UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON D.C. 20549
 


FORM 10-K
(MARK ONE)
[ X ] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
FOR THE FISCAL YEAR ENDED DECEMBER 31, 2009
 
OR

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

COMMISSION FILE NUMBER 1-13455
TETRA Technologies, Inc.
(EXACT NAME OF THE REGISTRANT AS SPECIFIED IN ITS CHARTER)

DELAWARE
74-2148293
(STATE OR OTHER JURISDICTION OF
(I.R.S. EMPLOYER
INCORPORATION OR ORGANIZATION)
IDENTIFICATION NO.)
   
24955 INTERSTATE 45 NORTH
  
THE WOODLANDS, TEXAS
77380
(ADDRESS OF PRINCIPAL EXECUTIVE OFFICES)
(ZIP CODE)
   
REGISTRANT’S TELEPHONE NUMBER, INCLUDING AREA CODE: (281) 367-1983

SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:
   
COMMON STOCK, PAR VALUE $.01 PER SHARE
NEW YORK STOCK EXCHANGE
(TITLE OF CLASS)
(NAME OF EXCHANGE ON WHICH REGISTERED)
   
RIGHTS TO PURCHASE SERIES ONE
  
JUNIOR PARTICIPATING PREFERRED STOCK
NEW YORK STOCK EXCHANGE
(TITLE OF CLASS)
(NAME OF EXCHANGE ON WHICH REGISTERED)
   
SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT: NONE
INDICATE BY CHECK MARK IF THE REGISTRANT IS A WELL-KNOWN SEASONED ISSUER (AS DEFINED IN RULE 405 OF THE SECURITIES ACT). YES [ X ]   NO [   ]
INDICATE BY CHECK MARK IF THE REGISTRANT IS NOT REQUIRED TO FILE REPORTS PURSUANT TO SECTION 13 OR SECTION 15(d) OF THE ACT. YES [   ]   NO [ X ]
INDICATE BY CHECK MARK WHETHER THE REGISTRANT (1) HAS FILED ALL REPORTS REQUIRED TO BE FILED BY SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 DURING THE PRECEDING 12 MONTHS (OR FOR SUCH SHORTER PERIOD THAT THE REGISTRANT WAS REQUIRED TO FILE SUCH REPORTS) AND (2) HAS BEEN SUBJECT TO SUCH FILING REQUIREMENTS FOR THE PAST 90 DAYS. YES [ X ]   NO [   ]
INDICATE BY CHECK MARK WHETHER THE REGISTRANT HAS SUBMITTED ELECTRONICALLY AND POSTED ON ITS CORPORATE WEB SITE, IF ANY, EVERY INTERACTIVE DATA FILE REQUIRED TO BE SUBMITTED AND POSTED PURSUANT TO RULE 405 OF REGULATION S-T DURING THE PRECEDING 12 MONTHS (OR FOR SUCH SHORTER PERIOD THAT THE REGISTRANT WAS REQUIRED TO SUBMIT AND POST SUCH FILES).
YES  [   ]  NO [   ]
INDICATE BY CHECK MARK IF DISCLOSURE OF DELINQUENT FILERS PURSUANT TO ITEM 405 OF REGULATION S-K IS NOT CONTAINED HEREIN, AND WILL NOT BE CONTAINED, TO THE BEST OF REGISTRANT’S KNOWLEDGE, IN DEFINITIVE PROXY OR INFORMATION STATEMENTS INCORPORATED BY REFERENCE IN PART III OF THIS FORM 10-K OR ANY AMENDMENT TO THIS FORM 10-K. [ X ]
INDICATE BY CHECK MARK WHETHER THE REGISTRANT IS A LARGE ACCELERATED FILER, AN ACCELERATED FILER, A NON-ACCELERATED FILER, OR A SMALLER REPORTING COMPANY. SEE THE DEFINITIONS OF “LARGE ACCELERATED FILER,” “ACCELERATED FILER,” AND “SMALLER REPORTING COMPANY”  IN RULE  12b-2 OF THE EXCHANGE ACT. (CHECK ONE):
LARGE ACCELERATED FILER [ X ]
ACCELERATED FILER [   ]
NON-ACCELERATED FILER [   ]
SMALLER REPORTING COMPANY [   ]
INDICATE BY CHECK MARK WHETHER THE REGISTRANT IS A SHELL COMPANY (AS DEFINED IN RULE 12b-2 OF THE EXCHANGE ACT).
YES [   ]  NO [ X ]
THE AGGREGATE MARKET VALUE OF COMMON STOCK HELD BY NON-AFFILIATES OF THE REGISTRANT WAS $581,526,580 AS OF JUNE 30, 2009, THE LAST BUSINESS DAY OF THE REGISTRANT’S MOST RECENTLY COMPLETED SECOND FISCAL QUARTER.
NUMBER OF SHARES OUTSTANDING OF THE ISSUER’S COMMON STOCK AS OF FEBRUARY 26, 2010 WAS 75,567,051 SHARES.
 
DOCUMENTS INCORPORATED BY REFERENCE
PART III INFORMATION IS INCORPORATED BY REFERENCE TO THE REGISTRANT’S PROXY STATEMENT FOR ITS ANNUAL MEETING OF STOCKHOLDERS TO BE HELD MAY 5, 2010 TO BE FILED WITH THE SECURITIES AND EXCHANGE COMMISSION WITHIN 120 DAYS OF THE END OF THE REGISTRANT’S FISCAL YEAR.
 
 
 


     TABLE OF CONTENTS

 
Part I
  
Item 1.
Business   
   1
Item 1A.
Risk Factors
   11
Item 1B.
Unresolved Staff Comments
   24
Item 2.
Properties
   24
Item 3.
Legal Proceedings
   28
Item 4.
[Removed and Reserved]
   29
     
 
Part II
  
Item 5.
Market for Registrant’s Common Equity, Related Stockholder Matters and
  
 
     Issuer Purchases of Equity Securities
   30
Item 6.
Selected Financial Data
   31
Item 7.
Management’s Discussion and Analysis of Financial Condition
  
 
     and Results of Operation
   32
Item 7A.
Quantitative and Qualitative Disclosures about Market Risk
   57
Item 8.
Financial Statements and Supplementary Data
   59
Item 9.
Changes in and Disagreements with Accountants on Accounting
  
 
     and Financial Disclosure
   59
Item 9A.
Controls and Procedures
   59
Item 9B.
Other Information
   60
     
 
Part III
  
Item 10.
Directors, Executive Officers and Corporate Governance
   61
Item 11.
Executive Compensation
   61
Item 12.
Security Ownership of Certain Beneficial Owners and Management and
  
 
     Related Stockholder Matters
   61
Item 13.
Certain Relationships and Related Transactions, and Director Independence
   61
Item 14.
Principal Accounting Fees and Services
   61
     
 
Part IV
  
Item 15.
Exhibits, Financial Statement Schedules
   62


 
 
 


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

General

We are a geographically diversified oil and gas services company focused on completion fluids and other products, production testing, wellhead compression, and selected offshore services including well plugging and abandonment, decommissioning, and diving, with a concentrated domestic exploration and production business. We are composed of five reporting segments organized into three divisions – Fluids, Offshore, and Production Enhancement.

Our Fluids Division manufactures and markets clear brine fluids, additives, and other associated products and services to the oil and gas industry for use in well drilling, completion, and workover operations, both in the United States and in certain regions of Latin America, Europe, Asia, and Africa. The Division also markets liquid and dry calcium chloride manufactured at its production facilities to a variety of markets outside the energy industry.

Our Offshore Division consists of two operating segments: Offshore Services and Maritech, an oil and gas exploration and production segment. The Offshore Services segment provides (1) downhole and subsea services such as plugging and abandonment, workover, and wireline services, (2) construction and decommissioning services, including hurricane damage remediation, utilizing our heavy lift barges and cutting technologies in the construction or decommissioning of offshore oil and gas production platforms and pipelines, and (3) diving services involving conventional and saturated air diving and the operation of several dive support vessels.
 
The Maritech segment consists of our Maritech Resources, Inc. (Maritech) subsidiary, which, with its subsidiaries, is an oil and gas exploration and production company focused in the offshore, inland waters, and onshore U.S. Gulf Coast region. Maritech periodically acquires oil and gas properties in order to replenish or expand its production operations and to provide additional development and exploitation opportunities. The Offshore Division’s Offshore Services segment performs a significant portion of the well abandonment and decommissioning services required by Maritech.

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

The Compressco segment provides wellhead compression-based production enhancement services throughout many of the onshore producing regions of the United States, as well as basins in Canada, Mexico, South America, Europe, Asia, and other international locations. These compression services can improve the value of natural gas and oil wells by increasing daily production and total recoverable reserves.
 
We continue to pursue a growth strategy that includes expanding our existing businesses – both through internal growth and through the pursuit of suitable acquisitions – and by identifying opportunities to establish operations in additional U.S. and international niche oil service markets. For financial information for each of our segments, including information regarding revenues and total assets, see “Note Q – Industry Segments and Geographic Information” contained in the Notes to Consolidated Financial Statements.

 
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We were incorporated in Delaware in 1981. Our corporate headquarters are located at 24955 Interstate 45 North in The Woodlands, Texas. Our phone number is 281-367-1983, and our website is accessed at www.tetratec.com. We make available, free of charge, on our website, our Corporate Governance Guidelines, Code of Business Conduct and Ethics, Code of Ethics for Senior Financial Officers, Audit Committee Charter, Management and Compensation Committee Charter, and Nominating and Corporate Governance Committee Charter as well as our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and all amendments to those reports as soon as is reasonably practicable after such materials are electronically filed with, or furnished to, the Securities and Exchange Commission (SEC). The information on our website is not, and shall not be deemed to be, a part of this annual report on Form 10-K or incorporated into any other filings with the SEC. Information filed with the SEC may be read or copied at the SEC’s Public Reference Room at 100 F Street, N.E., Washington D.C. 20549. Information on operation of the Public Reference Room may be obtained by calling the SEC at 1-800-SEC-0330. The SEC also maintains an internet website (http://www.sec.gov) that contains reports, proxy, and information statements, and other information regarding issuers that file electronically. We will also make these documents available in print, free of charge, to any stockholder who requests such information from the Corporate Secretary.

Products and Services

Fluids Division

Liquid calcium chloride, sodium bromide, calcium bromide, zinc bromide, and similar products produced by our Fluids Division are referred to as clear brine fluids (CBFs) in the oil and gas industry. CBFs are typically solids-free, clear salt solutions that have variable densities and are used as weighting fluids to control bottomhole pressures during oil and gas completion and workover activities. The use of CBFs can contribute to increased production by reducing the likelihood of damage to the wellbore and productive pay zone. CBFs are particularly important in offshore completion and workover operations due to the potentially greater formation sensitivity, the significantly greater investment necessary to drill and produce offshore, and the consequent higher cost of error. CBFs are manufactured and distributed by our Fluids Division and are also sold to other companies that service customers in the oil and gas industry.

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

The Division’s fluid engineering and management personnel use proprietary technology to determine the optimal CBF blend for a customer’s particular application to maximize the effectiveness and lifespan of the CBFs. We modify the specific volume, density, crystallization temperature, and chemical composition of the CBFs to satisfy a customer’s specific requirements. Our filtration services use a variety of techniques and equipment for the onsite removal of particulates from CBFs, so that those CBFs can be recirculated back into the well. Filtration also enables recovery of a greater percentage of used CBFs for recycling.

The Fluids Division produces CBFs from its production facilities that manufacture liquid and dry calcium chloride, sodium bromide, calcium bromide, zinc bromide and zinc calcium bromide for distribution into energy markets. Liquid and dry calcium chloride are also sold into the water treatment, industrial, cement, food processing, dust control, ice melt, agricultural, and consumer products markets. Liquid sodium bromide is also sold into the industrial water treatment markets, where it is used as a biocide in recirculated cooling tower waters.

