10-K 1 tti10k-20140303.htm 10-K tti10k-20140303


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, 2013
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. [ X ]
INDICATE BY CHECK MARK WHETHER THE REGISTRANT IS A LARGE ACCELERATED FILER, AN ACCELERATED FILER, A NON-ACCELERATED FILER, OR A SMALLER REPORTING COMPANY. SEE THE DEFINITIONS OF “LARGE ACCELERATED FILER,” “ACCELERATED FILER,” AND “SMALLER REPORTING COMPANY”  IN RULE  12b-2 OF THE EXCHANGE ACT. (CHECK ONE):
LARGE ACCELERATED FILER [ X ]
ACCELERATED FILER [ ]
NON-ACCELERATED FILER [   ]
SMALLER REPORTING COMPANY [   ]
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 $784,876,118 AS OF JUNE 28, 2013, 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 FEBRUARY 28, 2014 WAS 78,898,214 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 6, 2014 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
 



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, including, without limitation, statements concerning future sales, earnings, costs, expenses, acquisitions or corporate combinations, asset recoveries, working capital, capital expenditures, financial condition, and other results of operations. Such statements reflect our current views with respect to future events and financial performance and are subject to certain risks, uncertainties and assumptions, including those discussed in “Item 1A. Risk Factors.”  Should one or more of these risks or uncertainties materialize, or should underlying assumptions prove incorrect, actual results may vary materially from those anticipated, believed, estimated, or projected. Unless the context requires otherwise, when we refer to “we,” “us,” and “our,” we are describing TETRA Technologies, Inc. and its subsidiaries on a consolidated basis. 

PART I

Item 1. Business.
 
General
 
We are a geographically diversified oil and gas services company, focused on completion fluids and associated products and services, water management, after-frac flow back, production well testing, offshore rig cooling, compression-based production enhancement, and selected offshore services including well plugging and abandonment, decommissioning, and diving. We also have a limited domestic oil and gas production business. We are composed of five reporting segments organized into three divisions – Fluids, Production Enhancement, 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 North American onshore oil and gas operators with comprehensive water management services.
 
Our Production Enhancement Division consists of two operating segments: Production Testing and Compressco. The Production Testing segment provides after-frac flow back, production well testing, offshore rig cooling, and other associated services in many of the major oil and gas basins in the United States, Mexico and Canada, as well as in certain basins in certain regions in South America, Africa, Europe, the Middle East, and Australia.
 
The Compressco segment provides compression-based production enhancement services, which are used in both conventional wellhead compression applications and unconventional compression applications, and in certain circumstances, well monitoring and sand separation services. The Compressco segment provides these services throughout many of the onshore oil and gas producing regions of the United States, as well as certain basins in Mexico, Canada, and certain countries in South America, Europe, and the Asia-Pacific region.
 
Our Offshore Division consists of two operating segments: Offshore Services and Maritech. The Offshore Services segment provides (1) downhole and subsea services such as 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 air diving services.
 
The Maritech segment is 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 consist primarily of the ongoing abandonment and decommissioning associated with its remaining offshore wells and production platforms. Maritech intends to acquire a significant portion of the services necessary to abandon and decommission these properties from the Offshore Division’s Offshore Services segment.
 
We continue to pursue a growth strategy that includes expanding our existing core businesses, with the exception of the Maritech segment, through internal growth and acquisitions, domestically and internationally. For

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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.
We were incorporated in Delaware in 1981. Our corporate headquarters is located at 24955 Interstate 45 North in The Woodlands, Texas. Our phone number is 281-367-1983, and our website is accessed at www.tetratec.com. We make available on our website, free of charge, our Corporate Governance Guidelines, Code of Business Conduct and Ethics, Code of Ethics for Senior Financial Officers, Audit Committee Charter, Management and Compensation Committee Charter, and Nominating and Corporate Governance Committee Charter, as well as our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and all amendments to those reports as soon as is reasonably practicable after such materials are electronically filed with, or furnished to, the Securities and Exchange Commission (SEC). The information on 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. Information filed with the SEC may be read or copied at the SEC’s Public Reference Room at 100 F Street, N.E., Washington D.C. 20549. Information on operation of the Public Reference Room may be obtained by calling the SEC at 1-800-SEC-0330. The SEC also maintains an internet website (http://www.sec.gov) that contains reports, proxy and information statements, and other information regarding issuers that file electronically. We will also make these documents available in print, free of charge, to any stockholder who requests such information from the Corporate Secretary.
 
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 bottomhole pressures during oil and gas completion and workover operations. Although they are used in many types of wells, demand for CBFs is greater in offshore well operations. Our Fluids Division sells CBFs and various CBF additives to U.S. and foreign oil and gas exploration and production companies and distributes them to other companies that service customers in the oil and gas industry.
 
Our Fluids Division provides both stock and custom-blended CBFs based on our customers’ specific needs and the proposed application. We also provide a broad range of associated services, including onsite fluids filtration, handling, and recycling; wellbore cleanup; fluid engineering consultation; fluid management services; and high-volume water management services for fracturing operations. 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 provides domestic onshore oil and gas operators with comprehensive frac water management services, including selection, analysis, treatment, storage, transfer, recycling, and environmental risk mitigation. These services are provided using the Division’s BioRid® and other above-ground frac water treatment technologies, some of which are patented, and its TETRA® STEEL 1200 rapid deployment water transfer system. The Division’s water management personnel seek to design environmentally friendly solutions for the unique needs of each customer’s wellsite in order to maximize operational performance and efficiency. In January 2014, the Fluids Division acquired the assets and operations of WIT Water Transfer, LLC (which operated under the name TD Water Transfer), which provides water management services to customers in the South Texas and North Dakota regions of the U.S.
 
The Fluids Division manufactures liquid and dry calcium chloride, liquid calcium bromide, zinc bromide, zinc calcium bromide, and sodium bromide for distribution primarily into energy markets. Liquid and dry calcium chloride

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are also sold into the water treatment, industrial, cement, food processing, road maintenance, ice melt, agricultural, and consumer products markets. Liquid sodium bromide is also sold into the industrial water treatment markets, where it is used as a biocide in recirculated cooling tower waters and in other applications.
Our liquid and dry calcium chloride production facilities are located in the United States and Finland. We also acquire liquid and dry 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. 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 plants located in San Bernardino County, California, that produce liquid calcium chloride from underground brine reserves. All of our calcium chloride production facilities have a combined production capacity of more than 1.5 million equivalent liquid tons per year.

The Fluids Division manufactures calcium bromide, zinc bromide, zinc calcium bromide, and sodium bromide at our West Memphis, Arkansas, production facility. A patented and proprietary production 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 this Division.
 
Production Enhancement Division
 
Production Testing Segment. The Production Testing segment of the Production Enhancement Division provides after-frac flow back, production well testing, early production facilities, offshore rig cooling, and other associated services. The segment provides well flow management and evaluation services and data that enables operators to quantify reserves, optimize production, and minimize oil and gas reservoir damage. In addition to after-frac flow back and production well testing, the Production Testing segment provides well control, well cleanup, and laboratory analysis services. The Production Testing segment also provides early-life production solutions designed for newly producing oil and gas wells as well as late-life production enhancement solutions designed to boost and extend the productive life of oil and gas wells. Many of these early production services involve sophisticated evaluation techniques for reservoir management, including unconventional shale reservoir exploitation and optimization of well workover programs.
 
The Production Testing segment 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 Production Testing segment has domestic operating locations in Colorado, Louisiana, North Dakota, Oklahoma, Pennsylvania, West Virginia, Wyoming, and Texas. Internationally, the segment has locations in Mexico and Canada, and certain countries in South America, Africa, and the Middle East. The Production Testing segment's operations in Canada are provided through Greywolf Production Systems and GPS Ltd. (together, Greywolf).
 
Through our Optima Solutions Holdings Limited subsidiary (OPTIMA), the Production Testing segment 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. The March 2012 acquisition of OPTIMA, which is based in Aberdeen, Scotland, enables our Production Testing segment to provide its customers with a broader range of production testing related services and expands the segment’s presence in many significant global oil and gas markets.

Compressco Segment. The Division’s Compressco segment provides compression-based production enhancement services, which are used in both conventional wellhead compression applications and unconventional compression applications, and, in certain circumstances, well monitoring and sand separation services. Services are provided to a broad base of natural gas and oil exploration and production companies operating throughout many of the onshore oil and gas producing regions of the United States. Internationally, Compressco has significant operations in Mexico and Canada and a growing presence in certain countries in South America, Europe, and the Asia-Pacific region.


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Over time, oil and natural gas wells exhibit declining pressure and production. Production enhancement technologies are designed to increase daily production and total recoverable reserves. Conventional compression-based production enhancement services are utilized to increase gas production by deliquifying wells and lowering wellhead pressure. Conventional applications also include production enhancement services for dry gas wells and liquid-loaded gas wells, and backside auto injection systems (BAIS) for liquid loaded gas wells. Unconventional applications are utilized primarily in horizontal resource play reservoirs in connection with oil and liquids production, and include vapor recovery, casing gas systems, and gas lift applications. Gas lift technology involves the use of compression equipment to inject natural gas downhole in order to increase oil and liquids production, primarily in horizontal wells. While conventional applications are primarily associated with mature gas wells with low formation pressures, they are also utilized effectively on newer gas wells that have experienced significant production declines. In certain circumstances, in connection with primary production enhancement services, Compressco provides ongoing well monitoring services and automated sand separation services. Field services are performed by our highly trained staff of regional service supervisors, optimization specialists, and field mechanics. In addition, Compressco designs and fabricates most of the compressor packages it uses to provide services, and, in certain markets, Compressco sells compressor packages to customers. Compressco’s fleet of compressor packages used to provide services totaled 3,995 as of December 31, 2013, of which 3,426 packages were in service.
 
Virtually all of our Compressco segment’s operations are conducted through our subsidiary, Compressco Partners, L.P. (Compressco Partners), a Delaware limited partnership. We own approximately 83% of the outstanding ownership interest of Compressco Partners. Compressco primarily utilizes its natural gas powered GasJack®, electric powered VJack™, and three-stage natural gas powered SuperJackTM packages to provide compression services. Compressco utilizes its compressor packages to provide compression services to its customers, primarily on a month-to-month basis. Compressco services its compressors and provides maintenance services on sold packages through mobile field technicians who are based in Compressco’s market areas. In certain applications, the GasJack® package increases gas production by reducing surface pressure to allow wellbore liquids that can hinder gas flow to be carried to the surface. The liquids are separated from the gas and liquid-free gas flows into the GasJack® package, where the gas is compressed. That gas is then cooled before being sent to the gas sales line. The separated fluids are either stored in an onsite customer-provided tank or injected into the gas sales line for separation downstream. The 46-horsepower GasJack® package is an integrated power/compressor unit equipped with an industrial 460-cubic inch, V-8 engine that uses natural gas from the well to power one bank of cylinders that, in turn, powers the other bank of cylinders, which provide compression. Compressco utilizes its 20- and 40-horsepower electric VJack™ compressor package to provide production enhancement services on wells located in larger, mature oil fields and in environmentally sensitive areas where electric power is available at the production site. The VJack™ package operates with zero engine-driven emissions, and Compressco believes it requires significantly less maintenance than a natural gas powered compressor. The VJack™ package is primarily designed for vapor recovery applications (to capture natural gas vapors emitting from closed storage tanks after production and to reduce storage tank pressures) and casing gas systems applications on oil wells. During late 2013, Compressco purchased a number of three-stage compressor packages that it plans to market as "SuperJackTM packages." The SuperJackTM package includes a three-stage compressor with a natural gas powered engine ranging from 80 to 300 horsepower and is primarily used to provide production enhancement services on horizontal wells that have insufficient reservoir pressure. The majority of these packages purchased to date are 145 horsepower SuperJackTM packages to be primarily used in gas lift applications.
 
See “Note Q – Industry Segments and Geographic Information” in the Notes to Consolidated Financial Statements for financial information about this Division.
 
Offshore Division
 
Offshore Services Segment. The Offshore Services segment provides (1) downhole and subsea services such as 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 air diving services. We provide these services to offshore oil and gas operators, primarily in the U.S. Gulf of Mexico. We offer comprehensive, integrated services, including individualized engineering consultation and project management services.
In providing services, our Offshore Services segment utilizes rigless P&A equipment packages, two heavy lift barges, several dive support vessels, and other dive support assets. In addition, we lease other assets from third parties and engage third-party contractors whenever necessary. The Offshore Services segment provides a wide variety of conventional and saturated air diving services to its customers through its Epic Diving & Marine Services

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subsidiary (Epic). Well abandonment, decommissioning, diving, and certain construction services are performed primarily in the U.S. Gulf of Mexico. The Offshore Services segment provides offshore cutting services and tool rentals through its E.O.T. Cutting (EOT) operations. The Offshore Services segment also utilizes specialized equipment and engineering expertise to address a variety of specific platform construction and decommissioning issues, including those associated with platforms that have been toppled or severely damaged by hurricanes and other windstorms. The Offshore Services segment provides services to major oil and gas companies and independent operators, including Maritech, through its facilities located in Broussard, Belle Chasse, Fourchon, and Houma, Louisiana.
 
Our Offshore Services segment’s fleet of service vessels has expanded and contracted in size in recent years in response to changing demands for its services. With the TETRA Hedron, a 1,600-metric-ton heavy lift derrick barge, and the TETRA Arapaho, a 725-metric-ton heavy lift derrick barge, we perform heavy lift decommissioning and construction projects and integrated operations on oil and gas production platforms. The Offshore Services segment also performs contract diving operations, utilizing its owned dive service vessels, as well as vessels obtained under long term leases as needed. Diving services include saturation diving for up to 1,000 foot dive depths as well as mixed gas and surface diving for shallower dives.

Among other factors, demand for our Offshore Service segment’s operations in the Gulf of Mexico is affected by federal regulations governing the abandonment and decommissioning of offshore wells, production platforms and pipelines, particularly following the April 2010 Macondo well oil spill. These regulations include Notice To Lessees 2010-G05: “Decommissioning Guidance for Wells and Platforms” (NTL 2010-G05, known as the “Idle Iron Guidance”). The Bureau of Safety and Environmental Enforcement (BSEE) issues offshore permits, regulates offshore contractors, and oversees the provisions of the Idle Iron Guidance. The Idle Iron Guidance became effective October 15, 2010, and requires that operators perform and report decommissioning and abandonment plans and activities in accordance with BSEE requirements. The Idle Iron Guidance provides specific guidelines for when an operator has to permanently plug and abandon wells and decommission platforms and related facilities after the occurrence of certain events, including the end of useful operations, cessation of commercial production, and expiration of the lease.
 
Maritech Segment. The Maritech segment is 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. Maritech’s remaining operations consist primarily of the ongoing abandonment and decommissioning of its remaining offshore wells, facilities, and production platforms. Maritech intends to acquire a significant portion of these services with regard to such assets that it operates from the Offshore Division’s Offshore Services segment.
 
The sales of substantially all of Maritech’s oil and gas producing properties during 2011 and 2012 have 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 have ceased. Following these sales, Maritech’s remaining oil and gas reserves and production are negligible. Maritech’s operations consist 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, 2013, Maritech spent approximately $310.4 million on such efforts. Approximately $43.3 million of Maritech decommissioning liabilities remain as of December 31, 2013, and approximately $38.7 million of this amount is planned to be performed during 2014.
 
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. We review the adequacy of Maritech’s decommissioning liabilities whenever indicators suggest that the estimated cash flows underlying the liabilities have changed materially. The timing and amounts of these cash flows are subject to
changes in the energy industry environment and may result in additional liabilities being recorded. For a further discussion of Maritech’s 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 this Division.
 

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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 Division also recycles used calcium and zinc bromide CBFs repurchased from its oil and gas customers.
 
The Division produces liquid calcium chloride, either from underground brine reserves or by reacting hydrochloric acid with limestone. The 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, utilizing underground brine (tail brine) obtained from Chemtura Corporation (Chemtura) that contains calcium chloride. We also produce calcium chloride at our two plants in San Bernardino County, California, by solar evaporation of pumped underground brine reserves that contain calcium chloride. The underground reserves of this brine are deemed adequate to supply our foreseeable need for calcium chloride at those plants.
 
The Division’s primary sources of hydrochloric acid are chemical 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 Chemtura, under which the Division purchases its requirements of raw material bromine from Chemtura’s Arkansas bromine facilities. In addition, we have a long-term agreement with Chemtura under which Chemtura supplies the Division’s 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, that was constructed in 1985. This plant was acquired in 1988 and is not operable. We currently lease approximately 33,000 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 Chemtura bromine supply agreement discussed above provides us with a secure supply of bromine to support the Division’s current operations. We do, however, continue to evaluate our strategy related to the Magnolia, Arkansas, assets and their future development. Chemtura holds certain rights to participate in future development of the Magnolia, Arkansas, assets.
 
The Fluids Division and the Production Testing segment of our Production Enhancement Division purchase their water management, production testing, and rig cooling equipment and components from third-party manufacturers. The Compressco segment designs and assembles the Gas Jack® and VJack™ compressor packages it uses to provide wellhead compression-based production enhancement services and the majority of the required components are obtained from third party suppliers. Compressco acquires its SuperJackTM compressor packages and well monitoring and sand separation equipment and components from third party fabricators or from the Production Testing segment. Some of the components used in the assembly of compressor packages, and 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 that there are adequate alternative suppliers and that any impact to us would not be severe.
Market Overview and Competition
 
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. 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. The Division also markets to customers with deepwater operations that utilize high volumes of CBFs and can be subject to harsh downhole conditions, such as high pressure and high temperatures. Demand for offshore CBF products are generally driven by completion activity, which increased during 2013.

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During the past three years, a portion of the growth of the Division’s U.S. operations has been due to increased industry demand for onshore water management services in unconventional shale gas and oil reservoirs. The Division provides water management services to a wide range of onshore oil and gas operators located in the most significant domestic shale gas and oil reservoirs, including the Barnett, Cana Woodford, Eagle Ford, Fayetteville, Granite Wash, Haynesville, Marcellus, and Utica. The January 2014 acquisition of TD Water Transfer expands the Division's water management operations into the South Texas and North Dakota markets.
 
The 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, Devon, Dynamic Offshore Resources, Halliburton, Marathon, Petrobras (the national oil company of Brazil), Shell, Tullow, and TOTAL. The 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 Division’s European calcium chloride operations market our calcium chloride products to certain European markets. Our principal competitors in the non-energy related calcium chloride markets include Occidental Chemical Corporation and Vitro in North America, and Brunner Mond, Solvay, and NedMag in Europe.
 
Production Enhancement Division
 
Production Testing Segment. 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 segment provides the specialized equipment and qualified personnel to address these impediments to production. The Production Testing segment also provides certain services designed to accommodate the unique after-frac flow back and testing demands of shale gas reservoirs. During 2012, the Production Testing segment expanded its after-frac flowback and production testing equipment fleet, acquiring operations in new geographic markets to serve the rapidly growing demand for these services. Through Greywolf, the Production Testing segment serves the western Canada market. In addition, the Production Testing segment continues to serve the continuing demand for services associated with many of the domestic shale gas reservoirs, including the Bakken, Barnett, Cana Woodford, Eagle Ford, Fayetteville, Haynesville, Marcellus, and Niobrara. In addition, through our OPTIMA subsidiary, the Production Testing segment offers offshore oil and gas rig cooling services and associated products that suppress heat generated by high-rate flaring of hydrocarbons during offshore well test operations. OPTIMA primarily serves markets in the North Sea, Australia, and 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 in the marketplace. The Production Testing segment plans to continue growing its foreign operations in order to serve most major oil and gas markets worldwide, both organically and through additional strategic acquisitions. Competition in onshore U.S. production testing markets is primarily dominated by numerous small, privately owned operators. Expro International, Halliburton, Schlumberger, and Weatherford are major competitors in the foreign markets we serve. The major customers for this segment include BHP Billiton, Cabot, Chesapeake, Chevron, ConocoPhillips, Consol Energy, Encana, Geosouthern, Halliburton, Pioneer Natural Resources, Range Resources, Shell Oil, PEMEX (the national oil company of Mexico), Petrobras, Saudi ARAMCO (the national oil company of Saudi Arabia), and other national oil companies in foreign countries.
 
Compressco Segment. The Division’s Compressco segment provides its services to a broad base of natural gas and oil exploration and production companies operating throughout many of the onshore producing regions of the United States. Compressco also has significant operations in Mexico and Canada, and a growing presence in certain countries in South America, Europe, and the Asia-Pacific region. While most of Compressco’s domestic services are performed in the San Juan Basin, Permian Basin, and Mid-Continent regions of the United States, Compressco also has a substantial presence in other U.S. producing regions, including South Texas, the Central

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and Northern Rockies, the Ark-La-Tex region, and California. Compressco has historically focused on serving customers with production in mature conventional fields, but it now also services customers in some of the largest and fastest growing unconventional shale oil and gas reservoirs in the United States, including the Bakken, Barnett, Cotton Valley Trend, Eagle Ford, Fayetteville, Granite Wash, Marcellus, Piceance, Woodbine, and Woodford basins. While Compressco primarily serves customers in need of low discharge pressure compression services, the late 2013 purchase of SuperJackTM compressor assets allows it to compete in the higher discharge pressure gas lift market, including the liquids rich resource plays such as the Eagle Ford, Granite Wash, Mississippi Lime, and Woodbine regions. Compressco continues to seek opportunities for further domestic and foreign expansion.
 
The wellhead compression-based production enhancement services business is highly competitive, and competition primarily comes from companies that utilize packages consisting of a screw compressor with a separate engine driver or a reciprocating compressor with a separate engine driver. To a lesser extent, Compressco faces competition from large companies that have traditionally focused on higher-horsepower natural gas gathering and transportation equipment and services. Compressco’s strategy is to compete on the basis of superior services at a competitive price. Compressco believes that it is competitive, because of the significant increases in the value of natural gas wells that result 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 the services. Compressco’s major customers include PEMEX, BP, YPF, Anadarko, Devon Energy, and Apache.
 
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 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 activity of its customers, which is affected by oil and natural gas prices and government regulation. We believe that the enforcement of government regulations, including the Idle Iron Guidance, may accelerate the pace at which offshore Gulf of Mexico abandonment and decommissioning will be done in the future. The increased government focus on removing aging offshore platform infrastructure in the Gulf of Mexico has resulted in an increase in the number of wells to be plugged and abandoned, and platforms and pipelines to be decommissioned.
 
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: the proper equipment, including vessels and heavy lift barges; qualified, experienced personnel; technical expertise to address varying downhole, surface, and subsea conditions, particularly those related to damaged wells and platforms; and a comprehensive health, safety, and environmental program. Our Offshore Services segment's fleet of owned equipment includes two heavy lift derrick barges, including 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.
 
The Offshore Services segment markets its services primarily to major oil and gas companies and independent operators. The Offshore Services segment’s most significant customer during the past three years has been Maritech, however, the amount of work to be performed in the future for Maritech is expected to be reduced. Other major customers include Chevron, Fieldwood, McMoRan, Nexen, Sandridge, Shell, and Williams. The Offshore Services segment’s services are performed primarily in the U.S. Gulf of Mexico, however, the segment is also seeking to expand its operations to international markets. Our principal competitors in the U.S. Gulf of Mexico market are Bisso, Cal Dive International, Inc., Express Energy, Harkand, Oceaneering, Offshore Specialty Fabricators, Inc., and Superior Energy Services, Inc. This market is highly competitive, and competition is based primarily on service, equipment availability, safety record, and price.
 

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Other Business Matters
 
Marketing and Distribution
 
The Fluids Division markets its CBF products through its distribution facilities located in the U.S. Gulf Coast region, the North Sea region of Europe, and certain other foreign markets, including Brazil, West Africa, and the Middle East.
 
Non-oilfield calcium chloride products are also marketed through the Division’s sales offices in California, Missouri, Pennsylvania, and Texas, as well as through a network of distributors in the United States and northern and central Europe. In addition to production facilities in the United States and Finland, the Division has distribution facilities strategically located to provide efficient product distribution.
 
No single customer provided 10% or more of our total consolidated revenues during the year ended December 31, 2013.
 
Backlog
 
Our backlog is not indicative of our estimated future revenues, because a majority of our products and services either are not sold under long-term contracts or do not require long lead times to procure or deliver.
 
Employees
 
As of December 31, 2013, we had 3,462 employees. None of our U.S. employees are presently covered by a collective bargaining agreement other than the employees of our Lake Charles, Louisiana, calcium chloride production facility, who are represented by the United Steelworkers Union. Our foreign employees are generally members of labor unions and associations in the countries in which we operate. We believe that our relations with our employees are good.
 
Patents, Proprietary Technology, and Trademarks
 
As of December 31, 2013, we owned or licensed twenty-eight issued U.S. patents and had thirteen patent applications pending in the United States. We also had thirty-five owned or licensed foreign patents and thirty-five foreign patent applications pending in various other countries. The foreign patents and patent applications are primarily foreign counterparts to U.S. patents or patent applications. The issued patents expire at various times through 2032. 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 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 stormwater 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 BSEE of the U.S. Department of the Interior;

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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 (OSHA), and other state and local agencies and authorities. Specific environmental laws and regulations applicable to our operations include the Federal Water Pollution Control Act of 1972; the Resource Conservation and Recovery Act of 1976 (RCRA); the Clean Air Act of 1977; the Comprehensive Environmental Response, Compensation and Liability Act of 1980 (CERCLA); the Superfund Amendments and Reauthorization Act of 1986 (SARA); the Federal Insecticide, Fungicide, and Rodenticide Act of 1947 (FIFRA); the Toxic Substances Control Act of 1976 (TSCA); the Hazardous Materials Transportation Act of 1975; 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 believe that our manufacturing plants and other operations are in substantial compliance with all applicable U.S. and foreign health, safety, and environmental laws and regulations. Since our inception, we have not had a history of any significant fines or claims in connection with environmental or health and safety matters. 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 plant and service 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.
 
The EPA has determined that greenhouse gases present an endangerment to public health and the environment, because, according to the EPA, they contribute to global warming and climate change. As a result, the EPA has begun to regulate certain sources of greenhouse gases, including air emissions associated with oil and gas production particularly as they relate to the hydraulic fracturing of natural gas wells. In addition, the EPA has issued regulations requiring the reporting of greenhouse gas emissions from certain sources which include onshore and offshore oil and natural gas production facilities and onshore oil and gas processing, transmission, storage, and distribution facilities. Reporting of greenhouse gas emissions from such facilities is required on an annual basis. The EPA’s rules relating to emissions of greenhouse gases from large stationary sources of emissions are currently subject to a number of legal challenges, but the federal courts have thus far declined to issue any injunctions to prevent the EPA or state environmental agencies from implementing the rules. Further, Congress has considered, and almost one-half of the states have adopted, legislation that seeks to control or reduce emissions of greenhouse gases from a wide range of sources.

Offshore Operations
 
During the past four years, several Notices to Lessees (NTLs), SEMS (Safety and Environmental Management Systems) regulations, and other safety regulations implementing additional safety and certification requirements applicable to offshore activities in the Gulf of Mexico were issued. These NTLs and regulations include requirements by operators to:
•
submit well blowout prevention measures and contingency plans, including demonstrating access to subsea blowout containment resources;
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abide by new permitting standards requiring detailed, independently certified descriptions of well design, casing, and cementing;
•
follow new performance-based standards for offshore drilling and production operations
•
enhance the safety of operations by reducing the frequency and severity of accidents; and
•
certify that the operator has complied with all regulations.
 
The “Idle Iron Guidance” regulations, which were adopted in 2010 and govern the plugging, abandonment, and decommissioning of U.S. Gulf of Mexico offshore wells and production platforms, are overseen by BSEE. This agency's scope of responsibility includes maintaining an investigation and review unit, providing for public forums and conducting comprehensive environmental analyses, and creating implementation teams to analyze various aspects of the regulatory structure and to help implement the reform agenda.
 

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We maintain various types of insurance intended to reimburse certain costs in the event of 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 general liability and protection and indemnity policies that provide third-party liability coverage, up to applicable policy limits, for risks of an accidental nature, including but not limited to death and personal injury, collision, damage to fixed and floating objects, pollution, and wreck removal. We also maintain a vessel pollution liability policy that provides coverage for oil or hazardous substance pollution emanating from a vessel, addressing both OPA (Oil Pollution Act of 1990) and CERCLA obligations. This policy also provides coverage for cost of defense, fines, and penalties.
 
We provide services and products to customers in the Gulf of Mexico, generally pursuant to written master services agreements that create insurance and indemnity obligations for both parties. If there was an explosion or similar catastrophic event on an offshore location where we are providing services and products, under the majority of our master services agreements with our customers:
 
(1) We would be required to indemnify our customer for any claims for injury, death, or property loss or destruction made against them by us or our subcontractors or our subcontractor’s employees. The customer would be required to indemnify us for any claims for injury, death, or property loss or destruction made against us by the customer or its other subcontractors or the employees of the customer or its other subcontractors. These indemnities are intended to apply regardless of the cause of such claims, including but not limited to, the negligence of the indemnified party. Our insurance is structured to cover the cost of defense and any resulting liability from all indemnified claims, up to policy limits.
 
(2) The customer would be required to indemnify us for all claims for injury, death, or property loss or destruction made against us by a third party that arise out of the catastrophic event, regardless of the cause of such claims, including but not limited to, our negligence or our subcontractors’ negligence. Our insurance is structured to cover the cost of defense and any resulting liability from all such claims; however, our insurance would be applicable to the claim only if the customer defaulted or otherwise breached its indemnity obligations to us.
 
(3) The customer would be required to indemnify us for all claims made against us for environmental pollution or contamination that arise out of the catastrophic event, regardless of the cause of such claims, including our negligence or the negligence of our subcontractors. Our insurance is structured to cover the cost of defense and any resulting liability from all such claims; however, our insurance would be applicable to the claim only if the customer defaulted or otherwise breached its indemnity obligations to us.
Following the 2011 and 2012 sales of substantially all of Maritech’s offshore producing properties, we no longer participate in offshore drilling activities. However, Maritech and our Offshore Services segment engage contractors to provide well abandonment and related services and products on Maritech’s remaining offshore oil and gas production platforms and associated wells, generally pursuant to written master services agreements that create insurance and indemnity obligations for both parties. If there was an environmental event on an offshore Maritech location where a Maritech contractor was providing services and products, under a majority of Maritech’s master services agreements with its contractors, Maritech would be required to indemnify its contractor for any claims against the contractor for injury, death, or property loss or destruction brought by Maritech, its other subcontractors or their respective employees. The contractor would be required to indemnify Maritech for any claims for injury, death, or property loss or destruction made against Maritech by the contractor or its subcontractors or the employees of the contractor or its subcontractors. These indemnities would apply regardless of the cause of such claims, including the negligence of the indemnified party. Maritech’s insurance is structured to cover the cost of defense and any resulting liability from all indemnified claims, up to policy limits.
 
In accordance with applicable regulations, Maritech maintains an oil spill response plan with the BSEE and has designated contractors who are trained as qualified individuals and are prepared to coordinate a response to any spill or leak. Maritech also has contracts in place to assure that a complete and experienced resource team is available as required.

Item 1A. Risk Factors.
 
Forward Looking Statements
 
Some information included in this report, other materials filed or to be filed with the SEC, as well as information included in oral statements or other written statements made or to be made by us contain or incorporate

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by reference certain statements (other than statements of historical fact) that constitute forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. When used herein, the words “assume,” “may,” “will,” “should,” “goal,” “anticipate,” “expect,” “estimate,” “could,” “believes,” “seeks,” “plans,” “intends,” “projects” or “targets” and similar expressions that convey the uncertainty of future events or outcomes are intended to identify forward-looking statements.
 
Where any forward-looking statement includes a statement of the assumptions or bases underlying such forward-looking statement, we caution that, while we believe these assumptions or bases to be reasonable and to be made in good faith, assumed facts or bases almost always vary from actual results, and the difference between assumed facts or bases and actual results could be material, depending on the circumstances. It is important to note that actual results could differ materially from those projected by such forward-looking statements.
 
Although we believe that the expectations reflected in such forward-looking statements are reasonable and such forward-looking statements are based upon the best data available at the date this report is filed with the SEC, we cannot assure you that such expectations will prove correct. Factors that could cause our results to differ materially from the results discussed in such forward-looking statements include, but are not limited to, the following:
•
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 impact of market conditions and activity levels of our customers;
•
possible impairments of long-lived assets, including goodwill;
•
the availability of capital (including any financing) to fund our business strategy and/or operations, and our ability to comply with covenants and restrictions resulting from such financing;
•
technological obsolescence;
•
the availability of raw materials and labor at reasonable prices;
•
the potential impact of the loss of one or more key employees;
•
risks related to our growth strategies;
•
operating and safety risks inherent in our oil and gas services operations;
•
the demand for our products and services in the Gulf of Mexico, which could continue to be adversely impacted by increased regulation and continuing regulatory uncertainty;
•
budgetary constraints and ongoing violence in Mexico;
•
the valuation of decommissioning liabilities;
•
uncertainties about plugging and abandoning wells and structures, including the wells and structures previously sold;
•
weather risks, including the risk of physical damage to our platforms, facilities, and equipment;
•
exposure to credit risks from our customers;
•
foreign currency and interest rate risks;
•
the impact of existing and future laws and regulations;
•
risks related to our foreign operations;
•
Compressco’s ability to generate sufficient cash from operations to make cash distributions;
•
risks arising from the use of fixed price contracts;
•
acquisition valuation and integration risks;
•
environmental risks;
•
cost, availability, and adequacy of insurance and the ability to recover thereunder; and
•
loss or infringement of our intellectual property rights.
 
All such forward-looking statements in this document are expressly qualified in their entirety by the cautionary statements in this paragraph, and we undertake no obligation to publicly update or revise any forward-looking statements.

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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 products and services is materially dependent on the supply, demand, and prices for oil, natural gas, and competing energy sources, and is more specifically dependent on the supply, demand, and prices for the products and services we offer, both in the United States and in the foreign countries in which we operate. These factors are also influenced by the U.S., foreign, and regional economic, financial, business, political, and social conditions within the markets we serve. Oil and gas prices and, therefore, the levels of well drilling, completion, workover, and production activities, tend to fluctuate. Worldwide economic and political events, including initiatives by the Organization of Petroleum Exporting Countries and increasing or decreasing demand in other large world economies as well as tremendous growth in natural gas supplies in the U.S. from shale reserves, have contributed to, and are likely to continue to contribute to, price volatility. The expansion of alternative energy supplies that compete with oil and gas, improvements in energy conservation, and improvements in the energy efficiency of vehicles, plants, equipment, and devices will also reduce oil and gas consumption or slow its growth.
 
In particular, U.S. natural gas prices have been negatively affected by overall reduced energy demand in the U.S. due to economic conditions, weather, and the increase in natural gas supplies from shale gas drilling. Low natural gas prices have negatively affected the operating cash flows and exploration and development activities and plans of many of our customers and could have a negative impact on the demand for many of our products and services.
 
If economic conditions or energy prices deteriorate, there may be additional constraints on oil and gas industry spending levels. Reduced spending levels would negatively impact the demand for many of our products and services and the prices we charge for these products and services, which would negatively affect our revenues and future growth.

During times when oil or natural gas prices are low, many of our customers are more likely to experience a downturn in their financial condition. Poor economic conditions may also lead to additional constraints on the operating cash flows of our customers, potentially impacting their ability to pay us in a timely manner, which could result in increased customer bankruptcies and uncollectible receivables.
 
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 may have lower standards of quality, 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. 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.
 

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Other factors affecting our operating results and activity levels include oil and natural gas industry spending levels for exploration, development, and acquisition activities and plugging, abandonment, and decommissioning costs on Maritech’s remaining offshore production platforms, wells, and pipelines. 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.
 
The demand for our products and services in the Gulf of Mexico could continue to be adversely impacted by increased regulation and continuing regulatory uncertainty.
 
Operations in the U.S. Gulf of Mexico have been subject to an increasingly stringent regulatory environment including government regulations focused on offshore operating requirements, spill cleanup, and enforcement matters. These regulations also implement additional safety and certification requirements applicable to offshore activities in the Gulf of Mexico. Demand for our products and services in the Gulf of Mexico continues to be affected by regulatory restrictions. 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.
 
The majority of our business in Mexico is performed for Petróleos Mexicanos (PEMEX), and any cutbacks by the Mexican Government on PEMEX’s annual spending budget or security disruptions in Mexico could adversely affect our business, financial condition, results of operations, and cash flows.
 
The majority of our business in Mexico is performed for PEMEX. For the twelve months ended December 31, 2013, PEMEX accounted for approximately 3.4% of our consolidated revenues and a portion of our operating cash flows. No work or services are guaranteed to be ordered by PEMEX under our contracts with PEMEX, which typically range from six months to two years in length. PEMEX is a decentralized public entity of the Mexican Government, and, therefore, the Mexican Government controls PEMEX, as well as its annual budget, which is approved by the Mexican Congress. The Mexican Government may cut spending in the future. These cuts could adversely affect PEMEX’s annual budget and, thus, its ability to engage us or compensate us for our services. Additionally, at the expiration of our current contracts, we may be required to participate in an open auction to renew them. Recently, the Mexican government implemented an energy industry reform that will allow the government to grant non-Mexican companies the opportunity to enter into contracts and licenses to explore and drill for oil and natural gas in Mexico. Although this reform could result in additional customers for us in Mexico, and a reduction in our dependency on PEMEX, the timing of any impact from this reform is uncertain. Regardless of the impact of this reform, we anticipate that we will continue to be dependent on PEMEX as a significant customer in Mexico.
During the past several years, incidents of security disruptions in many regions of Mexico have increased, including drug-related gang activity. Certain incidents of violence have occurred in regions served by us and have resulted in the interruption of our operations. These interruptions could continue or increase in the future. To the extent that such security disruptions continue or increase, our operations will continue to be affected, and the levels of revenue and operating cash flow from our Mexican operations could be reduced.
 
Under the current Ley de Petróleos Mexicanos (the “PEMEX Law”), PEMEX has authority to contract through an auction process with third parties for the exploration, development, and production of hydrocarbons. Our contracts with PEMEX generally have initial terms of two years, and, when these contracts with PEMEX expire, we may be required to participate in an open auction to renew them. Any failure by us to renew our existing contracts with PEMEX or renew them on favorable terms could materially adversely affect our business, financial condition, results of operations, and cash flows.
 
PEMEX has authority to contract through an auction process with third parties for the exploration, development, and production of hydrocarbons. The PEMEX Law permits three types of contracting: contracts resulting from open auctions or invitation-only auctions with at least three invitees, or direct contracting. To utilize an invitation-only auction or a direct contract, PEMEX must provide written justification as to why the specific circumstances of the proposed service contract require less than an open auction. Additionally, open auctions must conform with one of three selected bidder models: either all bidders must be Mexican entities, all bidders must be Mexican entities or foreign entities whose countries of origin are parties to free trade agreements with Mexico that include sections related to governmental procurement, or bidders may be of any national origin. PEMEX may only select the third option if PEMEX determines that either (i) the Mexican market cannot adequately meet the needs of

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the contract, (ii) the third option would be better for PEMEX in terms of price or quality, (iii) the second bidder model was attempted but was unsuccessful, or (iv) the contracts are financed by certain legally required types of foreign loans. In addition, under the PEMEX Law, there may be other qualifications that must be met by bidding service providers. Bidders must meet and maintain all required qualifications at the time of bidding and throughout the term of the contract.
 
Our contracts with PEMEX generally have initial terms of two years, and, when they expire, we may be required to participate in an open auction to renew them. Any failure by us to renew our existing contracts with PEMEX or renew them on favorable terms could adversely affect our business, financial condition, results of operations, and cash flows.
 
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, 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. We also sell calcium chloride and sodium bromide to non-energy markets. Sales of calcium chloride and bromide compound 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 bromide compound products, we use elemental bromine, hydrobromic acid, and other raw materials which are purchased from third parties. We rely on Chemtura Corporation as a supplier of raw materials for our bromide compound products as well as for our El Dorado, Arkansas, calcium chloride plant. Although we have long-term supply agreements with Chemtura, if we were unable to acquire these raw materials at reasonable prices for a prolonged period, our business could be materially and adversely affected.
 
Some of the well plugging, abandonment, and decommissioning services performed by our Offshore Services segment require the use of vessels, diving, cutting, and other equipment and services provided by third parties. We lease equipment and obtain services from certain providers, and there can be no assurance that this equipment and these services will be available at reasonable prices in the future.
 
The fabrication of our production testing, well monitoring, and rig cooling equipment and wellhead compressor packages requires the purchase of many types of 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 Production Enhancement Division may be adversely affected due to our dependence on these key suppliers.
Changes in the economic environment could result in significant impairments of certain of our long-lived assets, including goodwill.
 
Changes in the economic environment could result in decreased 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 an impairment charge to earnings, resulting in increased earnings volatility.
 
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 and our market capitalization, future cash flows, and slower growth rates in our industry. If economic and market conditions decline, we may be required to record a charge to earnings during the period in which any impairment of our goodwill is determined, resulting in a negative impact on our results of operations.
 

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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, therefore, could adversely affect operating results.
 
Operating, Technological, and Strategic Risks

We have technological and age-obsolescence risk, both with our products and services as well as with our equipment assets.
 
New drilling, completion, and production technologies 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, including one of our heavy lift barges and certain dive support vessels, 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 vessels or 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 growth strategy.
 
Our 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) and 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 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 marine barges and vessels, heavy equipment, offshore production platforms, chemical manufacturing plants, and the performance of heavy lift and diving services involve particularly high levels of risk. In addition, certain of our employees who perform services on offshore platforms and vessels 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 them or their representatives to pursue actions against us for damages for job-related injuries. Whenever possible, we obtain 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.

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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. Due to the sale of substantially all of Maritech's oil and gas properties, obtaining typical operational risk coverage for its remaining properties, such as removal of debris, operators extra expense, control of well, and pollution and cleanup coverage, are not available at economical costs. To the extent we suffer losses or claims that are not covered, or are only partially covered by insurance, our results of operations could be adversely affected.
 
We could incur losses on fixed price contracts.
 
Due to competitive market conditions, a portion of our well abandonment and decommissioning projects may be performed on a lump sum basis. Pursuant to these types of contracts, defined work is delivered for a fixed price, and extra work, which is subject to customer approval, is charged separately. The revenue, cost, and gross profit realized on these types of contracts can vary from the estimated amount because of changes in offshore conditions, increases in the scope of the work to be performed, increased site clearance efforts required, labor and equipment availability, cost and productivity levels, and the performance level of other contractors. In addition, unanticipated events, such as accidents, work delays, significant changes in the condition of platforms or wells, downhole problems, weather, and environmental or other technical issues, could result in significant losses on these types of projects. These variations and risks may result in our experiencing reduced profitability or losses on these types of projects.

