Nine Energy Service Inc

Overview

Nine Energy Service, Inc. (either individually or together with its subsidiaries, as the context requires, the “Company,” “Nine,” “we,” “us,” and “our”) is a Delaware corporation that was formed in February 2013 through a combination of three service companies owned by SCF Partners, L.P. or its affiliates. Nine is a leading completion services provider that targets unconventional oil and gas resource development across North American basins and abroad. We partner with our exploration and production (“E&P”) customers to design and deploy downhole solutions and technology to prepare horizontal, multistage wells for production. We focus on providing our customers with cost-effective and comprehensive completion solutions designed to maximize their production levels and operating efficiencies. We believe our success is a product of our culture, which is driven by our intense focus on performance and wellsite execution as well as our commitment to forward-leaning technologies that aid us in the development of smarter, customized applications that drive efficiencies.

We provide our comprehensive completion solutions across a diverse set of well-types, including on the most complex, technically demanding unconventional wells. Modern, high-intensity completion techniques are a more effective way for our customers to maximize resource extraction from horizontal oil and gas wells. These completion techniques provide improved estimated ultimate recovery per lateral foot and a superior return on investment by decreasing cycle time, which make them attractive to operators. We compete for the most intricate and demanding projects, which are characterized by extended reach horizontal laterals, increased stage counts per well, multi-well pad development, and increased proppant loading per lateral foot. As stage counts per well and wells per pad increase, so do our operating leverage and returns, as we are able to complete more jobs and stages with the same number of units and crews. Service providers for these demanding projects are selected based on their technical expertise and ability to execute safely and efficiently. As our customers continue to improve operational efficiencies in completions design, increasing its complexity and difficulty, oilfield service selection becomes much more critical and selective.

We offer a variety of completion applications and technologies to match customer needs across the broadest addressable completions market. Our comprehensive well solutions range from cementing the well at the initial stages of the completion, preparing the well for stimulation, isolating all the stages of an extended reach lateral, and the drilling out of isolation tools. Our completion techniques are specifically tailored to the customer and geology of each well. At the initial stage of a well completion, our lab facilities produce customized cementing slurries used to secure the production casing to ensure well integrity throughout the life of the well. Once the casing is in place, we utilize our proprietary tools at the toe (end) of the well, often called stage one, to prepare for the well stimulation process. Following stage one, we perform plug-and-perf completions using a wireline or electric wireline truck and reel, as well as our composite, hybrid, or dissolvable frac plugs. Through our wireline units, we provide plug-and-perf services that, when combined with our fully-composite, hybrid, or dissolvable frac plugs, create perforations to isolate and divert the fracture to the correct stage. Our completion tool technology focuses on composite, hybrid, and dissolvable frac plugs that isolate stages in a completion but also includes a number of other patented technologies sold in North America and abroad. Our equipment also includes large-diameter coiled tubing units that are capable of reaching the farthest depths for the removal of plugs and cleaning of the wellbore to prepare for production.

Our website is located at https://nineenergyservice.com, and our investor relations website is located at https://investor.nineenergyservice.com. The information posted on our website is not incorporated into this Annual Report. Our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and amendments to reports filed or furnished pursuant to Sections 13(a) and 15(d) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), are available free of charge on our investor relations website as soon as reasonably practicable after we electronically file such material with, or furnish it to, the Securities and Exchange Commission (the “SEC”). You may also access all of our public filings through the SEC’s website at www.sec.gov. Investors and other interested parties should note that we use our investor relations website to publish important information about us, including information that may be deemed material to investors. We encourage investors and other interested parties to review the information we may publish through our investor relations website, in addition to our SEC filings, press releases, conference calls, and webcasts.

Our Services

We derive revenue by providing services integral to the completion of unconventional wells through a full range of tools and methodologies. The following is a description of our primary service offerings and deployment methods:

Cementing Services: Our cementing services consist of blending high-grade cement and water with various solid and liquid additives to create a cement slurry that is pumped between the casing and the wellbore of the well. We currently operate four high-quality laboratory facilities capable of designing and testing all of the current industry cement designs. The laboratory facilities operate twenty-four hours a day and are fully staffed by qualified technicians with the latest equipment and modeling software. Additionally, our technicians and engineers ensure that all tests are performed to American Petroleum Institute specifications and results are delivered to customers promptly. Our cement slurries are designed to achieve the proper cement thickening time, compressive strength, and fluid loss control. Our slurries can be modified to address a wide range of downhole needs of our E&P customers, including varying well depths, downhole temperatures, pressures, and formation characteristics.

We deploy our slurries by using our customized design twin-pumping units, which are fully redundant, containing two pumps, two hydraulic systems, two mixing pumps, and two electrical systems. This customized design significantly decreases our risk of downtime due to mechanical failure and eliminates the necessity of having an additional cementing unit on standby. We have invested in the highest quality cementing equipment.

From January 2018 through December 2024, we completed approximately 26,000 cementing jobs, with an on-time rate of approximately 89%. Punctuality of service is one of the primary metrics that E&P operators use to evaluate the cementing services they receive. Key contributors to our 89% on-time rate include our lab capabilities, personnel, close proximity to our customers’ acreage, dual-sided bulk loading plants, and our service-driven culture.

Completion Tools: We provide downhole solutions and technology used for multistage completions. Our comprehensive completion service offerings are mostly comprised of composite, hybrid, and dissolvable frac plugs in a variety of sizes to isolate stages during plug-and-perf operations. We have coupled patented tool designs with proprietary materials for our dissolvable offering, enabling us to serve the entire addressable plug market. With this ability, we have traditional and long-range plugs to address every type of wellbore situation. Our frac plug technology is complemented by our unconventional open hole and cemented completion tool products, such as liner hangers and accessories, fracture isolation packers, frac sleeves, stage one prep tools, casing flotation tools, specialty open hole float equipment, disk subs, composite cement retainers, and centralizers. Our tool portfolio also includes a multi-cycle barrier valve to address the international, conventional markets.