We manufacture liquid and dry calcium chloride in production facilities located in the United States and Europe. We also acquire raw material and production from other sources, including non-owned plants under agreements with the owners. During the fourth quarter of 2009, we began production of liquid calcium chloride at our newly completed plant near El Dorado, Arkansas. This plant also began production of dry (flake) calcium chloride during January 2010. Dry calcium chloride is also produced at our Kokkola, Finland
 
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plant. We operate our European calcium chloride manufacturing operations under the name TETRA Chemicals Europe. We also operate a plant in Lake Charles, Louisiana, where we produce mainly dry calcium chloride. We manufacture liquid calcium chloride from our facility in Parkersburg, West Virginia and have two solar evaporation plants located in San Bernardino County, California, which produce liquid calcium chloride from underground brine reserves. These plant facilities have a combined production capacity of more than 1.5 million tons per year.

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

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

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

Offshore Division

Our Offshore Division consists of two separate operating segments: the Offshore Services and Maritech segments. The Offshore Services segment provides (1) downhole and subsea services such as plugging and abandonment (P&A), workover, and wireline services, (2) construction and decommissioning services, including hurricane damage remediation, utilizing our heavy lift barges and cutting technologies in the construction or decommissioning of offshore oil and gas production platforms, subsea wells, and pipelines, and (3) diving services involving conventional and saturated air diving and the operation of several dive support vessels. While we are a leading provider of these services to the offshore Gulf of Mexico well abandonment and decommissioning markets, we provide these services to other oilfield markets as well, including the inland water and onshore markets in the Gulf of Mexico region. We offer comprehensive, integrated solutions to our customers, including engineering consultation and project management services. We provide individualized services to meet our customers’ specific requirements. The Maritech segment is an oil and gas exploration and production company focused in the offshore, inland waters, and onshore regions of the U.S. Gulf of Mexico. Maritech periodically acquires oil and gas properties in order to replenish or expand its production and to provide additional development and exploitation opportunities. The Offshore Division’s Offshore Services segment performs a significant portion of the well abandonment and decommissioning services required by Maritech, and Maritech is a significant customer of the Offshore Services segment.

In providing its array of services, our Offshore Services segment utilizes barge-mounted rigs, a platform rig, offshore rigless P&A packages, two heavy lift vessels, several dive support vessels and other dive support assets and onshore rigs which we own and operate. In addition, we rent certain equipment from third party contractors whenever necessary. The Division provides a wide variety of contract diving services to its customers through our subsidiary, Epic Diving & Marine Services (Epic). Construction, well abandonment, and decommissioning services are performed primarily offshore in the Gulf of Mexico, although the Division also provides well abandonment services to customers in the inland waters and onshore in Texas and Louisiana. The Division also provides onshore and offshore cutting services and tool rentals through its E.O.T. Rentals (EOT) operations. The Division’s electric wireline operations specializes in cased-hole logging, mechanical completion services, plugbacks, bridge plugs and packer services, pipe recovery (cased and open hole), perforating, and tubing-conveyed perforating services. The Offshore Services segment has been successful in marketing its experience, utilizing the specialized equipment and engineering expertise necessary to address a variety of specific construction and platform decommissioning issues, including project management and the issues associated with platforms toppled or severely damaged by hurricanes in the Gulf of Mexico. The Division provides services to major oil and gas companies and independent operators, including Maritech, through its facilities located in Lafayette, Broussard, Harvey, and Houma, Louisiana and in Bryan and Victoria, Texas.

 
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The size of our Offshore Division’s fleet of service vessels has been adjusted in recent years to serve the changing demand for well abandonment, construction, platform decommissioning, diving, and other offshore services. We currently have two vessels with the capacity to perform heavy lift projects and integrated operations on oil and gas production platforms. Subsequent to our acquisition of Epic in March 2006, we purchased a dynamically positioned dive support vessel, which we renamed the Epic Diver, and refurbished two of Epic’s existing dive support vessels, the Epic Explorer and the Epic Seahorse. Both the Epic Diver and the Epic Explorer offer saturation diving systems that are rated for up to 1,000 foot dive depths. Beginning in June 2009, we increased our service fleet through the leasing of a specialized dive service vessel which is being utilized for hurricane recovery work.

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

Maritech grows its operations by acquiring and developing oil and gas property interests located in the offshore, inland waters, and onshore U.S. Gulf of Mexico region. Maritech acquires both producing oil and gas properties as well as prospect acreage, and performs development and exploitation efforts in order to increase its oil and gas reserves and replace depleting production. During 2009, Maritech participated in drilling three wells, one each in Galveston Island 321, Main Pass 279, and Timbalier Bay fields. All three wells were successful with an average net finding cost of $12.90 per equivalent barrel (BOE). Maritech also participated in numerous successful recompletions in Timbalier Bay, Lake Hermitage, and the West Delta area. Maritech’s most significant development efforts currently consist of East Cameron 328, the Dromedary prospect acreage located onshore Louisiana, and the Timbalier Bay field located in the inland waters area of Louisiana. The most recent acquisitions of producing oil and gas properties were in December 2007 and January 2008, when Maritech purchased oil and gas producing properties for an aggregate of $74.9 million of cash and the assumption of associated decommissioning liabilities having an undiscounted value of approximately $51.5 million. In December 2007, we acquired interests in certain offshore properties located primarily in the Main Pass area of the Gulf of Mexico from a subsidiary of Cimarex Energy (the Cimarex Properties). Maritech completed a new condensate pipeline in April 2008, which eliminated the barging of produced condensate from the Cimarex Properties, resulting in significantly increased production in an area from which production had previously been restricted. Since acquiring the Cimarex Properties, Maritech has completed the hookup and has begun production from additional subsea wells in the Main Pass area. In January 2008, we acquired certain offshore oil and gas producing properties from Stone Energy Corporation. During the three year period ended December 31, 2009, Maritech has invested significantly in its acquisition and exploitation activities, spending approximately $290.2 million on such projects, although such activities decreased during 2009 due to capital spending constraints. Maritech’s activities also include the plugging, abandonment, and decommissioning efforts on its offshore oil and gas properties, particularly as part of its strategy to reduce its risk from future storms and in response to the increasing cost of windstorm insurance coverage. During the three year period ended December 31, 2009, Maritech has expended approximately $131.8 million on such efforts. As of December 31, 2009, Maritech had proved reserves of approximately 7.1 million barrels of oil and 33.5 billion cubic feet of natural gas, with undiscounted future net pretax cash flow of approximately $109.4 million.

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

Production Enhancement Division

The Production Testing segment of the Production Enhancement Division provides flow back pressure and volume testing of onshore and offshore oil and gas wells, providing reservoir data necessary to enable operators to optimize production and minimize oil and gas reservoir damage. In addition, the Production Testing segment provides services for coiled tubing, pipeline cleanout, blowout prevention, well cleanup, and laboratory analysis. The Production Testing segment also provides early-life production solutions designed to access newly available production and late-life production enhancement solutions designed to boost and extend the productive life of oil and gas wells. Many of these services involve
 
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sophisticated evaluation techniques needed for reservoir management and optimization of well workover programs.

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

During 2009, the Production Enhancement Division entered into a technical management contract to perform engineering, procurement, and installation of equipment needed for the cleanup and removal of oil bearing materials at two South American refinery locations. The contract is expected to be performed in project stages over the next one to three year period.

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

Compressco’s GasJack® unit increases gas production by reducing surface pressure to allow wellbore liquids that would normally block gas flow to produce up the well. The fluids are separated from the gas and liquid-free gas flows into the GasJack® unit, where the gas is compressed. The GasJack® unit is an integrated power/compressor unit equipped with an industrial 460-cubic inch, V-8 engine that uses natural gas from the well to power one bank of cylinders, while the other cylinders provide compression. This configuration is capable of creating suction conditions that range from 12 in/hg (inches of mercury) of negative pressure to 60 PSIG (Pounds per Square Inch Gauge) of positive pressure and discharge pressures of up to 450 PSIG. Compressco utilizes its GasJack® units in conjunction with its personnel to provide compression services to its customers, primarily on a month-to-month basis. Compressco services its compressors and provides maintenance service on sold units through a staff of mobile field technicians who are based throughout Compressco’s market areas. To a lesser extent, Compressco also sells GasJack® units to customers.

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

Sources of Raw Materials  

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

The Division manufactures liquid calcium chloride from a reaction of hydrochloric acid and limestone and from natural underground brine reserves. The Division also purchases liquid and dry calcium chloride from a number of U.S. and international chemical manufacturers. Some of the Division’s primary sources of hydrochloric acid are chemical co-product streams obtained from chemical manufacturers. We have written agreements with certain of those chemical companies regarding the supply of hydrochloric acid, bromine, or calcium chloride. We significantly increased our production capacity following the construction of our El Dorado, Arkansas, calcium chloride plant facility, which finished testing in September 2009 and began production of liquid calcium chloride during the fourth quarter of 2009. This plant is located on land purchased from Chemtura Corporation (Chemtura) and adjacent to Chemtura’s central bromine plant, located near El Dorado, Arkansas. This new plant is designed to produce liquid and flake calcium chloride, along with other co-products such as magnesium hydroxide and sodium chloride, and will allow the Division to reduce its
 
5
 
dependence on third-party hydrochloric acid suppliers. The plant is designed to utilize calcium chloride containing brines (tail brine) obtained from Chemtura’s operations. We purchase raw materials utilized by our Lake Charles facility to produce liquid and dry (pellet) calcium chloride from a variety of sources. We also produce calcium chloride at our two plants in San Bernardino County, California, through evaporation of naturally occurring underground brine reserves. These underground brine reserves are deemed adequate to supply our foreseeable need for calcium chloride in that market area. Substantial quantities of limestone are also consumed when converting hydrochloric acid into calcium chloride. We use a proprietary process that permits the use of less expensive limestone, while maintaining end-use product quality. We purchase limestone from several different sources. Currently, hydrochloric acid and limestone are generally available from multiple sources.

To produce calcium bromide, zinc bromide, and zinc calcium bromide at our West Memphis, Arkansas, facility, we use primarily bromine and various sources of zinc raw materials and lime. We use proprietary and patented processes that permit the use of cost-advantaged raw materials, while maintaining high product quality. There are multiple sources of zinc that we can use in the production of zinc bromide. In December 2006, we entered into a long-term supply agreement with Chemtura, whereby the Division purchases its requirements of raw material bromine from Chemtura’s Arkansas bromine facilities. In addition, Chemtura supplies the Division’s new El Dorado calcium chloride plant with tail brine from its Arkansas facilities following bromine extraction. During March 2009, Chemtura announced that it had filed voluntary petitions for reorganization under Chapter 11 of the U.S. Bankruptcy code. Under bankruptcy, Chemtura had the right to accept or reject executory contracts, such as our agreements with them under which we acquire bromine and brine. During the fourth quarter of 2009, we negotiated certain amendments to our existing agreements with Chemtura, as well as certain other agreements, and such amended agreements were approved by the bankruptcy court. While the amended agreements do include an increase in the cost of raw material bromine from Chemtura, other amendments to the agreements partially mitigate the impact of the increased costs.

We also own a calcium bromide manufacturing plant near Magnolia, Arkansas, that was constructed in 1985. This plant was acquired in 1988 and is not operable. We currently have approximately 33,000 gross acres of bromine-containing brine reserves under lease in the vicinity of this plant. While this plant is designed to produce calcium bromide, it could be modified to produce elemental bromine or select bromine compounds. We believe we have sufficient brine reserves under lease to operate a world-scale bromine facility for 25 to 30 years. Development of the brine field, construction of necessary pipelines, and reconfiguration of the plant would require a substantial capital investment. The execution of the Chemtura bromine supply agreement discussed above provides us with an immediate supply of bromine to support the Division’s current operations. We do, however, continue to evaluate our strategy related to the Magnolia, Arkansas assets and their future development. Chemtura holds certain rights to participate in the development of the Magnolia, Arkansas, assets.