The valuation of decommissioning liabilities is based on estimated data that may be materially incorrect.
 
Our estimates of future well abandonment and decommissioning liabilities are imprecise and are subject to change due to: changes in the forecasts of the supply, demand, cost and timing of well abandonment and decommissioning services; additional remediation work required on previously completed well abandonment projects; damage to wells and infrastructure caused by hurricanes and other natural events; changes in governmental regulations governing well abandonment and decommissioning work; and other factors. In particular, a portion of the remaining decommissioning liabilities for our Maritech subsidiary relates to offshore production platforms that were toppled and destroyed by hurricanes and the estimates to perform the remaining decommissioning and debris removal work on these properties is particularly imprecise due to the unusual nature of the work to be performed. During 2013, Maritech adjusted its decommissioning liabilities, increasing them by approximately $75.3 million, either for work performed during the year or related to adjusted estimates of the cost of future work to be performed. This adjustment was directly charged to earnings as an operating expense during 2013. If the actual cost of future abandonment and decommissioning work is materially greater than our current estimates, such additional costs could have an adverse effect on future earnings.
 
Weather-Related Risks
 
Certain of our operations are seasonal and depend, in part, on weather conditions.
 
The Offshore Services segment has historically enjoyed its highest vessel utilization rates during the period from April to October, when weather conditions are typically more favorable for offshore activities, and has experienced its lowest utilization rates in the period from November to March. This segment, under certain lump sum and other contracts, may bear the risk of delays caused by adverse weather conditions. In addition, demand for other products and services we provide are subject to seasonal fluctuations, due in part to weather conditions that cannot be predicted. Accordingly, our operating results may vary from quarter to quarter, depending on weather conditions in applicable areas.
 
In certain markets, the Fluids Division’s onshore water management services can be dependent on adequate water supplies that can be accessible to its customers. To the extent severe drought conditions prevent our customers from accessing water supplies, frac water operations may become impractical, and our Fluids Division business may be negatively affected.
 

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Severe weather, including named windstorms, can cause significant damage and disruption to our businesses.
 
A significant portion of our operations is susceptible to adverse weather conditions in the Gulf of Mexico, including hurricanes and other extreme weather conditions. High winds, storm surge, and turbulent seas can cause significant damage and curtail our operations for extended periods during and after such weather conditions, while damage is being assessed and remediated. 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.
 
A portion of the costs resulting from damages from previous hurricanes has yet to be incurred and may result in significant charges to earnings.
 
During the past four years, Maritech has performed an extensive amount of well intervention, abandonment, decommissioning, debris removal, and platform construction associated with offshore platforms that were destroyed by hurricanes. As of December 31, 2013, Maritech has remaining hurricane damage response work associated with three of the downed platforms, and the estimated cost to perform this remaining abandonment, decommissioning, and debris removal work is approximately $7.7 million net to our interest. Due to the unique nature of the remaining work to be performed, actual costs could greatly exceed these estimates and, depending on the nature of any excess costs incurred, could result in significant charges to earnings in future periods. All of this $7.7 million estimated amount has been accrued as part of Maritech’s decommissioning liabilities. Our estimates of the remaining costs to be incurred may be imprecise.
 
For a further discussion of the remaining costs resulting from damages from the 2005 and 2008 hurricanes, see Notes to Consolidated Financial Statements, “Note B – Summary of Significant Accounting Policies, Repair Costs and Insurance Recoveries.”

We have elected to self-insure windstorm damage to our remaining Maritech assets in the Gulf of Mexico, and hurricane damages could result in significant uninsured losses.
 
Despite the sales of substantially all of Maritech’s oil and gas reserves during 2011 and 2012, we have remaining decommissioning liabilities of approximately $43.3 million associated with offshore platforms and associated wells to be decommissioned and abandoned. We have discontinued insurance coverage for windstorm damage and have elected to self-insure these risks. To the extent the remaining offshore platforms and associated wells are not decommissioned and abandoned prior to a windstorm occurring, Maritech would be exposed to losses from windstorm damages and storms in the future. Depending on the severity and location of the storms, such losses could be significant and could have a material adverse effect on our financial position, results of operation, and cash flows.
 
There can be no assurance that future insurance coverage with favorable premiums and deductibles and maximum coverage amounts will be available in the market or that its cost will be justifiable. There can be no assurance that any windstorm insurance will be adequate to cover losses or liabilities associated with such windstorms. We cannot predict the continued availability of insurance or its availability at premium levels that justify its purchase.
 
Financial Risks
 
Deterioration of our financial ratios could result in covenant defaults under our long-term debt agreements and result in decreased credit availability.
 
As of December 31, 2013, our total debt outstanding was approximately $387.7 million, and our debt to total capital ratio was 36.9%. This debt to total capital ratio excludes approximately $38.8 million of available cash held as of December 31, 2013. Additional growth could result in increased debt levels to support our capital expenditure needs or acquisition activities. 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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Our long-term debt agreements contain customary covenants and other restrictions and requirements. In addition, the agreements require us to maintain certain financial ratios, including a minimum interest charge coverage ratio and a maximum leverage ratio, both of which are defined in our revolving bank credit facility agreement. Deterioration of these ratios could result in a default under the agreements.

The agreements also include cross-default provisions relating to any other indebtedness we have that is greater than a defined amount. If any such indebtedness is not paid or is accelerated and such event is not remedied in a timely manner, a default will occur under our long-term debt agreements. Any event of default, if not timely remedied, could result in a termination of all commitments of the lenders and an acceleration of any outstanding loans and credit obligations.

 We may have continuing exposure on abandonment and decommissioning obligations associated with oil and gas properties sold by Maritech.
 
During 2011, in connection with the sale of a significant majority of Maritech’s oil and gas producing properties, the buyers of the properties assumed associated decommissioning liabilities having a value at the time of sale of approximately $122.0 million pursuant to the purchase and sale agreements. For oil and gas properties for which Maritech was previously the operator, the buyer of the properties has now generally become the successor operator and has assumed the financial responsibilities associated with the properties’ operations. However, to the extent that purchasers of these oil and gas properties fail to perform the abandonment and decommissioning work required, and there is insufficient bonding and we have insufficient other security, the previous owners and operators of the properties, including Maritech, may be required to assume responsibility for the abandonment and decommissioning obligation. To the extent Maritech is required to assume or perform a significant portion of the abandonment and decommissioning obligations associated with these sold oil and gas properties, 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 fluctuating oil and gas commodity prices or generally increased operating expenses than larger companies. Our ability to collect from our customers may be impacted by adverse changes in the energy industry.
 
As the owner and operator of its oil and gas property interests, Maritech is liable for the proper abandonment and decommissioning of these properties. We have guaranteed a portion of the abandonment and decommissioning liabilities of Maritech. In certain instances, Maritech is entitled to be paid in the future for all or a portion of these obligations by the previous owner of the property once the liability is satisfied. We and Maritech are subject to the risk that the previous owner(s) will be unable to make these future payments. In addition, for certain remaining Maritech properties to be decommissioned or abandoned, the co-owners of such properties are responsible for the payment of their portions of the associated operating expenses and abandonment liabilities. However, if one or more co-owners do not pay their portions, Maritech and any other nondefaulting co-owners may be liable for the defaulted amount. If any required payment is not made by a previous owner or a co-owner and any security is not sufficient to cover the required payment, we could suffer material losses.
 
Our operating results and cash flows for certain of our subsidiaries are subject to foreign currency risk.
 
The operations of certain of our subsidiaries are exposed to fluctuations between the U.S. dollar and certain foreign currencies, particularly the euro, the British pound, the Mexican peso, and the Argentinian peso. Our plans to grow our international operations could cause this exposure from fluctuating currencies to increase. Historically, exchange rates of foreign currencies have fluctuated significantly compared to the U.S. dollar, and this exchange rate volatility is expected to continue. Significant fluctuations in foreign currencies against the U.S. dollar could adversely affect our balance sheet and results of operations.
 
We are exposed to interest rate risk with regard to our indebtedness.
 
As of December 31, 2013, we and Compressco Partners have a total of $82.7 million outstanding under our respective revolving credit facilities. Our revolving credit facilities consist of floating rate loans that bear interest at an agreed upon percentage rate spread above LIBOR. Accordingly, our cash flows and results of operations could

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be subject to interest rate risk exposure associated with the level of the variable rate debt balance outstanding. We currently are not a party to an interest rate swap contract or other derivative instrument designed to hedge our exposure to interest rate fluctuation risk.
 
Our revolving credit facility is scheduled to mature in 2015. Compressco Partners' revolving credit facility is scheduled to mature in 2017. Our Senior Notes bear interest at fixed interest rates and are scheduled to mature at various dates between April 2015 and December 2020. 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.
 
Compressco Partners may not generate sufficient cash from operations to make cash distributions to its common and subordinated unitholders.
 
Compressco Partners may not generate sufficient cash from operations to enable it to make cash distributions to holders of common units at the minimum quarterly distribution rate under its cash distribution policy. To the extent Compressco Partners has insufficient available cash to distribute, the distribution shortfall will first be attributed to the subordinated units we hold, resulting in a reduction in our financing cash flows from distributions from Compressco Partners. Any shortfall in quarterly distributions attributed to the subordinated units will not be carried forward in arrears or recovered in future distributions.
 
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 strictly govern our operations relating to: corporate governance, employees, taxation, fees, filing requirements, permitting requirements, importation and exportation restrictions, environmental affairs, health and safety, waste management, and the manufacture, storage, handling, transportation, use, and sale of chemical products. Certain international jurisdictions impose additional restrictions on our activities, such as currency restrictions and restrictions on various labor practices. Our operation and decommissioning of offshore properties are also subject to and affected by various government regulations, including numerous federal and state environmental protection laws and regulations. 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, injunctions, or both. Third parties may also have the right to pursue legal actions to enforce compliance. It is possible that increasingly strict environmental laws, regulations, and enforcement policies could result in substantial costs and liabilities to us and could subject our handling, manufacture, use, reuse, or disposal of substances or pollutants to increased scrutiny.
 
The EPA is performing a study of 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. In addition, in December 2012, the EPA announced an update of the progress made pursuant to a study of the effects of hydraulic fracturing on the environment and reported that the full results of the study would be provided in 2014. 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, Compressco, and Fluids segments.
 
A large portion of the services performed by our Offshore Services segment and all of Maritech’s remaining well abandonment and decommissioning operations are conducted on offshore federal leases and are governed by increasing U.S. government regulations. Government regulations also establish construction requirements for production facilities located on federal offshore leases and govern the plugging and abandonment of wells and the removal of production facilities from these leases. Operators must  abide by Idle Iron Guidance regulations that regulate the permanent plugging of nonproducing wells and the dismantling of oil and gas production platforms

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within a certain period of time after they are no longer being used. BSEE oversees the provisions of the Idle Iron Guidance. Under limited circumstances, the BSEE could require Maritech or our Offshore Services segment to suspend or terminate their operations on a federal lease, and both Maritech and our Offshore Services segment could be subject to fines and penalties.
 
We have significant 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. In addition to potential impacts on our financial results directly or indirectly resulting from climate change legislation or regulations, our financial results also could be negatively affected by climate change-related physical changes or changes in weather patterns.

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, India, Iraq, Mexico, Norway, Saudi Arabia, Sweden, and the United Kingdom, and have an operating joint venture in Libya. 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 foreign profits back to the United States;
•
the impact of anti-corruption laws and the risk that actions taken by us or others on our behalf may adversely affect our operations and competitive position in the affected countries;
•
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.
 

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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 (FCPA), 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 growing 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 the 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 devaluation pressure. Fiscal and monetary expansion in Argentina have led to a devaluation of the Argentinian peso, particularly in late 2013 and early 2014. 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 expanding operations in Argentina, consolidated revenues and operating cash flow generated in Argentina have increased over the past three years. As of December 31, 2013, approximately $1.5 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 the loss of liquidity, foreign exchange losses, and other potential financial impacts.
 
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.
 
On December 15, 2009, the EPA published its final findings that emissions of carbon dioxide, methane, and other “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. These findings allow the EPA to adopt and implement regulations that would restrict emissions of GHGs under existing provisions of the federal Clean Air Act (CAA). Based on these findings, the EPA has begun adopting and implementing regulations to restrict emissions of GHGs under existing provisions of the CAA. The 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 as well as requiring so-called “green” completions at hydraulically fractured natural gas wells beginning in 2015. The EPA also requires the annual reporting of GHG emissions from specified large GHG emission sources in the United States, including petroleum refineries, as well as from certain oil and gas production facilities.
 
The 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.
 

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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.
  
Item 1B. Unresolved Staff Comments.
 
None.
 
Item 2. Properties.
 
Our properties consist primarily of our corporate headquarters facility, chemical plants, processing plants, distribution facilities, heavy lift barge rigs, dive support vessels, well abandonment and decommissioning equipment, oil and gas properties, rig cooling equipment, and flow back production testing equipment. In addition, through our majority owned subsidiary, Compressco Partners, our properties include compression and other production enhancement equipment. All obligations under the bank revolving credit facility for Compressco Partners are secured by a first lien security interest in substantially all of Compressco Partners’ assets, including its compressor fleet, but excluding its real property. The following information describes facilities that we leased or owned as of December 31, 2013. 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 33,000 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 Enhancement 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 Brazil, Mexico, United Arab Emirates, United Kingdom, Saudi Arabia, Iraq, Argentina, Australia, Canada, and Colombia. The Compressco segment’s facilities include an owned fabrication facility and a leased headquarters facility in Oklahoma, a leased fabrication facility in Alberta, Canada, and several leased service and sales facilities in the United States, Mexico, and Argentina.
 
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, the Offshore Services segment owns the following

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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
Epic Seahorse
210-foot dive support vessel
 
In addition, the ADAMS Challenge is under chartered lease arrangement by the Offshore Division through October 2015, with an option to extend for an additional 12 months. The ADAMS Challenge is a 280-foot Class 2 dynamically positioned dive support vessel with a 1,000-foot split-level saturation diving system.
 
See below for a discussion of the Offshore Division’s oil and gas property assets.
 
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. In December 2012, we entered into a sale leaseback transaction where we sold the headquarters building and land for a sale price of $43.8 million before transaction costs and other deductions, and leased back the facility for an initial lease term of 15 years. In addition, we own a 28,000 square foot technical facility in The Woodlands, Texas, to service our Fluids Division operations.
 
Oil and Gas Properties
 
The following tables show, for the periods indicated, certain information related to our Maritech subsidiary’s oil and gas interests, all of which are located in the U.S. Gulf of Mexico. Maritech’s oil and gas operations are a separate segment included within our Offshore Division.
 
See also “Note R – Supplemental Oil and Gas Disclosures” in the Notes to Consolidated Financial Statements for additional information.
 
Oil and Gas Reserves
 
Following the 2011 and 2012 sales of substantially all of Maritech’s proved oil and gas reserves, Maritech’s remaining oil and gas reserves as of December 31, 2012 and 2013, are negligible and not material to our business operations or financial position.

Production Information
 
The table below sets forth information related to production, average sales price, and average production cost per unit of oil and gas produced during 2013, 2012, and 2011:

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Year Ended December 31,
 
 
2013
 
2012
 
2011
Production:
 
 

 
 

 
 

Natural gas (Mcf)
 
302,710

 
310,894

 
3,321,651

NGL (Bbls)
 
28,270

 
38,681

 
88,070

Oil (Bbls)
 
32,782

 
23,040

 
611,748

Revenues:
 
 

 
 

 
 

Natural Gas
 
$
1,148,000

 
$
1,609,000

 
$
14,596,000

NGL
 
1,225,000

 
1,907,000

 
4,744,000

Oil
 
3,187,000

 
2,642,000

 
62,601,000

Total
 
$
5,560,000

 
$
6,158,000

 
$
81,941,000

Average realized unit prices and production costs:
 
 

 
 

 
 

Natural gas (per Mcf)
 
$
3.79

 
$
5.18

 
$
4.39

NGL (per Bbl)
 
$
43.33

 
$
49.30

 
$
53.87

Oil (per Bbl)
 
$
97.22

 
$
114.63

 
$
102.34

Production cost per equivalent barrel
 
$
23.65

 
$
33.02

 
$
26.72

Depletion cost per equivalent barrel
 
$
—

 
$
—

 
$
22.05

 
Realized unit prices during 2011 include the impact of hedge commodity swap contracts. In April 2011, in connection with the anticipated plans to sell Maritech’s remaining oil and gas properties, we liquidated the derivative swap financial instruments that were designated as hedges of Maritech’s future oil production. Equivalent barrel (BOE) information is calculated assuming six Mcf of gas is equivalent to one barrel of oil. Depletion cost per equivalent barrel excludes the impact of dry hole costs and property impairments.
 
Acreage and Productive Wells
 
At December 31, 2013, our Maritech subsidiary owned interests in the following oil and gas wells and acreage:
 
 
Productive Gross
Wells
 
Productive Net
Wells
 
Developed
Acreage
 
Undeveloped
Acreage
State/Area
 
Oil
 
Gas
 
Oil
 
Gas
 
Gross
 
Net
 
Gross
 
Net
Louisiana Onshore
 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

Louisiana Offshore
 
—

 
4

 
—

 
1.3

 
—

 
—

 
683

 
341

Texas Onshore
 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

Texas Offshore
 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

Federal Offshore
 
—

 
—

 
—

 
—

 
21,875

 
7,463

 
26,809

 
12,953

Total
 
—

 
4

 
—

 
1.3

 
21,875

 
7,463

 
27,492

 
13,294

 
The majority of Maritech’s oil and gas properties are held by production. Leases covering undeveloped acreage other than acreage held by production have expiration terms ranging from 2014 through 2015. The following table sets forth the expiration amounts of our gross and net undeveloped acreage as of December 31, 2013:
 
 
2014
 
2015
 
2016
 
2017
 
2018
 
Held by
Production
State/Area
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
Louisiana Onshore
 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

Louisiana Offshore (State)
 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
683

 
342

Texas Offshore
 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

Federal Offshore
 
—

 
—

 
1,250

 
1,250

 
—

 
—

 
—

 
—

 
—

 
—

 
47,434

 
19,166

Total
 
—

 
—

 
1,250

 
1,250

 
—

 
—

 
—

 
—

 
—

 
—

 
48,117

 
19,508


25


 
Maritech has no significant delivery commitments with regard to its future oil and gas production.
 
Drilling Activity
 
During 2013 and 2012, Maritech did not participate in drilling activity. During 2011, Maritech participated in the drilling of 4 gross development wells (0.8 net wells), all of which were productive. As of December 31, 2013, there were no wells in the process of being drilled.
 
Significant Oil and Gas Properties
 
As of December 31, 2012 and 2013, Maritech has sold all of its most significant oil and gas producing properties. Remaining oil and gas properties are classified as Assets Held for Sale in our accompanying consolidated balance sheet as of December 31, 2012 and 2013. Prior to their sale, Maritech’s most significant oil and gas properties were its interests in the Timbalier Bay Area, the Main Pass Area, and the East Cameron 328 field. Production information for each of these most significant properties during the three years ended December 31, 2013, is as follows:
 
 
Year Ended December 31,
 
 
2013
 
2012
 
2011
 
 
Oil
 
NGL
 
Natural Gas
 
Oil
 
NGL
 
Natural Gas
 
Oil
 
NGL
 
Natural Gas
 
 
(MBbls)
 
(MBbls)
 
(MMcf)
 
(MBbls)
 
(MBbls)
 
(MMcf)
 
(MBbls)
 
(MBbls)
 
(MMcf)
Timbalier Bay Area
 
—

 
—

 
—

 
—

 
—

 
—

 
379

 
31

 
1,549

Main Pass Area
 
—

 
—

 
—

 
—

 
—

 
—

 
53

 
22

 
862

East Cameron 328
 
—

 
—

 
—

 
—

 
—

 
—

 
61

 
—

 
32

 
Average realized unit prices and production costs for each of these fields were approximately equal to Maritech’s overall unit prices and costs, as all of Maritech’s production is located in the Gulf of Mexico region.

Item 3. Legal Proceedings.
 
We are named defendants in several lawsuits and respondents in certain governmental proceedings arising in the ordinary course of business. While the outcome of lawsuits or other proceedings against us cannot be predicted with certainty, management does not consider it reasonably possible that a loss resulting from such lawsuits or other proceedings in excess of any amounts accrued has been incurred that is expected to have a material adverse 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 future remediation costs and 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.


26


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 1, 2014, there were approximately 8,629 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, 2013, as reported by the New York Stock Exchange.
 
 
High
 
Low
2013
 
 

 
 

First Quarter
 
$
10.74

 
$
7.72

Second Quarter
 
11.48

 
8.15

Third Quarter
 
12.97

 
9.41

Fourth Quarter
 
13.41

 
11.52

2012
 
 

 
 

First Quarter
 
$
10.66

 
$
8.69

Second Quarter
 
9.80

 
6.09

Third Quarter
 
7.57

 
6.00

Fourth Quarter
 
7.75

 
5.35

 
Market Price of Common Stock
 
The following graph compares the five-year cumulative total returns of our common stock, the Standard & Poor’s 500 Composite Stock Price Index (S&P 500), and the Philadelphia Oil Service Sector Index (PHLX Oil Service), assuming $100 invested in each stock or index on December 31, 2008, 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.


27


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 “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 2013 pursuant to the repurchase program. Shares repurchased during the fourth quarter of 2013 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, 2013
 
9,470

 
(2)
 
$
12.79

 
—

 
$
14,327,000

Nov 1 – Nov 30, 2013
 
10,964

 
(2)
 
12.23

 
—

 
14,327,000

Dec 1 – Dec 31, 2013
 
16,170

 
(2)
 
11.58

 
—

 
14,327,000

Total
 
36,604

 
 
 
 

 
—

 
$
14,327,000

(1) 
In January 2004, our Board of Directors authorized the repurchase of up to $20 million of our common stock. Purchases will be made from time to time in open market transactions at prevailing market prices. The repurchase program may continue until the authorized limit is reached, at which time the Board of Directors may review the option of increasing the authorized limit.
(2) 
Shares we received in connection with the exercise of certain employee stock options or the vesting of certain employee restricted stock. 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, 2013, 2012, 2011, 2010, and 2009. 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 “Management’s Discussion and Analysis of Financial Condition and Results of Operation” appearing elsewhere in this report. Please read “Item 1A. Risk Factors” beginning on page 11 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 2013, we recorded significant charges to earnings associated with Maritech's decommissioning liabilities. During 2012, our Production Testing segment acquired OPTIMA, ERS, and Greywolf. During 2010, we recorded significant impairments of our oil and gas properties, a dive support vessel, and a calcium chloride manufacturing plant, as well as significant charges to earnings associated with adjustments to Maritech’s decommissioning liabilities. During 2011, Maritech sold approximately 95% of the oil and gas proved reserves it held as of December 31, 2010. These acquisitions, dispositions, and impairments significantly impact the comparison of our financial statements for 2013 to earlier years.

28


 
 
Year Ended December 31,
 
 
2013
 
2012
 
2011
 
2010
 
2009
 
 
 
(In Thousands, Except Per Share Amounts)
Income Statement Data
 
 

 
 

 
 

 
 

 
 

 
Revenues
 
$
909,398

 
$
880,831

 
$
845,275

 
$
872,678

 
$
878,877

 
Gross profit
 
135,392

 
167,380

 
89,042

 
42,447

 
212,077

 
General and administrative expense
 
131,466

 
131,649

 
111,805

 
98,872

 
99,812

 
Interest expense
 
17,417

 
17,378

 
17,195

 
17,528

 
13,207

 
Interest income
 
(296
)
 
(298
)
 
(756
)
 
(224
)
 
(417
)
 
Other (income) expense, net
 
(13,067
)
 
(9,532
)
 
(45,435
)
 
64

 
(5,895
)
 
Income (loss) before discontinued operations
 
3,326

 
18,754

 
5,482

 
(43,325
)
 
68,807

 
Net income (loss)
 
3,325

 
18,757

 
5,418

 
(43,718
)
 
68,804

 
Net income (loss) attributable to TETRA stockholders
 
$
153

 
$
15,960

 
$
4,147

 
$
(43,718
)
 
$
68,804

 
Income (loss) per share, before discontinued operations attributable to TETRA stockholders
 
$
0.00

 
$
0.21

 
$
0.05

 
$
(0.57
)
 
$
0.92

 
Average shares
 
77,954

 
77,293

 
76,616

 
75,539

 
75,045

 
Income (loss) per diluted share, before discontinued operations attributable to TETRA stockholders
 
$
0.00

 
$
0.20

 
$
0.05

 
$
(0.57
)
 
$
0.91

 
Average diluted shares
 
78,840

(1) 
77,963

(2) 
77,991

(3) 
75,539

(4) 
75,722

(5) 
(1) 
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.
(2) 
For the year ended December 31, 2012, the calculation of average diluted shares outstanding excludes the impact of 2,832,192 average outstanding stock options that would have been antidilutive.
(3) 
For the year ended December 31, 2011, the calculation of average diluted shares outstanding excludes the impact of 2,831,118 average outstanding stock options that would have been antidilutive.
(4) 
For the years ended December 31, 2010, the calculation of average diluted shares outstanding excludes the impact of all of our outstanding stock options, since all were antidilutive due to the net loss for the year.
(5) 
For the year ended December 31, 2009, the calculation of average diluted shares outstanding excludes the impact of 3,185,388 average outstanding stock options that would have been antidilutive.

 
 
December 31,
 
 
2013
 
2012
 
2011
 
2010
 
2009
 
 
(In Thousands)
Balance Sheet Data
 
 

 
 

 
 

 
 

 
 

Working capital
 
$
200,913

 
$
178,294

 
$
296,136

 
$
198,106

 
$
148,343

Total assets
 
1,206,533

 
1,261,818

 
1,203,310

 
1,299,628

 
1,347,599

Long-term debt
 
387,727

 
331,268

 
305,000

 
305,035

 
310,132

Decommissioning and other long-term liabilities
 
48,282

 
80,427

 
96,857

 
261,438

 
218,498

Equity
 
597,498

 
593,308

 
569,088

 
516,323

 
576,494


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.
 

29


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 

Led by the unprecedented strength of our Fluids Division, operating results for the year ended December 31, 2013, reflected growth in consolidated revenues compared to the prior year, despite significant challenges and uncertainties in several of our key markets. The growth of the Fluids Division's onshore water management business, the increased sales of its manufactured products, and the strong demand for clear brine fluids (CBFs) in the U.S. Gulf of Mexico together resulted in record revenues and profitability for this Division. Our Compressco segment also reflected record revenues, as the reduction in activity by its principal customer in Mexico was more than offset by the growth of its U.S. unconventional compression services applications revenue and from growth in other foreign markets. Our Offshore Services segment continues to take the strategic measures necessary to successfully operate in a challenging U.S. Gulf of Mexico market and in anticipation of the decreasing work to be performed for our Maritech segment going forward. As a result of continuing cost reduction efforts and other steps taken, our Offshore Services segment generated increased profitability compared to the prior year, despite decreased revenues. The decreased revenues and profitability of our Production Testing segment reflect the reduction in Mexico activity, the suspension of activity in South Texas by a significant U.S. customer, and increased competitive pressure in several key North American markets. The pretax profitability of our core businesses was offset by significant losses by our Maritech segment, due to excess decommissioning costs expensed by Maritech during 2013, including costs for additional remediation work incurred and anticipated to be required on certain wells that had been previously plugged.

We are committed to the continuing growth of our core businesses, and we fund our growth primarily from the cash flows provided by our operating activities as well as from borrowings under our revolving credit facilities. Capital expenditures during 2013 totaled approximately $101.4 million, primarily for the expansion of our fleet of operating equipment for our Fluids and Production Enhancement Division businesses. In addition, in January 2014, we purchased the assets and operations of WIT Water Transfer, LLC (doing business as TD Water Transfer), a water management service provider operating primarily in South Texas, in exchange for $15.0 million in cash paid at closing plus additional contingent consideration. Also in January 2014, we purchased the remaining 50% ownership interest of a Saudi Arabian limited liability company, Ahmad Albinali & TETRA Arabia Company Ltd. (TETRA Arabia) through which we provide completion fluids and services as well as production testing and offshore rig cooling services. The purchase price consisted of $15.0 million in cash paid at closing with an additional $10.2 million scheduled to be paid in July 2014. As a result of the purchase of the remaining ownership, TETRA Arabia, which generated approximately $36.1 million of revenues during 2013, will become a consolidated subsidiary beginning in 2014. These acquisition transactions are expected to further strengthen the U.S. operations of our Fluids segment as well as the Eastern Hemisphere operations of both our Fluids and Production Testing segments. As of February 28, 2014, we have approximately $210.4 million available under our revolving credit facility to fund future strategic growth, and Compressco Partners has an additional $36.8 million available under its revolving credit facility.

Strategic efforts, including the company-wide cost reduction efforts initiated during late 2012 and the first half of 2013, have resulted in improved operating results and cash flow generation for each of our core businesses. Ongoing efforts to streamline and improve invoicing and collection processes have also improved our operating cash flow. Primarily as a result of these efforts, consolidated cash flows provided from operating activities during 2013 increased by $32.0 million, or 181.0%, compared to the prior year. The improvements in operating cash flow levels have enabled us to fund a large portion of our overall growth, while we also continue to aggressively pursue the extinguishment of Maritech's remaining decommissioning liabilities. During 2013, we expended approximately $114.1 million on Maritech decommissioning and abandonment efforts, and, as of December 31, 2013, Maritech's remaining decommissioning liabilities have been reduced to approximately $43.3 million. The majority of the remaining decommissioning and abandonment work is scheduled to be completed in 2014. The expected future decrease in the level of operating cash expended for this work is anticipated to result in a significant increase in operating cash flows.

Future demand for our products and services depends primarily on activity in the oil and natural gas exploration and production industry, particularly including the level of expenditures for the exploration and production of oil and natural gas reserves and for the plugging and decommissioning of abandoned offshore oil and natural gas properties. The growth of certain of our businesses may become hampered by the future pricing levels

30


of crude oil and natural gas. We believe that there are growth opportunities for our products and services, supported primarily by:
•
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;
•
increases in technologically driven deepwater oil and gas well completions in the Gulf of Mexico; and
•
increasing international oil and gas exploration and development activities.
 
Our Fluids Division generates revenues and cash flows by manufacturing and marketing clear brine completion fluids (CBFs), additives, CBF and water management services, 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 provides a broad range of associated services, including: onsite fluids filtration, handling, and recycling; wellbore cleanup; and fluid engineering consultation. 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. Fluids Division revenues increased $48.1 million during 2013 compared to 2012, due to the continuing growth of the Division's water management services business, increased CBF product sales from increased activity in the Gulf of Mexico, and increased sales of manufactured products compared to the prior year. Although demand for the Fluids Division’s CBF products is driven primarily by completion activity rather than drilling activity, the increase in the Gulf of Mexico rig count compared to 2012 reflects the increasing demand for offshore CBF products. Demand for the Division's products and services, particularly for its offshore CBF products, has been affected by regulatory restrictions in the past and may continue to be affected by future regulatory restrictions. With the acquisition of the TD Water Transfer assets, we anticipate that the revenues, profitability, and operating cash flows of the Fluids Division will continue to increase going forward.
 
Our Production Enhancement Division consists of two operating segments: the Production Testing segment and the Compressco segment. The Production Testing segment generates revenues and cash flows by performing after-frac flow back, production well testing, offshore rig cooling, early production facilities, and other associated services. The primary markets served by the Production Testing segment include many of the major oil and gas producing regions in the United States, Mexico, and Canada, as well as in certain oil and gas basins in certain regions in South America, Africa, Europe, the Middle East, and Australia. The 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 segment serves. The Production Testing segment’s revenues decreased by $12.0 million in 2013 compared to 2012, due to decreased activity by the segment's primary customers in Mexico and South Texas and the impact of increasing competition, particularly in North America.
 
Our Compressco segment generates revenues and cash flows by performing compression-based production enhancement services throughout many of the onshore oil and gas producing regions of the United States, as well as certain basins in Mexico and Canada, and certain countries in South America, Europe, and the Asia-Pacific region. The Compressco segment provides services that are used in both conventional wellhead compression applications and unconventional compression applications, and, in certain circumstances, well monitoring and sand separation services. In certain markets, the Compressco segment also sells compressor packages and parts. Compressco segment revenues increased $11.8 million in 2013 as compared to 2012, primarily due to increased demand for domestic unconventional compression applications, and the growth of activity in Canada and Argentina, which more than offset the decreased activity by its primary customer in Mexico. In addition, revenues from the sales of compressor packages and parts also increased compared to the prior year. While there are uncertainties in Latin America that could affect operations, including the upcoming renewal of certain customer contracts, as well as uncertainties surrounding the domestic price of natural gas which drives demand for a portion of Compressco’s domestic services, we expect revenues from the segment will continue to increase.
 
Our Offshore Division consists of two operating segments: Offshore Services and Maritech. Offshore Services generates revenues and cash flows by performing (1) downhole and subsea oil and gas well plugging and abandonment 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 air diving services. The services provided by the Offshore Services segment are marketed to offshore operators, primarily in the U.S. Gulf of Mexico. Gulf of Mexico platform decommissioning and

31


well abandonment activity levels are driven primarily by BSEE regulations; the declining production levels of producing fields; the age of production platforms and other structures; oil and natural gas commodity prices; sales activity of mature oil and gas producing properties; and overall oil and gas company activity levels. Offshore Services revenues decreased by $10.1 million during 2013 compared to 2012, due to the continuing challenges in the U.S. Gulf of Mexico market, including decreased heavy lift, abandonment, and cutting services activity, customer project delays, weather disruptions, and pricing pressures during the past year. We expect that the remaining decommissioning and abandonment work to be performed for Maritech will decrease beginning in 2014, and, thereafter, the Offshore Services segment is focused on replacing this work with work for third party customers.
 
The sales of substantially all of Maritech’s oil and gas producing properties during 2011 and 2012 have essentially removed us from the oil and gas exploration and production business. Maritech’s revenues are minimal and are expected to continue to be minimal going forward. Maritech’s current operations primarily consist of the ongoing plugging, abandonment, and decommissioning associated with its remaining offshore wells, facilities, and production platforms. We expect to complete the majority of this remaining work during 2014.

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 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.
 
Impairment of Long-Lived Assets
 
The determination of impairment of long-lived assets is conducted periodically whenever indicators of impairment are present. If such indicators are present, the determination of the amount of impairment is based on our judgments as to the future operating cash flows to be generated from these assets throughout their estimated useful lives. If an impairment of a long-lived asset is warranted, we estimate the fair value of the asset based on a present value of these cash flows or the value that could be realized from disposing of the asset in a transaction between market participants. The oil and gas industry is cyclical, and our estimates of the amount of future cash flows, the period over which these estimated future cash flows will be generated, as well as the fair value of an impaired asset, are imprecise. Our failure to accurately estimate these future operating cash flows or fair values could result in certain long-lived assets being overstated, which could result in impairment charges in periods
subsequent to the time in which the impairment indicators were first present. Alternatively, if our estimates of future operating cash flows or fair values are understated, impairments might be recognized unnecessarily or in excess of the appropriate amounts. During 2013, we recorded long-lived asset impairments of $9.6 million. During periods of economic uncertainty, the likelihood of additional material impairments of long-lived assets is higher due to the possibility of decreased demand for our products and services.
 
Impairment of Goodwill
 
The impairment of goodwill is also assessed whenever impairment indicators are present, but not less than once annually. The annual 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 it was not “more

32


likely than not” that the fair values of any of our reporting units were less than their carrying values as of December 31, 2013. If 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 would consist of a two-step accounting test performed on a reporting unit basis. If 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, if 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. There were no impairments of goodwill recorded based on our assessment as of December 31, 2013.
 
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. During each of the three years ended December 31, 2013, 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 those years. Maritech recorded approximately $194.5 million of excess decommissioning expense during the three years ended December 31, 2013, associated with work performed or to be performed on its oil and gas properties. In addition, adjustments to decommissioning liabilities associated with productive properties were capitalized to oil and gas properties and contributed significantly to Maritech recording approximately $15.2 million of oil and gas property impairments during 2011. 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. To the extent our decommissioning liabilities are understated, additional charges to earnings may be required in future periods.
 
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.

33



With regard to longer-term lump sum contracts, revenue is recognized using the percentage-of-completion method based on the ratio of costs incurred to total estimated costs at completion. The estimation of total costs to be incurred may be imprecise due to unexpected well conditions, delays, weather, and other uncertainties. Inaccurate cost estimates may result in the revenue associated with a specific contract being recognized in an inappropriate period. Total project revenue and cost estimates for lump sum contracts are reviewed periodically, but at least quarterly, as work progresses, and adjustments are reflected in the period in which such estimates are revised. Provisions for estimated losses on such contracts are made in full in the period such losses are determined. Despite the uncertainties associated with estimating the total contract cost, our recognition of revenue associated with these contracts has historically been reasonable.
 
Occasionally, our Offshore Services segment is a party to project management contracts which contain multiple deliverables, including the performance of service milestones. While the contract provides contract-determined values associated with each milestone, the recognition of revenue is determined based on the realized market values received by the customer. The determination of realized market values is supported by objective evidence whenever possible, but may also be determined based on our judgments as to the value of a particular deliverable.
 
Income Taxes
 
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. This calculation requires us to make certain estimates about our future operations, and many of these estimates of future operations may be imprecise. Changes in state, federal, and foreign tax laws, as well as changes in our financial condition, could affect these estimates. In addition, 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. Our estimates and judgments associated with our calculations of income taxes have been reasonable in the past, however, the possibility for changes in the tax laws, as well as the current economic uncertainty, could affect the accuracy of our income tax estimates in future periods.
 
Acquisition Purchase Price Allocations
 
We account for acquisitions of businesses using the purchase method, which requires the allocation of the purchase price based on the fair values of the assets and liabilities acquired. We estimate the fair values of the assets and liabilities acquired using accepted valuation methods, and, in many cases, such estimates are based on our judgments as to the future operating cash flows expected to be generated from the acquired assets throughout their estimated useful lives. We have completed several acquisitions during the past several years and have accounted for the various assets (including intangible assets) and liabilities acquired based on our estimate of fair values. Goodwill represents the excess of acquisition purchase price over the estimated fair values of the net assets acquired. Our estimates and judgments of the fair value of acquired businesses are imprecise, and the use of inaccurate fair value estimates could result in the improper allocation of the acquisition purchase price to acquired assets and liabilities, which could result in asset impairments, the recording of previously unrecorded liabilities, and other financial statement adjustments. The difficulty in estimating the fair values of acquired assets and liabilities is increased during periods of economic uncertainty.


34


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.
 
2013 Compared to 2012
 
Consolidated Comparisons
 
 
Year Ended
December 31,
 
Period to Period Change
 
 
2013
 
2012
 
2013 vs 2012
 
% Change
 
 
(In Thousands, Except Percentages)
Revenues
 
$
909,398

 
$
880,831

 
$
28,567

 
3.2
 %
Gross profit
 
135,392

 
167,380

 
(31,988
)
 
(19.1
)%
Gross profit as a percentage of revenue
 
14.9
 %
 
19.0
%
 
 

 
 

General and administrative expense
 
131,466

 
131,649

 
(183
)
 
(0.1
)%
General and administrative expense as a percentage of revenue
 
14.5
 %
 
14.9
%
 
 

 
 
Interest expense, net
 
17,121

 
17,080

 
41

 
0.2
 %
(Gain) loss on sale of assets
 
(5,776
)
 
(4,916
)
 
(860
)
 
 

Other (income) expense, net
 
(7,291
)
 
(4,616
)
 
(2,675
)
 
 

Income before taxes and discontinued operations
 
(128
)
 
28,183

 
(28,311
)
 
(100.5
)%
Income before taxes and discontinued operations as a percentage of revenue
 
—
 %
 
3.2
%
 
 

 
 

Provision (benefit) for income taxes
 
(3,454
)
 
9,429

 
(12,883
)
 
(136.6
)%
Income before discontinued operations
 
3,326

 
18,754

 
(15,428
)
 
(82.3
)%
Income (loss) from discontinued operations, net of taxes
 
(1
)
 
3

 
(4
)
 
 

Net income
 
3,325

 
18,757

 
(15,432
)
 
(82.3
)%
Net income attributable to noncontrolling interest
 
(3,172
)
 
(2,797
)
 
(375
)
 
 

Net income attributable to TETRA stockholders
 
$
153

 
$
15,960

 
$
(15,807
)
 
(99.0
)%
 
Consolidated revenues during 2013 increased compared to 2012 due to increased revenues of our Fluids and Compressco segments. Growth of the Fluids Division's onshore water management business, increased sales of its manufactured products, and strong demand for clear brine fluids (CBFs) in the U.S. Gulf of Mexico resulted in record revenues for this Division. Our Compressco segment also reflected record revenues, as the reduction in activity by its principal customer in Mexico was more than offset by the growth of its U.S. unconventional compression services applications revenue and from growth in other international markets. These increased consolidated revenues were negatively affected by our Offshore Services segment as well as our Production Testing segment. Our Offshore Services segment reported decreased revenues for the current year compared to the prior year due to a reduction in heavy lift and cutting services activity. This business was also adversely affected by weather delays during the second and third quarters of 2013 as well as by continuing market challenges in the U.S. Gulf of Mexico. Our Production Testing segment revenues also decreased, reflecting the reduction in Mexico activity, the suspension of activity by a significant U.S. customer, and increased competitive pressure in several key North American markets. Consolidated gross profit decreased, despite the increased profitability of our Fluids and Offshore Services segments, as our Maritech and Production Testing segments reported decreases. Maritech recorded increased excess decommissioning costs during 2013 as compared to 2012.

Consolidated general and administrative expenses during 2013 remained consistent with 2012 levels. Decreases in compensation and other employee related expenses by our Offshore Services, Corporate, and Compressco segments were primarily due to cost reduction efforts during late 2012 and early 2013 as well as decreased equity based compensation during 2013 compared to 2012. These administrative cost decreases were largely offset by increased general and administrative costs due to the growth of our Fluids Division, the acquisitions completed during 2012 by our Production Testing segment, and approximately $1.9 million of employee severance costs during 2013. Overall, cost reduction efforts taken by each of our segments are expected to continue to improve profitability during 2014.  

