Edgar Filing: TETRA TECHNOLOGIES INC

tti10k-20100301.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, 2009

[ ] 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 [ ]

INDICATE BY CHECK MARK WHETHER THE REGISTRANT HAS SUBMITTED ELECTRONICALLY AND POSTED ON ITS CORPORATE WEB SITE, IF ANY, EVERY INTERACTIVE DATA FILE REQUIRED TO BE SUBMITTED AND POSTED PURSUANT TO RULE 405 OF REGULATION S-T DURING THE PRECEDING 12 MONTHS (OR FOR SUCH SHORTER PERIOD THAT THE REGISTRANT WAS REQUIRED TO SUBMIT AND POST SUCH FILES).

YES [ ] NO [ ]

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

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

LARGE ACCELERATED FILER [ X ]

ACCELERATED FILER [ ]

NON-ACCELERATED FILER [ ]

SMALLER REPORTING COMPANY [ ]

INDICATE BY CHECK MARK WHETHER THE REGISTRANT IS A SHELL COMPANY (AS DEFINED IN RULE 12b-2 OF THE EXCHANGE ACT).

YES [ ] NO [ X ]

THE AGGREGATE MARKET VALUE OF COMMON STOCK HELD BY NON-AFFILIATES OF THE REGISTRANT WAS $581,526,580 AS OF JUNE 30, 2009, THE LAST BUSINESS DAY OF THE REGISTRANT’S MOST RECENTLY COMPLETED SECOND FISCAL QUARTER.

NUMBER OF SHARES OUTSTANDING OF THE ISSUER’S COMMON STOCK AS OF FEBRUARY 26, 2010 WAS 75,567,051 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 5, 2010 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	11
Item 1B.	Unresolved Staff Comments	24
Item 2.	Properties	24
Item 3.	Legal Proceedings	28
Item 4.	[Removed and Reserved]	29

	Part II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and
	Issuer Purchases of Equity Securities	30
Item 6.	Selected Financial Data	31
Item 7.	Management’s Discussion and Analysis of Financial Condition
	and Results of Operation	32
Item 7A.	Quantitative and Qualitative Disclosures about Market Risk	57
Item 8.	Financial Statements and Supplementary Data	59
Item 9.	Changes in and Disagreements with Accountants on Accounting
	and Financial Disclosure	59
Item 9A.	Controls and Procedures	59
Item 9B.	Other Information	60

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

	Part IV
Item 15.	Exhibits, Financial Statement Schedules	62

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 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, an oil and gas exploration and production segment. The Offshore Services segment provides (1) downhole and subsea services such as plugging and abandonment, workover, and wireline services, (2) construction and decommissioning services, including hurricane damage remediation, utilizing our heavy lift barges and 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 and the operation of several dive support vessels.

The Maritech segment consists of our Maritech Resources, Inc. (Maritech) subsidiary, which, with its subsidiaries, is an oil and gas exploration and production company focused in the offshore, inland waters, and onshore U.S. Gulf Coast region. Maritech periodically acquires oil and gas properties in order to replenish or expand its production operations and to provide additional development and exploitation opportunities. The Offshore Division’s Offshore Services segment performs a significant portion of the well 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 onshore basins in Mexico, Brazil, Northern Africa, the Middle East, and other international markets.

The Compressco segment provides wellhead compression-based production enhancement services throughout many of the onshore producing regions of the United States, as well as basins in Canada, Mexico, South America, Europe, Asia, and other international locations. These compression services can improve the value of natural gas and oil wells by increasing daily production and total recoverable reserves.

We continue to pursue a growth strategy that includes expanding our existing businesses – both through internal growth and through the pursuit of suitable acquisitions – and by identifying opportunities to establish operations in additional U.S. and international niche oil service markets. 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, free of charge, on our website, 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, sodium bromide, calcium bromide, zinc 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 typically solids-free, clear salt solutions that have variable densities and are used as weighting fluids to control bottomhole pressures during oil and gas completion and workover activities. The use of CBFs can contribute to increased production by reducing the likelihood of damage to the wellbore and productive pay zone. CBFs are particularly important in offshore completion and workover operations due to the potentially greater formation sensitivity, the significantly greater investment necessary to drill and produce offshore, and the consequent higher cost of error. CBFs are manufactured and distributed by our Fluids Division and are also sold 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 well operators based on the specific need of the customer and the proposed application of the product. We also provide these customers with a broad range of associated services, including onsite fluid filtration, handling, and recycling; wellbore cleanup; fluid engineering consultation; and fluid management, including high volume water transfer services in support of high pressure fracturing processes. We also offer to repurchase (buyback) used CBFs from customers, which we then 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 and management personnel use proprietary technology to determine the optimal CBF blend for a customer’s particular application to maximize the effectiveness and lifespan of the CBFs. We modify the specific volume, density, crystallization temperature, and chemical composition of the CBFs to satisfy a customer’s specific requirements. Our filtration services use a variety of techniques and equipment for the onsite removal of particulates from CBFs, so that those CBFs can be recirculated back into the well. Filtration also enables recovery of a greater percentage of used CBFs for recycling.

The Fluids Division produces CBFs from its production facilities that manufacture liquid and dry calcium chloride, sodium bromide, calcium bromide, zinc bromide and zinc calcium bromide for distribution 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.

We manufacture liquid and dry calcium chloride in production facilities located in the United States and Europe. We also acquire raw material and production from other sources, including non-owned plants under agreements with the owners. During the fourth quarter of 2009, we began production of liquid calcium chloride at our newly completed plant near El Dorado, Arkansas. This plant also began production of dry (flake) calcium chloride during January 2010. Dry calcium chloride is also produced at our Kokkola, Finland

plant. We operate our European calcium chloride manufacturing operations under the name TETRA Chemicals Europe. We also operate a plant in Lake Charles, Louisiana, where we produce mainly dry calcium chloride. We manufacture liquid calcium chloride from our facility in Parkersburg, West Virginia and have two solar evaporation plants located in San Bernardino County, California, which produce liquid calcium chloride from underground brine reserves. These plant facilities have a combined production capacity of more than 1.5 million tons per year.

We manufacture and distribute sodium bromide, calcium bromide and zinc bromide from our West Memphis, Arkansas, facility. A patented and proprietary production process utilized at this facility uses bromine or hydrobromic acid, along with various zinc sources, to manufacture these products. The group purchases raw material bromine pursuant to a long-term supply agreement. This facility also uses patented and proprietary technologies to recondition and upgrade used CBFs repurchased from our customers. In addition, our El Dorado, Arkansas, plant facility produces magnesium hydroxide as a by-product, and, beginning in 2011, will be capable of sodium chloride (salt) production.

We also have approximately 33,000 gross acres of bromine-containing brine reserves in Magnolia, Arkansas, that are under lease. We hold these assets for possible future development.

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: the Offshore Services and Maritech segments. The Offshore Services segment provides (1) downhole and subsea services such as plugging and abandonment (P&A), workover, and wireline services, (2) construction and decommissioning services, including hurricane damage remediation, utilizing our heavy lift barges and 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 and the operation of several dive support vessels. While we are a leading provider of these services to the offshore Gulf of Mexico well abandonment and decommissioning markets, we provide these services to other oilfield markets as well, including the inland water and onshore markets in the Gulf of Mexico region. We offer comprehensive, integrated solutions to our customers, including engineering consultation and project management services. We provide individualized services to meet our customers’ specific requirements. The Maritech segment is an oil and gas exploration and production company focused in the offshore, inland waters, and onshore regions of the U.S. Gulf of Mexico. Maritech periodically acquires oil and gas properties in order to replenish or expand its production and to provide additional development and exploitation opportunities. The Offshore Division’s Offshore Services segment performs a significant portion of the well abandonment and decommissioning services required by Maritech, and Maritech is a significant customer of the Offshore Services segment.

In providing its array of services, our Offshore Services segment utilizes barge-mounted rigs, a platform rig, offshore rigless P&A packages, two heavy lift vessels, several dive support vessels and other dive support assets and onshore rigs which we own and operate. In addition, we rent certain equipment from third party contractors whenever necessary. The Division provides a wide variety of contract diving services to its customers through our subsidiary, Epic Diving & Marine Services (Epic). Construction, well abandonment, and decommissioning services are performed primarily offshore in the Gulf of Mexico, although the Division also provides well abandonment services to customers in the inland waters and onshore in Texas and Louisiana. The Division also provides onshore and offshore cutting services and tool rentals through its E.O.T. Rentals (EOT) operations. The Division’s electric wireline operations 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 has been successful in marketing its experience, utilizing the specialized equipment and engineering expertise necessary to address a variety of specific construction and platform decommissioning issues, including project management and the issues associated with platforms toppled or severely damaged by hurricanes in the Gulf of Mexico. The Division 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 Division’s fleet of service vessels has been adjusted in recent years to serve the changing demand for well abandonment, construction, platform decommissioning, diving, and other offshore services. We currently have two vessels with the capacity to perform heavy lift 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, which we renamed the Epic Diver, and refurbished two of Epic’s existing dive support vessels, the Epic Explorer and the Epic Seahorse. Both the Epic Diver and the Epic Explorer offer saturation diving systems that are rated for up to 1,000 foot dive depths. Beginning in June 2009, we increased our service fleet through the leasing of a specialized dive service vessel which is being utilized for hurricane recovery work.

Maritech acquires, manages, explores, and develops oil and gas properties in the offshore, inland water, and onshore U.S. Gulf Coast region. Maritech periodically acquires oil and gas properties in order to replenish or expand its production and to provide additional development and exploitation opportunities. The Offshore Division’s Offshore Services segment performs a significant portion of the well abandonment and decommissioning services required by Maritech. Federal regulations generally require lessees to plug and abandon wells and decommission the associated platforms, pipelines, and other equipment within one year after the lease terminates.

Maritech grows its operations by acquiring and developing oil and gas property interests located in the offshore, inland waters, and onshore U.S. Gulf of Mexico region. Maritech acquires both producing oil and gas properties as well as prospect acreage, and performs development and exploitation efforts in order to increase its oil and gas reserves and replace depleting production. During 2009, Maritech participated in drilling three wells, one each in Galveston Island 321, Main Pass 279, and Timbalier Bay fields. All three wells were successful with an average net finding cost of $12.90 per equivalent barrel (BOE). Maritech also participated in numerous successful recompletions in Timbalier Bay, Lake Hermitage, and the West Delta area. Maritech’s most significant development efforts currently consist of East Cameron 328, the Dromedary prospect acreage located onshore Louisiana, and the Timbalier Bay field located in the inland waters area of Louisiana. The most recent acquisitions of producing oil and gas properties were in December 2007 and January 2008, when Maritech purchased oil and gas producing properties for an aggregate of $74.9 million of cash and the assumption of associated decommissioning liabilities having an undiscounted value of approximately $51.5 million. In December 2007, we acquired interests in certain offshore properties located primarily in the Main Pass area of the Gulf of Mexico from a subsidiary of Cimarex Energy (the Cimarex Properties). Maritech completed a new condensate pipeline in April 2008, which eliminated the barging of produced condensate from the Cimarex Properties, resulting in significantly increased production in an area from which production had previously been restricted. Since acquiring the Cimarex Properties, Maritech has completed the hookup and has begun production from additional subsea wells in the Main Pass area. In January 2008, we acquired certain offshore oil and gas producing properties from Stone Energy Corporation. During the three year period ended December 31, 2009, Maritech has invested significantly in its acquisition and exploitation activities, spending approximately $290.2 million on such projects, although such activities decreased during 2009 due to capital spending constraints. Maritech’s activities also include the plugging, abandonment, and decommissioning efforts on its offshore oil and gas properties, particularly as part of its strategy to reduce its risk from future storms and in response to the increasing cost of windstorm insurance coverage. During the three year period ended December 31, 2009, Maritech has expended approximately $131.8 million on such efforts. As of December 31, 2009, Maritech had proved reserves of approximately 7.1 million barrels of oil and 33.5 billion cubic feet of natural gas, with undiscounted future net pretax cash flow of approximately $109.4 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, providing reservoir data necessary to enable operators to optimize production and minimize oil and gas reservoir damage. In addition, the Production Testing segment provides services for coiled tubing, pipeline cleanout, blowout prevention, well cleanup, and laboratory analysis. The Production Testing segment also provides early-life production solutions designed to access newly available production and 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 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 specifically designed to work in environments in which high levels of hydrogen sulfide gas are present. The Production Testing segment has operating locations in each of the operating areas in which it serves, including Louisiana, Oklahoma, Pennsylvania, and throughout Texas. Internationally, the segment has several locations in Mexico and South America, North Africa, Middle East, Asia, and Europe.

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 South American refinery locations. The contract is expected to be performed in project stages over the next one to three year period.

The Division’s Compressco segment is a leading provider of wellhead compression-based production enhancement services to a broad base of natural gas and oil exploration and production companies. These production enhancement services include compression, liquids separation, gas metering services, and ongoing well evaluations. Although Compressco’s services are applied primarily to mature wells with low formation pressures, the services are also employed on newer wells that have experienced significant production declines or that are characterized by lower formation pressures. Compressco designs and manufactures the compressor equipment (GasJack® units) it uses to provide production enhancement services. Compressco’s fleet of GasJack® units totaled 3,627 as of December 31, 2009, of which 2,660 units were in service, representing a decrease in the number of units in service of approximately 13% from the prior year.

Compressco’s GasJack® unit increases gas production by reducing surface pressure to allow wellbore liquids that would normally block gas flow to produce up the well. The fluids are separated from the gas and liquid-free gas flows into the GasJack® unit, where the gas is compressed. The 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, while the other cylinders provide compression. This configuration is capable of creating suction conditions that range from 12 in/hg (inches of mercury) of negative pressure to 60 PSIG (Pounds per Square Inch Gauge) of positive pressure and discharge pressures of up to 450 PSIG. Compressco utilizes its GasJack® 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. To a lesser extent, Compressco also sells GasJack® units to customers.

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, sodium bromide, calcium bromide, zinc bromide, magnesium hydroxide, and zinc calcium 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 from a reaction of hydrochloric acid and limestone and from natural underground brine reserves. The Division also purchases liquid and dry calcium chloride from a number of U.S. and international chemical manufacturers. Some of the Division’s primary sources of hydrochloric acid are chemical co-product streams obtained from chemical manufacturers. We have written agreements with certain of those chemical companies regarding the supply of hydrochloric acid, bromine, or calcium chloride. We significantly increased our production capacity following the construction of our El Dorado, Arkansas, calcium chloride plant facility, which finished testing in September 2009 and began production of liquid calcium chloride during the fourth quarter of 2009. This plant is located on land purchased from Chemtura Corporation (Chemtura) and adjacent to Chemtura’s central bromine plant, located near El Dorado, Arkansas. This new plant is designed to produce liquid and flake calcium chloride, along with other co-products such as magnesium hydroxide and sodium chloride, and will allow the Division to reduce its

dependence on third-party hydrochloric acid suppliers. The plant is designed to utilize calcium chloride containing brines (tail brine) obtained from Chemtura’s operations. We purchase raw materials utilized by our Lake Charles facility to produce liquid and dry (pellet) calcium chloride from a variety of sources. We also produce calcium chloride at our two plants in San Bernardino County, California, through evaporation of naturally occurring underground brine reserves. These underground brine reserves are deemed adequate to supply our foreseeable need for calcium chloride in that market area. 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. We purchase limestone from several different sources. Currently, hydrochloric acid and limestone are generally available from multiple sources.

To produce calcium bromide, zinc bromide, and zinc calcium bromide at our West Memphis, Arkansas, facility, we use primarily bromine and various sources of zinc raw materials and lime. We use proprietary and patented processes that permit the use of cost-advantaged raw materials, while maintaining high product quality. There are multiple sources of zinc that we can use in the production of zinc bromide. In December 2006, we entered into a long-term supply agreement with Chemtura, whereby 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 bromine extraction. During March 2009, Chemtura announced that it 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, such as our agreements with them under which we acquire bromine and brine. During the fourth quarter of 2009, we negotiated certain amendments to our existing agreements with Chemtura, as well as certain other agreements, and such amended agreements were approved by the bankruptcy court. While the amended agreements do include an increase in the cost of raw material bromine from Chemtura, other amendments to the agreements partially mitigate the impact of the increased costs.

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 have approximately 33,000 gross acres of bromine-containing brine reserves under lease 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. We believe we have sufficient brine reserves under lease to operate a world-scale bromine facility for 25 to 30 years. 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 the development of the Magnolia, Arkansas, assets.

Our Production Enhancement Division, through its Production Testing segment, outsources the construction of production testing equipment to third-party manufacturers. This equipment is used to provide the flow back pressure and volume testing services to the segment’s customers. The Compressco segment designs and assembles its GasJack® units which it uses to provide wellhead compression-based production enhancement services. Some of the components used in the GasJack® units are obtained from a single supplier or a limited group of suppliers. Compressco does not have long-term contracts with these suppliers. While a partial or complete loss of certain of these suppliers could have a negative impact on Compressco’s business, Compressco believes that there are adequate, alternative suppliers of these components and that this impact would not be severe.

Market Overview and Competition

Fluids Division

Our Fluids Division sells CBFs, drilling and completion fluid systems, additives, and related products and services to oil and gas exploration and production companies, onshore and offshore, in the United States and worldwide. Current areas of market presence include the U.S. onshore Gulf Coast, the U.S. Gulf of Mexico, the North Sea, Mexico, South America, Europe, Asia, and Africa. The Division is also capitalizing on the current trend toward deepwater operations which utilize a larger volume of CBFs and are subject to harsh downhole conditions such as high pressure and high temperatures. 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. Although much of Petrobras’ activity associated with this contract was deferred during 2009, we anticipate that activity in Brazil will be increasing beginning in 2010.

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 L.L.C., a joint venture between Smith International, Inc. and Schlumberger Limited; and BJ Services Company, which has announced that it is being acquired by Baker Hughes. This market is highly competitive, and competition is based primarily on service, availability, and price. Although all competitors provide fluid handling, filtration, and recycling services, we believe that our historical focus on providing these and other value-added services to our customers have enabled us to compete successfully. Major customers of the Fluids Division include Anadarko, Chevron, Devon, Dominion Resources, EOG Resources, Halliburton Company, LLOG Exploration, Newfield Exploration Company, Nippon Oil Exploration, and Shell Oil. The Division also sells its 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 to which our products are marketed include agricultural, industrial, roadway dust control and de-icing, mining, janitorial, construction, pharmaceutical, and food processing. These products promote snow and ice melt, dust control, cement curing, food processing, dehumidification, and road stabilization and are also used as a source of calcium nutrients to improve agricultural yields. We also sell sodium bromide into the industrial water treatment markets as a biocide under the BioRid® trade name. Most of these markets are highly competitive. The Division’s European calcium chloride manufacturing operations based in Kokkola, Finland, permit us to market our calcium chloride products to certain European markets. Our major competitors in the calcium chloride market 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. The Division’s Offshore Services operations provide downhole and subsea services such as well abandonment, contract diving, construction, cutting, and decommissioning services offshore, primarily in the U.S. Gulf of Mexico. In addition, the Division also provides well abandonment, workover, and wireline services in the onshore and inland water areas of the U.S. Gulf Coast regions of Texas and Louisiana. Long-term demand for the Offshore Division’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 Division’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. In the market areas in which we currently operate, 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. 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. Current and projected demand for offshore abandonment and decommissioning services 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. The Division has developed specialized equipment and engineering expertise to provide such services to customers whose offshore wells and production platforms were toppled, destroyed, or heavily damaged by such storms. The threat of future storm activity, combined with increases in hurricane insurance premiums and deductibles, has also accelerated the abandonment and decommissioning plans for undamaged wells and structures of many offshore operators. Offshore activities in the Gulf of Mexico have historically been 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 participate in the current market include, among other factors: having an adequate fleet of the proper equipment to meet current market demand and conditions; having qualified, experienced personnel; having technical expertise to address varying downhole, surface, and subsea conditions, particularly those related to damaged wells and platforms; having the financial strength to ensure all abandonment and decommissioning obligations are satisfied; and having a comprehensive safety and environmental program. We believe our integrated service package and vessel fleet satisfy these market requirements, allowing us to successfully compete.

The Division markets its services primarily to major oil and gas companies and independent operators. Major customers include Apache, Chevron, Mariner Energy, Nexen Petroleum USA Inc., Shell Oil, Stone Energy, and W&T Offshore. These services are performed primarily offshore in the U.S. Gulf of Mexico and in the Gulf Coast inland waters and onshore in Texas and Louisiana. Our principal competitors in the offshore and inland water 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 successfully bid our services can fluctuate from year to year, depending on market conditions.

The Division’s Maritech operation competes with a wide number of independent Gulf of Mexico operators for the acquisition and leasing of oil and gas properties. Maritech typically acquires oil and gas properties from major oil and gas companies as well as from independent operators. Our ability to acquire producing oil and gas properties under acceptable terms is dependent on numerous factors, including oil and natural gas commodity prices, the availability of suitable properties for acquisition, the age and condition of offshore production platforms, and the level of competition from other operators pursuing such properties. Maritech sells its oil and gas production to a variety of purchasers. We believe that Maritech’s access to its affiliated Offshore Services segment allows it to better assess and evaluate the abandonment and decommissioning obligations associated with acquired properties. This access gives Maritech an advantage over many other operators with which it competes for property acquisitions.

Production Enhancement Division

The Production Enhancement Division, through its Production Testing and Compressco segments, 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 reservoirs containing high levels of hydrogen sulfide gas. The Division provides the specialized equipment and qualified personnel to address these impediments to production and to pressure test wells and wellhead equipment. The Production Testing segment also provides a variety of reservoir management and laboratory testing services for oil and gas producing properties, including coiled tubing, pipeline cleanout, blowout prevention, well cleanup, distillation analysis, gas composition analysis, and oilfield water analysis services. 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, working with our Compressco segment.

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. 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. Our customers include Chesapeake, ConocoPhillips, El Paso Corporation, Encana Oil & Gas, Quicksilver Resources, Shell Oil, PEMEX (the national oil company of Mexico), Petrobras (the national oil company of Brazil), Saudi ARAMCO (the national oil company of Saudi Arabia), and other national oil companies in foreign countries.