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

Market Overview and Competition

Fluids Division

Our Fluids Division sells CBFs, drilling and completion fluid systems, additives, and related products and services to oil and gas exploration and production companies, onshore and offshore, in the United States and worldwide. Current areas of market presence include the U.S. onshore Gulf Coast, the U.S. Gulf of Mexico, the North Sea, Mexico, South America, Europe, Asia, and Africa. The Division is also capitalizing on the current trend toward deepwater operations which utilize a larger volume of CBFs and are subject to harsh downhole conditions such as high pressure and high temperatures. In June 2008, we announced that we had
 
6
 
signed a contract with Petroleo Brasileiro S.A. (Petrobras), the national oil company of Brazil, to provide completion fluids and associated services on deepwater wells offshore Brazil. Although much of Petrobras’ activity associated with this contract was deferred during 2009, we anticipate that activity in Brazil will be increasing beginning in 2010.

The Division’s principal competitors in the sale of CBFs to the oil and gas industry are Baroid Corporation, a subsidiary of Halliburton Company; M-I L.L.C., a joint venture between Smith International, Inc. and Schlumberger Limited; and BJ Services Company, which has announced that it is being acquired by Baker Hughes. This market is highly competitive, and competition is based primarily on service, availability, and price. Although all competitors provide fluid handling, filtration, and recycling services, we believe that our historical focus on providing these and other value-added services to our customers have enabled us to compete successfully. Major customers of the Fluids Division include Anadarko, Chevron, Devon, Dominion Resources, EOG Resources, Halliburton Company, LLOG Exploration, Newfield Exploration Company, Nippon Oil Exploration, and Shell Oil. The Division also sells its products through various distributors worldwide.

Our liquid and dry calcium chloride products have a wide range of uses outside the energy industry. The non-energy market segments to which our products are marketed include agricultural, industrial, roadway dust control and de-icing, mining, janitorial, construction, pharmaceutical, and food processing. These products promote snow and ice melt, dust control, cement curing, food processing, dehumidification, and road stabilization and are also used as a source of calcium nutrients to improve agricultural yields. We also sell sodium bromide into the industrial water treatment markets as a biocide under the BioRid® trade name. Most of these markets are highly competitive. The Division’s European calcium chloride manufacturing operations based in Kokkola, Finland, permit us to market our calcium chloride products to certain European markets. Our major competitors in the calcium chloride market include Occidental Chemical Corporation and Industrial del Alkali in North America, and Brunner Mond, Solvay, and NedMag in Europe.

Offshore Division

Our Offshore Division consists of our Offshore Services and Maritech segments. The Division’s Offshore Services operations provide downhole and subsea services such as well abandonment, contract diving, construction, cutting, and decommissioning services offshore, primarily in the U.S. Gulf of Mexico. In addition, the Division also provides well abandonment, workover, and wireline services in the onshore and inland water areas of the U.S. Gulf Coast regions of Texas and Louisiana. Long-term demand for the Offshore Division’s offshore well abandonment and decommissioning services is predominantly driven by the maturity and decline of producing fields in the Gulf of Mexico, aging offshore platform infrastructure, damage from storms, and government regulations. Demand for the Offshore Division’s construction and other services is driven by the general level of activity of its customers, which are also affected by oil and natural gas prices and the general economic condition of the industry. In the market areas in which we currently operate, regulations generally require wells to be plugged, offshore platforms decommissioned, pipelines abandoned, and the well site cleared within twelve months after an oil or gas lease expires. The maturity and production decline of Gulf of Mexico oil and gas fields has, over time, caused an increase in the number of wells to be plugged and abandoned and platforms and pipelines to be decommissioned. Current and projected demand for offshore abandonment and decommissioning services increased substantially as a result of 2005 and 2008 hurricane activity in the Gulf of Mexico, which destroyed or caused significant damage to a large number of offshore platforms and associated wells. The Division has developed specialized equipment and engineering expertise to provide such services to customers whose offshore wells and production platforms were toppled, destroyed, or heavily damaged by such storms. The threat of future storm activity, combined with increases in hurricane insurance premiums and deductibles, has also accelerated the abandonment and decommissioning plans for undamaged wells and structures of many offshore operators. Offshore activities in the Gulf of Mexico have historically been highly seasonal, with the majority of work occurring during the months of April through October when weather conditions are most favorable. Critical factors required to participate in the current market include, among other factors: having an adequate fleet of the proper equipment to meet current market demand and conditions; having qualified, experienced personnel; having technical expertise to address varying downhole, surface, and subsea conditions, particularly those related to damaged wells and platforms; having the financial strength to ensure all abandonment and decommissioning obligations are satisfied; and having a comprehensive safety and environmental program. We believe our integrated service package and vessel fleet satisfy these market requirements, allowing us to successfully compete.

 
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The Division markets its services primarily to major oil and gas companies and independent operators. Major customers include Apache, Chevron, Mariner Energy, Nexen Petroleum USA Inc., Shell Oil, Stone Energy, and W&T Offshore. These services are performed primarily offshore in the U.S. Gulf of Mexico and in the Gulf Coast inland waters and onshore in Texas and Louisiana. Our principal competitors in the offshore and inland water markets are Global Industries, Ltd., Offshore Specialty Fabricators, Inc., Helix Energy Solutions, Cal Dive International, Inc., and Superior Energy Services, Inc. This market is highly competitive, and competition is based primarily on service, equipment availability, safety record, and price. Our ability to successfully bid our services can fluctuate from year to year, depending on market conditions.

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

Production Enhancement Division

The Production Enhancement Division, through its Production Testing and Compressco segments, provides production testing and wellhead compression-based services and products to its customers. The Production Testing segment provides services primarily to the natural gas segment of the oil and gas industry. In certain gas producing basins, water, sand, and other abrasive materials commonly accompany the initial production of natural gas, often under high pressure and high temperature conditions and in reservoirs containing high levels of hydrogen sulfide gas. The Division provides the specialized equipment and qualified personnel to address these impediments to production and to pressure test wells and wellhead equipment. The Production Testing segment also provides a variety of reservoir management and laboratory testing services for oil and gas producing properties, including coiled tubing, pipeline cleanout, blowout prevention, well cleanup, distillation analysis, gas composition analysis, and oilfield water analysis services. The Production Testing segment also provides early-life and late-life production enhancement solutions designed to boost and extend the productive life of oil and gas wells, working with our Compressco segment.

The production testing market is highly competitive, and competition is based on availability of equipment and qualified personnel, as well as price, quality of service, and safety record. We believe our equipment, skilled personnel, operating procedures, and safety record give us a competitive advantage in the marketplace. The Production Testing segment is also committed to growing its international operations in order to serve most major oil and gas markets worldwide. Competition in onshore U.S. markets is primarily dominated by numerous small, privately-owned operators. Schlumberger Limited, Weatherford International Oilfield Services, Halliburton, and Expro International are major competitors in the U.S. offshore market and international markets. Our customers include Chesapeake, ConocoPhillips, El Paso Corporation, Encana Oil & Gas, Quicksilver Resources, Shell Oil, PEMEX (the national oil company of Mexico), Petrobras (the national oil company of Brazil), Saudi ARAMCO (the national oil company of Saudi Arabia), and other national oil companies in foreign countries.

The Division’s Compressco segment provides production enhancement services to over 400 natural gas and oil producers throughout most of the onshore producing regions of the United States, as well as basins in Canada, Mexico, South America, Europe, Asia, and other international locations. Most of Compressco’s services are performed in the Ark-La-Tex Basin, San Juan Basin, and Mid-Continent region of the United States. While Compressco has historically targeted natural gas wells in its operating regions that produce between 30 thousand and 300 thousand cubic feet of natural gas per day, it is also effectively enhancing production in certain basins with production of up to one million cubic feet of daily production. Compressco believes that the majority of the wells it targets do not currently utilize production enhancement services. Compressco continues to seek opportunities to further expand its operations into other regions in the Western Hemisphere and elsewhere in the world.

 
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The wellhead compression-based production enhancement services business is highly competitive, and competition primarily comes from various local and regional companies that utilize packages consisting of a screw compressor with a separate engine driver or a reciprocating compressor with a separate engine driver. To a lesser extent, Compressco faces competition from large national and multinational companies that have traditionally focused on higher-horsepower natural gas gathering and transportation equipment and services. While many of Compressco’s competitors attempt to compete on the basis of price, Compressco believes that its pricing is competitive because of the significant increases in the value of natural gas wells that result from the quality of its services, its trained field personnel, and its GasJack® unit that it uses to provide the services. Compressco’s major customers include BP, PEMEX, Devon, Chesapeake, and EXCO Resources.

Other Business Matters

Marketing and Distribution

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

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

None of our customers individually exceeded 10% of our total consolidated revenues during the year ended December 31, 2009.

Backlog

 The level of backlog is not indicative of our estimated future revenues because a majority of our products and services either are not sold under long-term contracts or do not require long lead times to procure or deliver. Our backlog consists of estimated future revenues associated with a portion of our well abandonment and decommissioning business, and consists of the non-Maritech share of the well abandonment and decommissioning work associated with the oil and gas properties operated by Maritech. Our estimated backlog on December 31, 2009 was $121.9 million, of which approximately $7.6 million is expected to be billed during 2010. This compares to an estimated backlog of $137.8 million at December 31, 2008.

Employees

As of December 31, 2009, we had 2,837 employees. None of our U.S. employees are presently covered by a collective bargaining agreement, other than the employees of our Lake Charles, Louisiana, calcium chloride production facility, who are represented by the United Steelworkers Union. Our international employees are generally members of the various labor unions and associations common to the countries in which we operate. We believe that our relations with our employees are good.

Patents, Proprietary Technology, and Trademarks

As of December 31, 2009, we owned or licensed twenty-nine issued U.S. patents and had six patent applications pending in the United States. Internationally, we had fifteen owned or licensed foreign patents and one foreign patent application pending. The foreign patents and patent applications are primarily foreign counterparts to U.S. patents or patent applications. The issued patents expire at various times through 2026. We have elected to maintain certain other internally developed technologies, know-how, and inventions as trade secrets. While we believe that the protection of our patents and trade secrets is important to our competitive positions in our businesses, we do not believe any one patent or trade secret is essential to our success.

 
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It is our practice to enter into confidentiality agreements with key employees, consultants, and third parties to whom we disclose our confidential and proprietary information. There can be no assurance, however, that these measures will prevent the unauthorized disclosure or use of our trade secrets and expertise or that others may not independently develop similar trade secrets or expertise. Our management believes, however, that it would require a substantial period of time and substantial resources to independently develop similar know-how or technology. As a policy, we use all possible legal means to protect our patents, trade secrets, and other proprietary information.

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

Health, Safety, and Environmental Affairs Regulations

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

With respect to our operations in the United States, various environmental protection laws and regulations have been enacted and amended in the U.S. during the past three decades in response to public concerns pertaining to the environment. Our U.S. operations and its customers are subject to these various evolving environmental laws and corresponding regulations. In the United States, these laws and regulations are enforced by the U.S. Environmental Protection Agency; the Minerals Management Service of the U.S. Department of the Interior (MMS); the U.S. Coast Guard; and various other federal, state, and local environmental authorities. Similar laws and regulations, designed to protect the health and safety of our employees and visitors to our facilities, are enforced by the U.S. Occupational Safety and Health Administration (OSHA) and other state and local agencies and authorities. We must comply with the requirements of environmental laws and regulations applicable to our operations, including the Federal Water Pollution Control Act of 1972; the Resource Conservation and Recovery Act of 1976 (RCRA); the Clean Air Act of 1977; the Comprehensive Environmental Response, Compensation and Liability Act of 1980 (CERCLA); the Superfund Amendments and Reauthorization Act of 1986 (SARA); the Federal Insecticide, Fungicide, and Rodenticide Act of 1947 (FIFRA); the Hazardous Materials Transportation Act of 1975; and the Pollution Prevention Act of 1990.

