tti10k-20110301.htm

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

 
FORM 10-K
(MARK ONE)
[ X ] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
FOR THE FISCAL YEAR ENDED DECEMBER 31, 2010
 
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  [ X ]   NO [   ]
 
INDICATE BY CHECK MARK IF DISCLOSURE OF DELINQUENT FILERS PURSUANT TO ITEM 405 OF REGULATION S-K IS NOT CONTAINED HEREIN, AND WILL NOT BE CONTAINED, TO THE BEST OF REGISTRANT’S KNOWLEDGE, IN DEFINITIVE PROXY OR INFORMATION STATEMENTS INCORPORATED BY REFERENCE IN PART III OF THIS FORM 10-K OR ANY AMENDMENT TO THIS FORM 10-K. [   ]
 
INDICATE BY CHECK MARK WHETHER THE REGISTRANT IS A LARGE ACCELERATED FILER, AN ACCELERATED FILER, A NON-ACCELERATED FILER, OR A SMALLER REPORTING COMPANY. SEE THE DEFINITIONS OF “LARGE ACCELERATED FILER,” “ACCELERATED FILER,” AND “SMALLER REPORTING COMPANY”  IN RULE  12b-2 OF THE EXCHANGE ACT. (CHECK ONE):
LARGE ACCELERATED FILER [ X ]
ACCELERATED FILER [   ]
NON-ACCELERATED FILER [   ]
SMALLER REPORTING COMPANY [   ]
 
INDICATE BY CHECK MARK WHETHER THE REGISTRANT IS A SHELL COMPANY (AS DEFINED IN RULE 12b-2 OF THE EXCHANGE ACT). YES [   ]  NO [ X ]
 
THE AGGREGATE MARKET VALUE OF COMMON STOCK HELD BY NON-AFFILIATES OF THE REGISTRANT WAS $668,609,042 AS OF JUNE 30, 2010, THE LAST BUSINESS DAY OF THE REGISTRANT’S MOST RECENTLY COMPLETED SECOND FISCAL QUARTER.
 
NUMBER OF SHARES OUTSTANDING OF THE ISSUER’S COMMON STOCK AS OF FEBRUARY 25, 2011 WAS 76,598,911 SHARES.
 
DOCUMENTS INCORPORATED BY REFERENCE
 
PART III INFORMATION IS INCORPORATED BY REFERENCE TO THE REGISTRANT’S PROXY STATEMENT FOR ITS ANNUAL MEETING OF STOCKHOLDERS TO BE HELD MAY 3, 2011 TO BE FILED WITH THE SECURITIES AND EXCHANGE COMMISSION WITHIN 120 DAYS OF THE END OF THE REGISTRANT’S FISCAL YEAR.

 
 

 


     TABLE OF CONTENTS

 
Part I
 
Item 1.
Business
  1
Item 1A.
Risk Factors
  13
Item 1B.
Unresolved Staff Comments
  27
Item 2.
Properties
  27
Item 3.
Legal Proceedings
  32
Item 4.
[Removed and Reserved]
  33
     
 
Part II
 
Item 5.
Market for Registrant’s Common Equity, Related Stockholder Matters, and
 
 
     Issuer Purchases of Equity Securities
  34
Item 6.
Selected Financial Data
  36
Item 7.
Management’s Discussion and Analysis of Financial Condition
 
 
     and Results of Operation
  37
Item 7A.
Quantitative and Qualitative Disclosures about Market Risk
  64
Item 8.
Financial Statements and Supplementary Data
  65
Item 9.
Changes in and Disagreements with Accountants on Accounting
 
 
     and Financial Disclosure
  65
Item 9A.
Controls and Procedures
  65
Item 9B.
Other Information
  65
     
 
Part III
 
Item 10.
Directors, Executive Officers, and Corporate Governance
  66
Item 11.
Executive Compensation
  66
Item 12.
Security Ownership of Certain Beneficial Owners and Management and
 
 
     Related Stockholder Matters
  66
Item 13.
Certain Relationships and Related Transactions, and Director Independence
  66
Item 14.
Principal Accounting Fees and Services
  66
     
 
Part IV
 
Item 15.
Exhibits, Financial Statement Schedules
  67


 
 

 

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

Item 1. Business.

General

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 certain clear brine fluids, additives, and other associated products and services to the oil and gas industry for use in well drilling, completion, and workover operations, both in the United States and in certain regions of Latin America, Europe, Asia, and Africa. The Division also markets liquid and dry calcium chloride manufactured at its production facilities to a variety of markets outside the energy industry.
 
Our Offshore Division consists of two operating segments: Offshore Services and Maritech. The Offshore Services segment provides (1) downhole and subsea oil and gas services such as well plugging and abandonment, workover, and wireline services, (2) decommissioning and certain construction services utilizing heavy lift barges and various cutting technologies in the construction or decommissioning of offshore oil and gas production platforms and pipelines, and (3) diving services involving conventional and saturated air diving.
 
The Maritech segment is an oil and gas exploration, development, and production operation focused in the offshore, inland waters, and onshore U.S. Gulf Coast region. The Offshore Division’s Offshore Services segment performs a significant portion of the well plugging, abandonment, and decommissioning services required by Maritech.
 
Our Production Enhancement Division consists of two operating segments: Production Testing and Compressco. The Production Testing segment provides production testing services in many of the major oil and gas basins in the United States, as well as in certain regions in Mexico, Brazil, Northern Africa, the Middle East, and other international markets.
 
The Compressco segment provides wellhead compression-based production enhancement services throughout most of the onshore producing regions of the United States, as well as certain basins in Canada, Mexico, South America, Europe, Asia, and other international locations.
 
We continue to pursue a growth strategy that includes expanding our existing businesses – both through internal growth and acquisitions – domestically and internationally. For financial information for each of our segments, including information regarding revenues and total assets, see “Note Q – Industry Segments and Geographic Information” contained in the Notes to Consolidated Financial Statements.
 
We were incorporated in Delaware in 1981. Our corporate headquarters are located at 24955 Interstate 45 North in The Woodlands, Texas. Our phone number is 281-367-1983, and our website is accessed at www.tetratec.com. We make available on our website, free of charge, our Corporate Governance
 
 
1

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

Products and Services

Fluids Division

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

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

The Division’s fluid engineering personnel determine the optimal CBF blend for a customer’s particular application to maximize the effectiveness and lifespan of the CBFs. We modify the specific density, crystallization temperature, and chemical composition of the CBFs as necessary. Our filtration services use a variety of techniques and equipment for the removal of particulates from CBFs at the customer’s site, so they can be reused. Filtration also enables recovery of a greater percentage of used CBFs for reconditioning.

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

Our liquid and dry calcium chloride production facilities are located in the United States and Europe. We also acquire liquid and dry calcium chloride inventory from other sources, including non-owned plants under agreements with the owners. Domestically, we manufacture calcium chloride at five manufacturing plant facilities, the largest of which is our plant near El Dorado, Arkansas. This plant was recently constructed and began production of liquid calcium chloride during the fourth quarter of 2009 and dry (flake) calcium chloride during January 2010. Liquid and flake calcium chloride are also produced at our Kokkola, Finland plant. We operate our European calcium chloride manufacturing operations under the name TETRA Chemicals Europe. As of December 31, 2010, we continued to operate a plant in Lake Charles, Louisiana,
 
 
2

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

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

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

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

Offshore Division

Our Offshore Division consists of two separate operating segments: Offshore Services and Maritech. The Offshore Services segment provides (1) downhole and subsea services such as well plugging and abandonment (P&A), workover, and wireline services, (2) decommissioning and certain construction services utilizing heavy lift barges and various cutting technologies in the construction or decommissioning of offshore oil and gas production platforms, subsea wells, and pipelines, and (3) diving services involving conventional and saturated air diving. We provide these services to offshore oil and gas operators in the U.S. Gulf of Mexico and in the inland water and onshore markets in the U.S. Gulf Coast region. We offer comprehensive, integrated services, including individualized engineering consultation and project management services. The Maritech segment is an oil and gas exploration, development, and production company operating in the offshore, inland waters, and onshore U.S. Gulf Coast regions. The Offshore Division’s Offshore Services segment performs a significant portion of the P&A and decommissioning services required by Maritech, and Maritech is a significant customer of the Offshore Services segment.

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

The size of our Offshore Services segment’s fleet of service vessels has expanded and contracted in recent years as necessary to serve the changing demand for well abandonment, construction, platform and pipeline decommissioning, construction, diving, and other offshore services. We currently have two vessels with the capacity to perform heavy lift decommissioning and construction projects and integrated operations on oil and gas production platforms. Subsequent to our acquisition of Epic in March 2006, we purchased a
 
 
3

 
 
dynamically positioned dive support vessel, the Epic Diver, and refurbished two of Epic’s existing dive support vessels, the Epic Explorer and the Epic Seahorse. The Epic Diver, which has been significantly utilized since we acquired it, has required extensive repair and refurbishment in the past and is currently in need of significant further repairs. In addition, certain of the Offshore Services segment’s more significant customers now require more technologically updated dive support vessels. In response to these changes, beginning in June 2009, we increased our service fleet by leasing a specialized dive support vessel, the Adams Challenge. In addition, the Offshore Services segment leases additional dive support vessels as they are needed. As a result, in December 2010, we determined that the Epic Diver is no longer strategic to our Offshore Services segment’s plans to serve its markets going forward, and a decision was made to divest the vessel. Each of the leased dive support vessels, as well as one of the Offshore Services segment’s owned dive support vessels, the Epic Explorer, includes a saturation diving system that is rated for up to 1,000 foot dive depths.

Among other factors, demand for our Offshore Service segment’s operations in the Gulf of Mexico is affected by federal regulations governing the abandonment and decommissioning of offshore wells and production platforms and pipelines, particularly following the April 2010 Macondo well oil spill. Recent regulations issued by the Bureau of Ocean Energy, Management, Regulation, and Enforcement (BOEMRE) have included Notice To Lessees  2010-G05: “Decommissioning Guidance for Wells and Platforms” (NTL 2010-G05, known as the “Idle Iron Guidance”), which requires that permanent plugs be set in nearly 3,500 nonproducing wells in the U.S. Gulf of Mexico and that approximately 650 oil and gas production platforms in the U.S. Gulf of Mexico be dismantled if they are no longer being used. The “Idle Iron Guidance” became effective October 15, 2010, and requires that operators perform and report decommissioning and abandonment plans and activities in accordance with BOEMRE requirements. The NTL 2010-G05 regulations provide specific guidelines for the maximum time that an operator has to permanently plug and abandon wells and decommission platforms and related facilities upon the occurrence of certain events, including the end of useful operations, cessation of commercial production, and expiration of the lease.

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

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

Maritech’s decommissioning liabilities are established based on what it estimates a third party would charge to plug and abandon the wells, decommission the pipelines and platforms, and clear the sites. Maritech’s decommissioning liabilities, as of December 31, 2010, total $265.5 million ($285.8 million undiscounted). We review the adequacy of Maritech’s decommissioning liabilities whenever indicators suggest that the estimated cash flows underlying the liabilities have changed materially. The timing and amounts of these cash flows are subject to changes in the energy industry environment and may result in additional liabilities to be recorded. As of December 31, 2010, Maritech determined that significant adjustments were necessary to increase its decommissioning liabilities to reflect current industry developments, including the impact from the NTL 2010-G05 “Idle Iron Guidance” issued in late 2010 by BOEMRE. For a further discussion of Maritech’s adjustments to its decommissioning liabilities, see “Note I – Decommissioning and Other Asset Retirement Obligations” in the Notes to Consolidated Financial Statements.
 
 
4

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

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

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

Production Enhancement Division

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

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

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

The Division’s Compressco segment provides wellhead compression-based production enhancement services to a broad base of natural gas and oil exploration and production companies. These production enhancement services primarily consist of wellhead compression, related liquids separation, gas metering, and vapor recovery services. In certain circumstances, Compressco also provides ongoing well monitoring services and, in Mexico, automated sand separation services in connection with its primary production enhancement services. Although Compressco’s services are applied primarily to mature wells with low formation pressures, they are also employed on newer wells that have experienced significant production declines or that are characterized by lower formation pressures. Compressco’s field services are performed by its highly trained staffs of regional service supervisors, optimization specialists, and field mechanics. In addition, Compressco designs and manufactures the compressor equipment it uses to provide production enhancement services, and in certain markets, sells its compressor units to customers. Compressco’s fleet of compressor units totaled 3,647 as of December 31, 2010, of which 2,711 units were in service, representing an increase in the number of units in service of approximately 2% from the prior year.

Compressco primarily utilizes its natural gas powered GasJack® compressor unit to provide its production enhancement services. The GasJack® units increase gas production by reducing surface pressure
 
 
5

 
 
to allow wellbore liquids that would normally block gas flow (known as liquid loading) to produce up the wellbore. The liquids are separated from the gas stream and are either discharged to a customer-provided tank or reinjected into the sales line for separation downstream of the compressor. The gas is compressed, cooled and discharged into the sales line. The 46-horsepower GasJack® unit is an integrated power/compressor unit equipped with an industrial 460-cubic inch, V-8 engine that uses natural gas from the well to power one bank of cylinders that, in turn, powers the other bank of cylinders, which provide compression. Compressco recently introduced its 40-horsepower electric VJackTM compressor unit to provide its production enhancement services on wells located in larger, mature oil fields and in environmentally sensitive areas where electric power is available at the production site. The VJackTM unit increases production with zero engine-driven emissions and requires significantly less maintenance than a natural gas powered compressor. The VJackTM unit is primarily designed for vapor recovery applications (to capture natural gas vapors emitting from closed storage tanks after production and to reduce storage tank pressures) and backside pumping applications on oil wells. Compressco utilizes its GasJack® and VJackTM units in conjunction with its personnel to provide compression services to its customers, primarily on a month-to-month basis. Compressco services its compressors and provides maintenance service on sold units through a staff of mobile field technicians who are based throughout Compressco’s market areas.

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

Sources of Raw Materials

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

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

We obtain raw materials utilized by our Lake Charles, Louisiana, facility to produce liquid and dry (pellet) calcium chloride from a variety of sources. Due to our inability to obtain raw materials on an economic basis for this facility, during the fourth quarter of 2010 we determined that the future operating cash flows for the Lake Charles, Louisiana, facility were no longer adequate to support its carrying value, and recorded an impairment of the net asset carrying value for this plant. In February 2011, we shut down the pellet plant operation at the Lake Charles, Louisiana, plant, although the liquid calcium chloride operation remains operational.

To produce calcium bromide, zinc bromide, zinc calcium bromide, and sodium bromide at our West Memphis, Arkansas, facility, we use bromine, hydrobromic acid, zinc, and lime. There are multiple sources of zinc that we can use in the production of zinc bromide and zinc calcium bromide. In December 2006, we entered into a long-term supply agreement with Chemtura, under which the Division purchases its requirements of raw material bromine from Chemtura’s Arkansas bromine facilities. In addition, Chemtura supplies the Division’s new El Dorado calcium chloride plant with tail brine from its Arkansas facilities following the extraction of bromine from such brine.
 
 
6

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

Our Production Enhancement Division, through its Production Testing segment, outsources the construction of its production testing equipment to third-party manufacturers. The Compressco segment designs and assembles the compressor units it uses to provide wellhead compression-based production enhancement services. Some of the components used in the assembly of compressor units and production testing equipment are obtained from a single supplier or a limited group of suppliers. We do not have long-term contracts with these suppliers, and a partial or complete loss of certain of them could have a negative impact on our business. Should we experience unexpected unavailability of the components we use to assemble our equipment, we believe that there are adequate, alternative suppliers and that this impact would not be severe.

Market Overview and Competition

Fluids Division

Our Fluids Division provides CBFs, drilling and completion fluid systems, additives, filtration services, wellbore cleanup services, frac water handling and treatment services, and other related products and services to oil and gas exploration and production companies, onshore and offshore, in the United States and certain international markets. Current areas of market presence include the onshore U.S., the U.S. Gulf of Mexico, the North Sea, Mexico, and certain countries in South America, Europe, Asia, and Africa. The Division also markets to customers with deepwater operations that utilize high volumes of CBFs and are subject to harsh downhole conditions such as high pressure and high temperatures. However, deepwater drilling activity in the U.S. Gulf of Mexico was significantly affected by the April 2010 well blowout of the Macondo well, which resulted in a drilling moratorium in the deepwater Gulf of Mexico as well as a series of regulatory reforms associated with offshore oil and gas operations. While the deepwater drilling moratorium was lifted in October 2010, there remains significant regulatory uncertainty. In addition, government issuances of permits for offshore activities have slowed considerably, resulting in delays in the timing for offshore projects, including projects for many of our customers.

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

The Division’s principal competitors in the sale of CBFs to the oil and gas industry are Baroid Corporation, a subsidiary of Halliburton Company; M-I Swaco, a subsidiary of Schlumberger Limited; and Baker Hughes, through its recently acquired BJ Services Company subsidiary. This market is highly competitive, and competition is based primarily on service, availability, and price. Major customers of the Fluids Division include Anadarko, Devon, Dominion Resources, EOG Resources, Halliburton Company, LLOG Exploration, Newfield Exploration Company, Nippon Oil Exploration, Petrobras, Tullow Oil, and Shell Oil. The Division also sells its CBF products through various distributors worldwide.

Our liquid and dry calcium chloride products have a wide range of uses outside the energy industry. The non-energy market segments where these products are used include agricultural, industrial, roadway dust control and de-icing, mining, janitorial, construction, pharmaceutical, and food processing. We also sell sodium bromide into the industrial water treatment markets as a biocide under the BioRid® tradename. Most of these markets are highly competitive. The Division’s European calcium chloride manufacturing operations market our calcium chloride products to certain European markets. Our principal competitors in the non-
 
 
7

 
 
energy related calcium chloride markets include Occidental Chemical Corporation and Industrial del Alkali in North America, and Brunner Mond, Solvay, and NedMag in Europe.

Offshore Division

Our Offshore Division consists of our Offshore Services and Maritech segments. Long-term demand for the Offshore Services segment’s offshore well abandonment and decommissioning services is predominantly driven by the maturity and decline of producing fields in the Gulf of Mexico, aging offshore platform infrastructure, damage from storms, and government regulations. Demand for the Offshore Services segment’s construction and other services is driven by the general level of activity of its customers, which are also affected by oil and natural gas prices and the general economic condition of the industry.

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

Demand for offshore abandonment and decommissioning services during the past several years increased substantially as a result of 2005 and 2008 hurricane activity in the Gulf of Mexico, which destroyed or caused significant damage to a large number of offshore platforms and associated wells. While the vast majority of remediation work to be performed as a result of these storms has been performed, the Offshore Services segment continues to develop or acquire specialized equipment and engineering expertise that may be used to provide such services to customers whose offshore wells and production platforms were toppled, destroyed, or heavily damaged by storms or may be damaged by future storms. The threat of future storm activity, combined with the volatility of the cost of hurricane insurance premiums and associated deductibles, continues to accelerate the abandonment and decommissioning plans for undamaged wells and structures of many offshore operators.

Offshore activities in the Gulf of Mexico are highly seasonal, with the majority of work occurring during the months of April through October, when weather conditions are most favorable. Critical factors required to compete in the current market include, among other factors: an adequate fleet of the proper equipment; qualified, experienced personnel; technical expertise to address varying downhole, surface, and subsea conditions, particularly those related to damaged wells and platforms; the financial strength to ensure all abandonment and decommissioning obligations are satisfied; and a comprehensive safety and environmental program. During 2010, we acquired additional operating assets to supplement our existing equipment fleet, enabling us to expand our services, particularly those related to damaged wells and platforms. We believe our integrated service package and vessel fleet satisfy these market requirements, allowing us to successfully compete.

The Offshore Services segment markets its services primarily to major oil and gas companies and independent operators. The Offshore Services segment’s most significant customer during the past two years has been Maritech. Other major customers include Apache, Chevron, Mariner Energy, Nexen Petroleum USA Inc., Stone Energy, Versabuild, and W&T Offshore. These services are performed primarily offshore in the U.S. Gulf of Mexico and in Gulf Coast inland waters and onshore in Texas and Louisiana, however, the segment is also seeking to expand its operations to international markets. Our principal competitors in the domestic offshore and inland water services markets are Global Industries, Ltd., Offshore Specialty Fabricators, Inc., Helix Energy Solutions, Cal Dive International, Inc., and Superior Energy Services, Inc. This market is highly competitive, and competition is based primarily on service, equipment availability, safety record, and price. Our ability to acquire or lease suitable service vessels and other operating equipment is particularly important to our ability to serve our existing customers or to expand our operations to other markets. Our ability to successfully bid our services fluctuates from year to year, depending on market conditions.

 
8

 

 Production Enhancement Division

The Production Enhancement Division provides production testing and wellhead compression-based services and products to its customers. The Production Testing segment provides services primarily to the natural gas segment of the oil and gas industry. In certain gas producing basins, water, sand, and other abrasive materials commonly accompany the initial production of natural gas, often under high pressure and high temperature conditions and in some cases in reservoirs containing high levels of hydrogen sulfide gas. The Division provides the specialized equipment and qualified personnel to address these impediments to production. In addition, the Production Testing segment provides certain services designed to accommodate the unique demands of shale gas reservoirs. The Production Testing segment also provides early-life and late-life production enhancement solutions designed to boost and extend the productive life of oil and gas wells.

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

The Division’s Compressco segment provides wellhead compression-based production enhancement services to over 400 natural gas and oil exploration and production companies operating throughout most of the onshore producing regions of the United States. Internationally, Compressco has significant operations in Canada and Mexico and a growing presence in certain countries in South America, Eastern Europe, and the Asia-Pacific region. While most of Compressco’s domestic services are performed in the Ark-La-Tex region, San Juan Basin, and Mid-Continent region of the United States, it also has a substantial presence in other U.S. producing regions, including the Permian Basin, North Texas, Gulf Coast, Central and Northern Rockies, and California. Compressco has historically focused on serving customers with conventional production in mature fields, but it also services customers in some of the largest and fastest growing unconventional gas resource markets in the United States, including the Cotton Valley Trend, Barnett Shale, Fayetteville Shale, Woodford Shale, Piceance Basin, and Marcellus Shale. Compressco continues to seek opportunities to further expand its operations into other regions in the Western Hemisphere and elsewhere in the world.

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

Other Business Matters

Marketing and Distribution

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

 

 

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

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

Backlog

The level of backlog is not indicative of our estimated future revenues, because a majority of our products and services either are not sold under long-term contracts or do not require long lead times to procure or deliver. Our backlog consists of estimated future revenues associated with a portion of our well abandonment and decommissioning business and consists of the non-Maritech share of the well abandonment and decommissioning work associated with the oil and gas properties operated by Maritech. Prior to the impact of any future sales of Maritech oil and gas properties, our estimated backlog on December 31, 2010 was $64.1 million, of which approximately $7.6 million is expected to be billed during 2011. This compares to an estimated backlog of $121.9 million at December 31, 2009.

Employees

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

Patents, Proprietary Technology, and Trademarks

As of December 31, 2010, we owned or licensed twenty-one issued U.S. patents and had ten patent applications pending in the United States. Internationally, we had fifteen owned or licensed foreign patents and five foreign patent applications pending. The foreign patents and patent applications are primarily foreign counterparts to U.S. patents or patent applications. The issued patents expire at various times through 2028. We have elected to maintain certain other internally developed technologies, know-how, and inventions as trade secrets. While we believe that the protection of our patents and trade secrets is important to our competitive positions in our businesses, we do not believe any one patent or trade secret is essential to our success.

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

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

Health, Safety, and Environmental Affairs Regulations

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

 
10

 

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

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

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

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

Offshore Operations

During 2010, the U.S. federal government established the BOEMRE to replace the U.S. Minerals Management Service (MMS). This federal agency reorganization was largely in response to the April 2010 blowout of the Macondo well and resulting oil spill in the Gulf of Mexico. The U.S. federal government imposed a drilling moratorium in the deepwater Gulf of Mexico that extended until October 2010. BOEMRE has also issued formal Notice to Lessees (NTLs) and other safety regulations implementing additional safety and certification requirements applicable to drilling activities in the Gulf of Mexico that have resulted in operations and projects being delayed or suspended. Such notices and regulations issued to date include requirements by operators to:
 
·  
Submit well blowout prevention measures and contingency plans, including demonstrating access to subsea blowout containment resources;
 
·  
Abide by new permitting standards requiring detailed, independently certified descriptions of well design, casing, and cementing;
 
·  
Follow new performance-based standards for offshore drilling and production operations;
 
·  
Certify that the operator has complied with all regulations; and,
 
·  
Abide by the new “Idle Iron Guidance” regulations.

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

 
11 

 

We maintain various types of business insurance intended to mitigate our liability in the event of an explosion or similar event involving Maritech’s offshore operations. Our insurance program is reviewed not less than annually with our insurance brokers and underwriters. As part of our insurance program for offshore operations, we maintain general liability and protection and indemnity policies that provide third-party liability coverage, up to applicable policy limits, for risks of accidental nature, including but not limited to death and personal injury, full collision liability, damage to fixed and floating objects, pollution liability, and wreck removal. We also maintain a vessel pollution liability policy that provides pollution coverage for oil or hazardous substances emanating from a vessel, addressing both OPA (Oil Pollution Act of 1990) and CERCLA obligations. This coverage also provides coverage for cost of defense, fines, and penalties. The Maritech energy package provides operational all risks coverage (excluding named windstorm coverage) for physical loss or damage to scheduled offshore property, including removal of wreck and/or debris, and for operator’s extra expense such as control of well, redrill/extra expense, and pollution and cleanup.

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

(1)      We would be required to indemnify our customer for any claims for injury, death, or property loss or destruction made against them by us or our subcontractors or our employees. The customer would be required to indemnify us for any claims for injury, death, or property loss or destruction made against us by the customer or its other subcontractors or the employees of the customer or its other subcontractors. These indemnities are intended to apply regardless of the cause of such claims, including but not limited to, the negligence of the indemnified party. Our insurance is structured to cover the cost of defense and any resulting liability from all indemnified claims, up to policy limits.

(2)      The customer would be required to indemnify us for all claims for injury, death, or property loss or destruction made against us by a third party that arise out of the catastrophic event, regardless of the cause of such claims, including but not limited to, our negligence or our subcontractors’ negligence. Our insurance is structured to cover the cost of defense and any resulting liability from all such claims; however, our insurance would be applicable to the claim only if the customer defaulted or otherwise breached its indemnity obligations to us.

(3)      The customer would be required to indemnify us for all claims made against us for environmental pollution or contamination that arise out of the catastrophic event, regardless of the cause of such claims, including our negligence or the negligence of our subcontractors. Our insurance is structured to cover the cost of defense and any resulting liability from all such claims; however, our insurance would be applicable to the claim only if the customer defaulted or otherwise breached its indemnity obligations to us.

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

 
12

 

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

Item 1A. Risk Factors.

Forward Looking Statements

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

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

Although we believe that the expectations reflected in such forward-looking statements are reasonable and such forward-looking statements are based upon the best data available at the date this report is filed with the SEC, we cannot assure you that such expectations will prove correct. Factors that could cause our results to differ materially from the results discussed in such forward-looking statements include, but are not limited to, the following:
 
·  
general economic, business, and political conditions in the markets we serve or hope to serve in the United States and abroad;
 
·  
the demand for our products and services in the Gulf of Mexico could continue to be adversely impacted by the 2010 oil spill, resulting regulatory reforms, and ongoing regulatory uncertainty;
 
·  
the supply, demand, and prices for oil, gas, and competing energy sources, and more particularly the supply, demand, and prices for well completion, diving, and abandonment and decommissioning services;
 
·  
activities of our customers and competitors;
 
·  
the availability of raw materials and labor at reasonable prices;
 
·  
operating and safety risks inherent in oil and gas production;
 
·  
access to pipelines, gas gathering and processing facilities for our oil and gas production;
 
·  
possible impairments of long-lived assets, including goodwill;
 
·  
the potential impact of the loss of one or more key employees;
 
·  
cost, availability, and adequacy of insurance and the ability to recover thereunder;
 
·  
technological obsolescence;
 
·  
weather risks, including the risk of physical damage to our platforms, facilities, and equipment and the ability to resume operations following damage;
 
·  
our ability to implement our business strategy;
 
·  
uncertainties about finding, developing, producing, and estimating oil and gas reserves and plugging and abandoning wells and structures;
 
·  
the accounting for our oil and gas operations may result in volatility of earnings;
 
·  
the availability of capital (including any financing) to fund our business strategy and/or operations and any restrictions resulting from such financing;
 
·  
foreign currency risks;
 
·  
the impact of existing and future laws and regulations;
 
 
13

 
 
·  
environmental risks;
 
·  
estimates of hurricane repair costs;
 
·  
acquisition valuation and integration risks; and
 
·  
risks related to our foreign operations.
 
All such forward-looking statements in this document are expressly qualified in their entirety by the cautionary statements in this paragraph, and we undertake no obligation to publicly update or revise any forward-looking statements.

Certain Business Risks

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

Market Risks

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

The demand for our products and services is materially dependent on the supply, demand, and prices for oil, natural gas, and competing energy sources, and more specifically dependent on the supply, demand, and prices for the products and services we offer, both in the United States and in the foreign countries in which we operate. These factors are also influenced by the regional economic, financial, business, political, and social conditions within the markets we serve or hope to serve, as well as the national and international economic, financial, business, political and social conditions that impact the supply, demand, and prices of oil and gas. Activity levels have decreased as a result of the recent decline in energy consumption caused by the recent global recession. Decreased energy consumption has resulted in a decrease in energy prices, particularly natural gas prices, during much of 2010 compared to prices received during early to mid-2008. This decline in energy prices has negatively affected the operating cash flows and capital plans of many of our customers, which has negatively impacted the demand for many of our products and services.

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

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

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

On April 20, 2010, a blowout on the Macondo well resulted in the rig catching fire and sinking. The resulting government-imposed drilling moratorium in the deepwater Gulf of Mexico and related regulatory requirements have significantly reduced the U.S. Gulf of Mexico completion fluids market and slowed the permitting of new drilling activity and plug and abandonment work in the U.S. Gulf of Mexico. The BOEMRE has issued several new regulations that are focused on offshore operating requirements, spill cleanup and enforcement matters. The BOEMRE recently issued to U.S. Gulf of Mexico operators notices implementing additional safety and certification requirements applicable to drilling activities in the Gulf of Mexico that have resulted in operations and projects being curtailed or suspended. Although the moratorium was lifted in October 2010, the backlog of permits waiting to be issued for operations in the shallow water, for both new drilling and plug and abandonment work, and regulatory uncertainty regarding the deepwater activities did,
 
 
14

 
 
and are expected to continue to, negatively affect our Fluids Division and, to a lesser extent, our Offshore Services segment. Although we are unable to predict the full continuing impact of these factors on future operating results going forward, we expect our offshore activity levels and the offshore activity levels of our Fluids Division customers to be less than they were prior to April 2010.

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

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

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

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

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

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

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

Other factors affecting our operating results and activity levels include finding, development, and acquisition costs of oil and natural gas reserves; oil and gas industry spending levels for exploration, development, and acquisition activities; production costs; plugging and abandonment costs; insurance costs; the success rates of new oil and gas reserve development; and the remaining recoverable reserves in the basins in which we operate. A large concentration of our operating activities is located in the onshore and offshore U.S. Gulf Coast region. Our revenues and profitability are particularly dependent upon oil and gas industry activity and spending levels in this region. Our operations may also be affected by technological advances, cost of capital, tax policies, and overall worldwide economic activity. Adverse changes in any of these other factors may depress the levels of well drilling, completion, workover, and production activity and result in a corresponding decline in the demand for our products and services, thereby having a material adverse effect on our revenues and profitability.
 
 
15

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

We compete with numerous companies in our operations. Many of our competitors have substantially greater financial and other related resources than we have. To the extent competitors offer comparable products or services at lower prices, or higher quality, more cost-effective products or services, our business could be materially and adversely affected.

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

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

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

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

The fabrication of our production testing equipment and wellhead compressor units requires the purchase of many types of components, some of which we obtain from a single source or a limited group of suppliers. Our reliance on these suppliers exposes us to the risk of price increases, inferior component quality, or an inability to obtain an adequate supply of required components in a timely manner. The profitability or future growth of our Production Enhancement Division may be adversely affected due to our dependence on these key suppliers.

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

 
16

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

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

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

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

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

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

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

Operating, Technological, and Strategic Risks

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

We are subject to operating hazards normally associated with the oilfield service industry and offshore oil and gas production operations, including fires, explosions, blowouts, formation collapse, mechanical problems, abnormally pressured formations, and environmental accidents. Environmental accidents could include, but are not limited to: oil spills; gas leaks or ruptures; uncontrollable flows of oil, gas, or well fluids; or discharges of CBFs or toxic gases or other pollutants. These operating hazards also include injuries to employees and third parties during the performance of our operations. Our operation of marine vessels, heavy equipment, offshore production platforms, and the performance of heavy lift and diving
 
 
17

 
 
services involve particularly high levels of risk. In addition, certain of our employees who perform services on offshore platforms and vessels are covered by the provisions of the Jones Act, the Death on the High Seas Act, and general maritime law. These laws make the liability limits established by state workers’ compensation laws inapplicable to these employees and, instead, permit them or their representatives to pursue actions against us for damages for job-related injuries. Whenever possible, we obtain agreements from customers and suppliers that limit our exposure. However, the occurrence of certain operating hazards, including storms, could result in substantial losses to us due to injury or loss of life, damage to or destruction of property and equipment, pollution or environmental damage, and suspension of operations.

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

We face risks related to our growth strategy.

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

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

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

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

During late 2009 and early 2010, we completed the construction and began the commissioning of a calcium chloride plant facility near El Dorado, Arkansas. During 2010, the El Dorado plant experienced significant start-up costs and early production inefficiencies that resulted in decreased profitability levels compared to our estimates. We continue to take steps to improve the operational efficiency of the plant, however, there is still a considerable effort required, and significant improvement in plant performance is not expected until mid-2011. We believe that significant additional capital investment may be necessary,
 
 
18

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

We could incur losses on fixed price contracts.

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

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

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

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

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

 
19

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

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

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

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

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

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

In conjunction with our acquisition of oil and gas properties, we perform detailed due diligence review processes that we believe are consistent with industry practices. These acquired properties consist of both mature properties, which are generally in the later stages of their economic lives, as well as exploration and prospect opportunities. Each acquisition of oil and gas properties requires a thorough review of the expected cash flows acquired and the associated abandonment obligations assumed. The process of estimating oil and natural gas reserves is complex, requiring significant decisions and assumptions to be made in evaluating the available geological, geophysical, engineering, and economic data for each reservoir. The volatility of oil and natural gas commodity pricing additionally complicates the calculation of estimated future cash flows of properties to be acquired. As a result, these estimates are inherently imprecise. Actual future production, cash flows, development expenditures, operating and abandonment expenses, and quantities of recoverable natural gas and oil reserves may vary substantially from those initially estimated by us. Also, in conjunction with the purchase of certain oil and gas properties, we assume our proportionate share of the related well abandonment and decommissioning liabilities after performing detailed estimating procedures, analysis, and engineering studies. Our estimates of these future well abandonment and decommissioning liabilities are imprecise and are subject to change due to changes in the forecasts of the supply, demand, pricing and timing of well abandonment and decommissioning services; damage to wells and infrastructure caused by hurricanes and other natural events; changes in governmental regulations governing well abandonment and
 
 
20

 
 
decommissioning work; and other factors. During 2010, Maritech adjusted its decommissioning liabilities, increasing them by approximately $130.8 million, either for work performed during the year or related to adjusted estimates of the cost of future work to be performed. Approximately $54.0 million of this adjustment was directly charged to earnings as an operating expense and the remainder was charged to the associated properties and partly contributed to asset impairments during 2010. If the actual cost of future abandonment and decommissioning work is materially greater than our current estimates, such additional costs could have an additional adverse effect on earnings.

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

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

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

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

Weather Related Risks

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

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

 
21 

 

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

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

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

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

Following the collection of $47.8 million insurance settlement proceeds during 2010 associated with Hurricane Ike, Maritech has additional maximum remaining insurance coverage available of approximately $19.5 million, all of which relates to Hurricane Ike. With regard to the damages associated with Hurricane Ike, we have performed a significant majority of the property repairs on the damaged and destroyed platforms. These efforts included the reconstruction of the destroyed East Cameron 328 platform and the initial redrilling efforts of wells associated with this destroyed platform. Despite our confidence that the majority of the remaining repair, debris removal, and well redrilling costs relating to Hurricane Ike will qualify as covered costs pursuant to our insurance coverage, a portion of these costs may not be reimbursed. One of the underwriters associated with our windstorm insurance coverage for Hurricane Ike damages has contested whether certain repair costs incurred are covered costs under the policy. During December 2010, we initiated legal proceedings against this underwriter in an attempt to collect the amount of claim reimbursements provided for under the policy. The timing of the collection of any future reimbursements is beyond our control, and we will continue to use a significant amount of our working capital until such reimbursements are received. In addition, a portion of the reimbursements ultimately received may be offset by legal and other administrative costs incurred in our attempts to collect them. Our estimates of the remaining costs to be incurred may be imprecise. To the extent actual future costs exceed the policy maximum for these costs, such excess costs would not be reimbursable.

For a further discussion of the remaining costs to repair damage as a result of 2005 and 2008 hurricanes, see Notes to Consolidated Financial Statements, “Note B – Summary of Significant Accounting Policies, Repair Costs and Insurance Recoveries.
 
 
22

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

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

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

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

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

Financial Risks

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

As of December 31, 2010, our total debt outstanding was approximately $305.0 million and our debt to total capital ratio was 37.1%. This debt to total capital ratio excludes approximately $65.4 million of available cash held as of December 31, 2010. Additional growth could result in increased debt levels to support our capital expenditure needs or acquisition activities. Debt service costs related to outstanding long-term debt represent a significant use of our operating cash flow and could increase our vulnerability to general adverse economic and industry conditions. Our long-term debt agreements contain customary covenants and other restrictions and requirements. In addition, the agreements require us to maintain certain financial ratio requirements. Significant deterioration of these ratios could result in a default under the agreements. The agreements also include cross-default provisions relating to any other indebtedness we have that is greater than a defined amount. If any such indebtedness is not paid or is accelerated and such event is not remedied in a timely manner, a default will occur under the long-term debt agreements. Any event of default, if not
 
 
23

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

We are exposed to significant credit risks.

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

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

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

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

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

Our revolving credit facility consists of floating rate loans that bear interest at an agreed upon percentage rate spread above LIBOR. Although as of December 31, 2010, there is no balance outstanding under the revolving credit facility, there is no assurance that we will not borrow under the facility in the future. Accordingly, our cash flows and results of operations could be subject to interest rate risk exposure associated with the level of the variable rate debt balance outstanding. We currently are not a party to an interest rate swap contract or other derivative instrument designed to hedge our exposure to interest rate fluctuation risk.

The terms governing our revolving credit facility were agreed to in October 2010, and it is scheduled to mature in 2015. The terms governing our Senior Notes were agreed to in April 2006, April 2008, and October 2010. These Senior Notes all bear interest at fixed interest rates and are scheduled to mature at various dates between April 2013 and December 2020. There can be no assurance that the financial market conditions or borrowing terms at the times these existing debt agreements are renegotiated will be as favorable.


 
24 

 

Legal, Regulatory, and Political Risks

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

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

A large portion of Maritech’s oil and gas operations are conducted on offshore federal leases and are governed by increasing U.S. government regulations. During 2010, following the April 2010 Macondo well blowout and resulting oil spill in the Gulf of Mexico, the U.S. Minerals Management Service (MMS) was reorganized as the BOEMRE. The U.S. federal government imposed a drilling moratorium in the deepwater Gulf of Mexico that extended until October 2010. The BOEMRE has also issued formal Notice to Lessees (NTLs) and other safety regulations implementing additional safety and certification requirements applicable to drilling activities in the Gulf of Mexico that have resulted in operations and projects being curtailed or suspended. Government regulations also establish construction requirements for production facilities located on federal offshore leases and govern the plugging and abandonment of wells and the removal of production facilities from these leases. Operators must now abide by new “Idle Iron Guidance” regulations that require that permanent plugs be set in nearly 3,500 nonproducing wells and that 650 oil and gas production platforms be dismantled if they are no longer being used. Under limited circumstances, the BOEMRE could require us to suspend or terminate our operations on a federal lease. The BOEMRE also establishes the basis for royalty payments due under federal oil and natural gas leases through regulations issued under applicable statutory authority.

We have significant operations that are either ongoing or scheduled to commence in the U.S. Gulf of Mexico. At this time, we cannot predict the full impact that other regulatory actions that may be mandated by the BOEMRE may have on our operations or the operations of our customers. Other governmental or regulatory actions could further reduce our revenues and increase our operating costs, including the cost to insure offshore operations, resulting in reduced cash flows and profitability.

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

Federal legislation to reduce emissions of greenhouse gases (GHG) has been considered and many states have taken legal measures to reduce GHG emissions. It is not possible at this time to predict whether or when the U.S. Congress will pass climate change legislation, or how any bill approved by Congress may be reconciled with state and regional requirements. EPA has begun to promulgate federal rules under the Clean Air Act including mandatory reporting rules. On September 22, 2009, EPA issued a final rule requiring mandatory reporting of GHG from specified large GHG emission sources in the U.S. beginning in 2011 for emissions occurring in 2010. On November 30, 2010, EPA published a final rule expanding its existing GHG
 
 
25

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

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

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

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

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

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

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

We and our affiliates operate in countries where governmental corruption has been known to exist. While we and our subsidiaries are committed to conducting business in a legal and ethical manner, there is a risk of violating either the U.S. Foreign Corrupt Practices Act (FCPA) or laws or legislation promulgated pursuant to the 1997 OECD Convention on Combating Bribery of Foreign Public Officials in International Business Transactions or other applicable anti-corruption regulations that generally prohibit the making of improper payments to foreign officials for the purpose of obtaining or keeping business. Violation of these laws could result in monetary penalties against us or our subsidiaries and could damage our reputation and, therefore, our ability to do business.
 
 
26

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

Item 1B. Unresolved Staff Comments.

None.

Item 2. Properties.

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

Facilities

Fluids Division

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

As an inducement to locate our calcium chloride production plant in Union County, Arkansas, we received certain ad valorem property tax incentives. Our facility, which is located just outside the city of El Dorado, in Union County, Arkansas, is leased from Union County, Arkansas. We have the option of purchasing the property at any time during the term of the lease for a nominal price. The term of the lease expires in 2035, at which time we also have the option to purchase the facility at a nominal price. Under the terms of the lease, we are responsible for all costs incurred related to the facility.

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

Offshore Division

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

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

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

See below for a discussion of the Offshore Division’s oil and gas property assets.
 
 
27

 
 
Production Enhancement Division

The Production Enhancement Division conducts its operations through thirteen production testing service centers (twelve of which are leased) in the U.S. located in Texas, Louisiana, and Pennsylvania. In addition, the Production Testing segment has leased facilities in Brazil, Mexico, Libya, Egypt, Bahrain, India, United Arab Emirates, and Saudi Arabia. Compressco’s facilities include an owned fabrication facility and a leased headquarters facility in Oklahoma, a leased fabrication facility in Alberta, Canada, a leased service and sales facility in New Mexico, three leased service facilities in California, Mexico, and Argentina, and six sales offices in Oklahoma, Texas, Colorado, New Mexico, Louisiana, and Canada.

Corporate

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

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

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

Oil and Gas Reserves

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

A reserve audit is the process of reviewing certain of the pertinent facts interpreted and assumptions made that have resulted in an estimate of reserves prepared by others and the rendering of an opinion about the appropriateness of the methodologies employed, the adequacy and quality of the data relied upon, the depth and thoroughness of the reserves estimation process, the classification of reserves appropriate to the relevant definitions used, and the reasonableness of the estimated reserve quantities. In performing a reserve audit, an independent petroleum engineering firm meets with our technical staff to collect all necessary geologic, geophysical, engineering, and economic data, and performs an independent reserve evaluation. The reserve audit of our oil and gas reserves involves the rigorous examination of our technical evaluation, as well as the interpretation and extrapolation of well information such as flow rates, reservoir pressure declines, and other technical information and measurements. Maritech’s internal reservoir engineers interpret this data to determine the nature of the reservoir and, ultimately, the quantity of proved oil and gas reserves attributable to the specific property. Our proved reserves, as reflected in this Annual Report, include only quantities that Maritech expects to recover commercially using current technology, prices, and costs, within
 
 
28

 
 
existing economic conditions, operating methods, and governmental regulation. While Maritech can be reasonably certain that the proved reserves are economically producible, the timing and ultimate recovery can be affected by a number of factors, including completion of development projects, reservoir performance, regulatory approvals, and changes in projections of long-term oil and gas prices. Revisions can include upward or downward changes in the previously estimated volumes of proved reserves for existing fields due to evaluation of (1) already available geologic, reservoir, or production data or (2) new geologic or reservoir data obtained from wells. Revisions can also occur associated with significant changes in development strategy, oil and gas prices, or the related production equipment/facility capacity. Maritech’s independent petroleum engineers also examined the reserve estimates with respect to reserve categorization, using the definitions for proved reserves set forth in Regulation S-X Rule 4-10(a), Staff Accounting Bulletin No. 113, and subsequent SEC staff interpretations and guidance.

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

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

Reserve information is prepared in accordance with guidelines established by the SEC. All of Maritech’s reserves are located in U.S. state and federal offshore waters in the Gulf of Mexico region and onshore Texas and Louisiana. The following table sets forth information with respect to our estimated proved reserves as of December 31, 2010:
 
 
29

 
 
Summary of Oil and Gas Reserves as of December 31, 2010
 
Based on Average Fiscal Year Prices
 
                         
Reserves category
 
Oil
   
NGL
   
Natural Gas
   
Total
 
   
(MBbls)
   
(MBbls)
   
(MMcf)
   
(MBOE)
 
Proved reserves
                       
   Developed
    5,760       415       24,795       10,307  
   Undeveloped
    1,012       74       790       1,218  
Total proved reserves
    6,772       489       25,585       11,525  
 
Maritech’s proved undeveloped reserves as of December 31, 2010, represent approximately 10.6% of Maritech’s total proved reserves. Proved undeveloped reserves represented approximately 12.4% of Maritech total proved reserves as of December 31, 2009. During 2010, Maritech expended approximately $4.6 million of its development costs to convert approximately 55.9% of its proved undeveloped reserves at the beginning of the year to proved developed reserves. All of Maritech’s proved undeveloped reserves as of December 31, 2010, have been classified as proved undeveloped for less than five years. Maritech has historically developed its proved undeveloped reserves over a reasonable period of time and anticipates it will do so in the future, utilizing our future operating cash flows, available working capital, and, if necessary, long-term borrowings. All of Maritech’s proved undeveloped reserves as of December 31, 2010, are scheduled to be developed prior to December 31, 2015.
 
For additional information regarding estimates of oil and gas reserves, including estimates of proved and proved developed reserves, the standardized measure of discounted future net cash flows, and the changes in discounted future net cash flows, see “Note R – Supplemental Oil and Gas Disclosures” in the Notes to Consolidated Financial Statements.

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

Production Information

The table below sets forth information related to production, average sales price, and average production cost per unit of oil and gas produced during 2010, 2009, and 2008:
 
   
Year Ended December 31,
 
   
2010
   
2009
   
2008
 
Production:
                 
   Natural gas (Mcf)
    7,065,258       10,449,366       10,988,840  
   NGL (Bbls)
    132,191       105,479       82,520  
   Oil (Bbls)
    1,360,126       1,219,336       1,384,101  
                         
Revenues:
                       
   Natural Gas
  $ 60,416,000     $ 87,905,000     $ 99,901,000  
   NGL (Bbls)
    6,003,000       3,308,000       5,917,000  
   Oil
    131,422,000       82,978,000       101,362,000  
                         
   Total
  $ 197,841,000     $ 174,191,000     $ 207,180,000  
                         
Average realized unit prices and production costs:
                 
   Natural gas (per Mcf)
  $ 8.55     $ 8.41     $ 9.09  
   NGL (per Bbl)
  $ 45.41     $ 31.37     $ 71.70  
   Oil (per Bbl)
  $ 96.62     $ 68.05     $ 73.23  
                         
   Production cost per equivalent barrel
  $ 26.62     $ 25.80     $ 27.18  
   Depletion cost per equivalent barrel
  $ 27.60     $ 25.96     $ 25.14  
 
 
30

 
 
Realized unit prices include the impact of hedge commodity swap contracts. Production cost per equivalent barrel excludes the impact of storm repair and insurance-related costs and recoveries, which were charged or credited to operations during each of the years presented, with approximately $8.2 million and $8.5 million being charged in 2009 and 2008, respectively. Equivalent barrel (BOE) information is calculated assuming six Mcf of gas is equivalent to one barrel of oil. Insurance recoveries during 2010 and 2009 totaled approximately $2.5 million and $45.4 million, respectively, and are excluded from production cost per equivalent barrel for the year. The 2008 production cost per equivalent barrel was also increased due to the impact of hurricanes, which resulted in significant properties being shut-in during the last four months of 2008 and during much of 2009. Depletion cost per equivalent barrel excludes the impact of dry hole costs and property impairments.
 
Acreage and Productive Wells

At December 31, 2010, our Maritech subsidiary owned interests in the following oil and gas wells and acreage:
 
 
Productive Gross
 
Productive Net
 
Developed
 
Undeveloped
 
 
Wells
 
Wells
 
Acreage
 
Acreage
 
State/Area
Oil
   
Gas
 
Oil
   
Gas
 
Gross
   
Net
 
Gross
   
Net
 
                                         
Louisiana Onshore
  12       1     1.1       0.1     900       450     5,133       2,133  
Louisiana Offshore
  46       10     46.0       10.0     15,819       15,474     6,729       6,317  
Texas Onshore
  7       -     1.4       -     1,331       450     -       -  
Texas Offshore
  -       -     -       -     1,440       190     -       -  
Federal Offshore
  37       54     17.4       18.5     231,281       110,451     59,988       46,611  
                                                         
Total
  102       65     65.9       28.6     250,771       127,015     71,850       55,061  
 
The majority of Maritech’s oil and gas properties are held by production. Leases covering undeveloped acreage other than acreage held by production have expiration terms ranging from 2011 through 2015. The following table sets forth the expiration amounts of our gross and net undeveloped acreage as of December 31, 2010:
 
                                         
Held by
 
 
2011
 
2012
 
2013
 
2014
 
2015
 
Production
 
State/Area
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
 
                                                 
Louisiana Onshore
  265     133     1,223     582     689     250     2,643     1,012     313     156     -     -  
Louisiana Offshore
  4,417     4,417     -     -     1,282     1,282     207     207     -     -     823     411  
Texas Offshore
  -     -     -     -     -     -     -     -     -     -     -     -  
Federal Offshore
  -     -     -     -     19,521     16,641     -     -     6,250     6,250     34,217     23,720  
                                                                         
Total
  4,682     4,550     1,223     582     21,492     18,173     2,850     1,219     6,563     6,406     35,040     24,131  

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

Drilling Activity

During 2010, Maritech participated in the drilling of 6 gross development wells (4.32 net wells) and two gross exploratory wells (1.5 net wells), 7 of which were productive. During 2009, Maritech participated in the drilling of 2 gross development wells (1.12 net wells) and one gross exploratory well (0.5 net wells), all of which were productive. Maritech participated in the drilling of 10 gross development wells (4.3 net wells) during 2008, two of which were unproductive. As of December 31, 2010, there were no wells in the process of being drilled.
 
 
31

 
 
Significant Oil and Gas Properties

The following table provides a brief description as of December 31, 2010, of Maritech’s most significant oil and gas properties which individually represent fields that contain 15% or more of Maritech’s total proved reserves on a barrels-of-oil-equivalent (BOE) basis:
 
 
Net Total
                                       
 
Proved
 
Net Proved
   
Productive
                 
 
Reserves
 
Reserves Mix
   
Gross
 
Developed
 
Undeveloped
 
Working
   
Production
 
(MBOE)
 
Oil%
   
NGL%
   
Gas%
   
Wells
 
Acreage
 
Acreage
 
Interest %
   
Status
                                           
Timbalier Bay Area
  5,504     62 %     4 %     34 %     52     8,351     5,906     100 %  
Producing
Main Pass Area
  568     31 %     7 %     62 %     12     66,171     9,989     12%-100 %  
Producing
East Cameron 328
  1,785     92 %     -       8 %     6     5,000     -     50 %  
Producing
 
Production information for each of these most significant properties during the three years ended December 31, 2010, is as follows:
 
 
Year Ended December 31,
 
 
2010
 
2009
 
2008
 
 
Oil
 
NGL
 
Natural Gas
 
Oil
 
NGL
 
Natural Gas
 
Oil
 
NGL
 
Natural Gas
 
 
(MBbls)
 
(MBbls)
 
(MMcf)
 
(MBbls)
 
(MBbls)
 
(MMcf)
 
(MBbls)
 
(MBbls)
 
(MMcf)
 
Timbalier Bay Area
  555     25     912     526     23     1,289     653     53     3,500  
Main Pass Area
  87     35     2,362     74     40     5,715     36     2     3,251  
East Cameron 328
  213     -     132     52     -     48     250     -     149  
 
Average realized unit prices and production costs for each of these fields were approximately equal to Maritech’s overall unit prices and costs, as all of Maritech’s production is located in the Gulf of Mexico region.

Item 3. Legal Proceedings.

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

Class Action Lawsuit

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

Derivative Lawsuit

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
 
 
32

 
 
stayed by agreement of the parties pending the Court’s ruling on our motion to dismiss the federal class action. On September 8, 2009, the plaintiffs in this state court action filed a consolidated petition which makes factual allegations similar to the surviving allegations in the federal lawsuit. On April 19, 2010, the Court granted our motion to abate the suit, based on plaintiff’s inability to demonstrate derivative standing. On June 8, 2010, we received a letter from plaintiff’s counsel demanding that our board of directors take action against the defendants named in the previously filed derivative lawsuit. Our board is currently evaluating the best course of action to take in response to the demand letter.

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

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

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

Item 4. [Removed and Reserved.]
 
 
33

 
 
PART II

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

Price Range of Common Stock

Our common stock is traded on the New York Stock Exchange under the symbol “TTI.” As of February 25, 2011, there were approximately 11,558 holders of record of the common stock. The following table sets forth the high and low sale prices of the common stock for each calendar quarter in the two years ended December 31, 2010, as reported by the New York Stock Exchange.
 
   
High
   
Low
 
2010
           
     First Quarter
  $ 13.49     $ 8.95  
     Second Quarter
    14.64       8.20  
     Third Quarter
    11.10       8.00  
     Fourth Quarter
    12.14       9.41  
                 
2009
               
     First Quarter
  $ 6.28     $ 1.94  
     Second Quarter
    10.44       3.01  
     Third Quarter
    10.74       6.79  
     Fourth Quarter
    11.62       8.70  
 
Market Price of Common Stock

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

We have never paid cash dividends on our common stock. We currently intend to retain earnings to finance the growth and development of our business. Any payment of cash dividends in the future will depend upon our financial condition, capital requirements, and earnings, as well as other factors the Board of Directors may deem relevant. We declared a dividend of one Preferred Stock Purchase Right per share of
 
 
34

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

Purchases of Equity Securities by the Issuer and Affiliated Purchasers
 
In January 2004, our Board of Directors authorized the repurchase of up to $20 million of our common stock. Purchases may be made from time to time in open market transactions at prevailing market prices. The repurchase program may continue until the authorized limit is reached, at which time the Board of Directors may review the option of increasing the authorized limit. During 2004 through 2005, we repurchased 340,950 shares of our common stock pursuant to the repurchase program at a cost of approximately $5.7 million. There were no repurchases made during 2006, 2007, 2008, 2009, or 2010 pursuant to the repurchase program. Shares repurchased during the fourth quarter of 2010 other than pursuant to our repurchase program are as follows:
 
Period
 
Total Number of Shares Purchased
   
Average Price Paid per Share
   
Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs (1)
   
Maximum Number (or Approximate Dollar Value) of Shares that May Yet Be Purchased Under the Publicly Announced Plans or Programs (1)
 
                         
Oct 1 - Oct 31, 2010
    2,265  (2)   $ 10.40       -     $ 14,327,000  
                                 
Nov 1 - Nov 30, 2010
    -       -       -     $ 14,327,000  
                                 
Dec 1 - Dec 31, 2010
    118  (2)   $ 11.18       -     $ 14,327,000  
                                 
     Total
    2,383               -     $ 14,327,000  

(1)
In January 2004, our Board of Directors authorized the repurchase of up to $20 million of our common stock. Purchases may be made from time to time in open market transactions at prevailing market prices. The repurchase program may continue until the authorized limit is reached, at which time the Board of Directors may review the option of increasing the authorized limit.
(2)
Shares we received in connection with the vesting of certain employee restricted stock. These shares were not acquired pursuant to the stock repurchase program.
 
 
35

 
 
Item 6. Selected Financial Data.

The following tables set forth our selected consolidated financial data for the years ended December 31, 2010, 2009, 2008, 2007, and 2006. The selected consolidated financial data does not purport to be complete and should be read in conjunction with, and is qualified by, the more detailed information, including the Consolidated Financial Statements and related Notes and “Management’s Discussion and Analysis of Financial Condition and Results of Operation” appearing elsewhere in this report. Please read “Item 1A. Risk Factors” beginning on page 13 for a discussion of the material uncertainties which might cause the selected consolidated financial data not to be indicative of our future financial condition or results of operations. In December 2007, we sold our process services operations. In 2006, we made the decision to discontinue our Venezuelan fluids and production testing operations. In 2003, we made the decision to discontinue the operations of our Norwegian process services operations. During 2000, we commenced our exit from the micronutrients business. Accordingly, we have reflected each of the above operations as discontinued operations. During 2008, Maritech acquired certain oil and gas properties. During 2007, we completed the acquisition of two service companies and Maritech acquired certain oil and gas properties. During 2006, we completed the acquisitions of the operations of Epic Divers, Inc., Beacon Resources, LLC, and a heavy lift barge. During 2010, we recorded significant impairments of our oil and gas properties, a dive support vessel, and a calcium chloride manufacturing plant as well as significant charges to earnings associated with adjustments to Maritech’s decommissioning liabilities. During 2008, we recorded significant impairments of oil and gas properties, goodwill, and other long-lived assets. During 2007, we recorded significant impairments of our oil and gas properties. These acquisitions, dispositions, and impairments significantly impact the comparison of our financial statements for 2010 to earlier years.


   
Year Ended December 31,
 
   
2010
   
2009
   
2008
   
2007
   
2006
 
   
(In Thousands, Except Per Share Amounts)
 
Income Statement Data
                             
Revenues
  $ 872,678     $ 878,877     $ 1,009,065     $ 982,483     $ 767,795  
Gross profit
    43,707       213,097       152,001       116,383       252,804  
Operating income (loss)
    (56,425 )     112,265       (21 )     16,512       160,800  
Interest expense
    (17,528 )     (13,207 )     (17,557 )     (17,886 )     (13,637 )
Interest income
    224       417       779       731       348  
Other income (expense), net
    (64 )     5,895       12,884       2,805       4,858  
Income (loss) before discontinued
                                       
   operations
    (43,325 )     68,807       (9,655 )     1,221       99,880  
Net income (loss)
  $ (43,718 )   $ 68,804     $ (12,136 )   $ 28,771     $ 101,878  
                                         
Income (loss) per share, before
                                       
  discontinued operations (1)
  $ (0.57 )   $ 0.92     $ (0.13 )   $ 0.02     $ 1.39  
Average shares (1)
    75,539       75,045       74,519       73,573       71,631  
                                         
Income (loss) per diluted share,
                                       
  before discontinued operations (1)
  $ (0.57 )   $ 0.91     $ (0.13 )   $ 0.02     $ 1.33  
Average diluted shares (1)
    75,539  (2)     75,722  (3)     74,519  (2)     75,921  (4)     74,824  

(1)
Net income (loss) per share and average share outstanding information reflects the retroactive impact of a 2-for-1 stock split as of May 15, 2006. The stock split was effected in the form of a stock dividend as of the record date.
(2)
For the years ended December 31, 2008 and 2010, the calculation of average diluted shares outstanding excludes the impact of all of our outstanding stock options, since all were antidilutive due to the net loss for the periods.
(3)
For the year ended December 31, 2009, the calculation of average diluted shares outstanding excludes the impact of 3,185,388 average outstanding stock options that would have been antidilutive.
(4)
For the year ended December 31, 2007, the calculation of average diluted shares outstanding excludes the impact of 716,354 average outstanding stock options that would have been antidilutive.
 
 
36

 
 
   
December 31,
 
   
2010
   
2009
   
2008
   
2007
   
2006
 
   
(In Thousands)
 
Balance Sheet Data
                             
  Working capital
  $ 198,106     $ 148,343     $ 222,832     $ 181,441     $ 262,572  
  Total assets
    1,299,628       1,347,599       1,412,624       1,295,536       1,086,190  
  Long-term debt
    305,035       310,132       406,840       358,024       336,381  
  Decommissioning and other
                                       
     long-term liabilities
    261,438       218,498       277,482       247,543       167,671  
  Stockholders' equity
    516,323       576,494       515,821       447,919       420,380  
 
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operation.

The following discussion is intended to analyze major elements of our consolidated financial statements and provide insight into important areas of management’s focus. This section should be read in conjunction with the Consolidated Financial Statements and the accompanying Notes included elsewhere in this Annual Report. We have accounted for the discontinuance or disposal of certain businesses as discontinued operations and have adjusted prior period financial information to exclude these businesses from continuing operations.

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

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

Other than the impact from increased regulation of offshore oil and gas operations, our businesses also continued to be affected by other factors. Our Production Testing segment reported improved activity levels during 2010, as demand for U.S. onshore services increased during the year. Maritech revenue levels were enhanced primarily as a result of strong realized oil and natural gas commodity pricing as a result of hedge derivative contracts. However, Maritech’s natural gas hedge derivative contracts expired at the end of
 
 
37

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

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

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

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

 
38

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

Our Offshore Division consists of two operating segments: Offshore Services and Maritech. Offshore Services generates revenues and cash flows by performing (1) downhole and subsea services such as plugging and abandonment, workover, and wireline services, (2) decommissioning and certain construction services, including offshore platform removal and hurricane damage remediation, and (3) diving services involving conventional and saturated air diving and the operation of several dive support vessels. The services provided by the Offshore Services segment are marketed primarily in the Gulf Coast region of the U.S., including offshore, inland waters, and in certain onshore locations. Gulf of Mexico platform decommissioning and well abandonment activity levels are driven primarily by BOEMRE regulations; the age of producing fields; production platforms and other structures; oil and natural gas commodity prices; sales activity of mature oil and gas producing properties; and overall oil and gas company activity levels. Recent regulations enacted by the BOEMRE governing the timing of abandonment and decommissioning of nonproductive wells and unused offshore platforms are expected to increase the demand for the Offshore Services segment, perhaps significantly, over the next several years. Given the increased cost to insure offshore properties for windstorm damage coverage and to reduce the risk from future storms, many oil and gas operators, including Maritech, are accelerating their plans to abandon and decommission their offshore wells and platforms. Offshore Services revenues decreased by 22.5% during 2010 compared to the revenue level experienced during 2009, when increased utilization by the segment’s diving, abandonment, heavy lift, and cutting services businesses as a result of the high demand following the 2005 and 2008 hurricanes, resulted in record activity levels. For the reasons described, the Offshore Services segment expects strong demand for its services to continue, however, the segment anticipates its overall activity in 2011 will again be less than the record levels experienced during 2009.

Through Maritech, the Offshore Division acquires, manages, explores, and develops oil and gas properties in the offshore, inland water, and onshore region of the Gulf of Mexico and generates revenues and cash flows from the sale of the associated oil and natural gas production volumes. Maritech periodically acquires properties for their exploration and development potential. Maritech’s revenues during 2010 increased by 13.3% compared to 2009 due to increased realized oil and gas commodity prices and despite decreased production volumes during the year. The increase in realized prices was primarily due to the impact of commodity hedge derivative contracts. However, the derivative contracts with the most favorable terms compared to current market prices expired at the end of 2010. Maritech continues to perform a significant amount of plugging, abandonment, and decommissioning efforts on its offshore oil and gas properties, particularly as part of its strategy to reduce its risk from hurricanes and in response to the increased cost of windstorm insurance coverage. Maritech has historically grown its operations by acquiring and developing oil and gas property interests located in the offshore, inland waters, and onshore U.S. Gulf Coast region. However, due to a desire to conserve and reallocate capital, we have begun to decrease our investment in Maritech by suspending our search for oil and gas property acquisitions and decreasing our
 
 
39

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

Our Production Enhancement Division consists of two operating segments: the Production Testing segment and the Compressco segment. The Production Testing segment generates revenues and cash flows by performing flow back pressure and volume testing of onshore and offshore oil and gas wells and by providing reservoir data necessary to enable operators to optimize production and minimize oil and gas reservoir damage. The primary testing markets served include many of the major oil and gas basins in the United States, as well as in Mexico and South America, Northern Africa, the Middle East, and Asia. The Division’s production testing operations are generally driven by the demand for natural gas and oil and the resulting drilling and completion activities in the markets where the Production Testing segment serves. Production Testing segment’s revenues increased 33.8% in 2010 compared to 2009, primarily due to increased demand in the United States. Given the continuing increase in drilling activity, we anticipate that demand for our production testing services will continue to increase in 2011 compared to 2010.

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

Critical Accounting Policies and Estimates

In preparing our consolidated financial statements, we make assumptions, estimates, and judgments that affect the amounts reported. We periodically evaluate these estimates and judgments, including those related to potential impairments of long-lived assets (including goodwill), the collectability of accounts receivable, and the current cost of future abandonment and decommissioning obligations. “Note B – Summary of Significant Accounting Policies” to the Consolidated Financial Statements contains the accounting policies governing each of these matters. Our estimates are based on historical experience and on future expectations which we believe are reasonable. The fair values of large portions of our total assets and liabilities are measured using significant unobservable inputs. The combination of these factors forms the basis for our judgments made about the carrying values of assets and liabilities that are not readily apparent from other sources. These judgments and estimates may change as new events occur, as new information is acquired, and as changes in our operating environment are encountered. Actual results are likely to differ from our current estimates, and those differences may be material. The following critical accounting policies reflect the most significant judgments and estimates used in the preparation of our financial statements.

Impairment of Long-Lived Assets

The determination of impairment of long-lived assets is conducted periodically whenever indicators of impairment are present. If such indicators are present, the determination of the amount of impairment is based on our judgments as to the future operating cash flows to be generated from these assets throughout their estimated useful lives. If an impairment of a long-lived asset is warranted, we estimate the fair value of the asset based on a present value of these cash flows or the value that could be realized from disposing of the asset in a transaction between market participants. The oil and gas industry is cyclical, and our estimates of the amount of future cash flows, the period over which these estimated future cash flows will be generated, as well as the fair value of an impaired asset, are imprecise. Our failure to accurately estimate these future operating cash flows or fair values could result in certain long-lived assets being overstated, which could result in impairment charges in periods subsequent to the time in which the impairment indicators were first present. Alternatively, if our estimates of future operating cash flows or fair values are understated, impairments might be recognized unnecessarily or in excess of the appropriate amounts. Our estimates of
 
 
40

 
 
operating cash flows and fair values for assets impaired have generally been accurate. Although the majority of our impairments of long-lived assets have typically related to oil and gas properties (see separate discussion below), during 2010, we recorded other long-lived asset impairments of $25.1 million. Given the current volatile economic environment, the likelihood of additional material impairments of long-lived assets in future periods is higher due to the possibility of further decreased demand for our products and services.

Impairment of Goodwill

The impairment of goodwill is also assessed whenever impairment indicators are present, but not less than once annually. The assessment for goodwill impairment is performed for each reporting unit and consists of a comparison of the carrying amount of each reporting unit to our estimation of the fair value of that reporting unit. If the carrying amount of the reporting unit exceeds its estimated fair value, an impairment loss is calculated by comparing the carrying amount of the reporting unit’s goodwill to our estimated implied fair value of that goodwill. Our estimates of reporting unit fair value are imprecise and are subject to our estimates of the future cash flows of each business and our judgment as to how these estimated cash flows translate into each business’ estimated fair value. These estimates and judgments are affected by numerous factors, including the general economic environment at the time of our assessment, which affects our overall market capitalization. If we over estimate the fair value of our reporting units, the balance of our goodwill asset may be overstated. Alternatively, if our estimated reporting unit fair values are understated, impairments might be recognized unnecessarily or in excess of the appropriate amounts. During the fourth quarter of 2008, due to changes in the global economic environment which affected our stock price and market capitalization, we recorded an impairment of goodwill of $47.1 million. We believe our estimates of the fair value for each reporting unit are reasonable. However, given the current volatile economic environment, the likelihood of additional material impairments of goodwill in future periods is higher.

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

Oil and Gas Properties

Maritech accounts for its interests in oil and gas properties using the successful efforts method, whereby costs incurred to drill and equip development wells, including unsuccessful development wells, are capitalized, and costs related to unsuccessful exploratory wells are expensed as incurred. All capitalized costs are accumulated and recorded separately for each field and are depleted on a unit-of-production basis, based on the estimated remaining proved oil and gas reserves of each field. Oil and gas properties are assessed for impairment in value on an individual field basis, whenever indicators become evident, with any impairment charged to expense. Accordingly, Maritech’s results of operations may be more volatile compared to those oil and gas exploration and production companies who account for their operations using the full-cost method. Due to the impact of changing oil and gas prices, results of drilling and development efforts, and increased estimated decommissioning liabilities (see discussion below), Maritech has recorded oil and gas property impairments and dry hole costs, and during 2008, 2009, and 2010 these impairment charges were significant. Maritech periodically purchases oil and gas properties and assumes the associated well abandonment and decommissioning liabilities. Any significant differences in the actual amounts of oil and gas production cash flows produced or decommissioning costs incurred compared to the estimated amounts recorded will affect our anticipated profitability. Given the volatility of oil and natural gas prices, we are more likely to record additional significant impairments in future periods.
 
 
41

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

Decommissioning Liabilities

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

We review the adequacy of our decommissioning liabilities whenever indicators suggest that either the amount or timing of the estimated cash flows underlying the liabilities have changed materially. The estimated timing of these cash flows is determined by the productive life of the associated oil and gas property, which is based on the property’s oil and gas reserve estimates. The amount of cash flows necessary to abandon and decommission the property is subject to changes due to seasonal demand, increased demand following hurricanes, regulatory changes, and other general changes in the energy industry environment. Accordingly, the estimation of our decommissioning liabilities is imprecise. Following the issuance by the BOEMRE of NTL 2010-G05 “Idle Iron Guidance” regulations and due to other factors, Maritech significantly adjusted its decommissioning liabilities as of December 31, 2010. Largely as a result of these adjustments, as well as a result of the cost of significant abandonment and decommissioning work performed during the year, Maritech recorded approximately $30.2 million of increased excess decommissioning expense associated with work performed or to be performed on nonproductive oil and gas properties. In addition, adjustments to decommissioning liabilities associated with productive properties were capitalized to oil and gas properties and contributed significantly to Maritech recording approximately $52.4 million of increased oil and gas property impairments during 2010 compared to the prior year. The estimation of the decommissioning liabilities associated with the two remaining Maritech offshore platforms that were destroyed during the 2005 and 2008 hurricanes is particularly difficult due to the non-routine nature of the efforts required. The actual cost of performing Maritech’s well abandonment and decommissioning work has often exceeded our initial estimate of Maritech’s decommissioning liabilities and has resulted in charges to earnings in the period the work is performed or when the additional liability is determined. During 2008, 2009, and 2010, the amount of charges to earnings as a result of costs of work performed being in excess of our estimated liabilities has been significant. To the extent our decommissioning liabilities are understated, additional charges to earnings may be required in future periods.

Revenue Recognition

We generate revenue on certain well abandonment and decommissioning projects under contracts which are typically of short duration and that provide for either lump-sum turnkey charges or specific time,
 
 
42

 
 
material, and equipment charges, which are billed in accordance with the terms of such contracts. With regard to turnkey contracts, revenue is recognized using the percentage-of-completion method based on the ratio of costs incurred to total estimated costs at completion. The estimation of total costs to be incurred may be imprecise due to unexpected well conditions, delays, weather, and other uncertainties. Inaccurate cost estimates may result in the revenue associated with a specific contract being recognized in an inappropriate period. Total project revenue and cost estimates for turnkey contracts are reviewed periodically as work progresses, and adjustments are reflected in the period in which such estimates are revised. Provisions for estimated losses on such contracts are made in the period such losses are determined. Despite the uncertainties associated with estimating the total contract cost, our recognition of revenue associated with these contracts has historically been reasonable.

Our Production Testing segment is party to a South American technical management contract which contains multiple deliverables, including the delivery of equipment and the performance of service milestones. While the contract provides contract-determined values associated with each deliverable, the recognition of revenue is determined based on the realized market values received by the customer as well as by the realizability of collections under the contract. The determination of realized market values is supported by objective evidence whenever possible, but may also be determined based on our judgments as to the value of a particular deliverable.

Bad Debt Reserves

Reserves for bad debts are calculated on a specific identification basis, whereby we estimate whether or not specific accounts receivable will be collected. Such estimates of future collectability may be incorrect, which could result in the recognition of unanticipated bad debt expenses in future periods. A significant portion of our revenues come from oil and gas exploration and production companies, and historically our estimates of uncollectible receivables have proven reasonably accurate. However, if due to adverse circumstances, certain customers are unable to repay some or all of the amounts owed us, an additional bad debt allowance may be required, and such amount may be material.

Income Taxes

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

Acquisition Purchase Price Allocations

We account for acquisitions of businesses using the purchase method, which requires the allocation of the purchase price based on the fair values of the assets and liabilities acquired. We estimate the fair values of the assets and liabilities acquired using accepted valuation methods, and, in many cases, such estimates are based on our judgments as to the future operating cash flows expected to be generated from the acquired assets throughout their estimated useful lives. We have completed several acquisitions during the past several years and have accounted for the various assets (including intangible assets) and liabilities acquired based on our estimate of fair values. Goodwill represents the excess of acquisition purchase price over the estimated fair values of the net assets acquired. Our estimates and judgments of the fair value of
 
 
43

 
 
acquired businesses are imprecise, and the use of inaccurate fair value estimates could result in the improper allocation of the acquisition purchase price to acquired assets and liabilities, which could result in asset impairments, recording of previously unrecorded liabilities, and other financial statement adjustments. The difficulty in estimating the fair values of acquired assets and liabilities is increased during periods of economic uncertainty.

Stock-Based Compensation

We estimate the fair value of share-based payments of stock options using the Black-Scholes option-pricing model. This option-pricing model requires a number of assumptions, of which the most significant are: expected stock price volatility, the expected pre-vesting forfeiture rate, and the expected option term (the amount of time from the grant date until the options are exercised or expire). Expected volatility is calculated based upon actual historical stock price movements over the most recent periods equal to the expected option term. Expected pre-vesting forfeitures are estimated based on actual historical pre-vesting forfeitures over the most recent periods for the expected option term. All of these estimates are inherently imprecise and may result in compensation cost being recorded that is materially different from the actual fair value of the stock options granted. While the assumptions for expected stock price volatility and pre-vesting forfeiture rates are updated with each year’s option-valuing process, there have not been significant revisions made in these estimates to date.
 
Results of Operations

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

2010 Compared to 2009

Consolidated Comparisons

   
Year Ended December 31,
   
Period to Period Change
 
   
2010
   
2009
   
2010 vs 2009
   
% Change
 
   
(In Thousands, Except Percentages)
 
Revenues
  $ 872,678     $ 878,877     $ (6,199 )     -0.7 %
Gross profit
    43,707       213,097       (169,390 )     -79.5 %
Gross profit as a percentage of revenue
    5.0 %     24.2 %                
General and administrative expense
    100,132       100,832       (700 )     -0.7 %
General and administrative expense as a
   percentage of revenue
    11.5 %     11.5 %                
Interest expense, net
    17,304       12,790       4,514       35.3 %
Other (income) expense, net
    64       (5,895 )     5,959       -101.1 %
Income (loss) before taxes and discontinued
   operations
    (73,793 )     105,370       (179,163 )     -170.0 %
Income (loss) before taxes and discontinued
   operations as a percentage of revenue
    -8.5 %     12.0 %                
Provision (benefit) for income taxes
    (30,468 )     36,563       (67,031 )     -183.3 %
Income before discontinued operations
    (43,325 )     68,807       (112,132 )     -163.0 %
Loss from discontinued operations, net of taxes
    (393 )     (3 )     (390 )     -13000.0 %
Net income
  $ (43,718 )   $ 68,804     $ (112,522 )     -163.5 %
 
Consolidated revenues decreased despite increased revenues from our Fluids, Maritech, and Production Testing segments, primarily due to decreases in the revenues of the Offshore Services and Compressco segments. Offshore Services segment revenues decreased by $79.6 million compared to the record levels of 2009, which saw unprecedented activity and demand. Increased onshore oil and gas industry activity during 2010 contributed to the revenue increases by our Production Testing and Fluids Divisions, with the Fluids Division also reflecting increased sales of manufactured products from our new El Dorado, Arkansas, calcium chloride plant. Maritech revenues increased largely because of higher realized oil prices, which include the impact of certain commodity derivative hedges which expired at the end of 2010. Overall gross profit decreased primarily due to $72.8 million of decreased profitability from our Offshore Services segment, and due to significant impairments and other charges incurred by our Maritech, Offshore Services, and Fluids segments. In addition, the gross profit of our Fluids and Compressco segments were also
 
 
44

 
 
decreased compared to the prior year. These decreases were partially offset by increased Production Testing gross profit.

Consolidated general and administrative expenses decreased as compared to the prior year due to approximately $3.4 million of decreased bad debt expenses and $0.8 million of decreased insurance expenses during the current year. These decreases were largely offset by approximately $1.8 million of increased employee related costs, including increased salary, benefits, contract labor costs, and other associated employee expenses. In addition, general and administrative expenses during 2010 include $0.2 million of increased professional fees, $0.3 million of increased office expenses, and $1.2 million of increased taxes, investor relations, and other general expenses.

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

Consolidated other income decreased during 2010 compared to the prior year, primarily due to approximately $7.4 million of decreased gains on sales of assets, $3.8 million of decreased legal settlement gains, $1.2 million of decreased foreign currency gains, and due to the expensing of a $2.8 million prepayment premium on the repayment of the 2004 Senior Notes. These decreases were partially offset by $9.2 million of increased earnings in an unconsolidated joint venture, primarily due to a $6.8 million charge for an impairment of our Fluids Division European joint venture investment during 2009. In addition, we recorded $1.6 million of decreased hedge ineffectiveness losses compared to the prior year.

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

Divisional Comparisons

Fluids Division

   
Year Ended December 31,
   
Period to Period Change
 
   
2010
   
2009
   
2010 vs 2009
   
% Change
 
   
(In Thousands, Except Percentages)
 
Revenues
  $ 276,337     $ 225,517     $ 50,820       22.5 %
Gross profit
    38,984       47,549       (8,565 )     -18.0 %
Gross profit as a percentage of revenue
    14.1 %     21.1 %                
General and administrative expense
    23,712       22,355       1,357       6.1 %
General and administrative expense as a
   percentage of revenue
    8.6 %     9.9 %                
Interest (income) expense, net
    195       (35 )     230          
Other (income) expense, net
    (876 )     4,438       (5,314 )        
Income before taxes and discontinued operations
  $ 15,953     $ 20,791     $ (4,838 )     -23.3 %
Income before taxes and discontinued
   operations as a percentage of revenue
    5.8 %     9.2 %                
 
The increase in Fluids Division revenues as compared to the prior year was primarily due to $44.0 million of increased product sales revenues. This increase in product sales revenues was partially attributed to increased revenues from sales of liquid calcium chloride produced from our El Dorado, Arkansas, calcium chloride plant, which began production during the fourth quarter of 2009. Product sales revenues also increased due to increased domestic sales volumes of clear brine fluids (CBFs), particularly during the fourth quarter of 2010. Domestic product sales revenues also benefitted from increased pricing compared to the prior year and due to a significant sale of bromide products during the first quarter of 2010. International product sales revenues also increased, due to improved oil and gas activity levels in certain of the foreign markets we serve and due to increased product sales from our European calcium chloride operations. The increase in domestic product sales revenues during 2010 occurred despite the decreased activity and pricing on product sales to domestic deepwater operators as a result of the deepwater drilling moratorium, which was in effect during a portion of the year. Although this moratorium was lifted in October 2010, delays due to permitting and increased regulatory requirements have continued to slow the return of improved demand in the deepwater Gulf of Mexico. However, CBF sales volumes increased during the fourth quarter of 2010, and this trend may indicate that activity levels are increasing going forward. In addition to increased product sales
 
 
45

 
 
revenues, service revenues increased by approximately $6.9 million due to increased domestic frac water and filtration service activities.

Despite the increased revenues, gross profit decreased compared to the prior year primarily due to the significant losses from our domestic calcium chloride manufacturing operations. These losses were primarily due to the $7.2 million impairment of the Division’s Lake Charles, Louisiana, calcium chloride plant. Due to the current market pricing for calcium chloride and the uncertain supply of raw materials needed to operate the plant on economic terms, the expected operating cash flows of the plant are insufficient to cover the plant’s carrying value, resulting in the impairment. In addition, start-up costs and continuing production inefficiencies have negatively affected the profitability of our El Dorado, Arkansas, calcium chloride plant. We continue to take steps to improve the operational efficiency of this plant; however, there is still considerable effort required, and significant improvement in plant performance is not expected until mid 2011. Partially offsetting the significantly decreased profitability of our domestic calcium chloride manufacturing operations, gross profit on CBF sales and completion services increased approximately $5.4 million, due to the increased activity levels during the current year. In addition, gross profit from the Division’s European calcium chloride manufacturing operations also increased.

Income before taxes decreased compared to the prior year, primarily due to the decreased gross profit discussed above and due to an increase in general and administrative expense, primarily due to increased employee-related costs. This decrease in profitability was partially offset by a significant decrease in other expense as compared to the prior year when we recorded a $6.5 million charge for the impairment of the Division’s investment in a European unconsolidated joint venture. Partially offsetting this decrease in other expense, other income decreased as a result of decreased foreign currency gains on the Division’s international operations.

Offshore Division

Offshore Services Segment

   
Year Ended December 31,
   
Period to Period Change
 
   
2010
   
2009
   
2010 vs 2009
   
% Change
 
   
(In Thousands, Except Percentages)
 
Revenues
  $ 274,200     $ 353,798     $ (79,598 )     -22.5 %
Gross profit
    21,695       94,488       (72,793 )     -77.0 %
Gross profit as a percentage of revenue
    7.9 %     26.7 %                
General and administrative expense
    17,048       13,891       3,157       22.7 %
General and administrative expense as a
   percentage of revenue
    6.2 %     3.9 %                
Interest (income) expense, net
    100       (161 )     261          
Other (income) expense, net
    (117 )     2,364       (2,481 )        
Income before taxes and discontinued operations
  $ 4,664     $ 78,394     $ (73,730 )     -94.1 %
Income before taxes and discontinued
   operations as a percentage of revenue
    1.7 %     22.2 %                
 
The decrease in revenues for the Offshore Services segment was due to decreased activity compared to the record levels experienced in the prior year period. The decreased activity resulted in reduced utilization of much of the segment’s fleet as compared to the prior year period, without taking into effect the addition of a leased dive support vessel beginning in June 2009. In addition to the decreased activity for certain of the segment’s operations, overall pricing levels were lower during 2010 compared to the prior year. During 2010, the BOEMRE issued NTL 2010-G05, the “Idle Iron Guidance” regulations, which require that permanent plugs be set in nearly 3,500 nonproducing wells in the U.S. Gulf of Mexico. In addition, the new regulation requires approximately 650 oil and gas production platforms to be dismantled if they are not being used. We anticipate that these new requirements will increase, perhaps significantly, the future demand for well abandonment and decommissioning services to be performed by our Offshore Services segment. In addition, we continue to capitalize on the remaining demand for well abandonment and decommissioning services for the remaining offshore properties that were damaged or destroyed by hurricanes. Still, we anticipate that levels of Offshore Services segment activity in 2011 will again be lower than the record activity levels we experienced during most of 2009. A total of $62.5 million of the segment’s revenues during 2010 were performed for Maritech, compared with $45.6 million during the prior year. These intersegment revenues are eliminated in the consolidated statements of operations.
 
 
46

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

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

Maritech Segment

   
Year Ended December 31,
   
Period to Period Change
 
   
2010
   
2009
   
2010 vs 2009
   
% Change
 
   
(In Thousands, Except Percentages)
 
Revenues
  $ 200,559     $ 177,039     $ 23,520       13.3 %
Gross profit (loss)
    (65,055 )     20,655       (85,710 )     -415.0 %
Gross profit as a percentage of revenue
    -32.4 %     11.7 %                
General and administrative expense
    4,323       5,911       (1,588 )     -26.9 %
General and administrative expense as a
   percentage of revenue
    2.2 %     3.3 %                
Interest (income) expense, net
    (107 )     17       (124 )        
Other (income) expense, net
    (152 )     (7,285 )     7,133          
Income before taxes and discontinued operations
  $ (69,119 )   $ 22,012     $ (91,131 )     -414.0 %
Income before taxes and discontinued
   operations as a percentage of revenue
    -34.5 %     12.4 %                
 
Approximately $41.1 million of Maritech revenues was due to increased realized commodity prices during 2010 compared to the prior year. Maritech has hedged a portion of its expected future oil production levels by entering into commodity derivative hedge contracts, with certain contracts extending through 2011, although contracts having a positive impact compared to market prices expired at the end of 2010. Including the impact of its commodity derivative hedge contracts, Maritech reflected average realized oil and natural gas prices during 2010 of $96.63/barrel and $8.47/MMBtu, respectively, each of which were significantly higher than market prices of oil and natural gas during the period. Much of the favorable hedged oil pricing impact was as a result of 2010 oil swaps that were liquidated during 2009. Partially offsetting the increased realized prices, overall production volumes decreased during the current year period, resulting in $18.1 million of decreased revenues. This decrease was attributed to natural gas production interruptions and normal production declines during the period. A portion of Maritech’s Main Pass area production is currently shut-in due to third-party pipeline issues and the lack of available transportation for production. Although total oil production increased compared to the prior year period, Maritech’s interest in the East Cameron 328 field will continue to have a portion of its production shut-in until Maritech completes the redrilling of certain wells from a newly installed platform to replace the platform that was toppled during Hurricane Ike in 2008. Recent successful development efforts at Maritech’s Timbalier Bay field are expected to result in increased production going forward. However, since late 2008, as a result of our efforts to conserve capital and decrease our investment in Maritech, we have significantly reduced overall acquisition and development activities, and the level of such activity is expected to continue to be decreased going forward. In February 2011, Maritech sold a portion of its oil and gas properties, which will also result in decreased revenues going forward. In addition, Maritech reported $0.1 million of decreased processing revenue during 2010.

Despite the increased revenues, Maritech’s gross profit for 2010 decreased significantly compared to the prior year due to several factors. During 2009, Maritech recorded $42.2 million of additional credits to operating expense for the collection of insurance settlement proceeds, primarily from the $40 million insurance litigation settlement in December 2009 regarding certain claims associated with damage from
 
 
47

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

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

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

   
Year Ended December 31,
   
Period to Period Change
 
   
2010
   
2009
   
2010 vs 2009
   
% Change
 
   
(In Thousands, Except Percentages)
 
Revenues
  $ 103,995     $ 77,700     $ 26,295       33.8 %
Gross profit
    22,205       16,868       5,337       31.6 %
Gross profit as a percentage of revenue
    21.4 %     21.7 %                
General and administrative expense
    9,465       7,985       1,480       18.5 %
General and administrative expense as a
   percentage of revenue
    9.1 %     10.3 %                
Interest (income) expense, net
    (34 )     2       (36 )        
Other (income) expense, net
    (2,250 )     (6,823 )     4,573          
Income before taxes and discontinued operations
  $ 15,024     $ 15,704     $ (680 )     -4.3 %
Income before taxes and discontinued
   operations as a percentage of revenue
    14.4 %     20.2 %                
 
The increase in revenues for the Production Testing segment was primarily due to a $16.9 million increase in domestic operations, approximately $10.0 million of which was recorded during the fourth quarter of 2010. This increase reflects the increase in domestic drilling activity, which we anticipate will continue in 2011. In addition, international operations generated $9.4 million of increased revenues. Approximately $6.3 million of this increase was associated with a South American technical management contract. Increased international revenues were reported during 2010 due to increases in Eastern Hemisphere and Brazil, and were partially offset by decreased activity and revenues in Mexico, where customer budgetary issues, security disruptions, and regional flooding during the year have negatively affected activity levels.

The increase in gross profit was due to approximately $6.7 million of increased domestic gross profit, which more than offset the approximately $1.4 million decrease in international gross profit. Domestic profitability increased due to the higher activity levels and improved operating efficiencies. While international production testing operations have historically generated higher operating margins than domestic operations, decreased activity and operating interruptions in Mexico have hampered international profitability.

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

 
48

 
 
Compressco Segment

   
Year Ended December 31,
   
Period to Period Change
 
   
2010
   
2009
   
2010 vs 2009
   
% Change
 
   
(In Thousands, Except Percentages)
 
Revenues
  $ 81,413     $ 90,965     $ (9,552 )     -10.5 %
Gross profit
    28,672       35,985       (7,313 )     -20.3 %
Gross profit as a percentage of revenue
    35.2 %     39.6 %                
General and administrative expense
    11,008       10,518       490       4.7 %
General and administrative expense as a
   percentage of revenue
    13.5 %     11.6 %                
Interest (income) expense, net
    35       -       35          
Other (income) expense, net
    116       (82 )     198          
Income before taxes and discontinued operations
  $ 17,513     $ 25,549     $ (8,036 )     -31.5 %
Income before taxes and discontinued
   operations as a percentage of revenue
    21.5 %     28.1 %                
 
The decrease in Compressco revenues was due to $5.6 million of decreased U.S. compression service revenues, primarily reflecting the reduced U.S. demand for wellhead compression services during 2010. We believe the reduced demand was primarily due to continuing lower natural gas prices compared to prices during previous years, as well as due to the impact of increased competition. Compressco’s domestic activity levels have begun to increase during the past three quarters, and fourth quarter of 2010 revenue levels were increased compared to the prior year period. Over the past year, many domestic oil and gas operators, including certain Compressco customers, have responded to the lower gas prices by reducing operating expenses. In addition, international service revenues also decreased by $3.1 million, primarily due to decreased activity in Mexico. Going forward, we anticipate that Compressco’s international revenues will continue to be negatively affected by conditions in Mexico, where customer budgetary issues and security disruptions have negatively impacted activity levels during 2010. Revenues from sales of compressor units and parts during 2010 decreased $0.8 million compared to the prior year. Compressco has reduced the fabrication of new compressor units until demand for its production enhancement services increases and inventories of available units are reduced.

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

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

Corporate Overhead

   
Year Ended December 31,
   
Period to Period Change
 
   
2010
   
2009
   
2010 vs 2009
   
% Change
 
   
(In Thousands, Except Percentages)
 
Gross profit (primarily depreciation expense)
  $ (3,238 )   $ (3,019 )   $ (219 )     7.3 %
General and administrative expense
    34,576       40,173       (5,597 )     -13.9 %
Interest expense, net
    17,112       12,969       4,143       31.9 %
Other expense, net
    3,345       1,566       1,779       113.6 %
Income (loss) before taxes and
   discontinued operations
  $ (58,271 )   $ (57,727 )   $ (544 )     -0.9 %
 
Corporate Overhead includes corporate general and administrative expense, interest income and expense, and other income and expense. Such expenses and income are not allocated to our operating divisions, as they relate to our general corporate activities. Corporate Overhead increased during 2010 compared to the prior year, as decreased general and administrative expenses were offset by increased interest expense and other expense. Corporate general and administrative costs decreased primarily due to approximately $4.4 million of decreased salaries and employee-related expenses, which was mainly due to decreased incentive compensation. In addition, general and administrative expenses decreased due to $0.4
 
 
49

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

2009 Compared to 2008

Consolidated Comparisons

   
Year Ended December 31,
   
Period to Period Change
 
   
2009
   
2008
   
2009 vs 2008
   
% Change
 
   
(In Thousands, Except Percentages)
 
Revenues
  $ 878,877     $ 1,009,065     $ (130,188 )     -12.9 %
Gross profit
    213,097       152,001       61,096       40.2 %
Gross profit as a percentage of revenue
    24.2 %     15.1 %                
General and administrative expense
    100,832       104,949       (4,117 )     -3.9 %
General and administrative expense as a
   percentage of revenue
    11.5 %     10.4 %                
Impairment of goodwill
    -       47,073       (47,073 )     -100.0 %
Interest expense, net
    12,790       16,778       (3,988 )     -23.8 %
Other (income) expense, net
    (5,895 )     (12,884 )     6,989       -54.2 %
Income (loss) before taxes and discontinued
   operations
    105,370       (3,915 )     109,285       -2791.4 %
Income (loss) before taxes and discontinued
   operations as a percentage of revenue
    12.0 %     -0.4 %                
Provision for income taxes
    36,563       5,740       30,823       537.0 %
Income before discontinued operations
    68,807       (9,655 )     78,462       -812.7 %
Loss from discontinued operations, net of taxes
    (3 )     (2,481 )     2,478       99.9 %
Net income
  $ 68,804     $ (12,136 )   $ 80,940       -666.9 %
 
Consolidated revenues decreased despite a significant increase in our Offshore Services segment revenues. This was due to decreased revenues by each of the other reporting segments, which reflected the impact of the general decline in oil and gas industry activity during 2009. This decrease was primarily due to the global economic environment and specifically due to lower oil and natural gas commodity prices during 2009 compared to 2008. Offshore Services revenues increased by $47.4 million due to increased demand for diving, platform decommissioning, cutting, and abandonment services during 2009, following the damage to offshore platforms from hurricanes in the Gulf of Mexico in prior years and due to the risk of damage from future storms. This increase was more than offset by significantly decreased revenue from our Fluids Division, which experienced decreased demand for its products, primarily due to decreased oil and gas completion activity. In addition, our Production Testing, Maritech, and Compressco segments also reported decreased revenues, generally due to decreased demand resulting from lower oil and gas commodity pricing. Despite these decreases, overall gross profit increased during 2009 compared to 2008, primarily due to the unprecedented favorable performance of our Offshore Services segment, a favorable litigation settlement, and due to significant impairments to oil and gas properties during 2008.

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

Consolidated general and administrative expenses decreased primarily due to approximately $2.2 million of decreased salary, benefits, contract labor costs, and other associated employee expenses, primarily due to overall personnel cost reduction efforts. This decrease was despite increased incentive bonus and equity compensation expenses. General and administrative expenses were also decreased due to approximately $2.1 million of decreased office expense, primarily from decreased office rent following the first
 
 
50

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

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

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

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

Divisional Comparisons

Fluids Division

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