tti10k-20120229.htm

	Part I
Item 1.	Business	1
Item 1A.	Risk Factors	12
Item 1B.	Unresolved Staff Comments	24
Item 2.	Properties	24
Item 3.	Legal Proceedings	28
Item 4.	Mine Safety Disclosures	29

	Part II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters, and
	Issuer Purchases of Equity Securities	30
Item 6.	Selected Financial Data	31
Item 7.	Management’s Discussion and Analysis of Financial Condition
	and Results of Operation	32
Item 7A.	Quantitative and Qualitative Disclosures about Market Risk	58
Item 8.	Financial Statements and Supplementary Data	59
Item 9.	Changes in and Disagreements with Accountants on Accounting
	and Financial Disclosure	59
Item 9A.	Controls and Procedures	59
Item 9B.	Other Information	60

	Part III
Item 10.	Directors, Executive Officers, and Corporate Governance	60
Item 11.	Executive Compensation	60
Item 12.	Security Ownership of Certain Beneficial Owners and Management and
	Related Stockholder Matters	60
Item 13.	Certain Relationships and Related Transactions, and Director Independence	61
Item 14.	Principal Accounting Fees and Services	61

	Part IV
Item 15.	Exhibits, Financial Statement Schedules	61

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.

Our Fluids Division manufactures and markets certain clear brine fluids, additives, and other 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 non-energy markets.

The Maritech segment is an oil and gas exploration, development, and production operation focused in the offshore and onshore U.S. Gulf Coast region. During 2011, Maritech sold approximately 95% of the proved reserves it owned as of December 31, 2010, and is seeking to sell its remaining oil and gas producing property interests. Maritech’s remaining operations consist primarily 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 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.

Liquid calcium chloride, calcium bromide, zinc bromide, zinc calcium bromide, sodium bromide, and similar 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 transfer and treatment 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 the 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 their effectiveness and lifespan. Our filtration services use a variety of techniques and equipment to remove particulates from CBFs at the customer’s site, so they can be reused. Filtration also enables recovery of a greater percentage of used CBFs for reconditioning.

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. Domestically, 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

The Production Testing segment of the Production Enhancement Division provides post-frac flow back and well testing 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 flow back and 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 Division’s Compressco segment provides wellhead compression-based production enhancement services to a broad base of natural gas and oil exploration and production companies. These production enhancement services primarily consist of wellhead compression, related liquids separation, gas metering, and vapor recovery services. In certain circumstances, Compressco also provides ongoing well monitoring services and, in Mexico, automated sand separation services in connection with its primary production enhancement services. 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.

Although Compressco’s 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, wells that are characterized by lower formation pressures, and in other applications. Compressco’s field services are performed by its highly trained staffs of regional service supervisors, optimization specialists, and field mechanics. In addition, Compressco designs and manufactures a majority 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 3,653 as of December 31, 2011, of which 2,941 units were in service, representing an increase in the number of units in service of approximately 8.5% from the prior year.

Compressco primarily utilizes its natural gas powered GasJack® and electric VJackTM compressor units to provide its wellhead compression services. The GasJack® unit increases gas production by reducing surface pressure to allow wellbore liquids that would normally block gas flow to produce up the well. 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. In addition Compressco uses its VJackTM compressor unit on oil wells or liquid-rich gas wells at both the early and late stages of their productive lives. Compressco believes that its VJackTM unit provides production uplift with zero engine-driven emissions and 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 backside pumping applications on oil wells.

Our Offshore Division consists of two separate operating segments: Offshore Services and Maritech. The Offshore Services segment provides (1) downhole and subsea services such as well plugging and abandonment (P&A), workover, and wireline 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. The Maritech segment is an oil and gas exploration, development, and production operation in the offshore and onshore U.S. Gulf Coast region. During 2011, Maritech sold approximately 95% 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 from the Offshore Division’s Offshore Services segment. In addition, Maritech is seeking to sell its remaining interests in oil and gas producing properties.

In providing services, our Offshore Services segment utilizes offshore rigless P&A packages, three 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 contract 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 onshore and offshore cutting services and tool rentals through its E.O.T. Cutting (EOT) operations. The Offshore Services segment’s electric wireline operation specializes in cased-hole logging, mechanical completion services, plugbacks, bridge plugs and packer services, pipe recovery (cased and openhole), perforating, and tubing-conveyed perforating services. 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 hurricanes. 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.

The size of our Offshore Services segment’s fleet of service vessels has expanded and contracted in recent years in response to the changing demand for its services. Including the new 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. In addition, 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 will oversee 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 NTL 2010-G05 regulations provide specific guidelines for the maximum time that 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.

The sales of almost all of Maritech’s oil and gas producing properties during 2011 have essentially removed us from the oil and gas exploration and production business, and all of Maritech’s significant oil and gas acquisition, development, and exploitation activities have ceased. During late 2010, we elected to explore strategic alternatives to our ownership of Maritech in order to conserve and reallocate capital to, and allow us to focus on, our remaining core businesses. As part of this strategic decision, beginning in February 2011, Maritech began selling oil and gas properties. Most significantly, in May 2011, Maritech sold 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., pursuant to a Purchase and Sale Agreement dated April 1, 2011. The sale was made for a base purchase price of $222.3 million. At the closing of the sale, Tana assumed approximately $72.7 million of associated asset retirement obligations, and Maritech received $173.3 million cash. In addition to the sale to Tana, Maritech sold other oil and gas property interests in separate transactions, with the most recent sale occurring in August 2011. Maritech is seeking to sell its remaining oil and gas property interests during 2012. Maritech continues to perform a significant amount of plugging, abandonment, and decommissioning work on its remaining offshore wells, facilites and production platforms as part of its strategy to reduce its risk from hurricanes. During the three year period ended December 31, 2011, Maritech has expended approximately $277.3 million on such efforts. Approximately $132.8 million of Maritech decommissioning liabilities remain as of December 31, 2011, and approximately $105.0 million of this amount is planned to be performed during 2012.

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.

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 raw materials utilized by our Lake Charles, Louisiana, facility from a variety of sources to produce liquid calcium chloride. Due to our inability to obtain raw materials on an economic basis for this facility, during the fourth quarter of 2010 we determined that the future operating cash flows for the Lake Charles, Louisiana, facility were no longer adequate to support its carrying value and recorded an impairment of the net asset carrying value for this plant. In February 2011, we shut down the pellet plant operation at the Lake Charles, Louisiana, plant, however, we continue to produce liquid calcium chloride at this plant when economically priced hydrochloric acid is available.