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

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

We believe that our manufacturing plants and other facilities are in general compliance with all applicable health, safety, and environmental laws and regulations. Since our inception, we have not had a history of any significant fines or claims in connection with environmental or health and safety matters. However, risks of substantial costs and liabilities are inherent in certain plant and service operations and in the development and handling of certain products and equipment produced or used at our plants, well locations, and worksites. Because of these risks, there can be no assurance that significant costs and liabilities will not be incurred in the future. Changes in environmental and health and safety regulations could subject us to more rigorous standards. We cannot predict the extent to which our operations may be affected by future regulatory and enforcement policies.


 
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Item 1A. Risk Factors.

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

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

Although we believe that the expectations reflected in such forward-looking statements are reasonable and such forward-looking statements are based upon the best data available at the date this report is filed with the SEC, we cannot assure you that such expectations will prove correct. Factors that could cause our results to differ materially from the results discussed in such forward-looking statements include, but are not limited to, the following:
 
·  
general economic, business, and political conditions in the markets we serve or hope to serve in the United States and abroad;
·  
the supply, demand, and prices for oil, gas, and competing energy sources, and more particularly the supply, demand, and prices for well completion, diving, and abandonment and decommissioning services;
·  
activities of our customers and competitors;
·  
the availability of raw materials and labor at reasonable prices;
·  
operating and safety risks inherent in oil and gas production;
·  
access to pipelines, gas gathering and processing facilities for our oil and gas production;
·  
the potential impact of the loss of one or more key employees;
·  
possible impairments of long-lived assets, including goodwill;
·  
cost, availability and adequacy of insurance and the ability to recover thereunder;
·  
technological obsolescence;
·  
weather risks, including the risk of physical damage to our platforms, facilities and equipment and the ability to resume operations following damage;
·  
our ability to implement our business strategy;
·  
uncertainties about finding, developing, producing, and estimating oil and gas reserves and plugging and abandoning wells and structures;
·  
the accounting for our oil and gas operations may result in volatility of earnings;
·  
the availability of capital (including any financing) to fund our business strategy and/or operations and any restrictions resulting from such financing;
·  
foreign currency risks;
·  
the impact of existing and future laws and regulations;
·  
environmental risks;
·  
estimates of hurricane repair costs;
·  
acquisition valuation and integration risks; and
·  
risks related to our foreign operations.

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

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

Market Risks:

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

The demand for our products and services are materially dependent on the supply, demand, and prices for oil, natural gas, and competing energy sources, and more particularly dependent on the supply, demand, and prices for well completion, compression, diving, and abandonment and decommissioning products and services, both in the United States and abroad. These factors are also influenced by the regional economic, financial, business, political, and social conditions within the markets we serve or hope to serve, as well as the national and international economic, financial, business, political and social conditions that impact the supply, demand, and prices of oil and gas. Activity levels have decreased as a result of the recent decline in energy consumption and uncertainty of the capital markets caused by the recent global recession and financial crisis. Decreased energy consumption has resulted in a decrease in energy prices during much of 2009 compared to prices received during early to mid-2008. This decline in energy prices, along with concerns regarding the availability of capital, has negatively affected the operating cash flows and capital plans of many of our customers, as well as our Maritech subsidiary, which has negatively impacted the demand for many of our products and services.
 
    If current economic conditions continue or worsen, there may be additional constraints on oil and gas industry spending levels for an extended period of time. Such a stagnation of economic activity would negatively affect both the demand for many of our products and services as well as the prices we charge for these products and services, which would continue to negatively affect our revenues and future growth. Many of our customers finance their drilling and production operations through third-party lenders. The reduced availability and increased cost of borrowing could cause our customers to reduce their spending on drilling programs, thereby reducing demand and potentially resulting in lower pricing for our products and services. Continued instability in the capital markets, as a result of recession or otherwise, also may continue to affect the cost of capital and the ability to raise capital, both for us and our customers.
 
During times when oil or natural gas prices are low, many of our customers are more likely to experience a downturn in their financial condition. Current economic conditions may be exacerbated by insufficient financial sector liquidity, leading to additional constraints on the operating cash flows of our customers, further limiting their activities and also potentially impacting their ability to pay us in a timely manner, which could result in increased customer bankruptcies and may lead to increased uncollectible receivables.

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

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

Our revenues from oil and gas production represent approximately 19.8% of our total consolidated revenues for the year ended December 31, 2009. Therefore, we have significant direct market risk exposure in the pricing of our oil and gas production. Our realized pricing is primarily driven by the prevailing worldwide price for crude oil and spot prices in the U.S. natural gas market for our unhedged production and the fixed prices in our derivative contracts for the portion of our oil and gas production that is hedged. During 2009, the
 
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crude oil and natural gas prices we received averaged $61.35 and $4.00, respectively, prior to the impact of our derivative contracts. These crude oil and natural gas prices were significantly below the prices we received during 2008, and price volatility for crude oil and natural gas is expected to continue. Significant further declines in prices for oil and natural gas could have a material adverse effect on our results of operations and quantities of reserves recoverable on an economic basis.

Our risk management activities involve the use of derivative financial instruments, such as swap agreements, to hedge the impact of market price risk exposures for a portion of our oil and gas production. A portion of our production is sold at a fixed price as a shield against price declines that could occur in the market. These hedging activities limit our upside potential from oil and gas price increases, but also limit our downside risk of decreasing oil and gas prices. In addition, we are exposed to the volatility of oil and gas prices for the portion of our oil and gas production that is not hedged. Currently, our derivative swap contracts do not extend beyond December 31, 2010.

Oil and gas prices and, therefore, the levels of well drilling, completion, workover, and production activities, tend to fluctuate. Worldwide military, political, and economic events, including initiatives by the Organization of Petroleum Exporting Countries and increasing or decreasing demand in other large world economies, have contributed to, and are likely to continue to contribute to, price volatility. The expansion of alternative energy supplies that compete with oil and gas, improvements in energy conservation, and improvements in the energy efficiency of vehicles, plants, equipment, and devices will also reduce oil and gas consumption or slow its growth.

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

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

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

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

We compete with numerous companies in our operations. Many of our competitors have substantially greater financial and other related resources than we have. To the extent competitors offer comparable products or services at lower prices, or higher quality or more cost-effective products or services, our business could be materially and adversely affected. Certain competitors may also be better positioned to acquire producing oil and gas properties or other businesses for which we compete.

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

We sell a variety of clear brine fluids to the oil and gas industry, including calcium chloride, calcium bromide, zinc bromide, and sodium bromide, some of which we manufacture and some of which are purchased from third parties. We also sell calcium chloride to non-energy markets. Sales of calcium chloride and bromide compound products contribute significantly to our revenues. In our
 
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manufacture of calcium chloride, we use brines, hydrochloric acid, and other raw materials purchased from third parties. In our manufacture of bromide compound products, we use bromine, hydrobromic acid, and other raw materials, including various forms of zinc, which are purchased from third parties. We rely on Chemtura as a supplier of raw materials, both for our bromide compound products needs as well as for the needs of our new El Dorado, Arkansas, calcium chloride plant. We also acquire bromide compound products from several third-party suppliers. If we are unable to acquire the bromide compound products, bromine, hydrobromic or hydrochloric acid, zinc, or any other supplies of raw material at reasonable prices for a prolonged period, our business could be materially and adversely affected.

As a result of the current general economic conditions, many chemicals manufacturing feedstock suppliers are experiencing reduced demand, production interruptions, and financial difficulties. For example, during March 2009, Chemtura announced that it had filed voluntary petitions for reorganization under Chapter 11 of the U.S. Bankruptcy code. Under bankruptcy, Chemtura had the right to accept or reject executory contracts, such as our agreements with them under which we acquire bromine and brine. During the fourth quarter of 2009, we negotiated certain amendments to our existing agreements with Chemtura, and such amended agreements were signed by Chemtura and approved by the bankruptcy court. While the amended agreements do include an increase in the cost of raw material bromine from Chemtura, other amendments partially mitigate the impact of the increased costs. Also during 2009, we wrote down the value of our investment in a European calcium chloride manufacturing joint venture following our joint venture partner’s announced shutdown of its adjacent plant facility that supplies feedstock to the joint venture’s plant. In addition, occasional supply constraints for certain of our manufacturing facilities have resulted in certain facilities operating at less than full capacity and resulted in decreased production volumes. A limitation of feedstock supply for our European calcium chloride manufacturing facility affected the production levels of that operation during a portion of 2009 and could affect its operations in the future. The purchase of alternative supplies at a less favorable cost could also result in decreased profitability.

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

The fabrication of GasJack® wellhead compressor units by our Compressco subsidiary requires the purchase of many types of components, some of which we obtain from a single source or a limited group of suppliers. Our reliance on these suppliers exposes us to the risk of price increases, inferior component quality, or an inability to obtain an adequate supply of required components in a timely manner. Our Compressco operation’s profitability or future growth may be adversely affected due to our dependence on these key suppliers.

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

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

The marketing of oil and gas production depends in large part on the availability, proximity, and capacity of pipelines, gas gathering systems and other transportation, processing and refining facilities, as well as the existence of adequate markets. If there was insufficient capacity available on these systems, or if these systems were unavailable to us, the price offered for our production could be significantly depressed, or we could be forced to shut-in some production or delay or discontinue drilling plans while we construct our own facilities. We also rely (and expect to rely in the future) on facilities developed and owned by third parties in order to process, transmit, and sell our oil and gas production. Our plans to develop and sell our oil and gas reserves could be materially and adversely affected by the inability or unwillingness of third parties to provide sufficient transmission or processing facilities to us.

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

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

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

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

Under generally accepted accounting principles, we also review the carrying value of our goodwill for possible impairment annually or when events or changes in circumstances indicate the carrying value may not be recoverable. Changes in circumstances indicating the carrying value of our goodwill may not be recoverable include a decline in our stock price and our market capitalization, future cash flows, and slower growth rates in our industry. In connection with the preparation of our annual financial statements as of December 31, 2008, we determined that a $47.1 million impairment of goodwill was required. If current economic and market conditions persist or decline further, we may be required to record an additional charge to earnings during the period in which any impairment of our goodwill is determined, resulting in an impact on our results of operations.

Operating Risks:

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

We are subject to operating hazards normally associated with the oilfield service industry and offshore oil and gas production operations, including fires, explosions, blowouts, formation collapse, mechanical problems, abnormally pressured formations, and environmental accidents. Environmental accidents could include, but are not limited to, oil spills; gas leaks or ruptures; uncontrollable flows of oil, gas, or well fluids; or discharges of CBFs or toxic gases or other pollutants. These operating hazards also include injuries to employees and third parties during the performance of our operations. Our operation of marine vessels, heavy equipment, offshore production platforms, and the performance of heavy lift and diving services involve a particularly high level of risk. In addition, certain of our employees who perform services on offshore platforms and vessels are covered by the provisions of the Jones Act, the Death on the High Seas Act, and general maritime law. These laws make the liability limits established by state workers’ compensation laws inapplicable to these employees and, instead, permit them or their representatives to pursue actions against us for damages for job-related injuries. Whenever possible, we obtain agreements from customers and suppliers that limit our exposure. However, the occurrence of certain operating hazards, including storms, could result in substantial losses to us due to injury or loss of life, damage to or destruction of property and equipment, pollution or environmental damage, and suspension of operations.

