.
(c)All extension requests are subject to majority bank group approval.
(d)The Xcel Energy Inc. credit facility has a cross-default provision that Xcel Energy Inc. would be in default on its borrowings under the facility if it or any of its subsidiaries (except NSP-Wisconsin as long as its total assets do not comprise more than 15 % of Xcel Energy’s consolidated total assets) default on indebtedness in an aggregate principal amount exceeding $75 million.
If Xcel Energy Inc. or its utility subsidiaries do not comply with the covenant, an event of default may be declared, and if not remedied, any outstanding amounts due under the facility can be declared due by the lender. As of Dec. 31, 2025, Xcel Energy Inc. and its subsidiaries were in compliance with the financial covenant.
Xcel Energy Inc. and its utility subsidiaries had the following committed credit facilities available as of Dec. 31, 2025:
| (Millions of Dollars) | Credit Facility (a) | Drawn (b) | Available | |||||||||||||||||
| Xcel Energy Inc. | $ | $ | $ | |||||||||||||||||
| PSCo | ||||||||||||||||||||
| NSP-Minnesota | ||||||||||||||||||||
| SPS | ||||||||||||||||||||
| NSP-Wisconsin | ||||||||||||||||||||
| Total | $ | $ | $ | |||||||||||||||||
(a)These credit facilities mature in December 2029.
(b)Includes outstanding commercial paper and letters of credit.
All credit facility bank borrowings, outstanding letters of credit and outstanding commercial paper reduce the available capacity under the credit facilities. Xcel Energy Inc. and its utility subsidiaries had no
Term Loan Agreement — In January 2026, Xcel Energy Inc. entered into a $1.5 billion, 364-Day Delayed Draw Term Loan Agreement and borrowed $750 million under the term loan facility. The loan is unsecured and matures Jan. 30, 2027. The term loan includes one financial covenant, requiring Xcel Energy’s consolidated funded debt to total capitalization ratio to be less than or equal to 70 percent. Interest is at a rate equal to the Term SOFR rate, plus 85.0 basis points, or an alternate base rate.
Long-Term Borrowings and Other Financing Instruments
Generally, the property of NSP-Minnesota, NSP-Wisconsin, PSCo and SPS is subject to the liens of their respective first mortgage indentures for the benefit of bondholders.
Debt premiums, discounts and expenses are amortized over the life of the related debt. The premiums, discounts and expenses for refinanced debt are deferred and amortized over the life of the new issuance.
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Long-term debt obligations for Xcel Energy Inc. and its utility subsidiaries as of Dec. 31 (in millions of dollars, except interest rates):
| Xcel Energy Inc. | ||||||||||||||||||||||||||
| Financing Instrument | Interest Rate | Maturity Date | 2025 | 2024 | ||||||||||||||||||||||
| Unsecured senior notes | % | June 1, 2025 | $ | $ | ||||||||||||||||||||||
| Unsecured senior notes | June 1, 2025 | |||||||||||||||||||||||||
| Unsecured senior notes | Dec. 1, 2026 | |||||||||||||||||||||||||
| Unsecured senior notes | March 15, 2027 | |||||||||||||||||||||||||
| Unsecured senior notes | June 15, 2028 | |||||||||||||||||||||||||
Unsecured senior notes (a) | March 21, 2028 | |||||||||||||||||||||||||
| Unsecured senior notes | June 15, 2028 | |||||||||||||||||||||||||
| Unsecured senior notes | Dec. 1, 2029 | |||||||||||||||||||||||||
| Unsecured senior notes | June 1, 2030 | |||||||||||||||||||||||||
| Unsecured senior notes | Nov. 15, 2031 | |||||||||||||||||||||||||
| Unsecured senior notes | June 1, 2032 | |||||||||||||||||||||||||
| Unsecured senior notes | Aug. 15, 2033 | |||||||||||||||||||||||||
Unsecured senior notes (b) | March 15, 2034 | |||||||||||||||||||||||||
Unsecured senior notes (a) | April 15, 2035 | |||||||||||||||||||||||||
| Unsecured senior notes | July 1, 2036 | |||||||||||||||||||||||||
| Unsecured senior notes | Sept. 15, 2041 | |||||||||||||||||||||||||
| Unsecured senior notes | Dec. 1, 2049 | |||||||||||||||||||||||||
Junior subordinated notes (a) (c) | Oct. 15, 2085 | |||||||||||||||||||||||||
| Unamortized discount | ( | ( | ||||||||||||||||||||||||
| Unamortized debt issuance cost | ( | ( | ||||||||||||||||||||||||
| Current maturities | ( | ( | ||||||||||||||||||||||||
| Total long-term debt | $ | $ | ||||||||||||||||||||||||
(a)2025 financing .
(b)2024 financing .
(c)The notes may be redeemed at par value on or after Oct. 15, 2030 .
| NSP-Minnesota | ||||||||||||||||||||||||||
| Financing Instrument | Interest Rate | Maturity Date | 2025 | 2024 | ||||||||||||||||||||||
| First mortgage bonds | % | July 1, 2025 | $ | $ | ||||||||||||||||||||||
| First mortgage bonds | March 1, 2028 | |||||||||||||||||||||||||
| First mortgage bonds | April 1, 2031 | |||||||||||||||||||||||||
First mortgage bonds (a) | May 15, 2035 | |||||||||||||||||||||||||
| First mortgage bonds | July 15, 2035 | |||||||||||||||||||||||||
| First mortgage bonds | June 1, 2036 | |||||||||||||||||||||||||
| First mortgage bonds | July 1, 2037 | |||||||||||||||||||||||||
| First mortgage bonds | Nov. 1, 2039 | |||||||||||||||||||||||||
| First mortgage bonds | Aug. 15, 2040 | |||||||||||||||||||||||||
| First mortgage bonds | Aug. 15, 2042 | |||||||||||||||||||||||||
| First mortgage bonds | May 15, 2044 | |||||||||||||||||||||||||
| First mortgage bonds | Aug. 15, 2045 | |||||||||||||||||||||||||
| First mortgage bonds | May 15, 2046 | |||||||||||||||||||||||||
| First mortgage bonds | Sept. 15, 2047 | |||||||||||||||||||||||||
| First mortgage bonds | March 1, 2050 | |||||||||||||||||||||||||
| First mortgage bonds | June 1, 2051 | |||||||||||||||||||||||||
| First mortgage bonds | April 1, 2052 | |||||||||||||||||||||||||
| First mortgage bonds | June 1, 2052 | |||||||||||||||||||||||||
| First mortgage bonds | May 15, 2053 | |||||||||||||||||||||||||
First mortgage bonds (b) | March 15, 2054 | |||||||||||||||||||||||||
First mortgage bonds (a) | May 15, 2055 | |||||||||||||||||||||||||
| Other long-term debt | ||||||||||||||||||||||||||
| Long-term debt — related parties principal amount outstanding | 2.60 - 4.125 | 2044 - 2052 | ( | ( | ||||||||||||||||||||||
| Unamortized discount | ( | ( | ||||||||||||||||||||||||
| Unamortized debt issuance cost | ( | ( | ||||||||||||||||||||||||
| Current maturities | ( | |||||||||||||||||||||||||
| Total long-term debt | $ | $ | ||||||||||||||||||||||||
(a)2025 financing.
(b)2024 financing.
| NSP-Wisconsin | ||||||||||||||||||||||||||
| Financing Instrument | Interest Rate | Maturity Date | 2025 | 2024 | ||||||||||||||||||||||
| First mortgage bonds | % | Sept. 1, 2038 | $ | $ | ||||||||||||||||||||||
| First mortgage bonds | Oct. 1, 2042 | |||||||||||||||||||||||||
| First mortgage bonds | Dec. 1, 2047 | |||||||||||||||||||||||||
| First mortgage bonds | Sept. 1, 2048 | |||||||||||||||||||||||||
| First mortgage bonds | May 1, 2051 | |||||||||||||||||||||||||
| First mortgage bonds | May 1, 2051 | |||||||||||||||||||||||||
| First mortgage bonds | Sept. 15, 2052 | |||||||||||||||||||||||||
| First mortgage bonds | June 15, 2053 | |||||||||||||||||||||||||
First mortgage bonds (a) | June 15, 2054 | |||||||||||||||||||||||||
First mortgage bonds (b) | June 15, 2054 | |||||||||||||||||||||||||
| Unamortized discount | ( | ( | ||||||||||||||||||||||||
| Unamortized debt issuance cost | ( | ( | ||||||||||||||||||||||||
| Total long-term debt | $ | $ | ||||||||||||||||||||||||
(a)2024 financing.
(b)2025 financing.
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| PSCo | ||||||||||||||||||||||||||
| Financing Instrument | Interest Rate | Maturity Date | 2025 | 2024 | ||||||||||||||||||||||
| First mortgage bonds | % | May 15, 2025 | $ | $ | ||||||||||||||||||||||
| First mortgage bonds | June 15, 2028 | |||||||||||||||||||||||||
| First mortgage bonds | Jan. 15, 2031 | |||||||||||||||||||||||||
| First mortgage bonds | June 15, 2031 | |||||||||||||||||||||||||
| First mortgage bonds | June 1, 2032 | |||||||||||||||||||||||||
First mortgage bonds (a) | May 15, 2034 | |||||||||||||||||||||||||
First mortgage bonds (b) | May 15, 2034 | |||||||||||||||||||||||||
First mortgage bonds (a) | Sep 15, 2035 | |||||||||||||||||||||||||
| First mortgage bonds | Sept. 1, 2037 | |||||||||||||||||||||||||
| First mortgage bonds | Aug. 1, 2038 | |||||||||||||||||||||||||
| First mortgage bonds | Aug. 15, 2041 | |||||||||||||||||||||||||
| First mortgage bonds | Sept. 15, 2042 | |||||||||||||||||||||||||
| First mortgage bonds | March 15, 2043 | |||||||||||||||||||||||||
| First mortgage bonds | March 15, 2044 | |||||||||||||||||||||||||
| First mortgage bonds | June 15, 2046 | |||||||||||||||||||||||||
| First mortgage bonds | June 15, 2047 | |||||||||||||||||||||||||
| First mortgage bonds | June 15, 2048 | |||||||||||||||||||||||||
| First mortgage bonds | Sept. 15, 2049 | |||||||||||||||||||||||||
| First mortgage bonds | March 1, 2050 | |||||||||||||||||||||||||
| First mortgage bonds | Jan. 15, 2051 | |||||||||||||||||||||||||
| First mortgage bonds | June 1, 2052 | |||||||||||||||||||||||||
| First mortgage bonds | April 1, 2053 | |||||||||||||||||||||||||
First mortgage bonds (b) | May 15, 2054 | |||||||||||||||||||||||||
First mortgage bonds (a) | May 15, 2055 | |||||||||||||||||||||||||
| Unamortized discount | ( | ( | ||||||||||||||||||||||||
| Unamortized debt issuance cost | ( | ( | ||||||||||||||||||||||||
| Current maturities | ( | |||||||||||||||||||||||||
| Total long-term debt | $ | $ | ||||||||||||||||||||||||
(a)2025 financing .
(b)2024 financing.
| SPS | ||||||||||||||||||||||||||
| Financing Instrument | Interest Rate | Maturity Date | 2025 | 2024 | ||||||||||||||||||||||
| Unsecured senior notes | % | Oct. 1, 2033 | $ | $ | ||||||||||||||||||||||
First mortgage bonds (a) | May 15, 2035 | |||||||||||||||||||||||||
| Unsecured senior notes | Oct. 1, 2036 | |||||||||||||||||||||||||
| First mortgage bonds | Aug. 15, 2041 | |||||||||||||||||||||||||
| First mortgage bonds | Aug. 15, 2041 | |||||||||||||||||||||||||
| First mortgage bonds | Aug. 15, 2041 | |||||||||||||||||||||||||
| First mortgage bonds | Aug. 15, 2046 | |||||||||||||||||||||||||
| First mortgage bonds | Aug. 15, 2047 | |||||||||||||||||||||||||
| First mortgage bonds | Nov. 15, 2048 | |||||||||||||||||||||||||
| First mortgage bonds | June 15, 2049 | |||||||||||||||||||||||||
| First mortgage bonds | May 1, 2050 | |||||||||||||||||||||||||
| First mortgage bonds | May 1, 2050 | |||||||||||||||||||||||||
| First mortgage bonds | June 1, 2052 | |||||||||||||||||||||||||
| First mortgage bonds | Sept. 15, 2053 | |||||||||||||||||||||||||
First mortgage bonds (b) | June 1, 2054 | |||||||||||||||||||||||||
| Unamortized discount | ( | ( | ||||||||||||||||||||||||
| Unamortized debt issuance cost | ( | ( | ||||||||||||||||||||||||
| Total long-term debt | $ | $ | ||||||||||||||||||||||||
(a)2025 financing.
(b)2024 financing .
| Other Subsidiaries | ||||||||||||||||||||||||||
| Financing Instrument | Interest Rate | Maturity Date | 2025 | 2024 | ||||||||||||||||||||||
| Various Eloigne affordable housing project notes | 0.00% - 8.50% | 2026 - 2055 | $ | $ | ||||||||||||||||||||||
| Current maturities | ( | ( | ||||||||||||||||||||||||
| Total long-term debt | $ | $ | ||||||||||||||||||||||||
Maturities of long-term debt:
| (Millions of Dollars) | ||||||||
| 2026 | $ | |||||||
| 2027 | ||||||||
| 2028 | ||||||||
| 2029 | ||||||||
| 2030 | ||||||||
Xcel Energy Inc.’s Purchase of NSP-Minnesota’s First Mortgage Bonds — During 2024, Xcel Energy Inc. purchased $166 million in aggregate principal amounts of NSP-Minnesota’s 2.60 % First Mortgage Bonds Series due June 1, 2051 for $105 million.
During 2025, Xcel Energy Inc. purchased $787 million in aggregate principal amounts of NSP-Minnesota’s 4.125 % First Mortgage Bonds Series due May 15, 2044, 4.00 % First Mortgage Bonds Series due August 15, 2045, 3.60 % First Mortgage Bonds Series due May 15, 2046, 2.90 % First Mortgage Bonds Series due March 1, 2050, 2.60 % First Mortgage Bonds Series due June 1, 2051, and 3.20 % First Mortgage Bonds Series due April 1, 2052, for $607 million.
On a consolidated basis, Xcel Energy Inc.’s repurchases of NSP-Minnesota first mortgage bonds were accounted for as debt extinguishments and resulted in pre-tax gains of approximately $162 million and $56 million in the years ended Dec. 31, 2025 and 2024, respectively, net of unamortized discount and debt issuance costs. Interest expense related to the repurchased bonds was $6 million and immaterial for the years ended Dec. 31, 2025 and 2024, respectively.
Deferred Financing Costs — Deferred financing costs of approximately $270 million and $235 million, net of amortization, are presented as a deduction from the carrying amount of long-term debt as of Dec. 31, 2025 and 2024, respectively.
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, 3.1 million shares of common stock were issued ($188 million in net proceeds and $2 million in transaction fees paid). In 2024, 18.3 million shares of common stock were issued ($1.10 billion in net proceeds and $9 million in transaction fees paid). In 2025, 16.4 million shares ($1.16 billion in net proceeds and $9 million in transaction fees paid) were issued under the ATM program. As of August 1, 2025, no further transactions will occur under this ATM program.
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In August 2025, Xcel Energy Inc. filed a prospectus supplement under which it may sell up to $4 billion of its common stock through an ATM program. As of Dec. 31, 2025, Xcel Energy Inc. has issued 1.9 million shares of common stock ($142 million in net proceeds and $1 million in transaction fees paid) to or through its sales agents under the 2025 ATM program. In addition to these immediate issuances and sales of shares of common stock, Xcel Energy Inc. also may use the 2025 ATM program to enter into forward sale agreements under separate forward sale agreements between Xcel Energy Inc. and a banking counterparty. See below for information regarding shares issued or expected to be issued under forward sale agreements entered through Dec. 31, 2025.
Equity through DRIP and Benefits Program — Xcel Energy issued $67
Forward Equity Agreements — Xcel Energy Inc. has entered into multiple forward sale agreements in 2025 and 2024 in connection with completed public offerings of Xcel Energy common stock.
During the year ended Dec. 31, 2025, Xcel Energy Inc. physically settled its obligations under the following forward sale agreements (in millions of dollars, except per share data):
| Agreements Entered | Common Shares (in millions) | Forward Sale Price per Share | Cash Proceeds at Settlement | |||||||||||||||||
| Forward sale agreements settled in December 2025: | ||||||||||||||||||||
| 2024 forward equity agreements | $64.70 - 64.76 | $ | ||||||||||||||||||
| 2025 forward equity agreements | 71.91 - 80.97 | |||||||||||||||||||
| $ | ||||||||||||||||||||
The following forward sale agreements remain outstanding as of Dec. 31, 2025:
| Agreements Entered | Common Shares (in millions) | Final Maturity | Minimum Expected Proceeds (millions of dollars) | ||||||||||||||||||||
2025 forward equity agreements (a) | Feb. 2026 to Dec. 2028 (b) | (c) | |||||||||||||||||||||
2025 collared forward equity agreements (a) | Dec. 2026 | (d) | |||||||||||||||||||||
(a)Entered under the 2025 ATM prospectus supplement.
(b)Xcel Energy may settle the agreements at any time until final maturity.
(c)Actual cash proceeds will be impacted by the timing of settlement. Forward prices are based on the public offering price (net of underwriting fees), increased for the overnight bank funding rate, less a spread and less expected dividends on Xcel Energy’s common stock during the period the agreements are outstanding.
(d)Pricing for the physical delivery of common shares will be based on an average market price for Xcel Energy’s common stock during a period preceding settlement in December 2026, subject to a cap price and floor price derived from the September 2025 and December 2025 public offerings.
If settled in physical shares, stockholders’ equity equal to cash proceeds will be recorded at settlement.
The 2025 collared forward equity agreements cannot be settled until December 2026, and net cash settlement and net share settlement are generally unavailable. The 2025 forward equity agreements could have been settled at Dec. 31, 2025 with physical delivery of common shares to the banking counterparties in exchange for cash; if Xcel Energy unilaterally elected net cash or net share settlement, these agreements also could have been settled with delivery of cash or shares of common stock to the banking counterparties, as follows:
| Pro-Forma/Hypothetical Transactions | ||||||||||||||||||||
| Agreements Entered | Net Settlement: | Physical Share Delivery Proceeds (millions of dollars) | ||||||||||||||||||
| Common Shares (in millions) | Net Cash (millions of dollars) | |||||||||||||||||||
| 2025 forward equity agreements | $ | $ | ||||||||||||||||||
Capital Stock — Preferred stock authorized/outstanding:
| Preferred Stock Authorized (Shares) | Par Value of Preferred Stock | Preferred Stock Outstanding (Shares) 2025 and 2024 | ||||||||||||||||||
| Xcel Energy Inc. | $ | |||||||||||||||||||
| PSCo | ||||||||||||||||||||
| SPS | ||||||||||||||||||||
Xcel Energy Inc. had the following common stock authorized/outstanding:
| Common Stock Authorized (Shares) | Par Value of Common Stock | Common Stock Outstanding (Shares) as of Dec. 31, 2025 | Common Stock Outstanding (Shares) as of Dec. 31, 2024 | |||||||||||||||||
| $ | ||||||||||||||||||||
Dividend and Other Capital-Related Restrictions — Xcel Energy depends on its utility subsidiaries to pay dividends. Xcel Energy Inc.’s utility subsidiaries’ dividends are subject to the FERC’s jurisdiction, which prohibits the payment of dividends out of capital accounts. Dividends are solely to be paid from retained earnings. Certain covenants also require Xcel Energy Inc. to be current on interest payments prior to dividend disbursements.
State regulatory commissions impose dividend limitations for NSP-Minnesota, NSP-Wisconsin and SPS, which are more restrictive than those imposed by the FERC.
Requirements and actuals as of Dec. 31, 2025:
| Equity to Total Capitalization Ratio Required Range | Equity to Total Capitalization Ratio Actual | |||||||||||||||||||
| Low | High | 2025 | ||||||||||||||||||
| NSP-Minnesota | % | % | % | |||||||||||||||||
NSP-Wisconsin (a) | N/A | |||||||||||||||||||
SPS (b) | ||||||||||||||||||||
(a) Cannot pay annual dividends in excess of forecasted levels if its average equity-to-total capitalization ratio falls below the commission authorized level.
(b) Excludes short-term debt.
| (Amounts in Millions) | Unrestricted Retained Earnings | Total Capitalization | Limit on Total Capitalization | |||||||||||||||||
| NSP-Minnesota | $ | $ | $ | |||||||||||||||||
| NSP-Wisconsin | N/A | |||||||||||||||||||
SPS (a) | N/A | |||||||||||||||||||
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Issuance of securities by Xcel Energy Inc. is not generally subject to regulatory approval. However, utility financings and intra-system financings are subject to the jurisdiction of state regulatory commissions and/or the FERC. Xcel Energy may seek additional authorization as necessary.
Amounts authorized to issue as of Dec. 31, 2025:
| (Millions of Dollars) | Long-Term Debt | Short-Term Debt | ||||||||||||
NSP-Minnesota (a) | 52.8% of total capitalization | $ | ||||||||||||
| NSP-Wisconsin | $ | |||||||||||||
| PSCo | ||||||||||||||
| SPS | ||||||||||||||
6. Revenues | ||
Revenue is classified by the type of goods/services rendered and market/customer type. Xcel Energy’s operating revenues consisted of the following:
| Year Ended Dec. 31, 2025 | ||||||||||||||||||||||||||
| (Millions of Dollars) | Electric | Natural Gas | All Other | Total | ||||||||||||||||||||||
| Major revenue types | ||||||||||||||||||||||||||
| Revenue from contracts with customers: | ||||||||||||||||||||||||||
| Residential | $ | $ | $ | $ | ||||||||||||||||||||||
| C&I | ||||||||||||||||||||||||||
| Other | ||||||||||||||||||||||||||
| Total retail | ||||||||||||||||||||||||||
| Wholesale | ||||||||||||||||||||||||||
| Transmission | ||||||||||||||||||||||||||
| Other | ||||||||||||||||||||||||||
| Total revenue from contracts with customers | ||||||||||||||||||||||||||
| Alternative revenue and other | ||||||||||||||||||||||||||
| Total revenues | $ | $ | $ | $ | ||||||||||||||||||||||
| Year Ended Dec. 31, 2024 | ||||||||||||||||||||||||||
| (Millions of Dollars) | Electric | Natural Gas | All Other | Total | ||||||||||||||||||||||
| Major revenue types | ||||||||||||||||||||||||||
| Revenue from contracts with customers: | ||||||||||||||||||||||||||
| Residential | $ | $ | $ | $ | ||||||||||||||||||||||
| C&I | ||||||||||||||||||||||||||
| Other | ||||||||||||||||||||||||||
| Total retail | ||||||||||||||||||||||||||
| Wholesale | ||||||||||||||||||||||||||
| Transmission | ||||||||||||||||||||||||||
| Other | ||||||||||||||||||||||||||
| Total revenue from contracts with customers | ||||||||||||||||||||||||||
| Alternative revenue and other | ||||||||||||||||||||||||||
| Total revenues | $ | $ | $ | $ | ||||||||||||||||||||||
| Year Ended Dec. 31, 2023 | ||||||||||||||||||||||||||
| (Millions of Dollars) | Electric | Natural Gas | All Other | Total | ||||||||||||||||||||||
| Major revenue types | ||||||||||||||||||||||||||
| Revenue from contracts with customers: | ||||||||||||||||||||||||||
| Residential | $ | $ | $ | $ | ||||||||||||||||||||||
| C&I | ||||||||||||||||||||||||||
| Other | ||||||||||||||||||||||||||
| Total retail | ||||||||||||||||||||||||||
| Wholesale | ||||||||||||||||||||||||||
| Transmission | ||||||||||||||||||||||||||
| Other | ||||||||||||||||||||||||||
| Total revenue from contracts with customers | ||||||||||||||||||||||||||
| Alternative revenue and other | ||||||||||||||||||||||||||
| Total revenues | $ | $ | $ | $ | ||||||||||||||||||||||
7. Income Taxes | ||
Total income tax expense from operations differs from the amount computed by applying the statutory federal income tax rate to income before income tax expense.
