Kodiak Gas Services, Inc. 10-K

Item 1. Business Overview We are a leading operator of contract compression infrastructure in the United States. Our wholly-owned subsidiary Kodiak Gas Services, LLC was formed in 2011, and we have been operating compression infrastructure since that time. We completed the acquisition of Pegasus Optimization Managers, LLC, a provider of compression infrastructure, in October 2019 and completed our IPO in July 2023. Our compression operations (“Compression Operations”) and related services are critical to our customers’ ability to reliably produce and transport natural gas and oil. We are a market leader in the Permian Basin, which is the largest producing natural gas and oil basin in the U.S. We operate our large horsepower compression units under stable, fixed-revenue term contracts with upstream and midstream customers. We believe large horsepower compression units serve more stable applications, receive longer initial contracts, are more likely to be renewed, and produce higher margins, ultimately generating recurring cash flow and return on invested capital. When properly maintained, our compression assets have long useful lives, consistent with the expected production lives of the key regions where we operate. We believe our customer-centric business model positions us as the preferred contract compression operator for our customers and creates long-standing relationships. We strategically invest in the training, development, and retention of our highly skilled and dedicated employees and believe their expertise and commitment to excellence enhances and differentiates our business model. Furthermore, we maintain an intense focus on being one of the most sustainable and responsible operators of contract compression infrastructure. As of December 31, 2023, approximately 84% of our existing compression assets were strategically deployed in the Permian Basin and Eagle Ford Shale, which the United States Energy Information Administration (“EIA”) expects will maintain significant production volumes through at least 2050. We believe these two regions have 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 2027, according to the EIA. We expect this to translate into Permian Basin and Eagle Ford Shale natural gas production growth, requiring substantial additional compression horsepower. We believe these regions 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. We are a leader in large horsepower compression, with approximately 81% of our approximately 3.3 million horsepower fleet comprised of compression units larger than 1,000 horsepower. Due to lower initial reservoir pressures, production from unconventional resources, such as the Permian Basin and Eagle Ford Shale, requires significantly more compression horsepower than from conventional production. This need for additional horsepower in those regions supports our large horsepower strategy. Additionally, increased demand for large horsepower infrastructure is driven by multi-well pad drilling, overall well density, and large-scale gathering systems. We believe the quality of our relationships with our customers, the reliability of our Compression Operations and the structure of our contracts produce stable, recurring cash flow. We derive substantially all of our revenues from fixed-revenue contracts. Our assets and supporting operations have an industry-leading historical average mechanical availability (which measures the percentage of time in a given period that Compression Operations are being provided or are capable of being provided) of over 99.5% since inception. 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 four-year average fleet utilization of over 99% (which measures the revenue-generating horsepower divided by our total fleet horsepower).We are focused on being a resilient and sustainable enterprise, and we have ambitious sustainability goals. 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. Finally, we operate our business with integrity and ethics and maintain a corporate governance structure that includes appropriate oversight and transparency in all aspects of our operations. Our Operations Our business model is focused on large horsepower contract Compression Operations, which we believe is central to our customers’ efforts to meet the expected growing natural gas and oil demand from the Permian Basin and other regions in the U.S. large horsepower Compression Operations tend to garner longer-term contracts than small horsepower Compression Operations and, as a result, we believe large horsepower Contract Operations provide us with better 9 Table of Conten ts predictability of revenues and operations. We believe our focus on customer service in top-tier regions, and the critical nature of our assets results in long-term customer relationships and financial stability for our business. Our preventative and predictive maintenance and overhaul programs are designed to maximize mechanical availability and extend the useful lives of our assets over multiple decades. These programs allow us to contract our existing compression assets at rates that are comparable to our newest compression units. Our standardized fleet also enables streamlined and systematic training and on-site maintenance, thereby maximizing uptime for our customers. We are currently implementing advanced systems to proactively analyze and monitor the operating conditions of our equipment, with a focus on maximizing uptime for our customers. Our maintenance culture is foundational to our customer-centric business model and has allowed us to provide on average 99.5% mechanical availability to our customers. 