What changed in this filing

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Item 1. Business

2026-02-26 compared with 2025-03-07 · 95 added, 177 removed, 199 unchanged (58% of the section changed)

We are a leading provider and operator of large horsepower contract compression infrastructure in the U.S.

Our wholly-owned subsidiary Kodiak Services was formed in 2011, and we have been operating compression infrastructure since that time.

On July 3, 2023, we completed our IPO and our common stock is currently trading on the New York Stock Exchange ("NYSE") under the ticker symbol "KGS."

On April 1, 2024, we completed the acquisition of CSI Compressco, pursuant to the terms of the Merger Agreement.

CSI Compressco unitholders received 0.086 shares of common stock for each CSI Compressco common unit owned.

CSI Compressco unitholders that met certain criteria and that so elected (the “Electing Unitholders”) received 0.086 limited liability company common units (“OpCo Units”) representing economic interests in Kodiak Services (along with an equal number of shares of non-economic voting preferred stock of Kodiak) for each CSI Compressco common unit they held.

At the option of the holder, each such Opco Unit is redeemable for one share of our common stock (along with cancellation of a corresponding share of preferred stock of Kodiak), following a 180 day post-closing lock-up period and subject to certain conditions.

In connection with the CSI Acquisition, we re-evaluated our reportable segments.

Our determination of reportable segments was made on the basis of our strategic priorities within each segment and corresponds to the manner in which our chief operating decision maker reviews and evaluates operating performance to make decisions about resources to be allocated to the segment.

As a result, our business is managed through the following two operating segments:

We are a leading provider and operator of large horsepower contract compression infrastructure in the U.S, supporting the critical movement and processing of natural gas across key production regions.

Through our wholly-owned subsidiary, Kodiak Services, formed in 2011, we have built and operated a substantial fleet of high-reliability compression assets for more than a decade.

On July 3, 2023, we completed our IPO and our common stock is currently trading on the New York Stock Exchange (“NYSE”) under the ticker symbol “KGS.” Our business is centered on long‑term customer relationships, operational excellence, and disciplined capital deployment, positioning us to deliver stable performance while supporting the essential infrastructure needs of the domestic energy industry.

Our business is managed through the following two operating segments:

Contract Services and Other Services.

The results of operations of CSI Compressco are reflected in our accompanying consolidated financial statements from the closing date of the acquisition through December 31, 2024.

Results for the periods prior to April 1, 2024 do not include the financial and operating results of CSI Compressco.

As such, our historical results of operations are not comparable from period to period and may not be comparable to our financial results of operations in future periods.

Our Contract Services and related services are critical to our customers’ ability to reliably produce, gather and transport natural gas and oil.

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We believe the quality of our relationships with our customers, the historical reliability of our Contract Services and the structure of our contracts produce stable, recurring cash flow.

The combination of the reliability and critical nature of our assets, the strong capabilities of our work force, the strength of our customer relationships and contract structures, and our market leadership in the prolific Permian Basin have resulted in a historically high fleet utilization for our company.

are focused on being a resilient and sustainable enterprise and we seek to be a responsible operator that provides safe, reliable and efficient energy solutions.

The combination of the reliability and critical nature of our assets, the strong capabilities of our workforce, the strength of our customer relationships and contract structures, and our market leadership in the prolific Permian Basin have resulted in a historically high fleet utilization for our company.

We are focused on being a resilient and sustainable enterprise and we seek to be a responsible operator that provides safe, reliable and efficient energy solutions.

We will continue to innovate processes and technologies to assist our customers in meeting their emission reduction goals, while striving to provide a safe, inclusive and supportive environment for our employees and the communities where we operate.

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We continue to implement advanced systems to proactively analyze and monitor the operating conditions of our equipment, with a focus on maximizing uptime.

We believe our customers will continue to outsource all or a portion of their compression infrastructure needs, allowing them to limit their capital investments in compression equipment and increase their free cash flow or deploy capital on projects directly related to their core businesses.

We believe our customers will continue to outsource a portion of their compression infrastructure needs, allowing them to limit their capital investments in compression equipment and increase their free cash flow or deploy capital on projects directly related to their core businesses.

By outsourcing compression infrastructure, customers can efficiently address their changing compression requirements over time.

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The horsepower our fleet provides is characterized by a focus on large horsepower compression units, which aligns with the evolving industry demand for such units.

Large compression units enable multi-well pad development, reduce downtime, improve overall unit economics and provide lower emissions per horsepower relative to small horsepower compression units.

Large horsepower compression units enable multi-well pad development, reduce downtime, improve overall unit economics and provide lower emissions per horsepower relative to small horsepower compression units.

Fleet standardization and continued geographic concentration allow us to lower our cost of operations and improve margins through economies of scale.

Below is a tabular overview of our fleet by horsepower as of December 31, 2025:

(in thousands, except percentages)

Fleet Horsepower Percent of Total Horsepower Number of Units Percent of Units

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We strategically focus on deploying our compression assets in leading onshore U.S.

regions with superior hydrocarbon well and long production horizons.

regions with long production horizons.