The Division’s Compressco segment provides production enhancement services to over 400 natural gas and oil producers 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. Most of Compressco’s services are performed in the Ark-La-Tex Basin, San Juan Basin, and Mid-Continent region of the United States. While Compressco has historically targeted natural gas wells in its operating regions that produce between 30 thousand and 300 thousand cubic feet of natural gas per day, it is also effectively enhancing production in certain basins with production of up to one million cubic feet of daily production. Compressco believes that the majority of the wells it targets do not currently utilize production enhancement services. 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. While 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 quality of its services, its trained field personnel, and its GasJack® unit that it uses to provide the services. Compressco’s major customers include BP, PEMEX, Devon, Chesapeake, and EXCO Resources.

Other Business Matters

Marketing and Distribution

The Fluids Division markets its CBF products and services through its distribution facilities located in the Gulf Coast region of the United States, the North Sea region of Europe, and other selected 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, 2009.

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. Our estimated backlog on December 31, 2009 was $121.9 million, of which approximately $7.6 million is expected to be billed during 2010. This compares to an estimated backlog of $137.8 million at December 31, 2008.

Employees

As of December 31, 2009, we had 2,837 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, 2009, we owned or licensed twenty-nine issued U.S. patents and had six patent applications pending in the United States. Internationally, we had fifteen owned or licensed foreign patents and one foreign patent application 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 2026. 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. As a policy, we use all possible legal means to protect our patents, trade secrets, and other proprietary information.

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; the Minerals Management Service of the U.S. Department of the Interior (MMS); 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 affect on operations.

At our production plants, 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. 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.

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 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;

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

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

·	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 important risk factors which 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 are materially dependent on the supply, demand, and prices for oil, natural gas, and competing energy sources, and more particularly dependent on the supply, demand, and prices for well completion, compression, diving, and abandonment and decommissioning products and services, both in the United States and abroad. 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 and uncertainty of the capital markets caused by the recent global recession and financial crisis. Decreased energy consumption has resulted in a decrease in energy prices during much of 2009 compared to prices received during early to mid-2008. This decline in energy prices, along with concerns regarding the availability of capital, has negatively affected the operating cash flows and capital plans of many of our customers, as well as our Maritech subsidiary, which has negatively impacted the demand for many of our products and services.

If current economic conditions continue or worsen, there may be additional constraints on oil and gas industry spending levels for an extended period of time. 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. Many of our customers finance their drilling and production operations through third-party lenders. The reduced availability and increased cost of borrowing could cause our customers to reduce their spending on drilling programs, thereby reducing demand and potentially resulting in lower pricing for our products and services. Continued instability in the capital markets, as a result of recession or otherwise, also may continue to affect the cost of capital and the ability to raise capital, both for us and our customers.

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. Current economic conditions may be exacerbated by insufficient financial sector liquidity, leading to additional constraints on the operating cash flows of our customers, further limiting their activities and also 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.

Further, an increasing number of financial institutions and insurance companies have reported deterioration in their financial condition. If any of our lenders, insurers or other financial institutions are unable to fulfill their obligations under our various credit agreements, insurance policies and other contracts, and we are unable to find suitable replacements at a reasonable cost, our results of operations, liquidity and cash flows could be adversely impacted.

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

Our revenues from oil and gas production represent approximately 19.8% of our total consolidated revenues for the year ended December 31, 2009. 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 for our unhedged production and the fixed prices in our derivative contracts for the portion of our oil and gas production that is hedged. During 2009, the

crude oil and natural gas prices we received averaged $61.35 and $4.00, respectively, prior to the impact of our derivative contracts. These crude oil and natural gas prices were significantly below the prices we received during 2008, and price volatility for crude oil and natural gas is expected to continue. Significant further 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 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. A portion of our production is sold at a fixed price as a shield against price declines that could occur in the market. These hedging activities limit our upside potential from oil and gas price increases, but also limit our downside risk of decreasing oil and gas prices. In addition, 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, our derivative swap contracts do not extend beyond December 31, 2010.

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 activity levels include the finding, development, and acquisition costs of oil and natural gas reserves; the oil and gas industry spending levels for exploration, development, and acquisition activities; production costs; plugging and abandonment costs; insurance costs; the success rate 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 region of the U.S. Gulf of Mexico. Our revenues and profitability are particularly dependent upon oil and gas industry activity and spending levels in the Gulf of Mexico 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 or more cost-effective products or services, our business could be materially and adversely affected. Certain competitors may also be better positioned to acquire producing oil and gas properties or other businesses for which we compete.

We are dependent upon 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, 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 needs as well as for the needs of our new 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 current general economic conditions, many chemicals manufacturing feedstock suppliers are experiencing reduced demand, production interruptions, and financial difficulties. For example, during March 2009, Chemtura announced that it 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, such as our agreements with them under which we acquire 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. While the amended agreements do include an increase in the cost of raw material bromine from Chemtura, other amendments partially mitigate the impact of the increased costs. 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 supply constraints for certain of our manufacturing facilities have resulted in certain facilities operating at less than full capacity and resulted in decreased production volumes. A limitation of feedstock supply for our European calcium chloride manufacturing facility affected the production levels of that operation during a portion of 2009 and could affect its operations in the future. The purchase of alternative supplies at a less favorable cost could also result in decreased profitability.

Some of the well abandonment and decommissioning services performed by our Offshore Division 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 GasJack® wellhead compressor units by our Compressco subsidiary 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. Our Compressco operation’s profitability or future growth 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 (and expect to rely in the future) on facilities developed and owned by third parties in order to process, transmit, and sell our oil and gas production. 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.

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 is high, and the supply is limited. A lack of qualified personnel, therefore, could adversely affect operating results.

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

The current economic environment has resulted 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 also 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. In connection with the preparation of our annual financial statements as of December 31, 2008, we determined that a $47.1 million impairment of goodwill was required. If current economic and market conditions persist or decline further, we may be required to record an additional charge to earnings during the period in which any impairment of our goodwill is determined, resulting in an impact on our results of operations.

Operating 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 a particularly high level 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 expenditure investments, 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 such recent or future acquisition transactions by us may not achieve favorable financial results. Our operating results could also 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, particularly if we do not provide for economic downturns. Future acquisitions by us could also result in issuances of equity securities, or the rights associated with the equity securities, which could potentially dilute earnings per share. Future acquisitions could also 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.

Though we believe our products and services employ state of the art technologies and methodologies, competitors constantly evolve their technologies and methodologies and replace their used assets with new assets. If we are unable to adapt to new advances 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 our heavy lift barges and dive services vessels, are approaching the end of their useful lives and may adversely affect our ability to serve certain customers. The replacement or upgrade of any of these vessels will likely 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 new El Dorado, Arkansas, calcium chloride plant facility may not be as timely or as high as expected.

We have recently completed the construction of a new calcium chloride plant facility near El Dorado, Arkansas. The plant’s future profitability and the advantages we expect to receive from the plant will be based on many factors, including the sales prices to be received for the plant’s products, raw material and operating costs, and future demand for products. In addition, delays in the completion of the final phases of the calcium chloride facility, as well as changes in its operating environment, could also affect future profitability for our Fluids Division operations compared to 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 uncertainties surrounding estimates of oil and gas reserve volumes, finding and development costs, production costs, and abandonment and decommissioning costs. To the extent we over-estimate future oil and natural gas sales prices, economically recoverable reserve volumes, or future production flow rates, or 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, collisions, and hurricanes;

·	other adverse weather conditions;

·	shortages or delays in the delivery of equipment; and

·	compliance with environmental and other government requirements, which may increase our costs or restrict our activities.

During the three year period ended December 31, 2009, we have expended approximately $290.2 million of exploration and development costs, and we expect to continue to incur significant costs in the future. During this three year period ended December 31, 2009, we charged approximately $10.8 million of dry hole costs incurred to earnings. Future drilling activities also may not be successful, and, if unsuccessful, this failure 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. In addition, 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 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, 2009 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 2009, Maritech adjusted its decommissioning liability, either for work performed during the year or related to adjusted estimates of the cost of future work to be performed. Approximately $23.8 million of this adjustment was charged to earnings as an operating expense during 2009. 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 42.3% of our proved reserves as of December 31, 2009 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, 2009, and primarily due to increased decommissioning liabilities and the decrease in oil and natural gas prices, we recorded oil and gas property impairments on proved properties totaling approximately $130.2 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 while damage is being assessed and remediated. The costs to bring damaged offshore wells under control and to repair or remove damaged offshore platforms and pipelines can be significant. Moreover, even if we do not experience direct damage from storms, we may experience disruptions in our operations because customers or suppliers may curtail their activities due to damage to their wells, platforms, pipelines, and other facilities.

We will expend significant costs to repair damage as a result of 2005 and 2008 hurricanes, and a large portion of these costs 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. Reconstruction of the two destroyed production facilities is substantially complete, and one of the destroyed platforms was decommissioned during 2009. 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 destroyed offshore platforms and the construction of replacement platforms and redrilling of a number of destroyed wells. While a 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 portion of the work has yet to be performed. Through December 31, 2009, we have expended approximately $75.8 million for the well intervention, abandonment, decommissioning, and debris removal work performed on the platforms and production facilities which were destroyed by the storms. The remaining damage assessment, well intervention, and subsequent debris removal efforts could continue over the next several years. We estimate that remaining well intervention, abandonment, and decommissioning efforts associated with the destroyed platforms and production facilities, as well as the efforts to remove debris, reconstruct destroyed structures, and redrill associated wells, will be performed at an additional cost of approximately $95 to $110 million net to our interest and before any insurance recoveries. Due to the non-routine nature of the well intervention and debris removal efforts, however, our estimates of the future cost to perform this work may be understated, possibly significantly.

Approximately $45 to $50 million of the remaining well intervention, abandonment, decommissioning, and debris removal efforts are associated with the offshore platforms which were destroyed by Hurricanes Katrina and Rita. An estimate of these costs has been accrued for as part of Maritech’s decommissioning liability. During the fourth quarter of 2009, we entered into a settlement agreement with Maritech’s insurers and other associated parties under which we received approximately $40.0 million associated with the unreimbursed well intervention costs incurred or to be incurred. Except for approximately $0.6 million of proceeds expected to be received in March 2010, no significant additional insurance recoveries of well intervention, debris removal, or excess property damage costs associated with Hurricanes Katrina and Rita will be received. Following the collection of these amounts, we have collected substantially all of the maximum coverage limits pursuant to our policies.

With regard to the damages associated with Hurricane Ike, we have performed a significant majority of the property repairs on the damaged platforms and have performed a portion of the well intervention work related to the platforms that were destroyed. Despite our confidence that the repair, well intervention, and debris removal costs will qualify as covered costs pursuant to our insurance coverage, a portion of these costs may not be reimbursed. 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. 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 has resulted in the loss of production from a key producing field which represented 24.3% of our pre-storm production. 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. The full resumption of production from this field will require the construction of a new platform and several wells to be redrilled, and these efforts are estimated to cost approximately $25 to $30 million, before insurance recoveries, and are not scheduled to be completed until 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.

We may elect to continue to self-insure windstorm damage to our Maritech assets in the Gulf of Mexico, which could result in significant uninsured losses.

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. If premiums, deductibles, and policy limits for windstorm insurance remain as unfavorable for the June 2010 through May 2011 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, 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 continued availability of insurance or its availability at premium levels that justify its purchase.

Financial Risks:

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

As of December 31, 2009, our total debt outstanding was approximately $310.1 million and our debt to total capital ratio was 35.0%. This debt to total capital ratio excludes approximately $33.4 million of available cash held as of December 31, 2009. 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.

Our bank revolving credit facility is scheduled to mature in June 2011, and our Senior Notes are scheduled to mature at various dates between September 2011 and April 2016. The replacement of these capital sources at similar or more favorable terms is uncertain.

We are exposed to significant credit risks.

We face credit risk associated with the significant amounts of accounts receivable we have with our customers in the energy industry. Many of our customers, particularly those associated with our onshore operations, are small to medium-sized oil and gas 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, will subject 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 which bear interest at an agreed upon percentage rate spread above LIBOR. Although as of December 31, 2009, 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 are 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 June 2006. The revolving credit facility is scheduled to mature in June 2011. The terms governing our Senior Notes were agreed to in September 2004, April 2006, and April 2008, and these Senior Notes all bear interest at fixed interest rates and are scheduled to mature at various dates between September 2011 and April 2016. The terms for our indebtedness were negotiated during a period of historically low interest rates and credit spreads. There can be no assurance that the financial market conditions at the times these existing debt agreements are renegotiated will be on terms as favorable as their current terms.

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 types of government regulation, 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 federal leases that are administered by the Minerals Management Service (MMS) and are required to comply with the regulations and orders promulgated by the MMS under the Outer Continental Shelf Lands Act. MMS 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. Under limited circumstances, the MMS could require us to suspend or terminate our operations on a federal lease. The MMS also establishes the basis for royalty payments due under federal oil and natural gas leases through regulations issued under applicable statutory authority.

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.

Legislation currently pending in the U.S. Congress would establish an economy-wide cap-and-trade program to reduce U.S. emissions of greenhouse gases. Under this legislation, EPA would issue a capped and steadily declining number of tradable emissions allowances to certain major sources of greenhouse gas emissions so that such sources could continue to emit greenhouse gases into the atmosphere. 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. In addition, a variety of regulatory developments, proposals, or requirements have been introduced and/or adopted in international regions in which we operate that are focused on restricting the emission of carbon dioxide, methane, and other greenhouse gases.

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, 2009. We believe our facilities are adequate for our present needs.

Fluids Division. Fluids Division facilities include eight 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 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.

In addition to the above production plant facilities, 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-nine terminal locations, fifteen 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 which 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 Diver	220-foot dive support vessel with saturation diving system
Epic Explorer	210-foot dive support vessel with saturation diving system
Epic Seahorse	210-foot dive support vessel
Epic Mariner	110-foot dive support vessel

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

Production Enhancement Division. Production Enhancement Division facilities include fifteen production testing distribution facilities in the U.S. (thirteen of which are leased) located in Texas, Colorado, Louisiana, and Pennsylvania. In addition, the Production Testing segment has leased facilities in Brazil, Mexico, Libya, Bahrain, India, and Saudi Arabia. Compressco’s facilities include a fabrication and headquarters facility in Oklahoma, a leased fabrication facility in Alberta, Canada, a leased service facility in New Mexico, 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 Gulf of Mexico region. Maritech’s oil and gas operations are a separate segment included within our Offshore Division. The following table provides a brief description as of December 31, 2009 of Maritech’s most significant oil and gas properties:

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

Timbalier Bay Area	4,606	76%	24%	67	8,270	7,174	100%	Producing
Cimarex Properties,
Main Pass Area	2,101	13%	87%	16	71,172	14,984	47% - 100%	Producing
East Cameron 328	2,024	92%	8%	6	5,000	-	50%	Producing

Production information for each of these most significant properties during the three years ended December 31, 2009 is as follows:

	Year Ended December 31,
	2009	2008	2007
	(MBOE)

Timbalier Bay Area	764	1,289	1,702
Cimarex Properties,
Main Pass Area	1,034	580	4
East Cameron 328	60	275	403

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 reserves in conformance with guidelines established by the SEC. These SEC 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 value of the oil and gas reserves was affected by the impact of the new average pricing requirements. 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 80.2% of our proved reserve volumes as of December 31, 2009. The use of the term “reserve audit” is intended only to refer to the collective application of the engineering and geologic procedures which the independent petroleum engineering firms were engaged to perform and may be defined and used differently by other companies.

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, 2009, 2008, and 2007. 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 Cimarex Properties, and represented approximately 64.0% of our total proved oil and gas reserve volumes as of December 31, 2009. The reserve audit performed by DeGolyer and MacNaughton included the Cimarex Properties acquired in December 2007 and represented approximately 16.2% of our total proved oil and gas reserve volumes as of December 31, 2009. The independent petroleum engineers represent in their audit reports that they believe Maritech’s estimates of future reserves were prepared in accordance with generally accepted petroleum engineering and evaluation principles for the estimation of future reserves in accordance with SEC standards. In each case, the independent petroleum engineers concluded 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). 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 Louisiana. The following table sets forth information with respect to our estimated proved reserves as of December 31, 2009:

Summary of Oil and Gas Reserves as of December 31, 2009
Based on Average Year Prices

	Oil	Natural Gas	Total
Reserves category	(MBbls)	(MMcf)	(MBOE)
Proved reserves
Developed	5,690	32,387	11,088
Undeveloped	1,383	1,124	1,570
Total proved reserves	7,073	33,511	12,658

Maritech’s proved undeveloped reserves as of December 31, 2009 represent approximately 12.4% of Maritech’s total proved reserves. Proved undeveloped reserves represented approximately 12.4% of Maritech total proved reserves as of December 31, 2008. During 2009, Maritech did not expend any of its development costs to convert proved undeveloped reserves to proved developed reserves. All of Maritech’s proved undeveloped reserves as of December 31, 2009 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.

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 (the 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 2009, 2008, and 2007:

	Year Ended December 31,
	2009		2008		2007
Production:
Natural gas (Mcf)		10,449,366		10,988,840		9,515,214
Oil (Bbls)		1,324,815		1,466,621		1,985,183

Revenues:
Natural Gas	$	87,905,000	$	99,901,000	$	76,202,000
Oil		86,286,000		107,279,000		137,136,000

Total	$	174,191,000	$	207,180,000	$	213,338,000

Average realized unit prices and production costs:
Natural gas (per Mcf)	$	8.41	$	9.09	$	8.01
Oil (per Bbl)	$	65.13	$	73.15	$	69.08

Production cost per equivalent barrel	$	25.80	$	27.18	$	25.08
Depletion cost per equivalent barrel	$	25.96	$	25.14	$	20.70

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, $8.5 million, and $13.5 million being charged in 2009, 2008, and 2007, respectively. Equivalent barrel (BOE) information is calculated assuming six Mcf of gas is equivalent to one barrel of oil. Insurance recoveries during 2009 totaled approximately $45.4 million 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, 2009, 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	13	1	1.20	0.10	7,468	7,123	4,169	3,855
Louisiana Offshore	42	32	42.00	32.00	8,270	8,270	7,174	6,580
Texas Offshore	-	-	-	-	7,200	1,532	-	-
Federal Offshore	42	55	22.50	22.30	281,972	138,136	52,482	38,022

Total	97	88	65.70	54.40	304,910	155,061	63,825	48,457

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 2010 through 2014.

Drilling Activity. 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. Maritech participated in the drilling of 16 gross development wells (11.4 net wells) during 2007, two of which were unproductive. As of December 31, 2009, one additional gross exploratory well (1.0 net wells) was in the process of being drilled. In the first quarter of 2010, Maritech sold a 50% working interest in this well to a partner. As of December 31, 2008, one additional gross well (0.5 net wells) was in the process of being drilled. As of December 31, 2007, there were 5 additional wells (2.5 net wells) in the process of being drilled.

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.

Insurance Litigation - Through December 31, 2009, we have expended approximately $55.2 million on well intervention and debris removal work primarily associated with the three Maritech offshore platforms and associated wells which were destroyed as a result of Hurricanes Katrina and Rita in 2005. As a result of submitting claims associated with well intervention costs expended during 2006 and 2007 and responding to underwriters’ requests for additional information, approximately $28.9 million of these well intervention costs were reimbursed; however, our insurance underwriters maintained that well intervention costs for certain of the damaged wells did not qualify as covered costs and certain well intervention costs for qualifying wells were not covered under the policy. In addition, the underwriters also maintained that there was no additional coverage provided under an endorsement we obtained in August 2005 for the cost of debris removal associated with these platforms or for other damage repairs associated with Hurricanes Katrina and Rita on certain properties in excess of the insured values provided by the property damage section of the policy. Although we provided requested information to the underwriters and had numerous discussions with the underwriters, brokers, and insurance adjusters, we did not receive the requested reimbursement for these contested costs. As a result, on November 16, 2007, we filed a lawsuit in Montgomery County, Texas, entitled Maritech Resources, Inc. v. Certain Underwriters and Insurance Companies at Lloyd’s, London subscribing to Policy no. GA011150U and Steege Kingston, in which we sought damages for breach of contract and various related claims and a declaration of the extent of coverage of an endorsement to the policy. We also made an alternative claim against our insurance broker, based on its procurement of the August 2005 endorsement, and a separate claim against underwriters’ insurance adjuster for its role in handling the insurance claim.

During October 2009, we entered into a settlement agreement with regard to this lawsuit, under which we received approximately $40.0 million during the fourth quarter of 2009 associated with the August 2005 endorsement and well intervention costs incurred or to be incurred from Hurricanes Katrina and Rita. Except for approximately $0.6 million of proceeds expected to be received in March 2010, no significant additional insurance recoveries of well intervention, debris removal, or excess property damage costs associated with Hurricanes Katrina and Rita will be received. Following the collection of these amounts, we have collected approximately $136.6 million of insurance proceeds associated with damage from Hurricanes Katrina and Rita. This amount represents substantially all of the maximum coverage limits pursuant to our policies. We estimate that future well intervention, abandonment, decommissioning, and debris removal efforts related to these destroyed platforms will result in approximately $45 million to $50 million of additional costs, and an estimate of these costs has been accrued for as part of Maritech’s decommissioning liability. As a result of the resolution of this contingency, the full amount of settlement proceeds is reflected as a credit to earnings in the fourth quarter of 2009.

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 of our 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. The complaints allege that the defendants violated the federal securities laws during the period by, among other things, disseminating false and misleading statements and/or concealing material facts concerning our current and prospective business and financial results. The complaints also allege that, as a result of these actions, our stock price was artificially inflated during the class period, which enabled our insiders to sell their personally-held shares for a substantial gain. The complaints seek unspecified compensatory damages, costs, and expenses. 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 August 27, 2008, Lead Plaintiff Fulton County Employees’ Retirement System filed its Amended Consolidated Complaint. On October 28, 2008, we filed a motion to dismiss the federal class action. On July 9, 2009, the Court issued an opinion dismissing, without prejudice, most of the claims in this lawsuit but permitting plaintiffs to proceed on their allegations regarding disclosures pertaining to the collectability of certain insurance receivables.

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.

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.

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 23, 2010, there were approximately 10,800 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, 2009, as reported by the New York Stock Exchange.

