EDGAR 10-K Filing

Company CIK: 1532286
Filing Year: 2021
Filename: 1532286_10-K_2021_0001532286-21-000006.json

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ITEM 1. BUSINESS
Item 1. Business
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 all 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 despite their associated increased well cost. 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, rather than only price. 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 truck and reel, as well as our composite or dissolvable frac plugs. We also offer a pinpoint frac sleeve system technology to complete the remaining stages of the well. Through our wireline units, we provide plug-and-perf services that, when combined with our fully-composite or dissolvable frac plugs, create perforations to isolate and divert the fracture to the correct stage. Our completion tool technology focuses on composite 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 to have an additional cementing unit on standby. We have invested in the highest quality cementing equipment, and since 2012, we have deployed only new equipment for use in the fields. As of December 31, 2020, we had a total of 40 pumping units.
From January 2014 through December 2020, we completed approximately 22,000 cementing jobs, with an on-time rate of approximately 91%. Punctuality of service has become one of the primary metrics that E&P operators use to evaluate the cementing services they receive. Key contributors to our 91% 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 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 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 2014 through December 2020, we deployed approximately 241,200 isolation, stage one, and casing flotation tools.
Wireline Services: Our wireline services involve the use of a 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. We currently operate 47 wireline pumpdown units in the United States (the “U.S.”). 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 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 and dissolvable frac plugs through our wireline units. From January 2014 through December 2020, we completed approximately 171,000 wireline stages with a success rate of approximately 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.
We currently operate 14 coiled tubing units serving the Permian Basin and Haynesville markets. Our coiled tubing units carry data acquisition and dissemination technology, allowing our customers to monitor jobs via a web interface. Of the 14 coiled tubing units, we consider 12 to be “extended reach” units capable of reaching the toe of wells with total measured
depths of 24,000 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 April 2014 through December 2020, we have performed approximately 9,800 jobs and deployed more than 218 million running feet of coiled tubing, with a success rate of over 99%.
Well Services: On August 30, 2019, we sold our Production Solutions segment. For additional information on this divestiture, see Note 16 - Segment Information included in Item 8 of Part II of this Annual Report.
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.
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, Rockies, 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, 2020, our top five customers collectively accounted for approximately 37% 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, NexTier Oilfield Solutions, KLX Energy Services Holdings, 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, 2020, 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 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, 2020, we had 735 employees, of which 733 were full-time. We are not a party to any collective bargaining agreements.
Coronavirus Pandemic
The worldwide coronavirus outbreak in early 2020, which was declared a pandemic by the World Health Organization in March 2020, the uncertainty regarding its impact, and various governmental actions taken to mitigate its impact have resulted in an unprecedented decline in demand for oil. In the midst of the ongoing pandemic, the Organization of the Petroleum Exporting Countries (“OPEC”) and other oil producing nations, including Russia (collectively, “OPEC+”), were initially unable to reach an agreement on production levels for crude oil, at which point Saudi Arabia and Russia initiated efforts to aggressively increase production. The convergence of these events created the unprecedented dual impact of a massive decline in the demand for oil coupled with the risk of a substantial increase in supply. While OPEC+ agreed in April 2020 to cut production, downward pressure on commodity prices has remained and could continue for the foreseeable future.
In response to lower oil prices, our customers have generally revised their capital budgets downward and adjusted their operations accordingly, which has caused a significant decline in demand for our products and services.
While we cannot predict the length of time that market disruptions resulting from the coronavirus pandemic and efforts to mitigate its effects will continue, the ultimate impact on our business, or the pace or extent of any subsequent recovery, we
expect the coronavirus pandemic and related effects to continue to have a material adverse impact on commodity prices and our business generally. We have experienced inefficiencies and logistical challenges surrounding stay-at-home orders and remote work arrangements, travel restrictions, and an inability to commute to certain facilities and job sites, as we provide services and products to our customers. For more information, see “Risk Factors - Risks Related to the Coronavirus Pandemic” in Item 1A of Part I and in “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Overview - Impact of the Coronavirus Pandemic; Industry Trends and Outlook” in Item 7 of Part II of this Annual Report.
During the pandemic, we have maintained our commitment to the safety of our employees, customers, vendors, and community at large, and we have taken, and are continuing to take, a proactive approach to navigating the pandemic. To mitigate exposure and risk, we have implemented processes and procedures across our entire organization based on federal, regional, and local guidelines and mandates, and our Health, Safety & Environment and management teams are in frequent communication with our entire employee base to ensure they are receiving updated guidelines, processes, and procedures. In response to the pandemic, we have implemented the following changes, for example: at the field level, we are working closely with our customers and vendors to update standard operating procedures, based on social distancing, hand washing, and other recommended best practices set forth by the Centers for Disease Control and Prevention; electronic assessments have been employed to check the health of employees prior to reporting to work, to ensure facilities are being properly cleaned and sanitized, and to check visitor health before arrival to a Nine location; internal case managers have been identified to handle all coronavirus-related cases, and all confirmed and potential cases are tracked through closure; many of our corporate and office employees are working virtually to avoid unnecessary risk and exposure; and we have significantly limited any work-related travel. We are actively monitoring updates from regulatory and government bodies and evolving our strategy accordingly in an effort to keep our workforce and communities healthy.
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. 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 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 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. Specifically, RCRA excludes from the definition of hazardous waste produced waters and other wastes intrinsically associated with the exploration, development, or production of crude oil and natural gas. However, these oil and gas E&P wastes may still be regulated under state solid waste laws and regulations, and 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. For example, in December 2016, the EPA and environmental groups entered into a consent decree to address the EPA’s alleged failure to timely assess its RCRA Subtitle D criteria regulations exempting certain E&P related oil and gas wastes from regulation as hazardous wastes under RCRA. The consent decree required the EPA to propose a rulemaking no later than March 15, 2019 for revision of certain Subtitle D criteria regulations pertaining to oil and gas wastes or to sign a determination that revision of the regulations was not necessary. On April 23, 2019, the EPA determined that a revision of the regulations was not necessary. 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, imposes 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 or 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 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”), 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. In June 2016, OSHA finalized a regulation regarding crystalline silica exposures, which included requirements that hydraulic fracturing operations implement dust controls to limit exposures to the substance by June 23, 2021. 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, the federal Bureau of Alcohol, Tobacco, Firearms and Explosives establishes requirements for the safe use and storage of explosives, and the federal Nuclear Regulatory Commission establishes requirements for the protection against 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
At December 31, 2020, we operated a fleet in excess of 550 commercial motor vehicles. As such, we are subject to a number of federal and state laws and regulations, including the Federal Motor Carrier Safety Regulations and Hazardous Material Regulations for interstate travel and comparable state regulations for intrastate travel. 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 U.S. The discharge of pollutants into regulated waters, including jurisdictional wetlands, is prohibited, except in accordance with the terms of a permit issued by the EPA or an analogous state agency. In September 2015, the EPA and U.S. Army Corps of Engineers (the “Corps”) issued a rule defining the scope of federal jurisdiction over wetlands and other waters; however, this rule was repealed on October 22, 2019. On January 23, 2020, the EPA and the Corps issued the Navigable Waters Protection Rule re-defining the term “waters of the United States” as applied under the Clean Water Act and narrowing the scope of waters subject to federal regulation, and the final rule became effective on June 22, 2020. This Navigable Waters Protection Rule is subject to various pending legal challenges, and a federal district court in Colorado stayed implementation of the rule. The stay is limited to application of the rule in Colorado; the rule has taken effect in all other states. At President Biden’s direction, the EPA and the Corps requested the litigation be stayed while the agencies review the rule. To the extent a future rule expands the range of properties subject to the Clean Water Act’s 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 for the costs of removal, remediation, and damages in connection with any unauthorized discharges.
Air Emissions
The federal Clean Air Act (the “CAA”) and comparable state laws regulate emissions of various air pollutants through air emissions permitting programs and the imposition of other requirements. In addition, the EPA has developed, and continues to develop, stringent regulations governing emissions of toxic air pollutants at specified sources. These regulations change frequently. These laws and regulations may require us to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and strictly comply with stringent air permit requirements, or utilize specific equipment or technologies to control emissions of certain pollutants. In addition, in October 2015, the EPA lowered the National Ambient Air Quality Standard (“NAAQS”) for ozone from 75 to 70 parts per billion. In November 2017, the EPA published a list of areas that are in compliance with the new ozone standard and, separately in December 2017, issued responses to state recommendations for designating non-attainment areas. The EPA completed all initial area designations in July 2018. State implementation of the revised NAAQS could result in stricter permitting requirements, which in turn 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
The EPA has determined that emissions of greenhouse gases, 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 greenhouse gas emission reporting requirements for sources in the oil and gas sector and has also promulgated rules requiring certain large stationary sources of greenhouse gases to obtain preconstruction permits under the CAA and follow “best available control technology” requirements. Although we are not likely to become subject to greenhouse gas emissions permitting and best available control technology requirements because none of our facilities are presently major sources of greenhouse gas 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 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. Although the agreement does not create any binding obligations for nations to limit their greenhouse gas emissions, it does include pledges to voluntarily limit or reduce future emissions. On June 1, 2017, President Trump announced that the U.S. would withdraw from the Paris Agreement and that it would potentially seek to renegotiate the Paris Agreement on more favorable terms. The U.S. completed the process of withdrawing from the Paris Agreement on November 4, 2020. In response to the United States’ withdrawal announcement, various corporations, investors, and U.S. state and local governments publicly pledged to further the goals of the Paris Agreement. On January 20, 2021, President Biden issued written notification to the United Nations of the United States’ intention to rejoin the Paris Agreement, which became effective on February 19, 2021.
Also, the U.S. Congress has from time to time considered adopting legislation to reduce emissions of greenhouse gases, and many states have already established regional greenhouse gas “cap-and-trade” programs. The adoption of any legislation or regulation that restricts emissions of greenhouse gases 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. Finally, most scientists have concluded that increasing concentrations of greenhouse gases 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.
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 and published permitting guidance in February 2014 addressing the performance of such activities using diesel fuels.
There is considerable uncertainty surrounding regulation of the emissions of methane, which may be released during hydraulic fracturing. In 2016, the EPA issued final regulations under the CAA establishing performance standards, including standards for the capture of methane emissions released during hydraulic fracturing. However, the EPA has taken several steps to delay implementation of its methane standards, including most recently in September 2020, when the EPA finalized the Reconsideration Rule that rolls back parts of the 2016 performance standards. Various industry and environmental groups have separately challenged both the original standards and the EPA’s attempts to delay implementation of the rule. Separately, in September 2020, the EPA finalized the Review Rule rescinding requirements related to the regulations of methane emissions from the oil and natural gas industry. Both rules are subject to ongoing litigation and, on January 20, 2021, President Biden issued an Executive Order directing the EPA to rescind the Reconsideration Rule by September 2021 and consider revising the Review Rule. Therefore, the scope of future obligations continues to remain uncertain. In addition, in April 2018, a coalition of states filed a lawsuit in the U.S. District Court for the District of Columbia aiming to force the EPA to establish guidelines for limiting methane emissions from existing sources in the oil and natural gas sector; that lawsuit is pending. On March 20, 2015, the U.S. Bureau of Land Management (the “BLM”) finalized a rule regulating hydraulic fracturing activities on federal lands, including requirements for the disclosure, wellbore integrity, and handling of flowback water; however, on December 29, 2017, the BLM issued a rescission of the hydraulic fracturing rule. This rescission and the rule as promulgated are subject to ongoing litigation. The BLM also previously finalized in 2016 similar limitations on methane emissions from venting and flaring and leaking equipment from oil and natural gas activities on public lands, but in September 2018 issued a final rule repealing certain provisions of the 2016 rule and reinstating the pre-2016 regulations. The 2016 rule and the rescission were invalidated by separate federal district courts. As a result, future implementation of methane rules by either the EPA or the BLM is uncertain at this time. However, given the long-term trend towards increasing regulation, future federal regulation of methane and other greenhouse gas emissions from the oil and gas industry remains a possibility.
The EPA has also issued effluent limitation guidelines that prohibit the discharge of wastewater from hydraulic fracturing operations to publicly owned wastewater treatment plants. These rules were finalized in June 2016, and after a legal challenge by environmental groups, in July 2019, the EPA declined to revise the rules. The EPA conducted a study on effluent guidelines for the oil and gas industry, and a draft of this study was published in May 2019. 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 released its final 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. As described elsewhere in this Annual Report, these risks are regulated under various state, federal, and local laws.
Some states, counties, and municipalities have enacted or are considering moratoria on hydraulic fracturing. For example, New York, Vermont, Maryland, and Washington have banned, or are in the process of banning, the use of high-volume hydraulic fracturing. 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 are also considering 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, 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. On July 16, 2020, the Council on Environmental Quality revised NEPA’s implementing regulations in an effort to streamline approvals for projects. Among other revisions, the rules redefined environmental “effects” or “impacts” as the effects “that are reasonably foreseeable and have a reasonably close causal relationship to the proposed action or alternatives.” The rule also eliminated the current “direct,” “indirect,” or “cumulative” categories of effects. The new regulations are subject to ongoing litigation in several federal district courts, and future implementation of the regulations is unclear. To the extent that our customers’ current activities, as well as proposed plans, on federal lands require governmental permits that are subject to the requirements of NEPA, this process has the potential to delay or impose additional conditions upon the development of oil and natural gas projects.
Endangered Species Act and Migratory Bird Treaty Act
The Endangered Species Act (the “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 August 2019, the FWS and National Marine Fisheries Service issued three rules amending implementation of the ESA regulations revising, among other things, the process for listing species and designating critical habitat. A coalition of states and environmental groups have challenged the three rules and the litigation remains pending. In addition, on December 18, 2020, the FWS amended its regulations governing critical habitat designations. We anticipate the rule will be subject to litigation. 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. On January 7, 2021, the Department of the Interior finalized a rule limiting application of the MBTA; however the Department of the Interior under President Biden delayed the effective date of the rule and opened a public comment period for further review. Future implementation of the rules implementing the Endangered Species Act 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.

