PART I

Item 1. Business.

General

TETRA Technologies, Inc. (“TETRA” or “the Company”) is an oil and gas services company with an integrated calcium chloride and brominated products manufacturing operation that supplies feedstocks to energy markets, as well as other markets. The Company is comprised of three divisions – Fluids, Well Abandonment & Decommissioning, and Testing & Services.

The Company’s Fluids Division manufactures and markets clear brine fluids to the oil and gas industry for use in well drilling, completion, and workover operations in both domestic and international markets. The Division also markets certain fluids and dry calcium chloride manufactured at its production facilities to a variety of markets outside the energy industry.

The Company’s Well Abandonment & Decommissioning Division provides a broad array of services required for the abandonment of depleted oil and gas wells and the decommissioning of platforms, pipelines, and other associated equipment. The Division services the onshore U.S. Gulf Coast region and the inland waters and offshore markets of the Gulf of Mexico. The Division is also an oil and gas producer from wells acquired in connection with its well abandonment and decommissioning business and provides electric wireline, workover, and drilling services.

The Company’s Testing & Services Division provides production testing services to the Texas, Louisiana, Alabama, Mississippi, offshore Gulf of Mexico and certain Latin American markets. It also provides the technology and services required for the separation and recycling of oily residuals generated from petroleum refining operations.

The Company is pursuing a growth strategy which includes expanding its existing businesses – both through internal growth as well as through the pursuit of suitable acquisition transactions – and by identifying opportunities to establish operations in additional niche oil service markets. For financial information for each of the Company’s segments, see “Note Q – Industry Segments and Geographic Information” contained in the Notes to Consolidated Financial Statements.

TETRA Technologies, Inc. was incorporated in Delaware in 1981. All references to the Company or TETRA include TETRA Technologies, Inc. and its subsidiaries. The Company’s corporate headquarters are located at 25025 Interstate 45 North, Suite 600, in The Woodlands, Texas. Its phone number is 281-367-1983 and its web site is accessed at www.tetratec.com. The Company makes available, free of charge, on its website, its 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 its 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 reasonably practicable after such materials are electronically filed with, or furnished to, the Securities and Exchange Commission (“SEC”), and will make these available in print to any stockholder who requests such information from the Corporate Secretary.

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Products and Services

Fluids Division

Liquid calcium chloride, sodium bromide, calcium bromide, zinc bromide and zinc calcium bromide produced by the 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 distributed through the Company’s Fluids Division and are also sold to other companies who service customers in the oil and gas industry.

The 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. The Division also provides these customers with a broad range of associated services, including onsite fluid filtration, handling and recycling, fluid engineering consultation and fluid management. The Division also repurchases used CBFs from operators and recycles and reconditions these materials. The utilization of reconditioned CBFs reduces the net cost of the CBFs to the Company’s customers and minimizes the need for disposal of used fluids. The Company recycles and reconditions the CBFs through filtration, blending and the use of proprietary chemical processes, and then markets the reconditioned CBFs.

The Division’s fluid engineering and management personnel use proprietary technology to determine the proper blend for a particular application to maximize the effectiveness and lifespan of the CBFs. The specific volume, density, crystallization temperature and chemical composition of the CBFs are modified by the Company to satisfy a customer's specific requirements. The Company’s 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 manufacturing group of the Fluids Division presently obtains product from nine active production facilities that manufacture liquid and dry calcium chloride, sodium bromide, calcium bromide, zinc bromide and/or zinc calcium bromide for distribution primarily into energy markets. Liquid and dry calcium chloride are also sold into the water treatment, industrial, cement, food processing, dust control, ice melt 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.

Five of these facilities convert co-product hydrochloric acid from nearby sources into liquid and/or dry calcium chloride products. These operations are located near Lyondell’s Lake Charles, Louisiana TDI plant; Resolution Performance Product’s Norco, Louisiana epoxy resins plant; Honeywell’s Baton Rouge, Louisiana refrigerants plant; Vulcan’s Wichita, Kansas chlorinated solvents plant; and DuPont’s Parkersburg, West Virginia fluoromonomer plant. Some of these facilities consume feedstock acid from other sources as well. Dry calcium chloride is produced at the Company’s Lake Charles plant. The plant has a minimum production capacity of 100,000 tons of dry product per year. The Company also has two solar evaporation plants located in San Bernardino County, California, which produce liquid calcium chloride from underground brine reserves to supply markets in the western United States.

The manufacturing group manufactures and distributes calcium bromide and zinc bromide from its West Memphis, Arkansas facility. A patented and proprietary production process utilized at this facility uses a low cost hydrobromic acid or bromine, along with various zinc sources, to manufacture its products. This facility also uses patented and proprietary technologies to recondition and upgrade used CBFs repurchased from the Company’s customers. The group also has a facility at Dow’s Ludington, Michigan chemical plant that converts a crude bromine stream from Dow’s calcium/magnesium chemicals operation into bromine and liquid calcium bromide or liquid sodium bromide.

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The Company also owns a plant in Magnolia, Arkansas that is designed to produce calcium bromide. Approximately 33,000 gross acres of bromine-containing brine reserves are under lease by the Company in the vicinity of the plant to support its production. The plant is not currently in operation, and the Company continues to evaluate its strategy related to these assets and their future development.

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

Well Abandonment & Decommissioning Division

The Well Abandonment & Decommissioning (“WA&D”) Division provides a broad array of services required for the abandonment of depleted oil and gas wells and the decommissioning of platforms and other associated equipment onshore and in the inland waters of Texas and Louisiana and offshore in the Gulf of Mexico. In addition, the Division provides electric wireline, workover and drilling services and is a producer of oil and gas. The Company first entered the well abandonment business in an effort to expand the services offered to its customers and to capitalize on existing personnel, equipment and facilities along the Louisiana and Texas Gulf Coast. The Division later added electric wireline services to its mix with an additional acquisition.

The Division has service facilities located in Belle Chasse, Houma and Lafayette, Louisiana and in Bryan, Kilgore, Midland and Victoria, Texas. In providing its well abandonment and decommissioning services, the Company owns and operates onshore rigs, barge-mounted rigs, a platform rig, a heavy lift barge and numerous offshore rigless packages. In addition, the Company leases certain equipment from third party contractors whenever necessary. The Division’s integrated package of services includes engineering services, project management and other operations required to plug wells, salvage tubulars and decommission wellhead equipment, pipelines and platforms. Its electric wireline operations provide pressure transient testing, reservoir evaluation, well performance evaluation, cased hole and memory production logging, perforating, bridge plug and packer service and pipe recovery to major oil and gas companies and independent operators.

In the fourth quarter of 2000, the Company increased its capacity to service its markets through the acquisition of a number of offshore rigless well abandonment packages and a heavy lift barge, the Southern Hercules. In September 2002, the Company expanded its geographic coverage in the onshore well abandonment business to eastern Texas, northern Louisiana and southern Arkansas with the acquisition of the assets of Bee Line Well Service, Inc.

The Company formed Maritech Resources, Inc. (“Maritech”) in 1999 as a component of the WA&D Division to acquire, manage and exploit producing oil and gas properties purchased in conjunction with its well abandonment business. Federal regulations generally require lessees to plug and abandon wells and decommission the platforms, pipelines and other equipment located on the lease within one year after the lease terminates. The Division provides oil and gas companies with alternative ways of managing their well abandonment obligations, while effectively base-loading well abandonment and decommissioning work for the WA&D Division. This may include purchasing an ownership interest in the properties and operating them in exchange for assuming the proportionate share of the well abandonment and decommissioning obligations associated with such properties. In some transactions, cash may also be received or paid by Maritech.

Maritech’s operations have expanded significantly in the past three years, principally due to the acquisition of offshore Gulf of Mexico producing properties, and subsequent development operations on these properties. In the fourth quarter of 2001, Maritech purchased approximately $4.9 million of oil and gas producing properties in exchange for the assumption of the well abandonment and decommissioning liabilities (referred to as “decommissioning liabilities”) related to the properties and other consideration. As part of the transaction, the Company received approximately $1.7 million of cash to satisfy other working interest owners’ future well abandonment obligations for these properties. During the fourth quarter of 2002, Maritech purchased oil and gas producing properties in exchange for the assumption of approximately $13.9 million in decommissioning liabilities. In January 2003, Maritech purchased oil and gas producing properties in three separate transactions. In the largest of the three acquisitions, Maritech purchased oil and gas producing assets in offshore Gulf of Mexico and onshore Louisiana locations in exchange for the

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assumption of approximately $6.9 million in decommissioning liabilities. Maritech also purchased, in two separate transactions, additional working interests in oil and gas properties it previously owned in exchange for the assumption of approximately $1.1 million in decommissioning liabilities. In February 2003, Maritech purchased oil and gas properties in exchange for the assumption of approximately $2.1 million in decommissioning liabilities. In November 2003, Maritech purchased an interest in an oil and gas property in exchange for the assumption of approximately $0.8 million in decommissioning liabilities. At December 31, 2003, Maritech had proved reserves of approximately 3.3 million barrels of oil and 13.9 million cubic feet of natural gas, with undiscounted future net pretax cash flow of approximately $86.2 million.

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

Testing & Services Division

The production testing component of the Testing & Services Division provides flowback pressure and volume testing of oil and gas wells, predominantly in the Texas, Louisiana, Alabama, Mississippi, offshore Gulf of Mexico, Mexico and Venezuela markets. The Company believes this group to be the leading provider of these services in the Western Hemisphere onshore markets. These services facilitate the sophisticated evaluation techniques needed for reservoir management and optimization of well workover programs. In early 2004, the Company entered into a joint venture to pursue the performance of similar services in Saudi Arabia.

In 2000, the Company acquired certain assets of Southern Well Testing, Inc. and Key Energy Services, Inc., which significantly increased its equipment capacity in production testing. In September 2001, the Company expanded its testing capabilities in the offshore Gulf of Mexico market, as well as improving its onshore presence, through the acquisition of the assets of Production Well Testers. The Company continued this expansion in July 2002 with the acquisition of the assets of Precision Well Testing Company, further strengthening its presence in the offshore Gulf of Mexico and onshore areas. The Division maintains the largest fleet of high pressure production testing equipment in the South Texas area, with operations in Alice, Edinburg, Laredo and Victoria, Texas. The Division also has operations in Palestine, Texas; New Iberia, Louisiana; Reynosa and Veracruz, Mexico; Maturin, Venezuela; and it recently opened an office in Saudi Arabia.

The process services group of the Testing & Services Division applies a variety of technologies to separate oily residuals — mixtures of hydrocarbons, water and solids — into their components. The group provides its oil recovery and residuals separation and recycling services primarily to the petroleum refining market in the United States. This group utilizes various liquid/solid separation technologies, including a proprietary high temperature thermal desorption and recovery technology, hydrocyclones, centrifuges and filter presses. Oil is recycled for productive use, water is recycled or disposed of, and organic solids are recycled. Inorganic solids are treated to become inert, nonhazardous materials. The Division typically builds, owns and operates fixed systems that are located on its customers’ sites, providing these services under long-term contracts.

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

The Fluids Division manufactures calcium chloride, sodium bromide, calcium bromide, zinc bromide and zinc calcium bromide for distribution to its customers. The Division also purchases calcium chloride, calcium bromide and sodium bromide from a number of domestic and foreign manufacturers, and it recycles calcium and zinc bromide CBFs repurchased from its oil and gas customers.

Some of the Division’s primary sources of raw materials are low cost chemical co-product streams obtained from chemical manufacturers. At the Norco, Louisiana; Baton Rouge, Louisiana; Wichita, Kansas; Lake Charles, Louisiana; and Parkersburg, West Virginia calcium chloride production facilities, the principal raw material is co-product hydrochloric acid produced by other chemical companies. The Company has written agreements with those chemical companies regarding the supply

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of hydrochloric acid or calcium chloride, but believes that there are alternative sources of supply as well. The Company also produces calcium chloride at its two plants in San Bernardino County, California from underground brine reserves. These brines are deemed adequate to supply the Company’s foreseeable need for calcium chloride in that market area. Substantial quantities of limestone are also consumed when converting hydrochloric acid into calcium chloride. The Company uses a proprietary process that permits the use of less expensive limestone, while maintaining end-use product quality. The Company purchases limestone from several different sources. Hydrochloric acid and limestone are in abundant supply at market prices.