	High		Low
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

2008
First Quarter	$	19.38	$	13.56
Second Quarter		25.00		14.72
Third Quarter		24.02		5.69
Fourth Quarter		7.24		3.12

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, 2004, 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, or 2009 pursuant to the repurchase program. Shares repurchased during the fourth quarter of 2009 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, 2009		-		$	-		-	$	14,327,000

Nov 1 - Nov 30, 2009		1,929	(2)	$	10.01		-	$	14,327,000

Dec 1 - Dec 31, 2009		-		$	-		-	$	14,327,000

Total		1,929					-	$	14,327,000

(1)

(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, 2009, 2008, 2007, 2006, and 2005. The selected consolidated financial data does not purport to be complete and should be read in conjunction with, and is qualified by, the more detailed information, including the Consolidated Financial Statements and related Notes and “Management’s Discussion and Analysis of Financial Condition and Results of Operation” appearing elsewhere in this report. Please read “Item 1A. Risk Factors” beginning on page 11 for a discussion of the material uncertainties which might cause the selected consolidated financial data not to be indicative of our future financial condition or results of operations. During 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 2005, we acquired certain oil and gas properties as part of our Maritech subsidiary’s operations. These acquisitions significantly impact the comparison of our financial statements for 2009 to earlier years. 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, 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.

	Year Ended December 31,
	2009			2008			2007			2006			2005
	(In Thousands, Except Per Share Amounts)
Income Statement Data
Revenues	$	878,877		$	1,009,065		$	982,483		$	767,795		$	509,249
Gross profit		213,097			152,001			116,383			252,804			123,672	(1)
Operating income (loss)		112,265			(21	)		16,512			160,800			54,317
Interest expense		(13,207	)		(17,557	)		(17,886	)		(13,637	)		(6,310	)
Interest income		417			779			731			348			330
Other income (expense), net		5,895			12,884			2,805			4,858			3,692
Income (loss) before discontinued
operations		68,807			(9,655	)		1,221			99,880			34,802
Net income (loss)	$	68,804		$	(12,136	)	$	28,771		$	101,878		$	38,062

Income (loss) per share, before
discontinued operations (2)	$	0.92		$	(0.13	)	$	0.02		$	1.39		$	0.51
Average shares (2)		75,045			74,519			73,573			71,631			68,588

Income (loss) per diluted share, before
discontinued operations (2)	$	0.91		$	(0.13	)	$	0.02		$	1.33		$	0.48
Average diluted shares (2)		75,722	(3)		74,519	(4)		75,921	(5)		74,824			72,137

(1)	Gross profit for this period reflects the reclassification of certain billed operating costs as cost of revenues, which had previously been credited to general and administrative expense. The reclassified amount was $1,113 for 2005.
(2)	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, and a 3-for-2 stock split as of August 19, 2005. Each of the stock splits was effected in the form of a stock dividend as of the record dates.
(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, 2008, 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 period.
(5)	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,
	2009		2008		2007		2006		2005
	(In Thousands)
Balance Sheet Data
Working capital	$	148,343	$	222,832	$	181,441	$	262,572	$	135,989
Total assets		1,347,599		1,412,624		1,295,536		1,086,190		726,850
Long-term debt		310,132		406,840		358,024		336,381		157,270
Decommissioning and other
long-term liabilities		218,498		277,482		247,543		167,671		150,570
Stockholders' equity	$	576,494	$	515,821	$	447,919	$	420,380	$	284,147

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

Despite a decrease in consolidated revenues during 2009 compared to the prior year, our overall profitability increased, primarily due to the unprecedented favorable performance of our Offshore Services segment, a favorable insurance litigation settlement, and due to significant impairments to oil and gas properties and goodwill during 2008. The demand for diving, platform decommissioning, cutting, and abandonment services continued to be strong during the year 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 increased demand plus the additional efficiencies resulting from high utilization and optimal weather conditions during most of 2009 significantly benefitted the Offshore Services segment. We expect demand for these services to continue to be robust in 2010. Maritech’s revenues decreased during 2009 due to lower oil and gas pricing compared to 2008, despite having a large portion of the impact of decreased pricing offset by Maritech’s oil and gas hedge contracts. In addition, Maritech’s oil and gas production volumes decreased compared to the prior year due to the reduction in development activities over the past year and due to the continuing impact from Hurricane Ike in 2008, which shut-in production from a significant oil producing field. Despite these decreases in revenue, Maritech’s profitability increased compared to 2008 primarily due to the October 2009 settlement agreement with the various parties to our insurance litigation regarding certain costs associated with Maritech offshore platforms which were damaged or destroyed by Hurricanes Katrina and Rita during 2005. This settlement resulted in approximately $40.0 million of settlement gain during 2009. These increases in profitability were partially offset by the results of our Production Testing, Compressco, and Fluids operations, which experienced decreased demand from customers during 2009, resulting in decreased revenues and profitability. Although these operations continue to be affected by the lingering impact of the current global economic environment, we expect modest increases for these operations beginning in 2010 as a result of improving oil and gas commodity pricing and rig count levels, which are expected to result in increased activity for our customers. All of our businesses took steps during 2009 to reduce operating and administrative costs through temporary salary reductions, project deferrals, consolidation of locations, and other measures, and intend to continue to seek additional ways to maximize earnings and cash flow going forward.

The current cost reduction efforts also include a focus on improving cash flow and enhancing liquidity through a combination of reducing or deferring capital expenditures and carefully managing working capital. As a result of these efforts, and despite the difficult market environment for many of our businesses, operating cash flows increased compared to the prior year to approximately $272.3 million, and investing activities decreased compared to the prior year to $149.7 million. During the fourth quarter of 2009 we repaid the remaining outstanding balance under our bank revolving credit facility and accumulated approximately $33.4 million of available cash as of December 31, 2009. These efforts were accomplished despite expending approximately $149.7 million of capital expenditures and other investing activities during 2009, including $65.9 million for the continuing construction of our new El Dorado, Arkansas, calcium chloride plant facility, compared to $56.6 million during 2008. The El Dorado facility began production during the fourth quarter of 2009 and is expected to further increase the Fluids Division’s efficiency in manufacturing its chemicals and completion fluids products, which should strengthen operating cash flows in future years. In addition, we made significant progress during 2009 in the abandonment and decommissioning of many of Maritech’s offshore oil and gas property assets, expending approximately $79.5 million. These abandonment and decommissioning efforts are expected to continue to be significant going forward. As of December 31, 2009, Maritech has remaining decommissioning liabilities of approximately $218.4 million, including the remaining well intervention, abandonment, decommissioning and debris removal work to be done associated with offshore platforms destroyed by 2005 and 2008 hurricanes. In addition to the $40.0 million proceeds related to our insurance litigation settlement, we also generated additional cash from the liquidation of certain hedge derivative contracts and from sales of certain non-strategic assets. Given the expected prolonged economic recovery for certain of our businesses, we plan to continue to review future capital expenditures carefully as we also monitor the expected improvement of our operations. Despite this focus on conserving capital resources, we continue to seek strategic growth opportunities, both through acquisitions and internal growth, which we plan to fund from operating cash flows, and if necessary, from additional long-term debt borrowing. We continue to have availability under our bank revolving credit facility, which is scheduled to mature in June 2011. Our Senior Notes are scheduled to mature at various dates from September 2011 through April 2016.

Future demand for our products and services depends primarily on activity in the oil and gas exploration and production industry, which is significantly affected by that industry’s 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. Industry expenditures, as indicated by rig count statistics and other

measures, have recently begun to increase following the significant decline during the past year which was in response to the general uncertainty regarding availability of capital resources in the current economic environment and due to oil and natural gas price volatility. Our overall growth remains hampered by the current decreased industry demand for many of our products and services, although we still believe that there are growth opportunities for our products and services in the U.S. and international markets, supported primarily by:

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

·	continued reservoir depletion in the U.S. and the advancing age of offshore platforms in the Gulf of Mexico, which will drive abandonment and decommissioning work; and

·	increasing development of oil and gas reserves abroad.

Our Fluids Division generates revenues and cash flows by manufacturing and selling clear brine completion fluids (CBFs) and providing filtration, water transfer, and associated products and 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 decreased 23.1% during 2009 compared to the prior year, due primarily to a significant decrease in sales volumes, both of its CBF products and its other manufactured chemicals, primarily due to decreased energy industry demand. The overall outlook for the Division’s completion services business is 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. Overall industry drilling activity during 2009 was also negatively impacted by lower oil and natural gas prices during much of the year compared to 2008 and increased capital constraints as a result of the general economic conditions. We anticipate modest increases in spending beginning in 2010 given the current levels of oil and natural gas 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 brine solutions. In addition, we are also pursuing specific international opportunities where industry spending levels from major energy customers and national oil companies have generally been more stable. During 2008, the Fluids Division entered into a long-term contract with Petroleo Brasileiro S.A. (Petrobras) to provide completion fluids for its deepwater drilling program offshore Brazil. Although much of Petrobras’ activity associated with this contract was deferred during 2009, we anticipate that activity in Brazil will be increasing beginning in 2010. To further the growth of the Division’s manufactured products operation and provide additional internally produced supply for our completion fluids operations, in 2007 we began construction of a new calcium chloride plant facility located near El Dorado, Arkansas. During the fourth quarter of 2009, we began production of liquid calcium chloride at our newly completed calcium chloride plant. This plant also began production of dry (flake) calcium chloride during January 2010.

Our Offshore Division consists of two operating segments: the Offshore Services segment and the Maritech segment. Offshore Services generates revenues and cash flows by performing (1) downhole and subsea services such as plugging and abandonment, workover, and wireline services, (2) construction and decommissioning services, including 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 MMS 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. In addition, the segment continues to capitalize on the current demand for well abandonment and decommissioning services in the Gulf of Mexico, including a portion of the work to be performed over the next several years on offshore properties that were damaged or destroyed by the significant hurricanes that occurred in 2005 and 2008. Given the increasing cost to insure offshore properties, many oil and gas operators are accelerating their plans to abandon and decommission their offshore wells and platforms. Offshore Services revenues increased by 15.5% during 2009 primarily associated with the increased utilization, particularly by the segment’s diving, abandonment, heavy lift, and cutting services businesses which continue to enjoy high demand following the 2005 and 2008 hurricanes. In addition, the segment benefitted from near-optimal weather conditions during most of 2009. Although it expects robust demand for its services to continue, the segment anticipates its overall activity in 2010 will decrease from the record levels experienced during 2009, as the remaining hurricane remediation work moves at a less urgent pace and due to an expected return to normal levels of weather disruptions.

Through Maritech and its subsidiaries, 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. During 2009, Maritech’s operations continued to be hampered by production interruptions from the 2008 hurricanes, reduced funding for capital expenditures, and the need to perform significant well intervention and decommissioning efforts. Maritech has five remaining toppled offshore platforms that will require extensive efforts to decommission, and much of this work is planned for 2010. Maritech’s revenues during 2009 decreased by 15.1% compared to 2008, due to decreased overall production and lower oil and gas commodity prices compared to 2008. Although much of the storm-interrupted production has been restored, one of the destroyed offshore platforms served a key producing field, the East Cameron 328 field. Although a portion of the production from this field has been restored, the complete restoration of East Cameron 328 production will require the reconstruction of the destroyed platform and the redrilling of wells, and these efforts are not expected to be complete until 2011. Maritech’s existing lease portfolio, along with exploitation opportunities on producing leases, should continue to provide Maritech with additional attractive development projects, subject to capital expenditure constraints as a result of the current economic environment.

Our Production Enhancement Division consists of two operating segments: the Production Testing segment and Compressco segment. The Production Testing segment generates revenues and cash flows by performing flow back pressure, volume testing, and other services for oil and gas producers. The primary testing markets served include many of the major oil and gas basins in the United States as well as onshore basins in Mexico, Brazil, Northern Africa, the Middle East, and certain other international markets. 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 which the Production Testing segment serves. Production Testing segment revenues decreased 36.6% in 2009 as compared to 2008, primarily due to decreased demand in the United States. Given the recent increase in oil and natural gas pricing, we expect demand for our production testing services will increase in 2010 compared to 2009.

Compressco generates revenues and cash flows by performing wellhead compression-based production enhancement services throughout many of the onshore producing regions of the United States, as well as basins in Canada, Mexico, South America, Europe, Asia, and other international locations. Demand for wellhead compression services is generally driven by the need to boost production in certain mature gas wells with declining production. Compressco segment revenues decreased 9.6% in 2009 as compared to 2008, due to decreased U.S. and international demand for production enhancement services, primarily resulting from decreased natural gas prices. Given the recent increase in oil and natural gas prices, we anticipate Compressco’s 2010 revenues and cash flows will increase compared to 2009, 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 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 we have historically had minimal impairments of long-lived assets other than for oil and gas properties (see separate discussion below), during 2009 we recorded other long-lived asset impairments of $8.1 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, 2009, 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 14.8%, 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 Gas Jack® compressor units. The demand for Compressco’s wellhead compression services has been negatively affected by the global economic environment and the decrease in natural gas prices compared to the prior year. Further decreases in such demand 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 2007, 2008, and 2009 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 current 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 – We estimate the third-party market values (including an estimated profit to the service provider) to plug and abandon the wells, decommission the pipelines and platforms, and clear the sites, and we use these estimates to record Maritech’s well abandonment and decommissioning liabilities. 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 utilizes 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. Any profit we earn in performing such abandonment and decommissioning operations on Maritech’s properties is recorded as the work is performed. 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 additional profit on the project 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 liability whenever indicators suggest that either the amount or timing of the estimated cash flows underlying the liability 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, and other general changes in the energy industry environment. Accordingly, the estimation of our decommissioning liability is imprecise. The estimation of the decommissioning liability associated with the five 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 liability and has resulted in charges to earnings in the period the work is performed or when the additional liability is recorded. During 2008 and 2009, the amount of charges to earnings as a result of costs in excess of our estimated liabilities has been significant. To the extent our decommissioning liability is 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.

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, such as in the current economic environment, 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.

	Percentage of Revenues									Period-to-Period
	Year Ended December 31,									Change
Consolidated Results of Operations	2009			2008			2007			2009 vs 2008			2008 vs 2007

Revenues		100.0	%		100.0	%		100.0	%		(12.9	%)		2.7	%
Cost of revenues		75.8	%		84.9	%		88.2	%		(22.3	%)		(1.0	%)
Gross profit		24.2	%		15.1	%		11.8	%		40.2	%		30.6	%
General and administrative expense		11.5	%		10.4	%		10.2	%		(3.9	%)		5.1	%
Operating income (loss)		12.8	%		0.0	%		1.7	%	NM				(100.1	%)

Interest expense		1.5	%		1.7	%		1.8	%		(24.8	%)		(1.8	%)
Interest income		0.0	%		0.1	%		0.1	%		(46.5	%)		6.6	%
Other income (expense), net		0.7	%		1.3	%		0.3	%		(54.2	%)		359.3	%
Income (loss) before income taxes and
discontinued operations		12.0	%		(0.4	%)		0.2	%	NM				(281.1	%)
Net income (loss) before discontinued operations		7.8	%		(1.0	%)		0.1	%	NM				(890.7	%)
Discontinued operations, net of tax		(0.0	%)		(0.2	%)		2.8	%		(99.9	%)		(109.0	%)
Net income (loss)		7.8	%		(1.2	%)		2.9	%	NM				(142.2	%)

	Year Ended December 31,
	2009			2008			2007
	(In Thousands)
Revenues

Fluids Division	$	225,517		$	293,248		$	282,074
Offshore Division
Offshore Services		353,798			306,362			341,082
Maritech		177,039			208,509			214,154
Intersegment eliminations		(45,648	)		(22,971	)		(29,057	)
Total		485,189			491,900			526,179
Production Enhancement Division
Production Testing		80,557			127,019			93,130
Compressco		88,108			97,417			83,554
Total		168,665			224,436			176,684
Intersegment eliminations		(494	)		(519	)		(2,454	)
		878,877			1,009,065			982,483

Gross profit

Fluids Division	$	47,549		$	56,446		$	38,620
Offshore Division
Offshore Services		94,488			43,025			49,110
Maritech		20,655			(29,958	)		(45,631	)
Intersegment eliminations		571			(782	)		6,225
Total		115,714			12,285			9,704
Production Enhancement Division
Production Testing		19,164			44,413			32,813
Compressco		33,689			41,323			36,685
Total		52,853			85,736			69,498
Other		(3,019	)		(2,466	)		(1,439	)
		213,097			152,001			116,383

	Year Ended December 31,
	2009			2008			2007
	(In Thousands)

Income (loss) before taxes and discontinued operations

Fluids Division	$	20,791		$	5,401		$	10,897
Offshore Division
Offshore Services		78,394			3,019			33,496
Maritech		22,012			(31,932	)		(49,815	)
Intersegment eliminations		647			(782	)		6,225
Total		101,053			(29,695	)		(10,094	)
Production Enhancement Division
Production Testing		17,690			35,677			25,639
Compressco		23,563			30,310			26,663
Total		41,253			65,987			52,302
Corporate overhead		(57,727	)		(45,608	)		(50,943	)
		105,370			(3,915	)		2,162

2009 Compared to 2008

Consolidated Comparisons

Revenues and Gross Profit – Our total consolidated revenues for 2009 were $878.9 million compared to $1,009.1 million for the prior year, a decrease of 12.9%. Total consolidated gross profit increased to $213.1 million during 2009 compared to $152.0 million in the prior year, an increase of 40.2%. Consolidated gross profit as a percentage of revenue was 24.2% during 2009 compared to 15.1% during the prior year. See the Divisional Comparisons section below for a discussion of the changes in consolidated revenues and gross profit during 2009 compared to 2008.

General and Administrative Expenses – General and administrative expenses were $100.8 million during 2009 compared to $104.9 million during 2008, a decrease of $4.1 million or 3.9%. This decrease was 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. Despite these net decreases, general and administrative expenses as a percentage of revenue increased to 11.5% during 2009 compared to 10.4% during the prior year due to decreased revenues.

Other Income and Expense – Other income and expense was $5.9 million of income during 2009 compared to $12.9 million of income during the prior year, primarily due to the change in hedge ineffectiveness, as we recognized approximately $1.7 million of hedge ineffectiveness losses during the current year 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.

Interest Expense and Income Taxes – Net interest expense decreased to $12.8 million during 2009 compared to $16.8 million during 2008, despite increased borrowings of long-term debt during much of the year, which were used to fund our 2009 capital expenditure and working capital requirements. The decrease 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 new 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. Our provision for income taxes during 2009 increased to $36.6 million compared to $5.7 million during the prior year, primarily due to increased earnings.

Net Income – Net income before discontinued operations was $68.8 million during 2009 compared to a net loss before discontinued operations of $9.7 million in the prior year, an increase of $78.5 million. Net income per diluted share before discontinued operations was $0.91 on 75,721,651 average diluted shares outstanding during 2009 compared to a net loss per diluted share before discontinued operations of $0.13 on 74,519,371 average diluted shares outstanding in the prior year.

During the fourth quarter of 2007, we sold our process services operation for approximately $58.7 million, net of certain adjustments. During the fourth quarter of 2006, we made the decision to discontinue our Venezuelan fluids and production testing businesses due to several factors, including the changing political climate in that country. Net loss from discontinued operations was $0.0 million during 2009 compared to $2.5 million of net loss from discontinued operations during 2008.

Net income was $68.8 million during 2009 compared to a net loss of $12.1 million in the prior year, an increase of $80.9 million. Net income per diluted share was $0.91 on 75,721,651 average diluted shares outstanding during 2009 compared to a net loss per diluted share of $0.16 on 74,519,371 average diluted shares outstanding in the prior year.

Divisional Comparisons

Fluids Division – Our Fluids Division revenues during 2009 were $225.5 million, a decrease of $67.7 million compared to $293.2 million of revenues during the prior year. This 23.1% decrease 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 current trend of many operators 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 Division expects that the new facility, along with a general improvement in economic conditions, will contribute to increased revenues beginning in 2010.

Our Fluids Division gross profit decreased to $47.5 million during 2009 compared to $56.4 million during the prior year, a decrease of $8.9 million or 15.8%. The decrease in 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, to 21.1% during 2009 compared to 19.2% during 2008, primarily 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 Division expects that the new plant will result in reduced product costs and increased profitability in the future, particularly once the plant begins to produce at full capacity. Such benefits are expected despite increased raw material costs following the 2009 renegotiation of certain terms of our supply contracts with Chemtura Corporation (Chemtura) pursuant to Chemtura’s bankruptcy proceedings during the past year.

Fluids Division income before taxes during 2009 totaled $20.8 million compared to $5.4 million during the prior year, an increase of $15.4 million or 284.9%. This increase 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 $6.6 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 – Revenues from our Offshore Division decreased from $491.9 million during 2008 to $485.2 million during 2009, a decrease of $6.7 million or 1.4%. Offshore Division gross profit during 2009 totaled $115.7 million compared to $12.3 million during the prior year, an increase of $103.4 million or 841.9%. Offshore Division income before taxes was $101.1 million during 2009 compared to a loss before taxes of $29.7 million during the prior year, an increase of $130.7 million.

The revenues of the Division’s Offshore Services operations increased to $353.8 million during 2009 compared to $306.4 million during the prior year, an increase of $47.4 million or 15.5%. This increase 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 service vessel which was utilized for contracted hurricane recovery work during the remainder of the year and is expected to be utilized in early 2010. Following the current winter season, the Offshore Services segment plans to continue to capitalize on the anticipated high demand levels for well abandonment and decommissioning services in the Gulf of Mexico to be performed over the next several years on offshore properties which were damaged or destroyed by hurricanes. 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 of such 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. A significant amount of such work is planned for Maritech during 2010.

The Offshore Services segment of the Division reported gross profit of $94.5 million during 2009 compared to $43.0 million of gross profit during 2008, a $51.5 million or 119.6% increase. The Offshore Services segment’s gross profit as a percentage of revenues was 26.7% during 2009 compared to 14.0% during the prior year. This increase 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 the current year period, 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 from $3.0 million during 2008 to $78.4 million during 2009, an increase of $75.4 million or 2,496.9%. This increase was due to the $51.5 million 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.

The Division’s Maritech operations reported revenues of $177.0 million during 2009 compared to $208.5 million during the prior year, a decrease of $31.5 million or 15.1%. 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. Realized oil and natural gas prices during the first quarter of 2010 have increased, however, compared to the average prices received during 2009. 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. Maritech has restored the majority of the storm-

interrupted production from East Cameron 328, but will continue to have a portion of its production shut-in until a new platform can be constructed to replace a platform which was toppled during Hurricane Ike. During the fourth quarter of 2009, Maritech installed additional production equipment on the remaining platform in the field in order to restore a portion of the field’s production. 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.