We have maintained a policy of insuring our risks of operational hazards that we believe is typical in the industry. Limits of insurance coverage we have purchased are consistent with the exposures we face and the nature of our products and services. Due to economic conditions in the insurance industry, from time to time, we have increased our self-insured retentions for certain policies in order to minimize the increased costs of coverage. In certain areas of our business, we, from time to time, have elected to assume the risk of loss for specific assets. To the extent we suffer losses or claims that are not covered, or are only partially covered by insurance, our results of operations could be adversely affected.

We face risks related to our growth strategy.

Our growth strategy includes both internal growth and growth through acquisitions. Internal growth may require significant capital expenditure investments, some of which may become unrecoverable or fail to
 
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generate an acceptable level of cash flows. Internal growth may also require financial resources (including the use of available cash or additional long-term debt) and management and personnel resources. Acquisitions also require significant financial and management resources, both at the time of the transaction and during the process of integrating the newly acquired business into our operations. If we overextend our current financial resources by growing too aggressively, we could face liquidity problems or have difficulty obtaining additional financing. Any such recent or future acquisition transactions by us may not achieve favorable financial results. Our operating results could also be adversely affected if we are unable to successfully integrate newly acquired companies into our operations, are unable to hire adequate personnel, or are unable to retain existing personnel. We may not be able to consummate future acquisitions on favorable terms. Acquisition or internal growth assumptions developed to support our decisions could prove to be overly optimistic, particularly if we do not provide for economic downturns. Future acquisitions by us could also result in issuances of equity securities, or the rights associated with the equity securities, which could potentially dilute earnings per share. Future acquisitions could also result in the incurrence of additional debt or contingent liabilities and amortization expenses related to intangible assets. These factors could adversely affect our future operating results and financial position.

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

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

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

We have recently completed the construction of a new calcium chloride plant facility near El Dorado, Arkansas. The plant’s future profitability and the advantages we expect to receive from the plant will be based on many factors, including the sales prices to be received for the plant’s products, raw material and operating costs, and future demand for products. In addition, delays in the completion of the final phases of the calcium chloride facility, as well as changes in its operating environment, could also affect future profitability for our Fluids Division operations compared to original expectations.

We could incur losses on fixed price contracts.

Due to competitive market conditions, a portion of our well abandonment and decommissioning projects may be performed on a turnkey, modified turnkey, or day rate basis. Pursuant to these types of contracts, defined work is delivered for a fixed price, and extra work, which is subject to customer approval, is charged separately. The revenue, cost, and gross profit realized on these types of contracts can vary from the estimated amount because of changes in offshore conditions, increases in the scope of the work to be performed, increased site clearance efforts required, labor and equipment availability, cost and productivity levels, and the performance level of other contractors. In addition, unanticipated events such as accidents, work delays, significant changes in the condition of platforms or wells, downhole problems, and environmental or other technical issues could result in significant losses on these types of projects. These variations and risks may result in our experiencing reduced profitability or losses on these types of projects or on well abandonment and decommissioning work for our Maritech subsidiary.

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

We have risks associated with our Maritech exploration and production business. These risks include those associated with finding and developing economically recoverable and marketable oil and natural gas
 
16
 
reserves, and finding and acquiring leases and existing reserves on attractive terms. There are uncertainties surrounding estimates of oil and gas reserve volumes, finding and development costs, production costs, and abandonment and decommissioning costs. To the extent we over-estimate future oil and natural gas sales prices, economically recoverable reserve volumes, or future production flow rates, or underestimate the associated costs of exploration and production operations, our financial results will be negatively impacted.

Drilling for oil and natural gas is a particularly risky activity that includes the risk that we will not encounter commercially productive oil or natural gas reservoirs. The costs of drilling and completion operations are often difficult to estimate, and the timing of drilling operations may be curtailed, delayed, or canceled as a result of a variety of factors including, but not limited to:
 
·  
unexpected drilling conditions;
·  
pressure or irregularities in formations;
·  
equipment failures or accidents;
·  
marine risks such as capsizing, collisions, and hurricanes;
·  
other adverse weather conditions;
·  
shortages or delays in the delivery of equipment; and
·  
compliance with environmental and other government requirements, which may increase our costs or restrict our activities.

During the three year period ended December 31, 2009, we have expended approximately $290.2 million of exploration and development costs, and we expect to continue to incur significant costs in the future. During this three year period ended December 31, 2009, we charged approximately $10.8 million of dry hole costs incurred to earnings. Future drilling activities also may not be successful, and, if unsuccessful, this failure could have an adverse effect on our future results of operations and financial condition. We may not recover all or any portion of our investment in new wells. In addition, we are often uncertain as to the future cost or timing of drilling, completing, and operating wells. While all drilling, whether developmental or exploratory, involves these risks, exploratory drilling involves greater risks of dry holes or failure to find commercial quantities of hydrocarbons.

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

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

Oil and gas reservoir analysis is a subjective process which involves estimating underground accumulations of oil and gas that cannot be measured in an exact manner. Estimates of economically recoverable oil and gas reserves and of future net cash flows associated with such reserves necessarily depend upon a number of variable factors and assumptions. Because all reserve estimates are to some degree subjective, each of the following items may prove to differ materially from that assumed in estimating reserves:
 
·  
the quantities of oil and gas that are ultimately recovered;
·  
production flow rates over time;
·  
the production and operating costs incurred;
·  
the amount and timing of future development and abandonment expenditures; and
·  
future oil and gas sales prices.

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

17
 
    The estimated discounted future net cash flows from proved reserves described in this Annual Report for the year ended December 31, 2009 should not be considered as the current market value of the estimated oil and gas proved reserves attributable to Maritech’s properties. Such estimates are based on prices and costs in accordance with SEC requirements, while future prices and costs may be materially higher or lower. Using lower prices in forecasting reserves will result in a shorter life being given to producing oil and natural gas properties because such properties, as their production levels are estimated to decline, will reach an uneconomic limit with lower prices at an earlier date. There can be no assurance that a decrease in oil and gas prices or other differences in Maritech’s estimates of its reserves will not adversely affect our financial position or results of operations.

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

In conjunction with our acquisition of oil and gas properties, we perform detailed due diligence review processes that we believe are consistent with industry practices. These acquired properties consist of both mature properties, which are generally in the later stages of their economic lives, as well as exploration and prospect opportunities. Each acquisition of oil and gas properties requires a thorough review of the expected cash flows acquired and the associated abandonment obligations assumed. The process of estimating oil and natural gas reserves is complex, requiring significant decisions and assumptions to be made in evaluating the available geological, geophysical, engineering, and economic data for each reservoir. The volatility of oil and natural gas commodity pricing additionally complicates the calculation of estimated future cash flows of properties to be acquired. As a result, these estimates are inherently imprecise. Actual future production, cash flows, development expenditures, operating and abandonment expenses, and quantities of recoverable natural gas and oil reserves may vary substantially from those initially estimated by us. Also, in conjunction with the purchase of certain oil and gas properties, we assume our proportionate share of the related well abandonment and decommissioning liabilities after performing detailed estimating procedures, analysis, and engineering studies. Our estimates of these future well abandonment and decommissioning liabilities are imprecise and are subject to change due to changes in the forecasts of the supply, demand, pricing and timing of well abandonment and decommissioning services; damage to wells and infrastructure caused by hurricanes and other natural events; changes in governmental regulations governing well abandonment and decommissioning work; and other factors. During 2009, Maritech adjusted its decommissioning liability, either for work performed during the year or related to adjusted estimates of the cost of future work to be performed. Approximately $23.8 million of this adjustment was charged to earnings as an operating expense during 2009. If the actual cost of future abandonment and decommissioning work is materially greater than our current estimates, such additional costs could have an additional adverse effect on earnings.

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

The rate of production from oil and gas properties generally declines as reserves are depleted. Approximately 42.3% of our proved reserves as of December 31, 2009 are proved producing reserves. Except to the extent that we find or acquire additional properties containing estimated proved reserves; conduct successful exploration or development activities; or through engineering studies, identify additional behind-pipe zones, secondary recovery reserves, or tertiary recovery reserves, our estimated proved reserves will decline materially as reserves are produced. Natural gas and oil commodity pricing, as well as constraints on the amount of capital we have available to allocate to oil and gas activities, may limit our exploitation, development, or exploration activities for the foreseeable future, which will reduce our ability to replace produced oil and gas reserves. Future oil and gas production is, therefore, highly dependent upon our ability and level of success in acquiring or finding additional reserves.

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

We account for our oil and gas operations using the successful efforts method. Costs incurred to drill and equip development wells, including unsuccessful development wells, are capitalized. Costs related to unsuccessful exploratory wells are expensed as incurred. All capitalized costs are accumulated and recorded separately for each field and are depleted on a unit-of-production basis, based on the estimated remaining equivalent proved oil and gas reserves of each field. The capitalized costs of our oil and natural gas properties, on a field basis, cannot exceed the estimated undiscounted future net cash flows of that field. If net capitalized costs exceed undiscounted future net revenues, we must write down the costs of each such field to our estimate of its fair market value. Accordingly, a significant decline in oil or natural gas prices, unsuccessful exploration and/or development efforts, or an increase in our decommissioning liabilities could
 
18
 
cause a future write-down of capitalized costs. During the three year period ended December 31, 2009, and primarily due to increased decommissioning liabilities and the decrease in oil and natural gas prices, we recorded oil and gas property impairments on proved properties totaling approximately $130.2 million. Unproved properties are evaluated at the lower of cost or fair market value. On a field by field basis, our oil and gas properties are assessed for impairment in value whenever indicators become evident, with any impairment charged to expense. Under the successful efforts method of accounting, we are exposed to the risk that the value of a particular property (field) would have to be written down or written off if an impairment were present.

Weather Related Risks:

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

The Offshore Services segment has historically enjoyed its highest vessel utilization rates during the period from April to October, when weather conditions are typically more favorable for offshore activities, and has experienced its lowest utilization rates in the period from November to March. This segment, under certain turnkey and other contracts, may bear the risk of delays caused by adverse weather conditions. Severe storms can also cause our oil and gas producing properties to be shut-in. In addition, demand for other products and services we provide are subject to seasonal fluctuations, due in part to weather conditions that cannot be predicted. Accordingly, our operating results may vary from quarter to quarter depending on weather conditions in applicable areas.

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

A significant portion of our operations is susceptible to adverse weather conditions in the Gulf of Mexico, including hurricanes and other extreme weather conditions. High winds, rising water, storm surge, and turbulent seas can cause significant damage and curtail our operations for extended periods while damage is being assessed and remediated. The costs to bring damaged offshore wells under control and to repair or remove damaged offshore platforms and pipelines can be significant. Moreover, even if we do not experience direct damage from storms, we may experience disruptions in our operations because customers or suppliers may curtail their activities due to damage to their wells, platforms, pipelines, and other facilities.

We will expend significant costs to repair damage as a result of 2005 and 2008 hurricanes, and a large portion of these costs may not be covered under our insurance policies.

We incurred significant damage to certain of our onshore and offshore operating equipment and facilities during the third quarters of 2005 and 2008, primarily as a result of Hurricanes Katrina, Rita, and Ike. In particular, our Maritech subsidiary suffered varying levels of damage to the majority of its offshore oil and gas producing platforms, and six of its platforms were destroyed by these storms. In addition, two production facilities located in inland waters were destroyed. Reconstruction of the two destroyed production facilities is substantially complete, and one of the destroyed platforms was decommissioned during 2009. A majority of our damaged assets, with the exception of the remaining destroyed Maritech platforms, have been repaired or are in the final stages of being repaired, and have resumed operation. Remaining hurricane damage repair efforts consist primarily of the well intervention, abandonment, decommissioning, and debris removal associated with the destroyed offshore platforms and the construction of replacement platforms and redrilling of a number of destroyed wells. While a portion of the well intervention, abandonment, and decommissioning work has been performed on some of the destroyed platforms and the inland water production facilities, a significant portion of the work has yet to be performed. Through December 31, 2009, we have expended approximately $75.8 million for the well intervention, abandonment, decommissioning, and debris removal work performed on the platforms and production facilities which were destroyed by the storms. The remaining damage assessment, well intervention, and subsequent debris removal efforts could continue over the next several years. We estimate that remaining well intervention, abandonment, and decommissioning efforts associated with the destroyed platforms and production facilities, as well as the efforts to remove debris, reconstruct destroyed structures, and redrill associated wells, will be performed at an additional cost of approximately $95 to $110 million net to our interest and before any insurance recoveries. Due to the non-routine nature of the well intervention and debris removal efforts, however, our estimates of the future cost to perform this work may be understated, possibly significantly.

