TETRA TECHNOLOGIES INC - Annual Report: 2012 (Form 10-K)

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, 2012

[ ] 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
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THE AGGREGATE MARKET VALUE OF COMMON STOCK HELD BY NON-AFFILIATES OF THE REGISTRANT WAS $538,036,074 AS OF JUNE 30, 2012, 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 26, 2013 WAS 78,200,008 SHARES.

DOCUMENTS INCORPORATED BY REFERENCE

PART III INFORMATION IS INCORPORATED BY REFERENCE TO THE REGISTRANT’S PROXY STATEMENT FOR ITS ANNUAL MEETING OF STOCKHOLDERS TO BE HELD MAY 3, 2013 TO BE FILED WITH THE SECURITIES AND EXCHANGE COMMISSION WITHIN 120 DAYS OF THE END OF THE REGISTRANT’S FISCAL YEAR.

TABLE OF CONTENTS

	Part I
Item 1.	Business	1
Item 1A.	Risk Factors	12
Item 1B.	Unresolved Staff Comments	23
Item 2.	Properties	23
Item 3.	Legal Proceedings	26
Item 4.	Mine Safety Disclosures	26

	Part II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters, and
	Issuer Purchases of Equity Securities	26
Item 6.	Selected Financial Data	28
Item 7.	Management’s Discussion and Analysis of Financial Condition
	and Results of Operation	34
Item 7A.	Quantitative and Qualitative Disclosures about Market Risk	53
Item 8.	Financial Statements and Supplementary Data	54
Item 9.	Changes in and Disagreements with Accountants on Accounting
	and Financial Disclosure	54
Item 9A.	Controls and Procedures	54
Item 9B.	Other Information	55

	Part III
Item 10.	Directors, Executive Officers, and Corporate Governance	55
Item 11.	Executive Compensation	55
Item 12.	Security Ownership of Certain Beneficial Owners and Management and
	Related Stockholder Matters	55
Item 13.	Certain Relationships and Related Transactions, and Director Independence	55
Item 14.	Principal Accounting Fees and Services	55

	Part IV
Item 15.	Exhibits, Financial Statement Schedules	56

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, frac 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 domestic onshore oil and gas operators with comprehensive frac 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 oil and gas basins in certain regions in South America, Africa, Europe, the Middle East, and Australia.

Our Offshore Division consists of two operating segments: Offshore Services and Maritech. The Offshore Services segment provides (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 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 current operations primarily consist of the ongoing abandonment and decommissioning associated with its remaining operated and non-operated offshore wells, facilities, and production platforms. Maritech intends to acquire a significant portion of these services for its operated properties from the Offshore Division’s Offshore Services segment.

We continue to pursue a growth strategy that includes expanding our existing businesses, with the exception of Maritech, through internal growth and acquisitions, domestically and internationally. For financial information for each of our segments, including information regarding revenues and total assets, see “Note Q – Industry Segments and Geographic Information” contained in the Notes to Consolidated Financial Statements.

We were incorporated in Delaware in 1981. Our corporate headquarters are 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 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 basic 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; and fluid management services; as well as high-volume water management services for fracturing operations. We offer to repurchase (buyback) from customers used CBFs, 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 CBFs and using various additives, we are able to modify the specific density, crystallization temperature, and chemical composition of the CBFs as necessary. The Division’s fluid engineering personnel determine the optimal CBF blend for a customer’s particular application to maximize its effectiveness and lifespan. Our filtration services use a variety of techniques and equipment to remove particulates from CBFs at the customer’s site, so the CBFs can be reused. Filtration also enables recovery of a greater percentage of used CBFs for reconditioning.

The 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 expandable water transfer pipeline system. The Division’s frac 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.

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 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 Europe. 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 manufacturing 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 liquid equivalent tons per year.

We manufacture 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, 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 and provides late-life production enhancement solutions designed to boost and extend the productive life of oil and gas wells. Many of these 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. 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. 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, the U.S. Williston Basin (including the Bakken formation), and the Niobrara Shale formation of the U.S. Rocky Mountain region. These acquisitions represent a strategic geographic expansion of our existing Production Testing segment operations into additional oil and gas producing regions in the U.S and Canada. The Production Testing segment has domestic operating locations in Colorado, Louisiana, North Dakota, Oklahoma, Pennsylvania, and throughout Texas. Internationally, the segment has locations in Mexico and Canada, South America, Europe, North Africa, the Middle East, and Asia.

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 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 production testing related 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 we may pay up to an additional 4 million pounds sterling in contingent purchase price consideration, depending on a defined measure of earnings for OPTIMA over the two years subsequent to the closing.

The Production Testing segment also operates under a technical management contract to perform engineering, procurement, and installation of equipment needed for the cleanup and removal of oil bearing materials at two refinery locations in South America. The remaining services to be provided under this contract are expected to continue to be performed in stages over the next twelve month period.

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 to a broad base of natural gas and oil exploration and production companies. Over time, oil and natural gas wells exhibit declining pressure and production. Production enhancement technologies are designed to enhance daily production and total recoverable reserves. Compression-based production enhancement services are utilized to increase reserves production by deliquifying wells, lowering wellhead pressure, and increasing gas velocity. The Compressco segment’s conventional applications include production enhancement services for dry gas wells, liquid loaded gas wells, and backside auto injection system applications. Its unconventional applications are utilized primarily in connection with oil and liquids production, and include vapor recovery and casing gas system applications. In Mexico, in certain circumstances, the segment also provides ongoing well monitoring services and automated sand separation services in connection with its primary production enhancement services. Although Compressco’s compression-based services are applied primarily to mature wells with low formation pressures, they are also utilized effectively on newer wells that have experienced significant production declines.

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’s field services are performed by its highly trained staffs of regional service supervisors, optimization specialists, and field mechanics. Compressco designs and manufactures most of the compressors it uses to provide production enhancement services, and in certain markets, sells compressor units to customers. Compressco’s fleet of compressor units totaled 3,743 as of December 31, 2012, of which 3,198 units were in service.

Compressco primarily utilizes its natural gas powered GasJack® and electric VJackTM compressor units to provide its compression services. Compressco utilizes its GasJack® and VJackTM units to provide compression services to its customers, primarily on a month-to-month basis. Compressco services its compressors and provides maintenance services on sold units through a staff of mobile field technicians who are based throughout Compressco’s market areas. The GasJack® unit 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® unit, 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® unit 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 40-horsepower electric VJackTM compressor unit 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 VJackTM unit provides production uplift with zero engine-driven emissions, and Compressco believes it requires significantly less maintenance than a natural gas powered compressor. The VJackTM unit 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.

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 packages, two heavy lift vessels, 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 our subsidiary, Epic Diving & Marine Services (Epic). Well abandonment, decommissioning, and certain construction services are performed primarily offshore 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 toppled or severely damaged by windstorms. In December 2012, the Offshore Services segment sold its electric wireline operation. The Offshore Services segment provides services to major oil and gas companies and independent operators, including Maritech, through its facilities located in Lafayette, Broussard, Belle Chasse, 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. Including the 1,600-metric-ton heavy lift derrick barge we purchased in July 2011, we currently have three vessels capable of performing heavy lift decommissioning and construction projects and integrated operations on oil and gas production platforms. One of the heavy lift vessels, however, has recently been idled due to decreased demand in the shallow waters of the Gulf of Mexico in which it has operated historically. The Offshore Services segment is pursuing the sale of this vessel. The Offshore Services segment leases additional dive support vessels as they are needed. One of these leased vessels, the Adams Challenge, as well as one of the Offshore Services segment’s owned dive support vessels, the Epic Explorer, include saturation diving systems that are rated for up to 1,000-foot dive depths.

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. Regulations issued by the Bureau of Ocean Energy, Management, Regulation, and Enforcement (BOEMRE) include Notice To Lessees 2010-G05: “Decommissioning Guidance for Wells and Platforms” (NTL 2010-G05, known as the “Idle Iron Guidance”), which requires that permanent plugs be set in nearly 3,500 nonproducing wells in the U.S. Gulf of Mexico and that approximately 650 oil and gas production platforms in the U.S. Gulf of Mexico be dismantled if they are no longer being used. In October 2011, the BOEMRE’s responsibilities were divided between the Bureau of Ocean Energy Management (BOEM) and the Bureau of Safety and Environmental Enforcement (BSEE), which now 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 an 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. In addition, Maritech is seeking to sell its remaining interests in oil and gas producing properties.

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 remaining well abandonment and decommissioning of its offshore oil and gas platforms and facilities. During the three year period ended December 31, 2012, Maritech has expended approximately $292.2 million on such efforts. Approximately $87.4 million of Maritech decommissioning liabilities remain as of December 31, 2012, and approximately $80.7 million of this amount is planned to be performed during 2013.

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.

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 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 underground brine reserves that contain calcium chloride. These underground brine reserves 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. We obtain hydrochloric acid and limestone raw materials for our Lake Charles, Louisiana, facility from a variety of sources to produce liquid calcium chloride. In February 2011, we shut down the dry (pellet) operation at the Lake Charles, Louisiana plant.

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 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 Production Testing segment of our Production Enhancement Division purchases its production testing and rig cooling equipment and components from third-party manufacturers. The Compressco segment designs and assembles the compressor units 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 well monitoring and sand separation equipment and components from third party manufacturers or from the Production Testing segment. Some of the components used in the assembly of compressor units, 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 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 international 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. Deepwater drilling activity in the U.S. Gulf of Mexico was significantly affected by the April 2010 well blowout of the Macondo well, which resulted in a temporary drilling moratorium in the deepwater Gulf of Mexico as well as a series of regulatory reforms associated with offshore oil and gas operations. Although Gulf of Mexico rig count activity during the last part of 2012 reflects a return of pre-Macondo offshore drilling activity levels, demand for offshore CBF products are generally driven by completion activity, which is also increasing to early 2010 levels. Demand may also continue to be affected by future regulatory restrictions.

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 frac water management services in unconventional shale gas and oil reservoirs. The Division provides frac 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 Marcellus, Utica, Barnett, Eagle Ford, Fayetteville, Cana Woodford, Haynesville, and Granite Wash.

The Division’s principal competitors in the sale of CBFs to the oil and gas industry are Baker Hughes, Baroid Corporation 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 Oil, Petrobras (the national oil company of Brazil), Shell Oil, and Tullow Oil. The Division also sells its CBF products through various distributors. Competitors for the Division’s frac 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. The 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 the industrial water treatment markets as a biocide under the BioRid® tradename. Most of these markets are highly competitive. The Division’s European calcium chloride manufacturing 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 Industrial del Alkali 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. In addition, following the March 2012 acquisition of OPTIMA, 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. During the past two years, the Production Testing segment has expanded its after-frac flowback and production testing equipment fleet and acquired operations to serve the rapidly growing demand for these services. The Production Testing segment’s offshore rig cooling operations, obtained through the acquisition of OPTIMA, primarily serve markets in the North Sea, Australia and Asia-Pacific, the Middle East, and South America. As a result of the acquisitions of ERS and Greywolf, the Production Testing segment has expanded its operations to serve the Appalachian, U.S. Rocky Mountain, and western Canada markets. 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 Marcellus, Barnett, Eagle Ford, Fayetteville, Cana Woodford, Haynesville, Bakken, and Niobrara.

The U.S. and Canadian production testing markets are highly competitive, and competition is based on availability of equipment and qualified personnel, as well as price, quality of service, and safety record. We believe that our equipment, skilled personnel, operating procedures, and safety record give us a competitive advantage in the marketplace. The Production Testing segment plans to continue growing its international 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 international markets we serve. The major customers for this segment include BHP Billiton, Cabot, Chesapeake, ConocoPhillips, Encana, Geosouthern, Halliburton, 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, Eastern 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 region of the United States, it also has a substantial presence in other U.S. producing regions, including the Ark-La-Tex region, North Texas, South Texas, the Central and Northern Rockies, 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 gas resource reservoirs in the United States, including the Cotton Valley Trend, Barnett, Fayetteville, Cana Woodford, Piceance, Bakken, Eagle Ford, and Marcellus. Compressco continues to seek opportunities to further expand its operations into other regions in the Western Hemisphere and elsewhere in the world.

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 units it uses to provide the services. Compressco’s major customers include PEMEX, BP, Anadarko, Devon Energy, and Apache.

Offshore Division

Offshore Services Segment. Demand drivers for the Offshore Services segment’s offshore well abandonment and decommissioning services include the maturity and decline of producing fields in the Gulf of Mexico, aging offshore platform infrastructure, damage to platforms and pipelines from windstorms, and government regulations. Demand for the Offshore Services segment’s construction and other services is driven by the general level of activity of its customers, which is driven by oil and natural gas prices and government regulation. We believe that the regulations issued by the BOEMRE, including NTL 2010-G05, the Idle Iron Guidance, may accelerate the pace at which offshore Gulf of Mexico abandonment and decommissioning will be done in the future. The maturity and production decline of Gulf of Mexico oil and gas fields continues to cause an increase in the number of wells to be plugged and abandoned, and platforms and pipelines to be decommissioned.

Offshore Gulf of Mexico abandonment and decommissioning activity declined in 2012 compared to the higher activity during the past several years after the 2005 and 2008 hurricanes in the Gulf of Mexico, which destroyed or caused significant damage to a large number of offshore platforms and associated wells. While the vast majority of this hurricane-related recovery and removal activity has been completed, it provided the Offshore Services segment the opportunity to develop and acquire specialized equipment and engineering expertise that may be used to provide such services to customers whose offshore wells and production platforms may be damaged by future storms.

Offshore activities in the Gulf of Mexico are highly 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: an adequate fleet of the proper equipment; 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. In July 2011, our Offshore Services segment purchased a heavy lift derrick barge (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, subject to certain adjustments. We believe our integrated service package and vessel and equipment fleets satisfy current market requirements in the U.S. 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, and the majority of the remaining work to be performed for Maritech on properties it operates is planned to be performed by the Offshore Services segment during 2013. Other major customers include Apache, Chevron, McMoRan Exploration, Nexen Petroleum USA Inc., Stone Energy, Versabar, and W&T Offshore. 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 Cal Dive International, Inc., Offshore Specialty Fabricators, Inc, Superior Energy Services, Inc., and Technip USA (formerly Global Industries, Ltd). This market is highly competitive, and competition is based primarily on service, equipment availability, safety record, and price. Our ability to lease or otherwise acquire suitable service vessels and other operating equipment is particularly important to our ability to expand our operations to other markets.

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 Europe, 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, 2012.

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. Our backlog consists of estimated future revenues associated with a portion of our well abandonment and decommissioning business consisting of the non-Maritech share of the well abandonment and decommissioning work associated with the remaining oil and gas properties operated by Maritech. Our estimated backlog on December 31, 2012, was $3.4 million. This compares to an estimated backlog of $11.6 million at December 31, 2011.

Employees

As of December 31, 2012, we had 3,648 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, 2012, we owned or licensed twenty-five issued U.S. patents and had eleven patent applications pending in the United States. Internationally, we had thirty-two owned or licensed foreign patents and thirty-eight foreign patent applications pending. 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 2030. 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; 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, with reporting beginning in 2012 for emissions occurring in 2011. 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 2010, BOEMRE issued several Notices to Lessees (NTLs) and other safety regulations implementing additional safety and certification requirements applicable to drilling activities in the Gulf of Mexico, that have resulted in operations and projects being delayed or suspended. 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;

• 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; and

• certify that the operator has complied with all regulations.

In October 2011, the BOEMRE’s responsibilities were divided between BOEM and the BSEE, which oversees the provisions of the “Idle Iron Guidance.” These agencies’ scopes of responsibility include 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.

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. The Maritech energy insurance package provides operational all risks coverage (excluding named windstorm coverage) for physical loss or damage to scheduled offshore property, including removal of wreck and/or debris, and for operator’s extra expense such as control of well, redrill/extra expense, and pollution and cleanup.

Apart from our Maritech operations, 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 employees 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 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;

• 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 availability of raw materials and labor at reasonable prices;

• possible impairments of long-lived assets, including goodwill;

• 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;

• production volumes and profitability of our El Dorado, Arkansas, facility;

• cost, availability, and adequacy of insurance and the ability to recover thereunder;

• technological obsolescence;

• risks arising from the use of fixed price contracts;

• the valuation of decommissioning liabilities;

• weather risks, including the risk of physical damage to our platforms, facilities, and equipment;

• 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;

• exposure to credit risks from our customers;

• uncertainties about plugging and abandoning wells and structures, including the wells and structures previously sold;

• foreign currency and interest rate risks;

• Compressco’s ability to generate sufficient cash from operations to make cash distributions;

• the impact of existing and future laws and regulations;

• risks related to our foreign operations;

• environmental risks;

• estimates of hurricane repair costs;

• acquisition valuation and integration risks; 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.

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 and 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. To the extent competitors offer comparable products or services at lower prices or higher quality, 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. Such activity could materially and adversely affect our operations.