Effective income tax reconciliation for years ended Dec. 31:
| (Millions of Dollars) | 2025 | 2024 | 2023 | |||||||||||||||||
| Income before income taxes (domestic) | $ | $ | $ | |||||||||||||||||
| Federal statutory rate impact | ||||||||||||||||||||
| (Decreases) increases in tax from: | ||||||||||||||||||||
| Tax credits | ||||||||||||||||||||
PTCs (a) | ( | ( | ( | |||||||||||||||||
| Other | ( | ( | ( | |||||||||||||||||
Regulatory adjustments (b) | ||||||||||||||||||||
| Plant related excess deferred taxes | ( | ( | ( | |||||||||||||||||
| AFUDC equity | ( | ( | ( | |||||||||||||||||
| Other | ||||||||||||||||||||
State income taxes, net of federal tax effect (c) | ||||||||||||||||||||
| Other | ( | |||||||||||||||||||
| Income tax benefit | $ | ( | $ | ( | $ | ( | ||||||||||||||
| 2025 | 2024 | 2023 | ||||||||||||||||||
| Federal statutory rate | % | % | % | |||||||||||||||||
| (Decreases) increases in tax from: | ||||||||||||||||||||
| Tax credits | ||||||||||||||||||||
PTCs (a) | ( | ( | ( | |||||||||||||||||
| Other | ( | ( | ( | |||||||||||||||||
Regulatory adjustments (b) | ||||||||||||||||||||
| Plant related excess deferred taxes | ( | ( | ( | |||||||||||||||||
| AFUDC equity | ( | ( | ( | |||||||||||||||||
| Other | ||||||||||||||||||||
State income taxes, net of federal tax effect (c) | ||||||||||||||||||||
| Other | ||||||||||||||||||||
| Effective income tax rate | ( | % | ( | % | ( | % | ||||||||||||||
(a)Wind, Solar and Nuclear PTCs (net of transfer discounts) are generally credited to customers (reduction to revenue) and do not materially impact earnings.
(b)Regulatory adjustments primarily relate to the credit of plant related excess deferred taxes to customers for tax rate increases as well as the capitalization of AFUDC equity for book purposes only. Income tax benefits associated with the credit of excess deferred taxes are offset by corresponding revenue reductions.
(c)State and local income taxes are primarily made up of the following jurisdictions: Minnesota, Colorado
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Components of income tax expense for years ended Dec. 31:
| (Millions of Dollars) | 2025 | 2024 | 2023 | |||||||||||||||||
| Current federal tax (benefit) expense | $ | ( | $ | $ | ||||||||||||||||
| Current state tax expense | ||||||||||||||||||||
| Current change in unrecognized tax expense (benefit) | ( | |||||||||||||||||||
| Deferred federal tax benefit | ( | ( | ( | |||||||||||||||||
| Deferred state tax expense | ||||||||||||||||||||
| Deferred change in unrecognized tax (benefit) expense | ( | |||||||||||||||||||
| Deferred ITCs | ( | ( | ( | |||||||||||||||||
| Total income tax benefit | $ | ( | $ | ( | $ | ( | ||||||||||||||
Components of deferred income tax expense as of Dec. 31:
| (Millions of Dollars) | 2025 | 2024 | 2023 | |||||||||||||||||
| Deferred tax expense excluding items below | $ | $ | $ | |||||||||||||||||
| Adjustments to deferred income taxes for tax credit cash transfers | ( | ( | ( | |||||||||||||||||
| Amortization and adjustments to deferred income taxes on income tax regulatory assets and liabilities | ( | ( | ( | |||||||||||||||||
| Tax expense allocated to other comprehensive income and other | ( | ( | ||||||||||||||||||
| Deferred tax benefit | $ | ( | $ | ( | $ | ( | ||||||||||||||
Components of net deferred tax liability as of Dec. 31:
| (Millions of Dollars) | 2025 | 2024(a) | ||||||||||||
| Deferred tax liabilities: | ||||||||||||||
| Differences between book and tax bases of property | $ | $ | ||||||||||||
| Regulatory assets | ||||||||||||||
| Operating lease assets | ||||||||||||||
| Pension expense | ||||||||||||||
| Other | ||||||||||||||
| Total deferred tax liabilities | $ | $ | ||||||||||||
| Deferred tax assets: | ||||||||||||||
| Tax credit carryforward | $ | $ | ||||||||||||
| Regulatory liabilities | ||||||||||||||
| Operating lease liabilities | ||||||||||||||
| Other employee benefits | ||||||||||||||
| Deferred ITCs | ||||||||||||||
| NOL carryforward | ||||||||||||||
| NOL and tax credit valuation allowances | ( | ( | ||||||||||||
| Other | ||||||||||||||
| Total deferred tax assets | ||||||||||||||
| Net deferred tax liability | $ | $ | ||||||||||||
(a)Prior periods have been reclassified to conform to current year presentation .
Cash received (paid) for income taxes for the years ended Dec. 31:
| (Millions of Dollars) | 2025 | 2024 | 2023 | |||||||||||||||||
Cash received for income taxes: federal, net (a) | $ | $ | $ | |||||||||||||||||
| Cash paid for income taxes: state | ( | ( | ( | |||||||||||||||||
| Total | $ | $ | $ | |||||||||||||||||
(a)Includes proceeds from tax credit transfers.
Other Income Tax Matters — NOL amounts represent the tax loss that is carried forward and tax credits represent the deferred tax asset. NOL and tax credit carryforwards as of Dec. 31:
| (Millions of Dollars) | 2025 | 2024 | ||||||||||||
| Federal tax credit carryforwards | $ | $ | ||||||||||||
| Valuation allowances for federal credit carryforwards | ( | ( | ||||||||||||
| State NOL carryforwards | ||||||||||||||
| Valuation allowances for state NOL carryforwards | ( | ( | ||||||||||||
State tax credit carryforwards, net of federal detriment (a) | ||||||||||||||
Valuation allowances for state credit carryforwards, net of federal benefit (b) | ( | ( | ||||||||||||
(a)State tax credit carryforwards are net of federal detriment of $19
(b)Valuation allowances for state tax credit carryforwards were net of federal benefit of $17 million and $16 million as of Dec. 31, 2025 and 2024, respectively.
Federal carryforward periods expire between 2038 and 2045. State carryforward periods, not including those with indefinite carryforward periods, expire between 2026 and 2038.
Unrecognized Tax Benefits
Federal Audit — In 2023 the IRS issued its Revenue Agent’s Report related to the federal tax loss carryback claim. The Company materially agreed with the report and re-recognized the related benefit in 2023.
Statute of limitations applicable to Xcel Energy’s consolidated federal income tax returns expire as follows:
| Tax Year | Expiration | |||||||
| 2022 | September 2026 | |||||||
Additionally, the statute of limitations related to federal tax credit carryforwards will remain open until those credits are utilized in subsequent returns.
State Audits — Xcel Energy files consolidated state tax returns based on income in its major operating jurisdictions and various other state income-based tax returns.
As of Dec. 31, 2025, Xcel Energy’s earliest open tax years (subject to examination by state taxing authorities in its major operating jurisdictions) were as follows:
| State | Tax Year(s) | Expiration | ||||||||||||
| Colorado | 2014 - 2016 | March 2026 | ||||||||||||
| Colorado | 2021 | October 2026 | ||||||||||||
| Minnesota | 2021 | June 2026 | ||||||||||||
| Texas | 2020 | June 2028 | ||||||||||||
| Texas | 2021 | June 2029 | ||||||||||||
| Texas | 2022 | August 2027 | ||||||||||||
| Texas | 2023 | November 2028 | ||||||||||||
| Wisconsin | 2021 | October 2026 | ||||||||||||
•In 2025, Minnesota began an audit of tax years 2021-2023. As of Dec. 31, 2025, no material adjustments have been proposed.
•In 2021, Texas began an audit of tax years 2016 - 2019. As of Dec. 31, 2025, no material adjustments have been proposed.
•In 2021, Wisconsin began an audit of tax years 2016-2019. As of Dec. 31, 2025, no material adjustments have been proposed.
•No other state income tax audits are in progress for its major operating jurisdictions as of Dec. 31, 2025.
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Unrecognized tax benefit balance may include permanent tax positions, which if recognized would affect the ETR. In addition, the unrecognized tax benefit balance may include temporary tax positions for which deductibility is highly certain, but for which there is uncertainty about the timing. A change in the period of deductibility would not affect the ETR but would accelerate the payment to the taxing authority.
Unrecognized tax benefits - permanent vs. temporary:
| (Millions of Dollars) | Dec. 31, 2025 | Dec. 31, 2024 | ||||||||||||
| Unrecognized tax benefit — Permanent tax positions | $ | $ | ||||||||||||
| Unrecognized tax benefit — Temporary tax positions | ||||||||||||||
| Total unrecognized tax benefit | $ | $ | ||||||||||||
Changes in unrecognized tax benefits:
| (Millions of Dollars) | 2025 | 2024 | 2023 | |||||||||||||||||
| Balance at Jan. 1 | $ | $ | $ | |||||||||||||||||
| Additions based on tax positions related to the current year | ||||||||||||||||||||
| Additions for tax positions of prior years | ||||||||||||||||||||
| Reductions for tax positions of prior years | ( | ( | ( | |||||||||||||||||
| Reductions for tax positions related to settlements with taxing authorities | ( | |||||||||||||||||||
| Reductions for tax positions related to statute of limitations | ( | ( | ||||||||||||||||||
| Balance at Dec. 31 | $ | $ | $ | |||||||||||||||||
Unrecognized tax benefits were reduced by tax benefits associated with NOL and tax credit carryforwards:
| (Millions of Dollars) | Dec. 31, 2025 | Dec. 31, 2024 | ||||||||||||
| NOL and tax credit carryforwards | $ | ( | $ | ( | ||||||||||
Payable for interest related to unrecognized tax benefits is partially offset by the interest benefit associated with NOL and tax credit carryforwards.
Interest payable related to unrecognized tax benefits:
| (Millions of Dollars) | 2025 | 2024 | 2023 | |||||||||||||||||
| Payable for interest related to unrecognized tax benefits at Jan. 1 | $ | ( | $ | ( | $ | ( | ||||||||||||||
| Interest (expense) benefit related to unrecognized tax benefits | ( | ( | ||||||||||||||||||
| Payable for interest related to unrecognized tax benefits at Dec. 31 | $ | ( | $ | ( | $ | ( | ||||||||||||||
Penalties accrued related to unrecognized tax benefits as of Dec. 31, 2025 were not material. No
8. Share-Based Compensation | ||
Incentive Plan Including Share-Based Compensation — Xcel Energy has authorized 13.0 million shares under the Xcel Energy Inc. 2024 Equity Incentive Plan for grants made on May 22, 2024 or later and 6.0 million shares under the Amended and Restated 2015 Omnibus Incentive Plan for grants made prior to May 22, 2024.
Xcel Energy‘s Board of Directors has granted share based awards under these plans, which include various service, performance and market conditions. Following measurement at the end of a three-year restricted period settlement in shares or cash will occur if these conditions are met.
Awards granted in 2023 and 2024 with conditions incremental to service requirements contain goals based on environmental performance or Xcel Energy TSR relative to a peer group of utility companies. For 2025, awards with conditions incremental to service contain goals based on EPS, operations and environmental performance, each with adjustments for relative TSR ranking.
Equity award units granted to employees:
| (Units in Thousands) | 2025 | 2024 | 2023 | |||||||||||||||||
Granted units (a) | ||||||||||||||||||||
| Weighted average grant date fair value | $ | $ | $ | |||||||||||||||||
(a)Includes 2025, 2024 and 2023 grants of 379 , 457 and 413 units (each in thousands), respectively, subject only to service conditions.
Equity awards vested:
| (Units in Thousands, Fair Value in Millions) | 2025 | 2024 | 2023 | |||||||||||||||||
| Vested Units | ||||||||||||||||||||
| Total Fair Value | $ | $ | $ | |||||||||||||||||
Changes in the nonvested portion of equity award units:
| (Units in Thousands) | Units | Weighted Average Grant Date Fair Value | ||||||||||||
| Nonvested Units at Jan. 1, 2025 | $ | |||||||||||||
| Granted | ||||||||||||||
| Forfeited | ( | |||||||||||||
| Vested | ( | |||||||||||||
| Dividend equivalents | ||||||||||||||
| Nonvested Units at Dec. 31, 2025 | ||||||||||||||
Liability awards granted:
| (In Thousands) | 2025 | 2024 | 2023 | |||||||||||||||||
Awards granted (a) | ||||||||||||||||||||
(a)All grants contain performance and/or market conditions.
Liability awards settled:
| (Units In Thousands, Settlement Amount in Millions) | 2025 | 2024 | 2023 | |||||||||||||||||
| Awards settled | ||||||||||||||||||||
| Settlement amount (cash, common stock and deferred amounts) | $ | $ | $ | |||||||||||||||||
The amount of cash used to settle liability awards in 2025 was $2 million.
Stock Equivalent Units — Non-employee members of Xcel Energy‘s Board of Directors may elect to receive their annual equity grant as stock equivalent units in lieu of common stock. Each unit’s value is equal to one share of common stock. The annual equity grant is vested as of the date of each member’s election to the Board of Directors; there is no further service or other condition. Directors may also elect to receive their fees as stock equivalent units in lieu of cash. Stock equivalent units are payable as a distribution of common stock upon a director’s termination of service.
Stock equivalent units granted:
| (Units in Thousands) | 2025 | 2024 | 2023 | |||||||||||||||||
| Granted units | ||||||||||||||||||||
| Weighted average grant date fair value | $ | $ | $ | |||||||||||||||||
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Changes in stock equivalent units:
| (Units in Thousands) | Units | Weighted Average Grant Date Fair Value | ||||||||||||
| Stock equivalent units at Jan. 1, 2025 | $ | |||||||||||||
| Granted | ||||||||||||||
| Units distributed | ( | |||||||||||||
| Dividend equivalents | ||||||||||||||
| Stock equivalent units at Dec. 31, 2025 | ||||||||||||||
Share-Based Compensation Expense — Award settlement determination (cash or share settlement) is made by Xcel Energy, not the participants. Equity awards have not been previously settled in cash and Xcel Energy plans to continue electing share settlement. The grant date fair value of equity awards is expensed over the service period.
Awards with history of past settlement in cash or features that result in normal course cash settlement are accounted for as liability awards. For liability awards, the fair value expensed over the service period is remeasured periodically based on the expected cash settlement amounts.
Compensation costs related to share-based awards:
| (Millions of Dollars) | 2025 | 2024 | 2023 | |||||||||||||||||
Cost for share-based awards (a) | $ | $ | $ | |||||||||||||||||
| Tax benefit recognized in income | ||||||||||||||||||||
(a)Compensation costs for share-based payments are included in O&M expense. Amount for equity awards (non-cash) was $46 million, $33 million and $25 million in 2025, 2024 and 2023, respectively.
There was approximately $52 million and $38 million as of Dec. 31, 2025 and 2024, respectively, of total unrecognized compensation cost related to nonvested share-based compensation awards. Xcel Energy expects to recognize this amount over a weighted average period of 1.7 years.
9. Earnings Per Share | ||
Basic EPS was computed by dividing the earnings available to common shareholders by the weighted average number of common shares outstanding. Diluted EPS was computed by dividing the earnings available to common shareholders by the diluted weighted average number of common shares outstanding.
Diluted EPS reflects the potential dilution that could occur if securities or other agreements to issue common stock (i.e., common stock equivalents) were settled. The weighted average number of potentially dilutive shares outstanding used to calculate diluted EPS is calculated using the treasury stock method.
Common Stock Equivalents — Common stock equivalents include commitments to issue common stock related to forward equity agreements, collared equity agreements and time-based equity compensation awards.
Stock equivalent units granted to Xcel Energy’s Board of Directors are included in common shares outstanding upon grant date as there is no further service, performance or market condition following the grant of these awards. Restricted stock issued to employees under the Executive Annual Incentive Award Plan is included in common shares outstanding when granted.
Share-based compensation arrangements for which there is currently no dilutive impact to EPS include the following:
•Equity awards subject to a performance condition; included in common shares outstanding when all necessary conditions for settlement have been satisfied by the end of the reporting period.
•Liability awards subject to a performance condition; any portions settled in shares are included in common shares outstanding upon settlement.
Common shares outstanding used in the basic and diluted EPS computation:
| (Shares in Millions) | 2025 | 2024 | 2023 | |||||||||||||||||
| Basic | ||||||||||||||||||||
Diluted (a) | ||||||||||||||||||||
(a)Diluted common shares outstanding included common stock equivalents of 2.1 million, 0.5 million, and 0.3 million shares for 2025, 2024 and 2023, respectively.
10. Fair Value of Financial Assets and Liabilities | ||
Fair Value Measurements
Accounting guidance for fair value measurements and disclosures provides a hierarchical framework for disclosing the observability of the inputs utilized in measuring assets and liabilities at fair value.
•Level 1 — Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. The types of assets and liabilities included in Level 1 are actively traded instruments with observable actual trading prices.
•Level 2 — Pricing inputs are other than actual trading prices in active markets but are either directly or indirectly observable as of the reporting date. The types of assets and liabilities included in Level 2 are typically either comparable to actively traded securities or contracts or priced with models using highly observable inputs.
•Level 3 — Significant inputs to pricing have little or no observability as of the reporting date. The types of assets and liabilities included in Level 3 include those valued with models requiring significant judgment or estimation.
Specific valuation methods include:
Investments in equity securities and other funds — Equity securities are valued using quoted prices in active markets. The fair values for commingled funds and partnerships are measured using NAVs. The investments in commingled funds may be redeemed for NAV with proper notice. Private equity commingled funds require approval of the fund for any unscheduled redemption, and such redemptions may be approved or denied by the fund at its sole discretion. Unscheduled distributions from real estate commingled funds may be redeemed with proper notice, however, withdrawals may be delayed or discounted as a result of fund illiquidity.
Investments in debt securities — Fair values for debt securities are determined by a third party pricing service using recent trades and observable spreads from benchmark interest rates for similar securities.
Interest rate derivatives — Fair values of interest rate derivatives are based on broker quotes that utilize current market interest rate forecasts.
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Commodity derivatives — Methods used to measure the fair value of commodity derivative forwards and options utilize forward prices and volatilities, as well as pricing adjustments for specific delivery locations, and are generally assigned a Level 2 classification. When contracts relate to inactive delivery locations or extend to periods beyond those readily observable on active exchanges, the significance of the use of less observable inputs on a valuation is evaluated and may result in Level 3 classification.
Electric commodity derivatives held by NSP-Minnesota and SPS include transmission congestion instruments, generally referred to as FTRs. FTRs purchased from an RTO are financial instruments that entitle or obligate the holder to monthly revenues or charges based on transmission congestion across a given transmission path.
The values of these instruments are derived from, and designed to offset, the costs of transmission congestion. In addition to overall transmission load, congestion is also influenced by the operating schedules of power plants and the consumption of electricity pertinent to a given transmission path. Unplanned plant outages, scheduled plant maintenance, changes in the relative costs of fuels used in generation, weather and overall changes in demand for electricity can each impact the operating schedules of the power plants on the transmission grid and the value of these instruments.
FTRs are recognized at fair value and adjusted each period prior to settlement. Given the limited observability of certain variables underlying the reported auction values of FTRs, these fair value measurements have been assigned a Level 3 classification.
Net congestion costs, including the impact of FTR settlements, are shared through fuel and purchased energy cost recovery mechanisms. As such, the fair value of the unsettled instruments (i.e., derivative asset or liability) is offset/deferred as a regulatory asset or liability.
Non-Derivative Fair Value Measurements
Nuclear Decommissioning Fund
The NRC requires NSP-Minnesota to maintain a portfolio of investments to fund the costs of decommissioning its nuclear generating plants. Assets of the nuclear decommissioning fund are legally restricted for the purpose of decommissioning these facilities. The fund contains cash equivalents, debt securities, equity securities and other investments. NSP-Minnesota uses the MPUC approved asset allocation for the investment targets by asset class for the qualified trust.
NSP-Minnesota recognizes the costs of funding the decommissioning over the lives of the nuclear plants, assuming rate recovery of all costs. Realized and unrealized gains on fund investments over the life of the fund are deferred as an offset of NSP-Minnesota’s regulatory asset or as a regulatory liability (dependent on funding status) for nuclear decommissioning costs. Consequently, any realized and unrealized gains and losses on securities in the nuclear decommissioning fund are deferred as a component of the regulatory asset/liability.
Unrealized gains for the nuclear decommissioning fund were $1.8 billion and $1.4 billion as of Dec. 31, 2025 and 2024, respectively, and unrealized losses were $47 million and $49 million as of Dec. 31, 2025 and 2024, respectively.