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

With regard to the damages associated with Hurricane Ike, we have performed a significant majority of the property repairs on the damaged platforms and have performed a portion of the well intervention work related to the platforms that were destroyed. Despite our confidence that the repair, well intervention, and debris removal costs will qualify as covered costs pursuant to our insurance coverage, a portion of these costs may not be reimbursed. Also, the timing of the collection of any future reimbursements is beyond our control, and we will continue to use a significant amount of our working capital until such reimbursements are received. In addition, a portion of the reimbursements ultimately received may be offset by legal and other administrative costs incurred in our attempts to collect them. Our estimates of the remaining costs to be incurred may be imprecise. To the extent actual future costs exceed the policy maximum for these costs, such excess costs would not be reimbursable.

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

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

Our operating cash flows continue to be affected by the interruption in Maritech’s oil and gas production as a result of damage to offshore platforms and pipelines caused by the 2008 hurricanes. One of the destroyed offshore platforms has resulted in the loss of production from a key producing field which represented 24.3% of our pre-storm production. During the fourth quarter of 2009, Maritech modified one of the remaining platforms in this field and has restored a portion of the interrupted production. The full resumption of production from this field will require the construction of a new platform and several wells to be redrilled, and these efforts are estimated to cost approximately $25 to $30 million, before insurance recoveries, and are not scheduled to be completed until 2011. With regard to the shut-in production, our insurance protection does not include business interruption coverage. While repair and recovery efforts have been prioritized to restore Maritech’s production as soon as possible, these production restoration efforts are expected to continue into 2011 and beyond. The full resumption of Maritech’s pre-storm production levels may never occur.

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

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


 
20
 

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

Financial Risks:

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

As of December 31, 2009, our total debt outstanding was approximately $310.1 million and our debt to total capital ratio was 35.0%. This debt to total capital ratio excludes approximately $33.4 million of available cash held as of December 31, 2009. Additional growth could result in increased debt levels to support our capital expenditure needs or acquisition activities. Debt service costs related to outstanding long-term debt represent a significant use of our operating cash flow and could increase our vulnerability to general adverse economic and industry conditions. Our long-term debt agreements contain customary covenants and other restrictions and requirements. In addition, the agreements require us to maintain certain financial ratio requirements. Significant deterioration of these ratios could result in a default under the agreements. The agreements also include cross-default provisions relating to any other indebtedness we have that is greater than a defined amount. If any such indebtedness is not paid or is accelerated and such event is not remedied in a timely manner, a default will occur under the long-term debt agreements. Any event of default, if not timely remedied, could result in a termination of all commitments of the lenders and an acceleration of any outstanding loans and credit obligations.

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

We are exposed to significant credit risks.

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

Maritech purchases interests in oil and gas properties in connection with the operations of our Offshore Division. As the owner and operator of these interests, Maritech is liable for the proper abandonment and decommissioning of the wells, platforms, and pipelines as well as the site clearance related to these properties. We have guaranteed a portion of the abandonment and decommissioning liabilities of Maritech. In certain instances, Maritech is entitled to be paid in the future for all or a portion of these obligations by the previous owner of the property once the liability is satisfied. We and Maritech are subject to the risk that the previous owner(s) will be unable to make these future payments. In addition, if Maritech acquires less than 100% of the working interest in a property, its co-owners are responsible for the payment of their portions of the associated operating expenses and abandonment liabilities. However, if one or more co-owners do not pay their portions, Maritech and any other nondefaulting co-owners may be liable for the defaulted amount. If any required payment is not made by a previous owner or a co-owner and any security is not sufficient to cover the required payment, we could suffer material losses.

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

The operations of certain of our subsidiaries are exposed to fluctuations between the U.S. dollar and certain foreign currencies. Our plans to grow our international operations could cause this exposure from fluctuating currencies to increase. In particular, our growing operations in Brazil, as a result of a long-term contract with Petrobras entered into during 2008, will subject us to increased foreign currency risk in that country. Historically, exchange rates of foreign currencies have fluctuated significantly compared to the U.S.
 
21
 
dollar, and this exchange rate volatility is expected to continue. Significant fluctuations in foreign currencies against the U.S. dollar could adversely affect our balance sheet and results of operations.

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

Our revolving credit facility consists of floating rate loans which bear interest at an agreed upon percentage rate spread above LIBOR. Although as of December 31, 2009, there is no balance outstanding under the revolving credit facility, there is no assurance that we will not borrow under the facility in the future. Accordingly, our cash flows and results of operations are subject to interest rate risk exposure associated with the level of the variable rate debt balance outstanding. We currently are not a party to an interest rate swap contract or other derivative instrument designed to hedge our exposure to interest rate fluctuation risk.

The terms governing our revolving credit facility were agreed to in June 2006. The revolving credit facility is scheduled to mature in June 2011. The terms governing our Senior Notes were agreed to in September 2004, April 2006, and April 2008, and these Senior Notes all bear interest at fixed interest rates and are scheduled to mature at various dates between September 2011 and April 2016. The terms for our indebtedness were negotiated during a period of historically low interest rates and credit spreads. There can be no assurance that the financial market conditions at the times these existing debt agreements are renegotiated will be on terms as favorable as their current terms.

Legal, Regulatory, and Political Risks:

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

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

A large portion of Maritech’s oil and gas operations are conducted on federal leases that are administered by the Minerals Management Service (MMS) and are required to comply with the regulations and orders promulgated by the MMS under the Outer Continental Shelf Lands Act. MMS regulations also establish construction requirements for production facilities located on federal offshore leases and govern the plugging and abandonment of wells and the removal of production facilities from these leases. Under limited circumstances, the MMS could require us to suspend or terminate our operations on a federal lease. The MMS also establishes the basis for royalty payments due under federal oil and natural gas leases through regulations issued under applicable statutory authority.

Our business exposes us to risks such as the potential for harmful substances escaping into the environment and causing damages or injuries, which could be substantial. Although we maintain general liability and pollution liability insurance, these policies are subject to exceptions and coverage limits. We maintain limited environmental liability insurance covering named locations and environmental risks associated with contract services for oil and gas operations and for oil and gas producing properties. We could be materially and adversely affected by an enforcement proceeding or a claim that is not covered or is only partially covered by insurance.

 
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    Legislation currently pending in the U.S. Congress would establish an economy-wide cap-and-trade program to reduce U.S. emissions of greenhouse gases. Under this legislation, EPA would issue a capped and steadily declining number of tradable emissions allowances to certain major sources of greenhouse gas emissions so that such sources could continue to emit greenhouse gases into the atmosphere. It is not possible at this time to predict whether or when the U.S. Congress will pass climate change legislation, or how any bill approved by Congress may be reconciled with state and regional requirements. In addition, a variety of regulatory developments, proposals, or requirements have been introduced and/or adopted in international regions in which we operate that are focused on restricting the emission of carbon dioxide, methane, and other greenhouse gases.

Because our business depends on the level of activity in the oil and natural gas industry, existing or future laws, regulations, treaties or international agreements related to greenhouse gases and climate change, including incentives to conserve energy or use alternative energy sources, could have a negative impact on our business if such laws, regulations, treaties or international agreements reduce the worldwide demand for oil and natural gas or otherwise result in reduced economic activity generally. In addition, such laws, regulations, treaties or international agreements could result in increased compliance costs, capital spending requirements, or additional operating restrictions, which may have a negative impact on our business. In addition to potential impacts on our business directly or indirectly resulting from climate-change legislation or regulations, our business also could be negatively affected by climate-change related physical changes or changes in weather patterns.
 
In addition to increasing our risk of environmental liability, the rigorous enforcement of environmental laws and regulations has accelerated the growth of some of the markets we serve. Decreased regulation and enforcement in the future could materially and adversely affect the demand for the types of services offered by certain of our Offshore Services operations and, therefore, materially and adversely affect our business.

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

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

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

We plan to grow both in the United States and in foreign countries. We have established operations in, among other countries, Brazil, Mexico, Argentina, Canada, the United Kingdom, Norway, Finland, Sweden, and India, and have operating joint ventures in Saudi Arabia, and Libya. A portion of our planned future growth includes expansion into additional countries. Foreign operations carry special risks. Our business in the countries in which we currently operate and those in which we may operate in the future could be limited or disrupted by:
 
·  
government controls and government actions such as expropriation of assets and changes in legal and regulatory environments;
·  
import and export license requirements;
·  
political, social, or economic instability;
·  
trade restrictions;
·  
changes in tariffs and taxes;
·  
restrictions on repatriating foreign profits back to the United States;
·  
the impact of anti-corruption laws and the risk that actions taken by us or others on our behalf may adversely affect our operations and competitive position in the affected countries; and
·  
the limited knowledge of these markets or the inability to protect our interests.

We and our affiliates operate in countries where governmental corruption has been known to exist. While we and our subsidiaries are committed to conducting business in a legal and ethical manner, there is a risk of violating either the U.S. Foreign Corrupt Practices Act (FCPA) or laws or legislation promulgated pursuant to the 1997 OECD Convention on Combating Bribery of Foreign Public Officials in International Business Transactions or other applicable anti-corruption regulations that generally prohibit the making of
 
23
 
improper payments to foreign officials for the purpose of obtaining or keeping business. Violation of these laws could result in monetary penalties against us or our subsidiaries and could damage our reputation and, therefore, our ability to do business.

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

Item 1B. Unresolved Staff Comments.

None.

Item 2. Properties.

Our properties consist primarily of our corporate headquarters facility, chemical plants, processing plants, distribution facilities, barge rigs, heavy lift and dive support vessels, well abandonment and decommissioning equipment, oil and gas properties, flow back testing equipment, and compression equipment. The following information describes facilities that we leased or owned as of December 31, 2009. We believe our facilities are adequate for our present needs.

Fluids Division. Fluids Division facilities include eight chemical production plants located in the states of Arkansas, California, Louisiana, and West Virginia, and the country of Finland, having a total production capacity of more than 1.5 million tons per year. The two California locations contain 29 square miles of acreage containing solar evaporation ponds and leased mineral acreage. In addition, the Fluids Division also owns and leases brine mineral reserves in Arkansas.

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

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

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

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

Production Enhancement Division. Production Enhancement Division facilities include fifteen production testing distribution facilities in the U.S. (thirteen of which are leased) located in Texas, Colorado, Louisiana, and Pennsylvania. In addition, the Production Testing segment has leased facilities in Brazil, Mexico, Libya, Bahrain, India, and Saudi Arabia. Compressco’s facilities include a fabrication and headquarters facility in Oklahoma, a leased fabrication facility in Alberta, Canada, a leased service facility in New Mexico, and six sales offices in Oklahoma, Texas, Colorado, New Mexico, Louisiana, and Canada.

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

Oil and Gas Properties.

