TETRA TECHNOLOGIES INC - Annual Report: 2010 (Form 10-K)

tti10k-20110301.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON D.C. 20549

FORM 10-K

(MARK ONE)

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

FOR THE FISCAL YEAR ENDED DECEMBER 31, 2010

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

COMMISSION FILE NUMBER 1-13455

TETRA Technologies, Inc.

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

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

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

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

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

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

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

INDICATE BY CHECK MARK IF THE REGISTRANT IS A WELL-KNOWN SEASONED ISSUER (AS DEFINED IN RULE 405 OF THE SECURITIES ACT). YES [ X ] NO [ ]

INDICATE BY CHECK MARK IF THE REGISTRANT IS NOT REQUIRED TO FILE REPORTS PURSUANT TO SECTION 13 OR SECTION 15(d) OF THE ACT. YES [ ] NO [ X ]

INDICATE BY CHECK MARK WHETHER THE REGISTRANT (1) HAS FILED ALL REPORTS REQUIRED TO BE FILED BY SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 DURING THE PRECEDING 12 MONTHS (OR FOR SUCH SHORTER PERIOD THAT THE REGISTRANT WAS REQUIRED TO FILE SUCH REPORTS) AND (2) HAS BEEN SUBJECT TO SUCH FILING REQUIREMENTS FOR THE PAST 90 DAYS. YES [ X ] NO [ ]

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

INDICATE BY CHECK MARK WHETHER THE REGISTRANT IS A LARGE ACCELERATED FILER, AN ACCELERATED FILER, A NON-ACCELERATED FILER, OR A SMALLER REPORTING COMPANY. SEE THE DEFINITIONS OF “LARGE ACCELERATED FILER,” “ACCELERATED FILER,” AND “SMALLER REPORTING COMPANY” IN RULE 12b-2 OF THE EXCHANGE ACT. (CHECK ONE):

LARGE ACCELERATED FILER [ X ]

ACCELERATED FILER [ ]

NON-ACCELERATED FILER [ ]

SMALLER REPORTING COMPANY [ ]

INDICATE BY CHECK MARK WHETHER THE REGISTRANT IS A SHELL COMPANY (AS DEFINED IN RULE 12b-2 OF THE EXCHANGE ACT). YES [ ] NO [ X ]

THE AGGREGATE MARKET VALUE OF COMMON STOCK HELD BY NON-AFFILIATES OF THE REGISTRANT WAS $668,609,042 AS OF JUNE 30, 2010, THE LAST BUSINESS DAY OF THE REGISTRANT’S MOST RECENTLY COMPLETED SECOND FISCAL QUARTER.

NUMBER OF SHARES OUTSTANDING OF THE ISSUER’S COMMON STOCK AS OF FEBRUARY 25, 2011 WAS 76,598,911 SHARES.

DOCUMENTS INCORPORATED BY REFERENCE

PART III INFORMATION IS INCORPORATED BY REFERENCE TO THE REGISTRANT’S PROXY STATEMENT FOR ITS ANNUAL MEETING OF STOCKHOLDERS TO BE HELD MAY 3, 2011 TO BE FILED WITH THE SECURITIES AND EXCHANGE COMMISSION WITHIN 120 DAYS OF THE END OF THE REGISTRANT’S FISCAL YEAR.

TABLE OF CONTENTS

	Part I
Item 1.	Business	1
Item 1A.	Risk Factors	13
Item 1B.	Unresolved Staff Comments	27
Item 2.	Properties	27
Item 3.	Legal Proceedings	32
Item 4.	[Removed and Reserved]	33

	Part II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters, and
	Issuer Purchases of Equity Securities	34
Item 6.	Selected Financial Data	36
Item 7.	Management’s Discussion and Analysis of Financial Condition
	and Results of Operation	37
Item 7A.	Quantitative and Qualitative Disclosures about Market Risk	64
Item 8.	Financial Statements and Supplementary Data	65
Item 9.	Changes in and Disagreements with Accountants on Accounting
	and Financial Disclosure	65
Item 9A.	Controls and Procedures	65
Item 9B.	Other Information	65

	Part III
Item 10.	Directors, Executive Officers, and Corporate Governance	66
Item 11.	Executive Compensation	66
Item 12.	Security Ownership of Certain Beneficial Owners and Management and
	Related Stockholder Matters	66
Item 13.	Certain Relationships and Related Transactions, and Director Independence	66
Item 14.	Principal Accounting Fees and Services	66

	Part IV
Item 15.	Exhibits, Financial Statement Schedules	67

This Annual Report on Form 10-K contains “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended, including, without limitation, statements concerning future sales, earnings, costs, expenses, acquisitions or corporate combinations, asset recoveries, working capital, capital expenditures, financial condition, and other results of operations. Such statements reflect our current views with respect to future events and financial performance and are subject to certain risks, uncertainties and assumptions, including those discussed in “Item 1A. Risk Factors.” Should one or more of these risks or uncertainties materialize, or should underlying assumptions prove incorrect, actual results may vary materially from those anticipated, believed, estimated, or projected. Unless the context requires otherwise, when we refer to “we,” “us,” and “our,” we are describing TETRA Technologies, Inc. and its subsidiaries on a consolidated basis.

PART I

Item 1. Business.

General

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, both in the United States and in certain regions of Latin America, Europe, Asia, and Africa. The Division also markets liquid and dry calcium chloride manufactured at its production facilities to a variety of markets outside the energy industry.

Our Offshore Division consists of two operating segments: Offshore Services and Maritech. The Offshore Services segment provides (1) downhole and subsea oil and gas services such as well plugging and abandonment, workover, and wireline services, (2) decommissioning and certain construction services utilizing heavy lift barges and various cutting technologies in the construction or decommissioning of offshore oil and gas production platforms and pipelines, and (3) diving services involving conventional and saturated air diving.

The Maritech segment is an oil and gas exploration, development, and production operation focused in the offshore, inland waters, and onshore U.S. Gulf Coast region. The Offshore Division’s Offshore Services segment performs a significant portion of the well plugging, abandonment, and decommissioning services required by Maritech.

Our Production Enhancement Division consists of two operating segments: Production Testing and Compressco. The Production Testing segment provides production testing services in many of the major oil and gas basins in the United States, as well as in certain regions in Mexico, Brazil, Northern Africa, the Middle East, and other international markets.

The Compressco segment provides wellhead compression-based production enhancement services throughout most of the onshore producing regions of the United States, as well as certain basins in Canada, Mexico, South America, Europe, Asia, and other international locations.

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

We were incorporated in Delaware in 1981. Our corporate headquarters are located at 24955 Interstate 45 North in The Woodlands, Texas. Our phone number is 281-367-1983, and our website is accessed at www.tetratec.com. We make available on our website, free of charge, our Corporate Governance

Guidelines, Code of Business Conduct and Ethics, Code of Ethics for Senior Financial Officers, Audit Committee Charter, Management and Compensation Committee Charter, and Nominating and Corporate Governance Committee Charter, as well as our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and all amendments to those reports as soon as is reasonably practicable after such materials are electronically filed with, or furnished to, the Securities and Exchange Commission (SEC). The information on our website is not, and shall not be deemed to be, a part of this Annual Report on Form 10-K or incorporated into any other filings with the SEC. Information filed with the SEC may be read or copied at the SEC’s Public Reference Room at 100 F Street, N.E., Washington D.C. 20549. Information on operation of the Public Reference Room may be obtained by calling the SEC at 1-800-SEC-0330. The SEC also maintains an internet website (http://www.sec.gov) that contains reports, proxy and information statements, and other information regarding issuers that file electronically. We will also make these documents available in print, free of charge, to any stockholder who requests such information from the Corporate Secretary.

Products and Services

Fluids Division

Liquid calcium chloride, calcium bromide, zinc bromide, zinc calcium bromide, sodium bromide, and similar products produced 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 as weighting agents to control bottom hole pressures during oil and gas completion and workover operations. Although they are used in many types of wells, CBFs are particularly important in offshore well operations due to the potentially greater formation sensitivity and the significantly greater investment necessary to drill and produce offshore, which carries a higher cost of error. CBFs are manufactured and distributed by our Fluids Division to oil and gas exploration and production companies and to other companies that service customers in the oil and gas industry.

Our Fluids Division provides basic and custom-blended CBFs to U.S. and international oil and gas exploration and production companies based on their specific needs and the proposed application. We also provide a broad range of associated services, including onsite fluid filtration, handling, and recycling; wellbore cleanup; fluid engineering consultation; and fluid management services, as well as high volume water transfer and treatment services for high pressure fracturing operations. We offer to repurchase (buyback) from customers used CBFs, which we are able to recondition and recycle. The utilization of reconditioned CBFs reduces the net cost of the CBFs to our customers and minimizes the need to dispose of used fluids. We recondition the CBFs through filtration, blending, and the use of proprietary chemical processes, and then market the reconditioned CBFs.

The Division’s fluid engineering personnel determine the optimal CBF blend for a customer’s particular application to maximize the effectiveness and lifespan of the CBFs. We modify the specific density, crystallization temperature, and chemical composition of the CBFs as necessary. Our filtration services use a variety of techniques and equipment for the removal of 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, dust control, 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 sources, including non-owned plants under agreements with the owners. Domestically, we manufacture calcium chloride at five manufacturing plant facilities, the largest of which is our plant near El Dorado, Arkansas. This plant was recently constructed and began production of liquid calcium chloride during the fourth quarter of 2009 and dry (flake) calcium chloride during January 2010. Liquid and flake calcium chloride are also produced at our Kokkola, Finland plant. We operate our European calcium chloride manufacturing operations under the name TETRA Chemicals Europe. As of December 31, 2010, we continued to operate a plant in Lake Charles, Louisiana,

where we produced dry and liquid calcium chloride. However, in February 2011, we shut down the dry (pellet) calcium chloride plant at this facility. We manufacture liquid calcium chloride at our facility in Parkersburg, West Virginia and have two solar evaporation plants located in San Bernardino County, California, that produce liquid calcium chloride from underground brine reserves. All of our calcium chloride production facilities have a combined production capacity of more than 1.5 million liquid equivalent tons per year.

We manufacture and distribute calcium bromide, zinc bromide, zinc calcium bromide, and sodium bromide at our West Memphis, Arkansas, production facility. A patented and proprietary production process utilized at this facility uses bromine and zinc to manufacture zinc bromide. We purchase raw material bromine pursuant to a long-term supply agreement. This facility also uses proprietary processes to manufacture calcium bromide and sodium bromide and to recondition and upgrade used CBFs repurchased from our customers.

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

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

Offshore Division

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 in the construction or decommissioning of offshore oil and gas production platforms, subsea wells, and pipelines, and (3) diving services involving conventional and saturated air diving. We provide these services to offshore oil and gas operators in the U.S. Gulf of Mexico and in the inland water and onshore markets in the U.S. Gulf Coast region. 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 company operating in the offshore, inland waters, and onshore U.S. Gulf Coast regions. The Offshore Division’s Offshore Services segment performs a significant portion of the P&A and decommissioning services required by Maritech, and Maritech is a significant customer of the Offshore Services segment.

In providing its services, our Offshore Services segment utilizes barge-mounted P&A rigs, a platform P&A rig, offshore rigless P&A packages, two heavy lift vessels, several dive support vessels and other dive support assets, and onshore rigs that we own and operate. 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, although the Offshore Services segment provides P&A services to customers in the inland waters and onshore in Texas and Louisiana. 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 open hole), perforating, and tubing-conveyed perforating services. The Offshore Services segment also utilizes the specialized equipment and engineering expertise necessary 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, Harvey, and Houma, Louisiana and in Bryan and Victoria, Texas.

The size of our Offshore Services segment’s fleet of service vessels has expanded and contracted in recent years as necessary to serve the changing demand for well abandonment, construction, platform and pipeline decommissioning, construction, diving, and other offshore services. We currently have two vessels with the capacity to perform heavy lift decommissioning and construction projects and integrated operations on oil and gas production platforms. Subsequent to our acquisition of Epic in March 2006, we purchased a

dynamically positioned dive support vessel, the Epic Diver, and refurbished two of Epic’s existing dive support vessels, the Epic Explorer and the Epic Seahorse. The Epic Diver, which has been significantly utilized since we acquired it, has required extensive repair and refurbishment in the past and is currently in need of significant further repairs. In addition, certain of the Offshore Services segment’s more significant customers now require more technologically updated dive support vessels. In response to these changes, beginning in June 2009, we increased our service fleet by leasing a specialized dive support vessel, the Adams Challenge. In addition, the Offshore Services segment leases additional dive support vessels as they are needed. As a result, in December 2010, we determined that the Epic Diver is no longer strategic to our Offshore Services segment’s plans to serve its markets going forward, and a decision was made to divest the vessel. Each of the leased dive support vessels, as well as one of the Offshore Services segment’s owned dive support vessels, the Epic Explorer, includes a saturation diving system that is 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 and production platforms and pipelines, particularly following the April 2010 Macondo well oil spill. Recent regulations issued by the Bureau of Ocean Energy, Management, Regulation, and Enforcement (BOEMRE) have included 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. 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 BOEMRE 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 upon the occurrence of certain events, including the end of useful operations, cessation of commercial production, and expiration of the lease.

Maritech is an oil and gas exploration and production operation with properties located in the offshore, inland water, and onshore U.S. Gulf Coast region. The Offshore Division’s Offshore Services segment performs a significant portion of the well abandonment and decommissioning services required by Maritech.

Maritech has historically grown its operations by acquiring and developing oil and gas property interests located in the offshore, inland waters, and onshore U.S. Gulf Coast region. However, due to efforts to conserve and reallocate capital, we have begun to decrease our investment in Maritech by suspending our search for oil and gas property acquisitions and decreasing our development activities. In addition, we are exploring strategic alternatives to our ownership of Maritech and its oil and gas properties and are reviewing opportunities to sell Maritech oil and gas property packages to industry participants and other third parties. As part of this overall effort, in February 2011, Maritech sold a group of properties that accounted for approximately 11.4% of its proved reserves as of December 31, 2010. Maritech continues to perform a significant amount of plugging, abandonment, and decommissioning work on its offshore oil and gas properties as part of its strategy to reduce its risk from hurricanes and in response to the high cost of windstorm insurance coverage. During the three year period ended December 31, 2010, Maritech has expended approximately $194.8 million on such efforts.

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. Maritech’s decommissioning liabilities, as of December 31, 2010, total $265.5 million ($285.8 million undiscounted). 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 to be recorded. As of December 31, 2010, Maritech determined that significant adjustments were necessary to increase its decommissioning liabilities to reflect current industry developments, including the impact from the NTL 2010-G05 “Idle Iron Guidance” issued in late 2010 by BOEMRE. 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.

While Maritech’s exploration and development activities have been reduced during the past two years, Maritech has continued to develop certain of its most strategic property assets. Maritech’s mostsignificant development efforts are currently located on the East Cameron 328 block located in Federal offshore waters and the Timbalier Bay field located in the inland waters area of Louisiana. During 2010, Maritech participated in drilling eight wells, four of which were located in the Timbalier Bay field. Seven of the wells were successful. The most recent acquisitions of producing oil and gas properties were in July 2010, when Maritech purchased interests in certain onshore oil and gas properties located in McMullen County, Texas.

During the three year period ended December 31, 2010, Maritech invested approximately $182.4 million on exploration, exploitation, development, and acquisition activities, although such activities decreased beginning in 2009 due to capital spending constraints. As of December 31, 2010, Maritech had proved reserves of approximately 7.3 million barrels of oil and liquids, and 25.6 billion cubic feet of natural gas, with undiscounted future net pretax cash flow of approximately $210.0 million.

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

Production Enhancement Division

The Production Testing segment of the Production Enhancement Division provides flow back pressure and volume testing of onshore and offshore oil and gas wells, which provides reservoir data to enable operators to optimize production and minimize oil and gas reservoir damage. In addition, the Production Testing segment provides pipeline cleanout, well control, well cleanup, and laboratory analysis services. The Production Testing segment also provides early-life production solutions designed to access newly available production 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 needed for reservoir management, including shale gas exploitation, and optimization of well workover programs.

The Production Testing segment maintains one of the largest fleets of high pressure production testing equipment in the United States, including equipment designed to work in environments where high levels of hydrogen sulfide gas are present. The Production Testing segment has operating locations in Louisiana, Pennsylvania, and throughout Texas. Internationally, the segment has locations in Mexico and South America, North Africa, Middle East, and Asia.

During 2009, the Production Enhancement Division entered into a technical management contract to perform engineering, procurement, and installation of equipment needed for the cleanup and removal of oil bearing materials at two refinery locations in South America. The Division began providing services and equipment pursuant to this contract during late 2009 and throughout 2010. The remaining services to be provided under the contract are expected to continue to be performed in stages over the next two to three years.

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. Although Compressco’s services are applied primarily to mature wells with low formation pressures, they are also employed on newer wells that have experienced significant production declines or that are characterized by lower formation pressures. 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 the compressor equipment it uses to provide production enhancement services, and in certain markets, sells its compressor units to customers. Compressco’s fleet of compressor units totaled 3,647 as of December 31, 2010, of which 2,711 units were in service, representing an increase in the number of units in service of approximately 2% from the prior year.

Compressco primarily utilizes its natural gas powered GasJack® compressor unit to provide its production enhancement services. The GasJack® units increase gas production by reducing surface pressure

to allow wellbore liquids that would normally block gas flow (known as liquid loading) to produce up the wellbore. The liquids are separated from the gas stream and are either discharged to a customer-provided tank or reinjected into the sales line for separation downstream of the compressor. The gas is compressed, cooled and discharged into the sales line. 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 recently introduced its 40-horsepower electric VJackTM compressor unit to provide its production enhancement services on wells located in larger, mature oil fields and in environmentally sensitive areas where electric power is available at the production site. The VJackTM unit increases production 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. Compressco utilizes its GasJack® and VJackTM units in conjunction with its personnel to provide compression services to its customers, primarily on a month-to-month basis. Compressco services its compressors and provides maintenance service on sold units through a staff of mobile field technicians who are based throughout Compressco’s market areas.

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

Sources of Raw Materials

Our Fluids Division manufactures calcium chloride, calcium bromide, zinc bromide, zinc calcium bromide, and sodium bromide for distribution to its customers. The Division also recycles calcium and zinc bromide CBFs repurchased from its oil and gas customers.

The Division manufactures liquid calcium chloride, either by reacting hydrochloric acid with limestone or from natural underground brine reserves. The Division also purchases liquid and dry calcium chloride from a number of U.S. and international chemical manufacturers. 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. We use a proprietary process that permits the use of less expensive limestone, while maintaining end-use product quality. Currently, hydrochloric acid and limestone are generally available from multiple sources. We significantly increased our production capacity of liquid and dry calcium chloride with the construction of our El Dorado, Arkansas, calcium chloride plant facility, which began production of liquid calcium chloride during the fourth quarter of 2009. This plant is located on land adjacent to a bromine plant of Chemtura Corporation (Chemtura), located near El Dorado, Arkansas. Our El Dorado, Arkansas, plant produces liquid and flake calcium chloride utilizing calcium chloride containing brines (tail brine) obtained from Chemtura’s operations, which allows the Division to reduce its dependence on third-party purchases of hydrochloric acid. We also produce calcium chloride at our two plants in San Bernardino County, California, by evaporating naturally occurring 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.

We obtain raw materials utilized by our Lake Charles, Louisiana, facility to produce liquid and dry (pellet) calcium chloride from a variety of sources. 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, although the liquid calcium chloride operation remains operational.

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. There are multiple sources of zinc that we can use in the production of zinc bromide and zinc calcium bromide. In December 2006, we entered into 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, Chemtura supplies the Division’s new El Dorado calcium chloride plant with tail brine from its Arkansas facilities following the extraction of bromine from such brine.

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 execution of the Chemtura bromine supply agreement discussed above provides us with an immediate 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 any future development of the Magnolia, Arkansas, assets.

Our Production Enhancement Division, through its Production Testing segment, outsources the construction of its production testing equipment to 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, and a partial or complete loss of certain of them could have a negative impact on our business. Should we experience unexpected unavailability of the components we use to assemble our equipment, we believe that there are adequate, alternative suppliers and that this impact would not be severe.

Market Overview and Competition

Fluids Division

Our Fluids Division provides CBFs, drilling and completion fluid systems, additives, filtration services, wellbore cleanup services, frac water handling and treatment services, and other related products and services to oil and gas exploration and production companies, onshore and offshore, in the United States and certain international markets. Current areas of market presence include the onshore U.S., the U.S. Gulf of Mexico, the North Sea, Mexico, and certain countries in South America, Europe, Asia, and Africa. The Division also markets to customers with deepwater operations that utilize high volumes of CBFs and are subject to harsh downhole conditions such as high pressure and high temperatures. However, 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 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, there remains significant regulatory uncertainty. In addition, government issuances of permits for offshore activities have slowed considerably, resulting in delays in the timing for offshore projects, including projects for many of our customers.

In June 2008, we announced that we had signed a contract with Petroleo Brasileiro S.A. (Petrobras), the national oil company of Brazil, to provide completion fluids and associated services on deepwater wells offshore Brazil. Through December 31, 2010, activity with Petrobras pursuant to this contract has also been much lower than anticipated.

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, through its recently acquired BJ Services Company subsidiary. This market is highly competitive, and competition is based primarily on service, availability, and price. Major customers of the Fluids Division include Anadarko, Devon, Dominion Resources, EOG Resources, Halliburton Company, LLOG Exploration, Newfield Exploration Company, Nippon Oil Exploration, Petrobras, Tullow Oil, and Shell Oil. 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, roadway dust control and de-icing, mining, janitorial, construction, pharmaceutical, 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.

Offshore Division

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 are also affected by oil and natural gas prices and the general economic condition of the industry.

Future demand for the services provided by our Offshore Services segment is expected to be increased as a result of the recent regulations issued by the BOEMRE, including NTL 2010-G05, the “Idle Iron Guidance.” In the U.S. Gulf of Mexico market, regulations generally require wells to be plugged, offshore platforms decommissioned, pipelines abandoned, and the well site cleared within twelve months after an oil or gas lease expires. However, NTL 2010-G05 establishes well abandonment and decommissioning requirements that are no longer tied to the one year anniversary of lease expiration. The maturity and production decline of Gulf of Mexico oil and gas fields has, over time, caused an increase in the number of wells to be plugged and abandoned and platforms and pipelines to be decommissioned.

Demand for offshore abandonment and decommissioning services during the past several years increased substantially as a result of 2005 and 2008 hurricane activity 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 remediation work to be performed as a result of these storms has been performed, the Offshore Services segment continues to develop or acquire specialized equipment and engineering expertise that may be used to provide such services to customers whose offshore wells and production platforms were toppled, destroyed, or heavily damaged by storms or may be damaged by future storms. The threat of future storm activity, combined with the volatility of the cost 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 the current 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; the financial strength to ensure all abandonment and decommissioning obligations are satisfied; and a comprehensive safety and environmental program. During 2010, we 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 fleet satisfy these market requirements, allowing 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. Other major customers include Apache, Chevron, Mariner Energy, Nexen Petroleum USA Inc., Stone Energy, Versabuild, and W&T Offshore. These services are performed primarily offshore in the U.S. Gulf of Mexico and in Gulf Coast inland waters and onshore in Texas and Louisiana, however, the segment is also seeking to expand its operations to international markets. Our principal competitors in the domestic offshore and inland water services markets are Global Industries, Ltd., Offshore Specialty Fabricators, Inc., Helix Energy Solutions, 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 or to expand our operations to other markets. Our ability to successfully bid our services fluctuates from year to year, depending on market conditions.

Production Enhancement Division

The Production Enhancement Division provides production testing and wellhead compression-based services and products to its customers. The Production Testing segment provides services primarily to the natural gas segment of the oil and gas industry. 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 demands of shale gas reservoirs. 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 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. The segment is seeking to grow its international operations, 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 U.S. offshore market and international markets. The major customers for this segment include BP, Cabot, Chesapeake, ConocoPhillips, Encana Oil & Gas, Shell Oil, Southwestern Energy, 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 over 400 natural gas and oil exploration and production companies operating throughout most of the onshore producing regions of the United States. Internationally, Compressco has significant operations in Canada and Mexico 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 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 with a separate engine driver or a reciprocating compressor with a separate engine driver. To a lesser extent, Compressco faces competition from large, national and multinational 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 utilization of its services. Compressco’s major customers include BP, PEMEX, Devon, EXCO Resources, and ConocoPhillips.

Other Business Matters

Marketing and Distribution

The Fluids Division markets its CBF products and services through its distribution facilities located in the U.S. Gulf Coast region, the North Sea region of Europe, and certain other international markets, including Brazil, West Africa, and the Middle East. These facilities are in close proximity to both product supplies and customer concentrations.

Non-oilfield calcium chloride products are also marketed through the Division’s sales offices in California, Missouri, Pennsylvania, and Texas, as well as through a network of distributors located throughout the United States and northern and central Europe. In addition to shipping products directly from its production facilities in the United States and Europe, the Division has distribution facilities strategically located to provide efficient product distribution.

None of our customers individually exceeded 10% of our total consolidated revenues during the year ended December 31, 2010.

Backlog

The level of 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 and consists of the non-Maritech share of the well abandonment and decommissioning work associated with the oil and gas properties operated by Maritech. Prior to the impact of any future sales of Maritech oil and gas properties, our estimated backlog on December 31, 2010 was $64.1 million, of which approximately $7.6 million is expected to be billed during 2011. This compares to an estimated backlog of $121.9 million at December 31, 2009.

Employees

As of December 31, 2010, we had 2,932 employees. None of our U.S. employees are presently covered by a collective bargaining agreement other than the employees of our Lake Charles, Louisiana, calcium chloride production facility, who are represented by the United Steelworkers Union. Our international employees are generally members of the various labor unions and associations common to the countries in which we operate. We believe that our relations with our employees are good.

Patents, Proprietary Technology, and Trademarks

As of December 31, 2010, we owned or licensed twenty-one issued U.S. patents and had ten patent applications pending in the United States. Internationally, we had fifteen owned or licensed foreign patents and 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. 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. Our management believes, however, that it would require a substantial period of time and substantial resources to independently develop similar know-how or technology.

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

Health, Safety, and Environmental Affairs Regulations

We are subject to various federal, state, local, and international laws and regulations relating to occupational health and safety and the environment, including regulations and permitting for air emissions, wastewater and stormwater discharges, the disposal of certain hazardous and nonhazardous wastes, and wetlands preservation. Failure to comply with these occupational health, safety, and environmental laws and regulations or associated permits may result in the assessment of fines and penalties and the imposition of investigatory and remedial obligations.

With respect to our operations in the United States, various environmental protection laws and regulations have been enacted and amended in the U.S. during the past three decades in response to public concerns pertaining to the environment. Our U.S. operations and its customers are subject to these various evolving environmental laws and corresponding regulations. In the United States, these laws and regulations are enforced by the U.S. Environmental Protection Agency (EPA); the BOEMRE 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. We must comply with the requirements of environmental laws and regulations applicable to our operations, including 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 Hazardous Materials Transportation Act of 1975; and the Pollution Prevention Act of 1990.

Our operations outside the United States are subject to various international governmental controls and restrictions pertaining to the environment, occupational health and safety, and other regulated activities in the countries in which we operate. We believe that our operations are in substantial compliance with existing international governmental controls and regulations and that compliance with these international controls and regulations has not had a material adverse effect on operations.

At some of our facilities, we hold various permits regulating air emissions, wastewater and stormwater discharges, the disposal of certain hazardous and nonhazardous wastes, and wetlands preservation.

We believe that our manufacturing plants and other facilities are in general 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.

Offshore Operations

During 2010, the U.S. federal government established the BOEMRE to replace the U.S. Minerals Management Service (MMS). This federal agency reorganization was 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 has 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 delayed or suspended. Such notices and regulations issued to date include requirements by operators to:

·	Submit well blowout prevention measures and contingency plans, including demonstrating access to subsea blowout containment resources;

·	Abide by new permitting standards requiring detailed, independently certified descriptions of well design, casing, and cementing;

·	Follow new performance-based standards for offshore drilling and production operations;

·	Certify that the operator has complied with all regulations; and,

·	Abide by the new “Idle Iron Guidance” regulations.

The BOEMRE’s scope of responsibility also includes an investigation and review unit, provides for public forums, provides for the conducting of comprehensive environmental analyses, and creates implementation teams to analyze various aspects of the BOEMRE’s regulatory structure and to help implement the reform agenda.

We maintain various types of business insurance intended to mitigate our liability 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, full collision liability, damage to fixed and floating objects, pollution liability, and wreck removal. We also maintain a vessel pollution liability policy that provides pollution coverage for oil or hazardous substances emanating from a vessel, addressing both OPA (Oil Pollution Act of 1990) and CERCLA obligations. This coverage also provides coverage for cost of defense, fines, and penalties. The Maritech energy package provides operational all risks coverage (excluding named windstorm coverage) for physical loss or damage to scheduled offshore property, including removal of wreck and/or debris, and for operator’s extra expense such as control of well, redrill/extra expense, and pollution and cleanup.

Apart from our Maritech operations, we provide services and products to customers in the offshore Gulf of Mexico, generally pursuant to written master services agreements that create insurance and indemnity obligations for both parties. If there was an explosion or similar catastrophic event on an offshore location where we are providing services and products, under the majority of our master services agreements with our customers:

(1) We would be required to indemnify our customer for any claims for injury, death, or property loss or destruction made against them by us or our subcontractors or our 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.

Maritech engages contractors to provide drilling and related services and products and well abandonment and related services and products, generally pursuant to written master services agreements that create insurance and indemnity obligations for both parties. If there was an explosion or similar event on an offshore Maritech location where a Maritech contractor was providing services and products, under a majority of Maritech’s master services agreements with its contractors, Maritech would be required to indemnify its contractor for any claims against the contractor for injury, death, or property loss or destruction brought by Maritech, its other subcontractors or their respective employees. The contractor would be required to indemnify Maritech for any claims for injury, death, or property loss or destruction made against Maritech by the contractor or its subcontractors or the employees of the contractor or its subcontractors. These indemnities would apply regardless of the cause of such claims, including the negligence of the indemnified party. Maritech’s insurance is structured to cover the cost of defense and any resulting liability from all indemnified claims, up to policy limits.

In accordance with applicable regulations, Maritech maintains an oil spill response plan with the BOEMRE, and has designated employees who are trained as qualified individuals and prepared to coordinate a response to any spill or leak. Maritech also has contracts in place to assure that a complete and experienced resource team is available as required.

Item 1A. Risk Factors.

Forward Looking Statements

Some information included in this report, other materials filed or to be filed with the SEC, as well as information included in oral statements or other written statements made or to be made by us contain or incorporate by reference certain statements (other than statements of historical fact) that constitute forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. When used herein, the words “assume,” “may,” “will,” “should,” “goal,” “anticipate,” “expect,” “estimate,” “could,” “believes,” “seeks,” “plans,” “intends,” “projects” or “targets” and similar expressions that convey the uncertainty of future events or outcomes are intended to identify forward-looking statements.

Where any forward-looking statement includes a statement of the assumptions or bases underlying such forward-looking statement, we caution that, while we believe these assumptions or bases to be reasonable and to be made in good faith, assumed facts or bases almost always vary from actual results, and the difference between assumed facts or bases and actual results could be material, depending on the circumstances. It is important to note that actual results could differ materially from those projected by such forward-looking statements.

Although we believe that the expectations reflected in such forward-looking statements are reasonable and such forward-looking statements are based upon the best data available at the date this report is filed with the SEC, we cannot assure you that such expectations will prove correct. Factors that could cause our results to differ materially from the results discussed in such forward-looking statements include, but are not limited to, the following:

·	general economic, business, and political conditions in the markets we serve or hope to serve in the United States and abroad;

·	the demand for our products and services in the Gulf of Mexico could continue to be adversely impacted by the 2010 oil spill, resulting regulatory reforms, and ongoing regulatory uncertainty;

·	the supply, demand, and prices for oil, gas, and competing energy sources, and more particularly the supply, demand, and prices for well completion, diving, and abandonment and decommissioning services;

·	activities of our customers and competitors;

·	the availability of raw materials and labor at reasonable prices;

·	operating and safety risks inherent in oil and gas production;

·	access to pipelines, gas gathering and processing facilities for our oil and gas production;

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

·	the potential impact of the loss of one or more key employees;

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

·	technological obsolescence;

·	weather risks, including the risk of physical damage to our platforms, facilities, and equipment and the ability to resume operations following damage;

·	our ability to implement our business strategy;

·	uncertainties about finding, developing, producing, and estimating oil and gas reserves and plugging and abandoning wells and structures;

·	the accounting for our oil and gas operations may result in volatility of earnings;

·	the availability of capital (including any financing) to fund our business strategy and/or operations and any restrictions resulting from such financing;

·	foreign currency risks;

·	the impact of existing and future laws and regulations;

·	environmental risks;

·	estimates of hurricane repair costs;

·	acquisition valuation and integration risks; and

·	risks related to our foreign operations.

All such forward-looking statements in this document are expressly qualified in their entirety by the cautionary statements in this paragraph, and we undertake no obligation to publicly update or revise any forward-looking statements.

Certain Business Risks

Although it is not possible to identify all of the risks we encounter, we have identified the following significant risk factors that could affect our actual results and cause actual results to differ materially from any such results that might be projected, forecasted, or estimated by us in this report.

Market Risks

The demand and prices for our products and services are affected by the general economic, financial, business, political, and social conditions in the markets we serve or hope to serve in the future.

The 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 national and international economic, financial, business, political and social conditions that impact the supply, demand, and prices of oil and gas. Activity levels have decreased as a result of the recent decline in energy consumption caused by the recent global recession. Decreased energy consumption has resulted in a decrease in energy prices, particularly natural gas prices, during much of 2010 compared to prices received during early to mid-2008. This decline in energy prices has negatively affected the operating cash flows and capital plans of many of our customers, which has negatively impacted the demand for many of our products and services.

If economic conditions worsen, there may be additional constraints on oil and gas industry spending levels. Such a stagnation of economic activity would negatively affect both the demand for many of our products and services as well as the prices we charge for these products and services, which would continue to negatively affect our revenues and future growth.

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

The demand for our products and services in the Gulf of Mexico could continue to be adversely impacted by the 2010 Macondo blowout and resulting oil spill, which has led to increased regulation and continuing regulatory uncertainty.

On April 20, 2010, a blowout on the Macondo well resulted in the rig catching fire and sinking. The resulting government-imposed drilling moratorium in the deepwater Gulf of Mexico and related regulatory requirements have significantly reduced the U.S. Gulf of Mexico completion fluids market and slowed the permitting of new drilling activity and plug and abandonment work in the U.S. Gulf of Mexico. The BOEMRE has issued several new regulations that are focused on offshore operating requirements, spill cleanup and enforcement matters. The BOEMRE recently issued to U.S. Gulf of Mexico operators notices 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. Although the moratorium 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 uncertainty regarding the deepwater activities did,

and 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 on future operating results going forward, we expect our offshore activity levels and the offshore activity levels of our Fluids Division customers to be less than they were prior to April 2010.

In addition, we cannot predict how government regulatory agencies will further respond to the 2010 Macondo well incident or whether additional changes in laws and regulations concerning operations in the U.S. Gulf of Mexico will be enacted. Future regulatory requirements could further delay our customers’ activities, reduce our revenues, and increase our operating costs, including the cost to insure offshore operations, resulting in reduced cash flows and profitability.

Our oil and gas revenues and cash flows are subject to oil and gas price volatility.

Our revenues from the sale of oil and gas production represent approximately 23.1% of our total consolidated revenues for the year ended December 31, 2010. Therefore, we have significant direct market risk exposure in the pricing of our oil and gas production. Our realized pricing is primarily driven by the prevailing worldwide price for crude oil and spot prices in the U.S. natural gas market and by the fixed prices in our derivative contracts for the portion of our oil and gas production that is hedged. During 2010, the crude oil and natural gas prices we received averaged $79.01 and $4.57, respectively, prior to the impact of our derivative contracts. Prices for crude oil and natural gas have historically been volatile, and such volatility is expected to continue. Significant declines in prices for oil and natural gas could have a material adverse effect on our results of operations and quantities of reserves recoverable on an economic basis.

Our risk management activities include the use of derivative financial instruments, such as swap agreements, to hedge the impact of market price risk exposures for a portion of our oil and gas production. A portion of our production is sold at a fixed price that is intended to protect us from price declines that could occur in the market. These hedging activities also limit our upside potential from oil and gas price increases. We are exposed to the volatility of oil and gas prices for the portion of our oil and gas production that is not hedged. Currently, we do not have any natural gas derivative swap contracts in place, and our crude oil derivative swap contracts do not extend beyond December 31, 2011.

Oil and gas prices and, therefore, the levels of well drilling, completion, workover, and production activities, tend to fluctuate. Worldwide military, political, and economic 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.

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

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

Other factors affecting our operating results and activity levels include finding, development, and acquisition costs of oil and natural gas reserves; oil and gas industry spending levels for exploration, development, and acquisition activities; production costs; plugging and abandonment costs; insurance costs; the success rates of new oil and gas reserve development; and the remaining recoverable reserves in the basins in which we operate. 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 gas industry activity and spending levels in this region. Our operations may also be affected by technological advances, cost of capital, tax policies, and overall worldwide economic activity. Adverse changes in any of these other factors may depress the levels of well drilling, completion, workover, and production activity and result in a corresponding decline in the demand for our products and services, thereby having a material adverse effect on our revenues and profitability.

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

We compete with numerous companies in our operations. Many of our competitors have substantially greater financial and other related 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.

We are dependent on third-party suppliers for specific products and equipment necessary to provide certain of our products and services.

We sell a variety of clear brine fluids to the oil and gas industry, including calcium chloride, calcium bromide, zinc bromide, zinc calcium bromide, and sodium bromide, some of which we manufacture and some of which are purchased from third parties. We also sell calcium chloride 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 bromine, hydrobromic acid, and other raw materials, including various forms of zinc, 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. We also acquire bromide compound products from several third-party suppliers. If we are unable to acquire the bromide compound products, bromine, hydrobromic or hydrochloric acid, zinc, or any other supplies of raw material at reasonable prices for a prolonged period, our business could be materially and adversely affected.

As a result of the continuing general economic conditions, many chemical manufacturers are experiencing reduced demand, production interruptions, and financial difficulties. For example, during March 2009, Chemtura announced that it and its affiliates had filed voluntary petitions for reorganization under Chapter 11 of the U.S. Bankruptcy code. Under bankruptcy, Chemtura had the right to accept or reject executory contracts, including certain of our agreements with them under which we acquire raw material bromine and brine. During the fourth quarter of 2009, we negotiated certain amendments to our existing agreements with Chemtura, and such amended agreements were signed by Chemtura and approved by the bankruptcy court. Also during 2009, we wrote down the value of our investment in a European calcium chloride manufacturing joint venture following our joint venture partner’s announced shutdown of its adjacent plant facility that supplies feedstock to the joint venture’s plant. In addition, occasional raw material supply constraints have resulted in certain of our manufacturing facilities operating at less than full capacity, resulting in decreased production volumes. Most recently, the diminished availability of economical raw materials has led to the shutdown of our Lake Charles, Louisiana, calcium chloride plant facility’s dry product manufacturing operation. The availability of feedstock raw materials at economical prices may continue to affect the operations of our various manufacturing facilities going forward. The purchase of alternative raw material supplies at a less favorable cost could also result in decreased profitability.

Some of the well abandonment and decommissioning services performed by our Offshore Services segment require the use of vessels, equipment, and services provided by third parties. We lease equipment and obtain services from certain providers; this equipment and these services are subject to availability at reasonable prices, of which there can be no assurance.

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.

Our exploration and production operations are subject to the availability of drilling rigs, tubular products, and numerous other products and services at reasonable prices.

We may not be able to obtain access to pipelines, gas gathering, transmission, and processing facilities to market our oil and gas production.

The marketing of oil and gas production depends in large part on the availability, proximity, and capacity of pipelines, gas gathering systems, and other transportation, processing and refining facilities, as well as the existence of adequate markets. If there was insufficient capacity available on these systems, or if these systems were unavailable to us, the price offered for our production could be significantly depressed, or we could be forced to shut-in some production or delay or discontinue drilling plans while we construct our own facilities. We also rely on facilities developed and owned by third parties in order to process, transmit, and sell our oil and gas production. Currently, a portion of Maritech’s Main Pass field is shut-in due to third-party pipeline issues and the lack of available transportation for production. This production may remain shut-in indefinitely while we await a resolution by third parties and consider alternative transportation options. Our plans to develop and sell our oil and gas reserves could be materially and adversely affected by the inability or unwillingness of third parties to provide sufficient transmission or processing facilities to us.