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 calcium chloride plant with raw material tail brine from its Arkansas 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 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. Some of the components used in the assembly of compressor units and production testing 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.

services to oil and gas exploration and production companies, onshore and offshore, in the United States and certain foreign markets. Current areas of market presence include the onshore U.S., the U.S. Gulf of Mexico, the North Sea, Mexico, and certain countries in South America, Europe, Asia, the Middle East, and Africa. During the past two years, the Division’s U.S. operations have grown due to increased industry demand for frac water handling and treatment services in unconventional shale gas reservoirs. 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. While the deepwater drilling moratorium was lifted in October 2010, a return to pre-Macondo offshore activity levels has been slow due to many factors, including permitting and other delays for offshore projects, continuing regulatory uncertainty, and the focus by many operators on onshore opportunities.

The Division’s principal competitors in the sale of CBFs to the oil and gas industry are Baroid Corporation, a subsidiary of Halliburton Company; M-I Swaco, a subsidiary of Schlumberger Limited; and Baker Hughes. 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 Company, Marathon Oil, Seneca Resources, Petrobras (the national oil company of Brazil), Shell Oil, Tullow Oil and XTO Energy. The Division also sells its CBF products through various distributors worldwide.

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 agricultural, industrial, road maintenance, de-icing, mining, construction, and food processing. 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.

The Production Enhancement Division provides production testing and wellhead compression-based production enhancement services and products to its customers. 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 in reservoirs containing high levels of hydrogen sulfide gas. The Division provides the specialized equipment and qualified personnel to address these impediments to production. In addition, the Production Testing segment provides certain services designed to accommodate the unique flow back and testing demands of shale gas reservoirs. During the past two years, the Production Testing segment has expanded its equipment fleet to serve the rapidly growing demand for services associated with many of the domestic shale gas reservoirs, including the Marcellus, Barnett, Eagle Ford, Fayetteville, Woodford, and Haynesville basins. The Production Testing segment also provides early-life and late-life production enhancement solutions designed to boost and extend the productive life of oil and gas wells.

The U.S. production testing market is 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 our equipment, skilled personnel, operating procedures, and safety record give us a competitive advantage in the marketplace. The Production Testing segment is also committed to growing its international operations in order to serve most major oil and gas markets worldwide, both organically and through strategic acquisitions. Competition in onshore U.S. markets is primarily dominated by numerous small, privately owned operators. Schlumberger Limited, Weatherford International Oilfield Services, Halliburton, and Expro International are major competitors in the international markets we serve. The major customers for this segment include BHP Billiton, Cabot, Chesapeake, ConocoPhillips, Encana Oil & Gas, Geosouthern Energy, Halliburton Company, 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.

The Division’s Compressco segment provides wellhead compression-based production enhancement services to 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 Ark-La-Tex region, San Juan Basin, and Mid-Continent region of the United States, it also has a substantial presence in other U.S. producing regions, including the Permian Basin, North Texas, Gulf Coast, Central and Northern Rockies, and California. Compressco has historically focused on serving customers with conventional production in mature fields, but it also services customers in some of the largest and fastest growing unconventional shale gas resource markets in the United States, including the Cotton Valley Trend, Barnett Shale, Fayetteville Shale, Woodford Shale, Piceance Basin, and Marcellus Shale. 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 various local and regional companies that utilize packages consisting of a screw compressor 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. Many of Compressco’s competitors attempt to compete on the basis of price. Compressco believes that its pricing is competitive because of the significant increases in the value of natural gas wells that result from the use of its services. Compressco’s major customers include BP, PEMEX, Devon, EXCO Resources, and ConocoPhillips.

Our Offshore Division consists of our Offshore Services and Maritech segments. Long-term demand for the Offshore Services segment’s offshore well abandonment and decommissioning services is predominantly driven by the maturity and decline of producing fields in the Gulf of Mexico, aging offshore platform infrastructure, damage from storms, 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.

Future demand for the services provided by our Offshore Services segment is expected to be increased as a result of regulations issued by the BOEMRE, including NTL 2010-G05, the “Idle Iron Guidance.” In the U.S. Gulf of Mexico, regulations generally require wells to be plugged, offshore platforms decommissioned, pipelines abandoned, and the well site cleared within twelve months of the expiration of an oil or gas lease. However, NTL 2010-G05 establishes well abandonment and decommissioning requirements that are no longer tied to lease expiration. 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 abandonment and decommissioning activity was high during the past several years as a result of 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 activity has been performed, 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. The threat of future storm activity, combined with the volatility of hurricane insurance premiums and associated deductibles, continues to accelerate the abandonment and decommissioning plans for undamaged wells and structures of many offshore operators.

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 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, subject to certain adjustments. The TETRA Hedron was transported to the Gulf of Mexico during the third quarter of 2011 and placed into service during the fourth quarter of 2011, following final outfitting and sea trials. During 2010, we also acquired additional operating assets to supplement our existing equipment fleet, enabling us to expand our services, particularly those related to damaged wells and platforms. We believe our integrated service package and vessel and equipment fleets satisfy the 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 two years has been Maritech, and the majority of the remaining Maritech work to be performed for Maritech is planned to be performed during 2012. Other major customers include Apache, Chevron, Mariner Energy, Nexen Petroleum USA Inc., Stone Energy, Versabuild, and W&T Offshore. The Offshore Services segment’s services are performed primarily offshore 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 Technip USA (formerly Global Industries, Ltd.), Offshore Specialty Fabricators, Inc., Cal Dive International, Inc., and Superior Energy Services, Inc. This market is highly competitive, and competition is based primarily on service, equipment availability, safety record, and price. Our ability to acquire or lease suitable service vessels and other operating equipment is particularly important to our ability to serve our existing customers and to expand our operations to other markets.

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. Following the sales of Maritech oil and gas properties during 2011, our estimated backlog on December 31, 2011 was $11.6 million, the majority of which is expected to be billed during 2012. This compares to an estimated backlog of $64.1 million at December 31, 2010.

As of December 31, 2011, we owned or licensed twenty-two issued U.S. patents and had eleven patent applications pending in the United States. Internationally, we had sixteen owned or licensed foreign patents and twenty-five 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 2028. We have elected to maintain certain other internally developed technologies, know-how, and inventions as trade secrets. While we believe that the protection of our patents and trade secrets is 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 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.

We believe that our manufacturing plants and other operations are in substantial compliance with all applicable 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.

On December 15, 2009, the EPA published its final findings that emissions of carbon dioxide, methane and other “greenhouse gases” 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 greenhouse gases under existing provisions of the federal Clean Air Act. Accordingly, the EPA has adopted regulations that would require a reduction in emissions of greenhouse gases from motor vehicles and could trigger permit review for greenhouse gas emissions from certain stationary sources. In addition, on October 30, 2009, the EPA published a final rule requiring the reporting of greenhouse gas emissions from specified large greenhouse gas emission sources in the United States beginning in 2011 for emissions occurring in 2010. On November 8, 2010, the EPA finalized regulations to expand the existing greenhouse gas monitoring and reporting rule to 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 would be 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 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.