We believe partnering with top-tier customers in regions with multi-decade resource life will support continued strong utilization and recontracting of our assets through energy industry and broader macroeconomic cycles.

As of December 31, 2024, approximately 82% of our compression assets were deployed in the Permian Basin and Eagle Ford Shale, which the United States Energy Information Administration (“EIA”) expects to maintain significant production volumes through at least 2050.

We believe these two regions have some of the largest and lowest-cost unconventional resources in the U.S.

Additionally, there are significant liquefied natural gas (“LNG”) export projects in development, and overall U.S.

LNG export capacity is expected to double by 2030, according to the EIA.

We expect this to translate into continued Permian Basin and Eagle Ford Shale natural gas production growth, requiring substantial additional compression horsepower.

As of December 31, 2025, approximately 82.8% of our compression assets were deployed in the Permian Basin and Eagle Ford Shale.

The United States Energy Information Administration (“EIA”) expects continued growth in U.S.

natural gas production through 2050, led by associated gas from the Permian Basin.

We believe these two regions contain some of the largest and lowest-cost unconventional oil and natural gas resources in the U.S.

Additionally, there are significant liquefied natural gas (“LNG”) export projects in development, and U.S.

LNG export capacity is expected to continue to expand as additional projects are deployed, constructed and placed into service, according to the EIA.

We expect this to translate into continued Permian Basin and Eagle Ford Shale natural gas production growth, and, in turn, ongoing demand for additional compression horsepower in these basins.

We believe the U.S.

will play an increasingly important role in global energy security, as the world continues to require reliable and growing natural gas and oil production to support increasing global energy demand.

In addition to the Permian Basin and Eagle Ford Shale, we have assets located in the Powder River Basin, Mid-Continent Region, DJ Basin, Appalachian Basin, Barnett Shale / East Texas Region and Black Warrior Basin.

We have developed long-term commercial relationships with premier upstream and midstream customers in our key areas of operations.

We believe alignment with our customers’ goals is a key differentiator to our business, and we have built a reputation backed by our mechanical availability to earn and strengthen customer loyalty.

We believe mechanical availability is a critical consideration for a customer in making its contract compression decisions.

We prioritize maintaining a high level of mechanical availability, which maximizes total customer operational uptime and revenue stability.

We believe these factors make us a leading choice for our customers.

We have developed a systematic and selective customer evaluation methodology, based on key criteria that include customers' credit rating, size, and geological asset quality.

will remain a significant net exporter of natural gas over the coming decades and therefore play an increasingly important role in global energy security, as the world continues to

require reliable and growing natural gas and oil production to support increasing global energy demand.

In addition to the Permian Basin and Eagle Ford Shale, we have compression assets in other key U.S.

producing regions, including the Powder River Basin, Mid-Continent Region, DJ Basin, Appalachian Basin, Barnett Shale / East Texas Region and Black Warrior Basin.

We have established long-term commercial relationships with leading upstream and midstream customers in our key areas of operations.

We believe alignment with our customers’ operational objectives is a key differentiator to our business, and our reputation for high mechanical availability has been central to earning and maintaining customer loyalty.

We believe mechanical availability is a critical consideration for a customer in making its contract compression decisions, and we prioritize maintaining a consistently high level of mechanical availability to support customer uptime and contribute to stable revenue generation.

We believe these factors position us as a preferred provider of large-horsepower contract compression services.

We employ a systematic and selective customer evaluation process that considers factors such as customers’ creditworthiness, size, and geological asset quality.

For the years ended December 31, 2025, 2024 and 2023, our four largest customers accounted for approximately 32%, 32%, and 33%, respectively, of our total revenues.

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Our Sustainability Leadership

The energy industry is in a pivotal time as the world moves toward ambitious emissions reduction targets while maintaining affordable and reliable sources of energy.

We maintain an intense focus on being one of the most sustainable and responsible operators of contract compression infrastructure.

Furthermore, we strive to provide a safe, inclusive and supportive environment for the communities in which we live and the customers and employees with whom we work.

The energy industry continues to evolve as operators balance the need for reliable, affordable energy with changing regulatory and operational expectations.

Our focus remains on being one of the most sustainable and responsible operators of contract compression infrastructure.

Furthermore, we strive to provide a safe and supportive environment for the communities in which we live and the customers and employees with whom we work.

We seek to continuously improve our operations, relationships with our stakeholders and ultimately maintain our position as a sustainable and responsible operator of contract compression infrastructure.

Part of our strategy includes owning a lower-emissions fleet capable of operating in regions with the most stringent U.S.

regulatory requirements (emissions of 0.5g NOx or less).

We believe it is imperative that we continue to develop and implement innovative strategies and technologies that further reduce emissions intensity and improve the operational reliability of our business.

Many of our upstream and midstream customers have significantly increased their commitments to reduce emissions and rely on us to help them achieve their reduction goals.

As part of our long-term strategy, we invest in modern compression equipment designed to meet stringent U.S.

air-quality regulatory standards in challenging operating regions.

It is important that we continue to develop and implement innovative strategies and technologies that further reduce emissions intensity and improve the operational reliability of our business.