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

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

Other factors affecting our operating results and activity levels include oil and natural gas industry spending levels for exploration, 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.

Since the April 20, 2010, blowout on the Macondo well, operations in the U.S. Gulf of Mexico have been affected by an increasingly stringent regulatory environment. The BOEMRE issued several regulations, including notices to U.S. Gulf of Mexico operators, which are focused on offshore operating requirements, spill cleanup, and enforcement matters. These regulations also implement additional safety and certification requirements applicable to drilling activities in the Gulf of Mexico that have resulted in operations and projects in the past being curtailed or suspended. Although permitting levels and Gulf of Mexico rig count activity during late 2012 indicate that activity levels have returned to pre-Macondo levels, demand for our products and services in the Gulf of Mexico will continue to be affected by future regulatory restrictions. Future regulatory requirements could further 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, 2012, PEMEX accounted for approximately 7.6% of our consolidated revenues and a significant amount of 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.

During the past several years, incidents of security disruptions throughout 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 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 existing contracts with PEMEX have durations of up to 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 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 existing contracts with PEMEX have durations up to 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, and sodium bromide, 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 underground bromine, hydrobromic acid, and other raw materials which are purchased from third parties. We rely on Chemtura as a supplier of raw materials, both for our bromide compound products as well as for our El Dorado, Arkansas, calcium chloride plant. If we are 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 and rig cooling equipment and wellhead compressor units 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, 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.

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 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. In 2012, we completed three acquisitions: OPTIMA, ERS, and Greywolf. These acquired businesses may not achieve as favorable financial results as we anticipated when we decided to make such acquisitons. These acquisitions and any future acquisition transactions 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.

The production volumes and profitability from our El Dorado, Arkansas, calcium chloride plant facility may not be as high as originally expected.

During late 2009 and early 2010, we completed the construction and began the operation of a calcium chloride plant facility near El Dorado, Arkansas. The plant’s anticipated profitability and the advantages we expected to receive from the plant were based on many factors, including the level of production from the plant, our ability to improve the plant’s performance, sales prices to be received for the plant’s products, raw material and operating costs, and future demand for products. Given the plant’s production volumes and profitability to date, there can be no assurance that the El Dorado, Arkansas, plant’s future profitability will achieve original expectations.

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 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.

We have maintained a policy of insuring our risks of operational hazards that we believe is typical in the industry. Limits of insurance coverage we have purchased are consistent with the exposures we face and the nature of our products and services. Due to economic conditions in the insurance industry, from time to time, we have increased our self-insured retentions for certain policies in order to minimize the increased costs of coverage or we have reduced our limits of insurance coverage for, or not procured, named windstorm coverage. In certain areas of our business, we, from time to time, have elected to assume the risk of loss for specific assets. To the extent we suffer losses or claims that are not covered, or are only partially covered by insurance, our results of operations could be adversely affected.

We have technological and age-obsolescence risk, both with our products and services as well as with our equipment assets.

Competitors constantly evolve their technologies and methodologies and replace their used assets with new assets. If we are unable to adapt to new advances in technology or replace mature assets with new assets, we are at risk of losing customers and market share. In particular, many of our most significant equipment assets, including heavy lift barges and dive support vessels, are approaching the end of their useful lives, which may adversely affect our ability to serve certain customers. The permanent replacement or upgrade of any of our vessels will require significant capital. Due to the unique nature of many of these vessels, finding a suitable or acceptable replacement may be difficult and/or cost prohibitive. The replacement or enhancement of these vessels over the next several years may be necessary in order for the Offshore Services segment to effectively compete in the current marketplace.

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 or qualified 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 or on well abandonment and decommissioning work for our Maritech subsidiary.

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; 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 relate to offshore production platforms that were toppled and destroyed during 2005 and 2008 hurricanes, and the estimates to perform the work on these properties is particularly imprecise due to the unusual nature of the work to be performed. During 2012, Maritech adjusted its decommissioning liabilities, increasing them by approximately $40.8 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 2012. If the actual cost of future abandonment and decommissioning work is materially greater than our current estimates, such additional costs could have an additional adverse effect on 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 frac 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 onshore Fluids Division customers from accessing water supplies, frac water operations may become impractical, and our Fluids Division business may be negatively affected.

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, rising water, 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.

A portion of the costs resulting from damages from the 2005 and 2008 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 six offshore platforms that were destroyed by Hurricanes Rita and Ike during 2005 and 2008, respectively. As of December 31, 2012, Maritech has remaining work associated with two of the downed platforms. The estimated cost to perform the remaining abandonment, decommissioning, and debris removal is approximately $13.9 million net to our interest before any insurance recoveries. 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 $13.9 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 $87.4 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

Significant 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, 2012, our total debt outstanding was approximately $366.7 million, and our debt to total capital ratio was 41.4%. This debt to total capital ratio excludes approximately $74.0 million of available cash held as of December 31, 2012. 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. Our long-term debt agreements contain customary covenants and other restrictions and requirements. In addition, the agreements require us to maintain certain financial ratio requirements. Significant 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 the 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 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-sized to medium-sized oil and gas operating companies 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 certain oil and gas property interests, Maritech is liable for the proper abandonment and decommissioning of the wells, platforms, and pipelines, as well as the site clearance related to 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.

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.

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, and the Mexican 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, 2012, we have $51.2 million outstanding under our revolving credit facility. Our revolving credit facility consists 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 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.

The terms governing our revolving credit facility were agreed to in October 2010, and it is scheduled to mature in 2015. The terms governing our Senior Notes were agreed to in April 2006, April 2008, and October 2010. These Senior Notes all bear interest at fixed interest rates and are scheduled to mature at various dates between April 2013 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.

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, 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, importation and exportation restrictions, and restrictions on 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 Maritech’s remaining well abandonment and decommissioning operations are conducted on offshore federal leases and are governed by increasing U.S. government regulations. During 2010, the BOEMRE issued formal Notice to Lessees (NTLs) and other safety regulations implementing additional safety and certification requirements applicable to drilling activities in the Gulf of Mexico. 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 require that permanent plugs be set in nearly 3,500 nonproducing wells and that 650 oil and gas production platforms be dismantled if they are no longer being used. In October 2011, the BOEMRE’s responsibilities were divided between the BOEM and the BSEE, which oversees the provisions of the Idle Iron Guidance. Under limited circumstances, the BSEE could require Maritech to suspend or terminate its operations on a federal lease. The BOEM also establishes the basis for royalty payments due under federal oil and natural gas leases through regulations issued under applicable statutory authority.

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 affect our business. 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 business 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, which may have a negative impact on our business. In addition to potential impacts on our business directly or indirectly resulting from climate change legislation or regulations, our business 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 the types of services offered by certain of 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, Mexico, Norway, Sweden, and the United Kingdom, and have operating joint ventures in Libya and Saudi Arabia. A portion of our planned future growth includes expansion into additional countries. Foreign operations carry special risks. Our business in the countries in which we currently operate and those in which we may operate in the future could be limited or disrupted by:

• restrictions on repatriating 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

• the limited knowledge of these markets or the inability to protect our interests.

We and our affiliates operate in countries where governmental corruption has been known to exist. While we and our subsidiaries are committed to conducting business in a legal and ethical manner, there is a risk of violating either the U.S. Foreign Corrupt Practices Act (FCPA) 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 when we expect, our growth and profitability from international operations could be negatively affected.

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 to reduce emissions of GHGs associated with our operations. 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.

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, barge rigs, heavy lift and 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 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, 2012. We believe our facilities are adequate for our present needs.

Facilities

Fluids Division

Fluids Division facilities include seven active 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 mineral acreage, solar evaporation ponds, and related production and storage facilities. In addition, the Fluids Division also owns and leases brine mineral reserves in Arkansas.

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 twenty-seven service center facilities, sixteen in the United States and eleven internationally. The Fluids Division also leases eight offices and twenty-eight terminal locations, fourteen throughout the United States and fourteen internationally.

We also lease approximately 33,000 gross acres of bromine-containing brine reserves in Magnolia, Arkansas. We hold these assets for possible future development and to provide a security of supply for our bromine and other raw materials.

Production Enhancement Division

The Production Testing segment conducts its operations through thirteen production testing service centers (twelve of which are leased) in the U.S., 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, Libya, United Arab Emirates, Ghana, Angola, Saudi Arabia, Iraq, Argentina, Australia, Canada, United Kingdom, 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, a leased service and sales facility in New Mexico, leased service facilities in Argentina, California, and Mexico, and sales offices in California, Canada, Colorado, Louisiana, New Mexico, Oklahoma, Pennsylvania, and Texas.

Offshore Division

The Offshore Division conducts its operations through six offices and service facility locations (five of which are leased) located in Texas and Louisiana. In addition, the Offshore Services segment owns the following fleet of vessels that it uses in performing its well abandonment, decommissioning, construction, and contract diving operations:

TETRA Hedron	Derrick barge with 1,600-ton fully revolving crane
TETRA Arapaho	Derrick barge with 800-ton capacity crane
TETRA DB-1	Derrick barge with 615-ton capacity 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 2013, with an option to extend for an additional 12 months. The Adams Challenge is a 280-foot dynamically positioned dive support vessel with a 1,000-foot saturation diving system. One of our vessels, the TETRA DB-1, has recently been idled due to decreased demand in the shallower waters of the Outer Continental Shelf in the Gulf of Mexico in which it has historically operated. The Offshore Services segment is pursuing the sale of this vessel.

See below for a discussion of the Offshore Division’s oil and gas property assets.

Corporate

Our headquarters are located in The Woodlands, Texas, in a 153,000 square foot office building, which is located on 2.635 acres of land. In December 2012, we entered into a sale leaseback transaction whereby 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 to service our Fluids Division operations.

Oil and Gas Properties

The following tables show, for the periods indicated, operating 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, 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 2012, 2011, and 2010:

	Year Ended December 31,
	2012		2011			2010
Production:
Natural gas (Mcf)		310,894			3,321,651			7,065,258
NGL (Bbls)		38,681			88,070			132,191
Oil (Bbls)		23,040			611,748			1,360,126

Revenues:
Natural Gas	$	1,609,000		$	14,596,000		$	60,416,000
NGL		1,907,000			4,744,000			6,003,000
Oil		2,641,000			62,601,000			131,422,000
Total	$	6,157,000		$	81,941,000		$	197,841,000

Average realized unit prices and production costs:
Natural gas (per Mcf)	$	5.18		$	4.39		$	8.55
NGL (per Bbl)	$	49.30		$	53.87		$	45.41
Oil (per Bbl)	$	114.63		$	102.34		$	96.62

Production cost per equivalent barrel	$	33.02		$	26.72		$	26.62
Depletion cost per equivalent barrel	$	–		$	22.05		$	27.60

Realized unit prices during 2010 and 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. Insurance recoveries during 2010 totaled approximately $2.5 million and are excluded from production cost per equivalent barrel for the year. Depletion cost per equivalent barrel excludes the impact of dry hole costs and property impairments.

Acreage and Productive Wells

At December 31, 2012, our Maritech subsidiary owned interests in the following oil and gas wells and acreage:

Productive Gross

Productive Net

Developed

Undeveloped

Wells

Acreage

State/Area

Oil

Gas

Oil

Gas

Gross

Net

Gross

Net

Louisiana Onshore

–

Louisiana Offshore

–

1.3

–

1,187

594

Texas Onshore

–

Texas Offshore

–

Federal Offshore

–

26,875

12,463

31,809

15,116

Total

–

1.3

26,875

12,463

32,996

15,710

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 2013 through 2015. The following table sets forth the expiration amounts of our gross and net undeveloped acreage as of December 31, 2012:

Held by

2013

2014

2015

2016

2017

Production

State/Area

Gross

Net

Gross

Net

Gross

Net

Gross

Net

Gross

Net

Gross

Net

Louisiana Onshore

–

Louisiana Offshore

–

1,187

594

Texas Offshore

–

Federal Offshore

–

1,250

–

57,434

26,329

Total

–

1,250

–

58,621

26,923

Maritech has no significant delivery commitments with regard to its future oil and gas production.

Drilling Activity

During 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. During 2010, Maritech participated in the drilling of 6 gross development wells (4.32 net wells) and two gross exploratory wells (1.5 net wells), 7 of which were productive. As of December 31, 2012, there were no wells in the process of being drilled.

Significant Oil and Gas Properties

As of December 31, 2012, Maritech has sold all of its most significant oil and gas producing properties and is in the process of selling all of its remaining oil and gas producing properties. These remaining oil and gas properties are classified as Oil and Gas Properties Held for Sale in our accompanying consolidated balance sheet as of December 31, 2012. 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, 2012, is as follows:

	Year Ended December 31,
	2012			2011			2010
	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	555	25	912
Main Pass Area	–	–	–	53	22	862	87	35	2,362
East Cameron 328	–	–	–	61	–	32	213	–	132

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.

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, 2013, there were approximately 9,205 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, 2012, as reported by the New York Stock Exchange.

	High		Low
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

2011
First Quarter	$	15.57		$	10.41
Second Quarter		16.00			11.63
Third Quarter		13.45			7.71
Fourth Quarter		10.53			6.77

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 Sector), assuming $100 invested in each stock or index on December 31, 2007, 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.

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. We declared a dividend of one Preferred Stock Purchase Right per share of common stock to holders of record at the close of business on November 6, 1998. See “Note T – Stockholders’ Rights Plan” in the Notes to Consolidated Financial Statements attached hereto for a description of such Rights. 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 2012 pursuant to the repurchase program. Shares repurchased during the fourth quarter of 2012 other than pursuant to our repurchase program are as follows:

						Maximum Number (or
			Average		Total Number of Shares	Approximate Dollar Value) of
	Total Number		Price		Purchased as Part of	Shares that May Yet be
	of Shares		Paid per		Publicly Announced	Purchased Under the Publicly
Period	Purchased		Share		Plans or Programs(1)	Announced Plans or Programs(1)

Oct 1 – Oct 31, 2012	448	(2)	$	5.71	–	$	14,327,000
Nov 1 – Nov 30, 2012	6,323	(2)		6.70	–		14,327,000
Dec 1 – Dec 31, 2012	3,219	(2)		7.29	–		14,327,000
Total	9,990				–	$	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, 2012, 2011, 2010, 2009, and 2008. 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 12 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 2008, Maritech acquired certain oil and gas properties. During 2012, our Production Testing segment acquired OPTIMA, ERS, and Greywolf. During 2008, we recorded significant impairments of oil and gas properties, goodwill, and other long-lived assets. 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 2012 to earlier years.

	Year Ended December 31,
	2012			2011				2010				2009				2008
	(In Thousands, Except Per Share Amounts)
Income Statement Data
Revenues	$	880,831			$	845,275			$	872,678			$	878,877			$	1,009,065
Gross profit		168,869				90,510				43,707				213,097				152,001
General and administrative expense		133,138				113,273				100,132				100,832				104,949
Interest expense		17,378				17,195				17,528				13,207				17,557
Interest income		(298)				(756)				(224)				(417)				(779)
Other (income) expense, net		(9,532)				(45,435)				64				(5,895)				(12,884)
Income (loss) before discontinued
operations		18,754				5,482				(43,325)				68,807				(9,655)
Net income (loss)		18,757				5,418				(43,718)				68,804				(12,136)
Net income (loss) attributable to
TETRA stockholders	$	15,960			$	4,147			$	(43,718)			$	68,804			$	(12,136)

Income (loss) per share, before
discontinued operations attributable
to TETRA stockholders	$	0.21			$	0.05			$	(0.57)			$	0.92			$	(0.13)
Average shares		77,293				76,616				75,539				75,045				74,519

Income (loss) per diluted share,
before discontinued operations
attributable to TETRA stockholders	$	0.20			$	0.05			$	(0.57)			$	0.91			$	(0.13)
Average diluted shares		77,963	(1)			77,991	(2)			75,539	(3)			75,722	(4)			74,519	(3)

(1)	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.
(2)	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.
(3)	For the years ended December 31, 2008 and 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 periods.
(4)	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,
	2012		2011			2010			2009			2008
	(In Thousands)
Balance Sheet Data
Working capital	$	178,294		$	296,136		$	198,106		$	148,343		$	222,832
Total assets		1,261,818			1,203,310			1,299,628			1,347,599			1,412,624
Long-term debt		331,268			305,000			305,035			310,132			406,840
Decommissioning and other
long-term liabilities		80,427			96,857			261,438			218,498			277,482
Equity		593,308			569,088			516,323			576,494			515,821

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operation.

The following discussion is intended to analyze major elements of our consolidated financial statements and provide insight into important areas of management’s focus. This section should be read in conjunction with the Consolidated Financial Statements and the accompanying Notes included elsewhere in this Annual Report.

Statements in the following discussion may include forward-looking statements. These forward-looking statements involve risks and uncertainties. See “Item 1A. Risk Factors,” for additional discussion of these factors and risks.