35



Consolidated interest expense stayed consistent during 2013 compared to the prior year, as increased interest expense from Compressco Partners borrowings was largely offset by the impact of the lower interest rate on the 2013 Senior Notes.

Consolidated gains on sale of assets increased due to the sale by Maritech of one of its remaining oil and gas properties during the third quarter of 2013.

Consolidated other income increased primarily due to increased earnings from TETRA Arabia, an unconsolidated limited liability company, and partly offset by decreased foreign currency exchange losses.
 
The consolidated provision for income taxes decreased compared to the prior year due to decreased earnings.

Divisional Comparisons
 
Fluids Division
 
 
Year Ended
December 31,
 
Period to Period Change
 
 
2013
 
2012
 
2013 vs 2012
 
% Change
 
 
(In Thousands, Except Percentages)
Revenues
 
$
382,663

 
$
334,548

 
$
48,115

 
14.4
%
Gross profit
 
100,106

 
79,454

 
20,652

 
26.0
%
Gross profit as a percentage of revenue
 
26.2
%
 
23.7
%
 
 

 
 

General and administrative expense
 
32,648

 
30,466

 
2,182

 
7.2
%
General and administrative expense as a percentage of revenue
 
8.5
%
 
9.1
%
 
 

 
 

Interest (income) expense, net
 
(148
)
 
54

 
(202
)
 
 

Other (income) expense, net
 
(1,832
)
 
(1,896
)
 
64

 
 

Income before taxes and discontinued operations
 
$
69,438

 
$
50,830

 
$
18,608

 
36.6
%
Income before taxes and discontinued operations as a percentage of revenue
 
18.1
%
 
15.2
%
 
 

 
 

 
The increase in Fluids Division revenues during 2013 compared to 2012 was primarily due to approximately $24.0 million of increased product sales, primarily due to the increased demand for its calcium chloride manufactured products as well as increased sales of brominated products. A portion of these increased manufactured product sales was due to increased demand in selected markets and nonrecurring demand from a single U.S. customer during 2013. In addition, Fluids Division product sales also reflect the increased demand for its CBF products, as U.S. Gulf of Mexico drilling and completion activity levels increased in 2013 compared to the prior year. Decreased Latin America CBF product sales were partially offset by increased Eastern Hemisphere revenues. Following the January 2014 purchase of the remaining interest of TETRA Arabia, our unconsolidated Saudi Arabian limited liability company, TETRA Arabia will be consolidated as a wholly owned subsidiary and is expected to result in increased Division revenues and gross profit. In addition, the Division also reported approximately $24.2 million of increased service revenues, primarily from the growth of its onshore water management business. This growth in the water management business is expected to continue into 2014 primarily due to the January 2014 acquisition of the assets and operations of TD Water Transfer, which provides water management services to customers in the South Texas and North Dakota regions of the U.S.
 
Fluids Division gross profit increased compared to 2012, primarily as a result of the increased demand for manufactured products and the increased U.S. onshore water management activity discussed above, which more than offset the decrease in profitability in Latin America. The increased demand for manufactured products resulted in increased production efficiencies for our El Dorado, Arkansas, calcium chloride facility. Also, the profitability of our European calcium chloride operations improved during 2013 after experiencing reduced plant production levels and equipment repairs during 2012.
 

36


Fluids Division income before taxes increased compared to the prior year due to the increase in gross profit discussed above and despite increased administrative costs. Fluids Division administrative costs increased primarily due to increased personnel-related costs, partially offset by decreased professional fee expenses. Other income remained flat compared to the prior year, as increased foreign currency exchange losses were offset by increased earnings by TETRA Arabia. As discussed above, beginning in the first quarter of 2014, due to the purchase of the remaining ownership interest, the results of operations from TETRA Arabia will be consolidated as a wholly owned subsidiary.

Production Enhancement Division
 
Production Testing Segment
 
 
Year Ended
December 31,
 
Period to Period Change
 
 
2013
 
2012
 
2013 vs 2012
 
% Change
 
 
(In Thousands, Except Percentages)
Revenues
 
$
195,983

 
$
207,984

 
$
(12,001
)
 
(5.8
)%
Gross profit
 
29,566

 
58,009

 
(28,443
)
 
(49.0
)%
Gross profit as a percentage of revenue
 
15.1
%
 
27.9
%
 
 

 
 

General and administrative expense
 
24,671

 
23,386

 
1,285

 
5.5
 %
General and administrative expense as a percentage of revenue
 
12.6
%
 
11.2
%
 
 

 
 

Interest (income) expense, net
 
(34
)
 
(43
)
 
9

 
 

Other (income) expense, net
 
(9,164
)
 
(5,181
)
 
(3,983
)
 
 

Income before taxes and discontinued operations
 
$
14,093

 
$
39,847

 
$
(25,754
)
 
(64.6
)%
Income before taxes and discontinued operations as a percentage of revenue
 
7.2
%
 
19.2
%
 
 

 
 

 
Production Testing segment revenues decreased during 2013 compared to 2012 due to the decreases in activity by the segment's primary customer in Mexico. In addition, revenues decreased in the U.S. as a result of the suspension of activity in South Texas by a significant U.S. customer and increased competitive pressure in several key North American markets. These decreases in U.S. revenues more than offset the increased revenues as a result of including a full year of activity from the 2012 acquisitions of ERS and Greywolf. These decreases in the U.S. and Mexico were partially offset by increased revenues in Canada, as a result of the Greywolf acquisition, and in the Eastern Hemisphere, which contributed growth due to increased Middle East activity as well as due to the 2012 acquisition of the segment's OPTIMA offshore rig cooling business. As discussed above, in January 2014, we acquired the remaining ownership interest of TETRA Arabia. Beginning in the first quarter of 2014, TETRA Arabia will be consolidated as a wholly owned subsidiary, and is expected to result in increased revenues and gross profit.
 
Production Testing segment gross profit decreased during 2013 compared to the prior year, despite the 2012 acquisitions of OPTIMA, ERS, and Greywolf. The gross profit increase from the acquired businesses and the growth in certain of the segment's foreign operations was more than offset by the impact of the decreased activity and pricing levels in certain U.S. markets, increased labor costs, and the impact of the decreased production testing activity in Mexico compared to the prior year. Beginning in the second quarter of 2013, we took steps to downsize field operations and implement other cost reductions for the Production Testing segment, including the relocation of equipment and other resources, that have resulted in decreased operating expenses. We continue to seek additional steps in response to the decreased activity in certain U.S. markets that are expected to result in further operating expense reductions during 2014.
 
Production Testing segment income before taxes decreased due to the decreased gross profit discussed above as well as from increased administrative expenses compared to the prior year. The increased administrative expenses were primarily due to the increased personnel-related and other administrative costs associated with the acquired OPTIMA, ERS, and Greywolf businesses. These increases more than offset the decrease in professional services expenses, which included approximately $2.8 million of acquisition related costs during the prior year. Partially offsetting the decreased gross profit and increased general and administrative expenses, other income increased primarily due to increased earnings from TETRA Arabia. As discussed above, beginning in the first quarter of 2014, the results of operations from TETRA Arabia will be consolidated as a wholly owned subsidiary.

37



Compressco Segment
 
 
Year Ended
December 31,
 
Period to Period Change
 
 
2013
 
2012
 
2013 vs 2012
 
% Change
 
 
(In Thousands, Except Percentages)
Revenues
 
$
121,288

 
$
109,466

 
$
11,822

 
10.8
 %
Gross profit
 
38,726

 
38,991

 
(265
)
 
(0.7
)%
Gross profit as a percentage of revenue
 
31.9
%
 
35.6
%
 
 

 
 

General and administrative expense
 
17,353

 
17,424

 
(71
)
 
(0.4
)%
General and administrative expense as a percentage of revenue
 
14.3
%
 
15.9
%
 
 

 
 

Interest (income) expense, net
 
469

 
25

 
444

 
 

Other (income) expense, net
 
704

 
944

 
(239
)
 
 

Income before taxes and discontinued operations
 
$
20,200

 
$
20,598

 
$
(399
)
 
(1.9
)%
Income before taxes and discontinued operations as a percentage of revenue
 
16.7
%
 
18.8
%
 
 

 
 

 
The increase in Compressco segment revenues compared to the prior year was due to an increase of $9.9 million of service revenues, resulting primarily from increased activity in the U.S., Canada, and Argentina. The increase in the U.S. reflects the increased demand for unconventional compression services applications as a result of increased activity primarily in horizontal resource play reservoirs. These increases were partially offset by decreased revenues in Mexico. As a result of the budget re-evaluations by Compressco's primary customer in Mexico, in March 2013 Compressco began to experience a decline in demand for its oil and gas services in the northern region of Mexico. We believe this decline in demand is temporary. Compressco has continued to increase its compressor fleet, both in the U.S. and in certain foreign markets, to serve increasing demand. Revenues from the sales of compressor packages and parts during 2013 increased $2.0 million compared to the prior year.
 
Compressco segment gross profit decreased slightly during 2013 compared to the prior year, as the increased U.S., Canada, and Argentina revenues were largely offset by increased operating expenses, particularly labor, maintenance, and fuel costs. Gross profit as a percentage of revenue decreased compared to the prior year as a result of these cost increases. Primarily as a result of the current reduced activity in Mexico described above, Compressco has aggressively reduced its Mexico operating headcount and relocated certain equipment to the U.S. from Mexico.
 
Income before taxes for the Compressco segment decreased during 2013 compared to the prior year, primarily due to the increased interest expense as a result of the increased borrowings under the Compressco Partners bank credit facilities during the current year. The Compressco segment’s administrative expense levels also increased slightly compared to the prior year, as decreases in salaries and other employee related costs were largely offset by increased allocated costs and professional services. These increases were partially offset by decreased other expense, largely due to decreased foreign currency losses compared to the prior year.
 

38


Offshore Division
 
Offshore Services Segment
 
 
Year Ended
December 31,
 
Period to Period Change
 
 
2013
 
2012
 
2013 vs 2012
 
% Change
 
 
(In Thousands, Except Percentages)
Revenues
 
$
255,812

 
$
265,943

 
$
(10,131
)
 
(3.8
)%
Gross profit
 
36,147

 
33,272

 
2,875

 
8.6
 %
Gross profit as a percentage of revenue
 
14.1
%
 
12.5
%
 
 

 
 

General and administrative expense
 
13,386

 
17,494

 
(4,108
)
 
(23.5
)%
General and administrative expense as a percentage of revenue
 
5.2
%
 
6.6
%
 
 

 
 

Interest (income) expense, net
 
109

 
109

 
—

 
 

Other (income) expense, net
 
(218
)
 
(6,037
)
 
5,819

 
 

Income before taxes and discontinued operations
 
$
22,870

 
$
21,706

 
$
1,164

 
5.4
 %
Income before taxes and discontinued operations as a percentage of revenue
 
8.9
%
 
8.2
%
 
 

 
 


Revenues from our Offshore Services segment decreased during 2013 compared to 2012, primarily due to decreased activity levels in the Gulf of Mexico market for its heavy lift and cutting services businesses. Decreased demand for heavy lift services resulted in the idling of one of the segment's heavy lift barges during 2012. This barge remained idle during 2013 and was sold in January 2014. These businesses were also negatively affected by weather delays during 2013, including unseasonal weather delays during the second and third quarters, which affected utilization of key assets. Activity levels for the dive service business, however, increased during 2013 compared to the prior year due to increased demand for the segment's leased dive service vessels, particularly during the third quarter of 2013. Offshore Services revenues during the year ended December 31, 2013 and 2012 include approximately $50.1 million and $41.2 million, respectively, of revenues related to work performed for Maritech. The level of such Maritech work is expected to significantly decrease beginning in 2014.
 
Despite the decrease in revenues for the Offshore Services segment during 2013, gross profit increased compared to prior year. Gross profit as a percentage of revenues rose to 14.1% during the current year compared to 12.5% during the prior year. This increased profitability primarily reflects the impact of cost reduction efforts made during late 2012 and the second quarter of 2013. As a result of these cost reduction efforts, profitability for the segment has increased despite market conditions that continue to be challenging, including the impact of increased competition and decreased pricing compared to the prior year. In addition, the impact of weather delays during a portion of the current year negatively affected profitability. The Offshore Services segment continues to consider additional opportunities to optimize its cost structure.
 
Offshore Services segment income before taxes increased, primarily due to the increased gross profit discussed above and despite decreased other income. Other income decreased due to a $5.6 million gain on sale of certain abandonment assets recorded during the prior year. Offshore Services segment administrative costs decreased, primarily as a result of the segment’s cost reduction efforts, which reduced salary and personnel-related expenses, and more than offset approximately $0.3 million of severance costs expensed during 2013.


39


Maritech Segment
 
 
Year Ended
December 31,
 
Period to Period Change
 
 
2013
 
2012
 
2013 vs 2012
 
% Change
 
 
(In Thousands, Except Percentages)
Revenues
 
$
5,560

 
$
6,158

 
$
(598
)
 
(9.7
)%
Gross profit (loss)
 
(66,828
)
 
(39,397
)
 
(27,431
)
 
(69.6
)%
General and administrative expense
 
2,902

 
2,875

 
27

 
0.9
 %
General and administrative expense as a percentage of revenue
 
52.2
%
 
46.7
%
 
 

 
 

Interest (income) expense, net
 
11

 
98

 
(87
)
 
 

(Gain) loss on sales of assets
 
(5,378
)
 
420

 
(5,798
)
 
 

Other (income) expense, net
 
—

 
—

 
—

 
 

Income (loss) before taxes and discontinued operations
 
$
(64,363
)
 
$
(42,790
)
 
$
(21,573
)
 
(50.4
)%
 
As a result of the sale of almost all of its producing properties during 2011 and 2012, Maritech revenues during 2013 and 2012 were negligible and are expected to continue to be negligible going forward.
 
Maritech gross loss increased during 2013 due to approximately $75.3 million of excess decommissioning costs expensed during the current year, an increase of approximately $34.5 million compared to 2012. Revisions in estimated decommissioning liability cash flows during 2013 resulted primarily from additional work incurred and anticipated to be required on Maritech’s offshore oil and gas properties, including remediation work required on certain wells that had been previously plugged. Partially offsetting the increased costs, approximately $5.7 million of insurance settlements primarily associated with an insurance-related litigation settlement was credited to operating expenses during the first quarter of 2013.
 
The increase in Maritech’s pretax loss during 2013 compared to 2012 is primarily due to the increased gross loss discussed above. General and administrative expenses were consistent with the prior year despite approximately $0.2 million of increased professional fees primarily associated with the insurance-related litigation settlement received during the first quarter of 2013. Other income increased significantly during the current year, due to the approximately $5.4 million gain recognized on the sale of one of Maritech's remaining offshore oil and gas properties during 2013.

Corporate Overhead
 
 
Year Ended
December 31,
 
Period to Period Change
 
 
2013
 
2012
 
2013 vs 2012
 
% Change
 
 
(In Thousands, Except Percentages)
Gross profit (loss) (primarily depreciation expense)
 
$
(2,327
)
 
$
(2,949
)
 
$
622

 
21.1
 %
General and administrative expense
 
40,506

 
40,005

 
501

 
1.3
 %
Interest (income) expense, net
 
16,715

 
16,837

 
(122
)
 
 

Other (income) expense, net
 
2,711

 
2,217

 
494

 
 

(Loss) before taxes and discontinued operations
 
$
(62,259
)
 
$
(62,008
)
 
$
(251
)
 
(0.4
)%
 
Corporate Overhead increased during 2013 compared to the 2012, primarily due to increased corporate general and administrative expenses, which increased primarily due to approximately $2.6 million of increased office expense. The increased office expense was primarily rent, which resulted from the sale and leaseback of our corporate headquarters building in the fourth quarter of 2012. These increases were partially offset by approximately $1.6 million of decreased personnel-related expenses, $0.2 million of decreased professional expenses, and $0.4 million of increased allocations. The decreased personnel-related expenses were primarily as a result of second quarter 2013 cost reduction efforts and more than offset approximately $0.5 million of associated severance costs incurred during that period. Depreciation expense decreased compared to the prior year due to the sale and leaseback of our corporate headquarters building discussed above.


40


2012 Compared to 2011
 
Consolidated Comparisons
 
 
Year Ended
December 31,
 
Period to Period Change
 
 
2012
 
2011
 
2012 vs 2011
 
% Change
 
 
(In Thousands, Except Percentages)
Revenues
 
$
880,831

 
$
845,275

 
$
35,556

 
4.2
%
Gross profit
 
167,380

 
89,042

 
78,338

 
88.0
%
Gross profit as a percentage of revenue
 
19.0
%
 
10.5
%
 
 

 
 

General and administrative expense
 
131,649

 
111,805

 
19,844

 
17.7
%
General and administrative expense as a percentage of revenue
 
14.9
%
 
13.2
%
 
 

 
 

Interest expense, net
 
17,080

 
16,439

 
641

 
3.9
%
(Gain) loss on sale of assets
 
(4,916
)
 
(58,674
)
 
53,758

 
 

Other (income) expense, net
 
(4,616
)
 
13,239

 
(17,855
)
 
 

Income before taxes and discontinued operations
 
28,183

 
6,233

 
21,950

 
352.2
%
Income before taxes and discontinued operations as a percentage of revenue
 
3.2
%
 
0.7
%
 
 

 
 

Provision for income taxes
 
9,429

 
751

 
8,678

 
1,155.5
%
Income before discontinued operations
 
18,754

 
5,482

 
13,272

 
242.1
%
Income (loss) from discontinued operations, net of taxes
 
3

 
(64
)
 
67

 
 

Net income
 
18,757

 
5,418

 
13,339

 
246.2
%
Net income attributable to noncontrolling interest
 
(2,797
)
 
(1,271
)
 
(1,526
)
 
 

Net income attributable to TETRA stockholders
 
$
15,960

 
$
4,147

 
$
11,813

 
284.9
%
 
Consolidated revenues during 2012 increased compared to 2011 due to the growth and increased activity for many of our businesses, including unprecedented revenue levels for our Fluids, Production Testing, and Compressco segments. In particular, the acquisitions of OPTIMA, ERS, and Greywolf contributed $62.2 million of increased revenues for our Production Testing segment during 2012, along with $20.7 million of increased gross profit. In addition, our Production Testing segment also reported increased revenues compared to 2011 due to increased domestic drilling activity, particularly in certain of the shale reservoir markets it serves. Our Fluids segment’s revenue and gross profit growth was also due to increased industry activity, which resulted in increased CBF product sales, and more than offset the decreased product sales by the segment’s manufactured products businesses. Compressco also reported increased revenues and gross profit, primarily due to increased activity and demand in Latin America. These increased revenues more than offset the $76.6 million decrease in Maritech revenues due to the sales of substantially all of its oil and gas producing properties during 2011 and early 2012. In addition, Offshore Services revenues from third party customers as a result of the 2011 purchase of a heavy lift barge were largely offset by decreased diving and well abandonment services revenue, and the segment’s gross profit decreased primarily due to decreased diving and cutting services profitability. Overall gross profit increased, however, primarily due to significant impairments and excess decommissioning costs recorded by Maritech during 2011, the aforementioned acquisitions, and the increased profitability of our Fluids, Production Testing, and Compressco segments during 2012.
 
Consolidated general and administrative expenses increased during 2012 compared to 2011 by $19.9 million, primarily due to approximately $14.8 million of increased salaries, benefits, and other employee related costs, partially due to increased headcount as a result of acquisitions as well as due to increased equity compensation. In addition, general and administrative expenses also increased due to approximately $4.5 million of increased professional fee expenses, approximately $1.3 million of increased office expenses, and approximately $0.3 million of increased insurance and taxes expense. These increases in consolidated general and administrative expenses were partially offset by a decrease of approximately $1.0 million of other general expenses, including decreased provision for doubtful accounts. The increased professional fee expenses included approximately $2.8 million of acquisition transaction costs.
Consolidated net interest expense increased by $0.6 million during 2012 compared to 2011. This increase is due to increased borrowings during 2012.

41


 
During 2011, Maritech recorded gains on sales of its oil and gas properties, including approximately $58.2 million from a sale of approximately 79% of its oil and gas producing properties during the second quarter of 2011. Gains on sales of assets during 2012 consist primarily of the $5.6 million of gains recorded by our Offshore Services segment for the sale of our electric wireline assets during the fourth quarter of 2012 and the sale of certain abandonment assets during the first quarter of 2012. Consolidated other income increased during 2012 compared to 2011, primarily due to $14.2 million of hedge ineffectiveness losses recorded during 2011. Consolidated other income also includes increased earnings during 2012 compared to 2011 from TETRA Arabia, an unconsolidated limited liability company.

Our provision for income taxes increased during 2012 compared to 2011 due to increased net earnings.

Divisional Comparisons
 
Fluids Division
 
 
Year Ended
December 31,
 
Period to Period Change
 
 
2012
 
2011
 
2012 vs 2011
 
% Change
 
 
(In Thousands, Except Percentages)
Revenues
 
$
334,548

 
$
304,536

 
$
30,012

 
9.9
%
Gross profit
 
79,454

 
57,470

 
21,984

 
38.3
%
Gross profit as a percentage of revenue
 
23.7
%
 
18.9
%
 
 

 
 

General and administrative expense
 
30,466

 
26,586

 
3,880

 
14.6
%
General and administrative expense as a percentage of revenue
 
9.1
%
 
8.7
%
 
 

 
 

Interest (income) expense, net
 
54

 
14

 
40

 
 

Other (income) expense, net
 
(1,896
)
 
(1,206
)
 
(690
)
 
 

Income before taxes and discontinued operations
 
$
50,830

 
$
32,076

 
$
18,754

 
58.5
%
Income before taxes and discontinued operations as a percentage of revenue
 
15.2
%
 
10.5
%
 
 

 
 

 
The increase in Fluids Division revenues during 2012 compared to 2011 was primarily due to a $28.1 million net increase in product sales revenues. This increase was due to approximately $40.7 million of increased clear brine fluids (CBFs) product sales revenues, primarily due to increased domestic offshore well completion activity. This increase in domestic demand is due to increased activity in the deepwater Gulf of Mexico, as activity levels in late 2012 have returned to the pre-Macondo levels of early 2010. In addition, increased activity in our Eastern Hemisphere markets have also contributed, particularly in the North Sea, West Africa, and the Middle East regions. The increase in CBF sales was partially offset by approximately $12.5 million of decreased revenue from manufactured products, primarily from decreased industrial demand due to weather, increased competition, and due to the reduced sales of dry calcium chloride following the shutdown of the pellet plant at our Lake Charles facility during mid-2011. In addition to the net increase in product sales revenues, the Division also reported a $1.8 million increase in services revenues during 2012 due to increased domestic water management service activity in certain of the Division’s shale reservoir markets compared to 2011. However, the growth in domestic onshore service revenues has slowed compared to prior years.

Fluids Division gross profit increased during 2012 compared to 2011 primarily as a result of the increased domestic CBF revenues discussed above and from increased efficiency at our El Dorado, Arkansas, calcium chloride plant. Gross profit from the Division’s domestic onshore water management services operation also increased. These increases were partially offset by decreased gross profit from the Division’s European manufactured products operation, which was impacted by the decreased demand discussed above. In addition, the Division’s European calcium chloride plant experienced reduced production levels and higher costs during 2012 associated with equipment repairs at its calcium chloride plant.

Fluids Division income before taxes increased during 2012 compared to 2011 due to the increase in gross profit discussed above and increased other income, despite increased administrative costs. Other income increased primarily due to increased income from TETRA Arabia, our unconsolidated limited liability company, and foreign

42


currency exchange gains. Fluids Division administrative costs increased, primarily due to increased salaries, benefits, and personnel-related costs.

Production Enhancement Division
 
Production Testing Segment
 
 
Year Ended
December 31,
 
Period to Period Change
 
 
2012
 
2011
 
2012 vs 2011
 
% Change
 
 
(In Thousands, Except Percentages)
Revenues
 
$
207,984

 
$
139,756

 
$
68,228

 
48.8
%
Gross profit
 
58,009

 
46,889

 
11,120

 
23.7
%
Gross profit as a percentage of revenue
 
27.9
%
 
33.6
%
 
 

 
 

General and administrative expense
 
23,386

 
13,809

 
9,577

 
69.4
%
General and administrative expense as a percentage of revenue
 
11.2
%
 
9.9
%
 
 

 
 

Interest (income) expense, net
 
(43
)
 
(59
)
 
16

 
 

Other (income) expense, net
 
(5,181
)
 
(2,830
)
 
(2,351
)
 
 

Income before taxes and discontinued operations
 
$
39,847

 
$
35,969

 
$
3,878

 
10.8
%
Income before taxes and discontinued operations as a percentage of revenue
 
19.2
%
 
25.7
%
 
 

 
 


Production Testing revenues increased significantly during 2012, primarily due to an increase of approximately $62.2 million resulting from the acquisitions of OPTIMA, ERS, and Greywolf during 2012. These acquisitions have resulted in the Production Testing segment increasing its scope of services and expanding its operations into strategic geographic markets. In addition, during 2012 the segment reflected revenues from increased domestic drilling in many of its shale reservoir markets compared to 2011. These increases, along with increased revenues from the segment’s Eastern Hemisphere operations, were partially offset by decreased revenues in Mexico, where demand for certain of the segment’s production testing services has decreased and been more than offset, on a consolidated basis, by increased demand for well monitoring services by our Compressco segment.

Production Testing segment gross profit increased in 2012 compared to 2011, primarily due to approximately $20.7 million of increased gross profit from the acquisitions discussed above. Excluding the increased gross profit from these acquisitions, the impact from increased domestic activity was more than offset by increased operating expenses. In addition, gross profit from the segment’s international operations decreased during 2012 compared to 2011 as a result of the decreased production testing activity in Mexico.

Production Testing income before taxes increased due to the increased gross profit discussed above, as well as due to increased other income, which was primarily due to increased earnings from TETRA Arabia, our unconsolidated limited liability company. The increases in gross profit and other income were partially offset by increased administrative expenses resulting from higher personnel-related costs associated with the acquisitions, as well as approximately $2.8 million of acquisition transaction costs expensed during 2012.
 

43


Compressco Segment
 
 
Year Ended
December 31,
 
Period to Period Change
 
 
2012
 
2011
 
2012 vs 2011
 
% Change
 
 
(In Thousands, Except Percentages)
Revenues
 
$
109,466

 
$
95,768

 
$
13,698

 
14.3
%
Gross profit
 
38,991

 
29,567

 
9,424

 
31.9
%
Gross profit as a percentage of revenue
 
35.6
%
 
30.9
%
 
 

 
 

General and administrative expense
 
17,424

 
12,852

 
4,572

 
35.6
%
General and administrative expense as a percentage of revenue
 
15.9
%
 
13.4
%
 
 

 
 

Interest (income) expense, net
 
25

 
(67
)
 
92

 
 

Other (income) expense, net
 
944

 
983

 
(39
)
 
 

Income before taxes and discontinued operations
 
$
20,598

 
$
15,799

 
$
4,799

 
30.4
%
Income before taxes and discontinued operations as a percentage of revenue
 
18.8
%
 
16.5
%
 
 

 
 

 
The increase in Compressco revenues during 2012 compared to 2011 was primarily due to an increase of $20.6 million of service revenues resulting from increased activity, particularly in Latin America. While there are uncertainties in Latin America that could affect operations, including the renewal of certain customer contracts, we expect revenues from our Latin American operations will continue to increase. Partially offsetting this increase was a $6.9 million decrease from sales of compressor packages and parts during 2012 compared to the prior year.

Compressco gross profit increased during 2012 compared to 2011, primarily due to the increased Latin America activity discussed above, an increase in overall average compressor package utilization from 77.4% to 83.0%, and also due to continuing reductions in domestic operating expenses.

Income before taxes for Compressco increased during 2012 compared to 2011 due to the increased gross profit discussed above and despite increased administrative expenses. Compressco’s administrative expenses reflect increased administrative staff and professional fee expenses associated with being a separate publicly traded limited partnership. Administrative expenses during 2012 also reflect increased equity compensation expense arising from current year equity grants by Compressco Partners and the impact of a severance agreement. Additionally, incentive compensation expense increased as a result of favorable overall financial results. Beginning in June 2011, general and administrative expense also includes the allocation of a portion of our corporate administrative expenses to Compressco Partners pursuant to our Omnibus Agreement with Compressco Partners.

Offshore Division
 
Offshore Services Segment
 
 
Year Ended
December 31,
 
Period to Period Change
 
 
2012
 
2011
 
2012 vs 2011
 
% Change
 
 
(In Thousands, Except Percentages)
Revenues
 
$
265,943

 
$
287,300

 
$
(21,357
)
 
(7.4
)%
Gross profit
 
33,272

 
33,394

 
(122
)
 
(0.4
)%
Gross profit as a percentage of revenue
 
12.5
%
 
11.6
%
 
 

 
 

General and administrative expense
 
17,494

 
15,970

 
1,524

 
9.5
 %
General and administrative expense as a percentage of revenue
 
6.6
%
 
5.6
%
 
 

 
 

Interest (income) expense, net
 
109

 
45

 
64

 
 

Other (income) expense, net
 
(6,037
)
 
(1,076
)
 
(4,961
)
 
 

Income before taxes and discontinued operations
 
$
21,706

 
$
18,455

 
$
3,251

 
17.6
 %
Income before taxes and discontinued operations as a percentage of revenue
 
8.2
%
 
6.4
%
 
 

 
 


44


 
Revenues from our Offshore Services segment decreased in 2012 compared to 2011, primarily due to a decrease in the work performed for Maritech during 2012. Increased decommissioning services revenues, including those from the TETRA Hedron heavy lift barge purchased during 2011, were offset by
decreased diving, abandonment, and cutting services revenues during 2012. In addition to the continuing challenges of pricing pressures, reduced activity levels, reduced number of leased vessels, and project delays experienced by several of the Offshore Services segment’s customers, the segment also experienced weather disruptions during 2012, particularly from Tropical Storm Debby and Hurricane Isaac. Diving services revenues were also negatively affected by scheduled vessel repairs during the first quarter of 2012. In addition, revenues decreased due to the 2011 and early 2012 sales of certain of the segment’s onshore abandonment assets and operations, which generated approximately $13.7 million in revenues during 2011. In December 2012, the segment also disposed of its wireline assets, which generated $4.0 million and $1.7 million of revenues during 2011 and 2012, respectively. Approximately $41.2 million of Offshore Services revenues were from work performed for Maritech during 2012, compared to $65.0 million of such work in 2011 Intercompany revenues from Maritech work are eliminated in consolidation.
 
Gross profit for the Offshore Services segment during 2012 slightly decreased compared to 2011, despite approximately $6.2 million of due diligence and startup costs during 2011 associated with the purchase of the TETRA Hedron. Gross profit decreased primarily due to decreased profitability of our diving and cutting services operations, which largely resulted from decreased utilization and pricing during 2012. In the fourth quarter of 2012, we reclassified the TETRA DB-1 derrick barge as an asset held for sale and recorded a $7.7 million impairment on the asset. The segment also identified other asset impairments of approximately $0.7 million. The decreased profitability of our diving and cutting operations was partially offset by improved profitability of our heavy lift and abandonment operations. In addition to the impact of ongoing cost reductions that began during 2012, the Offshore Services segment expects increased profitability during 2013 as a result of increased bid activity and an observed decrease in Gulf of Mexico federal permitting delays.
 
Offshore Services segment income before taxes increased during 2012, despite the reduced gross profit discussed above and increased general and administrative expenses. These decreases were more than offset by the gains on the sale of certain abandonment and wireline assets that generated approximately $5.6 million of other income during 2012. Offshore Services segment administrative expenses increased during 2012, primarily due to increased salary and employee related expenses and increased bad debt and professional fee expenses during the year.

Maritech Segment
 
 
Year Ended
December 31,
 
Period to Period Change
 
 
2012
 
2011
 
2012 vs 2011
 
% Change
 
 
(In Thousands, Except Percentages)
Revenues
 
$
6,158

 
$
82,740

 
$
(76,582
)
 
(92.6
)%
Gross profit (loss)
 
(39,397
)
 
(75,762
)
 
36,365

 
48.0
 %
General and administrative expense
 
2,875

 
5,893

 
(3,018
)
 
(51.2
)%
General and administrative expense as a percentage of revenue
 
46.7
%
 
7.1
%
 
 

 
 

Interest (income) expense, net
 
98

 
73

 
25

 
 

(Gain) loss on sales of assets
 
420

 
(55,454
)
 
55,874

 
 

Other (income) expense, net
 
—

 
1

 
(1
)
 
 

Income (loss) before taxes and discontinued operations
 
$
(42,790
)
 
$
(26,275
)
 
$
(16,515
)
 
(62.9
)%
 
Maritech revenues decreased significantly during 2012 compared to 2011 due to the sales of substantially all of its oil and gas reserves during 2011 and early 2012. In particular, the May 31, 2011, sale of oil and gas properties resulted in the sale of approximately 79% of Maritech’s proven reserves. Following the sales of almost all of its producing properties, Maritech revenues are expected to continue to be negligible.

Maritech gross loss decreased during 2012 compared to 2011, primarily due to reduced operating and depletion expenses associated with the sold properties. In addition, Maritech recorded $15.2 million of impairments

45


and approximately $37.6 million of higher excess decommissioning costs associated with Maritech’s remaining decommissioning liabilities during 2011. Subsequent to December 31, 2012, in February 2013, Maritech entered into a $7.6 million settlement agreement with one of its underwriters relating to litigation involving its insurance claim following Hurricane Ike.
 
Maritech reported an increased pretax loss during 2012 compared to 2011, primarily due to approximately $55.5 million ($57.5 million consolidated) of gains from sales of producing properties reported during 2011. This decrease compared to 2011 was partially offset by the decreased gross loss discussed above. In addition, Maritech reported decreased net administrative expenses during 2012, primarily due to the reduction in its headcount following the sale of properties. This decrease in administrative costs was partially offset by increased legal expenses and decreased administrative costs billed to joint owners.

Corporate Overhead
 
 
Year Ended
December 31,
 
Period to Period Change
 
 
2012
 
2011
 
2012 vs 2011
 
% Change
 
 
(In Thousands, Except Percentages)
Gross profit (loss) (primarily depreciation expense)
 
$
(2,949
)
 
$
(2,626
)
 
$
(323
)
 
(12.3
)%
General and administrative expense
 
40,005

 
36,694

 
3,311

 
9.0
 %
Interest (income) expense, net
 
16,837

 
16,434

 
403

 
 

Other (income) expense, net
 
2,217

 
15,839

 
(13,622
)
 
 

(Loss) before taxes and discontinued operations
 
$
(62,008
)
 
$
(71,593
)
 
$
9,585

 
13.4
 %
 
Corporate Overhead includes corporate general and administrative expense, interest income and expense, and other income and expense. Such expenses and income are not allocated to our operating divisions, as they relate to our general corporate activities. However, in connection with the public offering of common units in our Compressco Partners subsidiary, on June 20, 2011, we began allocating and charging Compressco Partners for its share of our corporate administrative costs directly related to Compressco Partners’ activities. Corporate Overhead decreased during 2012 compared to 2011, primarily due to a $13.9 million hedge ineffectiveness loss during 2011. This hedge ineffectiveness loss was mainly due to the April 2011 liquidation of hedge derivative contracts, following the planned sale of a significant portion of Maritech oil and gas producing properties, which resulted in a $14.2 million charge to corporate other expense for hedge ineffectiveness during the second quarter of 2011. Corporate general and administrative expenses increased, largely due to approximately $3.1 million of increased employee related expenses, primarily due to $2.4 million of increased salaries and equity compensation, which includes the impact of severance costs associated with our previous chief financial officer. In addition, professional fee expenses increased approximately $0.4 million and office and insurance expenses increased by approximately $0.4 million. These increases were partially offset by approximately $0.6 million of decreased tax expenses. Corporate interest expense also increased, due to increased borrowings outstanding during much of 2012. In December 2012, we completed the sale of our corporate headquarters building for approximately $43.8 million, before transaction costs and other deductions, and entered into a lease of the facility with a minimum lease term of 15 years. As a result, beginning in 2013, Corporate Overhead will reflect the decreased depreciation expense associated with the sale, and general and administrative expense will reflect an increase for the lease expense going forward.


46


Liquidity and Capital Resources
 
Increased operating cash flows during 2013 compared to 2012 reflect the impact of strategic initiatives to reduce costs and streamline our customer billing and collection processes. Cost reduction efforts taken during the second quarter of 2013 and late 2012 resulted in improved profitability and cash flows for each of our segments. The increased operating cash flows have allowed us to continue to aggressively pursue extinguishing Maritech's remaining decommissioning liabilities, fund capital expenditure activity, and further strengthen our balance sheet. As of December 31, 2013, and after expending approximately $114.1 million during 2013 on decommissioning and associated work, Maritech's remaining decommissioning liabilities have been reduced to approximately $43.3 million. A large amount of the remaining work to be performed is expected to be performed during 2014. With the remaining amount of Maritech decommissioning work expected to decrease significantly, we anticipate the resulting increase in operating cash flows beginning in 2014 will provide significant opportunities to continue to strengthen our balance sheet and strategically grow our company. Through December 31, 2013, we spent an aggregate of approximately $101.4 million on capital expenditure activity for several of our existing businesses. In addition to the ongoing capital expenditure activity, we continue to evaluate opportunities to further expand certain of our businesses through acquisitions, consistent with our growth plan. During January 2014, we expended approximately $30.2 million in connection with two acquisitions: the purchase of the assets and operations of TD Water Transfer, a water management business operating primarily in South Texas, and the purchase of the remaining ownership interest in our Saudi Arabian limited liability company. In addition to available cash, as of February 28, 2014, we have approximately $210.4 million available under our revolving credit facility to fund our future strategic growth.
Operating Activities
 
Cash flows generated by operating activities totaled $49.7 million during 2013 compared to $17.7 million of cash provided by operating activities during 2012, an increase of $32.0 million. This increase in operating cash flows during 2013 compared to the prior year was largely due to an improvement of approximately $45.4 million from the collection of accounts receivable, reflecting a continuing effort begun during late 2012 to expedite collections. This increase in cash provided by operating activities was generated despite approximately $114.1 million of decommissioning activity performed during the year ended December 31, 2013, an increase of $19.7 million compared to 2012. A portion of the decommissioning activity performed during 2013 was associated with approximately $75.3 million of excess decommissioning costs charged to earnings during the year.
 
During the past three years, Maritech has performed approximately $310.4 million of well abandonment and decommissioning work associated with its remaining offshore oil and gas production wells, platforms, and facilities. As of December 31, 2013, and including the impact of adjustments made during 2013 for the estimated cost of work remaining to be performed, Maritech’s decommissioning liabilities totaled approximately $43.3 million. Until the remaining decommissioning liabilities are extinguished, our future operating cash flows will continue to be affected by the actual timing and amount of Maritech’s decommissioning expenditures. Most of the cash outflow necessary to extinguish Maritech’s remaining decommissioning liabilities is expected to occur during 2014. Included in Maritech’s decommissioning liabilities is the remaining abandonment, decommissioning, and debris removal associated with offshore platforms that were previously destroyed by a hurricane, as well as certain remediation work required on wells that were previously plugged. Due to the unique nature of the remaining work to be performed associated with these properties, actual costs could greatly exceed these estimates and could therefore result in significant charges to earnings in future periods.
 
In some cases, the previous owners of properties that were acquired by Maritech are contractually obligated to pay Maritech a fixed amount for the well abandonment and decommissioning work on these properties after the work is performed. Approximately $8.8 million of such contractual reimbursement arrangements as of December 31, 2013, is classified as receivable assets related to amounts waiting to be collected.
 
Demand for a large portion of our products and services is driven by oil and gas industry activity, which is affected by oil and natural gas commodity pricing. Oil and natural gas prices have been volatile in the past and are expected to continue to be volatile in the future. In addition, as a result of oil and natural gas commodity prices, drilling activity related to natural gas wells in North America has decreased. While only a portion of our revenues are related to gas drilling activity, we are exposed to the impact that this decreased demand could have on our businesses. In particular, our Production Testing, Compressco, and Fluids segments are vulnerable to the impact of a sustained low natural gas price environment. In addition, decreases in future worldwide crude oil prices could also

47


affect future overall industry drilling activity in certain of the regions in which we operate. If oil or gas industry activity levels decrease in the future, our levels of operating cash flows may be negatively affected.

During late 2012 and the first half of 2013, each of our segments implemented operating and administrative cost reductions, including reductions in headcount, that were designed to streamline our operations and downsize our organization, particularly in our corporate headquarters and in certain of our businesses. Together with the specific cost reduction steps taken by our Offshore Services segment in late 2012, these cost reduction efforts have resulted in increased operating cash flows and improved profitability, and the impact from these cost reduction efforts are expected to continue going forward. We continue to review our overall operating and administrative cost structure in order to identify additional opportunities to reduce costs.
 
We are subject to operating hazards normally associated with onshore and offshore oilfield service operations, including fires, explosions, blowouts, cratering, mechanical problems, abnormally pressured formations, and accidents that cause harm to the environment. In addition, in the performance of each of our operations we are exposed to additional hazards, including personal injuries and vehicle-related accidents. We maintain various types of insurance that are designed to be applicable in the event of an explosion or other catastrophic event involving our offshore operations. This insurance includes third-party liability, workers’ compensation and employers’ liability, automobile liability, general liability, and vessel pollution liability. Our insurance coverage is subject to deductibles that must be satisfied prior to recovery. Additionally, the levels of our insurance coverage are subject to certain exclusions and limitations and we have additional exposure from certain risks that we elect to self-insure. We believe our policy of insuring against such risks, as well as the levels of insurance we maintain, is typical in the industry. In addition, we provide services and products in the offshore Gulf of Mexico generally pursuant to agreements that create insurance and indemnity obligations for both parties. Our Maritech subsidiary maintains a formalized oil spill response plan that is submitted to the Bureau of Safety and Environmental Enforcement (BSEE). Maritech has designated third-party contractors in place to ensure that resources are available as required in the event of an environmental accident. While it is impossible to anticipate every potential accident or incident involving our offshore operations, we believe we have taken appropriate steps to mitigate the potential impact of such an event on the environment in the regions in which we operate.
Investing Activities
 
During 2013, the total amount of our net cash utilized on investing activities was $100.0 million. Total cash capital expenditures during 2013 were $101.4 million. Approximately $45.3 million of our capital expenditures during 2013 was spent by our Fluids Division, the majority of which related to the purchase of new equipment to support its onshore water management services business. Our Production Enhancement Division spent approximately $50.8 million on capital expenditures, consisting of approximately $26.8 million by the Production Testing segment to add or replace a portion of its production testing equipment fleet, and approximately $24.1 million by the Compressco segment, primarily for the upgrade and expansion of its wellhead compressor and equipment fleet. Our Offshore Services segment spent approximately $4.2 million for costs on its various heavy lift and dive support vessels. Corporate capital expenditures were approximately $1.1 million.