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. By outsourcing compression infrastructure, customers can efficiently address their changing compression requirements over time. Additionally, our customers benefit from the technical skills of our specialized personnel, and our focus on reliability and emissions reduction helps them advance their sustainability goals. We manage our business through two operating segments: Compression Operations and Other Services. “Compression Operations” consists of operating Company-owned and customer-owned compression infrastructure for our customers, pursuant to fixed-revenue contracts to enable the production and gathering of natural gas and oil. “Other Services” consists of a full range of contract services to support the needs of our customers, including station construction, maintenance and overhaul and other ancillary time and material-based offerings. Our Other Services offerings are often cross-sold, bolstering cash flow generation with no associated capital expenditures. Our Assets As of December 31, 2023, our compression asset base consists of 3,078 fleet compression units, amounting to approximately 3.3 million horsepower of owned compression, with an average of 1,059 horsepower per fleet compression unit. The average age of our fleet is 4.5 years and 72% of our compression fleet is less than five years old. Approximately 52% of our fleet is comprised of large horsepower compression units, aligning 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. 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, 2023: Fleet Horsepower Number of Units Percent of Total Horsepower Percent of Units Large horsepower >1,000 horsepower 2,653,737 1,596 81% 52% Medium & small horsepower <1,000 horsepower 607,924 1,482 19% 48% Total 3,261,661 3,078 100% 100% We have standardized our fleet and operational processes, creating an effective and seamless fleet maintenance program and spare parts inventory, and efficient and resilient supply chain. Additionally, our assets are designed to serve a wide variety of large horsepower applications, such as gathering, processing and transportation of natural gas and centralized gas lift of oil. Our Key Areas of Operation We strategically focus on deploying our compression assets in leading onshore U.S. regions with the longest 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, 2023, approximately 84% of our compression assets are deployed in the Permian Basin and Eagle Ford Shale, which the EIA expects to maintain significant production volumes through at least 2050. The Permian Basin and Eagle Ford Shale are connected through long-haul natural gas pipelines to the nearby U.S. Gulf Coast and are critical natural gas supply basins for the LNG export capacity expansion occurring in the region. In addition to the Permian Basin and Eagle Ford Shale, we have assets in the Powder River Basin, Mid-Continent Region, DJ Basin, Appalachian Basin, Barnett Shale / East Texas Region and Black Warrior Basin. 10 Table of Conten ts Kodiak Customers and Contracts 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 leading 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 over 99.5% mechanical availability in addition to providing uninterrupted “first-call” service for any and all downtime events across our fleet. This commitment to mechanical availability maximizes total customer operational uptime and revenue stability. We believe these factors make us the 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. Approximately 38% and 39% of our compression operations revenue came from our four largest customers for the years ended December 31, 2023 and 2022, respectively. Each of these customers is a S&P 500 constituent and investment grade-rated upstream or midstream company in the Permian Basin. Our customer-centric business model provides best-in-class reliability, which we believe is critical to securing and maintaining long-term relationships with our customers. Our contracts are designed to provide us with predictable, stable, and recurring cash flows through industry and broader macroeconomic cycles. To maximize cash flow stability, our contracts typically include: • fixed-revenue structures similar to midstream take-or-pay contracts; • annual built-in inflation adjustments; • pre-billing structure for the following month’s service fees; • primary contract terms of one to seven years in duration (with large horsepower compression units typically contracted for a primary term of three or more years); and • provisions requiring customers to pay for all mobilization and demobilization costs, which can be significant. Additionally, we believe that due largely to our history of high mechanical availability and the multi-decade resource life in our key areas of operations, our customer contracts often are renewed multiple times. 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. 