Tetra Technologies Earnings 2018-12-31

TTI 10K Annual Report

Balance Sheet	Income Statement	Cash Flow

10-K 1 tti2018123110k.htm 10-K Document

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON D.C. 20549

FORM 10-K

(MARK ONE)

[ X ] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

FOR THE FISCAL YEAR ENDED DECEMBER 31, 2018

[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE TRANSITION PERIOD FROM TO .

COMMISSION FILE NUMBER 1-13455

TETRA Technologies, Inc.

(EXACT NAME OF THE REGISTRANT AS SPECIFIED IN ITS CHARTER)



DELAWARE	74-2148293
(STATE OR OTHER JURISDICTION OF	(I.R.S. EMPLOYER
INCORPORATION OR ORGANIZATION)	IDENTIFICATION NO.)

24955 INTERSTATE 45 NORTH
THE WOODLANDS, TEXAS	77380
(ADDRESS OF PRINCIPAL EXECUTIVE OFFICES)	(ZIP CODE)

REGISTRANT’S TELEPHONE NUMBER, INCLUDING AREA CODE: (281) 367-1983



SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:

COMMON STOCK, PAR VALUE $.01 PER SHARE	NEW YORK STOCK EXCHANGE
(TITLE OF CLASS)	(NAME OF EXCHANGE ON WHICH REGISTERED)

SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT: NONE

INDICATE BY CHECK MARK IF THE REGISTRANT IS A WELL-KNOWN SEASONED ISSUER (AS DEFINED IN RULE 405 OF THE SECURITIES ACT).

YES [ ] NO [ X ]

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 [ X ]

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 [ X ] 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 DURING THE PRECEDING 12 MONTHS (OR FOR SUCH SHORTER PERIOD THAT THE REGISTRANT WAS REQUIRED TO SUBMIT SUCH FILES).

YES [ X ] NO [ ]

INDICATE BY CHECK MARK IF DISCLOSURE OF DELINQUENT FILERS PURSUANT TO ITEM 405 OF REGULATION S-K IS NOT CONTAINED HEREIN, AND WILL NOT BE CONTAINED, TO THE BEST OF REGISTRANT’S KNOWLEDGE, IN DEFINITIVE PROXY OR INFORMATION STATEMENTS INCORPORATED BY REFERENCE IN PART III OF THIS FORM 10-K OR ANY AMENDMENT TO THIS FORM 10-K. [ X]

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. (CHECK ONE):



LARGE ACCELERATED FILER [ ]	ACCELERATED FILER [ X ]	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 EXCHANGE ACT).

YES [ ] NO [ X ]

THE AGGREGATE MARKET VALUE OF COMMON STOCK HELD BY NON-AFFILIATES OF THE REGISTRANT WAS $527,447,571 AS OF JUNE 30, 2018, THE LAST BUSINESS DAY OF THE REGISTRANT’S MOST RECENTLY COMPLETED SECOND FISCAL QUARTER.

NUMBER OF SHARES OUTSTANDING OF THE ISSUER’S COMMON STOCK AS OF MARCH 1, 2019, WAS 125,629,069 SHARES.

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 3, 2019, TO BE FILED WITH THE SECURITIES AND EXCHANGE COMMISSION WITHIN 120 DAYS OF THE END OF THE REGISTRANT’S FISCAL YEAR.

TABLE OF CONTENTS



	Part I
Item 1.	Business	1
Item 1A.	Risk Factors	9
Item 1B.	Unresolved Staff Comments	22
Item 2.	Properties	22
Item 3.	Legal Proceedings	23
Item 4.	Mine Safety Disclosures	23
	Part II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters, and Issuer Purchases of Equity Securities	23
Item 6.	Selected Financial Data	24
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operation	26
Item 7A.	Quantitative and Qualitative Disclosures about Market Risk	53
Item 8.	Financial Statements and Supplementary Data	55
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	55
Item 9A.	Controls and Procedures	55
Item 9B.	Other Information	58
	Part III
Item 10.	Directors, Executive Officers, and Corporate Governance	59
Item 11.	Executive Compensation	59
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	59
Item 13.	Certain Relationships and Related Transactions, and Director Independence	59
Item 14.	Principal Accounting Fees and Services	59
	Part IV
Item 15.	Exhibits, Financial Statement Schedules	60
Item 16.	Form 10-K Summary	65

Forward-Looking Statements

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 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;


•	risks related to our foreign operations;


•	information technology risks including the risk from cyberattack, 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.

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 and offshore rig cooling services, and compression services and equipment. Prior to the March 2018 sale of our Offshore Division, our operations also included certain offshore services including well plugging and abandonment, decommissioning, and diving, as well as a limited domestic oil and gas production business. Following the acquisition and disposition transactions that closed during the three month period ended March 31, 2018, and as of December 31, 2018 we were composed of 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 ("CBFs"), 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, Mexico, and Canada, as well as in oil and gas basins in certain regions in South 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, transportation, processing, and storage. The Compression Division's equipment sales business includes the fabrication and sale of standard compressor packages and custom-designed compressor packages designed and fabricated at the Division's facilities. The Compression Division's aftermarket business provides compressor package reconfiguration and maintenance services and 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 foreign countries, including Mexico, Canada and Argentina.

We continue to pursue a long-term growth strategy that includes expanding our core businesses, through internal growth and acquisitions, domestically and internationally.

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 Completion Fluids & Products 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. The Completion Fluids & Products Division provides a broad range of associated CBF services, including: on-site fluids filtration, handling and recycling; wellbore cleanup; fluid engineering consultation; and fluid management services. The Completion Fluids & Products Division's newest CBF technology, TETRA CS Neptune^® completion fluids, are high-density fluids that are free of solids, zinc and formates. They were developed by TETRA to be environmentally friendly and cost-effective alternatives to traditional zinc bromide and cesium formate high-density completion fluids for use in well completion and workover operations, as well as a low-solids reservoir drilling fluid.

We offer to repurchase (buyback) certain used CBFs from customers, which we are able to recondition and recycle. Selling used CBFs back to us reduces the net cost of the CBFs to our 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 stock CBFs and using various additives, we are able to modify the specific density, crystallization temperature, and chemical composition of the CBFs as necessary. 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. We also acquire calcium chloride inventory from other producers. 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.

Our Completion Fluids & Products Division manufactures liquid calcium bromide, zinc bromide, zinc calcium bromide and sodium bromide at our West Memphis, Arkansas facility. A patented and proprietary process utilized at this facility uses bromine and zinc to manufacture zinc bromide. This facility also uses proprietary processes to manufacture calcium bromide and sodium bromide and to recondition and upgrade used CBFs that we have repurchased from our customers.

Water & Flowback Services Division

Our Water & Flowback Services Division provides a wide variety of water management services that support hydraulic fracturing in unconventional well completions for domestic onshore oil and gas operators. These services include fresh and produced water analysis, treatment, storage, transfer, engineering, recycling, and environmental risk mitigation. The Water & Flowback Services Division's patented equipment and processes include BioRid® treatment services, certain blending technologies, and TETRA Steel 1200 rapid deployment water transfer system. The Water & Flowback Services Division seeks to design environmentally friendly solutions for the unique needs of each customer’s wellsite 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 networks of water transfer lines including poly pipe and TETRA Steel™ lay-flat hose, TETRA Blend™ automated transfer and blending of produced water, and oil recovery from produced water via the TETRA Orapt™ (Oil Recovery After Production Technology) mobile oil separation system to transfer water around well pads in a safe, efficient and environmentally responsible manner.

On February 28, 2018, pursuant to a purchase agreement dated February 13, 2018 (the “SwiftWater Purchase Agreement"), we purchased all of the equity interests in SwiftWater Energy Services, LLC ("SwiftWater"), which provides water management solutions to oil and gas operators in the Permian Basin market. SwiftWater provides a diverse range of water management equipment and services for operators, offering an integrated line of services ranging from lay-flat hose water transfer, water treatment, above-ground water storage for fresh and produced water applications, secondary frac tank containment, poly pipe transfer, pit lining rentals, and supporting ancillary equipment and services. For additional information regarding the acquisition of SwiftWater, see Note E - "Acquisitions and Dispositions" of the Notes to Consolidated Financial Statements.

On December 6, 2018, we purchased all the equity interests in JRGO Energy Services LLC (“JRGO”), which specializes in delivering comprehensive water management services for oil and gas operators, as well as municipal, state and federal organizations in the Appalachian region of the U.S. For additional information regarding the acquisition of JRGO, see Note E - "Acquisitions and Dispositions" of the Notes to Consolidated Financial Statements.

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 gas-producing basins, water, sand and other abrasive materials commonly accompany the initial production of natural gas, 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 utilized 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 Canada, and in certain countries in Latin America, Europe, Africa, and the Middle East. Production Testing operations in Canada are provided through our Greywolf Energy Services subsidiary ("Greywolf").

Through our 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 our 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 our 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, transportation, processing, and storage. The Compression Division fabricates and sells standard and custom-designed 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 packaging 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, Canada and Mexico, as well as certain countries in South America.

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 5,700 compressor packages providing approximately 1.1 million in aggregate horsepower, utilizing a full spectrum of low-, medium-, and high-horsepower engines. Low-horsepower compressor packages enhance production for dry gas wells and liquid-loaded gas wells by deliquifying wells, lowering wellhead pressure and increasing gas velocity. Our low-horsepower compressor packages are also utilized in connection with oil and liquids production and in vapor recovery and casing gas system applications. Low- to medium-horsepower compressor packages are typically utilized in wellhead, gathering, and other applications primarily in connection with oil and liquids production. Our high-horsepower compressor package offerings are typically utilized for natural gas production, natural gas gathering, centralized compression facilities and midstream applications.

The horsepower of our compression services fleet on December 31, 2018, is summarized in the following table:



Range of Horsepower Per Package	Number of Packages	Aggregate Horsepower	% of Total Aggregate Horsepower

Low horsepower (0-100)	3,752	175,951	15.5	%
Medium-horsepower (101-1,000)	1,587	443,901	39.1	%
High-horsepower (1,001 and over)	380	515,625	45.4	%
Total	5,719	1,135,477	100.0	%

Our Compression Division's equipment sales business includes the fabrication and sale of standard compressor packages and custom-designed compressor packages that are designed and 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 coal bed methane systems. We design and fabricate 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, 2018, common units held by the public represented approximately a 65% 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 Completion Fluids & Products 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. The Completion Fluids & Products Division also purchases liquid and dry calcium chloride from a number of U.S. and foreign chemical manufacturers. Our El Dorado, Arkansas, plant produces liquid and flake calcium chloride and sodium chloride, utilizing 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 Completion Fluids & Products Division's primary sources of hydrochloric acid are co-product streams obtained from chemical manufacturers. Substantial quantities of limestone are also consumed when converting hydrochloric acid into calcium chloride. Currently, hydrochloric acid and limestone are generally available from multiple sources.

To produce calcium bromide, zinc bromide, zinc calcium bromide, and sodium bromide at our West Memphis, Arkansas facility, we use bromine, hydrobromic acid, zinc, 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.

We also own 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 us with 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. CCLP designs and fabricates its reciprocating and rotary screw 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. We do not have long-term contracts with these suppliers or manufacturers. 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. CCLP 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. Beginning in 2014, and continuing throughout most of 2016, reduced prices of natural gas and oil led to declines in our customers' drilling activities and capital expenditure levels in the domestic and international markets in which we operate. The decline in activity in the natural gas and oil exploration and production industry resulted in reduced demand for certain of our products and services compared to early 2014 levels. Oil and gas pricing increased throughout the second half of 2017 and most of 2018, and onshore demand has improved in the North America and international markets, with offshore activity remaining flat year-over-year. However, oil and gas pricing remains volatile.

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 utilize high volumes of clear brine fluids ("CBFs"), which can be subject to harsh downhole conditions, such as high pressure and high temperatures. Demand for CBF products is generally driven by offshore completion activity.

Our 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 Completion Fluids & Products Division also sells its CBF products through various distributors.

Our 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 acquisition of SwiftWater continues to expand our market share in the Permian Basin, which is one of the fastest growing basins for oilfield services globally. SwiftWater gives us significant additional service capacity as well as incremental services that allow us increased cross-selling of our water management, flowback and fluids products and services.

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 in various onshore 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 Greywolf subsidiary, the Division serves the western Canada market. In addition, through our OPTIMA subsidiary, we offer 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. We believe that our skilled personnel, operating procedures, integrated closed-loop water management systems, and safety record give us a competitive advantage. Competition in the U.S. water management markets includes various regional companies and Select Energy, while competition in onshore U.S.

and Canadian production testing markets is primarily dominated by numerous small, privately owned operators. Expro International, Halliburton, and Schlumberger are competitors in the foreign markets we serve although we provide these services to their customers on a subcontract basis from time to time. The 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. Competitors for our water management services include large, multinational providers, as well as small, privately owned operators.

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 foreign 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 the value that results from the use of its services, its superior customer service, its highly trained field personnel and the quality of the compressor packages it uses to provide services. The Compression Division’s customers include major integrated oil companies, public and private independent exploration and production companies and midstream companies.

The compression services and compressor package fabrication business is highly competitive. Certain of the Compression Division's competitors may be able to more quickly adapt to changes within the compression 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 various local and regional companies that utilize packages consisting of a screw compressor with a separate engine driver or a reciprocating compressor with a separate engine driver. These local and regional competitors tend to compete with us on the basis of price as opposed to our focus on providing production enhancement value to the customer. Competition for the medium- and high-horsepower compression services business comes primarily from large companies that may have greater financial resources than ours. Such competitors include ArchRock, Kodiak Gas Services, and USA Compression. Our competition in the standard compressor package fabrication and sales market includes several large companies and a large number of small, regional fabricators, including some of those who we compete with for compression services, as well as Enerflex, Exterran and others. The Compression Division's competition in the custom-designed compressor package market usually consists of larger companies that have the ability to address integrated projects and provide product support after the sale. The ability to fabricate these large custom-designed packages at the Compression Division's facilities, which is near the point of end-use of many customers, is often a competitive advantage.

No single customer provided 10% or more of our total consolidated revenues during the year ended December 31, 2018.

Other Business Matters

Backlog

The Compression Division’s equipment sales business consists of the fabrication and sale of standard compressor packages and custom-designed compressor packages that are fabricated to customer specifications and standard specifications, as applicable. The Division's custom-designed 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, 2018, the Compression Division's equipment sales backlog was $105.2 million, all of which is expected to be recognized in 2019. This backlog consists of firm customer orders for which a purchase or work order has been received, satisfactory credit or financing arrangements exist, and delivery has been scheduled. 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, 2018, we had approximately 2,900 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, 2018, we owned or licensed thirty-two issued U.S. patents and had six patent applications pending in the United States. We also had thirty-seven owned or licensed patents and fifteen patent applications pending in various other countries. The foreign patents and patent applications are primarily foreign counterparts to certain of our U.S. patents or patent applications. The issued patents expire at various times through 2035. We have elected to maintain certain other internally developed technologies, know-how, and inventions as trade secrets. While we believe that our patents and trade secrets are important to our competitive positions in our businesses, we do not believe any one patent or trade secret is essential to our success.

It is our practice to enter into confidentiality agreements with key employees, consultants and third parties to whom we disclose our confidential and proprietary information, and we have typical policies and procedures designed to maintain the confidentiality of such information. There can be no assurance, however, that these measures will prevent the unauthorized disclosure or use of our trade secrets and expertise, or that others may not independently develop similar trade secrets or expertise.

We sell various products and services under a variety of trademarks and service marks, some of which are registered in the United States or other countries.