In January 2014, we completed two acquisition transactions. Pursuant to an October 2013 agreement, we acquired the remaining 50% ownership interest of TETRA Arabia in exchange for $15.0 million which was paid at closing and $10.2 million to be paid in July 2014. As a result of this transaction, beginning in the first quarter of 2014, TETRA Arabia has become a wholly owned consolidated subsidiary. Also in January 2014, we acquired the assets and operations of TD Water Transfer for a cash purchase price of $15.0 million along with additional contingent consideration of up to approximately $8.0 million to be paid based on a measure of earnings and other considerations over the two years subsequent to closing. TD Water Transfer is a provider of water management services to oil and gas operators in the South Texas and North Dakota regions, and the acquisition represents a strategic geographic expansion of our Fluids segment operations.

Generally, a significant majority of our planned capital expenditures is related to identified opportunities to grow and expand our existing businesses (other than Maritech). Although our planned level of capital expenditures during 2014 is subject to the impact of acquisitions and future market conditions, we currently plan to expend up to approximately $119 million on total capital expenditures (excluding acquisitions) during 2014. However, certain of these planned expenditures may be postponed or canceled in an effort to conserve capital or otherwise address future market or financing conditions. The deferral of capital projects could affect our ability to compete in the future.

48


To the extent we consummate an additional significant acquisition transaction or other capital project, our liquidity position and capital plans will be affected.

Financing Activities 
 
To fund our capital and working capital requirements, we may supplement our existing cash balances and cash flow from operating activities as needed from long-term borrowings, short-term borrowings, operating leases, equity issuances, and other sources of capital.
 
Our Bank Credit Facilities
 
We have a $278 million revolving credit facility with a syndicate of banks pursuant to a credit facility agreement (the Credit Agreement). As of December 31, 2013, we had an outstanding balance on the revolving credit facility of approximately $52.8 million and had $9.5 million in letters of credit and guarantees against the $278 million revolving credit facility, leaving a net availability of $215.7 million. As a result of borrowings made subsequent to December 31, 2013, availability under the revolving credit facility has decreased to approximately $210.4 million as of February 28, 2014. In addition, the Credit Agreement allows us to increase the facility by $150 million, up to a $428 million limit, upon the agreement of the lenders and the satisfaction of certain conditions. Included in the approximately $52.8 million outstanding borrowings under the credit facility agreement as of December 31, 2013 is approximately $13.8 million equivalent denominated in euros, which has been designated as a hedge of the net investment in our European operations.
 
Under the Credit Agreement, which matures on October 29, 2015, the revolving credit facility is unsecured and guaranteed by certain of our material U.S. subsidiaries (excluding Compressco). Borrowings generally bear interest at the British Bankers Association LIBOR rate plus 1.5% to 2.5%, depending on one of our financial ratios. We pay a commitment fee ranging from 0.225% to 0.500% on unused portions of the facility. The Credit Agreement contains customary covenants and other restrictions, including certain financial ratio covenants based on our levels of debt and interest cost compared to a defined measure of our operating cash flows over a twelve month period. In addition, the Credit Agreement includes limitations on aggregate asset sales, individual acquisitions, and aggregate annual acquisitions and capital expenditures. Access to our revolving credit line is dependent upon our compliance with the financial ratio covenants set forth in the Credit Agreement. These financial ratios include a minimum interest charge coverage ratio (ratio of a defined measure of earnings to interest) of 3.0 and a maximum leverage ratio (ratio of debt and letters of credit outstanding to a defined measure of earnings) of 3.0. Both of these financial ratios are defined in our revolving bank credit facility agreement. Deterioration of the financial ratios could result in a default by us under the Credit Agreement and, if not remedied, could result in termination of the Credit Agreement and acceleration of any outstanding balances. Compressco is an unrestricted subsidiary and is not a borrower or a guarantor under our bank credit facility.
The Credit Agreement includes cross-default provisions relating to any other indebtedness greater than a defined amount. If any such indebtedness is not paid or is accelerated and such event is not remedied in a timely manner, a default will occur under the Credit Agreement. Our Credit Agreement also contains a covenant that restricts us from paying dividends in the event of a default or if such payment would result in an event of default. We are in compliance with all covenants and conditions of our Credit Agreement as of December 31, 2013. Our continuing ability to comply with these financial covenants depends largely upon our ability to generate adequate cash flow. Historically, our financial performance has been more than adequate to meet these covenants, and we expect this trend to continue.
 
Our European Credit Agreement
 
We also have a bank line of credit agreement to cover the day to day working capital needs of certain of our European operations (the European Credit Agreement). The European Credit Agreement provides borrowing capacity of up to 5 million euros (approximately $6.9 million equivalent as of December 31, 2013), with interest computed on any outstanding borrowings at a rate equal to the lender’s Basis Rate plus 0.75%. The European Credit Agreement is cancellable by either party with 14 business days notice and contains standard provisions in the event of default. As of December 31, 2013, we had no borrowings outstanding pursuant to the European Credit Agreement.
 

49


Compressco Partners’ Bank Credit Facility
 
On June 24, 2011, Compressco Partners entered into a credit agreement (the Previous Partnership Credit Agreement) with JPMorgan Chase Bank, N.A. Under the Previous Partnership Credit Agreement, as amended, Compressco Partners, along with certain of its subsidiaries, were named as borrowers, and all of its existing and future, direct and indirect, domestic subsidiaries were guarantors. We were not a borrower or a guarantor under the Previous Partnership Credit Agreement. The Previous Partnership Credit Agreement, as amended, included a maximum credit commitment of $20.0 million, that was available for letters of credit (with a sublimit of $5.0 million), and included an uncommitted $20.0 million expansion feature.

On October 15, 2013, Compressco Partners entered into a new asset-based revolving credit facility with a syndicate of lenders including JPMorgan Chase Bank, N.A. as administrative agent (the New Partnership Credit Agreement), which replaced the Previous Partnership Credit Agreement. Under the New Partnership Credit Agreement, Compressco Partners, along with certain of its subsidiaries, are named as borrowers, and all obligations under the credit agreement are guaranteed by all of its existing and future, direct and indirect, domestic subsidiaries. We are not a borrower or a guarantor under the New Partnership Credit Agreement. The New Partnership Credit Agreement includes a maximum credit commitment of $100.0 million that is available for letters of credit (with a sublimit of $20.0 million), and includes an uncommitted $30.0 million expansion feature. The actual maximum credit availability under the New Partnership Credit Agreement varies from time to time and is determined by calculating the applicable borrowing base, which is based upon applicable percentages of the values of eligible accounts receivable, inventory, and equipment, minus reserves as determined necessary by the Administrative Agent. As of February 28, 2014, Compressco Partners has a balance outstanding under the New Partnership Credit Agreement of $30.0 million and had availability under the New Partnership Credit Facility of $36.8 million, based upon a $67.4 million borrowing base and the $30.0 million outstanding balance.
 
The New Partnership Credit Agreement may be used to fund Compressco Partners’ working capital needs, letters of credit, and for general partnership purposes, including the repayment of the outstanding balance of the Previous Partnership Credit Agreement, capital expenditures and potential future expansions or acquisitions. So long as Compressco Partners is not in default, the New Partnership Credit Agreement may also be used to fund Compressco Partners’ quarterly distributions at the option of the board of directors of the Partnership's general partner (provided, that after giving effect to such distributions, the borrowers will be in compliance with the financial covenants). The initial borrowings under the New Partnership Credit Agreement of $24.5 million were used to repay in full all amounts outstanding under the Previous Partnership Credit Agreement dated June 24, 2011. Borrowings under the New Partnership Credit Agreement are subject to the satisfaction of customary conditions, including the absence of a default. The maturity date of the New Partnership Credit Agreement is October 15, 2017.
  
Borrowings under the New Partnership Credit Agreement bear interest at a rate per annum equal to, at Compressco Partners' option, either (a)  LIBOR (adjusted to reflect any required bank reserves) for an interest period equal to one, two, three or six months (as selected by Compressco Partners) plus a margin of 2.25% per annum or (b) a base rate determined by reference to the highest of (1) the prime rate of interest per annum announced from time to time by JPMorgan Chase Bank, N.A. or (2) LIBOR (adjusted to reflect any required bank reserves) for a one-month interest period on such day, plus 2.50% per annum. In addition to paying interest on outstanding principal under the New Partnership Credit Agreement, Compressco Partners is required to pay a commitment fee, in respect of the unutilized commitments thereunder, of 0.375% per annum, paid quarterly in arrears. Compressco Partners is also required to pay a customary letter of credit fee equal to the applicable margin on revolving credit LIBOR loans and fronting fees.
 
The New Partnership Credit Agreement requires Compressco Partners to maintain a minimum interest coverage ratio (ratio of earnings before interest and taxes to interest) of 4.0 to 1.0 as of the last day of any fiscal quarter, calculated on a trailing four quarters basis. In addition, the New Partnership Credit Agreement includes customary negative covenants, which, among other things, limit Compressco Partners’ ability to incur additional debt, incur, or permit certain liens to exist, or make certain loans, investments, acquisitions, or other restricted payments. The New Partnership Credit Agreement provides that Compressco Partners can make distributions to holders of its common and subordinated units, but only if there is no default or event of default under the facility. Compressco Partners was in compliance with the covenants and conditions of the New Partnership Credit Agreement as of December 31, 2013.
 

50


Senior Notes
 
In April 2006, we issued $90.0 million in aggregate principal amount of Series 2006-A Senior Notes pursuant to our existing Master Note Purchase Agreement dated September 2004, as supplemented as of April 18, 2006. The Series 2006-A Senior Notes bear interest at a fixed rate of 5.90% and mature on April 30, 2016. Interest on the 2006-A Senior Notes is due semiannually on April 30 and October 30 of each year.
 
In April 2008, we issued $35.0 million in aggregate principal amount of Series 2008-A Senior Notes and $90.0 million in aggregate principal amount of Series 2008-B Senior Notes (collectively the Series 2008 Senior Notes) pursuant to a Note Purchase Agreement dated April 30, 2008. The Series 2008-A Senior Notes bore interest at a fixed rate of 6.30% and matured and were repaid on April 30, 2013. The Series 2008-B Senior Notes bear interest at a fixed rate of 6.56% and mature on April 30, 2015. Interest on the Series 2008 Senior Notes is due semiannually on April 30 and October 31 of each year.
 
In December 2010, we issued $65.0 million in aggregate principal amount of Series 2010-A Senior Notes and $25.0 million in aggregate principal amount of Series 2010-B Senior Notes (collectively, the 2010 Senior Notes) pursuant to a Note Purchase Agreement dated September 30, 2010. The Series 2010-A Senior Notes bear interest at a fixed rate of 5.09% and mature on December 15, 2017. The Series 2010-B Senior Notes bear interest at a fixed rate of 5.67% and mature on December 15, 2020. Interest on the Series 2010 Senior Notes is due semiannually on June 15 and December 15 of each year.

In April 2013, we issued $35.0 million in aggregate principal amount of Series 2013 Senior Notes pursuant to a Note Purchase Agreement. The Series 2013 Senior Notes bear interest at a fixed rate of 4.0% and mature on April 29, 2020. On April 30, 2013, we utilized the proceeds from the issuance to repay the 2008-A Senior Notes. Interest on the 2013 Senior Notes is due semiannually on April 29 and October 29 of each year.
 
Each of the Senior Notes was sold in the United States to accredited investors pursuant to an exemption from the Securities Act of 1933. We may prepay the Senior Notes, in whole or in part, at any time at a price equal to 100% of the principal amount outstanding, plus accrued and unpaid interest and a “make-whole” prepayment premium. The Senior Notes are unsecured and are guaranteed by substantially all of our wholly owned U.S. subsidiaries. The Note Purchase Agreements and the Master Note Purchase Agreement, as supplemented, contain customary covenants and restrictions and require us to maintain certain financial ratios, including a minimum level of net worth and a ratio between our long-term debt balance and a defined measure of operating cash flow over a twelve month period. The Note Purchase Agreements and the Master Note Purchase Agreement also contain customary default provisions as well as a cross-default provision relating to any other of our indebtedness of $20 million or more. We are in compliance with all covenants and conditions of the Note Purchase Agreements and the Master Note Purchase Agreement as of December 31, 2013. Upon the occurrence and during the continuation of an event of default under the Note Purchase Agreements and the Master Note Purchase Agreements, as supplemented, the Senior Notes may become immediately due and payable, either automatically or by declaration of holders of more than 50% in principal amount of the Senior Notes outstanding at the time.
 
Other Sources and Uses
 
In addition to the aforementioned revolving credit facilities, we fund our short-term liquidity requirements from cash generated by operations, other operating leases, and from short-term vendor financing. Should additional capital be required, we believe that we have the ability to raise such capital through the issuance of additional debt or equity. However, instability or volatility in the capital markets at the times we need to access capital may affect the cost of capital and the ability to raise capital for an indeterminable length of time. As discussed above, our Credit Agreement matures in October 2015, the New Partnership Credit Agreement matures in October 2017, and our Senior Notes mature at various dates between April 2015 and December 2020. The replacement of these capital sources at similar or more favorable terms is not certain. If it is necessary to issue equity to fund our capital needs, dilution to our common stockholders will occur.

Compressco Partners’ Partnership Agreement requires that within 45 days after the end of each quarter, it distribute all of its available cash, as defined in the Partnership Agreement, to its unitholders of record on the applicable record date. For the year ended December 31, 2013, net of distributions paid to us, Compressco Partners distributed approximately $4.8 million to its public unitholders. 


51


Off Balance Sheet Arrangements
 
An “off balance sheet arrangement” is defined as any contractual arrangement to which an entity that is not consolidated with us is a party, under which we have, or in the future may have:
•
any obligation under a guarantee contract that requires initial recognition and measurement under U.S. Generally Accepted Accounting Principles;
•
a retained or contingent interest in assets transferred to an unconsolidated entity or similar arrangement that serves as credit, liquidity, or market risk support to that entity for the transferred assets;
•
any obligation under certain derivative instruments; or
•
any obligation under a material variable interest held by us in an unconsolidated entity that provides financing, liquidity, market risk or credit risk support to us, or engages in leasing, hedging, or research and development services with us.
 
As of December 31, 2013 and 2012, we had no “off balance sheet arrangements” that may have a current or future material effect on our consolidated financial condition or results of operations. For a discussion of operating leases, including the lease of our corporate headquarters facility, see “Note E – Leases” in the Notes to Consolidated Financial Statements.

Commitments and Contingencies
 
Litigation
 
We are named defendants in several lawsuits and respondents in certain governmental proceedings arising in the ordinary course of business. While the outcome of lawsuits or other proceedings against us cannot be predicted with certainty, management does not consider it reasonably possible that a loss resulting from such lawsuits or other proceedings in excess of any amounts accrued has been incurred that is expected to have a material adverse impact on our financial condition, results of operations, or liquidity.
 
Environmental
 
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 future remediation costs and 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. While the outcome cannot be predicted with certainty, management does not consider it reasonably possible that a loss in excess of any amounts accrued has been incurred or is expected to have a material adverse impact on our financial condition, results of operations, or liquidity.
 
Product Purchase Obligations
 
In the normal course of our Fluids Division operations, we enter into supply agreements with certain manufacturers of various raw materials and finished products. Some of these agreements have terms and conditions that specify a minimum or maximum level of purchases over the term of the agreement. Other agreements require us to purchase the entire output of the raw material or finished product produced by the manufacturer. Our purchase obligations under these agreements apply only with regard to raw materials and finished products that meet specifications set forth in the agreements. We recognize a liability for the purchase of such products at the time we receive them. As of December 31, 2013, the aggregate amount of the fixed and determinable portion of the purchase obligation pursuant to our Fluids Division’s supply agreements was approximately $205.9 million, extending through 2029.

Other Contingencies
 
Related to its remaining oil and gas property decommissioning liabilities, our Maritech subsidiary estimates the third-party fair values (including an estimated profit) to plug and abandon wells, decommission the pipelines and

52


platforms, and clear the sites, and uses these estimates to record Maritech’s decommissioning liabilities, net of amounts allocable to joint interest owners.
 
Contractual Obligations
 
The table below summarizes our contractual cash obligations as of December 31, 2013:
 
 
Payments Due
 
 
Total
 
2014
 
2015
 
2016
 
2017
 
2018
 
Thereafter
 
 
(In Thousands)
Long-term debt
 
$
387,816

 
$
89

 
$
172,727

 
$
90,000

 
$
65,000

 
$
—

 
$
60,000

Interest on debt
 
60,190

 
21,417

 
16,750

 
7,872

 
5,990

 
2,818

 
5,343

Purchase obligations
 
205,900

 
14,275

 
14,275

 
14,275

 
14,275

 
12,400

 
136,400

Decommissioning and other asset retirement obligations(1)
 
50,904

 
38,700

 
4,677

 
—

 
—

 
—

 
7,527

Operating and capital leases
 
74,839

 
12,613

 
8,689

 
6,233

 
5,411

 
5,012

 
36,881

Total contractual cash obligations(2)
 
$
779,649

 
$
87,094

 
$
217,118

 
$
118,380

 
$
90,676

 
$
20,230

 
$
246,151

(1) 
We have estimated the timing of these payments for decommissioning liabilities based upon our plans and the plans of outside operators, which are subject to many changing variables, including the estimated life of the producing oil and gas properties, which is affected by changing oil and gas commodity prices. The amounts shown represent the undiscounted obligation as of December 31, 2013.
(2) 
Amounts exclude other long-term liabilities reflected in our Consolidated Balance Sheet that do not have known payment streams. These excluded amounts include approximately $4.1 million of liabilities under FASB Codification Topic 740, “Accounting for Uncertainty in Income Taxes,” as we are unable to reasonably estimate the ultimate amount or timing of settlements. See “Note F – Income Taxes,” in the Notes to Consolidated Financial Statements for further discussion.

New Accounting Pronouncements
 
In June 2011, the FASB published ASU 2011-05, “Comprehensive Income (Topic 220), Presentation of Comprehensive Income” (ASU 2011-05), with the stated objective of improving the comparability, consistency, and transparency of financial reporting and increasing the prominence of items reported in other comprehensive income. As part of ASU 2011-05, the FASB eliminated the option to present components of other comprehensive income as part of the statement of changes in stockholders’ equity. The ASU amendments require that all non-owner changes in stockholders’ equity be presented either in a single continuous statement of comprehensive income or in two separate but consecutive statements. The ASU amendments are effective for fiscal years, and interim periods within those years, beginning after December 15, 2011, and the amendments are applied retrospectively. In December 2011, with the issuance of ASU 2011-12, “Deferral of the Effective Date for Amendments to the Presentation of Reclassifications of Items Out of Accumulated Other Comprehensive Income in Accounting Standards Update No. 2011-05,” the FASB announced that it has deferred certain aspects of ASU 2011-05. In February 2013, the FASB issued ASU 2013-2, “Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income,” with the stated objective of improving the reporting of reclassifications out of accumulated other comprehensive income. The amendments in this ASU are effective during interim and annual periods beginning after December 15, 2012. The adoption of these ASUs regarding comprehensive income have not had a significant impact on the accounting or disclosures in our financial statements. 
 
In December 2011, the FASB published ASU 2011-11, “Balance Sheet (Topic 210), Disclosures about Offsetting Assets and Liabilities” (ASU 2011-11), which requires an entity to disclose the nature of its rights of setoff and related arrangements associated with its financial instruments and derivative instruments. The objective of ASU 2011-11 is to make financial statements that are prepared under U.S. generally accepted accounting principles more comparable to those prepared under International Financial Reporting Standards. The new disclosures will give financial statement users information about both gross and net exposures. In January 2013, the FASB published ASU 2013-01, “Balance Sheet (Topic 210), Clarifying the Scope of Disclosures about
Offsetting Assets and Liabilities” (ASU 2013-01), with the stated objective of clarifying the scope of offsetting disclosures and address any unintended consequences of ASU 2011-11. ASU 2011-11 and ASU 2013-01 are effective for interim and annual reporting period beginning after January 1, 2013 and will be applied on a retrospective basis. The adoption of ASU 2011-11 and ASU 2013-01 did not have a material impact on our financial condition, results of operations, or liquidity.

In July 2013, the FASB published ASU No. 2013-11, "Presentation of an Unrecognized Tax Benefit When a

53


Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists" (ASU 2013-11). The amendments in this ASU provide guidance on presentation of unrecognized tax benefits and are expected to reduce diversity in practice and better reflect the manner in which an entity would settle at the reporting date any additional income taxes that would result from the disallowance of a tax position when net operating loss carryforwards, similar tax losses, or tax credit carryforwards exist. The amendments in this ASU are effective prospectively for interim and annual periods beginning after December 15, 2013, with early adoption and retrospective application permitted. We do not expect the adoption of this standard to have a material impact on our consolidated financial statements.

Item 7A. Quantitative and Qualitative Disclosures about Market Risk.
 
Interest Rate Risk
 
During 2013, we borrowed $1.6 million, net of repayments, pursuant to our revolving credit facility. During 2013, Compressco Partners borrowed $19.9 million to fund the expansion and upgrade of its compressor and equipment fleet. Each of these borrowings was made under existing revolving credit facilities that bear interest at an agreed-upon percentage rate spread above LIBOR, and is therefore subject to market risk exposure related to changes in applicable interest rates.
 
The following table sets forth as of December 31, 2013, our principal cash flows for our long-term debt obligations (which bear a variable rate of interest) and weighted average effective interest rate by their expected maturity dates. We are not a party to an interest rate swap contract or other derivative instrument designed to hedge our exposure to interest rate fluctuation risk.
 
 
Expected Maturity Date
 
 
 
Fair
 
 
2014
 
2015
 
2016
 
2017
 
2018
 
Thereafter
 
Total
 
Market
Value
As of December 31, 2013
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Long-term debt:
 
 

 
 

 
 

 
 

 
 

 
 

 
 

 
 

U.S. dollar variable rate
 
$
—

 
$
68,959

 
$
—

 
$
—

 
$
—

 
$
—

 
$
68,959

 
$
68,959

Euro variable rate (in $US)
 
—

 
13,768

 
—

 
—

 
—

 
—

 
13,768

 
13,768

Weighted average interest rate (variable)
 
—

 
2.487
%
 
—

 
—

 
—

 
—

 
2.487
%
 
 

U.S. dollar fixed rate
 
$
89

 
$
90,000

 
$
90,000

 
$
65,000

 
$
—

 
$
60,000

 
$
305,089

 
$
313,730

Weighted average interest rate (fixed)
 
—

 
6.560
%
 
5.900
%
 
5.090
%
 
—

 
4.696
%
 
5.684
%
 
 

Variable to fixed swaps
 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

Fixed pay rate
 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

Variable receive rate
 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
Exchange Rate Risk
 
We are exposed to fluctuations between the U.S. dollar and the euro with regard to our euro-denominated operating activities. In July 2012, we designated the 10.0 million euro borrowing described above as a hedge for our euro-denominated operations.
 
The following table sets forth as of December 31, 2013, our cash flows for our long-term debt obligations, which are denominated in euros. This information is presented in U.S. dollar equivalents. The table presents principal cash flows and related weighted average interest rates by its expected maturity dates. As described above, we utilize the long-term borrowings detailed in the following table as a hedge of our investment in foreign operations.

54


 
 
Expected Maturity Date
 
 
 
Fair
 
 
2014
 
2015
 
2016
 
2017
 
2018
 
Thereafter
 
Total
 
Market
Value
As of December 31, 2013
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Long-term debt:
 
 

 
 

 
 

 
 

 
 

 
 

 
 

 
 

Euro variable rate (in $US)
 
$
—

 
$
13,768

 
$
—

 
$
—

 
$
—

 
$
—

 
$
13,768

 
$
13,768

Euro fixed rate (in $US)
 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

Weighted average interest rate
 
—

 
2.399
%
 
—

 
—

 
—

 
—

 
2.399
%
 
 
Variable to fixed swaps
 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

Fixed pay rate
 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

Variable receive rate
 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
We also have currency exchange rate risk exposure related to revenues, expenses, operating receivables, and payables denominated in foreign currencies. In October 2013, we and Compressco Partners began entering into 30-day foreign currency forward derivative contracts as part of a program designed to mitigate the currency exchange rate risk exposure on selected transactions of certain foreign subsidiaries. As of December 31, 2013, we and Compressco Partners had the following foreign currency derivative contracts outstanding relating to a portion of our foreign operations:
Derivative Contracts
 
US Dollar Notional Amount
 
Traded Exchange Rate
 
Value Date

 
(In Thousands)
 

 

Forward sale Mexican pesos
 
$
10,332

 
13.01
 
1/17/2014
Forward purchase Mexican pesos
 
5,928

 
13.01
 
1/17/2014
Forward purchase euros
 
7,984

 
1.38
 
1/17/2014
Forward purchase pounds sterling
 
3,149

 
1.63
 
1/17/2014

Under this program, we and Compressco Partners may enter into similar derivative contracts from time to time. Although contracts pursuant to this program will serve as an economic hedge of the cash flow of our currency exchange risk exposure, they will not be formally designated as hedge contracts or qualify for hedge accounting treatment. Accordingly, any change in the fair value of these derivative instruments during a period will be included in the determination of earnings for that period.

The fair value of foreign currency derivative instruments are based on quoted market values as reported to us by our counterparty. The fair values of our foreign currency derivative instruments as of December 31, 2013, are as follows:
Foreign currency derivative instruments
Balance Sheet Location
 
 Fair Value at
December 31, 2013

 

 
(In Thousands)
Forward purchase contracts
 
Current assets
 
$
72

Forward sale contracts
 
Current assets
 
32

Forward purchase contracts
 
Current liabilities
 
(52
)
Total
 

 
$
52


Based on the derivative contracts that were in place as of December 31, 2013, a five percent devaluation of the Mexican peso compared to the U.S. dollar would result in an increase in the market value of our forward sale contract of $0.3 million, and a decrease in the market value of our forward purchase contract of $0.5 million. A five percent devaluation of the euro compared to the U.S. dollar would result in a decrease in the market value of our forward purchase contract of $0.6 million. A 5% devaluation of the British pound sterling compared to the U.S. dollar would result in a decrease in the market value of our forward purchase contract of $0.3 million.


55


Commodity Price Risk
 
We will be exposed to the commodity price risk associated with Maritech’s oil and natural gas production that we will continue to own until it is sold. Due to the minimal amount of expected production following the sale, such commodity price risk exposure is not expected to be significant.

Item 8. Financial Statements and Supplementary Data.
 
Our financial statements and supplementary data for us and our subsidiaries required to be included in this Item 8 are set forth in Item 15 of this Report.

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.
 
None.

Item 9A. Controls and Procedures.
 
Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures
 
Under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, we conducted an evaluation of our disclosure controls and procedures, as such term is defined under Rule 13a-15(e) promulgated under the Securities Exchange Act of 1934, as amended (the Exchange Act). Based on this evaluation, the Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of December 31, 2013, the end of the period covered by this Annual Report.
 
Management’s Report on Internal Control over Financial Reporting
 
Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f). Under the supervision and with the participation of management, including our Chief Executive Officer and Chief Financial Officer, an evaluation of the effectiveness of our internal control over financial reporting was conducted based on the framework in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (1992 framework) (COSO). Based on that evaluation under the framework in Internal Control – Integrated Framework issued by the COSO, our management concluded that our internal control over financial reporting was effective as of December 31, 2013.
 
An assessment of the effectiveness of our internal control over financial reporting as of December 31, 2013, has been performed by Ernst & Young LLP, an independent registered public accounting firm, as stated in their report which is included herein.

Changes in Internal Control over Financial Reporting
 
There were no changes in our internal control over financial reporting during the fiscal quarter ending December 31, 2013, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. 

Item 9B. Other Information.
 
None.


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PART III

Item 10. Directors, Executive Officers, and Corporate Governance.
 
The information required by this Item is hereby incorporated by reference from the information appearing under the captions “Proposal No. 1: Election of Directors,” “Executive Officers,” “Corporate Governance,” “Board Meetings and Committees,” and “Section 16(a) Beneficial Ownership Reporting Compliance” in our definitive proxy statement (the Proxy Statement) for the annual meeting of stockholders to be held on May 6, 2014, which involves the election of directors and is to be filed with the Securities and Exchange Commission (SEC) pursuant to the Securities Exchange Act of 1934 as amended (the Exchange Act) within 120 days of the end of our fiscal year on December 31, 2013.

Item 11. Executive Compensation.
 
The information required by this Item is hereby incorporated by reference from the information appearing under the captions “Management and Compensation Committee Report,” “Management and Compensation Committee Interlocks and Insider Participation,” “Compensation Discussion and Analysis,” “Compensation of Executive Officers,” and “Director Compensation” in our Proxy Statement. Notwithstanding the foregoing, in accordance with the instructions to Item 407 of Regulation S-K, the information contained in our Proxy Statement under the subheading “Management and Compensation Committee Report” shall be deemed furnished, and not filed, in this Form 10-K, and shall not be deemed incorporated by reference into any filing under the Securities Act of 1933, or the Exchange Act, as a result of this furnishing, except to the extent we specifically incorporate it by reference.

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.
 
The information required by this Item is hereby incorporated by reference from the information appearing under the captions “Beneficial Stock Ownership of Certain Stockholders and Management” and “Equity Compensation Plan Information” in our Proxy Statement. 

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

Item 14. Principal Accounting Fees and Services.
 
The information required by this Item is hereby incorporated by reference from the information appearing under the caption “Fees Paid to Principal Accounting Firm” in our Proxy Statement.


57


PART IV

Item 15. Exhibits and Financial Statement Schedules.
 
(a) List of documents filed as part of this Report
 
1.
Financial Statements of the Company
 
 
 
Page
 
F-1
 
F-3
 
F-5
 
F-6
 
F-7
 
F-8
 
F-9
2.
Financial statement schedules have been omitted as they are not required, are not applicable, or the required information is included in the financial statements or notes thereto.
 
3.
List of Exhibits
 
 
2.1
Asset Purchase Agreement, dated as of July 18, 2012, by and among Greywolf Production Systems Inc., GPS Limited, Greywolf USA Holdings, Inc., 1554531 Alberta Ltd., the shareholders designated therein, Greywolf Energy Services Ltd. And TETRA Production Testing Services, LLC (incorporated by reference to Exhibit 2.1 to the Company’s Form 8-K filed on July 20, 2012 (SEC File No. 001-13455)).
3.1
Restated Certificate of Incorporation of TETRA Technologies, Inc. (incorporated by reference to Exhibit 3.1 to the Company’s Registration Statement on Form S-4 filed on December 27, 1995 (SEC File No. 33-80881)).
3.2
Certificate of Amendment of Restated Certificate of Incorporation of TETRA Technologies, Inc. (incorporated by reference to Exhibit 3.1 to the Company’s Registration Statement on Form S-4 filed on December 27, 1995 (SEC File No. 33-80881)).
3.3
Certificate of Amendment of Restated Certificate of Incorporation of TETRA Technologies, Inc. (incorporated by reference to Exhibit 3.1(ii) to the Company’s Annual Report on Form 10-K for the year ended December 31, 2003 filed on March 15, 2004 (SEC File No. 001-13455)).
3.4
Certificate of Amendment of Restated Certificate of Incorporation of TETRA Technologies, Inc. (incorporated by reference to Exhibit 4.4 to the Company’s Registration Statement on Form S-4 filed on May 25, 2004 (SEC File No. 333-115859)).
3.5
Certificate of Amendment of Restated Certificate of Incorporation of TETRA Technologies, Inc. (incorporated by reference to Exhibit 4.5 to the Company’s Registration Statement on Form S-8 filed on May 4, 2006 (SEC File No. 333-133790)).
3.6
Amended and Restated Bylaws of TETRA Technologies, Inc. (incorporated by reference to Exhibit 4.6 to the Company’s Registration Statement on Form S-8 filed on May 4, 2006 (SEC File No. 333-133790)).
3.7
Certificate of Elimination, dated March 13, 2013, relating to the Series One Junior Participating Preferred Stock (incorporated by reference to Exhibit 3.1 to the Company’s Form 8-K filed on March 13, 2013 (SEC File No. 001-13455)).

4.1
Rights Agreement dated October 26, 1998 between the Company and Computershare Investor Services LLC (as successor in interest to Harris Trust & Savings Bank), as Rights Agent (incorporated by reference to Exhibit 1 to the Company’s Registration Statement on Form 8-A filed on October 28, 1998 (SEC File No. 001-13455)).
4.2
Master Note Purchase Agreement, dated September 27, 2004 by and among TETRA Technologies, Inc. and Jackson National Life Insurance Company, Massachusetts Mutual Life Insurance Company, C.M. Life Insurance Company, Allstate Life Insurance Company, Teachers Insurance and Annuity Association of America, Pacific Life Insurance Company, the Prudential Assurance Company Limited (PAC), and Panther CDO II, B.V. (incorporated by reference to Exhibit 4.1 to the Company’s Form 8-K filed on September 30, 2004 (SEC File No. 001-13455)).

58


4.3
Form of Subsidiary Guaranty dated September 27, 2004, executed by TETRA Applied Holding Company, TETRA International Incorporated, TETRA Micronutrients, Inc., TETRA Process Services, Inc., TETRA Thermal, Inc., Maritech Resources, Inc., Seajay Industries, Inc., TETRA Investment Holding Co., Inc., TETRA Financial Services, Inc., Compressco, Inc., Providence Natural Gas, Inc., TETRA Applied LP, LLC, TETRA Applied GP, LLC, TETRA Production Testing GP, LLC, TPS Holding Company, LLC, T Production Testing, LLC, TETRA Real Estate, LLC, TETRA Real Estate, LP, Compressco Testing, L.L.C., Compressco Field Services, Inc., TETRA Production Testing Services, L.P., and TETRA Applied Technologies, L. P., for the benefit of the holders of the Notes (incorporated by reference to Exhibit 4.4 to the Company’s Form 8-K filed on September 30, 2004 (SEC File No. 001-13455)).
4.4
First Supplement to Master Note Purchase Agreement, dated April 18, 2006, by and among TETRA Technologies, Inc. and Jackson National Life Insurance Company, Allianz Life Insurance Company of North America, United of Omaha Life Insurance Company, Mutual of Omaha Insurance Company, CUNA Mutual Life Insurance Company, CUNA Mutual Insurance Society, CUMIS Insurance Society, Inc., Members Life Insurance Company, and Modern Woodmen of America, attaching the form of the 5.90% Senior Notes, Series 2006-A, due April 30, 2016 as an exhibit thereto (incorporated by reference to Exhibit 4.1 to the Company’s Form 8-K filed on April 20, 2006 (SEC File No. 001-13455)).
4.5
Note Purchase Agreement, dated April 30, 2008, by and among TETRA Technologies, Inc. and The Prudential Insurance Company of America, Physicians Mutual Insurance Company, The Lincoln National Life Insurance Company, The Guardian Life Insurance Company of America, The Guardian Insurance & Annuity Company, Inc., Massachusetts Mutual Life Insurance Company, Hakone Fund II LLC, C.M. Life Insurance Company, Pacific Life Insurance Company, United of Omaha Life Insurance Company, Companion Life Insurance Company, United World Life Insurance Company, Country Life Insurance Company, The Ohio National Life Insurance Company and Ohio National Life Assurance Corporation (incorporated by reference to Exhibit 4.1 to the Company’s Form 8-K filed on May 5, 2008 (SEC File No. 001-13455)).
4.6
First Amendment to Rights Agreement dated as of November 6, 2008, by and between TETRA Technologies, Inc. and Computershare Trust Company, N.A. (as successor rights agent to Harris Trust and Savings Bank), as Rights Agent (incorporated by reference to Exhibit 4.1 to the Company’s Form 8-K filed on November 6, 2008 (SEC File No. 001-13455)).
4.7
Form of 6.30% Senior Notes, Series 2008-A, due April 30, 2013 (incorporated by reference to Exhibit 4.2 to the Company’s Form 8-K filed on May 5, 2008 (SEC File No. 001-13455)).
4.8
Form of 6.56% Senior Notes, Series 2008-B, due April 30, 2015 (incorporated by reference to Exhibit 4.3 to the Company’s Form 8-K filed on May 5, 2008 (SEC File No. 001-13455)).
4.9
Form of Subsidiary Guarantee dated as of April 30, 2008, executed by Beacon Resources, LLC, Compressco Field Services, Inc., EPIC Diving and Marine Services, LLC, Maritech Resources, Inc., TETRA Applied Technologies, LLC, TETRA International Incorporated, TETRA Process Services, L.C., TETRA Production Testing Services, LLC, and Maritech Timbalier Bay, LP, for the benefit of the holders of the Notes (incorporated by reference to Exhibit 4.4 to the Company’s Form 8-K filed on May 5, 2008 (SEC File No. 0001-13455)).
4.10
Note Purchase Agreement, dated September 30, 2010, by and among TETRA Technologies, Inc. and The Lincoln National Life Insurance Company, Teachers Insurance and Annuity Association of America, Wells Fargo Bank, N.A., The Guardian National Life Insurance Company of America, The Guardian Insurance & Annuity Company, Inc., Southern Farm Bureau Life Insurance Company, Primerica Life Insurance Company, Prime Reinsurance Company, Inc., Senior Health Insurance Company of Pennsylvania, The Union Central Life Insurance Company, Ameritas Life Insurance Corp., Acacia Life Insurance Company and First Ameritas Life Insurance Corp. of New York (incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K filed on October 8, 2010 (SEC File No. 001-13455)).
4.11
Form of 5.09% Senior Notes, Series 2010-A, due December 15, 2017 (incorporated by reference to Exhibit 4.2 to the Company’s Current Report on Form 8-K filed on October 8, 2010 (SEC File No. 001-13455)).
4.12
Form of 5.67% Senior Notes, Series 2010-B, due December 15, 2020 (incorporated by reference to Exhibit 4.3 to the Company’s Current Report on Form 8-K filed on October 8, 2010 (SEC File No. 001-13455)).
4.13
Second Amendment to Rights Agreement, dated as of March 13, 2013, between the Company and Computershare Trust Company, N.A., as Rights Agent (incorporated by reference to Exhibit 4.1 to the Company’s Form 8-K filed on March 13, 2013 (SEC File No. 001-13455)).

4.14
Note Purchase Agreement, dated April 29, 2013, by and among TETRA Technologies, Inc. and The Lincoln National Life Insurance Company and Lincoln Life & Annuity Company of New York (incorporated by reference to Exhibit 4.1 to the Company’s Form 8-K filed on May 3, 2013 (SEC File No. 001-13455)).

59


4.15
First Amendment to Note Purchase Agreement dated and effective as of April 29, 2013, by and among TETRA Technologies, Inc. and The Lincoln National Life Insurance Company and Lincoln Life & Annuity Company of New York (incorporated by reference to Exhibit 4.2 to the Company’s Form 8-K filed on May 3, 2013 (SEC File No. 001-13455)).

4.16
Form of 4.00% Senior Notes due April 29, 2020 (incorporated by reference to Exhibit 4.3 to the Company’s Form 8-K filed on May 3, 2013 (SEC File No. 001-13455)).

4.17
Subsidiary Guaranty dated April 29, 2013, executed by Compressco Field Services, L.L.C., EPIC Diving & Marine Services, LLC, TETRA Applied Technologies, LLC, TETRA International Incorporated and TETRA Production Testing Services, LLC, in favor of the holders of the 4.00% Senior Notes due April 29, 2020 (incorporated by reference to Exhibit 4.4 to the Company’s Form 8-K filed on May 3, 2013 (SEC File No. 001-13455)).

10.1***
1990 Stock Option Plan, as amended through January 5, 2001 (incorporated by reference to Exhibit 10.8 to the Company’s Form 10-K for the year ended December 31, 2000 filed on March 30, 2001 (SEC File No. 001-13455)).
10.2***
1996 Stock Option Plan for Nonexecutive Employees and Consultants (incorporated by reference to Exhibit 99.1 to the Company’s Registration Statement on Form S-8 filed on November 19, 1997 (SEC File No. 333-61988)).
10.3***
Agreement between TETRA Technologies, Inc. and Geoffrey M. Hertel, dated February 26, 1993 (incorporated by reference to Exhibit 10.2 to the Company’s Form 8-K filed on January 7, 2005 (SEC File No. 001-13455)).
10.4***
Form of Incentive Stock Option Agreement, dated as of December 28, 2004 (incorporated by reference to Exhibit 10.1 to the Company’s Form 8-K filed on January 7, 2005 SEC File No. 001-13455)).
10.5***
TETRA Technologies, Inc. 2006 Equity Incentive Compensation Plan (incorporated by reference to Exhibit 4.12 to the Company’s Registration Statement on Form S-8 filed on May 4, 2006 (SEC File No. 333-133790)).
10.6***
Forms of Employee Incentive Stock Option Agreement, Employee Nonqualified Stock Option Agreement, and Employee Restricted Stock Agreement under the TETRA Technologies, Inc. 2006 Equity Incentive Compensation Plan (incorporated by reference to Exhibits 10.1, 10.2, and 10.3 to the Company’s Form 8-K filed on May 8, 2006 (SEC File No. 001-13455)).
10.7***
Nonqualified Stock Option Agreement between TETRA Technologies, Inc. and Stuart M. Brightman, dated April 20, 2005 (incorporated by reference to Exhibit 10.1 to the Company’s Form 8-K filed on April 22, 2005 (SEC File No. 001-13455)).
10.8
Credit Agreement, as amended and restated, dated as of June 27, 2006, among TETRA Technologies, Inc. and certain of its subsidiaries, as borrowers, JPMorgan Chase Bank, N.A., as administrative agent, Bank of America, National Association and Wells Fargo Bank, N.A., as syndication agents, and Comerica Bank, as documentation agent, and the lenders party thereto (incorporated by reference to Exhibit 10.1 to the Company’s Form 8-K filed on June 30, 2006 (SEC File No. 001-13455)).
10.9
Agreement and First Amendment to Credit Agreement, dated as of December 15, 2006, among TETRA Technologies, Inc. and certain of its subsidiaries, as borrowers, JPMorgan Chase Bank, N.A., as administrative agent, Bank of America, National Association and Wells Fargo Bank, N.A., as syndication agents, and Comerica Bank, as documentation agent, and the lenders party thereto (incorporated by reference to Exhibit 10.1 to the Company’s Form 8-K filed on January 10, 2007 (SEC File No. 001-13455)).
10.10+***
Summary Description of the Compensation of Non-Employee Directors of TETRA Technologies, Inc.
10.11+***
Summary Description of Named Executive Officer Compensation.
10.12***
TETRA Technologies, Inc. Nonqualified Deferred Compensation Plan (incorporated by reference to Exhibit 10.9 to the Company’s Form 10-Q filed on August 13, 2002 (SEC File No. 001-13455)).
10.13***
TETRA Technologies, Inc. Nonqualified Deferred Compensation Plan and The Executive Excess Plan Adoption Agreement effective on June 30, 2005 (incorporated by reference to Exhibit 10.2 to the Company’s Form 10-Q/A filed on March 16, 2006 (SEC File No. 001-13455)).
10.14***
TETRA Technologies, Inc. 2007 Equity Incentive Compensation Plan (incorporated by reference to Exhibit 4.12 to the Company’s Registration Statement on Form S-8 filed on  May 4, 2007 (SEC File No. 333-142637)).
10.15***
Forms of Employee Incentive Stock Option Agreement, Employee Nonqualified Stock Option Agreement, and Employee Restricted Stock Agreement under the TETRA Technologies, Inc. 2007 Equity Incentive Compensation Plan (incorporated by reference to Exhibits 4.13, 4.14, and 4.15 to the Company’s Registration Statement on Form S-8 filed on May 4, 2007 (SEC File No. 333-142637)).

