UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON D.C. 20549
FORM 10-K
(MARK ONE)
[ X ] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
FOR THE FISCAL YEAR ENDED DECEMBER 31, 2007
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
FOR THE TRANSITION PERIOD FROM TO
COMMISSION FILE NO. 1-13455
TETRA Technologies, Inc.
(EXACT NAME OF THE REGISTRANT AS SPECIFIED IN ITS CHARTER)
| DELAWARE |
74-2148293 |
| (STATE
OR OTHER JURISDICTION OF |
(I.R.S.
EMPLOYER |
| INCORPORATION
OR ORGANIZATION) |
IDENTIFICATION
NO.) |
| |
|
| 25025
INTERSTATE 45 NORTH, SUITE 600 |
77380 |
| THE
WOODLANDS, TEXAS |
(ZIP
CODE) |
| (ADDRESS
OF PRINCIPAL EXECUTIVE OFFICES) |
|
| |
|
| (REGISTRANT'S
TELEPHONE NUMBER, INCLUDING AREA CODE): (281)
367-1983 |
|
SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:
COMMON
STOCK, PAR VALUE $.01 PER SHARE |
NEW
YORK STOCK EXCHANGE |
(TITLE
OF CLASS) |
(NAME
OF EXCHANGE ON WHICH REGISTERED) |
RIGHTS
TO PURCHASE SERIES ONE |
|
JUNIOR
PARTICIPATING PREFERRED STOCK |
NEW
YORK STOCK EXCHANGE |
(TITLE
OF CLASS) |
(NAME
OF EXCHANGE ON WHICH REGISTERED) |
SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT: NONE
INDICATE BY CHECK MARK IF THE REGISTRANT IS A WELL-KNOWN SEASONED ISSUER (AS DEFINED IN RULE 405 OF THE SECURITIES ACT). YES [ X ] NO [ ]
INDICATE BY CHECK MARK IF THE REGISTRANT IS NOT REQUIRED TO FILE REPORTS PURSUANT TO SECTION 13 OR SECTION 15(d) OF THE EXCHANGE ACT. YES [ ] NO [ X ]
INDICATE BY CHECK MARK WHETHER THE REGISTRANT (1) HAS FILED ALL REPORTS REQUIRED TO BE FILED BY SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 DURING THE PRECEDING 12 MONTHS (OR FOR SUCH SHORTER PERIOD THAT THE REGISTRANT WAS REQUIRED TO FILE SUCH REPORTS) AND (2) HAS BEEN SUBJECT TO SUCH FILING REQUIREMENTS FOR THE PAST 90 DAYS. YES [ X ] NO [ ]
INDICATE BY CHECK MARK IF DISCLOSURE OF DELINQUENT FILERS PURSUANT TO ITEM 405 OF REGULATION S-K IS NOT CONTAINED HEREIN, AND WILL NOT BE CONTAINED, TO THE BEST OF REGISTRANT'S KNOWLEDGE, IN DEFINITIVE PROXY OR INFORMATION STATEMENTS INCORPORATED BY REFERENCE IN PART III OF THIS FORM 10-K OR ANY AMENDMENT TO THIS FORM 10-K. [ ]
INDICATE BY CHECK MARK WHETHER THE REGISTRANT IS A LARGE ACCELERATED FILER, AN ACCELERATED FILER, A NON-ACCELERATED FILER, OR A SMALL REPORTING COMPANY (SEE DEFINITIONS OF "ACCELERATED FILER," "LARGE ACCELERATED FILER," AND "SMALLER REPORTING COMPANY" IN RULE 12b-2 OF THE EXCHANGE ACT). (CHECK ONE):
LARGE ACCELERATED FILER [ X ] ACCELERATED FILER [ ] NON-ACCELERATED FILER [ ] SMALLER REPORTING COMPANY [ ]
INDICATE BY CHECK MARK WHETHER THE REGISTRANT IS A SHELL COMPANY (AS DEFINED IN RULE 12b-2 OF THE EXCHANGE ACT). YES [ ] NO[ X ]
THE AGGREGATE MARKET VALUE OF COMMON STOCK HELD BY NON-AFFILIATES OF THE REGISTRANT WAS $2,060,905,209 AS OF JUNE 30, 2007, THE LAST BUSINESS DAY OF THE REGISTRANT'S MOST RECENTLY COMPLETED SECOND FISCAL QUARTER.
NUMBER OF SHARES OUTSTANDING OF THE ISSUER'S COMMON STOCK AS OF FEBRUARY 27, 2008 WAS 74,456,481 SHARES.
PART III INFORMATION IS INCORPORATED BY REFERENCE TO THE REGISTRANT'S PROXY STATEMENT FOR ITS ANNUAL MEETING OF STOCKHOLDERS TO BE HELD MAY 9, 2008 TO BE FILED WITH THE SECURITIES AND EXCHANGE COMMISSION WITHIN 120 DAYS OF THE END OF THE REGISTRANT'S FISCAL YEAR.
TABLE OF CONTENTS
This Annual Report on Form 10-K contains “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended, including, without limitation, statements concerning future sales, earnings, costs, expenses, acquisitions or corporate combinations, asset recoveries, working capital, capital expenditures, financial condition, and other results of operations. Such statements reflect our current views with respect to future events and financial performance and are subject to certain risks, uncertainties and assumptions, including those discussed in “Item 1A. Risk Factors.” Should one or more of these risks or uncertainties materialize, or should underlying assumptions prove incorrect, actual results may vary materially from those anticipated, believed, estimated, or projected. Unless the context requires otherwise, when we refer to “we,” “us,” and “our,” we are describing TETRA Technologies, Inc. and its subsidiaries on a consolidated basis.
PART I
General
We are an oil and gas services and production company with an integrated calcium chloride and brominated products manufacturing operation that supplies feedstocks to energy markets, as well as to other markets. We are composed of three divisions – Fluids, Well Abandonment & Decommissioning (WA&D), and Production Enhancement.
Our Fluids Division manufactures and markets clear brine fluids, additives, and other associated products and services to the oil and gas industry for use in well drilling, completion, and workover operations both 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.
Our WA&D Division consists of two operating segments: WA&D Services and an oil and gas production segment, 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. The WA&D Services segment also provides diving, marine, engineering, cutting, workover, drilling, and other services. The WA&D Services segment operates primarily in the onshore U.S. Gulf Coast region and the inland waters and offshore markets of the Gulf of Mexico.
The Maritech segment consists of our Maritech Resources, Inc. (Maritech) subsidiary, which, with its subsidiaries, is a producer of oil and gas from properties acquired to support and provide a baseload of business for the WA&D Services segment. In addition, Maritech conducts development and exploitation operations on certain of its oil and gas properties that are intended to increase the cash flows on such properties prior to their ultimate abandonment.
Our Production Enhancement Division provides production testing services to markets in Texas, New Mexico, Colorado, Oklahoma, Arkansas, Louisiana, offshore Gulf of Mexico, and certain international locations. In addition, it provides wellhead compression services to customers to enhance production from mature, low pressure natural gas wells located principally in the mid-continent, mid-western, western, Rocky Mountain, and Gulf Coast regions of the United States as well as in western Canada, Mexico, and other Latin American countries.
We continue to pursue a growth strategy that includes expanding our existing businesses – both through internal growth and through the pursuit of suitable acquisitions – and by identifying opportunities to establish operations in additional domestic and international niche oil service markets. For financial information for each of our segments, including information regarding revenues and total assets, see “Note Q – Industry Segments and Geographic Information” contained in the Notes to Consolidated Financial Statements.
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We were incorporated in Delaware in 1981. Our corporate headquarters are located at 25025 Interstate 45 North, Suite 600, in The Woodlands, Texas. Our phone number is 281-367-1983 and our website is accessed at www.tetratec.com. We make available, free of charge, on our website, our Corporate Governance Guidelines, Code of Business Conduct and Ethics, Code of Ethics for Senior Financial Officers, Audit Committee Charter, Management and Compensation Committee Charter, and Nominating and Corporate Governance Committee Charter as well as our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and all amendments to those reports as soon as is reasonably practicable after such materials are electronically filed with, or furnished to, the Securities and Exchange Commission (SEC). Information filed with the SEC may be read or copied at SEC’s Public Reference Room at 100 F Street, N.E., Washington D.C. 20549. Information on operation of the Public Reference Room may be obtained by calling the SEC at 1-800-SEC-0330. The SEC also maintains an internet website (http://www.sec.gov) that contains reports, proxy, and information statements, and other information regarding issuers that file electronically. We will also make these available in print, free of charge, to any stockholder who requests such information from the Corporate Secretary.
Products and Services
Fluids Division
Liquid calcium chloride, sodium bromide, calcium bromide, zinc bromide, and similar products produced by our Fluids Division are referred to as clear brine fluids (CBFs) in the oil and gas industry. CBFs are solids-free, clear salt solutions that, like conventional drilling “muds,” have high specific gravities and are used as weighting fluids to control bottomhole pressures during oil and gas completion and workover activities. The use of CBFs increases production by reducing the likelihood of damage to the wellbore and productive pay zone. CBFs are particularly important in offshore completion and workover operations due to the greater formation sensitivity, the significantly greater investment necessary to drill offshore, and the consequent higher cost of error. CBFs are manufactured and distributed through our Fluids Division and are also sold to other companies that service customers in the oil and gas industry.
Our Fluids Division provides basic and custom blended CBFs to domestic and international oil and gas well operators, based on the specific need of the customer and the proposed application of the product. We also provide these customers with a broad range of associated services, including onsite fluid filtration, handling, and recycling; fluid engineering consultation; and fluid management, including high volume water transfer services in support of high pressure fracturing processes. We expanded our fluids services operations with the April 2007 acquisition of a fluids transfer operation that allowed the Division to provide such services in the Arkansas, TexOma, and ArkLaTex regions. We also repurchase used CBFs from operators and recycle and recondition these materials. The utilization of reconditioned CBFs reduces the net cost of the CBFs to our customers and minimizes the need for disposal of used fluids. We recycle and recondition the CBFs through filtration, blending, and the use of proprietary chemical processes, and then market the reconditioned CBFs.
The Division’s fluid engineering and management personnel use proprietary technology to determine the proper blend for a particular application to maximize the effectiveness and lifespan of the CBFs. We modify the specific volume, density, crystallization temperature, and chemical composition of the CBFs to satisfy a customer’s specific requirements. Our filtration services use a variety of techniques and equipment for the onsite removal of particulates from CBFs, so that those CBFs can be recirculated back into the well. Filtration also enables recovery of a greater percentage of used CBFs for recycling.
The manufacturing group of the Fluids Division obtains product from numerous production facilities that manufacture liquid and/or dry calcium chloride, sodium bromide, calcium bromide, zinc bromide and/or zinc calcium bromide for distribution into energy markets. Liquid and dry calcium chloride are also sold into the water treatment, industrial, cement, food processing, dust control, ice melt, agricultural, and consumer products markets. Liquid sodium bromide is also sold into the industrial water treatment markets, where it is used as a biocide in recirculated cooling tower waters. We operate our European calcium chloride manufacturing operations under the trade name of TCE.
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We obtain calcium chloride from production facilities in the United States, Canada, China, and Europe. We own some of these plants, and we obtain production from the non-owned plants under written agreements with the owners. Dry calcium chloride is produced at our Kokkola, Finland plant, which has a production capacity of 165,000 tons per year. We also own a calcium chloride plant in Lake Charles, Louisiana, with a production capacity of 100,000 tons of dry product per year. In addition, we have begun development of a new calcium chloride plant near El Dorado, Arkansas, to produce liquid and flake calcium chloride beginning in late 2009. We also have 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 bromine or hydrobromic acid, along with various zinc sources, to manufacture its products. The group purchases raw material bromine pursuant to a new long-term supply agreement, which was executed in late 2006. This facility uses patented and proprietary technologies to recondition and upgrade used CBFs repurchased from our customers.
We also retain approximately 33,000 gross acres of bromine-containing brine reserves in Magnolia, Arkansas that are under lease. We hold these assets for possible future development.
See “Note Q – Industry Segments and Geographic Information” in the Notes to Consolidated Financial Statements for financial information about this Division.
Well Abandonment & Decommissioning (WA&D) Division
Our 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 primarily onshore and in the inland waters of Texas and Louisiana and offshore in the Gulf of Mexico. In addition, WA&D Services provides diving, marine, engineering, cutting, workover, drilling, and other 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 that are intended to increase the cash flows on such properties prior to their ultimate abandonment.
In providing our well abandonment and decommissioning services, we own and operate onshore rigs, barge-mounted rigs, a platform rig, offshore rigless packages, three heavy lift vessels, several dive support vessels, and other dive support assets. In addition, we rent certain equipment from third party contractors whenever necessary. The WA&D Services segment’s integrated package of services also includes the specialized equipment and engineering expertise necessary to address the specific well abandonment and decommissioning issues associated with toppled and severely damaged platforms as a result of the 2005 hurricanes in the Gulf of Mexico, as well as engineering services, project management, and other operations required to plug wells and decommission wellhead equipment, pipelines, and platforms. The Division also provides well abandonment services to customers in the inland waters and onshore in Texas and Louisiana. The Division provides a full array of contract diving services to its customers through its Epic Diving & Marine Services (Epic) operations, which we acquired in March 2006. In September 2007, we acquired the assets and operations of EOT Rentals, LLC (EOT), a business which provides onshore and offshore cutting services and tool rentals. Prior to the acquisition of EOT, we contracted these services from third parties, including EOT. The Division’s electric wireline operations provide pressure transient testing, reservoir evaluation, well performance evaluation, cased hole and memory production logging, perforating, bridge plug and packer services, and pipe recovery services. The Division provides services to major oil and gas companies and independent operators, including Maritech, through its facilities located in Belle Chasse, Broussard, Harvey, and Houma, Louisiana and in Bryan, and Victoria, Texas.
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The size of our WA&D Division’s fleet of service vessels has been adjusted in recent years to serve the changing demand for well abandonment, platform decommissioning, diving, and other offshore services. We currently have three vessels with the capacity to perform heavy lift projects and integrated operations on oil and gas production platforms. Subsequent to our acquisition of Epic, we purchased a dynamically positioned dive support vessel, which we renamed the Epic Diver, and refurbished two of Epic’s existing dive support vessels, the Epic Explorer and the Epic Seahorse. Both the Epic Diver and the Epic Explorer offer saturation diving systems which are rated for up to 1,000 foot dive depth. These three support vessels were placed in service in January and February 2007, further expanding Epic’s capacity to serve its customers through its increased saturation diving capabilities.
Through Maritech and its subsidiaries, the Division acquires, manages, develops, and exploits mature producing oil and gas properties in the offshore and inland water region of the Gulf of Mexico. These producing properties were historically purchased primarily to support the Division’s WA&D Services businesses, although one of Maritech’s most recent acquisitions was acquired as much for its exploitation and development potential (see discussion below). Maritech conducts development and exploitation operations on a number of its oil and gas properties, which are intended to increase the cash flows on such properties prior to their ultimate abandonment. 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. Maritech’s activities 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. The most recent acquisitions of oil and gas properties took place in December 2007 and January 2008, when we purchased oil and gas producing properties in three separate transactions in exchange for an aggregate of $74.0 million of cash and the assumption of associated decommissioning liabilities having an undiscounted value of approximately $53.6 million. In December 2007, we acquired interests in certain offshore properties located primarily in the Main Pass area of the Gulf of Mexico from a subsidiary of Cimarex Energy (which we refer to as the Cimarex Properties). An additional interest in one of the Cimarex Properties was also acquired in a separate transaction from an unrelated third party. A majority of the productive properties will begin production in mid 2008 following the completion of a connecting pipeline and the hookup of six subsea wells. Maritech is constructing this connecting pipeline, at an estimated cost of approximately $26.9 million, which will also serve other producing properties operated by third parties. In addition, the acquired properties include numerous development prospects, and strategic opportunities involving certain of Maritech’s existing infrastructure assets, which we intend to exploit over the next several years. In order to fund a portion of these development activities, we plan to sell a portion of certain of the Cimarex Properties for cash as early as March 2008. In January 2008, we acquired certain offshore oil and gas producing properties from Stone Energy Corporation. In addition, during the three year period ended December 31, 2007, Maritech significantly increased its acquisition, exploitation and development activities, expending approximately $293.4 million on such projects. As a result of this acquisition and development activity, at December 31, 2007, Maritech had proved reserves of approximately 6.7 million barrels of oil and 46.8 billion cubic feet of natural gas, with undiscounted future net pretax cash flow of approximately $498.1 million. Maritech’s most recent acquisitions provide it with a large portfolio of development and exploitation prospects.
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, Colorado, Oklahoma, Arkansas, Louisiana, offshore Gulf of Mexico, Mexico, Brazil, and Middle East markets. These services involve
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sophisticated evaluation techniques needed for reservoir management and optimization of well workover programs. During 2007, we expanded our domestic testing operations in the Rocky Mountain region of the United States.
The Division maintains one of the largest fleets of high pressure production testing equipment in the United States, with operating locations in Edinburg, Laredo, Palestine, Benbrook, Midland, and Victoria, Texas. The Division also has operating locations in Artesia, New Mexico; Parachute, Colorado; New Iberia and Bossier City, Louisiana; Reynosa, Villahermosa, Poza Rica, and Veracruz, Mexico; Macae, Brazil; and Dammam, Saudi Arabia.
The Division’s Compressco, Inc. (Compressco) operation provides production enhancement services to low pressure natural gas wells utilizing wellhead compressors to boost gas production in mature gas wells by reducing bottomhole pressure, removing wellbore liquids, and overcoming higher gas pipeline delivery pressure problems. Compressco’s fleet of patented design compressor equipment and experienced personnel allow us to assist oil and gas operators in increasing daily production volumes and extending the productive lives of low volume or marginal gas and oil wells. To a lesser extent, Compressco also sells compressor units, and provides other related services. Compressco’s fleet of GasJack® units totaled 3,108 as of December 31, 2007, of which 2,763 units were in service, representing an increase in the number of units in service of approximately 20% from the prior year.
Compressco designs and fabricates its GasJack compressor utilizing a 460 cubic inch V-8 engine, which is 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. Compressco primarily uses these compressor units in conjunction with its personnel to provide compression services to its customers, primarily on a month to month basis. Compressco services its compressors and provides maintenance service on sold units, through a staff of mobile field technicians, who are based throughout Compressco’s market areas.
In December 2007, we disposed of our process services operation through a sale of the associated assets and operations for total cash proceeds of approximately $58.7 million, net of certain adjustments. Our process services operation provided the technology and services required for the separation and reuse of oil bearing materials generated from petroleum refining operations. Our process services operation was not considered to be a strategic part of our core business.
See “Note Q – Industry Segments and Geographic Information” in the Notes to Consolidated Financial Statements for financial information about this Division.
Sources of Raw Materials
Our Fluids Division manufactures calcium chloride, sodium bromide, calcium bromide, zinc bromide, and zinc calcium bromide for distribution to its customers. The Division also purchases calcium chloride, calcium bromide, sodium bromide, sodium chloride, and potassium chloride 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, and from natural brine reserves. The Division also purchases calcium chloride from a number of chemical manufacturers, both domestically and internationally. Some of the Division’s primary sources of hydrochloric acid are chemical co-product streams obtained from chemical manufacturers. We have written agreements with certain of those chemical companies regarding the supply of hydrochloric acid or calcium chloride. In October 2005, one of the Division’s main hydrochloric acid 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. Since that time, we have replaced a large portion of this supply through the use of a variety of alternative sources, allowing our Lake Charles facility to continue to produce liquid calcium chloride, although total production levels have been lower than pre-October 2005 levels. In January 2008, we entered into a five year agreement with a supplier, whereby raw materials inventory from its Baton Rouge, Louisiana facility will be supplied to our Lake Charles facility. This supply agreement will allow us to resume production of dry calcium chloride
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from our Lake Charles facility, supplementing its existing liquid calcium chloride production. We also produce calcium chloride through evaporation at our two plants in San Bernardino County, California from underground brine reserves. These brines are deemed adequate to supply our foreseeable need for calcium chloride in that market area. Substantial quantities of limestone are also consumed when converting hydrochloric acid into calcium chloride. We use a proprietary process that permits the use of less expensive limestone, while maintaining end-use product quality. We purchase limestone from several different sources. Currently, hydrochloric acid and limestone are generally available from multiple sources. In addition, we purchase liquid calcium chloride from a Delfzijl, Netherlands plant owned by a joint venture in which we have a 50% ownership interest.
To significantly increase our existing production capacity, we have begun development of a new calcium chloride manufacturing plant located on land purchased from and adjacent to the Chemtura Corporation (Chemtura) central bromine plant, located near El Dorado, Arkansas. This new plant, which is being designed to produce liquid and flake calcium chloride, along with other co-products such as magnesium hydroxide and sodium chloride, is expected to allow the Division to reduce its dependence on third party suppliers. The plant will utilize depleted brines obtained from Chemtura’s operations. Construction of the new El Dorado calcium chloride plant is expected to be completed in late 2009.
To produce calcium bromide, zinc bromide, and zinc calcium bromide at our West Memphis, Arkansas facility, we use primarily bromine and various sources of zinc raw materials and lime. We use proprietary and patented processes that permit the use of cost-advantaged raw materials, while maintaining high product quality. There are multiple sources of zinc that we can use in the production of zinc bromide. In December 2006, we entered into a long-term supply agreement with Chemtura, whereby the Division will purchase its requirements of raw material bromine from Chemtura’s Arkansas bromine facilities. In addition, Chemtura will supply the Division’s new El Dorado calcium chloride plant with tail brine from its Arkansas facilities following bromine extraction. Upon entering the long-term Chemtura supply agreement, we amended our previous less favorable long-term supply agreement for calcium bromide. As part of this amendment, we agreed to meet certain purchase requirements through 2008. In December 2007, we entered into an agreement with our previous supplier whereby we were released from our remaining purchase requirements and the supply agreement was terminated in exchange for future payments totaling approximately $9.3 million to be made in 2008 and early 2009.
We also own a calcium bromide manufacturing plant near Magnolia, Arkansas that was constructed in 1985. This plant was acquired in 1988 and is not operable. We currently have approximately 33,000 gross acres of bromine-containing brine reserves under lease in the vicinity of this plant. While this plant is designed to produce calcium bromide, it could be modified to produce elemental bromine or select bromine compounds. We believe we have sufficient brine reserves under lease to operate a world-scale bromine facility for 25 to 30 years. Development of the brine field, construction of necessary pipelines and reconfiguration of the plant would require a substantial capital investment. The execution of the Chemtura bromine supply agreement discussed above provides us with an immediate supply of bromine to support the Division’s current operations. We do, however, continue to evaluate our strategy related to the Magnolia, Arkansas assets and their future development. Chemtura holds certain rights to participate in the development of the Magnolia, Arkansas assets.
Our Production Enhancement Division, through our Compressco operation, designs and fabricates natural gas wellhead compressors. All of our compressor models share many components that are obtained from a single source or a limited group of suppliers.
Market Overview and Competition
Fluids Division
Our Fluids Division 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. We also sell sodium bromide into the industrial water treatment markets as a biocide under the BioRid® trade name. 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 Africa. The Division’s principal competitors in the sale of CBFs to the oil and
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gas industry are Baroid Corporation, a subsidiary of Halliburton Company; M-I L.L.C., a joint venture between Smith International, Inc. and Schlumberger Limited; and BJ Services Company. This market is highly competitive and competition is based primarily on service, availability and price. Although all competitors provide fluid handling, filtration, and recycling services, we believe that our historical focus on providing these and other value-added services to our customers has enabled us to compete successfully. Major customers of the Fluids Division include Anadarko, Chevron, Devon, Dominion Resources, EOG Resources, Halliburton Company, LLOG Exploration, Newfield Exploration Company, Nippon Oil Exploration, and Shell Oil. The Division also sells its products through various distributors worldwide.
Our liquid and dry calcium chloride products have a wide range of uses outside the energy industry. The non-energy market segments to which our products are marketed include agricultural, industrial, 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. Most of these markets are highly competitive. The Division’s European calcium chloride manufacturing operations based in Kokkola, Finland permit us to market our calcium chloride products to certain European markets. Our major competitors in the calcium chloride market include Dow Chemical Company and Industrial del Alkali in North America, and Brunner Mond, Solvay, and NedMag in Europe.
WA&D Division
Our WA&D Division consists of our WA&D Services and Maritech operations. The Division’s WA&D Services operation provides well abandonment and decommissioning services offshore, primarily 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 the maturity and decline of producing fields in the Gulf of Mexico, aging offshore platform infrastructure, damage from storms, and government regulations. In the market areas in which we currently compete, regulations generally require wells to be plugged, offshore platforms decommissioned, pipelines abandoned, and the well site cleared within twelve months after an oil or gas lease expires. The maturity and production decline of Gulf of Mexico oil and gas fields has, over time, caused an increase in the number of wells to be plugged and abandoned and platforms and pipelines to be decommissioned. Current and projected demand for abandonment and decommissioning services has also been affected by 2005 hurricane activity in the Gulf of Mexico, which destroyed or caused significant damage to a large number of offshore platforms. The Division has developed specialized equipment and engineering expertise to provide such services to customers whose offshore wells and production platforms were toppled, destroyed, or heavily damaged by such storms. The threat of future storm activity, combined with 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 occurring during the months of April through October when weather conditions are most favorable. Critical factors required to participate in the current market include among other factors: having an adequate fleet of the proper equipment to meet current market demand and conditions; having qualified, experienced personnel; having technical expertise to address varying downhole, surface, and subsea conditions, particularly those related to damaged wells and platforms; having the financial strength to ensure all abandonment and decommissioning obligations are satisfied; and having a comprehensive safety and environmental program. We believe our integrated service package and expanded vessel fleet satisfies these market requirements, allowing us to successfully compete.
The Division markets its services primarily to major oil and gas companies and independent operators. Major customers include Apache, Chevron, ConocoPhillips, ExxonMobil, Forest Oil, Mariner Energy, Neumin Production, Newfield Exploration, Pioneer, Shell Oil, Stone Energy, and W&T Offshore. These services are performed onshore primarily in Texas and Louisiana, in the Gulf Coast inland waters, and offshore in the U.S. Gulf of Mexico. Our principal competitors in the offshore and inland water markets are Global Industries, Ltd., Offshore Specialties, Inc., Helix Energy Solutions, Cal Dive International, Inc., and Superior Energy Services, Inc. This market is highly competitive and competition is based primarily on service, equipment availability, safety record, and price. Our ability to successfully bid our services can fluctuate from year to year, depending on market conditions.
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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. We typically acquire oil and gas properties from major oil and gas companies as well as independent operators. Our ability to acquire producing oil and gas properties under acceptable terms is dependent on numerous factors, including oil and natural gas commodity prices, the availability of suitable properties for acquisition, the age and condition of offshore production platforms, and the level of competition from other operators pursuing such properties. Maritech sells its oil and gas production to a variety of purchasers, however, for the year ended December 31, 2007, Maritech had one customer, Shell Trading (US) Company, that accounted for 12.5% of our consolidated revenues. We did not have any other individual customer account for more than 10% of our consolidated revenues. We compete for the acquisition of producing properties with other companies also seeking to provide baseload support for their affiliated well abandonment and decommissioning service operations, as in the case of Superior Energy Services, Inc. and their oil and gas subsidiary, SPN Resources, LLC.
Production Enhancement Division
The Production Enhancement Division provides production testing and wellhead compression services and products to its customers. Production testing services are provided primarily to the natural gas segment of the oil and gas industry. In certain gas producing basins, water, sand, and other abrasive materials will commonly accompany the initial production of natural gas, often under high pressures. The Division provides the equipment and qualified personnel to remove these impediments to production and to pressure test wells and wellhead equipment. The Division also provides certain production testing and laboratory testing services for oil producing properties.
The production testing market is highly competitive, and competition is based on availability of equipment and qualified personnel, as well as price, quality of service, and safety record. We believe our equipment maintenance program and operating procedures give us a competitive advantage in the marketplace. Competition in onshore markets is dominated by numerous small, privately owned operators. Schlumberger Limited and Expro International are major competitors in the U.S. offshore market and international markets. Our customers include, among others, Chesapeake, ConocoPhillips, El Paso Corporation, Encana Oil & Gas, Quicksilver Resources, Shell Oil, PEMEX (the national oil company of Mexico), Petrobras (the national oil company of Brazil) and ARAMCO (the national oil company of Saudi Arabia).
The Division’s Compressco operation utilizes wellhead compression equipment to provide production enhancement services 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 in the south central United States; however, Compressco also serves a wide variety of other geographic operating areas, including the mid-continent, mid-western, western, Rocky Mountain, and Gulf Coast regions of the United States and internationally in western Canada, Mexico, and other areas of Latin America. We continue to seek opportunities to further expand Compressco’s operations into other regions in the Western Hemisphere and elsewhere in the world. Compressco’s competitors include Natural Gas Services, Exterran, 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. We believe that Compressco’s patented technology helps it to maintain a competitive position in the markets which it serves. Compressco’s major customers include BP, Chesapeake, Devon, and ConocoPhillips.