Non-derivative instruments with recurring fair value measurements in the nuclear decommissioning fund:
| Dec. 31, 2025 | ||||||||||||||||||||||||||||||||||||||
| Fair Value | ||||||||||||||||||||||||||||||||||||||
| (Millions of Dollars) | Cost | Level 1 | Level 2 | Level 3 | NAV | Total | ||||||||||||||||||||||||||||||||
Nuclear decommissioning fund (a) | ||||||||||||||||||||||||||||||||||||||
| Cash equivalents | $ | $ | $ | $ | $ | $ | ||||||||||||||||||||||||||||||||
| Commingled funds | ||||||||||||||||||||||||||||||||||||||
| Debt securities | ||||||||||||||||||||||||||||||||||||||
| Equity securities | ||||||||||||||||||||||||||||||||||||||
| Total | $ | $ | $ | $ | $ | $ | ||||||||||||||||||||||||||||||||
(a)Reported in nuclear decommissioning fund and other investments on the consolidated balance sheets, which also includes $285 million of equity method investments and $164 million of rabbi trust assets and other miscellaneous investments.
| Dec. 31, 2024 | ||||||||||||||||||||||||||||||||||||||
| Fair Value | ||||||||||||||||||||||||||||||||||||||
| (Millions of Dollars) | Cost | Level 1 | Level 2 | Level 3 | NAV | Total | ||||||||||||||||||||||||||||||||
Nuclear decommissioning fund (a) | ||||||||||||||||||||||||||||||||||||||
| Cash equivalents | $ | $ | $ | $ | $ | $ | ||||||||||||||||||||||||||||||||
| Commingled funds | ||||||||||||||||||||||||||||||||||||||
| Debt securities | ||||||||||||||||||||||||||||||||||||||
| Equity securities | ||||||||||||||||||||||||||||||||||||||
| Total | $ | $ | $ | $ | $ | $ | ||||||||||||||||||||||||||||||||
(a)Reported in nuclear decommissioning fund and other investments on the consolidated balance sheets, which also includes $246 million of equity investments in unconsolidated subsidiaries and $156 million of rabbi trust assets and other miscellaneous investments.
For the years ended Dec. 31, 2025 and 2024, there were immaterial Level 3 nuclear decommissioning fund investments or transfer of amounts between levels.
Contractual maturity dates of debt securities in the nuclear decommissioning fund as of Dec. 31, 2025:
| Final Contractual Maturity | ||||||||||||||||||||||||||||||||
| (Millions of Dollars) | Due in 1 Year or Less | Due in 1 to 5 Years | Due in 5 to 10 Years | Due after 10 Years | Total | |||||||||||||||||||||||||||
| Debt securities | $ | $ | $ | $ | $ | |||||||||||||||||||||||||||
Rabbi Trusts
Xcel Energy has established rabbi trusts to provide partial funding for future deferred compensation plan distributions. The fair value of assets held in the rabbi trusts were $107 million and $96 million at Dec. 31, 2025 and 2024, respectively, comprised of cash equivalents and mutual funds (level 1 valuation methods). Amounts are reported in nuclear decommissioning fund and other investments on the consolidated balance sheet.
Derivative Activities and Fair Value Measurements
Xcel Energy enters into derivative instruments, including forward contracts, futures, swaps and options, for trading purposes and to manage risk in connection with changes in interest rates, and utility commodity prices.
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Interest Rate Derivatives — Xcel Energy enters into contracts that effectively fix the interest rate on a specified principal amount of a hypothetical future debt issuance. These financial swaps net settle based on changes in a specified benchmark interest rate, acting as a hedge of changes in market interest rates that will impact specified anticipated debt issuances. These derivative instruments are designated as cash flow hedges for accounting purposes, with changes in fair value prior to occurrence of the hedged transactions recorded as other comprehensive income.
As of Dec. 31, 2025, accumulated other comprehensive loss related to interest rate derivatives included $2 million of net losses expected to be reclassified into earnings during the next 12 months as the hedged transactions impact earnings. As of Dec. 31, 2025, Xcel Energy had unsettled interest rate derivatives with a notional amount of $240 million.
See Note 13 for the financial impact of qualifying interest rate cash flow hedges on Xcel Energy’s accumulated other comprehensive loss included in the consolidated statements of common stockholder’s equity and in the consolidated statements of comprehensive income.
Wholesale and Commodity Trading — Xcel Energy Inc.’s utility subsidiaries conduct various wholesale and commodity trading activities, including the purchase and sale of electric capacity, energy, energy-related instruments and natural gas-related instruments, including derivatives. Xcel Energy is allowed to conduct these activities within guidelines and limitations as approved by its risk management committee, comprised of management personnel not directly involved in the activities governed by this policy.
Results of derivative instrument transactions entered into for trading purposes are presented in the consolidated statements of income as electric revenues, net of any sharing with customers. These activities are not intended to mitigate commodity price risk associated with regulated electric and natural gas operations. Sharing of these margins is determined through state regulatory proceedings as well as the operation of the FERC-approved joint operating agreement.
Commodity Derivatives — Xcel Energy enters into derivative instruments to manage variability of future cash flows from changes in commodity prices in its electric and natural gas operations. This could include the purchase or sale of energy or energy-related products, natural gas to generate electric energy, natural gas for resale and FTRs.
The most significant derivative positions outstanding at Dec. 31, 2025 and 2024 for this purpose relate to FTR instruments administered by MISO and SPP. These instruments are intended to offset the impacts of transmission system congestion.
When Xcel Energy enters into derivative instruments that mitigate commodity price risk on behalf of electric and natural gas customers, the instruments are not typically designated as qualifying hedging transactions. The classification of unrealized losses or gains on these instruments as a regulatory asset or liability, if applicable, is based on approved regulatory recovery mechanisms.
As of Dec. 31, 2025, Xcel Energy had no commodity contracts designated as cash flow hedges.
Gross notional amounts of commodity forwards, options and FTRs:
(Amounts in Millions) (a)(b) | Dec. 31, 2025 | Dec. 31, 2024 | ||||||||||||
| MWh of electricity | ||||||||||||||
| MMBtu of natural gas | ||||||||||||||
(a)Not reflective of net positions in the underlying commodities.
(b)Notional amounts for options included on a gross basis but weighted for the probability of exercise.
Consideration of Credit Risk and Concentrations — Xcel Energy continuously monitors the creditworthiness of counterparties to its interest rate derivatives and commodity derivative contracts prior to settlement and assesses each counterparty’s ability to perform on the transactions set forth in the contracts. Impact of credit risk was immaterial to the fair value of unsettled commodity derivatives presented on the consolidated balance sheets.
Xcel Energy’s utility subsidiaries’ often have significant concentrations of credit risk with particular entities or industries in their wholesale, trading and non-trading commodity activities.
As of Dec. 31, 2025, three of Xcel Energy’s ten most significant counterparties for these activities, comprising $22 million or 14 % of this credit exposure, had investment grade credit ratings from S&P Global Ratings, Moody’s Investor Services or Fitch Ratings.
Credit Related Contingent Features — Contract provisions for derivative instruments that the utility subsidiaries enter, including those accounted for as normal purchase and normal sale contracts and therefore not reflected on the consolidated balance sheets, may require the posting of collateral or settlement of the contracts for various reasons, including if the applicable utility subsidiary’s credit ratings are downgraded below its investment grade credit rating by any of the major credit rating agencies.
As of Dec. 31, 2025 and 2024, there were $7 million and $11 million, respectively, of derivative liabilities with such underlying contract provisions, respectively.
Certain contracts also contain cross default provisions that may require the posting of collateral or settlement of the contracts if there was a failure under other financing arrangements related to payment terms or other covenants.
As of Dec. 31, 2025 and 2024, there were approximately $62 million and $69 million of derivative liabilities with such underlying contract provisions, respectively.
Certain derivative instruments are also subject to contract provisions that contain adequate assurance clauses. These provisions allow counterparties to seek performance assurance, including cash collateral, in the event that a given utility subsidiary’s ability to fulfill its contractual obligations is reasonably expected to be impaired.
Xcel Energy had no
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Recurring Derivative Fair Value Measurements
Impact of derivative activity:
| Pre-Tax Fair Value Gains (Losses) Recognized During the Period in: | ||||||||||||||
| (Millions of Dollars) | Accumulated Other Comprehensive Loss | Regulatory (Assets) and Liabilities | ||||||||||||
| Year Ended Dec. 31, 2025 | ||||||||||||||
| Derivatives designated as cash flow hedges | ||||||||||||||
| Interest rate | $ | $ | ||||||||||||
| Total | $ | $ | ||||||||||||
| Other derivative instruments | ||||||||||||||
| Electric commodity | $ | $ | ||||||||||||
| Natural gas commodity | ( | |||||||||||||
| Total | $ | $ | ||||||||||||
| Year Ended Dec. 31, 2024 | ||||||||||||||
| Interest rate | $ | $ | ||||||||||||
| Total | $ | $ | ||||||||||||
| Other derivative instruments | ||||||||||||||
| Electric commodity | $ | $ | ||||||||||||
| Natural gas commodity | ||||||||||||||
| Total | $ | $ | ||||||||||||
| Year Ended Dec. 31, 2023 | ||||||||||||||
| Interest rate | $ | ( | $ | |||||||||||
| Total | $ | ( | $ | |||||||||||
| Other derivative instruments | ||||||||||||||
| Electric commodity | $ | $ | ( | |||||||||||
| Natural gas commodity | ( | |||||||||||||
| Total | $ | $ | ( | |||||||||||
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| Pre-Tax (Gains) Losses Reclassified into Income During the Period from: | Pre-Tax Gains (Losses) Recognized During the Period in Income | ||||||||||||||||||||||
| (Millions of Dollars) | Accumulated Other Comprehensive Loss | Regulatory Assets and (Liabilities) | |||||||||||||||||||||
| Year Ended Dec. 31, 2025 | |||||||||||||||||||||||
| Derivatives designated as cash flow hedges | |||||||||||||||||||||||
| Interest rate | $ | (a) | $ | $ | |||||||||||||||||||
| Total | $ | $ | $ | ||||||||||||||||||||
| Other derivative instruments | |||||||||||||||||||||||
| Commodity trading | $ | $ | $ | ( | (b) | ||||||||||||||||||
| Electric commodity | ( | (c) | |||||||||||||||||||||
| Natural gas commodity | ( | (d)(e) | |||||||||||||||||||||
| Total | $ | $ | ( | $ | ( | ||||||||||||||||||
| Year Ended Dec. 31, 2024 | |||||||||||||||||||||||
| Derivatives designated as cash flow hedges | |||||||||||||||||||||||
| Interest rate | $ | (a) | $ | $ | |||||||||||||||||||
| Total | $ | $ | $ | ||||||||||||||||||||
| Other derivative instruments | |||||||||||||||||||||||
| Commodity trading | $ | $ | $ | ( | (b) | ||||||||||||||||||
| Electric commodity | ( | (c) | |||||||||||||||||||||
| Natural gas commodity | ( | (d)(e) | |||||||||||||||||||||
| Total | $ | $ | $ | ( | |||||||||||||||||||
| Year Ended Dec. 31, 2023 | |||||||||||||||||||||||
| Derivatives designated as cash flow hedges | |||||||||||||||||||||||
| Interest rate | $ | (a) | $ | $ | |||||||||||||||||||
| Total | $ | $ | $ | ||||||||||||||||||||
| Other derivative instruments | |||||||||||||||||||||||
| Commodity trading | $ | $ | $ | ( | (b) | ||||||||||||||||||
| Electric commodity | (c) | ||||||||||||||||||||||
| Natural gas commodity | (d) | ( | (d)(e) | ||||||||||||||||||||
| Total | $ | $ | $ | ( | |||||||||||||||||||
(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 $4 million of 2025 and $3 million of 2024 losses recorded to electric fuel and purchased power, amounts are recorded to cost of natural gas sold and transported. Amounts are subject to cost-recovery mechanisms and reclassified out of income to a regulatory asset, as appropriate.
Xcel Energy had no
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Derivative assets and liabilities measured at fair value on a recurring basis were as follows:
| Dec. 31, 2025 | Dec. 31, 2024 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Fair Value | Fair Value Total | Netting (a) | Total | Fair Value | Fair Value Total | Netting (a) | Total | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| (Millions of Dollars) | Level 1 | Level 2 | Level 3 | Level 1 | Level 2 | Level 3 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Current derivative assets | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Derivatives designated as cash flow hedges: | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Interest rate | $ | $ | $ | $ | $ | $ | $ | $ | $ | $ | $ | $ | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Other derivative instruments: | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Commodity trading | $ | $ | $ | $ | $ | ( | $ | $ | $ | $ | $ | $ | ( | $ | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Electric commodity | ( | ( | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Natural gas commodity | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Total current derivative assets | $ | $ | $ | $ | $ | ( | $ | $ | $ | $ | $ | $ | ( | $ | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Noncurrent derivative assets | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Other derivative instruments: | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Commodity trading | $ | $ | $ | $ | $ | ( | $ | $ | $ | $ | $ | $ | ( | $ | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Total noncurrent derivative assets | $ | $ | $ | $ | $ | ( | $ | $ | $ | $ | $ | $ | ( | $ | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Dec. 31, 2025 | Dec. 31, 2024 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Fair Value | Fair Value Total | Netting (a) | Total | Fair Value | Fair Value Total | Netting (a) | Total | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| (Millions of Dollars) | Level 1 | Level 2 | Level 3 | Level 1 | Level 2 | Level 3 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Current derivative liabilities | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Other derivative instruments: | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Commodity trading | ( | ( | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Electric commodity | ( | ( | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Natural gas commodity | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Total current derivative liabilities | $ | $ | $ | $ | $ | ( | $ | $ | $ | $ | $ | ( | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
PPAs (b) | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Current derivative instruments | $ | $ | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Noncurrent derivative liabilities | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Other derivative instruments: | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Commodity trading | $ | $ | $ | $ | $ | ( | $ | $ | $ | $ | $ | $ | ( | $ | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Total noncurrent derivative liabilities | $ | $ | $ | $ | $ | ( | $ | $ | $ | $ | $ | ( | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
PPAs (b) | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Noncurrent derivative instruments | $ | $ | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
(a)Xcel Energy nets derivative instruments and related collateral on its consolidated balance sheets when supported by a legally enforceable master netting agreement. At Dec. 31, 2025 and 2024, derivative assets and liabilities include no 4 million and $2 million, respectively. Counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements.
(b)Xcel Energy currently applies the normal purchase exception to qualifying PPAs. Balance relates to specific contracts that were previously recognized at fair value prior to applying the normal purchase exception, and are being amortized over the remaining contract lives along with the offsetting regulatory assets and liabilities.
Changes in Level 3 commodity derivatives:
| Year Ended Dec. 31 | ||||||||||||||||||||
| (Millions of Dollars) | 2025 | 2024 | 2023 | |||||||||||||||||
| Balance at Jan. 1 | $ | $ | $ | |||||||||||||||||
Purchases (a) | ||||||||||||||||||||
Settlements (a) | ( | ( | ( | |||||||||||||||||
| Net transactions recorded during the period: | ||||||||||||||||||||
(Losses) gains recognized in earnings (b) | ( | ( | ||||||||||||||||||
Net gains (losses) recognized as regulatory assets and liabilities (a) | ( | |||||||||||||||||||
| Balance at Dec. 31 | $ | $ | $ | |||||||||||||||||
(a)Relates primarily to NSP-Minnesota and SPS FTR instruments administered by MISO and SPP, respectively.
(b)Relates to commodity trading and is subject to substantial offsetting losses and gains on derivative instruments categorized as levels 1 and 2 in the income statement. See above tables for the income statement impact of derivative activity, including commodity trading gains and losses.
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Fair Value of Long-Term Debt
As of Dec. 31, other financial instruments for which the carrying amount did not equal fair value:
| 2025 | 2024 | |||||||||||||||||||||||||
| (Millions of Dollars) | Carrying Amount | Fair Value | Carrying Amount | Fair Value | ||||||||||||||||||||||
| Long-term debt, including current portion | $ | $ | $ | $ | ||||||||||||||||||||||
Fair value of Xcel Energy’s long-term debt is estimated based on recent trades and observable spreads from benchmark interest rates for similar securities. Fair value estimates are based on information available to management as of Dec. 31, 2025 and 2024, and given the observability of the inputs, fair values presented for long-term debt were assigned as Level 2.
11. Benefit Plans and Other Postretirement Benefits | ||
Pension and Postretirement Health Care Benefits
Xcel Energy has several noncontributory, qualified, defined benefit pension plans that cover almost all employees. All newly hired or rehired employees participate under the Cash Balance formula, which is based on pay credits using a percentage of annual eligible pay and annual interest credits.
The average annual interest crediting rates for these plans was 4.76 , 4.90 and 4.72 % in 2025, 2024, and 2023, respectively.
Some employees may participate under legacy formulas such as the traditional final average pay or pension equity. Xcel Energy’s policy is to fully fund into an external trust the actuarially determined pension costs subject to the limitations of applicable employee benefit and tax laws.
In addition to the qualified pension plans, Xcel Energy maintains a nonqualified pension plan, which provides benefits for compensation that is in excess of the limits applicable to the qualified pension plans, with distributions funded by Xcel Energy’s consolidated operating cash flows.
Obligations of the nonqualified plan as of Dec. 31, 2025 and 2024 were $13 million. Xcel Energy recognized net benefit cost for the nonqualified plan of $3 million in 2025 and $2 million in 2024.
Xcel Energy’s postretirement health care benefit plan is a continuation of certain welfare benefit programs for current employees. A full-time employee’s date of hire or a retiree’s date of retirement determine eligibility for each of the programs.
Xcel Energy’s investment-return assumption considers the expected long-term performance for each of the asset classes in its pension and postretirement health care portfolio. Xcel Energy considers the historical returns achieved by its asset portfolios over long time periods, as well as the long-term projected return levels from investment experts.
Pension cost determination assumes a forecasted mix of investment types over the long-term.
•Investment returns in 2025 were above the assumed level of 7.13 %.
•Investment returns in 2024 were below the assumed level of 6.93 %.
•Investment returns in 2023 were above the assumed level of 6.93 %.
•In 2026, expected investment-return assumption is 7.13 %.
Pension plan and postretirement benefit assets are invested in a portfolio according to Xcel Energy’s return, liquidity and diversification objectives to provide a source of funding for plan obligations and minimize contributions to the plan, within appropriate levels of risk.
The principal mechanism for achieving these objectives is the asset allocation given the long-term risk, return, correlation and liquidity characteristics of each particular asset class.
There were no significant concentrations of risk in any industry, index, or entity. Market volatility can impact even well-diversified portfolios and significantly affect the return levels achieved by the assets in any year.
State agencies also have issued guidelines to the funding of postretirement benefit costs. SPS is required to fund postretirement benefit plans for Texas and New Mexico equal to amounts collected in rates. These assets are invested in a manner consistent with the investment strategy for the pension plan.
Xcel Energy’s ongoing investment strategy is based on plan-specific investment recommendations that seek to minimize potential investment and interest rate risk as a plan’s funded status increases over time.
The investment recommendations consider many factors and generally result in a greater percentage of long-duration fixed income securities being allocated to specific plans having relatively higher funded status ratios and a greater percentage of growth assets being allocated to plans having relatively lower funded status ratios.
Plan Assets
For each of the fair value hierarchy levels, Xcel Energy’s pension plan assets measured at fair value:
Dec. 31, 2025 (a) | Dec. 31, 2024 (a) | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| (Millions of Dollars) | Level 1 | Level 2 | Level 3 | Measured at NAV | Total | Level 1 | Level 2 | Level 3 | Measured at NAV | Total | ||||||||||||||||||||||||||||||||||||||||||||||||||||
| Cash equivalents | $ | $ | $ | $ | $ | $ | $ | $ | $ | $ | ||||||||||||||||||||||||||||||||||||||||||||||||||||
Commingled funds (b) | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Debt securities | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Equity securities | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Partnerships (b) | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Other | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Total | $ | $ | $ | $ | $ | $ | $ | $ | $ | $ | ||||||||||||||||||||||||||||||||||||||||||||||||||||
(a)See Note 10 for further information regarding fair value measurement inputs and methods.
(b)Prior period amounts have been reclassified to conform with current year presentation .
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For each of the fair value hierarchy levels, Xcel Energy’s postretirement benefit plan assets that were measured at fair value:
Dec. 31, 2025 (a) | Dec. 31, 2024 (a) | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| (Millions of Dollars) | Level 1 | Level 2 | Level 3 | Measured at NAV | Total | Level 1 | Level 2 | Level 3 | Measured at NAV | Total | ||||||||||||||||||||||||||||||||||||||||||||||||||||
| Cash equivalents | $ | $ | $ | $ | $ | $ | $ | $ | $ | $ | ||||||||||||||||||||||||||||||||||||||||||||||||||||
| Insurance contracts | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Commingled funds (b) | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Debt securities | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Partnerships (b) | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Other | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Total | $ | $ | $ | $ | $ | $ | $ | $ | $ | $ | ||||||||||||||||||||||||||||||||||||||||||||||||||||
(a)See Note 10 for further information on fair value measurement inputs and methods.
(b)Prior period amounts have been reclassified to conform with current year presentation .
Funded Status — Comparisons of the actuarially computed benefit obligation, changes in plan assets and funded status of the pension and postretirement health care plans for Xcel Energy are as follows:
| Pension Benefits | Postretirement Benefits | |||||||||||||||||||||||||
| (Millions of Dollars) | 2025 | 2024 | 2025 | 2024 | ||||||||||||||||||||||
| Change in Benefit Obligation: | ||||||||||||||||||||||||||
| Obligation at Jan. 1 | $ | $ | $ | $ | ||||||||||||||||||||||
| Service cost | ||||||||||||||||||||||||||
| Interest cost | ||||||||||||||||||||||||||
| Actuarial loss (gain) | ( | |||||||||||||||||||||||||
| Plan participants’ contributions | ||||||||||||||||||||||||||
| Medicare subsidy reimbursements | ||||||||||||||||||||||||||
| Benefit payments | ( | ( | (a) | ( | ( | |||||||||||||||||||||
| Obligation at Dec. 31 | $ | $ | $ | $ | ||||||||||||||||||||||
| Change in Fair Value of Plan Assets: | ||||||||||||||||||||||||||
| Fair value of plan assets at Jan. 1 | $ | $ | $ | $ | ||||||||||||||||||||||
| Actual return on plan assets | ||||||||||||||||||||||||||
| Employer contributions | ||||||||||||||||||||||||||
| Plan participants’ contributions | ||||||||||||||||||||||||||
| Benefit payments | ( | ( | ( | ( | ||||||||||||||||||||||
| Fair value of plan assets at Dec. 31 | ||||||||||||||||||||||||||
| Funded status of plans at Dec. 31 | $ | ( | $ | ( | $ | ( | $ | ( | ||||||||||||||||||
| Amounts recognized in the Consolidated Balance Sheet at Dec. 31: | ||||||||||||||||||||||||||
| Noncurrent assets | $ | $ | $ | $ | ||||||||||||||||||||||
| Current liabilities | ( | ( | ||||||||||||||||||||||||
| Noncurrent liabilities | ( | ( | ( | ( | ||||||||||||||||||||||
| Net amounts recognized | $ | ( | $ | ( | $ | ( | $ | ( | ||||||||||||||||||
(a)Includes $168 million of lump-sum benefit payments used in the determination of settlement charges in 2024.
| Pension Benefits | Postretirement Benefits | |||||||||||||||||||||||||
| Significant Assumptions Used to Measure Benefit Obligations: | 2025 | 2024 | 2025 | 2024 | ||||||||||||||||||||||
| Discount rate for year-end valuation | % | % | % | % | ||||||||||||||||||||||
| Expected average long-term increase in compensation level | % | % | N/A | N/A | ||||||||||||||||||||||
| Mortality table | PRI-2012 | PRI-2012 | PRI-2012 | PRI-2012 | ||||||||||||||||||||||
| Health care costs trend rate — initial: Pre-65 | N/A | N/A | % | % | ||||||||||||||||||||||
| Health care costs trend rate — initial: Post-65 | N/A | N/A | % | % | ||||||||||||||||||||||
| Ultimate trend assumption — initial: Pre-65 | N/A | N/A | % | % | ||||||||||||||||||||||
| Ultimate trend assumption — initial: Post-65 | N/A | N/A | % | % | ||||||||||||||||||||||
| Years until ultimate trend is reached | N/A | N/A | ||||||||||||||||||||||||
Accumulated benefit obligation for the pension plan was $2,624 million and $2,554 million as of Dec. 31, 2025 and 2024, respectively.