To produce calcium bromide, zinc bromide and zinc calcium bromide at its West Memphis, Arkansas facility, the Company uses hydrobromic acid, bromine and various sources of zinc raw materials. The Company has one internal and several external sources of bromine and several external sources of co-product hydrobromic acid. The Company uses 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 the Company can use in the production of zinc bromide. The Company has an agreement with Dow Chemical Company to purchase crude bromine to feed its bromine derivatives plant in Ludington, Michigan. This plant produces bromine for use at the West Memphis facility as well as liquid calcium bromide and sodium bromide for resale.

The Company also owns a calcium bromide manufacturing plant near Magnolia, Arkansas, that was constructed in 1985 and has a production capacity of 100 million pounds of calcium bromide per year. This plant was acquired in 1988 and is not presently in operation. The Company currently has 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. The Company believes it has 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 take several years and require a substantial investment of additional capital.

The Company has a long-term supply agreement with a foreign producer of calcium bromide as well. This agreement, coupled with production of bromine and sodium and calcium bromide from the Ludington, Michigan plant and calcium bromide, zinc bromide and zinc calcium bromide from the West Memphis, Arkansas facility, affords the Company additional flexibility, beyond the development of the Magnolia, Arkansas plant, for the secure supply of its required bromine derivatives.

Market Overview and Competition

Fluids Division

The Fluids Division markets and sells CBFs, drilling and completion fluids systems, and related products and services to major 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, the Far East, Europe, the Middle East and West Africa. 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, the Company believes that its historical focus on providing these and other value-added services to its customers has enabled it to compete successfully. Major customers of the Fluids Division include Amerada Hess Corporation, Anadarko Petroleum Corporation, Apache Corporation, BP, ChevronTexaco, ConocoPhillips, El Paso Corporation, Kerr-McGee Corporation, LLOG Exploration, Newfield Exploration Company, Spinnaker Exploration, Baker Hughes, M-I L.L.C. and Halliburton Company. The Division also sells its products through various distributors worldwide.

The Company's liquid and dry calcium chloride products have a wide range of uses outside the energy industry. The non-energy market segments to which the Company's products are marketed include the agricultural, industrial, mining, janitorial, construction and food industries. These products promote snow and ice melt, dust control, cement curing, and road stabilization and are used as a source

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of calcium nutrients to improve agricultural yields in many regions of the country. Most of these markets are highly competitive. The Company’s major competitors in the dry calcium chloride market include Dow Chemical Company, Industrial del Alkali and General Chemical Company. The Company also sells sodium bromide into the industrial water treatment markets as a biocide under the BioRid® trade name.

Well Abandonment & Decommissioning Division

The WA&D Division provides well abandonment and decommissioning services offshore in the U.S. Gulf of Mexico and in the inland waters and onshore in Texas and Louisiana. Demand for the services of the WA&D Division is predominately driven by government regulations. In the market areas in which the Company currently competes, 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 of Gulf of Mexico producing fields has increased the number of wells requiring plugging and the Company believes this increase will continue. Offshore platform decommissioning activities in the Gulf of Mexico are highly seasonal, with the majority of such operations performed during the months of April through October, when weather conditions are favorable. Critical factors required to participate in these markets include: the proper equipment to meet diverse market conditions; qualified, experienced personnel; technical expertise to address varying downhole and surface conditions; the financial strength to ensure all abandonment and decommissioning obligations are satisfied; and a comprehensive safety and environmental program. The Company believes its integrated service package satisfies these market requirements, allowing it to successfully compete.

The Division markets its services to major oil and gas companies, independent operators, and state governmental agencies. Major customers include ChevronTexaco, ExxonMobil, Shell Oil, BP, Forest Oil, Hunt Oil, Devon, Unocal, ConocoPhillips, Apache, Anadarko, and the Railroad Commission of the State of Texas. These services are performed onshore in Texas and Louisiana, in the Gulf Coast inland waterways and offshore in the Gulf of Mexico. The Company’s principal competitors in the offshore and inland waters markets are Global Industries Inc., Offshore Specialties, Inc., Horizon Offshore, Superior Energy Services, Inc. and Cal Dive International, Inc. This market is highly competitive and competition is based primarily on service, equipment availability, safety record and price.

Testing & Services Division

The Testing & Services Division provides production testing services primarily to the natural gas segment of the oil and gas industry. In certain gas producing basins, water, sand and other abrasive materials will commonly accompany the initial production of natural gas, often under high pressures. The Division provides the equipment and qualified personnel to remove these impediments to production and to pressure test wells and wellhead equipment. The Division also provides certain production testing services for oil producing properties as well.

The 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. The Company believes its equipment maintenance program and operating procedures give it a competitive advantage in the marketplace. Competition in onshore markets is dominated by numerous small, privately owned operators. Schlumberger Limited, Halliburton Company, Expro International and GeoService are major competitors in offshore markets and international markets. The Company’s customers include ConocoPhillips, Shell Oil, Dominion Exploration and Production, Inc., Anadarko, El Paso Corporation, ExxonMobil, ChevronTexaco, Devon, Newfield, Valence Operating Co., PEMEX (the national oil company of Mexico) and PDVSA (the national oil company of Venezuela).

The Division also provides oily residuals processing services to refineries concentrated in Texas and Louisiana. Although U.S. refineries have alternative technologies and disposal systems available to them, the Company feels its competitive edge lies in its ability to apply its various liquid/solid separation technologies to provide an efficient processing alternative at competitive prices. The Division currently has major processing facilities at the following refineries: ExxonMobil – Baton Rouge, Louisiana; Hovensa – St. Croix, Virgin Islands; Premcor and Motiva – Port Arthur, Texas; Lyondell-Citgo – Houston, Texas; ConocoPhillips – Borger, Texas; Premcor – Memphis, Tennessee; and Citgo – Lake Charles, Louisiana. This Division’s major competitor in this market is U.S. Filter.

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Other Business Matters

Marketing and Distribution

The Fluids Division markets its domestic products and services through its distribution facilities located principally in the Gulf Coast region of the United States. 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, the Division believes that its strategic locations make it one of the lowest cost suppliers of liquid calcium chloride and other CBFs in the southern United States and California. International markets that are served include the U.K. and Norwegian sectors of the North Sea, Mexico, Venezuela, Brazil, West Africa, Europe, the Middle East and the Far East.

The non-oilfield liquid and dry calcium chloride products are marketed through the Division’s sales offices and sales agents in California, Missouri, Florida, Texas and Wyoming, as well as through a network of distributors located throughout the country. To service these markets, the Division has over two dozen distribution facilities strategically located to provide efficient, low cost product availability.

Backlog

The level of backlog is not indicative of the Company’s estimated future revenues because a majority of the Company’s products and services are not sold under long-term contracts or do not require long lead times to procure or deliver. The Company’s backlog consists of estimated firm future revenues associated with its well abandonment and decommissioning and process services businesses in the U.S. The estimated backlog for the well abandonment and decommissioning business consists primarily of the non-Maritech share of the well abandonment and decommissioning work associated with the oil and gas properties operated by Maritech. The Company’s estimated backlog on December 31, 2003, was $87.9 million, of which approximately $20.3 million is expected to be billed during 2004. This compares to an estimated backlog of $77.2 million at December 31, 2002.

Employees

As of December 31, 2003, the Company had 1,273 employees. None of the Company’s U.S. employees are presently covered by a collective bargaining agreement, other than the employees of the Company’s Lake Charles, Louisiana calcium chloride production facility who are represented by the Paper, Allied Industrial, Chemical and Energy Workers International Union. The Company believes that its relations with its employees are good.

Patents, Proprietary Technology and Trademarks

As of December 31, 2003, the Company owned or licensed fifteen issued U.S. patents, and had seven patents pending in the U.S. Internationally, the Company had five issued foreign patents, nine foreign patents pending, and 25 patent applications. 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 2019. The Company has elected to maintain certain other internally developed technologies, know-how and inventions as trade secrets. While the Company believes that the protection of its patents and trade secrets is important to its competitive positions in its businesses, the Company does not believe any one patent or trade secret is essential to the success of the Company.

It is the practice of the Company to enter into confidentiality agreements with key employees, consultants and third parties to whom the Company discloses its confidential and proprietary information. There can be no assurance, however, that these measures will prevent the unauthorized disclosure or use of the Company’s trade secrets and expertise or that others may not independently develop similar trade secrets or expertise. Management of the Company 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, the Company uses all possible legal means to protect its patents, trade secrets and other proprietary information.

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The Company sells various products and services under a variety of trademarks and service marks, some of which are registered in the U.S. or certain foreign countries.

Safety, Health and Environmental Affairs Regulations

Various environmental protection laws and regulations have been enacted and amended during the past three decades in response to public concerns over the environment. The operations of the Company and its customers are subject to these various evolving environmental laws and corresponding regulations, which 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 the Company’s employees and visitors to its facilities are enforced by the U.S. Occupational Safety and Health Administration and other state and local agencies and authorities. The Company must comply with the requirements of environmental laws and regulations applicable to its 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. The Company is also subject to the applicable environmental and health and safety rules and regulations of the local, state and federal agencies in those foreign countries in which it operates. Many state and local agencies have imposed environmental laws and regulations with more rigorous standards than their federal counterparts. The Company believes that it is in general compliance with all material environmental laws and regulations.

At the Company’s Lake Charles, West Memphis, Parkersburg and San Bernardino County production plants, the Company holds various permits regulating air emissions, wastewater and storm-water discharges, the disposal of certain hazardous and nonhazardous wastes, and wetlands preservation.

The Company believes that its manufacturing plants and other facilities are in general compliance with all applicable environmental and health and safety laws and regulations. Since its inception, the Company has 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 operations and in the development and handling of certain products produced at the Company's plants; because of this, 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 the Company's handling, manufacture, use, reuse, or disposal of materials at plants to more rigorous scrutiny. The Company cannot predict the extent to which its operations may be affected by future regulatory and enforcement policies.

Certain Business Risks

The Company identifies the following important risk factors, which could affect the Company’s actual results and cause actual results to differ materially from any such results that might be projected, forecasted, or estimated by the Company in this report.

Market Risks:

The Company’s operations are materially dependent on levels of oil and gas well drilling, completion, workover and abandonment activities, both in the United States and internationally.

Activity levels for oil and gas drilling, completion, workover and abandonment are affected both by short-term and long-term trends in oil and gas prices and supply and demand balance, among other factors. Oil and gas prices and, therefore, the levels of well drilling, completion and workover activities, tend to fluctuate. Worldwide military, political and economic events, including initiatives by the Organization of Petroleum Exporting Countries, have contributed to, and are likely to continue to contribute to, price volatility. Also, a prolonged slowdown of the U.S. and/or world economy may contribute to an eventual downward trend in the demand and, correspondingly, the price of oil and natural gas.

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Other factors affecting the Company’s 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 the Company operates. A large concentration of the Company’s operating activities is located in the onshore and offshore region of the U.S. Gulf of Mexico. The Company’s revenues and profitability are particularly dependent upon oil and gas industry activity and spending levels in the Gulf of Mexico region. To a lesser extent, the Company’s 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 and workover activity and result in a corresponding decline in the demand for the Company’s products and services and, therefore, have a material adverse effect on the Company’s revenues and profitability.

Profitability of the Company’s operations are dependent on numerous factors beyond its control.

The Company’s operating results in general, and gross margin in particular, are functions of market conditions and the product and service mix sold in any period. Other factors, such as unit volumes, 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 ability to obtain items at reasonable prices may also continue to affect the cost of sales and the fluctuation of gross margin in future periods.