Our systems provide completion efficiencies at the wellsite by reducing our customers’ equipment needs and stimulation time and allowing for specific zonal treatment. Our dissolvable frac plugs help operators reduce cycle times to bring production online faster, decrease the amount of equipment and people needed on location, and significantly reduce carbon emissions compared to a traditional composite plug completion. Through these reductions in cycle time, our dissolvable plugs can help increase our customers’ internal rate of return and provide a safer and more efficient working environment. From January 2018 through December 2024, we deployed approximately 557,700 isolation, stage one, and casing flotation tools.

Wireline Services: Our wireline services involve the use of a wireline or electric wireline unit equipped with a spool of wireline that is unwound and lowered into oil and gas wells to convey specialized tools or equipment for well completion, well intervention, or pipe recovery. We operate a fleet of modern and “fit-for-purpose” cased hole wireline units designed for operating in unconventional completion operations. Our operation is equipped with the latest technology utilized to service long lateral completions, including head tension tools, ballistic release tools, and addressable switches. We have converted several of our hydraulic wireline units to electric, which significantly reduces carbon emissions and the use of diesel. We currently have wireline units equipped with Coated Line, which is a coated wireline that significantly reduces injector oil use. Offering a lower dynamic coefficient of friction, Coated Line wireline requires less pump down fluid to operate and is more conducive for reaching further depths in longer laterals.

The majority of our wireline work consists of plug-and-perf completions, which is a multistage well completion technique for cased-hole wells that consists of deploying perforating guns to a specified depth. We deploy proprietary specialized tools like our fully-composite, hybrid, and dissolvable frac plugs through our wireline units. From January 2018 through December 2024, we completed approximately 189,500 wireline stages with a success rate of over 99%.

Coiled Tubing Services: Coiled tubing services perform wellbore intervention operations utilizing a continuous steel pipe that is transported to the wellsite wound on a large spool in lengths of up to 30,000 feet. Coiled tubing provides a cost-effective solution for well work due to the ability to deploy efficiently and safely into a live well using specialized well-control equipment. The live well work capability limits the customer’s risk of formation damage associated with “killing” a well (the temporary placement of heavy fluids in a wellbore to keep reservoir fluids in place) while allowing for safer operations due to minimal equipment handling. Coiled tubing facilitates a variety of services in both new and old wells, such as milling, drilling, fishing, production logging, artificial lift, cementing, and stimulation.

Our coiled tubing units carry data acquisition and dissemination technology, allowing our customers to monitor jobs via a web interface. Our “extended reach” units are capable of reaching the toe of wells with total measured depths of 27,000 feet and beyond, including lateral lengths in excess of 12,500 feet, keeping pace with the industry’s most challenging downhole environments. While we specialize in larger-diameter (2 3/8” and 2 5/8”) coiled tubing units, we also offer 2” and 1 1/4”

diameter solutions to our customers. From January 2018 through December 2024, we have performed approximately 8,300 jobs and deployed more than 218 million running feet of coiled tubing, with a success rate of over 99%.

Geographic Areas of Operation

We operate in all major onshore basins in the U.S., including the Permian Basin, Marcellus and Utica Shales, Eagle Ford Shale, DJ Basin, SCOOP/STACK Formation, Bakken Formation, and Haynesville Formation as well as the Western Canada Sedimentary Basin in Canada. We provide our services through strategically placed operating facilities located in-basin throughout the U.S. This local presence allows us to quickly respond to customer demands and operate efficiently. Additionally, through our extensive footprint, we are able to track and implement best practices around completion trends and technology across all divisions and geography.

A portion of completion tool revenue is generated from outside of North America, and international completion tools are an important part of our revenue stream.

We believe that our strategic geographic diversity will benefit us as activity increases or decreases in select basins by helping to mitigate basin and commodity-risk. Our broad geographic footprint provides us with exposure to potential increases in drilling and completion activity and will allow us to opportunistically pursue new business in basins with the most active drilling environments.

Seasonality

Our operations are subject to seasonal factors, and our overall financial results reflect seasonal variations. Specifically, we typically have experienced a pause by our customers around the holiday season in the fourth quarter, which may be compounded as our customers exhaust their annual capital spending budgets towards year end.

Additionally, our operations are directly affected by weather conditions. During the winter months (portions of the first and fourth quarters) and periods of heavy snow, ice, or rain, particularly in the northeastern U.S., North Dakota, Rocky Mountains, and western Canada, our customers may delay operations or we may not be able to operate or move our equipment between locations. Also, during the spring thaw, which normally starts in late March and continues through June, some areas, primarily in western Canada, impose transportation restrictions to prevent damage caused by the spring thaw. Throughout the year, heavy rains adversely affect activity levels because well locations and dirt access roads can become impassible in wet conditions. Weather conditions may also negatively affect our customers’ activity levels.

Sales and Marketing

Our sales activities are conducted through a network of sales representatives and business development personnel, which provides us coverage at both the corporate and field level of our customers. We have a technical sales organization with expertise and focus within our specific service lines. Sales representatives work closely with local operations managers to target potential opportunities through strategic focus and planning. Customers are identified as targets based on their drilling and completion activity, geographic location, and economic viability. Our marketing activities are performed internally with input and guidance from a third-party marketing agency. Our strategy is based on building a strong brand though multiple media outlets including our website, select social media accounts, print and online advertisements, billboard advertisements, press releases and various industry-specific conferences, publications, and lectures.

