EDGAR 10-K Filing

Company CIK: 844965
Filing Year: 2021
Filename: 844965_10-K_2021_0000844965-21-000002.json

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ITEM 1. BUSINESS
Item 1. Business.
The financial statements presented in this Annual Report are the consolidated financial statements of TETRA Technologies, Inc., a Delaware corporation and its subsidiaries. When the terms “TETRA,” “the Company,” “we,” “us,” or “our” are used in this document, those terms refer to TETRA Technologies, Inc. and its consolidated subsidiaries.
TETRA is a Delaware corporation incorporated in 1981. Our corporate headquarters are located at 24955 Interstate 45 North, The Woodlands, Texas, 77380. Our phone number is 281-367-1983 and our website is www.tetratec.com. Our common stock is traded on the New York Stock Exchange (the “NYSE”) under the symbol “TTI.”
Our Corporate Governance Guidelines, Code of Business Conduct, Code of Ethics for Senior Financial Officers, Audit Committee Charter, Compensation Committee Charter, and Nominating and Corporate Governance Committee Charter, as well as our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, and Current Reports on Form 8-K, and all amendments to those reports are all available, free of charge, on our website at www.tetratec.com as soon as practicable after we file the reports with the SEC. Information contained on or connected to our website is not, and shall not be deemed to be, a part of this Annual Report on Form 10-K or incorporated into any other filings with the SEC. The documents referenced above are available in print at no cost to any stockholder who requests them from our Corporate Secretary.
About TETRA
TETRA Technologies, Inc., together with its consolidated subsidiaries, is a leading, geographically diversified oil and gas services company, focused on completion fluids and associated products and services, comprehensive water management, frac flowback and production well testing. Prior to the closing of the GP Sale (as defined below) on January 29, 2021, we operated in three reporting segments organized into three Divisions. Following the closing of the GP Sale, our products and services are delivered through two reporting segments organized into two Divisions - Completion Fluids & Products and Water & Flowback Services.
Our Completion Fluids & Products Division manufactures and markets clear brine fluids, additives, and associated products and services to the oil and gas industry for use in well drilling, completion, and workover operations in the United States and in certain countries in Latin America, Europe, Asia, the Middle East and Africa. The Division also markets liquid and dry calcium chloride products manufactured at its production facilities or purchased from third-party suppliers to a variety of markets outside the energy industry.
Our Water & Flowback Services Division provides onshore oil and gas operators with comprehensive water management services. The Division also provides frac flowback, production well testing, offshore rig cooling, and other associated services in many of the major oil and gas producing regions in the United States and Mexico, as well as in oil and gas basins in certain countries in Latin America, Europe, and the Middle East.
We continue to pursue a long-term growth strategy that includes expanding our core businesses, domestically and internationally, through the introduction of new technology, organic growth and accretive acquisitions.
Products and Services
Completion Fluids & Products Division
Liquid calcium chloride, calcium bromide, zinc bromide, zinc calcium bromide, sodium bromide, and blends of such products manufactured by our Completion Fluids & Products Division are referred to as clear brine fluids (“CBFs”) in the oil and gas industry. CBFs are salt solutions that have variable densities and are used to control bottom-hole pressures during oil and gas completion and workover operations. The Division sells CBFs and various CBF additives to U.S. and foreign oil and gas exploration and production companies and to other companies that service customers in the oil and gas industry.
The Completion Fluids & Products Division provides both stock and custom-blended CBFs based on each customer’s specific needs and the proposed application. It provides a broad range of associated CBF services, including: on-site fluids filtration, handling and recycling; wellbore cleanup; custom fluids blending; and fluid management services. The Division’s flagship CBF technology, TETRA CS Neptune® completion fluids, are high-density monovalent and divalent fluids that are free of undissolved solids, zinc, priority pollutants, and formate ions. They were developed by TETRA to be environmentally friendly alternatives to traditional zinc bromide high-density completion fluids and environmentally friendly and cost-effective alternatives to cesium formate high-density completion fluids, all of which are used in well completion and workover operations, as well as a low-solids reservoir drilling fluids.
The Completion Fluids & Products Division offers to repurchase, or “buy-back”, certain used CBFs from customers, which can be reconditioned and recycled. Selling used CBFs back to us reduces the net cost of the CBFs to customers and minimizes our customers’ need to dispose of used fluids. We recondition used CBFs through filtration, blending and the use of proprietary chemical processes, and then market the reconditioned CBFs.
By blending different CBFs and using various additives, we are able to modify the specific density, crystallization temperature, and chemical composition of the CBFs as required to meet our customers’ specific needs. The Division’s fluid engineering personnel determine the optimal CBF blend for a customer’s particular application to maximize its effectiveness and lifespan. Our filtration services use a variety of techniques and equipment to remove particulates from CBFs at the customer’s site so the CBFs can be reused. Filtration also enables recovery of a greater percentage of used CBFs for reconditioning.
The Completion Fluids & Products Division manufactures liquid and dry calcium chloride and liquid calcium bromide, zinc bromide, zinc calcium bromide, and sodium bromide for distribution, primarily into energy markets. Liquid and dry calcium chloride are also sold into water treatment, industrial, cement, food processing, road maintenance, ice melt, agricultural, and consumer products markets. Sodium bromide is also sold into industrial water treatment markets, where it is used as a biocide in recirculated cooling tower waters and in other applications.
Our calcium chloride manufacturing facilities are located in the United States and Finland. In the United States, we manufacture liquid calcium chloride products at four manufacturing plant facilities. Liquid and flake calcium chloride are also produced at our Kokkola, Finland plant. We operate our European calcium chloride operations under the name TETRA Chemicals Europe. We also manufacture liquid calcium chloride at our facilities in Parkersburg, West Virginia and Lake Charles, Louisiana, and we have two solar evaporation facility locations located in San Bernardino County, California, that produce liquid calcium chloride and sodium chloride from underground brine reserves, which are replenished naturally. Our calcium chloride production facilities have a combined production capacity of approximately 1.0 million equivalent liquid tons per year. We also acquire calcium chloride inventory from other producers.
Our Completion Fluids & Products Division manufactures liquid calcium bromide, zinc bromide, zinc calcium bromide, and sodium bromide at our West Memphis, Arkansas facility. A proprietary process applied at this facility uses bromine and zinc to manufacture zinc bromide. This facility also uses proprietary processes to manufacture calcium bromide and sodium bromide and to recondition and upgrade used CBFs that we have repurchased from our customers.
Water & Flowback Services Division
Our Water & Flowback Services Division provides a wide variety of water management services that support hydraulic fracturing in unconventional well completions for domestic onshore oil and gas operators. These services include fresh and produced water analysis, treatment and recycling, blending and distribution, storage and pit lining, transfer, engineering, and environmental risk mitigation. The Water & Flowback Services Division’s patented and patent-pending equipment and processes include advanced hydrocyclones for sand management, certain produced- and fresh-water blending technologies, and TETRA Steel™ 1200 rapid deployment water transfer system. The Water & Flowback Services Division seeks to design sustainable solutions that meet the unique needs of each customer in order to maximize operational performance and efficiency, and minimize the use of fresh water. These include tailored “Last Mile” infrastructure - which consists of water storage ponds, movable storage tanks, a network of water transfer lines including poly pipe and TETRA Steel™ lay-flat hose, automated transfer and blending of produced water, and water treatment and recycling systems including the TETRA SwiftWater Automated Treatment (SWAT™) system that chemically treats produced water through a clarification process and the oil recovery from produced water via the TETRA Oil Recovery After Production Technology (Orapt™) mobile oil
separation system to transfer water around well pads in a safe, efficient and environmentally responsible manner. Automation has also been deployed throughout 2020 across the TETRA water management portfolio to reduce health, safety and environmental risks and enhance reliability and cost-effectiveness.
Our Water & Flowback Services Division also provides frac flowback services, early production facilities and services, production well testing services, offshore rig cooling services, and other associated services, including well flow management and evaluation services that enable operators to quantify oil and gas reserves, optimize oil and gas production and minimize oil and gas reservoir damage. In certain basins, water, sand, and other abrasive materials commonly accompany the initial production of natural gas or oil, often under high-pressure and high-temperature conditions and, in some cases, from reservoirs containing high levels of hydrogen sulfide gas. The Water & Flowback Services Division provides the specialized equipment and qualified personnel to address these impediments to production. Early production services typically include sophisticated evaluation techniques for reservoir management, including unconventional shale reservoir exploitation and optimization of well workover programs. Frac flowback and production well testing services may include well control, well cleanup and laboratory analysis. These services are used in the completion process after hydraulic fracturing and in the production phase of oil and gas wells.
This Division maintains one of the largest fleets of high-pressure production testing equipment in the United States, including equipment designed to work in environments where high levels of hydrogen sulfide gas are present. The Division has domestic operating locations in Colorado, Louisiana, New Mexico, North Dakota, Ohio, Oklahoma, Pennsylvania, Texas, West Virginia, and Wyoming. The Division also has locations in certain countries in Latin America, Europe, and the Middle East.
Former Compression Division
Our former Compression Division provided compression services and equipment for natural gas and oil production, gathering, artificial lift, transmission, processing and storage. Our former Compression Division’s operations were conducted through our partially-owned CSI Compressco LP (“CCLP”) subsidiary. Through one of our former wholly-owned subsidiaries, CSI Compressco GP LLC (f/k/a CSI Compressco GP Inc.) (the “general partner”), we managed and controlled CCLP, and accordingly, we consolidated CCLP’s results of operations in our consolidated results of operations through December 31, 2020. As of December 31, 2020, common units held by the public represented approximately a 65% common unit ownership interest in CCLP. On January 29, 2021, we entered into the Purchase and Sale Agreement with Spartan Energy Partners, LP and Energy Holdco, LLC (together, “Spartan”) pursuant to which we sold the general partner of CCLP, including the incentive distribution rights (“IDRs”) in CCLP and approximately 23.1% of the outstanding limited partner interests in CCLP, in exchange for a combination of $13.4 million in cash paid at closing, $0.5 million in cash payable on the six-month anniversary of the closing and $3.1 million in contingent consideration in the form of cash and/or CCLP common units if CCLP achieves certain financial targets on or before December 31, 2022. We were required to use all net cash proceeds received at closing from the sale to repay borrowings under our Term Credit Agreement. Following the closing of the transaction, we retained approximately 11.1% of the outstanding CCLP common units. Throughout this Annual Report, we refer to the transaction with Spartan as the “GP Sale.” We have reflected the operations of our former Compression Division as discontinued operations for all periods presented. See Note 3 - “Discontinued Operations” and Note 18 - “Subsequent Event” in the Notes to Consolidated Financial Statements for further information.
Sources of Raw Materials
Our Completion Fluids & Products Division manufactures calcium chloride, calcium bromide, zinc bromide, zinc calcium bromide, and sodium bromide for sale to its customers. The Division also recycles used calcium bromide and zinc bromide CBFs repurchased from its oil and gas customers.
The Completion Fluids & Products Division manufactures liquid calcium chloride, either from underground brine or by reacting hydrochloric acid with limestone. We produce calcium chloride and sodium chloride at our two facilities in San Bernardino County, California, by solar evaporation of pumped underground brine reserves that contain calcium chloride. The underground reserves of this brine are deemed adequate to supply our foreseeable need for calcium chloride at those plants. The Division also purchases liquid and dry calcium chloride from a number of U.S. and foreign chemical manufacturers.
The Completion Fluids & Products Division’s primary sources of hydrochloric acid are co-product streams obtained from chemical manufacturers. Substantial quantities of limestone are also consumed when converting
hydrochloric acid into calcium chloride. Currently, hydrochloric acid and limestone are generally available from multiple sources.
To produce calcium bromide, zinc bromide, zinc calcium bromide, and sodium bromide at our West Memphis, Arkansas facility, we use bromine, hydrobromic acid, zinc, ammonia water and lime as raw materials. There are multiple sources of zinc that we can use in the production of zinc bromide and zinc calcium bromide. We have a long-term supply agreement with Lanxess, AG (Lanxess”) under which the Completion Fluids & Products Division purchases its requirements of raw material bromine from Lanxess’ Arkansas bromine production facilities.
The Completion Fluids & Products Division also owns a calcium bromide manufacturing plant near Magnolia, Arkansas, which was constructed in 1985. This plant was acquired in 1988 and is not operable. We currently lease over 27,000 acres of brine leases in the vicinity of this plant, which contain bromine and lithium. While this plant is designed to produce calcium bromide, it could be modified to produce elemental bromine or select bromine compounds. Development of the brine field, construction of necessary pipelines and reconfiguration of the plant would require a substantial capital investment. The long-term Lanxess bromine supply agreement discussed above provides a secure supply of bromine to support the Division’s current operations. We do, however, continue to evaluate our strategy related to the Magnolia, Arkansas, assets and their future development. Lanxess has certain rights to participate in future development of the Magnolia, Arkansas assets. In addition, we are party to agreements with Standard Lithium Ltd. (“Standard Lithium”) (TSXV:SLL), under which Standard Lithium has the right to explore, produce and extract lithium in our Arkansas leases as well as additional potential resources in the Mojave region (San Bernardino County) of California. See Note 2 - “Summary of Significant Accounting Policies” and Note 15 - “Fair Value Measurements” in the Notes to Consolidated Financial Statements for further information.
The Water & Flowback Services Division purchases water management and production testing equipment and components from third-party manufacturers.
Market Overview and Competition
Our operations are highly dependent upon the demand for, and production of, natural gas and oil in the various domestic and international locations in which we operate, and were significantly affected by the unprecedented impact of the COVID-19 pandemic. Demand for products and services of our Completion Fluids & Products Division remained resilient despite pandemic impacts on commodity prices. Recent oil price volatility and much lower oil prices during the second and third quarters of 2020 particularly affected domestic onshore demand for our Water & Flowback Services Division services. For example, in 2020 West Texas Intermediate oil prices ranged from a high of $63.27 per barrel in January 2020 to a low of negative $39.68 per barrel in April 2020.
Completion Fluids & Products Division
Our Completion Fluids & Products Division provides its products and services to oil and gas exploration and production companies in the United States and certain foreign markets, and to other customers that service such companies. Current areas of market presence include the onshore U.S., the U.S. Gulf of Mexico, the North Sea, Mexico and certain countries in South America, Europe, Asia, the Middle East and Africa. Customers with deepwater operations frequently use high volumes of CBFs, which can be subject to harsh downhole conditions, such as high pressure and high temperatures. Demand for CBF products is generally driven by offshore completion and workover activity.
The Completion Fluids & Products Division’s principal competitors in the sale of CBFs to the oil and gas industry are other major international drilling fluids and energy services companies, to many of which we provide products and services. This market is highly competitive and competition is based primarily on service, availability, and price. Customers of the Completion Fluids & Products Division include significant oilfield service companies, major and independent U.S. and international oil and gas producers, and U.S. and international chemical providers. The Division also sells its CBF products through various distributors.
The Completion Fluids & Products Division’s liquid and dry calcium chloride products have a wide range of uses outside the energy industry. Non-energy market segments where these products are used include water treatment, industrial, food processing, road maintenance, ice melt, agricultural, and consumer products. We also sell sodium bromide into industrial water treatment markets as a biocide under the BioRid® tradename. Most of these markets are highly competitive. The Completion Fluids & Products Division’s European calcium chloride operations market our calcium chloride products to certain European markets. Our principal competitors in the non-
energy related calcium chloride markets include Occidental Chemical Corporation and Vitro in North America and NedMag in Europe.
Water & Flowback Services Division
The Water & Flowback Services Division provides comprehensive water management and frac flowback services to a wide-range of onshore oil and gas operators located in all active North America unconventional oil and gas basins.
The Division also provides frac flowback services, early production facilities and services, production well testing services, sand filtration, and other associated services in various domestic and international locations, including well flow management and evaluation services that enable operators to quantify oil and gas reserves, optimize oil and gas production, and minimize oil and gas reservoir production damage.
The water management, flowback, and production testing markets are highly competitive, and competition is based on availability of appropriate equipment and qualified personnel, as well as price, quality of service, and safety record. The Division’s skilled personnel, operating procedures, integrated closed-loop water management solution, automation systems, and safety record give us a competitive advantage. Competition in the U.S. water management markets includes Select Energy and various regional companies, while competition in onshore U.S. production testing markets is primarily dominated by numerous small, privately owned operators. Halliburton, and Schlumberger are competitors in the international production testing markets we serve although we provide these services to their customers on a subcontract basis from time to time. Customers for the Water & Flowback Services Division include major integrated and independent U.S. and international oil and gas producers that are active in the areas in which we operate.
No single customer provided 10% or more of our total consolidated revenues during the years ended December 31, 2020 or 2018. One customer provided more than 10% of our total consolidated revenues during the year ended December 31, 2019.
Other Business Matters
Human Capital Management
We collaborate as a team to execute for each other, our customers, and our shareholders. As of December 31, 2020, we had approximately 1,800 people worldwide, including approximately 730 employees of CCLP. None of our U.S. employees are presently covered by a collective bargaining agreement. Our employees outside the U.S. are generally members of labor unions and associations in the countries in which they are employed. We believe that our relations with our employees are good.
Diversity and Inclusion
The diversity of our global workforce stimulates creativity and innovation as we use our collective talents to develop unique solutions to address the world's energy challenges. Our executive management sponsored Diversity & Inclusion Committee focuses on sharing information and promoting key initiatives across the company to educate and create awareness about the importance of a diverse and inclusive culture. The committee also assists the talent management group to attract, retain, develop, and reward a high-performing and diverse workforce, provide forums and sponsor training activities to share best practices concerning diversity and inclusion education, and develop communication platforms to share information about diversity and inclusion and promote the committee’s activities.
Career Development
The board of directors, the chief executive officer, and the director of Human Resources, evaluate, from time to time each year, executive development and succession planning to prepare us for future success. The succession planning process covers all senior management positions and certain other key positions. This review of executive talent determines readiness to take on additional leadership roles and identifies developmental opportunities needed to prepare our executives for greater responsibilities. Our short and long-term business strategy is considered when evaluating candidates and their skills.
Compensation and Benefits
The Company’s compensation programs are designed to incentivize performance, maximize returns, and build shareholder value. We work with consultants to benchmark our compensation and benefits programs to help us offer competitive compensation packages to attract and retain high-performing talent. We also offer competitive benefits to attract and retain exceptional talent.
Safety
Recognizing that safety, service quality, and environmental protection are conditions of employment, all employees and contractors are responsible for their safety, the safety of those around them, the quality of their work, and protection of the environment. As part of our safety-focused culture, it is customary that each meeting starts with an employee-led safety moment.
To ensure our work remains safe and of the highest quality, the Company has a comprehensive HSEQ Management System and program designed to improve the capacity of the organization by controlling worksite risks, developing proper work practices and procedures, and empowering employees with stop-work authority if they observe unsafe conditions, omissions, errors, or actions that could result in safety or environmental incidents, or product and service quality issues. If an incident takes place, we investigate all serious occurrences to root causes and implement corrective actions to ensure we expand our capacity to operate safely.
Driving is one of the highest exposure activities that we undertake in our day-to-day operations. We maintain a fleet of DOT and non-DOT vehicles and provide positive, real-time behavior feedback to our drivers via real-time monitors. Coupled with Journey Management, vehicle selection guidelines, and driver training, we have a comprehensive approach to reducing our driving exposure and incidents.
Proprietary Technology and Trademarks
As of December 31, 2020, we owned or licensed thirty-three issued U.S. patents and had fifteen patent applications pending in the United States. We also had thirty-six owned or licensed patents and forty-five patent applications pending in various other countries. The foreign patents and patent applications are primarily foreign counterparts to certain of our U.S. patents or patent applications. The issued patents expire at various times through 2037. We have elected to maintain certain other internally developed technologies, know-how, and inventions as trade secrets. While we believe that our patents and trade secrets are important to our competitive positions in our businesses, we do not believe any one patent or trade secret is essential to our success.
It is our practice to enter into confidentiality agreements with key employees, consultants and third parties to whom we disclose our confidential and proprietary information, and we have typical policies and procedures designed to maintain the confidentiality of such information. There can be no assurance, however, that these measures will prevent the unauthorized disclosure or use of our trade secrets and expertise, or that others may not independently develop similar trade secrets or expertise.
We sell various products and services under a variety of trademarks and service marks, some of which are registered in the United States or other countries.
Health, Safety, and Environmental Affairs Regulations
Our service and sales operations and manufacturing plants are subject to stringent and complex U.S. and foreign health, safety, and environmental laws and regulations. Although we are committed to conducting all of our operations under the highest standards of safety and respect for the environment, risks of substantial costs and liabilities pursuant to such laws and regulations are inherent in certain of our operations and in the development and handling of certain products and equipment produced or used at our plants, well locations, and worksites. Because of these risks, there can be no assurance that significant costs and liabilities will not be incurred now or in the future. Changes in environmental and health and safety laws and regulations could subject us to more rigorous standards and could affect demand for our customers’ products which in turn would impact demand for our products. We cannot predict the extent to which our operations may be affected by any changes to existing laws, regulations and enforcement policies, new interpretations of existing laws, regulations and policies, or any new laws, regulations, or policies promulgated in the future.
We are subject to numerous federal, state, local, and foreign laws and regulations relating to health, safety, and the environment, including regulations regarding air emissions, wastewater and storm water discharges, and the disposal of certain hazardous and nonhazardous wastes. Compliance with such laws and regulations may
expose us to significant costs and liabilities, and cause us to incur significant capital expenditures in our operations. Failure to comply with these laws and regulations or associated permits may result in the assessment of administration, civil or criminal fines and penalties, the imposition of other corrective action obligations or other injuctive relief, or both.
Our operations in the United States are subject to various evolving environmental laws and regulations that are enforced by the U.S. Environmental Protection Agency (“EPA”); the Bureau of Safety and Environmental Enforcement (“BSEE”) of the U.S. Department of the Interior; the U.S. Coast Guard; and various other federal, state, and local environmental authorities. Similar laws and regulations, designed to protect the health and safety of our employees and visitors to our facilities, are enforced by the U.S. Occupational Safety and Health Administration, and other state and local agencies and authorities. The primary environmental laws and regulations applicable to our operations include: (i) the Federal Water Pollution Control Act of 1972 (the “Clean Water Act”); (ii) the Resource Conservation and Recovery Act of 1976; (iii) the Clean Air Act of 1977 (“CAA”); (iv) the Comprehensive Environmental Response, Compensation, and Liability Act of 1980 (“CERCLA”); (v) the Superfund Amendments and Reauthorization Act of 1986; (vi) the Toxic Substances Control Act of 1976; (vii) the Hazardous Materials Transportation Act of 1975; and (viii) and the Pollution Prevention Act of 1990. Our operations outside the United States are subject to various foreign governmental laws and regulations relating to the environment, health and safety, and other regulated activities in the countries in which we operate.
Our operations routinely involve the handling of natural gas, oil, other petroleum products, and produced water. Hydrocarbons or hazardous and nonhazardous wastes may have been released during our operations, by third parties on wellhead sites where we provide services or store our equipment, or on or under other locations where wastes have been taken for disposal. Although most wastes associated with the exploration, development and production of oil and natural gas are currently exempt from the more stringent hazardous waste regulations under RCRA and its state analogs, it is possible that some of the material we handle now or may handle in the future may be subject to regulation under RCRA as a hazardous waste. Additionally, we cannot assure you that such materials will not be subject to more stringent requirements or characterized as hazardous wastes in the future. Separately, properties where such hydrocarbons and/or wastes are released or disposed of may be subject to investigatory, remediation, and monitoring requirements under foreign, federal, state, and local environmental laws and regulations. CERCLA and comparable state laws and regulations impose strict, joint, and several liabilities without regard to fault or the legality of the original conduct on certain classes of persons that contributed to the release of a hazardous substance into the environment. These persons include the owner or operator of a disposal site where a hazardous substance release occurred and any person that transported, disposed of, or arranged for the transport or disposal of such hazardous substances released at a site. Under CERCLA, such persons may be liable for the costs of remediating the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies.
The CAA and its implementing regulations, and comparable state laws and regulations, regulate the emissions of air pollutants from various industrial sources and impose monitoring and reporting requirements. These laws and regulations impose limits on the levels of various substances that may be emitted into the atmosphere. For example, in June 2016, the EPA adopted regulations under its New Source Performance Standards and National Emission Standards for Hazardous Air Pollutants that establish air emission controls for natural gas and natural gas liquids production, processing and transportation activities. These rules establish specific requirements associated with volatile organic compounds and methane emissions from certain hydraulically fractured natural gas wells, production-related wet seal and reciprocating compressors, and pneumatic controllers and storage vessels, and further require that most hydraulically fractured natural gas wells use so-called “green” completions. While the EPA under the Trump Administration finalized rules to rescind or modify certain of these requirements in September 2020, including rescission of the methane-specific requirements applicable to sources in the production and processing segments of the oil and gas industry, various states and industry and environmental groups are separately challenging the EPA’s June 2016 standards and its September 2020 final rule. Moreover, notwithstanding the current court challenges, the EPA under the Biden Administration is expected to reconsider the September 2020 final rule, which could result in more stringent rulemakings. While we do not believe that compliance with current regulatory requirements will have a material adverse effect on our business or operations, additional or more stringent regulations could impose new air permitting or pollution control requirements on our equipment that could require us to incur material costs.
In accordance with Section 402 of the Clean Water Act, the EPA is authorized to issue National Pollutant Discharge Elimination System (“NPDES”) General Permits to regulate offshore discharges in the Gulf of Mexico which includes Treatment, Completion and Workover (“TCW”) fluids. Our operations include providing services and
materials to oil and gas operators for the use of TCW fluids in the Gulf of Mexico. The EPA’s current NPDES permit for oil and gas operations in the federal waters of the Gulf of Mexico requires oil and gas operators to assess the toxicity characteristics of TCW fluids that are discharged and to submit the assessment results through 2021. Although the results of such assessments are not expected to have a material adverse impact on our business or operations, they could result in additional restrictions on oil and gas operation in the Gulf of Mexico under the Clean Water Act, which could have an indirect effect on us. In addition, the Clean Water Act, and comparable state laws and regulations thereunder, also prohibit the discharge of pollutants into regulated waters without a permit, including industrial wastewater discharges and storm water runoff, and establish limits on the levels of pollutants contained in such discharges.
The modification or reinterpretation of existing environmental laws or regulations, the more vigorous enforcement of existing environmental laws or regulations, or the adoption of new environmental laws or regulations could adversely affect oil and natural gas exploration and production operations, which in turn could have an adverse effect on us.
We maintain various types of insurance intended to reimburse us for certain costs in the event of an accident, including an explosion or similar event, involving our onshore and offshore operations. Our insurance program is reviewed not less than annually with our insurance brokers and underwriters. As part of our insurance program for offshore operations, we maintain Commercial General Liability, Protection and Indemnity, and Excess Liability policies that provide third-party liability coverage, including but not limited to death and personal injury, collision, damage to property including fixed and floating objects, pollution, and wreck removal up to the applicable policy limits. However, such insurance policies may not cover, or may only partially cover, certain losses or claims, which could result in a material adverse effect on our business and operations.