Health, Safety, and Environmental Affairs Regulations

We believe that our service and sales operations and manufacturing plants are in substantial compliance with all applicable U.S. and foreign health, safety, and environmental laws and regulations. We are committed to conducting all of our operations under the highest standards of safety and respect for the environment. However, risks of substantial costs and liabilities are inherent in certain of our operations and in the development and handling of certain products and equipment produced or used at our plants, well locations, and worksites. Because of these risks, there can be no assurance that significant costs and liabilities will not be incurred in the future. Changes in environmental and health and safety regulations could subject us to more rigorous standards. 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, and other petroleum products. Hydrocarbons or other hazardous 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. These properties may be subject to investigatory, remediation, and monitoring requirements under foreign, federal, state, and local environmental laws and regulations.

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. 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 trends in 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.

The reduction in oil and natural gas prices that began in 2014 and continued through 2015 and 2016 resulted in declining demand for certain of our products and services compared to 2014 levels. Although oil prices steadily increased during late 2017 and early 2018, they fell during the fourth quarter of 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 was $55.80 per barrel as of March 1, 2019. U.S. natural gas prices have also been volatile over the past three years, with the Henry Hub price ranging from a low of $1.61 per million British thermal units (“MMBtu”) in March 2016 to a high of $4.93 per MMBtu in November 2018. The Henry Hub price for natural gas as of March 1, 2019 was $2.86 per MMBtu. For more information, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Business Overview and Results of Operations.”

The prolonged reduction in oil and natural gas prices depressed levels of exploration, development, and production activity in 2015 and 2016, and if current oil and natural gas prices remain depressed or further decline, they 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. Even forecasts of longer-term lower oil and natural gas prices by oil and natural gas companies, including current concerns caused by the drop in oil prices during the fourth quarter of 2018, can similarly reduce or defer major expenditures given the long-term nature of many large-scale development projects.

Factors affecting the prices of oil and natural gas include: the level of supply and demand for oil and natural gas; governmental regulations, including the policies of governments regarding the exploration for and production and development of their oil and natural gas reserves; weather conditions and natural disasters; worldwide political, military, and economic conditions; the ability or willingness of the Organization of Petroleum Exporting Countries ("OPEC") to set and maintain oil production levels; the levels of oil production by 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 potential acceleration of the development of alternative fuels.

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.

Current 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. As of December 31, 2018, the market price for our common stock was $1.68 per share and the market price per common unit of CCLP was $2.32, reflecting steep declines during the fourth quarter of 2018. As of March 1, 2019, the price of our common stock and the price of the common units of CCLP were $2.48 and $3.10, respectively. 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 (similar to the Series A Convertible Preferred Units of CCLP that were issued in late 2016 (the "CCLP Preferred Units")) in the future for acquisition and financing transactions, if available, could be significantly dilutive to current common unitholders. In addition, as of December 31, 2018, CCLP had approximately $645.9 million aggregate principal amount outstanding under its 7.25% Senior Notes and 7.50% Senior Secured Notes. 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, 2018, CCLP's total capital expenditures were $103.5 million, primarily consisting of growth capital expenditures to increase its compression services equipment fleet. The majority of these capital expenditures were funded through the issuance of long-term debt during 2018. As of December 31, 2018, CCLP's total cash balance was $15.9 million. CCLP expects that the combination of this $15.9 million of cash on hand at the beginning of 2019, operating cash flows expected to be generated during the year, and financing transactions with TETRA will be sufficient to fund its anticipated 2019 capital expenditures without having to access the debt or equity markets. However, CCLP's ability to grow its business through capital expenditure or acquisition activities beyond these sources of financing may be significantly limited or curtailed. Without the ability to increase CCLP's compression equipment fleet or otherwise grow its operations, CCLP's ability to continue to retain customers whose compression services needs are expanding and to increase distributions to its common unitholders, including us, in the future may be limited.

We encounter, and expect to continue to encounter, intense competition in the sale of our products and services.

We compete with numerous companies in each of our operating segments, many of which have substantially greater financial and other resources than we have. Certain of our competitors have lower standards of quality, and offer equipment and services at lower prices than we do. Other competitors have newer equipment that is better suited to our customers' needs. Particularly during a period of low oil and natural gas pricing, to the extent competitors offer products or services at lower prices or higher quality, or more cost-effective products or services, our business could be materially and adversely affected. In addition, certain of our customers may elect to perform services internally in lieu of using our services, which could also materially and adversely affect our operations.

The profitability of our operations is dependent on other numerous factors beyond our control.

Our operating results in general, and gross profit in particular, are determined by market conditions and the products and services we sell in any period. Other factors, such as heightened competition, changes in sales and distribution channels, availability of skilled labor and contract services, shortages in raw materials, or inability to obtain supplies at reasonable prices, may also affect the cost of sales and the fluctuation of gross margin in future periods.

Other factors affecting our operating results and activity levels include oil and natural gas industry spending levels for exploration, completion, production, development, and acquisition activities, and impairments of long-lived assets. 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 reduced their capital expenditures during 2016 and 2017 in light of the significant declines in the prices of oil and natural gas, and the decline in oil prices during the fourth quarter of 2018, if sustained, could have a similar impact to 2019 industry capital expenditures. Such industry capital expenditure reductions have had, and are expected to continue to have, a negative effect on the demand for many of our products and services. This has had, and may continue to have, a negative effect on our revenues and results of operations. A large concentration of our operating activities is located in the Permian Basin region of Texas and New Mexico. Our revenues and profitability are particularly dependent upon oil and natural gas industry activity and spending levels in this region. Our operations may also be affected by technological advances, cost of capital, and tax policies. Adverse changes in any of these other factors may have a material adverse effect on our revenues and profitability.

Changes in the economic environment have resulted, and could further result, in significant impairments of certain of our long-lived assets and goodwill.

During the first quarter of 2016, we recorded consolidated long-lived asset impairments (excluding goodwill impairments) of approximately $10.7 million. During the fourth quarter of 2016, primarily as a result of the impact of significant decreases in oil and natural gas prices on certain of our long-lived assets, we recorded consolidated long-lived asset impairments of approximately $7.2 million. During the fourth quarter of 2017, consolidated long-lived asset impairments of approximately $14.9 million were recorded primarily due to the impairment of a certain identified intangible asset resulting from decreased expected future operating cash flows from a Water & Flowback Services Division customer. 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. During the two year period ending December 31, 2018, we have recorded a total of $18.5 million of impairments and other charges. Depressed commodity prices and/or adverse changes in the economic environment could result in a greater decrease in the demand for many of our products and services, which could impact the expected utilization rates of certain of our long-lived assets, including plant facilities, operating locations, and other operating equipment. 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.

As of December 31, 2018, our consolidated goodwill consists of the $25.9 million of goodwill attributed to our Water Management reporting unit, as part of our Water & Flowback Services Division. Under U.S. GAAP, we review the carrying value of our goodwill for possible impairment annually or when events or changes in

circumstances indicate the carrying value may not be recoverable. Changes in circumstances indicating the carrying value of our goodwill may not be recoverable include a decline in our stock price or future cash flows and slower growth rates in our industry. If economic and market conditions decline, we may be required to record additional charges to earnings during the period in which any impairment of our goodwill is determined, resulting in a negative impact on our results of operations. Specific uncertainties affecting the estimated fair value of our Water Management reporting unit includes the impact of competition, prices of oil and natural gas, and future overall activity levels in the regions in which we operate, the activity levels of our significant customers, and other factors affecting the rate of future growth of this reporting unit. These factors will continue to be reviewed and assessed going forward. Negative developments with regard to these factors could have a further negative effect on the fair value of the Water Management reporting unit, resulting in the impairment of all or a portion of goodwill.

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, and formate-based brines, some of which we manufacture and some of which are purchased from third parties. Sales of these products contribute significantly to our revenues. In our manufacture of calcium chloride, we use brines, hydrochloric acid, and other raw materials purchased from third parties. In our manufacture of brominated CBF products, we use elemental bromine, hydrobromic acid, and other raw materials that are purchased from third parties. We rely on Lanxess as a supplier of bromine for our brominated CBF products as well as tail brine for our El Dorado, Arkansas, calcium chloride plant. Although we have long-term supply agreements with Lanxess, if we were unable to acquire these raw materials at reasonable prices for a prolonged period, our Completion Fluids & Products Division business could be materially and adversely affected.

The fabrication of CCLP's compression packages and our production testing, well monitoring, and rig cooling equipment requires the purchase of various components, some of which we obtain from a single source or a limited group of suppliers. Our reliance on these suppliers exposes us to the risk of price increases, inferior component quality, or an inability to obtain an adequate supply of required components in a timely manner. The profitability or future growth of our Compression and Water & Flowback Services Divisions may be adversely affected due to our dependence on these key suppliers.

Our success depends upon the continued contributions of our personnel, many of whom would be difficult to replace, and the continued ability to attract new employees.

Our success depends on our ability to attract, train, and retain skilled management and employees at reasonable compensation levels. The delivery of our products and services requires personnel with specialized skills and experience. In addition, our ability to expand our operations depends in part on our ability to increase the size of our skilled labor force. The demand for skilled managers and workers in the U.S. Gulf Coast region and other regions in which we operate is high and the supply is limited. A lack of qualified personnel, could adversely affect operating results.

The demand for our products and services in the U.S. Gulf of Mexico could continue to be adversely impacted by increased regulation and continuing regulatory uncertainty.

Operations in the U.S. Gulf of Mexico have been subject to an increasingly stringent regulatory environment including government regulations focused on offshore operating requirements, spill cleanup, and enforcement matters. These regulations also implement additional safety and certification requirements applicable to offshore activities in the U.S. Gulf of Mexico. Demand for the products and services of our Completion Fluids & Products Division in the U.S. Gulf of Mexico continues to be affected by these regulations. Future regulatory requirements could delay our customers’ activities, reduce our revenues, and increase our operating costs, including the cost to insure offshore operations, resulting in reduced cash flows and profitability.

Operating, Technological, and Strategic Risks

We may not fully realize the benefits from the SwiftWater or JRGO acquisitions.

On February 28, 2018, we purchased all of the equity interests in SwiftWater, which is engaged in the business of providing water management and water solutions to oil and gas operators in the Permian Basin market.

On December 6, 2018, we purchased the equity interests of JRGO, which specializes in delivering comprehensive water management services, including containment solutions, for oil and gas operators in the Appalachian region of the U.S.

We performed an inspection of each entity's assets and liabilities, which we believe to be generally consistent with industry practices. However, there could be unknown liabilities or other problems that are not necessarily observable even when the inspection is undertaken. If problems are identified of the SwiftWater and JRGO acquisitions, we may have limited recourse.

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.

We face risks related to our long-term growth strategy.

Our long-term growth strategy includes both internal growth and growth through acquisitions. Internal growth may require significant capital expenditures, some of which may become unrecoverable or fail to generate an acceptable level of cash flows. Internal growth also requires financial resources (including the use of available cash or additional long-term debt), management, and personnel resources. Acquisitions also require significant management resources, both at the time of the transaction and during the process of integrating the newly acquired business into our operations. Acquisitions could adversely affect our operations if we are unable to successfully integrate the newly acquired operations into our existing operations, are unable to hire adequate personnel, or are unable to retain existing personnel. We may not be able to consummate future acquisitions on favorable terms. Acquisition or internal growth assumptions developed to support our decisions could prove to be overly optimistic. Future acquisitions by us could result in issuances of equity securities or the rights associated with the equity securities, which could potentially dilute earnings per share. Future acquisitions could result in the incurrence of additional debt or contingent liabilities and amortization expenses related to intangible assets. These factors could adversely affect our future operating results and financial position.

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 spills, gas leaks or ruptures, uncontrollable flows of oil, gas, or well fluids, or discharges of CBFs or toxic gases or other pollutants. These operating hazards may also include injuries to employees and third parties during the performance of our operations. In the past, our Compression Division has on occasion experienced fires that have damaged or destroyed certain of its compression fleet, and similar accidents or fires could reoccur in the future.

We have maintained a policy of insuring our risks of operational hazards that we believe is customary in the industry. We believe that the limits of insurance coverage we have purchased are consistent with the exposures we face and the nature of our products and services. Due to economic conditions in the insurance industry, from time to time, we have increased our self-insured retentions for certain policies in order to minimize the increased costs of coverage, or we have reduced our limits of insurance coverage for, or not procured, named windstorm 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

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, 2018, our total long-term debt outstanding (excluding CCLP) of $182.5 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"), although there was no balance outstanding under the CCLP Credit Agreement as of December 31, 2018. As of December 31, 2018, our consolidated balance sheet includes $633.0 million carrying amount of long-term debt of CCLP, which consisted of (i) $343.2 million carrying amount under its 7.50% Senior Secured Notes due 2025 (the "CCLP 7.50% Senior Secured Notes"), and (ii) $289.8 million carrying amount of CCLP's 7.25% Senior Notes due 2022 (the "CCLP 7.25% Senior Notes"). 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 the CCLP's ability to take certain actions including, among other things and subject to certain significant exceptions, (i) incurring debt, (ii) granting liens, (iii) making investments, (iv) entering into or amending transactions with affiliates, (v) paying dividends, and (vi) selling assets. The CCLP Credit Agreement also contains a provision that requires compliance with a fixed charge coverage ratio (as defined in the CCLP Credit Agreement) of not less than 1.0 to 1.0 in the event that certain conditions associated with outstanding borrowings and cash availability occur.

In addition, the indentures governing the CCLP 7.50% Senior Secured Notes and the CCLP 7.25% Senior Notes (the "CCLP Indentures") contain customary covenants restricting CCLP's ability and the ability of its restricted subsidiaries to (i) pay distributions on, purchase, or redeem its common units, make certain investments and other restricted payments, or purchase or redeem any subordinated debt; (ii) incur or guarantee additional indebtedness or issue certain kinds of preferred equity securities; (iii) create or incur certain liens securing indebtedness; (iv) sell

assets, including dispositions of the CCLP 7.50% Senior Secured Notes Collateral; (v) consolidate, merge, or transfer all or substantially all of its assets; (vi) enter into, or amend or modify transactions with affiliates; and (vii) enter into agreements that restrict distributions or other payments from CCLP's restricted subsidiaries to CCLP. These covenants are subject to a number of important limitations and exceptions, including certain provisions permitting CCLP, subject to the satisfaction of certain conditions, to transfer assets to certain of its unrestricted subsidiaries.

Our continuing ability to comply with covenants in our Long-Term Debt Agreements depends largely upon our ability to generate adequate earnings and operating cash flow.

The debt levels of our CCLP subsidiary have resulted in a significant use of its operating cash flows being used to fund debt service requirements, resulting in less cash available for distributions.

In March 2018, CCLP issued an aggregate $350.0 million of its 7.50% Senior Secured Notes due 2025 (the "CCLP 7.50% Senior Secured Notes"), the proceeds from which were partially used to repay the remaining outstanding balance of $258.0 million under CCLP's previous bank credit facility, which was then terminated. While the termination of the CCLP previous bank credit agreement removed certain financial covenant requirements, the issuance of the 7.50% Senior Secured Notes increased CCLP's aggregate amount of long-term debt outstanding as well as increased the aggregate interest rate of its debt outstanding. This increase in CCLP indebtedness has increased its total interest expense, which in turn reduces its cash available to fund capital expenditures or for distribution to CCLP's common unitholders, including us. CCLP's ability to service its indebtedness will depend upon, among other things, its future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond its control. If CCLP operating results are not sufficient to service its current or future indebtedness, CCLP may be forced to consider taking actions such as reducing or delaying is business activities, acquisitions, investments and/or capital expenditures, delaying the increase of distributions, selling assets, restructuring or refinancing its indebtedness, or seeking additional equity capital or bankruptcy protection. CCLP may not be able to take any of these courses of action.