Maritech reported gross profit of $20.7 million during 2009 compared to negative gross profit of $30.0 million during 2008, an increase of $50.6 million. This increase was despite the $31.5 million decrease in revenue discussed above. Maritech’s gross profit as a percentage of revenues during 2009 was 11.7%. This 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.

Maritech reported income before taxes of $22.0 million during 2009, compared to a pretax loss of $31.9 million during 2008, an increase of $53.9 million. This increase was due to the $50.6 million 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 compared to the prior year.

Production Enhancement Division – Production Enhancement Division revenues decreased from $224.4 million during 2008 to $168.7 million during 2009, a decrease of $55.8 million or 24.9%. Production Enhancement Division gross profit decreased from $85.7 million during 2008 to $52.9 million during 2009, a decrease of $32.9 million or 38.4%. Production Enhancement Division gross profit as a percentage of revenue also decreased from 38.2% during 2008 to 31.3% during 2009. Production Enhancement Division income before taxes decreased during 2009 to $41.3 million compared to $66.0 million during 2008, a decrease of $24.7 million or 37.5%.

Production Testing revenues decreased significantly during 2009 to $80.6 million, a 36.6% or $46.5 million decrease compared to $127.0 million during 2008. This decrease was due to the decrease in U.S. operations, primarily from reduced drilling activity as reflected by the U.S. rig count. The decreased demand has 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 also decreased from $44.4 million during 2008 to $19.2 million during 2009, a decrease of $25.2 million or 56.9%. Gross profit as a percentage of revenues also decreased from 35.0% during 2008 to 23.8% during 2009. This decrease in gross profit was due to the weaker demand, lower day rates, and decreased activity in the U.S.

Production Testing income before taxes decreased from $35.7 million during 2008 to $17.7 million during 2009, a decrease of $18.0 million or 50.4%. This decrease was due to the $25.2 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 revenues during 2009 decreased to $88.1 million during 2009 compared to $97.4 million during 2008, a decrease of $9.3 million and 9.6%, reflecting the decreased U.S. demand during most of 2009 compared to the prior year. Lower natural gas prices compared to the prior year and general industry economic conditions have resulted in decreased demand for wellhead compression services, as reflected in Compressco’s reduced utilization of its GasJack® compressor fleet. In response to the current economic environment, beginning in early 2009, Compressco has slowed its 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 from $41.3 million during 2008 to $33.7 million during 2009, a decrease of $7.6 million or 18.5%. Gross profit as a percentage of revenues also decreased from 42.4% during 2008 to 38.2% during 2009. This decrease in gross profit was primarily 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 from $30.3 million during 2008 to $23.6 million during 2009, a decrease of $6.7 million or 22.3%. This decrease was primarily due to the $7.6 million of decreased gross profit discussed above, partially offset by approximately $0.7 million of decreased administrative costs and $0.2 million of increased other income.

Corporate Overhead – 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 Overhead increased from $45.6 million during 2008 to $57.7 million during 2009, primarily due to increased administrative expense, depreciation and other expense. Corporate administrative costs increased approximately $6.0 million, 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, Corporate Overhead expense increased due to a $9.7 million change in other income (expense) during 2009 compared to 2008. This increase was primarily 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 by approximately $4.1 million during 2009 primarily due to an increase in the amount of interest capitalized on construction projects during the period.

2008 Compared to 2007

Consolidated Comparisons

Revenues and Gross Profit – Total consolidated revenues for the year ended December 31, 2008 were $1,009.1 million compared to $982.5 million for the prior year, an increase of 2.7%. Consolidated gross profit increased to $152.0 million during 2008 compared to $116.4 million in the prior year, an increase of 30.6%. Consolidated gross profit as a percentage of revenue was 15.1% during 2008 compared to 11.8% during the prior year period. Our profitability during 2008 and 2007 was significantly affected by several factors, which are discussed in detail in the Divisional Comparisons section below.

General and Administrative Expenses – General and administrative expenses were $104.9 million during 2008 compared to $99.9 million during the prior year, an increase of $5.1 million or 5.1%. This increase was primarily due to $1.5 million of increased legal and professional services fees, $1.6 million of increased bad debt expenses, $0.2 million of increased office expenses, and $1.7 million of other increased general expenses. Despite approximately $1.5 million of increased option expense, total personnel costs increased only approximately $0.1 million, due to decreased salaries, insurance, and other employee related

expenses. General and administrative expenses as a percentage of revenue were 10.4% during 2008 compared to 10.2% during the prior year.

Impairment of Goodwill – 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 adverse impact 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. As part of our annual test of goodwill impairment, we estimated the fair value of each of our reporting units, and determined, based on these estimated values, that an impairment of the goodwill of our Fluids and Offshore Services reporting units was necessary, primarily due to the market factors discussed above. Accordingly, during the fourth quarter of 2008, we recorded total impairment charges of $47.1 million associated with the goodwill impairment for these segments.

Other Income and Expense – Other income and expense was $12.9 million of income during 2008 compared to $2.8 million of income during 2007, primarily due to approximately $8.5 million of increased ineffectiveness gains from liquidated commodity derivatives, $1.6 million of increased equity from earnings of unconsolidated joint ventures, $1.4 million of increased currency exchange gains, and $0.9 million from increased gains from sales of long-lived assets. These increases were partially offset by approximately $2.3 million of decreased other income, primarily due to a $1.4 million legal settlement expensed during the current year and a $1.2 million legal settlement credited to earnings during 2007.

Interest Expense and Income Taxes – Net interest expense decreased from $17.2 million during 2007 to $16.8 million during the current year. This decrease occurred despite the increased borrowings of long-term debt used to fund our capital expenditure and acquisition requirements during 2007 and 2008 and was due to lower interest rates during the period as well as due to increased interest capitalized associated with our capital construction projects. Interest expense will increase in future periods as these capital construction projects are completed and to the extent additional borrowings are used to fund our acquisition and capital expenditure plans. Our provision for income taxes during 2008 increased to $5.7 million compared to $0.9 million during the prior year, primarily due to the increased effective state tax rate for certain of our operations and the nondeductible nature of a portion of our goodwill impairments during 2008.

Net Income (Loss) – Net loss before discontinued operations was $9.7 million during 2008 compared to net income of $1.2 million in 2007, a decrease of $10.9 million. Net loss per diluted share before discontinued operations was $0.13 on 74,519,371 average diluted shares outstanding during 2008 compared to net income per diluted share before discontinued operations of $0.02 on 75,920,768 average diluted shares outstanding during the prior year.

During the fourth quarter of 2007, we sold our process services operation for approximately $58.7 million, net of certain adjustments, as this operation was not a strategic part of our core operations. In addition, during the fourth quarter of 2006, we made the decision to discontinue our Venezuelan fluids and production testing businesses due to several factors, including the changing political climate in that country. Loss from discontinued operations was $2.5 million during 2008 compared to income from discontinued operations of $27.6 million during 2007, primarily due to the $25.8 million after tax gain on the sale of the process services operations during the prior year.

Net loss was $12.1 million during 2008 compared to net income of $28.8 million in 2007, a decrease of $40.9 million. Net loss per diluted share was $0.16 on 74,519,371 average diluted shares outstanding during 2008 compared to $0.38 of net income per diluted share on 75,920,768 average diluted shares outstanding in the prior year.

Divisional Comparisons

Fluids Division – Fluids Division revenues during 2008 were $293.2 million, compared to $282.1 million during 2007, an increase of $11.2 million or 4.0%. This increase was primarily due to $14.0 million of increased revenues from the sales of manufactured products, particularly in Europe, primarily resulting from increased pricing. In addition, the Division reported $11.2 million of increased service revenues primarily due to increased U.S. onshore service activity as well as the April 2007 acquisition of the assets and operations of a company providing fluids transfer and related services in support of high pressure fracturing processes. These increases were partially offset by decreased brine sales revenues, which declined $14.1 million due to

decreased sales volumes and prices, particularly during the last half of 2008, as many operators were recovering from the third quarter 2008 hurricanes. A large portion of the demand for the Division’s products and services is affected by the level of drilling activity, including deepwater drilling, particularly in the Gulf of Mexico region. This decrease in brine sales, particularly U.S. offshore, is expected to continue during 2009 as operators continue to recover from the storms and as overall spending in the oil and gas industry remains decreased due to the current economic uncertainty. However, during 2008, we entered into a long-term contract with Petrobras to provide completion fluids for its deepwater drilling program offshore Brazil, which should contribute added revenues in future years.

Our Fluids Division gross profit increased to $56.4 million during 2008, compared to $38.6 million during the prior year, an increase of $17.8 million or 46.2%. Gross profit as a percentage of revenue increased to 19.2% during 2008 compared to 13.7% during the prior year. This increase in gross profit was primarily due to the increased service activity discussed above. In addition, rainy weather conditions during much of 2007 negatively impacted the Division’s onshore and completion services operations. The increased raw material costs for certain of our manufactured products were largely offset by decreased brine costs. A favorable long-term supply for certain of the Division’s raw material needs has been secured, and the Division has begun to reflect lower product costs as a result. In December 2007, the Division terminated its remaining purchase commitment under its previous supply agreement in consideration of its agreement to pay $9.3 million, which was charged to operations during the fourth quarter of 2007.

Fluids Division income before taxes during 2008 totaled $5.4 million compared to $10.9 million in the prior year, a decrease of $5.5 million or 50.4%. This decrease was due to an impairment of the Division’s goodwill for $23.9 million during the fourth quarter of 2008, which more than offset the $17.8 million increase in gross profit discussed above. In addition, the Division reported approximately $0.1 million of decreased administrative expenses and approximately $0.4 million of increased other income, as a $1.4 million charge for a legal settlement and $0.6 million of decreased gains on asset sales were more than offset by $1.5 million of increased foreign currency gains and $0.9 million of increased earnings from unconsolidated joint ventures.

Offshore Division – The revenues of our Offshore Division decreased from $526.2 million during 2007 to $491.9 million during 2008, a decrease of $34.3 million or 6.5%. Offshore Division gross profit during 2008 totaled $12.3 million compared to $9.7 million during 2007, an increase of $2.6 million or 26.6%. Offshore Division loss before taxes was $29.7 million during 2008 compared to a $10.1 million loss before taxes during the prior year, a decrease of $19.6 million.

The Division’s Offshore Services operations revenues decreased by 10.2% to $306.4 million during 2008 compared to $341.1 million in the prior year, a decrease of $34.7 million. Excluding intercompany work performed for Maritech, Offshore Services revenues decreased by $28.6 million, or 9.2%. Decreased heavy lift capacity as compared to the prior year resulted in approximately $52.7 million of decreased segment revenue, as the Offshore Services segment had two additional leased vessels operating during a portion of 2007. In addition, the Division’s operations were plagued by poor weather throughout much of 2008 due to three named storms in addition to Hurricanes Gustav and Ike, resulting in disruptions to the Division’s planned activities. These decreases were partially offset by increased diving and cutting services, which have particularly increased following the hurricanes which occurred during the third quarter of 2008. The Division aims to capitalize on the current and expected demand for well abandonment, decommissioning, diving, and other service activity in the Gulf of Mexico, including the work to be performed over the next several years on offshore properties that were damaged or destroyed by hurricanes in 2005 and 2008.

The Offshore Services segment of the Division reported gross profit of $43.0 million during 2008, a $6.1 million decrease compared to $49.1 million during 2007. Offshore Services gross profit as a percentage of revenues also decreased to 14.0% during 2008 compared to 14.4% during 2007. The 12.4% decrease in gross profit was primarily due to the $8.7 million impairment of certain long-lived assets during 2008. In addition, the segment experienced significant decreases in abandonment and decommissioning activity as a result of the reduced heavy lift capacity and weather disruptions throughout the year. Weather resulted in a postponement of several projects throughout the year, resulting in reduced efficiency and profit for these projects. These decreases more than offset the operating efficiencies of our dive services business, which generated significant efficiencies from high utilization, particularly following the third quarter 2008 hurricanes. In addition, during 2007 the Offshore Services segment charged approximately $2.0 million to operations related to a contested insurance claim. Intercompany profit on work performed for Maritech’s insured storm damage repairs is not recognized until such time as the associated insurance claim proceeds are collected by

Maritech. During 2007, insurance claim collections related to intercompany work performed in 2006 for Maritech contributed to the recognition of an additional $6.2 million of Division intercompany gross profit.

The Offshore Services segment’s income before taxes decreased from $33.5 million during 2007 to $3.0 million during 2008, a decrease of $30.5 million or 91.0%. This decrease was due to the $6.1 million decrease in gross profit described above and due to a $23.2 million charge for goodwill impairment during the fourth quarter of 2008. In addition, other income decreased by approximately $1.5 million, primarily due to a legal settlement received during the prior year. These decreases were partially offset by a $0.3 million decrease in administrative expenses.

The Division’s Maritech operations reported revenues of $208.5 million during 2008 compared to $214.2 million during 2007, a decrease of $5.6 million, or 2.6%. As a result of Hurricane Ike during the third quarter of 2008, Maritech suffered damage to many of its offshore production platforms and third-party pipelines and facilities, which caused many of its producing properties to be shut-in during much of the last four months of 2008. Three offshore platforms and one inland water production facility were destroyed by Hurricane Ike, one of which served a key producing field. These destroyed platforms are in addition to the three offshore platforms destroyed by hurricanes during 2005. Much of Maritech’s daily production is processed through neighboring platforms, pipelines, and processing facilities of other operators and third parties, many of which were also damaged during the storm. As a result, a portion of Maritech’s production remains shut-in. Due primarily to the impact of these storms and despite increased gas production as a result of successful exploitation and development activities and from the acquisitions of properties over the past two years, overall equivalent barrel production volumes decreased during 2008 compared to the prior year, resulting in $23.7 million of decreased revenues. This decrease was largely offset by $17.6 million of increased revenue from higher oil and natural gas prices for much of 2008 compared to the prior year. However, beginning in the third quarter of 2008 and continuing into 2009, oil and natural gas prices have declined significantly. Maritech has hedged a portion of its expected future production levels by entering into derivative hedge contracts, with certain contracts extending through 2010. In addition to the impact from decreased production volumes and increased prices, Maritech revenues also increased $0.5 million during 2008 compared to the prior year, due to increased platform processing revenues. The full resumption of Maritech’s pre-storm production levels may never occur and will depend on the extent of damage and the repairs or reconstruction needed on certain assets. In addition, while Maritech plans to continue to replace its depleting oil and gas reserves through development activities, the amount of such expenditures must now be evaluated more critically in light of the current lower price environment and our need to conserve capital.

The Division’s Maritech operations reported a negative gross profit of $30.0 million during 2008 compared to $45.6 million of negative gross profit during 2007, a decrease in the amount of loss of $15.7 million or 34.3%. Maritech’s gross profit as a percentage of revenues increased during the current year to a negative 14.4% compared to a negative 21.3% during the prior year. This increase occurred despite the segment’s decrease in revenues during the current year, due to the decreased amount of oil and gas property impairments during 2008 compared to 2007. Maritech recorded $76.1 million of impairments during 2007, primarily due to the reversal of anticipated insurance recoveries as a result of certain future well intervention and debris removal costs being contested by our insurance provider. This decrease in anticipated insurance recoveries further reduced Maritech’s gross profit associated with certain hurricane damage repair costs incurred and resulted in a $13.5 million charge to operating expense, as the timing and amount of the reimbursement of these costs had become indeterminable. During the fourth quarter of 2007, Maritech filed a lawsuit against certain of its insurance underwriters related to certain contested well intervention and debris removal costs incurred and to be incurred on three offshore platforms which were destroyed by 2005 hurricanes. During the third and fourth quarters of 2008, Maritech recorded a total of $42.7 million of oil and gas property impairments, primarily due to decreasing oil and natural gas prices. In addition, Maritech’s gross profit increased during 2008 due to $5.1 million of decreased excess decommissioning and abandoning costs. The increased gross profit was partially offset by $10.7 million of increased depreciation and depletion expense and $7.4 million of increased dry hole costs. In addition, Maritech’s insurance costs decreased by $1.2 million during 2008 compared to 2007.

The Division’s Maritech operations reported a loss before taxes of $31.9 million during 2008 compared to a $49.8 million loss before taxes during the prior year, a $17.9 million decrease in the amount of loss. This 35.9% decrease was due to the $15.7 million decrease in negative gross profit and approximately $2.2 million of increased other income, primarily due to gains on sales of properties, partially offset by $0.1 million of increased administrative costs compared to the prior year.

Production Enhancement Division – Production Enhancement Division revenues increased significantly from $176.7 million during 2007 to $224.4 million during 2008, an increase of $47.8 million or 27.0%. Production Enhancement Division gross profit during 2008 totaled $85.7 million compared to $69.5 million during the prior year, an increase of $16.2 million or 23.4%. Production Enhancement Division income before taxes was $66.0 million during 2008 compared to $52.3 million of income before taxes during the prior year, an increase of $13.7 million or 26.2%.

Production Testing segment revenues increased from $93.1 million during 2007 to $127.0 million during 2008, an increase of $33.9 million or 36.4%. This increase was primarily due to $18.9 million of revenues from increased U.S. demand, where activity levels were high throughout 2008 despite decreased oil and natural gas pricing during the last portion of the year. Approximately $15.5 million of the increased Production Testing revenues were also attributed to increased activity in Mexico and Brazil. These increases were partially offset by $0.5 million of decreased environmental service fees compared to the prior year.

Production Testing gross profit increased $11.6 million during 2008 compared to 2007, increasing from $32.8 million to $44.4 million during 2008, an increase of 35.4%. Gross profit as a percentage of revenue decreased slightly, however, from 35.2% during 2007 to 35.0% during 2008. The increased gross profit reflected the higher level of activity throughout 2008, particularly for the segment’s international operations.

Production Testing reported income before taxes of $35.7 million during 2008, compared to $25.6 million during 2007, an increase of $10.0 million or 39.2%. This increase was due to the increased gross profit discussed above and $0.4 million of decreased other expense, primarily due to decreased foreign currency losses. These increases were partially offset by approximately $2.0 million of increased administrative costs.

The Division’s Compressco segment revenues increased by approximately $13.9 million during 2008 compared to the prior year, increasing 16.6% from $83.6 million during 2007 to $97.4 million during 2008. The majority of this increase occurred in the United States, however, Compressco’s operations in Mexico also increased significantly compared to the prior year. Compressco continued to add to its compressor fleet throughout 2008 to meet the growing demand for its services.

Compressco’s gross profit increased from $36.7 million during 2007 to $41.3 million during 2008, an increase of $4.6 million or 12.6%, primarily due to increased activity. Gross profit as a percentage of revenues decreased, however, from 43.9% during 2007 to 42.4% during 2008, primarily due to increased operating costs for its U.S. operations, despite increased strong margins on the growing Mexican operations.

Income before taxes for the Compressco segment increased from $26.7 million during 2007 to $30.3 million during 2008, an increase of $3.6 million or 13.7%. This increase was primarily due to the $4.6 million of increased gross profit discussed above, less approximately $0.8 million of increased administrative costs and $0.2 million of increased other expense.

Corporate Overhead – Corporate Overhead includes corporate general and administrative expenses, 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 overhead decreased by $5.3 million from $50.9 million during 2007 to $45.6 million during 2008 due to $8.6 million of increased other income, primarily from increased ineffectiveness gains on liquidated derivative contracts, which resulted in $8.5 million of other income. These gains were partially offset by approximately $2.7 million of increased corporate administrative costs and $1.0 million of increased depreciation expense. The increase in corporate administrative costs was primarily from $1.4 million of increased personnel costs, primarily from increased stock option expense, approximately $0.5 million of increased legal and professional fees, and approximately $0.7 million of increased general expenses. Net corporate interest expense decreased approximately $0.3 million due to lower interest rates and additional amounts of interest capitalized associated with our capital construction projects. The increased capitalization of interest will continue until our significant capital construction projects are completed, which is expected to occur later during 2009.

Liquidity and Capital Resources

During the past year, we have specifically focused on conserving capital resources, even while completing the largest construction project in our history. This focus has been accomplished by reducing or deferring other capital projects, reducing operating and administrative costs, maximizing operating efficiencies, idling or disposing of non-strategic assets, and carefully managing working capital. These efforts, along with the strong performance of our Offshore Services segment during the year, have more than overcome the decrease in revenues and operating cash flows from many of our other businesses and have resulted in increased consolidated operating cash flows during 2009 compared to 2008. Cash generated during the year was used to pay the remaining outstanding balance of our bank revolving credit facility and to increase our cash on hand as of yearend. We have historically funded the majority of our capital expenditure requirements through operating cash flows. We are continuing to conserve capital spending going forward, as we monitor the operating cash flows of each of our businesses. While focusing on these efforts, we also continue to seek opportunities for growth, particularly internationally, either through strategic expansion of existing businesses in niche markets or through suitable acquisitions. Our increased liquidity and availability under our revolving credit facility, which is scheduled to mature in June 2011, positions us to take advantage of growth opportunities. During 2009, cash flows from operating activities increased to $272.3 million, compared to $189.8 million during 2008, and funded $149.7 million of net investing activities, paid down $95.7 million of long-term debt and other financing activities, and increased cash on hand by approximately $29.5 million.

Operating Activities – Cash flow generated by operating activities grew to $272.3 million during 2009 compared to $189.8 million during 2008 and was primarily due to increased earnings, collections of accounts receivable, and other working capital changes. Contributing to the increased earnings was the operating results generated by our Offshore Services segment and the fourth quarter 2009 collection of a $40.0 million Maritech insurance litigation settlement. In addition, during 2009 we generated $23.1 million from the liquidation of certain oil swap derivative contracts. The increase in operating cash flows occurred despite a significant increase in the amount of Maritech decommissioning activity performed during 2009, and we plan to perform a similar level of decommissioning work in 2010. Operating cash flows also increased despite the decreased demand for many of our products and services, as cost reduction efforts and improved operating efficiencies partially offset these decreases. For Maritech, the remaining shut-in production resulting from damage suffered in 2008 from Hurricane Ike and the reduction in drilling projects during the past year continue to negatively affect the level of Maritech’s oil and gas production cash flows. In addition, the oil and gas prices received for Maritech’s production were also decreased compared to the prior year, although swap derivative hedge contracts partially offset this decrease.