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Net Periodic Benefit Cost — Net periodic benefit cost, other than the service cost component, is included in other income (expense) in the consolidated statements of income.
Components of net periodic benefit cost and amounts recognized in other comprehensive income and regulatory assets and liabilities:
| Pension Benefits | Postretirement Benefits | |||||||||||||||||||||||||||||||||||||
| (Millions of Dollars) | 2025 | 2024 | 2023 | 2025 | 2024 | 2023 | ||||||||||||||||||||||||||||||||
| Service cost | $ | $ | $ | $ | $ | $ | ||||||||||||||||||||||||||||||||
| Interest cost | ||||||||||||||||||||||||||||||||||||||
| Expected return on plan assets | ( | ( | ( | ( | ( | ( | ||||||||||||||||||||||||||||||||
| Amortization of prior service credit | ( | ( | ( | ( | ||||||||||||||||||||||||||||||||||
| Amortization of net loss | ||||||||||||||||||||||||||||||||||||||
Settlement charge (a) | ||||||||||||||||||||||||||||||||||||||
| Net periodic pension cost | ||||||||||||||||||||||||||||||||||||||
| Effects of regulation | ( | |||||||||||||||||||||||||||||||||||||
| Net benefit cost recognized for financial reporting | $ | $ | $ | $ | $ | $ | ||||||||||||||||||||||||||||||||
| Significant Assumptions Used to Measure Costs: | ||||||||||||||||||||||||||||||||||||||
| Discount rate | % | % | % | % | % | % | ||||||||||||||||||||||||||||||||
| Expected average long-term increase in compensation level | ||||||||||||||||||||||||||||||||||||||
| Expected average long-term rate of return on assets | ||||||||||||||||||||||||||||||||||||||
(a)A settlement charge is required when the amount of all lump-sum distributions during the year is greater than the sum of the service and interest cost components of the annual net periodic pension cost. In 2024, as a result of lump-sum distributions during the plan year, Xcel Energy recorded a total pension settlement charge of $67 million, the majority of which was not recognized due to the effects of regulation. A total of $8 million was recorded in the consolidated statements of income in 2024. There were no
| Pension Benefits | Postretirement Benefits | |||||||||||||||||||||||||
| (Millions of Dollars) | 2025 | 2024 | 2025 | 2024 | ||||||||||||||||||||||
| Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost: | ||||||||||||||||||||||||||
| Net loss | $ | $ | $ | $ | ||||||||||||||||||||||
| Prior service credit | ( | ( | ||||||||||||||||||||||||
| Total | $ | $ | $ | $ | ||||||||||||||||||||||
| Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost Have Been Recorded as Follows Based Upon Expected Recovery in Rates: | ||||||||||||||||||||||||||
| Current regulatory assets | $ | $ | $ | $ | ||||||||||||||||||||||
| Noncurrent regulatory assets | ||||||||||||||||||||||||||
| Current regulatory liabilities | ( | ( | ||||||||||||||||||||||||
| Noncurrent regulatory liabilities | ( | ( | ||||||||||||||||||||||||
| Deferred income taxes | ||||||||||||||||||||||||||
| Net-of-tax accumulated other comprehensive income | ||||||||||||||||||||||||||
| Total | $ | $ | $ | $ | ||||||||||||||||||||||
| Measurement date | Dec. 31, 2025 | Dec. 31, 2024 | Dec. 31, 2025 | Dec. 31, 2024 | ||||||||||||||||||||||
Cash Flows — Funding requirements can be impacted by changes to actuarial assumptions, actual asset levels and other calculations prescribed by the requirements of income tax and other pension-related regulations. Required contributions were made in 2023 - 2026 to meet minimum funding requirements.
Voluntary and required pension funding contributions:
•$75 million in January 2026.
•$125 million in 2025.
•$100 million in 2024.
•$50 million in 2023.
The postretirement health care plans have no funding requirements other than fulfilling benefit payment obligations when claims are presented and approved. Additional cash funding requirements are prescribed by certain state and federal rate regulatory authorities.
Voluntary postretirement funding contributions:
•$8 million expected during 2026.
•$13 million during 2025.
•$11 million during 2024.
•$11 million during 2023.
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Targeted asset allocations:
| Pension Benefits | Postretirement Benefits | |||||||||||||||||||||||||
| 2025 | 2024 | 2025 | 2024 | |||||||||||||||||||||||
| Long-duration fixed income securities | % | % | % | % | ||||||||||||||||||||||
| Domestic and international equity securities | ||||||||||||||||||||||||||
| Alternative investments | ||||||||||||||||||||||||||
| Short-to-intermediate fixed income securities | ||||||||||||||||||||||||||
| Cash | ||||||||||||||||||||||||||
| Total | % | % | % | % | ||||||||||||||||||||||
The asset allocations above reflect target allocations approved in the calendar year to take effect in the subsequent year.
Plan Amendments — There were no significant plan amendments made in 2025 and 2024 which affected the pension or postretirement benefit obligation.
In 2023, Xcel Energy amended the Xcel Energy Pension Plan and Xcel Energy Inc. Nonbargaining Pension Plan (South) to reduce supplemental social security benefits for all active participants on and after Jan. 1, 2024.
Projected Benefit Payments
Xcel Energy’s projected benefit payments:
| (Millions of Dollars) | Projected Pension Benefit Payments | Gross Projected Postretirement Health Care Benefit Payments | Expected Medicare Part D Subsidies | Net Projected Postretirement Health Care Benefit Payments | ||||||||||||||||||||||
| 2026 | $ | $ | $ | $ | ||||||||||||||||||||||
| 2027 | ||||||||||||||||||||||||||
| 2028 | ||||||||||||||||||||||||||
| 2029 | ||||||||||||||||||||||||||
| 2030 | ||||||||||||||||||||||||||
| 2031-2035 | ||||||||||||||||||||||||||
Voluntary Retirement Program
Incremental to amounts presented above for postretirement benefits, Xcel Energy has postemployment costs and obligations for its Voluntary Retirement Program, under which approximately 400 eligible non-bargaining employees retired in the fourth quarter of 2023.
Utilizing employee information and the following inputs, unfunded obligations of $22 million and $29 million for health plan subsidies and $4 million and $4 million for other medical benefits are presented in other current liabilities and noncurrent pension and employee benefit obligations in the consolidated balance sheets as of Dec. 31, 2025 and 2024, respectively.
| Significant Assumptions to Measure Benefit Obligations: | 2025 | 2024 | ||||||||||||
| Discount rate for year-end valuation | % | % | ||||||||||||
| Mortality table | PRI-2012 | PRI-2012 | ||||||||||||
| Health care costs trend rate | % | % | ||||||||||||
| Ultimate trend assumption | % | % | ||||||||||||
| Years until ultimate trend is reached | ||||||||||||||
Defined Contribution Plans
Xcel Energy maintains 401(k) and other defined contribution plans that cover most employees. Total expense to these plans was approximately $53 million in 2025, $50 million in 2024 and $49 million in 2023.
Multiemployer Plans
NSP-Minnesota and NSP-Wisconsin each contribute to several union multiemployer pension and other postretirement benefit plans, none of which are individually significant. These plans provide pension and postretirement health care benefits to certain union employees who may perform services for multiple employers and do not participate in the NSP-Minnesota and NSP-Wisconsin sponsored pension and postretirement health care plans.
Contributing to these types of plans creates risk that differs from providing benefits under NSP-Minnesota and NSP-Wisconsin sponsored plans, in that if another participating employer ceases to contribute to a multiemployer pension plan, additional unfunded obligations may need to be funded over time by remaining participating employers.
12. Commitments and Contingencies | ||
Legal
Xcel Energy is involved in various litigation matters in the ordinary course of business. The assessment of whether a loss is probable or is a reasonable possibility, and whether the loss or a range of loss is estimable, often involves a series of complex judgments about future events. Management maintains accruals for losses probable of being incurred and subject to reasonable estimation.
Management is sometimes unable to estimate an amount or range of a reasonably possible loss in certain situations, including but not limited to when (1) the damages sought are indeterminate, (2) the proceedings are in the early stages, or (3) the matters involve novel or unsettled legal theories.
In such cases, there is considerable uncertainty regarding the timing or ultimate resolution, including a possible eventual loss. For current proceedings not specifically reported herein, management does not anticipate that the ultimate liabilities, if any, would have a material effect on Xcel Energy’s consolidated financial statements. Legal fees are generally expensed as incurred.
Gas Trading Litigation — e prime is a wholly owned subsidiary of Xcel Energy. e prime was in the business of natural gas trading and marketing but has not engaged in natural gas trading or marketing activities since 2003. Multiple lawsuits involving multiple plaintiffs seeking monetary damages were commenced against e prime and its affiliates, including Xcel Energy, between 2003 and 2009 alleging fraud and anticompetitive activities in conspiring to restrain the trade of natural gas and manipulate natural gas prices. Cases were all consolidated in the U.S. District Court in Nevada.
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Marshall Wildfire Litigation — In December 2021, a wildfire ignited in Boulder County, Colorado (Marshall Fire). On June 8, 2023, the Boulder County Sheriff’s Office released its Marshall Fire Investigative Summary and Review and its supporting documents (Sheriff’s Report). According to the Sheriff’s Report, on Dec. 30, 2021, a fire ignited on a residential property in Boulder, Colorado, located in PSCo’s service territory, for reasons unrelated to PSCo’s power lines. According to the Sheriff’s Report, approximately one hour and 20 minutes after the first ignition, a second fire ignited just south of the Marshall Mesa Trailhead in unincorporated Boulder County, Colorado, also located in PSCo’s service territory. According to the Sheriff’s Report, the second ignition started approximately 80 to 110 feet away from PSCo’s power lines in the area.
PSCo received notice or otherwise became aware of 307 complaints on behalf of at least 4,087 plaintiffs, most of which also named Xcel Energy Inc. and Xcel Energy Services Inc. as additional defendants, relating to the Marshall Fire. The complaints generally alleged that PSCo’s equipment ignited the Marshall Fire and asserted various causes of action under Colorado law. In addition to asserting claims against PSCo, Xcel Energy Inc. and Xcel Energy Services Inc., various plaintiffs, including insurance company plaintiffs, asserted claims against certain telecommunications companies (the Telecom Companies). In April 2025, most of the remaining plaintiffs amended their complaints to also assert claims against the Telecom Companies. In June 2025, the Boulder County District Court dismissed Xcel Energy Inc. from the complaints that named that entity as a defendant, due to lack of jurisdiction.
An initial trial on liability issues was scheduled to start in September 2025. Prior to trial, in September 2025, Xcel Energy, Qwest Corporation and Teleport Communications America, LLC reached settlement agreements in principle that resolve all claims asserted by the subrogation insurers, the public entity plaintiffs and individual plaintiffs, and require PSCo to make settlement payments of $640 million. PSCo did not admit any fault, wrongdoing or negligence in connection with these settlement agreements.
As a result of settlements as well as legal and other costs of the matter, PSCo recognized charges to earnings of $287 million and $12 million in the quarterly periods ended Sept. 30 and Dec. 31, 2025, respectively, after consideration of total costs expected to be reimbursed by insurance. As of February 2026, final settlement documentation has been executed with the subrogation insurers, the public entity plaintiffs and nearly all the individual plaintiffs, and nearly all have received payment. If complaints of the remaining individual plaintiffs who have not accepted a settlement or have otherwise stopped prosecuting their claims are not resolved, they may be subject to further litigation.
A remaining estimated liability of $5 million is presented in other current liabilities as of Dec. 31, 2025; no estimated liability was recognized as of Dec. 31, 2024. PSCo records insurance recoveries when it is deemed probable that recovery will occur, and PSCo can reasonably estimate the amount or range. Insurance receivables of $353 million related to settlements are presented in prepayments and other current assets as of Dec. 31, 2025; no such insurance receivables were recognized as of Dec. 31, 2024.
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 56 complaints, most of which have also named Xcel Energy Services Inc. as an additional defendant, relating to the Smokehouse Creek Fire Complex. The complaints, which assert claims on behalf of one or more plaintiffs, generally allege that SPS’ equipment ignited the Smokehouse Creek Fire Complex and seek compensation for losses resulting from the fire, asserting various causes of action under Texas law. In addition to seeking compensatory damages, certain of the complaints also seek exemplary damages. Of the 56 complaints, 22 have been resolved and dismissed.
SPS has received 296 claims through its claims process, net of duplicative, withdrawn and denied claims, and has reached final settlements on 223 of those claims as of the date of this filing. In addition to filed complaints and claims made through SPS’ claims process, SPS has also received information from attorneys for approximately 101 claims which have not been submitted through the claims process and have also not been filed as lawsuits and has reached settlement of 79 of those claims through mediation.
SPS has settled claims related to both of the fatalities believed to be associated with the Smokehouse Creek Fire Complex. Settlements have also been reached with the subrogated insurer plaintiffs as well as the three largest claims asserted from the fire, as measured by fire-impacted acreage. Settlements reached as of the date of this filing total $382 million of expected loss payments, of which $374 million and $35 million were paid through Dec. 31, 2025 and 2024, respectively.
In December 2025, the Texas Attorney General’s office filed a lawsuit against SPS regarding the Smokehouse Creek Fire, seeking monetary damages and civil penalties for losses to property and wildlife resulting from the fires. In February 2026, pending resolution of the lawsuit, SPS and the Texas Attorney General’s office jointly filed a temporary injunction agreeing to certain distribution pole replacement procedures, largely consistent with current procedures.
Based on the current state of the law and the facts and circumstances available as of the date of this filing, Xcel Energy has recorded $430 million of total estimated losses for the matter (before available insurance). A remaining estimated liability of $56 million and $180 million is presented in other current liabilities as of Dec. 31, 2025 and 2024, respectively.
The cumulative estimated probable losses of $430 million for complaints and claims in connection with the Smokehouse Creek Fire Complex (before available insurance) represents the total of actual settlements reached to date plus the low end of the range for remaining reasonably estimable losses, and is subject to change as additional information becomes available. This $430 million estimate does not include amounts for (i) potential penalties or fines that may be imposed by governmental entities on Xcel Energy, (ii) exemplary or punitive damages, (iii) compensation claims by federal, state, county and local government entities or agencies, (iv) unsettled compensation claims for damage to trees and oil and gas equipment, or (v) other amounts that are not reasonably estimable.
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Xcel Energy remains unable to reasonably estimate any additional loss or the upper end of the range because there are a number of unknown facts and legal considerations that may impact the amount of any potential liability, including whether additional complaints and demands may be made. In the event that SPS or Xcel Energy Services Inc. was found liable related to the litigation related to the Smokehouse Creek Fire Complex and was required to pay damages, such amounts could exceed our insurance coverage of approximately $500 million for the annual policy period and could have a material adverse effect on our financial condition, results of operations or cash flows.
The process for estimating losses associated with potential claims related to the Smokehouse Creek Fire Complex requires management to exercise significant judgment based on a number of assumptions and subjective factors, including the factors identified above and estimates based on currently available information and prior experience with wildfires. As more information becomes available, management estimates and assumptions regarding the potential financial impact of the Smokehouse Creek Fire Complex may change.
Texas law does not apply strict liability in determining an electric utility company’s liability for fire-related damages. For negligence claims under Texas law, a public utility has a duty to exercise ordinary and reasonable care.
Potential liabilities related to the Smokehouse Creek Fire Complex depend on various factors, including the cause of the equipment failure and the extent and magnitude of potential damages, including damages to residential and commercial structures, personal property, vegetation, livestock and livestock feed (including replacement feed), personal injuries and any other damages, penalties, fines or restitution that may be imposed by courts or other governmental entities if SPS is found to have been negligent.
SPS records insurance recoveries when it is deemed probable that recovery will occur, and SPS can reasonably estimate the amount or range. Insurance receivables for estimated losses of approximately $195 million and $210 million, net of recoveries received are presented in prepayments and other current assets as of Dec. 31, 2025 and 2024, respectively. While SPS plans to seek recovery of all insured losses, it is unable to predict the ultimate amount and timing of such insurance recoveries.
Nuclear Antitrust Class Action — A class action complaint was filed in federal court for the District of Maryland in July 2025, alleging violations of the Sherman Antitrust Act in establishing wages for employees at nuclear facilities since 2003. The amended complaint names 46 defendants, including 45 entities that allegedly “own and/or operate all 54 commercial nuclear power plants in the United States,” including Xcel Energy Inc., Xcel Energy Services Inc., and NSP-Minnesota. NSP-Minnesota owns and operates two nuclear facilities in Minnesota, and disputes the allegations set forth against it and the other company entities. The litigation is ongoing, and Xcel Energy assesses the risk of a material impact to its consolidated financial statements as remote.
Rate Matters and Other
Xcel Energy’s operating subsidiaries are involved in various regulatory proceedings arising in the ordinary course of business. Until resolution, typically in the form of a rate order, uncertainties may exist regarding the ultimate rate treatment for certain activities and transactions. Amounts have been recognized for probable and reasonably estimable losses that may result. Unless otherwise disclosed, any reasonably possible range of loss in excess of any recognized amount is not expected to have a material effect on the consolidated financial statements.
Prairie Island Outage Prudency Review — In March 2024, NSP-Minnesota filed its annual fuel clause adjustment true-up petition to the MPUC. In a response to that petition, intervenors recommended refunds for replacement power costs related to an outage at the Prairie Island generating station (October 2023 through February 2024).
In a September 2024 decision, the MPUC ruled NSP-Minnesota was imprudent in the operation of the Prairie Island nuclear plant based on an incident that resulted in the extended outage. The MPUC did not quantify the refund and referred the determination of the refund amount to the Office of Administrative Hearings. NSP-Minnesota recorded an estimated liability for a customer refund in 2024.
In May 2025, in the resulting case currently before an ALJ to determine the refund amount, NSP-Minnesota submitted direct testimony asserting that no more than $6 million of customer refunds are warranted for the outage.
Rebuttal and surrebuttal testimony were filed in August and September 2025 and final briefs were filed in January 2026. Intervenor briefs included recommendations for customer refunds of approximately $40 million to account for the total impact of the outage on 2023 and 2024. An ALJ report is expected in March 2026, with a MPUC decision expected in the second quarter of 2026.
Environmental
New and changing federal and state environmental mandates can create financial liabilities for Xcel Energy, which are normally recovered through the regulated rate process.
Site Remediation
Various federal and state environmental laws impose liability where hazardous substances or other regulated materials have been released to the environment. Xcel Energy Inc.’s subsidiaries may sometimes pay all or a portion of the cost to remediate sites where past activities of their predecessors or other parties have caused environmental contamination.
Environmental contingencies could arise from various situations, including sites of former MGPs; and third-party sites, such as landfills, for which one or more of Xcel Energy Inc.’s subsidiaries are alleged to have sent wastes to that site.
MGP, Landfill and Disposal Sites
Xcel Energy is investigating, remediating or performing post-closure actions at 11 historical MGP, landfill or other disposal sites across its service territories, excluding sites that are being addressed under current coal ash regulations (see below).
Xcel Energy has approximately $15 million of remaining liabilities for resolution of these issues, however, the final outcome and timing are unknown. In addition, there may be regulatory recovery, insurance recovery and/or recovery from other potentially responsible parties, offsetting a portion of costs incurred.
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Environmental Requirements — Water and Waste
Coal Ash Regulation — Xcel Energy is subject to the CCR Rule, which imposes requirements for handling, storage, treatment and disposal of coal ash and other solid waste.
In May 2024, final amendments to the CCR Rule were published, widening its scope to include legacy CCR surface impoundments at inactive facilities and previously exempt areas where CCR was placed directly on land at CCR-regulated facilities, including areas of beneficial use.
As a requirement of the CCR Rule, utilities must complete facility evaluations and groundwater sampling around their subject landfills, surface impoundments and certain other areas where coal ash was placed on land.
If certain impacts to groundwater are detected, utilities are required to perform additional groundwater investigations and/or perform corrective actions beginning with an Assessment of Corrective Measures.
Investigation and/or corrective action related to groundwater impacts are currently underway at certain active and closed coal-generating facilities at a current estimated cost of at least $45 million. In addition, Xcel Energy expects to incur $15 million for investigations through 2028 to perform required reporting and assess whether corrective actions are necessary. AROs have been recorded for each of these activities, and amounts are expected to be recoverable through regulatory mechanisms.
Xcel Energy has also identified coal ash that is expected to be required to be removed from certain closed coal generating facilities at estimated costs totaling approximately $105 million. AROs have been recorded, with the costs expected to be recoverable through regulatory mechanisms.
Xcel Energy continues to perform site investigation activities related to the CCR Rule, which may result in updates to estimated costs as well as identification of additional required corrective actions.
In February 2026, the EPA issued a final rule amending the CCR Legacy rule. The ruling extends deadlines for various regulatory actions and clarifies previous information regarding implementation of the rule. Xcel Energy is still evaluating the final rule, but anticipates impacts to be consistent with prior accruals.
Clean Water Act Section 316(b) — The Federal Clean Water Act requires the EPA to regulate cooling water intake structures to assure they reflect the best technology available for minimizing impingement and entrainment of aquatic species.
Estimated capital expenditures of approximately $50 million may be required to comply with the requirements. Xcel Energy anticipates these costs will be recoverable through regulatory mechanisms.
