☒ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
FOR THE FISCAL YEAR ENDEDDECEMBER 31, 2019
OR
☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE TRANSITION PERIOD FROMTO.
COMMISSION FILE NUMBER 1-13455
TETRA Technologies, Inc.
(Exact name of registrant as specified in its charter)
Delaware
74-2148293
(State or Other Jurisdiction of Incorporation or Organization)
(I.R.S. Employer Identification No.)
24955 Interstate 45 North
The Woodlands,
Texas
77380
(Address of Principal Executive Offices)
(Zip Code)
(281) 367-1983
(Registrant’s Telephone Number, Including Area Code)
Securities registered pursuant to Section 12(b) of the Act:
Title of each class
Trading Symbol(s)
Name of each exchange on which registered
Common Stock
TTI
New York Stock Exchange
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☐No☒
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ☐No☒
Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports); and (2) has been subject to such filing requirements for the past 90 days. Yes☒ No☐
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes☒ No☐
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and "emerging growth company" in Rule 12b-2 of the Exchange Act.
Large accelerated filer
☐
Accelerated filer
☒
Non-accelerated filer
☐
Smaller reporting company
☒
Emerging growth company
☐
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes ☐ No ☒
The aggregate market value of common stock held by non-affiliates of the Registrant was $197,312,802 as of June 28, 2019.
As of March 12, 2020, TETRA Technologies, Inc. had 125,729,106 shares outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
Part III information is incorporated by reference to the registrant’s proxy statement for its annual meeting of stockholders to be held
May 7, 2020, to be filed with the Securities and Exchange Commission within 120 days of the end of the registrant’s fiscal year.
This Annual Report on Form 10-K contains “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. Forward-looking statements in this Annual Report are identifiable by the use of the following words, the negative of such words, and other similar words: “anticipates”, “assumes”, “believes”, “budgets”, “could”, “estimates”, “expects”, “forecasts”, “goal”, “intends”, “may”, “might”, “plans”, “predicts”, “projects”, “schedules”, “seeks”, “should, “targets”, “will”, and “would”.
Such forward-looking statements reflect our current views with respect to future events and financial performance and are based on assumptions that we believe to be reasonable, but such forward-looking statements
are subject to numerous risks, and uncertainties, including, but not limited to:
•
economic and operating conditions that are outside of our control, including the trading price of our common stock, and the supply, demand, and prices of oil and natural gas;
•
the availability of adequate sources of capital to us;
•
the levels of competition we encounter;
•
the activity levels of our customers;
•
our operational performance;
•
the availability of raw materials and labor at reasonable prices;
•
risks related to acquisitions and our growth strategy;
•
restrictions under our debt agreements and the consequences of any failure to comply with debt covenants;
•
the effect and results of litigation, regulatory matters, settlements, audits, assessments, and contingencies;
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risks related to our foreign operations;
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information technology risks including the risk of cyberattack,
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global or national health concerns, including the outbreak of pandemics or epidemics such as the coronavirus (COVID-19), and
•
other risks and uncertainties under “Item 1A. Risk Factors” in this Annual Report and as included in our other filings with the U.S. Securities and Exchange Commission (“SEC”), which are available free of charge on the SEC website at www.sec.gov.
The risks and uncertainties referred to above are generally beyond our ability to control, and we cannot predict all the risks and uncertainties that could cause our actual results to differ from those indicated by the forward-looking statements. If any of these risks or uncertainties materialize, or if any of the underlying assumptions prove incorrect, actual results may vary from those indicated by the forward-looking statements, and such variances may be material.
All subsequent written and oral forward-looking statements made by or attributable to us or to persons acting on our behalf are expressly qualified in their entirety by reference to these risks and uncertainties. You should not place undue reliance on forward-looking statements. Each forward-looking statement speaks only as of the date of the particular statement, and we undertake no obligation to update or revise any forward-looking statements we may make, except as may be required by law.