During 2010, the U.S. federal government established the BOEMRE to replace the U.S. Minerals Management Service (MMS) largely in response to the April 2010 blowout of the Macondo well and resulting oil spill in the Gulf of Mexico. The U.S. federal government imposed a drilling moratorium in the deepwater Gulf of Mexico that extended until October 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:

We maintain various types of insurance intended to reimburse certain costs in the event of an explosion or similar event involving Maritech’s 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 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.

(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 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 sales of the significant majority 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.

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

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.

Demand for our products and services is materially dependent on the supply, demand, and prices for oil, natural gas, and competing energy sources, and 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 regional economic, financial, business, political, and social conditions within the markets we serve or hope to serve, as well as the U.S. and foreign economic, financial, business, political and social conditions that impact the supply, demand, and prices of oil and gas. Oil and gas prices and, therefore, the levels of well drilling, completion, workover, and production activities, tend to fluctuate. Worldwide economic, political, and events, including initiatives by the Organization of Petroleum Exporting Countries and increasing or decreasing demand in other large world economies, 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.

Since the April 20, 2010, blowout on the Macondo well, operations in the U.S. Gulf of Mexico have been affected by an increased regulatory environment. The resulting federal regulatory requirements have significantly reduced the U.S. Gulf of Mexico completion fluids market. Although permitting levels increased somewhat during 2011, the pace of approvals for new drilling activity and plug and abandonment work in the Gulf of Mexico lags pre-Macondo levels. 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 being curtailed or suspended. Although a drilling moratorium that was issued immediately following the Macondo blowout was lifted in October 2010, the backlog of permits waiting to be issued for operations in the shallow water for both new drilling and plug and abandonment work, and regulatory uncertainties regarding the deepwater activities are expected to continue to negatively affect our Fluids Division and, to a lesser extent, our Offshore Services segment. Although we are unable to predict the full continuing impact of these factors

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.

Other factors affecting our operating results and activity levels include oil and natural gas industry spending levels for exploration, development, and acquisition activities; plugging, abandonment, and decommissioning costs on Maritech’s remaining offshore production platforms and associated wells. 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.

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 brines, 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.

The fabrication of our production testing 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.

The majority of our business in Mexico is performed for PEMEX. For the twelve months ended December 31, 2011, PEMEX accounted for approximately 4.8% of our consolidated revenues. No work or services are guaranteed to be ordered by PEMEX under our contracts with PEMEX. 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 and, as a result, our business, financial condition, results of operations and cash flows.

During the past two years, incidents of security disruptions throughout many regions of Mexico have increased. Drug related gang activity has grown in response to Mexico’s efforts to reduce and control drug trafficking within the country. Certain incidents of violence have occurred in regions served by us and have resulted in the interruption of our operations and 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.

Although the overall global economy has largely recovered from the 2008 recession, significant economic uncertainty remains. 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 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.

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, 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. 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.

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 may also require financial resources (including the use of available cash or additional long-term debt) and management and personnel resources. Acquisitions also require significant financial and 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. Any recent or future acquisition transactions by us may not achieve favorable financial results. Our operating results could be adversely affected if we are unable to successfully integrate 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.

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

During late 2009 and early 2010, we completed the construction and began the commissioning of a calcium chloride plant facility near El Dorado, Arkansas. The plant’s future profitability and the advantages we expect to receive from the plant will be 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. There can be no assurance that the El Dorado, Arkansas, plant’s future profitability will achieve original expectations.

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, 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.

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 2011, Maritech adjusted its decommissioning liabilities, increasing them by approximately $80.2 million, either for work performed during the year or related to adjusted estimates of the cost of future work to be performed. Approximately $78.4 million of this adjustment was directly charged to earnings as an operating expense during 2011. 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.

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. Severe storms can also cause our oil and gas producing properties to be shut-in. 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.

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.

During the past three 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, 2011, 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 $27.5 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 $27.5 million estimated amount has been accrued as part of Maritech’s decommissioning liabilities. Maritech has additional maximum remaining insurance coverage available of approximately $19.5 million, all of which relates to Hurricane Ike, although a portion of this coverage may not be utilized. One of the underwriters associated with our windstorm insurance coverage for Hurricane Ike damages has contested whether certain repair costs incurred are covered costs under the policy. During December 2010, we initiated legal proceedings against this underwriter in an attempt to collect the amount of claim reimbursements provided for under the policy. The timing of the collection of any future reimbursements is beyond our control, and we will continue to use a significant amount of our working capital until such reimbursements are received. In addition, a portion of the reimbursements ultimately received may be offset by legal and other administrative costs incurred in our attempts to collect them. Our estimates of the remaining costs to be incurred may be imprecise. To the extent actual future costs exceed the policy maximum for these costs, such excess costs would not be reimbursable.

Despite the sale of approximately 95% of Maritech’s oil and gas reserves during 2011, we have retained decommissioning liabilities of approximately $132.8 million associated with offshore platforms and associated wells to be decommissioned and abandoned. During the second quarter of 2011, we determined that the cost of premiums and the associated deductibles and coverage limits for windstorm damage for Maritech’s remaining offshore platforms and wells was uneconomical. Therefore, Maritech discontinued its insurance coverage for windstorm damage. Accordingly, Maritech is currently exposed to losses from windstorm damages and may be similarly exposed to storms in the future if we do not purchase windstorm insurance coverage. 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.

As of December 31, 2011, our total debt outstanding was approximately $305.0 million, and our debt to total capital ratio was 45.5%. This debt to total capital ratio excludes approximately $204.4 million of available cash held as of December 31, 2011. 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 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.

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 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.

The operations of certain of our subsidiaries are exposed to fluctuations between the U.S. dollar and certain foreign currencies. Our plans to grow our international operations could cause this exposure from fluctuating currencies to increase. In particular, our growing operations in Brazil, as a result of a long-term contract with Petrobras entered into during 2008, subjects us to increased foreign currency risk in that country. 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.

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.

Our revolving credit facility consists of floating rate loans that bear interest at an agreed upon percentage rate spread above LIBOR. Although as of December 31, 2011, there is no balance outstanding under the revolving credit facility, there is no assurance that we will not borrow under the facility in the future. 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.