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ITEM 1A. RISK FACTORS
Item 1A. Risk Factors.
Certain Business Risks
Although it is not possible to identify all of the risks we encounter, we have identified the following significant risk factors that could affect our actual results and cause actual results to differ materially from any such results that might be projected, forecasted, or estimated by us in this Annual Report.
Market Risks
The demand and prices for our products and services are affected by several factors, including the supply, demand, and prices for oil and natural gas.
Demand for our services and products is particularly sensitive to the level of exploration, development, and production activity of, and the corresponding capital spending by, oil and natural gas companies. The level of exploration, development, and production activity is directly affected by oil and natural gas prices, which historically have been volatile and are likely to continue to be volatile. Prices for oil and natural gas are subject to large fluctuations in response to relatively minor changes in the supply of and demand for oil and natural gas, market uncertainty, and a variety of other economic factors that are beyond our control.
Although oil prices steadily rose during late 2020 and early 2021, they fell during early 2020, with West Texas Intermediate oil prices dropping from a high of $63.27 per barrel in January 2020 to a low of negative $39.68 per barrel in April 2020. The West Texas Intermediate price averaged $39.16 per barrel during 2020. Over this same period, U.S. natural gas prices have also been volatile, with the Henry Hub price ranging from a high of $3.14 per million British thermal units (“MMBtu”) in October 2020 to a low of $1.33 per MMBtu in September 2020. As of March 3, 2021, the price of West Texas Intermediate oil was $61.28 per barrel and the Henry Hub price for natural gas was $2.82 per MMBtu. The prolonged volatility and low levels of oil and natural gas prices and persisting supply and demand imbalances have depressed levels of exploration, development, and production activity, and if the drop in oil and natural gas prices we have experienced in 2020 continues or further declines and the supply and demand imbalances persist, there would be a material adverse effect on our business, consolidated results of operations, and consolidated financial condition. Should current market conditions worsen for an extended period of time, we may be required to record additional asset impairments. Such potential impairment charges could have a material adverse impact on our operating results.
Factors affecting the prices of oil and natural gas include: the level of supply and demand for oil and natural gas, worldwide; governmental regulations, including the policies of governments regarding the exploration for and production and development of their oil and natural gas reserves; weather conditions, natural disasters, and health or similar issues, such as pandemics or epidemics; worldwide political, military, and economic conditions; the ability or willingness of the Organization of Petroleum Exporting Countries (“OPEC”) and non-OPEC countries, such as Russia, to set and maintain oil production levels; the levels of oil production in the U.S. and by other non-OPEC countries; oil refining capacity and shifts in end-customer preferences toward fuel efficiency and the use of natural gas; the cost of producing and delivering oil and natural gas; and acceleration of the development of, and demand for, alternative energy sources.
The COVID-19 pandemic has had, or may in the future have, certain negative impacts on our business, and such impacts have had, or may in the future have, an adverse effect on our business, our financial condition, results of operations, or liquidity.
The COVID-19 pandemic and the resulting economic impact have had a significant negative impact on the oil and gas industry. The deterioration in demand for oil caused by the pandemic, coupled with oil oversupply, has had, and is reasonably likely to continue to have, an adverse impact on the demand for our products and services. The public health crisis caused by the COVID-19 pandemic, and the measures that have been taken or that may be taken in the future by governments, various regulatory agencies, our customers and our suppliers, have had, or may in the future have, certain negative impacts on our financial condition, results of operations, and liquidity, including, without limitation, the following:
•demand for our products and services declining as our customers continue to adjust their operations in response to lower oil and gas prices;
•actions undertaken by national, state and local governments and health officials to contain COVID-19 or treat its effects. In response to various governmental directives, at points we have required most office-based employees, including most employees based at our headquarters in The Woodlands, Texas, to work remotely. We may experience reductions in productivity and disruptions to our business routines while work-from-home arrangements remain in place;
•We could encounter logistical complications and increased costs adapting our disclosure controls and procedures and our internal control over financial reporting in a changing environment that includes work-from-home arrangements and furloughs. In the future we may encounter operational challenges or disruptions stemming from the pandemic that require us to implement new or enhanced internal controls to mitigate the risks of operating in a remote environment or increased risks of material misstatements resulting from changes to the business and other uncertainties;
•restrictions on importing and exporting products;
•impacts related to late customer payments and contractual defaults associated with customer and supplier bankruptcies;
•potentially higher borrowing costs in the future;
•cybersecurity issues, as our network may become more vulnerable to cyberattacks due to increased remote access associated with work-from-home arrangements;
•our ability to use our net operating loss carryforwards may be limited;
•increased costs associated with possible facility closures to meet expected customer activity levels; and
•we may be required to record significant impairment charges with respect to assets, whose fair values may be negatively affected by the effects of the COVID-19 pandemic on our operations. Also, we may be required to write off obsolete inventory, and such charges may be significant.
The resumption of our normal business operations after the disruptions caused by the COVID-19 pandemic may be delayed or constrained by its lingering effects on the oil and gas industry. Any of the negative impacts of the COVID-19 pandemic, including those described above, alone or in combination with others, may have a significant
adverse effect on our financial condition, results of operations, or liquidity. The full extent to which the COVID-19 pandemic will negatively affect our financial condition, results of operations, or liquidity will depend on future developments that are highly uncertain and cannot be predicted, including the scope and duration of the pandemic, the COVID-19 infection rate, the efficacy of distribution of COVID-19 vaccines, the actions taken by authorities to contain it or treat its impact and the resulting impact on the oil and gas industry. Given the dynamic nature of these events, we cannot reasonably estimate the period of time that the COVID-19 pandemic and related market conditions will persist, the full extent of the impact they will have on our financial condition, results of operations, or liquidity or the pace or extent of any subsequent recovery.
Current debt and equity market conditions may continue to limit our ability to obtain additional financing, including to pursue other business opportunities or refinancing existing indebtedness upon maturity.
Conditions in the market for debt and equity securities in the energy sector have increased the difficulty of obtaining debt or equity financing to grow our business. Due in part to the recent stock market decline, the closing price of our common stock was $0.86 as of December 31, 2020. As of March 3, 2021 the market price for our common stock was $2.59. At the current price for our common stock, acquisition and financing transactions that involve the use of our common equity may be significantly dilutive to our stockholders. The issuance of new convertible debt or equity securities in the future for acquisition and financing transactions, if available, could be significantly dilutive to our stockholders. We may have difficulty obtaining refinancing for our existing indebtedness upon maturity in the current market environment. TETRA’s term loan matures in 2025.
We encounter, and expect to continue to encounter, intense competition in the sale of our products and services.
We compete with numerous companies in each of our operating segments, many of which have substantially greater financial and other resources than we have. Certain of our competitors have lower standards of quality, and offer equipment and services at lower prices than we do. Other competitors have newer equipment that is better suited to our customers’ needs. Particularly during a period of low oil and natural gas pricing, to the extent competitors offer products or services at lower prices or higher quality, or more cost-effective products or services, our business could be materially and adversely affected. In addition, certain of our customers may elect to perform services internally in lieu of using our services, which could also materially and adversely affect our operations.
The profitability of our operations is dependent on other numerous factors beyond our control.
Our operating results in general, and gross profit in particular, are determined by market conditions and the products and services we sell in any period. Other factors, such as heightened competition, changes in sales and distribution channels, availability of skilled labor and contract services, shortages in raw materials, or inability to obtain supplies at reasonable prices, may also affect the cost of sales and the fluctuation of gross margin in future periods.
Other factors affecting our operating results and activity levels include oil and natural gas industry spending levels for exploration, completion, production, development, and acquisition activities, and impairments of long-lived assets. Customer consolidation may also lead to reductions in capital spending that could have a material adverse effect on our business. Low oil prices and the supply and demand imbalance are expected to adversely affect such levels of spending in the oil and natural gas industry. In particular, Completion Fluids & Products Division profitability in future periods will continue to be affected by the mix of its products and services, including the timing of TETRA CS Neptune completion fluid projects, which are also dependent upon the success of customer offshore exploration and drilling efforts. Our customers are maintaining reduced capital expenditure plans for 2021 in light of current market conditions. Such industry capital expenditure reductions have had, and are expected to continue to have, a negative effect on the demand for many of our products and services. This has had, and may continue to have, a negative effect on our revenues and results of operations. A large concentration of our operating activities is located in the Permian Basin region of Texas and New Mexico. Our revenues and profitability are particularly dependent upon oil and natural gas industry activity and spending levels in this region. Our operations may also be affected by technological advances, cost of capital, and tax policies. Adverse changes in any of these other factors may have a material adverse effect on our revenues and profitability.
We are a significant shareholder of CCLP and the value of our investment in CCLP, including future distributions received from CCLP, may fluctuate substantially.
On January 29, 2021, we entered into and closed the GP Sale with Spartan to sell the general partner of CCLP along with the IDRs and approximately 23.1% of the outstanding limited partner interests in CCLP. Following the closing of the GP Sale, we retained approximately 11.1% of the outstanding CCLP common units. The value of our investment in CCLP may be adversely affected by negative changes in its results of operations, cash flows and financial position, which may occur as a result of the many risks attendant with operating in the compression services industry.
CCLP has substantial indebtedness and interest expense, which in turn reduces its cash available to fund capital expenditures or for distribution to CCLP’s common unitholders, including us. CCLP’s ability to service its indebtedness will depend upon, among other things, its future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors. If CCLP’s operating results are not sufficient to service its indebtedness, CCLP may be forced to consider taking actions such as reducing or delaying its business activities, investments and capital expenditures, delaying the increase of distributions, selling assets, restructuring or refinancing its indebtedness, or seeking additional equity capital or bankruptcy protection. Without the ability to increase CCLP’s compression equipment fleet or otherwise grow its operations, CCLP’s ability to continue to retain customers whose compression services needs are expanding and to increase distributions to its common unitholders, including us, in the future may be limited.
Changes in the economic environment have resulted, and could further result, in significant impairments of certain of our long-lived assets.
Under U.S. generally accepted accounting principles (“U.S. GAAP”), we review the carrying value of our long-lived assets when events or changes in circumstances indicate that the carrying value of these assets may not be recoverable, based on their expected future cash flows. The impact of reduced expected future cash flow could require the write-down of all or a portion of the carrying value for these assets, which would result in additional impairments, resulting in decreased earnings. During 2020, we recorded an impairment charge of $0.6 million primarily related to a right of use asset for the lease of our Canada office within our Water & Flowback Services Division as we ceased use of the office during the year. During the three year period ending December 31, 2020, we recorded a total of $95.5 million of impairments and other charges for long-lived assets other than goodwill. During the fourth quarter of 2019, we recorded an impairment of $91.6 million in our Completion Fluids & Products Division related to our El Dorado, Arkansas calcium chloride production plant facility assets as a result of a reduction in the cost of raw materials for certain of our other chemical production plants and reduced demand for calcium chloride from the El Dorado plant due to general market conditions in the oil and gas industry. During the fourth quarter of 2019, we also recorded an impairment of $0.3 million related to certain equipment assets in our Water & Flowback Services Division. During the third quarter of 2018, as a result of decreased expected future cash flows from a specific customer contract, we recorded a long-lived asset impairment of $2.9 million of an identified intangible asset within the Water & Flowback Services Division. Depressed commodity prices and/or adverse changes in the economic environment could result in a greater decrease in the demand for many of our products and services, which could impact the expected utilization rates of certain of our long-lived assets, including plant facilities, operating locations, and operating equipment.
As part of our internal annual business outlook for each of our reporting units that we performed during the fourth quarter of 2019, we considered changes in the global economic environment that negatively impacted our stock price and market capitalization. As part of the first step of goodwill impairment testing for our Water Management reporting unit (part of our Water & Flowback Services Division) as of December 31, 2019, the only reporting unit with goodwill, we determined that the fair value of the Water Management reporting unit was less than its carrying value, and the remaining balance of $25.9 million of goodwill was impaired.
We are dependent on third-party suppliers for specific products and equipment necessary to provide certain of our products and services.
We sell a variety of CBFs to the oil and gas industry and non-energy markets, including calcium chloride, calcium bromide, zinc bromide, zinc calcium bromide, sodium bromide, formate-based brines, and our TETRA CS Neptune fluids, some of which we manufacture and some of which are purchased from third parties. Sales of these products contribute significantly to our revenues. In our manufacture of calcium chloride, we use brines, hydrochloric acid, and other raw materials purchased from third parties. In our manufacture of brominated CBF products, we use elemental bromine, hydrobromic acid, and other raw materials that are purchased from third parties. Although we have long-term supply agreements with Lanxess, if we were unable to acquire these raw materials at reasonable
prices for a prolonged period, our Completion Fluids & Products Division business could be materially and adversely affected.
The fabrication of our production testing, well monitoring, sand separation, and water management equipment requires the purchase of various components, some of which we obtain from a single source or a limited group of suppliers. Our reliance on these suppliers exposes us to the risk of price increases, inferior component quality, or an inability to obtain an adequate supply of required components in a timely manner. The profitability or future growth of our Water & Flowback Services Division may be adversely affected due to our dependence on these key suppliers.
Operating and Technological Risks
We have technological and age-obsolescence risk, both with our products and services as well as with our equipment assets.
New drilling, completion, and production technologies and equipment are constantly evolving. If we are unable to adapt to new advances in technology or replace older assets with new assets, we are at risk of losing customers and market share. Certain equipment, such as a portion of our production testing equipment fleet, may be inadequate to meet the needs of our customers in certain markets. The permanent replacement or upgrade of any of our equipment will require significant capital. Due to the unique nature of many of these assets, finding a suitable or acceptable replacement may be difficult and/or cost prohibitive. The replacement or enhancement of these assets over the next several years may be necessary in order for us to effectively compete in the current marketplace.
Our operations involve significant operating risks and insurance coverage may not be available or cost-effective.
We are subject to operating hazards normally associated with the oilfield service industry, including automobile accidents, fires, explosions, blowouts, formation collapse, mechanical problems, abnormally pressured formations, and environmental accidents. Environmental accidents could include, but are not limited to oil and produced water spills, gas leaks or ruptures, uncontrollable flows of oil, gas, or well fluids, or discharges of CBFs or toxic gases or other pollutants. These operating hazards may also include injuries to employees and third parties during the performance of our operations.
We have maintained a policy of insuring our risks of operational hazards that we believe is customary in the industry. We believe that the limits of insurance coverage we have purchased are consistent with the exposures we face and the nature of our products and services. Due to economic conditions in the insurance industry, from time to time, we have increased our self-insured retentions for certain policies in order to minimize the increased costs of coverage, or we have reduced our limits of insurance coverage for, or not procured, certain coverage. In certain areas of our business, we, from time to time, have elected to assume the risk of loss for specific assets. To the extent we suffer losses or claims that are not covered, or are only partially covered by insurance, our results of operations could be adversely affected.
We are subject to a number of risks associated with the GP Sale, and these risks could adversely impact our operations, financial condition and business.
On January 29, 2021, we closed the sale of CCLP’s general partner and approximately 23.1% of the outstanding limited partner interests in CCLP to Spartan. We are subject to a number of risks associated with this transaction, including risks associated with:
•any required payments of indemnification obligations under the Purchase Agreement for retained liabilities and breaches of representations, warranties or covenants; and
•our failure to realize the full purchase price anticipated under the Purchase Agreement, including the ability of CCLP to generate adjusted EBITDA on or prior to December 31, 2022 sufficient to result in payment of the contingent consideration.
As a result of these risks, we may be unable to realize the anticipated benefits of the transaction, including the total amount of consideration we expect to realize. Our failure to realize the anticipated benefits of the transaction
would adversely impact our operations, financial condition and business and could limit our ability to pursue additional strategic transactions.
Weather-Related Risks
Certain of our operations are seasonal and depend, in part, on weather conditions.
In certain markets, the Water & Flowback Services Division’s onshore water management services can be dependent on adequate water supplies being available to its customers. To the extent severe drought or other weather-related conditions prevent our customers from obtaining needed water, frac water operations may not be possible and our Water & Flowback Services Division business may be negatively affected.
Severe weather, including named windstorms, and severe winter weather, can cause damage and disruption to our businesses.
A portion of our operations is susceptible to adverse weather conditions in the Gulf of Mexico, including hurricanes and other extreme weather conditions. Even if we do not experience direct damage from storms, we may experience disruptions in our operations, because we are unable to operate or our customers or suppliers may curtail their activities due to damage to their wells, platforms, pipelines, and facilities. From time to time, our onshore operations are also negatively affected by adverse weather conditions, including sustained rain and flooding. Severe weather during the winter may also have a significant impact on natural gas storage levels and reduce drilling activity and other customer activity substantially.
Financial Risks
The market price of our common stock has been and may continue to be volatile.
The market price of our common stock has fluctuated in the past and is subject to significant fluctuations in response to many factors, some of which are beyond our control, including the following:
•our operational performance;
•supply, demand, and prices of oil and natural gas;
•the activity levels of our customers;
•deviations in our earnings from publicly disclosed forward-looking guidance or analysts’ projections;
•recommendations by research analysts that cover us and other companies in our industry;
•risks related to acquisitions, divestitures and our growth strategy;
•uncertainty about current global economic conditions; and
•other general economic conditions.
During 2020, the closing price for our common stock ranged from a high of $2.03 per share to a low of $0.22 per share. In recent years, the stock market in general has experienced extreme price and volume fluctuations that have affected the market price for companies in industries similar to ours. Some of these fluctuations have been unrelated to operating performance and are attributable, in part, to outside factors such as the COVID-19 pandemic and its impact on the world economy. The volatility of our common stock may make it difficult to resell shares of our common stock at attractive prices.
Our long-term debt agreements contain covenants and other provisions that restrict our ability to take certain actions and may limit our ability to operate or grow our business in the future.
As of December 31, 2020, our total long-term debt outstanding of $199.9 million, excluding debt of CCLP included in liabilities of discontinued operations, consisted of the carrying amount outstanding under our credit agreement (the “Term Credit Agreement”) and our Asset-Based Credit Agreement (the “ABL Credit Agreement”), both of which we entered into in September 2018. Following the closing of the GP Sale on January 29, 2021, our consolidated balance sheet will no longer include the amounts of CCLP. We were required to use all net cash proceeds from the sale to repay borrowings under our Term Credit Agreement.
The ABL Credit Agreement and Term Credit Agreement each contain certain affirmative and negative covenants, including covenants that restrict the ability of TETRA and certain of its subsidiaries to take certain actions including, among other things and subject to certain significant exceptions, (i) incurring debt, (ii) granting
liens, (iii) engaging in mergers and other fundamental changes, (iv) making investments, (v) entering into, or amending, transactions with affiliates, (vi) paying dividends and making other restricted payments, (vii) prepaying other indebtedness, and (viii) selling assets. The ABL Credit Agreement also contains a provision that may require a fixed charge coverage ratio (as defined in the ABL Credit Agreement) of not less than 1.00 to 1.00 in the event that certain conditions associated with outstanding borrowings and cash availability occur. The Term Credit Agreement also contains a requirement that the borrowers comply at the end of each fiscal quarter with a minimum Interest Coverage Ratio (as defined in the Term Credit Agreement) of 1.00 to 1.00. Our Term Credit Agreement requires us to annually prepay up to 50% of Excess Cash Flow (as defined in the Term Credit Agreement) from the most recent full fiscal year. If our Leverage Ratio (as defined in the Term Credit Agreement) at year-end is less than 2.00 to 1.00 , the prepayment requirement is decreased to 25%. If our Leverage Ratio at year-end is less than 1.50 to 1.00, then no prepayment is required.
Our continuing ability to comply with covenants in our Long-Term Debt Agreements depends largely upon our ability to generate adequate earnings and operating cash flow.
We have continuing exposure to abandonment and decommissioning obligations associated with oil and gas properties previously owned by Maritech.
From 2001 to 2012, our former subsidiary, Maritech Resources, Inc. (“Maritech”), sold various oil and gas producing properties in numerous transactions to different buyers. In connection with those sales, the buyers generally assumed the decommissioning liabilities associated with the properties sold (the “Legacy Liabilities”) and generally became the successor operator. In some cases, Maritech retained certain liabilities and we provided guaranties of Maritech’s retained liabilities. Some buyers of these Maritech properties subsequently sold certain of these properties to other buyers, who also assumed the financial responsibilities associated with the properties’ operations, including decommissioning liabilities, and these buyers also typically became the successor operator of the properties. To the extent that a buyer of these properties fails to perform the decommissioning work required, a previous owner, including Maritech, may be required to perform operations to satisfy the decommissioning liabilities. As a result of the third-party indemnity agreements and corporate guaranties we have previously provided to the U.S. Department of the Interior and to other private third-parties as the former parent company of Maritech, we may be responsible for satisfying these decommissioning obligations if they are not satisfied by the current owners and operators of the properties or by Maritech. Significant decommissioning liabilities that were assumed by the buyers of the Maritech properties in these previous sales remain unperformed. If oil and natural gas pricing levels continue to be depressed or further deteriorate, one or more of these buyers may be unable to perform the decommissioning work required on a property previously owned by Maritech. If these buyers, or any successor owners of the Maritech properties, are unable to satisfy and extinguish their decommissioning liabilities due to bankruptcy or other liquidity issues, the U.S. Department of the Interior may seek to impose those decommissioning obligations on Maritech and on us due to our third party indemnity agreements, and contractual commitments and guaranties issued from time to time by us to the U.S. Department of the Interior and various third parties. The amount of cash necessary to satisfy these obligations could be significant and could adversely affect our business, results of operations, financial condition, and cash flows.
In March 2018, pursuant to a series of transactions, Maritech sold the remaining offshore leases held by Maritech to Orinoco Natural Resources, LLC (“Orinoco”) and, immediately thereafter, we sold all equity interest in Maritech to Orinoco. The assignments for six of the offshore leases conveyed to Orinoco have not been approved by the U.S. Department of the Interior and Maritech remains an owner of record for these leases. Maritech also remains a recognized operator of a portion of four other offshore properties. Under the Maritech Asset Purchase Agreement, Orinoco assumed all of Maritech’s decommissioning liabilities related to the leases conveyed to Orinoco (the “Orinoco Lease Liabilities”) and, under the Maritech Membership Interest Purchase Agreement, Orinoco assumed all other liabilities of Maritech, including the Legacy Liabilities, subject to limited exceptions unrelated to the decommissioning liabilities. Pursuant to a Bonding Agreement executed in connection with such purchase agreements, Orinoco provided non-revocable bonds in the aggregate amount of approximately $46.8 million to secure the performance of certain of Maritech’s decommissioning obligations related to the Orinoco Lease Liabilities and certain of Maritech’s remaining current decommissioning obligations (not including the Legacy Liabilities). Orinoco was required to replace the initial bonds delivered at closing with other non-revocable performance bonds in two stages. The first set of replacement bonds were required to be delivered within 90 days following closing and the second set of replacement bonds were required to be delivered within 180 days following closing. The replacement bonds had to meet certain additional requirements and were required to be in the aggregate sum of $47.0 million. In the event Orinoco did not provide the first or second set of replacement bonds, Orinoco was required to make cash escrow payments. Among the other requirements of the final replacement bonds was that