Business Overview

During 2012, we continued to pursue our strategy for growth in a market environment characterized by high oil prices, comparatively low domestic natural gas prices, recovering Gulf of Mexico activity levels, an emergence of attractive international contracts, and continuing overall economic uncertainty. In response to each of these market factors, we initiated or continued strategic efforts to capitalize on specific growth opportunities. The most significant of these market developments continues to be the strength of domestic onshore shale reservoir activity. While the growth levels of certain shale reservoir fields have crested, activity levels in the Eagle Ford, Bakken, Niobrara, and Permian Basin fields have remained robust. As part of our efforts to strategically expand the markets served by our Production Testing segment during 2012, we acquired the assets and operations of Eastern Reservoir Services (ERS), and Greywolf Production Systems, Inc. and GPS Ltd. (together Greywolf). These acquisitions contributed significant growth for our Production Testing segment and allow the segment to capture a greater share of the domestic and Canadian markets. Also, in response to continuing strong shale reservoir activity, our Fluids Division has organically expanded its domestic onshore operations to serve the demand for its frac water management services. The strength of domestic and Canadian crude oil and liquids prices has also led our Compressco segment to continue its focus on expanding its capacity to provide unconventional compression applications as a compliment to its significant dry gas production enhancement services. In the U.S. Gulf of Mexico, government restrictions and delays in obtaining regulatory permits have eased somewhat and have resulted in a return to pre-Macondo activity levels. Our Fluids Division has capitalized on this growth, resulting in significant increases in its deepwater offshore clear brine fluids (CBF) sales activity. However, the U.S. Gulf of Mexico well abandonment and decommissioning market remains challenging for our Offshore Services segment, and we have implemented cost reduction and asset rationalization efforts to improve the focus and efficiency of this segment. Outside of the United States, we are exploiting unique opportunities for many of our businesses. Our Compressco segment continues to grow its Latin America operations, while also continuing to pursue other international opportunities. Our Production Testing segment expanded its scope of services and international presence with the acquisition of Optima Solutions Holding Limited (OPTIMA), an Aberdeen, Scotland-based provider of offshore rig cooling services and associated products that suppress heat generated by high-rate flaring of hydrocarbons during well test operations. Our Production Testing and Fluids segments have each also expanded their Eastern Hemisphere operations through new service contracts and additional activity under existing service contracts, particularly in the Middle East.

Our consolidated revenues and gross profit for the year ended December 31, 2012, reflect the growth of our Production Testing, Compressco, and Fluids segments, each of which achieved record revenue levels during 2012. In particular, the results of our Production Testing segment for 2012 include the impact of its acquisitions of OPTIMA, ERS, and Greywolf. During 2012, these acquisitions contributed aggregate revenues of $62.2 million and income before taxes, net of $2.8 million of transaction costs, of $6.2 million. Our Compressco segment also reflected growth in revenues and profitability during 2012 compared to 2011, primarily as a result of the increased Latin America activity, but also due to the growth of its domestic unconventional application services. Our Fluids Division also reported increased revenues and profitability compared to 2011, primarily due to the increased CBF product sales from increased activity in the Gulf of Mexico and from increased services revenues and profits from its growing domestic frac water management operation. These increases in Fluids Division CBF and services revenues more than offset the decreased revenues from its manufactured products operation. Partially offsetting the growth in these segments, our Offshore Services segment reported decreased revenues during 2012 compared to 2011 due to a number of factors, including weather disruptions, customer project delays, and pricing pressures. Following the sales of its oil and gas producing properties, our Maritech segment now generates minimal revenues. Increased consolidated gross profit was partially offset by increased consolidated general and administrative expense, primarily due to the above mentioned acquisitions.

Despite spending an aggregate of approximately $163.3 million on acquisitions and an additional $107.5 million on capital expenditures during 2012, our balance sheet remains strong. The majority of the funding for this growth was provided from available cash, and of the $88.4 million of cash that was borrowed during 2012, $28.6 million was repaid by year-end. Our asset review efforts contributed approximately $59.3 million in cash from the sale of certain assets, including the sale and leaseback of our corporate headquarters facility. Cash provided from operations during 2012 was approximately $17.7 million, as our focus on cash generation during the fourth quarter, including improved accounts receivable collections, helped offset the significant expenditures to extinguish Maritech’s remaining decommissioning liabilities during the year. Despite the sale of the Maritech properties in 2011 and 2012, we continue to utilize a significant portion of our operating cash flows to extinguish Maritech’s remaining decommissioning liabilities. We expended approximately $94.4 million on decommissioning work performed during 2012, and a majority of the remaining decommissioning liability is anticipated to be extinguished during 2013. As of December 31, 2012, we had a consolidated cash balance of approximately $74.0 million,

although approximately $13.0 million of the balance is on Compressco Partners’ balance sheet to satisfy its operating requirements as well as to fund quarterly distributions pursuant to its partnership agreement. Subsequent to December 31, 2012, we repaid approximately $38.0 million of our outstanding balance under our revolving credit facility, and as of March 1, 2013, we had approximately $256.3 million available under the facility. As a result of our strong balance sheet, we remain focused on the growth priorities for our core service businesses, including the pursuit of additional acquisitions and funding the ongoing growth capital needs of our segments.

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 current pricing levels of natural gas, particularly as compared to crude oil. However, we believe that there are growth opportunities for our products and services in the U.S. and foreign markets, 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, 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; fluid engineering consultation; and fluid management services; as well as domestic onshore frac water management services. In addition, 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 $30.0 million during 2012 compared to 2011, primarily due to increased CBF product sales from increased activity in the Gulf of Mexico, as permitting activity has increased compared to the prior year. Although demand levels for the Fluids Division’s CBF products are driven primarily by completion activity rather than drilling activity, the increase in the Gulf of Mexico rig count during late 2012 to pre-Macondo levels reflects the increasing demand for offshore CBF products, which steadily increased during 2012. Demand may continue to be affected by future regulatory restrictions. We anticipate continued increases in industry spending in 2013, particularly given the current levels of crude oil prices. Also, continuing to capitalize on the industry trend toward developing unconventional onshore shale reservoirs, the Fluids Division has expanded its onshore frac water management operation, which also contributed to increased revenues and profitability during 2012.

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, 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 drilling and completion activities in the markets where the Production Testing segment serves. The Production Testing segment’s revenues increased significantly by $68.2 million in 2012 compared to 2011, primarily due to the acquisitions of OPTIMA, ERS, and Greywolf during 2012, and due to increased activity in unconventional shale reservoirs. The Production Testing segment anticipates that revenues will continue to increase in 2013 compared to 2012, primarily as a result of the 2012 acquisitions.

Compressco 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, Eastern 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. Compressco segment revenues increased $13.7 million in 2012 as compared to 2011, primarily due to increased service revenues resulting from increased demand, particularly in Latin America, partially offset by a decrease in sales of compressor units. While there are uncertainties in Latin America that could affect operations, including the 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 Coast region. Gulf of Mexico platform decommissioning and well abandonment activity levels are driven primarily by BSEE regulations; the age of producing fields; 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 $21.4 million during 2012 compared to 2011, due to a number of factors including decreased work performed for Maritech, decreased diving, abandonment, and cutting services activity, customer project delays, weather disruptions, pricing pressures, and the sales of certain operations during the past year. In addition, the profitability of our Offshore Services segment was affected by approximately $8.4 million of impairments, primarily related to the decision to sell one of its heavy lift derrick barges due to decreased demand in the shallow waters in which it has historically operated. However, the Offshore Services segment anticipates increased profitability going forward compared to 2012 as a result of cost reduction and asset rationalization initiatives which began during the latter part of 2012.

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. As part of this strategic decision, beginning in 2011, Maritech began selling oil and gas property packages to industry participants and other third parties. Maritech is continuing to seek the sale of its remaining oil and gas producing properties during 2013. As a result of these sales of oil and gas properties, Maritech’s revenues during 2012 decreased by $76.6 million compared to 2011 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, and we expect to complete the majority of this remaining work during 2013.

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. Although the majority of our impairments of long-lived assets have typically related to oil and gas properties, during 2012 we recorded other long-lived asset impairments of $8.4 million. Given the current uncertain economic environment, the likelihood of additional material impairments of long-lived assets in future periods 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. Beginning in 2011, 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, 2012. 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 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 over estimate 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.

Decommissioning Liabilities

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. These well abandonment and decommissioning liabilities (referred to as decommissioning liabilities) are recorded net of amounts allocable to joint interest owners and any contractual amounts to be paid by the previous owners of the property. 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. Maritech has adjusted its decommissioning liabilities during 2011 and 2012 as a result of increased estimates, as well as a result of the cost of significant abandonment and decommissioning work performed during the year. Maritech recorded approximately $40.8 and $78.4 million of excess decommissioning expense during 2012 and 2011, respectively, associated with work performed or to be performed on nonproductive 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 estimation of the decommissioning liabilities associated with the two remaining Maritech offshore platforms that were destroyed during the 2005 and 2008 hurricanes is particularly difficult due to the non-routine nature of the efforts required. The actual cost of performing Maritech’s well abandonment and

decommissioning work has often exceeded our initial estimate of Maritech’s 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 and decommissioning 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. With regard to 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 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. Despite the uncertainties associated with estimating the total contract cost, our recognition of revenue associated with these contracts has historically been reasonable.

Our Production Testing segment is party to a South American technical management contract which contains multiple deliverables, including the delivery of equipment and the performance of service milestones. While the contract provides contract-determined values associated with each deliverable, the recognition of revenue is determined based on the realized market values received by the customer as well as by the realizability of collections under the contract. 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.

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.

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		168,869			90,510			78,359		86.6%
Gross profit as a percentage of revenue		19.2%			10.7%
General and administrative expense		133,138			113,273			19,865		17.5%
General and administrative expense as a
percentage of revenue		15.1%			13.4%
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		1155.5%
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 the prior year 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 the prior year, the aforementioned acquisitions, and the increased profitability of our Fluids, Production Testing, and Compressco segments during the current year.

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 compared to the prior year. This increase is due to increased borrowings during 2012.

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 the prior year, primarily due to $14.2 million of hedge ineffectiveness losses recorded during the prior year. Consolidated other income also includes increased earnings from an unconsolidated joint venture compared to the prior year.

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

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. We expect these increased activity levels to continue in 2013. 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 due to increased domestic frac water management service activity in certain of the Division’s shale reservoir markets compared to the prior year. However, the growth in domestic onshore service revenues has slowed compared to prior year periods.

Fluids Division gross profit increased 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 frac water management services operation also increased. We expect to benefit from ongoing operational improvements at our El Dorado, Arkansas, calcium chloride facility in 2013. 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 compared to the prior year 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 an unconsolidated joint venture and foreign 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, the segment reflected revenues from increased domestic drilling in many of its shale reservoir markets compared to the prior year. 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 compared to the prior year 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 an unconsolidated joint venture. 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 the period.

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		40,479			31,035			9,444		30.4%
Gross profit as a percentage of revenue		37.0%			32.4%
General and administrative expense		18,912			14,320			4,592		32.1%
General and administrative expense as
a percentage of revenue		17.3%			15.0%
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 compared to the prior year period 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 units and parts during 2012 compared to the prior year. Compressco continues to expand its fleet in Latin America to serve the increasing demand.

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 unit 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 the current year period 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%

Revenues from our Offshore Services segment decreased in 2012 compared to 2011, primarily due to a decrease in the work performed for Maritech during the current year. 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 the current year, 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 the prior year period. 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 the prior year. Maritech plans to continue to aggressively decommission and abandon its remaining oil and gas platform structures, and we expect that the majority of this remaining Maritech work will be completed during 2013. 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 start up 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. Segment administrative expenses are expected to decrease going forward due to ongoing cost reductions that began in late 2012.

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%
Gross profit (loss) as a percentage of revenue		(639.8)%			(91.6)%
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%
Income (loss) before taxes and discontinued
operations as a percentage of revenue		(694.9)%			(31.8)%

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 the prior year, primarily due to reduced operating and depletion expenses associated with the sold properties. In addition, Maritech recorded $15.2 million of impairments and approximately $37.6 million of higher excess decommissioning costs associated with Maritech’s remaining decommissioning liabilities during the prior year period. We expect the substantial majority of Maritech’s decommissioning liabilities to be extinguished in 2013. Subsequent to December 31, 2012, in February 2013, Maritech entered into a settlement agreement with one of its underwriters relating to litigation involving its insurance claim following Hurricane Ike. Pursuant to the settlement, Maritech received approximately $7.6 million, and the impact of this settlement is expected to be reflected in first quarter 2013 results of operations.

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 the prior year, 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.

2011 Compared to 2010

Consolidated Comparisons

	Year Ended
	December 31,					Period to Period Change
	2011		2010			2011 vs 2010			% Change
	(In Thousands, Except Percentages)
Revenues	$	845,275		$	872,678		$	(27,403)		(3.1)%
Gross profit		90,510			43,707			46,803		107.1%
Gross profit as a percentage of revenue		10.7%			5.0%
General and administrative expense		113,273			100,132			13,141		13.1%
General and administrative expense as a
percentage of revenue		13.4%			11.5%
Interest expense, net		16,439			17,304			(865)		(5.0)%
(Gain) loss on sale of assets		(58,674)			89			(58,763)
Other (income) expense, net		13,239			(25)			13,264
Income before taxes and discontinued operations		6,233			(73,793)			80,026		(108.4)%
Income before taxes and discontinued
operations as a percentage of revenue		0.7%			(8.5)%
Provision for income taxes		751			(30,468)			31,219		(102.5)%
Income before discontinued operations		5,482			(43,325)			48,807		(112.7)%
Income (loss) from discontinued operations,
net of taxes		(64)			(393)			329
Net income		5,418			(43,718)			49,136		(112.4)%
Net income attributable to noncontrolling interest		(1,271)			–			(1,271)
Net income attributable to TETRA stockholders	$	4,147		$	(43,718)		$	47,865		(109.5)%

Consolidated revenues during 2011 decreased compared to 2010, as the decrease in Maritech revenues resulting from sales of almost all of its oil and gas producing properties during 2011 more than offset the growth in revenues from each of our other segments. In particular, revenues from our Production Testing segment increased significantly due to increased domestic demand and higher activity in Mexico. In addition, Fluids segment revenues increased due to CBF sales activity in the regions we serve as well as increased calcium chloride sales activity, primarily domestically. Our Compressco segment reported increased revenues, due largely to increased sales of compressor units during the year, but also due to increased international and domestic demand for its compression based services. Our Offshore Services segment also reported increased revenues due to increased well abandonment and decommissioning service activity during 2011 compared to 2010. Overall gross profit increased primarily due to higher profitability from our Production Testing and Fluids segments, both of which reflect the increased demand for their domestic onshore products and services. Our Offshore Services segment also reflected increased gross profit, primarily due to the impairment of one of its dive service vessels during 2010.

Consolidated general and administrative expenses increased during 2011 compared to 2010 due to approximately $6.9 million of increased salaries, benefits, and other employee-related costs, partially due to increased headcount. This increase was despite a $0.9 million decrease in equity-based compensation. In addition, general and administrative expenses also increased due to approximately $2.3 million of increased professional fee expenses, $2.1 million of decreased billings to joint owners for Maritech administrative overhead, and $1.0 million of increased bad debt expense, primarily due to the reversal of $1.0 million of bad debt expense during 2010. In addition, insurance, taxes, and other general expenses increased by approximately $0.8 million.

Net consolidated interest expense decreased during 2011 primarily due to increased interest income resulting from increased cash investments.

Consolidated gains on sales of assets increased significantly during 2011, primarily due to the sale of Maritech oil and gas producing properties, particularly the May 2011 sale of properties to Tana.

Consolidated other expense was $13.2 million during 2011 and was primarily due to the $14.2 million charge to expense upon the liquidation of commodity derivative swap contracts in connection with the decision to sell Maritech oil and gas producing properties. In addition, 2011 other expense includes approximately $1.3 million of increased foreign currency losses. These increases were partially offset by approximately $2.2 million of decreased other expense compared to 2010 primarily due to a $2.8 million premium that was charged during 2010 in connection with the early repayment of the 2004 Senior Notes.

Our provision for income taxes during 2011 increased due to our increased earnings compared to 2010.