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ITEM 1A. RISK FACTORS
Item 1A. Risk Factors
We face many challenges and risks in the industry in which we operate. You should carefully consider each of the following risk factors and all of the other information set forth in this Annual Report, including under the section titled “Cautionary Note Regarding Forward-Looking Statements.” The risks and uncertainties described are not the only ones we face. Additional risk factors not presently known to us or which we currently consider immaterial may also adversely affect our business, financial condition, or future results. If any of these risks were actually to occur, our business, financial condition, or results of operations could be materially adversely affected. In that case, the trading price of our common stock could decline, and a stockholder could lose all or part of its investment.
Risks Related to Our Industry
Our business is cyclical and depends on capital spending and well completions by the onshore oil and natural gas industry, and the level of such activity is volatile. Our business has been, and may continue to be, adversely affected by industry and financial market conditions that are beyond our control.
Our business is cyclical, and we depend on our customers’ willingness to make operating and capital expenditures to explore for, develop, and produce oil and natural gas, which, in turn, largely depends on prevailing industry and financial market conditions that are influenced by numerous factors beyond our control, including:
•the level of prices, and expectations about future prices, for oil and natural gas;
•the domestic and foreign supply of, and demand for, oil and natural gas and related products;
•the level of global and domestic oil and natural gas production;
•the supply of, and demand for, hydraulic fracturing and other oilfield services and equipment;
•governmental regulations, including the policies of governments regarding the exploration for and production and development of their oil and natural gas reserves;
•the cost of exploring for, developing, producing, and delivering oil and natural gas;
•available pipeline, storage, and other transportation capacity;
•worldwide political, military, and economic conditions;
•global or national health epidemics or concerns, such as the recent coronavirus outbreaks, which may reduce demand for oil, natural gas, and related products because of reduced global or national economic activity;
•lead times associated with acquiring equipment and products and availability of qualified personnel;
•the discovery rates of new oil and natural gas reserves;
•federal, state, and local regulation of hydraulic fracturing and other oilfield service activities, as well as E&P activities, including public pressure on governmental bodies and regulatory agencies to regulate our industry;
•economic and political conditions in oil and natural gas producing countries;
•actions of OPEC, its members, and other state-controlled oil companies relating to oil price and production levels, including announcements of potential changes to such levels;
•advances in exploration, development, and production technologies or in technologies affecting energy consumption;
•activities by non-governmental organizations to restrict the exploration, development, and production of oil and natural gas so as to minimize emissions of carbon dioxide, a greenhouse gas;
•the price and availability of alternative fuels and energy sources;
•global weather conditions and natural disasters; and
•uncertainty in capital and commodities markets and the ability of oil and natural gas producers to access capital.
A decline in oil and natural gas commodity prices may adversely affect the demand for our products and services and the rates we are able to charge.
Our business depends, to a significant extent, on the level of unconventional resource development activity and corresponding capital spending of oil and natural gas companies, which are strongly influenced by current and expected oil and natural gas prices. Volatility or weakness in oil and natural gas commodity prices (or the perception that oil and natural gas commodity prices will decrease) affects the spending patterns of our customers and may result in the drilling of fewer new wells or lower production spending on existing wells. Historically, oil and natural gas commodity prices have been extremely volatile. During the past five years ending December 31, 2020, the posted price for West Texas Intermediate (“WTI”) oil has ranged from a low of $(36.98) per barrel in April 2020 to a high of $77.41 per barrel in June 2018, and the Henry Hub spot market price of gas has ranged from a low of $1.33 per MMBtu in September 2020 to a high of $6.24 per MMBtu in January 2018. Oil and natural gas commodity prices were particularly volatile in 2020 as a result of multiple significant factors impacting supply and demand in the global oil and natural gas markets, including those relating to the coronavirus pandemic. In 2020, the daily spot prices for WTI crude oil ranged from a high of $63.27 per barrel to a low of $(36.98) per barrel, and the Henry Hub spot market price of gas ranged from a low of $1.33 per MMBtu to a high of $3.14 per MMBtu. Oil and natural gas commodity prices are expected to continue to be volatile. If the prices of oil and natural gas continue to decline or remain depressed for a lengthy period, our business, financial condition, results of operations, cash flows, and prospects may be materially and adversely affected.
Significant factors that are likely to affect near-term commodity prices include the extent to which members of OPEC and other oil exporting nations continue to reduce oil export prices and increase production; the effect of U.S. energy, monetary, and trade policies; the pace of economic growth in the U.S. and throughout the world, including the potential for macro weakness; geopolitical and economic developments in the U.S. and globally; changes to energy and EPA policies; and overall North American natural gas supply and demand fundamentals, including the pace at which export capacity grows. For additional information, please see “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Overview - Impact of the Coronavirus Pandemic; Industry Trends and Outlook” in Item 7 of Part II of this Annual Report.
The products and services we provide are, to a substantial extent, deferrable in the event oil and natural gas companies reduce capital expenditures. As a result, we may experience lower utilization of, and may be unable to increase rates or be forced to lower our rates for, our equipment and services in weak oil and natural gas commodity price environments. Even if oil and natural gas prices improve, E&P operator activity may not materially increase, as they remain focused on operating within their capital plans. Moreover, any substantial and unexpected drop in commodity prices in the future, even if the drop is relatively short-lived, or expectations of such a drop or of prolonged weak oil and natural gas commodity price environments, could similarly affect our customers’ expectations and capital spending, which could result in a material adverse effect on our business, financial condition, results of operations, cash flows, and prospects.
Reduced discovery rates of new oil and natural gas reserves in our market areas as a result of decreased capital spending may also have a negative long-term impact on our business, even in an environment of stronger oil and natural gas prices, to the extent the reduced number of wells for us to service more than offsets increasing completion activity and intensity.
Our business could be adversely affected by a decline in general economic conditions or a weakening of the broader energy industry.
A prolonged economic slowdown or recession, adverse events relating to the energy industry, or regional, national, or global economic conditions and factors, particularly a slowdown in the E&P industry, could negatively impact our operations and therefore adversely affect our results. The risks associated with our business are more acute during periods of economic slowdown or recession because such periods may be accompanied by decreased exploration and development spending by our customers, decreased demand for oil and natural gas, and decreased prices for oil and natural gas.
Increased attention to climate change and conservation measures may reduce oil and natural gas demand.
Increased attention to climate change, consumer demand for alternatives to oil and natural gas, and competitiveness of alternative energy sources (such as wind, solar geothermal, tidal, fuel cells, and biofuels) could reduce demand for oil and natural gas and therefore our products and services, which would lead to a reduction in our revenues and have a material adverse effect on our business, financial condition, results of operations, cash flows, and prospects.
A negative shift in investor sentiment of the oil and gas industry could adversely affect our ability to raise debt and equity capital.
Certain segments of the investor community have developed negative sentiment towards investing in our industry. Recent equity returns in the sector versus other industry sectors have led to lower oil and gas representation in certain key equity market indices. In addition, some investors, including investment advisors and certain sovereign wealth funds, pension funds, university endowments, and family foundations, have stated policies to disinvest in the oil and gas sector based on their social and environmental considerations. Certain other stakeholders have also pressured commercial and investment banks to stop financing oil and gas production and related infrastructure projects. Such developments, including environmental activism and initiatives aimed at limiting climate change and reducing air pollution, could result in downward pressure on the stock prices of oil and gas companies, including ours. These developments may also potentially result in a reduction of available capital funding for potential development projects, impacting our future financial results.
We face various risks associated with increased activism against oil and natural gas exploration and development activities.
Opposition toward oil and natural gas drilling and development activity has been growing globally and is particularly pronounced in the U.S. Companies in the oil and natural gas industry are often the target of activist efforts from both individuals and non-governmental organizations regarding safety, human rights, environmental matters, sustainability, and business practices. Anti-development activists are working to, among other things, reduce access to federal and state government lands and delay or cancel certain operations such as drilling and development. If activism against oil and natural gas exploration and development persists or increases, there could be a material adverse effect on our business, financial condition, and results of operations.
Risks Related to the Coronavirus Pandemic
The recent coronavirus pandemic and related economic repercussions have had, and are expected to continue to have, a significant adverse impact on our business, and depending on the duration of the pandemic and its effect on the oil and gas industry, could have a material adverse effect on our business, liquidity, results of operations, and financial condition.
The coronavirus pandemic and related economic repercussions have created significant volatility, uncertainty, and turmoil in the oil and gas industry. These events have directly affected our business and have exacerbated the potential negative impact from many of the risks described in this Annual Report, including those relating to our customers’ capital spending and trends in oil and natural gas prices. For example, demand for our products and services has and continues to decline as our customers continue to revise their capital budgets downwards and swiftly adjust their operations in response to lower commodity prices. In addition, the decline in market conditions resulted in goodwill impairment charges of $296.2 million recorded in the first quarter of 2020. We are also experiencing inefficiencies and logistical challenges surrounding stay-at-home orders and remote work arrangements, travel restrictions, and an inability to commute to certain facilities and job sites, as we provide services and products to our customers.
In the midst of the ongoing coronavirus pandemic, OPEC+ was initially unable to reach an agreement to continue to impose limits on the production of crude oil. The convergence of these events created the unprecedented dual impact of a global oil demand decline coupled with the risk of a substantial increase in supply. Oil demand significantly deteriorated as a result of the virus outbreak in March 2020 and corresponding preventative measures taken around the world to mitigate the spread of the virus, and at the same time, aggressive increases in production of oil by Saudi Arabia and Russia created a significant surplus in the supply of oil. While OPEC+ agreed in April 2020 to cut production, downward pressure on commodity prices has continued, as the coronavirus pandemic has continued with resurgences in the U.S. and worldwide.
Given the nature and significance of the events described above, we are not able to enumerate all potential risks to our business; however, we believe that in addition to the impacts described above, other current and potential impacts of these recent events include, but are not limited to:
•disruption to our supply chain for raw materials essential to our business, including restrictions on importing and exporting products;
•notices from customers, suppliers, and other third parties arguing that their non-performance under our contracts with them is permitted as a result of force majeure or other reasons;
•liquidity challenges, including impacts related to delayed customer payments and payment defaults associated with customer liquidity issues and bankruptcies;
•a credit rating downgrade of our corporate debt and potentially higher borrowing costs in the future;
•a need to preserve liquidity, which could result in a delay or change in our capital investment plan;
•cyber security issues, as digital technologies may become more vulnerable and experience a higher rate of cyber attacks in the current environment of remote connectivity;
•litigation risk and possible loss contingencies related to coronavirus and its impact, including with respect to commercial contracts, employee matters, and insurance arrangements;
•reduction of our workforce to adjust to market conditions, including severance payments, retention issues, and an inability to hire employees when market conditions improve;
•additional impairments along with other accounting charges as demand for our services and products decreases;
•infections and quarantining of our employees and the personnel of our customers, suppliers, and other third parties in areas in which we operate;
•changes in the regulation of the production of hydrocarbons, such as the imposition of limitations on the production of oil and gas by states or other jurisdictions, that may result in additional limits on demand for our products and services;
•actions undertaken by national, regional, and local governments and health officials to contain the virus or treat its effects; and
•a structural shift in the global economy and its demand for oil and natural gas as a result of changes in the way people work, travel, and interact, or in connection with a global recession or depression.
Given the dynamic nature of these events, we cannot reasonably estimate the period of time that the coronavirus pandemic and related market conditions will persist, the full extent of the impact they will have on our business, financial condition, results of operations, or cash flows or the pace or extent of any subsequent recovery.
The confluence of events described above have had, and are expected to continue to have, a significant impact on our business, and depending on the duration of the pandemic and its effect on the oil and gas industry, could have, a material adverse effect on our business, liquidity, results of operations, and financial condition.
Risks Related to Our Indebtedness
Our substantial debt obligations could have significant adverse consequences on our business and future prospects.
As of December 31, 2020, we had $346.7 million of 8.750% Senior Notes due 2023 (the “Senior Notes”) outstanding, and we had $37.9 million of availability under the 2018 ABL Credit Facility (as defined and described in “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources” in Item 7 of Part II of this Annual Report), net of outstanding letters of credit of $0.5 million. Subject to the restrictions in the 2018 ABL Credit Facility and the indenture governing the Senior Notes, we may incur substantial additional indebtedness (including secured indebtedness) in the future. Our current or future level of indebtedness could have significant adverse consequences on our business and future prospects, including in the following ways:
•requiring us to dedicate a substantial portion of our cash flow from operations to service our existing debt, thereby reducing the cash available to finance our operations and other business activities;
•limiting management’s discretion in operating our business and our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate;
•increasing our vulnerability to downturns and adverse developments in our business and the economy generally;
•limiting our ability to access the capital markets to raise capital on favorable terms or to obtain additional financing for working capital, capital expenditures, or acquisitions or to refinance existing indebtedness;
•making us vulnerable to increases in interest rates as our indebtedness under the 2018 ABL Credit Facility may vary with prevailing interest rates;
•placing us at a competitive disadvantage relative to competitors with lower levels of indebtedness in relation to their overall size or less restrictive terms governing their indebtedness; and
•making it more difficult for us to satisfy our obligations under our debt instruments and increase the risk that we may default on our debt obligations.
We may not be able to generate sufficient cash to service all of our indebtedness.
Our ability to make scheduled payments with respect to our indebtedness depends on our financial condition and operating performance, which are subject to prevailing economic and competitive conditions and certain financial, business, and other factors beyond our control. If our cash flows and capital resources are insufficient to fund debt service obligations, we may be forced to sell assets, seek additional capital, or restructure or refinance indebtedness. These alternative measures may not be successful and may not permit us to meet scheduled debt service obligations. For example, we may not be able to consummate dispositions, and the proceeds of any such disposition may not be adequate to meet any debt service obligations then due. Also, our ability to restructure or refinance indebtedness will depend on the condition of the capital markets and our financial condition at such time. Any refinancing of indebtedness could be at higher interest rates and may require us to comply with more onerous covenants, which could further restrict business operations. In addition, any debt restructuring transactions may involve the issuance of additional equity or convertible debt securities that could result in material dilution to our stockholders, and these securities could have rights superior to holders of our common stock and could contain covenants that will restrict our operations. The terms of existing or future debt instruments may restrict us from adopting some of these alternatives.
If we are unable to generate sufficient cash flow and are otherwise unable to obtain funds necessary to meet required payments of principal, premium, if any, and interest on our indebtedness, we could be in default under the terms of the agreements governing such indebtedness. An event of default, if not waived, could result in acceleration of the indebtedness outstanding under the applicable agreement and an event of default with respect to, and an acceleration of, the indebtedness outstanding under any other debt agreements to which we are a party. Any such accelerated indebtedness would become immediately due and payable. If that occurs, we may not be able to make all of the required payments. In addition, any failure to make payments on outstanding indebtedness on a timely basis would likely result in a reduction of our credit rating, which could harm our ability to incur additional indebtedness.
Restrictions in our debt agreements could limit our growth and our ability to engage in certain activities.
The 2018 ABL Credit Facility (as defined and described in “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources” in Item 7 of Part II of this Annual Report) and the indenture governing our Senior Notes have, and future financing agreements could have, restrictive covenants that could restrict our ability to finance future operations or capital needs or to expand or pursue our business activities. For example, our debt agreements contain restrictive covenants that limit our ability to, among other things:
•incur additional indebtedness and guarantee indebtedness;
•pay dividends or make other distributions or repurchase or redeem our capital stock;
•transfer or sell assets;
•make loans and investments;
•incur liens;
•enter into agreements that restrict dividends or other payments from any non-guarantor restricted subsidiaries to us;
•consolidate, merge, or sell all or substantially all of our assets;
•prepay, redeem, or repurchase certain debt;
•issue certain preferred stock or similar equity securities;
•make certain acquisitions and investments;
•engage in transactions with affiliates; and
•create unrestricted subsidiaries.
The restrictions in our debt agreements could also impact our ability to obtain capital to withstand a downturn in our business or the economy in general, or to otherwise conduct necessary corporate activities. We may also be prevented from taking advantage of business opportunities that arise because of the limitations that the restrictive covenants under our debt arrangements may impose on us.
A breach of any covenant in our debt agreements will result in a default under the applicable agreement and an event of default under such agreement if there is no grace period or if such default is not cured during any applicable grace period. An event of default, if not waived, could result in acceleration of the indebtedness outstanding under the applicable agreement and an event of default with respect to, and an acceleration of, the indebtedness outstanding under any other debt agreements to which we are a party. Any such accelerated indebtedness would become immediately due and payable. If that occurs, we may not be able to make all of the required payments or borrow sufficient funds to refinance such indebtedness. Even if new financing were available at that time, it may not be on terms that are acceptable to us.
Uncertainty relating to the London Interbank Offered Rate (“LIBOR”) calculation process and potential phasing out of LIBOR after 2021 may adversely affect the market value of our current or future debt obligations.
Loans to us and our domestic related subsidiaries under the 2018 ABL Credit Facility (as defined and described in “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources” in Item 7 of Part II of this Annual Report) may be base rate loans or LIBOR loans. LIBOR is calculated by reference to a market for interbank lending, and it is based on increasingly fewer actual transactions. This reduction increases the subjectivity of the LIBOR calculation process and increases the risk of manipulation. Actions by the regulators or law enforcement agencies, as well as ICE Benchmark Administration (the current administrator of LIBOR), may result in changes to the manner that LIBOR is determined or the establishment of alternative reference rates. For example, on July 27, 2017, the U.K. Financial Conduct Authority announced that it intends to stop persuading or compelling banks to submit LIBOR rates after 2021. U.S. Dollar LIBOR will likely be replaced by the Secured Overnight Financing Rate (“SOFR”) published by the Federal Reserve Bank of New York; however, the timing of this shift is currently unknown. SOFR is an overnight rate instead of a term rate, making SOFR an inexact replacement for LIBOR, and there is not an established process to create robust, forward-looking, SOFR term rates. Changing the benchmark rate for LIBOR loans from LIBOR to SOFR requires calculations of a spread. Industry organizations are attempting to structure the spread calculation in a manner that minimizes the possibility of value transfer between counterparties, borrowers, and lenders by the transition, but there is no assurance that the calculated spread will be fair and accurate. At this time, it is not possible to predict the effect of any such changes, any establishment of alternative reference rates or any other reforms to LIBOR that may be implemented. If LIBOR ceases to exist, we may need to renegotiate the 2018 ABL Credit Facility to determine the interest rate to replace LIBOR with the new standard that is established. As such, the potential effect of any such event on our interest expense cannot yet be determined.
Competition and Market Risks
We may be unable to maintain existing prices or implement price increases on our products and services.
We periodically seek to increase the prices on our products and services to offset rising costs and to generate higher returns for our stockholders. However, we operate in a very competitive industry and as a result, we are not always successful in raising or maintaining our existing prices. Volatility in oil and natural gas prices can impact our customers’ activity levels, and current energy prices are important contributors to cash flow for our customers and their actual or perceived ability to fund exploration and development activities, which may limit our ability to increase or maintain prices. Additionally, during periods of increased market demand, a significant amount of new service capacity, including new well service rigs, wireline units, and coiled tubing units, may enter the market, which also puts pressure on the pricing of our services and limits our ability to increase prices.
Even when we are able to increase our prices, we may not be able to do so at a rate that is sufficient to offset rising costs. In periods of high demand for oilfield services, a tighter labor market may result in higher labor costs. During such periods, our labor costs could increase at a greater rate than our ability to raise prices for our services. Also, we may not be able to successfully increase prices without adversely affecting our activity levels. The inability to maintain our pricing and to increase our pricing as costs increase could have a material adverse effect on our business, financial position, results of operations, and cash flows.
Intense competition in the markets for our dissolvable plug products may lead to pricing pressures, reduced sales, or reduced market share.
The oil and natural gas industry is intensely competitive and has been characterized by price erosion for new technologies as additional competing products enter the market. Throughout 2020 we experienced, and we continue to experience, a decline in the pricing and profitability of our dissolvable plug products and, to a lesser extent, our composite plug products. Any further declines in the future may harm our business.
We compete with major domestic and international oilfield services companies, many of which have greater market recognition and substantially greater financial, technical, marketing, distribution, and other resources than we do. We have experienced pricing declines in certain of our more mature proprietary product lines, primarily due to competitive conditions. Likewise, our customers may seek pricing declines more precipitously than our ability to reduce costs, leaving us unable to achieve or maintain pricing to our customers at a level sufficient to cover our costs.
We are continuing to work on reducing manufacturing costs of our products, as well as introducing new and differentiated technology to improve profitability, however, there can be no assurance that we will be able to do so in the future. If the amounts we are able to charge customers for our dissolvable plug products decline further or are insufficient to cover our costs, that could have a material adverse effect on our financial condition, results of operations, and cash flows.
Our current and potential competitors may have longer operating histories, significantly greater financial or technical resources, and greater name recognition than we do.
The oilfield services industry is highly competitive and fragmented and includes several large companies that compete in many of the markets we serve, as well as numerous small companies that compete with us on a local basis. The oilfield services industry competes primarily on a regional basis, and the intensity of competition may vary significantly from region to region at any particular time. We believe the principal competitive factors in the market areas we serve include price, equipment quality, supply chains, balance sheet strength and financial condition, product and service quality, safety record, availability of crews and equipment, and technical proficiency.
Many of our existing and potential competitors have substantially greater financial, technical, manufacturing, and other resources than we do. The greater size of many of our competitors provides them with cost advantages as a result of their economies of scale and their ability to obtain volume discounts and purchase raw materials at lower prices. As a result, such competitors may have stronger bargaining power with their suppliers and have an advantage over us in pricing as well as securing a sufficient supply of raw materials during times of shortage. Many of our competitors also have better brand name recognition, stronger presence in more geographic markets, more established distribution networks, larger customer bases, more in-depth knowledge of the target markets, and the ability to provide a much broader array of products and services. Some of our competitors may also be able to devote greater resources to the research and development, promotion, and sale of their products and better withstand the evolving industry standards and changes in market conditions as compared to us. Our operations may be adversely affected if our competitors introduce new products or services with better features, performance, prices, or other characteristics than our products and services or expand into service areas where we operate. Our operations may also be adversely affected if our competitors are able to respond more quickly to new or emerging technologies and services and changes in customer requirements.
Competitive pressures could reduce our market share or require us to reduce the price of our services and products, particularly during industry downturns, either of which would harm our business and operating results. Significant increases in overall market capacity have also caused active price competition and led to lower pricing and utilization levels for our services and products. The competitive environment has intensified since the industry downturn that began in late 2014, which caused an oversupply of, and reduced demand for, oilfield services, and we have seen substantial reductions in the prices we can charge for our services and products. Any significant future increase in overall market capacity for completion services may adversely affect our business, financial condition, and results of operations.
Operational Risks
Our operations are subject to conditions inherent in the oilfield services industry.
Conditions inherent in the oil and natural gas industry can cause personal injury or loss of life, disruption or suspension in operations, damage to geological formations, damage to facilities, substantial revenue loss, business interruption, and damage to, or destruction of, property, equipment, and the environment. Such risks may include, but are not limited to:
•equipment defects;
•liabilities arising from accidents or damage involving our fleet of trucks and other equipment;
•explosions and uncontrollable flows of gas or well fluids;
•unusual or unexpected geological formations or pressures and industrial accidents;
•blowouts;
•fires;
•cratering;
•loss of well control;
•collapse of the borehole; and
•damaged or lost equipment.
Defects or other performance problems in the products that we sell or services that we offer could result in our customers seeking damages from us for losses associated with these defects or other performance problems. In addition, our services could become a source of spills or release of fluids, including chemicals used during hydraulic fracturing activities, at the site where such services are performed, or could result in the discharge of such fluids into underground formations that were not targeted for fracturing or well completion activities, such as potable aquifers, or at third-party properties. These risks could expose us to substantial liability for personal injury, wrongful death, property damage, loss of oil and natural gas production, pollution, and other environmental damages and could result in a variety of claims, losses, and remedial obligations that could have an adverse effect on our business and results of operations. The existence, frequency, and severity of such incidents could affect operating costs, insurability, and relationships with customers, employees, and regulators. In particular, our customers may elect not to purchase our services if they view our safety record as unacceptable or otherwise experience material defects in our products or performance problems, which could cause us to lose customers and substantial revenue, and any litigation or claims, even if fully indemnified or insured, could negatively affect our reputation with our customers and the public and make it more difficult for us to compete effectively or obtain adequate insurance in the future.
Our assets require capital for maintenance, upgrades, and refurbishment, and we may require capital expenditures for new equipment.
Our equipment requires capital investment in maintenance, upgrades, and refurbishment to maintain their competitiveness. For the years ended December 31, 2020 and 2019, we spent approximately $2.9 million and $13.6 million, respectively, on capital expenditures related to maintenance, and we expect to spend approximately $13 million to $14 million on capital expenditures related to maintenance in 2021. Our equipment typically does not generate revenue while it is undergoing maintenance, refurbishment, or upgrades. Any maintenance, upgrade, or refurbishment project for our assets could increase our indebtedness or reduce cash available for other opportunities. Further, such projects may require proportionally greater capital investments as a percentage of total asset value, which may make such projects difficult to finance on acceptable terms. To the extent we are unable to fund such projects, we may have less equipment available for service or our equipment may not be attractive to potential or current customers. Additionally, competition or advances in technology within our industry may require us to update our products and services. Such demands on our capital or reductions in demand and the increase in cost to maintain labor necessary for such maintenance and improvement, in each case, could have a material adverse effect on our business, liquidity position, financial condition, prospects, and results of operations and may increase costs. In addition, although such projects may require material capital expenditures, there is no assurance that they will generate a positive return.
Risks Related to Our Customers and Suppliers
If we are unable to accurately predict customer demand or if customers cancel their orders on short notice, we may hold excess or obsolete inventory, which would reduce gross margins. Conversely, insufficient inventory would result in lost revenue opportunities and potentially in loss of market share and damaged customer relationships.
We often place orders with our suppliers based on forecasts of customer demand. Anticipating customer demand is difficult because our customers face unpredictable demand for their own products and are increasingly focused on cash preservation and tighter inventory management. Our forecasts of customer demand are based on multiple assumptions, each of which may introduce errors into the forecasts. If we overestimate customer demand, we may allocate resources to the purchase of material or manufactured products that we may not be able to sell when we expect to, if at all. As a result, we would hold excess or obsolete inventory, which would reduce gross margin and adversely affect financial results. Conversely, if we
underestimate customer demand or if insufficient manufacturing capacity is available, we would miss revenue opportunities and potentially lose market share and damage our customer relationships. In addition, any future significant cancellations or deferrals of orders or the return of previously sold products could materially and adversely affect profit margins, increase inventory obsolescence, and restrict our ability to fund our operations.
We are exposed to the credit risk of our customers, and the deterioration of the financial condition of our customers could adversely affect our financial results.
We are subject to the risk of loss resulting from nonpayment or nonperformance by our customers, many of whose operations are concentrated solely in the domestic and Canadian E&P industry, which, as described above, is subject to volatility and, therefore, credit risk. Our credit procedures and policies may not be adequate to fully reduce customer credit risk. If we are unable to adequately assess the creditworthiness of existing or future customers or unanticipated deterioration in their creditworthiness, any resulting increase in nonpayment or nonperformance by them and our inability to re-market or otherwise use our equipment could have a material adverse effect on our business, financial condition, prospects, and/or results of operations. In the course of our business, we hold accounts receivable from our customers. In the event of the financial distress or bankruptcy of a customer, we could lose all or a portion of such outstanding accounts receivable associated with that customer. Further, if a customer was to enter into bankruptcy, it could also result in the cancellation of all or a portion of our service contracts with such customer at significant expense or loss of expected revenues to us.
In addition, during times when the oil or natural gas markets weaken, our customers are more likely to experience financial difficulties, including being unable to access debt or equity financing, which could result in a reduction in our customers’ spending for our products and services.
We are dependent on customers in a single industry. The loss of one or more significant customers could adversely affect our financial condition, prospects, and results of operations.
Our customers are engaged in the oil and natural gas E&P business, which has been historically volatile. For the year ended December 31, 2020, our five largest customers collectively accounted for approximately 37% of total revenues. If we were to lose several key alliances over a relatively short period of time or if one of our largest customers fails to pay or delays in paying a significant amount of our outstanding receivables, we could experience an adverse impact on our business, financial condition, results of operations, cash flows, and prospects. Additionally, the E&P industry is characterized by frequent consolidation activity. Changes in ownership of our customers may result in the loss of, or reduction in, business from those customers, which could materially and adversely affect our business, financial condition, results of operations, and prospects.
Certain of our product lines are subject to the risk of supplier concentration, and certain of our product lines are subject to exclusive distribution arrangements, which we may not be able to maintain.
Certain of the product lines depend on a limited number of third-party suppliers and vendors. As a result of this concentration in some supply chains, our business and operations could be negatively affected if certain key suppliers were to experience significant disruptions affecting the price, quality, availability, or timely delivery of their products. The partial or complete loss of any one of those key suppliers, or a significant adverse change in the relationship with any such suppliers, through consolidation or otherwise, may limit our ability to manufacture and sell certain of our product lines.
In addition, we have arrangements with certain technology companies and manufacturers that give us exclusive distribution rights to certain product offerings. In some cases, we are, or may in the future will be, required to meet certain minimum volume or other requirements in order to retain our arrangement. If any of these companies or manufacturers terminate our right to sell some or all of their products, modify or terminate our exclusive distribution arrangement, or change the applicable terms and conditions of sale, our business and results of operations could be adversely affected.
Regulatory, Compliance, and Legal Risks
Oilfield anti-indemnity provisions enacted by many states may restrict or prohibit a party’s indemnification of us.
We typically enter into agreements with our customers governing the provision of our services, which usually include certain indemnification provisions for losses resulting from operations. Such agreements may require each party to indemnify the other against certain claims regardless of the negligence or other fault of the indemnified party; however, many states place limitations on contractual indemnity agreements, particularly agreements that indemnify a party against the consequences of its own negligence. Furthermore, certain states, including Louisiana, New Mexico, Texas, and Wyoming, have enacted statutes generally referred to as “oilfield anti-indemnity acts” expressly prohibiting certain indemnity agreements contained in or related to oilfield services agreements. Such oilfield anti-indemnity acts may restrict or void a party’s indemnification of us, which
could have a material adverse effect on our business, financial condition, prospects, and results of operations.
We may be subject to claims for personal injury and property damage or other litigation, which could materially adversely affect our financial condition, prospects, and results of operations.
Our services are subject to inherent risks that can cause personal injury or loss of life, damage to or destruction of property, equipment, or the environment, or the suspension of our operations. As the wells we service continue to become more complex, our exposure to such inherent risks becomes greater as downhole risks increase exponentially with an increase in complexity and lateral length. Our operations are also exposed to risks of labor organizing and risks of claims for alleged employment-related liabilities, including risks of claims related to alleged wrongful termination or discrimination, wage payment practices, retaliation claims, and other human resource related matters. Litigation arising from operations where our facilities are located, or our services are provided, may cause us to be named as a defendant in lawsuits asserting potentially large claims, including claims for exemplary damages. For example, transportation of heavy equipment creates the potential for our trucks to become involved in roadway accidents, which in turn could result in personal injury or property damages lawsuits being filed against us.
We maintain what we believe is customary and reasonable insurance to protect our business against most potential losses, but such insurance may not be adequate to cover our liabilities, especially as the inherent risks in our operations increase with increasing well complexity, and we are not fully insured against all risks, including alleged employment-related liabilities. Further, our insurance has deductibles or self-insured retentions and contains certain coverage exclusions. The current trend in the insurance industry is towards larger deductibles and self-insured retentions. In addition, insurance may not be available in the future at rates that we consider reasonable and commercially justifiable, compelling us to have larger deductibles or self-insured retentions to effectively manage expenses. As a result, we could become subject to material uninsured liabilities or situations where we have high deductibles or self-insured retentions that expose us to liabilities that could have a material adverse effect on our business, financial condition, prospects, or results of operations.
In recent years, oilfield services companies have been the subject of a significant volume of wage and hour-related litigation, including claims brought under the Fair Labor Standards Act (“FLSA”), in which employee pay practices have been challenged. We have been named as defendants in these lawsuits, and we do not maintain insurance for alleged wage and hour-related litigation. Some of these cases remain outstanding and are in various states of negotiation and/or litigation, and the results or costs of any such cases may have an adverse effect on our business, operating results, and financial condition. The frequency and significance of wage- or other employment-related claims may affect expenses, costs, and relationships with employees and regulators. Additionally, we could become subject to material uninsured liabilities that could have a material adverse effect on our business, financial condition, prospects, or results of operations.
Delays or restrictions in obtaining, or inability to obtain or renew, permits or authorizations by our customers for their operations or by us for our operations could impair our business.
In most states, our operations and the operations of our customers require permits or authorizations from one or more governmental agencies or other third parties to perform drilling and completion and production activities, including hydraulic fracturing. Such permits or approvals are typically required by state agencies, but federal and local governmental permits may also be required. We are also required to obtain federal, state, local, and/or third-party permits and authorizations in some jurisdictions in connection with our wireline services and trucking operations. The requirements for permits or authorizations vary depending on the location where the associated activities will be conducted. As with most permitting and authorization processes, there is a degree of uncertainty as to whether a permit will be granted, the time it will take for a permit or approval to be issued, and the conditions which may be imposed in connection with the granting of the permit. In Texas, rural water districts have begun to impose restrictions on water use and may require permits for water used in drilling and completion activities. In addition, some of our customers’ drilling and completion activities may take place on federal land or Native American lands, requiring leases and other approvals from the federal government or Native American tribes to conduct such drilling and completion activities. Permitting, authorization, or renewal delays, the inability to obtain new permits, or the revocation of current permits could cause a loss of revenue and potentially have a materially adverse effect on our business, financial condition, prospects, or results of operations.
We are subject to federal, state, and local laws and regulations regarding issues of health, safety, and protection of the environment. Under these laws and regulations, we may become liable for penalties, damages, or costs of remediation or other corrective measures. Any changes in laws or government regulations could increase our costs of doing business.
Our operations are subject to stringent federal, state, local, and tribal laws and regulations relating to, among other things, protection of natural resources, clean air and drinking water, wetlands, endangered species, greenhouse gases, air pollution, the environment, occupational health and safety, chemical use and storage, waste management, waste disposal, and
transportation of waste and other hazardous and nonhazardous materials. Our operations involve risks of environmental liability, including leakage from an operator’s casing during our operations or accidental spills of hazardous materials onto or into surface or subsurface soils, surface water, or groundwater. Some environmental laws and regulations may impose strict liability, joint and several liability, or both. In some situations, we could be exposed to liability as a result of our conduct that was lawful at the time it occurred or the conduct of, or conditions caused by, third parties without regard to whether we caused or contributed to the conditions. Additionally, environmental concerns, including clean air, drinking water contamination, and seismic activity, have prompted investigations that could lead to the enactment of regulations, limitations, restrictions, or moratoria that could potentially have a material adverse impact on our business. Actions arising under these laws and regulations could result in the shutdown of our operations, fines and penalties (administrative, civil, or criminal), revocations of permits to conduct business, expenditures for remediation or other corrective measures, and/or claims for liability for property damage, exposure to hazardous materials, exposure to hazardous waste, nuisance, or personal injuries. Sanctions for noncompliance with applicable environmental laws and regulations may also include the assessment of administrative, civil, or criminal penalties, revocation of permits and temporary or permanent cessation of operations in a particular location, and issuance of corrective action orders. Such claims or sanctions and related costs could cause us to incur substantial costs or losses and could have a material adverse effect on our business, financial condition, prospects, and results of operations. Additionally, an increase in regulatory requirements or limitations, restrictions, or moratoria on oil and natural gas exploration and completion activities at a federal, state, or local level could significantly delay or interrupt our operations, limit the amount of work we can perform, increase our costs of compliance, or increase the cost of our services, thereby possibly having a material adverse impact on our financial condition.
If we do not perform our operations in accordance with government, industry, customer, or our own stringent occupational safety, health, and environmental standards, we could lose business from our customers, many of whom have an increased focus on environmental and safety issues.
We are subject to the oversight of the EPA, the U.S. Department of Transportation (the “DOT”), U.S. Nuclear Regulation Commission, Bureau of Alcohol, Tobacco, Firearms and Explosives, OSHA, and state regulatory agencies that regulate operations to prevent air, soil, and water pollution. The energy extraction sector is one of the sectors designated for increased enforcement by the EPA, which will continue to regulate our industry in the years to come, potentially resulting in additional regulations that could have a material adverse impact on our business, prospects, or financial condition.
The EPA regulates air emissions from all engines, including off-road diesel engines that are used by us to power equipment in the field under the CAA Tier 4 emission standards (the “Tier 4” standards). The Tier 4 standards require substantial reductions in emissions of particulate matter and nitrous oxide from off-road diesel engines. Such emission reductions can be achieved through the use of appropriate control technologies. Under these U.S. emission control regulations, we could be limited in the number of certain off-road diesel engines we can purchase if we are unable to find a sufficient number of Tier 4-compliant engines from manufacturers. Further, these emission control regulations could result in increased capital and operating costs.
Changes in environmental laws and regulations could lead to material increases in our costs, and liability exposure, for future environmental compliance and remediation. Additionally, if we expand the size or scope of our operations, we could be subject to regulatory requirements that are more stringent than the requirements under which we are currently allowed to operate or require additional authorizations to continue operations. Compliance with this additional regulatory burden could increase our operating or other costs.
Federal, state, and local legislative and regulatory initiatives relating to hydraulic fracturing could prohibit, restrict, or limit hydraulic fracturing operations, or increase our operating costs.
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 and published permitting guidance in February 2014 addressing the performance of such activities using diesel fuels.
There is considerable uncertainty surrounding regulation of methane emissions. In 2016, the EPA issued final regulations under the CAA establishing performance standards, including standards for the capture of methane emissions released during hydraulic fracturing. However, the EPA has taken several steps to delay implementation of its methane standards, including most recently in September 2020, when the EPA finalized the Reconsideration Rule that rolls back parts of
the 2016 performance standards. Various industry and environmental groups have separately challenged both the original standards and the EPA’s attempts to delay implementation of the rule. Separately, in September 2020, the EPA finalized the Review Rule, rescinding requirements related to the regulation of methane emissions from the oil and natural gas industry. Both rules are subject to ongoing litigation, and on January 20, 2021, President Biden issued an Executive Order directing the EPA to rescind the Reconsideration Rule by September 2021 and consider revising the Review Rule. Therefore, future obligations continue to remain uncertain. In addition, in April 2018, a coalition of states filed a lawsuit in the U.S. District Court for the District of Columbia aiming to force the EPA to establish guidelines for limiting methane emissions from existing sources in the oil and natural gas sector; that lawsuit is pending. On March 20, 2015, the BLM finalized a rule regulating hydraulic fracturing activities on federal lands, including requirements for disclosure, wellbore integrity, and handling of flowback water; however, on December 29, 2017, the BLM issued a rescission of the hydraulic fracturing rule. This rescission and the rule as promulgated are subject to ongoing litigation. The BLM also previously finalized in 2016 similar limitations on methane emissions from venting and flaring and leaking equipment from oil and natural gas activities on public lands, but in September 2018 issued a final rule repealing certain provisions of the 2016 rule and reinstating the pre-2016 regulations. The 2016 rule and the rescission were invalidated by separate federal district courts. As a result, future implementation of methane rules by either the EPA or the BLM is uncertain at this time. However, given the long-term trend towards increasing regulation, future federal regulation of methane and other greenhouse gas emissions from the oil and gas industry remains a possibility.
The EPA has also issued effluent limitation guidelines that prohibit the discharge of wastewater from hydraulic fracturing operations to publicly owned wastewater treatment plants. These rules were finalized in June 2016, and after a legal challenge by environmental groups, in July 2019, the EPA declined to revise the rules. The EPA is currently conducting a study on effluent guidelines for the oil and gas extraction industry, and a draft of this study was published in May 2019. 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 products and services.
Various studies analyzing the potential environmental impacts of hydraulic fracturing have also been performed. For example, in December 2016, the EPA released its final 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. As described elsewhere in this Annual Report, these risks are regulated under various state, federal, and local laws.
Some states, counties, and municipalities have enacted or are considering moratoria on hydraulic fracturing. For example, New York, Vermont, Maryland, and Washington have banned, or are in the process of banning, the use of high-volume hydraulic fracturing. 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, and also to 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.
Existing or future laws and regulations related to greenhouse gases and climate change could have a negative impact on our business and may result in additional compliance obligations with respect to the release, capture, and use of greenhouse gases that could have a material adverse effect on our business, results of operations, prospects, and financial condition.
Changes in environmental requirements related to greenhouse gas emissions and climate change may negatively impact demand for our products and services. For example, oil and natural gas E&P may decline as a result of environmental requirements, including land use policies responsive to environmental concerns (e.g., numerous cities, including San Francisco, CA, have banned the use of natural gas in new construction starting in 2020, and other cities, including Seattle, WA, are considering similar initiatives). Federal, state, and local agencies have been evaluating climate-related legislation and other regulatory initiatives that would restrict emissions of greenhouse gases in areas in which we conduct business. Because our business depends on the level of activity in the oil and natural gas industry, existing or future laws and regulations related to
greenhouse gases and climate change, including incentives to conserve energy or use alternative energy sources, could have a negative impact on our business if such laws or regulations reduce demand for oil and natural gas. Likewise, such restrictions may result in additional compliance obligations with respect to the release, capture, sequestration, and use of greenhouse gases that could have a material adverse effect on our business, results of operations, prospects, and financial condition. Finally, most scientists have concluded that increasing concentrations of greenhouse gases in the Earth’s atmosphere may produce climate changes that could have significant physical effects, such as increased frequency and severity of storms, droughts, floods, and other climatic events; if such effects were to occur, they could have an adverse impact on our operations.
Studies by either state or federal agencies demonstrating a correlation between earthquakes and oil and natural gas activities could result in increased regulatory and operational burdens.
In light of concerns about seismic activity being triggered by the injection of produced waters into underground wells, certain regulators are also considering 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 operation, which in turn could decrease demand for our products and services and have a material adverse effect on our business.
We are subject to complex U.S. and foreign laws and regulations governing anti-corruption and export controls and economic sanctions.
The U.S. Foreign Corrupt Practices Act (the “FCPA”), the U.K. Bribery Act (“UKBA”), Canada’s Corruption of Foreign Public Officials Act (the “CFPOA”), and similar anti-bribery and anticorruption laws generally prohibit companies and their intermediaries from making improper payments or improperly providing anything of value for the purpose of obtaining or retaining business. We operate and make sales in parts of the world that may be viewed as higher risk for corruption or may have experienced some corruption in the past, and in some instances, strict compliance with the FCPA, UKBA, CFPOA, and similar anti-bribery laws may conflict with local practices. We are also subject to export control and economic sanctions laws and regulations, including those implemented by the U.S. Office of Foreign Assets Control, the U.S. Department of State, the U.S. Department of Commerce, the European Union and its member states, Her Majesty’s Treasury of the United Kingdom, and other relevant sanctions authorities. These measures can prohibit or restrict transactions and dealings with certain designated persons and in certain countries in which we conduct business. Despite efforts to ensure compliance, there can be no assurance that our directors, officers, employees, agents, and third-party intermediaries will comply with such laws and regulations. We can be held liable for violations under such laws and regulations either due to our acts or omissions or due to the acts or omissions of others, including intermediaries working on our behalf.
If we fail to comply with applicable laws and regulations, including those referred to above, we may be subject to criminal and civil penalties or other sanctions, which could harm our reputation and have a material adverse impact on our business, financial condition, results of operations, and prospects. Any investigation of any actual or alleged violations of such laws could also harm our reputation or have an adverse impact on our business, financial condition, results of operations, and prospects. Additionally, we could face other third-party claims by agents, stockholders, debt holders, or other interest holders or constituents of our company. Our customers in relevant jurisdictions could seek to impose penalties or take other actions adverse to our interests, and we may be required to dedicate significant time and resources to investigate and resolve allegations of misconduct, regardless of the merit of such allegations. Furthermore, compliance with this additional regulatory burden could increase our operating or other costs.
Changes in transportation regulations may increase our costs and negatively impact our results of operations.
We are subject to various transportation regulations including as a motor carrier by the DOT and by various federal, state, and tribal agencies, whose regulations include certain permit requirements of highway and safety authorities. These regulatory authorities exercise broad powers over our trucking operations, generally governing such matters as the authorization to engage in motor carrier operations, safety, equipment testing, driver requirements and specifications, and insurance requirements. Certain motor vehicle operators are required to register with the DOT. This registration requires an acceptable operating record. The DOT periodically conducts compliance reviews and may revoke registration privileges based on certain safety performance criteria, and a revocation could result in a suspension of operations. Since 2010, the DOT has pursued its Compliance, Safety, Accountability (“CSA”) program in an effort to improve commercial truck and bus safety. A component of CSA is the Safety Measurement System (“SMS”), which analyzes all safety violations recorded by federal and state law enforcement personnel to determine a carrier’s safety performance. The SMS is intended to allow the DOT to identify carriers with safety issues and intervene to address those problems.
The trucking industry is subject to possible regulatory and legislative changes that may impact our operations, such as
changes in fuel emissions limits, hours of service regulations that govern the amount of time a driver may drive or work in any specific period, and limits on vehicle weight and size. For example, in December 2016, the DOT finalized minimum training standards for new drivers seeking a commercial driver’s license, and effective December 2017, the FMCSA has mandated electronic logging devices in all interstate commercial trucks. As the federal government continues to develop and propose regulations relating to fuel quality, engine efficiency, and greenhouse gas emissions, we may experience an increase in costs related to truck purchases and maintenance, impairment of equipment productivity, a decrease in the residual value of vehicles, unpredictable fluctuations in fuel prices, and an increase in operating expenses. Increased truck traffic may contribute to deteriorating road conditions in some areas where our operations are performed. Our operations, including routing and weight restrictions, could be affected by road construction, road repairs, detours, and state and local regulations and ordinances restricting access to certain roads. Proposals to increase federal, state, or local taxes, including taxes on motor fuels, are also made from time to time, and any such increase would increase our operating costs. Also, state and local regulation of permitted routes and times on specific roadways could adversely affect our operations. We cannot predict whether, or in what form, any legislative or regulatory changes or municipal ordinances applicable to our logistics operations will be enacted and to what extent any such legislation or regulations could increase our costs or otherwise adversely affect our business or operations.
Risks Related to Technology
Our success may be affected by the use and protection of our proprietary technology as well as our ability to enter into license agreements. There are limitations to our intellectual property rights and, thus, our right to exclude others from the use of our proprietary technology.
Our success may be affected by our development and implementation of new product designs and improvements and by our ability to protect, obtain, and maintain intellectual property assets related to these developments. We rely on a combination of patents and trade secret laws to establish and protect this proprietary technology. We have received patents and have filed patent applications with respect to certain aspects of our technology, and we generally rely on patent protection with respect to our proprietary technology, as well as a combination of trade secrets and copyright law, employee and third-party non-disclosure agreements, and other protective measures to protect intellectual property rights pertaining to our products and technologies. In addition, we are a party to and rely on several arrangements with third parties, which give us exclusive distribution rights to certain product offerings with desirable intellectual property assets, and we may enter into similar arrangements in the future. Such measures may not provide meaningful protection of our trade secrets, know-how, or other intellectual property in the event of any unauthorized use, misappropriation, or disclosure. We cannot assure you that competitors will not infringe upon, misappropriate, violate, or challenge our intellectual property rights in the future. Additionally, we cannot assure you that our intellectual property rights will deter or prevent competitors from creating similar purpose products for our customers. If we are not able to adequately protect or enforce our intellectual property rights, such intellectual property rights may not provide significant value to our business, results of operations, or financial condition.
Moreover, our rights in our confidential information, trade secrets, and confidential know-how will not prevent third parties from independently developing similar technologies or duplicating such technologies. Publicly available information (e.g., information in issued patents, published patent applications, and scientific literature) can be used by third parties to independently develop technology, and we cannot provide assurance that this independently-developed technology will not be equivalent or superior to our proprietary technology. In addition, while we have patented some of our key technologies, we do not patent all of our proprietary technology, even when regarded as patentable. The process of seeking patent protection can be long and expensive. There can be no assurance that patents will be issued from currently pending or future applications or that, if patents are issued, they will be of sufficient scope or strength to provide meaningful protection or any commercial advantage to us. Further, with respect to exclusive third-party arrangements, these arrangements could be terminated, which would result in our inability to provide the services and/or products covered by such arrangements.
We may be adversely affected by disputes regarding intellectual property rights, and the value of our intellectual property rights is uncertain.
We may become involved in dispute resolution proceedings from time to time to protect and enforce our intellectual property rights. In these dispute resolution proceedings, a defendant may assert that our intellectual property rights are invalid or unenforceable. Third parties from time to time may also initiate dispute resolution proceedings against us by asserting that our businesses infringe, impair, misappropriate, dilute, or otherwise violate another party’s intellectual property rights. We may not prevail in any such dispute resolution proceedings, and our intellectual property rights may be found invalid or unenforceable or our products and services may be found to infringe, impair, misappropriate, dilute, or otherwise violate the intellectual property rights of others. Also, as a part of resolving such disputes, we may enter into cross-licenses, which could reduce the value of our existing intellectual property rights. The results or costs of any such dispute resolution proceedings may have an adverse effect on our business, operating results, and financial condition. Any dispute resolution proceeding concerning intellectual property could be protracted and costly, is inherently unpredictable, and could have an adverse effect on our
business, regardless of its outcome.
Our success may be affected by our ability to implement new technologies and services. Additionally, we rely on a limited number of manufacturers to produce the proprietary products used in the provision of our services, which exposes us to risks.
Our success may be affected by the ongoing development and implementation of new product designs, methods, and improvements, and our ability to protect, obtain, and maintain intellectual property assets related to these developments. If we are not able to obtain patent or other protection of our technology, it may not be economical for us to continue to develop systems, services, and technologies to meet evolving industry requirements at prices acceptable to our customers. Further, we may face competitive pressure to develop, implement, or acquire certain new technologies at a substantial cost. Although we take measures to ensure that we use advanced technologies, changes in technology or improvements in our competitors’ equipment could make our equipment less competitive or require significant capital investments to keep our equipment competitive.
We currently rely on a limited number of manufacturers for production of the proprietary products used in the provision of our products and services. Termination of the manufacturing relationship with any of these manufacturers could affect our ability to provide such products and services to our customers. Although we believe other alternate sources of supply for our proprietary products exist, we would need to establish relationships with new manufacturers, which could potentially involve significant expense, delay, and potential changes to certain product components. Any protracted curtailment or interruptions of the supply of any of our key products, whether or not as a result of termination of our manufacturing relationships or patent infringement claims, could have a material adverse effect on our financial condition, business, and results of operations.
Some of our competitors are large national and multinational companies that may be able to devote greater financial, technical, manufacturing, and marketing resources to research and development of new systems, services, and technologies and may have a larger number of manufacturers for their products or ability to manufacture their own products. As competitors and others use or develop new or comparable technologies in the future, we may lose market share or be placed at a competitive disadvantage if we are not able to develop and implement new technologies or products on a timely basis or at an acceptable cost. If we are unable to compete effectively given these risks, our business and results of operations could be affected.
Our operations are subject to cyber security risks that could have a material adverse effect on our results of operations and financial condition.
The efficient operation of our business is dependent on our information technology (“IT”) systems. Accordingly, we rely upon the capacity, reliability, and security of our IT hardware and software infrastructure and our ability to expand and update this infrastructure in response to our changing needs. Our IT systems are subject to possible breaches and other threats that could cause us harm. If our systems for protecting against cyber security risks prove not to be sufficient, we could be adversely affected by, among other things, loss or damage of intellectual property, proprietary information, customer or business data; interruption of business operations; or additional costs to prevent, respond to, or mitigate cyber security attacks. These risks could have a material adverse effect on our business, financial condition, and results of operations and could lead to litigation or regulatory action against us.
Risks Related to Certain Significant Stockholders
Significant ownership of our common stock by certain stockholders could adversely affect our other stockholders.
SCF VII, L.P. and SCF-VII(A), L.P. (collectively, “SCF”) owned approximately 29% of our outstanding common stock as of December 31, 2020. In addition, certain of our directors are currently employed by SCF. Consequently, SCF is able to strongly influence all matters that require approval by our stockholders, including the election and removal of directors, changes to our organizational documents, and approval of acquisition offers and other significant corporate transactions. In addition, another one of our stockholders beneficially owned approximately 16% of our outstanding common stock as of December 31, 2020. This concentration of ownership by a small group of stockholders will limit other stockholders’ ability to influence corporate matters, and as a result, actions may be taken that other stockholders may not view as beneficial. For example, this concentration of ownership could have the effect of delaying or preventing a change in control or otherwise discouraging a potential acquirer from attempting to obtain control of us, which in turn could cause the market price of our common stock to decline or prevent our stockholders from realizing a premium over the market price for their shares of our common stock. This concentration of stock ownership may also adversely affect the trading price of our common stock to the extent investors perceive a disadvantage in owning stock of a company with significant stockholders.
A significant reduction by SCF of its ownership interests in us could adversely affect us.
We believe that SCF’s substantial ownership interest in us provides them with an economic incentive to assist us to be successful. SCF is not subject to any obligation to maintain its ownership interest in us and may elect at any time to sell all or a substantial portion of or otherwise reduce its ownership interest in us. If SCF sells all or a substantial portion of its ownership interest in us, it may have less incentive to assist in our success and its affiliates that serve as members of our board of directors may resign. Such actions could adversely affect our ability to successfully implement our business strategies, which could adversely affect our cash flows or results of operations.
Certain of our directors may have conflicts of interest because they are also directors or officers of SCF. The resolution of these conflicts of interest may not be in our or other stockholders’ best interests.
Certain of our directors, namely David C. Baldwin and Andrew L. Waite, are currently officers of SCF’s ultimate general partner. Mr. Baldwin and Mr. Waite are also both directors of Forum Energy Technologies, a corporation in which SCF and its affiliates own an approximate 15% equity interest as of December 31, 2020. In addition, Mr. Waite is a director of National Energy Reunited Corp., a corporation in which SCF owns an approximate 9% equity interest as of December 31, 2020. These positions may conflict with such individuals’ duties as one of our directors regarding business dealings and other matters between SCF and us. The resolution of these conflicts may not always be in our or our other stockholders’ best interest.
SCF and its affiliates are not limited in their ability to compete with us, and the corporate opportunity provisions in our charter could enable SCF to benefit from corporate opportunities that may otherwise be available to us.
SCF and its affiliates have investments in other oilfield service companies that may compete with us, and SCF and its affiliates may invest in such other companies in the future. SCF, its other affiliates, and its other portfolio companies are referred to herein as the “SCF Group.” Conflicts of interest could arise in the future between us, on the one hand, and the SCF Group, on the other hand, concerning among other things, potential competitive business activities or business opportunities.
Our charter provides that, to the fullest extent permitted by applicable law, we renounce any interest or expectancy in any business opportunity that involves any aspect of the energy equipment or services business or industry and that may be from time to time presented to SCF or any of our directors or officers who is also an employee, partner, member, manager, officer, or director of any SCF Group entity, even if the opportunity is one that we might reasonably have pursued or had the ability or desire to pursue if granted the opportunity to do so. Our charter further provides that no such person or party shall be liable to us by reason of the fact that such person pursues any such business opportunity or fails to offer any such business opportunity to us. As a result, any of our directors or officers who is also an employee, partner, member, manager, officer, or director of any SCF Group entity may become aware, from time to time, of certain business opportunities, such as acquisition opportunities, and may direct such opportunities to other businesses in which they have invested, in which case we may not become aware of or otherwise have the ability to pursue such opportunity. Further, such businesses may choose to compete with us for these opportunities. As a result, by renouncing our interest and expectancy in any business opportunity that may be from time to time presented to any member of an SCF Group entity or any of our directors or officers who is also an employee, partner, member, manager, officer, or director of any SCF Group entity, our business or prospects could be adversely affected if attractive business opportunities are procured by such parties for their own benefit rather than for ours. Our charter provides that any amendment to or adoption of any provision inconsistent with our charter’s provisions governing the renouncement of business opportunities must be approved by the holders of at least 80% of the voting power of the outstanding stock of the corporation entitled to vote thereon. Any actual or perceived conflicts of interest with respect to the foregoing could have an adverse impact on the trading price of our common stock.
Risks Related to Human Capital
Our executive officers and certain key personnel are critical to our business, and these officers and key personnel may not remain with us in the future.
Our future success depends in substantial part on our ability to hire and retain our executive officers and other key personnel. In particular, we are highly dependent on certain of our executive officers, particularly our President and Chief Executive Officer, Ann G. Fox, and the Chief Operating Officer, David Crombie. These individuals possess extensive expertise, talent, and leadership, and they are critical to our success. The diminution or loss of the services of these individuals, or other integral key personnel affiliated with entities that we acquire in the future, could have a material adverse effect on our business. Furthermore, we may not be able to enforce all of the provisions in any employment agreement we have entered into with certain of our executive officers, and such employment agreements may not otherwise be effective in retaining such individuals. In addition, we may not be able to retain key employees of entities that we acquire in the future, which may impact our ability to successfully integrate or operate the assets we acquire.
We may be unable to employ, or maintain the employment of, a sufficient number of key employees, technical personnel, and other skilled and qualified workers.
The delivery of our services and products requires personnel with specialized skills and experience, including personnel who can perform physically demanding work, and our success depends, in large part, upon our ability to employ and retain key employees, technical personnel, and other skilled and qualified workers. To attract and retain qualified employees, we must compensate them at market levels. Recent cost-cutting measures across the organization include decreases in cash and equity compensation for our employees, which may adversely affect our ability to attract and retain qualified employees. If we are unable to continue to attract and retain qualified employees, or do so at rates necessary to maintain our liquidity and competitive position, our business, financial condition or results of operations could suffer. Workers may choose to pursue employment with our competitors or in fields that offer a more desirable work environment as a result of the volatility in the oilfield service industry and the demanding nature of our work. The right-sizing of our and our competitors’ labor force, as well as a significant decrease in the wages paid by us or our competitors as a result of reduced industry demand, has resulted in a reduction of the available skilled labor force to service the energy industry. To the extent that there is an increase in demand for our products or services, there is no assurance that the availability of skilled labor will improve. If we are unable to employ and retain skilled workers, our capacity and profitability could be diminished, and our growth potential could be impaired.
Other Material Risks
We do not intend to pay dividends on our common stock, and our debt agreements place certain restrictions on our ability to do so. Consequently, a stockholder’s only opportunity to achieve a return on his investment is if the price of our common stock appreciates.
We do not plan to declare dividends on shares of our common stock in the foreseeable future. Additionally, our debt agreements place certain restrictions on our ability to pay cash dividends. Consequently, unless we revise our dividend policy, a stockholder’s only opportunity to achieve a return on his investment in us will be by selling his common stock at a price greater than the stockholder paid for it. There is no guarantee that the price of our common stock that will prevail in the market will ever exceed the price at which a stockholder purchased his shares of our common stock.
We have operated at a loss in the past, and there is no assurance of our profitability in the future.
Historically, we have experienced periods of low demand for our products and services and have incurred operating losses. In the future, we may not be able to reduce our costs, increase our revenues, or reduce our debt service obligations sufficiently to achieve or maintain profitability and generate positive operating income. Under such circumstances, we may incur further operating losses and experience negative operating cash flow.
Our future financial condition and results of operations could be adversely impacted by long-lived assets or other asset impairment charges.
Determining whether an impairment exists and the amount of the potential impairment involves quantitative data and qualitative criteria that are based on estimates and assumptions requiring significant management judgment, such as those relating to revenue growth rates, future cash flows, and future market conditions. Future events or new information, including regarding the general economic environment, E&P activity levels, our financial performance and trends, and our strategies and business plans, may change management’s valuation of long-lived assets, other intangible assets, or other assets in a short amount of time. In particular, prolonged periods of decreased demand, low utilization, changes in technology or market conditions, or sales and other dispositions of assets for amounts less than their carrying value may cause us to recognize impairment charges relating to our long-lived assets, other intangible assets, or other assets that reduce our net income.
In 2020, we recorded goodwill impairment charges of $296.2 million in our tools, cementing, and wireline reporting units within our Completions Solutions segment due to sharp declines in global crude oil demand, an economic recession associated with the coronavirus pandemic, sharp declines in oil and natural gas prices, and an increased weighted average cost of capital driven by a reduction in our stock price and the Level 2 fair value of our Senior Notes.
In 2019, we recorded a goodwill impairment charge of $20.3 million and an intangible asset impairment charge of $12.7 million associated with indefinite-lived trade names in our coiled tubing reporting unit within our Completion Solutions segment as well as an intangible asset impairment charge of $7.1 million associated with definite-lived customer relationship intangible assets and a property and equipment impairment charge of $66.2 million in our coiled tubing asset group within our Completion Solutions segment. These impairment charges were due to a reduction of the need for coiled tubing during the drill-out phase of the overall completions process due to a decline in exploration and production capital budgets and activity, an over-supply of new coiled tubing units, and the introduction of dissolvable plug technology.
Additionally, in 2019, we recorded an intangible asset impairment charge of $95.0 million associated with indefinite-lived trade names in our completion tools reporting unit within our Completion Solutions segment and due to the transitioning of certain trade names from our 2018 acquisitions to our trade names in order to better funnel and allocate resources, create a stronger identity, facilitate cross-selling, and streamline and simplify communication with existing customers.
While we believe our estimates and assumptions used in impairment tests are reasonable, we cannot provide assurance that additional impairment charges in the future will not be required, especially if an economic downturn occurs and continues for a lengthy period or becomes severe or if our acquisitions and investments fail to achieve expected returns. Significant impairment charges as a result of a decline in market conditions or otherwise could have a material adverse effect on our financial condition or results of operations in future periods.
Seasonal and adverse weather conditions adversely affect demand for our products and services.
Weather can have a significant impact on demand for our services and products as consumption of energy is seasonal, and any variation from normal weather patterns or cooler or warmer summers and winters can have a significant impact on demand. In addition, adverse weather conditions, such as hurricanes, tropical storms, and severe cold weather, may interrupt or curtail our operations or our customers’ operations, cause supply disruptions, and damage our equipment and facilities, which may or may not be insured. In addition, most scientists have concluded that increasing concentrations of greenhouse gases in the Earth’s atmosphere may produce climate changes that could have significant physical effects, such as increased frequency and severity of storms, droughts, floods, and other climatic events. 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., Michigan, North Dakota, Wyoming, 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. For the years ended December 31, 2020 and 2019, we generated approximately 0.5% and 2.2%, respectively, of our revenue from our operations in western Canada. Lastly, throughout the year heavy rains adversely affect activity levels because well locations and dirt access roads can become impassible in wet conditions.
In addition, 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.
A terrorist attack or armed conflict could harm our business.
The occurrence or threat of terrorist attacks in the U.S. or other countries, anti-terrorist efforts, and other armed conflicts involving the U.S. or other countries, including continued hostilities in the Middle East, may adversely affect the U.S. and global economies and could prevent us from meeting financial and other obligations. We could experience loss of business, delays or defaults in payments from payors, or disruptions of fuel supplies and markets if wells, operations sites, or other related facilities are direct targets or indirect casualties of an act of terror or war. Such activities could reduce the overall demand for oil and natural gas, which, in turn, could also reduce the demand for our products and services. Oil and natural gas-related facilities could be direct targets of terrorist attacks, and our operations could be adversely impacted if infrastructure integral to our customers’ operations is destroyed or damaged. Costs for insurance and other security may increase as a result of these threats, and some insurance coverage may become more difficult to obtain, if available at all. Terrorist activities and the threat of potential terrorist activities and any resulting economic downturn could adversely affect our results of operations, impair our ability to raise capital, or otherwise adversely impact our ability to realize certain business strategies.
A portion of our revenue is derived from sales to customers outside of the U.S., which exposes us to risks inherent in doing business internationally.
In 2020, we derived 5.0% of our revenue from sales to customers outside of the U.S. Sales to customers in countries other than the U.S. are subject to various risks, including:
•volatility in political, social, and economic conditions;
•social unrest, acts of terrorism, war, or other armed conflicts;
•confiscatory taxation or other adverse tax policies;
•deprivation of contract rights;
•trade and economic sanctions or other restrictions imposed by the European Union, the U.S., or other countries;
•exposure under the FCPA or similar legislation, as discussed in the below risk factor; and
•currency exchange controls.
If we do not meet the continued listing requirements of the New York Stock Exchange (“NYSE”), the NYSE may delist our common stock.
To remain listed on the NYSE, the average closing price of our common stock must not fall below $1.00 per share over a period of 30 consecutive trading days. In April 2020, we received written notification from the NYSE that we did not satisfy this minimum average closing share price condition. In June 2020, we regained compliance with this condition; however, there is no assurance that we will be able to continue to do so. Further, our common stock could be delisted if (i) our average market capitalization over a consecutive 30 trading-day period is less than $15 million, or (ii) our common stock trades at an “abnormally low” price. If our common stock were to be delisted for any reason, it could negatively impact us by, among other things, reducing the liquidity and market price of our common stock, reducing the number of investors willing to hold or acquire our common stock, and negatively impacting our ability to access equity markets and obtain financing.
Our charter and bylaws contain provisions that could delay, discourage, or prevent a takeover attempt even if a takeover might be beneficial to our stockholders, and such provisions may adversely affect the market price of our common stock.
Provisions contained in our charter and bylaws could make it more difficult for a third party to acquire us. Our charter and bylaws also impose various procedural and other requirements, which could make it more difficult for stockholders to effect certain corporate actions. For example, our charter authorizes our board of directors to determine the rights, preferences, privileges, and restrictions of unissued series of preferred stock without any vote or action by our stockholders. Thus, our board of directors can authorize and issue shares of preferred stock with voting or conversion rights that could adversely affect the voting or other rights of holders of our capital stock. These rights may have the effect of delaying or deterring a change of control of our company. Additionally, for example, our bylaws (i) establish limitations on the removal of directors and on the ability of our stockholders to call special meetings, (ii) include advance notice requirements for nominations for election to our board of directors and for proposing matters that can be acted upon at stockholder meetings, (iii) provide that our board of directors is expressly authorized to adopt, or to alter or repeal, our bylaws, and (iv) provide for a classified board of directors, consisting of three classes of approximately equal size, each class serving staggered three-year terms, so that only approximately one-third of our directors will be elected each year. These provisions could limit the price that certain investors might be willing to pay in the future for shares of our common stock.
Our charter and bylaws designate the Court of Chancery of the State of Delaware as the sole and exclusive forum for certain types of actions and proceedings that may be initiated by our stockholders, which could limit our stockholders’ ability to obtain a favorable judicial forum for disputes with us or our directors, officers, employees, or agents.
Our charter and bylaws provide that, unless we consent in writing to the selection of an alternative forum, the Court of Chancery of the State of Delaware will, to the fullest extent permitted by applicable law, be the sole and exclusive forum for (i) any derivative action or proceeding brought on our behalf, (ii) any action asserting a claim of breach of a fiduciary duty owed by any of our directors, officers, employees, or agents to us or our stockholders, (iii) any action asserting a claim arising pursuant to any provision of the Delaware General Corporation Law (the “DGCL”), our charter or our bylaws, or (iv) any action asserting a claim against us that is governed by the internal affairs doctrine, in each such case subject to such Court of Chancery having personal jurisdiction over the indispensable parties named as defendants therein. These exclusive forum provisions are not intended to apply to actions arising under the Exchange Act or the Securities Act of 1933, as amended. The Court of Chancery of the State of Delaware has recently held that a Delaware corporation can only use its constitutive documents to bind a plaintiff to a particular forum where the claim involves rights or relationships that were established by or under the DGCL.
Any person or entity purchasing or otherwise acquiring any interest in shares of our capital stock will be deemed to have notice of, and consented to, the forum selection provisions of our charter and bylaws. These choice of forum provisions may limit a stockholder’s ability to bring a claim in a judicial forum that it finds favorable for disputes with us or our directors, officers, employees, or agents, which may discourage such lawsuits against us and such persons. Alternatively, if a court were to find these provisions of our charter or bylaws inapplicable to, or unenforceable in respect of, one or more of the specified types of actions or proceedings, we may incur additional costs associated with resolving such matters in other jurisdictions, which could adversely affect our business, financial condition, or results of operations.
Taking advantage of the reduced disclosure requirements applicable to “emerging growth companies” may make our common stock less attractive to investors.
We are an “emerging growth company,” as defined in the Jumpstart Our Business Startups Act of 2012 (the “JOBS Act”), and we will remain an emerging growth company until the earliest to occur of (i) the last day of the fiscal year in which we have more than $1.07 billion in annual revenue; (ii) the date on which we become a “large accelerated filer” (the fiscal year-end on which at least $700 million of equity securities are held by non-affiliates as of the last day of our then most recently completed second fiscal quarter); (iii) the date on which we have issued, in any three-year period, more than $1.0 billion in non-convertible debt securities; and (iv) December 31, 2023, which is the last day of the fiscal year ending after the fifth anniversary of the completion of our initial public offering (the “IPO”). An emerging growth company may take advantage of certain reduced reporting and other requirements that are otherwise applicable generally to public companies. Pursuant to these reduced disclosure requirements, emerging growth companies are not required to, among other things, comply with the auditor attestation requirements of Section 404 of the Sarbanes-Oxley Act of 2002, provide certain disclosures regarding executive compensation, hold stockholder advisory votes on executive compensation, or obtain stockholder approval of any golden parachute payments not previously approved. In addition, emerging growth companies have longer phase-in periods for the adoption of new or revised financial accounting standards. Under the JOBS Act, emerging growth companies can delay adopting new or revised accounting standards until such time as those standards apply to private companies.
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. 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.
Our election to use the phase-in periods permitted by this election may make it difficult to compare our financial statements to those of non-emerging growth companies and other emerging growth companies that have opted out of the longer phase-in periods under Section 107 of the JOBS Act and who will comply with new or revised financial accounting standards. We cannot predict if investors will find our common stock less attractive because we will rely on these exemptions. If some investors find our common stock less attractive as a result, there may be a less active trading market for our common stock and our common stock price may be more volatile.
On the other hand, once we are no longer an emerging growth company, compliance with rules and regulations that do not currently apply to us as an emerging growth company will increase our legal and financial compliance costs, may make some activities more difficult, time-consuming, or costly, and will increase demand on our systems and resources.
We previously identified material weaknesses in our internal control over financial reporting. We may identify additional material weaknesses in the future or otherwise fail to maintain an effective system of internal controls, which may result in material misstatements of our financial statements or cause us to fail to meet our reporting obligations.
Effective internal controls are necessary for us to provide reliable financial reports and prevent fraud. A material weakness is defined as a deficiency, or a combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of our annual or interim financial statements will not be prevented or detected on a timely basis. In 2017, we identified material weaknesses in our internal control over financial reporting, and immaterial misstatements were identified as result. We believe that these material weaknesses have been successfully remediated as of December 31, 2020.
Any newly identified material weakness could limit our ability to prevent or detect a misstatement of our accounts or disclosures that could result in a material misstatement of our annual or interim financial statements. In such case, we may be unable to maintain compliance with securities law requirements regarding timely filing of periodic reports in addition to applicable stock exchange listing requirements, we may be unable to prevent fraud, investors may lose confidence in our financial reporting, and our stock price may decline as a result. We cannot assure you that the measures we have taken to date, or any measures we may take in the future, will be sufficient to avoid potential future material weaknesses.
We may not be able to utilize a portion of our net operating loss carry forwards (“NOLs”) to offset future taxable income for U.S. federal or state tax purposes, which could adversely affect our net income and cash flows.
As of December 31, 2020, we had federal and state income tax NOLs of approximately $345.0 million, which will begin to expire between 2023 and 2034. Utilization of these NOLs depends on many factors, including our future taxable income, which cannot be assured. In addition, Section 382 of the Internal Revenue Code of 1986, as amended (“Section 382”), generally imposes an annual limitation on the amount of an NOL that may be used to offset taxable income when a corporation has undergone an “ownership change” (as determined under Section 382).
Determining the limitations under Section 382 is technical and highly complex. An ownership change generally occurs if one or more stockholders (or groups of stockholders) who are each deemed to own at least 5% of the corporation’s stock increase their ownership by more than 50 percentage points over their lowest ownership percentage within a rolling three-year period. In the event that an ownership change has occurred, or were to occur, with respect to a corporation following its recognition of an NOL, utilization of such NOL would be subject to an annual limitation under Section 382, generally determined by multiplying the value of the corporation’s stock at the time of the ownership change by the applicable long-term tax-exempt rate (as defined in Section 382). However, this annual limitation would be increased under certain circumstances by recognized built-in gains of the corporation existing at the time of the ownership change. In the case of an NOL that arose in a taxable year beginning before January 1, 2018, any unused annual limitation with respect to an NOL generally may be carried over to later years, subject to the expiration of such NOL 20 years after it arose.
The issuance of additional stock in the IPO, combined with ownership shifts over the rolling three-year period, resulted in an ownership change under Section 382, and we may be prevented from fully utilizing our NOLs prior to their expiration. Future changes in our stock ownership or future regulatory changes could also limit our ability to utilize our NOLs. To the extent we are not able to offset future taxable income with our NOLs, our net income and cash flows may be adversely affected.