60


10.16***
TETRA Technologies, Inc. 401(k) Retirement Plan, as amended and restated (incorporated by reference to Exhibit 99.1 to the Company’s Registration Statement on Form S-8 filed on February 22, 2008 (SEC File No. 333-149348)).
10.17***
TETRA Technologies, Inc. Amended and Restated 2007 Equity Incentive Compensation Plan (incorporated by reference to Exhibit 4.12 to the Company’s Registration Statement on Form S-8 filed on May 9, 2008 (SEC File No. 333-150783)).
10.18***
Forms of Employee Incentive Stock Option Agreement, Employee Nonqualified Stock Option Agreement, Employee Restricted Stock Agreement, and Non-Employee Director Restricted Stock Agreement under the TETRA Technologies, Inc. Amended and Restated 2007 Equity Incentive Compensation Plan (incorporated by reference to Exhibits 4.13, 4.14, 4.15 and 4.16 to the Company’s Registration Statement on Form S-8 filed on May 9, 2008 (SEC File No. 333-150783)).
10.19
Form of Senior Indenture (including form of senior debt security) (incorporated by reference to Exhibit 4.21 to the Company’s Registration Statement on Form S-3 filed on November 30, 2009 (SEC File No. 333-163409)).
10.20
Form of Subordinated Indenture (including form of subordinated debt security) (incorporated by reference to Exhibit 4.22 to the Company’s Registration Statement on Form S-3 filed on November 30, 2009 (SEC File No. 333-163409)).
10.21***
TETRA Technologies, Inc. Cash Incentive Compensation Plan (incorporated by reference to Exhibit 4.1 to the Company’s Form 10-Q filed on May 10, 2010 (SEC File No. 001-13455)).
10.22***
TETRA Technologies, Inc. 2007 Long Term Incentive Compensation Plan (incorporated by reference to Exhibit 4.11 to the Company’s Registration Statement on Form S-8 filed on May 5, 2010 (SEC File No. 333-166537)).
10.23***
Forms of Employee Incentive Stock Option Agreement, Employee Nonqualified Stock Option Agreement, Employee Restricted Stock Agreement, Non-Employee Consultant Nonqualified Stock Option Agreement, Non-Employee Consultant Restricted Stock Agreement, and Non-Employee Director Restricted Stock Agreement under the TETRA Technologies, Inc. 2007 Long Term Incentive Compensation Plan (incorporated by reference to Exhibits 4.12, 4.13, 4.14, 4.15, 4.16 and 4.17 to the Company’s Registration Statement on Form S-8 filed on May 5, 2010 (SEC File No. 333-166537)).
10.24
Agreement and Second Amendment to Credit Agreement dated as of October 29, 2010, among TETRA Technologies, Inc. and certain of its subsidiaries, as borrowers, JPMorgan Chase Bank, N.A., as administrative agent, Bank of America, National Association and Wells Fargo Bank, N.A. as syndication agents, and Comerica Bank, as documentation agent, and the lenders party thereto (incorporated by reference to Exhibit 10.1 to the Company’s Form 8-K filed on November 3, 2010 (SEC File No. 001-13455)).
10.25
Contribution, Conveyance and Assumption Agreement, dated June 20, 2011, by and among Compressco, Inc., Compressco Field Services, Inc., Compressco Canada, Inc., Compressco de Mexico, S. de R.L. de C.V., Compressco Partners GP Inc., Compressco Partners, L.P., Compressco Partners Operating, LLC, Compressco Netherlands B.V., Compressco Holdings, LLC, Compressco Netherlands Cooperatief U.A., Compressco Partners Sub, Inc., TETRA International Incorporated, Production Enhancement Mexico, S. de R.L. de C.V. and TETRA Technologies, Inc. (incorporated by reference to Exhibit 10.1 to the Company’s Form 8-K filed on June 30, 2011 (SEC File No. 001-13455)).
10.26
Omnibus Agreement dated June 20, 2011, by and among Compressco Partners, L.P., TETRA Technologies, Inc. and Compressco Partners GP Inc. (incorporated by reference to Exhibit 10.2 to the Company’s Form 8-K filed on June 30, 2011 (SEC File No. 001-13455)).
10.27
Purchase and Sale Agreement, dated April 1, 2011, by and between Maritech Resources, Inc. as Seller and Tana Exploration Company LLC as Buyer (incorporated by reference to Exhibit 10.3 to the Company’s Form 10-Q filed on August 9, 2011 (SEC File No. 001-13455)).
10.28***
TETRA Technologies, Inc. 2011 Long-Term Incentive Compensation Plan (incorporated by reference to Exhibit 4.11 to the Company’s Registration Statement on Form S-8 filed on May 10, 2011 (SEC File No. 333-174090)).
10.29***
Forms of Employee Incentive Stock Option Agreement, Employee Nonqualified Stock Option Agreement, Employee Restricted Stock Agreement, Non-Employee Consultant Nonqualified Stock Option Agreement, Non-Employee Consultant Restricted Stock Agreement and Non-Employee Director Restricted Stock Agreement under the TETRA Technologies, Inc. 2011 Long Term Incentive Compensation Plan (incorporated by reference to Exhibits 4.12, 4.13, 4.14, 4.15, 4.16 and 4.17 to the Company’s Registration Statement on Form S-8 filed on May 10, 2011 (SEC File No. 333-174090)).
10.30***
Employee Restricted Stock Agreement between TETRA Technologies, Inc. and Peter J. Pintar dated November 15, 2011 (incorporated by reference to Exhibit 4.11 to the Company’s Registration Statement on Form S-8 filed on November 15, 2011 (SEC File No. 333-177995)).

61


10.31***
Separation and Release Agreement dated July 31, 2012 by and between TETRA Technologies, Inc. and Joseph M. Abell (incorporated by reference to Exhibit 10.1 to the Company’s Form 8-K filed on August 1, 2012 (SEC File No. 001-13455)).
10.32***
Employee Equity Award Agreement dated August 15, 2012 by and between TETRA Technologies, Inc. and Elijio V. Serrano (incorporated by reference to Exhibit 10.1 to the Company’s Form 8-K filed on August 16, 2012 (SEC File No. 001-13455)).
10.33+
Purchase and Sale Agreement dated December 31, 2012 by and between TETRA Technologies, Inc. and Tetris Property LP.
10.34+
Lease Agreement dated December 31, 2012 by and between Tetris Property LP and TETRA Technologies, Inc.
10.37***
TETRA Technologies, Inc. 2011 Amended and Restated Long Term Incentive Compensation Plan (incorporated by reference to Exhibit 4.9 to the Company’s Registration Statement on Form S-8 filed on May 9, 2013 (SEC File No. 333-188494)).

10.38***
Forms of Employee Incentive Stock Option Agreement, Employee Nonqualified Stock Option Agreement, Employee Restricted Stock Agreement, Non-Employee Director Restricted Stock Agreement, Non-Employee Nonqualified Stock Option Agreement and Non-Employee Restricted Stock Agreement under the TETRA Technologies, Inc. 2011 Amended and Restated Long Term Incentive Compensation Plan (incorporated by reference to Exhibits 4.10, 4.11, 4.12, 4.13, 4.14 and 4.15, respectively to the Company’s Registration Statement on Form S-8 filed on May 9, 2013 (SEC File No. 333-188494)).

10.39***
Form of Change in Control Agreement (incorporated by reference to Exhibit 10.1 to the Company’s Form 8-K filed on June 4, 2013 (SEC File No. 001-13455)).

10.40
Credit Agreement, dated October 15, 2013, by and among Compressco Partners, L.P., Compressco Partners Operating, LLC, Compressco Partners Sub, Inc., Compressco Holdings, LLC, Compressco Leasing, LLC, Compressco Field Services International, LLC, and Compressco International, LLC, as the borrowers, JP Morgan Chase Bank, N.A., as Administrative Agent, and JPMorgan Chase Bank, N.A., Bank of America, N.A., and PNC Bank, National Association, as lenders (incorporated by reference to Exhibit 10.1 to Compressco Partners, L.P.’s Current Report on Form 8-K filed on October 18, 2013 (SEC File No. 001-35195)).

21+
Subsidiaries of the Company.
23.1+
Consent of Ernst & Young, LLP.
31.1+
Certification Pursuant to Rule 13(a)-14(a) or 15(d)-14(a) of the Exchange Act, As Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2+
Certification Pursuant to Rule 13(a)-14(a) or 15(d)-14(a) of the Exchange Act, As Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1**
Certification Furnished Pursuant to 18 U.S.C. Section 1350, As Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Chief Executive Officer).
32.2**
Certification Furnished Pursuant to 18 U.S.C. Section 1350, As Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Chief Financial Officer).
101.INS++
XBRL Instance Document.
101.SCH++
XBRL Taxonomy Extension Schema Document.
101.CAL++
XBRL Taxonomy Extension Calculation Linkbase Document.
101.LAB++
XBRL Taxonomy Extension Label Linkbase Document.
101.PRE++
XBRL Taxonomy Extension Presentation Linkbase Document.
101.DEF++
XBRL Taxonomy Extension Definition Linkbase Document.
_____________________________________________________________
+
Filed with this report.
**
Furnished with this report.
***
Management contract or compensatory plan or arrangement.
++
Attached as Exhibit 101 to this report are the following documents formatted in XBRL (Extensible Business Reporting Language): (i) Consolidated Statements of Operations for the years ended December 31, 2013, 2012 and 2011; (ii) Consolidated Balance Sheets as of December 31, 2013 and December 31, 2012; (iii) Consolidated Statements of Comprehensive Income for the years ended December 31, 2013, 2012 and 2011; (iv) Consolidated Statements of Cash Flows for the years ended December 31, 2013, 2012 and 2011; (v) Consolidated Statements of Stockholders’ Equity for the years ended December 31, 2013, 2012 and 2011; and (vi) Notes to Consolidated Financial Statements for the year ended December 31, 2013.

62


SIGNATURES
 
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, TETRA Technologies, Inc. has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
 
 
 
TETRA Technologies, Inc.
 
 
 
 
Date:
March 3, 2014
By:
/s/Stuart M. Brightman
 
 
 
Stuart M. Brightman, President & CEO
 
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated:
 
Signature
Title
Date
 
 
 
/s/Ralph S. Cunningham
Chairman of
March 3, 2014
Ralph S. Cunningham
the Board of Directors
 
 
 
 
/s/Stuart M. Brightman
President, Chief Executive
March 3, 2014
Stuart M. Brightman
Officer and Director
 
 
(Principal Executive Officer)
 
 
 
 
/s/Elijio V. Serrano
Senior Vice President and
March 3, 2014
Elijio V. Serrano
Chief Financial Officer
 
 
(Principal Financial Officer)
 
 
 
 
/s/Ben C. Chambers
Vice President – Accounting
March 3, 2014
Ben C. Chambers
and Controller
 
 
(Principal Accounting Officer)
 
 
 
 
/s/Mark E. Baldwin
Director
March 3, 2014
Mark E. Baldwin
 
 
 
 
 
/s/Thomas R. Bates, Jr.
Director
March 3, 2014
Thomas R. Bates, Jr.
 
 
 
 
 
/s/Paul D. Coombs
Director
March 3, 2014
Paul D. Coombs
 
 
 
 
 
/s/Tom H. Delimitros
Director
March 3, 2014
Tom H. Delimitros
 
 
 
 
 
/s/John F. Glick
Director
March 3, 2014
John F. Glick
 
 
 
 
 
/s/Geoffrey M. Hertel
Director
March 3, 2014
Geoffrey M. Hertel
 
 
 
 
 
/s/Kenneth P. Mitchell
Director
March 3, 2014
Kenneth P. Mitchell
 
 
 
 
 
/s/William D. Sullivan
Director
March 3, 2014
William D. Sullivan
 
 
 
 
 
/s/Kenneth E. White, Jr.
Director
March 3, 2014
Kenneth E. White, Jr.
 
 


63


EXHIBIT INDEX
 

2.1
Asset Purchase Agreement, dated as of July 18, 2012, by and among Greywolf Production Systems Inc., GPS Limited, Greywolf USA Holdings, Inc., 1554531 Alberta Ltd., the shareholders designated therein, Greywolf Energy Services Ltd. And TETRA Production Testing Services, LLC (incorporated by reference to Exhibit 2.1 to the Company’s Form 8-K filed on July 20, 2012 (SEC File No. 001-13455)).
3.1
Restated Certificate of Incorporation of TETRA Technologies, Inc. (incorporated by reference to Exhibit 3.1 to the Company’s Registration Statement on Form S-4 filed on December 27, 1995 (SEC File No. 33-80881)).
3.2
Certificate of Amendment of Restated Certificate of Incorporation of TETRA Technologies, Inc. (incorporated by reference to Exhibit 3.1 to the Company’s Registration Statement on Form S-4 filed on December 27, 1995 (SEC File No. 33-80881)).
3.3
Certificate of Amendment of Restated Certificate of Incorporation of TETRA Technologies, Inc. (incorporated by reference to Exhibit 3.1(ii) to the Company’s Annual Report on Form 10-K for the year ended December 31, 2003 filed on March 15, 2004 (SEC File No. 001-13455)).
3.4
Certificate of Amendment of Restated Certificate of Incorporation of TETRA Technologies, Inc. (incorporated by reference to Exhibit 4.4 to the Company’s Registration Statement on Form S-4 filed on May 25, 2004 (SEC File No. 333-115859)).
3.5
Certificate of Amendment of Restated Certificate of Incorporation of TETRA Technologies, Inc. (incorporated by reference to Exhibit 4.5 to the Company’s Registration Statement on Form S-8 filed on May 4, 2006 (SEC File No. 333-133790)).
3.6
Amended and Restated Bylaws of TETRA Technologies, Inc. (incorporated by reference to Exhibit 4.6 to the Company’s Registration Statement on Form S-8 filed on May 4, 2006 (SEC File No. 333-133790)).
3.7
Certificate of Elimination, dated March 13, 2013, relating to the Series One Junior Participating Preferred Stock (incorporated by reference to Exhibit 3.1 to the Company’s Form 8-K filed on March 13, 2013 (SEC File No. 001-13455)).

4.1
Rights Agreement dated October 26, 1998 between the Company and Computershare Investor Services LLC (as successor in interest to Harris Trust & Savings Bank), as Rights Agent (incorporated by reference to Exhibit 1 to the Company’s Registration Statement on Form 8-A filed on October 28, 1998 (SEC File No. 001-13455)).
4.2
Master Note Purchase Agreement, dated September 27, 2004 by and among TETRA Technologies, Inc. and Jackson National Life Insurance Company, Massachusetts Mutual Life Insurance Company, C.M. Life Insurance Company, Allstate Life Insurance Company, Teachers Insurance and Annuity Association of America, Pacific Life Insurance Company, the Prudential Assurance Company Limited (PAC), and Panther CDO II, B.V. (incorporated by reference to Exhibit 4.1 to the Company’s Form 8-K filed on September 30, 2004 (SEC File No. 001-13455)).
4.3
Form of Subsidiary Guaranty dated September 27, 2004, executed by TETRA Applied Holding Company, TETRA International Incorporated, TETRA Micronutrients, Inc., TETRA Process Services, Inc., TETRA Thermal, Inc., Maritech Resources, Inc., Seajay Industries, Inc., TETRA Investment Holding Co., Inc., TETRA Financial Services, Inc., Compressco, Inc., Providence Natural Gas, Inc., TETRA Applied LP, LLC, TETRA Applied GP, LLC, TETRA Production Testing GP, LLC, TPS Holding Company, LLC, T Production Testing, LLC, TETRA Real Estate, LLC, TETRA Real Estate, LP, Compressco Testing, L.L.C., Compressco Field Services, Inc., TETRA Production Testing Services, L.P., and TETRA Applied Technologies, L. P., for the benefit of the holders of the Notes (incorporated by reference to Exhibit 4.4 to the Company’s Form 8-K filed on September 30, 2004 (SEC File No. 001-13455)).
4.4
First Supplement to Master Note Purchase Agreement, dated April 18, 2006, by and among TETRA Technologies, Inc. and Jackson National Life Insurance Company, Allianz Life Insurance Company of North America, United of Omaha Life Insurance Company, Mutual of Omaha Insurance Company, CUNA Mutual Life Insurance Company, CUNA Mutual Insurance Society, CUMIS Insurance Society, Inc., Members Life Insurance Company, and Modern Woodmen of America, attaching the form of the 5.90% Senior Notes, Series 2006-A, due April 30, 2016 as an exhibit thereto (incorporated by reference to Exhibit 4.1 to the Company’s Form 8-K filed on April 20, 2006 (SEC File No. 001-13455)).

64


4.5
Note Purchase Agreement, dated April 30, 2008, by and among TETRA Technologies, Inc. and The Prudential Insurance Company of America, Physicians Mutual Insurance Company, The Lincoln National Life Insurance Company, The Guardian Life Insurance Company of America, The Guardian Insurance & Annuity Company, Inc., Massachusetts Mutual Life Insurance Company, Hakone Fund II LLC, C.M. Life Insurance Company, Pacific Life Insurance Company, United of Omaha Life Insurance Company, Companion Life Insurance Company, United World Life Insurance Company, Country Life Insurance Company, The Ohio National Life Insurance Company and Ohio National Life Assurance Corporation (incorporated by reference to Exhibit 4.1 to the Company’s Form 8-K filed on May 5, 2008 (SEC File No. 001-13455)).
4.6
First Amendment to Rights Agreement dated as of November 6, 2008, by and between TETRA Technologies, Inc. and Computershare Trust Company, N.A. (as successor rights agent to Harris Trust and Savings Bank), as Rights Agent (incorporated by reference to Exhibit 4.1 to the Company’s Form 8-K filed on November 6, 2008 (SEC File No. 001-13455)).
4.7
Form of 6.30% Senior Notes, Series 2008-A, due April 30, 2013 (incorporated by reference to Exhibit 4.2 to the Company’s Form 8-K filed on May 5, 2008 (SEC File No. 001-13455)).
4.8
Form of 6.56% Senior Notes, Series 2008-B, due April 30, 2015 (incorporated by reference to Exhibit 4.3 to the Company’s Form 8-K filed on May 5, 2008 (SEC File No. 001-13455)).
4.9
Form of Subsidiary Guarantee dated as of April 30, 2008, executed by Beacon Resources, LLC, Compressco Field Services, Inc., EPIC Diving and Marine Services, LLC, Maritech Resources, Inc., TETRA Applied Technologies, LLC, TETRA International Incorporated, TETRA Process Services, L.C., TETRA Production Testing Services, LLC, and Maritech Timbalier Bay, LP, for the benefit of the holders of the Notes (incorporated by reference to Exhibit 4.4 to the Company’s Form 8-K filed on May 5, 2008 (SEC File No. 0001-13455)).
4.10
Note Purchase Agreement, dated September 30, 2010, by and among TETRA Technologies, Inc. and The Lincoln National Life Insurance Company, Teachers Insurance and Annuity Association of America, Wells Fargo Bank, N.A., The Guardian National Life Insurance Company of America, The Guardian Insurance & Annuity Company, Inc., Southern Farm Bureau Life Insurance Company, Primerica Life Insurance Company, Prime Reinsurance Company, Inc., Senior Health Insurance Company of Pennsylvania, The Union Central Life Insurance Company, Ameritas Life Insurance Corp., Acacia Life Insurance Company and First Ameritas Life Insurance Corp. of New York (incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K filed on October 8, 2010 (SEC File No. 001-13455)).
4.11
Form of 5.09% Senior Notes, Series 2010-A, due December 15, 2017 (incorporated by reference to Exhibit 4.2 to the Company’s Current Report on Form 8-K filed on October 8, 2010 (SEC File No. 001-13455)).
4.12
Form of 5.67% Senior Notes, Series 2010-B, due December 15, 2020 (incorporated by reference to Exhibit 4.3 to the Company’s Current Report on Form 8-K filed on October 8, 2010 (SEC File No. 001-13455)).
4.13
Second Amendment to Rights Agreement, dated as of March 13, 2013, between the Company and Computershare Trust Company, N.A., as Rights Agent (incorporated by reference to Exhibit 4.1 to the Company’s Form 8-K filed on March 13, 2013 (SEC File No. 001-13455)).

4.14
Note Purchase Agreement, dated April 29, 2013, by and among TETRA Technologies, Inc. and The Lincoln National Life Insurance Company and Lincoln Life & Annuity Company of New York (incorporated by reference to Exhibit 4.1 to the Company’s Form 8-K filed on May 3, 2013 (SEC File No. 001-13455)).
4.15
First Amendment to Note Purchase Agreement dated and effective as of April 29, 2013, by and among TETRA Technologies, Inc. and The Lincoln National Life Insurance Company and Lincoln Life & Annuity Company of New York (incorporated by reference to Exhibit 4.2 to the Company’s Form 8-K filed on May 3, 2013 (SEC File No. 001-13455)).

4.16
Form of 4.00% Senior Notes due April 29, 2020 (incorporated by reference to Exhibit 4.3 to the Company’s Form 8-K filed on May 3, 2013 (SEC File No. 001-13455)).

4.17
Subsidiary Guaranty dated April 29, 2013, executed by Compressco Field Services, L.L.C., EPIC Diving & Marine Services, LLC, TETRA Applied Technologies, LLC, TETRA International Incorporated and TETRA Production Testing Services, LLC, in favor of the holders of the 4.00% Senior Notes due April 29, 2020 (incorporated by reference to Exhibit 4.4 to the Company’s Form 8-K filed on May 3, 2013 (SEC File No. 001-13455)).

10.1***
1990 Stock Option Plan, as amended through January 5, 2001 (incorporated by reference to Exhibit 10.8 to the Company’s Form 10-K for the year ended December 31, 2000 filed on March 30, 2001 (SEC File No. 001-13455)).

65


10.2***
1996 Stock Option Plan for Nonexecutive Employees and Consultants (incorporated by reference to Exhibit 99.1 to the Company’s Registration Statement on Form S-8 filed on November 19, 1997 (SEC File No. 333-61988)).
10.3***
Agreement between TETRA Technologies, Inc. and Geoffrey M. Hertel, dated February 26, 1993 (incorporated by reference to Exhibit 10.2 to the Company’s Form 8-K filed on January 7, 2005 (SEC File No. 001-13455)).
10.4***
Form of Incentive Stock Option Agreement, dated as of December 28, 2004 (incorporated by reference to Exhibit 10.1 to the Company’s Form 8-K filed on January 7, 2005 SEC File No. 001-13455)).
10.5***
TETRA Technologies, Inc. 2006 Equity Incentive Compensation Plan (incorporated by reference to Exhibit 4.12 to the Company’s Registration Statement on Form S-8 filed on May 4, 2006 (SEC File No. 333-133790)).
10.6***
Forms of Employee Incentive Stock Option Agreement, Employee Nonqualified Stock Option Agreement, and Employee Restricted Stock Agreement under the TETRA Technologies, Inc. 2006 Equity Incentive Compensation Plan (incorporated by reference to Exhibits 10.1, 10.2, and 10.3 to the Company’s Form 8-K filed on May 8, 2006 (SEC File No. 001-13455)).
10.7***
Nonqualified Stock Option Agreement between TETRA Technologies, Inc. and Stuart M. Brightman, dated April 20, 2005 (incorporated by reference to Exhibit 10.1 to the Company’s Form 8-K filed on April 22, 2005 (SEC File No. 001-13455)).
10.8
Credit Agreement, as amended and restated, dated as of June 27, 2006, among TETRA Technologies, Inc. and certain of its subsidiaries, as borrowers, JPMorgan Chase Bank, N.A., as administrative agent, Bank of America, National Association and Wells Fargo Bank, N.A., as syndication agents, and Comerica Bank, as documentation agent, and the lenders party thereto (incorporated by reference to Exhibit 10.1 to the Company’s Form 8-K filed on June 30, 2006 (SEC File No. 001-13455)).
10.9
Agreement and First Amendment to Credit Agreement, dated as of December 15, 2006, among TETRA Technologies, Inc. and certain of its subsidiaries, as borrowers, JPMorgan Chase Bank, N.A., as administrative agent, Bank of America, National Association and Wells Fargo Bank, N.A., as syndication agents, and Comerica Bank, as documentation agent, and the lenders party thereto (incorporated by reference to Exhibit 10.1 to the Company’s Form 8-K filed on January 10, 2007 (SEC File No. 001-13455)).
10.10+***
Summary Description of the Compensation of Non-Employee Directors of TETRA Technologies, Inc.
10.11+***
Summary Description of Named Executive Officer Compensation.
10.12***
TETRA Technologies, Inc. Nonqualified Deferred Compensation Plan (incorporated by reference to Exhibit 10.9 to the Company’s Form 10-Q filed on August 13, 2002 (SEC File No. 001-13455)).
10.13***
TETRA Technologies, Inc. Nonqualified Deferred Compensation Plan and The Executive Excess Plan Adoption Agreement effective on June 30, 2005 (incorporated by reference to Exhibit 10.2 to the Company’s Form 10-Q/A filed on March 16, 2006 (SEC File No. 001-13455)).
10.14***
TETRA Technologies, Inc. 2007 Equity Incentive Compensation Plan (incorporated by reference to Exhibit 4.12 to the Company’s Registration Statement on Form S-8 filed on  May 4, 2007 (SEC File No. 333-142637)).
10.15***
Forms of Employee Incentive Stock Option Agreement, Employee Nonqualified Stock Option Agreement, and Employee Restricted Stock Agreement under the TETRA Technologies, Inc. 2007 Equity Incentive Compensation Plan (incorporated by reference to Exhibits 4.13, 4.14, and 4.15 to the Company’s Registration Statement on Form S-8 filed on May 4, 2007 (SEC File No. 333-142637)).
10.16***
TETRA Technologies, Inc. 401(k) Retirement Plan, as amended and restated (incorporated by reference to Exhibit 99.1 to the Company’s Registration Statement on Form S-8 filed on February 22, 2008 (SEC File No. 333-149348)).
10.17***
TETRA Technologies, Inc. Amended and Restated 2007 Equity Incentive Compensation Plan (incorporated by reference to Exhibit 4.12 to the Company’s Registration Statement on Form S-8 filed on May 9, 2008 (SEC File No. 333-150783)).
10.18***
Forms of Employee Incentive Stock Option Agreement, Employee Nonqualified Stock Option Agreement, Employee Restricted Stock Agreement, and Non-Employee Director Restricted Stock Agreement under the TETRA Technologies, Inc. Amended and Restated 2007 Equity Incentive Compensation Plan (incorporated by reference to Exhibits 4.13, 4.14, 4.15 and 4.16 to the Company’s Registration Statement on Form S-8 filed on May 9, 2008 (SEC File No. 333-150783)).
10.19
Form of Senior Indenture (including form of senior debt security) (incorporated by reference to Exhibit 4.21 to the Company’s Registration Statement on Form S-3 filed on November 30, 2009 (SEC File No. 333-163409)).
10.20
Form of Subordinated Indenture (including form of subordinated debt security) (incorporated by reference to Exhibit 4.22 to the Company’s Registration Statement on Form S-3 filed on November 30, 2009 (SEC File No. 333-163409)).

66


10.21***
TETRA Technologies, Inc. Cash Incentive Compensation Plan (incorporated by reference to Exhibit 4.1 to the Company’s Form 10-Q filed on May 10, 2010 (SEC File No. 001-13455)).
10.22***
TETRA Technologies, Inc. 2007 Long Term Incentive Compensation Plan (incorporated by reference to Exhibit 4.11 to the Company’s Registration Statement on Form S-8 filed on May 5, 2010 (SEC File No. 333-166537)).
10.23***
Forms of Employee Incentive Stock Option Agreement, Employee Nonqualified Stock Option Agreement, Employee Restricted Stock Agreement, Non-Employee Consultant Nonqualified Stock Option Agreement, Non-Employee Consultant Restricted Stock Agreement, and Non-Employee Director Restricted Stock Agreement under the TETRA Technologies, Inc. 2007 Long Term Incentive Compensation Plan (incorporated by reference to Exhibits 4.12, 4.13, 4.14, 4.15, 4.16 and 4.17 to the Company’s Registration Statement on Form S-8 filed on May 5, 2010 (SEC File No. 333-166537)).
10.24
Agreement and Second Amendment to Credit Agreement dated as of October 29, 2010, among TETRA Technologies, Inc. and certain of its subsidiaries, as borrowers, JPMorgan Chase Bank, N.A., as administrative agent, Bank of America, National Association and Wells Fargo Bank, N.A. as syndication agents, and Comerica Bank, as documentation agent, and the lenders party thereto (incorporated by reference to Exhibit 10.1 to the Company’s Form 8-K filed on November 3, 2010 (SEC File No. 001-13455)).
10.25
Contribution, Conveyance and Assumption Agreement, dated June 20, 2011, by and among Compressco, Inc., Compressco Field Services, Inc., Compressco Canada, Inc., Compressco de Mexico, S. de R.L. de C.V., Compressco Partners GP Inc., Compressco Partners, L.P., Compressco Partners Operating, LLC, Compressco Netherlands B.V., Compressco Holdings, LLC, Compressco Netherlands Cooperatief U.A., Compressco Partners Sub, Inc., TETRA International Incorporated, Production Enhancement Mexico, S. de R.L. de C.V. and TETRA Technologies, Inc. (incorporated by reference to Exhibit 10.1 to the Company’s Form 8-K filed on June 30, 2011 (SEC File No. 001-13455)).
10.26
Omnibus Agreement dated June 20, 2011, by and among Compressco Partners, L.P., TETRA Technologies, Inc. and Compressco Partners GP Inc. (incorporated by reference to Exhibit 10.2 to the Company’s Form 8-K filed on June 30, 2011 (SEC File No. 001-13455)).
10.27
Purchase and Sale Agreement, dated April 1, 2011, by and between Maritech Resources, Inc. as Seller and Tana Exploration Company LLC as Buyer (incorporated by reference to Exhibit 10.3 to the Company’s Form 10-Q filed on August 9, 2011 (SEC File No. 001-13455)).
10.28***
TETRA Technologies, Inc. 2011 Long-Term Incentive Compensation Plan (incorporated by reference to Exhibit 4.11 to the Company’s Registration Statement on Form S-8 filed on May 10, 2011 (SEC File No. 333-174090)).
10.29***
Forms of Employee Incentive Stock Option Agreement, Employee Nonqualified Stock Option Agreement, Employee Restricted Stock Agreement, Non-Employee Consultant Nonqualified Stock Option Agreement, Non-Employee Consultant Restricted Stock Agreement and Non-Employee Director Restricted Stock Agreement under the TETRA Technologies, Inc. 2011 Long Term Incentive Compensation Plan (incorporated by reference to Exhibits 4.12, 4.13, 4.14, 4.15, 4.16 and 4.17 to the Company’s Registration Statement on Form S-8 filed on May 10, 2011 (SEC File No. 333-174090)).
10.30***
Employee Restricted Stock Agreement between TETRA Technologies, Inc. and Peter J. Pintar dated November 15, 2011 (incorporated by reference to Exhibit 4.11 to the Company’s Registration Statement on Form S-8 filed on November 15, 2011 (SEC File No. 333-177995)).
10.31***
Separation and Release Agreement dated July 31, 2012 by and between TETRA Technologies, Inc. and Joseph M. Abell (incorporated by reference to Exhibit 10.1 to the Company’s Form 8-K filed on August 1, 2012 (SEC File No. 001-13455)).
10.32***
Employee Equity Award Agreement dated August 15, 2012 by and between TETRA Technologies, Inc. and Elijio V. Serrano (incorporated by reference to Exhibit 10.1 to the Company’s Form 8-K filed on August 16, 2012 (SEC File No. 001-13455)).
10.33+
Purchase and Sale Agreement dated December 31, 2012 by and between TETRA Technologies, Inc. and Tetris Property LP.
10.34+
Lease Agreement dated December 31, 2012 by and between Tetris Property LP and TETRA Technologies, Inc.
10.37***
TETRA Technologies, Inc. 2011 Amended and Restated Long Term Incentive Compensation Plan (incorporated by reference to Exhibit 4.9 to the Company’s Registration Statement on Form S-8 filed on May 9, 2013 (SEC File No. 333-188494)).

10.38***
Forms of Employee Incentive Stock Option Agreement, Employee Nonqualified Stock Option Agreement, Employee Restricted Stock Agreement, Non-Employee Director Restricted Stock Agreement, Non-Employee Nonqualified Stock Option Agreement and Non-Employee Restricted Stock Agreement under the TETRA Technologies, Inc. 2011 Amended and Restated Long Term Incentive Compensation Plan (incorporated by reference to Exhibits 4.10, 4.11, 4.12, 4.13, 4.14 and 4.15, respectively to the Company’s Registration Statement on Form S-8 filed on May 9, 2013 (SEC File No. 333-188494)).


67


10.39***
Form of Change in Control Agreement (incorporated by reference to Exhibit 10.1 to the Company’s Form 8-K filed on June 4, 2013 (SEC File No. 001-13455)).

10.40
Credit Agreement, dated October 15, 2013, by and among Compressco Partners, L.P., Compressco Partners Operating, LLC, Compressco Partners Sub, Inc., Compressco Holdings, LLC, Compressco Leasing, LLC, Compressco Field Services International, LLC, and Compressco International, LLC, as the borrowers, JP Morgan Chase Bank, N.A., as Administrative Agent, and JPMorgan Chase Bank, N.A., Bank of America, N.A., and PNC Bank, National Association, as lenders (incorporated by reference to Exhibit 10.1 to Compressco Partners, L.P.’s Current Report on Form 8-K filed on October 18, 2013 (SEC File No. 001-35195)).

21+
Subsidiaries of the Company.
23.1+
Consent of Ernst & Young, LLP.
31.1+
Certification Pursuant to Rule 13(a)-14(a) or 15(d)-14(a) of the Exchange Act, As Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2+
Certification Pursuant to Rule 13(a)-14(a) or 15(d)-14(a) of the Exchange Act, As Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1**
Certification Furnished Pursuant to 18 U.S.C. Section 1350, As Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Chief Executive Officer).
32.2**
Certification Furnished Pursuant to 18 U.S.C. Section 1350, As Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Chief Financial Officer).
101.INS++
XBRL Instance Document.
101.SCH++
XBRL Taxonomy Extension Schema Document.
101.CAL++
XBRL Taxonomy Extension Calculation Linkbase Document.
101.LAB++
XBRL Taxonomy Extension Label Linkbase Document.
101.PRE++
XBRL Taxonomy Extension Presentation Linkbase Document.
101.DEF++
XBRL Taxonomy Extension Definition Linkbase Document.
_____________________________________________________________
+
Filed with this report.
**
Furnished with this report.
***
Management contract or compensatory plan or arrangement.
++
Attached as Exhibit 101 to this report are the following documents formatted in XBRL (Extensible Business Reporting Language): (i) Consolidated Statements of Operations for the years ended December 31, 2013, 2012 and 2011; (ii) Consolidated Balance Sheets as of December 31, 2013 and December 31, 2012; (iii) Consolidated Statements of Comprehensive Income for the years ended December 31, 2013, 2012 and 2011; (iv) Consolidated Statements of Cash Flows for the years ended December 31, 2013, 2012 and 2011; (v) Consolidated Statements of Stockholders’ Equity for the years ended December 31, 2013, 2012 and 2011; and (vi) Notes to Consolidated Financial Statements for the year ended December 31, 2013.





68


REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
 
 
Board of Directors and Stockholders of
TETRA Technologies, Inc.
 
We have audited the accompanying consolidated balance sheets of TETRA Technologies, Inc. and subsidiaries as of December 31, 2013 and 2012, and the related consolidated statements of operations, comprehensive income (loss), equity, and cash flows for each of the three years in the period ended December 31, 2013. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
 
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
 
In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of TETRA Technologies, Inc. and subsidiaries at December 31, 2013 and 2012, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2013, in conformity with U.S. generally accepted accounting principles.
 
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), TETRA Technologies, Inc.’s internal control over financial reporting as of December 31, 2013, based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (1992 framework) and our report dated March 3, 2014, expressed an unqualified opinion thereon.
 
 
/s/ERNST & YOUNG LLP
 
 
Houston, Texas
March 3, 2014


F-1


REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
 
 
Board of Directors and Stockholders of
TETRA Technologies, Inc.
 
We have audited TETRA Technologies, Inc. and subsidiaries’ internal control over financial reporting as of December 31, 2013, based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (1992 framework) (the COSO criteria). TETRA Technologies, Inc. and subsidiaries’ management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the company’s internal control over financial reporting based on our audit.
 
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
 
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
 
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
 
In our opinion, TETRA Technologies, Inc. and subsidiaries maintained, in all material respects, effective internal control over financial reporting as of December 31, 2013, based on the COSO criteria.
 
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of TETRA Technologies, Inc. and subsidiaries as of December 31, 2013 and 2012, and the related consolidated statements of operations, comprehensive income (loss), equity, and cash flows for each of the three years in the period ended December 31, 2013 of TETRA Technologies, Inc. and subsidiaries, and our report dated March 3, 2014, expressed an unqualified opinion thereon.
 