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PART I
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.
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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.
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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.
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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:
Range of Horsepower Per Package
Number of Packages
Aggregate Horsepower
% of Total Aggregate Horsepower
Low horsepower (0-100)
3,265
153,062
13.0
%
Medium-horsepower (101-1,000)
1,554
436,058
37.0
%
High-horsepower (1,001 and over)
426
588,625
50.0
%
Total
5,245
1,177,745
100.0
%
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.
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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,
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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.
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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
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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
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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. 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
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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
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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 companiesin each of our operating segments, many of whichhave 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 pricesor 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, aredetermined bymarket conditions and the productsand serviceswe sellin 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 andnaturalgas 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 andnaturalgas industry activity and spending levels in this region. Our operations may also be affected by technological advances, cost of capital,andtax policies. Adverse changes in any of these other factors mayhavea material adverse effect on our revenues and profitability.
Changes in theeconomic 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
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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 theeconomic 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 ofcalcium 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 acquiretheseraw materialsat 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 dependenceon 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
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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
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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.
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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 hasincreased 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
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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
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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 foreigncurrency risk.
The operations of certain of our subsidiaries are exposed to fluctuations between the U.S. dollarand 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.
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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 ofcertainoil 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 enactedregarding 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 imposedon oil and gas operatorsthrough the adoption of new laws and regulations,thedomesticdemand for certain of our products and servicescould bedecreased orsubject 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 thefederal governmentmay 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.
Ouronshore and offshore operations exposeus 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 agreementsthat 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 onGHGs 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
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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 rulesregulate GHG emissions under the CAA and requirea reduction in emissions of GHGs from motor vehiclesandfrom 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 EPAalsorequirestheannual reportingof GHG emissions from specified large GHG emission sources in the United States, including petroleum refineries,as well asfromcertain 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 ourproducts 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.
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Our operations in foreign countries exposes us to complex regulations and may present us with new obstacles to growth.
We plan tocontinue togrow both in the United States and in foreign countries. We have established operations inArgentina,Brazil,Finland, Ghana, Mexico,Norway, Saudi Arabia,Sweden, and the United Kingdom, as well as other foreign countries. Foreign operations carry special risks. Our business in the countries in which we currently operate and those in which we may operate in the future could be limited or disrupted by:
•
restrictions on repatriating cash back to the United States;
•
the impact of compliance with anti-corruption laws on our operations and competitive position in affected countries and the risk that actions taken by us or our agents may violate those laws;
•
government controls and government actions, such as expropriation of assets and changes in legal and regulatory environments;
•
import and export license requirements;
•
political, social, or economic instability;
•
trade restrictions;
•
changes in tariffs and taxes;and
•
our limited knowledge of these markets or our inability to protect our interests.
We and our affiliates operate in countries where governmental corruption has been known to exist. While we and our subsidiaries are committed to conducting business in a legal and ethical manner, there is a risk of violating the U.S. Foreign Corrupt Practices Act, the U.K Bribery Act, or laws or legislation promulgated pursuant to the 1997 OECD Convention on Combating Bribery of Foreign Public Officials in International Business Transactions or other applicable anti-corruption regulations that generally prohibit the making of improper payments to foreign officials for the purpose of obtaining or keeping business. Violation of these laws could result in monetary penalties against us or our subsidiaries and could damage our reputation and our ability to do business.
Foreign governments and agencies often establish permit and regulatory standards different from those in the U.S. If we cannot obtain foreign regulatory approvals, or if we cannot obtain them in a timely manner, our growth and profitability from foreign operations could be adversely affected.
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.
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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.
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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. Unresolved Staff Comments.
None.
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 leasedor 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 of29 square miles of leasedmineralacreage andsolar 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 facilityis located just outside the city of El Dorado, Arkansas,on property thatis 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 thepropertyat 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 multipleservice center facilitiesin 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.
