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 accessed at www.tetratec.com. Our common stock is traded on the New York Stock Exchange 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, production well testing, offshore rig cooling services, and compression services and equipment. Our products and services are delivered through three reporting segments organized into three Divisions - Completion Fluids & Products, Water & Flowback Services, and Compression.
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, Africa, Europe, the Middle East, and Australia.
Our Compression Division is a provider of compression services and equipment for natural gas and oil production, gathering, artificial lift, transmission, processing, and storage. The Compression Division's equipment sales business includes the fabrication and sale of standard and custom-designed, engineered compressor packages fabricated primarily at our facility in Midland, Texas. The Compression Division's aftermarket business provides a wide range of services to support the needs of customers who own compression equipment as well as the sale of compressor package parts and components manufactured by third-party suppliers. The Compression Division provides its services and equipment to a broad base of natural gas and oil exploration and production, midstream, transmission, and storage companies operating throughout many of the onshore producing regions of the United States, as well as in a number of other countries, including Mexico, Canada, and Argentina.
We continue to pursue a long-term growth strategy that includes expanding our core businesses, domestically and internationally, through 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 calcium chloride at five manufacturing plant facilities, the largest of which is our plant near El Dorado, Arkansas, which produces liquid and flake calcium chloride products and sodium chloride. 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 more than 1.5 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 2019 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, Africa, and the Middle East.
Through the Optima Solutions Holdings Limited subsidiary ("OPTIMA"), our Water & Flowback Services Division is a provider of offshore oil and gas rig cooling services and associated products that suppress heat and noise generated by high-rate flaring of hydrocarbons during offshore oil and gas well test operations. From off-the-shelf packages to complex engineered systems designed, fitted, and operated by highly trained onshore and offshore teams. OPTIMA manages a large portfolio of custom-built and off-the-shelf pumping packages and temporary fire safety systems to suit the individual requirements of customers with offshore operations in Asia-Pacific, Australia, Latin America, and the North Sea.
Compression Division
Our Compression Division is a provider of compression services and equipment for natural gas and oil production, gathering, artificial lift, transmission, processing, and storage. The Compression Division fabricates and sells standard and custom-designed, engineered compressor packages and provides aftermarket services and compressor package parts and components manufactured by third-party suppliers. The majority of the Compression Division’s service compression fleet is monitored 24/7 via satellite telemetry from Fleet Reliability Centers (FRC) located at The Woodlands, Texas-based corporate office and the Midland, Texas-based fabricating facility. The Compression Division provides its compression services and equipment to a broad base of natural gas and oil exploration and production, midstream, transmission, and storage companies operating throughout many of the onshore producing regions of the United States, as well as in a number of international locations, including the countries of Mexico, Canada, and Argentina.
The Compression Division is one of the largest providers of natural gas compression services in the United States. The compression and related services business includes a service fleet of approximately 5,200 compressor packages providing approximately 1.2 million in aggregate horsepower, using a full spectrum of low-, medium-, and high-horsepower engines. Low-horsepower compressor packages enhance production for dry gas wells and liquids-loaded gas wells by deliquefying wells, lowering wellhead pressure, and increasing gas velocity. These packages are also used in connection with oil and liquids production and in vapor recovery and casing gas system applications. Low- to medium-horsepower compressor packages are typically selected for wellhead and natural gas gathering systems, artificial lift systems, and other applications primarily in connection with natural gas and oil production. Our high-horsepower compressor package offerings are typically deployed in natural gas production, natural gas gathering, gas lift, centralized compression facilities, and midstream applications.
The horsepower of our compression services fleet on December 31, 2019, is summarized in the following table:
Our Compression Division's equipment sales business includes the fabrication and sale of standard and custom-designed, engineered compressor packages fabricated primarily at its facility in Midland, Texas. Our compressor packages are typically sold to natural gas and oil exploration and production, midstream, transmission, and storage companies for use in various applications including gas gathering, gas lift, carbon dioxide injection, wellhead compression, gas storage, refrigeration plant, gas processing, pressure maintenance, pipeline, vapor recovery, gas transmission, fuel gas booster, and coalbed methane systems. We design, fabricate, and assemble natural gas reciprocating and rotary compressor packages up to 2,500 horsepower for use in our service fleet and up to 8,000 horsepower for sale to our broadened customer base.
The Compression Division's aftermarket business provides a wide range of services and compressor package parts and components manufactured by third-party suppliers to support the needs of customers who own compression equipment. These services include operations, maintenance, overhaul and reconfiguration services, which may be provided under turnkey engineering, procurement and construction contracts. This business employs factory trained sales and support personnel in most of the major oil- and natural gas-producing basins in the United States to perform these services.
Virtually all of our Compression Division's operations are conducted through our partially owned CSI Compressco LP ("CCLP") subsidiary. Through one of our wholly owned subsidiaries, CSI Compressco GP Inc., we manage and control CCLP, and accordingly, we consolidate CCLP results of operation in our consolidated results of operation. As of December 31, 2019, common units held by the public represented approximately a 66% common unit ownership interest in CCLP.
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. Our El Dorado, Arkansas, plant produces liquid and flake calcium chloride and sodium chloride, using underground brine (tail brine) obtained from Lanxess AG ("Lanxess") that contains calcium chloride and sodium chloride. We also 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. During the fourth quarter of 2019, we entered into a long-term hydrochloric acid raw material supply agreement.
To produce calcium bromide, zinc bromide, zinc calcium bromide, and sodium bromide at our West Memphis, Arkansas facility, we use bromine, hydrobromic acid, zinc, 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, under which the Completion Fluids & Products Division purchases its requirements of raw material bromine from Lanxess’ Arkansas bromine production facilities. In addition, we have a long-term agreement with Lanxess under which Lanxess supplies our El Dorado, Arkansas calcium chloride plant with raw material tail brine.
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 approximately 30,000 gross acres of bromine-containing brine reserves in the vicinity of this plant. 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.
The Water & Flowback Services Division purchases water management, production testing and rig cooling equipment and components from third-party manufacturers.
The Compression Division designs and fabricates its compressor packages with components obtained from third party suppliers. These components represent a significant portion of the cost of the compressor packages.
Some of the components used in the assembly of compressor packages, well monitoring, sand separation, water management, production testing, and rig cooling equipment are obtained from a single supplier or a limited group of suppliers. Typical contracts with these suppliers are for a period of twelve months. Should we experience unavailability of the equipment or the components we use to assemble our equipment, we believe there are adequate alternative suppliers and any impact to us would not be severe. Our Compression division occasionally experiences long-lead times for components from suppliers and, therefore, may at times make purchases in anticipation of future orders.
Market Overview and Competition
Our operations are significantly dependent upon the demand for, and production of, natural gas and oil in the various domestic and international locations in which we operate. Demand for products and services of our Completion Fluids & Products Division has remained fairly consistent despite continued volatility in pricing for oil and uncertainty in many of the markets where we operate, which affects the plans of many of our oil and gas operations customers. Recent oil price volatility has particularly affected domestic onshore demand for our Water & Flowback Services Division services, resulting in increased customer contract pricing pressure. Beginning in 2017 and continuing throughout all of 2019, shale production for oil and the associated gas produced from these wells provided improved demand and opportunities for products and services of our Compression Division. Further, over the same period, the shift to gas lift as a preferred lifting method improved demand for the complete range of the product offerings of our Compression Division.
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, offshore rig cooling services, 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. Through our OPTIMA subsidiary, the Division offers offshore oil and gas rig cooling services and associated products that suppress heat and noise generated by high-rate flaring of hydrocarbons during offshore well testing operations. OPTIMA primarily serves offshore markets globally.
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. Expro International, 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.
Compression Division
The Compression Division provides its products and services to a broad base of natural gas and oil exploration and production, midstream, pipeline transmission, and storage companies, operating throughout many of the onshore producing regions of the United States. The Compression Division also has operations in Latin America and other international regions. While most of the Compression Division's services are performed throughout Texas, the San Juan Basin, the Rocky Mountain region and the Midcontinent region of the United States, we also have a presence in other U.S. producing regions. The Compression Division continues to seek opportunities to further expand its operations into other regions in the U.S. and elsewhere in the world.
This Division’s strategy is to compete on the basis of superior services at a competitive price. The Compression Division believes that it is competitive because of the significant increases in value that results from the use of its services, its superior customer service, its highly trained field personnel and the quality of the compressor packages it uses to provide services. The Compression Division’s customers include major integrated oil companies, public and private independent exploration and production companies and midstream companies.
The natural gas compression services and compressor package fabrication and sale businesses are highly competitive. We experience competition from companies that may be able to more quickly adapt to changes within our industry and changes in economic conditions as a whole, more readily take advantage of available opportunities, and adopt more aggressive pricing policies. Primary competition for our low-horsepower compression services business comes from smaller local and regional companies that utilize packages consisting of a screw or reciprocating compressor with a separate engine driver. Competition for our medium- and high-horsepower compression services business comes primarily from large companies that may have greater financial resources than we do. Such competitors include Archrock, Kodiak Gas Services, and USA Compression. Our competition in the standard compressor package fabrication and sale markets includes several large companies and a large number of small, regional fabricators, including some of those with whom we also compete for compression services, including Enerflex, Exterran and others. Our competition in the custom-designed, engineered compression equipment market usually consists of larger companies with the ability to provide integrated projects and product support after the sale, including some of the competitors noted above. The ability to fabricate these large custom-designed, engineered packages at the Compression Division's facilities, near the point of end-use of many customers, is often a competitive advantage.
Many of our compression services competitors compete on the basis of price. We believe our pricing has proven to be competitive because of the significant increases in the value that results from use of our services, our customer service, trained field personnel, and the quality of the compressor packages we use to provide our services.
No single customer provided 10% or more of our total consolidated revenues during the year ended December 31, 2019.
Other Business Matters
Backlog
The Compression Division’s equipment sales business consists of the design, fabrication, assembly, and sale of standard and custom-designed, engineered compressor packages that are fabricated to customer specifications and standard specifications, as applicable. The Division's custom-designed, engineered compressor packages are typically greater in size and complexity than standard fabrication packages, requiring more labor, materials, and overhead resources. This business requires diligent planning of those resources and project and backlog management in order to meet the customers' desired delivery dates and performance criteria, and achieve fabrication efficiencies. As of December 31, 2019, the Compression Division's equipment sales backlog was $35.5 million, all of which is expected to be recognized in 2020. This backlog consists of firm customer orders for which a purchase or work order has been received, satisfactory credit or financing arrangements exist, and target delivery dates have been established based on customer requirements. This backlog is a measure of marketing effectiveness that also allows us to plan future labor and raw material needs and to measure our success in winning bids from our customers.
Other than these Compression Division operations, our products and services generally are either not sold under long-term contracts or do not require long lead times to procure or deliver.
Employees
As of December 31, 2019, we had approximately 2,600 employees, including the employees of CCLP. None of our U.S. employees are presently covered by a collective bargaining agreement. Our foreign employees 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.
Patents, Proprietary Technology and Trademarks
As of December 31, 2019, we owned or licensed thirty-one issued U.S. patents and had eight patent applications pending in the United States. We also had thirty-two owned or licensed patents and fifteen 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 2035. 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
We believe that our service and sales operations and manufacturing plants are in substantial compliance with all applicable U.S. and foreign health, safety, and environmental laws and regulations. We are committed to conducting all of our operations under the highest standards of safety and respect for the environment. However, risks of substantial costs and liabilities 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 in the future. Changes in environmental and health and safety regulations could subject us to more rigorous standards and could affect demand for our customer's products which in turn would impact demand for our products. We cannot predict the extent to which our operations may be affected by future regulatory and enforcement policies.
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 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 fines and penalties and the imposition of other obligations.
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. Specific 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; (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.
We routinely deal with natural gas, oil, other petroleum products, and produced water. Hydrocarbons or hazardous and nonhazardous wastes may have been released during our operations or 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 exempt from regulation under RCRA and its state analogs, it is possible that some of the material we now handle 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 become subject to more stringent requirements in the future or will not be characterized as hazardous wastes in the future. Additionally, these properties 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 company 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 EPA has adopted regulations under the CAA to control emissions of hazardous air pollutants from reciprocal internal combustion engines and more recently the EPA adopted regulations that establish air emission controls for natural gas and natural gas liquids production, processing and transportation activities, including EPA's New Source Performance Standards ("NSPS") as well as emission standards to address hazardous air pollutants. Certain CCLP compressor packages are subject to these new requirements and additional control equipment and maintenance operations are required. These rules however are the subject of a recently proposed rule to modify or remove certain requirements. While we do not believe that compliance with current regulatory requirements will have a material adverse effect on the business, additional regulations could impose new air permitting or pollution control requirements on our equipment that could require us to incur material costs.
The modification or interpretation 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 may also adversely affect oil and natural gas exploration and production, which in turn could have an adverse effect on us.
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 provide services and materials to oil and gas operators for the use of TCW fluids in the Gulf of Mexico. Both Region IV and Region VI of the EPA are currently working with the oil and gas industry to further investigate the toxicity characteristics of TCW fluids. The study is expected to take place over the next few years and could impose additional restrictions under the Clean Water Act, however they are not expected to have a material adverse impact. The Clean Water Act and comparable state laws, and regulations thereunder, also regulate the discharge of pollutants into regulated waters, including industrial wastewater discharges and storm water runoff.
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 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.
Item 1A.
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 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 2017 and early 2018, they fell during late 2018, with 2018 West Texas Intermediate oil prices dropping from a high of $76.90 per barrel in October 2018 to a low of $42.36 per barrel in December 2018. The West Texas Intermediate price averaged $57.05 per barrel during 2019. Over this
same period, U.S. natural gas prices have also been volatile, with the Henry Hub price ranging from a high of $4.93 per million British thermal units ("MMBtu") in November 2018 to a low of $2.03 per MMBtu in August 2019. Beginning in February 2020, there has been a severe drop in the price of oil. As of March 12, 2020, the price of West Texas Intermediate oil was $31.50 per barrel and the Henry Hub price for natural gas was $1.84 per MMBtu. The prolonged volatility and low levels of oil and natural gas prices 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, the reduced prices could have 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 recent announcement by Saudi Arabia of a significant reduction in its export prices as well as a recent announcement by Russia that previously agreed upon production cuts will expire on April 1, 2020, have contributed to the recent significant decline in the price of oil.
The coronavirus (COVID-19) pandemic that began in early 2020 provides an illustrative example of how a pandemic or epidemic can also impact our operations and business by reducing global and national economic activity resulting in a decline in the demand for oil and for our products and services, and affecting the health of our workforce and rendering employees unable to work or travel. The price of oil has fallen significantly since the beginning of 2020, due in part to the factors discussed above and to concerns about the coronavirus (COVID-19) and its impact on the worldwide economy and demand for oil. In addition, if a pandemic or epidemic such as the coronavirus (COVID-19) pandemic were to impact a location where we have a high concentration of business and resources, our local workforce could be affected by such an occurrence or outbreak which could also significantly disrupt our operations and decrease our ability to provide services and products to our customers. The duration of the business disruption and related financial impact from the coronavirus (COVID-19) pandemic cannot be reasonably estimated at this time. If the impact of the coronavirus (COVID-19) pandemic continues for an extended period of time, it could materially adversely affect the demand for our products and services and our ability to operate our business in the manner and on the timelines previously planned. The extent to which the coronavirus (COVID-19) or other health pandemics or epidemics may impact our results will depend on future developments, which are highly uncertain and cannot be predicted.
Current debt and equity market conditions may continue to limit our ability, and the ability of our CCLP subsidiary, 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 and CCLP's businesses and we expect the stock market decline beginning in March 2020 will make it more difficult to obtain such financing in the near future. As of December 31, 2019, the market price for our common stock was $1.96 per share and the market price per common unit of CCLP was $2.71. Due, in part to the recent stock market decline, the closing price of our common stock was $0.37 as of March 12, 2020. 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 and to CCLP current common unitholders. In addition, as of December 31, 2019, CCLP had approximately $649.4 million aggregate principal amount outstanding under its 7.25% Senior Notes and 7.50% Senior Secured Notes. We may have difficulty obtaining refinancing for our existing indebtedness upon maturity. Obtaining equity or debt financing in the current market environment is particularly difficult for CCLP, given its current levels of long-term debt.
During the twelve months ended December 31, 2019, CCLP's total capital expenditures were $64.8 million, primarily consisting of growth capital expenditures to increase its compression services equipment fleet. As of
December 31, 2019, CCLP's total cash balance was $2.4 million. CCLP expects that the combination of this $2.4 million of cash on hand at the beginning of 2020 and operating cash flows expected to be generated during the year will be sufficient to fund its anticipated 2020 capital expenditures without having to access the debt or equity markets. However, CCLP's ability to grow its business through capital expenditure or acquisition activities beyond these sources of financing may be significantly limited or curtailed. 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.
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. The significant decline in oil prices since the beginning of 2020 is 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. Several of our customers have reduced their capital expenditure plans for 2020 in light of the current decreased prices of oil and natural gas. 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.
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 ("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 the two year period ending December 31, 2019, we have recorded a total of $98.8 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 second quarter of 2019, we recorded impairments of $2.3 million in our Compression
Division on certain units of our low-horsepower compression fleet, reflecting our decision to dispose of these units upon management's determination that refurbishing this equipment was not economic given limited current and forecasted demand for such equipment. 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 segment. 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. We rely on Lanxess as a supplier of bromine for our brominated CBF products as well as tail brine for our El Dorado, Arkansas, calcium chloride plant. 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 CCLP's compression packages and our production testing, well monitoring, sand separation, water management, and rig cooling 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 Compression and Water & Flowback Services Divisions 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. In the past, our Compression Division has on occasion experienced fires that have damaged or destroyed certain of its compression fleet, and similar accidents or fires could reoccur in the future.
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.
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, 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.
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:
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our operational performance;
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supply, demand, and prices of oil and natural gas;
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the activity levels of our customers;
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deviations in our earnings from publicly disclosed forward-looking guidance or analysts’ projections;
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recommendations by research analysts that cover us and other companies in our industry;
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risks related to acquisitions and our growth strategy;
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uncertainty about current global economic conditions; and
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other general economic conditions.
During 2019, the closing price for our common stock ranged from a high of $2.68 per share to a low of $1.11 per share. In connection with the recent stock market decline that began in March 2020, the closing market price of our common stock has declined below $1.00 per share with a closing price of $0.37 per share on March 12, 2020. In recent years, the stock market in general has experienced extreme price and volume fluctuations that have affected the market price for many 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 recent coronavirus (COVID-19) outbreak and its potential impact on the world economy. The volatility of our common stock may make it difficult for you to resell shares of our common stock when you want at attractive prices.
We are listed on the New York Stock Exchange (the “NYSE”). We are required to meet the NYSE’s continued listing standards, including a requirement that the average closing price of our common stock not be below $1.00 per share over any consecutive thirty trading-day period. As indicated above, the closing market price
of our common stock was recently below $1.00. The NYSE listing standards also provide that we will not not be in compliance if our market capitalization over any consecutive thirty trading-day period is less than $50 million and, at the same time our stockholders’ equity is less than $50 million. As of December 31, 2019, our stockholders’ equity was $34.4 million and our market capitalization as of March 12, 2020 was $46.5 million. If we are unable to meet these listing standards and are unable to cure any such non-compliance within the applicable cure period provided by the NYSE, the NYSE will delist our common stock. In that event, it is possible that our common stock would be quoted on the over-the-counter bulletin board. This could have negative consequences for us, including reduced liquidity for shareholders, reduced trading levels, limited availability of market quotations or analyst coverage, stricter trading rules for brokers trading our common stock, and reduced access to financing alternatives. We also could be subject to greater state securities regulation if our common stock is no longer listed on a national exchange.
Our long-term debt agreements contain covenants and other provisions that restrict our ability to take certain actions and may limit our ability to grow our business in the future.
As of December 31, 2019, our total long-term debt outstanding (excluding CCLP) of $204.6 million 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. In addition, in June 2018, CCLP entered into a Loan and Security Agreement (the "CCLP Credit Agreement"). As of December 31, 2019, our consolidated balance sheet includes $638.2 million carrying amount of long-term debt of CCLP, which consisted of (i) $344.2 million carrying amount under its 7.50% Senior Secured Notes due 2025 (the "CCLP 7.50% Senior Secured Notes"), (ii) $291.4 million carrying amount of CCLP's 7.25% Senior Notes due 2022 (the "CCLP 7.25% Senior Notes"), and (iii) $2.6 million carrying amount under the CCLP Credit Agreement. Debt service costs related to outstanding long-term debt represents a significant use of our and CCLP's operating cash flows and could increase our and CCLP's vulnerability to general adverse economic and industry conditions.