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. Approximately 96% of our current fleet is lower-emissions capable, meaning it is 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. We have developed several technologies targeting additional emissions reductions including ecoView, our patented emissions monitoring and leak detection system that can be used to monitor, analyze and manage emissions (including greenhouse gas “GHG” emissions) data and operating data from our compressors, and other fugitive methane reduction solutions. We began broad scale integration of ecoView across our large horsepower compression fleet during 2023. Electric motor driven compression is also part of our long-term strategy to reduce emissions intensity across our fleet. We have begun deploying electric motor driven compression with select customers and have additional assets that we will deploy in the near future under long-term fixed-revenue contracts. 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 comprehensive training program emphasizes safety, improving technical skills and professional development for employees across functional areas. This program is further bolstered through a virtual training program to better prepare our employees to safely address situations in the field. Diversity, equity and inclusion (“DEI”) are critically important to our organization. We believe that by embracing diversity and promoting inclusion, we can unlock the full potential of our workforce and create a more resilient, innovative and successful organization. Diversity is also important at our board level, where 56% of our board of directors identify as diverse based on gender, race and/or 11 Table of Conten ts ethnicity. We created the Kodiak Cares Foundation to support employees and charitable causes in the community. 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. 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 as well as for centralized gas lift for oil production. Without the increased pressure, gas cannot flow from the wellhead to end-markets. With the development of unconventional natural gas and oil resources, compression infrastructure becomes even more critical for the following reasons: • In unconventional resources, natural gas tends to be produced at lower pressures due to the geological nature of the resources, requiring compression infrastructure immediately upon initial production and throughout most of the life of the well. • Advancements in drilling, completion and production technologies have resulted in an increase in density of well locations and adoption of multi-well pads, allowing operators to achieve economies of scale with centralization of stations with more compression units and more horsepower per unit. Given the essential nature of their operations, compression infrastructure providers benefit from stable cash flows and fixed-revenue contracts. Furthermore, large horsepower compression infrastructure is costly to install and move, and, therefore, operators have increasingly focused on deploying capital into their core business, favoring outsourcing contract compression. By outsourcing, operators can more efficiently address their changing compression needs over time and are able to benefit from the specialized personnel and technical skills that compression infrastructure providers offer. We believe U.S. compression infrastructure industry growth will be supported by the following factors: • Continued, growing demand for U.S. natural gas driven by domestic natural gas and global LNG consumption. • Replacement of production from maturing and aging conventional basins with production from unconventional sources, which tend to require more compression infrastructure, to accommodate the increase in natural gas demand while offsetting declining production. • 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 the most effective and efficient artificial lift technology for the production of crude oil. General Compression Operations Contract Structures The following discussion describes the material terms generally common to our Compression Operations contracts allocated to our Compression Operations reporting unit. We maintain a general gas compression agreement with each of our customers and separate addenda for each compression unit. 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. As of December 31, 2023, approximately 10.2% of our revenue-generating horsepower was on a month-to-month contract term. Mechanical Availability Guarantee and Operations Standards and Specifications All of our contracts provide a guarantee of specified “mechanical availability,” which we define as the percentage of time each month that our Compression Operations equipment is “mechanically available” to compress gas under the design and operating conditions set forth in the contract. Our Compression Operations equipment is typically mechanically available during instances of downtime attributable to events of force majeure or acts or failures to act by the customer (i.e., production-related downtime). Our Compression Operations equipment is typically not mechanically available during all other instances of downtime including, without limitation, our scheduled maintenance. 12 Table of Conten ts We provide Kodiak-owned Compression Operations under contracts that typically provide that we will supply all compression equipment, tools, parts and field service support to meet our customers’ requirements. Our contracts do not specify the compression equipment we will use; instead, the contracts specify required operating conditions and, in consultation with the customer, we determine what equipment is necessary to meet our contractual commitments. Fees, Taxes and Expenses Our customers pay a fixed monthly fee for our Compression Operations similar to midstream “take-or-pay contracts.” The majority of our contracts include an annual inflation adjustment to the monthly fee based on a series of the producer price index. Generally, we bill for our Compression Operations on the 15th day of a month for the following month’s Compression Operations (i.e., pre-billed). Payments are generally due within 30 days of the invoice date. If Compression Operations are provided for a partial month, the monthly fee is pro-rated that month and is invoiced “due on receipt.” 