On December 20, 2018, CCLP announced that, given the decline in its common unit price, it was reducing its common unit distributions from $0.75 per unit per year (or $0.1875 per quarter) to $0.04 per unit per year (or $0.01 per quarter) for a period of up to four quarters, beginning with the February 2019 distribution. CCLP intends to use the approximately $34 million of the savings from the reduced distribution to redeem the remaining CCLP Preferred Units for cash and avoid the dilution to its common unitholders that would occur if the CCLP Preferred Units were converted into common units. 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, following the redemption of the CCLP Preferred Units.

We have continuing exposure to abandonment and decommissioning obligations associated with oil and gas properties previously owned by Maritech.

From 2001 to 2012, Maritech sold oil and gas producing properties in numerous transactions to different buyers. In connection with those sales, the buyers assumed the decommissioning liabilities associated with the properties sold (the "Legacy Liabilities") and generally became the successor operator. 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, 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 abandonment and decommissioning work required, a previous owner, including Maritech, may be required to perform the abandonment and decommissioning obligation. As the former parent company of Maritech, we also may be responsible for performing these abandonment and decommissioning obligations. A significant portion of the decommissioning liabilities that were assumed by the buyers of the Maritech properties in these previous sales remains unperformed, and we believe the amounts of these remaining liabilities are significant. We generally monitor the financial condition of the buyers of these properties, and if oil and natural gas pricing levels deteriorate, we expect that one or more of these buyers may be unable to perform the decommissioning work required on properties they acquired, either directly or indirectly from Maritech.

In March 2018, pursuant to a series of transactions, Maritech completed the sales of the remaining active leases held by Maritech to Orinoco Natural Resources, LLC ("Orinoco") and, immediately thereafter, we sold all

equity interest in Maritech to Orinoco. Under the Maritech Asset Purchase Agreement, Orinoco assumed all of Maritech's abandonment and decommissioning obligations related to the active leases (the “Orinoco Lease Liabilities”) and under the Maritech Equity Purchase Agreement Orinoco assumed all other liabilities of Maritech, including the Legacy Liabilities, subject to limited exceptions unrelated to the asset retirement obligations. Pursuant to a Bonding Agreement executed in connection with such purchase agreements, Orinoco provided non-revocable bonds in the aggregate amount of $47.0 million to secure their performance of Maritech’s abandonment and decommissioning obligations related to the Orinoco Lease Liabilities and Maritech’s remaining current abandonment and decommissioning obligations (not including the Legacy Liabilities). Orinoco was required to replace, within 90 days following the closing, the initial bonds delivered at closing with non-revocable performance bonds, meeting certain requirements, in the aggregate sum of $47.0 million. Orinoco has not delivered such replacement bonds and we are seeking to enforce the terms of the Bonding Agreement. The non-revocable performance bonds delivered at the closing remain in effect.

If in the future we become liable for any abandonment and decommissioning liability associated with any property previously owned by Maritech other than the Legacy Liabilities, the Bonding Agreement provides that, if we call any of these 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.

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.

Our operating results and cash flows for certain of our subsidiaries are subject to foreign currency risk.

The operations of certain of our subsidiaries are exposed to fluctuations between the U.S. dollar and certain foreign currencies, particularly the euro, the British pound, the Mexican peso, and the Argentinian peso. Our plans to grow our international operations could cause this exposure from fluctuating currencies to increase. Historically, exchange rates of foreign currencies have fluctuated significantly compared to the U.S. dollar, and this exchange rate volatility is expected to continue. Significant fluctuations in foreign currencies against the U.S. dollar could adversely affect our balance sheet and results of operations.

If the remaining CCLP Preferred Units are not redeemed for cash, as intended, the result would be the issuance of additional CCLP common units in the future, resulting in potential dilution of our existing common unit ownership in CCLP.

CCLP's partnership agreement does not limit the number of additional common units that CCLP may issue at any time without the approval of its common unitholders. In addition, subject to the provisions of the CCLP Series A Preferred Unit Purchase Agreements (the “CCLP Unit Purchase Agreements”), CCLP may issue an unlimited number of partnership units that are senior to the common units in right of distribution, liquidation, or voting. On August 8, 2016, CCLP issued an aggregate of 4,374,454 of CCLP Preferred Units for a cash purchase price of $11.43 per CCLP Preferred Unit (the “Issue Price”), resulting in total net proceeds, after deducting certain offering expenses, of $49.8 million. We purchased 874,891 of the CCLP Preferred Units at the Issue Price, for a purchase price of $10.0 million. Additionally, on September 20, 2016, CCLP issued an aggregate of 2,624,672 of CCLP Preferred Units for a cash purchase price of $11.43 per Preferred Unit, resulting in total net proceeds, after deducting certain offering expenses, of $29.0 million.

Pursuant to the initial CCLP Unit Purchase Agreement dated August 8, 2016, our wholly owned CSI Compressco GP Inc. subsidiary (the general partner of CCLP), executed the Second Amended and Restated Agreement of Limited Partnership of the Partnership (the “Amended and Restated CCLP Partnership Agreement”) to, among other things, authorize and establish the rights and preferences of the CCLP Preferred Units. The CCLP Preferred Units are a new class of equity security that ranks senior to CCLP's common units with respect to distribution rights and rights upon liquidation. The holders of CCLP Preferred Units (each, a “CCLP Preferred Unitholder”) will receive quarterly distributions in kind in additional CCLP Preferred Units, equal to an annual rate of

11.00% of the Issue Price ($1.2573 per unit annualized), subject to certain adjustments, including adjustments relating to any future issuances of common units below a set price, and any quarterly distributions on our common units in excess of $0.3775 per common unit. In the event CCLP fails to pay in full any quarterly distribution in additional CCLP Preferred Units, then until such failure is cured, CCLP is prohibited from making any distributions on its common units. Beginning March 8, 2017 and on the first trading day of each calendar month thereafter for a total of thirty months (each, a “Conversion Date”), the CCLP Preferred Units convert into common units in an amount equal to, with respect to each CCLP Preferred Unitholder, the number of CCLP Preferred Units held by such CCLP Preferred Unitholder divided by the number of Conversion Dates remaining. On June 7, 2017, as permitted under the Amended and Restated CCLP Partnership Agreement, CCLP elected to defer the monthly conversion of CCLP Preferred Units for each of the Conversion Dates during the three month period beginning July 2017. As a result, no CCLP Preferred Units were converted into CCLP common units during the three month period ended September 30, 2017, and future monthly conversions were increased beginning in October 2017. During 2018, conversions of the CCLP Preferred Units resulted in the issuance of approximately 8.0 million CCLP common units. CCLP may, at its option, pay cash, or a combination of cash and common units, to the CCLP Preferred Unitholders instead of issuing common units on any Conversion Date, subject to certain restrictions as described in the Amended and Restated CCLP Partnership Agreement and the CCLP Credit Agreement.

On December 20, 2018, CCLP announced that, given the decline in its common unit price, CCLP was reducing its common unit distributions from $0.75 per unit per year (or $0.1875 per quarter) to $0.04 per unit per year (or $0.01 per quarter) for a period of up to four quarters, beginning with the February 2019 distribution. CCLP intends to use the approximately $34 million of savings from the reduced distribution to redeem the remaining CCLP Preferred Units for cash and avoid the dilution to its common unitholders that would occur if the CCLP Preferred Units were converted into common units at a low unit price. However, there is no guarantee that CCLP will be able to fully redeem the remaining CCLP Preferred Units for cash and that additional dilution will not occur.

If the remaining CCLP Preferred Units are not redeemed for cash, as intended, the result would be common units issued upon conversion thereof, resulting in dilution of our common unit ownership in CCLP.

We and CCLP are exposed to interest rate risks with regard to our respective credit facility indebtedness.

As of December 31, 2018, we had a total of $0.0 million outstanding under our ABL Credit Agreement and $182.5 million outstanding under our Term Credit Agreement. CCLP has a total of $0.0 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 or CCLP have amounts outstanding under these facilities, our and CCLP's cash flows and results of operations could be subject to interest rate risk exposure associated with the level of the variable rate debt balance outstanding. We currently are not a party to an interest rate swap contract or other derivative instrument designed to hedge our exposure to interest rate fluctuation risk.

Our ABL Credit Agreement is scheduled to mature on September 10, 2023. Our Term Loan Agreement is scheduled to mature on September 10, 2025. The CCLP Credit Agreement is scheduled to mature on June 29, 2023. CCLP's 7.25% Senior Notes, which mature August 15, 2022, and CCLP's 7.50% Senior Secured Notes, which mature April 1, 2025, bear interest at fixed interest rates. There can be no assurance that the 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.

Legal, Regulatory, and Political Risks

Our operations are subject to extensive and evolving U.S. and foreign federal, state and local laws and regulatory requirements that increase our operating costs and expose us to potential fines, penalties, and litigation.

Laws and regulations govern our operations, including those relating to corporate governance, employees, taxation, fees, importation and exportation restrictions, environmental affairs, health and safety, and the manufacture, storage, handling, transportation, use, and sale of chemical products. Certain foreign countries impose additional restrictions on our activities, such as currency restrictions and restrictions on various labor practices. These laws and regulations are becoming increasingly complex and stringent, and compliance is becoming increasingly expensive. Governmental authorities have the power to enforce compliance with these regulations, and violators are subject to civil and criminal penalties, including civil fines, and injunctions. Third parties may also have the right to pursue legal actions to enforce compliance with certain laws and regulations. It is

possible that increasingly strict environmental, health and safety laws, regulations, and enforcement policies could result in substantial costs and liabilities to us.

The EPA is studying the environmental impact of hydraulic fracturing, a process used by the U.S. oil and gas industry in the development of certain oil and gas reservoirs. Specifically, the EPA is reviewing the impact of hydraulic fracturing on drinking water resources. Certain environmental and other groups have suggested that additional federal, state, and local laws and regulations may be needed to more closely regulate the hydraulic fracturing process. Several states have adopted regulations that require operators to disclose the chemical constituents in hydraulic fracturing fluids. We cannot predict whether any federal, state or local laws or regulations will be enacted regarding hydraulic fracturing, and, if so, what actions any such laws or regulations would require or prohibit. If additional levels of regulation or permitting requirements were imposed on oil and gas operators through the adoption of new laws and regulations, the domestic demand for certain of our products and services could be decreased or subject to delays, particularly for our Water & Flowback Services, Compression, and Completion Fluids & Products Divisions.

We have operations that are either ongoing or scheduled to commence in the U.S. Gulf of Mexico. At this time, we cannot predict the full impact that other regulatory actions that may be mandated by the federal government may have on our operations or the operations of our customers. Other governmental or regulatory actions could further reduce our revenues and increase our operating costs, including the cost to insure offshore operations, resulting in reduced cash flows and profitability.

Our onshore and offshore operations expose us to risks such as the potential for harmful substances escaping into the environment and causing damages or injuries, which could be substantial. Although we maintain general liability and pollution liability insurance, these policies are subject to exceptions and coverage limits. We maintain limited environmental liability insurance covering named locations and environmental risks associated with contract services for oil and gas operations. We could be materially and adversely affected by an enforcement proceeding or a claim that is not covered or is only partially covered by insurance.

Because our business depends on the level of activity in the oil and natural gas industry, existing or future laws, regulations, treaties, or international agreements that impose additional restrictions on the industry may adversely affect our financial results. Regulators are becoming more focused on air emissions from oil and gas operations, including volatile organic compounds, hazardous air pollutants, and greenhouse gases ("GHGs"). In particular, the focus on GHGs and climate change, including incentives to conserve energy or use alternative energy sources, could have a negative impact on our financial results if such laws, regulations, treaties, or international agreements reduce the worldwide demand for oil and natural gas or otherwise result in reduced economic activity generally. In addition, such laws, regulations, treaties, or international agreements could result in increased compliance costs, capital spending requirements, or additional operating restrictions for us, which may have a negative impact on our financial results.

In addition to increasing our risk of environmental liability, the rigorous enforcement of environmental laws and regulations has accelerated the growth of some of the markets we serve.

Our expansion into foreign countries exposes us to complex regulations and may present us with new obstacles to growth.

We plan to continue to grow both in the United States and in foreign countries. We have established operations in, among other countries, Argentina, Brazil, Canada, Finland, Ghana, Mexico, Norway, Saudi Arabia, Sweden, and the United Kingdom. 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 either 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, therefore, 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 in that country, including the changing regulations over repatriation of cash generated from our operations in Argentina.

The current economic, legal, and political environment in Argentina and recent devaluation of the Argentinian peso have created increased economic instability for foreign investment in Argentina. The Argentinian government is currently attempting to address the current high rate of inflation and the continuing devaluations pressure. Fiscal and monetary expansion in Argentina has led to devaluations of the Argentinian peso, particularly in late 2013, early 2014, and late 2015. 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. As of December 31, 2018, approximately $0.9 million of our consolidated cash balance is located in Argentina, and the process of repatriating this cash to the U.S. is subject to increasingly complex regulations. There can be no assurances that our growing Argentinian operations will not expose us to a loss of liquidity, foreign exchange losses, and other potential financial impacts.

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 determined that GHGs present an endangerment to public health and the environment, because emissions of such gases are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes. Based on these findings, the EPA has begun adopting and implementing regulations to restrict emissions of GHGs under existing provisions of the CAA. Such EPA rules regulate GHG emissions under the CAA and require a reduction in emissions of GHGs from motor vehicles and from certain large stationary sources. The EPA rules also require so-called “green” completions at hydraulically fractured natural gas wells beginning in 2015. In addition, the EPA also requires the annual reporting of GHG emissions from specified large GHG emission sources in the United States, including petroleum refineries, as well as from certain oil and gas production facilities.

The EPA has adopted regulations under the CAA to control emissions of hazardous air pollutants from reciprocal internal combustion engines and more recently the EPA adopted regulations that establish air emission controls for natural gas and natural gas liquids production, processing and transportation activities, including NSPS as well as emission standards to address hazardous air pollutants. Certain CCLP compressor packages are subject to these new requirements and additional control equipment and maintenance operations are required. 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. To the extent that the United States and other countries implement the Paris Agreement or impose 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. Further, U.S. Congress ("Congress") has considered and almost one-half of the states have adopted legislation that seeks to control or reduce emissions of GHGs from a wide range of sources. Any such legislation could adversely affect demand for the oil and natural gas our customers produce and, in turn, demand for our products and services. Finally, it should be noted that some scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods, and other climatic events; if any such effects were to occur, they could have an adverse effect on our operations and cause us to incur costs in preparing for or responding to those effects.

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 an important and common practice that is used to stimulate production of hydrocarbons from dense subsurface rock formations. The process involves the injection of water, sand or other proppants and chemical additives under pressure into targeted geological formations to fracture the surrounding rock and stimulate production.

Hydraulic fracturing typically is regulated by state oil and gas commissions or similar state agencies, but several federal agencies have asserted regulatory authority over certain aspects of the process. For example, the EPA 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; 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; published in June 2016 an effluent limitations guidelines final rule prohibiting the discharge of waste water from shale natural-gas extraction operations before discharging to a treatment plant; and 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. Also, the U.S. Bureau of Land Management ("BLM") published a final rule in March 2015 that established new or more stringent standards for performing hydraulic fracturing on federal and Indian lands. However, in June 2016, a Wyoming federal judge struck down this final rule, finding that the BLM lacked authority to promulgate the rule, the BLM appealed the decision to the U.S. Circuit Court of Appeals for the Tenth Circuit in July 2016, the appellate court issued a ruling in September 2017 to vacate the Wyoming trial court decision and dismiss the lawsuit challenging the 2015 rule in response to the BLM’s issuance of a proposed rulemaking to rescind the 2015 rule and, in December 2017, the BLM published a final rule rescinding the March 2015 rule. In January 2018, litigation challenging the BLM’s rescission of the 2015 rule was brought in federal court, but, in June 2016, a Wyoming federal judge struck down this final rule, finding that the BLM lacked authority to promulgate the rule. That decision was appealed by the BLM to the U.S. Circuit Court of Appeals for the Tenth Circuit in 2016, but, in March 2017, the BLM filed a request with the Tenth Circuit to put the appeal on hold pending rescission of the 2015 final rule.