The ABL Credit Agreement and Term Credit Agreement each contains certain affirmative and negative covenants, including covenants that restrict the ability of TETRA and certain of its subsidiaries (other than CCLP) 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.
The CCLP Credit Agreement contains certain affirmative and negative covenants, including covenants that restrict CCLP's ability to take certain actions including, among other things and subject to certain significant exceptions, (i) incurring debt, (ii) granting liens, (iii) making investments, (iv) entering into or amending transactions with affiliates, (v) paying dividends, and (vi) selling assets. The CCLP Credit Agreement also contains a provision that requires compliance with a fixed charge coverage ratio (as defined in the CCLP Credit Agreement) of not less than 1.0 to 1.0 in the event that certain conditions associated with outstanding borrowings and cash availability occur.
In addition, the indentures governing the CCLP 7.50% Senior Secured Notes and the CCLP 7.25% Senior Notes (the "CCLP Indentures") contain customary covenants restricting CCLP's ability and the ability of its restricted subsidiaries to (i) pay distributions on, purchase, or redeem its common units, make certain investments and other restricted payments, or purchase or redeem any subordinated debt; (ii) incur or guarantee additional indebtedness or issue certain kinds of preferred equity securities; (iii) create or incur certain liens securing indebtedness; (iv) sell assets, including dispositions of the CCLP 7.50% Senior Secured Notes Collateral; (v) consolidate, merge, or transfer all or substantially all of its assets; (vi) enter into, or amend or modify transactions with affiliates; and (vii) enter into agreements that restrict distributions or other payments from CCLP's restricted subsidiaries to CCLP. These covenants are subject to a number of important limitations and exceptions, including certain provisions permitting CCLP, subject to the satisfaction of certain conditions, to transfer assets to certain of its unrestricted subsidiaries.
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.
The debt levels of our CCLP subsidiary have resulted in a significant use of its operating cash flows being used to fund debt service requirements, resulting in less cash available for distributions and to fund capital expenditures.
In March 2018, CCLP issued an aggregate $350.0 million of its 7.50% Senior Secured Notes, the proceeds from which were partially used to repay the remaining outstanding balance of $258.0 million under CCLP's previous bank credit facility, which was then terminated. While the termination of the CCLP previous bank credit agreement removed certain financial covenant requirements, the issuance of the 7.50% Senior Secured Notes increased CCLP's aggregate amount of long-term debt outstanding as well as increased the aggregate interest rate of its debt outstanding. This increase in CCLP indebtedness has increased its total 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, some of which are beyond its control. If CCLP operating results are not sufficient to service its current or future indebtedness, CCLP may be forced to consider taking actions such as reducing or delaying is business activities, acquisitions, investments and/or capital expenditures, delaying the increase of distributions, selling assets, restructuring or refinancing its indebtedness, or seeking additional equity capital or bankruptcy protection. CCLP may not be able to take any of these courses of action. Given its need to fund capital expenditures and debt service requirements, there can be no assurance that CCLP will increase its distributions to its common unitholders, including us.
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 US 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 US 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 US 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 US 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 US 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 US 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 US 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. In addition, the 2016 NTL is being held in abeyance by the US Department of the Interior, which creates additional and significant uncertainty 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 US Department of the Interior and/or to third parties through our private guarantees.
The US 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 US Department of the Interior relating to financial assurance for decommissioning liabilities. The US Department of the Interior's revisions to its 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, recent and anticipated changes to the bonding and financial assurance program for the Gulf of Mexico are likely to 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 will 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 US 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 and CCLP are exposed to interest rate risks with regard to our respective credit facility debt and future refinancing thereof.
As of December 31, 2019, we had a total of $1.0 million outstanding under our ABL Credit Agreement and $220.5 million outstanding under our Term Credit Agreement. CCLP has a total of $3.5 million outstanding under the CCLP Credit Agreement. 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 and CCLP have amounts outstanding under these facilities, our respective 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. The CCLP Credit Agreement is scheduled to mature on June 29, 2023. CCLP's 7.25% Senior Notes, which mature August 15, 2022, and CCLP's 7.50% Senior Secured Notes, which mature April 1, 2025, bear interest at fixed interest rates. 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.
The EPA is studying the environmental impact of hydraulic fracturing, a process used by the U.S. oil and gas industry in the development of certain oil and gas reservoirs. Specifically, 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. The EPA rules also require so-called “green” completions at hydraulically fractured natural gas wells. Under the current administration, in 2019 the EPA proposed rules to loosen these requirements, but those rules have not been finalized. 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.
The EPA has adopted regulations under the CAA to control emissions of hazardous air pollutants from reciprocal internal combustion engines and more recently the EPA adopted regulations that establish air emission controls for natural gas and natural gas liquids production, processing and transportation activities, including NSPS as well as emission standards to address hazardous air pollutants. Certain CCLP compressor packages are subject to these new requirements and additional control equipment and maintenance operations are required. However, these rules are the subject of a recently proposed rule to modify or remove certain requirements. While we do not believe that compliance with current regulatory requirements will have a material adverse effect on the business, additional regulations could impose new air permitting or pollution control requirements on our equipment that could require us to incur material costs.
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, including the United States, ratified or otherwise indicated their intent to be bound by the Paris Agreement. However, in June 2017, President Trump announced that the United States intends to withdraw from the Paris Agreement and to seek negotiations either to reenter the Paris Agreement on different terms or a separate agreement. In August 2017, the U.S. Department of State officially informed the United Nations of the United States’ intent to withdraw from the Paris Agreement. The Paris Agreement provides for a four-year exit process beginning when it took effect in November 2016, which would result in an effective exit date of November 2020. The United States’ adherence to the exit process and/or the terms on which the United States may re-enter the Paris Agreement or a separately negotiated agreement are unclear at this time. In November 2019 the U.S. submitted formal notice required under the Paris Agreement. The withdrawal is scheduled to take effect November 4, 2020. To the extent that the other countries implement the Paris Agreement or the United States imposes other climate change regulations on the oil and natural gas industry, it could have an adverse effect on our business.
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:
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restrictions on repatriating cash back to the United States;
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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;
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government controls and government actions, such as expropriation of assets and changes in legal and regulatory environments;
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import and export license requirements;
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political, social, or economic instability;
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trade restrictions;
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changes in tariffs and taxes; and
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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.
Our operations in Argentina expose us to the changing economic, legal, and political environments there, including the changing regulations over repatriation of cash generated from our operations in Argentina.
The current economic, legal, and political environment in Argentina and devaluation of the Argentinian peso have created increased economic instability for foreign investment in Argentina. Fiscal and monetary expansion in Argentina led to numerous devaluations of the Argentinian peso since 2013. Additional currency adjustment may be necessary to help boost the current Argentina economy, but may be accompanied by fiscal and monetary tightening, including additional restrictions on the purchase of U.S. dollars in Argentina. On June 30, 2018, we determined the economy in Argentina to be highly inflationary. As a result of this determination and in accordance with U.S. GAAP, on July 1, 2018, the functional currency of our operations in Argentina was changed from the Argentine peso to the U.S. dollar. The remeasurement did not have a material impact on our consolidated financial position or results of operations.
As a result of our operations in Argentina, consolidated revenues and operating cash flow generated in Argentina have increased over the past three years. The process of repatriating this cash to the U.S. is subject to complex regulations. There can be no assurances that our Argentinian operations will not expose us to a loss of liquidity, foreign exchange losses, and other potential financial impacts.
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.
Hydraulic fracturing is a practice that is used to stimulate production of hydrocarbons from dense subsurface rock formations. The process involves the injection of water, sand or other proppants and chemical additives under pressure into targeted geological formations to fracture the surrounding rock and stimulate production.
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 during for the oil and natural gas hydraulic fracturing industry (however, rules have been proposed in 2019 to modify or rescind 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 before discharging 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 March 2015, 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 has issued a final rule rescinding the 2015 action; however, this new rule remains subject to legal challenge.
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.
Regulatory initiatives relating to the protection of endangered or threatened species in the United States, or in other countries where we operate, could have an adverse impact on our and our customers’ ability to expand operations.
In the U.S., the Endangered Species Act (the “ESA”) restricts activities that may affect endangered or threatened species or their habitats. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act (the “MBTA”). To the extent species that are listed under the ESA or similar state laws, or are protected under the MBTA, live in the areas where we or our customers operate, both our and our customers’ abilities to conduct or expand operations and construct facilities could be limited or be forced to incur material additional costs.
The designation of previously unidentified endangered or threatened species could indirectly cause us to incur additional costs, cause our or our customers’ operations to become subject to operating restrictions or bans, and limit future oil and gas development activity in affected areas. The designation of previously unprotected species as threatened or endangered in areas where we or our customers might conduct operations could result in limitations or prohibitions on our operations and could adversely impact our business.
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 continue to experience 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.
Item 1B.
Item 1B. Unresolved Staff Comments.
None.
Item 2.
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, 2019. We believe our facilities are adequate for our present needs.
Facilities
Completion Fluids & Products Division
Our Completion Fluids & Products Division facilities include seven 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 1.5 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 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 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 approximately 30,000 gross acres of bromine-containing brine reserves in Magnolia, Arkansas, 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 Canada, Mexico, and certain countries in Europe, the Middle East and South America.
Compression Division
The Compression Division’s facilities include owned offices and fabrication facilities in Midland, Texas, consisting of an aggregate of approximately 177,000 square feet of structures that are located on 38.5 acres of land. In addition, the Division has several owned and leased service, fabrication, and sales facilities in Argentina, Canada, Mexico, and the U.S. All obligations under the CCLP 7.50% Senior Secured Notes are secured by a first lien security interest in substantially all of CCLP’s assets, including CCLP's fabrication facilities in Midland, Texas and Oklahoma City, Oklahoma, but excluding other real property assets.
For a profile of our compression fleet, see "Item 1. Business "Products and Services - Compression Division."
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.
Item 3.
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.
Item 4.
Item 4. Mine Safety Disclosures.
None.
PART II
Item 5.
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 12, 2020, there were approximately 305 holders of record of the common stock.
Purchases of Equity Securities by the Issuer and Affiliated Purchasers
In January 2004, our Board of Directors authorized the repurchase of up to $20 million of our common stock. Purchases may be made from time to time in open market transactions at prevailing market prices. The repurchase program may continue until the authorized limit is reached, at which time the Board of Directors may review the option of increasing the authorized limit. During 2004 through 2005, we repurchased 340,950 shares of our common stock pursuant to the repurchase program at a cost of approximately $5.7 million. The approximate
dollar value of the maximum number of shares that may be Purchased Under the Publicly Announced Plans or Programs is $14,327,000. There were no repurchases made during 2006 through 2019 pursuant to the repurchase program. In addition, no repurchases of our common stock were made outside the repurchase program during the fourth quarter of 2019.
Item 6.
Item 6. Selected Financial Data.
The following tables set forth our selected consolidated financial data for the years ended December 31, 2019, 2018, 2017, 2016, and 2015. The selected consolidated financial data does not purport to be complete and should be read in conjunction with, and is qualified by, the more detailed information, including the Consolidated Financial Statements and related Notes and “Item 7.
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operation.
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.
This section of this Form 10-K generally discusses 2019 and 2018 items and year-to-year comparisons between 2019 and 2018. Discussions of 2017 items and year-to-year comparisons between 2018 and 2017 that are not included in this Form 10-K can be found in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Part II, Item 7 of our Annual Report on Form 10-K for the fiscal year ended December 31, 2018.
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, and compression services and equipment. We operate through three reporting segments organized into three Divisions - Completion Fluids & Products, Water & Flowback Services, and Compression.
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. Demand for products and services of our Completion Fluids & Products Division has remained fairly consistent despite continued volatility in pricing for oil and natural gas and uncertainty in many of the markets where we operate; however, we expect the significant decline in oil prices since the beginning of 2020 may adversely effect the demand for our products and services for the near future. During 2019, we experienced increased CBF product sales revenues in the U.S. Gulf of Mexico, including product sales associated with a TETRA CS Neptune completion fluid sale and increased international CBF product sales and domestic manufactured products sales. Future profitability levels of our Completion Fluids & Products Division will continue to be affected by the timing of future TETRA CS Neptune projects and other CBF sales. Gross profit during 2019 was significantly impacted by an impairment of $91.8 million related to our El Dorado, Arkansas calcium chloride production plant facility assets.
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, Africa, Europe, the Middle East, and Australia. Recent oil and natural gas price volatility has particularly affected domestic onshore demand for our Water & Flowback Services Division services, resulting in increased customer contract pricing pressure. During the fourth quarter of 2019, due to further decline in the energy industry outlook resulting in decreased expected
future cash flows for our Water Management reporting unit, we recorded a full goodwill impairment of $25.8 million. As a result, there is no remaining goodwill balance as of December 31, 2019.
Our Compression Division is a provider of compression services and equipment for natural gas and oil production, gathering, artificial lift, transmission, processing, and storage. Our compression and related services business includes a fleet of more than 5,200 compressor packages providing approximately 1.2 million capacity in aggregate horsepower, utilizing a full spectrum of low-, medium-, and high-horsepower engines. Customers of our Compression Division operate throughout many of the onshore producing regions of the United States, as well as in a number of international locations, including the countries of Mexico, Canada and Argentina. Our Compression Division operates primarily through our CSI Compressco LP subsidiary ("CCLP"), of which we own 34% of the common equity and control through our ownership of its general partner.
The operations of the Compression Division are significantly dependent upon the demand for, and production of, oil and the associated gas from unconventional oil production in the domestic and international markets in which we operate. Beginning in 2017 and continuing throughout all of 2019, production of oil and the associated gas produced from these wells in shale basins including the Permian Basin in Texas and New Mexico provided improved compression demand opportunities for our products and services. This growth in demand resulted in increases in our compression services revenues, through increased activity and customer contract pricing. This has resulted in increased utilization of our compression equipment fleet, with over 1.06 million horsepower of our compression equipment in service as of December 31, 2019. During 2019, the overall compression fleet utilization of the Compression Division reached 90.1%, the highest overall compression fleet utilization since CCLP's acquisition of Compressor Systems, Inc. in 2014. As of December 31, 2019 our Compression Division is close to maximum utilization for our high-horsepower class of compression equipment at 97.9%. During 2019, the shift to centralized gas lift as a preferred lifting method improved demand, particularly for our high-horsepower service offerings. While we have experienced increased demand and utilization for certain of our compressor packages, the recent decline in oil prices as well as the volatility and declines in the stock market may impact demand for compression services and equipment.
Future demand for our products and services depends primarily on activity in the oil and natural gas exploration and production industry, particularly including the level of expenditures for the exploration and production of oil and natural gas, and for additional natural gas compression infrastructure. The future growth of certain of our businesses is dependent on improved future pricing levels of oil and natural gas. When oil and natural gas prices increase, we believe there are growth opportunities for our products and services, supported primarily by:
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increases in technologically-driven deepwater oil and gas well completions in the Gulf of Mexico;
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applications for many of our products and services in the continuing exploitation and development of shale reservoirs; and
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increases in selected international oil and gas exploration and development activities.
We are monitoring the 2020 spending plans of our customers, particularly after the recent declines in the price of oil and natural gas and the stock market, and are aggressively managing our working capital and capital expenditure needs in order to maximize our liquidity in the current oil and gas industry environment. Capital expenditure levels continue to be monitored carefully for each of our businesses to insure that capital investments are only made for the most attractive growth opportunities. As obtaining additional financing is challenging in the current debt and equity markets, growth capital expenditures are expected to be primarily funded by available cash and expected cash provided by operating activities. Our Compression Division may also seek to expand its compression fleet, in response to increased demand, through finance or operating leases with third parties.
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:
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evaluate the financial performance of our assets without regard to financing methods, capital structure, or historical cost basis; and
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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:
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.
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 2019, primarily as the result of the impairment of our El Dorado, Arkansas calcium chloride production plant due to a reduction in the cost of raw materials for certain of our other chemical production plants, we recorded consolidated impairments and other charges of $95.2 million. During periods of economic uncertainty, the likelihood of additional material impairments of long-lived assets is higher due to the possibility of decreased demand for our products and services.
Impairment of Goodwill
The impairment of goodwill is also assessed whenever impairment indicators are present, but not less than once annually at a reporting unit level. During the third quarter of 2019, we determined that the current decreased 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.
We perform the annual test of goodwill impairment as of the last day of the fourth quarter of each year. The first step of the impairment test is to compare the estimated fair value with the recorded net book value (including goodwill) of our reporting unit. Our estimates of fair value are based on a combination of an income and market approach. These estimates are imprecise and are subject to our estimates of the future cash flows of the reporting unit. These estimates and judgments are affected by numerous factors, including the general economic environment at the time of our assessment. If we overestimate the fair value, the balance of our goodwill asset may be overstated. Alternatively, if our estimated reporting unit fair value is understated, impairments might be recognized unnecessarily or in excess of the appropriate amounts. Specific uncertainties affecting the estimated fair value of our Water Management reporting unit includes the impact of competition, prices of oil and natural gas, future overall activity levels in the regions in which it operates, the activity levels of our significant customers, and other factors affecting the rate of future growth of this reporting unit. If our analysis results in the fair value of our reporting unit being less than the carrying value, impairment is calculated based on the difference between the fair value and carrying value in accordance with our early adoption of ASU 2017-04 "Intangibles-Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment."
During the fourth quarter of 2019, due to further decline 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 $25.8 million. As a result, there was no goodwill balance as of December 31, 2019.
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.
2019 Compared to 2018
Consolidated Comparisons
Consolidated revenues for 2019 increased compared to the prior year due to increased revenues in our Compression and Completion Fluids & Products Divisions. Compression Division revenues increased by $38.0 million driven by service revenues from compression and aftermarket services operations and new compressor equipment sales activity. Our Completion Fluids & Products Division revenues increased by $21.8 million due to increased CBF product sales revenues in the U.S. Gulf of Mexico, including product sales associated with a TETRA CS Neptune completion fluid sale, and increased international CBF product sales and domestic manufactured products sales. These increases were partly offset by a decrease in Water & Flowback Services Division revenues primarily due to decreased water management services activity. See Divisional Comparisons section below for additional discussion.
Consolidated gross profit decreased during 2019 compared to the prior year due to our Completion Fluids & Products and Water & Flowback Services Divisions. The Completion Fluids & Products Division gross profit decrease resulted from an impairment of $91.8 million related to our El Dorado, Arkansas calcium chloride production plant facility assets. The impairment charge is primarily the result of a reduction in the cost of raw materials for certain of our other chemical production plants, following the execution of a long-term raw material supply agreement during the fourth quarter of 2019. The Water & Flowback Services Division decrease in gross profit is attributable to the costs to demobilize from one customer to mobilize for another. In addition, Water & Flowback Services Division gross profit reflected the decrease in high-margin projects performed during the prior year. These decreases were partly offset by increases in Compression Division gross profit due to added horsepower and overall increased utilization of our compression fleet. Despite the improvement in activity levels of
certain of our businesses, offshore activity levels remain flat and the impact of pricing pressures continues to challenge profitability in certain onshore markets. Operating expense levels reflect the increase in consolidated revenues, although we remain aggressive in managing operating costs and minimizing increased headcount.
Consolidated general and administrative expenses increased during 2019 compared to the prior year, primarily due to $6.2 million of increased salary related expenses and $2.3 million of increased bad debt and marketing expenses. These increases were offset by $0.7 million of decreased professional services fees and $0.4 million of decreased insurance and other general expenses. General and administrative expense as a percentage of revenues was relatively flat compared to the prior year. In December 2019, we announced the implementation of a series of cost reduction actions in response to the slowdown in North America onshore drilling and completions activity. In addition to reducing field staff and field operating costs to align with lower activity, management is restructuring its support functions to reduce general and administrative expenses at the corporate level and at its North America onshore operations.
Consolidated interest expense, net, increased in 2019 compared to the prior year primarily due to corporate interest expense from the Term Credit Agreement and ABL Credit Agreement, which were entered into in September 2018 and replaced the 11% Senior Note and the previous bank credit agreement. Interest expense during 2019 and 2018 includes $4.0 million and $4.3 million, respectively, of finance cost amortization.
Gain on sale of assets increased in 2019 compared to the prior year primarily due to increased asset disposals during the year.
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.
The CCLP Preferred Units were eligible to be settled using a variable number of CCLP common units, and therefore the fair value of the CCLP Preferred Units was classified as a long-term liability on our consolidated balance sheets in accordance with ASC 480. Because the CCLP Preferred Units were convertible into CCLP common units at the option of the holder, the fair value of the CCLP Preferred Units generally increased or decreased with the trading price of the CCLP common units, and this increase (decrease) in CCLP Preferred Unit fair value was charged (credited) to earnings, as appropriate. The last remaining outstanding CCLP Preferred Units were redeemed for cash on August 8, 2019.