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. Further, ad valorem or business personal property taxes assessed on our compression equipment are generally reimbursed by our customers, as well as any sales tax related to our Compression Operations. Additionally, our customers are typically responsible for any damage to our compression equipment caused by contaminants or liquid carryover in the compressed gas stream or inferior fuel gas. We generally own the compression equipment in our fleet that we use to provide Compression Operations, and we typically bear the risk of loss or damage to our equipment and tools and injury or death to our personnel outside the exceptions set forth in the contracts. Additionally, substantially all of our contracts include provisions eliminating our liability for consequential damages (e.g., damage to formations, lost production, damage to production equipment, etc.). The vast majority of our contracts require our customers to pay for any out-of-pocket expenses associated with the cost of the mobilization and demobilization of our compression equipment to and from their locations. Our contracts typically provide that both we and our customers are required to carry various types of insurance coverage including, but not limited to, general liability, workers’ compensation, employers’ liability, property, automobile and excess liability insurance. Marketing and Sales Our marketing and customer service functions are performed on a coordinated basis by our sales and operations teams. Sales, fleet and operations personnel analyze and scope new compression applications. Additionally, our salespeople regularly visit our customers to ensure customer satisfaction, to determine a customer’s needs related to existing Compression Operations being provided and to determine the customer’s future compression requirements. This ongoing communication allows us to quickly identify and respond to our customers’ compression requirements and gives us significant insight into their activities. Suppliers and Service Providers We rely primarily on key vendors to manufacture, package and assemble our compression equipment. Although we rely primarily on these suppliers, we believe alternative sources for natural gas compression equipment are generally available if needed. However, relying on alternative sources may increase our costs and change the standardized nature of our fleet. We have not experienced any material supply problems to date. Competition The compression and related services business is competitive. On a regional basis, we experience competition from numerous smaller companies that may be able to adapt to changes more quickly within our industry and changes in economic conditions, more readily take advantage of available opportunities and adopt more aggressive pricing policies. Additionally, the historical availability of attractive financing terms from financial institutions and equipment manufacturers has made the purchase of individual compression units affordable for our customers. We believe that we compete effectively based on our customer-centric business model, flexibility in meeting customer needs, price, equipment availability, quality and reliability of our Compression Operations. Seasonality Our results of operations have not historically been materially affected by seasonality, and we do not currently have reason to believe that seasonal fluctuations will have a material impact in the foreseeable future. Operating Risks and Insurance 13 Table of Conten ts We believe that our insurance coverage is customary for the industry and adequate for our business. As is customary in the compression industry, we review our safety equipment and procedures and carry insurance against most, but not all, risks of our business. Losses and liabilities not covered by insurance would increase our costs. The compression business can be hazardous, involving unforeseen circumstances, such as uncontrollable flows of gas or well fluids, fires and explosions or environmental damage. To address the hazards inherent in our business, we maintain insurance coverage that, subject to certain deductibles, includes physical damage coverage, third party general liability insurance, employer’s liability, environmental and pollution and other coverage, although coverage for environmental and pollution related losses is subject to certain limitations. Under the terms of our standard Compression Operations contract, we are responsible for maintaining insurance coverage on our compression equipment. No accidents or incidents have occurred that have caused us to experience a material adverse effect. Governmental Regulation We are subject to stringent and complex federal, state and local laws and regulations governing the discharge of materials into the environment or otherwise relating to protection of human health, safety and the environment. These regulations include compliance obligations for air emissions, water quality, wastewater discharges and solid and hazardous waste disposal, as well as regulations designed for the protection