Environmental Requirements — Air
Compliance with the published plan would require subject facilities to secure additional allowances, install NOx controls and/or develop a strategy of operations that utilizes the existing allowance allocations. While the financial impacts of the final rule are uncertain and dependent on market forces and anticipated generation, if the rule is implemented, Xcel Energy anticipates the annual costs could be significant but would be recoverable through regulatory mechanisms.
In January 2026, the EPA proposed Phase 1 of its reconsideration of the “Good Neighbor” rule. Under Phase 1, the agency would approve eight State Implementation Plans, including Minnesota and New Mexico, which were partially disapproved in 2023. Xcel Energy will continue to evaluate any additional phases of the reconsideration of this rule as they are published by the EPA.
AROs — AROs have been recorded for Xcel Energy’s assets. For nuclear assets, the ARO is associated with the decommissioning of NSP-Minnesota nuclear generating plants.
Aggregate fair value of NSP-Minnesota’s legally restricted assets, for funding future nuclear decommissioning was $3.9 billion and $3.5 billion for 2025 and 2024, respectively.
Xcel Energy’s AROs were as follows:
| (Millions of Dollars) | Jan. 1, 2025 | Amounts Incurred (a) | Accretion | Cash Flow Revisions (b) | Dec. 31, 2025 | |||||||||||||||||||||||||||
| Electric | ||||||||||||||||||||||||||||||||
| Nuclear | $ | $ | $ | $ | $ | |||||||||||||||||||||||||||
| Wind | ( | |||||||||||||||||||||||||||||||
| Steam, hydro and other production | ( | |||||||||||||||||||||||||||||||
| Distribution | ||||||||||||||||||||||||||||||||
| Natural gas | ||||||||||||||||||||||||||||||||
| Transmission and distribution | ( | |||||||||||||||||||||||||||||||
| Other | ||||||||||||||||||||||||||||||||
| Miscellaneous | ||||||||||||||||||||||||||||||||
| Total liability | $ | $ | $ | $ | ( | $ | ||||||||||||||||||||||||||
(a)Amounts incurred largely pertain to obligations associated with new solar facilities.
(b)In 2025, AROs were revised for changes in timing and estimates of cash flows. Wind was revised due to the repowering of two wind facilities in NSP-Minnesota.
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| (Millions of Dollars) | Jan. 1, 2024 | Amounts Incurred (a) | Amounts Settled | Accretion | Cash Flow Revisions (b) | Dec. 31, 2024 | ||||||||||||||||||||||||||||||||
| Electric | ||||||||||||||||||||||||||||||||||||||
| Nuclear | $ | $ | $ | $ | $ | $ | ||||||||||||||||||||||||||||||||
| Wind | ( | |||||||||||||||||||||||||||||||||||||
| Steam, hydro and other production | ( | |||||||||||||||||||||||||||||||||||||
| Distribution | ||||||||||||||||||||||||||||||||||||||
| Natural gas | ||||||||||||||||||||||||||||||||||||||
| Transmission and distribution | ( | |||||||||||||||||||||||||||||||||||||
| Other | ||||||||||||||||||||||||||||||||||||||
| Miscellaneous | ||||||||||||||||||||||||||||||||||||||
| Total liability | $ | $ | $ | ( | $ | $ | $ | |||||||||||||||||||||||||||||||
(a)Amounts incurred largely pertain to CCR coal ash regulations and new obligations associated with Sherco Solar Unit 1, which was placed in service in 2024.
(b)In 2024, AROs were revised for changes in timing and estimates of cash flows. Changes were driven by updated assumptions in the NSP-Minnesota nuclear decommissioning triennial filing coupled with discount rate and escalation rate changes. Wind, steam, hydro and other production AROs were revised due to the results of the 2024 dismantling studies and changes in cost estimates to remediate ash containment facilities .
Indeterminate AROs — Outside of the recorded asbestos AROs, other plants or buildings may contain asbestos due to the age of many of Xcel Energy’s facilities, but no confirmation or measurement of the cost of removal could be determined as of Dec. 31, 2025. Therefore, an ARO was not recorded for these facilities.
Nuclear
Nuclear Insurance — NSP-Minnesota’s public liability for claims from any nuclear incident is limited to $16.3 billion under the Price-Anderson amendment to the Atomic Energy Act. NSP-Minnesota has $500 million of coverage for its public liability exposure with a pool of insurance companies. The remaining $15.8 billion of exposure is funded by the Secondary Financial Protection Program available from assessments by the federal government.
NSP-Minnesota is subject to assessments of up to $166 million per reactor-incident for each of its three reactors, for public liability arising from a nuclear incident at any licensed nuclear facility in the United States. The maximum funding requirement is $25 million per reactor-incident during any one year. Maximum assessments are subject to inflation adjustments.
NSP-Minnesota purchases insurance for property damage and site decontamination cleanup costs from NEIL and EMANI for each of NSP-Minnesota’s two nuclear plant sites. The coverage limits are $2.8 billion for both Monticello and Prairie Island. NEIL also provides business interruption insurance coverage up to $490 million and $420 million at Monticello and Prairie Island, respectively, including the cost of replacement power during prolonged accidental outages of nuclear generating units. Premiums are expensed over the policy term.
All companies insured with NEIL are subject to retroactive premium adjustments if losses exceed accumulated reserve funds. Capital has been accumulated in the reserve funds of NEIL and EMANI to the extent that NSP-Minnesota would have no exposure for retroactive premium assessments in case of a single incident under the business interruption and the property damage insurance coverage. NSP-Minnesota could be subject to annual maximum assessments of $21 million for business interruption insurance and $38 million for property damage insurance if losses exceed accumulated reserve funds.
Nuclear Fuel Disposal — NSP-Minnesota is responsible for temporarily storing spent nuclear fuel from its nuclear plants. The DOE is responsible for permanently storing spent fuel from U.S. nuclear plants, but no such facility is yet available.
NSP-Minnesota owns temporary on-site storage facilities for spent fuel at its Monticello and Prairie Island nuclear plants, which consist of storage pools and dry cask facilities. In October 2023, the MPUC approved additional storage at the Monticello site to support extended operations to 2040. The decommissioning plan addresses the disposition of spent fuel at the end of the licensed life in 2050.
In October 2025, the MPUC approved additional storage at the Prairie Island site to support extended operations to 2054.
Regulatory Plant Decommissioning Recovery — Decommissioning activities for NSP-Minnesota’s nuclear facilities are planned to begin at the end of each unit’s authorized retirement dates, which can be different than the currently approved NRC operating licenses. These decommissioning activities are planned to be completed at both facilities by 2101.
NSP-Minnesota’s current operating licenses allow continued use of its Monticello nuclear plant until 2050 and its Prairie Island nuclear plant until 2033 for Unit 1 and 2034 for Unit 2. NSP-Minnesota's authorized retirement dates are 2040 for Monticello, 2033 for Prairie Island Unit 1 and 2034 for Prairie Island Unit 2. As of Dec. 31, 2025, the planned retirement dates of the Prairie Island Unit 1 and Unit 2 and Monticello were 2053, 2054 and 2050, based off the approved 2024-2040 Upper Midwest Resource Plan. These will be incorporated in decommissioning estimates once additional approvals have been received. Approvals are expected in the third quarter of 2026.
Future decommissioning costs of nuclear facilities are estimated through triennial periodic studies that assess the costs and timing of planned nuclear decommissioning activities for each unit. The most recent triennial decommissioning study was filed in November 2024 and approved by the MPUC in May 2025.
Obligations for decommissioning are expected to be funded 100 % by the external decommissioning trust fund. NSP-Minnesota had $3.9 billion and $3.5 billion of assets held in external decommissioning trusts at Dec. 31, 2025 and 2024, respectively.
See Note 10 to the consolidated financial statements for additional discussion.
Leases
ROU assets represent Xcel Energy's rights to use leased assets. The present value of future operating lease payments is recognized in other current operating lease liabilities and noncurrent operating lease liabilities. The present value of future finance lease payments is included in other current liabilities and noncurrent finance lease liabilities. These amounts, adjusted for any prepayments or incentives, are recognized as ROU assets.
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Leases with an initial term of 12 months or less are classified as short-term leases and are not recognized on the consolidated balance sheet.
Operating lease ROU assets:
| (Millions of Dollars) | Dec. 31, 2025 | Dec. 31, 2024 | ||||||||||||
| PPAs | $ | $ | ||||||||||||
| Other | ||||||||||||||
| Gross operating lease ROU assets | ||||||||||||||
| Accumulated amortization | ( | ( | ||||||||||||
| Net operating lease ROU assets | $ | $ | ||||||||||||
Finance lease ROU assets:
| (Millions of Dollars) | Dec. 31, 2025 | Dec. 31, 2024 | ||||||||||||
| Generation facilities | $ | $ | ||||||||||||
| Gas storage facilities | ||||||||||||||
| Gas pipeline | ||||||||||||||
| Gross finance lease ROU assets | ||||||||||||||
| Accumulated amortization | ( | ( | ||||||||||||
| Net finance lease ROU assets | $ | $ | ||||||||||||
In the third quarter of 2025, certain PPAs for natural gas fueled generating facilities were amended, extending NSP-Minnesota’s use of these plants to 2039 and 2048. The amended agreements qualify for classification as finance leases. As of Dec. 31, 2025, other current liabilities and non-current finance lease liabilities include $37 million and $1.2 billion of finance lease obligations for these amended PPAs, respectively. Prior to these amendments, the agreements were classified as operating leases.
Certain of Xcel Energy’s finance lease activities are related to WYCO, a joint venture with CIG, to develop and lease natural gas pipeline and storage facilities. Xcel Energy Inc. has a 50 % ownership interest in WYCO. WYCO leases its facilities to CIG and CIG operates the facilities, providing natural gas storage and transportation services to PSCo under separate service agreements.
PSCo accounts for its Totem natural gas storage service and Front Range pipeline arrangements with CIG and WYCO, respectively, as finance leases. Xcel Energy Inc. eliminates 50 % of the finance lease obligation related to WYCO in the consolidated balance sheet along with an equal amount of Xcel Energy Inc.’s equity investment in WYCO.
Commitments under operating and finance leases as of Dec. 31, 2025:
| (Millions of Dollars) | PPA (a) (b) Operating Leases | Other Operating Leases | Total Operating Leases | Finance Leases (c) | ||||||||||||||||||||||
| 2026 | $ | $ | $ | $ | ||||||||||||||||||||||
| 2027 | ||||||||||||||||||||||||||
| 2028 | ||||||||||||||||||||||||||
| 2029 | ||||||||||||||||||||||||||
| 2030 | ||||||||||||||||||||||||||
| Thereafter | ||||||||||||||||||||||||||
| Total minimum obligation | ||||||||||||||||||||||||||
| Interest component of obligation | ( | ( | ( | ( | ||||||||||||||||||||||
| Present value of minimum obligation | $ | |||||||||||||||||||||||||
| ( | ( | |||||||||||||||||||||||||
| Noncurrent operating and finance lease liabilities | $ | $ | ||||||||||||||||||||||||
| Weighted-average remaining lease term in years | ||||||||||||||||||||||||||
(a)Amounts do not include PPAs accounted for as executory contracts and/or contingent payments, such as energy payments on renewable PPAs.
(b)PPA operating leases contractually expire at various dates through 2033.
(c)Excludes certain amounts related to Xcel Energy’s 50 % ownership interest in WYCO.
PPA finance lease payments are allocated between interest charges and depreciation and amortization on the consolidated statements of income. PPA operating lease payments are included in electric fuel and purchased power, and expense for other operating leases is included in O&M expense and electric fuel and purchased power.
Components of lease expense:
| (Millions of Dollars) | 2025 | 2024 | 2023 | |||||||||||||||||
| Operating leases | ||||||||||||||||||||
| PPA capacity payments | $ | $ | $ | |||||||||||||||||
Other operating leases (a) | ||||||||||||||||||||
| Total operating lease expense | $ | $ | $ | |||||||||||||||||
| Finance leases | ||||||||||||||||||||
| Amortization of ROU assets | $ | $ | $ | |||||||||||||||||
| Interest expense on lease liability | ||||||||||||||||||||
| Total finance lease expense | $ | $ | $ | |||||||||||||||||
(a)Includes immaterial short-term lease expense.
Most of Xcel Energy’s leases do not contain a readily determinable discount rate. Therefore, the present value of future lease payments is generally calculated using the applicable Xcel Energy subsidiary’s estimated incremental borrowing rate at commencement of each lease (weighted average of 5.1 %).
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PPAs and Fuel Contracts
Non-Lease PPAs — NSP-Minnesota, PSCo and SPS have entered into PPAs with other utilities and energy suppliers for purchased power to meet system load and energy requirements, operating reserve obligations and as part of wholesale and commodity trading activities. In general, these agreements provide for energy payments, based on actual energy delivered, and may also include capacity payments. Certain non-lease PPAs with various expiration dates through 2040, contain minimum energy purchase commitments. Total energy payments on those contracts were $111 million, $212 million and $214 million in 2025, 2024 and 2023, respectively.
Included in electric fuel and purchased power expenses for PPAs accounted for as executory contracts were payments for capacity of $49 million, $81 million and $77 million in 2025, 2024 and 2023, respectively.
Capacity and energy payments are contingent on the IPPs meeting contract obligations, including plant availability requirements. Certain contractual payments are adjusted based on market indices. The effects of price adjustments on financial results are mitigated through purchased energy cost recovery mechanisms.
At Dec. 31, 2025, the estimated future payments for capacity and energy that the utility subsidiaries of Xcel Energy are obligated to purchase pursuant to these non-lease contracts, subject to availability, were as follows:
| (Millions of Dollars) | Capacity | Energy (a) | ||||||||||||
| 2026 | $ | $ | ||||||||||||
| 2027 | ||||||||||||||
| 2028 | ||||||||||||||
| 2029 | ||||||||||||||
| 2030 | ||||||||||||||
| Thereafter | ||||||||||||||
| Total | $ | $ | ||||||||||||
(a)Excludes contingent energy payments for renewable energy PPAs.
Fuel Contracts — Xcel Energy has entered into various long-term commitments for the purchase and delivery of a significant portion of its coal, nuclear fuel and natural gas requirements. These contracts expire between 2026 and 2060. Xcel Energy is required to pay additional amounts depending on actual quantities delivered under these agreements.
Estimated minimum purchases under these contracts as of Dec. 31, 2025:
| (Millions of Dollars) | Coal | Nuclear fuel | Natural gas supply | Natural gas storage and transportation | ||||||||||||||||||||||
| 2026 | $ | $ | $ | $ | ||||||||||||||||||||||
| 2027 | ||||||||||||||||||||||||||
| 2028 | ||||||||||||||||||||||||||
| 2029 | ||||||||||||||||||||||||||
| 2030 | ||||||||||||||||||||||||||
| Thereafter | ||||||||||||||||||||||||||
| Total | $ | $ | $ | $ | ||||||||||||||||||||||
VIEs
PPAs — Under certain PPAs, NSP-Minnesota, PSCo and SPS purchase power from IPPs for which the utility subsidiaries are required to reimburse fuel costs, or to participate in tolling arrangements under which the utility subsidiaries procure the natural gas required to produce the energy that they purchase. Xcel Energy has determined that certain IPPs are VIEs, however Xcel Energy is not subject to risk of loss from the operations of these entities, and no significant financial support is required other than contractual payments for energy and capacity.
In addition, certain solar PPAs provide an option to purchase emission allowances or sharing provisions related to production credits generated by the solar facility under contract. These specific PPAs create a variable interest in the IPP.
Xcel Energy evaluated each of these VIEs for possible consolidation, including review of qualitative factors such as the length and terms of the contract, control over O&M, control over dispatch of electricity, historical and estimated future fuel and electricity prices and financing activities. Xcel Energy concluded that these entities are not required to be consolidated in its consolidated financial statements because Xcel Energy does not have the power to direct the activities that most significantly impact the entities’ economic performance.
The utility subsidiaries had 3,476 MW and 3,751 MW of capacity under long-term PPAs at Dec. 31, 2025 and 2024, respectively, with entities that have been determined to be VIEs. These agreements have expiration dates through 2048.
Fuel Contracts — SPS purchases all of its coal requirements for its Tolk plant from TUCO Inc. under contracts that will expire in December 2027. TUCO arranges for the purchase, receiving, transporting, unloading, handling, crushing, weighing and delivery of coal to meet SPS’ requirements. TUCO is responsible for negotiating and administering contracts with coal suppliers, transporters and handlers.
SPS has not provided any significant financial support to TUCO, other than contractual payments for delivered coal. However, the fuel contracts create a variable interest in TUCO due to SPS’ reimbursement of fuel procurement costs.
SPS has determined that TUCO is a VIE, however it has concluded that SPS is not the primary beneficiary because it does not have the power to direct the activities that most significantly impact TUCO’s economic performance.
Low-Income Housing Limited Partnerships — Eloigne and NSP-Wisconsin have entered into limited partnerships with affordable rental housing activities that qualify for low-income housing tax credits.
Eloigne and NSP-Wisconsin, as primary beneficiaries of these activities, consolidate these limited partnerships in their consolidated financial statements.
Amounts reflected in Xcel Energy’s consolidated balance sheets for these investments include $39 million of assets and $34 million of liabilities at Dec. 31, 2025, and $40 million of assets and $34 million of liabilities at Dec. 31, 2024.
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Other
Guarantees and Bond Indemnifications — Xcel Energy Inc. and its subsidiaries provide guarantees and bond indemnities, which guarantee payment or performance. Xcel Energy Inc.’s exposure is based upon the net liability under the specified agreements or transactions. Most of the guarantees and bond indemnities issued by Xcel Energy Inc. and its subsidiaries have a stated maximum amount.
As of Dec. 31, 2025 and 2024, Xcel Energy Inc. and its subsidiaries had no 120 million and $93 million at Dec. 31, 2025 and 2024, respectively.
Other Indemnification Agreements — Xcel Energy Inc. and its subsidiaries provide indemnifications through various contracts. These are primarily indemnifications against adverse litigation outcomes in connection with underwriting agreements, as well as breaches of representations and warranties, including corporate existence and transaction authorization. Additionally, Xcel Energy Inc. and its subsidiaries have agreed to reimburse purchasers of the subsidiaries’ transferable tax credits for any unexpected reductions or IRS disallowances.
Xcel Energy Inc.’s and its subsidiaries’ obligations under these agreements may be limited in terms of duration and amount. Maximum future payments under these indemnifications cannot be reasonably estimated as the dollar amounts are often not explicitly stated.
13. Other Comprehensive Income | ||
Changes in accumulated other comprehensive loss, net of tax, for the years ended Dec. 31:
| 2025 | ||||||||||||||||||||
| (Millions of Dollars) | Gains and Losses on Interest Rate Cash Flow Hedges | Defined Benefit Pension and Postretirement Items | Total | |||||||||||||||||
| Accumulated other comprehensive loss at Jan. 1 | $ | ( | $ | ( | $ | ( | ||||||||||||||
| Other comprehensive income (loss) before reclassifications | ( | |||||||||||||||||||
| Losses reclassified from net accumulated other comprehensive loss: | ||||||||||||||||||||
Interest rate derivatives (a) | ||||||||||||||||||||
Amortization of net actuarial losses (b) | ||||||||||||||||||||
| Net current period other comprehensive income | ||||||||||||||||||||
| Accumulated other comprehensive loss at Dec. 31 | $ | ( | $ | ( | $ | ( | ||||||||||||||
(a)Included in interest charges.
(b)Included in the computation of net periodic pension and postretirement benefit costs. See Note 11 for further information.
| 2024 | ||||||||||||||||||||
| (Millions of Dollars) | Gains and Losses on Interest Rate Cash Flow Hedges | Defined Benefit Pension and Postretirement Items | Total | |||||||||||||||||
| Accumulated other comprehensive loss at Jan. 1 | $ | ( | $ | ( | $ | ( | ||||||||||||||
| Other comprehensive income (loss) before reclassifications | ( | |||||||||||||||||||
| Losses reclassified from net accumulated other comprehensive loss: | ||||||||||||||||||||
Interest rate derivatives (a) | ||||||||||||||||||||
Amortization of net actuarial losses (b) | ||||||||||||||||||||
| Net current period other comprehensive income | ||||||||||||||||||||
| Accumulated other comprehensive loss at Dec. 31 | $ | ( | $ | ( | $ | ( | ||||||||||||||
(a)Included in interest charges.
(b)Included in the computation of net periodic pension and postretirement benefit costs. See Note 11 for further information.
14. Segment Information | ||
Xcel Energy’s chief operating decision maker, the CEO, sets financial performance objectives and budgets and establishes separate targets for the regulated electric utility net income of NSP-Minnesota, NSP-Wisconsin, PSCo and SPS, as well as the regulated natural gas utility net income of NSP-Minnesota, NSP-Wisconsin and PSCo.
The regulated electric utility and regulated natural gas utility segments are managed separately because of inherent differences between activities to serve electric customers and those required to serve natural gas customers, and as the revenue streams are dependent upon regulated rate recovery, which is separately determined for each segment. The CEO assesses financial performance, including quarterly and annual budget-to-actual and year-over-year variances in revenues and expenses, to inform operating decisions, capital investments and cost recovery strategies.
Xcel Energy has the following reportable segments :
•Regulated Electric Utility — The regulated electric utility segment generates, purchases, transmits, distributes and sells electricity in Colorado, Michigan, Minnesota, New Mexico, North Dakota, South Dakota, Texas and Wisconsin; each state’s regulated electric utility activities qualify as an operating segment, and is aggregated into Xcel Energy’s regulated electric utility segment. In addition, this segment includes sales for resale and provides wholesale transmission service to various entities in the United States. The regulated electric utility segment also includes wholesale commodity and trading operations.
•Regulated Natural Gas Utility — The regulated natural gas utility segment purchases, transports, stores, distributes and sells natural gas primarily in portions of Colorado, Michigan, Minnesota, North Dakota and Wisconsin; each state’s regulated natural gas utility activities qualify as an operating segment, and is aggregated into Xcel Energy’s regulated natural gas utility segment.
Equity method investments in the regulated natural gas utility segment of $81 million and $85 million at Dec. 31, 2025 and 2024, respectively, primarily relate to WYCO. Non-segment equity method investments of $204 million and $161 million as of Dec. 31, 2025 and 2024, respectively, relate to investments in energy technology funds.
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Asset and capital expenditure information is not provided for Xcel Energy’s reportable segments. As an integrated electric and natural gas utility, Xcel Energy operates significant assets that are not dedicated to a specific business segment.
Reporting assets and capital expenditures by business segment would require arbitrary and potentially misleading allocations, which may not necessarily reflect the assets that would be required for the operation of the business segments on a stand-alone basis.
Certain costs, such as common depreciation, common O&M expenses and interest expense are allocated based on cost causation allocators across each segment. In addition, a general allocator is used for certain general and administrative expenses, including office supplies, rent, property insurance and general advertising.