Customers

Our customer base includes a broad range of integrated and independent E&P companies. For the year ended December 31, 2024, our top five customers collectively accounted for approximately 25% of our revenues.

Demand for our services and products is cyclical and substantially dependent upon activity levels in the oil and gas industry, particularly our customers’ willingness to spend capital on the exploration for and development of oil and natural gas. Our customers’ spending plans are generally based on their outlook for near-term and long-term commodity prices. As a result, the demand for our services and products is highly sensitive to current and expected commodity prices.

Competition

We provide our services and products across the U.S., Canada, and abroad, and we compete against different companies in each service and product line we offer. Our competition includes many large and small oilfield service companies, including the largest integrated oilfield services companies. We believe that the principal competitive factors in the markets we serve are technology offerings, wellsite execution, service quality, technical expertise, equipment capacity, work force competency, efficiency, safety record, reputation, and experience. Additionally, projects are often awarded on a bid basis, which tends to create a highly competitive environment. We seek to differentiate our company from our competitors by delivering the highest-quality services, technology, and equipment possible, coupled with superior execution and operating efficiency in a safe working environment. By focusing on cultivating our existing customer relationships and maintaining our high standard of customer service, technology, safety, performance, and quality of crews, equipment, and services, we believe we are differentiated in a competitive market.

Our major competitors include Halliburton Company, Schlumberger Limited, NCS Multistage, Patterson-UTI Energy, KLX Energy Services Holdings, Innovex International, and a significant number of private and locally-oriented businesses.

Suppliers

We purchase a wide variety of raw materials, parts, and components that are manufactured and supplied for our operations from various suppliers. While we are not dependent on any single supplier for those materials, parts, or components, certain product lines depend on a limited number of third-party suppliers and vendors. During the year ended December 31, 2024, no supplier of the materials used in our services provided over 10% of our materials or equipment as a percentage of overall costs.

To date, we have generally been able to obtain the equipment, parts, and supplies necessary to support our operations on a timely basis. While we believe that we will be able to make satisfactory alternative arrangements in the event of any interruption in the supply of these materials and/or products by one of our suppliers, we may not always be able to make alternative arrangements. In addition, certain materials for which we do not currently have long-term supply agreements could experience shortages and significant price increases in the future. As a result, we may be unable to mitigate any future supply shortages, and our results of operations, prospects, and financial condition could be adversely affected.

Research & Technology, Intellectual Property

Our sales and earnings are influenced by our ability to successfully introduce new or improved products and services to the market. We believe we have become a “go-to” provider for piloting new technologies because of our service quality and offering, execution at the wellsite, and geographic footprint.

Our engineering and technology efforts are focused on providing efficient and cost-effective solutions to maximize production for our customers across major North American onshore basins and abroad. We have dedicated resources focused on internally developing new technology and equipment and evolving our existing proprietary tools, as well as resources focused on sourcing and commercializing new technologies through mergers and acquisitions and strategic partnerships, to stay ahead of industry trends and achieve lower completion and production costs for our customers.

We have developed a suite of proprietary downhole tools, products, and techniques through both internal resources, as well as mergers and acquisitions and strategic partnerships with manufacturers and engineering companies looking for a reliable and expansive channel to market. In these partnerships, we have exclusive rights to market and sell technology unavailable to any other service providers in the designated regions, and we sell the technology directly to the customer and order from the manufacturer on an as-needed basis, with no minimum volume requirements and without having to hold excess inventory. These strategic partnerships provide us and our customers with access to unique downhole technology from independent innovators while allowing us to minimize exposure to potential technology adoption risks and the significant costs associated with developing and implementing research and development internally.

Although in the aggregate our patents, licenses, and strategic partnerships are important to us, we do not regard any single patent, license, or strategic partnership as critical or essential to our business as a whole. In general, we depend on our technological capabilities, customer service-oriented culture, and application of our know-how to distinguish ourselves from our competitors, rather than our right to exclude others through patents or exclusive licenses. We also consider the quality and timely delivery of our products, the service we provide to our customers, and the technical knowledge and skill of our personnel to be more important than our registered intellectual property in our ability to compete.

Risk Management and Insurance

Our operations are subject to hazards inherent in the oil and natural gas industry, including, but not limited to, accidents, blowouts, explosions, craterings, fires, oil spills, and hazardous materials spills. These conditions can cause personal injury or loss of life; damage to, or destruction of, property, the environment, and wildlife; and the suspension of our and/or our customers’ operations.

In addition, claims for loss of oil and gas production and damage to formations can occur in the oilfield services industry. If a serious accident were to occur at a location where our equipment and services are being used, it could result in us being named as a defendant in lawsuits asserting large claims.

Because our business involves the transportation of heavy equipment and materials, we may also experience traffic accidents which may result in spills, property damage, and personal injury.

Despite our efforts to maintain high safety standards, from time to time, we have suffered accidents, and there is a risk that we will experience accidents in the future. In addition to the property and personal losses from these accidents, the frequency and severity of these incidents affect our operating costs, insurability, and relationships with customers, employees, and regulatory agencies. In particular, in recent years, many of our large customers have placed an increased emphasis on the safety records of their service providers. Any significant increase in the frequency or severity of these incidents, or the general level of compensatory payments, could adversely affect the cost of, or our ability to obtain, workers’ compensation and other forms of insurance and could have other material adverse effects on our financial condition and results of operations.