of human health and safety and protected species. Compliance with these environmental laws and regulations could expose us to significant costs and liabilities and cause us to incur significant capital expenditures in our operations. We are often obligated to assist our customers in obtaining permits or approvals for their operations from various federal, state and local authorities. These permits and approvals can be denied or delayed, which may cause us to lose potential and current customers, interrupt our operations and limit our growth and revenue. Moreover, failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, imposition of remedial obligations and other injunctive relief that could delay or prohibit our operations. Private parties may also have the right to pursue legal actions to enforce compliance, as well as to seek damages for non-compliance with environmental laws and regulations or for personal injury or property damage. While we believe that our operations are in substantial compliance with applicable environmental laws and regulations and that continued compliance with current requirements would not have a material adverse effect on us, we cannot predict whether our cost of compliance will materially increase in the future. Any changes in existing environmental laws and regulations or the enforcement thereof, or passage of additional environmental laws and regulations that result in more stringent and costly requirements for pollution control equipment, waste handling, storage, transport, disposal or remediation could have a material adverse effect on our operations and financial position. See the section titled “Risk Factors—Risks Related to Our Business and Our Industry—Kodiak’s operations are subject to stringent environmental, health and safety regulation, and changes in these regulations could increase Kodiak’s costs or liabilities” in this Annual Report. The following is a discussion of material environmental and safety laws that relate to our operations. 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. 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 Compression Operations 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. 14 Table of Conten ts 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. Climate Change Climate change and GHG emissions reduction initiatives continue to attract considerable public and scientific attention. Methane, a primary component of natural gas, and carbon dioxide, a byproduct of the burning of natural gas, are examples of GHGs. In recent years, the U.S. 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 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 July 2023, the Environmental Protection Agency (“EPA”) proposed 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 proposed 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 is currently scheduled to be finalized in 2024 and would take effect on January 1, 2025 for reporting year 2025 (due March 2026) in certain circumstances, with the potential to also impact GHG reporting for reporting year 2024 (due March 2025) in certain circumstances. In January 2024, the EPA proposed a rule implementing the Inflation Reduction Act’s methane emissions charge. The proposed rule includes potential methodologies for calculating the amount by which a facility’s reported methane emissions are below or exceed the waste emissions thresholds and contemplates approaches for implementing 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 would be $900 per ton emitted over annual methane emissions thresholds, and would increase to $1,200 in 2025, and $1,500 in 2026. 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”), 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 for integrated gasification combined cycle units and utility boilers based on the use of the best system of emissions reduction that the EPA has determined has been adequately demonstrated for each type of unit. The rule also sets limits for stationary natural gas combustion turbines based on the use of natural gas combined cycle technology. In May 2023, the EPA issued a notice of proposed rule making that would revise 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 initial comment period ended in July 2023, but a supplemental notice of proposed rule making was issued in November 2023. The supplemental comment period ended in December 2023, and a final rule is anticipated by April 2024. 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”). 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. In April 2021, the current administration announced a new “nationally determined contribution” for U.S. GHG emissions that would achieve emissions reductions of 15 Table of Conten ts at least 50% relative to 2005 levels by 2030. Those national commitments by themselves create no binding requirements on individual companies or facilities, but they do provide indications of the current administration’s policy direction and the types of legislative and regulatory requirements—such as the EPA’s proposed methane rules—that may be needed to achieve those commitments. In September 2021, the U.S. and European Union jointly announced the launch of the “Global Methane Pledge,” which aims to cut global methane pollution by at least 30% by 2030 relative to 2020 levels, including “all feasible reductions” in the energy sector. Since its formal launch at the 26th Conference of the Parties (“COP26”), over 150 countries have joined the pledge. Additionally, at the 28th Conference of the Parties (“COP28”), member countries entered into an agreement that calls for actions towards achieving, at a global scale, a tripling of renewable energy capacity and doubling of energy efficiency improvements by 2030. The goals of the agreement, among other things, are to accelerate efforts towards the phase-down of unabated coal power, phase out inefficient fossil fuel subsidies, and take other measures that drive the transition away from fossil fuels in energy systems. With the exception of the final EPA methane rules and related updates, which were announced by President Biden at COP28, 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. 