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 oil and gas reservoirs. Specifically, the EPA is reviewing the impact of hydraulic fracturing wastewater and stormwater on drinking water resources through the use of scenario evaluation, laboratory and case studies, and an analysis of existing data. 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, the EPA has announced that it will release initial study results during 2012 and an additional report during 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 demand for certain of our products and services could be decreased or subject to delays, particularly for our Production Testing 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, following the April 2010 Macondo well blowout and resulting oil spill in the Gulf of Mexico, the U.S. Minerals Management Service (MMS) was reorganized as the BOEMRE. The U.S. federal government imposed a drilling moratorium in the deepwater Gulf of Mexico that extended until October 2010. The BOEMRE also 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 that have resulted in operations and projects being curtailed or suspended. 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 now abide by new “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 will oversee the provisions of the “Idle Iron Guidance”. Under limited circumstances, the BSEE could require us to suspend or terminate our 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 business exposes 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 and for oil and gas producing properties. 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

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 recently adopted two sets of rules that became effective January 2, 2011 that regulate GHG emissions under the CAA, one of which requires a reduction in emissions of GHGs from motor vehicles and the other of which regulates emissions of GHGs from certain large stationary sources. The EPA has also adopted rules requiring the reporting, on an annual basis, beginning in 2011, of GHG emissions from specified large GHG emission sources in the United States, including petroleum refineries, for emissions occurring after January 1, 2010, as well as certain oil and gas production facilities, on an annual basis, beginning in 2012 for emissions occurring in 2011.

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.

We plan to grow both in the United States and in foreign countries. We have established operations in, among other countries, Brazil, Mexico, Argentina, Canada, the United Kingdom, Norway, Finland, Sweden, Ghana, and India, and have operating joint ventures in Saudi Arabia and Libya. 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:

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.

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, and flow back 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, 2011. We believe our facilities are adequate for our present needs.

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 contain 29 square miles of acreage containing solar evaporation ponds and leased mineral acreage. 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.

The Production Enhancement Division conducts its operations through thirteen production testing service centers (twelve of which are leased) in the U.S., located in Texas, Louisiana, Oklahoma, and Pennsylvania. In addition, the Production Testing segment has leased facilities in Brazil, Mexico, Libya, Bahrain, United Arab Emirates, and Saudi Arabia. Compressco’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 California, Mexico, and Argentina, and sales offices in Oklahoma, Texas, Colorado, New Mexico, Louisiana, California, Pennsylvania, and Canada.

Following the 2011 sale of approximately 95% of Maritech’s proved oil and gas reserves as of December 31, 2010, Maritech has retained selected staff and contractors who are responsible for determining proved oil and gas reserves in conformance with guidelines established by the SEC. Reserve estimates were prepared based upon the interpretation of production performance data and geologic interpretation of sub-surface information derived from the drilling of wells. In accordance with Maritech’s documented oil and gas reserve policy as prescribed by our Board of Directors, the preparation of these reserve estimates is subject

Our proved reserves, as reflected in this Annual Report, include only quantities that Maritech expects to recover commercially using current technology, prices, and costs, within existing economic conditions, operating methods, and governmental regulation. While Maritech can be reasonably certain that the proved reserves are economically producible, the timing and ultimate recovery can be affected by a number of factors, including reservoir performance, regulatory approvals, and changes in projections of long-term oil and gas prices. Revisions can include upward or downward changes in the previously estimated volumes of proved reserves for existing fields due to evaluation of (1) already available geologic, reservoir, or production data or (2) new geologic or reservoir data obtained from wells. Revisions can also occur associated with significant changes in oil and gas prices or the related production equipment/facility capacity.

As of December 31, 2011, Maritech’s proved undeveloped reserves represented approximately 50.1% of Maritech’s total proved reserves. Maritech’s proved undeveloped reserves as of December 31, 2010, represented approximately 10.6% of Maritech’s total proved reserves. Proved undeveloped reserves represented approximately 12.4% of Maritech total proved reserves as of December 31, 2009. During 2010, Maritech expended approximately $4.6 million of its development costs to convert approximately 55.9% of its proved undeveloped reserves at the beginning of the year to proved developed reserves. All of Maritech’s proved undeveloped reserves as of December 31, 2011, have been classified as proved undeveloped for less than five years.

Maritech is not required to file, and has not filed on a recurring basis, estimates of its total proved net oil and gas reserves with any U.S. or non-U.S. governmental regulatory authority or agency other than the Department of Energy (DOE) and the SEC. The estimates furnished to the DOE have been consistent with those furnished to the SEC, however, they are not necessarily directly comparable, due to special DOE reporting requirements. In no instance has gross reserve volume information used to prepare the estimates for the DOE differed by more than five percent from the corresponding estimates reflected in total reserves reported to the SEC.

	Year Ended December 31,
	2011		2010		2009
Production:
Natural gas (Mcf)		3,321,651		7,065,258		10,449,366
NGL (Bbls)		88,070		132,191		105,479
Oil (Bbls)		611,748		1,360,126		1,219,336

Revenues:
Natural Gas	$	14,596,000	$	60,416,000	$	87,905,000
NGL (Bbls)		4,744,000		6,003,000		3,308,000
Oil		62,601,000		131,422,000		82,978,000
Total	$	81,941,000	$	197,841,000	$	174,191,000

Average realized unit prices and production costs:
Natural gas (per Mcf)	$	4.39	$	8.55	$	8.41
NGL (per Bbl)	$	53.87	$	45.41	$	31.36
Oil (per Bbl)	$	102.34	$	96.62	$	68.05

Production cost per equivalent barrel	$	26.72	$	26.62	$	25.80
Depletion cost per equivalent barrel	$	22.05	$	27.60	$	25.96

Realized unit prices include the impact of hedge commodity swap contracts. Production cost per equivalent barrel excludes the impact of storm repair and insurance-related costs, which were charged to operations, with approximately $8.2 million being charged in 2009. Equivalent barrel (BOE) information is calculated assuming six Mcf of gas is equivalent to one barrel of oil. Insurance recoveries during 2010 and 2009 totaled approximately $2.5 million and $45.4 million, respectively, and are excluded from production cost per equivalent barrel for the year. The 2009 production cost per equivalent barrel was also increased due to the impact of hurricanes, which resulted in significant properties being shut-in during much of 2009. Depletion cost per equivalent barrel excludes the impact of dry hole costs and property impairments.

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. During 2009, Maritech participated in the drilling of 2 gross development wells (1.12 net wells) and one gross exploratory well (0.5 net wells), all of which were productive. As of December 31, 2011, there were no wells in the process of being drilled.