The economic environment could result in significant impairments of certain of our long-lived assets, including goodwill.

The economic environment could result in decreased demand for many of our products and services, which could impact the expected utilization rates of certain of our long-lived assets, including plant facilities, operating locations, vessels, and other operating equipment. Under generally accepted accounting principles, we review the carrying value of our long-lived assets when events or changes in circumstances indicate that the carrying value of these assets may not be recoverable, based on their expected future cash flows. The impact of reduced expected future cash flow could require the write-down of all or a portion of the carrying value for these assets, which would result in an impairment charge to earnings, resulting in increased earnings volatility.

Under generally accepted accounting principles, we review the carrying value of our goodwill for possible impairment annually or when events or changes in circumstances indicate the carrying value may not be recoverable. Changes in circumstances indicating the carrying value of our goodwill may not be recoverable include a decline in our stock price and our market capitalization, future cash flows, and slower growth rates in our industry. If economic and market conditions decline, we may be required to record a charge to earnings during the period in which any impairment of our goodwill is determined, resulting in a negative impact on our results of operations.

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

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

Operating, Technological, and Strategic Risks

Our operations involve significant operating risks, and insurance coverage may not be available or cost effective.

We are subject to operating hazards normally associated with the oilfield service industry and offshore oil and gas production operations, 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 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.

We face risks related to our growth strategy.

Our growth strategy includes both internal growth and growth through acquisitions. Internal growth may require significant capital expenditures, some of which may become unrecoverable or fail to generate an acceptable level of cash flows. Internal growth 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.

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

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

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

During late 2009 and early 2010, we completed the construction and began the commissioning of a calcium chloride plant facility near El Dorado, Arkansas. During 2010, the El Dorado plant experienced significant start-up costs and early production inefficiencies that resulted in decreased profitability levels compared to our estimates. We continue to take steps to improve the operational efficiency of the plant, however, there is still a considerable effort required, and significant improvement in plant performance is not expected until mid-2011. We believe that significant additional capital investment may be necessary,

depending on the plant’s performance during the first half of 2011. The plant’s future profitability and the advantages we expect to receive from the plant will be based on many factors, including the sales prices to be received for the plant’s products, raw material and operating costs, our ability to improve the plant’s performance, and future demand for products. There can be no assurance that the El Dorado, Arkansas, plant’s future profitability will achieve original expectations.

We could incur losses on fixed price contracts.

Due to competitive market conditions, a portion of our well abandonment and decommissioning projects may be performed on a turnkey, modified turnkey, or day-rate 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.

Oil and gas exploration and production activities involve numerous risks and are subject to a variety of factors that we cannot control.

We have risks associated with our Maritech exploration and production business. These risks include those associated with finding and developing economically recoverable and marketable oil and natural gas reserves, and finding and acquiring leases and existing reserves on attractive terms. There are inherent uncertainties surrounding estimates of oil and gas reserve volumes, finding and development costs, production costs, and abandonment and decommissioning costs. To the extent we overestimate future oil and natural gas sales prices, economically recoverable reserve volumes, or future production flow rates, or we underestimate the associated costs of exploration and production operations, our financial results will be negatively impacted.

Drilling for oil and natural gas is a particularly risky activity that includes the risk that we will not encounter commercially productive oil or natural gas reservoirs. The costs of drilling and completion operations are often difficult to estimate, and the timing of drilling operations may be curtailed, delayed, or canceled as a result of a variety of factors including, but not limited to:

·	unexpected drilling conditions;

·	pressure or irregularities in formations;

·	equipment failures or accidents;

·	marine risks such as capsizing and collisions;

·	hurricanes and other adverse weather conditions;

·	shortages or delays in the delivery of equipment; and

·	compliance with environmental and other government requirements.

During the three year period ended December 31, 2010, we have expended approximately $182.4 million of exploration and development costs, and we may incur significant costs in the future. During the three year period ended December 31, 2010, we charged approximately $9.3 million of dry hole costs incurred to earnings. Future drilling activities may not be successful, and, if unsuccessful, this could have an adverse effect on our future results of operations and financial condition. We may not recover all or any portion of our investment in new wells. We are often uncertain as to the future cost or timing of drilling, completing, and operating wells. While all drilling, whether developmental or exploratory, involves these risks, exploratory drilling involves greater risks of dry holes or failure to find commercial quantities of hydrocarbons.

Maritech’s estimates of its oil and gas reserves and related future cash flows are based on many factors and assumptions, including various assumptions that are based on changing conditions in existence as of the dates of the estimates. Any material changes in those conditions, or other factors affecting those assumptions, could impair the quantity and value of our oil and gas reserves.

Maritech’s estimates of oil and gas reserve information are prepared in accordance with Rule 4-10 of Regulation S-X and reflect only estimates of the accumulation of oil and gas and the economic recoverability of those volumes. Maritech’s future production, revenues, and expenditures with respect to such oil and gas reserves will likely be different from estimates, and any material differences may negatively affect our business, financial condition, and results of operations. As a result, Maritech has experienced, and may continue to experience, significant revisions to its reserve estimates.

Oil and gas reservoir analysis is a subjective process which involves estimating underground accumulations of oil and gas that cannot be measured in an exact manner. Estimates of economically recoverable oil and gas reserves and of future net cash flows associated with such reserves necessarily depend upon a number of variable factors and assumptions. Because all reserve estimates are to some degree subjective, each of the following items may prove to differ materially from that assumed in estimating reserves:

·	the quantities of oil and gas that are ultimately recovered;

·	production flow rates over time;

·	the production and operating costs incurred;

·	the amount and timing of future development and abandonment expenditures; and

·	future oil and gas sales prices.

Furthermore, different reserve engineers may make different estimates of reserves and cash flow based on the same available data.

The estimated discounted future net cash flows from proved reserves described in this Annual Report for the year ended December 31, 2010, should not be considered as the current market value of the estimated oil and gas proved reserves attributable to Maritech’s properties. Such estimates are based on prices and costs in accordance with SEC requirements, while future prices and costs may be materially higher or lower. Using lower prices in forecasting reserves will result in a shorter life being given to producing oil and natural gas properties, because such properties, as their production levels are estimated to decline, will reach an uneconomic limit with lower prices at an earlier date. There can be no assurance that a decrease in oil and gas prices or other differences in Maritech’s estimates of its reserves will not adversely affect our financial position or results of operations.

The acquisition of oil and gas properties and their associated well abandonment and decommissioning liabilities is based on estimated data that may be materially incorrect.

In conjunction with our acquisition of oil and gas properties, we perform detailed due diligence review processes that we believe are consistent with industry practices. These acquired properties consist of both mature properties, which are generally in the later stages of their economic lives, as well as exploration and prospect opportunities. Each acquisition of oil and gas properties requires a thorough review of the expected cash flows acquired and the associated abandonment obligations assumed. The process of estimating oil and natural gas reserves is complex, requiring significant decisions and assumptions to be made in evaluating the available geological, geophysical, engineering, and economic data for each reservoir. The volatility of oil and natural gas commodity pricing additionally complicates the calculation of estimated future cash flows of properties to be acquired. As a result, these estimates are inherently imprecise. Actual future production, cash flows, development expenditures, operating and abandonment expenses, and quantities of recoverable natural gas and oil reserves may vary substantially from those initially estimated by us. Also, in conjunction with the purchase of certain oil and gas properties, we assume our proportionate share of the related well abandonment and decommissioning liabilities after performing detailed estimating procedures, analysis, and engineering studies. Our estimates of these future well abandonment and decommissioning liabilities are imprecise and are subject to change due to changes in the forecasts of the supply, demand, pricing 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. During 2010, Maritech adjusted its decommissioning liabilities, increasing them by approximately $130.8 million, either for work performed during the year or related to adjusted estimates of the cost of future work to be performed. Approximately $54.0 million of this adjustment was directly charged to earnings as an operating expense and the remainder was charged to the associated properties and partly contributed to asset impairments during 2010. 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.

Acquisitions or discoveries of additional reserves are needed to avoid a material decline in oil and gas reserves and production volumes.

The rate of production from oil and gas properties generally declines as reserves are depleted. Approximately 42.7% of our proved reserves as of December 31, 2010, are proved producing reserves. Except to the extent that we find or acquire additional properties containing estimated proved reserves; conduct successful exploration or development activities; or through engineering studies, identify additional behind-pipe zones, secondary recovery reserves, or tertiary recovery reserves, our estimated proved reserves will decline materially as reserves are produced. Natural gas and oil commodity pricing, as well as constraints on the amount of capital we have available to allocate to oil and gas activities, may limit our exploitation, development, or exploration activities for the foreseeable future, which will reduce our ability to replace produced oil and gas reserves. Future oil and gas production is, therefore, highly dependent upon our ability and level of success in acquiring or finding additional reserves.

Our accounting for oil and gas operations may result in volatile earnings.

We account for our oil and gas operations using the successful efforts method. Costs incurred to drill and equip development wells, including unsuccessful development wells, are capitalized. Costs related to unsuccessful exploratory wells are expensed as incurred. All capitalized costs are accumulated and recorded separately for each field and are depleted on a unit-of-production basis, based on the estimated remaining equivalent proved oil and gas reserves of each field. The capitalized costs of our oil and natural gas properties, on a field basis, cannot exceed the estimated undiscounted future net cash flows of that field. If net capitalized costs exceed undiscounted future net revenues, we must write down the costs of each such field to our estimate of its fair market value. Accordingly, a significant decline in oil or natural gas prices, unsuccessful exploration and/or development efforts, or an increase in our decommissioning liabilities could cause a future write-down of capitalized costs. During the three year period ended December 31, 2010, and primarily due to increased decommissioning liabilities and the decrease in oil and natural gas prices, we recorded oil and gas property impairments totaling approximately $117.8 million. Unproved properties are evaluated at the lower of cost or fair market value. On a field by field basis, our oil and gas properties are assessed for impairment in value whenever indicators become evident, with any impairment charged to expense. Under the successful efforts method of accounting, we are exposed to the risk that the value of a particular property (field) would have to be written down or written off if an impairment were present.

Weather Related Risks

Certain of our operations, particularly those conducted offshore, are seasonal and depend, in part, on weather conditions.

The Offshore Services segment has historically enjoyed its highest vessel utilization rates during the period from April to October, when weather conditions are typically more favorable for offshore activities, and has experienced its lowest utilization rates in the period from November to March. This segment, under certain turnkey 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.

Severe weather, including named windstorms, can cause significant damage and disruption to our businesses.

A significant portion of our operations is susceptible to adverse weather conditions in the Gulf of Mexico, including hurricanes and other extreme weather conditions. High winds, rising water, storm surge, and turbulent seas can cause significant damage and curtail our operations for extended periods during and after such weather conditions, while damage is being assessed and remediated. The costs to bring damaged offshore wells under control and to repair or remove damaged offshore platforms, pipelines, vessels, or other equipment can be significant. Moreover, 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 other facilities.

We incurred a significant amount of damage as a result of 2005 and 2008 hurricanes, and a portion of these costs have yet to be incurred and may not be covered under our insurance policies.

We incurred significant damage to certain of our onshore and offshore operating equipment and facilities during the third quarters of 2005 and 2008, primarily as a result of Hurricanes Katrina, Rita, and Ike. In particular, our Maritech subsidiary suffered varying levels of damage to the majority of its offshore oil and gas producing platforms, and six of its platforms were destroyed by these storms. In addition, two production facilities located in inland waters were destroyed. Maritech has reconstructed the two destroyed production facilities, and four of the destroyed platforms have been decommissioned. A majority of our damaged assets, with the exception of the remaining destroyed Maritech platforms, have been repaired or are in the final stages of being repaired, and have resumed operation. Remaining hurricane damage repair efforts consist primarily of the well intervention, abandonment, decommissioning, and debris removal associated with the remaining destroyed offshore platforms and the redrilling of a number of destroyed wells to be redrilled from a newly constructed replacement platform. While a large portion of the well intervention, abandonment, and decommissioning work has been performed on some of the destroyed platforms and the inland water production facilities, a significant amount of the work has yet to be performed. Through December 31, 2010, we have expended approximately $125.0 million for the well intervention, abandonment, decommissioning, platform reconstruction, and debris removal work performed on the platforms and production facilities which were destroyed by the storms. The remaining well intervention and subsequent debris removal efforts are expected to be performed during 2011. We estimate that the remaining abandonment, decommissioning, debris removal, and well redrilling efforts associated with the destroyed platforms will be performed at an additional cost of approximately $50 to $65 million net to our interest and before any insurance recoveries. 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.

Following the collection of $47.8 million insurance settlement proceeds during 2010 associated with Hurricane Ike, Maritech has additional maximum remaining insurance coverage available of approximately $19.5 million, all of which relates to Hurricane Ike. With regard to the damages associated with Hurricane Ike, we have performed a significant majority of the property repairs on the damaged and destroyed platforms. These efforts included the reconstruction of the destroyed East Cameron 328 platform and the initial redrilling efforts of wells associated with this destroyed platform. Despite our confidence that the majority of the remaining repair, debris removal, and well redrilling costs relating to Hurricane Ike will qualify as covered costs pursuant to our insurance coverage, a portion of these costs may not be reimbursed. 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.

For a further discussion of the remaining costs to repair damage as a result of 2005 and 2008 hurricanes, see Notes to Consolidated Financial Statements, “Note B – Summary of Significant Accounting Policies, Repair Costs and Insurance Recoveries.”

Our oil and gas production levels continue to be affected by the 2008 hurricanes.

Our operating cash flows continue to be affected by the interruption in Maritech’s oil and gas production as a result of damage to offshore platforms and pipelines caused by the 2008 hurricanes. One of the destroyed offshore platforms was on the East Cameron 328 field, which is a key producing field. During the fourth quarter of 2009, Maritech modified one of the remaining platforms in this field and has restored a portion of the interrupted production. During 2010, Maritech completed the construction of a new offshore production platform to replace the destroyed platform, and has begun redrilling certain wells from the new platform. These redrill efforts are estimated to cost approximately $13 to $19 million, before insurance recoveries, and are scheduled to be completed in 2011. With regard to the shut-in production, our insurance protection does not include business interruption coverage. While repair and recovery efforts have been prioritized to restore Maritech’s production as soon as possible, these production restoration efforts are expected to continue into 2011 and beyond. The full resumption of Maritech’s pre-storm production levels may never occur.

Windstorm insurance coverage for Gulf of Mexico offshore oil and gas production operations is costly, and may result in significant uninsured losses for our Maritech operations.

In the past, we have maintained windstorm insurance that is designed to cover damages to our Maritech platforms, equipment, and other assets located in the Gulf of Mexico. As a result of hurricanes in 2005 and 2008, Maritech suffered varying levels of damage to a majority of its offshore platforms, and several platforms were destroyed. Following these storms, insurance premiums and deductibles for windstorm insurance covering these assets increased dramatically, and policy limits and sub-limits were decreased dramatically. During the second quarter of 2009, we determined that the cost of premiums and the associated deductibles and coverage limits for windstorm damage for Maritech’s offshore properties made the continuation of such coverage uneconomical, and Maritech discontinued its insurance coverage for windstorm damage through May 2010, electing to self-insure for these damages. During the second quarter of 2010, we purchased windstorm insurance coverage for the June 2010 through May 2011 season, but with significantly decreased policy limits and sub-limits and increased deductibles. If premiums, deductibles, and policy limits for windstorm insurance remain as unfavorable for the June 2011 through May 2012 season, we may once again choose to retain a significant amount of hurricane risk. Depending on the severity and location of any storms during a period in which we are self-insured or carry high deductibles, uninsured losses could be significant and could have a material adverse effect on our financial position, results of operations, and cash flows.

There can be no assurance that future insurance coverage with more favorable deductible and maximum coverage amounts will be available in the market or that its cost will be justifiable. There can be no assurance that any insurance will be adequate to cover losses or liabilities associated with operational hazards. We cannot predict the availability of insurance or its availability at premium levels that justify its purchase.

Financial Risks

Significant deterioration of our financial ratios could result in covenant defaults under our long-term debt agreements and result in decreased credit availability.

As of December 31, 2010, our total debt outstanding was approximately $305.0 million and our debt to total capital ratio was 37.1%. This debt to total capital ratio excludes approximately $65.4 million of available cash held as of December 31, 2010. Additional growth could result in increased debt levels to support our capital expenditure needs or acquisition activities. Debt service costs related to outstanding long-term debt represent a significant use of our operating cash flow and could increase our vulnerability to general adverse economic and industry conditions. Our long-term debt agreements contain customary covenants and other restrictions and requirements. In addition, the agreements require us to maintain certain financial ratio requirements. Significant deterioration of these ratios could result in a default under the agreements. The agreements also include cross-default provisions relating to any other indebtedness we have that is greater than a defined amount. If any such indebtedness is not paid or is accelerated and such event is not remedied in a timely manner, a default will occur under the long-term debt agreements. Any event of default, if not

timely remedied, could result in a termination of all commitments of the lenders and an acceleration of any outstanding loans and credit obligations.

We are exposed to significant credit risks.

We face credit risk associated with the significant amounts of accounts receivable we have with our customers in the energy industry. Many of our customers, particularly those associated with our onshore operations, are small-sized to medium-sized oil and gas operating companies that may be more susceptible to fluctuating oil and gas commodity prices or generally increased operating expenses than larger companies. Our ability to collect from our customers may be impacted by adverse changes in the energy industry.

Maritech purchases interests in oil and gas properties in connection with the operations of our Offshore Division. As the owner and operator of these 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, if Maritech acquires less than 100% of the working interest in a property, its co-owners are responsible for the payment of their portions of the associated operating expenses and abandonment liabilities. However, if one or more co-owners do not pay their portions, Maritech and any other nondefaulting co-owners may be liable for the defaulted amount. If any required payment is not made by a previous owner or a co-owner and any security is not sufficient to cover the required payment, we could suffer material losses.

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

The operations of certain of our subsidiaries are exposed to fluctuations between the U.S. dollar and certain foreign currencies. 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.

We are exposed to interest rate risk with regard to our indebtedness.

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, 2010, 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.

Legal, Regulatory, and Political Risks

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

Laws and regulations strictly govern our operations relating to: corporate governance, employees, taxation, fees, filing requirements, permitting requirements, environmental affairs, health and safety, waste management, and the manufacture, storage, handling, transportation, use, and sale of chemical products. Certain international jurisdictions impose additional restrictions on our activities, such as currency restrictions, importation and exportation restrictions, and restrictions on labor practices. Our operation and decommissioning of offshore properties are also subject to and affected by various government regulations, including numerous federal and state environmental protection laws and regulations. These laws and regulations are becoming increasingly complex and stringent, and compliance is becoming increasingly expensive. Governmental authorities have the power to enforce compliance with these regulations, and violators are subject to civil and criminal penalties, including civil fines, injunctions, or both. Third parties may also have the right to pursue legal actions to enforce compliance. It is possible that increasingly strict environmental laws, regulations, and enforcement policies could result in substantial costs and liabilities to us and could subject our handling, manufacture, use, reuse, or disposal of substances or pollutants to increased scrutiny.

A large portion of Maritech’s oil and gas 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 has 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. Under limited circumstances, the BOEMRE could require us to suspend or terminate our operations on a federal lease. The BOEMRE 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 BOEMRE 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.

Federal legislation to reduce emissions of greenhouse gases (GHG) has been considered and many states have taken legal measures to reduce GHG emissions. It is not possible at this time to predict whether or when the U.S. Congress will pass climate change legislation, or how any bill approved by Congress may be reconciled with state and regional requirements. EPA has begun to promulgate federal rules under the Clean Air Act including mandatory reporting rules. On September 22, 2009, EPA issued a final rule requiring mandatory reporting of GHG from specified large GHG emission sources in the U.S. beginning in 2011 for emissions occurring in 2010. On November 30, 2010, EPA published a final rule expanding its existing GHG

emissions rule to include onshore and offshore oil and natural gas systems such as those operated by our Maritech subsidiary.

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 related to greenhouse gases and climate change, including incentives to conserve energy or use alternative energy sources, could have a negative impact on our business if such laws, regulations, treaties or international agreements reduce the worldwide demand for oil and natural gas or otherwise result in reduced economic activity generally. In addition, such laws, regulations, treaties, or international agreements could result in increased compliance costs, capital spending requirements, or additional operating restrictions, which may have a negative impact on our business. In addition to potential impacts on our business directly or indirectly resulting from climate-change legislation or regulations, our business also could be negatively affected by climate-change related physical changes or changes in weather patterns.

In addition to increasing our risk of environmental liability, the rigorous enforcement of environmental laws and regulations has accelerated the growth of some of the markets we serve. Decreased regulation and enforcement in the future could materially and adversely affect the demand for the types of services offered by certain of our Offshore Services operations and, therefore, materially and adversely affect our business.

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

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

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

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, 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:

·	government controls and government actions, such as expropriation of assets and changes in legal and regulatory environments;

·	import and export license requirements;

·	political, social, or economic instability;

·	trade restrictions;

·	changes in tariffs and taxes;

·	restrictions on repatriating foreign profits back to the United States;

·	the impact of anti-corruption laws and the risk that actions taken by us or others on our behalf may adversely affect our operations and competitive position in the affected countries; and

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

We and our affiliates operate in countries where governmental corruption has been known to exist. While we and our subsidiaries are committed to conducting business in a legal and ethical manner, there is a risk of violating either the U.S. Foreign Corrupt Practices Act (FCPA) or laws or legislation promulgated pursuant to the 1997 OECD Convention on Combating Bribery of Foreign Public Officials in International Business Transactions or other applicable anti-corruption regulations that generally prohibit the making of improper payments to foreign officials for the purpose of obtaining or keeping business. Violation of these laws could result in monetary penalties against us or our subsidiaries and could damage our reputation and, therefore, our ability to do business.

Foreign governments and agencies often establish permit and regulatory standards different from those in the U.S. If we cannot obtain foreign regulatory approvals, or if we cannot obtain them when we expect, our growth and profitability from international operations could be negatively affected.

Item 1B. Unresolved Staff Comments.

None.

Item 2. Properties.

Our properties consist primarily of our corporate headquarters facility, chemical plants, processing plants, distribution facilities, barge rigs, heavy lift and dive support vessels, well abandonment and decommissioning equipment, oil and gas properties, flow back testing equipment, and compression equipment. The following information describes facilities that we leased or owned as of December 31, 2010. We believe our facilities are adequate for our present needs.

Facilities

Fluids Division

Fluids Division facilities include seven active chemical production plants located in the states of Arkansas, California, Louisiana, and West Virginia, and the country of Finland, having a total production capacity of more than 1.5 million equivalent liquid tons per year. The two California locations 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, which is located just outside the city of El Dorado, in Union County, Arkansas, 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 facility at a nominal price. Under the terms of the lease, we are responsible for all costs incurred related to the facility.

In addition to the production facilities described above, the Fluids Division owns or leases thirty-one service center facilities, twenty in the United States and eleven internationally. The Fluids Division also leases eight offices and twenty-eight terminal locations, fourteen throughout the United States and fourteen internationally.

Offshore Division

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

TETRA Arapaho	Derrick barge with 800-ton capacity crane
TETRA DB-1	Derrick barge with 615-ton capacity crane
Epic Explorer	210-foot dive support vessel with saturation diving system
Epic Seahorse	210-foot dive support vessel

In addition, the Adams Challenge is under chartered lease arrangement by the Offshore Division through 2011. The Adams Challenge is a 280-foot dynamically positioned dive support vessel with a 1,000-foot saturation diving system.

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

Production Enhancement Division

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, and Pennsylvania. In addition, the Production Testing segment has leased facilities in Brazil, Mexico, Libya, Egypt, Bahrain, India, 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, three leased service facilities in California, Mexico, and Argentina, and six sales offices in Oklahoma, Texas, Colorado, New Mexico, Louisiana, and Canada.

Corporate

Our headquarters are located in The Woodlands, Texas, in our 153,000 square foot office building, which is located on 2.635 acres of land. In addition, we own a 20,000 square foot technical facility to service our Fluids Division operations.

Oil and Gas Properties

The following tables show, for the periods indicated, reserves and operating information related to our Maritech subsidiary’s oil and gas interests in developed and undeveloped leases, all of which are located in the U.S. Gulf Coast region. Maritech’s oil and gas operations are a separate segment included within our Offshore Division.

See also “Note R – Supplemental Oil and Gas Disclosures” in the Notes to Consolidated Financial Statements for additional information.

Oil and Gas Reserves

Through our Maritech subsidiary, we employ full-time, experienced reservoir engineers and geologists, who are responsible for determining proved oil and gas reserves in conformance with guidelines established by the SEC. These SEC guidelines were revised effective with the December 31, 2009, information. Reserve estimates were prepared by Maritech engineers, based upon their 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 to Maritech’s system of internal control, whereby key inputs in preparing reserve estimates, such as oil and natural gas pricing data, oil and gas property ownership interest percentages, and data regarding levels of operating, development, and abandonment costs, are reviewed by Maritech personnel outside of the reserve engineering department. Reserve estimates are also reviewed by Maritech’s President, who is also a licensed professional engineer and has overall responsibility for overseeing the preparation of the proved reserve estimates. In addition to the complete analysis and review by Maritech’s internal reservoir engineers, independent petroleum engineers and geologists performed reserve audits of approximately 92.2% of our proved reserve volumes as of December 31, 2010. The use of the term “reserve audit” is intended only to refer to the collective application of the engineering and geologic procedures that the independent petroleum engineering firms were engaged to perform and may be defined and used differently by other companies.

A reserve audit is the process of reviewing certain of the pertinent facts interpreted and assumptions made that have resulted in an estimate of reserves prepared by others and the rendering of an opinion about the appropriateness of the methodologies employed, the adequacy and quality of the data relied upon, the depth and thoroughness of the reserves estimation process, the classification of reserves appropriate to the relevant definitions used, and the reasonableness of the estimated reserve quantities. In performing a reserve audit, an independent petroleum engineering firm meets with our technical staff to collect all necessary geologic, geophysical, engineering, and economic data, and performs an independent reserve evaluation. The reserve audit of our oil and gas reserves involves the rigorous examination of our technical evaluation, as well as the interpretation and extrapolation of well information such as flow rates, reservoir pressure declines, and other technical information and measurements. Maritech’s internal reservoir engineers interpret this data to determine the nature of the reservoir and, ultimately, the quantity of proved oil and gas reserves attributable to the specific property. 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 completion of development projects, 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 development strategy, oil and gas prices, or the related production equipment/facility capacity. Maritech’s independent petroleum engineers also examined the reserve estimates with respect to reserve categorization, using the definitions for proved reserves set forth in Regulation S-X Rule 4-10(a), Staff Accounting Bulletin No. 113, and subsequent SEC staff interpretations and guidance.

Maritech engaged Ryder Scott Company, L.P. and DeGolyer and MacNaughton to perform the reserve audits of a portion of our oil and gas reserves as of December 31, 2010, 2009, and 2008. Both Ryder Scott Company, L.P. and DeGolyer and MacNaughton are established oil and gas reservoir engineering firms providing engineering services worldwide. The staffs of both of these firms, including the personnel assigned to the reserve audits of Maritech’s reserve estimates, include licensed reservoir engineers experienced in performing these services. In the conduct of these reserve audits, these independent petroleum engineering firms did not independently verify the accuracy and completeness of information and data furnished by Maritech with respect to property interests owned, oil and gas production and well tests from examined wells, or historical costs of operation and development; however, they did verify product prices, geological structural and isopach maps, along with reservoir data such as well logs, core analyses, and pressure measurements. If, in the course of the examinations, a matter of question arose regarding the validity or sufficiency of any such information or data, the independent petroleum engineering firms did not accept such information or data until all questions relating thereto were satisfactorily resolved. Furthermore, in instances where decline curve analysis was not adequate in determining proved producing reserves, the independent petroleum engineering firms performed volumetric analysis, which included the analysis of geologic, reservoir, and fluids data. Proved undeveloped reserves were analyzed by volumetric analysis, which takes into consideration recovery factors relative to the geology of the location and similar reservoirs. Where applicable, the independent petroleum engineering firms examined data related to well spacing, including potential drainage from offsetting producing wells, in evaluating proved reserves of undrilled well locations.

The reserve audit performed by Ryder Scott Company, L.P. included certain properties selected by Maritech, including all of our significant properties described above, excluding the Main Pass Area properties, and represented approximately 70.6% of our total proved oil and gas reserve volumes as of December 31, 2010. The reserve audit performed by DeGolyer and MacNaughton included the Main Pass Area properties acquired in December 2007 and represented approximately 21.6% of our total proved oil and gas reserve volumes as of December 31, 2010. Ryder Scott Company, L.P. states in its audit report that they believe that the overall procedures and methodologies utilized by Maritech in preparing their estimates of proved reserves as of December 31, 2010 comply with current SEC regulations and that the overall proved reserves for the reviewed properties as estimated by Maritech were, in the aggregate, reasonable within the established audit tolerance guidelines of 10% as set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers (SPE). DeGolyer and MacNaughton states in its audit report that the information relating to Maritech’s estimated proved reserves of oil, condensate, and natural gas contained in this Annual Report have been prepared in accordance with applicable accounting standards and SEC regulations. There were no limitations imposed or encountered by Maritech or the independent petroleum engineers in the preparation of our estimated reserves or in the performance of the reserve audits by the independent petroleum engineers.

Reserve information is prepared in accordance with guidelines established by the SEC. All of Maritech’s reserves are located in U.S. state and federal offshore waters in the Gulf of Mexico region and onshore Texas and Louisiana. The following table sets forth information with respect to our estimated proved reserves as of December 31, 2010:

Summary of Oil and Gas Reserves as of December 31, 2010
Based on Average Fiscal Year Prices

Reserves category	Oil		NGL		Natural Gas		Total
	(MBbls)		(MBbls)		(MMcf)		(MBOE)
Proved reserves
Developed		5,760		415		24,795		10,307
Undeveloped		1,012		74		790		1,218
Total proved reserves		6,772		489		25,585		11,525

Maritech’s proved undeveloped reserves as of December 31, 2010, represent 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, 2010, have been classified as proved undeveloped for less than five years. Maritech has historically developed its proved undeveloped reserves over a reasonable period of time and anticipates it will do so in the future, utilizing our future operating cash flows, available working capital, and, if necessary, long-term borrowings. All of Maritech’s proved undeveloped reserves as of December 31, 2010, are scheduled to be developed prior to December 31, 2015.

For additional information regarding estimates of oil and gas reserves, including estimates of proved and proved developed reserves, the standardized measure of discounted future net cash flows, and the changes in discounted future net cash flows, see “Note R – Supplemental Oil and Gas Disclosures” in the Notes to Consolidated Financial Statements.

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 have 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.

Production Information

The table below sets forth information related to production, average sales price, and average production cost per unit of oil and gas produced during 2010, 2009, and 2008:

	Year Ended December 31,
	2010		2009		2008
Production:
Natural gas (Mcf)		7,065,258		10,449,366		10,988,840
NGL (Bbls)		132,191		105,479		82,520
Oil (Bbls)		1,360,126		1,219,336		1,384,101

Revenues:
Natural Gas	$	60,416,000	$	87,905,000	$	99,901,000
NGL (Bbls)		6,003,000		3,308,000		5,917,000
Oil		131,422,000		82,978,000		101,362,000

Total	$	197,841,000	$	174,191,000	$	207,180,000

Average realized unit prices and production costs:
Natural gas (per Mcf)	$	8.55	$	8.41	$	9.09
NGL (per Bbl)	$	45.41	$	31.37	$	71.70
Oil (per Bbl)	$	96.62	$	68.05	$	73.23

Production cost per equivalent barrel	$	26.62	$	25.80	$	27.18
Depletion cost per equivalent barrel	$	27.60	$	25.96	$	25.14

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 and recoveries, which were charged or credited to operations during each of the years presented, with approximately $8.2 million and $8.5 million being charged in 2009 and 2008, respectively. 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 2008 production cost per equivalent barrel was also increased due to the impact of hurricanes, which resulted in significant properties being shut-in during the last four months of 2008 and during much of 2009. Depletion cost per equivalent barrel excludes the impact of dry hole costs and property impairments.

Acreage and Productive Wells

At December 31, 2010, our Maritech subsidiary owned interests in the following oil and gas wells and acreage:

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

Louisiana Onshore		12		1		1.1		0.1		900		450		5,133		2,133
Louisiana Offshore		46		10		46.0		10.0		15,819		15,474		6,729		6,317
Texas Onshore		7		-		1.4		-		1,331		450		-		-
Texas Offshore		-		-		-		-		1,440		190		-		-
Federal Offshore		37		54		17.4		18.5		231,281		110,451		59,988		46,611

Total		102		65		65.9		28.6		250,771		127,015		71,850		55,061

The majority of Maritech’s oil and gas properties are held by production. Leases covering undeveloped acreage other than acreage held by production have expiration terms ranging from 2011 through 2015. The following table sets forth the expiration amounts of our gross and net undeveloped acreage as of December 31, 2010:

																					Held by
	2011				2012				2013				2014				2015				Production
State/Area	Gross		Net		Gross		Net		Gross		Net		Gross		Net		Gross		Net		Gross		Net

Louisiana Onshore		265		133		1,223		582		689		250		2,643		1,012		313		156		-		-
Louisiana Offshore		4,417		4,417		-		-		1,282		1,282		207		207		-		-		823		411
Texas Offshore		-		-		-		-		-		-		-		-		-		-		-		-
Federal Offshore		-		-		-		-		19,521		16,641		-		-		6,250		6,250		34,217		23,720

Total		4,682		4,550		1,223		582		21,492		18,173		2,850		1,219		6,563		6,406		35,040		24,131

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

Drilling Activity

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. Maritech participated in the drilling of 10 gross development wells (4.3 net wells) during 2008, two of which were unproductive. As of December 31, 2010, there were no wells in the process of being drilled.

Significant Oil and Gas Properties

The following table provides a brief description as of December 31, 2010, of Maritech’s most significant oil and gas properties which individually represent fields that contain 15% or more of Maritech’s total proved reserves on a barrels-of-oil-equivalent (BOE) basis:

	Net Total
	Proved		Net Proved									Productive
	Reserves		Reserves Mix									Gross		Developed		Undeveloped		Working			Production
	(MBOE)		Oil%			NGL%			Gas%			Wells		Acreage		Acreage		Interest %			Status

Timbalier Bay Area		5,504		62	%		4	%		34	%		52		8,351		5,906		100	%	Producing
Main Pass Area		568		31	%		7	%		62	%		12		66,171		9,989		12%-100	%	Producing
East Cameron 328		1,785		92	%		-			8	%		6		5,000		-		50	%	Producing

Production information for each of these most significant properties during the three years ended December 31, 2010, is as follows:

	Year Ended December 31,
	2010						2009						2008
	Oil		NGL		Natural Gas		Oil		NGL		Natural Gas		Oil		NGL		Natural Gas
	(MBbls)		(MBbls)		(MMcf)		(MBbls)		(MBbls)		(MMcf)		(MBbls)		(MBbls)		(MMcf)
Timbalier Bay Area		555		25		912		526		23		1,289		653		53		3,500
Main Pass Area		87		35		2,362		74		40		5,715		36		2		3,251
East Cameron 328		213		-		132		52		-		48		250		-		149

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

Item 3. Legal Proceedings.

We are named defendants in several lawsuits and respondents in certain governmental proceedings arising in the ordinary course of business. While the outcome of lawsuits or other proceedings against us cannot be predicted with certainty, management does not reasonably expect these matters to have a material adverse impact on the financial statements.

Class Action Lawsuit

Between March 27, 2008, and April 30, 2008, two putative class action complaints were filed in the United States District Court for the Southern District of Texas (Houston Division) against us and certain former officers by certain stockholders on behalf of themselves and other stockholders who purchased our common stock between January 3, 2007, and October 16, 2007. The complaints assert claims under Sections 10(b) and 20(a) of the Securities Exchange Act of 1934, as amended, and Rule 10b-5 promulgated thereunder. On May 8, 2008, the Court consolidated these complaints as In re TETRA Technologies, Inc. Securities Litigation, No. 4:08-cv-0965 (S.D. Tex.). On June 16, 2010, defendants and plaintiff’s counsel reached a settlement agreement whereby all claims against defendants will be released in exchange for a payment of $8.25 million, which was subsequently paid by our insurers. On September 29, 2010, the Court approved the settlement and entered the Order and Final Judgment terminating the class action lawsuit.

Derivative Lawsuit

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. 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. Our board is currently evaluating the best course of action to take in response to the demand letter.

At this stage, it is impossible to predict the outcome of the derivative lawsuit or its impact upon us. We continue to believe that the allegations made in the derivative lawsuit are without merit, and we intend to continue to seek dismissal of and vigorously defend against this lawsuit. While a successful outcome cannot be guaranteed, we do not reasonably expect this lawsuit to have a material adverse effect.

Environmental Proceedings

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

In August of 2009, the Environmental Protection Agency (EPA), pursuant to Sections 308 and 311 of the Clean Water Act (CWA), served a request for information with regard to a release of zinc bromide that occurred from one of our transport barges on the Mississippi River on March 11, 2009. We timely filed a response to that request for information in August 2009. In January 2010, the EPA issued a Notice of Violation and Opportunity to Show Cause related to the spill. We met with the EPA in April 2010 to discuss potential violations and penalties. It has been agreed that no injunctive relief will be required. We have finalized a joint stipulation of settlement with the EPA whereby we are responsible for a penalty of $487,000, which has been submitted to the Department of Justice for approval. We expect to pay this penalty amount during the second quarter of 2011 and expect the full amount to be covered by insurance.

Item 4. [Removed and Reserved.]

PART II

Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters, and Issuer Repurchases of Equity Securities.

Price Range of Common Stock

Our common stock is traded on the New York Stock Exchange under the symbol “TTI.” As of February 25, 2011, there were approximately 11,558 holders of record of the common stock. The following table sets forth the high and low sale prices of the common stock for each calendar quarter in the two years ended December 31, 2010, as reported by the New York Stock Exchange.

	High		Low
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

2009
First Quarter	$	6.28	$	1.94
Second Quarter		10.44		3.01
Third Quarter		10.74		6.79
Fourth Quarter		11.62		8.70

Market Price of Common Stock

The following graph compares the five-year cumulative total returns of our common stock, the Standard & Poor’s 500 Composite Stock Price Index (S&P 500) and the Philadelphia Oil Service Sector Index (PHLX Oil Service Sector), assuming $100 invested in each stock or index on December 31, 2005, all dividends reinvested, and a fiscal year ending December 31. This information shall be deemed furnished, and not filed, in this Form 10-K and shall not be deemed incorporated by reference into any filing under the Securities Act of 1933 or the Securities Exchange Act of 1934 as a result of this furnishing, except to the extent we specifically incorporate it by reference.

Dividend Policy

We have never paid cash dividends on our common stock. We currently intend to retain earnings to finance the growth and development of our business. Any payment of cash dividends in the future will depend upon our financial condition, capital requirements, and earnings, as well as other factors the Board of Directors may deem relevant. We declared a dividend of one Preferred Stock Purchase Right per share of

common stock to holders of record at the close of business on November 6, 1998. See “Note T – Stockholders’ Rights Plan” in the Notes to Consolidated Financial Statements attached hereto for a description of such Rights. See “Management’s Discussion and Analysis of Financial Condition and Results of Operation – Liquidity and Capital Resources” for a discussion of potential restrictions on our ability to pay dividends.

Purchases of Equity Securities by the Issuer and Affiliated Purchasers

In January 2004, our Board of Directors authorized the repurchase of up to $20 million of our common stock. Purchases may be made from time to time in open market transactions at prevailing market prices. The repurchase program may continue until the authorized limit is reached, at which time the Board of Directors may review the option of increasing the authorized limit. During 2004 through 2005, we repurchased 340,950 shares of our common stock pursuant to the repurchase program at a cost of approximately $5.7 million. There were no repurchases made during 2006, 2007, 2008, 2009, or 2010 pursuant to the repurchase program. Shares repurchased during the fourth quarter of 2010 other than pursuant to our repurchase program are as follows:

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

Oct 1 - Oct 31, 2010		2,265	(2)	$	10.40		-	$	14,327,000

Nov 1 - Nov 30, 2010		-			-		-	$	14,327,000

Dec 1 - Dec 31, 2010		118	(2)	$	11.18		-	$	14,327,000

Total		2,383					-	$	14,327,000

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

Item 6. Selected Financial Data.