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. According to the most recent SEC rule making agenda, the SEC is targeting April 2024 for the finalization of these rules. Although the proposed rule’s ultimate date of effectiveness and the final form and substance of these requirements is not yet known and the ultimate scope and impact on our business is uncertain, compliance with the proposed rule, if finalized, 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. See “Risk Factors—Risks Related to Our Business and Our Industry—Kodiak’s business is subject to climate-related transitional risks, including evolving climate change legislation, regulatory initiatives and stakeholder pressures which could result in increased operating expenses and capital costs, financial risks and potential reduction in demand for Kodiak’s services.” Notwithstanding potential risks related to climate change, the International Energy Agency estimates that natural gas and oil will continue to represent a significant share of global energy use through 2040 under some, though not all, future scenarios. However, recent activism directed at shifting funding and/or demand away from companies with fossil fuel-related assets could result in limitations or restrictions on certain sources of funding for the energy sector. See “Risk Factors—Risks Related to Our Business and Our Industry—A climate-related decrease in demand for natural gas and oil could negatively affect Kodiak’s business.” Water Discharge The Clean Water Act (“CWA”) and analogous state laws impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of oil and other substances, into waters of the United States (“WOTUS”). The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or an analogous state agency. The CWA and regulations implemented thereunder also prohibit the discharge of dredge and fill material into regulated waters, including jurisdictional wetlands, unless authorized by an appropriately issued permit. The CWA also requires the development and implementation of spill prevention, control and countermeasures, including the construction and maintenance of containment berms and similar structures, if required, to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon tank spill, rupture or leak at such facilities. 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. 16 Table of Conten ts 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 United States. 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. Our Compression Operations 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. In any event, our customers assume responsibility under the majority of our standard gas compression agreements for obtaining any permits that may be required under the CWA, whether for discharges or developing property by filling wetlands. Considerable legal uncertainty exists surrounding the standard for what constitutes jurisdictional waters and wetlands subject to the protections and requirements of the CWA. Safe Drinking Water Act A significant portion of our customers’ hydrocarbon production is developed from unconventional sources that require hydraulic fracturing as part of the completion process. Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into the rock formation to stimulate hydrocarbon production. The U.S. Congress has from time to time considered legislation to amend the Safe Drinking Water Act (“SDWA”) to exempt hydraulic fracturing from the definition of “underground injection” and require federal permitting and regulatory control of hydraulic fracturing and disclosure of the chemical constituents of the fluids used in the fracturing process. Scrutiny of hydraulic fracturing activities continues in other ways. In December 2016, the EPA issued a report on the potential impacts of hydraulic fracturing on drinking water resources. The final report concluded that “water cycle” activities associated with hydraulic fracturing may impact drinking water resources “under some circumstances,” noting that the following hydraulic fracturing water cycle activities and local-or regional-scale factors are more likely than others to result in more frequent or more severe impacts: water withdrawals for fracturing in times or areas of low water availability; surface spills during the management of fracturing fluids, chemicals or produced water; injection of fracturing fluids into wells with inadequate mechanical integrity; injection of fracturing fluids directly into groundwater resources; discharge of inadequately treated fracturing wastewater to surface waters; and disposal or storage of fracturing wastewater in unlined pits. To date, the EPA has taken no further action in response to the December 2016 report. Under the CWA, the EPA also prohibits the discharge of wastewater from hydraulic fracturing and certain other natural