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ITEM 1B. UNRESOLVED STAFF COMMENTS
Item 1B. Unresolved Staff Comments
None.

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ITEM 2. PROPERTIES
Item 2. Properties
The following table describes the material facilities owned or leased by us as of December 31, 2020.
Location Basin/Region Leased or Owned Principal/Most
Significant Use
Houston, TX - Leased Corporate Headquarters/Administrative
Athens, TX - Leased Operations
Baker, MT Bakken Owned Operations/Administrative
Bergen, Norway - Leased Operations
El Reno, OK SCOOP/STACK Leased Operations
Charleroi, PA Marcellus/Utica Leased Operations
Corpus Christi, TX - Leased Operations/Administrative
Dickinson, ND Bakken Leased Operations/Administrative
Enid, OK SCOOP/STACK Leased Operations/Administrative
Fort Worth, TX - Leased Administrative
Hobbs, NM Permian Leased Operations
Jacksboro, TX Barnett Leased Operations
Kilgore, TX Haynesville Leased Operations
Longview, TX Haynesville Owned Operations
Marietta, OH Marcellus/Utica Leased Operations/Administrative
Mead, CO Rockies Leased Operations
Midland, TX Permian Leased Operations
Midland, TX Permian Owned Operations/Administrative
Midland, TX Permian Leased Operations/Administrative
Midland, TX Permian Leased Operations
Monahans, TX Permian Leased Operations/Administrative
Oklahoma City, OK SCOOP/STACK Leased Operations
Pleasanton, TX Eagle Ford Leased Operations
Poolville, TX - Owned Operations
Red Deer, AB, Canada WCSB Leased Operations
San Antonio, TX Eagle Ford Leased Operations/Administrative
Sweetwater, TX Permian Leased Operations
Ulster, PA Marcellus/Utica Leased Operations
Tyler, TX Haynesville Leased Operations
Williston, ND Bakken Owned Operations
Williston, ND Bakken Owned Operations/Administrative

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ITEM 3. LEGAL PROCEEDINGS
Item 3. Legal Proceeding
From time to time, we have various claims, lawsuits, and administrative proceedings that are pending or threatened with respect to personal injury, workers’ compensation, contractual matters, and other matters. Although no assurance can be given with respect to the outcome of these claims, lawsuits, or proceedings or the effect such outcomes may have, we believe any ultimate liability resulting from the outcome of such claims, lawsuits, or administrative proceedings, to the extent not otherwise provided for or covered by insurance, will not have a material adverse effect on our business, operating results, or financial condition. For additional information related to legal proceedings, see Note 12 - Commitments and Contingencies included in Item 8 of Part II of this Annual Report.

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ITEM 4. MINE SAFETY DISCLOSURE
Item 4. Mine Safety Disclosures
Not applicable.
PART II

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ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY
Item 5. Market for Registrant’s Common Equity and Related Shareholder Matters and Issuer Purchases of Equity Securities
Market Information
Nine Energy Service, Inc.’s common stock is traded on the NYSE under the symbol “NINE.”
Holders
As of March 4, 2021, we had 48 stockholders of record. The number of record holders does not include persons who held shares of our common stock in nominee or “street name” accounts through brokers.
Dividend Policy
We do not anticipate declaring or paying any cash dividends to holders of our common stock in the foreseeable future. We currently intend to retain future earnings, if any, to fund our operations and to develop and grow our business. Our future dividend policy is within the discretion of our board of directors and will depend upon various factors our board of directors deems relevant, including our results of operations, financial condition, capital requirements, and investment opportunities, as well as any restrictions on our ability to pay cash dividends.
Recent Sales of Unregistered Securities
None.
Purchases of Equity Securities by the Issuer and Affiliated Purchasers
None.

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ITEM 6. SELECTED FINANCIAL DATA
Item 6. Selected Financial Data
As a “smaller reporting company,” as defined under the Exchange Act, we are not required to provide the information required by this Item.