The following tables set forth our selected consolidated financial data for the years ended December 31, 2010, 2009, 2008, 2007, and 2006. 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 13 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 2006, we completed the acquisitions of the operations of Epic Divers, Inc., Beacon Resources, LLC, and a heavy lift barge. 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. These acquisitions, dispositions, and impairments significantly impact the comparison of our financial statements for 2010 to earlier years.

	Year Ended December 31,
	2010			2009			2008			2007			2006
	(In Thousands, Except Per Share Amounts)
Income Statement Data
Revenues	$	872,678		$	878,877		$	1,009,065		$	982,483		$	767,795
Gross profit		43,707			213,097			152,001			116,383			252,804
Operating income (loss)		(56,425	)		112,265			(21	)		16,512			160,800
Interest expense		(17,528	)		(13,207	)		(17,557	)		(17,886	)		(13,637	)
Interest income		224			417			779			731			348
Other income (expense), net		(64	)		5,895			12,884			2,805			4,858
Income (loss) before discontinued
operations		(43,325	)		68,807			(9,655	)		1,221			99,880
Net income (loss)	$	(43,718	)	$	68,804		$	(12,136	)	$	28,771		$	101,878

Income (loss) per share, before
discontinued operations (1)	$	(0.57	)	$	0.92		$	(0.13	)	$	0.02		$	1.39
Average shares (1)		75,539			75,045			74,519			73,573			71,631

Income (loss) per diluted share,
before discontinued operations (1)	$	(0.57	)	$	0.91		$	(0.13	)	$	0.02		$	1.33
Average diluted shares (1)		75,539	(2)		75,722	(3)		74,519	(2)		75,921	(4)		74,824

(1)	Net income (loss) per share and average share outstanding information reflects the retroactive impact of a 2-for-1 stock split as of May 15, 2006. The stock split was effected in the form of a stock dividend as of the record date.
(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.

	December 31,
	2010		2009		2008		2007		2006
	(In Thousands)
Balance Sheet Data
Working capital	$	198,106	$	148,343	$	222,832	$	181,441	$	262,572
Total assets		1,299,628		1,347,599		1,412,624		1,295,536		1,086,190
Long-term debt		305,035		310,132		406,840		358,024		336,381
Decommissioning and other
long-term liabilities		261,438		218,498		277,482		247,543		167,671
Stockholders' equity		516,323		576,494		515,821		447,919		420,380

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

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

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

Business Overview

Marked by the significant environmental impact in the U.S. Gulf of Mexico as a result of the Macondo oil spill, the year of 2010 ushered in a new regulatory climate for offshore energy operators. Despite the October 2010 lifting of a federally mandated deepwater drilling moratorium, offshore oil and gas industry regulations, as administered by the newly formed BOEMRE, have resulted in delays and added regulatory costs to offshore projects. In addition, newly enacted regulations have also imposed requirements on operators, particularly affecting the abandonment and decommissioning of offshore oil and gas wells and production platforms. The new regulatory environment following the Macondo incident significantly affected our operations during 2010 and will continue to affect certain of our businesses going forward. Our Fluids Division revenues were negatively affected during 2010 by the decreased activity caused by the moratorium and the ensuing permitting delays that continue to hamper the timing of offshore drilling projects by its customers. Until the first deepwater drilling permit was approved by BOEMRE on February 28, 2011, no permits to drill in the deepwater U.S. Gulf of Mexico had been issued since the Macondo oil spill. Our Gulf of Mexico Fluids Division activity will not fully recover until the pace of permitting reaches the pre-Macondo spill level. Our Offshore Services segment operations were also affected by project delays on its offshore operations during 2010, resulting from plug and abandonment permitting delays. Going forward, however, the demand for abandonment and decommissioning services on offshore assets is expected to increase, perhaps significantly, as a result of new regulations. In particular, the NTL 2010-G05, or “Idle Iron Guidance,” issued by the BOEMRE in September 2010, will require many operators to accelerate decommissioning plans. Our Maritech segment operations were also affected, as the expected increased demand for abandonment and decommissioning services as a result of the new regulations will increase Maritech’s cost for these activities. The increased cost estimates for future Maritech abandonment and decommissioning work, along with the costs incurred on the significant amount of work performed during 2010, contributed significantly to Maritech recording approximately $54.0 million of charges for excess decommissioning costs during the year. In addition, the increased abandonment and decommissioning cost estimates also contributed to Maritech recording a total of $63.8 million of oil and gas property impairments during the year. These charges were the most significant factors in our reporting a $43.7 million net loss for 2010.

Other than the impact from increased regulation of offshore oil and gas operations, our businesses also continued to be affected by other factors. Our Production Testing segment reported improved activity levels during 2010, as demand for U.S. onshore services increased during the year. Maritech revenue levels were enhanced primarily as a result of strong realized oil and natural gas commodity pricing as a result of hedge derivative contracts. However, Maritech’s natural gas hedge derivative contracts expired at the end of

2010 and its remaining oil hedge derivative contracts are at prices below current market prices. The current levels of natural gas prices are expected to significantly reduce Maritech’s revenues and profitability going forward compared to 2010. Lower natural gas prices have also continued to affect Compressco’s operations, as revenue and profitability decreased compared to the prior year. While overall Fluids Division revenues were increased during 2010 as a result of production and sales of product from the El Dorado, Arkansas, calcium chloride manufacturing plant, profitability from the plant has been hampered by constrained production and resulting higher product costs per unit of production. Efforts to improve the plant’s performance are ongoing, but are not expected to impact its profitability until mid-2011. Consolidated results were also affected by impairments of other long-lived assets, including the Lake Charles, Louisiana, calcium chloride manufacturing plant and certain Offshore Services assets, including one of its dive support vessels. Results were also affected by increased interest expense, as a significant amount of interest was capitalized during 2009 to long-term construction projects.

We continue to maintain a strong balance sheet, and recent modifications to our long-term debt borrowings have improved our liquidity going forward. Operating cash flows during 2010 totaled $153.3 million, which was a 43.7% decrease compared to 2009. Operating cash flows during 2010 reflect the decreased activity level of our Offshore Services segment compared to its record activity levels during 2009. A large portion of our operating cash flows during the past two years has been dedicated to the extinguishment of Maritech decommissioning liabilities for its offshore oil and gas properties, and this focus will continue in 2011. As discussed above, the estimated cost of future decommissioning work has increased significantly, partly as a result of increased regulations. Capital expenditures during 2010 totaled $107.7 million, all of which were funded from operating cash flows and existing cash balances. We continue to monitor our capital expenditure levels closely. In particular, due to a desire to conserve and reallocate capital, we have begun to decrease our investment in Maritech by suspending our search for oil and gas property acquisitions and decreasing our development activities. In addition, we are exploring strategic alternatives to our ownership of Maritech and its oil and gas properties and we are reviewing opportunities to sell Maritech oil and gas property packages to industry participants and other third parties. As part of this overall effort, a portion of Maritech’s properties was sold in February 2011.

During the fourth quarter of 2010, we sold $90 million of Series 2010 Senior Notes, using the proceeds from these borrowings to help retire $91.8 million of Series 2004 Senior Notes which were scheduled to mature in 2011. Also during the fourth quarter of 2010, we amended our bank revolving credit facility, decreasing the facility to $278 million and extending its scheduled maturity to 2015. We continue to carry no outstanding balance on our bank credit facility as of March 1, 2011. With our strong cash position and borrowing capacity, we continue to review strategic acquisitions and growth opportunities for our businesses.

Future demand for our products and services depends primarily on activity in the oil and gas exploration and production industry, particularly including the level of expenditures for the exploration and production of oil and gas reserves and for the plugging and decommissioning of abandoned oil and gas properties. U.S. onshore domestic oil and gas industry expenditures, as indicated by rig count statistics and other measures, have recently increased to late 2008 levels. Industry expenditure levels had been in decline during the past two years in response to the general uncertainty regarding availability of capital resources during the recent global recession and due to oil and natural gas price volatility. U.S. offshore drilling activity, which also began increasing during the first half of 2010, was then significantly reduced as a result of the offshore drilling moratorium which followed the Macondo oil spill. Post-moratorium offshore rig counts have recently begun to increase, however, activity levels are still far below pre-moratorium levels. The growth of certain of our businesses remains hampered by the current pricing levels of natural gas, particularly as compared to crude oil. However, we still believe that there are growth opportunities for our products and services in the U.S. and international markets, supported primarily by:

·	increased regulatory requirements governing the abandonment and decommissioning work on aging offshore platforms and wells in the Gulf of Mexico;

·	increases in technologically-driven deepwater oil and gas well completions in the Gulf of Mexico;

·	applications for many of our products and services in the exploitation and development of shale gas reservoirs; and

·	increasing international oil and gas exploration and development activities.

Our Fluids Division generates revenues and cash flows by selling clear brine completion fluids (CBFs) and providing filtration, water transfer, and associated products and technical engineering services to U.S. and international exploration and production companies. In addition, the Fluids Division also provides liquid and dry calcium chloride products manufactured at its production facilities or purchased from third-party suppliers to a variety of markets outside the energy industry. Fluids Division revenues increased 22.5% during 2010 compared to the prior year, due primarily to the commencement of operation of our El Dorado, Arkansas, calcium chloride plant. The El Dorado plant began initial production in late 2009 and produces liquid and dry (flake) calcium chloride as part of our manufactured products operation. In addition, the Fluids Division’s completion products and services business generated increased revenues, reflecting the increasing U.S. onshore industry activity and demand for CBF products during the year. This increase occurred despite the negative impact of the offshore drilling moratorium, which significantly decreased offshore activity during much of 2010. We estimate that the impact of the moratorium negatively affected our Fluids Division revenues by approximately $20 to $22 million during the last half of 2010. The overall outlook for the Division’s completion services business continues to be dependent on the level of oil and gas drilling activity, particularly in the Gulf of Mexico, which has remained flat or has decreased during the past several years, due largely to the maturity of the producing fields in the heavily developed portions of the Gulf of Mexico. However, we anticipate continued increases in industry spending in 2011, particularly given the current levels of crude oil prices. Also, the Division is attempting to capitalize on the current industry trend toward drilling deepwater wells that generally require greater volumes of more expensive CBFs. In addition, we continue to pursue specific international opportunities where industry spending levels from major energy customers and national oil companies have generally been more stable.

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 services such as plugging and abandonment, workover, and wireline services, (2) decommissioning and certain construction services, including offshore platform removal and hurricane damage remediation, and (3) diving services involving conventional and saturated air diving and the operation of several dive support vessels. The services provided by the Offshore Services segment are marketed primarily in the Gulf Coast region of the U.S., including offshore, inland waters, and in certain onshore locations. Gulf of Mexico platform decommissioning and well abandonment activity levels are driven primarily by BOEMRE 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. Recent regulations enacted 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, perhaps significantly, 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, many oil and gas operators, including Maritech, are accelerating their plans to abandon and decommission their offshore wells and platforms. Offshore Services revenues decreased by 22.5% during 2010 compared to the revenue level experienced during 2009, when increased utilization by the segment’s diving, abandonment, heavy lift, and cutting services businesses as a result of the high demand following the 2005 and 2008 hurricanes, resulted in record activity levels. For the reasons described, the Offshore Services segment expects strong demand for its services to continue, however, the segment anticipates its overall activity in 2011 will again be less than the record levels experienced during 2009.

Through Maritech, the Offshore Division acquires, manages, explores, and develops oil and gas properties in the offshore, inland water, and onshore region of the Gulf of Mexico and generates revenues and cash flows from the sale of the associated oil and natural gas production volumes. Maritech periodically acquires properties for their exploration and development potential. Maritech’s revenues during 2010 increased by 13.3% compared to 2009 due to increased realized oil and gas commodity prices and despite decreased production volumes during the year. The increase in realized prices was primarily due to the impact of commodity hedge derivative contracts. However, the derivative contracts with the most favorable terms compared to current market prices expired at the end of 2010. Maritech continues to perform a significant amount of plugging, abandonment, and decommissioning efforts on its offshore oil and gas properties, particularly as part of its strategy to reduce its risk from hurricanes and in response to the increased cost of windstorm insurance coverage. Maritech has historically grown its operations by acquiring and developing oil and gas property interests located in the offshore, inland waters, and onshore U.S. Gulf Coast region. However, due to a desire to conserve and reallocate capital, we have begun to decrease our investment in Maritech by suspending our search for oil and gas property acquisitions and decreasing our

development activities. In addition, we are exploring strategic alternatives to our ownership of Maritech and its oil and gas properties and we are reviewing opportunities to sell Maritech oil and gas property packages to industry participants and other third parties. As part of this overall effort, in late February 2011, Maritech sold a group of properties that accounted for approximately 11.4% of its proved reserves as of December 31, 2010.

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 flow back pressure and volume testing of onshore and offshore oil and gas wells and by providing reservoir data necessary to enable operators to 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 33.8% in 2010 compared to 2009, primarily due to increased demand in the United States. Given the continuing increase in drilling activity, we anticipate that demand for our production testing services will continue to increase in 2011 compared to 2010.

Compressco generates revenues and cash flows by performing wellhead compression-based production enhancement services throughout most of the onshore producing regions of the United States, as well as basins in Canada, Mexico, 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 decreased 10.5% in 2010 as compared to 2009, due to decreased demand for production enhancement services as a result of lower natural gas prices as well as from increased competition. Given the recent increases in oil and natural gas prices, we anticipate Compressco’s 2011 revenues and cash flows will increase modestly compared to 2010, particularly as we also continue to seek new U.S. and international markets for Compressco operations.

Critical Accounting Policies and Estimates

In preparing our consolidated financial statements, we make assumptions, estimates, and judgments that affect the amounts reported. 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. Our estimates are based on historical experience and on future expectations which we believe are reasonable. The fair values of large portions of our total assets and liabilities are measured using significant unobservable inputs. The combination of these factors forms the basis for our judgments made about the carrying values of assets and liabilities that are not readily apparent from other sources. These judgments and estimates may change as new events occur, as new information is acquired, and as changes in our operating environment are encountered. Actual results are likely to differ from our current estimates, and those differences may be material. The following critical accounting policies reflect the most significant judgments and estimates used in the preparation of our financial statements.

Impairment of Long-Lived Assets

The determination of impairment of long-lived assets is conducted periodically whenever indicators of impairment are present. If such indicators are present, the determination of the amount of impairment is based on our judgments as to the future operating cash flows to be generated from these assets throughout their estimated useful lives. If an impairment of a long-lived asset is warranted, we estimate the fair value of the asset based on a present value of these cash flows or the value that could be realized from disposing of the asset in a transaction between market participants. The oil and gas industry is cyclical, and our estimates of the amount of future cash flows, the period over which these estimated future cash flows will be generated, as well as the fair value of an impaired asset, are imprecise. Our failure to accurately estimate these future operating cash flows or fair values could result in certain long-lived assets being overstated, which could result in impairment charges in periods subsequent to the time in which the impairment indicators were first present. Alternatively, if our estimates of future operating cash flows or fair values are understated, impairments might be recognized unnecessarily or in excess of the appropriate amounts. Our estimates of

operating cash flows and fair values for assets impaired have generally been accurate. Although the majority of our impairments of long-lived assets have typically related to oil and gas properties (see separate discussion below), during 2010, we recorded other long-lived asset impairments of $25.1 million. Given the current volatile 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.

Impairment of Goodwill

The impairment of goodwill is also assessed whenever impairment indicators are present, but not less than once annually. The assessment for goodwill impairment is performed for each reporting unit and consists of a comparison of the carrying amount of each reporting unit to our estimation of the fair value of that reporting unit. 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 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. However, given the current volatile economic environment, the likelihood of additional material impairments of goodwill in future periods is higher.

As of December 31, 2010, our Offshore Services, Production Testing, and Compressco reporting units reflect goodwill in the amounts of $3.8 million, $23.0 million, and $72.2 million, respectively. The fair values of our Offshore Services and Production Testing reporting units significantly exceed their carrying values. However, because the estimated fair value of our Compressco reporting unit currently exceeds its carrying value by approximately 13.3%, there is a reasonable possibility that Compressco’s goodwill may be impaired in a future period and the amount of such impairment may be material. Specific uncertainties affecting the estimated fair value of our Compressco reporting unit include the prices received by Compressco’s customers for natural gas production, the rate of future growth of Compressco’s business, and the need and timing of the full resumption of the fabrication of new Compressco compressor units. In addition, Compressco’s Mexico operations may continue to be disrupted by security issues in that country. The demand for Compressco’s wellhead compression services continues to be decreased compared to early 2008 levels and negatively affected by the current economic environment. A decrease in natural gas prices could have a further negative effect on the fair value of our Compressco reporting unit.

Oil and Gas Properties

Maritech accounts for its interests in oil and gas properties using the successful efforts method, whereby costs incurred to drill and equip development wells, including unsuccessful development wells, are capitalized, and costs related to unsuccessful exploratory wells are expensed as incurred. All capitalized costs are accumulated and recorded separately for each field and are depleted on a unit-of-production basis, based on the estimated remaining proved oil and gas reserves of each field. Oil and gas properties are assessed for impairment in value on an individual field basis, whenever indicators become evident, with any impairment charged to expense. Accordingly, Maritech’s results of operations may be more volatile compared to those oil and gas exploration and production companies who account for their operations using the full-cost method. Due to the impact of changing oil and gas prices, results of drilling and development efforts, and increased estimated decommissioning liabilities (see discussion below), Maritech has recorded oil and gas property impairments and dry hole costs, and during 2008, 2009, and 2010 these impairment charges were significant. Maritech periodically purchases oil and gas properties and assumes the associated well abandonment and decommissioning liabilities. Any significant differences in the actual amounts of oil and gas production cash flows produced or decommissioning costs incurred compared to the estimated amounts recorded will affect our anticipated profitability. Given the volatility of oil and natural gas prices, we are more likely to record additional significant impairments in future periods.

The process of estimating oil and gas reserves is complex, requiring significant decisions and assumptions in the evaluation of available geological, geophysical, engineering, and economic data for each reservoir. As a result, these estimates are inherently imprecise. Actual future production, cash flows, development expenditures, operating and abandonment expenses, and quantities of recoverable oil and gas reserves may vary substantially from those initially estimated by Maritech. Any significant variance in these assumptions could result in significant upward or downward revisions of previous estimates, as reflected in our annual disclosure of the estimated quantity and value of our proved reserves. In previous years, we have reflected revisions to our previous estimates of reserve quantities and values, and in some years, these revisions have been significant. It is possible we will have additional revisions to our estimated quantities of proved reserves in future periods.

Decommissioning Liabilities

Maritech’s decommissioning liabilities are established based on what it estimates a third party would charge to plug and abandon the wells, decommission the pipelines and platforms, and clear the sites. These well abandonment and decommissioning liabilities (referred to as decommissioning liabilities) are recorded net of amounts allocable to joint interest owners, anticipated insurance recoveries, 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 saves us the profit margin that a third party would charge for such services. When these services are performed by an affiliated company, all recorded intercompany revenues are eliminated in the consolidated financial statements. Any difference between our own internal costs to settle the decommissioning liability and the recorded liability is recognized in the period in which we perform the work. The recorded decommissioning liability associated with a specific property is fully extinguished when the property is completely abandoned. Once a Maritech well abandonment and decommissioning project is performed, any remaining decommissioning liability in excess of the actual cost of the work performed is recorded as a gain and included in earnings in the period in which the project is completed. Conversely, actual costs in excess of the decommissioning liability are charged against earnings in the period in which the work is performed.

We review the adequacy of our decommissioning liabilities whenever indicators suggest that either the amount or timing of the estimated cash flows underlying the liabilities have changed materially. The estimated timing of these cash flows is determined by the productive life of the associated oil and gas property, which is based on the property’s oil and gas reserve estimates. 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 issuance by the BOEMRE of NTL 2010-G05 “Idle Iron Guidance” regulations and due to other factors, Maritech significantly adjusted its decommissioning liabilities as of December 31, 2010. Largely as a result of these adjustments, as well as a result of the cost of significant abandonment and decommissioning work performed during the year, Maritech recorded approximately $30.2 million of increased excess decommissioning expense 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 the prior year. 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. During 2008, 2009, and 2010, the amount of charges to earnings as a result of costs of work performed being in excess of our estimated liabilities has been significant. To the extent our decommissioning liabilities are understated, additional charges to earnings may be required in future periods.

Revenue Recognition

We generate revenue on certain well abandonment and decommissioning projects under contracts which are typically of short duration and that provide for either lump-sum turnkey charges or specific time,

material, and equipment charges, which are billed in accordance with the terms of such contracts. With regard to turnkey 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 turnkey 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.

Bad Debt Reserves

Reserves for bad debts are calculated 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.

Income Taxes

We provide for income taxes by taking into account the differences between the financial statement treatment and tax treatment of certain transactions. Deferred tax assets and liabilities are recognized for the anticipated future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis amounts. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect of a change in tax rates is recognized as income or expense in the period that includes the enactment date. This calculation requires us to make certain estimates about our future operations, and many of these estimates of future operations may be imprecise. Changes in state, federal, and foreign tax laws, as well as changes in our financial condition, could affect these estimates. In addition, we consider many factors when evaluating and estimating income tax uncertainties. These factors include an evaluation of the technical merits of the tax position as well as the amounts and probabilities of the outcomes that could be realized upon ultimate settlement. The actual resolution of those uncertainties will inevitably differ from those estimates, and such differences may be material to the financial statements. Our estimates and judgments associated with our calculations of income taxes have been reasonable in the past, however, the possibility for changes in the tax laws, as well as the current economic uncertainty, could affect the accuracy of our income tax estimates in future periods.

Acquisition Purchase Price Allocations

We account for acquisitions of businesses using the purchase method, which requires the allocation of the purchase price based on the fair values of the assets and liabilities acquired. We estimate the fair values of the assets and liabilities acquired using accepted valuation methods, and, in many cases, such estimates are based on our judgments as to the future operating cash flows expected to be generated from the acquired assets throughout their estimated useful lives. We have completed several acquisitions during the past several years and have accounted for the various assets (including intangible assets) and liabilities acquired based on our estimate of fair values. Goodwill represents the excess of acquisition purchase price over the estimated fair values of the net assets acquired. Our estimates and judgments of the fair value of

acquired businesses are imprecise, and the use of inaccurate fair value estimates could result in the improper allocation of the acquisition purchase price to acquired assets and liabilities, which could result in asset impairments, 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.

Stock-Based Compensation

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, there have not been significant revisions made in these estimates to date.

Results of Operations

The following data should be read in conjunction with the Consolidated Financial Statements and the associated Notes contained elsewhere in this report.

2010 Compared to 2009

Consolidated Comparisons

	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 (benefit) 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	$	(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 interest expense increased primarily due to a decrease in capitalized interest compared to the prior year period following the completion of significant construction projects, including the El Dorado, Arkansas, calcium chloride facility and our corporate headquarters building.

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.

We recorded a consolidated income tax benefit of $30.5 million during 2010 due to our net loss for the period. This compares to a consolidated tax provision of $36.6 million during 2009.

Divisional Comparisons

Fluids Division

	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 current 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 are 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; however, there is still considerable effort required, and significant improvement in plant performance is not expected until mid 2011. 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.

Offshore Division

Offshore Services Segment

	Year Ended December 31,						Period to Period Change
	2010			2009			2010 vs 2009			% Change
	(In Thousands, Except Percentages)
Revenues	$	274,200		$	353,798		$	(79,598	)		-22.5	%
Gross profit		21,695			94,488			(72,793	)		-77.0	%
Gross profit as a percentage of revenue		7.9	%		26.7	%
General and administrative expense		17,048			13,891			3,157			22.7	%
General and administrative expense as a percentage of revenue		6.2	%		3.9	%
Interest (income) expense, net		100			(161	)		261
Other (income) expense, net		(117	)		2,364			(2,481	)
Income before taxes and discontinued operations	$	4,664		$	78,394		$	(73,730	)		-94.1	%
Income before taxes and discontinued operations as a percentage of revenue		1.7	%		22.2	%

The decrease in revenues for the Offshore Services segment was due to decreased activity compared to the record levels experienced in the prior year period. The decreased activity resulted in reduced utilization of much of the segment’s fleet as compared to the prior year period, without taking into effect the addition of a leased dive support vessel beginning in June 2009. In addition to the decreased activity for certain of the segment’s operations, overall pricing levels were lower during 2010 compared to the prior year. During 2010, the BOEMRE issued NTL 2010-G05, the “Idle Iron Guidance” regulations, which require that permanent plugs be set in nearly 3,500 nonproducing wells in the U.S. Gulf of Mexico. In addition, the new regulation requires approximately 650 oil and gas production platforms to be dismantled if they are not being used. We anticipate that these new requirements will increase, perhaps significantly, the future demand for well abandonment and decommissioning services to be performed by our Offshore Services segment. In addition, we continue to capitalize on the remaining demand for well abandonment and decommissioning services for the remaining offshore properties that were damaged or destroyed by hurricanes. Still, we anticipate that levels of Offshore Services segment activity in 2011 will again be lower than the record activity levels we experienced during most of 2009. A total of $62.5 million of the segment’s revenues during 2010 were performed for Maritech, compared with $45.6 million during the prior year. These intersegment revenues are eliminated in the consolidated statements of operations.

The decrease in gross profit was primarily due to the decreased activity and pricing, but also included the impact of decreased utilization and efficiencies compared to the prior year period. In addition, during the fourth quarter of 2010, the Offshore Services segment recorded an impairment of $15.3 million to the net carrying value of the Epic Diver, a dive support vessel owned by our Epic Diving & Marine Services subsidiary. We determined that the vessel is no longer strategic to the segment’s plan to serve its markets going forward. In addition, the segment recorded additional impairments of approximately $2.4 million during 2010, associated with other non-strategic assets. As a result of the NTL 2010-G05 regulations discussed above, we anticipate that activity and profitability levels of the Offshore Services segment will increase compared to 2010. However, we expect 2011 profitability to be lower than the record high profitability levels of 2009, due to the expected decrease in utilization rates and pricing.

The decrease in income before taxes was primarily due to the decreased gross profit discussed above. Increased general and administrative expenses include the impact of increased salaries and personnel-related costs compared to the prior year. Partially offsetting these decreases, other expense during 2009 included a charge for a $2.0 million legal settlement.

Maritech Segment

	Year Ended December 31,						Period to Period Change
	2010			2009			2010 vs 2009			% Change
	(In Thousands, Except Percentages)
Revenues	$	200,559		$	177,039		$	23,520			13.3	%
Gross profit (loss)		(65,055	)		20,655			(85,710	)		-415.0	%
Gross profit as a percentage of revenue		-32.4	%		11.7	%
General and administrative expense		4,323			5,911			(1,588	)		-26.9	%
General and administrative expense as a percentage of revenue		2.2	%		3.3	%
Interest (income) expense, net		(107	)		17			(124	)
Other (income) expense, net		(152	)		(7,285	)		7,133
Income before taxes and discontinued operations	$	(69,119	)	$	22,012		$	(91,131	)		-414.0	%
Income before taxes and discontinued operations as a percentage of revenue		-34.5	%		12.4	%

Approximately $41.1 million of Maritech revenues was due to increased realized commodity prices during 2010 compared to the prior year. Maritech has hedged a portion of its expected future oil production levels by entering into commodity derivative hedge contracts, with certain contracts extending through 2011, although contracts having a positive impact compared to market prices expired at the end of 2010. Including the impact of its commodity derivative hedge contracts, Maritech reflected average realized oil and natural gas prices during 2010 of $96.63/barrel and $8.47/MMBtu, respectively, each of which were significantly higher than market prices of oil and natural gas during the period. Much of the favorable hedged oil pricing impact was as a result of 2010 oil swaps that were liquidated during 2009. Partially offsetting the increased realized prices, overall production volumes decreased during the current year period, resulting in $18.1 million of decreased revenues. This decrease was attributed to natural gas production interruptions and normal production declines during the period. A portion of Maritech’s Main Pass area production is currently shut-in due to third-party pipeline issues and the lack of available transportation for production. Although total oil production increased compared to the prior year period, Maritech’s interest in the East Cameron 328 field will continue to have a portion of its production shut-in until Maritech completes the redrilling of certain wells from a newly installed platform to replace the platform that was toppled during Hurricane Ike in 2008. Recent successful development efforts at Maritech’s Timbalier Bay field are expected to result in increased production going forward. However, since late 2008, as a result of our efforts to conserve capital and decrease our investment in Maritech, we have significantly reduced overall acquisition and development activities, and the level of such activity is expected to continue to be decreased going forward. In February 2011, Maritech sold a portion of its oil and gas properties, which will also result in decreased revenues going forward. In addition, Maritech reported $0.1 million of decreased processing revenue during 2010.

Despite the increased revenues, Maritech’s gross profit for 2010 decreased significantly compared to the prior year due to several factors. During 2009, Maritech recorded $42.2 million of additional credits to operating expense for the collection of insurance settlement proceeds, primarily from the $40 million insurance litigation settlement in December 2009 regarding certain claims associated with damage from

Hurricanes Katrina and Rita. In addition, partly due to the issuance by the BOEMRE of NTL 2010-G05 “Idle Iron Guidance” regulations in the U.S. Gulf of Mexico, Maritech significantly adjusted its decommissioning liabilities as of December 31, 2010. Largely as a result of these adjustments, as well as a result of the cost of significant abandonment and decommissioning work performed during the year, Maritech recorded approximately $30.2 million of increased excess decommissioning expense 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, along with the decreased fair value of certain oil and gas properties, contributed significantly to Maritech recording approximately $52.4 million of increased oil and gas property impairments during 2010 compared to the prior year. Partially offsetting these increased operating expenses were approximately $3.1 million of decreased insurance expense and $5.9 million of decreased repair expense, primarily due to the amount of repairs performed during 2009 associated with Hurricane Ike.

Maritech’s pretax profitability decreased during 2010 compared to 2009, primarily due to the significant decrease in gross profit discussed above. In addition, Maritech other income decreased due to gains that were recorded during 2009 on sales of oil and gas properties. Partially offsetting these decreases, Maritech general and administrative expenses decreased, primarily due to decreased bad debt expense.

Production Enhancement Division

Beginning in the fourth quarter of 2010, certain Mexican production enhancement operations were reclassified from our Production Testing segment to our Compressco segment. Segment information for prior years has been revised to conform to the 2010 presentation.

Production Testing Segment

	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, which we anticipate will continue in 2011. 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.

Despite the increase in gross profit, income before taxes decreased primarily due to a $5.8 million gain from a legal settlement which was recorded in the prior year. This decrease in other income plus increased administrative costs was partially offset by the increased gross profit during the current year.

Compressco Segment

	Year Ended December 31,						Period to Period Change
	2010			2009			2010 vs 2009			% Change
	(In Thousands, Except Percentages)
Revenues	$	81,413		$	90,965		$	(9,552	)		-10.5	%
Gross profit		28,672			35,985			(7,313	)		-20.3	%
Gross profit as a percentage of revenue		35.2	%		39.6	%
General and administrative expense		11,008			10,518			490			4.7	%
General and administrative expense as a percentage of revenue		13.5	%		11.6	%
Interest (income) expense, net		35			-			35
Other (income) expense, net		116			(82	)		198
Income before taxes and discontinued operations	$	17,513		$	25,549		$	(8,036	)		-31.5	%
Income before taxes and discontinued operations as a percentage of revenue		21.5	%		28.1	%

The decrease in Compressco revenues was due to $5.6 million of decreased U.S. compression service revenues, primarily reflecting the reduced U.S. demand for wellhead compression services during 2010. We believe the reduced demand was primarily due to continuing lower natural gas prices compared to prices during previous years, as well as due to the impact of increased competition. Compressco’s domestic activity levels have begun to increase during the past three quarters, and fourth quarter of 2010 revenue levels were increased compared to the prior year period. Over the past year, many domestic oil and gas operators, including certain Compressco customers, have responded to the lower gas prices by reducing operating expenses. In addition, international service revenues also decreased by $3.1 million, primarily due to decreased activity in Mexico. Going forward, we anticipate that Compressco’s international revenues will continue to be negatively affected by conditions in Mexico, where customer budgetary issues and security disruptions have negatively impacted activity levels during 2010. Revenues from sales of compressor units and parts during 2010 decreased $0.8 million compared to the prior year. Compressco has reduced the fabrication of new compressor units until demand for its production enhancement services increases and inventories of available units are reduced.

The decrease in gross profit was due to decreased demand domestically for Compressco’s products and services, as well as due to the above described decreased activity in Mexico. Domestic profitability during 2010 was also affected by decreased pricing and certain non-recurring operating charges during the year. Gross profit as a percentage of revenues also decreased due to the decreased activity, despite Compressco’s efforts to improve operating efficiencies.

The decrease in income before taxes was primarily due to the decrease in gross profit and, to a lesser extent, from increased administrative expenses, which were primarily due to increased salary and personnel-related expenses.

Corporate Overhead

	Year Ended December 31,						Period to Period Change
	2010			2009			2010 vs 2009			% Change
	(In Thousands, Except Percentages)
Gross profit (primarily depreciation expense)	$	(3,238	)	$	(3,019	)	$	(219	)		7.3	%
General and administrative expense		34,576			40,173			(5,597	)		-13.9	%
Interest expense, net		17,112			12,969			4,143			31.9	%
Other expense, net		3,345			1,566			1,779			113.6	%
Income (loss) before taxes and discontinued operations	$	(58,271	)	$	(57,727	)	$	(544	)		-0.9	%

million of decreased office expenses, $0.4 million of decreased insurance and taxes expenses, $0.1 million of decreased professional fee expenses, and approximately $0.4 million of decreased general expenses. These decreases were partially offset by approximately $0.2 million of increased investor relations expenses. Largely offsetting this decrease, corporate interest expense increased due to a decrease in the amount of interest capitalized on construction projects during the period, particularly following the completion of the construction of the El Dorado, Arkansas, calcium chloride facility. In addition, other expense increased, despite a $1.6 million decrease in hedge ineffectiveness losses, due to the charge for approximately $2.8 million in prepayment premium on the repayment of the 2004 Senior Notes.

2009 Compared to 2008

Consolidated Comparisons

	Year Ended December 31,						Period to Period Change
	2009			2008			2009 vs 2008			% Change
	(In Thousands, Except Percentages)
Revenues	$	878,877		$	1,009,065		$	(130,188	)		-12.9	%
Gross profit		213,097			152,001			61,096			40.2	%
Gross profit as a percentage of revenue		24.2	%		15.1	%
General and administrative expense		100,832			104,949			(4,117	)		-3.9	%
General and administrative expense as a percentage of revenue		11.5	%		10.4	%
Impairment of goodwill		-			47,073			(47,073	)		-100.0	%
Interest expense, net		12,790			16,778			(3,988	)		-23.8	%
Other (income) expense, net		(5,895	)		(12,884	)		6,989			-54.2	%
Income (loss) before taxes and discontinued operations		105,370			(3,915	)		109,285			-2791.4	%
Income (loss) before taxes and discontinued operations as a percentage of revenue		12.0	%		-0.4	%
Provision for income taxes		36,563			5,740			30,823			537.0	%
Income before discontinued operations		68,807			(9,655	)		78,462			-812.7	%
Loss from discontinued operations, net of taxes		(3	)		(2,481	)		2,478			99.9	%
Net income	$	68,804		$	(12,136	)	$	80,940			-666.9	%

Consolidated revenues decreased despite a significant increase in our Offshore Services segment revenues. This was due to decreased revenues by each of the other reporting segments, which reflected the impact of the general decline in oil and gas industry activity during 2009. This decrease was primarily due to the global economic environment and specifically due to lower oil and natural gas commodity prices during 2009 compared to 2008. Offshore Services revenues increased by $47.4 million due to increased demand for diving, platform decommissioning, cutting, and abandonment services during 2009, following the damage to offshore platforms from hurricanes in the Gulf of Mexico in prior years and due to the risk of damage from future storms. This increase was more than offset by significantly decreased revenue from our Fluids Division, which experienced decreased demand for its products, primarily due to decreased oil and gas completion activity. In addition, our Production Testing, Maritech, and Compressco segments also reported decreased revenues, generally due to decreased demand resulting from lower oil and gas commodity pricing. Despite these decreases, overall gross profit increased during 2009 compared to 2008, primarily due to the unprecedented favorable performance of our Offshore Services segment, a favorable litigation settlement, and due to significant impairments to oil and gas properties during 2008.

During the fourth quarter of 2008, changes to the global economic environment resulting in uncertain capital markets and reductions in global economic activity had a severe impact on the estimated fair value of each of our reporting units as of December 31, 2008. As part of our annual test of goodwill impairment, we determined that an impairment of the goodwill of our Fluids and Offshore Services reporting units was necessary. Accordingly, we recorded goodwill impairment charges for these segments.

Consolidated general and administrative expenses decreased primarily due to approximately $2.2 million of decreased salary, benefits, contract labor costs, and other associated employee expenses, primarily due to overall personnel cost reduction efforts. This decrease was despite increased incentive bonus and equity compensation expenses. General and administrative expenses were also decreased due to approximately $2.1 million of decreased office expense, primarily from decreased office rent following the first

quarter 2009 relocation to our new corporate headquarters building, approximately $0.8 million of decreased professional fees, and approximately $0.6 million of decreased marketing, investor relations, and other general expenses. These decreases were partially offset by approximately $1.3 million of increased insurance and property tax expenses and approximately $0.3 million of increased bad debt expenses.

Consolidated other income decreased primarily due to the change in hedge ineffectiveness, as we recognized approximately $1.7 million of hedge ineffectiveness losses during 2009 compared to $8.6 million of hedge ineffectiveness gains during the prior year. In addition, earnings from unconsolidated joint ventures decreased $5.7 million, primarily due to an impairment charge of approximately $6.6 million during 2009 associated with the write down of our unconsolidated European joint venture investment. Partially offsetting these decreases, we recorded $4.6 million of increased net legal settlement income, $4.0 million of increased gains on sales of assets, and $0.4 million of increased foreign currency gains during 2009.

Consolidated net interest expense decreased, despite increased borrowings of long-term debt during much of the year. The increased borrowings were used to fund our 2009 capital expenditure and working capital requirements. The decrease in interest expense was primarily due to $3.6 million of increased capitalized interest primarily associated with our Arkansas calcium chloride plant and corporate headquarters construction projects. The corporate headquarters building was completed during the first quarter of 2009, and our calcium chloride facility in El Dorado, Arkansas, began initial production during the fourth quarter of 2009. Accordingly, despite a decrease in the balance of long-term debt outstanding as of December 31, 2009, our net interest expense is expected to increase beginning in 2010 since the amount of interest capitalized will be reduced.

Consolidated provision for income taxes increased primarily due to increased earnings.

Divisional Comparisons

Fluids Division

	Year Ended December 31,						Period to Period Change
	2009			2008			2009 vs 2008			% Change
	(In Thousands, Except Percentages)
Revenues	$	225,517		$	293,248		$	(67,731	)		-23.1	%
Gross profit		47,549			56,444			(8,895	)		-15.8	%
Gross profit as a percentage of revenue		21.1	%		19.2	%
General and administrative expense		22,355			28,526			(6,171	)		-21.6	%
General and administrative expense as a percentage of revenue		9.9	%		9.7	%
Impairment of goodwill		-			23,850			(23,850	)
Interest (income) expense, net		(35	)		(92	)		57
Other (income) expense, net		4,438			(1,241	)		5,679
Income before taxes and discontinued operations	$	20,791		$	5,401		$	15,390			284.9	%
Income before taxes and discontinued operations as a percentage of revenue		9.2	%		1.8	%

The decrease in Fluids Division revenue was primarily due to a $59.6 million decrease in product sales revenues, primarily due to decreased sales volumes of completion fluids as a result of the overall decreased demand for the Division’s brine products. This decrease reflects the overall decreased industry spending as reflected in the U.S. and international rig counts during 2009 compared to 2008 and the trend of many operators during 2009 to defer completion operations on drilled oil and gas wells. In addition, the decreased product sales revenues were due to decreased sales volumes of the Division’s manufactured chemicals products, primarily due to the impact of decreased economic conditions which have affected the level of activity of the Division’s oil and gas industry customers. The Division also reflected $8.1 million of decreased service revenues, primarily due to decreased U.S. onshore oil and gas activity. During the fourth quarter of 2009, the Division began initial production of liquid calcium chloride from its El Dorado, Arkansas, plant facility. The plant also began initial production of dry calcium chloride in early 2010.

The decrease in Fluids Division gross profit was primarily due to the decreased sales volumes discussed above, particularly for U.S. completion fluids products. In addition, the Fluids Division recorded approximately $1.4 million of impairments of long-lived assets during 2009. Gross profit as a percentage of

revenue increased, however, due to increased international margins, particularly by the Division’s European calcium chloride operation. As discussed above, the Division’s new El Dorado, Arkansas, calcium chloride plant facility began initial production during the fourth quarter of 2009.