Consolidated other (income) expense, net, was $0.2 million of income during 2019 compared to $7.9 million of expense during the prior year. The decrease in expense is primarily due to $3.4 million of expense in the prior year compared to $1.0 million of income in the current year associated with the remeasurement of contingent purchase price consideration, $3.5 million of decreased expense related to unamortized deferred financing costs charged to earnings during the prior year as a result of the termination of the CCLP Bank Credit Facility, $1.0 million of decreased loan fees associated with new TETRA credit agreements that were issued in the prior year and foreign currency gains of $0.4 million. These decreases in expense were offset by an increased expense of $1.5 million associated with redemption premiums incurred in connection with the redemption of CCLP Preferred Units for cash in the current year.
Our consolidated provision for income taxes during 2019 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, 2019 of negative 4.3% 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 net operating loss carryforwards and tax credits that are available to offset future income tax liabilities in the U.S. as well as in certain foreign jurisdictions.
Divisional Comparisons
Completion Fluids & Products Division
The increase in Completion Fluids & Products Division revenues during 2019 compared to the prior year was due to $16.2 million of increased product sales revenue, which was partly due to increased CBF product sales revenues in the U.S. Gulf of Mexico, including product sales associated with a TETRA CS Neptune completion fluid sale. Increased revenues during 2019 were also the result of improved markets and pricing environments for CBF product sales in international locations, including South America, the Middle East, and Europe and domestic manufactured products sales. Service revenues increased $5.6 million primarily due to increased TETRA CS Neptune service revenue and increased international completion services activity.
Completion Fluids & Products Division gross profit during 2019 decreased compared to the prior year despite the profitability associated with increased revenues discussed above due to $91.8 million of long-lived asset impairments related to our El Dorado, Arkansas calcium chloride production plant facility assets during 2019. 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 and other CBF projects.
The Completion Fluids & Products Division reported a pretax loss during 2019 compared to pretax earnings in the prior year primarily due to the decrease in gross profit discussed above. Completion Fluids & Products Division administrative cost levels increased compared to the prior year, primarily due to $0.9 million of increased salary and employee related expenses, $0.5 million of increased insurance and other general expenses, and $0.2 million of increased legal and professional fees. These increases were partially offset by $0.4 million of decreased bad debt expense.
Water & Flowback Services Division
Water & Flowback Services Division revenues decreased during 2019 compared to the prior year primarily due to decreased water management services activity. Water management and flowback service revenues decreased $20.0 million during 2019 compared to the prior year despite having the impact of a full twelve months of revenues from SwiftWater, which was acquired on February 28, 2018, and the impact of the December 2018 acquisition of JRGO Energy Services LLC ("JRGO"). The volatility in oil and gas commodity prices driving reductions in customer capital spending decisions have resulted in decreased pricing and activity when compared to the prior year. Product sales revenue decreased by $1.0 million, due to decreased international equipment sales activity.
The Water & Flowback Services Division reflected decreased gross profit during 2019 compared to the prior year due to decreased revenues and a shift in revenue mix away from smaller, capital constrained customers towards larger operators with stronger balance sheets. The costs to demobilize from one customer to mobilize for another within the same period also had a meaningful impact on profitability. In addition, we reflected decreased revenues and gross profit as a result of certain high-margin projects performed during the prior year. We also experienced high maintenance costs on our flowback service equipment following significant activity experienced in the fourth quarter of 2018, which was our highest flowback service revenue quarter in over three years.
The Water & Flowback Services Division reported pretax loss compared to pretax income during the prior year, primarily due to the decrease in gross profit described above and due to the impairment of goodwill during the current year. General and administrative expenses increased primarily due to increased bad debt expense of $1.8 million and increased general expenses of $0.3 million. These increases were offset by decreased wage and benefit expenses of $0.4 million, and decreased professional fees of $0.3 million. The Water & Flowback Services Division reported other income, net, during the current year compared to other expense during the prior year primarily due to $3.4 million of expense in the prior year compared to $1.0 million of income in the current year associated with the remeasurement of contingent purchase price consideration and increased gains on the disposal of assets of $0.9 million, slightly offset by increased foreign currency losses of $0.3 million.
Compression Division
Compression Division revenues increased during 2019 compared to the prior year due to a $26.7 million increase in service revenues from compression and aftermarket services operations and a $11.4 million increase in product sales revenues. The increase in service revenues was primarily due to growth in demand for compression services that positively impacted our compression fleet utilization rates. The overall compression fleet horsepower utilization rate as of December 31, 2019 increased to 90.0% compared to 86.6% as of December 31, 2018. In addition, increased demand has led to improved customer contract pricing for compression services. Demand for new compressor equipment remains strong, although the current equipment sales backlog has decreased compared to the prior year period, due to significant sales orders recorded in the prior year period which were completed during the current year. Changes in our new equipment sales backlog are a function of additional customer orders less completed orders that result in equipment sales revenues.
Compression Division gross profit increased during 2019 compared to the prior year due to the increased revenues discussed above resulting from added horsepower and overall increased utilization of our compression fleet. Gross profit was also positively impacted during the current year due to improved customer contract pricing, higher margins on new compressor equipment, labor efficiencies, and reduced maintenance costs. The increase in gross profit was despite a $3.3 million charge for the impairment and other charges on certain low-horsepower compressor equipment and associated inventory and damage caused by fire to a certain compressor package during the current year period.
The Compression Division recorded a decreased pretax loss during 2019 compared to the prior year due to increased gross profit as discussed above. General and administrative expense levels increased compared to the prior year, due to increased bad debt expense of $1.6 million, increased professional fees of $1.2 million, and increased salary and employee-related expenses, including equity compensation, of $1.0 million. In addition, other (income) expense, net, was $0.6 million income in 2019 compared to $2.1 million of expense in 2018 primarily due to $3.5 million of unamortized deferred financing costs charged to other expense in the prior year as a result of the termination of the CCLP Prior Credit Facility and increased foreign currency gains during the current year of $0.5 million, offset by increased expense of $1.5 million of redemption premium incurred during the current year in connection with the redemption of CCLP Series A Preferred Units for cash. The last remaining outstanding CCLP Series A Preferred Units were redeemed for cash on August 8, 2019.
Corporate Overhead
Corporate Overhead pretax loss increased during 2019 compared to the prior year. The fair value of the outstanding Warrants liability resulted in a $1.6 million credit to earnings in the current year compared to an $11.1 million credit to earnings during the prior year. Interest expense increased due to increased borrowings. Corporate general and administrative expense increased primarily due to $4.6 million of salary and employee-related expenses, which included $1.8 million of executive transition costs. This increase was offset by $1.9 million of decreased professional fees, including $0.9 million of decreased transaction costs, $1.0 million of decreased general expenses, and $0.7 million of decreased consulting expense. In addition, other expense decreased $1.8 million during 2019 compared to prior year primarily due to debt issuance fees related to the ABL Credit Agreement and the Term Credit Agreement entered into during the prior year and increased foreign currency gains.
Liquidity and Capital Resources
We believe that our and CCLP's capital structures allow us to meet our respective financial obligations and fund future growth as needed, despite current uncertain operating conditions and financial markets. Because of the level of consolidated debt, we believe it is important to consider our capital structure and that of CCLP separately, as there are no cross-default provisions, cross-collateralization provisions, or cross-guarantees between CCLP's debt and TETRA's debt. Our consolidated debt outstanding has a carrying value of approximately $842.9 million as of December 31, 2019. However, approximately $638.2 million of this consolidated debt balance is owed by CCLP and is serviced from the cash balances and cash flows of CCLP, and $346.8 million is secured by certain of CCLP's assets. Through our common unit ownership interest in CCLP, which was approximately 34% as of December 31, 2019, and ownership of an approximate 1% general partner interest, we receive our share of the distributable cash flows of CCLP through its quarterly cash distributions. Approximately $2.4 million of the $17.7 million of the cash balance reflected on our consolidated balance sheet is owned by CCLP and is not accessible by us. The following table provides condensed consolidating balance sheet information reflecting TETRA's net assets and CCLP's net assets that service and secure TETRA's and CCLP's respective capital structures.
As of December 31, 2019, we and CCLP are in compliance with all covenants of our respective debt agreements.
As of December 31, 2019, subject to compliance with the covenants, borrowing base requirements, and other provisions of the agreement that may limit borrowings, we had availability of approximately $63.3 million under the ABL Credit Agreement. As of December 31, 2019, and subject to compliance with the covenants, borrowing base requirements, and other provisions of the agreement that may limit borrowings under the CCLP Credit Agreement, CCLP had availability of $17.2 million. See CCLP Financing Activities below for further discussion.
Our consolidated sources and uses of cash during the year ended December 31, 2019 and 2018 are as follows:
Operating Activities
Consolidated cash flows provided by operating activities totaled $90.2 million during 2019 compared to $46.6 million during the prior year, an increase of $43.6 million. Operating cash flows increased due to improved operating profitability and due to working capital management, particularly related to the management of inventory levels, collections of accounts receivable, and the timing of payments of accounts payable. 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
Total cash capital expenditures during 2019 were $108.3 million, which is net of $6.5 million cost of equipment sold. Our Completion Fluids & Products Division spent $7.1 million on capital expenditures during 2019, the majority of which related to plant and facility additions. Our Water & Flowback Services Division spent $24.3 million on capital expenditures, primarily to add to its water management equipment fleet. Our Compression Division spent $82.3 million, primarily for growth capital expenditure projects to increase its compression fleet. Proceeds of $12.9 million from the sale of property, plant and equipment are primarily the result of a sale-leaseback transaction during the fourth quarter of 2019, where we purchased ten compression units and immediately leased them back to CCLP at a monthly rate. These compression units are now included in operating lease right-of-use assets on our consolidated balance sheets.
Generally, a significant majority of our planned capital expenditures has been related to identified opportunities to grow and expand our existing businesses. However, certain of these planned expenditures have 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. Excluding our Compression Division, we expect to spend approximately $20 to $30 million during 2020, primarily to further expand the Water & Flowback Services Division equipment fleet.
Our Compression Division expects to spend approximately $47.0 million to $56.0 million on capital expenditures during 2020, primarily to expand and enhance its compression fleet in response to increased demand for compression services. The foregoing estimates were based on assumptions prior to the March 2020 decline in oil prices and the stock market and we will continue to monitor such estimates going forward. Our Compression Division, through the separate capital structure of CCLP, expects to fund 2020 growth capital expenditures for new compression services equipment primarily through available cash and operating cash flows.
If the forecasted demand for our products and services increases or decreases, the amount of planned expenditures on growth and expansion may be adjusted.
Financing Activities
During 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 and CCLP 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. CCLP may also seek to expand its compression fleet through finance or operating leases with third parties. We and CCLP are aggressively managing our working capital and capital expenditure needs in order to maximize our liquidity in the current environment. We and CCLP are in compliance with all covenants of our respective credit and debt agreements as of December 31, 2019.
TETRA Long-Term Debt
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. As of December 31, 2019, subject to compliance with the covenants, borrowing base, and other provisions of the agreement that may limit borrowings, TETRA had an availability of $63.3 million under this agreement. As of March 12, 2020, we have $21.0 million outstanding under our ABL Credit Agreement and $6.9 million letters of credit.
Borrowings under the ABL Credit Agreement bear interest at a rate per annum equal to, at the option of TETRA, either (i) LIBOR plus a margin based upon a fixed charge coverage ratio or (ii) a base rate plus a margin based on a fixed charge coverage ratio. The base rate is determined by reference to the highest of (a) the prime rate of interest as announced from time to time by JPMorgan Chase Bank, N.A. (b) the Federal Funds Effective Rate (as defined in the ABL Credit Agreement) plus 0.5% per annum or (c) LIBOR (adjusted to reflect any required bank reserves) for a one-month period on such day plus 1.0% per annum. Borrowings outstanding have an applicable margin ranging from 1.75% to 2.25% per annum for LIBOR-based loans and 0.75% to 1.25% per annum for base-rate loans, based upon the applicable fixed charge coverage ratio. In addition to paying interest on the
outstanding principal under the ABL Credit Agreement, TETRA is required to pay certain fees. The maturity date of the ABL Credit Agreement is September 10, 2023.
The ABL Credit Agreement contains 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, incurring debt, granting liens, engaging in mergers and other fundamental changes, making investments, entering into or amending transactions with affiliates, paying dividends and making other restricted payments, prepaying other indebtedness, and selling assets. The ABL Credit Agreement also contains a provision that requires 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. As of December 31, 2019, such conditions have not occurred. All obligations under the ABL Credit Agreement and the guarantees of those obligations are secured, subject to certain exceptions, by a security interest on substantially all of the personal property of TETRA and certain subsidiaries of TETRA, the equity interests in certain domestic subsidiaries, including CCLP, and a maximum of 65% of the equity interests in certain foreign subsidiaries.
The ABL Credit Agreement includes customary events of default, including non-payment of principal, interest or fees, violation of covenants, inaccuracy of representations or warranties, cross-default to other material indebtedness, bankruptcy and insolvency events, invalidity or impairment of security interests or invalidity of loan documents, certain ERISA events, unsatisfied or unstayed judgments, and any change of control.
The ABL Credit Agreement may be used for working capital needs, capital expenditures and other general corporate purposes.
Term Credit Agreement. The Term Credit Agreement provides an initial loan in the amount of $200 million (the “Initial Term Loan”) and the availability of additional loans through September 10, 2019, subject to the terms of the Term Credit Agreement, up to an aggregate amount of $75 million for certain acquisitions (the “Additional Term Loans,” and together with the Initial Term Loan, the “Term Loan”). As of March 12, 2020, $220.5 million in aggregate principal amount of our Term Credit Agreement is outstanding.
Borrowings under the Term Credit Agreement bear interest at a rate per annum equal to, at the option of TETRA, either (i) LIBOR plus a margin of 6.25% per annum or (ii) a base rate plus a margin of 5.25% per annum. In addition to paying interest on the outstanding principal under the Term Credit Agreement, TETRA is required to pay a commitment fee in respect of the unutilized commitments at the rate of 1.0% per annum, paid quarterly in arrears based on utilization of the commitments under the Term Credit Agreement.
The Term Credit Agreement contains 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, incurring debt, granting liens, engaging in mergers and other fundamental changes, making investments, entering into or amending transactions with affiliates, paying dividends and making other restricted payments, prepaying other indebtedness, and selling assets. 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. As of December 31, 2019, TETRA is in compliance with the Interest Coverage Ratio requirement.
All obligations under the Term Credit Agreement and the guarantees of those obligations are secured, subject to certain exceptions, by a security interest for the benefit of the Term Lenders on substantially all of the personal property of TETRA and certain of its subsidiaries, the equity interests in certain domestic subsidiaries, including CCLP, and a maximum of 65% of the equity interests in certain foreign subsidiaries.
The Term Credit Agreement includes customary events of default including non-payment of principal, interest or fees, violation of covenants, inaccuracy of representations or warranties, cross-default to other material indebtedness, bankruptcy and insolvency events, invalidity or impairment of security interests or invalidity of loan documents, certain ERISA events, unsatisfied or unstayed judgments, and any change of control.
The loans under the Term Credit Agreement may be voluntarily prepaid, in whole or in part, subject to applicable breakage fees. Any prepayment during the period commencing after the one-year anniversary and ending on the two-year anniversary will have a premium of 3.0% and during the period commencing after the two-
year anniversary and ending on the three-year anniversary, a premium of 1.0%. The maturity date of the Term Credit Agreement is September 10, 2025. There is no prepayment premium required after the third anniversary.
CCLP Financing Activities
CCLP Preferred Units. In January 2019, CCLP began redeeming the remaining CCLP Preferred Units for cash, resulting in 2,660,569 Preferred Units being redeemed during the year ended December 31, 2019 for $31.9 million, which includes approximately $1.5 million of redemption premium that was paid. The last redemption of the remaining outstanding CCLP Preferred Units occurred on August 8, 2019.
CCLP Bank Credit Facility. All of the obligations of CCLP and two of its wholly owned subsidiaries (collectively the "CCLP Borrowers") under the CCLP Credit Agreement are guaranteed by certain of their existing and future domestic subsidiaries. The CCLP Credit Agreement includes a maximum credit commitment of $50.0 million which is available for loans, letters of credit (with a sublimit of $25.0 million), and swingline loans (with a sublimit of $5.0 million), subject to a borrowing base determined by reference to the value of CCLP’s and any other borrowers’ accounts receivable. As of December 31, 2019, and subject to compliance with the covenants, borrowing base, and other provisions of the agreements that may limit borrowings under the CCLP Credit Agreement, CCLP had availability of $17.2 million. Such maximum credit commitment may be increased by $25.0 million in accordance with the terms and conditions of the CCLP Credit Agreement. On June 26, 2019, CCLP entered into an amendment of the CCLP Credit Agreement that, among other things, revised and increased the borrowing base, including adding the value of certain inventory in the determination of the borrowing base.
The CCLP Borrowers may borrow funds under the CCLP Credit Agreement to pay fees and expenses related to the CCLP Credit Agreement and for the Borrowers' ongoing working capital needs and for general partnership purposes. The maturity date of the CCLP Credit Agreement is June 29, 2023. As of December 31, 2019, a $3.5 million balance was outstanding along with $3.5 million in letters of credit against the CCLP Credit Agreement. As of March 12, 2020, CCLP has no balance outstanding under the CCLP Credit Agreement and $3.0 million letters of credit.
Borrowings under the CCLP Credit Agreement will bear interest at a rate per annum equal to, at the option of the CCLP Borrowers, either (i) LIBOR plus a margin based on average daily excess availability or (ii) a base rate plus a margin based on average daily excess availability. LIBOR-based loans will have an applicable margin ranging between 1.75% and 2.25% per annum and base-rate loans will have an applicable margin ranging from 0.75% to 1.25% per annum, according to average daily excess availability when financial statements are delivered. In addition to paying interest on outstanding principal under the CCLP Credit Agreement, the CCLP Borrowers are required to pay certain fees.
The CCLP Credit Agreement contains certain affirmative and negative covenants, including covenants that restrict the ability of the CCLP Borrowers and certain of its wholly owned subsidiaries named as guarantors (the "CCLP Credit Agreement Guarantors"), and certain of their subsidiaries to take certain actions including, among other things and subject to certain significant exceptions, incurring debt, granting liens, making investments, entering into or amending transactions with affiliates, paying dividends, and selling assets. The CCLP Credit Agreement also contains a provision that requires compliance with a fixed charge coverage ratio (as defined in the CCLP Credit Agreement) of not less than 1.0 to 1.0 in the event that certain conditions associated with outstanding borrowings and cash availability occur. As of December 31, 2019, such conditions have not occurred.
All obligations under the CCLP Credit Agreement and the guarantees of those obligations are secured, subject to certain exceptions, by a first priority security interest for the benefit of the Lenders in the CCLP Borrowers’ and the CCLP Credit Agreement Guarantors’ present and future accounts receivable, inventories and related assets, and proceeds of the foregoing.
CCLP Senior Secured Notes. The obligations under the CCLP 7.50% Senior Secured Notes (the "CCLP Senior Secured Notes") are jointly and severally, and fully and unconditionally guaranteed on a senior secured basis by each of CCLP's domestic restricted subsidiaries (other than CSI Compressco Finance) that guarantee its other indebtedness (the "CCLP Senior Secured Notes Guarantors" and together with CCLP and CSI Compressco Finance Inc, the "CCLP Senior Secured Notes Obligors"). The CCLP Senior Secured Notes and the subsidiary guarantees thereof (together, the "CCLP Senior Secured Notes Securities") were issued pursuant to an indenture
described below. As of March 12, 2020, $350.0 million in aggregate principal amount of the CCLP Senior Secured Notes are outstanding. The CCLP Senior Secured Notes Securities are secured by a first-priority security interest in substantially all of CCLP Senior Secured Notes Obligors' assets (the "Collateral"), subject to certain permitted encumbrances and exceptions.
The CCLP Senior Secured Notes accrue interest at a rate of 7.50% per annum. Interest on the CCLP Senior Secured Notes is payable semi-annually in arrears on April 1 and October 1 of each year. The CCLP Senior Secured Notes are scheduled to mature on April 1, 2025.
