Edgar Filing: TETRA TECHNOLOGIES INC

tti10k030209.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, 2008

[ ] 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 [ ] NO [ X ]

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

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

LARGE ACCELERATED FILER [ X ]

ACCELERATED FILER [ ]

NON-ACCELERATED FILER [ ]

SMALLER REPORTING COMPANY [ ]

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

YES [ ] NO [ X ]

THE AGGREGATE MARKET VALUE OF COMMON STOCK HELD BY NON-AFFILIATES OF THE REGISTRANT WAS $1,747,453,200 AS OF JUNE 30, 2008, 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 27, 2009 WAS 75,260,086 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, 2009 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	22
Item 2.	Properties	22
Item 3.	Legal Proceedings	26
Item 4.	Submission of Matters to a Vote of Security Holders	27

	Part II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and
	Issuer Purchases of Equity Securities	27
Item 6.	Selected Financial Data	28
Item 7.	Management’s Discussion and Analysis of Financial Condition
	and Results of Operation	30
Item 7A.	Quantitative and Qualitative Disclosures about Market Risk	54
Item 8.	Financial Statements and Supplementary Data	57
Item 9.	Changes in and Disagreements with Accountants on Accounting
	and Financial Disclosure	57
Item 9A.	Controls and Procedures	57
Item 9B.	Other Information	57

	Part III
Item 10.	Directors, Executive Officers and Corporate Governance	58
Item 11.	Executive Compensation	58
Item 12.	Security Ownership of Certain Beneficial Owners and Management and
	Related Stockholder Matters	58
Item 13.	Certain Relationships and Related Transactions, and Director Independence	58
Item 14.	Principal Accounting Fees and Services	58

	Part IV
Item 15.	Exhibits, Financial Statement Schedules	59

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

Our Offshore Division, which was previously known as our Well Abandonment & Decommissioning (WA&D) Division, consists of two operating segments: Offshore Services (previously known as WA&D Services) and Maritech, an oil and gas exploration, exploitation, and production segment. The Offshore Services segment provides (1) downhole and sub-sea services such as plugging and abandonment, workover, inland water drilling, and wireline services, (2) construction and decommissioning services, including hurricane damage remediation, utilizing our heavy-lift barges and cutting technology 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, exploitation, and production company focused in the offshore, inland waters and onshore regions of the Gulf of Mexico. Maritech acquires oil and gas properties in order to grow its production operations and to provide additional development and exploitation opportunities, as well as to provide a baseload of business for the Division’s Offshore Services segment.

Our Production Enhancement Division consists of two operating segments; Production Testing and Compressco. The Production Testing segment provides production testing services to markets in Texas, New Mexico, Colorado, Oklahoma, Arkansas, Louisiana, Pennsylvania, offshore Gulf of Mexico, Mexico, Brazil, Northern Africa, and the Middle East.

The Compressco segment provides wellhead compression-based production enhancement services to a broad base of customers throughout 14 states that encompass most of the onshore producing regions of the United States, as well as in Canada, Mexico, and other international locations. These production enhancement 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 domestic 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 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 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 solids-free, clear salt solutions that, like conventional drilling “muds,” have high specific gravities and are used as weighting fluids to control bottomhole pressures during oil and gas completion and workover activities. The use of CBFs increases 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 greater formation sensitivity, the significantly greater investment necessary to drill 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 domestic 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 chemicals manufacturing group of the Fluids Division obtains product from numerous production facilities that manufacture liquid and/or dry calcium chloride, sodium bromide, calcium bromide, zinc bromide and/or 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 obtain liquid and dry calcium chloride from production facilities located in the United States, Canada, China, and Europe. We own some of these plants, and we obtain production from the non-owned plants under agreements with the owners. Dry calcium chloride is produced at our Kokkola, Finland plant, which has a production capacity of 165,000 tons per year. We operate our European calcium chloride manufacturing operations under the name TCE. We also own a calcium chloride plant in Lake Charles, Louisiana, with a production capacity of 100,000 tons of dry product per year. In addition, we are constructing a new calcium chloride plant near El Dorado, Arkansas, to produce liquid and dry (flake) calcium chloride with production scheduled to begin in late 2009. We also manufacture liquid calcium chloride from our facility in Parkersburg, West Virginia. We also have two solar evaporation plants located in San Bernardino County, California, which produce liquid calcium chloride from underground brine reserves.

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 its 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.

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 sub-sea services such as plugging and abandonment, workover, inland water drilling, and wireline services, (2) construction and decommissioning services, including hurricane remediation, utilizing our heavy-lift barges and cutting technology 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. 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, exploitation, and production company focused in the offshore and inland waters of the Gulf of Mexico. Maritech acquires oil and gas properties on which it conducts exploitation operations that are intended to increase the cash flows on such properties prior to their ultimate abandonment. In addition, oil and gas properties acquired by Maritech provide a baseload of business for the Offshore Services segment.

In providing its array of services, our Offshore Services segment utilizes barge-mounted rigs, a platform rig, offshore rigless 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 provide pressure transient testing, reservoir evaluation, well performance evaluation, cased hole and memory production logging, perforating, bridge plug and packer services, and pipe recovery 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 Belle Chasse, 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.

Maritech acquires, manages, and exploits oil and gas properties in the offshore, inland water and onshore region of the Gulf of Mexico. Maritech acquires properties for their potential for additional exploitation, although many of Maritech’s producing properties were also purchased to support the Division’s Offshore Services businesses. 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’s operations grew substantially during the past several years due to the acquisition of offshore Gulf of Mexico producing properties and subsequent development activities on these properties. The most recent acquisitions of oil and gas properties were in December 2007 and January 2008, when Maritech purchased oil and gas producing properties in three separate transactions for an aggregate of $75.1 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. We refer to these properties as the Cimarex Properties. An additional interest in one of the Cimarex Properties was also acquired in a separate transaction from an unrelated third party. 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 which had previously been restricted. This connecting pipeline also serves other producing properties operated by third parties. In July 2008, Maritech further developed the Cimarex Properties by completing the hookup of three new sub-sea wells, specifically on Main Pass blocks 185, 187, and 200, and these wells are currently capable of producing approximately 17 MMcf/day and 119 barrels/day, net to Maritech’s interest. Maritech began production from four additional subsea wells in the Main Pass area during February 2009, at rates of approximately 11 MMcf/day and 175 barrels/day, net to Maritech’s interest. In addition, the acquired Cimarex Properties, through their accompanying leasehold ownership, provide us with additional development prospects which we intend to exploit over the next several years utilizing 100 blocks of purchased and reprocessed 3D seismic data. In January 2008, we acquired certain offshore oil and gas producing properties from Stone Energy Corporation. During the three year period ended December 31, 2008, Maritech significantly increased its acquisition, and exploitation activities, spending approximately $324.0 million on such projects. As a result of this acquisition and exploitation activity, at December 31, 2008, Maritech had proved reserves of approximately 5.9 million barrels of oil and 42.0 billion cubic feet of natural gas, with undiscounted future net pretax cash flow of approximately $50.9 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 flowback pressure and volume testing of 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, and laboratory analysis. 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. This includes 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 Alice, Benbrook, Corpus Christi, Edinburg, Laredo, Midland, Palestine, and Victoria, Texas. The Division also has operating locations in Parachute, Colorado; New Iberia and Bossier City, Louisiana; Rochester, Pennsylvania; Reynosa, Villahermosa, Poza Rica, and Veracruz, Mexico; Macae, Brazil; Tripoli, Libya; Manama, Bahrain; and Dammam, Saudi Arabia.

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 are characterized by lower formation pressures. Compressco designs and manufactures the compressor equipment (the GasJackTM units) it uses to provide production enhancement services. Compressco’s fleet of GasJackTM units totaled 3,605 as of December 31, 2008, of which 3,064 units were in service, representing an increase in the number of units in service of approximately 11% from the prior year.

Compressco’s GasJackTM 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 GasJackTM unit, where the gas is compressed. The GasJackTM 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 GasJackTM 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 GasJackTM 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, 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 domestic 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 or calcium chloride. We purchase raw materials utilized by our Lake Charles facility from a variety of sources, although supply constraints have resulted in this facility operating at less than full capacity. When supply of liquid calcium chloride is available, the Lake Charles plant also produces solid (pellet) calcium chloride. The Lake Charles pellet plant operated for four months during

2008. The raw material supply for our Lake Charles facility is expected to be enhanced with liquid calcium chloride to be provided by our new El Dorado, Arkansas plant. We also produce calcium chloride at our two plants in San Bernardino County, California through evaporation of naturally occurring underground brine reserves. These brines 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. In addition, we purchase liquid calcium chloride from a Delfzijl, Netherlands plant owned by a joint venture in which we have a 50% ownership interest.

To significantly increase our existing production capacity, we are constructing a new calcium chloride manufacturing plant located on land purchased from Chemtura Corporation (Chemtura) and adjacent to Chemtura’s central bromine plant, located near El Dorado, Arkansas. This new plant, which is designed to produce liquid and flake calcium chloride, along with other co-products such as magnesium hydroxide and sodium chloride, is expected to allow the Division to reduce its dependence on third party suppliers. The plant is designed to utilize calcium chloride containing brines obtained from Chemtura’s operations. Construction of the new El Dorado calcium chloride plant is expected to be completed in late 2009.

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 will purchase its requirements of raw material bromine from Chemtura’s Arkansas bromine facilities. In addition, Chemtura will supply the Division’s new El Dorado calcium chloride plant with tail brine from its Arkansas facilities following bromine extraction. Upon entering the long-term Chemtura supply agreement, we amended our previous less favorable long-term supply agreement for calcium bromide. As part of this amendment, we agreed to meet certain purchase requirements through 2008. In December 2007, we entered into an agreement with our previous supplier whereby we were released from our remaining purchase requirements and the supply agreement was terminated in exchange for future payments totaling approximately $9.3 million to be made in 2008 and early 2009.

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 Compressco segment, designs and manufactures its compressor equipment (the GasJackTM units) which it uses to provide wellhead compression-based production enhancement services. Some of the components used in the GasJackTM 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 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.

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. 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 has enabled us to compete successfully. Besides Petrobras, major customers of the Fluids Division also 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, governmental, 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 Dow Chemical Company 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 sub-sea 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, drilling, 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 predominately 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, drilling, 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 related property damage insurance costs, has also accelerated the

abandonment and decommissioning plans of many offshore operators. Offshore activities in the Gulf of Mexico have historically been highly seasonal, with the majority 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 sub-sea 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, ConocoPhillips, ExxonMobil, Forest Oil, Mariner Energy, Newfield Exploration, Pioneer, 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 Specialties, 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; however, for the year ended December 31, 2008, Maritech had one customer, Shell Trading (US) Company, that accounted for 13.5% of our consolidated revenues. We did not have any other individual customer account for more than 10% of our consolidated revenues. 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, distillation analysis, gas composition analysis, and oilfield water analysis services.

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 and operating procedures give us a competitive advantage in the marketplace. Competition in onshore markets is dominated by numerous small, privately owned operators. Schlumberger Limited 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), and ARAMCO (the national oil company of Saudi Arabia).

The Division’s Compressco segment provides production enhancement services to over 400 natural gas and oil producers throughout 14 states that encompass most of the onshore producing regions of the United States, as well as in Canada, Mexico, 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. Compressco primarily targets natural gas wells in its operating regions that produce between 30 thousand and 300 thousand cubic feet of natural gas per day, with less than 50 barrels of water per day. 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 GasJackTM 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. These facilities are in close proximity to both product supplies and customer concentrations. Since transportation costs can represent a large percentage of the total delivered cost of chemical products, particularly liquid chemicals, we believe that our Fluids Division’s strategic locations give us a competitive advantage over certain other suppliers of CBFs in the southern United States and California. In addition, the Fluids Division supplies CBFs to selected international markets, including Brazil, Mexico, the British and Norwegian sectors of the North Sea, West Africa, and the Middle East.

Non-oilfield calcium chloride products are also marketed through the Division’s sales offices in California, Missouri, Pennsylvania, and Texas, as well as through a network of distributors 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.

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, 2008 was $137.8 million, of which approximately $42.0 million is expected to be billed during 2009. This compares to an estimated backlog of $175.5 million at December 31, 2007.

Employees

As of December 31, 2008, we had 3,107 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, 2008, we owned or licensed twenty-four issued U.S. patents and had nine patent applications pending in the United States. Internationally, we had fourteen issued foreign patents and thirty-seven foreign patent applications pending. The foreign patents and patent applications are primarily foreign counterparts to U.S. patents or patent applications. The issued patents expire at various times through 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 domestic operations, various environmental protection laws and regulations have been enacted and amended in the United States 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 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 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

Certain 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 “budget,” “budgeted,” “assumes,” “should,” “goal,” “anticipates,” “expects,” “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: activity levels for oil and gas drilling, completion, workover, production, and abandonment activities; volatility of oil and gas prices; general economic and business conditions including the impact the current economic uncertainty may have on us or our customers; foreign currency risks; operating risks inherent in oil and gas production; weather; our ability to implement our business strategy; uncertainties about estimates of reserves; environmental risks; estimates of hurricane repair costs; 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 for our products and services is affected by the current global financial crisis.

The demand for our products and services are materially dependent on levels of oil and gas well drilling, completion, workover, production, and abandonment activities, both in the United States and internationally. Such activity levels have decreased as a result of the recent decline in energy consumption and uncertainty of the capital markets caused by the current global financial crisis. Decreased energy consumption has resulted in a significant decrease in energy prices during the last half of 2008 and continuing into 2009. This decline in energy prices 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.

The consequences of a prolonged economic recession may include a further decrease in economic activity, including oil and gas industry spending levels, for an extended period of time. This decrease in 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 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 the oil or natural gas markets weaken, 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 continued price risk.

Our revenues from oil and gas production represent approximately 20.5% of our total consolidated revenues for the year ended December 31, 2008. Therefore, we have significant direct market risk exposure in the pricing of our oil and gas production. Our realized pricing is primarily driven by the prevailing worldwide price for crude oil and spot prices in the U.S. natural gas market and the portion of our oil and gas production that is hedged. During the first half of 2008, and prior to the impact of our derivative hedges, crude oil and natural gas prices received for Maritech’s production averaged $114.01 and $10.29, respectively. During December 2008, these crude oil and natural gas prices received averaged $32.45 and $6.19, respectively. This price volatility is expected to continue. Significant further declines in prices for oil and natural gas could have a material affect 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. This means that 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.

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 development of additional competing non-oil and gas energy supplies, efforts to improve energy conservation, and improvements in the energy efficiency of vehicles, plants, equipment, and devices may also reduce oil and gas consumption.

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 price competition, changes in sales and distribution channels, availability of skilled labor and contract services, shortages in raw materials due to untimely supplies, or inability to obtain supplies at reasonable prices may also continue to affect the cost of sales and the fluctuation of gross margin in future periods.

Other factors affecting our operating activity levels include the cost of exploring for and producing oil and gas, the discovery rate of new oil and gas reserves, 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, interest rates and 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 and 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 CBFs, including brominated CBFs, such as calcium bromide, zinc bromide, sodium bromide, and other brominated products, some of which we manufacture and some of which are purchased from third parties. We also sell calcium chloride as a CBF for use in oil and gas wells and in other forms and for other applications. Sales of calcium chloride and brominated products contribute significantly to our revenues. In our manufacture of calcium chloride, we use hydrochloric acid and other raw materials purchased from third parties. We purchase raw materials utilized by our Lake Charles calcium chloride facility from a variety of sources, although supply constraints have resulted in this facility operating at less than full capacity. In our manufacture of brominated 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 brominated products needs as well as for the needs of our new El Dorado, Arkansas calcium chloride plant beginning later in 2009. We also acquire brominated products from several third party suppliers. If we are unable to acquire the brominated 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.

Some of the well abandonment and decommissioning services performed by our Offshore Division require the use of vessels and services provided by third parties. We lease equipment and obtain services from certain providers, but these are subject to availability at reasonable prices.

The fabrication of GasJackTM wellhead compressor units by our Compressco subsidiary requires the purchase of many types of components that 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 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 a portion of our outstanding indebtedness.

As of December 31, 2008, $97.4 million of our outstanding long-term debt consists of floating rate loans, which bear interest at an agreed upon percentage rate spread above LIBOR. 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.

Operating Risks:

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 as a result of hurricanes. 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 toppled and destroyed by these storms. In addition, two production facilities located in inland waters were destroyed, one of which was reconstructed during 2007. A majority of our damaged assets, with the exception of the destroyed Maritech platforms, have been repaired or are in the final stages of being repaired, and have resumed operation. We currently estimate that the repairs to the remaining partially damaged platforms and assets will cost from $6 million to $8 million net to our interest before insurance recoveries, and these costs will be incurred over the next several months. With regard to the destroyed offshore platforms, however, well intervention efforts have been performed on certain wells associated with two of the platforms destroyed in 2005, and we are assessing the extent of well intervention work required on wells associated with the four additional destroyed platforms. In addition, we have yet to incur costs for debris removal associated with any of the destroyed offshore platforms, but are also assessing these costs. Such damage assessment, well intervention, and subsequent debris removal efforts could continue over the next several years. We estimate that future well intervention and abandonment efforts associated with the destroyed platforms and production facility, including costs to remove debris, reconstruct destroyed structures, and redrill certain associated wells, will cost approximately $140 to $190 million net to our interest 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.

While we believe we will be reimbursed for a majority of the cost of the damages incurred in excess of policy deductibles pursuant to our various insurance policies, including the well intervention and debris removal costs to be incurred by Maritech, there can be no assurances that all of such expected reimbursements will be collected. Related to certain well intervention costs incurred in connection with the 2005 hurricanes, our insurance underwriters have continued to maintain that costs for certain of the damaged wells do not qualify as covered costs and that certain well intervention costs for qualifying wells are not covered under the policy for that period. In addition, the underwriters have also maintained that there is no additional coverage provided under an endorsement we obtained in August 2005 for the cost of removal of the platforms destroyed in 2005 or for the repair of other 2005 damage on certain properties in excess of the insured values provided by our property damage policy for that period. In late 2007, we filed a lawsuit against the underwriters, adjuster, and one of our brokers in a further attempt to collect the reimbursement for these well intervention and repair costs incurred as well as future well intervention and debris removal costs to be incurred resulting from the 2005 hurricanes.

We have begun to perform the initial phases of the well intervention work related to the platforms destroyed by the 2008 hurricanes. 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. Despite our efforts to pursue our rights legally, we may not collect any of the contested well intervention and debris removal costs incurred and to be incurred as a result of the 2005 storms. 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.

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

Our operating cash flows also 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. Approximately 32.6% of Maritech’s oil production and 17.0% of its natural gas production from fields producing before the storms is currently shut-in. One of the destroyed offshore platforms has resulted in the loss of production from a key producing field. In addition, much of Maritech’s daily production is processed through neighboring platforms, pipelines, and processing facilities of other operators and third parties. 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 beyond 2009. Although we anticipate that many of Maritech’s remaining shut-in properties will resume during early 2009, 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, including certain assets owned by third parties, the timing of which is outside of Maritech’s control.

We could incur losses on well abandonment and decommissioning projects.

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

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 purchase 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 exploitation 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 natural gas and oil 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 current volatility of natural gas and oil 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 subject to change due to changing cost estimates, oil and gas prices, revisions of reserve estimates and other factors. During 2008, 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 $7.0 million of this adjustment was charged to earnings as an operating expense during 2008. 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.

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

Drilling for oil and natural gas involves numerous risks, including the risk that we will not encounter commercially productive oil or natural gas reservoirs. The costs of drilling, completing, and operating wells are often uncertain, and 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, 2008, we have expended approximately $324.0 million of development and exploitation costs, and we expect to continue to incur such costs in the future. During the year ended December 31, 2008, we charged approximately $9.1 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.

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 31.5% of our proved reserves as of December 31, 2008 are proved producing reserves. Except to the extent that we find or acquire additional properties containing estimated proved reserves; conduct successful exploitation, development, or exploration 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. Current natural gas and oil commodity pricing, as well as our need to conserve capital in light of the current economic environment, 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.