We maintain insurance coverage of types and amounts that we believe to be customary in the industry including workers’ compensation, employer’s liability, claims-based pollution, umbrella, comprehensive commercial general liability, business automobile, and property. Our insurance coverage may be inadequate to cover our liabilities. In addition, we may not be able to maintain adequate insurance in the future at rates we consider reasonable and commercially justifiable or on terms as favorable as our current arrangements.

We endeavor to allocate potential liabilities and risks between the parties in our Master Service Agreements (“MSAs”). We retain the risk for any liability not indemnified by our customers in excess of our insurance coverage. These MSAs delineate our and our customers’ respective warranty and indemnification obligations with respect to the services we provide. We endeavor to negotiate MSAs with our customers that provide, among other things, that we and our customers assume (without regard to fault) liability for damages to our respective personnel and property. For catastrophic losses, we endeavor to negotiate MSAs that include industry-standard carve-outs from the knock-for-knock indemnities. Additionally, our MSAs often provide carve-outs to the “without regard to fault” concept that would permit, for example, us to be held responsible for events of catastrophic loss only if they arise as a result of our gross negligence or willful misconduct. Our MSAs typically provide for industry-standard pollution indemnities, pursuant to which we assume liability for surface pollution associated with our equipment and originating above the surface (without regard to fault), and our customer assumes (without regard to fault) liability arising from all other pollution, including, without limitation, underground pollution and pollution emanating from the wellbore as a result of an explosion, fire, or blowout. This description of our MSAs is a summary of the material terms of the typical MSA that we have in place and does not reflect every MSA that we have entered into or may enter into in the future, some of which may contain indemnity structures and risk allocations between our customers and us that are different than those described here.

Employees

As of December 31, 2024, we had 1,077 employees, all of which were full-time. We are not a party to any collective bargaining agreements.

Regulatory Matters

Our operations are subject to numerous stringent and complex laws and regulations at the U.S. federal, state, and local levels governing the discharge of materials into the environment, environmental protection, and health and safety aspects of our operations. In addition, due to our operations in Canada, we are subject to Canadian environmental statutes and regulations as well as Canada’s new anti-forced labor law. Failure to comply with these laws and regulations or to obtain or comply with permits may result in the assessment of administrative, civil, and criminal penalties, imposition of remedial or corrective action requirements, and the imposition of injunctions or other orders to prohibit certain activities, restrict certain operations, or force future compliance with environmental requirements.

There is inherent risk of incurring significant environmental costs and liabilities in the performance of our operations due to our handling of petroleum hydrocarbons, other hazardous substances, and wastes, as a result of air emissions and wastewater discharges related to our operations, and because of historical operations and waste disposal practices. Spills or other releases of regulated substances, including such spills and releases that occur in the future, could expose us to material losses, expenditures, and liabilities under applicable environmental laws and regulations. Under certain of such laws and regulations, we could be held strictly and jointly and severally liable for the removal or remediation of previously released materials or property contamination, regardless of whether we were responsible for the release or contamination and even if our operations met previous standards in the industry at the time they were conducted.

The following is a summary of some of the existing laws, rules, and regulations to which we are subject.

Hazardous Substances and Waste Handling

The Resource Conservation and Recovery Act (“RCRA”) and comparable state statutes regulate the management, generation, transportation, treatment, storage, disposal, and cleanup of hazardous and non-hazardous wastes. Under the guidance issued by the U.S. Environmental Protection Agency (the “EPA”), the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. We are required to manage the disposal of hazardous and non-hazardous wastes in compliance with RCRA and analogous state laws. RCRA currently exempts many E&P wastes from classification as hazardous waste if properly handled. Specifically, RCRA excludes from the definition of hazardous waste drilling fluids, produced waters, and most of the other wastes intrinsically associated with the exploration, development, or production of crude oil and natural gas and, instead, these fluids, waters, and wastes are regulated under RCRA’s less stringent non-hazardous waste provisions, state laws, or other federal laws. However, it is possible that certain oil and natural gas E&P wastes now classified as non-hazardous could be classified as hazardous waste in the future. Stricter regulation of wastes generated during our or our customers’ operations could result in increased costs for our operations or the operations of our customers, which could in turn reduce demand for our services and adversely affect our business.

Comprehensive Environmental Response, Compensation, and Liability Act

The Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”), also known as the Superfund law, and comparable state laws impose joint and several liability, without regard to fault or legality of conduct, on classes of persons who are considered to be responsible for the release of a hazardous substance into the environment. These persons include the current and former owner or operator of the site where the release occurred and anyone who transported, disposed, or arranged for the transport or disposal of a hazardous substance released at the site. Persons who are or were responsible for releases of hazardous substances under CERCLA and any state analogs may be subject to joint and several and strict liability for the costs of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources and for the costs of certain health studies. We currently own, lease, or operate numerous properties that have been used for manufacturing and other operations for many years. These properties and the substances disposed or released on them may be subject to CERCLA and analogous state laws. Under such laws, we could be required to remove previously disposed substances and wastes, remediate contaminated property, or perform remedial operations to prevent future contamination. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment.

Worker Health and Safety

We are subject to a number of federal and state laws and regulations, including the federal Occupational Safety and Health Act (“OSHA”) and comparable state laws, establishing requirements to protect the health and safety of workers. The OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of the federal Superfund Amendment and Reauthorization Act, and comparable state statutes require maintenance of information about hazardous materials used or produced in operations and provision of this information to employees, state and local government authorities, and citizens. Additionally, the Federal Motor Carrier Safety Administration (the “FMCSA”) regulates and provides safety oversight of commercial motor vehicles, the EPA establishes requirements to protect human health and the environment, and the federal Bureau of Alcohol, Tobacco, Firearms and Explosives establishes requirements for the safe use and storage of explosives. The federal Nuclear Regulatory Commission establishes requirements for the possession and use of radioactive materials, while most states have entered into agreements that allow them to assume licensing and oversight activities for specified classes of such materials. State agencies typically regulate other sources of ionizing and non-ionizing radiation. Substantial fines and penalties can be imposed, and orders or injunctions limiting or prohibiting certain operations may be issued, in connection with any failure to comply with these laws and regulations.