The increase in Fluids Division income before taxes was primarily due to a non-recurring $23.9 million charge for the impairment of goodwill recorded during the fourth quarter of 2008. This increase was partially offset by the $8.9 million decrease in gross profit discussed above and a $6.5 million charge during 2009 associated with the impairment of the Division’s investment in a European unconsolidated joint venture. The joint venture ceased operation of the calcium chloride manufacturing plant following our joint venture partner’s announced closure of its adjacent plant facility which supplies the joint venture’s plant with feedstock raw material. These decreases in earnings were partially offset by approximately $6.2 million of decreased administrative expenses and approximately $0.9 million of increased other income, which was primarily due to a $1.4 million charge for a legal settlement in the prior year period.

Offshore Division

Offshore Services Segment

	Year Ended December 31,						Period to Period Change
	2009			2008			2009 vs 2008			% Change
	(In Thousands, Except Percentages)
Revenues	$	353,798		$	306,362		$	47,436			15.5	%
Gross profit		94,488			43,027			51,461			119.6	%
Gross profit as a percentage of revenue		26.7	%		14.0	%
General and administrative expense		13,891			16,351			(2,460	)		-15.0	%
General and administrative expense as a percentage of revenue		3.9	%		5.3	%
Impairment of goodwill		-			23,223			(23,223	)
Interest (income) expense, net		(161	)		71			(232	)
Other (income) expense, net		2,364			363			2,001
Income before taxes and discontinued operations	$	78,394		$	3,019		$	75,375			2496.7	%
Income before taxes and discontinued operations as a percentage of revenue		22.2	%		1.0	%

The increase in Offshore Services revenues was due to increased utilization, particularly by the segment’s diving, abandonment, heavy lift, and cutting services businesses, which enjoyed unprecedented high demand following the 2005 and 2008 hurricanes. Beginning in June 2009, the segment increased its service fleet through the leasing of a specialized dive support vessel which was utilized for contracted hurricane recovery work during the remainder of the year. In addition, many offshore oil and gas operators, including Maritech, have accelerated their efforts to abandon and decommission offshore platform facilities in response to the risks from future storms and the significantly increased windstorm insurance cost for offshore properties. Many operators have discontinued or reduced their windstorm insurance coverage until premium costs decrease or become justifiable and are seeking to maximize their abandonment and decommissioning activity in order to decrease their risk of future damage.

The increase in gross profit was primarily due to the increased gross profit of the segment’s heavy lift, diving, and cutting services businesses, which generated significant efficiencies from increased utilization during 2009. These efficiencies were partially due to improved weather conditions during 2009, as the segment incurred significant downtime during the third quarter of 2008 due to Hurricanes Gustav and Ike. The hurricane season from June through November can generate significant downtime in certain years. In addition, heavy seas, winds, and winter squalls tend to disrupt activities and, therefore, reduce demand for our services in the first and fourth quarters. Also during 2008 the Offshore Services segment recorded an $8.7 million impairment of certain long-lived assets. In addition, during 2009 the segment consolidated certain office and administrative functions, reduced crews, and sold or temporarily idled selected inland water equipment in order to increase efficiencies for certain of its operations.

Offshore Services segment income before taxes increased due to the increase in gross profit described above and $2.5 million of decreased administrative expenses, partially offset by approximately $1.8 million of increased other expense, primarily due to a legal settlement during the third quarter of 2009. In addition, the Offshore Services segment recorded a charge to earnings of $23.2 million for a goodwill impairment during the fourth quarter of 2008.

Maritech Segment

	Year Ended December 31,						Period to Period Change
	2009			2008			2009 vs 2008			% Change
	(In Thousands, Except Percentages)
Revenues	$	177,039		$	208,509		$	(31,470	)		-15.1	%
Gross profit		20,655			(29,958	)		50,613			-168.9	%
Gross profit as a percentage of revenue		11.7	%		-14.4	%
General and administrative expense		5,911			6,632			(721	)		-10.9	%
General and administrative expense as a percentage of revenue		3.3	%		3.2	%
Interest (income) expense, net		17			(124	)		141
Other (income) expense, net		(7,285	)		(4,534	)		(2,751	)
Income before taxes and discontinued operations	$	22,012		$	(31,932	)	$	53,944			-168.9	%
Income before taxes and discontinued operations as a percentage of revenue		12.4	%		-15.3	%

Maritech’s revenues decreased during 2009 compared to the prior year due to decreased pricing and production volumes. Decreased realized commodity prices resulted in $17.7 million of decreased revenues, as during 2009 Maritech reflected average realized oil and natural gas prices of $65.13/barrel and $8.41/MMBtu, respectively, each of which was lower than 2008 levels. Maritech has hedged a portion of its expected future production levels by entering into derivative hedge contracts. The average realized prices above include the impact of these hedge contracts during 2009, which significantly reduced the impact of decreased prices during the year. In addition to decreased pricing, decreased Maritech production volumes resulted in decreased revenues of approximately $15.3 million primarily due to one of Maritech’s key oil producing fields, the East Cameron 328 field, being shut-in for most of the year. The decreased production from normal production declines and the shut-in properties more than offset newly added production during the period from wells drilled in 2008 and 2009. The level of Maritech’s drilling and development activity has decreased during 2009 as a result of our efforts to conserve capital. Partially offsetting the revenue decreases associated with decreased pricing and production volumes, Maritech reported $1.5 million of increased processing revenue during the current year period.

The increase in gross profit was primarily due to the $44.7 million of increased insurance related gains, primarily from the $40 million settlement of our insurance litigation regarding claims associated with damage from Hurricanes Katrina and Rita. The proceeds from this settlement were received during the fourth quarter of 2009. In addition, Maritech recorded oil and gas property impairments of $11.4 million during 2009, compared to $42.6 million during 2008. Also, Maritech recorded $13.8 million of decreased operating expenses and depreciation, depletion, and amortization during 2009 compared to the prior year. This decrease was primarily due to decreased production volumes and reduced insurance premium costs, following Maritech’s decision to self insure from windstorm damage risk during the last half of the year. Maritech also recorded $9.1 million of dry hole costs during 2008. Partially offsetting these expense decreases, Maritech recorded $16.7 million of increased excess decommissioning costs incurred during 2009.

The increase in Maritech income before taxes compared to the prior year was due to the increase in gross profit discussed above, approximately $2.9 million of increased gains on sales of properties recorded, and approximately $0.7 million of decreased administrative costs, partially offset by approximately $0.3 million of decreased other income during 2009.

Production Enhancement Division

Production Testing Segment

	Year Ended December 31,						Period to Period Change
	2009			2008			2009 vs 2008			% Change
	(In Thousands, Except Percentages)
Revenues	$	77,700		$	123,872		$	(46,172	)		-37.3	%
Gross profit		16,868			41,909			(25,041	)		-59.8	%
Gross profit as a percentage of revenue		21.7	%		33.8	%
General and administrative expense		7,985			8,080			(95	)		-1.2	%
General and administrative expense as a percentage of revenue		10.3	%		6.5	%
Interest (income) expense, net		2			30			(28	)
Other (income) expense, net		(6,823	)		293			(7,116	)
Income before taxes and discontinued operations	$	15,704		$	33,506		$	(17,802	)		-53.1	%
Income before taxes and discontinued operations as a percentage of revenue		20.2	%		27.0	%

Production Testing revenues decreased due to the decrease in U.S. operations, primarily from reduced drilling activity as reflected by the U.S. rig count. The decreased demand also resulted in decreased day rates for our services. The Division’s Production Testing segment is particularly affected by the activities of its U.S. customers, many of which have been significantly affected by the current economic climate. This decrease was partially offset by increased international revenues, primarily in Mexico and Brazil.

Production Testing gross profit decreased primarily due to an approximately $24.7 million decrease in domestic gross profit due to the weaker demand, lower day rates, and decreased activity in the U.S. In addition, gross profit from international production testing activities also decreased by approximately $0.3 million.

Production Testing income before taxes decreased due to the $25.0 million decrease in gross profit discussed above, which was partially offset by approximately $7.1 million of increased other income, primarily due to a $5.6 million legal settlement gain, $0.5 million of increased gains on sales of assets, and $1.0 million of increased other income, primarily from increased earnings from an unconsolidated joint venture.

Compressco Segment

	Year Ended December 31,						Period to Period Change
	2009			2008			2009 vs 2008			% Change
	(In Thousands, Except Percentages)
Revenues	$	90,965		$	100,564		$	(9,599	)		-9.5	%
Gross profit		35,985			43,828			(7,843	)		-17.9	%
Gross profit as a percentage of revenue		39.6	%		43.6	%
General and administrative expense		10,518			11,173			(655	)		-5.9	%
General and administrative expense as a percentage of revenue		11.6	%		11.1	%
Interest (income) expense, net		-			-			-
Other (income) expense, net		(82	)		174			(256	)
Income before taxes and discontinued operations	$	25,549		$	32,481		$	(6,932	)		-21.3	%
Income before taxes and discontinued operations as a percentage of revenue		28.1	%		32.3	%

Compressco revenues during 2009 decreased, reflecting the decreased U.S. demand during most of 2009 compared to the prior year. Lower natural gas prices and general industry economic conditions resulted in decreased demand compared to 2008 for wellhead compression services, as reflected in Compressco’s reduced utilization of its GasJack® compressor fleet. Beginning in early 2009, Compressco reduced the fabrication of new compressor units until demand for its production enhancement services increases and inventories of available units are reduced. However, Compressco continues to seek new niche opportunities to expand its operations, including additional opportunities in international markets.

Compressco gross profit decreased primarily due to decreased activity and due to unabsorbed fabrication overhead as a result of the decreased production of new compressor units along with other increased operating expenses for Compressco’s U.S. operations.

Income before taxes for Compressco decreased primarily due to the $7.8 million of decreased gross profit discussed above, partially offset by decreased administrative costs and increased other income.

Corporate Overhead

	Year Ended December 31,						Period to Period Change
	2009			2008			2009 vs 2008			% Change
	(In Thousands, Except Percentages)
Gross profit (primarily depreciation expense)	$	(3,011	)	$	(2,470	)	$	(541	)		21.9	%
General and administrative expense		40,173			34,186			5,987			17.5	%
Interest (income) expense, net		12,969			16,906			(3,937	)		-23.3	%
Other (income) expense, net		1,574			(7,954	)		9,528			-119.8	%
Income (loss) before taxes and discontinued operations	$	(57,727	)	$	(45,608	)	$	(12,119	)		-26.6	%

Corporate Overhead includes corporate general and administrative expense, interest income and expense, and other income and expense. Such expenses and income are not allocated to our operating divisions, as they relate to our general corporate activities. Corporate administrative costs increased primarily due to approximately $6.9 million of increased salary and employee expenses. Although Corporate employee salary expenses decreased due to cost reduction efforts, these decreases were more than offset by increases in company-wide incentive bonus and equity compensation expense. In addition, Corporate administrative expenses increased due to approximately $1.0 million of increased insurance, taxes, and other general expenses. These administrative cost increases were partially offset by $1.0 million of decreased professional services and investor relations expense and $0.9 million of decreased office expenses, primarily from decreased office rent following the first quarter 2009 relocation to our new corporate headquarters building. In addition to increased administrative expenses, other expense increased due to $1.7 million of hedge ineffectiveness losses included in other expense during 2009 compared to $8.6 million of hedge ineffectiveness gains which were included in other income during 2008. In addition, Corporate Overhead expense increased due to $0.6 million of increased depreciation expense, primarily due to our new corporate headquarters building. Partially offsetting these increases, Corporate interest expense decreased during 2009 primarily due to an increase in the amount of interest capitalized on construction projects during the period.

Liquidity and Capital Resources

During the past year, we have continued to conserve capital, improve our liquidity, and maintain a strong financial position. During the fourth quarter of 2010, we sold $90 million of Series 2010 Senior Notes, using the proceeds from the offering to help retire $91.8 million of Series 2004 Senior Notes which were scheduled to mature in September 2011. In addition, we amended our bank credit facility to extend its scheduled maturity to October 2015, which will provide a source of capital for the next five years. We continue to fund our existing capital expenditure needs, however, from our operating cash flows. Our operating cash flows during 2010 were significantly less than 2009, primarily due to the decreased profitability and cash flows from our Offshore Services segment, which enjoyed unprecedented activity levels during the prior year. Also, operating cash flows during 2010 have been negatively affected by the current uncertain regulatory environment following the recent events in the Gulf of Mexico, low natural gas prices, and the effects of the continuing economic recovery. Still, the demand for the products and services of many of our businesses was improving during 2010 compared to the prior year, and this bodes well for additional growth in 2011. The capital expenditure plans for many of our businesses are also increasing from 2010 levels, and we anticipate these expenditures will again be funded primarily from operating cash flows. However, due to a desire to conserve and reallocate capital, we have begun to decrease our investment in Maritech by suspending our search for oil and gas property acquisitions and decreasing our development activities. In addition, we are exploring strategic alternatives to our ownership of Maritech and its oil and gas properties and we are reviewing opportunities to sell Maritech oil and gas property packages to industry participants and other third parties. As part of this overall effort, in late February 2011, Maritech sold a group of properties that accounted for 11.4% of its proved reserves as of December 31, 2010. Our capital conservation efforts are expected to position us so that we may continue to seek acquisition and growth opportunities that meet certain criteria,

particularly internationally, either through strategic expansion of existing businesses in niche markets or through suitable acquisitions.

Operating Activities

Cash flows generated by operating activities totaled approximately $153.3 million during 2010 compared to $272.3 million during 2009, a decrease of 43.7%. Approximately $47.8 million of current period operating cash flows were generated from insurance settlements and claims proceeds from a portion of Maritech’s insurance coverage related to damages suffered from Hurricane Ike during 2008. Operating cash flows from insurance settlement collections were similarly significant during 2009. Prior period operating cash flows include $23.1 million from the liquidation of certain oil swap derivative contracts. However, the decrease in operating cash flows during 2010 primarily reflects the decreased operating cash flows of our Offshore Services segment, which enjoyed unprecedented demand for its products and services during 2009.

Operating cash flows were also reduced during 2010 as a result of the regulatory uncertainty that followed the April 2010 Macondo oil spill in the U.S. Gulf of Mexico. Future operating cash flows for many of our businesses will also be largely dependent upon the level of oil and gas industry activity, particularly in the U.S. Gulf of Mexico region. As a result of the Macondo oil spill, regulatory requirements for offshore operators, particularly deepwater operators, have increased. We estimate that the combined impact of the recent U.S. government imposed deepwater drilling moratorium and related regulatory issues resulted in the reduction of our consolidated revenues by approximately $22 to $25 million during 2010, compared to the level of revenues we would have expected had the recent events in the Gulf of Mexico not occurred. This decrease was experienced primarily by our Fluids Division, although our Offshore Services segment was also affected. Although the deepwater drilling moratorium was lifted in October 2010, the impact of regulatory uncertainty is expected to continue to negatively affect the cost and timing of offshore activities in the future, perhaps significantly. Many within the oil and gas industry are expecting further increases in regulatory requirements for all U.S. offshore drilling and production operations, particularly for deepwater projects. Operators are currently experiencing delays in permitting for deepwater as well as shallow water offshore projects. A portion of our revenues will continue to be impacted by the current regulatory environment. Following the Macondo spill and the announcement of the drilling moratorium, the U.S. Gulf of Mexico offshore rig count dropped significantly, and while this offshore rig count has improved recently, it is still below pre-Macondo spill levels. For certain of our businesses, increased government regulations could affect us positively. However, to the extent more stringent government regulations affecting deepwater and shallow water drilling are enacted, our future revenues and operating cash flows could be negatively affected overall.

Perhaps the most significant impact affecting our operations from the newly enacted regulations following the Macondo oil spill is the new NTL 2010-G05 “Idle Iron Guidance” regulation which requires that permanent plugs be set in nearly 3,500 nonproducing wells and that approximately 650 oil and gas production platforms be dismantled if they are no longer being used. These “Idle Iron Guidance” requirements are expected to increase, possibly significantly, the future demand for the abandonment and decommissioning services of our Offshore Services segment. Also significantly affected is our Maritech subsidiary, as the new regulatory requirement is one factor resulting in Maritech significantly increasing its estimate of the decommissioning liabilities for the plugging, abandonment, and decommissioning of its oil and gas properties as of December 31, 2010. Our future operating cash flow will be affected by the actual timing and amount of these decommissioning expenditures. The estimated third-party discounted fair value, including an estimated profit, of Maritech’s decommissioning liabilities as adjusted as of December 31, 2010, totals $265.5 million ($285.8 million undiscounted). Approximately $72.3 million of the cash outflow necessary to extinguish Maritech’s decommissioning liabilities is expected to occur during 2011. The remainder of Maritech’s decommissioning liabilities are expected to be extinguished in future years, as reserves are depleted. The amount and timing of these cash outflows are estimated based on expected costs, as well as on the timing of future oil and gas production and the resulting depletion of Maritech’s oil and gas reserves. Such estimates are imprecise and subject to change due to changing cost estimates, further changes to BOEMRE requirements, commodity prices, revisions of reserve estimates, and other factors. In addition to the impact from regulatory changes, Maritech’s increased decommissioning liabilities also reflect the decision to limit future development activity. This decision results in the acceleration of the estimated timing of when abandonment and decommissioning activities on certain properties will be performed.

Maritech’s estimated decommissioning liabilities are net of amounts allocable to joint interest owners

and any contractual amounts to be paid by the previous owners of the properties. In some cases, the previous owners of the properties that were acquired by Maritech are contractually obligated to pay Maritech a fixed amount for the future well abandonment and decommissioning work on these properties as the work is performed, which partially offsets Maritech’s future expenditures. As of December 31, 2010, Maritech’s total undiscounted decommissioning obligation is approximately $321.7 million and consists of Maritech’s total liability of $285.8 million plus approximately $35.9 million of such contractual reimbursement arrangements with the previous owners.

While the timing and strength of the current global economic recovery continues to be difficult to predict, industry rig count and other data indicates that domestic oil and gas industry spending is increasing, spurred by the current strong pricing for crude oil and the recent trends for onshore shale gas exploitation. Still, domestic oil and gas operators’ activities and spending levels are significantly below early 2008 levels. Demand for a large portion of our products and services is driven by oil and gas drilling and production activity, which is affected by oil and natural gas commodity pricing. In particular, our Production Testing, Compressco, and Fluids segments reported increased domestic activity levels during the last half of 2010. We are anticipating similar increases in revenues and cash flows for these businesses in 2011; however, these planned levels are expected to continue to be significantly below the levels generated by these businesses during the first half of 2008.

Our operating cash flows continue to be affected by hurricanes. During the past two years, Maritech has performed an extensive amount of well intervention, abandonment, decommissioning, debris removal, and platform construction associated with the six offshore platforms that were destroyed by Hurricanes Rita and Ike during 2005 and 2008, respectively. As of December 31, 2010, Maritech has two remaining downed platforms to be removed, and has begun redrilling certain wells at its East Cameron 328 field using a newly installed replacement platform. Until these wells are redrilled, production from the East Cameron 328 field continues to be below their pre-storm levels. The estimated cost to perform the remaining abandonment, decommissioning, debris removal, and well redrilling will be approximately $50 to $65 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. Approximately $38.1 million of this amount has been accrued as part of Maritech’s decommissioning liabilities. An additional amount of approximately $13 to $19 million relates primarily to the estimated cost to finalize the newly installed offshore platform and to complete the redrilling of the wells at the East Cameron 328 location. Following the collection of $47.8 million of insurance settlement proceeds associated with Hurricane Ike during 2010, Maritech has additional maximum remaining insurance coverage available of approximately $19.5 million, all of which relates to Hurricane Ike. We anticipate that damages from Hurricane Ike will exceed our coverage limits for this storm. Despite our confidence that the majority of the remaining abandonment, decommissioning, debris removal, and well redrilling costs up to our coverage limits will qualify as covered costs pursuant to our insurance coverage, a portion of these costs may not be reimbursed. 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. Also, 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.

The recent explosion and subsequent oil spill at the Macondo well evidences the general operating risks associated with offshore oil and gas activities. While we have no liability associated with this specific incident, we are subject to operating hazards normally associated with the oilfield service industry and offshore oil and gas production operations, including fires, explosions, blowouts, cratering, mechanical problems, abnormally pressured formations, and environmental accidents. We maintain various types of business insurance that would be applicable in the event of an explosion or other catastrophic event involving our offshore operations. This insurance includes third-party liability, workers’ compensation and employers’ liability, general liability, vessel pollution liability, and operational risk coverage for our Maritech oil and gas properties, including named windstorm damage, removal of debris, operator’s extra expense, control of well, and pollution and clean-up coverage. Our insurance coverage includes deductibles that must be met prior to recovery. Additionally, our insurance is subject to certain exclusions and limitations. We believe our policy of insuring against such risks, as well as the levels of insurance we maintain, is typical in the industry. In addition, we provide services and products in the offshore Gulf of Mexico generally pursuant to agreements

that create insurance and indemnity obligations for both parties. Our Maritech subsidiary maintains a formalized oil spill response plan that it submits to BOEMRE. Maritech has designated employees and third-party contracts in place to ensure that resources are available as required in the event of an environmental accident. While it is impossible to anticipate every potential accident or incident involving our offshore operations, we believe we have taken appropriate steps to mitigate the potential impact of such an event on the environment in the regions in which we operate.

Future operating cash flow will continue to be affected by the oil and gas prices received for Maritech’s production. To minimize the risk of fluctuating oil and gas prices, Maritech enters into oil and natural gas swap derivative transactions that are designated to hedge a portion of Maritech’s oil and gas production. Maritech’s oil and natural gas swap derivative contracts during 2010 resulted in Maritech receiving a fixed price for hedged natural gas production that was in excess of prices currently being received. Following the expiration of its 2010 swap derivative contracts, Maritech’s natural gas production is currently unhedged and its hedged oil production is fixed at prices below current oil prices.

Investing Activities

During 2010, we expended $115.9 million of capital expenditures and other investing activities. This level of capital expenditures was significantly reduced compared to the past several years, partially due to the completion during 2009 of our new corporate headquarters in The Woodlands, Texas, and our El Dorado, Arkansas, calcium chloride plant facility. In light of uncertainties regarding our future operating cash flows, our capital expenditure plans have been, and will continue to be, reviewed carefully, and a significant amount of such capital expenditures have been deferred until activity levels increase. This restraint on capital expenditure activity may also affect future growth. In particular, prior to 2009, we had invested significantly in Maritech acquisition and development activities. The current effort to reduce our investment in Maritech includes the suspension of oil and gas property acquisition activities and the reduction of oil and gas development activities. In addition, we are exploring strategic alternatives to our ownership of Maritech and its oil and gas properties and we are reviewing opportunities to sell Maritech oil and gas property packages to industry participants and other third parties.

During 2010, our cash capital expenditures totaled approximately $107.7 million. In addition, in December 2010, we expended $6.3 million for the acquisition of certain well abandonment and wireline assets for our Offshore Services segment. Approximately $10.9 million of our capital expenditures was expended by our Fluids Division, approximately $6.7 million of which related to the ongoing modification of our new calcium chloride plant facility. Our Offshore Division expended approximately $81.4 million, consisting of approximately $70.2 million of acquisition, exploration and development expenditures for Maritech. In addition, the Offshore Division expended approximately $11.3 million on its Offshore Services operations for costs on its various heavy lift and dive support vessels exclusive of the December 2010 acquisition. Our Production Enhancement Division spent approximately $13.9 million, consisting of approximately $6.0 million by the Production Testing segment to replace or enhance a portion of its production testing equipment fleet and approximately $7.9 million by the Compressco segment for general infrastructure needs, along with minimal expansion of its wellhead compressor fleet. Corporate capital expenditures were approximately $1.4 million.

Generally, a significant majority of our planned capital expenditures is related to identified opportunities to grow and expand our existing businesses; however, certain of these expenditures may be postponed or cancelled in our continuing efforts to conserve capital. We plan to expend over $120 million on total capital expenditures during 2011. This anticipated level of capital expenditure activity would result in increased spending for each of our business segments other than Maritech and Compressco. The deferral of certain capital projects, such as the replacement or upgrading of vessels in our Offshore Services fleet, could affect our ability to compete in the future. This restraint on capital expenditure activity may also affect future growth. However, our long-term growth strategy also continues to include the pursuit of suitable acquisitions or opportunities to establish operations in additional niche oil and gas service markets. To the extent we consummate a significant transaction, our liquidity position will be affected.

Financing Activities

To fund our capital and working capital requirements, we may supplement our existing cash balances and cash flow from operating activities as needed from long-term borrowings, short-term borrowings, equity issuances, and other sources of capital.

Bank Credit Facilities

On October 29, 2010, we amended our existing bank revolving credit facility agreement with a syndication of banks, whereby the credit facility was decreased from $300 million to $278 million and its scheduled maturity was extended from June 2011 to October 2015. In addition, the amended credit facility agreement allows us to increase the facility by $150 million up to a $428 million limit upon the agreement of the lenders and the satisfaction of certain conditions. As of March 1, 2011, we did not have any outstanding balance on the amended revolving credit facility and had $14.2 million in letters of credit and guarantees against the $278.0 million amended revolving credit facility, leaving a net availability of $263.8 million.

Under the amended credit facility agreement (the Credit Agreement), the revolving credit facility remains unsecured and guaranteed by certain of our material U.S. subsidiaries. Borrowings generally bear interest at the British Bankers Association LIBOR rate plus 1.5% to 2.5%, depending on one of our financial ratios. We pay a commitment fee ranging from 0.225% to 0.500% on unused portions of the facility. Similar to the previous terms, the Credit Agreement contains customary covenants and other restrictions, including certain financial ratio covenants involving our levels of debt and interest cost compared to a defined measure of our operating cash flows over a twelve month period. In addition, the Credit Agreement includes limitations on aggregate asset sales, individual acquisitions, and aggregate annual acquisitions and capital expenditures. Access to our revolving credit line is dependent upon our ability to comply with the certain financial ratio covenants set forth in the Credit Agreement, as discussed above. Significant deterioration of the financial ratios could result in a default under the Credit Agreement and, if not remedied, could result in termination of the agreement and acceleration of any outstanding balances.

The Credit Agreement also includes cross-default provisions relating to any other indebtedness greater than a defined amount. If any such indebtedness is not paid or is accelerated and such event is not remedied in a timely manner, a default will occur under the Credit Agreement. Our Credit Agreement also contains a covenant that restricts us from paying dividends in the event of a default or if such payment would result in an event of default. We are in compliance with all covenants and conditions of our Credit Agreement as of December 31, 2010. Our continuing ability to comply with these financial covenants depends largely upon our ability to generate adequate cash flow. Historically, our financial performance has been more than adequate to meet these covenants and we expect this trend to continue.

Senior Notes

In September 2004, we issued, and sold through a private placement, $55.0 million in aggregate principal amount of Series 2004-A Senior Notes and 28 million Euros in aggregate principal amount of Series 2004-B Senior Notes pursuant to a Master Note Purchase Agreement. In December 2010 we used the proceeds from our Series 2010 Senior Notes and applied $95.7 million to repay the Series 2004 Senior Notes, including principal, accrued interest, and a $2.8 million “make-whole” prepayment premium.

In April 2006, we issued, and sold through a private placement, $90.0 million in aggregate principal amount of Series 2006-A Senior Notes pursuant to our existing Master Note Purchase Agreement dated September 2004, as supplemented as of April 18, 2006. The Series 2006-A Senior Notes bear interest at the fixed rate of 5.90% and mature on April 30, 2016. Interest on the 2006-A Senior Notes is due semiannually on April 30 and October 30 of each year. The Series 2006-A Senior Notes were sold in the United States to accredited investors pursuant to an exemption from the Securities Act of 1933. Net proceeds from the sale of the Series 2006-A Senior Notes were used to pay down a portion of the existing indebtedness under the bank revolving credit facility.

In April 2008, we issued, and sold through a private placement, $35.0 million in aggregate principal amount of Series 2008-A Senior Notes and $90.0 million in aggregate principal amount of Series 2008-B Senior Notes (collectively the Series 2008 Senior Notes) pursuant to a Note Purchase Agreement dated April 30, 2008. The Series 2008-A Senior Notes bear interest at the fixed rate of 6.30% and mature on April 30,

2013. The Series 2008-B Senior Notes bear interest at the fixed rate of 6.56% and mature on April 30, 2015. Interest on the 2008 Senior Notes is due semiannually on April 30 and October 31 of each year. The Series 2008 Senior Notes were sold in the United States to accredited investors pursuant to an exemption from the Securities Act of 1933. A significant majority of the combined net proceeds from the sale of the Series 2008 Senior Notes was used to pay down a portion of the existing indebtedness under the bank revolving credit facility.

In September 2010, we entered into an agreement whereby we agreed to issue and sell through a private placement, $65.0 million in aggregate principal amount of Series 2010-A Senior Notes and $25.0 million in aggregate principal amount of Series 2010-B Senior Notes (collectively, the 2010 Senior Notes) pursuant to a Note Purchase Agreement dated September 30, 2010. Upon receipt of the proceeds in December 2010, we utilized the funds to repay the 2004 Senior Notes. The Series 2010-A Senior Notes bear interest at the fixed rate of 5.09% and mature on December 15, 2017. The Series 2010-B Senior Notes bear interest at the fixed rate of 5.67% and mature on December 15, 2020. Interest on the 2010 Senior Notes is due semiannually on June 15 and December 15 of each year. The Series 2008 Senior Notes were sold in the United States to accredited investors pursuant to an exemption from the Securities Act of 1933.

We may prepay the Senior Notes, in whole or in part, at any time at a price equal to 100% of the principal amount outstanding, plus accrued and unpaid interest and a “make-whole” prepayment premium. The Senior Notes are unsecured and are guaranteed by substantially all of our wholly owned U.S. subsidiaries. The Note Purchase Agreement and the Master Note Purchase Agreement, as supplemented, contain customary covenants and restrictions and require us to maintain certain financial ratios, including a minimum level of net worth and a ratio between our long-term debt balance and a defined measure of operating cash flow over a twelve month period. The Note Purchase Agreement and the Master Note Purchase Agreement also contain customary default provisions as well as a cross-default provision relating to any other of our indebtedness of $20 million or more. We are in compliance with all covenants and conditions of the Note Purchase Agreement and the Master Note Purchase Agreement as of December 31, 2010. Upon the occurrence and during the continuation of an event of default under the Note Purchase Agreement and the Master Note Purchase Agreement, as supplemented, the Senior Notes may become immediately due and payable, either automatically or by declaration of holders of more than 50% in principal amount of the Senior Notes outstanding at the time.

Other Sources

In addition to the aforementioned revolving credit facility, we fund our short-term liquidity requirements from cash generated by operations, from short-term vendor financing and, to a lesser extent, from leasing with institutional leasing companies. Should additional capital be required, we believe that we have the ability to raise such capital through the issuance of additional debt or equity. However, instability or volatility in the capital markets at the times we need to access capital may affect the cost of capital and the ability to raise capital for an indeterminable length of time. As discussed above, our Credit Agreement matures in 2015 and our Senior Notes mature at various dates between April 2013 and December 2020. The replacement of these capital sources at similar or more favorable terms is not certain. If it is necessary to utilize equity to fund our capital needs, dilution to our common stockholders could occur.

In November 2009, we filed a universal shelf registration statement on Form S-3 that permits us to issue an indeterminate amount of securities including common stock, preferred stock, senior and subordinated debt securities, warrants, and units. Such securities may be used for working capital needs, capital expenditures, and expenditures related to general corporate purposes, including possible future acquisitions. In May 2004, we filed a universal acquisition shelf registration statement on Form S-4 that permits us to issue up to $400 million of common stock, preferred stock, senior and subordinated debt securities, and warrants in one or more acquisition transactions that we may undertake from time to time.

In January 2004, our Board of Directors authorized the repurchase of up to $20 million of our common stock. We purchased $5.7 million of common stock pursuant to this authorization from 2004 through 2005 and have made no purchases pursuant to the authorization since then. We received $1.3 million, $1.2 million, and $4.8 million during 2010, 2009 and 2008, respectively, from the exercise of stock options by employees.

Off Balance Sheet Arrangements

An “off balance sheet arrangement” is defined as any contractual arrangement to which an entity that is not consolidated with us is a party, under which we have, or in the future may have:

·	any obligation under a guarantee contract that requires initial recognition and measurement under U.S. Generally Accepted Accounting Principles;

·	a retained or contingent interest in assets transferred to an unconsolidated entity or similar arrangement that serves as credit, liquidity, or market risk support to that entity for the transferred assets;

·	any obligation under certain derivative instruments; or

·	any obligation under a material variable interest held by us in an unconsolidated entity that provides financing, liquidity, market risk or credit risk support to us, or engages in leasing, hedging, or research and development services with us.

As of December 31, 2010 and 2009, we had no “off balance sheet arrangements” that may have a current or future material effect on our consolidated financial condition or results of operations.

Commitments and Contingencies

Litigation

Class Action Lawsuit

Derivative Lawsuit

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 the class action lawsuit, and 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. 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. Our board is currently evaluating the best course of action to take in response to the demand letter.

At this stage, it is impossible to predict the outcome of these proceedings or their impact upon us. We continue to believe that the allegations made in the derivative lawsuits are without merit, and we intend to seek dismissal of and vigorously defend against this lawsuit. While a successful outcome cannot be guaranteed, we do not reasonably expect this lawsuit to have a material adverse effect.

Environmental

Product Purchase Obligations

In the normal course of our Fluids Division operations, we enter into supply agreements with certain manufacturers of various raw materials and finished products. Some of these agreements have terms and conditions that specify a minimum or maximum level of purchases over the term of the agreement. Other agreements require us to purchase the entire output of the raw material or finished product produced by the manufacturer. Our purchase obligations under these agreements apply only with regard to raw materials and finished products that meet specifications set forth in the agreements. We recognize a liability for the purchase of such products at the time we receive them. As of December 31, 2010, the aggregate amount of the fixed and determinable portion of the purchase obligation pursuant to our Fluids Division’s supply agreements was approximately $266.4 million, extending through 2029.

Other Contingencies

Related to its acquired interests in oil and gas properties, our Maritech subsidiary estimates the third-party fair values (including an estimated profit) to plug and abandon wells, decommission the pipelines and platforms, and clear the sites, and uses these estimates to record Maritech’s decommissioning liabilities, net of amounts allocable to joint interest owners and any amounts contractually agreed to be paid in the future by the previous owners of the properties. In some cases, previous owners of acquired oil and gas properties are contractually obligated to pay Maritech a fixed amount for the future well abandonment and decommissioning work on these properties as such work is performed. As of December 31, 2010, Maritech’s decommissioning liabilities are net of approximately $35.9 million for such future reimbursements from these previous owners.

Contractual Obligations

The table below summarizes our contractual cash obligations as of December 31, 2010:

	Payments Due
	Total		2011			2012		2013		2014		2015		Thereafter
	(In Thousands)

Long-term debt	$	305,035	$	-		$	35	$	35,000	$	-	$	90,000	$	180,000
Interest on debt		96,129		18,145			18,145		16,665		15,940		11,977		15,257
Purchase obligations		266,385		13,935			15,275		15,275		15,275		15,275		191,350
Decommissioning and
other asset retirement
obligations(1)		321,659		77,738	(3)		81,794		16,203		36,171		47,437		62,316
Operating and
capital leases		14,898		5,719			3,595		2,168		1,320		487		1,609
Total contractual
cash obligations(2)	$	1,004,106	$	115,537		$	118,844	$	85,311	$	68,706	$	165,176	$	450,532

(1)	Decommissioning liabilities related to oil and gas properties generally must be satisfied within twelve months after a property’s lease expires. Lease expiration generally occurs six months after the last producing well on the lease ceases production. We have estimated the timing of these payments based upon anticipated lease expiration dates, which are subject to many changing variables, including the estimated life of the producing oil and gas properties, which is affected by changing oil and gas commodity prices. The amounts shown represent the undiscounted obligation as of December 31, 2010.
(2)	Amounts exclude other long-term liabilities reflected in our Consolidated Balance Sheet that do not have known payment streams. These excluded amounts include approximately $3.6 million of liabilities under FASB Codification Topic 740, “Accounting for Uncertainty in Income Taxes,” as we are unable to reasonably estimate the ultimate amount or timing of settlements. See “Note F – Income Taxes,” in the Notes to Consolidated Financial Statements for further discussion.
(3)	Approximately $38.1 million of the amounts expected to be paid in 2011 represent well abandonment, decommissioning, and debris removal related to offshore platforms destroyed in the 2005 and 2008 hurricanes, net of anticipated insurance recoveries.

Recently Issued Accounting Pronouncements

In October 2009, the Financial Accounting Standards Board (FASB) published Accounting Standards Update (ASU) 2009-13, “Revenue Recognition (Topic 605), Multiple Deliverable Revenue Arrangements,” which establishes the accounting and reporting guidance for arrangements under which service providers will perform multiple revenue-generating activities. Specifically, this guidance addresses how to separate deliverables and how to measure and allocate arrangement consideration to one or more units of accounting. Additional disclosures of multiple deliverable arrangements will also be required. ASU 2009-13 is effective prospectively for revenue arrangements entered into or materially modified in fiscal years beginning on or after June 15, 2010. Early adoption is permitted. The adoption of the accounting and disclosure requirements of this ASU will not have a significant impact on our financial statements.

In January 2010, the FASB published ASU 2010-06, “Fair Value Measurements and Disclosures (Topic 820), Improving Disclosures about Fair Value Measurements,” which requires new disclosures about transfers in and out of fair value hierarchy levels, requires more detailed disclosures about activity in Level 3 fair value measurements, and clarifies existing disclosure requirements about asset and liability aggregation, inputs, and valuation techniques. The new disclosures and clarifications of existing disclosures are effective for interim and annual reporting periods beginning after December 15, 2009, except for the disclosure requirements of activity in Level 3 fair value measurements, which become effective for fiscal years beginning after December 15, 2010, and for interim periods within those fiscal years. The adoption of the disclosure requirements of this ASU did not have a significant impact on our financial statements, and the disclosure requirements of activity in Level 3 fair value measurements will not have a significant impact on our financial statements.

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

Interest Rate Risk

Any balances outstanding under the floating rate portion of our bank credit facility are subject to market risk exposure related to changes in applicable interest rates. We borrow funds pursuant to our bank credit facility as necessary to fund our capital expenditure requirements and certain acquisitions. These instruments carry interest at an agreed-upon percentage rate spread above LIBOR. We had no balance outstanding under our bank credit facility as of December 31, 2010. Accordingly, as of that date, there are no long-term debt obligations which bear a variable rate of interest.

Exchange Rate Risk

We are exposed to fluctuations between the U.S. dollar and the euro with regard to our euro-denominated operating activities. In September 2004, we borrowed euros to fund the acquisition of our European calcium chloride assets. We entered into long-term euro-denominated borrowings, in order to provide a natural currency hedge for our euro-based operating cash flow. In December 2010, we repaid our euro denominated debt and currently have no currency hedge for our euro-denominated operations. In our European operations, we continue to have exposure related to revenues, expenses, operating receivables, and payables denominated in euros, as well as other currencies; however, such transactions are not pursuant to long-term contract terms, and the amount of such foreign currency exposure is not determinable or considered material. We also have operations in other foreign countries in which we have exposure to the fluctuation between the local currencies in those markets and the U.S. dollar. We currently have no hedges in place with regard to these currencies.

Commodity Price Risk

We have market risk exposure in the pricing applicable to our oil and gas production. Realized pricing is primarily driven by the prevailing worldwide price for crude oil and spot prices in the U.S. natural gas market. Historically, prices received for oil and gas production have been volatile and unpredictable, and such price volatility is expected to continue. Our risk management activities involve the use of derivative financial instruments, such as swap agreements, to hedge the impact of market price risk exposures for a portion of our oil and gas production. We are exposed to the volatility of oil and gas prices for the portion of our oil and gas production that is not hedged. Net of the impact of the crude oil hedges as of December 31, 2010, described below, each $1 per barrel decrease in future crude oil prices would result in a decrease in after tax earnings of $0.3 million. As of December 31, 2010, we have no natural gas hedges, therefore, each decrease in future gas prices of $0.10 per Mcf would result in a decrease in after tax earnings of $0.5 million.