Divisional Comparisons

Fluids Division

	Year Ended
	December 31,					Period to Period Change
	2011		2010			2011 vs 2010			% Change
	(In Thousands, Except Percentages)
Revenues	$	304,536		$	276,337		$	28,199		10.2%
Gross profit		57,470			38,984			18,486		47.4%
Gross profit as a percentage of revenue		18.9%			14.1%
General and administrative expense		26,586			23,712			2,874		12.1%
General and administrative expense as a
percentage of revenue		8.7%			8.6%
Interest (income) expense, net		14			195			(181)
Other (income) expense, net		(1,206)			(876)			(330)
Income before taxes and discontinued operations	$	32,076		$	15,953		$	16,123		101.1%
Income before taxes and discontinued
operations as a percentage of revenue		10.5%			5.8%

The increase in Fluids Division revenues during 2011 compared to 2010 was primarily due to $17.5 million of increased product sales revenues. This increase was due to $10.7 million of increased CBF product sales revenues, as increased activity internationally, particularly in Brazil, more than offset a decrease in domestic offshore activity and pricing. Domestic offshore activity levels continue to be reduced as a result of the uncertain regulations governing offshore drilling activities following the April 2010 Macondo accident. Also contributing to the increased revenues was $6.8 million of increased sales of calcium chloride and other manufactured products, primarily from our El Dorado, Arkansas, calcium chloride plant. Increased onshore domestic activity levels, particularly associated with unconventional shale reservoir markets, resulted in approximately $10.7 million of increased service revenues, including increased revenues from frac water management services.

Our Fluids Division gross profit increased during 2011 compared to 2010, primarily as a result of the increased gross profit from our chemicals manufacturing operations resulting from the 2010 impairment of the $7.2 million carrying value of the Division’s Lake Charles, Louisiana, calcium chloride plant. Due to the market pricing for calcium chloride and the uncertain supply of raw materials needed to operate the plant on economic terms, the expected operating cash flows of the plant were insufficient to cover the plant’s carrying value. In addition, startup costs and production inefficiencies during 2010 negatively affected the profitability of our El Dorado, Arkansas, plant. While many of these production inefficiencies were mitigated during 2011, we continue to seek ways to improve the plant’s operating performance. Associated with these plant operational inefficiencies, in March 2011, we filed a lawsuit in Union County, Arkansas, seeking to recover damages related to certain design and other services provided in connection with the construction of the El Dorado plant. In addition to the improved gross profit from our chemicals manufacturing operations, gross profit generated from the increased frac water management and other services during 2011 more than offset the decreased gross profit from sales of CBFs, that was primarily a result of the decreased domestic offshore market.

Fluids Division income before taxes increased during 2011 compared to 2010 due to the increase in gross profit discussed above and an increase in other income, which more than offset the increased administrative costs. Fluids Division administrative costs increased due to increased salary and employee benefit costs and due to increased professional fees.

Production Enhancement Division

Production Testing Segment

	Year Ended
	December 31,					Period to Period Change
	2011		2010			2011 vs 2010			% Change
	(In Thousands, Except Percentages)
Revenues	$	139,756		$	103,995		$	35,761		34.4%
Gross profit		46,889			22,205			24,684		111.2%
Gross profit as a percentage of revenue		33.6%			21.4%
General and administrative expense		13,809			9,465			4,344		45.9%
General and administrative expense as
a percentage of revenue		9.9%			9.1%
Interest (income) expense, net		(59)			(34)			(25)
Other (income) expense, net		(2,830)			(2,250)			(580)
Income before taxes and discontinued operations	$	35,969		$	15,024		$	20,945		139.4%
Income before taxes and discontinued
operations as a percentage of revenue		25.7%			14.4%

Production Testing revenues increased significantly during 2011 due to an increase of approximately $30.6 million in domestic revenues. This increase was a result of increased domestic onshore oil and gas drilling activity, as reflected by rig count data. In particular, the Production Testing segment is capitalizing on the increased domestic onshore activity associated with unconventional shale drilling in many of the regions it serves. In addition, international revenues increased by approximately $5.3 million, primarily due to increased PEMEX activity in Mexico.

The increase in Production Testing gross profit during 2011 was primarily due to the increased domestic activity discussed above and the increased efficiencies at the higher activity levels. Gross profit on international Production Testing operations also increased during 2011 primarily due to increased profitability on a South American technical management contract.

Production Testing income before taxes increased due to the increased gross profit discussed above. These increases were partially offset by increased administrative expenses, primarily from increased salary and other employee-related costs during the 2011 period. In addition, the Production Testing segment reflected increased office and professional fees, as well as increased bad debt expense, particularly associated with the segment’s Libyan operations.

Compressco Segment

	Year Ended
	December 31,					Period to Period Change
	2011		2010			2011 vs 2010			% Change
	(In Thousands, Except Percentages)
Revenues	$	95,768		$	81,413		$	14,355		17.6%
Gross profit		31,035			28,672			2,363		8.2%
Gross profit as a percentage of revenue		32.4%			35.2%
General and administrative expense		14,320			11,008			3,312		30.1%
General and administrative expense as
a percentage of revenue		15.0%			13.5%
Interest (income) expense, net		(67)			35			(102)
Other (income) expense, net		983			116			867
Income before taxes and discontinued operations	$	15,799		$	17,513		$	(1,714)		(9.8)%
Income before taxes and discontinued
operations as a percentage of revenue		16.5%			21.5%

The increase in Compressco revenues was due to an increase of approximately $9.2 million of revenues from sales of compressor units and parts during 2011 compared to 2010. This increase was primarily due to sales of compressor units to two specific customers, and the level of compressor unit sales going forward is expected to decrease compared to 2011. Compressco service revenue increased by approximately $5.3 million, primarily due to increased international demand for compression services, particularly in Latin America. To a lesser extent, service revenue also increased due to increased domestic demand.

Compressco gross profit increased during 2011 compared to 2010, primarily due to the increased sales of compressor units. In addition, gross profit on international service revenues increased, particularly in Latin America. Gross profit on domestic service revenues decreased, despite the increase in revenues, due to increased operating expenses.

Income before taxes for Compressco decreased during 2011 compared to 2010, despite the increase in gross profit described above, primarily due to increased administrative expense. Compressco administrative expenses reflect the increased professional fee expenses and increased administrative staff as a result of Compressco Partners being a separate public limited partnership and the allocation of a portion of our corporate administrative expenses to Compressco Partners pursuant to the Omnibus Agreement which we and Compressco Partners executed in connection with Compressco Partners’ initial public offering. In addition, the Compressco segment had increased other expense, primarily due to increased foreign currency losses.

Offshore Division

Offshore Services Segment

	Year Ended
	December 31,					Period to Period Change
	2011		2010			2011 vs 2010			% Change
	(In Thousands, Except Percentages)
Revenues	$	287,300		$	274,200		$	13,100		4.8%
Gross profit		33,394			21,695			11,699		53.9%
Gross profit as a percentage of revenue		11.6%			7.9%
General and administrative expense		15,970			17,048			(1,078)		(6.3)%
General and administrative expense as a
percentage of revenue		5.6%			6.2%
Interest (income) expense, net		45			100			(55)
Other (income) expense, net		(1,076)			(117)			(959)
Income before taxes and discontinued operations	$	18,455		$	4,664		$	13,791		295.7%
Income before taxes and discontinued
operations as a percentage of revenue		6.4%			1.7%

Revenues from our Offshore Services segment increased during 2011 compared to 2010, primarily due to increased decommissioning, abandonment and diving services activity. These increases were partially offset by decreased cutting services and wireline activity, and the impact throughout 2011 of a softer pricing environment. In addition, during May 2011, we sold our onshore abandonment operations, although this sale is not expected to significantly reduce our revenues in the future. In July 2011, we purchased a new heavy lift derrick barge (which we named the TETRA Hedron) with a 1,600-metric-ton lift capacity, fully revolving crane. With this vessel, which was placed into service in the Gulf of Mexico during the fourth quarter of 2011, our Offshore Services segment has significantly increased its heavy lift capacity, enabling us to better serve the Gulf of Mexico decommissioning market and to serve customers with heavier structures. Approximately $65.0 million of Offshore Services revenues were from work performed for Maritech during 2011, compared to $62.5 million of such work during 2010. These intercompany revenues are eliminated in consolidation.

Gross profit for the Offshore Services segment during 2011 increased as compared to 2010 due to approximately $15.3 million of impairments during 2010, primarily from the impairment of the carrying value of the Epic Diver, a dive support vessel owned by our Epic Diving & Marine Services subsidiary. During 2010, we determined that this vessel was no longer strategic to the segment’s plan to serve its markets. While the purchase of the TETRA Hedron heavy lift derrick barge is expected to generate increased profitability for our decommissioning operations going forward, gross profit for 2011 was decreased by approximately $6.2 million for the due diligence, inspection, and start up costs incurred during 2011 prior to the vessel being placed into service during the fourth quarter. Overall segment profitability was also affected by a lower pricing environment during 2011, partly due to increased competition.

Offshore Services segment income before taxes increased primarily due to the increase in gross profit described above. In addition, Offshore Services segment administrative costs decreased primarily due to decreased salaries and employee-related, office expenses, insurance, and other general costs. Offshore Services segment income before taxes also increased due to the increase in other income, which was primarily generated from the sale of onshore abandonment operations during 2011.

Maritech Segment

	Year Ended
	December 31,					Period to Period Change
	2011		2010			2011 vs 2010			% Change
	(In Thousands, Except Percentages)
Revenues	$	82,740		$	200,559		$	(117,819)		(58.7)%
Gross profit (loss)		(75,762)			(65,055)			(10,707)		(16.5)%
Gross profit (loss) as a percentage of revenue		(91.6)%			(32.4)%
General and administrative expense		5,893			4,323			1,570		36.3%
General and administrative expense as
a percentage of revenue		7.1%			2.2%
Interest (income) expense, net		73			(107)			180
(Gain) loss on sales of assets		(55,454)			(156)			(55,298)
Other (income) expense, net		1			4			(3)
Income (loss) before taxes and
discontinued operations	$	(26,275)		$	(69,119)		$	42,844		(62.0)%
Income (loss) before taxes and discontinued
operations as a percentage of revenue		(31.8)%			(34.5)%

Maritech revenues decreased significantly during 2011 compared to 2010, due to the sale during 2011 of approximately 95% of Maritech’s total proved oil and gas reserves as of December 31, 2010. The most significant sale of oil and gas producing properties was on May 31, 2011, when Maritech completed the sale to Tana of oil and gas properties that collectively represented approximately 79% of Maritech’s December 31, 2010, total proved reserves. As a result of these sales, decreased production volumes resulted in decreased revenues of approximately $95.4 million. In addition to the impact of decreased production, Maritech revenues decreased approximately $20.5 million, primarily due to decreased realized prices of Maritech’s natural gas production. Maritech had previously hedged a portion of its expected production cash flows by entering into derivative hedge contracts and its contracts hedging its oil production extended through 2011. However, Maritech’s natural gas hedges expired at the end of 2010. Maritech’s average natural gas price received during 2011 was $4.39/MMBtu compared to the $8.55/Mcf average realized price received during 2010. In April 2011, in connection with the planned sale of oil and gas producing properties to Tana, we liquidated the oil derivative hedge contracts. As a result, beginning April 2011, Maritech’s remaining oil and gas production cash flows are no longer hedged. Including the impact of its oil hedge contracts through March 2011, Maritech reflected average realized oil prices during 2011 of $102.34/barrel compared to $96.62/barrel during 2010. Following the above mentioned sales of producing properties, Maritech revenues are expected to continue to be minimal going forward.

Maritech gross profit decreased during 2011 compared to 2010 due to the decreased revenues discussed above, although this was largely offset by decreased operating and depletion expenses also as a result of the sales of properties. Although oil and gas property impairments also decreased approximately $48.5 million during 2011 compared to 2010, this decrease was partially offset by approximately $24.4 million of increased excess decommissioning costs. A large portion of the excess decommissioning costs recorded during 2011 was associated with properties not operated by Maritech. In addition, Maritech recorded approximately $2.5 million of insurance settlement gains during 2010 as a result of settlement and claim proceeds from Hurricane Ike damages. Maritech continues to perform significant decommissioning work on its remaining offshore facilities and platforms, and additional charges for decommissioning costs in excess of estimates may occur in future periods.

Despite the decrease in gross profit discussed above, Maritech reported a decreased loss before taxes during 2011 compared to 2010 due to approximately $55.8 million ($57.5 million consolidated) of net gains on the sales of producing properties during 2011. Partially offsetting this increase in gain on sale was the increase in administrative expenses, primarily due to decreased overhead allocated and billed to joint owners on operated properties, caused by the sales of the properties. In addition, decreased salary, benefit, and employee related expenses resulting from the decrease in administrative staff during the last half of 2011 was largely offset by retention and incentive compensation incurred earlier in the year associated with the sale of Maritech properties. In addition, Maritech administrative expense includes an increase in bad debt expenses, primarily due to a reversal of bad debt expense during 2010.

Corporate Overhead

	Year Ended
	December 31,					Period to Period Change
	2011		2010			2011 vs 2010			% Change
	(In Thousands, Except Percentages)
Gross profit (loss) (primarily depreciation expense)	$	(2,626)		$	(3,238)		$	612		18.9%
General and administrative expense		36,694			34,576			2,118		6.1%
Interest (income) expense, net		16,434			17,112			(678)
Other (income) expense, net		15,839			3,345			12,494
(Loss) before taxes and discontinued
operations	$	(71,593)		$	(58,271)		$	(13,322)		(22.9)%

Corporate Overhead includes corporate general and administrative expense, interest income and expense, and other income and expense. Such expenses and income are generally 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 increased significantly during 2011 compared to 2010, primarily due to increased other expense which resulted from approximately $13.8 million of increased hedge ineffectiveness loss. This increased hedge ineffectiveness loss was 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. In addition, other expense increased due to approximately $1.2 million of decreased foreign currency gains and despite a $2.8 million premium that was charged during 2010 in connection with the early repayment of the 2004 Senior Notes. Corporate administrative costs increased due to approximately $1.5 million of increased salaries and other general employee expenses, despite approximately $1.4 million decrease in equity-based compensation. In addition, corporate administrative costs also increased due to approximately $1.1 million of increased insurance and tax expenses. These increases were partially offset by approximately $0.4 million of decreased professional fee expenses.

Liquidity and Capital Resources

Our growth strategy continues to include the pursuit of suitable acquisitions and other opportunities to expand our operations. During the year ended December 31, 2012, we spent approximately $163.3 million of cash on acquisitions. In March 2012, we spent approximately $65.0 million from our available cash to acquire the common stock of OPTIMA, a provider of offshore rig cooling services and associated products that suppress heat generated by high-rate flaring of hydrocarbons during well test operations. In April 2012, we spent an additional $42.5 million of our available cash to acquire the assets and operations of ERS, a domestic production testing and after-frac flow back operation. In July 2012, we spent an additional $55.5 million from available cash and borrowings to acquire the assets and operations of Greywolf, a North American production testing and after-frac flow back operation. Each of these acquisitions has significantly and strategically expanded our Production Testing segment’s operations. To fund the acquisition of Greywolf and to provide for general corporate working capital needs and other purposes in the last half of 2012, we borrowed $58.0 million and 10.0 million euros (approximately $13.2 million equivalent at December 31, 2012) pursuant to our revolving credit facility. In addition to funding these acquisitions, during the year ended December 31, 2012, we spent $107.5 million on additional capital expenditures for our existing businesses. In addition to funding the acquisition and capital expenditure activity from available cash and borrowings, we also generated approximately $59.3 million from the sale of certain assets, including the sale and leaseback of our corporate headquarters facility. Cash provided by operations also increased during the fourth quarter of 2012, largely as a result of cash collection efforts. Our future operating cash flows, as well as revenues and profitability levels, are largely dependent on the level of oil and gas industry activity in the markets we serve and are significantly affected by oil and natural gas commodity prices. Operating cash flows are expected to increase significantly as a result of the 2012 acquisitions and after the extinguishment of Maritech’s remaining decommissioning liabilities. These efforts resulted in the use of $94.4 million of our operating cash flows during 2012, and the majority of the remaining decommissioning work is expected to be completed in 2013. As of December 31, 2012, we had a consolidated cash balance of approximately $74.0 million, although approximately $13.0 million of this balance is on Compressco Partners’ balance sheet to satisfy its operating requirements and fund quarterly distributions pursuant to its partnership agreement. Although the use of approximately $163.3 million of cash on the above acquisitions significantly changes our liquidity position compared to December 31, 2011, we continue to have significant capital resources, including $256.3 million in availability under our revolving credit facility as of March 1, 2013.

Operating Activities

Cash flows provided by operating activities totalled $17.7 million during 2012 compared to $43.8 million of cash generated by operating activities in 2011, a decrease of $26.1 million. This decrease in operating cash flows during 2012 compared to the prior year primarily reflects the increased use of operating cash flows for working capital during the current year and the sale by Maritech of substantially all of its oil and gas properties during 2011. Increased cash used for working capital during 2012 compared to 2011 was mainly as a result of increased accounts receivable balances and the collection of federal tax refunds during the 2011 period. Cash flows from operating activities have increased following the 2012 acquisitions of OPTIMA, ERS, and Greywolf, and the impact of these acquisitions is expected to continue to generate increased cash flows going forward in 2013 compared to 2012.