The Company encounters and expects to continue to encounter intense competition in the sale of its products and services.

The Company competes with numerous companies in its oil and gas and chemical operations. Many of the Company’s competitors have substantially greater financial and other related resources than the Company. To the extent competitors offer comparable products or services at lower prices, or higher quality and more cost-effective products or services, the Company’s 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 the Company competes.

The Company is dependent upon third party suppliers for specific products and equipment necessary to provide certain of its products and services.

The Company sells a variety of CBFs, including brominated CBFs, such as calcium bromide, zinc bromide, sodium bromide and other brominated products, some of which are manufactured by the Company and some of which are purchased from third parties. The Company also sells calcium chloride, as a CBF and in other forms and for other applications. Sales of calcium chloride and brominated products contribute significantly to the Company’s revenues. In its manufacture of calcium chloride, the Company uses hydrochloric acid and other raw materials purchased from third parties. In its manufacture of brominated products, the Company uses bromine, hydrobromic acid and other raw materials, including various forms of zinc, that are purchased from third parties. The Company acquires brominated products from a variety of third party suppliers. If the Company is unable to acquire the brominated products, bromine, hydrobromic or hydrochloric acid, zinc or any other raw material supplies for a prolonged period, the Company’s business could be materially and adversely affected.

A portion of the well abandonment and decommissioning services performed by the Company’s WA&D Division require the use of lift boats and heavy lift vessels, which the Company does not own. The Company leases this equipment from certain providers, but is subject to the available supply of these vessels in the Gulf of Mexico region, and could be affected by shortages of supply. To the extent such vessels are not available, or are only available at prices which are prohibitive, the Company’s WA&D Division business could be materially and adversely affected.

The Company’s oil and gas revenues and cash flows are subject to commodity price risk.

The Company’s revenues from oil and gas production are increasing significantly; therefore, the Company has increased market risk exposure in the pricing applicable to its 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

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unpredictable, and this price volatility is expected to continue. Significant declines in prices for oil and natural gas could have a material effect on the Company’s results of operations and quantities of reserves recoverable on an economic basis. The Company’s 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 its oil and gas production. Because of this, the Company is exposed to the volatility of oil and gas prices for the portion of its oil and gas production that is not hedged.

Operating Risks:

The Company’s operations involve significant operating risks and insurance coverage may not be available or cost effective.

The Company is subject to operating hazards normally associated with the oilfield service industry and offshore oil and gas production operations. The Company’s operation of marine vessels and offshore production platforms involves a particularly high level of risk. Whenever possible, the Company obtains agreements from customers and suppliers that limit its exposure. However, the occurrence of certain operating hazards, including storms, could result in substantial losses to the Company due to injury or loss of life, damage to or destruction of property and equipment, pollution or environmental damage, and suspension of operations. The Company has maintained a policy of insuring its risks of operational hazards that it believes is typical in the industry. Limits of insurance coverage purchased by the Company are consistent with the exposures faced by the Company and the nature of its products and services. Due to economic conditions in the insurance industry, in certain instances the Company has increased its self-insured retentions and deductibles for certain policies in order to minimize the increased costs of coverage. In certain areas of its business, the Company has elected to assume the risk of loss for specific assets. To the extent the Company suffers losses or claims that are not covered, or are only partially covered by insurance, its results of operations could be adversely affected. There can be no assurance that any insurance will be adequate to cover losses or liabilities associated with operational hazards. The Company cannot predict the continued availability of insurance, or its availability at premium levels that justify its purchase.

The Company’s operations, particularly those conducted in the Gulf of Mexico, are seasonal and depend, in part, on weather conditions.

The WA&D Division has historically enjoyed its highest vessel utilization rates during the months from April to October, when weather conditions are favorable for offshore activities, and has experienced its lowest utilization rates in the months from November to March. This Division, under certain turnkey contracts, may bear the risk of delays caused by adverse weather conditions. Storms can also cause the Company’s oil and gas producing properties to be shut-in. In addition, demand for other products and services provided by the Company are subject to seasonal fluctuations, due in part to weather conditions which cannot be predicted. Accordingly, the Company’s operating results may vary from quarter to quarter depending on weather conditions in applicable areas of the United States and in international regions.

The Company could incur losses on well abandonment and decommissioning projects.

Due to competitive market conditions, a significant portion of the Company’s well abandonment and decommissioning projects are performed on a turnkey or a modified turnkey 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 a turnkey contract can vary from the estimated amount because of changes in offshore conditions, changes in the scope of site clearance efforts required, variations in labor and equipment availability and productivity from the original estimates, 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, environmental and other technical issues could result in significant losses on certain turnkey projects. These variations and risks may result in the Company experiencing reduced profitability or losses on turnkey projects, or on well abandonment and decommissioning work for its Maritech subsidiary.

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The Company faces risks related to its growth strategy.

The Company’s aggressive growth strategy includes both internal growth and growth through acquisitions. Acquisitions require significant financial and management resources both at the time of the transaction and during the process of integrating the newly acquired business into the Company’s operations. Internal growth requires both financial and management resources as well as hiring additional personnel. The Company’s operating results could be adversely affected if it is unable to successfully integrate such new companies into its operations or is unable to hire adequate personnel. The Company may not be able to consummate future acquisitions on favorable terms. Additionally, any such future acquisition transactions may not achieve favorable financial results. Future acquisitions by the Company 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 the Company’s future operating results and financial position.

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

In conjunction with its purchase of oil and gas properties, the Company performs detailed due diligence review processes that it believes are consistent with industry practices. These acquired properties are generally in the later stages of their economic lives and require a thorough review of each property acquired along with its associated abandonment obligations. The process of estimating natural gas and oil 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 natural gas and oil reserves may vary substantially from those initially estimated by the Company. Also, in conjunction with the purchase of certain oil and gas properties, the Company has assumed its proportionate share of the related well abandonment and decommissioning liabilities after performing detailed estimating procedures, analysis and engineering studies. If costs of abandonment and decommissioning are materially greater than original estimates, such additional costs could have an adverse effect on earnings.

The Company’s success depends upon the continued contributions of its personnel, many of whom would be difficult to replace.

The success of the Company will depend on the ability of the Company to attract and retain skilled employees. Changes in personnel, therefore, could adversely affect operating results.

Financial Risks:

Certain of the Company’s businesses are exposed to significant credit risks.

Maritech purchases interests in certain end-of-life oil and gas properties in connection with the operations of the Company's WA&D Division. As the owner and operator of these interests, Maritech is liable for the proper abandonment and decommissioning of the wells, platforms, pipelines and the site clearance related to these properties. The Company has guaranteed a portion of the abandonment and decommissioning liabilities of Maritech, which can be material in amount. In certain instances Maritech will 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. Maritech and the Company are subject to the risk that the previous owner(s) will be unable to make these future payments. Maritech and the Company attempt to minimize this risk by analyzing the creditworthiness of the previous owner(s), and others who may be legally obligated to pay in the event the previous owner(s) are unable to do so, and obtaining guarantees, bonds, letters of credit or other forms of security when they are deemed necessary. 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 as well. 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, the Company could suffer material losses.

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Maritech’s estimates of its oil and gas reserves and related future cash flows may be significantly incorrect.

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 the Company’s 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 & gas reservoir analysis is a subjective process of 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 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, 2003 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 requires that the Company report its 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 the Company’s financial position or results of operations.

The Company’s accounting for oil and gas operations may result in volatile earnings.

The Company accounts for its 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. On a field by field basis, the Company’s 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, the Company is 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.

Legal/Regulatory Risks:

The Company’s operations are subject to extensive and evolving federal, state and local laws and regulatory requirements which increase its operating costs and expose it to potential fines, penalties and litigation.

Laws and regulations strictly govern the Company’s operations and require permits relating to: environmental affairs, health and safety, waste management, and the manufacture, storage, handling, transportation, use and sale of chemical products. The Company’s operation and decommissioning of offshore properties are also subject to and affected by various types of government regulation, including

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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 required permits, 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 the Company and could subject the Company’s handling, manufacture, use, reuse, or disposal of substances or pollutants to increased scrutiny. The Company’s business exposes it to risks such as the potential for harmful substances escaping into the environment and causing damages or injuries, which could be substantial. Although the Company maintains general liability insurance, this insurance is subject to coverage limits and generally excludes coverage for losses or liabilities relating to environmental damage or pollution. The Company maintains limited environmental liability insurance covering named locations and environmental risks associated with contract services for oil and gas operations, refinery waste treatment operations and for its oil and gas production properties. The extent of this coverage is consistent with the Company’s other insurance programs. The Company could be materially and adversely affected by an enforcement proceeding or a claim that was not covered or was only partially covered by insurance.

In addition to increasing the Company’s risk of environmental liability, the promulgation of more rigorous environmental laws, regulations and enforcement policies has accelerated the growth of some of the markets served by the Company. Decreased regulation and enforcement in the future could materially and adversely affect the demand for the types of systems offered by the Company’s process services and well abandonment and decommissioning operations and, therefore, materially and adversely affect the Company’s business.

The Company’s proprietary rights may be violated or compromised, which could damage its operations.

The Company owns 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 taken by the Company to protect its proprietary rights will be adequate to deter misappropriation of these rights. In addition, independent third parties may develop competitive or superior technologies.

The foregoing review of factors pursuant to the Private Securities Litigation Reform Act of 1995 should not be construed as exhaustive. In addition to the foregoing, the Company wishes to refer readers to the Company’s future press releases and filings and reports with the Securities and Exchange Commission for further information on the Company's business and operations and risks and uncertainties that could cause actual results to differ materially from those contained in forward looking statements, such as this report. The Company undertakes no obligation to publicly release the result of any revisions to any such forward looking statements which may be made to reflect the events or circumstances after the date hereof or to reflect the occurrence of unanticipated events.

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Item 2. Properties.

The Company’s properties consist primarily of chemical plants, processing plants, distribution facilities, barge rigs, well abandonment and decommissioning equipment, oil and gas properties and flowback testing equipment. The following table sets forth certain information concerning facilities leased or owned by the Company and facilities from which the Company purchases products under long-term supply contracts as of December 31, 2003. The Company believes its facilities are adequate for its present needs.

(1) Includes real property and buildings unless otherwise noted.

(2) Includes solar evaporation ponds and leased mineral acreage.

(3) In addition, the Company owns an adjacent tract of land that is approximately 2.635 acres in size.

Oil and Gas Properties. The following tables show, for the periods indicated, reserves and operating information related to Maritech’s oil and gas interests in the Gulf of Mexico region. Maritech’s oil and gas properties are included within the Company’s WA&D Segment. See also “Note R – Supplemental Oil and Gas Disclosures” in the Notes to Consolidated Financial Statements.

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The standardized measure of discounted future net cash flows attributable to oil and gas reserves was prepared 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. Maritech’s reserves were estimated by Ryder Scott Company, L.P., independent petroleum engineers. All of Maritech’s reserves are located in U.S. state and federal offshore waters in the Gulf of Mexico region and onshore Louisiana.

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.

Acreage and Wells. At December 31, 2003, Maritech owned interests in the following oil and gas wells and acreage:

Drilling Activity. Maritech drilled no wells during 2003, 2002 or 2001. As of December 31, 2003, and March 15, 2004, there were no wells in the process of being drilled.

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Item 3. Legal Proceedings.

The Company is a named defendant in numerous lawsuits and a respondent in certain other governmental proceedings arising in the ordinary course of business. While the outcome of such lawsuits and other proceedings cannot be predicted with certainty, management does not expect these matters to have a material adverse impact on the Company.

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

No matters were submitted to a vote of security holders of the Company, through solicitation of proxies or otherwise, during the fourth quarter of the year ended December 31, 2003.

PART II

Item 5. Market for the Registrant's Common Equity and Related Stockholder Matters.