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ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following discussion and analysis of our financial condition and results of operations should be read in conjunction with “Financial Statements and Supplementary Data” in Item 8 of Part II of this Annual Report.
This discussion contains forward-looking statements based on our current expectations, estimates, and projections about our operations and the industry in which we operate. Our actual results may differ materially from those anticipated in these forward-looking statements as a result of a variety of risks and uncertainties, including those described under “Risk Factors” in Item 1A of Part I of this Annual Report. We assume no obligation to update any of these forward-looking statements.
Overview
Company Description
We are a leading North American onshore completion services provider that targets unconventional oil and gas resource development. We partner with our E&P customers across all major onshore basins in both the U.S. and Canada as well as abroad 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 (i) cementing services, which 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, (ii) an innovative portfolio of completion tools, including those that provide pinpoint frac sleeve system technologies as well as a portfolio of completion technologies used for completing the toe stage of a horizontal well and fully-composite, dissolvable, and extended range frac plugs to isolate stages during plug-and-perf operations, (iii) wireline services, the majority of which consist of plug-and-perf completions, which is a multistage well completion technique for cased-hole wells that consists of deploying perforating guns and isolation tools to a specified depth, and (iv) coiled tubing services, which 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 and which provides a cost-effective solution for well work due to the ability to deploy efficiently and safely into a live well.
How We Generate Revenue and the Costs of Conducting Our Business
We generate our revenues by providing completion services to E&P customers across all major onshore basins in both the U.S. and Canada as well as abroad. We primarily earn our revenues pursuant to work orders entered into with our customers on a job-by-job basis. We typically will enter into an MSA with each customer that provides a framework of general terms and conditions of our services that will govern any future transactions or jobs awarded to us. Each specific job is obtained through competitive bidding or as a result of negotiations with customers. The rate we charge is determined by location, complexity of the job, operating conditions, duration of the contract, and market conditions. In addition to MSAs, we have entered into a select number of longer-term contracts with certain customers relating to our wireline and cementing services, and we may enter into similar contracts from time to time to the extent beneficial to the operation of our business. These longer-term contracts address pricing and other details concerning our services, but each job is performed on a standalone basis.
The principal expenses involved in conducting our business include labor costs, materials and freight, the costs of maintaining our equipment, and fuel costs. Our direct labor costs vary with the amount of equipment deployed and the utilization of that equipment. Another key component of labor costs relates to the ongoing training of our field service employees, which improves safety rates and reduces employee attrition.
How We Evaluate Our Operations
We evaluate our performance based on a number of financial and non-financial measures, including the following:
•Revenue: We compare actual revenue achieved each month to the most recent projection for that month and to the annual plan for the month established at the beginning of the year. We monitor our revenue to analyze trends in the performance of our operations compared to historical revenue drivers or market metrics. We are particularly interested in identifying positive or negative trends and investigating to understand the root causes.
•Adjusted Gross Profit (Loss): Adjusted gross profit (loss) is a key metric that we use to evaluate operating performance. We define adjusted gross profit (loss) as revenues less direct and indirect costs of revenues
(excluding depreciation and amortization). Costs of revenues include direct and indirect labor costs, costs of materials, maintenance of equipment, fuel and transportation freight costs, contract services, crew cost, and other miscellaneous expenses. For additional information, see “Non-GAAP Financial Measures” below.
•Adjusted EBITDA: We define Adjusted EBITDA as net income (loss) before interest, taxes, and depreciation and amortization, further adjusted for (i) goodwill, intangible asset, and/or property and equipment impairment charges, (ii) transaction and integration costs related to acquisitions, (iii) loss or gain on revaluation of contingent liabilities, (iv) gain on the extinguishment of debt, (v) loss or gain on the sale of subsidiaries, (vi) restructuring charges, (vii) stock-based compensation expense, (viii) loss or gain on sale of property and equipment, and (ix) other expenses or charges to exclude certain items which we believe are not reflective of ongoing performance of our business, such as legal expenses and settlement costs related to litigation outside the ordinary course of business. For additional information, see “Non-GAAP Financial Measures” below.
•Return on Invested Capital (“ROIC”): We define ROIC as after-tax net operating profit (loss), divided by average total capital. We define after-tax net operating profit (loss) as net income (loss) plus (i) goodwill, intangible asset, and/or property and equipment impairment charges, (ii) transaction and integration costs related to acquisitions, (iii) interest expense (income), (iv) restructuring charges, (v) loss or gain on the sale of subsidiaries, (vi) gain on the extinguishment of debt, and (vii) the provision or benefit for deferred income taxes. We define total capital as book value of equity plus the book value of debt less balance sheet cash and cash equivalents. We compute the average of the current and prior period-end total capital for use in this analysis. For additional information, see “Non-GAAP Financial Measures” below.
•Safety: We measure safety by tracking the total recordable incident rate (“TRIR”), which is reviewed on a monthly basis. TRIR is a measure of the rate of recordable workplace injuries, defined below, normalized and stated on the basis of 100 workers for an annual period. The factor is derived by multiplying the number of recordable injuries in a calendar year by 200,000 (i.e., the total hours for 100 employees working 2,000 hours per year) and dividing this value by the total hours actually worked in the year. A recordable injury includes occupational death, nonfatal occupational illness, and other occupational injuries that involve loss of consciousness, restriction of work or motion, transfer to another job, or medical treatment other than first aid.
Factors Affecting the Comparability of Our Results of Operations
Our future results of operations may not be comparable to our historical results of operations for the periods presented, and our historical results of operations among the periods presented may not be comparable to each other.
Our historical results of operations included in this Annual Report include the impact of the divestiture of the Production Solutions segment on August 30, 2019. Future results of operations will not include activity related to the Production Solutions segment. For additional information on the divestiture of the Production Solutions segment, see Note 16 - Segment Information included in Item 8 of Part II of this Annual Report.
Impact of the Coronavirus Pandemic; Industry Trends and Outlook
Our business depends, to a significant extent, on the level of unconventional resource development activity and corresponding capital spending of oil and natural gas companies. These activity and spending levels are strongly influenced by the current and expected oil and natural gas prices. The worldwide coronavirus outbreak in early 2020, which was declared a pandemic by the World Health Organization in March 2020, the uncertainty regarding its impact, and various governmental actions taken to mitigate its impact resulted in an unprecedented decline in demand for oil. In the midst of the ongoing pandemic, OPEC+ was initially unable to reach an agreement on production levels for crude oil, at which point Saudi Arabia and Russia initiated efforts to aggressively increase production. The convergence of these events created the unprecedented dual impact of a massive decline in the demand for oil coupled with the risk of a substantial increase in supply. While OPEC+ agreed in April 2020 to cut production, downward pressure on commodity prices persisted throughout 2020, and the imbalance between the supply of and demand for oil, as well as the uncertainty around the extent and timing of an economic recovery, caused extreme market volatility and a substantial adverse effect on oil prices. In 2020, the WTI price averaged approximately $39 per barrel as compared to $57 per barrel in 2019.
In response to lower oil prices, our customers have generally revised their capital budgets downward and adjusted their operations accordingly, which has caused a significant decline in demand for our products and services. These reductions were most evident in the Permian Basin where total completions declined approximately 53% in 2020 versus 2019 per the Energy Information Administration (the “EIA”). Additionally, the EIA reported total U.S. completions declined approximately 49%
year over year, and new wells drilled declined approximately 56%. This overall decline in activity, coupled with downward pricing pressure, has led to a significant reduction in our revenue and profitability for 2020.
Thus far in 2021, despite oil prices having improved, demand for our products and services and our near-term prospects remain depressed, and we expect our customer’s capital spend and drilling and completion activity will be down in 2021 versus 2020. Because of sustained lower activity into 2021, we expect pricing will remain depressed for the near-term, offsetting much or possibly all of the anticipated revenue increases. In particular, our cementing and coiled tubing services have experienced improved profitability and pricing; however, we expect such improvements to be outweighed by the challenges faced by our completion tools and wireline services with respect to both utilization and pricing. Even with further improvements in oil prices, our business in 2021 may not improve materially or at all if downward pricing pressures remain.
While we cannot predict the length of time that market disruptions resulting from the coronavirus pandemic and efforts to mitigate its effects will continue, the ultimate impact on our business, or the pace or extent of any subsequent recovery, we expect the coronavirus pandemic and related effects will continue to have a material adverse impact on demand for oil, commodity prices, and our business generally. We have experienced inefficiencies and logistical challenges surrounding stay-at-home orders and remote work arrangements, travel restrictions, and an inability to commute to certain facilities and job sites, as we provide services and products to our customers.
During the pandemic, we have maintained our commitment to the safety of our employees, customers, vendors, and community at large, and we have taken, and are continuing to take, a proactive approach to navigating the pandemic. To mitigate exposure and risk, we have implemented processes and procedures across our entire organization based on federal, regional, and local guidelines and mandates, and our Health, Safety & Environment and management teams are in frequent communication with our entire employee base to ensure they are receiving updated guidelines, processes, and procedures. In response to the pandemic, we have implemented the following changes, for example: at the field level, we are working closely with our customers and vendors to update standard operating procedures, based on social distancing, hand washing, and other recommended best practices set forth by the Centers for Disease Control and Prevention; electronic assessments have been employed to check the health of employees prior to reporting to work, to ensure facilities are being properly cleaned and sanitized, and to check visitor health before arrival to our locations; internal case managers have been identified to handle all coronavirus-related cases, and all confirmed and potential cases are tracked through closure; many of our corporate and office employees are working virtually to avoid unnecessary risk and exposure; and we have significantly limited any work-related travel. We are actively monitoring updates from regulatory and government bodies and evolving our strategy accordingly in an effort to keep our workforce and communities healthy.
Other significant factors that are likely to affect commodity prices moving forward include the extent to which members of OPEC+ and other oil exporting nations continue to reduce oil export prices and increase production; the effect of energy, monetary, and trade policies of the U.S.; the pace of economic growth in the U.S. and throughout the world, including the potential for macro weakness; geopolitical and economic developments in the U.S. and globally; new energy policies put in place by the new administration and EPA; and overall North American oil and natural gas supply and demand fundamentals, including the pace at which export capacity grows. Even with price improvements in oil and natural gas, operator activity may not materially increase, as operators remain focused on operating within their capital plans, and uncertainty remains around supply and demand fundamentals.
In this challenging environment, we will nevertheless continue to focus on generating returns and cash flow. Due to our high level of variable costs and the asset-light make-up of our business, we were able to quickly implement cost-cutting measures and will continue our efforts to adapt as the market dictates.
Generally, operators have continued to improve operational efficiencies in completions design, increasing the complexity and difficulty, making oilfield service selection more important. This increase in high-intensity, high-efficiency completions of oil and gas wells further enhances the demand for our services. We compete for the most complex and technically demanding wells in which we specialize, which are characterized by extended laterals, increased stage spacing, multi-well pads, cluster spacing, and high proppant loads. These well characteristics lead to increased operating leverage and returns for us, as we are able to complete more jobs and stages with the same number of units and crews. Service providers for these projects are selected based on their technical expertise and ability to execute safely and efficiently, rather than only price. Nonetheless, we have experienced increased pricing pressures, and an increase in customer focus on price over performance, with respect to certain of our products and services, including our dissolvable frac plugs. As a result, although we expect our sales of dissolvable frac plugs to increase, due to significant pricing pressures from customers, increased competition, and our inability to proportionately reduce our materials costs, our ability to profit from such sales may be limited.
Other Significant Events
Production Solutions Divestiture
On August 30, 2019, we sold our Production Solutions segment for approximately $17.1 million in cash. In connection with this divestiture, we recorded a loss of $15.9 million during the year ended December 31, 2019. For additional information on this divestiture, see Note 16 - Segment Information included in Item 8 of Part II of this Annual Report.
Magnum Acquisition
On October 25, 2018, pursuant to the terms of a Securities Purchase Agreement, dated October 15, 2018, we acquired all of the equity interests of Magnum Oil Tools International, LTD, Magnum Oil Tools GP, LLC, and Magnum Oil Tools Canada Ltd. (such entities collectively, “Magnum” and such acquisition, the “Magnum Acquisition”) for approximately $334.5 million in upfront cash consideration, subject to customary adjustments, and 5.0 million shares of our common stock, which were issued to the sellers of Magnum in a private placement.
Results of Operations
Year Ended December 31,
2020 2019 Change
(in thousands)
Revenues
Completion Solutions $ 310,851 $ 774,665 $ (463,814)
Production Solutions (1)
- 58,272 (58,272)
$ 310,851 $ 832,937 $ (522,086)
Cost of revenues (exclusive of depreciation and amortization shown separately below)
Completion Solutions $ 302,157 $ 620,125 $ (317,968)
Production Solutions (1)
- 49,854 (49,854)
$ 302,157 $ 669,979 $ (367,822)
Adjusted gross profit (loss)
Completion Solutions $ 8,694 $ 154,540 $ (145,846)
Production Solutions (1)
- 8,418 (8,418)
$ 8,694 $ 162,958 $ (154,264)
General and administrative expenses $ 49,346 $ 81,327 $ (31,981)
Depreciation 32,431 50,544 (18,113)
Amortization of intangibles 16,467 18,367 (1,900)
Impairment of goodwill 296,196 20,273 275,923
Impairment of intangibles - 114,804 (114,804)
Impairment of property and equipment - 66,200 (66,200)
(Gain) loss on revaluation of contingent liabilities 276 (21,187) 21,463
Loss on sale of subsidiaries - 15,896 (15,896)
Gain on sale of property and equipment (2,857) (538) (2,319)
Loss from operations $ (383,165) $ (182,728) $ (200,437)
Non-operating (income) expenses (1,759) 38,910 (40,669)
Loss before income taxes (381,406) (221,638) (159,768)
Benefit for income taxes (2,458) (3,887) 1,429
Net loss $ (378,948) $ (217,751) $ (161,197)
(1) We sold the Production Solutions segment to Brigade Energy Service LLC on August 30, 2019. For additional information on the divestiture of the Production Solutions segment, see Note 16 - Segment Information.
Revenues
Revenues decreased $522.1 million, or 63%, to $310.9 million in 2020 which was primarily related to reduced activity and pricing pressure caused by poor market conditions, including an economic recession associated with the coronavirus pandemic, as well as international pricing and production disputes, in comparison to 2019. We depend, to a significant extent, on the level of unconventional resource development activity and corresponding capital spending of oil and natural gas companies onshore in North America. In turn, activity and capital spending are strongly influenced by current and expected oil and natural gas prices. During 2020, the average closing price was $39.16 per barrel of WTI, and the average closing price of natural gas was $2.03 per MMBtu. During 2019, the average closing price was $56.98 per barrel of WTI, and the average closing price of natural gas was $2.56 per MMBtu.
Additional information with respect to revenues by historical reportable segment is discussed below.
Completion Solutions: Revenues decreased $463.8 million, or 60%, to $310.9 million in 2020. The decrease was
prevalent across all lines of service and was a direct reflection of pricing pressures caused by reasons described above. More specifically, wireline revenues decreased $154.1 million, or 65%, as total completed wireline stages decreased by 59% in comparison to 2019. In addition, cementing revenues (including pump downs) decreased by $115.3 million, or 53%, as total cement job count decreased 46% in comparison to 2019, tools revenues decreased $107.3 million, or 58%, as completion tools stages decreased by 44% in comparison to 2019, and coiled tubing revenues decreased by $87.1 million, or 65%, as total days worked decreased by 53% in comparison to 2019.
Production Solutions: Revenues decreased $58.3 million, or 100%, for 2020 as the Production Solutions segment was sold on August 30, 2019.
Cost of Revenues (Exclusive of Depreciation and Amortization)
Cost of revenues decreased $367.8 million, or 55%, to $302.2 million in 2020, which is primarily related to reduced activity and pricing pressure caused by poor market conditions, including an economic recession associated with the coronavirus pandemic, in comparison to 2019.
Additional information with respect to cost of revenues by historical reportable segment is discussed below.
Completion Solutions: Cost of revenue decreased $317.9 million, or 51%, to $302.2 million in 2020. The decrease in comparison to 2019 was prevalent across all lines of service and was a direct reflection of reasons described above. More specifically, the decrease was primarily related to a $180.8 million decrease in materials installed and consumed while performing services, a $103.3 million decrease in employee costs, a $30.9 million decrease in other costs such as repair and maintenance, vehicle, travel, and meals and entertainment, and a $6.1 million decrease in transaction and integration costs association with the Magnum Acquisition. The overall decrease in cost of revenues was partially offset by a $2.1 million increase in bad debt expense and a $1.1 million increase in non-cash facility lease costs between periods.
Production Solutions: Cost of revenue decreased $49.9 million, or 100%, for 2020 as the Production Solutions segment was sold on August 30, 2019.
Adjusted Gross Profit (Loss)
Completion Solutions: Adjusted gross profit decreased $145.9 million to $8.7 million in 2020 as a result of the factors described above under “Revenues” and “Cost of Revenues.”
Production Solutions: Adjusted gross profit decreased $8.4 million to $0.0 million in 2020 as a result of the factors described above under “Revenues” and “Cost of Revenues.”
General and Administrative Expenses
General and administrative expenses decreased $32.0 million to $49.3 million in 2020. The decrease in comparison to 2019 was primarily related to a $22.1 million decrease in employee costs due mainly to headcount and salary reductions, including the suspension of matching contributions under the Nine Energy Service 401(k) Plan, across the organization. The overall decrease was also partly attributed to a $6.8 million reduction in transaction and integration costs associated with the Magnum Acquisition and a $4.0 million decrease in other general and administrative expenses such as professional fees, marketing, travel expense, as well as expenses associated with the recently sold Production Solutions segment. The overall decrease in general and administrative expenses was partially offset by a $1.0 million increase in severance and other general administrative type restructuring costs between periods.
Depreciation
Depreciation expense decreased $18.1 million to $32.4 million in 2020. The decrease in comparison to 2019 was related to a $9.9 million reduction in depreciation expense associated with our coiled tubing business mainly due to the property and equipment charge recorded in the fourth quarter of 2019, coupled with a $5.0 million reduction in depreciation expense in the Production Solutions segment, which was sold on August 30, 2019, and a $3.2 million reduction in depreciation expense in other lines of service within our Completion Solutions segment due to a decrease in capital expenditures between periods.
Amortization of Intangibles
Amortization of intangibles decreased $1.9 million to $16.5 million in 2020, primarily due to a $0.9 million decrease in amortization associated with certain non-compete agreements that were fully amortized in 2019, coupled with a $0.8 million decrease in amortization associated with our coiled tubing business due to the intangible asset impairment charge recorded in
the fourth quarter of 2019 as well as a $0.2 million decrease in amortization associated with a customer relationship intangible that was fully amortized in 2020.
Impairment of Goodwill
In 2020, we recorded goodwill impairment charges of $296.2 million in our tools, cementing, and wireline reporting units within our Completion Solutions segment due to sharp declines in global crude oil demand, an economic recession associated with the coronavirus pandemic, sharp declines in oil and natural gas prices, and an increased weighted average cost of capital driven by a reduction in our stock price and the Level 2 fair value of our Senior Notes.
In comparison, in 2019, we recorded a goodwill impairment charge of $20.3 million in our Completion Solutions segment due to a reduction of the need for coiled tubing during the drill-out phase of the overall completions process due to a decline in exploration and production capital budgets and activity, an over-supply of new coiled tubing units, and the introduction of dissolvable plug technology.
Impairment of Intangibles
In 2019, we recorded intangible asset impairment charges of $107.7 million associated with indefinite-lived trade names and an intangible asset impairment charge of $7.1 million associated with definite-lived customer relationship intangible assets, all within our Completion Solutions segment. These intangible asset impairment charges were primarily due to the transitioning of certain Magnum trade names to our trade names. These intangible asset impairment charges were also partly attributed to a reduction of the need for coiled tubing during the drill-out phase of the overall completions process due to a decline in exploration and production capital budgets and activity, an over-supply of new coiled tubing units, and the introduction of dissolvable plug technology. These intangible asset impairment charges did not recur in 2020.
Impairment of Property and Equipment
In 2019, we recorded a property and equipment impairment charge of $66.2 million in our Completion Solutions segment due to a reduction of the need for coiled tubing during the drill-out phase of the overall completions process due to a recent decline in exploration and production capital budgets and activity, an over-supply of new coiled tubing units, and the introduction of dissolvable plug technology. These property and equipment impairment charges did not recur in 2020.
(Gain) Loss on Revaluation of Contingent Liabilities
We recorded a $0.3 million loss on the revaluation of contingent liabilities in 2020 compared to a $21.2 million gain on the revaluation of contingent liabilities recorded in 2019. The $21.5 million change was primarily related to a $0.8 million loss on the revaluation of the Magnum Earnout (as defined in Note 9 - Debt Obligations included in Item 8 of Part II of this Annual Report) in 2020 compared to a $21.9 million gain on the revaluation of the Magnum Earnout in 2019. The Magnum Earnout was terminated in the second quarter of 2020. The change was partially offset by a $0.5 million gain on the revaluation of the earnout associated with our acquisition of Frac Technology AS (the “Frac Tech Earnout”) in 2020 compared to a $0.7 million loss on the revaluation of the Frac Tech Earnout.
(Gain) Loss on Sale of Subsidiaries
We recorded a $15.9 million loss on the sale of subsidiaries in 2019 associated with the sale of the historical Production Solutions segment. This loss on the sale of subsidiaries did not recur in 2020.
Non-Operating (Income) Expenses
We recorded $1.8 million in non-operating income for 2020 compared to $38.9 million in non-operating expenses for 2019. The $40.7 million change was primarily related to a $37.8 million gain on the extinguishment of debt related to the repurchase of Senior Notes in 2020 that did not occur in 2019. The change is also partly attributable to a $3.0 million reduction in interest expense and a $0.1 million decrease in interest income between periods.
Provision (Benefit) for Income Taxes
Our effective tax rate was 0.6% for 2020 and 1.8% for 2019. Our tax benefit for 2020 primarily comprised of changes to our valuation allowance position due to impairment recorded during the year, as well as the benefit from the five-year net operating loss carryback provided by the Coronavirus Aid, Relief, and Economic Security Act signed into law during 2020.
Adjusted EBITDA
Adjusted EBITDA decreased $138.8 million to a $25.8 million loss for 2020. The Adjusted EBITDA decrease is primarily due to the changes in revenue and expenses discussed above. See “Non-GAAP Financial Measures” below for further explanation.
Non-GAAP Financial Measures
EBITDA and Adjusted EBITDA
EBITDA and Adjusted EBITDA are supplemental non-GAAP financial measures that are used by management and external users of our financial statements, such as industry analysts, investors, lenders, and rating agencies.
We define EBITDA as net income (loss) before interest, taxes, depreciation, and amortization.
We define Adjusted EBITDA as EBITDA further adjusted for (i) goodwill, intangible asset, and/or property and equipment impairment charges, (ii) transaction and integration costs related to acquisitions, (iii) loss or gain on revaluation of contingent liabilities, (iv) gain on the extinguishment of debt, (v) loss or gain on the sale of subsidiaries, (vi) restructuring charges, (vii) stock-based compensation expense, (viii) loss or gain on sale of property and equipment, and (ix) other expenses or charges to exclude certain items which we believe are not reflective of ongoing performance of our business, such as legal expenses and settlement costs related to litigation outside the ordinary course of business.
Management believes EBITDA and Adjusted EBITDA are useful because they allow us to more effectively evaluate our operating performance and compare the results of our operations from period to period without regard to our financing methods or capital structure. We exclude the items listed above from net income (loss) in arriving at these measures because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures, and the method by which the assets were acquired. These measures should not be considered as an alternative to, or more meaningful than, net income (loss) as determined in accordance with accounting principles generally accepted in the United States of America (“GAAP”) or as an indicator of our operating performance. Certain items excluded from these measures are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure, as well as the historic costs of depreciable assets, none of which are components of these measures. Our computations of these measures may not be comparable to other similarly titled measures of other companies. We believe that these are widely followed measures of operating performance.
The following table presents a reconciliation of the non-GAAP financial measures of EBITDA and Adjusted EBITDA to the GAAP financial measure of net income (loss):
Year Ended December 31,
2020 2019
(in thousands)
EBITDA reconciliation:
Net loss $ (378,948) $ (217,751)
Interest expense 36,759 39,770
Interest income (615) (860)
Benefit for income taxes (2,458) (3,887)
Depreciation 32,431 50,544
Amortization of intangibles 16,467 18,367
EBITDA $ (296,364) $ (113,817)
Adjusted EBITDA reconciliation:
EBITDA $ (296,364) $ (113,817)
Impairment of goodwill 296,196 20,273
Impairment of intangibles - 114,804
Impairment of property and equipment - 66,200
Transaction and integration costs 146 13,047
(Gain) loss on revaluation of contingent liabilities (1)
276 (21,187)
Gain on extinguishment of debt (37,841) -
Loss on sale of subsidiaries - 15,896
Restructuring charges 4,907 3,976
Stock-based compensation expense 9,744 14,057
Gain on sale of property and equipment (2,857) (538)
Legal fees and settlements (2)
39 307
Adjusted EBITDA $ (25,754) $ 113,018
(1) Amounts relate to the revaluation of contingent liabilities associated with our 2018 acquisitions. The impact is included in our Consolidated Statements of Income and Comprehensive Income (Loss). For additional information on contingent liabilities, see Note 12 - Commitments and Contingencies included Item 8 of Part II of this Annual Report.
(2) Amounts represent fees and legal settlements associated with legal proceedings brought pursuant to the FLSA and/or similar state laws.
Return on Invested Capital
ROIC is a supplemental non-GAAP financial measure. We define ROIC as after-tax net operating profit (loss), divided by average total capital. We define after-tax net operating profit (loss) as net income (loss) plus (i) goodwill, intangible asset, and/or property and equipment impairment charges, (ii) transaction and integration costs related to acquisitions, (iii) interest expense (income), (iv) restructuring charges, (v) loss or gain on the sale of subsidiaries, (vi) gain on the extinguishment of debt, and (vii) the provision or benefit for deferred income taxes. We define total capital as book value of equity plus the book value of debt less balance sheet cash and cash equivalents. We compute the average of the current and prior period-end total capital for use in this analysis.
Management believes ROIC is a meaningful measure because it quantifies how well we generate operating income relative to the capital we have invested in our business and illustrates the profitability of a business or project taking into account the capital invested. Management uses ROIC to assist them in capital resource allocation decisions and in evaluating business performance. Although ROIC is commonly used as a measure of capital efficiency, definitions of ROIC differ, and our computation of ROIC may not be comparable to other similarly titled measures of other companies.
The following table provides an explanation of our calculation of ROIC for the years ended December 31, 2020 and 2019:
Year Ended December 31,
2020 2019
(in thousands)
Net loss $ (378,948) $ (217,751)
Add back:
Impairment of goodwill 296,196 20,273
Impairment of intangibles - 114,804
Impairment of property and equipment - 66,200
Transaction and integration costs 146 13,047
Interest expense 36,759 39,770
Interest income (615) (860)
Restructuring charges 4,907 3,976
Loss on sale of subsidiaries - 15,896
Gain on extinguishment of debt (37,841) -
Benefit for deferred income taxes (1,588) (4,327)
After-tax net operating profit (loss) $ (80,984) $ 51,028
Total capital as of prior period-end:
Total stockholders’ equity $ 389,877 $ 594,823
Total debt 400,000 435,000
Less cash and cash equivalents (92,989) (63,615)
Total capital as of prior period-end $ 696,888 $ 966,208
Total capital as of period-end:
Total stockholders’ equity $ 20,409 $ 389,877
Total debt 348,637 400,000
Less cash and cash equivalents (68,864) (92,989)
Total capital as of period-end $ 300,182 $ 696,888
Average total capital $ 498,535 $ 831,548
ROIC -16.2 % 6.1 %
Adjusted Gross Profit (Loss)
GAAP defines gross profit (loss) as revenues less cost of revenues and includes depreciation and amortization in costs of revenues. We define adjusted gross profit (loss) as revenues less direct and indirect costs of revenues (excluding depreciation and amortization). This measure differs from the GAAP definition of gross profit (loss) because we do not include the impact of depreciation and amortization, which represent non-cash expenses.
Management uses adjusted gross profit (loss) to evaluate operating performance. We prepare adjusted gross profit (loss) to eliminate the impact of depreciation and amortization because we do not consider depreciation and amortization indicative of our core operating performance. Adjusted gross profit (loss) should not be considered as an alternative to gross profit (loss), operating income (loss), or any other measure of financial performance calculated and presented in accordance with GAAP. Adjusted gross profit (loss) may not be comparable to similarly titled measures of other companies because other companies may not calculate adjusted gross profit (loss) or similarly titled measures in the same manner as we do.
The following table presents a reconciliation of adjusted gross profit (loss) to GAAP gross profit (loss).
Year Ended December 31,
2020 2019
(in thousands)
Calculation of gross profit (loss)
Revenues $ 310,851 $ 832,937
Cost of revenues (exclusive of depreciation and amortization shown separately below) 302,157 669,979
Depreciation (related to cost of revenues) 30,161 47,006
Amortization of intangibles 16,467 18,367
Gross profit (loss) $ (37,934) $ 97,585
Adjusted gross profit reconciliation:
Gross profit (loss) $ (37,934) $ 97,585
Depreciation (related to cost of revenues) 30,161 47,006
Amortization of intangibles 16,467 18,367
Adjusted gross profit $ 8,694 $ 162,958
Liquidity and Capital Resources
Sources and Uses of Liquidity
Historically, we have met our liquidity needs principally from cash on hand, cash flows from operating activities and, if needed, external borrowings. Our principal uses of cash are to fund capital expenditures and acquisitions, to service our outstanding debt, and to fund our working capital requirements. We may also, from time to time, make open market debt repurchases (including our Senior Notes) when it is opportunistic to do to manage our debt maturity profile. In 2018, we issued $400.0 million of Senior Notes, together with cash on hand and borrowings under the 2018 ABL Credit Facility (as defined below), to fund the Magnum Acquisition as well as fully repay and terminate the term loan borrowings and the outstanding revolving credit commitments under our prior credit facility. For additional information regarding the Senior Notes, see Note 9 - Debt Obligations included in Item 8 of Part II of this Annual Report. In the third quarter of 2019, we divested the Production Solutions segment for approximately $17.1 million in cash. We used such proceeds to support working capital requirements and fund a portion of our 2020 capital expenditures.
We continually monitor potential capital sources, including equity and debt financing, to meet our investment and target liquidity requirements. Our future success and growth will be highly dependent on our ability to continue to access outside sources of capital. In addition, our ability to satisfy our liquidity requirements depends on our future operating performance, which is affected by prevailing economic conditions, the level of drilling, completion and production activity for North American onshore oil and natural gas resources, and financial and business and other factors, many of which are beyond our control. In 2020, in response to rapidly deteriorating market conditions driven in large part by the coronavirus pandemic, we implemented certain cost-cutting measures across the organization. We expect to continue to maintain many of these measures, including those relating to employee compensation, and may implement additional cost-cutting measures, as necessary. We can make no assurance regarding our ability to successfully implement such measures, or whether such measures would be sufficient to mitigate a decline in our financial performance.
Our total 2020 capital expenditure budget, excluding possible acquisitions, was between $10.0 million and $15.0 million, and the actual amount of capital expenditures incurred in 2020 was $10.2 million. Our capital expenditure budget for 2021, excluding possible acquisitions, is expected to be between $15.0 million and $20.0 million. The nature of our capital expenditures is comprised of a base level of investment required to support our current operations and amounts related to growth and company initiatives. Capital expenditures for growth and company initiatives are discretionary. We continually evaluate our capital expenditures and the amount we ultimately spend will depend on a number of factors including expected industry activity levels and company initiatives.
Although we do not budget for acquisitions, pursuing growth through acquisitions may continue to be a significant part of our business strategy. Our ability to make significant additional acquisitions for cash will require us to obtain additional equity or debt financing, which we may not be able to obtain on terms acceptable to us or at all.
At December 31, 2020, we had $68.9 million of cash and cash equivalents and $37.9 million of availability under the 2018 ABL Credit Facility (as defined below), which resulted in a total liquidity position of $106.8 million. As of February 28, 2021, we had approximately $62 million of cash and cash equivalents, which has decreased our total liquidity position. Although we believe our total liquidity position will continue to materially erode, due in large part to interest payments due on the Senior Notes, we believe that, based on our current forecasts, our cash on hand, together with cash flow from operations, and borrowings under the 2018 ABL Credit Facility, should be sufficient to fund our capital requirements for at least the next twelve months from the issuance date of our consolidated financial statements. However, we can make no assurance regarding our ability to achieve our forecasts, which are materially dependent on our financial performance and the ever-changing market.
Senior Notes
On October 25, 2018, we issued the Senior Notes due 2023 under an indenture, dated as of October 25, 2018 (the “Indenture”), by and among us, including certain of our subsidiaries, and Wells Fargo, National Association, as Trustee. The Senior Notes bear interest at an annual rate of 8.750% payable on May 1 and November 1 of each year, and the first interest payment was due on May 1, 2019. Based on current amounts outstanding as of February 28, 2021, the semi-annual interest payments are $15.2 million each. The Senior Notes are senior unsecured obligations and are fully and unconditionally guaranteed on a senior unsecured basis by each of our current domestic subsidiaries and by certain future subsidiaries.
The Indenture contains covenants that limit our ability and the ability of our restricted subsidiaries to engage in certain activities. We were in compliance with the provisions of the Indenture at December 31, 2020.
Upon an event of default, the trustee or the holders of at least 25% in aggregate principal amount of then outstanding Senior Notes may declare the Senior Notes immediately due and payable, except that a default resulting from certain events of bankruptcy or insolvency with respect to us, any of our restricted subsidiaries that are a significant subsidiary or any group of restricted subsidiaries that, taken together, would constitute a significant subsidiary, will automatically cause all outstanding Senior Notes to become due and payable.
We repurchased approximately $53.3 million of Senior Notes at a repurchase price of approximately $14.6 million in cash for the year ended December 31, 2020. Deferred financing costs associated with these transactions were $0.9 million for the year ended December 31, 2020. As a result, for the year ended December 31, 2020, we recorded a $37.8 million gain on the extinguishment of debt, which was calculated as the difference between the repurchase price and the carrying amount of the Senior Notes partially offset by the deferred financing costs. The gain on extinguishment of debt is included as a separate line item in our Consolidated Statement of Income and Comprehensive Income (Loss) for the year ended December 31, 2020. In
addition to repurchases, from time to time, we have explored, and may continue to further consider, transactions to restructure
or refinance a portion of the Senior Notes. Any such transactions may involve the issuance of additional equity or convertible
debt securities that could result in material dilution to our stockholders, and these securities could have rights superior to
holders of our common stock and could contain covenants that will restrict our operations.
For additional information on the Senior Notes, see Note 9 - Debt Obligations included in Item 8 of Part II of this Annual Report.
2018 ABL Credit Facility
On October 25, 2018, we entered into a credit agreement dated as of October 25, 2018 (the “2018 ABL Credit Agreement”), that permits aggregate borrowings of up to $200.0 million, subject to a borrowing base, including a Canadian tranche with a sub-limit of up to $25.0 million and a sub-limit of $50.0 million for letters of credit (the “2018 ABL Credit Facility”). The 2018 ABL Credit Facility will mature on October 25, 2023 or, if earlier, on the date that is 180 days before the scheduled maturity date of the Senior Notes if they have not been redeemed or repurchased by such date.
Loans to us and our domestic related subsidiaries (the “U.S. Credit Parties”) under the 2018 ABL Credit Facility may be base rate loans or LIBOR loans; and loans to Nine Energy Canada Inc., a corporation organized under the laws of Alberta, Canada, and its restricted subsidiaries (the “Canadian Credit Parties”) under the Canadian tranche may be Canadian Dollar Offered Rate (“CDOR”) loans or Canadian prime rate loans. The applicable margin for base rate loans and Canadian prime rate loans vary from 0.75% to 1.25% and the applicable margin for LIBOR loans or CDOR loans vary from 1.75% to 2.25% in each depending on our leverage ratio. In addition, a commitment fee of 0.50% per annum will be charged on the average daily unused portion of the revolving commitments.
The 2018 ABL Credit Agreement contains various affirmative and negative covenants, including financial reporting requirements and limitations on indebtedness, liens, mergers, consolidations, liquidations and dissolutions, sales of assets, dividends and other restricted payments, investments (including acquisitions) and transactions with affiliates. In addition, the 2018 ABL Credit Agreement contains a minimum fixed charge ratio covenant of 1.00 to 1.00 that is tested quarterly when the availability under the 2018 ABL Credit Facility drops below $18.75 million or a default has occurred until the availability exceeds such threshold for 30 consecutive days and such default is no longer outstanding. We were in compliance with all covenants under the 2018 ABL Credit Agreement as of December 31, 2020.
All of the obligations under the 2018 ABL Credit Facility are secured by first priority perfected security interests (subject to permitted liens) in substantially all of the personal property of U.S. Credit Parties, excluding certain assets. The obligations under the Canadian tranche are further secured by first priority perfected security interests (subject to permitted liens) in substantially all of the personal property of Canadian Credit Parties excluding certain assets. The 2018 ABL Credit Facility is guaranteed by the U.S. Credit Parties, and the Canadian tranche is further guaranteed by the Canadian Credit Parties and the U.S. Credit Parties.
At December 31, 2020, our availability under the 2018 ABL Credit Facility was approximately $37.9 million, net of outstanding letters of credit of $0.5 million.
Cash Flows
Our cash flows for the years ended December 31, 2020, and 2019 are presented below:
Year Ended December 31,
2020 2019
(in thousands)
Operating activities $ (4,901) $ 101,305
Investing activities (1,778) (34,121)
Financing activities (17,385) (37,905)
Impact of foreign exchange rate on cash (61) 95
Net change in cash and cash equivalents $ (24,125) $ 29,374
Operating Activities
Net cash used in operating activities was $4.9 million in 2020 compared to $101.3 million in net cash provided by operating activities in 2019. The $106.2 million decrease in net cash provided by operating activities was primarily a result of a $107.5 million decrease in cash flow provided by operations, adjusted for any non-cash items, primarily due to an increase in net loss in 2020 compared to 2019. The overall decrease in net cash provided by operating activities was partially offset by an increase of $1.3 million in cash collections and other changes in working capital which provided an increased source of cash in 2020 in comparison to 2019.
Investing Activities
Net cash used in investing activities was $1.8 million in 2020 compared to $34.1 million in net cash used in investing activities in 2019. The $32.3 million decrease in net cash used in investing activities was primarily related to a decrease of $55.5 million in cash purchases of property and equipment in 2020 in comparison to 2019. The overall decrease was also partly due to an increase in proceeds from sales of property and equipment (including insurance) of $2.3 million in 2020 compared to 2019. The overall decrease in net cash used in investing activities was partially offset by $16.9 million in proceeds from the sale of subsidiaries, $7.6 million in proceeds from notes receivable payments, and $1.0 million proceeds of acquisitions, which we received in 2019 that did not recur in 2020.
Financing Activities
Net cash used in financing activities was $17.4 million in 2020 compared to $37.9 million in net cash used in financing activities in 2019. The $20.5 million decrease in net cash used in financing activities was primarily related to $45.0 million in payments on the 2018 ABL Credit Facility in 2019 that did not recur in 2020. The overall decrease was also partly due to a decrease of $1.5 million in cash used for the vesting of restricted stock in 2020 in comparison to 2019. The overall decrease in net cash used in financing activities was partially offset by $14.6 million of purchases of the Senior Notes and $0.3 million of payments on the Magnum Promissory Notes (as defined in Note 9 - Debt Obligations included in Item 8 of Part II of this Annual Report) in 2020 that did not occur in 2019, coupled with $10.0 million in proceeds from the 2018 ABL Credit Facility in 2019 that did not recur in 2020 as well as an additional $1.0 million in payments of contingent liabilities and $0.1 million in payments on finance leases in comparison to 2019.
Contractual Obligations
As a “smaller reporting company,” as defined under the Exchange Act, we are not required to provide this information.
Off-Balance Sheet Arrangements
At December 31, 2020, we had letters of credit of $0.5 million, which represented off-balance sheet arrangements as defined in Item 303(a)(4)(ii) of Regulation S-K. As of December 31, 2020, no liability has been recognized in our Consolidated Balance Sheet for the letters of credit.
Operating leases were excluded from our Consolidated Balance Sheet as of December 31, 2019 but are included in our Consolidated Balance Sheet as of December 31, 2020 following the January 1, 2020 effective date of Accounting Standards Update (“ASU”) 2016-02, Leases (Topic 842) and its related ASUs (“ASC 842”). For additional information, see “Critical Accounting Policies” below as well as Note 2 - Significant Accounting Policies and Note 6 - Leases in Item 8 of Part II of this Annual Report.
Critical Accounting Policies
The discussion and analysis of our financial condition and results of operations are based upon our financial statements, which have been prepared in accordance with GAAP. The preparation of our financial statements requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities. Certain accounting policies involve judgments and uncertainties to such an extent that there is a reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been used. We evaluate our estimates and assumptions on a regular basis. We base our estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates and assumptions used in preparation of our financial statements. We provide expanded discussion of our more significant accounting policies, estimates, and judgments below. We believe that most of these accounting policies reflect our more significant estimates and assumptions used in preparation of our financial statements.
Emerging Growth Company Status
We are an “emerging growth company” as defined in the JOBS Act. Under Section 107 of the JOBS Act, as an emerging growth company, we are taking advantage of an extended transition period for the adoption of new or revised financial accounting standards, including the reduced reporting requirements and exemptions, and the longer phase-in periods for the adoption of new or revised financial accounting standards, until we are no longer an emerging growth company. Our election to use the longer 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. 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.
Smaller Reporting Company Status
We are a “smaller reporting company” as defined by the SEC. As such, we are eligible to comply with the scaled disclosure requirements in several Regulation S-K and Regulation S-X items. Our disclosures in this Annual Report reflect these scaled requirements.
Revenue Recognition
We recognize revenue under Accounting Standards Codification Topic 606 (“ASC 606”) when products are received by a customer’s domestic common carrier at our facility or when the product is received by the customer’s international carrier. We believe this recognition policy reflects the point at which the customer has control of the product as required by ASC 606.
Performance Obligations
A performance obligation is a promise in a contract to transfer a distinct good or service to the customer and is the unit of account in ASC 606. A contract’s transaction price is allocated to each distinct performance obligation and recognized as revenue when, or as, the performance obligation is satisfied. We exclude sales taxes, value added taxes, and other taxes we collect concurrent with revenue-producing activities from revenue.
Our revenue is derived from the sale of products and services which are sold directly to customers or are consumed by customers on their well sites. For domestic product sales, we typically recognize revenue when we meet our performance obligation upon the shipment of the products from our facilities to our customer. For international product sales, we typically recognize revenue when we meet our performance obligation upon receipt of the products by the customer’s international carrier. We recognize service revenue over the time the service is performed as the customer consumes and benefits from the use of our products and services for well service. Service revenues represent revenue recognized over time, as our customer arrangements typically provide agreed upon hourly or daily fixed-rates, and we recognize service revenue based upon the number of hours or days services have been performed.
Contracts for our products and services are negotiated on a per-job basis at a regional level. Contracts vary in nature but typically have a duration of less than a month and have a single performance obligation either for a job, a series of distinct jobs, or a period we stand ready to provide our services to our client as needed. Our payment terms vary by the type and location of our customers and type of product and service offered. We receive cash equal to the invoice amount for most services and product sales, and payment terms typically range from 30 to 60 days from the date we invoice a customer. Since
the period between the delivery of our products and services and our receipt of customer payment for these products and services is not expected to exceed one year, we have elected not to calculate or disclose a financing component for our customer contracts.
Contract Estimates
We receive reimbursements from our customers for the purchase of supplies, equipment, personnel services, and other services provided at a customer’s request. Reimbursable revenues are subject to uncertainty as the timing of the receipt of these amounts is dependent on factors outside of our influence. Accordingly, these revenues are not recognized until the uncertainty is resolved, which typically occurs when the related costs are incurred on behalf of the customer. We are considered a principal in these transactions and record the associated revenues at the gross amount billed to the customer.
Changes and modifications to contracts are routine in the performance of our contracts due to the dynamic nature of well operations and the services we provide for our customers. We consider contract modifications to exist when the modification either creates a new contract or changes the existing enforceable rights and obligations of a contract. Most of our contract modifications are for services or goods that are not distinct from existing contracts due to the significant integration provided or significant interdependencies in the context of the contract and are accounted for as if they were part of the original contract.
Contract Balances
Contract assets arise when recorded revenues for a contract exceed the amounts billed under the terms of the contracts. We classify contract liabilities as unearned income. Such deferred revenue typically results from advance payments received on well service orders prior to performance of the service.
For additional information, see Note 2 - Significant Accounting Policies and Note 3 - Revenues in Item 8 of Part II of this Annual Report.
Leases
On December 31, 2020, we adopted ASC 842 effective January 1, 2020. Under ASC 842, we determine if an arrangement is a lease at inception. To the extent that we determine an arrangement represents a lease, we classify that lease as an operating lease or a finance lease.
We capitalize operating leases on our Consolidated Balance Sheets through a Right of Use (“ROU”) asset and a corresponding lease liability. ROU assets represent our right to use an underlying asset for the lease term, and lease liabilities represent our obligation to make lease payments arising from the operating lease. Operating lease ROU assets and obligations are recognized at the commencement date of an arrangement based on the present value of lease payments over the lease term utilizing an interest rate that would have been incurred to borrow over a similar term the funds necessary to purchase the leased asset. Lease expense for operating leases is recognized on a straight-line basis over the lease term for 2020 and 2019.
Accounting for finance leases under ASC 842 remained unchanged from previous accounting guidance.
For additional information, see Note 2 - Significant Accounting Policies and Note 6 - Leases in Item 8 of Part II of this Annual Report.
Property and Equipment
Property and equipment is stated at cost and depreciated under the straight-line method over the estimated useful life of the asset. Equipment held under capital leases is stated at the present value of its future minimum lease payments and is depreciated under the straight-line method over the shorter of the lease term or the estimated useful life of the asset. When assets are retired or otherwise disposed of, the cost and related accumulated depreciation are removed from the accounts and any resulting gain or loss is recognized within operating expenses. Normal repair and maintenance costs are charged to operating expense as incurred. Significant renewals and betterments are capitalized.
Valuation of Long-Lived Assets
Long-lived assets are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. In performing the review for impairment, future cash flows expected to result from the use of the asset and its eventual disposal are estimated. If the undiscounted future cash flows are less than the carrying amount of the assets, there is an indication that the asset may be impaired. The amount of the impairment is measured as the difference between the carrying value and the Level 3 fair value of the asset. The Level 3 fair value is determined either through
the use of an external valuation, or by means of an analysis of discounted future cash flows based on expected utilization. Determining fair value requires the use of estimates and assumptions. Such estimates and assumptions include revenue growth rates, operating profit margins, weighted average costs of capital, terminal growth rates, future market share, the impact of new product development, and future market conditions, among others. We believe that the estimates and assumptions used in impairment assessments are reasonable and appropriate. Impairment losses are reflected in “Income (loss) from operations” in our Consolidated Statements of Income and Comprehensive Income (Loss).
With a significant reduction in exploration and production capital budgets and activity, primarily driven by sharp declines in global crude oil demand and an economic recession associated with the coronavirus pandemic, as well as sharp declines in oil and natural gas prices, the carrying amount of long-lived assets (inclusive of definite-lived intangible assets and property and equipment) associated with our asset groups may not be recoverable. As such, we performed an impairment assessment of long-lived assets in our asset groups under Accounting Standards Codification 360, Property, Plant and Equipment (“ASC 360”) at March 31, 2020, based on our best internal projections and the likelihood of various outcomes. Based on our assessment, we determined that the estimated future undiscounted cash flows derived from long-lived assets associated with our asset groups exceeded the carrying amount of long-lived assets associated with our asset groups, and no impairment to long-lived assets was required. No events triggered additional impairment tests under ASC 360 through December 31, 2020. However, the occurrence of future events or deteriorating market conditions could result in additional impairment assessments under ASC 360 subsequent to December 31, 2020.
In the fourth quarter of 2019, we recorded a property and equipment impairment charge of $66.2 million and a definite-lived customer relationship intangible asset impairment charge of $7.1 million. These impairment charges represent the difference between the carrying value and the estimated fair value of the long-lived assets in our coiled tubing asset group within our Completion Solutions segment and were due to a reduction of the need for coiled tubing during the drill-out phase of the overall completions process due to a recent decline in exploration and production capital budgets and activity, an over-supply of new coiled tubing units, and the introduction of dissolvable plug technology.
For additional information on these impairment charges, see Note 5 - Property and Equipment included in Item 8 of Part II of this Annual Report.
Valuation of Goodwill and Intangible Assets
Goodwill has an indefinite useful life and is not subject to amortization. Intangible assets with indefinite useful lives (specifically trademarks and trade names) are also not subject to amortization. For goodwill and intangible assets with indefinite useful lives, an assessment for impairment is performed annually on December 31 or when there is an indication an impairment may have occurred. Goodwill is reviewed for impairment by comparing the carrying value of each of our reporting unit’s net assets (including allocated goodwill) to the Level 3 fair value of our reporting unit. The Level 3 fair value of our reporting unit is determined by using the income approach (discounted cash flows of forecasted income). Intangible assets with indefinite useful lives are reviewed for impairment by comparing the carrying value of the intangible asset to the Level 3 fair value of the intangible asset. The Level 3 fair value of intangible assets with indefinite useful lives (specifically trademarks and trade names) is estimated using the relief-from-royalty method of the income approach. This approach is based on the assumption that in lieu of ownership, a company would be willing to pay a royalty in order to exploit the related benefits of this intangible asset. Determining fair value requires the use of estimates and assumptions. Such estimates and assumptions include revenue growth rates, operating profit margins, royalty rates, weighted average costs of capital, terminal growth rates, future market share, the impact of new product development, and future market conditions, among others. We believe that the estimates and assumptions used in impairment assessments are reasonable and appropriate. We recognize a goodwill impairment charge for the amount by which the carrying value of goodwill exceeds our reporting unit’s Level 3 fair value. We recognize an indefinite-lived intangible asset impairment charge of the amount by which the carrying value of the intangible asset exceeds the Level 3 fair value of the intangible asset. Any impairment losses are reflected in “Income (loss) from operations” in our Consolidated Statements of Income and Comprehensive Income (Loss).
Intangible assets with definite lives include technology, customer relationships, and non-compete agreements. The Level 3 fair value of technology and the Level 3 fair value of customer relationships are estimated using the income approach, specifically the multi-period excess earnings method. The multi-period excess earnings method consists of isolating the cash flows attributed to the intangible asset, which are then discounted to present value to calculate the Level 3 fair value of the intangible asset. The Level 3 fair value of non-compete agreements is estimated using a with and without scenario where cash flows are projected through the term of the non-compete agreement assuming the non-compete agreement is in place and compared to cash flows assuming the non-compete agreement is not in place.
Intangible assets with definite lives are amortized based on the estimated consumption of the economic benefit over their estimated useful lives. Intangible assets with definite lives are tested for impairment whenever events or changes in circumstances indicate that their carrying amount may not be recoverable.
In the first quarter of 2020, in connection with an interim goodwill impairment test, we recorded goodwill impairment charges of $296.2 million in our tools, cementing, and wireline reporting units within our Completions Solutions segment due to sharp declines in global crude oil demand, an economic recession associated with the coronavirus pandemic, sharp declines in oil and natural gas prices, and an increased weighted average cost of capital driven by a reduction in our stock price and the Level 2 fair value of our Senior Notes.
In the fourth quarter of 2019, in connection with our annual goodwill impairment test, we recorded a goodwill impairment charge of $20.3 million, in our coiled tubing reporting unit within our Completion Solutions segment. In addition, in the fourth quarter of 2019, in connection with our annual indefinite-lived intangible asset impairment test, we recorded an intangible asset impairment charge of $12.7 million associated with the indefinite-lived trade names in our coiled tubing reporting unit and an intangible asset impairment charge of $95.0 million associated with the indefinite-lived trade names in our completion tools reporting unit, both within our Completion Solutions segment. As described above in “Critical Accounting Policies - Valuation of Long-Lived Assets” and also in the fourth quarter of 2019, we recorded an intangible asset impairment charge of $7.1 million associated with the definite-lived customer relationship intangible assets in our coiled tubing asset group within our Completion Solutions segment.
For additional information on goodwill and both indefinite-lived and definite-lived intangible asset impairment charges, see Note 7 - Goodwill and Intangible Assets included in Item 8 of Part II of this Annual Report.
Recognition of Provisions for Contingencies
In the ordinary course of business, we are subject to various claims, suits, and complaints. We, in consultation with internal and external advisors, will provide for a contingent loss in the financial statements if it is probable that a liability has been incurred at the date of the financial statements and the amount can be reasonably estimated. If it is determined that the reasonable estimate of the loss is a range and that there is no best estimate within the range, provision will be made for the lower amount of the range. Legal costs are expensed as incurred.
Stock-based Compensation
We account for awards of stock-based compensation at fair value on the date granted to employees and recognize the compensation expense in the financial statements over the requisite service period. Forfeitures are recorded as they occur. All stock-based compensation expense is recorded using the straight-line method and is included in “General and administrative expenses” in our Consolidated Statements of Income and Comprehensive Income (Loss).
Determining Fair Market Value
Fair value of all the options outstanding was measured using the Black-Scholes model. Determining the appropriate fair value model and calculating the fair value of options requires the input of highly subjective assumptions, including the expected volatility of the price of our stock, the risk-free rate, the expected term of the options, and the expected dividend yield of our common stock. These estimates involve inherent uncertainties and the application of management’s judgment. If factors change and different assumptions are used, our stock-based compensation expense could be materially different in the future. The Black-Scholes option pricing model requires estimates of key assumptions based on both historical information and management judgment regarding market factors and trends.
Expected Life - The expected term of stock options represents the period the stock options are expected to remain outstanding and is based on the simplified method, which is the weighted average vesting term plus the original contractual term, divided by two.
Expected Volatility - We develop our expected volatility based upon a weighted average volatility of our peer group.
Risk-free Interest Rate - The risk-free interest rates for options granted are based on the average of five year and seven year constant maturity Treasury bond rates whose term is consistent with the expected term of an option from the date of grant.
Expected Term - The expected term is based on the midpoint between the vesting date and contractual term of an option. The expected term represents the period that our stock-based awards are expected to be outstanding.
Expected Dividend Yield - We do not anticipate paying cash dividends on our shares of common stock; therefore, the expected dividend yield is assumed to be zero.
Fair value of the stock-based compensation for all of the performance share units outstanding was measured using a Monte Carlo simulation model.
Recent Accounting Pronouncements
For additional information on recent accounting pronouncements, see Note 2 - Significant Accounting Policies included in Item 8 of Part II of this Annual Report.