Many of our upstream and midstream customers have established operational or environmental objectives, and we work with them to provide compression solutions that align with their requirements.

Electric motor driven compression is also part of our long-term strategy to reduce emissions intensity across our fleet.

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In addition, in select geographic areas where electric infrastructure exists, we assist our customers in building out their electric compression infrastructure.

Our people are vital to the success of our business.

As a result, we have developed a robust safety culture that permeates all aspects of our business.

Our employees are central to our success.

We maintain a robust safety culture that permeates all aspects of our business.

Our comprehensive training program emphasizes safety, improving technical skills and professional development for employees across functional areas.

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We created the Kodiak Cares Foundation to support employees and charitable causes in the communities in which we live and operate.

We are also committed to supporting veterans and do so through our recruiting and hiring efforts, as well as supporting several causes that assist veterans and active-duty military.

We also remain committed to supporting veterans through targeted recruiting and hiring efforts and partnerships with organizations that assist veterans and active-duty military.

Compression Industry

Compression is a mechanical process whereby natural gas is compressed to a smaller volume resulting in higher pressures.

This process is critical for the production, gathering, and transportation of natural gas is a core component of one of the leading artificial lift technologies utilized in oil production.

This process is critical for the production, gathering, and transportation of natural gas.

Without the increased pressure, gas cannot flow from the wellhead to end-markets.

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• A continued emphasis by federal, state and local regulatory agencies as well as oil and gas producers on reducing the volume of natural gas that is flared during the production of crude oil, which will result in the need for additional field infrastructure to transport natural gas, which in turn will result in increased demand for compression infrastructure.

• The prevalence of U.S.

oil and gas producers in key unconventional basins like the Permian Basin and the Eagle Ford Shale to rely on centralized gas lift as one of the more effective and efficient artificial lift technologies for the production of crude oil.

• The use of centralized gas lift as one of the more effective and efficient artificial lift technologies for the production of crude oil and is widely used by U.S.

oil and gas producers in key unconventional basins like the Permian Basin and the Eagle Ford Shale.

General Contract Services Contract Structures

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Term and Termination

Our contracts typically have a primary term length between one and seven years, depending on the customer, application, location, and size of the compression unit, with large horsepower typically contracted for a primary term of three or more years.

After the expiration of the primary term, our contracts continue on a month-to-month basis until renewed or until the contract is terminated by us or our customer, upon written notice.

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Payments are generally due within 30 days of the invoice date.

We are generally responsible for the costs and expenses associated with operation and maintenance of our equipment, although certain fees and expenses are the responsibility of our customers under the terms of our contracts.

We are generally responsible for the costs and expenses associated with operation and maintenance of our equipment, although

certain fees and expenses are the responsibility of our customers under the terms of our contracts.

For example, fuel gas necessary to operate our compression equipment is provided by our customers without cost to us.

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Air Emissions

The Clean Air Act (“CAA ” ) and comparable state laws regulate emissions of air pollutants from various industrial sources, including natural gas compressors, and impose certain monitoring and reporting requirements.

The CAA and comparable state laws regulate emissions of air pollutants from various industrial sources, including natural gas compressors, and impose certain monitoring and reporting requirements.

Such emissions are regulated by air emissions permits, which are applied for and obtained through various state or federal regulatory agencies.

Our standard natural gas Contract Services contract provides that the customer is responsible for obtaining air emissions permits and assuming the environmental risks related to site operations.

In some instances, our customers may be required to aggregate emissions from a number of different sources on the theory that the different sources should be considered a single source.

Any such determinations could have the effect of making projects more costly than our customers expected and could require the installation of more costly emissions controls, which could cause some of our customers not to pursue certain projects.

Our standard natural gas Contract Services contract provides that the customer is responsible for obtaining air emissions permits and assuming the environmental risks related to site operations, but new regulatory requirements could have the effect of making projects more costly than our customers expected and could require the installation of more costly emissions controls, which could cause some of our customers not to pursue certain projects.

There can be no assurance that future requirements compelling the installation of more costly emission control equipment would not have a material adverse impact on our business, financial condition, results of operations and cash available for distribution.

See the section titled “Risk Factors—Risks Related to Our Business and Our Industry—New regulations, proposed regulations and proposed modifications to existing regulations under the CAA, if implemented, could result in increased compliance costs and changes in customers’ demand and desired suppliers” of this Annual Report.

For additional information and associated risks, see the section titled “Risk Factors—Risks Related to Our Business and Our Industry—New regulations, proposed regulations and proposed modifications to existing regulations under the CAA, if implemented, could result in increased compliance costs and changes in customers’ demand and desired suppliers” of this Annual Report.

Climate Change

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Congress has considered legislation to restrict or regulate GHG emissions.

The $1 trillion legislative infrastructure package passed by Congress in November 2021 includes a number of climate-focused spending initiatives targeted at climate resilience, enhanced response and preparation for extreme weather events and clean energy and transportation investments.

In addition, the Inflation Reduction Act of 2022 (the “Inflation Reduction Act”) also provides significant funding for research and development of low-carbon energy production methods, carbon capture and other programs directed at addressing climate change.