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, we believe that our Fluids Division’s 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
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CBFs to selected international markets, including the British and Norwegian sectors of the North Sea, Mexico, Brazil, Africa, Europe, the Middle East, and the Far East.
Non-oilfield calcium chloride products are also marketed through the Division’s sales offices 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 our estimated future revenues because a majority of our products and services either are not sold under long-term contracts or do not require long lead times to procure or deliver. Our backlog consists of estimated future revenues associated with a portion of our well abandonment and decommissioning business, and consists of the non-Maritech share of the well abandonment and decommissioning work associated with the oil and gas properties operated by Maritech. Our estimated backlog on December 31, 2007 was $175.5 million, of which approximately $18.5 million is expected to be billed during 2008. This compares to an estimated backlog of $107.6 million at December 31, 2006.
Employees
As of December 31, 2007, we had 2,895 employees. None of our U.S. employees are presently covered by a collective bargaining agreement, other than the employees of our Lake Charles, Louisiana calcium chloride production facility, who are represented by the United Steelworkers Union. Our international employees are generally members of the various labor unions and associations common to the countries in which we operate. We believe that our relations with our employees are good.
Patents, Proprietary Technology, and Trademarks
As of December 31, 2007, we owned or licensed twenty-three issued U.S. patents and had five patent applications pending in the United States. Internationally, we had thirteen issued foreign patents and eighteen 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 2024. We have elected to maintain certain other internally developed technologies, know-how, and inventions as trade secrets. While we believe that the protection of our patents and trade secrets is important to our competitive positions in our businesses, we do not believe any one patent or trade secret is essential to our success.
It is our practice to enter into confidentiality agreements with key employees, consultants, and third parties to whom we disclose our confidential and proprietary information. There can be no assurance, however, that these measures will prevent the unauthorized disclosure or use of our trade secrets and expertise or that others may not independently develop similar trade secrets or expertise. Our management believes, however, that it would require a substantial period of time, and substantial resources, to independently develop similar know-how or technology. As a policy, we use all possible legal means to protect our patents, trade secrets, and other proprietary information.
We sell various products and services under a variety of trademarks and service marks, some of which are registered in the United States or certain foreign countries.
Health, Safety, and Environmental Affairs Regulations
We are subject to various federal, state, local, and international laws and regulations relating to occupational health and safety and the environment, including regulations and permitting for air emissions, wastewater and stormwater discharges, the disposal of certain hazardous and nonhazardous wastes, and wetlands preservation. Failure to comply with these occupational health 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.
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With respect to our domestic operations, various environmental protection laws and regulations have been enacted and amended in the United States during the past three decades in response to public concerns pertaining to the environment. Our U.S. operations and its customers are subject to these various evolving environmental laws and corresponding regulations. In the United States, these laws and regulations are enforced by the U.S. Environmental Protection Agency; the Minerals Management Service of the U.S. Department of the Interior (MMS); the U.S. Coast Guard; and various other federal, state, and local environmental authorities. Similar laws and regulations, designed to protect the health and safety of our employees and visitors to our facilities, are enforced by the U.S. Occupational Safety and Health Administration and other state and local agencies and authorities. We must comply with the requirements of environmental laws and regulations applicable to our operations, including the Federal Water Pollution Control Act of 1972; the Resource Conservation and Recovery Act of 1976 (RCRA); the Clean Air Act of 1977; the Comprehensive Environmental Response, Compensation and Liability Act of 1980 (CERCLA); the Superfund Amendments and Reauthorization Act of 1986 (SARA); the Federal Insecticide, Fungicide, and Rodenticide Act of 1947 (FIFRA); the Hazardous Materials Transportation Act of 1975; and the Pollution Prevention Act of 1990.
Our operations outside the United States are subject to various international governmental controls and restrictions pertaining to the environment, occupational health and safety, and other regulated activities in the countries in which we operate. We believe our operations are in substantial compliance with existing international governmental controls and regulations and that compliance with these international controls and regulations has not had a material adverse affect on operations.
At our production plants, we hold various permits regulating air emissions, wastewater and stormwater discharges, the disposal of certain hazardous and nonhazardous wastes, and wetlands preservation.
We believe that our manufacturing plants and other facilities are in general compliance with all applicable environmental and health and safety laws and regulations. Since our inception, we have not had a history of any significant fines or claims in connection with environmental or health and safety matters. However, risks of substantial costs and liabilities are inherent in certain plant and service operations and in the development and handling of certain products and equipment produced or used at our plants, well locations, and worksites. Because of these risks, there can be no assurance that significant costs and liabilities will not be incurred in the future. Changes in environmental and health and safety regulations could subject us to more rigorous standards. We cannot predict the extent to which our operations may be affected by future regulatory and enforcement policies.
Forward Looking Statements
Certain information included in this report, other materials filed or to be filed with the SEC, as well as information included in oral statements or other written statements made or to be made by us contain or incorporate by reference certain statements (other than statements of historical fact) that constitute forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. When used herein, the words “budget,” “budgeted,” “assumes,” “should,” “goal,” “anticipates,” “expects,” “could,” “believes,” “seeks,” “plans,” “intends,” “projects” or “targets” and similar expressions that convey the uncertainty of future events or outcomes are intended to identify forward-looking statements. Where any forward-looking statement includes a statement of the assumptions or bases underlying such forward-looking statement, we caution that, while we believe these assumptions or bases to be reasonable and to be made in good faith, assumed facts or bases almost always vary from actual results, and the difference between assumed facts or bases and actual results could be material, depending on the circumstances. It is important to note that actual results could differ materially from those projected by such forward-looking statements. Although we believe that the expectations reflected in such forward-looking statements are reasonable and such forward-looking statements are based upon the best data available at the date this report is filed with the SEC, we cannot assure you that such expectations will prove correct. Factors that could cause our results to differ materially from the results discussed in such forward-looking statements include, but are not limited to,
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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. The development of additional competing non-oil and gas energy supplies, efforts to improve energy conservation, and improvements in the energy efficiency of plants, equipment, and devices may also reduce oil and gas consumption.
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.
Our oil and gas revenues and cash flows are subject to price risk.
Our revenues from oil and gas production are increasing significantly, representing approximately 21.7% of our total consolidated revenues for the year ended December 31, 2007. 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. This means that a portion of our production is sold at a fixed price as a shield against price declines that could occur in the market. These hedging activities limit our upside potential from oil and gas price increases. In addition, we are exposed to the volatility of oil and gas prices for the portion of our oil and gas production that is not hedged.
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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 heightened price competition, changes in sales and distribution channels, availability of skilled labor and contract services, shortages in raw materials due to untimely supplies, or inability to obtain supplies at reasonable prices may also continue to affect the cost of sales and the fluctuation of gross margin in future periods.
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 for use in oil and gas wells and in other forms and for other applications. Sales of calcium chloride and brominated products contribute significantly to our revenues. In our manufacture of calcium chloride, we use hydrochloric acid and other raw materials purchased from third parties. 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, which has temporarily resulted in decreased production output at our Lake Charles calcium chloride plant. 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 also acquire brominated products from several third party suppliers. If we are unable to acquire the brominated products, bromine, hydrobromic or hydrochloric acid, zinc, or any other supplies of raw material at reasonable prices for a prolonged period, our business could be materially and adversely affected.
Some of the well abandonment and decommissioning services performed by our WA&D Division require the use of vessels and services provided by third parties. We lease equipment and obtain services from certain providers, but these are subject to availability at reasonable prices.
The fabrication of wellhead compressors by our 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. Our plans to grow our international operations could cause this exposure from fluctuating currencies to increase. In September 2004, related to the acquisition of our European calcium chloride assets, we entered into long-term Euro-denominated borrowings, as we believe such borrowings provide a natural currency hedge for our Euro-based operating 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.
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We are exposed to interest rate risk with regard to a portion of our outstanding indebtedness.
As of December 31, 2007, $171.8 million of our outstanding long-term debt consists of floating rate loans, which bear interest at an agreed upon percentage rate spread above LIBOR. Accordingly, our cash flows and results of operations are subject to interest rate risk exposure associated with the level of the variable rate debt balance outstanding. We currently are not a party to an interest rate swap contract or other derivative instrument designed to hedge our exposure to interest rate fluctuation risk.
Operating Risks:
We may incur well intervention and platform debris removal costs as a result of 2005 hurricanes that are not covered under our insurance policies.
We incurred significant damage to certain of our assets during the third quarter of 2005 as a result of Hurricanes Katrina and Rita. In particular, our Maritech subsidiary suffered varying levels of damage to the majority of its offshore oil and gas producing platforms, and three of its platforms and one of its production facilities were completely destroyed. A majority of our damaged assets, with the exception of the destroyed Maritech assets, have been repaired or are in the final stages of being repaired, and have resumed operation. With regard to the destroyed offshore platforms, well intervention efforts on a majority of the wells associated with two of the destroyed platforms have been performed, and we are continuing to assess the extent of well intervention work required on wells associated with the third platform. In addition, we have yet to incur costs for debris removal associated with the destroyed platforms, but are also continuing to assess these costs. Such damage assessment, well intervention, and subsequent debris removal efforts will continue into 2008 and beyond.
Through December 31, 2007, we have expended approximately $47.8 million of well intervention work on certain wells associated with two of the destroyed platforms, and it is estimated that future repair and well intervention efforts, including platform debris removal and other storm related costs, will result in approximately $50 to $70 million of additional costs. Approximately $28.6 million of the costs previously expended and submitted to insurance have been reimbursed; however, our insurance underwriters have continued to maintain that well intervention costs for certain of the damaged wells do not qualify as covered costs and that certain well intervention costs for qualifying wells are not covered under the policy. In addition, the underwriters have also maintained that there is no additional coverage provided under an endorsement we obtained in August 2005 for the cost of removal of these platforms or for other damage repairs on certain properties in excess of the insured values provided by our property damage policy. After continuing to provide requested information to the underwriters regarding the damaged wells, and having numerous discussions with the underwriters, brokers and insurance adjusters, we have yet to receive the requested reimbursement for these contested costs. In late 2007, we filed a lawsuit against the underwriters in an attempt to collect the reimbursement for these well intervention costs incurred as well as future well intervention and debris removal costs to be incurred. We continue to believe that these costs are covered costs pursuant to the policies. However, during the fourth quarter of 2007, we reversed the anticipated insurance recoveries previously included in estimating Maritech’s decommissioning liability, increasing the decommissioning liability to $48.4 million to reflect the well intervention work to be performed, assuming no insurance reimbursements will be received. In addition, we reversed a portion of our anticipated insurance recoveries previously included in accounts receivable associated with certain damage repair costs incurred, resulting in a $13.5 million charge to operating expense, as the amount and timing of further reimbursements of these costs from our insurance providers are now indeterminable.
Despite our confidence that we will ultimately be reimbursed for well intervention and debris removal costs pursuant to our insurance coverage, all or a portion of these contested costs may not be reimbursed. Additionally, the timing of the collection of any future reimbursements is beyond our control, and we will continue to use a significant amount of our working capital until such reimbursements, if any, are received. In addition, a portion of the reimbursements ultimately received may be offset by legal and other administrative costs incurred in our attempts to collect them. Due to the non-routine nature of these well intervention and debris removal efforts, our estimates of the future cost to perform this work may be understated, and could result in additional charges to earnings in the future. To the extent actual future costs exceed the policy maximum for these costs, such excess costs would not be reimbursable even if our efforts to obtain reimbursement are successful.
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We could incur losses on well abandonment and decommissioning projects.
Due to competitive market conditions, a portion of our well abandonment and decommissioning projects may be performed on a turnkey, modified turnkey, or fixed price day rate basis, where defined work is delivered for a fixed price and extra work, which is subject to customer approval, is charged separately. The revenue, cost, and gross profit realized on these types of contracts can vary from the estimated amount because of changes in offshore conditions, increases in the scope of the work to be performed, increased site clearance efforts required, labor and equipment availability, cost and productivity levels, and the performance level of other contractors. In addition, unanticipated events such as accidents, work delays, significant changes in the condition of platforms or wells, downhole problems, and environmental or other technical issues could result in significant losses on these types of projects. These variations and risks may result in us experiencing reduced profitability or losses on these types of projects or on well abandonment and decommissioning work for our Maritech subsidiary.
The acquisition of oil and gas properties and their associated well abandonment and decommissioning liabilities is based on estimated data that may be materially incorrect.
In conjunction with our purchase of oil and gas properties, we perform detailed due diligence review processes that we believe are consistent with industry practices. These acquired properties consist of both mature properties, which are generally in the later stages of their economic lives, as well as exploitation, development, and prospect opportunities. Each acquisition of oil and gas properties requires a thorough review of the expected cash flows acquired and the associated abandonment obligations assumed. The process of estimating natural gas and oil reserves is complex, requiring significant decisions and assumptions to be made in evaluating the available geological, geophysical, engineering, and economic data for each reservoir. As a result, these estimates are inherently imprecise. Actual future production, cash flows, development expenditures, operating and abandonment expenses, and quantities of recoverable natural gas and oil reserves may vary substantially from those initially estimated by us. Also, in conjunction with the purchase of certain oil and gas properties, we assume our proportionate share of the related well abandonment and decommissioning liabilities after performing detailed estimating procedures, analysis, and engineering studies. Our estimates of these future well abandonment and decommissioning liabilities are imprecise and subject to change due to changing cost estimates, oil and gas prices, revisions of reserve estimates and other factors. During 2007, Maritech adjusted its decommissioning liability, either for work performed during the year or related to adjusted estimates of the cost of future work to be performed. Approximately $12.2 million of this adjustment was charged to earnings as an operating expense during 2007. If the actual cost of future abandonment and decommissioning work is materially greater than our current estimates, such additional costs could have an additional adverse effect on earnings.
Oil and gas drilling activities involve numerous risks and are subject to a variety of factors that we cannot control.
Drilling for oil and natural gas involves numerous risks, including the risk that we will not encounter commercially productive oil or natural gas reservoirs. The costs of drilling, completing, and operating wells are often uncertain, and drilling operations may be curtailed, delayed, or canceled as a result of a variety of factors including, but not limited to:
• unexpected drilling conditions;
• pressure or irregularities in formations;
• equipment failures or accidents;
• marine risks such as capsizing, collisions and hurricanes;
• other adverse weather conditions;
• shortages or delays in the delivery of equipment; and
• compliance with environmental and other government requirements, which may increase our costs or restrict our activities.
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During the two year period ended December 31, 2007, we have expended approximately $165.7 million of development and exploitation drilling costs, and we expect to continue to incur significant drilling costs in the future. Certain future drilling activities may not be successful and, if unsuccessful, this failure could have an adverse effect on our future results of operations and financial condition. We may not recover all or any portion of our investment in new wells. In addition, we are often uncertain as to the future cost or timing of drilling, completing, and operating wells. While all drilling, whether developmental or exploratory, involves these risks, exploratory drilling involves greater risks of dry holes or failure to find commercial quantities of hydrocarbons.
Acquisitions or discoveries of additional reserves are needed to avoid a material decline in oil and gas reserves and production volumes.
The rate of production from oil and gas properties generally declines as reserves are depleted. Approximately 44.6% of our proved reserves as of December 31, 2007 are proved producing reserves. Except to the extent that we find or acquire additional properties containing estimated proved reserves; conduct successful exploitation, development, or exploration activities; or through engineering studies, identify additional behind-pipe zones, secondary recovery reserves, or tertiary recovery reserves, our estimated proved reserves will decline materially as reserves are produced. Future oil and gas production is, therefore, highly dependent upon our level of success in acquiring or finding additional reserves.
We may not be able to obtain access to pipelines, gas gathering, transmission and processing facilities to market our oil and gas production.
The marketing of oil and gas production depends in large part on the availability, proximity and capacity of pipelines, gas gathering systems and other transportation, processing and refining facilities, as well as the existence of adequate markets. If there were insufficient capacity available on these systems, or if these systems were unavailable to us, the price offered for our production could be significantly depressed, or we could be forced to shut-in some production or delay or discontinue drilling plans and commercial production following a discovery of hydrocarbons while we construct our own facility. We also rely (and expect to rely in the future) on facilities developed and owned by third parties in order to process, transmit and sell our oil and gas production. Our plans to develop and sell our oil and gas reserves could be materially and adversely affected by the inability or unwillingness of third parties to provide sufficient transmission or processing facilities to us.
Our operations involve significant operating risks, and insurance coverage may not be available or cost effective.
We are subject to operating hazards normally associated with the oilfield service industry and offshore oil and gas production operations, including fires, explosions, blowouts, cratering, mechanical problems, abnormally pressured formations, and environmental accidents. Environmental accidents could include, but are not limited to, oil spills; gas leaks or ruptures; uncontrollable flows of oil, gas, or well fluids; or discharges of toxic gases or other pollutants. We are particularly susceptible to adverse weather conditions in the Gulf of Mexico, including hurricanes and other extreme weather conditions. Damage caused by high winds and turbulent seas could potentially cause us to curtail both service and production operations for significant periods of time until damage can be assessed and repaired. Moreover, even if we do not experience direct damage from these storms, we may experience disruptions in our operations because customers may curtail their development activities due to damage to their platforms, pipelines, and other related facilities.
These hazards also include injuries to employees and third parties during the performance of our operations. Our operation of marine vessels, heavy equipment, and offshore production platforms involves a particularly high level of risk. In addition, certain of our employees who perform services on offshore platforms and vessels are covered by the provisions of the Jones Act, the Death on the High Seas Act and general maritime law. These laws make the liability limits established by state workers’ compensation laws inapplicable to these employees and, instead, permit them or their representatives to pursue actions against us for damages for job-related injuries. Whenever possible, we obtain agreements from customers and suppliers that limit our exposure. However, the occurrence of certain operating
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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 increased dramatically. Current coverage premiums now cost several times more than they did historically, particularly for offshore oil and gas production operations. Insurance coverage with favorable deductible and maximum coverage amounts may not be available in the market, or its cost may not be justifiable. Our insurance coverage today includes higher deductibles and lower maximum coverage limits than in prior years. There can be no assurance that any insurance will be adequate to cover losses or liabilities associated with operational hazards. We cannot predict the continued availability of insurance, or its availability at premium levels that justify its purchase.
Certain of our operations, particularly those conducted offshore, are seasonal and depend, in part, on weather conditions.
The WA&D Division has historically enjoyed its highest vessel utilization rates during the period from April to October, when weather conditions are typically more favorable for offshore activities, and has experienced its lowest utilization rates in the period from November to March. This Division, under certain turnkey and other contracts, may bear the risk of delays caused by adverse weather conditions. Storms can also cause our oil and gas producing properties to be shut-in. In addition, demand for other products and services we provide are subject to seasonal fluctuations, due in part to weather conditions that cannot be predicted. Accordingly, our operating results may vary from quarter to quarter depending on weather conditions in applicable areas.
Delays or cost overruns on construction projects could adversely affect our business, or the expected profitability and cash flows upon completion may not be as timely or as high as expected.
We are currently beginning significant construction projects related to a new calcium chloride plant facility near El Dorado, Arkansas, and a new corporate headquarters facility in The Woodlands, Texas. Due to our continuing growth strategy, we could have other significant construction projects in the future. These projects are subject to the risk of delays or cost overruns inherent in construction projects. These risks include, but are not limited to:
• unforeseen quality or engineering problems;
• work stoppages;
• weather interference;
• unanticipated cost increases;
• delays in receipt of necessary equipment; and
• inability to obtain the requisite permits or approvals.
The completion of these construction projects will require a significant amount of working capital, and delays or cost overruns on these projects could adversely affect our cash flows. In addition, we will not receive any material increase in revenue or cash flow from the El Dorado, Arkansas calcium chloride plant until after it is placed in service and we are able to begin production. Delays in the completion of this calcium chloride facility could affect future profitability for our Fluids Division operations.
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We face risks related to our growth strategy.
Our growth strategy includes both internal growth and growth through acquisitions. Internal growth may require significant capital expenditure investments, some of which may become unrecoverable or fail to generate an acceptable level of cash flows. Internal growth may also require financial resources (including the use of available cash or additional long-term debt) and management and personnel resources. Acquisitions also require significant financial and management resources, both at the time of the transaction and during the process of integrating the newly acquired business into our operations. Our operating results could be adversely affected if we are unable to successfully integrate such new companies into our operations, are unable to hire adequate personnel, or are unable to retain existing personnel. We may not be able to consummate future acquisitions on favorable terms. 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, the United Kingdom, Norway, Finland, Sweden, Canada, Mexico, Argentina, and Brazil, and have joint ventures in Saudi Arabia and The Netherlands. A portion of our planned future growth includes expansion into additional countries. Foreign operations carry special risks. Our business in the countries in which we currently operate and those in which we may operate in the future could be limited or disrupted by:
• government controls and government actions such as expropriation of assets and changes in legal and regulatory environments;
• import and export license requirements;
• political, social or economic instability;
• trade restrictions;
• changes in tariffs and taxes;
• restrictions on repatriating foreign profits back to the United States;
• the impact of anti-corruption laws and the risk that actions taken by us or others on our behalf may adversely affect our operations and competitive position in the affected countries; and
• the limited knowledge of these markets or the inability to protect our interests.
We and our affiliates operate in countries where governmental corruption has been known to exist. While we and our subsidiaries are committed to conducting business in a legal and ethical manner, there is a risk of violating either the U.S. Foreign Corrupt Practices Act (FCPA) or laws or legislation promulgated pursuant to the 1997 OECD Convention on Combating Bribery of Foreign Public Officials in International Business Transactions or other applicable anti-corruption regulations that generally prohibit the making of improper payments to foreign officials for the purpose of obtaining or keeping business. Violation of these laws could result in monetary penalties against us or our subsidiaries and could damage our reputation and, therefore, our ability to do business.
Foreign governments and agencies often establish permit and regulatory standards different from those in the U.S. If we cannot obtain foreign regulatory approvals, or if we cannot obtain them when we expect, our growth and profitability from international operations could be limited.
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Our success depends upon the continued contributions of our personnel, many of whom would be difficult to replace, and the continued ability to attract new employees.
Our success will depend on our ability to attract and retain skilled employees. The delivery of our products and services requires personnel with specialized skills and experience. In addition, our ability to expand our operations depends in part on our ability to increase the size of our skilled labor force. The demand for skilled workers in the Gulf Coast region is high, and the supply is limited. Changes in personnel, therefore, could adversely affect operating results.
Financial Risks:
We have significant long-term debt outstanding.
As of December 31, 2007, our long-term debt outstanding was approximately $358.0 million. Additional growth could result in increased debt levels to support our capital expenditure needs or acquisition activities. Our current level of long-term debt could limit our ability to obtain additional financing on satisfactory terms to fund our capital expenditures, acquisitions, working capital needs, and other general corporate requirements. A large portion of our long-term debt outstanding is at variable interest rates. Debt service costs related to outstanding long-term debt represent a significant use of our operating cash flow and could increase our vulnerability to general adverse economic and industry conditions. Our long-term debt agreements contain customary covenants and other restrictions and requirements. In addition, the agreements require us to maintain certain financial ratio requirements. Significant deterioration of these ratios could result in a default under the agreements. The agreements also include cross-default provisions relating to any other indebtedness we have that is greater than a defined amount. If any such indebtedness is not paid or is accelerated and such event is not remedied in a timely manner, a default will occur under the long-term debt agreements. Any event of default, if not timely remedied, could result in a termination of all commitments of the lenders and an acceleration of any outstanding loans and credit obligations.
Certain of our businesses are exposed to significant credit risks.
We face concentrations of credit risk associated with the significant amounts of accounts receivable we have with companies in the energy industry. Many of our customers, particularly those associated with our onshore operations, may be small to medium sized oil and gas operating companies who may be susceptible to fluctuating oil and gas commodity prices or generally increased operating expenses. Our ability to collect from our customers may be impacted by adverse changes in the energy industry.
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, and pipelines as well as the site clearance related to these properties. We have guaranteed a portion of the abandonment and decommissioning liabilities of Maritech. In certain instances, Maritech is entitled to be paid in the future for all or a portion of these obligations by the previous owner of the property once the liability is satisfied. We and Maritech are subject to the risk that the previous owner(s) will be unable to make these future payments. In addition, if Maritech acquires less than 100% of the working interest in a property, its co-owners are responsible for the payment of their portions of the associated operating expenses and abandonment liabilities. However, if one or more co-owners do not pay their portions, Maritech and any other nondefaulting co-owners may be liable for the defaulted amount. If any required payment is not made by a previous owner or a co-owner, and any security is not sufficient to cover the required payment, we could suffer material losses.
18
Maritech’s estimates of its oil and gas reserves and related future cash flows are based on many factors and assumptions, including various assumptions that are based on conditions in existence as of the dates of the estimates. Any material changes in those conditions, or other factors affecting those assumptions, could impair the quantity and value of our oil and gas reserves.
Maritech’s estimates of oil and gas reserve information are prepared in accordance with Rule 4-10 of Regulation S-X, and reflect only estimates of the accumulation of oil and gas and the economic recoverability of those volumes. Maritech’s future production, revenues and expenditures with respect to such oil and gas reserves will likely be different from estimates, and any material differences may negatively affect our business, financial condition, and results of operations. As a result, Maritech has experienced and may continue to experience significant revisions to its reserve estimates.
Oil and gas reservoir analysis is a subjective process which involves estimating underground accumulations of oil and gas that cannot be measured in an exact manner. Estimates of economically recoverable oil and gas reserves and of future net cash flows associated with such reserves necessarily depend upon a number of variable factors and assumptions. Because all reserve estimates are to some degree subjective, each of the following items may prove to differ materially from that assumed in estimating reserves:
• the quantities of oil and gas that are ultimately recovered;
• the production and operating costs incurred;
• the amount and timing of future development and abandonment expenditures; and
• future oil and gas sales prices.
Furthermore, different reserve engineers may make different estimates of reserves and cash flow based on the same available data.
The estimated discounted future net cash flows described in this Annual Report for the year ended December 31, 2007 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. The capitalized costs of our oil and natural gas properties, on a field basis, cannot exceed the estimated undiscounted future net cash flows of that field. If net capitalized costs exceed future net revenues, we must write down the costs of each such field to our estimate of its fair market value. Accordingly, a significant decline in oil or natural gas prices, unsuccessful exploration and/or development efforts, or an increase in our decommissioning liabilities could cause a future write-down of capitalized costs. Unproved properties are evaluated at the lower of cost or fair market value. On a field by field basis, our oil and gas properties are assessed for impairment in value whenever indicators become evident, with any impairment charged to expense. Under the successful efforts method of accounting, we are exposed to the risk that the value of a particular property (field) would have to be written down or written off if an impairment were present.
19
Legal/Regulatory Risks:
Our operations are subject to extensive and evolving U.S. and foreign federal, state and local laws and regulatory requirements that increase our operating costs and expose us to potential fines, penalties, and litigation.
Laws and regulations strictly govern our operations relating to: corporate governance, environmental affairs, health and safety, waste management, and the manufacture, storage, handling, transportation, use, and sale of chemical products. Our operation and decommissioning of offshore properties are also subject to and affected by various types of government regulation, including numerous federal and state environmental protection laws and regulations. These laws and regulations are becoming increasingly complex and stringent, and compliance is becoming increasingly expensive. Governmental authorities have the power to enforce compliance with these regulations, and violators are subject to civil and criminal penalties, including civil fines, injunctions, or both. Third parties may also have the right to pursue legal actions to enforce compliance. It is possible that increasingly strict environmental laws, regulations and enforcement policies could result in substantial costs and liabilities to us and could subject our handling, manufacture, use, reuse, or disposal of substances or pollutants to increased scrutiny.
A large portion of our Maritech subsidiary’s oil and gas operations are conducted on federal leases that are administered by the MMS and are required to comply with the regulations and order promulgated by the MMS under the Outer Continental Shelf Lands Act. MMS regulations also establish construction requirements for production facilities located on federal offshore leases and govern the plugging and abandonment of wells and the removal of production facilities from these leases. Under limited circumstances, the MMS could require us to suspend or terminate our operations on a federal lease. The MMS also establishes the basis for royalty payments due under federal oil and natural gas leases through regulations issued under applicable statutory authority.
Our business exposes us to risks such as the potential for harmful substances escaping into the environment and causing damages or injuries, which could be substantial. Although we maintain general liability and pollution liability insurance, these policies are subject to coverage limits. We maintain limited environmental liability insurance covering named locations and environmental risks associated with contract services for oil and gas operations, and for oil and gas producing properties. The extent of this coverage is consistent with our other insurance programs. We could be materially and adversely affected by an enforcement proceeding or a claim that is not covered or is only partially covered by insurance.
In addition to increasing our risk of environmental liability, the rigorous enforcement of environmental laws and regulations has accelerated the growth of some of the markets we serve. Decreased regulation and enforcement in the future could materially and adversely affect the demand for the types of services offered by 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. Unresolved Staff Comments.
None.
20
Our properties consist primarily of chemical plants, processing plants, distribution facilities, barge rigs, heavy lift and dive support vessels, well abandonment and decommissioning equipment, oil and gas properties, flowback testing equipment, and compression equipment. The following information describes facilities that we leased or owned as of December 31, 2007. We believe our facilities are adequate for our present needs.