The CCLP Senior Secured Notes Securities indenture (the "Senior Secured Notes Indenture") contains customary covenants restricting CCLP's ability and the ability of its restricted subsidiaries to: (i) pay distributions on, purchase, or redeem CCLP common units or purchase or redeem any subordinated debt; (ii) incur or guarantee additional indebtedness or issue certain kinds of preferred equity securities; (iii) create or incur certain liens securing indebtedness; (iv) sell assets, including dispositions of the Collateral; (v) consolidate, merge, or transfer all or substantially all of CCLP's assets; (vi) enter into transactions with affiliates; and (vii) enter into agreements that restrict distributions or other payments from CCLP's restricted subsidiaries to CCLP. These covenants are subject to a number of important limitations and exceptions, including certain provisions permitting CCLP, subject to the satisfaction of certain conditions, to transfer assets to certain of its unrestricted subsidiaries. Moreover, if the CCLP Senior Secured Notes receive an investment grade rating from at least two rating agencies and no default has occurred and is continuing under the CCLP Senior Secured Notes Indenture, many of the restrictive covenants in the CCLP Senior Secured Notes Indenture will be terminated. The CCLP Senior Secured Notes Indenture also contains customary events of default and acceleration provisions relating to events of default, which provide that upon an event of default under the CCLP Senior Secured Notes Indenture, the Trustee or the holders of at least 25% in aggregate principal amount of the then outstanding CCLP Senior Secured Notes may declare all of the CCLP Senior Secured Notes to be due and payable immediately. CCLP is in compliance with all covenants of the CCLP Senior Secured Notes Indenture as of December 31, 2019.
CCLP Senior Notes. The obligations under the CCLP 7.25% Senior Notes (the "CCLP Senior Notes") are jointly and severally and fully and unconditionally, guaranteed on a senior unsecured basis by each of CCLP’s domestic restricted subsidiaries (other than CSI Compressco Finance) that guarantee CCLP’s other indebtedness (the "Guarantors" and together with the Issuers, the "Obligors"). The CCLP Senior Notes and the subsidiary guarantees thereof (together, the "CCLP Senior Note Securities") were issued pursuant to an indenture described below. As of March 12, 2020, $295.9 million in aggregate principal amount of the CCLP Senior Notes are outstanding.
The Obligors issued the CCLP Senior Note Securities pursuant to the Indenture dated as of August 4, 2014 (the "CCLP Senior Notes Indenture") by and among the Obligors and U.S. Bank National Association, as trustee (the "Trustee"). The CCLP Senior Notes accrue interest at a rate of 7.25% per annum. Interest on the CCLP Senior Notes is payable semi-annually in arrears on February 15 and August 15 of each year. The CCLP Senior Notes are scheduled to mature on August 15, 2022.
The CCLP Senior Notes Indenture contains customary covenants restricting CCLP’s ability and the ability of its restricted subsidiaries to: (i) pay dividends and make certain distributions, investments and other restricted payments; (ii) incur additional indebtedness or issue certain preferred shares; (iii) create certain liens; (iv) sell assets; (v) merge, consolidate, sell or otherwise dispose of all or substantially all of its assets; (vi) enter into transactions with affiliates; and (vii) designate its subsidiaries as unrestricted subsidiaries under the CCLP Senior Notes Indenture. The CCLP Senior Notes Indenture also contains customary events of default and acceleration provisions relating to such events of default, which provide that upon an event of default under the CCLP Senior Notes Indenture, the Trustee or the holders of at least 25% in aggregate principal amount of the CCLP Senior Notes then outstanding may declare all amounts owing under the CCLP Senior Notes to be due and payable. CCLP is in compliance with all covenants of the CCLP Senior Note Purchase Agreement as of December 31, 2019.
Other Sources and Uses
In addition to the aforementioned credit facilities and senior notes, we and CCLP fund our respective short-term liquidity requirements from cash generated by our respective 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.
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.
The Second Amended and Restated Partnership Agreement of CCLP requires that within 45 days after the end of each quarter, CCLP distribute all of its available cash, as defined in the Second Amended and Restated Partnership Agreement, to its unitholders of record on the applicable record date. During the year ended December 31, 2019, CCLP distributed approximately $1.9 million in cash, including approximately $1.2 million to its public unitholders. The amount of quarterly distributions is determined based on a variety of factors, including estimates of CCLP's cash needs to fund its future operating, investing, and debt service requirements. There can be no assurance that quarterly distributions from CCLP will increase from this amount per unit going forward.
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, 2019 and 2018, 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
We are named defendants in several 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 impact on our financial condition, results of operations, or liquidity.
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, 2019, 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 $95.0 million, extending through 2029.
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 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 US 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”) payable to us in full, together with interest at a rate of 1.52% per annum, on December 31, 2019, along with a personal guaranty agreement from Thomas M. Clarke and Ana M. Clarke guaranteeing the payment obligations of Epic Companies pursuant to the Epic Promissory Note (the “Clarke Promissory Note Guaranty Agreement”). Additionally, pursuant to the Equity Interest Purchase Agreement (the “Offshore Services Purchase Agreement”) and other agreements with Epic Companies, certain other amounts relating to the Offshore Division totaling approximately $1.5 million were payable to us. At the end of August 2019, Epic Companies filed for bankruptcy. We recorded a reserve of $7.5
million for the full amount of the promissory note, including accrued interest, and the 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. Upon the default by Epic and the Clarkes, we filed a lawsuit against the Clarkes on January 15, 2020 in Montgomery County, Texas for breach of the Clarke Promissory Note Guaranty Agreement, seeking the amounts due under the Epic Promissory Note and related interest, as well as attorneys’ fees and expenses. The Clarkes each filed an answer and counterclaims for fraud and negligent misrepresentation and seek monetary damages in excess of $1 million, punitive damages, and attorneys’ fees. We will vigorously prosecute our claim and defend against the claims by the Clarkes.
For further discussion, see Note 10 - "Acquisitions and Dispositions," in the Notes to Consolidated Financial Statements.
Contractual Obligations
The table below summarizes our consolidated contractual cash obligations as of December 31, 2019:
(1)
We have estimated the timing of these payments for asset retirement obligation liabilities based upon our plans. The amounts shown represent the discounted obligation as of December 31, 2019.
(2)
Amounts exclude other long-term liabilities reflected in our Consolidated Balance Sheet that do not have known payment streams. These excluded amounts include approximately $0.4 million of liabilities under FASB Codification Topic 740, “Accounting for Uncertainty in Income Taxes,” as we are unable to reasonably estimate the ultimate amount or timing of settlements. See Note 16 - "Income Taxes” in the Notes to Consolidated Financial Statements for further discussion.
New Accounting Pronouncements
We adopted the new lease accounting standard on January 1, 2019. The new lease standard had a material impact to our consolidated financial statements, resulting from the inclusion of operating lease right-of-use assets and operating lease liabilities in our consolidated balance sheet. In addition, during the fourth quarter of 2019, we early adopted the new goodwill standard that allowed for a simplified goodwill impairment test by eliminating Step 2. We used this revised method in our application of the measurement of our goodwill impairment, which was material to our consolidated balance sheet and consolidated statement of operations. Refer to Note 2 - "Summary of Significant Accounting Policies, New Accounting Pronouncements," in the Notes to Consolidated Financial Statements for further discussion.
Item 7A.
Item 7A. Quantitative and Qualitative Disclosures about Market Risk.
Not Applicable.
Item 8.
Item 8. Financial Statements and Supplementary Data.
Our financial statements and supplementary data for us and our subsidiaries required to be included in this Item 8 are set forth in Item 15 of this Report.
Item 9.
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.
None.
Item 9A.
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 Securities Exchange Act of 1934, as amended (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, 2019.
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, 2019, 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, 2019.
Ernst & Young 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, 2019. Ernst & Young 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, 2019, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Board of Directors and Stockholders of
TETRA Technologies, Inc. and Subsidiaries
Opinion on Internal Control over Financial Reporting
We have audited TETRA Technologies, Inc. and subsidiaries’ internal control over financial reporting as of December 31, 2019, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 Framework) (the COSO criteria). In our opinion, TETRA Technologies, Inc. (the Company) maintained, in all material respects, effective internal control over financial reporting as of December 31, 2019, based on the COSO criteria.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the 2018 consolidated financial statements of the Company and our report dated March 16, 2020, expressed an unqualified opinion thereon.
Basis for Opinion
The Company's management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying “Management’s Report on Internal Control Over Financial Reporting.” Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects.
Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
Definition and Limitations of Internal Control Over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s 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 the assets of the company; (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 of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s 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. Also, 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.
/s/ ERNST & YOUNG LLP
Houston, Texas
March 16, 2020
Item 9B.
Item 9B. Other Information.
None.
PART III
Item 10.
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,” and “Section 16(a) Beneficial Ownership Reporting Compliance” in our definitive proxy statement (the "Proxy Statement") for the annual meeting of stockholders to be held on May 7, 2020, which involves the election of directors and is to be filed with the SEC pursuant to the Securities Exchange Act of 1934 as amended (the "Exchange Act") within 120 days of the end of our fiscal year on December 31, 2019.
Item 11.
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 of 1933, or the Exchange Act, as a result of this furnishing, except to the extent we specifically incorporate it by reference.
Item 12.
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.
Item 13.
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.
Item 14.
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
Item 15.
Item 15. Exhibits and Financial Statement Schedules.
(a) List of documents filed as part of this Report
+
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, 2019, 2018 and 2017; (ii) Consolidated Balance Sheets as of December 31, 2019 and December 31, 2018; (iii) Consolidated Statements of Comprehensive Income for the years ended December 31, 2019, 2018 and 2017; (iv) Consolidated Statements of Cash Flows for the years ended December 31, 2019, 2018 and 2017; (v) Consolidated Statements of Stockholders’ Equity for the years ended December 31, 2019, 2018 and 2017; and (vi) Notes to Consolidated Financial Statements for the year ended December 31, 2019.
Item 16. Form 10-K Summary.
None.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, TETRA Technologies, Inc. has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated:
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Board of Directors and Stockholders of
TETRA Technologies, Inc. and Subsidiaries
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of TETRA Technologies, Inc. and subsidiaries (the Company) as of December 31, 2019 and 2018, the related consolidated statements of operations, comprehensive income (loss), equity, and cash flows for each of the three years in the period ended December 31, 2019, and the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company at December 31, 2019 and 2018, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2019, in conformity with U.S. generally accepted accounting principles.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company's internal control over financial reporting as of December 31, 2019, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 Framework) and our report dated March 16, 2020, expressed an unqualified opinion thereon.
Basis for Opinion
These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures include examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
/s/ ERNST & YOUNG LLP
We have served as the Company's auditor since 1981.
Houston, Texas
March 16, 2020
TETRA Technologies, Inc. and Subsidiaries
Consolidated Balance Sheets
(In Thousands)
See Notes to Consolidated Financial Statements
TETRA Technologies, Inc. and Subsidiaries
Consolidated Balance Sheets
(In Thousands, Except Share Amounts)
See Notes to Consolidated Financial Statements
TETRA Technologies, Inc. and Subsidiaries
Consolidated Statements of Operations
(In Thousands, Except Per Share Amounts)
See Notes to Consolidated Financial Statements
TETRA Technologies, Inc. and Subsidiaries
Consolidated Statements of Comprehensive Income (Loss)
(In Thousands)
See Notes to Consolidated Financial Statements
TETRA Technologies, Inc. and Subsidiaries
Consolidated Statements of Equity
(In Thousands)
See Notes to Consolidated Financial Statements
TETRA Technologies, Inc. and Subsidiaries
Consolidated Statements of Cash Flows
(In Thousands)
See Notes to Consolidated Financial Statements
TETRA Technologies, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
December 31, 2019
NOTE 1 - ORGANIZATION AND OPERATIONS
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, offshore rig cooling services, and compression services and equipment. We were incorporated in Delaware in 1981. Our products and services are delivered through three reporting segments - Completion Fluids & Products, Water & Flowback Services, and Compression. Unless the context requires otherwise, when we refer to “we,” “us,” and “our,” we are describing TETRA Technologies, Inc. and its consolidated subsidiaries on a consolidated basis.
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, Africa, Europe, the Middle East, and Australia.
Our Compression Division is a provider of compression services and equipment for natural gas and oil production, gathering, artificial lift, transmission, processing, and storage. The Compression Division's equipment sales business includes the fabrication and sale of standard and custom-designed, engineered compressor packages fabricated primarily at our facility in Midland, Texas. The Compression Division's aftermarket business provides a wide range of services to support the needs of customers who own compression equipment as well as the sale of compressor package parts and components manufactured by third-party suppliers. The Compression Division provides its services and equipment to a broad base of natural gas and oil exploration and production, midstream, transmission, and storage companies operating throughout many of the onshore producing regions of the United States, as well as in a number of other countries, including Mexico, Canada, and Argentina.
NOTE 2 - BASIS OF PRESENTATION AND SIGNIFICANT ACCOUNTING POLICIES
Principles of Consolidation
Our consolidated financial statements include the accounts of our wholly owned subsidiaries. We consolidate the financial statements of our CSI Compressco LP subsidiary ("CCLP") as part of our Compression Division, as we determined that CCLP is a variable interest entity and we are the primary beneficiary. We control the financial interests of CCLP and have the ability to direct the activities of CCLP that most significantly impact its economic performance through our ownership of its general partner. The share of CCLP net assets and earnings that is not owned by us is presented as noncontrolling interest in our consolidated financial statements. Our cash flows from our investment in CCLP are limited to the quarterly distributions we receive on our CCLP common units and general partner interest (including incentive distribution rights) and the amounts collected for services we perform on behalf of CCLP, as TETRA's capital structure and CCLP's capital structure are separate, and do not include cross default provisions, cross collateralization provisions, or cross guarantees. As of December 31, 2019, our consolidated balance sheet includes $49.0 million of restricted net assets, consisting of the consolidated net assets of CCLP. All intercompany accounts and transactions have been eliminated in consolidation.
Use of Estimates
The preparation of financial statements in conformity with U.S. generally accepted accounting principles ("GAAP") requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclose contingent assets and liabilities at the date of the financial statements and the reported
amounts of revenues, expenses, and impairments during the reporting period. Actual results could differ from those estimates, and such differences could be material.
Reclassifications
Certain previously reported financial information has been reclassified to conform to the current year's presentation. For a discussion of the reclassification of the financial presentation of our Offshore Division as discontinued operations, see Note 11 - "Discontinued Operations."
Cash Equivalents
We consider all highly liquid cash investments with a maturity of three months or less when purchased to be cash equivalents.
Financial Instruments
Financial instruments that subject us to concentrations of credit risk consist principally of trade receivables with companies in the energy industry. Our policy is to evaluate, prior to providing goods or services, each customer's financial condition and to determine the amount of open credit to be extended. We generally require appropriate, additional collateral as security for credit amounts in excess of approved limits. Our customers consist primarily of major, well-established oil and gas producers and independent oil and gas companies. Payment terms are on a short-term basis.
We have currency exchange rate risk exposure related to transactions denominated in a foreign currency as well as to investments in certain of our international operations. Our risk management activities include the use of foreign currency forward purchase and sale derivative contracts as part of a program designed to mitigate the currency exchange rate risk exposure on selected international operations.
We have $1.0 million and CCLP has $3.5 million outstanding under variable rate revolving credit facilities as of December 31, 2019. Outstanding balances on variable rate bank credit facilities create market risk exposure related to changes in applicable interest rates.
Allowance for Doubtful Accounts
The allowance for doubtful accounts is determined on a specific identification basis when we believe that the collection of specific amounts owed to us is not probable. Changes in the allowance is as follows:
Inventories
Inventories are stated at the lower of cost or net realizable value. Except for work in progress inventory, cost is determined using the weighted average method. The cost of work in progress is determined using the specific identification method.
Property, Plant, and Equipment
Property, plant, and equipment are stated at cost. Expenditures that increase the useful lives of assets are capitalized. The cost of repairs and maintenance is charged to operations as incurred. For financial reporting
purposes, we provide for depreciation using the straight-line method over the estimated useful lives of assets, which are generally as follows:
Leasehold improvements are depreciated over the shorter of the remaining term of the associated lease or its useful life. Depreciation expense, excluding impairments and other charges, for the years ended December 31, 2019, 2018, and 2017 was $116.2 million, $106.9 million, and $97.3 million, respectively.
Construction in progress as of December 31, 2019 and 2018 consists primarily of equipment fabrication projects.
Intangible Assets other than Goodwill
Patents, trademarks, and other intangible assets are amortized on a straight-line basis over their estimated useful lives, ranging from 2 to 20 years. Amortization expense of patents, trademarks, and other intangible assets was $8.5 million, $7.3 million, and $6.1 million for the years ended December 31, 2019, 2018, and 2017, respectively, and is included in depreciation, amortization and accretion. The estimated future annual amortization expense of patents, trademarks, and other intangible assets is $7.7 million for 2020, $7.4 million for 2021, $7.0 million for 2022, $6.7 million for 2023, and $6.6 million for 2024.
Intangible assets other than goodwill are tested for recoverability whenever events or changes in circumstances indicate that the carrying value of the asset may not be recoverable. In such an event, we will determine the fair value of the asset using an undiscounted cash flow analysis of the asset at the lowest level for which identifiable cash flows exist. If an impairment has occurred, we will recognize a loss for the difference between the carrying value and the estimated fair value of the intangible asset. During 2018 and 2017, certain intangible assets were impaired. See "Impairments of Long-Lived Assets" section in Note 5 - "Impairments and Other Charges".
Goodwill
Goodwill represents the excess of cost over the fair value of the net assets acquired in business combinations. We perform a goodwill impairment test at a reporting unit level on an annual basis or whenever indicators of impairment are present. We perform the annual test of goodwill impairment as of the last day of the fourth quarter of each year. The first step of the impairment test is to compare the estimated fair value of the reporting unit to its recorded net book value (including goodwill). If the estimated fair value is higher than the recorded net book value, no impairment is deemed to exist and no further testing is required. If, however, the carrying amount of the reporting unit exceeds its estimated fair value, an impairment loss is calculated based on the difference between the fair value and carrying value. These estimates are imprecise and are subject to our estimates of the future cash flows of the reporting unit. These estimates and judgments are affected by numerous factors, including the general economic environment at the time of our assessment. During the fourth quarter of 2019, we recorded an impairment on all our remaining goodwill. See Note 4 - "Goodwill" for additional discussion.
Leases
As a lessee, unless the lease meets the criteria of short-term and is excluded per our policy election described below, we initially recognize a lease liability and related right-of-use asset on the commencement date. The right-of-use asset represents our right to use an underlying asset and the lease liability represents our obligation to make lease payments to the lessor over the lease term.
Long-term operating leases are included in operating lease right-of-use assets, accrued liabilities and other, and operating lease liabilities in our consolidated balance sheet as of December 31, 2019. Long-term finance leases are not material. We determine whether a contract is or contains a lease at inception of the contract. Where we are a lessee in a contract that includes an option to extend or terminate the lease, we include the extension
period or exclude the period covered by the termination option in our lease term, if it is reasonably certain that we would exercise the option.
As an accounting policy election, we do not include short-term leases on our balance sheet. Short-term leases include leases with a term of 12 months or less, inclusive of renewal options we are reasonably certain to exercise. The lease payments for short-term leases are included as operating lease costs on a straight-line basis over the lease term in cost of revenues or general and administrative expense based on the use of the underlying asset. We recognize lease costs for variable lease payments not included in the determination of a lease liability in the period in which an obligation is incurred.
As allowed by U.S. GAAP, we do not separate nonlease components from the associated lease component for our compression services contracts and instead account for those components as a single component based on the accounting treatment of the predominant component. In our evaluation of whether Financial Accounting Standards Board ("FASB") Accounting Standards Codification ("ASC") 842 "Leases" or ASC 606 "Revenue from Contracts with Customers" is applicable to the combined component based on the predominant component, we determined the services nonlease component is predominant, resulting in the ongoing recognition of our compression services contracts following ASC 606.
Our operating and finance leases are recognized at the present value of lease payments over the lease term. When the implicit discount rate is not readily determinable, we use our incremental borrowing rate to calculate the discount rate used to determine the present value of lease payments. Consistent with other long-lived assets or asset groups that are held and used, we test for impairment of our right-of-use assets when impairment indicators are present.
Impairments of Long-Lived Assets
Impairments of long-lived assets, including identified intangible assets, are determined periodically when 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 undiscounted operating cash flows to be generated from these assets throughout their remaining estimated useful lives. If these undiscounted cash flows are less than the carrying amount of the related asset, an impairment is recognized for the excess of the carrying value over its fair value. Assets held for disposal are recorded at the lower of carrying value or estimated fair value less estimated selling costs. See Note 5 - "Impairments and Other Charges" for additional discussion of recorded impairments.
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. These facilities are a combination of owned and leased assets. We are required to take certain actions in connection with the retirement of these assets. Asset retirement obligations are recorded in accordance with ASC 410, "Asset Retirement and Environmental Obligations," whereby the estimated fair value of a liability for asset retirement obligations is recognized in the period in which it is incurred and in which a reasonable estimate can be made. Such estimates are based on relevant assumptions that we believe are reasonable. We have reviewed our obligations in this regard in detail and estimated the cost of these actions. The associated asset retirement costs are capitalized as part of the carrying amount of these long-lived assets and are depreciated on a straight-line basis over the life of the assets.