Transportation Safety and Compliance

As of December 31, 2024, we operated a fleet in excess of 580 commercial motor vehicles. As such, we are subject to regulation as a motor carrier by the U.S. Department of Transportation (the “DOT”) and analogous state agencies and their applicable federal and state laws and regulations, including the Federal Motor Carrier Safety Regulations and Hazardous Materials Regulations for interstate travel promulgated by the FMCSA under the DOT and comparable state regulations for intrastate travel. These regulatory authorities exercise broad powers, governing activities such as the authorization to engage in motor carrier operations, regulatory safety, equipment testing, driver requirements and specifications, and insurance requirements. In connection with these rules, substantial fines and penalties can be imposed and orders or injunctions limiting or prohibiting certain operations may be issued in connection with any failure to comply with laws and regulations relating to the safe operation of commercial motor vehicles.

Water Discharges

The Federal Water Pollution Control Act (the “Clean Water Act”) 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”) and state waters. The discharge of pollutants into, and other impacts to, regulated waters, including jurisdictional wetlands, is prohibited, except in accordance with the terms of a permit issued by the EPA, the U.S. Army Corps of Engineers (the “Corps”) or an analogous state agency. The scope of federal jurisdictional reach over waters of the United States has been subject to substantial revision in recent years. In 2015, the EPA and the Corps issued a rule defining the scope of federal jurisdiction over WOTUS, which never took effect before being replaced by the Navigable Waters Protection Rule (the “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. In January 2023, the EPA and the Corps issued a final rule 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 waters. In September 2023, the 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, roughly half of the states and other plaintiffs are continuing to challenge the September 2023 rule, and the EPA and the Corps are using the pre-2015 definition of WOTUS in these states while litigation continues. As a result, substantial uncertainty exists with respect to future implementation of the September 2023 rule and the scope of Clean Water Act jurisdiction generally. In addition, in an April 2020 decision defining the scope of the Clean Water Act 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 Clean Water Act. 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. However, in January 2025, President Trump issued executive orders directing (i) the EPA and the Corps to identify planned or potential actions that could be subject to emergency treatment under Section 404 of the Clean Water Act and (ii) the heads of all federal agencies to identify and begin the processes to suspend, revise, or rescind all agency actions, including all existing regulations and guidance documents, that are unduly burdensome on the identification, development, or use of domestic energy resources. Accordingly, future implementation and enforcement of these rules and policies is uncertain at this time. To the extent a future rule or court decision expands Clean Water Act jurisdiction, certain energy companies could face increased costs and delays with respect to obtaining permits for dredge and fill activities in wetland areas, which in turn could reduce demand for our services. The process for obtaining permits has the potential to delay our operations and those of our customers. Spill prevention, control, and countermeasure requirements of federal laws require appropriate containment berms and similar structures to help prevent the contamination of navigable waters by a petroleum hydrocarbon tank spill, rupture, or leak. In addition, the Clean Water Act and analogous state laws require individual permits or coverage under general permits for discharges of wastewater and 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 Clean Water Act and analogous state laws and regulations. The Clean Water Act and analogous state laws provide for administrative, civil, and criminal penalties for unauthorized discharges and, together with the Oil Pollution Act of 1990, impose rigorous requirements for spill prevention and response planning, as well as substantial potential liability, such as strict liability and natural resources damages liability, for the costs of removal, remediation, and damages in connection with any unauthorized discharges.

Air Emissions

Through the federal Clean Air Act, as amended (“CAA”), and comparable state and local laws and regulations, the EPA regulates emissions of various air pollutants through the issuance of permits and the imposition of other requirements. The EPA has developed, and continues to develop, stringent regulations governing emissions of air pollutants at specified sources. New facilities may be required to obtain permits before work can begin, and modified and existing facilities may be required to obtain additional permits.

In June 2016, the EPA finalized regulations establishing New Source Performance Standards, known as Subpart OOOOa, for methane and volatile organic compounds from new and modified oil and natural gas production and natural gas processing and transmission facilities. In December 2023, the EPA issued a final rule, under the CAA’s New Source Performance Standards, intended to reduce methane emissions from new and existing oil and gas sources. The new rule makes the existing regulations in Subpart OOOOa more stringent and creates a Subpart OOOOb to expand reduction requirements for new, modified, and reconstructed oil and gas sources that commenced construction, modification, or reconstruction after December 6, 2022, including standards focusing on certain source types that have never been regulated under the CAA (including intermittent vent pneumatic controllers, associated gas, and liquids unloading facilities). The new rule phases out flaring through Subpart OOOOb, which prohibits routine flaring from new oil wells after the phase-in period, and through a new Subpart OOOOc, which prohibits flaring absent a showing of technical infeasibility for existing wells with documented methane emissions of 40 tons per year or more. In addition, the final rule establishes “Emissions Guidelines” in Subpart OOOOc, which requires states to develop plans to reduce methane emissions from existing sources that must be at least as effective as presumptive standards set by EPA. The final rule gives states, along with federal tribes that wish to regulate existing sources, until March 2026 to develop and submit their plans for reducing methane emissions from existing sources. The final emissions guidelines under Subpart OOOOc provide until 2029 for existing sources (i.e., sources constructed prior to December 6, 2022) to comply. The final rule is subject to ongoing litigation but remains in effect. However, in January 2025, President Trump issued an executive order directing the heads of all federal agencies to identify and begin the processes to suspend, revise, or rescind all agency actions that are unduly burdensome on the identification, development, or use of domestic energy resources. Consequently, future implementation and enforcement of the final rule remains uncertain at this time.