Fluids Division. Fluids Division facilities include seven chemical production plants located in the states of Arkansas, California, Louisiana, and West Virginia, and the country of Finland. The total manufacturing area of these plants, excluding the two California locations, is approximately 496,000 square feet. The two California locations contain 29 square miles of acreage containing solar evaporation ponds and leased mineral acreage. In addition, the Fluids Division owns and leases brine mineral reserves in Arkansas.
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 thirty-seven terminal locations, twenty-three throughout the United States and fourteen internationally.
WA&D Division. The WA&D Division conducts its operations through seven offices and service facility locations (six of which are leased) located in Texas and Louisiana. In addition, the WA&D Services segment owns the following fleet of vessels which it uses in performing its well abandonment, decommissioning and contract diving operations:
| TETRA Arapaho |
Heavy lift derrick barge with 800-ton capacity crane |
| TETRA DB-1 |
Heavy lift derrick barge with 615-ton capacity crane |
| TETRA Southern Hercules |
Four point anchor spread with 150-ton capacity crane |
| Epic Diver |
220 foot dive support vessel with saturation diving system |
| Epic Explorer |
210 foot dive support vessel with saturation diving system |
| Epic Seahorse |
210 foot dive support vessel |
| Epic Mariner |
110 foot dive support vessel |
| Epic Pioneer |
110 foot dive support vessel |
| Epic Endeavor |
110 foot utility vessel |
See below for a discussion of the WA&D Division’s oil and gas property assets.
Production Enhancement Division. Production Enhancement Division facilities include sixteen production testing distribution facilities (fifteen of which are leased) in Texas, New Mexico, Colorado, and Louisiana, and in Brazil, Mexico, and Saudi Arabia. Compressco’s facilities include a fabrication and headquarters facility in Oklahoma, a leased fabrication facility in Alberta, Canada, a leased service facility in New Mexico, and six sales offices in Oklahoma, Texas, Colorado, New Mexico, Louisiana, and Canada.
Corporate. Our headquarters are located in The Woodlands, Texas, where we lease approximately 105,000 square feet of office space. We also own 2.635 acres of land adjacent to our headquarters location, on which we are constructing a new headquarters building. In addition, we own a 20,000 square foot technical facility to service our Fluids Division operations.
Oil and Gas Properties.
The following tables show, for the periods indicated, reserves and operating information related to our Maritech subsidiary’s oil and gas interests in developed and undeveloped leases, all of which are located in the Gulf of Mexico region. Maritech’s oil and gas operations are a separate segment included within our WA&D Division. The following table provides a brief description of Maritech’s most significant oil and gas properties:
21
| Net Total Proved Reserves |
|
Net Proved Reserves Mix |
|
2007 Net Production |
|
|
|
Production |
|||
|
(MMcfe) |
|
Oil% |
|
Gas% |
|
(MMcfe) |
|
WI% |
|
Status |
|
| U.S. Offshore Gulf of Mexico: |
|
|
|||||||||
| Timbalier Bay Area |
30,249 |
|
66% |
34% |
10,210 |
100% |
Producing |
||||
| Cimarex Properties, Main Pass Area(1) |
18,214 |
3% |
97% |
21 |
50% – 100% |
Producing |
|||||
| East Cameron 328 |
12,815 |
91% |
9% |
2,419 |
50% |
Producing |
|||||
| Vermillion 252/253 |
2,682 |
40% |
60% |
1,469 |
50% |
Producing |
|||||
(1) Information reflects production subsequent to the December, 2007 acquisition of the Cimarex Properties. Reserve and working interest percentage information is as of December 31, 2007, and does not reflect the impact of the planned sale of a portion of the Cimarex Property interests.
See also “Note R – Supplemental Oil and Gas Disclosures” in the Notes to Consolidated Financial Statements for additional information.
Oil and Gas Reserves. Through our Maritech subsidiary, we employ full-time experienced reservoir engineers and geologists who are responsible for determining proved reserves in conformance with SEC guidelines. Reserve estimates were prepared by Maritech engineers based upon their interpretation of production performance data and geologic interpretation of sub-surface information derived from the drilling of wells. In addition to the complete analysis by Maritech’s internal reservoir engineers, independent petroleum engineers and geologists performed reserve audits of approximately 81.9% of our proved reserve volumes as of December 31, 2007. The use of the term reserve audit is intended only to refer to the collective application of the engineering and geologic procedures which the independent petroleum engineering firms were engaged to perform and may be defined and used differently by other companies.
A reserve audit is a process whereby an independent petroleum engineering firm performs extensive visits, collects and includes all necessary geologic, geophysical, engineering, and economic data, followed by an independent reserve evaluation. The reserve audit of our oil and gas reserves involves the rigorous examination of our technical evaluation, as well as the interpretation and extrapolation of well information such as flow rates, reservoir pressure declines, and other technical information and measurements. Maritech’s internal reservoir engineers interpret this data to determine the nature of the reservoir and, ultimately, the quantity of proved oil and gas reserves attributable to the specific property. Our proved reserves, as reflected in this Annual Report, include only quantities that Maritech expects to recover commercially using current technology, prices, and costs, and within existing regulatory and environmental limits. While Maritech can be reasonably certain that the proved reserves will be produced, the timing and ultimate recovery can be affected by a number of factors, including completion of development projects, reservoir performance, regulatory approvals, and changes in projections of long-term oil and gas prices. Revisions can include upward or downward changes in the previously estimated volumes of proved reserves for existing fields due to evaluation of (1) already available geologic, reservoir, or production data or (2) new geologic or reservoir data obtained from wells. Revisions can also occur associated with significant changes in development strategy, oil and gas prices, or the related production equipment/facility capacity. Maritech’s independent petroleum engineers also examined the reserve estimates with respect to reserve categorization, using the definitions for proved reserves set forth in Regulation S-X Rule 4-10(a) and subsequent SEC staff interpretations and guidance.
Maritech engaged Ryder Scott Company, L.P. and DeGolyer and McNaughton to perform the reserve audits of our oil and gas reserves as of December 31, 2007. In the conduct of these reserve audits, these independent petroleum engineering firms did not independently verify the accuracy and completeness of information and data furnished by Maritech with respect to property interests owned, oil and gas production and well tests from examined wells, or historical costs of operation and development; however, they did verify product prices, geological structural and isopach maps, well logs, core analyses, and pressure measurements. If, in the course of the examinations, a matter of question arose regarding the validity or sufficiency of any such information or data, the independent petroleum engineering firms did not accept such information or data until all questions relating thereto were satisfactorily resolved.
22
Furthermore, in instances where decline curve analysis was not adequate in determining proved producing reserves, the independent petroleum engineering firms performed volumetric analysis, which included the analysis of geologic, reservoir, and fluids data. Proved undeveloped reserves were analyzed by volumetric analysis, which takes into consideration recovery factors relative to the geology of the location and similar reservoirs. Where applicable, the independent petroleum engineering firms examined data related to well spacing, including potential drainage from offsetting producing wells, in evaluating proved reserves of undrilled well locations.
The reserve audit performed by Ryder Scott Company, L.P. included certain properties selected by Maritech, including all of our significant properties described above, excluding the Cimarex Properties, and represented approximately 61.1% of our total proved oil and gas reserve volumes. The reserve audit performed by DeGolyer and McNaughton included the Cimarex Properties acquired in December 2007 and represented approximately 20.8% of our total proved oil and gas reserve volumes. The independent petroleum engineers represent in their audit reports that they believe Maritech’s estimates of future reserves were prepared in accordance with generally accepted petroleum engineering and evaluation principles for the estimation of future reserves as set forth in Society of Petroleum Engineers (SPE) standards. In each case, the independent petroleum engineers concluded that the overall proved reserves for the reviewed properties as estimated by Maritech, were, in the aggregate, reasonable within the established audit tolerance guidelines of 10% as set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the SPE. There were no limitations imposed or encountered by Maritech or the independent petroleum engineers in the preparation of our estimated reserves or in the performance of the reserve audits by the independent petroleum engineers.
The following table sets forth information with respect to our estimated proved reserves as of December 31, 2007. The standardized measure of discounted future net cash flows attributable to oil and gas reserves was prepared by our Maritech subsidiary using constant prices as of the calculation date, net of future income taxes, discounted at 10% per annum. Reserve information is prepared in accordance with guidelines established by the SEC. All of Maritech’s reserves are located in U.S. state and federal offshore waters in the Gulf of Mexico region and onshore Louisiana.
|
December 31, 2007 |
||||
| Estimated proved reserves: |
||||
| Natural gas (Mcf) |
46,807,000 |
|||
| Oil (Bbls) |
6,735,000 |
|||
|
|
||||
| Standardized measure of discounted future net cash flows |
$ |
298,679,000 |
||
For additional information regarding estimates of oil and gas reserves, including estimates of proved and proved developed reserves, the standardized measure of discounted future net cash flows, and the changes in discounted future net cash flows, see “Note R – Supplemental Oil and Gas Disclosures” in the Notes to Consolidated Financial Statements.
Maritech is not required to file, and has not filed on a recurring basis, estimates of its total proved net oil and gas reserves with any U.S. or non-U.S. governmental regulatory authority or agency other than the Department of Energy (the DOE) and the SEC. The estimates furnished to the DOE have been consistent with those furnished to the SEC. They are not necessarily directly comparable, however, due to special DOE reporting requirements. In no instance have the estimates for the DOE differed by more than five percent from the corresponding estimates reflected in total reserves reported to the SEC.
23
Production Information. The table below sets forth information related to production, average sales price, and average production cost per unit of oil and gas produced during 2007, 2006, and 2005:
Year Ended December 31, |
|||||||||
|
2007 |
2006 |
2005 |
|||||||
| Production: |
|||||||||
| Natural gas (Mcf) |
9,515,214 |
7,812,339 |
5,088,000 |
||||||
| Oil (Bbls) |
1,985,183 |
1,356,108 |
484,300 |
||||||
|
|
|||||||||
| Revenues: |
|||||||||
| Natural gas |
$ |
76,202,000 |
$ |
81,271,000 |
$ |
39,998,000 |
|||
| Oil |
137,136,000 |
82,828,000 |
22,878,000 |
||||||
| Total |
$ |
213,338,000 |
$ |
164,099,000 |
$ |
62,876,000 |
|||
|
|
|||||||||
| Average realized unit prices and costs: |
|||||||||
| Natural gas (per Mcf) |
$ |
8.01 |
$ |
10.40 |
$ |
7.86 |
|||
| Oil (per Bbl) |
$ |
69.08 |
$ |
61.08 |
$ |
47.24 |
|||
|
|
|||||||||
| Production cost per equivalent Mcf |
$ |
4.18 |
$ |
3.99 |
$ |
4.34 |
|||
| Depletion cost per equivalent Mcf |
$ |
3.45 |
$ |
2.42 |
$ |
1.86 |
|||
Production cost per equivalent Mcf excludes the impact of storm and insurance related costs and recoveries, which were charged or credited to operations during each of the years presented, with approximately $13.5 million being charged during 2007. The 2005 production cost per equivalent Mcf was increased, however, due to the impact of hurricanes which resulted in significant properties being shut-in during the last four months of 2005. Depletion cost per equivalent Mcf excludes the impact of dry hole costs and property impairments.
Acreage and Productive Wells. At December 31, 2007, our Maritech subsidiary owned interests in the following oil and gas wells and acreage:
|
Productive Gross Wells |
|
Productive Net Wells |
|
Developed Acreage |
|
Undeveloped Acreage |
||||||||||
| State/Area |
Oil |
Gas |
Oil |
Gas |
Gross |
Net |
Gross |
Net |
||||||||
| Louisiana Onshore |
20 |
– |
1.23 |
– |
367 |
23 |
– |
– |
||||||||
| Louisiana Offshore |
64 |
24 |
64.00 |
23.08 |
9,458 |
9,458 |
2,334 |
2,334 |
||||||||
| Texas Offshore |
– |
2 |
– |
1.50 |
10,064 |
3,501 |
– |
– |
||||||||
| Federal Offshore |
56 |
110 |
25.60 |
60.16 |
369,952 |
178,858 |
106,475 |
73,761 |
||||||||
|
|
||||||||||||||||
| Total |
140 |
136 |
90.83 |
84.74 |
389,841 |
191,840 |
108,809 |
76,095 |
||||||||
In January 2008, through Maritech’s acquisition of certain oil and gas properties from Stone Energy Corporation, Maritech acquired an additional 14 gross oil wells (12.52 net) and 37 gross gas wells (26.62 net), as well as 40,925 gross developed acres (30,692 net), primarily located in U.S. Federal offshore waters.
Drilling Activity. Maritech participated in the drilling of 16 gross development wells (11.4 net wells) during 2007, two of which were unproductive. Maritech participated in the drilling of 10 gross productive wells (6.75 net wells) during 2006. Maritech participated in the drilling of 13 gross productive development wells (4.4 net wells) during 2005. As of December 31, 2007, there were 5 additional wells (2.5 net wells) in the process of being drilled. As of December 31, 2006 there were 3 additional wells (1.33 net wells) in the process of being drilled, one of which was subsequently determined to be unproductive.
24
We are named defendants in several lawsuits and respondents in certain governmental proceedings arising in the ordinary course of business. While the outcome of lawsuits or other proceedings against us cannot be predicted with certainty, management does not expect these matters to have a material adverse impact on the financial statements.
As previously disclosed, our Maritech subsidiary incurred significant damage as a result of hurricanes Katrina and Rita. Although portions of the well intervention costs previously expended on these facilities and submitted to our insurers have been reimbursed, our insurance underwriters have continued to maintain that well intervention costs for certain of the damaged wells do not qualify as covered costs and that certain well intervention costs for qualifying wells are not covered under the policies. In addition, the underwriters have also maintained that there is no additional coverage provided under an endorsement we obtained in August 2005 for the cost of removal of these platforms and for other damage repairs on certain properties in excess of the insured values provided by our property damage policy. On November 16, 2007, we filed a lawsuit in the 359th Judicial District Court, Montgomery County, Texas, entitled Maritech Resources, Inc. v. Certain Underwriters and Insurance Companies at Lloyd’s, London subscribing to Policy no. GA011150U and Steege Kingston, in which we are seeking damages for breach of contract and various related claims and a declaration of the extent of coverage of an endorsement to the policy. We cannot predict the outcome of this lawsuit; however, the ultimate resolution could have a significant impact upon our future operating cash flow.
Item 4. Submission of Matters to a Vote of Security Holders.
No matters were submitted to a vote of our security holders, through solicitation of proxies or otherwise, during the fourth quarter of the year ended December 31, 2007.
25
PART II
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Repurchases of Equity Securities.
Price Range of Common Stock
Our common stock is traded on the New York Stock Exchange under the symbol “TTI.” As of February 22, 2007, there were approximately 6,157 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, 2007, as reported by the New York Stock Exchange and as adjusted for a 2-for-1 stock split, which was declared and effected in May 2006.
High |
Low |
|||||
2007 |
||||||
First Quarter |
$ |
25.69 |
$ |
21.00 |
||
Second Quarter |
28.94 |
24.61 |
||||
Third Quarter |
30.20 |
17.10 |
||||
Fourth Quarter |
22.96 |
14.58 |
||||
2006 |
||||||
First Quarter |
$ |
23.78 |
$ |
15.71 |
||
Second Quarter |
32.00 |
22.65 |
||||
Third Quarter |
30.87 |
21.74 |
||||
Fourth Quarter |
28.46 |
20.71 |
||||
Market Price of Common Stock
The following graph compares the five-year cumulative total returns of our common stock, the Standard & Poor’s 500 Composite Stock Price Index (S&P 500) and the Philadelphia Oil Service Sector Index (PHLX Oil Service Sector), assuming $100 invested in each stock or index on December 31, 2002, all dividends reinvested, and a fiscal year ending December 31. This information shall be deemed furnished, and not filed, in this Form 10-K, and shall not be deemed incorporated by reference into any filing under the Securities Act of 1933, or the Securities Exchange Act of 1934, as a result of this furnishing, except to the extent we specifically incorporate it by reference.
26
Dividend Policy
We have never paid cash dividends on our common stock. We currently intend to retain earnings to finance the growth and development of our business. Any payment of cash dividends in the future will depend upon our financial condition, capital requirements, and earnings, as well as other factors the Board of Directors may deem relevant. We declared a dividend of one Preferred Stock Purchase Right per share of common stock to holders of record at the close of business on November 6, 1998. See “Note T – Stockholders’ Rights Plan” in the Notes to Consolidated Financial Statements attached hereto for a description of such Rights. In May 2006, we declared a 2-for-1 stock split, which was effected in the form of a stock dividend to all stockholders of record as of May 15, 2006. In August 2005, we 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. See “Note K – Capital Stock” in the Notes to Consolidated Financial Statements attached hereto for a description of certain 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 our ability to pay dividends.
Purchases of Equity Securities by the Issuer and Affiliated Purchasers
In January 2004, our Board of Directors authorized the repurchase of up to $20 million of our common stock. Purchases will be made from time to time in open market transactions at prevailing market prices. The repurchase program may continue until the authorized limit is reached, at which time the Board of Directors may review the option of increasing the authorized limit. During 2004, we repurchased 210,000 shares of our common stock pursuant to the repurchase program at a cost of approximately $3.3 million. During 2005, we repurchased 130,950 shares of our common stock pursuant to the repurchase program at a cost of approximately $2.4 million. There were no repurchases made during 2006 or 2007 pursuant to the repurchase program. Shares repurchased during the fourth quarter of 2007 other than pursuant to our repurchase program are as follows:
|
Period |
|
Total Number of Shares Purchased |
|
Average Price Paid per Share |
|
Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs (1) |
|
Maximum Number (or Approximate Dollar Value) of Shares that May Yet be Purchased Under the Publicly Announced Plans or Programs (1) |
|||
| Oct 1 – Oct 31, 2007 |
– |
$ |
– |
– |
$ |
14,327,000 |
|||||
|
|
|
||||||||||
| Nov 1 – Nov 30, 2007 |
961 |
(2) |
$ |
16.06 |
– |
$ |
14,327,000 |
||||
|
|
|
||||||||||
| Dec 1 – Dec 31, 2007 |
– |
|
$ |
– |
– |
$ |
14,327,000 |
||||
|
|
|||||||||||
| Total |
961 |
– |
|
$ |
14,327,000 |
||||||
(1) 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.
(2) Shares we received in connection with the exercise of certain employee stock options or the vesting of certain employee restricted stock. These shares were not acquired pursuant to the stock repurchase program.
Item 6. Selected Financial Data.
The following tables set forth our selected consolidated financial data for the years ended December 31, 2007, 2006, 2005, 2004, and 2003. The selected consolidated financial data does not purport to be complete and should be read in conjunction with, and is qualified by, the more detailed information, including the Consolidated Financial Statements and related Notes and “Management’s Discussion and Analysis of Financial Condition and Results of Operation” appearing elsewhere in this report. Please read “Item 1A. Risk Factors” beginning on page 10 for a discussion of the material uncertainties which might cause the selected consolidated financial data not to be indicative of our future financial condition or results of operations. During 2007, we completed the acquisition of two service companies and Maritech acquired certain oil and gas properties. During 2006, we completed the acquisitions of the operations of Epic Divers, Inc., Beacon Resources, LLC, and a heavy lift barge. During 2005, we acquired certain oil and gas properties as part of our Maritech subsidiary’s operations. During 2004, we completed the acquisitions of Compressco, Inc., the European calcium chloride assets, and a
27
heavy lift barge. These acquisitions significantly impact the comparison of our financial statements for 2007 to earlier years. In December 2007, we sold our process services operations. In 2006, we made the decision to discontinue our Venezuelan fluids and production testing operations. In 2003, we made the decision to discontinue the operations of Damp Rid, Inc. and our Norwegian process services operations. During 2000, we commenced our exit from the micronutrients business. Accordingly, we have reflected each of the above operations as discontinued operations.
Year Ended December 31, |
|||||||||||||||
2007 |
|
2006 |
2005 |
2004 |
|
2003 |
|||||||||
(In
Thousands, Except Per Share Amounts) |
|||||||||||||||
|
Income Statement Data |
|||||||||||||||
|
Revenues |
$ |
982,483 |
$ |
767,795 |
$ |
509,249 |
$ |
334,881 |
$ |
302,323 |
(1) | ||||
|
Gross profit |
116,383 |
252,804 |
123,671 |
(2) |
71,983 |
(2,3) |
66,422 |
(2,3) | |||||||
|
Operating income |
16,512 |
160,800 |
54,317 |
23,494 |
26,309 |
||||||||||
|
Interest expense |
(17,886 |
) |
(13,637 |
) |
(6,310 |
) |
(1,962 |
) |
(524 |
) | |||||
|
Interest income |
731 |
348 |
330 |
286 |
210 |
||||||||||
|
Other income (expense), net |
2,805 |
4,858 |
3,692 |
257 |
630 |
||||||||||
|
Income before discontinued operations and cumulative effect of accounting change |
1,221 |
99,880 |
34,802 |
15,184 |
17,915 |
||||||||||
|
Net income |
$ |
28,771 |
$ |
101,878 |
$ |
38,062 |
$ |
17,699 |
$ |
21,664 |
|||||
|
|
|||||||||||||||
|
Income per share, before discontinued operations and cumulative effect of accounting change (4) |
$ |
0.02 |
$ |
1.39 |
$ |
0.51 |
$ |
0.23 |
$ |
0.27 |
|||||
|
Average shares (4) |
73,573 |
71,631 |
68,588 |
67,112 |
65,550 |
||||||||||
|
|
|||||||||||||||
|
Income per diluted share, before discontinued operations and cumulative effect of accounting change (4) |
$ |
0.02 |
$ |
1.33 |
$ |
0.48 |
$ |
0.21 |
$ |
0.26 |
|||||
|
Average diluted shares (4) |
75,921 |
(5) |
74,824 |
72,137 |
71,199 |
69,016 |
|||||||||
(1) Revenues for this period 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 amount was $7,686 for 2003.
(2) Gross profit for these periods reflects the reclassification of certain billed operating costs as cost of revenues, which had previously been credited to general and administrative expense. The reclassified amounts were $1,113 for 2005; $360 for 2004; and $291 for 2003.
(3) Gross profit for these periods 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; and $3,019 for 2003.
(4) Net income per share and average share outstanding information reflects the retroactive impact of a 2-for-1 stock split as of May 15, 2006, and 3-for-2 stock splits as of August 19, 2005 and August 15, 2003. Each of the stock splits were effected in the form of a stock dividend as of the record dates.
(5) For the year ended December 31, 2007, the calculation of average diluted shares outstanding excludes the impact of 716,354 average outstanding stock options that would have been antidilutive.
December 31, |
|||||||||||||||
2007 |
2006 |
2005 |
2004 |
|
2003 |
||||||||||
(In Thousands) |
|||||||||||||||
Balance Sheet Data |
|||||||||||||||
Working capital |
$ |
181,441 |
$ |
262,572 |
$ |
135,989 |
$ |
117,350 |
$ |
113,411 |
|||||
Total assets |
1,295,536 |
1,086,190 |
726,850 |
508,988 |
309,599 |
||||||||||
Long-term debt |
358,024 |
336,381 |
157,270 |
143,754 |
4 |
||||||||||
Decommissioning and other long-term liabilities |
247,543 |
167,671 |
150,570 |
68,145 |
54,076 |
||||||||||
Stockholders' equity |
$ |
447,919 |
$ |
420,380 |
$ |
284,147 |
$ |
236,181 |
$ |
210,769 |
|||||
28
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operation.
The following discussion is intended to analyze major elements of our consolidated financial statements and provide insight into important areas of management’s focus. This section should be read in conjunction with the Consolidated Financial Statements and the accompanying Notes included elsewhere in this Annual Report. We have accounted for the discontinuance or disposal of certain businesses as discontinued operations, and have adjusted prior period financial information to exclude these businesses from continuing operations.
Statements in the following discussion may include forward-looking statements. These forward-looking statements involve risks and uncertainties. See “Item 1A. Risk Factors,” for additional discussion of these factors and risks.
Business Overview
Although each of our operating segments continued to capitalize on the current strong demand for our products and services, our results of operations during 2007 reflect the significant operating challenges that affected each of our segments during the year. Despite each segment reporting revenue growth compared to the prior year, only our Production Enhancement Division reflected increased profitability, showing a growth of $13.2 million in pretax profit compared to the prior year. This division’s profit growth was more than offset by the decreased profitability of our other segments, particularly by our Maritech Resources, Inc. (Maritech) subsidiary, which, despite a significant increase in oil and gas production, reported a decrease in pretax profit of approximately $104.9 million compared to 2006. Maritech’s loss was largely due to approximately $71.8 million, net of intercompany profits, of oil and gas property impairments recorded during the year. These impairments were primarily due to the reversal of anticipated insurance recoveries as a result of continued delays from our insurance underwriters related to 2005 hurricane repair costs, which caused the timing and amount of claim reimbursements on costs incurred, or to be incurred in the future, to become indeterminable. Maritech also recorded approximately $13.5 million of charges to operating expenses also resulting from the reversal of anticipated insurance recoveries previously recorded as insurance receivables related to certain hurricane repair expenses. In addition, Maritech reported $7.9 million of decreased pretax profit due to decreased realized oil and gas prices during 2007. Our Fluids Division pretax profits decreased by $50.0 million compared to 2006, largely due to increased product costs, a temporary decrease in shallow water offshore demand, and the cost associated with the termination of a previous supply agreement. Our WA&D Services segment was hampered during the year by operating inefficiencies, unfavorable terms on certain contracts, and vessel utilization issues. Although consolidated gross profit as a percentage of revenues decreased to 11.8% during 2007, each of our segments took steps needed to improve their profitability, and to attempt to capitalize on the expected continuing increase in revenues in the future.
We continued to execute our long-term growth strategy during 2007, resulting in continuing expansion of our operations, through both internal and external growth. Our Maritech operation continues to grow rapidly, through additional oil and gas property acquisitions, and a significant exploitation and development program, resulting in unprecedented oil and gas production levels for this segment. We also continue to grow geographically, with new international expansion during the year for our production testing, compression services, and fluids and completion services operations. We expended $290.6 million of cash acquisition and capital expenditure activity during 2007, however, the December 2007 sale of our process services operation generated approximately $58.7 million. We intend to continue our growth initiatives, having budgeted over $280 million of capital expenditure activity during 2008. Significant capital projects planned during the coming year include continuing development of our Fluids Division’s new Arkansas calcium chloride plant, continuing development of Maritech oil and gas properties, continuing growth of our compression services and production testing fleets, and the construction of a new corporate headquarters building. We plan to fund these growth projects with our operating cash flow and our long-term borrowing capabilities. Although we expect our outstanding debt balance to increase during 2008 as a result of our capital expenditure plans, we are carefully managing our debt balance, through the application of any excess operating cash flow. Our total debt to equity ratio was 44.4% as of December 31, 2007.
29
Demand for our products and services depends primarily on activity in the oil and gas exploration and production industry, which is significantly affected by that industry’s level of expenditures for the exploration and production of oil and gas reserves and for the plugging and decommissioning of abandoned oil and gas properties. Industry expenditures, as indicated by rig count statistics and other measures, have generally risen during the past five years and reflect the industry’s response to higher crude oil and natural gas pricing during this period. Continued overall strong demand is largely dependent on continued high oil and gas pricing, although we believe that there will also continue to be growth opportunities for our 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; and
• increasing development of oil and gas reserves abroad.
Our Fluids Division generates revenues and cash flows by manufacturing and selling completion fluids and providing filtration and associated products and engineering services to domestic and international exploration and production companies. The demand for these products and services is particularly affected by drilling activity in the Gulf of Mexico, which has remained flat or has decreased during the past several years due largely to the maturity of the producing fields in the heavily developed portions of the Gulf of Mexico. Significantly offsetting this impact is the current industry trend for drilling deep water wells that generally require greater volumes of more expensive brine solutions. In addition, international demand for our Fluids Division products has been generally increasing. The Fluids Division also provides liquid and dry calcium chloride products manufactured at its production facilities or purchased from third party suppliers to a variety of markets outside the energy industry. Fluids Division revenues increased 15.3% during 2007 compared to the prior year due to increased prices and service activity. Further growth by our Fluids Division is predicated on the availability of certain raw materials at acceptable cost levels and increasing demand for our products and services at acceptable sales prices. In late 2006, our Fluids Division executed an agreement for the favorable long-term supply for bromine, which is used in the manufacture of bromide completion fluids, and in late 2007, entered into an agreement with our previous supplier whereby in consideration of our agreement to pay $9.3 million, we were released from our remaining purchase requirements under our previous supply agreement, in order to accelerate the transition to this new favorable supply.