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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 Divisionconducts its operations through production testing service centers (most of which are leased) in the U.S., located inArkansas, 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
TheCompression Division’sfacilities 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, ina153,000 square foot office building, which is located on 2.6 acres of land, under a lease that expires in 2027.In addition, weown 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. 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.Mine Safety Disclosures.
None.
PART II
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 ofMarch 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
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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 2006through 2019pursuant 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. 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. Management’s Discussion and Analysis of Financial Condition and Results of Operation” appearing elsewhere in this report. Please read “Item 1A. Risk Factors” for a discussion of the material uncertainties that might cause the selected consolidated financial data not to be indicative of our future financial condition or results of operations. During February 2018, our Water & Flowback Services Division acquired SwiftWater Energy Services, LLC ("SwiftWater"). In March 2018, we closed a series of related transactions that resulted in the disposition of what we previously defined as our Offshore Division, consisting of our Offshore Services segment and Maritech segment. Accordingly, we have reflected the operations of our former Offshore Division as discontinued operations. During 2019, 2016, and 2015, we recorded significant impairments of long-lived assets and goodwill. These acquisitions, dispositions, and impairments significantly impact the comparison of our financial statements.
Year Ended December 31,
2019
2018
2017
2016
2015
(In Thousands, Except Per Share Amounts)
Consolidated Income Statement Data
Revenues
$
1,037,933
$
998,775
$
723,098
$
617,391
$
1,010,641
Gross profit
91,799
162,298
108,390
60,839
181,157
General and administrative expense
139,747
132,446
115,414
108,422
145,843
Goodwill impairment
25,784
—
—
106,205
177,006
Interest expense
73,886
72,066
58,027
59,984
55,134
Interest income
(656
)
(1,120
)
(781
)
(1,370
)
(688
)
Other (income) expense, net
(2,839
)
(4,668
)
(20,227
)
10,818
1,596
Loss before taxes and discontinued operations
(144,123
)
(36,426
)
(44,043
)
(223,220
)
(197,734
)
Loss from discontinued operations, net of taxes
(10,213
)
(41,515
)
(17,389
)
(14,017
)
(5,334
)
Net loss
(160,500
)
(84,240
)
(62,183
)
(239,393
)
(209,467
)
Net loss attributable to TETRA stockholders
$
(147,413
)
$
(61,617
)
$
(39,048
)
$
(161,462
)
$
(126,183
)
Loss per share, before discontinued operations attributable to TETRA stockholders
$
(1.09
)
$
(0.16
)
$
(0.19
)
$
(1.69
)
$
(1.53
)
Average shares
125,600
124,101
114,499
87,286
79,169
Loss per diluted share, before discontinued operations attributable to TETRA stockholders
$
(1.09
)
$
(0.16
)
$
(0.19
)
$
(1.69
)
$
(1.53
)
Average diluted shares
125,600
(1), (2)
124,101
(1), (2)
114,499
(1), (2)
87,286
(1), (2)
79,169
(1)
(1)
Forthe years ended December 31, 2019, 2018, 2017, 2016, and 2015, the calculation of average diluted shares outstanding excludes the impact of all outstanding stock awards, as the inclusion of these shares would have been antidilutive due to the net loss recorded during the year.
(2)
Forthe years ended December 31, 2019, 2018, 2017, and 2016, the calculation of average diluted shares outstanding excludes the impact of warrants, as the inclusion of these shares would have been antidilutive due to the net loss recorded during the year.