One of the most significant uncertainties regarding the level of our operating cash flows in 2010 and beyond, in addition to the factors discussed below associated with our Maritech operations, is the timing and magnitude of the continuing global economic recovery and its impact on oil and gas industry activity. The demand for a large portion of our products and services is driven by oil and gas drilling and production activity generally. Our Production Testing and Compressco segments, along with the completion fluids and services business of our Fluids Division, have been particularly affected by the decrease in industry activity during the past year, as reflected in the revenue and profitability levels for these segments during 2009. Oil and gas prices and rig count activity levels have been increasing during the last half of 2009 and during the first portion of 2010. However, the overall demand for our products and services is also driven by spending levels within the oil and gas industry, particularly domestically, which is also affected by the availability of capital and general economic conditions. While we expect that the level of revenues and cash flows for our Production Testing, Compressco, and Fluids segments will improve modestly in 2010, such levels are expected to continue to be significantly below the levels generated during the first half of 2008.

Our operating cash flows continue to be affected by the impact from hurricanes. During 2008, Hurricane Ike caused damage to certain of our properties, including damage to many of Maritech’s offshore production platforms, three of which were destroyed. Including the platforms and facility destroyed by Hurricanes Katrina and Rita during 2005, one of which was decommissioned during 2009, Maritech has five remaining destroyed platforms and associated wells on which it needs to perform well intervention, abandonment, decommissioning, debris removal, platform construction, and well redrilling. We estimate the cost to perform this remaining work will be approximately $95 to $110 million. Approximately $70 to $80 million of this amount has been accrued for as part of Maritech’s decommissioning liability. Approximately $50 to $60 million of these amounts relate to platforms destroyed by Hurricane Ike, and we anticipate that the

majority of these costs will be reimbursed by insurance. See further discussion below. During 2009, we charged approximately $8.2 million of damage repair costs from Hurricane Ike to earnings and as of December 31, 2009, we reflect an insurance receivable of approximately $16.7 million for the portion of the costs incurred, including non-hurricane related claims, that are covered by our various insurance policies. Although a significant portion of the insurance reimbursements associated with Hurricane Ike damage costs expended to date was received during 2009 and early 2010, the timing of the collection of additional reimbursements is beyond our control. Also related to Hurricane Ike, one of the destroyed offshore platforms served the East Cameron 328 field, which produced approximately 24.3% of our pre-storm oil production. 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. The full resumption of production from the East Cameron 328 field will require the construction of a new platform and several wells to be redrilled, and these efforts are estimated to cost approximately $25 to $30 million, before insurance recoveries, and are not scheduled to be completed until 2011. Beginning in June 2009 and for the period ending May 2010, Maritech discontinued its insurance coverage for windstorm damage due to the current high premium cost of insurance and the reduced levels of coverage. This decision resulted in increased operating cash flow during the last half of 2009 as a result of lower premium costs. If Maritech elects to continue to self-insure for windstorm damage in future periods, it will be exposed to losses from future uninsured windstorm damages. Depending on the severity and location of the storms, such losses could be significant.

Future operating cash flow will also be affected by the timing and amount of expenditures required for the plugging, abandonment, and decommissioning of Maritech’s oil and gas properties. The third party discounted fair value, including an estimated profit, of Maritech’s decommissioning liability as of December 31, 2009 totals $218.4 million ($234.0 million undiscounted). These amounts include the well intervention, decommissioning, and debris removal efforts associated with five remaining destroyed offshore platforms, including the three platforms destroyed by Hurricane Ike. Approximately $77.9 million of the cash outflow necessary to extinguish Maritech’s decommissioning liability is expected to occur during 2010. The remainder of Maritech’s decommissioning liability is 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, MMS requirements, commodity prices, revisions of reserve estimates, and other factors. The estimated cost to perform the work on the five remaining destroyed platforms and associated wells is particularly imprecise due to the unique nature of the work to be performed. Maritech’s decommissioning liability at yearend includes $23.3 million of adjustments made during 2009 relating to future work to be performed which were capitalized to the associated oil and gas properties. Additional adjustments of approximately $23.8 million were primarily related to work performed on certain properties during the year in excess of the property’s decommissioning liability and were charged to earnings.

Maritech’s estimated decommissioning liabilities are net of amounts allocable to joint interest owners, contractual amounts to be paid by the previous owners of the properties, and insurance recoveries. In some cases, the previous owners of acquired properties 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, partially offsetting Maritech’s future obligation expenditures. Maritech’s decommissioning liability is net of approximately $43.6 million of amounts contractually required to be reimbursed to Maritech. Although we anticipate that a majority of the well intervention, decommissioning, and debris removal costs associated with destroyed offshore platforms from Hurricane Ike will be reimbursed by insurance, only costs that are similar to the costs that were reimbursed by our insurers following Hurricanes Katrina and Rita have been recognized as an insurance recovery partially offsetting Maritech’s estimated decommissioning liabilities, and this amount is approximately $10.3 million as of December 31, 2009. As of December 31, 2009, and prior to the impact of contractually required reimbursements and insurance recoveries, Maritech’s total undiscounted decommissioning obligation is approximately $287.9 million and consists of Maritech’s total liability of $234.0 million, plus approximately $53.9 million of such future reimbursements and recoveries.

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 natural gas swap derivative contracts result in Maritech receiving a fixed price for hedged natural gas production that is in excess of prices currently being received. Although a majority of Maritech’s production is currently hedged, these hedge contracts expire at the end of 2010.

Investing Activities – During 2009, we expended approximately $151.8 million of cash for capital expenditures and an additional $18.1 million on purchase consideration adjustments on acquisition transactions from prior years. Approximately $65.9 million of the 2009 capital expenditures was spent on the construction of our new El Dorado, Arkansas, calcium chloride plant facility, which began production of liquid calcium chloride during the fourth quarter of 2009. The plant began production of dry calcium chloride during the first quarter of 2010 and is expected to begin sodium chloride production in 2011. The construction phase of the plant was substantially complete as of December 31, 2009 at a total cost excluding capitalized interest of approximately $126.9 million, making it the most significant construction project in our history. During 2009, capital expenditures associated with the El Dorado plant represented 43.4% of our total capital expenditures, as many of our other investment projects were either cancelled or deferred pending the completion of the plant. As a result, despite the continuing plant construction costs during the year, our total cash capital expenditures decreased by 42.1% compared to 2008. Going forward, our capital expenditure plans will continue to be reviewed carefully in light of the current capital market constraints and the continued reduced demand and operating cash flows for several of our businesses.

During 2009, our cash capital expenditures totaled approximately $151.8 million, $84.1 million of which was expended by our Fluids Division, primarily for the construction of the El Dorado plant facility, but also including improvements and expansion of fluids and chemical plant facility locations. Our Offshore Division expended approximately $44.3 million, consisting of approximately $26.8 million of exploration and development expenditures for Maritech. In addition, the Offshore Division also expended approximately $17.9 million for the Offshore Services segment, primarily related to vessel and equipment refurbishments for its diving and heavy lift operations. Our Production Enhancement Division spent approximately $12.0 million, consisting of approximately $9.0 million to replace and enhance a portion of the testing equipment fleet by our Production Testing segment. In addition, Compressco spent approximately $2.9 million for general infrastructure needs along with minimal expansion of its compressor fleet. Our total capital expenditures also included approximately $11.4 million of Corporate capital expenditures, primarily related to the final construction phase of our new headquarters office building, which was completed in the first quarter of 2009.

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 efforts to conserve capital. We plan to expend over $140 million on total capital expenditures during 2010, and while this represents a further decrease in total capital expenditures compared to 2009, it would result in increased spending for each of our business segments other than our Fluids Division. Many of our capital expenditure plans will be deferred until activity levels increase. Deferral of certain capital projects, such as the replacement or upgrading of vessels in our Offshore Services fleet, could affect our ability to compete. 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, and the current reduction in spending may result in negative growth for Maritech over time as a result of postponing the replacement of depleting oil and gas reserves and production cash flows. However, our long-term growth strategy continues to include the pursuit of suitable acquisitions. To the extent we consummate a significant acquisition, 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 - We have a revolving credit facility with a syndicate of banks, pursuant to a credit agreement which was amended in June 2006 and December 2006 (the Credit Agreement). As of December 31, 2009 and February 26, 2010, we did not have any outstanding balance on the revolving credit facility, and had $17.6 million in letters of credit and guarantees against the $300 million revolving credit facility, leaving a net availability of $282.4 million.

Pursuant to the Credit Agreement, the revolving credit facility is scheduled to mature in June 2011, is unsecured, and is guaranteed by certain of our material U.S. subsidiaries. Borrowings generally bear interest at the British Bankers Association LIBOR rate plus 0.50% to 1.25%, depending on one of our financial ratios. We pay a commitment fee ranging from 0.15% to 0.30% on unused portions of the facility. 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 flow 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 continue 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 under the facility prior to 2011. 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 were in compliance with all covenants and conditions of our Credit Agreement as of December 31, 2009. 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 subject to the duration of the current economic environment, 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 (approximately $40.1 million equivalent at December 31, 2009) in aggregate principal amount of Series 2004-B Senior Notes pursuant to a Master Note Purchase Agreement. The Series 2004-A Senior Notes and 2004-B 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 Senior Notes were used to pay down a portion of existing indebtedness under the revolving credit facility and to fund the acquisition of our European calcium chloride assets.

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 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 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.

The Series 2004-A Senior Notes bear interest at the fixed rate of 5.07% and mature on September 30, 2011. The Series 2004-B Senior Notes bear interest at the fixed rate of 4.79% and mature on September 30, 2011. Interest on the 2004-A Senior Notes and the 2004-B Senior Notes is due semiannually on March 30 and September 30 of each year. 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 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. 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, 2009. 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 bank revolving credit facility matures in June 2011 and our Senior Notes mature at various dates between September 2011 and April 2016. The replacement of these capital sources at similar or more favorable terms is uncertain. 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.

During the fourth quarter of 2008, we liquidated the swap derivative contracts related to the remainder of Maritech’s 2008 production in exchange for net cash received of approximately $6.5 million. During the second quarter of 2009, we liquidated certain swap derivative contracts related to Maritech’s oil production in exchange for net cash received of approximately $23.1 million, a large majority of which was used to pay a portion of our outstanding balance of our bank revolving credit facility. As of December 31, 2009, the market value of our natural gas swap contracts was approximately $19.9 million. All or a portion of these contracts are marketable to the corresponding counterparty and could be liquidated in order to generate additional cash. The liquidation of any of these swap contracts would expose an additional portion of Maritech’s expected future natural gas production to market price volatility in future periods.

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 $1.2 million, $4.8 million, and $12.1 million during 2009, 2008 and 2007, 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, 2009 and 2008, 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

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.

Environmental

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

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 expect to meet with the EPA soon to discuss potential violations and penalties. It has been agreed that no injunctive relief will be required. Though penalties have not yet been discussed, it is possible that they will exceed $100,000.

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. During 2006, we significantly increased our purchase obligations as a result of the execution of a long-term supply agreement with Chemtura Corporation. As of December 31, 2009, the aggregate amount of the fixed and determinable portion of the purchase obligation pursuant to our Fluids Division’s supply agreements was approximately $278.6 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, 2009, Maritech’s decommissioning liabilities are net of approximately $43.6 million for such future reimbursements from these previous owners.

Contractual Obligations

The table below summarizes our contractual cash obligations as of December 31, 2009:

	Payments Due
	Total		2010			2011		2012		2013		2014		Thereafter
	(In Thousands)

Long-term debt	$	310,132	$	-		$	95,132	$	-	$	35,000	$	-	$	180,000
Interest on debt		80,641		18,130			16,942		13,419		11,939		11,214		8,997
Purchase obligations		278,605		12,595			13,935		15,275		15,275		15,275		206,250
Decommissioning and
other asset retirement
obligations(1)		233,952		76,179	(3)		39,167		17,809		21,193		15,132		64,472
Operating and
capital leases		11,370		4,738			2,453		1,853		1,123		808		395
Total contractual
cash obligations(2)	$	914,700	$	111,642		$	167,629	$	48,356	$	84,530	$	42,429	$	460,114

(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, 2009.
(2)	Amounts exclude other long-term liabilities reflected in our Consolidated Balance Sheet that do not have known payment streams. These excluded amounts include approximately $4.3 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 $59.0 million of the amounts expected to be paid in 2010 represent well intervention, 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 June 2009, the Financial Accounting Standards Board (FASB) published Statement of Financial Accounting Standard (SFAS) No. 168, “The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles – a replacement of FASB Statement No. 162,” which establishes the FASB Accounting Standards Codification (FASB Codification) as the source of authoritative U.S. generally accepted accounting principles (GAAP) recognized by the FASB to be applied by nongovernmental entities. Beginning on the effective date of the standard (now incorporated into FASB Codification Subtopic 105-10), the FASB Codification superseded all then-existing non-SEC accounting and reporting standards. All other non-grandfathered non-SEC accounting literature not included in the FASB Codification has become non-authoritative. The standard is effective for financial statements issued for interim and annual periods ending after September 15, 2009. In the FASB’s view, the issuance of the standard and the FASB Codification will not change GAAP for public companies, and, accordingly, the adoption of the standard did not have a significant impact on our financial statements.

In March 2008, the FASB published SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities, an amendment of FASB Statement No. 133,” (FASB Codification Topic 815, “Derivatives and Hedging”), which requires entities to provide greater transparency about (1) how and why an entity uses derivative instruments, (2) how derivative instruments and related hedged items are accounted for under FASB Codification Topic 815 (SFAS No. 133 and its related interpretations); and (3) how derivative instruments and related hedged items affect an entity’s financial position, results of operations, and cash flows. This standard is effective for financial statements issued for fiscal years and interim periods within those fiscal years beginning after November 15, 2008. Accordingly, we adopted the new disclosure requirements as of January 1, 2009.

financial effects of the business combination. The standard changes many aspects of the accounting for business combinations and applies prospectively to business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008. We adopted this standard as of January 1, 2009 with no significant impact, as there have been no acquisitions during 2009. However, the standard is expected to significantly impact how we account for and disclose future acquisition transactions.

In May 2009, the FASB published SFAS No. 165, “Subsequent Events,” (FASB Codification Topic 855, “Subsequent Events”), which establishes general standards of accounting for and disclosure of events that occur after the balance sheet date but before financial statements are issued or are available to be issued. In particular, it sets forth (1) the period after the balance sheet date during which management of a reporting entity should evaluate events or transactions that may occur for potential recognition or disclosure; (2) the circumstances under which an entity should recognize events or transactions occurring after the balance sheet date; and (3) the disclosures that an entity should make about events or transactions that occurred after the balance sheet date. This standard is effective for financial statements for periods ending after June 15, 2009. We adopted this standard as of July 1, 2009, however the standard did not have a significant impact on our financial statements.

In December 2008, the SEC released its “Modernization of Oil and Gas Reporting” rules, which revise the disclosure of oil and gas reserve information. The new disclosure requirements include provisions that permit the use of new technologies to determine proved reserves in certain circumstances. The new requirements also will allow companies to disclose their probable and possible reserves and require companies to (1) report on the independence and qualifications of a reserves preparer or auditor; (2) file reports when a third party is relied upon to prepare reserve estimates or conduct a reserves audit; and (3) report oil and gas reserves using an average price based upon the prior twelve month period, rather than year-end prices. These new reporting requirements are effective for annual reports on Form 10-K for fiscal years ending on or after December 31, 2009. We adopted these new SEC oil and gas reserve rules as of December 31, 2009, however they did 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, 2009. Accordingly, as of that date, there are no long-term debt obligations which bear a variable rate of interest.

The following table sets forth, as of December 31, 2009, our cash flows for the outstanding principal balance of our long-term debt obligations which bear a variable rate of interest and weighted average effective interest rates by their expected maturity dates. 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.

	Expected Maturity Date														Fair
	2009		2010		2011		2012		2013		Thereafter		Total		Market Value
	(In Thousands, Except Percentages)
As of December 31, 2009
Long-term debt:
U.S. dollar variable rate	$	-	$	-	$	-	$	-	$	-	$	-	$	-	$	-
Euro variable rate (in $US)		-		-		-		-		-		-		-		-
Weighted average
interest rate		-		-		-		-		-		-		-		-
Variable to fixed swaps		-		-		-		-		-		-		-		-
Fixed pay rate		-		-		-		-		-		-		-		-
Variable receive rate		-		-		-		-		-		-		-		-

Exchange Rate Risk

We are exposed to fluctuations between the U.S. dollar and the euro with regard to our euro-denominated operating activities and related long-term euro denominated debt. In September 2004, we borrowed euros to fund the acquisition of our European calcium chloride assets. We entered into long-term euro-denominated borrowings, as we believe such borrowings provide a natural currency hedge for our euro-based operating cash flow. In our European operations, we also 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.

The following table sets forth as of December 31, 2009 our cash flows for the outstanding principal balances of our long-term debt obligations which are denominated in euros. This information is presented in U.S. dollar equivalents. The table presents principal cash flows and related weighted average interest rates by their expected maturity dates. As described above, we utilize the long-term borrowings detailed in the following table as a hedge to our investment in our acquired foreign operations, and, currently, we are not a party to a foreign currency swap contract or other derivative instrument designed to further hedge our currency exchange rate risk exposure. Our exchange rate risk exposure related to these borrowings will generally be offset by the offsetting fluctuations in the value of the related foreign investment.

	Expected Maturity Date																Fair
	2010		2011			2012		2013		2014		Thereafter		Total			Market Value
	(In Thousands, Except Percentages)
As of December 31, 2009
Long-term debt:
Euro variable rate (in $US)	$	-	$	-		$	-	$	-	$	-	$	-	$	-		$	-
Euro fixed rate (in $US)		-		40,132			-		-		-		-		-			40,357
Weighted average
interest rate		-		4.790	%		-		-		-		-		4.790	%		-
Variable to fixed swaps		-		-			-		-		-		-		-			-
Fixed pay rate		-		-			-		-		-		-		-			-
Variable receive rate		-		-			-		-		-		-		-			-

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 and natural gas hedges as of December 31, 2009, described below, each $1 per barrel decrease in future crude oil prices would result in a decrease in after tax earnings of $0.4 million and each decrease in future gas prices of $0.10 per Mcf would result in a decrease in after tax earnings of $0.2 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, 2009 and 2008, 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, 2009
Oil swaps	2,000 barrels/day	$78.70/barrel	2010
Natural gas swaps	20,000 MMBtu/day	$8.147/MMBtu	2010
December 31, 2008
Oil swaps	2,500 barrels/day	$68.864/barrel	2009
Oil swaps	2,000 barrels/day	$104.125/barrel	2010
Natural gas swaps	25,000 MMBtu/day	$8.967/MMBtu	2009
Natural gas swaps	10,000 MMBtu/day	$10.265/MMBtu	2010

In January 2010, we entered into an additional cash flow hedging oil swap contract, covering 1,000 barrels/day from February to December 2010, with a contract price of $84.90/barrel. During the second quarter of 2009, we liquidated cash flow hedging oil swap contracts in exchange for cash of approximately $23.1 million.

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 $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. 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.

The market value of our oil swaps asset at December 31, 2008 was $41.5 million. A $1 increase in the future price of oil would have resulted in the market value of the combined oil derivative asset decreasing by $1.6 million. The market value of our natural gas swaps asset at December 31, 2008 was $35.7 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 $1.3 million.

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, 2009, 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, 2009.

An assessment of the effectiveness of our internal control over financial reporting as of December 31, 2009 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, 2009 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Item 9B. Other Information.

None.

PART III

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

The information required by this Item is hereby incorporated by reference from the information appearing under the captions “Proposal No. 1: Election of Directors,” “Executive Officers,” “Corporate Governance,” “Board Meetings and Committees,” and “Section 16(a) Beneficial Ownership Reporting Compliance” in our definitive proxy statement (the Proxy Statement) for the annual meeting of stockholders to be held May 5, 2010, 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, 2009.

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, 2009 and 2008	F-3
	Consolidated Statements of Operations for the years ended December 31, 2009, 2008, and 2007	F-5
	Consolidated Statements of Stockholders’ Equity for the years ended December 31, 2009, 2008, and 2007	F-6
	Consolidated Statements of Cash Flows for the years ended December 31, 2009, 2008, and 2007	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)).
	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)).
	10.5***	Letter of Agreement with Gary C. Hanna, dated March, 2002 (incorporated by reference to Exhibit 10.8 to the Company’s Form 10-K for the year ended December 31, 2001 filed on March 29, 2002 (SEC File No. 001-13455)).
	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	Credit Agreement dated as of September 7, 2004, among TETRA Technologies, Inc. and certain of its subsidiaries, as borrowers, Bank of America, National Association, as Administrative Agent, Bank One, NA and Wells Fargo Bank, N.A., as syndication agents, and Comerica Bank, as documentation agent, attaching the guaranty dated as of September 7, 2004, by the borrowers, as guarantors, to the Administrative Agent for the benefit of the lenders under the Credit Agreement (incorporated by reference to Exhibit 10.1 to the Company’s Form 8-K filed on September 8, 2004 (SEC File No. 001-13455)).
	10.8***	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)).
	10.9***	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)).
	10.10***	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)).
	10.11***	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)).
	10.12+***	Summary Description of the Compensation of Non-Employee Directors of TETRA Technologies, Inc.
	10.13+***	Summary Description of Named Executive Officer Compensation.
	10.14	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).
	10.15***	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)).
	10.16***	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)).
	10.17***	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)).
	10.18	Agreement and Third Amendment to Credit Agreement, dated as of January 20, 2006, among TETRA Technologies, Inc. and certain of its subsidiaries, as borrowers, JP Morgan Chase Bank, National Association (successor to Bank One, NA) and Wells Fargo Bank, N.A., as syndication agents, Comerica Bank, as documentation agent, Bank of America, National Association, as administrative agent, and the lenders party thereto (incorporated by reference to Exhibit 10.1 to the Company’s Form 8-K filed on January 23, 2006 (SEC File No. 001-13455)).
	10.19	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)).
	10.20	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)).
	10.21***	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)).
	10.22***	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)).

	10.23***	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)).
	10.24***	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)).
	10.25***	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)).
	10.26***	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)).
	10.27***	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)).
	10.28***	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)).
	10.29***	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)).
	10.30***	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)).
	10.31***	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)).
	10.32***	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)).
	10.33	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)).
	10.34	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)).
	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.

+ Filed with this report.