Our 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 diving, marine, engineering, cutting, workover, drilling and other services. The segment’s services are marketed primarily in the Gulf Coast region of the U.S., including onshore, offshore and in inland waters. 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 other 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. In addition, the segment intends to capitalize on the current demand for well abandonment and decommissioning activity in the Gulf of Mexico, including a portion of the work to be performed over the next several years on offshore properties that were damaged or destroyed by the significant hurricanes that occurred in 2005. WA&D Services revenues increased by 14.4% during 2007, primarily due to increased activity levels for well abandonment and decommissioning services, the Division’s increased capacity to perform those services, and from the March 2006 acquisition of Epic Diving & Marine Services (Epic). Approximately 8.5% of the 2007 revenues generated by the WA&D Services segment were from work performed for Maritech, and were eliminated in consolidation.
Our Maritech segment acquires, manages, develops, 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, our 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 2007, Maritech’s operations reflected significant increased production volumes and revenues primarily as a
30
result of recent exploitation and development efforts conducted primarily on oil and gas properties acquired in 2005, which more than offset the normal production declines. During the two year period ended December 31, 2007, Maritech has expended approximately $165.7 million on development and exploitation projects. Accordingly, Maritech’s revenues during 2007 increased by 27.6% compared to 2006, despite decreased realized natural gas prices during the year. In December 2007, we acquired certain proved and unproved oil and gas properties from a subsidiary of Cimarex Energy Company (the Cimarex Properties) which should provide Maritech with additional attractive development projects during 2008 and beyond. Maritech expects that the new production volumes resulting from current and future development activities will also generate increased revenues and cash flows during 2008 compared to 2007. Maritech continues to assess the remaining well intervention and debris removal efforts associated with three offshore platforms that were destroyed in the 2005 hurricanes. Maritech continues to believe that such hurricane related costs incurred and to be incurred are covered costs pursuant to its various insurance policies.
Our Production Enhancement Division generates revenues and cash flows by performing flowback pressure, volume testing, wellhead compression, and other services for oil and gas producers. The primary testing markets served are in Texas, New Mexico, Colorado, Oklahoma, Arkansas, Louisiana, the U.S. Gulf of Mexico, and certain international markets. The Division’s production testing operations are generally driven by the demand for natural gas and oil and the resulting industry drilling and completion activities in the markets which the Division serves. Compressco, the Division’s wellhead compression service provider, markets its services principally in the mid-continent, mid-western, western, Rocky Mountain, and Gulf Coast regions of the United States as well as in western Canada, Mexico, and other Latin American countries. Demand for wellhead compression services is generally driven by the need to boost production in certain mature gas wells with declining production. Production Enhancement Division revenues increased 34.0% in 2007 as compared to 2006, primarily due to the growth of the Division’s existing domestic production testing and Compressco operations, as well as from a March 2006 acquisition, which expanded the Division’s production testing market territory into western Texas and eastern New Mexico. We anticipate continued growth in revenues and cash flows from the Division during 2008, as its domestic operations continue to grow as a result of increased industry activity, and as the Division continues to seek new domestic and international markets for its testing and Compressco operations.
Critical Accounting Policies and Estimates
In preparing our consolidated financial statements, we make assumptions, estimates, and judgments that affect the amounts reported. We periodically evaluate these estimates and judgments, including those related to potential impairments of long-lived assets (including goodwill), the collectibility of accounts receivable, and the current cost of future abandonment and decommissioning obligations. “Note B – Summary of Significant Accounting Policies” to the Consolidated Financial Statements contains the accounting policies governing each of these matters. Our estimates are based on historical experience and on future expectations, which we believe are reasonable. The combination of these factors forms the basis for judgments made about the carrying values of assets and liabilities that are not readily apparent from other sources. These judgments and estimates may change as new events occur, as new information is acquired, and 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 a significant impact on the carrying value of these assets and, particularly in periods of prolonged down cycles, may result in impairment charges.
31
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. 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 we earn in performing such abandonment and decommissioning operations on Maritech’s properties is recorded as the work is performed. The recorded decommissioning liability associated with a specific property is fully extinguished when the property is completely abandoned. Once a Maritech well abandonment and decommissioning project is performed, any remaining decommissioning liability in excess of the actual cost of the work performed is recorded as additional profit on the project and included in earnings in the period in which the project is completed. Conversely, actual costs in excess of the decommissioning liability are charged against earnings in the period in which the work is performed. We review the adequacy of our decommissioning liability whenever indicators suggest that either the amount or timing of the estimated cash flows underlying the liability have changed materially. The 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 under contracts which are typically of short duration, and that provide for either lump-sum turnkey charges or specific time, material, and equipment charges, which are billed in accordance with the terms of such contracts. With regard to turnkey contracts, revenue is recognized using the percentage-of-completion method based on the ratio of costs incurred to total estimated costs at completion. 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 anticipated future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis
32
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. In addition, pursuant to FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes,” which we adopted on January 1, 2007, we consider many factors when evaluating and estimating income tax uncertainties. These factors include an evaluation of the technical merits of the tax position as well as the amounts and probabilities of the outcomes that could be realized upon ultimate settlement. The actual resolution of those uncertainties will inevitably differ from those estimates, and such differences may be material to the financial statements.
Acquisition Purchase Price Allocations – We account for acquisitions of businesses using the purchase method, which requires the allocation of the purchase price based on the fair values of the assets and liabilities acquired. We estimate the fair values of the assets and liabilities acquired using accepted valuation methods, and in many cases, such estimates are based on our judgments as to the future operating cash flows expected to be generated from the acquired assets throughout their estimated useful lives. We have completed several acquisitions during the past several years and have accounted for the various assets (including intangible assets) and liabilities acquired based on our estimate of fair values. Goodwill represents the excess of acquisition purchase price over the estimated fair values of the net assets acquired.
Stock-Based Compensation – Effective January 1, 2006, we adopted the fair value recognition provisions of Statement of Financial Accounting Standard 123(R), “Share-Based Payment” (SFAS No. 123R) using the modified prospective transition method. Under the modified prospective transition method, compensation cost recognized during 2006 and 2007 includes: (a) compensation cost for all share-based payments granted prior to, but not yet vested as of January 1, 2006, based on the grant date fair value estimated in accordance with the original provisions of SFAS No. 123 (as amended), “Accounting for Share-Based Compensation” (SFAS No. 123), and (b) compensation cost for all share-based payments granted beginning January 1, 2006, based on the grant date fair value estimated in accordance with the provisions of SFAS No. 123R. Prior to the adoption of SFAS 123R, we accounted for stock-based compensation using the intrinsic value method, whereby the compensation cost for stock options was measured as the excess, if any, of the quoted market price of our stock at the date of the grant over the amount an employee was to pay to acquire the stock. In accordance with the modified prospective transition method, results for prior periods have not been restated.
We estimate the fair value of share-based payments of stock options using the Black-Scholes option-pricing model. This option-pricing model requires a number of assumptions, of which the most significant are: expected stock price volatility, the expected pre-vesting forfeiture rate, and the expected option term (the amount of time from the grant date until the options are exercised or expire). Expected volatility is calculated based upon actual historical stock price movements over the most recent periods equal to the expected option term. Expected pre-vesting forfeitures are estimated based on actual historical pre-vesting forfeitures over the most recent periods for the expected option term.
33
Results of Operations
The following data should be read in conjunction with the Consolidated Financial Statements and the associated Notes contained elsewhere in this report.
| Percentage of Revenues |
Period-to-Period |
|||||||||
Year Ended December 31, |
Change |
|||||||||
| Consolidated Results of Operations |
2007 |
|
2006 |
|
2005 |
|
2007 vs 2006 |
|
2006 vs 2005 |
|
Revenues |
100.0% |
100.0% |
100.0% |
28.0% |
|
50.8% |
||||
Cost of revenues |
88.2% |
67.1% |
75.7% |
68.2% |
33.6% |
|||||
Gross profit |
11.8% |
|
32.9% |
24.3% |
(54.0% |
) |
104.4% |
|||
General and administrative expense |
10.2% |
12.0% |
13.6% |
8.6% |
32.7% |
|||||
Operating income |
1.7% |
20.9% |
10.7% |
(89.7% |
) |
196.0% |
||||
|
|
|||||||||
Interest expense |
1.8% |
1.8% |
|
1.2% |
31.2% |
116.1% |
||||
Interest income |
0.1% |
0.0% |
0.1% |
110.1% |
5.5% |
|||||
Other income (expense), net |
0.3% |
0.6% |
0.7% |
(42.3% |
) |
31.6% |
||||
| Income before income taxes and discontinued operations |
0.2% |
19.8% |
10.2% |
(98.6% |
) |
192.9% |
||||
| Net income before discontinued operations |
0.1% |
13.0% |
6.8% |
(98.8% |
) |
187.0% |
||||
Discontinued operations, net of tax |
2.8% |
0.3% |
0.6% |
1278.9% |
(38.7% |
) |
||||
Net income |
2.9% |
13.3% |
7.5% |
(71.8% |
) |
167.7% |
||||
Year Ended December 31, |
|||||||||
2007 |
2006 |
2005 |
|||||||
(In Thousands) |
|||||||||
Revenues |
|||||||||
Fluids Division |
$ |
282,074 |
$ |
244,549 |
$ |
221,368 |
|||
Well Abandonment & Decommissioning (WA&D) Division |
|||||||||
WA&D Services |
341,082 |
298,185 |
141,947 |
||||||
Maritech |
214,154 |
167,808 |
65,152 |
||||||
Intersegment eliminations |
(29,057 |
) |
(73,859 |
) |
(6,031 |
) |
|||
Total |
526,179 |
392,134 |
201,068 |
||||||
Production Enhancement Division |
176,684 |
|
131,849 |
87,104 |
|||||
Intersegment eliminations |
(2,454 |
) |
(737 |
) |
(291 |
) |
|||
|
982,483 |
767,795 |
509,249 |
||||||
Gross profit |
|||||||||
Fluids Division |
38,620 |
85,712 |
51,551 |
||||||
Well Abandonment & Decommissioning (WA&D) Division |
|||||||||
WA&D Services |
49,110 |
64,088 |
32,468 |
||||||
Maritech |
(45,631 |
) |
59,527 |
8,060 |
|||||
Intersegment eliminations |
6,225 |
(7,865 |
) |
(34 |
) |
||||
Total |
9,704 |
115,750 |
40,494 |
||||||
Production Enhancement Division |
69,498 |
52,513 |
32,587 |
||||||
Other |
(1,439 |
) |
(1,171 |
) |
(961 |
) |
|||
|
116,383 |
252,804 |
123,671 |
||||||
| Income before taxes and discontinued operations |
|||||||||
Fluids Division |
10,897 |
60,939 |
33,805 |
||||||
Well Abandonment & Decommissioning (WA&D) Division |
|||||||||
WA&D Services |
33,496 |
51,007 |
21,370 |
||||||
Maritech |
(49,815 |
) |
55,105 |
4,871 |
|||||
Intersegment eliminations |
6,225 |
(7,865 |
) |
(34 |
) |
||||
Total |
(10,094 |
) |
98,247 |
26,207 |
|||||
Production Enhancement Division |
52,302 |
39,141 |
22,131 |
||||||
Corporate overhead |
(50,943 |
) |
(45,958 |
) |
(30,114 |
) |
|||
|
2,162 |
152,369 |
52,029 |
||||||
34
2007 Compared to 2006
Consolidated Comparisons
Revenues and Gross Profit – Total consolidated revenues for the year ended December 31, 2007 were $982.5 million compared to $767.8 million for the prior year, an increase of 28.0%. Consolidated gross profit decreased to $116.4 million during 2007 compared to $252.8 million in the prior year, a decrease of 54.0%. Consolidated gross profit as a percentage of revenue was 11.8% during 2007 compared to 32.9% during the prior year period. Our profitability during 2007 was significantly affected by several factors, which are discussed in detail in the Divisional Comparisons section below.
General and Administrative Expenses – General and administrative expenses were $99.9 million during 2007 compared to $92.0 million during the prior year, an increase of $7.9 million or 8.6%. This increase was primarily due to the increased headcount necessary to support our revenue growth and included approximately $6.8 million of increased salary, benefits, contract labor costs, and other associated employee expenses, net of decreased incentive compensation. The increase also included approximately $1.4 million of increased office expenses and approximately $2.3 million of increased insurance and bad debt expenses, which were partially offset by approximately $2.6 million of decreased professional services and other general expenses. General and administrative expenses as a percentage of revenue were 10.2% during 2007 compared to 12.0% during the prior year.
Other Income and Expense – Other income and expense was $2.8 million of income during 2007 compared to $4.9 million of income during 2006, due to approximately $2.5 million of decreased gains from sales of assets and approximately $1.2 million of decreased equity from earnings of unconsolidated joint ventures. These decreases were partially offset by approximately $1.6 million of increased other income, primarily due to a $1.2 million legal settlement received during the current year period.
Interest Expense and Income Taxes – Net interest expense increased from $13.3 million during 2006 to $17.2 million during the current year due to increased borrowings of long-term debt used to fund our capital expenditure and acquisition requirements during 2006 and 2007. Interest expense will increase in future periods to the extent additional borrowings are used to fund our acquisition and capital expenditure plans. Our provision for income taxes during 2007 decreased to $0.9 million compared to $52.5 million during the prior year, primarily due to decreased earnings.
Net Income – Net income before discontinued operations was $1.2 million during 2007 compared to $99.9 million in the prior year, a decrease of $98.7 million. Net income per diluted share before discontinued operations was $0.02 on 75,920,768 average diluted shares outstanding during 2007 compared to $1.33 on 74,823,808 average diluted shares outstanding during the prior year.
During the fourth quarter of 2007, we sold our process services operation for approximately $58.7 million, net of certain adjustments, as such operations were not a strategic part of our core operations. In addition, during the fourth quarter of 2006, we made the decision to discontinue our Venezuelan fluids and production testing businesses due to several factors, including the changing political climate in that country. Income from discontinued operations was $27.6 million during 2007 compared to $2.0 million during 2006, primarily due to the $25.8 million after tax gain on sale of the process services operations.
Net income was $28.8 million during 2007 compared to $101.9 million in the prior year, a decrease of $73.1 million. Net income per diluted share was $0.38 on 75,920,768 average diluted shares outstanding during 2007 compared to $1.36 on 74,823.808 average diluted shares outstanding in the prior year.
Divisional Comparisons
Fluids Division – Fluids Division revenues during 2007 were $282.1 million, compared to $244.5 million during the prior year, an increase of $37.5 million, or 15.3%. Approximately $20.2 million of this increase was due to increased service activity, particularly for onshore services. In September 2006 and April 2007, the Division completed the acquisitions of certain service assets and operations, expanding the Division’s completion services operations and allowing it to provide such services to customers in the
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Arkansas, New Mexico, TexOma, and ArkLaTex regions. We expect these acquired operations to continue to provide increased service revenues to the Division in the future, as much of the anticipated increase during 2007 was negatively impacted by rainy weather conditions during a portion of the year. To a lesser extent, the increased revenues were also due to increased product pricing and international sales of the Division’s chemicals and CBF products. A portion of the demand for the Division’s products and services is affected by the level of drilling activity, particularly deepwater drilling, in the Gulf of Mexico region.
Fluids Division gross profit decreased to $38.6 million during 2007, compared to $85.7 million during the prior year, a decrease of $47.1 million or 54.9%. Gross profit as a percentage of revenue decreased to 13.7% during 2007, from 35.0% during the prior year. This decrease was primarily due to the increased cost of raw materials for the Division’s products, which particularly affected the profitability of the Division’s offshore operations. In addition, weather conditions during much of 2007 negatively impacted the Division’s onshore and completion services operations. A favorable long-term supply for certain of the Division’s raw material needs has been secured, and, in December 2007, the Division terminated its remaining purchase commitment under its previous supply agreement in consideration of its agreement to pay $9.3 million, which was charged to operations during the fourth quarter of 2007. As a result, the Division expects to purchase its future raw material needs at a more favorable cost, which will result in cheaper finished goods inventory costs, which should improve the Division’s gross profit, particularly after it sells its remaining higher cost inventory.
Fluids Division income before taxes during 2007 totaled $10.9 million compared to $60.9 million during 2006, a decrease of $50.0 million or 82.1%. This decrease was primarily generated by the $47.1 million decrease in gross profit discussed above, along with approximately $3.6 million of increased administrative expenses, partially offset by approximately $0.9 million of increased other income, primarily from gains from foreign currency and sales of assets.
WA&D Division – WA&D Division revenues increased significantly from $392.1 million during 2006 to $526.2 million during 2007, an increase of $134.0 million or 34.2%. WA&D Division gross profit during 2007 totaled $9.7 million compared to $115.8 million during the prior year, a decrease of $106.0 million or 91.6%. WA&D Division loss before taxes was $10.1 million during 2007 compared to $98.2 million of income before taxes during the prior year, a decrease of $108.3 million or 110.3%.
The Division’s WA&D Services operations revenues increased to $341.1 million during 2007 compared to $298.2 million in the prior year, an increase of $42.9 million or 14.4%. Excluding intercompany work performed for Maritech, WA&D Services revenues increased by $87.7 million, or 39.1%. Approximately $30.7 million of the segment’s revenue increase was as a result of the March 2006 acquisition of the assets and operations of Epic and the subsequent expansion and refurbishment of Epic’s dive support vessel fleet, which was completed in early 2007, although one of these dive support vessels was idled during a portion of the year for mechanical problems. Additional segment revenue increases were primarily due to increased vessel activity levels during much of 2007, although the utilization of these vessels was somewhat limited due to weather conditions during the second and third quarters. With its current fleet of three heavy lift vessels, the Division aims to continue to capitalize on the current demand for well abandonment and decommissioning activity in the Gulf of Mexico, including the remaining work to be performed over the next several years on offshore properties that were damaged or destroyed in 2005 by Hurricanes Katrina and Rita. The September 2007 acquisition of the assets and operations of EOT Rentals, LLC (EOT) also generated approximately $3.4 million of increased revenues for cutting tool services provided to the Division’s customers, and is expected to contribute an additional increase in the future.
The WA&D Services segment of the Division reported a $15.0 million decrease in gross profit, a 23.4% decrease, from $64.1 million during 2006 to $49.1 million during the current year. WA&D Services’ gross profit as a percentage of revenues decreased to 14.4% during the current year compared to 21.5% during the prior year. Despite the increase in revenues, the segment experienced operating inefficiencies caused by weather disruptions and unfavorable contract issues that negatively affected gross profit, particularly during the first three quarters. In addition, Epic’s newly refurbished dive service vessels, which were placed into service during the first quarter of 2007, also experienced lower utilization due to weather and maintenance issues, with one of its vessels experiencing significant mechanical problems during
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most of the third quarter. During 2007, the WA&D Services segment charged approximately $2.0 million to operations related to a contested insurance claim. In response to the current market demand, we have modified the segment’s approach to providing our services associated with platforms that were damaged or destroyed by the 2005 storms. We expect that the segment’s gross profit margin will increase during future quarters. Intercompany profit on work performed for Maritech’s insured storm damage repairs is not recognized until such time as the associated insurance claim proceeds are collected by Maritech. During 2006, intercompany profit of $7.9 million was eliminated in consolidation. During 2007, insurance claim collections related to prior year intercompany work performed for Maritech contributed to the recognition of an additional $6.2 million of Division intercompany gross profit.
The WA&D Services segment’s income before taxes decreased from $51.0 million during 2006 to $33.5 million during the current year, a decrease of $17.5 million or 34.3%. This decrease was due to the $15.0 million decrease in gross profit described above, as well as a $3.8 million increase in administrative expenses due to the Division’s growth, partially offset by increased other income of approximately $1.3 million, primarily from a legal settlement received during the current year.
The Division’s Maritech operations reported revenues of $214.2 million during 2007 compared to $167.8 million during the prior year, an increase of $46.3 million, or 27.6%. Increased production volumes generated increased revenues of approximately $57.1 million, primarily from successful exploitation and development activities. During the past two years, Maritech has expended approximately $165.7 million on exploitation and development activities, and such activity is expected to continue in the future, particularly following Maritech’s acquisition of the Cimarex Properties in December 2007. In addition, during a portion of the first quarter of 2006, many of Maritech’s producing properties remained shut-in as a result of third quarter 2005 hurricanes. These revenue increases from increased production were partially offset by approximately $7.9 million of lower realized oil and gas prices, including approximately $17.4 million from decreased pricing for Maritech’s natural gas production. Realized natural gas prices during 2006 included the impact of a natural gas swap derivative hedge contract, which resulted in Maritech realizing a price of $10.465/MMBtu throughout 2006 for a portion of its gas production. This derivative contract expired at the end of 2006. During 2007 and early 2008, Maritech entered into several new commodity hedge contracts extending through 2010, including natural gas swap derivative hedge contracts, which resulted in Maritech receiving an average price of $8.13/MMBtu for a portion of its 2007 natural gas production. In addition, during 2007, Maritech recorded approximately $2.9 million less of prospect and other fee revenues compared to the prior year.
The Division’s Maritech operations reported a negative gross profit of $45.6 million during 2007 compared to $59.5 million of positive gross profit during 2006, a decrease of $105.2 million or 176.7%. This decrease occurred despite the segment’s exploitation and development activity, which resulted in the addition of several newly productive wells. Maritech’s gross profit as a percentage of revenues also decreased during the current year to a negative 21.3% compared to a positive 35.5% during the prior year. A large portion of this decrease in Maritech’s gross profit was due to approximately $72.7 million of increased oil and gas property impairments. Maritech recorded $76.1 million of impairments during 2007, primarily due to the reversal of anticipated insurance recoveries as a result of certain future well intervention and debris removal costs being contested by our insurance provider, compared to $3.4 million of impairments during 2006. This decrease in anticipated insurance recoveries further reduced Maritech’s gross profit associated with certain hurricane damage repair costs incurred, and resulted in a $13.5 million charge to operating expense, as the timing and amount of the reimbursement of these costs has also become indeterminable. During the fourth quarter of 2007, Maritech filed a lawsuit against certain of its insurance underwriters related to certain contested well intervention and debris removal costs incurred and to be incurred on certain offshore platforms which were destroyed by 2005 hurricanes. In addition, Maritech’s gross profit decreased due to the decreased realized commodity prices discussed above, $35.3 million of increased depletion expense, $8.4 million of increased excess decommissioning and abandonment costs, and $1.3 million of increased insurance premiums. During 2007, Maritech also recorded increased dry hole costs of approximately $0.6 million and reflected decreased gains from insurance proceeds compared to the prior year period of approximately $7.3 million.
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The Division’s Maritech operations reported a loss before taxes of $49.8 million during 2007 compared to $55.1 million of income before taxes during the prior year, a $104.9 million decrease. This 190.4% decrease was due to the $105.2 million decrease in gross profit and approximately $2.7 million of decreased gains on sales of properties, partially offset by $3.0 million of decreased administrative costs compared to the prior year, primarily due to decreased incentive compensation.
Production Enhancement Division – Production Enhancement Division revenues increased from $131.8 million during 2006 to $176.7 million during the current year, an increase of $44.8 million or 34.0%. This increase was primarily due to $27.8 million of increased revenues from the Division’s production testing operations, particularly from increased demand for services provided by the Beacon Resources, LLC subsidiary (Beacon), which was acquired in February 2006. Increased production testing activity in Mexico and Brazil also contributed to the increased revenues during 2007. Compressco revenues also increased by approximately $16.5 million compared to the prior year period, due to its overall growth both domestically, and in Latin America. Compressco continues to add to its compressor fleet to meet the growing demand for its services. In addition, the Division recorded revenues of approximately $0.6 million during 2007 related to an environmental services contract.
Production Enhancement Division gross profit increased from $52.5 million during 2006 to $69.5 million during 2007, an increase of $17.0 million or 32.3%. Each of the areas highlighted in the revenue discussion above contributed to the higher gross profits. Gross profit as a percentage of revenues decreased slightly, however, from 39.8% during 2006 to 39.3% during 2007, primarily due to increased operating expenses for the Division’s domestic production testing operations.
Income before taxes for the Production Enhancement Division increased from $39.1 million during 2006 to $52.3 million during the current year, an increase of $13.2 million, or 33.6%. This increase was primarily due to the $17.0 million of increased gross profit discussed above, less approximately $3.2 million of increased administrative costs and approximately $0.6 million of decreased other income, primarily from decreased equity earnings in an unconsolidated joint venture and from decreased foreign currency gains.
Corporate Overhead – Corporate Overhead includes corporate general and administrative expenses, interest income and expense, and other income and expense. Such expenses and income are not allocated to our operating divisions, as they relate to our general corporate activities. Corporate overhead increased by $4.9 million from $46.0 million during 2006 to $50.9 million during 2007, primarily due to increased net interest expense of approximately $4.1 million. This increase in corporate interest expense during 2007 was due to the increased outstanding balance of long-term debt, which was used to fund our capital expenditure requirements during 2006 and 2007. Corporate general and administrative expenses increased by approximately $0.4 million compared to the prior year, as approximately $0.9 million of increased office expenses and approximately $0.7 million of increased insurance expenses were offset by approximately $1.2 million of decreased personnel related costs, primarily due to decreased incentive compensation recorded during 2007. In addition, during 2007, we reflected approximately $0.3 million of decreased other income.
2006 Compared to 2005
Consolidated Comparisons
Revenues and Gross Profit – Total consolidated revenues for the year ended December 31, 2006 were $767.8 million compared to $509.2 million during 2005, an increase of 50.8%. Consolidated gross profit also increased significantly to $252.8 million during 2006 compared to $123.7 million during 2005, an increase of 104.4%. Consolidated gross profit as a percentage of revenue was 32.9% during 2006 compared to 24.3% during 2005.
General and Administrative Expenses – General and administrative expenses were $92.0 million during 2006 compared to $69.4 million during 2005, an increase of $22.7 million or 32.7%. This increase was primarily due to our overall growth and included approximately $19.0 million of increased salary, incentive, benefits and other associated employee expenses; approximately $2.2 million of increased
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office expenses; approximately $1.4 million of higher professional service expenses; and approximately $0.9 million of increased insurance expenses, which was partially offset by approximately $0.9 million of decreased other general expenses. Included as part of increased employee expenses during 2006 is approximately $3.4 million of compensation expense recorded pursuant to SFAS No. 123R, which was adopted on January 1, 2006. General and administrative expenses as a percentage of revenue decreased to approximately 12.0% during 2006 compared to approximately 13.6% during 2005.
Other Income and Expense – Other income and expense was $4.9 million of income during 2006 compared to $3.7 million of income during 2005, due to approximately $2.6 million of additional gains on sales of assets in 2006. This increase was partially offset by approximately $1.4 million of decreased other income, consisting primarily of decreased gains from foreign currency fluctuations and decreased earnings from an unconsolidated joint venture.
Interest Expense and Income Taxes – Net interest expense increased from $6.0 million during 2005 to $13.3 million during 2006 due to the significant borrowings of long-term debt used to fund our capital expenditure requirements and acquisitions during the periods. Our provision for income taxes during 2006 increased to $52.5 million compared to $17.2 million during 2005, primarily due to increased earnings.
Net Income – Net income before discontinued operations was $99.9 million during 2006 compared to $34.8 million during 2005, an increase of $65.1 million. Net income per diluted share before discontinued operations was $1.33 on 74,823,808 average diluted shares outstanding during 2006 compared to $0.48 on 72,136,964 average diluted shares outstanding in 2005.
During the fourth quarter of 2007, we sold our process services operation for approximately $58.7 million, net of certain adjustments. In addition, during the fourth quarter of 2006, we made the decision to discontinue our Venezuelan fluids and production testing businesses due to several factors, including the changing political climate in that country. Net income from discontinued operations per diluted share during 2006 was $0.03 compared to a net income per diluted share of $0.05 during 2005, primarily due to decreased process services profitability levels.
Net income was $101.9 million during 2006 compared to $38.1 million during 2005, an increase of $63.8 million. Net income per diluted share was $1.36 on 74,823,808 average diluted shares outstanding during 2006 compared to $0.53 on 72,136,964 average diluted shares outstanding during 2005.
Divisional Comparisons
Fluids Division – Fluids Division revenues increased from $221.4 million during 2005 to $244.5 million during 2006, an increase of $23.2 million or 10.5%. This increase was primarily due to increased product pricing and service activity, which more than offset the decreased production from our Lake Charles calcium chloride manufacturing facility, which began operating at a reduced level beginning in late 2005, due to the loss of a major raw material supplier.
Fluids Division gross profit increased significantly to $85.7 million during 2006, compared to $51.6 million during 2005, an increase of $34.2 million or 66.3%. Gross profit as a percentage of revenue increased from 23.3% during 2005 to 35.0% during 2006. This increase was primarily due to the increased prices, a more favorable mix of higher-margin products and services, and the sale of lower cost inventory during the period. Inventory costs increased during 2006 for the Division’s products and raw materials.
Fluids Division income before taxes during 2006 totaled $60.9 million compared to $33.8 million during 2005, an increase of $27.1 million or 80.3%. This increase was generated by the $34.2 million increase in gross profit discussed above, which was partially offset by approximately $5.5 million of increased administrative expenses, approximately $0.7 million of decreased gains on sales of assets, and approximately $0.9 million of decreased gains on foreign currency fluctuations.