they must provide coverage for all of the asset retirement obligations of Maritech instead of only relating to specific properties. The payment obligations of Orinoco under the Bonding Agreement are guaranteed by Thomas M. Clarke and Ana M. Clarke pursuant to a separate guaranty agreement (the “Clarke Bonding Guaranty Agreement”). Orinoco has not delivered such replacement bonds and neither it nor the Clarkes has made any of the escrow payments required pursuant to the terms of the Bonding Agreement. We filed a lawsuit against Orinoco and the Clarkes to enforce the terms of the Bonding Agreement and the Clarke Bonding Guaranty Agreement. A summary judgment was initially granted in favor of Orinoco and the Clarkes, which dismissed our claims against Orinoco under the Bonding Agreement and against the Clarkes under the Clarke Bonding Guaranty Agreement. We filed an appeal and also asked the trial court to grant a new trial on the summary judgment to modify the judgment because we believe this judgment should not have been granted. On November 5, 2019, the trial court signed an order granting our motion for new trial and vacating the prior order granting summary judgment for Orinoco and the Clarkes. The parties are awaiting direction from the court on a new scheduling order and/or trial setting. The non-revocable performance bonds delivered at the closing remain in effect.
If in the future we become liable for decommissioning liabilities associated with any property covered by either an initial bond or stage 1 permanent bond, the Bonding Agreement provides that if we call any of the initial bonds or the stage 1 permanent bonds to satisfy such liability and the amount of the bond payment is not sufficient to pay for such liability, Orinoco will pay us for the additional amount required. To the extent Orinoco is unable to cover any such deficiency or we become liable for a significant portion of the Legacy Liabilities, our financial condition and results of operations may be negatively affected.
Possible changes in the U.S. Department of Interior’s supplemental bonding and financial assurance requirements may increase our risks associated with the decommissioning obligations pertaining to oil and gas properties previously owned by Maritech.
Recent and additional anticipated changes to the supplemental bonding and financial assurance program managed by the U.S. Department of the Interior could require all oil and gas owners and operators with infrastructure in the Gulf of Mexico to provide additional supplemental bonds or other acceptable financial assurance for decommissioning liabilities. These changes have the potential to adversely impact the financial condition of lease owners and operators in the Gulf of Mexico and increase the number of such owners and operators seeking bankruptcy protection, given current oil and gas prices. In July 2016, the U.S. Department of the Interior issued a Notice to Lessees and Operators (“2016 NTL”) that strengthened requirements for the posting of additional financial assurance by offshore lease owners and operators to assure that sufficient security is available to satisfy and extinguish decommissioning obligations with respect to offshore wells, platforms, pipelines and other facilities. The 2016 NTL, which became effective in September 2016, eliminated the past practice of waiving supplemental bonding requirements where lease owners or operators, or their guarantors, could demonstrate a certain level of financial strength. Instead, under the 2016 NTL, the U.S. Department of the Interior indicated that it would allow lease owners and operators to “self-insure,” but only up to 10% of their “tangible net worth,” which is defined as the difference between a company’s total assets and the value of all liabilities and intangible assets. It is unclear how this self-insurance allowance relates to lease owners or operators with a guarantor presently in place.
Although the U.S. Department of the Interior under the Trump Administration ultimately rescinded the 2016 NTL in 2020, the Biden Administration could seek to reconsider the changes made by the U.S. Department of the Interior under the Trump Administration and, should the Biden Administration re-issue and fully implement guidance or rules analogous to, or more rigorous than, the 2016 NTL, such developments could increase operating costs for lease owners and operators in the Gulf of Mexico and reduce the availability of surety bonds due to the increased demands for such bonds in a low-price commodity environment. As a result, there is significant uncertainty surrounding financial assurance obligations for Gulf of Mexico lease owners and operators and for us through the third party indemnity agreements we have provided for Maritech liabilities to the U.S. Department of the Interior and/or to third parties through our private guarantees.
The U.S. Department of the Interior also recently increased its estimates for decommissioning liabilities in the Gulf of Mexico, causing the potential need for additional supplemental bonding and/or other financial assurances to be dramatically increased. When coupled with the volatile and currently low prices of oil and gas, it is difficult to predict the impact of the rule and regulatory changes already promulgated and as may be forthcoming by the U.S. Department of the Interior relating to financial assurance for decommissioning liabilities. Any revisions to the U.S. Department of the Interior’s supplemental bonding process could result in demands for the posting of increased financial assurances by owners and operators in the Gulf of Mexico, including Maritech, Orinoco and the other entities to whom Maritech divested its Gulf of Mexico assets, but such demands cannot be directly placed on
us due to the fact that we are only a former parent company of Maritech and are only a guarantor as opposed to an actual lease owner or operator. This may force lease owners and operators of leases and other infrastructure in the Gulf of Mexico to obtain surety bonds or other forms of financial assurance, the costs of which could be significant. Moreover, anticipated changes to the bonding and financial assurance program for the Gulf of Mexico could result in the loss of supplemental bonding waivers for a large number of lease owners and operators of infrastructure in the Gulf of Mexico, which could in turn force these owners and operators to seek additional surety bonds which could exceed the surety bond market’s ability to provide such additional financial assurance. Lease owners and operators who have already leveraged their assets could face difficulty obtaining surety bonds because of concerns the surety may have about the priority of their liens on their collateral as well as the creditworthiness of such lease owners and operators. Consequently, anticipated changes to the bonding and financial assurance program could result in additional lease owners and operators in the Gulf of Mexico initiating bankruptcy proceedings, which in turn could result in the U.S. Department of the Interior seeking to impose decommissioning costs on predecessors in interest and providers of third party indemnity agreements in the event that the current lease owners and/or operators cannot meet their decommissioning obligations. As a result, this could increase the risk that we may be required to step in and satisfy remaining decommissioning liabilities of Maritech and any buyer of the Maritech properties, including Orinoco, through our third party indemnity agreements and private guarantees, which obligations could be significant and could adversely affect our business, results of operations, financial condition and cash flows.
We are exposed to significant credit risks.
We face credit risk associated with the significant amounts of accounts receivable we have with our customers in the energy industry. Many of our customers, particularly those associated with our onshore operations, are small- to medium-sized oil and gas operators that may be more susceptible to declines in oil and gas commodity prices or generally increased operating expenses than larger companies. Our ability to collect from our customers is impacted by the current volatile oil and natural gas price environment and we may face increased credit risks if the current reduced price of oil continues for an extended period of time.
As discussed in the preceding risk factors, we face the risk of having to satisfy decommissioning liabilities on properties presently or formerly owned by Maritech. Continued decreased oil and natural gas prices have resulted in reduced revenues and cash flows for oil and gas lease owners and operators, including companies that have purchased Maritech properties or are joint-owners in properties presently and formerly owned by Maritech and from whom Maritech is entitled to receive payments upon satisfaction of certain decommissioning obligations. Consequently, we face credit risk associated with the ability of these companies to satisfy their decommissioning liabilities. If these companies are unable to satisfy their obligations, it will increase the possibility that we will become liable for such decommissioning obligations in the future.
Our operating results and cash flows for certain of our subsidiaries are subject to foreign currency risk.
The operations of certain of our subsidiaries are exposed to fluctuations between the U.S. dollar and certain foreign currencies, particularly the euro, the British pound, the Mexican peso, and the Argentinian peso. Our plans to grow our international operations could cause this exposure from fluctuating currencies to increase. Historically, exchange rates of foreign currencies have fluctuated significantly compared to the U.S. dollar, and this exchange rate volatility is expected to continue. Significant fluctuations in foreign currencies against the U.S. dollar could adversely affect our balance sheet and results of operations.
We are exposed to interest rate risks with regard to our credit facility debt and future refinancing thereof.
As of December 31, 2020, we had no outstanding balance under our ABL Credit Agreement and $213.5 million outstanding under our Term Credit Agreement. Following repayment from GP Sale proceeds, the balance outstanding under our Term Credit Agreement is $201.7 million. These credit facilities consist of floating rate loans that bear interest at an agreed upon percentage rate spread above London Interbank Offered Rate (“LIBOR”) or an alternate base rate. Accordingly, whenever we have amounts outstanding under these facilities, our cash flows and results of operations will be subject to interest rate risk exposure associated with the debt balance outstanding. We currently are not a party to an interest rate swap contract or other derivative instrument designed to hedge our exposure to interest rate fluctuation risk.
Our ABL Credit Agreement is scheduled to mature on September 10, 2023. Our Term Loan Agreement is scheduled to mature on September 10, 2025. There can be no assurance that financial market conditions or borrowing terms at the times these existing debt agreements are renegotiated will be as favorable as the current
terms and interest rates. We may be unable to obtain financing in the future for working capital, capital expenditures, acquisitions, debt service requirements, or other purposes.
Legal, Regulatory, and Political Risks
Our operations are subject to extensive and evolving U.S. and foreign federal, state and local laws and regulatory requirements that increase our operating costs and expose us to potential fines, penalties, and litigation.
Laws and regulations govern our operations, including those relating to corporate governance, employees, taxation, fees, importation and exportation restrictions, environmental affairs, health and safety, and the manufacture, storage, handling, transportation, use, and sale of chemical products. Certain foreign countries impose additional restrictions on our activities, such as currency restrictions and restrictions on various labor practices. These laws and regulations are becoming increasingly complex and stringent, and compliance is becoming increasingly expensive. Governmental authorities have the power to enforce compliance with these regulations, and violators are subject to civil and criminal penalties, including civil fines, and injunctions. Third parties may also have the right to pursue legal actions to enforce compliance with certain laws and regulations. It is possible that increasingly strict environmental, health and safety laws, regulations, and enforcement policies could result in substantial costs and liabilities to us.
For example, the EPA has asserted federal regulatory authority under the Safe Drinking Water Act Underground Injection Control program over certain hydraulic fracturing activities involving the use of diesel fuels and published permitting guidance for such activities, and issued a final regulation under the Clean Water Act prohibiting discharges to publicly owned treatment works of wastewater from onshore unconventional oil and gas facilities. Additionally, in December 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources, concluding that “water cycle” activities associated with hydraulic fracturing may impact drinking water resources “under some circumstances,” including 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. Certain environmental and other groups have suggested that additional federal, state, and local laws and regulations may be needed to more closely regulate the hydraulic fracturing process. Several states have adopted regulations that require operators to disclose the chemical constituents in hydraulic fracturing fluids. We cannot predict whether any federal, state or local laws or regulations will be enacted regarding hydraulic fracturing, and, if so, what actions any such laws or regulations would require or prohibit. If additional levels of regulation or permitting requirements were imposed on oil and gas operators through the adoption of new laws and regulations, the domestic demand for certain of our products and services could be decreased or subject to delays.
We operate in the U.S. Gulf of Mexico. At this time, we cannot predict the full impact that other regulatory actions that may be mandated by the federal government may have on our operations or the operations of our customers. Other governmental or regulatory actions could further reduce our revenues and increase our operating costs, including the cost to insure offshore operations, resulting in reduced cash flows and profitability.
Our onshore and offshore operations expose us to risks such as the potential for harmful substances escaping into the environment and causing damages or injuries, which could be substantial. We maintain limited environmental liability insurance covering named locations and environmental risks associated with contract services for oil and gas operations. We could be materially and adversely affected by an enforcement proceeding or a claim that is not covered or is only partially covered by insurance.
Because our business depends on the level of activity in the oil and natural gas industry, existing or future laws, regulations, treaties, or international agreements that impose additional restrictions on the industry may adversely affect our financial results. Regulators are becoming more focused on air emissions from oil and gas operations, including volatile organic compounds, hazardous air pollutants, and greenhouse gases (“GHGs”). In particular, the focus on GHGs and climate change, including incentives to conserve energy or use alternative energy sources, could have a negative impact on our financial results if such laws, regulations, treaties, or international agreements reduce the worldwide demand for oil and natural gas or otherwise result in reduced economic activity generally. In addition, such laws, regulations, treaties, or international agreements could result in increased compliance costs, capital spending requirements, or additional operating restrictions for us, which may have a negative impact on our financial results.
In addition to increasing our risk of environmental liability, the rigorous enforcement of environmental laws and regulations has accelerated demand for our products and services in some of the markets we serve.
Climate change legislation or regulations restricting emissions of GHGs could result in increased operating costs and reduced demand for the oil and natural gas our customers produce, while the physical effects of climate change could disrupt production and cause us to incur costs in preparing for or responding to those effects.
The EPA has adopted various regulations to restrict emissions of GHGs under existing provisions of the CAA. Such EPA rules regulate GHG emissions under the CAA and require a reduction in emissions of GHGs from motor vehicles and from certain large stationary sources. For example, the EPA published final rules in June 2016 that require the reduction of volatile organic compounds and methane emissions from certain hydraulically fractured natural gas wells and further require that most wells use so-called “green” completions. These regulations also established new requirements regarding emissions from production-related wet seal and reciprocating compressors, pneumatic controllers and storage vessels. While the EPA under the Trump Administration finalized rules to rescind or modify certain of these requirements in September 2020, including rescission of the methane-specific requirements applicable to sources in the production and processing segments of the oil and gas industry, various states and industry and environmental groups are separately challenging the EPA’s 2016 standards and its September 2020 final rule. Moreover, notwithstanding the current court challenges, the EPA under the Biden Administration is expected to reconsider the September 2020 final rule, which could result in more stringent methane emission rulemaking. In addition, the EPA also requires the annual reporting of GHG emissions from specified large GHG emission sources in the United States, including petroleum refineries, as well as from certain oil and gas production facilities.
In addition, in December 2015, over 190 countries, including the United States, reached an agreement to reduce global GHG emissions (the “Paris Agreement”). The Paris Agreement entered into force in November 2016 after more than 170 nations ratified or otherwise indicated their intent to be bound by the Paris Agreement. Although the United States withdrew from the Paris Agreement in November 2020, President Biden issued an executive order recommitting the United States to the Paris Agreement in January 2021.
President Biden has also issued executive orders that commit to substantial action on climate change, calling for, among other things, the increased use of zero-emissions vehicles by the federal government, the elimination of subsidies provided to the fossil fuel industry, and an increased emphasis on climate-related risk across government agencies and economic sectors. The adoption and implementation of any regulations imposing reporting obligations on, or limiting emissions of GHGs from, our facilities and operations could require us to incur costs. The U.S. Congress (“Congress”) has considered and almost one-half of the states have adopted legislation that seeks to control or reduce emissions of GHGs from a wide range of sources. Any such legislation could adversely affect demand for the oil and natural gas our customers produce and, in turn, demand for our products and services. Finally, it should be noted that some scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods, and other climatic events; if any such effects were to occur, they could have an adverse effect on our operations and cause us to incur costs in preparing for or responding to those effects.
Our operations in foreign countries exposes us to complex regulations and may present us with new obstacles to growth.
We plan to continue to grow both in the United States and in foreign countries. We have established operations in Argentina, Brazil, Finland, Ghana, Mexico, Norway, Saudi Arabia, Sweden, and the United Kingdom, as well as other foreign countries. Foreign operations carry special risks. Our business in the countries in which we currently operate and those in which we may operate in the future could be limited or disrupted by:
•restrictions on repatriating cash back to the United States;
•the impact of compliance with anti-corruption laws on our operations and competitive position in affected countries and the risk that actions taken by us or our agents may violate those laws;
•government controls and government actions, such as expropriation of assets and changes in legal and regulatory environments;
•import and export license requirements;
•political, social, or economic instability;
•trade restrictions;
•changes in tariffs and taxes; and
•our limited knowledge of these markets or our inability to protect our interests.
We and our affiliates operate in countries where governmental corruption has been known to exist. While we and our subsidiaries are committed to conducting business in a legal and ethical manner, there is a risk of violating the U.S. Foreign Corrupt Practices Act, the U.K Bribery Act, or laws or legislation promulgated pursuant to the 1997 OECD Convention on Combating Bribery of Foreign Public Officials in International Business Transactions or other applicable anti-corruption regulations that generally prohibit the making of improper payments to foreign officials for the purpose of obtaining or keeping business. Violation of these laws could result in monetary penalties against us or our subsidiaries and could damage our reputation and our ability to do business.
Foreign governments and agencies often establish permit and regulatory standards different from those in the U.S. If we cannot obtain foreign regulatory approvals, or if we cannot obtain them in a timely manner, our growth and profitability from foreign operations could be adversely affected.
Regulatory initiatives related to hydraulic fracturing in the countries where we and our customers operate could result in operating restrictions or delays in the completion of oil and gas wells that may reduce demand for our services.
Although we do not directly engage in hydraulic fracturing, our operations support many of our exploration and production customers in such activities. The practice continues to be controversial in certain parts of the country, resulting in increased scrutiny and regulation of the hydraulic fracturing process, including by federal and state agencies and local municipalities.
Hydraulic fracturing typically is regulated by state oil and gas commissions or similar state agencies, but several federal agencies have asserted regulatory authority over certain aspects of the process in the U.S. For example, the EPA (i) asserted regulatory authority pursuant to the federal Safe Drinking Water Act Underground Injection Control program over hydraulic fracturing activities involving the use of diesel and issued guidance covering such activities, (ii) published final rules under the federal CAA in 2012 and published additional final regulations in June 2016 governing methane and volatile organic compound performance standards, including standards for the capture of air emissions released by the oil and natural gas hydraulic fracturing industry (however, rules were finalized in September 2020 modifying or rescinding some of these requirements), (iii) in June 2016 published an effluent limitations final rule prohibiting the discharge of waste water from shale natural-gas extraction operations to a treatment plant, and (iv) in 2014 published an Advance Notice of Proposed Rulemaking regarding Toxic Substances Control Act reporting of the chemical substances and mixtures used in hydraulic fracturing. In 2016, the U.S. Bureau of Land Management (“BLM”) published a final rule that established new or more stringent standards for performing hydraulic fracturing on federal and Indian lands. BLM under the Trump Administration issued a final rule in late 2018 rescinding the 2016 action; however, a California federal court vacated the 2018 final rule in July 2020, and a Wyoming federal court subsequently vacated the 2016 final rule in October 2020. Accordingly, the 2016 final rule is no longer in effect, but the Wyoming decision is expected to be appealed. Moreover, the Biden Administration is expected to pursue regulatory initiatives that restrict hydraulic fracturing activities on federal lands as well as other actions to more stringently regulate certain aspects of oil and gas development such as air emissions and water discharges. On January 20, 2021, the Acting Secretary of the U.S. Department of the Interior issued an order, effective immediately, that suspends new oil and gas leases and drilling permits on non-Indian federal lands and waters for a period of 60 days. In addition, President Biden issued an executive order on January 27, 2021, that suspends new leasing activities for oil and gas exploration and production on non-Indian federal lands and offshore waters pending completion of a comprehensive review and reconsideration of federal oil and gas permitting and leasing practices that take into consideration potential climate and other impacts associated with oil and gas activities on such lands and waters. However, these orders do not apply to operations under existing leases and permits.
The Congress has from time to time considered legislation to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the hydraulic fracturing process. At the state level, some states, including Texas, Oklahoma and New Mexico, have adopted, and other states are considering adopting legal requirements that could impose new or more stringent permitting, public disclosure, or well construction requirements on hydraulic fracturing activities. States could elect to prohibit high volume hydraulic fracturing altogether, following the approach taken by the State of New York in 2015. Local governments also may seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular. If new or more stringent federal, state, or local legal restrictions relating to the hydraulic fracturing process are adopted, our customers could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development or production activities, and perhaps even be precluded from drilling wells.
Increased regulation and attention given to the hydraulic fracturing process could lead to greater opposition to oil and gas production activities using hydraulic fracturing techniques. Additional legislation or regulation could also lead to operational delays or increased operating costs for our customers in the production of oil and gas, including from the developing shale plays, or could make it more difficult to perform hydraulic fracturing. The adoption of any federal, state or local laws or the implementation of additional regulations regarding hydraulic fracturing could potentially cause a decrease in the completion of new oil and gas wells and an associated decrease in demand for our services and increased compliance costs and time, which could have a material adverse effect on our liquidity, consolidated results of operations, and consolidated financial condition.
Our proprietary rights may be violated or compromised, which could damage our operations.
We own numerous patents, patent applications, and unpatented trade secret technologies in the U.S. and certain foreign countries. There can be no assurance that the steps we have taken to protect our proprietary rights will be adequate to deter misappropriation of these rights. In addition, independent third parties may develop competitive or superior technologies.
Our operations and reputation may be impaired if our information technology systems fail to perform adequately or if we are the subject of a data breach or cyberattack.
Our information technology systems are critically important to operating our business efficiently. We rely on our information technology systems to manage our business data, communications, supply chain, customer invoicing, employee information, and other business processes. We outsource certain business process functions to third-party providers and similarly rely on these third parties to maintain and store confidential information on their systems. The failure of these information technology systems to perform as we anticipate could disrupt our business and could result in transaction errors, processing inefficiencies, and the loss of sales and customers, causing our business and results of operations to suffer.
Although we allocate significant resources to protect our information technology systems, we have experienced varying degrees of cyber-incidents in the normal conduct of our business, including viruses, worms, other destructive software, process breakdowns, phishing and other malicious activities. On January 6, 2020, the Department of Homeland Security issued a public warning that indicated companies in the energy industry might be specific targets of cybersecurity threats. Such breaches have in the past and could again in the future result in unauthorized access to information including customer, supplier, employee, or other company confidential data. We do carry insurance against these risks, although the potential damages we might incur could exceed our available insurance coverage. We also invest in security technology, perform penetration tests from time to time, and design our business processes to attempt to mitigate the risk of such breaches. However, there can be no assurance that security breaches will not occur. Moreover, the development and maintenance of these measures requires continuous monitoring as technologies change and efforts to overcome security measures evolve. We have experienced and expect to continue to experience, cyber security threats and incidents, none of which has been material to us to date. However, a successful breach or attack could have a material negative impact on our operations or business reputation and subject us to consequences such as litigation and direct costs associated with incident response.