A number of states have also begun to address GHG emissions, primarily through the planned development of emissions inventories or regional GHG cap and trade programs.

Depending on the particular program, we could be required to control GHG emissions or to purchase and surrender allowances for GHG emissions resulting from our operations.

The Inflation Reduction Act also amends the CAA to include a Methane Emissions Waste Reduction Incentive Program for petroleum and natural gas systems, which requires the EPA to impose a “waste emissions charge” on certain oil and gas sources that are already required to report under the EPA's Greenhouse Gas Reporting Program.

In order to implement the program, the Inflation Reduction Act required revisions to GHG reporting regulations for petroleum and natural gas systems (Subpart W) by 2024.

In May 2024, the Environmental Protection Agency (“EPA”) finalized a rule to expand the scope of the Greenhouse Gas Reporting Program for petroleum and natural gas facilities, as required by the Inflation Reduction Act.

Among other things, the rule expands the emissions events that are subject to reporting requirements to include “other large release events” and applies reporting requirements to certain new sources and sectors.

The rule took effect on January 1, 2025 for reporting year 2025 (due March 2026) in certain circumstances, with GHG reporting required for reporting year 2024 (due March 2025) in certain circumstances.

In November 2024, the EPA finalized a rule implementing the Inflation Reduction Act’s methane emissions charge.

The rule includes methodologies for calculating the amount by which a facility’s reported methane emissions are below or exceed the waste emissions thresholds and addresses certain exemptions created by the Inflation Reduction Act.

The methane emissions charge imposed under the Methane Emissions and Waste Reduction Incentive Program for calendar year 2024 is $900 per ton emitted over annual methane emissions thresholds, and increases to $1,200 in 2025, and $1,500 in 2026.

However, a proposed resolution has recently been filed in Congress under the Congressional Review Act to disapprove the methane emissions charge rule.

The Inflation Reduction Act of 2022 also amended the CAA to require the Environmental Protection Agency (the “EPA”) to impose a “waste emissions charge” on certain oil and gas sources that are already required to report under the EPA's Greenhouse Gas Reporting Program.

In November 2024, the EPA finalized a rule implementing the Inflation Reduction Act’s methane emissions requirements.

However, in March 2025, the Trump Administration implemented a Congressional Review Act disapproval of the methane charge regulatory provisions.

Independent of Congress, the EPA has promulgated regulations controlling GHG emissions under its existing CAA authority.

The EPA has adopted rules requiring many facilities, including petroleum and natural gas systems, to inventory and report their GHG emissions (as discussed above).

In addition, the EPA rules provide air permitting requirements for certain large sources of GHG emissions.

The requirement for certain large sources of GHG emissions to obtain and comply with permits could affect some of our and our customers’ largest new or modified facilities going forward but is not expected to cause us to incur material costs.

As noted in the risk factors below (see “Risk Factors—Risks Related to Our Business and Our Industry—New regulations, proposed regulations and proposed modifications to existing regulations under the CAA, if implemented, could result in increased compliance costs and changes in customers’ demand and desired suppliers”).

For example, the EPA has undertaken efforts to regulate emissions of methane (considered a GHG) in the natural gas and oil sector, with the adoption of additional, more stringent rules.

In 2015, the EPA finalized a performance standard that sets limits for stationary natural gas combustion turbines based on the use of natural gas combined cycle technology.

In April 2024, the EPA issued a final rule that revises the limits for new gas-fired combustion turbines, existing coal, oil- and gas-fired steam generating units and certain existing gas-fire combustion turbines.

The EPA has undertaken efforts to regulate emissions of methane (considered a GHG) in the natural gas and oil sector, with the adoption of additional, more stringent rules.

It is currently unclear whether or to what extent the Trump Administration may reconsider these standards.

At the international level, the U.S.

joined the international community at the 21st Conference of the Parties of the United Nations Framework Convention on Climate Change in Paris, France (“COP21”), which resulted in an agreement intended to nationally determine the participants’ contributions and set GHG emission reduction goals every five years beginning in 2020 (the “Paris Agreement”).

participated in the 21st Conference of the Parties of the United Nations Framework Convention on Climate Change in Paris, France (“COP21”), resulting in an agreement intended to nationally determine the participants’ contributions and set GHG emission reduction goals every five years beginning in 2020 (the “Paris Agreement”).

While the Paris Agreement does not impose direct requirements on emitters, national plans to meet its pledge could result in new regulatory requirements or initiatives.

However, in January 2025, President Trump withdrew the United States from the Paris Agreement.

Consequently, we cannot predict whether these pledges made during these international climate change meetings will result in any particular new regulatory requirements or initiatives or whether such requirements or initiatives will cause us to incur material costs should the U.S.'s participation in the Paris Agreement again change in the future.

Various state and local governments have also publicly committed to furthering the goals of the Paris Agreement.

Additionally, in March 2022, the U.S.

Securities and Exchange Commission (“SEC”) issued a proposed rule regarding the enhancement and standardization of mandatory climate-related disclosures for investors.