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 were 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 and commercial production following a discovery of hydrocarbons while we construct our own facility. 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 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, cratering, 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 toxic gases or other pollutants. We are particularly susceptible to adverse weather conditions in the Gulf of Mexico, including hurricanes and other extreme weather conditions. Damage caused by high winds and turbulent seas could potentially cause us to curtail both service and production operations for significant periods of time until damage can be assessed and repaired. Moreover, even if we do not experience direct damage from these storms, we may experience disruptions in our operations because customers may curtail their development activities due to damage to their platforms, pipelines, and other related facilities.

These hazards also include injuries to employees and third parties during the performance of our operations. Our operation of marine vessels, heavy equipment, and offshore production platforms involves 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 and deductibles 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.

Following the hurricanes in the Gulf of Mexico region during the third quarters of 2005 and 2008, the cost of the insurance coverage we have typically purchased in the past has increased dramatically. Current coverage premiums now cost several times more than they did historically, particularly for offshore oil and gas production operations. Insurance coverage with favorable deductible and maximum coverage amounts may not be available in the market, or its cost may not be justifiable. Our insurance coverage today includes higher deductibles and lower maximum coverage limits than in prior years. 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.

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

The Offshore Division 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 Division, under certain turnkey and other contracts, may bear the risk of delays caused by adverse weather conditions. 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.

Delays or cost overruns on construction projects could adversely affect our business, or the expected profitability and cash flows upon completion may not be as timely or as high as expected.

We are currently constructing a new calcium chloride plant facility near El Dorado, Arkansas, and have recently completed construction of a new corporate headquarters facility in The Woodlands, Texas. Due to our continuing growth strategy, we could have other significant construction projects in the future. These projects are subject to the risk of delays or cost overruns inherent in construction projects. These risks include, but are not limited to:

·	unforeseen quality or engineering problems;

·	work stoppages;

·	weather interference;

·	unanticipated cost increases;

·	delays in receipt of necessary equipment; and

·	inability to obtain the requisite permits or approvals.

The completion of these construction projects will require a significant amount of working capital, and delays or cost overruns on these projects could adversely affect our cash flows. In addition, we will not receive any material increase in revenue or cash flow from the El Dorado, Arkansas calcium chloride plant until after it is placed in service and we are able to begin production. Delays in the completion of this calcium chloride facility could affect future profitability for our Fluids Division operations.

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 underestimate the duration of the current economic downturn. 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.

Our expansion into foreign countries exposes us to unfamiliar regulations and may expose us to 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, Ivory Coast and Libya, and have joint ventures in Saudi Arabia and The Netherlands. 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 limited.

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 will depend on our ability to attract and retain skilled employees. 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 workers in the Gulf Coast region is high, and the supply is limited. Changes in personnel, therefore, could adversely affect operating results.

Financial Risks:

We have significant long-term debt outstanding.

As of December 31, 2008, our long-term debt outstanding was approximately $406.8 million and our debt to total capital ratio was 44.1%. Additional growth could result in increased debt levels to support our capital expenditure needs or acquisition activities. Our current level of long-term debt could limit our ability to obtain additional financing on satisfactory terms to fund our capital expenditures, acquisitions, working capital needs, and other general corporate requirements. A portion of our long-term debt outstanding is at variable interest rates. 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.

Certain of our businesses are exposed to significant credit risks.

We face concentrations of credit risk associated with the significant amounts of accounts receivable we have with companies 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 who 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.

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;

·	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 described in this Annual Report for the year ended December 31, 2008 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 as of the date of the estimate, in accordance with SEC requirements, while future prices and costs may be materially higher or lower. The SEC currently requires that we report our oil and natural gas reserves using the price as of the last day of the year. Using lower values 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.

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 last two quarters of 2008, and primarily due to the decrease in oil and natural gas prices, we recorded oil and gas property impairments on proved properties totaling approximately $42.7 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.

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. Factors that may be considered a change 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, 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.

Legal/Regulatory 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, environmental affairs, health and safety, waste management, and the manufacture, storage, handling, transportation, use, and sale of chemical products. 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 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 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. The extent of this coverage is consistent with our other insurance programs. 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.

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.

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, flowback testing equipment, and compression equipment. The following information describes facilities that we leased or owned as of December 31, 2008. We believe our facilities are adequate for our present needs.

Fluids Division. Fluids Division facilities include seven chemical production plants located in the states of Arkansas, California, Louisiana, and West Virginia, and the country of Finland. The total manufacturing area of these plants, excluding the two California locations, is approximately 496,000 square feet. The two California locations contain 29 square miles of acreage containing solar evaporation ponds and leased mineral acreage. A new calcium chloride plant facility is currently being constructed in Arkansas. 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 twenty-four service center facilities, thirteen domestically and eleven internationally. The Fluids Division also leases eight offices and thirty-seven terminal locations, twenty-three 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
TETRA Southern Hercules	Four point anchor barge
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
Epic Pioneer	110-foot dive support vessel
Epic Endeavor	110-foot utility vessel

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

Production Enhancement Division. Production Enhancement Division facilities include sixteen production testing distribution facilities (fifteen of which are leased) in Texas, Colorado, Louisiana, and Pennsylvania and in Brazil, Mexico, Libya, Bahrain, 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. As of December 31, 2008, we leased approximately 105,000 square feet of office space. In February 2009, we relocated our headquarters to our newly constructed office building, located on 2.635 acres of land adjacent to our previous location. 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, 2008 of Maritech’s most significant oil and gas properties:

	Net Total
	Proved	Net Proved		2008 Net
	Reserves	Reserves Mix		Production	Working	Production
	(MMcfe)	Oil%	Gas%	(MMcfe)	Interest %	Status

Timbalier Bay Area	23,233	70%	30%	7,735	100%	Producing
Cimarex Properties,
Main Pass Area	18,545	4%	96%	3,479	50% - 100%	Producing
East Cameron 328	9,618	89%	11%	1,647	50%	Shut-in

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 SEC guidelines. 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 addition to the complete analysis by Maritech’s internal reservoir engineers, independent petroleum engineers and geologists performed reserve audits of approximately 85.3% of our proved reserve volumes as of December 31, 2008. 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.

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) and subsequent SEC staff interpretations and guidance.

Maritech engaged Ryder Scott Company, L.P. and DeGolyer and McNaughton to perform the reserve audits of a portion of our oil and gas reserves as of December 31, 2008 and 2007. 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, 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 61.9% of our total proved oil and gas reserve volumes as of December 31, 2008. The reserve audit performed by DeGolyer and McNaughton included the Cimarex Properties acquired in December 2007 and represented approximately 23.4% of our total proved oil and gas reserve volumes as of December 31, 2008. 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 as set forth in Society of Petroleum Engineers (SPE) 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 table sets forth information with respect to our estimated proved reserves as of December 31, 2008. The standardized measure of discounted future net cash flows attributable to oil and gas reserves was prepared by our Maritech subsidiary, using constant prices as of the calculation date, net of future income taxes, discounted at 10% per annum. 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, and approximately 88% of our estimated proved reserves as of December 31, 2008 are classified as proved developed reserves.

	December 31, 2008

Estimated proved reserves:
Natural gas (Mcf)		42,012,000
Oil (Bbls)		5,937,000

Standardized measure of discounted future net cash flows	$	60,348,000

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. They are not necessarily directly comparable, however, due to special DOE reporting requirements. In no instance have 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 2008, 2007, and 2006:

	Year Ended December 31,
	2008		2007		2006
Production:
Natural gas (Mcf)		10,988,840		9,515,214		7,812,339
Oil (Bbls)		1,466,621		1,985,183		1,356,108

Revenues:
Natural Gas	$	99,901,000	$	76,202,000	$	81,271,000
Oil		107,279,000		137,136,000		82,828,000

Total	$	207,180,000	$	213,338,000	$	164,099,000

Average realized unit prices and costs:
Natural gas (per Mcf)	$	9.09	$	8.01	$	10.40
Oil (per Bbl)	$	73.15	$	69.08	$	61.08

Production cost per equivalent Mcf	$	4.53	$	4.18	$	3.99
Depletion cost per equivalent Mcf	$	4.19	$	3.45	$	2.42

Production cost per equivalent Mcf 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 $13.5 million being charged during 2007 and $8.5 million in 2008. The 2008 production cost per equivalent Mcf was also increased due to the impact of hurricanes which resulted in significant properties being shut-in during the last four months of 2008. Depletion cost per equivalent Mcf excludes the impact of dry hole costs and property impairments.

Acreage and Productive Wells. At December 31, 2008, 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	15	-	0.90	-	367	23	-	-
Louisiana Offshore	55	21	55.00	21.00	16,559	16,559	5,777	5,777
Texas Offshore	-	2	-	1.50	2,864	1,968	-	-
Federal Offshore	19	56	9.80	21.70	346,601	164,920	112,753	78,885

Total	89	79	65.70	44.20	366,391	183,470	118,530	84,662

Drilling Activity. 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. Maritech participated in the drilling of 10 gross productive wells (6.75 net wells) during 2006. As of December 31, 2008, there was 1 additional gross well (0.5 net wells) 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. As of December 31, 2006 there were 3 additional wells (1.33 net wells) in the process of being drilled, one of which was subsequently determined to be unproductive.

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 expect these matters to have a material adverse impact on the financial statements.

Class Action Lawsuit - Between March 27, 2008 and April 30, 2008, two putative class action complaints were filed in the United States District Court for the Southern District of Texas (Houston Division) against us and certain 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.

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 actions, 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 case has been stayed by agreement of the parties pending the Court’s ruling on our motion to dismiss the federal class action.

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.

Insurance Litigation – Through December 31, 2008, we have expended approximately $47.4 million of well intervention work on certain wells associated with two of the three Maritech offshore platforms which were destroyed as a result of Hurricanes Katrina and Rita in 2005. We estimate that future repair and well intervention efforts related to these destroyed platforms, including platform debris removal and other storm related costs, will result in approximately $50 to $70 million of additional costs. Approximately $28.9 million of the well intervention costs previously expended and submitted to our insurance providers have been reimbursed; however, our insurance underwriters have continued to maintain that well intervention costs for certain of the damaged wells do not qualify as covered costs and that certain well intervention costs for qualifying wells are not covered under the policy for that period. In addition, the underwriters have also maintained that there is no additional coverage provided under an endorsement we obtained in August 2005 for the cost of removal of these platforms or for other damage repairs on certain properties in excess of the insured values provided by our property damage policy. After continuing to provide requested information to the underwriters regarding the damaged wells, and having numerous discussions with the underwriters, brokers, and insurance adjusters, we have yet to receive the requested reimbursement for these contested costs. On November 16, 2007, we filed

a lawsuit in the 359th Judicial District Court, 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 are seeking damages for breach of contract and various related claims and a declaration of the extent of coverage of an endorsement to the policy. We cannot predict the outcome of this lawsuit.

Item 4. Submission of Matters to a Vote of Security Holders.

No matters were submitted to a vote of our security holders, through solicitation of proxies or otherwise, during the fourth quarter of the year ended December 31, 2008.

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, 2009, there were approximately 12,710 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, 2008, as reported by the New York Stock Exchange.

	High		Low
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

2007
First Quarter	$	25.69	$	21.00
Second Quarter		28.94		24.61
Third Quarter		30.20		17.10
Fourth Quarter		22.96		14.58

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, 2003, 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. In May 2006, we declared a 2-for-1 stock split, which was effected in the form of a stock dividend to all stockholders of record as of May 15, 2006. See “Note K – Capital Stock” in the Notes to Consolidated Financial Statements attached hereto for a description of this stock split. 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 will be made from time to time in open market transactions at prevailing market prices. The repurchase program may continue until the authorized limit is reached, at which time the Board of Directors may review the option of increasing the authorized limit. During 2004, we repurchased 210,000 shares of our common stock pursuant to the repurchase program at a cost of approximately $3.3 million. During 2005, we repurchased 130,950 shares of our common stock pursuant to the repurchase program at a cost of approximately $2.4 million. There were no repurchases made during 2006, 2007, or 2008 pursuant to the repurchase program. Shares repurchased during the fourth quarter of 2008 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, 2008		-		$	-		-	$	14,327,000

Nov 1 - Nov 30, 2008		1,506	(2)	$	3.77		-	$	14,327,000

Dec 1 - Dec 31, 2008		-		$	-		-	$	14,327,000

Total		1,506					-	$	14,327,000

(1)

(2)	Shares we received in connection with the exercise of certain employee stock options or the vesting of certain employee restricted stock. These shares were not acquired pursuant to the stock repurchase program.

Item 6. Selected Financial Data.

The following tables set forth our selected consolidated financial data for the years ended December 31, 2008, 2007, 2006, 2005, and 2004. 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 10 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. During 2004, we completed the acquisitions of

Compressco, Inc., the European calcium chloride assets, and a heavy lift barge. These acquisitions significantly impact the comparison of our financial statements for 2008 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,
	2008			2007			2006			2005			2004
	(In Thousands, Except Per Share Amounts)
Income Statement Data
Revenues	$	1,009,065		$	982,483		$	767,795		$	509,249		$	334,881
Gross profit		152,001			116,383			252,804			123,672	(1)		71,983	(1)(2)
Operating income (loss)		(21	)		16,512			160,800			54,317			23,494
Interest expense		(17,557	)		(17,886	)		(13,637	)		(6,310	)		(1,962	)
Interest income		779			731			348			330			286
Other income (expense), net		12,884			2,805			4,858			3,692			257
Income (loss) before discontinued
operations		(9,655	)		1,221			99,880			34,802			15,184
Net income (loss)	$	(12,136	)	$	28,771		$	101,878		$	38,062		$	17,699

Income (loss) per share, before
discontinued operations (3)	$	(0.13	)	$	0.02		$	1.39		$	0.51		$	0.23
Average shares (3)		74,519			77,353			71,631			68,588			67,112

Income (loss) per diluted share, before
discontinued operations (3)	$	(0.13	)	$	0.02		$	1.33		$	0.48		$	0.21
Average diluted shares (3)		74,519	(4)		75,921	(5)		74,824			72,137			71,199

(1)	Gross profit for these periods reflects the reclassification of certain billed operating costs as cost of revenues, which had previously been credited to general and administrative expense. The reclassified amounts were $1,113 for 2005 and $360 for 2004.

(2)	Gross profit for this period reflects the reclassification of certain depreciation, amortization and accretion costs as cost of revenues, which had previously been included in general and administrative expense. The reclassified amount was $3,619 for 2004.

(3)	Net income 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 were effected in the form of a stock dividend as of the record dates.

(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,
	2008		2007		2006		2005		2004
	(In Thousands)
Balance Sheet Data
Working capital	$	222,832	$	181,441	$	262,572	$	135,989	$	117,350
Total assets		1,412,624		1,295,536		1,086,190		726,850		508,988
Long-term debt		406,840		358,024		336,381		157,270		143,754
Decommissioning and other
long-term liabilities		277,482		247,543		167,671		150,570		68,145
Stockholders' equity	$	515,821	$	447,919	$	420,380	$	284,147	$	236,181

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

The changing global economic environment, particularly as it has affected the oil and gas industry, has created an uncertainty that threatens to interrupt a period of unprecedented growth for our company. During the year ended December 31, 2008, and for the seventh consecutive year, our consolidated revenues increased over the prior year period, reflecting the increasing demand for our products and services during this period, and the execution of our growth strategy, both through internal expansion and acquisitions. Much of the increase in the general demand for energy services during this period was in response to escalating oil and natural gas pricing, caused by the increased energy demands of a growing global economy. While we continue to pursue growth, the impact of decreased oil and natural gas prices and uncertain capital markets caused by the current global financial crisis has now decreased the demand for many of our products and services. This has caused us to temper our growth strategy by implementing more conservative fiscal disciplines, such as lower growth expectations, operating and administrative cost reductions, more careful spending on capital projects, consideration of alternative sources of capital, and a more focused effort on using excess cash flow to reduce our long-term debt whenever possible. During 2008, and particularly subsequent to the third quarter hurricanes which interrupted a large portion of Maritech’s production cash flows, our long-term debt balance grew to $406.8 million, resulting in a debt to total capital ratio of 44.1% as of December 31, 2008. Subsequent to yearend, and as of February 27, 2009, this long-term debt balance has increased to $425.4 million and is not expected to significantly decrease until key capital expenditure projects in progress are completed. The most significant capital project is the construction of a new calcium chloride plant in El Dorado, Arkansas, which is expected to be completed and begin operations in the fourth quarter of 2009. Carefully managing our long-term debt levels and our growing asset retirement and decommissioning liabilities, while facing potentially weakening overall operating cash flows, are key strategies during this period of economic uncertainty, the duration of which appears to be indefinite.

Despite reporting overall increased consolidated revenues during 2008 compared to 2007, our profitability was negatively affected by several events and accounting adjustments recorded during the year. Our Maritech segment was severely affected by hurricanes during the third quarter of 2008, which resulted in a significant portion of its producing properties being shut-in during the last several months of the year. Maritech also was directly impacted by the significant decrease in oil and natural gas prices experienced during the last half of 2008, which largely contributed to $42.7 million of oil and gas property impairments recognized in 2008. These decreased oil and natural gas prices are expected to continue during 2009, affecting the profitability of Maritech and indirectly affecting each of our other reporting segments as well. Our Fluids Division showed significant operating growth during 2008, with improved gross profit as a result of lower costs for its CBF products and increased completion service margins. Our Offshore Services segment (formerly known as our Well Abandonment & Decommissioning Services segment) showed minimally improved performance, as lower capacity and poor operating weather conditions during much of the year were offset by the strong performance late in the year of its contract diving operation, which is capitalizing on the post-hurricane market demand for its services. The performances of our Fluids and Offshore Services segments were offset, however, by the impairments of goodwill and other long-term assets, which resulted in each segment reporting decreased pretax earnings compared to the prior year. Our Production Enhancement Division, consisting of our Production Testing segment and Compressco segment, reported continuing growth in earnings compared to the prior year, as each of these businesses continued to expand their operations during most of the year. Corporate overhead decreased during 2008 compared to 2007 as growth in overall administrative expenses were

more than offset by gains recorded to other income associated with certain commodity derivative contracts during the fourth quarter of 2008.

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 decreased significantly recently in response to lower oil and natural gas pricing and the general uncertainty regarding availability of capital resources in the current economic environment. Our overall growth is hampered by the current decreased industry demand for 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.;

·	advancing age of offshore platforms in the Gulf of Mexico; and

·	increasing development of oil and gas reserves abroad.

Our Fluids Division generates revenues and cash flows by manufacturing and selling completion fluids and providing filtration, water transfer, and associated products and engineering services to domestic and international exploration and production companies. In addition, the Fluids Division also provides liquid and dry calcium chloride products manufactured at its production facilities or purchased from third party suppliers to a variety of markets outside the energy industry. Fluids Division revenues increased 4.0% during 2008 compared to the prior year due primarily to increased prices and service activity. 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. More recently, overall industry drilling activity has also been acutely impacted by the current decreased oil and natural gas prices and increased capital constraints as a result of the general economic conditions. Potentially offsetting some of this decline, 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 demand for our Fluids Division products has 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. 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 in El Dorado, Arkansas. The plant is expected to increase the Division’s capacity for providing calcium chloride to its customers, generating revenues and cash flows beginning in the fourth quarter of 2009.

Our Offshore Division consists of two operating segments: the Offshore Services segment and Maritech segment. Offshore Services generates revenues and cash flows by performing (1) downhole and sub-sea services such as plugging and abandonment, workover, inland water drilling, and wireline services, (2) construction and decommissioning services, including hurricane remediation, and (3) diving services involving conventional and saturated air diving. 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 intends to capitalize on the current demand for well abandonment and decommissioning activity 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 decreased by 10.2% during 2008, primarily associated with the heavy lift capacity from vessels which we leased during portions of 2007 and due to decreased 2008 activity levels for well abandonment and decommissioning services, a portion of which was due to unfavorable weather during much of the year. This decrease was despite a significant increase in dive services activity, particularly following the 2008 hurricanes. Despite

this increase in demand for dive services, the Division expects overall activity to further decrease in 2009 due to lower oil and natural gas prices.