FASB Codification Topic 815, “Derivatives and Hedging,” requires companies to record derivatives on the balance sheet as assets and liabilities, measured at fair value. Gains or losses resulting from changes in the values of those derivatives are accounted for depending on the use of the derivative and whether it qualifies for hedge accounting. As of December 31, 2010 and 2009, we had the following cash flow hedging swap contracts outstanding relating to a portion of our Maritech subsidiary’s oil and gas production:

Commodity Contracts	Aggregate Daily Volume	Weighted Average Contract Price	Contract Year
December 31, 2010
Oil swaps	2,000 barrels/day	$87.68/barrel	2011
December 31, 2009
Oil swaps	2,000 barrels/day	$78.70/barrel	2010
Natural gas swaps	20,000 MMBtu/day	$8.147/MMBtu	2010

Each oil and gas swap contract uses the NYMEX WTI (West Texas Intermediate) oil price and the NYMEX Henry Hub natural gas price as the referenced price. Based upon an average NYMEX strip price over the remaining contract term of $93.76/barrel, the market value of our oil swaps liability at December 31, 2010, was $5.2 million. A $1 increase in the future price of oil would result in the market value of the combined oil derivative liability increasing by $0.7 million. The market value associated with the 2011 oil swap

contract is reflected as a current liability as of December 31, 2010, in the accompanying consolidated balance sheet.

Based upon an average NYMEX strip price over the remaining contract term of $82.31/barrel, the market value of our oil swaps liability at December 31, 2009 was $2.6 million. A $1 increase in the future price of oil would result in the market value of the combined oil derivative liability increasing by $0.7 million. Based on an average NYMEX strip price over the remaining contract term of $5.79/MMBtu, the market value of our natural gas swaps asset at December 31, 2009 was $19.9 million. A $0.10 increase in the future price of natural gas would result in the market value of the combined natural gas derivative asset decreasing by $0.7 million. As of December 31, 2009, the market value associated with the 2010 natural gas swap contracts is reflected as a current asset, and the market value associated with the 2010 oil swap contracts is reflected as a current liability in the accompanying consolidated balance sheet.

Item 8. Financial Statements and Supplementary Data.

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

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.

None.

Item 9A. Controls and Procedures.

Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures

Under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, we conducted an evaluation of our disclosure controls and procedures, as such term is defined under Rule 13a-15(e) promulgated under the Securities Exchange Act of 1934, as amended (the Exchange Act). Based on this evaluation, the Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of December 31, 2010, the end of the period covered by this Annual Report.

Management’s Report on Internal Control over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f). Under the supervision and with the participation of management, including our Chief Executive Officer and Chief Financial Officer, an evaluation of the effectiveness of our internal control over financial reporting was conducted based on the framework in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on that evaluation under the framework in Internal Control – Integrated Framework issued by the COSO, our management concluded that our internal control over financial reporting was effective as of December 31, 2010.

An assessment of the effectiveness of our internal control over financial reporting as of December 31, 2010, has been performed by Ernst & Young LLP, an independent registered public accounting firm, as stated in their report which is included herein.

Changes in Internal Control over Financial Reporting

There were no changes in our internal control over financial reporting during the fiscal quarter ending December 31, 2010, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Item 9B. Other Information.

In connection with the preparation of our financial statements for the period ended December 31, 2010, we determined that a charge of approximately $40.7 million for the partial impairment of Maritech oil

and gas properties was required. The impairment charge primarily resulted from the impact of increased estimated asset retirement obligations during the fourth quarter of 2010. The oil and gas property impairment charge will not result in future capital expenditures. The disclosure set forth in this Item 9B is included in this Annual Report on Form 10-K in accordance with instructions to Item 2.06 of Form 8-K.

PART III

Item 10. Directors, Executive Officers, and Corporate Governance.

The information required by this Item is hereby incorporated by reference from the information appearing under the captions “Proposal No. 1: Election of Directors,” “Executive Officers,” “Corporate Governance,” “Board Meetings and Committees,” and “Section 16(a) Beneficial Ownership Reporting Compliance” in our definitive proxy statement (the Proxy Statement) for the annual meeting of stockholders to be held on May 3, 2011, which involves the election of directors and is to be filed with the Securities and Exchange Commission (SEC) pursuant to the Securities Exchange Act of 1934 as amended (the Exchange Act) within 120 days of the end of our fiscal year on December 31, 2010.

Item 11. Executive Compensation.

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

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.

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

Item 13. Certain Relationships and Related Transactions, and Director Independence.

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

Item 14. Principal Accounting Fees and Services.

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

PART IV

Item 15. Exhibits and Financial Statement Schedules.

(a) List of documents filed as part of this Report

1.	Financial Statements of the Company
		Page
	Reports of Independent Registered Public Accounting Firm	F-1
	Consolidated Balance Sheets at December 31, 2010 and 2009	F-3
	Consolidated Statements of Operations for the years ended December 31, 2010, 2009, and 2008	F-5
	Consolidated Statements of Stockholders’ Equity for the years ended December 31, 2010, 2009, and 2008	F-6
	Consolidated Statements of Cash Flows for the years ended December 31, 2010, 2009, and 2008	F-7
	Notes to Consolidated Financial Statements	F-8
2.	Financial statement schedules have been omitted as they are not required, are not applicable, or the required information is included in the financial statements or notes thereto.
3.	List of Exhibits

	3.1	Restated Certificate of Incorporation of TETRA Technologies, Inc. (incorporated by reference to Exhibit 3.1 to the Company’s Registration Statement on Form S-4 filed on December 27, 1995 (SEC File No. 33-80881)).
	3.2	Certificate of Amendment of Restated Certificate of Incorporation of TETRA Technologies, Inc. (incorporated by reference to Exhibit 3.1 to the Company’s Registration Statement on Form S-4 filed on December 27, 1995 (SEC File No. 33-80881)).
	3.3	Certificate of Amendment of Restated Certificate of Incorporation of TETRA Technologies, Inc. (incorporated by reference to Exhibit 3.1(ii) to the Company’s Annual Report on Form 10-K for the year ended December 31, 2003 filed on March 15, 2004 (SEC File No. 001-13455)).
	3.4	Certificate of Amendment of Restated Certificate of Incorporation of TETRA Technologies, Inc. (incorporated by reference to Exhibit 4.4 to the Company’s Registration Statement on Form S-4 filed on May 25, 2004 (SEC File No. 333-115859)).
	3.5	Certificate of Amendment of Restated Certificate of Incorporation of TETRA Technologies, Inc. (incorporated by reference to Exhibit 4.5 to the Company’s Registration Statement on Form S-8 filed on May 4, 2006 (SEC File No. 333-133790)).
	3.6	Certificate of Designation of Series One Junior Participating Preferred Stock of the Company dated October 27, 1998 (incorporated by reference to Exhibit 2 to the Company’s Registration Statement on Form 8-A filed on October 28, 1998 (SEC File No. 001-13455)).
	3.7	Amended and Restated Bylaws of TETRA Technologies, Inc. (incorporated by reference to Exhibit 4.6 to the Company’s Registration Statement on Form S-8 filed on May 4, 2006 (SEC File No. 333-133790)).
	4.1	Rights Agreement dated October 26, 1998 between the Company and Computershare Investor Services LLC (as successor in interest to Harris Trust & Savings Bank), as Rights Agent (incorporated by reference to Exhibit 1 to the Company’s Registration Statement on Form 8-A filed on October 28, 1998 (SEC File No. 001-13455)).
	4.2	Master Note Purchase Agreement, dated September 27, 2004 by and among TETRA Technologies, Inc. and Jackson National Life Insurance Company, Massachusetts Mutual Life Insurance Company, C.M. Life Insurance Company, Allstate Life Insurance Company, Teachers Insurance and Annuity Association of America, Pacific Life Insurance Company, the Prudential Assurance Company Limited (PAC), and Panther CDO II, B.V. (incorporated by reference to Exhibit 4.1 to the Company’s Form 8-K filed on September 30, 2004 (SEC File No. 001-13455)).
	4.3	Form of 5.07% Senior Notes, Series 2004-A, due September 30, 2011 (incorporated by reference to Exhibit 4.2 to the Company’s Form 8-K filed on September 30, 2004 (SEC File No. 001-13455)).

	4.4	Form of 4.79% Senior Notes, Series 2004-B, due September 30, 2011 (incorporated by reference to Exhibit 4.3 to the Company’s Form 8-K filed on September 30, 2004 (SEC File No. 001-13455)).
	4.5	Form of Subsidiary Guaranty dated September 27, 2004, executed by TETRA Applied Holding Company, TETRA International Incorporated, TETRA Micronutrients, Inc., TETRA Process Services, Inc., TETRA Thermal, Inc., Maritech Resources, Inc., Seajay Industries, Inc., TETRA Investment Holding Co., Inc., TETRA Financial Services, Inc., Compressco, Inc., Providence Natural Gas, Inc., TETRA Applied LP, LLC, TETRA Applied GP, LLC, TETRA Production Testing GP, LLC, TPS Holding Company, LLC, T Production Testing, LLC, TETRA Real Estate, LLC, TETRA Real Estate, LP, Compressco Testing, L.L.C., Compressco Field Services, Inc., TETRA Production Testing Services, L.P., and TETRA Applied Technologies, L. P., for the benefit of the holders of the Notes (incorporated by reference to Exhibit 4.4 to the Company’s Form 8-K filed on September 30, 2004 (SEC File No. 001-13455)).
	4.6	First Supplement to Master Note Purchase Agreement, dated April 18, 2006, by and among TETRA Technologies, Inc. and Jackson National Life Insurance Company, Allianz Life Insurance Company of North America, United of Omaha Life Insurance Company, Mutual of Omaha Insurance Company, CUNA Mutual Life Insurance Company, CUNA Mutual Insurance Society, CUMIS Insurance Society, Inc., Members Life Insurance Company, and Modern Woodmen of America, attaching the form of the 5.90% Senior Notes, Series 2006-A, due April 30, 2016 as an exhibit thereto (incorporated by reference to Exhibit 4.1 to the Company’s Form 8-K filed on April 20, 2006 (SEC File No. 001-13455)).
	4.7	Note Purchase Agreement, dated April 30, 2008, by and among TETRA Technologies, Inc. and The Prudential Insurance Company of America, Physicians Mutual Insurance Company, The Lincoln National Life Insurance Company, The Guardian Life Insurance Company of America, The Guardian Insurance & Annuity Company, Inc., Massachusetts Mutual Life Insurance Company, Hakone Fund II LLC, C.M. Life Insurance Company, Pacific Life Insurance Company, United of Omaha Life Insurance Company, Companion Life Insurance Company, United World Life Insurance Company, Country Life Insurance Company, The Ohio National Life Insurance Company and Ohio National Life Assurance Corporation (incorporated by reference to Exhibit 4.1 to the Company’s Form 8-K filed on May 5, 2008 (SEC File No. 001-13455)).
	4.8	First Amendment to Rights Agreement dated as of November 6, 2008, by and between TETRA Technologies, Inc. and Computershare Trust Company, N.A. (as successor rights agent to Harris Trust and Savings Bank), as Rights Agent (incorporated by reference to Exhibit 4.1 to the Company’s Form 8-K filed on November 6, 2008 (SEC File No. 001-13455)).
	4.9	Form of 6.30% Senior Notes, Series 2008-A, due April 30, 2013 (incorporated by reference to Exhibit 4.2 to the Company’s Form 8-K filed on May 5, 2008 (SEC File No. 001-13455)).
	4.10	Form of 6.56% Senior Notes, Series 2008-B, due April 30, 2015 (incorporated by reference to Exhibit 4.3 to the Company’s Form 8-K filed on May 5, 2008 (SEC File No. 001-13455)).
	4.11	Form of Subsidiary Guarantee dated as of April 30, 2008, executed by Beacon Resources, LLC, Compressco Field Services, Inc., EPIC Diving and Marine Services, LLC, Maritech Resources, Inc., TETRA Applied Technologies, LLC, TETRA International Incorporated, TETRA Process Services, L.C., TETRA Production Testing Services, LLC, and Maritech Timbalier Bay, LP, for the benefit of the holders of the Notes (incorporated by reference to Exhibit 4.4 to the Company’s Form 8-K filed on May 5, 2008 (SEC File No. 0001-13455)).
	4.12	Note Purchase Agreement, dated September 30, 2010, by and among TETRA Technologies, Inc. and The Lincoln National Life Insurance Company, Teachers Insurance and Annuity Association of America, Wells Fargo Bank, N.A., The Guardian National Life Insurance Company of America, The Guardian Insurance & Annuity Company, Inc., Southern Farm Bureau Life Insurance Company, Primerica Life Insurance Company, Prime Reinsurance Company, Inc., Senior Health Insurance Company of Pennsylvania, The Union Central Life Insurance Company, Ameritas Life Insurance Corp., Acacia Life Insurance Company and First Ameritas Life Insurance Corp. of New York (incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K filed on October 8, 2010 (SEC File No. 001-13455)).
	4.13	Form of 5.09% Senior Notes, Series 2010-A, due December 15, 2017 (incorporated by reference to Exhibit 4.2 to the Company’s Current Report on Form 8-K filed on October 8, 2010 (SEC File No. 001-13455)).
	4.14	Form of 5.67% Senior Notes, Series 2010-B, due December 15, 2020 (incorporated by reference to Exhibit 4.3 to the Company’s Current Report on Form 8-K filed on October 8, 2010 (SEC File No. 001-13455)).
	10.1***	1990 Stock Option Plan, as amended through January 5, 2001 (incorporated by reference to Exhibit 10.8 to the Company’s Form 10-K for the year ended December 31, 2000 filed on March 30, 2001 (SEC File No. 001-13455)).

	10.2***	Director Stock Option Plan (incorporated by reference to Exhibit 10.9 to the Company’s Form 10-K for the year ended December 31, 2000 filed on March 30, 2001 (SEC File No. 001-13455)).
	10.3***	1998 Director Stock Option Plan (incorporated by reference to Exhibit 10.10 to the Company’s Form 10-K for the year ended December 31, 2000 filed on March 23, 2001 (SEC File No. 001-13455)).
	10.4***	1996 Stock Option Plan for Nonexecutive Employees and Consultants (incorporated by reference to Exhibit 99.1 to the Company’s Registration Statement on Form S-8 filed on November 19, 1997 (SEC File No. 333-61988)).
	10.6***	1998 Director Stock Option Plan (incorporated by reference to Exhibit 10.8 to the Company’s Form 10-K for the year ended December 31, 2002 filed on March 28, 2003 (SEC File No. 001-13455)).
	10.7***	Agreement between TETRA Technologies, Inc. and Geoffrey M. Hertel, dated February 26, 1993 (incorporated by reference to Exhibit 10.2 to the Company’s Form 8-K filed on January 7, 2005 (SEC File No. 001-13455)).
	10.8***	Form of Incentive Stock Option Agreement, dated as of December 28, 2004 (incorporated by reference to Exhibit 10.1 to the Company’s Form 8-K filed on January 7, 2005 SEC File No. 001-13455)).
	10.9***	TETRA Technologies, Inc. 2006 Equity Incentive Compensation Plan (incorporated by reference to Exhibit 4.12 to the Company’s Registration Statement on Form S-8 filed on May 4, 2006 (SEC File No. 333-133790)).
	10.10***	Forms of Employee Incentive Stock Option Agreement, Employee Nonqualified Stock Option Agreement, and Employee Restricted Stock Agreement under the TETRA Technologies, Inc. 2006 Equity Incentive Compensation Plan (incorporated by reference to Exhibits 10.1, 10.2, and 10.3 to the Company’s Form 8-K filed on May 8, 2006 (SEC File No. 001-13455)).
	10.11+***	Summary Description of the Compensation of Non-Employee Directors of TETRA Technologies, Inc.
	10.12+***	Summary Description of Named Executive Officer Compensation.
	10.13	Purchase and Sale Agreement by and between Pioneer Natural Resources USA, Inc. as Seller and Maritech Resources, Inc. as Purchaser, dated July 7, 2005 (incorporated by reference to Exhibit 10.1 to the Company’s Form 10-Q filed on November 9, 2005 (SEC File No. 001-13455), certain portions of this exhibit have been omitted pursuant to a confidential treatment request filed with the Securities and Exchange Commission).
	10.14***	Nonqualified Stock Option Agreement between TETRA Technologies, Inc. and Stuart M. Brightman, dated April 20, 2005 (incorporated by reference to Exhibit 10.1 to the Company’s Form 8-K filed on April 22, 2005 (SEC File No. 001-13455)).
	10.15***	First Amendment to the TETRA Technologies, Inc. 1998 Director Stock Option Plan (As Amended Through June 27, 2003), dated December 16, 2005 (incorporated by reference to Exhibit 10.1 to the Company’s Form 8-K filed on December 22, 2005 (SEC File No. 001-13455)).
	10.16***	Form of Stock Option Agreement under the TETRA Technologies, Inc. 1998 Director Stock Option Plan (As Amended Through June 27, 2003), as further amended by the First Amendment to the TETRA Technologies, Inc. 1998 Director Stock Option Plan (As Amended Through June 27, 2003) (incorporated by reference to Exhibit 10.2 to the Company’s Form 8-K filed on December 22, 2005 (SEC File No. 001-13455)).
	10.17	Credit Agreement, as amended and restated, dated as of June 27, 2006, among TETRA Technologies, Inc. and certain of its subsidiaries, as borrowers, JPMorgan Chase Bank, N.A., as administrative agent, Bank of America, National Association and Wells Fargo Bank, N.A., as syndication agents, and Comerica Bank, as documentation agent, and the lenders party thereto (incorporated by reference to Exhibit 10.1 to the Company’s Form 8-K filed on June 30, 2006 (SEC File No. 001-13455)).
	10.18	Agreement and First Amendment to Credit Agreement, dated as of December 15, 2006, among TETRA Technologies, Inc. and certain of its subsidiaries, as borrowers, JPMorgan Chase Bank, N.A., as administrative agent, Bank of America, National Association and Wells Fargo Bank, N.A., as syndication agents, and Comerica Bank, as documentation agent, and the lenders party thereto (incorporated by reference to Exhibit 10.1 to the Company’s Form 8-K filed on January 10, 2007 (SEC File No. 001-13455)).
	10.19***	TETRA Technologies, Inc. Nonqualified Deferred Compensation Plan (incorporated by reference to Exhibit 10.9 to the Company’s Form 10-Q filed on August 13, 2002 (SEC File No. 001-13455)).
	10.20***	TETRA Technologies, Inc. Nonqualified Deferred Compensation Plan and The Executive Excess Plan Adoption Agreement effective on June 30, 2005 (incorporated by reference to Exhibit 10.2 to the Company’s Form 10-Q/A filed on March 16, 2006 (SEC File No. 001-13455)).

	10.21***	TETRA Technologies, Inc. 2007 Equity Incentive Compensation Plan (incorporated by reference to Exhibit 4.12 to the Company’s Registration Statement on Form S-8 filed on May 4, 2007 (SEC File No. 333-142637)).
	10.22***	Forms of Employee Incentive Stock Option Agreement, Employee Nonqualified Stock Option Agreement, and Employee Restricted Stock Agreement under the TETRA Technologies, Inc. 2007 Equity Incentive Compensation Plan (incorporated by reference to Exhibits 4.13, 4.14, and 4.15 to the Company’s Registration Statement on Form S-8 filed on May 4, 2007 (SEC File No. 333-142637)).
	10.23***	TETRA Technologies, Inc. 401(k) Retirement Plan, as amended and restated (incorporated by reference to Exhibit 99.1 to the Company’s Registration Statement on Form S-8 filed on February 22, 2008 (SEC File No. 333-149348)).
	10.24***	Employee Restricted Stock Agreement between TETRA Technologies, Inc. and Philip N. Longorio, dated February 22, 2008 (incorporated by reference to Exhibit 4.12 to the Company’s Registration Statement on Form S-8 filed on February 22, 2008 (SEC File No. 333-149347)).
	10.25***	TETRA Technologies, Inc. Amended and Restated 2007 Equity Incentive Compensation Plan (incorporated by reference to Exhibit 4.12 to the Company’s Registration Statement on Form S-8 filed on May 9, 2008 (SEC File No. 333-150783)).
	10.26***	Form of Employee Incentive Stock Option Agreement under the TETRA Technologies, Inc. Amended and Restated 2007 Equity Incentive Compensation Plan (incorporated by reference to Exhibit 4.13 to the Company’s Registration Statement on Form S-8 filed on May 9, 2008 (SEC File No. 333-150783)).
	10.27***	Form of Employee Nonqualified Stock Option Agreement under the TETRA Technologies, Inc. Amended and Restated 2007 Equity Incentive Compensation Plan (incorporated by reference to Exhibit 4.14 to the Company’s Registration Statement on Form S-8 filed on May 9, 2008 (SEC File No. 333-150783)).
	10.28***	Form of Employee Restricted Stock Agreement under the TETRA Technologies, Inc. Amended and Restated 2007 Equity Incentive Compensation Plan (incorporated by reference to Exhibit 4.15 to the Company’s Registration Statement on Form S-8 filed on May 9, 2008 (SEC File No. 333-150783)).
	10.29***	Form of Non-Employee Director Restricted Stock Agreement under the TETRA Technologies, Inc. Amended and Restated 2007 Equity Incentive Compensation Plan (incorporated by reference to Exhibit 4.16 to the Company’s Registration Statement on Form S-8 filed on May 9, 2008 (SEC File No. 333-150783)).
	10.30***	Transition Agreement effective as of May 5, 2009, by and among TETRA Technologies, Inc. and Geoffrey M. Hertel (incorporated by reference to Exhibit 10.1 to the Company’s Form 8-K filed on May 8, 2009 (SEC File No. 001-13455)).
	10.31	Form of Senior Indenture (including form of senior debt security) (incorporated by reference to Exhibit 4.21 to the Company’s Registration Statement on Form S-3 filed on November 30, 2009 (SEC File No. 333-163409)).
	10.32	Form of Subordinated Indenture (including form of subordinated debt security) (incorporated by reference to Exhibit 4.22 to the Company’s Registration Statement on Form S-3 filed on November 30, 2009 (SEC File No. 333-163409)).
	10.33***	TETRA Technologies, Inc. Cash Incentive Compensation Plan (incorporated by reference to Exhibit 4.1 to the Company’s Form 10-Q filed on May 10, 2010 (SEC File No. 001-13455)).
	10.34***	TETRA Technologies, Inc. 2007 Long Term Incentive Compensation Plan (incorporated by reference to Exhibit 4.11 to the Company’s Registration Statement on Form S-8 filed on May 5, 2010 (SEC File No. 333-166537)).
	10.35***	Form of Employee Incentive Stock Option Agreement under the TETRA Technologies, Inc. 2007 Long Term Incentive Compensation Plan (incorporated by reference to Exhibit 4.12 to the Company’s Registration Statement on Form S-8 filed on May 5, 2010 (SEC File No. 333-166537)).
	10.36***	Form of Employee Nonqualified Stock Option Agreement under the TETRA Technologies, Inc. 2007 Long Term Incentive Compensation Plan (incorporated by reference to Exhibit 4.13 to the Company’s Registration Statement on Form S-8 filed on May 5, 2010 (SEC File No. 333-166537)).
	10.37***	Form of Employee Restricted Stock Agreement under the TETRA Technologies, Inc. 2007 Long Term Incentive Compensation Plan (incorporated by reference to Exhibit 4.14 to the Company’s Registration Statement on Form S-8 filed on May 5, 2010 (SEC File No. 333-166537)).
	10.38***	Form of Non-Employee Consultant Nonqualified Stock Option Agreement under the TETRA Technologies, Inc. 2007 Long Term Incentive Compensation Plan (incorporated by reference to Exhibit 4.15 to the Company’s Registration Statement on Form S-8 filed on May 5, 2010 (SEC File No. 333-166537)).

	10.39***	Form of Non-Employee Consultant Restricted Stock Agreement under the TETRA Technologies, Inc. 2007 Long Term Incentive Compensation Plan (incorporated by reference to Exhibit 4.16 to the Company’s Registration Statement on Form S-8 filed on May 5, 2010 (SEC File No. 333-166537)).
	10.40***	Form of Non-Employee Director Restricted Stock Agreement under the TETRA Technologies, Inc. 2007 Long Term Incentive Compensation Plan (incorporated by reference to Exhibit 4.17 to the Company’s Registration Statement on Form S-8 filed on May 5, 2010 (SEC File No. 333-166537)).
	10.41	Agreement and Second Amendment to Credit Agreement dated as of October 29, 2010, among TETRA Technologies, Inc. and certain of its subsidiaries, as borrowers, JPMorgan Chase Bank, N.A., as administrative agent, Bank of America, National Association and Wells Fargo Bank, N.A. as syndication agents, and Comerica Bank, as documentation agent, and the lenders party thereto (incorporated by reference to Exhibit 10.1 to the Company’s Form 8-K filed on November 3, 2010 (SEC File No. 001-13455)).
	10.42+***	Retention Agreement effective as of November 2, 2010, by and among TETRA Technologies, Inc. and Edgar A. Anderson.
	21+	Subsidiaries of the Company.
	23.1+	Consent of Ernst & Young, LLP.
	23.2+	Consent of Ryder Scott Company, L.P.
	23.3+	Consent of DeGolyer and MacNaughton.
	31.1+	Certification Pursuant to Rule 13(a)-14(a) or 15(d)-14(a) of the Exchange Act, As Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
	31.2+	Certification Pursuant to Rule 13(a)-14(a) or 15(d)-14(a) of the Exchange Act, As Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
	32.1**	Certification Furnished Pursuant to 18 U.S.C. Section 1350, As Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Chief Executive Officer).
	32.2**	Certification Furnished Pursuant to 18 U.S.C. Section 1350, As Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Chief Financial Officer).
	99.1+	Report of Ryder Scott Company, L.P.
	99.2+	Report of DeGolyer and MacNaughton.
	101.INS++	XBRL Instance Document.
	101.SCH++	XBRL Taxonomy Extension Schema Document.
	101.CAL++	XBRL Taxonomy Extension Calculation Linkbase Document.
	101.LAB++	XBRL Taxonomy Extension Label Linkbase Document.
	101.PRE++	XBRL Taxonomy Extension Presentation Linkbase Document.
	101.DEF++	XBRL Taxonomy Extension Definition Linkbase Document.

+	Filed with this report.
**	Furnished with this report.
***	Management contract or compensatory plan or arrangement.
++	Attached as Exhibit 101 to this report are the following documents formatted in XBRL (Extensible Business Reporting Language): (i) Consolidated Statements of Operations for the years ended December 31, 2010, 2009 and 2008; (ii) Consolidated Balance Sheets as of December 31, 2010 and December 31, 2009; (iii) Consolidated Statements of Cash Flows for the years ended December 31, 2010, 2009 and 2008; (iv) Consolidated Statements of Stockholders’ Equity for the years ended December 31, 2010, 2009 and 2008; and (v) Notes to Consolidated Financial Statements for the year ended December 31, 2010. Users of this data are advised pursuant to Rule 406T of Regulation S-T that the interactive data files in Exhibit 101 to this Annual Report on Form 10-K shall not be “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to the liabilities of that section, and shall not be part of any registration statement or other document filed under the Securities Act of 1933, as amended, or the Securities Exchange Act of 1934, as amended, except as shall be expressly set forth by specific reference in such filing.

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, TETRA Technologies, Inc. has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

	TETRA Technologies, Inc.

Date: March 1, 2011	By:	/s/Stuart M. Brightman
		Stuart M. Brightman, President & CEO

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated:

Signature	Title	Date
/s/Ralph S. Cunningham	Chairman of	March 1, 2011
Ralph S. Cunningham	the Board of Directors

/s/Stuart M. Brightman	President, Chief Executive	March 1, 2011
Stuart M. Brightman	Officer and Director
	(Principal Executive Officer)

/s/Joseph M. Abell	Senior Vice President and	March 1, 2011
Joseph M. Abell	Chief Financial Officer
	(Principal Financial Officer)

/s/Ben C. Chambers	Vice President – Accounting	March 1, 2011
Ben C. Chambers	and Controller
	(Principal Accounting Officer)

/s/Paul D. Coombs	Director	March 1, 2011
Paul D. Coombs

/s/Tom H. Delimitros	Director	March 1, 2011
Tom H. Delimitros

/s/Geoffrey M. Hertel	Director	March 1, 2011
Geoffrey M. Hertel

/s/Allen T. McInnes	Director	March 1, 2011
Allen T. McInnes

/s/Kenneth P. Mitchell	Director	March 1, 2011
Kenneth P. Mitchell

/s/William D. Sullivan	Director	March 1, 2011
William D. Sullivan

/s/Kenneth E. White, Jr.	Director	March 1, 2011
Kenneth E. White, Jr.

EXHIBIT INDEX

3.1	Restated Certificate of Incorporation of TETRA Technologies, Inc. (incorporated by reference to Exhibit 3.1 to the Company’s Registration Statement on Form S-4 filed on December 27, 1995 (SEC File No. 33-80881)).
3.2	Certificate of Amendment of Restated Certificate of Incorporation of TETRA Technologies, Inc. (incorporated by reference to Exhibit 3.1 to the Company’s Registration Statement on Form S-4 filed on December 27, 1995 (SEC File No. 33-80881)).
3.3	Certificate of Amendment of Restated Certificate of Incorporation of TETRA Technologies, Inc. (incorporated by reference to Exhibit 3.1(ii) to the Company’s Annual Report on Form 10-K for the year ended December 31, 2003 filed on March 15, 2004 (SEC File No. 001-13455)).
3.4	Certificate of Amendment of Restated Certificate of Incorporation of TETRA Technologies, Inc. (incorporated by reference to Exhibit 4.4 to the Company’s Registration Statement on Form S-4 filed on May 25, 2004 (SEC File No. 333-115859)).
3.5	Certificate of Amendment of Restated Certificate of Incorporation of TETRA Technologies, Inc. (incorporated by reference to Exhibit 4.5 to the Company’s Registration Statement on Form S-8 filed on May 4, 2006 (SEC File No. 333-133790)).
3.6	Certificate of Designation of Series One Junior Participating Preferred Stock of the Company dated October 27, 1998 (incorporated by reference to Exhibit 2 to the Company’s Registration Statement on Form 8-A filed on October 28, 1998 (SEC File No. 001-13455)).
3.7	Amended and Restated Bylaws of TETRA Technologies, Inc. (incorporated by reference to Exhibit 4.6 to the Company’s Registration Statement on Form S-8 filed on May 4, 2006 (SEC File No. 333-133790)).
4.1	Rights Agreement dated October 26, 1998 between the Company and Computershare Investor Services LLC (as successor in interest to Harris Trust & Savings Bank), as Rights Agent (incorporated by reference to Exhibit 1 to the Company’s Registration Statement on Form 8-A filed on October 28, 1998 (SEC File No. 001-13455)).
4.2	Master Note Purchase Agreement, dated September 27, 2004 by and among TETRA Technologies, Inc. and Jackson National Life Insurance Company, Massachusetts Mutual Life Insurance Company, C.M. Life Insurance Company, Allstate Life Insurance Company, Teachers Insurance and Annuity Association of America, Pacific Life Insurance Company, the Prudential Assurance Company Limited (PAC), and Panther CDO II, B.V. (incorporated by reference to Exhibit 4.1 to the Company’s Form 8-K filed on September 30, 2004 (SEC File No. 001-13455)).
4.3	Form of 5.07% Senior Notes, Series 2004-A, due September 30, 2011 (incorporated by reference to Exhibit 4.2 to the Company’s Form 8-K filed on September 30, 2004 (SEC File No. 001-13455)).
4.4	Form of 4.79% Senior Notes, Series 2004-B, due September 30, 2011 (incorporated by reference to Exhibit 4.3 to the Company’s Form 8-K filed on September 30, 2004 (SEC File No. 001-13455)).
4.5	Form of Subsidiary Guaranty dated September 27, 2004, executed by TETRA Applied Holding Company, TETRA International Incorporated, TETRA Micronutrients, Inc., TETRA Process Services, Inc., TETRA Thermal, Inc., Maritech Resources, Inc., Seajay Industries, Inc., TETRA Investment Holding Co., Inc., TETRA Financial Services, Inc., Compressco, Inc., Providence Natural Gas, Inc., TETRA Applied LP, LLC, TETRA Applied GP, LLC, TETRA Production Testing GP, LLC, TPS Holding Company, LLC, T Production Testing, LLC, TETRA Real Estate, LLC, TETRA Real Estate, LP, Compressco Testing, L.L.C., Compressco Field Services, Inc., TETRA Production Testing Services, L.P., and TETRA Applied Technologies, L. P., for the benefit of the holders of the Notes (incorporated by reference to Exhibit 4.4 to the Company’s Form 8-K filed on September 30, 2004 (SEC File No. 001-13455)).
4.6	First Supplement to Master Note Purchase Agreement, dated April 18, 2006, by and among TETRA Technologies, Inc. and Jackson National Life Insurance Company, Allianz Life Insurance Company of North America, United of Omaha Life Insurance Company, Mutual of Omaha Insurance Company, CUNA Mutual Life Insurance Company, CUNA Mutual Insurance Society, CUMIS Insurance Society, Inc., Members Life Insurance Company, and Modern Woodmen of America, attaching the form of the 5.90% Senior Notes, Series 2006-A, due April 30, 2016 as an exhibit thereto (incorporated by reference to Exhibit 4.1 to the Company’s Form 8-K filed on April 20, 2006 (SEC File No. 001-13455)).
4.7	Note Purchase Agreement, dated April 30, 2008, by and among TETRA Technologies, inc. and The Prudential Insurance Company of America, Physicians Mutual Insurance Company, The Lincoln National Life Insurance Company, The Guardian Life Insurance Company of America, The Guardian Insurance & Annuity Company, Inc., Massachusetts Mutual Life Insurance Company, Hakone Fund II LLC, C.M. Life Insurance Company, Pacific Life Insurance Company, United of Omaha Life Insurance Company, Companion Life Insurance Company, United World Life Insurance Company, Country Life Insurance Company, The Ohio National Life Insurance Company and Ohio National Life Assurance Corporation (incorporated by reference to Exhibit 4.1 to the Company’s Form 8-K filed on May 5, 2008 (SEC File No. 001-13455)).
4.8	First Amendment to Rights Agreement dated as of November 6, 2008, by and between TETRA Technologies, Inc. and Computershare Trust Company, N.A. (as successor rights agent to Harris Trust and Savings Bank), as Rights Agent (incorporated by reference to Exhibit 4.1 to the Company’s Form 8-K filed on November 6, 2008 (SEC File No. 001-13455)).
4.9	Form of 6.30% Senior Notes, Series 2008-A, due April 30, 2013 (incorporated by reference to Exhibit 4.2 to the Company’s Form 8-K filed on May 5, 2008 (SEC File No. 001-13455)).
4.10	Form of 6.56% Senior Notes, Series 2008-B, due April 30, 2015 (incorporated by reference to Exhibit 4.3 to the Company’s Form 8-K filed on May 5, 2008 (SEC File No. 001-13455)).
4.11	Form of Subsidiary Guarantee dated as of April 30, 2008, executed by Beacon Resources, LLC, Compressco Field Services, Inc., EPIC Diving and Marine Services, LLC, Maritech Resources, Inc., TETRA Applied Technologies, LLC, TETRA International Incorporated, TETRA Process Services, L.C., TETRA Production Testing Services, LLC, and Maritech Timbalier Bay, LP, for the benefit of the holders of the Notes (incorporated by reference to Exhibit 4.4 to the Company’s Form 8-K filed on May 5, 2008 (SEC File No. 0001-13455)).
4.12	Note Purchase Agreement, dated September 30, 2010, by and among TETRA Technologies, Inc. and The Lincoln National Life Insurance Company, Teachers Insurance and Annuity Association of America, Wells Fargo Bank, N.A., The Guardian National Life Insurance Company of America, The Guardian Insurance & Annuity Company, Inc., Southern Farm Bureau Life Insurance Company, Primerica Life Insurance Company, Prime Reinsurance Company, Inc., Senior Health Insurance Company of Pennsylvania, The Union Central Life Insurance Company, Ameritas Life Insurance Corp., Acacia Life Insurance Company and First Ameritas Life Insurance Corp. of New York (incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K filed on October 8, 2010 (SEC File No. 001-13455)).
4.13	Form of 5.09% Senior Notes, Series 2010-A, due December 15, 2017 (incorporated by reference to Exhibit 4.2 to the Company’s Current Report on Form 8-K filed on October 8, 2010 (SEC File No. 001-13455)).
4.14	Form of 5.67% Senior Notes, Series 2010-B, due December 15, 2020 (incorporated by reference to Exhibit 4.3 to the Company’s Current Report on Form 8-K filed on October 8, 2010 (SEC File No. 001-13455)).
10.1***	1990 Stock Option Plan, as amended through January 5, 2001 (incorporated by reference to Exhibit 10.8 to the Company’s Form 10-K for the year ended December 31, 2000 filed on March 30, 2001 (SEC File No. 001-13455)).
10.2***	Director Stock Option Plan (incorporated by reference to Exhibit 10.9 to the Company’s Form 10-K for the year ended December 31, 2000 filed on March 30, 2001 (SEC File No. 001-13455)).
10.3***	1998 Director Stock Option Plan (incorporated by reference to Exhibit 10.10 to the Company’s Form 10-K for the year ended December 31, 2000 filed on March 23, 2001 (SEC File No. 001-13455)).
10.4***	1996 Stock Option Plan for Nonexecutive Employees and Consultants (incorporated by reference to Exhibit 99.1 to the Company’s Registration Statement on Form S-8 filed on November 19, 1997 (SEC File No. 333-61988)).
10.6***	1998 Director Stock Option Plan (incorporated by reference to Exhibit 10.8 to the Company’s Form 10-K for the year ended December 31, 2002 filed on March 28, 2003 (SEC File No. 001-13455)).
10.7***	Agreement between TETRA Technologies, Inc. and Geoffrey M. Hertel, dated February 26, 1993 (incorporated by reference to Exhibit 10.2 to the Company’s Form 8-K filed on January 7, 2005 (SEC File No. 001-13455)).
10.8***	Form of Incentive Stock Option Agreement, dated as of December 28, 2004 (incorporated by reference to Exhibit 10.1 to the Company’s Form 8-K filed on January 7, 2005 SEC File No. 001-13455)).
10.9***	TETRA Technologies, Inc. 2006 Equity Incentive Compensation Plan (incorporated by reference to Exhibit 4.12 to the Company’s Registration Statement on Form S-8 filed on May 4, 2006 (SEC File No. 333-133790)).
10.10***	Forms of Employee Incentive Stock Option Agreement, Employee Nonqualified Stock Option Agreement, and Employee Restricted Stock Agreement under the TETRA Technologies, Inc. 2006 Equity Incentive Compensation Plan (incorporated by reference to Exhibits 10.1, 10.2, and 10.3 to the Company’s Form 8-K filed on May 8, 2006 (SEC File No. 001-13455)).
10.11+***	Summary Description of the Compensation of Non-Employee Directors of TETRA Technologies, Inc.
10.12+***	Summary Description of Named Executive Officer Compensation.
10.13	Purchase and Sale Agreement by and between Pioneer Natural Resources USA, Inc. as Seller and Maritech Resources, Inc. as Purchaser, dated July 7, 2005 (incorporated by reference to Exhibit 10.1 to the Company’s Form 10-Q filed on November 9, 2005 (SEC File No. 001-13455), certain portions of this exhibit have been omitted pursuant to a confidential treatment request filed with the Securities and Exchange Commission).
10.14***	Nonqualified Stock Option Agreement between TETRA Technologies, Inc. and Stuart M. Brightman, dated April 20, 2005 (incorporated by reference to Exhibit 10.1 to the Company’s Form 8-K filed on April 22, 2005 (SEC File No. 001-13455)).
10.15***	First Amendment to the TETRA Technologies, Inc. 1998 Director Stock Option Plan (As Amended Through June 27, 2003), dated December 16, 2005 (incorporated by reference to Exhibit 10.1 to the Company’s Form 8-K filed on December 22, 2005 (SEC File No. 001-13455)).
10.16***	Form of Stock Option Agreement under the TETRA Technologies, Inc. 1998 Director Stock Option Plan (As Amended Through June 27, 2003), as further amended by the First Amendment to the TETRA Technologies, Inc. 1998 Director Stock Option Plan (As Amended Through June 27, 2003) (incorporated by reference to Exhibit 10.2 to the Company’s Form 8-K filed on December 22, 2005 (SEC File No. 001-13455)).
10.17	Credit Agreement, as amended and restated, dated as of June 27, 2006, among TETRA Technologies, Inc. and certain of its subsidiaries, as borrowers, JPMorgan Chase Bank, N.A., as administrative agent, Bank of America, National Association and Wells Fargo Bank, N.A., as syndication agents, and Comerica Bank, as documentation agent, and the lenders party thereto (incorporated by reference to Exhibit 10.1 to the Company’s Form 8-K filed on June 30, 2006 (SEC File No. 001-13455)).
10.18	Agreement and First Amendment to Credit Agreement, dated as of December 15, 2006, among TETRA Technologies, Inc. and certain of its subsidiaries, as borrowers, JPMorgan Chase Bank, N.A., as administrative agent, Bank of America, National Association and Wells Fargo Bank, N.A., as syndication agents, and Comerica Bank, as documentation agent, and the lenders party thereto (incorporated by reference to Exhibit 10.1 to the Company’s Form 8-K filed on January 10, 2007 (SEC File No. 001-13455)).
10.19***	TETRA Technologies, Inc. Nonqualified Deferred Compensation Plan (incorporated by reference to Exhibit 10.9 to the Company’s Form 10-Q filed on August 13, 2002 (SEC File No. 001-13455)).
10.20***	TETRA Technologies, Inc. Nonqualified Deferred Compensation Plan and The Executive Excess Plan Adoption Agreement effective on June 30, 2005 (incorporated by reference to Exhibit 10.2 to the Company’s Form 10-Q/A filed on March 16, 2006 (SEC File No. 001-13455)).
10.21***	TETRA Technologies, Inc. 2007 Equity Incentive Compensation Plan (incorporated by reference to Exhibit 4.12 to the Company’s Registration Statement on Form S-8 filed on May 4, 2007 (SEC File No. 333-142637)).
10.22***	Forms of Employee Incentive Stock Option Agreement, Employee Nonqualified Stock Option Agreement, and Employee Restricted Stock Agreement under the TETRA Technologies, Inc. 2007 Equity Incentive Compensation Plan (incorporated by reference to Exhibits 4.13, 4.14, and 4.15 to the Company’s Registration Statement on Form S-8 filed on May 4, 2007 (SEC File No. 333-142637)).
10.23***	TETRA Technologies, Inc. 401(k) Retirement Plan, as amended and restated (incorporated by reference to Exhibit 99.1 to the Company’s Registration Statement on Form S-8 filed on February 22, 2008 (SEC File No. 333-149348)).
10.24***	Employee Restricted Stock Agreement between TETRA Technologies, Inc. and Philip N. Longorio, dated February 22, 2008 (incorporated by reference to Exhibit 4.12 to the Company’s Registration Statement on Form S-8 filed on February 22, 2008 (SEC File No. 333-149347)).
10.25***	TETRA Technologies, Inc. Amended and Restated 2007 Equity Incentive Compensation Plan (incorporated by reference to Exhibit 4.12 to the Company’s Registration Statement on Form S-8 filed on May 9, 2008 (SEC File No. 333-150783)).
10.26***	Form of Employee Incentive Stock Option Agreement under the TETRA Technologies, Inc. Amended and Restated 2007 Equity Incentive Compensation Plan (incorporated by reference to Exhibit 4.13 to the Company’s Registration Statement on Form S-8 filed on May 9, 2008 (SEC File No. 333-150783)).
10.27***	Form of Employee Nonqualified Stock Option Agreement under the TETRA Technologies, Inc. Amended and Restated 2007 Equity Incentive Compensation Plan (incorporated by reference to Exhibit 4.14 to the Company’s Registration Statement on Form S-8 filed on May 9, 2008 (SEC File No. 333-150783)).
10.28***	Form of Employee Restricted Stock Agreement under the TETRA Technologies, Inc. Amended and Restated 2007 Equity Incentive Compensation Plan (incorporated by reference to Exhibit 4.15 to the Company’s Registration Statement on Form S-8 filed on May 9, 2008 (SEC File No. 333-150783)).
10.29***	Form of Non-Employee Director Restricted Stock Agreement under the TETRA Technologies, Inc. Amended and Restated 2007 Equity Incentive Compensation Plan (incorporated by reference to Exhibit 4.16 to the Company’s Registration Statement on Form S-8 filed on May 9, 2008 (SEC File No. 333-150783)).
10.30***	Transition Agreement effective as of May 5, 2009, by and among TETRA Technologies, Inc. and Geoffrey M. Hertel (incorporated by reference to Exhibit 10.1 to the Company’s Form 8-K filed on May 8, 2009 (SEC File No. 001-13455)).
10.31	Form of Senior Indenture (including form of senior debt security) (incorporated by reference to Exhibit 4.21 to the Company’s Registration Statement on Form S-3 filed on November 30, 2009 (SEC File No. 333-163409)).
10.32	Form of Subordinated Indenture (including form of subordinated debt security) (incorporated by reference to Exhibit 4.22 to the Company’s Registration Statement on Form S-3 filed on November 30, 2009 (SEC File No. 333-163409)).
10.33***	TETRA Technologies, Inc. Cash Incentive Compensation Plan (incorporated by reference to Exhibit 4.1 to the Company’s Form 10-Q filed on May 10, 2010 (SEC File No. 001-13455)).
10.34***	TETRA Technologies, Inc. 2007 Long Term Incentive Compensation Plan (incorporated by reference to Exhibit 4.11 to the Company’s Registration Statement on Form S-8 filed on May 5, 2010 (SEC File No. 333-166537)).
10.35***	Form of Employee Incentive Stock Option Agreement under the TETRA Technologies, Inc. 2007 Long Term Incentive Compensation Plan (incorporated by reference to Exhibit 4.12 to the Company’s Registration Statement on Form S-8 filed on May 5, 2010 (SEC File No. 333-166537)).
10.36***	Form of Employee Nonqualified Stock Option Agreement under the TETRA Technologies, Inc. 2007 Long Term Incentive Compensation Plan (incorporated by reference to Exhibit 4.13 to the Company’s Registration Statement on Form S-8 filed on May 5, 2010 (SEC File No. 333-166537)).
10.37***	Form of Employee Restricted Stock Agreement under the TETRA Technologies, Inc. 2007 Long Term Incentive Compensation Plan (incorporated by reference to Exhibit 4.14 to the Company’s Registration Statement on Form S-8 filed on May 5, 2010 (SEC File No. 333-166537)).
10.38***	Form of Non-Employee Consultant Nonqualified Stock Option Agreement under the TETRA Technologies, Inc. 2007 Long Term Incentive Compensation Plan (incorporated by reference to Exhibit 4.15 to the Company’s Registration Statement on Form S-8 filed on May 5, 2010 (SEC File No. 333-166537)).
10.39***	Form of Non-Employee Consultant Restricted Stock Agreement under the TETRA Technologies, Inc. 2007 Long Term Incentive Compensation Plan (incorporated by reference to Exhibit 4.16 to the Company’s Registration Statement on Form S-8 filed on May 5, 2010 (SEC File No. 333-166537)).
10.40***	Form of Non-Employee Director Restricted Stock Agreement under the TETRA Technologies, Inc. 2007 Long Term Incentive Compensation Plan (incorporated by reference to Exhibit 4.17 to the Company’s Registration Statement on Form S-8 filed on May 5, 2010 (SEC File No. 333-166537)).
10.41	Agreement and Second Amendment to Credit Agreement dated as of October 29, 2010, among TETRA Technologies, Inc. and certain of its subsidiaries, as borrowers, JPMorgan Chase Bank, N.A., as administrative agent, Bank of America, National Association and Wells Fargo Bank, N.A. as syndication agents, and Comerica Bank, as documentation agent, and the lenders party thereto (incorporated by reference to Exhibit 10.1 to the Company’s Form 8-K filed on November 3, 2010 (SEC File No. 001-13455)).
10.42+***	Retention Agreement effective as of November 2, 2010, by and among TETRA Technologies, Inc. and Edgar A. Anderson.
21+	Subsidiaries of the Company.
23.1+	Consent of Ernst & Young, LLP.
23.2+	Consent of Ryder Scott Company, L.P.
23.3+	Consent of DeGolyer and McNaughton.
31.1+	Certification Pursuant to Rule 13(a)-14(a) or 15(d)-14(a) of the Exchange Act, As Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2+	Certification Pursuant to Rule 13(a)-14(a) or 15(d)-14(a) of the Exchange Act, As Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1**	Certification Furnished Pursuant to 18 U.S.C. Section 1350, As Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Chief Executive Officer).
32.2**	Certification Furnished Pursuant to 18 U.S.C. Section 1350, As Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Chief Financial Officer).
99.1+	Report of Ryder Scott Company, L.P.
99.2+	Report of DeGolyer and MacNaughton.
101.INS++	XBRL Instance Document.
101.SCH++	XBRL Taxonomy Extension Schema Document.
101.CAL++	XBRL Taxonomy Extension Calculation Linkbase Document.
101.LAB++	XBRL Taxonomy Extension Label Linkbase Document.
101.PRE++	XBRL Taxonomy Extension Presentation Linkbase Document.
101.DEF++	XBRL Taxonomy Extension Definition Linkbase Document.