gas operations to publicly owned wastewater treatment plants. State and federal regulatory agencies have also recently focused on a possible connection between the operation of injection wells used for natural gas and oil waste disposal and seismic activity. Increased regulation and attention given to induced seismicity 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. See “Risk Factors—Risks Related to Our Business and Our Industry—Increased regulation of 17 Table of Conten ts hydraulic fracturing could result in reductions of, or delays in, natural gas and oil production by our customers, which could adversely impact our revenue.” We cannot predict the future of any such legislation and what additional, if any, provisions would be included. If additional levels of regulation, restrictions and permits were required through the adoption of 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 Compression Operations, which would materially adversely affect our revenue and results of operations. Solid Waste The Resource Conservation and Recovery Act (“RCRA”) and comparable state laws control the management and disposal of hazardous and non-hazardous waste. These laws and regulations govern the generation, storage, treatment, transfer and disposal of wastes that we generate including, but not limited to, used oil, antifreeze, filters, sludges, paint, solvents and sandblast materials. The EPA and various state agencies have limited the approved methods of disposal for these types of wastes. 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. Site Remediation The Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”) and comparable state laws impose strict, joint and several liability without regard to fault or the legality of the original conduct on certain classes of persons that are considered to have contributed to the release of a hazardous substance into the environment. These persons include the owner and operator of a disposal site where a hazardous substance release occurred and any company that transported, disposed of or arranged for the transport or disposal of hazardous substances released at the site. Under CERCLA, such persons may be liable for the costs of remediating the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. 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 compression operations equipment, we may use third-party properties for such storage and possible maintenance and repair activities. Additionally, our active compression operations 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; 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. We cannot provide any assurance that the costs and liabilities associated with the future imposition of such remedial obligations upon us would not have a material adverse effect on our operations or financial position. Endangered Species Act and Migratory Birds The Endangered Specifies 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. The U.S. 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”). The presence of any protected species or the final designation of previously unprotected species as threatened or endangered in areas where we operate could result in increased costs from species protection measures or could result in limitations, delays, or prohibitions on our customers’ exploration and production activities. Safety and Health 18 Table of Conten ts The Occupational Safety and Health Act (“OSHA”) and comparable state laws and regulations govern the protection of the health and safety of employees. The OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of CERCLA and similar state statutes and regulations require that we organize and, as necessary, disclose information about hazardous materials used or produced in our operations to various federal, state and local agencies, as well as employees. Other OSHA standards regulate specific worker safety aspects of our operations. Human Capital Employees As of December 31, 2023, we had 781 full-time employees. None of our employees are subject to collective bargaining agreements. We consider our employees to be our greatest asset and believe that our success depends on our ability to attract, develop and retain our employees. DEI are foundational to our leadership approach, and our focus is on how our actions and the actions of our employees foster DEI in our everyday activities at Kodiak. We support diversity in hiring, and 30% of our executive leadership team is gender diverse and 44% of our total workforce is gender, racially and/or ethnically diverse as of the date hereof. We support pay equity for all legally protected individuals (i.e., gender, ethnicity, race) and believe 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. Talent Development We invest significant resources to develop the talent needed to provide our industry-leading Compression Operations. 