The proposed rule would require registrants to include certain climate-related disclosures in their registration statements and periodic reports, including, but not limited to, information about the registrant’s governance of climate-related risks and relevant risk management processes;

climate-related risks that are reasonably likely to have a material impact on the registrant’s business, results of operations, or financial condition and their actual and likely climate-related impacts on the registrant’s business strategy, model, and outlook;

climate-related targets, goals and transition plan (if any);

certain climate-related financial statement metrics in a note to their audited financial statements;

Scope 1 and Scope 2 GHG emissions;

and Scope 3 GHG emissions and intensity, if material, or if the registrant has set a GHG emissions reduction target, goal or plan that includes Scope 3 GHG emissions.

However, in April 2024, the SEC voluntarily stayed the effectiveness of the rule, pending completion of judicial review, and the new administration has requested the court to refrain from proceeding while the rule undergoes review.

Thus, the ultimate scope and impact on our business is uncertain, but compliance with the rule, if it takes effect, may result in increased legal, accounting and financial compliance costs, make some activities more difficult, time-consuming and costly, and place strain on our personnel, systems and resources.

However, in January 2025, President Trump withdrew the United States from the Paris Agreement.

Consequently, we cannot predict whether these pledges made during these international climate change meetings will lead to new regulatory requirements or initiatives or whether such requirements or initiatives will cause us to incur material costs should the U.S.’s participation in the Paris Agreement again change in the future.

Additionally, the U.S.

Securities and Exchange Commission (“SEC”) adopted a final rule in March 2024 requiring disclosures on climate-related risks and impacts, governance, targets and Scope 1 and Scope 2 greenhouse gas emissions, but not Scope 3 emissions.

Litigation in the U.S.

Court of Appeals for the Eighth Circuit is ongoing, but as of early 2026, the SEC has withdrawn its defense of the rule.

Thus, the ultimate scope, timing, and impact on our business remain uncertain, but compliance, if required, may result in increased legal, accounting and financial compliance costs, make some activities more difficult, time-consuming and costly, and place strain on our personnel, systems and resources.

Although it is not currently possible to predict with specificity how any proposed or future GHG legislation, regulation, agreements or initiatives will impact our business, any legislation or regulation of GHG emissions that may be imposed in areas in which we conduct business or on the assets we operate could result in increased compliance or operating costs, additional operating restrictions or reduced demand for our services, and could have a material adverse effect on our business, financial condition and results of operations.

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Additionally, the CWA and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities.

Federal and state regulatory agencies can impose administrative, civil and criminal penalties, as well as other enforcement mechanisms for non-compliance with discharge permits or other requirements of the CWA and analogous state laws and regulations.

The definition of WOTUS and, relatedly, the scope of federal CWA jurisdiction, have been the subject of notable rule making efforts and judicial challenges over several decades, culminating in a recent U.S.

Supreme Court decision issued in May 2023.

In 2015, the EPA and the U.S.

Army Corps of Engineers (“Corps”) issued a rule defining the scope of the EPA’s and the Corps’ jurisdiction over WOTUS under the CWA, which never took effect before being replaced by the Navigable Waters Protection Rule (“NWPR”) in 2020.

A coalition of states and cities, environmental groups and agricultural groups challenged the NWPR, which was vacated by a federal district court in August 2021.

The EPA and the Corps issued a final rule in January 2023 that based the definition of WOTUS on the pre-2015 definition.

Separately, in May 2023, the U.S.

Supreme Court’s decision in Sackett v.

EPA narrowed federal jurisdiction over wetlands to “traditional navigable waters” and wetlands or other waters that have a “continuous surface connection” with or are otherwise indistinguishable from traditional navigable water.

In September 2023, EPA and the Corps published a direct-to-final rule that conforms the regulatory definition of WOTUS to the Supreme Court’s May 2023 decision in Sackett .

However, litigation opposing the September 2023 final rule remains ongoing and substantial uncertainty exists with respect to future implementation of the September 2023 rule and the scope of CWA jurisdiction more generally.

In addition, in an April 2020 decision defining the scope of the CWA that was issued days after the NWPR was published, the U.S.

Supreme Court held that, in certain cases, discharges from a point source to a WOTUS through groundwater require a permit if the

discharge is the “functional equivalent” of a direct discharge.

The Court rejected the EPA and the Corps’ assertion that groundwater should be totally excluded from the CWA.

In November 2023, the EPA issued draft guidance describing the functional equivalent analysis and the information that should be used to determine which discharges through groundwater may require a permit.

If finalized, the guidance could subject previously unregulated discharges to CWA permit requirements.

As a result, future implementation is uncertain at this time.

Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of the CWA and analogous state laws and regulations.

Spill prevention, control and countermeasure plan requirements imposed under the CWA require appropriate containment berms and similar structures to help prevent the contamination of navigable waters in the event of a hydrocarbon tank spill, rupture or leak.

The CWA and analogous state laws also require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities.

The Oil Pollution Act of 1990, as amended (the “OPA”), amends the CWA and establishes strict liability and natural resource damages liability for unauthorized discharges of oil into waters of the U.S.

The Oil Pollution Act of 1990, as amended (the “OPA”), amended the CWA and established strict liability and natural resource damages liability for unauthorized discharges of oil into waters of the U.S.

