10-K – 2026-02-25 – xel-20251231.htm

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.
Biennially, as part of Xcel Energy’s enterprise risk program, an integrated cybersecurity risk identification and assessment is completed across Xcel Energy’s business, including generation, transmission, distribution and fuel storage facilities, information technology systems and other infrastructure or physical assets as well as information processed in our systems (including systems hosted by third parties) that could be affected by cybersecurity incidents. This analysis includes the impact, likelihood, timeframe and controllability of cybersecurity risks and is presented to the Board of Directors. Management monitors and reviews the results of this analysis, integrating them into the enterprise risk assessment processes and implements appropriate mitigating actions as needed.
Xcel Energy’s cybersecurity policies, standards, practices, annual cybersecurity training content and readiness are regularly assessed by third-party consultants. These partners are engaged to perform independent penetration testing and other security related services to assist in the prevention, detection, monitoring, mitigation and remediation of cybersecurity incidents and risks. The results of these assessments are communicated to management and the Board of Directors by the Chief Security Officer.
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 .

Management has assigned responsibility for the security risk program to the Chief Security Officer who has multiple years of experience in the Defense Industrial Base. The Chief Security Officer is informed about and monitors prevention, detection, mitigation and remediation efforts through a team of security professionals, many of whom are Certified Information Systems Security Professionals, Certified Information Security Managers or have received other cybersecurity certifications. The team has extensive experience selecting, deploying and operating cybersecurity technologies, initiatives and processes that aid in preventing, remediating and mitigating known and unknown security threats.
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.
The Board of Directors oversees the risks associated with cybersecurity and the physical security of our assets, with information security matters being discussed at board meetings as well as at the ONES and Audit Committee meetings throughout the year.
While the ONES Committee has primary committee responsibility for cybersecurity due to the operational issues involved, the Board of Directors has determined that the topic is of sufficient importance to warrant this comprehensive oversight approach. Augmenting such oversight efforts, the enterprise has the ability to notify and update the Board of Directors in the event of a possible crisis situation.
Cybersecurity risks are a part of Xcel Energy’s normal course of business. To date, no cybersecurity incident or attack affecting us or our vendors has had a material impact on our business or results of operations. As of Feb. 25, 2026 there have been no material cybersecurity incidents to report.

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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 unde rground transmis sion 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/ DELOITTE & TOUCHE LLP

Minneapolis, Minnesota
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 $ 12,160   $ 11,147   $ 11,446  
Natural gas 2,452   2,230   2,645  
Other 57   64   115  
Total operating revenues 14,669   13,441   14,206  

Operating expenses
Electric fuel and purchased power 3,961   3,788   4,278  
Cost of natural gas sold and transported 1,041   951   1,456  
Cost of sales — other 11   14   49  
Operating and maintenance expenses 2,732   2,540   2,444  
Conservation and demand side management expenses 406   394   286  
Depreciation and amortization 2,953   2,744   2,448  
Taxes (other than income taxes) 686   624   657  
Marshall Wildfire litigation 296   —   —  
Loss on Comanche Unit 3 litigation —   —   35  
Workforce reduction expenses —   —   72  
Total operating expenses 12,086   11,055   11,725  

Operating income 2,583   2,386   2,481  

Other income, net 235   143   22  
Earnings from equity method investments 17   19   35  
Allowance for funds used during construction — equity 281   168   91  

Interest charges and financing costs
Interest charges — includes other financing costs 1,468   1,255   1,055  
Allowance for funds used during construction — debt ( 125 ) ( 73 ) ( 51 )
Total interest charges and financing costs 1,343   1,182   1,004  

Income before income taxes 1,773   1,534   1,625  
Income tax benefit ( 245 ) ( 402 ) ( 146 )
Net income $ 2,018   $ 1,936   $ 1,771  

Weighted average common shares outstanding:
Basic 587   563   552  
Diluted 589   563   552  

Earnings per average common share:
Basic $ 3.44   $ 3.44   $ 3.21  
Diluted 3.42   3.44   3.21  

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 $ 2,018   $ 1,936   $ 1,771  
Other comprehensive income
Pension and retiree medical benefits:
Net pension and retiree medical losses arising during the period, net of tax ( 1 ) ( 3 ) ( 4 )
Reclassification of losses to net income, net of tax 2   5   2  
Derivative instruments:
Net fair value increase (decrease), net of tax 2   22   ( 2 )
Reclassification of losses to net income, net of tax 2   2   3  

Total other comprehensive income (loss) 5   26   ( 1 )
Total comprehensive income $ 2,023   $ 1,962   $ 1,770  
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 $ 2,018   $ 1,936   $ 1,771  
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization 2,968   2,769   2,471  
Nuclear fuel amortization 114   106   96  
Deferred income taxes 414   225   ( 59 )
Allowance for equity funds used during construction ( 281 ) ( 168 ) ( 91 )
Earnings from equity method investments ( 17 ) ( 19 ) ( 35 )
Dividends from equity method investments 32   34   35  
Provision for bad debts 61   47   79  
Share-based compensation expense 46   33   25  

Changes in operating assets and liabilities:
Accounts receivable ( 129 ) 19   ( 27 )
Accrued unbilled revenues ( 48 ) 21   252  
Inventories ( 300 ) ( 140 ) ( 98 )
Other current assets ( 122 ) ( 139 ) 86  
Accounts payable ( 50 ) 37   ( 149 )
Net regulatory assets and liabilities ( 189 ) 436   911  
Other current liabilities ( 174 ) ( 317 ) 200  
Pension and other employee benefit obligations ( 100 ) ( 89 ) 17  
Other, net ( 160 ) ( 150 ) ( 157 )
Net cash provided by operating activities 4,083   4,641   5,327  