** Furnished with this report.

*** Management contract or compensatory plan or arrangement.

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, 2010	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, 2010
Ralph S. Cunningham	the Board of Directors

/s/Stuart M. Brightman	President, Chief Executive	March 1, 2010
Stuart M. Brightman	Officer and Director
	(Principal Executive Officer)

/s/Joseph M. Abell	Senior Vice President and	March 1, 2010
Joseph M. Abell	Chief Financial Officer
	(Principal Financial Officer)

/s/Ben C. Chambers	Vice President – Accounting	March 1, 2010
Ben C. Chambers	and Controller
	(Principal Accounting Officer)

/s/Paul D. Coombs	Director	March 1, 2010
Paul D. Coombs

/s/Tom H. Delimitros	Director	March 1, 2010
Tom H. Delimitros

/s/Geoffrey M. Hertel	Director	March 1, 2010
Geoffrey M. Hertel

/s/Allen T. McInnes	Director	March 1, 2010
Allen T. McInnes

/s/Kenneth P. Mitchell	Director	March 1, 2010
Kenneth P. Mitchell

/s/William D. Sullivan	Director	March 1, 2010
William D. Sullivan

/s/Kenneth E. White, Jr.	Director	March 1, 2010
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)).
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)).
10.5***	Letter of Agreement with Gary C. Hanna, dated March, 2002 (incorporated by reference to Exhibit 10.8 to the Company’s Form 10-K for the year ended December 31, 2001 filed on March 29, 2002 (SEC File No. 001-13455)).
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	Credit Agreement dated as of September 7, 2004, among TETRA Technologies, Inc. and certain of its subsidiaries, as borrowers, Bank of America, National Association, as Administrative Agent, Bank One, NA and Wells Fargo Bank, N.A., as syndication agents, and Comerica Bank, as documentation agent, attaching the guaranty dated as of September 7, 2004, by the borrowers, as guarantors, to the Administrative Agent for the benefit of the lenders under the Credit Agreement (incorporated by reference to Exhibit 10.1 to the Company’s Form 8-K filed on September 8, 2004 (SEC File No. 001-13455)).
10.8***	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)).
10.9***	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)).
10.10***	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)).
10.11***	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)).
10.12+***	Summary Description of the Compensation of Non-Employee Directors of TETRA Technologies, Inc.
10.13+***	Summary Description of Named Executive Officer Compensation.
10.14	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).
10.15***	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)).
10.16***	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)).

10.17***	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)).
10.18	Agreement and Third Amendment to Credit Agreement, dated as of January 20, 2006, among TETRA Technologies, Inc. and certain of its subsidiaries, as borrowers, JP Morgan Chase Bank, National Association (successor to Bank One, NA) and Wells Fargo Bank, N.A., as syndication agents, Comerica Bank, as documentation agent, Bank of America, National Association, as administrative agent, and the lenders party thereto (incorporated by reference to Exhibit 10.1 to the Company’s Form 8-K filed on January 23, 2006 (SEC File No. 001-13455)).
10.19	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)).
10.20	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)).
10.21***	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)).
10.22***	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)).
10.23***	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)).
10.24***	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)).
10.25***	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)).
10.26***	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)).
10.27***	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)).
10.28***	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)).
10.29***	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)).
10.30***	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)).
10.31***	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)).
10.32***	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)).
10.33	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)).

10.34	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)).
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.

+ Filed with this report.

** Furnished with this report.

*** Management contract or compensatory plan or arrangement.

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, 2009 and 2008, and the related consolidated statements of operations, stockholders' equity, and cash flows for each of the three years in the period ended December 31, 2009. 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, 2009 and 2008, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2009, 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, 2009, 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, 2010, expressed an unqualified opinion thereon.

/s/ERNST & YOUNG LLP

Houston, Texas

March 1, 2010

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, 2009, 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, 2009, 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, 2009 and 2008, and the related consolidated statements of operations, stockholders’ equity and cash flows for each of the three years in the period ended December 31, 2009, and our report dated March 1, 2010, expressed an unqualified opinion thereon.

/s/ERNST & YOUNG LLP

Houston, Texas

March 1, 2010

F-2

TETRA Technologies, Inc. and Subsidiaries

Consolidated Balance Sheets

(In Thousands)

	December 31,
	2009			2008
ASSETS
Current assets:
Cash and cash equivalents	$	33,394		$	3,882
Restricted cash		266			2,150
Accounts receivable, net of allowance for doubtful accounts
of $5,007 in 2009 and $3,198 in 2008		181,038			225,491
Inventories		122,274			117,731
Derivative assets		19,926			38,052
Prepaid expenses and other current assets		33,905			47,768
Assets of discontinued operations		15			239
Total current assets		390,818			435,313

Property, plant, and equipment:
Land and building		77,246			23,730
Machinery and equipment		458,675			463,788
Automobiles and trucks		42,432			43,047
Chemical plants		94,767			46,121
Oil and gas producing assets (successful efforts method)		676,692			697,754
Construction in progress		95,470			118,103
		1,445,282			1,392,543
Less accumulated depreciation and depletion		(628,908	)		(585,077	)
Net property, plant and equipment		816,374			807,466

Other assets:
Goodwill		99,005			82,525
Patents, trademarks, and other intangible assets, net of
accumulated amortization of $18,997 in 2009 and $15,611 in 2008		13,198			16,549
Derivative assets		-			39,098
Deferred tax assets		1,342			1,699
Other assets		26,862			29,974
Total other assets		140,407			169,845
	$	1,347,599		$	1,412,624

See Notes to Consolidated Financial Statements

F-3

TETRA Technologies, Inc. and Subsidiaries

Consolidated Balance Sheets

(In Thousands, Except Per Share Amounts)

	December 31,
	2009			2008
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Trade accounts payable	$	57,418		$	76,973
Accrued liabilities		84,638			86,659
Decommissioning and other asset retirement obligations, current		77,891			45,954
Deferred tax liabilities		19,893			2,882
Derivative liabilities		2,618			-
Liabilities of discontinued operations		17			13
Total current liabilities		242,475			212,481

Long-term debt, net		310,132			406,840
Deferred income taxes		56,125			64,911
Decommissioning and other asset retirement obligations, net		146,219			202,771
Other liabilities		16,154			9,800
Total long-term and other liabilities		528,630			684,322

Commitments and contingencies

Stockholders' equity:
Common stock, par value $.01 per share; 100,000,000 shares
authorized; 77,039,628 shares issued at December 31, 2009
and 76,841,424 shares issued at December 31, 2008		770			768
Additional paid-in capital		193,718			186,318
Treasury stock, at cost; 1,497,346 shares held at December 31,
2009 and 1,582,465 shares held at December 31, 2008		(8,310	)		(8,843	)
Accumulated other comprehensive income		26,822			42,888
Retained earnings		363,494			294,690
Total stockholders' equity		576,494			515,821
	$	1,347,599		$	1,412,624

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,
	2009			2008			2007
Revenues:
Product sales	$	350,005		$	447,341		$	457,238
Services and rentals		528,872			561,724			525,245
Total revenues		878,877			1,009,065			982,483

Cost of revenues:
Cost of product sales		237,911			283,194			304,976
Cost of services and rentals		310,943			364,275			362,745
Gain on insurance recoveries		(45,391	)		(697	)		(3,245	)
Depreciation, depletion, amortization, and accretion		149,326			158,893			129,844
Impairments of long-lived assets		12,991			51,399			71,780
Total cost of revenues		665,780			857,064			866,100
Gross profit		213,097			152,001			116,383

General and administrative expense		100,832			104,949			99,871
Impairment of goodwill		-			47,073			-
Operating income (loss)		112,265			(21	)		16,512

Interest expense, net		12,790			16,778			17,155
Other income, net		5,895			12,884			2,805

Income (loss) before taxes and discontinued operations		105,370			(3,915	)		2,162
Provision for income taxes		36,563			5,740			941

Income (loss) before discontinued operations		68,807			(9,655	)		1,221

Discontinued operations:
Income (loss) from discontinued operations, net of taxes		(426	)		(2,481	)		1,723
Gain on disposal of discontinued operations, net of taxes		423			-			25,827
Income (loss) from discontinued operations		(3	)		(2,481	)		27,550

Net income (loss)	$	68,804		$	(12,136	)	$	28,771


Basic net income (loss) per common share:
Income (loss) before discontinued operations	$	0.92		$	(0.13	)	$	0.02
Income (loss) from discontinued operations		(0.01	)		(0.03	)		0.02
Gain on disposal of discontinued operations		0.01			-			0.35
Net income (loss)	$	0.92		$	(0.16	)	$	0.39
Average shares outstanding		75,045			74,519			73,573

Diluted net income (loss) per common share:
Income (loss) before discontinued operations	$	0.91		$	(0.13	)	$	0.02
Income (loss) from discontinued operations		(0.01	)		(0.03	)		0.02
Gain on disposal of discontinued operations		0.01			-			0.34
Net income (loss)	$	0.91		$	(0.16	)	$	0.38
Average diluted shares outstanding		75,722			74,519			75,921

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, 2006		71,931,428		1,946,039		$	739	$	147,178		$	(10,524	)	$	278,112		$	2,883		$	1,992		$	420,380
Net income for 2007															28,771									28,771
Translation adjustment, net of
taxes of $1,381																					4,870			4,870
Net change in derivative fair value,
net of taxes of $21,887																		(37,110	)					(37,110	)
Reclassification of derivative fair value
into earnings, net of taxes of $809																		1,366						1,366
Comprehensive income																								(2,103	)
Impact of adoption of FIN No. 48															(57	)								(57	)
Exercise of common stock options		2,208,371		(422,861	)		20		9,954			2,192												12,166
Grants of restricted stock, net		230,966		27,784								(73	)											(73	)
Stock option expense									4,416															4,416
Tax benefit upon exercise of certain
nonqualified and incentive options									13,190															13,190
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

See Notes to Consolidated Financial Statements

F-6

TETRA Technologies, Inc. and Subsidiaries

Consolidated Statements of Cash Flows

(In Thousands)

	Year Ended December 31,
	2009			2008			2007
Operating activities:
Net income (loss)	$	68,804		$	(12,136	)	$	28,771
Reconciliation of net income (loss) to cash provided by operating activities:
Depreciation, depletion, amortization, and accretion		149,326			158,893			129,844
Impairment of goodwill		-			47,073			-
Impairments of long-lived assets		19,531			51,399			71,780
Provision (benefit) for deferred income taxes		21,204			(1,067	)		674
Stock compensation expense		6,662			5,898			4,416
Provision for doubtful accounts		3,393			3,082			1,459
Proceeds from sale of derivatives		23,060			-			-
Gain on sale of property, plant, and equipment		(7,333	)		(3,347	)		(4,974	)
Other non-cash charges and credits		25,043			(212	)		26,043
Excess tax benefit from exercise of stock options		(247	)		(1,510	)		(13,189	)
Equity in (earnings) loss of unconsolidated subsidiary		(510	)		(554	)		1,063
Changes in operating assets and liabilities, net of assets acquired:
Accounts receivable		62,364			(3,940	)		(5,346	)
Inventories		(4,628	)		(1,397	)		2,626
Prepaid expenses and other current assets		13,611			(18,913	)		(5,152	)
Trade accounts payable and accrued expenses		(30,622	)		(14,058	)		27,936
Decommissioning liabilities		(79,471	)		(19,430	)		(32,919	)
Operating activities of discontinued operations		228			3,344			(22,993	)
Other		1,900			(3,314	)		(1,000	)
Net cash provided by operating activities		272,315			189,811			209,039

Investing activities:
Purchases of property, plant, and equipment		(151,773	)		(262,099	)		(276,074	)
Business combinations, net of cash acquired		(18,105	)		-			(14,479	)
Proceeds from sale of property, plant, and equipment		15,925			380			2,582
Other investing activities		4,254			264			(2,621	)
Investing activities of discontinued operations		-			-			55,414
Net cash used in investing activities		(149,699	)		(261,455	)		(235,178	)

Financing activities:
Proceeds from long-term debt		197,900			182,450			116,930
Principal payments on long-term debt		(295,034	)		(131,428	)		(100,937	)
Excess tax benefit from exercise of stock options		247			1,510			13,189
Proceeds from sale of common stock and exercise of stock options		1,165			4,749			12,087
Net cash provided by (used in) financing activities		(95,722	)		57,281			41,269
Effect of exchange rate changes on cash		2,618			(3,588	)		1,168

Increase (decrease) in cash and cash equivalents		29,512			(17,951	)		16,298
Cash and cash equivalents at beginning of period		3,882			21,833			5,535
Cash and cash equivalents at end of period	$	33,394		$	3,882		$	21,833

Supplemental cash flow information:
Interest paid	$	19,940		$	19,488		$	18,640
Taxes paid		11,505			9,420			12,184

Supplemental disclosure of non-cash investing and financing activities:
Oil and gas properties acquired through assumption of
decommissioning liabilities	$	-		$	22,236		$	24,759

Adjustment of fair value of decommissioning liabilities
capitalized to oil and gas properties	$	23,705		$	32,511		$	71,683

See Notes to Consolidated Financial Statements

F-7

TETRA TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2009

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 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 services such as plugging and abandonment, workover, and wireline services, (2) construction and decommissioning services, including hurricane damage remediation, utilizing our heavy lift barges and 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 and the operation of several dive support vessels.

The Maritech segment consists of our Maritech Resources, Inc. (Maritech) subsidiary, which, with its subsidiaries, is an oil and gas exploration and production company focused in the offshore and onshore U.S. Gulf Coast region. Maritech periodically acquires oil and gas properties in order to replenish or expand its production operations and to provide additional development and exploitation opportunities. The Offshore Division’s Offshore Services segment performs a significant portion of the well 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 to onshore basins in Mexico, Brazil, Northern Africa, the Middle East, and other international markets.

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.

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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 and the impact of prior period’s reclassifications on our consolidated financial statements.

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, 2009 and 2008 includes escrowed funds related to agreed repairs to be expended at one of our former Fluids Division facility locations. In addition, restricted cash as of December 31, 2008 includes a third party’s proportionate obligation in the plugging and abandonment of a particular oil and gas property operated by our Maritech subsidiary. This cash became unrestricted at the time the associated plugging and abandonment project was completed during 2009.

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 risk exposure, we have entered into certain fixed interest rate notes, which are scheduled to mature at various dates from 2011 through 2016 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, 2009 and 2008 are as follows:

	December 31,
	2009		2008
	(In Thousands)

Finished goods	$	88,704	$	85,908
Raw materials		3,436		4,106
Parts and supplies		26,060		26,531
Work in progress		4,074		1,186
Total inventories	$	122,274	$	117,731

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 oil and gas impairments and dry hole costs, for the years ended December 31, 2009, 2008, and 2007 was $137.8 million, $138.0 million, and $118.6 million, respectively.

Interest capitalized for the years ended December 31, 2009, 2008, and 2007 was $6.8 million, $3.2 million, and $1.4 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 at the time of closing 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 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 two to six years (having a weighted average useful life of 5.5 years). Amortization expense of patents, trademarks, and other intangible assets was $3.6 million, $4.5 million, and $3.8 million for the twelve months ended December 31, 2009, 2008, and 2007, 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 2010, $2.2 million for 2011, $2.1 million for 2012, $2.0 million for 2013, and $0.7 million for 2014.

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

F-10

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, 2009.

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.

The changes in the carrying amount of goodwill by reporting unit for the two year period ended December 31, 2009, 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	$	72,107	$	130,335
Goodwill adjustments		-			-			-		-		54		54
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

F-11

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.

During 2009, 2008, and 2007, we identified impairments totaling approximately $11.4 million, $42.7 million, and $71.8 million, respectively, net of intercompany eliminations, of the net carrying value of certain Maritech oil and gas properties. The impairments during 2009 were primarily due to decreased production volumes or an increase in the associated decommissioning liability. The impairments during 2008 were primarily due to the impact of lower oil and natural gas pricing. In addition, certain properties were impaired as a result of decreased production volumes and increases in the associated decommissioning liabilities, particularly as a result of the 2008 hurricanes. The impairments during 2007 were caused primarily due to the reversal of anticipated insurance recoveries resulting in increased decommissioning liabilities due to certain future well intervention and debris removal costs being contested by our insurance provider. Impairments were also recorded during 2007 on certain other properties as a result of changes in development plans following Maritech’s acquisition of certain oil and gas properties in December 2007. In addition, certain properties were also impaired during 2007 due to decreased production volumes or an increase in the associated decommissioning liability.

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 planned 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

F-12

and decommissioning work on these properties as such work is performed. As of December 31, 2009 and 2008, our Maritech subsidiary’s decommissioning liabilities are net of approximately $43.6 million and $48.7 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 reported as income (or loss) 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. In connection with 2008 and 2007 oil and gas property acquisitions, we assumed net decommissioning liabilities having an estimated fair value of approximately $20.2 million and $24.8 million, respectively. As a result of decommissioning work performed, we recorded total reductions to the decommissioning liabilities for the years 2009, 2008, and 2007 of $74.6 million, $16.5 million, and $32.9 million, respectively. We made adjustments to increase our decommissioning liabilities during the years 2009, 2008, and 2007 as a result of changes in the timing or amount of future cash flows of approximately $47.1 million, $43.1 million, and $63.3 million, respectively. A large portion of the adjustments for each of these years was due to the increased decommissioning liabilities associated with certain Maritech offshore platforms which were destroyed by hurricanes in 2005 and 2008.

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.

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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, 2009 and 2008, we reflected oil and gas balancing receivables of $3.5 million and $3.6 million, respectively, in accounts receivable or other long-term assets and oil and gas balancing payables of $6.2 million and $6.4 million, respectively, in accrued liabilities or 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.

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 2009, one of our Fluids Division’s transport barges capsized and sank while docked near our West Memphis, Arkansas, manufacturing facility, destroying the vessel and the majority of the inventory cargo. The damages associated with the sunken transport barge consist of the cost of recovery efforts, replacement or repair of the barge, and the lost inventory cargo. Total damages associated with the sunken barge were approximately $4.6 million, substantially all of which are expected to be reimbursed from insurance.

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, the well intervention, abandonment, decommissioning, and debris removal associated with the destroyed offshore platforms, and the construction of replacement platforms and facilities, and the redrilling of destroyed wells. The reconstruction of the two inland water production facilities has been substantially completed, and one of the platforms destroyed in 2008 was decommissioned during 2009. 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 each of the years ended December 31, 2009, 2008, and 2007 of $8.2 million, $8.5 million, and $13.5 million, respectively.

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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, 2009, we have expended approximately $75.8 million for the well intervention, abandonment, decommissioning, and debris removal work performed on the destroyed platforms and production facilities. For certain of the destroyed platforms, however, a significant amount of such 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 future well intervention, abandonment, decommissioning, debris removal, platform reconstruction, and well redrill efforts associated with the destroyed platforms will cost approximately $95 to $110 million net to our interest before any insurance recoveries. Approximately $50 to $60 million of this cost relates to platforms destroyed by Hurricane Ike, and we anticipate that the majority of these costs will be reimbursed by insurance.

One of the offshore platforms destroyed in 2008 by Hurricane Ike served a key producing field. We are currently planning to construct a new platform from which we can redrill certain of the wells associated with the destroyed platform in order to restore a portion of the production from this field. We estimate that the cost to construct the platform and redrill these wells will be approximately $25 to $30 million, net to our interest and before insurance recoveries, and will be capitalized as oil and gas properties, net of any insurance recoveries.

In the past, we have maintained insurance protection which we believe to be customary and in amounts sufficient to reimburse us for a majority of the repair, well intervention, abandonment, decommissioning, and debris removal costs associated with the damages incurred from hurricanes and other damages, such as the value of the lost inventory and the cost to replace the sunken transport barge, reconstruct the destroyed platforms and facilities, and redrill the associated wells. Such insurance coverage is subject to certain coverage limits. For our Maritech hurricane damages caused by Hurricane Ike, we anticipate that we will exceed these coverage limits. In addition, with regard to the 2008 hurricanes, the relevant insurance policies provide for deductibles of up to $5 million per hurricane, and this deductible has been satisfied for Hurricane Ike. No significant additional insurance recoveries will be received related to the 2005 hurricanes. Due to the prohibitively high premium cost and deductible, and the significantly reduced policy limit and confining sub-limits for renewal of Maritech’s windstorm insurance coverage that terminated on May 31, 2009, beginning June 2009, we have elected to self-insure Maritech’s windstorm damage risk for the current coverage period ending May 2010. We have, however, renewed Maritech’s operational risk policies.

With regard to the costs incurred which 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 relates. The amount of anticipated insurance recoveries is included either in accounts receivable or as a reduction of 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,
	2009			2008
	(In Thousands)

Beginning balance	$	33,591		$	11,279

Activity in the period:
Damage related expenditures		21,228			31,952
Insurance reimbursements		(27,176	)		(9,303	)
Contested insurance recoveries		(651	)		(337	)
Ending balance at December 31	$	26,992		$	33,591

As discussed further in Note J – Commitments and Contingencies, Insurance Litigation, 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

F-15

insurers and other associated parties in an attempt to collect pursuant to the applicable policies. Accordingly, during the fourth quarter of 2007, we reversed $62.9 million of anticipated insurance recoveries as they were deemed to be not probable of collection. This reversal resulted in a charge to earnings of approximately $60.1 million during 2007. A significant portion of the amounts capitalized to oil and gas properties following the increase in decommissioning liabilities due to hurricanes resulted in increased oil and gas property impairments during 2008 and 2007. See further discussion in Impairment of Long-Lived Assets section above. 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.

Approximately $70 to $80 million of the $95 to $110 million remaining hurricane related costs associated with the destroyed platforms is for the well intervention, abandonment, decommissioning, and debris removal. An estimate of the cost of this work has been accrued for as part of Maritech’s decommissioning liability, net of anticipated insurance recoveries. Anticipated insurance recoveries that have been reflected as a reduction of our decommissioning liabilities were $10.3 million at December 31, 2009, and $19.5 million at December 31, 2008. Anticipated insurance recoveries that have been reflected as insurance receivables, including the damages incurred during 2009 from the sunken barge, were $16.7 million at December 31, 2009, and $14.1 million at December 31, 2008. Subsequent to December 31, 2009, and through February 26, 2010, we have collected an additional $10.8 million of insurance recoveries. 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 2009, 2008, and 2007, approximately $5.4 million, $0.7 million, and $3.2 million, respectively, of such excess proceeds were credited to earnings. Intercompany profit on repair work performed by our Offshore Services segment is not recognized until such time as insurance claim proceeds are received.

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.