Although there may be an adverse financial impact (including compliance costs, potential permitting delays and increased regulatory requirements) associated with these regulatory changes, the extent and magnitude of impacts cannot be reliably or accurately estimated due to the present uncertainty regarding any additional measures and how they will be implemented. Any new regulations implementing stricter permitting requirements could delay or impair our or our customers’ ability to obtain air emission permits, and result in increased expenditures for pollution control equipment, the costs of which could be significant. Federal and state regulatory agencies can impose administrative, civil, and criminal penalties, as well as injunctive relief, for non-compliance with air permits or other requirements of the CAA and associated state laws and regulations.

Climate Change

Numerous reports from scientific and governmental bodies, such as the Sixth Assessment Report of the Intergovernmental Panel on Climate Change, have expressed heightened concerns about the impacts of human activity, especially fossil fuel combustion, on the global climate. In turn, governments and civil society are increasingly focused on limiting the emissions of greenhouse gases (“GHGs”), including emissions of carbon dioxide from the use of oil and natural gas. The EPA has determined that emissions of GHGs, including carbon dioxide and methane, present a danger to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the Earth’s atmosphere and other climatic changes. The EPA has established GHG emission reporting requirements for sources in the oil and gas sector and has also promulgated rules requiring certain large stationary sources of GHGs to obtain preconstruction permits under the CAA and follow “best available control technology” requirements. Although we are not likely to become subject to GHG emissions permitting and best available control technology requirements because none of our facilities are presently major sources of GHG emissions, such requirements could become applicable to our customers and could have an adverse effect on their costs of operations or financial performance, thereby adversely affecting demand for our products and services and our business, financial condition, and results of operations.

In December 2015, the 21st Conference of the Parties of the United Nations Framework Convention on Climate Change resulted in nearly 200 countries, including the U.S., coming together to develop the Paris Agreement, which calls for the parties to undertake “ambitious efforts” to limit the average global temperature. In November 2020, under the first Trump Administration, the U.S. withdrew from the Paris Agreement; however, various corporations, investors, and U.S. state and local governments continued to publicly pledge to further the goals of the Paris Agreement. In February 2021, under the Biden Administration, the United States rejoined the Paris Agreement and set a target to reduce U.S. GHG emissions by 50-52% by the year 2030 as compared with 2005 levels. In addition, in September 2021, the Biden Administration publicly announced the Global Methane Pledge, a pact that commits its signatories to the collective goal of reducing global methane emissions at least 30% below 2020 levels by 2030, including “all feasible reductions” in the energy sector. At the 27th Conference of the Parties, the United States agreed, in conjunction with the European Union and a number of other partner countries, to develop standards for monitoring and reporting methane emissions to help create a market for low methane-intensity natural gas. At the 28th Conference of the Parties, member countries agreed to the first “global stocktake,” which calls on countries to contribute to global efforts, including a tripling of renewable energy capacity and doubling energy efficiency improvements by 2030, accelerating efforts toward the phase-down of unabated coal power, phasing out inefficient fossil fuel subsidies, and transitioning away from fossil fuels in energy systems. Most recently, at the 29th Conference of the Parties, delegates approved rules to operationalize international carbon markets under Article 6 of the Paris Agreement, including a new Paris Agreement Crediting Mechanism to trade UN-approved carbon credits. However, in January 2025, President Trump issued an executive order directing the immediate notice to the United Nations of the United States’ withdrawal from the Paris Agreement and all other agreements made under the United Nations Framework Convention on Climate Change. The full impact of these actions remains unclear at this time. However, various state and local governments in the U.S. have publicly committed to furthering the goals of the Paris Agreement.

The U.S. Congress has from time to time considered adopting legislation to reduce emissions of GHGs, but no comprehensive federal laws regulating the emission of GHGs or directly imposing a price of carbon have been adopted in recent years. However, such legislation has periodically been introduced in the U.S. Congress and may be proposed or adopted in the future, and energy legislation and other regulatory initiatives have been proposed that are relevant to GHG emissions issues. For example, the Inflation Reduction Act of 2022, which appropriates significant funding for renewable energy initiatives and, for the first time, imposes a fee on GHG emissions from certain oil and gas facilities, was signed into law in August 2022. The Inflation Reduction Act amends the CAA to include a Methane Emissions and Waste Reduction Incentive Program, which requires the EPA to impose a “Waste Emissions Charge” on certain natural gas and oil sources that are already required to report under the EPA’s Greenhouse Gas Reporting Program. To implement the program, in May 2024, the EPA finalized revisions to the Greenhouse Gas Reporting Program for petroleum and natural gas facilities. The emissions reported under the Greenhouse Gas Reporting Program will be the basis for any payments under the Methane Emissions Reduction Program. However, petitions for reconsideration to the EPA are pending and litigation in the D.C. Circuit Court of Appeals has commenced. In November 2024, the EPA finalized a rule implementing the Inflation Reduction Act’s Waste Emissions Charge, which became effective on January 1, 2025. The fee imposed under the Methane Emissions and Waste Reduction Incentive Program for 2024 is $900 per ton emitted over annual methane emissions thresholds and increases to $1,200 in 2025 and $1,500 in 2026. In January 2025, industry associations challenged the Waste Emissions Charge rule in the D.C. Circuit Court of Appeals. The emissions fee and funding provisions of the law could increase operating costs within the oil and gas industry and accelerate the transition away from fossil fuels, which could in turn adversely affect our and our customers’ business and results of operations. However, in January 2025, President Trump issued an executive order directing the heads of all federal agencies to identify and begin the processes to suspend, revise, or rescind all agency actions that are unduly burdensome on the identification, development, or use of domestic energy resources. In addition, based on the timing of the rule’s finalization and statements from congressional Republicans, the Waste Emissions Charge rule is potentially vulnerable to repeal by Congress under the Congressional Review Act, and the Inflation Reduction Act may also be subject to amendment or repeal through Congressional budget reconciliation. However, many U.S. state and local governments have intensified or stated their intent to intensify efforts to support international climate commitments and treaties, in addition to developing programs that are aimed at tracking and reducing GHG emissions by means of carbon taxes, policies or incentives to encourage the use of renewable energy or alternative low-carbon fuels, the development of GHG inventories, and cap-and-trade programs that typically require major sources of GHG emissions to acquire and surrender emission allowances in return for emitting GHGs.