24
December 31,
2019
2018
2017
2016
2015
(In Thousands)
Consolidated Balance Sheet Data
Working capital
$
162,631
$
200,340
$
164,640
$
158,906
$
168,783
Total assets
1,271,922
1,385,527
1,308,614
1,315,540
1,636,202
Long-term debt, net
842,871
815,560
629,855
623,730
853,228
CCLP Series A Preferred Units
—
27,019
61,436
77,062
—
Warrants liability
449
2,073
13,202
18,503
—
Total equity
162,826
312,749
352,561
400,466
514,180
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
25
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 andnaturalgas exploration and production industry, particularly including the level of expenditures for the exploration and production of oil andnaturalgas, and for additional natural gas compression infrastructure. The future growth of certain of our businessesis dependenton 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:
•
increases in technologically-driven deepwater oil and gas well completions in the Gulf of Mexico;
•
applications for many of our products and services in thecontinuingexploitation and development of shale reservoirs; and
•
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 trackiton a monthly basis, both in dollars and as a percentage of revenues(typically compared to the prior month,prior year
26
period,and to budget). We define Adjusted EBITDA as earnings before interest, taxes, depreciation, amortization, impairments and certain non-cash charges and non-recurring adjustments.
Adjusted EBITDA is used as a supplemental financial measure by our management to:
•
evaluate the financial performance of our assets without regard to financing methods, capital structure, or historical cost basis; and
•
determine our ability to incur and service debt and fund capital expenditures.
The following tablereconciles net income (loss) to Adjusted EBITDA for the periods indicated:
Twelve Months Ended
December 31, 2019
Net Income (Loss), as reported
Tax Provision
Income (Loss) Before Tax, as Reported
Impairments & Special Charges
Adjusted Income (Loss) Before Tax
Adjusted Interest Expense, Net
Depreciation & Amortization
Equity Comp. Expense
Adjusted EBITDA
(In Thousands)
Completion Fluids & Products Division
$
(33,969
)
$
91,140
$
57,171
$
(720
)
$
13,518
$
—
$
69,969
Water & Flowback Services Division
(21,173
)
25,619
4,446
(1
)
33,424
—
37,869
Compression Division
(16,014
)
8,814
(7,200
)
51,974
76,663
1,064
122,501
Eliminations and other
14
—
14
—
(14
)
—
—
Subtotal
(71,142
)
125,573
54,431
51,253
123,591
1,064
230,339
Corporate and other
(72,981
)
111
(72,870
)
21,977
635
7,063
(43,195
)
TETRA excluding Discontinued Operations
$
(150,287
)
$
6,164
$
(144,123
)
$
125,684
$
(18,439
)
$
73,230
$
124,226
$
8,127
$
187,144
Twelve Months Ended
December 31, 2018
Net Income (Loss), as reported
Tax Provision
Income (Loss) Before Tax, as Reported
Impairments & Special Charges
Adjusted Income (Loss) Before Tax
Adjusted Interest Expense, Net
Depreciation & Amortization
Equity Comp. Expense
Adjusted EBITDA
(In Thousands)
Completion Fluids & Products Division
$
30,623
$
70
$
30,693
$
(599
)
$
15,345
$
—
$
45,439
Water & Flowback Services Division
28,712
6,373
35,085
—
28,439
—
63,524
Compression Division
(33,797
)
5,788
(28,009
)
51,905
70,500
639
95,035
Eliminations and other
11
—
11
—
(17
)
—
(6
)
Subtotal
25,549
12,231
37,780
51,306
114,267
639
203,992
Corporate and other
(61,975
)
(8,137
)
(70,112
)
19,640
658
6,740
(43,074
)
TETRA excluding Discontinued Operations
$
(42,725
)
$
6,299
$
(36,426
)
$
4,094
$
(32,332
)
$
70,946
$
114,925
$
7,379
$
160,918
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 aswe 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.
27
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.
28
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.