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; or • 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 19 Table of Conten ts 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; or • the last day of the fiscal year following the fifth anniversary of our initial public offering. Recent Developments Dividend On February 23, 2024, Kodiak paid a quarterly cash dividend of $0.38 per share to all holders of Kodiak Common Stock as of the close of business on February 16, 2024, resulting in an aggregate payment of approximately $30 million. Pending Merger with CSI Compressco On December 19, 2023, Kodiak entered into the Merger Agreement with CSI Compressco and CSI Compressco GP LLC, the sole general partner of CSI Compressco, pursuant to which Kodiak agreed to acquire 100% of the issued and outstanding partnership interests of CSI Compressco in an all-equity transaction. In connection with closing of the Merger, Kodiak intends to (i) repay all amounts outstanding under CSI Compressco's existing (a) Loan and Security Agreement, dated as of June 29, 2018, as amended, (b) Loan, Security and Guaranty Agreement, dated as of January 29, 2021, as amended, and to terminate such agreements and any security interests and guarantees in connection therewith and (ii) call for redemption, contingent upon consummation of the Merger, CSI Compressco's existing (a) 7.50% First Lien Notes due 2025 and (b) 10.00%/10.75% Second Lien Notes due 2026 and to terminate any security interests and guarantees in connection therewith. We expect to close the Merger in the second quarter of 2024, subject to the satisfaction of customary closing conditions, although we cannot assure you that we will complete the Merger on the terms contemplated or at all. See the section titled “Risk Factors—Risks Related to the Merger” of this Annual Report. Third Amendment to Fourth Amended and Restated Credit Agreement On January 22, 2024, Kodiak entered into the Third Amendment to Fourth Amended and Restated Credit Agreement, which amends the Fourth Amended and Restated Credit Agreement, dated as of March 22, 2023.The Third Amendment, among other things, amended certain provisions of the Existing ABL Credit Agreement (i) to accommodate the consummation of the transactions contemplated by the Agreement and Plan of Merger, dated as of December 19, 2023, by and among the Borrowers, Kick Stock Merger Sub, LLC, Kick GP Merger Sub, LLC, Kick LP Merger Sub, LLC, CSI Compressco LP and CSI Compressco GP LLC (the “Merger Agreement”) and (ii) to account for the Company’s organizational structure after giving effect to the transactions contemplated by the Merger Agreement. In addition, the Third Amendment amended the Existing ABL Credit Agreement to (i) increase the maximum secured leverage ratio (calculated based on the ratio of Senior Secured Debt to EBITDA, each as defined in the ABL Credit Agreement), which will begin to be tested after we issue any unsecured indebtedness, to (x) 3.75 to 1.00 for the first four fiscal quarters after we issue any unsecured indebtedness and (y) 3.25 to 1.00 for each fiscal quarter thereafter, (ii) modify the triggers for commencing a “cash dominion” period (i.e., a period when the Administrative Agent applies proceeds in our deposit accounts to reduce borrowings under the ABL Facility) such that a “cash dominion” period will commence when availability under the ABL Facility is less than $125 million for five consecutive business days or if certain types of events of default occur (although this change will effectively be unwound if the Merger provided for in the Merger Agreement does not occur on or prior to the Reversion Date (as defined in the ABL Credit Agreement)), (iii) include customary provisions relating to the designation of “unrestricted subsidiaries” (i.e., subsidiaries that are not required to become loan parties or be bound by the covenants contained in the ABL Credit Agreement), (iv) provide that only material domestic restricted subsidiaries are required to become guarantors and collateral grantors under the ABL Facility and (v) 20 Table of Conten ts permit the Company and its restricted subsidiaries to incur additional indebtedness and liens and to make additional investments, dividends, distributions, redemptions and dispositions. 2029 Notes Indenture On February 2, 2024, Kodiak Gas Services, LLC, a Delaware limited liability company (the “Issuer”), issued $750,000,000 aggregate principal amount of Kodiak Services' 7.250% senior notes due 2029 (the “Notes”), pursuant to an indenture, dated February 2, 2024 (the “Indenture”), by and among the Issuer, Kodiak Gas Services, Inc., a Delaware corporation (the “Parent”), certain other subsidiary guarantors party thereto (collectively with the Parent, the “Guarantors”) and U.S. Bank Trust Company, National Association, as trustee (the “Trustee”). The net proceeds from the Offering will be used to repay a portion of the outstanding indebtedness under the ABL Facility and to pay related fees, costs, premiums and expenses in connection therewith and with the closing of the Company’s previously announced acquisition of CSI Compressco LP (the “CSI Acquisition”). In connection with closing of the CSI Acquisition, the Company intends, using proceeds from additional draws on the ABL Facility, to repay, terminate and/or redeem all of CSI’s existing long-term indebtedness. Available Information We file Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, other reports and amendments to those reports with the SEC. Our website address is http://www.kodiakgas.com. We make available, free of charge at the “Investor Relations” section of our website, our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and all amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), as soon as reasonably practicable after such reports are electronically filed with, or furnished to, the SEC. The information contained on our website does not constitute part of this Annual Report. We will provide electronic or paper copies of our filings free of charge upon request. The SEC maintains a website that contains these reports at http://www.sec.gov.