Environmental Liabilities
Environmental expenditures that result in additions to property and equipment are capitalized, while other environmental expenditures are expensed. Environmental remediation liabilities are recorded on an undiscounted basis when environmental assessments or cleanups are probable and the costs can be reasonably estimated. We have no significant environmental remediation liabilities as of December 31, 2019 and 2018. Estimates of future environmental remediation expenditures often consist of a range of possible expenditure amounts, a portion of which may be in excess of amounts of liabilities recorded. In such an instance, we disclose the full range of amounts reasonably possible of being incurred. Any changes or developments in environmental remediation efforts are accounted for and disclosed each quarter as they occur. Any recoveries of environmental remediation costs from other parties are recorded as assets when their receipt is deemed probable.
Complexities involving environmental remediation efforts can cause estimates of the associated liability to be imprecise. Factors that cause uncertainties regarding the estimation of future expenditures include, but are not limited to, the effectiveness of the anticipated work plans in achieving targeted results and changes in the desired remediation methods and outcomes as prescribed by regulatory agencies. Uncertainties associated with environmental remediation contingencies are pervasive and often result in wide ranges of reasonably possible outcomes. Estimates developed in the early stages of remediation can vary significantly. Normally, a finite estimate of cost does not become fixed and determinable at a specific point in time. Rather, the costs associated with environmental remediation become estimable as the work is performed and the range of ultimate cost becomes more defined. It is possible that cash flows and results of operations could be materially affected by the impact of the ultimate resolution of these contingencies.
Revenue Recognition
Performance Obligations. Revenue is generally recognized when we transfer control of our products or services to our customers. Revenue is measured as the amount of consideration we expect to receive in exchange for transferring products or providing services to our customers. We receive cash equal to the invoice price for most sales of product and services and payment terms typically range from 30 to 60 days from the date we invoice our customer. Since the period between when we deliver products or services and when the customer pays for such products or services is not expected to exceed one year, we have elected not to calculate or disclose a financing component for our customer contracts.
Depending on the terms of the arrangement, we may also defer the recognition of revenue for a portion of the consideration received because we have to satisfy a future performance obligation. For example, consideration received from customers during the fabrication of new compressor packages is typically deferred until control of the compressor package is transferred to our customer.
For any arrangements with multiple performance obligations, we use management's estimated selling price to determine the stand-alone selling price for separate performance obligations. For revenue associated with mobilization of service equipment as part of a service contract arrangement, such revenue, if significant, is deferred and amortized over the estimated service period.
Product Sales. Product sales revenues are generally recognized when we ship products from our facility to our customer. The product sales for our Completion Fluids & Products Division consist primarily of clear brine fluids ("CBFs"), additives, and associated manufactured products. Product sales for our Water & Flowback Services Division are typically attributed to specific performance obligations within certain production testing service arrangements. Parts and equipment sales comprise the product sales for the Compression Division.
Services. Service revenues represent revenue recognized over time, as our customer arrangements typically provide agreed upon day-rates (monthly service rates for compression services) and we recognize service revenue based upon the number of days services have been performed. Service revenue recognized over time is associated with a majority of our Water & Flowback Services Division arrangements, compression service and aftermarket service contracts within our Compression Division, and a small portion of Completion Fluids & Products Division revenue that is associated with completion fluid service arrangements. With the exception of the initial terms of the compression services contracts for medium- and high-horsepower compressor packages of our Compression Division, our customer contracts are generally for terms of one year or less. The majority of the service arrangements in the Water & Flowback Services Division are for a period of 90 days or less.
Sales taxes, value added taxes, and other taxes we collect concurrent with revenue-producing activities are excluded from revenue. We have elected to recognize the cost for freight and shipping costs as part of cost of product sales when control over our products (i.e. delivery) has transferred to the customer.
Use of Estimates. In recognizing revenue for variable consideration arrangements, the amount of variable consideration recognized is limited so that it is probable that significant amounts of revenues will not be reversed in future periods when the uncertainty is resolved. For products returned by the customer, we estimate the expected returns based on an analysis of historical experience. For volume discounts earned by the customer, we estimate the discount (if any) based on our estimate of the total expected volume of products sold or services to be provided to the customer during the discount period. In certain contracts for the sale of CBFs, we may agree to issue credits for the repurchase of reclaimable used fluids from certain customers at an agreed price that is based on the condition of the fluids.
Contract Assets and Liabilities. We consider contract assets to be trade accounts receivable when we have an unconditional right to consideration and only the passage of time is required before payment is due. In certain instances, particularly those requiring customer specific documentation prior to invoicing, our invoicing of the customer is delayed until certain documentation requirements are met. In those cases, we recognize a contract asset rather than a billed trade accounts receivable until we are able to invoice the customer. Contract assets, along with billed trade accounts receivable, are included in trade accounts receivable in our consolidated balance sheets.
We classify contract liabilities as unearned income in our consolidated balance sheets. Such deferred revenue typically results from advance payments received on orders for new compressor equipment prior to the time such equipment is completed and transferred to the customer in accordance with the customer contract. New equipment sales orders generally take less than twelve months to build and deliver.
Bill-and-Hold Arrangements. We design and fabricate compressor packages based on our customer’s specifications. In some cases, the customer will request us to hold the equipment, upon completion of the unit, until the job site is ready to receive the equipment. When this occurs, we along with the customer sign a bill-and-hold agreement, which outlines that the customer has title to the equipment, the equipment is ready for delivery, we cannot use the equipment or direct it to another customer, and we have a present right to payment. When those criteria have been met and the agreement is executed, we recognize the revenue on the equipment because control of the equipment has passed to our customer and our performance obligations are complete. Entering into these arrangements is something we have done as a courtesy for certain customers for many years. The equipment subject to the bill-and-hold agreements have generally been invoiced and paid for through progressive billings such that at the time the bill-and-hold agreement is executed, the majority of the contractual cash obligation of the customer has been received by us.
Operating Costs
Cost of product sales includes direct and indirect costs of manufacturing and producing our products, including raw materials, fuel, utilities, labor, overhead, repairs and maintenance, materials, services, transportation, warehousing, equipment rentals, insurance, and certain taxes. Cost of services includes operating expenses we incur in delivering our services, including labor, equipment rental, fuel, repair and maintenance, transportation, overhead, insurance, and certain taxes. We include in product sales revenues the reimbursements we receive from customers for shipping and handling costs. Shipping and handling costs are included in cost of product sales. Amounts we incur for “out-of-pocket” expenses in the delivery of our services are recorded as cost of services. Reimbursements for “out-of-pocket” expenses we incur in the delivery of our services are recorded as service revenues. Depreciation, amortization, and accretion includes depreciation expense for all of our facilities, equipment and vehicles, amortization expense on our intangible assets, and accretion expense related to our decommissioning and other asset retirement obligations.
We include in general and administrative expense all costs not identifiable to our specific product or service operations, including divisional and general corporate overhead, professional services, corporate office costs, sales and marketing expenses, insurance, and certain taxes.
Equity-Based Compensation
We and CCLP have various equity incentive compensation plans which provide for the granting of restricted common stock, options for the purchase of our common stock, and other performance-based, equity-based compensation awards to our executive officers, key employees, nonexecutive officers, and directors. Total equity-based compensation expense, net of taxes, for the three years ended December 31, 2019, 2018, and 2017, was $5.8 million, $5.8 million, and $5.0 million, respectively. For further discussion of equity-based compensation, see Note 14 - "Equity-Based Compensation."
Income Taxes
Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis amounts. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect of a
change in tax rates is recognized as income or expense in the period that includes the enactment date. A portion of the carrying value of certain deferred tax assets are subject to a valuation allowance. See Note 16 - "Income Taxes" for further discussion.
In January 2018, the FASB released guidance on the accounting for tax on the global intangible low-taxed income ("GILTI") provisions of the Act. The GILTI provisions impose a tax on foreign income in excess of a deemed return on tangible assets of foreign corporations. The guidance indicates that either accounting for deferred taxes related to GILTI inclusions or to treat any taxes on GILTI inclusions as period costs are both acceptable methods subject to an accounting policy election. As of December 31, 2018, we elected to account for GILTI as a period cost in the year the tax is incurred.
Accumulated Other Comprehensive Income (Loss)
Certain of our international operations maintain their accounting records in the local currencies that are their functional currencies. For these operations, the functional currency financial statements are converted to United States dollar equivalents, with the effect of the foreign currency translation adjustment reflected as a component of accumulated other comprehensive income (loss). Accumulated other comprehensive income (loss) is included in partners' capital in the accompanying audited consolidated balance sheets and consists of the cumulative currency translation adjustments associated with such international operations. Activity within accumulated other comprehensive income includes no reclassifications to net income.
Income (Loss) per Common Share
The calculation of basic earnings per share excludes any dilutive effects of equity awards or warrants. The calculation of diluted earnings per share includes the effect of equity awards and warrants, if dilutive, which is computed using the treasury stock method during the periods such equity awards and warrants were outstanding. A reconciliation of the common shares used in the computations of income (loss) per common and common equivalent shares is presented in Note 17 - "Income (Loss) Per Share."
Foreign Currency Translation
We have designated the euro, the British pound, the Norwegian krone, the Canadian dollar, the Brazilian real, and the Mexican peso as the functional currencies for our operations in Finland and Sweden, the United Kingdom, Norway, Canada, Brazil, and certain of our operations in Mexico, respectively. The U.S. dollar is the designated functional currency for all of our other foreign operations. The cumulative translation effects of translating the applicable accounts from the functional currencies into the U.S. dollar at current exchange rates are included as a separate component of equity. Foreign currency exchange (gains) and losses are included in other (income) expense, net, and totaled $(3.1) million, $(0.1) million, and $1.6 million for the years ended December 31, 2019, 2018 and 2017, respectively.
On June 30, 2018, we determined the economy in Argentina to be highly inflationary. As a result of this determination and in accordance with U.S. GAAP, on July 1, 2018, the functional currency of our operations in Argentina was changed from the Argentine peso to the U.S. dollar. The remeasurement did not have a material impact on our consolidated financial position or results of operations.
Fair Value Measurements
We utilize fair value measurements to account for certain items and account balances within our consolidated financial statements. Fair value measurements are utilized on a recurring basis in the determination of the carrying values of certain liabilities, including the liabilities for the warrants to purchase 11.2 million shares of our common stock (the "Warrants") and our foreign currency derivative contracts. Refer to Note 15 - "Fair Value Measurements" for further discussion.
Fair value measurements are also utilized on a nonrecurring basis in certain circumstances, such as in the allocation of purchase consideration for acquisition transactions to the assets and liabilities acquired, including intangible assets and goodwill (a Level 3 fair value measurement), the initial recording of our asset retirement obligations, and for the impairment of long-lived assets, including goodwill (a Level 3 fair value measurement).
CCLP Preferred Units
In January 2019, CCLP began redeeming CSI Compressco LP Series A Convertible Preferred Units (the "CCLP Preferred Units") for cash, resulting in 2,660,569 CCLP Preferred Units being redeemed during the twelve months ended December 31, 2019 for an aggregate of $31.9 million, which includes approximately $1.5 million of redemption premium that was paid and charged to other (income) expense, net in the accompanying consolidated statements of operation. The last redemption of the remaining outstanding CCLP Preferred Units, along with a final cash payment made in lieu of paid-in-kind units, occurred on August 8, 2019, for an aggregate cash payment of $5.0 million, of which $0.6 million was paid to us.
New Accounting Pronouncements
Standards adopted in 2019
In February 2016, the FASB issued Accounting Standards Update ("ASU") 2016-02, "Leases (Topic 842)" to increase comparability and transparency among different organizations. Organizations are required to recognize right-of-use lease assets and lease liabilities in the balance sheet related to the right to use the underlying asset for the lease term. In addition, through improved disclosure requirements, ASC 842 will enable users of financial statements to further understand the amount, timing, and uncertainty of cash flows arising from leases. We adopted the standard effective January 1, 2019. The standard had a material impact on our consolidated balance sheet, specifically, the reporting of our operating leases. The impact in the reporting of our finance leases was insignificant.
We chose to transition using a modified retrospective approach which allows for the recognition of a cumulative effect adjustment to the opening balance of retained earnings in the period of adoption rather than the earliest period presented. Comparative information is reported under the accounting standards that were in effect for those periods. In addition, upon transition, we elected the package of practical expedients, which allows us to continue to apply historical lease classifications to existing contracts. Upon adoption, we recognized $60.6 million in operating right-of-use assets, $12.0 million in accrued liabilities and other, and $50.7 million in operating lease liabilities in our consolidated balance sheet. In addition, we also recognized a $2.8 million cumulative effect adjustment to increase retained earnings, primarily as a result of a deferred gain from a previous sale and leaseback transaction on our corporate headquarters facility that was accounted for as an operating lease. Refer to Note 7 - “Leases” for further information on our leases.
In February 2018, the FASB issued ASU 2018-02, "Income Statement-Reporting Comprehensive Income (Topic 220)" that gives entities the option to reclassify the income tax effects of the Tax Cuts and Jobs Act from accumulated other comprehensive income to retained earnings. This was effective for us on January 1, 2019, however, as we do not have associated tax effects in accumulated other comprehensive income, there was no impact.
In June 2018, the FASB issued ASU 2018-07, “Compensation-Stock Compensation (Topic 718): Improvements to Nonemployee Share-Based Payment Accounting” to align the measurement and classification guidance for share-based payments to nonemployees with the guidance currently applied to employees, with certain exceptions. We adopted this ASU during the three months ended March 31, 2019, with no material impact to our consolidated financial statements.
In January 2017, the FASB issued ASU 2017-04, "Intangibles-Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment," which simplifies how an entity is required to test goodwill for impairment by eliminating Step 2 from the goodwill impairment test. The ASU is effective for annual periods beginning after December 15, 2019, and interim periods within those annual periods, with early adoption permitted, under a prospective adoption. Due to its simplification of goodwill impairment measurement, we chose to early adopt the standard during the fourth quarter of 2019 and impaired $25.8 million of goodwill, leaving no remaining goodwill on our balance sheet. See Note 4 - "Goodwill" for further discussion.
Standards not yet adopted
In June 2016, the FASB issued ASU 2016-13, "Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments." ASU 2016-13 amends the impairment model to utilize an expected loss methodology in place of the currently used incurred loss methodology, which will result in the more timely recognition of losses on financial instruments not accounted for at fair value through net income. The
provisions require credit impairments to be measured over the contractual life of an asset and developed with consideration for past events, current conditions, and forecasts of future economic information. Credit impairment will be accounted for as an allowance for credit losses deducted from the amortized cost basis at each reporting date. Updates at each reporting date after initial adoption will be recorded through selling, general, and administrative expense. ASU 2016-13 is effective for us the first quarter of fiscal 2023. We continue to assess the potential effects of these changes to our consolidated financial statements.
In August 2018, the FASB issued ASU 2018-15, "Intangibles-Goodwill and Other-Internal-Use Software (Subtopic 350-40): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract." ASU 2018-15 clarifies the accounting for implementation costs in cloud computing arrangements. ASU 2018-15 is effective for us the first quarter of fiscal 2020. We do not expect the adoption of this standard to have a material impact on our consolidated financial statements.
In December 2019, the FASB issued ASU 2019-12, "Income Taxes (Topic 740): Simplifying the Accounting for Income Taxes." ASU 2019-12 simplifies the accounting for income taxes by eliminating certain exceptions related to intraperiod tax allocation, interim period income tax calculation methodology, and the recognition of deferred tax liabilities for outside basis differences. It also simplifies certain aspects of accounting for franchise taxes and clarifies the accounting for transactions that results in a step-up in the tax basis of goodwill. ASU 2019-12 is effective for us the first quarter of fiscal 2021. We continue to assess the potential effects of these changes to our consolidated financial statements.
NOTE 3 - REVENUE FROM CONTRACTS WITH CUSTOMERS
As of December 31, 2019, we had $62.3 million of remaining contractual performance obligations for compression services. As a practical expedient, this amount does not reflect revenue for compression service contracts whose original expected duration is less than twelve months and does not consider the effects of the time value of money. Expected revenue to be recognized in the future as of December 31, 2019 for completion of performance obligations of compression service contracts are as follows:
For sales of CBFs where we have agreed to issue credits for the repurchase of reclaimable used fluids at an agreed price based on the condition of the fluid upon return, we adjust the revenue recognized in the period of shipment by an estimated amount, based on historical experience, of the credit expected to be issued. As of December 31, 2019, the amount of remaining credits expected to be issued for the repurchase of reclaimable used fluids was $2.3 million recorded in inventory (right of return asset) and accounts payable. There were no material differences between amounts recognized during the year ended December 31, 2019, compared to estimates made in a prior period from these variable consideration arrangements.
Our contract asset balances, primarily associated with customer documentation requirements, were $34.9 million and $44.2 million as of December 31, 2019 and December 31, 2018, respectively. Contract assets, along with billed trade accounts receivable, are included in trade accounts receivable in our consolidated balance sheets.
Collections primarily associated with progressive billings to customers for the construction of compression equipment is included in unearned income in the consolidated balance sheets. The following table reflects the changes in unearned income in our consolidated balance sheets for the periods indicated:
During the year ended December 31, 2019, we recognized product sales revenue of $22.6 million from unearned income that was deferred as of December 31, 2018. During the year ended December 31, 2018, we recognized product sales revenue of $14.7 million from unearned income that was deferred as of our adoption of ASC 606 on January 1, 2018.
As of December 31, 2019 and December 31, 2018, contract costs were immaterial.
Disaggregation of Revenue. We disaggregate revenue from contracts with customers into Product Sales and Services within each segment, as noted in our three reportable segments in Note 18. In addition, we disaggregate revenue from contracts with customers by geography based on the following table below.
NOTE 4 - GOODWILL
Our Water & Flowback Services Division consists of two reporting units, Production Testing and Water Management. During the third quarter of 2019, as part of our internal long-term outlook for each of these reporting units, we updated our assessment of the Water Management reporting unit and determined that the current decreased energy industry outlook was an indicator requiring further analysis for impairment of goodwill. As part of the first step of goodwill impairment testing for our Water Management reporting unit, the only reporting unit with goodwill, we updated our assessment of the future cash flows, applying expected long-term growth rates, discount rates, and terminal values that we consider reasonable for the reporting unit. We calculated a present value of the cash flows for the Water Management reporting unit to arrive at an estimate of fair value using a combination of the income approach and the market approach. Based on these assumptions, we determined that the fair value of the Water Management reporting unit exceeded its carrying value, resulting in no impairment at September 30, 2019.
During the fourth quarter of 2019, coinciding with the timing of our annual goodwill assessment, there was further decline in the energy industry outlook resulting in decreased expected future cash flows for our Water Management reporting unit. As part of the first step of goodwill impairment testing for our Water Management reporting unit, the only reporting unit with goodwill, we updated our assessment of the future cash flows, applying expected long-term growth rates, discount rates, and terminal values that we consider reasonable for the reporting unit. We calculated a present value of the cash flows for the Water Management reporting unit to arrive at an estimate of fair value using a combination of the income approach and the market approach. Based on these
assumptions, we determined that the fair value of the Water Management reporting unit was less than its carrying value indicating an impairment. The amount of impairment is calculated based on the difference between the fair value and carrying value in accordance with our early adoption of ASU 2017-04 "Intangibles-Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment." This resulted in an impairment of the entire goodwill balance of $25.8 million at December 31, 2019.
As of December 31, 2019, the carrying amount of goodwill for the Completion Fluids & Products, Water & Flowback Services, and Compression reporting segments are net of $23.8 million, $137.7 million, and $231.8 million, respectively, of accumulated impairment losses. The changes in the carrying amount of goodwill by segment for the three year period ended December 31, 2019, are as follows:
NOTE 5 - IMPAIRMENTS AND OTHER CHARGES
Impairments of Long-Lived Assets
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. The impairment charge is primarily the result of a reduction in the cost of raw materials for certain of our other chemical production plants, following the execution of a long-term raw material supply agreement during the fourth quarter of 2019. As a result, we expect to reduce our dependence on calcium chloride produced at the El Dorado facility, which uses a different production process, involving mechanical evaporation. In addition, demand for calcium chloride from the El Dorado plant is expected to be reduced due to general market conditions in the oil and gas industry. Using the reduced expected future net cash flows on an undiscounted basis, we determined that the carrying value of the El Dorado facility was not recoverable. Fair value of the El Dorado facility was determined using a fair value in-exchange assumption, and the difference between the carrying value of the El Dorado facility asset group and its indicated fair value was recorded as an impairment. Also during the fourth quarter of 2019, we recorded an impairment of $0.3 million related to certain equipment assets in our Water & Flowback Services Division.