+	Filed with this report.
**	Furnished with this report.
***	Management contract or compensatory plan or arrangement.
++	Attached as Exhibit 101 to this report are the following documents formatted in XBRL (Extensible Business Reporting Language): (i) Consolidated Statements of Operations for the years ended December 31, 2010, 2009 and 2008; (ii) Consolidated Balance Sheets as of December 31, 2010 and December 31, 2009; (iii) Consolidated Statements of Cash Flows for the years ended December 31, 2010, 2009 and 2008; (iv) Consolidated Statements of Stockholders’ Equity for the years ended December 31, 2010, 2009 and 2008; and (v) Notes to Consolidated Financial Statements for the year ended December 31, 2010. Users of this data are advised pursuant to Rule 406T of Regulation S-T that the interactive data files in Exhibit 101 to this Annual Report on Form 10-K shall not be “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to the liabilities of that section, and shall not be part of any registration statement or other document filed under the Securities Act of 1933, as amended, or the Securities Exchange Act of 1934, as amended, except as shall be expressly set forth by specific reference in such filing.

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors and Stockholders of

TETRA Technologies, Inc.

We have audited the accompanying consolidated balance sheets of TETRA Technologies, Inc. and subsidiaries as of December 31, 2010 and 2009, and the related consolidated statements of operations, stockholders' equity, and cash flows for each of the three years in the period ended December 31, 2010. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of TETRA Technologies, Inc. and subsidiaries at December 31, 2010 and 2009, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2010, in conformity with U.S. generally accepted accounting principles.

As discussed in Notes B and R to the consolidated financial statements, in 2009, the Company adopted SEC Release 33-8995 and the amendments to ASC Topic 932, “Extractive Industries – Oil and Gas,” resulting from ASU 2010-03 (collectively, the Modernization Rules).

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), TETRA Technologies, Inc.’s internal control over financial reporting as of December 31, 2010, based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 1, 2011, expressed an unqualified opinion thereon.

/s/ERNST & YOUNG LLP

Houston, Texas

March 1, 2011

F-1

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors and Stockholders of

TETRA Technologies, Inc.

We have audited TETRA Technologies, Inc. and subsidiaries’ internal control over financial reporting as of December 31, 2010, based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). TETRA Technologies, Inc. and subsidiaries’ management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the company’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, TETRA Technologies, Inc. and subsidiaries maintained, in all material respects, effective internal control over financial reporting as of December 31, 2010, based on the COSO criteria.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of TETRA Technologies, Inc. and subsidiaries as of December 31, 2010 and 2009, and the related consolidated statements of operations, stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2010 of TETRA Technologies, Inc. and subsidiaries, and our report dated March 1, 2011, expressed an unqualified opinion thereon.

/s/ERNST & YOUNG LLP

Houston, Texas

March 1, 2011

F-2

TETRA Technologies, Inc. and Subsidiaries

Consolidated Balance Sheets

(In Thousands)

	December 31,
	2010			2009
ASSETS
Current assets:
Cash and cash equivalents	$	65,360		$	33,394
Restricted cash		360			266
Accounts receivable, net of allowance for doubtful accounts
of $2,590 in 2010 and $5,007 in 2009		162,405			181,038
Inventories		104,305			122,274
Derivative assets		2,436			19,926
Deferred tax assets		29,685			-
Prepaid expenses and other current assets		50,387			33,920
Total current assets		414,938			390,818

Property, plant, and equipment:
Land and building		79,368			77,246
Machinery and equipment		482,677			458,675
Automobiles and trucks		43,492			42,432
Chemical plants		176,853			94,767
Oil and gas producing assets (successful efforts method)		761,449			676,692
Construction in progress		15,677			95,470
Total property, plant, and equipment		1,559,516			1,445,282
Less accumulated depreciation and depletion		(819,646	)		(628,908	)
Net property, plant, and equipment		739,870			816,374

Other assets:
Goodwill		99,005			99,005
Patents, trademarks, and other intangible assets, net of
accumulated amortization of $21,499 in 2010 and $18,997 in 2009		13,024			13,198
Deferred tax assets		899			1,342
Other assets		31,892			26,862
Total other assets		144,820			140,407
Total assets	$	1,299,628		$	1,347,599

See Notes to Consolidated Financial Statements

F-3

TETRA Technologies, Inc. and Subsidiaries

Consolidated Balance Sheets

(In Thousands, Except Per Share Amounts)

	December 31,
	2010			2009
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Trade accounts payable	$	55,555		$	57,418
Accrued liabilities		83,804			84,655
Decommissioning and other asset retirement obligations, current		72,265			77,891
Deferred tax liabilities		-			19,893
Derivative liabilities		5,208			2,618
Total current liabilities		216,832			242,475

Long-term debt, net		305,035			310,132
Deferred income taxes		46,789			56,125
Decommissioning and other asset retirement obligations, net		200,550			146,219
Other liabilities		14,099			16,154
Total long-term and other liabilities		566,473			528,630

Commitments and contingencies

Stockholders' equity:
Common stock, par value $.01 per share; 100,000,000 shares
authorized; 77,825,398 shares issued at December 31, 2010
and 77,039,628 shares issued at December 31, 2009		778			770
Additional paid-in capital		203,044			193,718
Treasury stock, at cost; 1,533,653 shares held at December 31,
2010 and 1,497,346 shares held at December 31, 2009		(8,382	)		(8,310	)
Accumulated other comprehensive income		1,107			26,822
Retained earnings		319,776			363,494
Total stockholders' equity		516,323			576,494
Total liabilities and stockholders' equity	$	1,299,628		$	1,347,599

See Notes to Consolidated Financial Statements

F-4

TETRA Technologies, Inc. and Subsidiaries

Consolidated Statements of Operations

(In Thousands, Except Per Share Amounts)

	Year Ended December 31,
	2010			2009			2008
Revenues:
Product sales	$	419,926		$	350,005		$	447,341
Services and rentals		452,752			528,872			561,724
Total revenues		872,678			878,877			1,009,065

Cost of revenues:
Cost of product sales		302,675			237,911			283,194
Cost of services and rentals		291,948			310,943			364,275
Gain on insurance recoveries		(2,541	)		(45,391	)		(697	)
Depreciation, depletion, amortization, and accretion		148,022			149,326			158,893
Impairments of long-lived assets		88,867			12,991			51,399
Total cost of revenues		828,971			665,780			857,064
Gross profit		43,707			213,097			152,001

General and administrative expense		100,132			100,832			104,949
Impairment of goodwill		-			-			47,073
Operating income (loss)		(56,425	)		112,265			(21	)

Interest expense, net		17,304			12,790			16,778
Other income (expense), net		(64	)		5,895			12,884

Income (loss) before taxes and discontinued operations		(73,793	)		105,370			(3,915	)
Provision (benefit) for income taxes		(30,468	)		36,563			5,740

Income (loss) before discontinued operations		(43,325	)		68,807			(9,655	)

Discontinued operations:
Income (loss) from discontinued operations, net of taxes		(393	)		(426	)		(2,481	)
Gain on disposal of discontinued operations, net of taxes		-			423			-
Income (loss) from discontinued operations		(393	)		(3	)		(2,481	)

Net income (loss)	$	(43,718	)	$	68,804		$	(12,136	)


Basic net income (loss) per common share:
Income (loss) before discontinued operations	$	(0.57	)	$	0.92		$	(0.13	)
Income (loss) from discontinued operations		(0.01	)		(0.01	)		(0.03	)
Gain on disposal of discontinued operations		-			0.01			-
Net income (loss)	$	(0.58	)	$	0.92		$	(0.16	)
Average shares outstanding		75,539			75,045			74,519

Diluted net income (loss) per common share:
Income (loss) before discontinued operations	$	(0.57	)	$	0.91		$	(0.13	)
Income (loss) from discontinued operations		(0.01	)		(0.01	)		(0.03	)
Gain on disposal of discontinued operations		-			0.01			-
Net income (loss)	$	(0.58	)	$	0.91		$	(0.16	)
Average diluted shares outstanding		75,539			75,722			74,519

See Notes to Consolidated Financial Statements

F-5

TETRA Technologies, Inc. and Subsidiaries

Consolidated Statements of Stockholders’ Equity

(In Thousands, Except Share Information)

																	Accumulated Other
	Outstanding		Treasury			Common		Additional									Comprehensive Income (Loss)						Total
	Common		Shares			Stock		Paid-In			Treasury			Retained			Derivative			Currency			Stockholders'
	Shares		Held			Par Value		Capital			Stock			Earnings			Instruments			Translation			Equity

Balance at December 31, 2007		74,370,765		1,550,962		$	759	$	174,738		$	(8,405	)	$	306,826		$	(32,861	)	$	6,862		$	447,919
Net loss for 2008															(12,136	)								(12,136	)
Translation adjustment, net of
taxes of $387																					(11,381	)		(11,381	)
Net change in derivative fair value,
net of taxes of $26,449																		44,650						44,650
Reclassification of derivative fair value
into earnings, net of taxes of $21,099																		35,618						35,618
Comprehensive income																								56,751
Exercise of common stock options		722,992		(18,696	)		7		4,170			(296	)											3,881
Grants of restricted stock, net		165,202		50,199			2					(142	)											(140	)
Stock option expense									5,898															5,898
Tax benefit upon exercise of certain
nonqualified and incentive options									1,512															1,512
Balance at December 31, 2008		75,258,959		1,582,465		$	768	$	186,318		$	(8,843	)	$	294,690		$	47,407		$	(4,519	)	$	515,821

Net income for 2009															68,804									68,804
Translation adjustment, net of
taxes of $1,564																					7,869			7,869
Net change in derivative fair value,
net of taxes of $3,339																		5,601						5,601
Reclassification of derivative fair value
into earnings, net of taxes of $(17,496)																		(29,536	)					(29,536	)
Comprehensive income																								52,738
Exercise of common stock options		204,651		(106,000	)		2		632			588												1,222
Grants of restricted stock, net		78,672		20,881								(55	)											(55	)
Stock option expense									6,662															6,662
Minority interest									(141	)														(141	)
Tax benefit upon exercise of certain
nonqualified and incentive options									247															247
Balance at December 31, 2009		75,542,282		1,497,346		$	770	$	193,718		$	(8,310	)	$	363,494		$	23,472		$	3,350		$	576,494

Net loss for 2010															(43,718	)								(43,718	)
Translation adjustment, net of
taxes of $2,041																					420			420
Net change in derivative fair value,
net of taxes of $2,724																		4,599						4,599
Reclassification of derivative fair value
into earnings, net of taxes of $(18,205)																		(30,734	)					(30,734	)
Comprehensive loss																								(69,433	)
Exercise of common stock options		354,219		630			8		1,598			(9	)											1,597
Grants of restricted stock, net		395,244		35,677								(63	)											(63	)
Stock option expense									7,211															7,211
Minority interest																								-
Tax benefit upon exercise of certain
nonqualified and incentive options									517															517
Balance at December 31, 2010		76,291,745		1,533,653		$	778	$	203,044		$	(8,382	)	$	319,776		$	(2,663	)	$	3,770		$	516,323

See Notes to Consolidated Financial Statements

F-6

TETRA Technologies, Inc. and Subsidiaries

Consolidated Statements of Cash Flows

(In Thousands)

	Year Ended December 31,
	2010			2009			2008
Operating activities:
Net income (loss)	$	(43,718	)	$	68,804		$	(12,136	)
Reconciliation of net income (loss) to cash provided by operating activities:
Depreciation, depletion, amortization, and accretion		148,022			149,326			158,893
Impairment of goodwill		-			-			47,073
Impairments of long-lived assets		88,867			19,531			51,399
Provision (benefit) for deferred income taxes		(45,487	)		21,204			(1,067	)
Stock compensation expense		7,211			6,662			5,898
Provision for doubtful accounts		(1	)		3,393			3,082
Proceeds from sale of derivatives		-			23,060			-
Non-cash income from sold hedge derivatives		(22,853	)		-			-
(Gain) loss on sale of property, plant, and equipment		89			(7,333	)		(3,347	)
Proceeds from insurance settlements		47,772			-			-
Excess decommissioning/abandoning costs and
other non-cash charges and credits		54,006			25,043			(212	)
Excess tax benefit from exercise of stock options		(517	)		(247	)		(1,510	)
Equity in (earnings) loss of unconsolidated subsidiary		(504	)		(510	)		(554	)
Changes in operating assets and liabilities, net of assets acquired:
Accounts receivable		6,613			62,364			(3,940	)
Inventories		17,308			(4,628	)		(1,397	)
Prepaid expenses and other current assets		(2,092	)		13,611			(18,913	)
Trade accounts payable and accrued expenses		(5,500	)		(30,622	)		(14,058	)
Decommissioning liabilities		(95,872	)		(79,471	)		(19,430	)
Operating activities of discontinued operations		(8	)		228			3,344
Other		(11	)		1,900			(3,314	)
Net cash provided by operating activities		153,325			272,315			189,811

Investing activities:
Purchases of property, plant, and equipment		(107,684	)		(151,773	)		(262,099	)
Business combinations, net of cash acquired		(6,250	)		(18,105	)		-
Proceeds from sale of property, plant, and equipment		2,997			15,925			380
Other investing activities		(4,949	)		4,254			264
Net cash used in investing activities		(115,886	)		(149,699	)		(261,455	)

Financing activities:
Proceeds from long-term debt		90,035			197,900			182,450
Principal payments on long-term debt		(91,784	)		(295,034	)		(131,428	)
Excess tax benefit from exercise of stock options		517			247			1,510
Proceeds from sale of common stock and exercise of stock options		1,287			1,165			4,749
Financing and loan prepayment costs		(5,963	)		-			-
Net cash provided by (used in) financing activities		(5,908	)		(95,722	)		57,281
Effect of exchange rate changes on cash		435			2,618			(3,588	)

Increase (decrease) in cash and cash equivalents		31,966			29,512			(17,951	)
Cash and cash equivalents at beginning of period		33,394			3,882			21,833
Cash and cash equivalents at end of period	$	65,360		$	33,394		$	3,882

Supplemental cash flow information:
Interest paid	$	19,136		$	19,940		$	19,488
Taxes paid		29,095			11,505			9,420

Supplemental disclosure of non-cash investing and financing activities:
Oil and gas properties acquired through assumption of
decommissioning liabilities	$	22		$	-		$	22,236

Adjustment of fair value of decommissioning liabilities
capitalized to oil and gas properties		65,664			23,705			32,511

See Notes to Consolidated Financial Statements

F-7

TETRA TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2010

NOTE A — ORGANIZATION AND OPERATIONS

We are a geographically diversified oil and gas services company focused on completion fluids and other products, production testing, wellhead compression, and selected offshore services including well plugging and abandonment, decommissioning, and diving, with a concentrated domestic exploration and production business. We were incorporated in Delaware in 1981. We are composed of five reporting segments organized into three divisions – Fluids, Offshore, and Production Enhancement. Unless the context requires otherwise, when we refer to “we,” “us,” and “our,” we are describing TETRA Technologies, Inc. and its consolidated subsidiaries on a consolidated basis.

Our Offshore Division consists of two operating segments: Offshore Services and Maritech. The Offshore Services segment provides (1) downhole and subsea oil and gas services such as plugging and abandonment, workover, and wireline services, (2) decommissioning and certain construction services utilizing heavy lift barges and various cutting technologies in the construction or decommissioning of offshore oil and gas production platforms and pipelines, and (3) diving services involving conventional and saturated air diving.

NOTE B — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Principles of Consolidation

The consolidated financial statements include the accounts of our wholly owned subsidiaries. Investments in unconsolidated joint ventures in which we participate are accounted for using the equity method. Our interests in oil and gas properties are proportionately consolidated. All significant intercompany accounts and transactions have been eliminated in consolidation.

Use of Estimates

The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclose contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

F-8

Reclassifications

We have accounted for the discontinuance or disposal of certain businesses as discontinued operations and have reclassified prior period financial statements to exclude these businesses from continuing operations. See Note C – Discontinued Operations, for a further discussion of the discontinuance of these businesses.

Certain other previously reported financial information has also been reclassified to conform to the current year's presentation.

Cash Equivalents

We consider all highly liquid investments, with a maturity of three months or less when purchased, to be cash equivalents.

Restricted Cash

Restricted cash reflected on our balance sheets as of December 31, 2010 and 2009 includes escrowed funds related to agreed repairs to be expended at one of our former Fluids Division facility locations. This cash will remain restricted until such time as the associated project is completed, which we expect to occur during the next twelve months.

Financial Instruments

Financial instruments that subject us to concentrations of credit risk consist principally of trade receivables with companies in the energy industry. Our policy is to evaluate, prior to providing goods or services, each customer's financial condition and to determine the amount of open credit to be extended. We generally require appropriate, additional collateral as security for credit amounts in excess of approved limits. Our customers consist primarily of major, well-established oil and gas producers and independent oil and gas companies. Our risk management activities currently involve the use of derivative financial instruments, such as oil and gas swap contracts, to hedge the impact of commodity market price risk exposures related to a portion of our oil and gas production cash flow.

To the extent we have any outstanding balance under our variable rate bank credit facility, we may face market risk exposure related to changes in applicable interest rates. Although we have no interest rate swap contracts outstanding to hedge this potential risk exposure, we have entered into certain fixed interest rate notes, which are scheduled to mature at various dates from 2013 through 2020 and which mitigate this risk on our total outstanding borrowings.

Allowances for Doubtful Accounts

Allowances for doubtful accounts are determined on a specific identification basis when we believe that the collection of specific amounts owed to us is not probable.

Inventories

Inventories are stated at the lower of cost or market value. Cost is determined using the weighted average method. Significant components of inventories as of December 31, 2010 and 2009 are as follows:

	December 31,
	2010		2009
	(In Thousands)

Finished goods	$	75,874	$	88,704
Raw materials		5,103		3,436
Parts and supplies		22,457		26,060
Work in progress		871		4,074
Total inventories	$	104,305	$	122,274

F-9

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

Property, Plant, and Equipment

Property, plant, and equipment are stated at the cost of assets acquired. Expenditures that increase the useful lives of assets are capitalized. The cost of repairs and maintenance is charged to operations as incurred. For financial reporting purposes, we generally provide for depreciation using the straight-line method over the estimated useful lives of assets, which are as follows:

Buildings	15 – 25 years
Machinery, vessels, and equipment	3 – 15 years
Automobiles and trucks	4 years
Chemical plants	15 – 30 years

Leasehold improvements are depreciated over the shorter of the remaining term of the associated lease or its useful life. Depreciation and depletion expense, excluding long-lived asset impairments and dry hole costs, for the years ended December 31, 2010, 2009, and 2008 was $139.7 million, $137.8 million, and $138.0 million, respectively.

Interest capitalized for the years ended December 31, 2010, 2009, and 2008 was $1.1 million, $6.8 million, and $3.2 million, respectively.

Oil and Gas Properties

Maritech conducts oil and gas exploration, development, and production activities. Maritech periodically purchases oil and gas properties and assumes the related well abandonment and decommissioning liabilities (referred to as decommissioning liabilities). We follow the successful efforts method of accounting for our oil and gas operations. Under the successful efforts method, the costs of successful exploratory wells and leases are capitalized. Costs incurred to drill and equip development wells, including unsuccessful development wells, are capitalized. Other costs such as geological and geophysical costs, drilling costs of unsuccessful exploratory wells, and all internal costs are expensed. Maritech’s property purchases are recorded at the fair value of our working interest share of decommissioning liabilities assumed, plus or minus any cash or other consideration paid or received as part of the transaction. All capitalized costs are accumulated and recorded separately for each field and allocated to leasehold costs and well costs. Leasehold costs are depleted on a unit of production method based on the estimated remaining equivalent proved oil and gas reserves of each field. Well costs are depleted on a unit of production method based on the estimated remaining equivalent proved developed oil and gas reserves of each field.

Intangible Assets other than Goodwill

Patents, trademarks, and other intangible assets are recorded on the basis of cost and are amortized on a straight-line basis over their estimated useful lives, ranging from 3 to 20 years. During 2010, as a part of an acquisition consummated during the year, we acquired intangible assets having a fair value of approximately $0.6 million with estimated useful lives ranging from 3 to 6 years (having a weighted average useful life of 5.3 years). During 2007, as a part of certain acquisitions consummated during the year, we acquired intangible assets having a fair value of approximately $2.4 million with estimated useful lives ranging from 2 to 6 years (having a weighted average useful life of 5.5 years). Amortization expense of patents, trademarks, and other intangible assets was $2.8 million, $3.6 million, and $4.5 million for the twelve months ended December 31, 2010, 2009, and 2008, respectively, and is included in operating income. The estimated future annual amortization expense of patents, trademarks, and other intangible assets is $2.3 million for 2011, $2.2 million for 2012, $1.7 million for 2013, $0.7 million for 2014, and $0.7 million for 2015.

F-10

Goodwill

Goodwill represents the excess of cost over the fair value of the net assets of businesses acquired in purchase transactions. We perform a goodwill impairment test on an annual basis or whenever indicators of impairment are present. We perform the annual test of goodwill impairment following the fourth quarter of each year. The goodwill impairment test consists of a two-step accounting test performed on a reporting unit basis. For purposes of this impairment test, the reporting units are our five reporting segments: Fluids, Offshore Services, Maritech, Production Testing, and Compressco. The first step of the impairment test is to compare the estimated fair value of any reporting units that have recorded goodwill with the recorded net book value (including goodwill) of the reporting unit. If the estimated fair value of the reporting unit is higher than the recorded net book value, no impairment is deemed to exist and no further testing is required. If, however, the estimated fair value of the reporting unit is below the recorded net book value, then a second step must be performed to determine the goodwill impairment required, if any. In this second step, the estimated fair value from the first step is used as the purchase price in a hypothetical acquisition of the reporting unit. Purchase business combination accounting rules are followed to determine a hypothetical purchase price allocation to the reporting unit’s assets and liabilities. The residual amount of goodwill that results from this hypothetical purchase price allocation is compared to the recorded amount of goodwill for the reporting unit, and the recorded amount is written down to the hypothetical amount, if lower.

Because quoted market prices for our reporting units are not available, management must apply judgment in determining the estimated fair value of these reporting units for purposes of performing the goodwill impairment test. Management uses all available information to make these fair value determinations, including the present value of expected future cash flows using discount rates commensurate with the risks involved in the assets. The resultant fair values calculated for the reporting units are then compared to observable metrics for other companies in our industry, or on mergers and acquisitions in our industry, to determine whether those valuations, in our judgment, appear reasonable. We have estimated the fair value of each reporting unit based upon the future discounted cash flows of the businesses to which goodwill relates and have determined that there is no impairment of the goodwill recorded as of December 31, 2010.

During the fourth quarter of 2008, changes to the global economic environment resulting in uncertain capital markets and reductions in global economic activity had severe adverse impacts on stock markets and oil and natural gas prices, both of which contributed to a significant decline in our company’s stock price and corresponding market capitalization. For most of the fourth quarter, our market capitalization was below the recorded net book value of our balance sheet, including goodwill. The accounting principles regarding goodwill acknowledge that the observed market prices of individual trades of a company’s stock (and thus its computed market capitalization) may not be representative of the fair value of the company as a whole. Substantial value may arise from the ability to take advantage of synergies and other benefits that flow from control over another entity. Consequently, measuring the fair value of a collection of assets and liabilities that operate together in a controlled entity is different from measuring the fair value of a single share of that entity’s common stock. Therefore, once the fair values of the reporting units were determined, we also added a control premium to the calculations. This control premium is judgmental and is based on observed mergers and acquisitions in our industry.

After determining the fair values of our various reporting units which had recorded goodwill as of December 31, 2008, it was determined that our Production Testing and Compressco reporting units passed the first step of the goodwill impairment test, while our Fluids and Offshore Services reporting units did not pass the first step. Maritech does not have any recorded goodwill. As described above, the second step of the goodwill impairment test uses the estimated fair value for the Fluids and Offshore Services reporting units as the purchase price in a hypothetical acquisition of the reporting unit. The allocation of this purchase price includes hypothetical adjustments to the carrying values of several asset carrying values for the Fluids and Offshore Services reporting units. After making these purchase price allocation adjustments, there was no residual purchase price to be allocated to goodwill. Based on this analysis, we concluded that an impairment of the entire amount of recorded goodwill for our Fluids and Offshore Services reporting units was required, resulting in a charge to earnings of $47.1 million during the fourth quarter of 2008.

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The changes in the carrying amount of goodwill by reporting unit for the three year period ended December 31, 2010, are as follows:

	Fluids			Offshore Services			Maritech		Production Testing		Compressco		Total
	(In Thousands)
Balance as of December 31, 2007	$	24,641		$	23,223		$	-	$	10,364	$	72,161	$	130,389
Goodwill adjustments		-			-			-		-		-		-
Foreign currency fluctuations		(791	)		-			-		-		-		(791	)
Goodwill impairments		(23,850	)		(23,223	)		-		-		-		(47,073	)

Balance as of December 31, 2008		-			-			-		10,364		72,161		82,525
Goodwill adjustments		-			3,809			-		12,671		-		16,480

Balance as of December 31, 2009		-			3,809			-		23,035		72,161		99,005
Goodwill adjustments		-			-			-		-		-		-

Balance as of December 31, 2010	$	-		$	3,809		$	-	$	23,035	$	72,161	$	99,005

In March 2006, we acquired Beacon Resources, LLC (Beacon), a production testing operation, for approximately $15.6 million paid at closing. In addition, the acquisition agreement provided for additional contingent consideration of up to $19.1 million, depending on the average of Beacon’s annual pretax results of operations over the three year period following the closing date through March 2009. Based on Beacon’s annual pretax results of operations during this three year period, we paid $12.7 million in April 2009 to the sellers pursuant to this contingent consideration provision. This amount was charged to goodwill associated with the acquisition of Beacon.

In March 2006, we acquired the assets and operations of Epic Divers, Inc. and certain affiliated companies (Epic), a full service commercial diving operation. In June 2006, Epic purchased a dynamically positioned dive support vessel and saturation diving unit. Pursuant to the Epic Asset Purchase Agreement, a portion of the net profits earned by this dive support vessel and saturation diving unit over the initial three year term following its purchase was to be paid to the sellers. Based on the vessel’s high utilization following the 2008 hurricanes, we paid $3.8 million in July 2009 pursuant to this contingent consideration provision. This amount was charged to goodwill associated with the acquisition of Epic.

Impairment of Long-Lived Assets

Impairments of long-lived assets are determined periodically when indicators of impairment are present. If such indicators are present, the determination of the amount of impairment is based on our judgments as to the future undiscounted operating cash flows to be generated from these assets throughout their estimated useful lives. If these undiscounted cash flows are less than the carrying amount of the related asset, an impairment is recognized for the excess of the carrying value over its fair value. The assessment of oil and gas properties for impairment is based on the risk adjusted future estimated cash flows from our proved, probable, and possible reserves. Assets held for disposal are recorded at the lower of carrying value or estimated fair value less estimated selling costs.

Impairments of Oil and Gas Properties

During 2010, 2009, and 2008, we identified impairments totaling approximately $63.8 million, $11.4 million, and $42.7 million, respectively, net of intercompany eliminations, of the net carrying value of certain Maritech oil and gas properties. The oil and gas property impairments during 2010 were mainly associated with Maritech’s non-core properties and were primarily due to significant increases in Maritech’s associated decommissioning liabilities for these properties. For further discussion of the adjustments to Maritech’s decommissioning liabilities during 2010, see Note I – Decommissioning and Other Asset Retirement Obligations. Additional oil and gas property impairments were also recorded during 2010 as a result of decreased production volumes, changes in development plans, or due to lower oil and natural gas pricing. The oil and gas property impairments during 2009 were primarily due to decreased production volumes or an increase in the associated decommissioning liabilities. The oil and gas property impairments during 2008 were primarily due to the impact of lower oil and natural gas pricing. In addition, certain properties were impaired as

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a result of decreased production volumes and increases in the associated decommissioning liabilities, particularly as a result of the 2008 hurricanes.

Impairments of Other Long-Lived Assets

Due to the current market pricing for pellet calcium chloride and the uncertain supply of raw materials needed to operate our Fluids Division’s Lake Charles, Louisiana, calcium chloride plant on economic terms, expected operating cash flows of the plant are insufficient to cover the plant’s carrying value. Demand for pellet calcium chloride produced at the Lake Charles plant has been negatively affected by current market conditions. Accordingly, we recorded an impairment of approximately $7.2 million of the plant’s carrying value during the fourth quarter of 2010. In February, 2011, we shut down the pellet plant operation, although the liquid calcium chloride operation remains operational.

Although the Epic Diver, a dynamically positioned dive support vessel owned by our Epic Diving & Marine (Epic) subsidiary, has performed significantly since it was acquired in 2006, our Offshore Services segment has determined that the vessel is no longer strategic to its plans to serve its markets going forward. This decision was influenced by the recent extension of the charter of a modern dive support vessel that has been leased and utilized by Epic during the past year. This decision resulted in an impairment of the net carrying value of the Epic Diver by $15.3 million, which was recorded during the fourth quarter of 2010. In January 2011, the Offshore Services segment finalized its decision to divest the Epic Diver. The Offshore Services segment also identified certain additional, less significant, asset impairments during 2010.

Our Fluids Division owns a 50% interest in an unconsolidated joint venture whose assets consist primarily of a calcium chloride plant located in Europe. During 2009, the joint venture partner announced the shutdown of its adjacent plant facility, which supplies raw material to the calcium chloride plant. As a result, the joint venture’s calcium chloride plant was also shut down. During 2009, we reduced our investment in the joint venture to its estimated fair value based on the estimated plant decommissioning costs and salvage value cash flows of the joint venture, resulting in an impairment of our investment in the joint venture of $6.5 million.

During 2008, we identified impairments totaling approximately $8.7 million associated with a portion of the net carrying value of certain Offshore Services assets. Approximately $7.3 million of these impairments was as a result of decreased expected future cash flows from one of the segment’s barge vessels.

Decommissioning Liabilities

Related to our acquired interests in oil and gas properties, we estimate the third-party fair values (including an estimated profit) to plug and abandon wells, decommission the pipelines and platforms, and clear the sites, and we use these estimates to record Maritech’s decommissioning liabilities, net of amounts allocable to joint interest owners, anticipated insurance recoveries, and any amounts contractually agreed to be paid in the future by the previous owners of the properties. In some cases, previous owners of acquired oil and gas properties are contractually obligated to pay Maritech a fixed amount for the future well abandonment and decommissioning work on these properties as such work is performed. As of December 31, 2010 and 2009, our Maritech subsidiary’s decommissioning liabilities are net of approximately $32.5 million and $43.6 million, respectively, of such future reimbursements from these previous owners.

In estimating the decommissioning liabilities, we perform detailed estimating procedures, analysis, and engineering studies. Whenever practical and cost effective, Maritech will utilize the services of its affiliated companies to perform well abandonment and decommissioning work. When these services are performed by an affiliated company, all recorded intercompany revenues are eliminated in the consolidated financial statements. The recorded decommissioning liability associated with a specific property is fully extinguished when the property is completely abandoned. The liability is first reduced by all cash expenses incurred to abandon and decommission the property. If the liability exceeds (or is less than) our actual out-of-pocket costs, the difference is credited (or charged) to earnings in the period in which the work is performed. We review the adequacy of our decommissioning liabilities whenever indicators suggest that the estimated cash flows underlying the liabilities have changed materially. The timing and amounts of these cash flows are subject to changes in the energy industry environment and may result in additional liabilities to be recorded, which, in turn, would increase the carrying values of the related properties. As a result of decommissioning

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work performed, we recorded total reductions to the decommissioning liabilities for the years 2010, 2009, and 2008 of $88.2 million, $74.6 million, and $16.5 million, respectively. For a further discussion of adjustments and other activity related to Maritech’s decommissioning liabilities, including significant adjustments made during 2010, see Note I – Decommissioning and Other Asset Retirement Obligations.

