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, 2017
OR
[   ] 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 [ X ]   NO [   ]
INDICATE BY CHECK MARK IF THE REGISTRANT IS NOT REQUIRED TO FILE REPORTS PURSUANT TO SECTION 13 OR SECTION 15(d) OF THE ACT.
YES [   ]   NO [ 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 AND POSTED ON ITS CORPORATE WEB SITE, IF ANY, EVERY INTERACTIVE DATA FILE REQUIRED TO BE SUBMITTED AND POSTED 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 AND POST 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. [ ]
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 $311,416,405 AS OF JUNE 30, 2017, 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, 2018, WAS 125,528,953 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 4, 2018, 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
 
 
Part II
 
 
Part III
 
 
Part IV
 
Item 16.
Form 10-K Summary




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 crude oil and natural gas;
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;
our ability to comply with the financial covenants in our debt agreements and the consequences of any failure to comply with such financial covenants;
the availability of adequate sources of capital to us;
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.


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PART I

Item 1. Business.
 
The financial statements presented in this Annual Report are the consolidated financial statements of TETRA Technologies, Inc., a Delaware corporation and its subsidiaries. When the terms “TETRA,” “the Company,” “we,” “us,” or “our” are used in this document, those terms refer to TETRA Technologies, Inc. and its consolidated subsidiaries.

TETRA is a Delaware corporation, incorporated in 1981. Our corporate headquarters are located at 24955 Interstate 45 North, The Woodlands, Texas, 77380. Our phone number is 281-367-1983, and our website is accessed at www.tetratec.com. Our common stock is traded on the New York Stock Exchange under the symbol “TTI.”

Our Corporate Governance Guidelines, Code of Business Conduct, Code of Ethics for Senior Financial Officers, Audit Committee Charter, Compensation Committee Charter, and Nominating and Corporate Governance Committee Charter, as well as our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, and Current Reports on Form 8-K, and all amendments to those reports are all available, free of charge, on our website at www.tetratec.com as soon as practicable after we file the reports with the SEC. Information contained on or connected to our website is not, and shall not be deemed to be, a part of this Annual Report on Form 10-K or incorporated into any other filings with the SEC. The documents referenced above are available in print at no cost to any stockholder who requests them from our Corporate Secretary.

About TETRA

TETRA Technologies, Inc., together with its consolidated subsidiaries, is a leading, geographically diversified oil and gas services company, focused on completion fluids and associated products and services, water management, frac flowback, production well testing, offshore rig cooling, and compression services and equipment. Prior to March 2018, our operations also included selected offshore services including well plugging and abandonment, decommissioning, and diving, as well as a limited domestic oil and gas production business. As of December 31, 2017 we were composed of five reporting segments organized into four divisions - Fluids, Production Testing, Compression, and Offshore.
 
Our Fluids Division manufactures and markets clear brine fluids, additives, and associated products and services to the oil and gas industry for use in well drilling, completion and workover operations in the United States and in certain countries in Latin America, Europe, Asia, the Middle East and Africa. The division also markets liquid and dry calcium chloride products manufactured at its production facilities or purchased from third-party suppliers to a variety of markets outside the energy industry. The Fluids Division also provides domestic onshore oil and gas operators with a wide variety of water management services.

Our Production Testing Division provides frac flowback, production well testing, offshore rig cooling, and other associated services and early production facilities (EPFs) 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, custom-designed compressor packages and oilfield pump systems 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.

Our Offshore Division consists of two operating segments, both of which were disposed on March 1, 2018: Offshore Services and Maritech. The Offshore Services segment provided services primarily to the offshore oil and gas industry, consisting of: (1) downhole and subsea services, such as well plugging and abandonment and

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inspection, repair and maintenance services; (2) decommissioning and certain construction services utilizing heavy lift barges and various cutting technologies with regard to offshore oil and gas production platforms and pipelines; and (3) conventional and saturation diving services. For additional information regarding the sale of the Offshore Division, see "Note C - Acquisitions and Dispositions" of the Notes to Consolidated Financial Statements.

The Maritech segment was a limited oil and gas production operation. During 2011 and the first quarter of 2012, Maritech sold substantially all of its oil- and gas-producing property interests. Maritech’s operations consisted primarily of the ongoing abandonment and decommissioning associated with its remaining offshore wells and production platforms.
 
We continue to pursue a long-term growth strategy that includes expanding our continuing core businesses, which excludes our recently disposed Offshore Services and Maritech segments, through internal growth and acquisitions, domestically and internationally. For financial information for each of our segments, including information regarding revenues and total assets, see “Note Q - Industry Segments and Geographic Information” contained in the Notes to Consolidated Financial Statements.

Products and Services
 
Fluids Division

Liquid calcium chloride, calcium bromide, zinc bromide, zinc calcium bromide, sodium bromide, and blends of such products manufactured by our Fluids 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 Fluids 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 Fluids Division provides both stock and custom-blended CBFs based on each customer's specific needs and the proposed application. The Fluids 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 Fluids Division's newest CBF technology, TETRA CS Neptune® completion fluids, are high-density, solids-, zinc- and formate-free completion fluids. 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 that the CBFs can be reused. Filtration also enables recovery of a greater percentage of used CBFs for reconditioning.
 
The Fluids Division also 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 Fluids Division's patented equipment and processes include BioRid® treatment services, certain blending technologies, and TETRA STEELTM 1200 rapid deployment water transfer system. The Fluids 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 network of water transfer lines including TETRA STEEL™ lay-flat hose, TETRA Blend™ automated transfer and blending of produced water, and oil recovery from produced water via the TETRA Orapt™ mobile oil separator system - to transfer water around the well pads in a safe, efficient and environmentally responsible manner.


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On February 28, 2018, pursuant to a purchase agreement dated February 13, 2018 (the 'SwiftWater Purchase Agreement"), we purchased all of the equity interests in SwiftWater Energy Services, LLC ("SwiftWater"), which is engaged in the business of providing water management and water solutions to oil and gas operators in the Permian Basin market of Texas. SwiftWater provides a diverse range of water management equipment and services for operators in the Permian Basin, 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, pit lining rentals, and supporting ancillary equipment. For additional information regarding the acquisition of SwiftWater, see "Note C - Acquisitions and Dispositions" of the Notes to Consolidated Financial Statements.
 
The Fluids 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 naturally replenished. All of our calcium chloride production facilities have a combined production capacity of more than 1.5 million equivalent liquid tons per year.

Our Fluids 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.
 
See “Note Q - Industry Segments and Geographic Information” in the Notes to Consolidated Financial Statements for financial information about the Fluids Division.
 
Production Testing Division
 
Our Production Testing Division 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 Production Testing 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.
 
Our Production Testing 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, North Dakota, Oklahoma, Pennsylvania, Texas, West Virginia, and Wyoming. The division also has locations in Canada, and in certain countries in South America, Europe, Africa, and the Middle East. Production Testing operations in Canada are provided through our subsidiary, Greywolf Energy Services ("Greywolf").
 

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Through our Optima Solutions Holdings Limited subsidiary ("OPTIMA"), the Production Testing Division is a provider of offshore oil and gas rig cooling services and associated products that suppress heat generated by high rate flaring of hydrocarbons during offshore oil and gas well test operations.

See “Note Q - Industry Segments and Geographic Information” in the Notes to Consolidated Financial Statements for financial information about the Production Testing Division.

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, as well as oilfield fluid pump systems, 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 5,800 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, 2017, is summarized in the following table:
Range of Horsepower Per Package
 
Number of Packages
 
Aggregate Horsepower
 
% of Total Aggregate Horsepower
 
 
 
 
 
 
 
0 - 100
 
3,842
 
180,156
 
16.7
%
101 - 800
 
1,590
 
444,520
 
41.1
%
Over 800
 
341
 
457,243
 
42.3
%
Total
 
5,773
 
1,081,919
 
100.0
%

Our Compression Division's equipment sales business includes the fabrication and sale of standard compressor packages, custom-designed compressor packages and oilfield fluid pump systems 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, mid-stream, 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 8,000 horsepower for use in our service fleet and for sale to our broadened customer base. Our pump systems can be utilized in numerous applications including oil production, transfer and pipelines, as well as water injection and disposal.

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

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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 subsidiary, CSI Compressco LP ("CCLP"). Through our wholly owned subsidiary, 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, 2017, common units held by the public represented approximately a 60% common unit ownership interest in CCLP.

See “Note Q - Industry Segments and Geographic Information” in the Notes to Consolidated Financial Statements for financial information about the Compression Division.

Offshore Division
 
Our Offshore Division consists of two operating segments: Offshore Services and Maritech. On March 1, 2018, we closed a series of related transactions that resulted in the disposition of these two businesses. Pursuant to an Asset Purchase and Sale Agreement (the "Maritech Asset Purchase Agreement") with Orinoco Natural Resources, LLC ("Orinoco") Orinoco purchased certain offshore oil, gas and mineral leases and related assets of Maritech (the "Maritech Properties"). Immediately thereafter, we closed a Membership Interest Purchase and Sale Agreement (the "Maritech Equity Purchase Agreement") with Orinoco, whereby Orinoco purchased all of the equity interests of Maritech (the "Maritech Equity Interests"). Immediately thereafter, we closed an Equity Interest Purchase Agreement (the "Offshore Services Purchase Agreement") with Epic Offshore Specialty, LLC, an affiliate of Orinoco ("Epic Offshore"), whereby Epic Offshore purchased (the "Offshore Services Sale") all of the equity in TSB Offshore, Inc. and TETRA Applied Technologies, LLC, which owns all of the equity interests in Epic Diving & Marine Services, LLC, which are the wholly owned subsidiaries that comprise our Offshore Services segment operations (the "Offshore Services Equity Interests").

Under the terms of the Maritech Asset Purchase Agreement, the Maritech Equity Purchase Agreement, and the Offshore Services Purchase Agreement, the consideration delivered by Orinoco and Epic Offshore for the Maritech Properties, the Maritech Equity Interests and the Offshore Services Equity Interests consisted of (i) the assumption by Orinoco of all of the liabilities and obligations relating to the ownership, operation and condition of the Maritech Properties and the provision of certain indemnities by Orinoco to us under the Maritech Asset Purchase Agreement, (ii) the assumption by Orinoco of all of the liabilities of Maritech and the provision of certain indemnities by Orinoco under the Maritech Equity Purchase Agreement, (iii) the assumption by Epic Offshore of substantially all of the liabilities of the Offshore Services Equity Interests relating to the periods following the closing of the Offshore Services Sale and the provision of certain indemnities by Epic Offshore under the Offshore Services Purchase Agreement, (iv) cash in the amount $3.1 million which is equal to the value of the fuel in the vessels owned by Offshore Services as of the closing plus the value (determined to be sixty percent of the amount paid by Offshore Services therefore) of all usable spare parts and supply inventory of Offshore Services, (v) a promissory note in the original principal amount of $7.5 million payable by Epic Offshore to us in full, together with interest at a rate of 1.52% per annum, on December 31, 2019, (vi) performance by Orinoco under a Bonding Agreement executed in connection with the Maritech Asset Purchase Agreement and the Maritech Equity Purchase Agreement whereby Orinoco provided at closing non-revocable performance bonds in an amount equal to $46.8 million to cover the performance by Orinoco and Maritech of the asset retirement obligations of Maritech, to be replaced within 90 days of the closing with non-revocable performance bonds, meeting certain requirements, in the sum of $47.0 million, and (vii) the delivery of a personal guaranty agreement from Thomas M. Clarke and Ana M. Clarke guaranteeing the payment obligations of Orinoco under the Bonding Agreement (collectively, the "Transaction Consideration"). See "Note C - Acquisitions and Dispositions" in the Notes to Consolidated Financial Statements for financial information about the February 2018 sale of the Offshore Division.

As a result of these transactions, we have effectively exited the businesses of our Offshore Services and Maritech segments.

Offshore Services Segment. The Offshore Services segment provided: (1) downhole and subsea services, such as well plugging and abandonment and inspection, repair and maintenance services; (2) decommissioning and certain construction services utilizing heavy lift barges and various cutting technologies with regard to offshore oil and gas production platforms and pipelines; and (3) conventional and saturation diving services. We provided these services to offshore oil and gas operators, primarily in the U.S. Gulf of Mexico. We offered comprehensive integrated services, including individualized engineering consultation and project management services.