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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.
Our properties consist primarily of our corporate headquarters facility, chemical plants, processing plants and distribution facilities. The following information describes facilities that we leased or owned as of December 31, 2020. We believe our facilities are adequate for our present needs.
Facilities
Completion Fluids & Products Division
Our Completion Fluids & Products Division facilities include six operating chemical production plants located in the states of Arkansas, California, Louisiana, and West Virginia, and the country of Finland, having a total production capacity of more than 1.1 million equivalent liquid tons per year. The two California locations consist of 29 square miles of leased mineral acreage and solar evaporation ponds, and related owned production and storage facilities.
As an inducement to locate our El Dorado calcium chloride production plant in Union County, Arkansas, we received certain ad valorem property tax incentives. Our facility is located just outside the city of El Dorado, Arkansas, on property that is leased from Union County, Arkansas. We have the option of purchasing the property at any time during the term of the lease for a nominal price. The term of the lease expires in 2035, at which time we also have the option to purchase the property at a nominal price. Under the terms of the lease, we are responsible for all costs incurred related to the facility. In April 2020, in response to market conditions, we began the process of discontinuing chemical production operations at this facility. We continued to manufacture and deliver products through early June 2020, at which time we began a sequenced shutdown of the manufacturing facility. As of December 31, 2020, the plant is not operational.
In addition to the production facilities described above, the Completion Fluids & Products Division owns or leases multiple service center facilities in the United States and in other countries. The Completion Fluids & Products Division also leases several offices and numerous terminal locations in the U.S. and in other countries.
We lease over 27,000 acres of brine leases in Magnolia, Arkansas, which contain bromine and lithium. This acreage is leased for possible future development and as a source of supply for our bromine and other raw materials.
Water & Flowback Services Division
The Water & Flowback Services Division conducts its operations through production testing service centers (most of which are leased) in the U.S., located in Arkansas, Colorado, Louisiana, New Mexico, North Dakota, Oklahoma, Pennsylvania, Texas, West Virginia, and Wyoming. In addition, the Water & Flowback Services Division has leased facilities in Mexico and certain countries in Europe, the Middle East and South America.
Corporate
Our headquarters is located in The Woodlands, Texas, in a 153,000 square foot office building, which is located on 2.6 acres of land, under a lease that expires in 2027. In addition, we own a 28,000 square foot technical facility in The Woodlands, Texas, to service our Completion Fluids & Products and Water & Flowback Services Divisions’ operations.