Through Maritech and its subsidiaries, the Division acquires, manages, explores, and exploits 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 acquires properties for their exploration and development potential, although many of Maritech’s producing properties were also purchased to support the Division’s Offshore Services businesses. During 2008, Maritech’s operations were hampered by several factors that will continue to impact its operations going forward, including production interruptions from hurricanes, decreasing oil and natural gas pricing, increased insurance and other operating costs, reduced funding for capital expenditures, and significant future well intervention and decommissioning efforts. Following the 2008 hurricanes, Maritech now has six toppled offshore platforms that will require extensive efforts to decommission. Maritech continues to assess the remaining well intervention and debris removal efforts associated with these six offshore platforms and continues to believe that substantially all such hurricane related costs incurred and to be incurred in excess of deductibles are covered costs pursuant to its insurance policies. Maritech’s revenues during 2008 decreased by 2.6% compared to 2007, despite significantly increased realized oil and natural gas prices during much of the year, due primarily to the decreased overall production following the third quarter 2008 hurricanes. Although much of the storm-interrupted production has been restored or will be restored by the end of the first quarter of 2009, one of the destroyed offshore platforms served a key producing field, the East Cameron 328 field. The complete restoration of East Cameron 328 production will require the redrilling of new wells, and this effort is not expected to be complete until 2010. Maritech’s twenty-one primary term leases, along with exploitation opportunities on producing leases, should continue to provide Maritech with additional attractive exploitation 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 flowback pressure, volume testing, and other services for oil and gas producers. The primary testing markets served are in Texas, New Mexico, Colorado, Oklahoma, Arkansas, Louisiana, Pennsylvania, the U.S. Gulf of Mexico, Mexico, 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 industry drilling and completion activities in the markets which the Production Testing segment serves. The Production Testing segment revenues increased 36.4% in 2008 as compared to 2007, primarily due to increased domestic demand. Given the current and expected decreased oil and natural gas price environment, we expect demand for our production testing services will decrease in 2009 compared to 2008. In addition, many of our production testing customers are smaller independent operators, who may be more severely impacted by the current economic uncertainty than larger operators.

Compressco generates revenues and cash flows by performing wellhead compression-based production enhancement services which it markets throughout 14 states that encompass most of the onshore producing regions of the United States, as well as in Canada, Mexico, 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. The Compressco segment’s revenues increased 16.6% in 2008 as compared to 2007 due to increased domestic and international demand for production enhancement services. Though demand for Compressco’s services is also affected by oil and natural gas prices, we anticipate Compressco’s 2009 revenues and cash flows to be impacted less than our other businesses, as we continue to seek new domestic 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 collectibility 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 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 2008 we recorded long-lived asset impairments of $8.7 million. Given the current volatile economic environment, the likelihood of 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 no 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 feel 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.

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 the fourth quarter of 2007 and the third and fourth quarters of 2008 these impairment charges were significant. Maritech 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 plug and abandon the wells, decommission the pipelines and platforms and clear the sites, and 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 six 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. 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 – Effective January 1, 2006, we adopted the fair value recognition provisions of Statement of Financial Accounting Standard (SFAS) 123(R), “Share-Based Payment” (SFAS No. 123R) using the modified prospective transition method. Under the modified prospective transition method, compensation cost recognized includes: (a) compensation cost for all share-based payments granted prior to, but not yet vested as of January 1, 2006, based on the grant date fair value estimated in accordance with the original provisions of SFAS No. 123 (as amended), “Accounting for Share-Based Compensation” (SFAS No. 123) and (b) compensation cost for all share-based payments granted beginning January 1, 2006, based on the grant date fair value estimated in accordance with the provisions of SFAS No. 123R.

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	2008			2007			2006			2008 vs 2007			2007 vs 2006

Revenues		100.0	%		100.0	%		100.0	%		2.7	%		28.0	%
Cost of revenues		84.9	%		88.2	%		67.1	%		(1.0	%)		68.2	%
Gross profit		15.1	%		11.8	%		32.9	%		30.6	%		(54.0	%)
General and administrative expense		10.4	%		10.2	%		12.0	%		5.1	%		8.6	%
Operating income (loss)		0.0	%		1.7	%		20.9	%		(100.1	%)		(89.7	%)

Interest expense		1.7	%		1.8	%		1.8	%		(1.8	%)		31.2	%
Interest income		0.1	%		0.1	%		0.0	%		6.6	%		110.1	%
Other income (expense), net		1.3	%		0.3	%		0.6	%		359.3	%		(42.3	%)
Income (loss) before income taxes
and discontinued operations		(0.4	%)		0.2	%		19.8	%		(281.1	%)		(98.6	%)
Net income (loss) before discontinued operations		(1.0	%)		0.1	%		13.0	%		(890.7	%)		(98.8	%)
Discontinued operations, net of tax		(0.2	%)		2.8	%		0.3	%		(109.0	%)		1278.9	%
Net income (loss)		(1.2	%)		2.9	%		13.3	%		(142.2	%)		(71.8	%)

	Year Ended December 31,
	2008			2007			2006
	(In Thousands)
Revenues

Fluids Division	$	293,248		$	282,074		$	244,549
Offshore Division
Offshore Services		306,362			341,082			298,185
Maritech		208,509			214,154			167,808
Intersegment eliminations		(22,971	)		(29,057	)		(73,859	)
Total		491,900			526,179			392,134
Production Enhancement Division
Production Testing		127,019			93,130			66,526
Compressco		97,417			83,554			65,323
Total		224,436			176,684			131,849
Intersegment eliminations		(519	)		(2,454	)		(737	)
		1,009,065			982,483			767,795

Gross profit

Fluids Division		56,446			38,620			85,712
Offshore Division
Offshore Services		43,025			49,110			64,088
Maritech		(29,958	)		(45,631	)		59,527
Intersegment eliminations		(782	)		6,225			(7,865	)
Total		12,285			9,704			115,750
Production Enhancement Division
Production Testing		44,413			32,813			23,463
Compressco		41,323			36,685			29,050
Total		85,736			69,498			52,513
Other		(2,466	)		(1,439	)		(1,171	)
		152,001			116,383			252,804

	Year Ended December 31,
	2008			2007			2006
	(In Thousands)

Income (loss) before taxes and discontinued operations

Fluids Division		5,401			10,897			60,939
Offshore Division
Offshore Services		3,019			33,496			51,007
Maritech		(31,932	)		(49,815	)		55,105
Intersegment eliminations		(782	)		6,225			(7,865	)
Total		(29,695	)		(10,094	)		98,247
Production Enhancement Division
Production Testing		35,677			25,639			18,308
Compressco		30,310			26,663			20,833
Total		65,987			52,302			39,141
Corporate overhead		(45,608	)		(50,943	)		(45,958	)
		(3,915	)		2,162			152,369

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, we performed an annual test of goodwill impairment in accordance with SFAS No. 142, "Goodwill and Other Intangible Assets." During the fourth quarter of 2008, changes to the global economic environment resulting in uncertain capital markets and reductions in global economic activity have 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 the test of goodwill impairment, we have estimated the fair value of each of our reporting units, and have 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 the prior year, 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 such operations were 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 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 the prior year, 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 the prior year, 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 domestic 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 domestic 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 during 2009.

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 the current year period 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 corresponding prior year period, 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, which was formerly known as our Well Abandonment and Decommissioning (WA&D) Division, decreased during 2008 from $526.2 million during 2007 to $491.9 million during the current year, 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, 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 the year, a majority of which was associated with the overall assessment of the segment’s assets as part of its annual goodwill impairment test pursuant to SFAS No. 142. 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 pursuant to SFAS No. 142. 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. These hedge contracts are at prices significantly above the current market prices being received. 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. Although we anticipate that many of Maritech’s remaining shut-in properties will resume production during early 2009, 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, including certain assets owned by third parties, the timing of which is outside of Maritech’s control. In addition, while Maritech plans to continue to replace its depleting oil and gas reserves through exploitation 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. While Maritech’s insurance costs decreased by $1.2 million during 2008 compared to 2007, we anticipate that insurance costs for offshore oil and gas properties will significantly increase in 2009 following the 2008 hurricanes, resulting in Maritech experiencing reduced gross profit, higher deductibles, lower coverage levels, and potentially self-insuring certain offshore properties.

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 – Beginning in the fourth quarter of 2008, our Production Enhancement Division consists of two separate reporting segments, our Production Testing segment and our Compressco segment. 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 the current year, an increase of $33.9 million or 36.4%. This increase was primarily due to $18.9 million of revenues from increased domestic 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 the current year, an increase of 35.4%. Gross profit as a percentage of revenue decreased slightly, however, from 35.2% during 2007 to 35.0% during the current year. 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 the current year. The majority of this increase occurred domestically, 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 domestic 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 the current year, 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.

2007 Compared to 2006

Consolidated Comparisons

Revenues and Gross Profit – Total consolidated revenues for the year ended December 31, 2007 were $982.5 million compared to $767.8 million for 2006, an increase of 28.0%. Consolidated gross profit decreased to $116.4 million during 2007 compared to $252.8 million in 2006, a decrease of 54.0%. Consolidated gross profit as a percentage of revenue was 11.8% during 2007 compared to 32.9% during

2006. Our profitability during 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 $99.9 million during 2007 compared to $92.0 million during 2006, an increase of $7.9 million or 8.6%. This increase was primarily due to the increased headcount necessary to support our revenue growth and included approximately $6.8 million of increased salary, benefits, contract labor costs, and other associated employee expenses, net of decreased incentive compensation. The increase also included approximately $1.4 million of increased office expenses and approximately $2.3 million of increased insurance and bad debt expenses, which were partially offset by approximately $2.6 million of decreased professional services and other general expenses. General and administrative expenses as a percentage of revenue were 10.2% during 2007 compared to 12.0% during 2006.

Other Income and Expense – Other income and expense was $2.8 million of income during 2007 compared to $4.9 million of income during 2006, due to approximately $2.5 million of decreased gains from sales of assets and approximately $1.2 million of decreased equity from earnings of unconsolidated joint ventures. These decreases were partially offset by approximately $1.6 million of increased other income, primarily due to a $1.2 million legal settlement received during 2007.

Interest Expense and Income Taxes – Net interest expense increased from $13.3 million during 2006 to $17.2 million during 2007 due to increased borrowings of long-term debt used to fund our capital expenditure and acquisition requirements during 2006 and 2007. Interest expense will increase in future periods to the extent additional borrowings are used to fund our acquisition and capital expenditure plans. Our provision for income taxes during 2007 decreased to $0.9 million compared to $52.5 million during 2006, primarily due to decreased earnings.

Net Income – Net income before discontinued operations was $1.2 million during 2007 compared to $99.9 million in 2006, a decrease of $98.7 million. Net income per diluted share before discontinued operations was $0.02 on 75,920,768 average diluted shares outstanding during 2007 compared to $1.33 on 74,823,808 average diluted shares outstanding during 2006.

During the fourth quarter of 2007, we sold our process services operation for approximately $58.7 million, net of certain adjustments, as such operations were 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. Income from discontinued operations was $27.6 million during 2007 compared to $2.0 million during 2006, primarily due to the $25.8 million after tax gain on sale of the process services operations.

Net income was $28.8 million during 2007 compared to $101.9 million in 2006, a decrease of $73.1 million. Net income per diluted share was $0.38 on 75,920,768 average diluted shares outstanding during 2007 compared to $1.36 on 74,823.808 average diluted shares outstanding in 2006.

Divisional Comparisons

Fluids Division – Fluids Division revenues during 2007 were $282.1 million, compared to $244.5 million during 2006, an increase of $37.5 million, or 15.3%. Approximately $20.2 million of this increase was due to increased service activity, particularly for onshore services. In September 2006 and April 2007, the Division completed the acquisitions of certain service assets and operations, expanding the Division’s completion services operations and allowing it to provide such services to customers in the Arkansas, New Mexico, TexOma, and ArkLaTex regions. To a lesser extent, the increased revenues were also due to increased product pricing and international sales of the Division’s chemicals and CBF products. A portion of the demand for the Division’s products and services is affected by the level of drilling activity, particularly deepwater drilling, in the Gulf of Mexico region.

Fluids Division gross profit decreased to $38.6 million during 2007, compared to $85.7 million during 2006, a decrease of $47.1 million or 54.9%. Gross profit as a percentage of revenue decreased to 13.7% during 2007, from 35.0% during 2006. This decrease in gross profit was primarily due to the increased cost of raw materials for the Division’s products, which particularly affected the profitability of the Division’s offshore operations. In addition, weather conditions during much of 2007 negatively impacted the Division’s onshore and completion services operations. A favorable long-term supply for

certain of the Division’s raw material needs has been secured, and, 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 2007 totaled $10.9 million compared to $60.9 million during 2006, a decrease of $50.0 million or 82.1%. This decrease was primarily generated by the $47.1 million decrease in gross profit discussed above, along with approximately $3.6 million of increased administrative expenses, partially offset by approximately $0.9 million of increased other income, primarily from gains from foreign currency and sales of assets.

Offshore Division – Offshore Division revenues increased significantly from $392.1 million during 2006 to $526.2 million during 2007, an increase of $134.0 million or 34.2%. Offshore Division gross profit during 2007 totaled $9.7 million compared to $115.8 million during 2006, a decrease of $106.0 million or 91.6%. Offshore Division loss before taxes was $10.1 million during 2007 compared to $98.2 million of income before taxes during 2006, a decrease of $108.3 million or 110.3%.

The Division’s Offshore Services operations revenues increased to $341.1 million during 2007 compared to $298.2 million in 2006, an increase of $42.9 million or 14.4%. Excluding intercompany work performed for Maritech, Offshore Services revenues increased by $87.7 million, or 39.1%. Approximately $30.7 million of the segment’s revenue increase was as a result of the March 2006 acquisition of the assets and operations of Epic Diving and Marine Services (Epic) and the subsequent expansion and refurbishment of Epic’s dive support vessel fleet, which was completed in early 2007, although one of these dive support vessels was idled during a portion of the year for mechanical problems. Additional segment revenue increases were primarily due to increased vessel activity levels during much of 2007, although the utilization of these vessels was somewhat limited due to weather conditions during the second and third quarters. The September 2007 acquisition of the assets and operations of E.O.T. Rentals, LLC (EOT) also generated approximately $3.4 million of increased revenues for cutting tool services provided to the Division’s customers, and is expected to contribute additional revenues in the future.

The Offshore Services segment of the Division reported a $15.0 million decrease in gross profit, a 23.4% decrease, from $64.1 million during 2006 to $49.1 million during 2007. Offshore Services’ gross profit as a percentage of revenues decreased to 14.4% during 2007 compared to 21.5% during 2006. Despite the increase in revenues, the segment experienced operating inefficiencies caused by weather disruptions and unfavorable contract issues that negatively affected gross profit, particularly during the first three quarters of 2007. In addition, Epic’s refurbished dive service vessels, which were placed into service during the first quarter of 2007, also experienced lower utilization due to weather and maintenance issues, with one of its vessels experiencing significant mechanical problems during most of the third quarter. During 2007, the Offshore Services segment charged approximately $2.0 million to operations related to a contested insurance claim. During 2007, we modified the segment’s approach to providing our services associated with platforms that were damaged or destroyed by the 2005 storms. 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 2006, intercompany profit of $7.9 million was eliminated in consolidation. During 2007, insurance claim collections related to prior year intercompany work performed 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 $51.0 million during 2006 to $33.5 million during 2007, a decrease of $17.5 million or 34.3%. This decrease was due to the $15.0 million decrease in gross profit described above, as well as a $3.8 million increase in administrative expenses due to the Division’s growth, partially offset by increased other income of approximately $1.3 million, primarily from a legal settlement received during 2007.

The Division’s Maritech operations reported revenues of $214.2 million during 2007 compared to $167.8 million during 2006, an increase of $46.3 million, or 27.6%. Increased production volumes generated increased revenues of approximately $57.1 million, primarily from successful exploitation and development activities. During 2007 and 2006, Maritech has expended approximately $165.7 million on exploitation and development activities. In addition, during a portion of the first quarter of 2006, many of Maritech’s producing properties remained shut-in as a result of third quarter 2005 hurricanes. These

revenue increases from increased production were partially offset by approximately $7.9 million of lower realized oil and natural gas prices, including approximately $17.4 million from decreased pricing for Maritech’s natural gas production. Realized natural gas prices during 2006 included the impact of a natural gas swap derivative hedge contract, which resulted in Maritech realizing a price of $10.465/MMBtu throughout 2006 for a portion of its gas production. This derivative contract expired at the end of 2006. During 2007 and early 2008, Maritech entered into several new commodity hedge contracts extending through 2010, including natural gas swap derivative hedge contracts, which resulted in Maritech receiving an average price of $8.13/MMBtu for a portion of its 2007 natural gas production. In addition, during 2007, Maritech recorded approximately $2.9 million less of prospect and other fee revenues compared to the prior year.

The Division’s Maritech operations reported a negative gross profit of $45.6 million during 2007 compared to $59.5 million of positive gross profit during 2006, a decrease of $105.2 million or 176.7%. This decrease occurred despite the segment’s exploitation and development activity, which resulted in the addition of several newly productive wells. Maritech’s gross profit as a percentage of revenues also decreased during the current year to a negative 21.3% compared to a positive 35.5% during the prior year. A large portion of this decrease in Maritech’s gross profit was due to approximately $72.7 million of increased oil and gas property impairments. 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, compared to $3.4 million of impairments during 2006. 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 has also 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 certain offshore platforms which were destroyed by 2005 hurricanes. In addition, Maritech’s gross profit decreased due to the decreased realized commodity prices discussed above, $35.3 million of increased depletion expense, $8.4 million of increased excess decommissioning and abandonment costs, and $1.3 million of increased insurance premiums. During 2007, Maritech also recorded increased dry hole costs of approximately $0.6 million and reflected decreased gains from insurance proceeds compared to 2006 of approximately $7.3 million.

The Division’s Maritech operations reported a loss before taxes of $49.8 million during 2007 compared to $55.1 million of income before taxes during 2006, a $104.9 million decrease. This 190.4% decrease was due to the $105.2 million decrease in gross profit and approximately $2.7 million of decreased gains on sales of properties, partially offset by $3.0 million of decreased administrative costs compared to 2006, primarily due to decreased incentive compensation.

Production Enhancement Division – Production Enhancement Division revenues increased from $131.8 million during 2006 to $176.7 million during 2007, an increase of $44.8 million or 34.0%. Production Enhancement Division gross profit increased from $52.5 million during 2006 to $69.5 million during 2007, an increase of $17.0 million or 32.3%. Income before taxes for the Production Enhancement Division increased from $39.1 million during 2006 to $52.3 million during 2007, an increase of $13.2 million, or 33.6%.

The Division’s Production Testing segment revenues increased from $66.5 million during 2006 to $93.1 million during 2007, an increase of $26.6 million or 40.0%. This increase was primarily due to increased revenues provided by the Beacon Resources, LLC subsidiary (Beacon), which was acquired in February 2006. Increased production testing activity in Mexico and Brazil also contributed to the increased revenues during 2007. In addition, the segment recorded revenues of approximately $0.6 million during 2007 related to an environmental services contract.

Production Testing gross profit increased from $23.5 million during 2006 to $32.8 million during 2007, an increase of $9.4 million, or 39.8%. Gross profit as a percentage of revenues for the Production Testing segment decreased slightly, however, to 35.2% during 2007 compared to 35.3% during 2006, primarily due to increased domestic operating costs. Increased gross profit was primarily provided by the segment’s international operations in Mexico and Brazil.

Production Testing income before taxes increased $7.3 million during 2007 compared to 2006, increasing 40.0% from $18.3 million to $25.6 million. This increase was primarily due to the increased gross profit discussed above, less approximately $1.3 million of increased administrative expense and $0.8 million of decreased other income, primarily from decreased equity earnings in an unconsolidated joint venture and from decreased foreign currency gains.

Compressco revenues increased by approximately $18.2 million compared to the prior year period, from $65.3 million during 2006 to $83.6 million during 2007. This 27.9% increase was due to Compressco’s overall growth both domestically and in Latin America. Compressco continues to add to its compressor fleet to meet the growing demand for its services.