/s/ERNST & YOUNG LLP
 
Houston, Texas
March 3, 2014

F-2


TETRA Technologies, Inc. and Subsidiaries
Consolidated Balance Sheets
(In Thousands)
 
 
 
December 31,
2013
 
December 31,
2012
ASSETS
 
 

 
 

Current assets:
 
 

 
 

Cash and cash equivalents
 
$
38,754

 
$
74,048

Restricted cash
 
9,067

 
5,571

Trade accounts receivable, net of allowances for doubtful accounts of $1,349 in 2013 and $1,085 in 2012
 
180,659

 
176,352

Deferred tax asset
 
14,740

 
29,789

Inventories
 
100,792

 
103,041

Assets held for sale
 
5,541

 
12,009

Prepaid expenses and other current assets
 
24,386

 
34,299

Total current assets
 
373,939

 
435,109

Property, plant, and equipment:
 
 

 
 

Land and building
 
42,954

 
41,153

Machinery and equipment
 
682,836

 
589,725

Automobiles and trucks
 
57,588

 
57,708

Chemical plants
 
175,494

 
161,565

Construction in progress
 
14,170

 
40,452

Total property, plant, and equipment
 
973,042

 
890,603

Less accumulated depreciation
 
(400,426
)
 
(337,889
)
Net property, plant, and equipment
 
572,616

 
552,714

Other assets:
 
 

 
 

Goodwill
 
188,159

 
189,604

Patents, trademarks and other intangible assets, net of accumulated amortization of $31,956 in 2013 and $27,044 in 2012
 
31,980

 
36,735

Deferred tax assets
 
2,170

 
594

Other assets
 
37,669

 
47,062

Total other assets
 
259,978

 
273,995

Total assets
 
$
1,206,533

 
$
1,261,818

 
See Notes to Consolidated Financial Statements

F-3


TETRA Technologies, Inc. and Subsidiaries
Consolidated Balance Sheets
(In Thousands, Except Share Amounts)
 
 
 
December 31,
2013
 
December 31,
2012
LIABILITIES AND EQUITY
 
 

 
 

Current liabilities:
 
 

 
 

Trade accounts payable
 
$
69,220

 
$
67,453

Accrued liabilities
 
65,017

 
73,254

Current portion of long-term debt
 
89

 
35,441

Decommissioning and other asset retirement obligations, net
 
38,700

 
80,667

Total current liabilities
 
173,026

 
256,815

Long-term debt, net
 
387,727

 
331,268

Deferred income taxes
 
17,651

 
41,910

Decommissioning and other asset retirement obligations, net
 
12,204

 
14,254

Other liabilities
 
18,427

 
24,263

Total long-term liabilities
 
436,009

 
411,695

Commitments and contingencies
 
 

 
 

Equity:
 
 

 
 

TETRA Stockholders' equity:
 
 

 
 

Common stock, par value $0.01 per share; 100,000,000 shares authorized; 81,333,631, shares issued at December 31, 2013, and 80,446,169 shares issued at December 31, 2012
 
813

 
804

Additional paid-in capital
 
234,360

 
226,954

Treasury stock, at cost; 2,478,084 shares held at December 31, 2013, and 2,334,137 shares held at December 31, 2012
 
(15,765
)
 
(15,027
)
Accumulated other comprehensive income (loss)
 
(3,903
)
 
(1,494
)
Retained earnings
 
340,036

 
339,883

Total TETRA stockholders' equity
 
555,541

 
551,120

Noncontrolling interests
 
41,957

 
42,188

Total equity
 
597,498

 
593,308

Total liabilities and equity
 
$
1,206,533

 
$
1,261,818

 
See Notes to Consolidated Financial Statements

F-4


TETRA Technologies, Inc. and Subsidiaries
Consolidated Statements of Operations
(In Thousands, Except Per Share Amounts)
 
 
 
Year Ended December 31,
 
 
2013
 
2012
 
2011
Revenues:
 
 

 
 

 
 

Product sales
 
$
300,145

 
$
276,155

 
$
329,489

Services and rentals
 
609,253

 
604,676

 
515,786

Total revenues
 
909,398

 
880,831

 
845,275

Cost of revenues:
 
 

 
 

 
 

Cost of product sales
 
282,704

 
242,297

 
306,953

Cost of services and rentals
 
400,739

 
387,047

 
338,703

Depreciation, depletion, amortization, and accretion
 
80,985

 
75,747

 
94,839

Impairments of long-lived assets
 
9,578

 
8,360

 
15,738

Total cost of revenues
 
774,006

 
713,451

 
756,233

Gross profit
 
135,392

 
167,380

 
89,042

General and administrative expense
 
131,466

 
131,649

 
111,805

Interest expense, net
 
17,121

 
17,080

 
16,439

(Gain) loss on sales of assets
 
(5,776
)
 
(4,916
)
 
(58,674
)
Other (income) expense, net
 
(7,291
)
 
(4,616
)
 
13,239

Income (loss) before taxes and discontinued operations
 
(128
)
 
28,183

 
6,233

Provision (benefit) for income taxes
 
(3,454
)
 
9,429

 
751

Income before discontinued operations
 
3,326

 
18,754

 
5,482

Discontinued operations:
 
 
 
 

 
 

Income (loss) from discontinued operations, net of taxes
 
(1
)
 
3

 
(64
)
Net income
 
3,325

 
18,757

 
5,418

Less: income attributable to noncontrolling interest
 
(3,172
)
 
(2,797
)
 
(1,271
)
Net income attributable to TETRA stockholders
 
$
153

 
$
15,960

 
$
4,147

Basic net income per common share:
 
 

 
 

 
 

Income before discontinued operations attributable to TETRA stockholders
 
$
0.00

 
$
0.21

 
$
0.05

Income (loss) from discontinued operations attributable to TETRA stockholders
 
—

 
—

 
—

Net income attributable to TETRA stockholders
 
$
0.00

 
$
0.21

 
$
0.05

Average shares outstanding
 
77,954

 
77,293

 
76,616

Diluted net income per common share:
 
 

 
 

 
 

Income before discontinued operations attributable to TETRA stockholders
 
$
0.00

 
$
0.20

 
$
0.05

Income (loss) from discontinued operations attributable to TETRA stockholders
 
—

 
—

 
—

Net income attributable to TETRA stockholders
 
$
0.00

 
$
0.20

 
$
0.05

Average diluted shares outstanding
 
78,840

 
77,963

 
77,991

 
See Notes to Consolidated Financial Statements

F-5


TETRA Technologies, Inc. and Subsidiaries
Consolidated Statements of Comprehensive Income (Loss)
(In Thousands)
 
 
 
Year Ended December 31,
 
 
2013
 
2012
 
2011
 
 
 
 
 
 
 
Net income
 
$
3,325

 
$
18,757

 
$
5,418

Foreign currency translation adjustment, net of taxes of $(1,076) in 2013, $(951) in 2012, and $(1,828) in 2011
 
(2,409
)
 
1,383

 
(6,647
)
Net change in derivative fair value, net of taxes of $1,578 in 2011
 
—

 
—

 
2,663

Comprehensive income
 
916

 
20,140

 
1,434

Less: comprehensive income attributable to noncontrolling interest
 
(3,172
)
 
(2,797
)
 
(1,271
)
Comprehensive income (loss) attributable to TETRA stockholders
 
$
(2,256
)
 
$
17,343

 
$
163

 
See Notes to Consolidated Financial Statements

F-6


TETRA Technologies, Inc. and Subsidiaries
Consolidated Statements of Equity
(In Thousands)
 
Common Stock
Par Value
 
Additional Paid-In
Capital
 
 
 
Accumulated Other 
Comprehensive Income (Loss)
 
 
 
 
 
 
 
 
 
Treasury
Stock
 
Derivative
Instruments
 
Currency
Translation
 
Retained
Earnings
 
Noncontrolling
Interest
 
Total
Equity
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Balance at December 31, 2010
$
778

 
$
203,044

 
$
(8,382
)
 
$
(2,663
)
 
$
3,770

 
$
319,776

 
$
—

 
$
516,323

Net income for 2011
 

 
 

 
 

 
 

 
 

 
4,147

 
1,271

 
5,418

Translation adjustment, net of taxes of $(1,828)
 

 
 

 
 

 
 

 
(6,647
)
 
 

 
 

 
(6,647
)
Net change in derivative fair value, net of taxes of $(1,578)
 

 
 

 
 

 
2,663

 
 

 
 

 
 

 
2,663

Comprehensive income
 

 
 

 
 

 
 

 
 

 
 

 
 

 
1,434

Issuance of Compressco Partners' common units, net of offering costs
 
 
 

 
 

 
 

 
 

 
 

 
42,177

 
42,177

Distributions to public unitholders
 

 
 

 
 

 
 

 
 

 
 

 
(1,182
)
 
(1,182
)
Exercise of common stock options
19

 
9,965

 
(5,803
)
 
 

 
 

 
 

 
 

 
4,181

Grants of restricted stock, net
 

 
 

 
(656
)
 
 

 
 

 
 

 
 

 
(656
)
Equity compensation expense
 

 
5,801

 
 

 
 

 
 

 
 

 
487

 
6,288

Other noncontrolling interests
 

 
 

 
 

 
 

 
 

 
 

 
(811
)
 
(811
)
Tax benefit related to equity-based compensation, net
 

 
1,334

 
 

 
 

 
 

 
 

 
 

 
1,334

Balance at December 31, 2011
$
797

 
$
220,144

 
$
(14,841
)
 
$
—

 
$
(2,877
)
 
$
323,923

 
$
41,942

 
$
569,088

Net income for 2012
 

 
 

 
 

 
 

 
 

 
15,960

 
2,797

 
18,757

Translation adjustment, net of taxes of $(951)
 

 
 

 
 

 
 

 
1,383

 
 

 
 

 
1,383

Comprehensive income
 

 
 

 
 

 
 

 
 

 
 

 
 

 
20,140

Distributions to public unitholders
 

 
 

 
 

 
 

 
 

 
 

 
(4,489
)
 
(4,489
)
Exercise of common stock options
7

 
943

 
(19
)
 
 

 
 

 
 

 
 

 
931

Grants of restricted stock, net
 

 
 

 
(167
)
 
 

 
 

 
 

 
 

 
(167
)
Equity compensation expense
 

 
7,536

 
 

 
 

 
 

 
 

 
1,905

 
9,441

Other noncontrolling interests
 

 
 

 
 

 
 

 
 

 
 

 
33

 
33

Tax benefit related to equity-based compensation, net
 

 
(1,669
)
 
 

 
 

 
 

 
 

 
 

 
(1,669
)
Balance at December 31, 2012
$
804

 
$
226,954

 
$
(15,027
)
 
$
—

 
$
(1,494
)
 
$
339,883

 
$
42,188

 
$
593,308

Net income for 2013
 

 
 

 
 

 
 

 
 

 
153

 
3,172

 
3,325

Translation adjustment, net of taxes of $(1,076)
 

 
 

 
 

 
 

 
(2,409
)
 
 

 
 

 
(2,409
)
Comprehensive income
 
 
 
 
 
 
 
 
 
 
 
 
 
 
916

Distributions to public unitholders
 

 
 

 
 

 
 

 
 

 
 

 
(4,846
)
 
(4,846
)
Exercise of common stock options
9

 
2,245

 
(276
)
 
 

 
 

 
 

 
 

 
1,978

Grants of restricted stock, net
 

 
 

 
(462
)
 
 

 
 

 
 

 
 

 
(462
)
Equity compensation expense
 

 
5,265

 
 

 
 

 
 

 
 

 
1,459

 
6,724

Other noncontrolling interests
 

 
 

 
 

 
 

 
 

 
 

 
(16
)
 
(16
)
Tax adjustment related to equity- based compensation, net
 

 
(104
)
 
 

 
 

 
 

 
 

 
 

 
(104
)
Balance at December 31, 2013
$
813

 
$
234,360

 
$
(15,765
)
 
$
—

 
$
(3,903
)
 
$
340,036

 
$
41,957

 
$
597,498

 
See Notes to Consolidated Financial Statements

F-7


TETRA Technologies, Inc. and Subsidiaries
Consolidated Statements of Cash Flows
(In Thousands)
 
 
Year Ended December 31,
 
 
2013
 
2012
 
2011
Operating activities:
 
 

 
 

 
 

Net income
 
$
3,325

 
$
18,757

 
$
5,418

Reconciliation of net income to cash provided by operating activities:
 
 

 
 

 
 

Depreciation, depletion, amortization, and accretion
 
80,985

 
75,747

 
94,839

Impairments of long-lived assets
 
9,578

 
8,360

 
15,738

Provision (benefit) for deferred income taxes
 
(9,824
)
 
(2,012
)
 
(5,757
)
Equity-based compensation expense
 
6,724

 
9,441

 
6,288

Provision for doubtful accounts
 
374

 
(237
)
 
973

(Gain) loss on sale of property, plant, and equipment
 
(5,776
)
 
(4,916
)
 
(58,674
)
Excess decommissioning/abandoning costs
 
75,312

 
40,767

 
78,382

Other non-cash charges and credits
 
(10,165
)
 
(6,527
)
 
(6,149
)
Changes in operating assets and liabilities, net of assets acquired: 
 
 
 
 

 
 

Accounts receivable
 
14,139

 
(31,229
)
 
16,129

Inventories
 
3,011

 
(3,749
)
 
2,158

Prepaid expenses and other current assets
 
12,281

 
(1,335
)
 
23,447

Trade accounts payable and accrued expenses
 
(16,192
)
 
7,291

 
(29,984
)
Decommissioning liabilities
 
(114,109
)
 
(94,419
)
 
(101,920
)
Other
 
(7
)
 
1,730

 
2,899

Net cash provided by operating activities
 
49,656

 
17,669

 
43,787

Investing activities:
 
 

 
 

 
 

Purchases of property, plant, and equipment
 
(101,379
)
 
(107,524
)
 
(123,604
)
Business combinations, net of cash acquired
 
—

 
(163,305
)
 
(1,500
)
Proceeds from sale of property, plant, and equipment
 
1,794

 
59,325

 
188,273

Other investing activities
 
(440
)
 
4,817

 
(16,330
)
Net cash provided by (used in) investing activities
 
(100,025
)
 
(206,687
)
 
46,839

Financing activities:
 
 

 
 

 
 

Proceeds from long-term debt
 
140,971

 
88,426

 
—

Principal payments on long-term debt
 
(120,664
)
 
(28,597
)
 
—

Excess tax benefit from equity-based compensation
 
—

 
198

 
1,334

Proceeds from issuance of Compressco Partners' common units, net of underwriters' discount
 
—

 
—

 
50,234

Compressco Partners' offering costs
 
—

 
—

 
(2,747
)
Compressco Partners' distributions
 
(4,846
)
 
(4,513
)
 
(1,159
)
Proceeds from sale of common stock and exercise of stock options
 
2,251

 
784

 
3,418

Other financing activities
 
(1,978
)
 
—

 
(347
)
Net cash provided by (used in) financing activities
 
15,734

 
56,298

 
50,733

Effect of exchange rate changes on cash
 
(659
)
 
2,356

 
(2,307
)
Increase (decrease) in cash and cash equivalents
 
(35,294
)
 
(130,364
)
 
139,052

Cash and cash equivalents at beginning of period
 
74,048

 
204,412

 
65,360

Cash and cash equivalents at end of period
 
$
38,754

 
$
74,048

 
$
204,412

Supplemental cash flow information:
 
 

 
 

 
 

Interest paid
 
$
17,728

 
$
18,711

 
$
18,145

Taxes paid (refunded)
 
7,438

 
8,020

 
(12,649
)
Supplemental disclosure of non-cash investing and financing activities:
 
 

 
 

 
 

Adjustment of fair value of decommissioning liabilities capitalized to oil and gas properties
 
$
—

 
$
—

 
$
1,804

 

See Notes to Consolidated Financial Statements

F-8


TETRA Technologies, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
December 31, 2013
NOTE A – ORGANIZATION AND OPERATIONS
 
We are geographically diversified oil and gas services company, focused on completion fluids and associated products and services, water management, after-frac flow back, production well testing, offshore rig cooling, compression-based production enhancement, and selected offshore services including well plugging and abandonment, decommissioning, and diving. We also have a limited domestic oil and gas production business. We were incorporated in Delaware in 1981 and are composed of five reporting segments organized into three divisions – Fluids, Production Enhancement, and Offshore. Unless the context requires otherwise, when we refer to “we,” “us,” and “our,” we are describing TETRA Technologies, Inc. and its consolidated subsidiaries on a consolidated basis.
 
Our 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 North American onshore oil and gas operators with comprehensive water management services.
 
Our Production Enhancement Division consists of two operating segments: Production Testing and Compressco. The Production Testing segment provides after-frac flow back, production well testing, offshore rig cooling, and other associated services in many of the major oil and gas producing basins in the United States, Mexico and Canada, as well as in certain basins in certain regions in South America, Africa, Europe, the Middle East, and Australia.
 
The Compressco segment provides compression-based production enhancement services, which are used in both conventional wellhead compression applications and unconventional compression applications, and, in certain circumstances, well monitoring and sand separation services. The Compressco segment provides these services throughout many of the onshore oil and gas producing regions of the United States, as well as certain basins in Mexico, Canada, and certain countries in South America, Europe, and the Asia-Pacific region. Beginning June 20, 2011, following the initial public offering of Compressco Partners, L.P. (Compressco Partners), we allocate and charge certain corporate and divisional direct and indirect administrative costs to Compressco Partners.
 
Our Offshore Division consists of two operating segments: Offshore Services and Maritech. The Offshore Services segment provides (1) downhole and subsea services such 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 air diving services.
 
The Maritech segment is 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 consist primarily of the ongoing abandonment and decommissioning associated with its remaining offshore wells and production platforms. Maritech intends to acquire a significant portion of the services necessary to abandon and decommission these properties from the Offshore Division’s Offshore Services segment.
NOTE B – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
 
Principles of Consolidation
 
The consolidated financial statements include the accounts of our wholly owned subsidiaries. Investments in unconsolidated joint ventures in which we participate are accounted for using the equity method. Our interests in oil and gas properties are proportionately consolidated. All significant intercompany accounts and transactions have been eliminated in consolidation.


F-9


Use of Estimates
 
The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclose contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
 
Reclassifications
 
Beginning with the three month period ended September 30, 2013, certain ad valorem tax expenses for operating equipment of our Compressco segment have been reclassified as cost of revenues instead of being included in general and administrative expense as reported in prior periods. Prior period amounts have been reclassified to conform to the current year period's presentation. The amount of such reclassification is $1.5 million and $1.5 million for the year ended December 31, 2012 and 2011, respectively.

Certain other previously reported financial information has been reclassified to conform to the current year's presentation. The impact of such reclassifications was not significant to the prior year's overall presentation.
 
Cash Equivalents
 
We consider all highly liquid cash investments, with a maturity of three months or less when purchased, to be cash equivalents.
 
Restricted Cash
 
Restricted cash is classified as a current asset when it is expected to be repaid or settled in the next twelve month period. Restricted cash reported on our balance sheet as of December 31, 2013, consists primarily of escrowed cash associated with our July 2011 purchase of a heavy lift derrick barge. The escrowed cash will be released to the sellers in accordance with the terms of the escrow agreement.
 
Financial Instruments
 
Financial instruments that subject us to concentrations of credit risk consist principally of trade receivables with companies in the energy industry. Our policy is to evaluate, prior to providing goods or services, each customer's financial condition and to determine the amount of open credit to be extended. We generally require appropriate, additional collateral as security for credit amounts in excess of approved limits. Our customers consist primarily of major, well-established oil and gas producers and independent oil and gas companies. Prior to April 2011, our risk management activities involved the use of derivative financial instruments, such as oil and gas swap contracts, to hedge the impact of commodity market price risk exposures related to a portion of our oil and gas production cash flow. All of our oil and gas swap contracts were liquidated in April 2011 in connection with the sales of Maritech oil and gas producing properties.
 
We have currency exchange rate risk exposure related to transactions denominated in a foreign currency as well as to investments in certain of our international operations. Beginning in 2013, our risk management activities include the use of foreign currency forward purchase and sale derivative contracts as part of a program designed to mitigate the currency exchange rate risk exposure on selected international operations.

As a result of the outstanding balances under our variable rate revolving credit facilities, we face market risk exposure related to changes in applicable interest rates. Although we have no interest rate swap contracts outstanding to hedge this potential risk exposure, we have entered into certain fixed interest rate notes, which are scheduled to mature at various dates from 2015 through 2020 and which mitigate this risk on our total outstanding borrowings.
 
Allowances for Doubtful Accounts
 
Allowances for doubtful accounts are determined generally and on a specific identification basis when we believe that the collection of specific amounts owed to us is not probable. The changes in allowances for doubtful accounts for the three year period ended December 31, 2013, are as follows:

F-10


 
 
Year Ended December 31,
 
 
2013
 
2012
 
2011
 
 
(In Thousands)
At beginning of period
 
$
1,085

 
$
1,849

 
$
2,590

Activity in the period:
 
 

 
 

 
 

Provision for doubtful accounts
 
374

 
(237
)
 
973

Account chargeoffs
 
(110
)
 
(527
)
 
(1,714
)
At end of period
 
$
1,349

 
$
1,085

 
$
1,849


Inventories

Inventories are stated at the lower of cost or market value and consist primarily of finished goods. Cost is determined using the weighted average method. Significant components of inventories as of December 31, 2013, and December 31, 2012, are as follows:
 
 
December 31,
 
 
2013
 
2012
 
 
(In Thousands)
Finished goods
 
$
73,515

 
$
72,312

Raw materials
 
3,894

 
5,396

Parts and supplies
 
22,668

 
24,497

Work in progress
 
715

 
836

Total inventories
 
$
100,792

 
$
103,041

 
Finished goods inventories include newly manufactured clear brine fluids as well as recycled brines that are repurchased from certain customers. Recycled brines are recorded at cost, using the weighted average method. We provide a reserve for estimated unrealizable inventory equal to the difference between the cost of the inventory and its estimated realizable value.
 
Assets Held for Sale
 
Assets are classified as held for sale when, among other factors, they are identified and marketed for sale in their present condition, management is committed to their disposal, and the sale of the asset is probable within one year. Assets Held for Sale as of December 31, 2013, consists primarily of the estimated fair value of a heavy lift barge from our Offshore Services segment that was reclassified to Assets Held for Sale during late 2012 and was sold in January 2014. In addition, Assets Held for Sale as of December 31, 2013, includes the carrying value of an international Production Testing facility location that was reclassified during 2013.
 
Property, Plant, and Equipment
 
Property, plant, and equipment are stated at the cost of assets acquired. Expenditures that increase the useful lives of assets are capitalized. The cost of repairs and maintenance is charged to operations as incurred. For financial reporting purposes, we provide for depreciation using the straight-line method over the estimated useful lives of assets, which are generally as follows:
Buildings
 
15 – 40 years
Barges and vessels
 
5 – 30 years
Machinery and equipment
 
2 – 20 years
Automobiles and trucks
 
4 years
Chemical plants
 
15 – 30 years
 
Leasehold improvements are depreciated over the shorter of the remaining term of the associated lease or its useful life. Prior to being reclassified to assets held for sale in June 2011, oil and gas property leasehold costs were depleted on a unit of production method based on the estimated remaining equivalent proved oil and gas

F-11


reserves of each field. Oil and gas property well costs were depleted on a unit of production method based on the estimated remaining equivalent proved developed oil and gas reserves of each field. Depreciation and depletion expense, excluding long-lived asset impairments and dry hole costs, for the years ended December 31, 2013, 2012, and 2011 was $76.9 million, $70.7 million, and $87.7 million, respectively.

In December 2012, we sold our corporate headquarters facility pursuant to a sale and leaseback transaction. For further discussion of the terms of this transaction, see Note E – Leases.
 
Interest capitalized for the years ended December 31, 2013, 2012, and 2011 was $1.6 million, $2.0 million, and $1.2 million, respectively.
 
Intangible Assets other than Goodwill
 
Patents, trademarks, and other intangible assets are recorded on the basis of cost and are amortized on a straight-line basis over their estimated useful lives, ranging from 3 to 20 years. During 2012, as part of three acquisitions consummated during the year, we acquired intangible assets having a fair value of approximately $27.3 million with estimated useful lives ranging from 3 to 20 years (having a weighted average useful life of 12.1 years). During 2011, as a part of an acquisition consummated during the year, we acquired intangible assets having a fair value of approximately $1.4 million with estimated useful lives ranging from 3 to 6 years (having a weighted average useful life of 5.6 years). Amortization expense of patents, trademarks, and other intangible assets was $5.0 million, $4.5 million, and $2.8 million for the twelve months ended December 31, 2013, 2012, and 2011, respectively, and is included in depreciation, depletion, amortization and accretion. The estimated future annual amortization expense of patents, trademarks, and other intangible assets is $3.7 million for 2014, $3.4 million for 2015, $3.2 million for 2016, $3.0 million for 2017, and $2.9 million for 2018.
 
Goodwill
 
Goodwill represents the excess of cost over the fair value of the net assets of businesses acquired in purchase transactions. We perform a goodwill impairment test on an annual basis or whenever indicators of impairment are present. We perform the annual test of goodwill impairment following the fourth quarter of each year. The annual 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 it was not “more likely than not” that the fair values of any of our reporting units were less than their carrying values as of December 31, 2013. If 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 would consist of a two-step accounting test performed on a reporting unit basis. For purposes of this impairment test, the reporting units are our five reporting segments: Fluids, Production Testing, Compressco, Offshore Services, and Maritech. The first step of the impairment test, if required, is to compare the estimated fair value of any reporting units that have recorded goodwill with the recorded net book value (including goodwill) of the reporting unit. If the estimated fair value of the reporting unit is higher than the recorded net book value, no impairment is deemed to exist and no further testing is required. If, however, the estimated fair value of the reporting unit is below the recorded net book value, then a second step must be performed to determine the goodwill impairment required, if any. In this second step, the estimated fair value from the first step is used as the purchase price in a hypothetical acquisition of the reporting unit. Purchase business combination accounting rules are followed to determine a hypothetical purchase price allocation to the reporting unit’s assets and liabilities. The residual amount of goodwill that results from this hypothetical purchase price allocation is compared to the recorded amount of goodwill for the reporting unit, and the recorded amount is written down to the hypothetical amount, if lower.
 
Because quoted market prices for our reporting units are not available, management must apply judgment in determining the estimated fair value of these reporting units for purposes of performing the goodwill impairment test. Management uses all available information to make these fair value determinations, including the present value of expected future cash flows using discount rates commensurate with the risks involved in the assets. The resultant fair values calculated for the reporting units are then compared to observable metrics for other companies in our industry or on mergers and acquisitions in our industry, to determine whether those valuations, in our judgment, appear reasonable.
 

F-12


The carrying amount of goodwill for the Fluids and Offshore Services reporting units are net of $23.9 million and $23.2 million, respectively, of accumulated impairment losses. The changes in the carrying amount of goodwill by reporting unit for the three year period ended December 31, 2013, are as follows:
 
 
Fluids
 
Production Testing
 
Compressco
 
Offshore Services
 
Maritech
 
Total
 
 
(In Thousands)
Balance as of December 31, 2010
 
$
—

 
$
23,035

 
$
72,161

 
$
3,809

 
$
—

 
$
99,005

Goodwill adjustments
 
—

 
—

 
—

 
127

 
—

 
127

Balance as of December 31, 2011
 
—

 
23,035

 
72,161

 
3,936

 
—

 
99,132

Goodwill acquired during the year
 
—

 
90,472

 
—

 
—

 
—

 
90,472

Balance as of December 31, 2012
 
—

 
113,507

 
72,161

 
3,936

 
—

 
189,604

Goodwill adjustments
 
—

 
(1,445
)
 
—

 
—

 
—

 
(1,445
)
Balance as of December 31, 2013
 
$
—

 
$
112,062

 
$
72,161

 
$
3,936

 
$
—

 
$
188,159

 
Impairment of Long-Lived Assets
 
Impairments of long-lived assets are determined periodically when indicators of impairment are present. If such indicators are present, the determination of the amount of impairment is based on our judgments as to the future undiscounted operating cash flows to be generated from these assets throughout their remaining estimated useful lives. If these undiscounted cash flows are less than the carrying amount of the related asset, an impairment is recognized for the excess of the carrying value over its fair value. The assessment of oil and gas properties for impairment is based on the risk adjusted future estimated cash flows from our proved, probable, and possible reserves. Assets held for disposal are recorded at the lower of carrying value or estimated fair value less estimated selling costs.
 
During the fourth quarter of 2012, the Offshore Services segment began pursuing the sale of the TETRA DB-1 heavy lift barge due to decreased demand in the shallow waters of the Outer Continental Shelf of the Gulf of Mexico, where it historically operated. In connection with this decision, an impairment of approximately $7.7 million was recorded to reduce the carrying value of the TETRA DB-1 to its estimated fair value, less estimated cost to sell.

During the first quarter of 2014, the Offshore Services segment sold the TETRA DB-1 heavy lift barge for a sales price of $3.0 million. As a result, an additional impairment of approximately $9.3 million was recorded in December 2013 to reduce the carrying value of the TETRA DB-1 to the sales price.
 
Impairments of Oil and Gas Properties
 
During 2011, we identified impairments totaling approximately $15.2 million, net of intercompany eliminations, of the net carrying value of certain Maritech oil and gas properties. The oil and gas property impairments during 2011 were primarily associated with Maritech’s plans to sell its remaining oil and gas producing properties and the reduction in their carrying values to fair value less cost to sell.  
 
Decommissioning Liabilities
 
Related to Maritech’s remaining oil and gas property decommissioning liabilities, we estimate the third-party fair values (including an estimated profit) to plug and abandon wells, decommission the pipelines and platforms, and clear the sites, and we use these estimates to record Maritech’s decommissioning liabilities, net of amounts allocable to joint interest owners, and any amounts contractually agreed to be paid in the future by the previous owners of the properties. In some cases, previous owners of acquired oil and gas properties are
contractually obligated to pay Maritech a fixed amount for the future well abandonment and decommissioning work on these properties as such work is performed. As of December 31, 2013 and 2012, our Maritech subsidiary’s decommissioning liabilities were net of approximately $0.0 million and $7.0 million, respectively, of such future reimbursements from these previous owners.
 
In estimating the decommissioning liabilities, we perform detailed estimating procedures, analysis, and engineering studies. Whenever practical and cost effective, Maritech will utilize the services of its affiliated companies to perform well abandonment and decommissioning work. When these services are performed by an

F-13


affiliated company, all recorded intercompany revenues are eliminated in the consolidated financial statements. The recorded decommissioning liability associated with a specific property is fully extinguished when the property is completely abandoned. The liability is first reduced by all cash expenses incurred to abandon and decommission the property. If the liability exceeds (or is less than) our actual out-of-pocket costs, the difference is credited (or charged) to earnings in the period in which the work is performed. We review the adequacy of our decommissioning liabilities whenever indicators suggest that the estimated cash flows underlying the liabilities have changed materially. The timing and amounts of these cash flows are subject to changes in the energy industry environment and may result in additional liabilities to be recorded, which, in turn, would increase the carrying values of the related properties or result in direct charges to earnings. Primarily as a result of decommissioning work performed, we recorded total reductions to the decommissioning liabilities for the years 2013, 2012, and 2011 of $119.6 million, $87.4 million, and $94.7 million, respectively. For a further discussion of adjustments and other activity related to Maritech’s decommissioning liabilities, including significant adjustments made during 2013, 2012, and 2011, see Note I – Decommissioning and Other Asset Retirement Obligations.
 
Environmental Liabilities
 
Environmental expenditures that result in additions to property and equipment are capitalized, while other environmental expenditures are expensed. Environmental remediation liabilities are recorded on an undiscounted basis when environmental assessments or cleanups are probable and the costs can be reasonably estimated. Estimates of future environmental remediation expenditures often consist of a range of possible expenditure amounts, a portion of which may be in excess of amounts of liabilities recorded. In such an instance, we disclose the full range of amounts reasonably possible of being incurred. Any changes or developments in environmental remediation efforts are accounted for and disclosed each quarter as they occur. Any recoveries of environmental remediation costs from other parties are recorded as assets when their receipt is deemed probable.
 
Complexities involving environmental remediation efforts can cause estimates of the associated liability to be imprecise. Factors that cause uncertainties regarding the estimation of future expenditures include, but are not limited to, the effectiveness of the anticipated work plans in achieving targeted results and changes in the desired remediation methods and outcomes as prescribed by regulatory agencies. Uncertainties associated with environmental remediation contingencies are pervasive and often result in wide ranges of reasonably possible outcomes. Estimates developed in the early stages of remediation can vary significantly. Normally, a finite estimate of cost does not become fixed and determinable at a specific point in time. Rather, the costs associated with environmental remediation become estimable as the work is performed and the range of ultimate cost becomes more defined. It is possible that cash flows and results of operations could be materially affected by the impact of the ultimate resolution of these contingencies.
 
Revenue Recognition
 
Revenues are recognized when finished products are shipped or services have been provided to unaffiliated customers and only when collectability is reasonably assured. Sales terms for our products are FOB shipping point, with title transferring at the point of shipment. Revenue is recognized at the point of transfer of title. We recognize oil and gas product sales revenues from our Maritech subsidiary’s interests in producing wells as oil and gas is produced and sold from those wells. Oil and gas sold is not significantly different from Maritech’s share of production. With regard to longer-term lump-sum contracts, revenues are recognized using the percentage-of-completion method based on the ratio of costs incurred to total estimated costs at completion. Total project revenue and cost estimates for lump-sum contracts are reviewed periodically as work progresses, and adjustments are reflected in the period in which such estimates are revised. Provisions for estimated losses on such contracts are made in the period such losses are determined. Occasionally we have contracts that contain multiple deliverables, and for such contracts the recognition of revenue is determined based on the realized market values received by the customer as well as the timing of collections under the contract.
Operating Costs
 
Cost of product sales includes direct and indirect costs of manufacturing and producing our products, including raw materials, fuel, utilities, labor, overhead, repairs and maintenance, materials, services, transportation, warehousing, equipment rentals, insurance, and taxes. In addition, cost of product sales includes oil and gas operating expense. Cost of services and rentals includes operating expenses we incur in delivering our services, including labor, equipment rental, fuel, repair and maintenance, transportation, overhead, insurance, and certain

F-14


taxes. We include in product sales revenues the reimbursements we receive from customers for shipping and handling costs. Shipping and handling costs are included in cost of product sales. Amounts we incur for “out-of-pocket” expenses in the delivery of our services are recorded as cost of services and rentals. Reimbursements for “out-of-pocket” expenses we incur in the delivery of our services are recorded as service revenues. Depreciation, depletion, amortization, and accretion includes depreciation expense for all of our facilities, equipment and vehicles, depletion and dry hole expense on our oil and gas properties, amortization expense on our intangible assets, and accretion expense related to our decommissioning and other asset retirement obligations.
 
We include in general and administrative expense all costs not identifiable to our specific product or service operations, including divisional and general corporate overhead, professional services, corporate office costs, sales and marketing expenses, insurance, and taxes.
 
Repair Costs and Insurance Recoveries
 
Our Maritech subsidiary incurred significant damage to the majority of its offshore oil and gas producing platforms as a result of Hurricane Ike during 2008 and Hurricanes Katrina and Rita during 2005. This damage included the destruction of six of its offshore platforms. Hurricane damage response efforts consist of (1) the assessment and repair of damaged facilities and equipment; (2) the well intervention, abandonment, decommissioning, and debris removal associated with destroyed offshore platforms; and (3) the construction of replacement platforms and facilities and the redrilling of destroyed wells. The cost to repair and restore damaged assets, including the cost for damage assessment, is expensed as incurred. The estimated cost of expected well intervention, abandonment, decommissioning, and debris removal efforts associated with destroyed offshore platforms is accounted for as part of Maritech’s decommissioning liabilities. The cost to replace destroyed platforms and facilities and redrill destroyed wells is capitalized as incurred as part of oil and gas properties. Subsequent to these storms, Maritech has substantially completed the required hurricane damage response efforts, and, as of December 31, 2013, the remaining work to be performed consists primarily of decommissioning and debris removal efforts on three of the destroyed platforms. We estimate that the remaining future decommissioning and debris removal efforts associated with these remaining platforms will cost approximately $7.7 million, net to our interest, and has been accrued as part of Maritech’s decommissioning liabilities. Actual hurricane response costs could exceed these estimates and, depending on the nature of the cost, could result in significant charges to earnings in future periods.
 
When it is economical to purchase, we typically maintain insurance protection that we believe to be customary and in amounts sufficient to reimburse us for a majority of our casualty losses. Our insurance coverage is subject to certain overall coverage limits and deductibles. With regard to costs incurred that we believe will qualify for coverage under our various insurance policies, we recognize anticipated insurance recoveries when collection is deemed probable. Any recognition of anticipated insurance recoveries is used to offset the original charge to which the insurance recovery relates. The amount of anticipated insurance recoveries as of December 31, 2013 and 2012, is included in accounts receivable in the accompanying consolidated balance sheets. Anticipated insurance recoveries that have been reflected as insurance receivables were $0 million as of December 31, 2013, and $1.1 million at December 31, 2012.
 
During December 2010, we initiated legal proceedings against one of Maritech’s underwriters that had disputed that certain hurricane damage related costs incurred or to be incurred qualified as covered costs pursuant to Maritech's windstorm insurance policies. In February 2013, we entered into a settlement agreement with the underwriter, whereby we received $7.6 million, a portion of which was credited to operating expenses during the year ended December 31, 2013
 
Repair costs incurred and the net book value of any destroyed assets which are covered under our insurance policies are anticipated insurance recoveries which are included in accounts receivable. Repair costs not considered probable of collection are charged to earnings. Insurance recoveries in excess of destroyed asset carrying values and repair costs incurred are credited to earnings when received.
 
Discontinued Operations
 
We account for our discontinued businesses as discontinued operations and reclassify prior period financial statements to exclude these businesses from continuing operations.
 

F-15


Income Taxes
 
Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis amounts. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect of a change in tax rates is recognized as income or expense in the period that includes the enactment date.
 
Income (Loss) per Common Share
 
The calculation of basic earnings per share excludes any dilutive effects of options. The calculation of diluted earnings per share includes the dilutive effect of stock options, which is computed using the treasury stock method during the periods such options were outstanding. A reconciliation of the common shares used in the computations of income (loss) per common and common equivalent shares is presented in Note P – Income (Loss) Per Share.
 
Foreign Currency Translation
 
We have designated the euro, the British pound, the Norwegian krone, the Canadian dollar, the Brazilian real, and the Mexican peso as the functional currency for our operations in Finland and Sweden, the United Kingdom, Norway, Canada, Brazil, and certain of our operations in Mexico, respectively. The U.S. dollar is the designated functional currency for all of our other foreign operations. The cumulative translation effects of translating the accounts from the functional currencies into the U.S. dollar at current exchange rates are included as a separate component of equity.
 
Fair Value Measurements
 
Fair value is defined as “the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date” within an entity’s principal market, if any. The principal market is the market in which the reporting entity would sell the asset or transfer the liability with the greatest volume and level of activity, regardless of whether it is the market in which the entity will ultimately transact for a particular asset or liability or if a different market is potentially more advantageous. Accordingly, this exit price concept may result in a fair value that may differ from the transaction price or market price of the asset or liability.
 
Under generally accepted accounting principles, the fair value hierarchy prioritizes inputs to valuation techniques used to measure fair value. Fair value measurements should maximize the use of observable inputs and minimize the use of unobservable inputs, where possible. Observable inputs are developed based on market data obtained from sources independent of the reporting entity. Unobservable inputs may be needed to measure fair value in situations where there is little or no market activity for the asset or liability at the measurement date and are developed based on the best information available in the circumstances, which could include the reporting entity’s own judgments about the assumptions market participants would utilize in pricing the asset or liability.
We utilize fair value measurements to account for certain items and account balances within our consolidated financial statements. Fair value measurements are utilized in the allocation of purchase consideration for acquisition transactions to the assets and liabilities acquired, including intangible assets and goodwill. In addition, we utilize fair value measurements in the initial recording of our decommissioning and other asset retirement obligations. Fair value measurements may also be utilized on a nonrecurring basis, such as for the impairment of long-lived assets, including goodwill. The fair value of our financial instruments, which may include cash, temporary investments, accounts receivable, short-term borrowings, and long-term debt pursuant to our bank credit agreement, approximate their carrying amounts. The fair value of our long-term Senior Notes at December 31, 2013 and 2012, was approximately $318.4 million and $327.4 million, respectively, compared to a carrying amount of approximately $305.0 million, as current rates as of those dates were more favorable than the Senior Note interest rates. We calculate the fair value of our Senior Notes internally, using current market conditions and average cost of debt (a Level 2 fair value measurement).
We also utilize fair value measurements on a recurring basis in the accounting for our foreign currency forward sale derivative contracts. For these fair value measurements, we utilize the quoted value as determined by our counterparty financial institution (a Level 1 measurement). A summary of these fair value measurements as of December 31, 2013, is as follows:

F-16


 
 
 
 
Fair Value Measurements Using
 
 
Total as of
 
Quoted Prices
in Active
Markets for
Identical
Assets
or Liabilities
 
Significant
Other
Observable
Inputs
 
Significant
Unobservable
Inputs
Description
 
Dec 31, 2013
 
(Level 1)
 
(Level 2)
 
(Level 3)
 
 
(In Thousands)
Asset for foreign currency derivative contracts
 
$
104

 
$
104

 
—

 
—

Liability for foreign currency derivative contracts
 
(52
)
 
(52
)
 
—

 
—

Total
 
$
52

 


 

 


During 2013 and 2012, our Offshore Services segment recorded total impairment charges of approximately $9.3 million and $8.4 million, respectively, primarily associated with the decision to sell a heavy lift derrick barge, the TETRA DB-1. Accordingly, the carrying value of this vessel was adjusted to estimated fair value less estimated cost to sell, and reclassified as Assets Held for Sale. The fair value is estimated based on current market prices being received for similar vessels, which is based on significant unobservable inputs (Level 3) in accordance with the fair value hierarchy. A summary of these nonrecurring fair value measurements as of December 31, 2013, using the fair value hierarchy is as follows:
 
 
 
 
Fair Value Measurements Using
 
 
 
 
Total as of
 
Quoted Prices
in Active
Markets for
Identical
Assets
or Liabilities
 
Significant
Other
Observable
Inputs
 
Significant
Unobservable
Inputs
 
Year-to-Date
Impairment
Description
 
Dec 31, 2013
 
(Level 1)
 
(Level 2)
 
(Level 3)
 
Losses
 
 
(In Thousands)
Offshore Services assets
 
$
3,000

 
$
—

 
$
—

 
$
3,000

 
$
9,285

Other
 
—

 
—

 
—

 
—

 
293

Total
 
$
3,000

 

 

 

 
$
9,578


A summary of these nonrecurring fair value measurements as of December 31, 2012, using the fair value hierarchy is as follows:
 
 
 
 
Fair Value Measurements Using
 
 
 
 
Total as of
 
Quoted Prices
in Active
Markets for
Identical
Assets
or Liabilities
 
Significant
Other
Observable
Inputs
 
Significant
Unobservable
Inputs
 
Year-to-Date
Impairment
Description
 
Dec 31, 2012
 
(Level 1)
 
(Level 2)
 
(Level 3)
 
Losses
 
 
(In Thousands)
Offshore Services assets
 
$
14,000

 
$
—

 
$
—

 
$
14,000

 
$
8,360

New Accounting Pronouncements
 
In June 2011, the Financial Accounting Standards Board (FASB) published Accounting Standards Update (ASU) 2011-05, “Comprehensive Income (Topic 220), Presentation of Comprehensive Income” (ASU 2011-05), with the stated objective of improving the comparability, consistency, and transparency of financial reporting and increasing the prominence of items reported in other comprehensive income. As part of ASU 2011-05, the FASB eliminated the option to present components of other comprehensive income as part of the statement of changes in stockholders’ equity. The ASU 2011-05 amendments require that all non-owner changes in stockholders’ equity be presented either in a single continuous statement of comprehensive income or in two separate but consecutive statements. The ASU 2011-05 amendments are effective for fiscal years, and interim periods within those years,

F-17


beginning after December 15, 2011, and the amendments are applied retrospectively. In December 2011, with the issuance of ASU 2011-12, “Deferral of the Effective Date for Amendments to the Presentation of Reclassifications of Items Out of Accumulated Other Comprehensive Income in Accounting Standards Update No. 2011-05,” the FASB announced that it has deferred certain aspects of ASU 2011-05. In February 2013, the FASB issued ASU 2013-2, “Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income,” with the stated objective of improving the reporting of reclassifications out of accumulated other comprehensive income. The amendments in ASU 2013-2 are effective during interim and annual periods beginning after December 31, 2012. The adoption of ASU 2011-05, 2011-12 and 2013-2 regarding comprehensive income have not had a significant impact on the accounting or disclosures in our financial statements. 
 
In December 2011, the FASB published ASU 2011-11, “Balance Sheet (Topic 210), Disclosures about Offsetting Assets and Liabilities” (ASU 2011-11), which requires an entity to disclose the nature of its rights of setoff and related arrangements associated with its financial instruments and derivative instruments. The objective of ASU 2011-11 is to make financial statements that are prepared under U.S. generally accepted accounting principles more comparable to those prepared under International Financial Reporting Standards. The new disclosures will give financial statement users information about both gross and net exposures. In January 2013, the FASB published ASU 2013-01, “Balance Sheet (Topic 210), Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities” (ASU 2013-01), with the stated objective of clarifying the scope of offsetting disclosures and address any unintended consequences of ASU 2011-11. ASU 2011-11 and ASU 2013-01 are effective for interim and annual reporting period beginning after January 1, 2013 and will be applied on a retrospective basis. The adoption of ASU 2011-11 and ASU 2013-01 did not have a material impact on our financial condition, results of operations, or liquidity.