Other segment expenses, net, for the reportable segments includes conservation and DSM expenses, taxes (other than income taxes), other income (expense), net, earnings from equity method investments, intersegment expenses and AFUDC - equity.
Non-segment revenues include steam, appliance repair and non-utility real estate activities and revenues associated with processing solid waste into RDF and from investments in rental housing projects that qualify for low-income housing tax credits. Non-segment net loss also includes costs associated with these activities as well as unallocated corporate O&M expenses, interest charges and income taxes as well as earnings from equity method investments in energy technology funds.
Segment information and reconciliations to Xcel Energy’s consolidated operating revenues and net income:
| 2025 | ||||||||||||||||||||
| (Millions of Dollars) | Regulated electric utility | Regulated natural gas utility | Total segments | |||||||||||||||||
| Operating revenues | $ | $ | $ | |||||||||||||||||
| Intersegment revenue | ||||||||||||||||||||
| Total segment revenues | ||||||||||||||||||||
| Electric fuel and purchased power | ||||||||||||||||||||
| Cost of natural gas sold and transported | ||||||||||||||||||||
| O&M expenses | ||||||||||||||||||||
| Depreciation and amortization | ||||||||||||||||||||
Other segment expenses, net (a) | ||||||||||||||||||||
| Interest charges and financing costs | ||||||||||||||||||||
| Income tax (benefit) expense | ( | ( | ||||||||||||||||||
| Net income | $ | $ | $ | |||||||||||||||||
| Total segment revenues | $ | |||||||||||||||||||
| Eliminate intersegment revenue | ( | |||||||||||||||||||
| Non-segment revenues | ||||||||||||||||||||
| Consolidated operating revenues | $ | |||||||||||||||||||
| Total segment net income | $ | |||||||||||||||||||
| Non-segment net loss | ( | |||||||||||||||||||
| Consolidated net income | $ | |||||||||||||||||||
(a)Other segment expenses, net, for 2025 additionally includes Marshall Wildfire litigation expense.
| 2024 | ||||||||||||||||||||
| (Millions of Dollars) | Regulated electric utility | Regulated natural gas utility | Total segments | |||||||||||||||||
| Operating revenues | $ | $ | $ | |||||||||||||||||
| Intersegment revenue | ||||||||||||||||||||
| Total segment revenues | ||||||||||||||||||||
| Electric fuel and purchased power | ||||||||||||||||||||
| Cost of natural gas sold and transported | ||||||||||||||||||||
| O&M expenses | ||||||||||||||||||||
| Depreciation and amortization | ||||||||||||||||||||
| Other segment expenses, net | ||||||||||||||||||||
| Interest charges and financing costs | ||||||||||||||||||||
| Income tax (benefit) expense | ( | ( | ||||||||||||||||||
| Net income | $ | $ | $ | |||||||||||||||||
| Total segment revenues | $ | |||||||||||||||||||
| Eliminate intersegment revenue | ( | |||||||||||||||||||
| Non-segment revenues | ||||||||||||||||||||
| Consolidated operating revenues | $ | |||||||||||||||||||
| Total segment net income | $ | |||||||||||||||||||
| Non-segment net loss | ( | |||||||||||||||||||
| Consolidated net income | $ | |||||||||||||||||||
| 2023 | ||||||||||||||||||||
| (Millions of Dollars) | Regulated electric utility | Regulated natural gas utility | Total segments | |||||||||||||||||
| Operating revenues | $ | $ | $ | |||||||||||||||||
| Intersegment revenue | ||||||||||||||||||||
| Total segment revenues | ||||||||||||||||||||
| Electric fuel and purchased power | ||||||||||||||||||||
| Cost of natural gas sold and transported | ||||||||||||||||||||
| O&M expenses | ||||||||||||||||||||
| Depreciation and amortization | ||||||||||||||||||||
Other segment expenses, net (a) | ||||||||||||||||||||
| Interest charges and financing costs | ||||||||||||||||||||
| Income tax (benefit) expense | ( | ( | ||||||||||||||||||
| Net income | $ | $ | $ | |||||||||||||||||
| Total segment revenues | $ | |||||||||||||||||||
| Eliminate intersegment revenue | ( | |||||||||||||||||||
| Non-segment revenues | ||||||||||||||||||||
| Consolidated operating revenues | $ | |||||||||||||||||||
| Total segment net income | $ | |||||||||||||||||||
| Non-segment net loss | ( | |||||||||||||||||||
| Consolidated net income | $ | |||||||||||||||||||
(a)Other segment expenses, net, for 2023 additionally includes loss on Comanche Unit 3 litigation with CORE Electric Cooperative related to lost power damages and other costs and workforce reduction expenses.
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15. Workforce Reduction | ||
In 2023, Xcel Energy implemented workforce actions to align resources and investments with evolving business and customer needs, and streamline the organization for long-term success.
In September 2023, Xcel Energy announced a voluntary retirement program to a group of eligible non-bargaining employees, with an enhanced retirement package including certain health care and cash benefits for accepted employees. Approximately 400 employees retired under this program in December 2023.
In November 2023, Xcel Energy, Inc. also reduced its non-bargaining workforce by approximately 150 employees through an involuntary severance program.
In the fourth quarter of 2023, Xcel Energy recorded total expense of $72 million related to these workforce actions, primarily related to the estimated cost of future health plan subsidies and other medical benefits for the voluntary retirement program, as well as severance and other employee payouts and legal and other professional fees.
No such activities occurred in 2024 or 2025.
ITEM 9 — CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE | ||
None.
ITEM 9A — 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 Dec. 31, 2025, based on an evaluation carried out under the supervision and with the participation of Xcel Energy’s management, including the CEO and CFO, of the effectiveness of its disclosure controls and procedures, the CEO and CFO have concluded that Xcel Energy’s disclosure controls and procedures were effective.
Internal Control Over Financial Reporting
No changes in Xcel Energy’s internal control over financial reporting occurred during the most recent fiscal quarter ended Dec. 31, 2025 that materially affected, or are reasonably likely to materially affect, Xcel Energy’s internal control over financial reporting. Xcel Energy maintains internal control over financial reporting to provide reasonable assurance regarding the reliability of the financial reporting. Xcel Energy has evaluated and documented its controls in process activities, general computer activities, and on an entity-wide level.
During the year and in preparation for issuing its report for the year ended Dec. 31, 2025 on internal controls under section 404 of the Sarbanes-Oxley Act of 2002, Xcel Energy conducted testing and monitoring of its internal control over financial reporting. Based on the control evaluation, testing and remediation performed, Xcel Energy did not identify any material control weaknesses, as defined under the standards and rules issued by the Public Company Accounting Oversight Board, as approved by the SEC and as indicated in Xcel Energy’s Management Report on Internal Controls over Financial Reporting, which is contained in Item 8 herein.
ITEM 9B — OTHER INFORMATION | ||
None of the Company’s directors or officers adopted terminated
On Feb. 24, 2026, the Company approved a new executive severance and change in control plan. Under the plan, a participant whose employment is terminated under certain circumstances will receive severance benefits (consisting of base salary, target annual incentive and certain retirement and health benefits), which are then applied to a multiple. The multiple applied to the severance benefits is 2 for the CEO and 1.5 for the other executive officers. If the participant is terminated within two years following a change in control, the multiple applied to the severance benefits is 3 for the CEO and 2 for the other executive officers. Notwithstanding the foregoing, the severance multiple applied for a change in control termination impacting our currently serving executive vice presidents will be 3. The Xcel Energy Inc. Executive Severance and Change in Control Plan which goes into effect on March 1, 2026 is filed as Exhibit 10.33 hereto.
ITEM 9C — DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS | ||
Not applicable.
PART III
ITEM 10 — DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE | ||
Information required under this Item with respect to Directors and Corporate Governance will be set forth in Xcel Energy Inc.’s Proxy Statement for its 2026 Annual Meeting of Shareholders under the captions “Proposal No. 1 Election of Directors,” "Board Committees," "Additional Compensation Program Features and Policies -- Insider Trading Policies and Policies on Hedging and Pledging" and “Delinquent Section 16(a) Reports” and is incorporated by reference. Information with respect to Executive Officers is included in Item 1 to this report under the caption “Information about our Executive Officers”.
Our Code of Conduct applies to Xcel Energy Inc.’s board of directors and all Xcel Energy employees, including the Chief Executive Officer, Chief Financial Officer and Controller. The Code of Conduct is available on our website at www.xcelenergy.com.
If any substantive amendments to the Code of Conduct are made or any waivers are granted, including any implicit waiver, from a provision of the Code of Conduct, to our Chief Executive Officer, Chief Financial Officer or Controller, we will disclose the nature of such amendment or waiver on our website at www.xcelenergy.com, or in a report on Form 8-K.
ITEM 11 — EXECUTIVE COMPENSATION | ||
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Information required under this Item is set forth in Xcel Energy Inc.’s Proxy Statement for its 2026 Annual Meeting of Shareholders under the captions “Compensation Discussion and Analysis,” “Report of the Compensation Committee,” “Executive Compensation” and “Director Compensation” and is incorporated by reference.
ITEM 12 — SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS | ||
Information required under this Item is contained in Xcel Energy Inc.’s Proxy Statement for its 2026 Annual Meeting of Shareholders under the captions “Ownership of Securities” and “Executive Compensation -- Securities Authorized for Issuance under Equity Compensation Plans" and is incorporated by reference.
ITEM 13 — CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE | ||
Information required under this Item is contained in Xcel Energy Inc.’s Proxy Statement for its 2026 Annual Meeting of Shareholders under the captions “Related Person Transactions” and “Board Planning and Composition – Director Independence” and is incorporated by reference.
ITEM 14 — PRINCIPAL ACCOUNTANT FEES AND SERVICES | ||
Information required under this Item (aggregate fees billed to us by our principal accountant, Deloitte & Touche LLP (PCAOB ID No. 34 )) is contained in Xcel Energy Inc.’s Proxy Statement for its 2026 Annual Meeting of Shareholders under the caption “Independent Auditors” and is incorporated by reference.
PART IV
| ITEM 15 — EXHIBITS AND FINANCIAL STATEMENT SCHEDULES | ||
| 1 | Consolidated Financial Statements | ||||||||||
Management Report on Internal Controls Over Financial Reporting — For the year ended Dec. 31, 2025. | |||||||||||
| Report of Independent Registered Public Accounting Firm — Financial Statements and Internal Controls Over Financial Reporting | |||||||||||
Consolidated Statements of Income — For each of the three years ended Dec. 31, 2025, 2024 and 2023. | |||||||||||
Consolidated Statements of Comprehensive Income — For each of the three years ended Dec. 31, 2025, 2024 and 2023. | |||||||||||
Consolidated Statements of Cash Flows — For each of the three years ended Dec. 31, 2025, 2024 and 2023. | |||||||||||
Consolidated Balance Sheets — As of Dec. 31, 2025 and 2024. | |||||||||||
Consolidated Statements of Common Stockholders’ Equity — For each of the three years ended Dec. 31, 2025, 2024 and 2023. | |||||||||||
| 2 | Schedule I — Condensed Financial Information of Registrant. | ||||||||||
Schedule II — Valuation and Qualifying Accounts and Reserves for the years ended Dec. 31, 2025, 2024 and 2023. | |||||||||||
| 3 | Exhibits | ||||||||||
| * | Indicates incorporation by reference | ||||||||||
| + | Executive Compensation Arrangements and Benefit Plans Covering Executive Officers and Directors | ||||||||||
| Xcel Energy Inc. | |||||||||||
| Exhibit Number | Description | Report or Registration Statement | Exhibit Reference | ||||||||
3.01* | Amended and Restated Articles of Incorporation of Xcel Energy Inc. | Xcel Energy Inc. Form 8-K dated May 16, 2012 | 3.01 | ||||||||
3.02* | Bylaws of Xcel Energy Inc., as Amended and Restated on August 23, 2023 | Xcel Energy Inc. Form 8-K dated August 23, 2023 | 3.02 | ||||||||
4.01* | Description of Securities | Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2019 | 4.01 | ||||||||
4.02* | Indenture, dated as of Dec. 1, 2000, by and between Xcel Energy Inc. and U.S Bank Trust Company (as successor to Computershare Trust Company, N.A.), as Trustee | Xcel Energy Inc. Form 8-K dated Dec. 14, 2000 | 4.01 | ||||||||
4.03* | Supplemental Indenture No. 3, dated as of June 1, 2006, by and between Xcel Energy Inc. and U.S. Bank Trust Company (as successor to Computershare Trust Company, N.A.), as Trustee, creating $300 million of 6.50% Senior Notes, Series due July 1, 2036 | Xcel Energy Inc. Form 8-K dated June 6, 2006 | 4.01 | ||||||||
4.04* | Supplemental Indenture No. 6, dated as of Sept. 1, 2011, by and between Xcel Energy Inc. and U.S Bank Trust Company (as successor to Computershare Trust Company, N.A.), as Trustee, creating $250 million of 4.80% Senior Notes, Series due Sept. 15, 2041 | Xcel Energy Inc. Form 8-K dated Sept. 12, 2011 | 4.01 | ||||||||
4.05* | Supplemental Indenture No. 10, dated as of Dec. 1, 2016, by and between Xcel Energy Inc. and U.S Bank Trust Company (as successor to Computershare Trust Company, N.A.), as Trustee, creating $500 million aggregate principal amount of 3.35% Senior Notes, Series due Dec. 1, 2026 | Xcel Energy Inc. Form 8-K dated Dec. 1, 2016 | 4.01 | ||||||||
4.06* | Supplemental Indenture No. 11, dated as of June 25, 2018, by and between Xcel Energy Inc. and U.S Bank Trust Company (as successor to Computershare Trust Company, N.A.), as Trustee, creating $500 million aggregate principal amount of 4.00% Senior Notes, Series due June 15, 2028 | Xcel Energy Inc. Form 8-K dated June 25, 2018 | 4.01 | ||||||||
4.07* | Supplemental Indenture No. 12, dated as of Nov. 7, 2019 by and between Xcel Energy Inc. and U.S Bank Trust Company (as successor to Computershare Trust Company, N.A.), as Trustee, creating $500 million aggregate principal amount of 2.60% Senior Notes, Series due Dec 1. 2029 and $500 million aggregate principal amount of 3.50% Senior Notes, Series due Dec. 1, 2049 | Xcel Energy Inc. Form 8-K dated Nov. 7, 2019 | 4.01 | ||||||||
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4.08* | Supplemental Indenture No. 13, dated as of April 1, 2020 by and between Xcel Energy Inc. and U.S Bank Trust Company (as successor to Computershare Trust Company, N.A.), as Trustee, creating $600 million aggregate principal amount of 3.40% Senior Notes, Series due June 1, 2030 | Xcel Energy Inc. Form 8-K dated April 1, 2020 | 4.01 | ||||||||
4.09* | Supplemental Indenture No. 15, dated as of Nov. 3, 2021 between Xcel Energy Inc. and U.S Bank Trust Company (as successor to Computershare Trust Company, N.A.), as Trustee, creating $500 million aggregate principal amount of 1.75% Senior Notes, Series due March 15, 2027 and $300 million aggregate principal amount of 2.35% Senior Notes, Series due Nov. 15, 2031 | Xcel Energy Inc. Form 8-K dated Nov. 3, 2021 | 4.01 | ||||||||
4.10* | Supplemental Indenture No. 16, dated as of May 6, 2022, by and between Xcel Energy Inc. and U.S Bank Trust Company (as successor to Computershare Trust Company, N.A.), as Trustee, creating $700 million aggregate principal amount of 4.60% Senior Notes, Series due June 1, 2032 | Xcel Energy Form 8-K dated May 6, 2022 | 4.01 | ||||||||
4.11* | Supplemental Indenture No. 17, dated as of August 3, 2023, by and between Xcel Energy Inc. and U.S Bank Trust Company (as successor to Computershare Trust Company, N.A.), as Trustee, creating $800 million aggregate principal amount of 5.45% Senior Notes, Series due August 15, 2033. | Xcel Energy Form 8-K dated August 3, 2023 | 4.01 | ||||||||
4.12* | Supplemental Indenture No. 18, dated as of February 29, 2024 by and between Xcel Energy Inc. and U.S. Bank Trust Company, National Association (as successor to Computershare Trust Company, N.A.), as trustee, creating $800,000,000 aggregate principal amount of 5.50% Senior Notes, Series due March 15, 2034. | Xcel Energy Inc Form 8-K dated February 29, 2024 | 4.01 | ||||||||
4.13* | Supplemental Indenture No. 19, dated as of March 21, 2025 by and between Xcel Energy Inc. and U.S. Bank Trust Company, National Association (as successor to Computershare Trust Company, N.A.), as trustee, creating $350,000,000 aggregate principal amount of 4.75% Senior Notes, Series due March 21, 2028 and $750,000,000 aggregate principal amount of 5.60% Senior Notes, Series due April 15, 2035. | Xcel Energy Inc. Form 8-K dated March 21, 2025 | 4.01 | ||||||||
4.14* | Junior Subordinated Indenture, dated as of October 1, 2025, by and between Xcel Energy Inc. and U.S. Bank Trust Company, National Association, as trustee. | Xcel Energy Inc. Form 8-K dated October 7, 2025 | 4.01 | ||||||||
4.15* | Supplemental Indenture No. 1, dated as of October 7, 2025, by and between Xcel Energy Inc. and U.S. Bank Trust Company, National Association, as trustee, creating $900,000,000 aggregate principal amount of 6.25% Junior Subordinated Notes, Series due 2085. | Xcel Energy Inc. Form 8-K dated October 7, 2025 | 4.02 | ||||||||
10.01*+ | Xcel Energy Inc. Nonqualified Pension Plan (2009 Restatement) | Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2008 | 10.02 | ||||||||
10.02*+ | Xcel Energy Senior Executive Severance and Change-in-Control Policy (2009 Restatement) | Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2008 | 10.05 | ||||||||
10.03*+ | Second Amendment to Exhibit 10.02 dated Oct. 26, 2011 | Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2011 | 10.18 | ||||||||
10.04*+ | Fifth Amendment to Exhibit 10.02 dated May 3, 2016 | Xcel Energy Inc. Form 10-Q for the quarter ended June 30, 2016 | 10.01 | ||||||||
10.05*+ | Seventh Amendment to Exhibit 10.02 dated May 7, 2018 | Xcel Energy Inc. Form 10-Q for the quarter ended June 30, 2018 | 10.01 | ||||||||
10.06*+ | Eighth Amendment to Exhibit 10.02 dated March 31, 2020 | Xcel Energy Inc. Form 10-Q for the quarter ended March 31, 2020 | 10.02 | ||||||||
10.07*+ | Ninth Amendment to Exhibit 10.02 dated May 22, 2020 | Xcel Energy Inc. Form 10-Q for the quarter ended June 30, 2020 | 10.01 | ||||||||
10.08*+ | Tenth Amendment to Exhibit 10.02 dated May 20, 2024 | Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2024 | 10.08 | ||||||||
10.09*+ | Eleventh Amendment to the Xcel Energy Senior Executive Severance and Change in Control Policy | Xcel Energy Inc. Form 10-Q for the quarter ended June 30, 2025 | 10.01 | ||||||||
10.10*+ | Twelfth Amendment to the Xcel Energy Senior Executive Severance and Change in Control Policy | Xcel Energy Inc. Form 10-Q for the quarter ended June 30, 2025 | 10.02 | ||||||||
10.11*+ | Xcel Energy Inc. Supplemental Executive Retirement Plan as amended and restated Jan. 1, 2009 | Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2008 | 10.17 | ||||||||
10.12*+ | Xcel Energy Inc. Nonqualified Deferred Compensation Plan (2009 Restatement) | Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2008 | 10.07 | ||||||||
10.13*+ | First Amendment to Exhibit 10.12 effective Nov. 29, 2011 | Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2011 | 10.17 | ||||||||
10.14*+ | Second Amendment to Exhibit 10.12 dated May 21, 2013 | Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2013 | 10.22 | ||||||||
10.15*+ | Third Amendment to Exhibit 10.12 dated Sept. 30, 2016 | Xcel Energy Inc. Form 10-Q for the quarter ended Sept. 30, 2016 | 10.01 | ||||||||
10.16*+ | Fourth Amendment to Exhibit 10.12 dated Oct. 23, 2017 | Xcel Energy Inc. Form 10-Q for the quarter ended Sept. 30, 2017 | 10.1 | ||||||||
10.17*+ | Xcel Energy Inc. Amended and Restated 2015 Omnibus Incentive Plan | Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2018 | 10.34 | ||||||||
10.18*+ | Form of Award Agreement for Restricted Stock Units and/or Performance Share Units under the Xcel Energy Inc. 2015 Omnibus Incentive Plan for awards between 2020-2023 | Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2019 | 10.32 | ||||||||
10.19*+ | Form of Award Agreement for Restricted Stock Units and/or Performance Share Units under the Xcel Energy Inc. 2015 Omnibus Incentive Plan for awards in 2024 | Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2023 | 10.16 | ||||||||
10.20*+ | Form of Award Agreement for Retention-Based Restricted Stock Units under the Xcel Energy Inc. Amended and Restated 2015 Omnibus Incentive Plan | Xcel Energy Inc. Form 8-K dated Dec. 10, 2021 | 10.01 | ||||||||
10.21*+ | Xcel Energy Inc. Annual Incentive Plan, effective Feb. 21, 2024 | Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2023 | 10.18 | ||||||||
10.22*+ | Summary of Non-Employee Director Compensation, effective as of May 24, 2023 | Xcel Energy Inc. Form 8-K dated Jan. 20, 2025 | 10.01 | ||||||||
10.23*+ | Stock Equivalent Plan for Non-Employee Directors of Xcel Energy Inc. as amended and restated effective Feb. 23, 2011 | Xcel Energy Inc. Definitive Proxy Statement dated April 5, 2011 | Appendix A | ||||||||