During the past three years, Maritech has performed an extensive amount of well abandonment and decommissioning work associated with its offshore oil and gas production wells, platforms, and facilities. As of December 31, 2012, and following the sales of substantially all of its oil and gas producing properties, the estimated third-party discounted value, including an estimated profit, of Maritech’s decommissioning liabilities totalled $87.4 million. Our future operating cash flow will continue to be affected by the actual timing and amount of Maritech’s decommissioning expenditures. Approximately $80.7 million of the cash outflow necessary to extinguish Maritech’s remaining decommissioning liability is expected to occur over the twelve month period ending December 31, 2013. Included in Maritech’s decommissioning liabilities is the remaining abandonment, decommissioning, and debris removal associated with two offshore platforms that were previously destroyed by hurricanes. Due to the unique nature of the remaining work to be performed associated with these downed platforms, 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.

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 $20.6 million of such contractual reimbursement arrangements as of December 31, 2012, is classified as receivable assets related to amounts waiting to be invoiced and/or 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. Given that North American natural gas prices have been volatile and decreased relative to crude oil prices during the past year, 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 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.

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. 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, general liability, vessel pollution liability, and operational risk coverage for our Maritech oil and gas properties, including removal of debris, operator’s extra expense, control of well, and pollution and clean up coverage. Our insurance coverage is subject to deductibles that must be satisfied prior to recovery. Additionally, our insurance is subject to certain exclusions and limitations. 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 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 2012, the total amount of our net cash used in investing activities was $206.7 million and included $163.0 million for the acquisitions of OPTIMA, ERS and Greywolf in March 2012, April 2012 and July 2012, respectively. In addition to cash spent on acquisitions, total cash capital expenditures during 2012 were $107.5 million. Approximately $31.8 million of our capital expenditures during 2012 was spent by our Fluids Division, the majority of which related to the purchase of new equipment to support its onshore frac water management services business. Our Production Enhancement Division spent approximately $62.2 million of capital expenditures, consisting of approximately $40.0 million by the Production Testing segment to add or replace a portion of its production testing equipment fleet, and approximately $22.2 million by the Compressco segment, primarily for the upgrade and expansion of its wellhead compressor and equipment fleet. Our Offshore Services segment spent approximately $12.1 million for costs on its various heavy lift and dive support vessels. Corporate capital expenditures were approximately $1.1 million.

Generally, a significant majority of our planned capital expenditures is related to identified opportunities to grow and expand our existing businesses (other than Maritech). We plan to spend over $100 million on total capital expenditures during 2013. However, certain of these planned expenditures may be postponed or cancelled in an effort to conserve capital. The deferral of capital projects could affect our ability to compete in the future. As reflected by our recent acquisitions of OPTIMA, ERS, and Greywolf, our long-term growth strategy also continues to include the pursuit of suitable acquisitions or opportunities to expand operations in oil and gas service markets. To the extent we consummate an additional significant acquisition transaction or other capital project, our liquidity position and capital plans will be affected.

Sales of assets during 2012 generated approximately $59.3 million of proceeds, including approximately $42.5 million of net proceeds generated from the sale and leaseback of our corporate headquarters facility in The Woodlands, Texas. In addition, identified Offshore Services segment assets were sold for additional consideration of approximately $10.7 million.

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, equity issuances, and other sources of capital.

Our Bank Credit Facilities

We have a revolving credit facility with a syndicate of banks pursuant to a credit facility agreement that was most recently amended in October 2010 (the Credit Agreement). As of December 31, 2012, we had an outstanding balance on the revolving credit facility of approximately $51.2 million and had $7.9 million in letters of credit and guarantees against the $278 million revolving credit facility, leaving a net availability of $218.9 million. As a result of repayments made subsequent to December 31, 2012, availability under the revolving credit facility has increased to approximately $256.3 million as of March 1, 2013. In addition, the amended credit facility 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 $51.2 million outstanding borrowings under the credit facility agreement as of December 31, 2012 is approximately $13.2 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. 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. 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, 2012. 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 $6.7 million equivalent as of December 31, 2012), 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, 2012, we had no borrowings outstanding pursuant to the European Credit Agreement.

Compressco Partners’ Bank Credit Facility

On June 24, 2011, Compressco Partners entered into a credit agreement (the Partnership Credit Agreement) with JPMorgan Chase Bank, N.A., which was amended on December 4, 2012. Under the Partnership Credit Agreement, as amended, Compressco Partners, along with certain of its subsidiaries, are named as borrowers, and all of its existing and future, direct and indirect, domestic subsidiaries are guarantors. We are not a borrower or a guarantor under the Partnership Credit Agreement. The Partnership Credit Agreement, as amended, includes a borrowing capacity of $20.0 million, that is available for letters of credit (with a sublimit of $5.0 million), and includes an uncommitted $20.0 million expansion feature.

The Partnership Credit Agreement may be used to fund Compressco Partners’ working capital needs, letters of credit, and for general partnership purposes, including capital expenditures and potential future acquisitions. So long as Compressco Partners is not in default, the Partnership Credit Agreement may also be used to fund Compressco Partners’ quarterly distributions. Borrowings under the Partnership Credit Agreement are subject to the satisfaction of customary conditions, including the absence of a default. As of December 31, 2012, Compressco Partners had an outstanding balance of $10.1 million under the Partnership Credit Agreement. The maturity date of the Partnership Credit Agreement is June 24, 2015.

All obligations under the 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 the assets (excluding real property) of Compressco Partners 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). Borrowings under the Partnership Credit Agreement, as amended, are limited to a borrowing capacity that is determined based on Compressco Partners’ domestic accounts receivable, inventory, and compressor fleet, less a reserve of $3.0 million. As of December 31, 2012, Compressco Partners had availability under its revolving credit facility of $9.5 million, based upon a $19.6 million borrowing capacity and the $10.1 million outstanding balance.

Borrowings under the Partnership Credit Agreement bear interest at a rate per annum equal to, at Compressco Partners’ option, either (a) British Bankers Association LIBOR (adjusted to reflect any required bank reserves) for an interest period equal to one, two, three, or six months (as it selects) 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 announced from time to time by JPMorgan Chase Bank, N.A. or (2) British Bankers Association 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 any outstanding principal under the Partnership Credit Agreement, Compressco Partners is required to pay customary collateral monitoring fees and letter of credit fees, including without limitation, a letter of credit fee equal to the applicable margin on revolving credit LIBOR loans and fronting fees.

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 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. If an event of default occurs, the lenders are entitled to take various actions, including the acceleration of amounts due under the Partnership Credit Agreement and all actions permitted to be taken by secured creditors.

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 the 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 bear interest at the fixed rate of 6.30% and mature on April 30, 2013. The Series 2008-B Senior Notes bear interest at the 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. We anticipate funding the repayment of the Series 2008-A Senior Notes in April 2013 with available cash balances, borrowings under our revolving credit facility, or through the issuance of additional debt instruments.

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 the fixed rate of 5.09% and mature on December 15, 2017. The Series 2010-B Senior Notes bear interest at the 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.

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 Agreement 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 Agreement 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 Agreement and the Master Note Purchase Agreement as of December 31, 2012. Upon the occurrence and during the continuation of an event of default under the Note Purchase Agreement and the Master Note Purchase Agreement, 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 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 2015, and our Senior Notes mature at various dates between April 2013 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, 2012, net of distributions paid to us, Compressco Partners distributed approximately $4.5 million to its public unitholders.

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, 2012 and 2011, 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

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, 2012, the aggregate amount of the fixed and determinable portion of the purchase obligation pursuant to our Fluids Division’s supply agreements was approximately $220.2 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 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, 2012:

	Payments Due
	Total		2013				2014			2015			2016			2017			Thereafter
	(In Thousands)
Long-term debt	$	366,709		$	35,441			$	–		$	151,268		$	90,000		$	65,000		$	25,000
Interest on debt		72,671			21,240				20,509			15,666			6,472			4,590			4,194
Purchase obligations		220,175			14,275				14,275			14,275			14,275			14,275			148,800
Decommissioning and
other asset retirement
obligations(1)		94,921			80,667	(3)			6,727			–			–			–			7,527
Operating and
capital leases		73,381			11,028				7,471			5,995			5,182			4,566			39,139
Total contractual
cash obligations(2)	$	827,857		$	162,651			$	48,982		$	187,204		$	115,929		$	88,431		$	224,660

(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, 2012.
(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 $4.6 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.
(3)	Approximately $13.9 million of the amounts expected to be paid in 2013 represent well abandonment, decommissioning, and debris removal related to offshore platforms destroyed in the 2005 and 2008 hurricanes.

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, and are not expected to have, a significant impact on the accounting or disclosures in our financial statements.

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 are not expected to have a material impact on our financial condition, results of operations, or liquidity.

Item 7A. Quantitative and Qualitative Disclosures about Market Risk.

Interest Rate Risk

During the last half of 2012, we borrowed $38.0 million and 10.0 million euros (approximately $13.2 million equivalent as of December 31, 2012), net of repayments, pursuant to our revolving credit facility, which included funding for a portion of the consideration for the acquisition of Greywolf. During 2012, Compressco Partners borrowed $10.1 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, 2012, 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
																						Market
	2013		2014			2015			2016			2017			Thereafter			Total			Value

As of December 31, 2012
Long-term debt:
U.S. dollar variable rate	$	–		$	–		$	48,050		$	–		$	–		$	–		$	48,050		$	48,050
Euro variable rate (in $US)		–			–			13,218			–			–			–			13,218			13,218
Weighted average
interest rate (variable)		–			–			2.739%			–			–			–			2.739%
U.S. dollar fixed rate	$	35,441		$	–		$	90,000		$	90,000		$	65,000		$	25,000		$	305,441		$	327,399
Weighted average
interest rate (fixed)		6.300%			–			6.560%			5.900%			5.090%			5.670%			5.900%
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, 2012, 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 and are currently not a party to a foreign currency swap contract or other derivative instrument designed to further hedge our currency exchange rate risk exposure.

Expected Maturity Date

Fair

Market

2013

2014

2015

2016

2017

Thereafter

Total

Value

As of December 31, 2012

Long-term debt:

Euro variable rate (in $US)

–

13,218

–

13,218

Euro fixed rate (in $US)

–

Weighted average

interest rate

–

2.634%

–

2.634%

Variable to fixed swaps

–

Fixed pay rate

–

Variable receive rate

–

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, 2012, 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 (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, 2012.

An assessment of the effectiveness of our internal control over financial reporting as of December 31, 2012, 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, 2012, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Item 9B. Other Information.

None.

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 3, 2013, 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, 2012.

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.

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
	Reports of Independent Registered Public Accounting Firm	F-1
	Consolidated Balance Sheets at December 31, 2012 and 2011	F-3
	Consolidated Statements of Operations for the years ended December 31, 2012, 2011, and 2010	F-5
	Consolidated Statements of Comprehensive Income (Loss) for the years ended December 31, 2012, 2011, and 2010	F-6
	Consolidated Statements of Equity for the years ended December 31, 2012, 2011, and 2010	F-7
	Consolidated Statements of Cash Flows for the years ended December 31, 2012, 2011, and 2010	F-8
	Notes to Consolidated Financial Statements	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	Certificate of Designation of Series One Junior Participating Preferred Stock of the Company dated October 27, 1998 (incorporated by reference to Exhibit 2 to the Company’s Registration Statement on Form 8-A filed on October 28, 1998 (SEC File No. 001-13455)).
	3.7	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)).
	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)).
	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)).
	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)).
	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***	Employee Restricted Stock Agreement between TETRA Technologies, Inc. and Philip N. Longorio, dated February 22, 2008 (incorporated by reference to Exhibit 4.12 to the Company’s Registration Statement on Form S-8 filed on February 22, 2008 (SEC File No. 333-149347)).
	10.18***	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)).
	10.19***	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)).
	10.20***	Transition Agreement effective as of May 5, 2009, by and among TETRA Technologies, Inc. and Geoffrey M. Hertel (incorporated by reference to Exhibit 10.1 to the Company’s Form 8-K filed on May 8, 2009 (SEC File No. 001-13455)).
	10.21	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)).
	10.22	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)).

	10.23***	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)).
	10.24***	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)).
	10.25***	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)).
	10.26	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)).
	10.27	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)).
	10.28	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)).
	10.29	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)).
	10.30***	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)).
	10.31***	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)).
	10.32***	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)).
	10.33***	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)).
	10.34***	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)).
	10.35+	Purchase and Sale Agreement dated December 31, 2012 by and between TETRA Technologies, Inc. and Tetris Property LP.
	10.36+	Lease Agreement dated December 31, 2012 by and between Tetris Property LP and TETRA Technologies, Inc.
	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, 2012, 2011 and 2010; (ii) Consolidated Balance Sheets as of December 31, 2012 and December 31, 2011; (iii) Consolidated Statements of Comprehensive Income for the years ended December 31, 2012, 2011 and 2010; (iv) Consolidated Statements of Cash Flows for the years ended December 31, 2012, 2011 and 2010; (v) Consolidated Statements of Stockholders’ Equity for the years ended December 31, 2012, 2011 and 2010; and (vi) Notes to Consolidated Financial Statements for the year ended December 31, 2012.

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 1, 2013	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 1, 2013
Ralph S. Cunningham	the Board of Directors

/s/Stuart M. Brightman	President, Chief Executive	March 1, 2013
Stuart M. Brightman	Officer and Director
	(Principal Executive Officer)

/s/Elijio V. Serrano	Senior Vice President and	March 1, 2013
Elijio V. Serrano	Chief Financial Officer
	(Principal Financial Officer)

/s/Ben C. Chambers	Vice President – Accounting	March 1, 2013
Ben C. Chambers	and Controller
	(Principal Accounting Officer)

/s/Thomas R. Bates, Jr.	Director	March 1, 2013
Thomas R. Bates, Jr.

/s/Paul D. Coombs	Director	March 1, 2013
Paul D. Coombs

/s/Tom H. Delimitros	Director	March 1, 2013
Tom H. Delimitros

/s/Geoffrey M. Hertel	Director	March 1, 2013
Geoffrey M. Hertel

/s/Kenneth P. Mitchell	Director	March 1, 2013
Kenneth P. Mitchell

/s/William D. Sullivan	Director	March 1, 2013
William D. Sullivan

/s/Kenneth E. White, Jr.	Director	March 1, 2013
Kenneth E. White, Jr.

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	Certificate of Designation of Series One Junior Participating Preferred Stock of the Company dated October 27, 1998 (incorporated by reference to Exhibit 2 to the Company’s Registration Statement on Form 8-A filed on October 28, 1998 (SEC File No. 001-13455)).
3.7	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)).
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)).
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)).
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)).
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***	Employee Restricted Stock Agreement between TETRA Technologies, Inc. and Philip N. Longorio, dated February 22, 2008 (incorporated by reference to Exhibit 4.12 to the Company’s Registration Statement on Form S-8 filed on February 22, 2008 (SEC File No. 333-149347)).
10.18***	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)).
10.19***	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)).
10.20***	Transition Agreement effective as of May 5, 2009, by and among TETRA Technologies, Inc. and Geoffrey M. Hertel (incorporated by reference to Exhibit 10.1 to the Company’s Form 8-K filed on May 8, 2009 (SEC File No. 001-13455)).
10.21	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)).
10.22	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)).
10.23***	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)).
10.24***	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)).
10.25***	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)).
10.26	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)).
10.27	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)).
10.28	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)).
10.29	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)).
10.30***	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)).
10.31***	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)).
10.32***	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)).
10.33***	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)).
10.34***	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)).
10.35+	Purchase and Sale Agreement dated December 31, 2012 by and between TETRA Technologies, Inc. and Tetris Property LP.
10.36+	Lease Agreement dated December 31, 2012 by and between Tetris Property LP and TETRA Technologies, Inc.
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, 2012, 2011 and 2010; (ii) Consolidated Balance Sheets as of December 31, 2012 and December 31, 2011; (iii) Consolidated Statements of Comprehensive Income for the years ended December 31, 2012, 2011 and 2010; (iv) Consolidated Statements of Cash Flows for the years ended December 31, 2012, 2011 and 2010; (v) Consolidated Statements of Stockholders’ Equity for the years ended December 31, 2012, 2011 and 2010; and (vi) Notes to Consolidated Financial Statements for the year ended December 31, 2012.

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, 2012 and 2011, 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, 2012. 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, 2012 and 2011, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2012, 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, 2012, based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 1, 2013, expressed an unqualified opinion thereon.

/s/ERNST & YOUNG LLP

Houston, Texas

March 1, 2013

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, 2012, based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (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, 2012, 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, 2012 and 2011, 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, 2012 of TETRA Technologies, Inc. and subsidiaries, and our report dated March 1, 2013, expressed an unqualified opinion thereon.