Compressco gross profit during 2007 increased to $36.7 million, a $7.6 million increase compared to the $29.1 million of gross profit during 2006. This 26.3% increase reflected the increased overall activity, particularly in Mexico. As a percentage of revenue, however, gross profit decreased from 44.5% during 2006 to 43.9% during 2007, due to increased domestic operating costs.

Compressco income before income taxes increased from $20.8 million during 2006 to $26.7 million during 2007, a $5.8 million increase, or 28.0%. This increase was primarily due to the $7.6 million of increased gross profit discussed above less approximately $1.8 million of increased administrative costs.

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 increased by $5.0 million from $46.0 million during 2006 to $50.9 million during 2007, primarily due to increased net interest expense of approximately $4.1 million. This increase in corporate interest expense during 2007 was due to the increased outstanding balance of long-term debt, which was used to fund our capital expenditure and acquisition requirements during 2006 and 2007. Corporate general and administrative expenses increased by approximately $0.4 million compared to the prior year, as approximately $0.9 million of increased office expenses and approximately $0.7 million of increased insurance expenses were offset by approximately $1.2 million of decreased personnel related costs, primarily due to decreased incentive compensation recorded during 2007. In addition, during 2007, we reflected approximately $0.3 million of decreased other income.

Liquidity and Capital Resources

Over each of the past three years, we have utilized our operating cash flow and increased our borrowings to aggressively grow our businesses, both through acquisitions as well as through our internal capital expenditure plans. We continue to pursue a long-term growth strategy that further expands our operations through significant internal growth, strategic acquisitions, and the establishment of operations in additional niche oil and gas service markets, both domestically and internationally. In the current global economic market environment, however, these objectives must be balanced with the need to conserve capital, given the current limited availability of debt and equity financing on attractive terms and the potential reduction in operating cash flows. Our most significant ongoing capital expenditure projects include the construction of a new calcium chloride production facility in Arkansas and a new headquarters office building, and these projects are continuing toward their completion during 2009. However, the balance of our planned capital expenditure activity, which is also funded through operating cash flows and our long-term borrowing capacity, is being reviewed carefully in light of current financing constraints. While our operating cash flows are currently reduced primarily due to lower oil and gas prices and the interruption of Maritech production cash flows as a result of the September 2008 hurricanes, we will consider using any operating cash flow generated in excess of our reduced capital expenditure and other investing requirements to reduce the outstanding balance under our credit facility, which is scheduled to mature in mid-2011. Although we continue to consider suitable acquisitions, the current environment may limit acquisitions to those which can be funded through available borrowing capacity, rather than through the issuance of new debt or equity.

Operating Activities – Cash flow generated by operating activities totaled approximately $189.8 million during 2008, compared to $209.0 million during 2007. While the earnings for both years were greatly impacted by certain nonrecurring charges, such charges were generally for impairments and other non-cash charges which did not affect our operating cash flows. However, approximately 94.7% of our

2008 operating cash flow was generated during the first three quarters of the year, and certain factors which affected our fourth quarter operating activities are expected to continue to affect our operations going forward. The significant decline in oil and natural gas prices experienced during the last half of 2008 has directly affected the cash flow of oil and gas operators, including our Maritech subsidiary. Accordingly, the demand for the products and services of many of our businesses has decreased compared to the first half of 2008, which has resulted in decreased operating cash flow. Our future operating cash flow is particularly affected by activity levels in the Gulf of Mexico region of the U.S., which have remained flat over the past several years despite high oil and natural gas prices during this period. Although our consolidated revenues were increased during 2008 compared to 2007, we anticipate overall demand for our products and services to decrease during 2009. We expect the operating cash flow impact from this decreased demand to be partially offset, however, by our efforts during the coming year to decrease our operating and administrative costs, capitalize on the continuing high demand for some of our Offshore Services businesses, and successfully manage the risks associated with the current offshore oil and gas exploration and production environment, including post-hurricane insurance costs, damage repairs, and increased Maritech decommissioning liabilities.

Primarily during the fourth quarter of 2008, we expended approximately $21.9 million net to our interest for repairs of damage caused by Hurricane Ike, which damaged many of Maritech’s offshore platforms, wells and pipelines during the third quarter and toppled and destroyed three of its offshore platforms and one of its inland water production facilities. Hurricane Ike caused lesser damage to certain assets of our Fluids and Offshore Services segments. Of the repair costs incurred, only $13.4 million represented qualifying costs in excess of deductibles and is considered probable of collection pursuant to Maritech’s insurance coverage and is therefore included in accounts receivable as of December 31, 2008. We estimate that remaining storm damage for Maritech’s partially damaged platforms will result in approximately $6 million to $8 million of additional repair work to be done during 2009, and we expect that a majority of these repairs will be reimbursed pursuant to insurance coverage. The timing of the collection of any future insurance reimbursements is beyond our control, however, and we will continue to use a significant amount of our working capital until such reimbursements are received. With regard to Hurricanes Katrina and Rita, which occurred during 2005, a portion of the repair and well intervention costs on the three destroyed offshore platforms was previously expended, was submitted to insurance, and has been reimbursed; however, our insurance underwriters have continued to maintain that costs for certain of the damaged wells do not qualify as covered costs and that certain well intervention and repair costs for qualifying wells are not covered under the policy for that period. In addition, the underwriters have also maintained that there is no additional coverage provided under an endorsement we obtained in August 2005 for the cost of removal of platforms destroyed by the 2005 storms or the repair of other 2005 damage on certain properties in excess of the insured values provided by our property damage policy for that period. In late 2007, we filed a lawsuit against the underwriters, adjuster, and one of our brokers in a further attempt to collect the reimbursement for these well intervention and repair costs incurred as well as future well intervention and debris removal costs to be incurred resulting from the 2005 hurricanes.

Our operating cash flows also continue to be affected by the interruption in Maritech’s oil and gas production due to damaged offshore platforms and pipelines as a result of the 2008 hurricanes. Approximately 32.6% of Maritech’s pre-storm oil production and 17.0% of its natural gas production is currently shut-in. One of the destroyed offshore platforms served the East Cameron 328 field, which produced approximately 24.3% of our pre-storm oil production. In addition, much of Maritech’s daily production is processed through neighboring platforms, pipelines, and processing facilities of other operators and third parties. 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 beyond 2009. Although we anticipate that many of Maritech’s remaining shut-in properties will resume during early 2009, the complete resumption of production from the East Cameron 328 field will require several wells to be redrilled. 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, including certain assets owned by third parties.

Future operating cash flow will continue to be affected by the oil and gas prices received for Maritech’s production. Although a majority of Maritech’s production is currently hedged, during the first half of 2008, pre-hedge prices received for Maritech’s oil and gas production averaged $114.01 and $10.29, respectively. During December 2008, these prices averaged $32.45 and $6.19, respectively. During 2007 and early 2008, following the acquisitions and exploitation and development drilling operations that increased its oil and gas production levels, Maritech entered into additional oil and natural

gas swap derivative transactions, some of which extend through 2010, that are designated to hedge a portion of Maritech’s operating cash flows from risks associated with the fluctuating prices of oil and natural gas. Each of these swap derivative contracts result in Maritech receiving a fixed price for oil and natural gas for hedged production that is in excess of prices currently being received for its unhedged production, mitigating the impact of current low oil and natural gas prices.

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, 2008 totals $244.5 million ($260.0 million undiscounted). During 2008, Maritech’s decommissioning liability increased by approximately $49.0 million primarily due to the January 2008 acquisition of additional properties and due to the third quarter 2008 hurricanes, which toppled three of Maritech’s offshore platforms and one of its inland water production facilities and increased the cost of work to perform on these properties, net of expected insurance recoveries. See below for a further discussion of the estimated costs related to these six toppled offshore platforms. This increase was net of approximately $19.4 million of plugging, abandonment, and decommissioning operations expended during the year on a portion of Maritech’s properties. The cash outflow necessary to extinguish the remainder of Maritech’s decommissioning liability is expected to occur over several years, shortly after the end of each property’s productive life. 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.

Following the 2005 and 2008 hurricanes, Maritech has six offshore platforms and one remaining inland water production facility which have been toppled and destroyed. The estimated cost to perform well intervention, decommissioning, and debris removal efforts on these platforms is particularly imprecise due to the unique nature of the work to be performed. Maritech estimates that future well intervention and abandonment efforts, including costs to remove debris, reconstruct certain destroyed structures, and redrill certain wells associated with these destroyed platforms and production facility, will cost from $140 million to $190 million, net to our interest before any insurance recoveries. Actual costs could greatly exceed these estimates. Maritech incurred well intervention costs related to hurricane damage suffered in 2005, and certain of those costs have not been reimbursed by insurers. We have reviewed the types of remaining estimated well intervention costs to be incurred related to the six toppled platforms, including those costs related to the 2008 storms. Despite our belief that substantially all of these costs qualify for coverage under our insurance policies, any costs that are similar to the costs that have not yet been reimbursed following the 2005 storms are excluded from anticipated insurance recoveries.

Maritech’s estimated decommissioning liabilities are also net of amounts allocable to joint interest owners and any contractual amounts to be paid by the previous owners of the properties. In some cases, the previous owners 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. As of December 31, 2008, Maritech’s total undiscounted decommissioning obligation is approximately $308.7 million and consists of Maritech’s total liability of $260.0 million, plus approximately $48.7 million, which is contractually required to be reimbursed to Maritech pursuant to such contractual arrangements with the previous owners.

Investing Activities – During 2008, we expended approximately $262.1 million of cash for capital expenditures, the largest amount of annual capital expenditures in our history. Approximately $56.6 million of this amount was spent on the construction of a new calcium chloride facility located in El Dorado, Arkansas, which we expect will be completed in the fourth quarter of 2009 at a total cost of approximately $126 million. In addition, we expended approximately $26.7 million during 2008 on the construction of our new corporate headquarters in The Woodlands, Texas, which was completed in February 2009 at a total cost of approximately $43 million. Over the past three years, we have invested approximately $710.6 million of cash for capital expenditures and acquisitions, including approximately $324.0 million, or approximately 45.6%, for the acquisition, exploration, exploitation, and development activities by our Maritech subsidiary to increase its oil and gas reserves and replace its production. In particular, the December 2007 acquisition by Maritech of the Cimarex Properties resulted in the purchase of additional proved reserves and additional prospects for future drilling and development. In addition to its continuing capital expenditure program, Maritech also continues to pursue the purchase of additional

producing oil and gas properties to provide additional exploration, exploitation and development opportunities.

During 2008, our cash capital expenditures totaled approximately $262.1 million and included approximately $99.0 million by our Offshore Division, of which approximately $85.0 million was expended by the Division’s Maritech segment, including approximately $11.4 million for the acquisition of producing properties in January 2008 and approximately $7.5 million for the construction of a new connecting pipeline for its Cimarex Properties. In addition, our Offshore Division expended approximately $14.3 million relating to the Offshore Services segment operations, primarily for vessel and equipment purchases and refurbishments. The Fluids Division reflected approximately $76.5 million of capital expenditures, primarily related to the El Dorado calcium chloride plant project discussed above. The Production Enhancement Division spent approximately $59.1 million, consisting of approximately $33.2 million related to compressor fleet expansion by our Compressco segment, and approximately $25.9 million to replace and enhance a portion of the testing equipment fleet by our Production Testing segment. Corporate capital expenditures were approximately $27.4 million and consisted primarily of the construction costs for our new corporate office building.

Although our investing activities have been extensive during the past several years, beginning in late 2008 our capital expenditure plans have been reviewed carefully in light of the current capital market constraints, as discussed in the Financing Activities section below. 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 now be postponed or cancelled due to the current environment. We plan to expend over $185 million on additional capital additions during 2009, however, approximately $74 million of this amount represents the costs to complete our El Dorado, Arkansas calcium chloride facility and our new corporate headquarters building located in The Woodlands, Texas. We expect to fund our 2009 capital expenditure activity through cash flows from operations and from our bank credit facility. Many of our other capital expenditure plans will be deferred until they can be funded from operating cash flow, without increasing the balance outstanding under our bank credit facility. This restraint on capital expenditure activity may result in a suspension from the aggressive growth strategy we have experienced over the past several years, and in the case of Maritech, may result in negative growth 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 or opportunities to establish operations in additional niche oil and gas service markets, and even in the current environment, this activity is continuing. 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 February 27, 2009, we had an outstanding balance of $119.9 million, and $27.0 million in letters of credit and guarantees against the $300 million revolving credit facility, leaving a net availability of $153.1 million.

Pursuant to the Credit Agreement, the revolving credit facility is scheduled to mature in June 2011, is unsecured, and guaranteed by certain of our material domestic 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. As of December 31, 2008, the weighted average interest rate on the outstanding balance under the credit facility was 3.10%. 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. We were in compliance with all covenants and conditions of our Credit Agreement as of December 31, 2008. 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 $39.5 million equivalent at December 31, 2008) 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 domestic 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, 2008. 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. Current market conditions, however, have made it increasingly difficult to access capital, either debt or

equity, on acceptable terms. Continued instability in the capital markets, as a result of recession or otherwise, may continue to 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. Unless current market conditions improve prior to the dates of these maturities, the replacement of these capital sources at similar or more favorable terms is unlikely. Given the current environment, it may be necessary to utilize our equity to fund our capital needs or issue as consideration in an acquisition transaction, either of which could result in dilution to our common stockholders.

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. As part of our strategic plan, we evaluate opportunities to acquire businesses and assets and intend to consider attractive acquisition opportunities, which may involve the payment of cash or the issuance of debt or equity securities. Such acquisitions may be funded with existing cash balances, funds under our credit facility, or securities issued under our acquisition shelf registration on Form S-4.

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. As of December 31, 2008, the market value of our remaining oil and natural gas swap contracts was approximately $77.1 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 oil and 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. During 2006, 2007 and 2008, we made no purchases of our common stock pursuant to this authorization. We also received $4.8 million, $12.1 million, and $11.4 million during 2008, 2007 and 2006, respectively, from the exercise of stock options by employees.

Contractual Obligations

The table below summarizes our contractual cash obligations as of December 31, 2008:

	Payments Due
	Total		2009		2010			2011		2012		2013		Thereafter
	(In Thousands)
Long-term debt	$	406,840	$	-	$	-		$	191,840	$	-	$	35,000	$	180,000
Interest on debt		106,545		21,115		21,115			18,746		13,419		11,939		20,211
Purchase obligations		222,872		8,622		11,875			11,875		11,875		11,875		166,750
Decommissioning and other
asset retirement obligations(1)		259,970		43,610		103,711	(3)		17,320		6,488		27,390		61,451
Acquisition contingent
consideration		18,308		18,308		-			-		-		-		-
Operating leases		14,155		5,795		3,018			2,175		1,648		859		660
Total contractual
cash obligations(2)	$	1,028,690	$	97,450	$	139,719		$	241,956	$	33,430	$	87,063	$	429,072

(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, 2008.

(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 $4.7 million of liabilities under FASB Interpretation No. 48, “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 $46.3 million of the amounts expected to be paid in 2010 represents well intervention, abandonment, decommissioning, and debris removal related to offshore platforms destroyed in the 2005 and 2008 hurricanes, net of anticipated insurance recoveries. Insurance recoveries pursuant to the 2005 hurricanes are being contested by the insurers, and are not included.

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, 2008 and 2007, 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

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, 2008, we have expended approximately $47.4 million of well intervention work on certain wells associated with two of the three Maritech offshore platforms which were destroyed as a result of Hurricanes Katrina and Rita in 2005. We estimate that future repair and well intervention efforts related to these destroyed platforms, including platform debris removal and other storm related costs, will result in approximately $50 million to $70 million of additional costs. Approximately $28.9 million of the well intervention costs previously expended and submitted to our insurance providers have been reimbursed; however, our insurance underwriters have continued to maintain that well intervention costs for certain of the damaged wells do not qualify as covered costs and that certain well intervention costs for qualifying wells are not covered under the policy. In addition, the underwriters have also maintained that there is no additional coverage provided under an endorsement we obtained in August 2005 for the cost of removal of these platforms or for other damage repairs on certain properties in excess of the insured values provided by our property damage policy. After continuing to provide requested information to the underwriters regarding the damaged wells, and having numerous discussions with the underwriters, brokers, and insurance adjusters, we have yet to receive the requested reimbursement for these contested costs. On November 16, 2007, we filed a lawsuit in the 359th Judicial District Court, 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 are seeking damages for breach of contract and various related claims and a declaration of the extent of coverage of an endorsement to the policy. We cannot predict the outcome of this lawsuit.

We continue to believe that these costs qualify for coverage pursuant to the policy. However, 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 will be received. In addition, we have reversed a portion of our anticipated insurance recoveries previously included in accounts receivable related to certain damage repair costs incurred, as the amount and timing of further reimbursements from our insurance providers are now indeterminable. As a result of the increase to the decommissioning liability, certain capitalized property 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.

If we successfully collect our reimbursement from our insurance providers, such reimbursements will be credited to operations in the period collected. In the event that our actual well intervention costs are more or less than the associated decommissioning liabilities, as adjusted, the difference may be reported in income in the period in which the work is performed.

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. We have reviewed estimated remediation costs prepared by our independent, third-party environmental engineering consultant, based on a detailed environmental study. The estimated remediation costs range from $0.6 million to $1.4 million. Based upon our review and discussions with our third-party consultants, we established a reserve for such remediation costs which is included in other long-term liabilities in the accompanying consolidated balance sheets. As of December 31, 2008 and following the performance of the required remediation activities at the site, the amount of the reserve for these remediation costs, included in current liabilities, is approximately $0.2 million. The reserve will be further adjusted as information develops or conditions change.

We have not been named a potentially responsible party by the EPA or any state environmental agency.

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 and the amendment of a previous supply agreement. Under the amended agreement with the previous supplier, we remained committed to purchase certain volumes of product through 2008. In December 2007, we were released from these further purchases pursuant to an agreement terminating the amended agreement in exchange for our agreement to pay $9.3 million in five installments during 2008 and early 2009. As of December 31, 2008, the aggregate amount of the fixed and determinable portion of the purchase obligation pursuant to our Fluids Division’s supply agreements was approximately $222.9 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, 2008, Maritech’s decommissioning liabilities are net of approximately $48.7 million for such future reimbursements from these previous owners.

In March 2006, we acquired Beacon Resources, LLC (Beacon), a production testing operation, for approximately $15.6 million paid at closing and an additional $0.5 million to be paid, subject to adjustment, over a three year period through March 2009. In addition, the acquisition provides for additional contingent consideration of up to $19.1 million to be paid in March 2009, depending on the average of Beacon’s annual pretax results of operations over the three year period following the closing date through March 2009. We currently anticipate that a payment will be required pursuant to this contingent consideration provision of the agreement, since, as of December 31, 2008, the amount of Beacon’s pretax results of operations (as defined in the agreement) from the date of the acquisition is now in excess of the minimum amount required to generate a payment. Any amount payable pursuant to this contingent consideration provision will be reflected as a liability and added to goodwill as it becomes fixed and determinable at the end of the three year period.

Recently Issued Accounting Pronouncements

In March 2008, the Financial Accounting Standards Board (FASB) published Statement of Financial Accounting Standard (SFAS) No. 161, “Disclosures about Derivative Instruments and Hedging Activities, an amendment of FASB Statement No. 133,” which requires entities to provide greater transparency about (a) how and why an entity uses derivative instruments, (b) how derivative instruments and related hedged items are accounted for under SFAS No. 133 and its related interpretations, and (c) how derivative instruments and related hedged items affect an entity’s financial position, results of operations, and cash flows. SFAS No. 161 is effective for financial statements issued for fiscal years, and interim periods within those fiscal years, beginning after November 15, 2008. We anticipate that the issuance of SFAS No. 161 will not have a significant impact on our financial position or results of operations.

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. SFAS No. 141R changes many aspects of the accounting for business combinations and is expected to significantly impact how we account for and disclose future acquisition transactions. SFAS No. 141R 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.