2019Compared to 2018
Consolidated Comparisons
Year Ended
December 31,
Period to Period Change
2019
2018
2019 vs. 2018
% Change
(In Thousands, Except Percentages)
Revenues
$
1,037,933
$
998,775
$
39,158
3.9
%
Gross profit
91,799
162,298
(70,499
)
(43.4
)%
Gross profit as a percentage of revenue
8.8
%
16.2
%
General and administrative expense
139,747
132,446
7,301
5.5
%
General and administrative expense as a percentage of revenue
13.5
%
13.3
%
Goodwill impairment
25,784
—
25,784
100.0
%
Interest expense, net
73,230
70,946
2,284
3.2
%
Gain on sale of assets
(2,333
)
(729
)
(1,604
)
220.0
%
Warrants fair value adjustment
(1,624
)
(11,129
)
9,505
(85.4
)%
CCLP Series A Preferred fair value adjustment
1,309
(733
)
2,042
(278.6
)%
Other (income) expense, net
(191
)
7,923
(8,114
)
(102.4
)%
Loss before taxes and discontinued operations
(144,123
)
(36,426
)
(107,697
)
295.7
%
Loss before taxes and discontinued operations as a percentage of revenue
(13.9
)%
(3.6
)%
Provision for income taxes
6,164
6,299
(135
)
(2.1
)%
Loss before discontinued operations
(150,287
)
(42,725
)
(107,562
)
251.8
%
Loss from discontinued operations (including 2018 loss on disposal of $33.8 million), net of taxes
(10,213
)
(41,515
)
31,302
(75.4
)%
Net loss
(160,500
)
(84,240
)
(76,260
)
90.5
%
Loss attributable to noncontrolling interest
13,087
22,623
(9,536
)
(42.2
)%
Net loss attributable to TETRA stockholders
$
(147,413
)
$
(61,617
)
$
(85,796
)
139.2
%
Consolidated revenuesfor 2019increased 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
29
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.
30
Divisional Comparisons
Completion Fluids & Products Division
Year Ended
December 31,
Period to Period Change
2019
2018
2019 vs. 2018
% Change
(In Thousands, Except Percentages)
Revenues
$
279,255
$
257,408
$
21,847
8.5
%
Gross profit (loss)
(15,034
)
48,675
(63,709
)
(130.9
)%
Gross profit (loss) as a percentage of revenue
(5.4
)%
18.9
%
General and administrative expense
19,990
18,830
1,160
6.2
%
General and administrative expense as a percentage of revenue
7.2
%
7.3
%
Interest (income) expense, net
(720
)
(599
)
(121
)
20.2
%
Other (income) expense, net
(335
)
(179
)
(156
)
87.2
%
Income (loss) before taxes
$
(33,969
)
$
30,623
$
(64,592
)
(210.9
)%
Income (loss) before taxes as a percentage of revenue
(12.2
)%
11.9
%
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 2019decreased 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.
31
Water & Flowback Services Division
Year Ended
December 31,
Period to Period Change
2019
2018
2019 vs. 2018
% Change
(In Thousands, Except Percentages)
Revenues
$
281,986
$
303,072
$
(21,086
)
(7.0
)%
Gross profit
27,458
55,247
(27,789
)
(50.3
)%
Gross profit as a percentage of revenue
9.7
%
18.2
%
General and administrative expense
25,009
23,640
1,369
5.8
%
General and administrative expense as a percentage of revenue
8.9
%
7.8
%
Goodwill impairment
25,784
—
25,784
Interest (income) expense, net
(1
)
—
(1
)
—
%
Other (income) expense, net
(2,161
)
2,895
(5,056
)
(174.6
)%
Income (loss) before taxes
$
(21,173
)
$
28,712
$
(49,885
)
(173.7
)%
Income (loss) before taxes as a percentage of revenue
(7.5
)%
9.5
%
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.
32
Compression Division
Year Ended
December 31,
Period to Period Change
2019
2018
2019 vs. 2018
% Change
(In Thousands, Except Percentages)
Revenues
$
476,692
$
438,673
$
38,019
8.7
%
Gross profit
79,992
59,017
20,975
35.5
%
Gross profit as a percentage of revenue
16.8
%
13.5
%
General and administrative expense
43,281
39,544
3,737
9.5
%
General and administrative expense as a percentage of revenue