In July 2013, the FASB published ASU No. 2013-11, "Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists" (ASU 2013-11). The amendments in this ASU provide guidance on presentation of unrecognized tax benefits and are expected to reduce diversity in practice and better reflect the manner in which an entity would settle at the reporting date any additional income taxes that would result from the disallowance of a tax position when net operating loss carryforwards, similar tax losses, or tax credit carryforwards exist. The amendments in this ASU are effective prospectively for interim and annual periods beginning after December 15, 2013, with early adoption and retrospective application permitted. We do not expect the adoption of this standard to have a material impact on our consolidated financial statements.
NOTE C — COMPRESSCO PARTNERS, L.P. INITIAL PUBLIC OFFERING
 
On June 20, 2011, our Compressco Partners subsidiary completed its initial public offering of 2,670,000 common units (representing a 17.3% limited partner interest) in exchange for $53.4 million of gross proceeds (the Offering). Following the issuance of an additional 400,500 units to us in July 2011 as a result of the expiration of an underwriters’ option to purchase additional common units, our ownership in Compressco Partners was increased to 83.2%, including common units, subordinated units, and a 2.0% general partner interest. In connection with the Offering, certain of our wholly owned subsidiaries, including Compressco Partners GP Inc. (the General Partner), contributed substantially all of our Compressco segment’s wellhead compression-based production enhancement service business, operations, and related assets and liabilities to Compressco Partners and its wholly owned subsidiaries. In exchange, including the additional units issued in July 2011, Compressco Partners issued to us 6,427,257 common units (representing a 40.6% limited partner interest), 6,273,970 subordinated units (representing a 39.6% limited partner interests), an aggregate 2.0% general partner interest, and incentive distribution rights. Also, certain directors, executive officers, and other employees of the General Partner were then issued 157,870 restricted units (representing a 1.0% limited partner interest) granted pursuant to a long-term incentive plan. The issuance of the 2,670,000 common units in the Offering at a $20 per unit Offering Price resulted in Compressco Partners receiving $53.4 million of gross proceeds, $32.2 million of which was distributed to us to repay an intercompany loan balance. Approximately $11.2 million of the Offering proceeds was used to satisfy Offering expenses, including underwriters’ discount and approximately $8.0 million that was paid to us by Compressco Partners to reimburse us for costs we incurred on their behalf. The contribution transactions described above represent transactions between entities under common control. Consequently, the contributed assets were recorded at our carrying value.
The contributions of the majority of the operations and related assets and liabilities of our Compressco segment were effected pursuant to the terms of a Contribution, Conveyance and Assumption Agreement (the Contribution Agreement). Compressco Partners is governed by the First Amended and Restated Agreement of

F-18


Limited Partnership (the Partnership Agreement). The Partnership Agreement requires Compressco Partners to distribute all of its available cash, as defined in the Partnership Agreement, to the holders of the common units, subordinated units, 2.0% general partner interest, and incentive distribution rights in accordance with the terms of the Partnership Agreement. The Partnership Agreement also provides for the management of Compressco Partners by the General Partner. The reimbursement of direct and indirect costs incurred by us in providing personnel and services on behalf of Compressco Partners, as well as other transactions between us and Compressco Partners, is governed by the terms of an Omnibus Agreement between us and Compressco Partners.
 
Following the Offering, and the subsequent granting and vesting of director, officer, and employee equity awards, approximately 17.7% and 17.2% of Compressco Partners is owned by public unitholders as of December 31, 2013 and 2012, respectively, and reflected as a noncontrolling interest in our consolidated financial statements.
NOTE D – ACQUISITIONS AND DISPOSITIONS
 
Acquisition of Limited Liability Company Interest

On January 16, 2014, we finalized the purchase of the remaining 50% ownership interest of Ahmad Albinali & TETRA Arabia Company Ltd. (TETRA Arabia, a Saudi Arabian limited liability company) for consideration of $25.2 million. The closing of this transaction was pursuant to the terms of the Share Sale and Purchase Agreement entered into as of October 1, 2013, with the outside shareholder in TETRA Arabia. TETRA Arabia is a provider of production testing services, offshore rig cooling services, and clear brine fluids products and related services to its primary customer in Saudi Arabia. The acquisition of the remaining 50% interest of TETRA Arabia results in the Production Testing and Fluids segments owning a 100% interest in its Saudi Arabian operations, which it will operate directly through the TETRA Arabia entity. Prior to the transaction, our 50% ownership interest in TETRA Arabia was accounted for under the equity method of accounting, whereby our investment was classified as Other Assets in our consolidated balance sheets, and our share of company earnings was classified as Other Income in the consolidated statements of operations. Following the acquisition, TETRA Arabia will be consolidated as a wholly owned subsidiary. The $25.2 million purchase price for the 50% ownership interest includes $15.0 million that was paid at closing, and an additional $10.2 million that will be payable June 16, 2014.

As a result of the purchase of the remaining 50% ownership interest of TETRA Arabia, during the first quarter of 2014, we will remeasure to fair value our existing investment carrying value in TETRA Arabia and allocate this value to the consolidated balance sheet line items and record a remeasurement gain. Fair value measurements will also be used to record a charge to earnings associated with the termination of our existing relationship with the previous shareholder. As of March 3, 2014, a preliminary allocation of the fair value of the existing investment and the purchase price of the acquired interest in TETRA Arabia had yet to be calculated, but will be determined during the first quarter of 2014. Accordingly, disclosure of the allocation of the purchase price to the applicable TETRA Arabia balance sheet line items and the pro forma presentation reflecting the impact of the acquisition of the remaining interest will be presented in subsequent filings.

Acquisition of TD Water Transfer

On January 29, 2014, we acquired the assets and operations of WIT Water Transfer, LLC (doing business as TD Water Transfer) for a cash purchase price of $15.0 million paid at closing. In addition, additional contingent consideration of up to $8.0 million may be paid, depending on a defined measure of earnings over each of the two years subsequent to closing. TD Water Transfer is a provider of water management services to oil and gas operators in the South Texas and North Dakota regions, and the acquisition represented a strategic geographic expansion of our Fluids segment operations, allowing it to serve customers in additional basins in the U.S. As of March 3, 2014, a preliminary allocation of the TD Water Transfer purchase price had yet to be calculated, but will be determined during the first half of 2014. Accordingly, disclosure of the allocation of the purchase price to the applicable TD Water Transfer balance sheet line items and the pro forma presentation reflecting the impact of the TD Water Transfer acquisition will be presented in subsequent filings.

Acquisition of OPTIMA
 
On March 9, 2012, we acquired 100% of the outstanding common stock of Optima Solutions Holdings Limited (OPTIMA), a provider of offshore oil and gas rig cooling services and associated products that suppress

F-19


heat generated by high-rate flaring of hydrocarbons during offshore oil and gas well test operations. The acquisition of OPTIMA, which is based in Aberdeen, Scotland, enables our Production Testing segment to provide its customers with a broader range of associated services and expands the segment’s presence in many significant global markets. Including the impact of additional working capital received and other adjustments to the purchase price, we paid 41.2 million pounds sterling (approximately $65.0 million equivalent at the time of closing) in cash as the purchase price for the OPTIMA stock at closing and may pay up to an additional 4 million pounds sterling in contingent consideration, depending on a defined measure of earnings for OPTIMA over each of the two years subsequent to the closing.
 
We allocated the purchase price to the fair value of the assets and liabilities acquired, which consisted of approximately $3.0 million of net working capital; $16.8 million of property, plant, and equipment; $20.4 million of certain intangible assets; $7.2 million of deferred and other tax liabilities; $3.5 million of other liabilities associated with the contingent consideration; and $35.6 million of nondeductible goodwill. The fair value of the obligation to pay the contingent consideration was calculated based on the anticipated earnings for OPTIMA over each of the two twelve month periods subsequent to the closing and could increase (up to 4 million pounds sterling) or decrease (to zero) depending on OPTIMA’s actual and expected earnings going forward. Increases or decreases in the value of the anticipated contingent consideration liability due to changes in the amounts paid or expected to be paid will be charged or credited to earnings in the period in which such changes occur. Subsequent to the acquisition, the liability associated with the contingent consideration was adjusted downward by approximately $2.4 million (approximately $1.2 million of which was adjusted during the year ended December 31, 2013), and this amount was credited to earnings. The $35.6 million of goodwill recorded to our Production Testing segment as a result of the OPTIMA acquisition is supported by the expected strategic benefits discussed above to be generated from the acquisition. For the year ended December 31, 2012, our revenues, depreciation and amortization, and income before taxes included $20.2 million, $3.1 million, and $2.5 million, respectively, associated with the acquired operations of OPTIMA after the closing in March 2012. In addition to the above impact on our results of operations, transaction costs associated with the acquisition of OPTIMA of approximately $1.3 million were also charged to general and administrative expense during the year ended December 31, 2012.
 
Acquisition of ERS
 
On April 23, 2012, we acquired the assets and operations of Eastern Reservoir Services (ERS), a division of Patterson-UTI Energy, Inc., for a cash purchase price of $42.5 million. ERS was a provider of production testing and after-frac flow back services to oil and gas operators in the Appalachian and U.S. Rocky Mountain regions, and the acquisition represented a strategic geographic expansion of our existing Production Testing segment operations, allowing it to serve customers in additional basins in the U.S.
We allocated the purchase price to the fair value of the assets acquired, which consisted of approximately $18.5 million of property, plant, and equipment, approximately $3.4 million of certain intangible assets, and approximately $20.6 million of nondeductible goodwill. The $20.6 million of goodwill recorded to our Production Testing segment as a result of the ERS acquisition is supported by the strategic benefits discussed above to be generated from the acquisition. For the year ended December 31, 2012, our revenues, depreciation and amortization, and income before taxes included $24.6 million, $3.0 million, and $5.4 million, respectively, associated with the acquired operations of ERS after the closing in April 2012. In addition to the above impact on our results of operations, transaction costs associated with the ERS acquisition of approximately $0.5 million were also charged to general and administrative expense during the year ended December 31, 2012.
 
Acquisition of Greywolf
 
On July 31, 2012, we acquired the assets and operations of Greywolf Production Systems Inc. and GPS Ltd. (together, Greywolf) for a cash purchase price of approximately $55.5 million. Greywolf was a provider of production testing and after-frac flow back services to oil and gas operators in western Canada and the U.S. Williston Basin (including the Bakken formation) and the Niobrara Shale formation of the U.S. Rocky Mountain region. This acquisition represented an additional strategic geographic expansion of our existing Production Testing segment operations.
 
We allocated the purchase price to the fair value of the assets acquired, which consisted of approximately $17.7 million of property, plant, and equipment, approximately $3.5 million of certain intangible assets, and approximately $34.3 million of nondeductible goodwill. The $34.3 million of goodwill recorded to our Production Testing segment as a result of the Greywolf acquisition is supported by the strategic benefits discussed above to be

F-20


generated from the acquisition. For the year ended December 31, 2012, our revenues, depreciation and amortization, and income before taxes included $17.3 million, $1.0 million, and $1.1 million, respectively, associated with the acquired operations of Greywolf after the closing in July 2012. In addition to the above impact on our results of operations, transaction costs associated with the Greywolf acquisition of approximately $1.0 million were also charged to general and administrative expense during the year ended December 31, 2012.
 
Pro Forma Financial Information (Unaudited)
 
The pro forma information presented below has been prepared to give effect to the acquisitions of OPTIMA, ERS, and Greywolf as if they had occurred at the beginning of the period presented and include the impact from the allocation of the purchase price on depreciation and amortization. This pro forma information does not include the impact of the January 2014 acquisitions of TD Water Transfer or the limited liability company interest of TETRA Arabia, as the initial allocation of the purchase price for these acquisitions has yet to be calculated. The aggregate pro forma impact of the sale of equipment and oil and gas producing properties described below is not material and is not included in the following pro forma information. The pro forma information is presented for illustrative purposes only and is based on estimates and assumptions we deemed appropriate. The following pro forma information is not necessarily indicative of the historical results that would have been achieved if the acquisition transactions had occurred in the past, and our operating results may have been different from those reflected in the pro forma information below. Therefore, the pro forma information should not be relied upon as an indication of the operating results that we would have achieved if the transactions had occurred at the beginning of the periods presented or the future results that we will achieve after the acquisitions.
 
Year Ended
 
December 31, 2012
 
(In Thousands)
Revenues
$
924,795

Depreciation, depletion, amortization, and accretion
$
78,826

Gross profit
$
179,143

Income before discontinued operations
$
25,858

Net income
$
25,861

Net income attributable to TETRA stockholders
$
23,064

 
 
Per share information:
 

Income before discontinued operations attributable to TETRA stockholders
 

Basic
$
0.30

Diluted
$
0.29

Net income attributable to TETRA stockholders
 

Basic
$
0.30

Diluted
$
0.29

Other Acquisitions
 
On July 20, 2011, we purchased a new heavy lift derrick barge (which we have named the TETRA Hedron) with a 1,600-metric-ton lift capacity, fully revolving crane. The vessel was purchased from Wison (Nantong) Heavy Industry Co., Ltd. and Nantong MLC Tongbao Shipbuilding Co., Ltd. for $62.8 million. Approximately $20.8 million of the purchase price was initially held in certain escrow accounts, and the remaining escrow amount is to be released in accordance with the terms of the escrow agreements. The amount of remaining cash in escrow will be included in restricted cash on our consolidated balance sheet until the final release of escrow cash on April 30, 2014. The vessel was transported to the Gulf of Mexico during the third quarter and was placed into service during the fourth quarter of 2011 following final outfitting and sea trials.
 
In March 2011, we acquired a project management and engineering consulting services business that provides liability and risk assessment services for domestic and international offshore well abandonment and decommissioning projects. The purchase price for this acquisition was $1.5 million, and the assets acquired consist primarily of intangible assets.
 

F-21


Sale of Equipment
 
During 2012, our Offshore Services segment sold certain wireline and abandonment equipment for cash of approximately $10.7 million. As a result of these sales, we recognized gains on disposal of approximately $6.8 million, which is included in gain on sale of assets.
 
Sale of Maritech Producing Properties
 
In late 2010, we began to decrease our investment in Maritech by suspending oil and gas property acquisitions, decreasing our development activities, exploring strategic alternatives to our ownership of Maritech and its oil and gas properties, and reviewing opportunities to sell Maritech oil and gas property packages. As part of this overall effort, in February and March 2011, Maritech sold certain properties, along with the associated decommissioning liabilities. As part of these transactions, Maritech paid an aggregate of approximately $2.8 million at closing after normal purchase price adjustments. These sold properties, in the aggregate, accounted for approximately 12% of Maritech’s proved reserves as of December 31, 2010.
 
On May 31, 2011, Maritech completed the sale of approximately 79% of its proved oil and gas reserves as of December 31, 2010, to Tana Exploration Company LLC (Tana), a subsidiary of TRT Holdings, Inc. (TRT), pursuant to a Purchase and Sale Agreement dated April 1, 2011. The sale was made to Tana for a base purchase price of $222.3 million. At the closing of the sale, Tana assumed approximately $72.7 million of associated asset retirement obligations, and Maritech received $173.3 million cash at closing, representing the base purchase price less $11.1 million that consisted of a deposit that was paid in April 2011 and purchase price adjustments, including those adjustments reflecting cash flows subsequent to the January 1, 2011, effective date. The proceeds were subject to additional post-closing adjustments. As a result of the sale, we recorded a consolidated gain on sale of assets of $56.8 million. Due to Maritech’s continuing efforts to sell its remaining oil and gas properties, such properties were reclassified to Assets Held for Sale, and their net book values have been adjusted to fair value, less cost to dispose. In connection with the sale of Maritech oil and gas producing properties, during the second quarter of 2011, we charged to general and administrative expenses approximately $2.7 million of employee retention and incentive benefits paid in connection with these sales.
 
In August 2011, Maritech sold an additional remaining oil and gas property in exchange for the purchaser assuming the associated decommissioning liability. The sold property represents approximately 3% of Maritech’s December 31, 2010, oil and gas reserves.
 
In March 2012, Maritech sold its interest in certain onshore oil and gas producing properties for cash consideration of approximately $4.4 million. Following this transaction, Maritech’s remaining oil and gas reserves and production are negligible, and its operations consist primarily of the remaining well abandonment and decommissioning of its offshore oil and gas platforms and facilities.
NOTE E — LEASES
 
We lease some of our transportation equipment, office space, warehouse space, operating locations, and machinery and equipment. Certain facility storage tanks being constructed are leased pursuant to a ten year term, which is classified as a capital lease. Capitalized costs pursuant to a capital lease are depreciated over the term of the lease. The office, warehouse, and operating location leases, which vary from one to twenty-five year terms that expire at various dates through 2027 and are generally renewable for three and five year periods on similar terms, are classified as operating leases. Transportation equipment leases expire at various dates through 2020 and are also classified as operating leases. The office, warehouse, and operating location leases, and machinery and equipment leases generally require us to pay all maintenance and insurance costs.
 
Our corporate headquarters facility located in The Woodlands, Texas, was sold on December 31, 2012, pursuant to a sale and leaseback transaction. Pursuant to the transaction, we sold the building, parking garage, and land to an unaffiliated third party for a sale price of $43.8 million, before transaction costs and other deductions. As a condition to the consummation of the purchase and sale of the facility, the parties entered into a lease agreement for the facility having an initial lease term of 15 years, which is classified as an operating lease. Under the terms of the lease agreement, we have the ability to extend the lease for five successive five year periods at base rental rates to be determined at the time of each extension. The lease is on a net basis and the aggregate base rental payable during the initial fifteen year terms is approximately $52.9 million. We are also responsible for the payment of all related taxes, utilities, insurance, and certain maintenance and improvement costs. Pursuant to sale and

F-22


leaseback accounting, the approximately $8.3 million gain on the sale of the facility has been deferred and will be recognized over the initial lease term.  
 
Future minimum lease payments by year and in the aggregate, under non-cancelable capital and operating leases with terms of one year or more, and including the headquarters facility lease discussed above, consist of the following at December 31, 2013:
 
 
Capital Lease
 
Operating Leases
 
 
(In Thousands)
2014
 
$
76

 
$
12,537

2015
 
76

 
8,613

2016
 
76

 
6,157

2017
 
76

 
5,335

2018
 
76

 
4,936

After 2018
 
76

 
36,805

Total minimum lease payments
 
$
456

 
$
74,383

 
Rental expense for all operating leases was $37.7 million, $23.9 million, and $18.5 million in 2013, 2012, and 2011, respectively.
NOTE F — INCOME TAXES
 
The income tax provision (benefit) attributable to continuing operations for the years ended December 31, 2013, 2012, and 2011, consists of the following:
 
 
Year Ended December 31,
 
 
2013
 
2012
 
2011
 
 
(In Thousands)
Current
 
 

 
 

 
 

Federal
 
$
530

 
$
1,362

 
$
(1,661
)
State
 
(225
)
 
683

 
1,294

Foreign
 
6,065

 
9,396

 
6,875

 
 
6,370

 
11,441

 
6,508

Deferred
 
 

 
 

 
 

Federal
 
(6,685
)
 
(361
)
 
(7,053
)
State
 
(1,121
)
 
(495
)
 
(2,258
)
Foreign
 
(2,018
)
 
(1,156
)
 
3,554

 
 
(9,824
)
 
(2,012
)
 
(5,757
)
Total tax provision (benefit)
 
$
(3,454
)
 
$
9,429

 
$
751

 
A reconciliation of the provision (benefit) for income taxes attributable to continuing operations, computed by applying the federal statutory rate for the years ended December 31, 2013, 2012, and 2011, to income before income taxes and the reported income taxes, is as follows:

F-23


 
 
Year Ended December 31,
 
 
2013
 
2012
 
2011
 
 
(In Thousands)
Income tax provision (benefit) computed at statutory federal income tax rates
 
$
(45
)
 
$
9,864

 
$
2,182

State income taxes (net of federal benefit)
 
(875
)
 
122

 
(627
)
Nondeductible meals and entertainment
 
1,382

 
1,460

 
1,046

Impact of international operations
 
(3,538
)
 
(2,377
)
 
(1,229
)
Other
 
(378
)
 
360

 
(621
)
Total tax provision (benefit)
 
$
(3,454
)
 
$
9,429

 
$
751

 
The provision (benefit) for income taxes includes amounts related to the anticipated repatriation of certain earnings of our non-U.S. subsidiaries. Undistributed earnings above the amounts upon which taxes have been provided, which was $48.9 million at December 31, 2013, are intended to be permanently invested. It is not practicable to determine the amount of applicable taxes that would be incurred if any such earnings were repatriated.
 
Income (loss) before taxes and discontinued operations includes the following components: 
 
 
Year Ended December 31,
 
 
2013
 
2012
 
2011
 
 
(In Thousands)
Domestic
 
$
(14,322
)
 
$
2,206

 
$
(9,167
)
International
 
14,194

 
25,977

 
15,400

Total
 
$
(128
)
 
$
28,183

 
$
6,233


A reconciliation of the beginning and ending amount of our gross unrecognized tax benefit liability is as follows: 
 
 
Year Ended December 31,
 
 
2013
 
2012
 
2011
 
 
(In Thousands)
Gross unrecognized tax benefits at beginning of period
 
$
2,327

 
$
1,552

 
$
1,849

Additions related to acquisitions
 
—

 
742

 
—

Increases in tax positions for prior years
 
—

 
—

 
—

Decreases in tax positions for prior years
 
(118
)
 
—

 
—

Increases in tax positions for current year
 
202

 
313

 
—

Settlements
 
—

 
—

 
—

Lapse in statute of limitations
 
(393
)
 
(280
)
 
(297
)
Gross unrecognized tax benefits at end of period
 
$
2,018

 
$
2,327

 
$
1,552

 
We recognize interest and penalties related to uncertain tax positions in income tax expense. During the years ended December 31, 2013, 2012, and 2011, we recognized $(0.2) million, $0.3 million, and $0.3 million, respectively, of interest and penalties to the provision for income tax. As of December 31, 2013 and 2012, we had $2.1 million and $2.3 million, respectively, of accrued potential interest and penalties associated with these uncertain tax positions. The total amount of unrecognized tax benefits that would affect our effective tax rate if recognized is $2.1 million and $2.6 million as of December 31, 2013 and 2012, respectively. We do not expect a significant change to the unrecognized tax benefits during the next twelve months.
 
We file tax returns in the U.S. and in various state, local, and non-U.S. jurisdictions. The following table summarizes the earliest tax years that remain subject to examination by taxing authorities in any major jurisdiction in which we operate:

F-24


Jurisdiction
Earliest Open Tax Period
United States – Federal
2010
United States – State and Local
2002
Non-U.S. jurisdictions
2007
 
We use the liability method for reporting income taxes, under which current and deferred tax assets and liabilities are recorded in accordance with enacted tax laws and rates. Under this method, at the end of each period, the amounts of deferred tax assets and liabilities are determined using the tax rate expected to be in effect when the taxes are actually paid or recovered. We will 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. While we have considered future taxable income and ongoing tax planning strategies in assessing the need for the valuation allowance, there can be no guarantee that we will be able to realize all of our deferred tax assets. Significant components of our deferred tax assets and liabilities as of December 31, 2013 and 2012, are as follows: 
 
 
December 31,
 
 
2013
 
2012
 
 
(In Thousands)
Net operating losses
 
$
51,130

 
$
20,888

Foreign tax credits and alternative minimum tax credits
 
10,233

 
6,976

Accruals
 
30,057

 
46,259

All other
 
2,856

 
2,130

Total deferred tax assets
 
94,276

 
76,253

Valuation allowance
 
(3,747
)
 
(4,048
)
Net deferred tax assets
 
$
90,529

 
$
72,205

 
 
December 31,
 
 
2013
 
2012
 
 
(In Thousands)
Excess book over tax basis in property, plant, and equipment
 
$
85,035

 
$
78,614

All other
 
8,414

 
7,506

Total deferred tax liability
 
93,449

 
86,120

Net deferred tax liability
 
$
2,920

 
$
13,915

 
The change in the valuation allowance during 2013 primarily relates to the utilization and expiration of certain state net operating losses that were previously fully valued. The increase (decrease) in the valuation allowance during the years ended December 31, 2013, 2012, and 2011 were ($0.3) million, ($0.7) million, and ($2.4) million, respectively. We believe the ability to generate sufficient taxable income may not allow us to realize all the tax benefits of the deferred tax assets within the allowable carryforward period. Therefore, an appropriate valuation allowance has been provided.
 
At December 31, 2013, we had approximately $242.3 million of federal, foreign and state net operating loss carryforwards. In those countries and states in which net operating losses are subject to an expiration period, our loss carryforwards, if not utilized, will expire at various dates from 2014 through 2033. At December 31, 2013, we had $9.4 million of foreign tax credits available to offset future payment of federal income taxes. The foreign tax credits expire in varying amounts from 2020 through 2023.

F-25


NOTE G — ACCRUED LIABILITIES
 
Accrued liabilities are detailed as follows: 
 
 
December 31,
 
 
2013
 
2012
 
 
(In Thousands)
Compensation and employee benefits
 
$
15,221

 
$
15,248

Accrued interest
 
2,473

 
2,740

Accrued capital expenditures
 
11,496

 
8,130

Deferred tax liability
 
2,177

 
2,388

Other accrued liabilities
 
33,650

 
44,748

Total accrued liabilities
 
$
65,017

 
$
73,254

 
NOTE H – LONG-TERM DEBT AND OTHER BORROWINGS
 
Long-term debt consists of the following: 
 
 
 
 
December 31,
2013
 
December 31,
2012
 
 
 
 
(In Thousands)
 
 
Scheduled Maturity
 
 
 
 
Bank revolving line of credit facility
 
October 29, 2015
 
$
52,768

 
$
51,218

Compressco Partners' bank credit facility
 
October 15, 2017
 
29,959

 
10,050

5.90% Senior Notes, Series 2006-A
 
April 30, 2016
 
90,000

 
90,000

6.30% Senior Notes, Series 2008-A
 
April 30, 2013
 
—

 
35,000

6.56% Senior Notes, Series 2008-B
 
April 30, 2015
 
90,000

 
90,000

5.09% Senior Notes, Series 2010-A
 
December 15, 2017
 
65,000

 
65,000

5.67% Senior Notes, Series 2010-B
 
December 15, 2020
 
25,000

 
25,000

4.0% Senior Notes, Series 2013
 
April 29, 2020
 
35,000

 
—

European bank credit facility
 
 
 
—

 
—

Other
 
 
 
89

 
441

Total debt
 
 
 
387,816

 
366,709

Less current portion
 
 
 
(89
)
 
(35,441
)
Total long-term debt
 
 
 
$
387,727

 
$
331,268

Scheduled maturities for the next five years and thereafter are as follows:
 
 
Year Ending December 31,
 
 
(In Thousands)
2014
 
$
89

2015
 
172,727

2016
 
90,000

2017
 
65,000

2018
 
—

Thereafter
 
60,000

Total maturities
 
$
387,816



F-26


Bank Credit Facilities
 
Our Bank Credit Facility
 
On October 29, 2010, we amended our existing bank revolving credit facility agreement with a syndicate of banks, whereby the credit facility was decreased from $300 million to $278 million and its scheduled maturity was extended from June 2011 to October 2015. In addition, the amended credit facility agreement (the Credit Agreement) allows us to increase the facility by $150 million up to a $428 million limit upon the agreement of the lenders and the satisfaction of certain conditions. As of December 31, 2013, we had a balance of approximately $52.8 million outstanding on the amended revolving credit facility, as well as $9.5 million in letters of credit and guarantees against the $278 million availability under the amended revolving credit facility, leaving a net availability of approximately $215.7 million.
 
Under the Credit Agreement, which matures on October 29, 2015, the revolving credit facility is unsecured and guaranteed by certain of our material U.S. subsidiaries (excluding Compressco). Borrowings generally bear interest at the British Bankers Association LIBOR rate plus 1.5% to 2.5%, depending on one of our financial ratios. The weighted average interest rate on borrowings outstanding as of December 31, 2013, was 2.4% per annum. We pay a commitment fee ranging from 0.225% to 0.500% on unused portions of the facility. The Credit Agreement contains customary covenants and other restrictions, including certain financial ratio covenants based on our levels of debt and interest cost compared to a defined measure of our operating cash flows over a twelve month period. In addition, the Credit Agreement includes limitations on aggregate asset sales, individual acquisitions, aggregate annual acquisitions, and capital expenditures. Access to our revolving credit line is dependent upon our compliance with the financial ratio covenants set forth in the Credit Agreement, as discussed above. Significant deterioration of the financial ratios could result in a default under the Credit Agreement and, if not remedied, could result in termination of the Credit Agreement and acceleration of any outstanding balances. In June 2011, associated with the contribution of the majority of the operations and related assets and liabilities of our Compressco segment into Compressco Partners, Compressco Partners was designated as an unrestricted subsidiary and is no longer a borrower or a guarantor under our bank credit facility.
 
The Credit Agreement includes cross-default provisions relating to any other indebtedness greater than a defined amount. If any such indebtedness is not paid or is accelerated and such event is not remedied in a timely manner, a default will occur under the Credit Agreement. Our Credit Agreement also contains a covenant that restricts us from paying dividends in the event of a default or if such payment would result in an event of default. We are in compliance with all covenants and conditions of our Credit Agreement as of December 31, 2013. Our continuing ability to comply with these financial covenants depends largely upon our ability to generate adequate cash flow. Historically, our financial performance has been more than adequate to meet these covenants, and we expect this trend to continue.
 
Our European Credit Agreement
 
We also have a bank line of credit agreement covering the day to day working capital needs of certain of our European operations (the European Credit Agreement). The European Credit Agreement provides borrowing capacity of up to 5 million euros (approximately $6.9 million equivalent as of December 31, 2013), with interest computed on any outstanding borrowings at a rate equal to the lender’s Basis Rate plus 0.75%. The European Credit Agreement is cancellable by either party with 14 business days notice and contains standard provisions in the event of default. As of December 31, 2013, we had no borrowings pursuant to the European Credit Agreement.

Compressco Partners’ Bank Credit Facility
 
On June 24, 2011, Compressco Partners entered into a credit agreement with JPMorgan Chase Bank, N.A., which was amended on December 4, 2012, and May 14, 2013 (as amended, the Previous Partnership Credit Agreement), whereby, among other modifications, the maximum credit commitment under the credit facility was increased from $20.0 million to $40.0 million. Under the Previous Partnership Credit Agreement, Compressco Partners, along with certain of its subsidiaries, were named as borrowers, and all obligations under the Previous Partnership Credit Agreement were guaranteed by all of its existing and future, direct and indirect, domestic subsidiaries. The Previous Partnership Credit Agreement included a maximum credit commitment of $40.0 million and was available for letters of credit (with a sublimit of $5.0 million) and included an uncommitted $20.0 million expansion feature. The Previous Partnership Credit Agreement was available to be used to fund Compressco Partners' working capital needs, letters of credit, and for general partnership purposes, including capital

F-27


expenditures and potential future acquisitions. So long as Compressco Partners was not in default, the Previous Partnership Credit Agreement could also be used to fund quarterly distributions. Borrowings under the Previous Partnership Credit Agreement were subject to the satisfaction of customary conditions, including the absence of a default. The maturity date of the Previous Partnership Credit Agreement was June 24, 2015. Borrowings under the Previous Partnership Credit Agreement bore interest at a rate equal to three month British Bankers Association LIBOR (adjusted to reflect any required bank reserves) plus a margin of 2.25% per annum. 

On October 15, 2013, Compressco Partners entered into a new asset-based revolving credit agreement with a syndicate of lenders including JPMorgan Chase Bank, N.A. as administrative agent (the New Partnership Credit Agreement), which replaced the Previous Partnership Credit Agreement. Under the New Partnership Credit Agreement, Compressco Partners, along with certain of its subsidiaries, are named as borrowers, and all obligations under the New Partnership Credit Agreement are guaranteed by all of its existing and future, direct and indirect, domestic subsidiaries. The New Partnership Credit Agreement includes a maximum credit commitment of $100.0 million that is available for letters of credit (with a sublimit of $20.0 million), and includes an uncommitted $30.0 million expansion feature. The actual maximum credit availability under the New Partnership Credit Agreement varies from time to time and is determined by calculating the applicable borrowing base, which is based upon applicable percentages of the values of eligible accounts receivable, inventory, and equipment, minus reserves as determined necessary by the Administrative Agent. As of December 31, 2013, Compressco Partners had a balance outstanding under the New Partnership Credit Agreement of $30.0 million and had availability under the New Partnership Credit Agreement of $37.0 million, based upon a $67.4 million borrowing base and the $30 million outstanding balance.

The New Partnership Credit Agreement may be used to fund Compressco Partners' working capital needs, letters of credit, and for general partnership purposes, including the repayment of the indebtedness under the Previous Partnership Credit Agreement, capital expenditures, and potential future expansions or acquisitions. So long as Compressco Partners is not in default, the New Partnership Credit Agreement could also be used to fund its quarterly distributions at the option of the board of directors of its general partner (provided, that after giving effect to such distributions, Compressco Partners will be in compliance with the financial covenants). The initial borrowings under the New Partnership Credit Agreement were used to repay in full all amounts outstanding under the Previous Partnership Credit Agreement. Borrowings under the New Partnership Credit Agreement are subject to the satisfaction of customary conditions, including the absence of a default. The maturity date of the New Partnership Credit Agreement is October 15, 2017.

Borrowings under the New Partnership Credit Agreement bear interest at a rate per annum equal to, at Compressco Partners' option, either (a) LIBOR (adjusted to reflect any required bank reserves) for an interest period equal to one, two, three or six months (as selected by us), plus a margin of 2.25% per annum or (b) a base rate determined by reference to the highest of (1) the prime rate of interest per annum announced from time to time by JPMorgan Chase Bank, N.A. or (2) LIBOR (adjusted to reflect any required bank reserves) for a one-month interest period on such day plus 2.50% per annum. The weighted average interest rate on borrowings outstanding as of December 31, 2013, was 2.5625% per annum. In addition to paying interest on outstanding principal under the New Partnership Credit Agreement, Compressco Partners is required to pay a commitment fee, in respect of the unutilized commitments thereunder, of 0.375% per annum, paid quarterly in arrears. Compressco Partners is also required to pay a customary letter of credit fee equal to the applicable margin on revolving credit LIBOR loans and fronting fees.

The New Partnership Credit Agreement requires Compressco Partners to maintain a minimum interest coverage ratio (ratio of earnings before interest and taxes to interest) of 4.0 to 1.0 as of the last day of any fiscal quarter, calculated on a trailing four quarters basis. In addition, the New Partnership Credit Agreement includes customary negative covenants, which, among other things, limits Compressco Partners' ability to incur additional debt, incur or permit certain liens to exist, or make certain loans, investments, acquisitions, or other restricted payments. The New Partnership Credit Agreement provides that Compressco Partners can make distributions to holders of its common and subordinated units, but only if there is no default or event of default under the facility.

All obligations under the New Partnership Credit Agreement and the guarantees of those obligations are secured, subject to certain exceptions, by a first lien security interest in substantially all of Compressco Partners' assets (excluding real property) and its existing and future, direct and indirect domestic subsidiaries, and all of the capital stock of its existing and future, direct and indirect subsidiaries (limited, in the case of foreign subsidiaries, to 65% of the capital stock of first tier foreign subsidiaries).
 

F-28


Senior Notes
 
Each of our issuances of senior notes (collectively, the Senior Notes) are governed by the terms of the Master Note Purchase Agreement dated September 2004, as supplemented, the Note Purchase Agreements dated April 2008 and April 2013, or the Master Note Purchase Agreement dated September 23, 2010, (collectively, the Note Purchase Agreements). We may prepay the Senior Notes, in whole or in part, at any time at a price equal to 100% of the principal amount outstanding, plus accrued and unpaid interest and a “make-whole” prepayment premium. The Senior Notes are unsecured and are guaranteed by substantially all of our wholly owned U.S. subsidiaries. The Note Purchase Agreements, as supplemented, contain customary covenants and restrictions, require us to maintain certain financial ratios, and contain customary default provisions, as well as a cross-default provision relating to any other of our indebtedness of $20.0 million or more. We are in compliance with all covenants and conditions of the Note Purchase Agreements as of December 31, 2013. Upon the occurrence and during the continuation of an event of default under the Note Purchase Agreements, the Senior Notes may become immediately due and payable, either automatically or by declaration of holders of more than 50% in principal amount of the Senior Notes outstanding at the time.
 
In April 2013, we issued $35.0 million in aggregate principal amount of Series 2013 Senior Notes pursuant to a Note Purchase Agreement dated April 29, 2013. On April 30, 2013, we utilized the proceeds from the issuance to repay the 2008-A Senior Notes. The Series 2013 Senior Notes bear interest at the fixed rate of 4.00% and mature on April 29, 2020. Interest on the Series 2013 Senior Notes is due semiannually on April 29 and October 29 of each year. The Senior Notes were sold in the United States to accredited investors pursuant to an exemption from the Securities Act of 2033.
NOTE I – DECOMMISSIONING AND OTHER ASSET RETIREMENT OBLIGATIONS
 
The large majority of our asset retirement obligations consists of the remaining future well abandonment and decommissioning costs for offshore oil and gas properties and platforms owned by our Maritech subsidiary, including the decommissioning and debris removal costs associated with its remaining offshore platforms previously destroyed by hurricanes. The amount of decommissioning liabilities recorded by Maritech is reduced by amounts allocable to joint interest owners and any contractual amounts to be paid by the previous owners of the oil and gas properties when the liabilities are satisfied. We also operate facilities in various U.S. and foreign locations that are used in the manufacture, storage, and sale of our products, inventories, and equipment. These facilities are a combination of owned and leased assets. The value of our asset retirement obligations for non-Maritech properties was approximately $7.6 million and $7.5 million as of December 31, 2013 and 2012, respectively. We are required to take certain actions in connection with the retirement of these assets. We have reviewed our obligations in this regard in detail and estimated the cost of these actions. These estimates are the fair values that have been recorded for retiring these long-lived assets. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. The costs for non-oil and gas assets are depreciated on a straight-line basis over the life of the asset.
 
The changes in the asset retirement obligations during the most recent two year period are as follows:
 
 
Year Ended December 31,
 
 
2013
 
2012
 
 
(In Thousands)
Beginning balance for the period, as reported
 
$
94,921

 
$
139,835

Activity in the period:
 
 

 
 

Accretion of liability
 
673

 
1,536

Retirement obligations incurred
 
—

 
—

Revisions in estimated cash flows
 
74,946

 
40,986

Settlement of retirement obligations
 
(119,636
)
 
(87,436
)
Ending balance
 
$
50,904

 
$
94,921

 
We review the adequacy of our decommissioning liabilities whenever indicators suggest that the estimated cash flows underlying the liabilities have changed. For our Maritech segment, the timing and amounts of these cash flows are subject to changes in the energy industry environment and other factors and may result in additional liabilities to be recorded. During 2013 and 2012, we increased the estimated cash flows to decommission these

F-29


properties by approximately $75.0 million and $41.0 million, respectively, which resulted in approximately $75.3 million and $40.8 million, respectively, of direct charges to expense during these years. These increased estimates are included in the revisions in estimated cash flows in the table above. A portion of the excess decommissioning costs recorded during 2013 and 2012 was associated with properties not operated by Maritech and also include additional work incurred and anticipated to be required, including remediation work required on certain wells that had been previously plugged.  

Our estimate of remaining hurricane related decommissioning costs is approximately $7.7 million and has been accrued as part of Maritech’s decommissioning liabilities. Settlements of asset retirement obligations during 2013 include approximately $5.3 million of obligations associated with oil and gas properties that were sold by Maritech during the year.
NOTE J – COMMITMENTS AND CONTINGENCIES
 
Litigation
 
We are named defendants in several lawsuits and respondents in certain governmental proceedings arising in the ordinary course of business. While the outcome of lawsuits or other proceedings against us cannot be predicted with certainty, management does not consider it reasonably possible that a loss resulting from such lawsuits or other proceedings in excess of any amounts accrued has been incurred that is expected to have a material adverse impact on our financial condition, results of operations, or liquidity.
 
Environmental
 
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 future remediation costs and 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.
 
Product Purchase Obligations
 
In the normal course of our Fluids Division operations, we enter into supply agreements with certain manufacturers of various raw materials and finished products. Some of these agreements have terms and conditions that specify a minimum or maximum level of purchases over the term of the agreement. Other agreements require us to purchase the entire output of the raw material or finished product produced by the manufacturer. Our purchase obligations under these agreements apply only with regard to raw materials and finished products that meet specifications set forth in the agreements. We recognize a liability for the purchase of such products at the time we receive them. As of December 31, 2013, the aggregate amount of the fixed and determinable portion of the purchase obligation pursuant to our Fluids Division’s supply agreements was approximately $205.9 million, including $14.3 million during 2014, $14.3 million during 2015, $14.3 million during 2016, $14.3 million during 2017, $12.4 million during 2018, and $136.4 million thereafter, extending through 2029. Amounts purchased under these agreements for each of the years ended December 31, 2013, 2012, and 2011, was $21.3 million, $17.7 million, and $15.3 million, respectively.
NOTE K — CAPITAL STOCK
 
Our Restated Certificate of Incorporation authorizes us to issue 100,000,000 shares of common stock, par value $.01 per share, and 5,000,000 shares of preferred stock, par value $.01 per share. As of December 31, 2013, we had 78,855,547 shares of common stock outstanding, with 2,478,084 shares held in treasury, and no shares of preferred stock outstanding. The voting, dividend, and liquidation rights of the holders of common stock are subject to the rights of the holders of preferred stock. The holders of common stock are entitled to one vote for each share held. There is no cumulative voting. Dividends may be declared and paid on common stock as determined by our Board of Directors, subject to any preferential dividend rights of any then outstanding preferred stock. A summary of the activity of our common shares outstanding and treasury shares held for the three year period ending December 31, 2013, is as follows:

F-30


Common Shares Outstanding
 
Year Ended December 31,
 
 
2013
 
2012
 
2011
At beginning of period
 
78,112,032

 
77,423,415

 
76,291,745

Exercise of common stock options, net
 
373,106

 
580,097

 
858,727

Grants of restricted stock, net
 
370,409

 
108,520

 
272,943

At end of period
 
78,855,547

 
78,112,032

 
77,423,415

 
Treasury Shares Held
 
Year Ended December 31,
 
 
2013
 
2012
 
2011
At beginning of period
 
2,334,137

 
2,249,959

 
1,533,653

Shares received upon exercise of common stock options
 
119,477

 
81,616

 
592,992

Shares received upon vesting of restricted stock, net
 
24,470

 
2,562

 
123,314

At end of period
 
2,478,084

 
2,334,137

 
2,249,959

 
Our Board of Directors is empowered, without approval of the stockholders, to cause shares of preferred stock to be issued in one or more series and to establish the number of shares to be included in each such series and the rights, powers, preferences, and limitations of each series. Because the Board of Directors has the power to establish the preferences and rights of each series, it may afford the holders of any series of preferred stock preferences, powers and rights, voting or otherwise, senior to the rights of holders of common stock. The issuance of the preferred stock could have the effect of delaying or preventing a change in control of the Company.