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WA&D Division – WA&D Division revenues increased to $392.1 million during 2006 compared to $201.1 million during 2005, an increase of $191.1 million or 95.0%. WA&D Division gross profit during 2006 totaled $115.8 million compared to $40.5 million during 2005, an increase of $75.3 million or 185.8%. WA&D Division income before taxes was $98.2 million during 2006 compared to $26.2 million during 2005, an increase of $72.0 million or 274.9%.
The Division’s WA&D Services segment revenues increased to $298.2 million during 2006 compared to $141.9 million during 2005, an increase of $156.2 million or 110.1%. This increase was primarily due to the increased well abandonment and decommissioning activity in the Gulf of Mexico region following the significant hurricanes during the third quarter of 2005 as well as the Division’s increased capacity to serve its customers. Approximately $67.8 million of this increase was from increased work performed for Maritech, and was eliminated in consolidation. The Division anticipates continued increased demand for its services, as operators repair or decommission damaged platforms and pipelines and accelerate their abandonment and decommissioning plans due, in part, to the risk of future storm damage and due to the increased insurance costs related to offshore assets. To increase its capacity to provide services, the Division purchased the DB-1 derrick barge in February 2006, made extensive repairs and modifications to one of its existing vessels, and entered into arrangements to lease three additional vessels: the Anna IV, which was utilized from March to November 2006; the Orion, which was leased beginning in July 2006; and the Achiever, which was leased beginning in September 2006. These vessel leases have subsequently been terminated. The DB-1 was refurbished and it began operating in July 2006. The Orion and the Achiever were placed in service beginning September and October 2006, respectively. The March 2006 acquisition of the assets of Epic, a full service diving operation, contributed approximately $59.3 million of revenues during 2006. Subsequent to the acquisition of Epic, the Division purchased and subsequently refurbished a dynamically positioned dive support vessel, which was renamed the Epic Diver, and refurbished two other Epic dive support vessels. Each of these vessels was placed in service during the first quarter of 2007, and they are expected to contribute additional revenues in the future. The Epic acquisition allows the Division to provide additional services to its customers, including Maritech, and to supply a substantial portion of such services for WA&D Services operations.
The WA&D Services segment of the Division reported a $31.6 million increase in gross profit, from $32.5 million during 2005 to $64.1 million during 2006. WA&D Services gross profit as a percentage of revenues decreased to 21.5% during 2006 compared to 22.9% during 2005, primarily due to increased operating expenses caused by weather disruptions. In addition, the WA&D Services segment incurred certain expenses related to the expansion of its heavy lift vessel fleet and the refurbishment of one of its existing heavy lift vessels and several of its dive support vessels. These increased costs were more than offset by the overall increase in segment revenues, and by diving and support operations, which contributed $18.0 million of segment gross profit. The Division’s increased vessel fleet and the addition of the 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.
WA&D Services segment income before taxes increased to $51.0 million during 2006 compared to $21.4 million during 2005, an increase of $29.6 million or 138.7%. This increase was due to the $31.6 million increase in gross profit described above, less approximately $2.0 million, primarily from increased administrative expenses, including the administrative expenses incurred during the year associated with Epic’s operations.
The Division’s Maritech segment reported revenues of $167.8 million during 2006 compared to $65.2 million during 2005, an increase of $102.7 million or 157.6%. Approximately $73.0 million of this increase was from increased production volumes primarily due to acquisitions of producing properties and successful exploitation and development activities. During the third quarter of 2005, Maritech acquired producing oil and gas properties in three significant acquisitions. 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, which caused varying levels of damage to the majority of its offshore production platforms and destroyed three of its platforms and one of its production facilities. While the vast majority of Maritech’s properties have resumed production, a small portion of Maritech’s daily production remains shut-in. In addition, Maritech’s revenues increased approximately $28.1 million during 2006 as a result of higher realized oil and gas commodity prices
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compared to the prior year period. Also, Maritech reported $1.5 million of increased prospect fee and service revenue during the current year period. Realized natural gas prices during 2006 include the impact of a natural gas swap derivative hedge contract that resulted in Maritech realizing a price of $10.465/MMBtu throughout the year for a portion of its gas production. This derivative contract expired as of December 31, 2006.
The Division’s Maritech segment reported gross profit of $59.5 million during 2006 compared to $8.1 million during 2005, a $51.5 million increase. Maritech’s gross profit as a percentage of revenues also increased significantly during 2006 to 35.5% compared to 12.4% during 2005. The significant growth in Maritech’s production volumes—primarily resulting from the acquisitions completed during the third quarter of 2005, plus the increased realized commodity prices discussed above—was partially offset by approximately $51.2 million of increased operating expenses, including approximately $28.5 million of increased depreciation, depletion, and accretion costs primarily associated with production from the newly acquired and developed properties. This increase in operating expenses also includes approximately $13.4 million of increased insurance premium costs and approximately $5.2 million of well intervention costs and other hurricane damage repair costs, charged to earnings, which we believe will not be reimbursed under our insurance coverage. Such costs were either incurred during the period or have been reflected as increased decommissioning liabilities on our consolidated balance sheet. Partially offsetting these increases, we included approximately $9.2 million of increased gain associated with insurance claim proceeds in excess of the net carrying value of destroyed assets. In addition, during 2005, Maritech reported an impairment charge of approximately $1.9 million as required under successful efforts accounting. The Division has completed most of the required repairs to its damaged platform facilities, and has performed certain well intervention operations on wells associated with two of the three destroyed platforms. Maritech is currently assessing the extent of the damages related to the third destroyed platform, as well as the debris removal effort for each of the destroyed platforms.
The Division’s Maritech segment reported income before taxes of $55.1 million during 2006 compared to $4.9 million during 2005, a $50.2 million increase. This increase was due to the $51.5 million increase in gross profit discussed above and $3.0 million of increased gains on sales of properties compared to the prior year period, partially offset by $4.3 million of increased administrative costs associated with Maritech’s growth.
Production Enhancement Division – Production Enhancement Division revenues increased $44.7 million during 2006 compared to 2005, from $87.1 million during 2005 to $131.8 million during 2006. This 51.4% increase was due to the increased revenues from the Division’s Compressco and production testing operations. The Division’s production testing operations revenues increased by $30.7 million during 2006 compared to 2005, due to the first quarter 2006 acquisition of Beacon, the increased activity from its domestic customers, and from recent growth of its Latin American operations, including its operation in Brazil. Compressco revenues increased by $14.1 million compared to the prior year, due to its overall growth domestically, as well as in Canada and Mexico. Compressco continues to add to its compressor fleet to meet the growing demand for its services.
Production Enhancement Division gross profit increased from $32.6 million during 2005 to $52.5 million during 2006, an increase of $19.9 million or 61.1%. Gross profit as a percentage of revenues also increased, from 37.4% during 2005 to 39.8% during 2006, reflecting the acquisition of Beacon as well as the increased demand for compressor and production testing services described above.
Income before taxes for the Production Enhancement Division increased 76.9%, from $22.1 million during 2005 to $39.1 million during 2006, an increase of $17.0 million. This increase was primarily due to the increased gross profit discussed above, plus $0.1 million of increased gains from currency fluctuation, less $2.9 million of increased administrative costs primarily associated with Beacon and Compressco, plus $0.2 million of decreased gains on asset sales.
Corporate Overhead – Corporate overhead includes corporate general and administrative expenses, corporate depreciation and amortization, interest income and expense, and other income and expense. Such expenses and income are not allocated to our operating divisions, as they relate to our general corporate activities. Corporate overhead increased from $30.1 million during 2005 to $46.0 million during 2006, primarily due to the 2006 acquisitions and the staff growth resulting from the expansion of its
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existing businesses. This growth resulted in increased administrative costs of $8.7 million. The increase in administrative costs resulted from $6.4 million of increased salary, incentive, benefit, and other associated employee expenses, including $3.4 million of compensation expense required under SFAS No. 123R; $0.9 million of increased professional fee expenses; and $1.3 million of increased office, insurance, and other general expenses. Total estimated unrecognized compensation cost from unvested stock options pursuant to SFAS No. 123R as of December 31, 2006 was approximately $10.0 million, which is expected to be recognized over a weighted average period of approximately 3.0 years. Corporate interest expense during 2006 increased by $7.2 million compared to 2005 due to the increased outstanding balance of long-term debt, which was used to fund our capital expenditure program and the acquisitions completed during the third quarter of 2005 and the first quarter of 2006.
Liquidity and Capital Resources
Over each of the past three years, we have utilized our operating cash flow and increased borrowing capacity to aggressively grow our businesses, both through acquisitions as well as through our internal capital expenditure plans. During this three year period, we have generated approximately $301.9 million of net cash flow from operating activities, $65.8 million of proceeds from asset sales and other investing activities, and $520.8 million of debt borrowings, which we used to fund approximately $525.5 million of capital expenditures, $83.1 million of business acquisitions, and $311.2 million of debt repayments. This growth strategy has resulted in us reporting total assets of approximately $1.3 billion and total long-term debt outstanding of approximately $358.0 million as of December 31, 2007. During 2007, we invested a total of approximately $235.2 million in investing activities, including approximately $276.1 million of cash capital expenditures; approximately $14.5 million for acquisitions, including the purchase of the EOT operation and a fluids transfer operation; and net of approximately $55.3 million from the disposal of our process services operation. To fund a portion of this growth, we increased our borrowings under our revolving credit facility. Our outstanding long-term debt facility is scheduled to mature no earlier than 2011. We anticipate capital expenditure activity in 2008 of over $280 million, much of which will help further grow our operations. We continue to generate increased operating cash flow from each of our operating divisions, which we plan to use to fund a majority of these anticipated capital expenditures. Cash flow in excess of our capital expenditures will be used principally to reduce the outstanding balance under our credit facility, which was approximately $170.5 million as of February 28, 2008. We have additional borrowing capacity of approximately $104.0 million as of February 28, 2008, and believe we have various options to additionally expand our capital resources should the need arise.
Operating Activities – Despite greatly reduced earnings during 2007, cash flow generated by operating activities totaled approximately $209.0 million, due to the significant non-cash charges for depreciation, oil and gas property impairments, the reversal of anticipated insurance recoveries, and other non-cash charges during the year. Operating cash flow during 2007 increased significantly compared to the prior year, as 2006 operating cash flow was net of approximately $41.5 million of cash expended for increased inventory volumes and costs, and approximately $85.6 million of increased accounts receivable, due largely to increased amounts pursuant to insured hurricane repair costs. 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. Our increased revenues from existing businesses during 2007 reflect the increased demand for a majority of our products and services, and we expect that such demand will continue to be relatively high during 2008. The operating cash flow impact from this increased demand is expected to be limited or partially offset, however, by the increased product, operating, and administrative costs required to deliver our products and services and our equipment and personnel capacity constraints.
Through December 31, 2007, we have expended approximately $125.7 million for well intervention and repair work on certain Maritech wells and platforms that were damaged or destroyed as a result of Hurricanes Katrina and Rita in 2005. We estimate that remaining storm related repairs, primarily the remaining well intervention and debris removal costs associated with three destroyed platforms, will result in approximately $50 to $70 million of additional costs, which are expected to be incurred in 2008 and beyond. Approximately $86.9 million of the repair and well intervention costs previously expended and submitted to insurance have been reimbursed; however, our insurance underwriters have continued to maintain that certain well intervention and repair costs do not qualify as covered costs under the policies. In addition, the underwriters have maintained that there is no additional
42
coverage provided under an endorsement we obtained in August 2005 for the cost of removal of these platforms or for other damage repairs on certain properties in excess of the insured values provided by our property damage policy. After continuing to provide requested information to the underwriters regarding the damaged wells, and having numerous discussions with the underwriters, brokers, and insurance adjusters, we have yet to receive the requested reimbursement for these contested costs. In late 2007, we filed a lawsuit against the underwriters in an attempt to collect the reimbursement for these well intervention costs incurred as well as future well intervention and debris removal costs to be incurred. We continue to believe that these costs are covered costs pursuant to the policies. However, during the fourth quarter of 2007, we reversed the anticipated insurance recoveries previously included in estimating Maritech’s decommissioning liability, increasing the decommissioning liability to $48.4 million to reflect the well intervention work to be performed, assuming no insurance reimbursements will be received. In addition, we reversed a portion of our anticipated insurance recoveries previously included in accounts receivable associated with certain damage repair costs incurred, resulting in a $13.5 million charge to operating expense, as the amount and timing of further reimbursements of these costs from our insurance providers are now also indeterminable. If we successfully collect reimbursements from our insurance providers, such reimbursements will be credited to operations in the periods collected.
Future operating cash flow will also be affected by the oil and gas prices received for Maritech’s production. During 2007 and early 2008, following recent acquisitions and exploitation and development drilling operations that have increased its oil and gas production levels, Maritech entered into additional oil and gas derivative transactions, some of which extend through 2010, that are designated to hedge a portion of Maritech’s operating cash flows from risks associated with the fluctuating prices of oil and natural gas.
Future operating cash flow will also be affected by the timing and amount of expenditures required for the plugging, abandonment, and decommissioning of Maritech’s oil and gas properties. The third party discounted fair value, including an estimated profit, of Maritech’s decommissioning liability as of December 31, 2007 totals $195.6 million ($221.6 million undiscounted). During 2007, we performed plugging, abandonment and decommissioning operations on a significant number of Maritech’s properties, extinguishing approximately $32.9 million of Maritech’s decommissioning liability. The cash outflow necessary to extinguish the remainder of Maritech’s decommissioning liability is expected to occur over several years, shortly after the end of each property’s productive life. The amount and timing of these cash outflows is estimated based on expected costs, as well as the timing of future oil and gas production and the resulting depletion of Maritech’s oil and gas reserves. Such estimates are imprecise and subject to change due to changing cost estimates, commodity prices, revisions of reserve estimates, and other factors. During 2007, Maritech adjusted its decommissioning liability by approximately $59.4 million, either based on the cost it incurred for work performed during the year, or related to adjusted estimates of the cost of future work to be performed. In addition, Maritech increased its decommissioning liability associated with the three offshore platforms which were destroyed during the 2005 hurricanes. Maritech estimates that future well intervention and debris removal activity associated with these destroyed platforms will cost approximately $48.4 million. Actual costs could exceed these estimates due to the non-routine nature of this work.
Maritech’s estimated 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, 2007, Maritech’s total undiscounted decommissioning obligation is approximately $276.4 million and consists of Maritech’s liability of $221.6 million, plus approximately $54.8 million, which is contractually required to be reimbursed to Maritech pursuant to such contractual arrangements with the previous owners.
Investing Activities – During 2007, we expended approximately $276.1 million of cash for capital expenditures, including the purchase of oil and gas properties, and approximately $14.5 million of net cash for acquisitions, for a total of $290.6 million. In the fourth quarter of 2007, we paid approximately $56.2 million, subject to further adjustment, for Maritech’s acquisition of oil and gas properties from Cimarex Energy (the Cimarex Properties). A majority of the productive properties will begin production in mid-2008 following the completion of a connecting pipeline and the hookup of six subsea wells. Maritech
43
is constructing this connecting pipeline, at an estimated cost of $26.9 million, which will also serve other producing properties operated by third parties. In January 2008, we paid approximately $13.5 million, subject to further adjustment, for Maritech’s acquisition of oil and gas properties from Stone Energy Company. In December 2007, we entered into an agreement to sell a portion of Maritech’s interest in certain of the newly acquired Cimarex Properties for cash, and such sale is expected to close as early as March 2008. In April 2007, we acquired a fluids transfer service operation in exchange for $8.5 million paid at closing, with additional consideration of up to $2.5 million to be paid based on revenues generated by the acquired operation over the next two years. In September 2007, we also acquired the assets and operations of EOT, an onshore and offshore cutting tools operation, for $6.1 million paid at closing, with an additional $1.0 million to be paid over the next two years. Each of the above transactions was primarily funded by long-term borrowings from our revolving bank credit facility. In December 2007, we sold our process services operation, which we identified as not a strategic part of our core operations. The sale generated available cash of approximately $55.3 million, offsetting a large portion of the capital expenditure activity discussed above, and resulting in net cash expended on investing activities of $235.2 million.
Total cash capital expenditures of approximately $276.1 million during 2007 included approximately $203.0 million by our WA&D Division. Approximately $178.4 million was expended by the Division’s Maritech subsidiary, primarily related to acquisition and development expenditures on its offshore oil and gas properties. In addition, our WA&D Division expended approximately $29.7 million relating to the WA&D Services segment operations, primarily for construction and refurbishment costs on three dive support vessels, which were placed in service during the first quarter of 2007. The Production Enhancement Division spent approximately $46.2 million, consisting of approximately $23.7 million related to Compressco compressor fleet expansion, and approximately $22.5 million to replace and enhance a portion of the production testing equipment fleet. The Fluids Division reflected approximately $18.9 million of capital expenditures, primarily related to plant expansion projects during the year and the initial phase of the El Dorado calcium chloride plant project. Corporate capital expenditures were approximately $8.0 million.
During the past two years, we have expended an aggregate of $531.6 million on cash capital expenditures and acquisitions. Of this amount, approximately $248.7 million, or 46.8%, has been for the acquisition, development and exploitation of Maritech oil and gas properties, and has resulted in significantly increased Maritech revenues and cash flows. The December 2007 acquisition of the Cimarex Properties provides Maritech with a significant portfolio of development prospects, which it intends to exploit in the years ahead. In addition to its continuing capital expenditure program, Maritech also continues to pursue the purchase of additional producing oil and gas properties as part of our strategy to support our WA&D Services operations and to provide additional exploitation and development opportunities. While future purchases of such properties may also 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.
We plan to expend over $280.0 million on additional capital additions during 2008, including Maritech’s development program. The significant majority of such planned capital expenditures is related to identified opportunities to grow and expand our existing businesses, and may be postponed or cancelled as conditions change. Projects planned during 2008 include the continuing development of our El Dorado, Arkansas calcium chloride facility and the expansion of the West Memphis, Arkansas brominated fluids production facility, plans which over the next three years are expected to total approximately $103.0 million. Also, we have begun the construction of a new corporate headquarters building located in The Woodlands, Texas, which is expected to cost approximately $39.2 million. Our growth strategy continues to include the pursuit of suitable acquisitions or opportunities to establish operations in additional niche oil and gas service markets. To the extent we consummate a significant acquisition, our liquidity position will be affected. We expect to fund our 2008 capital expenditure activity through cash flows from operations and from our bank credit facility. Should additional capital be required, we believe that we have the ability to raise such capital through the issuance of additional debt or equity.
44
Financing Activities – To fund our capital and working capital requirements, we may supplement our existing cash balances and cash flow from operating activities as needed from long-term borrowings, short-term borrowings, equity issuances, and other sources of capital. We have a revolving credit facility with a syndicate of banks, pursuant to a credit facility agreement which was amended in June 2006 and December 2006 (the Restated Credit Facility). As of February 28, 2008, following the January acquisition of additional Maritech oil and gas properties, we had an outstanding balance of $170.5 million, and $25.5 million in letters of credit and guarantees against the $300 million revolving credit facility, leaving a net availability of $104.0 million.
The Restated Credit Facility, which is scheduled to mature in 2011, is unsecured and guaranteed by certain of our material domestic subsidiaries. Borrowings generally bear interest at the British Bankers Association LIBOR rate plus 0.50% to 1.25%, depending on one of our financial ratios. As of December 31, 2007, the average interest rate on the outstanding balance under the credit facility was 5.76%. We pay a commitment fee ranging from 0.15% to 0.30% on unused portions of the facility. The Restated Credit Facility agreement contains customary covenants and other restrictions, including certain financial ratio covenants, and includes limitations on aggregate asset sales, individual acquisitions, and aggregate annual acquisitions and capital expenditures. Access to our revolving credit line is dependent upon our ability to comply with certain financial ratio covenants set forth in the Restated Credit Facility agreement. Significant deterioration of the financial ratios could result in a default under the Restated Credit Facility agreement and, if not remedied, could result in termination of the agreement and acceleration of any outstanding balances under the facility prior to 2011. The Restated Credit Facility agreement also includes cross-default provisions relating to any other indebtedness greater than a defined amount. If any such indebtedness is not paid or is accelerated and such event is not remedied in a timely manner, a default will occur under the Restated Credit Facility. We were in compliance with all covenants and conditions of our credit facility as of December 31, 2007. Our continuing ability to comply with these financial covenants centers largely upon our ability to generate adequate cash flow. Historically, our financial performance has been more than adequate to meet these covenants, and we expect this trend to continue.
In September 2004, we issued and sold through a private placement $55 million in aggregate principal amount of Series 2004-A Senior Notes and 28 million Euros (approximately $41.2 million equivalent at December 31, 2007) in aggregate principal amount of Series 2004-B Senior Notes pursuant to a Master Note Purchase Agreement. The Series 2004-A Senior Notes bear interest at a fixed rate of 5.07% and mature on September 30, 2011. The Series 2004-B Senior Notes bear interest at a fixed rate of 4.79% and also mature on September 30, 2011. In April 2006, we issued and sold through a private placement, $90.0 million in aggregate principal amount of Series 2006-A Senior Notes pursuant to our existing Master Note Purchase Agreement dated September 2004, as supplemented (the Series 2006-A Senior Notes, together with the Series 2004-A Senior Notes and Series 2004-B Senior Notes are collectively referred to as the Senior Notes). Interest on the 2004-A and 2004-B Senior Notes is due semiannually on March 30 and September 30 of each year. The Series 2006-A Senior Notes bear interest at the fixed rate of 5.90%, and mature on April 30, 2016. Interest on the 2006-A Senior Notes is due semiannually on April 30 and October 30 of each year. Pursuant to the Master Note Purchase Agreement, as supplemented, the Senior Notes are unsecured and guaranteed by substantially all of our wholly owned subsidiaries. The Master Note Purchase Agreement contains customary covenants and restrictions, requires us 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. We were in compliance with all covenants and conditions of our Senior Notes as of December 31, 2007. Upon the occurrence and during the continuation of an event of default under the Master 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, we filed a universal acquisition shelf registration statement on Form S-4 that permits us to issue up to $400 million of common stock, preferred stock, senior and subordinated debt securities, and warrants in one or more acquisition transactions that we may undertake from time to time. As part of our strategic plan, we evaluate opportunities to acquire businesses and assets and intend to consider attractive acquisition opportunities, which may involve the payment of cash or the issuance of debt or
45
equity securities. Such acquisitions may be funded with existing cash balances, funds under our credit facility, or securities issued under our acquisition shelf registration on Form S-4.
In addition to the aforementioned revolving credit facility, we fund our short-term liquidity requirements from cash generated by operations, short-term vendor financing and, to a lesser extent, from leasing with institutional leasing companies. We believe we have the ability to generate additional capital to fund our capital expenditure plans through the issuance of additional debt or equity.
In January 2004, our Board of Directors authorized the repurchase of up to $20 million of our common stock. During 2006 and 2007, we made no purchases of our common stock pursuant to this authorization. During 2005, we purchased 130,950 shares of our common stock at a cost of approximately $2.4 million pursuant to this authorization. We also received $12.1 million, $11.4 million and $10.5 million during 2007, 2006 and 2005, respectively, from the exercise of stock options by employees.
Contractual Obligations
The table below summarizes our contractual cash obligations as of December 31, 2007:
Payments Due |
|||||||||||||||||||||
Total |
2008 |
|
2009 |
2010 |
2011 |
2012 |
Thereafter |
||||||||||||||
(In
Thousands) |
|||||||||||||||||||||
Long-term debt |
$ |
358,024 |
$ |
– |
$ |
– |
$ |
– |
$ |
268,024 |
$ |
– |
$ |
90,000 |
|||||||
Interest on debt |
96,578 |
19,965 |
19,965 |
19,965 |
13,697 |
5,310 |
17,676 |
||||||||||||||
Purchase obligations |
247,250 |
19,378 |
13,622 |
11,875 |
11,875 |
11,875 |
178,625 |
||||||||||||||
Decommissioning and other asset retirement obligations(1) |
199,506 |
28,593 |
68,947 |
20,446 |
9,230 |
25,816 |
46,474 |
||||||||||||||
Operating leases |
14,321 |
6,715 |
3,280 |
2,008 |
1,415 |
766 |
137 |
||||||||||||||
Total contractual cash obligations(2) |
$ |
915,679 |
$ |
74,651 |
$ |
105,814 |
$ |
54,294 |
$ |
304,241 |
$ |
43,767 |
$ |
332,912 |
|||||||
(1) Decommissioning liabilities related to oil and gas properties generally must be satisfied within twelve months after a property’s lease expires. Lease expiration generally occurs six months after the last producing well on the lease ceases production. We have estimated the timing of these payments based upon anticipated lease expiration dates, which are subject to many changing variables, including the estimated life of the producing oil and gas properties, which is affected by changing oil and gas commodity prices. The amounts shown represent the estimated fair values as of December 31, 2007.
(2) Amounts exclude other long-term liabilities reflected in our Consolidated Balance Sheet that do not have known payment streams. These excluded amounts include approximately $5.3 million of liabilities under FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes,” as we are unable to reasonably estimate the ultimate amount or timing of settlements. See “Note F – Income Taxes,” in the Notes to Consolidated Financial Statements for further discussion.
Off Balance Sheet Arrangements
An “off balance sheet arrangement” is defined as any contractual arrangement to which an entity that is not consolidated with us is a party, under which we have, or in the future may have:
• any obligation under a guarantee contract that requires initial recognition and measurement under U.S. Generally Accepted Accounting Principles;
• a retained or contingent interest in assets transferred to an unconsolidated entity or similar arrangement that serves as credit, liquidity, or market risk support to that entity for the transferred assets;
• any obligation under certain derivative instruments; or
• any obligation under a material variable interest held by us in an unconsolidated entity that provides financing, liquidity, market risk or credit risk support to us, or engages in leasing, hedging, or research and development services with us.
As of December 31, 2007 and 2006, we had no “off balance sheet arrangements” that may have a current or future material affect on our consolidated financial condition or results of operations.
46
Commitments and Contingencies
Litigation – We are named defendants in several lawsuits and respondents in certain governmental proceedings arising in the ordinary course of business. While the outcome of lawsuits or other proceedings against us cannot be predicted with certainty, management does not expect these matters to have a material adverse impact on the financial statements.
As previously disclosed, our Maritech subsidiary incurred significant damage as a result of hurricanes Katrina and Rita. Although portions of the well intervention costs previously expended on these facilities and submitted to our insurers have been reimbursed, our insurance underwriters have continued to maintain that well intervention costs for certain of the damaged wells do not qualify as covered costs and that certain well intervention costs for qualifying wells are not covered under the policies. In addition, the underwriters have also maintained that there is no additional coverage provided under an endorsement we obtained in August 2005 for the cost of removal of these platforms and for other damage repairs on certain properties in excess of the insured values provided by our property damage policy. On November 16, 2007, we filed a lawsuit in the 359th Judicial District Court, Montgomery County, Texas, entitled Maritech Resources, Inc. v. Certain Underwriters and Insurance Companies at Lloyd’s, London subscribing to Policy no. GA011150U and Steege Kingston, in which we are seeking damages for breach of contract and various related claims and a declaration of the extent of coverage of an endorsement to the policy. We cannot predict the outcome of this lawsuit; however, the ultimate resolution could have a significant impact upon our future operating cash flow.
Environmental – One of our subsidiaries, TETRA Micronutrients, Inc. (TMI), previously owned and operated a production facility located in Fairbury, Nebraska. TMI is subject to an Administrative Order on Consent issued to American Microtrace, Inc. (n/k/a/ TETRA Micronutrients, Inc.) in the proceeding styled In the Matter of American Microtrace Corporation, EPA I.D. No. NED00610550, Respondent, Docket No. VII-98-H-0016, dated September 25, 1998 (the Consent Order), with regard to the Fairbury facility. TMI is liable for future remediation costs at the Fairbury facility under the Consent Order; however, the current owner of the Fairbury facility is responsible for costs associated with the closure of that facility. We have reviewed estimated remediation costs prepared by our independent, third-party environmental engineering consultant, based on a detailed environmental study. The estimated remediation costs range from $0.6 million to $1.4 million. Based upon our review and discussions with our third-party consultants, we established a reserve for such remediation costs which is included in other long-term liabilities in the accompanying consolidated balance sheets. As of December 31, 2007, and following the performance of certain remediation activities at the site, the amount of the reserve for these remediation costs, included in current liabilities, is approximately $0.5 million. The reserve will be further adjusted as information develops or conditions change.
We have not been named a potentially responsible party by the EPA or any state environmental agency.
Product Purchase Obligations – In the normal course of our Fluids Division operations, we enter into supply agreements with certain manufacturers of various raw materials and finished products. Some of these agreements have terms and conditions that specify a minimum or maximum level of purchases over the term of the agreement. Other agreements require us to purchase the entire output of the raw material or finished product produced by the manufacturer. Our purchase obligations under these agreements apply only with regard to raw materials and finished products that meet specifications set forth in the agreements. We recognize a liability for the purchase of such products at the time we receive them. During 2006, we significantly increased our purchase obligations as a result of the execution of a long-term supply agreement with Chemtura Corporation, and the amendment of a previous supply agreement. Under the amended agreement with the previous supplier, we remained committed to purchase certain volumes of product through 2008. In December 2007, we were released from these further purchases pursuant to an agreement terminating the amended agreement in exchange for our agreement to pay $9.3 million in five installments during 2008 and early 2009. As of December 31, 2007, the aggregate amount of the fixed and determinable portion of the purchase obligation pursuant to our Fluids Division’s supply agreements, including the 2008 buyout installments discussed above, was approximately $247.3 million, extending through 2029.