As of December 31, 2011, 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, 2011. 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, 2011, is as follows:

Between May 28, 2008 and June 27, 2008, two petitions were filed by alleged stockholders in the District Courts of Harris County, Texas, 133rd and 113th Judicial Districts, purportedly on our behalf. The suits name our directors and certain officers as defendants. The factual allegations in these lawsuits mirror those in a federal class action lawsuit which was settled during 2010. The claims are for breach of fiduciary duty, unjust enrichment, abuse of control, gross mismanagement, and waste of corporate assets. The petitions seek disgorgement, costs, expenses, and unspecified equitable relief. On September 22, 2008, the 133rd District Court consolidated these complaints as In re TETRA Technologies, Inc. Derivative Litigation, Cause No. 2008-23432 (133rd Dist. Ct., Harris County, Tex.), and appointed Thomas Prow and Mark Patricola as Co-

Lead Plaintiffs. This lawsuit was stayed by agreement of the parties pending the Court’s ruling on our motion to dismiss the federal class action. On September 8, 2009, the plaintiffs in this state court action filed a consolidated petition which makes factual allegations similar to the surviving allegations in the federal lawsuit prior to it being settled. On April 19, 2010, the Court granted our motion to abate the suit, based on plaintiff’s inability to demonstrate derivative standing. On June 8, 2010, we received a letter from plaintiff’s counsel demanding that our board of directors take action against the defendants named in the previously filed derivative lawsuit. On August 22, 2011, the Court issued a Preliminary Approval Order preliminarily approving the settlement of the suit as set forth in the Stipulation of Settlement dated August 12, 2011 (the Stipulation). The Stipulation does not provide for the payment of monetary compensation to stockholders; rather, it provides for certain additions to our corporate governance policies and procedures and for the payment of plaintiff’s attorneys’ fees and litigation expenses, which have been paid by our insurers. On October 17, 2011, the Court granted final approval of the settlement.

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.

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, 2006, 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.

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 –

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, 2007, 2008, 2009, 2010, or 2011 pursuant to the repurchase program. Shares repurchased during the fourth quarter of 2011 other than pursuant to our repurchase program are as follows:

(1)	In January 2004, our Board of Directors authorized the repurchase of up to $20 million of our common stock. Purchases may be made from time to time in open market transactions at prevailing market prices. The repurchase program may continue until the authorized limit is reached, at which time the Board of Directors may review the option of increasing the authorized limit.
(2)	Shares we received in connection with the exercise of certain employee stock options or the vesting of certain employee restricted stock. These shares were not acquired pursuant to the stock repurchase program.

The following tables set forth our selected consolidated financial data for the years ended December 31, 2011, 2010, 2009, 2008, and 2007. 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. In December 2007, we sold our process services operations. In 2006, we made the decision to discontinue our Venezuelan fluids and production testing operations. In 2003, we made the decision to discontinue the operations of our Norwegian process services operations. During 2000, we commenced our exit from the micronutrients business. Accordingly, we have reflected each of the above operations as discontinued operations. During 2008, Maritech acquired certain oil and gas properties. During 2007, we completed the acquisition of two service companies and Maritech acquired certain oil and gas properties. 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 2008, we recorded significant impairments of oil and gas properties, goodwill, and other long-lived assets. During 2007, we recorded significant impairments of our oil and gas properties. 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 2011 to earlier years.

	Year Ended December 31,
	2011			2010			2009			2008			2007
	(In Thousands, Except Per Share Amounts)
Income Statement Data
Revenues	$	845,275		$	872,678		$	878,877		$	1,009,065		$	982,483
Gross profit		90,510			43,707			213,097			152,001			116,383
General and administrative expense		113,273			100,132			100,832			104,949			99,871
Interest expense		(17,195	)		(17,528	)		(13,207	)		(17,557	)		(17,886	)
Interest income		756			224			417			779			731
Other income (expense), net		45,435			(64	)		5,895			12,884			2,805
Income (loss) before discontinued
operations		5,482			(43,325	)		68,807			(9,655	)		1,221
Net income (loss)		5,418			(43,718	)		68,804			(12,136	)		28,771
Net income (loss) attributable to
TETRA stockholders	$	4,147		$	(43,718	)	$	68,804		$	(12,136	)	$	28,771

Income (loss) per share, before
discontinued operations attributable
to TETRA stockholders	$	0.05		$	(0.57	)	$	0.92		$	(0.13	)	$	0.02
Average shares		76,616			75,539			75,045			74,519			73,573

Income (loss) per diluted share,
before discontinued operations
attributable to TETRA stockholders	$	0.05		$	(0.57	)	$	0.91		$	(0.13	)	$	0.02
Average diluted shares		77,991	(1)		75,539	(2)		75,722	(3)		74,519	(2)		75,921	(4)

(1)	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.
(2)	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.
(3)	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.
(4)	For the year ended December 31, 2007, the calculation of average diluted shares outstanding excludes the impact of 716,354 average outstanding stock options that would have been antidilutive.

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. We have accounted for the discontinuance or disposal of certain businesses as discontinued operations and have adjusted prior period financial information to exclude these businesses from continuing operations.

During the past two year period, a significant portion of the growth in the U.S. oil and gas industry activity has shifted from offshore operations to onshore. Led by the dramatic increase in activity in unconventional shale reservoirs throughout the United States, domestic onshore rig counts have increased significantly during this period. This trend has coincided with the continuing impact from the 2010 Macondo well accident in the U.S. Gulf of Mexico, which resulted in increased government regulation over offshore oil and gas operations. While the permitting delays affecting offshore drilling operations have been easing, offshore drilling activity levels in the Gulf of Mexico have been slow to recover and have only recently begun to trend toward pre-Macondo levels. These industry trends have significantly impacted our businesses. As evidenced by the unprecedented activity and revenue levels of our Production Testing segment, our U.S. onshore businesses have capitalized on the increased demand for domestic services, particularly in the most significant shale reservoirs, including the Haynesville, Eagle Ford, Marcellus, and others. Our Fluids Division segment has capitalized on the increased domestic onshore demand for its products and services, particularly water transfer and treatment services for fracturing operations. Our Compressco segment has also targeted these domestic growth regions for its compression-based production enhancement services. The continuing slow recovery of domestic offshore operations has affected our Fluids and Offshore Services businesses, but activity levels are increasing. However, the significant drilling activity for onshore shale gas reservoirs during the past two years, along with other demand factors, has resulted in declining prices for natural gas, particularly during the last half of 2011 and early 2012. Following the sale of substantially all of our Maritech segment’s oil and gas producing properties during 2011, the most significant direct impact on our revenues and operating cash flows resulting from decreased natural gas prices has been removed. However, the current low natural gas pricing environment, plus the continuing strength of crude oil prices, has resulted in a new trend by the industry toward oil drilling, which could once again impact certain of our businesses.

The strong performance by our Production Testing and Fluids segments contributed to our overall operating results for 2011. Production Testing segment revenues and profitability increased significantly compared to the prior year due to the increased domestic demand discussed above, although international activity increased as well. Fluids Division revenues and profitability also grew primarily due to increased domestic onshore product and service demand, although this segment also saw growth internationally. Our Offshore Services segment reported increased revenues during 2011 despite a soft pricing environment in the U.S. Gulf of Mexico. The July 2011 purchase of a new heavy lift derrick barge enables the Offshore Services segment to have increased capacity to serve the sustained long-term demand for heavy lift services, which we anticipate will continue due to the increased government regulation of offshore well abandonment and platform decommissioning that was enacted during 2010. Compressco also reported increased revenues primarily due to increased sales of compressor units compared to 2010. The Compressco segment’s profitability was negatively impacted, however, by increased operating expenses during 2011 and by increased public company costs associated with Compressco Partners following its initial public offering during June 2011. Increased Corporate Overhead costs were caused primarily by the recognized loss from liquidating our hedge derivative contracts, which we had used to hedge Maritech’s production cash flows. Maritech recognized significant gains on the sales of its oil and gas producing properties during 2011, but generated a significant loss for the year due to excess decommissioning costs associated with its remaining well abandonment and decommissioning obligations.