In December 2007, the FASB published SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements – an amendment of ARB No. 51,” which establishes accounting and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. It clarifies that a noncontrolling interest in a subsidiary is an ownership interest in the consolidated entity that should be reported as equity in the consolidated financial statements. SFAS No. 160 is effective for fiscal years, and interim periods within those fiscal years, beginning on or after December 15, 2008. We are currently evaluating the impact, if any, the adoption of SFAS No. 160 will have on our financial position and results of operations.

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; require companies to report on the independence and qualifications of a reserves preparer or auditor; file reports when a third party is relied upon to prepare reserve estimates or conduct a reserves audit; and 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 are currently assessing the impact that adoption of the new disclosure requirements will have on our disclosures of oil and gas reserves.

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. Based on the balances of floating rate debt outstanding as of December 31, 2008, each increase of 100 basis points in the LIBOR rate would result in a decrease in earnings of approximately $0.6 million.

The following table sets forth, as of December 31, 2008 and 2007, our cash flows for the outstanding principal balances 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, 2008
Long-term debt:
U.S. dollar variable rate	$	-	$	-	$	87,500		$	-	$	-	$	-	$	87,500		$	87,500
Euro variable rate (in $US)		-		-		9,868			-		-		-		9,868			9,868
Weighted average
interest rate		-		-		3.104	%		-		-		-		3.104	%		-
Variable to fixed swaps		-		-		-			-		-		-		-			-
Fixed pay rate		-		-		-			-		-		-		-			-
Variable receive rate		-		-		-			-		-		-		-			-

	Expected Maturity Date																Fair
	2008		2009		2010		2011			2012		Thereafter		Total			Market Value
	(In Thousands, Except Percentages)
As of December 31, 2007
Long-term debt:
U.S. dollar variable rate	$	-	$	-	$	-	$	160,000		$	-	$	-	$	160,000		$	160,000
Euro variable rate (in $US)		-		-		-		11,783			-		-		11,783			11,783
Weighted average
interest rate		-		-		-		5.758	%		-		-		5.758	%		-
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 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, 2008 and 2007, 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
	2009		2010		2011			2012		2013		Thereafter		Total			Market Value
	(In Thousands, Except Percentages)
As of December 31, 2008
Long-term debt:
Euro variable rate (in $US)	$	-	$	-	$	9,868		$	-	$	-	$	-	$	9,868		$	9,868
Euro fixed rate (in $US)		-		-		39,472			-		-		-		39,472			29,414
Weighted average
interest rate		-		-		4.624	%		-		-		-		4.624	%		-
Variable to fixed swaps		-		-		-			-		-		-		-			-
Fixed pay rate		-		-		-			-		-		-		-			-
Variable receive rate		-		-		-			-		-		-		-			-

	Expected Maturity Date																Fair
	2008		2009		2010		2011			2012		Thereafter		Total			Market Value
	(In Thousands, Except Percentages)
As of December 31, 2007
Long-term debt:
Euro variable rate (in $US)	$	-	$	-	$	-	$	11,783		$	-	$	-	$	11,783		$	11,783
Euro fixed rate (in $US)		-		-		-		41,241			-		-		41,241			41,494
Weighted average
interest rate		-		-		-		4.953	%		-		-		4.953	%		-
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 hedges as of December 31, 2008 described below, each $1 per barrel decrease in future crude oil prices would result in a decrease in after tax earnings of $0.3 million. 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 Statement No. 133, “Accounting for Derivative Instruments and Hedging Activities,” 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, 2008 and 2007, 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, 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

December 31, 2007

Oil swaps	3,500 barrels/day	$66.92/barrel	2008
Oil swaps	2,500 barrels/day	$68.86/barrel	2009
Oil swaps	1,000 barrels/day	$70.75/barrel	2010

Natural gas swaps	7,500 MMBtu/day	$8.462/MMBtu	2008

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, respectively. Based upon an average NYMEX strip price over the remaining contract term of $59.18/barrel, the market value of our oil swaps at December 31, 2008 was $41.5 million. A $1 increase in the future price of oil would result in the market value of the combined oil derivative asset decreasing by $1.6 million. Based on an average NYMEX strip price over the remaining contract term of $6.71/MMBtu, the market value of our natural gas swaps 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. The portion of these market values associated with 2009 swap contracts is reflected as a current asset, and the portion related to later periods is reflected as a long-term asset.

The market value of our oil swaps at December 31, 2007 was $53.4 million, which is reflected as a liability. A $1 increase in the future price of oil would have resulted in the market value of the combined oil derivative liability decreasing by $2.4 million. The market value of our natural gas swaps at December 31, 2007 was $1.3 million, which is reflected as a current asset. 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 $0.3 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, 2008, 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, 2008.

An assessment of the effectiveness of our internal control over financial reporting as of December 31, 2008 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, 2008 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, 2009, 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, 2008.

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, 2008 and 2007		F-4
	Consolidated Statements of Operations for the years ended December 31, 2008, 2007, and 2006		F-6
	Consolidated Statements of Stockholders’ Equity for the years ended December 31, 2008, 2007, and 2006		F-7
	Consolidated Statements of Cash Flows for the years ended December 31, 2008, 2007, and 2006		F-8
	Notes to Consolidated Financial Statements		F-9
2.	Financial statement schedules have been omitted as they are not required, are not applicable, or the required information is included in the financial statements or notes thereto.
3.	List of Exhibits
	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)).
	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).

+ 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 2, 2009	By:	/s/ Geoffrey M. Hertel
		Geoffrey M. Hertel, 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 2, 2009
Ralph S. Cunningham	the Board of Directors

/s/Geoffrey M. Hertel	President, Chief Executive	March 2, 2009
Geoffrey M. Hertel	Officer and Director
	(Principal Executive Officer)

/s/Joseph M. Abell	Senior Vice President and	March 2, 2009
Joseph M. Abell	Chief Financial Officer
	(Principal Financial Officer)

/s/Ben C. Chambers	Vice President – Accounting	March 2, 2009
Ben C. Chambers	and Controller
	(Principal Accounting Officer)

/s/Paul D. Coombs	Director	March 2, 2009
Paul D. Coombs

/s/Tom H. Delimitros	Director	March 2, 2009
Tom H. Delimitros

/s/Allen T. McInnes	Director	March 2, 2009
Allen T. McInnes

/s/Kenneth P. Mitchell	Director	March 2, 2009
Kenneth P. Mitchell

/s/William D. Sullivan	Director	March 2, 2009
William D. Sullivan

/s/Kenneth E. White, Jr.	Director	March 2, 2009
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)).
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).

+ 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, 2008 and 2007, and the related consolidated statements of operations, stockholders' equity, and cash flows for each of the three years in the period ended December 31, 2008. 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, 2008 and 2007, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2008, in conformity with U.S. generally accepted accounting principles.

As discussed in Notes B and F to the consolidated financial statements, in 2007, the Company adopted FASB Interpretation No. 48 “Accounting for Uncertainty in Income Taxes.” In addition, as described in Notes B and L to the consolidated financial statements, in 2006 the Company adopted the provisions of Statement of Financial Accounting Standards No. 123 (revised 2004), “Share-Based Payments.”

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, 2008, based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 27, 2009, expressed an unqualified opinion thereon.

/s/ERNST & YOUNG LLP

Houston, Texas

February 27, 2009

F-1

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors and Stockholders of

TETRA Technologies, Inc.

We have audited TETRA Technologies, Inc.’s internal control over financial reporting as of December 31, 2008, 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.’s 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 Report of Management 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. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2008, 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, 2008 and 2007, and the related consolidated statements of operations, stockholders’ equity and cash flows for each of the three years in the period ended December 31, 2008, and our report dated February 27, 2009, expressed an unqualified opinion thereon.

/s/ERNST & YOUNG LLP

Houston, Texas

February 27, 2009

F-2

TETRA Technologies, Inc. and Subsidiaries

Consolidated Balance Sheets

(In Thousands)

	December 31,
	2008			2007
ASSETS
Current assets:
Cash and cash equivalents	$	3,882		$	21,833
Restricted cash		2,150			4,218
Accounts receivable, net of allowance for doubtful accounts
of $3,198 in 2008 and $1,293 in 2007		225,491			215,284
Inventories		117,731			118,502
Deferred tax assets		-			26,247
Derivative assets		38,052			1,299
Prepaid expenses and other current assets		47,768			32,066
Assets of discontinued operations		239			4,042
Total current assets		435,313			423,491

Property, plant and equipment:
Land and building		23,730			21,359
Machinery and equipment		463,788			404,647
Automobiles and trucks		43,047			37,483
Chemical plants		46,121			46,267
Oil and gas producing assets (successful efforts method)		697,754			564,493
Construction in progress		118,103			19,595
		1,392,543			1,093,844
Less accumulated depreciation and depletion		(585,077	)		(397,453	)
Net property, plant and equipment		807,466			696,391

Other assets:
Goodwill		82,525			130,335
Patents, trademarks and other intangible assets, net of
accumulated amortization of $15,611 in 2008 and $14,489 in 2007		16,549			19,884
Derivative assets		39,098			-
Other assets		31,673			25,435
Total other assets		169,845			175,654
	$	1,412,624		$	1,295,536

See Notes to Consolidated Financial Statements

F-3

TETRA Technologies, Inc. and Subsidiaries

Consolidated Balance Sheets

(In Thousands, Except Per Share Amounts)

	December 31,
	2008			2007
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Trade accounts payable	$	84,435		$	108,101
Accrued liabilities		128,033			101,009
Derivative liabilities		-			32,516
Liabilities of discontinued operations		13			424
Total current liabilities		212,481			242,050

Long-term debt, net		406,840			358,024
Deferred income taxes		64,911			46,263
Decommissioning and other asset retirement obligations, net		202,771			162,106
Derivative liabilities		-			20,853
Other liabilities		9,800			18,321
Total long-term and other liabilities		684,322			605,567

Commitments and contingencies

Stockholders' equity:
Common stock, par value $.01 per share; 100,000,000 shares
authorized; 76,841,424 shares issued at December 31, 2008
and 75,921,727 shares issued at December 31, 2007		768			759
Additional paid-in capital		186,318			174,738
Treasury stock, at cost; 1,582,465 shares held at December 31,
2008 and 1,550,962 shares held at December 31, 2007		(8,843	)		(8,405	)
Accumulated other comprehensive income (loss)		42,888			(25,999	)
Retained earnings		294,690			306,826
Total stockholders' equity		515,821			447,919
	$	1,412,624		$	1,295,536

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,
	2008			2007		2006
Revenues:
Product sales	$	447,341		$	457,238	$	388,257
Services and rentals		561,724			525,245		379,538
Total revenues		1,009,065			982,483		767,795

Cost of revenues:
Cost of product sales		282,497			301,731		197,874
Cost of services and rentals		364,275			362,745		232,781
Depreciation, depletion, amortization and accretion		158,893			129,844		80,931
Impairments of long-lived assets		51,399			71,780		3,405
Total cost of revenues		857,064			866,100		514,991
Gross profit		152,001			116,383		252,804

General and administrative expense		104,949			99,871		92,004
Impairment of goodwill		47,073			-		-
Operating income (loss)		(21	)		16,512		160,800

Interest expense, net		16,778			17,155		13,289
Other income, net		12,884			2,805		4,858

Income (loss) before taxes and discontinued operations		(3,915	)		2,162		152,369
Provision for income taxes		5,740			941		52,489

Income (loss) before discontinued operations		(9,655	)		1,221		99,880

Discontinued operations:
Income (loss) from discontinued operations, net of taxes		(2,481	)		1,723		1,998
Gain on disposal of discontinued operations, net of taxes		-			25,827		-
Income (loss) from discontinued operations		(2,481	)		27,550		1,998

Net income (loss)	$	(12,136	)	$	28,771	$	101,878


Basic net income (loss) per common share:
Income (loss) before discontinued operations	$	(0.13	)	$	0.02	$	1.39
Income (loss) from discontinued operations		(0.03	)		0.02		0.03
Gain on disposal of discontinued operations		-			0.35		-
Net income (loss)	$	(0.16	)	$	0.39	$	1.42
Average shares outstanding		74,519			73,573		71,631

Diluted net income (loss) per common share:
Income (loss) before discontinued operations	$	(0.13	)	$	0.02	$	1.33
Income (loss) from discontinued operations		(0.03	)		0.02		0.03
Gain on disposal of discontinued operations		-			0.34		-
Net income (loss)	$	(0.16	)	$	0.38	$	1.36
Average diluted shares outstanding		74,519			75,921		74,824

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 Par		Paid-In		Treasury			Retained			Derivative			Currency			Stockholders'
	Shares	Held		Value		Capital		Stock			Earnings			Instruments			Translation			Equity

Balance at December 31, 2005	69,537,882	2,219,480		$	717	$	121,022	$	(11,657	)	$	176,234		$	(1,124	)	$	(1,045	)	$	284,147

Net income for 2006												101,878									101,878
Translation adjustment, net of taxes of $1,528																		3,037			3,037
Net change in derivative fair value, net of taxes of $5,592															9,440						9,440
Reclassification of derivative fair value into earnings, net of taxes of $3,218															(5,433	)					(5,433	)
Comprehensive income																					108,922
Exercise of common stock options	2,393,546	(273,441	)		22		10,221		1,133												11,376
Stock option expense							3,430														3,430
Tax benefit upon exercise of certain nonqualified and incentive options							12,505														12,505
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

See Notes to Consolidated Financial Statements

F-6

TETRA Technologies, Inc. and Subsidiaries

Consolidated Statements of Cash Flows

(In Thousands)

	Year Ended December 31,
	2008			2007			2006
Operating activities:
Net income (loss)	$	(12,136	)	$	28,771		$	101,878
Reconciliation of net income to cash provided by operating activities:
Depreciation, depletion, amortization and accretion		158,893			129,844			80,931
Impairment of goodwill		47,073			-			-
Impairments of long-lived assets		51,399			71,780			3,405
Provision (benefit) for deferred income taxes		(1,067	)		674			23,152
Stock compensation expense		5,898			4,416			3,430
Provision for doubtful accounts		3,082			1,459			442
Gain on sale of property, plant and equipment		(3,347	)		(4,974	)		(5,031	)
Other non-cash charges and credits		(212	)		26,043			(5,872	)
Excess tax benefit from exercise of stock options		(1,510	)		(13,189	)		(12,505	)
Equity in (earnings) loss of unconsolidated subsidiary		(554	)		1,063			(250	)
Changes in operating assets and liabilities, net of assets acquired:
Accounts receivable		(3,940	)		(5,346	)		(85,596	)
Inventories		(1,397	)		2,626			(41,522	)
Prepaid expenses and other current assets		(18,913	)		(5,152	)		(12,575	)
Trade accounts payable and accrued expenses		(14,058	)		27,936			14,426
Decommissioning liabilities		(19,430	)		(32,919	)		(19,089	)
Operating activities of discontinued operations		3,344			(22,993	)		3,278
Other		(3,314	)		(1,000	)		(721	)
Net cash provided by operating activities		189,811			209,039			47,781

Investing activities:
Purchases of property, plant and equipment		(262,099	)		(276,074	)		(172,415	)
Business combinations, net of cash acquired		-			(14,479	)		(68,651	)
Proceeds from sale of property, plant and equipment		380			2,582			2,454
Other investing activities		264			(2,621	)		(1,145	)
Investing activities of discontinued operations		-			55,414			(2,135	)
Net cash used in investing activities		(261,455	)		(235,178	)		(241,892	)

Financing activities:
Proceeds from long-term debt		182,450			116,930			321,693
Principal payments on long-term debt		(131,428	)		(100,937	)		(148,057	)
Excess tax benefit from exercise of stock options		1,510			13,189			12,505
Proceeds from sale of common stock and exercise of stock options		4,749			12,087			11,377
Net cash provided by financing activities		57,281			41,269			197,518
Effect of exchange rate changes on cash		(3,588	)		1,168			531

Increase (decrease) in cash and cash equivalents		(17,951	)		16,298			3,938
Cash and cash equivalents at beginning of period		21,833			5,535			1,597
Cash and cash equivalents at end of period	$	3,882		$	21,833		$	5,535

Supplemental cash flow information:
Interest paid	$	19,488		$	18,640		$	13,468
Taxes paid		9,420			12,184			24,957

Supplemental disclosure of non-cash investing and financing activities:
Oil and gas properties acquired through assumption of
decommissioning liabilities	$	22,236		$	24,759		$	7,620

Adjustment of fair value of decommissioning liabilities
capitalized (credited) to oil and gas properties	$	32,511		$	71,683		$	6,003

See Notes to Consolidated Financial Statements

F-7

TETRA TECHNOLOGIES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2008

NOTE A — ORGANIZATION AND OPERATIONS

We are an oil and gas services and production company with an integrated calcium chloride and brominated products manufacturing operation that supplies feedstocks to energy markets, as well as to other markets. 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.

NOTE B — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Principles of Consolidation

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

F-8

Use of Estimates

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

Reclassifications

The consolidated financial statements retroactively reflect the effect of certain stock splits of our common stock, which were each effected in the form of a stock dividend to all stockholders of record as of the record dates. In May 2006, we declared a 2-for-1 stock split to all stockholders of record as of May 15, 2006. On May 22, 2006, stockholders received one additional share of common stock for each share held on the record date. Accordingly, all disclosures involving the number of shares of our common stock outstanding, issued or to be issued, such as with our stock options, and all per share amounts, have been retroactively adjusted to reflect the impact of the stock split. See Note K – Capital Stock, for further discussion of this stock split.

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, 2008 and 2007 includes funds related to 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 will remain restricted until such time as the associated plugging and abandonment project is completed, which we expect to occur during the next twelve months. Restricted cash at December 31, 2008 also 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, 2007 includes approximately $3.6 million of escrowed funds associated with the sale of our process services operation, which was transferred to our operating account in December 2008 in accordance with the terms of the purchase and sale agreement.

Financial Instruments

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, 2008 was approximately $195.5 million compared to a carrying amount of approximately $309.5 million. 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 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.

F-9

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. Oil and gas swap contracts result in us receiving a fixed amount per barrel or MMBtu over the term of the contract. The effective portion of the derivative’s gain or loss (i.e., that portion of the derivative’s gain or loss that offsets the corresponding change in the cash flows of the hedged transaction) is initially reported as a component of accumulated other comprehensive income (loss) and will be subsequently reclassified into revenues to match the offsetting impact of commodity prices on the hedged exposure when it affects revenues. The “ineffective” portion of the derivative’s gain or loss is recognized in earnings immediately. See Note O – Hedge Contracts, for further discussion of our oil and gas swap contracts.

We are exposed to fluctuations between the U.S. dollar and the Euro, as well as other foreign currencies, with regard to our foreign operations. In addition, we entered into Euro-denominated debt as a hedge of our net investment in our Euro-based operating activities. The hedge is considered to be effective since the debt balance designated as the hedge is less than or equal to the net investment in the foreign operation.

As a result of our outstanding balance under a variable rate bank credit facility, we 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, 2008 and 2007 are as follows:

	December 31,
	2008		2007
	(In Thousands)

Finished goods	$	85,908	$	89,309
Raw materials		4,106		6,373
Parts and supplies		26,531		21,081
Work in progress		1,186		1,739
Total inventories	$	117,731	$	118,502

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 years

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Certain machinery, equipment and properties are depreciated or depleted based on operating hours or units of production, subject to a minimum amount, because depreciation and depletion occur primarily through use rather than through elapsed time. 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, 2008, 2007, and 2006 was $138.0 million, $118.6 million, and $70.2 million, respectively.

Interest capitalized for the years ended December 31, 2008, 2007, and 2006 was $3.2 million, $1.4 million, and $1.1 million, respectively.

Oil and Gas Properties

Maritech purchases oil and gas properties and assumes the related well abandonment and decommissioning liabilities (referred to as decommissioning liabilities). Maritech also conducts oil and gas exploration, exploitation, and production activities on the acquired properties. 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. Oil and gas producing assets were depleted at an average rate of $4.19, $3.45, and $2.42 per Mcf equivalent for the years ended December 31, 2008, 2007, and 2006, respectively.