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, where the drilling program is expected to operate, 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 in areas where the drilling program operates, including, for example, on federal and American Indian lands, the partnership 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. 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. “Water cycle” describes the use of water in hydraulic fracturing, from water withdrawals to the making of hydraulic fracturing fluids, through the mixing and injection of hydraulic fracturing fluids in oil and natural gas production wells, to the collection and disposal or reuse of produced water.

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, in other countries where we operate, could have an adverse impact on our and our customers’ ability to expand operations.

In the United States, 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 development activity in affected areas. The designation of previously unprotected species as threatened or endangered in areas where we or our customers might conduct operations could result in limitations or prohibitions on our operations and could adversely impact our business.

Our proprietary rights may be violated or compromised, which could damage our operations.

We own numerous patents, patent applications, and unpatented trade secret technologies in the U.S. and certain foreign countries. There can be no assurance that the steps we have taken to protect our proprietary rights will be adequate to deter misappropriation of these rights. In addition, independent third parties may develop competitive or superior technologies.

Our operations and reputation may be impaired if our information technology systems fail to perform adequately or if we are the subject of a data breach or cyberattack.

Our information technology systems are critically important to operating our business efficiently. We rely on our information technology systems to manage our business data, communications, supply chain, customer invoicing, employee information, and other business processes. We outsource certain business process functions to third-party providers and similarly rely on these third parties to maintain and store confidential information on their systems. The failure of these information technology systems to perform as we anticipate could disrupt our

business and could result in transaction errors, processing inefficiencies, and the loss of sales and customers, causing our business and results of operations to suffer.

Although we allocate significant resources to protect our information technology systems, we have experienced varying degrees of cyber-incidents in the normal conduct of our business, including viruses, worms, other destructive software, process breakdowns, phishing and other malicious activities. 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 not carry insurance against these risks, although we do invest in security technology, perform penetration tests from time to time, and design our business processes to attempt to mitigate the risk of such breaches. However, there can be no assurance that security breaches will not occur. Moreover, the development and maintenance of these measures requires continuous monitoring as technologies change and efforts to overcome security measures evolve. We have experienced, and expect to continue to experience, cyber security threats and incidents, none of which has been material to us to date. However, a successful breach or attack could have a material negative impact on our operations or business reputation and subject us to consequences such as litigation and direct costs associated with incident response.

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 leased or owned as of December 31, 2018. We believe our facilities are adequate for our present needs.

Facilities

Completion Fluids & Products Division

Our Completion Fluids & Products Division facilities include seven chemical production plants located in the states of Arkansas, California, Louisiana, and West Virginia, and the country of Finland, having a total production capacity of more than 1.5 million equivalent liquid tons per year. The two California locations consist of 29 square miles of leased mineral acreage and solar evaporation ponds, and related owned production and storage facilities.

As an inducement to locate our calcium chloride production plant in Union County, Arkansas, we received certain ad valorem property tax incentives. Our facility is located just outside the city of El Dorado, Arkansas, on property that is leased from Union County, Arkansas. We have the option of purchasing the property at any time during the term of the lease for a nominal price. The term of the lease expires in 2035, at which time we also have the option to purchase the property at a nominal price. Under the terms of the lease, we are responsible for all costs incurred related to the facility.

In addition to the production facilities described above, the Completion Fluids & Products Division owns or leases multiple service center facilities in the United States and in other countries. The Completion Fluids & Products Division also leases several offices and numerous terminal locations in the United States and in other countries.

We lease approximately 30,000 gross acres of bromine-containing brine reserves in Magnolia, Arkansas, for possible future development and as a source of supply for our bromine and other raw materials.

Water & Flowback Services Division

The Water & Flowback Services Division conducts its operations through production testing service centers (most of which are leased) in the United States, located in Colorado, Louisiana, North Dakota, Oklahoma, Pennsylvania, Texas, West Virginia, and Wyoming. In addition, the Water & Flowback Services Division has leased facilities in Australia, Canada, Mexico, and certain countries in the United Kingdom, the Middle East and South America.

Compression Division

The Compression Division’s facilities include owned offices and fabrication facilities in Midland, Texas, consisting of an aggregate of approximately 177,000 square feet of structures that are located on 38.5 acres of land. In addition, the Division has several owned and leased service, fabrication, and sales facilities in Argentina, Canada, Mexico, and the United States. 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 the Midland, Texas facility.

For a profile of our compression fleet, see "Item 1. Business "Products and Services - Compression Division."

Corporate

Our headquarters is located in The Woodlands, Texas, in a 153,000 square foot office building, which is located on 2.6 acres of land, under a lease that expires in 2027. In addition, we own a 28,000 square foot technical facility in The Woodlands, Texas, to service our Completion Fluids & Products Division 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.

Environmental Proceedings

One of our subsidiaries, TETRA Micronutrients, Inc. ("TMI"), previously owned and operated a production facility located in Fairbury, Nebraska. TMI is subject to an Administrative Order on Consent issued to American Microtrace, Inc. (n/k/a/ TETRA Micronutrients, Inc.) in the proceeding styled In the Matter of American Microtrace Corporation, EPA I.D. No. NED00610550, Respondent, Docket No. VII-98-H-0016, dated September 25, 1998 (the "Consent Order"), with regard to the Fairbury facility. TMI is liable for ongoing environmental monitoring at the Fairbury facility under the Consent Order; however, the current owner of the Fairbury facility is responsible for costs associated with the closure of that facility.

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 of March 1, 2019, there were approximately 338 holders of record of the common stock.

Market Price of Common Stock

The following graph compares the five-year cumulative total returns of our common stock, the Standard & Poor’s 500 Composite Stock Price Index (S&P 500), and the Philadelphia Oil Service Sector Index (PHLX Oil Service), assuming $100 invested in each stock or index on December 31, 2013, all dividends reinvested, and a fiscal year ending December 31. This information shall be deemed furnished, and not filed, in this Form 10-K and shall not be deemed incorporated by reference into any filing under the Securities Act of 1933 or the Securities Exchange Act of 1934 as a result of this furnishing, except to the extent we specifically incorporate it by reference.

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. There were no repurchases made during 2006 through 2018 pursuant to the repurchase program. Shares repurchased during the fourth quarter of 2018, other than pursuant to our repurchase program, are as follows:



Period	Total Number of Shares Purchased		Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs⁽¹⁾	Maximum Number (or Approximate Dollar Value) of Shares that May Yet be Purchased Under the Publicly Announced Plans or Programs⁽¹⁾
Oct 1 – Oct 31, 2018	149	(2)	$	2.97	—	$	14,327,000
Nov 1 – Nov 30, 2018	5,172	(2)	3.22		—	14,327,000
Dec 1 – Dec 31, 2018	1,513	(2)	2.32		—	14,327,000
Total	6,834				—	$	14,327,000


⁽¹⁾	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.


⁽²⁾	Shares we received in connection with the exercise of certain employee stock options or the vesting of certain employee restricted stock awards. These shares were not acquired pursuant to the stock repurchase program.

Item 6. Selected Financial Data.

The following tables set forth our selected consolidated financial data for the years ended December 31, 2018, 2017, 2016, 2015, and 2014. 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 2016, 2015, and 2014, we recorded significant impairments of long-lived assets and goodwill. During 2014, our Compression Division acquired Compressor Systems, Inc. ("CSI"), and financed a portion of the $825.0 million purchase price through the issuance of additional common units of CSI Compressco LP and through the issuance of long-term debt. These acquisitions, dispositions, and impairments significantly impact the comparison of our financial statements.



	Year Ended December 31,
	2018				2017				2016				2015				2014
	(In Thousands, Except Per Share Amounts)
Income Statement Data
Revenues	$	998,775			$	723,098			$	617,391			$	1,010,641			$	908,070
Gross profit	162,298				108,390				60,839				181,157				175,220
General and administrative expense	132,446				115,414				108,422				145,843				129,234
Goodwill impairment	—				—				106,205				177,006				60,358
Interest expense	72,066				58,027				59,984				55,134				35,676
Interest income	(1,120		)		(781		)		(1,370		)		(688		)		(757		)
Other (income) expense, net	(4,668		)		(20,227		)		10,818				1,596				11,174
Loss before taxes and discontinued operations	(36,426		)		(44,043		)		(223,220		)		(197,734		)		(60,465		)
Loss from discontinued operations, net of taxes	(41,515		)		(17,389		)		(14,017		)		(5,334		)		(73,045		)
Net loss	(84,240		)		(62,183		)		(239,393		)		(209,467		)		(167,575		)
Net loss attributable to TETRA stockholders	$	(61,617	)		$	(39,048	)		$	(161,462	)		$	(126,183	)		$	(169,678	)
Loss per share, before discontinued operations attributable to TETRA stockholders	$	(0.16	)		$	(0.19	)		$	(1.69	)		$	(1.53	)		$	(1.23	)
Average shares	124,101				114,499				87,286				79,169				78,600
Loss per diluted share, before discontinued operations attributable to TETRA stockholders	$	(0.16	)		$	(0.19	)		$	(1.69	)		$	(1.53	)		$	(1.23	)
Average diluted shares	124,101			^{(1), (2)}	114,499			^{(1), (2)}	87,286			^{(1), (2)}	79,169			⁽¹⁾	78,600			⁽¹⁾


⁽¹⁾	For the years ended December 31, 2018, 2017, 2016, 2015, and 2014, 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⁾	For the years ended December 31, 2018, 2017, 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.



	December 31,
	2018		2017		2016		2015		2014
	(In Thousands)
Balance Sheet Data
Working capital	$	200,340	$	164,640	$	158,906	$	168,783	$	121,476
Total assets	1,385,527		1,308,614		1,315,540		1,636,202		2,063,522
Long-term debt, net	815,560		629,855		623,730		853,228		826,095
Other long-term liabilities	27,775		29,621		30,481		21,459		23,563
CCLP Series A Preferred Units	27,019		61,436		77,062		—		—
Warrants liability	2,073		13,202		18,503		—		—
Total equity	312,749		352,561		400,466		514,180		765,601

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.

Following the acquisition of SwiftWater and the disposition of the Offshore Division during the three month period ended March 31, 2018, we reorganized our reporting segments and now manage our operations through three divisions: Completion Fluids & Products, Water & Flowback Services, and Compression. Our Completion Fluids & Products Division was previously reported as our Fluids Division, and included our water management services operations. Following the acquisition of SwiftWater in February 2018, our expanded water management operations are now included with our production testing operations as part of our Water & Flowback Services Division. The operations of our previous Offshore Division, consisting of our previous Offshore Services and Maritech segments, are now reported as discontinued operations following their disposal in March 2018.

Business Overview

Our consolidated results of operations for the year ended December 31, 2018 reflected the strong improvement in demand for the products and services of many of our businesses. A strong increase in demand for compression equipment and services resulted in our Compression Division contributing a $143.1 million increase to consolidated revenues compared to 2017 and generating improved gross profit compared to the prior year primarily as a result of improved pricing. Improved onshore domestic rig counts and completion activity during 2018, along with the acquisition of SwiftWater Energy Services, LLC ("SwiftWater") during February 2018, led to the growth of our Water & Flowback Services Division, which reported increased revenues of $131.5 million compared to 2017, along with significantly increased gross profit compared to the prior year. Our Completion Fluids & Products Division reported revenues during 2018 consistent with 2017 levels, despite benefiting in the prior year from a TETRA CS Neptune^® completion fluids project, as international activity increased compared to the prior year. Future profitability levels of our Completion Fluids & Products Division will continue to be affected by the timing of future TETRA CS Neptune projects. On a consolidated basis, the increased revenues and gross profit during 2018 were partially offset by increased general and administrative cost levels, reflecting the overall growth in our operations, as well as by increased interest expense, primarily from increased borrowings by our CSI Compressco LP subsidiary ("CCLP"). The improved 2018 results occurred despite the impact of decreased oil prices during the fourth quarter of 2018. We are monitoring the 2019 spending plans of our customers as a result of the current reduced oil prices, and if oil prices decrease further during 2019, demand for many of our products and services could be negatively impacted. The consolidated net loss for 2018 includes the impact of the loss attributed to the March 2018 disposal of our former Offshore Division. That disposition increased our ability to focus on the growth of our core businesses.

Our consolidated cash provided by operating activities during the year ended December 31, 2018 decreased by $18.0 million, or 27.9%, compared to the prior year. This decrease in consolidated cash provided by operating activities was driven primarily by increased working capital, particularly accounts receivable and inventory, driven by the growth of certain of our businesses, and despite increased operating profitability. We and CCLP continue to maintain our efforts to manage working capital. Consolidated capital expenditures were $141.9 million during the year ended December 31, 2018, and included $104.0 million of capital expenditures by our Compression Division, compared to $51.9 million of consolidated capital expenditures during the prior year, which included $25.9 million by our Compression Division. Capital expenditure levels continue to be monitored carefully for each of our businesses, including CCLP, to insure that capital investments are only made for the most attractive growth opportunities. A majority of CCLP capital expenditures during 2018 were funded by additional long-term debt borrowings. As obtaining additional financing is challenging in the current debt and equity market environment, growth capital expenditures by CCLP during 2019 are expected to be primarily funded by available cash, expected cash provided by operating activities, and up to $15.0 million of new compression services equipment to be purchased by us, whereby we will lease the equipment to CCLP under a finance lease.

During 2018, we continued our focus on enhancing our debt structure, as well as the debt structure of CCLP. During the third quarter of 2018, we entered into a new credit agreement (the “Term Credit Agreement”) which provided an initial loan in the amount of $200 million and the availability of additional loans, subject to the terms of the Term Credit Agreement, up to an aggregate amount of $75 million for acquisitions. In addition, during the third quarter of 2018, we entered into an asset-based lending credit agreement (the “ABL Credit Agreement”)

that provides for a senior secured revolving credit facility of up to $100 million, subject to a borrowing base. As of December 31, 2018, subject to compliance with the covenants, borrowing base, and other provisions of the agreement that may limit borrowings, TETRA had an availability of $47.6 million under this agreement. Proceeds from both the Term Credit Agreement and ABL Credit Agreement were used to repay our 11% Senior Secured Note due November 5, 2022 (the "11% Senior Notes") and repay all outstanding borrowings and obligations under our then existing bank credit agreement. Both the note-purchase agreement related to the 11% Senior Note and the then existing bank credit agreement were terminated. To fund its growth, during the first half of 2018, CCLP enhanced its long-term debt structure through the issuance of the CCLP 7.50% Senior Secured First Lien Notes due 2025 (the "CCLP Senior Secured Notes"), repaying and terminating CCLP's prior credit facility (the "CCLP Prior Credit Facility"), and entering into a Loan and Security Agreement (the "CCLP Credit Agreement"), which provides up to $50.0 million to fund ongoing working capital and letter of credit needs and for general business purposes. As of December 31, 2018, and subject to compliance with the covenants, borrowing base, and other provisions of the agreements that may limit borrowings under the CCLP Credit Agreement, CCLP had availability of $27.1 million. As of March 1, 2019, no borrowings are outstanding under the ABL Credit Agreement or the CCLP Credit Agreement. Key objectives associated with our separate capital structures include the ongoing management of amounts outstanding and available under our ABL Credit Agreement and Term Credit Agreement, and the CCLP Credit Agreement.