Price Range of Common Stock

The Common Stock is traded on the New York Stock Exchange under the symbol “TTI.” As of February 26, 2004, there were approximately 3,240 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, 2003, as reported by the New York Stock Exchange and as adjusted for a 3-for-2 stock split, which was declared and effected in August 2003.

Dividend Policy

The Company has never paid cash dividends on its Common Stock. The Company currently intends to retain earnings to finance the growth and development of its business. Any payment of cash dividends in the future will depend upon the financial condition, capital requirements and earnings of the Company as well as other factors the Board of Directors may deem relevant. The Company 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 August 2003, the Company declared a 3-for-2 stock split, which was effected in the form of a stock dividend to all stockholders of record as of August 15, 2003. See “Note K – Capital Stock” in the Notes to Consolidated Financial Statements attached hereto for a description of this stock split.

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Item 6. Selected Financial Data.

(1) The above selected financial data has been restated to reflect the discontinued operations of Damp Rid, Inc., the Company's Norwegian process service operations and TETRA Micronutrients, Inc.

(2) Revenues for each of the periods presented reflect the reclassification into cost of goods sold of certain product shipping and handling costs, which had previously been deducted from product sales revenues. The reclassified amounts were $7,686 for 2003; $7,736 for 2002; $8,836 for 2001; $7,938 for 2000; and $7,091 for 1999.

(3) Net income (loss) per share and average share outstanding information reflects the retroactive impact of a 3-for-2 stock split, which was effected in the form of a stock dividend to holders of record as of August 15, 2003.

(4) Includes special charge of $4,745 and restructuring charge of $2,320.

(5) Includes gain on the sale of administrative building of $6,731 and gain on sale of business of $29,629.

(6) Excluding goodwill amortization, net income per diluted share, before discontinued operations and cumulative effect of accounting change was $1.08 for 2001, $0.43 for 2000 and $0.73 for 1999.

(7) For the year ended December 31, 2000, the calculation of average diluted shares outstanding excludes 519,000 shares from stock options, the inclusion of which would have had an antidilutive effect on net loss per share.

(1) The above selected financial data has been restated to reflect the discontinued operations of Damp Rid, Inc., the Company’s Norwegian process services operations, and TETRA Micronutrients, Inc.

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

Business Overview

Recent increased activity levels within the oil and gas exploration and production industry have contributed to the Company’s increased revenues and cash flows during 2003, compared to the prior year. Such increased cash flows from operations were primarily applied to the repayment of the Company’s long-term debt, thus providing the Company with significant flexibility and financial strength to capitalize on future opportunities for continued growth. As of December 31, 2003, the Company had total assets of $309.6 million and working capital of $92.1 million, including $16.7 million of cash and temporary investments. The Company’s growth strategy includes expanding its existing businesses — both through internal growth as well as the pursuit of suitable acquisition transactions — and identifying opportunities to establish operations in additional niche oil service markets. Given the Company’s financial position, such acquisitions could be consummated using cash, debt, equity, or any combination thereof.

Demand for the Company’s products and services depends primarily on activity in the oil and gas exploration and production industry in the Gulf of Mexico, Texas, Louisiana and in selected international markets. This activity can be significantly affected by the level of capital expenditures for the exploration and production of oil and gas reserves and for the plugging and decommissioning of abandoned oil and gas properties. These expenditures are influenced strongly by industry expectations about oil and gas prices and the supply and demand for crude oil and natural gas. Strong oil and gas prices during late 2002 and throughout 2003, along with general economic improvement and signs of market recovery have led to increased oil and gas industry spending during 2003, which is expected to continue into 2004. Such increased activity was reflected in the Company’s revenues and operating cash flows during 2003.

The Gulf of Mexico and selected international oil and gas rig counts are leading indicators for the Fluids Division. The maturity of Gulf of Mexico producing fields, oil and gas prices and government regulation are the drivers for the Well Abandonment & Decommissioning Division. Natural gas prices and gas drilling rig counts in North and South America are key indicators for the Testing & Services Division. Gulf of Mexico oil and gas rig counts were down slightly during 2003, averaging 104 rigs compared to an average of 108 during 2002. International rig counts averaged 771 during 2003 compared to 732 during 2002, with a majority of the increase generated in Mexico, where the Company has its most significant international production testing operations. U.S. natural gas drilling increased during 2003 compared to the prior year, with an average gas rig count of 872 (951 average during the fourth quarter of 2003) compared to a 691 average during 2002. Such activity was spurred by higher natural gas prices, with a 2003 average price of approximately $5.50/MMBtu, compared to a 2002 average price of approximately $3.30/MMBtu. The Company anticipates that industry activity and spending will again increase in 2004, with Gulf of Mexico activity increasing more modestly compared to other sectors of the industry. Over the longer term, the Company believes that there will continue to be growth opportunities for the Company’s products and services in both the U.S. and international markets. Such increased activity will be supported by:

• deeper gas drilling operations with more complex completions in the U.S.,

• faster reservoir depletion in the U.S.,

• more rigorous enforcement of environmental and abandonment regulations,

• advancing age of offshore platforms in the U.S.,

• increasing development of oil and gas reserves abroad, and

• increasing future demand for natural gas and oil in the U.S. and abroad.

The Fluids Division generates revenues and cash flows by manufacturing and selling completion fluids and providing filtration and associated products and engineering services to exploration and production companies worldwide. The Fluids Division sells products and services primarily to domestic energy market customers, and these products and services are particularly affected by drilling activity in the Gulf of Mexico. Given the lack of growth in the Gulf of Mexico drilling activity during 2003 compared to 2002, the Fluids Division revenues increased only slightly during the year and earnings decreased. The Company’s management anticipates that worldwide spending on exploration and production activities will increase in 2004 over the prior year, although management believes that Gulf of Mexico activity will increase more modestly than growth rates worldwide. This increase in activity, combined with the Company’s current market position as a major supplier of completion fluids, should provide a modest increase in revenues and cash flows for this Division in 2004.

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The Well Abandonment & Decommissioning Division generates revenues and cash flows by performing well plug and abandonment, pipeline and platform decommissioning and removal and site clearance services for oil and gas companies. In addition, the Division provides electric wireline, workover, engineering and drilling services and is a producer of oil and gas. Services are marketed in the Gulf Coast region of the U.S. including onshore, offshore and in the inland waters. Platform decommissioning and well abandonment operations are driven primarily by MMS regulations and oil and gas company activity levels. Led by the Division’s offshore abandonment and decommissioning operations, divisional revenues and cash flows increased significantly in 2003, compared to the prior year, reflecting an increased market share as well as overall increased well abandonment and decommissioning activity levels in the Gulf of Mexico. Given the advancing age of offshore platforms in the Gulf of Mexico, management expects the Division’s well abandonment and decommissioning activities to again expand in 2004. The Division includes Maritech Resources, Inc. (“Maritech”), a wholly-owned subsidiary formed in 1999 to acquire, produce and exploit oil and gas properties in conjunction with the Company’s well abandonment business. Maritech’s business is strongly affected by oil and gas prices and the availability of producing properties which could be acquired on acceptable terms. Maritech also generated increased revenues and cash flows during 2003, resulting from higher commodity prices and the acquisition of additional producing properties in late 2002 and early 2003.

The Testing & Services Division generates revenues and cash flows by performing flowback pressure and volume testing and other services for oil and gas producers. The primary markets served are Texas, Louisiana, Mississippi, Alabama, offshore Gulf of Mexico, Mexico and Venezuela. The Testing & Services Division also provides technology and services required for separation and recycling of oily residuals generated from petroleum refining, primarily to oil refineries in the United States. Testing & Services Division revenues increased slightly during 2003 compared to the prior year, due to increased oil and gas drilling activity. Management expects additional growth in this Division in 2004, based on anticipated increases in industry drilling and completion activities both domestically and internationally.

Critical Accounting Policies and Estimates

In preparing its consolidated financial statements, the Company makes assumptions, estimates and judgments that affect the amounts reported. The Company periodically evaluates its estimates and judgments 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. The Company’s estimates are based on historical experience and on future expectations that are believed to be 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. Actual results are likely to differ from the Company’s current estimates, and those differences may be material.

Impairment of Long-Lived Assets – The determination of impairment of long-lived assets, including goodwill, is conducted periodically whenever indicators of impairment are present. If such indicators are present, the determination of the amount of impairment is based on the Company’s judgments as to the future operating cash flows to be generated from these assets throughout their estimated useful lives. The oil and gas industry is cyclical, and the Company’s estimates of the period over which future cash flows will be generated, as well as the predictability of these cash flows, can have significant impact on the carrying value of these assets and, in periods of prolonged down cycles, may result in impairment charges.

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. 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

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and gas reserves may vary substantially from those initially estimated by Maritech. Any significant variance in these assumptions could materially affect the estimated quantity and value of proved reserves. Maritech’s oil and gas properties are assessed for impairment in value whenever indicators become evident, with any impairment charged to expense. Maritech purchases oil and gas properties and assumes the related well abandonment and decommissioning liabilities. Many of the transactions have been structured so that the estimated fair market value of the oil and gas reserves acquired and recorded approximately equals the amount of the working interest ownership of the well abandonment and decommissioning liabilities recorded, net of any cash received or paid. Therefore, any difference in the actual amounts of oil and gas reserves produced or decommissioning costs incurred will affect the Company’s anticipated profitability.

Decommissioning Liabilities – The Company estimates 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 uses these estimates to record Maritech’s well abandonment and decommissioning liabilities, net of amounts allocable to joint interest owners and any contractual amount to be paid by the previous owners of the property (referred to as “decommissioning liabilities”). In estimating the decommissioning liabilities, the Company performs 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. 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) the Company’s out-of-pocket costs, the difference is reported as income (or loss) in the period in which the work is performed. The Company reviews the adequacy of its decommissioning liability whenever indicators suggest that either the amount or timing of the estimated cash flows underlying the liability 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 recorded, which in turn would increase the carrying values of the related properties.

Revenue Recognition – The Company generates revenue on certain well abandonment and decommissioning projects from billings under contracts, which are typically of short duration, 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. 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.

Bad Debt Reserves – Reserves for bad debts are calculated on a specific identification basis, whereby the Company estimates whether or not specific accounts receivable will be collected. A significant portion of the Company’s revenues come from oil and gas exploration and production companies. If, due to adverse circumstances, certain customers are unable to repay some or all of the amounts owed the Company, an additional bad debt allowance may be required.

Income Taxes – The Company provides 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 future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. 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 the Company to make certain estimates about its future operations. Changes in state, federal and foreign tax laws, as well as changes in the Company’s financial condition, could affect these estimates.

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Results of Operations

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

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2003 Compared to 2002

Consolidated Comparisons

Revenues and Gross Profit – Total consolidated revenues for the year ended December 31, 2003 were $318.7 million compared to $238.4 million during 2002, an increase of 33.7%. Each of the Company’s operating divisions reflected an increase in revenues during 2003 compared to the prior year. Consolidated gross profit for 2003 was $73.8 million compared to $54.0 million during 2002, an increase of 36.7%. Overall, gross profit was 23.2% of revenues during 2003 compared to 22.7% of revenues during 2002.

General and Administrative Expenses – Consolidated general and administrative expenses increased $7.8 million to $44.7 million during 2003 compared to $36.9 million during the prior year, an increase of 21.1%. This increase was primarily caused by a $3.2 million increase in payroll and incentive compensation and a $3.1 million increase in professional fees consistent with the Company’s growth and with industry trends. The increase in professional fees was also due to unusually low professional fees during 2002 due to the recovery of $1.1 million of legal fees associated with a long-standing lawsuit. Also, beginning in 2003 the Company reflected $1.4 million of accretion expenses related to asset retirement obligations in accordance with Statement of Financial Accounting Standards (“SFAS”) 143 rules. Despite these increases in general and administrative costs, as a percentage of revenues, general and administrative expenses decreased to 14.0% of revenues during 2003 compared to 15.5% of revenues during 2002.