Intangible Assets other than Goodwill

Patents, trademarks, and other intangible assets are recorded on the basis of cost and are amortized on a straight-line basis over their estimated useful lives, ranging from 3 to 20 years. During 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). During 2006, as part of the acquisitions consummated during the year, we acquired intangible assets with a fair value of approximately $13.1 million, with estimated useful lives ranging from 3 to 8 years (having a weighted average useful life of 6.29 years). Amortization expense of patents, trademarks, and other intangible assets was $4.5 million, $3.8 million, and $2.8 million for the twelve months ended December 31, 2008, 2007, and 2006, respectively, and is included in operating income. The estimated future annual amortization expense of patents, trademarks, and other intangible assets is $2.7 million for 2009, $2.3 million for 2010, $2.2 million for 2011, $2.1 million for 2012, and $1.8 million for 2013.

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. In accordance with Statement of Financial Accounting Standards (SFAS) No. 142 “Goodwill and Other Intangible Assets”, the goodwill impairment test consists of a two-step accounting test performed on a reporting unit basis. For purposes of this impairment test, the reporting units are our five reporting segments: Fluids, Offshore Services, Maritech, Production Testing, and Compressco. The first step of the impairment test is to compare the estimated fair value of any reporting units that have recorded goodwill with the recorded net book value (including goodwill) of the reporting unit. If the estimated fair value of the reporting unit is higher than the recorded net book value, no impairment is deemed to exist and no further testing is required. If, however, the estimated fair value of the reporting unit is below the recorded net book value, then a second step must be performed to determine the goodwill impairment required, if any. In this second step, the estimated fair value from the

F-11

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. A key component of these fair value determinations is a reconciliation of the sum of these net present value calculations to our market capitalization.

During the fourth quarter of 2008, changes to the global economic environment resulting in uncertain capital markets and reductions in global economic activity have 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 value 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 have 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, including adjustments to equity method investments, property, plant and equipment, certain intangible assets, and the deferred income taxes associated with these assets. 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, 2008, are as follows:

	Fluids			Offshore Services			Maritech		Production Testing		Compressco		Total
	(In Thousands)
Balance as of December 31, 2006	$	21,464		$	19,347		$	-	$	10,364	$	72,107	$	123,282
Goodwill acquired during the year		1,267			3,876			-		-		-		5,143
Foreign currency fluctuations		1,910			-			-		-		-		1,910

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

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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 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 2008, 2007, and 2006, we identified impairments totaling approximately $42.7 million, $71.8 million, and $3.4 million, respectively, net of intercompany eliminations, of the net carrying value of certain Maritech oil and gas properties. The impairments during 2008 were primarily due to the impact of lower oil and natural gas pricing, and were recorded during the third and fourth quarters of 2008. In addition, certain properties were impaired as a result of decreased production volumes or an increase 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. During 2006, a portion of the net carrying value of a certain Maritech property was impaired due to the reversal of anticipated insurance recoveries resulting in increased decommissioning liabilities as a result of contested insurance claims.

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, which was evaluated for impairment as part of the overall assessment of the segment’s assets pursuant to the goodwill impairment requirements under SFAS No. 142 as discussed above.

Decommissioning Liabilities

Related to our acquired interests in oil and gas properties, we estimate the third party fair values (including an estimated profit) to plug and abandon wells, decommission the pipelines and platforms and clear the sites, and we use these estimates to record Maritech’s decommissioning liabilities, net of amounts allocable to joint interest owners, anticipated insurance recoveries, and any amounts contractually agreed to be paid in the future by the previous owners of the properties. In some cases, previous owners of acquired oil and gas properties are contractually obligated to pay Maritech a fixed amount for the future well abandonment and decommissioning work on these properties as such work is performed. As of December 31, 2008 and 2007, our Maritech subsidiary’s decommissioning liabilities are net of approximately $48.7 million and $54.8 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, 2007, and 2006 oil and gas property additions, we assumed net

F-13

decommissioning liabilities having an estimated fair value of approximately $20.2 million, $24.8 million, and $3.0 million, respectively. As a result of decommissioning work performed, we recorded total reductions to the decommissioning liabilities for the years 2008, 2007, and 2006 of $16.5 million, $32.9 million, and $19.1 million, respectively. We made adjustments to increase our decommissioning liabilities during the years 2008, 2007, and 2006 as a result of changes in the timing or amount of future cash flows of approximately $43.1 million, $63.3 million, and $15.9 million, respectively.

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 collectibility 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 natural gas is produced and sold from those wells. Oil and natural 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.

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, 2008 and 2007, we reflected oil and gas balancing receivables of $3.6 million and $3.2 million, respectively, in accounts receivable or other long-term assets and oil and gas balancing payables of $6.4 million and $7.1 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.

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Operating Costs

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

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

Hurricane Repair Costs and Recoveries

During the three year period ended December 31, 2008, we incurred significant damage to certain of our onshore and offshore operating equipment and facilities as a result of hurricanes. During the third quarter of 2008, 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 toppled and/or destroyed. Maritech is the operator for two of the destroyed offshore platforms and the production facility, and owns a 10% working interest in the third offshore platform, which is operated by a third party. In addition, certain of our fluids facilities also suffered damage during the 2008 storms. During the third quarter of 2005, as a result of Hurricanes Katrina and Rita, our Maritech subsidiary suffered varying levels of 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 toppled and/or completely destroyed. The inland water production facility destroyed in 2005 was reconstructed during 2007. The 2005 hurricanes also resulted in the damage or destruction of certain of our fluids facilities, as well as certain of our decommissioning assets, including one of our heavy lift barges.

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 redrilling of destroyed wells. A majority of our damaged facilities and equipment, including our offshore platforms that were only partially damaged, have been repaired. We currently estimate that our share of the remaining repairs to the partially damaged platforms will cost from $6 million to $8 million net to our interest and before insurance recoveries, to be incurred over the next several months. 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, 2008, 2007, and 2006 of $8.5 million, $13.5 million, and $1.5 million, respectively.

With regard to the six offshore platforms and remaining inland water production facility which were destroyed by the 2005 and 2008 hurricanes, we have yet to complete the full assessment of the well intervention, abandonment, decommissioning, and debris removal efforts required. Well intervention and abandonment work has been performed on several of the wells associated with the destroyed platforms from the 2005 hurricanes, at a cost of approximately $47.4 million. Well intervention efforts to date have been performed by our Offshore Services segment. We estimate that future well intervention and abandonment efforts associated with the destroyed platforms and production facility, including efforts to remove debris, reconstruct certain destroyed structures, and redrill certain associated wells, will cost approximately $140 to $190 million net to our interest, before any insurance recoveries. The estimated

F-15

amount of future well intervention, abandonment, decommissioning, and debris removal costs are recorded in the period in which such damage occurred, net of expected insurance recoveries, as part of Maritech’s decommissioning liabilities. During 2008, as a result of the estimated future well intervention, decommissioning, and debris removal work to be performed as a result of Hurricane Ike, we increased Maritech’s decommissioning liabilities by approximately $8.7 million.

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. The cost to construct the platform and redrill these wells will be capitalized as oil and gas properties, net of insurance recoveries.

We maintain customary insurance protection which we believe will cover a majority of the damages incurred as well as the expected cost to reconstruct the destroyed platforms and redrill the associated wells. Such insurance coverage is subject to certain coverage limits, however, and it is possible we could exceed these coverage limits. In addition, related to the 2008 hurricanes, the relevant insurance policies provide for deductibles up to $5 million per hurricane. Damages related to Hurricane Gustav were not significant and we do not expect that the Maritech repair costs associated with Hurricane Gustav will exceed this deductible.

With regard to repair 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. As of December 31, 2008 and 2007, approximately $98.8 million and $93.6 million of 2005 hurricane related costs have been reimbursed to us under our applicable insurance policies. Subsequent to December 31, 2008, we have received an additional $4.4 million of hurricane related reimbursements.

As discussed further in Note J – Commitments and Contingencies, Insurance Litigation, Maritech incurred well intervention costs related to hurricane damage suffered in 2005, and certain of those costs have not been reimbursed by its insurers. Accordingly, in 2007, we reversed $62.9 million of anticipated insurance recoveries as they were deemed to be not probable of collection. This 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 has resulted in increased oil and gas property impairments during 2008 and 2007. See further discussion in Impairment of Long-Lived Assets section, above. We have reviewed the types of estimated well intervention costs to be incurred related to the 2008 hurricanes. Despite our belief that substantially all of these costs in excess of deductibles will qualify for coverage under our current insurance policies, any costs that are similar to the costs that have not been reimbursed following the 2005 storms are excluded from anticipated insurance recoveries. The changes in anticipated insurance recoveries, including recoveries for non-hurricane related claims, during the most recent two year period are as follows:

	Year Ended December 31,
	2008			2007
	(In Thousands)

Beginning balance	$	11,279		$	93,456

Activity in the period:
Storm related expenditures		31,952			14,846
Insurance reimbursements		(9,303	)		(34,124	)
Contested insurance recoveries		(337	)		(62,899	)
Ending balance at December 31	$	33,591		$	11,279

Anticipated insurance recoveries that have been reflected as a reduction of our decommissioning liabilities were $19.5 million at December 31, 2008 and $0 million at December 31, 2007. Anticipated

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insurance recoveries that have been reflected as insurance receivables were $14.1 million at December 31, 2008 and $11.3 million at December 31, 2007. 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 2008, 2007, and 2006, approximately $0.7 million, $3.2 million, and $10.6 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.

Our Maritech subsidiary also incurred damage to one of its offshore platforms during 2004 as a result of Hurricane Ivan, which was further damaged in 2005 by Hurricane Katrina. We received a $5.7 million insurance settlement payment for the full insured value for these property claims, less a deductible, resulting in a credit to earnings of $1.9 million during 2007.

Stock Compensation

Effective January 1, 2006, we adopted the fair value recognition provisions of SFAS No. 123(R), “Share-Based Payment” (SFAS No. 123R) using the modified prospective transition method. The adoption of SFAS No. 123R resulted in stock compensation expense related to stock options and restricted stock for each of the years ended December 31, 2008, 2007, and 2006 of $5.9 million, $4.4 million, and $3.4 million, respectively, which is included in general and administrative expense. For further discussion of our stock option plans see Note L – Equity Based Compensation.

Research and Development

We expense the costs of research and development as they are incurred. Research and development expense for each of the years ended December 31, 2008, 2007, and 2006 was $1.2 million, $1.6 million, and $1.5 million, respectively.

Income Taxes

We account for income taxes in accordance with SFAS No. 109, “Accounting for Income Taxes” (SFAS No. 109). 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. Effective January 1, 2007, we adopted the provisions of Financial Accounting Standards Board (FASB) Interpretation No. 48, “Accounting for Uncertainty in Income Taxes” (FIN No. 48). FIN No. 48 provides guidance on measurement and recognition in accounting for income tax uncertainties and provides related guidance on derecognition, classification, disclosure, interest, and penalties. SFAS No, 109 and FIN No. 48 require us to make certain estimates about our future operations and uncertain tax positions. Changes in state, federal, and foreign tax laws, as well as changes in our financial condition, could affect these estimates. For a further discussion of our income tax provisions, as well as our deferred tax assets and liabilities, see Note F – Income Taxes.

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

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Sweden, the United Kingdom, Norway, Canada, Mexico, and Brazil, respectively. The U.S. dollar is the designated functional currency for all of our other foreign operations. The cumulative translation effects of translating the accounts from the functional currencies into the U.S. dollar at current exchange rates are included as a separate component of stockholders' equity.

Fair Value Measurements

Effective January 1, 2008, we adopted the provisions of SFAS No. 157, “Fair Value Measurements,” which defines fair value, establishes a framework for measuring fair value, and expands disclosures about fair value measurements. SFAS No. 157 applies under other accounting pronouncements that require or permit fair value measurements. SFAS No. 157 establishes a fair value hierarchy and requires disclosure of fair value measurements within that hierarchy.

Under SFAS No. 157, 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.

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, 2008, using the fair value hierarchy as prescribed by SFAS No. 157, is as follows:

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

A summary of fair value measurements utilized on a non-recurring basis, such as the impairment of long-lived assets, including certain oil and gas properties and goodwill, is excluded, as permitted under FASB Staff Position No. 157-2, “Effective Date of FASB Statement No. 157.”

F-18

New Accounting Pronouncements

In March 2008, the FASB published SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities, an amendment of FASB Statement No. 133,” which requires entities to provide greater transparency about (a) how and why an entity uses derivative instruments, (b) how derivative instruments and related hedged items are accounted for under SFAS No. 133 and its related interpretations, and (c) how derivative instruments and related hedged items affect an entity’s financial position, results of operations, and cash flows. SFAS No. 161 is effective for financial statements issued for fiscal years, and interim periods within those fiscal years, beginning after November 15, 2008. We anticipate that the issuance of SFAS No. 161 will not have a significant impact on our financial position or results of operations.

In December 2007, the FASB published SFAS No. 141R, “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. SFAS No. 141R changes many aspects of the accounting for business combinations, and is expected to significantly impact how we account for and disclose future acquisition transactions. SFAS No. 141R 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.

NOTE C — DISCONTINUED OPERATIONS

During the fourth quarter of 2007, we disposed of our process services operations through a sale of the associated assets and operations for total cash proceeds of approximately $58.9 million. Our process services operation provided the technology and services required for the separation and recycling of oily residuals generated from petroleum refining operations. Our process services operation was not considered to be a strategic part of our core business. 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.

During the fourth quarter of 2006, we made the decision to dispose of our fluids and production testing operations in Venezuela, due to several factors, including the country’s changing political climate. Our Venezuelan fluids operation was previously part of our Fluids Division and the production testing operation was previously part of our Production Enhancement Division. A significant majority of the Venezuelan property assets have been sold or transferred to other market locations, and the remaining closure efforts were finalized during 2008.

F-19

We have accounted for our process services business, our Venezuelan fluids and production testing businesses, and our other discontinued businesses as discontinued operations, and have reclassified prior period financial statements to exclude these businesses from continuing operations. A summary of financial information related to our discontinued operations for each of the past three years is as follows:

	Year Ended December 31,
	2008			2007			2006
	(In Thousands)
Revenues
Process services operations	$	-		$	16,145		$	17,073
Venezuelan fluids and production testing operations		-			608			3,570
	$	-		$	16,753		$	20,643

Income (loss), net of taxes
Process services operations, net of taxes of $(226),
$1,182, and $1,719, respectively	$	(424	)	$	1,939		$	2,810
Venezuelan fluids and production testing operations,
net of taxes of $1, $90, and $231, respectively		(1,501	)		(137	)		(915	)
Other discontinued operations		(556	)		(79	)		103
	$	(2,481	)	$	1,723		$	1,998

Gain from disposal
Process services operation, net of taxes of $14,906	$	-		$	25,827		$	-

Total income (loss) from discontinued operations, net of tax
Process services	$	(424	)	$	27,766		$	2,810
Venezuelan fluids and production testing operations		(1,501	)		(137	)		(915	)
Other discontinued operations		(556	)		(79	)		103
	$	(2,481	)	$	27,550		$	1,998

Assets and liabilities of discontinued operations consist of the following as of December 31, 2008 and 2007:

	December 31,
	2008		2007
	(In Thousands)
Current assets
Process services	$	-	$	705
Venezuelan fluids and testing		128		3,146
		128		3,851
Property, plant and equipment, net
Process services		-		-
Venezuelan fluids and testing		-		48
		-		48
Other long-term assets
Process services		-		-
Venezuelan fluids and testing		111		143
		111		143
Total assets
Process services		-		705
Venezuelan fluids and testing		239		3,337
	$	239	$	4,042
Current liabilities
Process services	$	-	$	223
Venezuelan fluids and testing		13		201
Total liabilities	$	13	$	424

F-20

NOTE D — ACQUISITIONS AND DISPOSITIONS

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, and the payment of $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. In February 2009, Maritech sold an additional property in which the buyer assumed approximately $2.5 million of Maritech’s associated decommissioning liabilities. 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 expands our Fluids Division’s existing 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, with up to an additional $2.5 million to be paid over the next two years, depending on the level of revenues generated by the acquired assets. In January 2009, this contingent consideration provision was eliminated pursuant to a settlement with the seller. 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. The acquisition of EOT’s assets is a strategic expansion of our Offshore Services segment which, in the past, has contracted cutting services from third parties, including EOT, in order to provide such services to its customers. 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 to be paid at prescribed dates over the next 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 (which we refer to as 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 properties include development prospects and strategic opportunities involving a portion of Maritech’s existing infrastructure assets, and other assets to be constructed by Maritech. The acquired oil and gas properties were recorded at a cost of approximately $84.8 million.

In December 2007, we sold our process services business for cash. For further discussion, see Note C – Discontinued Operations.

F-21

In February 2006, our Offshore Services segment purchased a heavy lift derrick barge with a 615-ton capacity crane, the DB-1, from Offshore Specialty Fabricators, Inc. for $20 million. Subsequently, we made a number of modifications to the vessel, which began operating in the Gulf of Mexico in July 2006. The purchase further expanded our Offshore Services segment’s decommissioning operations in the Gulf of Mexico.

In March 2006, our Offshore Services segment acquired the assets and operations of Epic Divers, Inc. and certain associated affiliated companies (Epic), a full service commercial diving operation that included six marine vessels and two saturation diving units. Pursuant to the asset purchase agreement (the Epic Asset Purchase Agreement), we acquired Epic for consideration consisting of approximately $47.7 million of cash paid at closing. In addition, the Epic Asset Purchase Agreement provided for us to pay an additional $0.5 million, which was paid in June 2006, as well as a working capital adjustment of approximately $2.6 million, which was paid in September 2006. In addition, we accrued approximately $0.8 million of additional purchase price adjustments, which we paid to the sellers during 2007. On June 7, 2006, we purchased a dynamically positioned dive support vessel, including a saturation diving unit, for an initial purchase price of approximately $6.5 million. 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 is to be paid to the sellers. We currently anticipate that a payment will be required during 2009 pursuant to this contingent consideration provision of the agreement due to the high utilization of the acquired dive support vessel following the 2008 hurricanes. Any amount payable pursuant to this contingent consideration provision will be reflected as a liability and added to goodwill as it becomes fixed and determinable at the end of the three year period. In addition, approximately $1.6 million, subject to adjustment, of additional purchase consideration is to be paid to the sellers at the end of this three year term. We allocated the purchase price of the Epic acquisition to the fair value of the assets and liabilities acquired, which consisted of approximately $13.8 million of net working capital; $17.6 million of property, plant and equipment; $8.9 million of certain intangible assets; and $12.6 million of goodwill. Intangible assets other than goodwill are amortized over their useful lives, ranging from three to eight years.

In March 2006, we acquired Beacon Resources, LLC (Beacon), a production testing operation, as part of our Production Enhancement Division. The acquisition of Beacon expanded the Division’s production testing services operation into the west Texas and eastern New Mexico markets. We acquired Beacon for approximately $15.6 million paid at closing, with an additional $0.5 million to be paid, subject to adjustment, over a three year period ending in March 2009. In addition, the acquisition provides for additional contingent consideration of up to $19.1 million, to be paid in March 2009, depending on Beacon’s average pretax results of operations for each of the three years following the closing date. We currently anticipate that a payment will be required during 2009 pursuant to this contingent consideration provision of the agreement, since as of December 31, 2008, the amount of Beacon’s pretax results of operations (as defined in the agreement) from the date of the acquisition is now in excess of the minimum amount required to generate a payment. Any amount payable pursuant to this contingent consideration provision will be reflected as a liability and added to goodwill as it becomes fixed and determinable at the end of the three year period. We allocated the purchase price of the Beacon acquisition to the fair value of the assets and liabilities acquired, which consisted of approximately $1.5 million of net working capital; $5.3 million of property, plant and equipment; $4.2 million of certain intangible assets; $0.4 million of other liabilities; and $5.5 million of goodwill. Intangible assets other than goodwill are amortized over their useful lives ranging from five to eight years.