We do not analyze or manage our capital structure on a consolidated basis, as there are no cross default provisions, cross collateralization provisions, or cross guarantees between CCLP's long-term debt and TETRA's long-term debt.

Approximately $633.0 million of our consolidated debt balance carrying value is owed by CCLP and serviced by CCLP's existing cash balances and cash provided by CCLP's operations (less its capital expenditures) and $343.2 million of which is secured by certain assets of CCLP. The following table provides condensed consolidating balance sheet information reflecting our net assets, excluding CCLP ("TETRA"), and CCLP's net assets that service our respective capital structures.



	December 31, 2018
Condensed Consolidating Balance Sheet	TETRA		CCLP		Eliminations			Consolidated
	(In Thousands)
Cash, excluding restricted cash	$	24,180	$	15,858	$	—		$	40,038
Affiliate receivables	3,517		—		(3,517		)	—
Assets of discontinued operations	1,354				—			1,354
Other current assets	223,410		135,889					359,299
Property, plant and equipment, net	212,612		641,319		—			853,931
Other assets, including investment in CCLP	29,162		33,678		68,065			130,905
Total assets	$	494,235	$	826,744	$	64,548		$	1,385,527

Affiliate payables	$	—	$	3,517	$	(3,517	)	$	—
Current portion of long-term debt	—		—		—			—
Other current liabilities	105,370		90,836		—			196,206
Long-term debt, net	182,547		633,013		—			815,560
CCLP Series A Preferred Units	—		30,900		(3,881		)	27,019
Warrant liability	2,073		—		—			2,073
Other non-current liabilities	26,700		1,075					27,775
Total equity	173,400		67,403		71,946			312,749
Total liabilities and equity	$	494,235	$	826,744	$	64,548		$	1,385,527

TETRA’s debt is serviced by existing cash balances and cash provided from operating activities (excluding CCLP) and the distributions we receive from CCLP in excess of our cash capital expenditures (excluding CCLP). During the year ended December 31, 2018, consolidated cash provided from operating activities was $46.6 million, which included approximately $30.1 million generated by CCLP. During 2018, we received $12.1 million from CCLP as our share of CCLP distributions. In December 2018,CCLP announced a significant reduction, for a period of up to four quarters, in the level of cash distributions to its common unitholders, including us, reducing the distribution to $0.04 per common unit per year. CCLP intends to use the cash savings from the reduced distributions to redeem the remaining CCLP Preferred Units outstanding. Despite this reduced level of cash distributions from CCLP to us, we believe that current increased levels of operating activity will allow us and CCLP to continue to meet our respective financial obligations and fund our respective future growth plans as needed.

Future demand for our products and services depends primarily on activity in the oil and natural gas exploration and production industry, particularly including the level of expenditures for the exploration and production of oil and natural gas reserves, and natural gas compression infrastructure. The future growth of certain of our businesses is dependent on improved future pricing levels of oil and natural gas. When oil and natural gas prices increase, we believe that 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 the continuing exploitation and development of shale reservoirs; and


•	increases in selected international oil and gas exploration and development activities.

Our Completion Fluids & Products Division generates revenues and cash flows by manufacturing and marketing clear brine fluids ("CBFs"), 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 Completion Fluids & Products 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. Completion Fluids & Products Division revenues decreased $0.4 million during 2018 compared to 2017, primarily due to product and services sales revenues during 2017 associated with a TETRA CS Neptunecompletion fluid project, and despite improving demand for CBFs and associated product sales in the U.S. Gulf of Mexico during 2018. While offshore rig counts remain low, we have seen an increase in demand from our customers. In addition, international offshore fluid sales and onshore manufactured product sales increased compared to the prior year.

Our Water & Flowback Services Division provides oil and gas operators with comprehensive water management services as well as 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, Mexico, and Canada, as well as in oil and gas basins in certain regions in South America, Africa, Europe, the Middle East, and Australia. The Water & Flowback Services Division’s operations are generally driven by the demand for natural gas and oil and the resulting levels of drilling and completion activities in the markets that the Water & Flowback Services Division serves. Many of the markets served by the Water & Flowback Services Division are characterized by high lifting costs for oil and natural gas, such as in certain unconventional shale gas and oil reservoirs located in certain basins in the U.S., Canada, and certain other international markets. North American onshore rig counts increased during 2018 compared to the prior year. The Water & Flowback Services Division’s revenues increased by $131.5 million in 2018 compared to 2017, due to increased activity in certain domestic and international markets and due to the impact of acquired water management services businesses, particularly from the February 28, 2018 acquisition of SwiftWater. Onshore U.S. activity levels in certain markets have reflected increased rig counts compared to the prior year, although customer demand for services during the fourth quarter of 2018 has been reduced due to the recent decline in oil prices.

Our Compression Division, through CCLP, generates revenues and cash flows by providing compression services and equipment for natural gas and oil production, gathering, transportation, processing, and storage. The Compression Division's equipment sales business includes the fabrication and sale of standard compressor packages and custom-designed compressor packages designed and fabricated at the Compression Division's facilities. The Compression Division's aftermarket business provides a wide range of services including operation, maintenance, overhaul and reconfiguration services 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 foreign countries, including Mexico, Canada and Argentina. Compression Division revenues increased $143.1 million in 2018 as compared to 2017, primarily due to a significant increase in revenues from sales of compressor equipment, as well as increased compression and related services revenues. The overall utilization of the Compression Division's compression fleet has improved sequentially for the past two years, reflecting increasing demand for compression services.

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 estimates on historical experience, available information, and various other assumptions that we believe are reasonable. We periodically evaluate these estimates and judgments, including those related to potential impairments of long-lived assets (including goodwill), the fair value of financial instruments (our outstanding stock warrants (the "Warrants") and CCLP Preferred Units), the collectability of accounts receivable, the current cost of future asset retirement obligations, the allocation of acquisition purchase price consideration and the fair value of contingent acquisition consideration. Note B – "Summary of Significant Accounting Policies” to the Consolidated Financial Statements contains the accounting policies governing each of these matters. The fair values of portions of our total assets and liabilities are measured using significant unobservable inputs. The combination of these factors forms the basis for our judgments made about the carrying values of assets and liabilities that are not readily apparent from other sources. These judgments and estimates 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.

Fair Value of Financial Instruments

During 2016, we issued the Warrants and CCLP issued the CCLP Preferred Units as part of equity offerings to generate proceeds that were used to reduce long-term debt outstanding. The Warrants are accounted for as a derivative liability in accordance with Financial Accounting Standards Board ("FASB") Accounting Standards Codification ("ASC") 815 "Derivatives and Hedging" and therefore they are classified as a long-term liability on our consolidated balance sheet at their fair value. The CCLP Preferred Units may be settled using a variable number of common units, and therefore the fair value of the CCLP Preferred Units is classified as a long-term liability on our consolidated balance sheet in accordance with ASC 480 "Distinguishing Liabilities and Equity." Changes in fair value of these financial instruments during each quarterly period are charged to earnings in the accompanying consolidated statements of operations. The Warrants are valued using the Black Scholes option valuation model that includes estimates of the volatility of the Warrants based on their trading prices. The CCLP Preferred Units are valued using market information related to debt instruments, the trading price of the CCLP common units, and lattice modeling techniques. The fair values of the Warrants and the CCLP Preferred Units will generally increase or decrease with the trading price and volatility of our common stock and the CCLP common units, respectively. Increases (or decreases) in the fair value of these financial instruments will increase (decrease) the associated liability, resulting in future adjustments to earnings for the associated valuation losses (gains), and resulting in future volatility of our earnings during the period the financial instruments are outstanding. These estimates used in the calculated fair values of these financial instruments may not be accurate. As of December 31, 2018, the estimated fair value of the Warrants was $2.1 million, and the $11.1 million change in fair value during the year was credited to earnings during the period. As of December 31, 2018, the estimated fair value of the CCLP Preferred Units was $27.0 million, and the $0.7 million change in fair value during the year was credited to earnings during the period.

Acquisition Purchase Price Allocations

We account for acquisitions of businesses using the purchase method, which requires the allocation of the purchase price consideration based on the fair values of the assets and liabilities acquired. We estimate the fair values of the assets and liabilities acquired using accepted valuation methods, and, in many cases, such estimates are based on our judgments as to the future operating cash flows expected to be generated from the acquired assets throughout their estimated useful lives. Following the February 28, 2018 acquisition of SwiftWater and the December 6, 2018 acquisition of JRGO, we have accounted for the various assets (including intangible assets) and liabilities acquired based on our estimate of their fair values. Goodwill represents the excess of acquisition purchase price consideration over the estimated fair values of the net assets acquired. Our estimates and judgments of the fair value of acquired businesses are imprecise, and the use of inaccurate fair value estimates could result in the improper allocation of the acquisition purchase price consideration to acquired assets and liabilities, which could result in asset impairments, the recording of previously unrecorded liabilities, and other financial statement adjustments. The difficulty in estimating the fair values of acquired assets and liabilities is increased during periods of economic uncertainty.

Contingent Consideration

As part of the purchase of SwiftWater we may be required to pay additional contingent consideration, in an aggregate amount of up to $15.0 million, calculated on EBITDA and revenue of the combined water management business of SwiftWater and our pre-existing operations in the Permian Basin in respect of the period from January 1, 2018 through December 31, 2019. The contingent consideration may be paid in cash or shares of our common stock, at our election. The fair value of the contingent consideration is based on a probability simulation utilizing forecasted revenues and EBITDA of the water management business of SwiftWater and all of our pre-existing operations in the Permian Basin (a Level 3 fair value measurement). During the period from the closing date to December 31, 2018, the estimated fair value for the liabilities associated with the contingent purchase price consideration increased to $11.0 million, resulting in $3.4 million being charged to other (income) expense, net, during the year ended December 31, 2018. As part of the purchase of JRGO, we may be required to pay additional contingent consideration, in an aggregate amount of up to $1.5 million, during 2019 based on JRGO's performance during the fourth quarter of 2018.

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 2018, primarily as a result of the decreased expected future cash flows from a specific customer contract, we recorded consolidated impairments and other charges of $3.6 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. We perform the annual test of goodwill impairment as of the last day of the fourth quarter of each year. As of December 31, 2018, consolidated goodwill consists of $25.9 million attributed to our Water Management reporting unit, included as part of our Water & Flowback Services Division. 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 units. If the estimated fair value is higher than the recorded net book value, no impairment is deemed to exist and no further testing is required. If, however, the carrying amount of the reporting unit exceeds its estimated fair value, an impairment loss is calculated by comparing the carrying amount of the reporting unit’s goodwill to our estimated implied fair value of that goodwill. Our estimates of reporting unit fair value, when required, 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 each business and our judgment as to how these estimated cash flows translate into each business’ estimated fair value. These estimates and judgments are affected by numerous factors, including the general economic environment at the time of our assessment, which affects our overall market capitalization. If we overestimate the fair value of our reporting units, the balance of our goodwill asset may be overstated. Alternatively, if our estimated reporting unit fair values are understated, impairments might be recognized unnecessarily or in excess of the appropriate amounts.

During the fourth quarter of 2018, global oil prices decreased significantly. An accompanying decrease in our common stock price during the fourth quarter of 2018 has also indicated an overall reduction in our market capitalization. As part of our internal annual business outlook for each of our reporting units that we performed during the fourth quarter, we considered changes in the global economic environment that affected 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), the only reporting unit with goodwill as of December 31, 2018, we updated our assessment of the future cash flows, applying expected long-term growth rates, discount rates, and terminal values that we consider reasonable for the reporting unit. We calculated a present value of the cash flows for the Water Management reporting unit to arrive at an estimate of fair value using a combination of the income approach and market approach. Based on these assumptions, we determined that the fair value of the Water Management reporting unit exceeded its carrying value, which includes approximately $25.9 million of goodwill, by approximately 30%. Specific uncertainties affecting the estimated fair value of our Water Management reporting unit includes the impact of competition, prices of oil and natural gas, and future overall activity levels in the regions in which we operate, the activity levels of our significant customers, and other factors affecting the rate of future growth of this reporting unit. These factors will continue to be reviewed and assessed going forward. Negative developments with regard to these factors could have a further negative effect on the fair value of the Water Management reporting unit.

Throughout 2016, lower oil and natural gas commodity prices resulted in a decreased demand for many of the products and services of each of our reporting units. Specifically to our Compression Division, which is one reporting unit, demand for low-horsepower wellhead compression services and for sales of compressor equipment decreased significantly. During the first quarter of 2016, as the market for services of CCLP continued to decline, the market capitalization of CCLP dropped significantly from December 31, 2015. Accordingly, the fair value, including the market capitalization for CCLP, for the Compression reporting unit was less than its carrying value as of March 31, 2016.

Our Water & Flowback Services Division has two reporting units; Production Testing and Water Management. For our Production Testing reporting unit, market activity continued to decrease during the first quarter of 2016. As a result, the fair value of the Production Testing reporting unit was also less than its carrying value as of March 31, 2016.

After making the hypothetical purchase price adjustments as part of the second step of the goodwill impairment test as of March 31, 2016, we concluded that a full impairment of $92.3 million of remaining recorded goodwill for our Compression reporting unit and a full impairment of $13.9 million of the remaining recorded goodwill for our Production Testing reporting unit (included in our Water & Flowback Services Division) was required as of March 31, 2016.

Income Taxes

We are a U.S. company and are subject to income taxes in the U.S. We also operate in a number of countries under many legal forms. Our operations are taxed on various bases, including actual income before taxes, deemed profits (which are generally determined using a percentage of revenue rather than profits) and withholding taxes based on revenue. Determination of taxable income in any jurisdiction requires the interpretation of the applicable tax laws and regulations and the use of estimates and assumptions regarding significant future events such as the amount, timing, and character of deductions, permissible revenue recognition methods under the applicable tax laws, and the sources and character of income and tax credits.

We provide for income taxes by taking into account the differences between the financial statement treatment and tax treatment of certain transactions. Deferred tax assets and liabilities are recognized for the anticipated future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis amounts. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect of a change in tax rates is recognized as income or expense in the period that includes the enactment date. Management must make certain assumptions regarding whether tax differences are permanent or temporary and must estimate the timing of their reversal, and whether taxable operating income in future periods will be sufficient to fully recognize any gross deferred tax assets.

We establish valuation allowances to reduce deferred tax assets when it is more likely than not that some portion or all of the deferred tax assets will not be realized. In determining the need for valuation allowances, management has considered and made judgments and estimates regarding estimated future taxable income and ongoing prudent and feasible tax planning strategies. Changes in state, federal, and foreign tax laws, as well as changes in our financial condition, could affect these estimates.

In addition, we maintain liabilities for estimated tax exposures and uncertainties in jurisdictions where we operate. The annual tax provision includes the impact of income tax provisions and benefits for changes to liabilities that we consider appropriate, as well as related interest and penalties. We consider many factors when evaluating and estimating income tax uncertainties. These factors include an evaluation of the technical merits of the tax position as well as the amounts and probabilities of the outcomes that could be realized upon ultimate settlement. The actual resolution of those uncertainties will inevitably differ from those estimates, and such differences may be material to the financial statements. We believe that an appropriate liability has been established for the estimated exposures associated with these uncertainties under the guidance in ASC 740 “Income Taxes.” However, the actual resolution of those uncertainties will inevitably differ from those estimates, and such differences may be material to our consolidated financial statements.

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.