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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
As a “smaller reporting company,” as defined under the Exchange Act, we are not required to provide the information required by this Item.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Item 8. Financial Statements and Supplementary Data
Index to Consolidated Financial Statements
Report of Independent Registered Public Accounting Firm
Consolidated Balance Sheets as of December 31, 2020 and 2019
Consolidated Statements of Income and Comprehensive Income (Loss) for the Years Ended December 31, 2020 and 2019
Consolidated Statements of Changes in Shareholders’ Equity for the Years Ended December 31, 2020 and 2019
Consolidated Statements of Cash Flows for the Years Ended December 31, 2020 and 2019
Notes to Consolidated Financial Statements
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Stockholders of Nine Energy Service, Inc.
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of Nine Energy Service, Inc. and its subsidiaries (the “Company”) as of December 31, 2020 and 2019, and the related consolidated statements of income and comprehensive income (loss), of stockholders’ equity and of cash flows for the years then ended, including the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2020 and 2019, and the results of its operations and its cash flows for the years then ended in conformity with accounting principles generally accepted in the United States of America.
Changes in Accounting Principle
As discussed in Note 2 to the consolidated financial statements, the Company changed the manner in which it accounts for leases in 2020.
Basis for Opinion
These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s consolidated financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits of these consolidated financial statements in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.
/s/ PricewaterhouseCoopers LLP
Houston, Texas
March 8, 2021
We have served as the Company’s auditor since 2011.
NINE ENERGY SERVICE, INC.
CONSOLIDATED BALANCE SHEETS
(In thousands, except share and per share amounts)
December 31,
2020 2019
Assets
Current assets
Cash and cash equivalents $ 68,864 $ 92,989
Accounts receivable, net 41,235 96,889
Income taxes receivable 1,392 660
Inventories, net 38,402 60,945
Prepaid expenses and other current assets 16,270 17,434
Total current assets 166,163 268,917
Property and equipment, net 102,429 128,604
Operating lease right of use assets, net 36,360 -
Finance lease right of use assets, net 1,816 -
Intangible assets, net 132,524 148,991
Goodwill - 296,196
Other long-term assets 3,308 8,187
Total assets $ 442,600 $ 850,895
Liabilities and Stockholders’ Equity
Current liabilities
Accounts payable $ 18,140 $ 35,490
Accrued expenses 17,139 24,730
Current portion of long-term debt 844 -
Current portion of operating lease obligations 6,200 -
Current portion of finance lease obligations 1,092 995
Total current liabilities 43,415 61,215
Long-term liabilities
Long-term debt 342,714 392,059
Long-term operating lease obligations 32,295 -
Long-term finance lease obligations 1,109 2,201
Deferred income taxes - 1,588
Other long-term liabilities 2,658 3,955
Total liabilities 422,191 461,018
Commitments and contingencies (Note 12)
Stockholders’ equity
Common stock (120,000,000 shares authorized at $0.01 par value; 31,557,809 and 30,555,677 shares issued and outstanding at December 31, 2020 and 2019 respectively)
316 306
Additional paid-in capital 768,429 758,853
Accumulated other comprehensive loss (4,501) (4,467)
Accumulated deficit (743,835) (364,815)
Total stockholders’ equity 20,409 389,877
Total liabilities and stockholders’ equity $ 442,600 $ 850,895
The accompanying notes are an integral part of these consolidated financial statements.
NINE ENERGY SERVICE, INC.
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME (LOSS)
(In thousands, except share and per share amounts)
Year Ended December 31,
2020 2019
Revenues
Service $ 231,719 $ 646,508
Product 79,132 186,429
310,851 832,937
Cost and expenses
Cost of revenues (exclusive of depreciation and amortization shown separately below)
Service 220,960 528,643
Product 81,197 141,336
General and administrative expenses 49,346 81,327
Depreciation 32,431 50,544
Amortization of intangibles 16,467 18,367
Impairment of goodwill 296,196 20,273
Impairment of intangibles - 114,804
Impairment of property and equipment - 66,200
(Gain) loss on revaluation of contingent liabilities 276 (21,187)
Loss on sale of subsidiaries - 15,896
Gain on sale of property and equipment (2,857) (538)
Loss from operations (383,165) (182,728)
Interest expense 36,759 39,770
Interest income (615) (860)
Gain on extinguishment of debt (37,841) -
Other income (62) -
Loss before income taxes (381,406) (221,638)
Benefit for income taxes (2,458) (3,887)
Net loss $ (378,948) $ (217,751)
Loss per share
Basic $ (12.74) $ (7.43)
Diluted $ (12.74) $ (7.43)
Weighted average shares outstanding
Basic 29,744,830 29,308,107
Diluted 29,744,830 29,308,107
Other comprehensive income (loss), net of tax
Foreign currency translation adjustments, net of $0 tax in each period
$ (34) $ 376
Total other comprehensive income (loss), net of tax (34) 376
Total comprehensive loss $ (378,982) $ (217,375)
The accompanying notes are an integral part of these consolidated financial statements.
NINE ENERGY SERVICE, INC.
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
(In thousands, except share amounts)
Common Stock Additional
Paid-in Accumulated
Other
Comprehensive Retained
Earnings
(Accumulated Total
Stockholders’
Shares Amounts Capital Income (Loss) Deficit) Equity
Stockholders’ equity as of December 31, 2018 30,163,408 $ 302 $ 746,428 $ (4,843) $ (147,064) $ 594,823
Issuance of common stock under stock compensation plan, net of forfeitures 462,622 5 (5) - - -
Stock-based compensation expense - - 14,057 - - 14,057
Exercise of stock options 674 - 15 - - 15
Vesting of restricted stock (71,027) (1) (1,642) - - (1,643)
Other comprehensive income - - - 376 - 376
Net loss - - - - (217,751) (217,751)
Stockholders’ equity as of December 31, 2019 30,555,677 $ 306 $ 758,853 $ (4,467) $ (364,815) $ 389,877
Cumulative effect adjustment of lease implementation (Note 6) - - - - (72) (72)
Issuance of common stock under stock compensation plan, net of forfeitures 1,151,915 11 (11) - - -
Stock-based compensation expense - - 9,744 - - 9,744
Vesting of restricted stock (149,783) (1) (157) - - (158)
Other comprehensive loss - - - (34) - (34)
Net loss - - - - (378,948) (378,948)
Stockholders’ equity as of December 31, 2020 31,557,809 $ 316 $ 768,429 $ (4,501) $ (743,835) $ 20,409
The accompanying notes are an integral part of these consolidated financial statements.
NINE ENERGY SERVICE, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
Year Ended December 31,
2020 2019
Cash flows from operating activities
Net loss $ (378,948) $ (217,751)
Adjustments to reconcile net loss to net cash provided by operating activities
Depreciation 32,431 50,544
Amortization of intangibles 16,467 18,367
Amortization of operating leases 8,897 -
Amortization of deferred financing costs 2,836 2,984
Provision for doubtful accounts 2,820 849
Benefit for deferred income taxes (1,588) (4,327)
Provision for inventory obsolescence 8,957 5,148
Impairment of goodwill 296,196 20,273
Impairment of intangibles - 114,804
Impairment of property and equipment - 66,200
Impairment of operating lease 466 -
Stock-based compensation expense 9,744 14,057
Gain on extinguishment of debt (37,841) -
Gain on sale of property and equipment (2,857) (538)
(Gain) loss on revaluation of contingent liabilities 276 (21,187)
Loss on sale of subsidiaries - 15,896
Changes in operating assets and liabilities, net of effects from acquisitions
Accounts receivable, net 52,914 41,852
Inventories, net 13,600 22,545
Prepaid expenses and other current assets 1,368 2,395
Accounts payable and accrued expenses (25,456) (27,901)
Income taxes receivable/payable (732) (294)
Other assets and liabilities (4,451) (2,611)
Net cash provided by (used in) operating activities (4,901) 101,305
Cash flows from investing activities
Acquisitions, net of cash acquired - 1,020
Proceeds from sale of subsidiaries - 16,914
Proceeds from sales of property and equipment 6,402 3,702
Proceeds from property and equipment casualty losses 1,237 1,576
Proceeds from notes receivable payments - 7,626
Purchases of property and equipment (9,417) (64,959)
Net cash used in investing activities (1,778) (34,121)
Cash flows from financing activities
Proceeds from 2018 ABL Credit Facility - 10,000
Payments on 2018 ABL Credit Facility - (45,000)
Purchases of Senior Notes (14,561) -
Payments on Magnum Promissory Notes (281) -
Payments on finance leases (995) (903)
Payments of contingent liabilities (1,390) (374)
Year Ended December 31,
2020 2019
Proceeds from exercise of stock options - 15
Vesting of restricted stock (158) (1,643)
Net cash used in financing activities (17,385) (37,905)
Impact of foreign currency exchange on cash (61) 95
Net increase (decrease) in cash and cash equivalents (24,125) 29,374
Cash and cash equivalents
Cash and cash equivalents at beginning of period 92,989 63,615
Cash and cash equivalents at end of period $ 68,864 $ 92,989
Supplemental disclosures of cash flow information:
Cash paid for interest $ 34,421 $ 37,376
Cash paid (refunded) for income taxes $ (540) $ 517
Non-cash investing and financing activities:
Termination of contingent liability related to business acquisition $ 3,375 $ -
Capital expenditures in accounts payable and accrued expenses $ 747 $ 10
Property and equipment obtained by finance leases $ - $ 1,621
Receivable from property and equipment sale (including insurance) $ 3,223 $ 5,949
The accompanying notes are an integral part of these consolidated financial statements.
NINE ENERGY SERVICE, INC.
NOTES TO THE FINANCIAL STATEMENTS
1. Company and Organization
Company Description
Nine Energy Service, Inc. (the “Company” or “Nine”), a Delaware corporation, is an oilfield services business that provides services integral to the completion of unconventional wells through a full range of tools and methodologies. The Company is headquartered in Houston, Texas.
Risks and Uncertainties
The Company’s business depends, to a significant extent, on the level of unconventional resource development activity and corresponding capital spending of oil and natural gas companies. These activity and spending levels are strongly influenced by the current and expected oil and natural gas prices. The worldwide coronavirus outbreak in early 2020, which was declared a pandemic by the World Health Organization in March 2020, the uncertainty regarding its impact, and various governmental actions taken to mitigate its impact have resulted in an unprecedented decline in demand for oil. In the midst of the ongoing pandemic, the Organization of the Petroleum Exporting Countries and other oil producing nations, including Russia, were initially unable to reach an agreement on production levels for crude oil, at which point Saudi Arabia and Russia initiated efforts to aggressively increase production. The convergence of these events created the unprecedented dual impact of a massive decline in the demand for oil, coupled with the risk of a substantial increase in supply, which has directly affected the Company. While the Company cannot predict the length of time that market disruptions resulting from the coronavirus pandemic and efforts to mitigate its effects will continue, the ultimate impact on its business, or the pace or extent of any subsequent recovery, the Company expects the coronavirus pandemic and related effects to continue to have a material adverse impact on commodity prices and its business generally.
Historically, the Company has met its liquidity needs principally from cash on hand, cash flow from operations and, if needed, external borrowings. In response to the above events, the Company has implemented certain cost-cutting measures across the organization to continue to maintain its current liquidity position. Based on its current forecasts, the Company believes that cash on hand, together with cash flow from operations, and borrowings under the 2018 ABL Credit Facility (as defined in Note 9 - Debt Obligations), should be sufficient to fund its capital requirements for at least the next twelve months from the issuance date of its consolidated financial statements.
2. Significant Accounting Policies
Basis of Presentation
The accompanying consolidated financial statements are prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”).
Principles of Consolidation
The consolidated financial statements as of December 31, 2020 and 2019, and for the years ended December 31, 2020 and 2019, include the accounts of Nine and its wholly owned subsidiaries. All inter-company balances and transactions have been eliminated in the consolidation.
Use of Estimates
The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. These estimates are based on management’s best knowledge of current events and actions that the Company may undertake in the future. Such estimates include fair value assumptions used in purchase accounting and in analyzing goodwill, definite and indefinite-lived intangible assets, and property and equipment for possible impairment, useful lives used in depreciation and amortization expense, stock-based compensation fair value, estimated realizable value on excess and obsolete inventories, deferred taxes and income tax contingencies, and losses on accounts receivable. It is at least reasonably possible that the estimates used will change within the next year.
Revenue Recognition
The Company recognizes revenue under Accounting Standards Codification Topic 606 (“ASC 606”) when products are received by a customer’s domestic common carrier at the Company’s facility or when the product is received by the customer’s international carrier. The Company believes this recognition policy reflects the point at which the customer has control of the product as required by ASC 606.
Performance Obligations
A performance obligation is a promise in a contract to transfer a distinct good or service to the customer and is the unit of account in ASC 606. A contract’s transaction price is allocated to each distinct performance obligation and recognized as revenue when, or as, the performance obligation is satisfied. The Company excludes sales taxes, value added taxes, and other taxes it collects concurrent with revenue-producing activities from revenue.
The Company’s revenue is derived from the sale of products and services which are sold directly to customers or are consumed by customers on their well sites. For domestic product sales, the Company typically recognizes revenue when it meets its performance obligation upon the shipment of the products from its facilities to its customer. For international product sales, the Company typically recognizes revenue when it meets its performance obligation upon receipt of the products by the customer’s international carrier. The Company recognizes service revenue over the time the service is performed as the customer consumes and benefits from the use of the Company’s products and services for well service. Service revenues represent revenue recognized over time, as the Company’s customer arrangements typically provide agreed upon hourly or daily fixed-rates, and the Company recognizes service revenue based upon the number of hours or days services have been performed.
Contracts for the Company’s products and services are negotiated on a per-job basis at a regional level. Contracts vary in nature but typically have a duration of less than a month and have a single performance obligation either for a job, a series of distinct jobs, or a period the Company stands ready to provide its services to its client as needed.
The Company’s payment terms vary by the type and location of its customers and type of product and service offered. The Company receives cash equal to the invoice amount for most services and product sales, and payment terms typically range from 30 to 60 days from the date the Company invoices a customer. Since the period between the delivery of the Company’s products and services and the Company’s receipt of customer payment for these products and services is not expected to exceed one year, the Company has elected not to calculate or disclose a financing component for its customer contracts.
Contract Estimates
The Company receives reimbursements from its customers for the purchase of supplies, equipment, personnel services, and other services provided at a customer’s request. Reimbursable revenues are subject to uncertainty as the timing of the receipt of these amounts is dependent on factors outside of the Company’s influence. Accordingly, these revenues are not recognized until the uncertainty is resolved, which typically occurs when the related costs are incurred on behalf of the customer. The Company is considered a principal in these transactions and records the associated revenues at the gross amount billed to the customer.
Changes and modifications to contracts are routine in the performance of the Company’s contracts due to the dynamic nature of well operations and the services the Company provides for its customers. The Company considers contract modifications to exist when the modification either creates a new contract or changes the existing enforceable rights and obligations of a contract. Most of the Company’s contract modifications are for services or goods that are not distinct from existing contracts due to the significant integration provided or significant interdependencies in the context of the contract and are accounted for as if they were part of the original contract.
Contract Balances
Any contract assets are included in “Accounts receivable, net” in the Company’s Consolidated Balance Sheets. Contract assets arise when recorded revenues for a contract exceed the amounts billed under the terms of the contracts. The Company classifies contract liabilities as unearned income which is included in “Accrued expenses” in the Company’s Consolidated Balance Sheets. Such deferred revenue typically results from advance payments received on well service orders prior to performance of the service.
For information regarding the Company’s revenue, see Note 3 - Revenues.
Leases
On December 31, 2020, the Company adopted Accounting Standards Update (“ASU”) 2016-02, Leases (Topic 842) and its related ASUs (“ASC 842”) effective January 1, 2020. Prior to January 1, 2020, the Company accounted for leases under Accounting Standards Codification 840 (“ASC 840”). All periods, including quarterly periods, previously reported under ASC 840 will continue to be reported under ASC 840, and periods beginning December 31, 2020 and after are reported under ASC 842.
The Company determines if an arrangement is a lease at inception. To the extent an arrangement represents a lease, the Company classifies that lease as an operating lease or a finance lease.
The Company capitalizes operating leases on its Consolidated Balance Sheets through a Right of Use (“ROU”) asset and a corresponding lease liability. ROU assets represent the Company’s right to use an underlying asset for the lease term, and lease liabilities represent the Company’s obligation to make lease payments arising from the operating lease. Operating lease ROU assets and obligations are recognized at the commencement date of an arrangement based on the present value of lease payments over the lease term utilizing an interest rate that the Company would have incurred to borrow over a similar term the funds necessary to purchase the leased asset. Operating leases are included in “Operating lease right of use assets, net,” “Current portion of operating lease obligations,” and “Long-term operating lease obligations” in the Company’s Consolidated Balance Sheet as of December 31, 2020. Lease expense for operating leases is recognized on a straight-line basis over the lease term for 2020 and 2019.
Accounting for finance leases under ASC 842 remained unchanged from previous accounting guidance and are included in the line items “Finance lease right of use assets, net,” “Current portion of finance lease obligations,” and “Long-term finance lease obligations” in the Company’s Consolidated Balance Sheet as of December 31, 2020 and in the line items “Property and equipment, net,” “Current portion of finance lease obligations,” and “Long-term finance lease obligations” in the Company’s Consolidated Balance Sheet as of December 31, 2019.
For additional information regarding the Company’s leases, see Note 6 - Leases.
Cash and Cash Equivalents
The Company considers all highly liquid debt instruments with a maturity of three months or less when purchased to be cash equivalents. Throughout the year, the Company maintained cash balances that were in excess of their federally insured limits. The Company has not experienced any losses in such accounts.
Cash flows from the Company’s Canadian subsidiary are calculated based on its functional currency. As a result, amounts related to changes in assets and liabilities reported in the Company’s Consolidated Statements of Cash Flows will not
necessarily agree to changes in the corresponding balances in the Company’s Consolidated Balance Sheets.
Foreign Currency
The Company’s functional currency is the United States Dollar (“USD”). The financial position and results of operations of the Company’s Canadian subsidiary are measured using the local currency as the functional currency. Revenues and expenses of the subsidiary have been translated into USD at average exchange rates prevailing during the period. Assets and liabilities have been translated at the rates of exchange on the date of the Company’s Consolidated Balance Sheets. The resulting translation gain and loss adjustments have been recorded as a separate component of other comprehensive income (loss) in the Company’s Consolidated Statements of Income and Comprehensive Income (Loss) and its Consolidated Statements of Changes in Stockholders’ Equity.
Accounts Receivable
The Company extends credit to customers in the normal course of business. Accounts receivable are carried at their estimated collectible amount. Trade credit is generally extended on a short-term basis; thus, receivables do not bear interest, although a finance charge may be applied to amounts past due. The Company maintains an allowance for doubtful accounts for estimated losses that may result from the inability of its customers to make required payments. Such allowances are based upon several factors including, but not limited to, credit approval practices, industry and customer historical experience, as well as the current and projected financial condition of the specific customer. Accounts receivable outstanding longer than contractual terms are considered past due. The Company writes off accounts receivable to the allowance for doubtful accounts when they become uncollectible. Any payments subsequently received on receivables previously written off are credited to bad debt expense.
The Company had $41.2 million and $96.9 million of “Accounts receivable, net” at December 31, 2020 and 2019, respectively. The Company maintains an allowance for doubtful accounts based on the expected collectability of accounts receivable, which is included in “Accounts receivable, net” on the Company’s Consolidated Balance Sheets. The Company had an allowance for doubtful accounts of $3.4 million and $0.8 million at December 31, 2020 and 2019, respectively. Bad debt expense was $2.8 million and $0.8 million for the years ended December 31, 2020 and 2019, respectively.
Concentration of Credit Risk
The Company derives a significant portion of its revenues from companies in the exploration and production (“E&P”) industry, and its customer base includes a broad range of integrated and independent domestic E&P companies and international E&P companies operating in the markets that the Company serves. While current energy prices are important contributors to positive cash flow for the customers, expectations about future prices and price volatility are generally more important for determining future spending levels. Any prolonged increase or decrease in oil and natural gas prices affects the levels of exploration, development, and production activity as well as the entire health of the oil and natural gas industry and can therefore negatively impact spending by the Company’s customers. One customer accounted for more than 10% of the revenues for the year ended December 31, 2020. No customer accounted for more than 10% of revenues for the year ended December 31, 2019.
Concentration of Supplier Risk
Purchases during the years ended December 31, 2020 and 2019 did not include purchases from any supplier that individually represented more than 10% of total operating purchases.
Property and Equipment
Property and equipment is stated at cost and depreciated under the straight-line method over the estimated useful lives of the assets. Equipment held under capital leases is stated at the present value of its future minimum lease payments and is depreciated under the straight-line method over the shorter of the lease term or the estimated useful life of the asset. When assets are retired or otherwise disposed of, the cost and related accumulated depreciation are removed from the accounts, and any resulting gain or loss is recognized within operating expenses. Normal repair and maintenance costs are charged to operating expense as incurred. Significant renewals and betterments are capitalized.
Valuation of Long-Lived Assets
Long-lived assets are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. In performing the review for impairment, future cash flows expected to result from the use of the asset and its eventual disposal are estimated. If the undiscounted future cash flows are less than the carrying
amount of the assets, there is an indication that the asset may be impaired. The amount of the impairment is measured as the difference between the carrying value and the Level 3 fair value of the asset. The Level 3 fair value is determined either through the use of an external valuation, or by means of an analysis of discounted future cash flows based on expected utilization. Determining fair value requires the use of estimates and assumptions. Such estimates and assumptions include revenue growth rates, operating profit margins, weighted average costs of capital, terminal growth rates, future market share, the impact of new product development, and future market conditions, among others. The Company believes that the estimates and assumptions used in impairment assessments are reasonable and appropriate. Impairment losses are reflected in “Income (loss) from operations” in the Company’s Consolidated Statements of Income and Comprehensive Income (Loss).
With a significant reduction in exploration and production capital budgets and activity, primarily driven by sharp declines in global crude oil demand and an economic recession associated with the coronavirus pandemic, as well as sharp declines in oil and natural gas prices, the carrying amount of long-lived assets (inclusive of definite-lived intangible assets and property and equipment) associated with the Company’s asset groups may not be recoverable. As such, the Company performed an impairment assessment of long-lived assets in its asset groups under Accounting Standards Codification 360, Property, Plant and Equipment (“ASC 360”) at March 31, 2020, based on its best internal projections and the likelihood of various outcomes. Based on its assessment, the Company determined that the estimated future undiscounted cash flows derived from long-lived assets associated with its asset groups exceeded the carrying amount of long-lived assets associated with its asset groups, and no impairment to long-lived assets was required. No events triggered additional impairment tests under ASC 360 through December 31, 2020. However, the occurrence of future events or deteriorating market conditions could result in additional impairment assessments under ASC 360 subsequent to December 31, 2020.
In the fourth quarter of 2019, the Company recorded a property and equipment impairment charge of $66.2 million and a definite-lived customer relationship intangible asset impairment charge of $7.1 million. These impairment charges represent the difference between the carrying value and the estimated fair value of the long-lived assets in the Company’s coiled tubing asset group within its Completion Solutions segment and were due to a reduction of the need for coiled tubing during the drill-out phase of the overall completions process due to a recent decline in exploration and production capital budgets and activity, an over-supply of new coiled tubing units, and the introduction of dissolvable plug technology. For additional information on these impairment charges, see Note 5 - Property and Equipment.
Valuation of Goodwill and Intangible Assets
Goodwill has an indefinite useful life and is not subject to amortization. Intangible assets with indefinite useful lives (specifically trademarks and trade names) are also not subject to amortization. For goodwill and intangible assets with indefinite useful lives, an assessment for impairment is performed annually on December 31 or when there is an indication an impairment may have occurred. Goodwill is reviewed for impairment by comparing the carrying value of each of the Company’s reporting unit’s net assets (including allocated goodwill) to the Level 3 fair value of the reporting unit. The Level 3 fair value of the reporting unit is determined by using the income approach (discounted cash flows of forecasted income). Intangible assets with indefinite useful lives are reviewed for impairment by comparing the carrying value of the intangible asset to the Level 3 fair value of the intangible asset. The Level 3 fair value of intangible assets with indefinite useful lives (specifically trademarks and trade names) is estimated using the relief-from-royalty method of the income approach. This approach is based on the assumption that in lieu of ownership, a company would be willing to pay a royalty in order to exploit the related benefits of this intangible asset. Determining fair value requires the use of estimates and assumptions. Such estimates and assumptions include revenue growth rates, operating profit margins, royalty rates, weighted average costs of capital, terminal growth rates, future market share, the impact of new product development, and future market conditions, among others. The Company believe that the estimates and assumptions used in impairment assessments are reasonable and appropriate. The Company recognizes a goodwill impairment charge for the amount by which the carrying value of goodwill exceeds the reporting unit’s Level 3 fair value. The Company recognizes an indefinite-lived intangible asset impairment charge of the amount by which the carrying value of the intangible asset exceeds the Level 3 fair value of the intangible asset. Any impairment losses are reflected in “Income (loss) from operations” in the Company’s Consolidated Statements of Income and Comprehensive Income (Loss).
Intangible assets with definite lives include technology, customer relationships, and non-compete agreements. The Level 3 fair value of technology and the Level 3 fair value of customer relationships are estimated using the income approach, specifically the multi-period excess earnings method. The multi-period excess earnings method consists of isolating the cash flows attributed to the intangible asset, which are then discounted to present value to calculate the Level 3 fair value of the intangible asset. The Level 3 fair value of non-compete agreements is estimated using a with and without scenario where cash flows are projected through the term of the non-compete agreement assuming the non-compete agreement is in place and compared to cash flows assuming the non-compete agreement is not in place.
Intangible assets with definite lives are amortized based on the estimated consumption of the economic benefit over their estimated useful lives. Intangible assets with definite lives are tested for impairment whenever events or changes in
circumstances indicate that their carrying amount may not be recoverable.
In the first quarter of 2020, in connection with an interim goodwill impairment test, the Company recorded goodwill impairment charges of $296.2 million in its tools, cementing, and wireline reporting units within its Completion Solutions segment due to sharp declines in global crude oil demand, an economic recession associated with the coronavirus pandemic, sharp declines in oil and natural gas prices, and an increased weighted average cost of capital driven by a reduction in the Company’s stock price and the Level 2 fair value of its Senior Notes (as defined in Note 9 - Debt Obligations).
In the fourth quarter of 2019, in connection with its annual goodwill impairment test, the Company recorded a goodwill impairment charge of $20.3 million in its coiled tubing reporting unit within its Completion Solutions segment. In addition, in the fourth quarter of 2019, in connection with its annual indefinite-lived intangible asset impairment test, the Company recorded an intangible asset impairment charge of $12.7 million associated with the indefinite-lived trade names in its coiled tubing reporting unit and an intangible asset impairment charge of $95.0 million associated with the indefinite-lived trade names in its completion tools reporting unit, both within its Completion Solutions segment. As described above in “Valuation of Long-Lived Assets” and also in the fourth quarter of 2019, the Company recorded an intangible asset impairment charge of $7.1 million associated with the definite-lived customer relationship intangible assets in its coiled tubing asset group within its Completion Solutions segment.
For additional information on goodwill and both indefinite-lived and definite-lived intangible asset impairment charges, see Note 7 - Goodwill and Intangible Assets.
Stock-based Compensation
The Company has stock-based compensation plans for certain of its employees. The Company measures employee stock-based compensation awards at fair value on the date they are granted to employees and recognizes compensation cost in its financial statements over the requisite service period. As a result of the adoption of ASU No. 2016-09, the Company elected to account for stock-based compensation forfeitures as they occur.
Restricted Stock and Restricted Stock Units
Compensation expense is recorded for restricted stock and restricted stock units over the applicable vesting period based on the Company’s closing stock price as of the grant date.
Performance Units
Performance stock units are recorded at their fair value and expensed over their performance period. Fair value for performance stock units is measured using a Monte Carlo simulation model.
Options
Options are issued with an exercise price equal to the fair value of the stock on the date of grant. Compensation expense is recorded for the fair value of the stock options and is recognized over the period of the underlying security’s vesting schedule. Consideration paid on the exercise of stock options is credited to share capital and additional paid-in capital. For options, fair value of the stock-based compensation is measured by use of the Black-Scholes pricing model. The following discusses the assumptions used related to the Black-Scholes pricing model.
•The expected term of stock options represents the period the stock options are expected to remain outstanding and is based on the simplified method, which is the weighted average vesting term plus the original contractual term, divided by two.
•Expected volatility measures the amount that a stock price has fluctuated or is expected to fluctuate during a period. The Company developed its expected volatility based upon a weighted average volatility of its peer group.
•At the time of the issuance of the options, the Company did not plan to pay cash dividends in the foreseeable future. Therefore, a zero expected dividend yield was used in the valuation model.
•The risk-free interest rate is based on United States’ Treasury zero-coupon issues with remaining terms similar to the expected term on the options.
Income Taxes
The Company accounts for income taxes under Accounting Standards Codification 740, Income Taxes (“ASC 740”) . Under this method, deferred income tax assets and liabilities are determined based upon temporary differences between the carrying amounts and tax bases of the Company’s assets and liabilities at the balance sheet date and are measured using enacted tax rates and laws that will be in effect when the differences are expected to reverse. The effect on deferred tax assets and liabilities of a change in the tax rates is recognized in income in the period in which the change occurs. The Company records a valuation reserve in each reporting period when management believes that it is more likely than not that any deferred tax asset created will not be realized.
The Company recognizes the financial statement benefit of a tax position only after determining that the relevant tax authority would more likely than not sustain the position following an audit. If a tax position meets the “more likely than not” recognition criteria, the tax position is measured at the largest amount of benefit greater than 50% likely of being realized upon ultimate settlement.
Fair Value of Financial Instruments
The carrying amounts for financial instruments classified as current assets and current liabilities approximate fair value, due to the short maturity of such instruments.
For financial assets and liabilities disclosed at fair value, fair value is determined as the exit price, or the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The established fair value hierarchy divides fair value measurement into three levels:
•Level 1 - inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities that the reporting entity has the ability to access at the measurement date;
•Level 2 - inputs other than quoted prices included within Level 1 that are observable for the assets or liability, either directly or indirectly; and
•Level 3 - inputs are unobservable for the asset or liability, which reflect the best judgment of management.
Financial assets and liabilities that are disclosed at fair value are categorized in one of the above three levels based on the lowest level input that is significant to the fair value measurement in its entirety. Level 1 provides the most reliable measure of fair value, whereas Level 3 generally requires significant management judgment.
The fair value of the Company’s debt obligations is classified as Level 2 in the fair value hierarchy and is established based on observable inputs in less active markets. For additional information on the fair value of the Company’s debt obligations, see Note 9 - Debt Obligations.
The fair value of the Company’s contingent consideration is classified as Level 3 in the fair value hierarchy and is established on unobservable markets which reflect the best judgment of management. For additional information on the fair value of the Company’s contingent consideration, see Note 12 - Commitments and Contingencies.
Earnings (Loss) Per Share
Basic earnings (loss) per share is calculated by dividing net income (loss) by the weighted average number of common shares outstanding during the period. Diluted earnings (loss) per share is calculated by dividing net income (loss) by the weighted average number of common shares outstanding during the period, taking into effect, if any, the exercise of potentially dilutive stock options assumed to be purchased from the proceeds using the average market price of the Company’s stock for each of the periods presented as well as potentially dilutive restricted stock, restricted stock units, and performance stock units. There was no dilutive effect for the year ended December 31, 2020 and 2019 as the Company was in a net loss position for those years. For additional information on earnings (loss) per share, see Note 14 - Earnings (Loss) Per Share.
Accounting Pronouncements Recently Adopted
In February 2016, the Financial Accounting Standards Board (the “FASB”) issued ASU No. 2016-02, Leases (Topic 842), which requires lessees to recognize leases on-balance sheet and disclose key information about leasing arrangements. ASU 2016-02 was subsequently amended by multiple ASUs. Together, these ASUs establish a ROU model that requires a lessee to recognize a ROU asset and lease liability on the balance sheet for all leases with a term longer than 12 months. Leases will be classified as finance or operating, with classification affecting the pattern and classification of expense recognition in the income statement. Effective January 1, 2020, the Company adopted ASC 842. Prior to January 1, 2020, the Company accounted
for leases under ASC 840. All periods, including quarterly periods, previously reported under ASC 840 will continue to be reported under ASC 840, and periods beginning December 31, 2020 and after are reported under ASC 842. For additional information about the Company’s adoption of ASC 842, see Note 6 - Leases.
In August 2018, the FASB issued ASU 2018-13, Fair Value Measurement (Topic 820): Disclosure Framework - Changes to the Disclosure Requirements for Fair Value Measurement, which eliminates, adds, and modifies certain disclosure requirements for fair value measurements as part of its disclosure framework project. The standard is effective for all entities for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2019. The standard is required to be applied retrospectively, except the new Level 3 disclosure requirements are applied prospectively. The Company adopted ASU 2018-13 in the first quarter of 2020, and it did not have a material impact on the Company’s consolidated financial statements.
Accounting Pronouncements Not Yet Adopted
In March 2020, the FASB issued ASU 2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting, which provides optional expedients and exceptions for applying GAAP to contract modifications and hedging relationships, subject to meeting certain criteria, that reference London Interbank Offered Rate (“LIBOR”) or another reference rate expected to be discontinued. The amendments in ASU 2020-04 are effective for all entities as of March 12, 2020 through December 31, 2022. An entity may elect to apply the amendments for contract modifications as of any date from the beginning of an interim period that includes or is subsequent to March 12, 2020, or prospectively from a date within an interim period that includes or is subsequent to March 12, 2020, up to the date that the financial statements are available to be issued. The Company is currently evaluating the impact of the standard on its consolidated financial statements.
In August 2018, the FASB issued ASU 2018-15, Intangibles - Goodwill and Other - Internal-Use Software (Subtopic 350-40): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract. ASU 2018-15 provides additional guidance on the accounting for costs of implementation activities performed in a cloud computing arrangement that is a service contract. The amendments in ASU 2018-15 align the requirements for capitalizing implementation costs incurred in a hosting arrangement that is a service contract with the requirements for capitalizing implementation costs incurred to develop or obtain internal-use software (and hosting arrangements that include an internal-use software license). Costs for implementation activities in the application development stage are capitalized depending on the nature of the costs, while costs incurred during the preliminary project and post implementation stages are expensed as the activities are performed. ASU 2018-15 is effective for public businesses for fiscal years beginning after December 15, 2019, and interim periods within those fiscal years. As an emerging growth company, the Company is permitted, and plans, to adopt the new standard for fiscal years beginning after December 15, 2020 and interim periods within fiscal years beginning after December 15, 2021. The Company is currently evaluating the impact of the standard on its consolidated financial statements.
In June 2016, the FASB issued ASU 2016-13, Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments. ASU 2016-13 requires a financial asset (or a group of financial assets) measured at amortized cost basis to be presented at the net amount expected to be collected. The amendments in ASU 2016-13 replace the current incurred loss impairment methodology in current GAAP with a methodology that reflects expected credit losses and requires consideration of a broader range of reasonable and supportable information. ASU 2016-13 is effective for Securities and Exchange Commission filers, excluding smaller reporting companies, for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years. As an emerging growth company, the Company is permitted, and plans, to adopt the new standard for the fiscal years beginning after December 15, 2022, including interim periods within those fiscal years. The Company is currently evaluating the impact of the standard on its consolidated financial statements.
3. Revenues
Disaggregation of Revenues
The Company adopted ASC 606 on December 31, 2019, effective January 1, 2019, using the modified retrospective method. Accordingly, results for the year ended December 31, 2019 and periods thereafter are presented in accordance with ASC 606 while prior period results, including those presented below for the year ended December 31, 2019, have not been adjusted and are reported under the previous revenue recognition guidance.
Disaggregated revenue for the years ended December 31, 2020 and 2019 was as follows:
Year Ended December 31, 2020
Completion Solutions Production Solutions (2)
Total
(in thousands)
Cement $ 102,631 $ - $ 102,631
Tools 79,132 - 79,132
Wireline 81,684 - 81,684
Coiled tubing 47,404 - 47,404
Well service - - -
Total revenues $ 310,851 $ - $ 310,851
Year Ended December 31, 2019
Completion Solutions Production Solutions (2)
Total
(in thousands)
Cement $ 217,893 $ - $ 217,893
Tools 186,429 - 186,429
Wireline 235,800 - 235,800
Coiled tubing 134,543 - 134,543
Well service - 58,272 58,272
Total revenues $ 774,665 $ 58,272 $ 832,937
Year Ended December 31, 2020
Completion Solutions Production Solutions (2)
Total
(in thousands)
Service (1)
$ 231,719 $ - $ 231,719
Product (1)
79,132 - 79,132
Total $ 310,851 $ - $ 310,851
Year Ended December 31, 2019
Completion Solutions Production Solutions (2)
Total
(in thousands)
Service (1)
$ 588,236 $ 58,272 $ 646,508
Product (1)
186,429 - 186,429
Total $ 774,665 $ 58,272 $ 832,937
(1) The Company recognizes revenues from the sales of products at a point in time and revenues from the sales of services over time.
(2) The Production Solutions segment was sold to Brigade Energy Service LLC (“Brigade”) on August 30, 2019. For additional information on the Production Solutions divestiture, see Note 16 - Segment Information.
Performance Obligations
At December 31, 2020 and December 31, 2019, the amount of remaining performance obligations were not material.
Contract Balances
At December 31, 2020 and December 31, 2019, contract assets and contract liabilities were not material.
4. Inventories
Inventories, consisting primarily of finished goods and raw materials, are stated at the lower of cost or net realizable value. Cost is determined on an average cost basis. The Company reviews its inventory balances and writes down its inventory for estimated obsolescence or excess inventory equal to the difference between the cost of inventory and the estimated market value based upon assumptions about future demand and market conditions. The reserve for obsolescence was $13.3 million and $5.4 million at December 31, 2020 and 2019, respectively.
Inventories, net as of December 31, 2020 and 2019 were comprised of the following:
December 31,
2020 2019
(in thousands)
Raw materials $ 33,361 $ 38,823
Work in progress 367 -
Finished goods 17,952 27,555
Inventories 51,680 66,378
Reserve for obsolescence (13,278) (5,433)
Inventories, net $ 38,402 $ 60,945
5. Property and Equipment
Property and equipment amounts as of December 31, 2020 and 2019 were as follows:
December 31,
Estimated
Useful Lives 2020 2019
(in thousands)
Operating equipment 1 to 12 years
$ 296,491 $ 293,237
Autos and trucks 1 to 7 years
4,102 15,053
Furniture, fixtures, and equipment 2 to 12 years
4,100 4,054
Shop equipment 3 to 15 years
13,558 16,144
Buildings 7 to 39 years
8,489 7,991
Leasehold improvements 3 to 11 years
1,320 1,653
Land indefinite 791 791
328,851 338,923
Less: Accumulated depreciation (226,422) (210,319)
Property and equipment, net $ 102,429 $ 128,604
Depreciation expense was $32.4 million and $50.5 million for the years ended December 31, 2020 and 2019, respectively.
With a significant reduction in exploration and production capital budgets and activity, primarily driven by sharp declines in global crude oil demand and an economic recession associated with the coronavirus pandemic, as well as sharp declines in oil and natural gas prices, the carrying amount of long-lived assets (inclusive of definite-lived intangible assets and property and equipment) associated with the Company’s asset groups may not be recoverable. As such, the Company performed an impairment assessment of long-lived assets in its asset groups under ASC 360 at March 31, 2020, based on its best internal projections and the likelihood of various outcomes. Based on its assessment, the Company determined that the estimated future undiscounted cash flows derived from long-lived assets associated with its asset groups exceeded the carrying amount of long-lived assets associated with its asset groups, and no impairment to long-lived assets was required. No events triggered additional impairment tests under ASC 360 through December 31, 2020. However, the occurrence of future events or deteriorating market conditions could result in additional impairment assessments under ASC 360 subsequent to December 31, 2020.
2019 Property and Equipment Impairment