The adoption of any new climate change-related legislation or regulation, including any such legislation or regulation that restricts emissions of GHGs from the equipment and operations of our customers or with respect to the oil and natural gas they produce, could adversely affect demand for our products and services. Consequently, legislation and regulatory programs to reduce emissions of GHGs could have an adverse effect on our business, financial condition, and results of operations. In June 2024, the U.S. Supreme Court issued a ruling in Loper Bright Enterprises v. Raimondo that ended the use of the Chevron doctrine when courts analyze federal regulations. The Chevron doctrine required courts to defer to the reasonable interpretation of agencies when deciding if a regulation reflected the intent of Congress. While the end of Chevron is likely to introduce new complexity for federal agencies and administration of climate change policy and regulatory programs, many of these initiatives are expected to continue. Moreover, incentives to conserve energy or use alternative energy sources, such as policies designed to increase utilization of zero-emissions or electric vehicles, as a means of addressing climate change could reduce demand for the oil and natural gas produced by our customers and, in turn, could adversely affect demand for our products and services. Finally, most scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that could have significant physical effects, such as increased frequency and severity of storms, droughts, and floods and other climatic events; if such effects were to occur, they could have an adverse impact on our operations.

Regulations requiring the disclosure of GHG emissions, and other climate-related information or information substantiating climate-related claims, are also increasingly being adopted or proposed at the federal and state level. For example, at the state level, California enacted legislation in October 2023 that will ultimately require certain companies that do business in California to publicly disclose their Scopes 1, 2, and 3 GHG emissions, with third-party assurance of such data, and issue public reports on their climate-related financial risk and related mitigation measures.

Hydraulic Fracturing

Our businesses are dependent on hydraulic fracturing and horizontal drilling activities. Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons, particularly natural gas, from tight formations, including shales. The process, which involves the injection of water, sand, and chemicals under pressure into formations to fracture the surrounding rock and stimulate production, is typically regulated by state oil and natural gas commissions. However, federal agencies have asserted regulatory authority over certain aspects of the process. For example, the EPA has asserted federal regulatory authority pursuant to the federal Safe Drinking Water Act over certain hydraulic fracturing activities involving the use of diesel fuels in fracturing fluids and has issued permitting guidance that applies to such activities.

There is considerable uncertainty surrounding regulation of the emissions of methane, which may be released during hydraulic fracturing. In addition to the EPA’s new Subpart OOOO regulations discussed above, other federal agencies have promulgated rules regulating methane. In April 2024, the U.S. Bureau of Land Management (the “BLM”) finalized a rule to reduce the waste of natural gas during the production of oil and gas on federal and tribal lands. The final rule took effect in June 2024. However, in May 2024, the states of North Dakota, Texas, Montana, Wyoming, and Utah challenged the rule. In September 2024, the U.S. District Court for the District of North Dakota granted a motion prohibiting the BLM from enforcing the rule against those states pending the outcome of the litigation. However, in January 2025, President Trump issued an executive order directing the heads of all federal agencies to identify and begin the processes to suspend, revise, or rescind all agency actions that are unduly burdensome on the identification, development, or use of domestic energy resources. Consequently, future implementation and enforcement of the final rule remains uncertain at this time.

The EPA has also issued effluent limitation guidelines that prohibit the discharge of wastewater from hydraulic fracturing operations to publicly owned wastewater treatment plants. Also, from time to time, legislation has been introduced, but not enacted, in Congress to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the hydraulic fracturing process. It is unclear how any additional federal regulation of hydraulic fracturing activities may affect our operations, but additional regulatory burdens on our customers could ultimately result in decreased demand for our services.

Various studies analyzing the potential environmental impacts of hydraulic fracturing have also been performed. For example, in December 2016, the EPA issued a report on the potential impacts of hydraulic fracturing on drinking water resources, which 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. As described elsewhere in this Annual Report, these risks are regulated under various state, federal, and local laws. To date, the EPA has taken no further action in response to the 2016 report.