During the third quarter of 2019, we recorded a charge of $0.8 million for the carrying value of a certain compressor package that was written off due to being destroyed by fire. Also impacting our Compression Division, during the second quarter of 2019, we recorded impairments of $2.3 million on certain units of our low-horsepower compression fleet, reflecting our decision to dispose of these units upon management's determination that refurbishing this equipment was not economic given limited current and forecasted demand for such equipment. A recoverability analysis was performed on the remaining low-horsepower fleet and we concluded that the remaining fleet was recoverable from estimated future cash flows.
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 on an identified intangible asset within the Water & Flowback Services segment.
During the fourth quarter of 2017, consolidated long-lived asset impairments of approximately $14.9 million were recorded primarily due to the impairment of a certain identified intangible asset resulting from decreased expected future operating cash flows from a Water & Flowback Services segment customer.
NOTE 6 - INVENTORIES
Components of inventories, net of reserve, are as follows:
Finished goods inventories include newly manufactured clear brine fluids as well as used brines that are repurchased from certain customers for recycling. Work in progress inventory consists primarily of new compressor packages located at our Compression Division fabrication facility in Midland, Texas.
NOTE 7 - LEASES
We have operating leases for some of our transportation equipment, office space, warehouse space, operating locations, and machinery and equipment. We have finance leases for certain facility storage tanks and equipment rentals. These finance leases are not material to our financial statements. Our leases have remaining lease terms ranging from 1 to 16 years. Some of our leases have options to extend for various periods, while some have termination options with prior notice of generally 30 days or six months. The office space, warehouse space, operating location leases, and machinery and equipment leases generally require us to pay all maintenance and insurance costs. During the fourth quarter of 2019, our Compression Division entered into a lease agreement commitment for 14 compressor packages that are currently being fabricated. The leases are for a term of seven years and will commence upon the completion of the equipment fabrication, which is expected to occur during the second quarter of 2020. We have no other leases that have not yet commenced that create significant rights and obligations. Our lease agreements do not contain any material residual value guarantees or material restrictive covenants. Variable rent expense was not material.
Our corporate headquarters facility located in The Woodlands, Texas, was sold on December 31, 2012, pursuant to a sale and leaseback transaction. As a condition to the consummation of the purchase and sale of the facility, the parties entered into a lease agreement for the facility having an initial lease term of 15 years, which is classified as an operating lease. Under the terms of the lease agreement, we have the ability to extend the lease for five successive five year periods at base rental rates to be determined at the time of each extension. In November 2019, our Compression Division entered into a sale and leaseback transaction with a third-party lessor whereby we received $9.8 million of proceeds from the sale of compression equipment in service and entered into an associated lease of the equipment having an initial lease term of seven years.
Components of lease expense, included in either cost of revenues or general and administrative expense based on the use of the underlying asset, are as follows (inclusive of lease expense for leases not included on our consolidated balance sheet based on our accounting policy election to exclude leases with a term of 12 months or less):
Rental expense for all operating leases was $59.4 million, $40.9 million, and $27.1 million for the years ended December 31, 2019, 2018, and 2017, respectively. At December 31, 2019, future minimum rental receipts under a non-cancelable sublease for office space in one of our locations totaled $6.3 million. For the year ended December 31, 2019, we recognized sublease income of $1.0 million.
Supplemental cash flow information:
Supplemental balance sheet information:
Additional operating lease information:
Future minimum lease payments by year and in the aggregate, under non-cancelable operating leases with terms in excess of one year consist of the following at December 31, 2019:
NOTE 8 - ACCRUED LIABILITIES
Accrued liabilities are detailed as follows:
NOTE 9 - LONG-TERM DEBT AND OTHER BORROWINGS
We believe our capital structure excluding CCLP ("TETRA") and CCLP's capital structure should be considered separately, as there are no cross default provisions, cross collateralization provisions, or cross guarantees between CCLP's debt and TETRA's debt.
Consolidated long-term debt, net of associated deferred financing costs, consists of the following:
Scheduled maturities for the next five years and thereafter are as follows:
As of December 31, 2019, TETRA had $1.0 million outstanding balance and had $6.9 million in letters of credit against its ABL Credit Agreement (as defined below). As of December 31, 2019, subject to compliance with the covenants, borrowing base, and other provisions of the agreement that may limit borrowings, TETRA had an availability of $63.3 million under this agreement. Because the amount of associated deferred financing costs was in excess of the $1.0 million outstanding balance on this ABL Credit Agreement, associated deferred financing costs of $0.3 million as of December 31, 2019, were classified as other long-term assets on the accompanying consolidated balance sheet. As of December 31, 2019, and subject to compliance with the covenants, borrowing base, and other provisions of the agreements that may limit borrowings under the CCLP Credit Agreement, CCLP had availability of $17.2 million.
As described below, TETRA and CCLP are both in compliance with all covenants of their respective credit and senior note agreements as of December 31, 2019.
TETRA Long-Term Debt
Asset-Based Credit Agreement. On September 10, 2018, TETRA, as borrower, and certain of its subsidiaries, entered into an asset-based lending credit agreement (the “ABL Credit Agreement”) with a syndicate of lenders, including JPMorgan Chase Bank, N.A., as administrative agent (collectively, the "ABL Lenders"). 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.
Borrowings under the ABL Credit Agreement bear interest at a rate per annum equal to, at the option of TETRA, either (i) London Interbank Offering Rate (“LIBOR”) plus a margin based upon a fixed charge coverage ratio or (ii) a base rate plus a margin based on a fixed charge coverage ratio. The base rate is determined by reference to the highest of (a) the prime rate of interest as announced from time to time by JPMorgan Chase Bank, N.A. (b) the Federal Funds Effective Rate (as defined in the ABL Credit Agreement) plus 0.5% per annum and (c) LIBOR (adjusted to reflect any required bank reserves) for a one-month period on such day plus 1.0% per annum. Borrowings outstanding have an applicable margin ranging from 1.75% to 2.25% per annum for LIBOR-based loans and 0.75% to 1.25% per annum for base-rate loans, based upon the applicable fixed charge coverage ratio. In addition to paying interest on the outstanding principal under the ABL Credit Agreement, TETRA is required to pay a commitment fee in respect of the unutilized commitments at an applicable rate ranging from 0.375% to 0.5% per annum, paid monthly in arrears based on utilization of the commitments under the ABL Credit Agreement. TETRA is also required to pay a customary letter of credit fee equal to the applicable margin on LIBOR-based loans and fronting fees.
The revolving loans under the ABL Credit Agreement may be voluntarily prepaid, in whole or in part, without premium or penalty, subject to applicable breakage fees. The maturity date of the ABL Credit Agreement is September 10, 2023.
The ABL Credit Agreement contains 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, incurring debt, granting liens, engaging in mergers and other fundamental changes, making investments, entering into or amending transactions with affiliates, paying dividends and making other restricted payments, prepaying other indebtedness, and 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. As of December 31, 2019, such conditions have not occurred. All obligations under the ABL Credit Agreement and the guarantees of those obligations are secured, subject to certain exceptions, by a security interest for the benefit of the ABL Lenders on substantially all of the personal property of TETRA and certain subsidiaries of TETRA, the equity interests in certain domestic subsidiaries, including CCLP, and a maximum of 65% of the equity interests in certain foreign subsidiaries.
The ABL Credit Agreement includes customary events of default including non-payment of principal, interest or fees, violation of covenants, inaccuracy of representations or warranties, cross-default to other material indebtedness, bankruptcy and insolvency events, invalidity or impairment of security interests or invalidity of loan documents, certain ERISA events, unsatisfied or unstayed judgments, and any change of control.
Proceeds of loans under the ABL Credit Agreement were used to pay certain debt of TETRA existing on the effective date of the ABL Credit Agreement and may be used for working capital needs, capital expenditures, and other general corporate purposes. The ABL Credit Agreement replaced TETRA's previous Bank Credit Agreement, as defined and discussed in further detail below. In connection with the execution of the ABL Credit Agreement, $1.3 million of financing costs were incurred, and deferred against the carrying value of the amount outstanding, if any.
Term Credit Agreement
On September 10, 2018, TETRA, as borrower, entered into a credit agreement (the “Term Credit Agreement”) with a syndicate of lenders (collectively, the “Term Lenders”) and Wilmington Trust, National Association, as administrative agent. The Term Credit Agreement provided an initial loan in the amount of $200 million (the “Initial Term Loan”) and the availability of additional loans through September 10, 2019, subject to the terms of the Term Credit Agreement, up to an aggregate amount of $75 million for certain acquisitions (together with the Initial Term Loan, the “Term Loan”).
Borrowings under the Term Credit Agreement bear interest at a rate per annum equal to, at the option of TETRA, either (i) LIBOR plus a margin of 6.25% per annum or (ii) a base rate plus a margin of 5.25% per annum. In addition to paying interest on the outstanding principal under the Term Credit Agreement, TETRA is required to pay a commitment fee in respect of the unutilized commitments at the rate of 1.0% per annum, paid quarterly in arrears based on utilization of the commitments under the Term Credit Agreement.
The Term Credit Agreement contains 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, incurring debt, granting liens, engaging in mergers and other fundamental changes, making investments, entering into or amending transactions with affiliates, paying dividends and making other restricted payments, prepaying other indebtedness, and selling assets. 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. As of December 31, 2019, TETRA is in compliance with the Interest Coverage Ratio requirement.
All obligations under the Term Credit Agreement and the guarantees of those obligations are secured, subject to certain exceptions, by a security interest for the benefit of the Term Lenders on substantially all of the personal property of TETRA and certain of its subsidiaries, the equity interests in certain domestic subsidiaries, including CCLP, and a maximum of 65% of the equity interests in certain foreign subsidiaries.
The Term Credit Agreement includes customary events of default including non-payment of principal, interest or fees, violation of covenants, inaccuracy of representations or warranties, cross-default to other material indebtedness, bankruptcy and insolvency events, invalidity or impairment of security interests or invalidity of loan documents, certain ERISA events, unsatisfied or unstayed judgments and any change of control.
Proceeds from the Initial Term Loan, net of a 2% discount in the amount of $4.0 million, were used to prepay the outstanding indebtedness under the $125.0 million 11% Senior Secured Notes due November 5, 2022 (the “11% Senior Notes”) and indebtedness of TETRA under its then existing bank credit agreement. The loans under the Term Credit Agreement may be voluntarily prepaid, in whole or in part, subject to applicable breakage fees. Any prepayment prior to the one-year anniversary is subject to a “make-whole” payment as set forth in the Term Credit Agreement. Thereafter, any prepayment during the period commencing after the one-year anniversary and ending on the two-year anniversary will have a premium of 3.0% and during the period commencing after the two-year anniversary and ending on the three-year anniversary, a premium of 1.0%. The maturity date of the Term Loan is September 10, 2025. There is no prepayment premium required after the third anniversary. In connection with the issuance of the Term Credit Agreement, TETRA incurred $1.0 million of financing costs, $0.4 million of which was charged to other (income) expense, net during the three months ended September 30, 2018 and $0.6 million of lender fees were deferred against the carrying value of the amount outstanding. These deferred financing costs, along with the 2% discount, are amortized over the term of the Term Credit Agreement.
Bank Credit Agreement
On September 10, 2018, in connection with the closing of the above-described loans, TETRA repaid all outstanding borrowings and obligations under its then existing bank credit agreement dated as of January 27, 2006, as previously amended with a portion of the net proceeds from the above-described loans, and terminated the then existing bank credit agreement. As a result of the termination of the then existing bank credit agreement, during the three month period ended September 30, 2018, associated unamortized deferred financing costs of $0.5 million were charged to other (income) expense, net, and $0.4 million were deferred and will be amortized over the term of the ABL Credit Agreement. Certain ABL Lenders were lenders under the existing bank credit agreement and, accordingly, received a portion of the proceeds from the above-described loans in connection with the repayment of the outstanding borrowings under the bank credit agreement.
11% Senior Note
On September 10, 2018, in connection with the closing of the above-described loans, TETRA repaid all outstanding indebtedness under the 11% Senior Note with a portion of the proceeds from the above-described loans, terminated its obligations under the 11% Senior Note and related note purchase agreement. Affiliates of certain Term Lenders were holders of the 11% Senior Note and, accordingly, received a portion of the proceeds from the Term Credit Agreement in connection with the repayment of the outstanding indebtedness under the 11% Senior Note. In connection with the early termination of the 11% Senior Note, TETRA paid a $7.0 million "make-whole" prepayment fee in accordance with the terms of the 11% Senior Note. This prepayment fee, along with $3.4 million of unamortized discount and $2.9 million of unamortized deferred financing costs associated with the 11% Senior Note, has been deferred and is being amortized over the term of the new Term Credit Agreement.
CCLP Long-Term Debt
CCLP Bank Credit Facility.
On March 22, 2018, in connection with the closing of the CCLP Offering (as defined below), CCLP repaid all outstanding borrowings and obligations under its then existing CCLP Prior Credit Facility with a portion of the net proceeds from the CCLP Offering, and terminated the CCLP Prior Credit Facility. As a result of the termination of the CCLP Prior Credit Facility, associated unamortized deferred financing costs of $3.5 million were charged to other (income) expense, net, during the three month period ended March 31, 2018.
On June 29, 2018, CCLP and two of its wholly owned subsidiaries (collectively the "CCLP Borrowers"), and certain of its wholly owned subsidiaries named therein as guarantors (the "CCLP Credit Agreement Guarantors"), entered into a Loan and Security Agreement (the "CCLP Credit Agreement") with the lenders thereto (the "Lenders"), and Bank of America, N.A., in its capacity as administrative agent, collateral agent, letter of credit issuer, and swing line lender. All of the CCLP Borrowers' obligations under the CCLP Credit Agreement are guaranteed by certain of their existing and future domestic subsidiaries. The CCLP Credit Agreement includes a maximum credit commitment of $50.0 million which is available for loans, letters of credit with a sublimit of $25.0 million and swingline loans with a sublimit of $5.0 million, subject to a borrowing base to be determined by reference to the value of CCLP’s and any other borrowers’ accounts receivable. Such maximum credit commitment may be increased by $25.0 million in accordance with the terms and conditions of the CCLP Credit Agreement.
On June 26, 2019, CCLP entered into an amendment of the CCLP Credit Agreement that, among other things, revised and increased the borrowing base, including adding the value of certain inventory in the determination of the borrowing base.
The CCLP Borrowers may borrow funds under the CCLP Credit Agreement to pay fees and expenses related to the CCLP Credit Agreement and for the Borrower's ongoing working capital needs and for general business purposes. The revolving loans under the CCLP Credit Agreement may be voluntarily prepaid, in whole or in part, without premium or penalty, subject to breakage or similar costs. The maturity date of the CCLP Credit Agreement is June 29, 2023. As of December 31, 2019, $3.5 million balance was outstanding under the CCLP Credit Agreement.
Borrowings under the CCLP Credit Agreement will bear interest at a rate per annum equal to, at the option of the CCLP Borrowers, either (i) the LIBOR plus a margin based on average daily excess availability or (ii) a base rate plus a margin based on average daily excess availability LIBOR-based loans will have an applicable margin of
2.00% per annum and base-rate loans will have an applicable margin of 1.00% per annum; thereafter, the applicable margin will range between 1.75% and 2.25% per annum for LIBOR-based loans and 0.75% and 1.25% per annum for base-rate loans, according to average daily excess availability when financial statements are delivered. In addition to paying interest on outstanding principal under the CCLP Credit Agreement, the CCLP Borrowers are required to pay a commitment fee in respect of the unutilized commitments thereunder, initially at the rate of 0.375% per annum until the delivery of the financial statements for the fiscal quarter ending December 31, 2019 and thereafter at the applicable rate ranging from 0.250% to 0.375% per annum, paid quarterly in arrears based on utilization of the commitments under the CCLP Credit Agreement. The CCLP Borrowers are also required to pay a customary letter of credit fee equal to the applicable margin on revolving credit LIBOR loans and fronting fees.
The CCLP Credit Agreement contains certain affirmative and negative covenants, including covenants that restrict the ability of the CCLP Borrowers, the CCLP Credit Agreement Guarantors and certain of their subsidiaries to take certain actions including, among other things and subject to certain significant exceptions, incurring debt, granting liens, making investments, entering into or amending transactions with affiliates, paying dividends and selling assets. The CCLP Credit Agreement also contains a provision that requires compliance with a fixed charge coverage ratio (as defined in the CCLP Credit Agreement) of not less than 1.0 to 1.0 in the event that certain conditions associated with outstanding borrowings and cash availability occur. As of December 31, 2019, such conditions have not occurred.
All obligations under the CCLP Credit Agreement and the guarantees of those obligations are secured, subject to certain exceptions, by a first priority security interest for the benefit of the Lenders in the CCLP Borrowers’ and the CCLP Credit Agreement Guarantors’ present and future accounts receivable, inventory and related assets and proceeds of the foregoing.
CCLP Senior Notes
The obligations under the CCLP 7.25% Senior Notes (the "CCLP Senior Notes") are jointly and severally and fully and unconditionally, guaranteed on a senior unsecured basis by each of CCLP’s domestic restricted subsidiaries (other than CSI Compressco Finance) that guarantee CCLP’s other indebtedness (the "Guarantors" and together with the Issuers, the "Obligors"). The CCLP Senior Notes and the subsidiary guarantees thereof (together, the "CCLP Senior Note Securities") were issued pursuant to an indenture described below. As of December 31, 2019, $295.9 million in aggregate principal amount of the 7.25% Senior Notes are outstanding.
The Obligors issued the CCLP Senior Note Securities pursuant to the Indenture dated as of August 4, 2014 (the "CCLP Senior Notes Indenture") by and among the Obligors and U.S. Bank National Association, as trustee (the "Trustee"). The CCLP Senior Notes accrue interest at a rate of 7.25% per annum. Interest on the CCLP Senior Notes is payable semi-annually in arrears on February 15 and August 15 of each year. The CCLP Senior Notes are scheduled to mature on August 15, 2022.
The CCLP Senior Notes Indenture contains customary covenants restricting CCLP’s ability and the ability of its restricted subsidiaries to: (i) pay dividends and make certain distributions, investments and other restricted payments; (ii) incur additional indebtedness or issue certain preferred shares; (iii) create certain liens; (iv) sell assets; (v) merge, consolidate, sell or otherwise dispose of all or substantially all of its assets; (vi) enter into transactions with affiliates; and (vii) designate its subsidiaries as unrestricted subsidiaries under the CCLP Senior Notes Indenture. The CCLP Senior Notes Indenture also contains customary events of default and acceleration provisions relating to such events of default, which provide that upon an event of default under the CCLP Senior Notes Indenture, the Trustee or the holders of at least 25% in aggregate principal amount of the CCLP Senior Notes then outstanding may declare all amounts owing under the CCLP Senior Notes to be due and payable. CCLP is in compliance with all covenants of the CCLP Senior Note Purchase Agreement as of December 31, 2019.
During September 2016 and October 2016, we repurchased on the open market and retired $54.1 million aggregate principal amount of 7.25% Senior Notes for a purchase price of $50.9 million, at an average repurchase price of 94% of the principal amount of the 7.25% Senior Notes, plus accrued interest, utilizing a portion of the net proceeds of the sale of the CCLP Preferred Units. Following the repurchase of these 7.25% Senior Notes, $295.9 million aggregate principal amount of 7.25% Senior Notes remain outstanding. In connection with the repurchase of these 7.25% Senior Notes, $1.4 million of early extinguishment net gain was credited to other (income) expense, net during the year ended December 31, 2016, representing the difference between the repurchase price and the
$54.1 million aggregate principal amount of the 7.25% Senior Notes repurchased, and $1.8 million of remaining unamortized deferred finance costs and discounts associated with the repurchased 7.25% Senior Notes.
CCLP Senior Secured Notes
On March 8, 2018, CCLP, and its wholly owned subsidiary, CSI Compressco Finance Inc. (together with CCLP, the "CCLP Issuers") entered into the Purchase Agreement (the “Purchase Agreement”) with Merrill Lynch, Pierce, Fenner & Smith Incorporated as representative of the initial purchasers listed in Schedule A thereto (collectively, the “Initial Purchasers”), pursuant to which the CCLP Issuers agreed to issue and sell to the Initial Purchasers $350 million aggregate principal amount of the CCLP Issuers’ 7.50% Senior Secured First Lien Notes due 2025 (the "CCLP Senior Secured Notes") (the "CCLP Offering") pursuant to an exemption from the registration requirements of the Securities Act of 1933, as amended (the "Securities Act").