F-16

Fair Value Measurements

Effective January 1, 2008, we adopted the provisions of the Financial Accounting Standards Board Accounting Standards Codification (FASB Codification) Topic 820, “Fair Value Measurements and Disclosures,” which defines fair value, establishes a framework for measuring fair value, and expands disclosures about fair value measurements. FASB Codification Topic 820 establishes a fair value hierarchy and requires disclosure of fair value measurements within that hierarchy.

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.

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

We utilize fair value measurements to account for certain items and account balances within our consolidated financial statements. Fair value measurements are utilized in the allocation of purchase consideration for acquisition transactions to the assets and liabilities acquired, including intangible assets and goodwill. In addition, we utilize fair value measurements in the initial recording of our decommissioning and other asset retirement obligations. Fair value measurements may also be utilized on a nonrecurring basis, such as for the impairment of long-lived assets, including goodwill. The fair value of our financial instruments, which may include cash, temporary investments, accounts receivable, short-term borrowings, and long-term debt pursuant to our bank credit agreement, approximate their carrying amounts. The fair value of our long-term Senior Notes at December 31, 2009 was approximately $323.6 million compared to a carrying amount of approximately $310.1 million as current rates are more favorable than actual 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, 2009 and 2008 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
	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

F-17

Fair Value Measurements as of December 31, 2008 Using

Quoted Prices in

Active Markets for

Significant Other

Significant

Identical Assets

Observable

Unobservable

Total as of

or Liabilities

Inputs

Description

December 31, 2008

(Level 1)

(Level 2)

(Level 3)

(In Thousands)

Asset for natural gas

swap contracts

35,659

Asset for oil swap contracts

41,491

Total

77,150

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 Ended		or Liabilities		Inputs		Inputs		Total
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

New Accounting Pronouncements

In June 2009, the FASB published Statement of Financial Accounting Standard (SFAS) No. 168, “The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles – a replacement of FASB Statement No. 162,” which establishes the FASB Codification as the source of authoritative U.S. generally accepted accounting principles (GAAP) recognized by the FASB to be applied by nongovernmental entities. Beginning on the effective date of the standard (now incorporated into FASB Codification Subtopic 105-10), the FASB Codification superseded all then-existing non-SEC accounting and reporting standards. All other non-grandfathered non-SEC accounting literature not included in the FASB Codification has become non-authoritative. The standard is effective for financial statements issued for interim

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and annual periods ending after September 15, 2009. In the FASB’s view, the issuance of the standard and the FASB Codification will not change GAAP for public companies, and, accordingly, the adoption of the standard did not have a significant impact on our financial statements.

In March 2008, the FASB published SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities, an amendment of FASB Statement No. 133,” (FASB Codification Topic 815, “Derivatives and Hedging”), which requires entities to provide greater transparency about (1) how and why an entity uses derivative instruments, (2) how derivative instruments and related hedged items are accounted for under FASB Codification Topic 815 (SFAS No. 133 and its related interpretations); and (3) how derivative instruments and related hedged items affect an entity’s financial position, results of operations, and cash flows. This standard is effective for financial statements issued for fiscal years and interim periods within those fiscal years, beginning after November 15, 2008. Accordingly, we adopted the new disclosure requirements as of January 1, 2009.

In December 2007, the FASB published SFAS No. 141R, “Business Combinations,” (incorporated into FASB Codification Topic 805, “Business Combinations”), which established principles and requirements for how an acquirer of a business (1) recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, and any noncontrolling interest in the acquiree; (2) recognizes and measures the goodwill acquired in the business combination or a gain from a bargain purchase; and (3) determines what information to disclose to enable users of the financial statements to evaluate the nature and financial effects of the business combination. The standard changes many aspects of the accounting for business combinations and applies prospectively to business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008. We adopted this standard as of January 1, 2009 with no significant impact, as there have been no acquisitions during 2009. However, the standard is expected to significantly impact how we account for and disclose future acquisition transactions.

In December 2008, the SEC released its “Modernization of Oil and Gas Reporting” rules, which revise the disclosure of oil and gas reserve information. The new disclosure requirements include provisions that permit the use of new technologies to determine proved reserves in certain circumstances. The new requirements also will allow companies to disclose their probable and possible reserves and require companies to (1) report on the independence and qualifications of a reserves preparer or auditor; (2) file reports when a third party is relied upon to prepare reserve estimates or conduct a reserves audit; and (3) report oil and gas reserves using an average price based upon the prior twelve month period, rather than year-end prices. These new reporting requirements are effective for annual reports on Form 10-K for fiscal years ending on or after December 31, 2009. We adopted these new SEC oil and gas reserve rules as of December 31, 2009, however, they did 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. As a result of this disposal, we reflected a gain on the sale of our process services business of approximately $25.8 million, net of tax, for the difference between the sales proceeds and the net carrying value of the disposed net assets. The calculation of this gain included $2.7 million of goodwill related to the process services operation. Our process services operation was previously included as a component of our Production Enhancement Division.

F-19

A summary of financial information related to our discontinued operations for each of the past three years is as follows:

	Year Ended December 31,
	2009			2008			2007
	(In Thousands)
Revenues
Process services operations	$	-		$	-		$	16,145
Venezuelan fluids and production testing operations		-			-			608
	$	-		$	-		$	16,753

Income (loss), net of taxes
Process services operations, net of taxes of $(86),
$(226), and $1,182, respectively	$	(161	)	$	(424	)	$	1,939
Venezuelan fluids and production testing operations,
net of taxes of $101, $1, and $90, respectively		(216	)		(1,501	)		(137	)
Other discontinued operations		(49	)		(556	)		(79	)
	$	(426	)	$	(2,481	)	$	1,723

Gain from disposal
Process services operation, net of taxes of $228, $0 and
$14,906, respectively	$	423		$	-		$	25,827

Total income (loss) from discontinued operations, net of tax
Process services	$	262		$	(424	)	$	27,766
Venezuelan fluids and production testing operations		(216	)		(1,501	)		(137	)
Other discontinued operations		(49	)		(556	)		(79	)
	$	(3	)	$	(2,481	)	$	27,550

NOTE D — ACQUISITIONS AND DISPOSITIONS

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.

In April 2007, we acquired certain assets and the operations of a company that provides fluids transfer and related services in support of high pressure fracturing processes. The acquisition expanded our Fluids Division’s fluids transfer and related services business by providing such services to customers in the Arkansas, TexOma, and ArkLaTex regions. As consideration for the acquired assets, we paid approximately $8.5 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 $0.2 million of inventory, $5.5 million of property, plant, and equipment; $1.4 million of certain intangible assets; and $1.3 million of goodwill. Intangible assets, other than goodwill, are amortized over their useful lives, ranging from five to six years.

In September 2007, we acquired the assets and operations of E.O.T. Rentals, LLC (EOT), a business which provides onshore and offshore cutting services and equipment rentals and services in the U.S. Gulf Coast region. As consideration for the acquired assets, we paid approximately $6.1 million of cash at closing, subject to adjustment, with an additional $1.0 million which was paid at prescribed dates over the subsequent

F-20

two years. We allocated the purchase price of this acquisition to the fair value of the assets and liabilities acquired, which consisted of approximately $0.7 million of net working capital, approximately $2.8 million of property, plant, and equipment; $0.9 million of certain intangible assets; and $2.5 million of goodwill. Intangible assets, other than goodwill, are amortized over their useful lives, ranging from five to six years.

During 2007, our Maritech subsidiary entered into seven separate transactions in which it sold interests in certain oil and gas properties and assets. As a result of these transactions, the buyers of these properties assumed an aggregate of approximately $4.0 million of Maritech’s associated decommissioning liabilities. Maritech paid total net cash of approximately $0.5 million in these transactions and recognized gains totaling approximately $2.4 million. The amount of oil and gas reserve volumes associated with the sold properties was immaterial.

In December 2007, our Maritech subsidiary acquired interests in oil and gas properties located in the offshore Gulf of Mexico from a subsidiary of Cimarex Energy Company (the Cimarex Properties) in exchange for cash of $59.2 million after final closing adjustments during 2008 and the assumption of the associated decommissioning liabilities with a fair value of approximately $23.6 million. Also in December 2007, an additional interest in one of the Cimarex Properties was separately acquired from an unrelated third party in exchange for cash of $2.0 million. The acquired oil and gas properties were recorded at a cost of approximately $84.8 million.

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 ten 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 2014 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, 2009:

	Capital Lease		Operating Leases
	(In Thousands)

2010	$	62	$	4,676
2011		62		2,391
2012		62		1,791
2013		62		1,061
2014		62		746
After 2014		310		85
Total minimum lease payments	$	620	$	10,750

Rental expense for all operating leases was $10.0 million, $13.3 million, and $12.8 million in 2009, 2008, and 2007, respectively.

F-21

NOTE F — INCOME TAXES

The income tax provision attributable to continuing operations for the years ended December 31, 2009, 2008, and 2007 consists of the following:

	Year Ended December 31,
	2009			2008			2007
	(In Thousands)
Current
Federal	$	7,762		$	(4,840	)	$	(2,319	)
State		(856	)		5,156			(1,255	)
Foreign		8,453			6,491			3,841
		15,359			6,807			267
Deferred
Federal		18,889			794			1,325
State		1,742			(1,204	)		1,257
Foreign		573			(657	)		(1,908	)
		21,204			(1,067	)		674
Total tax provision	$	36,563		$	5,740		$	941

A reconciliation of the provision for income taxes attributable to continuing operations, computed by applying the federal statutory rate for the years ended December 31, 2009, 2008, and 2007 to income before income taxes and the reported income taxes, is as follows:

	Year Ended December 31,
	2009			2008			2007
	(In Thousands)
Income tax provision (benefit) computed at
statutory federal income tax rates	$	36,880		$	(1,370	)	$	757
State income taxes (net of federal benefit)		576			2,568			(84	)
Nondeductible expenses		1,566			4,281			1,320
Impact of international operations		(1,138	)		1,248			(1,045	)
Excess depletion		(124	)		(239	)		(279	)
Tax credits		(237	)		(538	)		(171	)
Other		(960	)		(210	)		443
Total tax provision	$	36,563		$	5,740		$	941

The provision 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 approximated $5.9 million at December 31, 2009, 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,
	2009		2008			2007
	(In Thousands)

Domestic	$	82,251	$	(11,054	)	$	(8,432	)
International		23,119		7,139			10,594
Total	$	105,370	$	(3,915	)	$	2,162

We file U.S. federal, state, and foreign income tax returns. We believe we have justification for the tax positions utilized in the various tax returns we file. With few exceptions, we are no longer subject to U.S. federal, state, local, or non-U.S. income tax examinations by tax authorities for years prior to 2003.

F-22

We adopted the provisions of FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes” (now incorporated into FASB Codification Topic 740, “Income Taxes”), on January 1, 2007. The standard provides guidance on measurement and recognition in accounting for income tax uncertainties and provides related guidance on derecognition, classification, disclosure, interest, and penalties. As a result of the implementation of the standard, we recognized an approximate $0.1 million increase in the liability for unrecognized tax benefits, which was accounted for as a reduction to the January 1, 2007 balance of retained earnings.

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

	Year Ended December 31,
	2009			2008			2007
	(In Thousands)

Gross unrecognized tax benefits at beginning of period	$	2,235		$	2,566		$	2,483

Increases in tax positions for prior years		561			-			-
Decreases in tax positions for prior years		-			-			-
Increases in tax positions for current year		-			341			394
Settlements		-			-			-
Lapse in statute of limitations		(540	)		(672	)		(311	)
Gross unrecognized tax benefits at end of period	$	2,256		$	2,235		$	2,566

We recognize interest and penalties related to uncertain tax positions in income tax expense. During the years ended December 31, 2009, 2008, and 2007, we recognized approximately $0.5 million, $0.3 million, and $0.6 million, respectively, in interest and penalties in provision for income tax. As of December 31, 2009 and 2008, we had approximately $2.0 million and $2.5 million, respectively, of accrued potential interest and penalties associated with these uncertain tax positions. The total amount of unrecognized tax benefits that would affect our effective tax rate if recognized is $1.7 million and $2.2 million as of December 31, 2009 and 2008, 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	2006
United States – State and Local	2002
Non-U.S. jurisdictions	2003

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, 2009 and 2008 are as follows:

F-23

Deferred Tax Assets:
	December 31,
	2009			2008
	(In Thousands)

Accruals	$	87,088		$	99,357
Goodwill		5,249			7,528
All other		26,280			23,299
Total deferred tax assets		118,617			130,184
Valuation allowance		(4,255	)		(3,337	)
Net deferred tax assets	$	114,362		$	126,847

Deferred Tax Liabilities:
	December 31,
	2009		2008
	(In Thousands)
Excess book over tax basis in
property, plant, and equipment	$	161,126	$	148,684
Unrealized gains on derivatives		13,879		28,700
All other		14,033		15,557
Total deferred tax liability		189,038		192,941
Net deferred tax liability	$	74,676	$	66,094

The change in the valuation allowance during 2009 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, 2009, we had approximately $4.9 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 2010 through 2029. At December 31, 2009, we had approximately $2.1 million of foreign tax credits available to offset future payment of federal income taxes. The foreign tax credits expire in varying amounts through 2018.

NOTE G — ACCRUED LIABILITIES

Accrued liabilities are detailed as follows:

	December 31,
	2009		2008
	(In Thousands)

Taxes payable	$	13,932	$	7,280
Oil and gas drilling advances		367		11,283
Compensation and employee benefits		16,525		17,280
Oil and gas producing liabilities		20,643		23,859
Unearned income		12,844		189
Accrued inventory supply settlement		-		1,747
Other accrued liabilities		20,327		25,021
	$	84,638	$	86,659

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NOTE H — LONG-TERM DEBT AND OTHER BORROWINGS

Long-term debt consists of the following:

	December 31,
	2009		2008
	(In Thousands)

Bank revolving line of credit facility, due 2011	$	-	$	97,368
5.07% Senior Notes, Series 2004-A, due 2011		55,000		55,000
4.79% Senior Notes, Series 2004-B, due 2011		40,132		39,472
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
European credit facility		-		-
		310,132		406,840
Less current portion		-		-

Total long-term debt	$	310,132	$	406,840

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

	Year Ending
	December 31,
	(In Thousands)

2010	$	-
2011		95,132
2012		-
2013		35,000
2014		-
Thereafter		180,000

	$	310,132

Bank Credit Facilities

Our bank credit agreement (the Credit Agreement) provides for available borrowing capacity of up to $300 million and matures June 27, 2011. The facility is unsecured and is guaranteed by our material U.S. subsidiaries. Borrowings under the Credit Agreement bear interest at the British Bankers Association LIBOR rate plus 0.50% to 1.25%, depending on one of our financial ratios. We pay a commitment fee on unused portions of the facility at a rate from 0.15% to 0.30%, also depending on this financial ratio. As of December 31, 2009, there was no balance outstanding under the credit facility.

The Credit Agreement contains customary covenants and other restrictions, including certain financial ratio covenants that were modified from the previous credit facility agreement. Additionally, the Credit Agreement includes cross-default provisions relating to any of our other indebtedness 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 pursuant to the Credit Agreement. We are in compliance with all covenants and conditions of our Credit Agreement as of December 31, 2009. Defaults under the Credit Agreement that are 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 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 $7.2 million equivalent as of December 31, 2009), 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, 2009, we had no borrowings pursuant to the European Credit Agreement.

F-25

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, or the Note Purchase Agreement dated April 2008. 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 Master Note Purchase Agreement, 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 Agreement and Master Note Purchase Agreement as of December 31, 2009. Upon the occurrence and during the continuation of an event of default under the Note Purchase Agreement and 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.

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,
	2009			2008
	(In Thousands)

Beginning balance for the period, as reported	$	248,725		$	199,506

Activity in the period:
Accretion of liability		7,893			7,084
Retirement obligations incurred		1,326			20,274
Revisions in estimated cash flows		47,069			43,034
Settlement of retirement obligations		(80,903	)		(21,173	)

Ending balance at December 31	$	224,110		$	248,725

NOTE J — COMMITMENTS AND CONTINGENCIES

Litigation

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Insurance Litigation – Through December 31, 2009, we have expended approximately $55.2 million of well intervention and debris removal work primarily associated with the three Maritech offshore platforms and associated wells which were destroyed as a result of Hurricanes Katrina and Rita in 2005. As a result of submitting claims associated with well intervention costs expended during 2006 and 2007 and responding to underwriters’ requests for additional information, approximately $28.9 million of these well intervention costs were reimbursed; however, our insurance underwriters maintained that well intervention costs for certain of the damaged wells did not qualify as covered costs and certain well intervention costs for qualifying wells were not covered under the policy. In addition, the underwriters also maintained that there was no additional coverage provided under an endorsement we obtained in August 2005 for the cost of debris removal associated with these platforms or for other damage repairs associated with Hurricanes Katrina and Rita on certain properties in excess of the insured values provided by the property damage section of the policy. Although we provided requested information to the underwriters and had numerous discussions with the underwriters, brokers, and insurance adjusters, we did not receive the requested reimbursement for these contested costs. As a result, on November 16, 2007, we filed a lawsuit in Montgomery County, Texas, entitled Maritech Resources, Inc. v. Certain Underwriters and Insurance Companies at Lloyd’s, London subscribing to Policy no. GA011150U and Steege Kingston, in which we sought damages for breach of contract and various related claims and a declaration of the extent of coverage of an endorsement to the policy. We also made an alternative claim against our insurance broker, based on its procurement of the August 2005 endorsement, and a separate claim against underwriters’ insurance adjuster for its role in handling the insurance claim. During the fourth quarter of 2007, we reversed the anticipated insurance recoveries previously included in estimating Maritech’s decommissioning liability, increasing the decommissioning liability to $48.4 million for well intervention and debris removal work to be performed, assuming no insurance reimbursements would be received. In addition, we reversed a portion of our anticipated insurance recoveries previously included in accounts receivable related to certain damage repair costs incurred. As a result of the increase to the decommissioning liability, certain capitalized costs were not realizable, resulting in impairments in accordance with the successful efforts method of accounting. See Note B – Summary of Significant Accounting Policies, Oil and Gas Properties for further discussion.

During October 2009, we entered into a settlement agreement with regard to this lawsuit, under which we received approximately $40.0 million during the fourth quarter of 2009 associated with the 2005 endorsement and well intervention costs incurred or to be incurred from Hurricanes Katrina and Rita. Except for approximately $0.6 million of proceeds expected to be received in March 2010, no significant additional insurance recoveries of well intervention, debris removal, or excess property damage costs associated with Hurricanes Katrina and Rita will be received. Following the collection of these amounts, we have collected approximately $136.6 million of insurance proceeds associated with damage from Hurricanes Katrina and Rita. This amount represents substantially all of the maximum coverage limits pursuant to our policies. We estimate that future repair and well intervention, abandonment, decommissioning, and debris removal efforts related to these destroyed platforms will result in approximately $45 million to $50 million of additional costs, and an estimate of these costs has been accrued for as part of Maritech’s decommissioning liability. As a result of the resolution of this contingency, the full amount of settlement proceeds is reflected as a credit to earnings in the fourth quarter of 2009.

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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.

Environmental

Product Purchase Obligations

NOTE K — CAPITAL STOCK

Our Restated Certificate of Incorporation authorizes us to issue 100,000,000 shares of common stock, par value $.01 per share, and 5,000,000 shares of preferred stock, par value $.01 per share. As of December 31, 2009, we had 75,542,282 shares of common stock outstanding, with 1,497,346 shares held in treasury, and no shares of preferred stock outstanding. The voting, dividend, and liquidation rights of the

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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 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, 2009, 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 recognized in earnings over the requisite service period. Total equity-based compensation expense for the three years ended December 31, 2009, 2008, and 2007 was $6.7 million, $5.9 million, and $4.4 million, respectively, which approximated the fair value of equity-based compensation awards vesting during the periods. This expense reduced net income by $4.4 million, $3.7 million, and $2.8 million and reduced basic and diluted earnings per share by $0.06, $0.05 and $0.04, respectively, for the three years ended December 31, 2009, 2008, and 2007.

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, 2009 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, 2009 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

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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.

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. Pursuant to the TETRA Technologies, Inc. Amended and Restated 2007 Equity Incentive Compensation Plan, we are authorized to grant up to 4,590,000 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, 2009, we granted to certain officers and employees restricted shares, which generally vest over a three to five year period. During 2009, we granted a total of 98,053 restricted shares, having an average market value (equal to the 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. During 2008, we granted a total of 216,901 restricted shares, having an average market value (equal to the quoted closing price of the common stock on the dates of grant) of $19.51 per share, or an aggregate market value of $4.2 million, at the date of grant. During 2007, we granted a total of 258,750 restricted shares, having an average market value of $27.66 per share, or an aggregate market value of approximately $7.2 million, at the date of grant.