2018 Compared to 2017

Consolidated Comparisons



	Year Ended December 31,						Period to Period Change
	2018			2017			2018 vs. 2017			% Change
	(In Thousands, Except Percentages)
Revenues	$	998,775		$	723,098		$	275,677		38.1	%
Gross profit	162,298			108,390			53,908			49.7	%
Gross profit as a percentage of revenue	16.2		%	15.0		%
General and administrative expense	132,446			115,414			17,032			14.8	%
General and administrative expense as a percentage of revenue	13.3		%	16.0		%
Interest expense, net	70,946			57,246			13,700			23.9	%
Gain on sale of assets	(729		)	—			(729		)
Warrants fair value adjustment	(11,129		)	(5,301		)	(5,828		)
CCLP Series A Preferred fair value adjustment	(733		)	(2,975		)	2,242
Litigation arbitration award income	—			(12,816		)	12,816
Other (income) expense, net	7,923			865			7,058
Loss before taxes and discontinued operations	(36,426		)	(44,043		)	7,617
Loss before taxes and discontinued operations as a percentage of revenue	(3.6		)%	(6.1		)%
Provision for income taxes	6,299			751			5,548
Loss before discontinued operations	(42,725		)	(44,794		)	2,069
Loss from discontinued operations (including 2018 loss on disposal of $33.8 million), net of taxes	(41,515		)	(17,389		)	(24,126		)
Net loss	(84,240		)	(62,183		)	(22,057		)
Loss attributable to noncontrolling interest	22,623			23,135			(512		)
Net loss attributable to TETRA stockholders	$	(61,617	)	$	(39,048	)	$	(22,569	)

Consolidated revenues for 2018 increased compared to the prior year due to increased revenues in our Compression and Water & Flowback Services Divisions. Compression Division revenues increased by $143.1 million driven by increased new compressor equipment sales activity and improved pricing. Our Water & Flowback Services Division revenues increased by $131.5 million due to increased activity in certain domestic and international markets and the February 28, 2018 acquisition of SwiftWater. See Divisional Comparisons section below for additional discussion.

Consolidated gross profit increased during 2018 compared to the prior year due to the increased revenues of our Water & Flowback Services and Compression Divisions. The increased gross profit from these divisions more than offset the lower gross profit of our Completion Fluids & Products Division, which resulted from the mix of products and services compared to the prior year. Despite the improvement in activity levels of certain of our businesses, offshore activity levels remain flat and the impact of pricing pressures continues to challenge profitability in certain onshore markets. Operating expense levels reflect the increase in consolidated revenues, although we remain aggressive in managing operating costs and minimizing increased headcount.

Consolidated general and administrative expenses increased during 2018 compared to the prior year, primarily due to $10.1 million of increased salary related expenses, $3.3 million of insurance and other general expenses, $2.7 million of increased professional services fees, and $0.9 million of increased bad debt and marketing expenses. Due to the increased consolidated revenues discussed above, general and administrative expense as a percentage of revenues decreased compared to the prior year.

Consolidated interest expense, net, increased in 2018 compared to the prior year primarily due to increased Compression Division interest expense. Compression Division interest expense increased due to higher CCLP outstanding debt balances and a higher interest rate on the CCLP Senior Secured Notes, a portion of the proceeds of which were used to repay the balance outstanding under the CCLP Prior Credit Facility. Increased interest expense is expected to continue compared to prior years. Corporate interest expense also increased due to 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 2018 and 2017 includes $4.3 million and $4.7 million, respectively, of finance cost amortization.

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 may be settled using a variable number of CCLP common units, and therefore the fair value of the CCLP Preferred Units is classified as a long-term liability on our consolidated balance sheet in accordance with ASC 480. Because the CCLP Preferred Units are convertible into CCLP common units at the option of the holder, the fair value of the CCLP Preferred Units will generally increase or decrease with the trading price of the CCLP common units, and this increase (decrease) in CCLP Preferred Unit fair value will be charged (credited) to earnings, as appropriate, resulting in future volatility of our earnings during the period the CCLP Preferred Units are outstanding.

In January 2017, our Completion Fluids & Products Division collected $12.8 million from a successful legal arbitration award, resulting in a credit to earnings. See Commitments and Contingencies - Litigation section below for additional discussion.

Consolidated other (income) expense, net, was $7.9 million of expense during 2018 compared to $0.9 million of expense during the prior year, primarily due to $3.4 million of increased expense associated with the remeasurement of the contingent purchase price consideration for SwiftWater and $3.5 million of increased expense related to the unamortized deferred financing costs charged to earnings as a result of the termination of the CCLP Prior Credit Facility. These increased expenses were partially offset by increased foreign currency gains.

Our consolidated provisions for income taxes during 2018 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, 2018 of negative 17.3% 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.

We applied the guidance in Staff Accounting Bulletin 118 (“SAB 118”) when accounting for the enactment-date effects of the Act. During the 4th quarter of 2017, we recorded our best estimate of the impact of the Act in our year-end income tax provision in accordance with our understanding of the Act and guidance available and as a result recorded income tax expense of $54.1 million. This income tax expense was fully offset by a decrease in the valuation allowance previously recorded on our deferred tax assets. As such, the Act resulted in no net tax expense. As of December 31, 2018, we completed our accounting analysis for all of the enactment-date income tax effects and reduced our December 31, 2017 provisional amount by $2.5 million. The decrease in the income tax expense was fully offset by an increase in the valuation allowance. As such, the Act resulted in no net tax expense.

In January 2018, the FASB released guidance on the accounting for tax on the global intangible low-taxed income ("GILTI") provisions of the Act. The GILTI provisions impose a tax on foreign income in excess of a deemed return on tangible assets of foreign corporations. The guidance indicates that either accounting for deferred taxes related to GILTI inclusions or to treat any taxes on GILTI inclusions as period costs are both acceptable methods subject to an accounting policy election. As of December 31, 2017, we had not yet completed our assessment or elected an accounting policy to either recognize deferred taxes for basis differences expected to reverse as GILTI

or to record GILTI as period costs if and when incurred. After further consideration in 2018, we have elected to account for GILTI as a period cost in the year the tax is incurred. See "Note H - Income Taxes" contained in the Notes to Consolidated Financial Statements for the effect on our 2018 tax provision.

Divisional Comparisons

Completion Fluids & Products Division



	Year Ended December 31,						Period to Period Change
	2018			2017			2018 vs. 2017			% Change
	(In Thousands, Except Percentages)
Revenues	$	257,408		$	257,851		$	(443	)	(0.2	)%
Gross profit	48,675			71,022			(22,347		)	(31.5	)%
Gross profit as a percentage of revenue	18.9		%	27.5		%
General and administrative expense	18,830			19,661			(831		)	(4.2	)%
General and administrative expense as a percentage of revenue	7.3		%	7.6		%
Interest (income) expense, net	(599		)	(53		)	(546		)
Litigation arbitration award income	—			(12,816		)	12,816
Other (income) expense, net	(179		)	339			(518		)
Income before taxes	$	30,623		$	63,891		$	(33,268	)	(52.1	)%
Income before taxes as a percentage of revenue	11.9		%	24.8		%

The decrease in Completion Fluids & Products Division revenues during 2018 compared to the prior year was due to $16.7 million of decreased service revenues, largely due to a reduction in completion services activity associated with a 2017 TETRA CS Neptunecompletion fluid project. This decrease was offset by $16.3 million of increased product sales revenue, attributed to increased manufactured products sales and international CBF product sales, partially offset by reduced CBF product sales revenues in the U.S. Gulf of Mexico.

Completion Fluids & Products Division gross profit during 2018 decreased compared to the prior year primarily due to the profitability associated with the mix of CBF products and services, particularly for offshore completion fluids products. 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.

The Completion Fluids & Products Division reported a decrease in pretax earnings during 2018 compared to the prior year primarily due to the reduction in gross profit discussed above and due to the collection of a successful legal arbitration award of $12.8 million during January 2017 that was credited to earnings. Completion Fluids & Products Division administrative cost levels decreased compared to the prior year, primarily due to $2.0 million of decreased salary and employee related expenses and $0.2 million of decreased insurance and other general expenses. These decreases were partially offset by $1.1 million of increased legal and professional fees and $0.3 million of increased bad debt expense. The Completion Fluids & Products Division continues to review opportunities to further reduce its administrative costs. The Division reported other income, net, during 2018 compared to other expense, net, during the prior year period primarily due to contract income recorded during the current year.

Water & Flowback Services Division



	Year Ended December 31,						Period to Period Change
	2018			2017			2018 vs. 2017		% Change
	(In Thousands, Except Percentages)
Revenues	$	303,072		$	171,621		$	131,451	76.6	%
Gross profit	55,247			2,319			52,928		2,282.4	%
Gross profit as a percentage of revenue	18.2		%	1.4		%
General and administrative expense	23,640			16,155			7,485		46.3	%
General and administrative expense as a percentage of revenue	7.8		%	9.4		%
Interest (income) expense, net	—			(296		)	296
Other (income) expense, net	2,895			(724		)	3,619
Income (loss) before taxes	$	28,712		$	(12,816	)	$	41,528	324.0	%
Income (loss) before taxes as a percentage of revenue	9.5		%	(7.5		)%

Water & Flowback Services Division revenues increased during 2018 compared to the prior year primarily due to increased water management services activity. Water management and flowback service revenues increased $142.1 million during 2018 compared to the prior year primarily resulting from the acquisition of SwiftWater and increased completion activity. We estimate that approximately $95.2 million of the water management services revenue increase was generated from the operations of SwiftWater, which was acquired on February 28, 2018. Product sales revenue decreased by $10.6 million, as there was an international equipment sale in the prior year. We continue to focus on expanding our Water & Flowback Services Division equipment asset fleet, particularly in selected markets, which is expected to generate increased revenues going forward.

The Water & Flowback Services Division reflected increased gross profit during 2018 compared to the prior year due to the increase in revenues and improving customer pricing levels. This improvement was also due to the impact of a $2.9 million long-lived asset impairment during 2018 compared to $14.9 million of long-lived asset impairments during 2017. Customer pricing continues to be challenging due to excess availability of equipment in certain markets. The Water & Flowback Services Division continues to monitor its cost structure, minimizing increased costs despite increasing activity levels.

The Water & Flowback Services Division reported pretax income compared to a pretax loss during the prior year, primarily due to the improvement in gross profit described above. General and administrative expenses increased primarily due to SwiftWater operations, with increased wage and benefit expenses of $6.2 million, increased general expenses of $0.4 million, increased professional fees of $0.4 million, and $0.5 million of increased bad debt and consulting fees. Other expense, net, was recorded during the year primarily due to $3.4 million of increased expense associated with the remeasurement of the contingent purchase price consideration for SwiftWater and increased foreign currency losses.

Compression Division



	Year Ended December 31,						Period to Period Change
	2018			2017			2018 vs. 2017		% Change
	(In Thousands, Except Percentages)
Revenues	$	438,673		$	295,587		$	143,086	48.4	%
Gross profit	59,017			35,114			23,903		68.1	%
Gross profit as a percentage of revenue	13.5		%	11.9		%
General and administrative expense	39,544			33,442			6,102		18.2	%
General and administrative expense as a percentage of revenue	9.0		%	11.3		%
Interest (income) expense, net	51,905			42,082			9,823
CCLP Series A Preferred fair value adjustment	(733		)	(2,975		)	2,242
Other (income) expense, net	2,098			(189		)	2,287
Loss before taxes	$	(33,797	)	$	(37,246	)	$	3,449	(9.3	)%
Loss before taxes as a percentage of revenue	(7.7		)%	(12.6		)%

Compression Division revenues increased during 2018 compared to the prior year due to a $98.2 million increase in product sales revenues, due to a higher number of new compressor equipment sales compared to the prior year. Demand for new compressor equipment continues to increase, and the current new equipment sales backlog has increased significantly compared to the prior year period. Cumulative new equipment sales orders added to our backlog during 2018 were $188 million. New equipment sales orders generally take less than 12 months to build and deliver. In addition, 2018 revenues reflect a $44.9 million increase in service revenues from compression and aftermarket services operations. This increase in service revenues was primarily due to increasing demand for compression services, as reflected by increased compression fleet utilization rates. Overall utilization of the Compression Division's compression fleet has improved sequentially for the past two years, led by increased utilization of the high- and medium-horsepower fleet.

Compression Division gross profit increased during 2018 compared to the prior year due to increased revenues discussed above. The increased compression fleet utilization rates have led to increases in customer contract pricing.

The Compression Division recorded a decreased pretax loss during 2018 compared to the prior year due to increased gross profit as discussed above. Interest expense increased compared to the prior year due to higher outstanding CCLP debt balances and a higher interest rate on the CCLP Senior Secured Notes, issued in March 2018, when compared to the CCLP Prior Credit Facility. In addition, other (income) expense, net, reflected an increased expense primarily due to $3.5 million of unamortized deferred financing costs charged to earnings as a result of the termination of the CCLP Prior Credit Facility offset by foreign currency gains and decreased income associated with insurance proceeds from the prior year. In addition, the CCLP Preferred Units fair value adjustment resulted in a decreased credit to earnings in 2018 as compared to the prior year. Changes in the fair value of the CCLP Preferred Units may generate additional volatility to our earnings going forward. General and administrative expense levels increased compared to the prior year, due to increased salary and employee-related expenses, including equity compensation, of $5.3 million, increased other general expenses of $1.6 million, and increased sales and marketing expenses of $0.2 million. These increases were offset by decreased professional fees of $1.0 million.

Corporate Overhead



	Year Ended December 31,						Period to Period Change
	2018			2017			2018 vs. 2017			% Change
	(In Thousands, Except Percentages)
Gross profit (loss) (primarily depreciation expense)	$	(658	)	$	(84	)	$	(574	)	(683.3	)%
General and administrative expense	50,431			46,156			4,275			9.3	%
Interest expense, net	19,640			15,513			4,127
Warrants fair value adjustment (income) expense	(11,128		)	(5,301		)	(5,827		)
Other (income) expense, net	2,374			1,269			1,105
Loss before taxes	$	(61,975	)	$	(57,721	)	$	(4,254	)	(7.4	)%

Corporate Overhead pretax loss increased during 2018 compared to the prior year. Interest expense increased due to increased borrowings. Corporate general and administrative expense increased primarily due to $2.3 million of increased professional fees, including $0.9 million of transaction costs, $1.5 million of increased general expenses, and $0.6 million of salary and employee-related expenses. Interest expense increased due to increased borrowings under 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. Other expense, net also increased, primarily due to $1.0 million of debt issuance fees pursuant to the new ABL Credit Agreement and the new Term Credit Agreement. These increases in expense were offset by the fair value adjustment of the outstanding Warrants liability in the current year resulting in a $5.8 million increased credit to earnings compared to the prior year.

2017 Compared to 2016

Consolidated Comparisons



	Year Ended December 31,						Period to Period Change
	2017			2016			2017 vs. 2016			% Change
	(In Thousands, Except Percentages)
Revenues	$	723,098		$	617,391		$	105,707		17.1	%
Gross profit	108,390			60,839			47,551			78.2	%
Gross profit as a percentage of revenue	15.0		%	9.9		%
General and administrative expense	115,414			108,422			6,992			6.4	%
General and administrative expense as a percentage of revenue	16.0		%	17.6		%
Goodwill impairment	—			106,205			(106,205		)
Interest expense, net	57,246			58,614			(1,368		)	(2.3	)%
Warrants fair value adjustment	(5,301		)	2,106			(7,407		)
CCLP Series A Preferred fair value adjustment	(2,975		)	4,404			(7,379		)
Litigation arbitration award income, net	(12,816		)	—			(12,816		)
Other (income) expense, net	865			4,308			(3,443		)
Loss before taxes and discontinued operations	(44,043		)	(223,220		)	179,177
Loss before taxes as a percentage of revenue	(6.1		)%	(36.2		)%
Provision (benefit) for income taxes	751			2,156			(1,405		)
Income (loss) from continuing operations	(44,794		)	(225,376		)	180,582
Loss from discontinued operations, net of taxes	(17,389		)	(14,017		)	(3,372		)
Net loss	(62,183		)	(239,393		)	177,210
Net (income loss attributable to noncontrolling interest	23,135			77,931			(54,796		)
Net income (loss) attributable to TETRA stockholders	$	(39,048	)	$	(161,462	)	$	122,414

Consolidated revenues for 2017 increased compared to the prior year primarily due to increased Water & Flowback Services revenues, which increased by $66.6 million, driven by increased onshore production testing and water management services activity. In addition, our Completion Fluids & Products Division also reported increased revenues compared to the prior year. Partially offsetting these increases, our Compression Division reported a $15.8 million decrease in revenues compared to the prior year, due to decreased demand for new compressor equipment in 2017 and pricing pressures for compression services, despite recent increases in compression fleet utilization. Challenging and competitive markets and activity levels continue to impact each of our businesses, although we continue to see indicators of improving demand for many of our products and services.