Upon our dissolution or liquidation, whether voluntary or involuntary, holders of our common stock will be entitled to receive all of our assets available for distribution to our stockholders, subject to any preferential rights of any then outstanding preferred stock.
 
In January 2004, our Board of Directors authorized the repurchase of up to $20.0 million of our common stock. During the three years ending December 31, 2013, we made no purchases of our common stock pursuant to this authorization.
NOTE L — EQUITY-BASED COMPENSATION
 
We have various equity incentive compensation plans which provide for the granting of restricted common stock, options for the purchase of our common stock, and other performance-based, equity-based compensation awards to our executive officers, key employees, nonexecutive officers, consultants, and directors. Incentive stock options are exercisable for periods of up to ten years. Compensation cost for all share-based payments is based on the grant date fair value and is recognized in earnings over the requisite service period. Total equity-based compensation expense, net of taxes, for the three years ended December 31, 2013, 2012, and 2011 was $4.4 million, $6.1 million, and $4.1 million, respectively.
 
The Black-Scholes option-pricing model is used to estimate option fair values. This option-pricing model requires a number of assumptions, of which the most significant are: expected stock price volatility, the expected pre-vesting forfeiture rate, and the expected option term (the amount of time from the grant date until the options are exercised or expire). Expected volatility was calculated based upon actual historical stock price movements over the most recent periods ending December 31, 2013, equal to the expected option term. Expected pre-vesting forfeitures were estimated based on actual historical pre-vesting forfeitures over the most recent periods ending December 31, 2013, for the expected option term.
 
The TETRA Technologies, Inc. 1990 Stock Option Plan (the 1990 Plan) was initially adopted in 1985 and subsequently amended to change the name, the number, and the type of options that could be granted, as well as the time period for granting stock options. As of December 31, 2004, no further options may be granted under the 1990 Plan. We granted performance stock options under the 1990 Plan to certain executive officers. These granted options have an exercise price per share of not less than the market value at the date of issuance and are fully vested and exercisable.


F-31


During 1996, we adopted the 1996 Stock Option Plan for Nonexecutive Employees and Consultants (the Nonqualified Plan) to enable us to award nonqualified stock options to nonexecutive employees and consultants who are key to our performance. As of May 2, 2006, no further options may be granted under the Nonqualified Plan.
 
In May 2006, our stockholders approved the adoption of the TETRA Technologies, Inc. 2006 Equity Incentive Compensation Plan. Pursuant to the TETRA Technologies, Inc. 2006 Equity Incentive Compensation Plan, we were authorized to grant up to 1,300,000 shares in the form of stock options (including incentive stock options and nonqualified stock options); restricted stock; bonus stock; stock appreciation rights; and performance awards to employees, consultants, and non-employee directors. As a result of the May 2006 adoption and approval of the TETRA Technologies, Inc. 2006 Equity Incentive Compensation Plan, no further awards may be granted under our other previously existing plans. As of May 4, 2008, no further awards may be granted under the TETRA Technologies, Inc. 2006 Equity Incentive Compensation Plan.
 
In May 2007, our stockholders approved the adoption of the TETRA Technologies, Inc. 2007 Equity Incentive Compensation Plan. In May 2008, our stockholders approved the adoption of the TETRA Technologies, Inc. Amended and Restated 2007 Equity Incentive Compensation Plan, which among other changes, resulted in an increase in the maximum number of shares authorized for issuance. In May 2010, our stockholders approved further amendments to the TETRA Technologies, Inc. Amended and Restated 2007 Equity Incentive Compensation Plan (renamed as the 2007 Long Term Incentive Compensation Plan) which, among other changes, resulted in an additional increase in the maximum number of shares authorized for issuance. Pursuant to the 2007 Long Term Incentive Compensation Plan, we are authorized to grant up to 5,590,000 shares in the form of stock options (including incentive stock options and nonqualified stock options); restricted stock; bonus stock; stock appreciation rights; and performance awards to employees, consultants, and non-employee directors.
 
In May 2011, our stockholders approved the adoption of the TETRA Technologies, Inc. 2011 Long Term Incentive Compensation Plan. Pursuant to this plan, we were authorized to grant up to 2,200,000 shares in the form of stock options, restricted stock, bonus stock, stock appreciation rights, and performance awards to employees, consultants, and non-employee directors. On May 3, 2013, shareholders approved the TETRA Technologies, Inc. 2011 Long Term Incentive Compensation Plan which, among other things, increased the number of authorized shares to 5,600,000.
 
In June 2011, the Compressco Partners, L.P. 2011 Long Term Incentive Plan (Compressco Partners Long Term Incentive Plan) was adopted by the board of directors of Compressco Partners’ general partner. The plan is intended to promote Compressco Partners’ interests by providing to employees, consultants, and directors of its general partner incentive compensation based on common units, to encourage superior performance. The Compressco Partners Long Term Incentive Plan provides for grants of restricted units, phantom units, unit awards and other unit-based awards up to a plan maximum of 1,537,122 common units. The plan is also intended to attract and retain the services of individuals who are essential for the growth and profitability of Compressco Partners and its affiliates.
 
Grants of Restricted Common Stock
 
During each of the three years ended December 31, 2013, we granted to certain officers, directors and employees restricted shares, which generally vest over a three to five year period. During 2013, we granted a total of 490,684 restricted shares, having an average market value (equal to the closing price of the common stock on the dates of grant) of $10.37 per share, or an aggregate market value of $5.1 million. During 2012, we granted a total of 523,096 restricted shares, having an average market value (equal to the closing price of the common stock on the dates of grant) of $6.83 per share, or an aggregate market value of $3.6 million. During 2011, we granted a total of 397,907 restricted shares, having an average market value (equal to the quoted closing price of the common stock on the dates of grant) of $12.43 per share, or an aggregate market value of $4.9 million, at the date of grant. The fair value of awards vesting during 2013, 2012, and 2011, was approximately $3.6 million, $4.8 million, and $5.2 million, respectively.

The following is a summary of restricted stock activity for the year ended December 31, 2013:

F-32


 
 
Shares
 
Weighted Average
Grant Date Fair
Value Per Share
 
 
(In Thousands)
 
 
Nonvested restricted shares outstanding at December 31, 2012
 
621

 
$
8.49

Shares granted
 
490

 
10.37

Shares cancelled
 
(76
)
 
9.10

Shares vested
 
(391
)
 
9.11

Nonvested restricted shares outstanding at December 31, 2013
 
644

 
$
9.47

 
Grants of Equity Awards by Compressco Partners
 
During 2012, Compressco Partners granted restricted unit, phantom unit and performance phantom unit awards to certain employees, officers, and directors of its general partner. Awards of restricted units and phantom units generally vest over a three year period. Awards of performance phantom units cliff vest at the end of a performance period and are settled based on achievement of related performance measures over the performance period. Each of the phantom unit and performance phantom unit awards includes distribution equivalent rights that enable the recipient to receive additional units equal in value to the accumulated cash distributions made on the units subject to the award from the date of grant. Accumulated distributions associated with each underlying unit are payable upon settlement of the related phantom unit award (and are forfeited if the related award is forfeited). Restricted units are common units subject to time-based vesting restrictions. Phantom units are notional units that entitle the grantee to receive a common unit upon the vesting of the award.
 
The following is a summary of Compressco Partners’ equity award activity for the year ended December 31, 2013:
 
 
Units
 
Weighted Average
Grant Date Fair
Value Per Unit
 
 
(In Thousands)
 
 
Nonvested units outstanding at December 31, 2012
 
153

 
$
16.07

Units granted
 
74

 
20.28

Units cancelled
 
(18
)
 
15.65

Units vested
 
(76
)
 
16.43

Nonvested units outstanding at December 31, 2013
 
133

 
$
18.25

 
 Grants of Options to Purchase Common Stock
 
The following is a summary of stock option activity for the year ended December 31, 2013:
 
 
Shares Under Option
 
Weighted Average
Option Price
Per Share
 
 
(In Thousands)
 
 
Outstanding at December 31, 2012
 
4,333

 
$
11.85

Options granted
 
695

 
10.38

Options cancelled
 
(339
)
 
14.00

Options exercised
 
(397
)
 
5.48

Outstanding at December 31, 2013
 
4,292

 
$
12.03

 
 
 
 
 
Expected to vest
 
1,000

 
$
9.47

Exercisable, end of year
 
3,293

 
$
12.81

Available for grant, end of year
 
4,289

 
 

The total intrinsic value, or the difference between the exercise price and the market price on the date of exercise, of all options exercised during the three years ended December 31, 2013, 2012, and 2011, was approximately $0.7 million, $0.6 million, and $2.5 million, respectively. The intrinsic value of options outstanding as

F-33


of December 31, 2013, was $13.7 million, the intrinsic value of options expected to vest as of December 31, 2013 was $2.9 million, and the intrinsic value of options exercisable as of December 31, 2013, was $10.8 million. Cash received from stock options exercised during the three years ended December 31, 2013, 2012, and 2011, was $2.3 million, $0.9 million, and $3.4 million, respectively. Recognized excess tax benefits (adjustments) related to the exercise of stock options during the three years ended December 31, 2013, 2012, and 2011, were $(0.1) million, $(1.7) million, and $1.3 million, respectively.
 
The fair value of each option grant is estimated on the date of grant using the Black-Scholes option pricing model with the following assumptions used for each of the three years ended December 31, 2013:
 
 
Year Ended December 31,
 
 
2013
 
2012
 
2011
Expected stock price volatility
 
54% to 74% 

 
74% to 75% 

 
72% to 75% 

Expected life of options
 
4.9 years 

 
4.8 years 

 
4.7 years 

Risk free interest rate
 
0.76% to 1.48% 

 
0.62% to 1.03% 

 
0.87% to 2.24% 

Expected dividend yield
 
—

 
—

 
—

 
The weighted average fair value of options granted during the years ended December 31, 2013, 2012, and 2011 using the Black-Scholes model was $6.00, $4.06, and $7.55 per share, respectively. Total estimated unrecognized compensation cost from unvested stock options and restricted stock as of December 31, 2013, was approximately $8.4 million, which is expected to be recognized over a weighted average period of approximately 1.5 years.
 
During 2013, 2012, and 2011, we received 40,163, 24,121 and 52,065 shares, respectively, of our common stock related to the vesting of certain employee restricted stock. Such surrendered shares received by us are included in treasury stock. At December 31, 2013, net of options previously exercised pursuant to our various equity compensation plans, we have a maximum of 6,178,178 shares of common stock issuable pursuant to awards previously granted and outstanding and awards authorized to be granted in the future.
NOTE M — 401(k) PLAN
 
We have a 401(k) retirement plan (the Plan) that covers substantially all employees and entitles them to contribute up to 70% of their annual compensation, subject to maximum limitations imposed by the Internal Revenue Code. We have historically matched 50% of each employee’s contribution up to 6% of annual compensation, subject to certain limitations as outlined in the Plan. In addition, we can make discretionary contributions which are allocable to participants in accordance with the Plan. Total expense related to our 401(k) plan was $4.2 million, $3.5 million, and $3.3 million in 2013, 2012, and 2011, respectively.
NOTE N — DEFERRED COMPENSATION PLAN
 
We provide our officers, directors, and certain key employees with the opportunity to participate in an unfunded, deferred compensation program. There were thirty participants in the program at December 31, 2013. Under the program, participants may defer up to 100% of their yearly total cash compensation. The amounts deferred remain our sole property, and we use a portion of the proceeds to purchase life insurance policies on the lives of certain of the participants. The insurance policies, which also remain our sole property, are payable to us upon the death of the insured. We separately contract with the participant to pay to the participant the amount of deferred compensation, as adjusted for gains or losses, invested in participant-selected investment funds. Participants may elect to receive deferrals and earnings at termination, death, or at a specified future date while still employed. Distributions while employed must be at least three years after the deferral election. The program is not qualified under Section 401 of the Internal Revenue Code. At December 31, 2013, the amounts payable under the plan approximated the value of the corresponding assets we owned.
NOTE O – MARKET RISKS AND DERIVATIVE AND HEDGE CONTRACTS
 
We are exposed to financial and market risks that affect our businesses. We have currency exchange rate risk exposure related to transactions denominated in a foreign currency as well as to investments in certain of our international operations. As a result of our variable rate bank credit facilities, including the variable rate credit facility

F-34


of Compressco Partners, we face market risk exposure related to changes in applicable interest rates. We have concentrations of credit risk as a result of trade receivables owed to us by companies in the energy industry. In addition, we have market risk exposure in the sales prices we receive for the remainder of our oil and gas production. Our financial risk management activities may at times involve, among other measures, the use of derivative financial instruments, such as swap and collar agreements, to hedge the impact of market price risk exposures. Prior to the execution of the purchase and sale agreement in April 2011 pursuant to which we sold substantially all of our remaining Maritech oil and gas properties in May 2011, we utilized cash flow commodity hedge transactions to reduce our exposure related to the volatility of oil and gas prices. As indicated below, these cash flow commodity hedge contracts were liquidated in the second quarter of 2011. For these and other hedge contracts qualifying for hedge accounting treatment, we formally document all relationships between hedging instruments and hedged items, as well as our risk management objectives, our strategies for undertaking various hedge transactions, and our methods for assessing and testing correlation and hedge ineffectiveness. All hedging instruments are linked to the hedged asset, liability, firm commitment, or forecasted transaction. We also assess, both at the inception of the hedge and on an ongoing basis, whether the derivatives that are used in these hedging transactions are highly effective in offsetting changes in cash flows of the hedged items.
 
Derivative Contracts
 
Foreign Currency Derivative Contracts. In October 2013, we and Compressco Partners began entering into 30-day foreign currency forward derivative contracts as part of a program designed to mitigate the currency exchange rate risk exposure on selected transactions of certain foreign subsidiaries. As of December 31, 2013, we and Compressco Partners had the following foreign currency derivative contracts outstanding relating to a portion of our foreign operations:
Derivative Contracts
 
US Dollar Notional Amount
 
Traded Exchange Rate
 
Value Date

 
(In Thousands)
 
 
 
 
Forward sale Mexican pesos
 
$
10,332

 
13.01

 
1/17/2014
Forward purchase Mexican pesos
 
$
5,928

 
13.01

 
1/17/2014
Forward purchase euros
 
$
7,984

 
1.38

 
1/17/2014
Forward purchase pounds sterling
 
$
3,149

 
1.63

 
1/17/2014

Under this program, we and Compressco Partners may enter into similar derivative contracts from time to time. Although contracts pursuant to this program will serve as an economic hedge of the cash flow of our currency exchange risk exposure, they will not be formally designated as hedge contracts or qualify for hedge accounting treatment. Accordingly, any change in the fair value of these derivative instruments during a period will be included in the determination of earnings for that period.

The fair value of foreign currency derivative instruments are based on quoted market values as reported to us by our counterparty (a Level 1 measurement) . The fair values of our foreign currency derivative instruments as of December 31, 2013, are as follows:
Foreign currency derivative instruments
Balance Sheet Location
 
 Fair Value at
December 31, 2013

 

 
(In Thousands)
Forward purchase contracts
 
Current assets
 
$
72

Forward sale contracts
 
Current assets
 
32

Forward purchase contracts
 
Current liabilities
 
(52
)
Total
 

 
$
52


None of the foreign currency derivative contracts contain credit risk related contingent features that would require us to post assets or collateral for contracts that are classified as liabilities. During the year ended December 31, 2013, we recognized approximately $34,000 of net losses associated with our foreign currency derivative program.

Oil and gas commodity derivative contracts. In April 2011, following the execution of the purchase and sale agreement pursuant to which Maritech agreed to sell approximately 79% of its proved reserves as of December 31,

F-35


2011, we liquidated our remaining oil hedge contracts and paid $14.2 million to the counterparty. Therefore, from April 2011 forward, we have no remaining cash flow hedging swap contracts outstanding associated with our Maritech subsidiary’s oil or gas production.
 
Prior to their liquidation during 2011, we believe that our swap agreements were “highly effective cash flow hedges” in managing the volatility of future cash flows associated with Maritech’s oil production. The effective portion of the change in the derivative’s fair value (i.e., that portion of the change in the derivative’s fair value that offsets the corresponding change in the cash flows of the hedged transaction) was initially reported as a component of accumulated other comprehensive income, which was classified within equity. This component of accumulated other comprehensive income associated with cash flow hedge derivative contracts, including any derivative contracts which have been liquidated, was subsequently reclassified into product sales revenues, utilizing the specific identification method, when the hedged exposure affected earnings (i.e., when hedged oil and gas production volumes were reflected in revenues). Any “ineffective” portion of the change in the derivative’s fair value was recognized in earnings immediately.
 
As the hedge contracts were highly effective, the effective portion of the gain, net of taxes, from changes in contract fair value, including the gain on the liquidated oil swap contracts, is included in accumulated other comprehensive income within stockholders’ equity as of December 31, 2011. Pretax gains and losses associated with oil and gas derivative swap contracts for the year ended December 31, 2011, are summarized below:
 
 
Year Ended December 31, 2011
Derivative swap contracts
 
Oil
 
Natural Gas
 
Total
 
 
(In Thousands)
Amount of pretax gain reclassified from accumulated other comprehensive income into product sales revenue (effective portion)
 
$
1,177

 
$
—

 
$
1,177

Amount of pretax gain (loss) from change in derivative fair value recognized in other comprehensive income
 
(7,854
)
 
—

 
(7,854
)
Amount of pretax gain (loss) recognized in other income (expense) (ineffective portion)
 
(13,947
)
 
—

 
(13,947
)
 
Other Hedge Contracts
 
Transaction gains and losses attributable to a foreign currency transaction that is designated as, and is effective as, an economic hedge of a net investment in a foreign entity is subject to the same accounting as translation adjustments. As such, the effect of a rate change on a foreign currency hedge is the same as the accounting for the effect of the rate change on the net foreign investment; both are recorded in the cumulative translation account, a component of stockholders’ equity, and are partially or fully offsetting. In July 2012, we borrowed 10.0 million euros (approximately $13.8 million equivalent as of December 31, 2013) and designated the borrowing as a hedge of our net investment in our European operations. Changes in the foreign currency exchange rate have resulted in a cumulative change to the cumulative translation adjustment account of $1.1 million net of taxes, at December 31, 2013, with no ineffectiveness recorded.
NOTE P — INCOME PER SHARE
 
The following is a reconciliation of the common shares outstanding with the number of shares used in the computation of income per common and common equivalent share:
 
 
Year Ended December 31,
 
 
2013
 
2012
 
2011
 
 
(In Thousands)
Number of weighted average common shares outstanding
 
77,954

 
77,293

 
76,616

Assumed exercise of stock options
 
886

 
670

 
1,375

Average diluted shares outstanding
 
78,840

 
77,963

 
77,991

 
For the year ended December 31, 2013, the average diluted shares outstanding excludes the impact of 2,061,534 of average outstanding stock options that have exercise prices in excess of the average market price, as the inclusion of these shares would have been antidilutive. For the year ended December 31, 2012, the average

F-36


diluted shares outstanding excludes the impact of 2,832,192 of average outstanding stock options that have exercise prices in excess of the average market price, as the inclusion of these shares would have been antidilutive. For the year ended December 31, 2011, the average diluted shares outstanding excludes the impact of 2,831,118 of average outstanding stock options that have exercise prices in excess of the average market price, as the inclusion of these shares would have been antidilutive.
NOTE Q – INDUSTRY SEGMENTS AND GEOGRAPHIC INFORMATION
 
We manage our operations through five operating segments: Fluids, Production Testing, Compressco, Offshore Services, and Maritech.

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 North American onshore oil and gas operators with comprehensive water management services.
 
Our Production Enhancement Division consists of two operating segments: Production Testing and Compressco. The Production Testing segment provides after-frac flow back, production well testing, offshore rig cooling, and other associated services in many of the major oil and gas producing regions in the United States, Mexico, and Canada, as well as in certain basins in certain regions in South America, Africa, Europe, the Middle East, and Australia.
 
The Compressco segment provides compression-based production enhancement services, which are used in both conventional wellhead compression applications and unconventional compression applications, and, in certain circumstances, well monitoring and sand separation services. The Compressco segment provides these services throughout many of the onshore oil and gas producing regions of the United States, as well as certain basins in Mexico, Canada, and certain countries in South America, Europe, and the Asia-Pacific region. Beginning June 20, 2011, following the initial public offering of Compressco Partners, we allocate and charge certain corporate and divisional direct and indirect administrative costs to Compressco Partners.
 
Our Offshore Division consists of two operating segments: Offshore Services and Maritech. The Offshore Services segment provides (1) downhole and subsea services such as 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 air diving services.
 
The Maritech segment is 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 consist primarily of the ongoing abandonment and decommissioning associated with its remaining offshore wells and production platforms. Maritech intends to acquire a significant portion of these services from the Offshore Division’s Offshore Services segment.
 
We generally evaluate the performance of and allocate resources to our segments based on profit or loss from their operations before income taxes and nonrecurring charges, return on investment, and other criteria. Transfers between segments and geographic areas are priced at the estimated fair value of the products or services as negotiated between the operating units. “Corporate overhead” includes corporate general and administrative expenses, corporate depreciation and amortization, interest income and expense, and other income and expense.
 
Summarized financial information concerning the business segments from continuing operations is as follows:

F-37


 
 
Year Ended December 31,
 
 
2013
 
2012
 
2011
 
 
(In Thousands)
Revenues from external customers
 
 

 
 

 
 

Product sales
 
 

 
 

 
 

Fluids Division
 
$
281,585

 
$
257,558

 
$
229,426

Production Enhancement Division
 
 

 
 

 
 

Production Testing
 
—

 
—

 
—

Compressco
 
8,293

 
6,322

 
13,201

Total Production Enhancement Division
 
8,293

 
6,322

 
13,201

Offshore Division
 
 

 
 

 
 

Offshore Services
 
4,707

 
6,267

 
4,921

Maritech
 
5,560

 
6,008

 
81,941

Total Offshore Division
 
10,267

 
12,275

 
86,862

Consolidated
 
$
300,145

 
$
276,155

 
$
329,489


F-38


 
 
Year Ended December 31,
 
 
2013
 
2012
 
2011
 
 
(In Thousands)
Services and rentals
 
 

 
 

 
 

Fluids Division
 
$
101,040

 
$
76,858

 
$
75,032

Production Enhancement Division
 
 

 
 

 
 

Production Testing
 
195,983

 
207,984

 
139,755

Compressco
 
112,994

 
103,144

 
82,567

Intersegment eliminations
 
(1,747
)
 
(2,354
)
 
—

Total Production Enhancement Division
 
307,230

 
308,774

 
222,322

Offshore Division
 
 

 
 

 
 

Offshore Services
 
200,983

 
218,477

 
217,341

Maritech
 
—

 
150

 
799

Intersegment eliminations
 
—

 
—

 
—

Total Offshore Division
 
200,983

 
218,627

 
218,140

Corporate overhead
 
—

 
417

 
292

Consolidated
 
$
609,253

 
$
604,676

 
$
515,786

 
 
 
 
 
 
 
Intersegment revenues
 
 

 
 

 
 

Fluids Division
 
$
38

 
$
132

 
$
78

Production Enhancement Division
 
 

 
 

 
 

Production Testing
 
—

 
—

 
1

Compressco
 
—

 
—

 
—

Total Production Enhancement Division
 
—

 
—

 
1

Offshore Division 
 


 
 

 
 

Offshore Services
 
50,122

 
41,199

 
65,038

Maritech
 
—

 
—

 
—

Intersegment eliminations
 
(50,122
)
 
(41,199
)
 
(65,036
)
Total Offshore Division
 
—

 
—

 
2

Intersegment eliminations
 
(38
)
 
(132
)
 
(81
)
Consolidated
 
$
—

 
$
—

 
$
—

 
 
 
 
 
 
 
Total revenues
 
 

 
 

 
 

Fluids Division
 
$
382,663

 
$
334,548

 
$
304,536

Production Enhancement Division
 


 
 

 
 

Production Testing
 
195,983

 
207,984

 
139,756

Compressco
 
121,287

 
109,466

 
95,768

Intersegment eliminations
 
(1,747
)
 
(2,354
)
 
—

Total Production Enhancement Division
 
315,523

 
315,096

 
235,524

Offshore Division
 
 

 
 

 
 

Offshore Services
 
255,812

 
265,943

 
287,300

Maritech
 
5,560

 
6,158

 
82,740

Intersegment eliminations
 
(50,122
)
 
(41,199
)
 
(65,036
)
Total Offshore Division
 
211,250

 
230,902

 
305,004

Corporate overhead
 
—

 
417

 
292

Intersegment eliminations
 
(38
)
 
(132
)
 
(81
)
Consolidated
 
$
909,398

 
$
880,831

 
$
845,275


F-39


 
 
Year Ended December 31,
 
 
2013
 
2012
 
2011
 
 
(In Thousands)
Depreciation, depletion, amortization, and accretion
 
 

 
 

 
 

Fluids Division
 
$
22,508

 
$
19,034

 
$
19,596

Production Enhancement Division
 
 

 
 

 
 

Production Testing
 
27,262

 
22,261

 
13,893

Compressco
 
14,511

 
13,398

 
12,791

Total Production Enhancement Division
 
41,773

 
35,659

 
26,684

Offshore Division
 
 

 
 

 
 

Offshore Services
 
14,254

 
16,650

 
14,502

Maritech
 
123

 
1,039

 
31,314

Intersegment eliminations
 
—

 
—

 
(174
)
Total Offshore Division
 
14,377

 
17,689

 
45,642

Corporate overhead
 
2,327

 
3,365

 
2,917

Consolidated
 
$
80,985

 
$
75,747

 
$
94,839

 
 
 
 
 
 
 
Interest expense
 
 

 
 

 
 

Fluids Division
 
$
37

 
$
77

 
$
121

Production Enhancement Division
 
 

 
 

 
 

Production Testing
 
19

 
13

 
32

Compressco
 
500

 
81

 
(20
)
Total Production Enhancement Division
 
519

 
94

 
12

Offshore Division
 
 

 
 

 
 

Offshore Services
 
109

 
109

 
45

Maritech
 
11

 
98

 
78

Intersegment eliminations
 
—

 
—

 
—

Total Offshore Division
 
120

 
207

 
123

Corporate overhead
 
16,741

 
17,000

 
16,939

Consolidated
 
$
17,417

 
$
17,378

 
$
17,195

 
 
 
 
 
 
 
Income (loss) before taxes and discontinued operations
 
 

 
 

 
 

Fluids Division
 
$
69,438

 
$
50,830

 
$
32,076

Production Enhancement Division
 
 

 
 

 
 

Production Testing
 
14,093

 
39,847

 
35,969

Compressco
 
20,200

 
20,598

 
15,799

   Intersegment eliminations
 
(105
)
 
—

 
—

Total Production Enhancement Division
 
34,188

 
60,445

 
51,768

Offshore Division
 
 

 
 

 
 

Offshore Services
 
22,870

 
21,706

 
18,455

Maritech
 
(64,365
)
 
(42,790
)
 
(26,275
)
Intersegment eliminations
 
—

 
—

 
1,802

Total Offshore Division
 
(41,495
)
 
(21,084
)
 
(6,018
)
Corporate overhead(1)
 
(62,259
)
 
(62,008
)
 
(71,593
)
Consolidated
 
$
(128
)
 
$
28,183

 
$
6,233


F-40


 
 
Year Ended December 31,
 
 
2013
 
2012
 
2011
 
 
(In Thousands)
Total assets
 
 

 
 

 
 

Fluids Division
 
$
400,028

 
$
387,034

 
$
375,741

Production Enhancement Division
 
 

 
 

 
 

Production Testing
 
327,413

 
337,208

 
119,311

Compressco
 
230,829

 
219,838

 
210,754

Total Production Enhancement Division
 
558,242

 
557,046

 
330,065

Offshore Division
 
 

 
 

 
 

Offshore Services
 
181,617

 
188,034

 
216,927

Maritech
 
46,903

 
75,383

 
63,294

Intersegment eliminations
 
—

 
—

 
—

Total Offshore Division
 
228,520

 
263,417

 
280,221

Corporate overhead
 
19,743

 
54,321

 
217,283

Consolidated
 
$
1,206,533

 
$
1,261,818

 
$
1,203,310

 
 
 
 
 
 
 
Capital expenditures
 
 

 
 

 
 

Fluids Division
 
$
45,238

 
$
31,839

 
$
17,922

Production Enhancement Division
 


 
 

 
 

Production Testing
 
26,757

 
40,025

 
19,925

Compressco
 
24,103

 
22,215

 
12,471

Total Production Enhancement Division
 
50,860

 
62,240

 
32,396

Offshore Division
 
 

 
 

 
 

Offshore Services
 
4,207

 
12,050

 
64,420

Maritech
 
21

 
343

 
7,924

Intersegment eliminations
 
—

 
—

 
(66
)
Total Offshore Division
 
4,228

 
12,393

 
72,278

Corporate overhead
 
1,053

 
1,052

 
1,008

Consolidated
 
$
101,379

 
$
107,524

 
$
123,604

(1) 
Amounts reflected include the following general corporate expenses:
 
 
2013
 
2012
 
2011
 
 
(In Thousands)
General and administrative expense
 
$
40,506

 
$
40,005

 
$
36,694

Depreciation and amortization
 
2,327

 
3,365

 
2,917

Interest expense
 
16,715

 
17,000

 
16,939

Other general corporate (income) expense, net
 
2,711

 
1,638

 
15,043

Total
 
$
62,259

 
$
62,008

 
$
71,593

Summarized financial information concerning the geographic areas of our customers and in which we operate at December 31, 2013, 2012, and 2011, is presented below:

F-41


 
 
Year Ended December 31,
 
 
2013
 
2012
 
2011
 
 
(In Thousands)
Revenues from external customers:
 
 

 
 

 
 

U.S.
 
$
673,376

 
$
625,885

 
$
671,926

Canada and Mexico
 
58,080

 
85,133

 
49,314

South America
 
31,788

 
42,482

 
28,765

Europe
 
102,990

 
92,882

 
75,033

Africa
 
15,127

 
20,194

 
13,877

Asia and other
 
28,037

 
14,255

 
6,360

Total
 
$
909,398

 
$
880,831

 
$
845,275

Transfers between geographic areas:
 
 

 
 

 
 

U.S.
 
$
—

 
$
—

 
$
—

Canada and Mexico
 
—

 
—

 
—

South America
 
—

 
—

 
—

Europe
 
112

 
172

 
322

Africa
 
—

 
—

 
—

Asia and other
 
—

 
—

 
—

Eliminations
 
(112
)
 
(172
)
 
(322
)
Total revenues
 
$
909,398

 
$
880,831

 
$
845,275

Identifiable assets:
 
 

 
 

 
 

U.S.
 
$
852,483

 
$
913,080

 
$
994,151

Canada and Mexico
 
104,831

 
116,059

 
62,558

South America
 
43,326

 
51,858

 
43,295

Europe
 
150,415

 
135,219

 
78,974

Africa
 
9,063

 
13,700

 
11,653

Asia and other
 
46,351

 
31,902

 
12,679

Eliminations and discontinued operations
 
64

 
—

 
—

Total identifiable assets
 
$
1,206,533

 
$
1,261,818

 
$
1,203,310

 
During each of the three years ended December 31, 2013, 2012, and 2011, no single customer accounted for more than 10% of our consolidated revenues.
NOTE R — SUPPLEMENTAL OIL AND GAS DISCLOSURES (Unaudited)
 
As part of the Offshore Division activities, Maritech and its subsidiaries previously acquired oil and gas reserves and operated the properties in exchange for assuming the proportionate share of the well abandonment and decommissioning obligations associated with such properties. Accordingly, our Maritech segment is included within our Offshore Division.
 
Costs Incurred in Property Acquisition, Exploration, and Development Activities
 
The following table reflects the costs incurred in oil and gas property acquisition, exploration, and development activities during the years indicated. Consideration given for the acquisition of proved properties includes the assumption, and any subsequent revision, of the amount of the proportionate share of the well abandonment and decommissioning obligations associated with the properties.

F-42


 
 
Year Ended December 31,
 
 
2013
 
2012
 
2011
 
 
(In Thousands)
Acquisition
 
$
—

 
$
—

 
$
141

Exploration
 
—

 
—

 
—

Development
 
—

 
—

 
5,798

Total costs incurred
 
$
—

 
$
—

 
$
5,939

 
Capitalized Costs Related to Oil and Gas Producing Activities
 
In connection with our decision during 2011 to sell Maritech’s oil and gas properties, beginning June 30, 2011, we reclassified Maritech’s remaining oil and gas properties to Assets Held for Sale in our consolidated balance sheet, and have recorded their value at fair value, less cost to dispose.
 
Results of Operations for Oil and Gas Producing Activities
 
Results of operations for oil and gas producing activities excludes general and administrative and interest expenses directly related to such activities as well as any allocation of corporate or divisional overhead.
 
 
Year Ended December 31,
 
 
2013
 
2012
 
2011
 
 
(In Thousands)
Oil and gas sales revenues
 
$
5,560

 
$
6,158

 
$
81,941

Production (lifting) costs
 
2,637

 
3,749

 
33,496

Depreciation, depletion, and amortization
 
37

 
60

 
27,640

Impairments of properties
 
—

 
—

 
15,233

Excess decommissioning and abandonment costs 
 
75,313

 
40,767

 
78,382

Exploration expenses
 
—

 
—

 
77

Accretion expense
 
87

 
979

 
3,705

Dry hole costs
 
—

 
—

 
(32
)
Gain on insurance recoveries
 
(5,685
)
 
—

 
—

Pretax income (loss) from producing activities
 
(66,829
)
 
(39,397
)
 
(76,560
)
Income tax expense (benefit)
 
(23,390
)
 
(13,789
)
 
(26,797
)
Results of oil and gas producing activities
 
$
(43,439
)
 
$
(25,608
)
 
$
(49,763
)
 
Estimated Quantities of Proved Oil and Gas Reserves (Unaudited)
 
Proved oil and gas reserves are defined as the estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Reservoirs are considered proved if economic productibility is supported by either actual production or conclusive formation tests. The area of a reservoir considered proved includes (a) that portion delineated by drilling and defined by gas-oil and/or gas-water contacts, if any, and (b) the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data. Reserves which can be produced economically through the application of improved recovery techniques are included in the “proved” classification when successful testing by a pilot project or the operation of an installed program in the reservoir provides support for the engineering analysis on which the project or program was based.
 
The reliability of reserve information is considerably affected by several factors. Reserve information is imprecise due to the inherent uncertainties in, and the limited nature of, the database upon which the estimating of reserve information is predicated. Moreover, the methods and data used in estimating reserve information are often necessarily indirect or analogical in character, rather than direct or deductive. Furthermore, estimating reserve information involves numerous judgments. The extent and significance of the judgments to be made are, in themselves, sufficient to render reserve information inherently imprecise.

F-43



Following the 2011 and 2012 sales of substantially all of Maritech’s proved oil and gas reserves, Maritech’s remaining oil and gas reserves are negligible. The reserve values and cash flow amounts reflected in the following reserve disclosures as of December 31, 2011 and 2010, are based on the average price of oil and natural gas during the twelve month period then ended, determined as an unweighted arithmetic average of the first-day-of-the-month for each month within the period. All of Maritech’s reserves are located in U. S. state and federal offshore waters of the Gulf of Mexico and onshore Texas and Louisiana. Proved oil and gas reserve quantities as of December 31, 2011, reflect the 2011 sale of approximately 95% of such reserves.
Reserve Quantity Information
 
Oil
 
NGL
 
Gas
 
 
(MBbls)
 
(MBbls)
 
(MMcf)
December 31, 2011
 
 

 
 

 
 

Proved developed reserves
 
95

 
40

 
676

Proved undeveloped reserves
 
107

 
60

 
480

Total proved reserves at December 31, 2011
 
202

 
100

 
1,156

December 31, 2012
 
 

 
 

 
 

Proved developed reserves
 
—

 
—

 
—

Proved undeveloped reserves
 
—

 
—

 
—

Total proved reserves at December 31, 2012
 
—

 
—

 
—

December 31, 2013
 
 

 
 

 
 

Proved developed reserves
 
—

 
—

 
—

Proved undeveloped reserves
 
—

 
—

 
—

Total proved reserves at December 31, 2013
 
—

 
—

 
—

 
 
 
 
 
 
 
 
 
Oil
 
NGL
 
Gas
 
 
(MBbls)
 
(MBbls)
 
(MMcf)
Total proved reserves at December 31, 2010
 
6,772

 
489

 
25,585

Revisions of previous estimates
 
(88
)
 
22

 
(1,903
)
Production
 
(612
)
 
(88
)
 
(3,322
)
Extensions and discoveries
 
—

 
—

 
—

Purchases of reserves in place
 
—

 
—

 
—

Sales of reserves in place
 
(5,870
)
 
(323
)
 
(19,204
)
Total proved reserves at December 31, 2011
 
202

 
100

 
1,156

Revisions of previous estimates
 
(8
)
 
39

 
(52
)
Production
 
(23
)
 
(39
)
 
(311
)
Extensions and discoveries
 
—

 
—

 
—

Purchases of reserves in place
 
—

 
—

 
—

Sales of reserves in place
 
(171
)
 
(100
)
 
(793
)
Total proved reserves at December 31, 2012
 
—

 
—

 
—

Revisions of previous estimates
 
—

 
—

 
—

Production
 
—

 
—

 
—

Extensions and discoveries
 
—

 
—

 
—

Purchases of reserves in place
 
—

 
—

 
—

Sales of reserves in place
 
—

 
—

 
—

Total proved reserves at December 31, 2013
 
—

 
—

 
—

 
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves
 
“Standardized measure” relates to the estimated discounted future net cash flows and major components of that calculation relating to proved reserves at the end of the year in the aggregate, based on SEC prescribed prices and costs, using statutory tax rates and using a 10% annual discount rate. The standardized measure is not an estimate of the fair value of proved oil and gas reserves. Probable and possible reserves, which may become

F-44


proved in the future, are excluded from these calculations. Furthermore, prices used to determine the standardized measure are prior to the impact of hedge derivatives and are influenced by seasonal demand and other factors and may not be representative in estimating future revenues or reserve data.
 
Changes in Standardized Measure of Discounted Future Net Cash Flows
 
 
Year Ended December 31,
 
 
2013
 
2012
 
2011
 
 
(In Thousands)
Standardized measure, beginning of year
 
$
—

 
$
6,475

 
$
133,269

Sales, net of production costs
 
—

 
(2,409
)
 
(48,445
)
Net change in prices, net of production costs
 
—

 
—

 
(11,916
)
Changes in future development and abandonment costs
 
—

 
—

 
43,792

Development and abandonment costs incurred
 
—

 
—

 
25,083

Accretion of discount
 
—

 
—

 
17,909

Net change in income taxes
 
—

 
—

 
44,612

Purchases of reserves in place
 
—

 
—

 
—

Extensions and discoveries
 
—

 
—

 
—

Sales of reserves in place
 
—

 
(7,918
)
 
(198,324
)
Net change due to revision in quantity estimates
 
—

 
—

 
(10,814
)
Changes in production rates (timing) and other
 
—

 
3,852

 
11,309

Subtotal
 
—

 
(6,475
)
 
(126,794
)
Standardized measure, end of year
 
$
—

 
$
—

 
$
6,475

NOTE S — QUARTERLY FINANCIAL INFORMATION (Unaudited)
 
Summarized quarterly financial data for 2013 and 2012 is as follows:
 
 
Three Months Ended 2013
 
 
March 31
 
June 30
 
September 30
 
December 31
 
 
(In Thousands, Except Per Share Amounts)
Total revenues
 
$
208,559

 
$
221,101

 
$
254,303

 
$
225,435

Gross profit
 
38,359

 
31,050

 
47,442

 
18,541

Income (loss) before discontinued operations
 
2,100

 
(2,508
)
 
12,854

 
(9,120
)
Net income (loss)
 
2,100

 
(2,508
)
 
12,854

 
(9,121
)
Net income (loss) attributable to TETRA stockholders
 
1,303

 
(2,931
)
 
12,110

 
(10,329
)
Net income (loss) per share before discontinued operations attributable to TETRA stockholders
 
$
0.02

 
$
(0.04
)
 
$
0.16

 
$
(0.13
)
Net income (loss) per diluted share before discontinued operations attributable to TETRA stockholders
 
$
0.02

 
$
(0.04
)
 
$
0.15

 
$
(0.13
)


F-45


 
 
Three Months Ended 2012
 
 
March 31
 
June 30
 
September 30
 
December 31
 
 
(In Thousands, Except Per Share Amounts)
Total revenues
 
$
180,796

 
$
234,909

 
$
233,986

 
$
231,140

Gross profit (loss)
 
31,997

 
52,710

 
50,447

 
32,226

Income (loss) before discontinued operations
 
1,148

 
12,178

 
8,601

 
(3,173
)
Net income (loss)
 
1,147

 
12,181

 
8,602

 
(3,173
)
Net income (loss) attributable to TETRA stockholders
 
681

 
11,574

 
7,713

 
(4,008
)
Net income (loss) per share before discontinued operations attributable to TETRA stockholders
 
$
0.01

 
$
0.15

 
$
0.10

 
$
(0.05
)
Net income (loss) per diluted share before discontinued operations attributable to TETRA stockholders
 
$
0.01

 
$
0.15

 
$
0.10

 
$
(0.05
)
 
Beginning with the three month period ended September 30, 2013, certain ad valorem tax expenses for operating equipment for our Compressco segment have been reclassified as cost of revenues instead of being included in general and administrative expense as previously reported. Gross profit for the reporting periods prior to the three month period ended September 30, 2013 has been adjusted to reflect this reclassification. This reclassification had no effect on net income for any of the periods presented.
NOTE T — STOCKHOLDERS’ RIGHTS PLAN
 
On October 27, 1998, the Board of Directors adopted a stockholders’ rights plan (the Rights Plan) designed to assure that all of our stockholders receive fair and equal treatment in the event of a proposed takeover. The Rights Plan, as amended on November 6, 2008, was formed to help guard against partial tender offers, open market accumulations, and other abusive tactics to gain control of our company without paying an adequate and fair price in any takeover attempt, and was scheduled to expire on November 6, 2018. In March 2013, the Board of Directors approved an amendment to the Rights Plan whereby its expiration was accelerated to March 13, 2013. As a result of its expiration, the rights issued pursuant to the Rights Plan expired and are no longer outstanding.
 

F-46