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ITEM 3. LEGAL PROCEEDINGS
Item 3. Legal Proceedings.
We are named defendants in numerous lawsuits and respondents in certain governmental proceedings arising in the ordinary course of business. While the outcome of lawsuits or other proceedings against us cannot be predicted with certainty, management does not consider it reasonably possible that a loss resulting from such lawsuits or other proceedings in excess of any amounts accrued has been incurred that is expected to have a material adverse effect on our financial condition, results of operations or liquidity. See Note 12 - “Commitments and Contingencies” in the Notes to Consolidated Financial Statements for further information.

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ITEM 4. MINE SAFETY DISCLOSURE
Item 4. Mine Safety Disclosures.
None.
PART II

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ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters, and Issuer Repurchases of Equity Securities.
Common Stock
Our common stock is traded on the New York Stock Exchange under the symbol “TTI.” As of March 3, 2021, there were approximately 284 holders of record of the common stock. The actual number of holders of our common stock is greater than this number of record holders and includes common stockholders who are beneficial owners but whose shares are held in street name by banks, brokers and other nominees.
Securities Authorized for Issuance Under Equity Compensation Plans
For additional information about common stock authorized for issuance under equity compensation plans, see Note 14 - “Equity-Based Compensation and Other” in the Notes to Consolidated Financial Statements.

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ITEM 6. SELECTED FINANCIAL DATA
Item 6. Selected Financial Data.
Not required.