The CCLP Issuers closed the CCLP Offering on March 22, 2018. The CCLP Senior Secured Notes were issued at par for net proceeds of approximately $342.5 million, after deducting certain financing costs. CCLP used a portion of the net proceeds to repay in full and terminate its existing CCLP Prior Credit Facility and plans to use the remainder for general partnership purposes, including the expansion of its compression fleet. The obligations under the CCLP Senior Secured Notes are jointly and severally, and fully and unconditionally guaranteed on a senior secured basis by each of CCLP's domestic restricted subsidiaries (other than CSI Compressco Finance) that guarantee its indebtedness (the "CCLP Senior Secured Notes Guarantors" and together with CCLP and CSI Compressco Finance Inc, the "CCLP Senior Secured Notes Obligors"). The CCLP Senior Secured Notes and the subsidiary guarantees thereof (together, the "CCLP Senior Secured Notes Securities") were issued pursuant to an indenture described below. The CCLP Senior Secured Notes Securities are secured by a first-priority security interest in substantially all of CCLP Senior Secured Notes Obligors' assets (other than certain excluded assets) (the "Collateral") as collateral security for their obligations under the CCLP Senior Secured Notes Securities, subject to certain permitted encumbrances and exceptions. On the closing date, CCLP entered into an indenture (the "CCLP Senior Secured Notes Indenture") by and among the Obligors and U.S. Bank National Association, as trustee with respect to the Securities. The CCLP Senior Secured Notes accrue interest at a rate of 7.50% per annum. Interest on the CCLP Senior Secured Notes is payable semi-annually in arrears on April 1 and October 1 of each year, beginning October 1, 2018. The CCLP Senior Secured Notes are scheduled to mature on April 1, 2025. During the year ended December 31, 2018, CCLP incurred total financing costs of $7.6 million related to the CCLP Senior Secured Notes. These costs are deferred, netting against the carrying value of the amount outstanding.
The CCLP Senior Secured Notes Indenture contains customary covenants restricting CCLP's ability and the ability of its restricted subsidiaries to: (i) pay distributions on, purchase, or redeem CCLP common units or purchase or redeem any subordinated debt; (ii) incur or guarantee additional indebtedness or issue certain kinds of preferred equity securities; (iii) create or incur certain liens securing indebtedness; (iv) sell assets, including dispositions of the Collateral; (v) consolidate, merge, or transfer all or substantially all of CCLP's assets; (vi) enter into transactions with affiliates; and (vii) enter into agreements that restrict distributions or other payments from CCLP's restricted subsidiaries to CCLP. These covenants are subject to a number of important limitations and exceptions, including certain provisions permitting CCLP, subject to the satisfaction of certain conditions, to transfer assets to certain of its unrestricted subsidiaries. Moreover, if the CCLP Senior Secured Notes receive an investment grade rating from at least two rating agencies and no default has occurred and is continuing under the CCLP Senior Secured Notes indenture, many of the restrictive covenants in the CCLP Senior Secured Notes Indenture will be terminated. The CCLP Senior Secured Notes Indenture also contains customary events of default and acceleration provisions relating to events of default, which provide that upon an event of default under the CCLP Senior Secured Notes Indenture, the Trustee or the holders of at least 25% in aggregate principal amount of the then outstanding CCLP Senior Secured Notes may declare all of the CCLP Senior Secured Notes to be due and payable immediately. CCLP is in compliance with all covenants of the CCLP Senior Secured Notes Indenture as of December 31, 2019.
On and after April 1, 2021, CCLP may redeem all or a part of the CCLP Senior Secured Notes, from time to time, at the following redemption prices (expressed as a percentage of principal amount), plus accrued and unpaid interest thereon to, but not including, the applicable redemption date, subject to the right of holders of record on the relevant record date to receive interest due on the relevant interest payment date, if redeemed during the 12-month period beginning on April 1 of the years indicated below:
In addition, at any time and from time to time before April 1, 2021, CCLP may, at its option, redeem all or a portion of the CCLP Senior Secured Notes at a redemption price equal to 100% of the principal amount thereof plus the Applicable Premium (as defined in the CCLP Senior Secured Notes Indenture) with respect to the CCLP Senior Secured Notes plus accrued and unpaid interest, if any, to, but not including, the applicable redemption date, subject to the rights of holders of the CCLP Senior Secured Notes on the relevant record date to receive interest due on the relevant interest payment date.
Prior to April 1, 2021, CCLP may on one or more occasions redeem up to 35% of the principal amount of the CCLP Senior Secured Notes with an amount of cash not greater than the amount of the net cash proceeds from one or more equity offerings at a redemption price equal to 107.500% of the principal amount of the CCLP Senior Secured Notes to be redeemed, plus accrued and unpaid interest, if any, to, but not including, the date of redemption, subject to the right of holders of record on the relevant record date to receive interest due on the relevant interest payment date, provided that (a) at least 65% of the aggregate principal amount of the CCLP Senior Secured Notes originally issued on the issue date (excluding notes held by CCLP and its subsidiaries) remains outstanding after each such redemption; and (b) the redemption occurs within 180 days after the date of the closing of the equity offering.
If CCLP experiences certain kinds of changes of control, each holder of the CCLP Senior Secured Notes will be entitled to require CCLP to repurchase all or any part (equal to $2,000 or an integral multiple of $1,000 in excess of $2,000) of that holder’s CCLP Senior Secured Notes pursuant to an offer on the terms set forth in the CCLP Senior Secured Notes Indenture. CCLP will offer to make a cash payment equal to 101% of the aggregate principal amount of the CCLP Senior Secured Notes repurchased plus accrued and unpaid interest, if any, on the CCLP Senior Secured Notes repurchased to the date of repurchase, subject to the rights of holders of the CCLP Senior Secured Notes on the relevant record date to receive interest due on the relevant interest payment date.
NOTE 10 - ACQUISITIONS AND DISPOSITIONS
Acquisition of SwiftWater Energy Services
On February 28, 2018, pursuant to a purchase agreement dated February 13, 2018 (the "SwiftWater Purchase Agreement"), we purchased all of the equity interests in SwiftWater Energy Services, LLC ("SwiftWater"), which is engaged in the business of providing water management and water solutions to oil and gas operators in the Permian Basin market of Texas. Strategically, the acquisition of SwiftWater enhances our position as one of the leading integrated water management companies, providing water transfer, storage, and treatment services, along with proprietary automation technology and numerous other water-related services.
Under the terms of the SwiftWater Purchase Agreement, consideration of $42.0 million of cash, subject to a working capital adjustment, and 7,772,021 shares of our common stock (valued at $28.2 million) were paid at closing. Subsequent to closing, in August 2018, a working capital adjustment of approximately $1.0 million was paid. The sellers also had a right to receive contingent consideration payments, in an aggregate amount of up to $15.0 million, calculated on EBITDA and revenue (each as defined in the SwiftWater Purchase Agreement) of the combined water management business of SwiftWater and our pre-existing operations in the Permian Basin in respect of the period from January 1, 2018 through December 31, 2019. Contingent consideration in the amount of $10.0 million was paid to the sellers during 2019 based on 2018 performance. As of December 31, 2019, all contingent consideration has been paid.
Our allocation of the purchase price for the SwiftWater acquisition that closed on February 28, 2018, is as follows (in thousands):
The above allocation of the purchase price to the SwiftWater net tangible assets and liabilities considers approximately $7.6 million of the initial estimated fair value for the liabilities associated with the contingent purchase price consideration. The initial fair value of the obligation to pay the contingent purchase price consideration was calculated based on the anticipated EBITDA and revenue as of the closing date for the operations of SwiftWater and our pre-existing operations in the Permian Basin.
The allocation of the purchase price to the SwiftWater net tangible assets and liabilities and identifiable intangible assets is final and adjustments to the purchase price allocation have been reflected in the accompanying consolidated balance sheets as of December 31, 2018. Machinery and equipment is depreciated using useful lives of 3 to 15 years and automobiles and trucks are depreciated using useful lives of 3 to 4 years. The acquired intangible assets include $3.3 million for the trademark/tradename, $37.2 million for customer relationships, and $1.5 million of other intangible assets that are stated at estimated fair value and are amortized on a straight-line basis over their estimated useful lives, ranging from 5 to 16 years.
Acquisition of JRGO Energy Services LLC
On December 6, 2018, we purchased JRGO Energy Services LLC (“JRGO”) for a cash purchase price of $7.6 million paid at closing, subject to a working capital adjustment. In addition, contingent consideration of $1.4 million was paid during 2019, based on JRGO's performance during the fourth quarter of 2018. JRGO specializes in delivering comprehensive water management services for oil and gas operators, as well as municipal, state and federal organizations. The acquisition of JRGO broadens our footprint in the Appalachian region and is expected to provide our customers an enhanced, more efficient, diverse, and strategically positioned portfolio of integrated water management services in the Marcellus and Utica basins.
Our allocation of the purchase price for the JRGO acquisition that closed on December 6, 2018, is as follows (in thousands):
The allocation of the purchase price to the JRGO net tangible assets and liabilities and identifiable intangible assets, as of December 31, 2019, is final and adjustments to the purchase price allocation have been reflected in the accompanying consolidated balance sheets as of December 31, 2019.
Sale of Offshore Division
On March 1, 2018, we closed a series of related transactions that resulted in the disposition of our Offshore Division. Pursuant to an Asset Purchase and Sale Agreement (the "Maritech Asset Purchase Agreement") with Orinoco Natural Resources, LLC ("Orinoco"), Orinoco purchased certain remaining offshore oil, gas and mineral leases and related assets of Maritech (the "Maritech Properties"). Immediately thereafter, we closed the transactions contemplated by a Membership Interest Purchase and Sale Agreement (the "Maritech Equity Purchase Agreement") with Orinoco, whereby Orinoco purchased all of the equity interests of Maritech (the "Maritech Equity Interests"). Immediately thereafter, we closed the transactions contemplated by an Equity Interest Purchase Agreement (the "Offshore Services Purchase Agreement") with Epic Offshore Specialty, LLC, an affiliate of Orinoco ("Epic Offshore"), whereby Epic Offshore (the "Offshore Services Sale") purchased all of the equity interests in the wholly owned subsidiaries that comprised our Offshore Services segment operations (the "Offshore Services Equity Interests").
Under the terms of the Maritech Asset Purchase Agreement, the Maritech Equity Purchase Agreement, and the Offshore Services Purchase Agreement, the consideration delivered by Orinoco and Epic Offshore for the Maritech Properties, the Maritech Equity Interests and the Offshore Services Equity Interests consisted of (i) the assumption by Orinoco of substantially all of the liabilities and obligations relating to the ownership, operation and condition of the Maritech Properties and the provision of certain indemnities by Orinoco to us under the Maritech Asset Purchase Agreement, (ii) the assumption by Orinoco of substantially all of the liabilities of Maritech and the provision of certain indemnities by Orinoco under the Maritech Equity Purchase Agreement, (iii) the assumption by Epic Offshore of substantially all of the liabilities of the Offshore Services Equity Interests relating to the periods following the closing of the Offshore Services Sale and the provision of certain indemnities by Epic Offshore under the Offshore Services Purchase Agreement, (iv) cash in the amount $3.1 million (v) a promissory note in the original principal amount of $7.5 million payable by Epic Offshore to us in full, together with interest at a rate of 1.52% per annum, on December 31, 2019, (vi) performance by Orinoco under a Bonding Agreement executed in connection with the Maritech Asset Purchase Agreement and the Maritech Equity Purchase Agreement whereby Orinoco provided at closing non-revocable performance bonds in an amount equal to $46.8 million to cover the performance by Orinoco and Maritech of the asset retirement obligations of Maritech, and (vii) the delivery of a personal guaranty agreement from Thomas M. Clarke and Ana M. Clarke guaranteeing the payment obligations of Orinoco under the Bonding Agreement (collectively, the "Transaction Consideration"). See Note 12 - "Commitments and Contingencies" for further discussion of the promissory note and the Bonding Agreement.
As a result of these transactions, we have effectively exited the businesses of our Offshore Services and Maritech segments, and these operations are reflected as discontinued operations in our consolidated financial statements. See Note 11 - "Discontinued Operations" for further discussion.
NOTE 11 - DISCONTINUED OPERATIONS
As discussed in Note 10 - "Acquisitions and Dispositions," on March 1, 2018, we closed a series of related transactions that resulted in the disposition of our Offshore Division. As a result, we have accounted for our Offshore Division, consisting of our Offshore Services and Maritech segments, as discontinued operations and have revised prior period financial statements to exclude these businesses from continuing operations. During the third quarter of 2019, as a result of the bankruptcy filing of Epic Companies, LLC, we recorded a reserve for the full amount of certain other receivables of discontinued operations in the amount of $1.5 million and for the full amount of a $7.5 million promissory note, including accrued interest, that we received as part of the consideration for the sale. See Note 12 - "Commitments and Contingencies" for further discussion. A summary of financial information related to our discontinued operations is as follows:
Reconciliation of the Line Items Constituting Pretax Loss from Discontinued Operations to the After-Tax Loss from Discontinued Operations
(in thousands)
Reconciliation of Major Classes of Assets and Liabilities of the Discontinued Operations to Amounts Presented Separately in the Statement of Financial Position
(in thousands)
NOTE 12 - COMMITMENTS AND CONTINGENCIES
Litigation
We are named defendants in several 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 impact on our financial condition, results of operations, or liquidity.
On March 18, 2011, we filed a lawsuit in the Circuit Court of Union County, Arkansas, asserting claims of professional negligence, breach of contract and other claims against the engineering firm we hired for engineering design, equipment, procurement, advisory, testing and startup services for our El Dorado, Arkansas chemical production facility. The engineering firm disputed our claims and promptly filed a motion to compel the matter to arbitration. After a lengthy procedural dispute in Arkansas state court, arbitration proceedings were initiated on November 15, 2013. Ultimately, on December 16, 2016, the arbitration panel ruled in our favor, declared us as the prevailing party, and awarded us a total net amount of $12.8 million. We received full payment of the $12.8 million final award on January 5, 2017, and this amount was credited to earnings during the first quarter of 2017.
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, 2019, 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 $95.0 million, including $9.5 million during 2020, $9.5 million during 2021, $9.5 million during 2022, $9.5 million during 2023, $9.5 million during 2024, and $47.3 million thereafter, extending through 2029. Amounts purchased under these agreements for each of the years ended December 31, 2019, 2018, and 2017, was $18.7 million, $18.0 million, and $16.1 million, respectively.
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 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 US 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”) payable to us in full, together with interest at a rate of 1.52% per annum, on December 31, 2019, along with a personal guaranty agreement from Thomas M. Clarke and Ana M. Clarke guaranteeing the payment obligations of Epic Companies pursuant to the Epic Promissory Note (the “Clarke Promissory Note Guaranty Agreement”). Additionally, pursuant to the Equity Interest Purchase Agreement (the “Offshore Services Purchase Agreement”) and other agreements with Epic Companies, certain other amounts relating to the Offshore Division totaling approximately $1.5 million were payable to us. At the end of August 2019, Epic Companies filed for bankruptcy. We recorded a reserve of $7.5 million for the full amount of the promissory note, including accrued interest, and the 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. Upon the default by Epic and the Clarkes, we filed a lawsuit against the Clarkes on January 15, 2020 in Montgomery County, Texas for breach of the Clarke Promissory Note Guaranty Agreement, seeking the amounts due under the Epic Promissory Note and related interest, as well as attorneys’ fees and expenses. The Clarkes each filed an answer and counterclaims for fraud and negligent misrepresentation and seek monetary damages in excess of $1 million, punitive damages, and attorneys’ fees. We will vigorously prosecute our claim and defend against the claims by the Clarkes.
NOTE 13 - CAPITAL STOCK AND WARRANTS
Our Restated Certificate of Incorporation, as amended during 2017, authorizes us to issue 250,000,000 shares of common stock, par value $.01 per share, and 5,000,000 shares of preferred stock, par value $.01 per share. As of December 31, 2019, we had 125,481,163 shares of common stock outstanding, with 2,823,191 shares held in treasury, and no shares of preferred stock outstanding. The voting, dividend, and liquidation rights of the holders of common stock are subject to the rights of the holders of preferred stock. The holders of common stock are entitled to one vote for each share held. There is no cumulative voting. Dividends may be declared and paid on
common stock as determined by our Board of Directors, subject to any preferential dividend rights of any then outstanding preferred stock.
Issuances of Common Stock. On February 28, 2018, we issued 7,772,021 shares of our common stock as part of the consideration paid for the acquisition of SwiftWater. For further discussion of the SwiftWater acquisition, see Note 10 - "Acquisitions and Dispositions."
On December 14, 2016, we completed a firm commitment underwritten offering of 22.3 million shares of our common stock at a price to the public of $5.15 per share ($4.9183 per share net of underwriting discounts) and the Warrants to purchase 11.2 million shares of our common stock at an exercise price of $5.75 per share prior to the 60-month expiration date of the Warrants. The 22.3 million shares of our common stock issued and the Warrants to purchase 11.2 million shares of our common stock includes 2.9 million shares of our common stock and Warrants to acquire an additional 1.5 million shares of our common stock related to the exercise of an option granted to the underwriters. We utilized the net offering proceeds of $109.7 million to repay outstanding indebtedness and other offering expenses. As of December 31, 2019, all of the Warrants remain outstanding.
The Warrants were issued pursuant to a Warrant Agreement, dated December 14, 2016, and are exercisable immediately upon issuance and from time to time thereafter through and including the fifth year anniversary of the initial issuance date. At the request of a holder following a change of control, we or the successor entity will exchange such Warrant for consideration in accordance with a Black Scholes option pricing model in the form of, at our election, Rights (as defined in the Warrant Agreement) or cash. Similarly, within a period of time prior to the consummation of a change of control, we have the right to redeem all of the Warrants for cash in an amount determined in accordance with a Black-Scholes option pricing model.
The Warrants are accounted for as a derivative liability in accordance with ASC 815 "Derivatives and Hedging" and accordingly are carried at their fair value, with changes in fair value included in earnings in the period of change.
A summary of the activity of our common shares outstanding and treasury shares held for the three year period ending December 31, 2019, is as follows:
(1)
Prior to 2019, we primarily granted restricted stock awards, which immediately impact common shares outstanding. In contrast, during 2019, we primarily granted restricted stock units that will not impact common shares outstanding until vesting, which will begin in 2020.
Our Board of Directors is empowered, without approval of the stockholders, to cause shares of preferred stock to be issued in one or more series and to establish the number of shares to be included in each such series and the rights, powers, preferences, and limitations of each series. Because the Board of Directors has the power to establish the preferences and rights of each series, it may afford the holders of any series of preferred stock preferences, powers and rights, voting or otherwise, senior to the rights of holders of common stock. The issuance of the preferred stock could have the effect of delaying or preventing a change in control of the Company.
Upon our dissolution or liquidation, whether voluntary or involuntary, holders of our common stock will be entitled to receive all of our assets available for distribution to our stockholders, subject to any preferential rights of any then outstanding preferred stock.
In January 2004, our Board of Directors authorized the repurchase of up to $20.0 million of our common stock. During the three years ending December 31, 2019, we made no purchases of our common stock pursuant to this authorization.
NOTE 14 - EQUITY-BASED COMPENSATION AND OTHER
Equity-Based Compensation
We have various equity incentive compensation plans that provide for the granting of restricted common stock, options for the purchase of our common stock, and other performance-based, equity-based compensation awards to our executive officers, key employees, nonexecutive officers, and directors. Stock options are exercisable for periods of up to ten years. Compensation cost for all share-based payments is based on the grant date fair value and is recognized in earnings over the requisite service period. Total equity-based compensation expense, before tax, for the three years ended December 31, 2019, 2018, and 2017, was $7.4 million, $7.4 million, and $7.8 million, respectively, and is included in general and administrative expense. Total equity-based compensation expense, net of taxes, for the three years ended December 31, 2019, 2018, and 2017, was $5.8 million, $5.8 million, and $5.0 million, respectively.
Stock Incentive Plans
In May 2007, our stockholders approved the adoption of the TETRA Technologies, Inc. 2007 Equity Incentive Compensation Plan. In May 2008, our stockholders approved the adoption of the TETRA Technologies, Inc. Amended and Restated 2007 Equity Incentive Compensation Plan, which among other changes, resulted in an increase in the maximum number of shares authorized for issuance. In May 2010, our stockholders approved further amendments to the TETRA Technologies, Inc. Amended and Restated 2007 Equity Incentive Compensation Plan (renamed as the 2007 Long Term Incentive Compensation Plan) which, among other changes, resulted in an additional increase in the maximum number of shares authorized for issuance. Pursuant to the 2007 Long Term Incentive Compensation Plan, we are authorized to grant up to 5,590,000 shares in the form of stock options (including incentive stock options and nonqualified stock options); restricted stock; bonus stock; stock appreciation rights; and performance awards to employees, and non-employee directors. As of February 2017, no further awards may be granted under the TETRA Technologies, Inc. Amended and Restated 2007 Equity Incentive Compensation Plan.