47
Insurance Contingencies – Through December 31, 2007, we have expended approximately $47.8 million of well intervention work on certain wells associated with three Maritech offshore platforms which were destroyed as a result of Hurricanes Katrina and Rita in 2005. We estimate that future well intervention efforts related to these destroyed platforms, including platform debris removal, will result in approximately $48.4 million of additional costs. Approximately $28.6 million of the well intervention costs previously expended and submitted to insurance have been reimbursed; however, our insurance underwriters have continued to maintain that well intervention costs for certain of the damaged wells do not qualify as covered costs and that certain well intervention costs for qualifying wells are not covered under the policy. In addition, the underwriters have also maintained that there is no additional coverage provided under an endorsement we obtained in August 2005 for the cost of removal of these platforms or for other damage repairs on certain properties in excess of the insured values provided by our property damage policy. After continuing to provide requested information to the underwriters regarding the damaged wells, and having numerous discussions with the underwriters, we have yet to receive the requested reimbursement for these contested costs. In late 2007, we filed a lawsuit against the underwriters in an attempt to collect the reimbursement for these well intervention costs incurred as well as future well intervention and debris removal costs to be incurred. We continue to believe that these costs are covered costs pursuant to the policies. However, during the fourth quarter of 2007, we reversed the anticipated insurance recoveries previously included in estimating Maritech’s decommissioning liability, increasing the liability to $48.4 million to reflect the well intervention work to be performed, assuming no insurance reimbursements will be received, as the amount and timing of further reimbursements from our insurance providers are now indeterminable.
If we successfully collect reimbursements from our insurance providers, such reimbursements will be credited to operations in the period collected. In addition, in the event that our actual well intervention costs are more or less than the associated decommissioning liabilities, as adjusted, the difference may be reported in income in the period in which the work is performed.
In October 2005, one of our drilling rig barges was damaged by a fire, and a claim was submitted pursuant to our insurance coverage. The drilling rig barge was repaired during 2006 for a cost of approximately $8.4 million. In January 2007, we collected approximately $2.1 million of insurance reimbursements as a result of our claim for the repair costs incurred. In February 2007, we received a notice from our insurance underwriters, stating that they consider that approximately $3.7 million of this claim is not covered under the applicable policy. We have reviewed the underwriters’ position with regard to this claim, and believe it is without merit. In August 2007, the underwriters responded to our position with regard to this claim, requested additional information on a portion of the remaining costs incurred, and agreed to continue discussions. In September 2007, we met with underwriters to discuss the claim and delivered the additional requested information, and we are currently awaiting any further questions. As of December 31, 2007, approximately $4.3 million is included in our accounts receivable associated with the repair costs incurred for this asset, as such costs are considered probable of being reimbursed pursuant to our applicable insurance policy. This amount is net of the approximately $2.1 million of insurance reimbursements received, and approximately $2.0 million of costs that were charged to expense during 2007. We continue to work with the underwriters to pursue reimbursement of our repair costs.
Other Contingencies – Related to its acquired interests in oil and gas properties, our Maritech subsidiary estimates the third party fair values (including an estimated profit) to plug and abandon wells, decommission the pipelines and platforms, and clear the sites, and uses these estimates to record Maritech’s decommissioning liabilities, net of amounts allocable to joint interest owners and any amounts contractually agreed to be paid in the future by the previous owners of the properties. In some cases, previous owners of acquired oil and gas properties are contractually obligated to pay Maritech a fixed amount for the future well abandonment and decommissioning work on these properties as such work is performed. As of December 31, 2007, Maritech’s decommissioning liabilities are net of approximately $54.8 million for such future reimbursements from these previous owners.
In March 2006, we acquired Beacon, a production testing operation, for approximately $15.6 million paid at closing and an additional $0.5 million to be paid, subject to adjustment, over a three year period through March 2009. In addition, the acquisition provides for additional contingent consideration of up to $19.1 million to be paid in March 2009, depending on the average of Beacon’s annual pretax results
48
of operations over the three year period following the closing date through March 2009. Through December 31, 2007, we have estimated the amount of Beacon’s pretax results of operations (as defined in the agreement) to date since the acquisition and have determined that this amount is less than the amount required to generate a payment pursuant to this contingent consideration provision. Any amount payable pursuant to this contingent consideration provision will be reflected as a liability as it becomes fixed and determinable at the end of the three year period.
Recently Issued Accounting Pronouncements
In December 2007, the FASB published Statement of Financial Accounting Standard (SFAS) No. 141R, “Business Combinations,” which established principles and requirements for how an acquirer of a business (1) recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, and any noncontrolling interest in the acquiree; (2) recognizes and measures the goodwill acquired in the business combination or a gain from a bargain purchase; and (3) determines what information to disclose to enable users of the financial statements to evaluate the nature and financial effects of the business combination. SFAS No. 141R changes many aspects of the accounting for business combinations, and is expected to significantly impact how we account for and disclose future acquisition transactions. SFAS No. 141R applies prospectively to business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008.
In December 2007, the FASB published SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements – an amendment of ARB No. 51,” which establishes accounting and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. It clarifies that a noncontrolling interest in a subsidiary is an ownership interest in the consolidated entity that should be reported as equity in the consolidated financial statements. SFAS No. 160 is effective for fiscal years, and interim periods within those fiscal years, beginning on or after December 15, 2008. We are currently evaluating the impact, if any, the adoption of SFAS No. 160 will have on our financial position and results of operations.
In February 2007, the FASB published SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities,” which permits entities to choose to make an irrevocable election at specific election dates to measure most financial assets and financial liabilities at fair value. The fair value option may be elected on an instrument-by-instrument basis, with a few exceptions, as long as it is applied to the instrument in its entirety. Changes in fair value would be recorded to earnings. SFAS No. 159 applies to fiscal years beginning after November 15, 2007, with early adoption permitted for an entity that has also elected to apply the provisions of SFAS No. 157. Currently, we have elected not to adopt the fair value option provision allowed under SFAS No. 159.
In September 2006, the FASB published SFAS No. 157, “Fair Value Measurements,” which defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles, and expands disclosures about fair value measurements. SFAS No. 157 applies under other accounting pronouncements that require or permit fair value measurements. SFAS No. 157 establishes a fair value hierarchy and requires disclosure of fair value measurements within that hierarchy. SFAS No. 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. The adoption of SFAS No. 157 is not expected to have a material impact on our financial statements, but will result in additional disclosures related to the use of fair values in the financial statements.
49
Item 7A. Quantitative and Qualitative Disclosures about Market Risk.
Interest Rate Risk
Any balances outstanding under the floating rate portion of our bank credit facility are subject to market risk exposure related to changes in applicable interest rates. We borrow funds pursuant to our bank credit facility as necessary to fund our capital expenditure requirements and certain acquisitions. These instruments carry interest at an agreed-upon percentage rate spread above LIBOR. Based on the balances of floating rate debt outstanding as of December 31, 2007, each increase of 100 basis points in the LIBOR rate would result in a decrease in earnings of approximately $1,079,000.
The following table sets forth, as of December 31, 2007 and 2006, our cash flows for the outstanding principal balances of our long-term debt obligations (which bear a variable rate of interest) and weighted average effective interest rates by their expected maturity dates. We currently are not a party to an interest rate swap contract or other derivative instrument designed to hedge our exposure to interest rate fluctuation risk.
Expected Maturity Date |
Fair |
|||||||||||||||||||||||
|
2008 |
|
2009 |
|
2010 |
|
2011 |
|
2012 |
|
Thereafter |
|
Total |
|
Market Value |
||||||||||
(In Thousands, Except Percentages) |
||||||||||||||||||||||||
| As of December 31, 2007 |
||||||||||||||||||||||||
Long-term debt: |
||||||||||||||||||||||||
U.S. dollar variable rate |
$ |
– |
$ |
– |
$ |
– |
$ |
160,000 |
$ |
– |
$ |
– |
$ |
160,000 |
$ |
160,000 |
||||||||
Euro variable rate (in $US) |
– |
– |
– |
11,783 |
– |
– |
11,783 |
11,783 |
||||||||||||||||
Weighted average interest rate |
– |
– |
– |
5.758% |
– |
|
– |
5.758% |
– |
|||||||||||||||
Variable to fixed swaps |
– |
– |
– |
– |
– |
– |
– |
– |
||||||||||||||||
Fixed pay rate |
– |
– |
– |
– |
– |
– |
– |
– |
||||||||||||||||
Variable receive rate |
– |
– |
– |
– |
– |
– |
– |
– |
||||||||||||||||
Expected Maturity Date |
Fair |
|||||||||||||||||||||||
|
2007 |
|
2008 |
|
2009 |
|
2010 |
|
2011 |
|
Thereafter |
|
Total |
|
Market Value |
||||||||||
(In Thousands, Except Percentages) |
||||||||||||||||||||||||
| As of December 31, 2006 |
||||||||||||||||||||||||
Long-term debt: |
||||||||||||||||||||||||
U.S. dollar variable rate |
$ |
– |
$ |
– |
$ |
– |
$ |
– |
$ |
145,000 |
$ |
– |
$ |
145,000 |
$ |
145,000 |
||||||||
Euro variable rate (in $US) |
– |
– |
– |
– |
9,242 |
– |
9,242 |
9,242 |
||||||||||||||||
Weighted average interest rate |
– |
– |
– |
– |
5.883% |
– |
5.883% |
– |
||||||||||||||||
Variable to fixed swaps |
– |
– |
– |
– |
– |
– |
– |
– |
||||||||||||||||
Fixed pay rate |
– |
– |
– |
– |
– |
– |
– |
– |
||||||||||||||||
Variable receive rate |
– |
– |
– |
– |
– |
– |
– |
– |
||||||||||||||||
Exchange Rate Risk
We are exposed to fluctuations between the U.S. dollar and the Euro with regard to our Euro-denominated operating activities and related long-term Euro denominated debt. In September 2004, we borrowed Euros to fund the acquisition of our European calcium chloride assets. We entered into long-term Euro-denominated borrowings, as we believe such borrowings provide a natural currency hedge for our Euro-based operating cash flow. We also have exposure related to operating receivables and payables denominated in Euros as well as other currencies; however, such transactions are not pursuant to long-term contract terms, and the amount of such foreign currency exposure is not determinable or considered material.
50
The following table sets forth as of December 31, 2007 and 2006, our cash flows for the outstanding principal balances of our long-term debt obligations which are denominated in Euros. This information is presented in U.S. dollar equivalents. The table presents principal cash flows and related weighted average interest rates by their expected maturity dates. As described above, we utilize the long-term borrowings detailed in the following table as a hedge to our investment in our acquired foreign operations and, currently, we are not a party to a foreign currency swap contract or other derivative instrument designed to further hedge our currency exchange rate risk exposure. Our exchange rate risk exposure related to these borrowings will generally be offset by the offsetting fluctuations in the value of the related foreign investment.
Expected Maturity Date |
Fair |
|||||||||||||||||||||||
|
2008 |
|
2009 |
|
2010 |
|
2011 |
|
2012 |
|
Thereafter |
|
Total |
|
Market Value |
||||||||||
(In Thousands, Except Percentages) |
||||||||||||||||||||||||
| As of December 31, 2007 |
||||||||||||||||||||||||
Long-term debt: |
||||||||||||||||||||||||
Euro variable rate (in $US) |
$ |
– |
$ |
– |
$ |
– |
$ |
11,783 |
$ |
– |
$ |
– |
$ |
11,783 |
$ |
11,783 |
||||||||
Euro fixed rate (in $US) |
– |
– |
– |
41,241 |
– |
– |
41,241 |
41,494 |
||||||||||||||||
Weighted average interest rate |
– |
– |
– |
4.953% |
– |
|
– |
4.953% |
– |
|||||||||||||||
Variable to fixed swaps |
– |
– |
– |
– |
– |
– |
– |
– |
||||||||||||||||
Fixed pay rate |
– |
– |
– |
– |
– |
– |
– |
– |
||||||||||||||||
Variable receive rate |
– |
– |
– |
– |
– |
– |
– |
– |
||||||||||||||||
Expected Maturity Date |
Fair |
|||||||||||||||||||||||
|
2007 |
|
2008 |
|
2009 |
|
2010 |
|
2011 |
|
Thereafter |
|
Total |
|
Market Value |
||||||||||
(In Thousands, Except Percentages) |
||||||||||||||||||||||||
| As of December 31, 2006 |
||||||||||||||||||||||||
Long-term debt: |
||||||||||||||||||||||||
Euro variable rate (in $US) |
$ |
– |
$ |
– |
$ |
– |
$ |
– |
$ |
9,242 |
$ |
– |
$ |
9,242 |
$ |
9,242 |
||||||||
Euro fixed rate (in $US) |
– |
– |
– |
– |
36,969 |
– |
36,969 |
37,223 |
||||||||||||||||
Weighted average interest rate |
– |
– |
– |
– |
4.693% |
– |
4.693% |
– |
||||||||||||||||
Variable to fixed swaps |
– |
– |
– |
– |
– |
– |
– |
– |
||||||||||||||||
Fixed pay rate |
– |
– |
– |
– |
– |
– |
– |
– |
||||||||||||||||
Variable receive rate |
– |
– |
– |
– |
– |
– |
– |
– |
||||||||||||||||
Commodity Price Risk
We have market risk exposure in the pricing applicable to our oil and gas production. Realized pricing is primarily driven by the prevailing worldwide price for crude oil and spot prices in the U.S. natural gas market. Historically, prices received for oil and gas production have been volatile and unpredictable, and such price volatility is expected to continue. Our risk management activities involve the use of derivative financial instruments, such as swap agreements, to hedge the impact of market price risk exposures for a portion of our oil and gas production. We are exposed to the volatility of oil and gas prices for the portion of our oil and gas production that is not hedged. Net of the impact of the crude oil hedges as of December 31, 2007 described below, each $1 per barrel decrease in future crude oil prices would result in a decrease in after tax earnings of $445,000. Each decrease in future gas prices of $0.10 per Mcf would result in a decrease in after tax earnings of $453,000.
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, 2007 and 2006, we had the following cash flow hedging swap contracts outstanding relating to a portion of our Maritech subsidiary’s oil and gas production:
51
Commodity Contract |
Daily Volume |
Contract Price |
Contract Term |
||||
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 |
||||
Oil swap |
1,000 barrels/day |
$68.06/barrel |
January 1, 2008 - December 31, 2008 |
||||
Oil swap |
1,000 barrels/day |
$74.35/barrel |
January 1, 2008 - December 31, 2008 |
||||
Oil swap |
500 barrels/day |
$68.23/barrel |
January 1, 2009 - December 31, 2009 |
||||
Oil swap |
500 barrels/day |
$68.32/barrel |
January 1, 2009 - December 31, 2009 |
||||
Oil swap |
500 barrels/day |
$68.05/barrel |
January 1, 2009 - December 31, 2009 |
||||
Oil swap |
500 barrels/day |
$68.22/barrel |
January 1, 2009 - December 31, 2009 |
||||
Oil swap |
500 barrels/day |
$71.50/barrel |
January 1, 2009 - December 31, 2009 |
||||
Oil swap |
1,000 barrels/day |
$70.75/barrel |
January 1, 2010 - December 31, 2010 |
||||
Natural gas swap |
4,500 MMBtu/day |
$8.470/MMBtu |
January 1, 2008 - December 31, 2008 |
||||
Natural gas swap |
3,000 MMBtu/day |
$8.450/MMBtu |
January 1, 2008 - December 31, 2008 |
||||
|
|
|
|
||||
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 |
In January and February 2008, we entered into certain natural gas swap contracts, covering a total of 15,000 MMBtu/day from February to December 2008, with an average contract price of $8.318/MMBtu. In addition, we entered into certain natural gas swap contracts, covering a total of 15,000 MMBtu/day for 2009, with an average contract price of $8.585/MMBtu.
Each oil and gas swap contract uses the NYMEX WTI (West Texas Intermediate) oil price and the NYMEX Henry Hub natural gas price as the referenced price, respectively. The market value of our oil swaps at December 31, 2007 was $53,369,000. The portion of this market value associated with 2008 swap contracts is reflected as a current liability, and the portion related to later periods is reflected as a long-term liability. A $1 increase in the future price of oil would result in the market value of the combined oil derivative liability increasing by $2,403,000. The market value of our natural gas swaps at December 31, 2007 was $1,299,000 and is reflected as a current asset. A $0.10 increase in the future price of natural gas would result in the market value of the combined natural gas derivative asset decreasing by $270,000.
The market value of our oil swaps at December 31, 2006 was $4,590,000, which is reflected as a current asset. A $1 increase in the future price of oil would have resulted in the market value of the combined oil derivative asset decreasing by $1,504,000.
Item 8. Financial Statements and Supplementary Data.
Our financial statements and supplementary data for us and our subsidiaries required to be included in this Item 8 are set forth in Item 15 of this Report.
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.
None.
52
Item 9A. Controls and Procedures.
Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures
Under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, we conducted an evaluation of our disclosure controls and procedures, as such term is defined under Rule 13a-15(e) promulgated under the Securities Exchange Act of 1934, as amended (the Exchange Act). Based on this evaluation, the Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of December 31, 2007, the end of the period covered by this annual report.
Management’s Report on Internal Control over Financial Reporting
Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f). Under the supervision and with the participation of management, including our Chief Executive Officer and Chief Financial Officer, an evaluation of the effectiveness of our internal control over financial reporting was conducted based on the framework in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on that evaluation under the framework in Internal Control – Integrated Framework issued by the COSO, our management concluded that our internal control over financial reporting was effective as of December 31, 2007.
An assessment of the effectiveness of our internal control over financial reporting as of December 31, 2007 has been performed by Ernst & Young LLP, an independent registered public accounting firm, as stated in their report which is included herein.
Changes in Internal Control over Financial Reporting
There were no changes in our internal control over financial reporting during the fiscal quarter ending December 31, 2007 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
None.
53
PART III
Item 10. Directors and Executive Officers of the Registrant.
The information required by this Item is hereby incorporated by reference from the information appearing under the captions “Proposal No. 1: Election of Directors,” “Executive Officers,” “Corporate Governance,” “Board Meetings and Committees,” and “Section 16(a) Beneficial Ownership Reporting Compliance” in our definitive proxy statement (the Proxy Statement) for the annual meeting of stockholders to be held May 9, 2008, which involves the election of directors and is to be filed with the Securities and Exchange Commission (SEC) pursuant to the Securities Exchange Act of 1934 as amended (the Exchange Act) within 120 days of the end of our fiscal year on December 31, 2007.
Item 11. Executive Compensation.
The information required by this Item is hereby incorporated by reference from the information appearing under the captions “Management and Compensation Committee Report,” “Management and Compensation Committee Interlocks and Insider Participation,” “Compensation Discussion and Analysis,” “Compensation of Executive Officers,” and “Director Compensation” in our Proxy Statement. Notwithstanding the foregoing, in accordance with the instructions to Item 407 of Regulation S-K, the information contained in our Proxy Statement under the subheading “Management and Compensation Committee Report” shall be deemed furnished, and not filed, in this Form 10-K, and shall not be deemed incorporated by reference into any filing under the Securities Act of 1933, or the Securities Exchange Act of 1934, as a result of this furnishing, except to the extent we specifically incorporate it by reference.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.
The information required by this Item is hereby incorporated by reference from the information appearing under the captions “Beneficial Stock Ownership of Certain Stockholders and Management” and “Equity Compensation Plan Information” in our Proxy Statement.
Item 13. Certain Relationships and Related Transactions, and Director Independence.
The information required by this Item is hereby incorporated by reference from the information appearing under the captions “Certain Transactions” and “Director Independence” in our Proxy Statement.
Item 14. Principal Accountant Fees and Services.
The information required by this Item is hereby incorporated by reference from the information appearing under the caption “Fees Paid to Principal Accounting Firm” in our Proxy Statement.
54
PART IV
Item 15. Exhibits and Financial Statement Schedules.
(a) List of documents filed as part of this Report |
||||
1. Financial Statements of the Company |
||||
|
Page |
|||
Reports of Independent Registered Public Accounting Firm |
F-1 |
|||
Consolidated Balance Sheets at December 31, 2006 and 2005 |
F-4 |
|||
Consolidated Statements of Operations for the years ended December 31, 2006, 2005, and 2004 |
F-6 |
|||
Consolidated Statements of Stockholders' Equity for the years ended December 31, 2006, 2005, and 2004 |
F-7 |
|||
Consolidated Statements of Cash Flows for the years ended December 31, 2006, 2005, and 2004 |
F-8 |
|||
Notes to Consolidated Financial Statements |
F-9 |
|||
| 2. Financial statement schedules have been omitted as they are not required, are not applicable, or the required information is included in the financial statements or notes thereto. |
||
| 3. List of Exhibits |
||
| 3.1 |
Restated Certificate of Incorporation of TETRA Technologies, Inc. (incorporated by reference to Exhibit 3.1 to the Company’s Registration Statement on Form S-4 filed on December 27, 1995 (SEC File No. 33-80881)). |
|
| 3.2 |
Certificate of Amendment of Restated Certificate of Incorporation of TETRA Technologies, Inc. (incorporated by reference to Exhibit 3.1 to the Company’s Registration Statement on Form S-4 filed on December 27, 1995 (SEC File No. 33-80881)). |
|
|
3.3 |
Certificate of Amendment of Restated Certificate of Incorporation of TETRA Technologies, Inc. (incorporated by reference to Exhibit 3.1(ii) to the Company’s Annual Report on Form 10-K for the year ended December 31, 2003 filed on March 15, 2004 (SEC File No. 001-13455)). |
|
|
3.4 |
Certificate of Amendment of Restated Certificate of Incorporation of TETRA Technologies, Inc. (incorporated by reference to Exhibit 4.4 to the Company’s Registration Statement on Form S-4 filed on May 25, 2004 (SEC File No. 333-115859)). |
|
| 3.5 |
Certificate of Amendment of Restated Certificate of Incorporation of TETRA Technologies, Inc. (incorporated by reference to Exhibit 4.5 to the Company’s Registration Statement on Form S-8 filed on May 4, 2006 (SEC File No. 333-133790)). |
|
| 3.6 |
Certificate of Designation of Series One Junior Participating Preferred Stock of the Company dated October 27, 1998 (incorporated by reference to Exhibit 2 to the Company’s Registration Statement on Form 8-A filed on October 28, 1998 (SEC File No. 001-13455)). |
|
| 3.7 |
Amended and Restated Bylaws of TETRA Technologies, Inc. (incorporated by reference to Exhibit 4.6 to the Company’s Registration Statement on Form S-8 filed on May 4, 2006 (SEC File No. 333-133790)). |
|
| 4.1 |
Rights Agreement dated October 26, 1998 between the Company and Computershare Investor Services LLC (as successor in interest to Harris Trust & Savings Bank), as Rights Agent (incorporated by reference to Exhibit 1 to the Company’s Registration Statement on Form 8-A filed on October 28, 1998 (SEC File No. 001-13455)). |
|
| 4.2 |
Master Note Purchase Agreement, dated September 27, 2004 by and among TETRA Technologies, Inc. and Jackson National Life Insurance Company, Massachusetts Mutual Life Insurance Company, C.M. Life Insurance Company, Allstate Life Insurance Company, Teachers Insurance and Annuity Association of America, Pacific Life Insurance Company, the Prudential Assurance Company Limited (PAC), and Panther CDO II, B.V. (incorporated by reference to Exhibit 4.1 to the Company’s Form 8-K filed on September 30, 2004 (SEC File No. 001-13455)). |
|
|
4.3 |
Form of 5.07% Senior Notes, Series 2004-A, due September 30, 2011 (incorporated by reference to Exhibit 4.2 to the Company’s Form 8-K filed on September 30, 2004 (SEC File No. 001-13455)). |
|
55
| 4.4 |
Form of 4.79% Senior Notes, Series 2004-B, due September 30, 2011 (incorporated by reference to Exhibit 4.3 to the Company’s Form 8-K filed on September 30, 2004 (SEC File No. 001-13455)). |
|
| 4.5 |
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 (incorporated by reference to Exhibit 4.4 to the Company’s Form 8-K filed on September 30, 2004 (SEC File No. 001-13455)). |
|
| 4.6 |
First Supplement to Master Note Purchase Agreement, dated April 18, 2006, by and among TETRA Technologies, Inc. and Jackson National Life Insurance Company, Allianz Life Insurance Company of North America, United of Omaha Life Insurance Company, Mutual of Omaha Insurance Company, CUNA Mutual Life Insurance Company, CUNA Mutual Insurance Society, CUMIS Insurance Society, Inc., Members Life Insurance Company, and Modern Woodmen of America, attaching the form of the 5.90% Senior Notes, Series 2006-A, due April 30, 2016 as an exhibit thereto (incorporated by reference to Exhibit 4.1 to the Company’s Form 8-K filed on April 20, 2006 (SEC File No. 001-13455)). |
|
| 10.1*** |
1990 Stock Option Plan, as amended through January 5, 2001 (incorporated by reference to Exhibit 10.8 to the Company’s Form 10-K for the year ended December 31, 2000 filed on March 23, 2001 (SEC File No. 001-13455)). |
|
| 10.2*** |
Director Stock Option Plan (incorporated by reference to Exhibit 10.9 to the Company’s Form 10-K for the year ended December 31, 2000 filed on March 23, 2001 (SEC File No. 001-13455)). |
|
| 10.3*** |
1998 Director Stock Option Plan (incorporated by reference to Exhibit 10.10 to the Company’s Form 10-K for the year ended December 31, 2000 filed on March 23, 2001 (SEC File No. 001-13455)). |
|
| 10.4*** |
1996 Stock Option Plan for Nonexecutive Employees and Consultants (incorporated by reference to Exhibit 99.1 to the Company’s Registration Statement on Form S-8 filed on November 19, 1997 (SEC File No. 333-61988)). |
|
| 10.5*** |
Letter of Agreement with Gary C. Hanna, dated March, 2002 (incorporated by reference to Exhibit 10.8 to the Company’s Form 10-K for the year ended December 31, 2001 filed on March 26, 2002 (SEC File No. 001-13455)). |
|
| 10.6*** |
Director Stock Option Plan (incorporated by reference to Exhibit 10.8 to the Company’s Form 10-K for the year ended December 31, 2002 filed on March 27, 2003 (SEC File No. 001-13455)). |
|
| 10.7 |
Credit Agreement dated as of September 7, 2004, among TETRA Technologies, Inc. and certain of its subsidiaries, as borrowers, Bank of America, National Association, as Administrative Agent, Bank One, NA and Wells Fargo Bank, N.A., as syndication agents, and Comerica Bank, as documentation agent, attaching the guaranty dated as of September 7, 2004, by the borrowers, as guarantors, to the Administrative Agent for the benefit of the lenders under the Credit Agreement (incorporated by reference to Exhibit 10.1 to the Company’s Form 8-K filed on September 8, 2004 (SEC File No. 001-13455)). |
|
| 10.8*** |
Agreement between TETRA Technologies, Inc. and Geoffrey M. Hertel dated February 26, 1993 (incorporated by reference to Exhibit 10.2 to the Company’s Form 8-K filed on January 7, 2005 (SEC File No. 001-13455)). |
|
| 10.9*** |
Form of Incentive Stock Option Agreement, dated as of December 28, 2004 (incorporated by reference to Exhibit 10.1 to the Company’s Form 8-K filed on January 7, 2005 SEC File No. 001-13455)). |
|
| 10.10*** |
TETRA Technologies, Inc. 2006 Equity Incentive Compensation Plan (incorporated by reference to Exhibit 4.12 to the Company’s Registration Statement on Form S-8 filed on May 4, 2006 (SEC File No. 333-133790)). |
|
| 10.11*** |
Forms of Employee Incentive Stock Option Agreement, Employee Nonqualified Stock Option Agreement, and Employee Restricted Stock Agreement under the TETRA Technologies, Inc. 2006 Equity Incentive Compensation Plan (incorporated by reference to Exhibits 10.1, 10.2, and 10.3 to the Company’s Form 8-K filed on May 8, 2006 (SEC File No. 001-13455)). |
|
| 10.12+*** |
Summary Description of the Compensation of Non-Employee Directors of TETRA Technologies, Inc. |
|
| 10.13+*** |
Summary Description of Named Executive Officer Compensation. |
|
| 10.14 |
Purchase and Sale Agreement by and between Pioneer Natural Resources USA, Inc. as Seller and Maritech Resources, Inc. as Purchaser, dated July 7, 2005 (incorporated by reference to Exhibit 10.1 to the Company’s Form 10-Q filed on November 9, 2005 (SEC File No. 001-13455), certain portions of this exhibit have been omitted pursuant to a confidential treatment request filed with the Securities and Exchange Commission). |
|
| 10.15*** |
Nonqualified Stock Option Agreement between TETRA Technologies, Inc. and Stuart Brightman, dated April 20, 2005 (incorporated by reference to Exhibit 10.1 to the Company’s Form 8-K filed on April 22, 2005 (SEC File No. 001-13455)). |
56
| 10.16*** |
First Amendment to the TETRA Technologies, Inc. 1998 Director Stock Option Plan (As Amended Through June 27, 2003) dated December 16, 2005 (incorporated by reference to Exhibit 10.1 to the Company’s Form 8-K filed on December 22, 2005 (SEC File No. 001-13455)). |
|
| 10.17*** |
Form of Stock Option Agreement under the TETRA Technologies, Inc. 1998 Director Stock Option Plan (As Amended Through June 27, 2003), as further amended by the First Amendment to the TETRA Technologies, Inc. 1998 Director Stock Option Plan (As Amended Through June 27, 2003) (incorporated by reference to Exhibit 10.2 to the Company’s Form 8-K filed on December 22, 2005 (SEC File No. 001-13455)). |
|
| 10.18 |
Agreement and Third Amendment to Credit Agreement dated as of January 20, 2006, among TETRA Technologies, Inc. and certain of its subsidiaries, as borrowers, JP Morgan Chase Bank, National Association (successor to Bank One, NA) and Wells Fargo Bank, N.A., as syndication agents, Comerica Bank, as documentation agent, Bank of America, National Association, as administrative agent, and the lenders party thereto (incorporated by reference to Exhibit 10.1 to the Company’s Form 8-K filed on January 23, 2006 (SEC File No. 001-13455)). |
|
| 10.19 |
Credit Agreement, as amended and restated, dated as of June 27, 2006, among TETRA Technologies, Inc. and certain of its subsidiaries, as borrowers, JPMorgan Chase Bank, N.A., as administrative agent, Bank of America, National Association and Wells Fargo Bank, N.A., as syndication agents, and Comerica Bank, as documentation agent, and the lenders party thereto (incorporated by reference to Exhibit 10.1 to the Company’s Form 8-K filed on June 30, 2006 (SEC File No. 001-13455)). |
|
| 10.20 |
Agreement and First Amendment to Credit Agreement dated as of December 15, 2006, among TETRA Technologies, Inc. and certain of its subsidiaries, as borrowers, JPMorgan Chase Bank, N.A., as administrative agent, Bank of America, National Association and Wells Fargo Bank, N.A., as syndication agents, and Comerica Bank, as documentation agent, and the lenders party thereto (incorporated by reference to Exhibit 10.1 to the Company’s Form 8-K filed on January 10, 2007 (SEC File No. 001-13455)). |
|
| 10.21*** |
TETRA Technologies, Inc. Nonqualified Deferred Compensation Plan (incorporated by reference to Exhibit 10.9 to the Company’s Form 10-Q filed on August 12, 2002 (SEC File No. 001-13455)). |
|
| 10.22*** |
TETRA Technologies, Inc. Nonqualified Deferred Compensation Plan and The Executive Excess Plan Adoption Agreement effective on June 30, 2005 (incorporated by reference to Exhibit 10.2 to the Company’s Form 10-Q/A filed on March 16, 2006 (SEC File No. 001-13455)). |
|
| 10.23*** |
TETRA Technologies, Inc. 2007 Equity Incentive Compensation Plan (incorporated by reference to Exhibit 4.12 to the Company’s Registration Statement on Form S-8 filed on May 4, 2007 (SEC File No. 333-142637)). |
|
| 10.24*** |
Forms of Employee Incentive Stock Option Agreement, Employee Nonqualified Stock Option Agreement, and Employee Restricted Stock Agreement under the TETRA Technologies, Inc. 2007 Equity Incentive Compensation Plan (incorporated by reference to Exhibits 4.13, 4.14, and 4.15 to the Company’s Registration Statement on Form S-8 filed on May 4, 2007 (SEC File No. 333-142637)). |
|
| 10.25*** |
TETRA Technologies, Inc. 401(k) Retirement Plan, as amended and restated (incorporated by reference to Exhibit 99.1 to the Company’s Registration Statement on Form S-8 filed on February 22, 2008 (SEC File No. 333-149348)). |
|
| 10.26*** |
Employee Restricted Stock Agreement between TETRA Technologies, Inc. and Philip N. Longorio, dated February 22, 2008 (incorporated by reference to Exhibit 4.12 to the Company’s Registration Statement on Form S-8 filed on February 22, 2008 (SEC File No. 333-149347)). |
|
| 21+ |
Subsidiaries of the Company. |
|
| 23.1+ |
Consent of Ernst & Young, LLP. |
|
| 23.2+ |
Consent of Ryder Scott Company, L.P. |
|
| 23.3+ |
Consent of DeGolyer and McNaughton. |
|
| 31.1+ |
Certification Pursuant to Rule 13(a)-14(a) or 15(d)-14(a) of the Exchange Act, As Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
|
| 31.2+ |
Certification Pursuant to Rule 13(a)-14(a) or 15(d)-14(a) of the Exchange Act, As Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
|
| 32.1** |
Certification Furnished Pursuant to 18 U.S.C. Section 1350, As Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Chief Executive Officer). |
|
| 32.2** |
Certification Furnished Pursuant to 18 U.S.C. Section 1350, As Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Chief Financial Officer). |
+ Filed with this report.