With a recent decline in exploration and production capital budgets and activity, coupled with an over-supply of new coiled tubing units, the demand for coiled tubing during the drill-out phase of the overall completions process diminished in the fourth quarter of 2019, shrinking the overall coiled tubing market. Additionally, in the fourth quarter of 2019, dissolvable plug technology became more widely adopted by operators, which significantly reduced and will potentially eliminate the need for coiled tubing drill-outs. This weakened market outlook indicated that the carrying amount of long-lived assets in the Company’s coiled tubing asset group within its Completion Solutions segment might not have been recoverable. As such, the Company performed an impairment assessment of all long-lived assets in its coiled tubing asset group within its Completion Solutions segment under ASC 360 at December 31, 2019. Based on this assessment, which was in consideration of its best internal projections, the Company determined that the carrying amount of long-lived assets in its coiled tubing reporting asset group within its Completion Solutions segment exceeded the estimated future undiscounted cash flows derived from its coiled tubing asset group’s long-lived assets. As such, the Company determined the fair value of the long-lived assets in its coiled tubing asset group within its Completion Solutions segment using the market approach (consideration of market sales values for similar assets). Based on its fair value determination, the Company recorded an impairment charge of $66.2 million related to property and equipment in its coiled tubing asset group within its Completion Solutions segment and an impairment charge of $7.1 million related to definite-lived customer relationship intangible assets in its coiled tubing asset group within its Completion Solutions segment. The property and equipment impairment charge is included in the line item “Impairment of property and equipment” in the Company’s Consolidated Statement of Income and Comprehensive Income (Loss) for the year ended December 31, 2019, and the definite-lived intangible asset impairment charge is included in the line item “Impairment of intangibles” in the Company’s Consolidated Statement of Income and Comprehensive Income (Loss) for the year ended December 31, 2019. The total impairment charge represents the difference between the carrying value and the estimated fair value of the long-lived assets in the Company’s coiled tubing asset group within its Completion Solutions segment and was allocated across the long-lived asset classifications in its coiled tubing asset group within its Completion Solutions segment.
6. Leases
Implementation of ASC 842
On December 31, 2020, the Company adopted ASC 842 with an effective date of January 1, 2020. The Company took advantage of various practical expedients provided by ASC 842, including:
•use of the transition package of practical expedients which, among other things, allows the Company to carry forward the historical lease classification for existing leases;
•making an accounting policy election for leases with an initial term of 12 months or less to be excluded from the Consolidated Balance Sheets; and
•electing to not separate non-lease components from lease components for all classes of underlying lease assets.
Prior to January 1, 2020, the Company accounted for leases under ASC 840. All periods previously reported under ASC 840 will continue to be reported under ASC 840, and periods beginning December 31, 2020 and after are reported under ASC 842.
The adoption of ASC 842 resulted in the recording of net operating lease right of use assets of approximately $42.8 million and operating lease obligations of approximately $44.1 million as of January 1, 2020. The cumulative effect on retained earnings was not material. The adoption of ASC 842 did not materially affect the Company’s Consolidated Statement of Income and Comprehensive Income (Loss) for the year ended December 31, 2020.
Under ASC 842, the Company determines if an arrangement is a lease at inception. Leases with an initial term of 12 months or less are not recorded in the Company’s Consolidated Balance Sheets. Lease with an initial term greater than 12 months are recognized in the Company’s Consolidated Balance Sheets based on lease classification as either operating or financing. Some of the Company’s lease agreements include lease and non-lease components for which the Company has elected to not separate for all classes of underlying assets. The Company’s lease agreements do not contain any material residual value guarantees or material restrictive covenants. The Company may sublease its real estate to third parties, subject to certain provision of the lease, when it has no future use for the property.
Operating Leases
As a lessee, the Company’s operating lease portfolio primarily consists of operating leases for equipment, vehicles, office space, yard facilities, and employee housing. Operating lease ROU assets and operating lease obligations are recognized based on the present value of the future minimum lease payments at commencement date. As most of the Company’s leases do not provide an implicit borrowing rate, the Company uses its incremental borrowing rate based on the lease information available at the commencement date in determining the present value of future payments. The incremental borrowing rate utilized is based upon the interest rate associated with the Company’s 2018 ABL Credit Facility (as defined in Note 9 - Debt Obligations) which is utilized to fund its working capital needs and planned capital expenditures. The Company’s leases have remaining terms of one to ten years and may include options to extend or terminate the lease. The operating lease ROU assets also include any upfront lease payments made and exclude lease incentives and initial direct costs incurred.
The Company leases most of these properties under long-term (greater than one year) non-cancelable term leases many of which contain renewal options that can extend the lease term from one to five years and some of which contain escalation clauses. The Company may also enter into short-term or month-to-month operating leases. Options to renew these leases are generally not considered reasonably certain to be exercised due to the nature of the Company’s operations and the markets it serves. Therefore, the periods covered by such optional periods are not included in the determination of the term of the lease.
The Company also leases supplemental equipment, typically under cancellable short-term contracts which are less than 30 days. This equipment is typically required for a specific project and for a short duration. Due to the nature of the Company’s operations, any option to renew these short-term leases is generally not considered reasonably certain to be exercised. Therefore, the periods covered by such optional periods are not included in the determination of the term of the lease, and the lease payments during these periods are similarly excluded from the calculation of operating lease asset and lease obligation balances.
Operating lease expense consists of rent expense related to leases that were included in ROU assets under ASC 842. The Company recognizes operating lease expense on a straight-line basis, except for certain variable expenses that are recognized when the variability is resolved, typically during the period in which they are paid. Variable operating lease payments typically include charges for property taxes and insurance, and some leases contain variable payments related to non-lease components, including common area maintenance and usage of facilities or office equipment (for example, copiers). The Company does not have variable expenses.
Operating leases are included in “Operating lease right of use assets, net,” “Current portion of operating lease obligations,” and “Long-term operating lease obligations” in the Company’s Consolidated Balance Sheet as of December 31, 2020.
Finance Leases
Finance leases are included in the line items “Finance lease right of use assets, net,” “Current portion of finance lease obligations,” and “Long-term finance lease obligations” in the Company’s Consolidated Balance Sheet as of December 31, 2020 and in the line items “Property and equipment, net,” “Current portion of finance lease obligations,” and “Long-term finance lease obligations” in the Company’s Consolidated Balance Sheet as of December 31, 2019.
Additional Information
The following table summarizes the components of the Company’s lease expense recognized for the year ended December 31, 2020, excluding variable lease and prepaid rent costs:
Year Ended December 31, 2020
(in thousands)
Operating lease expense
Operating lease right of use assets $ 8,897
Operating lease non right of use assets 5,795
Total operating lease expense $ 14,692
Finance lease expense
Depreciation of right of use assets $ 321
Interest on lease obligations 257
Total finance lease expense $ 578
Total rent expense for all operating leases was approximately $11.5 million for the year ended December 31, 2019.
Operating lease expense is included in the line items “Cost of revenues” and “General and administrative expenses” in the Company’s Consolidated Statements of Income and Comprehensive Income (Loss) for the years ended December 31, 2020 and 2019.
Supplemental information related to leases was as follows as of December 31, 2020:
December 31, 2020
Operating leases
Weighted average remaining lease term 7.0
Weighted average discount rate 5.0%
Finance leases
Weighted average remaining lease term 2.0
Weighted average discount rate 9.3%
Supplemental balance sheet information related to leases was as follows as of December 31, 2020:
December 31, 2020
(in thousands)
Operating lease right of use assets
Operating lease right of use assets, gross $ 43,061
Less: Accumulated amortization (6,701)
Operating lease right of use assets, net $ 36,360
Operating lease obligations
Current portion of operating lease obligations $ 6,200
Long-term operating lease obligations 32,295
Total operating lease obligations $ 38,495
Finance lease right of use assets
Finance lease right of use assets, gross $ 2,952
Less: Accumulated depreciation (1,136)
Finance lease right of use assets, net $ 1,816
Finance lease obligations
Current portion of finance lease obligations $ 1,092
Long-term finance lease obligations 1,109
Total finance lease obligations $ 2,201
Future annual minimum lease payments as of December 31, 2020 were as follows:
Operating Lease Right of Use Obligations Finance Leases Total
(in thousands)
2021 $ 7,947 $ 1,253 $ 9,200
2022 6,757 1,098 7,855
2023 6,500 66 6,566
2024 5,066 - 5,066
2025 4,481 - 4,481
Thereafter 15,050 - 15,050
Total lease payments $ 45,801 $ 2,417 $ 48,218
Less: present value discount (7,306) (216) (7,522)
Present value of lease obligations $ 38,495 $ 2,201 $ 40,696
Future annual minimum lease payments as of December 31, 2019 were as follows (in thousands):
2020 $ 10,597
2021 8,504
2022 7,485
2023 6,649
2024 4,470
Thereafter 17,105
Total lease payments $ 54,810
Supplemental cash flow information related to leases was as follows for the year ended December 31, 2020:
Year Ended December 31, 2020
(in thousands)
Cash paid for amounts included in the measurement of lease obligations:
Operating cash flows from operating leases $ 8,592
Operating cash flows from finance leases $ 321
Financing cash flows from finance leases $ (995)
Right of use assets obtained in exchange for lease obligations:
Operating leases $ 1,099
7. Goodwill and Intangible Assets
Goodwill
The changes in the net carrying amount of the components of goodwill for the years ended December 31, 2020 and 2019 were as follows:
Goodwill
Gross Value Accumulated Impairment Loss Net
(in thousands)
Balance as of December 31, 2018 $ 400,067 $ (92,263) $ 307,804
Purchase price adjustments (1)
8,665 - 8,665
Impairment - (20,273) (20,273)
Balance as of December 31, 2019 $ 408,732 $ (112,536) $ 296,196
Impairment - (296,196) (296,196)
Balance as of December 31, 2020 $ 408,732 $ (408,732) $ -
(1) The Company recorded adjustments to the fair value of goodwill in relation to its 2018 purchase of Magnum Oil Tools International, LTD, Magnum Oil Tools GP, LLC, and Magnum Oil Tools Canada Ltd. (such entities collectively, “Magnum” and such acquisition, the “Magnum Acquisition”).
Goodwill by segment for the years ended December 31, 2020 and 2019 was as follows:
Completion Solutions
2020 2019
(in thousands)
Balance as of January 1, $ 296,196 $ 307,804
Additions - -
Purchase price adjustments (1)
- 8,665
Impairment (296,196) (20,273)
Balance as of December 31, $ - $ 296,196
(1) The Company recorded adjustments to the fair value of goodwill in relation to the Magnum Acquisition.
Historically, the Company performed its annual goodwill impairment test on December 31 or when there was an indication an impairment may have occurred.
2020 Goodwill Impairment
With a significant reduction in exploration and production capital budgets and activity, primarily driven by sharp declines in global crude oil demand and an economic recession associated with the coronavirus pandemic, as well as, sharp declines in oil and natural gas prices, the outlook for expected future cash flows associated with the Company’s reporting units decreased dramatically in the first quarter of 2020. Based on these events, an indication of impairment associated with the Company’s reporting units occurred, triggering an interim goodwill impairment test of the Level 3 fair value of each reporting unit under Accounting Standards Codification 350, Intangibles - Goodwill and Other (“ASC 350”) at March 31, 2020.
As such, based on its Level 3 fair value determination in connection with the interim goodwill impairment test under ASC 350, the Company recorded goodwill impairment charges of $296.2 million in the first quarter of 2020 associated with its tools, cementing, and wireline reporting units. These charges represented a full write-off of goodwill and were due to the events described above, coupled with an increased weighted average cost of capital driven by a reduction in the Company’s stock price and the Level 2 fair value of its Senior Notes (as defined in Note 9 - Debt Obligations). These goodwill impairment charges are included in the line item “Impairment of goodwill” in the Company’s Consolidated Statement of Income and Comprehensive Income (Loss) for the year ended December 31, 2020.
2019 Goodwill Impairment
With a recent decline in exploration and production capital budgets and activity, coupled with an over-supply of new coiled tubing units, the demand for coiled tubing during the drill-out phase of the overall completions process diminished in the fourth quarter of 2019, shrinking the overall coiled tubing market. Additionally, in the fourth quarter of 2019, dissolvable plug technology became more widely adopted by operators, which significantly reduced and will potentially eliminate the need for coiled tubing drill-outs. As a consequence, the outlook for expected future cash flows in the Company’s coiled tubing reporting unit within its Completion Solutions segment reduced as the coiled tubing reporting unit’s carrying value exceeded its estimated Level 3 fair value. As such, in the fourth quarter of 2019, in connection with its annual goodwill impairment test, the Company recorded a goodwill impairment charge of $20.3 million in its coiled tubing reporting unit within its Completion Solutions segment. This goodwill impairment charge is included in the line item “Impairment of goodwill” in the Company’s Consolidated Statement of Income and Comprehensive Income (Loss) for the year ended December 31, 2019.
Intangible Assets
The gross carrying amount and accumulated amortization of intangible assets as of December 31, 2020 and 2019 were as follows:
Gross Carrying Amount Accumulated Amortization Net Carrying Amount Weighted Average Amortization Period
(in thousands, except weighted average amortization period information)
Customer relationships $ 63,270 $ (38,084) $ 25,186 5.5
Non-compete agreements 6,500 (5,366) 1,134 2.8
Technology 125,110 (19,906) 105,204 12.7
In-process research and development 1,000 - 1,000 Indefinite
Total $ 195,880 $ (63,356) $ 132,524
Gross Carrying Amount Accumulated Amortization Net Carrying Amount Weighted Average Amortization Period
(in thousands, except weighted average amortization period information)
Customer relationships $ 63,270 $ (30,734) $ 32,536 6.0
Non-compete agreements 6,500 (4,966) 1,534 3.8
Technology 125,110 (11,189) 113,921 13.6
In-process research and development 1,000 - 1,000 Indefinite
Total $ 195,880 $ (46,889) $ 148,991
2019 Indefinite-Lived Intangible Asset Impairment
With a recent decline in exploration and production capital budgets and activity, coupled with an over-supply of new coiled tubing units, the demand for coiled tubing during the drill-out phase of the overall completions process diminished in the fourth quarter of 2019, shrinking the overall coiled tubing market. Additionally, in the fourth quarter of 2019, dissolvable plug technology became more widely adopted by operators, which significantly reduced and will potentially eliminate the need for coiled tubing drill-outs. As a consequence, the outlook for expected future cash flows attributed to indefinite-lived trade names associated with the Company’s coiled tubing reporting unit within its Completion Solutions segment reduced as the trade names’ carrying value exceeded its estimated fair value. In addition, in the fourth quarter of 2019, the Company changed its marketing strategy and began the process of transitioning certain Magnum trade names to the Company’s trade names in order to better funnel and allocate resources, create a stronger identity, facilitate cross-selling, and streamline and simplify communication with existing customers. As a consequence, the outlook for expected future cash flows attributed to indefinite-lived trade names in the Company’s completion tools reporting unit within its Completion Solutions segment also reduced as the trade names’ carrying value exceeded its estimated fair value. As such, in the fourth quarter of 2019, in connection with its annual indefinite-lived intangible asset impairment test, the Company recorded an intangible asset impairment charge of $12.7 million associated with the indefinite-lived trade names in its coiled tubing reporting unit and an intangible asset impairment charge of $95.0 million associated with the indefinite-lived trade names in its completion tools reporting unit, both within its Completion Solutions segment. These indefinite-lived intangible asset impairment charges are included in the line item
“Impairment of intangibles” in the Company’s Consolidated Statement of Income and Comprehensive Income (Loss) for the year ended December 31, 2019.
2019 Definite-Lived Intangible Asset Impairment
In the fourth quarter of 2019, the Company also recorded an impairment charge of $7.1 million related to definite-lived customer relationship intangible assets in its coiled tubing asset group within its Completion Solutions segment. This definite-lived intangible asset impairment charge is included in the line item “Impairment of intangibles” in the Company’s Consolidated Statement of Income and Comprehensive Income (Loss) for the year ended December 31, 2019. For additional information on this definite-lived impairment charge, see Note 5 - Property and Equipment.
Amortization of Intangibles
Amortization of intangibles was $16.5 million and $18.4 million for the years ended December 31, 2020 and 2019, respectively.
Future estimated amortization of intangibles is as follows:
Year Ending December 31, (in thousands)
2021 $ 16,116
2022 13,463
2023 11,516
2024 11,183
2025 11,183
Thereafter 68,063
$ 131,524
8. Accrued Expenses
Accrued expenses as of December 31, 2020 and 2019 consisted of the following:
December 31,
2020 2019
(in thousands)
Accrued compensation and benefits $ 5,430 $ 7,009
Accrued interest 5,313 6,091
Accrued bonus - 5,043
Other accrued expenses 6,396 6,587
Accrued expenses $ 17,139 $ 24,730
9. Debt Obligations
The Company’s debt obligations as of December 31, 2020 and 2019 were as follows:
December 31,
2020 2019
(in thousands)
Senior Notes $ 346,668 $ 400,000
2018 ABL Credit Facility - -
Magnum Promissory Notes 1,969 -
Total debt before deferred financing costs $ 348,637 $ 400,000
Deferred financing costs (5,079) (7,941)
Total debt $ 343,558 $ 392,059
Less: Current portion of long-term debt (844) -
Long-term debt $ 342,714 $ 392,059
Senior Notes
Background
On October 25, 2018, the Company issued $400.0 million principal amount of 8.750% Senior Notes due 2023 (the “Senior Notes”). The Senior Notes were issued under an indenture, dated as of October 25, 2018 (the “Indenture”), by and among the Company, certain subsidiaries of the Company and Wells Fargo, National Association, as Trustee. The Senior Notes bear interest at an annual rate of 8.750% payable on May 1 and November 1 of each year, and the first interest payment was due on May 1, 2019. The Senior Notes are senior unsecured obligations of the Company and are fully and unconditionally guaranteed on a senior unsecured basis by each of the Company’s current domestic subsidiaries and by certain future subsidiaries.
The Indenture contains covenants that limit the Company’s ability and the ability of its restricted subsidiaries to engage in certain activities. The Company was in compliance with the provisions of the Indenture at December 31, 2020.
Upon an event of default, the trustee or the holders of at least 25% in aggregate principal amount of then outstanding Senior Notes may declare the Senior Notes immediately due and payable, except that a default resulting from certain events of bankruptcy or insolvency with respect to the Company, any restricted subsidiary of the Company that is a significant subsidiary or any group of restricted subsidiaries that, taken together, would constitute a significant subsidiary, will automatically cause all outstanding Senior Notes to become due and payable.
Unamortized deferred financing costs associated with the Senior Notes were $5.1 million and $7.9 million at December 31, 2020 and 2019, respectively. These costs are direct deductions from the carrying amount of the Senior Notes and are being amortized through interest expense through the maturity date of the Senior Notes using the effective interest method.
Extinguishment of Debt
The Company repurchased approximately $53.3 million of Senior Notes at a repurchase price of approximately $14.6 million in cash for the year ended December 31, 2020. Deferred financing costs associated with these transactions were $0.9 million for the year ended December 31, 2020. As a result, for the year ended December 31, 2020, the Company recorded a $37.8 million gain on the extinguishment of debt, which was calculated as the difference between the repurchase price and the carrying amount of the Senior Notes partially offset by the deferred financing costs. The gain on extinguishment of debt is included as a separate line item in the Company’s Consolidated Statement of Income and Comprehensive Income (Loss) for the year ended December 31, 2020.
2018 ABL Credit Facility
On October 25, 2018, the Company entered into a credit agreement dated as of October 25, 2018 (the “2018 ABL Credit Agreement”), by and among the Company, Nine Energy Canada, Inc., JP Morgan Chase Bank, N.A. as administrative agent and as an issuing lender, and certain other financial institutions party thereto as lenders and issuing lenders. The 2018 ABL Credit Agreement permits aggregate borrowings of up to $200.0 million, subject to a borrowing base, including a Canadian tranche with a sub-limit of up to $25.0 million and a sub-limit of $50.0 million for letters of credit (the “2018 ABL Credit Facility”). The 2018 ABL Credit Facility will mature on October 25, 2023 or, if earlier, on the date that is 180 days before the scheduled maturity date of the Senior Notes if they have not been redeemed or repurchased by such date.
Loans to the Company and its domestic related subsidiaries (the “U.S. Credit Parties”) under the 2018 ABL Credit Facility may be base rate loans or LIBOR loans; and loans to Nine Energy Canada Inc., a corporation organized under the laws of Alberta, Canada, and its restricted subsidiaries (the “Canadian Credit Parties”) under the Canadian tranche may be Canadian Dollar Offered Rate (“CDOR”) loans or Canadian prime rate loans. The applicable margin for base rate loans and Canadian prime rate loans vary from 0.75% to 1.25% and the applicable margin for LIBOR loans or CDOR loans vary from 1.75% to 2.25%, in each depending on the Company’s leverage ratio. In addition, a commitment fee of 0.50% per annum will be charged on the average daily unused portion of the revolving commitments.
The 2018 ABL Credit Agreement contains various affirmative and negative covenants, including financial reporting requirements and limitations on indebtedness, liens, mergers, consolidations, liquidations and dissolutions, sales of assets, dividends and other restricted payments, investments (including acquisitions), and transactions with affiliates. In addition, the 2018 ABL Credit Agreement contains a minimum fixed charge ratio covenant of 1.00 to 1.00 that is tested quarterly when the availability under the 2018 ABL Credit Facility drops below $18.75 million or a default has occurred until the availability exceeds such threshold for 30 consecutive days and such default is no longer outstanding. The Company was in compliance with all covenants under the 2018 ABL Credit Agreement as of December 31, 2020.
All of the obligations under the 2018 ABL Credit Facility are secured by first priority perfected security interests (subject to permitted liens) in substantially all of the personal property of U.S. Credit Parties, excluding certain assets. The obligations under the Canadian tranche are further secured by first priority perfected security interests (subject to permitted liens) in substantially all of the personal property of Canadian Credit Parties, excluding certain assets. The 2018 ABL Credit Facility is guaranteed by the U.S. Credit Parties, and the Canadian tranche is further guaranteed by the Canadian Credit Parties and the U.S. Credit Parties.
At December 31, 2020, the Company’s availability under the 2018 ABL Credit Facility was approximately $37.9 million, net of outstanding letters of credit of $0.5 million.
Magnum Promissory Notes
On October 25, 2018, pursuant to the terms of a Securities Purchase Agreement, dated October 15, 2018 (as amended on June 7, 2019, the “Magnum Purchase Agreement”), the Company acquired all of the equity interests of Magnum. The Magnum Purchase Agreement included the potential for additional future payments in cash of (i) up to 60% of net income (before interest, taxes, and certain gains or losses) for the “E-Set” tools business in 2019 through 2026 and (ii) up to $25.0 million based on sales of certain dissolvable plug products in 2019 (the “Magnum Earnout”).
On June 30, 2020, pursuant to an amendment to the Magnum Purchase Agreement to terminate the remaining Magnum Earnout and all obligations related thereto (the “Magnum Purchase Agreement Amendment”), the Company issued promissory notes with an aggregated principal amount of $2.3 million (the “Magnum Promissory Notes”) to the sellers of Magnum. The Magnum Promissory Notes bear interest at a rate of 6.0% per annum. The principal amount of the Magnum Promissory Notes will be paid in equal quarterly installments beginning January 1, 2021. The entire unpaid principal amount will be due and payable on the maturity date, which is the earlier of October 1, 2022 and the business day after the date on which the Company sells, transfers or otherwise disposes of the “E-Set” tools business to an unaffiliated third party, unless such sale, transfer or disposition is made, directly or indirectly, as part of the sale, transfer or disposition of the Dissolvable Plugs Business or due to the occurrence of a Change of Control Event (each as defined in the Magnum Purchase Agreement).
For additional information regarding the termination of the Magnum Earnout, see Note 12 - Commitments and Contingencies.
Fair Value of Debt Instruments
The estimated fair value of the Company’s debt obligations as of December 31, 2020 and 2019 was as follows:
December 31,
2020 2019
(in thousands)
Senior Notes $ 156,001 $ 324,000
2018 ABL Credit Facility $ - $ -
Magnum Promissory Notes $ 1,969 $ -
The fair value of the Senior Notes, 2018 ABL Credit Facility, and the Magnum Promissory Notes is classified as Level 2 in the fair value hierarchy. The fair value of the Senior Notes is established based on observable inputs in less active markets. The fair value of the 2018 ABL Credit Facility and the Magnum Promissory Notes approximates their carrying value.
10. Defined Contribution Plans
Background
Nine and Magnum sponsored defined contribution plans under Section 401(k) of the Internal Revenue Code of 1986, as amended, for all qualified employees.
Effective January 1, 2019, under the Nine Energy Service 401(k) Plan (the “Nine Plan”), employee contributions were matched by the Company at 100% of the first 5% of the participant’s eligible compensation. Effective April 1, 2019, the Magnum Oil Tools International Ltd. Profit Sharing & 401(k) Plan (the “Magnum Plan”) merged with the Nine Plan. Prior to the merger, under the Magnum Plan, the Company had matched employee contributions at 100% of the first 3% and 50% of the remaining up to 5% of the participant’s eligible compensation.
Effective April 25, 2020, Nine suspended its matching contributions for employees.
Contributions
For the year ended December 31, 2020, the Company made employer contributions of $1.4 million under the Nine Plan.
For the year ended December 31, 2019, the Company made employer contributions of $4.8 million under the Nine Plan and no contributions under the Magnum Plan
11. Stock-based Compensation
Stock Options
Information about stock option activity during the years ended December 31, 2020 and 2019 was as follows:
2020 Activity Number of
Shares in
Underlying
Options Weighted
Average
Exercise Price Remaining
Weighted Average
Contractual Life
in Years Intrinsic Value
(in thousands)
Beginning balance 816,427 $ 32.51 5.8 $ -
Granted - - - -
Exercised - - - -
Forfeited (466) 31.18 - -
Expired (113,419) 31.78 - -
Total outstanding 702,542 $ 32.63 4.5 $ -
Options exercisable 702,542 $ 32.63 4.5 $ -
2019 Activity Number of
Shares in
Underlying
Options Weighted
Average
Exercise Price Remaining
Weighted Average
Contractual Life
in Years Intrinsic Value
(in thousands)
Beginning balance 957,659 $ 31.98 6.9 $ 6
Granted - - - -
Exercised (674) 22.63 - 2
Forfeited (28,050) 30.18 - -
Expired (112,508) 28.66 - -
Total outstanding 816,427 $ 32.51 5.8 $ -
Options exercisable 704,944 $ 32.99 5.5 $ -
The intrinsic value at December 31, 2020 and 2019 is the amount by which the fair value of the underlying share exceeds the exercise price of an option as of December 31, 2020 and 2019, respectively.
The Company granted no options in 2020 and 2019.
Compensation expense recorded was approximately $0.3 million and $1.8 million for the years ended December 31, 2020 and 2019, respectively. As of December 31, 2020, there is no remaining compensation expense related to options for the Company to expense. Future stock option grants will result in additional compensation expense.
Restricted Stock and Restricted Stock Units
Information about restricted stock and restricted stock unit activity during the years ended December 31, 2020 and 2019 was as follows:
2020 2019
Nonvested at January 1, 1,208,625 1,017,945
Granted 1,383,059 666,173
Vested (641,658) (292,326)
Cancelled (235,628) (183,167)
Nonvested at December 31, 1,714,398 1,208,625
The weighted-average grant date fair value of the restricted stock and restricted stock units granted was $0.85 and $22.31 during the years ended December 31, 2020 and 2019, respectively. The total amount of compensation expense related to the restricted stock and restricted stock units recorded was approximately $9.0 million and $11.7 million for the years ended December 31, 2020 and 2019, respectively. As of December 31, 2020, the Company expects to record compensation expense related to restricted stock and restricted stock units of approximately $5.5 million over the remaining term of approximately 1.2 years. Future restricted stock and restricted stock unit grants will result in additional compensation expense.
Performance Stock Units
The Company granted performance stock units (“PSUs”) in 2019. The number of PSUs that will vest is contingent upon the Company’s achievement of certain specified targets. These awards have market conditions and were valued using a Monte Carlo simulation model.
The volatility of 49.7% was developed based upon the historical volatility of the Company as well as the volatilities of a group of peer companies, as the Company’s trading history needed to be supplemented with additional data as it went public in 2018. The risk-free rate, which was derived using the United States’ Treasury security rates at the grant date, was 2.44%.
2020 2019
Nonvested at January 1, 61,900 -
Granted (1)
- 61,900
Vested - -
Cancelled - -
Nonvested at December 31, 61,900 61,900
(1) The Company granted PSUs in 2019 that will vest contingent upon the Company’s achievement of certain specified targets. The number of PSUs in the table reflects the target level of PSUs.
The Company did not grant PSUs in 2020.
The total amount of compensation expense related to PSUs was approximately $0.5 million for both the years ended December 31, 2020 and 2019. As of December 31, 2020, the Company expects to record compensation expense related to PSUs of approximately $0.6 million over the remaining term of approximately 1.0 year. Future PSU grants will result in additional compensation expense.
12. Commitments and Contingencies
Litigation
From time to time, the Company has various claims, lawsuits, and administrative proceedings that are pending or threatened with respect to personal injury, workers’ compensation, contractual matters, and other matters. Although no assurance can be given with respect to the outcome of these claims, lawsuits, or proceedings or the effect such outcomes may have, the Company believes any ultimate liability resulting from the outcome of such claims, lawsuits, or administrative proceedings, to the extent not otherwise provided for or covered by insurance, will not have a material adverse effect on its business, operating results, or financial condition.
Self-insurance
The Company uses a combination of third-party insurance and self-insurance for health insurance claims. The self-insured liability represents an estimate of the undiscounted ultimate cost of uninsured claims incurred as of the balance sheet date. The estimate is based on an analysis of trailing months of incurred medical claims to project the amount of incurred but not reported claims liability. The estimated liability for self-insured medical claims was $1.3 million and $1.8 million at December 31, 2020 and 2019, respectively, and is included under the caption “Accrued expenses” on the Company’s Consolidated Balance Sheets.
Although the Company does not expect the amounts ultimately paid to differ significantly from the estimates, the self-insurance liability could be affected if future claims experience differs significantly from historical trends and actuarial assumptions.
Contingent Liabilities
The Company’s contingent liabilities (Level 3) for the years ended December 31, 2020 and 2019 were as follows:
Magnum Frac Tech Total
(in thousands)
Balance at January 1, 2019 $ 24,521 $ 1,008 $ 25,529
Payments - (374) (374)
Revaluation adjustments (21,912) 725 (21,187)
Balance at January 1, 2020 $ 2,609 $ 1,359 $ 3,968
Payments (1,125) (265) (1,390)
Revaluation adjustments 766 (490) 276
Termination (2,250) - (2,250)
Balance at December 31, 2020 $ - $ 604 $ 604
The contingent consideration related to the contingent liabilities is reported at fair value, based on a Monte Carlo simulation model. Significant inputs used in the fair value measurement include estimated gross margin related to forecasted sales of the plugs, term of the agreement, and a risk adjusted discount factor. Contingent liabilities include $0.2 million and $0.4 million reported in “Accrued expenses” at December 31, 2020 and 2019, respectively, and $0.4 million and $3.6 million reported in “Other long-term liabilities” at December 31, 2020 and 2019, respectively, in the Company’s Consolidated Balance Sheets. The impact of the revaluation adjustments is included in the Company’s Consolidated Statements of Income and Comprehensive Income (Loss).
Magnum Earnout
The Magnum Purchase Agreement included the potential for additional future payments in cash of (i) up to 60% of net income (before interest, taxes, and certain gains or losses) for the “E-Set” tools business in 2019 through 2026 and (ii) up to $25.0 million based on sales of certain dissolvable plug products in 2019.
In 2019, the Company did not meet the sales requirement of certain dissolvable plug products during the year.
Pursuant to the Magnum Purchase Agreement Amendment, which terminated the remaining Magnum Earnout and all obligations related thereto, the Company made a cash payment of $1.1 million and issued the Magnum Promissory Notes with an aggregated principal amount of $2.3 million to the sellers of Magnum. For additional information regarding the Magnum Promissory Notes, see Note 9 - Debt Obligations.
Frac Tech Earnout
On October 1, 2018, pursuant to the terms and conditions of a Securities Purchase Agreement (“the Frac Tech Purchase Agreement”), the Company acquired Frac Technology AS, a Norwegian private limited company (“Frac Tech”) focused on the development of downhole technology, including a casing flotation tool and a number of patented downhole completion tools. The Frac Tech Purchase Agreement, as amended, includes, among other things, the potential for additional future payments, based on certain Frac Tech revenue metrics through December 31, 2025.
13. Taxes
The components of the provision (benefit) for income taxes for the years ended December 31, 2020 and 2019 were as follows:
Year Ended December 31,
2020 2019
(in thousands)
Current
U.S. federal $ (874) $ (22)
U.S. state 4 452
Foreign - 10
Total current provision (benefit) $ (870) $ 440
Deferred
U.S. federal $ (1,122) $ (4,276)
U.S. state (466) (51)
Foreign - -
Total deferred benefit (1,588) (4,327)
Total benefit for income taxes $ (2,458) $ (3,887)
The provision (benefit) for income taxes for the years ended December 31, 2020 and 2019 differed from the provision (benefit) calculated using the applicable statutory federal income tax rate as follows:
Year Ended December 31,
2020 2019
(in thousands)
Tax benefit at statutory rate $ (80,095) $ (46,544)
Foreign rate differential (117) (364)
State income taxes, net of federal benefit (463) 306
Nondeductible expenses 608 1,057
Impact from goodwill impairment 5,036 -
Valuation allowance 70,387 40,480
Other 2,186 1,178
Total benefit for income taxes $ (2,458) $ (3,887)
The tax effects of the cumulative temporary differences resulting in the net deferred tax asset (liabilities) at December 31, 2020 and 2019 were as follows:
December 31,
2020 2019
(in thousands)
Deferred income tax assets:
Inventories $ 2,990 $ 2,094
Goodwill and intangible assets 90,829 34,092
Deferred tax benefit from net losses 63,844 38,501
Stock-based compensation 5,564 5,976
Tax credit carryforwards 680 680
Accrued expenses 2,142 2,763
Interest carryover 553 3,459
Lease liability 8,607 -
Other 165 163
Total deferred income tax assets 175,374 87,728
Less: Valuation allowance (157,703) (79,912)
Net deferred income tax assets $ 17,671 $ 7,816
Deferred income tax liabilities:
Property and equipment $ (9,283) $ (9,404)
ROU asset (8,388) -
Total deferred income tax liabilities (17,671) (9,404)
Net deferred income tax liability $ - $ (1,588)
As of December 31, 2020, the Company had federal and state net operating loss carryforwards (“NOLs”) of approximately $345.0 million. The federal NOLs related to tax years 2017 and prior can be used for a 20-year period and, if unused, will begin to expire in 2034. The state NOLs can be used from 10 to 20 years and vary by state. A small portion of state NOLs will begin to expire in 2023.
The Company evaluates its deferred tax assets on a quarterly basis to determine whether a valuation allowance is required. The Company assesses whether a valuation allowance should be established based on its determination of whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible and prior to the expiration of its NOL and tax credit carryforwards. The Company considers the scheduled reversal of deferred tax liabilities, projected future taxable income, and tax planning strategies in making this assessment. Due to recent operating results, the Company continues to be in a three-year cumulative loss position for the year ended December 31, 2020. According to FASB ASC 740, cumulative losses in recent years represent significant negative evidence in considering whether deferred tax assets are realizable. As a result, the Company continues to record a valuation allowance against its United States’ domestic and Canadian deferred tax assets. The 2020 results include an increase in the Company’s valuation allowance of approximately $77.8 million primarily due to the goodwill impairment recorded during the year. If the Company is able to generate sufficient taxable income in the future, and it becomes more likely than not that the Company will be able to fully utilize the net deferred tax assets on which a valuation allowance was recorded, the allowance will be released resulting in a potential decrease to its effective tax rate.
The Company is subject to United States’ federal income tax as well as income tax in multiple state jurisdictions. The earliest period the Company is subject to examination of federal income tax returns by the Internal Revenue Service is 2017. The state income tax returns and other state tax filings of the Company are subject to examination by the state taxing authorities for various periods, generally up to four years after they are filed.
The Company accounts for uncertain tax positions in accordance with guidance in ASC 740, which prescribes the minimum recognition threshold a tax position taken or expected to be taken in a tax return is required to meet before being recognized in the financial statements. A reconciliation of the beginning and ending amount of uncertain tax positions is as follows:
(in thousands)
Balance at January 1, $ 568
Additional based on tax positions related to prior years -
Additional based on tax positions related to current year 211
Reduction based on tax positions related to prior years -
Lapse of statute of limitations -
Balance at December 31, $ 779
The total amount of unrecognized tax benefits at December 31, 2020 was $0.8 million. The total balance of unrecognized tax benefit would impact the Company’s future effective income tax rate if recognized. The Company recognizes interest and penalties related to uncertain tax positions within the provision for income taxes in its Consolidated Statements of Income and Comprehensive Income (Loss). As of December 31, 2020, no interest and penalties have been accrued.
14. Earnings (Loss) Per Share
Basic earnings (loss) per share is computed by dividing net income (loss) by the weighted average number of common shares outstanding for the period. Diluted earnings (loss) per share is based on the weighted average number of shares outstanding during each period and the exercise of potentially dilutive stock options assumed to be purchased from the proceeds using the average market price of the Company’s stock for each of the periods presented as well as the potentially dilutive restricted stock, restricted stock units, and performance stock units.
Basic and diluted earnings (loss) per common share was computed as follows:
2020 2019
(in thousands, except for share and per share amounts)
Net loss $ (378,948) $ (217,751)
Average shares outstanding 29,744,830 29,308,107
Loss per share (basic and diluted) $ (12.74) $ (7.43)
The diluted earnings per share calculation excludes all stock options, unvested restricted stock, unvested restricted stock units, and unvested performance stock units for 2020 and 2019 because there is a net loss for each period and their inclusion would be anti-dilutive. The average number of securities that were excluded from diluted earnings (loss) per share that would potentially dilute earnings (loss) per share for the periods in which the Company experienced a net loss were as follows:
2020 2019
Year ended December 31, 753,609 100,383
15. Related Party Transactions
As part of the acquisition of Crest Pumping Technologies, LLC (“Crest”) in 2014, the Company issued promissory notes totaling $9.4 million to former owners of Crest, including David Crombie, who is an executive officer of the Company. The principal was due on June 30, 2019. The interest rate was based on the prime rate, the federal funds rate, or LIBOR, plus a margin to be determined in connection with the Company’s credit agreement and was due quarterly. Mr. Crombie paid $1.8 million during 2016 to pay his promissory note in full. At December 31, 2018, the outstanding principal balance of the notes of the remaining individuals totaled $7.6 million and unpaid interest, included in “Prepaid expenses and other current assets” in the Company’s Consolidated Balance Sheets, totaled $10,000. During the second quarter of 2019, the Company received the full principal balance of the notes outstanding as well as all unpaid interest.
The Company leases office space, yard facilities, and equipment and purchases building maintenance services from entities owned by Mr. Crombie. Total lease expense and building maintenance expense associated with these entities was $0.8 million for both the years ended December 31, 2020 and 2019. The Company also purchased equipment of $1.6 million and $1.4 million for the years ended December 31, 2020 and 2019, respectively, from an entity in which Mr. Crombie is a limited partner. There were outstanding payables due to this entity relating to equipment purchases of $0.2 million and $0.1 million at December 31, 2020 and 2019, respectively.
In addition, the Company leases office space in Corpus Christi and Midland, Texas from an entity affiliated with Warren Lynn Frazier, a beneficial owner of more than 5% of the Company’s stock. In the third quarter of 2020, another entity affiliated with Mr. Frazier began to sub-lease a portion of such space in Corpus Christi, Texas from the Company. Total rental expense associated with this office space, net of sub-leasing income, was $1.3 million and $1.5 million for the years ended December 31, 2020 and 2019, respectively. There were net outstanding payables due to the entity of $0.1 million at December 31, 2020. Additionally, on June 30, 2020, the Company issued the Magnum Promissory Notes to the sellers of Magnum, including Mr. Frazier. At December 31, 2020, the outstanding principal balance payable to Mr. Frazier was $1.9 million. For additional information regarding the Magnum Promissory Notes, see Note 9 - Debt Obligations.
The Company purchases cable for its wireline trucks from an entity owned by Forum Energy Technologies (“Forum”). Two of the Company’s directors also serve as directors of Forum. The Company was billed $0.5 million and $1.9 million for cable during the years ended December 31, 2020 and 2019, respectively. There were outstanding payables due to the entity of $0.1 million and $0.3 million at December 31, 2020 and 2019, respectively. The Company purchases coiled tubing string from another entity owned by Forum. The Company was billed $4.6 million and $8.0 million for coiled tubing string during the years ended December 31, 2020 and 2019, respectively. There were outstanding payables due to the entity of $0.9 million at both December 31, 2020 and 2019.
The Company purchases chemical additives used in cementing from Select Energy Services, Inc. (“Select”). One of the Company’s directors also serves as a director of Select. The Company was billed $1.2 million and $2.1 million for chemicals during the years ended December 31, 2020 and 2019, respectively. There were outstanding payables due to this entity of $0.2 million and $0.1 million at December 31, 2020 and 2019, respectively.
The Company provides products and rentals to National Energy Reunited Corp. (“NESR”), where one of the Company’s directors serves as a director. The Company billed NESR $1.6 million for products and rentals and issued credit memos of $0.5 million during the year ended December 31, 2020. The Company billed NESR $0.9 million during the year ended December 31, 2019, and additionally, during the fourth quarter of 2019, the Company sold coiled tubing equipment for $5.9 million to NESR with payments due in 24 monthly equal installments beginning on January 31, 2020. Total outstanding receivables due to the Company from NESR (inclusive of the equipment sale above) were $3.7 million and $6.8 million at December 31, 2020 and 2019, respectively.
On June 5, 2019, Ann G. Fox, President and Chief Executive Officer and a director of the Company, was elected as a director of Devon Energy Corporation (“Devon”). The Company generated revenue from Devon of $5.8 million and $18.4 million for the years ended December 31, 2020 and 2019, respectively. There were outstanding receivables due from Devon of $0.4 million and $1.0 million at December 31, 2020 and 2019, respectively.
16. Segment Information
On August 30, 2019, the Company sold its Production Solutions segment to Brigade. Prior to its sales of the Production Solutions segment, the Company reported its results in two segments, the Completion Solutions segment and the Production Solutions segment. As a result of the Company’s sale of its Production Solutions segment, the Company considers the Completion Solutions segment to be its operating and reporting segment. This segmentation is representative of the manner in which the Chief Operating Decision Maker (“CODM”) and its Board of Directors view the business in allocating resources and measuring financial performance. The Company considers the CODM to be its Chief Executive Officer.
Financial data through the sales of the Production Solutions segment is reported below for the Production Solutions segment. The amounts labeled “Corporate” relate to assets or capex not allocated to either the Completion Solutions segment or the Production Solutions segment.
Year Ended December 31,
2020 2019
(in thousands)
Revenues
Completion Solutions $ 310,851 $ 774,665
Production Solutions - 58,272
$ 310,851 $ 832,937
Cost of revenues (exclusive of depreciation and amortization shown separately below)
Completion Solutions $ 302,157 $ 620,125
Production Solutions - 49,854
$ 302,157 $ 669,979
Adjusted gross profit
Completion Solutions $ 8,694 $ 154,540
Production Solutions - 8,418
$ 8,694 $ 162,958
General and administrative expenses 49,346 81,327
Depreciation 32,431 50,544
Amortization of intangibles 16,467 18,367
Impairment of goodwill 296,196 20,273
Impairment of intangibles - 114,804
Impairment of property and equipment - 66,200
(Gain) loss on revaluation of contingent liabilities 276 (21,187)
Loss on sale of subsidiaries - 15,896
Gain on sale of property and equipment (2,857) (538)
Loss from operations $ (383,165) $ (182,728)
Interest expense 36,759 39,770
Interest income (615) (860)
Gain on extinguishment of debt (37,841) -
Other income (62) -
Loss before income taxes $ (381,406) $ (221,638)
Benefit for income taxes (2,458) (3,887)
Net loss $ (378,948) $ (217,751)
Capital expenditures by segment for years ended December 31, 2020 and 2019 were as follows:
Year Ended December 31,
2020 2019
(in thousands)
Completion Solutions $ 10,147 $ 59,231
Production Solutions - 2,790
Corporate 7 93
$ 10,154 $ 62,114
Total assets by segment as of December 31, 2020 and 2019 were as follows:
December 31,
2020 2019
(in thousands)
Completion Solutions $ 358,128 $ 739,142
Corporate 84,472 111,753
$ 442,600 $ 850,895
Revenue by country for the years ended December 31, 2020 and 2019 were as follows:
Year Ended December 31, 2020 Year Ended December 31, 2019
Amount Percentage Amount Percentage
(in thousands) (in thousands)
United States $ 309,206 99.5 % $ 814,639 97.8 %
Canada 1,645 0.5 % 18,298 2.2 %
$ 310,851 100.0 % $ 832,937 100.0 %
Long-lived assets (defined as property and equipment and definite-lived intangible assets) by country as of December 31, 2020 and 2019 were as follows:
December 31,
2020 2019
(in thousands)
United States $ 231,294 $ 271,791
Canada and other 2,659 4,804
$ 233,953 $ 276,595