The OPA requires owners or operators of certain onshore facilities to prepare facility response plans for a discharge of oil into waters of the United States.

Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of the CWA, OPA, and analogous state laws and regulations.

Our Contract Services do not currently generate process waste waters that are discharged into waters of the United States and we do not foresee this occurring in the future.

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Increased regulation under the Safe Drinking Water Act could lead to greater opposition to, and litigation concerning, natural gas and oil activities utilizing hydraulic fracturing or injection wells for waste disposal, which could indirectly impact our business, financial condition and results of operations.

We cannot predict the future of any such legislation and what additional, if any, regulations, restrictions and permits.

Adoption of such new laws and regulations at the federal or state level or the development of new interpretations of those requirements by the agencies that issue the required permits could lead to operational delays, increased operating costs and process prohibitions that could reduce demand for our Contract Services, which would materially adversely affect our revenue and results of operations.

Solid and Hazardous Waste

The Resource Conservation and Recovery Act (“RCRA”) and comparable state laws control the management and disposal of hazardous and non-hazardous waste.

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Drilling fluids, produced waters and most of the other wastes associated with the exploration, development and production of natural gas, natural gas liquids and oil, if properly handled, are currently exempt from regulation as hazardous waste under RCRA and, instead, are regulated under RCRA’s less stringent non-hazardous waste provisions, state laws or other federal laws.

However, it is possible that certain natural gas, natural gas liquids and oil drilling and production wastes now classified as non-hazardous could be classified as hazardous wastes in the future.

Any such change could result in an increase in the costs to manage and dispose of wastes, which could increase the costs of our customers’ operations.

However, any change in classification could result in an increase in the costs to manage and dispose of wastes, which could increase the costs of our customers’ operations.

Site Remediation

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Additionally, where contamination may be present, it is not uncommon for the neighboring landowners and other third parties to file claims for personal injury, property damage and recovery of response costs.

Although we generate materials in the course of our

operations that may be regulated as hazardous substances, we have not received notification that we may be potentially responsible for cleanup costs under CERCLA at any site.

While we do not currently own or lease any facilities or properties for storage or maintenance of our inactive contract services equipment, we may use third-party properties for such storage and possible maintenance and repair activities.

Additionally, our active contract services equipment typically is installed on properties owned or leased by third-party customers and operated by us pursuant to terms set forth in the contracts executed by those customers.

Under most of our contracts, our customers must contractually indemnify us for certain damages we might incur as a result of the release into the environment of hazardous and toxic substances.

We are not currently responsible for any remedial activities at any properties we use;

Although we generate materials in the course of our operations that may be regulated as hazardous substances, we have not received notification that we may be potentially responsible for cleanup costs under CERCLA at any site and we are not currently responsible for any remedial activities at any properties we use.

However, there is always the possibility that our future use of those properties may result in spills or releases of petroleum hydrocarbons, wastes or other regulated substances into the environment that may cause us to become subject to remediation costs and liabilities under CERCLA, RCRA or other environmental laws.

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Endangered Species Act and Migratory Birds

The Endangered Specifies Act (“ESA”) was established to protect endangered and threatened species.

The Endangered Species Act (“ESA”) was established to protect endangered and threatened species.

Pursuant to the ESA, if a species is listed as threatened or endangered, restrictions may be imposed on activities adversely affecting that species or its habitat.

Fish and Wildlife Service may designate critical habitat and suitable habitat areas it believes are necessary for survival of a threatened or endangered species.

While some of our facilities are in areas that may be designated as a habitat for endangered species, we believe that we are in substantial compliance with the ESA.

Similar protections are offered to migratory birds under the Migratory Bird Treaty Act (“MBTA”) and to bald and golden eagles under the Bald and Golden Eagle Protection Act (“BGEPA”).

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As of December 31, 2025, we had approximately 1,300 full-time employees.

Some employees in Mexico are subject to collective bargaining agreements.

None of our employees are subject to collective bargaining agreements.

We offer competitive and comprehensive compensation and benefits packages that include annual bonuses, stock awards, a 401(k) plan with employer contribution, healthcare and insurance benefits, health savings account with employer contribution, dependent care flexible spending account, paid time off, family leave, an employee assistance program and tuition assistance, among many other benefits.

Safety, Health and Wellness

The success of our business is fundamentally connected to the well-being of our people, and so we are committed to the safety, health and wellness of our employees.

Safety is a core value of our Company.

We actively promote the highest standards of safety, behavior and environmental awareness and strive to meet or exceed all applicable local and national regulations.

The success of our business depends fundamentally on the well-being of our people, and so we are committed to the safety, health and wellness of our employees.

Our comprehensive safety program emphasizes education, training, standard operating procedures, policies, and reporting to empower employees to perform tasks using best safety practices.

Talent Development

We invest significant resources to develop the talent needed to provide our industry-leading Contract Services.

We work closely with suppliers to develop training programs for our field service technicians.

Our field service technicians are supported by a dedicated training team.

Additionally, we offer a number of non-technical, targeted skills-based and career-enhancing training programs, including technical orientation for non-technical employees, supervisor coaching,

performance management and conflict resolution.