Our strong balance sheet was further enhanced during 2011, particularly as a result of the sale of Maritech’s oil and gas producing properties as these sales generated approximately $181.4 million of cash, net of adjustments. This strategic disposition has also allowed us to focus our capital expenditure priorities on our core service businesses, including the purchase of the above mentioned heavy lift barge by our Offshore Services segment and to fund the capital needs of our growing Production Testing segment. Despite the sale of the Maritech properties, we continue to utilize a significant portion of our operating cash flows to extinguish Maritech’s remaining decommissioning liabilities. We expended approximately $101.9 million on decommissioning work performed during 2011, and a significant portion of the remaining decommissioning liability is anticipated to be extinguished during 2012. The June 2011 initial public offering of Compressco Partners (the Offering) generated approximately $42.2 million of net Offering proceeds. Approximately $32.2 million of these Offering proceeds were used to repay to us certain intercompany note balances. Following the Offering, we own approximately 83% of Compressco Partners, and we continue to consolidate this subsidiary as part of our Compressco segment. In addition to significant availability under our bank revolving credit facility, we had

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 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:

Our Fluids Division generates revenues and cash flows by manufacturing and marketing clear brine completion fluids (CBFs), additives, and other associated products 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; completion fluids additives and fluid management services; as well as high volume water transfer and treatment services for fracturing operations. 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 non-energy markets. Fluids Division revenues increased 10.2% during 2011 compared to 2010 primarily due to increased international CBF product sales. Domestic offshore activity levels continue to be impacted negatively as a result of the maturity of the producing fields in the heavily developed portions of the Gulf of Mexico as well as uncertain regulations governing offshore drilling activities following the April 2010 Macondo accident. Offshore oil and gas drilling activity levels have recently improved, but are still below pre-Macondo levels. This decrease in offshore activity has been largely offset, however, by increased domestic onshore operations, including increased revenues from frac water services. We anticipate continued increases in industry spending in 2012, particularly given the current levels of crude oil prices. Also, the Division plans to continue to capitalize on the current industry trend toward developing unconventional onshore shale reservoirs, where demand for its products and services have significantly increased during the past two years.

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 post-frac flow back and well testing and by providing reservoir data necessary to enable operators to quantify reserves, optimize production, and minimize oil and gas reservoir damage. The primary testing markets served include many of the major oil and gas basins in the United States, as well as in Mexico and South America, Northern Africa, the Middle East, and Asia. 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. Production Testing segment’s revenues increased 34.4% in 2011 compared to 2010, primarily due to increased demand in the United States, and particularly due to increased activity in unconventional shale reservoirs. Given the continuing increase in drilling activity, we anticipate that demand for our production testing services will continue to increase in 2012 compared to 2011.

Compressco generates revenues and cash flows by performing wellhead compression-based production enhancement services throughout many of the onshore producing regions of the United States, as well as certain onshore basins in Mexico, Canada, South America, Europe, Asia, and other international locations. Demand for wellhead compression services is primarily driven by the need to boost production in certain mature gas wells with declining production. Compressco segment revenues increased 17.8% in 2011 as compared to 2010, primarily due to increased sales of compressor units as well as an increase in demand

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 services such as well plugging and abandonment, workover, and wireline services, (2) decommissioning and certain construction services, including 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. Regulations enacted during 2010 by the BOEMRE governing the timing of abandonment and decommissioning of nonproductive wells and unused offshore platforms are expected to increase the demand for the Offshore Services segment over the next several years. Given the increased cost to insure offshore properties for windstorm damage coverage and to reduce the risk from future storms, some oil and gas operators, including Maritech, are accelerating their plans to abandon and decommission their offshore wells and platforms. Offshore Services revenues increased by 4.8% during 2011 compared to 2010, primarily due to increased abandonment and decommissioning work performed. In July 2011, the Offshore Services segment purchased a new 1,600-metric-ton heavy lift derrick barge, which we have named the TETRA Hedron. This vessel was placed into service during the fourth quarter of 2011 and significantly increases the Offshore Services segment’s heavy lift capacity to serve customers with heavier structures.

The sales of almost all of Maritech’s oil and gas producing properties during 2011 have essentially removed us from the oil and gas exploration and production business. During late 2010, we elected to explore strategic alternatives to our ownership of Maritech in order to conserve and reallocate capital to, and allow us to focus on, our remaining core businesses. As part of this strategic decision, beginning in February 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 2012. As a result of these sales of oil and gas properties, Maritech’s revenues during 2011 decreased by 58.7% compared to 2010 and are expected to be minimal going forward. Maritech continues to perform a significant amount of plugging, abandonment, and decommissioning efforts on its remaining offshore wells, facilities and production platforms.

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.

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 2010 we recorded other long-lived asset impairments of $25.1 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 further decreased demand for our products and services.

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, 2011. 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. During the fourth quarter of 2008, due to changes in the global economic environment which affected our stock price and market capitalization, we recorded an impairment of goodwill of $47.1 million. We believe our estimates of the fair value for each reporting unit are reasonable. As of December 31, 2011, our Offshore Services, Production Testing, and Compressco reporting units reflect goodwill in the amounts of $3.9 million, $23.0 million, and $72.2 million, respectively.

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

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. Following the late 2010 issuance by the BOEMRE of NTL 2010-G05 “Idle Iron Guidance” regulations, the estimate for Maritech’s decommissioning liabilities increased significantly. In addition, Maritech has adjusted its decommissioning liabilities during 2010 and 2011 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 $54.0 and $78.4 million of excess decommissioning expense during 2010 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 $52.4 million of increased oil and gas property impairments during 2010 compared to 2009. 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.

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.

Reserves for bad debts are calculated generally and on a specific identification basis, whereby we estimate whether or not specific accounts receivable will be collected. Such estimates of future collectability may be incorrect, which could result in the recognition of unanticipated bad debt expenses in future periods. A significant portion of our revenues come from oil and gas exploration and production companies, and historically our estimates of uncollectible receivables have proven reasonably accurate. However, if due to adverse circumstances, certain customers are unable to repay some or all of the amounts owed us, an additional bad debt allowance may be required, and such amount may be material.

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.

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.