Other Income & Expense – Other income and expense was $0.6 million of income for the current year compared to $0.1 million of income in the prior year. This change is primarily due to $0.7 million of gains on sales of property, plant and equipment during 2003, compared to a $0.2 million loss on such disposals in the prior year.

Interest Expense and Income Taxes – Net interest expense decreased from $2.6 million during 2002 to $0.3 million during the current year, a decrease of 88.2%, due to the Company’s reduction and eventual payment of the balance outstanding under its bank credit facility during 2003. Also, prior to paying the remaining balance of the facility, interest expense was reflected at lower interest rates during 2003 compared to the prior year’s expense, due partly to the Company’s 6.4% interest rate swap contract, which expired after the end of 2002. The Company’s average interest rate during 2003 was approximately 3%. The provision for income taxes was $9.9 million in 2003, an increase of $4.8 million, as a result of increased earnings compared to the prior year. The effective tax rate for the year decreased to 33.9% during 2003 compared to 35.3% in 2002, due primarily to a reduction in the impact of international income taxes.

Net Income – Net income before discontinued operations and cumulative effect of change in accounting principle was $19.4 million during 2003 compared to $9.4 million during 2002. Net income per diluted share before discontinued operations and cumulative effect of change in accounting principle was $0.84 with 23,005,108 shares outstanding compared to $0.42 with 22,342,952 shares outstanding.

In September 2003, the Company sold its subsidiary, Damp Rid, Inc., and made the decision to discontinue its Norwegian process services operation. The Company recorded a gain of $4.9 million from the sale of Damp Rid, net of taxes of $2.4 million, and a loss of $1.3 million for the asset impairment related to the future disposal of the Norwegian process services facility, net of $0.7 million tax benefit. Net income from discontinued operations per diluted share during 2003 was $0.16 compared to a net loss of $0.02 in the prior year, primarily due to the net gain on disposal of Damp Rid.

In July 2001, the Financial Accounting Standards Board released SFAS 143, “Accounting for Asset Retirement Obligations,” which requires that costs associated with the retirement of tangible long-lived assets be recorded as part of the carrying value of the asset when the obligation is incurred. The Company adopted the provisions of SFAS 143 on January 1, 2003. Prior to 2003, the Company expensed the costs of retiring its non-oil and gas properties at the time of retirement. In addition, prior to 2003 the Company recorded the retirement obligations associated with its oil and gas properties at an

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undiscounted fair market value. The effect of adopting SFAS 143 was to record a charge of $1.5 million ($0.06 per diluted share), net of taxes of $0.8 million, to expense the costs of retirement obligations associated with the Company’s existing long-lived assets and to accrete the liability to its present value as of January 1, 2003.

Net income for the year ended December 31, 2003 was $21.7 million compared to $8.9 million in the prior year, an increase of $12.8 million or 143.4%. Net income per diluted share was $0.94 with 23,005,108 shares outstanding compared to $0.40 with 22,342,952 shares outstanding.

Divisional Comparisons

Fluids Division – Fluids Division revenues increased $2.4 million to $119.4 million during 2003 compared to $117.1 million during the prior year, an increase of 2.0%, primarily due to an approximate $3.1 million increase from higher product sales volumes and approximately $2.5 million from pricing improvements. The Division also reflected increased revenues of approximately $1.6 million, resulting from improved utilization of filtration service equipment and an estimated $1.0 million from fluids product market share gains. These increases domestically were largely offset, however, by decreases in international fluids revenues, particularly in the United Kingdom and Norway, where decreased North Sea activity contributed to a revenue decrease of $6.0 million compared to the prior year.

Despite the overall revenue increase, gross profit for the Fluids Division decreased by $4.7 million to $27.2 million, a 14.7% decrease. Gross profit percentage for the Fluids Division decreased from 27.2% of revenues during 2002 to 22.8% of revenues during 2003, as approximately $4.7 million of increases in product and related costs, including feedstocks, transportation, utilities, repair and maintenance, payroll and insurance more than offset $2.5 million of pricing increases. Gross profits were also lower by approximately $0.5 million, due to lower-margin product sales in certain operating areas. Fluids Division profitability was particularly affected by a decline in activity related to the decrease in the average Gulf of Mexico rig count during 2003 compared to 2002. Future revenue and profit levels will continue to be affected by overall energy market activity levels. The above mentioned decrease in North Sea activity also resulted in an additional gross profit decrease of approximately $1.7 million related to the Division’s international operations.

Fluids Division income before taxes decreased by $4.0 million to $14.0 million during 2003, a 22.2% decrease compared to the prior year, due to the above mentioned $4.7 million decrease in gross profit, offset partially by approximately $0.7 million in decreased overall administrative costs for the Division.

Well Abandonment & Decommissioning Division – The Well Abandonment & Decommissioning (“WA&D”) Division reflected revenues of $153.5 million during 2003 compared to $78.6 million during the prior year, an increase of $74.9 million, or 95%. The largest revenue increase was generated by the Division’s offshore abandonment and decommissioning business, with an increase of $42.1 million, which captured an increased share of the overall increased activity levels in the Gulf of Mexico and, in particular, benefited from the timing during 2003 of several large projects for specific customers. These operations are driven primarily by the maturity of the Gulf of Mexico fields, and the age of the platforms and structures in the Gulf. Increased overall Gulf of Mexico activity levels should continue as existing Gulf of Mexico fields continue to deplete, and the number of aging offshore platforms requiring decommissioning increases. The Division’s inland water well abandonment operations also reflected increased activity early in the year, with a $3.2 million increase (despite lower rates for its services due to competition) and its land operations contributed a $4.5 million increase, which includes approximately $2.2 million of added revenues from an acquisition during 2002. Also contributing to the increased WA&D Division revenues was its Maritech oil and gas production subsidiary, which contributed approximately $21.4 million of additional production revenues related to producing properties acquired in late 2002 and early 2003, and an approximate $3.9 million increase in revenues from higher oil and gas commodity prices during 2003.

WA&D Division gross profit also rose significantly, increasing from $11.0 million in 2002 to $35.4 million in 2003, an increase of $24.4 million, or 222.2%. Gross profit percentage for the WA&D Division increased to 23.1% of revenues from 14.0% of revenues in the prior year. These gross profit increases were also led by the Division’s offshore abandonment and decommissioning operations, which reflected a

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gross profit increase of $14.7 million, primarily from the successful completion of several large projects and a $1.1 million gain from the settlement of an insurance claim for the prior year’s damages to the Company’s heavy lift barge. The Division’s inland water plug and abandonment and rig operations reflected approximately a $0.1 million decrease in gross profit compared to the prior year, and have been negatively affected during the second half of 2003 by lower rates and reduced activity related to the recent and pending ownership changes of many inland water properties. The Company has taken certain steps to reduce the cost structure of its inland water operations. Maritech’s gross profit increased approximately $7.3 million due to the above mentioned producing property acquisitions as well as approximately $3.9 million from increased commodity prices. Such increases more than offset the $1.7 million charge for Maritech’s relinquishment of an oil and gas property during the year.

Income before taxes for the WA&D Division increased significantly to $23.5 million, a $20.3 million or 628.9% increase from the prior year. The above mentioned increase in gross profit of $24.4 million was offset partially by approximately $3.3 million of Division personnel infrastructure cost increases, consistent with the increased levels of activity. The Division also reflected $1.2 million of expense related to FAS 143 accretion for Maritech’s abandonment and decommissioning liabilities beginning in 2003.

Testing & Services Division – Testing & Services Division revenues increased $2.6 million during the current year, increasing from $44.5 million during 2002 to $47.1 million, an increase of 5.9%, largely due to a $2.8 million revenue increase from the domestic production testing operations, which have recently reflected increased drilling and completion activity in the Texas and Louisiana areas. This increase in domestic production testing activity more than offset a $0.6 million decline in production testing revenues in Mexico and Venezuela. Revenues for process services increased $0.5 million during 2003 compared to the prior year, due to higher demand and increased processed volumes.

Gross profit for the Testing & Services Division was $11.2 million during 2003 and 2002. Increased domestic production testing activity was more than offset by increased costs and the lower overall utilization of the operation’s resource base, resulting in a $0.5 million decrease in gross profit for this business. The increased process services demand resulted in throughput efficiencies which resulted in increased gross profit of approximately $0.4 million. Division gross profit as a percentage of revenues decreased from 25.2% to 23.8%.

Testing & Services Division income before taxes decreased $0.7 million, from $7.1 million to $6.4 million, a 10.1% decrease compared to the prior year. Administrative costs for professional services increased during 2003, compared to the prior year, due to the recovery during 2002 of approximately $1.1 million of legal fees associated with a long standing lawsuit. Other administrative cost increases related to increased personnel infrastructure costs of approximately $0.3 million, primarily related to the domestic production testing operations. Such increases were partially offset by $0.7 million of gains on sales of production testing equipment during the year.

Corporate Overhead – The Company includes in corporate overhead general and administrative expense, interest income and expense and other income and expense. Such expenses and income are not allocated to the Company’s business segments, as they relate to the Company’s general corporate activities. Corporate overhead increased from $13.8 million in 2002 to $14.6 million during 2003, a $0.8 million increase compared to the prior year. This increase was primarily caused by approximately $2.3 million of increased corporate salary and incentive compensation expenses, $1.1 million of increased professional services and public company expenses, and $0.3 million of increased corporate insurance expense. Such increases were partially mitigated by a $2.4 million decrease in interest expense, as a result of the decrease in long-term debt outstanding, and an approximate $1.1 million decrease in corporate insurance claims and other fringe benefit costs during the year.

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2002 Compared to 2001

Consolidated Comparisons

Revenues and Gross Profit – Consolidated revenues for the year ended December 31, 2002 were $238.4 million, down $64.0 million or 21.2% from the prior year total of $302.4 million. All operating divisions of the Company experienced a drop in their revenues, as 2001 represented a peak activity year for the oil and gas industry, and in 2002 the industry experienced a significant downturn in rig count activity resulting from decreased oil and gas prices. Gross profit for the year was $54.0 million compared to $81.0 million in the prior year, a decrease of $27.0 million or 33.3%. The decrease is principally the result of the drop in revenues of $64.0 million during the year combined with a decrease in gross margin percentage from 26.8% to 22.7%.

General and Administrative Expenses – Consolidated general and administrative expenses were $36.9 million in 2002 compared to $40.8 million in the prior year, a decrease of $3.8 million or 9.4%. However, general and administrative expenses as a percent of revenue increased to 15.5% in 2002 from 13.5% in the prior year, due to decreased revenues. Reductions of $4.9 million in incentive compensation, lower legal expenses as a result of the recovery of legal costs of $1.1 million associated with a long standing suit settled in 2002, and $0.6 million of reduced sales and marketing expenses accounted for most of the decrease. These reductions were partially offset by $1.1 million of costs for additional infrastructure in information technology and other corporate departments necessary to support the future growth of the Company.

Other Income & Expense – Other income and expense was $0.1 million of income for the year compared to $0.4 million of expense in the prior year. This change is a result of state tax refunds offset by losses on the disposal of fixed assets, loan fees and various foreign non-income taxes in excess of the prior year amounts.

Interest Expense and Income Taxes – Net interest expense for the year was $2.6 million compared to $2.1 million in the prior year. The increase was primarily a result of the interest expense allocation to discontinued operations in the first three quarters of 2001. Actual interest paid decreased $0.2 million from the prior year due to a significant reduction in average long-term debt. The provision for income taxes was $5.1 million in 2002, a decrease of $9.0 million as a result of reduced earnings from the prior year. The effective tax rate for the year was 35.3% versus 37.4% in 2001, due primarily to a reduction in state income tax expense and the utilization of general business credits.