In May 2011, our stockholders approved the adoption of the TETRA Technologies, Inc. 2011 Long Term Incentive Compensation Plan. Pursuant to this plan, we were authorized to grant up to 2,200,000 shares in the form of stock options, restricted stock, bonus stock, stock appreciation rights, and performance awards to employees, and non-employee directors. On May 3, 2013, shareholders approved the TETRA Technologies, Inc. 2011 Long Term Incentive Compensation Plan that, among other things, increased the number of authorized shares to 5,600,000. On May 3, 2016, shareholders approved the TETRA Technologies, Inc. Third Amended and Restated 2011 Long Term Incentive Compensation Plan which, among other things, increased the number of authorized shares to 11,000,000. As of May 2018, no further awards may be granted under the TETRA Technologies, Inc. Third Amended and Restated 2011 Long Term Incentive Compensation Plan.
In June 2011, the Compressco Partners, L.P. 2011 Long Term Incentive Plan ("CCLP Long Term Incentive Plan") was adopted by the board of directors of CCLP’s general partner. The CCLP Long Term Incentive Plan provides for grants of restricted units, phantom units, unit awards and other unit-based awards up to a plan maximum of 1,537,122 common units. On November 28, 2018, unitholders approved the CSI Compressco LP Second Amended and Restated 2011 Long Term Incentive Plan that, among other things, increased the number of authorized units to 5,037,122.
In February 2018, the board of directors adopted the 2018 Inducement Restricted Stock Plan (“2018 Inducement Plan”). The 2018 Inducement Plan provides for grants of restricted stock up to a plan maximum of 1,000,000 shares.
In May 2018, our stockholders approved the adoption of the TETRA Technologies, Inc. 2018 Equity Incentive Plan (“2018 Equity Plan”). Pursuant to this plan, we were authorized to grant up to 6,635,000 shares in the form of stock options, restricted stock, restricted stock units, bonus stock, stock appreciation rights, performance units, performance awards, other stock-based awards and cash-based awards to employees and non-employee directors.
In May 2018, our stockholders approved the adoption of the TETRA Technologies, Inc. 2018 Non-Employee Director Equity Incentive Plan (“2018 Director Plan”). Pursuant to this plan, we were authorized to grant up to 335,000 shares in the form of nonqualified stock options, stock appreciation rights, restricted stock, restricted stock units, other stock-based awards and cash-based awards to non-employee directors.
Grants of Equity Awards by CCLP
During the three years ended December 31, 2019, CCLP granted phantom unit and performance phantom unit awards to certain employees, officers, and directors of its general partner. Awards of restricted units and phantom units generally vest over a three year period. Awards of performance phantom units cliff vest at the end of a performance period and are settled based on achievement of related performance measures over the performance period. Phantom units are notional units that entitle the grantee to receive a common unit upon the vesting of the award. Each of the phantom unit and performance phantom unit awards includes distribution equivalent rights that enable the recipient to receive additional common units equal in value to the accumulated cash distributions made on the common units subject to the award from the date of grant. Such additional common units are issued upon settlement of the related phantom unit or performance phantom unit award (and are forfeited if the related award is forfeited).
The following is a summary of CCLP’s equity award activity for the year ended December 31, 2019:
(1)
The number excludes 290,528 performance-based phantom units, which represents the additional number of common units that would be issued if the maximum level of performance under the awards is achieved.
(2) The number of units granted shown above excludes 44,314 performance-based phantom units, which, when combined with the 172,237 granted (net of 2019 forfeitures), represents the maximum number of common units that would be issued if the maximum level of performance under the awards is achieved. The number of units actually issued under the awards may range from zero to 433,102.
Stock Options
The weighted average fair value of options granted during the years ended December 31, 2019, 2018, and 2017, was $0.76, $1.88, and $2.01, respectively, using the Black-Scholes option valuation model with the following weighted average assumptions:
The risk-free interest rate is based on the U.S. Treasury yield curve in effect on the grant date for a period commensurate with the estimated expected life of the stock options. Expected volatility is based on the historical volatility of our stock over the period commensurate with the expected life of the stock options and other factors.
The dividend yield is based on the current annualized dividend rate in effect during the quarter in which the grant was made. At the time of the stock option grants during each of the years ended December 31, 2019, 2018 and 2017, we had not historically paid any dividends and did not expect to pay any dividends during the expected life of the stock options.
The following is a summary of stock option activity for the year ended December 31, 2019:
Intrinsic value is the difference between the market value of our stock option multiplied by the number of stock options outstanding for those stock options where the market value exceeds their exercise price. The total intrinsic value of stock options exercised during December 31, 2019, 2018, and 2017, was approximately $0.0 million, $0.1 million, and $0.0 million, respectively.
At December 31, 2019, total unrecognized compensation cost related to unvested stock options of
$1.1 million is expected to be recognized over a weighted-average remaining service period of 1.0 year.
Restricted Stock
Restricted stock awards and restricted stock units are periodically granted to key employees, including grants for employment inducements, as well as to members of our Board of Directors. These awards historically have provided for vesting periods of three years. Non-employee director grants vest in full before the first anniversary of the grant. Upon vesting of restricted stock awards, shares are issued to award recipients. Restricted stock units may be settled in cash or shares at vest, as determined by the Compensation Committee or the Non-Executive Award Committee, as applicable. The following is a summary of activity for our outstanding restricted stock for the year ended December 31, 2019:
Total compensation cost recognized for restricted stock was $4.8 million, $4.9 million, and $4.0 million for the years ended December 31, 2019, 2018, and 2017, respectively. Total unrecognized compensation cost at December 31, 2019, related to restricted stock is approximately $6.3 million which is expected to be recognized over a weighted-average remaining amortization period of 1.74 years. During the years ended December 31, 2019, 2018, and 2017, the total fair value of shares vested was $4.0 million, $3.2 million and $4.8 million, respectively.
During 2019, 2018, and 2017, we received 105,622, 79,476 and 101,669 shares, respectively, of our common stock related to the vesting of certain employee restricted stock. Such surrendered shares received by us are included in treasury stock. At December 31, 2019, net of options previously exercised pursuant to our various equity compensation plans, we have a maximum of 4,326,637 shares of common stock issuable pursuant to awards previously granted and outstanding and awards authorized to be granted in the future.
401(k) Plan
We have a 401(k) retirement plan (the "Plan") that covers substantially all employees and entitles them to contribute up to 70% of their annual compensation, subject to maximum limitations imposed by the Internal Revenue Code. Effective October 1, 2018, enhancements were made to the Plan, including changing the employer match to 50% of each employee's contribution up to 8%. Additionally, participants will be 100% vested in employer match contributions after 3 years of service, instead of after 5 years of service. In addition, we can make discretionary contributions which are allocable to participants in accordance with the Plan. Total expense related to our 401(k) plan was $5.1 million, $3.8 million, and $0.9 million in 2019, 2018, and 2017, respectively.
Deferred Compensation Plan
We provide our officers, directors, and certain key employees with the opportunity to participate in an unfunded, deferred compensation program. There were nineteen participants in the program at December 31, 2019. Under the program, participants may defer up to 100% of their yearly total cash compensation. The amounts deferred remain our sole property, and we use a portion of the proceeds to purchase life insurance policies on the lives of certain of the participants. The insurance policies, which also remain our sole property, are payable to us upon the death of the insured. We separately contract with the participant to pay to the participant the amount of deferred compensation, as adjusted for gains or losses, invested in participant-selected investment funds. Participants may elect to receive deferrals and earnings at termination, death, or at a specified future date while still employed. Distributions while employed must be at least three years after the deferral election. The program is not qualified under Section 401 of the Internal Revenue Code. At December 31, 2019, the amounts payable under the plan approximated the value of the corresponding assets we owned.
NOTE 15 - FAIR VALUE MEASUREMENTS
Fair value is defined as “the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date” within an entity’s principal market, if any. The principal market is the market in which the reporting entity would sell the asset or transfer the liability with the greatest volume and level of activity, regardless of whether it is the market in which the entity will ultimately transact for a particular asset or liability or if a different market is potentially more advantageous. Accordingly, this exit price concept may result in a fair value that may differ from the transaction price or market price of the asset or liability.
Under U.S. GAAP, the fair value hierarchy prioritizes inputs to valuation techniques used to measure fair value. Fair value measurements should maximize the use of observable inputs and minimize the use of unobservable inputs, where possible. Observable inputs are developed based on market data obtained from sources independent of the reporting entity. Unobservable inputs may be needed to measure fair value in situations where there is little or no market activity for the asset or liability at the measurement date and are developed based on the best information available in the circumstances, which could include the reporting entity’s own judgments about the assumptions market participants would utilize in pricing the asset or liability.
Financial Instruments
CCLP Preferred Units
The CCLP Preferred Units were valued using a lattice modeling technique that, among a number of lattice structures, included significant unobservable items (a Level 3 fair value measurement). These unobservable items included (i) the volatility of the trading price of CCLP's common units compared to a volatility analysis of equity prices of CCLP's comparable peer companies, (ii) a yield analysis that utilized market information related to the debt yields of comparable peer companies, and (iii) a future conversion price analysis. The fair valuation of the CCLP Preferred Units liability increased by, among other factors, projected increases in CCLP's common unit price and by increases in the volatility and decreases in the debt yields of CCLP's comparable peer companies. Increases (or decreases) in the fair value of CCLP Preferred Units increased (decreased) the associated liability
and resulted in future adjustments to earnings for the associated valuation losses (gains). The last redemption of all remaining Preferred Units occurred on August 8, 2019.
Warrants
The Warrants are valued by using a Black Scholes option valuation model that includes implied volatility of the trading price (a Level 3 fair value measurement). The fair value of the Warrants liability is increased by, among other factors, increases in our common stock price, and by increases in the volatility of our common stock price. Increases (or decreases) in the fair value of the Warrants will increase (decrease) the associated liability and result in future adjustments to earnings for the associated valuation losses (gains).
Contingent Consideration
The February 2018 acquisition of SwiftWater resulted in a contingent purchase price consideration that was payable in two tranches based on 2018 and 2019 results. During the year ended 2019, the sellers received a payment of $10.0 million based on 2018 performance. Changes to the estimated contingent purchase price consideration for performance during 2019 resulted in $1.0 million being credited to other (income) expense, net, during the year ended December 31, 2019. Also during the year ended December 31, 2019, in accordance with the December 2018 purchase of JRGO, the sellers were paid contingent consideration of $1.4 million based on performance during the fourth quarter of 2018. As of December 31, 2019, there are no remaining contingent purchase price consideration liabilities for either acquisition.
Derivative Contracts
We are exposed to financial and market risks that affect our businesses. We have concentrations of credit risk as a result of trade receivables owed to us by companies in the energy industry. We have currency exchange rate risk exposure related to transactions denominated in foreign currencies as well as to investments in certain of our international operations. As a result of our variable rate debt facilities, we face market risk exposure related to changes in applicable interest rates. Our financial risk management activities may at times involve, among other measures, the use of derivative financial instruments, such as swap and collar agreements, to hedge the impact of market price risk exposures.
We and CCLP each enter into short term foreign currency forward derivative contracts with third parties as part of a program designed to mitigate the currency exchange rate risk exposure on selected transactions of certain foreign subsidiaries. As of December 31, 2019, we and CCLP had the following foreign currency derivative contracts outstanding relating to portions of our foreign operations:
As of December 31, 2018, we and CCLP had the following foreign currency derivative contracts outstanding relating to a portion of our foreign operations:
Under this program, we and CCLP may enter into similar derivative contracts from time to time. Although contracts pursuant to this program will serve as an economic hedge of the cash flow of our currency exchange risk exposure, they are not formally designated as hedge contracts or qualify for hedge accounting treatment. Accordingly, any change in the fair value of these derivative instruments during a period will be included in the determination of earnings for that period.
The fair values of foreign currency derivative instruments are based on quoted market values (a Level 2 fair value measurement). The fair values of our and CCLP's foreign currency derivative instruments as of December 31, 2019 and 2018, are as follows:
None of the foreign currency derivative contracts contain credit risk related contingent features that would require us to post assets or collateral for contracts that are classified as liabilities. During the year ended December 31, 2019, 2018, and 2017, we recognized approximately $2.3 million, $(0.4) million and $(1.3) million of net (gains) losses, respectively, reflected in other (income) expense, net, associated with our foreign currency derivative program.
A summary of these recurring fair value measurements by valuation hierarchy as of December 31, 2019 and December 31, 2018, is as follows:
During 2019, our Completion Fluids & Products, Water & Flowback Services and Compression Divisions each recorded certain long-lived tangible asset impairments. The Completion Fluids & Products Division recorded an impairment of $91.6 million related to our El Dorado, Arkansas calcium chloride production plant facility assets primarily due to a reduction in the cost of raw materials for certain of our other chemical production plants, following the execution of a long-term raw material supply agreement during the fourth quarter of 2019. Also in 2019, our Water & Flowback Services Division recorded goodwill impairment of $25.8 million. During 2018, our Water & Flowback Services Division recorded certain long-lived asset impairments, primarily related to an identified intangible asset. The fair values used in these impairment calculations were estimated based on discounted estimated future cash flows or a fair value in-exchange assumption, which are based on significant unobservable inputs (Level 3) in accordance with the fair value hierarchy. For further discussion, see Note 5 - Impairments and Other Charges. A summary of these nonrecurring fair value measurements during the year ended December 31, 2019, using the fair value hierarchy, is as follows:
A summary of these nonrecurring fair value measurements during the year ended December 31, 2018, using the fair value hierarchy, is as follows:
The fair values of cash, restricted cash, accounts receivable, accounts payable, accrued liabilities, short-term borrowings and long-term debt pursuant to TETRA's ABL Credit Agreement and Term Credit Agreement, and the CCLP Credit Agreement approximate their carrying amounts. The fair values of the publicly traded CCLP 7.25% Senior Notes (as herein defined) at December 31, 2019 and 2018, were approximately $266.0 million and $266.3 million, respectively. Those fair values compare to the face amount of $295.9 million both at December 31, 2019 and 2018. The fair values of the CCLP 7.50% Senior Secured Notes at December 31, 2019 and 2018, were approximately $344.8 million and $332.5 million, respectively. These fair values compare to aggregate principal amount of such notes at both December 31, 2019 and 2018, of $350.0 million. We based the fair values of the CCLP 7.25% Senior Notes and the CCLP 7.50% Senior Secured Notes as of December 31, 2019 on recent trades for these notes. See Note 9 - "Long-Term Debt and Other Borrowings," for a complete discussion of our debt.
NOTE 16 - INCOME TAXES
The income tax provision attributable to continuing operations for the years ended December 31, 2019, 2018, and 2017, consists of the following:
A reconciliation of the provision (benefit) for income taxes attributable to continuing operations, computed by applying the federal statutory rate to income (loss) before income taxes and the reported income taxes, is as follows:
Income (loss) before taxes and discontinued operations includes the following components:
A reconciliation of the beginning and ending amount of our gross unrecognized tax benefit is as follows:
We recognize interest and penalties related to uncertain tax positions in income tax expense. During the years ended December 31, 2019, 2018, and 2017, we recognized $(0.3) million, $(0.2) million, and $(0.3) million, respectively, of interest and penalties. As of December 31, 2019 and 2018, we had $0.2 million and $0.5 million, respectively, of accrued potential interest and penalties associated with uncertain tax positions. The total amount of unrecognized tax benefits that would affect our effective tax rate if recognized is $0.4 million and $0.8 million as of December 31, 2019 and 2018, respectively. We do not expect a significant change to the unrecognized tax benefits during the next twelve months.
We file tax returns in the U.S. and in various state, local, and non-U.S. jurisdictions. The following table summarizes the earliest tax years that remain subject to examination by taxing authorities in any major jurisdiction in which we operate:
We use the liability method for reporting income taxes, under which current and deferred tax assets and liabilities are recorded in accordance with enacted tax laws and rates. Under this method, at the end of each period, the amounts of deferred tax assets and liabilities are determined using the tax rate expected to be in effect when the taxes are actually paid or recovered. 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. We considered all available evidence, both positive and negative, in determining whether, based on the weight of that evidence, a valuation allowance is needed for some portion or all of our deferred tax assets. In determining the need for a valuation allowance on our deferred tax assets we placed greater weight on recent and objectively verifiable current information, as compared to more forward-looking information that is used in valuating other assets on the balance sheet. While we have considered taxable income in prior carryback years, future reversals of existing taxable temporary differences, future taxable income, and tax planning strategies in assessing the need for the valuation allowance, there can be no guarantee that we will be able to realize our net deferred tax assets. Significant components of our deferred tax assets and liabilities as of December 31, 2019 and 2018 are as follows:
We believe that it is more likely than not we will not realize all the tax benefits of the deferred tax assets within the allowable carryforward period. Therefore, an appropriate valuation allowance has been provided. The valuation allowance as of December 31, 2019 and 2018 primarily relates to federal deferred tax assets. The increase (decrease) in the valuation allowance during the years ended December 31, 2019, 2018, and 2017, were $32.9 million, $(1.4) million, and $(54.8) million, respectively. The increase in the valuation allowance during 2019 primarily relates to the change of the deferred taxes associated with the impairments of our El Dorado, Arkansas calcium chloride production plant facility assets and goodwill.
At December 31, 2019, we had federal, state, and foreign net operating loss carryforwards/carrybacks equal to approximately $93.3 million, $12.3 million, and $16.4 million, respectively. In those countries and states in which net operating losses are subject to an expiration period, our loss carryforwards, if not utilized, will expire at various dates from 2020 through 2039. Utilization of the net operating loss and credit carryforwards may be subject to a significant annual limitation due to ownership changes that have occurred previously or could occur in the future provided by Section 382 of the Internal Revenue Code.
NOTE 17 - NET INCOME (LOSS) PER SHARE
The following is a reconciliation of the weighted average number of common shares outstanding with the number of shares used in the computations of net income (loss) per common and common equivalent share:
For the years ended December 31, 2019, 2018, and 2017, the average diluted shares outstanding excludes the impact of all outstanding equity awards and warrants, as the inclusion of these shares would have been anti-dilutive due to the net losses recorded during the year. In addition, for the years ended December 31, 2019, 2018, and 2017, the calculation of diluted earnings per common share excludes the impact of the CCLP Preferred Units, as the inclusion of the impact from conversion of the CCLP Preferred Units (as defined in Note 2) into CCLP common units would have been anti-dilutive.
NOTE 18 - INDUSTRY SEGMENTS AND GEOGRAPHIC INFORMATION
We manage our operations through three divisions: Completion Fluids & Products, Water & Flowback Services, and Compression.
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, Africa, Europe, the Middle East, and Australia.
Our Compression Division is a provider of compression services and equipment for natural gas and oil production, gathering, artificial lift, transmission, processing, and storage. The Compression Division's equipment sales business includes the fabrication and sale of standard and custom-designed, engineered compressor packages fabricated primarily at our facility in Midland, Texas. The Compression Division's aftermarket business provides a wide range of services to support the needs of customers who own compression equipment as well as the sale of compressor package parts and components manufactured by third-party suppliers. The Compression Division provides its services and equipment to a broad base of natural gas and oil exploration and production, midstream, transmission, and storage companies operating throughout many of the onshore producing regions of the United States, as well as in a number of other countries, including Mexico, Canada, and Argentina.
We generally evaluate the performance of and allocate resources to our segments based on profit or loss from their operations before income taxes and nonrecurring charges, return on investment, and other criteria. Transfers between segments and geographic areas are priced at the estimated fair value of the products or services as negotiated between the operating units. “Corporate overhead” includes corporate general and administrative expenses, corporate depreciation and amortization, interest income and expense, and other income and expense.
Summarized financial information concerning the business segments is as follows:
(1)
Amounts reflected include the following general corporate expenses:
(2)
Amounts presented net of cost of equipment sold, including $0.0 million during 2019, $0.1 million during 2018 and $4.2 million during 2017 for our Water & Flowback Services Division.
(3)
Amounts presented net of cost of equipment sold, including $6.5 million during 2019, $10.0 million during 2018, and $8.5 million during 2017 for our Compression Division.
Summarized financial information concerning the geographic areas of our customers and in which we operate at December 31, 2019, 2018, and 2017, is presented below:
During each of the three years ended December 31, 2019, 2018, and 2017, no single customer accounted for more than 10% of our consolidated revenues.