Environmental Liabilities

Environmental expenditures which result in additions to property and equipment are capitalized, while other environmental expenditures are expensed. Environmental remediation liabilities are recorded on an undiscounted basis when environmental assessments or cleanups are probable and the costs can be reasonably estimated. Estimates of future environmental remediation expenditures often consist of a range of possible expenditure amounts, a portion of which may be in excess of amounts of liabilities recorded. In this instance, we disclose the full range of amounts reasonably possible of being incurred. Any changes or developments in environmental remediation efforts are accounted for and disclosed each quarter as they occur. Any recoveries of environmental remediation costs from other parties are recorded as assets when their receipt is deemed probable.

Complexities involving environmental remediation efforts can cause the estimates of the associated liability to be imprecise. Factors which cause uncertainties regarding the estimation of future expenditures include, but are not limited to, the effectiveness of the anticipated work plans in achieving targeted results and changes in the desired remediation methods and outcomes as prescribed by regulatory agencies. Uncertainties associated with environmental remediation contingencies are pervasive and often result in wide ranges of reasonably possible outcomes. Estimates developed in the early stages of remediation can vary significantly. Normally, a finite estimate of cost does not become fixed and determinable at a specific point in time. Rather, the costs associated with environmental remediation become estimable as the work is performed and the range of ultimate cost becomes more defined. It is possible that cash flows and results of operations could be materially affected by the impact of the ultimate resolution of these contingencies.

Revenue Recognition

Revenues are recognized when finished products are shipped or services have been provided to unaffiliated customers and only when collectability is reasonably assured. Sales terms for our products are FOB shipping point, with title transferring at the point of shipment. Revenue is recognized at the point of transfer of title. We recognize oil and gas product sales revenues from our Maritech subsidiary’s interests in producing wells as oil and gas is produced and sold from those wells. Oil and gas sold is not significantly different from Maritech’s share of production. With regard to turnkey contracts, revenues are recognized using the percentage-of-completion method based on the ratio of costs incurred to total estimated costs at completion. Total project revenue and cost estimates for turnkey contracts are reviewed periodically as work progresses, and adjustments are reflected in the period in which such estimates are revised. Provisions for estimated losses on such contracts are made in the period such losses are determined. For contracts that contain multiple deliverables, the recognition of revenue is determined based on the realized market values received by the customer as well as the timing of collections under the contract.

Oil and Gas Balancing

As part of our Maritech subsidiary’s acquisitions of producing properties, we have acquired oil and gas balancing receivables and payables related to certain properties. We allocate value for any acquired oil and gas balancing positions using estimated fair value amounts expected to be received or paid in the future. Amounts related to underproduced volume positions acquired are reflected as assets, and amounts related to overproduced volume positions acquired are reflected as liabilities. At December 31, 2010 and 2009, we reflected oil and gas balancing receivables of $2.6 million and $3.5 million, respectively, in accounts receivable and other long-term assets and oil and gas balancing payables of $5.4 million and $6.2 million, respectively, in accrued liabilities and other long-term liabilities. We recognize oil and gas product sales from our Maritech subsidiary’s interest in producing wells, based on its entitled share of oil and natural gas produced and sold from those wells. Changes to our oil and gas balancing receivable or payable are valued at the lower of the price in effect at time of production, current market price, or contract price, if applicable.

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Operating Costs

Cost of product sales includes direct and indirect costs of manufacturing and producing our products, including raw materials, fuel, utilities, labor, overhead, repairs and maintenance, materials, services, transportation, warehousing, equipment rentals, insurance, and taxes. In addition, cost of product sales includes oil and gas operating expense. Cost of services and rentals includes operating expenses we incur in delivering our services, including labor, equipment rental, fuel, repair and maintenance, transportation, overhead, insurance, and certain taxes. We include in product sales revenues the reimbursements we receive from customers for shipping and handling costs. Shipping and handling costs are included in cost of product sales. Amounts we incur for “out-of-pocket” expenses in the delivery of our services are recorded as cost of services and rentals. Reimbursements for “out-of-pocket” expenses we incur in the delivery of our services are recorded as service revenues. Depreciation, depletion, amortization, and accretion includes depreciation expense for all of our facilities, equipment and vehicles, depletion and dry hole expense on our oil and gas properties, amortization expense on our intangible assets, and accretion expense related to our decommissioning and other asset retirement obligations.

We include in general and administrative expense all costs not identifiable to our specific product or service operations, including divisional and general corporate overhead, professional services, corporate office costs, sales and marketing expenses, insurance, and taxes.

Repair Costs and Insurance Recoveries

During 2008, we incurred significant damage to certain of our onshore and offshore operating equipment and facilities, primarily as a result of Hurricane Ike. Our Maritech subsidiary suffered varying levels of damage to the majority of its offshore oil and gas producing platforms, and three of its offshore platforms and one of its inland water production facilities were destroyed. During 2005, as a result of Hurricanes Katrina and Rita, our Maritech subsidiary also suffered damage to the majority of its offshore oil and gas producing platforms, and three of its platforms and one of its inland water production facilities were also destroyed.

Hurricane damage repair efforts consist of the repair of damaged facilities and equipment, well intervention, abandonment, decommissioning, and debris removal associated with the destroyed offshore platforms, construction of replacement platforms and facilities, and redrilling of destroyed wells. The reconstruction of the two inland water production facilities has been completed, and four of the six platforms destroyed have been decommissioned. In addition, a majority of our damaged facilities and equipment, including our offshore platforms that were only partially damaged, have been repaired. Damage assessment costs and repair expenses up to the amount of insurance deductibles or not covered by insurance are charged to earnings as they are incurred. We recognized hurricane related repair expenses for the years ended December 31, 2009 and 2008 of $8.2 million and $8.5 million, respectively.

The estimated amount of future well intervention, abandonment, decommissioning, and debris removal costs were initially recorded in the period in which such damage occurred, net of expected insurance recoveries, as part of Maritech’s decommissioning liabilities. See further discussion of Maritech’s decommissioning liabilities in Decommissioning Liabilities section above. Through December 31, 2010, we have expended approximately $125.0 million for the well intervention, abandonment, decommissioning, debris removal, and platform reconstruction work performed on the destroyed platforms and production facilities. For certain of the destroyed platforms, however, a significant amount of decommissioning and debris removal work remains to be completed. The majority of the well intervention efforts to date have been performed by our Offshore Services segment. We estimate that the remaining future abandonment, decommissioning, debris removal, and well redrill efforts associated with the platforms destroyed by hurricanes during 2005 and 2008 will cost approximately $50 to $65 million net to our interest before any insurance recoveries. Approximately $28 to $39 million of this cost relates to platforms destroyed by Hurricane Ike in 2008. Approximately $38.1 million of our total future cost estimate has been accrued as part of Maritech’s decommissioning liabilities. An additional amount of approximately $13 to $19 million relates primarily to the estimated cost to finalize a newly installed offshore platform at Maritech’s East Cameron 328 field and to complete the redrilling of several wells at this location. Actual hurricane repair costs could exceed these estimates and, depending on the nature of the cost, could result in significant charges to earnings in future periods. See below for a discussion of our remaining insurance coverage associated with hurricane damage repairs.

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We typically maintain insurance protection that we believe to be customary and in amounts sufficient to reimburse us for a majority of our casualty losses, including for a portion of the repair, well intervention, abandonment, decommissioning, and debris removal costs associated with the damages incurred from named windstorms and hurricanes. In addition, other damages, such as the value of lost inventory and the cost to replace a sunken transport barge which was lost in 2009, are also covered by insurance. Our insurance coverage is subject to certain overall coverage limits and deductibles. For the Maritech hurricane damages caused by Hurricane Ike during 2008, we anticipate that those damages will exceed these overall coverage limits. With regard to costs incurred that we believe will qualify for coverage under our various insurance policies, we recognize anticipated insurance recoveries when collection is deemed probable. Any recognition of anticipated insurance recoveries is used to offset the original charge to which the insurance recovery relates. The amount of anticipated insurance recoveries is either included in accounts receivable or recorded as an offset to Maritech’s decommissioning liabilities in the accompanying consolidated balance sheets.

The changes in anticipated insurance recoveries, including anticipated recoveries associated with the sunken barge and other non-hurricane related claims, during the most recent two year period are as follows:

	Year Ended December 31,
	2010			2009
	(In Thousands)

Beginning balance	$	26,992		$	33,591

Activity in the period:
Claim related expenditures		370			21,228
Insurance reimbursements		(26,238	)		(27,176	)
Contested insurance recoveries		(583	)		(651	)
Ending balance at December 31	$	541		$	26,992

During 2010, Maritech collected approximately $47.8 million of insurance proceeds associated with Hurricane Ike, which included the settlement of certain coverage at an amount less than the applicable coverage limits. For the $39.8 million of this amount that was collected in March 2010, the amount collected was greater than the covered hurricane repair, well intervention, and abandonment costs incurred as of that date, with the excess representing an advance payment of costs anticipated to be incurred in the future. The collection of these settlement proceeds have resulted in the extinguishment of all of Maritech’s insurance receivables, the reversal of the costs previously capitalized for the future decommissioning of oil and gas properties, the reversal of anticipated insurance recoveries that had been netted against certain decommissioning liabilities, and approximately $2.2 million of pre-tax insurance gains that were credited to earnings during 2010. Maritech maintains that it has additional remaining coverage available relating to hurricane damage repairs of approximately $19.5 million, all of which relates to Hurricane Ike. During December 2010, we initiated legal proceedings against one of Maritech’s underwriters, that is disputing that certain costs incurred or to be incurred qualify as covered costs pursuant to the policies.

Maritech incurred certain well intervention, debris removal, and repair costs related to damage from Hurricanes Katrina and Rita which were not reimbursed by its insurers. In December 2007, Maritech filed a lawsuit against its insurers and other associated parties in an attempt to collect pursuant to the applicable policies. During the fourth quarter of 2009, Maritech entered into a settlement agreement under which it received approximately $40.0 million of the previously unreimbursed costs. We have reviewed the types of estimated well intervention costs incurred or to be incurred related to Hurricane Ike. Despite our belief that substantially all of these costs in excess of deductibles and within policy limits will qualify for coverage under our insurance policies, any costs that are similar to the costs that were not initially reimbursed following Hurricanes Katrina and Rita have been excluded from anticipated insurance recoveries and were either capitalized to the associated oil and gas properties or expensed.

Anticipated insurance recoveries that have been reflected as a reduction of our decommissioning liabilities were $0 million at December 31, 2010, and $10.3 million at December 31, 2009. Anticipated insurance recoveries that have been reflected as insurance receivables were $0.5 million as of December 31,

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2010, and $16.7 million at December 31, 2009. Uninsured assets that were destroyed during the storms are charged to earnings. Repair costs incurred and the net book value of any destroyed assets which are covered under our insurance policies are anticipated insurance recoveries which are included in accounts receivable. Repair costs not considered probable of collection are charged to earnings. Insurance recoveries in excess of destroyed asset carrying values and repair costs incurred are credited to earnings when received. During 2010, 2009, and 2008, approximately $2.5 million, $5.4 million, and $0.7 million, respectively, of such excess proceeds were credited to earnings.

Income Taxes

Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis amounts. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect of a change in tax rates is recognized as income or expense in the period that includes the enactment date.

Income (Loss) per Common Share

The calculation of basic earnings per share excludes any dilutive effects of options. The calculation of diluted earnings per share includes the dilutive effect of stock options, which is computed using the treasury stock method during the periods such options were outstanding. A reconciliation of the common shares used in the computations of income (loss) per common and common equivalent shares is presented in Note P – Income (Loss) Per Share.

Foreign Currency Translation

We have designated the euro, the British pound, the Norwegian krone, the Canadian dollar, the Mexican peso, and the Brazilian real as the functional currency for our operations in Finland and Sweden, the United Kingdom, Norway, Canada, Mexico, and Brazil, respectively. The U.S. dollar is the designated functional currency for all of our other foreign operations. The cumulative translation effects of translating the accounts from the functional currencies into the U.S. dollar at current exchange rates are included as a separate component of stockholders' equity.

Fair Value Measurements

Fair value is defined as “the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date” within an entity’s principal market, if any. The principal market is the market in which the reporting entity would sell the asset or transfer the liability with the greatest volume and level of activity, regardless of whether it is the market in which the entity will ultimately transact for a particular asset or liability or if a different market is potentially more advantageous. Accordingly, this exit price concept may result in a fair value that may differ from the transaction price or market price of the asset or liability.

Under generally accepted accounting principles, the fair value hierarchy prioritizes inputs to valuation techniques used to measure fair value. Fair value measurements should maximize the use of observable inputs and minimize the use of unobservable inputs, where possible. Observable inputs are developed based on market data obtained from sources independent of the reporting entity. Unobservable inputs may be needed to measure fair value in situations where there is little or no market activity for the asset or liability at the measurement date and are developed based on the best information available in the circumstances, which could include the reporting entity’s own judgments about the assumptions market participants would utilize in pricing the asset or liability.

We utilize fair value measurements to account for certain items and account balances within our consolidated financial statements. Fair value measurements are utilized in the allocation of purchase consideration for acquisition transactions to the assets and liabilities acquired, including intangible assets and goodwill. In addition, we utilize fair value measurements in the initial recording of our decommissioning and other asset retirement obligations. Fair value measurements may also be utilized on a nonrecurring basis,

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such as for the impairment of long-lived assets, including goodwill. The fair value of our financial instruments, which may include cash, temporary investments, accounts receivable, short-term borrowings, and long-term debt pursuant to our bank credit agreement, approximate their carrying amounts. The fair value of our long-term Senior Notes at December 31, 2010 was approximately $315.7 million compared to a carrying amount of approximately $305.0 million, as current rates are more favorable than the Senior Note interest rates. We calculate the fair value of our Senior Notes internally, using current market conditions and average cost of debt. We have not calculated or disclosed recurring fair value measurements of non-financial assets and non-financial liabilities.

We also utilize fair value measurements on a recurring basis in the accounting for our derivative contracts used to hedge a portion of our oil and natural gas production cash flows. For these fair value measurements, we compare forward oil and natural gas pricing data from published sources over the remaining derivative contract term to the contract swap price and calculate a fair value using market discount rates. A summary of these fair value measurements as of December 31, 2010 and 2009 is as follows:

				Fair Value Measurements as of December 31, 2010 Using
				Quoted Prices in
				Active Markets for		Significant Other			Significant
				Identical Assets		Observable			Unobservable
	Total as of			or Liabilities		Inputs			Inputs
Description	December 31, 2010			(Level 1)		(Level 2)			(Level 3)
	(In Thousands)
Asset for natural gas
swap contracts	$	2,436		$	-	$	2,436		$	-
Liability for oil swap contracts		(5,208	)		-		(5,208	)		-
Total	$	(2,772	)

				Fair Value Measurements as of December 31, 2009 Using
				Quoted Prices in
				Active Markets for		Significant Other			Significant
				Identical Assets		Observable			Unobservable
	Total as of			or Liabilities		Inputs			Inputs
Description	December 31, 2009			(Level 1)		(Level 2)			(Level 3)
	(In Thousands)
Asset for natural gas
swap contracts	$	19,926		$	-	$	19,926		$	-
Liability for oil swap contracts		(2,618	)		-		(2,618	)		-
Total	$	17,308

During 2010, certain Maritech oil and gas property impairments of $63.8 million were charged to earnings. The majority of the oil and gas property impairments for 2010 were due to increased estimates of Maritech’s decommissioning liabilities. For a portion of these impaired properties, however, the change in the fair value of the properties was due to decreased expected future cash flows based on forward oil and natural gas pricing data from published sources. Because such published forward pricing data was applied to estimated oil and gas reserve volumes based on our internally prepared reserve estimates, such fair value calculation is based on significant unobservable inputs (Level 3) in accordance with the fair value hierarchy. Also during 2010, our Offshore Services segment recorded impairments for certain equipment assets, including the Epic Diver. In addition, our Fluids segment recorded an impairment for its Lake Charles, Louisiana, calcium chloride plant. The fair values of these assets were based on their resale value based on purchase offers received or their estimated salvage values.

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A summary of these nonrecurring fair value measurements as of December 31, 2010, using the fair value hierarchy is as follows:

			Fair Value Measurements as of
			December 31, 2010 Using
			Quoted Prices in
			Active Markets for		Significant Other		Significant
			Identical Assets		Observable		Unobservable		Year-to-Date
	Year Ended		or Liabilities		Inputs		Inputs		Impairment
Description	December 31, 2010		(Level 1)		(Level 2)		(Level 3)		Losses
	(In Thousands)
Impairments of oil and
gas properties	$	50,339	$	-	$	-	$	50,339	$	63,774
Impairment of Offshore
Services assets		2,453		-		-		2,453		17,731
Impairment of calcium
chloride plant		932		-		-		932		7,213
Other		-		-		-		-		149
Total									$	88,867

During 2009, certain Maritech oil and gas property impairments of $11.4 million were charged to earnings. For a portion of these impaired properties, the change in the fair value of the properties was due to decreased expected future cash flows based on forward oil and natural gas pricing data from published sources. Because such published forward pricing data was applied to estimated oil and gas reserve volumes based on our internally prepared reserve estimates, such fair value calculation is based on significant unobservable inputs (Level 3) in accordance with the fair value hierarchy.

Our Fluids Division owns a 50% interest in an unconsolidated joint venture whose assets consist primarily of a calcium chloride plant located in Europe. During 2009, the joint venture partner announced the shutdown of its adjacent plant facility, which supplies raw material to the calcium chloride plant. As a result, the joint venture’s calcium chloride plant was also shut down. During the second quarter 2009, we reduced our investment in the joint venture to its estimated fair value based on the estimated plant decommissioning costs and salvage value cash flows of the joint venture, resulting in an impairment of our investment in the joint venture of $6.5 million. Because the investment fair value was determined based on internally prepared estimates, such fair value calculation is based on significant unobservable inputs (Level 3) in accordance with the fair value hierarchy.

A summary of these nonrecurring fair value measurements as of December 31, 2009, using the fair value hierarchy is as follows:

			Fair Value Measurements as of
			December 31, 2009 Using
			Quoted Prices in
			Active Markets for		Significant Other		Significant
			Identical Assets		Observable		Unobservable		Year-to-Date
	Year Ended		or Liabilities		Inputs		Inputs		Impairment
Description	December 31, 2009		(Level 1)		(Level 2)		(Level 3)		Losses
	(In Thousands)
Impairments of oil and
gas properties	$	13,228	$	-	$	-	$	13,228	$	11,410
Impairment of investment
in unconsolidated
joint venture		250		-		-		250		6,540
Other		-		-		-		-		1,581
Total									$	19,531

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New Accounting Pronouncements

In January 2010, the FASB published ASU 2010-06, “Fair Value Measurements and Disclosures (Topic 820), Improving Disclosures about Fair Value Measurements,” which requires new disclosures about transfers in and out of fair value hierarchy levels, requires more detailed disclosures about activity in Level 3 fair value measurements and clarifies existing disclosure requirements about asset and liability aggregation, inputs, and valuation techniques. The new disclosures and clarifications of existing disclosures are effective for interim and annual reporting periods beginning after December 15, 2009, except for the disclosure requirements of activity in Level 3 fair value measurements, which become effective for fiscal years beginning after December 15, 2010, and for interim periods within those fiscal years. The adoption of the disclosure requirements of this ASU did not have a significant impact on our financial statements, and the disclosure requirements of activity in Level 3 fair value measurements will not have a significant impact on our financial statements.

NOTE C — DISCONTINUED OPERATIONS

During the fourth quarter of 2007, we disposed of our process services operations through a sale of the associated assets and operations for total cash proceeds of approximately $58.9 million. Our process services operation provided the technology and services required for the separation and recycling of oily residuals generated from petroleum refining operations. Our process services operation was previously included as a component of our Production Enhancement Division.

During the fourth quarter of 2006, we made the decision to dispose of our fluids and production testing operations in Venezuela due to several factors including the country’s changing political climate. Our Venezuelan fluids operation was previously part of our Fluids Division, and the production testing operation was previously part of our Production Enhancement Division.

We have accounted for our process services business, our Venezuelan fluids and production testing businesses, and our other discontinued businesses as discontinued operations and have reclassified prior period financial statements to exclude these businesses from continuing operations.

NOTE D — ACQUISITIONS AND DISPOSITIONS

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

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

In late 2010, we began to decrease our investment in Maritech by suspending our search for oil and gas property acquisitions and decreasing our development activities. In addition, we are exploring strategic alternatives to our ownership of Maritech and its oil and gas properties and we are reviewing opportunities to

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sell Maritech oil and gas property packages to industry participants and other third parties. As part of this overall effort, in February 2011, Maritech sold a group of properties that accounted for approximately 11.4% of its proved reserves.

During 2009, our Maritech subsidiary sold interests in certain oil and gas properties in two separate transactions. As a result of these transactions, the buyers of the properties assumed an aggregate of approximately $6.3 million of Maritech’s associated decommissioning liabilities. Maritech received cash of approximately $4.2 million as a result of these sale transactions and recognized gains totaling approximately $7.3 million. The amount of oil and gas reserve volumes associated with the sold properties was immaterial.

In January 2008, our Maritech subsidiary acquired oil and gas producing properties located in the offshore Gulf of Mexico from Stone Energy Corporation in exchange for the assumption of the associated decommissioning liabilities with a fair value of approximately $19.9 million. In addition, we paid $13.7 million of cash, $2.3 million of which had been paid on deposit in November 2007. The acquired properties were recorded at their cost of approximately $33.6 million.

During the third quarter of 2008, Maritech sold certain oil and gas properties and assets in which the buyers assumed an aggregate of approximately $4.7 million of Maritech’s associated decommissioning liabilities. Maritech retained a decommissioning obligation of approximately $0.2 million in these transactions and recognized gains totaling approximately $4.5 million. The amount of oil and gas reserve volumes associated with the sold properties was immaterial.

All of our acquisitions have been accounted for as purchases, with operations of the companies and businesses acquired included in the accompanying consolidated financial statements from their respective dates of acquisition. The purchase price has been allocated to the acquired assets and liabilities based on a determination of their respective fair values. The excess of the purchase price over the fair value of the net assets acquired is included in goodwill and assessed for impairment whenever indicators are present. We have not recorded any goodwill in conjunction with our oil and gas property acquisitions.

NOTE E — LEASES

We lease some of our transportation equipment, office space, warehouse space, operating locations, and machinery and equipment. Certain facility storage tanks being constructed are leased pursuant to a ten year term, which is classified as a capital lease. The office, warehouse, and operating location leases, which vary from one to twenty-five year terms that expire at various dates through 2017 and are renewable for three and five year periods on similar terms, are classified as operating leases. Transportation equipment leases expire at various dates through 2016 and are also classified as operating leases. The office, warehouse, and operating location leases, and machinery and equipment leases generally require us to pay all maintenance and insurance costs.

Future minimum lease payments by year and in the aggregate, under non-cancelable capital and operating leases with terms of one year or more, consist of the following at December 31, 2010:

	Capital Lease		Operating Leases
	(In Thousands)

2011	$	76	$	5,643
2012		76		3,519
2013		76		2,092
2014		76		1,244
2015		76		411
After 2015		304		1,305
Total minimum lease payments	$	684	$	14,214

Rental expense for all operating leases was $10.9 million, $10.0 million, and $13.3 million in 2010, 2009, and 2008, respectively.

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NOTE F — INCOME TAXES

The income tax provision (benefit) attributable to continuing operations for the years ended December 31, 2010, 2009, and 2008 consists of the following:

	Year Ended December 31,
	2010			2009			2008
	(In Thousands)
Current
Federal	$	8,930		$	7,762		$	(4,840	)
State		1,096			(856	)		5,156
Foreign		4,993			8,453			6,491
		15,019			15,359			6,807
Deferred
Federal		(41,513	)		18,889			794
State		(3,922	)		1,742			(1,204	)
Foreign		(52	)		573			(657	)
		(45,487	)		21,204			(1,067	)
Total tax provision (benefit)	$	(30,468	)	$	36,563		$	5,740

A reconciliation of the provision (benefit) for income taxes attributable to continuing operations, computed by applying the federal statutory rate for the years ended December 31, 2010, 2009, and 2008 to income before income taxes and the reported income taxes, is as follows:

	Year Ended December 31,
	2010			2009			2008
	(In Thousands)
Income tax provision (benefit) computed at
statutory federal income tax rates	$	(25,827	)	$	36,880		$	(1,370	)
State income taxes (net of federal benefit)		(1,837	)		576			2,568
Nondeductible expenses		1,654			1,566			4,281
Impact of international operations		(3,526	)		(1,138	)		1,248
Excess depletion		(377	)		(124	)		(239	)
Tax credits		-			(237	)		(538	)
Other		(555	)		(960	)		(210	)
Total tax provision (benefit)	$	(30,468	)	$	36,563		$	5,740

The provision (benefit) for income taxes includes amounts related to the anticipated repatriation of certain earnings of our non-U.S. subsidiaries. Undistributed earnings above the amounts upon which taxes have been provided, which was $18.7 million at December 31, 2010, are intended to be permanently invested. It is not practicable to determine the amount of applicable taxes that would be incurred if any such earnings were repatriated.

Income (loss) before taxes and discontinued operations includes the following components:

	Year Ended December 31,
	2010			2009		2008
	(In Thousands)

Domestic	$	(92,557	)	$	82,251	$	(11,054	)
International		18,764			23,119		7,139
Total	$	(73,793	)	$	105,370	$	(3,915	)

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

	Year Ended December 31,
	2010			2009			2008
	(In Thousands)

Gross unrecognized tax benefits at beginning of period	$	2,256		$	2,235		$	2,566

Increases in tax positions for prior years		-			561			-
Decreases in tax positions for prior years		-			-			-
Increases in tax positions for current year		-			-			341
Settlements		-			-			-
Lapse in statute of limitations		(407	)		(540	)		(672	)
Gross unrecognized tax benefits at end of period	$	1,849		$	2,256		$	2,235

We recognize interest and penalties related to uncertain tax positions in income tax expense. During the years ended December 31, 2010, 2009, and 2008, we credited $0.2 million, $0.5 million, and $0.3 million, respectively, for the net reversal of previously recorded interest and penalties to the provision for income tax. As of December 31, 2010 and 2009, we had $1.8 million and $2.0 million, respectively, of accrued potential interest and penalties associated with these uncertain tax positions. The total amount of unrecognized tax benefits that would affect our effective tax rate if recognized is $1.4 million and $1.7 million as of December 31, 2010 and 2009, respectively. We do not expect a significant change to the unrecognized tax benefits during the next twelve months.

We file tax returns in the U.S. and in various state, local, and non-U.S. jurisdictions. The following table summarizes the earliest tax years that remain subject to examination by taxing authorities in any major jurisdiction in which we operate:

Jurisdiction	Earliest Open Tax Period
United States – Federal	2008
United States – State and Local	2002
Non-U.S. jurisdictions	2004

We use the liability method for reporting income taxes, under which current and deferred tax assets and liabilities are recorded in accordance with enacted tax laws and rates. Under this method, at the end of each period, the amounts of deferred tax assets and liabilities are determined using the tax rate expected to be in effect when the taxes are actually paid or recovered. We will establish a valuation allowance to reduce the deferred tax assets when it is more likely than not that some portion or all of the deferred tax assets will not be realized. While we have considered future taxable income and ongoing tax planning strategies in assessing the need for the valuation allowance, there can be no guarantee that we will be able to realize all of our deferred tax assets. Significant components of our deferred tax assets and liabilities as of December 31, 2010 and 2009 are as follows:

Deferred Tax Assets:
	December 31,
	2010			2009
	(In Thousands)

Accruals	$	103,507		$	87,088
Goodwill		3,325			5,249
All other		35,709			26,280
Total deferred tax assets		142,541			118,617
Valuation allowance		(7,121	)		(4,255	)
Net deferred tax assets	$	135,420		$	114,362

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Deferred Tax Liabilities:
	December 31,
	2010		2009
	(In Thousands)
Excess book over tax basis in
property, plant, and equipment	$	144,525	$	161,126
Unrealized gains on derivatives		-		13,879
All other		7,100		14,033
Total deferred tax liability		151,625		189,038
Net deferred tax liability	$	16,205	$	74,676

The change in the valuation allowance during 2010 primarily relates to an increase of state operating loss carryforwards. We believe the ability to generate sufficient taxable income may not allow us to realize all the tax benefits of the deferred tax assets within the allowable carryforward period. Therefore, an appropriate valuation allowance has been provided.

At December 31, 2010, we had approximately $5.5 million of foreign and state net operating loss carryforwards. In those countries and states in which net operating losses are subject to an expiration period, our loss carryforwards, if not utilized, will expire at various dates from 2011 through 2030. At December 31, 2010, we had $3.6 million of foreign tax credits available to offset future payment of federal income taxes. The foreign tax credits expire in varying amounts from 2015 through 2020.

NOTE G — ACCRUED LIABILITIES

Accrued liabilities are detailed as follows:

	December 31,
	2010		2009
	(In Thousands)

Taxes payable	$	7,311	$	13,932
Oil and gas drilling advances		547		367
Compensation and employee benefits		11,382		16,525
Oil and gas producing liabilities		31,347		20,643
Unearned income		16,073		12,844
Other accrued liabilities		17,144		20,344
	$	83,804	$	84,655

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NOTE H — LONG-TERM DEBT AND OTHER BORROWINGS

Long-term debt consists of the following:

	December 31,
	2010		2009
	(In Thousands)

Bank revolving line of credit facility, due 2015	$	-	$	-
5.07% Senior Notes, Series 2004-A, due 2011		-		55,000
4.79% Senior Notes, Series 2004-B, due 2011		-		40,132
5.90% Senior Notes, Series 2006-A, due 2016		90,000		90,000
6.30% Senior Notes, Series 2008-A, due 2013		35,000		35,000
6.56% Senior Notes, Series 2008-B, due 2015		90,000		90,000
5.09% Senior Notes, Series 2010-A, due 2017		65,000		-
6.67% Senior Notes, Series 2008-B, due 2020		25,000		-
European credit facility		-		-
Other		35		-
		305,035		310,132
Less current portion		-		-

Total long-term debt	$	305,035	$	310,132

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

	Year Ending
	December 31,
	(In Thousands)

2011	$	-
2012		35
2013		35,000
2014		-
2015		90,000
Thereafter		180,000

	$	305,035

Bank Credit Facilities

On October 29, 2010, we amended our existing bank revolving credit facility agreement with a syndication of banks, whereby the credit facility was decreased from $300 million to $278 million and its scheduled maturity was extended from June 2011 to October 2015. In addition, the amended credit facility agreement allows us to increase the facility by $150 million up to a $428 million limit upon the agreement of the lenders and the satisfaction of certain conditions. As of December 31, 2010, we did not have any outstanding balance on the amended revolving credit facility and had $13.4 million in letters of credit and guarantees against the $278.0 million amended revolving credit facility, leaving a net availability of $264.6 million.

Under the amended credit facility agreement (the Credit Agreement), the revolving credit facility, which is scheduled to mature in October 2015, remains unsecured and guaranteed by certain of our material U.S. subsidiaries. Borrowings generally bear interest at the British Bankers Association LIBOR rate plus 1.5% to 2.5%, depending on one of our financial ratios. We pay a commitment fee ranging from 0.225% to 0.500% on unused portions of the facility. Similar to the previous terms, the Credit Agreement contains customary covenants and other restrictions, including certain financial ratio covenants involving our levels of debt and interest cost compared to a defined measure of our operating cash flows over a twelve month period. In addition, the Credit Agreement includes limitations on aggregate asset sales, individual acquisitions, and aggregate annual acquisitions and capital expenditures. Access to our revolving credit line is dependent upon our ability to comply with the certain financial ratio covenants set forth in the Credit Agreement, as discussed

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above. Significant deterioration of the financial ratios could result in a default under the Credit Agreement and, if not remedied, could result in termination of the agreement and acceleration of any outstanding balances.

The Credit Agreement also includes cross-default provisions relating to any other indebtedness greater than a defined amount. If any such indebtedness is not paid or is accelerated and such event is not remedied in a timely manner, a default will occur under the Credit Agreement. Our Credit Agreement also contains a covenant that restricts us from paying dividends in the event of a default or if such payment would result in an event of default. We are in compliance with all covenants and conditions of our Credit Agreement as of December 31, 2010. Our continuing ability to comply with these financial covenants centers largely upon our ability to generate adequate cash flow. Historically, our financial performance has been more than adequate to meet these covenants, and we expect this trend to continue.

We also have a bank line of credit agreement covering the day to day working capital needs of certain of our European operations (the European Credit Agreement). The European Credit Agreement provides for available borrowing capacity of up to 5 million euros (approximately $6.7 million equivalent as of December 31, 2010), with interest computed on any outstanding borrowings at a rate equal to the lender’s Basis Rate plus 0.75%. The European Credit Agreement is cancellable by either party with 14 business days notice and contains standard provisions in the event of default. As of December 31, 2010, we had no borrowings pursuant to the European Credit Agreement.

Senior Notes

Each of our issuances of senior notes (collectively, the Senior Notes) are governed by the terms of the Master Note Purchase Agreement dated September 2004, as supplemented, the Note Purchase Agreement dated April 2008, or the Master Note Purchase Agreement dated September 23, 2010 (collectively, the Note Purchase Agreements). We may prepay the Senior Notes, in whole or in part, at any time at a price equal to 100% of the principal amount outstanding, plus accrued and unpaid interest and a “make-whole” prepayment premium. The Senior Notes are unsecured and are guaranteed by substantially all of our wholly owned U.S. subsidiaries. The Note Purchase Agreements, as supplemented, contain customary covenants and restrictions, require us to maintain certain financial ratios, and contain customary default provisions, as well as a cross-default provision relating to any other of our indebtedness of $20 million or more. We are in compliance with all covenants and conditions of the Note Purchase Agreements as of December 31, 2010. Upon the occurrence and during the continuation of an event of default under the Note Purchase Agreements, the Senior Notes may become immediately due and payable, either automatically or by declaration of holders of more than 50% in principal amount of the Senior Notes outstanding at the time.

In September 2010, we entered into an agreement whereby we agreed to issue and sell through a private placement, $65.0 million in aggregate principal amount of Series 2010-A Senior Notes and $25.0 million in aggregate principal amount of Series 2010-B Senior Notes (collectively, the 2010 Senior Notes) pursuant to a Note Purchase Agreement dated September 30, 2010. In December 2010, partially funded by the $90 million proceeds from the 2010 Senior Notes, we paid $95.7 million to repay the Series 2004 Senior Notes, including principal, accrued interest, and a $2.8 million “make whole” prepayment premium which was charged to other expense.

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

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NOTE I — DECOMMISSIONING AND OTHER ASSET RETIREMENT OBLIGATIONS

The large majority of our asset retirement obligations consists of the future well abandonment and decommissioning costs for offshore oil and gas properties and platforms owned by our Maritech subsidiary. The amount of decommissioning liabilities recorded by Maritech is reduced by amounts allocable to joint interest owners, anticipated insurance recoveries, and any contractual amount to be paid by the previous owner of the oil and gas property when the liabilities are satisfied. We also operate facilities in various U.S. and foreign locations that are used in the manufacture, storage, and sale of our products, inventories, and equipment, including offshore oil and gas production facilities and equipment. These facilities are a combination of owned and leased assets. We are required to take certain actions in connection with the retirement of these assets. We have reviewed our obligations in this regard in detail and estimated the cost of these actions. These estimates are the fair values that have been recorded for retiring these long-lived assets. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. The costs are depreciated on a straight-line basis over the life of the asset for non-oil and gas assets and on a unit of production basis for oil and gas properties.

The changes in the asset retirement obligations during the most recent two year period are as follows:

	Year Ended December 31,
	2010			2009
	(In Thousands)

Beginning balance for the period, as reported	$	224,110		$	248,725

Activity in the period:
Accretion of liability		5,539			7,893
Retirement obligations incurred		22			1,326
Revisions in estimated cash flows		131,889			47,069
Settlement of retirement obligations		(88,745	)		(80,903	)

Ending balance at December 31	$	272,815		$	224,110

We review the adequacy of our decommissioning liabilities whenever indicators suggest that the estimated cash flows underlying the liabilities have changed materially. For our Maritech segment, the timing and amounts of these cash flows are subject to changes in the energy industry environment and other factors and may result in additional liabilities to be recorded. In September 2010, the Bureau of Ocean Energy Management, Regulation, and Enforcement (BOEMRE) provided in a Notice to Lessees No. 2010-G05 (NTL 2010-G05) rules for the plugging and abandonment of wells and decommissioning of associated platforms and facilities. NTL 2010-G05 provides specific guidelines for the maximum time that an operator has to permanently plug wells and decommission platforms and facilities upon occurrence of certain events including the end of useful operations, cessation of commercial production, and expiration of leases. As of December 31, 2010, Maritech identified significant adjustments to be made to increase its decommissioning liabilities to reflect current industry developments, including the impact from these NTL 2010-G05 “Idle Iron Guidance” regulations. The adjustments made during 2010 resulted in $54.0 million of direct charges to operating expense, and the remainder was charged to the associated properties and partly contributed to asset impairments during the year. Specific factors causing Maritech’s decommissioning liabilities to increase significantly include:

Maritech received a letter from BOEMRE in October 2010 that identifies certain of its wells and platforms that are required to be abandoned or decommissioned in accordance with the NTL 2010-G05 regulations. As a result, it will be necessary to perform the abandonment and decommissioning of these properties on an accelerated basis, thus increasing the discounted fair value of the associated decommissioning liabilities;

·	Maritech believes that its ability to obtain permits for reefing abandoned platforms and facilities in place will now be significantly diminished and, accordingly, it has increased its cost estimates to reflect the incremental costs of transportation to shore;

Following the Macondo oil spill in 2010, Maritech’s well abandonment cost estimates have been increased to add additional costs for surveying, planning, executing, and supervising abandonment activities in a manner that ensures maximum protection for the environment and personnel engaged in the operations;

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·	Our decision to decrease Maritech’s development activities has resulted in the acceleration of certain planned abandonment and decommissioning work compared to previous estimates, thus increasing the discounted fair value of the decommissioning liabilities;

·	Our extensive abandonment program of the last year has caused us to revise and refine certain of our estimates, particularly those relating to the cost of final site clearance and cleanup; and

We believe that a significant increase in the cost of contracted services will result from the increased regulatory requirements. A significant increase in demand for abandonment and decommissioning services is expected during the next several years, when the majority of Maritech’s work is currently planned to be performed due to the age of its properties.

Maritech’s decommissioning liabilities also include the remaining future well intervention, abandonment, decommissioning, and debris removal efforts associated with the platforms destroyed by hurricanes during 2005 and 2008. During 2010 and 2009, we increased the estimated cash flows to decommission these properties by approximately $29.3 million and $17.9 million, respectively. These increased estimates are included in the revisions in estimated cash flows in the table above. Our estimate of hurricane related decommissioning costs is approximately $38.1 million and has been accrued as part of Maritech’s decommissioning liabilities.

NOTE J — COMMITMENTS AND CONTINGENCIES

Litigation

Class Action Lawsuit

Derivative Lawsuit

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 the class action lawsuit, and 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. 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. Our board is currently evaluating the best course of action to take in response to the demand letter.

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At this stage, it is impossible to predict the outcome of these proceedings or their impact upon us. We currently believe that the allegations made in the federal complaints and state petitions are without merit, and we intend to seek dismissal of and vigorously defend against these actions. While a successful outcome cannot be guaranteed, we do not reasonably expect these lawsuits to have a material adverse effect.

Environmental

In August of 2009, the Environmental Protection Agency (EPA), pursuant to Sections 308 and 311 of the Clean Water Act (CWA), served a request for information with regard to a spill of zinc bromide that occurred on the Mississippi River on March 11, 2009. We timely filed a response to that request for information in August 2009. In January 2010, the EPA issued a Notice of Violation and Opportunity to Show Cause related to the spill. We met with the EPA in April 2010 to discuss potential violations and penalties. It has been agreed that no injunctive relief will be required. We finalized a joint stipulation of settlement with the EPA whereby we are responsible for a penalty of $487,000, which has been submitted to the Department of Justice for approval. We expect to pay this penalty amount during the second quarter of 2011, and expect the full amount to be covered by insurance.