/s/ERNST & YOUNG LLP

Houston, Texas

March 1, 2013

F-2

TETRA Technologies, Inc. and Subsidiaries

Consolidated Balance Sheets

(In Thousands)

	December 31, 2012		December 31, 2011

ASSETS
Current assets:
Cash and cash equivalents	$	74,048		$	204,412
Restricted cash		5,571			8,780
Trade accounts receivable, net of allowances for doubtful
accounts of $1,085 in 2012 and $1,849 in 2011		176,352			141,537
Deferred tax asset		29,789			39,330
Inventories		103,041			99,985
Assets held for sale		12,009			3,743
Prepaid expenses and other current assets		34,299			30,714
Total current assets		435,109			528,501

Property, plant, and equipment
Land and building		41,153			76,937
Machinery and equipment		589,725			530,408
Automobiles and trucks		57,708			46,950
Chemical plants		161,565			158,065
Construction in progress		40,452			25,316
Total property, plant, and equipment		890,603			837,676
Less accumulated depreciation		(337,889)			(308,375)
Net property, plant, and equipment		552,714			529,301

Other assets:
Goodwill		189,604			99,132
Patents, trademarks and other intangible assets, net of accumulated
amortization of $27,044 in 2012 and $22,572 in 2011		36,735			11,872
Deferred tax assets		594			258
Other assets		47,062			34,246
Total other assets		273,995			145,508
Total assets	$	1,261,818		$	1,203,310

See Notes to Consolidated Financial Statements

F-3

TETRA Technologies, Inc. and Subsidiaries

Consolidated Balance Sheets

(In Thousands, Except Share Amounts)

	December 31, 2012		December 31, 2011

LIABILITIES AND EQUITY
Current liabilities:
Trade accounts payable	$	67,453		$	46,382
Accrued liabilities		73,254			80,940
Current portion of long-term debt		35,441			35
Decommissioning and other asset retirement obligations, net		80,667			105,008
Total current liabilities		256,815			232,365

Long-term debt, net		331,268			305,000
Deferred income taxes		41,910			48,537
Decommissioning and other asset retirement obligations, net		14,254			34,827
Other liabilities		24,263			13,493
Total long-term liabilities		411,695			401,857

Commitments and contingencies

Equity:
TETRA Stockholders' equity:
Common stock, par value $0.01 per share; 100,000,000 shares
authorized; 80,446,169, shares issued at December 31, 2012,
and 79,673,374 shares issued at December 31, 2011		804			797
Additional paid-in capital		226,954			220,144
Treasury stock, at cost; 2,334,137 shares held at December 31,
2012, and 2,249,959 shares held at December 31, 2011		(15,027)			(14,841)
Accumulated other comprehensive income (loss)		(1,494)			(2,877)
Retained earnings		339,883			323,923
Total TETRA stockholders' equity		551,120			527,146
Noncontrolling interests		42,188			41,942
Total equity		593,308			569,088
Total liabilities and equity	$	1,261,818		$	1,203,310

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,
	2012		2011			2010
Revenues:
Product sales	$	276,155		$	329,489		$	419,926
Services and rentals		604,676			515,786			452,752
Total revenues		880,831			845,275			872,678

Cost of revenues:
Cost of product sales		242,297			306,953			302,675
Cost of services and rentals		385,558			337,235			291,948
Gain on insurance recoveries		–			–			(2,541)
Depreciation, depletion, amortization, and accretion		75,747			94,839			148,022
Impairments of long-lived assets		8,360			15,738			88,867
Total cost of revenues		711,962			754,765			828,971
Gross profit		168,869			90,510			43,707

General and administrative expense		133,138			113,273			100,132
Interest expense, net		17,080			16,439			17,304
(Gain) loss on sales of assets		(4,916)			(58,674)			89
Other (income) expense, net		(4,616)			13,239			(25)

Income (loss) before taxes and discontinued operations		28,183			6,233			(73,793)
Provision (benefit) for income taxes		9,429			751			(30,468)

Income (loss) before discontinued operations		18,754			5,482			(43,325)

Discontinued operations:
Income (loss) from discontinued operations, net of taxes		3			(64)			(393)

Net income (loss)		18,757			5,418			(43,718)
Less: income attributable to noncontrolling interest		(2,797)			(1,271)			–
Net income (loss) attributable to TETRA stockholders	$	15,960		$	4,147		$	(43,718)

Basic net income (loss) per common share:
Income (loss) before discontinued operations attributable
to TETRA stockholders	$	0.21		$	0.05		$	(0.57)
Income (loss) from discontinued operations attributable
to TETRA stockholders		0.00			(0.00)			(0.01)
Net income (loss) attributable to TETRA stockholders	$	0.21		$	0.05		$	(0.58)
Average shares outstanding		77,293			76,616			75,539

Diluted net income (loss) per common share:
Income (loss) before discontinued operations attributable
to TETRA stockholders	$	0.20		$	0.05		$	(0.57)
Income (loss) from discontinued operations attributable
to TETRA stockholders		0.00			(0.00)			(0.01)
Net income (loss) attributable to TETRA stockholders	$	0.20		$	0.05		$	(0.58)
Average diluted shares outstanding		77,963			77,991			75,539

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,
	2012		2011			2010

Net income (loss)	$	18,757		$	5,418		$	(43,718)
Foreign currency translation adjustment, net of taxes
of $(951) in 2012, $(1,828) in 2011, and $2,041 in 2010		1,383			(6,647)			420
Net change in derivative fair value, net of taxes of
$1,578 in 2011 and $(15,481) in 2010		–			2,663			(26,135)
Comprehensive income (loss)		20,140			1,434			(69,433)
Less: comprehensive income attributable to
noncontrolling interest		(2,797)			(1,271)			–
Comprehensive income (loss) attributable to
TETRA stockholders	$	17,343		$	163		$	(69,433)

See Notes to Consolidated Financial Statement

F-6

TETRA Technologies, Inc. and Subsidiaries

Consolidated Statements of Equity

(In Thousands)

									Accumulated Other
	Common		Additional						Comprehensive Income (Loss)
	Stock		Paid-In			Treasury				Derivative			Currency			Retained			Noncontrolling			Total
	Par Value		Capital			Stock				Instruments			Translation			Earnings			Interest			Equity

Balance at December 31, 2009	$	770		$	193,718		$	(8,310)			$	23,472		$	3,350		$	363,494		$	–		$	576,494

Net loss for 2010																		(43,718)						(43,718)
Translation adjustment, net of
taxes of $2,041															420									420
Net change in derivative fair value,
net of taxes of $(15,481)												(26,135)												(26,135)
Comprehensive loss																								(69,433)
Exercise of common stock options		8			1,598			(9)																1,597
Grants of restricted stock, net								(63)																(63)
Stock compensation expense					7,211																			7,211
Tax benefit related to equity-based
compensation, net					517																			517
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 adjustment 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

See Notes to Consolidated Financial Statements

F-7

TETRA Technologies, Inc. and Subsidiaries

Consolidated Statements of Cash Flows

(In Thousands)

	Year Ended December 31,
	2012		2011			2010
Operating activities:
Net income (loss)	$	18,757		$	5,418		$	(43,718)
Reconciliation of net income (loss) to cash provided by
operating activities:
Depreciation, depletion, amortization, and accretion		75,747			94,839			148,022
Impairments of long-lived assets		8,360			15,738			88,867
Provision (benefit) for deferred income taxes		(2,012)			(5,757)			(45,487)
Equity-based compensation expense		9,441			6,288			7,211
Provision for doubtful accounts		(237)			973			(1)
Non-cash income from sold hedge derivatives		–			–			(22,853)
(Gain) loss on sale of property, plant, and equipment		(4,916)			(58,674)			89
Proceeds from insurance settlements		–			–			47,772
Excess decommissioning/abandoning costs		40,767			78,382			53,997
Other non-cash charges and credits		(6,527)			(6,149)			(1,012)
Changes in operating assets and liabilities, net of assets acquired:
Accounts receivable		(31,229)			16,129			6,613
Inventories		(3,749)			2,158			17,308
Prepaid expenses and other current assets		(1,335)			23,447			(2,092)
Trade accounts payable and accrued expenses		7,291			(29,984)			(5,500)
Decommissioning liabilities		(94,419)			(101,920)			(95,872)
Other		1,730			2,899			(19)
Net cash provided by operating activities		17,669			43,787			153,325

Investing activities:
Purchases of property, plant, and equipment		(107,524)			(123,604)			(107,684)
Business combinations, net of cash acquired		(163,305)			(1,500)			(6,250)
Proceeds from sale of property, plant, and equipment		59,325			188,273			2,997
Other investing activities		4,817			(16,330)			(4,949)
Net cash provided by (used in) investing activities		(206,687)			46,839			(115,886)

Financing activities:
Proceeds from long-term debt		88,426			–			90,035
Principal payments on long-term debt		(28,597)			–			(91,784)
Excess tax benefit from equity-based compensation		198			1,334			517
Proceeds from issuance of Compressco Partners' common units,
net of underwriters' discount		–			50,234			–
Compressco Partners' offering costs		–			(2,747)			–
Compressco Partners' distributions		(4,513)			(1,159)			–
Proceeds from sale of common stock and
exercise of stock options		784			3,418			1,287
Deferred financing costs		–			(347)			(5,963)
Net cash provided by (used in) financing activities		56,298			50,733			(5,908)

Effect of exchange rate changes on cash		2,356			(2,307)			435

Increase (decrease) in cash and cash equivalents		(130,364)			139,052			31,966
Cash and cash equivalents at beginning of period		204,412			65,360			33,394
Cash and cash equivalents at end of period	$	74,048		$	204,412		$	65,360

Supplemental cash flow information:
Interest paid	$	18,711		$	18,145		$	19,136
Taxes paid (refunded)		8,020			(12,649)			29,095

Supplemental disclosure of non-cash investing
and financing activities:
Adjustment of fair value of decommissioning liabilities
capitalized to oil and gas properties	$	–		$	1,804		$	65,664

See Notes to Consolidated Financial Statements

F-8

TETRA Technologies, Inc. and Subsidiaries

Notes to Consolidated Financial Statements

December 31, 2012

NOTE A – ORGANIZATION AND OPERATIONS

We are geographically diversified oil and gas services company, focused on completion fluids and associated products and services, frac 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.

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. Compressco provides these 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, Eastern 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.

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 current operations primarily consist of the ongoing abandonment and decommissioning associated with its remaining offshore wells, facilities, and production platforms. Maritech intends to acquire a significant portion of these services 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

Certain previously reported financial information has been reclassified to conform to the current year's 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, 2012, 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.

To the extent we have any outstanding balance under variable rate bank credit facilities, we may 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 2013 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, 2012, are as follows:

	Year Ended December 31,
	2012		2011			2010
	(In Thousands)

At beginning of period	$	1,849		$	2,590		$	5,007
Activity in the period:
Provision for doubtful accounts		(237)			973			(1)
Account chargeoffs		(527)			(1,714)			(2,416)
At end of period	$	1,085		$	1,849		$	2,590

F-10

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, 2012, and December 31, 2011, are as follows:

	December 31,
	2012		2011
	(In Thousands)

Finished goods	$	72,312		$	71,247
Raw materials		5,396			5,653
Parts and supplies		24,497			22,216
Work in progress		836			869
Total inventories	$	103,041		$	99,985

Finished goods inventories include, in addition to newly manufactured clear brine fluids, recycled brines that are repurchased from certain of our customers. Recycled brines are recorded at cost, using the weighted average method.

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, 2012, consists primarily of the estimated fair value of a heavy lift barge from our Offshore Services segment, less estimated selling costs. This asset was reclassified to Assets Held for Sale during late 2012.

Assets Held for Sale as of December 31, 2011, consists of the estimated fair value of Maritech’s remaining oil and gas properties, less estimated selling costs. Following the decision to sell a significant portion of Maritech’s oil and gas properties during the second quarter of 2011, the remaining oil and gas properties were reclassified to Assets Held for Sale. Substantially all of these remaining oil and gas properties were sold by Maritech during the first quarter of 2012.

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 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, 2012, 2011, and 2010 was $70.7 million, $87.7 million, and $139.7 million, respectively.

F-11

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, 2012, 2011, and 2010 was $2.0 million, $1.2 million, and $1.1 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 completed during the year, we acquired intangible assets having a fair value of approximately $27.3 million with estimated lives ranging from 4 to 20 years (having a weighted average useful life of 12.1 years). During 2011, as 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). During 2010, as a part of an acquisition consummated during the year, we acquired intangible assets having a fair value of approximately $0.6 million with estimated useful lives ranging from 3 to 6 years (having a weighted average useful life of 5.3 years). Amortization expense of patents, trademarks, and other intangible assets was $4.5 million, $2.8 million, and $2.8 million for the twelve months ended December 31, 2012, 2011, and 2010, respectively, and is included in depreciation, depletion, amortization and accretion. The estimated future annual amortization expense of patents, trademarks, and other intangible assets is $4.8 million for 2013, $3.5 million for 2014, $3.4 million for 2015, $3.2 million for 2016, and $3.0 million for 2017.

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. Beginning in 2011, 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, 2012. 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.

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, 2012, are as follows:

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	Fluids		Production Testing			Compressco			Offshore Services			Maritech			Total
	(In Thousands)
Balance as of December 31, 2009	$	–		$	23,035		$	72,161		$	3,809		$	–		$	99,005
Goodwill adjustments		–			–			–			–			–			–
Balance as of December 31, 2010		–			23,035			72,161			3,809			–			99,005
Goodwill acquired during the year		–			–			–			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

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.

Impairments of Oil and Gas Properties

During 2012, 2011, and 2010, we identified impairments totaling approximately $0 million, $15.2 million, and $63.8 million, respectively, 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. The oil and gas property impairments during 2010 were mainly associated with Maritech’s non-core properties and were primarily due to significant increases in Maritech’s associated decommissioning liabilities for these properties. Additional oil and gas property impairments were also recorded during 2010 as a result of decreased production volumes, changes in development plans, or due to lower oil and natural gas pricing.

Impairments of Other Long-Lived Assets

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 has 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.

Due to the market pricing for pellet calcium chloride and the uncertain supply of raw materials needed to operate our Fluids Division’s Lake Charles, Louisiana, calcium chloride plant on economic terms, we recorded an impairment of approximately $7.2 million of the plant’s carrying value during the fourth quarter of 2010. In February, 2011, we shut down the pellet plant operation, although the liquid calcium chloride operation remains operational.

During the fourth quarter of 2010, our Offshore Services segment determined that the Epic Diver was no longer strategic to its plans to serve its markets going forward. This decision was influenced by the extension of the charter of a modern dive support vessel that had been leased and utilized by Epic during 2010. The $15.3 million net carrying value of the Epic Diver was impaired during 2010. In January 2011, the Offshore Services segment finalized its decision to divest the Epic Diver, and the vessel was subsequently sold.

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

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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, 2011, our Maritech subsidiary’s decommissioning liabilities were net of approximately $7.0 million 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 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. As a result of decommissioning work performed, we recorded total reductions to the decommissioning liabilities for the years 2012, 2011, and 2010 of $87.4 million, $94.7 million, and $88.2 million, respectively. For a further discussion of adjustments and other activity related to Maritech’s decommissioning liabilities, including significant adjustments made during 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 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. For contracts that contain multiple deliverables, 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.

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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 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

We incurred significant damage to certain of our onshore and offshore operating equipment and facilities, primarily as a result of Hurricane Ike during 2008 and Hurricanes Katrina and Rita during 2005. Our Maritech subsidiary suffered varying levels of damage to the majority of its offshore oil and gas producing platforms during these storms, including 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.

Remaining hurricane damage response efforts as of December 31, 2012, consists primarily of the decommissioning of two of the destroyed Maritech offshore platforms. We estimate that the remaining future abandonment, decommissioning, and debris removal efforts associated with these remaining platforms destroyed by hurricanes during 2005 and 2008 will cost approximately $13.9 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. See below for a discussion of our remaining insurance coverage associated with hurricane damage repairs.

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, including for a portion of the response costs associated with the damages incurred from named windstorms and hurricanes. In addition, other damages are also covered by insurance. 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, 2012 and 2011, is included in accounts receivable in the accompanying consolidated balance sheets.

During 2010, Maritech collected approximately $47.8 million of insurance proceeds associated with Hurricane Ike, which included the settlement of certain coverage at an amount less than the applicable coverage limits. For the $39.8 million of this amount that was collected in March 2010, the amount collected was greater than the covered hurricane repair, well intervention, and abandonment costs incurred as of that date, with the excess representing an advance payment of costs anticipated to be incurred in the future. The collection of these settlement proceeds resulted in the extinguishment of all of Maritech’s insurance receivables, the reversal of the costs previously capitalized for the future decommissioning of oil and gas properties, the reversal of anticipated insurance recoveries that had been netted against certain decommissioning liabilities, and approximately $2.2 million of pre-tax insurance gains that were credited to earnings during 2010. During December 2010 we initiated

F-15

legal proceedings against one of Maritech’s underwriters that is disputing that certain costs incurred or to be incurred qualify as covered costs pursuant to the policies. In February 2013, we entered into a settlement agreement with the underwriter whereby we received $7.6 million in satisfaction of an insurance claim filed in connection with Hurricane Ike.