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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None.

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ITEM 9A. CONTROLS AND PROCEDURES
Item 9A. Controls and Procedures
Evaluation of Disclosure Controls and Procedures
Disclosure controls and procedures are controls and other procedures that are designed to ensure that information required to be disclosed by an issuer in the reports the issuer files or submits under the Exchange Act is recorded, processed, summarized, and reported within the time period specified in the rules and forms of the SEC. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by an issuer in reports filed or submitted under the Exchange Act is accumulated and communicated to the issuer’s management, including its principal executive and financial officers, as appropriate to allow timely decisions regarding required disclosure.
As required by Rule 13a-15(b) under the Exchange Act, our management, with the participation of our principal executive officer and principal financial officer, has evaluated the effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of December 31, 2020. Based upon that evaluation, our principal executive officer and principal financial officer concluded that our disclosure controls and procedures were effective as of December 31, 2020.
Management’s Report on Internal Control Over Financial Reporting
Our management is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rule 13a-15(f) and Rule 15d-15(f) under the Exchange Act). Our internal control over financial reporting is a process designed under the supervision of our principal executive officer and principal financial officer, and effected by our board of directors, management, and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of our financial statements for external purposes in accordance with GAAP.
As of December 31, 2020, our management assessed the effectiveness of our internal control over financial reporting based on the criteria for effective internal control over financial reporting established by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”) in Internal Control-Integrated Framework (2013). Based on its assessment using the COSO criteria, management has concluded that our internal control over financial reporting was effective as of December 31, 2020.
Remediation of Previously Reported Material Weakness in our Internal Control Over Financial Reporting
As reported in Item 9A of Part II of our Annual Report on Form 10-K for the year ended December 31, 2019, we did not design and maintain adequate controls to address the segregation of certain accounting duties related to journal entries, account reconciliations, and other accounting functions. Certain accounting personnel had the ability to prepare and post journal entries, as well as reconcile accounts, without an independent review by someone other than the preparer. Specifically, our internal controls were not designed or operating effectively to evidence that journal entries were appropriately recorded or were properly reviewed for validity, accuracy, and completeness. Immaterial misstatements were identified related to the inadequate segregation of accounting duties. This material weakness could have resulted in misstatement of the aforementioned accounts and disclosures that would result in a material misstatement in our annual or interim consolidated financial statements that would not have been prevented or detected on a timely basis.
In response to the material weakness described above, our management has dedicated significant time and effort to improve our internal control over financial reporting and develop a detailed action plan to fully remediate the material weakness, as follows:
•Replaced the less sophisticated accounting systems used by the majority of our newly acquired subsidiaries with the enterprise resource planning system used by the majority of our existing subsidiaries.
•Hired additional resources, including an experienced Internal Audit Director to lead our internal audit department, with responsibility for direction and oversight of all internal audit functions.
•Completed a comprehensive risk assessment of the design of internal controls, including the implementation of new internal controls as needed to ensure the segregation of certain accounting duties related to journal entries, account reconciliations, and other accounting functions.
•Designed and implemented a monitoring control that captures key roles and responsibilities within our enterprise resource planning system with consideration of mitigating business process controls designed to reduce the risk of material misstatement related to inadequate segregation of certain accounting duties related to journal entries, account reconciliations, and other accounting functions.
•Removed access for certain accounting personnel to create and post journal entries and designed and implemented an internal control which has enforced a review of all journal entries by individuals without the ability to create and post.
•Instituted additional training programs for appropriate personnel regarding the application of our enterprise resource planning system.
We have completed the documentation, implementation, and testing of the corrective actions described above and, as of December 31, 2020, have concluded that the steps taken have remediated the material weakness related to the segregation of certain accounting duties related to journal entries, account reconciliations, and other accounting functions.
Attestation Report of the Independent Registered Public Accounting Firm
This Annual Report does not include an attestation report of our independent registered public accounting firm regarding internal control over financial reporting as we are an “emerging growth company” as defined under the JOBS Act. In addition, management’s report on internal control over financial reporting was not subject to attestation by our independent registered public accounting firm pursuant to rules of the SEC that permit us to provide only management’s report in this Annual Report.
Changes in Internal Control over Financial Reporting
There have been no changes in our internal control over financial reporting that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting during the quarterly period ended December 31, 2020.