The following is a summary of restricted stock activity for the year ended December 31, 2009:

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

Nonvested restricted shares outstanding at December 31, 2008		352		$	23.39

Shares granted		98			8.07
Shares cancelled		(15	)		24.29
Shares vested		(152	)		17.60
Nonvested restricted shares outstanding at December 31, 2009		283		$	21.16

F-30

Grants of Options to Purchase Common Stock

Stock options authorized for issuance, outstanding and currently exercisable at December 31, 2009, 2008, and 2007 are as follows:

	2009		2008		2007
	(In Thousands, Except Per Share Amounts)
TETRA Technologies, Inc. Amended and Restated 2007 Equity
Incentive Compensation Plan
Maximum number of shares authorized for issuance		4,590		4,590		90
Shares reserved for future grants		931		2,908		63
Options exercisable at period end		469		6		6
Weighted average exercise price of options exercisable
at period end	$	19.90	$	18.50	$	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		-		-		48
Options exercisable at period end		359		320		257
Weighted average exercise price of options exercisable
at period end	$	27.04	$	26.86	$	26.61

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		1,290		1,395		1,955
Weighted average exercise price of options exercisable
at period end	$	7.43	$	7.09	$	6.52

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		342
Weighted average exercise price of options exercisable
at period end	$	15.26	$	12.09	$	11.74

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		870		842		936
Weighted average exercise price of options exercisable
at period end	$	14.40	$	13.85	$	12.13

The following is a summary of options outstanding and options exercisable as of December 31, 2009:

		Options Outstanding						Options Exercisable
				Weighted		Weighted				Weighted		Weighted
				Average		Average				Average		Average
Range of				Remaining		Exercise				Remaining		Exercise
Exercise Price		Shares		Contracted Life		Price		Shares		Contracted Life		Price
		(In Thousands)		(In Years)				(In Thousands)		(In Years)
	$1.61 to $4.07		1,966		8.3	$	3.72		235		2.0	$	3.29
	$4.08 to $8.11		608		3.8	$	4.74		498		2.6	$	4.83
	$8.12 to $9.21		1,241		2.9	$	9.09		1,232		2.9	$	9.10
	$9.22 to $20.85		333		4.0	$	15.78		283		3.2	$	15.80
	$20.86 to $30.00		1,862		7.5	$	22.85		883		6.8	$	23.80
			6,010		6.2	$	11.53		3,131		3.9	$	12.74

F-31

The following is a summary of stock option activity for the year ended December 31, 2009:

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

Outstanding at December 31, 2008		4,590		$	14.80

Options granted		1,948			3.88
Options cancelled		(324	)		15.39
Options exercised		(204	)		5.90
Outstanding at December 31, 2009		6,010		$	11.53

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, 2009, 2008, and 2007 was approximately $0.8 million, $5.3 million and $43.2 million, respectively. The intrinsic value of options outstanding as of December 31, 2009 was $20.8 million, and the intrinsic value of options exercisable as of December 31, 2009 was $7.4 million. Cash received from stock options exercised during the three years ended December 31, 2009, 2008, and 2007 was $1.2 million, $4.7 million and $12.1 million, respectively. Recognized excess tax benefits related to the exercise of stock options during the three years ended December 31, 2009, 2008, and 2007 were $0.2 million, $1.5 million and $13.2 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, 2009:

	Year Ended December 31,
	2009	2008	2007

Expected stock price volatility	65% to 73%	32% to 57%	31% to 36%
Expected life of options	4.7 years	4.4 to 4.8 years	3.4 to 4.3 years
Risk free interest rate	1.9% to 2.6%	1.5% to 3.9%	4.3% to 5.0%
Expected dividend yield	-	-	-

The weighted average fair value of options granted during the years ended December 31, 2009, 2008 and 2007, using the Black-Scholes model, was $2.73, $7.61, and $7.74 per share, respectively. Total estimated unrecognized compensation cost from unvested stock options and restricted stock as of December 31, 2009 was approximately $15.0 million, which is expected to be recognized over a weighted average period of approximately 2.4 years.

Certain options exercised during 2008 and 2007 were exercised through the surrender of 26,304 and 4,655 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 2009, 2008, and 2007, we received 6,318, 8,119 and 27,784 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, 2009, net of options previously exercised pursuant to our various stock option plans, we have a maximum of 7,224,063 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 $0.7 million, $3.3 million, and $2.7 million in 2009, 2008, and 2007, respectively.

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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-one participants in the program at December 31, 2009. 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, 2009, 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 our 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 involve, among other measures, the use of derivative financial instruments, such as swap and collar agreements, to hedge the impact of market price risk exposures for a significant portion of our oil and gas production and for certain foreign currency transactions. We are exposed to the volatility of oil and gas prices for the portion of our 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, 2009, 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
Natural gas swap contracts	20,000 MMBtu/day	$8.147/MMBtu	2010
Oil swap contracts	2,000 Bbls/day	$78.70/Bbl	2010

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. The summary above includes a natural gas swap contract for 10,000 MMBtu/day of 2010 production at a contract price of $6.03/MMBtu and an oil swap contract for 2,000 barrels/day of 2010 production at a contract price of $78.70/barrel, both of which were added during 2009. In January 2010, we entered into an additional oil swap contract for 1,000 barrels/day of 2010 production, beginning February 2010, at a contract price of $84.90/barrel.

We believe that our swap agreements are “highly effective cash flow hedges” in managing the volatility of future cash flows associated with our oil and gas 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 those derivative contracts which have been liquidated, will be subsequently reclassified into product sales

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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, 2009, the total balance (approximately $23.5 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.

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, 2009 and 2008 are as follows:

	Balance Sheet	Fair Value at December 31,
Derivatives designated as hedging	Location	2009			2008
instruments		(In Thousands)

Natural gas swap contracts	Current assets	$	19,926		$	25,031
Oil swap contracts	Current assets		-			13,021
Natural gas swap contracts	Long-term assets		-			10,628
Oil swap contracts	Long-term assets		-			28,470
Oil swap contracts	Current liabilities		(2,618	)		-
Oil swap contracts	Long-term liabilities		-			-
Total derivatives designated as hedging
instruments		$	17,308		$	77,150

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, 2009. Pretax gains and losses associated with oil and gas derivative swap contracts for each of the three years ended December 31, 2009, 2008, and 2007 are summarized below:

	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	)

	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

F-34

	Year Ended December 31, 2007
	Oil			Natural Gas			Total
	(In Thousands)
Derivative swap contracts
Amount of pretax gain (loss) reclassified from accumulated other comprehensive
income into product sales revenue (effective portion)	$	5,277		$	(3,102	)	$	2,175
Amount of pretax gain (loss) from change in derivative fair value
recognized in other comprehensive income		(63,261	)		4,264			(58,997	)
Amount of pretax gain (loss) recognized in other income (expense)
(ineffective portion)		-			165			165

The cash flow hedging swap contracts that were liquidated during the second quarter of 2009 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 in the accompanying statements of cash flows. 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 the third quarter of 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, 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 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. Our long-term debt includes borrowings which are designated as a hedge of our net investment in our European calcium chloride operations. At December 31, 2009, we had 28.0 million euros (approximately $40.1 million) designated as a hedge of a net investment in this foreign operation. Changes in the foreign currency exchange rate have resulted in a cumulative change to the cumulative translation adjustment account of $4.7 million, net of taxes, at December 31, 2009, 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,
	2009		2008		2007
	(In Thousands)

Number of weighted average common shares outstanding		75,045		74,519		73,573
Assumed exercise of stock options		677		-		2,348
Average diluted shares outstanding		75,722		74,519		75,921

For the year ended December 31, 2009, the average diluted shares outstanding excludes the impact of 3,185,388 of average outstanding stock options that have exercise prices in excess of the average market price, as the inclusion of these shares would have been antidilutive. For the year and the three month period 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. For the year ended December 31, 2007, the average diluted shares outstanding excludes the impact of 716,354 of average outstanding stock options that have exercise prices in excess of the average market price, as the inclusion of these shares would have been antidilutive.

F-35

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 2008, our Production Enhancement Division consists of two separate reporting segments: the Production Testing segment, and the Compressco segment. Segment information for 2007 has been revised to conform to the 2008 and 2009 presentation.

Our Fluids Division manufactures and markets 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, an oil and gas exploration, exploitation, and production segment. The Offshore Services segment provides (1) downhole and subsea services such as plugging and abandonment, workover, and wireline services, (2) construction and decommissioning services, including hurricane damage remediation, utilizing our heavy lift barges and 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 and the operation of several dive support vessels.

The Maritech segment consists of our Maritech Resources, Inc. (Maritech) subsidiary, which, with its subsidiaries, is an oil and gas exploration and production company focused in the offshore and onshore U.S. Gulf Coast region. Maritech periodically acquires oil and gas properties in order to replenish or expand its production operations and to provide additional development and exploitation opportunities. The Offshore Division’s Offshore Services segment performs a significant portion of the well 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.

F-36

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

	Year Ended December 31,
	2009			2008			2007
	(In Thousands)
Revenues from external customers
Product sales
Fluids Division	$	167,984		$	227,194		$	226,399
Offshore Division
Offshore Services		2,970			4,328			4,860
Maritech		174,191			207,180			213,338
Intersegment eliminations		-			-			-
Total Offshore Division		177,161			211,508			218,198
Production Enhancement Division
Production Testing		-			-			-
Compressco		4,860			8,639			12,641
Total Production Enhancement Division		4,860			8,639			12,641
Consolidated	$	350,005		$	447,341		$	457,238

Services and rentals
Fluids Division	$	57,491		$	65,602		$	54,353
Offshore Division
Offshore Services		304,729			279,019			306,174
Maritech		2,848			1,329			816
Intersegment eliminations		-			-			-
Total Offshore Division		307,577			280,348			306,990
Production Enhancement Division
Production Testing		80,556			126,996			92,989
Compressco		83,248			88,778			70,913
Total Production Enhancement Division		163,804			215,774			163,902
Consolidated	$	528,872		$	561,724		$	525,245

Intersegment revenues
Fluids Division	$	42		$	452		$	1,322
Offshore Division
Offshore Services		46,099			23,015			30,048
Maritech		-			-			-
Intersegment eliminations		(45,648	)		(22,971	)		(29,057	)
Total Offshore Division		451			44			991
Production Enhancement Division
Production Testing		1			23			141
Compressco		-			-			-
Total Production Enhancement Division		1			23			141
Intersegment eliminations		(494	)		(519	)		(2,454	)
Consolidated	$	-		$	-		$	-

Total revenues
Fluids Division	$	225,517		$	293,248		$	282,074
Offshore Division
Offshore Services		353,798			306,362			341,082
Maritech		177,039			208,509			214,154
Intersegment eliminations		(45,648	)		(22,971	)		(29,057	)
Total Offshore Division		485,189			491,900			526,179
Production Enhancement Division
Production Testing		80,557			127,019			93,130
Compressco		88,108			97,417			83,554
Total Production Enhancement Division		168,665			224,436			176,684
Intersegment eliminations		(494	)		(519	)		(2,454	)
Consolidated	$	878,877		$	1,009,065		$	982,483

F-37

	Year Ended December 31,
	2009			2008			2007
	(In Thousands)

Depreciation, depletion, amortization, and accretion
Fluids Division	$	15,281		$	14,033		$	12,758
Offshore Division
Offshore Services		16,347			18,998			16,279
Maritech		87,274			99,665			82,800
Intersegment eliminations		(506	)		(544	)		(891	)
Total Offshore Division		103,115			118,119			98,188
Production Enhancement Division
Production Testing		14,139			12,233			9,355
Compressco		13,780			12,049			8,043
Total Production Enhancement Division		27,919			24,282			17,398
Corporate overhead		3,011			2,459			1,500
Consolidated	$	149,326		$	158,893		$	129,844

Interest expense
Fluids Division	$	116		$	173		$	159
Offshore Division
Offshore Services		6			101			75
Maritech		19			43			57
Intersegment eliminations		-			-			-
Total Offshore Division		25			144			132
Production Enhancement Division
Production Testing		2			30			21
Compressco		-			-			-
Total Production Enhancement Division		2			30			21
Corporate overhead		13,064			17,210			17,574
Consolidated	$	13,207		$	17,557		$	17,886

Income (loss) before taxes and discontinued operations
Fluids Division	$	20,791		$	5,401		$	10,897
Offshore Division
Offshore Services		78,394			3,019			33,496
Maritech		22,012			(31,932	)		(49,815	)
Intersegment eliminations		647			(782	)		6,225
Total Offshore Division		101,053			(29,695	)		(10,094	)
Production Enhancement Division
Production Testing		17,690			35,677			25,639
Compressco		23,563			30,310			26,663
Total Production Enhancement Division		41,253			65,987			52,302
Corporate overhead		(57,727	)(1)		(45,608	)(1)		(50,943	)(1)
Consolidated	$	105,370		$	(3,915	)	$	2,162

Total assets
Fluids Division	$	375,754		$	328,852		$	285,882
Offshore Division
Offshore Services		190,494			220,671			262,729
Maritech		363,605			413,661			391,703
Intersegment eliminations		(2,246	)		(2,902	)		(2,119	)
Total Offshore Division		551,853			631,430			652,313
Production Enhancement Division
Production Testing		112,276			100,676			80,281
Compressco		202,995			212,619			186,448
Total Production Enhancement Division		315,271			313,295			266,729
Corporate overhead		104,721	(2)		139,047	(2)		90,612	(2)
Consolidated	$	1,347,599		$	1,412,624		$	1,295,536

F-38

	Year Ended December 31,
	2009			2008			2007
	(In Thousands)

Capital expenditures
Fluids Division	$	84,134		$	76,531		$	18,877
Offshore Division
Offshore Services		17,930			14,299			29,732
Maritech		26,832			84,970			178,392
Intersegment eliminations		(454	)		(247	)		(5,113	)
Total Offshore Division		44,308			99,022			203,011
Production Enhancement Division
Production Testing		9,036			25,904			22,513
Compressco		2,944			33,241			23,676
Total Production Enhancement Division		11,980			59,145			46,189
Corporate overhead		11,351			27,401			7,997
Consolidated	$	151,773		$	262,099		$	276,074

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

	2009		2008			2007
General and administrative expense	$	40,173	$	34,185		$	31,533
Depreciation and amortization		3,011		2,459			1,500
Interest expense		13,064		17,210			17,574
Other general corporate (income) expense, net		1,479		(8,246	)		336
Total	$	57,727	$	45,608		$	50,943

(2) Includes assets of discontinued operations.

Summarized financial information concerning the geographic areas of our customers and in which we operate at December 31, 2009, 2008, and 2007 is presented below:

	Year Ended December 31,
	2009			2008			2007
	(In Thousands)
Revenues from external customers:
U.S.	$	751,101		$	855,380		$	850,857
Canada and Mexico		37,984			36,939			25,330
South America		17,372			15,522			9,307
Europe		68,015			85,713			80,495
Africa		2,477			1,973			2,498
Asia and other		1,928			13,538			13,996
Total	$	878,877		$	1,009,065		$	982,483

Transfers between geographic areas:
U.S.	$	-		$	2,578		$	318
Canada and Mexico		-			-			-
South America		-			225			-
Europe		1,472			55			1,548
Africa		-			-			-
Asia and other		-			-			-
Eliminations		(1,472	)		(2,858	)		(1,866	)
Total revenues	$	878,877		$	1,009,065		$	982,483

Identifiable assets:
U.S.	$	1,197,512		$	1,273,642		$	1,163,604
Canada and Mexico		32,811			26,732			22,482
South America		41,556			27,379			17,843
Europe		59,633			70,964			79,972
Africa		5,468			4,684			1,821
Asia and other		10,649			9,636			5,772
Eliminations and discontinued operations		(30	)		(413	)		4,042
Total identifiable assets	$	1,347,599		$	1,412,624		$	1,295,536

F-39

In 2008 and 2007, a single purchaser of Maritech’s oil and gas production, Shell Trading (US) Company, accounted for approximately 13.5% and 12.5%, respectively, of our consolidated revenues. In 2009, 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,
	2009		2008		2007
	(In Thousands)

Acquisition	$	2,993	$	45,373	$	82,976
Exploration		6,820		8,522		-
Development		38,806		79,620		152,372
Total costs incurred	$	48,619	$	133,515	$	235,348

Approximately $5.0 million of the exploration costs incurred during 2009 was capitalized as of December 31, 2009, pending the determination of proved reserves. These capitalized exploration costs are associated with the drilling of a single well, which is expected to be evaluated in March 2010.

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,
	2009			2008
	(In Thousands)

Undeveloped properties	$	16,592		$	15,284
Proved developed properties being amortized		668,512			691,398
Total capitalized costs		685,104			706,682
Less accumulated depletion, depreciation,
and amortization		(388,069	)		(367,952	)
Net capitalized costs	$	297,035		$	338,730

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.

F-40

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,
	2009			2008			2007
	(In Thousands)

Oil and gas sales revenues	$	174,191		$	207,180		$	213,338
Production (lifting) costs (1)		79,115			89,574			89,605
Depreciation, depletion, and amortization		79,610			82,971			73,835
Impairments of properties (2)		11,410			42,658			76,094
Excess decommissioning and abandonment costs		23,771			7,045			12,153
Exploration expenses		151			224			1,174
Accretion expense		7,717			7,631			6,841
Dry hole costs		-			9,063			1,699
Gain on insurance recoveries		(45,391	)		(697	)		(3,245	)
Pretax income (loss) from producing activities		17,808			(31,289	)		(44,818	)
Income tax expense (benefit)		6,551			(8,455	)		(16,549	)
Results of oil and gas producing activities	$	11,257		$	(22,834	)	$	(28,269	)

(1)	Production costs during 2009, 2008, and 2007 include certain hurricane repair expenses of $8.2 million, $8.5 million, and $13.5 million, respectively.

(2)	Impairments of oil and gas properties during 2007 were primarily due to the increase in Maritech’s decommissioning liability as a result of contested insurance coverage. Impairments of oil and gas properties during 2008 were primarily due to decreased oil and natural gas prices.

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, by applying generally accepted petroleum engineering and evaluation principles, 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.

Through our Maritech subsidiary, we employ full-time, experienced reservoir engineers and geologists, who are responsible for determining proved reserves in conformance with guidelines established by the SEC. These SEC 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 value of the oil and gas reserves was affected by the impact of the new average pricing requirements. 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

F-41

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 80.2% of our proved reserve volumes as of December 31, 2009. The use of the term “reserve audit” is intended only to refer to the collective application of the engineering and geologic procedures which 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, and within existing economic conditions, operating methods, and governmental regulations. 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 engineering audits of a portion of our oil and gas reserves as of December 31, 2009, 2008, and 2007. 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, and 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.

F-42

The reserve audit performed by Ryder Scott Company, L.P. included certain properties selected by Maritech, including all of our most significant properties, excluding the Cimarex Properties, and represented approximately 64.0% of our total proved oil and gas reserve volumes (66.8% of discounted future net pretax cash flows) as of December 31, 2009. The reserve audit performed by DeGolyer and MacNaughton included the Cimarex Properties acquired in December 2007 and represented approximately 16.2% of our total proved oil and gas reserve volumes (15.1% of discounted future net pretax cash flows) as of December 31, 2009. The independent petroleum engineers represent in their audit reports that they believe Maritech’s estimates of future reserves were prepared in accordance with generally accepted petroleum engineering and evaluation principles for the estimation of future reserves in accordance with SEC standards. In each case, the independent petroleum engineers concluded 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 SPE. 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.

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, 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 for periods prior to December 31, 2009 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 Louisiana.

Reserve Quantity Information		Oil	Gas
		(MBbls)	(MMcf)

December 31, 2006
	Proved developed reserves	7,872	36,373
	Proved undeveloped reserves	957	3,365
Total proved reserves at December 31, 2006		8,829	39,738

December 31, 2007
	Proved developed reserves	6,646	43,898
	Proved undeveloped reserves	89	2,909
Total proved reserves at December 31, 2007		6,735	46,807

December 31, 2008
	Proved developed reserves	4,504	40,988
	Proved undeveloped reserves	1,433	1,024
Total proved reserves at December 31, 2008		5,937	42,012

December 31, 2009
	Proved developed reserves	5,690	32,387
	Proved undeveloped reserves	1,383	1,124
Total proved reserves at December 31, 2009		7,073	33,511

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	Oil			Gas
	(MBbls)			(MMcf)

Total proved reserves at December 31, 2006		8,829			39,738
Revisions of previous estimates		(760	)		(6,280	)
Production		(1,985	)		(9,515	)
Extensions and discoveries		584			2,766
Purchases of reserves in place		174			20,621
Sales of reserves in place		(107	)		(523	)

Total proved reserves at December 31, 2007		6,735			46,807
Revisions of previous estimates		(40	)		(1,774	)
Production		(1,467	)		(10,989	)
Extensions and discoveries		521			2,771
Purchases of reserves in place		191			5,199
Sales of reserves in place		(3	)		(2	)

Total proved reserves at December 31, 2008		5,937			42,012
Revisions of previous estimates		1,971			(623	)
Production		(1,325	)		(10,449	)
Extensions and discoveries		569			3,365
Purchases of reserves in place		-			-
Sales of reserves in place		(79	)		(794	)

Total proved reserves at December 31, 2009		7,073			33,511

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

“Standardized measure” relates to the estimated discounted future net cash flows and major components of that calculation relating to proved reserves at the end of the year in the aggregate, based on SEC prescribed prices and costs, using statutory tax rates and using a 10% annual discount rate. The standardized measure is not an estimate of the fair value of proved oil and gas reserves. Probable and possible reserves, which may become proved in the future, are excluded from these calculations. Furthermore, prices used to determine the standardized measure are prior to the impact of hedge derivatives and are influenced by seasonal demand and other factors and may not be representative in estimating future revenues or reserve data.

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

	December 31,
	2009			2008
	(In Thousands)

Future cash inflows	$	536,594		$	494,908
Future costs
Production		192,152			192,998
Development and abandonment		235,042			251,015
Future net cash flows before income taxes		109,400			50,895
Future income taxes		(14,846	)		(2,399	)
Future net cash flows		94,554			48,496
Discount at 10% annual rate		(8,505	)		11,852
Standardized measure of discounted future net cash flows	$	86,049		$	60,348

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Changes in Standardized Measure of Discounted Future Net Cash Flows:

	Year Ended December 31,
	2009			2008			2007
	(In Thousands)

Standardized measure, beginning of year	$	60,348		$	298,679		$	186,090

Sales, net of production costs		(95,076	)		(110,561	)		(111,580	)
Net change in prices, net of production costs		43,098			(297,719	)		179,079
Changes in future development costs		2,235			(30,590	)		10,635
Development costs incurred		10,585			39,035			26,615
Accretion of discount		6,396			41,245			27,569
Net change in income taxes		(7,536	)		110,150			(24,171	)
Purchases of reserves in place		-			13,233			55,673
Extensions and discoveries		27,873			19,108			53,504
Sales of reserves in place		1,268			(252	)		4,114
Net change due to revision in quantity estimates		41,045			(6,295	)		(83,826	)
Changes in production rates (timing) and other		(4,187	)		(15,685	)		(25,023	)
Subtotal		25,701			(238,331	)		112,589

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

NOTE S — QUARTERLY FINANCIAL INFORMATION (Unaudited)

Summarized quarterly financial data for 2009 and 2008 is as follows:

	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

	Three Months Ended 2008
	March 31		June 30		September 30		December 31
	(In Thousands, Except Per Share Amounts)

Total revenues	$	225,156	$	304,389	$	249,099	$	230,421
Gross profit (loss)		42,047		77,427		43,708		(11,181	)
Income (loss) before discontinued operations		7,354		30,157		12,118		(59,284	)

Net income (loss)		6,687		29,417		11,657		(59,897	)

Net income (loss) per share before
discontinued operations	$	0.10	$	0.41	$	0.16	$	(0.79	)

Net income (loss) per diluted share before
discontinued operations	$	0.10	$	0.40	$	0.16	$	(0.79	)

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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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