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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 is intended to analyze major elements of our consolidated financial statements and provide insight into important areas of management’s focus. This section should be read in conjunction with the Consolidated Financial Statements and the accompanying Notes included elsewhere in this Annual Report. Statements in the following discussion may include forward-looking statements. These forward-looking statements involve risks and uncertainties. See “Item 1A. Risk Factors” for additional discussion of these factors and risks.
Business Overview
We are a geographically diversified oil and gas services company, focused on completion fluids and associated products and services, comprehensive water management, frac flowback, production well testing and offshore rig cooling services. Prior to the closing of the GP Sale on January 29, 2021, we operated in three reporting segments organized into three Divisions. Following the closing of the GP sale, we operate through two reporting segments organized into two Divisions - Completion Fluids & Products and Water & Flowback Services.
Demand for products and services of our Completion Fluids & Products Division remained resilient during 2020 despite the unprecedented effect of the COVID-19 pandemic on the oil and gas industry. The impact of lower US activity was partially offset by strong international sales in the Middle East and Europe. While significant macro-economic uncertainty remains, oil prices have returned to pre-pandemic levels and activity is expected to continue to rebound from its recent lows.
Lower commodity prices during 2020 particularly affected domestic onshore demand for our Water & Flowback Services Division. However, although water management services activity dropped significantly during the second and third quarters, we began to see some recovery in activity levels during the fourth quarter as oil and gas prices stabilized above $40.
Our former Compression Division provided compression services for natural gas and oil production, gathering, artificial lift, transmission, processing, and storage. Our former Compression Division operated primarily through CCLP, of which we owned 35% of the common equity and controlled through our ownership of its general partner as of December 31, 2020. On January 29, 2021, we entered into the Purchase and Sale Agreement with Spartan pursuant to which we sold the general partner of CCLP, including IDRs in CCLP and approximately 23.1% of the outstanding limited partner interests in CCLP, in exchange for a combination of $13.4 million in cash paid at closing, $0.5 million in cash payable on the six-month anniversary of the closing and $3.1 million in contingent consideration in the form of cash and/or CCLP common units if CCLP achieves certain financial target on or before December 31, 2022. We were required to use all net cash proceeds received at closing from the sale to repay borrowings under our Term Credit Agreement. Following the closing of the transaction, we retained approximately 11.1% of the outstanding CCLP common units. We have reflected the operations of our former Compression Division as discontinued operations for all periods presented. See Note 3 - “Discontinued Operations” and Note 18- “Subsequent Event” in the Notes to Consolidated Financial Statements for further information.
We actively managed our flexible cost structure as a proactive response to the changing market conditions throughout 2020. We implemented temporary and permanent cost actions in 2020, including reduced capital expenditures, workforce reductions, salary reductions, suspension of 401(k) matching contributions for our employees and negotiated reductions in expenditures with many of our suppliers. While we are not able to predict how long market disruptions resulting from the COVID-19 pandemic will continue, or what impact it will ultimately have on our business, we saw activity levels begin to stabilize starting at the end of the third quarter 2020 and increase since then.
Results of Operations
The following data should be read in conjunction with the Consolidated Financial Statements and the associated Notes contained elsewhere in this report.
2020 Compared to 2019
Consolidated Comparisons
Year Ended
December 31, Period to Period Change
2020 2019 2020 vs. 2019 % Change
(In Thousands, Except Percentages)
Revenues $ 377,715 $ 561,241 $ (183,526) (32.7) %
Gross profit 67,543 11,807 55,736 472.1 %
Gross profit as a percentage of revenue
17.9 % 2.1 %
General and administrative expense 76,697 96,466 (19,769) (20.5) %
General and administrative expense as a percentage of revenue
20.3 % 17.2 %
Goodwill impairment - 25,784 (25,784)
Interest expense, net 18,926 21,256 (2,330) (11.0) %
Gain on sale of assets (2,878) (1,665) (1,213) 72.9 %
Warrants fair value adjustment (251) (1,624) 1,373 (84.5) %
Other (income) expense, net 135 (301) 436 (144.9) %
Loss before taxes and discontinued operations (25,086) (128,109) 103,023 (80.4) %
Loss before taxes and discontinued operations as a percentage of revenue
(6.6) % (22.8) %
Provision for income taxes 1,758 2,811 (1,053) (37.5) %
Loss before discontinued operations (26,844) (130,920) 104,076 (79.5) %
Loss from discontinued operations, net of taxes (72,089) (29,580) (42,509) 143.7 %
Net loss (98,933) (160,500) 61,567 (38.4) %
Loss attributable to noncontrolling interest 47,790 13,087 34,703 265.2 %
Net loss attributable to TETRA stockholders $ (51,143) $ (147,413) $ 96,270 (65.3) %
Revenues
Consolidated revenues for 2020 decreased compared to the prior year primarily due to lower activity in our Water & Flowback Services Division, where revenue decreased by $146.9 million. The decreased for this division was driven by a significant reduction in capital spending by our customers in response to the decline in oil prices associated with the COVID-19 pandemic. See Divisional Comparisons section below for additional discussion.
Gross Profit
Consolidated gross profit increased during 2020 compared to the prior year primarily due to a $91.8 million impairment charge at our El Dorado plant, which reduced gross profit for the Completion Fluids and Products Division in 2019. Despite lower activity levels, this division continued to deliver strong margins during 2020 and generated gross profit that was in line with the prior year gross profit before impairments. The increased gross profit for the Completion Fluids and Products Division in 2020 was partially offset by results for the Water & Flowback Services Division, where lower revenues impacted gross profit, despite aggressive management of costs.
General and Administrative Expense
Consolidated general and administrative expenses decreased during 2020 compared to the prior year primarily due to decreased salary related expenses of $19.1 million, decreased general expenses of $1.9 million and decreased professional services fees of $1.7 million. These decreases were partially offset by increased bad debt expenses of $3.3 million. Decreased general and administrative expenses were primarily driven by our
Corporate Division. Most of the decrease in general and administrative expenses resulted from restructuring and headcount reductions in response to the decline in activity levels, particularly in our U.S. onshore operations. Despite the significant cost reduction, general and administrative expense as a percentage of revenues increased compared to the prior year due to lower revenues.
Interest Expense, Net
Consolidated interest expense, net, decreased in 2020 compared to the prior year primarily due to a decrease in Corporate interest expense. Corporate interest expense decreased due to lower borrowings under the ABL Credit Agreement. Interest expense during 2020 and 2019 includes $1.6 million and $1.4 million, respectively, of finance cost amortization.
Gain on Sale of Assets
Consolidated gain on sale of assets increased during 2020 compared to the prior year primarily due to increased sales of assets during the year.
Warrants
The warrants are accounted for as a derivative liability in accordance with ASC 815 and therefore they are classified as a long-term liability on our consolidated balance sheet at their fair value. Increases (or decreases) in the fair value of the warrants are generally associated with increases (or decreases) in the trading price of our common stock, resulting in adjustments to earnings for the associated valuation losses (gains), and resulting in future volatility of our earnings during the period the warrants are outstanding.
Loss from Discontinued Operations
The loss from discontinued operations increased during 2020 compared to 2019 primarily due to lower revenues from our former Compression Division as well as increased impairments recognized during 2020 as a result of the recent market conditions, partially offset by lower operating costs from our former Compression Division. The loss from discontinued operations also decreased $9.0 million from loss reserves recorded during 2019 related to the exit from the Offshore Division.
Provision for Income Tax
Our consolidated provision for income taxes during 2020 was primarily attributable to taxes in certain foreign jurisdictions and Texas gross margin taxes. Our consolidated effective tax rate for the year ended December 31, 2020 of negative 7.0% was primarily the result of losses generated in entities for which no related tax benefit has been recorded. The losses generated by these entities do not result in tax benefits due to offsetting valuation allowances being recorded against the related net deferred tax assets. We establish a valuation allowance to reduce the deferred tax assets when it is more likely than not that some portion or all of the deferred tax assets will not be realized. Included in our deferred tax assets are $104.5 million of net operating loss carryforwards that may be available to offset future income tax liabilities in the U.S. as well as in certain international jurisdictions where net operating loss carryforwards exist.
Divisional Comparisons
Completion Fluids & Products Division
Year Ended
December 31, Period to Period Change
2020 2019 2020 vs. 2019 % Change
(In Thousands, Except Percentages)
Revenues $ 242,661 $ 279,255 $ (36,594) (13.1) %
Gross profit (loss) 77,206 (15,034) 92,240 (613.5) %
Gross profit (loss) as a percentage of revenue 31.8 % (5.4) %
General and administrative expense 24,852 19,990 4,862 24.3 %
General and administrative expense as a percentage of revenue 10.2 % 7.2 %
Interest (income) expense, net (666) (720) 54 (7.5) %
Other (income) expense, net (2,314) (335) (1,979) 590.7 %
Income (loss) before taxes and discontinued operations $ 55,334 $ (33,969) $ 89,303 (262.9) %
Income (loss) before taxes as a percentage of revenue 22.8 % (12.2) %
The decrease in Completion Fluids & Products Division revenues during 2020 compared to the prior year was primarily due to lower activity related to the decline in oil and gas prices resulting from the COVID-19 pandemic.
Completion Fluids & Products Division gross profit during 2020 increased compared to the prior year primarily due to a $91.8 million impairment charge at our El Dorado plant, which reduced gross profit for the prior year. Despite lower activity levels, the division continued to deliver strong margins and generated gross profit that was broadly in line with the prior year gross profit before impairments. Completion Fluids & Products Division profitability in future periods will be continue to be affected by the mix of its products and services, including the timing of TETRA CS Neptune completion fluid projects.
The Completion Fluids & Products Division reported a pretax income during 2020 compared to pretax loss in the prior year primarily due to the increase in gross profit discussed above. Completion Fluids & Products Division administrative cost levels increased compared to the prior year, primarily due to increased bad debt of $3.5 million and increased salary and employee related expenses of $1.3 million.
Water & Flowback Services Division
Year Ended
December 31, Period to Period Change
2020 2019 2020 vs. 2019 % Change
(In Thousands, Except Percentages)
Revenues $ 135,054 $ 281,986 $ (146,932) (52.1) %
Gross profit (8,856) 27,458 (36,314) (132.3) %
Gross profit as a percentage of revenue (6.6) % 9.7 %
General and administrative expense 15,644 25,009 (9,365) (37.4) %
General and administrative expense as a percentage of revenue 11.6 % 8.9 %
Goodwill impairment 25,784 (25,784)
Interest (income) expense, net (1,135) (1) (1,134) - %
Other (income) expense, net (1,515) (2,161) 646 (29.9) %
Loss before taxes and discontinued operations $ (21,850) $ (21,173) $ (677) 3.2 %
Income (loss) before taxes as a percentage of revenue (16.2) % (7.5) %
Water & Flowback Services Division revenues decreased during 2020 compared to the prior year primarily due to reduced customer drilling and completions activity as a result of lower oil and gas prices caused primarily by
the ongoing COVID-19 pandemic. Water management and flowback service revenues decreased $148.9 million during 2020 compared to the prior year. The volatility in oil and gas commodity prices driving reductions in customer capital spending has resulted in decreased pricing and activity when compared to the prior year, leading to lower revenues and margins. Product sales revenue increased by $2.0 million, due to higher equipment sales in the US.
The Water & Flowback Services Division reflected a gross loss during 2020 compared a gross profit in the prior year primarily due to lower revenues associated with lower activity levels.
The Water & Flowback Services Division reported a slight increase in pretax loss compared to the prior year, primarily due to the gross loss described above, offset by the goodwill impairment recognized in 2019. General and administrative expenses decreased primarily due to decreased wage and benefit expenses of $7.3 million, decreased general expenses of $1.4 million, and decreased bad debt expense of $0.7 million.
Corporate Overhead
Year Ended
December 31, Period to Period Change
2020 2019 2020 vs. 2019 % Change
(In Thousands, Except Percentages)
Depreciation and amortization $ 818 $ 631 $ 187 (29.6) %
General and administrative expense 36,201 51,466 (15,265) (29.7) %
Interest expense, net 20,727 21,977 (1,250) (5.7) %
Warrants fair value adjustment (income) expense (251) (1,624) 1,373 (84.5) %
Other (income) expense, net 1,087 531 556 104.7 %
Loss before taxes $ (58,582) $ (72,981) $ 14,399 19.7 %
Corporate Overhead pretax loss decreased during 2020 compared to the prior year primarily due to decreased general and administrative expense and decreased interest expense. Corporate general and administrative expense decreased primarily due to decreased salary related expense of $13.1 million, $1.2 million of decreased general expenses and $1.0 million of decreased professional fees. Interest expense decreased due to lower borrowings under the ABL Credit Agreement. The fair value of the outstanding warrants liability resulted in a $0.3 million credit to earnings in the current year compared to a $1.6 million credit to earnings during 2019.
How we Evaluate Operations
We use U.S. GAAP financial measures such as revenues, gross profit, income (loss) before taxes, and net cash provided by operating activities, as well as certain non-GAAP financial measures, including Adjusted EBITDA, as performance measures for our business.
Adjusted EBITDA. We view Adjusted EBITDA as one of our primary management tools, and we track it on a monthly basis, both in dollars and as a percentage of revenues (typically compared to the prior month, prior year period, and to budget). We define Adjusted EBITDA as earnings before interest, taxes, depreciation, amortization, impairments and certain non-cash charges and non-recurring adjustments.
Adjusted EBITDA is used as a supplemental financial measure by our management to:
•evaluate the financial performance of our assets without regard to financing methods, capital structure, or historical cost basis; and
•determine our ability to incur and service debt and fund capital expenditures.
The following table reconciles net income (loss) to Adjusted EBITDA for the periods indicated:
Year Ended
December 31, 2020
Net Income (Loss), as reported Tax Provision Income (Loss) Before Tax, as Reported Impairments & Special Charges Adjusted Income (Loss) Before Tax Interest Expense, Net
Depreciation & Amortization
Equity Comp. Expense Adjusted EBITDA
(In Thousands)
Completion Fluids & Products Division
$ 55,334 $ 6,370 $ 61,704 $ (853) $ 7,389 $ - $ 68,240
Water & Flowback Services Division
(21,850) 3,960 (17,890) (1,594) 30,384 - 10,900
Eliminations and other
12 - 12 - (12) - -
Subtotal
33,496 10,330 43,826 (2,447) 37,761 - 79,140
Corporate G&A (36,201) 2,185 (34,016) - 4,721 (29,295)
Other (22,381) 226 (22,155) 20,727 720 - (708)
TETRA excluding Discontinued Operations
$ (26,844) $ 1,758 $ (25,086) $ 12,741 $ (12,345) $ 18,280 $ 38,481 $ 4,721 $ 49,137
Year Ended
December 31, 2019
Net Income (Loss), as reported Tax Provision Income (Loss) Before Tax, as Reported Impairments & Special Charges Adjusted Income (Loss) Before Tax Interest Expense, Net Depreciation & Amortization Equity Comp. Expense Adjusted EBITDA
(In Thousands)
Completion Fluids & Products Division
$ (33,969) $ 91,140 $ 57,171 $ (720) $ 13,518 $ - $ 69,969
Water & Flowback Services Division
(21,173) 25,619 4,446 (1) 33,424 - 37,869
Eliminations and other
14 - 14 - (14) - -
Subtotal
(55,128) 116,759 61,631 (721) 46,928 - 107,838
Corporate G&A (51,466) 2,085 (49,381) 7,064 (42,317)
Other (21,515) (1,471) (22,986) 21,473 635 - (878)
TETRA excluding Discontinued Operations
$ (130,920) $ 2,811 $ (128,109) $ 117,373 $ (10,736) $ 20,752 $ 47,563 $ 7,064 $ 64,643
Adjusted EBITDA is a financial measure that is not in accordance with U.S. GAAP and should not be considered an alternative to net income, operating income, cash flows from operating activities, or any other measure of financial performance presented in accordance with U.S. GAAP. This measure may not be comparable to similarly titled financial metrics of other entities, as other entities may not calculate Adjusted EBITDA in the same manner as we do. Management compensates for the limitations of Adjusted EBITDA as analytical tools by reviewing the comparable U.S. GAAP measures, understanding the differences between the measures, and incorporating this knowledge into management’s decision-making processes.
Liquidity and Capital Resources
We believe that our capital structure allows us to meet our financial obligations despite current uncertain operating conditions and financial markets. Our liquidity at the end of fourth quarter was $91.9 million. Liquidity is defined as unrestricted cash plus availability under the revolving credit facility.
Our consolidated sources and uses of cash, including cash activity from our former Compression Division, during the years ended December 31, 2020 and 2019 are as follows:
Year Ended December 31,
2020 2019
(In Thousands)
Operating activities $ 76,912 $ 90,232
Investing activities 6,038 (106,442)
Financing activities (17,629) (5,925)
Consolidated cash flows provided by operating activities totaled $76.9 million during 2020 compared to $90.2 million during the prior year, a decrease of $13.3 million. CCLP generated $20.8 million of our consolidated cash flows provided by operating activities during the year ended December 31, 2020 compared to $67.7 million during the prior year. Operating cash flows decreased primarily due to a decrease in revenues, which were partly offset by monetization of working capital. During 2020, TETRA increased cash generation, which offset CCLP’s decreased cash generation. Our cash flows from operating, investing and financing activities will no longer include cash activities of our former Compression Division, including CCLP, following the GP Sale on January 29, 2021. We continue to monitor customer credit risk in the current environment and focus on serving larger capitalized oil and gas operators and national oil companies.
Investing Activities
During 2020, CCLP launched an initiative to rationalize its fleet by selling smaller and mid-sized equipment to focus on the larger-horsepower fleet as well as to sell equipment outside its core area of focus. One of CCLP’s larger customers purchased a small number of large units recently deployed. Additionally during 2020, the Partnership sold its Midland fabrication facility and real estate for $17.0 million. Investing cash flows for 2020 also include $14.2 million from TETRA’s sale of 15 high horse power compressor units to Spartan during the fourth quarter. As a result of CCLP’s and TETRA’s equipment sales, 2020 cash proceeds from the sale of used equipment exceed the cash outflows to purchase new equipment.
Total cash capital expenditures, including capital expenditures associated with discontinued operations, during 2020 were $29.4 million, net of $12.7 million cost of compressors sold, as we adjusted to current market conditions. Our Completion Fluids & Products Division spent $4.0 million on capital expenditures during 2020, the majority of which related to plant and facility additions. Our Water & Flowback Services Division spent $9.7 million on capital expenditures, primarily to maintain, automate and upgrade its water management and flowback equipment fleet. Our former Compression Division spent $14.7 million, primarily to maintain its compression fleet. 2019 Investing cash flows include proceeds of $12.9 million from the sale of property, plant and equipment primarily the result of a sale-leaseback transaction during the fourth quarter of 2019, where CCLP sold ten compression units and immediately leased them back at a monthly rate. These compression units are included in operating lease right-of-use assets on our consolidated balance sheets.
Historically, a significant majority of our planned capital expenditures have been related to identified opportunities to grow and expand our existing businesses. However, such expenditures have recently been, and may continue to be, postponed or canceled as we are reviewing all capital expenditure plans carefully in an effort to conserve cash. We currently have no long-term capital expenditure commitments. The deferral of capital projects could affect our ability to compete in the future.
If the forecasted demand for our products and services increases or decreases, the amount of planned expenditures on growth and expansion may be adjusted.
Through our common unit ownership interest in CCLP, which was approximately 35% as of December 31, 2020 and approximately 11% as of March 4, 2021, we receive quarterly cash distributions, if any, from CCLP. On January 19, 2021, CCLP announced a cash distribution of $0.01 per common unit for the quarter ended December 31, 2020, which was paid on February 12, 2021 based on our retained interest.
Financing Activities
During the year ended December 31, 2020, the total amount of consolidated net cash used in financing activities was $17.6 million, primarily related to pay down of our Term Credit Agreement, cash fees related to the exchange of CCLP debt and repayments under our ABL Credit Agreement. During the year ended December 31, 2019, the total amount of consolidated net cash provided by financing activities was $5.9 million, primarily due to borrowings under our ABL Credit Agreement and our Term Credit Agreement, net of cash redemptions of the CCLP Preferred Units. We may supplement our existing cash balances and cash flow from operating activities with short-term borrowings, long-term borrowings, issuances of equity and debt securities, and other sources of capital. We are aggressively managing our working capital and capital expenditure needs in order to maximize our liquidity in the current environment.
Asset-Based Credit Agreement. The ABL Credit Agreement provides for a senior secured revolving credit facility of up to $100 million, subject to a borrowing base to be determined by reference to the value of inventory and accounts receivable, and includes a sublimit of $20.0 million for letters of credit and a swingline loan sublimit of $10.0 million. The ABL Credit Agreement may be used for working capital needs, capital expenditures and other general corporate purposes. The amounts we may borrow under the ABL Credit Agreement are based on a percentage of our accounts receivable and certain inventory. Changes in demand for our products and services have an impact on our eligible accounts receivable, which could result in significant changes to our borrowing base and therefore our availability under our ABL Credit Agreement. With the current depressed oil and gas market conditions, we believe our availability under our ABL Credit facility will be adversely impacted by the expected decline in our customers’ activity levels. The ABL Credit Agreement is scheduled to mature on September 10, 2023. As of December 31, 2020, we had no outstanding balance under the ABL Credit Agreement and, subject to compliance with the covenants, borrowing base, and other provisions of the agreement that may limit borrowings, we had an availability of $24.6 million under the ABL Credit Agreement. As of March 3, 2021, we have no outstanding borrowings under our ABL Credit Agreement and $8.3 million letters of credit, resulting in $30.1 million of availability.
Term Credit Agreement. The Term Credit Agreement provides a loan in the amount of $220.5 million and is scheduled to mature on September 10, 2025 for certain acquisitions (the “Additional Term Loans,” and together with the Initial Term Loan, the “Term Loan”). Our Term Credit Agreement requires us to annually prepay up to 50% of Excess Cash Flow (as defined in the Term Credit Agreement) from the most recent full fiscal year. If our Leverage Ratio (as defined in the Term Credit Agreement) at year-end is less than 2.00 to 1.00, the prepayment requirement is decreased to 25%. If our Leverage Ratio at year-end is less than 1.50 to 1.00, then no prepayment is required. As of March 3, 2021, $201.7 million in aggregate principal amount of our Term Credit Agreement is outstanding.
As of December 31, 2020, we are in compliance with all covenants of our debt agreements. See Note 10 - “Long-Term Debt and Other Borrowings” in the Notes to Consolidated Financial Statements for further information.
Other Sources and Uses
In addition to the aforementioned credit facilities and senior notes, we fund our short-term liquidity requirements from cash generated by our operations and from short-term vendor financing. Should additional capital be required, the ability to raise such capital through the issuance of additional debt or equity securities may currently be limited. Instability or volatility in the capital markets at the times we need to access capital may affect the cost of capital and the ability to raise capital for an indeterminable length of time. If it is necessary to issue additional equity to fund our capital needs, additional dilution of our common stockholders will occur. We periodically evaluate engaging in strategic transactions and may consider divesting non-core assets where our evaluation suggests such transaction is in the best interest of our business. In challenging economic environments, we may experience increased delays and failures by customers to pay our invoices. Given the nature and significance of the COVID-19 pandemic and disruption in the oil and gas industry, we could experience delayed customer payments and payment defaults associated with customer liquidity issues and bankruptcies. If our customers delay paying or fail to pay us a significant amount of our outstanding receivables, it could have an adverse effect on our liquidity. An increase of unpaid receivables would also negatively affect our borrowing availability under the ABL Credit Agreement.
In November 2020, we sold 15 high horsepower compressor units to Spartan for $14.2 million. In connection with that sale, we also assigned a lease with CCLP for those units to Spartan. On January 29, 2021 we completed the GP Sale. Approximately $18.8 million in net cash proceeds from both the November 2020 compressor sale and the GP Sale were used to repay borrowings under our Term Credit Agreement.
On April 11, 2019, we filed a universal shelf Registration Statement on Form S-3 with the SEC. On May 1, 2019, the Registration Statement on Form S-3 was declared effective by the SEC. Pursuant to this registration statement, we have the ability to sell debt or equity securities in one or more public offerings up to an aggregate public offering price of $464.1 million, inclusive of $64.1 million of our common stock issuable upon conversion of our currently outstanding warrants. This shelf registration statement currently provides us additional flexibility with regard to potential financings that we may undertake when market conditions permit or our financial condition may require.
Critical Accounting Policies and Estimates
This discussion and analysis of our financial condition and results of operations is based upon our consolidated financial statements. We prepared these financial statements in conformity with U.S. GAAP. In preparing our consolidated financial statements, we make assumptions, estimates, and judgments that affect the amounts reported. We base these on historical experience, available information, and various other assumptions that we believe are reasonable. Our assumptions, estimates, and judgments may change as new events occur, as new information is acquired, and as changes in our operating environments are encountered. Actual results are likely to differ from our current estimates, and those differences may be material. The following critical accounting policies reflect the most significant judgments and estimates used in the preparation of our financial statements.
Impairment of Long-Lived Assets
The determination of impairment of long-lived assets, including identified intangible assets, is conducted periodically whenever indicators of impairment are present. If such indicators are present, the determination of the amount of impairment is based on our judgments as to the future operating cash flows to be generated from these assets throughout their estimated useful lives. If an impairment of a long-lived asset is warranted, we estimate the fair value of the asset based on a present value of these cash flows or the value that could be realized from disposing of the asset in a transaction between market participants. The oil and gas industry is cyclical, and our estimates of the amount of future cash flows, the period over which these estimated future cash flows will be generated, as well as the fair value of an impaired asset, are imprecise. Our failure to accurately estimate these future operating cash flows or fair values could result in certain long-lived assets being overstated, which could result in impairment charges in periods subsequent to the time in which the impairment indicators were first present. Alternatively, if our estimates of future operating cash flows or fair values are understated, impairments might be recognized unnecessarily or in excess of the appropriate amounts. During 2020, we recorded an impairment charge of $0.6 million primarily related to a right of use asset for the lease of our Canada office within our Water & Flowback Services Division as we ceased use of the office during the year.
Impairment of Goodwill
During the third quarter of 2019, we determined that the deteriorating energy industry outlook was an indicator requiring further analysis for impairment of goodwill. We determined at that time that the fair value of the Water Management reporting unit, the only reporting unit with goodwill, exceeded its carrying value and there was no impairment to goodwill.
During the fourth quarter of 2019, due to further deterioration in the energy industry outlook resulting in decreased expected future cash flows for our Water Management reporting unit, a component of our Water & Flowback Services Division, we recorded a full goodwill impairment of $25.9 million. As a result, there was no goodwill balance as of December 31, 2020 or December 31, 2019.
Off Balance Sheet Arrangements
An “off balance sheet arrangement” is defined as any contractual arrangement to which an entity that is not consolidated with us is a party, under which we have, or in the future may have:
•any obligation under a guarantee contract that requires initial recognition and measurement under U.S. GAAP;
•a retained or contingent interest in assets transferred to an unconsolidated entity or similar arrangement that serves as credit, liquidity, or market risk support to that entity for the transferred assets;
•any obligation under certain derivative instruments; or
•any obligation under a material variable interest held by us in an unconsolidated entity that provides financing, liquidity, market risk or credit risk support to us, or engages in leasing, hedging, or research and development services with us.
As of December 31, 2020 and 2019, we had no off balance sheet arrangements that may have a current or future material effect on our consolidated financial condition or results of operations.
Commitments and Contingencies
Litigation
For information regarding litigation, see See Note 12 - “Commitments and Contingencies” in the Notes to Consolidated Financial Statements.
Long-Term Debt
For information on our credit agreements, see Note 10 - “Long-Term Debt and Other Borrowings” in the Notes to Consolidated Financial Statements.
Asset Retirement Obligations
We operate facilities in various U.S. and foreign locations that are used in the manufacture, storage, and sale of our products, inventories, and equipment. We are required to take certain actions in connection with the retirement of these assets. See Note 2 - “Summary of Significant Accounting Policies” and Note 8 - “Leases” in the Notes to Consolidated Financial Statements for further information regarding asset retirement obligations.
Leases
We have operating leases for some of our transportation equipment, office space, warehouse space, operating locations, and machinery and equipment. Our leases have remaining lease terms ranging from 1 to 16 years. See Note 2 - “Summary of Significant Accounting Policies” in the Notes to Consolidated Financial Statements for further information our lease obligations.
Product Purchase Obligations
In the normal course of our Completion Fluids & Products Division operations, we enter into supply agreements with certain manufacturers of various raw materials and finished products. Some of these agreements have terms and conditions that specify a minimum or maximum level of purchases over the term of the agreement. Other agreements require us to purchase the entire output of the raw material or finished product produced by the manufacturer. Our purchase obligations under these agreements apply only with regard to raw materials and finished products that meet specifications set forth in the agreements. We recognize a liability for the purchase of such products at the time we receive them. As of December 31, 2020, the aggregate amount of the fixed and determinable portion of the purchase obligation pursuant to our Completion Fluids & Products Division’s supply agreements was approximately $85.3 million, extending through 2029, including commitments of $9.5 million per year from 2021 through 2025.
Contingencies of Discontinued Operations
In early 2018, we closed the Maritech Asset Purchase and Sale Agreement with Orinoco Natural Resources, LLC (“Orinoco”) that provided for the purchase by Orinoco of Maritech’s remaining oil and gas properties and related assets. Also in early 2018, we closed the Maritech Membership Interest Purchase and Sale Agreement with Orinoco that provided for the purchase by Orinoco of all of the outstanding membership interests in Maritech. As a result of these transactions, we have effectively exited the business of our former Maritech segment.
Under the Maritech Asset Purchase and Sale Agreement, Orinoco assumed all of Maritech’s decommissioning liabilities related to the leases sold to Orinoco (the “Orinoco Lease Liabilities”) and, under the Maritech Membership Interest Purchase and Sale Agreement, Orinoco assumed all other liabilities of Maritech, including the decommissioning liabilities associated with the oil and gas properties previously sold by Maritech (the “Legacy Liabilities”), subject to certain limited exceptions unrelated to the decommissioning liabilities. To the extent that Maritech or Orinoco fails to satisfy decommissioning liabilities associated with any of the Orinoco Lease Liabilities or the Legacy Liabilities, we may be required to satisfy such liabilities under third party indemnity agreements and corporate guarantees that we previously provided to the U.S. Department of the Interior and other parties, respectively.
Pursuant to a Bonding Agreement entered into as part of these transactions (the “Bonding Agreement”), Orinoco provided non-revocable performance bonds in an aggregate amount of $46.8 million to cover the performance by Orinoco and Maritech of the asset retirement obligations of Maritech (the “Initial Bonds”) and agreed to replace, within 90 days following the closing, the Initial Bonds with other non-revocable performance bonds, meeting certain requirements, in the aggregate sum of $47.0 million (collectively, the “Interim Replacement Bonds”). Orinoco further agreed to replace, within 180 days following the closing, the Interim Replacement Bonds with a maximum of three non-revocable performance bonds in the aggregate sum of $47.0 million, meeting certain requirements (the “Final Bonds”). Among the other requirements of the Final Bonds was that they must provide coverage for all of the asset retirement obligations of Maritech instead of only relating to specific properties. In the event Orinoco does not provide the Interim Replacement Bonds or the Final Bonds, Orinoco is required to make certain cash escrow payments to us.
The payment obligations of Orinoco under the Bonding Agreement were guaranteed by Thomas M. Clarke and Ana M. Clarke pursuant to a separate guaranty agreement (the “Clarke Bonding Guaranty Agreement”). Orinoco has not delivered such replacement bonds and neither it nor the Clarkes has made any of the agreed upon cash escrow payments and we filed a lawsuit against Orinoco and the Clarkes to enforce the terms of the Bonding Agreement and the Clarke Bonding Guaranty Agreement. A summary judgment was initially granted in favor of Orinoco and the Clarkes which dismissed our claims against Orinoco under the Bonding Agreement and against the Clarkes under the Clarke Bonding Guaranty Agreement. We filed an appeal and also asked the trial court to grant a new trial on the summary judgment or to modify the judgment because we believe this judgment should not have been granted. On November 5, 2019, the trial court signed an order granting our motion for new trial and vacating the prior order granting summary judgment for Orinoco and the Clarkes. The parties are awaiting direction from the court on a new scheduling order and/or trial setting. The Initial Bonds, which are non-revocable, remain in effect.
If we become liable in the future for any decommissioning liability associated with any property covered by either an Initial Bond or an Interim Replacement Bond while such bonds are outstanding and the payment made to us under such bond is not sufficient to satisfy such liability, the Bonding Agreement provides that Orinoco will pay us an amount equal to such deficiency and if Orinoco fails to pay any such amount, such amount must be paid by the Clarkes under the Clarke Bonding Guaranty Agreement. However, if the Final Bonds or the full amount of the escrowed cash have been provided, neither Orinoco nor the Clarkes would be liable to pay us for any such deficiency. Our financial condition and results of operations may be negatively affected if Orinoco is unable to cover any such deficiency or if we become liable for a significant portion of the decommissioning liabilities.
In early 2018, we also closed the sale of our Offshore Division to Epic Companies, LLC (“Epic Companies,” formerly known as Epic Offshore Specialty, LLC). Part of the consideration we received was a promissory note of Epic Companies in the original principal amount of $7.5 million (the “Epic Promissory Note”). At the end of August 2019, Epic Companies filed for bankruptcy and we recorded a reserve of $7.5 million for the full amount of the promissory note, including accrued interest, and certain other receivables in the amount of $1.5 million during the quarter ended September 30, 2019. The Epic Promissory Note became due on December 31, 2019 and neither Epic nor the Clarkes made payment. TETRA filed a lawsuit against the Clarkes on January 15, 2020 for breach of the promissory note guaranty agreement. In September 2020, the court granted TETRA’s Motion for Summary
Judgment and entered Final Judgment in our favor, dismissing counterclaims by the Clarkes and awarded TETRA $7.9 million in damages. The Clarkes have filed an appeal which we will defend. We cannot provide any assurance the Clarkes will pay the judgment or that they will not file for bankruptcy protection. If the Clarkes do file for bankruptcy protection, we likely would be unable to collect all, or even a significant portion of, the judgment owed to us.
For further discussion, see Note 3 - “Discontinued Operations” and Note 11 - “Acquisitions and Dispositions” in the Notes to Consolidated Financial Statements for further information.