Product Purchase Obligations

NOTE K — CAPITAL STOCK

Our Restated Certificate of Incorporation authorizes us to issue 100,000,000 shares of common stock, par value $.01 per share, and 5,000,000 shares of preferred stock, par value $.01 per share. As of December 31, 2010, we had 76,291,745 shares of common stock outstanding, with 1,533,653 shares held in treasury, and no shares of preferred stock outstanding. The voting, dividend, and liquidation rights of the holders of common stock are subject to the rights of the holders of preferred stock. The holders of common stock are entitled to one vote for each share held. There is no cumulative voting. Dividends may be declared and paid on common stock as determined by our Board of Directors, subject to any preferential dividend rights of any then outstanding preferred stock.

Our Board of Directors is empowered, without approval of the stockholders, to cause shares of preferred stock to be issued in one or more series and to establish the number of shares to be included in each such series and the rights, powers, preferences and limitations of each series. Because the Board of Directors has the power to establish the preferences, and rights of each series, it may afford the holders of any series of preferred stock preferences, powers and rights, voting or otherwise, senior to the rights of holders of

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common stock. The issuance of the preferred stock could have the effect of delaying or preventing a change in control of the Company. See Note T – Stockholders’ Rights Plan for a discussion of our stockholders’ rights plan, as amended.

Upon our dissolution or liquidation, whether voluntary or involuntary, holders of our common stock will be entitled to receive all of our assets available for distribution to our stockholders, subject to any preferential rights of any then outstanding preferred stock.

In January 2004, our Board of Directors authorized the repurchase of up to $20.0 million of our common stock. During the three years ending December 31, 2010, we made no purchases of our common stock pursuant to this authorization.

NOTE L — EQUITY-BASED COMPENSATION

We have various equity incentive compensation plans which provide for the granting of restricted common stock, options for the purchase of our common stock, and other performance-based, equity-based compensation awards to our executive officers, key employees, nonexecutive officers, consultants, and directors. Incentive stock options are exercisable for periods up to ten years. Compensation cost for all share-based payments is based on the grant date fair value and is recognized in earnings over the requisite service period. Total equity-based compensation expense for the three years ended December 31, 2010, 2009, and 2008 was $7.2 million, $6.7 million, and $5.9 million, respectively, which approximated the fair value of equity-based compensation awards vesting during the periods. This expense reduced net income by $4.2 million, $4.4 million, and $3.7 million and reduced basic and diluted earnings per share by $0.06, $0.06 and $0.05, respectively, for the three years ended December 31, 2010, 2009, and 2008.

The Black-Scholes option-pricing model is used to estimate option fair values. This option-pricing model requires a number of assumptions, of which the most significant are: expected stock price volatility, the expected pre-vesting forfeiture rate, and the expected option term (the amount of time from the grant date until the options are exercised or expire). Expected volatility was calculated based upon actual historical stock price movements over the most recent periods ending December 31, 2010, equal to the expected option term. Expected pre-vesting forfeitures were estimated based on actual historical pre-vesting forfeitures over the most recent periods ending December 31, 2010, for the expected option term.

The TETRA Technologies, Inc. 1990 Stock Option Plan (the 1990 Plan) was initially adopted in 1985 and subsequently amended to change the name, the number, and the type of options that could be granted, as well as the time period for granting stock options. As of December 31, 2004, no further options may be granted under the 1990 Plan. We granted performance stock options under the 1990 Plan to certain executive officers. These granted options have an exercise price per share of not less than the market value at the date of issuance and are fully vested and exercisable.

In 1993, we adopted the TETRA Technologies, Inc. Director Stock Option Plan (the Directors’ Plan). In 1996, the Directors’ Plan was amended to increase the number of shares issuable under automatic grants thereunder. In 1998, we adopted the TETRA Technologies, Inc. 1998 Director Stock Option Plan as amended (the 1998 Director Plan). The purpose of the Directors’ Plan and the 1998 Director Plan (together the Director Stock Option Plans) is to enable us to attract and retain qualified individuals to serve as our directors and to align their interests more closely with our interests. The 1998 Director Plan is funded with our treasury stock and was amended and restated effective December 18, 2002 to increase the number of shares issuable thereunder, to change the types of options that may be granted thereunder, and to increase the number of shares issuable under automatic grants thereunder. The 1998 Director Plan was amended and restated effective June 27, 2003, and was further amended in December 2005 to increase the number of shares issuable thereunder. As of May 2, 2006, no further options may be granted under the Director Stock Option Plans.

During 1996, we adopted the 1996 Stock Option Plan for Nonexecutive Employees and Consultants (the Nonqualified Plan) to enable us to award nonqualified stock options to nonexecutive employees and consultants who are key to our performance. As of May 2, 2006, no further options may be granted under the Nonqualified Plan.

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In May 2006, our stockholders approved the adoption of the TETRA Technologies, Inc. 2006 Equity Incentive Compensation Plan. Pursuant to the TETRA Technologies, Inc. 2006 Equity Incentive Compensation Plan, we were authorized to grant up to 1,300,000 shares in the form of stock options (including incentive stock options and nonqualified stock options); restricted stock; bonus stock; stock appreciation rights; and performance awards to employees, consultants, and non-employee directors. As a result of the May 2006 adoption and approval of the TETRA Technologies, Inc. 2006 Equity Incentive Compensation Plan, no further awards may be granted under our other previously existing plans. As of May 4, 2008, no further awards may be granted under the TETRA Technologies, Inc. 2006 Equity Incentive Compensation Plan.

In May 2007, our stockholders approved the adoption of the TETRA Technologies, Inc. 2007 Equity Incentive Compensation Plan. In May 2008, our stockholders approved the adoption of the TETRA Technologies, Inc. Amended and Restated 2007 Equity Incentive Compensation Plan, which among other changes, resulted in an increase in the maximum number of shares authorized for issuance. In May 2010, our stockholders approved further amendments to the TETRA Technologies, Inc. Amended and Restated 2007 Equity Incentive Compensation Plan (renamed as the 2007 Long Term Incentive Compensation Plan) which, among other changes, resulted in an additional increase in the maximum number of shares authorized for issuance. Pursuant to the 2007 Long Term Incentive Compensation Plan, we are authorized to grant up to 5,590,000 shares in the form of stock options (including incentive stock options and nonqualified stock options); restricted stock; bonus stock; stock appreciation rights; and performance awards to employees, consultants, and non-employee directors.

Grants of Restricted Common Stock

During each of the three years ended December 31, 2010, we granted to certain officers and employees restricted shares, which generally vest over a three to five year period. During 2010, we granted a total of 434,101 restricted shares, having an average market value (equal to the closing price of the common stock on the dates of grant) of $10.20 per share, or an aggregate market value of $4.4 million. During 2009, we granted a total of 98,053 restricted shares, having an average market value (equal to the quoted closing price of the common stock on the dates of grant) of $8.07 per share, or an aggregate market value of $0.8 million, at the date of grant. During 2008, we granted a total of 216,901 restricted shares, having an average market value of $19.51 per share, or an aggregate market value of approximately $4.2 million, at the date of grant.

The following is a summary of restricted stock activity for the year ended December 31, 2010:

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

Nonvested restricted shares outstanding at December 31, 2009		283		$	21.16

Shares granted		434			10.20
Shares cancelled		(31	)		16.70
Shares vested		(144	)		16.34
Nonvested restricted shares outstanding at December 31, 2010		542		$	13.92

F-31

Grants of Options to Purchase Common Stock

Stock options authorized for issuance, outstanding and currently exercisable at December 31, 2010, 2009, and 2008, are as follows:

	2010		2009		2008
	(In Thousands, Except Per Share Amounts)
2007 Long Term Incentive Compensation Plan
Maximum number of shares authorized for issuance		5,590		4,590		4,590
Shares reserved for future grants		1,026		931		2,908
Options exercisable at period end		1,620		469		6
Weighted average exercise price of options exercisable
at period end	$	10.83	$	19.90	$	18.50

TETRA Technologies, Inc. 2006 Equity Incentive Compensation Plan
Maximum number of shares authorized for issuance		1,300		1,300		1,300
Shares reserved for future grants		-		-		-
Options exercisable at period end		406		359		320
Weighted average exercise price of options exercisable
at period end	$	27.23	$	27.04	$	26.86

1990 TETRA Technologies, Inc. Employee Plan (as amended)
Maximum number of shares authorized for issuance		17,775		17,775		17,775
Shares reserved for future grants		-		-		-
Options exercisable at period end		1,195		1,290		1,395
Weighted average exercise price of options exercisable
at period end	$	7.46	$	7.43	$	7.09

Director Stock Option Plans (as amended)
Maximum number of shares authorized for issuance		2,138		2,138		2,138
Shares reserved for future grants		-		-		-
Options exercisable at period end		-		144		297
Weighted average exercise price of options exercisable
at period end		N/A	$	15.26	$	12.09

All Other Plans
Maximum number of shares authorized for issuance		3,615		3,615		3,615
Shares reserved for future grants		-		-		-
Options exercisable at period end		761		870		842
Weighted average exercise price of options exercisable
at period end	$	16.20	$	14.40	$	13.85

The following is a summary of options outstanding and options exercisable as of December 31, 2010:

	Options Outstanding						Options Exercisable
			Weighted						Weighted
			Average		Weighted				Average		Weighted
			Remaining		Average				Remaining		Average
Range of			Contracted		Exercise				Contracted		Exercise
Exercise Price	Shares		Life		Price		Shares		Life		Price
	(In Thousands)		(In Years)				(In Thousands)		(In Years)
$2.96 to $4.07		1,727		7.2	$	3.72		1,135		6.7	$	3.66
$4.08 to $8.11		469		3.1	$	4.72		377		1.9	$	4.83
$8.12 to $9.21		1,188		2.0	$	9.09		1,180		1.9	$	9.09
$9.22 to $20.85		772		8.5	$	11.48		139		4.8	$	15.98
$20.86 to $30.00		1,719		6.4	$	22.84		1,151		6.1	$	23.48
		5,875		5.8	$	11.50		3,982		4.6	$	11.54

F-32

The following is a summary of stock option activity for the year ended December 31, 2010:

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

Outstanding at December 31, 2009		6,010		$	11.53

Options granted		635			10.25
Options cancelled		(418	)		15.52
Options exercised		(352	)		4.97
Outstanding at December 31, 2010		5,875		$	11.50

The total intrinsic value, or the difference between the exercise price and the market price on the date of exercise, of all options exercised during the three years ended December 31, 2010, 2009, and 2008 was approximately $1.8 million, $0.8 million and $5.3 million, respectively. The intrinsic value of options outstanding as of December 31, 2010 was $21.8 million, and the intrinsic value of options exercisable as of December 31, 2010 was $15.3 million. Cash received from stock options exercised during the three years ended December 31, 2010, 2009, and 2008 was $1.3 million, $1.2 million and $4.7 million, respectively. Recognized excess tax benefits related to the exercise of stock options during the three years ended December 31, 2010, 2009, and 2008 were $0.5 million, $0.2 million and $1.5 million, respectively.

The fair value of each option grant is estimated on the date of grant using the Black-Scholes option pricing model with the following assumptions used for each of the three years ended December 31, 2010:

	Year Ended December 31,
	2010	2009	2008

Expected stock price volatility	72% to 73%	65% to 73%	32% to 57%
Expected life of options	4.7 years	4.7 years	4.4 to 4.8 years
Risk free interest rate	1.3% to 2.8%	1.9% to 2.6%	1.5% to 3.9%
Expected dividend yield	-	-	-

The weighted average fair value of options granted during the years ended December 31, 2010, 2009 and 2008 using the Black-Scholes model was $6.00, $2.73, and $7.61 per share, respectively. Total estimated unrecognized compensation cost from unvested stock options and restricted stock as of December 31, 2010, was approximately $13.0 million, which is expected to be recognized over a weighted average period of approximately 1.6 years.

Certain options exercised during 2010 and 2008 were exercised through the surrender of 630 and 26,304 shares, respectively, of our common stock previously owned by the option holder for a period of at least six months prior to exercise. In addition, during 2010, 2009, and 2008, we received 6,048, 6,318 and 8,119 shares, respectively, of our common stock related to the vesting of certain employee restricted stock. Such surrendered shares received by us are included in treasury stock. At December 31, 2010, net of options previously exercised pursuant to our various stock option plans, we have a maximum of 7,443,184 shares of common stock issuable pursuant to stock options previously granted and outstanding and stock options authorized to be granted in the future.

NOTE M — 401(k) PLAN

We have a 401(k) retirement plan (the Plan) that covers substantially all employees and entitles them to contribute up to 70% of their annual compensation, subject to maximum limitations imposed by the Internal Revenue Code. We have historically matched 50% of each employee’s contribution up to 6% of annual compensation, subject to certain limitations as outlined in the Plan. Beginning in February 2009, we suspended company matching of employee contributions, although company matching resumed effective January 2, 2010. In addition, we can make discretionary contributions which are allocable to participants in accordance with the Plan. Total expense related to our 401(k) plan was $3.3 million, $0.7 million, and $3.3 million in 2010, 2009, and 2008, respectively.

F-33

NOTE N — DEFERRED COMPENSATION PLAN

We provide our officers, directors, and certain key employees with the opportunity to participate in an unfunded, deferred compensation program. There were thirty-two participants in the program at December 31, 2010. Under the program, participants may defer up to 100% of their yearly total cash compensation. The amounts deferred remain our sole property, and we use a portion of the proceeds to purchase life insurance policies on the lives of certain of the participants. The insurance policies, which also remain our sole property, are payable to us upon the death of the insured. We separately contract with the participant to pay to the participant the amount of deferred compensation, as adjusted for gains or losses, invested in participant-selected investment funds. Participants may elect to receive deferrals and earnings at termination, death, or at a specified future date while still employed. Distributions while employed must be at least three years after the deferral election. The program is not qualified under Section 401 of the Internal Revenue Code. At December 31, 2010, the amounts payable under the plan approximated the value of the corresponding assets we owned.

NOTE O — HEDGE CONTRACTS

We are exposed to financial and market risks that affect our businesses. We have market risk exposure in the sales prices we receive for Maritech’s oil and gas production. We have currency exchange rate risk exposure related to specific transactions denominated in a foreign currency as well as to investments in certain of our international operations. As a result of our variable rate bank credit facility, to the extent we have debt outstanding, we may face market risk exposure related to changes in applicable interest rates. We have concentrations of credit risk as a result of trade receivables from companies in the energy industry. Our financial risk management activities include, among other measures, the use of derivative financial instruments, such as swap and collar agreements, to hedge the impact of market price risk exposures for a portion of Maritech’s oil and gas production and for certain of our foreign currency transactions. We are exposed to the volatility of oil and gas prices for the portion of Maritech’s oil and gas production that is not hedged. We formally document all relationships between hedging instruments and hedged items, as well as our risk management objectives, our strategies for undertaking various hedge transactions, and our methods for assessing and testing correlation and hedge ineffectiveness. All hedging instruments are linked to the hedged asset, liability, firm commitment, or forecasted transaction. We also assess, both at the inception of the hedge and on an ongoing basis, whether the derivatives that are used in these hedging transactions are highly effective in offsetting changes in cash flows of the hedged items.

Derivative Hedge Contracts

As of December 31, 2010, we had the following cash flow hedging swap contracts outstanding relating to a portion of our Maritech subsidiary’s oil and gas production:

Derivative Contracts		Aggregate Daily Volume		Weighted Average Contract Price		Contract Year
Oil swap contracts		2,000 barrels/day		$87.68/barrel		2011

We believe that our swap agreements are “highly effective cash flow hedges” in managing the volatility of future cash flows associated with Maritech’s oil production. The effective portion of the change in the derivative’s fair value (i.e., that portion of the change in the derivative’s fair value that offsets the corresponding change in the cash flows of the hedged transaction) is initially reported as a component of accumulated other comprehensive income, which is classified within stockholders’ equity. This component of accumulated other comprehensive income associated with cash flow hedge derivative contracts, including any derivative contracts which have been liquidated, will be subsequently reclassified into product sales revenues, utilizing the specific identification method, when the hedged exposure affects earnings (i.e., when hedged oil and gas production volumes are reflected in revenues). As of December 31, 2010, the total balance (approximately $2.7 million) of accumulated other comprehensive income associated with cash flow hedge derivatives is expected to be reclassified into product sales revenue in the subsequent twelve month period. Any “ineffective” portion of the change in the derivative’s fair value is recognized in earnings immediately.

F-34

The fair value of hedging instruments reflects our best estimate and is based upon exchange or over-the-counter quotations, whenever they are available. Quoted valuations may not be available. Where quotes are not available, we utilize other valuation techniques or models to estimate fair values. These modeling techniques require us to make estimations of future prices, price correlation, and market volatility and liquidity. The actual results may differ from these estimates, and these differences can be positive or negative. The fair values of our oil and natural gas swap contracts as of December 31, 2010 and 2009 are as follows:

	Balance Sheet	Fair Value at December 31,
Derivatives designated as hedging	Location	2010			2009
instruments		(In Thousands)

Natural gas swap contracts	Current assets	$	2,436		$	19,926
Oil swap contracts	Current liabilities		(5,208	)		(2,618	)
Total derivatives designated as hedging
instruments		$	(2,772	)	$	17,308

Oil and natural gas swap assets and liabilities which are classified as current assets or liabilities relate to the portion of the derivative contracts associated with hedged oil and gas production to occur over the next twelve month period. None of the oil and natural gas swap contracts contain credit risk related contingent features that would require us to post assets as collateral for contracts that are classified as liabilities.

As the hedge contracts were highly effective, the effective portion of the gain, net of taxes, from changes in contract fair value, including the gain on the liquidated oil swap contracts, is included in accumulated other comprehensive income within stockholders’ equity as of December 31, 2010. Pretax gains and losses associated with oil and gas derivative swap contracts for each of the three years ended December 31, 2010, 2009, and 2008 are summarized below:

	Year Ended December 31, 2010
	Oil			Natural Gas		Total
	(In Thousands)
Derivative swap contracts
Amount of pretax gain reclassified from accumulated other comprehensive
income into product sales revenue (effective portion)	$	22,725		$	26,214	$	48,939
Amount of pretax gain (loss) from change in derivative fair value
recognized in other comprehensive income		(1,947	)		9,118		7,171
Amount of pretax gain (loss) recognized in other income (expense)
(ineffective portion)		(152	)		-		(152	)

	Year Ended December 31, 2009
	Oil			Natural Gas			Total
	(In Thousands)
Derivative swap contracts
Amount of pretax gain reclassified from accumulated other comprehensive
income into product sales revenue (effective portion)	$	6,978		$	40,054		$	47,032
Amount of pretax gain (loss) from change in derivative fair value
recognized in other comprehensive income		(13,966	)		22,906			8,940
Amount of pretax gain (loss) recognized in other income (expense)
(ineffective portion)		(408	)		(1,321	)		(1,729	)

F-35

	Year Ended December 31, 2008
	Oil		Natural Gas		Total
	(In Thousands)
Derivative swap contracts
Amount of pretax gain reclassified from accumulated other comprehensive
income into product sales revenue (effective portion)	$	42,462	$	14,255	$	56,717
Amount of pretax gain (loss) from change in derivative fair value
recognized in other comprehensive income		52,151		18,948		71,099
Amount of pretax gain (loss) recognized in other income (expense)
(ineffective portion)		1,768		6,862		8,630

During the second quarter of 2009, we liquidated certain cash flow hedging swap contracts associated with Maritech’s oil production in exchange for cash of approximately $23.1 million. These liquidated cash flow hedging swap contracts met the effectiveness requirements to be accounted for as hedges, and as a result, the gain on the liquidated swap contracts was retained in other comprehensive income and the $23.1 million proceeds were classified as a cash flow from operating activities during 2009 in the accompanying statements of cash flows. These gains were then reclassified into product sales revenue during 2010. Due to the suspension of a portion of Maritech’s oil and gas production following Hurricane Ike in September 2008, certain of our oil and natural gas swap contracts associated with 2008 production no longer met the effectiveness requirements to be accounted for as hedges. As a result, the portion of other comprehensive income associated with these contracts was credited to earnings during 2008. Also as a result of suspended Maritech production, certain qualifying hedge contracts reflected ineffectiveness during the third and fourth quarter of 2008. During the fourth quarter of 2008, we liquidated each of the oil and natural gas swap contracts associated with 2008 production in exchange for cash of $6.5 million. The associated cash flows from the 2008 liquidation of these ineffective contracts were classified as cash flows from investing activities during 2008 in the accompanying consolidated statements of cash flows.

Other Hedge Contracts

Transaction gains and losses attributable to a foreign currency transaction that is designated as, and is effective as, an economic hedge of a net investment in a foreign entity is subject to the same accounting as translation adjustments. As such, the effect of a rate change on a foreign currency hedge is the same as the accounting for the effect of the rate change on the net foreign investment; both are recorded in the cumulative translation account, a component of stockholders’ equity, and are partially or fully offsetting. Prior to December 2010, our long-term debt included borrowings which were designated as a hedge of our net investment in our European calcium chloride operations. In December 2010, these euro-denominated borrowings were repaid. During the period these hedge designated euro-denominated borrowings were outstanding, changes in the foreign currency exchange rate resulted in a cumulative change to the cumulative translation adjustment account of $2.6 million, net of taxes, at December 31, 2010, with no ineffectiveness recorded.

NOTE P — INCOME (LOSS) PER SHARE

The following is a reconciliation of the common shares outstanding with the number of shares used in the computation of income per common and common equivalent share:

	Year Ended December 31,
	2010		2009		2008
	(In Thousands)

Number of weighted average common shares outstanding		75,539		75,045		74,519
Assumed exercise of stock options		-		677		-
Average diluted shares outstanding		75,539		75,722		74,519

For the year and the three months ended December 31, 2010, the average diluted shares outstanding excludes the impact of all outstanding stock options, as the inclusion of these shares would have been antidilutive due to the net loss recorded during the period. For the year ended December 31, 2009, the average diluted shares outstanding excludes the impact of 3,185,388 of average outstanding stock options

F-36

that have exercise prices in excess of the average market price, as the inclusion of these shares would have been antidilutive. For the year ended December 31, 2008, all outstanding stock options were excluded from average diluted shares outstanding, as the inclusion of these shares would have been antidilutive due to the net loss recorded during the period.

NOTE Q — INDUSTRY SEGMENTS AND GEOGRAPHIC INFORMATION

We manage our operations through five operating segments: Fluids, Offshore Services, Maritech, Production Testing and Compressco. Beginning in the fourth quarter of 2010, certain Mexican production enhancement operations were reclassified from our Production Testing, segment to our Compressco segment. Segment information for 2009 and 2008 has been revised to conform to the 2010 presentation.

The Maritech segment is an oil and gas exploration, development, and production company focused in the offshore, inland waters, and onshore U.S. Gulf Coast region. The Offshore Division’s Offshore Services segment performs a significant portion of the well plugging, abandonment, and decommissioning services required by Maritech.

We generally evaluate performance and allocate resources based on profit or loss from operations before income taxes and nonrecurring charges, return on investment, and other criteria. Transfers between segments, as well as geographic areas, are priced at the estimated fair value of the products or services as negotiated between the operating units. “Corporate overhead” includes corporate general and administrative expenses, corporate depreciation and amortization, interest income and expense, and other income and expense.

Summarized financial information concerning the business segments from continuing operations is as follows:

F-37

	Year Ended December 31,
	2010			2009			2008
	(In Thousands)
Revenues from external customers
Product sales
Fluids Division	$	211,917		$	167,984		$	227,194
Offshore Division
Offshore Services		2,576			2,970			4,328
Maritech		197,806			174,191			207,180
Intersegment eliminations		-			-			-
Total Offshore Division		200,382			177,161			211,508
Production Enhancement Division
Production Testing		3,610			-			-
Compressco		4,017			4,860			8,639
Total Production Enhancement Division		7,627			4,860			8,639
Consolidated	$	419,926		$	350,005		$	447,341

Services and rentals
Fluids Division	$	64,358		$	57,491		$	65,602
Offshore Division
Offshore Services		207,934			304,729			279,019
Maritech		2,718			2,848			1,329
Intersegment eliminations		-			-			-
Total Offshore Division		210,652			307,577			280,348
Production Enhancement Division
Production Testing		100,346			77,699			123,849
Compressco		77,396			86,105			91,925
Total Production Enhancement Division		177,742			163,804			215,774
Consolidated	$	452,752		$	528,872		$	561,724

Intersegment revenues
Fluids Division	$	62		$	42		$	452
Offshore Division
Offshore Services		63,690			46,099			23,015
Maritech		35			-			-
Intersegment eliminations		(62,526	)		(45,648	)		(22,971	)
Total Offshore Division		1,199			451			44
Production Enhancement Division
Production Testing		39			1			23
Compressco		-			-			-
Total Production Enhancement Division		39			1			23
Intersegment eliminations		(1,300	)		(494	)		(519	)
Consolidated	$	-		$	-		$	-

Total revenues
Fluids Division	$	276,337		$	225,517		$	293,248
Offshore Division
Offshore Services		274,200			353,798			306,362
Maritech		200,559			177,039			208,509
Intersegment eliminations		(62,526	)		(45,648	)		(22,971	)
Total Offshore Division		412,233			485,189			491,900
Production Enhancement Division
Production Testing		103,995			77,700			123,872
Compressco		81,413			90,965			100,564
Total Production Enhancement Division		185,408			168,665			224,436
Intersegment eliminations		(1,300	)		(494	)		(519	)
Consolidated	$	872,678		$	878,877		$	1,009,065

F-38

	Year Ended December 31,
	2010			2009			2008
	(In Thousands)
Depreciation, depletion, amortization, and accretion
Fluids Division	$	20,899		$	15,281		$	14,033
Offshore Division
Offshore Services		18,067			16,347			18,998
Maritech		79,012			87,274			99,665
Intersegment eliminations		(339	)		(506	)		(544	)
Total Offshore Division		96,740			103,115			118,119
Production Enhancement Division
Production Testing		14,429			14,053			12,139
Compressco		13,029			13,866			12,143
Total Production Enhancement Division		27,458			27,919			24,282
Corporate overhead		2,925			3,011			2,459
Consolidated	$	148,022		$	149,326		$	158,893

Interest expense
Fluids Division	$	237		$	116		$	173
Offshore Division
Offshore Services		1			6			101
Maritech		9			19			43
Intersegment eliminations					-			-
Total Offshore Division		10			25			144
Production Enhancement Division
Production Testing		-			2			30
Compressco		38			-			-
Total Production Enhancement Division		38			2			30
Corporate overhead		17,243			13,064			17,210
Consolidated	$	17,528		$	13,207		$	17,557

Income (loss) before taxes and discontinued operations
Fluids Division	$	15,953		$	20,791		$	5,401
Offshore Division
Offshore Services		4,664			78,394			3,019
Maritech		(69,119	)		22,012			(31,932	)
Intersegment eliminations		443			647			(782	)
Total Offshore Division		(64,012	)		101,053			(29,695	)
Production Enhancement Division
Production Testing		15,024			15,704			33,506
Compressco		17,513			25,549			32,481
Total Production Enhancement Division		32,537			41,253			65,987
Corporate overhead		(58,271	)(1)		(57,727	)(1)		(45,608	)(1)
Consolidated	$	(73,793	)	$	105,370		$	(3,915	)

Total assets
Fluids Division	$	376,309		$	375,754		$	328,852
Offshore Division
Offshore Services		154,535			190,494			220,671
Maritech		329,585			363,605			413,661
Intersegment eliminations		(1,802	)		(2,246	)		(2,902	)
Total Offshore Division		482,318			551,853			631,430
Production Enhancement Division
Production Testing		106,304			111,497			100,018
Compressco		195,879			203,774			213,277
Total Production Enhancement Division		302,183			315,271			313,295
Corporate overhead		138,818	(2)		104,721	(2)		139,047	(2)
Consolidated	$	1,299,628		$	1,347,599		$	1,412,624

F-39

	Year Ended December 31,
	2010			2009			2008
	(In Thousands)
Capital expenditures
Fluids Division	$	10,914		$	84,134		$	76,531
Offshore Division
Offshore Services		11,273			17,930			14,299
Maritech		70,597			26,832			84,970
Intersegment eliminations		(445	)		(454	)		(247	)
Total Offshore Division		81,425			44,308			99,022
Production Enhancement Division
Production Testing		6,010			9,036			25,904
Compressco		7,927			2,944			33,241
Total Production Enhancement Division		13,937			11,980			59,145
Corporate overhead		1,408			11,351			27,401
Consolidated	$	107,684		$	151,773		$	262,099

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

	2010		2009		2008
	(In Thousands)
General and administrative expense	$	34,577	$	40,173	$	34,185
Depreciation and amortization		2,925		3,011		2,459
Interest expense		17,243		13,064		17,210
Other general corporate (income) expense, net		3,526		1,479		(8,246	)
Total	$	58,271	$	57,727	$	45,608

(2)	Includes assets of discontinued operations.

Summarized financial information concerning the geographic areas of our customers and in which we operate at December 31, 2010, 2009, and 2008 is presented below:

	Year Ended December 31,
	2010			2009			2008
	(In Thousands)
Revenues from external customers:
U.S.	$	735,400		$	751,101		$	855,380
Canada and Mexico		32,645			37,984			36,939
South America		19,802			17,372			15,522
Europe		71,356			68,015			85,713
Africa		10,194			2,477			1,973
Asia and other		3,281			1,928			13,538
Total	$	872,678		$	878,877		$	1,009,065

Transfers between geographic areas:
U.S.	$	-		$	-		$	2,578
Canada and Mexico		-			-			-
South America		-			-			225
Europe		254			1,472			55
Africa		-			-			-
Asia and other		-			-			-
Eliminations		(254	)		(1,472	)		(2,858	)
Total revenues	$	872,678		$	878,877		$	1,009,065

Identifiable assets:
U.S.	$	1,125,512		$	1,197,512		$	1,273,642
Canada and Mexico		35,274			32,811			26,732
South America		47,710			41,556			27,379
Europe		67,383			59,633			70,964
Africa		10,862			5,468			4,684
Asia and other		13,187			10,649			9,636
Eliminations and discontinued operations		(300	)		(30	)		(413	)
Total identifiable assets	$	1,299,628		$	1,347,599		$	1,412,624

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In 2008, a single purchaser of Maritech’s oil and gas production, Shell Trading (US) Company, accounted for approximately 13.5% of our consolidated revenues. In 2009 and 2010, no single customer accounted for more than 10% of our consolidated revenues.

NOTE R — SUPPLEMENTAL OIL AND GAS DISCLOSURES (Unaudited)

As part of the Offshore Division activities, Maritech and its subsidiaries periodically acquire oil and gas reserves and operate the properties in exchange for assuming the proportionate share of the well abandonment and decommissioning obligations associated with such properties. Accordingly, our Maritech segment is included within our Offshore Division.

Costs Incurred in Property Acquisition, Exploration, and Development Activities

The following table reflects the costs incurred in oil and gas property acquisition, exploration, and development activities during the years indicated. Consideration given for the acquisition of proved properties includes the assumption, and any subsequent revision, of the amount of the proportionate share of the well abandonment and decommissioning obligations associated with the properties.

	Year Ended December 31,
	2010		2009		2008
	(In Thousands)

Acquisition	$	5,497	$	2,993	$	45,373
Exploration		16,822		6,820		8,522
Development		87,465		38,806		79,620
Total costs incurred	$	109,784	$	48,619	$	133,515

Approximately $5.0 million of the exploration costs incurred during 2009 was capitalized as of December 31, 2009, pending the determination of proved reserves. During 2010, these capitalized exploration costs were classified to developed oil and gas properties based on the determination of proved reserves.

Capitalized Costs Related to Oil and Gas Producing Activities

Aggregate amounts of capitalized costs relating to our oil and gas producing activities and the aggregate amounts of related accumulated depletion, depreciation, and amortization as of the dates indicated are presented below.

	December 31,
	2010			2009
	(In Thousands)
Undeveloped properties	$	12,954		$	16,592
Proved developed properties being amortized		757,663			668,512
Total capitalized costs		770,617			685,104
Less accumulated depletion, depreciation,
and amortization		(501,048	)		(388,069	)
Net capitalized costs	$	269,569		$	297,035

Capitalized costs include the costs of support equipment and facilities. Also included in capitalized costs of proved developed properties being amortized is our estimate of our proportionate share of well abandonment and decommissioning liabilities assumed relating to these properties, which is also reflected as decommissioning and other asset retirement obligations in the accompanying consolidated balance sheets.

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Results of Operations for Oil and Gas Producing Activities

Results of operations for oil and gas producing activities excludes general and administrative and interest expenses directly related to such activities as well as any allocation of corporate or divisional overhead.

	Year Ended December 31,
	2010			2009			2008
	(In Thousands)

Oil and gas sales revenues	$	197,841		$	174,191		$	207,180
Production (lifting) costs (1)		71,066			79,115			89,574
Depreciation, depletion, and amortization		73,679			79,610			82,971
Impairments of properties (2)		63,774			11,410			42,658
Excess decommissioning and abandonment costs		53,997			23,771			7,045
Exploration expenses		306			151			224
Accretion expense		5,008			7,717			7,631
Dry hole costs		325			-			9,063
Gain on insurance recoveries		(2,541	)		(45,391	)		(697	)
Pretax income (loss) from producing activities		(67,773	)		17,808			(31,289	)
Income tax expense (benefit)		(25,186	)		6,551			(8,455	)
Results of oil and gas producing activities	$	(42,587	)	$	11,257		$	(22,834	)

(1)	Production costs during 2009 and 2008 include certain hurricane repair expenses of $8.2 million and $8.5 million, respectively.
(2)	Impairments of oil and gas properties during 2010 were primarily due to the increase in Maritech’s decommissioning liabilities.

Estimated Quantities of Proved Oil and Gas Reserves (Unaudited)

Proved oil and gas reserves are defined as the estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Reservoirs are considered proved if economic productibility is supported by either actual production or conclusive formation tests. The area of a reservoir considered proved includes (a) that portion delineated by drilling and defined by gas-oil and/or gas-water contacts, if any, and (b) the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data. Reserves which can be produced economically through the application of improved recovery techniques are included in the “proved” classification when successful testing by a pilot project or the operation of an installed program in the reservoir provides support for the engineering analysis on which the project or program was based.

The reliability of reserve information is considerably affected by several factors. Reserve information is imprecise due to the inherent uncertainties in, and the limited nature of, the database upon which the estimating of reserve information is predicated. Moreover, the methods and data used in estimating reserve information are often necessarily indirect or analogical in character, rather than direct or deductive. Furthermore, estimating reserve information involves numerous judgments based upon the engineer’s educational background, professional training, and professional experience. The extent and significance of the judgments to be made are, in themselves, sufficient to render reserve information inherently imprecise.

The following information is presented with regard to our proved oil and gas reserve quantities reported in accordance with guidelines established by the SEC, and these guidelines were revised effective with the December 31, 2009 information. The impact of the revision to these reserve guidelines was not considered significant to our proved oil and gas reserve volumes. The reserve values and cash flow amounts reflected in the following reserve disclosures as of December 31, 2010 and 2009 are based on the average price of oil and natural gas during the twelve month period then ended, determined as an unweighted arithmetic average of the first-day-of-the-month for each month within the period. The reserve values and cash flow amounts as of December 31, 2008 and 2007, are based on prices as of each yearend. All of Maritech’s reserves are located in U. S. state and federal offshore waters of the Gulf of Mexico and onshore Texas and Louisiana.

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Reserve Quantity Information	Oil		NGL		Gas
	(MBbls)		(MBbls)		(MMcf)

December 31, 2007
Proved developed reserves		6,420		226		43,898
Proved undeveloped reserves		89		-		2,909
Total proved reserves at December 31, 2007		6,509		226		46,807

December 31, 2008
Proved developed reserves		4,365		139		40,988
Proved undeveloped reserves		1,433		-		1,024
Total proved reserves at December 31, 2008		5,798		139		42,012

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

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

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

Total proved reserves at December 31, 2007		6,509			226			46,807
Revisions of previous estimates		(28	)		(12	)		(1,774	)
Production		(1,384	)		(83	)		(10,989	)
Extensions and discoveries		521			-			2,771
Purchases of reserves in place		183			8			5,199
Sales of reserves in place		(3	)		-			(2	)

Total proved reserves at December 31, 2008		5,798			139			42,012
Revisions of previous estimates		1,805			166			(623	)
Production		(1,219	)		(106	)		(10,449	)
Extensions and discoveries		564			5			3,365
Purchases of reserves in place		-			-			-
Sales of reserves in place		(79	)		-			(794	)

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

Total proved reserves at December 31, 2010		6,772			489			25,585

Revisions of previous proved reserves estimates during 2010 were primarily due to the declassification of natural gas reserves associated with a portion of Maritech’s Main Pass field due to pipeline and transportation interruptions. Revisions of previous proved reserve estimates during 2009 were the result of improved performance at Maritech’s Timbalier Bay field plus improvements in oil prices, which added to the economic lives of certain fields.

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves

“Standardized measure” relates to the estimated discounted future net cash flows and major components of that calculation relating to proved reserves at the end of the year in the aggregate, based on SEC prescribed prices and costs, using statutory tax rates and using a 10% annual discount rate. The standardized measure is not an estimate of the fair value of proved oil and gas reserves. Probable and possible reserves, which may become proved in the future, are excluded from these calculations.

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Furthermore, prices used to determine the standardized measure are prior to the impact of hedge derivatives and are influenced by seasonal demand and other factors and may not be representative in estimating future revenues or reserve data.

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

	December 31,
	2010			2009
	(In Thousands)

Future cash inflows	$	673,295		$	536,594
Future costs
Production		199,196			192,152
Development and abandonment		264,074			235,042
Future net cash flows before income taxes		210,025			109,400
Future income taxes		(53,481	)		(14,846	)
Future net cash flows		156,544			94,554
Discount at 10% annual rate		(23,275	)		(8,505	)
Standardized measure of discounted future net cash flows	$	133,269		$	86,049

Changes in Standardized Measure of Discounted Future Net Cash Flows

	Year Ended December 31,
	2010			2009			2008
	(In Thousands)

Standardized measure, beginning of year	$	86,049		$	60,348		$	298,679

Sales, net of production costs		(74,718	)		(95,076	)		(110,561	)
Net change in prices, net of production costs		92,065			43,098			(297,719	)
Changes in future development and abandonment costs		(48,002	)		2,235			(30,590	)
Development and abandonment costs incurred		42,151			10,585			39,035
Accretion of discount		9,720			6,396			41,245
Net change in income taxes		(34,665	)		(7,536	)		110,150
Purchases of reserves in place		8,694			-			13,233
Extensions and discoveries		63,411			27,873			19,108
Sales of reserves in place		(58	)		1,268			(252	)
Net change due to revision in quantity estimates		(13,738	)		41,045			(6,295	)
Changes in production rates (timing) and other		2,360			(4,187	)		(15,685	)
Subtotal		47,220			25,701			(238,331	)

Standardized measure, end of year	$	133,269		$	86,049		$	60,348

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NOTE S — QUARTERLY FINANCIAL INFORMATION (Unaudited)

Summarized quarterly financial data for 2010 and 2009 is as follows:

	Three Months Ended 2010
	March 31		June 30		September 30		December 31
	(In Thousands, Except Per Share Amounts)

Total revenues	$	205,893	$	241,618	$	211,918	$	213,249
Gross profit (loss)		35,094		47,832		28,779		(67,998	)
Income (loss) before discontinued operations		5,456		13,635		187		(62,603	)

Net income (loss)		5,427		13,560		170		(62,875	)

Net income (loss) per share before
discontinued operations	$	0.07	$	0.18	$	0.00	$	(0.83	)

Net income (loss) per diluted share before
discontinued operations	$	0.07	$	0.18	$	0.00	$	(0.83	)

	Three Months Ended 2009
	March 31		June 30		September 30		December 31
	(In Thousands, Except Per Share Amounts)

Total revenues	$	195,251	$	217,944	$	253,975	$	211,707
Gross profit		43,370		40,389		62,773		66,565
Income before discontinued operations		11,370		9,210		22,812		25,415

Net income		11,162		9,175		22,662		25,805

Net income per share before discontinued
operations	$	0.15	$	0.12	$	0.30	$	0.34

Net income per diluted share before
discontinued operations	$	0.15	$	0.12	$	0.30	$	0.33

NOTE T — STOCKHOLDERS’ RIGHTS PLAN

On October 27, 1998, the Board of Directors adopted a stockholders’ rights plan (the Rights Plan) designed to assure that all of our stockholders receive fair and equal treatment in the event of a proposed takeover. The Rights Plan helps to guard against partial tender offers, open market accumulations, and other abusive tactics to gain control of our company without paying an adequate and fair price in any takeover attempt. The Rights are not presently exercisable and are not represented by separate certificates. We are currently not aware of any effort of any kind to acquire control of our company.

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

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

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