Consolidated gross profit increased significantly during 2017 compared to the prior year due to increased revenues and activity, particularly for the Completion Fluids & Products Division. Despite the improving demand for many of our products and services, the impact of pricing pressures continued to challenge the profitability of each of our businesses. While we remain aggressive in managing operating costs and maintaining reduced headcount, the results of each of our businesses reflect the impact of company-wide reinstatements during the first half of 2017 reversing wage and benefit reductions that were implemented during the first half of 2016.

Consolidated general and administrative expenses increased during 2017 compared to the prior year, primarily due to $10.7 million of increased salary related expenses and $2.2 million of insurance and other general expenses, partly offset by decreased professional services fees of $4.2 million and decreased bad debt and marketing expenses of $1.6 million. Due to the increased consolidated revenues discussed above, general and administrative expense as a percentage of revenues decreased compared to the prior year.

During the first quarter of 2016, we updated our test of goodwill impairment in accordance with the Financial Accounting Standards Board ("FASB") Accounting Standards Codification ("ASC") 350-20 "Goodwill" due to the decreases in the price of our common stock and the common unit price of CCLP. Continued decreased oil and natural gas prices had, and were expected to have, a continuing negative impact on industry drilling and capital expenditure activity, which affects the expected demand for products and services of each of our reporting units. Specifically, demand for our Compression Division's compression services and for sales of new compressor equipment had decreased significantly and was expected to continue to be decreased for the foreseeable future. Demand for our Water & Flowback Services Division's production testing services also had decreased as a result of decreased drilling and completion activity. This expected decreased demand, along with the decreases in the price of our common stock and the common unit price of CCLP, also caused an overall reduction in the fair values of each of our reporting units, particularly our Compression and Production Testing reporting units. As part of the test of goodwill impairment, we estimated the fair value of each of our reporting units, and determined, based on these estimated values, that impairments of the remaining goodwill of our Compression and Production Testing reporting units were necessary, primarily due to the market factors discussed above. Accordingly, during the first quarter of 2016, we recorded total impairment charges of $106.2 million associated with the goodwill of these reporting units. We did not record any goodwill impairment charges during 2017.

Consolidated interest expense, net, decreased in 2017 compared to the prior year primarily due to the decrease in Corporate interest expense, reflecting the decrease in long-term debt outstanding. Largely offsetting this decrease, Compression Division interest expense increased related to the paid in kind quarterly distributions on the CCLP Preferred Units. Interest expense during 2017 and 2016 includes $4.7 million and $4.1 million, respectively, of finance cost amortization.

Gain on sales of assets decreased during 2017 compared to the prior year primarily due to significant gains on sales of Water & Flowback Services Division assets during 2016.

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 the increase (or decrease) 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.

price of the CCLP common units, and this increase (decrease) in CCLP Preferred Unit fair value will be charged (credited) to earnings, resulting in future volatility of our earnings during the period the CCLP Preferred Units are outstanding.

Consolidated other (income) expense, net, was $0.9 million of expense during 2017 compared to $4.3 million of expense during 2016, with the improvement primarily due to $2.1 million of issuance costs from the CCLP Preferred Units which were issued during 2016, $1.8 million of unamortized deferred finance costs that were charged to earnings in 2016 as a result of the repayment of senior notes and senior secured notes, $1.0 million of decreased finance fees associated with warrants issued in 2016, $1.1 million of insurance recoveries and $0.9 million of increased foreign currency gains. Partially offsetting these decreases is $1.4 million of net gains on the extinguishment of certain CCLP 7.25% Senior Notes during 2016.

Our consolidated provision for income taxes during 2017 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, 2017 of negative 1.7% 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. Further, the effective tax rate during 2016 was negatively impacted by the nondeductible portion of our goodwill impairments recorded during the three month period ended March 31, 2016.

The Act was enacted on December 22, 2017, making significant changes to the Internal Revenue Code. Changes included, but were not limited to, a corporate tax rate decrease from 35% to 21% effective for tax years beginning after December 31, 2017, the transition of U.S. international taxation from a worldwide tax system to a territorial system, and a one-time transition tax on the mandatory deemed repatriation of cumulative foreign earnings as of December 31, 2017. We calculated our best estimate of the impact of the Act in our year end 2017 income tax provision. See Note H – "Income Taxes" contained in the Notes to Consolidated Financial Statements for the effect on our 2017 tax provision.

Divisional Comparisons

Completion Fluids & Products Division



	Year Ended December 31,						Period to Period Change
	2017			2016			2017 vs. 2016			% Change
	(In Thousands, Except Percentages)
Revenues	$	257,851		$	205,156		$	52,695		25.7	%
Gross profit	71,022			40,157			30,865			76.9	%
Gross profit as a percentage of revenue	27.5		%	19.6		%
General and administrative expense	19,661			22,673			(3,012		)	(13.3	)%
General and administrative expense as a percentage of revenue	7.6		%	11.1		%
Interest income, net	(53		)	(4		)	(49		)
Litigation arbitration award income	(12,816		)	—			(12,816		)
Other (income) expense, net	339			(254		)	593
Income before taxes	$	63,891		$	17,742		$	46,149		260.1	%
Income before taxes as a percentage of revenue	24.8		%	8.6		%

Increased Completion Fluids & Products Division revenues during 2017 compared to 2016 were primarily due to $49.3 million of increased product sales revenues attributed to increased CBFs and associated product sales

revenues in the U.S. Gulf of Mexico, including product sales associated with a TETRA CS Neptune completion fluid project during 2017. While offshore rig counts remain low, we have seen an increase in demand from our offshore customers. In addition, international offshore fluid sales and onshore manufactured product sales increased compared to the prior year. Service revenues increased $3.3 million, primarily due to increased offshore completion services associated with the U.S. Gulf of Mexico TETRA CS Neptune completion project.

Completion Fluids & Products Division gross profit during 2017 increased significantly compared to 2016 primarily due to the profitability associated with the mix of CBF products and services, particularly for offshore completion fluids products and increased revenues. Completion Fluids & Products Division profitability in future periods will continue to be affected by the mix of its products and services and the timing of TETRA CS Neptune completion projects.

The Completion Fluids & Products Division reported a significant increase in pretax earnings during 2017 compared to the prior year primarily due to the increased gross profit discussed above. In addition, pretax earnings also increased due to the collection of a successful legal arbitration award of $12.8 million during January 2017 that was credited to earnings. Completion Fluids & Products Division administrative cost levels decreased compared to 2016, primarily due to $3.7 million of decreased legal and professional fees, following the legal arbitration award. In addition, bad debt and consulting expenses decreased by $0.1 million. These decreases were partially offset by $0.8 million of increased wage and benefit related expenses. The Division reported other expense, net, during 2017 compared to other income, net, during the prior year period primarily due to increased foreign currency losses compared to the prior year.

Water & Flowback Services Division



	Year Ended December 31,						Period to Period Change
	2017			2016			2017 vs. 2016			% Change
	(In Thousands, Except Percentages)
Revenues	$	171,621		$	105,057		$	66,564		63.4	%
Gross profit (loss)	2,319			(16,586		)	18,905			(114.0	)%
Gross profit (loss) as a percentage of revenue	1.4		%	(15.8		)%
General and administrative expense	16,155			14,783			1,372			9.3	%
General and administrative expense as a percentage of revenue	9.4		%	14.1		%
Goodwill impairment	—			13,871			(13,871		)
Interest income, net	(296		)	(594		)	298
Other (income) expense, net	(724		)	(1,863		)	1,139
Loss before taxes	$	(12,816	)	$	(42,783	)	$	29,967		70.0	%
Loss before taxes as a percentage of revenue	(7.5		)%	(40.7		)%

Water & Flowback Services Division revenues increased during 2017 compared to the prior year primarily due to increased service revenues of $54.1 million during 2017 compared to 2016, reflecting increased water management services activity resulting from the impact of increased demand, reflecting the growth in domestic onshore rig count and activity in certain domestic and international markets. Onshore U.S. activity levels in certain markets, particularly the Permian Basin of Texas, have reflected the increased rig counts during the last half of 2017 compared to the prior year, although customer pricing levels in certain markets continue to be challenging due to excess availability of equipment. Water & Flowback Services revenues also increased during 2017 due to $12.4 million of product sales revenues associated with international equipment sales.

The Water & Flowback Services Division reported an increased gross profit during 2017 compared to a gross loss during 2016 due to the international equipment sales discussed above as well as due to the increased industry activity levels. This improvement was despite $14.9 million of long-lived asset impairments during 2017 compared to $6.4 million of long-lived asset impairments during the prior year.

The Water & Flowback Services Division reported a decreased pretax loss compared to the prior year, primarily due to the gross profit discussed above and due to a goodwill impairment recorded during the prior year.

General and administrative expenses increased compared to the prior year, primarily due to increased general expenses and increased salary and benefit expenses. Other income, net decreased primarily due to decreased foreign currency gains and decreased gains on disposal of assets.

Compression Division



	Year Ended December 31,						Period to Period Change
	2017			2016			2017 vs. 2016			% Change
	(In Thousands, Except Percentages)
Revenues	$	295,587		$	311,374		$	(15,787	)	(5.1	)%
Gross profit	35,114			37,681			(2,567		)	(6.8	)%
Gross profit as a percentage of revenue	11.9		%	12.1		%
General and administrative expense	33,442			36,199			(2,757		)	(7.6	)%
General and administrative expense as a percentage of revenue	11.3		%	11.6		%
Goodwill impairment	—			92,334			(92,334		)
Interest expense, net	42,082			38,055			4,027
CCLP Series A Preferred fair value adjustment	(2,975		)	5,036			(8,011		)
Other (income) expense, net	(189		)	2,384			(2,573		)
Loss before taxes	$	(37,246	)	$	(136,327	)	$	99,081		(72.7	)%
Loss before taxes as a percentage of revenue	(12.6		)%	(43.8		)%

Compression Division revenues decreased during 2017 compared to 2016 due to reductions in both compression and related services revenues and new compressor equipment sales revenues. The $10.7 million decrease in compression and related service revenues resulted primarily from the reduction in pricing for compression services, and was realized despite increased overall compression fleet utilization. Although overall utilization of the Compression Division's compression fleet has improved sequentially for five consecutive quarterly periods, demand for low-horsepower production enhancement compression services remains challenged. Revenues from sales of compressor equipment and parts during 2017 decreased $5.1 million compared to the prior year primarily due to decreased sales of new compressor equipment.

Compression Division gross profit decreased during 2017 compared to the prior year despite a $2.4 million insurance recovery in 2017 for equipment that was damaged in the prior year, and despite $10.2 million in impairments and other charges recorded during the prior year period. This decrease in gross profit was primarily due to compression services customer pricing pressures discussed above. Although some customer pricing still remains lower than early 2016 levels, pricing pressures have been easing, and pricing for compression services is expected to continue to improve going forward.

The Compression Division recorded a decreased pretax loss during 2017 compared to 2016 primarily due to the impact of goodwill impairment recorded during the prior year. In addition, the fair value adjustment of the CCLP Preferred Units was credited to earnings during 2017 compared to a charge to earnings in the prior year. Changes in the fair value of the CCLP Preferred Units may generate additional volatility to our earnings going forward. Also, general and administrative expense levels decreased compared to the prior year, mainly due to decreased professional fees of $1.0 million, decreased bad debt expense of $0.7 million, decreased salary related expenses of $0.5 million and decreased other expenses of $0.3 million. The Compression Division recorded other income, net, during 2017 compared to other expense, net, during the prior year due to $2.1 million of CCLP Preferred Units issuance costs that were expensed during the prior year, and due to $0.6 million of insurance recoveries credited to other income during 2017. These decreased expenses were partially offset by the decreased gross profit discussed above, and due to increased interest expense, net, compared to the prior year due to the expense associated with paid in kind quarterly distributions on the CCLP Preferred Units that were issued during the third quarter of 2016.

Corporate Overhead



	Year Ended December 31,						Period to Period Change
	2017			2016			2017 vs. 2016			% Change
	(In Thousands, Except Percentages)
Gross profit (loss) (primarily depreciation expense)	$	(84	)	$	(430	)	$	346		80.5	%
General and administrative expense	46,156			34,767			11,389			32.8	%
Interest expense, net	15,513			21,593			(6,080		)
Warrants fair value adjustment (income) expense	(5,301		)	2,106			(7,407		)
Other (income) expense, net	1,269			4,037			(2,768		)
Loss before taxes	$	(57,721	)	$	(62,933	)	$	5,212		8.3	%

Corporate Overhead pretax loss decreased during 2017 compared to the prior year, primarily due to the adjustment of the fair value of the outstanding Warrants liability that resulted in a $5.3 million credit to earnings during 2017 compared to a charge to earnings during 2016. In addition, interest expense, net, during 2017 decreased compared to the prior year reflecting the reduction in outstanding long-term debt following the June and December 2016 equity offerings, the proceeds from which were primarily used to retire long-term debt outstanding. In addition, other expense, net, decreased primarily due to $1.8 million of unamortized deferred finance costs that were charged to earnings pursuant to the repayment of senior notes and senior secured notes in the prior year. Corporate general and administrative expense increased primarily due to $9.8 million of increased salary, incentives and employee related expense, $1.9 million of increased general expenses, and $0.4 million of increased professional fees. The increased salary, incentives and employee related expenses include the impact of company-wide wage and salary reinstatements during the first half of 2017 and the discontinuation of the workweek reductions that were implemented during the first half of 2016, as well as the impact of severance expense during 2017. These increases were partially offset by $0.8 million of decreased consulting marketing fees.

Liquidity and Capital Resources

We reported decreased consolidated cash flows provided by operating activities during 2018 compared to the prior year. This decrease occurred despite improved profitability of our operations, due to increased working capital needs largely due to the timing of payments of accounts payable. We generated $46.6 million of consolidated operating cash flows during the year ended December 31, 2018, with CCLP providing $30.1 million of this consolidated total. We received $12.1 million of cash distributions from CCLP during the year ended December 31, 2018 compared to $14.2 million during the prior year. The amount of distributions we receive from CCLP is expected to decrease further in 2019, following CCLP's announcement in December 2018 of a significant reduction in distributions to its common unitholders, including us. As a result of the acquisition of SwiftWater, our operating cash flows increased during 2018, and such increase more than offset the decrease in operating cash flows following the March 2018 disposal of our Offshore Division. We believe that the capital restructuring steps we have taken during the past three years support our ability to meet our financial obligations and fund future growth as needed, despite current uncertain operating and financial markets.

We and CCLP are in compliance with all covenants of our respective debt agreements as of December 31, 2018. We have reviewed our financial forecasts for the twelve month period subsequent to March 4, 2019, which consider our debt covenant requirements. Based on our financial forecasts, which are based on current market conditions and certain operating and other business assumptions that we believe to be reasonable as of March 4, 2019, we believe that we will have adequate liquidity, earnings, and operating cash flows to fund our operations and debt obligations and maintain compliance with our debt covenants through at least the next twelve months. With regard to CCLP, also considering financial forecasts based on current market conditions as of March 4, 2019, CCLP believes that it will have adequate liquidity, earnings, and operating cash flows to fund its operations and debt obligations and maintain compliance with the covenants under its long-term debt agreements through at least the next twelve months.