10.24*+ | Stock Program for Non-Employee Directors of Xcel Energy Inc. as Amended and Restated on Dec. 12, 2017 under the 2015 Omnibus Incentive Plan | Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2018 | 10.36 | ||||||||
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10.25*+ | Xcel Energy Inc. 2024 Equity Incentive Plan | Xcel Energy Inc. Form S-8 dated May 22, 2024 | 4.03 | ||||||||
10.26*+ | Xcel Energy Inc. Stock Program for Non-Employee Directors (Effective May 22, 2024) under the 2024 Equity Incentive Plan | Xcel Energy Inc. Form 8-K dated May 22, 2024 | 10.01 | ||||||||
10.27+ | Form of Award Agreement for Restricted Stock Units under the Xcel Energy Inc. 2024 Equity Incentive Plan for awards since 2025. | ||||||||||
10.28+ | Form of Award Agreement for Performance Stock Units under the Xcel Energy Inc. 2024 Equity Incentive Plan for awards since 2025. | ||||||||||
10.29*+ | Form of Award Agreement for Retention-Based Restricted Stock Units under the Xcel Energy Inc. 2024 Equity Incentive Plan | Xcel Energy Inc. Form 8-K dated May 22, 2024 | 10.03 | ||||||||
10.30*+ | Form of Award Agreement for Restricted Stock under the Xcel Energy Inc. Equity Incentive Plan | Xcel Energy Inc. Form 8-K dated May 22, 2024 | 10.04 | ||||||||
10.31* | Form of Services Agreement between Xcel Energy Services Inc. and utility companies | Xcel Energy Inc. Form U5B dated Nov. 16, 2000 | H-1 | ||||||||
10.32*+ | Aircraft Time Sharing Agreement, effective Feb. 25, 2025, between Xcel Energy Services Inc., as Operator, and the Chief Executive Officer of Operator | Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2024 | 10.30 | ||||||||
10.33+ | Xcel Energy Inc. Executive Severance and Change in Control Plan (Effective March 1, 2026) | ||||||||||
10.34* | Fifth Amended and Restated Credit Agreement, dated as of May 6, 2025, among Xcel Energy Inc., as Borrower, the several lenders from time to time parties thereto, JPMorgan Chase Bank, N.A., as Administrative Agent, Bank of America, N.A. and Barclays Bank PLC, as Syndication Agents, Citibank, N.A., Mizuho Bank, Ltd., Morgan Stanley Senior Funding, Inc., MUFG Bank, Ltd. and Wells Fargo Bank, National Association, as Documentation Agents and the several lenders party thereto. | Xcel Energy Inc. Form 8-K dated May 6, 2025 | 99.01 | ||||||||
10.35* | 364-Day Delayed Draw Term Loan Agreement dated as of January 30, 2026 among Xcel Energy Inc., as Borrower, the several lenders from time to time parties thereto, and U.S. Bank National Association, as Administrative Agent. | Xcel Energy Inc. Form 8-K dated February 2, 2026 | 10.01 | ||||||||
19.1* | Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2024 | 19.1 | |||||||||
19.2* | Securities Trading for Pre-Clearance Persons Policy | Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2024 | 19.2 | ||||||||
| NSP-Minnesota | |||||||||||
4.16* | Supplemental and Restated Trust Indenture, dated May 1, 1988, from NSP-Minnesota to Harris Trust and Savings Bank, as Trustee, providing for the issuance of First Mortgage Bonds, Supplemental Indentures between NSP-Minnesota and said Trustee | Xcel Energy Inc. Form S-3 dated April 18, 2018 | 4(b)(3) | ||||||||
4.17* | Supplemental Trust Indenture, dated as of March 1, 1998, from NSP-Minnesota to Harris Trust and Savings Bank, as Trustee, creating $150 million aggregate principal amount of 6.5% First Mortgage Bonds, Series due March 1, 2028 | Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2017 | 4.12 | ||||||||
4.18* | Supplemental Trust Indenture, dated as of Aug. 1, 2000 (Assignment and Assumption of Trust Indenture) | NSP-Minnesota Form 10-12G dated Oct. 5, 2000 | 4.51 | ||||||||
4.19* | Supplemental Trust Indenture, dated as of July 1, 2005, by and between NSP-Minnesota and The Bank of New York Mellon Trust Company, NA (as successor to BNY Midwest Trust Company), as Trustee, creating $250 million aggregate principal amount of 5.25% First Mortgage Bonds, Series due July 15, 2035 | NSP-Minnesota Form 8-K dated July 14, 2005 | 4.01 | ||||||||
4.20* | Supplemental Trust Indenture, dated as of May 1, 2006, by and between NSP-Minnesota and The Bank of New York Mellon Trust Company, NA (as successor to BNY Midwest Trust Company), as Trustee, creating $400 million aggregate principal amount of 6.25% First Mortgage Bonds, Series due June 1, 2036 | NSP-Minnesota Form 8-K dated May 18, 2006 | 4.01 | ||||||||
4.21* | Supplemental Trust Indenture, dated as of June 1, 2007, by and between NSP-Minnesota and The Bank of New York Mellon Trust Company, NA (as successor to BNY Midwest Trust Company), as Trustee, creating $350 million aggregate principal amount of 6.20% First Mortgage Bonds, Series due July 1, 2037 | NSP-Minnesota Form 8-K dated June 19, 2007 | 4.01 | ||||||||
4.22* | Supplemental Trust Indenture, dated as of Nov. 1, 2009, by and between NSP-Minnesota and The Bank of New York Mellon Trust Company., NA, as Trustee, creating $300 million aggregate principal amount of 5.35% First Mortgage Bonds, Series due Nov. 1, 2039 | NSP-Minnesota Form 8-K dated Nov. 16, 2009 | 4.01 | ||||||||
4.23* | Supplemental Trust Indenture, dated as of Aug. 1, 2010, by and between NSP-Minnesota and The Bank of New York Mellon Trust Company, NA, as Trustee, creating $250 million aggregate principal amount of 4.85% First Mortgage Bonds, Series due Aug. 15, 2040 | NSP-Minnesota Form 8-K dated Aug. 4, 2010 | 4.01 | ||||||||
4.24* | Supplemental Trust Indenture, dated as of Aug. 1, 2012, by and between NSP-Minnesota and The Bank of New York Mellon Trust Company, NA, as Trustee, creating $500 million aggregate principal amount of 3.40% First Mortgage Bonds, Series due Aug. 15, 2042 | NSP-Minnesota Form 8-K dated Aug. 13, 2012 | 4.01 | ||||||||
4.25* | Supplemental Trust Indenture, dated as of May 1, 2014, by and between NSP-Minnesota and The Bank of New York Mellon Trust Company, N.A., as Trustee, creating $300 million aggregate principal amount of 4.125% First Mortgage Bonds, Series due May 15, 2044 | NSP-Minnesota Form 8-K dated May 13, 2014 | 4.01 | ||||||||
4.26* | Supplemental Trust Indenture, dated as of Aug. 1, 2015, by and between NSP-Minnesota and The Bank of New York Mellon Company, N.A., as Trustee, creating $300 million aggregate principal amount of 4.00% First Mortgage Bonds, Series due Aug. 15, 2045 | NSP-Minnesota Form 8-K dated Aug. 11, 2015 | 4.01 | ||||||||
4.27* | Supplemental Trust Indenture, dated as of May 1, 2016, by and between NSP-Minnesota and The Bank of NY Mellon Trust Company, N.A., as Trustee, creating $350 million aggregate principal amount of 3.60% First Mortgage Bonds, Series due May 15, 2046 | NSP-Minnesota Form 8-K dated May 31, 2016 | 4.01 | ||||||||
4.28* | Supplemental Trust Indenture, dated as of Sept. 1, 2017, by and between NSP-Minnesota and The Bank of New York Mellon Trust Company, N.A., as Trustee, creating $600 million aggregate principal amount of 3.60% First Mortgage Bonds, Series due Sept. 15, 2047 | NSP-Minnesota Form 8-K dated Sept. 13, 2017 | 4.01 | ||||||||
4.29* | Supplemental Trust Indenture, dated as of Sept. 1, 2019, by and between NSP-Minnesota and The Bank of New York Mellon Trust Company, N.A., as Trustee, creating $600 million aggregate principal amount of 2.90% First Mortgage Bonds, Series due March 1, 2050 | NSP-Minnesota Form 8-K dated Sept. 10, 2019 | 4.01 | ||||||||
4.30* | Supplemental Indenture, dated as of June 8, 2020, by and between NSP-Minnesota and The Bank of New York Mellon Trust Company, N.A., as Trustee, creating $700 million aggregate principal amount of 2.60% First Mortgage Bonds, Series due June 1, 2051 | NSP-Minnesota 8-K dated June 15, 2020 | 4.01 | ||||||||
4.31* | Supplemental Indenture, dated as of March 1, 2021, by and between NSP-Minnesota and The Bank of New York Mellon Trust Company, N.A., as Trustee, creating $425 million principal amount of 2.25% First Mortgage Bonds, Series due April 1, 2031 and $425 million principal amount of 3.20% First Mortgage Bonds, Series due April 1, 2052 | NSP-Minnesota 8-K dated March 30, 2021 | 4.01 | ||||||||
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4.32* | Supplemental Indenture, dated as of May 1, 2022, by and between NSP-Minnesota and The Bank of New York Mellon Trust Company, N.A., as Trustee, creating $500 million aggregate principal amount of 4.50% First Mortgage Bonds, Series due June 1, 2052 | NSP-Minnesota 8-K dated May 9, 2022 | 4.01 | ||||||||
4.33* | Supplemental Trust Indenture dated as of May 1, 2023 between NSP-Minnesota and The Bank of New York Mellon Trust Company, N.A., as successor Trustee, creating $800 million aggregate principal amount of 5.10% First Mortgage Bonds, Series due May 15, 2053. | NSP-Minnesota 8-K dated May 8, 2023 | 4.01 | ||||||||
4.34* | Supplemental Trust Indenture dated as of February 1, 2024 between Northern States Power Company and The Bank of New York Mellon Trust Company, N.A., as successor Trustee, creating $700,000,000 aggregate principal amount of 5.40% First Mortgage Bonds, Series due March 15, 2054. | NSP-Minnesota Form 8-K dated February 29, 2024 | 4.01 | ||||||||
4.35* | Supplemental Trust Indenture dated as of April 1, 2025 between Northern States Power Company and The Bank of New York Mellon Trust Company, N.A., as successor Trustee, creating $600,000,000 aggregate principal amount of 5.05% First Mortgage Bonds, Series due May 15, 2035 and $500,000,000 aggregate principal amount of 5.65% First Mortgage Bonds, Series due May 15, 2055. | NSP-Minnesota Form 8-K dated May 5, 2025 | 4.01 | ||||||||
10.35* | Restated Interchange Agreement dated Jan. 16, 2001 between NSP-Wisconsin and NSP-Minnesota | NSP-Wisconsin Form S-4 dated Jan. 21, 2004 | 10.01 | ||||||||
10.36* | Fifth Amended and Restated Credit Agreement, dated as of May 6, 2025, among Northern States Power Company, a Minnesota corporation, as Borrower, the several lenders from time to time parties thereto, JPMorgan Chase Bank, N.A., as Administrative Agent, Bank of America, N.A. and Barclays Bank PLC, as Syndication Agents, Citibank, N.A., Mizuho Bank, Ltd., Morgan Stanley Senior Funding, Inc., MUFG Bank, Ltd. and Wells Fargo Bank, National Association, as Documentation Agents and the several lenders party thereto. | Xcel Energy Inc. Form 8-K dated May 6, 2025 | 99.02 | ||||||||
| NSP-Wisconsin | |||||||||||
4.36* | Supplemental and Restated Trust Indenture, dated as of March 1, 1991, by and between NSP-Wisconsin and U.S. Bank Trust Company, National Association (as successor to First Wisconsin Trust Company), as Trustee providing for the issuance of First Mortgage Bonds | Xcel Energy Inc. Form S-3 dated April 18, 2018 | 4(c)(3) | ||||||||
4.37* | Trust Indenture, dated Sept. 1, 2000, by and between NSP-Wisconsin and U.S. Bank Trust Company, National Association (as successor to Firstar Bank, N.A.), as Trustee | NSP-Wisconsin Form 8-K dated Sept. 25, 2000 | 4.01 | ||||||||
4.38* | Supplemental Trust Indenture, dated as of Sept. 1, 2008, by and between NSP-Wisconsin and U.S. Bank Trust Company, National Association (as successor to U.S. Bank National Association), as Trustee, creating $200 million aggregate principal amount of 6.375% First Mortgage Bonds, Series due Sept. 1, 2038 | NSP-Wisconsin Form 8-K dated Sept. 3, 2008 | 4.01 | ||||||||
4.39* | Supplemental Trust Indenture, dated as of Oct. 1, 2012, by and between NSP-Wisconsin and U.S. Bank Trust Company, National Association (as successor to U.S. Bank National Association), as Trustee, creating $100 million aggregate principal amount of 3.70% First Mortgage Bonds, Series due Oct. 1, 2042 | NSP-Wisconsin Form 8-K dated Oct. 10, 2012 | 4.01 | ||||||||
4.40* | Supplemental Trust Indenture, dated as of Nov 1, 2017, by and between NSP-Wisconsin and U.S. Bank Trust Company, National Association (as successor to U.S. Bank National Association), as Trustee, creating $100 million aggregate principal amount of 3.75% First Mortgage Bonds, Series due Dec. 1, 2047 | NSP-Wisconsin Form 8-K dated Dec. 4, 2017 | 4.01 | ||||||||
4.41* | Supplemental Indenture, dated as of Sept. 1, 2018, by and between NSP-Wisconsin and U.S. Bank Trust Company, National Association (as successor to U.S. Bank National Association), as Trustee, creating $200 million aggregate principal amount of 4.20% First Mortgage Bonds, Series due Sept. 1, 2048 | NSP-Wisconsin Form 8-K dated Sept. 12, 2018 | 4.01 | ||||||||
4.42* | Supplemental Trust Indenture, dated as of May 18, 2020, by and between NSP-Wisconsin and U.S. Bank Trust Company, National Association (as successor to U.S. Bank National Association), as Trustee, creating $100 million aggregate principal amount of 3.05% First Mortgage Bonds, Series due May 1, 2051 | NSP-Wisconsin Form 8-K dated May 26, 2020 | 4.01 | ||||||||
4.43* | Supplemental Indenture dated as of July 19, 2021 between NSP-Wisconsin and U.S. Bank Trust Company, National Association (as successor to U.S. Bank National Association), as Trustee, creating $100 million principal amount of 2.82% First Mortgage Bonds, Series due May 1, 2051 | NSP-Wisconsin Form 8-K dated July 20, 2021 | 4.01 | ||||||||
4.44* | Supplemental Trust Indenture, dated as of July 15, 2022, by and between NSP-Wisconsin and U.S. Bank Trust Company, National Association, as Trustee, creating $100 million aggregate principal amount of 4.86% First Mortgage Bonds, Series due Sept. 15, 2052 | NSP-Wisconsin Form 8-K dated July 15, 2022 | 4.01 | ||||||||
4.45* | Supplemental Indenture dated as of May 10, 2023 between NSP-Wisconsin and U.S. Bank Trust Company, National Association, as successor Trustee, creating 5.30% First Mortgage Bonds, Series due June 15, 2053 | NSP-Wisconsin Form 8-K dated May 10, 2023 | 4.01 | ||||||||
4.46* | Supplemental Indenture dated as of May 13, 2024 between Northern States Power Company and U.S. Bank Trust Company, National Association, as successor Trustee, creating $400 million principal amount of 5.65% First Mortgage Bonds, Series due June 15, 2054 | NSP-Wisconsin Form 8-K dated May 16, 2024 | 4.01 | ||||||||
10.37* | Restated Interchange Agreement dated Jan. 16, 2001 between NSP-Wisconsin and NSP-Minnesota | NSP-Wisconsin Form S-4 dated Jan. 21, 2004 | 10.01 | ||||||||
10.38* | Fifth Amended and Restated Credit Agreement, dated as of May 6, 2025, among Northern States Power Company, a Wisconsin corporation, as Borrower, the several lenders from time to time parties thereto, JPMorgan Chase Bank, N.A., as Administrative Agent, Bank of America, N.A. and Barclays Bank PLC, as Syndication Agents, Citibank, N.A., Mizuho Bank, Ltd., Morgan Stanley Senior Funding, Inc., MUFG Bank, Ltd. and Wells Fargo Bank, National Association, as Documentation Agents and the several lenders party thereto. | Xcel Energy Inc. Form 8-K dated May 6, 2025 | 99.05 | ||||||||
| PSCo | |||||||||||
4.47* | Indenture, dated as of Oct. 1, 1993, by and between PSCo and U.S. Bank Trust Company, National Association (as successor to Morgan Guaranty Trust Company of New York), as Trustee, providing for the issuance of First Collateral Trust Bonds | Xcel Energy Inc. Form S-3 dated April 18, 2018 | 4(d)(3) | ||||||||
4.48* | Supplemental Indenture No. 17, dated as of Aug. 1, 2007, by and between PSCo and U.S. Bank Trust Company, National Association (as successor to U.S. Bank National Association), as Trustee, creating $350 million of 6.25% First Mortgage Bonds, Series No. 17 due Sept. 1, 2037 | PSCo Form 8-K dated Aug. 8, 2007 | 4.01 | ||||||||
4.49* | Supplemental Indenture No. 18, dated as of Aug. 1, 2008, by and between PSCo and U.S. Bank Trust Company, National Association (as successor to U.S. Bank National Association), as Trustee, creating $300 million aggregate principal amount of 6.50% First Mortgage Bonds, Series No. 19 due Aug. 1, 2038 | PSCo Form 8-K dated Aug. 6, 2008 | 4.01 | ||||||||
4.50* | Supplemental Indenture No. 21, dated as of Aug. 1, 2011, by and between PSCo and U.S. Bank Trust Company, National Association (as successor to U.S. Bank National Association), as Trustee, creating $250 million aggregate principal amount of 4.75% First Mortgage Bonds, Series No. 22 due Aug. 15, 2041 | PSCo Form 8-K dated Aug. 9, 2011 | 4.01 | ||||||||
4.51* | Supplemental Indenture No. 22, dated as of Sept. 1, 2012, between PSCo and U.S. Bank Trust Company, National Association (as successor to U.S. Bank National Association), as Trustee, creating $500 million aggregate principal amount of 3.60% First Mortgage Bonds, Series No. 24 due Sept. 15, 2042 | PSCo Form 8-K dated Sept. 11, 2012 | 4.01 | ||||||||
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4.52* | Supplemental Indenture No. 24, dated as of March 1, 2014, by and between PSCo and U.S. Bank Trust Company, National Association (as successor to U.S. Bank National Association), as Trustee, creating $300 million aggregate principal amount of 4.30% First Mortgage Bonds, Series No. 27 due March 15, 2044 | PSCo Form 8-K dated March 10, 2014 | 4.01 | ||||||||
4.53* | Supplemental Indenture No. 26, dated as of June 1, 2016, by and between PSCo and U.S. Bank Trust Company, National Association (as successor to U.S. Bank National Association), as Trustee, creating $250 million aggregate principal amount of 3.55% First Mortgage Bonds, Series No. 29 due June 15, 2046 | PSCo Form 8-K dated June 13, 2016 | 4.01 | ||||||||
4.54* | Supplemental Indenture No. 27, dated as of June 1, 2017, by and between PSCo and U.S. Bank Trust Company, National Association (as successor to U.S. Bank National Association), as Trustee, creating $400 million aggregate principal amount of 3.80% First Mortgage Bonds, Series No. 30 due June 15, 2047 | PSCo Form 8-K dated June 19, 2017 | 4.01 | ||||||||
4.55* | Supplemental Indenture No. 28, dated as of June 1, 2018, by and between PSCo and U.S. Bank Trust Company, National Association (as successor to U.S. Bank National Association), as Trustee, creating $350 million aggregate principal amount of 3.70% First Mortgage Bonds, Series No. 31 due June 15, 2028, and $350 million aggregate principal amount of 4.10% First Mortgage Bonds, Series No. 32 due June 15, 2048 | PSCo Form 8-K dated June 21, 2018 | 4.01 | ||||||||
4.56* | Supplemental Indenture No. 29, dated as of March 1, 2019, by and between PSCo and U.S. Bank Trust Company, National Association (as successor to U.S. Bank National Association), as Trustee, creating $400 million aggregate principal amount of 4.05% First Mortgage Bonds, Series No. 33 due Sept. 15, 2049 | PSCo Form 8-K dated March 13, 2019 | 4.01 | ||||||||
4.57* | Supplemental Indenture No. 30, dated as of Aug. 1, 2019, by and between PSCo and U.S. Bank Trust Company, National Association (as successor to U.S. Bank National Association), as Trustee, creating $550 million aggregate principal amount of 3.20% First Mortgage Bonds, Series No. 34 due March 1, 2050 | PSCo Form 8-K dated August 13, 2019 | 4.01 | ||||||||
4.58* | Supplemental Indenture No. 31, dated as of May 1, 2020, by and between PSCo and U.S. Bank Trust Company, National Association (as successor to U.S. Bank National Association), as Trustee, creating $375 million aggregate principal amount of 2.70% First Mortgage Bonds, Series No. 35 due Jan. 15, 2051 and $375 million aggregate principal amount of 1.90% First Mortgage Bonds, Series No. 36 due Jan. 15, 2031 | PSCo Form 8-K dated May 15, 2020 | 4.01 | ||||||||
4.59* | Supplemental Indenture No. 32, dated as of February 1, 2021, by and between PSCo and U.S. Bank Trust Company, National Association (as successor to U.S. Bank National Association), as Trustee, creating $750 million aggregate principal amount of 1.875% First Mortgage Bonds, Series No. 37 due June 15, 2031 | PSCo Form 8-K dated March 1, 2021 | 4.01 | ||||||||
4.60* | Supplemental Indenture No. 33, dated as of May 1, 2022, by and between PSCo and U.S. Bank Trust Company, National Association, as Trustee, creating $300 million aggregate principal amount of 4.10% First Mortgage Bonds, Series No. 38 due June 1, 2032 and $400 million aggregate principal amount of 4.50% First Mortgage Bonds, Series No. 39 due June 1, 2052 | PSCo Form 8-K dated May 17, 2022 | 4.01 | ||||||||
4.61* | Supplemental Indenture No. 34, dated as of March 1, 2023, between PSCo and U.S. Bank Trust Company, National Association, as successor Trustee, creating $850 million principal amount of 5.25% First Mortgage Bonds, Series No. 40 due April 1, 2053. | PSCo Form 8-K dated April 3, 2023 | 4.01 | ||||||||
4.62* | Supplemental Indenture dated as of April 1, 2024, between Public Service Company of Colorado and U.S. Bank Trust Company, National Association, as successor Trustee, creating $450 million principal amount of 5.35% First Mortgage Bonds, Series No. 41 due 2034 and $750 million principal amount of 5.75% First Mortgage Bonds, Series No. 42 due 2054. | PSCo Form 8-K dated April 4, 2024 | 4.01 | ||||||||
4.63* | Supplemental Indenture No. 36 dated as of March 1, 2025, between Public Service Company of Colorado and U.S. Bank Trust Company, National Association, as successor Trustee, creating $600 million principal amount of 5.85% First Mortgage Bonds, Series No. 43 due 2055. | PSCo Form 8-K dated March 20, 2025 | 4.03 | ||||||||
4.64* | Supplemental Indenture No. 37 dated as of August 1, 2025, between Public Service Company of Colorado and U.S. Bank Trust Company, National Association, as successor Trustee, creating $800,000,000 million principal amount of 5.15% First Mortgage Bonds, Series No. 44 due 2035. | PSCo Form 8-K dated August 7, 2025 | 4.03 | ||||||||
10.39* | Fifth Amended and Restated Credit Agreement, dated as of May 6, 2025, among Public Service Company of Colorado, as Borrower, the several lenders from time to time parties thereto, JPMorgan Chase Bank, N.A., as Administrative Agent, Bank of America, N.A. and Barclays Bank PLC, as Syndication Agents, Citibank, N.A., Mizuho Bank, Ltd., Morgan Stanley Senior Funding, Inc., MUFG Bank, Ltd. and Wells Fargo Bank, National Association, as Documentation Agents and the several lenders party thereto. | Xcel Energy Inc. Form 8-K dated May 6, 2025 | 99.03 | ||||||||