We estimate the fair value of share-based payments of stock options using the Black-Scholes option-pricing model. 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 is calculated based upon actual historical stock price movements over the most recent periods equal to the expected option term. Expected pre-vesting forfeitures are estimated based on actual historical pre-vesting forfeitures over the most recent periods for the expected option term. All of these estimates are inherently imprecise and may result in compensation cost being recorded that is materially different from the actual fair value of the stock options granted. While the assumptions for expected stock price volatility and pre-vesting forfeiture rates are updated with each year’s option-valuing process, we experienced significant revisions during 2011 primarily due to the reduction in the workforce of our Maritech segment. Prior to 2011, there have not been significant revisions made in these estimates.

	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 (loss) before taxes and discontinued operations		6,233			(73,793	)		80,026			108.4	%
Income (loss) before taxes and discontinued operations as a percentage of revenue		0.7	%		-8.5	%
Provision (benefit) for income taxes		751			(30,468	)		31,219			102.5	%
Income (loss) before discontinued operations		5,482			(43,325	)		48,807			112.7	%
Loss from discontinued operations, net of taxes		(64	)		(393	)		329			83.7	%
Net income (loss)		5,418			(43,718	)		49,136			112.4	%
Net income attributable to noncontrolling interest		(1,271	)		-			-
Net income (loss) attributable to TETRA stockholders	$	4,147		$	(43,718	)	$	47,865

Consolidated revenues during 2011 decreased compared to the prior year, as the decrease in Maritech revenues resulting from sales of almost all of its oil and gas producing properties during the year 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 the prior year. 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 the prior year 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 the prior year period. In addition, insurance, taxes, and other general expenses increased by approximately $0.8 million.

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, current year 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 the prior year period primarily due to a $2.8 million premium that was charged during 2010 in connection with the early repayment of the 2004 Senior Notes.

	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 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 and other services during 2011 more than offset the decreased gross profit from sales of CBFs, that were primarily a result of the decreased domestic offshore market.

	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.

	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’s continuing growth domestically could be negatively affected by current low natural

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.

	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 dive 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. We continue to anticipate that the NTL 2010-G05 “Idle Iron Guidance” regulations issued during 2010 will increase the future demand for well abandonment and decommissioning services to be performed by our Offshore Services segment. 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. Despite the sale of Maritech’s oil and gas producing properties, a significant amount of abandonment and decommissioning work remains for Maritech, and a majority of this work is scheduled to be performed during 2012.

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.

	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 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 the current year period 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 expects to sell its remaining oil and gas producing property interests during 2012.

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 the prior year, 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 the current year period. 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 prior year period reversal of bad debt expense.

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.

	Year Ended December 31,						Period to Period Change
	2010			2009			2010 vs 2009			% Change
	(In Thousands, Except Percentages)
Revenues	$	872,678		$	878,877		$	(6,199	)		-0.7	%
Gross profit		43,707			213,097			(169,390	)		-79.5	%
Gross profit as a percentage of revenue		5.0	%		24.2	%
General and administrative expense		100,132			100,832			(700	)		-0.7	%
General and administrative expense as a percentage of revenue		11.5	%		11.5	%
Interest expense, net		17,304			12,790			4,514			35.3	%
Other income (expense), net		(64	)		5,895			(5,959	)		-101.1	%
Income (loss) before taxes and discontinued operations		(73,793	)		105,370			(179,163	)		-170.0	%
Income (loss) before taxes and discontinued operations as a percentage of revenue		-8.5	%		12.0	%
Provision for income taxes		(30,468	)		36,563			(67,031	)		-183.3	%
Income before discontinued operations		(43,325	)		68,807			(112,132	)		-163.0	%
Loss from discontinued operations, net of taxes		(393	)		(3	)		(390	)		-13000.0	%
Net income (loss)	$	(43,718	)	$	68,804		$	(112,522	)		-163.5	%

Consolidated revenues decreased despite increased revenues from our Fluids, Maritech, and Production Testing segments, primarily due to decreases in the revenues of the Offshore Services and Compressco segments. Offshore Services segment revenues decreased by $79.6 million compared to the record levels of 2009, which saw unprecedented activity and demand. Increased onshore oil and gas industry activity during 2010 contributed to the revenue increases by our Production Testing and Fluids Divisions, with the Fluids Division also reflecting increased sales of manufactured products from our new El Dorado, Arkansas, calcium chloride plant. Maritech revenues increased largely because of higher realized oil prices, which include the impact of certain commodity derivative hedges which expired at the end of 2010. Overall gross profit decreased primarily due to $72.8 million of decreased profitability from our Offshore Services segment and due to significant impairments and other charges incurred by our Maritech, Offshore Services, and Fluids segments. In addition, the gross profit of our Fluids and Compressco segments were also decreased compared to the prior year. These decreases were partially offset by increased Production Testing gross profit.

Consolidated general and administrative expenses decreased as compared to the prior year due to approximately $3.4 million of decreased bad debt expenses and $0.8 million of decreased insurance expenses during the current year. These decreases were largely offset by approximately $1.8 million of increased employee related costs, including increased salary, benefits, contract labor costs, and other associated employee expenses. In addition, general and administrative expenses during 2010 include $0.2 million of increased professional fees, $0.3 million of increased office expenses, and $1.2 million of increased taxes, investor relations, and other general expenses.

Consolidated other income decreased during 2010 compared to the prior year, primarily due to approximately $7.4 million of decreased gains on sales of assets, $3.8 million of decreased legal settlement gains, $1.2 million of decreased foreign currency gains, and due to the expensing of a $2.8 million prepayment premium on the repayment of the 2004 Senior Notes. These decreases were partially offset by $9.2 million of increased earnings in an unconsolidated joint venture, primarily due to a $6.8 million charge for an impairment of our Fluids Division European joint venture investment during 2009. In addition, we recorded $1.6 million of decreased hedge ineffectiveness losses compared to the prior year.