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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Item 7A. Quantitative and Qualitative Disclosures about Market Risk.
Not applicable.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Item 8. Financial Statements and Supplementary Data.
The financial statements and supplementary data required to be included in this Item 8 are set forth in Item 15 of this Annual Report.

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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.
Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures
Under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, we conducted an evaluation of our disclosure controls and procedures, as such term is defined under Rule 13a-15(e) promulgated under the Exchange Act as of the end of the period covered by this report. Based on this evaluation, our Chief Executive Officer and Chief 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 such term is defined in Exchange Act Rule 13a-15(f). Our Internal control over financial reporting is a process to provide reasonable assurance regarding the reliability of our financial reporting for external purposes in accordance with accounting principles generally accepted in the United States of America.
Our internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that in reasonable detail accurately and fairly reflect the transactions and dispositions of our assets; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures are being made only in accordance with authorizations of our management and directors; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of our assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. In addition, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Under the supervision and with the participation of management, including our Chief Executive Officer and Chief Financial Officer, an evaluation of the effectiveness of our internal control over financial reporting as of December 31, 2020 was conducted based on the framework in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) (“COSO”). Based on
this assessment, management has determined that our internal control over financial reporting was effective as of December 31, 2020.
Grant Thornton LLP, our independent registered public accounting firm, has issued an attestation report on the effectiveness of our internal control over financial reporting as of December 31, 2020. Grant Thornton LLP’s report on our internal control over financial reporting is included herein.
Changes in Internal Control over Financial Reporting
There were no changes in our internal control over financial reporting that occurred during the fourth quarter of the fiscal year ended December 31, 2020, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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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 by this Item is hereby incorporated by reference from the information appearing under the captions “Proposal No. 1: Election of Directors,” “Executive Officers,” “Corporate Governance,” “Board Meetings and Committees,” in our definitive proxy statement (the “Proxy Statement”) for the annual meeting of stockholders to be held on April 29, 2021, which involves the election of directors and is to be filed with the SEC pursuant to the Exchange Act within 120 days of the end of our fiscal year on December 31, 2020.

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ITEM 11. EXECUTIVE COMPENSATION
Item 11. Executive Compensation.
The information required by this Item is hereby incorporated by reference from the information appearing under the captions “Management and Compensation Committee Report,” “Management and Compensation Committee Interlocks and Insider Participation,” “Compensation Discussion and Analysis,” “Compensation of Executive Officers,” and “Director Compensation” in our Proxy Statement. Notwithstanding the foregoing, in accordance with the instructions to Item 407 of Regulation S-K, the information contained in our Proxy Statement under the subheading “Compensation Committee Report” shall be deemed furnished, and not filed, in this Form 10-K, and shall not be deemed incorporated by reference into any filing under the Securities Act, or the Exchange Act, as a result of this furnishing, except to the extent we specifically incorporate it 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 by this Item is hereby incorporated by reference from the information appearing under the captions “Beneficial Stock Ownership of Certain Stockholders and Management” and “Equity Compensation Plan Information” in our Proxy Statement.

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ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Item 13. Certain Relationships and Related Transactions, and Director Independence.
The information required by this Item is hereby incorporated by reference from the information appearing under the captions “Certain Transactions” and “Director Independence” in our Proxy Statement.