| SPS | |||||||||||
4.65* | Indenture, dated as of Feb. 1, 1999, by and between SPS and The Chase Manhattan Bank, as Trustee | SPS Form 8-K dated Feb. 25, 1999 | 99.2 | ||||||||
4.66* | Third Supplemental Indenture, dated as of Oct. 1, 2003, by and between SPS and JPMorgan Chase Bank (as successor to The Chase Manhattan Bank), as Trustee, creating $100 million aggregate principal amount of Series C Notes, 6% due Oct. 1, 2033 and Series D Notes, 6% due Oct. 1, 2033 | Xcel Energy Inc. Form 10-Q for the quarter ended Sept. 30, 2003 | 4.04 | ||||||||
4.67* | Fourth Supplemental Indenture, dated as of Oct. 1, 2006, by and between SPS and The Bank of New York (as successor to The Chase Manhattan Bank), as Trustee, creating $250 million aggregate principal amount of Series F Notes, 6% due Oct. 1, 2036 | SPS Form 8-K dated Oct. 3, 2006 | 4.01 | ||||||||
4.68* | Indenture, dated as of Aug. 1, 2011, by and between SPS and U.S. Bank Trust Company, National Association (as successor to U.S. Bank National Association), as Trustee | SPS Form 8-K dated Aug. 10, 2011 | 4.01 | ||||||||
4.69* | Supplemental Indenture No. 1, dated as of Aug. 3, 2011, by and between SPS and U.S. Bank Trust Company, National Association (as successor to U.S. Bank National Association), as Trustee, creating $200 million aggregate principal amount of 4.50% First Mortgage Bonds, Series No. 1 due Aug. 15, 2041 | SPS Form 8-K dated Aug. 10, 2011 | 4.02 | ||||||||
4.70* | Supplemental Indenture No. 4, dated as of Aug. 1, 2016, by and between SPS and U.S. Bank Trust Company, National Association (as successor to U.S. Bank National Association), as Trustee, creating $300 million aggregate principal amount of 3.40% First Mortgage Bonds, Series No. 4 due Aug. 15, 2046 | SPS Form 8-K dated Aug. 12, 2016 | 4.02 | ||||||||
4.71* | Supplemental Indenture No. 5, dated as of Aug. 1, 2017, by and between SPS and U.S. Bank Trust Company, National Association (as successor to U.S. Bank National Association), as Trustee, creating $450 million aggregate principal amount of 3.70% First Mortgage Bonds, Series No. 5 due Aug. 15 2047 | SPS Form 8-K dated Aug 9. 2017 | 4.02 | ||||||||
4.72* | Supplemental Indenture No. 6, dated as of Oct. 1, 2018, by and between SPS and U.S. Bank Trust Company, National Association (as successor to U.S. Bank National Association), as Trustee, creating $300 million aggregate principal amount of 4.40% First Mortgage Bonds, Series No. 6 due Nov. 15, 2048 | SPS Form 8-K dated Nov. 5, 2018 | 4.02 | ||||||||
4.73* | Supplemental Indenture No. 7, dated as of June 1, 2019, by and between SPS and U.S. Bank Trust Company, National Association (as successor to U.S. Bank National Association), as Trustee, creating $300 million aggregate principal amount of 3.75% First Mortgage Bonds, Series No. 7 due June 15, 2049 | SPS Form 8-K dated June 18, 2019 | 4.02 | ||||||||
4.74* | Supplemental Indenture No. 8, dated as of May 1, 2020, by and between SPS and U.S. Bank Trust Company, National Association (as successor to U.S. Bank National Association), as Trustee, creating $600 million aggregate principal amount of 3.15% First Mortgage Bonds, Series No. 8 due May 1, 2050 | SPS Form 8-K dated May 18, 2020 | 4.02 | ||||||||
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4.75* | Supplemental Indenture No. 9, dated as of May 1, 2022, by and between SPS and U.S. Bank Trust Company, National Association, as Trustee, creating $200 million aggregate principal amount of 5.15% First Mortgage Bonds, Series No. 9 due June 1, 2052 | SPS Form 8-K dated May 31, 2022 | 4.02 | ||||||||
4.76* | Supplemental Indenture No. 10 dated as of August 21, 2023 between SPS and U.S. Bank Trust Company, National Association (as successor to U.S. Bank National Association), as Trustee, creating $100 million aggregate principal amount of 6.00% First Mortgage Bonds, Series No. 10 due 2053. | SPS Form 8-K dated August 21, 2023 | 4.01 | ||||||||
4.77* | Supplemental Indenture No. 11 dated as of May 15, 2024 between Southwestern Public Service Company and U.S. Bank Trust Company, National Association (as successor to U.S. Bank National Association), as Trustee, creating $600 million principal amount of 6.00% First Mortgage Bonds, Series No. 11 due 2054 | SPS Form 8-K dated June 6, 2024 | 4.02 | ||||||||
4.78* | Supplemental Indenture No. 12 dated as of April 15, 2025 between Southwestern Public Service Company and U.S. Bank Trust Company, National Association (as successor to U.S. Bank National Association), as Trustee, creating 5.30% First Mortgage Bonds, Series No. 12 due 2035. | SPS Form 8-K dated May 2, 2025 | 4.02 | ||||||||
10.40* | Fifth Amended and Restated Credit Agreement, dated as of May 6, 2025, among Southwestern Public Service Company, as Borrower, the several lenders from time to time parties thereto, JPMorgan Chase Bank, N.A., as Administrative Agent, Bank of America, N.A. and Barclays Bank PLC, as Syndication Agents, Citibank, N.A., Mizuho Bank, Ltd., Morgan Stanley Senior Funding, Inc., MUFG Bank, Ltd. and Wells Fargo Bank, National Association, as Documentation Agents and the several lenders party thereto. | Xcel Energy Inc. Form 8-K dated May 6, 2025 | 99.04 | ||||||||
| Xcel Energy Inc. | |||||||||||
21.01 | Subsidiaries of Xcel Energy Inc. | ||||||||||
23.01 | Consent of Independent Registered Public Accounting Firm | ||||||||||
24.01 | Powers of Attorney | ||||||||||
31.01 | Principal Executive Officer’s certification 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 certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 | ||||||||||
32.01 | Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 | ||||||||||
97.01 | Mandatory Compensation Recovery Policy for Section 16 Officers | ||||||||||
| 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) | ||||||||||
89
Table of Contents
SCHEDULE I
XCEL ENERGY INC.
CONDENSED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(amounts in millions, except per share data)
| Year Ended Dec. 31 | |||||||||||||||||
| 2025 | 2024 | 2023 | |||||||||||||||
| Income | |||||||||||||||||
| Equity earnings of subsidiaries | $ | $ | $ | ||||||||||||||
| Total income | |||||||||||||||||
| Expenses and other deductions | |||||||||||||||||
| Operating expenses | |||||||||||||||||
| Other income | ( | ( | ( | ||||||||||||||
| Interest charges and financing costs | |||||||||||||||||
| Total expenses and other deductions | |||||||||||||||||
| Income before income taxes | |||||||||||||||||
| Income tax benefit | ( | ( | ( | ||||||||||||||
| Net income | $ | $ | $ | ||||||||||||||
| Other Comprehensive Income | |||||||||||||||||
| Pension and retiree medical benefits, net of tax | $ | $ | $ | ( | |||||||||||||
| Derivative instruments, net of tax | |||||||||||||||||
| Other comprehensive income (loss) | ( | ||||||||||||||||
| Comprehensive income | $ | $ | $ | ||||||||||||||
| Weighted average common shares outstanding: | |||||||||||||||||
| Basic | |||||||||||||||||
| Diluted | |||||||||||||||||
| Earnings per average common share: | |||||||||||||||||
| Basic | $ | $ | $ | ||||||||||||||
| Diluted | |||||||||||||||||
| See Notes to Condensed Financial Statements | |||||||||||||||||
XCEL ENERGY INC.
CONDENSED STATEMENTS OF CASH FLOWS
(amounts in millions)
| Year Ended Dec. 31 | |||||||||||||||||
| 2025 | 2024 | 2023 | |||||||||||||||
| Operating activities | |||||||||||||||||
| Net cash provided by operating activities | $ | $ | $ | ||||||||||||||
| Investing activities | |||||||||||||||||
| Capital contributions to subsidiaries | ( | ( | ( | ||||||||||||||
| Investment in debt securities — intercompany | ( | ( | |||||||||||||||
| Net return in the utility money pool | ( | ||||||||||||||||
| Net cash used in investing activities | ( | ( | ( | ||||||||||||||
| Financing activities | |||||||||||||||||
| Proceeds from (repayment of) short-term borrowings, net | ( | ||||||||||||||||
| Proceeds from issuance of long-term debt | |||||||||||||||||
| Repayment of long-term debt | ( | ( | |||||||||||||||
| Proceeds from issuance of common stock | |||||||||||||||||
| Dividends paid | ( | ( | ( | ||||||||||||||
| Other | ( | ( | ( | ||||||||||||||
| Net cash provided by (used in) financing activities | ( | ||||||||||||||||
| Net change in cash, cash equivalents, and restricted cash | ( | ||||||||||||||||
| Cash, cash equivalents and restricted cash at beginning of period | |||||||||||||||||
| Cash, cash equivalents and restricted cash at end of period | $ | $ | $ | ||||||||||||||
| See Notes to Condensed Financial Statements | |||||||||||||||||
XCEL ENERGY INC.
CONDENSED BALANCE SHEETS
(amounts in millions)
| Dec. 31 | |||||||||||
| 2025 | 2024 | ||||||||||
| Assets | |||||||||||
| Cash and cash equivalents | $ | $ | |||||||||
| Accounts receivable from subsidiaries, net | |||||||||||
| Other current assets | |||||||||||
| Total current assets | |||||||||||
| Investment in subsidiaries | |||||||||||
| Investment in debt securities — intercompany | |||||||||||
| Other assets | |||||||||||
| Total other assets | |||||||||||
| Total assets | $ | $ | |||||||||
| Liabilities and Equity | |||||||||||
| Current portion of long-term debt | |||||||||||
| Dividends payable | |||||||||||
| Short-term debt | |||||||||||
| Other current liabilities | |||||||||||
| Total current liabilities | |||||||||||
| Other liabilities | |||||||||||
| Total other liabilities | |||||||||||
| Commitments and contingencies | |||||||||||
| Capitalization | |||||||||||
| Long-term debt | |||||||||||
| Common stockholders' equity | |||||||||||
| Total capitalization | |||||||||||
| Total liabilities and equity | $ | $ | |||||||||
| See Notes to Condensed Financial Statements | |||||||||||
Notes to Condensed Financial Statements
Incorporated by reference are Xcel Energy’s consolidated statements of common stockholders’ equity and other comprehensive income in Part II, Item 8.
Basis of Presentation
The condensed financial information of Xcel Energy Inc. is presented to comply with Rule 12-04 of Regulation S-X. Xcel Energy Inc.’s investments in subsidiaries are presented under the equity method of accounting. Under this method, the assets and liabilities of subsidiaries are not consolidated. The investments in net assets of the subsidiaries are recorded in the balance sheets. The income from operations of the subsidiaries is reported on a net basis as equity in income of subsidiaries.
As a holding company with no business operations, Xcel Energy Inc.’s assets consist primarily of investments in its utility subsidiaries. Xcel Energy Inc.’s material cash inflows are only from dividends and other payments received from its utility subsidiaries and the proceeds raised from the sale of debt and equity securities. The ability of its utility subsidiaries to make dividend and other payments is subject to the availability of funds after taking into account their respective funding requirements, the terms of their respective indebtedness, the regulations of the FERC under the Federal Power Act, and applicable state laws. Management does not expect maintaining these requirements to have an impact on Xcel Energy Inc.’s ability to pay dividends at the current level in the foreseeable future. Each of its utility subsidiaries, however, is legally distinct and has no obligation, contingent or otherwise, to make funds available to Xcel Energy Inc.
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Guarantees and Indemnifications
Xcel Energy Inc. provides guarantees and bond indemnities under specified agreements or transactions, which guarantee payment or performance. Xcel Energy Inc.’s exposure is based upon the net liability of the relevant subsidiary under the specified agreements or transactions. Most of the guarantees and bond indemnities issued by Xcel Energy Inc. limit the exposure to a maximum stated amount. As of Dec. 31, 2025 and 2024, Xcel Energy Inc. had no
Guarantees and bond indemnities issued and outstanding as of Dec. 31, 2025:
| (Millions of Dollars) | Guarantor | Guarantee Amount | Current Exposure | Triggering Event | ||||||||||||||||||||||
| Guarantees of Capital Services equipment purchase contracts | Xcel Energy Inc. | (a) | (b) | |||||||||||||||||||||||
| Guarantees of Xcel Energy Services Inc. performance and payments on operating lease agreements | Xcel Energy Inc. | 43 | (b) | |||||||||||||||||||||||
Guarantee performance and payment of surety bonds for Xcel Energy Inc.’s utility subsidiaries (c) | Xcel Energy Inc. | (d) | (e) | |||||||||||||||||||||||
(a)Relative to the guaranteed performance obligations of Capital Services, vendors have completed approximately 60% of the manufacturing required to deliver completed equipment.
(b)Nonperformance and/or nonpayment.
(c)The surety bonds primarily relate to workers compensation benefits and utility projects. The workers compensation bonds are renewed annually and the project based bonds expire in conjunction with the completion of the related projects.
(d)Due to the number of projects associated with the surety bonds, the total current exposure of this indemnification cannot be determined. Xcel Energy Inc. believes the exposure to be significantly less than the total amount of the outstanding bonds.
(e)Per the indemnity agreement between Xcel Energy Inc. and the various surety companies, surety companies have the discretion to demand that collateral be posted.
Indemnification Agreements
Xcel Energy Inc. provides indemnifications through contracts entered into in the normal course of business. Indemnifications are primarily against adverse litigation outcomes in connection with underwriting agreements, breaches of representations and warranties, including corporate existence, transaction authorization and certain income tax matters. Obligations under these agreements may be limited in terms of duration or amount. Maximum future payments under these indemnifications cannot be reasonably estimated as the dollar amounts are often not explicitly stated.
Related Party Transactions
Xcel Energy Inc. presents related party receivables net of payables. Accounts and notes receivable net of payables with affiliates at Dec. 31:
| (Millions of Dollars) | 2025 | 2024 | ||||||||||||
| NSP-Minnesota | $ | $ | ||||||||||||
| NSP-Wisconsin | ||||||||||||||
| PSCo | ||||||||||||||
| SPS | ||||||||||||||
| Xcel Energy Services Inc. | ||||||||||||||
| Other subsidiaries of Xcel Energy Inc. | ||||||||||||||
| $ | $ | |||||||||||||
Dividends — Cash dividends paid to Xcel Energy Inc. by its subsidiaries were $1,258 million, $1,685 million and $1,693 million for the years ended Dec. 31, 2025, 2024 and 2023, respectively. These cash receipts are included in operating cash flows of the condensed statements of cash flows.
Money Pool — FERC approval was received 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 Inc. 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 Inc.
Money pool lending for Xcel Energy Inc.:
| (Amounts in Millions, Except Interest Rates) | Three Months Ended Dec. 31, 2025 | Year Ended | ||||||||||||||||||||||||
| 2025 | 2024 | 2023 | ||||||||||||||||||||||||
| Loan outstanding at period end | $ | $ | $ | $ | ||||||||||||||||||||||
| Average loan outstanding | ||||||||||||||||||||||||||
| Maximum loan outstanding | ||||||||||||||||||||||||||
| Weighted average interest rate, computed on a daily basis | % | % | % | % | ||||||||||||||||||||||
| Weighted average interest rate at end of period | N/A | |||||||||||||||||||||||||
| Money pool interest income | $ | $ | $ | $ | ||||||||||||||||||||||
During 2024, Xcel Energy Inc. purchased $166 million in aggregate principal amounts of NSP-Minnesota’s 2.60 % First Mortgage Bonds Series due June 1, 2051 for $105 million.
During 2025, Xcel Energy Inc. purchased $787 million in aggregate principal amounts of NSP-Minnesota’s 4.125 % First Mortgage Bonds Series due May 15, 2044, 4.00 % First Mortgage Bonds Series due August 15, 2045, 3.60 % First Mortgage Bonds Series due May 15, 2046, 2.90 % First Mortgage Bonds Series due March 1, 2050, 2.60 % First Mortgage Bonds Series due June 1, 2051, and 3.20 % First Mortgage Bonds Series due April 1, 2052, for $607 million.
See notes to the consolidated financial statements in Part II, Item 8.
SCHEDULE II
Xcel Energy Inc. and Subsidiaries Valuation and Qualifying Accounts Years Ended Dec. 31
| Allowance for bad debts | NOL and tax credit valuation allowances | ||||||||||||||||||||||||||||||||||||||||
| (Millions of Dollars) | 2025 | 2024 | 2023 | 2025 | 2024 | 2023 | |||||||||||||||||||||||||||||||||||
| Balance at Jan. 1 | $ | $ | $ | $ | $ | $ | |||||||||||||||||||||||||||||||||||
| Additions charged to costs and expenses | |||||||||||||||||||||||||||||||||||||||||
| Additions charged to other accounts | (a) | (a) | (a) | ||||||||||||||||||||||||||||||||||||||
| Deductions from reserves | ( | (b) | ( | (b) | ( | (b) | ( | (c) | ( | (c) | ( | (c) | |||||||||||||||||||||||||||||
| Balance at Dec. 31 | $ | $ | $ | $ | $ | $ | |||||||||||||||||||||||||||||||||||
(a)Recovery of amounts previously written-off.
(b)Deductions related primarily to bad debt write-offs.
(c)Primarily reversals of valuation allowances on completed tax credit sales and reductions of valuation allowances for items forecasted to be used prior to expiration .
ITEM 16 — FORM 10-K SUMMARY | ||
None.
91
Table of Contents
Signatures
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this annual report to be signed on its behalf by the undersigned thereunto duly authorized.
| XCEL ENERGY INC. | ||||||||
| Feb. 25, 2026 | By: | /s/ BRIAN J. VAN ABEL | ||||||
| Brian J. Van Abel | ||||||||
| Executive Vice President, Chief Financial Officer | ||||||||
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities on the date indicated above.
| /s/ ROBERT C. FRENZEL | Chairman, President, Chief Executive Officer and Director | ||||||||||
| Robert C. Frenzel | (Principal Executive Officer) | ||||||||||
| /s/ BRIAN J. VAN ABEL | Executive Vice President, Chief Financial Officer | ||||||||||
| Brian J. Van Abel | (Principal Financial Officer) | ||||||||||
| /s/ MELISSA L. OSTROM | Senior Vice President, Controller | ||||||||||
| Melissa L. Ostrom | (Principal Accounting Officer) | ||||||||||
| * | |||||||||||
| Megan Burkhart | Director | ||||||||||
| * | |||||||||||
| Lynn Casey | Director | ||||||||||
| * | |||||||||||
| Maria Demaree | Director | ||||||||||
| * | |||||||||||
| Netha Johnson | Director | ||||||||||
| * | |||||||||||
| Patricia L. Kampling | Director | ||||||||||
| * | |||||||||||
| George J. Kehl | Director | ||||||||||
| * | |||||||||||
| Richard T. O’Brien | Director | ||||||||||
| * | |||||||||||
| Charles Pardee | Director | ||||||||||
| * | |||||||||||
| James Prokopanko | Director | ||||||||||
| * | |||||||||||
| Devin Stockfish | Director | ||||||||||
| * | |||||||||||
| Timothy Welsh | Director | ||||||||||
| *By: | /s/ BRIAN J. VAN ABEL | ||||||||||
| Brian J. Van Abel | Attorney-in-Fact | ||||||||||
92
FAQ
What is Xcel Energy (XEL) and where does it operate?
Xcel Energy is a major regulated electric and natural gas delivery company headquartered in Minneapolis. It serves about 3.9 million electric and 2.2 million natural gas customers across Colorado, Michigan, Minnesota, New Mexico, North Dakota, South Dakota, Texas and Wisconsin.
How much does Xcel Energy plan to invest in its grid and clean energy?
Xcel Energy plans to invest about $60 billion over the next five years. Spending targets reliability, resiliency, sustainability and demand growth, with roughly $29 billion in 2026–2030 earmarked specifically for transmission and distribution system improvements across its service territories.
What are Xcel Energy’s key clean energy and emissions reduction goals?
Xcel Energy targets zero‑carbon electricity by 2050 and net‑zero greenhouse gas emissions from natural gas service by 2050. Through 2025, it estimates a 58% reduction in carbon emissions from generation versus 2005 levels and plans to fully exit coal by the end of 2030.
How has Xcel Energy performed financially over time for investors?
Xcel Energy reports meeting or exceeding its initial ongoing earnings guidance range for 21 consecutive years. It has also delivered 23 straight years of dividend growth, positioning its total shareholder return as a key pillar of its performance-focused strategy for long‑term investors.
What major risks does Xcel Energy highlight in its business?
Xcel Energy cites operational hazards, wildfire exposure, extreme weather, commodity price volatility, changing regulation, cybersecurity threats, long‑term resource planning challenges and credit or capital market risks. These factors could impact reliability, cost recovery, capital needs, earnings stability and overall financial condition.
How is Xcel Energy addressing wildfire risk in its service areas?
Xcel Energy has wildfire mitigation and system resiliency plans approved in Colorado and Texas, with public plans in each state it serves. Investments include advanced cameras, weather stations, safety settings, pole inspections, replacements and public safety power shutoffs to reduce ignition risk and protect communities.
What workforce and diversity metrics does Xcel Energy disclose?
Xcel Energy reports 11,534 full‑time employees as of December 2025, with 44% covered by collective bargaining. It provides diversity data showing female and ethnically diverse representation across its board, management, employees, new hires and interns, and ties 70% of annual incentives to safety, reliability and inclusion metrics.
Xcel Energy Inc
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Utilities - Regulated Electric
Electric & Other Services Combined
United States
MINNEAPOLIS