The following tables show, for the periods indicated, reserves and operating information related to our Maritech subsidiary’s oil and gas interests in developed and undeveloped leases, all of which are located in
 
24
 
the Gulf of Mexico region. Maritech’s oil and gas operations are a separate segment included within our Offshore Division. The following table provides a brief description as of December 31, 2009 of Maritech’s most significant oil and gas properties:
 
 
Net Total
                            
 
Proved
  
Net Proved
  
Productive
                
 
Reserves
  
Reserves Mix
  
Gross
  
Developed
  
Undeveloped
  
Working
  
Production
 
(MBOE)
  
Oil%
  
Gas%
  
Wells
  
Acreage
  
Acreage
  
Interest %
  
Status
                               
Timbalier Bay Area
4,606
  
76%
  
24%
  
67
  
 8,270
  
 7,174
  
100%
  
Producing
Cimarex Properties,
                            
   Main Pass Area
2,101
  
13%
  
87%
  
16
  
 71,172
  
 14,984
  
47% - 100%
  
Producing
East Cameron 328
2,024
  
92%
  
8%
  
6
  
 5,000
  
 -
  
50%
  
Producing
 
Production information for each of these most significant properties during the three years ended December 31, 2009 is as follows:


 
Year Ended December 31,
 
2009
  
2008
  
2007
 
(MBOE)
           
Timbalier Bay Area
 764
  
 1,289
  
 1,702
Cimarex Properties,
          
  Main Pass Area
 1,034
  
 580
  
 4
East Cameron 328
 60
  
 275
  
 403


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

Oil and Gas Reserves. Through our Maritech subsidiary, we employ full-time, experienced reservoir engineers and geologists, who are responsible for determining proved reserves in conformance with guidelines established by the SEC. These SEC guidelines were revised effective with the December 31, 2009 information. The impact of the revision to these reserve guidelines was not considered significant to our proved oil and gas reserve volumes. The value of the oil and gas reserves was affected by the impact of the new average pricing requirements. Reserve estimates were prepared by Maritech engineers, based upon their interpretation of production performance data and geologic interpretation of sub-surface information derived from the drilling of wells. In accordance with Maritech’s documented oil and gas reserve policy as prescribed by our Board of Directors, the preparation of these reserve estimates is subject to Maritech’s system of internal control whereby key inputs in preparing reserve estimates, such as oil and natural gas pricing data, oil and gas property ownership interest percentages, and data regarding levels of operating, development, and abandonment costs, are reviewed by Maritech personnel outside of the reserve engineering department. Reserve estimates are also reviewed by Maritech’s President, who is also a licensed professional engineer and has overall responsibility for overseeing the preparation of the proved reserve estimates. In addition to the complete analysis and review by Maritech’s internal reservoir engineers, independent petroleum engineers and geologists performed reserve audits of approximately 80.2% of our proved reserve volumes as of December 31, 2009. The use of the term “reserve audit” is intended only to refer to the collective application of the engineering and geologic procedures which the independent petroleum engineering firms were engaged to perform and may be defined and used differently by other companies.

A reserve audit is the process of reviewing certain of the pertinent facts interpreted and assumptions made that have resulted in an estimate of reserves prepared by others and the rendering of an opinion about the appropriateness of the methodologies employed, the adequacy and quality of the data relied upon, the depth and thoroughness of the reserves estimation process, the classification of reserves appropriate to the relevant definitions used, and the reasonableness of the estimated reserve quantities. In performing a reserve audit, an independent petroleum engineering firm meets with our technical staff to collect all necessary geologic, geophysical, engineering, and economic data, and performs an independent reserve evaluation. The reserve audit of our oil and gas reserves involves the rigorous examination of our technical evaluation, as well as the interpretation and extrapolation of well information such as flow rates, reservoir pressure declines, and other technical information and measurements. Maritech’s internal reservoir engineers interpret this data
 
25
 
to determine the nature of the reservoir and, ultimately, the quantity of proved oil and gas reserves attributable to the specific property. Our proved reserves, as reflected in this Annual Report, include only quantities that Maritech expects to recover commercially using current technology, prices, and costs, within existing economic conditions, operating methods, and governmental regulation. While Maritech can be reasonably certain that the proved reserves are economically producible, the timing and ultimate recovery can be affected by a number of factors, including completion of development projects, reservoir performance, regulatory approvals, and changes in projections of long-term oil and gas prices. Revisions can include upward or downward changes in the previously estimated volumes of proved reserves for existing fields due to evaluation of (1) already available geologic, reservoir, or production data or (2) new geologic or reservoir data obtained from wells. Revisions can also occur associated with significant changes in development strategy, oil and gas prices, or the related production equipment/facility capacity. Maritech’s independent petroleum engineers also examined the reserve estimates with respect to reserve categorization, using the definitions for proved reserves set forth in Regulation S-X Rule 4-10(a), Staff Accounting Bulletin No. 113, and subsequent SEC staff interpretations and guidance.

Maritech engaged Ryder Scott Company, L.P. and DeGolyer and MacNaughton to perform the reserve audits of a portion of our oil and gas reserves as of December 31, 2009, 2008, and 2007. Both Ryder Scott Company, L.P. and DeGolyer and MacNaughton are established oil and gas reservoir engineering firms providing engineering services worldwide. The staffs of both of these firms, including the personnel assigned to the reserve audits of Maritech’s reserve estimates, include licensed reservoir engineers experienced in performing these services. In the conduct of these reserve audits, these independent petroleum engineering firms did not independently verify the accuracy and completeness of information and data furnished by Maritech with respect to property interests owned, oil and gas production and well tests from examined wells, or historical costs of operation and development; however, they did verify product prices, geological structural and isopach maps, along with reservoir data such as well logs, core analyses, and pressure measurements. If, in the course of the examinations, a matter of question arose regarding the validity or sufficiency of any such information or data, the independent petroleum engineering firms did not accept such information or data until all questions relating thereto were satisfactorily resolved. Furthermore, in instances where decline curve analysis was not adequate in determining proved producing reserves, the independent petroleum engineering firms performed volumetric analysis, which included the analysis of geologic, reservoir, and fluids data. Proved undeveloped reserves were analyzed by volumetric analysis, which takes into consideration recovery factors relative to the geology of the location and similar reservoirs. Where applicable, the independent petroleum engineering firms examined data related to well spacing, including potential drainage from offsetting producing wells, in evaluating proved reserves of undrilled well locations.

The reserve audit performed by Ryder Scott Company, L.P. included certain properties selected by Maritech, including all of our significant properties described above, excluding the Cimarex Properties, and represented approximately 64.0% of our total proved oil and gas reserve volumes as of December 31, 2009. The reserve audit performed by DeGolyer and MacNaughton included the Cimarex Properties acquired in December 2007 and represented approximately 16.2% of our total proved oil and gas reserve volumes as of December 31, 2009. The independent petroleum engineers represent in their audit reports that they believe Maritech’s estimates of future reserves were prepared in accordance with generally accepted petroleum engineering and evaluation principles for the estimation of future reserves in accordance with SEC standards. In each case, the independent petroleum engineers concluded that the overall proved reserves for the reviewed properties as estimated by Maritech were, in the aggregate, reasonable within the established audit tolerance guidelines of 10% as set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers (SPE). There were no limitations imposed or encountered by Maritech or the independent petroleum engineers in the preparation of our estimated reserves or in the performance of the reserve audits by the independent petroleum engineers.

Reserve information is prepared in accordance with guidelines established by the SEC. All of Maritech’s reserves are located in U.S. state and federal offshore waters in the Gulf of Mexico region and onshore Louisiana. The following table sets forth information with respect to our estimated proved reserves as of December 31, 2009:
 
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Summary of Oil and Gas Reserves as of December 31, 2009
Based on Average Year Prices
             
   
Oil
  
Natural Gas
  
Total
Reserves category
  
(MBbls)
  
(MMcf)
  
(MBOE)
Proved reserves
            
   Developed
  
 5,690
  
 32,387
  
 11,088
   Undeveloped
  
 1,383
  
 1,124
  
 1,570
Total proved reserves
  
 7,073
  
 33,511
  
 12,658
 
Maritech’s proved undeveloped reserves as of December 31, 2009 represent approximately 12.4% of Maritech’s total proved reserves. Proved undeveloped reserves represented approximately 12.4% of Maritech total proved reserves as of December 31, 2008. During 2009, Maritech did not expend any of its development costs to convert proved undeveloped reserves to proved developed reserves. All of Maritech’s proved undeveloped reserves as of December 31, 2009 have been classified as proved undeveloped for less than five years. Maritech has historically developed its proved undeveloped reserves over a reasonable period of time and anticipates it will do so in the future, utilizing our future operating cash flows, available working capital, and if necessary, long-term borrowings.
 
For additional information regarding estimates of oil and gas reserves, including estimates of proved and proved developed reserves, the standardized measure of discounted future net cash flows, and the changes in discounted future net cash flows, see “Note R – Supplemental Oil and Gas Disclosures” in the Notes to Consolidated Financial Statements.

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

Production Information. The table below sets forth information related to production, average sales price, and average production cost per unit of oil and gas produced during 2009, 2008, and 2007:
 
   
Year Ended December 31,
  
   
2009
    
2008
    
2007
  
Production:
                  
   Natural gas (Mcf)
     10,449,366       10,988,840       9,515,214  
   Oil (Bbls)
     1,324,815       1,466,621       1,985,183  
                         
Revenues:
                        
   Natural Gas
   $ 87,905,000     $ 99,901,000     $ 76,202,000  
   Oil
     86,286,000       107,279,000       137,136,000  
                         
   Total
   $ 174,191,000     $ 207,180,000     $ 213,338,000  
                         
Average realized unit prices and production costs:
                  
   Natural gas (per Mcf)
   $ 8.41     $ 9.09     $ 8.01  
   Oil (per Bbl)
   $ 65.13     $ 73.15     $ 69.08  
                         
   Production cost per equivalent barrel
   $ 25.80     $ 27.18     $ 25.08  
   Depletion cost per equivalent barrel
   $ 25.96     $ 25.14     $ 20.70  
 
Realized unit prices include the impact of hedge commodity swap contracts. Production cost per equivalent barrel excludes the impact of storm repair and insurance related costs and recoveries, which were charged or credited to operations during each of the years presented, with approximately $8.2 million, $8.5 million, and $13.5 million being charged in 2009, 2008, and 2007, respectively. Equivalent barrel (BOE) information is calculated assuming six Mcf of gas is equivalent to one barrel of oil. Insurance recoveries during 2009 totaled approximately $45.4 million and are excluded from production cost per equivalent barrel for the year. The 2008 production cost per equivalent barrel was also increased due to the impact of
 
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hurricanes, which resulted in significant properties being shut-in during the last four months of 2008 and during much of 2009. Depletion cost per equivalent barrel excludes the impact of dry hole costs and property impairments.

Acreage and Productive Wells. At December 31, 2009, our Maritech subsidiary owned interests in the following oil and gas wells and acreage:
 
 
Productive Gross
  
Productive Net
  
Developed
  
Undeveloped
 
Wells
  
Wells
  
Acreage
  
Acreage
State/Area
Oil
  
Gas
  
Oil
  
Gas
  
Gross
  
Net
  
Gross
  
Net
                               
Louisiana Onshore
 13
  
 1
  
1.20
  
0.10
  
7,468
  
7,123
  
 4,169
  
 3,855
Louisiana Offshore
 42
  
 32
  
42.00
  
32.00
  
8,270
  
8,270
  
 7,174
  
 6,580
Texas Offshore
 -
  
 -
  
 -
  
 -
  
7,200
  
1,532
  
 -
  
 -
Federal Offshore
 42
  
 55
  
22.50
  
22.30
  
281,972
  
138,136
  
52,482
  
38,022
                               
Total
 97
  
 88
  
65.70
  
54.40
  
304,910
  
155,061
  
63,825
  
48,457
 
The majority of Maritech’s oil and gas properties are held by production. Leases covering undeveloped acreage other than acreage held by production have expiration terms ranging from 2010 through 2014.