** Furnished with this report.
*** Management contract or compensatory plan or arrangement.
57
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: February 29, 2008
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/Ralph S. Cunningham |
Chairman of |
February 29, 2008 |
Ralph S. Cunningham |
the Board of Directors |
|
|
|
|
/s/Geoffrey M. Hertel |
President and Director |
February 29, 2008 |
Geoffrey M. Hertel |
(Principal Executive Officer) |
|
|
|
|
/s/Joseph M. Abell |
Senior Vice President |
February 29, 2008 |
Joseph M. Abell |
(Principal Financial Officer) |
|
|
|
|
/s/Ben C. Chambers |
Vice President - Accounting |
February 29, 2008 |
Ben C. Chambers |
(Principal Accounting Officer) |
|
|
|
|
/s/Paul D. Coombs |
Director |
February 29, 2008 |
Paul D. Coombs |
|
|
|
|
|
/s/Tom H. Delimitros |
Director |
February 29, 2008 |
Tom H. Delimitros |
|
|
|
|
|
/s/Allen T. McInnes |
Director |
February 29, 2008 |
Allen T. McInnes |
|
|
|
|
|
/s/Kenneth P. Mitchell |
Director |
February 29, 2008 |
Kenneth P. Mitchell |
|
|
|
|
|
/s/William D. Sullivan |
Director |
February 29, 2008 |
William D. Sullivan |
|
|
|
|
|
/s/Kenneth E. White, Jr. |
Director |
February 29, 2008 |
Kenneth E. White, Jr. |
|
|
51
EXHIBIT INDEX
| 3.1 |
Restated Certificate of Incorporation of TETRA Technologies, Inc. (incorporated by reference to Exhibit 3.1 to the Company’s Registration Statement on Form S-4 filed on December 27, 1995 (SEC File No. 33-80881)). |
| 3.2 |
Certificate of Amendment of Restated Certificate of Incorporation of TETRA Technologies, Inc. (incorporated by reference to Exhibit 3.1 to the Company’s Registration Statement on Form S-4 filed on December 27, 1995 (SEC File No. 33-80881)). |
| 3.3 |
Certificate of Amendment of Restated Certificate of Incorporation of TETRA Technologies, Inc. (incorporated by reference to Exhibit 3.1(ii) to the Company’s Annual Report on Form 10-K for the year ended December 31, 2003 filed on March 15, 2004 (SEC File No. 001-13455)). |
| 3.4 |
Certificate of Amendment of Restated Certificate of Incorporation of TETRA Technologies, Inc. (incorporated by reference to Exhibit 4.4 to the Company’s Registration Statement on Form S-4 filed on May 25, 2004 (SEC File No. 333-115859)). |
| 3.5 |
Certificate of Amendment of Restated Certificate of Incorporation of TETRA Technologies, Inc. (incorporated by reference to Exhibit 4.5 to the Company’s Registration Statement on Form S-8 filed on May 4, 2006 (SEC File No. 333-133790)). |
| 3.6 |
Certificate of Designation of Series One Junior Participating Preferred Stock of the Company dated October 27, 1998 (incorporated by reference to Exhibit 2 to the Company’s Registration Statement on Form 8-A filed on October 28, 1998 (SEC File No. 001-13455)). |
| 3.7 |
Amended and Restated Bylaws of TETRA Technologies, Inc. (incorporated by reference to Exhibit 4.6 to the Company’s Registration Statement on Form S-8 filed on May 4, 2006 (SEC File No. 333-133790)). |
| 4.1 |
Rights Agreement dated October 26, 1998 between the Company and Computershare Investor Services LLC (as successor in interest to Harris Trust & Savings Bank), as Rights Agent (incorporated by reference to Exhibit 1 to the Company’s Registration Statement on Form 8-A filed on October 28, 1998 (SEC File No. 001-13455)). |
| 4.2 |
Master Note Purchase Agreement, dated September 27, 2004 by and among TETRA Technologies, Inc. and Jackson National Life Insurance Company, Massachusetts Mutual Life Insurance Company, C.M. Life Insurance Company, Allstate Life Insurance Company, Teachers Insurance and Annuity Association of America, Pacific Life Insurance Company, the Prudential Assurance Company Limited (PAC), and Panther CDO II, B.V. (incorporated by reference to Exhibit 4.1 to the Company’s Form 8-K filed on September 30, 2004 (SEC File No. 001-13455)). |
| 4.3 |
Form of 5.07% Senior Notes, Series 2004-A, due September 30, 2011 (incorporated by reference to Exhibit 4.2 to the Company’s Form 8-K filed on September 30, 2004 (SEC File No. 001-13455)). |
| 4.4 |
Form of 4.79% Senior Notes, Series 2004-B, due September 30, 2011 (incorporated by reference to Exhibit 4.3 to the Company’s Form 8-K filed on September 30, 2004 (SEC File No. 001-13455)). |
| 4.5 |
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 (incorporated by reference to Exhibit 4.4 to the Company’s Form 8-K filed on September 30, 2004 (SEC File No. 001-13455)). |
| 4.6 |
First Supplement to Master Note Purchase Agreement, dated April 18, 2006, by and among TETRA Technologies, Inc. and Jackson National Life Insurance Company, Allianz Life Insurance Company of North America, United of Omaha Life Insurance Company, Mutual of Omaha Insurance Company, CUNA Mutual Life Insurance Company, CUNA Mutual Insurance Society, CUMIS Insurance Society, Inc., Members Life Insurance Company, and Modern Woodmen of America, attaching the form of the 5.90% Senior Notes, Series 2006-A, due April 30, 2016 as an exhibit thereto (incorporated by reference to Exhibit 4.1 to the Company’s Form 8-K filed on April 20, 2006 (SEC File No. 001-13455)). |
| 10.1*** |
1990 Stock Option Plan, as amended through January 5, 2001 (incorporated by reference to Exhibit 10.8 to the Company’s Form 10-K for the year ended December 31, 2000 filed on March 23, 2001 (SEC File No. 001-13455)). |
| 10.2*** |
Director Stock Option Plan (incorporated by reference to Exhibit 10.9 to the Company’s Form 10-K for the year ended December 31, 2000 filed on March 23, 2001 (SEC File No. 001-13455)). |
| 10.3*** |
1998 Director Stock Option Plan (incorporated by reference to Exhibit 10.10 to the Company’s Form 10-K for the year ended December 31, 2000 filed on March 23, 2001 (SEC File No. 001-13455)). |
| 10.4*** |
1996 Stock Option Plan for Nonexecutive Employees and Consultants (incorporated by reference to Exhibit 99.1 to the Company’s Registration Statement on Form S-8 filed on November 19, 1997 (SEC File No. 333-61988)). |
| 10.5*** |
Letter of Agreement with Gary C. Hanna, dated March, 2002 (incorporated by reference to Exhibit 10.8 to the Company’s Form 10-K for the year ended December 31, 2001 filed on March 26, 2002 (SEC File No. 001-13455)). |
| 10.6*** |
Director Stock Option Plan (incorporated by reference to Exhibit 10.8 to the Company’s Form 10-K for the year ended December 31, 2002 filed on March 27, 2003 (SEC File No. 001-13455)). |
| 10.7 |
Credit Agreement dated as of September 7, 2004, among TETRA Technologies, Inc. and certain of its subsidiaries, as borrowers, Bank of America, National Association, as Administrative Agent, Bank One, NA and Wells Fargo Bank, N.A., as syndication agents, and Comerica Bank, as documentation agent, attaching the guaranty dated as of September 7, 2004, by the borrowers, as guarantors, to the Administrative Agent for the benefit of the lenders under the Credit Agreement (incorporated by reference to Exhibit 10.1 to the Company’s Form 8-K filed on September 8, 2004 (SEC File No. 001-13455)). |
| 10.8*** |
Agreement between TETRA Technologies, Inc. and Geoffrey M. Hertel dated February 26, 1993 (incorporated by reference to Exhibit 10.2 to the Company’s Form 8-K filed on January 7, 2005 (SEC File No. 001-13455)). |
| 10.9*** |
Form of Incentive Stock Option Agreement, dated as of December 28, 2004 (incorporated by reference to Exhibit 10.1 to the Company’s Form 8-K filed on January 7, 2005 SEC File No. 001-13455)). |
| 10.10*** |
TETRA Technologies, Inc. 2006 Equity Incentive Compensation Plan (incorporated by reference to Exhibit 4.12 to the Company’s Registration Statement on Form S-8 filed on May 4, 2006 (SEC File No. 333-133790)). |
| 10.11*** |
Forms of Employee Incentive Stock Option Agreement, Employee Nonqualified Stock Option Agreement, and Employee Restricted Stock Agreement under the TETRA Technologies, Inc. 2006 Equity Incentive Compensation Plan (incorporated by reference to Exhibits 10.1, 10.2, and 10.3 to the Company’s Form 8-K filed on May 8, 2006 (SEC File No. 001-13455)). |
| 10.12+*** |
Summary Description of the Compensation of Non-Employee Directors of TETRA Technologies, Inc. |
| 10.13+*** |
Summary Description of Named Executive Officer Compensation. |
| 10.14 |
Purchase and Sale Agreement by and between Pioneer Natural Resources USA, Inc. as Seller and Maritech Resources, Inc. as Purchaser, dated July 7, 2005 (incorporated by reference to Exhibit 10.1 to the Company’s Form 10-Q filed on November 9, 2005 (SEC File No. 001-13455), certain portions of this exhibit have been omitted pursuant to a confidential treatment request filed with the Securities and Exchange Commission). |
| 10.15*** |
Nonqualified Stock Option Agreement between TETRA Technologies, Inc. and Stuart Brightman, dated April 20, 2005 (incorporated by reference to Exhibit 10.1 to the Company’s Form 8-K filed on April 22, 2005 (SEC File No. 001-13455)). |
| 10.16*** |
First Amendment to the TETRA Technologies, Inc. 1998 Director Stock Option Plan (As Amended Through June 27, 2003) dated December 16, 2005 (incorporated by reference to Exhibit 10.1 to the Company’s Form 8-K filed on December 22, 2005 (SEC File No. 001-13455)). |
| 10.17*** |
Form of Stock Option Agreement under the TETRA Technologies, Inc. 1998 Director Stock Option Plan (As Amended Through June 27, 2003), as further amended by the First Amendment to the TETRA Technologies, Inc. 1998 Director Stock Option Plan (As Amended Through June 27, 2003) (incorporated by reference to Exhibit 10.2 to the Company’s Form 8-K filed on December 22, 2005 (SEC File No. 001-13455)). |
| 10.18 |
Agreement and Third Amendment to Credit Agreement dated as of January 20, 2006, among TETRA Technologies, Inc. and certain of its subsidiaries, as borrowers, JP Morgan Chase Bank, National Association (successor to Bank One, NA) and Wells Fargo Bank, N.A., as syndication agents, Comerica Bank, as documentation agent, Bank of America, National Association, as administrative agent, and the lenders party thereto (incorporated by reference to Exhibit 10.1 to the Company’s Form 8-K filed on January 23, 2006 (SEC File No. 001-13455)). |
| 10.19 |
Credit Agreement, as amended and restated, dated as of June 27, 2006, among TETRA Technologies, Inc. and certain of its subsidiaries, as borrowers, JPMorgan Chase Bank, N.A., as administrative agent, Bank of America, National Association and Wells Fargo Bank, N.A., as syndication agents, and Comerica Bank, as documentation agent, and the lenders party thereto (incorporated by reference to Exhibit 10.1 to the Company’s Form 8-K filed on June 30, 2006 (SEC File No. 001-13455)). |
| 10.20 |
Agreement and First Amendment to Credit Agreement dated as of December 15, 2006, among TETRA Technologies, Inc. and certain of its subsidiaries, as borrowers, JPMorgan Chase Bank, N.A., as administrative agent, Bank of America, National Association and Wells Fargo Bank, N.A., as syndication agents, and Comerica Bank, as documentation agent, and the lenders party thereto (incorporated by reference to Exhibit 10.1 to the Company’s Form 8-K filed on January 10, 2007 (SEC File No. 001-13455)). |
| 10.21*** |
TETRA Technologies, Inc. Nonqualified Deferred Compensation Plan (incorporated by reference to Exhibit 10.9 to the Company’s Form 10-Q filed on August 12, 2002 (SEC File No. 001-13455)). |
| 10.22*** |
TETRA Technologies, Inc. Nonqualified Deferred Compensation Plan and The Executive Excess Plan Adoption Agreement effective on June 30, 2005 (incorporated by reference to Exhibit 10.2 to the Company’s Form 10-Q/A filed on March 16, 2006 (SEC File No. 001-13455)). |
| 10.23*** |
TETRA Technologies, Inc. 2007 Equity Incentive Compensation Plan (incorporated by reference to Exhibit 4.12 to the Company’s Registration Statement on Form S-8 filed on May 4, 2007 (SEC File No. 333-142637)). |
| 10.24*** |
Forms of Employee Incentive Stock Option Agreement, Employee Nonqualified Stock Option Agreement, and Employee Restricted Stock Agreement under the TETRA Technologies, Inc. 2007 Equity Incentive Compensation Plan (incorporated by reference to Exhibits 4.13, 4.14, and 4.15 to the Company’s Registration Statement on Form S-8 filed on May 4, 2007 (SEC File No. 333-142637)). |
| 10.25*** |
TETRA Technologies, Inc. 401(k) Retirement Plan, as amended and restated (incorporated by reference to Exhibit 99.1 to the Company’s Registration Statement on Form S-8 filed on February 22, 2008 (SEC File No. 333-149348)). |
| 10.26*** |
Employee Restricted Stock Agreement between TETRA Technologies, Inc. and Philip N. Longorio, dated February 22, 2008 (incorporated by reference to Exhibit 4.12 to the Company’s Registration Statement on Form S-8 filed on February 22, 2008 (SEC File No. 333-149347)). |
| 21+ |
Subsidiaries of the Company. |
| 23.1+ |
Consent of Ernst & Young, LLP. |
| 23.2+ |
Consent of Ryder Scott Company, L.P. |
| 23.3+ |
Consent of DeGolyer and McNaughton. |
| 31.1+ |
Certification Pursuant to Rule 13(a)-14(a) or 15(d)-14(a) of the Exchange Act, As Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
| 31.2+ |
Certification Pursuant to Rule 13(a)-14(a) or 15(d)-14(a) of the Exchange Act, As Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
| 32.1** |
Certification Furnished Pursuant to 18 U.S.C. Section 1350, As Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Chief Executive Officer). |
| 32.2** |
Certification Furnished Pursuant to 18 U.S.C. Section 1350, As Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Chief Financial Officer). |
+ Filed with this report.
** Furnished with this report.
*** Management contract or compensatory plan or arrangement.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Board of Directors and Stockholders of
TETRA Technologies, Inc.
We have audited the accompanying consolidated balance sheets of TETRA Technologies, Inc. and subsidiaries as of December 31, 2007 and 2006, and the related consolidated statements of operations, stockholders' equity, and cash flows for each of the three years in the period ended December 31, 2007. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of TETRA Technologies, Inc. and subsidiaries at December 31, 2007 and 2006, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2007, in conformity with U.S. generally accepted accounting principles.
As discussed in Notes B and F to the consolidated financial statements, in 2007, the Company adopted FASB Interpretation No. 48 “Accounting for Uncertainty in Income Taxes.” In addition, as described in Notes B and L to the consolidated financial statements, in 2006 the Company adopted the provisions of Statement of Financial Accounting Standards No. 123 (revised 2004), “Share-Based Payments.”
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), TETRA Technologies, Inc.’s internal control over financial reporting as of December 31, 2007, based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 28, 2008, expressed an unqualified opinion thereon.
/s/ERNST & YOUNG LLP
Houston, Texas
February 28, 2008
F-1
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Board of Directors and Stockholders of
TETRA Technologies, Inc.
We have audited TETRA Technologies, Inc.’s internal control over financial reporting as of December 31, 2007, based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). TETRA Technologies, Inc.’s management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Report of Management on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the company’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, TETRA Technologies, Inc. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2007, based on the COSO criteria.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of TETRA Technologies, Inc. and subsidiaries as of December 31, 2007 and 2006, and the related consolidated statements of operations, stockholders’ equity and cash flows for each of the three years in the period ended December 31, 2007, and our report dated February 28, 2008, expressed an unqualified opinion thereon.