Net Income – Net income before discontinued operations was $9.4 million during 2002 compared to $23.6 million during 2001. Net income per diluted share before discontinued operations was $0.42 with 22,342,952 shares outstanding compared to $1.06 with 22,255,679 shares outstanding. Discontinued operations include the operations of Damp Rid, Inc. and the Company’s Norwegian process services operations. Income (loss) per diluted share from discontinued operations was a loss of $0.02 during 2002 compared to an income of $0.01 during 2001. Net income for the year was $8.9 million compared to $23.9 million in the prior year. For 2002, net income per diluted share was $0.40 on 22,342,952 average diluted shares outstanding compared to $1.07 per diluted share on 22,255,679 average diluted shares outstanding in 2001, or $1.09 excluding goodwill amortization.

Divisional Comparisons

Fluids Division – The Fluids Division reported revenues of $117.1 million, a decrease of $33.1 million or 22.0% from the prior year. The Division’s domestic revenues decreased $20.0 million, reflecting the drop of 26.4% in the average offshore Gulf of Mexico rig count from 2001, while the Division’s international revenues decreased $9.7 million, reflecting the drop of 12.2% in the average rig count activity for certain international regions in which the Division operates. Weather conditions in the Gulf of Mexico in the fourth quarter contributed approximately $1.2 million to the revenue decrease, as did political events in Venezuela, which were the main cause of a $1.0 million decline in revenues from that country.

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Fluids Division gross profit decreased 10.7%, or $3.8 million, from $35.7 million to $31.9 million, as a result of the lower revenues caused by the factors described above, which consequently reduced gross profit by $8.2 million. Helping to offset this decline was an improvement in this Division’s gross profit percentage from 23.7% to 27.2%, as improved pricing in select areas contributed an approximate $1.4 million increase in gross profit, and a favorable mix of product and service revenues generated an approximate $3.1 million increase in gross profit compared to the prior year.

Fluids Division income before taxes decreased $3.2 million, or 15.2%, to $18.0 million compared to the prior year. This decrease primarily reflects an approximate $8.0 million decrease in income from lower demand, offset by the approximate $4.5 million increase in income from pricing and more favorable mix of higher-margin product and service revenues.

Well Abandonment & Decommissioning Division – The WA&D Division reported revenues of $78.6 million, a decrease of $20.0 million or 20.3% from the prior year. The Division’s heavy lift barge, the Southern Hercules, was out of service for approximately ten months of the year for renovation and repair, contributing approximately $1.0 million to the decrease in revenues. The most significant decrease, however, was due to the September and October Gulf of Mexico hurricanes and earlier tropical storms, which contributed to lower utilization of the inland water and offshore well abandonment rigs and equipment for much of the second half of the year. The reduced utilization resulted in an estimated revenue decrease of $15.9 million as compared to the same period for the prior year. In addition, revenues for the Division’s exploitation and production company, Maritech, were $1.2 million lower than the previous year, a 9% reduction. This decrease was due primarily to an estimated $0.9 million revenue decrease resulting from shut-in production due to hurricane damage as well as an approximate $3.4 million decrease in revenues from lower commodity prices received during the year. The Division’s electric wireline business saw its equipment utilization drop significantly from the prior year, which was the primary cause of a $2.5 million revenue decrease, as the lower rig count activity contributed to fewer projects in addition to putting downward pressure on pricing for services.

WA&D Division gross profit declined $13.0 million during 2002 to $11.0 million, a 54.1% decrease from the prior year, and divisional gross profit as a percentage of revenues decreased from 24.3% to 14.0%. The lower utilization of the Division’s rig fleet and heavy lift barge in addition to the costs and downtime related to the Gulf of Mexico storms in the second half of the year contributed approximately $7.2 million to the decline. In the first quarter, the Division’s heavy lift barge (the Southern Hercules) was involved in a storm-related accident that resulted in significant downtime and repair expense, contributing approximately $0.7 million to the decline in gross profit. During this downtime period, the Company elected to perform substantial upgrades and capital improvements to the Southern Hercules before returning it to service, which was anticipated in the second quarter of 2003. During 2003, the Company received proceeds from an insurance claim for a significant portion of its repair costs; however, the repair costs related to the Southern Hercules were expensed as incurred in 2002. Decreased electric wireline equipment utilization further reduced Division gross profit by approximately $1.5 million. The Division also increased its infrastructure in the decommissioning and well abandonment businesses to accommodate the higher activity associated with the acquisition opportunities and the management of Maritech oil and gas properties, resulting in an approximate $0.8 million reduction in gross profit. Maritech’s gross profit was lower than the previous year due, in part, to 34.5% lower average realized commodity prices in 2002 resulting in a decrease in revenues of approximately $3.4 million, and a further decrease of approximately $1.1 million from higher downtime, repair expenses and logistics costs related to the Gulf of Mexico storms.

WA&D Division income before taxes decreased $13.2 million to $3.2 million, an 80.3% decrease from the prior year, due primarily to an $8.2 million decrease from lower equipment utilization, $1.5 million from heavy lift barge downtime and repair expenses, $3.4 million from lower commodity prices and $1.1 million from lost production and costs related to storms. The previously mentioned increased personnel infrastructure for the decommissioning and well abandonment businesses included administrative costs associated with the acquisition opportunities and the management of Maritech oil and gas properties as well, resulting in a total decrease in earnings of approximately $1.2 million.

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Testing & Services Division – Revenues for the Testing & Services Division were $44.5 million, a decrease of $11.4 million or 20.3% from the prior year. Revenues for the domestic production testing group decreased by $7.7 million, a 25.4% decrease from the prior year, primarily due to the drop in the U.S. average gas rig count of 26%. The Division acquired the assets of Precision Well Testing Company in July, 2002, bolstering the offshore Gulf of Mexico equipment fleet and increasing revenue by approximately $0.7 million.

Testing & Services Division gross profit decreased 47.6% to $11.2 million, a $10.2 million decrease from the prior year, with a decrease in gross profit percentage from 38.2% to 25.2%. Lower gas drilling activity contributed to much of the decline in the production testing business, where underutilized equipment and personnel reduced margins by approximately $7.1 million domestically and $2.8 million internationally.

Testing & Services Division income before taxes decreased $10.1 million to $7.1 million, a 58.6% decrease compared to the prior year, primarily due to the above mentioned decreases in overall production testing business activity, which resulted in an approximate $10.1 million decrease in earnings. The Division’s earnings for the year also reflected a decrease in the Division’s general and administrative expenses compared to 2001, primarily due to lower legal expenses as a result of recovery of legal costs of $1.1 million associated with a long standing suit settled in 2002.

Corporate Overhead – The Company includes in corporate overhead general and administrative expense, interest income and expense and other income and expense. Such expenses and income are not allocated to the Company’s business segments, as they relate to the Company’s general corporate activities. Corporate overhead decreased from $17.2 million in the prior year to $13.8 million during 2002, a decrease of $3.4 million or 19.8%. This decrease in general corporate overhead was primarily due to a $4.5 million reduction in corporate incentive compensation expenses and a $0.6 million decrease in corporate legal expenses, which was offset somewhat by an increase of $1.1 million of expenses for additional infrastructure in information technology and a higher net interest expense of $0.4 million.

Liquidity and Capital Resources

The Company has historically funded its growth and working capital needs primarily from the cash flows from its three operating divisions and its revolving line of credit. During the year ended December 31, 2003, the Company generated a total of approximately $36.4 million of cash flow from operating activities. This cash flow was supplemented by an additional $18.0 million of net proceeds from the sale of the Company’s Damp Rid, Inc. subsidiary during September 2003. This cash flow was used to repay the remaining outstanding balance of its existing bank line of credit. At December 31, 2003, the Company had working capital of approximately $92.1 million and unrestricted cash and temporary investments of approximately $16.7 million. During the three-year period ended December 31, 2003, the Company generated approximately $119.4 million of net cash flow from operating activities, which it used to fund the purchase of approximately $57.4 million of capital expenditures and $19.6 million of acquisitions. An additional $57.6 million, net of borrowings, was used to retire long-term debt during this three year period.

Operating Activities – Net cash provided by operating activities was $36.4 million during 2003 compared to $24.3 million in 2002, an increase of $12.1 million. This increase was primarily due to the growth in revenues and profitability from the Company’s WA&D Division which resulted from higher utilization and activity levels as well as from increased oil and gas production cash flows. Increased overall operating activities during the fourth quarter of 2003 compared to the prior year resulted in an increase in accounts receivable at December 31, 2003 compared to the prior year balance. The Company has historically generated net operating cash flow from each of its three operating divisions. Future operating cash flows are largely dependent upon the level of oil and gas industry activity, particularly in the Gulf of Mexico region of the U.S. While the Company expects that such industry activity will increase in 2004, the resulting net cash flow will also be affected by the impact of competition, the prices for its products and services, and the operating and administrative costs required to deliver its products and services.

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In addition to the above factors, future operating cash flow will also continue to be affected by the timing of expenditures required for the plugging, abandonment and decommissioning of Maritech’s oil and gas properties. The third party market value, including an estimated profit, of Maritech’s decommissioning liability was $31.4 million as of December 31, 2003, and the cash outflow necessary to extinguish this liability is expected to occur over several years, shortly after the end of each property’s productive life. Such timing is estimated based on the future oil and gas production cash flows as indicated by the Company’s oil and gas reserve estimates and, as such, are imprecise and subject to change due to changing commodity prices, reserve revisions and other factors. The Company’s decommissioning liability is net of amounts allocable to joint interest owners and any contractual amount to be paid by the previous owners of the properties.

Investing Activities – Cash capital expenditures for the year ended December 31, 2003 were $11.4 million. Approximately $6.9 million was invested in the WA&D Division primarily related to development expenditures on Maritech’s offshore oil and gas properties. Also, the Division invested in additional equipment assets, particularly for its plug and abandonment and wireline businesses. The Fluids Division incurred approximately $2.3 million of capital expenditures for the procurement of plant additions, particularly related to its chlorides manufacturing business. Approximately $1.9 million was invested in the Testing & Services Division, a significant portion of which went to replace and enhance the production testing equipment fleet. The Company also invested additional capital in its process services operations to enhance its oily residual separation business. The remaining capital expenditures were used to support general corporate activities. During 2003, the Company disposed of certain production testing assets, oil and gas properties and other various assets for proceeds of $2.2 million, in addition to the sale of its Damp Rid subsidiary.

During the first quarter of 2003, Maritech purchased oil and gas producing properties in four separate transactions. Maritech purchased oil and gas producing assets in offshore Gulf of Mexico and onshore Louisiana locations in exchange for the assumption of approximately $10.2 million in decommissioning liabilities. These oil and gas producing assets were purchased for approximately the value of the decommissioning liabilities assumed, less cash received of $2.7 million. The Company continues to pursue the purchase of additional producing oil and gas properties as part of its strategy to support its WA&D Division. While the purchases of such properties are primarily funded through the assumption of the associated decommissioning liabilities, the transactions may also involve the payment or receipt of cash at closing.

The Company expects to continue its ongoing capital expenditure program in order to grow and expand its existing operations in each of its operating divisions. The Company expects to fund such capital expenditures in 2004 through cash flows from operations. The vast majority of the Company’s future cash capital expenditure plans is discretionary, however, and may be postponed or cancelled as conditions change. In addition, the Company’s strategy includes the pursuit of suitable acquisition transactions and the identification of opportunities to establish operations in additional niche oil service markets. Given the Company’s financial position, such acquisitions could be consummated using cash, debt, equity, or any combination thereof. To the extent the Company consummates a significant transaction, all or a portion of the purchase consideration may be funded with cash, which could significantly alter the Company’s liquidity position. Other commercial commitments of the Company as of December 31, 2003 include letters of credit of $9.8 million, all of which will expire within one year.