Anticipated insurance recoveries that have been reflected as insurance receivables were $1.1 million as of December 31, 2012, and $1.1 million at December 31, 2011. 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. During 2010, approximately $2.5 million of such excess proceeds were credited to earnings.

Discontinued Operations

We have accounted for our discontinued businesses as discontinued operations and have reclassified prior period financial statements to exclude these businesses from continuing operations.

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.

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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, 2012 and 2011, was approximately $327.4 million and $332.4 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).

During 2012, our Offshore Services segment recorded total impairment charges of approximately $8.4 million, 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, 2012, using the fair value hierarchy is as follows:

Fair Value Measurements Using

Quoted Prices

in Active

Markets for

Significant

Identical

Other

Significant

Assets

Observable

Unobservable

Year-to-Date

Total as of

or Liabilities

Inputs

Impairment

Description

Dec. 31, 2012

(Level 1)

(Level 2)

(Level 3)

Losses

(In Thousands)

Offshore Services assets

14,000

–

14,000

8,360

During 2011, Maritech recorded total impairment charges of approximately $15.2 million associated with its remaining oil and gas properties. During 2011, Maritech sold approximately 95% of its oil and gas reserves and is seeking to sell its remaining properties at current market values. Accordingly, all of Maritech’s remaining oil and gas properties as of December 31, 2011, have been reclassified to oil and gas properties held for sale and their net book values have been adjusted to fair value less cost to sell. Fair values are estimated based on current market prices being received for these properties’ expected future production cash flows, using forward oil and natural gas pricing data from published sources. Because such published forward pricing data was applied to estimated oil and gas reserve volumes based on our internally prepared reserve estimates, such fair value calculation 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, 2011, using the fair value hierarchy is as follows:

Fair Value Measurements Using

Quoted Prices

in Active

Markets for

Significant

Identical

Other

Significant

Assets

Observable

Unobservable

Year-to-Date

Total as of

or Liabilities

Inputs

Impairment

Description

Dec. 31, 2011

(Level 1)

(Level 2)

(Level 3)

Losses

(In Thousands)

Oil and gas properties

3,743

–

3,743

15,233

Other

246

505

Total

3,989

15,738

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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 31, 2012. The adoption of these ASUs regarding comprehensive income have not had, and are not expected to have, 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 are not expected to have a material impact on our financial condition, results of operations, or liquidity.

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% 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.

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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 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% 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 17.2% and 16.8% of Compressco Partners is owned by public unitholders as of December 31, 2012 and 2011, respectively, and reflected as a noncontrolling interest in our consolidated financial statements.

NOTE D – ACQUISITIONS AND DISPOSITIONS

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 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 production testing related 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 purchase price 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 purchase price consideration obligation; and $35.6 million of nondeductible goodwill. The fair value of the obligation to pay the contingent purchase price consideration was calculated based on the anticipated earnings for OPTIMA over each of the next 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 purchase price consideration obligation 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. During 2012, the liabilities associated with the contingent purchase price consideration obligation were adjusted downward by approximately $1.2 million, 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 represents a strategic geographic expansion of our existing Production Testing segment operations, allowing it to serve customers in additional basins in the U.S.

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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 represents 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. This allocation of the purchase price to the Greywolf assets is preliminary and subject to the potential identification of additional assets and contingencies or revisions to the fair value calculations. These fair value calculations and allocations are expected to be finalized during the first quarter of 2013 and could result in adjustments to the calculated depreciation and amortization of the tangible and intangible assets, respectively. The $34.3 million of goodwill preliminarily recorded to our Production Testing segment as a result of the Greywolf 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 $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 periods presented and include the impact from the allocation of the purchase price on depreciation and amortization. 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		2011
	(In Thousands, Except Per Share Amounts)

Revenues	$	924,795		$	945,112
Depreciation, depletion, amortization, and accretion	$	78,826		$	104,274
Gross Profit	$	180,645		$	121,674

Income before discontinued operations	$	25,858		$	15,071
Net income	$	25,861		$	15,007
Net income attributable to
TETRA stockholders	$	23,064		$	13,736

Per share information:
Income before discontinued operations
attributable to TETRA stockholders
Basic	$	0.30		$	0.18
Diluted	$	0.29		$	0.18

Net income attributable to
TETRA stockholders
Basic	$	0.30		$	0.18
Diluted	$	0.29		$	0.18

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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.

In December 2010, our Offshore Services segment acquired certain well abandonment and wireline assets and operations from ProServ Offshore, Inc., pursuant to an asset purchase agreement. As consideration for the acquired assets, we paid approximately $6.3 million of cash at closing. We allocated the purchase price of this acquisition to the fair value of the assets and liabilities acquired, which consisted of approximately $6.4 million of property, plant, and equipment; $0.6 million of certain intangible assets; and $0.7 million of current liabilities. Intangible assets are amortized over their estimated useful lives, ranging from three to six years.

In July 2010, our Maritech subsidiary purchased interests in certain onshore oil and gas properties located in McMullen County, Texas, from Texoz E&P Holding, Inc. The acquired properties were recorded at a cost of approximately $6.7 million.

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

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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 oil and gas properties 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 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, 2012:

	Capital Lease		Operating Leases
	(In Thousands)

2013	$	76		$	10,952
2014		76			7,395
2015		76			5,919
2016		76			5,106
2017		76			4,490
After 2017		151			38,988
Total minimum lease payments	$	531		$	72,850

Rental expense for all operating leases was $23.9 million, $18.5 million, and $10.9 million in 2012, 2011, and 2010, respectively.

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NOTE F — INCOME TAXES

The income tax provision (benefit) attributable to continuing operations for the years ended December 31, 2012, 2011, and 2010, consists of the following:

	Year Ended December 31,
	2012		2011			2010
	(In Thousands)
Current
Federal	$	1,362		$	(1,661)		$	8,930
State		683			1,294			1,096
Foreign		9,396			6,875			4,993
		11,441			6,508			15,019
Deferred
Federal		(361)			(7,053)			(41,513)
State		(495)			(2,258)			(3,922)
Foreign		(1,156)			3,554			(52)
		(2,012)			(5,757)			(45,487)
Total tax provision (benefit)	$	9,429		$	751		$	(30,468)

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, 2012, 2011, and 2010, to income before income taxes and the reported income taxes, is as follows:

	Year Ended December 31,
	2012		2011			2010
	(In Thousands)
Income tax provision (benefit) computed at
statutory federal income tax rates	$	9,864		$	2,182		$	(25,827)
State income taxes (net of federal benefit)		122			(627)			(1,837)
Nondeductible expenses		2,340			1,577			1,654
Impact of international operations		(2,377)			(1,229)			(3,526)
Other		(520)			(1,152)			(932)
Total tax provision (benefit)	$	9,429		$	751		$	(30,468)

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 $36.9 million at December 31, 2012, 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,
	2012		2011			2010
	(In Thousands)

Domestic	$	2,206		$	(9,167)		$	(92,557)
International		25,977			15,400			18,764
Total	$	28,183		$	6,233		$	(73,793)

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A reconciliation of the beginning and ending amount of our gross unrecognized tax benefit liability is as follows:

	Year Ended December 31,
	2012		2011			2010
	(In Thousands)

Gross unrecognized tax benefits at beginning of period	$	1,552		$	1,849		$	2,256

Additions related to acquisitions		742			–			–
Increases in tax positions for prior years		–			–			–
Decreases in tax positions for prior years		–			–			–
Increases in tax positions for current year		313			–			–
Settlements		–			–			–
Lapse in statute of limitations		(280)			(297)			(407)
Gross unrecognized tax benefits at end of period	$	2,327		$	1,552		$	1,849

We recognize interest and penalties related to uncertain tax positions in income tax expense. During the years ended December 31, 2012, 2011, and 2010, we recognized $0.3 million, $0.3 million, and $(0.2) million, respectively, of interest and penalties to the provision for income tax. As of December 31, 2012 and 2011, we had $2.3 million and $1.5 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 $2.6 million and $1.1 million as of December 31, 2012 and 2011, 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:

Jurisdiction	Earliest Open Tax Period
United States – Federal	2010
United States – State and Local	2002
Non-U.S. jurisdictions	2006

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, 2012 and 2011, are as follows:

	December 31,
	2012		2011
	(In Thousands)

Net operating losses	$	20,888		$	5,570
Foreign tax credits and alternative minimum
tax credits		6,976			5,003
Accruals		46,259			53,584
Goodwill		–			1,975
All other		2,130			17,489
Total deferred tax assets		76,253			83,621
Valuation allowance		(4,048)			(4,769)
Net deferred tax assets	$	72,205		$	78,852

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	December 31,
	2012		2011
	(In Thousands)

Excess book over tax basis in
property, plant, and equipment	$	78,614		$	81,501
All other		7,506			6,225
Total deferred tax liability		86,120			87,726
Net deferred tax liability	$	13,915		$	8,874

The change in the valuation allowance during 2012 primarily relates to the utilization and expiration of certain state net operating losses that were previously fully valued. 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, 2012, we had approximately $137.0 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 2013 through 2032. At December 31, 2012, we had $6.3 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 2022.

NOTE G — ACCRUED LIABILITIES

Accrued liabilities are detailed as follows:

	December 31,
	2012		2011
	(In Thousands)

Compensation and employee benefits	$	15,248		$	12,784
Oil and gas producing liabilities		7,850			15,966
Unearned income		3,318			13,160
Deferred tax liability		2,388			–
Other accrued liabilities		44,450			39,030
Total accrued liabilities	$	73,254		$	80,940

NOTE H – LONG-TERM DEBT AND OTHER BORROWINGS

Long-term debt consists of the following:

		December 31, 2012		December 31, 2011
		(In Thousands)
	Scheduled Maturity
Bank revolving line of credit facility	October 29, 2015	$	51,218		$	–
Compressco Partners' bank credit facility	June 24, 2015		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			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
European bank credit facility			–			–
Other			441			35
Total debt			366,709			305,035
Less current portion			(35,441)			(35)
Total long-term debt		$	331,268		$	305,000

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Scheduled maturities for the next five years and thereafter are as follows:

	Year Ending
	December 31,
	(In Thousands)

2013	$	35,441
2014		–
2015		151,268
2016		90,000
2017		65,000
Thereafter		25,000
Total maturities	$	366,709

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 June 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, 2012, we had a balance of approximately $51.2 million outstanding on the amended revolving credit facility, as well as $7.9 million in letters of credit and guarantees against the $278.0 million availability under the amended revolving credit facility, leaving a net availability of approximately $218.9 million. Subsequent to December 31, 2012, and as of March 1, 2013, we reapid approximately $38.0 million of the outstanding balance under the revolving credit facility, leaving a net availability of approximately $256.3 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, 2012, was 2.7% 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.

Our European Credit Agreement

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Compressco Partners’ Bank Credit Facility

Borrowings under the Partnership Credit Agreement bear interest at a rate per annum equal to, at Compressco Partners’ option, either (a) British Bankers Association LIBOR (adjusted to reflect any required bank reserves) for an interest period equal to one, two, three, or six months (as we select), 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 announced from time to time by JPMorgan Chase Bank, N.A. or (2) British Bankers Association 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, 2012, was 2.5986% per annum. In addition to paying interest on any outstanding principal under the Partnership Credit Agreement, Compressco Partners is required to pay customary collateral monitoring fees and letter of credit fees, including, without limitation, a letter of credit fee equal to the applicable margin on revolving credit LIBOR loans and fronting fees.

The Partnership Credit Agreement requires Compressco Partners to maintain a minimum interest coverage ratio (ratio of earnings before interest and taxes to interest) of 2.5 to 1.0 as of the last day of any fiscal quarter, calculated on a trailing four quarter basis, whenever availability is less than $5 million. In addition, the 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 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. If an event of default occurs, the lenders are entitled to take various actions, including the acceleration of amounts due under the Partnership Credit Agreement and all actions permitted to be taken by secured creditors.

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 Agreement dated April 2008, 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

F-27

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 million or more. We are in compliance with all covenants and conditions of the Note Purchase Agreements as of December 31, 2011. 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 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. In December 2010, partially funded by the $90 million proceeds from the 2010 Senior Notes, we paid $95.7 million to repay the Series 2004 Senior Notes, including principal, accrued interest, and a $2.8 million “make whole” prepayment premium which was charged to other expense.

Pursuant to the Note Purchase Agreements, the Series 2010-A Senior Notes bear interest at the fixed rate of 5.09% and mature on December 15, 2017. The Series 2010-B Senior Notes bear interest at the fixed rate of 5.67% and mature on December 15, 2020. Interest on the 2010 Senior Notes is due semiannually on June 15 and December 15 of each year. The Senior Notes were sold in the United States to accredited investors pursuant to an exemption from the Securities Act of 1933.

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 two 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. 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,
	2012		2011
	(In Thousands)

Beginning balance for the period, as reported	$	139,835		$	272,815

Activity in the period:
Accretion of liability		1,536			4,325
Retirement obligations incurred		–			–
Revisions in estimated cash flows		40,986			79,360
Settlement of retirement obligations		(87,436)			(216,665)
Ending balance	$	94,921		$	139,835

We review the adequacy of our decommissioning liabilities whenever indicators suggest that the estimated cash flows underlying the liabilities have changed materially. 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 2012, we increased the estimated cash flows to decommission these properties by approximately $41.0 million, which resulted in approximately $40.8 million of direct charges to expense during the year. 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 2012 and 2011 was associated with properties not operated by Maritech. Specific factors that caused Maritech’s decommissioning liabilities to increase during 2012 and 2011 included:

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• certain properties that had been previously abandoned required additional work to relieve pressure on wells and to remove structural debris not previously known;

• due to our continued extensive abandonment program begun in prior years, we were able to further refine our estimates for certain properties with similar characteristics and risk profiles to those recently abandoned; and

• two platforms destroyed by hurricanes during 2005 were found to be more extensively damaged than previously estimated, which caused us to add additional costs for removing these downed structures.

Our estimate of remaining hurricane related decommissioning costs is approximately $13.9 million and has been accrued as part of Maritech’s decommissioning liabilities. Settlements of asset retirement obligations during 2011 include approximately $122.0 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

Product Purchase Obligations

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, 2012, we had 78,112,032 shares of common stock outstanding, with 2,334,137 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, 2012, is as follows:

F-29

Common Shares Outstanding	Year Ended December 31,
	2012		2011		2010

At beginning of period		77,423,415		76,291,745		75,542,282
Exercise of common stock options, net		580,097		858,727		354,219
Grants of restricted stock, net		108,520		272,943		395,244
At end of period		78,112,032		77,423,415		76,291,745

Treasury Shares Held	Year Ended December 31,
	2012		2011		2010

At beginning of period		2,249,959		1,533,653		1,497,346
Shares received upon exercise of common stock options		81,616		592,992		630
Shares received upon vesting of restricted stock, net		2,562		123,314		35,677
At end of period		2,334,137		2,249,959		1,533,653

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. See Note T – Stockholders’ Rights Plan for a discussion of our stockholders’ rights plan, as amended.

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, 2012, 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, 2012, 2011, and 2010 was $6.1 million, $4.1 million, and $4.7 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, 2012, 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, 2012, 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-30

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.

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, 2012, we granted to certain officers and employees restricted shares, which generally vest over a three to five year period. 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 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. During 2010, we granted a total of 434,101 restricted shares, having an average market value (equal to the quoted closing price of the common stock on the dates of grant) of $10.20 per share, or an aggregate market value of $4.4 million, at the date of grant. The fair value of awards vesting during 2012, 2011, and 2010, was approximately $4.8 million, $5.2 million, and $2.4 million, respectively.

F-31

The following is a summary of restricted stock activity for the year ended December 31, 2012:

			Weighted Average
			Grant Date Fair
	Shares		Value Per Share
	(In Thousands)

Nonvested restricted shares outstanding at December 31, 2011		512		$	12.38
Shares granted		523			6.83
Shares cancelled		(57)			10.78
Shares vested		(357)			11.25
Nonvested restricted shares outstanding at December 31, 2012		621		$	8.49

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, 2012:

			Weighted Average
			Grant Date Fair
	Units		Value Per Unit
	(In Thousands)

Nonvested units outstanding at December 31, 2011		160		$	17.87

Units granted		95			13.68
Units cancelled		(5)			17.29
Units vested		(97)			16.65
Nonvested units outstanding at December 31, 2012		153		$	16.07

Grants of Options to Purchase Common Stock

The following is a summary of stock option activity for the year ended December 31, 2012:

			Weighted Average
			Option Price
	Shares Under Option		Per Share
	(In Thousands)

Outstanding at December 31, 2011		4,318		$	12.82
Options granted		689			6.84
Options cancelled		(425)			18.20
Options exercised		(249)			4.03
Outstanding at December 31, 2012		4,333		$	11.85

Expected to vest		989		$	9.10
Exercisable, end of year		3,344			12.67
Available for grant, end of year		1,846

F-32

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, 2012, 2011, and 2010, was approximately $0.6 million, $2.5 million, and $1.8 million, respectively. The intrinsic value of options outstanding as of December 31, 2012 was $4.3 million, the intrinsic value of options expected to vest as of December 31, 2012 was $1.0 million, and the intrinsic value of options exercisable as of December 31, 2012 was $3.3 million. Cash received from stock options exercised during the three years ended December 31, 2012, 2011, and 2010, was $0.9 million, $3.4 million, and $1.3 million, respectively. Recognized excess tax benefits (adjustments) related to the exercise of stock options during the three years ended December 31, 2012, 2011, and 2010, were $(1.7) million, $1.3 million, and $0.5 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, 2012:

Year Ended December 31,

2012

2011

2010

Expected stock price volatility

74% to 75%

72% to 75%

72% to 73%

Expected life of options

4.8 years

4.7 years

Risk free interest rate

0.62% to1.03%

0.87% to 2.24%

1.3% to 2.8%

Expected dividend yield

–

The weighted average fair value of options granted during the years ended December 31, 2012, 2011, and 2010 using the Black-Scholes model was $4.06, $7.55, and $6.00 per share, respectively. Total estimated unrecognized compensation cost from unvested stock options and restricted stock as of December 31, 2012, was approximately $7.8 million, which is expected to be recognized over a weighted average period of approximately 1.2 years.