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ITEM 9B. OTHER INFORMATION
Item 9B. Other Information
None.
PART III

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ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
Item 10. Directors, Executive Officers and Corporate Governance
The information required in response to this Item will be set forth in our definitive proxy statement for the 2021 annual meeting of stockholders and is incorporated herein by reference.

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ITEM 11. EXECUTIVE COMPENSATION
Item 11. Executive Compensation
The information required in response to this Item will be set forth in our definitive proxy statement for the 2021 annual meeting of stockholders and is incorporated herein by reference.

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ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
The information required in response to this Item will be set forth in our definitive proxy statement for the 2021 annual meeting of stockholders and is incorporated herein by reference.

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ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Item 13. Certain Relationships and Related Transactions, and Director Independence
The information required in response to this Item will be set forth in our definitive proxy statement for the 2021 annual meeting of stockholders and is incorporated herein by reference.

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ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
Item 14. Principal Accountant Fees and Services
The information required in response to this Item will be set forth in our definitive proxy statement for the 2021 annual meeting of stockholders and is incorporated herein by reference.
PART IV

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ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
Item 15. Exhibits and Financial Statement Schedules
(a) Documents Filed as Part of This Annual Report
1. Financial Statements
The following consolidated financial statements of the Company are filed as a part of this Annual Report:
Report of Independent Registered Public Accounting Firm
Consolidated Balance Sheets as of December 31, 2020 and 2019
Consolidated Statements of Income and Comprehensive Income (Loss) for the Years Ended December 31, 2020 and 2019
Consolidated Statements of Changes in Shareholders’ Equity for the Years Ended December 31, 2020 and 2019
Consolidated Statements of Cash Flows for the Years Ended December 31, 2020 and 2019
Notes to Consolidated Financial Statements
2. Financial Statement Schedules
All financial statement schedules have been omitted because they are not applicable, or the required information is presented in the consolidated financial statements and related notes.
3. Exhibits
The exhibits to this Annual Report required to be filed pursuant to Item 15(b) are listed below.
Exhibit
Number Description
2.1† Securities Purchase Agreement, dated as of October 15, 2018, by and among Warren Lynn Frazier, Garrett Lynn Frazier 2018 DG Trust, Derrick Chase Frazier 2018 DG Trust, Frazier Family Foundation, Inc., as sellers, Warren Lynn Frazier, solely in his capacity as seller representative, MOTI Holdco, LLC and Nine Energy Canada Inc., as buyers, Nine Energy Service, Inc. and certain other parties named therein (Incorporated by reference to Exhibit 2.1 of Nine Energy Service, Inc.’s Current Report on Form 8-K filed on October 15, 2018).
2.2 First Amendment to Securities Purchase Agreement, dated June 7, 2019, by and among Warren Lynn Frazier, Garrett Lynn Frazier 2018 DG Trust, Derrick Chase Frazier 2018 DG Trust, and Frazier Family Foundation, Inc., as sellers, MOTI Holdco, LLC and Nine Energy Canada Inc., as buyers, and Nine Energy Service, Inc. (Incorporated by reference to Exhibit 2.2 of Nine Energy Service, Inc.’s Quarterly Report on Form 10-Q filed August 12, 2019).
2.3 Second Amendment to Securities Purchase Agreement, dated June 30, 2020, by and among Warren Lynn Frazier, Garrett Lynn Frazier 2018 DG Trust, Derrick Chase Frazier 2018 DG Trust, and Frazier Family Foundation, Inc. as sellers, MOTI Holdco, LLC and Nine Energy Canada Inc., as buyers, and Nine Energy Service, Inc. (Incorporated by reference to Exhibit 2.1 of Nine Energy Service, Inc.’s Quarterly Report on Form 10-Q filed August 7, 2020).
2.4†^ Membership Interest Purchase Agreement, dated August 30, 2019, by and between Brigade Energy Services LLC and Nine Energy Service, Inc. (Incorporated by reference to Exhibit 2.1 of Nine Energy Service, Inc.’s Current Report on Form 8-K filed on September 6, 2019).
3.1 Third Amended and Restated Certificate of Incorporation of Nine Energy Service, Inc., dated January 23, 2018 (Incorporated by reference to Exhibit 3.1 of Nine Energy Service, Inc.’s Current Report on Form 8-K filed on January 23, 2018).
3.2 Fourth Amended and Restated Bylaws of Nine Energy Service, Inc., dated January 23, 2018 (Incorporated by reference to Exhibit 3.2 of Nine Energy Service, Inc.’s Current Report on Form 8-K filed on January 23, 2018).
4.1 Form of Common Stock Certificate (Incorporated by reference to Exhibit 4.1 of Nine Energy Service, Inc.’s Amendment No. 2 to Registration Statement on Form S-1 filed on May 24, 2017).
4.2 Second Amended and Restated Stockholders Agreement, dated as of February 28, 2017, by and among Nine Energy Service, Inc. and the parties thereto (Incorporated by reference to Exhibit 4.2 of Nine Energy Service, Inc.’s Amendment No. 2 to Registration Statement on Form S-1 filed on May 24, 2017).
4.3 First Amendment to Second Amended and Restated Stockholders Agreement, dated as of July 24, 2017, by and among Nine Energy Service, Inc. and the parties thereto (Incorporated by reference to Exhibit 4.3 of Nine Energy Service, Inc.’s Amendment No. 3 to Registration Statement on Form S-1 filed on August 14, 2017).
4.4 Indenture, dated as of October 25, 2018, by and among Nine Energy Service, Inc., the guarantors party thereto and Wells Fargo Bank, National Association, as trustee (including Form of Note) (Incorporated by reference to Exhibit 4.1 of Nine Energy Service, Inc.’s Current Report on Form 8-K filed on October 26, 2018).
4.5 Supplemental Indenture and Guarantee, dated as of November 23, 2018, by and among MOTI Holdco, LLC, Magnum Oil Tools GP, LLC, and Magnum Oil Tools International, LTD, Nine Energy Service, Inc. and certain other subsidiaries and Wells Fargo Bank, National Association, as a trustee (Incorporated by reference to Exhibit 4.5 of Nine Energy Service, Inc.’s Annual Report on Form 10-K filed on March 7, 2019).
4.6 Registration Rights Agreement, dated as of October 25, 2018, by and among Nine Energy Service, Inc., the former owners of the equity interests of Magnum Oil Tools International, LTD, Magnum Oil Tools Canada Ltd. and Magnum Oil Tools GP, LLC and the other holders that may become party thereto from time to time (Incorporated by reference to Exhibit 4.2 of Nine Energy Service, Inc.’s Current Report on Form 8-K filed on October 26, 2018).
4.7 Description of Common Stock (Incorporated by reference to Exhibit 4.7 of Nine Energy Service, Inc.’s Annual Report on Form 10-K filed on March 10, 2020).
10.1 Credit Agreement, dated as of October 25, 2018, by and among Nine Energy Service, Inc., Nine Energy Canada Inc., JPMorgan Chase Bank, N.A. and certain other financial institutions (Incorporated by reference to Exhibit 10.1 of Nine Energy Service, Inc.’s Current Report on Form 8-K filed on October 26, 2018).
10.2+ Form of Indemnification Agreement between Nine Energy Service, Inc. and its directors and certain officers (Incorporated by reference to Exhibit 10.10 of Nine Energy Service, Inc.’s Amendment No. 2 to Registration Statement on Form S-1 filed on May 24, 2017).
10.3+ Nine Energy Service, Inc. 2011 Stock Incentive Plan, as amended and restated effective February 28, 2017 (Incorporated by reference to Exhibit 10.10 of Nine Energy Service, Inc.’s Registration Statement on Form S-1 filed on May 2, 2017).
10.4+ Form of Nine Energy Service, Inc. Restricted Stock Agreement for Executives (Incorporated by reference to Exhibit 10.1 of Nine Energy Service, Inc.’s Quarterly Report on Form 10-Q filed on May 14, 2018).
10.5+ Form of Nine Energy Service, Inc. Nonstatutory Stock Option Agreement for Executives (Incorporated by reference to Exhibit 10.2 of Nine Energy Service, Inc.’s Quarterly Report on Form 10-Q filed on May 14, 2018).
10.6+ Form of Nine Energy Service, Inc. Restricted Stock Agreement for Non-Employee Directors (Incorporated by reference to Exhibit 10.3 of Nine Energy Service, Inc.’s Quarterly Report on Form 10-Q filed on May 14, 2018).
10.7+ Form of Nine Energy Service, Inc. Nonstatutory Stock Option Agreement for Non-Employee Directors (Incorporated by reference to Exhibit 10.4 of Nine Energy Service, Inc.’s Quarterly Report on Form 10-Q filed on May 14, 2018).
10.8+ Form of Nine Energy Service, Inc. Performance Share Unit Grant Notice and Form of Performance Share Unit Agreement (Incorporated by reference to Exhibit 10.1 of Nine Energy Service, Inc.’s Quarterly Report on Form 10-Q filed on May 8, 2019).
10.9+ Amended and Restated Employment Agreement, dated August 28, 2018, by and between Nine Energy Service, LLC and Ann G. Fox (Incorporated by reference to Exhibit 10.1 of Nine Energy Service, Inc.’s Current Report on Form 8-K filed on August 30, 2018).
10.10+ Employment Agreement between Guy Sirkes and Nine Energy Service, LLC, dated as of March 31, 2020 (Incorporated by reference to Exhibit 10.1 of Nine Energy Service, Inc.’s Current Report on Form 8-K filed on March 31, 2020).
10.11+ Amended and Restated Employment Agreement between David Crombie and Nine Energy Service, LLC, dated as of November 20, 2018 (Incorporated by reference to Exhibit 10.1 of Nine Energy Service, Inc.’s Current Report on Form 8-K filed on November 27, 2018).
10.12+
Amended and Restated Employment Agreement between Edward Bruce Morgan and Nine Energy Service, LLC, dated as of November 20, 2018 (Incorporated by reference to Exhibit 10.3 of Nine Energy Service, Inc.’s Current Report on Form 8-K filed on November 27, 2018).
10.13+ First Amendment to Amended and Restated Employment Agreement, by and among Nine Energy Service, LLC, Nine Energy Service, Inc. and Edward Bruce Morgan, effective as of August 30, 2019 (Incorporated by reference to Exhibit 10.1 of Nine Energy Service, Inc.’s Current Report on Form 8-K filed on September 6, 2019).
10.14+ Second Amendment to Amended and Restated Employment Agreement, effective May 29, 2020, by and among Nine Energy Service, LLC, Nine Energy Service, Inc., and Edward Bruce Morgan (Incorporated by reference to Exhibit 10.6 of Nine Energy Service, Inc.’s Quarterly Report on Form 10-Q filed on August 7, 2020).
10.15+
Amended and Restated Employment Agreement between Theodore R. Moore and Nine Energy Service, LLC, dated as of November 20, 2018 (Incorporated by reference to Exhibit 10.4 of Nine Energy Service, Inc.’s Current Report on Form 8-K filed on November 27, 2018).
10.16+ Separation Agreement and General Release of Claims between Clinton Roeder and Nine Energy Service, LLC, dated March 31, 2020 (Incorporated by reference to Exhibit 10.3 of Nine Energy Service, Inc.’s Current Report on Form 8-K filed on March 31, 2020).
10.17+ Letter Agreement, effective as of April 1, 2020, between Nine Energy Service, LLC and Ann G. Fox (Incorporated by reference to Exhibit 10.1 of Nine Energy Service, Inc.’s Quarterly Report on Form 10-Q filed on August 7, 2020).
10.18+ Letter Agreement, effective as of April 1, 2020, between Nine Energy Service, LLC and David Crombie (Incorporated by reference to Exhibit 10.2 of Nine Energy Service, Inc.’s Quarterly Report on Form 10-Q filed on August 7, 2020).
10.19+ Letter Agreement, effective as of April 1, 2020, between Nine Energy Service, LLC and Guy Sirkes (Incorporated by reference to Exhibit 10.3 of Nine Energy Service, Inc.’s Quarterly Report on Form 10-Q filed on August 7, 2020).
10.20+ Letter Agreement, effective as of April 1, 2020, between Nine Energy Service, LLC and Edward Bruce Morgan (Incorporated by reference to Exhibit 10.4 of Nine Energy Service, Inc.’s Quarterly Report on Form 10-Q filed on August 7, 2020).
10.21+ Letter Agreement, effective as of April 1, 2020, between Nine Energy Service, LLC and Theodore R. Moore (Incorporated by reference to Exhibit 10.5 of Nine Energy Service, Inc.’s Quarterly Report on Form 10-Q filed on August 7, 2020).
21.1* List of Subsidiaries of Nine Energy Service, Inc.
23.1* Consent of PricewaterhouseCoopers LLP.
31.1* Certification by Chief Executive Officer pursuant to Rule 13a-14(a) and 15d-14(a) of the Exchange Act Rules, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2* Certification by Chief Financial Officer pursuant to Rule 13a-14(a) and 15d-14(a) of the Exchange Act Rules, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1** Certifications by Chief Executive Officer pursuant to Title 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of Sarbanes-Oxley Act of 2002.
32.2** Certifications by Chief Financial Officer pursuant to Title 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of Sarbanes-Oxley Act of 2002.
101* Interactive Data Files.
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* Filed herewith.
** Furnished herewith.
† Certain schedules and similar attachments have been omitted pursuant to Item 601(a)(5) of Regulation S-K and will be provided to the SEC upon request.
^ Pursuant to Item 601(b)(2) of Regulation S-K, certain immaterial provisions of the agreement that would likely cause competitive harm to the Company if publicly disclosed have been redacted. The Company hereby undertakes to furnish supplementally an unredacted copy of the agreement to the SEC upon request; provided, however, that the Company may request confidential treatment pursuant to Rule 24b-2 of the Exchange Act for any documents so furnished.
+ Management contract or compensatory plan or arrangement.