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ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
Item 14. Principal Accounting Fees and Services.
The information required by this Item is hereby incorporated by reference from the information appearing under the caption “Fees Paid to Principal Accounting Firm” in our Proxy Statement.
PART IV

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ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
Item 15. Exhibits and Financial Statement Schedules.
(a) List of documents filed as part of this Report
1. Financial Statements of the Company
Page
Reports of Independent Registered Public Accounting Firms
Consolidated Balance Sheets at December 31, 2020 and 2019
Consolidated Statements of Operations for the years ended December 31, 2020, 2019, and 2018
Consolidated Statements of Comprehensive Income (Loss) for the years ended December 31, 2020, 2019, and 2018
Consolidated Statements of Equity for the years ended December 31, 2020, 2019, and 2018
Consolidated Statements of Cash Flows for the years ended December 31, 2020, 2019, and 2018
Notes to Consolidated Financial Statements
2. Financial statement schedules
All other schedules for which provision is made in the applicable accounting regulation of the Securities and Exchange Commission are not required under the related instructions or are inapplicable and therefore have been omitted.
3. List of Exhibits
2.1 Asset Purchase and Sale Agreement, dated February 28, 2018, by and between Maritech Resources, LLC, TETRA Technologies, Inc., and Orinoco Natural Resources, LLC (incorporated by reference to Exhibit 2.1 to the Company’s Quarterly Report filed on May 10, 2018 (SEC File No. 001-13455)).
2.2 Equity Interest Purchase and Sale Agreement, dated February 28, 2018, by and among TETRA Technologies, Inc., TETRA Production Testing Holding LLC, and Epic Offshore Specialty, LLC (incorporated by reference to Exhibit 2.2 to the Company’s Quarterly Report filed on May 10, 2018 (SEC File No. 001-13455)).
2.3 Equity Interest Purchase Agreement, dated February 13, 2018, by and among the sellers listed therein, the sellers representative and TETRA Technologies, Inc (incorporated by reference to Exhibit 2.3 to the Company’s Quarterly Report filed on May 10, 2018 (SEC File No. 001-13455)).
2.4 Membership Interest Purchase And Sale Agreement, dated as of February 28, 2018, by and among TETRA Applied Technologies, LLC, Maritech Resources, LLC, TETRA Technologies, Inc., and Orinoco Natural Resources, LLC (incorporated by reference to Exhibit 2.4 to the Company’s Quarterly Report filed on May 10, 2018 (SEC File No. 001-13455)).
2.5+++
Purchase and Sale Agreement dated as of January 29, 2021 between Spartan Energy Holdco, LLC, TETRA Technologies, Inc., and, solely for the limited purposes set forth therein, Spartan Energy Partners LP (incorporated by reference to Exhibit 2.1 to the Company's Form 8-K filed on January 29, 2021 (SEC File No. 001-13455)).
3.1 Restated Certificate of Incorporation of TETRA Technologies, Inc. (incorporated by reference to Exhibit 4.1 to the Company’s Registration Statement on Form S-8 filed on December 22, 2016 (SEC File No. 333-215283)).
3.2 Amended and Restated Bylaws of TETRA Technologies, Inc. (incorporated by reference to Exhibit 4.6 to the Company’s Registration Statement on Form S-8 filed on May 4, 2006 (SEC File No. 333-133790)).
3.3 Certificate of Amendment of Restated Certificate of Incorporation of TETRA Technologies, Inc. (incorporated by reference to Exhibit 3.1 to the Company's Quarterly Report filed on August 9, 2017 (SEC File No. 001-13455)).
4.1 Form of Senior Indenture (including form of senior debt security) (incorporated by reference to Exhibit 4.24 to the Company's Registration Statement on Form S-3 filed on March 23, 2016 (SEC File No. 333-210335)).
4.2 Form of Subordinated Indenture (incorporated by reference to Exhibit 4.25 to the Company's Registration Statement on Form S-3 filed on March 23, 2016 (SEC File No. 333-210335)).
4.3 Warrant Agreement, dated December 14, 2016, between TETRA Technologies, Inc. and Computershare Trust Company, N.A. (incorporated by reference to Exhibit 4.1 to the Company's Form 8-K filed on December 14, 2016 (SEC File No. 001-13455)).
4.4 Form of Warrant Certificate, dated December 14, 2016, between TETRA Technologies, Inc. and Computershare Trust Company, N.A. (incorporated by reference to Exhibit 4.2 to the Company's Form 8-K filed on December 14, 2016 (SEC File No. 001-13455)).
4.5 Credit Agreement, date September 10, 2018, among TETRA Technologies, Inc. and JPMorgan Chase Bank (incorporated by reference to Exhibit 10.1 to the Company's Form 8-K filed on September 13, 2018 (SEC File No. 001-13455)).
4.6 Credit Agreement, date September 10, 2018, among TETRA Technologies, Inc. and Wilmington Trust, National Association (incorporated by reference to Exhibit 10.2 to the Company's Form 8-K filed on September 13, 2018 (SEC File No. 001-13455)).
4.7 Intercreditor Agreement, date September 10, 2018, among TETRA Technologies, Inc., JPMorgan Chase Bank, and Wilmington Trust, National Association (incorporated by reference to Exhibit 10.1 to the Company's Form 8-K filed on September 13, 2018 (SEC File No. 001-13455)).
4.8 Description of the Registrant's Securities Registered Pursuant to Section 12 of the Securities Exchange Act of 1934.
10.1*** TETRA Technologies, Inc. Nonqualified Deferred Compensation Plan (incorporated by reference to Exhibit 10.9 to the Company’s Form 10-Q filed on August 13, 2002 (SEC File No. 001-13455)).
10.2*** TETRA Technologies, Inc. Nonqualified Deferred Compensation Plan and The Executive Excess Plan Adoption Agreement effective on June 30, 2005 (incorporated by reference to Exhibit 10.2 to the Company’s Form 10-Q/A filed on March 16, 2006 (SEC File No. 001-13455)).
10.3*** TETRA Technologies, Inc. 401(k) Retirement Plan, as amended and restated (incorporated by reference to Exhibit 99.1 to the Company’s Registration Statement on Form S-8 filed on February 22, 2008 (SEC File No. 333-149348)).
10.4*** TETRA Technologies, Inc. 2007 Equity Incentive Compensation Plan (incorporated by reference to Exhibit 4.12 to the Company’s Registration Statement on Form S-8 filed on May 4, 2007 (SEC File No. 333-142637)).
10.5*** TETRA Technologies, Inc. Amended and Restated 2007 Equity Incentive Compensation Plan (incorporated by reference to Exhibit 4.12 to the Company’s Registration Statement on Form S-8 filed on May 9, 2008 (SEC File No. 333-150783)).
10.6*** TETRA Technologies, Inc. 2007 Long Term Incentive Compensation Plan (incorporated by reference to Exhibit 4.11 to the Company’s Registration Statement on Form S-8 filed on May 5, 2010 (SEC File No. 333-166537)).
10.7*** TETRA Technologies, Inc. Amended and Restated 2007 Long Term Incentive Compensation Plan, as amended through February 20, 2015 (incorporated by reference to Exhibit 10.3 to the Company's Form 10-Q filed on August 10, 2015 (SEC File No. 001-13455)).
10.8*** TETRA Technologies, Inc. 2011 Long-Term Incentive Compensation Plan (incorporated by reference to Exhibit 4.11 to the Company’s Registration Statement on Form S-8 filed on May 10, 2011 (SEC File No. 333-174090)).
10.9*** TETRA Technologies, Inc. 2011 Amended and Restated Long Term Incentive Compensation Plan (incorporated by reference to Exhibit 4.9 to the Company’s Registration Statement on Form S-8 filed on May 9, 2013 (SEC File No. 333-188494)).
10.10*** TETRA Technologies, Inc. Second Amended and Restated 2011 Long Term Incentive Compensation Plan, as amended through February 20, 2015 (incorporated by reference to Exhibit 10.4 to the Company's Form 10-Q filed on August 10, 2015 (SEC File No. 001-13455)).
10.11*** Third Amended and Restated 2011 Long Term Incentive Compensation Plan (incorporated by reference to Exhibit 10.1 to the Company's Form 8-K filed on May 6, 2016 (SEC File No. 001-13455)).
10.12*** Employee Equity Award Agreement dated August 15, 2012 by and between TETRA Technologies, Inc. and Elijio V. Serrano (incorporated by reference to Exhibit 10.1 to the Company’s Form 8-K filed on August 16, 2012 (SEC File No. 001-13455)).
10.13 Lease Agreement dated December 31, 2012 by and between Tetris Property LP and TETRA Technologies, Inc. (incorporated by reference to Exhibit 10.36 to the Company's Form 10-K filed on March 4, 2013 (SEC File No. 001-13455)).
10.14 Bonding Agreement, dated February 28, 2018, between TETRA Technologies, Inc., Orinoco Natural Resources, LLC, and Epic Offshore Specialty, LLC.
10.15*** Form of Change in Control Agreement (incorporated by reference to Exhibit 10.21 to the Company’s Form 10-K filed on March 16, 2020 (SEC File No. 001-13455)).
10.16 Omnibus Agreement dated June 20, 2011, by and among Compressco Partners, L.P., TETRA Technologies, Inc. and Compressco Partners GP Inc. (incorporated by reference to Exhibit 10.2 to the Company’s Form 8-K filed on June 30, 2011 (SEC File No. 001-13455)).
10.17 First Amendment to Omnibus Agreement, dated June 20, 2014, by and among TETRA Technologies, Inc., Compressco Partners, L.P., and Compressco Partners GP Inc. (incorporated by reference to Exhibit 10.1 to the Company's Form 8-K filed on June 26, 2014 (SEC File No. 001-13455)).
10.18 Indenture, dated as of August 4, 2014, by and among Compressco Partners, L.P., Compressco Finance Inc., the Guarantors party thereto and U.S. Bank National Association, as Trustee (incorporated by reference to Exhibit 4.1 to the Company's Form 8-K filed on August 5, 2014 (SEC File No. 001-13455)).
10.19 Guaranty, dated July 20, 2014, by Compressco Partners, L.P. in favor of Warren Equipment Company (incorporated by reference to Exhibit 10.1 to the Company's Form 8-K filed on July 21, 2014 (SEC File No. 001-13455)).
10.20 Contribution, Conveyance and Assumption Agreement, dated June 20, 2011, by and among Compressco, Inc., Compressco Field Services, Inc., Compressco Canada, Inc., Compressco de Mexico, S. de R.L. de C.V., Compressco Partners GP Inc., Compressco Partners, L.P., Compressco Partners Operating, LLC, Compressco Netherlands B.V., Compressco Holdings, LLC, Compressco Netherlands Cooperatief U.A., Compressco Partners Sub, Inc., TETRA International Incorporated, Production Enhancement Mexico, S. de R.L. de C.V. and TETRA Technologies, Inc. (incorporated by reference to Exhibit 10.1 to the Company’s Form 8-K filed on June 30, 2011 (SEC File No. 001-13455)).
10.21 Contribution and Unit Purchase Agreement, dated as of July 20, 2014, by and among Compressco Partners, L.P., Compressco Partners GP, Inc. and TETRA Technologies, Inc. (incorporated by reference to Exhibit 10.2 to the Company's Form 8-K filed on July 21, 2014 (SEC File No. 001-13455)).
10.22 Purchase Agreement, dated as of July 29, 2014, by and among Compressco Partners, L.P., Compressco Finance Inc., the Guarantors party thereto and Merrill Lynch, Pierce, Fenner & Smith Incorporated as representative of the Initial Purchasers named therein (incorporated by reference to Exhibit 10.1 to the Company's Form 8-K filed on August 5, 2014 (SEC File No. 001-13455)).
10.23 Purchase Agreement Joinder, dated as of August 4, 2014, by and among the Guarantors party thereto and Merrill Lynch, Pierce, Fenner & Smith Incorporated, as Representative of the Initial Purchasers named therein (incorporated by reference to Exhibit 10.2 to the Company's Form 8-K filed on August 5, 2014 (SEC File No. 001-13455)).
10.24*** TETRA Technologies, Inc. Cash Incentive Compensation Plan (incorporated by reference to Exhibit 4.1 to the Company’s Form 10-Q filed on May 10, 2010 (SEC File No. 001-13455)).
10.25*** Amendment No. 2 to the TETRA Technologies, Inc. Cash Incentive Compensation Plan (incorporated by reference to Exhibit 10.1 to the Company's Form 8-K filed on February 26, 2016 (SEC File No. 001-13455)).
10.26*** Stand-Alone Cash-Settled Stock Appreciation Rights Award Agreement, dated August 9, 2017, between TETRA Technologies, Inc. and Stuart M. Brightman (incorporated by reference to Exhibit 10.1 to the Company's Quarterly Report filed on November 9, 2017 (SEC File No. 001-13455)).
10.27*** Stand-Alone Cash-Settled Stock Appreciation Rights Award Agreement, dated February 22, 2018, between TETRA Technologies, Inc. and Stuart M. Brightman (incorporated by reference to Exhibit 10.44 to the Company’s Form 10-K filed on March 4, 2019 (SEC File No. 001-13455)).
10.28*** TETRA Technologies, Inc. 2018 Inducement Restricted Stock Plan (incorporated by reference to Exhibit 4.5 to the Company’s Registration Statement on Form S-8 filed on February 12, 2018 ((SEC File No. 333-222976)).
10.29*** Form of Restricted Stock Award Agreement under the TETRA Technologies, Inc. 2018 Inducement Restricted Stock Plan (incorporated by reference to Exhibit 4.6 to the Company’s Registration Statement on Form S-8 filed on February 12, 2018 (SEC File No. 333-222976)).
10.30*** Transition Agreement dated as of May 8, 2019 between TETRA Technologies, Inc. and Stuart M. Brightman (incorporated by reference to Exhibit 10.1 to the Company’s Form 8-K filed on May 8, 2019 (SEC File No. 001-13455)).
10.31*** Amendment to Transition Agreement dated April 8, 2020 between TETRA Technologies, Inc. and Stuart M. Brightman (incorporated by reference to Exhibit 10.1 to the Company’s Quarterly Report filed on August 7, 2020 (SEC File No. 001-13455)).
10.32*** Transition Agreement dated July 27, 2020 between TETRA Technologies, Inc. and Bass C. Wallace, Jr. (incorporated by reference to Exhibit 10.1 to the Company’s Quarterly Report filed on November 3, 2020 (SEC File No. 001-13455)).
10.33*** TETRA Technologies, Inc. 2018 Inducement Restricted Stock Plan (incorporated by reference to Exhibit 4.5 to the Company’s Registration Statement on Form S-8 filed on February 12, 2018 (SEC File No. 333-222976)).
10.34*** Form of Restricted Stock Award Agreement under the TETRA Technologies, Inc. 2018 Inducement Restricted Stock Plan (incorporated by reference to Exhibit 4.6 to the Company’s Registration Statement on Form S-8 filed on February 12, 2018 (SEC File No. 333-222976)).
10.35*** TETRA Technologies, Inc. 2018 Equity Incentive Plan (incorporated by reference to Exhibit 4.5 to the Company’s registration statement on Form S-8 filed on May 4, 2018 (SEC File No. 333-224679).
10.36*** Form of TETRA Technologies, Inc. 2018 Equity Incentive Plan Restricted Stock Award Agreement (incorporated by reference to Exhibit 4.6 to the Company’s registration statement on Form S-8 filed on May 4, 2018 (SEC File No. 333-224679).
10.37*** Form of TETRA Technologies, Inc. 2018 Equity Incentive Plan Incentive Stock Option Award Agreement (incorporated by reference to Exhibit 4.7 to the Company’s registration statement on Form S-8 filed on May 4, 2018 (SEC File No. 333224679).
10.38*** Form of TETRA Technologies, Inc. 2018 Equity Incentive Plan Nonqualified Stock Option Award Agreement (incorporated by reference to Exhibit 4.8 to the Company’s registration statement on Form S-8 filed on May 4, 2018 (SEC File No. 333-224679).
10.39*** TETRA Technologies, Inc. 2018 Non-Employee Director Equity Incentive Plan (incorporated by reference to Exhibit 4.5 to the Company’s registration statement on Form S-8 filed on May 4, 2018 (SEC File No. 333-224678).
10.40*** Form of TETRA Technologies, Inc. 2018 Non-Employee Director Equity Incentive Plan Restricted Stock Award Agreement (incorporated by reference to Exhibit 4.6 to the Company’s registration statement on Form S-8 filed on May 4, 2018 (SEC File No. 333-224678).
10.41*** Form of Cash Retainer Award Agreement under the TETRA Technologies, Inc. 2018 Equity Incentive Plan (incorporated by reference to Exhibit 10.2 to the Company’s Quarterly Report filed on November 3, 2020 (SEC File No. 001-13455)).
16.1 Letter of Ernst & Young LLP dated as of June 18, 2020 (incorporated by reference to Exhibit 16.1 to the Company’s Form 8-K filed on June 18, 2020 (SEC File No. 001-13455)).
21+ Subsidiaries of the Company.
23.1+ Consent of Grant Thornton LLP
23.2+ Consent of Ernst & Young LLP
31.1+ Certification Pursuant to Rule 13(a)-14(a) or 15(d)-14(a) of the Exchange Act, As Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2+ Certification Pursuant to Rule 13(a)-14(a) or 15(d)-14(a) of the Exchange Act, As Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1** Certification Furnished Pursuant to 18 U.S.C. Section 1350, As Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Chief Executive Officer).
32.2** Certification Furnished Pursuant to 18 U.S.C. Section 1350, As Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Chief Financial Officer).
101.INS++ XBRL Instance Document.
101.SCH++ XBRL Taxonomy Extension Schema Document.
101.CAL++ XBRL Taxonomy Extension Calculation Linkbase Document.
101.LAB++ XBRL Taxonomy Extension Label Linkbase Document.
101.PRE++ XBRL Taxonomy Extension Presentation Linkbase Document.
101.DEF++ XBRL Taxonomy Extension Definition Linkbase Document.
104++ Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101).
+ Filed with this report
** Furnished with this report.
*** Management contract or compensatory plan or arrangement.
++ Attached as Exhibit 101 to this report are the following documents formatted in XBRL (Extensible Business Reporting Language): (i) Consolidated Statements of Operations for the years ended December 31, 2020, 2019 and 2018; (ii) Consolidated Balance Sheets as of December 31, 2020 and December 31, 2019; (iii) Consolidated Statements of Comprehensive Income for the years ended December 31, 2020, 2019 and 2018; (iv) Consolidated Statements of Cash Flows for the years ended December 31, 2020, 2019 and 2018; (v) Consolidated Statements of Stockholders’ Equity for the years ended December 31, 2020, 2019 and 2018; and (vi) Notes to Consolidated Financial Statements for the year ended December 31, 2020.
+++ Certain schedules have been omitted pursuant to Item 601(a)(5) of Regulation S-K. The registrant agrees to furnish supplementally a copy of any such omitted schedule to the SEC upon request.