Our consolidated sources and uses of cash during the year ended December 31, 2018, 2017, and 2016 are as follows:



	Year Ended December 31,
	2018			2017			2016
	(In Thousands)
Operating activities	$	46,586		$	64,595		$	55,659
Investing activities	(188,646		)	(47,897		)	(14,295		)
Financing activities	154,994			(21,336		)	(32,633		)

Because of the level of our consolidated debt, we believe it is important to consider our capital structure and CCLP's capital structure separately, as there are no cross default provisions, cross collateralization provisions, or cross guarantees between CCLP's debt and TETRA's debt. (See Financing Activities section below for a complete discussion of the terms of our and CCLP's respective debt arrangements.) Our consolidated debt outstanding has a carrying value of approximately $815.6 million as of December 31, 2018. However, approximately $633.0 million of this consolidated debt balance is owed by CCLP and is serviced from the cash balances and cash flows of CCLP, $343.2 million of which is secured by certain of CCLP's assets. Through our approximately 35% common unit ownership interest in CCLP and ownership of an approximately 1% general partner interest, we receive our share of the distributable cash flows of CCLP through its quarterly cash distributions. Approximately $15.9 million of the $40.0 million of the cash balance reflected on our consolidated balance sheet is owned by CCLP and is not available to us. In September 2018, we entered into the ABL Credit Agreement and Term Credit Agreement. In connection with the closing of these debt agreements, we used a portion of the proceeds to repay all outstanding borrowings and obligations under our then existing bank credit agreement and all outstanding indebtedness under the 11% Senior Note, and both the bank credit agreement and the note purchase agreement for the 11% Senior Note were then terminated. As of December 31, 2018, subject to compliance with the covenants, borrowing base requirements, and other provisions of the agreement that may limit borrowings, we had availability of approximately $47.6 million under the ABL Credit Agreement. Following the March 2018 issuance of the CCLP Senior Secured Notes, CCLP used a portion of the proceeds to repay the outstanding borrowings under the CCLP Prior Credit Facility, which was then terminated. In June 2018, CCLP entered into the CCLP Credit Agreement. As of December 31, 2018, and subject to compliance with the covenants, borrowing base requirements, and other provisions of the agreement that may limit borrowings under the CCLP Credit Agreement, CCLP had availability of $27.1 million. See CCLP Financing Activities below for further discussion.

Operating Activities

Consolidated cash flows provided by operating activities totaled $46.6 million during 2018 compared to $64.6 million during the prior year, a decrease of $18.0 million. Operating cash flows decreased despite improved operating profitability due to the use of cash for working capital changes, particularly related to the timing of payments of accounts payable. We have taken steps to aggressively manage working capital, including increased collection efforts. We continue to monitor customer credit risk and have historically focused on serving larger capitalized oil and gas operators and national oil companies. Cash utilized for increased inventory primarily relates to work in progress inventory for new compressor package sales by our Compression Division, and this increase was largely offset by advance funding by its customers.

Demand for the vast majority of our products and services is driven by oil and gas industry activity, which is affected by oil and natural gas pricing. With the increase in oil prices in early 2018, operating plans and capital expenditure levels of many of our oil and natural gas customers increased, benefiting certain of our operating segments with improved revenues and cash flows. The acquisition of SwiftWater provided additional revenues and operating cash flows during the year ended December 31, 2018, and, along with the acquisition of JRGO in December 2018, is expected to continue to do so going forward. Growth in completion activity compared to early 2017 has resulted in improved cash provided by operating activities of our Water & Flowback Services Division. The increased capital expenditure activity of our Compression Division customers has resulted in increased demand for compression services and equipment, and related increased revenues. The improved 2018 results were realized despite the impact of decreased oil commodity prices that occurred during the fourth quarter of 2018. We are monitoring the 2019 spending plans of our customers as a result of the current reduced oil prices, and if oil prices decrease further during 2019, demand for many of our products and services, and our associated operating cash

flows, could be negatively impacted. During early 2018, and despite increasing activity levels, our goal was to minimize growth to our operating and administrative headcount and continue to maintain a low cost structure for our businesses, particularly during the current period of volatile oil and natural gas prices.

As part of the sale of our Offshore Division in March 2018, Orinoco Natural Resources, LLC ("Orinoco") assumed all liabilities and obligations currently associated with our former Maritech subsidiary, including but not limited to all current and future decommissioning obligations related to properties owned or formerly owned by our Maritech subsidiary prior to its purchase by Orinoco.

Investing Activities

During 2018, the total amount of our net cash utilized on investing activities was $188.6 million. Total cash capital expenditures during 2018 were $141.9 million, which is net of $10.1 million cost of equipment sold. Our Completion Fluids & Products Division spent $5.3 million on capital expenditures during 2018, the majority of which related to plant and facility additions. Our Water & Flowback Services Division spent $30.2 million on capital expenditures, primarily to add to its water management equipment fleet. Our Compression Division spent $114.0 million, primarily for growth capital expenditure projects to increase its compression fleet. The acquisition of SwiftWater included initial cash purchase price consideration of $42.0 million, plus $1.0 million which was subsequently paid in August 2018 as a working capital adjustment. The acquisition of JRGO included initial cash purchase price consideration of $7.6 million.

Generally, a significant majority of our planned capital expenditures has been related to identified opportunities to grow and expand our existing businesses. However, certain of these planned expenditures have been, and may continue to be, postponed or canceled as we are reviewing all capital expenditure plans carefully in an effort to conserve cash. We currently have no long-term capital expenditure commitments. The deferral of capital projects could affect our ability to compete in the future. Excluding our Compression Division, we expect to spend approximately $25 to $35 million during 2019, primarily to further expand the Water & Flowback Services Division equipment fleet. Our Compression Division expects to spend approximately $75 million to $80 million on capital expenditures during 2019, primarily to expand its compression fleet in response to increased demand for compression services. Growth capital expenditures by our Compression Division during 2019 are expected to be funded by CCLP's available cash, cash provided by operating activities, and a portion funded by TETRA. The level of future growth capital expenditures depends on forecasted demand for our products and services. If the forecasted demand for our products and services during 2019 increases or decreases, the amount of planned expenditures on growth and expansion may be adjusted accordingly.

Financing Activities

During 2018, the total amount of consolidated cash provided by financing activities was $155.0 million, consisting primarily of the proceeds from the issuance of long-term debt. In September 2018, we entered into the ABL Credit Agreement and Term Credit Agreement, a portion of the proceeds of which were used to repay all outstanding borrowings and obligations under our then existing bank credit agreement and all outstanding indebtedness under the 11% Senior Note and both the bank credit agreement and the note purchase agreement for the 11% Senior Note were then terminated. Borrowings of up to $100 million under the ABL Credit Agreement, and up to $75 million of additional borrowings under the Term Credit Agreement will be available, subject to their availability, to fund future working capital requirements, capital expenditure requirements as well as potential acquisition financing. In March 2018, CCLP issued the CCLP Senior Secured Notes, a portion of the proceeds of which were used to repay the outstanding balance under the CCLP Prior Credit Facility and provide funding for 2018 capital expenditures. In June 2018, CCLP entered into the CCLP Credit Agreement, which provides up to $50.0 million to fund ongoing working capital and letter of credit needs and for general business purposes of CCLP. We and CCLP may supplement our existing cash balances and cash flow from operating activities with short-term borrowings, long-term borrowings, leases, issuances of equity and debt securities, and other sources of capital, subject to availability. During December 2018, CCLP decided to begin redeeming a portion of the CCLP Preferred Units using cash, rather than converting using CCLP common units, beginning with the January 2019 conversion date. We and CCLP are in compliance with all covenants of our respective credit and debt agreements as of December 31, 2018.

See CCLP Financing Activities below for discussion of the CCLP Preferred Units and CCLP's long-term debt.

TETRA Long-Term Debt

Asset-Based Credit Agreement. On September 10, 2018, TETRA, as borrower, and certain of its subsidiaries, entered into the ABL Credit Agreement with a syndicate of lenders, including JPMorgan Chase Bank, N.A., as administrative agent (collectively, the "ABL Lenders"). The ABL Credit Agreement provides for a senior secured revolving credit facility of up to $100 million, subject to a borrowing base to be determined by reference to the value of inventory and accounts receivable, and includes a sublimit of $20.0 million for letters of credit and a swingline loan sublimit of $10.0 million. As of December 31, 2018, subject to compliance with the covenants, borrowing base, and other provisions of the agreement that may limit borrowings, TETRA had an availability of $47.6 million under this agreement. As of March 1, 2019, we have $32.0 million outstanding under our ABL Credit Agreement and $9.0 million letters of credit.

Borrowings under the ABL Credit Agreement bear interest at a rate per annum equal to, at the option of TETRA, either (i) London Interbank Offering Rate (“LIBOR”) plus a margin based upon a fixed charge coverage ratio or (ii) a base rate plus a margin based on a fixed charge coverage ratio. The base rate is determined by reference to the highest of (a) the prime rate of interest as announced from time to time by JPMorgan Chase Bank, N.A. (b) the Federal Funds Effective Rate (as defined in the ABL Credit Agreement) plus 0.5% per annum and (c) LIBOR (adjusted to reflect any required bank reserves) for a one-month period on such day plus 1.0% per annum. Borrowings outstanding have an applicable margin ranging from 1.75% to 2.25% per annum for LIBOR-based loans and 0.75% to 1.25% per annum for base-rate loans, based upon the applicable fixed charge coverage ratio. In addition to paying interest on the outstanding principal under the ABL Credit Agreement, TETRA is required to pay certain fees.

The revolving loans under the ABL Credit Agreement may be voluntarily prepaid, in whole or in part, without premium or penalty, subject to applicable breakage fees. The maturity date of the ABL Facility is September 10, 2023.

The ABL Credit Agreement contains certain affirmative and negative covenants, including covenants that restrict the ability of TETRA and certain of its subsidiaries to take certain actions including, among other things and subject to certain significant exceptions, incurring debt, granting liens, engaging in mergers and other fundamental changes, making investments, entering into or amending transactions with affiliates, paying dividends and making other restricted payments, prepaying other indebtedness, and selling assets. The ABL Credit Agreement also contains a provision that requires a fixed charge coverage ratio (as defined in the ABL Credit Agreement) of not less than 1.00 to 1.00 in the event that certain conditions associated with outstanding borrowings and cash availability occur. As of December 31, 2018, such conditions have not occurred. All obligations under the ABL Credit Agreement and the guarantees of those obligations are secured, subject to certain exceptions, by a security interest on substantially all of the personal property of TETRA and certain subsidiaries of TETRA, the equity interests in certain domestic subsidiaries, including CCLP, and a maximum of 65% of the equity interests in certain foreign subsidiaries.

The ABL Credit Agreement includes customary events of default, including non-payment of principal, interest or fees, violation of covenants, inaccuracy of representations or warranties, cross-default to other material indebtedness, bankruptcy and insolvency events, invalidity or impairment of security interests or invalidity of loan documents, certain ERISA events, unsatisfied or unstayed judgments, and any change of control.

Proceeds of loans under the ABL Credit Agreement were used to pay certain debt of TETRA existing on the effective date of the ABL Credit Agreement and may be used for working capital needs, capital expenditures and other general corporate purposes. The ABL Credit Agreement replaced our previous Bank Credit Agreement, as defined and discussed in further detail below.

Term Credit Agreement. On September 10, 2018, TETRA, as borrower, entered into the Term Credit Agreement with a syndicate of lenders (collectively, the “Term Lenders”) and Wilmington Trust, National Association, as administrative agent. The Term Credit Agreement provides an initial loan in the amount of $200 million (the “Initial Term Loan”) and the availability of additional loans, subject to the terms of the Term Credit Agreement, up to an aggregate amount of $75 million for certain acquisitions (the “Additional Term Loans,” and together with the

Initial Term Loan, the “Term Loan”). As of March 1, 2019, $200.0 million in aggregate principal amount of our Term Credit Agreement is outstanding.

Borrowings under the Term Credit Agreement bear interest at a rate per annum equal to, at the option of TETRA, either (i) LIBOR plus a margin of 6.25% per annum or (ii) a base rate plus a margin of 5.25% per annum. In addition to paying interest on the outstanding principal under the Term Credit Agreement, TETRA is required to pay a commitment fee in respect of the unutilized commitments at the rate of 1.0% per annum, paid quarterly in ar

Closing Price ($)	Shares Out (MM)	Market Cap ($MM)
$2.44	126	$307

10-K	2018-12-31	Annual: 2018-12-31
10-Q	2018-09-30	Quarter: 2018-09-30
10-Q	2018-06-30	Quarter: 2018-06-30
10-Q	2018-03-31	Quarter: 2018-03-31
10-K	2017-12-31	Annual: 2017-12-31
10-Q	2017-09-30	Quarter: 2017-09-30
10-Q	2017-06-30	Quarter: 2017-06-30
10-Q	2017-03-31	Quarter: 2017-03-31
10-K	2016-12-31	Annual: 2016-12-31
10-Q	2016-09-30	Quarter: 2016-09-30
10-Q	2016-06-30	Quarter: 2016-06-30
10-Q	2016-03-31	Quarter: 2016-03-31
10-K	2015-12-31	Annual: 2015-12-31
10-Q	2015-09-30	Quarter: 2015-09-30
10-Q	2015-06-30	Quarter: 2015-06-30
10-Q	2015-03-31	Quarter: 2015-03-31
10-K	2014-12-31	Annual: 2014-12-31
10-Q	2014-09-30	Quarter: 2014-09-30
10-Q	2014-06-30	Quarter: 2014-06-30
10-Q	2014-03-31	Quarter: 2014-03-31
10-K	2013-12-31	Annual: 2013-12-31

8-K	2019-02-25	Officers, Exhibits
8-K	2018-12-26	Officers, Exhibits
8-K	2018-11-08	Earnings, Exhibits
8-K	2018-09-30	Officers
8-K	2018-09-10	Enter Agreement, Leave Agreement, Off-BS Arrangement, Shareholder Rights, Exhibits
8-K	2018-08-09	Earnings, Exhibits
8-K	2018-07-16	Officers
8-K	2018-07-13	Officers, Exhibits
8-K	2018-05-31	Regulation FD, Exhibits
8-K	2018-05-21	Regulation FD
8-K	2018-05-08	Earnings, Exhibits
8-K	2018-05-04	Officers, Shareholder Vote, Regulation FD, Exhibits
8-K	2018-04-27	Regulation FD, Exhibits
8-K	2018-02-28	Regulation FD, Other Events, Exhibits
8-K	2018-02-22	Officers
8-K	2018-02-13	Enter Agreement, Sale of Shares, Regulation FD, Exhibits
8-K	2018-02-08	Officers, Exhibits

SNY	Sanofi	104,040
SAIL	Sailpoint Technologies Holdings	2,480
COLL	Collegium Pharmaceutical	481
WSR	Whitestone REIT	479
LPG	Doriang	431
FRSH	Papa Murphy's Holdings	110
CGIX	Cancer Genetics	15
NVIV	Invivo Therapeutics Holdings	14
FMFG	Farmers & Merchants Bancshares	0
DEAC	Elite Data Services	0

EX-10.44	a20181231ex1044.htm
EX-21	a20181231ex21.htm
EX-23.1	a20181231ex231.htm
EX-31.1	a20181231ex311.htm
EX-31.2	a20181231ex312.htm
EX-32.1	a20181231ex321.htm
EX-32.2	a20181231ex322.htm