Drilling Activity. During 2009, Maritech participated in the drilling of 2 gross development wells (1.12 net wells) and one gross exploratory well (0.5 net wells), all of which were productive. Maritech participated in the drilling of 10 gross development wells (4.3 net wells) during 2008, two of which were unproductive. Maritech participated in the drilling of 16 gross development wells (11.4 net wells) during 2007, two of which were unproductive. As of December 31, 2009, one additional gross exploratory well (1.0 net wells) was in the process of being drilled. In the first quarter of 2010, Maritech sold a 50% working interest in this well to a partner. As of December 31, 2008, one additional gross well (0.5 net wells) was in the process of being drilled. As of December 31, 2007, there were 5 additional wells (2.5 net wells) in the process of being drilled.

Item 3. Legal Proceedings.

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

Insurance Litigation - Through December 31, 2009, we have expended approximately $55.2 million on well intervention and debris removal work primarily associated with the three Maritech offshore platforms and associated wells which were destroyed as a result of Hurricanes Katrina and Rita in 2005. As a result of submitting claims associated with well intervention costs expended during 2006 and 2007 and responding to underwriters’ requests for additional information, approximately $28.9 million of these well intervention costs were reimbursed; however, our insurance underwriters maintained that well intervention costs for certain of the damaged wells did not qualify as covered costs and certain well intervention costs for qualifying wells were not covered under the policy. In addition, the underwriters also maintained that there was no additional coverage provided under an endorsement we obtained in August 2005 for the cost of debris removal associated with these platforms or for other damage repairs associated with Hurricanes Katrina and Rita on certain properties in excess of the insured values provided by the property damage section of the policy. Although we provided requested information to the underwriters and had numerous discussions with the underwriters, brokers, and insurance adjusters, we did not receive the requested reimbursement for these contested costs. As a result, on November 16, 2007, we filed a lawsuit in Montgomery County, Texas, entitled Maritech Resources, Inc. v. Certain Underwriters and Insurance Companies at Lloyd’s, London subscribing to Policy no. GA011150U and Steege Kingston, in which we sought damages for breach of contract and various related claims and a declaration of the extent of coverage of an endorsement to the policy. We also made an alternative claim against our insurance broker, based on its procurement of the August 2005 endorsement, and a separate claim against underwriters’ insurance adjuster for its role in handling the insurance claim.
 
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During October 2009, we entered into a settlement agreement with regard to this lawsuit, under which we received approximately $40.0 million during the fourth quarter of 2009 associated with the August 2005 endorsement and well intervention costs incurred or to be incurred from Hurricanes Katrina and Rita. Except for approximately $0.6 million of proceeds expected to be received in March 2010, no significant additional insurance recoveries of well intervention, debris removal, or excess property damage costs associated with Hurricanes Katrina and Rita will be received. Following the collection of these amounts, we have collected approximately $136.6 million of insurance proceeds associated with damage from Hurricanes Katrina and Rita. This amount represents substantially all of the maximum coverage limits pursuant to our policies. We estimate that future well intervention, abandonment, decommissioning, and debris removal efforts related to these destroyed platforms will result in approximately $45 million to $50 million of additional costs, and an estimate of these costs has been accrued for as part of Maritech’s decommissioning liability. As a result of the resolution of this contingency, the full amount of settlement proceeds is reflected as a credit to earnings in the fourth quarter of 2009.

Class Action Lawsuit - Between March 27, 2008 and April 30, 2008, two putative class action complaints were filed in the United States District Court for the Southern District of Texas (Houston Division) against us and certain of our officers by certain stockholders on behalf of themselves and other stockholders who purchased our common stock between January 3, 2007 and October 16, 2007. The complaints assert claims under Sections 10(b) and 20(a) of the Securities Exchange Act of 1934, as amended, and Rule 10b-5 promulgated thereunder. The complaints allege that the defendants violated the federal securities laws during the period by, among other things, disseminating false and misleading statements and/or concealing material facts concerning our current and prospective business and financial results. The complaints also allege that, as a result of these actions, our stock price was artificially inflated during the class period, which enabled our insiders to sell their personally-held shares for a substantial gain. The complaints seek unspecified compensatory damages, costs, and expenses. On May 8, 2008, the Court consolidated these complaints as In re TETRA Technologies, Inc. Securities Litigation, No. 4:08-cv-0965 (S.D. Tex.). On August 27, 2008, Lead Plaintiff Fulton County Employees’ Retirement System filed its Amended Consolidated Complaint. On October 28, 2008, we filed a motion to dismiss the federal class action. On July 9, 2009, the Court issued an opinion dismissing, without prejudice, most of the claims in this lawsuit but permitting plaintiffs to proceed on their allegations regarding disclosures pertaining to the collectability of certain insurance receivables.

Between May 28, 2008 and June 27, 2008, two petitions were filed by alleged stockholders in the District Courts of Harris County, Texas, 133rd and 113th Judicial Districts, purportedly on our behalf. The suits name our directors and certain officers as defendants. The factual allegations in these lawsuits mirror those in the class action lawsuit, and the claims are for breach of fiduciary duty, unjust enrichment, abuse of control, gross mismanagement, and waste of corporate assets. The petitions seek disgorgement, costs, expenses, and unspecified equitable relief. On September 22, 2008, the 133rd District Court consolidated these complaints as In re TETRA Technologies, Inc. Derivative Litigation, Cause No. 2008-23432 (133rd Dist. Ct., Harris County, Tex.), and appointed Thomas Prow and Mark Patricola as Co-Lead Plaintiffs. This lawsuit was stayed by agreement of the parties pending the Court’s ruling on our motion to dismiss the federal class action. On September 8, 2009, the plaintiffs in this state court action filed a consolidated petition which makes factual allegations similar to the surviving allegations in the federal lawsuit.

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

Item 4. [Removed and Reserved.]

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PART II

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

Price Range of Common Stock

Our common stock is traded on the New York Stock Exchange under the symbol “TTI.” As of February 23, 2010, there were approximately 10,800 holders of record of the common stock. The following table sets forth the high and low sale prices of the common stock for each calendar quarter in the two years ended December 31, 2009, as reported by the New York Stock Exchange.
 
   
High
    
Low
  
2009
            
     First Quarter
   $ 6.28     $ 1.94  
     Second Quarter
     10.44       3.01  
     Third Quarter
     10.74       6.79  
     Fourth Quarter
     11.62       8.70  
                 
2008
                
     First Quarter
   $ 19.38     $ 13.56  
     Second Quarter
     25.00       14.72  
     Third Quarter
     24.02       5.69  
     Fourth Quarter
     7.24       3.12  
 
Market Price of Common Stock

The following graph compares the five-year cumulative total returns of our common stock, the Standard & Poor’s 500 Composite Stock Price Index (S&P 500) and the Philadelphia Oil Service Sector Index (PHLX Oil Service Sector), assuming $100 invested in each stock or index on December 31, 2004, all dividends reinvested, and a fiscal year ending December 31. This information shall be deemed furnished, and not filed, in this Form 10-K and shall not be deemed incorporated by reference into any filing under the Securities Act of 1933 or the Securities Exchange Act of 1934 as a result of this furnishing, except to the extent we specifically incorporate it by reference.
 
Dividend Policy

We have never paid cash dividends on our common stock. We currently intend to retain earnings to finance the growth and development of our business. Any payment of cash dividends in the future will depend upon our financial condition, capital requirements, and earnings, as well as other factors the Board of Directors may deem relevant. We declared a dividend of one Preferred Stock Purchase Right per share of
 
30
 
common stock to holders of record at the close of business on November 6, 1998. See “Note T – Stockholders’ Rights Plan” in the Notes to Consolidated Financial Statements attached hereto for a description of such Rights. See “Management’s Discussion and Analysis of Financial Condition and Results of Operation – Liquidity and Capital Resources” for a discussion of potential restrictions on our ability to pay dividends.
 
Purchases of Equity Securities by the Issuer and Affiliated Purchasers
 
In January 2004, our Board of Directors authorized the repurchase of up to $20 million of our common stock. Purchases may be made from time to time in open market transactions at prevailing market prices. The repurchase program may continue until the authorized limit is reached, at which time the Board of Directors may review the option of increasing the authorized limit. During 2004 through 2005, we repurchased 340,950 shares of our common stock pursuant to the repurchase program at a cost of approximately $5.7 million. There were no repurchases made during 2006, 2007, 2008, or 2009 pursuant to the repurchase program. Shares repurchased during the fourth quarter of 2009 other than pursuant to our repurchase program are as follows:
 
Period
  
Total Number of Shares Purchased
    
Average Price Paid per Share
    
Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs (1)
    
Maximum Number (or Approximate Dollar Value) of Shares that May Yet Be Purchased Under the Publicly Announced Plans or Programs (1)
  
                         
Oct 1 - Oct 31, 2009
     -     $ -       -     $ 14,327,000  
                                 
Nov 1 - Nov 30, 2009
     1,929  (2)   $ 10.01       -     $ 14,327,000  
                                 
Dec 1 - Dec 31, 2009
     -     $ -       -     $ 14,327,000  
                                 
     Total
     1,929               -     $ 14,327,000  
(1)
In January 2004, our Board of Directors authorized the repurchase of up to $20 million of our common stock. Purchases may be made from time to time in open market transactions at prevailing market prices. The repurchase program may continue until the authorized limit is reached, at which time the Board of Directors may review the option of increasing the authorized limit.
(2)
Shares we received in connection with the vesting of certain employee restricted stock. These shares were not acquired pursuant to the stock repurchase program.
 
Item 6. Selected Financial Data.

The following tables set forth our selected consolidated financial data for the years ended December 31, 2009, 2008, 2007, 2006, and 2005. The selected consolidated financial data does not purport to be complete and should be read in conjunction with, and is qualified by, the more detailed information, including the Consolidated Financial Statements and related Notes and “Management’s Discussion and Analysis of Financial Condition and Results of Operation” appearing elsewhere in this report. Please read “Item 1A. Risk Factors” beginning on page 11 for a discussion of the material uncertainties which might cause the selected consolidated financial data not to be indicative of our future financial condition or results of operations. During 2008, Maritech acquired certain oil and gas properties. During 2007, we completed the acquisition of two service companies and Maritech acquired certain oil and gas properties. During 2006, we completed the acquisitions of the operations of Epic Divers, Inc., Beacon Resources, LLC, and a heavy lift barge. During 2005, we acquired certain oil and gas properties as part of our Maritech subsidiary’s operations. These acquisitions significantly impact the comparison of our financial statements for 2009 to earlier years. In December 2007, we sold our process services operations. In 2006, we made the decision to discontinue our Venezuelan fluids and production testing operations. In 2003, we made the decision to discontinue the operations of our Norwegian process services operations. During 2000, we commenced our exit from the micronutrients business. Accordingly, we have reflected each of the above operations as discontinued operations. During 2008, we recorded significant impairments of oil and gas properties, goodwill, and other long-lived assets. During 2007, we recorded significant impairments of our oil and gas properties.
 
31
 
   
Year Ended December 31,
  
   
2009
    
2008
    
2007
    
2006
    
2005
  
   
(In Thousands, Except Per Share Amounts)
  
Income Statement Data
                              
Revenues
   $ 878,877     $ 1,009,065     $ 982,483     $ 767,795     $ 509,249  
Gross profit
     213,097       152,001       116,383       252,804       123,672  (1) 
Operating income (loss)
     112,265       (21 )     16,512       160,800       54,317  
Interest expense
     (13,207 )     (17,557 )     (17,886 )     (13,637 )     (6,310 )
Interest income
     417       779       731       348       330  
Other income (expense), net
     5,895       12,884       2,805       4,858       3,692  
Income (loss) before discontinued
                                        
   operations
     68,807       (9,655 )     1,221       99,880       34,802  
Net income (loss)
   $ 68,804     $ (12,136 )   $ 28,771     $ 101,878     $ 38,062  
                                         
Income (loss) per share, before