Investing activities
Capital/construction expenditures ( 10,908 ) ( 7,364 ) ( 5,854 )

Purchase of investment securities ( 1,200 ) ( 998 ) ( 994 )
Proceeds from the sale of investment securities 1,197   961   959  
Other, net ( 58 ) ( 27 ) ( 37 )
Net cash used in investing activities ( 10,969 ) ( 7,428 ) ( 5,926 )

Financing activities
Proceeds (repayments) of short-term borrowings, net 855   ( 90 ) ( 28 )
Proceeds from issuances of long-term debt 5,763   3,647   2,630  
Repayments of long-term debt ( 1,713 ) ( 656 ) ( 1,151 )
Proceeds from issuance of common stock 3,349   1,117   270  
Dividends paid ( 1,282 ) ( 1,175 ) ( 1,092 )
Other, net 9   ( 6 ) ( 12 )
Net cash provided by financing activities 6,981   2,837   617  

Net change in cash and cash equivalents 95   50   18  
Cash, cash equivalents and restricted cash at beginning of period 179   129   111  
Cash, cash equivalents and restricted cash at end of period $ 274   $ 179   $ 129  

Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized) $ ( 1,262 ) $ ( 1,131 ) $ ( 945 )

Supplemental disclosure of non-cash investing and financing transactions:
Accrued property, plant and equipment additions $ 1,170   $ 964   $ 553  
Inventory transfers to property, plant and equipment 348   258   197  
Operating and finance lease right-of-use assets 1,253   138   238  
Allowance for equity funds used during construction 281   168   91  
Issuance of common stock for reinvested dividends and/or equity awards 80   68   64  
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 $ 274   $ 179  
Accounts receivable, net 1,330   1,249  
Accrued unbilled revenues 880   832  
Inventories 761   666  
Regulatory assets 529   561  
Derivative instruments 165   114  

Prepayments and other 1,075   724  
Total current assets 5,014   4,325  

Property, plant and equipment, net 65,639   57,198  

Other assets
Nuclear decommissioning fund and other investments 4,389   3,896  
Regulatory assets 2,998   2,849  
Derivative instruments 54   72  
Operating lease right-of-use assets 893   1,060  
Finance lease right-of-use assets 1,348   111  
Other 1,036   524  
Total other assets 10,718   8,512  
Total assets $ 81,371   $ 70,035  

Liabilities and Equity
Current liabilities
Current portion of long-term debt $ 501   $ 1,103  
Short-term debt 1,550   695  
Accounts payable 2,307   1,781  
Regulatory liabilities 714   852  
Taxes accrued 579   535  
Accrued interest 337   280  
Dividends payable 355   314  
Derivative instruments 31   37  
Operating lease liabilities 110   227  
Other 605   635  
Total current liabilities 7,089   6,459  

Deferred credits and other liabilities
Deferred income taxes 6,004   5,319  

Regulatory liabilities 6,277   6,010  
Asset retirement obligations 3,888   3,713  
Derivative instruments 67   77  
Customer advances 129   146  
Pension and employee benefit obligations 365   477  
Operating lease liabilities 788   867  
Finance lease liabilities 1,262   60  
Other 61   69  
Total deferred credits and other liabilities 18,841   16,738  

Commitments and contingencies
Capitalization
Long-term debt 31,832   27,316  
Common stock — 1,000,000,000 shares authorized of $ 2.50 par value; 623,600,715 and 574,365,598 shares outstanding at Dec. 31, 2025 and Dec. 31, 2024, respectively
1,559   1,436  
Additional paid in capital 12,906   9,601  
Retained earnings 9,207   8,553  
Accumulated other comprehensive loss ( 63 ) ( 68 )
Total common stockholders’ equity 23,609   19,522  
Total liabilities and equity $ 81,371   $ 70,035  

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 549,578,018   $ 1,374   $ 8,155   $ 7,239   $ ( 93 ) $ 16,675  

Net income 1,771   1,771  
Other comprehensive loss ( 1 ) ( 1 )
Dividends declared on common stock ($ 2.08 per share)
( 1,148 ) ( 1,148 )
Issuances of common stock 5,363,685   13   295   308  

Share-based compensation 15   ( 4 ) 11  

Balance at Dec. 31, 2023 554,941,703   $ 1,387   $ 8,465   $ 7,858   $ ( 94 ) $ 17,616  

Net Income 1,936   1,936  
Other comprehensive income 26   26  
Dividends declared on common stock ($ 2.19 per share)
( 1,236 ) ( 1,236 )
Issuances of common stock 19,423,895   49   1,098   1,147  

Share-based compensation 38   ( 5 ) 33  

Balance at Dec. 31, 2024 574,365,598   $ 1,436   $ 9,601   $ 8,553   $ ( 68 ) $ 19,522  

Net income 2,018   2,018  
Other comprehensive income 5   5  
Dividends declared on common stock ($ 2.28 per share)
( 1,357 ) ( 1,357 )
Issuances of common stock 49,235,117   123   3,253   3,376  

Share-based compensation 52   ( 7 ) 45  

Balance at Dec. 31, 2025 623,600,715   $ 1,559   $ 12,906   $ 9,207   $ ( 63 ) $ 23,609  

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.