	Year Ended December 31,						Period to Period Change
	2010			2009			2010 vs 2009			% Change
	(In Thousands, Except Percentages)
Revenues	$	276,337		$	225,517		$	50,820			22.5	%
Gross profit		38,984			47,549			(8,565	)		-18.0	%
Gross profit as a percentage of revenue		14.1	%		21.1	%
General and administrative expense		23,712			22,355			1,357			6.1	%
General and administrative expense as a percentage of revenue		8.6	%		9.9	%
Interest (income) expense, net		195			(35	)		230
Other income (expense), net		876			(4,438	)		5,314
Income before taxes and discontinued operations	$	15,953		$	20,791		$	(4,838	)		-23.3	%
Income before taxes and discontinued operations as a percentage of revenue		5.8	%		9.2	%

The increase in Fluids Division revenues as compared to the prior year was primarily due to $44.0 million of increased product sales revenues. This increase in product sales revenues was partially attributed to increased revenues from sales of liquid calcium chloride produced from our El Dorado, Arkansas, calcium chloride plant, which began production during the fourth quarter of 2009. Product sales revenues also increased due to increased domestic sales volumes of clear brine fluids (CBFs), particularly during the fourth quarter of 2010. Domestic product sales revenues also benefitted from increased pricing compared to the prior year and due to a significant sale of bromide products during the first quarter of 2010. International product sales revenues also increased, due to improved oil and gas activity levels in certain of the foreign markets we serve and due to increased product sales from our European calcium chloride operations. The increase in domestic product sales revenues during 2010 occurred despite the decreased activity and pricing on product sales to domestic deepwater operators as a result of the deepwater drilling moratorium, which was in effect during a portion of the year. Although this moratorium was lifted in October 2010, delays due to permitting and increased regulatory requirements have continued to slow the return of improved demand in the deepwater Gulf of Mexico. However, CBF sales volumes increased during the fourth quarter of 2010, and this trend may indicate that activity levels are increasing going forward. In addition to increased product sales revenues, service revenues increased by approximately $6.9 million due to increased domestic frac water and filtration service activities.

Despite the increased revenues, gross profit decreased compared to the prior year primarily due to the significant losses from our domestic calcium chloride manufacturing operations. These losses were primarily due to the $7.2 million impairment 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, resulting in the impairment. In addition, start up costs and continuing production inefficiencies have negatively affected the profitability of our El Dorado, Arkansas, calcium chloride plant. We continue to take steps to improve the operational efficiency of this plant. Partially offsetting the significantly decreased profitability of our domestic calcium chloride manufacturing operations, gross profit on CBF sales and completion services increased approximately $5.4 million, due to the increased activity levels during the current year. In addition, gross profit from the Division’s European calcium chloride manufacturing operations also increased.

Income before taxes decreased compared to the prior year, primarily due to the decreased gross profit discussed above and due to an increase in general and administrative expense, primarily due to increased employee-related costs. This decrease in profitability was partially offset by a significant decrease in other expense as compared to the prior year when we recorded a $6.5 million charge for the impairment of the Division’s investment in a European unconsolidated joint venture. Partially offsetting this decrease in other expense, other income decreased as a result of decreased foreign currency gains on the Division’s international operations.

	Year Ended December 31,						Period to Period Change
	2010			2009			2010 vs 2009			% Change
	(In Thousands, Except Percentages)
Revenues	$	103,995		$	77,700		$	26,295			33.8	%
Gross profit		22,205			16,868			5,337			31.6	%
Gross profit as a percentage of revenue		21.4	%		21.7	%
General and administrative expense		9,465			7,985			1,480			18.5	%
General and administrative expense as a percentage of revenue		9.1	%		10.3	%
Interest (income) expense, net		(34	)		2			(36	)
Other income (expense), net		2,250			6,823			(4,573	)
Income before taxes and discontinued operations	$	15,024		$	15,704		$	(680	)		-4.3	%
Income before taxes and discontinued operations as a percentage of revenue		14.4	%		20.2	%

The increase in revenues for the Production Testing segment was primarily due to a $16.9 million increase in domestic operations, approximately $10.0 million of which was recorded during the fourth quarter of 2010. This increase reflects the increase in domestic drilling activity. In addition, international operations generated $9.4 million of increased revenues. Approximately $6.3 million of this increase was associated with a South American technical management contract. Increased international revenues were reported during 2010 due to increases in Eastern Hemisphere and Brazil, and were partially offset by decreased activity and revenues in Mexico, where customer budgetary issues, security disruptions, and regional flooding during the year have negatively affected activity levels.

The increase in gross profit was due to approximately $6.7 million of increased domestic gross profit, which more than offset the approximately $1.4 million decrease in international gross profit. Domestic profitability increased due to the higher activity levels and improved operating efficiencies. While international production testing operations have historically generated higher operating margins than domestic operations, decreased activity and operating interruptions in Mexico have hampered international profitability.

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

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

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

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

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

RIGHTS TO PURCHASE SERIES ONE
JUNIOR PARTICIPATING PREFERRED STOCK	NEW YORK STOCK EXCHANGE
(TITLE OF CLASS)	(NAME OF EXCHANGE ON WHICH REGISTERED)

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

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

Summary of Oil and Gas Reserves as of December 31, 2011
Based on Average Fiscal Year Prices

Reserves category	Oil		NGL		Natural Gas		Total
	(MBbls)		(MBbls)		(MMcf)		(MBOE)
Proved reserves
Developed		95		40		676		247
Undeveloped		107		60		480		248
Total proved reserves		202		100		1,156		495

	Productive Gross				Productive Net				Developed				Undeveloped
	Wells				Wells				Acreage				Acreage
State/Area	Oil		Gas		Oil		Gas		Gross		Net		Gross		Net

Louisiana Onshore		-		-		-		-		-		-		-		-
Louisiana Offshore		-		4		-		1.3		-		-		1,187		594
Texas Onshore		11		-		2.2		-		1,331		266		-		-
Texas Offshore		2		3		-		-		-		-		-		-
Federal Offshore		-		-		-		-		66,521		25,973		26,716		16,220
Total		13		7		2.2		1.3		67,852		26,239		27,903		16,814

																					Held by
	2012				2013				2014				2015				2016				Production
State/Area	Gross		Net		Gross		Net		Gross		Net		Gross		Net		Gross		Net		Gross		Net

Louisiana Onshore		-		-		-		-		-		-		-		-		-		-		-		-
Louisiana Offshore		-		-		-		-		-		-		-		-		-		-		1,187		593
Texas Offshore		-		-		-		-		-		-		-		-		-		-		-		-
Federal Offshore		5,000		2,000		-		-		-		-		1,250		1,250		-		-		20,467		12,970
Total		5,000		2,000		-		-		-		-		1,250		1,250		-		-		21,654		13,563

	High		Low
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

2010
First Quarter	$	13.49	$	8.95
Second Quarter		14.64		8.20
Third Quarter		11.10		8.00
Fourth Quarter		12.14		9.41

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

Oct 1 - Oct 31, 2011		-			-		-	$	14,327,000
Nov 1 - Nov 30, 2011		8,115	(2)	$	8.91		-	$	14,327,000
Dec 1 - Dec 31, 2011		513,855	(2)	$	9.35		-	$	14,327,000
Total		521,970					-	$	14,327,000

	December 31,
	2011		2010		2009		2008		2007
	(In Thousands)
Balance Sheet Data
Working capital	$	296,136	$	198,106	$	148,343	$	222,832	$	181,441
Total assets		1,203,310		1,299,628		1,347,599		1,412,624		1,295,536
Long-term debt		305,000		305,035		310,132		406,840		358,024
Decommissioning and other
long-term liabilities		96,857		261,438		218,498		277,482		247,543
Equity		569,088		516,323		576,494		515,821		447,919