In March 2006, Maritech exercised a contractual right to acquire certain overriding royalty interests related to one of its oil and gas properties in exchange for $5.0 million in cash and a $5.0 million reduction in the amount to be paid to Maritech by the seller upon performance of certain future well abandonment and decommissioning work. Maritech had previously entered into a development agreement with a third party covering the development of this oil and gas property, and, pursuant to this agreement, received $5.0 million cash during March 2006. In March, June, and November 2006, Maritech sold certain oil and gas property assets in four separate transactions in exchange for the buyer’s assumption of the associated decommissioning liabilities, resulting in combined gains totaling approximately $5.1 million.

F-22

In September 2006, we acquired the assets and operations of Arrowhead Oil Field Services, Inc. (Arrowhead), an onshore water transfer company specializing in the transfer of high volumes of water in support of high pressure fracturing processes, as an expansion of our Fluids Division. The acquisition of Arrowhead allows our Fluids Division to expand its capacity for such services to customers in the Texas, Oklahoma, Arkansas, New Mexico, and Louisiana markets. We acquired Arrowhead for approximately $6.5 million of cash paid at closing. We allocated the purchase price of the Arrowhead acquisition to the fair value of the assets acquired, which consisted of approximately $2.3 million of property, plant and equipment; $3.3 million of certain intangible assets; and $0.9 million of goodwill. Intangible assets other than goodwill are amortized over their useful lives, ranging from three to eight years.

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. 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.

As of December 31, 2008, we had no significant capital leases outstanding. Future minimum lease payments by year and in the aggregate, under non-cancelable operating leases with terms of one year or more, consist of the following at December 31, 2008:

	Operating Leases
	(In Thousands)

2009	$	5,795
2010		3,018
2011		2,175
2012		1,648
2013		859
After 2013		660
Total minimum lease payments	$	14,155

Rental expense for all operating leases was $13.3 million, $12.8 million, and $12.0 million in 2008, 2007, and 2006, respectively.

F-23

NOTE F — INCOME TAXES

The income tax provision attributable to continuing operations for the years ended December 31, 2008, 2007, and 2006 consists of the following:

	Year Ended December 31,
	2008			2007			2006
	(In Thousands)
Current
Federal	$	(4,840	)	$	(2,319	)	$	24,133
State		5,156			(1,255	)		747
Foreign		6,491			3,841			4,457
		6,807			267			29,337
Deferred
Federal		794			1,325			20,407
State		(1,204	)		1,257			1,939
Foreign		(657	)		(1,908	)		806
		(1,067	)		674			23,152
Total tax provision	$	5,740		$	941		$	52,489

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, 2008, 2007, and 2006 to income before income taxes and the reported income taxes, is as follows:

	Year Ended December 31,
	2008			2007			2006
	(In Thousands)
Income tax provision (benefit) computed at statutory federal income tax rates	$	(1,370	)	$	757		$	53,330
State income taxes (net of federal benefit)		2,568			(84	)		1,746
Nondeductible expenses		4,281			1,320			1,052
Impact of international operations		1,248			(1,045	)		(1,145	)
Excess depletion		(239	)		(279	)		(698	)
Tax credits		(538	)		(171	)		(467	)
Other		(210	)		443			(1,329	)
Total tax provision	$	5,740		$	941		$	52,489

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

	Year Ended December 31,
	2008			2007			2006
	(In Thousands)

Domestic	$	(11,054	)	$	(8,432	)	$	134,241
International		7,139			10,594			18,128
Total	$	(3,915	)	$	2,162		$	152,369

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 2002.

We adopted the provisions of FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes” (FIN No. 48), on January 1, 2007. FIN No. 48 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 FIN No. 48, 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.

F-24

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

	Year Ended December 31,
	2008			2007
	(In Thousands)

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

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

We recognize interest and penalties related to uncertain tax positions in income tax expense. During the years ended December 31, 2008, 2007, and 2006, we recognized approximately $0.3 million, $0.6 million, and $0.4 million, respectively, in interest and penalties in provision for income tax. As of December 31, 2008 and 2007, we had approximately $2.5 million and $2.8 million, respectively, of accrued potential interest and penalties associated with these uncertain tax positions. The total amount of unrecognized tax benefits that would affect our effective tax rate if recognized is $2.2 million and $2.6 million as of December 31, 2008 and 2007, respectively.

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, 2008 and 2007 are as follows:

Deferred Tax Assets:
	December 31,
	2008			2007
	(In Thousands)

Accruals	$	99,357		$	101,163
Goodwill		7,528			-
All other		23,299			19,043
Total deferred tax assets		130,184			120,206
Valuation allowance		(3,337	)		(2,167	)
Net deferred tax assets	$	126,847		$	118,039

Deferred Tax Liabilities:
	December 31,
	2008		2007
	(In Thousands)
Excess book over tax basis in
property, plant and equipment	$	148,684	$	125,777
Unrealized gains on derivatives		28,700		-
All other		15,557		12,278
Total deferred tax liability		192,941		138,055
Net deferred tax liability	$	66,094	$	20,016

F-25

The change in the valuation allowance during 2008 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, 2008, we had approximately $3.7 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 2009 through 2028. At December 31, 2008, we had approximately $1.3 million of foreign tax credits available to offset future payment of federal income taxes. The foreign tax credits expire in varying amounts through 2017.

NOTE G — ACCRUED LIABILITIES

Accrued liabilities are detailed as follows:

	December 31,
	2008		2007
	(In Thousands)

Decommissioning liabilities, current portion	$	45,954	$	37,400
Taxes payable		7,280		3,942
Deferred tax liability		2,882		-
Oil and gas drilling advances		11,283		2,966
Compensation and employee benefits		17,280		18,290
Oil and gas producing liabilities		16,396		15,435
Accrued inventory supply settlement		1,747		9,250
Other accrued liabilities		25,211		13,726
	$	128,033	$	101,009

NOTE H — LONG-TERM DEBT AND OTHER BORROWINGS

Long-term debt consists of the following:

	December 31,
	2008		2007
	(In Thousands)

Bank revolving line of credit facility	$	97,368	$	171,783
5.07% Senior Notes, Series 2004-A		55,000		55,000
4.79% Senior Notes, Series 2004-B		39,472		41,241
5.90% Senior Notes, Series 2006-A		90,000		90,000
6.30% Senior Notes, Series 2008-A		35,000		-
6.56% Senior Notes, Series 2008-B		90,000		-
European credit facility		-		-
		406,840		358,024
Less current portion		-		-

Total long-term debt	$	406,840	$	358,024

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

	Year Ending
	December 31,
	(In Thousands)

2009	$	-
2010		-
2011		191,840
2012		-
2013		35,000
Thereafter		180,000

	$	406,840

F-26

Bank Credit Facilities

In September 2004, we entered into a five year $140 million revolving credit facility with a syndication of banks. We used the initial borrowings under this facility to repay all outstanding obligations under our previous credit facility, and terminated the previous credit facility. The $140 million revolving credit facility was unsecured and was guaranteed by certain of our domestic subsidiaries. Borrowings generally bore interest at LIBOR plus 0.75% to 1.75%, depending on a certain financial ratio, and we paid a commitment fee on unused portions of the facility at a rate from 0.20% to 0.375%, also depending on this financial ratio. The credit facility contained customary covenants and other restrictions, including dollar limits on the amount of our capital expenditures, acquisitions, and asset sales.

In January 2006, we amended our revolving credit facility agreement to increase the facility up to $200 million, thus increasing our availability under the facility by $60 million. During the first quarter of 2006, we borrowed approximately $101.4 million under our bank revolving credit facility, primarily to fund certain first quarter 2006 acquisitions.

In June 2006, we entered into a bank credit agreement (the Credit Agreement), which amended and restated our existing credit facility to, among other things, extend the maturity date of the five year $200 million facility from September 7, 2009 to June 27, 2011 and provide for a future expansion of the facility, with the agreement of existing or additional lenders, to a maximum of $300 million. In December 2006, we amended the revolving credit facility to increase the facility to the maximum $300 million. The facility remains unsecured and is guaranteed by our material domestic 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, 2008, the weighted average interest rate on the outstanding balance under the credit facility was 3.10%.

The Credit Agreement contains customary covenants and other restrictions, including certain financial ratio covenants that were modified from the previous credit facility agreement. In addition, the Credit Agreement also eliminates the previous limitations on aggregate asset sales and capital expenditures. 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, 2008. 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.

During the first quarter of 2007, we entered into 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 $7.0 million equivalent as of December 31, 2008), 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, 2008, we had no borrowings pursuant to the European Credit Agreement.

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 $39.5 million equivalent at December 31, 2008) 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.

F-27

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 domestic 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, 2008. 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

We account for asset retirement obligations in accordance with SFAS No. 143, “Accounting for Asset Retirement Obligations.” The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. The large majority of these asset retirement costs 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 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. These fair value amounts have been capitalized as part of the cost basis of these assets. 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 market risk premium for a significant majority of the asset retirement obligations is considered small, relative to the related estimated cash flows, and has not been used in the calculation of asset retirement obligations.

F-28

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

	Year Ended December 31,
	2008			2007
	(In Thousands)

Beginning balance for the period, as reported	$	199,506		$	138,340

Activity in the period:
Accretion of liability		7,084			7,044
Retirement obligations incurred		20,274			27,204
Revisions in estimated cash flows		43,034			63,364
Settlement of retirement obligations		(21,173	)		(36,446	)

Ending balance at December 31	$	248,725		$	199,506

A significant portion of the revisions in estimated cash flows relate to well intervention, abandonment, decommissioning, and debris removal associated with destroyed Maritech offshore platforms. Such revisions in estimated cash flows during 2007 were as a result of the reversal of anticipated insurance recoveries which are being contested by our insurer.

NOTE J — COMMITMENTS AND CONTINGENCIES

Litigation

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

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 actions, 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 case has been stayed by agreement of the parties pending the Court’s ruling on our motion to dismiss the federal class action.

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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.

Insurance Litigation - Through December 31, 2008, we have expended approximately $47.4 million of well intervention work on certain wells associated with the three Maritech offshore platforms which were destroyed as a result of Hurricanes Katrina and Rita in 2005. We estimate that future repair and well intervention efforts related to these destroyed platforms, including platform debris removal and other storm related costs, will result in approximately $50 million to $70 million of additional costs. Approximately $28.9 million of the well intervention costs previously expended and submitted to our insurance providers have been reimbursed; however, our insurance underwriters have continued to maintain that well intervention costs for certain of the damaged wells do not qualify as covered costs and that certain well intervention costs for qualifying wells are not covered under the policy. In addition, the underwriters have also maintained that there is no additional coverage provided under an endorsement we obtained in August 2005 for the cost of removal of these platforms or for other damage repairs on certain properties in excess of the insured values provided by our property damage policy. After continuing to provide requested information to the underwriters regarding the damaged wells, and having numerous discussions with the underwriters, brokers, and insurance adjusters, we have not received the requested reimbursement for these contested costs. On November 16, 2007, we filed a lawsuit in the 359th Judicial District Court, 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 are seeking damages for breach of contract and various related claims and a declaration of the extent of coverage of an endorsement to the policy. We cannot predict the outcome of this 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. We have reviewed estimated remediation costs prepared by our independent, third-party environmental engineering consultant, based on a detailed environmental study. Based upon our review and discussions with our third-party consultants, we established a reserve for such remediation costs. As of December 31, 2008, and following the performance of the required remediation activities at the site, the amount of the reserve for these remediation costs, included in current liabilities, is approximately $0.2 million. The reserve will be further adjusted as information develops or conditions change.

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We have not been named a potentially responsible party by the EPA or any state environmental agency.

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, and the amendment of a previous supply agreement. Under the amended agreement with the previous supplier, we remained committed to purchase certain volumes of product through 2008. In December 2007, we were released from these further purchase obligations pursuant to an agreement terminating the amended agreement in exchange for our agreement to pay $9.3 million, which was charged to earnings during 2007 and which will be paid in five installments during 2008 and early 2009. As of December 31, 2008, the aggregate amount of the fixed and determinable portion of the purchase obligation pursuant to our Fluids Division’s supply agreements was approximately $222.9 million, including $8.6 million during 2009, $11.9 million during 2010, $11.9 million during 2011, $11.9 million during 2012, $11.9 million during 2013, and $166.8 million thereafter, extending through 2029. Amounts purchased under these agreements for each of the years ended December 31, 2008, 2007, and 2006 was $19.2 million, $16.7 million, and $1.0 million, respectively.

NOTE K — CAPITAL STOCK

Our Restated Certificate of Incorporation authorizes us to issue 100,000,000 shares of common stock, par value $.01 per share, and 5,000,000 shares of preferred stock, par value $.01 per share. As of December 31, 2008, we had 75,258,959 shares of common stock outstanding, with 1,582,465 shares held in treasury, and no shares of preferred stock outstanding. The voting, dividend, and liquidation rights of the holders of common stock are subject to the rights of the holders of preferred stock. The holders of common stock are entitled to one vote for each share held. There is no cumulative voting. Dividends may be declared and paid on common stock as determined by our Board of Directors, subject to any preferential dividend rights of any then outstanding preferred stock.

Our Board of Directors is empowered, without approval of the stockholders, to cause shares of preferred stock to be issued in one or more series and to establish the number of shares to be included in each such series and the rights, powers, preferences and limitations of each series. Because the Board of Directors has the power to establish the preferences and rights of each series, it may afford the holders of any series of preferred stock preferences, powers and rights, voting or otherwise, senior to the rights of holders of 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, 2008, we made no purchases of our common stock pursuant to this authorization.

In May 2006, we declared a 2-for-1 stock split, which was effected in the form of a stock dividend. Stockholders of record as of May 16, 2006 (the Record Date), received additional shares of our common stock, with fractional shares paid in cash based on the closing price per share of the common stock as of the Record Date. This stock split resulted in the May 22, 2006 issuance of 36,740,501 additional shares outstanding. The consolidated financial statements retroactively reflect the effect of this stock split and, accordingly, all disclosures involving the number of shares of common stock outstanding, issued or to be issued, and all per share amounts, retroactively reflect the impact of the stock split.

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NOTE L — EQUITY-BASED COMPENSATION

Effective January 1, 2006, we adopted the fair value recognition provisions of SFAS No. 123(R), “Share-Based Payment” (SFAS No. 123R) using the modified prospective transition method. In addition, the SEC issued Staff Accounting Bulletin No. 107, “Share-Based Payment” (SAB No. 107) in March, 2005, which provides supplemental SFAS No. 123R application guidance based on the views of the SEC. Under the modified prospective transition method, compensation cost recognized during the three years ended December 31, 2008 includes: (a) compensation cost for all share-based payments granted prior to, but not yet vested as of January 1, 2006, based on the grant date fair value estimated in accordance with the original provisions of SFAS No. 123 (as amended), “Accounting for Share-Based Compensation” (SFAS No. 123), and (b) compensation cost for all share-based payments granted beginning January 1, 2006, based on the grant date fair value estimated in accordance with the provisions of SFAS No. 123R. In accordance with the modified prospective transition method, results for prior periods have not been restated.

The adoption of SFAS No. 123R resulted in stock compensation expense related to stock options and restricted stock for the three years ended December 31, 2008 of $5.9 million, $4.4 million and $3.4 million, respectively, which is included in general and administrative expense. This expense reduced net income by $3.7 million, $2.8 million and $2.2 million and reduced basic and diluted earnings per share by $0.05, $0.04 and $0.03, respectively, for the three years ended December 31, 2008.

The Black-Scholes option-pricing model was used to estimate the option fair values. The 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, 2008 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, 2008 for the expected option term.

Prior to the adoption of SFAS No. 123R, we presented any tax benefits of deductions resulting from the exercise of stock options within operating cash flows in our consolidated statements of cash flows. SFAS No. 123R requires tax benefits resulting from tax deductions in excess of the compensation cost recognized for those options (excess tax benefits) to be classified and reported as a financing cash inflow upon adoption of SFAS No. 123R.

In November 2005, the FASB issued Staff Position No. FAS 123(R)-3, “Transition Election Related to Accounting for the Tax Effects of Share-Based Payment Awards” (FSP 123R-3). We have elected to adopt the alternative transition method provided in FSP 123R-3 for calculating the tax effects of stock-based compensation under SFAS No. 123 R. The alternative transition method includes simplified methods to establish the beginning balance of the additional paid-in capital pool (APIC Pool) related to the tax effects of stock-based compensation, and for determining the subsequent impact on the APIC Pool and consolidated statements of cash flows of the tax effects of stock-based compensation awards that are outstanding upon adoption of SFAS No. 123R.

Equity-Based Compensation as of December 31, 2008

We have various stock option plans which provide for the granting of options for the purchase of our common stock and other performance-based awards to our executive officers, key employees, nonexecutive officers, consultants, and directors. Incentive stock options are exercisable for periods up to ten years.

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.

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

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

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 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.

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.

During each of the three years ended December 31, 2008, we granted to certain officers and employees restricted shares, which generally vest 20% per year over a five year period. 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. During 2006, we granted a total of 83,708 restricted shares, having an average market value of $29.47 per share, or an aggregate market value of approximately $2.5 million at the date of grant.

The following is a summary of stock option activity for the year ended December 31, 2008:

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

Outstanding at December 31, 2007		4,189		$	11.45

Options granted		1,508			20.92
Options cancelled		(358	)		20.23
Options exercised		(749	)		5.82
Outstanding at December 31, 2008		4,590		$	14.80

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The following is a summary of restricted stock activity for the year ended December 31, 2008:

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

Nonvested shares outstanding at December 31, 2007		287		$	27.98

Shares granted		216			19.51
Shares cancelled		(42	)		26.34
Shares vested		(109	)		26.57
Nonvested shares outstanding at December 31, 2008		352		$	23.39

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, 2008 was approximately $5.3 million, $43.2 million and $41.0 million, respectively. Cash received from stock options exercised during the three years ended December 31, 2008 was $4.7 million, $12.1 million and $11.4 million, respectively. Recognized excess tax benefits related to the exercise of stock options during the three years ended December 31, 2008 were $1.5 million, $13.2 million and $12.5 million, respectively.

Stock options authorized for issuance, outstanding and currently exercisable at December 31, 2008, 2007, and 2006 are as follows:

	2008		2007		2006
	(In Thousands, Except Per Share Amounts)
TETRA Technologies, Inc. 2007 Equity Incentive Compensation Plan
Maximum number of shares authorized for issuance		4,590		90		-
Shares reserved for future grants		2,908		63		-
Options exercisable at period end		6		6		-
Weighted average exercise price of options exercisable
at period end	$	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		589
Options exercisable at period end		320		257		-
Weighted average exercise price of options exercisable
at period end	$	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		1,395		1,955		3,297
Weighted average exercise price of options exercisable
at period end	$	7.09	$	6.52	$	6.05

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		297		342		770
Weighted average exercise price of options exercisable
at period end	$	12.09	$	11.74	$	8.30

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		842		936		904
Weighted average exercise price of options exercisable
at period end	$	13.85	$	12.13	$	8.74

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The following is a summary of options outstanding and options exercisable as of December 31, 2008:

		Options Outstanding						Options Exercisable
Range of Exercise Price		Shares		Weighted Average Remaining Contracted Life		Weighted Average Exercise Price		Shares		Weighted Average Remaining Contracted Life		Weighted Average Exercise Price
		(In Thousands)		(In Years)				(In Thousands)		(In Years)
	$1.61 to $4.37		600		3.0	$	3.57		590		2.9	$	3.56
	$4.38 to $8.11		255		3.2	$	5.83		249		3.1	$	5.89
	$8.12 to $9.21		1,254		3.9	$	9.09		1,242		3.9	$	9.09
	$9.22 to $20.85		450		6.9	$	12.62		378		6.7	$	13.70
	$20.86 to $30.00		2,031		8.7	$	22.90		402		7.5	$	26.12
			4,590		6.2	$	14.80		2,861		4.5	$	10.67

The intrinsic value of options outstanding as of December 31, 2008 was $3.6 million, and the intrinsic value of options exercisable as of December 31, 2008 was 2.9 million.

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: expected stock price volatility 31% to 37%, expected life of options 4.4 to 5.4 years, risk-free interest rate 1.5% to 5.0%, and no expected dividend yield. The weighted average fair value of options granted during the years ended December 31, 2008, 2007 and 2006, using the Black-Scholes model, was $7.61, $7.74, and $8.17 per share, respectively. Total estimated unrecognized compensation cost from unvested stock options and restricted stock as of December 31, 2008 was approximately $19.9 million, which is expected to be recognized over a weighted average period of approximately 3.4 years.