During 2012, 2011, and 2010, we received 24,121, 52,065 and 6,048 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, 2012, 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 $3.5 million, $3.3 million, and $3.3 million in 2012, 2011, and 2010, 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-seven participants in the program at December 31, 2012. 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, 2012, the amounts payable under the plan approximated the value of the corresponding assets we owned.

F-33

NOTE O – 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 of Compressco Partners, to the extent we have debt outstanding, 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 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, 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 Hedge 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, 2010, 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, 2010. Pretax gains and losses associated with oil and gas derivative swap contracts for each of the years ended December 31, 2011 and 2010, 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)

F-34

	Year Ended December 31, 2010
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)	$	22,725		$	26,214		$	48,939
Amount of pretax gain (loss) from change in derivative fair value
recognized in other comprehensive income		(1,947)			9,118			7,171
Amount of pretax gain (loss) recognized in other income (expense)
(ineffective portion)		(152)			–			(152)

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 $13.2 million equivalent as of December 31, 2012) 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 $8.0 million, net of taxes, at December 31, 2012, with no ineffectiveness recorded.

Prior to December 2010, our long-term debt included borrowings which were designated as a hedge of our net investment in our European calcium chloride operations. In December 2010, these euro-denominated borrowings were repaid. During the period these hedge designated euro-denominated borrowings were outstanding, changes in the foreign currency exchange rate resulted in a cumulative change to the cumulative translation adjustment account of $2.6 million, net of taxes, with no ineffectiveness recorded.

NOTE P — INCOME (LOSS) 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,
	2012		2011		2010
	(In Thousands)

Number of weighted average common shares outstanding		77,293		76,616		75,539
Assumed exercise of stock options		670		1,375		–
Average diluted shares outstanding		77,963		77,991		75,539

For the year ended December 31, 2012, the average 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. For the year and the three months ended December 31, 2010, the average diluted shares outstanding excludes the impact of all outstanding stock options, as the inclusion of these shares would have been antidilutive due to the net loss recorded during the period.

NOTE Q – INDUSTRY SEGMENTS AND GEOGRAPHIC INFORMATION

We manage our operations through five operating segments: Fluids, Production Testing, Compressco, Offshore Services, and Maritech. Beginning in the fourth quarter of 2010, certain Mexican production enhancement operations were reclassified from our Production Testing segment to our Compressco segment.

F-35

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 oil and gas 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. Compressco provides these 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, Eastern 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.

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 current operations primarily consist of the ongoing abandonment and decommissioning associated with its remaining offshore wells, facilities, 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:

	Year Ended December 31,
	2012		2011			2010
	(In Thousands)
Revenues from external customers
Product sales
Fluids Division	$	257,558		$	229,426		$	211,917
Production Enhancement Division
Production Testing		–			–			3,610
Compressco		6,322			13,201			4,017
Total Production Enhancement Division		6,322			13,201			7,627
Offshore Division
Offshore Services		6,267			4,921			2,576
Maritech		6,008			81,941			197,806
Total Offshore Division		12,275			86,862			200,382
Consolidated	$	276,155		$	329,489		$	419,926

F-36

	Year Ended December 31,
	2012		2011			2010
	(In Thousands)
Services and rentals
Fluids Division	$	76,858		$	75,032		$	64,358
Production Enhancement Division
Production Testing		207,984			139,755			100,346
Compressco		103,144			82,567			77,396
Intersegment eliminations		(2,354)			–			–
Total Production Enhancement Division		308,774			222,322			177,742
Offshore Division
Offshore Services		218,477			217,341			207,934
Maritech		150			799			2,718
Intersegment eliminations		–			–			–
Total Offshore Division		218,627			218,140			210,652
Corporate overhead		417			292			–
Consolidated	$	604,676		$	515,786		$	452,752

Intersegment revenues
Fluids Division	$	132		$	78		$	62
Production Enhancement Division
Production Testing		–			1			39
Compressco		–			–			–
Total Production Enhancement Division		–			1			39
Offshore Division
Offshore Services		41,199			65,038			63,690
Maritech		–			–			35
Intersegment eliminations		(41,199)			(65,036)			(62,526)
Total Offshore Division		–			2			1,199
Intersegment eliminations		(132)			(81)			(1,300)
Consolidated	$	–		$	–		$	–

Total revenues
Fluids Division	$	334,548		$	304,536		$	276,337
Production Enhancement Division
Production Testing		207,984			139,756			103,995
Compressco		109,466			95,768			81,413
Intersegment eliminations		(2,354)			–			–
Total Production Enhancement Division		315,096			235,524			185,408
Offshore Division
Offshore Services		265,943			287,300			274,200
Maritech		6,158			82,740			200,559
Intersegment eliminations		(41,199)			(65,036)			(62,526)
Total Offshore Division		230,902			305,004			412,233
Corporate overhead		417			292			–
Intersegment eliminations		(132)			(81)			(1,300)
Consolidated	$	880,831		$	845,275		$	872,678

F-37

	Year Ended December 31,
	2012		2011			2010
	(In Thousands)
Depreciation, depletion, amortization, and accretion
Fluids Division	$	19,034		$	19,596		$	20,899
Production Enhancement Division
Production Testing		22,261			13,893			14,429
Compressco		13,398			12,791			13,029
Total Production Enhancement Division		35,659			26,684			27,458
Offshore Division
Offshore Services		16,650			14,502			18,067
Maritech		1,039			31,314			79,012
Intersegment eliminations		–			(174)			(339)
Total Offshore Division		17,689			45,642			96,740
Corporate overhead		3,365			2,917			2,925
Consolidated	$	75,747		$	94,839		$	148,022

Interest expense
Fluids Division	$	77		$	121		$	237
Production Enhancement Division
Production Testing		13			32			–
Compressco		81			(20)			38
Total Production Enhancement Division		94			12			38
Offshore Division
Offshore Services		109			45			1
Maritech		98			78			9
Intersegment eliminations		–			–			–
Total Offshore Division		207			123			10
Corporate overhead		17,000			16,939			17,243
Consolidated	$	17,378		$	17,195		$	17,528

Income (loss) before taxes and discontinued operations
Fluids Division	$	50,830		$	32,076		$	15,953
Production Enhancement Division
Production Testing		39,847			35,969			15,024
Compressco		20,598			15,799			17,513
Total Production Enhancement Division		60,445			51,768			32,537
Offshore Division
Offshore Services		21,706			18,455			4,664
Maritech		(42,790)			(26,275)			(69,119)
Intersegment eliminations		–			1,802			443
Total Offshore Division		(21,084)			(6,018)			(64,012)
Corporate overhead (1)		(62,008)			(71,593)			(58,271)
Consolidated	$	28,183		$	6,233		$	(73,793)

F-38

	Year Ended December 31,
	2012		2011			2010
	(In Thousands)
Total assets
Fluids Division	$	387,034		$	375,741		$	376,309
Production Enhancement Division
Production Testing		337,208			119,311			106,304
Compressco		219,838			210,754			195,879
Total Production Enhancement Division		557,046			330,065			302,183
Offshore Division
Offshore Services		188,034			216,927			154,535
Maritech		75,383			63,294			329,585
Intersegment eliminations		–			–			(1,802)
Total Offshore Division		263,417			280,221			482,318
Corporate overhead		54,321			217,283			138,818
Consolidated	$	1,261,818		$	1,203,310		$	1,299,628

Capital expenditures
Fluids Division	$	31,839		$	17,922		$	10,914
Production Enhancement Division
Production Testing		40,025			19,925			6,010
Compressco		22,215			12,471			7,927
Total Production Enhancement Division		62,240			32,396			13,937
Offshore Division
Offshore Services		12,050			64,420			11,273
Maritech		343			7,924			70,597
Intersegment eliminations		–			(66)			(445)
Total Offshore Division		12,393			72,278			81,425
Corporate overhead		1,052			1,008			1,408
Consolidated	$	107,524		$	123,604		$	107,684

(1)	Amounts reflected include the following general corporate expenses:

	2012		2011			2010
	(In Thousands)
General and administrative expense	$	40,005		$	36,694		$	34,577
Depreciation and amortization		3,365			2,917			2,925
Interest expense		17,000			16,939			17,243
Other general corporate (income) expense, net		1,638			15,043			3,526
Total	$	62,008		$	71,593		$	58,271

F-39

Summarized financial information concerning the geographic areas of our customers and in which we operate at December 31, 2012, 2011, and 2010, is presented below:

	Year Ended December 31,
	2012		2011			2010
	(In Thousands)
Revenues from external customers:
U.S.	$	625,885		$	671,926		$	735,400
Canada and Mexico		85,133			49,314			32,645
South America		42,482			28,765			19,802
Europe		92,882			75,033			71,356
Africa		20,194			13,877			10,194
Asia and other		14,255			6,360			3,281
Total	$	880,831		$	845,275		$	872,678

Transfers between geographic areas:
U.S.	$	–		$	–		$	–
Canada and Mexico		–			–			–
South America		–			–			–
Europe		172			322			254
Africa		–			–			–
Asia and other		–			–			–
Eliminations		(172)			(322)			(254)
Total revenues	$	880,831		$	845,275		$	872,678

Identifiable assets:
U.S.	$	913,080		$	994,151		$	1,125,512
Canada and Mexico		116,059			62,558			35,274
South America		51,858			43,295			47,710
Europe		135,219			78,974			67,383
Africa		13,700			11,653			10,862
Asia and other		31,902			12,679			13,187
Eliminations and discontinued operations		–			–			(300)
Total identifiable assets	$	1,261,818		$	1,203,310		$	1,299,628

During each of the three years ended December 31, 2012, 2011, and 2010, 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.

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	Year Ended December 31,
	2012		2011			2010
	(In Thousands)

Acquisition	$	–		$	141		$	5,497
Exploration		–			–			16,822
Development		–			5,798			87,465
Total costs incurred	$	–		$	5,939		$	109,784

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,
	2012		2011			2010
	(In Thousands)

Oil and gas sales revenues	$	6,158		$	81,941		$	197,841
Production (lifting) costs (1)		3,749			33,496			71,066
Depreciation, depletion, and amortization		60			27,640			73,679
Impairments of properties		–			15,233			63,774
Excess decommissioning and abandonment costs		40,767			78,382			53,997
Exploration expenses		–			77			306
Accretion expense		979			3,705			5,008
Dry hole costs		–			(32)			325
Gain on insurance recoveries		–			–			(2,541)
Pretax income (loss) from producing activities		(39,397)			(76,560)			(67,773)
Income tax expense (benefit)		(13,789)			(26,797)			(25,186)
Results of oil and gas producing activities	$	(25,608)		$	(49,763)		$	(42,587)

(1)	Impairments of oil and gas properties during 2010 were primarily due to the increase in Maritech’s decommissioning liabilities.

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.

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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, 2009
Proved developed reserves	5,502	188	32,387
Proved undeveloped reserves	1,367	16	1,124
Total proved reserves at December 31, 2009	6,869	204	33,511

December 31, 2010
Proved developed reserves	5,760	415	24,795
Proved undeveloped reserves	1,012	74	790
Total proved reserves at December 31, 2010	6,772	489	25,585

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	–	–	–

	Oil	NGL	Gas
	(MBbls)	(MBbls)	(MMcf)

Total proved reserves at December 31, 2009	6,869	204	33,511
Revisions of previous estimates	266	310	(6,303)
Production	(1,360)	(132)	(7,065)
Extensions and discoveries	712	107	4,749
Purchases of reserves in place	293	–	876
Sales of reserves in place	(8)	–	(183)

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 proved reserves estimates during 2010 were primarily due to the declassification of natural gas reserves associated with a portion of Maritech’s Main Pass field due to pipeline and transportation interruptions.

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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 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.

The standardized measure of discounted future net cash flows relating to proved oil and gas reserves attributed to our oil and gas properties is as follows:

	December 31,
	2012		2011
	(In Thousands)

Future cash inflows	$	–		$	28,873
Future costs
Production		–			10,240
Development and abandonment		–			7,922
Future net cash flows before income taxes		–			10,711
Future income taxes		–			(1,513)
Future net cash flows		–			9,198
Discount at 10% annual rate		–			(2,723)
Standardized measure of discounted future net cash flows	$	–		$	6,475

Changes in Standardized Measure of Discounted Future Net Cash Flows

	Year Ended December 31,
	2012		2011			2010
	(In Thousands)

Standardized measure, beginning of year	$	6,475		$	133,269		$	86,049
Sales, net of production costs		(2,409)			(48,445)			(74,718)
Net change in prices, net of production costs		–			(11,916)			92,065
Changes in future development and abandonment costs		–			43,792			(48,002)
Development and abandonment costs incurred		–			25,083			42,151
Accretion of discount		–			17,909			9,720
Net change in income taxes		–			44,612			(34,665)
Purchases of reserves in place		–			–			8,694
Extensions and discoveries		–			–			63,411
Sales of reserves in place		(7,918)			(198,324)			(58)
Net change due to revision in quantity estimates		–			(10,814)			(13,738)
Changes in production rates (timing) and other		3,852			11,309			2,360
Subtotal		(6,475)			(126,794)			47,220
Standardized measure, end of year	$	–		$	6,475		$	133,269

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NOTE S — QUARTERLY FINANCIAL INFORMATION (Unaudited)

Summarized quarterly financial data for 2012 and 2011 is as follows:

	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		32,395			53,108			50,883			32,483
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		681			11,574			7,713			(4,008)
stockholders

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)

	Three Months Ended 2011
	March 31		June 30		September 30		December 31
	(In Thousands, Except Per Share Amounts)

Total revenues	$	222,545	$	235,114	$	201,434	$	186,182
Gross profit (loss)		26,364		35,813		35,668		(7,335)
Income (loss) before discontinued operations		(2,512)		30,523		1,960		(24,489)

Net income (loss)		(2,515)		30,469		1,954		(24,490)
Net income (loss) attributable to TETRA
stockholders		(2,515)		30,374		1,387		(25,099)

Net income (loss) per share before discontinued
operations attributable to TETRA stockholders	$	(0.03)	$	0.40	$	0.02	$	(0.33)
Net income (loss) per diluted share before discontinued
operations attributable to TETRA stockholders	$	(0.03)	$	0.39	$	0.02	$	(0.33)

Results from operations during the second quarter of 2011 include the impact from gains on sales of oil and gas properties by our Maritech segment. Results from operations during the fourth quarters of 2012 and 2011 include the impact of increased decommissioning liabilities by our Maritech segment.

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 helps to 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. The Rights are not presently exercisable and are not represented by separate certificates. We are currently not aware of any effort of any kind to acquire control of our company.

The terms of the Rights Plan, as adopted in 1998, provide that each holder of record of an outstanding share of common stock subsequent to November 6, 1998, receives a dividend distribution of one Preferred Stock Purchase Right. The Rights Plan would be triggered if an acquiring party accumulates or initiates a tender offer to purchase 20% or more of our common stock and would entitle holders of the Rights to purchase either our stock or shares in an acquiring entity at half of market value. Each Right entitles the holder thereof to purchase 1/100 of a share of Series One Junior Participating Preferred Stock for $50.00 per share, subject to adjustment. We would generally be entitled to redeem the Rights at $.01 per Right at any time until the tenth day following the time the Rights become exercisable.

On November 6, 2008, the Board of Directors entered into a First Amendment to the Rights Agreement. The amendment extends the term of the Rights Agreement and the final expiration date of our rights thereunder, which would otherwise have expired at the close of business on November 6, 2008, until the close of business on November 6, 2018. The amendment also increases the purchase price for each 1/100 of a share of Series One Junior Participating Preferred Stock from $50.00 per share to $100.00 per share.

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