Our talent development programs provide employees with the resources they need to help achieve their career goals, build management skills and lead their organizations.

Emerging Growth Company

We are an “emerging growth company” as defined in the Jumpstart Our Business Startups Act of 2012 (the “JOBS Act”).

For as long as we are an emerging growth company, unlike public companies that are not emerging growth companies under the JOBS Act, we will not be required to:

• provide an auditor’s attestation report on management’s assessment of the effectiveness of our system of internal control over financial reporting pursuant to Section 404(b) of the Sarbanes-Oxley Act of 2002 (the “Sarbanes-Oxley Act”);

• comply with any new requirements adopted by the Public Company Accounting Oversight Board requiring mandatory audit firm rotation or a supplement to the auditor’s report in which the auditor would be required to provide additional information about the audit and the financial statements of the issuer;

• provide certain disclosures regarding executive compensation required of larger public companies or hold stockholder advisory votes on executive compensation required by the Dodd-Frank Wall Street Reform and Consumer Protection Act;

• obtain stockholder approval of any golden parachute payments not previously approved.

In addition, Section 107 of the JOBS Act provides that an emerging growth company can take advantage of the extended transition period provided in Section 7(a)(2)(B) of the Securities Act of 1933, as amended (the “Securities Act”), for adopting new or revised financial accounting standards.

We intend to take advantage of all of the reduced reporting requirements and exemptions, including the longer phase-in periods for the adoption of new or revised financial accounting standards under Section 107 of the JOBS Act, until we are no longer an emerging growth company.

Our election to use the phase-in periods permitted by this election may make it difficult to compare our financial statements to those of non-emerging growth companies and other emerging growth companies that have opted out of the longer phase-in periods under Section 107 of the JOBS Act and who will comply with new or revised financial accounting standards.

See “Risk Factors—Risks Related to Owning Kodiak Common Stock—Taking advantage of the reduced disclosure requirements applicable to ‘emerging growth companies’ may make our common stock less attractive to investors.” If we were to subsequently elect instead to comply with these public company effective dates, such election would be irrevocable pursuant to Section 107 of the JOBS Act.

We will cease to be an emerging growth company upon the earliest of:

• the last day of the fiscal year in which we have $1.235 billion or more in annual revenues;

• the date on which we become a “large accelerated filer” (the fiscal year-end on which the total market value of our common equity securities held by non-affiliates is $700 million or more as of June 30);

• the date on which we issue more than $1.0 billion of non-convertible debt securities over a three-year period;

• the last day of the fiscal year following the fifth anniversary of our initial public offering.

We invest significant resources in developing the skilled workforce required to deliver our industry‑leading Contract Services.

Our talent development programs combine technical training, professional development, and leadership readiness to support employee growth and ensure consistent, high‑quality service.

A core component of our technical training platform is our Technician Fundamentals program taught at our dedicated hands-on training facility, BEARS Academy.

The Technician Fundamentals program provides a structured hands-on learning opportunity for both new and experienced technicians when they join Kodiak.

The curriculum covers natural gas compression fundamentals, safety procedures, engine and compressor components and systems, electrical systems and panel boards, preventative maintenance, and troubleshooting, supplemented by virtual-reality scenarios for key standard operating procedures such as LOTO (lockout/tagout) and startup and shutdown.

In 2025, over 270 employees graduated from the three-week Technicians Fundamentals program.

BEARS Academy is also home to several other technical training courses, where our employees gain hands-on instruction in a safe, controlled environment, alongside a qualified trainer that enables them to practice with tools on equipment they work on every day.

Kodiak maintains a formal technical training curriculum spanning multiple levels of technical proficiency to continuously invest in the development of our technicians’ learning.

With a wide range of both internally developed courses and supplier-supported courses at BEARS Academy, our employees have gained tremendous skills and foundational competencies across our technical operations.

To further expand capacity and strengthen our technical pipeline, we are constructing a significantly larger, state-of-the-art training facility for our new BEARS Academy home in Midland, scheduled to open in summer 2026.

In addition to technical training, Kodiak recognizes the importance of professional development, regardless of role or position.

We provide both skill-based and job-specific courses designed to encourage all employees to grow in a manner that is meaningful to them.

Our robust manager curriculum including topics such as coaching, performance management, conflict resolution, and financial training supports the transition and enhances leadership capabilities across the organization.

Recent Developments

CSI Acquisition

On April 1, 2024, we completed the CSI Acquisition, pursuant to the terms of the Merger Agreement.

CSI Compressco unitholders received 0.086 shares of common stock for each CSI Compressco common unit owned.

The Electing Unitholders received 0.086 OpCo Units representing economic interests in Kodiak Services (along with an equal number of shares of non-economic voting preferred stock of Kodiak) for each CSI Compressco common unit they held.

At the option of the holder, each OpCo Unit is redeemable for one share of our common stock (along with cancellation of a corresponding share of preferred stock of Kodiak), following a 180 day post-closing lock-up period and subject to certain conditions.

Offerings and Share Repurchases

On September 11, 2024, Frontier TopCo Partnership, L.P.