Certain options exercised during 2008, 2007, and 2006 were exercised through the surrender of 26,304, 4,655, and 15,559 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, we received 8,119 and 27,784 shares, respectively, of our common stock during 2008 and 2007 related to the vesting of certain employee restricted stock. Such surrendered shares received by us are included in treasury stock. At December 31, 2008, net of options previously exercised pursuant to our various stock option plans, we have a maximum of 7,849,668 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. However, beginning in February 2009, we have suspended matching employee contributions. In addition, we can make discretionary contributions which are allocable to participants in accordance with the Plan. Total expense related to our 401(k) plan was $3.3 million, $2.7 million, and $2.0 million in 2008, 2007, and 2006, respectively.

NOTE N — DEFERRED COMPENSATION PLAN

We provide our officers, directors and certain key employees with the opportunity to participate in an unfunded, deferred compensation program. There were thirty-two participants in the program at December 31, 2008. 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

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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, 2008, the amounts payable under the plan approximated the value of the corresponding assets we owned.

NOTE O — HEDGE CONTRACTS

We have market risk exposure in the sales prices we receive for our oil and gas production and 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. 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. Under SFAS No. 133, as amended by SFAS Nos. 137 and 138, all derivative instruments are required to be recognized on the balance sheet at their fair value, and criteria must be established to determine the effectiveness of the hedging relationship. Hedging activities may include hedges of fair value exposures, hedges of cash flow exposures, and hedges of a net investment in a foreign operation. A fair value hedge requires that the effective portion of the change in the fair value of a derivative instrument be offset against the change in the fair value of the underlying asset, liability, or firm commitment being hedged through earnings. Hedges of cash flow exposure are undertaken to hedge a forecasted transaction or the variability of cash flows to be received or paid related to a recognized asset or liability. A cash flow hedge requires that the effective portion of the change in the fair value of a derivative instrument be recognized in other comprehensive income, a component of stockholders’ equity, and then be reclassified into earnings in the period or periods during which the hedged transaction affects earnings. 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. Any ineffective portion of a derivative instrument’s change in fair value is immediately recognized in earnings.

As required by SFAS No. 133, 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.

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.

We believe that our swap and collar agreements are “highly effective cash flow hedges,” as defined by SFAS No. 133, 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 (loss) and will be subsequently reclassified into product sales revenues utilizing the specific identification method when the hedged exposure affects earnings (i.e., when hedged oil and gas production volumes are reflected in revenues). Any “ineffective” portion of the change in the derivative’s fair value is recognized in earnings immediately.

During the years ended December 31, 2008, 2007, and 2006, we entered into certain cash flow hedging swap and collar contracts to fix cash flows relating to a portion of our oil and gas production.

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Each of these contracts qualified for hedge accounting. However, 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 pursuant to SFAS No. 133. 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. For the three year period ended December 31, 2008, we recorded approximately $8.6 million, $0.2 million, and $0.0 million, respectively, related to the net gain(loss) for ineffective contracts or the ineffective portion of the change in the derivatives’ fair value related to the oil and natural gas swap contracts. We have classified such net gain within other (income) expense in the accompanying consolidated statements of operations. The associated cash flows from the liquidation of these ineffective contracts is classified as a cash flow from investing activities in the accompanying consolidated statements of cash flows. As of December 31, 2008, twelve swap contracts remain outstanding, with various expiration dates through December 2010. The fair value of the assets and liabilities for oil and natural gas swap contracts as of December 31, 2008 and 2007 are as follows:

	Year Ended December 31,
	2008		2007
	(In Thousands)
Derivative Contract Assets:
Natural gas swap contracts	$	35,659	$	1,299
Oil swap contracts		41,491		-
Total		77,150		1,299
Less current portion		38,052		1,299
	$	39,098	$	-
Derivative Contract Liabilities:
Natural gas swap contracts	$	-	$	-
Oil swap contracts		-		53,369
Total		-		53,369
Less current portion		-		32,516
	$	-	$	20,853

The current portion of these oil and natural gas swap assets and liabilities are associated with the proximate year's production and are included in current assets and current liabilities, respectively, in the accompanying consolidated balance sheets. The derivative fair value amounts will be reclassified into earnings over the term of the hedge swap contracts. As the remaining hedge contracts were highly effective, the entire gain (loss) of $47.4 million and $(32.9) million from changes in contract fair value, net of taxes, as of December 31, 2008 and 2007, respectively, are included in other comprehensive income (loss) within stockholders’ equity. Approximately $23.0 million of such contract fair value, net of taxes, as of December 31, 2008, is expected to be reclassified into earnings within the next twelve months.

During the year ended December 31, 2004, we borrowed 35 million Euros to fund the acquisition of the European calcium chloride assets. This debt is designated as a hedge of our net investment in that foreign operation. The hedge is considered to be effective since the debt balance designated as the hedge is less than or equal to the net investment in the foreign operation. At December 31, 2008, the Company had 35 million Euros (approximately $49.3 million equivalent) designated as a hedge of a net investment in a foreign operation. Changes in the foreign currency exchange rate have resulted in a cumulative change to the cumulative translation adjustment account of $(4.2) million and $(5.6) million, net of taxes, as of December 31, 2008 and 2007, respectively.

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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,
	2008		2007		2006
	(In Thousands)

Number of weighted average common shares outstanding		74,519		73,573		71,632
Assumed exercise of stock options		-		2,348		3,192
Average diluted shares outstanding		74,519		75,921		74,824

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. There were no stock options or other dilutive securities excluded in the computation of diluted earnings per share for the year ended December 31, 2006.

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 prior periods has been revised to conform to the 2008 presentation.

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These production enhancement services can improve the value of natural gas and oil wells by increasing daily production and total recoverable reserves.

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. The accounting policies of the reportable segments are the same as those described in the summary of significant accounting policies. Transfers between segments, as well as geographic areas, are priced at the estimated fair value of the products or services as negotiated between the operating units. “Corporate overhead” includes corporate general and administrative expenses, corporate depreciation and amortization, interest income and expense and other income and expense.

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

	Year Ended December 31,
	2008			2007			2006
	(In Thousands)
Revenues from external customers
Product sales
Fluids Division	$	227,194		$	226,399		$	209,829
Offshore Division
Offshore Services		4,328			4,860			3,448
Maritech		207,180			213,338			164,099
Intersegment eliminations		-			-			-
Total Offshore Division		211,508			218,198			167,547
Production Enhancement Division
Production Testing		-			-			-
Compressco		8,639			12,641			10,881
Total Production Enhancement Division		8,638			12,641			10,881
Consolidated		447,341			457,238			388,257

Services and rentals
Fluids Division		65,602			54,353			34,158
Offshore Division
Offshore Services		279,019			306,174			220,878
Maritech		1,329			816			3,709
Intersegment eliminations		-			-			-
Total Offshore Division		280,348			306,990			224,587
Production Enhancement Division
Production Testing		126,996			92,989			66,351
Compressco		88,778			70,913			54,442
Total Production Enhancement Division		215,774			163,902			120,793
Consolidated		561,724			525,245			379,538

Intersegment revenues
Fluids Division		452			1,322			562
Offshore Division
Offshore Services		23,015			30,048			73,859
Maritech		-			-			-
Intersegment eliminations		(22,971	)		(29,057	)		(73,859	)
Total Offshore Division		44			991			-
Production Enhancement Division
Production Testing		23			141			175
Compressco		-			-			-
Total Production Enhancement Division		23			141			175
Intersegment eliminations		(519	)		(2,454	)		(737	)
Consolidated		-			-			-

F-39

	Year Ended December 31,
	2008			2007			2006
	(In Thousands)
Total revenues
Fluids Division		293,248			282,074			244,549
Offshore Division
Offshore Services		306,362			341,082			298,185
Maritech		208,509			214,154			167,808
Intersegment eliminations		(22,971	)		(29,057	)		(73,859	)
Total Offshore Division		491,900			526,179			392,134
Production Enhancement Division
Production Testing		127,019			93,130			66,526
Compressco		97,417			83,554			65,323
Total Production Enhancement Division		224,436			176,684			131,849
Intersegment eliminations		(519	)		(2,454	)		(737	)
Consolidated	$	1,009,065		$	982,483		$	767,795

Depreciation, depletion, amortization, and accretion
Fluids Division	$	14,033		$	12,758		$	9,180
Offshore Division
Offshore Services		18,998			16,279			11,958
Maritech		99,665			82,800			46,988
Intersegment eliminations		(544	)		(891	)		(127	)
Total Offshore Division		118,119			98,188			58,819
Production Enhancement Division
Production Testing		12,233			9,355			5,578
Compressco		12,049			8,043			6,358
Total Production Enhancement Division		24,282			17,398			11,936
Corporate overhead		2,459			1,500			996
Consolidated	$	158,893		$	129,844		$	80,931

Interest expense
Fluids Division	$	173		$	159		$	1
Offshore Division
Offshore Services		101			75			62
Maritech		43			57			4
Intersegment eliminations		-			-			-
Total Offshore Division		144			132			66
Production Enhancement Division
Production Testing		30			21			4
Compressco		-			-			85
Total Production Enhancement Division		30			21			89
Corporate overhead		17,210			17,574			13,481
Consolidated	$	17,557		$	17,886		$	13,637

Income (loss) before taxes and discontinued operations
Fluids Division	$	5,401		$	10,897		$	60,939
Offshore Division
Offshore Services		3,019			33,496			51,007
Maritech		(31,932	)		(49,815	)		55,105
Intersegment eliminations		(782	)		6,225			(7,865	)
Total Offshore Division		(29,695	)		(10,094	)		98,247
Production Enhancement Division
Production Testing		35,677			25,639			18,308
Compressco		30,310			26,663			20,833
Total Production Enhancement Division		65,987			52,302			39,141
Corporate overhead		(45,608	)(1)		(50,943	)(1)		(45,958	)(1)
Consolidated	$	(3,915	)	$	2,162		$	152,369

F-40

	Year Ended December 31,
	2008			2007			2006
	(In Thousands)
Total assets
Fluids Division	$	328,852		$	285,882		$	270,152
Offshore Division
Offshore Services		220,671			262,729			279,541
Maritech		413,661			391,703			302,381
Intersegment eliminations		(2,902	)		(2,119	)		(41,618	)
Total Offshore Division		631,430			652,313			540,304
Production Enhancement Division
Production Testing		100,676			80,281			60,401
Compressco		212,619			186,448			163,530
Total Production Enhancement Division		313,295			266,729			223,931
Corporate overhead		139,047	(2)		90,612	(2)		51,803	(2)
Consolidated	$	1,412,624		$	1,295,536		$	1,086,190

Capital expenditures
Fluids Division	$	76,531		$	18,877		$	11,679
Offshore Division
Offshore Services		14,299			29,732			59,335
Maritech		84,970			178,392			60,660
Intersegment eliminations		(247	)		(5,113	)		(1,635	)
Total Offshore Division		99,022			203,011			118,360
Production Enhancement Division
Production Testing		25,904			22,513			12,255
Compressco		33,241			23,676			25,971
Total Production Enhancement Division		59,145			46,189			38,226
Corporate overhead		27,401			7,997			4,150
Consolidated	$	262,099		$	276,074		$	172,415

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

	2008			2007		2006
General and administrative expense	$	34,185		$	31,533	$	31,149
Depreciation and amortization		2,459			1,500		997
Interest expense		17,210			17,574		13,481
Other general corporate (income) expense, net		(8,246	)		336		331
Total	$	45,608		$	50,943	$	45,958

(2) Includes assets of discontinued operations.

Summarized financial information concerning the geographic areas of our customers and in which we operate at December 31, 2008, 2007, and 2006 is presented below:

	Year Ended December 31,
	2008		2007		2006
	(In Thousands)
Revenues from external customers:
U.S.	$	855,380	$	850,857	$	646,172
Canada and Mexico		36,939		25,330		22,001
South America		15,522		9,307		12,881
Europe		85,713		80,495		74,292
Africa		1,973		2,498		3,421
Asia and other		13,538		13,996		9,028
Total		1,009,065		982,483		767,795

F-41

	Year Ended December 31,
	2008			2007			2006
	(In Thousands)
Transfers between geographic areas:
U.S.		2,578			318			1,425
Canada and Mexico		-			-			-
South America		225			-			-
Europe		55			1,548			256
Africa		-			-			-
Asia and other		-			-			112
Eliminations		(2,858	)		(1,866	)		(1,793	)
Total revenues	$	1,009,065		$	982,483		$	767,795

Identifiable assets:
U.S.	$	1,273,642		$	1,163,604		$	965,975
Canada and Mexico		26,732			22,482			12,515
South America		27,379			17,843			17,823
Europe		70,964			79,972			73,816
Africa		4,684			1,821			2,136
Asia and other		9,636			5,772			637
Eliminations and discontinued operations		(413	)		4,042			13,288
Total identifiable assets	$	1,412,624		$	1,295,536		$	1,086,190

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 2006, no single customer accounted for more than 10% of our consolidated revenues.

NOTE R — SUPPLEMENTAL OIL AND GAS DISCLOSURES (Unaudited)

The following information regarding the activities of our Maritech segment is presented pursuant to SFAS No. 69, “Disclosures About Oil and Gas Producing Activities (SFAS No. 69).” As part of the Offshore Division activities, Maritech and its subsidiaries generally acquire oil and gas reserves and operate the properties in exchange for assuming the proportionate share of the well abandonment 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,
	2008		2007		2006
	(In Thousands)

Acquisition	$	45,373	$	82,976	$	8,561
Exploration		8,522		-		-
Development		79,620		152,372		78,774
Total costs incurred	$	133,515	$	235,348	$	87,335

F-42

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,
	2008			2007
	(In Thousands)

Undeveloped properties	$	7,599		$	7,599
Proved developed properties being amortized		699,083			565,568
Total capitalized costs		706,682			573,167
Less accumulated depletion, depreciation,
and amortization		(367,952	)		(233,829	)
Net capitalized costs	$	338,730		$	339,338

Included in capitalized costs of proved developed properties being amortized is our estimate of our proportionate share of decommissioning liabilities assumed relating to these properties, which is also reflected as decommissioning and other asset retirement obligations in the accompanying consolidated balance sheets.

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,
	2008			2007			2006
	(In Thousands)

Oil and gas sales revenues	$	207,180		$	213,338		$	164,099
Production (lifting) costs (1)		89,574			89,605			63,665
Depreciation, depletion, and amortization		82,971			73,835			38,550
Impairments of properties (2)		42,658			76,094			3,405
Excess decommissioning and
abandonment costs		7,045			12,153			3,755
Exploration expenses		224			1,174			8
Accretion expense		7,631			6,841			6,825
Dry hole costs		9,063			1,699			1,145
Gain on insurance recoveries		(697	)		(3,245	)		(10,555	)
Pretax income (loss) from producing activities		(31,289	)		(44,818	)		57,301
Income tax expense (benefit)		(8,455	)		(16,549	)		20,605
Results of oil and gas producing activities	$	(22,834	)	$	(28,269	)	$	36,696

(1)	Production costs during 2007 and 2008 include certain hurricane repair expenses of $13.5 million and $8.5 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

F-43

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 SEC guidelines. 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 addition to the complete analysis by Maritech’s internal reservoir engineers, independent petroleum engineers and geologists performed reserve audits of approximately 85.3% of our proved reserve volumes as of December 31, 2008. 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 a process whereby an independent petroleum engineering firm visits with our technical staff to collect all necessary geologic, geophysical, engineering, and economic data, followed by 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 regulatory and environmental limits. While Maritech can be reasonably certain that the proved reserves will be produced, 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) and subsequent SEC staff interpretations and guidance.

Maritech engaged Ryder Scott Company, L.P. and DeGolyer and McNaughton to perform the engineering audits of a portion of our oil and gas reserves as of December 31, 2008 and 2007. 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, 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

F-44

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 most significant properties, excluding the Cimarex Properties, and represented approximately 61.9% of our total proved oil and gas reserve volumes (70.1% of discounted future net pretax cash flows). The reserve audit performed by DeGolyer and McNaughton included the Cimarex Properties acquired in December 2007 and represented approximately 23.4% of our total proved oil and gas reserve volumes (97.6% of discounted future net pretax cash flows). 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 as set forth in Society of Petroleum Engineers (SPE) 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 reserves. The reserve values and cash flow amounts reflected in the following reserve disclosures are based on prices as of year end. Proved oil and gas reserve quantities are reported in accordance with guidelines established by the SEC. Ryder Scott Company, L.P. prepared the estimates for our reserves at December 31, 2006, except for two producing fields (representing approximately 43% of proved reserves volumes) as of December 31, 2006, which was prepared by Maritech. All of Maritech’s reserves are located in U. S. state and federal offshore waters of the Gulf of Mexico and onshore Louisiana.

	Oil			Gas
Reserve Quantity Information	(MBbls)			(MMcf)

Total proved reserves at December 31, 2005		7,987			42,274
Revisions of previous estimates		732			(44	)
Production		(1,356	)		(7,812	)
Extensions and discoveries		1,299			5,230
Purchases of reserves in place		180			163
Sales of reserves in place		(13	)		(73	)

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

	Oil			Gas
Proved Developed Reserves	(MBbls)			(MMcf)

December 31, 2006		7,872			36,373
December 31, 2007		6,646			43,898
December 31, 2008		4,504			40,988

F-45

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

The standardized measure of discounted future net cash flows and changes in such cash flows are prepared using procedures prescribed by SFAS No. 69. As prescribed by SFAS No. 69, “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 year end prices, costs, and 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 the calculations. Furthermore, year end 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,
	2008			2007
	(In Thousands)

Future cash inflows	$	494,908		$	962,734
Future costs
Production		192,998			237,835
Development and abandonment		251,015			226,842
Future net cash flows before income taxes		50,895			498,057
Future income taxes		(2,399	)		(134,950	)
Future net cash flows		48,496			363,107
Discount at 10% annual rate		11,852			(64,428	)
Standardized measure of discounted future net cash flows	$	60,348		$	298,679

Changes in Standardized Measure of Discounted Future Net Cash Flows:

	Year Ended December 31,
	2008			2007			2006
	(In Thousands)

Standardized measure, beginning of year	$	298,679		$	186,090		$	233,988

Sales, net of production costs		(110,561	)		(111,580	)		(103,829	)
Net change in prices, net of production costs		(297,719	)		179,079			(143,181	)
Changes in future development costs		(30,590	)		10,635			9,127
Development costs incurred		39,035			26,615			13,148
Accretion of discount		41,245			27,569			34,742
Net change in income taxes		110,150			(24,171	)		23,835
Purchases of reserves in place		13,233			55,673			6,585
Extensions and discoveries		19,108			53,504			86,223
Sales of reserves in place		(252	)		4,114			3,885
Net change due to revision in quantity estimates		(6,295	)		(83,826	)		17,534
Changes in production rates (timing) and other		(15,685	)		(25,023	)		4,033
Subtotal		(238,331	)		112,589			(47,898	)

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

F-46

NOTE S — QUARTERLY FINANCIAL INFORMATION (Unaudited)

Summarized quarterly financial data for 2008 and 2007 is as follows:

	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	)

	Three Months Ended 2007
	March 31		June 30		September 30		December 31
	(In Thousands, Except Per Share Amounts)

Total revenues	$	243,596	$	254,054	$	238,858	$	245,975
Gross profit (loss)		57,465		60,605		35,650		(37,337	)
Income (loss) before discontinued
operations		20,347		22,165		3,046		(44,337	)

Net income (loss)		20,662		22,870		3,862		(18,623	)

Net income (loss) per share before
discontinued operations	$	0.28	$	0.30	$	0.04	$	(0.60	)

Net income (loss) per diluted share
before discontinued operations	$	0.27	$	0.29	$	0.04	$	(0.60	)

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.

For a more detailed description of the Rights Plan and the First Amendment to the Rights Plan, refer to our Forms 8-K filed with the SEC on October 28, 1998, and November 6, 2008.

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