Financing Activities – To fund its capital and working capital requirements, the Company supplements its cash flow from operating activities as needed from its general purpose, secured, prime rate/LIBOR-based revolving line of credit with a bank syndicate led by Bank of America. In September 2002, the Company amended its credit facility, expanding its available line of credit to $95 million. This agreement matures in December 2004, carries no amortization, and is secured by accounts receivable and inventories. The agreement permits the Company to execute up to $20 million of capital leases and $50 million of unsecured senior notes, and there are no limitations or restrictions on operating leases or unsecured nonrecourse financing. The Company’s credit facility is subject to common financial ratio covenants and dollar limits on the total amount of capital expenditures and acquisitions the Company may undertake in any given year without receiving a waiver from the lenders. The Company pays a commitment fee on unused portions of the line and a LIBOR-based interest rate on any outstanding balance, plus an additional 1.0% to 2.0% above the LIBOR-based interest rate based upon changes in a

28

designated debt ratio. The Company is not required to maintain compensating balances. The covenants also include certain restrictions on the Company for the sale of assets. As of December 31, 2003, the Company has $9.8 million in letters of credit, with no balance of long-term debt outstanding, against a $95 million line of credit, leaving a net availability of $85.2 million. The Company believes this credit facility will meet its foreseeable capital and working capital requirements through December 2004, and plans to enter into a new credit facility agreement during the year to extend and possibly expand its financing arrangements beyond 2004.

The Company’s access to its revolving credit line is dependent upon its ability to comply with certain financial ratio covenants in the credit agreement. Significant deterioration of these 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. The credit facility agreement also includes cross-default provisions relating to any other indebtedness greater than $5 million. 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 Company’s credit facility. The Company is in compliance with all covenants and conditions of its credit facility as of December 31, 2003. The Company’s continuing ability to comply with these financial covenants centers largely upon its ability to generate adequate cash flow. Historically, the Company’s financial performance has been more than adequate to meet these covenants, and the Company expects this trend to continue. During 2003, the Company paid all of the $37.0 million bank facility balance outstanding as of December 31, 2002. As of March 15, 2004, the Company continues to have no balance outstanding pursuant to the credit facility.

In addition to the aforementioned revolving credit facility, the Company funds its short-term liquidity requirements from cash generated by operations, short-term vendor financing and, to a minor extent, from leasing with institutional leasing companies. The Company believes its principal sources of liquidity, cash flow from operations, revolving credit facility and other traditional financing arrangements are adequate to meet its current and anticipated capital and operating requirements through at least December 2004.

In January 2004, the Company’s Board of Directors authorized the repurchase of up to $20 million of its common stock. As of March 15, 2004, the Company has purchased 34,000 shares of its common stock at a price of approximately $0.8 million pursuant to this authorization. The Company has historically repurchased its stock at times when it felt that its stock price was undervalued in relation to its peer group. During 2003, the Company did not repurchase any shares of its stock. During the year 2002, the Company repurchased 151,800 shares at a cost of $2.0 million. The Company also received $4.3 million during 2003 from the exercise of stock options by employees.

Contractual Cash Obligations – The table below recaps the Company’s contractual cash obligations as of December 31, 2003:

(1) Decommissioning liabilities related to oil and gas properties generally must be satisfied within twelve months after the property’s lease expires. Lease expiration occurs six months after the last producing well on the lease ceases production. The Company has 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 estimated fair values as of December 31, 2003.

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Off-Balance Sheet Arrangements – An “off-balance sheet arrangement” is defined as any contractual arrangement to which an entity that is not consolidated with the Company is a party, under which the Company has, or in the future may have:

• Any obligation under a guarantee contract that requires initial recognition and measurement under U.S. GAAP;

• 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 the Company in an unconsolidated entity that provides financing, liquidity, market risk or credit risk support to the Company, or engages in leasing, hedging or research and development services with the Company.

As of December 31, 2003 and 2002, the Company had no “off-balance sheet arrangements” that may have a current or future material affect on the Company’s consolidated financial condition or results of operations.

Commitments and Contingencies – The Company and its subsidiaries are named defendants in several lawsuits and respondents in certain governmental proceedings arising in the ordinary course of business. While the outcomes of lawsuits or other proceedings against the Company cannot be predicted with certainty, management does not expect these matters to have a material impact on the financial statements.

In the normal course of its Fluids Division operations, the Company enters into agreements with certain manufacturers of various raw materials and finished products. Some of these agreements require the Company to make minimum levels of purchases over the term of the agreement. Other agreements require the Company to purchase the entire output of the raw material or finished product produced by the manufacturer. The Company’s purchase obligations under these agreements apply only with regard to raw materials and finished product that meet specifications set forth in the agreements. The Company recognizes a liability for the purchase of such product at the time it is received by the Company.

Related to its acquired interests in oil and gas properties, Maritech estimates the third party fair market values (including an estimated profit) to plug and abandon wells, decommission the pipeline and platforms and clear the sites, and uses these estimates to record Maritech’s decommissioning liability, 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, 2003, Maritech’s decommissioning liability is net of approximately $35.6 million for such future reimbursements from these previous owners.

A subsidiary of the Company, 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 at the Fairbury facility under the Consent Order; however, the current owner of the Fairbury facility is responsible for costs associated with the closure of that facility. The Company has reviewed estimated remediation costs prepared by its 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 its review and discussions with its third-party consultants, the Company established a reserve for such remediation costs of $0.6 million at December 31, 2003 and 2002. The reserve will be further adjusted as information develops or conditions change.

The Company has not been named a potentially responsible party by the EPA or any state environmental agency.

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Recently Issued Accounting Pronouncements – In January 2003, the FASB issued Interpretation No. 46, “Consolidation of Variable Interest Entities, an Interpretation of Accounting Research Bulletin No. 51.” Interpretation No. 46 requires a company to consolidate a variable interest entity (“VIE”) if the company has a variable interest (or combination of variable interests) that is: exposed to a majority of the entity’s expected losses if they occur, will receive a majority of the entity’s expected residual returns if they occur, or both. In addition, more extensive disclosure requirements apply to the primary and other significant variable interest owners of the VIE. This interpretation applied immediately to VIEs created after January 31, 2003, and to VIEs in which an enterprise obtains an interest after that date. It is also effective for the first fiscal year or interim period beginning after December 15, 2003, to VIEs in which a company holds a variable interest that was acquired before February 1, 2003. The Company does not have any VIEs; therefore, the issuance of this interpretation will not have any material impact on the Company’s financial statements.

The SEC has recently questioned the application of certain provisions of SFAS No. 141 and SFAS No. 142 to companies in the extractive industries. Specifically, the accounting for and disclosure of mineral rights held under lease and other contractual arrangements has been questioned in various comment letters issued to companies in the oil and gas industry. The issue is whether SFAS No. 142 requires companies to classify the costs of mineral rights held under lease or other contractual arrangements associated with extracting oil and gas as intangible assets in the balance sheet, apart from other capitalized oil and gas property costs, and provide specific footnote disclosures. Historically, the Company has included the costs of such mineral rights associated with its oil and gas exploitation and production as a component of oil and gas properties. If it is ultimately determined that SFAS No. 142 requires oil and gas companies to classify costs of mineral rights held under lease or other contractual arrangements associated with extracting oil and gas as a separate intangible assets line item on the balance sheet, a significant amount of capitalized costs would be reclassified out of oil and gas properties, net of accumulated depletion, depreciation and amortization, pursuant to this requirement.

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

Interest Rate Risk

Any balances outstanding under the Company’s floating rate portion of its bank credit facility are subject to market risk exposure related to changes in applicable interest rates. These instruments carry interest at an agreed-upon percentage rate spread above LIBOR. At December 31, 2003, the Company had no balance outstanding under its credit facility.

The following table sets forth, as of December 31, 2003 and 2002, the Company’s principal cash flows for its long-term debt obligations (which bear a variable rate of interest) and weighted average effective interest rates by expected maturity dates. Additionally, the table sets forth the notional amounts and weighted average interest rates of the Company’s interest rate swaps by expected maturity date.

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Expected Maturity Date

Fair

2002

2003

2004

2005

2006

Thereafter

Total

Market Value

(In Thousands, Except Per Share Amounts)

As of December 31, 2003

Long-term debt

$–

$–

$–

$–

$–

$–

$–

$–

Weighted average interest rate

–

–

–

–

–

–

–

–

Variable to fixed swaps

–

–

–

–

–

–

–

–

Fixed pay rate

–

–

–

–

–

–

–

–

Variable receive rate

–

–

–

–

–

–

–

–

As of December 31, 2002

Long-term debt

$–

$–

$37,000

$–

$–

$–

$37,000

$37,000

Weighted average interest rate

–

–

3.060%

–

–

–

3.060%

–

Variable to fixed swaps

40,000

–

–

–

–

–

–

476

Fixed pay rate

6.445%

–

–

–

–

–

–

–

Variable receive rate

1.890%

–

–

–

–

–

–

–

Commodity Price Risk

The Company has market risk exposure in the pricing applicable to its 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 price volatility is expected to continue. The Company’s 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 its oil and gas production. The Company is exposed to the volatility of oil and gas prices for the portion of its oil and gas production that is not hedged. Net of the impact of the crude oil hedges described below, each $1 per barrel decrease in future crude oil prices would result in a decrease in earnings of $126,000. Each decrease in future gas prices of $0.10 per Mcf would result in a decrease in earnings of $148,000.

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, 2003 and 2002, the Company had the following cash flow hedging swap contracts outstanding relating to a portion of Maritech’s oil and gas production:

Each oil and gas swap contract uses WTI NYMEX and NYMEX Henry Hub as the referenced commodity, respectively. The market value of the Company’s oil swaps at December 31, 2003 is $546,000, which is reflected as a current liability. A $1 increase in the future price of oil would result in the market value of the combined oil derivative liability increasing by $331,000. The market value of the Company’s natural gas swap at December 31, 2003 is $704,000, which is also reflected as a current liability. A $0.10 per MMbtu increase in the future price of natural gas would result in the market value of the derivative liability increasing by $36,000.

32

The market value of the Company’s oil swap at December 31, 2002 was $212,000, which was reflected as a current liability. A $1 increase in the future price of oil would result in the market value of the derivative liability increasing by $168,000.

The Company has no financial instruments subject to foreign currency fluctuation at December 31, 2003.

Item 8. Financial Statements and Supplementary Data.

The financial statements and supplementary data of the Company and its 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.

There is no disclosure required by Item 304 of Regulation S-K in this report.

Item 9A. Controls and Procedures.

The Company’s chief executive officer and chief financial officer have evaluated the Company’s disclosure controls and procedures as of December 31, 2003, the end of the period covered by this report. Based upon that evaluation, the Company’s chief executive officer and chief financial officer concluded that the Company’s disclosure controls and procedures were effective to ensure that information required to be disclosed by the Company in the reports that it files or submits under the Securities Exchange Act is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms.

There were no changes in the Company’s internal control over financial reporting during the fiscal quarter ending December 31, 2003 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

33

PART III

Item 10. Directors and Executive Officers of the Registrant.

The information required by this Item as to the directors and executive officers of the Company is hereby incorporated by reference from the information appearing under the captions “Proposal No. 1: Election of Directors,” “Information about Continuing Directors,” “Executive Officers,” “Section 16(a) Beneficial Ownership Reporting Compliance,” and “Board Meetings and Committees” in the Company’s definitive proxy statement, which involves the election of directors and is to be filed with the SEC pursuant to the Securities Exchange Act of 1934 as amended (the “Exchange Act”) within 120 days of the end of the Company’s fiscal year on December 31, 2003.

Item 11. Executive Compensation.

The information required by this Item as to the management of the Company is hereby incorporated by reference from the information appearing under the captions “Director Compensation” and “Executive Compensation” in the Company’s definitive proxy statement, which involves the election of directors and is to be filed with the SEC pursuant to the Exchange Act within 120 days of the end of the Company’s fiscal year on December 31, 2003. Notwithstanding the foregoing, in accordance with the instructions to Item 402 of Regulation S-K, the information contained in the Company’s proxy statement under the subheading “Management and Compensation Committee Report” and “Performance Graph” shall not be deemed to be filed as part of or incorporated by reference into this Form 10-K.

Item 12. Security Ownership of Certain Beneficial Owners and Management.