/s/ERNST & YOUNG LLP
Houston, Texas
February 28, 2008
F-2
TETRA Technologies, Inc. and Subsidiaries
Consolidated Balance Sheets
(In Thousands)
December 31, |
||||||
2007 |
2006 |
|||||
ASSETS |
||||||
Current assets: |
||||||
Cash and cash equivalents |
$ |
21,833 |
$ |
5,535 |
||
Restricted cash |
4,218 |
582 |
||||
Accounts receivable, net of allowances for doubtful accounts of $1,293 in 2007 and $2,432 in 2006 |
215,284 |
240,904 |
||||
Inventories |
118,502 |
117,986 |
||||
Deferred tax assets |
26,247 |
4,438 |
||||
Prepaid expenses and other current assets |
33,365 |
31,006 |
||||
Assets of discontinued operations |
4,042 |
23,879 |
||||
Total current assets |
423,491 |
424,330 |
||||
|
||||||
Property, plant and equipment: |
||||||
Land and building |
21,359 |
19,439 |
||||
Machinery and equipment |
404,647 |
295,662 |
||||
Automobiles and trucks |
37,483 |
27,022 |
||||
Chemical plants |
46,267 |
48,332 |
||||
Oil and gas producing assets (successful efforts method) |
564,493 |
284,266 |
||||
Construction in progress |
19,595 |
39,470 |
||||
|
1,093,844 |
714,191 |
||||
Less accumulated depreciation and depletion |
(397,453 |
) |
(219,592 |
) |
||
Net property, plant and equipment |
696,391 |
494,599 |
||||
|
||||||
Other assets: |
||||||
Goodwill |
130,335 |
123,285 |
||||
Patents, trademarks and other intangible assets, net of accumulated amortization of $14,489 in 2007 and $11,335 in 2006 |
19,884 |
21,317 |
||||
Other assets |
25,435 |
22,659 |
||||
Total other assets |
175,654 |
167,261 |
||||
|
$ |
1,295,536 |
$ |
1,086,190 |
||
See Notes to Consolidated Financial Statements
F-3
TETRA Technologies, Inc. and Subsidiaries
Consolidated Balance Sheets
(In Thousands)
December 31, |
||||||
2007 |
2006 |
|||||
LIABILITIES AND STOCKHOLDERS' EQUITY |
||||||
Current liabilities: |
||||||
Trade accounts payable |
$ |
108,101 |
$ |
78,738 |
||
Accrued liabilities |
133,525 |
82,137 |
||||
Liabilities of discontinued operations |
424 |
883 |
||||
Total current liabilities |
242,050 |
161,758 |
||||
|
||||||
Long-term debt, net |
358,024 |
336,381 |
||||
Deferred income taxes |
46,263 |
51,243 |
||||
Decommissioning and other asset retirement obligations, net |
162,106 |
104,938 |
||||
Other liabilities |
39,174 |
11,490 |
||||
Total long-term and other liabilities |
605,567 |
504,052 |
||||
|
||||||
Commitments and contingencies |
||||||
|
||||||
Stockholders' equity: |
||||||
Common stock, par value $.01 per share; 100,000,000 shares authorized; 75,921,727 shares issued at December 31, 2007 and 73,877,467 shares issued at December 31, 2006 |
759 |
739 |
||||
Additional paid-in capital |
174,738 |
147,178 |
||||
Treasury stock, at cost; 1,550,962 shares held at December 31, 2007, and 1,946,039 shares held at December 31, 2006 |
(8,405 |
) |
(10,524 |
) |
||
Accumulated other comprehensive income |
(25,999 |
) |
4,875 |
|||
Retained earnings |
306,826 |
278,112 |
||||
Total stockholders' equity |
447,919 |
420,380 |
||||
|
$ |
1,295,536 |
$ |
1,086,190 |
||
See Notes to Consolidated Financial Statements
F-4
TETRA Technologies, Inc. and Subsidiaries
Consolidated Statements of Operations
(In Thousands, Except Per Share Amounts)
Year Ended December 31, |
|||||||||
2007 |
2006 |
2005 |
|||||||
Revenues: |
|||||||||
Product sales |
$ |
457,238 |
$ |
388,257 |
$ |
279,483 |
|||
Services and rentals |
525,245 |
379,538 |
229,766 |
||||||
| Total revenues |
982,483 |
767,795 |
509,249 |
||||||
|
|||||||||
Cost of revenues: |
|||||||||
Cost of product sales |
301,731 |
197,874 |
192,631 |
||||||
Cost of services and rentals |
362,745 |
232,781 |
|
149,401 |
|||||
Depreciation, depletion, amortization and accretion |
129,844 |
80,931 |
41,639 |
||||||
Impairments of long-lived assets |
71,780 |
3,405 |
1,907 |
||||||
Total cost of revenues |
866,100 |
514,991 |
385,578 |
||||||
Gross profit |
116,383 |
252,804 |
123,671 |
||||||
|
|||||||||
General and administrative expense |
99,871 |
92,004 |
69,354 |
||||||
Operating income |
16,512 |
160,800 |
54,317 |
||||||
|
|||||||||
Interest expense, net |
17,155 |
13,289 |
5,980 |
||||||
Other income, net |
2,805 |
4,858 |
3,692 |
||||||
| Income before taxes and discontinued operations |
2,162 |
152,369 |
52,029 |
||||||
Provision for income taxes |
941 |
52,489 |
17,227 |
||||||
| Income before discontinued operations |
1,221 |
99,880 |
34,802 |
||||||
Discontinued operations: |
|
|
|
||||||
Income from discontinued operations, net of taxes |
1,723 |
1,998 |
|
3,260 |
|||||
Gain on disposal of discontinued operations, net of taxes |
25,827 |
– |
|
– |
|||||
Income from discontinued operations |
27,550 |
1,998 |
|
3,260 |
|||||
|
|||||||||
Net income |
$ |
28,771 |
$ |
101,878 |
$ |
38,062 |
|||
|
|||||||||
Basic net income per common share: |
|||||||||
| Income before discontinued operations |
$ |
0.02 |
$ |
1.39 |
$ |
0.51 |
|||
Income from discontinued operations |
0.02 |
0.03 |
|
0.04 |
|||||
Gain on disposal of discontinued operations |
0.35 |
– |
|
– |
|||||
Net income |
$ |
0.39 |
$ |
1.42 |
$ |
0.55 |
|||
Average shares outstanding |
73,573 |
71,631 |
68,588 |
||||||
|
|||||||||
Diluted net income per common share: |
|||||||||
| Income before discontinued operations |
$ |
0.02 |
$ |
1.33 |
$ |
0.48 |
|||
Income from discontinued operations |
0.02 |
0.03 |
|
0.05 |
|||||
Gain on disposal of discontinued operations |
0.34 |
– |
|
– |
|||||
Net income |
$ |
0.38 |
$ |
1.36 |
$ |
0.53 |
|||
Average diluted shares outstanding |
75,921 |
74,824 |
72,137 |
||||||
See Notes to Consolidated Financial Statements
F-5
TETRA Technologies, Inc. and Subsidiaries
Consolidated Statements of Stockholders' Equity
(In Thousands, Except Share Information)
|
Accumulated
Other Comprehensive Income |
|||||||||||||||||||||||||
|
Outstanding Common Shares |
|
Treasury Shares Held |
|
Common Stock Par Value |
|
Additional Paid-In Capital |
|
Treasury Stock |
|
Retained Earnings |
|
Derivative Instruments |
|
Currency Translation |
|
Total Stockholders' Equity |
|||||||||
Balance at December 31, 2004 |
67,542,366 |
2,188,662 |
$ |
697 |
$ |
105,451 |
$ |
(10,279 |
) |
$ |
138,172 |
$ |
(39 |
) |
$ |
2,179 |
|
$ |
236,181 |
||||||
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
Net income for 2005 |
38,062 |
38,062 |
|||||||||||||||||||||||
Translation adjustment, net of taxes of $2,096 |
(3,224 |
) |
(3,224 |
) |
|||||||||||||||||||||
Net change in derivative fair value, net of taxes of $2,747 |
(4,636 |
) |
(4,636 |
) |
|||||||||||||||||||||
Reclassification of derivative fair value into earnings, net of taxes of $2,103 |
3,551 |
3,551 |
|||||||||||||||||||||||
Comprehensive income |
33,753 |
||||||||||||||||||||||||
Exercise of common stock options |
2,257,416 |
(231,082 |
) |
20 |
9,462 |
973 |
10,455 |
||||||||||||||||||
Purchase of treasury stock |
(261,900 |
) |
261,900 |
(2,351 |
) |
(2,351 |
) |
||||||||||||||||||
Tax benefit upon exercise of certain nonqualified and incentive options |
|
|
|
6,109 |
|
|
|
|
6,109 |
||||||||||||||||
Balance at December 31, 2005 |
69,537,882 |
2,219,480 |
|
$ |
717 |
$ |
121,022 |
$ |
(11,657 |
) |
$ |
176,234 |
$ |
(1,124 |
) |
$ |
(1,045 |
) |
$ |
284,147 |
|||||
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
Net income for 2006 |
101,878 |
101,878 |
|||||||||||||||||||||||
Translation adjustment, net of taxes of $1,528 |
3,037 |
3,037 |
|||||||||||||||||||||||
Net change in derivative fair value, net of taxes of $5,592 |
9,440 |
9,440 |
|||||||||||||||||||||||
Reclassification of derivative fair value into earnings, net of taxes of $3,218 |
(5,433 |
) |
(5,433 |
) |
|||||||||||||||||||||
Comprehensive income |
108,922 |
||||||||||||||||||||||||
Exercise of common stock options |
2,393,546 |
(273,441 |
) |
22 |
10,221 |
1,133 |
11,376 |
||||||||||||||||||
Stock option expense |
3,430 |
3,430 |
|||||||||||||||||||||||
Tax benefit upon exercise of certain nonqualified and incentive options |
|
|
|
12,505 |
|
|
|
|
12,505 |
||||||||||||||||
Balance at December 31, 2006 |
71,931,428 |
1,946,039 |
$ |
739 |
$ |
147,178 |
$ |
(10,524 |
) |
$ |
278,112 |
$ |
2,883 |
$ |
1,992 |
$ |
420,380 |
||||||||
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
Net income for 2007 |
28,771 |
28,771 |
|||||||||||||||||||||||
Translation adjustment, net of taxes of $1,381 |
4,870 |
4,870 |
|||||||||||||||||||||||
Net change in derivative fair value, net of taxes of $21,887 |
(37,110 |
) |
(37,110 |
) |
|||||||||||||||||||||
Reclassification of derivative fair value into earnings, net of taxes of $809 |
1,366 |
1,366 |
|||||||||||||||||||||||
Comprehensive income |
(2,103 |
) | |||||||||||||||||||||||
Impact of adoption of FIN No. 48 |
(57 |
) |
(57 |
) | |||||||||||||||||||||
Exercise of common stock options |
2,208,371 |
(422,861 |
) |
20 |
9,954 |
2,192 |
12,166 |
||||||||||||||||||
Grants of restricted stock, net |
230,966 |
27,784 |
(73 |
) |
(73 |
) | |||||||||||||||||||
Stock option expense |
4,416 |
4,416 |
|||||||||||||||||||||||
Tax benefit upon exercise of certain nonqualified and incentive options |
|
|
|
13,190 |
|
|
|
|
13,190 |
||||||||||||||||
Balance at December 31, 2007 |
74,370,765 |
1,550,962 |
$ |
759 |
$ |
174,738 |
$ |
(8,405 |
) |
$ |
306,826 |
$ |
(32,861 |
) |
$ |
6,862 |
$ |
447,919 |
|||||||
See Notes to Consolidated Financial Statements
F-6
TETRA Technologies, Inc. and Subsidiaries
Consolidated Statements of Cash Flows
(In Thousands)
Year Ended December 31, |
|||||||||
2007 |
2006 |
2005 |
|||||||
Operating activities: |
|||||||||
Net income |
$ |
28,771 |
$ |
101,878 |
$ |
38,062 |
|||
Reconciliation of net income to cash provided by operating activities: |
|||||||||
Depreciation, depletion, amortization and accretion |
129,844 |
80,931 |
41,639 |
||||||
Impairments of long-lived assets |
71,780 |
3,405 |
1,907 |
||||||
Provision for deferred income taxes |
674 |
|
23,152 |
|
(3,244 |
) |
|||
Stock compensation expense |
4,416 |
|
3,430 |
– |
|||||
Provision for doubtful accounts |
1,459 |
442 |
668 |
||||||
Gain on sale of property, plant and equipment |
(4,974 |
) |
(5,031 |
) |
(2,406 |
) |
|||
Other non-cash charges and credits |
26,043 |
|
(5,872 |
) |
3,065 |
|
|||
Excess tax benefit from exercise of stock options |
(13,189 |
) |
(12,505 |
) |
– |
|
|||
Equity in (earnings) loss of unconsolidated subsidiary |
1,063 |
|
(250 |
) |
(511 |
) |
|||
Changes in operating assets and liabilities, net of assets acquired: |
|||||||||
Accounts receivable |
(5,346 |
) |
(85,596 |
) |
(57,777 |
) |
|||
Inventories |
2,626 |
(41,522 |
) |
(23,052 |
) |
||||
Prepaid expenses and other current assets |
(5,152 |
) |
(12,575 |
) |
(7,241 |
) |
|||
Trade accounts payable and accrued expenses |
27,936 |
14,426 |
57,116 |
|
|||||
Decommissioning liabilities |
(32,919 |
) |
(19,089 |
) |
(5,106 |
) |
|||
Operating activities of discontinued operations |
(22,993 |
) |
3,278 |
1,940 |
|||||
Other |
(1,000 |
) |
(721 |
) |
17 |
|
|||
Net cash provided by operating activities |
209,039 |
47,781 |
45,077 |
||||||
|
|||||||||
Investing activities: |
|||||||||
Purchases of property, plant and equipment |
(276,074 |
) |
(172,415 |
) |
(76,993 |
) |
|||
Business combinations, net of cash acquired |
(14,479 |
) |
(68,651 |
) |
– |
||||
Proceeds from sale of property, plant and equipment |
2,582 |
2,454 |
5,484 |
||||||
Other investing activities |
(2,621 |
) |
(1,145 |
) |
(62 |
) |
|||
Investing activities of discontinued operations |
55,414 |
(2,135 |
) |
(4,981 |
) |
||||
Net cash used in investing activities |
(235,178 |
) |
(241,892 |
) |
(76,552 |
) |
|||
|
|||||||||
Financing activities: |
|||||||||
Proceeds from long-term debt |
116,930 |
321,693 |
82,163 |
||||||
Principal payments on long-term debt |
(100,937 |
) |
(148,057 |
) |
(62,172 |
) |
|||
Repurchase of common stock |
– |
– |
|
(2,351 |
) |
||||
Excess tax benefit from exercise of stock options |
13,189 |
12,505 |
|
– |
|||||
Proceeds from sale of common stock and exercised stock options |
12,087 |
11,377 |
10,455 |
||||||
Net cash provided by financing activities |
41,269 |
197,518 |
28,095 |
||||||
Effect of exchange rate changes on cash |
1,168 |
|
531 |
|
(387 |
) |
|||
|
|||||||||
| Increase (decrease) in cash and cash equivalents |
16,298 |
|
3,938 |
|
(3,767 |
) |
|||
Cash and cash equivalents at beginning of period |
5,535 |
1,597 |
|
5,364 |
|||||
Cash and cash equivalents at end of period |
$ |
21,833 |
$ |
5,535 |
$ |
1,597 |
|||
|
|||||||||
Supplemental cash flow information: |
|||||||||
Interest paid |
$ |
18,640 |
$ |
13,468 |
$ |
6,414 |
|||
Taxes paid |
12,184 |
24,957 |
10,285 |
||||||
|
|||||||||
Supplemental disclosure of non-cash investing and financing activities: |
|||||||||
Oil and gas properties acquired through assumption of decommissioning liabilities |
$ |
24,759 |
$ |
7,620 |
$ |
71,126 |
|||
|
|||||||||
Adjustment of fair value of decommissioning liabilities capitalized (credited) to oil and gas properties |
$ |
71,683 |
$ |
6,003 |
$ |
(741 |
) |
||
See Notes to Consolidated Financial Statements
F-7
TETRA TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2007
NOTE A — ORGANIZATION AND OPERATIONS OF THE COMPANY
TETRA Technologies, Inc. is an oil and gas services and production company with an integrated calcium chloride and brominated products manufacturing operation that supplies feedstocks to energy markets, as well as to other markets. We were incorporated in Delaware in 1981. We are composed of three divisions – Fluids, Well Abandonment & Decommissioning (WA&D), and Production Enhancement. Unless the context requires otherwise, when we refer to “we,” “us,” and “our,” we are describing TETRA Technologies, Inc. and its consolidated subsidiaries on a consolidated basis.
Our Fluids Division manufactures and markets clear brine fluids, additives, and other associated products and services to the oil and gas industry for use in well drilling, completion, and workover operations both domestically and in certain regions of Europe, Asia (including the Middle East), 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.
Our WA&D Division consists of two operating segments: WA&D Services and an oil and gas production segment, 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. The WA&D Services segment also provides diving, marine, engineering, cutting, workover, drilling, and other services. The WA&D Services segment operates primarily in the onshore U.S. Gulf Coast region and the inland waters and offshore markets of the Gulf of Mexico.
The Maritech segment consists of our Maritech Resources, Inc. subsidiary, which, with its subsidiaries (Maritech), is a producer of oil and gas from properties acquired to support and provide a baseload of business for our WA&D Services segment. In addition, Maritech conducts development and exploitation operations on certain of its oil and gas properties that are intended to increase the cash flows on such properties prior to their ultimate abandonment.
Our Production Enhancement Division provides production testing services to markets in Texas, New Mexico, Colorado, Oklahoma, Arkansas, Louisiana, offshore Gulf of Mexico, and certain international locations. In addition, it provides wellhead compression services to customers to enhance production from mature, low pressure natural gas wells located principally in the mid-continent, mid-western, western, Rocky Mountain, and Gulf Coast regions of the United States as well as in western Canada, Mexico, and other Latin American countries.
NOTE B — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Principles of Consolidation
The consolidated financial statements include the accounts of our wholly owned subsidiaries. Investments in unconsolidated joint ventures in which we participate are accounted for using the equity method. Our interests in oil and gas properties are proportionately consolidated. All significant intercompany accounts and transactions have been eliminated in consolidation.
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.
F-8
Reclassifications
The consolidated financial statements retroactively reflect the effect of certain stock splits of our common stock, which were each effected in the form of a stock dividend to all stockholders of record as of the record dates. In May 2006, we declared a 2-for-1 stock split to all stockholders of record as of May 15, 2006. On May 22, 2006, stockholders received one additional share of common stock for each share held on the record date. In August 2005, we declared a 3-for-2 stock split to all stockholders of record as of August 19, 2005. On August 26, 2005, stockholders received one additional share of common stock for every two shares held as of the record date. Accordingly, all disclosures involving the number of shares of our common stock outstanding, issued or to be issued, such as with our stock options, and all per share amounts, have been retroactively adjusted to reflect the impact of the stock split. See Note K – Capital Stock, for further discussion of the stock splits.
We have accounted for the discontinuance or disposal of certain businesses as discontinued operations, and have reclassified prior period financial statements to exclude these businesses from continuing operations. See Note C – Discontinued Operations, for a further discussion of the discontinuance of these businesses and the impact of prior period’s reclassifications on our consolidated financial statements.
Certain other previously reported financial information has also been reclassified to conform to the current year's presentation.
Cash Equivalents
We consider all highly liquid investments, with a maturity of three months or less when purchased, to be cash equivalents.
Restricted Cash
Restricted cash reflected on our balance sheets as of December 31, 2007 includes approximately $3.6 million of escrowed funds associated with the sale of our process services operation, which will be available to us within twelve months from the date of sale, assuming no breach in the terms of the sales contracts is identified by the buyer. In addition, restricted cash as of December 31, 2007 and 2006 includes funds related to a third party’s proportionate obligation in the plugging and abandonment of a particular oil and gas property operated by our Maritech subsidiary. This cash will remain restricted until such time as the associated plugging and abandonment project is completed, which we expect to occur during the next twelve months.
Financial Instruments
The fair value of our 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 us to concentrations of credit risk consist principally of trade receivables with companies in the energy industry. Our policy is to evaluate, prior to providing goods or services, each customer's financial condition and determine the amount of open credit to be extended. We generally require appropriate, additional collateral as security for credit amounts in excess of approved limits. Our customers consist primarily of major, well-established oil and gas producers and independent oil and gas companies.
Our risk management activities currently involve the use of derivative financial instruments, such as oil and gas swap contracts, to hedge the impact of commodity market price risk exposures related to a portion of our oil and gas production cash flow. Oil and gas swap contracts result in us receiving a fixed amount per barrel or MMBtu over the term of the contract. The effective portion of the derivative’s gain or loss (i.e., that portion of the derivative’s gain or loss that offsets the corresponding change in the cash flows of the hedged transaction) is initially reported as a component of accumulated other comprehensive income (loss) and will be subsequently reclassified into revenues to match the offsetting impact of commodity prices on the hedged exposure when it affects revenues. The “ineffective” portion of the derivative’s gain or loss is recognized in earnings immediately.
F-9
We are exposed to fluctuations between the U.S. dollar and the Euro, as well as other foreign currencies, with regard to our foreign operations. In addition, we entered into Euro-denominated debt as a hedge of our net investment in our Euro-based operating activities. The hedge is considered to be effective since the debt balance designated as the hedge is less than or equal to the net investment in the foreign operation.
As a result of our outstanding balance under a variable rate bank credit facility, we face market risk exposure related to changes in applicable interest rates. Although we have no interest rate swap contracts outstanding to hedge this risk exposure, we have entered into certain fixed interest rate notes, which are scheduled to mature in 2011 and 2016 and which mitigate this risk on our total outstanding borrowings.
Allowances for Doubtful Accounts
Allowances for doubtful accounts are determined on a specific identification basis when we believe that the collection of specific amounts owed to us is not probable.
Inventories
Inventories are stated at the lower of cost or market value. Cost is determined using the weighted average method. Significant components of inventories as of December 31, 2007 and 2006 are as follows:
December 31, |
||||||
2007 |
2006 |
|||||
(In Thousands) |
||||||
Finished goods |
$ |
89,309 |
$ |
98,036 |
||
Raw materials |
6,373 |
6,093 |
||||
Parts and supplies |
21,081 |
13,347 |
||||
Work in progress |
1,739 |
510 |
||||
Total inventories |
$ |
118,502 |
$ |
117,986 |
||
Property, Plant and Equipment
Property, plant and equipment are stated at the cost of assets acquired. Expenditures that increase the useful lives of assets are capitalized. The cost of repairs and maintenance is charged to operations as incurred. For financial reporting purposes, we generally provide for depreciation using the straight-line method over the estimated useful lives of assets which are as follows:
Buildings |
15 – 25 years |
Machinery, vessels, and equipment |
3 – 15 years |
Automobiles and trucks |
4 years |
Chemical plants |
15 years |
Certain machinery, equipment and properties are depreciated or depleted based on operating hours or units of production, subject to a minimum amount, because depreciation and depletion occur primarily through use rather than through elapsed time. Leasehold improvements are depreciated over the shorter of the remaining term of the associated lease or its useful life. Depreciation and depletion expense, excluding oil and gas impairments and dry hole costs, for the years ended December 31, 2007, 2006, and 2005 was $118.6 million, $70.2 million, and $38.5 million, respectively.
Interest capitalized for the years ended December 31, 2007, 2006, and 2005 was $1.4 million, $1.1 million, and $0.3 million, respectively.
F-10
Oil and Gas Properties
Maritech purchases oil and gas properties and assumes the related well abandonment and decommissioning liabilities (referred to as decommissioning liabilities). Maritech also conducts oil and gas exploitation and production activities on the acquired properties. We follow the successful efforts method of accounting for our oil and gas operations. Under the successful efforts method, the costs of successful exploratory wells and leases are capitalized. Costs incurred to drill and equip development wells, including unsuccessful development wells, are capitalized. Other costs such as geological and geophysical costs, drilling costs of unsuccessful exploratory wells, and all internal costs are expensed. Maritech’s property purchases are recorded at the fair value of our working interest share of decommissioning liabilities assumed (plus or minus any cash or other consideration paid or received at the time of closing the transaction). All capitalized costs are accumulated and recorded separately for each field and allocated to leasehold costs and well costs. Leasehold costs are depleted on a unit of production method based on the estimated remaining equivalent proved oil and gas reserves of each field. Well costs are depleted on a unit of production method based on the estimated remaining equivalent proved developed oil and gas reserves of each field. Oil and gas producing assets were depleted at an average rate of $3.45, $2.42, and $1.86 per Mcf equivalent for the years ended December 31, 2007, 2006, and 2005, respectively.
Impairment of Long-Lived Assets
Impairments of long-lived assets are determined periodically when indicators of impairment are present. If such indicators are present, the determination of the amount of impairment is based on our judgments as to the future undiscounted operating cash flows to be generated from these assets throughout their estimated useful lives. If these undiscounted cash flows are less than the carrying amount of the related asset, an impairment is recognized for the excess of the carrying value over its fair value. The assessment of oil and gas properties for impairment is based on the future estimated cash flows from our proved, probable and possible reserves. Assets held for disposal are recorded at the lower of carrying value or estimated fair value less estimated selling costs.
During 2007, 2006, and 2005, we identified impairments totaling approximately $71.8 million, $3.4 million, and $1.9 million, respectively, net of intercompany eliminations, of the net carrying value of certain Maritech oil and gas properties. These impairments during 2007 were caused primarily due to the reversal of anticipated insurance recoveries resulting in increased decommissioning liabilities due to certain future well intervention and debris removal costs being contested by our insurance provider. Impairments were also recorded on certain other properties as a result of changes in development plans following Maritech’s acquisition of certain oil and gas properties in December 2007. In addition, certain properties were impaired due to decreased production volumes or an increase in the associated decommissioning liability. During 2006, a portion of the net carrying value of a certain Maritech property was impaired due to the reversal of anticipated insurance recoveries resulting in increased decommissioning liabilities as a result of contested insurance claims. During 2005, the carrying value of a certain property was impaired after Maritech made the decision not to attempt certain workover procedures necessary to restore production on an offshore field which it operates. The above charges to earnings are included in depreciation, depletion, amortization and accretion in the accompanying statements of operations.
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 2007, as a part of certain acquisitions consummated during the year, we acquired intangible assets having a fair value of approximately $2.4 million, with estimated useful lives ranging from two to six years (having a weighted average useful life of 5.5 years). During 2006, as part of the acquisitions consummated during the year, we acquired intangible assets with a fair value of approximately $13.1 million, with estimated useful lives ranging from 3 to 8 years (having a weighted average useful life of 6.29 years). Amortization expense of patents, trademarks, and other intangible assets was $3.8 million, $2.8 million, and $1.3 million for the twelve months ended December 31, 2007, 2006, and 2005,
F-11
respectively, and is included in operating income. The estimated future annual amortization expense of patents, trademarks, and other intangible assets is $3.6 million for 2008, $2.6 million for 2009, $2.2 million for 2010, $2.1 million for 2011, and $2.0 million for 2012.
Goodwill represents the excess of cost over the fair value of the net assets of businesses acquired in purchase transactions. We perform a goodwill impairment test on an annual basis or whenever indicators of impairment are present. For purposes of the impairment test, the reporting units are our four reporting segments: Fluids, WA&D Services, Maritech, and Production Enhancement. We have estimated the fair value of each reporting unit based upon the future discounted cash flows of the businesses to which goodwill relates and have determined that there is no impairment of the goodwill recorded as of December 31, 2007 or December 31, 2006. The changes in the carrying amount of goodwill by reporting unit for the two year period ended December 31, 2007, are as follows:
|
Fluids |
|
WA&D Services |
|
Maritech |
|
Production Enhancement |
|
Total |
|||||||
(In Thousands) |
|||||||||||||||
Balance as of December 31, 2005 |
$ |
18,860 |
$ |
6,764 |
$ |
– |
$ |
76,937 |
$ |
102,561 |
|||||
Goodwill acquired during the year |
905 |
12,583 |
– |
5,534 |
19,022 |
|
|||||||||
Foreign currency fluctuations |
1,699 |
– |
– |
– |
|
1,699 |
|
||||||||
|
|||||||||||||||
Balance as of December 31, 2006 |
21,464 |
19,347 |
– |
82,471 |
123,282 |
||||||||||
Goodwill acquired during the year |
1,267 |
3,876 |
– |
– |
5,143 |
||||||||||
Foreign currency fluctuations |
1,910 |
– |
– |
– |
1,910 |
||||||||||
|
|||||||||||||||
Balance as of December 31, 2007 |
$ |
24,641 |
$ |
23,223 |
$ |
– |
$ |
82,471 |
$ |
130,335 |
|||||
Decommissioning Liabilities
Related to our acquired interests in oil and gas properties, we estimate the third party fair values (including an estimated profit) to plug and abandon wells, decommission the pipelines and platforms and clear the sites, and we use these estimates to record Maritech’s decommissioning liabilities, net of amounts allocable to joint interest owners 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, 2007 and 2006, our Maritech subsidiary’s decommissioning liabilities are net of approximately $54.8 million and $65.3 million, respectively, of such future reimbursements from these previous owners.
In estimating the decommissioning liabilities, we perform detailed estimating procedures, analysis, and engineering studies. Whenever practical and cost effective, Maritech will utilize the services of its affiliated companies to perform well abandonment and decommissioning work. When these services are performed by an affiliated company, all recorded intercompany revenues are eliminated in the consolidated financial statements. The recorded decommissioning liability associated with a specific property is fully extinguished when the property is completely abandoned. The liability is first reduced by all cash expenses incurred to abandon and decommission the property. If the liability exceeds (or is less than) our actual out-of-pocket costs, the difference is reported as income (or loss) in the period in which the work is performed. We review the adequacy of our decommissioning liabilities whenever indicators suggest that the estimated cash flows underlying the liabilities have changed materially. The timing and amounts of these cash flows are subject to changes in the energy industry environment and may result in additional liabilities to be recorded, which, in turn, would increase the carrying values of the related properties. In connection with 2007, 2006, and 2005 oil and gas property additions, we assumed net decommissioning liabilities having an estimated fair value of approximately $24.8 million, $3.0 million, and $97.4 million, respectively. As a result of decommissioning work performed, we recorded total reductions to the decommissioning liabilities for the years 2007, 2006, and 2005 of $32.9 million, $19.1 million, and $5.1 million, respectively. We made adjustments to our decommissioning liabilities during the years 2007, 2006, and 2005 as a result of changes in the timing or amount of future cash flows of approximately $63.3 million, $15.9 million, and $1.9 million, respectively.
F-12
Environmental Liabilities
Environmental expenditures which result in additions to property and equipment are capitalized, while other environmental expenditures are expensed. Environmental remediation liabilities are recorded on an undiscounted basis when environmental assessments or cleanups are probable and the costs can be reasonably estimated. Estimates of future environmental remediation expenditures often consist of a range of possible expenditure amounts, a portion of which may be in excess of amounts of liabilities recorded. In this instance, we disclose the full range of amounts reasonably possible of being incurred. Any changes or developments in environmental remediation efforts are accounted for and disclosed each quarter as they occur. Any recoveries of environmental remediation costs from other parties are recorded as assets when their receipt is deemed probable.
Complexities involving environmental remediation efforts can cause the estimates of the associated liability to be imprecise. Factors which cause uncertainties regarding the estimation of future expenditures include, but are not limited to, the effectiveness of the anticipated work plans in achieving targeted results and changes in the desired remediation methods and outcomes as prescribed by regulatory agencies. Uncertainties associated with environmental remediation contingencies are pervasive and often result in wide ranges of reasonably possible outcomes. Estimates developed in the early stages of remediation can vary significantly. Normally, a finite estimate of cost does not become fixed and determinable at a specific point in time. Rather, the costs associated with environmental remediation become estimable as the work is performed and the range of ultimate cost becomes more defined. It is possible that cash flows and results of operations could be materially affected by the impact of the ultimate resolution of these contingencies.
Revenue Recognition
Revenues are recognized when finished products are shipped or services have been provided to unaffiliated customers and only when collectibility is reasonably assured. Sales terms for our products are FOB shipping point, with title transferring at the point of shipment. Revenue is recognized at the point of transfer of title. We recognize oil and gas product sales revenues from our Maritech subsidiary’s interests in producing wells as oil and natural gas is produced and sold from those wells. Oil and natural gas sold is not significantly different from Maritech’s share of production. With regard to turnkey contracts, revenues are recognized using the percentage-of-completion method based on the ratio of costs incurred to total estimated costs at completion. Total project revenue and cost estimates for turnkey contracts are reviewed periodically as work progresses, and adjustments are reflected in the period in which such estimates are revised. Provisions for estimated losses on such contracts are made in the period such losses are determined.
Gas Balancing
As part of our Maritech subsidiary’s acquisitions of producing properties, we have acquired gas balancing receivables and payables related to certain properties. We allocate value for any acquired gas balancing positions using estimated fair value amounts expected to be received or paid in the future. Amounts related to under produced volume positions acquired are reflected as assets and amounts related to overproduced volume positions acquired are reflected as liabilities. At December 31, 2007 and 2006, we reflected gas balancing receivables of $3.2 million and $3.3 million, respectively, in accounts receivable or other long-term assets and gas balancing payables of $7.1 million and $6.9 million, respectively, in accrued liabilities or other long-term liabilities. We recognize oil and gas product sales from our Maritech subsidiary’s interest in producing wells based on its entitled share of oil and natural gas produced and sold from those wells. Changes to our gas balancing receivable or payable are valued at the lower of the price in effect at time of production, current market price, or contract price, if applicable.
Operating Costs
Cost of product sales includes direct and indirect costs of manufacturing and producing our products, including raw materials, fuel, utilities, labor, overhead, repairs and maintenance, materials, services, transportation, warehousing, equipment rentals, depreciation, insurance, and taxes. In addition, cost of product sales includes oil and gas operating expense. Cost of services and rentals includes operating expenses we incur in delivering our services, including labor, equipment rental, fuel, repair and
F-13
maintenance, transportation, overhead, insurance, and certain taxes. We include in product sales revenues the reimbursements we receive from customers for shipping and handling costs. Shipping and handling costs are included in cost of product sales. Amounts we incur for “out-of-pocket” expenses in the delivery of our services are recorded as cost of services and rentals. Reimbursements for “out-of-pocket” expenses we incur in the delivery of our services are recorded as service revenues. Depreciation, depletion, amortization and accretion includes depreciation expense for all of our facilities, equipment and vehicles, depletion, and dry hole expense on our oil and gas properties, amortization expense on our intangible assets, and accretion expense related to our asset retirement obligations.
We include in general and administrative expense all costs not identifiable to our specific product or service operations, including divisional and general corporate overhead, professional services, corporate office costs, sales and marketing expenses, insurance and taxes.
Insured Costs and Recoveries
We incurred significant damage to certain of our onshore and offshore operating equipment and facilities during the third quarter of 2005 as a result of Hurricanes Katrina and Rita and other events during this period. These events resulted in the damage or destruction of certain of our fluids facilities, as well as certain of our decommissioning assets, including one of our heavy lift barges. Our Maritech subsidiary also suffered varying levels of damage to the majority of its offshore oil and gas producing platforms, and three of its platforms and one of its production facilities were completely destroyed. The majority of the assets damaged during these hurricanes have been repaired and have resumed operation. With regard to the destroyed offshore platforms, well intervention efforts on several of the wells associated with two of the destroyed platforms have been performed, and we are continuing to assess the extent of well intervention work required on wells associated with the third platform. Well intervention efforts to date have been performed by our WA&D Services segment. In addition, we are also continuing to assess the removal of debris costs associated with the destroyed platforms. Cumulative storm and other related expenditures, including well intervention costs and repair costs of other damaged assets, totaled approximately $136.5 million and $121.6 million as of December 31, 2007 and 2006, respectively. We estimate that remaining storm related repairs, primarily the remaining well intervention and debris removal costs associated with the three destroyed platforms, will result in approximately $50 to $70 million of additional costs, and are expected to be incurred in 2008 and beyond. As of December 31, 2007 and 2006, approximately $93.6 million and $57.7 million of hurricane related costs have been reimbursed to us under our applicable insurance policies. Subsequent to December 31, 2007, we have received an additional $3.9 million of hurricane related reimbursements.
We recognize anticipated insurance recoveries when collection is deemed probable. