Item 1. Business.
General
TETRA Technologies, Inc. (the Company) is an oil and gas services company with an integrated calcium chloride and brominated products manufacturing operation that supplies feedstocks to energy markets, as well as other markets. The Company is composed of three divisions - Fluids, Well Abandonment & Decommissioning (WA&D), and Production Enhancement.
The Company’s Fluids Division manufactures and markets clear brine fluids, additives and other associated products and services to the oil and gas industry for use in well drilling, completion, and workover operations both domestically and in certain regions of Europe, Asia, Latin America and Africa. The Division also markets certain fluids and dry calcium chloride manufactured at its production facilities to a variety of domestic and international markets outside the energy industry.
The Company’s WA&D Division consists of two operating segments: WA&D Services and Maritech. The WA&D Services segment provides a broad array of services required for the abandonment of depleted oil and gas wells and the decommissioning of platforms, pipelines, and other associated equipment, serving the onshore U.S. Gulf Coast region and the inland waters and offshore markets of the Gulf of Mexico. The segment also provides electric wireline, engineering, diving, workover, and drilling services. The Maritech segment consists of the Company’s Maritech Resources, Inc. (Maritech) subsidiary, which, with its subsidiaries, is a producer of oil and gas from properties acquired primarily to support and provide a baseload of business for the WA&D Services operation. In addition, Maritech conducts development and exploitation operations on certain of its oil and gas properties, which are intended to increase the cash flows on such properties prior to their ultimate abandonment.
The Company’s Production Enhancement Division provides production testing services to the Texas, New Mexico, Louisiana, offshore Gulf of Mexico, Mexico, Venezuela, Brazil and Middle East markets. In addition, it is engaged in the design, fabrication, sale, lease and service of wellhead compression equipment primarily used to enhance production from mature, low pressure natural gas wells located principally in the mid-continent, mid-western, Rocky Mountain, Texas and Louisiana regions of the United States as well as in western Canada and Mexico. The Division also provides the technology and services required for the separation and recycling of oily residuals generated from petroleum refining operations.
The Company continues to pursue a growth strategy that includes expanding its existing businesses - both through internal growth and through the pursuit of suitable acquisitions - and by identifying opportunities to establish operations in additional niche oil service markets. For financial information for each of the Company’s segments, including information regarding revenues and total assets, see “Note Q - Industry Segments and Geographic Information” contained in the Notes to Consolidated Financial Statements.
TETRA Technologies, Inc. was incorporated in Delaware in 1981. All references to the Company include TETRA Technologies, Inc. and its subsidiaries. The Company’s corporate headquarters are located at 25025 Interstate 45 North, Suite 600, in The Woodlands, Texas. Its phone number is 281-367-1983 and its web site is accessed at www.tetratec.com. The Company makes available, free of charge, on its website, its Corporate Governance Guidelines, Code of Business Conduct and Ethics, Code of Ethics for Senior Financial Officers, Audit Committee Charter, Management and Compensation Committee Charter and Nominating and Corporate Governance Committee Charter as well as its annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and all amendments to those reports as soon as is reasonably practicable after such materials are electronically filed with, or furnished to, the Securities and Exchange Commission (SEC). The Company will also make these available in print free of charge to any stockholder who requests such information from the Corporate Secretary.
Products and Services
Fluids Division
Liquid calcium chloride, sodium bromide, calcium bromide, zinc bromide and zinc calcium bromide produced by the Fluids Division are referred to as clear brine fluids (CBFs) in the oil and gas industry. CBFs are solids-free, clear salt solutions that, like conventional drilling “muds,” have high specific gravities and are used as weighting fluids to control bottomhole pressures during oil and gas completion and workover activities. The use of CBFs increases production by reducing the likelihood of damage to the wellbore and productive pay zone. CBFs are particularly important in offshore completion and workover operations due to the greater formation sensitivity, the significantly greater investment necessary to drill offshore, and the consequent higher cost of error. CBFs are distributed through the Company’s Fluids Division and are also sold to other companies who service customers in the oil and gas industry.
The Fluids Division provides basic and custom blended CBFs to domestic and international oil and gas well operators, based on the specific need of the customer and the proposed application of the product. The Division also provides these customers with a broad range of associated services, including onsite fluid filtration, handling and recycling, fluid engineering consultation and fluid management. The Division also repurchases used CBFs from operators and recycles and reconditions these materials. The utilization of reconditioned CBFs reduces the net cost of the CBFs to the Company’s customers and minimizes the need for disposal of used fluids. The Company recycles and reconditions the CBFs through filtration, blending and the use of proprietary chemical processes, and then markets the reconditioned CBFs.
The Division’s fluid engineering and management personnel use proprietary technology to determine the proper blend for a particular application to maximize the effectiveness and lifespan of the CBFs. The specific volume, density, crystallization temperature and chemical composition of the CBFs are modified by the Company to satisfy a customer's specific requirements. The Company’s filtration services use a variety of techniques and equipment for the onsite removal of particulates from CBFs, so that those CBFs can be recirculated back into the well. Filtration also enables recovery of a greater percentage of used CBFs for recycling.
The manufacturing group of the Fluids Division obtains product from numerous production facilities that manufacture liquid and/or dry calcium chloride, sodium bromide, calcium bromide, zinc bromide and/or zinc calcium bromide for distribution into energy markets. Liquid and dry calcium chloride are also sold into the water treatment, industrial, cement, food processing, dust control, ice melt, agricultural and consumer products markets. Liquid sodium bromide is also sold into the industrial water treatment markets, where it is used as a biocide in recirculated cooling tower waters.
The Fluids Division’s calcium chloride operations expanded significantly during 2004, primarily due to the September 2004 acquisition of the European calcium chloride manufacturing assets from Kemira Oyj (Kemira) of Helsinki, Finland. The Company operates these assets under the trade name of TCE. The acquisition enhanced the Company’s position as a leading producer and marketer of calcium chloride to both energy and industrial markets.
The Company obtains calcium chloride from production facilities in the United States, Canada, China, and Europe. Some of these plants are owned by the Company, and the Company obtains production from the non-owned plants under written agreements with the owner. Dry calcium chloride is produced at the Company’s Kokkola, Finland plant, which has a production capacity of 165,000 tons per year. The Company also owns a calcium chloride plant in Lake Charles, Louisiana, with a production capacity of 100,000 tons of dry product per year. In October 2005, the main feedstock supplier for the Company’s Lake Charles plant announced that it had permanently ceased production from its TDI plant in Lake Charles. The Lake Charles plant is currently operating at a reduced level while the Company reviews alternative sources of feedstock. The Company also has two solar evaporation plants located in San Bernardino County, California, which produce liquid calcium chloride from underground brine reserves for sale to markets in the western United States.
The manufacturing group manufactures and distributes sodium bromide, calcium bromide and zinc bromide from its West Memphis, Arkansas facility. A patented and proprietary production process utilized at this facility uses a low cost hydrobromic acid or bromine, along with various zinc sources, to manufacture its products. This facility also uses patented and proprietary technologies to recondition and upgrade used CBFs repurchased from the Company’s customers. The group has a facility at Dow Chemical’s Ludington, Michigan chemical plant that converts a crude bromine stream from Dow’s calcium/magnesium chemicals operation into bromine and liquid calcium bromide or liquid sodium bromide.
The Company also owns a plant in Magnolia, Arkansas that is designed to produce calcium bromide. Approximately 33,000 gross acres of bromine-containing brine reserves are under lease by the Company in the vicinity of the plant to support its production. The existing plant is not operable; however, the Company has begun plans to develop the Magnolia location, including the drilling of brine production wells on its leased location and the construction of a bromine plant, a calcium chloride plant and the expansion of its existing West Memphis bromide facility. This multi-year project, expected to be completed in 2009, is expected to allow the Company to produce substantially all of the raw materials necessary to fully integrate its fluids business, allowing the Company to use bromine from Magnolia in the manufacture of CBFs for its oil and gas services business.
See “Note Q - Industry Segments and Geographic Information” in the Notes to Consolidated Financial Statements for financial information about this Division.
Well Abandonment & Decommissioning (WA&D) Division
The WA&D Division consists of two separate operating segments: the WA&D Services and Maritech segments. WA&D Services provides a broad array of services required for the abandonment of depleted oil and gas wells and the decommissioning of platforms, pipelines, and other associated equipment onshore and in the inland waters of Texas and Louisiana and offshore in the Gulf of Mexico. In addition, WA&D Services provides electric wireline, engineering, diving, workover and drilling services. The Maritech segment, through Maritech and its subsidiaries, is a producer of oil and gas from properties located in the offshore Gulf of Mexico and in the inland water region of Louisiana. Maritech acquires primarily mature producing properties to support and provide a baseload of business for WA&D Services. In addition, Maritech conducts development and exploitation operations on certain of its oil and gas properties, which are intended to increase the cash flows on such properties prior to their ultimate abandonment.
The Division has WA&D Services facilities located in Belle Chasse, Broussard, Harvey and Houma, Louisiana and in Bryan, Houston and Victoria, Texas. In providing its well abandonment and decommissioning services, the Company owns and operates onshore rigs, barge-mounted rigs, a platform rig, three heavy lift vessels and several offshore rigless packages. In addition, the Company rents certain equipment from third party contractors whenever necessary. The Division’s integrated package of services includes engineering services, emergency management response services (related to hurricane damage repair efforts), project management and other operations required to plug wells, salvage tubulars and decommission wellhead equipment, pipelines and platforms. Its electric wireline operations provide pressure transient testing, reservoir evaluation, well performance evaluation, cased hole and memory production logging, perforating, bridge plug and packer services and pipe recovery
services. The Division provides services to major oil and gas companies and independent operators, including Maritech.
In February 2006, the Company purchased a 650-ton heavy lift derrick barge from Offshore Specialty Fabricators, Inc. and leased an additional derrick barge, with options that extend into future years. These additions expand the Company’s decommissioning operations and give the Company additional capabilities and capacity to perform heavy lift projects. In September 2004, the Company purchased an 800-ton heavy lift derrick barge from Global Industries, Ltd. The Company is pursuing additional capacity by increasing its offshore well abandonment rigless packages and crews and acquiring the services, through acquisition or lease, of additional heavy lift equipment. In March 2006, the Company acquired the assets and operations of Epic Divers, Inc. and associated affiliate companies (Epic), a full service commercial diving business that includes seven marine vessels and two saturation dive units. In the past, the WA&D Division has utilized the services of various third party diving services, including Epic, to provide its offshore well abandonment and decommissioning services to its customers. In addition to adding a new service to provide to customers, the acquisition of Epic allows the WA&D Division to satisfy a substantial portion of its own diving needs, which it believes will improve efficiency and secure a supply for such diving services in the future.
Through Maritech and its subsidiaries, the Division acquires, manages and exploits mature producing oil and gas properties in the offshore and inland waters region of the Gulf of Mexico. These producing properties are purchased primarily to support the Division’s WA&D Services businesses. Federal regulations generally require lessees to plug and abandon wells and decommission the platforms, pipelines and other equipment located on the lease within one year after the lease terminates. Maritech provides oil and gas companies with alternative ways of managing their well abandonment obligations, while effectively baseloading well abandonment and decommissioning work for WA&D Services. This may include purchasing an ownership interest in the properties and operating them in exchange for assuming the proportionate share of the well abandonment and decommissioning obligations associated with such properties. In some transactions, cash may also be received or paid by Maritech. Maritech has a field office located in Lafayette, Louisiana.
Maritech’s operations have grown substantially during the past several years due to the acquisition of offshore Gulf of Mexico producing properties and subsequent development activities on these properties. Maritech’s most significant growth took place during 2005, when Maritech purchased oil and gas producing properties in three separate transactions in exchange for an aggregate of $23.1 million of cash and the assumption of associated decommissioning liabilities having a discounted fair value of approximately $94.6 million. During 2004, Maritech purchased oil and gas producing properties in four separate transactions, in exchange for the assumption of an aggregate of approximately $12.0 million in associated decommissioning liabilities. During 2003, Maritech purchased oil and gas producing properties in six separate transactions, in exchange for the assumption of an aggregate of approximately $11.5 million in associated decommissioning liabilities. In addition to the above acquisitions of producing oil and gas properties, Maritech also conducts oil and gas exploitation and development activities on the acquired properties and during 2005, incurred approximately $26.2 million of such expenditures. As a result of such acquisition and development activity, at December 31, 2005, Maritech had proved reserves of approximately 8.0 million barrels of oil and 42.3 billion cubic feet of natural gas, with undiscounted future net pretax cash flow of approximately $418.7 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 component of the Production Enhancement Division provides flowback pressure and volume testing of oil and gas wells, predominantly in the Texas, New Mexico, Louisiana, offshore Gulf of Mexico, Mexico, Venezuela and Middle East markets. These services involve sophisticated evaluation techniques needed for reservoir management and optimization of well workover programs. In March 2006, the Company significantly expanded its domestic production testing operations into the Fort Worth and Permian Basin regions through the acquisition of Beacon Resources, LLC.
The Division maintains one of the largest fleets of high pressure production testing equipment in the U.S., with operating locations in Edinburg, Laredo, Palestine, Benbrook, Odessa and Victoria, Texas. The Division also has operating locations in Hobbs, New Mexico; New Iberia, Louisiana; Reynosa, Villahermosa, Poza Rica and Veracruz, Mexico; Maturin, Cabimas, and Anaco, Venezuela; Macae, Brazil; and Dammam, Saudi Arabia. In June 2004, the Company expanded and enhanced its existing Venezuelan production testing operations with the acquisition of certain assets of a Venezuelan production testing company.
In July 2004, the Company completed the acquisition of Compressco, Inc. (Compressco), which designs, fabricates, sells, leases and services low pressure natural gas wellhead compressors. Compressco has been involved in the oil and gas services industry since 1990. Compressco’s patented design compressor equipment and experienced personnel assist oil and gas operators in increasing daily produced volumes and extending the productive lives of low volume or marginal gas and oil wells. Compressco’s fleet of GasJack® units totaled 1,990 as of December 31, 2005, and 1,809 units were in service, representing an increase of approximately 28% from the prior year.
The GasJack® compressor utilizes a 460 cubic inch V-8 engine, modified such that one bank of four cylinders uses natural gas from the well to power the other bank of four cylinders to provide compression. Engines and parts used in the fabrication of the compressor units are readily available from numerous sources. Compressco leases these compressor units to its customers, primarily on a month to month basis, or sells them. Compressco services its leased compressor fleet, as well as provides maintenance service on sold units, through a staff of mobile field technicians, who are based throughout Compressco’s market areas.
The process services group of the Production Enhancement Division applies a variety of technologies to separate oily residuals - mixtures of hydrocarbons, water and solids - into their components. The group provides its oil recovery and residuals separation and recycling services primarily to the petroleum refining market in the United States. This group utilizes various liquid/solid separation technologies, including a proprietary high temperature thermal desorption and recovery technology, hydrocyclones, centrifuges and filter presses. Oil is recycled for productive use, water is recycled or disposed of, and organic solids are recycled. Inorganic solids are treated to become inert, nonhazardous materials. The Division typically builds, owns and operates fixed systems that are located on its customers’ sites, providing these services under long-term contracts.
See “Note Q - Industry Segments and Geographic Information” in the Notes to Consolidated Financial Statements for financial information about this Division.
Sources of Raw Materials
The Fluids Division manufactures calcium chloride, sodium bromide, calcium bromide, zinc bromide and zinc calcium bromide for distribution to its customers. The Division also purchases calcium chloride, crude bromine, calcium bromide and sodium bromide from a number of domestic and foreign manufacturers, and it recycles calcium and zinc bromide CBFs repurchased from its oil and gas customers.
The Division manufactures calcium chloride from a reaction of hydrochloric acid and limestone, or from natural brine reserves. The Division also purchases calcium chloride from a number of chemical manufacturers. Some of the Division’s primary sources of hydrochloric acid are chemical co-product streams obtained from chemical manufacturers. The Company has written agreements with those chemical companies regarding the supply of hydrochloric acid or calcium chloride. In October 2005, one of the Division’s main raw material suppliers announced that it had permanently ceased production from its TDI plant in Lake Charles, Louisiana. This plant supplied feedstock to the Division’s Lake Charles calcium chloride manufacturing facility. The Company believes alternative sources of supply are available and is currently reviewing these alternatives to determine the most suitable replacement supply for its Lake Charles facility. The Company also produces calcium chloride through evaporation at its two plants in San Bernardino County, California from underground brine reserves. These brines are deemed adequate to supply the Company’s foreseeable need for calcium chloride in that market area. Substantial quantities of limestone are also consumed when converting hydrochloric acid into calcium chloride. The
Company uses a proprietary process that permits the use of less expensive limestone, while maintaining end-use product quality. The Company purchases limestone from several different sources. Currently, hydrochloric acid and limestone are generally available from multiple sources. In addition, the Company purchases liquid calcium chloride from a Delfzijl, Netherlands plant owned by a joint venture in which the Company has a 50% ownership interest.
To produce calcium bromide, zinc bromide and zinc calcium bromide at its West Memphis, Arkansas facility, the Company uses hydrobromic acid, bromine and various sources of zinc raw materials. The Company has several sources of bromine and co-product hydrobromic acid. The Company uses proprietary and patented processes that permit the use of cost-advantaged raw materials, while maintaining high product quality. There are multiple sources of zinc that the Company can use in the production of zinc bromide. The Company has an agreement with Dow Chemical Company to purchase crude bromine to feed its bromine derivatives plant in Ludington, Michigan. This plant produces bromine for use at the West Memphis facility as well as liquid calcium bromide and sodium bromide for resale.
The Company also owns a calcium bromide manufacturing plant near Magnolia, Arkansas that was constructed in 1985. This plant was acquired in 1988 and is not operable. The Company currently has approximately 33,000 gross acres of bromine-containing brine reserves under lease in the vicinity of this plant, which the Company intends to develop through the drilling of brine production wells and the construction of a bromine plant, a calcium chloride plant and the expansion of its West Memphis bromide facility. This multi-year development project, expected to be completed in 2009, is expected to allow the Company to produce substantially all of the raw materials necessary to fully integrate its fluids business, allowing the Company to use bromine from Magnolia in the manufacture of CBFs for its oil and gas services business. The Company believes it has sufficient brine reserves under lease to operate a world-scale bromine facility for 25 to 30 years.
The Company has a long-term supply agreement with a foreign producer of calcium bromide as well. This agreement affords the Company additional flexibility, beyond the development of the Magnolia, Arkansas plant, for the supply of its required bromine derivatives.
The Company’s Production Enhancement Division, through its Compressco operation, designs and fabricates natural gas wellhead compressors for lease or sale to its customers. All of its compressor models share many components which are obtained from a single source or a limited group of suppliers.
Market Overview and Competition
Fluids Division
The Fluids Division markets and sells CBFs, drilling and completion fluid systems, additives, and related products and services to major oil and gas exploration and production companies, onshore and offshore, in the United States and worldwide. Current areas of market presence include the U.S. onshore Gulf Coast, the U.S. Gulf of Mexico, the North Sea, Mexico, South America, the Far East, Europe, the Middle East and West Africa. The Division’s principal competitors in the sale of CBFs to the oil and gas industry are Baroid Corporation, a subsidiary of Halliburton Company; M-I L.L.C., a joint venture between Smith International, Inc. and Schlumberger Limited; and BJ Services Company. This market is highly competitive and competition is based primarily on service, availability and price. Although all competitors provide fluid handling, filtration and recycling services, the Company believes that its historical focus on providing these and other value-added services to its customers has enabled it to compete successfully. Major customers of the Fluids Division include Anadarko, Apache Corporation, Devon, EOG Resources, Halliburton Company, Kerr-McGee Corporation, LLOG Exploration, Millennium Offshore, Newfield Exploration Company, Shell Oil, CNR, and Spinnaker Exploration. The Division also sells its products through various distributors worldwide.
The Company's liquid and dry calcium chloride products have a wide range of uses outside the energy industry. The non-energy market segments to which the Company's products are marketed include agricultural, industrial, governmental, mining, janitorial, construction, pharmaceutical and food processing. These products promote snow and ice melt, dust control, cement curing, food processing, dehumidification, and road stabilization and are also used as a source of calcium nutrients to improve agricultural yields in many regions of the country. Most of these markets are highly competitive. The
acquisition of the Kemira calcium chloride assets in September 2004 allows the Company to strategically expand the marketing of its calcium chloride products to certain European markets through its TCE operations. The Company’s major competitors in the calcium chloride market include Dow Chemical Company and Industrial del Alkali in North America, and Brunner Mond, Solvay and NedMag in Europe. The Company also sells sodium bromide into the industrial water treatment markets as a biocide under the BioRid® trade name.
WA&D Division
The Division’s WA&D Services operation provides well abandonment and decommissioning services offshore in the U.S. Gulf of Mexico and in the inland waters and onshore in Texas and Louisiana. Long-term demand for the services of the WA&D Division is predominately driven by government regulations. In the market areas in which the Company currently competes, regulations generally require wells to be plugged, offshore platforms decommissioned, pipelines abandoned and the wellsite cleared within twelve months after an oil or gas lease expires. The maturity and decline of Gulf of Mexico producing fields has, over time, caused an increase in the number of wells to be plugged and abandoned and platforms and pipelines to be decommissioned. Projected demand for abandonment and decommissioning services has also been affected by recent hurricane activity in the Gulf of Mexico, particularly during 2005, which destroyed or caused significant damage to a large number of offshore platforms. The Division has reconfigured certain of its equipment to enable it to provide emergency management response services to customers whose offshore wells and production platforms were destroyed or heavily damaged by such storms. The threat of future storm activity, combined with an increase in related insurance costs, has also accelerated the abandonment and decommissioning plans of many offshore operators. Offshore platform decommissioning activities in the Gulf of Mexico have historically been highly seasonal, with the majority of such operations performed during the months of April through October when weather conditions are most favorable, although the Company anticipates that post-hurricane demand will result in more sustained activity throughout the year. Critical factors required to participate in the current market include among other factors: having an adequate fleet of the proper equipment to meet current market demand and conditions; having qualified, experienced personnel; having technical expertise to address varying downhole and surface conditions, particularly related to damaged wells and platforms; having the financial strength to ensure all abandonment and decommissioning obligations are satisfied; and having a comprehensive safety and environmental program. The Company believes its integrated service package satisfies these market requirements, allowing it to successfully compete, but is looking to further expand its capacity through the acquisition of additional equipment, personnel and service offerings, such as the February 2006 purchase of an additional heavy lift barge and the March 2006 acquisition of Epic.
The Division markets its services to major oil and gas companies, independent operators, and state governmental agencies. Major customers include Apache, Burlington Resources, ChevronTexaco, ConocoPhillips, ExxonMobil, Forest Oil, Magnum Hunter, Shell Oil, and W&T Offshore. These services are performed onshore primarily in Texas and Louisiana, in the Gulf Coast inland waterways and offshore in the U.S. Gulf of Mexico. The Company’s principal competitors in the offshore and inland waters markets are Global Industries, Ltd., Offshore Specialties, Inc., Helix Energy Solutions (formerly known as Cal-Dive International, Inc.), Horizon Offshore, and Superior Energy Services, Inc. This market is highly competitive and competition is based primarily on service, equipment availability, safety record and price. The Company’s ability to successfully bid its services can fluctuate from year to year.
The Division’s Maritech operation competes with a wide number of independent Gulf of Mexico operators for the acquisition of producing oil and gas properties. Maritech typically acquires oil and gas properties from major oil and gas companies as well as independent operators. Maritech’s ability to acquire producing oil and gas properties under acceptable terms is dependent on numerous factors, including oil and natural gas commodity prices, the age and condition of offshore production platforms, and the level of competition from other operators pursuing such properties. Recent hurricane activity in the Gulf of Mexico is expected to increase the number of producing properties that will become available for purchase, as existing operators assess the risk of damage from future storms and the associated escalating cost of insurance protection. In pursuing the acquisition of producing oil and gas properties, Maritech’s competitors include companies also seeking to provide baseload support for their affiliated well abandonment and decommissioning service operations, including Helix Energy Solutions and Superior Energy Services, Inc.
Production Enhancement Division
The Production Enhancement Division provides production testing services primarily to the natural gas segment of the oil and gas industry. In certain gas producing basins, water, sand and other abrasive materials will commonly accompany the initial production of natural gas, often under high pressures. The Division provides the equipment and qualified personnel to remove these impediments to production and to pressure test wells and wellhead equipment. The Division provides certain production testing and laboratory testing services for oil producing properties as well.
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. The Company believes its equipment maintenance program and operating procedures give it a competitive advantage in the marketplace. Competition in onshore markets is dominated by numerous small, privately owned operators. Schlumberger Limited, Power Well Services, and Expro International are major competitors in the U.S. offshore market and international markets. The Company’s customers include ConocoPhillips, Shell Oil, Dominion Exploration and Production, Inc., Anadarko, El Paso Corporation, Hunt Petroleum, National Energy Group, Newfield, Cabot, Valence Operating Co., W&T Offshore, EOG, Quicksilver, Antero, Chesapeake, PEMEX (the national oil company of Mexico), Petrobras (the national oil company of Brazil) and PDVSA (the national oil company of Venezuela).
The Division’s Compressco operations provide wellhead compression equipment and services primarily to operators of low volume or marginal gas and oil wells. Many mature gas fields in the United States are experiencing a loss of pressure and are requiring production enhancement at earlier stages to maintain production levels. Compressco’s core service areas are located primarily in the south central United States; however Compressco also serves a wide variety of geographic operating areas, including throughout the mid-continent, Rocky Mountain, Texas and Louisiana regions of the United States and western Canada. During 2005, Compressco expanded its operations into Mexico, and is continuing to further expand its operations geographically. Compressco’s competitors include Natural Gas Services, Hanover, Plains Machinery and other companies, many of which use a screw compressor with a separate engine driver or a reciprocating compressor with a separate engine driver. Compressco believes that its patented technology helps it to maintain a competitive position in the market which it serves. Compressco’s major customers include BP, Chesapeake, Devon, and Burlington Resources.
The Division also provides oily residuals processing services to refineries concentrated in Texas and Louisiana. Although U.S. refineries have alternative technologies and disposal systems available to them, the Company feels its competitive edge lies in its ability to apply its various liquid/solid separation technologies to provide an efficient processing alternative at competitive prices. The Division currently has major processing facilities at the following refineries: ExxonMobil - Baton Rouge, Louisiana; Hovensa - St. Croix, Virgin Islands; Valero and Motiva - Port Arthur, Texas; Lyondell-Citgo - Houston, Texas; ConocoPhillips - Borger, Texas; Valero - Memphis, Tennessee; and Citgo - Lake Charles, Louisiana. This Division’s major competitor in this market is Veolia Water North America.
Other Business Matters
Marketing and Distribution
The Fluids Division markets its CBF products and services domestically through its distribution facilities located principally in the Gulf Coast region of the United States. These facilities are in close proximity to both product supplies and customer concentrations. Since transportation costs can represent a large percentage of the total delivered cost of chemical products, particularly liquid chemicals, the Fluids Division believes that its strategic locations give it a competitive advantage over certain other suppliers of CBFs in the southern United States and California. In addition, the Fluids Division supplies CBFs to selected international markets including the U.K. and Norwegian sectors of the North Sea, Mexico, Venezuela, Brazil, West Africa, Europe, the Middle East, and the Far East.
The non-oilfield calcium chloride products are also marketed through the Division’s sales offices and sales agents in California, Missouri, Pennsylvania, Texas and Wyoming, as well as through a network of distributors located throughout the United States and northern and central Europe. In addition to shipping products directly from its production facilities in the United States and Europe, the Division has distribution facilities strategically located to provide efficient product distribution.
Backlog
The level of backlog is not indicative of the Company’s estimated future revenues, because a majority of the Company’s products and services either are not sold under long-term contracts or do not require long lead times to procure or deliver. The Company’s backlog consists of estimated future revenues associated with a portion of its well abandonment and decommissioning and process services businesses in the U.S. The estimated backlog for the well abandonment and decommissioning business consists primarily of the non-Maritech share of the well abandonment and decommissioning work associated with the oil and gas properties operated by Maritech. The Company’s estimated backlog on December 31, 2005 was $165.4 million, of which approximately $38.0 million is expected to be billed during 2006. This compares to an estimated backlog of $109.2 million at December 31, 2004.
Employees
As of December 31, 2005, the Company had 1,668 employees. None of the Company’s U.S. employees are presently covered by a collective bargaining agreement, other than the employees of the Company’s Lake Charles, Louisiana calcium chloride production facility who are represented by the Paper, Allied Industrial, Chemical and Energy Workers International Union. The Company’s international employees are generally members of the various labor unions and associations common to the countries in which the Company operates. The Company believes that its relations with its employees are good.
Patents, Proprietary Technology and Trademarks
As of December 31, 2005, the Company owned or licensed twenty-one issued U.S. patents and had four patent applications pending in the U.S. Internationally, the Company had six issued foreign patents and seventeen 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 2022. The Company has elected to maintain certain other internally developed technologies, know-how and inventions as trade secrets. While the Company believes that the protection of its patents and trade secrets is important to its competitive positions in its businesses, the Company does not believe any one patent or trade secret is essential to the success of the Company.
It is the practice of the Company to enter into confidentiality agreements with key employees, consultants and third parties to whom the Company discloses its confidential and proprietary information. There can be no assurance, however, that these measures will prevent the unauthorized disclosure or use of the Company’s trade secrets and expertise or that others may not independently develop similar trade secrets or expertise. Management of the Company believes, however, that it would require a substantial period of time, and substantial resources, to independently develop similar know-how or technology. As a policy, the Company uses all possible legal means to protect its patents, trade secrets and other proprietary information.
The Company sells various products and services under a variety of trademarks and service marks, some of which are registered in the U.S. or certain foreign countries.
Safety, Health and Environmental Affairs Regulations
The Company is 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 storm-water discharges, the disposal of certain hazardous and nonhazardous wastes, and wetlands preservation. Failure to comply with these occupational health and safety and environmental laws and regulations or associated permits may result in the assessment of fines and penalties and the imposition of investigatory and remedial obligations.
With respect to the Company’s domestic operations, various environmental protection laws and regulations have been enacted and amended in the United States during the past three decades in response to public concerns over the environment. The U.S. operations of the Company and its customers are subject to these various evolving environmental laws and corresponding regulations. In the United States, these laws and regulations are enforced by the U.S. Environmental Protection Agency, the Minerals Management Service of the U.S. Department of the Interior (MMS), the U.S. Coast Guard and various other federal, state and local environmental authorities. Similar laws and regulations, designed to protect the health and safety of the Company’s employees and visitors to its facilities, are enforced by the U.S. Occupational Safety and Health Administration and other state and local agencies and authorities. The Company must comply with the requirements of environmental laws and regulations applicable to its operations, including the Federal Water Pollution Control Act of 1972; the Resource Conservation and Recovery Act of 1976 (RCRA); the Clean Air Act of 1977; the Comprehensive Environmental Response, Compensation and Liability Act of 1980 (CERCLA); the Superfund Amendments and Reauthorization Act of 1986 (SARA); the Federal Insecticide, Fungicide, and Rodenticide Act of 1947 (FIFRA); the Hazardous Materials Transportation Act of 1975; and the Pollution Prevention Act of 1990.
The Company’s operations outside the U.S. 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 the Company operates. The Company believes its operations are in substantial compliance with existing international governmental controls and regulations and that compliance with these international controls and regulations has not had a material adverse affect on operations.
At the Company’s production plants, the Company holds various permits regulating air emissions, wastewater and storm-water discharges, the disposal of certain hazardous and nonhazardous wastes, and wetlands preservation.
The Company believes that its manufacturing plants and other facilities are in general compliance with all applicable environmental and health and safety laws and regulations. Since its inception, the Company has not had a history of any significant fines or claims in connection with environmental or health and safety matters. However, risks of substantial costs and liabilities are inherent in certain plant and service operations and in the development and handling of certain products and equipment produced or used at the Company's 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 the Company to more rigorous standards. The Company cannot predict the extent to which its operations may be affected by future regulatory and enforcement policies.
Item 1A.
Item 1A. Risk Factors.
Forward Looking Statements
Certain information included in this report, other materials filed or to be filed with the SEC, as well as information included in oral statements or other written statement made or to be made by us contain or incorporate by reference certain statements (other than statements of historical fact) that constitute forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. When used herein, the words “budget,” “budgeted,” “assumes,” “should,” “goal,” “anticipates,” “expects,” “believes,” “seeks,” “plans,” “intends,” “projects” or “targets” and similar expressions that convey the uncertainty of future events or outcomes are intended to identify forward-looking statements. Where any forward-looking statement includes a statement of the assumptions or bases underlying such forward-looking statement, we caution that while we believe these assumptions or bases to be reasonable and to be made in good faith, assumed facts or bases almost always vary from actual results and the difference between assumed facts or bases and actual results could be material, depending on the circumstances. It is important to note that actual results could differ materially from those projected by such forward-looking statements. Although we believe that the expectations reflected in such forward-looking statements are reasonable and such forward-looking statements are based upon the best data available at the date this report is filed with the SEC, we cannot assure you that such expectations will prove correct. Factors that could cause our results to differ
materially from the results discussed in such forward-looking statements include, but are not limited to, the following: activity levels for oil and gas drilling, completion, workover, production and abandonment activities; volatility of oil and gas prices; foreign currency risks; operating risks inherent in oil and gas production; weather; our ability to implement our business strategy; uncertainties about estimates of reserves; environmental risks; estimates of hurricane repair costs; and risks related to our foreign operations. All such forward-looking statements in this document are expressly qualified in their entirety by the cautionary statements in this paragraph, and we undertake no obligation to publicly update or revise any forward-looking statements.
Certain Business Risks
We have identified the following important risk factors, which could affect our actual results and cause actual results to differ materially from any such results that might be projected, forecasted, or estimated by us in this report.
Market Risks:
Our operations are materially dependent on levels of oil and gas well drilling, completion, workover, production and abandonment activities, both in the United States and internationally.
Activity levels for oil and gas drilling, completion, workover, production and abandonment are affected both by short-term and long-term trends in oil and gas prices and supply and demand balance, among other factors. Oil and gas prices and, therefore, the levels of well drilling, completion, workover and production activities, tend to fluctuate. Worldwide military, political and economic events, including initiatives by the Organization of Petroleum Exporting Countries and increasing demand in other large world economies, have contributed to, and are likely to continue to contribute to, price volatility. In addition, a prolonged slowdown of the U.S. and/or world economy may contribute to an eventual downward trend in the demand and, correspondingly, the price of oil and natural gas.
Other factors affecting our operating activity levels include the cost of exploring for and producing oil and gas, the discovery rate of new oil and gas reserves, and the remaining recoverable reserves in the basins in which we operate. A large concentration of our operating activities is located in the onshore and offshore region of the U.S. Gulf of Mexico. Our revenues and profitability are particularly dependent upon oil and gas industry activity and spending levels in the Gulf of Mexico region. Our operations may also be affected by technological advances, interest rates and cost of capital, tax policies and overall worldwide economic activity. Adverse changes in any of these other factors may depress the levels of well drilling, completion, workover and production activity and result in a corresponding decline in the demand for our products and services and, therefore, have a material adverse effect on our revenues and profitability.
Profitability of our operations is dependent on numerous factors beyond our control.
Our operating results in general, and gross margin in particular, are functions of market conditions and the product and service mix sold in any period. Other factors, such as unit volumes, heightened price competition, changes in sales and distribution channels, availability of skilled labor and contract services, shortages in raw materials due to untimely supplies or ability to obtain items at reasonable prices may also continue to affect the cost of sales and the fluctuation of gross margin in future periods.
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 us. To the extent competitors offer comparable products or services at lower prices, or higher quality and more cost-effective products or services, our business could be materially and adversely affected. Certain competitors may also be better positioned to acquire producing oil and gas properties or other businesses for which we compete.
We are dependent upon third party suppliers for specific products and equipment necessary to provide certain of our products and services.
We sell a variety of CBFs, including brominated CBFs, such as calcium bromide, zinc bromide, sodium bromide and other brominated products, some of which we manufacture and some of which are purchased from third parties. We also sell calcium chloride, as a CBF and in other forms and for other applications. Sales of calcium chloride and brominated products contribute significantly to our revenues. In our manufacture of calcium chloride, we use hydrochloric acid and other raw materials purchased from third parties. During 2005, one of our main suppliers announced that it had permanently ceased production of a raw material used in our manufacture of calcium chloride, and we are now reviewing alternative sources of supply. In our manufacture of brominated products, we use bromine, hydrobromic acid and other raw materials, including various forms of zinc, that are purchased from third parties. We acquire brominated products from a variety of third party suppliers. If we are unable to acquire the brominated products, bromine, hydrobromic or hydrochloric acid, zinc or any other raw material supplies at reasonable prices for a prolonged period, our business could be materially and adversely affected.
A portion of the well abandonment and decommissioning services performed by our WA&D Division require the use of vessels and services which must be provided by third parties. We lease equipment and obtain services from certain providers, but are subject to the availability of third party equipment and services in the Gulf of Mexico region, and could be adversely affected by a lack of availability or prohibitively high prices.
The fabrication of wellhead compressors by our Production Enhancement Division’s Compressco operation requires the purchase of many types of components that we obtain from a single source or a limited group of suppliers. Our reliance on these suppliers exposes us to the risk of price increases, inferior component quality or an inability to obtain an adequate supply of required components in a timely manner. Our Compressco operation’s profitability or future growth may be adversely affected due to our dependence on these key suppliers.
Our operating results and cash flows for certain of our subsidiaries are subject to foreign currency risk.
The operations of certain of our subsidiaries are exposed to fluctuations between the U.S. dollar and certain foreign currencies. In particular, we have exposure related to fluctuations in the dollar value of operating receivables and payables denominated in other currencies. In addition, in September 2004, related to the acquisition of the European calcium chloride assets from Kemira, we entered into long-term Euro-denominated borrowings, as we believe such borrowings provide a natural currency hedge for our Euro-based operating activities. Historically, exchange rates of foreign currencies have fluctuated significantly compared to the U.S. dollar, and this exchange rate volatility is expected to continue. Significant fluctuations in foreign currencies against the U.S. dollar could adversely affect our balance sheet and results of operations.
We are exposed to interest rate risk with regard to a portion of our outstanding indebtedness.
As of March 16, 2006, $161.1 million of our outstanding long-term debt consists of floating rate loans, which bear interest at an agreed upon percentage rate spread above LIBOR. Accordingly, our cash flows and results of operations are subject to interest rate risk exposure associated with the level of the variable rate debt balance outstanding. We currently are not a party to an interest rate swap contract or other derivative instrument designed to hedge our exposure to interest rate fluctuation risk.
Our oil and gas revenues and cash flows are subject to commodity price risk.
Our revenues from oil and gas production are increasing significantly; therefore, we have increased market risk exposure in the pricing applicable to our oil and gas production. Realized pricing is primarily driven by the prevailing worldwide price for crude oil and spot prices in the U.S. natural gas market. Historically, prices received for oil and gas production have been volatile and unpredictable, and this price volatility is expected to continue. Significant declines in prices for oil and natural gas could have a material effect on our results of operations and quantities of reserves recoverable on an economic
basis. Our risk management activities involve the use of derivative financial instruments, such as swap agreements, to hedge the impact of market price risk exposures for a portion of our oil and gas production. Because of this, we are exposed to the volatility of oil and gas prices for the portion of our oil and gas production that is not hedged.
Operating Risks:
Our operations continue to be affected by recent hurricanes and we could suffer additional losses in the future related to storm repair efforts.
During the third quarter of 2005, we incurred significant damage to certain of our assets as a result of hurricanes Katrina and Rita, which affected several of our operations in the U.S. Gulf of Mexico region. We suffered damages at certain of our fluids facilities, and to certain of our decommissioning assets, including one of our heavy lift barges. Our Maritech subsidiary suffered varying levels of damage to the majority of its offshore oil and gas producing platforms, and three of its platforms were completely destroyed. During the third and fourth quarters of 2005, we repaired some of the damaged assets; however, we are continuing to assess the extent of certain damages, particularly to the destroyed Maritech platforms, and this assessment process will likely extend throughout 2006 and beyond. While it is still difficult to accurately predict the total amount of damage, our best estimate is that total Company-wide repair costs, including the cost to repair fluids and well abandonment facilities and equipment, abandon damaged offshore wells and decommission the destroyed platforms, will range between $85 to $105 million. The majority of these costs are expected to be incurred in 2006 and 2007, with some costs likely also to be incurred in later years. We maintain insurance protection covering substantially all of the property damages incurred; and repair costs incurred up to the amount of deductibles were charged to earnings as they were incurred during 2005. However, the amount of covered costs is subject to certain maximum amounts, depending on the policy. If actual repair costs are significantly greater than our estimates, we may exceed these maximum coverage amounts. In that event, it is possible that a portion of future repair expenditures will have to be funded with our capital resources and result in charges to our earnings. In addition, for repair expenditures that are covered by insurance, the collection of insurance claims may be delayed, resulting in the temporary use of our working capital to fund such repairs.
Our insurance protection does not include business interruption coverage. Maritech has resumed daily production from a majority of its producing properties; however, much of its production is processed through neighboring platforms, pipelines, and onshore processing facilities of other operators and third parties. The full resumption of Maritech’s production levels, therefore, also depends on the damage assessments and repairs of certain of these third party assets, the timing of which is outside of Maritech’s control. There can be no assurance that all of these third party assets will be repaired, or that the timing of these repairs will not result in significant delays in production from several of Maritech’s properties.
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. These hazards include injuries to employees and third parties during the performance of our operations. Our operation of marine vessels, heavy equipment and offshore production platforms involves a particularly high level of risk. Whenever possible, we obtain agreements from customers and suppliers that limit our exposure. However, the occurrence of certain operating hazards, including storms, could result in substantial losses to us due to injury or loss of life, damage to or destruction of property and equipment, pollution or environmental damage, and suspension of operations. We have maintained a policy of insuring our risks of operational hazards that we believe is typical in the industry. Limits of insurance coverage we have purchased are consistent with the exposures we face and the nature of our products and services. Due to economic conditions in the insurance industry, from time to time, we have increased our self-insured retentions and deductibles for certain policies in order to minimize the increased costs of coverage. In certain areas of our business, we from time to time have elected to assume the risk of loss for specific assets. To the extent we suffer losses or claims that are not covered, or are only partially covered by insurance, our results of operations could be adversely affected.
Following the hurricanes in the Gulf of Mexico region during the third quarter of 2005, the cost of the insurance coverage we have typically purchased in the past has increased dramatically. We estimate that future coverage premiums will cost several times more than they have historically, particularly for offshore oil and gas production operations. Insurance coverage with similar deductible and maximum coverage amounts may not be available in the market, or its cost may not be justifiable. There can be no assurance that any insurance will be adequate to cover losses or liabilities associated with operational hazards. We cannot predict the continued availability of insurance, or its availability at premium levels that justify its purchase.
Our operations, particularly those conducted offshore, are seasonal and depend, in part, on weather conditions.
The WA&D Division has historically enjoyed its highest vessel utilization rates during the months from April to October, when weather conditions are more favorable for offshore activities, and has experienced its lowest utilization rates in the months from November to March. This Division, under certain turnkey contracts, may bear the risk of delays caused by adverse weather conditions. Storms can also cause 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 of the United States and in international regions.
We could incur losses on well abandonment and decommissioning projects.
Due to competitive market conditions, a portion of our well abandonment and decommissioning projects may be performed on a turnkey or a modified turnkey basis, where defined work is delivered for a fixed price and extra work, which is subject to customer approval, is charged separately. The revenue, cost and gross profit realized on a turnkey contract can vary from the estimated amount because of changes in offshore conditions, the scope of site clearance efforts required, labor and equipment availability, cost and productivity from the original estimates, and the performance level of other contractors. In addition, unanticipated events such as accidents, work delays, significant changes in the condition of platforms or wells, downhole problems, environmental and other technical issues could result in significant losses on certain turnkey projects. These variations and risks may result in us experiencing reduced profitability or losses on turnkey projects, or on well abandonment and decommissioning work for our Maritech subsidiary.
We face risks related to our growth strategy.
Our growth strategy includes both internal growth and growth through acquisitions. Internal growth may require significant capital expenditure investments, some of which may become unrecoverable or fail to generate an acceptable level of cash flows. Internal growth may also require financial resources (including the use of available cash or the incurrence of 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. Our operating results could be adversely affected if we are unable to successfully integrate such new companies into our operations or are unable to hire adequate personnel. We may not be able to consummate future acquisitions on favorable terms. Additionally, any such recent or future acquisition transactions by us may not achieve favorable financial results. Future acquisitions by us could also result in issuances of equity securities, or the rights associated with the equity securities, which could potentially dilute earnings per share. Future acquisitions could also result in the incurrence of additional debt or contingent liabilities and amortization expenses related to intangible assets. These factors could adversely affect our future operating results and financial position.
Our expansion into foreign countries exposes us to unfamiliar regulations and may expose us to new obstacles to growth.
We plan to grow both in the United States and in foreign countries. We have established operations in, among other countries, Finland, Sweden, Canada, Mexico, Venezuela, the United Kingdom, Norway, Nigeria, and Brazil and have entered into joint ventures in Saudi Arabia and The
Netherlands. 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;
• import and export license requirements;
• political, social or economic instability, particularly in Venezuela and Nigeria;
• trade restrictions;
• changes in tariffs and taxes;
• restrictions on repatriating foreign profits back to the U.S.; and
• our limited knowledge of these markets or our inability to protect our interests.
Foreign governments and agencies often establish permit and regulatory standards different from those in the U.S. If we cannot obtain foreign regulatory approvals, or if we cannot obtain them when we expect, our growth and profitability from international operations could be limited.
The acquisition of oil and gas properties and related well abandonment and decommissioning liabilities is based on estimated data that may be materially incorrect.
In conjunction with our purchase of oil and gas properties, we perform detailed due diligence review processes that we believe are consistent with industry practices. These acquired properties are generally in the later stages of their economic lives and require a thorough review of the expected cash flows acquired along with the associated abandonment obligations. The process of estimating natural gas and oil reserves is complex, requiring significant decisions and assumptions to be made in evaluating the available geological, geophysical, engineering and economic data for each reservoir. 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 have assumed our proportionate share of the related well abandonment and decommissioning liabilities after performing detailed estimating procedures, analysis and engineering studies. If actual costs of abandonment and decommissioning are materially greater than original estimates, such additional costs could have an adverse effect on earnings.
Our success depends upon the continued contributions of our personnel, many of whom would be difficult to replace.
Our success will depend on our ability to attract and retain skilled employees. Changes in personnel, therefore, could adversely affect operating results.
Financial Risks:
We have significant long-term debt outstanding.
As of December 31, 2005, we had approximately $157.3 million of long-term debt outstanding, and as of March 16, 2006, this amount has increased to approximately $249.3 million. Additional growth could result in increased debt levels in order 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 dollar limits on the total amount of capital expenditures, acquisitions and asset sales, as well as other restrictions and requirements. In addition, the agreements require us to maintain certain financial ratio and net worth 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 $5 million. If any such indebtedness is not paid or is accelerated and such event is not remedied in a timely manner, a default will occur under the long-term debt agreements. Any event of default, if not timely remedied, could result in a termination of all commitments of the lenders and an acceleration of any outstanding loans and credit obligations.
Certain of our businesses are exposed to significant credit risks.
Maritech purchases interests in certain end-of-life oil and gas properties in connection with the operations of our WA&D Division. As the owner and operator of these interests, Maritech is liable for the proper abandonment and decommissioning of the wells, platforms, pipelines and the site clearance related to these properties. 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. We and Maritech attempt to minimize this risk by analyzing the creditworthiness of the previous owner(s), and others who may be legally obligated to pay in the event the previous owner(s) are unable to do so, and obtaining guarantees, bonds, letters of credit or other forms of security when they are deemed necessary. In addition, if Maritech acquires less than 100% of the working interest in a property, its co-owners are responsible for the payment of their portions of the associated operating expenses and abandonment liabilities. However, if one or more co-owners do not pay their portions, Maritech and any other nondefaulting co-owners may be liable for the defaulted amount as well. If any required payment is not made by a previous owner or a co-owner and any security is not sufficient to cover the required payment, we could suffer material losses.
Maritech’s estimates of its oil and gas reserves and related future cash flows may be significantly incorrect.
Maritech’s estimates of oil and gas reserve information are prepared in accordance with Rule 4-10 of Regulation S-X, and reflect only estimates of the accumulation of oil and gas and the economic recoverability of those volumes. Maritech’s future production, revenues and expenditures with respect to such oil and gas reserves will likely be different from estimates, and any material differences may negatively affect our business, financial condition and results of operations. As a result, Maritech has experienced and may continue to experience significant revisions to its reserve estimates.
Oil and gas reservoir analysis is a subjective process which involves estimating underground accumulations of oil and gas that cannot be measured in an exact manner. Estimates of economically recoverable oil and gas reserves and of future net cash flows associated with such reserves necessarily depend upon a number of variable factors and assumptions. Because all reserve estimates are to some degree subjective, each of the following items may prove to differ materially from that assumed in estimating reserves:
• the quantities of oil and gas that are ultimately recovered;
• the production and operating costs incurred;
• the amount and timing of future development and abandonment expenditures; and
• future oil and gas sales prices.
Furthermore, different reserve engineers may make different estimates of reserves and cash flow based on the same available data.
The estimated discounted future net cash flows described in this Annual Report for the year ended December 31, 2005 should not be considered as the current market value of the estimated oil and gas proved reserves attributable to Maritech’s properties. Such estimates are based on prices and costs as of the date of the estimate, in accordance with SEC requirements, while future prices and costs may be materially higher or lower. The SEC requires that we report our oil and natural gas reserves using the price as of the last day of the year. Using lower values in forecasting reserves will result in a shorter life being given to producing oil and natural gas properties because such properties, as their production levels are estimated to decline, will reach an uneconomic limit, with lower prices, at an earlier date. There can be no assurance that a decrease in oil and gas prices or other differences in Maritech’s estimates of its reserves will not adversely affect our financial position or results of operations.
Our accounting for oil and gas operations may result in volatile earnings.
We account for our oil and gas operations using the successful efforts method. Costs incurred to drill and equip development wells, including unsuccessful development wells, are capitalized. Costs related to unsuccessful exploratory wells are expensed as incurred. All capitalized costs are accumulated and recorded separately for each field, and are depleted on a unit-of-production basis, based on the estimated remaining equivalent proved oil and gas reserves of each field. 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.
Legal/Regulatory Risks:
Our operations are subject to extensive and evolving U.S. and foreign federal, state and local laws and regulatory requirements that increase our operating costs and expose us to potential fines, penalties and litigation.
Laws and regulations strictly govern our operations relating to: corporate governance, environmental affairs, health and safety, waste management, and the manufacture, storage, handling, transportation, use and sale of chemical products. Our operation and decommissioning of offshore properties are also subject to and affected by various types of government regulation, including numerous federal and state environmental protection laws and regulations. These laws and regulations are becoming increasingly complex and stringent, and compliance is becoming increasingly expensive. Governmental authorities have the power to enforce compliance with these regulations, and violators are subject to civil and criminal penalties, including civil fines, injunctions or both. Third parties may also have the right to pursue legal actions to enforce compliance. It is possible that increasingly strict environmental laws, regulations and enforcement policies could result in substantial costs and liabilities to us and could subject our handling, manufacture, use, reuse, or disposal of substances or pollutants to increased scrutiny.
Our business exposes us to risks such as the potential for harmful substances escaping into the environment and causing damages or injuries, which could be substantial. Although we maintain general liability and pollution liability insurance, these policies are subject to coverage limits. We maintain limited environmental liability insurance covering named locations and environmental risks associated with contract services for oil and gas operations, refinery waste treatment operations and for oil and gas producing properties. The extent of this coverage is consistent with our other insurance programs. We could be materially and adversely affected by an enforcement proceeding or a claim that was not covered or was only partially covered by insurance.
In addition to increasing our risk of environmental liability, the rigorous enforcement of environmental laws and regulations has accelerated the growth of some of the markets we serve. Decreased regulation and enforcement in the future could materially and adversely affect the demand for the types of systems offered by our process services and the services offered by our well abandonment and decommissioning operations and, therefore, materially and adversely affect our business.
Our proprietary rights may be violated or compromised, which could damage our operations.
We own numerous patents, patent applications and unpatented trade secret technologies in the U.S. and certain foreign countries. There can be no assurance that the steps we have taken to protect our proprietary rights will be adequate to deter misappropriation of these rights. In addition, independent third parties may develop competitive or superior technologies.
Item 1B.
Item 1B. Unresolved Staff Comments.
None.
Item 2.
Item 2. Properties.
The Company’s properties consist primarily of chemical plants, processing plants, distribution facilities, barge rigs, well abandonment and decommissioning equipment, oil and gas properties, flowback testing equipment and compression equipment. The following information describes facilities leased or owned by the Company as of December 31, 2005. The Company believes its facilities are adequate for its present needs.
Fluids Division. Fluids Division facilities include eight chemical production plants located in the states of Arkansas, California, Louisiana, Michigan, and West Virginia, and the country of Finland. The total manufacturing area of these plants, excluding the two California locations, is approximately 496,000 square feet. The two California locations contain 29 square miles of acreage containing solar evaporation ponds and leased mineral acreage. In addition, the Fluids Division owns and leases brine mineral reserves in Arkansas, which may be used to produce bromine, calcium chloride and sodium chloride.
In addition to the above production plant facilities, the Fluids Division owns or leases twenty-five service center facilities, twelve domestically and thirteen internationally. The Fluids Division also leases eight offices and fourteen terminal locations throughout the United States.
WA&D Division. The WA&D Division conducts its operations through six offices and service facility locations (five of which are leased) located in Texas and Louisiana. See below for a discussion of the WA&D Division’s oil and gas property assets.
Production Enhancement Division. Production Enhancement Division facilities include twelve production testing distribution facilities (eleven of which are leased) in Texas and Louisiana and in Venezuela, Brazil and Mexico. The Division’s eight process services facilities are located in Texas, Louisiana, Tennessee and the Virgin Islands. Compressco’s facilities include a fabrication and headquarters facility in Oklahoma, a leased fabrication facility located in Alberta, Canada, three leased service facilities located in New Mexico and Texas and five sales offices located in Oklahoma, Texas, Colorado, New Mexico and Louisiana.
Corporate. The Company’s headquarters are located in The Woodlands, Texas, where it leases approximately 95,000 square feet of office space. The Company also owns 2.635 acres of land adjacent to its headquarters location. In addition, the Company owns a 20,000 square foot technical facility to service its Fluids Division and process services operations.
Oil and Gas Properties.
The following tables show, for the periods indicated, reserves and operating information related to Maritech’s oil and gas interests in the Gulf of Mexico region. Maritech’s oil and gas properties are a separate segment included within the Company’s WA&D Division. See also “Note R - Supplemental Oil and Gas Disclosures” in the Notes to Consolidated Financial Statements for additional information.
Oil and Gas Reserves. The following table sets forth information with respect to the Company’s estimated proved reserves as of December 31, 2005. The standardized measure of discounted future net cash flows attributable to oil and gas reserves was prepared by the Company using constant prices as of the calculation date, net of future income taxes, discounted at 10% per annum. Reserve information is prepared in accordance with guidelines established by the SEC. A substantial majority of Maritech’s reserves were estimated by Ryder Scott Company, L.P., independent petroleum engineers. All of Maritech’s reserves are located in U.S. state and federal offshore waters in the Gulf of Mexico region and onshore Louisiana.
December 31, 2005
Estimated proved reserves:
Natural gas (Mcf)
42,274,000
Oil (Bbls)
7,987,000
Standardized measure of discounted future net cash flows
$233,988,000
Maritech is not required to file, and has not filed on a recurring basis, estimates of its total proved net oil and gas reserves with any U.S. or non-U.S. governmental regulatory authority or agency other than the Department of Energy (the DOE) and the SEC. The estimates furnished to the DOE have been consistent with those furnished to the SEC. They are not necessarily directly comparable, however, due to special DOE reporting requirements. In no instance have the estimates for the DOE differed by more than five percent from the corresponding estimates reflected in total reserves reported to the SEC.
Production Information. The table below sets forth production, average sales price, and average production cost per unit of oil and gas produced during 2005, 2004 and 2003:
production costs per equivalent Mcf were increased due to the impact of hurricanes, which resulted in significant properties being shut-in during the last four months of 2005.
Acreage and Wells. At December 31, 2005, Maritech owned interests in the following oil and gas wells and acreage:
Drilling Activity. Maritech participated in the drilling of 13 gross productive development wells (4.4 net wells) during 2005. Maritech participated in the drilling of 4 gross productive development wells (1.1 net wells) during 2004 and no wells during 2003. As of December 31, 2005 there were no wells in the process of being drilled.
Item 3.
Item 3. Legal Proceedings.
The Company is a named defendant in numerous lawsuits and a respondent in certain other governmental proceedings arising in the ordinary course of business. While the outcome of such lawsuits and other proceedings cannot be predicted with certainty, management does not expect these matters to have a material adverse impact on the Company.
Item 4.
Item 4. Submission of Matters to a Vote of Security Holders.
No matters were submitted to a vote of security holders of the Company, through solicitation of proxies or otherwise, during the fourth quarter of the year ended December 31, 2005.
PART II
Item 5.
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Repurchases of Equity Securities.
Price Range of Common Stock
The Company’s common stock is traded on the New York Stock Exchange under the symbol “TTI.” As of March 3, 2006, there were approximately 6,765 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, 2005, as reported by the New York Stock Exchange and as adjusted for a 3-for-2 stock split, which was declared and effected in August 2005.
High
Low
First Quarter
$21.71
$16.33
Second Quarter
21.41
17.00
Third Quarter
31.28
21.02
Fourth Quarter
32.85
24.58
First Quarter
$18.74
$15.37
Second Quarter
18.30
13.83
Third Quarter
21.00
15.81
Fourth Quarter
21.71
18.22
Dividend Policy
The Company has never paid cash dividends on its common stock. The Company currently intends to retain earnings to finance the growth and development of its business. Any payment of cash dividends in the future will depend upon the financial condition, capital requirements and earnings of the Company as well as other factors the Board of Directors may deem relevant. The Company declared a dividend of one Preferred Stock Purchase Right per share of common stock to holders of record at the close of business on November 6, 1998. See “Note T - Stockholders’ Rights Plan” in the Notes to Consolidated Financial Statements attached hereto for a description of such Rights. In August 2005, the Company declared a 3-for-2 stock split, which was effected in the form of a stock dividend to all stockholders of record as of August 19, 2005. In August 2003, the Company declared a 3-for-2 stock split, which was effected in the form of a stock dividend to all stockholders of record as of August 15, 2003. See “Note K - Capital Stock” in the Notes to Consolidated Financial Statements attached hereto for a description of these stock splits. See “Management’s Discussion and Analysis of Financial Condition and Results of Operation - Liquidity and Capital Resources” for a discussion of potential restrictions on the Company’s ability to pay dividends.
Purchases of Equity Securities by the Issuer and Affiliated Purchasers
In January 2004, the Board of Directors of the Company authorized the repurchase of up to $20 million of its common stock. Purchases will be made from time to time in open market transactions at prevailing market prices. The repurchase program may continue until the authorized limit is reached, at which time the Board of Directors may review the option of increasing the authorized limit. During 2004, the Company repurchased 210,000 shares of its common stock pursuant to the repurchase program at a cost of approximately $3.3 million. During 2005, the Company repurchased 130,950 shares of its common stock pursuant to the repurchase program at a cost of approximately $2.4 million. There were no repurchases made during any month of the fourth quarter of 2005.
Item 6.
Item 6. Selected Financial Data.
The following tables set forth selected consolidated financial data of the Company for the years ended December 31, 2005, 2004, 2003, 2002 and 2001. The selected consolidated financial data does not purport to be complete and should be read in conjunction with, and is qualified by, the more detailed information, including the Consolidated Financial Statements and related Notes and “Management’s Discussion and Analysis of Financial Condition and Results of Operation” appearing elsewhere in this report. Please read “Item 1A. Risk Factors” beginning on page 10 for a discussion of the material uncertainties which might cause the selected consolidated financial data not to be indicative of the Company’s future financial condition or results of operations. During 2005, the Company acquired certain producing oil and gas properties as part of its Maritech operations. During 2004, the Company completed the acquisitions of Compressco, Inc., the Kemira calcium chloride assets and an 800-ton heavy lift barge. These acquisitions significantly impact the comparison of the Company’s financial statements for 2005 to earlier years. In addition, during 2003 the Company made the decision to discontinue the operations of Damp Rid, Inc. and its Norwegian process services operations and during 2000, commenced its exit from the micronutrients business. Accordingly, the Company has reflected the operations of Damp Rid, Inc., the Company’s Norwegian process services operations and TETRA Micronutrients, Inc. as discontinued operations.
(1) Revenues for these periods retroactively reflect the reclassification of certain product shipping and handling costs as costs of goods sold, which had previously been deducted from product sales revenues. The reclassified amounts were $7,686 for 2003; $7,736 for 2002; and $8,836 for 2001.
(2) Gross profit for these periods retroactively reflects the reclassification of certain depreciation, amortization and accretion costs as cost of revenues, which had previously been included in general and administrative expense. The reclassified amounts were $3,619 for 2004; $3,019 for 2003; $1,366 for 2002; and $1,552 for 2001.
(3) Net income per share and average shares outstanding information reflects the retroactive impact of 3-for-2 stock splits, which were effected in the form of a stock dividend to holders of record as of August 19, 2005 and August 15, 2003.
(4) Excluding goodwill amortization, net income per diluted share, before discontinued operations and cumulative effect of accounting change, was $0.72 for 2001.
Item 7.
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operation.
The following discussion is intended to analyze major elements of the Company’s 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.
Statements in the following discussion may include forward-looking statements. These forward-looking statements involve risks and uncertainties. See “Item 1A. Risk Factors,” for additional discussion of these factors and risks.
Business Overview
The Company experienced significant growth in revenues and profitability during 2005. Much of this growth came from three significant transactions consummated during the third quarter of 2004: the acquisition of Compressco, Inc. (Compressco), the purchase of the Kemira calcium chloride assets which make up the Company’s TCE operations, and the purchase of the Arapaho derrick barge. In addition, increased demand for many of the Company’s products and services resulted in increased pricing and sales volumes, and higher utilization of equipment. Consolidated revenues increased 50.4% during 2005 compared to 2004 and consolidated gross profit as a percentage of revenues increased from 22.0% during 2004 to 24.5% during 2005. Demand for the Company’s products and services depends primarily on activity in the oil and gas exploration and production industry, which is significantly affected by the level of capital expenditures for the exploration and production of oil and gas reserves and for the plugging and decommissioning of abandoned oil and gas properties. Industry expenditures for drilling, as indicated by onshore rig count statistics, have risen during the past four years and reflect the industry’s response to higher crude oil and natural gas pricing during this period. The Company expects that such increased industry spending levels will continue during 2006. Over the longer term, the Company believes that there will continue to be growth opportunities for the Company’s products and services in both the U.S. and international markets, supported primarily by:
• increases in technologically-driven deepwater gas well completions in the Gulf of Mexico;
• continued reservoir depletion in the U.S.;
• advancing age of offshore platforms in the Gulf of Mexico;
• increasing development of oil and gas reserves abroad; and
• storm damage to offshore production facilities in the Gulf of Mexico.
The Company continues to grow its businesses to capitalize on the current market environment for the industry. During 2005, the Company significantly expanded the operations of its Maritech Resources, Inc. (Maritech) subsidiary with three acquisitions of producing properties. In February 2006, the Company acquired an additional heavy lift barge, the DB-1, and leased the Anna IV derrick barge under extendable terms, in order to increase the Company’s capacity to serve the growing Gulf of Mexico decommissioning market. In March 2006, the Company acquired the assets and operations of Epic Divers, Inc. and associated affiliate companies (Epic), a full service diving operation, to diversify the service offerings and enhance the efficiency of the WA&D Division. Also, in March 2006, the Company consummated the acquisition of Beacon Resources, LLC (Beacon), a domestic production testing operation. The Company has also planned significant capital expenditure activity during 2006, including the initial phases of a project to develop its Magnolia, Arkansas brine reserves, the construction of a bromine plant and a calcium chloride plant, and the expansion of its existing West Memphis, Arkansas bromine facility.
During the third quarter of 2005, hurricanes Katrina and Rita affected several of the Company’s operations in the U.S. Gulf of Mexico region and damaged certain of its fluids facilities, and certain of its decommissioning assets, including one of its heavy lift barges. Maritech suffered varying levels of damage to a majority of its offshore oil and gas producing platforms, and three of its platforms were completely destroyed. The storms also caused the majority of Maritech properties to be shut-in for several weeks, postponing the initial impact on earnings from the third quarter acquisitions. Production from certain Maritech properties continues to be suspended as a result of the hurricanes. During the third and fourth quarters of 2005, the Company performed repair efforts on certain of the damaged assets;
however, the Company is continuing to assess the extent of damages, particularly to the destroyed Maritech platforms. While it is still difficult to accurately predict the total amount of damage, the Company’s best estimate is that total Company-wide repair costs, including the cost to repair fluids and well abandonment facilities and equipment, abandon damaged offshore wells and decommission or repair damaged platforms, will range between $85 to $105 million. The majority of these costs are expected to be incurred in 2006 and 2007, with some costs likely to also be incurred in later years. As the Company gathers additional information, this range of total repair costs could change in the future. The Company’s insurance protection is expected to cover substantially all of the damages incurred; and repair costs incurred up to the amount of deductibles were charged to earnings during 2005. As of December 31, 2005, repair expenditures incurred in excess of such deductibles and covered by insurance protection totaled approximately $12.8 million and are included in accounts receivable. The Company anticipates that its future insurance coverage premiums will significantly increase as a result of the recent storms.
The Company’s Fluids Division is a world leader in oil and gas completion fluids and generates revenues and cash flows by manufacturing and selling completion fluids and providing filtration and associated products and engineering services to domestic and international exploration and production companies worldwide. The demand for the Company’s products and services is particularly affected by drilling activity in the Gulf of Mexico, which has remained flat or decreased during the past several years due to the maturity of a majority of Gulf of Mexico producing fields. The average Gulf of Mexico rig count decreased in 2005 to 89 rigs, compared to the prior year average of 94. Somewhat offsetting this impact is the current industry trend for drilling deeper offshore gas prospects that generally require higher volumes and precisely-engineered brine solutions. The Fluids Division also markets certain liquid and dry calcium chloride products manufactured at its production facilities to a variety of markets outside the energy industry. With the addition of the TCE operations acquired during 2004, the Company has expanded its calcium chloride manufacturing and distribution operations into European markets, and further reduced the Division’s dependence on the Gulf of Mexico. Fluids Division revenues increased 47.1% during 2005, compared to the prior year primarily due to the impact from the acquisition of the TCE operations, but also due to increased domestic sales volumes and prices. Further growth by the Fluids Division is predicated on the availability of selected raw materials at acceptable cost levels, and the ability of the Company to pass along the increased cost for such materials to its customers through increased product prices.
The WA&D Division consists of two operating segments: the WA&D Services and Maritech segments. WA&D Services generates revenues and cash flows by performing well plug and abandonment, pipeline and platform decommissioning and removal and site clearance services for oil and gas companies. In addition, the segment provides electric wireline, workover, engineering and drilling services. In March 2006, the segment added the operations of a full service diving operation with the acquisition of Epic. The segment’s services are marketed primarily in the Gulf Coast region of the U.S. including onshore, offshore and in inland waters. WA&D Services revenues increased by 38.4% during 2005, despite interruptions due to the hurricanes, primarily due to increased platform decommissioning services performed during the year. Long-term Gulf of Mexico platform decommissioning and well abandonment activity levels are driven primarily by MMS regulations and the age of producing fields and production platforms and structures. In the shorter term, activity levels are driven by oil and gas commodity prices, sales activity of mature oil and gas producing properties and overall oil and gas company activity levels. Given the significant damage incurred by many offshore operators as a result of hurricanes Katrina and Rita during 2005, a new driver for the WA&D Services businesses is the repair work required by the offshore industry following these storms, and the escalation of existing work due to the risks posed by future storms, and the associated increased insurance costs associated with offshore platforms and properties. The March 2006 acquisition of Epic, as well as the February 2006 purchase of an additional heavy lift derrick barge, increases the WA&D Services segment’s capacity to participate in the current post-hurricane market.
The Maritech segment acquires, manages and exploits producing oil and gas properties and generates revenues and cash flows from the sale of the associated oil and natural gas production volumes. Through Maritech, the WA&D Division provides oil and gas companies with alternative ways of managing their well abandonment obligations, while effectively baseloading well abandonment and decommissioning work for the WA&D Services segment of the Division. During 2005, Maritech and its subsidiaries consummated three significant acquisitions of producing oil and gas properties, more than doubling its oil and gas reserve volumes at December 31, 2005 compared to the prior year. These
acquisitions also significantly increased the backlog of WA&D Services to be performed on Maritech operated properties compared to the prior year. Maritech’s revenues during 2005 increased 55.1% compared to 2004, primarily due to higher commodity prices. The full revenue and cash flow impact from the 2005 oil and gas property acquisitions was largely postponed, however, due to the impact of hurricanes during the third quarter of 2005, which caused several of Maritech’s properties to be shut-in for an extended period awaiting repairs of associated platforms, pipelines and other facilities. The Company anticipates that revenues and cash flows from the Maritech segment will increase significantly during 2006, reflecting substantially increased oil and gas production volumes and the continuing high oil and gas commodity prices which are expected during the year.
The Production Enhancement Division generates revenues and cash flows by performing flowback pressure and volume testing and providing low pressure wellhead compression equipment and other services for oil and gas producers. The primary testing markets served are Texas, Louisiana, offshore Gulf of Mexico, Mexico, Brazil and Venezuela. Following the March 2006 acquisition of Beacon, the Division has expanded its production testing market to include western Texas and eastern New Mexico. Compressco, the Division’s wellhead compression operation, markets its equipment and services principally in the mid-continent, mid-western, Rocky Mountain, Texas and Louisiana regions of the United States as well as in western Canada and Mexico. The Production Enhancement Division also provides the technology and services required for separation and recycling of oily residuals generated from petroleum refining to oil refineries in the United States. The Division’s operations are generally driven by the demand for natural gas and oil, and the resulting increases in industry drilling and completion activities, in the domestic and international markets which the Division serves. Production Enhancement Division revenues increased 59.2% primarily due to the full year inclusion of Compressco, which was acquired in July 2004. The Company anticipates increased revenues and cash flows from the Division during 2006, reflecting the acquisition of Beacon as well as the increased industry activity levels by customers in its markets.
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 our estimates and judgments related to potential impairments of long-lived assets (including goodwill), the collectibility of accounts receivable, and the current cost of future abandonment and decommissioning obligations. “Note B - Summary of Significant Accounting Policies” to the Consolidated Financial Statements contains the accounting policies governing each of these matters. Our estimates are based on historical experience and on future expectations which we believe are reasonable. The combination of these factors forms the basis for judgments made about the carrying values of assets and liabilities that are not readily apparent from other sources. These judgments and estimates may change as new events occur, as new information is acquired, and with changes in our operating environment. 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, including goodwill, is conducted periodically whenever indicators of impairment are present. Goodwill is assessed for potential impairment at least annually. 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. The oil and gas industry is cyclical, and our estimates of the period over which future cash flows will be generated, as well as the predictability of these cash flows, can have significant impact on the carrying value of these assets and, in periods of prolonged down cycles, may result in impairment charges.
Oil and Gas Properties - Maritech accounts for its interests in oil and gas properties using the successful efforts method, whereby costs incurred to drill and equip development wells, including unsuccessful development wells, are capitalized and costs related to unsuccessful exploratory wells are expensed as incurred. All capitalized costs are accumulated and recorded separately for each field, and are depleted on a unit-of-production basis, based on the estimated remaining proved oil and gas reserves of each field. The process of estimating oil and gas reserves is complex, requiring significant decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data
for each reservoir. As a result, these estimates are inherently imprecise. Actual future production, cash flows, development expenditures, operating and abandonment expenses and quantities of recoverable oil and gas reserves may vary substantially from those initially estimated by Maritech. Any significant variance in these assumptions could materially affect the estimated quantity and value of proved reserves. Maritech’s oil and gas properties are assessed for impairment in value whenever indicators become evident, with any impairment charged to expense. Maritech purchases oil and gas properties and assumes the associated well abandonment and decommissioning liabilities. The acquired oil and gas producing properties are recorded at a cost equal to the estimated fair value of the decommissioning liabilities assumed, adjusted by the amount of any cash or other consideration received or paid. 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.
Decommissioning Liabilities - We estimate the third party market values (including an estimated profit) to plug and abandon the wells, decommission the pipelines and platforms and clear the sites, and use these estimates to record Maritech’s well abandonment and decommissioning liabilities, net of amounts allocable to joint interest owners and any contractual amount to be paid by the previous owners of the property (referred to as decommissioning liabilities). In estimating the decommissioning liabilities, we perform detailed estimating procedures, analysis and engineering studies. Whenever practical, Maritech utilizes the services of its affiliated companies to perform well abandonment and decommissioning work. When these services are performed by an affiliated company, all recorded intercompany revenues are eliminated in the consolidated financial statements. Any profit earned by us in performing such abandonment and decommissioning operations on Maritech’s properties is recorded as the work is performed. The recorded decommissioning liability associated with a specific property is fully extinguished when the property is completely abandoned. Once a Maritech well abandonment and decommissioning project is performed, any remaining decommissioning liability in excess of the actual costs of the work performed is recorded as additional profit on the project and included in earnings in the period in which the work is performed. Conversely, actual costs in excess of the decommissioning liability are charged against earnings in the period in which the work is performed. We review the adequacy of our decommissioning liability whenever indicators suggest that either the amount or timing of the estimated cash flows underlying the liability have changed materially. The timing and amounts of these cash flows are subject to changes in the energy industry environment and may result in additional liabilities recorded, which, in turn, would increase the carrying values of the related properties.
Revenue Recognition - We generate revenue on certain well abandonment and decommissioning projects from billings under contracts, which are typically of short duration, that provide for either lump-sum turnkey charges or specific time, material and equipment charges which are billed in accordance with the terms of such contracts. With regard to turnkey contracts, revenue is recognized using the percentage-of-completion method based on the ratio of costs incurred to total estimated costs at completion. Total project revenue and cost estimates for turnkey contracts are reviewed periodically as work progresses, and adjustments are reflected in the period in which such estimates are revised. Provisions for estimated losses on such contracts are made in the period such losses are determined.
Bad Debt Reserves - Reserves for bad debts are calculated on a specific identification basis, whereby we estimate whether or not specific accounts receivable will be collected. A significant portion of our revenues come from oil and gas exploration and production companies. If, due to adverse circumstances, certain customers are unable to repay some or all of the amounts owed us, an additional bad debt allowance may be required.
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 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. Changes in state, federal and foreign tax laws, as well as changes in our financial condition, could affect these estimates.
Acquisition Purchase Price Allocations - The accounting for acquisitions of businesses using the purchase method 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 assets and liabilities acquired.
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.
Compared to 2004
Consolidated Comparisons
Revenues and Gross Profit - Total consolidated revenues for the year ended December 31, 2005 were $531.0 million, compared to $353.2 million during the prior year, an increase of 50.4%. Consolidated gross profit during 2005 also increased significantly from the prior year, from $77.8 million during 2004 to $130.0 million during the current year, an increase of 67.2%. Consolidated gross profit as a percent of revenues was 24.5% during 2005, compared to 22.0% during the prior year.
General and Administrative Expenses - Consolidated general and administrative expenses were $70.4 million during 2005, an increase of $20.2 million or 40.3%, compared to 2004. The increase was primarily due to the overall growth of the Company, with a large portion of the increase attributable to the addition of the Compressco and TCE operations, which were acquired during the third quarter of 2004. The increased general and administrative expenses included approximately $13.8 million of increased salaries, incentives, benefits and other associated employee expenses, approximately $3.3 million of higher professional service expenses, approximately $1.4 million of increased office expenses, approximately $0.9 million of increased bad debt expense, and approximately $0.8 million of other
general expense increases. Due to the significant increase in the Company’s operating revenues, however, general and administrative expenses as a percent of revenue decreased to 13.3% during 2005, compared to 14.2% during the prior year.
Other Income and Expense - Other income and expense was $3.6 million of income during 2005, compared to $0.5 million of income during the prior year period, an increase of $3.1 million. The increase was primarily due to approximately $2.3 million of increased net gains on sales of assets, approximately $0.5 million of increased equity in the earnings of unconsolidated joint ventures and approximately $0.2 million of increased foreign currency gains.
Interest Expense and Income Taxes - Net interest expense was $6.0 million during 2005, primarily due to significant borrowings of long-term debt used to fund a portion of the Company’s acquisitions during the third quarter of 2004. During the first half of 2004, the Company had no long-term debt balances outstanding other than minimal amounts related to capitalized leases. In addition, the Company increased its long-term debt borrowings by approximately $13.5 million during 2005, as borrowings related to the closing of a Maritech oil and gas property acquisition during the third quarter of 2005 and other working capital needs during the fourth quarter of 2005 more than offset the approximately $62.2 million of debt repayments during the year. During the first quarter of 2006, the Company borrowed additional amounts under its bank credit facility to fund certain acquisition and purchase transactions. Interest expense is expected to increase to the extent such borrowings remain outstanding. The Company’s provision for income taxes during 2005 increased to $18.9 million, compared to $8.3 million during the prior year, primarily due to increased earnings.
Net Income - Income before discontinued operations was $38.3 million during 2005, compared to $18.1 million in the prior year, an increase of 112.3%. Income per diluted share before discontinued operations was $1.06 on 36,068,482 average diluted shares outstanding during 2005, compared to $0.51 on 35,599,275 average diluted shares outstanding in the prior year.
Net income was $38.1 million during 2005, compared to $17.7 million during the prior year. Net income per diluted share was $1.05 on 36,068,482 average diluted shares outstanding, compared to $0.50 on 35,599,275 average diluted shares outstanding in the prior year.
Divisional Comparisons
Fluids Division - Fluids Division revenues increased significantly, from $152.7 million during 2004 to $224.6 million during 2005, an increase of $72.0 million, or 47.1%. The impact from including a full year of operations of TCE, which was acquired in September 2004, resulted in approximately $43.4 million of this increase. Increased product pricing, sales volumes and service activity generated an additional increase of approximately $28.5 million in revenue. In October 2005, one of the Division’s main raw material suppliers announced that it had permanently ceased production from its TDI plant in Lake Charles, Louisiana. This plant supplied feedstock to the Division’s Lake Charles calcium chloride manufacturing facility, which generated approximately 12% of the Division’s revenues during 2005. The Division is operating its Lake Charles facility at a reduced level for an indefinite period while it reviews alternative sources of raw materials, and calcium chloride revenues could be decreased during this period.
Fluids Division gross profit increased from $30.1 million during 2004 to $52.4 million during 2005, an increase of $22.3 million, or 74.0%. Gross profit as a percentage of revenue increased from 19.7% during 2004 to 23.3% during 2005. Such increases were primarily due to increased product sales volumes, a more favorable mix of higher-margin products and services, and increased prices during the period, which offset the impact of higher product costs. In addition, the inclusion of the TCE operations for the full year contributed an increase of approximately $6.8 million. Given the increased cost of raw materials for its products, and the potential higher cost of alternative feedstock supply for the Division’s Lake Charles manufacturing facility, future levels of gross profit for the Fluids Division will be impacted by the Division’s ability to pass along these increased costs to its customers through higher product prices.
Fluids Division income before taxes during 2005 increased by $18.4 million, totaling $34.3 million, compared to $15.9 million during 2004, an increase of 116.0%. This increase was generated by the $22.3 million increase in gross profit discussed above, approximately $0.7 million of gain from disposal of
certain international assets, approximately $0.4 million of increased foreign currency gains, and $0.5 million of equity in earnings of unconsolidated joint ventures. These increases were partially offset by approximately $5.5 million of increased administrative expenses, including a full year of administrative expenses of TCE.
WA&D Division - WA&D Division revenues increased to $201.1 million during 2005, compared to $134.5 million during the prior year, an increase of $66.5 million or 49.5%. The Division’s WA&D Services operations revenues increased by approximately $39.4 million, from $102.6 million during 2004 to $141.9 million during 2005, an increase of approximately 38.4%. This increase was primarily due to the increased activity of the Division’s well abandonment and decommissioning operations, particularly in the Gulf of Mexico and inland waters region. The Division’s decommissioning operations were able to capitalize on the increased activity levels following the purchase of the Arapaho, an 800-ton heavy lift barge, during 2004. As a result of the hurricane damage experienced by many offshore operators during the third quarter of 2005, the Division anticipates increased demand for its services, as operators repair or decommission damaged platforms or escalate their abandonment and decommissioning plans due to the risk of future storms and the associated increasing insurance costs. To increase its capacity to provide services, the Division purchased another derrick barge in February 2006, the DB-1, made extensive repairs and modifications to one of its existing vessels, and entered into an arrangement to lease an additional vessel, the Anna IV. In March 2006, the Division acquired Epic, a full service diving operation, in order to provide additional services to its customers and to secure a substantial portion of the supply of such services for WA&D Services operations.
The Division’s Maritech operations reported revenues of $65.2 million during 2005, compared to $42.0 million during 2004, an increase of $23.2 million, or 55.1%. This increase was due to approximately $15.5 million from higher realized oil and gas sales prices compared to the prior year period, a $7.2 million increase from increased production volumes primarily due to acquisitions of producing properties and a $0.5 million increase from prospect fee revenue recorded during 2005. During the third quarter of 2005, Maritech and its subsidiaries consummated three significant acquisitions of producing properties. Beginning in the last half of the third quarter of 2005, production from a majority of Maritech’s producing properties, including its newly acquired properties, was shut-in as a result of hurricanes Katrina and Rita. While the majority of Maritech’s properties resumed production during the fourth quarter of 2005, much of the potential increased revenue impact from the acquisitions was postponed as a result of the storm interruptions. As of March 16, 2006, a portion of Maritech’s daily production remains shut-in, primarily relating to production which is processed through neighboring platforms, pipelines and processing facilities of other operators and third parties. While the Company anticipates that the majority of these shut-in properties will resume production during 2006, the full resumption of Maritech’s production levels depends on the damage assessments and repairs of certain of these third party assets, the timing of which is outside of Maritech’s control. Even with this delay, however, the Division anticipates that revenues for the Maritech operations will increase in the future as a result of the 2005 acquisitions, successful exploitation efforts, and increased oil and gas sales prices, a portion of which have been hedged through 2008.
WA&D Division gross profit during 2005 totaled $39.4 million, an increase of $10.5 million, or 36.1%, compared to $28.9 million during 2004. WA&D Services gross profit increased from $18.5 million during 2004 to $32.5 million during 2005, an increase of $13.9 million. WA&D Services gross profit as a percentage of revenues increased to 22.9% compared to 18.1% during 2004. These increases were due to operating efficiencies generated from the higher equipment and crew utilization as a result of the increased demand for well abandonment and decommissioning services in the offshore and inland water region. The Division’s increased vessel fleet and the newly acquired Epic diving operations are expected to provide additional efficiencies in the future as the Division attempts to capitalize on the current market demand for its services.
The Division’s Maritech operations reported gross profit of $6.9 million during 2005, compared to $10.4 million during 2004, a $3.4 million decrease. Gross profit as a percentage of revenues decreased during 2005 to 10.7%, compared to 24.7% during 2004. Increased commodity prices were more than offset by approximately $17.0 million of increased operating expenses, and an impairment charge of approximately $1.9 million during 2005. The increased operating expenses were primarily due to the recent producing property acquisitions and include an increase from the associated depreciation, depletion and accretion costs. As a result of the timing of these acquisitions, such increased operating
expenses were incurred during the last four months of 2005, when a significant portion of Maritech’s production was shut-in following the hurricanes. Maritech suffered varying levels of damage to the majority of its offshore production platforms, and three of its platforms were completely destroyed. The Division is currently assessing the extent of these damages, particularly with regard to the destroyed platforms, and expects to incur significant costs during 2006 and beyond to repair these assets. Substantially all of these damaged assets are covered under the Company’s various insurance policies, the cost of which is expected to significantly increase beginning in 2006.
WA&D Division income before taxes was $26.2 million during 2005 compared to $17.1 million during 2004, an increase of $9.1 million, or 53.0%. WA&D Services income before taxes increased from $8.6 million during 2004 to $21.4 million during 2005, an increase of $12.8 million, or 149.5%. This increase was due to the $13.9 million increase in gross profit described above, partially offset by approximately $1.1 million of increased administrative expenses, primarily from increased employee and workers’ compensation liability related expenses.
The Division’s Maritech operations reported income before taxes of $4.9 million, compared to $8.5 million during 2004, a $3.7 million decrease, or 43.0%. This decrease was due to the $3.4 million decrease in gross profit discussed above, and due to approximately $1.8 million of increased administrative costs related to the growth of Maritech’s operations. Such decreases were partially offset by approximately $1.6 million of increased gains from sales of properties.
Production Enhancement Division - Production Enhancement Division revenues increased 59.2% during 2005 compared to 2004, from $66.4 million during 2004 to $105.6 million during 2005, an increase of $39.3 million. Approximately $31.4 million of this increase was due to the inclusion of Compressco’s operations for the full year. Compressco was acquired during the third quarter of 2004. In addition, the Division’s domestic and international production testing operations revenues increased by approximately $6.9 million during 2005, due to increased activity from certain of its customers and the recent extension of such services into Brazil. The Division’s process services operations provided an additional $1.0 million increase. The Division’s March 2006 acquisition of Beacon is expected to enable the Division to expand its domestic production testing operations into the western Texas and eastern New Mexico markets.
Production Enhancement Division gross profit totaled $39.2 million during 2005, increasing from $19.3 million during 2004, a $19.8 million increase, or 102.7%. As a percentage of revenues, gross profit increased from 29.1% during 2004 to 37.1% in 2005. Increased gross profit and gross profit percentage were due mainly to the acquisition of Compressco, and to a lesser extent, was due to the increased activity in the production testing business.
Income before taxes for the Production Enhancement Division increased from $11.2 million during 2004 to $26.8 million during 2005, an increase of $15.6 million or 140.1%. This increase was primarily due to the $19.8 million increase in gross profit discussed above, less approximately $4.1 million of increased administrative costs, primarily related to administrative costs associated with Compressco.
Corporate Overhead - Corporate overhead includes corporate general and administrative expenses, depreciation and amortization, interest income and expense, and other income and expense. Such expenses and income are not allocated to the Company’s operating divisions, as they relate to the Company’s general corporate activities. Corporate overhead increased from $17.8 million during 2004 to $30.1 million during 2005, an increase of $12.3 million. This increase was due to increased administrative costs and net interest expense. The Company recorded an increase in interest expense of approximately $4.4 million related to the outstanding balance of long-term debt that was outstanding during all of 2005. The Company utilized long-term borrowings during the third quarter of 2004 to fund acquisitions. Administrative costs increased approximately $7.4 million due to approximately $5.3 million of increased salaries, benefits, incentive compensation and other employee related expenses, approximately $0.9 million of increased audit and professional service expenses, approximately $0.5 million of increased office expenses, and approximately $0.7 million of increased other general expenses.
Compared to 2003
Consolidated Comparisons
Revenues and Gross Profit - Total consolidated revenues for the year ended December 31, 2004 were $353.2 million, compared to $318.7 million during 2003, an increase of 10.8%, largely due to the acquisitions made during 2004. Consolidated gross profit increased 9.9%, from $70.8 million during 2003 to $77.8 million during 2004, also largely due to the acquisitions. Consolidated gross profit as a percentage of revenue was 22.0% during 2004, compared to 22.2% during 2003.
General and Administrative Expenses - General and administrative expenses were $50.2 million during 2004, an increase of $8.5 million, or 20.3%, compared to 2003. This increase was reflective of the overall growth in the Company’s operations due to acquisitions and primarily consists of approximately $5.8 million of salary, incentive and employee benefit cost increases, $1.7 million of increased professional fees primarily for corporate compliance costs related to the Sarbanes-Oxley Act, plus approximately $0.7 million of increased insurance costs. General and administrative expenses as a percentage of revenue increased to 14.2% during 2004, versus 13.1% during 2003.
Interest Expense and Income Taxes - During 2004, the Company recorded $1.7 million of net interest expense, compared to $0.3 million of net interest expense during 2003, primarily due to the significant increase in the outstanding balances of long-term debt beginning in the third quarter of 2004. Such borrowings, which were used to fund the acquisitions of Compressco, the Kemira calcium chloride assets, and a heavy lift barge during the third quarter of 2004, consisted of borrowings under the Company’s line of credit facility and from the issuance of debt in a private debt offering. The provision for income taxes was $8.3 million in 2004, a decrease of $1.6 million, primarily as a result of decreased earnings compared to 2003. The effective tax rate for the year decreased to 31.5% during 2004 compared to 33.9% in 2003, due primarily to an increase in income from existing international operations as well as the operations from the newly acquired Kemira calcium chloride assets during the third quarter of 2004.
Net Income - Income before discontinued operations and cumulative effect of change in accounting principle was $18.1 million during 2004, compared to $19.4 million during 2003, a decrease of 6.9%. Income per diluted share before discontinued operations and cumulative effect of change in accounting principle was $0.51 on 35,599,275 average diluted shares outstanding during 2004, compared to $0.56 on 34,507,662 average diluted shares outstanding during 2003.
Discontinued operations during 2004 consisted of the Norwegian process services operations. During 2003, discontinued operations also included the operations of Damp Rid, Inc., which was sold in September 2003. The Company recorded a gain of $4.9 million from the sale of Damp Rid, net of taxes of $2.4 million, and a loss of $1.3 million for the asset impairment related to the future disposal of the Norwegian process services facility, net of a $0.7 million tax benefit.
In July 2001, the Financial Accounting Standards Board released SFAS No. 143, “Accounting for Asset Retirement Obligations,” which requires that costs associated with the retirement of tangible long-lived assets be recorded as part of the carrying value of the asset when the obligation is incurred. The Company adopted the provisions of SFAS No. 143 on January 1, 2003. Prior to 2003, the Company expensed the costs of retiring its non-oil and gas properties at the time of retirement. In addition, prior to 2003 the Company recorded the retirement obligations associated with its oil and gas properties at an undiscounted fair market value. The effect of adopting SFAS No. 143 was to record a charge of $1.5 million ($0.04 per diluted share), net of taxes of $0.8 million, during the first quarter of 2003, to expense the costs of retirement obligations associated with the Company’s existing long-lived assets and to accrete the liability to its present value as of January 1, 2003.
Net income was $17.7 million during 2004, compared to $21.7 million during 2003. Net income per diluted share was $0.50 on 35,599,275 average diluted shares outstanding, compared to $0.63 on 34,507,662 average diluted shares outstanding during 2003.
Divisional Comparisons
Fluids Division - Fluids Division revenues increased $33.2 million, or 27.8%, during 2004 compared to 2003, totaling $152.7 million during 2004. This increase was due to increased market share for certain of the Division’s products and services, despite the impact of reduced Gulf of Mexico drilling activity. A portion of this market share increase was due to the September 2004 acquisition of the Kemira calcium chloride assets, which generated revenues during the fourth quarter of 2004 of approximately $11.9 million.
Fluids Division gross profit during 2004 increased by $3.4 million, or 12.8%, compared to 2003. Gross profit as a percentage of revenues decreased from 22.4% during 2003 to 19.7% during 2004. The increased market share for certain of the Division’s products, including the impact of the acquisition mentioned above, generated approximately $7.3 million of increased gross profit. This increased gross profit was partially offset by the impact of decreased prices and increased net costs for certain of the Division’s products, including feedstocks, transportation and utilities, which decreased gross profit by approximately $3.8 million.
Fluids Division income before taxes during 2004 totaled $15.9 million, compared to $14.0 million during 2003, an increase of $1.9 million or 13.6%, as the $3.4 million increase in gross margin discussed above was partially offset by increased administrative expenses.
WA&D Division - The WA&D Division generated revenues of $134.5 million during 2004, compared to $153.5 million during 2003, a decrease of $19.0 million or 12.4%. The Division’s WA&D Services operations reported revenues of $102.6 million, decreasing $17.6 million from 2003 revenues of $120.1 million. $10.0 million of WA&D Services revenues during 2004 were related to services performed for Maritech. The decrease in WA&D Services revenues was primarily due to reduced overall abandonment and decommissioning activity in the Gulf of Mexico, and despite a $5.4 million increase in wireline and onshore well abandonment revenues. Much of the Gulf of Mexico abandonment and decommissioning activity was postponed by many WA&D Division customers, including Maritech, due to strong commodity prices and property sales during 2004. In addition, storm activity in the Gulf of Mexico during 2004 caused increased delays in well abandonment and decommissioning activity compared to the prior year. The Division’s success in bidding for such services can also fluctuate from year to year, given the substantial competition for its services in the Gulf of Mexico. Well abandonment and decommissioning revenues during the fourth quarter of 2004 did increase compared to the prior year quarter, partially due to the Division’s September 2004 purchase of a heavy lift barge.
The Division’s Maritech operations reported revenues of $42.0 million during 2004, an increase of $6.8 million compared to 2003, as an increase in realized commodity prices generated $3.5 million of additional revenues and increased production volumes generated $3.3 million of increased revenues. These production volume increases were due to producing property acquisitions and exploitation efforts, and more than offset normal production declines. Maritech suffered storm damage to one of its offshore production platforms during Hurricane Ivan, causing one of its producing properties to remain shut-in.
WA&D Division gross profit decreased $5.0 million, or 14.8%, to $28.9 million during 2004 from $34.0 million during 2003. WA&D Services’ gross profit totaled $18.5 million during 2004 compared to $25.5 million during 2003. Gross profit as a percentage of revenues was 18.1% during 2004 compared to 21.2% during 2003. The long-term drivers for the well abandonment operations are primarily MMS regulations, the overall maturity of Gulf of Mexico fields, and the age of the platforms and structures in the Gulf. However, the impact of short-term factors discussed above caused a decrease in the WA&D Division’s Gulf of Mexico well abandonment and decommissioning activity levels during 2004 and contributed to a reduction in equipment and personnel utilization, resulting in decreased gross profit of approximately $7.0 million for the WA&D Services operations.
The WA&D Division’s Maritech operation’s gross profit increased from $8.5 million during 2003 to $10.4 million during 2004, an increase of $1.9 million. Gross profit as a percentage of revenues was 24.7% during 2004 compared to 24.0% in 2003. Maritech generated $3.5 million of additional gross profit from increased commodity prices and $2.4 million from higher production volumes due to property acquisitions and reserve volume increases. These increases more than offset $5.4 million of increased
lease operating expenses, resulting from workover and exploitation projects conducted during 2004. The remaining net increase in Maritech’s gross profit of $1.4 million is due to the difference in the amount of property impairments recorded in 2003 of $1.7 million compared to $0.3 million recorded in 2004.
WA&D Division income before taxes totaled $17.1 million during 2004, a decrease of $6.3 million, or 27.0%, compared to 2003. WA&D Services decreased from $16.8 million during 2003 to $8.6 million during 2004, a decrease of $8.3 million. This decrease was due to the $7.0 million decrease in WA&D Services gross profit described above, plus approximately $1.5 million of additional administrative expenses during the year primarily from increased salaries and employer’s liability insurance related expenses. In addition, WA&D Services reflected a $0.1 million gain on the sale of an asset during 2003.
The Division’s Maritech operations reported $8.5 million of income before taxes, compared to $6.6 million during 2003. This $1.9 million increase was caused by the $1.9 million increased gross profit plus $0.4 million of increased gain on sales of assets during 2004, less approximately $0.4 million of increased administrative expenses due to the growth of Maritech’s operations.
Production Enhancement Division - Production Enhancement Division revenues increased $19.2 million, or 40.8%, to $66.4 million during 2004, compared to $47.1 million during 2003. This increase was primarily due to the July 2004 acquisition of Compressco, which generated $18.6 million of revenues during the last half of the year. The Division’s production testing revenues were relatively flat compared to the prior year, despite increased industry activity, due to competitive pressures, the inactivity of a major domestic customer and contract interruptions in Latin America during a portion of the year. In addition, the Company’s process services operations generated a $0.7 million increase in revenues due to higher processed volumes at certain of its contract locations.
The Production Enhancement Division reported gross profit of $19.3 million during 2004 compared to $10.8 million during 2003, a 79.2% increase. Gross profit as a percentage of revenues increased to 29.1% during 2004 compared to 22.9% during 2003. The addition of Compressco, beginning in July 2004, increased gross profit by $8.1 million. In addition, the process services operations generated $0.9 million of added gross profit, primarily from increased efficiencies due to the higher volumes processed. Production testing gross profit decreased approximately $0.5 million during the year, primarily due to the Latin American contract interruptions.
Income before taxes for the Production Enhancement Division increased from $6.4 million during 2003 to $11.2 million during 2004. This 73.7% increase was primarily due to the increased gross profit discussed above, less approximately $3.3 million of increased administrative costs, primarily from the acquisition of Compressco. In addition, the Division’s results reflected approximately $0.5 million in additional gains during the prior year period from the sale of certain production testing equipment.
Corporate Overhead - The Company includes in corporate overhead general and administrative expense, depreciation and amortization, interest income and expense, and other income and expense. Such expenses and income are not allocated to the Company’s business segments, as they relate to the Company’s general corporate activities. Corporate overhead increased from $14.6 million during 2003 to $17.8 million during 2004, primarily due to a $2.0 million increase in administrative expenses, primarily from increased salaries and professional fee expenses associated with increased corporate compliance costs related to the Sarbanes-Oxley Act. In addition, net interest expense increased $1.4 million during 2004, due to the increased long-term borrowings beginning in the third quarter of 2004, which were utilized to fund acquisitions during the period.
Liquidity and Capital Resources
Over the past three years, the Company has generated approximately $143.9 million of net cash flow from operating activities, $28.3 million of proceeds from asset sales and other investing activities, and $135.1 million from financing activities, which it used to fund approximately $153.7 million of capital expenditures and the purchase of $153.7 million of business acquisitions. During the year ended December 31, 2005, and in early 2006, the Company has continued to increase its asset base and execute its growth strategy. The Company’s Maritech subsidiary consummated significant acquisition transactions during 2005, more than doubling its oil and gas reserves. During the first quarter of 2006, the Company acquired Epic and Beacon and purchased a heavy lift barge for a total of approximately $83.4
million of cash. To fund this growth, the Company utilized much of its available capital resources, which the Company expanded in January 2006 by increasing the borrowing capacity under its bank credit facility from $140 million to $200 million. The Company’s cash capital expenditures during 2005 totaled approximately $89.0 million, and the Company anticipates increased capital expenditure activity in 2006 to further grow its operations. The Company continues to generate increased operating cash flow from each of its operating divisions, which it plans to use to fund a majority of the anticipated capital expenditure activity. Cash flow in excess of the Company’s capital expenditures will be used principally to reduce the outstanding balance under its credit facility, which was approximately $161.1 million as of March 16, 2006 after funding the acquisition of the heavy lift barge, Beacon and Epic. The Company has additional availability under its bank credit facility of approximately $18.1 million as of March 16, 2006. The Company could require additional capital in the near term to fund its capital expenditure plans. The Company believes it has various options to expand its capital resources should the need arise. Long-term borrowings are not scheduled to mature until 2009 through 2011.
Operating Activities - The Company continued to generate positive operating cash flow from each of its three operating divisions, resulting in total cash provided by operating activities of $52.8 million during 2005, compared to $54.7 million during 2004. Accounts receivable increased during 2005, reflecting the impact from higher prices, activity and product sales volumes in addition to amounts receivable pursuant to insured hurricane repair costs. This increase was largely offset by increased payables and accrued expenses during the year. Operating cash flow was reduced, however, by the increased volumes and cost of product inventory during the year, and such cost increases are expected to continue during 2006. The Company anticipates that the recent acquisitions of Epic and Beacon and the purchase of the additional heavy lift derrick barge will contribute additional operating cash flow beginning in 2006. Future operating cash flow is also largely dependent upon the level of oil and gas industry activity, particularly in the Gulf of Mexico region of the U.S. The Company’s increased revenues and operating cash flows during 2005 reflect the increased demand for the products and services of the majority of its businesses, and the Company expects that such demand will continue to increase in 2006. The operating cash flow impact from this increased demand is limited or partially offset, however, by the increased product, operating and administrative costs required to deliver its products and services, and the Company’s equipment and personnel capacity constraints.
As a result of significant hurricanes during the third quarter of 2005, the Company suffered damage to certain of its fluids facilities and to certain of its decommissioning assets, including one of its heavy lift barges. Maritech suffered varying levels of damage to the majority of its offshore oil and gas producing platforms, and three of its platforms were completely destroyed. Maritech’s operating cash flow was particularly affected, and several of its properties remain shut-in awaiting platform, pipeline or other facilities to be repaired. Though the resumption of shut-in production on these properties is largely outside of Maritech’s control, the Company expects that the majority of these shut-in properties will return to production during 2006. Beginning in the third quarter of 2005, the Company began performing repair efforts on certain of the damaged assets; however the Company is continuing to assess the extent of certain damage, particularly to the destroyed Maritech platforms. While it is still difficult to accurately predict the total amount of damage, the Company’s best estimate is that total repair costs, including the cost to repair fluids and well abandonment facilities and equipment, abandon damaged offshore wells, and decommission the destroyed platforms will range between $85 to $105 million. The majority of these costs are expected to be incurred in 2006 and 2007, with some additional costs likely to be incurred in later years. The Company’s insurance protection is expected to cover substantially all of the property damage incurred. However, for repair expenditures that are covered by insurance, the collection of insurance claims may be delayed, resulting in the temporary use of Company capital resources to fund such repairs. As of December 31, 2005, repair expenditures incurred in excess of deductibles and covered by insurance protection totaled approximately $12.8 million and are included in accounts receivable, pending the processing of the Company’s insurance claims. The Company anticipates that its future insurance coverage premiums will significantly increase as a result of the recent storms, and that future coverage with similar deductible and maximum coverage amounts may not be available in the market, or its cost may not be justifiable.
Future operating cash flow will also be affected by the commodity prices received for Maritech’s oil and gas production and the timing of expenditures required for the plugging, abandonment and decommissioning of Maritech’s oil and gas properties. Following the third quarter 2005 acquisitions of additional producing properties, Maritech entered into additional oil and gas commodity derivative
transactions which extend through 2008 and are designed to hedge a portion of Maritech’s operating cash flows from risks associated with the fluctuating prices of oil and natural gas. Also, as a result of these acquisitions, the third party discounted fair value, including an estimated profit, of Maritech’s decommissioning liability increased significantly to $133.2 million ($172.2 million undiscounted) as of December 31, 2005. The cash outflow necessary to extinguish this liability is expected to occur over several years, shortly after the end of each property’s productive life. This timing is estimated based on the future oil and gas production cash flows as indicated by the Company’s oil and gas reserve estimates and, as such, is imprecise and subject to change due to changing commodity prices, revisions of these reserve estimates and other factors. The Company’s decommissioning liability is net of amounts allocable to joint interest owners and any contractual amounts to be paid by the previous owners of the properties. In some cases the previous owners are contractually obligated to pay Maritech a fixed amount for the future well abandonment and decommissioning work on these properties as the work is performed, partially offsetting Maritech’s future obligation expenditures. As of December 31, 2005, Maritech’s total undiscounted decommissioning obligation is approximately $248.1 million, and consists of Maritech’s liability of $172.2 million plus approximately $75.9 million, which is contractually required to be reimbursed to Maritech pursuant to such contractual arrangements with the previous owners.
Investing Activities - During 2005, the Company expended approximately $89.0 million of cash for capital expenditures, including approximately $23.1 million of net cash for acquisitions of Maritech oil and gas producing properties. In February 2006, the Company expended approximately $20.0 million for the purchase of a heavy lift derrick barge. In March 2006, the Company paid approximately $47.8 million at closing, subject to adjustment, for the acquisition of Epic, which allows the WA&D Division to offer diving services to its customers. In connection with the acquisition of Epic, the Company shall pay an additional $1.6 million of consideration at a future date to be determined dependent on certain events. Also in March 2006, the Company paid approximately $15.6 million for the acquisition of Beacon, which will allow the Company’s production testing operation to expand into a new geographic market. The Beacon acquisition also contains a contingent consideration provision which, if satisfied, could result in up to $19.1 million of additional consideration to be paid in March 2009. Such transactions were funded by increased borrowings under the Company’s bank credit facility. In addition to the above transactions, the Company plans to expend an estimated $140.0 million on additional capital additions during 2006. The significant majority of such planned capital expenditures is related to identified opportunities to grow and expand the Company’s existing businesses, and may be postponed or cancelled as conditions change. Projects planned during 2006 include the initial phase of the development of the Company’s Magnolia, Arkansas brine facility. In addition to the above capital expenditure plans, the Company may also consider suitable acquisitions or opportunities to establish operations in additional niche oil and gas service markets. To the extent the Company consummates a significant transaction, the Company’s liquidity position will be affected. The Company expects to fund the increased amount of capital expenditures in 2006 through cash flows from operations and from its bank credit facility. Should additional capital be required, the Company believes that it has the ability to generate such capital through the issuance of additional debt or equity.
Total cash capital expenditures of approximately $89.0 million during 2005 included approximately $44.7 million by the WA&D Division, of which approximately $23.1 million was for Maritech acquisitions and approximately $21.6 million was primarily related to exploitation and development expenditures on Maritech’s offshore oil and gas properties. The Production Enhancement Division spent approximately $34.8 million, consisting of approximately $25.6 million related to Compressco compressor fleet expansion, approximately $5.2 million to replace and enhance a portion of the production testing equipment fleet, and approximately $4.0 million for process services capital projects. The Fluids Division reflected approximately $8.4 million of capital expenditures, primarily related to plant expansion projects during the year. Corporate capital expenditures were approximately $1.1 million.
During 2005, Maritech purchased offshore oil and gas producing properties in three separate acquisition transactions in exchange for approximately $23.1 million of net cash plus the assumption of approximately $148.4 million, undiscounted, of associated decommissioning obligations. The previous owners of the properties are contractually obligated to pay $19.5 million of these acquired obligations as the abandonment and decommissioning work is performed. These oil and gas producing assets were recorded at a cost equal to the cash consideration paid plus the discounted fair value of the net decommissioning liabilities assumed of $94.6 million. The Company continues to pursue the purchase of additional producing oil and gas properties as part of its strategy to support its WA&D Division. While
future purchases of such properties are also expected to be primarily funded through the assumption of the associated decommissioning liabilities, the transactions may also involve the payment or receipt of cash at closing or the receipt of cash when associated well abandonment and decommissioning work is performed in the future.
Financing Activities - To fund its capital and working capital requirements, the Company supplements its existing cash balances and cash flow from operating activities as needed from long-term borrowings, short-term borrowings, equity issuances and other sources of capital. The Company has a five year revolving credit facility with a syndicate of banks, which it entered into in September 2004. As of December 31, 2005, the Company had an outstanding balance of $69.1 million and $17.3 million in letters of credit against a $140 million revolving credit facility, leaving a net availability of $53.6 million. In January 2006, the Company amended the revolving credit facility agreement to increase the facility up to $200 million, thus increasing its net availability under the facility by $60 million. The Company utilized much of this availability to fund the March 2006 acquisitions of Epic and Beacon, and the February 2006 purchase of the DB-1 derrick barge.
The bank credit facility is unsecured and guaranteed by certain of the Company’s domestic subsidiaries. Borrowings generally bear interest at LIBOR plus 0.75% to 1.75%, depending on a certain financial ratio of the Company. As of December 31, 2005, the average interest rate on the outstanding balance under the credit facility was 5.22%. The Company pays a commitment fee ranging from 0.20% to 0.375% on unused portions of the facility. The credit facility agreement contains customary financial ratio covenants and dollar limits on the total amount of capital expenditures, acquisitions and asset sales. Access to the Company’s revolving credit line is dependent upon its ability to comply with certain financial ratio covenants set forth in the credit agreement. Significant deterioration of these ratios could result in a default under the credit agreement and, if not remedied, could result in termination of the agreement and acceleration of any outstanding balances under the facility. The credit facility agreement also includes cross-default provisions relating to any other indebtedness greater than $5 million. If any such indebtedness is not paid or is accelerated and such event is not remedied in a timely manner, a default will occur under the Company’s credit facility. The credit facility agreement also prohibits dividends and the Company’s repurchase of equity interests if the Company is in default or if such distribution or repurchase would result in an event of default. The Company was in compliance with all covenants and conditions of its credit facility as of December 31, 2005. The Company’s continuing ability to comply with these financial covenants centers largely upon its ability to generate adequate cash flow. Historically, the Company’s financial performance has been more than adequate to meet these covenants, and the Company expects this trend to continue.
In September 2004, the Company issued, and sold through a private placement, $55 million in aggregate principal amount of Series 2004-A Notes and 28 million Euros (approximately $33.2 million equivalent at December 31, 2005) in aggregate principal amount of Series 2004-B Notes pursuant to a Note Purchase Agreement (collectively the Senior Notes). The Series 2004-A Notes bear interest at a fixed rate of 5.07% and mature on September 30, 2011. The Series 2004-B Notes bear interest at a fixed rate of 4.79% and also mature on September 30, 2011. Interest on the Senior Notes is due semiannually on March 30 and September 30 of each year. Pursuant to the Note Purchase Agreement, the Senior Notes are unsecured and guaranteed by substantially all of the Company’s wholly owned subsidiaries. The Note Purchase Agreement contains customary covenants and restrictions, requires the Company to maintain certain financial ratios and contains customary default provisions, as well as cross-default provisions relating to any other indebtedness of $20 million or more. The Company was in compliance with all covenants and conditions of its Senior Notes as of December 31, 2005. Upon the occurrence and during the continuation of an event of default under the Note Purchase Agreement, the Senior Notes may become immediately due and payable, either automatically or by declaration of holders of more than 50% in principal amount of the Senior Notes outstanding at the time.
In May 2004, the Company filed a universal acquisition shelf registration statement on Form S-4 that permits the Company to issue up to $400 million of common stock, preferred stock, senior and subordinated debt securities and warrants in one or more acquisition transactions that the Company may undertake from time to time. As part of the Company’s strategic plan, the Company evaluates opportunities to acquire businesses and assets and intends to consider attractive acquisition opportunities, which may involve the payment of cash or issuance of debt or equity securities. Such acquisitions may be funded with existing cash balances, funds under the Company’s credit facility, or
securities issued under the Company’s acquisition shelf registration on Form S-4.
In addition to the aforementioned revolving credit facility, the Company funds its short-term liquidity requirements from cash generated by operations, short-term vendor financing and, to a lesser extent, from leasing with institutional leasing companies. The Company believes it has the ability to generate additional capital to fund its capital expenditure plans through the issuance of additional debt or equity.
In January 2004, the Company’s Board of Directors authorized the repurchase of up to $20 million of its common stock. During 2005, the Company purchased 130,950 shares of its common stock at a cost of approximately $2.4 million pursuant to this authorization. During 2004, the Company purchased 210,000 shares of its common stock at a cost of approximately $3.3 million pursuant to this authorization. During 2003, the Company did not repurchase any shares of its stock. The Company also received $10.5 million and $5.4 million during 2005 and 2004, respectively, from the exercise of stock options by employees.
Contractual Cash Obligations - The table below summarizes the Company’s contractual cash obligations as of December 31, 2005:
(1) Decommissioning liabilities related to oil and gas properties generally must be satisfied within twelve months after a property’s lease expires. Lease expiration occurs six months after the last producing well on the lease ceases production. The Company has estimated the timing of these payments based upon anticipated lease expiration dates, which are subject to many changing variables, including the estimated life of the producing oil and gas properties, which is affected by changing oil and gas commodity prices. The amounts shown represent the estimated fair values as of December 31, 2005.
Off Balance Sheet Arrangements - An “off balance sheet arrangement” is defined as any contractual arrangement to which an entity that is not consolidated with the Company is a party, under which the Company has, or in the future may have:
• any obligation under a guarantee contract that requires initial recognition and measurement under U.S. Generally Accepted Accounting Principles;
• a retained or contingent interest in assets transferred to an unconsolidated entity or similar arrangement that serves as credit, liquidity or market risk support to that entity for the transferred assets;
• any obligation under certain derivative instruments; or
• any obligation under a material variable interest held by the Company in an unconsolidated entity that provides financing, liquidity, market risk or credit risk support to the Company, or engages in leasing, hedging or research and development services with the Company.
As of December 31, 2005 and 2004, the Company had no “off balance sheet arrangements” that may have a current or future material affect on the Company’s consolidated financial condition or results of operations.
Commitments and Contingencies - The Company and its subsidiaries are named defendants in several lawsuits and respondents in certain governmental proceedings arising in the ordinary course of business. While the outcomes of lawsuits or other proceedings against the Company cannot be predicted with certainty, management does not expect these matters to have a material impact on the financial statements.
In the normal course of its Fluids Division operations, the Company enters into agreements with certain manufacturers of various raw materials and finished products. Some of these agreements require the Company to make minimum levels of purchases over the term of the agreement. Other agreements require the Company to purchase the entire output of the raw material or finished product produced by the manufacturer. The Company’s purchase obligations under these agreements apply only with regard to raw materials and finished products that meet specifications set forth in the agreements. The Company recognizes a liability for the purchase of such products at the time they are received by the Company.
Related to its acquired interests in oil and gas properties, Maritech estimates the third party fair market values (including an estimated profit) to plug and abandon wells, decommission the pipelines and platforms and clear the sites, and uses these estimates to record Maritech’s decommissioning liabilities, net of amounts allocable to joint interest owners and any amounts contractually agreed to be paid in the future by the previous owners of the properties. In some cases, previous owners of acquired oil and gas properties are contractually obligated to pay Maritech a fixed amount for the future well abandonment and decommissioning work on these properties as such work is performed. As of December 31, 2005, Maritech’s decommissioning liabilities are net of approximately $75.9 million for such future reimbursements from these previous owners.
A subsidiary of the Company, TETRA Micronutrients, Inc. (TMI), previously owned and operated a production facility located in Fairbury, Nebraska. TMI is subject to an Administrative Order on Consent issued to American Microtrace, Inc. (n/k/a/ TETRA Micronutrients, Inc.) in the proceeding styled In the Matter of American Microtrace Corporation, EPA I.D. No. NED00610550, Respondent, Docket No. VII-98-H-0016, dated September 25, 1998 (the Consent Order), with regard to the Fairbury facility. TMI is liable for future remediation costs at the Fairbury facility under the Consent Order; however, the current owner of the Fairbury facility is responsible for costs associated with the closure of that facility. The Company has reviewed estimated remediation costs prepared by its independent, third-party environmental engineering consultant, based on a detailed environmental study. The estimated remediation costs range from $0.6 million to $1.4 million. Based upon its review and discussions with its third-party consultants, the Company established a reserve for such remediation costs of $0.6 million, undiscounted, which is included in Other Liabilities in the accompanying consolidated balance sheets at December 31, 2005 and 2004. The reserve will be further adjusted as information develops or conditions change.
The Company has not been named a potentially responsible party by the EPA or any state environmental agency.
Recently Issued Accounting Pronouncements - In December 2004, the FASB issued SFAS No. 123(R), “Share-Based Payment” (SFAS No. 123R), which is a revision of SFAS No. 123. As modified by the SEC in April 2005, the revised statement is effective at the beginning of the first fiscal year beginning after June 15, 2005. SFAS No. 123R must be applied to new awards and previously granted awards that are not fully vested on the effective date. The Company currently accounts for stock-based compensation using the intrinsic value method. Public companies may begin to apply SFAS No. 123R using either a modified-retrospective or modified-prospective method. Under the modified-prospective application, the Company’s compensation cost for previously granted awards that were not recognized under SFAS No. 123 will be recognized under SFAS No. 123R beginning in the first quarter of 2006. However, had the Company adopted SFAS No. 123R in prior periods, the impact of that standard would have approximated the impact of SFAS No. 123 as described in the disclosure of pro forma net income and earnings per share contained in Note B - Summary of Significant Accounting Policies in the Notes to Consolidated Financial Statements. SFAS No. 123R also requires the benefits of tax deductions in excess of recognized compensation cost be reported as a financing cash flow, rather than as an operating cash flow as required under current literature. This requirement will reduce net operating cash flow and increase net financing cash flow in periods after adoption. While the Company cannot accurately estimate what those future amounts will be (as they depend on, among other things, when employees exercise stock options), the amounts of operating cash flows recognized for such excess tax deductions were $6.1 million, $2.5 million and $1.5 million in 2005, 2004 and 2003, respectively.
Item 7A.
Item 7A. Quantitative and Qualitative Disclosures about Market Risk.
Interest Rate Risk
Any balances outstanding under the Company’s floating rate portion of its bank credit facility are subject to market risk exposure related to changes in applicable interest rates. The Company borrowed funds during the third quarter of 2004, pursuant to the bank credit facility, to fund certain acquisitions. These instruments carry interest at an agreed-upon percentage rate spread above LIBOR. Based on the balances of floating rate debt outstanding as of December 31, 2005, each increase of 100 basis points in the LIBOR rate would result in a decrease in earnings of approximately $463,000.
The following table sets forth, as of December 31, 2005 and 2004, the Company’s principal cash flows for its long-term debt obligations (which bear a variable rate of interest) and weighted average effective interest rates by their expected maturity dates. The Company currently is not a party to an interest rate swap contract or other derivative instrument designed to hedge the Company’s exposure to interest rate fluctuation risk.
Exchange Rate Risk
The Company is exposed to fluctuations between the U.S. dollar and the Euro with regard to its Euro-denominated operating activities and related long-term Euro denominated debt. In September 2004, the Company borrowed Euros to fund the European calcium chloride asset acquisition from Kemira. The Company entered into long-term Euro-denominated borrowings, as it believes such borrowings provide a natural currency hedge for its Euro-based operating cash flow. The Company also has exposure related to operating receivables and payables denominated in Euros as well as other currencies; however, such transactions are not pursuant to long-term contract terms, and the amount of such foreign currency exposure is not determinable or considered material.
The following table sets forth as of December 31, 2005 and 2004, the Company’s cash flows for its long-term debt obligations which are denominated in Euros. This information is presented in U.S. dollar equivalents. The table presents principal cash flows and related weighted average interest rates by their expected maturity dates. As described above, the Company utilizes the long-term borrowings detailed in the following table as a hedge to its investment in its acquired foreign operations and currently is not a party to a foreign currency swap contract or other derivative instrument designed to further hedge the Company’s currency exchange rate risk exposure. The Company’s exchange rate risk exposure related to these borrowings will generally be offset by the offsetting fluctuations in the value of its foreign investment.
Commodity Price Risk
The Company has market risk exposure in the pricing applicable to its oil and gas production. Realized pricing is primarily driven by the prevailing worldwide price for crude oil and spot prices in the U.S. natural gas market. Historically, prices received for oil and gas production have been volatile and unpredictable, and such price volatility is expected to continue. The Company’s risk management activities involve the use of derivative financial instruments, such as swap agreements, to hedge the impact of market price risk exposures for a portion of its oil and gas production. During the third quarter of 2005, the Company’s Maritech Resources, Inc. subsidiary acquired additional oil and gas producing properties in three separate transactions. Given the increased oil and gas production volumes expected as a result of these acquisitions, the Company entered into additional derivative financial instruments designed to hedge the price volatility associated with a portion of the increased production. The Company is exposed to the volatility of oil and gas prices for the portion of its oil and gas production that is not hedged. Net of the impact of the crude oil hedges described below, each $1 per barrel decrease in future crude oil prices would result in a decrease in earnings of $120,000. Each decrease in future gas prices of $0.10 per Mcf would result in a decrease in earnings of $216,000.
FASB Statement No. 133, “Accounting for Derivative Instruments and Hedging Activities,” requires companies to record derivatives on the balance sheet as assets and liabilities, measured at fair
value. Gains or losses resulting from changes in the values of those derivatives are accounted for depending on the use of the derivative and whether it qualifies for hedge accounting. As of December 31, 2005 and 2004, the Company had the following cash flow hedging swap contracts outstanding relating to a portion of Maritech’s oil and gas production:
Commodity Contract
Daily Volume
Contract Price
Contract Term
December 31, 2005
Oil swap
400 barrels/day
$54.90/barrel
January 1, 2006 - December 31, 2006
Oil swap
500 barrels/day
$66.50/barrel
January 1, 2006 - December 31, 2006
Oil swap
800 barrels/day
$66.50/barrel
January 1, 2006 - December 31, 2006
Oil swap
800 barrels/day
$66.40/barrel
January 1, 2006 - December 31, 2006
Oil swap
700 barrels/day
$63.75/barrel
January 1, 2007 - December 31, 2007
Oil swap
800 barrels/day
$63.25/barrel
January 1, 2007 - December 31, 2007
Oil swap
500 barrels/day
$65.40/barrel
January 1, 2007 - December 31, 2007
Oil swap
700 barrels/day
$61.75/barrel
January 1, 2008 - December 31, 2008
Oil swap
800 barrels/day
$60.75/barrel
January 1, 2008 - December 31, 2008
Natural gas swap
20,000 MMBtu/day
$10.465/MMBtu
January 1, 2006 - December 31, 2006
December 31, 2004
Oil swap
500 barrels/day
$42.26/barrel
January 1, 2005 - December 31, 2005
Each oil and gas swap contract uses WTI NYMEX and NYMEX Henry Hub as the referenced commodity, respectively. The market value of the Company’s oil swaps at December 31, 2005 was $607,000, which is reflected as a current asset. A $1 increase in the future price of oil would result in the market value of the combined oil derivative asset decreasing by $2,066,000. The market value of the Company’s natural gas swap at December 31, 2005, was $2,397,000, which was reflected as a current liability. A $0.10 per MMBtu increase in the future price of natural gas would result in the market value of the derivative liability increasing by $707,000.
The market value of the Company’s oil swap at December 31, 2004 was $60,000, which was reflected as a current liability. A $1 increase in the future price of oil would have resulted in the market value of the derivative liability increasing by $183,000.
Item 8.
Item 8. Financial Statements and Supplementary Data.
The financial statements and supplementary data of the Company and its subsidiaries required to be included in this Item 8 are set forth in Item 15 of this Report.
Item 9.
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.
None.
Item 9A.
Item 9A. Controls and Procedures.
Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures
Under the supervision and with the participation of the Company’s management, including its Chief Executive Officer and Chief Financial Officer, the Company conducted an evaluation of its disclosure controls and procedures, as such term is defined under Rule 13a-15(e) promulgated under the Securities Exchange Act of 1934, as amended (the Exchange Act). Based on this evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the Company’s disclosure controls and procedures were effective as of December 31, 2005, the end of the period covered by this annual report.
Management’s Report on Internal Control over Financial Reporting
The management of the Company is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f). Under the supervision and with the participation of management, including the Company’s Chief Executive Officer and Chief Financial Officer, an evaluation of the effectiveness of the Company’s internal control over financial reporting was conducted based on the framework in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on that evaluation under the framework in Internal Control - Integrated Framework issued by the COSO, the Company’s management concluded that the Company’s internal control over financial reporting was effective as of December 31, 2005.
As permitted by guidance provided by the staff of the Securities and Exchange Commission, the scope of management’s assessment of internal control over financial reporting as of December 31, 2005 has excluded certain oil and gas producing properties acquired by Maritech during the third quarter of 2005. These acquired properties represent approximately $123.2 million of total assets as of December 31, 2005, $31.8 million of net assets as of December 31, 2005, $21.6 million of revenues for the year then ended, and $8.5 million of net income for the year then ended. The Company will include these acquired properties in the scope of management’s assessment of internal control over financial reporting beginning in 2006.
Management’s assessment of the effectiveness of the Company’s internal control over financial reporting as of December 31, 2005 has been audited by Ernst & Young LLP, an independent registered public accounting firm, as stated in their report which is included herein.
Changes in Internal Control over Financial Reporting
There were no changes in the Company’s internal control over financial reporting during the fiscal quarter ending December 31, 2005 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.
Item 9B.
Item 9B. Other Information.
In December 2005, the Management and Compensation Committee (the Committee) of the Company’s Board of Directors approved an increase in the salary of Geoffrey M. Hertel, President and Chief Executive Officer of the Company, from $385,000 to $450,000 per annum. The proposed increase became effective December 24, 2005. The base salary increase was approved by the Committee, but it is not otherwise set forth in a written agreement between Mr. Hertel and the Company. There is no written employment agreement between Mr. Hertel and the Company which guarantees Mr. Hertel’s term of employment, salary or other incentives, all of which are entirely at the discretion of the Board of Directors. A copy of the agreement previously entered into between the Company and Mr. Hertel, which is substantially identical to the form executed by substantially all of the employees of TETRA and evidences the at-will nature of their employment, has been previously filed by the Company.
In December, 2005, the Committee also approved discretionary cash bonuses for certain of the Company’s named executive officers, Messrs. Hertel, Coombs and Brightman, in the amounts of $385,000, $300,000 and $175,000, respectively.
A summary of the compensation for the Company’s directors is filed as Exhibit 10.12 to this report, and a summary of the compensation for the Company’s named executive officers is filed as Exhibit 10.13 to this report.
PART III
Item 10.
Item 10. Directors and Executive Officers of the Registrant.
The information required by this Item as to the directors and executive officers of the Company is hereby incorporated by reference from the information appearing under the captions “Proposal No. 1:
Election of Directors,” “Information about Continuing Directors,” “Executive Officers,” and “Board Meetings and Committees” in the Company’s definitive proxy statement for the annual meeting of stockholders to be held May 2, 2006, which involves the election of directors and is to be filed with the Securities and Exchange Commission (SEC) pursuant to the Securities Exchange Act of 1934 as amended (the Exchange Act) within 120 days of the end of the Company’s fiscal year on December 31, 2005.
The information required by this Item concerning compliance with Section 16(a) of the Exchange Act is hereby incorporated by reference from the information appearing under the caption “Section 16(a) Beneficial Ownership Reporting Compliance” in the Company’s definitive proxy statement for the annual meeting of stockholders to be held May 2, 2006. The information required by this Item concerning the Audit Committee of the Company and the audit committee financial experts is hereby incorporated by reference from the information appearing under the caption “Board Meetings and Committees” in the Company’s definitive proxy statement for the annual meeting of stockholders to be held May 2, 2006. The information required by this Item as to the Company’s Code of Ethics is hereby incorporated by reference from the information appearing under the caption “Board Meetings and Committees” in the Company’s definitive proxy statement for the annual meeting of stockholders to be held May 2, 2006.
Item 11.
Item 11. Executive Compensation.
The information required by this Item is hereby incorporated by reference from the information appearing under the captions “Director Compensation” and “Executive Compensation” in the Company’s definitive proxy statement for the annual meeting of stockholders to be held May 2, 2006, which involves the election of directors and is to be filed with the SEC pursuant to the Exchange Act within 120 days of the end of the Company’s fiscal year on December 31, 2005. Notwithstanding the foregoing, in accordance with the instructions to Item 402 of Regulation S-K, the information contained in the Company’s proxy statement under the subheading “Management and Compensation Committee Report” and “Performance Graph” shall not be deemed to be filed as part of or incorporated by reference into this Form 10-K.
Item 12.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.
The information required by this Item as to the ownership by management and others of securities of the Company is hereby incorporated by reference from the information appearing under the captions “Beneficial Stock Ownership of Certain Stockholders and Management” and “Equity Compensation Plan Information” in the Company’s definitive proxy statement for the annual meeting of stockholders to be held May 2, 2006, which involves the election of directors and is to be filed with the SEC pursuant to the Exchange Act within 120 days of the end of the Company’s fiscal year on December 31, 2005.
Item 13.
Item 13. Certain Relationships and Related Transactions.
The information required by this Item as to certain business relationships and transactions with management and other related parties of the Company is hereby incorporated by reference to such information appearing under the captions “Management and Compensation Committee Interlocks and Insider Participation” and “Certain Transactions” in the Company’s definitive proxy statement for the annual meeting of stockholders to be held May 2, 2006, which involves the election of directors and is to be filed with the SEC pursuant to the Exchange Act within 120 days of the end of the Company’s fiscal year on December 31, 2005.
Item 14.
Item 14. Principal Accountant Fees and Services.
The information required by this Item as to principal accountant fees and services for the Company is hereby incorporated by reference to such information appearing under the caption “Fees Paid to Principal Accounting Firm” in the Company’s definitive proxy statement for the annual meeting of stockholders to be held May 2, 2006, which involves the election of directors and is to be filed with the SEC pursuant to the Exchange Act within 120 days of the end of the Company’s fiscal year on December 31, 2005.
PART IV
Item 15.
Item 15. Exhibits and Financial Statement Schedules.
Mutual Life Insurance Company, C.M. Life Insurance Company, Allstate Life Insurance Company, Teachers Insurance and Annuity Association of America, Pacific Life Insurance Company, the Prudential Assurance Company Limited (PAC), and Panther CDO II, B.V. (filed as an exhibit to the Company's Form 8-K filed on September 30, 2004 and incorporated herein by reference).
4.3
Form of 5.07% Senior Notes, Series 2004-A, due September 30, 2011 (filed as an exhibit to the Company's Form 8-K filed on September 30, 2004 and incorporated herein by reference).
4.4
Form of 4.79% Senior Notes, Series 2004-B, due September 30, 2011 (filed as an exhibit to the Company's Form 8-K filed on September 30, 2004 and incorporated herein by reference).
4.5
Subsidiary Guaranty dated September 27, 2004, executed by TETRA Applied Holding Company, TETRA International Incorporated, TETRA Micronutrients, Inc., Seajay Industries, Inc., TETRA Investment Holding Co., Inc., TETRA Financial Services, Inc., Compressco, Inc., Providence Natural Gas, Inc., TETRA Applied LP, LLC, TETRA Applied GP, LLC, TETRA Production Testing GP, LLC, TPS Holding Company, LLC, T Production Testing, LLC, TETRA Real Estate, LLC, TETRA Real Estate, LP, Compressco Testing, L.L.C., Compressco Field Services, Inc., TETRA Production Testing Services, L.P., and TETRA Applied Technologies, L.P., for the benefit of the holders of the Notes (filed as an exhibit to the Company's Form 8-K filed on September 30, 2004 and incorporated herein by reference).
10.1
Long-term Supply Agreement with Bromine Compounds Ltd. (filed as an exhibit to the Company's Form 10-K for the year ended December 31, 1996 and incorporated herein by reference; certain portions of this exhibit have been omitted pursuant to a confidential treatment request filed with the Securities and Exchange Commission).
10.2
Agreement dated November 28, 1994 between Olin Corporation and TETRA-Chlor, Inc. (filed as an exhibit to the Company's Form 10-K for the year ended December 31, 1994 and incorporated herein by reference; certain portions of this exhibit have been omitted pursuant to a confidential treatment request filed with the Securities and Exchange Commission).
10.3***
Stock Option Plan, as amended through January 5, 2001 (filed as an exhibit to the Company's Form 10-K for the year ended December 31, 2000 and incorporated herein by reference).
10.4***
Director Stock Option Plan (filed as an exhibit to the Company's Form 10-K for the year ended December 31, 2000 and incorporated herein by reference).
10.5***
Director Stock Option Plan (filed as an exhibit to the Company's Form 10-K for the year ended December 31, 2000 and incorporated herein by reference).
10.6***
Stock Option Plan for Nonexecutive Employees and Consultants (filed as an exhibit to the Company's Registration Statement on Form S-8 (333-61988) and incorporated herein by reference).
10.7***
Letter of Agreement with Gary C. Hanna, dated March, 2002 (filed as an exhibit to the Company's Form 10-K for the year ended December 31, 2001 and incorporated herein by reference).
10.8***
Director Stock Option Plan (filed as an exhibit to the Company's Form 10-K for the year ended December 31, 2002, and incorporated herein by reference).
10.9
Credit Agreement dated as of September 7, 2004, among TETRA Technologies, Inc. and certain of its subsidiaries, as borrowers, Bank of America, National Association, as Administrative Agent, Bank One, NA and Wells Fargo Bank, N.A., as syndication agents, and Comerica Bank, as documentation agent, attaching the guaranty dated as of September 7, 2004, by the borrowers, as guarantors, to the Administrative Agent for the benefit of the lenders under the Credit Agreement (filed as an exhibit to the Company's Form 8-K filed on September 8, 2004 and incorporated herein by reference).
10.10***
Agreement between TETRA Technologies, Inc. and Geoffrey M. Hertel dated February 26, 1993 (filed as an exhibit to the Company's Form 8-K filed on January 7, 2005 and incorporated herein by reference).
10.11***
Form of Incentive Stock Option Agreement, dated as of December 28, 2004 (filed as an exhibit to the Company's Form 8-K filed on January 7, 2005 and incorporated herein by reference).
10.12+***
Summary Description of the Compensation of Non-Employee Directors of TETRA Technologies, Inc.
10.13+***
Summary Description of Named Executive Officer Compensation.
10.14
Purchase and Sale Agreement by and between Pioneer Natural Resources USA, Inc. as Seller and Maritech Resources, Inc. as Purchaser, dated July 7, 2005 (filed as an exhibit to the Company's Form 10-Q filed on November 9, 2005 and incorporated herein by reference; certain portions of this exhibit have been omitted pursuant to a confidential treatment request filed with the Securities and Exchange Commission).
10.15
Purchase and Sale Agreement among Devon Energy Production Company, L.P., Devon Louisiana Corporation, and Devon Energy Petroleum Pipeline Company, as Seller and Maritech Resources, Inc., as Buyer and TETRA Technologies, Inc., as Guarantor, dated July 22, 2005, as amended by the 1st Amendment to Purchase and Sale Agreement (filed as an exhibit to the Company's Form 10-Q filed on November 9, 2005 and incorporated herein by reference; certain portions of this exhibit have been omitted pursuant to a confidential treatment request filed with the Securities and Exchange Commission).
10.16***
Nonqualified Stock Option Agreement between TETRA Technologies, Inc. and Stuart Brightman, dated as of April 20, 2005 (filed as an exhibit to the Company’s Form 8-K filed on April 20, 2005 and incorporated herein by reference).
10.17***
First Amendment to the TETRA Technologies, Inc. 1998 Director Stock Option Plan (As Amended Through June 27, 2003) dated December 16, 2005 (filed as an exhibit to the Company’s Form 8-K filed on December 22, 2005 and incorporated herein by reference).
10.18***
Form of Stock Option Agreement under the TETRA Technologies, Inc. 1998 Director Stock Option Plan (As Amended Through June 27, 2003), as further amended by the First Amendment to the TETRA Technologies, Inc. 1998 Director Stock Option Plan (As Amended Through June 27, 2003) (filed as an exhibit to the Company’s Form 8-K filed on December 22, 2005 and incorporated herein by reference).
10.19
Agreement and Third Amendment to Credit Agreement dated as of January 20, 2006, among TETRA Technologies, Inc. and certain of its subsidiaries, as borrowers, JP Morgan Chase Bank, National Association (successor to Bank One, NA) and Wells Fargo Bank, N.A., as syndication agents, Comerica Bank, as documentation agent, Bank of America, National Association, as administrative agent, and the lenders party thereto (filed as an exhibit to the Company’s Form 8-K filed on January 23, 2006 and incorporated herein by reference).
10.20***
TETRA Technologies, Inc. Nonqualified Deferred Compensation Plan (filed as an exhibit to the Company’s Form 10-Q filed on August 12, 2002 and incorporated herein by reference).
10.21***
TETRA Technologies, Inc. Nonqualified Deferred Compensation Plan and The Executive Excess Plan Adoption Agreement effective on June 30, 2005 (filed as an exhibit to the Company’s Form 10-Q/A filed on March 16, 2006 and incorporated herein by reference).
21+
Subsidiaries of the Company.
23.1+
Consent of Ernst & Young, LLP.
23.2+
Consent of Ryder Scott Company, L.P.
31.1+
Certification Pursuant to Rule 13(a) -14(a) or 15(d) -14(a) of the Exchange Act, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2+
Certification Pursuant to Rule 13(a) -14(a) or 15(d) -14(a) of the Exchange Act, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1**
Certification Furnished Pursuant to 18 U.S.C. Section 1350, As Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Chief Executive Officer).
32.2**
Certification Furnished Pursuant to 18 U.S.C. Section 1350, As Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Chief Financial Officer).
+ Filed with this report.
** Furnished with this report.
*** Management contract or compensatory plan or arrangement.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, TETRA Technologies, Inc. has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
TETRA Technologies, Inc.
Date: March 16, 2006
By: /s/Geoffrey M. Hertel
Geoffrey M. Hertel, President and CEO
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated:
Signature
Title
Date
/s/J. Taft Symonds
Chairman of
March 16, 2006
J. Taft Symonds
the Board of Directors
/s/Geoffrey M. Hertel
President and Director
March 16, 2006
Geoffrey M. Hertel
(Principal Executive Officer)
/s/Joseph M. Abell
Senior Vice President
March 16, 2006
Joseph M. Abell
(Principal Financial Officer)
/s/Ben C. Chambers
Vice President - Accounting
March 16, 2006
Ben C. Chambers
(Principal Accounting Officer)
/s/Stuart M. Brightman
Executive Vice President
March 16, 2006
Stuart M. Brightman
(Principal Operating Officer)
/s/Bruce A. Cobb
Vice President - Finance
March 16, 2006
Bruce A. Cobb
(Treasurer)
/s/Hoyt Ammidon, Jr.
Director
March 16, 2006
Hoyt Ammidon, Jr.
/s/Paul D. Coombs
Executive Vice President and Director
March 16, 2006
Paul D. Coombs
(Executive Vice President of Strategic Initiatives)
/s/Ralph S. Cunningham
Director
March 16, 2006
Ralph S. Cunningham
/s/Tom H. Delimitros
Director
March 16, 2006
Tom H. Delimitros
/s/Allen T. McInnes
Director
March 16, 2006
Allen T. McInnes
/s/Kenneth P. Mitchell
Director
March 16, 2006
Kenneth P. Mitchell
/s/Kenneth E. White, Jr.
Director
March 16, 2006
Kenneth E. White, Jr.
EXHIBIT INDEX
Exhibit No.
Exhibit
2.1
Agreement and Plan of Merger dated June 22, 2004 by and among TETRA Technologies, Inc., TETRA Acquisition Sub, Inc. and Compressco, Inc. (filed as an exhibit to the Company's Form 8-K filed on July 26, 2004 and incorporated herein by reference).
3.1(i)
Restated Certificate of Incorporation (filed as an exhibit to the Company's Registration Statement on Form S-1(33-33586) and incorporated herein by reference).
3.1(ii)
Certificate of Amendment to Restated Certificate of Incorporation (filed as an exhibit to the Company's Annual Report on Form 10-K filed on March 15, 2004 and incorporated herein by reference).
3.1(iii)
Certificate of Designation of Series One Junior Participating Preferred Stock of the Company dated October 27, 1998 (filed as an exhibit to the Company's Registration Statement on Form 8-A filed on October 27, 1998 (the 1998 Form 8-A) and incorporated herein by reference).
3.2
Bylaws, as amended (filed as an exhibit to the Company's Registration Statement on Form S-1 (33-33586) and incorporated herein by reference).
4.1
Rights Agreement dated as of October 26, 1998 between the Company and Computershare Investor Services LLC (as successor to Harris Trust & Savings Bank), as Rights Agent (filed as an exhibit to the 1998 Form 8-A and incorporated herein by reference).
4.2
Master Note Purchase Agreement, dated September 27, 2004 by and among TETRA Technologies, Inc. and Jackson National Life Insurance Company, Massachusetts Mutual Life Insurance Company, C.M. Life Insurance Company, Allstate Life Insurance Company, Teachers Insurance and Annuity Association of America, Pacific Life Insurance Company, the Prudential Assurance Company Limited (PAC), and Panther CDO II, B.V. (filed as an exhibit to the Company's Form 8-K filed on September 30, 2004 and incorporated herein by reference).
4.3
Form of 5.07% Senior Notes, Series 2004-A, due September 30, 2011 (filed as an exhibit to the Company's Form 8-K filed on September 30, 2004 and incorporated herein by reference).
4.4
Form of 4.79% Senior Notes, Series 2004-B, due September 30, 2011 (filed as an exhibit to the Company's Form 8-K filed on September 30, 2004 and incorporated herein by reference).
4.5
Subsidiary Guaranty dated September 27, 2004, executed by TETRA Applied Holding Company, TETRA International Incorporated, TETRA Micronutrients, Inc., Seajay Industries, Inc., TETRA Investment Holding Co., Inc., TETRA Financial Services, Inc., Compressco, Inc., Providence Natural Gas, Inc., TETRA Applied LP, LLC, TETRA Applied GP, LLC, TETRA Production Testing GP, LLC, TPS Holding Company, LLC, T Production Testing, LLC, TETRA Real Estate, LLC, TETRA Real Estate, LP, Compressco Testing, L.L.C., Compressco Field Services, Inc., TETRA Production Testing Services, L.P., and TETRA Applied Technologies, L.P., for the benefit of the holders of the Notes (filed as an exhibit to the Company's Form 8-K filed on September 30, 2004 and incorporated herein by reference).
10.1
Long-term Supply Agreement with Bromine Compounds Ltd. (filed as an exhibit to the Company's Form 10-K for the year ended December 31, 1996 and incorporated herein by reference; certain portions of this exhibit have been omitted pursuant to a confidential treatment request filed with the Securities and Exchange Commission).
10.2
Agreement dated November 28, 1994 between Olin Corporation and TETRA-Chlor, Inc. (filed as an exhibit to the Company's Form 10-K for the year ended December 31, 1994 and incorporated herein by reference; certain portions of this exhibit have been omitted pursuant to a confidential treatment request filed with the Securities and Exchange Commission).
10.3***
Stock option Plan, as amended through January 5, 2001 (filed as an exhibit to the Company's Form 10-K for the year ended December 31, 2000 and incorporated herein by reference).
10.4***
Director Stock Option Plan (filed as an exhibit to the Company's Form 10-K for the year ended December 31, 2000 and incorporated herein by reference).
10.5***
Director Stock Option Plan (filed as an exhibit to the Company's Form 10-K for the year ended December 31, 2000 and incorporated herein by reference).
10.6***
Stock Option Plan for Nonexecutive Employees and Consultants (filed as an exhibit to the Company's Registration Statement on Form S-8 (333-61988) and incorporated herein by reference).
10.7***
Letter of Agreement with Gary C. Hanna, dated March, 2002 (filed as an exhibit to the Company's Form 10-K for the year ended December 31, 2001 and incorporated herein by reference).
10.8***
Director Stock Option Plan (filed as an exhibit to the Company's Form 10-K for the year ended December 31, 2002, and incorporated herein by reference).
10.9
Credit Agreement dated as of September 7, 2004, among TETRA Technologies, Inc. and certain of its subsidiaries, as borrowers, Bank of America, National Association, as Administrative Agent, Bank One, NA and Wells Fargo Bank, N.A., as syndication agents, and Comerica Bank, as documentation agent, attaching the guaranty dated as of September 7, 2004, by the borrowers, as guarantors, to the Administrative Agent for the benefit of the lenders under the Credit Agreement (filed as an exhibit to the Company's Form 8-K filed on September 8, 2004 and incorporated herein by reference).
10.10***
Agreement between TETRA Technologies, Inc. and Geoffrey M. Hertel dated February 26, 1993 (filed as an exhibit to the Company's Form 8-K filed on January 7, 2005 and incorporated herein by reference).
10.11***
Form of Incentive Stock Option Agreement, dated as of December 28, 2004 (filed as an exhibit to the Company's Form 8-K filed on January 7, 2005 and incorporated herein by reference).
10.12+***
Summary Description of the Compensation of Non-Employee Directors of TETRA Technologies, Inc.
10.13+***
Summary Description of Named Executive Officer Compensation.
10.14
Purchase and Sale Agreement by and between Pioneer Natural Resources USA, Inc. as Seller and Maritech Resources, Inc. as Purchaser, dated July 7, 2005 (filed as an exhibit to the Company's Form 10-Q filed on November 9, 2005 and incorporated herein by reference; certain portions of this exhibit have been omitted pursuant to a confidential treatment request filed with the Securities and Exchange Commission).
10.15
Purchase and Sale Agreement among Devon Energy Production Company, L.P., Devon Louisiana Corporation, and Devon Energy Petroleum Pipeline Company, as Seller and Maritech Resources, Inc., as Buyer and TETRA Technologies, Inc., as Guarantor, dated July 22, 2005, as amended by the 1st Amendment to Purchase and Sale Agreement (filed as an exhibit to the Company's Form 10-Q filed on November 9, 2005 and incorporated herein by reference; certain portions of this exhibit have been omitted pursuant to a confidential treatment request filed with the Securities and Exchange Commission).
10.16***
Nonqualified Stock Option Agreement between TETRA Technologies, Inc. and Stuart Brightman, dated as of April 20, 2005 (filed as an exhibit to the Company’s Form 8-K filed on April 20, 2005 and incorporated herein by reference).
10.17***
First Amendment to the TETRA Technologies, Inc. 1998 Director Stock Option Plan (As Amended Through June 27, 2003) dated December 16, 2005 (filed as an exhibit to the Company’s Form 8-K filed on December 22, 2005 and incorporated herein by reference).
10.18***
Form of Stock Option Agreement under the TETRA Technologies, Inc. 1998 Director Stock Option Plan (As Amended Through June 27, 2003), as further amended by the First Amendment to the TETRA Technologies, Inc. 1998 Director Stock Option Plan (As Amended Through June 27, 2003) (filed as an exhibit to the Company’s Form 8-K filed on December 22, 2005 and incorporated herein by reference).
10.19
Agreement and Third Amendment to Credit Agreement dated as of January 20, 2006, among TETRA Technologies, Inc. and certain of its subsidiaries, as borrowers, JP Morgan Chase Bank, National Association (successor to Bank One, NA) and Wells Fargo Bank, N.A., as syndication agents, Comerica Bank, as documentation agent, Bank of America, National Association, as administrative agent, and the lenders party thereto (filed as an exhibit to the Company’s Form 8-K filed on January 23, 2006 and incorporated herein by reference).
10.20***
TETRA Technologies, Inc. Nonqualified Deferred Compensation Plan (filed as an exhibit to the Company’s Form 10-Q filed on August 12, 2002 and incorporated herein by reference).
10.21***
TETRA Technologies, Inc. Nonqualified Deferred Compensation Plan and The Executive Excess Plan Adoption Agreement effective on June 30, 2005 (filed as an exhibit to the Company’s Form 10-Q/A filed on March 16, 2006 and incorporated herein by reference).
21+
Subsidiaries of the Company.
23.1+
Consent of Ernst & Young, LLP.
23.2+
Consent of Ryder Scott Company, L.P.
31.1+
Certification Pursuant to Rule 13(a) -14(a) or 15(d) -14(a) of the Exchange Act, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2+
Certification Pursuant to Rule 13(a) -14(a) or 15(d) -14(a) of the Exchange Act, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1**
Certification Furnished Pursuant to 18 U.S.C. Section 1350, As Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Chief Executive Officer).
32.2**
Certification Furnished Pursuant to 18 U.S.C. Section 1350, As Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Chief Financial Officer).
+ Filed with this report.
** Furnished with this report.
*** Management contract or compensatory plan or arrangement.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Board of Directors and Stockholders of
TETRA Technologies, Inc.
We have audited the accompanying consolidated balance sheets of TETRA Technologies, Inc. and subsidiaries as of December 31, 2005 and 2004, and the related consolidated statements of operations, stockholders' equity, and cash flows for each of the three years in the period ended December 31, 2005. Our audits also included the financial statement schedule listed in the Index at Item 15(a). These financial statements and schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and schedule based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of TETRA Technologies, Inc. and subsidiaries at December 31, 2005 and 2004, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2005, in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of TETRA Technologies, Inc.’s internal control over financial reporting as of December 31, 2005, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 9, 2006 expressed an unqualified opinion thereon.
ERNST & YOUNG LLP
Houston, Texas
March 9, 2006
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Board of Directors and Stockholders of
TETRA Technologies, Inc.
We have audited management’s assessment, included in the accompanying Management’s Report on Internal Control over Financial Reporting, that TETRA Technologies, Inc. maintained effective internal control over financial reporting as of December 31, 2005, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). TETRA Technologies, Inc.’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management’s assessment and an opinion on the effectiveness of the company’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
As indicated in the accompanying Management’s Report on Internal Control over Financial Reporting, management’s assessment of and conclusion on the effectiveness of internal control over financial reporting did not include the internal controls of certain oil and gas producing properties acquired by TETRA Technologies, Inc., which are included in the 2005 consolidated financial statements of TETRA Technologies, Inc. and constituted $123.2 million of total assets as of December 31, 2005, $31.8 million of net assets as of December 31, 2005, $21.6 million of revenues for the year then ended, and $8.5 million of net income for the year then ended. These operations were acquired in acquisitions during 2005. Our audit of internal control over financial reporting of TETRA Technologies, Inc. also did not include an evaluation of the internal control over financial reporting of these certain oil and gas producing properties acquired by TETRA Technologies, Inc.
In our opinion, management’s assessment that TETRA Technologies, Inc. maintained effective internal control over financial reporting as of December 31, 2005, is fairly stated, in all material respects, based on the COSO criteria. Also, in our opinion, TETRA Technologies, Inc. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2005, based on the COSO criteria.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of TETRA Technologies, Inc. as of December 31, 2005 and 2004, and the related consolidated statements of operations, stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2005 of TETRA Technologies, Inc. and our report dated March 9, 2006 expressed an unqualified opinion thereon.
ERNST & YOUNG LLP
Houston, Texas
March 9, 2006
TETRA Technologies, Inc. and Subsidiaries
Consolidated Balance Sheets
(In Thousands)
See Notes to Consolidated Financial Statements
TETRA Technologies, Inc. and Subsidiaries
Consolidated Balance Sheets
(In Thousands)
See Notes to Consolidated Financial Statements
TETRA Technologies, Inc. and Subsidiaries
Consolidated Statements of Operations
(In Thousands, Except Per Share Amounts)
See Notes to Consolidated Financial Statements
TETRA Technologies, Inc. and Subsidiaries
Consolidated Statements of Stockholders' Equity
(In Thousands, Except Share Information)
See Notes to Consolidated Financial Statements
TETRA Technologies, Inc. and Subsidiaries
Consolidated Statements of Cash Flows
(In Thousands)
See Notes to Consolidated Financial Statements
TETRA TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2005
NOTE A - ORGANIZATION AND OPERATIONS OF THE COMPANY
TETRA Technologies, Inc. and its subsidiaries (the Company) is an oil and gas services company with an integrated calcium chloride and brominated products manufacturing operation that supplies feedstocks to energy markets, as well as other markets. TETRA Technologies, Inc. was incorporated in Delaware in 1981. The Company is composed of three divisions - Fluids, Well Abandonment & Decommissioning (WA&D), and Production Enhancement.
The Company’s Fluids Division manufactures and markets clear brine fluids, additives and other associated products and services to the oil and gas industry for use in well drilling, completion and workover operations both domestically and in certain regions of Europe, Asia, Latin America and Africa. The Division also markets certain fluids and dry calcium chloride manufactured at its production facilities to a variety of domestic and international markets outside the energy industry.
The Company’s WA&D Division consists of two operating segments: WA&D Services and Maritech. The WA&D Services segment provides a broad array of services required for the abandonment of depleted oil and gas wells and the decommissioning of platforms, pipelines, and other associated equipment, servicing the onshore U.S. Gulf Coast region and the inland waters and offshore markets of the Gulf of Mexico. The segment also provides electric wireline, engineering, diving, workover, and drilling services. The Maritech segment consists of the Company’s Maritech Resources, Inc. (Maritech) subsidiary, which, with its subsidiaries, is a producer of oil and gas from wells acquired primarily to support and provide a baseload of business for the WA&D Services operation. In addition, Maritech conducts development and exploitation operations on certain of its oil and gas properties, which are intended to increase the cash flows on such properties prior to their ultimate abandonment.
The Company’s Production Enhancement Division provides production testing services to the Texas, New Mexico, Louisiana, offshore Gulf of Mexico and certain international markets. In addition, it is engaged in the design, fabrication, sale, lease and service of wellhead compression equipment primarily used to enhance production from mature, low pressure natural gas wells located principally in the mid-continent, mid-western, Rocky Mountain, Texas and Louisiana regions of the United States as well as in western Canada and Mexico. The Division also provides the technology and services required for the separation and recycling of oily residuals generated from petroleum refining operations.
NOTE B - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Principles of Consolidation
The consolidated financial statements include the accounts of the Company and its wholly owned subsidiaries. Investments in unconsolidated joint ventures in which the Company participates are accounted for using the equity method. All significant intercompany accounts and transactions have been eliminated in consolidation.
Use of Estimates
The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclose contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
Reclassifications
The consolidated financial statements retroactively reflect the effect of a 3-for-2 stock split, which was approved by the Board of Directors and issued to all stockholders of record as of August 19, 2005. Accordingly, all disclosures involving the number of shares of the Company’s common stock outstanding, issued or to be issued, such as with Company stock options, and all per share amounts, have been retroactively adjusted to reflect the impact of the stock split. See Note K - Capital Stock, for further discussion of the stock split.
Certain depreciation, amortization and accretion expenses have been reported within cost of revenues instead of being included in general and administrative expense as previously reported in prior years. Prior year period amounts have been reclassified to conform to the current year’s presentation. The amounts of such reclassification are $3.6 million and $3.0 million for the years ended December 31, 2004 and 2003, respectively. The amount of such expenses is $6.2 million for the year ended December 31, 2005. This reclassification had no effect on net income for any of the periods presented.
The Company has accounted for the discontinuance or disposal of certain businesses as discontinued operations, and has reclassified prior period financial statements to exclude these businesses from continuing operations. See Note C - Discontinued Operations, for a further discussion of the discontinuance of these businesses and the impact of prior period’s reclassifications on the Company’s consolidated financial statements.
Certain other previously reported financial information has also been reclassified to conform to the current year's presentation.
Cash Equivalents
The Company considers all highly liquid investments, with a maturity of three months or less when purchased, to be cash equivalents.
Financial Instruments
The fair value of the Company’s financial instruments, which may include cash, temporary investments, accounts receivable, short-term borrowings and long-term debt, approximates their carrying amounts. Financial instruments that subject the Company to concentrations of credit risk consist principally of trade receivables with companies in the energy industry. The Company's policy is to evaluate, prior to providing goods or services, each customer's financial condition and determine the amount of open credit to be extended. The Company generally requires appropriate, additional collateral as security for credit amounts in excess of approved limits. The Company’s customers consist primarily of major, well-established oil and gas producers and independent oil and gas companies.
The Company determines the appropriate classification of any marketable debt securities at the time of purchase and reevaluates such designation as of each balance sheet date. Such debt securities are classified as available for sale. The Company purchased $16.2 million and $14.0 million of marketable debt securities during 2004 and 2003, respectively and, during 2004, the Company sold all $30.2 million of such marketable debt securities. The Company reflected no unrealized net holding gains or losses at December 31, 2004. During 2005, 2004 and 2003, the Company held no securities which were classified as held to maturity or trading.
The Company’s risk management activities currently involve the use of derivative financial instruments, such as oil and gas swap contracts, to hedge the impact of commodity market price risk exposures related to a portion of its oil and gas production cash flow. Oil and gas swap contracts result in the Company receiving a fixed amount per barrel or MMBtu over the term of the contract. The effective portion of the derivative’s gain or loss (i.e., that portion of the derivative’s gain or loss that offsets the corresponding change in the cash flows of the hedged transaction) is initially reported as a component of accumulated other comprehensive income (loss) and will be subsequently reclassified into revenues to match the offsetting impact of commodity prices on the hedged exposure when it affects revenues. The “ineffective” portion of the derivative’s gain or loss is recognized in earnings immediately.
The Company is exposed to fluctuations between the U.S. dollar and the Euro, as well as other foreign currencies, with regard to its foreign operations. In addition, the Company entered into Euro-denominated debt, as it believes such debt provides a natural currency hedge for its net investment in its Euro-based operating activities. The hedge is considered to be effective since the debt balance designated as the hedge is less than or equal to the net investment in the foreign operation.
As a result of its outstanding balance under a variable rate bank credit facility, the Company faces market risk exposure related to changes in applicable interest rates. The Company has previously reduced the cash flow volatility of its variable rate debt through the utilization of interest rate swap contracts which provided for the Company to pay a fixed rate of interest and receive a variable rate of interest over the term of the contracts. As of December 31, 2005 and 2004, the Company had no interest rate swap contracts outstanding, but has entered into certain fixed interest rate notes which are scheduled to mature in 2011.
Allowances for Doubtful Accounts
Allowances for doubtful accounts are determined on a specific identification basis when the Company believes that collection of specific amounts owed to it is not probable.
Inventories
Inventories are stated at the lower of cost or market value and consist primarily of finished goods. Cost is determined using the weighted average method.
Property, Plant and Equipment
Property, plant and equipment are stated at the cost of assets acquired. Expenditures that increase the useful lives of assets are capitalized. The cost of repairs and maintenance are charged to operations as incurred. For financial reporting purposes, the Company generally provides for depreciation using the straight-line method over the estimated useful lives of assets which are as follows:
Buildings
- 25 years
Machinery and equipment
- 15 years
Automobiles and trucks
years
Chemical plants
years
Certain machinery, equipment and properties are depreciated or depleted based on operating hours or units of production, subject to a minimum amount, because depreciation and depletion occur primarily through use rather than through elapsed time. Leasehold improvements are depreciated over the remaining term of the associated building lease. Depreciation and depletion expense for the years ended December 31, 2005, 2004 and 2003 was $42.3 million, $29.6 million and $28.7 million, respectively.
Interest capitalized for the years ended December 31, 2005, 2004 and 2003 was $0.3 million, $0.1 million and $0.1 million, respectively.
Oil and Gas Properties
Maritech and its subsidiaries purchase oil and gas properties and assume the related well abandonment and decommissioning liabilities (referred to as decommissioning liabilities). Maritech also conducts oil and gas exploitation and production activities on the acquired properties. The Company follows the successful efforts method of accounting for its oil and gas operations. Under the successful efforts method, the costs of successful exploratory wells and leases are capitalized. Costs incurred to drill and equip development wells, including unsuccessful development wells, are capitalized. Other costs such as geological and geophysical costs, drilling costs of unsuccessful exploratory wells, and all internal costs are expensed. Maritech’s property purchases are recorded at the discounted fair value of the Company’s working interest share of decommissioning liabilities assumed (plus or minus any cash or other consideration paid or received at the time of closing the transaction). Many of the transactions have
been structured so that the estimated fair value of the oil and gas reserves acquired and recorded approximately equals the amount of its working interest ownership of the decommissioning liabilities recorded, net of any cash received or paid. All capitalized costs are accumulated and recorded separately for each field and allocated to leasehold costs and well costs. Leasehold costs are depleted on a unit of production basis based on the estimated remaining equivalent proved oil and gas reserves of each field. Well costs are depleted on a unit of production basis based on the estimated remaining equivalent proved developed oil and gas reserves of each field. Oil and gas producing assets were depleted at an average rate of $1.86, $1.26 and $1.23 per Mcf equivalent for the years ended December 31, 2005, 2004 and 2003, respectively. Properties are assessed for impairment in value, with any impairment charged to expense, whenever indicators become evident.
During the first quarter of 2005, Maritech made the decision not to attempt certain workover procedures necessary to restore production on an offshore field which it operates. In connection with this decision, the Company charged the approximately $1.9 million net carrying value of such field to earnings. In July 2003, Maritech relinquished the oil and gas lease covering one of its offshore properties. Subsequently, in August 2003, Maritech participated in the Minerals Management Service’s Western Gulf of Mexico lease sale in which it was the highest bidder and was subsequently awarded a new lease covering the same block. By this action, Maritech enhanced its net revenue interest and extended the time over which it may conduct its operations on a prospect that it has identified on this block. Maritech retained the ownership of the offshore production platform and facilities related to this property, which it plans to use to support anticipated future exploitation and production efforts. In connection with the relinquishment of the prior lease, however, Maritech recorded a $1.7 million charge to earnings during 2003 for the net carrying value of the related oil and gas reserves. The above charges to earnings are included in depreciation, depletion, amortization and accretion in the accompanying statements of operations.
Gas Balancing
As part of its acquisitions of producing properties, Maritech has acquired gas balancing receivables and payables related to certain properties. Maritech allocates value for any acquired gas balancing positions using estimated amounts expected to be received or paid in the future. Amounts related to under-produced volume positions acquired are reflected in accounts receivable and amounts related to overproduced volume positions acquired are included in accrued liabilities. At December 31, 2005 and 2004, the Company reflected a gas balancing receivable of $3.2 million and $2.0 million, respectively, in accounts receivable and a gas balancing payable of $3.1 million and $1.6 million, respectively, in accrued liabilities. Maritech accounts for gas sales revenue from such properties based on its entitled share of total monthly production, with any monthly over- or under-production taken as an adjustment to the gas balancing receivable or payable.
Long-Lived Assets
The determination of impairment on long-lived assets is conducted periodically when indicators of impairment are present. If such indicators were present, the determination of the amount of impairment would be based on the Company’s judgments as to the future operating cash flows to be generated from these assets throughout their estimated useful lives. The oil and gas industry is cyclical and the Company’s estimates of the period over which future cash flows will be generated, as well as the predictability of these cash flows, can have significant impact on the carrying value of these assets and, in periods of prolonged down cycles, may result in impairment charges. The assessment of oil and gas properties for impairment is based on the future estimated cash flows from the Company’s proved, probable and possible reserves. Assets held for disposal are recorded at the lower of carrying value or estimated fair value less estimated selling costs.
Intangible Assets
Patents, trademarks and other intangible assets are recorded on the basis of cost and are amortized on a straight-line basis over their estimated useful lives, ranging from 3 to 20 years. During 2004, the Company acquired intangible assets of approximately $3.4 million, with estimated useful lives ranging from 3 to 10 years (having a weighted average useful life of 5.78 years), associated with certain acquisitions consummated during the year. Amortization expense of patents, trademarks and other
intangible assets was $1.5 million, $1.4 million, and $0.9 million for the twelve months ended December 31, 2005, 2004 and 2003, respectively, and is included in operating income. The estimated future annual amortization expense of patents, trademarks and other intangible assets is $1.3 million for 2006, $1.0 million for 2007, $0.5 million for 2008, $0.5 million for 2009, and $0.5 million for 2010.
Goodwill represents the excess of cost over the fair value of the net assets of businesses acquired in purchase transactions. For purposes of the impairment test, the reporting units are the Company’s four reporting segments: Fluids, WA&D Services, Maritech and Production Enhancement. The Company has estimated the fair value of each reporting unit based upon the future discounted cash flows of the businesses to which goodwill relates and has determined that there is no impairment of the goodwill recorded as of December 31, 2005 or December 31, 2004. The Company performs the impairment test on an annual basis or whenever indicators of impairment are present. The changes in the carrying amount of goodwill by reporting unit for the two year period ended December 31, 2005, are as follows:
Decommissioning Liabilities
Related to its acquired interests in oil and gas properties, Maritech estimates the third party fair values (including an estimated profit) to plug and abandon wells, decommission the pipelines and platforms and clear the sites, and uses these estimates to record Maritech’s decommissioning liabilities, net of amounts allocable to joint interest owners and any amounts contractually agreed to be paid in the future by the previous owners of the properties. In some cases, previous owners of acquired oil and gas properties are contractually obligated to pay Maritech a fixed amount for the future well abandonment and decommissioning work on these properties as such work is performed. As of December 31, 2005 and 2004, Maritech’s decommissioning liabilities are net of approximately $75.9 million and $57.6 million, respectively, of such future reimbursements from these previous owners.
In estimating the decommissioning liabilities, the Company performs detailed estimating procedures, analysis and engineering studies. Whenever practical, Maritech will utilize the services of its affiliated companies to perform well abandonment and decommissioning work. When these services are performed by an affiliated company, all recorded intercompany revenues are eliminated in the consolidated financial statements. The recorded decommissioning liability associated with a specific property is fully extinguished when the property is completely abandoned. The liability is first reduced by all cash expenses incurred to abandon and decommission the property. If the liability exceeds (or is less than) the Company’s actual out-of-pocket costs, the difference is reported as income (or loss) in the period in which the work is performed. The Company reviews the adequacy of its decommissioning liabilities whenever indicators suggest that the estimated cash flows underlying the liabilities have changed materially. The timing and amounts of these cash flows are subject to changes in the energy industry environment and may result in additional liabilities to be recorded, which, in turn, would increase the carrying values of the related properties. In connection with 2005, 2004 and 2003 oil and gas property additions, the Company assumed net decommissioning liabilities having an estimated discounted fair value of approximately $97.4 million, $12.0 million and $11.5 million, respectively. In association with decommissioning work performed, the Company recorded total reductions to the decommissioning liabilities for the years 2005, 2004 and 2003 of $5.1 million, $5.0 million and $3.0 million, respectively.
Environmental Liabilities
Environmental expenditures which result in additions to property and equipment are capitalized, while other environmental expenditures are expensed. Environmental remediation liabilities are recorded on an undiscounted basis when environmental assessments or cleanups are probable and the costs can be reasonably estimated. These costs are adjusted as further information develops or circumstances change. Any recoveries of environmental remediation costs from other parties are recorded as assets when their receipt is deemed probable.
Revenue Recognition
Revenues are recognized when finished products are shipped or services have been provided to unaffiliated customers and only when collectibility is reasonably assured. Sales terms for the Company’s products are FOB shipping point, with title transferring at the point of shipment. Revenue is recognized at the point of transfer of title. The Company recognizes oil and gas revenues from its interests in producing wells as oil and natural gas is produced and sold from those wells and includes such revenues in product sales revenues. Oil and natural gas sold is not significantly different from the Company’s share of production. With regard to turnkey contracts, revenues are recognized on the percentage-of-completion method based on the ratio of costs incurred to total estimated costs at completion. Total project revenue and cost estimates for turnkey contracts are reviewed periodically as work progresses, and adjustments are reflected in the period in which such estimates are revised. Provisions for estimated losses on such contracts are made in the period such losses are determined.
Operating Costs
Cost of product sales includes direct and indirect costs of manufacturing and producing the Company’s products, including raw materials, fuel, utilities, labor, overhead, repairs and maintenance, purchasing and receiving, transportation, warehousing, equipment rentals, depreciation, insurance and taxes. In addition, cost of product sales includes oil and gas operating expense. Cost of services and rentals includes operating expenses incurred by the Company in delivering its services, including labor, equipment rental, fuel, repair and maintenance, transportation, overhead, depreciation, insurance and taxes. The Company includes in product sales revenues the reimbursements it receives from customers for shipping and handling costs. Shipping and handling costs are included in cost of product sales. Amounts incurred by the Company for “out-of-pocket” expenses in the delivery of its services are recorded as cost of services and rentals. Reimbursements for “out-of-pocket” expenses incurred by the Company in the delivery of its services are recorded as service revenues. Depreciation, depletion, amortization and accretion includes depreciation expense for all of the Company’s facilities, equipment and vehicles, depletion expense on its oil and gas properties, amortization expense on its intangible assets and accretion expense related to its asset retirement obligations.
The Company includes in general and administrative expense all costs not identifiable to its specific product or service operations, including divisional and general corporate overhead, professional services, corporate office costs, sales and marketing expenses, insurance and taxes.
Hurricane Repair Expenses
The Company incurred damage to certain of its onshore and offshore operating equipment and facilities as a result of hurricanes Katrina and Rita during the third quarter of 2005. The damage affected certain of the Company’s fluids facilities, as well as certain of its decommissioning assets, including one of its heavy lift barges. The Company’s Maritech subsidiary also suffered varying levels of damage to the majority of its offshore oil and gas producing platforms, and three of its platforms were completely destroyed. A majority of the Company’s damaged onshore facilities and equipment have been repaired, or are in the final stages of being repaired. With regard to the damaged offshore platforms, the Company is continuing to assess the extent of such damages, and expects that such damage assessment and repair will continue throughout 2006 and beyond.
The Company maintains customary insurance protection covering substantially all of the damages incurred, although certain uninsured assets which were destroyed during the storms have been charged to earnings. Repair costs incurred up to the amount of deductibles are charged to earnings as they are incurred. Repair costs incurred which are covered under the Company’s various insurance policies are included in accounts receivable until processed and collected, and such amounts totaled approximately $12.8 million as of December 31, 2005. Repair costs not probable of collection are charged to earnings. Insurance claim proceeds in excess of destroyed asset carrying values and repair costs incurred are credited to earnings.
Stock Compensation
The Company accounts for stock-based compensation using the intrinsic value method. Compensation cost for stock options is measured as the excess, if any, of the quoted market price of the Company’s stock at the date of the grant over the amount an employee must pay to acquire the stock.
Assuming that the Company had accounted for its stock-based compensation using the alternative fair value method of accounting under SFAS No. 123, “Accounting for Stock-Based Compensation,” and amortized the fair value to expense over the options’ vesting periods, net income and earnings per share would have been as follows:
The fair value of each option grant is estimated on the date of grant using the Black-Scholes option pricing model with the following assumptions: expected stock price volatility 36% to 45%, expected life of options 4.7 to 6.0 years, risk-free interest rate 3.0% to 6.0% and no expected dividend yield. The weighted average fair value of options granted during 2005, 2004 and 2003, using the Black-Scholes model, was $8.04, $9.17 and $6.03 per share, respectively. The pro forma effect on net income for the years presented is not representative of the pro forma effect on net income in future years because of the potential of accelerated vesting of certain options. The pro forma effect on net income for the years ended December 31, 2004 and 2003 has been adjusted to conform to the current year presentation, which correctly reflects the impact of options exercised in prior periods and certain option grants which were immediately vested upon issuance.
Research and Development
The Company expenses costs of research and development as incurred. Research and development expense for each of the years ended December 31, 2005, 2004 and 2003 was $1.3 million, $1.5 million and $1.8 million, respectively.
Advertising
The Company expenses costs of advertising as incurred. Advertising expense for each of the years ended December 31, 2005, 2004 and 2003 was $0.2 million, $0.2 million and $0.1 million, respectively.
Income Taxes
The Company provides for income taxes in accordance with Statement of Financial Accounting Standards (SFAS) No. 109, “Accounting for Income Taxes.” Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis amounts. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect of a change in tax rates is recognized as income or expense in the period that includes the enactment date. This calculation requires the Company to make certain estimates about its future operations. Changes in state, federal and foreign tax laws, as well as changes in the Company’s financial condition, could affect these estimates.
Income per Common Share
Basic earnings per share excludes any dilutive effects of options. Diluted earnings per share includes the dilutive effect of stock options, which is computed using the treasury stock method during the periods such options were outstanding. A reconciliation of the common shares used in the computations of income per common and common equivalent shares is presented in Note P - Income Per Share. There were no stock options or other dilutive securities excluded in the computation of diluted earnings per share for the years ended December 31, 2005, 2004 or 2003.
Foreign Currency Translation
The Company has designated the Euro, the British Pound, the Norwegian Kroner, the Canadian dollar and the Brazilian Real as the functional currency for its operations in Finland and Sweden, the United Kingdom, Norway, Canada and Brazil, respectively. The U.S. dollar is the designated functional currency for all of the Company's other foreign operations. The cumulative translation effects of translating the accounts from the functional currencies into the U.S. dollar at current exchange rates are included as a separate component of stockholders' equity.
New Accounting Pronouncements
In December 2004, the FASB issued SFAS No. 123(R), “Share-Based Payment” (SFAS No. 123R), which is a revision of SFAS No. 123. As modified by the Securities and Exchange Commission (SEC) in April 2005, the revised statement is effective at the beginning of the first fiscal year beginning after June 15, 2005. SFAS No. 123R must be applied to new awards and previously granted awards that are not fully vested on the effective date. The Company currently accounts for stock-based compensation using the intrinsic value method. Public companies may begin to apply SFAS No. 123R using either a modified-retrospective or a modified-prospective method. Under the modified-prospective application, the Company’s compensation cost for previously granted awards that were not recognized under SFAS No. 123 will be recognized under SFAS No. 123R beginning in the first quarter of 2006. However, had the Company adopted SFAS No. 123R in prior periods, the impact of that standard would have approximated the impact of SFAS No. 123 as described in the above disclosure of pro forma net income and earnings per share. SFAS No. 123R also requires the benefits of tax deductions in excess of recognized compensation cost be reported as a financing cash flow, rather than as an operating cash flow as required under current literature. This requirement will reduce net operating cash flow and increase net financing cash flow in periods after adoption. While the Company cannot accurately estimate what those future amounts will be (as they depend on, among other things, when employees exercise stock options), the amounts of operating cash flows recognized for such excess tax deductions were $6.1 million, $2.5 million and $1.5 million in 2005, 2004 and 2003, respectively.
NOTE C - DISCONTINUED OPERATIONS
In September 2003, the Company sold its wholly owned subsidiary, Damp Rid, Inc. (Damp Rid), for total cash proceeds of approximately $19.4 million. Damp Rid markets calcium chloride based desiccant products to retailers. Damp Rid was no longer considered to be a strategic part of the Company’s core businesses. During the third quarter of 2003, the Company reflected a gain on the sale of Damp Rid of approximately $4.9 million, net of tax, for the difference between the sales proceeds and the net carrying value of the subsidiary. The calculation of this gain included $6.1 million of goodwill, net of accumulated amortization, related to the Damp Rid subsidiary. Damp Rid was previously reflected as a component of the Company’s Production Enhancement Division.
During the third quarter of 2003, the Company also made the decision to dispose of its Norwegian process services operations, and began selling the associated facility assets. The Company determined that the Norwegian process services operation’s long-term model did not fit its core business strategy. The Company estimated the fair value of the facility assets based on negotiations to sell the facility and, during the third quarter of 2003, reflected an impairment of approximately $1.3 million, net of tax, on the assets related to its plans to dispose of the operation. In June 2005, the Company curtailed its attempts to sell the remaining facility assets, recorded an impairment expense for the carrying value of certain of the remaining facility assets, and transported the remaining equipment to the United States for use in the Company’s domestic process services operations. The Norwegian process services operation was previously reflected as a component of the Company’s Production Enhancement Division.
The Company has accounted for its Damp Rid and Norwegian process services businesses as discontinued operations, and has reclassified prior period financial statements to exclude these businesses from continuing operations. A summary of financial information related to the Company’s discontinued operations for each of the past three years is as follows:
Assets and liabilities of discontinued operations related to the Norwegian process services operations consist of the following as of December 31, 2005 and 2004:
NOTE D - ACQUISITIONS AND DISPOSITIONS
In July 2005, Maritech acquired oil and gas producing properties located in the offshore Gulf of Mexico, in exchange for the assumption of the associated decommissioning obligations with an undiscounted value of approximately $32.6 million. The previous owner of the properties is contractually obligated to pay up to $19.5 million of the decommissioning obligations when the abandonment and decommissioning work is performed. The acquired oil and gas producing properties were recorded at a cost of approximately $11.4 million, consisting primarily of the discounted fair value of the net decommissioning liability assumed. The purchase and sale agreement also includes an option whereby Maritech may purchase additional oil and gas property interests in exchange for $5.0 million cash. Maritech exercised this purchase option in March 2006.
In August 2005, a wholly owned subsidiary of Maritech acquired oil and gas producing properties located in the inland waters region of Louisiana in exchange for the assumption of the associated decommissioning liabilities with a discounted fair value of approximately $15.5 million. The purchase and sale agreement also provided for cash consideration to be paid by Maritech of $49.1 million, subject to adjustment for the acquired properties’ cash flows occurring on or after the April 1, 2005 effective date. As a result of such cash adjustment for the acquired properties’ cash flows, Maritech paid net cash of approximately $39.3 million and recorded the acquired properties at a cost of approximately $55.2 million.
In September 2005, Maritech acquired oil and gas producing properties located in the offshore and inland waters region of the Gulf of Mexico in exchange for the assumption of the associated decommissioning liabilities with a discounted fair value of approximately $67.9 million, along with other associated liabilities of approximately $1.1 million. The purchase and sale agreement provided for Maritech to pay cash consideration of $4.0 million, subject to adjustment for the effects of exercised preferential rights and the properties’ cash flows occurring on or after the January 1, 2005 effective date. As a result of approximately $22.3 million of such cash adjustments primarily relating to the properties’ cash flows, Maritech received a net settlement of approximately $18.3 million of cash at closing, and will receive additional cash of approximately $2.9 million after closing, subject to final adjustment. The acquired oil and gas producing properties were recorded at their net cost of approximately $49.7 million, which includes approximately $1.9 million of associated transaction costs.
The unaudited pro forma information presented below has been prepared to give effect to the September 2005 acquisition of oil and gas producing properties by Maritech as if it had occurred at the beginning of the periods presented. The pro forma information is presented for illustrative purposes only and is based on estimates and assumptions deemed appropriate by the Company. The following pro forma information is not necessarily indicative of the historical results that would have been achieved if the acquisition transaction had occurred in the past and the Company’s operating results may have been different from those reflected in the pro forma information below. The pro forma information is not indicative of future results to be expected by the Company due to production declines of the oil and gas properties acquired and other changes in the properties’ operations. Therefore, the pro forma information should not be relied upon as an indication of the operating results that the Company would have achieved if the transaction had occurred at the beginning of the periods presented or the future results that the Company will achieve after the acquisition.
Subsequent to December 31, 2005, the Company consummated three acquisition transactions. In February 2006, the Company purchased a heavy lift derrick barge, the DB-1, from Offshore Specialty Fabricators, Inc. for $20 million. The purchase will further expand the WA&D Services segment’s decommissioning operations in the Gulf of Mexico. In March 2006, the WA&D Services segment acquired the assets and operations of Epic Divers, Inc. and associated affiliate companies (Epic), a full service diving operation, for approximately $49.9 million, consisting of approximately $47.8 million paid at closing, $0.5 million, subject to adjustment, to be paid 60 days following closing, and approximately $1.6 million to be paid at a future date to be determined dependant on future events. The acquisition of Epic, which provides services to customers in the Gulf of Mexico, is a strategic addition for the WA&D Services segment which allows it to provide an additional service to its customers, while also internally securing a source for a substantial portion of these services, which are part of the offshore abandonment and decommissioning services. Also in March 2006, the Company acquired Beacon Resources, LLC (Beacon), a production testing operation, as part of its Production Enhancement Division. The acquisition of Beacon will expand the Division’s production testing services operation into the west Texas and eastern New Mexico markets. The Company acquired Beacon for approximately $15.6 million paid at closing, with an additional $0.5 million to be paid, subject to adjustment, over a three year period through March 2009. In addition, the acquisition provides for additional contingent consideration of up to $19.1 million to be paid in March 2009 depending on Beacon’s average pretax results of operations for each of the three years following the closing date up through March 2009. The above first quarter 2006 transactions were funded primarily from the Company’s bank credit facility.
During 2005, Maritech sold certain oil and gas property interests in five separate transactions. In January 2005, Maritech sold a portion of its interest in the oil and gas lease covering one of its offshore properties and retained the decommissioning liability related to the interest conveyed. In connection with the sale, the buyer committed to perform certain development drilling on the lease, received an option to participate in the drilling of a prospect identified on the lease, and agreed to carry a portion of Maritech’s share of the associated drilling costs. In February 2005, Maritech assigned a 75% interest in the oil and gas lease covering one of its offshore properties, subject to the buyer’s commencement of future drilling operations on three prospects identified on the lease. The buyer commenced drilling operations on the first well on the initial prospect in May 2005. In March 2005, Maritech acquired certain interests in an offshore oil and gas property and then sold such acquired interests to a separate party. In August and December 2005, Maritech sold its interest in separate oil and gas properties in exchange for the buyers’ assumption of the associated decommissioning liability. Pursuant to these transactions, and in addition to being carried in the drilling costs discussed above, Maritech received an aggregate of $1.3 million cash in exchange for property interests with approximately 9.5 million equivalent Mcf of primarily proved undeveloped reserves, net of reserves acquired. Maritech recorded gains and prospect fee revenues as a result of the above transactions totaling approximately $2.5 million during 2005.
In May 2005, the Company’s Fluids Division sold certain international assets for approximately $1.0 million cash. In July 2005, the Company’s WA&D Division sold certain well abandonment equipment located in west Texas for approximately $2.1 million cash. In connection with these transactions, the
Company recorded gains totaling approximately $1.0 million during 2005.
In April 2004, the Company purchased certain equipment assets of a well abandonment company located in west Texas for cash. The asset acquisition has been incorporated into the WA&D Division’s onshore well abandonment operations. In June 2004, the Company acquired certain assets of a Venezuelan production testing company for cash, plus additional contingent cash consideration not to exceed $0.5 million. The asset acquisition expands and enhances the existing Venezuelan production testing operations of the Production Enhancement Division. The above operations were acquired for total cash consideration of approximately $3.6 million.
In May 2004, Maritech acquired oil and gas producing properties in the offshore Gulf of Mexico in exchange for the assumption of the associated decommissioning obligations with an undiscounted value of approximately $16.1 million. The previous owner of the properties is contractually obligated to pay $12.3 million of the decommissioning obligations when the abandonment and decommissioning work is performed. The acquired oil and gas producing properties were recorded at a cost of approximately $2.6 million, consisting of the estimated discounted fair value of the net decommissioning liabilities assumed of approximately $3.8 million, less cash and other value received of approximately $1.2 million. In addition, in July 2004, Maritech acquired additional offshore Gulf of Mexico oil and gas producing properties in exchange for the assumption of the associated decommissioning liabilities with an estimated discounted fair value of approximately $1.6 million. These oil and gas producing properties were recorded at cost equal to the estimated fair value of the decommissioning liabilities assumed. In November 2004, Maritech acquired additional offshore Gulf of Mexico oil and gas producing properties in exchange for the assumption of the associated decommissioning obligations with an undiscounted value of approximately $22.4 million. The previous owner of the properties is contractually obligated to pay $16.3 million of the decommissioning obligations when the abandonment and decommissioning work is performed. The acquired oil and gas producing properties were recorded at a cost of approximately $5.6 million, consisting of the estimated fair value of the decommissioning liabilities assumed of approximately $6.1 million, less cash received of approximately $0.5 million.
In July 2004, the Company completed the acquisition of Compressco, Inc. (Compressco) for approximately $94 million in cash, including transaction costs. Additionally, the Company repaid Compressco’s outstanding bank debt of approximately $15.8 million. Compressco designs, fabricates, sells, leases and services wellhead compressors designed to enhance production from mature, low pressure natural gas wells located principally in the mid-continent, Rocky Mountain, Texas and Louisiana regions of the United States and western Canada. The acquisition cost of Compressco reflects Compressco’s significant strategic value to the Company. The Company retained Compressco’s existing management and workforce to expand Compressco’s operations and to develop synergies with the Company’s existing operations. The Company allocated the purchase price of the Compressco acquisition to the fair value of the assets and liabilities acquired, which consisted of approximately $7.7 million of net working capital, approximately $29.3 million of property, plant and equipment, approximately $1.9 million of certain intangible assets, approximately $1.7 million of other liabilities and approximately $72.1 million of goodwill. Intangible assets acquired are amortized over their useful lives of three to six years. Beginning July 2004, the results of operations of Compressco were combined with the Company’s Production Enhancement Division.
In September 2004, the Company completed the acquisition of the European calcium chloride assets of Kemira Oyj (Kemira) of Helsinki, Finland in a cash transaction. The acquisition closed on September 30, 2004, with a total consideration of approximately $40.5 million, including accrued transaction costs. The acquired assets enabled the Company to expand its calcium chloride production and marketing operations and further penetrate international energy and industrial markets. The acquisition cost of the Kemira calcium chloride assets is in excess of the net tangible and intangible assets acquired and reflects the strategic value of the acquisition to the Company’s Fluids Division. The Company allocated the purchase price of the acquisition to the fair value of the assets and liabilities acquired, which consisted of approximately $4.7 million of net working capital, approximately $11.8 million of property, plant and equipment, approximately $5.6 million of other assets, approximately $0.9 million of certain intangible assets, approximately $0.5 million of other liabilities and approximately $15.5 million of tax deductible goodwill. Intangible assets acquired are amortized over their useful lives of three to ten years. Beginning October 2004, the results of operations from the acquired calcium chloride assets were combined with the Company’s Fluids Division operations.
In September 2004, the Company purchased an 800-ton heavy lift derrick barge, based in the Gulf of Mexico, for approximately $21 million in cash. The purchase expanded the decommissioning operations of the Company’s WA&D Division.
In January 2003, Maritech purchased oil and gas producing properties in three separate transactions. In the largest of the three acquisitions, Maritech purchased oil and gas producing properties in offshore Gulf of Mexico and onshore Louisiana locations in exchange for the assumption of the associated decommissioning liabilities with a discounted fair value of approximately $6.9 million. The acquired oil and gas producing properties were recorded at a cost of approximately $5.6 million, consisting of the fair value of the decommissioning liabilities assumed, less cash received of $1.3 million. Maritech also purchased, in two separate transactions, additional working interests in oil and gas properties in exchange for the assumption of the associated decommissioning liabilities with a discounted fair value of approximately $1.1 million. The acquired oil and gas producing assets were recorded at a cost of approximately $0.6 million, consisting of the estimated fair value of the decommissioning liabilities assumed, less cash received of $0.5 million. In February 2003, Maritech purchased oil and gas producing properties in exchange for the assumption of the associated decommissioning obligations with an undiscounted value of approximately $3.6 million. The previous owner of the properties is contractually obligated to pay $1.5 million of the decommissioning obligations when the abandonment and decommissioning work is performed. The acquired oil and gas producing properties were recorded at a cost of approximately $1.2 million, consisting of the estimated discounted fair value of the net decommissioning liabilities assumed of approximately $2.1 million, less cash received of $0.9 million. In April 2003, Maritech purchased oil and gas producing properties in exchange for the assumption of the associated decommissioning obligations with an undiscounted value of approximately $16.7 million. The previous owner of the properties is contractually obligated to pay $16.4 million of the decommissioning obligations when the abandonment and decommissioning work is performed. Approximately $7.9 million of this additional decommissioning work was performed during 2003 and reimbursed by the previous owner. The acquired oil and gas producing properties were recorded at a cost of approximately $0.3 million, consisting of the estimated discounted fair value of the net decommissioning liabilities assumed. In November 2003, Maritech purchased an interest in an oil and gas property in exchange for the assumption of the associated decommissioning liabilities with a discounted fair value of approximately $0.8 million. This oil and gas property, also located in the offshore Gulf of Mexico, was recorded at a cost of approximately $0.4 million, consisting of the estimated fair value of the decommissioning liabilities assumed, less cash received of $0.4 million.
All acquisitions by the Company have been accounted for as purchases, with operations of the companies and businesses acquired included in the accompanying consolidated financial statements from their respective dates of acquisition. The purchase price has been allocated to the acquired assets and liabilities based on a determination of their respective fair values. The excess of the purchase price over the fair value of the net assets acquired is included in goodwill and assessed for impairment whenever indicators are present. The Company has not recorded any goodwill in conjunction with its oil and gas property acquisitions.
NOTE E - LEASES
The Company leases some of its transportation equipment, office space, warehouse space, operating locations and machinery and equipment. The office, warehouse and operating location leases, which vary from one to ten year terms that expire at various dates through 2010, and are renewable for three and five year periods on similar terms, are classified as operating leases. Transportation equipment leases expire at various dates through 2010 and are also classified as operating leases. The office, warehouse and operating location leases and machinery and equipment leases generally require the Company to pay all maintenance and insurance costs.
As of December 31, 2005, the Company had no significant capital leases outstanding. Future minimum lease payments by year and in the aggregate, under non-cancelable operating leases with terms of one year or more, consist of the following at December 31, 2005:
Operating Leases
(In Thousands)
$5,611
3,455
2,263
After
-
Total minimum lease payments
$12,213
Rental expense for all operating leases was $7.2 million, $6.7 million and $6.5 million in 2005, 2004 and 2003, respectively.
The Company, through its Compressco subsidiary, leases oil and gas wellhead compression equipment to its customers throughout the mid-continent, mid-western, western, Rocky Mountain, Texas and Louisiana regions of the United States as well as in western Canada and Mexico. Total compressor equipment leased or available for lease at December 31, 2005 and 2004 is approximately $47.3 million and $32.5 million, respectively. Future minimum rental payments as of December 31, 2005 are not material, as leasing arrangements are typically on a month to month basis.
NOTE F - INCOME TAXES
The income tax provision attributable to continuing operations for the years ended December 31, 2005, 2004 and 2003, consists of the following:
A reconciliation of the provision for income taxes attributable to continuing operations, computed by applying the federal statutory rate for the years ended December 31, 2005, 2004 and 2003 to income before income taxes and the reported income taxes, is as follows:
Income before taxes, discontinued operations and cumulative effect of accounting change includes the following components:
The Company uses the liability method for reporting income taxes, under which current and deferred tax assets and liabilities are recorded in accordance with enacted tax laws and rates. Under this method, at the end of each period, the amounts of deferred tax assets and liabilities are determined using the tax rate expected to be in effect when the taxes are actually paid or recovered. The Company will establish a valuation allowance, to reduce the deferred tax assets, when it is more likely than not that some portion or all of the deferred tax assets will not be realized. While the Company has considered future taxable income and ongoing tax planning strategies in assessing the need for the valuation allowance, there can be no guarantee that the Company will be able to realize all of its deferred tax assets. Significant components of the Company's deferred tax assets and liabilities as of December 31, 2005 and 2004 are as follows:
The change in the valuation allowance during 2005 relates to an increase of foreign operating loss carryforwards generated and other foreign deferred tax assets partially offset by a reduction due to the utilization of foreign operating loss carryforwards. The Company believes the ability to generate sufficient taxable income may not allow it to realize the tax benefits of the deferred tax assets generated in 2005 within the allowable carryforward period. Therefore, an appropriate valuation allowance has been provided.
At December 31, 2005 the Company had approximately $8.9 million of foreign net operating loss carryforwards. In addition, for U.S. Federal income tax purposes at December 31, 2005, the Company has approximately $7.3 million of net operating losses (NOLs) that were generated by Compressco domestic entities prior to their acquisition by the Company. Although the use of these acquired domestic NOLs are subject to limitations imposed by the Internal Revenue Code, the Company believes that it is more likely than not that such NOLs will be utilized prior to their expiration. In those countries in which NOLs are subject to an expiration period, the Company’s loss carryforwards, if not utilized, will expire at various dates from 2012 through 2024. At December 31, 2005, the Company had approximately $1.0 million of foreign tax credits available to offset future payment of Federal income taxes. The foreign tax credits expire in varying amounts through 2015.
The Company has provided additional taxes for the anticipated repatriation of earnings of its foreign subsidiaries where it has determined that the foreign subsidiaries’ earnings are not indefinitely reinvested. For foreign subsidiaries whose earnings are indefinitely reinvested, no provision for U.S. federal and state income taxes has been provided on the unremitted earnings. Unremitted earnings, representing tax basis accumulated earnings and profits, totaled approximately $8.0 million as of December 31, 2005. It is not practicable to estimate the amount of deferred income taxes associated with these unremitted earnings.
NOTE G - ACCRUED LIABILITIES
Accrued liabilities are detailed as follows:
NOTE H - LONG-TERM DEBT AND OTHER BORROWINGS
Long-term debt consists of the following:
Scheduled maturities for the next five years and thereafter are as follows:
Year Ending
December 31,
(In Thousands)
$-
-
-
69,106
-
Thereafter
88,164
$157,270
Bank Credit Facilities
At December 31, 2003, the Company had a $95 million bank credit facility that was scheduled to mature on December 31, 2004 and was secured by accounts receivable, inventories, guarantees of the Company’s domestic subsidiaries, and pledges of stock of the Company’s foreign subsidiaries. During July 2004, the Company borrowed $75 million under the credit facility to fund a portion of the purchase price for the acquisition of Compressco.
In September 2004, the Company entered into a five year $140 million revolving credit facility with a syndication of banks. The Company used the initial borrowings under this facility to repay all outstanding obligations under the previous credit facility, and terminated the previous credit facility. The current facility is unsecured and is guaranteed by certain of the Company’s domestic subsidiaries. Borrowings generally bear interest at LIBOR plus 0.75% to 1.75%, depending on a certain financial ratio of the Company, and the Company pays a commitment fee on unused portions of the facility at a rate from 0.20% to 0.375%, also depending on this financial ratio. As of December 31, 2005, the average interest rate on the outstanding balance under the credit facility was 5.22%.
As of December 31, 2005, the Company had an outstanding balance of $69.1 million and $17.3 million in letters of credit against the $140 million line of credit, leaving a net availability of $53.6 million. In January 2006, the Company amended the revolving credit facility agreement to increase the facility up to $200 million, thus increasing its availability under the facility by $60 million. As of March 16, 2006, the Company’s outstanding balance under the facility had increased to $161.1 million, due to additional borrowings used to fund certain first quarter 2006 acquisitions.
The revolving credit facility agreement contains customary covenants and other restrictions. In addition, the facility requires the Company to maintain certain financial ratio and net worth requirements and provides dollar limits on the amount of Company capital expenditures, acquisitions and asset sales. The facility also includes cross-default provisions relating to any other indebtedness of the Company greater than $5 million. If any such indebtedness is not paid or is accelerated and such event is not remedied in a timely manner, a default will occur under the credit facility. The Company is in compliance with all covenants and conditions of its credit facility as of December 31, 2005. Defaults under the credit facility that are not timely remedied could result in a termination of all commitments of the lenders and an acceleration of any outstanding loans and credit obligations.
Senior Notes
In September 2004, the Company issued, and sold through a private placement, $55 million in aggregate principal amount of Series 2004-A Notes and 28 million Euros (approximately $33.2 million equivalent at December 31, 2005) in aggregate principal amount of Series 2004-B Notes pursuant to a Note Purchase Agreement. The Series 2004-A Notes and the 2004-B Notes (collectively the Senior Notes) were sold in the United States only to accredited investors pursuant to an exemption from the Securities Act and to non-U.S. persons in reliance upon Regulation S under the Securities Act. Net proceeds from the sale of the Senior Notes were used to pay down a portion of existing indebtedness under the new revolving credit facility and to fund the acquisition of the Kemira calcium chloride assets.
The Series 2004-A Senior Notes bear interest at the fixed rate of 5.07% and mature on September 30, 2011. The Series 2004-B Senior Notes bear interest at the fixed rate of 4.79% and mature on September 30, 2011. Interest on the Senior Notes is due semiannually on March 30 and September 30 of each year, commencing March 30, 2005. The Company may prepay the Senior Notes, in whole or in part, at any time at a price equal to 100% of the principal amount outstanding, plus accrued and unpaid interest and a “make-whole” prepayment premium. The Senior Notes were issued under a Note Purchase Agreement and are unsecured. They are guaranteed by substantially all of the Company’s wholly owned domestic subsidiaries. The Note Purchase Agreement contains customary covenants and restrictions, requires the Company to maintain certain financial ratios and contains customary default provisions, as well as a cross-default provision relating to any other indebtedness of the Company of $20 million or more. The Company is in compliance with all covenants and conditions of the Note Purchase Agreement as of December 31, 2005. Upon the occurrence and during the continuation of an event of default under the Note Purchase Agreement, the Senior Notes may become immediately due and payable, either automatically or by declaration of holders of more than 50% in principal amount of the Senior Notes outstanding at the time.
NOTE I - ASSET RETIREMENT OBLIGATIONS
Effective January 1, 2003, the Company changed its method of accounting for asset retirement obligations in accordance with SFAS No. 143, “Accounting for Asset Retirement Obligations.” The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. The amount of decommissioning liabilities recorded by Maritech is reduced by amounts allocable to joint interest owners and any contractual amount to be paid by the previous owner of the property when the liabilities are satisfied. Maritech’s decommissioning liabilities increased significantly during the year ended December 31, 2005 due to the acquisition of oil and gas producing properties. The Company also operates facilities in various U.S. and foreign locations in the manufacture, storage, and sale of its products, inventories and equipment, including offshore oil and gas production facilities and equipment. These facilities are a combination of owned and leased assets. The Company is required to take certain actions in connection with the retirement of these assets. The Company has reviewed its obligations in this regard in detail and estimated the cost of these actions. These estimates are the fair values that have been recorded for retiring these long-lived assets. These fair value amounts have been capitalized as part of the cost basis of these assets. The costs are depreciated on a straight-line basis over the life of the asset for non-oil and gas assets and on a unit of production basis for oil and gas properties. The market risk premium for a significant majority of the asset retirement obligations is considered small, relative to the related estimated cash flows, and has not been used in the calculation of asset retirement obligations.
The cumulative effect of the change on prior years’ reported income as a result of the adoption of SFAS No. 143 resulted in a charge to income of $1.5 million (net of income taxes of $0.8 million) ($0.04 per diluted share), which is included in income for the year ended December 31, 2003. The effect of the change for the year ended December 31, 2003 was to decrease income before the cumulative effect of the accounting change by $0.6 million (net of taxes) ($0.02 per diluted share), due to the resulting accretion and depreciation expense. The pro forma effects, net of taxes, of the application of SFAS No. 143 as if the Statement had been adopted prior to January 1, 2003, are presented below:
Year Ended
December 31, 2003
(In Thousands, Except Per Share Amounts)
Net income, as reported
$21,664
Additional accretion and depreciation expense
-
Cumulative effect of accounting change
1,464
Pro forma net income
$23,128
Pro forma net income per diluted share
$0.67
The changes in the asset retirement obligations during the most recent two year period are as follows:
NOTE J - COMMITMENTS AND CONTINGENCIES
The Company and its subsidiaries are named defendants in several lawsuits and respondents in certain governmental proceedings arising in the ordinary course of business. While the outcome of lawsuits or other proceedings against the Company cannot be predicted with certainty, management does not expect these matters to have a material adverse impact on the financial statements.
In the normal course of its Fluids Division operations, the Company enters into agreements with certain manufacturers of various raw materials and finished products. Some of these agreements require the Company to make minimum levels of purchases over the term of the agreement. Other agreements require the Company to purchase the entire output of the raw material or finished product produced by the manufacturer. The Company’s purchase obligations under these agreements apply only with regard to raw materials and finished products that meet specifications set forth in the agreements. The Company recognizes a liability for the purchase of such products at the time they are received by the Company. The aggregate amount of the fixed and determinable portion of the purchase obligation pursuant to these agreements was approximately $21.8 million, consisting of approximately $1.9 million per year through 2017. Amounts purchased under these agreements totaled approximately $2.0 million during 2005.
Related to its acquired interests in oil and gas properties, Maritech estimates the third party fair values (including an estimated profit) to plug and abandon wells, decommission the pipelines and platforms, and clear the sites, and uses the estimates to record Maritech’s decommissioning liabilities, net
of amounts allocable to joint interest owners and any amounts contractually agreed to be paid in the future by the previous owners of the properties. In some cases, previous owners of acquired oil and gas properties are contractually obligated to pay Maritech a fixed amount for the future well abandonment and decommissioning work on these properties as such work is performed. As of December 31, 2005, Maritech’s decommissioning liability is net of approximately $75.9 million of such future reimbursements from these previous owners.
A subsidiary of the Company, TETRA Micronutrients, Inc. (TMI), previously owned and operated a production facility located in Fairbury, Nebraska. TMI is subject to an Administrative Order on Consent issued to American Microtrace, Inc. (n/k/a/ TETRA Micronutrients, Inc.) in the proceeding styled In the Matter of American Microtrace Corporation, EPA I.D. No. NED00610550, Respondent, Docket No. VII-98-H-0016, dated September 25, 1998 (the Consent Order), with regard to the Fairbury facility. TMI is liable for future remediation costs at the Fairbury facility under the Consent Order; however, the current owner of the Fairbury facility is responsible for costs associated with the closure of that facility. The Company has reviewed estimated remediation costs prepared by its independent, third-party environmental engineering consultant, based on a detailed environmental study. The estimated remediation costs range from $0.6 million to $1.4 million. Based upon its review and discussions with its third-party consultants, the Company established a reserve for such remediation costs of $0.6 million, undiscounted, which is included in Other Liabilities in the accompanying consolidated balance sheets at December 31, 2005 and 2004. The reserve will be further adjusted as information develops or conditions change.
The Company has not been named a potentially responsible party by the EPA or any state environmental agency.
NOTE K - CAPITAL STOCK
The Company's Restated Certificate of Incorporation authorizes the Company to issue 70,000,000 shares of common stock, par value $.01 per share, and 5,000,000 shares of preferred stock, par value $.01 per share. The voting, dividend and liquidation rights of the holders of common stock are subject to the rights of the holders of preferred stock. The holders of common stock are entitled to one vote for each share held. There is no cumulative voting. Dividends may be declared and paid on common stock as determined by the Board of Directors, subject to any preferential dividend rights of any then outstanding preferred stock.
The Board of Directors of the Company is empowered, without approval of the stockholders, to cause shares of preferred stock to be issued in one or more series and to establish the number of shares to be included in each such series and the rights, powers, preferences and limitations of each series. Because the Board of Directors has the power to establish the preferences and rights of each series, it may afford the holders of any series of preferred stock preferences, powers and rights, voting or otherwise, senior to the rights of holders of common stock. The issuance of the preferred stock could have the effect of delaying or preventing a change in control of the Company.
Upon dissolution or liquidation of the Company, whether voluntary or involuntary, holders of common stock will be entitled to receive all assets of the Company available for distribution to its stockholders, subject to any preferential rights of any then outstanding preferred stock.
In January 2004, the Board of Directors of the Company authorized the repurchase of up to $20.0 million of its common stock. During 2005, the Company purchased 130,950 shares of its common stock for aggregate consideration of approximately $2.4 million pursuant to this authorization. During 2004, the Company purchased 210,000 shares of its common stock for aggregate consideration of approximately $3.3 million pursuant to this authorization.
During the past three years, the Company has declared two 3-for-2 stock splits, which were each effected in the form of stock dividends, whereby stockholders of record received one additional share of common stock for every two shares held as of the record date, with fractional shares paid in cash based on the closing price per share of the common stock as of the record date. In August 2005, the Company declared a 3-for-2 stock split to all stockholders of record as of August 19, 2005 (the 2005 Record Date), resulting in the August 26, 2005 issuance of 11,403,016 additional shares outstanding. In August 2003, the Company declared a 3-for-2 stock split to all stockholders of record as of August 15, 2003 (the 2003
Record Date), resulting in the August 22, 2003 issuance of 10,918,919 additional shares outstanding. The consolidated financial statements retroactively reflect the effect of each of the above 3-for-2 stock splits and, accordingly, all disclosures involving the number of shares of common stock outstanding, issued or to be issued, and all per share amounts, retroactively reflect the impact of these stock splits.
NOTE L - STOCK OPTION PLANS
The Company has various stock option plans which provide for the granting of options for the purchase of the Company’s common stock and other performance-based awards to executive officers, key employees, nonexecutive officers, consultants and directors of the Company. Incentive stock options can vest over a period of up to five years and are exercisable for periods up to ten years.
The TETRA Technologies, Inc. 1990 Stock Option Plan (the 1990 Plan) was initially adopted in 1985 and subsequently amended to change the name and the number and type of options that could be granted as well as the time period for granting stock options. As of December 31, 2005, no further options may be granted under the 1990 Plan.
The Company has granted performance stock options under the 1990 Plan to certain executive officers. These granted options have an exercise price per share of not less than the market value at the date of issuance and generally vest in full in no less than five years, subject to earlier vesting as follows: fifty percent of each such option vests immediately if the market value per share of the Company’s common stock is equal to or greater than 150% of the exercise price of the performance option for a period of at least 20 consecutive trading days; and the remaining fifty percent vests immediately if the market value per share is equal to or greater than 200% of the exercise price of the performance option for a period of at least 20 consecutive trading days. These options are immediately exercisable upon vesting; provided, however, that no more than 150,000 shares of common stock may be exercised by any individual after vesting in any 90 day period, except in the event of death, incapacity or termination of employment of the holder or the occurrence of a corporate change. Such options must be exercised within three years of vesting or they expire; but, in any event, all options expire eight years from their grant date. As of December 31, 2005, all performance stock option grants are fully vested and exercisable.
In 1993, the Company adopted the TETRA Technologies, Inc. Director Stock Option Plan (the Directors’ Plan). In 1996, the Directors’ Plan was amended to increase the number of shares issuable under automatic grants thereunder. In 1998, the Company adopted the TETRA Technologies, Inc. 1998 Director Stock Option Plan as amended (the 1998 Director Plan). The purpose of the Directors’ Plan and the 1998 Director Plan (together the Director Stock Option Plans) is to enable the Company to attract and retain qualified individuals to serve as directors of the Company and to align their interests more closely with the Company’s interests. The 1998 Director Plan is funded with treasury stock of the Company and was amended and restated effective December 18, 2002 to increase the number of shares issuable thereunder, change the types of options that may be granted thereunder, and to increase the number of shares issuable under automatic grants thereunder. In June 2003, the 1998 Director Plan was amended and restated effective June 27, 2003 to increase the number of shares issuable thereunder. At December 31, 2005, 1,068,750 shares of common stock have been registered and are reserved for grants under the Director Stock Option Plans, of which 141,279 are available for future grants.
During 1996, the Company adopted the 1996 Stock Option Plan for Nonexecutive Employees and Consultants (the Nonqualified Plan) to enable the Company to award nonqualified stock options to nonexecutive employees and consultants who are key to the performance of the Company. At December 31, 2005, 1,687,500 shares of common stock have been registered and are reserved for grants under the Nonqualified Plan, of which 136,761 are available for future grants. The following is a summary of stock option activity for the years ended December 31, 2005, 2004 and 2003:
Shares Under Option
Weighted Average Option
(In Thousands)
Price Per Share
Outstanding at December 31, 2002
4,011
$7.28
Options granted
1,425
9.31
Options cancelled
(92
)
9.11
Options exercised
(851
)
5.22
Outstanding at December 31, 2003
4,493
8.28
Options granted
1,265
17.13
Options cancelled
(180
)
10.18
Options exercised
(864
)
7.05
Outstanding at December 31, 2004
4,714
10.80
Options granted
19.32
Options cancelled
(55
)
9.83
Options exercised
(1,145
)
9.45
Outstanding at December 31, 2005
3,876
$12.01
Certain options exercised during 2005, 2004 and 2003 were exercised through the surrender of 15,708, 43,083, and 15,459 shares, respectively, of the Company’s common stock previously owned by the option holder for a period of at least six months prior to exercise. Such surrendered shares received by the Company are included in treasury stock. At December 31, 2005, net of options previously exercised pursuant to its various stock option plans, the Company has a maximum of 4,153,955 shares of common stock issuable pursuant to stock options previously granted and outstanding and stock options authorized to be granted in the future.
NOTE M - 401(k) PLAN
The Company has a 401(k) retirement plan (the Plan) that covers substantially all employees and entitles them to contribute up to 70% of their annual compensation, subject to maximum limitations imposed by the Internal Revenue Code. The Company matches 50% of each employee’s contribution up to 6% of annual compensation, subject to certain limitations as outlined in the Plan. In addition, the Company can make discretionary contributions which are allocable to participants in accordance with the Plan. Total expense related to the Company’s 401(k) plan was $1.5 million, $0.5 million and $1.3 million in 2005, 2004 and 2003, respectively.
NOTE N - DEFERRED COMPENSATION PLAN
The Company provides its officers, directors and certain key employees with the opportunity to participate in an unfunded, deferred compensation program. There were twenty participants in the program at December 31, 2005. Under the program, participants may defer up to 100% of their yearly total cash compensation. The amounts deferred remain the sole property of the Company, which uses a portion of the proceeds to purchase life insurance policies on the lives of certain of the participants. The insurance policies, which remain the sole property of the Company, are payable to the Company upon the death of the insured. The Company separately contracts with the participant to pay to the participant the amount of deferred compensation, as adjusted for gains or losses, invested in participant-selected investment funds. Participants may elect to receive deferrals and earnings at termination, death, or at a specified future date while still employed. Distributions while employed must be at least three years after the deferral election. The program is not qualified under Section 401 of the Internal Revenue Code. At December 31, 2005, the amounts payable under the plan approximated the value of the corresponding assets owned by the Company.
NOTE O - HEDGE CONTRACTS
The Company has market risk exposure in the sales prices it receives for its oil and gas production and currency exchange rate risk exposure related to investments in certain of its international operations. The Company’s financial risk management activities involve, among other measures, the use of derivative financial instruments, such as swap and collar agreements, to hedge the impact of market price risk exposures for a significant portion of its oil and gas production. Under SFAS No. 133, as amended by SFAS Nos. 137 and 138, all derivative instruments are required to be recognized on the balance sheet at their fair value, and criteria must be established to determine the effectiveness of the hedging relationship. Hedging activities may include hedges of fair value exposures, hedges of cash flow exposures and hedges of a net investment in a foreign operation. A fair value hedge requires that the effective portion of the change in the fair value of a derivative instrument be offset against the change in the fair value of the underlying assets, liability or firm commitment being hedged through earnings. Hedges of cash flow exposure are undertaken to hedge a forecasted transaction or the variability of cash flows to be received or paid related to a recognized asset or liability. A cash flow hedge requires that the effective portion of the change in the fair value of a derivative instrument be recognized in other comprehensive income, a component of stockholders’ equity, and then be reclassified into earnings in the period or periods during which the hedged transaction affects earnings. Transaction gains and losses attributable to a foreign currency transaction that is designated as, and is effective as, an economic hedge of a net investment in a foreign entity is subject to the same accounting as translation adjustments. As such, the effect of a rate change on a foreign currency hedge is the same as the accounting for the effect of the rate change on the net foreign investment; both are recorded in the cumulative translation account, a component of stockholders’ equity, and are partially or fully offsetting. Any ineffective portion of a derivative instrument’s change in fair value is immediately recognized in earnings.
As required by SFAS No. 133, the Company formally documents all relationships between hedging instruments and hedged items, as well as its risk management objectives, strategies for undertaking various hedge transactions and its methods for assessing and testing correlation and hedge ineffectiveness. All hedging instruments are linked to the hedged asset, liability, firm commitment or forecasted transaction. The Company also assesses, both at the inception of the hedge and on an ongoing basis, whether the derivatives that are used in these hedging transactions are highly effective in offsetting changes in cash flows of the hedged items.
The fair value of hedging instruments reflects the Company’s best estimate and is based upon exchange or over-the-counter quotations, whenever they are available. Quoted valuations may not be available. Where quotes are not available, the Company utilizes other valuation techniques or models to estimate fair values. These modeling techniques require it to make estimations of future prices, price correlation and market volatility and liquidity. The actual results may differ from these estimates, and these differences can be positive or negative.
The Company believes that its swap and collar agreements are “highly effective cash flow hedges,” as defined by SFAS No. 133, in managing the volatility of future cash flows associated with its oil and gas production. The effective portion of the change in the derivative’s fair value (i.e., that portion of the change in the derivative’s fair value that offsets the corresponding change in the cash flows of the hedged transaction) is initially reported as a component of accumulated other comprehensive income (loss) and will be subsequently reclassified into product sales revenues utilizing the specific identification method when the hedged exposure affects earnings (i.e., when hedged oil and gas production volumes are reflected in revenues). Any “ineffective” portion of the change in the derivative’s fair value is recognized in earnings immediately.
During the years ended December 31, 2005, 2004 and 2003, the Company entered into certain cash flow hedging swap and collar contracts to fix cash flows relating to a portion of the Company’s oil and gas production. Each of these contracts qualified for hedge accounting. As of December 31, 2005, ten swap contracts remain outstanding, with various expiration dates through December 2008. The fair value of the liability for the outstanding cash flow hedge natural gas swap contract at December 31, 2005 was $2,397,000. The fair value of the liability for the outstanding cash flow hedge oil swap contract at December 31, 2004 was $60,000. These liabilities are included in accrued liabilities in the accompanying consolidated balance sheets. The fair value of the asset for outstanding cash flow hedge oil swap contracts at December 31, 2005 was $607,000, which is included in prepaid expenses and other current assets in the accompanying consolidated balance sheets. Such amounts at December 31, 2005 will be reclassified into earnings over the term of the hedge swap contracts. As the hedge contracts were highly effective, the entire losses of $1,124,000 and $39,000 from changes in contract fair value, net of taxes, as of December 31, 2005 and 2004, respectively, are included in other comprehensive income (loss) within stockholders’ equity. Approximately $705,000 of such contract fair value, net of taxes, is expected to be reclassified into earnings within the next twelve months.
During the year ended December 31, 2004, the Company borrowed 35 million Euros to fund the acquisition of the Kemira calcium chloride assets. This debt is designated as a hedge of the Company’s net investment in that foreign operation. The hedge is considered to be effective since the debt balance designated as the hedge is less than or equal to the net investment in the foreign operation. At December 31, 2005, the Company had 35 million Euros ($40.3 million) designated as a hedge of a net investment in a foreign operation. Changes in the foreign currency exchange rate have resulted in a cumulative change to the cumulative translation adjustment account of $1.2 million and ($3.0) million, net of taxes, as of December 31, 2005 and 2004, respectively.
NOTE P - INCOME PER SHARE
The following is a reconciliation of the common shares outstanding with the number of shares used in the computation of income per common and common equivalent share:
NOTE Q - INDUSTRY SEGMENTS AND GEOGRAPHIC INFORMATION
The Company manages its operations through four operating segments: Fluids, WA&D Services, Maritech and Production Enhancement. The Company has defined its Maritech operations as a separate operating segment within the WA&D Division due to the significant growth of Maritech during 2005. Prior year segment information for the WA&D Division has been adjusted to conform to the current year presentation.
The Company’s Fluids Division manufactures and markets clear brine fluids, additives, and other associated products and services to the oil and gas industry for use in well drilling, completion, and workover operations both domestically and in certain regions of Europe, Asia, Latin America and Africa. The Division also markets certain fluids and dry calcium chloride manufactured at its production facilities to a variety of markets outside the energy industry.
The WA&D Division consists of two operating segments: WA&D Services and Maritech. The WA&D Services segment provides a broad array of services required for the abandonment of depleted oil and gas wells and the decommissioning of platforms, pipelines, and other associated equipment, serving the onshore U.S. Gulf Coast region and the inland waters and offshore markets of the Gulf of Mexico. The WA&D Services segment also provides electric wireline, engineering, diving, workover and drilling services.
The Maritech segment consists of the Company’s Maritech subsidiary, which, with its subsidiaries, is a producer of oil and gas from properties acquired primarily to support and provide a baseload of business for the WA&D Services segment. In addition, the segment conducts development and exploitation operations on certain of its oil and gas properties, which are intended to increase the cash flows on such properties prior to their ultimate abandonment.
The Company’s Production Enhancement Division provides production testing services to the Texas, New Mexico, Louisiana, offshore Gulf of Mexico and certain international markets. In addition, it is engaged in the design, fabrication, sale, lease and service of wellhead compression equipment primarily used to enhance production from mature, low pressure natural gas wells located principally in the mid-continent, mid-western, Rocky Mountain, Texas and Louisiana regions of the United States as well as in western Canada and Mexico. The Division also provides the technology and services required for the separation and recycling of oily residuals generated from petroleum refining operations.
The Company generally evaluates performance and allocates resources based on profit or loss from operations before income taxes and nonrecurring charges, return on investment and other criteria. The accounting policies of the reportable segments are the same as those described in the summary of significant accounting policies. Transfers between segments, as well as geographic areas, are priced at the estimated fair value of the products or services as negotiated between the operating units. “Corporate overhead” includes corporate general and administrative expenses, depreciation and amortization, interest income and expense and other income and expense.
Summarized financial information concerning the business segments from continuing operations is as follows:
(1) Amounts reflected include the following general corporate expenses:
General and administrative expense
$22,495
$15,053
$13,005
Depreciation and amortization
Interest expense
6,297
1,930
Other general corporate (income)/expense, net
Total
$30,114
$17,828
$14,557
(2) Includes assets of discontinued operations.
Summarized financial information concerning the geographic areas in which the Company operates at December 31, 2005, 2004 and 2003 is presented below:
(1) Includes assets of discontinued operations.
In 2005, 2004 and 2003, no single customer accounted for more than 10% of the Company’s consolidated revenues.
NOTE R - SUPPLEMENTAL OIL AND GAS DISCLOSURES
The following information regarding the activities of the Company’s Maritech segment is presented pursuant to SFAS No. 69, “Disclosures About Oil and Gas Producing Activities (SFAS No. 69).” As part of the WA&D Division activities, Maritech and its subsidiaries acquire oil and gas reserves and operate the properties in exchange for assuming the proportionate share of the well abandonment obligations associated with such properties. Accordingly, the Company’s Maritech segment is included within its WA&D Division.
Costs Incurred in Property Acquisition, Exploration and Development Activities
The following table reflects the costs incurred in oil and gas property acquisition, exploration and development activities during the years indicated. Consideration given for the acquisition of proved properties includes the assumption of the proportionate share of the well abandonment and decommissioning obligations associated with the properties. Costs incurred for the acquisition of proved properties also include the impact to the Company from the adoption of SFAS No. 143 on January 1, 2003, which resulted in a reduction of such costs of $1.5 million during 2003, and subsequent revisions to its decommissioning liabilities.
Capitalized Costs Related to Oil and Gas Producing Activities:
Aggregate amounts of capitalized costs relating to the Company’s oil and gas producing activities and the aggregate amounts of related accumulated depletion, depreciation and amortization as of the dates indicated, are presented below.
Included in capitalized costs of proved developed properties being amortized is the Company’s estimate of its proportionate share of decommissioning liabilities assumed relating to these properties, which is also reflected as decommissioning liabilities in the accompanying consolidated balance sheets.
Results of Operations for Oil and Gas Producing Activities:
Results of operations for oil and gas producing activities excludes general and administrative and interest expenses directly related to such activities as well as any allocation of corporate or divisional overhead.
Estimated Quantities of Proved Oil and Gas Reserves (Unaudited):
The following information is presented with regard to the Company’s proved oil and gas reserves. The reserve values and cash flow amounts reflected in the following reserve disclosures are based on prices as of year end. Proved oil and gas reserve quantities are reported in accordance with guidelines established by the SEC. Ryder Scott Company, L.P. prepared the estimates for all of the Company’s
reserves at December 31, 2005, 2004 and 2003, with the exception of one producing field as of December 31, 2005, which was prepared by the Company. All of Maritech’s reserves are located in U. S. state and federal offshore waters of the Gulf of Mexico and onshore Louisiana.
Proved oil and gas reserves are defined as the estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Reservoirs are considered proved if economic productibility is supported by either actual production or conclusive formation tests. The area of a reservoir considered proved includes (a) that portion delineated by drilling and defined by gas-oil and/or gas-water contacts, if any, and (b) the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data. Reserves which can be produced economically through application of improved recovery techniques are included in the “proved” classification when successful testing by a pilot project, or the operation of an installed program in the reservoir, provides support for the engineering analysis on which the project or program was based.
The reliability of reserve information is considerably affected by several factors. Reserve information is imprecise due to the inherent uncertainties in, and the limited nature of, the database upon which the estimating of reserve information is predicated. Moreover, the methods and data used in estimating reserve information are often necessarily indirect or analogical in character, rather than direct or deductive. Furthermore, estimating reserve information, by applying generally accepted petroleum engineering and evaluation principles, involves numerous judgments based upon the engineer’s educational background, professional training and professional experience. The extent and significance of the judgments to be made are, in themselves, sufficient to render reserve information inherently imprecise.
Reserve Quantity Information
Oil
Gas
(MBbls)
(MMcf)
Total proved reserves at December 31, 2002
10,004
Revisions of previous estimates
(556
)
Production
(473
)
(3,953
)
Extensions and discoveries
1,314
1,654
Purchases of reserves in place
6,776
Sales of reserves in place
-
-
Total proved reserves at December 31, 2003
3,275
13,925
Revisions of previous estimates
(301
)
1,223
Production
(502
)
(4,101
)
Extensions and discoveries
6,615
Purchases of reserves in place
4,986
Sales of reserves in place
-
(243
)
Total proved reserves at December 31, 2004
2,646
22,405
Revisions of previous estimates
(3,421
)
Production
(484
)
(5,088
)
Extensions and discoveries
3,195
Purchases of reserves in place
5,703
29,900
Sales of reserves in place
(800
)
(4,717
)
Total proved reserves at December 31, 2005
7,987
42,274
Oil
Gas
Proved Developed Reserves
(MBbls)
(MMcf)
December 31, 2003
1,593
10,332
December 31, 2004
1,127
15,356
December 31, 2005
6,372
35,091
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves:
The standardized measure of discounted future net cash flows and changes in such cash flows are prepared using procedures prescribed by SFAS No. 69. As prescribed by SFAS No. 69, “standardized measure” relates to the estimated discounted future net cash flows and major components of that calculation relating to proved reserves at the end of the year in the aggregate, based on year end prices, costs, and statutory tax rates and using a 10% annual discount rate. The standardized measure is not an estimate of the fair value of proved oil and gas reserves. Probable and possible reserves, which may become proved in the future, are excluded from the calculations. Furthermore, year end prices, used to determine the standardized measure, are influenced by seasonal demand and other factors and may not be representative in estimating future revenues or reserve data.
The standardized measure of discounted future net cash flows relating to proved oil and gas reserves attributed to the Company’s oil and gas properties is as follows:
Changes in Standardized Measure of Discounted Future Net Cash Flows:
NOTE S - QUARTERLY FINANCIAL INFORMATION (Unaudited)
Summarized quarterly financial data from continuing operations for 2005 and 2004 is as follows:
(1) The amounts for gross profit for each of the periods presented reflect the reclassification into cost of revenues of certain depreciation, amortization and accretion expenses, which had previously been classified as general and administrative expense. The reclassified amounts were $1,041, $1,124, $1,701, and $2,319 during the quarters ended March 31, June 30, September 30 and December 31, 2005, respectively. The reclassified amounts were $733, $800, $1,008 and $ 1,078 during the quarters ended March 31, June 30, September 30, and December 31, 2004, respectively. The reclassification conforms to the current year presentation and had no effect on net income for the periods presented.
NOTE T - STOCKHOLDERS’ RIGHTS PLAN
On October 27, 1998, the Board of Directors adopted a stockholders’ rights plan (the Rights Plan) designed to assure that all of the Company’s stockholders receive fair and equal treatment in the event of any proposed takeover of the Company. The Rights Plan helps to guard against partial tender offers, open market accumulations and other abusive tactics to gain control of the Company without paying an adequate and fair price in any takeover attempt. The Rights are not presently exercisable and are not represented by separate certificates. The Company is currently not aware of any effort of any kind to acquire control of the Company.
Terms of the Rights Plan provide that each holder of record of an outstanding share of common stock subsequent to November 6, 1998, receive a dividend distribution of one Preferred Stock Purchase Right. The Rights Plan would be triggered if an acquiring party accumulates or initiates a tender offer to purchase 20% or more of the Company’s Common Stock and would entitle holders of the Rights to purchase either the Company’s stock or shares in an acquiring entity at half of market value. Each Right entitles the holder thereof to purchase 1/100 of a share of Series One Junior Participating Preferred Stock for $50.00 per share, subject to adjustment. The Company would generally be entitled to redeem the Rights at $.01 per Right at any time until the tenth day following the time the Rights become exercisable. The Rights will expire on November 6, 2008.
For a more detailed description of the Rights Plan, refer to the Company’s Form 8-K filed with the SEC on October 28, 1998.
TETRA TECHNOLOGIES, INC. AND SUBSIDIARIES
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
(In Thousands)
Balance at Beginning of Period
Charged to Costs and Expenses
Charged to Other Accounts - Describe
Deductions - Describe
Balance at End of Period
Year ended December 31, 2003:
Allowance for doubtful accounts
$2,355
$170
$(2
)
$(1,200
)(1)
$1,323
Inventory reserves
$237
$-
$-
$(35
)(2)
$202
Year ended December 31, 2004:
Allowance for doubtful accounts
$1,323
$(257
)
$148
(3)
$(730
)(1)
$484
Inventory reserves
$202
$-
$-
$(54
)(2)
$148
Year ended December 31, 2005:
Allowance for doubtful accounts
$484
$668
$-
$(374
)(1)
$778
Inventory reserves
$148
$17
$-
$-
(2)
$165
(1) Uncollectible accounts written off, net of recoveries.
(2) Write-off of obsolete and/or worthless inventory.
(3) Includes $158,000 of allowance for doubtful accounts added from acquisition of businesses.
S-1