(“Kodiak Holdings”), an affiliate of EQT AB and holder of record of Kodiak Gas Services, Inc.

common stock, sold 7,000,000 shares of common stock to the public pursuant to an underwritten offering (the “September Secondary Offering”).

We did not receive any proceeds from the September Secondary Offering.

On September 11, 2024, we also repurchased 1,000,000 shares from Kodiak Holdings in a private transaction (the “September Share Repurchase”).

The September Share Repurchase was consummated at a price of $25.00 per share for an aggregate purchase price of $25.0 million.

The shares of common stock purchased in the September Share Repurchase were recorded as treasury stock.

In November 2024, the Board of Directors at Kodiak (the "Kodiak Board") approved a share repurchase program to buy up to an aggregate of $50 million of our outstanding common stock (the “Share Repurchase Program”).

The Share Repurchase Program commenced on November 13, 2024 and expires on December 31, 2025.

We expect shares to be acquired from time to time in open-market transactions or through privately negotiated transactions at our discretion, subject to market conditions, applicable legal requirements and other relevant factors.

We expect any purchases to be funded by cash on hand, cash flow from operations and short-term borrowings.

As of December 31, 2024, 434,783 shares have been repurchased under the Share Repurchase Program as further detailed below.

On November 18, 2024, Kodiak Holdings, sold 6,565,217 shares of common stock to the public pursuant to an underwritten offering (the “November Secondary Offering”).

We did not receive any proceeds from the November Secondary Offering.

On November 18, 2024, we repurchased 434,783 shares from Kodiak Holdings in a private transaction (the “November Share Repurchase”) pursuant to the Share Repurchase Program.

The November Share Repurchase was consummated at a price of $34.50 per share for an aggregate purchase price of $15.0 million.

The shares of common stock purchased in the November Share Repurchase were recorded as treasury stock.

On December 12, 2024, Kodiak Holdings sold 5,500,000 shares of common stock to the public pursuant to an underwritten offering (the "December Secondary Offering").

We did not sell any shares of common stock nor did we receive any proceeds from the December Secondary Offering.

The December Secondary Offering closed on December 13, 2024.

On September 12, 2024, the Company sold certain property, plant and equipment and other assets in the U.S.

as well as our legal entity in Canada to a third-party buyer.

The majority of the operations were included in the Contract Services segment through the date of sale.

At the disposal date, total net assets sold were approximately $18.0 million, consisting primarily of compression equipment, inventory, and other assets.

Upon disposition, we incurred a loss of approximately $7.0 million included in loss (gain) on sale of assets in our consolidated statements of operations for the year ended December 31, 2024.

On December 9, 2024, we sold certain assets and our legal entity in Argentina.

The transaction constituted the sale of a business for accounting purposes.

Total assets sold primarily consisted of approximately $10.8 million in property, plant and equipment, $2.7 million in accounts receivable, and $2.2 million in inventory.

We recognized a loss of $13.6 million, which is included in loss (gain) on sale of assets in our consolidated statements of operations for the year ended December 31, 2024.

On February 21, 2025, Kodiak paid a cash dividend of $0.41 per share to all holders of Kodiak Common Stock as of the close of business on February 14, 2025, resulting in an aggregate payment of approximately $36.0 million.

Pending Acquisition of Distributed Power Solutions

On February 5, 2026, the Company entered into a purchase agreement to acquire DPS, a provider of distributed power solutions in an equity and cash transaction valued at approximately $675.0 million at the time of signing per the terms of the purchase agreement, subject to adjustment in accordance with the purchase agreement.

Per the terms of the purchase agreement, the purchase price includes $575.0 million in cash, subject to adjustment in accordance with the purchase agreement, and the issuance of 2,401,278 shares, representing approximately $100.0 million of the Company’s common stock based on the volume weighted average price of the Company’s stock price for the five days prior to February 5, 2026 of $41.64 to the sellers.

The obligations of each of the parties to consummate the transactions contemplated by the purchase agreement are subject to customary conditions.

The Company has agreed to pay to the sellers a termination fee of $37.1 million in the event the purchase agreement is terminated under certain circumstances.

Secondary Offerings and Share Repurchases

During 2025, affiliates of EQT AB, primarily Frontier TopCo Partnership, L.P., executed a series of secondary public offerings and Rule 144 sales of our common stock.

In addition, we repurchased over 2.7 million shares from EQT affiliates during 2025 pursuant to our Share Repurchase Program.

In the aggregate, these transactions reduced EQT’s ownership position from approximately 43.1% at the beginning of the year to zero by December 2, 2025.

In total, approximately 38.5 million shares were sold by EQT affiliates in non-dilutive transactions, and we did not receive any proceeds from these offerings.

On September 30, 2025, we sold our operations and legal entities in Mexico to a third-party buyer as part of a strategic refocus on core U.S.

contract compression activities.

The disposal resulted in a $33.3 million net loss.

On January 28, 2026, our Board declared a quarterly dividend of $0.49 per share of common stock, or approximately $43.1 million, which was paid on February 20, 2026 to stockholders of record at the close of business on February 13, 2026

Available Information

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Item 1. Business