Some states, counties, and municipalities have implemented, or are considering, increased regulatory oversight of hydraulic fracturing through additional permit requirements, operational restrictions, disclosure requirements, well construction, and temporary or permanent bans on hydraulic fracturing in certain areas. For example, some states have banned the use of high-volume hydraulic fracturing, and others have adopted regulations that impose new or more stringent permitting, disclosure, disposal, and well construction requirements on hydraulic fracturing operations. Alternatively, some municipalities are, or have considered, zoning and other ordinances, the conditions of which could impose a de facto ban on drilling and/or hydraulic fracturing operations. Further, some states, counties, and municipalities are closely examining water use issues, such as permit and disposal options for processed water, which could have a material adverse impact on our financial condition, prospects, and results of operations if such additional permitting requirements are imposed upon our industry. If new laws or regulations that significantly restrict hydraulic fracturing are adopted, such laws could reduce demand for our business by making it more difficult or costly for certain customers to perform fracturing to stimulate production from tight formations. In addition, if hydraulic fracturing becomes regulated at the federal level as a result of federal legislation or regulatory initiatives by the EPA, the business and operations of our customers could be subject to additional permitting requirements, attendant permitting delays, increased operating and compliance costs and process prohibitions, which could have an adverse effect on our business, financial condition, and results of operations.

In light of concerns about seismic activity being triggered by the injection of produced waters into underground wells, certain regulators have also implemented or are considering implementing additional requirements related to seismic safety for hydraulic fracturing activities. A 2015 U.S. Geological Survey report identified eight states, including Texas, with areas of increased rates of induced seismicity that could be attributed to fluid injection or oil and gas extraction. Any regulation that restricts the ability of our customers to dispose of produced waters or increases their cost of doing business could cause them to curtail operations, which in turn could decrease demand for our services and have a material adverse effect on our business.

National Environmental Policy Act

Businesses and operations of our customers that are carried out on federal lands may be subject to the National Environmental Policy Act (“NEPA”), which requires federal agencies, including the Department of the Interior (the “DOI”), to evaluate major agency actions having the potential to significantly impact the human environment. In the course of such evaluations, an agency will evaluate the potential direct, indirect, and cumulative impacts of a proposed project and, if necessary, will prepare a detailed Environmental Impact Statement that must be made available for public review and comment. In July 2020, the Council on Environmental Quality (“CEQ”) revised NEPA’s implementing regulations in an effort to streamline approvals for projects. In October 2021, the Council on Environmental Quality announced its Phase I rule, the first of two planned rules to roll back the 2020 rule, which was finalized in April 2022. The Phase I final rule generally restores certain regulatory provisions that were in effect prior to the 2020 rule. In May 2024, CEQ finalized the Phase II rule, which accelerates NEPA reviews while maintaining consideration of relevant environmental, climate change, and environmental justice effects of a proposed project. Several states and environmental groups have challenged the Phase II rule in federal district court. The CEQ’s changes could result in increased NEPA review timelines for projects involving agency action regarding federal lands, federal funds, or federal permits or approvals. Additionally, in November 2024, a federal appeals court found that CEQ lacks statutory authority to issue NEPA regulations binding on other federal agencies. However, the court’s holding was confined to striking down the agencies’ action under review on separate grounds, and CEQ’s Phase I and II rules remain in effect. However, in January 2025, President Trump issued an executive order requiring CEQ to provide guidance on implementing NEPA and to propose rescinding and replacing CEQ’s NEPA regulations with implementing regulations at the agency level. The executive order also instructs federal agencies to adhere to only the relevant legislated requirements for environmental reviews and to prioritize efficiency and certainty over any other objectives in such reviews. In February 2025, CEQ sent an interim final rule to the White House Office of Management and Budget that would immediately withdraw the NEPA implementing regulations. The potential impact of further changes to the NEPA regulations and statutory text therefore remains uncertain and could have an effect on our customers’ business and operations, which could ultimately result in decreased demand for our services.

Endangered Species Act and Migratory Bird Treaty Act

The Endangered Species Act (“ESA”) was established to protect endangered and threatened species. Pursuant to that act, 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 (the “FWS”) must also designate the species’ critical habitat and suitable habitat as part of the effort to ensure survival of the species. In April 2024, the FWS finalized three rules that revise regulations regarding listing and reclassification of species and designation of critical habitat. These rules also clarify definitions that impact interagency cooperation and reinstated the general application of the “blanket rule” option for protecting newly listed threatened species. These rules were challenged in August 2024 in the Northern District of California. A critical habitat or suitable habitat designation could result in further material restrictions to land use and may materially delay or prohibit land access for oil and natural gas development. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act (the “MBTA”), which makes it illegal to, among other things, hunt, capture, kill, possess, sell, or purchase migratory birds, nests, or eggs without a permit. This prohibition covers most bird species in the U.S. In January 2021, the DOI finalized a rule limiting application of the MBTA; however, the DOI revoked the rule in October 2021 and issued an advance notice of proposed rulemaking seeking comment on the DOI’s plan to develop regulations that authorize incidental take under certain prescribed conditions. The DOI has not yet issued a proposed rule. However, in January 2025, President Trump issued an executive order declaring a national energy emergency under the National Emergencies Act. As part of that executive order, agencies were directed to use, to the maximum extent permissible, the ESA regulation on consultations in emergencies to facilitate the domestic energy supply. The executive order also requires the quarterly convening of the Endangered Species Act Committee to ensure prompt and efficient review of all submissions for potential actions that could facilitate energy development. President Trump also issued an executive order directing the heads of all federal agencies to identify and begin the processes to suspend, revise, or rescind all agency actions that are unduly burdensome on the identification, development, or use of domestic energy resources. Consequently, future implementation and enforcement of the rules impacting the ESA and the MBTA are uncertain. If our customers were to have areas within their business and operations designated as critical or suitable habitat for a protected species, it could decrease demand for our services and have a material adverse effect on our business. There is also increasing interest in nature-related matters beyond protected species, such as general biodiversity, which may similarly require us or our customers to incur costs or take other measures that may adversely impact our business or operations.