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Maritech Segment. The Maritech segment was a limited oil and gas production operation in the offshore U.S. Gulf of Mexico. During 2011 and the first quarter of 2012, Maritech sold substantially all of its proved reserves. Subsequent to these sales of proved reserves, Maritech’s remaining operations consisted primarily of the ongoing abandonment and decommissioning of its remaining offshore wells, facilities and production platforms. As part of the sale of our Offshore Division in March 2018, Orinoco purchased Maritech and its remaining oil and gas leases and assumed all of Maritech's abandonment and decommissioning obligations.
 
The sales of substantially all of Maritech’s oil and gas producing properties during 2011 and 2012 essentially removed us from the oil and gas exploration and production business, and significantly all of Maritech’s oil and gas acquisition, development and exploitation activities ceased. Since the sales of its proved reserves, Maritech’s remaining oil and gas reserves and production were negligible. Prior to March 1, 2018, Maritech’s operations consisted primarily of the well abandonment and decommissioning of its remaining offshore oil and gas platforms and facilities. During the three year period ended December 31, 2017, Maritech spent approximately $14.9 million on such efforts. Approximately $46.7 million of Maritech decommissioning liabilities remained as of December 31, 2017, and such liabilities were assumed by Orinoco as part of the sale of the Offshore Division.

Maritech’s decommissioning liabilities are established based on what it estimates a third party would charge to plug and abandon the wells, decommission the pipelines and platforms, and clear the sites associated with its properties. For a further discussion of Maritech’s historical adjustments to its decommissioning liabilities, see “Note I - Decommissioning and Other Asset Retirement Obligations” in the Notes to Consolidated Financial Statements.
 
See “Note Q - Industry Segments and Geographic Information” in the Notes to Consolidated Financial Statements for financial information about the Offshore Division.
 
Sources of Raw Materials
 
Our Fluids Division manufactures calcium chloride, calcium bromide, zinc bromide, zinc calcium bromide, and sodium bromide for sale to its customers. The Fluids Division also recycles used calcium bromide and zinc bromide CBFs repurchased from its oil and gas customers.
 
The Fluids Division manufactures liquid calcium chloride, either from underground brine or by reacting hydrochloric acid with limestone. The Fluids 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," which acquired Chemtura Corporation during 2017) that contains calcium chloride and sodium chloride. We also produce calcium chloride and sodium chloride at our two facility locations 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 Fluids 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 Fluids Division purchases its requirements of raw material bromine from Lanxess’s Arkansas bromine facilities. In addition, we have a long-term agreement with Lanxess under which Lanxess supplies the Fluids’ El Dorado, Arkansas, calcium chloride plant with raw material tail brine from its Arkansas bromine production facilities.
 
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

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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 Fluids and Production Testing Divisions purchase their 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 and pumps with components obtained from third party suppliers. These components represent a significant portion of the cost of the compressor packages and pump systems. Some of the components used in the assembly of compressor packages, well monitoring, sand separation, 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 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. With the increase in oil and gas pricing that continued throughout most of 2017 and early 2018, we are seeing indicators of improving demand in the North America and international markets, while offshore activity remains flat year-over-year.

Fluids Division
 
Our Fluids 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 CBFs, which can be subject to harsh downhole conditions, such as high pressure and high temperatures. Demand for CBF products offshore is generally driven by completion activity.
 
Since 2014, there has been increased industry demand for onshore water management services in unconventional shale gas and oil reservoirs in connection with hydraulic fracturing operations. However, beginning in 2015, demand for certain Fluids Division products and services, particularly water management services, was adversely affected by declining oil and natural gas pricing and customer budgetary constraints. Throughout 2017, demand for our North American onshore water management services increased as oil and natural gas prices rose. The Fluids Division provides water management 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 expands our market share in the Permian Basin, which is one of the fastest growing basins for oilfield services globally, by adding significant capacity as well as incremental products and services, with nominal customer overlap.
 
Our Fluids Division’s principal competitors in the sale of CBFs to the oil and gas industry are Baker Hughes, Baroid, a subsidiary of Halliburton, and M-I Swaco, a subsidiary of Schlumberger. This market is highly competitive, and competition is based primarily on service, availability, and price. Major customers of the Fluids Division include Anadarko, Chesapeake, Chevron, ConocoPhillips, Devon Energy, Encana, EOG Resources, ExxonMobil, Halliburton, LLOG Exploration, Oklahoma Energy Corp., Petrobras, Pioneer Natural Resources, Saudi Aramco, Schlumberger, Shell, Southwestern Energy, Total, Tullow, W & T Offshore, and YPF. The Fluids Division also sells its CBF products through various distributors. Competitors for the division’s water management services include large, multinational providers as well as small, privately owned operators.
 
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 Fluids Division’s European calcium chloride operations market our calcium chloride products to certain European

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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.
 
Production Testing Division
 
Our Production Testing Division 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. The Production Testing Division serves all active North America unconventional oil and gas basins. Through Greywolf, the division serves the western Canada market. In addition, through our OPTIMA subsidiary, the Production Testing Division offers offshore oil and gas rig cooling services and associated products that suppress heat generated by high-rate flaring of hydrocarbons during offshore well testing operations. OPTIMA primarily serves markets in the North Sea, Asia-Pacific, the Middle East and South America.

The U.S. and Canadian 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 and safety record give us a competitive advantage. 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 major competitors in the foreign markets we serve although, we provide these services to their customers on a subcontract basis from time to time. The major customers for this division include Chevron, ConocoPhillips, Eclipse Resources, Encana, EP Energy, EQT, Expro, Peyto, Pioneer Natural Resources, Range Resources, Rice Energy, Saudi Aramco, Schlumberger, Shell, and Vantage Energy.
 
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 major customers include Anadarko, Cimarex Energy, ConocoPhillips, Denbury Onshore, and Targa Resources.

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 mid- and high-horsepower compression services business comes primarily from large national and multinational companies that may have greater financial resources than ours. Such competitors include ArchRock, AXIP Energy Services, CDM Resource Management, Exterran, J-W Power, 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 AG Equipment Company, Enerflex, SEC Energy Products & Services, 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.


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Offshore Division
 
Offshore Services Segment. Demand for the Offshore Services segment’s offshore well abandonment and decommissioning services in the Gulf of Mexico is primarily driven by the maturity and decline of producing fields, aging offshore platform infrastructure, damage to platforms and pipelines from hurricanes and other windstorms, and government regulations, among other factors. Demand for the Offshore Services segment’s construction and other services is driven by the general level of offshore activity of its customers, which is affected by oil and natural gas prices and government regulation. Offshore activities in the Gulf of Mexico are seasonal, with the majority of work occurring during the months of April through October when weather conditions are most favorable. Critical factors required to compete in this market include, among other factors: (i) the proper equipment, including vessels and heavy lift barges; (ii) qualified, experienced personnel; (iii) technical expertise to address varying downhole, surface and subsea conditions, particularly those related to damaged wells and platforms; and (iv) a comprehensive health, safety and environmental program. Our Offshore Services segment's fleet of owned equipment includes two heavy lift derrick barges, the TETRA Hedron, which has a 1,600-metric-ton lift capacity, fully revolving crane and the TETRA Arapaho, which has a 725-metric-ton lift capacity. We believe that the integrated services that we offer and our vessel and equipment fleets satisfy current market requirements in the Gulf of Mexico and allow us to successfully compete in that market.
 
The Offshore Services segment markets its services primarily to major oil and gas companies and independent operators. One of the Offshore Services segment’s most significant customers historically has been Maritech; however, the amount of work performed for Maritech has been reduced in recent years and the amount of work to be performed in the future for Maritech is expected to continue to decline. Major customers include, Fieldwood Energy, Shell, Stone Energy, Talos Energy, and W&T Offshore. The Offshore Services segment’s services are performed primarily in the U.S. Gulf of Mexico, however, the segment has provided services in the Mexican Gulf of Mexico and in the Asia-Pacific region and is seeking to expand its operations to international markets. Our principal competitors in the U.S. Gulf of Mexico market are Chet Morrison Contractors, Manson Gulf, Montco Oilfield Contractors, Oceaneering, Ranger Offshore, and Superior Energy Services, Inc. This market is highly competitive, and competition is based primarily on service, equipment availability, safety record, and price. 

No single customer provided 10% or more of our total consolidated revenues during the year ended December 31, 2017.

Other Business Matters
 
Backlog
 
The Compression Division’s equipment sales business consist of the fabrication and sale of standard compressor packages, custom-designed compressor packages, and oilfield fluid pump systems 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, 2017, the Compression Division's equipment sales backlog was $47.5 million, all of which is expected to be recognized in 2018, based on title passing to the customer, the customer assuming the risks of ownership, reasonable assurance of collectability, and delivery occurring as directed by our customer. 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 allows us to plan future labor and raw material needs and to measure our success in winning bids from our customers. Following a record single $66.7 million sales order received from a customer in early 2018, the Compression Division's equipment sales backlog has further increased significantly after December 31, 2017.

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, 2017, we had approximately 2,600 employees. None of our U.S. employees are presently covered by a collective bargaining agreement. Our foreign employees are generally members of labor

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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, 2017, we owned or licensed fifty-six (56) issued U.S. patents and had seven (7) patent applications pending in the United States. Twenty five (25) of the U.S. patents and the seven (7) patent applications pending in the U.S. are held by our Offshore Services segment, which was disposed in March 2018. We also had forty-five (45) owned or licensed patents and seven (7) patent applications pending in various other countries. Eight (8) of the foreign patents and one of the foreign patent applications are held by our Offshore Services segment. 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 various 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; (ii) the Resource Conservation and Recovery Act of 1976; (iii) the Clean Air Act of 1977; (iv) the Comprehensive Environmental Response, Compensation and Liability Act of 1980 ("CERCLA"); (v) the Superfund Amendments and Reauthorization Act of 1986; (vi) the Federal Insecticide, Fungicide, and Rodenticide Act of 1947; (vii) the Toxic Substances Control Act of 1976; (viii) the Hazardous Materials Transportation Act of 1975; (ix) 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

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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 U.S. Environmental Protection Agency (the “EPA”) has adopted regulations under the Clean Air Act 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 New Source Performance Standards as well as emission standards to address hazardous air pollutants. Certain CSI compressors 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.

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. Additionally, related to our Offshore Services operations which we disposed in March 2018, we maintained a vessel pollution liability policy that provides coverage for oil or hazardous substance pollution emanating from a vessel, addressing both Oil Pollution Act of 1990 ("OPA") and CERCLA obligations. This policy also provides coverage for cost of defense, and limited coverage for fines, and penalties up to the applicable policy limits.

We provided services and products to customers in the Gulf of Mexico, generally pursuant to written master services agreements that created insurance and indemnity obligations for both parties. Following the March 2018 sale of our Offshore Division, Orinoco has assumed substantially all of the liabilities of our Offshore Division.


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. Crude oil prices have fluctuated significantly since 2014, with West Texas Intermediate (WTI) oil spot prices declining from a high of $108 per barrel in June 2014 to a low of $26.19 per barrel in February 2016, a level which has not been experienced since 2003. Although crude oil prices have increased during the second half of 2017 and early 2018 with a high of $66.14 per barrel in January 2018, the volatility of crude oil prices continues

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to be high. For more information, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Business Environment 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 decrease, 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 the perception of longer-term lower oil and natural gas prices by oil and natural gas companies 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.

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 older equipment and safety, and offer 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 and production, development, and acquisition activities, and impairments of long-lived assets. 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 such 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 is expected to continue to have, a negative effect on our revenues and results of operations. A large concentration of our operating activities is located in the onshore and offshore U.S. Gulf Coast region. 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 further 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

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identified intangible asset resulting from decreased expected future operating cash flows from a Production Testing segment customer. During the two year period ending December 31, 2017, we have recorded a total of $33.0 million of long-lived asset impairments. 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, barges and vessels, and other operating equipment. Under generally accepted accounting principles, we review the carrying value of our long-lived assets when events or changes in circumstances indicate that the carrying value of these assets may not be recoverable, based on their expected future cash flows. The impact of reduced expected future cash flow could require the write-down of all or a portion of the carrying value for these assets, which would result in additional impairments, resulting in decreased earnings.
 