The information required by this Item as to the ownership by management and others of securities of the Company is hereby incorporated by reference from the information appearing under the caption “Beneficial Stock Ownership of Certain Stockholders and Management” in the Company’s definitive proxy statement, which involves the election of directors and is to be filed with the SEC pursuant to the Exchange Act within 120 days of the end of the Company’s fiscal year on December 31, 2003.

Item 13. Certain Relationships and Related Transactions.

The information required by this Item as to certain business relationships and transactions with management and other related parties of the Company is hereby incorporated by reference to such information appearing under the caption “Management and Compensation Committee Interlocks and Insider Participation” in the Company’s definitive proxy statement, which involves the election of directors and is to be filed with the SEC pursuant to the Exchange Act within 120 days of the end of the Company’s fiscal year on December 31, 2003.

Item 14. Principal Accountant Fees and Services.

The information required by this Item as to principal accountant fees and services for the Company is hereby incorporated by reference to such information appearing under the caption “Fees Paid to Principal Accounting Firm” in the Company’s definitive proxy statement, which involves the election of directors and is to be filed with the SEC pursuant to the Exchange Act within 120 days of the end of the Company’s fiscal year on December 31, 2003.

34

PART IV

Item 15. Exhibits, Financial Statement Schedules and Reports on Form 8-K.

35

	10.3***	1990 Stock option Plan, as amended through January 5, 2001 (filed as an exhibit to the Company's Form 10-K for the year ended December 31, 2000 and incorporated herein by reference).
	10.4***	Director Stock Option Plan (filed as an exhibit to the Company's Form 10-K for the year ended December 31, 2000 and incorporated herein by reference).
	10.5***	1998 Director Stock Option Plan (filed as an exhibit to the Company's Form 10-K for the year ended December 31, 2000 and incorporated herein by reference).
	10.6***	1996 Stock Option Plan for Nonexecutive Employees and Consultants (filed as an exhibit to the Company's Registration Statement on Form S-8 (333-61988) and incorporated herein by reference).
	10.7	Amended and Restated Credit Agreement dated as of December 14, 2001 with Bank of America N.A. (filed as an exhibit to the Company's Form 10-K for the year ended December 31, 2001 and incorporated herein by reference).
	10.8***	Letter of Agreement with Gary C. Hanna, dated March, 2002 (filed as an exhibit to the Company's Form 10-K for the year ended December 31, 2001 and incorporated herein by reference).
	10.9***	1998 Director Stock Option Plan (filed as an exhibit to the Company's Form 10-K for the year ended December 31, 2002, and incorporated herein by reference).
	21*	Subsidiaries of the Company.
	23.1*	Consent of Ernst & Young, LLP.
	23.2*	Consent of Ryder Scott Company, L.P.

	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

(b) Form 8-K:

(i) A Current Report on Form 8-K was filed October 24, 2003 reporting under Items 7 and 12 the Company's financial results for the third quarter of 2003.

36

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 15, 2004

By: /s/Geoffrey M. Hertel

Geoffrey M. Hertel, President and 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:

37

EXHIBIT INDEX

* Filed with this report

** Furnished with this report

*** Management contract or compensatory plan or arrangement

Exhibit 3.1 (ii)

CERTIFICATE OF AMENDMENT

OF

RESTATED CERTIFICATE OF INCORPORATION

OF

TETRA TECHNOLOGIES, INC.

TETRA Technologies, Inc. (the “Company”), a corporation organized and existing under and by virtue of the General Corporation Law of the State of Delaware.

DOES HEREBY CERTIFY:

FIRST: That the Board of Directors of the Company, by unanimous written consent in accordance with Section 141(f) of the General Corporation Law of the State of Delaware, adopted resolutions proposing and declaring advisable the following amendment to the Company’s Restated Certificate of Incorporation, so that, as amended, the first sentence of the Article FOURTH shall read in its entirety as follows:

“FOURTH: The total number of shares of stock that the Corporation shall have authority to issue is 25 million, consisting of five million shares of Preferred Stock, of the par value of $.01 per share (hereinafter called “Preferred Stock”), and 20 million shares of Common Stock, of the par value of $.01 per share (hereinafter called “Common Stock”).”

SECOND: That thereafter, pursuant to the resolutions of the Board of Directors, the proposed amendment was considered at the next annual meeting of stockholders of the Company duly called and held on May 22, 1995, upon notice in accordance with Section 222 of the General Corporation Law of the State of Delaware, at which meeting a majority of the outstanding shares of Common Stock of the Company entitled to vote thereon were voted in favor of such amendment.

THIRD: That said amendment was duly adopted in accordance with applicable provisions of Section 242 of the General Corporation Law of the State of Delaware.

IN WITNESS THEREOF, the Company has caused this certificate to be signed by Michael L. Jeane, the President and Chief Executive Officer, and attested to by Geoffrey M. Hertel, its Corporate Secretary, this 11 day of August, 1995.

By: /s/ Michael L Jeane

Michael L. Jeane

President and Chief Executive Officer

ATTEST:

/s/ Geoffrey M. Hertel

Geoffrey M. Hertel, Corporate Secretary

Exhibit 21

TETRA Technologies, Inc.

List of Subsidiaries or Other Related Entities

TETRA Micronutrients, Inc.

SeaJay Industries, Inc.

TETRA Agricultural Products de Mexico, S.A. de C.V. (1)

TETRA International Incorporated

TETRA de Mexico, S.A. de C.V. (2)

TETRA Technologies de Venezuela, S.A.

TETRA Technologies do Brasil, Ltda. (3)

TETRA Technologies (U.K.) Limited

TETRA Technologies de Mexico, S.A. de C.V. (2)

TETRA Technologies Nigeria Limited

Ahmad Albinali & TETRA Arabia Company Ltd. (LLC) (4)

TETRA Technologies Australia Pty Ltd

TETRA Thermal, Inc.

TPS Holding Company, LLC

TETRA Process Services, L.C.

TETRA Applied Holding Company

TETRA Applied L.P. LLC

TETRA Applied GP, LLC

TETRA Applied Technologies, LP (5)

T-Production Testing LLC

Maritech Resources, Inc.

TETRA Production Testing GP, LLC

TETRA Production Testing Services, L.P. (6)

TETRA Investment Holding Co., Inc.

TETRA Real Estate, LLC

TETRA Real Estate, L.P. (7)

TETRA Financial Services, Inc.

TETRA (U.K.) Limited

(1) TETRA Micronutrients, Inc. owns 99.99% and TETRA Technologies, Inc. owns 0.01%.

(2) TETRA Technologies, Inc. owns 0.02% and TETRA International Incorporated owns 99.98%.

(3) TETRA International Incorporated owns 99.9% and TETRA Technologies, Inc. owns 0.1%.

(4) TETRA International Incorporated owns 50%.

(5) TETRA Applied LP, LLC owns 99.9% and TETRA Applied GP, LLC owns 0.1%.

(6) TETRA Applied Technologies, L.P. owns 99.9% and TETRA Production Testing GP, LLC owns 0.1%.

(7) TETRA Investment Holding Co., Inc. owns 99.9% and TETRA Real Estate, LLC owns 0.1%.

Exhibit 23.1

CONSENT OF INDEPENDENT AUDITORS

We consent to the incorporation by reference in the following Registration Statements previously filed by TETRA Technologies, Inc. of our report dated February 23, 2004, with respect to the consolidated financial statements and schedule of TETRA Technologies, Inc. included in the Annual Report (Form 10-K) for the year ended December 31, 2003:

Form S-8 (No. 333-40509) 1996 Stock Option Plan for Non-Executive Employees and Consultants

Form S-8 (No. 33-41337) 401(k) Retirement Plan

Form S-8 (No. 33-35750) 1990 Stock Option Plan

Form S-8 (No. 33-76804) 1993 Director Stock Option Plan

Form S-8 (No. 33-76806) 1990 Stock Option Plan

Form S-8 (No. 333-04284) 401(k) Retirement Plan

Form S-8 (No. 333-09889) 1990 Stock Option Plan

Form S-8 (No. 333-61988) 1990 Stock Option Plan, as amended, and TETRA Technologies, Inc.

1996 Stock Option Plan for Non-Executive Employees and Consultants

Form S-8 (No. 333-84444) Non-Qualified Stock Option Plan

Form S-8 (No. 333-76039) 1998 Director Stock Option Plan

ERNST & YOUNG LLP

Houston, Texas

March 10, 2004

Exhibit 23.2

CONSENT OF INDEPENDENT RESERVE ENGINEERS

We hereby consent to the use of our name and the information from our report prepared for Maritech Resources, Inc. regarding our estimates of reserves and future net revenues from the production and sale of reserves attributable to Maritech Resources, Inc. in the Annual Report on Form 10-K of TETRA Technologies, Inc. for the year ended December 31, 2003, and to the incorporation by reference thereof into TETRA Technologies, Inc. filed Registration Statements Nos. 333-40509, 33-41337, 33-35750, 33-76804, 33-76806, 333-04284, 333-09889, 333-61988, 333-84444 and 333-76039. Maritech Resources, Inc. is a wholly owned subsidiary of TETRA Technologies, Inc.

RYDER SCOTT COMPANY, L.P.

Houston, Texas

March 10, 2004

Exhibit 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

I, Geoffrey M. Hertel, certify that:

1. I have reviewed this annual report on Form 10-K for the year ended December 31, 2003, of TETRA Technologies, Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a -15(e) and 15d -15(e)) for the registrant and have:

a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation;

c) disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent function):

a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: March 15, 2004

/s/ Geoffrey M. Hertel

Geoffrey M. Hertel

President

Chief Executive Officer

Exhibit 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

I, Jospeh M. Abell, certify that:

1. I have reviewed this annual report on Form 10-K for the year ended December 31, 2003, of TETRA Technologies, Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a -15(e) and 15d -15(e)) for the registrant and have:

a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation;

c) disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent function):

a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: March 15, 2004

/s/ Joseph M. Abell

Joseph M. Abell

Senior Vice President

Chief Financial Officer

Exhibit 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

In connection with the Annual Report of TETRA Technologies, Inc. (the “Company”) on Form 10-K for the year ending December 31, 2003 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Geoffrey M. Hertel, President and Chief Executive Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

(1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Dated: March 15, 2004

/s/ Geoffrey M. Hertel

Geoffrey M. Hertel

President

Chief Executive Officer

TETRA Technologies, Inc.

A signed original of this written statement required by Section 906 has been provided to the Company and will be retained by the Company and furnished to the Securities and Exchange Commission or its staff upon request.

Exhibit 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

In connection with the Annual Report of TETRA Technologies, Inc. (the “Company”) on Form 10-K for the year ending December 31, 2003 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Joseph M. Abell, Senior Vice President and Chief Financial Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

(1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Dated: March 15, 2004

/s/ Joseph M. Abell

Joseph M. Abell

Senior Vice President

Chief Financial Officer

TETRA Technologies, Inc.

A signed original of this written statement required by Section 906 has been provided to the Company and will be retained by the Company and furnished to the Securities and Exchange Commission or its staff upon request.

REPORT OF INDEPENDENT AUDITORS

Board of Directors and Stockholders

TETRA Technologies, Inc.

We have audited the accompanying consolidated balance sheets of TETRA Technologies, Inc. and subsidiaries (the “Company”) as of December 31, 2003 and 2002, and the related consolidated statements of operations, stockholders' equity, and cash flows for each of the three years in the period ended December 31, 2003. Our audits also included the financial statement schedule listed in the Index at Item 15(a). These financial statements and schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and schedule based on our audits.

We conducted our audits in accordance with auditing standards generally accepted in the 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, 2003 and 2002, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2003, in conformity with accounting principles generally accepted in the United States. Also, in our opinion, the related financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein.

ERNST & YOUNG LLP

Houston, Texas

February 23, 2004

F-1

TETRA Technologies, Inc. and Subsidiaries

Consolidated Balance Sheets

(In Thousands)