During the two year period ending December 31, 2017, we have recorded a total of approximately $106.2 million of goodwill impairments. Following these goodwill impairments, as of December 31, 2017, our consolidated goodwill consists of the $6.6 million of goodwill attributed to our Fluids reporting unit. Under generally accepted accounting principles, 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.
 

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 clear brine fluids 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 clear brine fluid 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 clear brine fluid 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 business could be materially and adversely affected.
 

The fabrication of our compression packages, pump systems, and 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 Production Testing 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

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matters. These regulations also implement additional safety and certification requirements applicable to offshore activities in the U.S. Gulf of Mexico. Demand for our products and services 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 acquisition.
    
On February 28, 2018, pursuant to the SwiftWater Purchase Agreement dated February 13, 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 of Texas.

We performed an inspection of SwiftWater's assets, 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 after closing of the SwiftWater acquisition, the purchase agreement provides for limited recourse against the sellers.

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. In particular, many of our significant equipment assets, are approaching the end of their useful lives, which may adversely affect our ability to serve certain customers. Other 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. If we overextend our current financial resources by growing too aggressively, we could face liquidity problems or have difficulty obtaining additional financing. Acquisitions could adversely affect our operations if we are unable to successfully integrate the newly acquired companies into our 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. Our operation of heavy equipment and chemical manufacturing plants involve particularly high levels of risk. In addition, certain of our former employees of the Offshore Services segment

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performed services on offshore platforms and vessels and are covered by the provisions of the Jones Act, the Death on the High Seas Act, and general maritime law. These laws make the liability limits established by state workers’ compensation laws inapplicable to these employees and, instead, permit our affected employees or their representatives to pursue actions against us for damages for job-related injuries. Whenever possible, we obtained agreements from customers and suppliers that limit our exposure. However, the occurrence of certain operating hazards, including storms, could result in substantial losses to us due to injury or loss of life, damage to or destruction of property and equipment, pollution or environmental damage, and suspension of operations.
 
We have maintained a policy of insuring our risks of operational hazards that we believe is typical 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 Fluids 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 Fluids 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
 
Failure to comply with the financial ratios in our long-term debt agreements could result in defaults under those agreements.
 
As of December 31, 2017, our total long-term debt outstanding (excluding CCLP) of $117.7 million consisted of the carrying amount of our 11% Senior Note, which was issued under our Amended and Restated Note Purchase Agreement dated as of July 1, 2016, as subsequently amended (the "Amended and Restated 11% Senior Note Agreement"). We currently have $0.0 million carrying amount outstanding under our credit agreement, as amended, with a syndicate of banks including JPMorgan Chase Bank, N.A. as administrative agent, which provides us with a secured revolving credit facility with a borrowing capacity of up to $200 million (subject to certain conditions) (the "Credit Agreement"). In addition, as of December 31, 2017 our consolidated balance sheet includes $512.2 million of long-term debt of CCLP, which consisted of (i) $224.0 million carrying amount under CCLP's credit agreement, dated as of August 4, 2014, as subsequently amended, with a syndicate of banks including Bank of America, N.A. as administrative agent, which provides CCLP with an asset-based revolving credit facility with a borrowing capacity of up to $315 million, subject to borrowing base requirements (the "CCLP Credit Agreement"), and (ii) $288.2 million carrying amount of CCLP's 7.25% Senior Notes due 2022 (the "CCLP 7.25% Senior Notes"), which were issued pursuant to an Indenture, dated as of August 4, 2014, with U.S. Bank National Association, as trustee (the "CCLP Indenture"). Debt service costs related to outstanding long-term debt represent a significant use of our operating cash flow and could increase our vulnerability to general adverse economic and industry conditions.

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Each of the Credit Agreement and the Amended and Restated 11% Senior Note Agreement (collectively the "Long-Term Debt Agreements") contains covenants and other restrictions and requirements that, among other things, requires us to maintain certain financial ratios as of the end of each fiscal quarter. Deterioration of these ratios could result in a default under these agreements. Although our Long-Term Debt Agreements include cross-default provisions relating to each other and other indebtedness that we may incur that is greater than a defined amount, there are no cross default provisions, cross collateralization provisions, or cross guarantees between our Long-Term Debt Agreements and CCLP's Credit Agreement or the CCLP Indenture. If an event of default occurs under either of our Long-Term Debt Agreements and such event is not remedied in a timely manner, an event of default will occur under both of the Long-Term Debt Agreements. Any event of default, if not timely remedied, could result in a termination of all commitments of the lenders under the Credit Agreement, acceleration of all amounts owed thereunder and with regard to the 11% Senior Note, and foreclosure on the collateral securing both of the Long-Term Debt Agreements.

Following the Fifth Amendment to the Credit Agreement in December 2016, the financial ratios in the Credit Agreement include a minimum fixed charge coverage ratio (which is the ratio of a defined measure of earnings to interest, both measures over the trailing twelve months) of 1.25 to 1 and a maximum leverage ratio (which is the ratio of (i) outstanding debt under the Long-Term Debt Agreements and certain other obligations, including letters of credit outstanding, to (ii) a measure of our consolidated net earnings ("EBITDA"), all as defined in the Credit Agreement ) of (i) 5.00 to 1 at the end of the fiscal quarters ending during the period from and including March 31, 2017 through and including December 31, 2017, (ii) 4.75 to 1 at the end of the fiscal quarters ending March 31, 2018 and June 30, 2018, (iii) 4.50 to 1 at the end of the fiscal quarters ending September 30, 2018 and December 31, 2018, and (iv) 4.00 to 1 at the end of each of the fiscal quarters thereafter. EBITDA is defined in our Credit Agreement as the aggregate of our net income (or loss) and the net income (or loss) of our consolidated restricted subsidiaries (which excludes CCLP), including cash dividends and distributions (not the return of capital) received from persons (including CCLP) other than consolidated restricted subsidiaries and after allowances for taxes for such period determined on a consolidated basis in accordance with U.S. generally accepted accounting principles ("GAAP"), excluding certain items specifically described therein. This definition of consolidated net earnings excludes an amount of extraordinary and nonrecurring losses up to 25% of a measure of earnings. At December 31, 2016, our fixed charge coverage ratio was 3.05 to 1 and our leverage ratio was 1.66 to 1.

Under the Amended and Restated 11% Senior Note Agreement, the financial ratio requirements include a minimum fixed charge coverage ratio (which is identical to the minimum fixed charge coverage ratio under the Credit Agreement) of 1.25 to 1 and a maximum leverage ratio (which is identical to the maximum leverage ratio under the Credit Agreement) of (i) 5.00 to 1 at the end of the fiscal quarters ending during the period from and including March 31, 2017 through and including December 31, 2017, (ii) 4.75 to 1 at the end of the fiscal quarters ending March 31, 2018 and June 30, 2018, (iii) 4.50 to 1 at the end of the fiscal quarters ending September 30, 2018 and December 31, 2018, and (iv) 4.00 to 1 at the end of the fiscal quarters ending thereafter.

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 flows. Due to the decreased demand for certain of our products and services by our customers in response to decreased oil and natural gas prices during 2015 and 2016, we reduced long-term debt from the use of equity offering proceeds took strategic cost reduction efforts, including headcount reductions, deferral of salary increases, salary reductions, benefit reductions, and other efforts to reduce costs and generate cash to mitigate the reduced demand for our products and services. We and CCLP are in compliance with all covenants of our respective long-term debt agreements as of December 31, 2017. Based on our financial forecasts as of March 2, 2018, which are based on certain operating and other business assumptions that we believe to be reasonable, we anticipate that, despite the current industry environment and activity levels, we will have sufficient liquidity, earnings and operating cash flows to maintain compliance with all covenants under our Long-Term Debt Agreements through March 2, 2019. However, there can be no assurance that the assumptions we have made will turn out to be accurate or that we will remain in compliance with these covenants going forward, and we could consequently be in default under our Long-Term Debt Agreements if we were unable to obtain a waiver or amendment from our lenders.
    

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CCLP's failure to comply with the financial ratios in its long-term debt agreements could result in defaults under those agreements and reduced distributions to us.

The CCLP Credit Agreement provides CCLP with an asset-based revolving credit facility with a borrowing capacity of up to $315 million, subject to borrowing base requirements. As of December 31, 2017, CCLP's balance sheet includes $512.2 million of carrying value of long-term debt of CCLP consisting of (i) $224.0 million under the CCLP Credit Agreement and (ii) $288.2 million of CCLP 7.25% Senior Notes issued pursuant to the CCLP Indenture. Debt service costs related to CCLP's outstanding long-term debt represents a significant use of its operating cash flow and could increase its vulnerability to general adverse economic and industry conditions. Payment of CCLP's debt service obligations reduces cash available for distribution to its common unitholders, including us. Any breach of, or CCLP's inability to borrow under, the CCLP Credit Agreement, could impact CCLP's ability to fund distributions (if CCLP elected to do so), among other adverse impacts.

The CCLP Credit Agreement, as amended in May 2017, contains financial ratio covenants requiring CCLP to maintain (i) the consolidated total leverage ratio may not exceed (a) 5.95 to 1 as of March 31, 2017; (b) 6.75 to 1 as of June 30, 2017 and September 30, 2017; (c) 6.50 to 1 as of December 31, 2017 and March 31, 2018; (d) 6.25 to 1 as of June 30, 2018 and September 30, 2018; (e) 6.00 to 1 as of December 31, 2018; and (f) 5.75 to 1 as of March 31, 2019 and thereafter; and (ii) the consolidated secured leverage ratio may not exceed 3.25 to 1 as of the end of any fiscal quarter. The consolidated interest coverage ratio was not amended by the CCLP Fifth Amendment. In addition, the CCLP Fifth Amendment (i) increased the applicable margin by 0.25% in the event the consolidated total leverage ratio exceeds 6.00 to 1, resulting in a range for the applicable margin between 2.00% and 3.50% per annum for LIBOR-based loans and between 1.00% and 2.50% per annum for base-rate loans, depending on the consolidated total leverage ratio, and (ii) modified the appraisal delivery requirement from an annual requirement to a semi-annual requirement. In connection with the CCLP Fifth Amendment, the level of CCLP's cash distributions payable on its common units for the quarterly period ended June 30, 2017 will be limited to the current reduced level. The CCLP Fifth Amendment also included additional revisions that provide flexibility to CCLP for the issuance of preferred securities. At December 31, 2017, the CCLP consolidated total leverage ratio was 6.48 to 1 (compared to 6.50 to 1 maximum allowed under the CCLP Credit Agreement), its consolidated secured leverage ratio was 2.89 to 1 (compared to a 3.25 to 1 maximum ratio allowed under the CCLP Credit Agreement), and its interest coverage ratio was 2.55 to 1 (compared to a 2.25 to 1 minimum ratio required under the CCLP Credit Agreement).

Continued access to the CCLP Credit Agreement is dependent upon CCLP's compliance with the financial ratio covenants as well as the borrowing base and other provisions set forth in the CCLP Credit Agreement. The CCLP Credit Agreement contains additional restrictive provisions ("cash dominion provisions") that are imposed if an event of default has occurred and is continuing or "excess availability" falls below $30.0 million. The CCLP Credit Agreement provides that CCLP may make distributions to holders of its common units, but only if there is no default under the CCLP Credit Agreement and CCLP maintains excess availability of $30.0 million. CCLP's ability to comply with the covenants and restrictions contained in the CCLP Credit Agreement may be affected by events beyond its control, including prevailing economic, financial, and industry conditions. If market or other economic conditions deteriorate, CCLP's ability to comply with these covenants may be impaired. A failure to comply with the provisions of the CCLP Credit Agreement could result in an event of default. Upon an event of default, unless waived, the lenders under the CCLP Credit Agreement would have all remedies available to secured lenders and could elect to terminate their commitments, cease making further loans, require cash collateralization of letters of credit, cause their loans to become due and payable in full, institute foreclosure proceedings against CCLP or its subsidiaries’ assets, and force CCLP and its subsidiaries into bankruptcy or liquidation. If the payment of CCLP's debt is accelerated, its assets may be insufficient to repay such debt in full, and the holders of CCLP common units, including us, could experience a partial or total loss of their investment. An event of default by CCLP under the CCLP Credit Agreement may constitute an event of default under the CCLP 7.25% Senior Notes.

CCLP is in compliance with all covenants of the CCLP Credit Agreement as of December 31, 2017. As a result of the recent decreased demand and pricing for certain of CCLP's products and services by CCLP's customers in response to decreased oil and natural gas prices, CCLP reduced long-term debt from the use of the CCLP Preferred Units offering proceeds and taken strategic cost reduction efforts to reduce costs and generate cash. Based on CCLP's financial forecasts as of February 28, 2018, which are based on certain operating and other business assumptions that CCLP believes to be reasonable, CCLP anticipates that, despite the current industry environment and activity levels, it will have sufficient earnings and operating cash flows to maintain compliance with all covenants under the CCLP Credit Agreement through February 27, 2019. CCLP's plans and forecasts for 2018 include expectations that we will settle certain expenses owed to us by CCLP pursuant to an Omnibus Agreement previously entered into on June 20, 2011 (as amended, the "Omnibus Agreement") using CCLP common units in

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lieu of cash. There can be no assurance that the assumptions CCLP made will turn out to be accurate or that CCLP will remain in compliance with these covenants going forward, and could consequently be in default under the CCLP Credit Agreement if it were unable to obtain a waiver or amendment from its lenders. Any such default under the CCLP Credit Agreement may constitute an event of default under the CCLP 7.25% Senior Notes. As a result, our cash flows could be further affected.

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 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 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). 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 decreased 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.


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The Series A Convertible Preferred Units of CCLP issued on August 2016 and September 2016 (the "CCLP Preferred Units") are senior in right of distributions, liquidation and voting to the common units of CCLP, and will result in the issuance of additional CCLP common units in the future, resulting in dilution of our existing common unit ownership in CCLP, and such dilution is potentially unlimited.
 
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 partnership agreement and the CCLP Series A Preferred Unit Purchase Agreements, as herein defined, 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 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 Series A Preferred Unit Purchase Agreement, 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 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 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 2017, conversions of the CCLP Preferred Units resulted in the issuance of 3.7 million CCLP common units. CCLP anticipates that the number of CCLP common units that will be issued upon conversions of the CCLP Preferred Units during 2018 will increase, as monthly conversions are expected during the full year of 2018 and due to the three month deferral of conversions during 2017. 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.

Because we own 40% of the outstanding CCLP common units, 12.6% of the newly issued CCLP Preferred Units, and approximately 2% general partner interest in CCLP, as a result of the conversion of the CCLP Preferred Units into CCLP common units:
our previously existing ownership interest in the common units of CCLP will decrease;
the amount of cash available for distribution on each CCLP common unit may decrease;
the voting power attributable to our previously existing CCLP common units will be diminished; and
the market price of CCLP common units may decline.
 
We and CCLP are exposed to interest rate risks with regard to our respective credit facility indebtedness.
 
As of December 31, 2017, CCLP has a total of $224.0 million outstanding under its revolving credit facility, and we did not have any outstanding borrowings under our revolving credit facility. In connection with the SwiftWater acquisition, we borrowed $40.0 million and we may borrow additional amounts under our revolving credit facility in the future. These revolving credit facilities consist of floating rate loans that bear interest at an agreed upon percentage rate spread (which is determined on our leverage ratio) above London Interbank Offered Rate ("LIBOR"). Accordingly, our cash flows and results of operations could be subject to interest rate risk exposure

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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 revolving credit facility is scheduled to mature on September 30, 2019. CCLP's revolving credit facility is scheduled to mature on August 4, 2019. Our 11% Senior Note, which matures November 2022, and CCLP's 7.25% Senior Notes, which mature August 2022, 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 Production Testing, Compression, and Fluids 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. In particular, the focus on greenhouse gases 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.

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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. Decreased regulation and enforcement in the future could materially and adversely affect the demand for certain of the services offered by our Offshore Services operations and, therefore, materially and adversely affect our business.
 
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.

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, 2017, 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.
 
Tax laws and regulations may change over time, and the recently passed comprehensive tax reform bill could adversely affect our business and financial condition.


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On December 22, 2017, H.R.1, “An Act to Provide the Reconciliation Pursuant to Titles II and V of the Concurrent Resolution on the Budget for Fiscal Year 2018” (the “Act”) (previously known as “The Tax Cuts and Jobs Act”) was signed into law making significant changes to the Internal Revenue Code. The Act, among other things, (i) permanently reduces the U.S. corporate income tax rate, (ii) repeals the corporate alternative minimum tax, (iii) eliminates the deduction for certain domestic production activities, (iv) imposes new limitations on the utilization of net operating losses, and (v) provides for more general changes to the taxation of corporations, including changes to cost recovery rules and to the deductibility of interest expense, which may impact the taxation of oil and gas companies. The Act is complex and far-reaching and we cannot predict with certainty the resulting impact its enactment has on us. The ultimate impact of the Act may differ from our estimates due to changes in interpretations and assumptions made by us as well as additional regulatory guidance that may be issued and any such changes in interpretations or assumptions could adversely affect our business and financial condition. See "Note E - Income Taxes" to our Consolidated Financial Statements for additional information.

Climate change legislation or regulations restricting emissions of “greenhouse gases” 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 greenhouse gases ("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 Clean Air Act ("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.
 
In addition, in December 2015, over 190 countries, including the United States, reached an agreement to reduce global greenhouse gas 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, 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.


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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 (“SDWA”) Underground Injection Control (“UIC”) 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 (“VOC”) 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 U.S. Congress (“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.

23




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. In addition, as a result of a settlement approved by the United States for the District of Columbia in 2011, the U.S. Fish and Wildlife Service is required to make a determination of listing of numerous species as endangered or threatened under the Endangered Species Act prior to the completion of the agency’s 2017 fiscal year. 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.

Furthermore, our information technology systems may be vulnerable to security breaches beyond our control, including those involving cyberattacks using viruses, worms or other destructive software, process breakdowns, phishing or other malicious activities, or any combination of the foregoing. 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. Prior to the March 2018 sale of the Offshore Services segment, our properties also

24



included heavy lift barge rigs and dive support vessels, each of which are included in the assets owned as of December 31, 2017. The following information describes facilities that we leased or owned as of December 31, 2017. We believe our facilities are adequate for our present needs.
 
Facilities
 
Fluids Division
 
Our Fluids 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 Fluids Division owns or leases multiple service center facilities in the United States and in other countries. The Fluids 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.

Production Testing Division
 
The Production Testing segment 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 Production Testing segment 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 and Oklahoma City, Oklahoma, and several owned and leased service and sales facilities in Argentina, Canada, Mexico, and the United States. All obligations under the bank revolving credit facility for CCLP are secured by a first lien security interest in substantially all of CCLP’s assets, including the Midland, Texas and Oklahoma City, Oklahoma facilities.

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

Offshore Division
 
The Offshore Division conducts its operations through four offices and service facility locations (three of which are leased) located in Texas and Louisiana. In addition, as of December 31, 2017, the Offshore Services segment owned the following fleet of vessels that it uses in performing its well abandonment, decommissioning, construction, and contract diving operations:
TETRA Hedron
Derrick barge with 1,600-metric-ton revolving crane
TETRA Arapaho
Derrick barge with 725-metric-ton revolving crane
Epic Explorer
210-foot dive support vessel with saturation diving system
 
We have access to additional leased vessels as needed to adjust to demand for our services. Each of the above properties were sold as part of the March 2018 disposition of our Offshore Division.

25



 
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 Fluids 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.
 
Price Range of Common Stock
 
Our common stock is traded on the New York Stock Exchange under the symbol “TTI.” As of March 2, 2018, there were approximately 359 holders of record of the common stock. The following table sets forth the high and low sale prices of the common stock for each calendar quarter in the two years ended December 31, 2017, as reported by the New York Stock Exchange.
 
 
High
 
Low
2017
 
 

 
 

First Quarter
 
$
5.23

 
$
3.53

Second Quarter
 
4.26

 
2.67

Third Quarter
 
3.12

 
1.87

Fourth Quarter
 
4.40

 
2.63

2016
 
 

 
 

First Quarter
 
$
7.81

 
$
4.62

Second Quarter
 
7.75

 
4.65

Third Quarter
 
6.77

 
5.33

Fourth Quarter
 
6.34

 
4.36

 
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

26



Service), assuming $100 invested in each stock or index on December 31, 2012, 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.

marketpricegrapha01.gif

Dividend Policy
 
We have never paid cash dividends on our common stock. We currently intend to retain earnings to finance the growth and development of our business. Any payment of cash dividends in the future will depend upon our financial condition, capital requirements, and earnings, as well as other factors the Board of Directors may deem relevant. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operation – Liquidity and Capital Resources” for a discussion of potential restrictions on our ability to pay dividends.
 
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 2017 pursuant to the repurchase program. Shares repurchased during the fourth quarter of 2017, 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, 2017
 
162

 
(2)
 
$
2.84

 

 
$
14,327,000

Nov 1 – Nov 30, 2017
 
29,781

 
(2)
 
3.24

 

 
14,327,000

Dec 1 – Dec 31, 2017
 
1,549

 
(2)
 
4.13

 

 
14,327,000

Total
 
31,492

 
 
 
 

 

 
$
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.

27



(2) 
Shares we received in connection with the exercise of certain employee stock options or the vesting of certain employee restricted stock. 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, 2017, 2016, 2015, 2014, and 2013. 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 which might cause the selected consolidated financial data not to be indicative of our future financial condition or results of operations. During 2016, 2015, and 2014, we recorded significant impairments of long-lived assets and goodwill. During 2014 and 2013, we recorded significant charges to earnings associated with Maritech's decommissioning liabilities. 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 for 2016 to earlier years.
 
 
Year Ended December 31,
 
 
2017
 
2016
 
2015
 
2014
 
2013
 
 
 
(In Thousands, Except Per Share Amounts)
Income Statement Data
 
 

 
 

 
 

 
 

 
 

 
Revenues
 
$
820,378

 
$
694,764

 
$
1,130,145

 
$
1,077,567

 
$
909,398

 
Gross profit
 
99,824

 
51,417

 
189,236

 
95,044

 
135,392

 
General and administrative expense
 
121,905

 
115,964

 
157,812

 
142,689

 
131,466

 
Goodwill impairment
 

 
106,205

 
177,006

 
64,295

 

 
Interest expense
 
58,027

 
59,996

 
55,165

 
35,711

 
18,278

 
Interest income
 
(781
)
 
(1,370
)
 
(690
)
 
(745
)
 
(296
)
 
Other (income) expense, net
 
(18,344
)
 
7,712

 
1,706

 
10,965

 
(13,928
)
 
Loss before taxes
 
(60,983
)
 
(237,090
)
 
(201,763
)
 
(157,871
)
 
(128
)
 
Net income (loss)
 
(62,183
)
 
(239,393
)
 
(209,467
)
 
(167,575
)
 
3,326

 
Net income (loss) attributable to TETRA stockholders
 
$
(39,048
)
 
$
(161,462
)
 
$
(126,183
)
 
$
(169,678
)
 
$
153

 
Income (loss) per share, before discontinued operations attributable to TETRA stockholders
 
$
(0.34
)
 
$
(1.85
)
 
$
(1.59
)
 
$
(2.16
)
 
$

 
Average shares
 
114,499

 
87,286

 
79,169

 
78,600

 
77,954

 
Income (loss) per diluted share, before discontinued operations attributable to TETRA stockholders
 
$
(0.34
)
 
$
(1.85
)
 
$
(1.59
)
 
$
(2.16
)
 
$

 
Average diluted shares
 
114,499

(1) 
87,286

(1) 
79,169

(1) 
78,600

(1) 
78,840

(2) 
(1) 
For the years ended December 31, 2017, 2016, 2015, and 2014, the calculation of average diluted shares outstanding excludes the impact of all outstanding stock options and warrants, as the inclusion of these shares would have been antidilutive due to the net loss recorded during the year.
(2) 
For the year ended December 31, 2013, the calculation of average diluted shares outstanding excludes the impact of 2,061,534 average outstanding stock options that would have been antidilutive.


28



 
 
December 31,
 
 
2017
 
2016
 
2015
 
2014
 
2013
 
 
(In Thousands)
Balance Sheet Data
 
 

 
 

 
 

 
 

 
 

Working capital
 
$
164,640

 
$
158,906

 
$
168,783

 
$
121,476

 
$
200,227

Total assets
 
1,308,614

 
1,315,540

 
1,636,202

 
2,063,522

 
1,203,786

Long-term debt, net
 
629,855

 
623,730

 
853,228

 
826,095

 
384,980

Decommissioning and other long-term liabilities
 
77,846

 
78,894

 
83,548

 
93,366

 
48,282

CCLP Series A Preferred Units
 
61,436

 
77,062

 

 

 

Warrant Liability
 
13,202

 
18,503

 

 

 

Total equity
 
352,561

 
400,466

 
514,180

 
765,601

 
597,498



29



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.

Business Overview 
    
Improving oil and natural gas commodity pricing during late 2017 and early 2018 have spurred increased industry drilling and completion activity. As a result, we have seen improved demand for many of our products and services compared to 2016. Increased onshore rig counts are reflected in improved demand in many of our U.S. markets, particularly in the Permian Basin of Texas which is expected to continue with increased demand during the remainder of 2018. Despite flat offshore rig counts compared to 2016, demand from certain of our offshore Fluids Division customers continued to be strong during 2017. As a result, our Fluids and Production Testing Divisions reflect increased revenues and improved profitability during 2017 compared to 2016. These increases have occurred despite continuing customer pricing pressure for all of our businesses. Fluids Division revenues and operating cash flows are expected to further increase following the acquisition of SwiftWater Energy Services, LLC ("SwiftWater"), which is engaged in the business of providing water management and water solutions to oil and gas operators in the Permian Basin market of Texas. Our Compression Division, through our CSI Compressco LP subsidiary ("CCLP") continues to report improved utilization for its compressor equipment fleet, particularly for its high- and mid-level horsepower compression services. Following a record $66.7 million sales order received from a customer in early 2018, its new equipment sales backlog has significantly increased from the prior year. Increased overall industry activity levels are expected to continue in 2018, which should result in further easing of customer pricing pressures and result in continued increased revenues and profitability going forward for each of our businesses. For our Offshore Services segment, which was sold on March 1, 2018, increased activity levels resulted in increased revenues, although challenging weather conditions during 2017 resulted in reduced profitability. Despite the recent increase in operating activity levels, we continue to minimize headcount additions and seek to maintain the reduced operating and administrative cost structure implemented during the past three years, notwithstanding the reinstatement of company-wide wages and benefits to their levels prior to the reductions that were implemented during 2016. As a result of the above factors, consolidated revenues and gross profit each increased significantly during 2017 compared to 2016. Our consolidated pretax loss was also reduced compared to 2016 primarily due to goodwill impairments recorded during the prior year, fair market valuation gains associated with our warrants liability and the CCLP Series A Preferred Units recorded during 2017, and the net gain from litigation arbitration awards recorded during 2017.

On March 1, 2018, we closed a series of related transactions that resulted in the disposition of our Offshore Division. Pursuant to an Asset Purchase and Sale Agreement (the "Maritech Asset Purchase Agreement") with Orinoco Natural Resources, LLC ("Orinoco"), Orinoco purchased certain offshore oil, gas and mineral leases and related assets of Maritech (the "Maritech Properties"). Immediately thereafter, we closed a Membership Interest Purchase and Sale Agreement (the "Maritech Equity Purchase Agreement") with Orinoco, whereby Orinoco purchased all of the equity interests of Maritech (the "Maritech Equity Interests"). Immediately thereafter, we closed an Equity Interest Purchase Agreement (the "Offshore Services Purchase Agreement") with Epic Offshore Specialty, LLC, an affiliate of Orinoco ("Epic Offshore"), whereby Epic Offshore purchased (the "Offshore Services Sale") all of the equity in the wholly owned subsidiaries that comprise our Offshore Services segment operations (the "Offshore Services Equity Interests"). As a result of these transactions, we have effectively exited the businesses of our Offshore Services and Maritech segments.

Our consolidated cash provided by operating activities during the year ended December 31, 2017 increased by $8.9 million, or 16.1%, compared to the prior year. This increase in consolidated cash provided by operating activities was driven primarily by improved operating profitability, and despite cash being used during 2017 for working capital changes primarily related to the timing of collections of accounts receivable. We and CCLP continue to maintain our efforts to manage working capital. We and CCLP believe that maintaining reduced cost structures and monitoring our balance sheets and capital structures on an ongoing basis enhances our respective abilities to remain fiscally responsible as the current customer pricing environment continues to improve and positions each of us to capitalize on growth opportunities. Consolidated capital expenditures were $51.9 million during the year ended December 31, 2017, and included $25.9 million of capital expenditures by our Compression Division, compared to $21.1 million of consolidated capital expenditures during the prior year, including $11.6 million

30



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 made for the most attractive growth opportunities. Key objectives associated with our separate capital structure (excluding the capital structure of CCLP) include the ongoing management of amounts outstanding and available under our Credit Agreement and repayment of our 11% Senior Note.

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 $512.2 million of our consolidated debt balance is owed by CCLP, and is to be serviced by CCLP's existing cash balances and cash provided by CCLP's operations (less its capital expenditures) and is secured by the assets of CCLP.

The following table provides condensed consolidating balance sheet information reflecting our net assets and CCLP's net assets that service our and its respective capital structures.
 
December 31, 2017
Condensed Consolidating Balance Sheet
TETRA
 
CCLP
 
Eliminations
 
Consolidated
 
(In Thousands)
Cash, excluding restricted cash
$
18,527

 
$
7,601

 
$

 
$
26,128

Affiliate receivables
3,034

 

 
(3,034
)
 

Other current assets
217,680

 
94,546

 
 
 
312,226

Property, plant and equipment, net
288,826

 
606,479

 

 
895,305

Other assets, including investment in CCLP
19

 
34,306

 
40,630

 
74,955

Total assets
$
528,086

 
$
742,932

 
$
37,596

 
$
1,308,614

 
 
 
 
 
 
 
 
Affiliate payables
$

 
$
3,034

 
$
(3,034
)
 
$

Current portion of long-term debt

 

 

 

Other current liabilities
112,742

 
60,972

 

 
173,714

Long-term debt, net
117,679

 
512,176

 

 
629,855

  CCLP Series A Preferred Units

 
70,260

 
(8,824
)
 
61,436

Warrant liability
13,202

 

 

 
13,202

Other non-current liabilities
76,383

 
1,463

 


 
77,846

Total equity
208,080

 
95,027

 
49,454

 
352,561

Total liabilities and equity
$
528,086

 
$
742,932

 
$
37,596

 
$
1,308,614


TETRA’s debt is serviced by our 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, 2017, consolidated cash provided from operating activities was $64.6 million, which included approximately $39.1 million generated by CCLP. During 2017, we received $14.2 million from CCLP as our share of CCLP distributions. In April 2017, CCLP announced a reduction of approximately 50% in the level of cash distributions to its common unitholders, including us. Despite the current level of cash distributions from CCLP, we believe that current increased levels of operating activity along with the cost reduction steps we and CCLP have taken during the past two years 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, natural gas compression infrastructure, and for the plugging and decommissioning of abandoned offshore oil and natural gas properties. 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;

31



applications for many of our products and services in the continuing exploitation and development of shale reservoirs;
increased regulatory requirements governing the abandonment and decommissioning work on aging offshore platforms and wells in the Gulf of Mexico; and
increases in selected international oil and gas exploration and development activities.
 
Our Fluids 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 Fluids 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. The Fluids Division also provides domestic onshore oil and gas operators with a wide variety of water management services. Fluids Division revenues increased $88.7 million during 2017 compared to 2016, primarily due 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 the period. While offshore rig counts remain low, we have seen an increase in demand from our customers, contributing to this increase. In addition, international offshore fluid sales and onshore manufactured product sales increased compared to the prior year. The Fluids water management business is also dependent upon domestic drilling activity, particularly in unconventional shale gas and oil reservoirs. North American onshore rig counts increased during 2017 compared to the prior year. Water management service revenues increased resulting from the impact of increased demand, reflecting the growth in domestic onshore rig count.

Our Production Testing Division generates revenues and cash flows by performing frac flowback, production well testing, offshore rig cooling, early production, and other associated services and products. The primary markets served by the Production Testing Division include 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 Production Testing Division’s production testing 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 Production Testing Division serves. Many of the markets served by the Production Testing 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. The Production Testing Division’s revenues increased by $30.5 million in 2017 compared to 2016, due to increased activity in certain domestic and international markets and product sales revenues associated with international equipment sales. Onshore U.S. activity levels in certain markets have reflected increased rig counts compared to the prior year, although customer pricing levels continue to be challenging due to excess availability of equipment.

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, custom-designed compressor packages, and oilfield pump systems 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 decreased $15.8 million in 2017 as compared to 2016, due to reductions in both compressor sales and compression and related services revenues. Although overall utilization of the Compression Division's compressor fleet has improved sequentially for five consecutive quarterly periods, customer pricing for compression services and demand for low-horsepower production enhancement compression services remains challenged.

Our Offshore Division consists of two operating segments, both of which were disposed in the March 1, 2018 sale: Offshore Services and Maritech. The Offshore Services segment generates revenues and cash flows by performing (1) downhole and subsea services such as oil and gas well plugging and abandonment and workover services, (2) decommissioning and certain construction services utilizing heavy lift barges and various cutting technologies with regard to offshore oil and gas production platforms and pipelines, and (3) conventional and saturated diving services. Offshore Services revenues increased by $19.2 million during 2017 compared to 2016, due to increased revenues from its diving, well abandonment, and cutting businesses, partially offset by decreased

32



heavy lift services revenues. Decreased heavy lift activity levels in the U.S. Gulf of Mexico 2017 reflects decreased utilization, reflecting the impact of increased hurricane activity and other weather disruptions in the U.S. Gulf of Mexico that caused significant downtime during 2017. Revenues for work performed for Maritech are eliminated in consolidation. Demand for services in 2017 reflects recent reduced volatility of oil and natural gas commodity prices.
 
The sale of substantially all of Maritech’s offshore oil and gas producing properties during 2011 and 2012 essentially removed us from the oil and gas exploration and production business. Maritech's remaining assets and operations, as well as its asset retirement obligations, were conveyed in the March 1, 2018 sale described in Item 1 - Business to Orinoco.

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 United States generally accepted accounting principles. 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 (the Warrants and CCLP Preferred Units), the collectability of accounts receivable, and the current cost of future abandonment and decommissioning obligations. “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 environment 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, 2017, the estimated fair value of the Warrants was $13.2 million, and the $5.3 million change in fair value during the year was credited to earnings during the period. As of December 31, 2017, the estimated fair value of the CCLP Preferred Units was $61.4 million, and the $3.0 million change in fair value during the year was credited to earnings during the period.

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

33



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 2017, primarily as a result of the decreased expected future cash flows from a specific customer contract, we recorded consolidated long-lived asset impairments of $14.9 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. As of December 31, 2017, consolidated goodwill consists of the $6.6 million goodwill attributed to our Fluids reporting unit. The assessment for goodwill impairment begins with a qualitative assessment of whether it is “more likely than not” that the fair value of each reporting unit is less than its carrying value. This qualitative assessment requires the evaluation, based on the weight of evidence, of the significance of all identified events and circumstances for each reporting unit. Based on this qualitative assessment, we determined that due to the reduced volatility of oil and natural gas commodity prices during 2017 and the improving demand for the products and services for our Fluids Division businesses, it was not “more likely than not” that the fair value of our Fluids reporting unit was less than its carrying value as of December 31, 2017.

When the qualitative analysis indicates that it is “more likely than not” that a reporting unit’s fair value is less than its carrying value, the resulting goodwill impairment test consists of a two-step accounting test performed on a reporting unit basis. 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.

Throughout 2015 and 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, demand for low-horsepower wellhead compression services and for sales of compressor equipment was decreased significantly. Accordingly, the fair value for the Compression Division reporting unit, including the market capitalization for CCLP, was less than its carrying value as of December 31, 2015. In addition, 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, despite impairments recorded as of December 31, 2015. For our Production Testing Division reporting unit, demand for production testing services was decreased in each of the market areas in which we operate, resulting in decreased estimated future cash flows. As a result, the fair value of the Production Testing reporting unit was also less than its carrying value as of December 31, 2015. In addition, the market activity continued to decrease during the first quarter of 2016 and as a result the fair value of the Production Testing reporting unit was also less than its carrying value as of March 31, 2016, despite impairments recorded as of December 31, 2015. After making the hypothetical purchase price adjustments as part of the second step of the goodwill impairment test as of March 31, 2016, there was $0.0 million residual purchase price to be allocated to the goodwill of the Compression reporting unit and $0.0 million residual purchase price to be allocated to the goodwill of the Production Testing reporting unit. Based on this analysis, we concluded that a full impairment of $92.3 million of remaining recorded goodwill for Compression and a

34



full impairment of $13.9 million of the remaining recorded goodwill for Production Testing was required as of March 31, 2016.

Maritech Decommissioning Liabilities
 
Maritech records a liability associated with the costs of abandoning and decommissioning the wells, platforms, and pipelines located on its oil and gas leases, as well as removing associated debris. Maritech’s decommissioning liabilities are established based on what Maritech estimates a third party would charge to perform these services. These well abandonment and decommissioning liabilities (referred to as decommissioning liabilities) are recorded net of amounts allocable to joint interest owners. In estimating the decommissioning liabilities, we perform detailed estimating procedures, analysis, and engineering studies. Whenever practical, Maritech settles these decommissioning liabilities by utilizing the services of its affiliated companies to perform well abandonment and decommissioning work. This practice saves us the profit margin that a third party would charge for such services. When these services are performed by an affiliated company, all recorded intercompany revenues are eliminated in the consolidated financial statements. Any difference between our own internal costs to settle the decommissioning liability and the recorded liability is recognized in the period in which we perform the work. The recorded decommissioning liability associated with a specific property is fully extinguished when the property is completely abandoned. Once a Maritech well abandonment and decommissioning project is performed, any remaining decommissioning liability in excess of the actual cost of the work performed is recorded as a gain and is included in earnings in the period in which the project is completed. Conversely, estimated or actual costs in excess of the decommissioning liability are charged against earnings in the period in which the work is estimated or performed.
 
We review the adequacy of our decommissioning liabilities whenever indicators suggest that either the amount or timing of the estimated cash flows underlying the liabilities have changed materially. The amount of cash flows necessary to abandon and decommission the property is subject to changes due to seasonal demand, increased demand following hurricanes, regulatory changes, and other general changes in the energy industry environment. Accordingly, the estimation of our decommissioning liabilities is imprecise. Asset retirement obligations are recorded in accordance with ASC 410 "Asset Retirement and Environmental Obligations," whereby the estimated fair value of a liability for asset retirement obligations is recorded in the period in which it is incurred and in which a reasonable estimate can be made. Such estimates are based on relevant assumptions that we believe are reasonable. The cost estimates for Maritech asset retirement obligations are considered reasonable estimates consistent with market conditions at the time they are made, and we believe they reflect the amount of work legally obligated to be performed in accordance with BSEE standards, as revised from time to time.
    
During each of the three years ended December 31, 2017, Maritech adjusted its decommissioning liabilities as a result of increased estimates, as well as the actual cost of significant abandonment and decommissioning work performed during each of those years. Maritech recorded approximately $5.3 million of excess decommissioning expense during the three years ended December 31, 2017, associated with work performed or to be performed on its oil and gas properties. The actual cost of performing Maritech’s well abandonment and decommissioning work has often exceeded Maritech's initial estimate of these decommissioning liabilities and has resulted in charges to earnings in the period the work is performed or when the additional liability is determined. The Maritech Properties, and Maritech itself, including its asset retirement obligations, were sold in the March 1, 2018 sale to Orinoco.
 
Revenue Recognition
 
We generate revenue on certain well abandonment, decommissioning, and dive services projects under contracts which are typically of short duration and that provide for either lump-sum charges or specific time, material, and equipment charges, which are billed in accordance with the terms of such contracts. We generally recognize revenue once the following four criteria are met: (1) persuasive evidence of an arrangement exists; (2) delivery has occurred or services have been provided; (3) the sales price is fixed or determinable; and (4) collectability is reasonably assured.

The majority of our compression services are provided pursuant to contract terms ranging from one month to twenty-four months. Collections associated with progressive billings to customers for the construction of compression equipment are generally included in unearned income in the consolidated balance sheets until such time as the equipment is delivered.
 

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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. 
 
On December 22, 2017, H.R.1, “An Act to Provide the Reconciliation Pursuant to Titles II and V of the Concurrent Resolution on the Budget for Fiscal Year 2018” (the “Act”) (previously known as “The Tax Cuts and Jobs Act”) was signed into law making significant changes to the Internal Revenue Code. Changes include, but are 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 have calculated 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 as of the date of this filing. See "Note E - Income Taxes" contained in the Notes to Consolidated Financial Statements for the effect on our 2017 tax provision.
 

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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.
 
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
 
$
820,378

 
$
694,764

 
$
125,614

 
18.1
 %
Gross profit
 
99,824

 
51,417

 
48,407

 
94.1
 %
Gross profit as a percentage of revenue
 
12.2
 %
 
7.4
 %
 
 

 
 

General and administrative expense
 
121,905

 
115,964

 
5,941

 
5.1
 %
General and administrative expense as a percentage of revenue
 
14.9
 %
 
16.7
 %
 
 

 
 
Goodwill impairment
 

 
106,205

 
(106,205
)
 
 
Interest expense, net
 
57,246

 
58,626

 
(1,380
)
 
(2.4
)%
(Gain) loss on sale of assets
 
(674
)
 
(2,357
)
 
1,683

 
 

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 expense (income), net

 
(10,027
)
 

 
(10,027
)
 
 
Other (income) expense, net
 
633

 
3,559

 
(2,926
)
 
 

Loss before taxes
 
(60,983
)
 
(237,090
)
 
176,107

 


Income (loss) before taxes as a percentage of revenue
 
(7.4
)%
 
(34.1
)%
 
 

 
 

Provision (benefit) for income taxes
 
1,200

 
2,303

 
(1,103
)
 


Net loss
 
(62,183
)
 
(239,393
)
 
177,210

 


Net (income) loss attributable to noncontrolling interest
 
23,135

 
77,931

 
(54,796
)
 
 

Net 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 Fluids Division revenues, which increased by $88.7 million, driven by increased sales of offshore completion fluids products and onshore water management services activity. Fluids Division revenues are expected to further increase following the acquisition of SwiftWater. In addition, our Production Testing Division and Offshore Services segments 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 equipment earlier in 2017 and pricing pressures for compression services, and 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 an improving demand for many of our products and services. Following the March 2018 sale of our Offshore Division, Offshore Services and Maritech operations will be discontinued, decreasing our consolidated revenues going forward. See Divisional Comparisons section below for additional discussion.

Consolidated gross profit increased significantly during 2017 compared to the prior year due to increased revenues and activity, particularly for the Fluids Division. Despite the improving demand for many of our products and services, the impact of pricing pressures continues 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 $9.8 million of increased salary related expenses and $2.1 million of insurance and other general

37



expenses, partly offset by decreased professional services fees of $4.3 million and decreased bad debt expense of $1.5 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. The continued decreased oil and natural gas commodity 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 compressor equipment had decreased significantly and was expected to continue to be decreased for the foreseeable future. Demand for our Production Testing Division's 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 our CCLP subsidiary, 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 recorded 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 distributions on the CCLP Preferred Units that were issued during late 2016. 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 Production Testing 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.

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, resulting in future volatility of our earnings during the period the CCLP Preferred Units are outstanding.

In January 2017, our Fluids 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. Partially offsetting this award, the Offshore Services segment recorded a charge to earnings of $2.8 million associated with a litigation arbitration ruling related to a dispute over leased vessel charges.

Consolidated other (income) expense, net, was $0.6 million of expense during 2017 compared to $3.6 million of expense during the prior year, with the improvement primarily due to $2.1 million of issuance costs from the CCLP Preferred Units which were issued during the prior year and $1.8 million of unamortized deferred finance costs that were charged to earnings in the prior year as a result of the repayment of senior notes and senior secured notes. In addition, $0.6 million of insurance recoveries were credited to other income during 2017. Partially offsetting these decreases is $2.9 million of decreased other income associated with Maritech, $2.4 million of decreased currency gains, and $1.4 million of decreased net gains on the extinguishment of the CCLP 7.25% Senior Notes.


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Our consolidated provisions 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 2.0% was primarily the result of losses generated in entities for which no related tax benefit has been recorded. The losses generated by these entities do not result in tax benefits due to offsetting valuation allowances being recorded against the related net deferred tax assets. We establish a valuation allowance to reduce the deferred tax assets when it is more likely than not that some portion or all of the deferred tax assets will not be realized. Included in our deferred tax assets are 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.

On December 22, 2017, H.R.1, “An Act to Provide the Reconciliation Pursuant to Titles II and V of the Concurrent Resolution on the Budget for Fiscal Year 2018” (the “Act”) (previously known as “The Tax Cuts and Jobs Act”) was signed into law making significant changes to the Internal Revenue Code. Changes include, but are 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 have calculated 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 as of the date of this filing. See "Note E - Income Taxes" contained in the Notes to Consolidated Financial Statements for the effect on our 2017 tax provision.

Divisional Comparisons
 
Fluids Division
 
 
Year Ended
December 31,
 
Period to Period Change
 
 
2017
 
2016
 
2017 vs. 2016
 
% Change
 
 
(In Thousands, Except Percentages)
Revenues
 
$
335,331

 
$
246,595

 
$
88,736

 
36.0
 %
Gross profit
 
81,839

 
36,888

 
44,951

 
121.9
 %
Gross profit as a percentage of revenue
 
24.4
%
 
15.0
%
 
 

 
 

General and administrative expense
 
25,874

 
27,650

 
(1,776
)
 
(6.4
)%
General and administrative expense as a percentage of revenue
 
7.7
%
 
11.2
%
 
 

 
 

Interest (income) expense, net
 
(53
)
 
(4
)
 
(49
)
 
 

Litigation arbitration award income
 
(12,816
)
 

 
(12,816
)
 
 
Other (income) expense, net
 
294

 
(1,188
)
 
1,482

 
 

Income before taxes
 
$
68,540

 
$
10,430

 
$
58,110

 
557.1
 %
Income before taxes and discontinued operations as a percentage of revenue
 
20.4
%
 
4.2
%
 
 

 
 

 
Increased Fluids Division revenues during 2017 compared to the prior year were primarily due to $49.7 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 customers, contributing to this increase. In addition, international offshore fluid sales and onshore manufactured product sales increased compared to the prior year. Service revenues increased $39.1 million, primarily due to increased water management services activity resulting from the impact of increased demand, reflecting the growth in domestic onshore rig count. Fluids Division revenues are expected to further increase following the February 2018 acquisition of SwiftWater, which is engaged in the business of providing water management and water solutions to oil and gas operators in the Permian Basin market of Texas.

Fluids Division gross profit during 2017 increased significantly 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 and increased revenues and improved profitability from water management services. Fluids Division profitability in future periods will continue to be affected by the mix of its products and services.

39




The Fluids 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. Fluids Division administrative cost levels decreased compared to the prior year period, primarily due to $3.7 million of decreased legal and professional fees, following the legal arbitration award. In addition, bad debt expense decreased by $0.1 million. These decreases were partially offset by $1.1 million of increased wage and benefit related expenses, and $0.3 million of increased insurance and other general expense. The Fluids Division continues to review opportunities to further reduce its administrative costs. 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.

Production Testing Division
 
 
Year Ended
December 31,
 
Period to Period Change
 
 
2017
 
2016
 
2017 vs. 2016
 
% Change
 
 
(In Thousands, Except Percentages)
Revenues
 
$
94,142

 
$
63,618

 
$
30,524

 
48.0
 %
Gross profit (loss)
 
(8,498
)
 
(13,317
)
 
4,819

 
(36.2
)%
Gross profit (loss) as a percentage of revenue
 
(9.0
)%
 
(20.9
)%
 
 

 
 

General and administrative expense
 
9,942

 
9,806

 
136

 
1.4
 %
General and administrative expense as a percentage of revenue
 
10.6
 %
 
15.4
 %
 
 

 
 

Goodwill impairment
 

 
13,871

 
(13,871
)
 


Interest (income) expense, net
 
(296
)
 
(594
)
 
298

 
 

Other (income) expense, net
 
(679
)
 
(929
)
 
250

 
 

Loss before taxes
 
$
(17,465
)
 
$
(35,471
)
 
$
18,006

 
50.8
 %
Loss before taxes and discontinued operations as a percentage of revenue
 
(18.6
)%
 
(55.8
)%
 
 

 
 

 
Production Testing Division revenues increased during 2017 compared to the prior year primarily due to increased service revenues of $18.4 million during 2017 compared to the prior year, reflecting increased 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. Production Testing revenues also increased during 2017 due to $12.1 million of product sales revenues associated with international equipment sales.

The Production Testing Division reflected a decreased gross loss during 2017 compared to the prior year 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 Production Testing 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 salary and benefit expenses. Other income, net decreased primarily due to decreased foreign currency gains.


40



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 (income) 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
)
 
 

Income (loss) before taxes
 
$
(37,246
)
 
$
(136,327
)
 
$
99,081

 
(72.7
)%
Income (loss) before taxes and discontinued operations as a percentage of revenue
 
(12.6
)%
 
(43.8
)%
 
 

 
 

 
Compression Division revenues decreased during 2017 compared to the prior year due to reductions in both compression and related services revenues and compressor 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 compressor fleet utilization. Increased demand is expected to result in improved customer pricing during 2018. Although overall utilization of the Compression Division's compressor fleet has improved sequentially for five consecutive quarterly periods, demand for low-horsepower production enhancement compression services remains challenged. Revenues from sales of compressor packages and parts during 2017 decreased $5.1 million compared to the prior year period primarily due to decreased sales of new compressor packages. However, given the significant increase in new compression equipment sales backlog during the last half of 2017 and early 2018, increased sales of compressor packages are expected beginning in 2018.

Compression Division gross profit decreased during 2017 compared to the prior year despite an approximately $2.4 million insurance recovery in 2017 for equipment that was damaged and impaired in the prior year, and despite a $10.2 million impairment of long-lived assets that was recorded during the prior year period. This decrease in gross profit was primarily due to the competitive 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 the prior year period 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 distributions on the CCLP Preferred Units, that were issued during the third quarter of 2016.

Offshore Division

On March 1, 2018, we closed a series of related transactions that resulted in the disposition of the Offshore Division. Pursuant to the Maritech Asset Purchase Agreement with Orinoco, Orinoco purchased the Maritech Properties. Immediately thereafter, we closed the Maritech Equity Purchase Agreement with Orinoco, whereby

41



Orinoco purchased the Maritech Equity Interests. Immediately thereafter, we closed the Offshore Services Purchase Agreement with Epic Offshore, an affiliate of Orinoco, whereby Epic Offshore purchased (the "Offshore Services Sale") all of the Offshore Services Equity Interests. As a result of these transactions, we have effectively exited the businesses of our Offshore Services and Maritech segments. As a result of these transactions, our consolidated results of operations for the quarterly period ending March 31, 2018, will include a loss on the disposal of our Offshore Division, estimated to range from approximately $33.0 million to $35.0 million.
 
Offshore Services Segment
 
 
Year Ended
December 31,
 
Period to Period Change
 
 
2017
 
2016
 
2017 vs. 2016
 
% Change
 
 
(In Thousands, Except Percentages)
Revenues
 
$
96,741

 
$
77,525

 
$
19,216

 
24.8
 %
Gross profit (loss)
 
(6,612
)
 
(5,574
)
 
(1,038
)
 
(18.6
)%
Gross profit as a percentage of revenue
 
(6.8
)%
 
(7.2
)%
 
 

 
 

General and administrative expense
 
5,708

 
6,454

 
(746
)
 
(11.6
)%
General and administrative expense as a percentage of revenue
 
5.9
 %
 
8.3
 %
 
 

 
 

Litigation arbitration award expense
 
2,789

 

 
2,789

 
 
Other (income) expense, net
 
(342
)
 
(3
)
 
(339
)
 
 

Loss before taxes
 
$
(14,767
)
 
$
(12,025
)
 
$
(2,742
)
 
(22.8
)%
Loss before taxes and discontinued operations as a percentage of revenue
 
(15.3
)%
 
(15.5
)%
 
 

 
 


Revenues for the Offshore Services segment increased during 2017 compared to the prior year due to increased revenues from its diving, well abandonment, and cutting services businesses. Heavy lift activity revenues decreased slightly during 2017, reflecting decreased utilization, due to the impact of increased hurricane activity and other weather disruptions in the U.S. Gulf of Mexico that caused significant downtime during 2017. Additionally, the remainder of Offshore Services businesses were also negatively impacted by the more significant weather downtime. There were no revenues from Offshore Services work performed for our Maritech segment during 2017.

The Offshore Services segment reported an increased gross loss for 2017 as the impact of decreased activity levels for heavy lift services more than offset the improved profitability from diving, well abandonment, and cutting services businesses. The gross loss was increased due to weather disruptions during 2017 as noted above. In addition, significant activity levels have resulted in the Offshore Services segment leasing third-party equipment to serve certain customers, resulting in increased operating costs. The Offshore Services segment also recorded a $1.1 million long-lived asset impairment during 2016.
 
Offshore Services segment loss before taxes increased compared to the prior year period primarily due to a charge to earnings associated with a litigation arbitration ruling related to a dispute over leased vessel charges, as well as due to the increase gross loss discussed above. The increased segment pretax loss occurred despite a reduction in general and administrative expenses, that was primarily from reduced salary and employee related expenses of $0.9 million, partially offset by increased bad debt expenses of $0.2 million.



42



Maritech Segment
 
 
Year Ended
December 31,
 
Period to Period Change
 
 
2017
 
2016
 
2017 vs. 2016
 
% Change
 
 
(In Thousands, Except Percentages)
Revenues
 
$
538

 
$
751

 
$
(213
)
 
(28.4
)%
Gross profit (loss)
 
(1,954
)
 
(3,847
)
 
1,893

 
49.2
 %
General and administrative expense
 
783

 
1,087

 
(304
)
 
(28.0
)%
General and administrative expense as a percentage of revenue
 
145.5
%
 
144.7
%
 
 

 
 

Interest (income) expense, net
 

 
12

 
(12
)
 
 

(Gain) loss on sales of assets
 
(400
)
 

 
(400
)
 
 

Other (income) expense, net
 
(165
)
 
(3,105
)
 
2,940

 
 

Loss before taxes
 
$
(2,172
)
 
$
(1,841
)
 
$
(331
)
 
(18.0
)%
 
As a result of the sale of almost all of its producing properties during 2011 and 2012, Maritech revenues were negligible during 2017.

Maritech reported a decreased gross loss during 2017 compared to the prior year, primarily due to charges during the prior year for decommissioning costs incurred in prior periods no longer considered collectible from third parties.

Maritech reported an increased pretax loss during 2017 compared to the prior year despite the decreased gross loss as discussed above. This increased loss is due to a decrease in other income, net, associated with the prior year receipt of funds previously held in escrow as part of a security on contingent abandonment obligations on sold properties.


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 (income) expense, net
 
15,513

 
21,157

 
(5,644
)
 
 

Warrants fair value adjustment (income) expense
 
(5,301
)
 
2,106

 
(7,407
)
 
 
Other (income) expense, net
 
1,269

 
3,404

 
(2,135
)
 
 

Loss before taxes
 
$
(57,721
)
 
$
(61,864
)
 
$
4,143

 
6.7
%
 
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 $0.6 million of increased professional fees. The increased salary, incentives and employee related expenses include the impact of company-wide reinstatements during the first half of 2017 of salaries 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.

43



2016 Compared to 2015
 
Consolidated Comparisons
 
 
Year Ended
December 31,
 
Period to Period Change
 
 
2016
 
2015
 
2016 vs. 2015
 
% Change
 
 
(In Thousands, Except Percentages)
Revenues
 
$
694,764

 
$
1,130,145

 
$
(435,381
)
 
(38.5
)%
Gross profit
 
51,417

 
189,236

 
(137,819
)
 
(72.8
)%
Gross profit as a percentage of revenue
 
7.4
 %
 
16.7
 %
 
 

 
 

General and administrative expense
 
115,964

 
157,812

 
(41,848
)
 
(26.5
)%
General and administrative expense as a percentage of revenue
 
16.7
 %
 
14.0
 %
 
 

 
 

Goodwill impairment
 
106,205

 
177,006

 
(70,801
)
 
 
Interest expense, net
 
58,626

 
54,475

 
4,151

 
7.6
 %
(Gain) loss on sale of assets
 
(2,357
)
 
(4,375
)
 
2,018

 
 

Warrants fair value adjustment
 
2,106

 

 
2,106

 
 
CCLP Series A Preferred fair value adjustment
 
4,404

 

 
4,404

 
 
Other (income) expense, net
 
3,559

 
6,081

 
(2,522
)
 
 

Income (loss) before taxes and discontinued operations
 
(237,090
)
 
(201,763
)
 
(35,327
)
 


Income (loss) before taxes and discontinued operations as a percentage of revenue
 
(34.1
)%
 
(17.9
)%
 
 

 
 

Provision (benefit) for income taxes
 
2,303

 
7,704

 
(5,401
)
 


Net income (loss)
 
(239,393
)
 
(209,467
)
 
(29,926
)
 


Net income attributable to noncontrolling interest
 
77,931

 
83,284

 
(5,353
)
 
 

Net income (loss) attributable to TETRA stockholders
 
$
(161,462
)
 
$
(126,183
)
 
$
(35,279
)
 



Consolidated revenues for 2016 decreased compared to the prior year due to continuing overall oil and gas services industry market challenges as a result of lower oil and natural gas commodity prices compared to 2014 and early 2015. Each of our segments reported decreased revenues due to the impact of reduced demand for our products and services. The Fluids Division reported the most significant reduction in revenues, with decreased completion services and products, water management services, and manufactured product sales combining for $177.5 million of decreased revenues. Our Compression Division also reported significantly decreased revenues during 2016, primarily due to reduced sales of compressor units and from decreased demand for compression services. See Divisional Comparisons section below for additional discussion.

Consolidated gross profit decreased significantly during 2016 compared to the prior year due to the reduced demand for our products and services, as well as the impact of pricing pressures in each of our businesses. Our Fluids Division reported the most significant reduction in gross profit, due to the impact from decreased offshore completion fluids products and services, including those associated with fluid technology projects during the prior year. Our Compression Division reported a decrease in gross profit compared to the prior year primarily due to the decrease in compression services. The results of each of our businesses reflect the impact of company-wide salary reductions and headcount reductions that were implemented during 2016. We continue to review the cost structure of each of our businesses for opportunities to further improve gross profit.
 
Consolidated general and administrative expenses decreased during 2016 compared to the prior year, primarily due to cost reduction efforts across all segments resulting in lower salary and employee related expenses. Despite the cost reductions made during the current year, consolidated general and administrative expense increased as a percentage of consolidated revenues due to the significant decrease in revenues.
 
During the first quarter of 2016, we updated our test of goodwill impairment in accordance with the ASC 350-20 "Goodwill" due to the decreases in the price of our common stock and the common unit price of CCLP. The continued decreased oil and natural gas commodity prices had, and was expected to have, a continuing negative impact on industry drilling and capital expenditure activity, which affects the expected demand for products and

44



services of each of our reporting units. Specifically, demand for our Compression Division's compression services and for sales of compressor equipment decreased significantly and was expected to continue to be decreased for the foreseeable future. Demand for our Production Testing Division's services also 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 our CCLP subsidiary, 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.

Consolidated interest expense increased in 2016 compared to the prior year primarily due to the higher interest rate on the 11% Senior Note that was issued in November 2015 and from the increased interest recorded related to the paid in kind distributions on the CCLP Preferred Units which were issued during 2016. Interest expense during 2016 and 2015 includes $4.1 million and $4.0 million, respectively, of finance cost amortization.
 
Gain on sales of assets decreased during 2016 compared to the prior year primarily due to significant gains on sales of Production Testing Division assets during 2015.

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 will increase (decrease) the associated liability, 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 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, resulting in future volatility of our earnings during the period the CCLP Preferred Units are outstanding.

Consolidated other expense, net, was $3.6 million during 2016 compared to $6.1 million during the prior year. The change in other expense, net, is primarily due to $2.7 million of increased other income associated with Maritech, $2.6 million of increased currency gains, and $1.4 million of net gains on the extinguishment of CCLP Senior Notes. These increases in other income were offset by increased expenses associated with bank and commitment fees of $3.1 million and increased foreign currency exchange losses of $1.4 million.
 
Our consolidated provisions for income taxes during 2016 and 2015 were primarily attributable to taxes in certain foreign jurisdictions and Texas gross margin taxes. Our consolidated effective tax rate for the year ended December 31, 2016 of negative 1.0% was primarily the result of losses generated in entities for which no related tax benefit has been recorded. The losses generated by these entities do not result in tax benefits due to offsetting valuation allowances being recorded against the related net deferred tax assets. We establish a valuation allowance to reduce the deferred tax assets when it is more likely than not that some portion or all of the deferred tax assets will not be realized. Included in our deferred tax assets are 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 is negatively impacted by the nondeductible portion of our goodwill impairments recorded during 2016 and 2015.



45



Divisional Comparisons
 
Fluids Division
 
 
Year Ended
December 31,
 
Period to Period Change
 
 
2016
 
2015
 
2016 vs. 2015
 
% Change
 
 
(In Thousands, Except Percentages)
Revenues
 
$
246,595

 
$
424,044

 
$
(177,449
)
 
(41.8
)%
Gross profit
 
36,888

 
111,969

 
(75,081
)
 
(67.1
)%
Gross profit as a percentage of revenue
 
15.0
%
 
26.4
%
 
 

 
 

General and administrative expense
 
27,650

 
32,576

 
(4,926
)
 
(15.1
)%
General and administrative expense as a percentage of revenue
 
11.2
%
 
7.7
%
 
 

 
 

Interest (income) expense, net
 
(4
)
 
(258
)
 
254

 
 

Other (income) expense, net
 
(1,188
)
 
(1,138
)
 
(50
)
 
 

Income before taxes and discontinued operations
 
$
10,430

 
$
80,789

 
$
(70,359
)
 
(87.1
)%
Income before taxes and discontinued operations as a percentage of revenue
 
4.2
%
 
19.1
%
 
 

 
 

 
Decreased Fluids Division revenues during 2016 compared to the prior year were primarily due to $129.6 million of decreased product sales revenues, which were primarily due to decreased CBF and associated product sales revenues in the U.S. Gulf of Mexico, reflecting the decreased rig count activity compared to the prior year and a decrease resulting from a customer well completion project during the prior year using a completion fluid technology that was introduced during 2015. In addition, product sales revenues also decreased compared to the prior year due to decreased domestic manufactured products sales revenues (as a result of reduced energy industry demand and due to milder winter weather). Service revenues decreased $47.8 million, primarily due to reduced demand in the U.S. Gulf of Mexico for completion services as a result of a reduction in completion activity and due to decreased water management services activity resulting from the impact of lower oil and natural gas commodity prices. We began to see an increased demand in the U.S. Gulf of Mexico for our completion products and services during the second half of 2016.

Fluids Division gross profit during 2016 decreased compared to the prior year primarily due to continued pricing pressures on our products and services, lower revenues and decreased profitability associated with the mix of CBF products and services, particularly for offshore completion fluids products and services associated with the new fluid technology projects during the prior year. In addition, Fluids Division gross profit declined as a result of the reduced demand for manufactured products during 2016 compared to the prior year.
 
The Fluids Division reported a significant decrease in pretax earnings during 2016 compared to the prior year primarily due to the decreased gross profit discussed above. Fluids Division administrative cost levels decreased compared to the prior year, primarily due to $4.2 million of decreased salary and employee expenses due to administrative cost and salary reductions and decreased general, office, and other administrative expenses of $1.9 million. This increase was offset primarily by $1.2 million of increased legal and professional fees associated with litigation involving our El Dorado, Arkansas calcium chloride plant. In January 2017, we received a $12.8 million settlement award as a result of this litigation. Partially offsetting the decreased gross profit, other income increased primarily due to increased foreign currency gains.


46



Production Testing Division
 
 
Year Ended
December 31,
 
Period to Period Change
 
 
2016
 
2015
 
2016 vs. 2015
 
% Change
 
 
(In Thousands, Except Percentages)
Revenues
 
$
63,618

 
$
133,904

 
$
(70,286
)
 
(52.5
)%
Gross profit
 
(13,317
)
 
(3,046
)
 
(10,271
)
 
337.2
 %
Gross profit as a percentage of revenue
 
(20.9
)%
 
(2.3
)%
 
 

 
 

General and administrative expense
 
9,806

 
17,726

 
(7,920
)
 
(44.7
)%
General and administrative expense as a percentage of revenue
 
15.4
 %
 
13.2
 %
 
 

 
 

Goodwill impairment
 
13,871

 
37,562

 
(23,691
)
 
 
Interest (income) expense, net
 
(594
)
 
(89
)
 
(505
)
 
 

Other (income) expense, net
 
(929
)
 
(2,525
)
 
1,596

 
 

Income (loss) before taxes and discontinued operations
 
$
(35,471
)
 
$
(55,720
)
 
$
20,249

 
36.3
 %
Income (loss) before taxes and discontinued operations as a percentage of revenue
 
(55.8
)%
 
(41.6
)%
 
 

 
 


Production Testing Division revenues decreased significantly during 2016 compared to the prior year due to reduced overall market activity. Production Testing service revenues decreased $63.2 million during 2016 compared to the prior year, as the impact of lower oil and natural gas pricing has negatively impacted demand for services in each of the division's areas of operations, including certain shale reservoir markets that were a source of revenue growth during the past several years. Decreased U.S. demand reflects the significant decline in onshore rig count activity compared to the prior year. Although rig count activity has improved in early 2017 compared to 2016 levels, such activity levels are still significantly below early 2015 levels. In addition, increased competition for decreased market activity negatively affected pricing levels for services, particularly internationally. Production Testing product sales decreased $7.1 million, due to a sale of equipment that occurred during 2015.

The Production Testing Division had an increased gross loss during 2016 compared to the prior year due to the decreased industry activity and increased competition as discussed above. This increase in Production Testing Division gross loss was realized despite $6.4 million of long-lived intangible asset impairments during 2016 compared to $12.3 million of long-lived asset impairments recorded during 2015. The increased gross loss occurred despite significant cost reduction efforts, which have included headcount reductions, salary reductions, and other steps to adjust the Production Testing Division's cost structure in light of then current market conditions.
 
The Production Testing Division reported a decreased pretax loss during 2016 compared to the prior year, primarily due to the reduced goodwill impairment recorded during 2016 compared to the prior year. We account for goodwill in accordance with ASC 350-20, and the impairments of goodwill reflect the significant decreases in future profitability and cash flows expected in the current market environment. General and administrative expenses also decreased due to $4.1 million of decreased general, office and bad debt expenses and $3.7 million of decreased employee-related expenses, primarily from reduced headcount, salary reductions, and other employee related cost reductions. The division continues to review additional opportunities to further reduce its operating and administrative cost levels in light of current market conditions. Other income decreased during 2016 compared to the prior year due to decreased gains on asset sales.

 

47



Compression Division
 
 
Year Ended
December 31,
 
Period to Period Change
 
 
2016
 
2015
 
2016 vs. 2015
 
% Change
 
 
(In Thousands, Except Percentages)
Revenues
 
$
311,374

 
$
457,639

 
$
(146,265
)
 
(32.0
)%
Gross profit
 
37,681

 
73,135

 
(35,454
)
 
(48.5
)%
Gross profit as a percentage of revenue
 
12.1
 %
 
16.0
 %
 
 

 
 

General and administrative expense
 
36,199

 
43,356

 
(7,157
)
 
(16.5
)%
General and administrative expense as a percentage of revenue
 
11.6
 %
 
9.5
 %
 
 

 
 

Goodwill impairment
 
92,334

 
139,444

 
(47,110
)
 
 
Interest (income) expense, net
 
38,055

 
34,964

 
3,091

 
 

CCLP Series A Preferred fair value adjustment
 
5,036

 

 
5,036

 
 
Other (income) expense, net
 
2,384

 
2,169

 
215

 
 

Income before taxes and discontinued operations
 
$
(136,327
)
 
$
(146,798
)
 
$
10,471

 
(7.1
)%
Income before taxes and discontinued operations as a percentage of revenue
 
(43.8
)%
 
(32.1
)%
 
 

 
 

 
Compression Division revenues decreased significantly during 2016 compared to the prior year due to reductions in both compressor sales and compression and related services revenues. Revenues from sales of compressor packages during 2016 decreased $69.7 million compared to the prior year due to a reduction in customer projects, particularly for high-horsepower compressor packages. The current reduced equipment fabrication backlog indicates that this decrease in compressor package sales revenues will continue going forward. The $76.6 million decrease in compression and related service revenues resulted primarily from the reduction in overall utilization in total horsepower as well as compression services pricing compared to the prior year. The decreased overall utilization has affected each horsepower class of the Compression Division's fleet, but has particularly decreased the demand for low-horsepower production enhancement compression services as a result of lower oil and natural gas commodity prices compared to the prior year.

Compression Division gross profit decreased during 2016 compared to the prior year as a result of the lower demand for compressors and compression services discussed above. The Compression Division recorded $10.2 million of long-lived intangible asset impairments during 2016 compared to $12.3 million during 2015. Competitive pricing pressures and rate reduction requests in the current market environment have also resulted in reduced gross profit. During 2016, the Compression Division took additional steps to reduce its operating costs and improve operating efficiencies, and efforts to further adjust its cost structure will continue going forward.

The Compression Division recorded a decreased pretax loss during 2016 compared to the prior year. The amount of the pretax loss for both years was significantly increased due to the impairments of goodwill pursuant to ASC 350-20. In addition to the decreased gross profit discussed above, other expense increased primarily due to the CCLP Preferred Units fair value adjustment of $5.0 million and $2.1 million of offering costs associated with the private placements of the CCLP Preferred Units that were issued during 2016. Changes in the fair value of the CCLP Preferred Units may generate additional volatility to our earnings going forward. Interest expense also increased primarily due to the paid in kind distributions on the CCLP Preferred Units and as a result of increased borrowings outstanding by CCLP under the CCLP Credit Agreement during 2016 compared to the prior year. Interest expense on the CCLP Senior Notes decreased beginning in late 2016 due to the repayment of $54.1 million face amount of CCLP Senior Notes in September and October of 2016. General and administrative expense levels decreased compared to the prior year, mainly due to $6.0 million of administrative salary reductions and decreased professional services of $0.8 million.


48



Offshore Division
 
Offshore Services Segment
 
 
Year Ended
December 31,
 
Period to Period Change
 
 
2016
 
2015
 
2016 vs. 2015
 
% Change
 
 
(In Thousands, Except Percentages)
Revenues
 
$
77,525

 
$
122,194

 
$
(44,669
)
 
(36.6
)%
Gross profit
 
(5,574
)
 
10,602

 
(16,176
)
 
(152.6
)%
Gross profit as a percentage of revenue
 
(7.2
)%
 
8.7
 %
 
 

 
 

General and administrative expense
 
6,454

 
10,689

 
(4,235
)
 
(39.6
)%
General and administrative expense as a percentage of revenue
 
8.3
 %
 
8.7
 %
 
 

 
 

Interest (income) expense, net
 

 

 

 
 

Other (income) expense, net
 
(3
)
 
108

 
(111
)
 
 

Income (loss) before taxes and discontinued operations
 
$
(12,025
)
 
$
(195
)
 
$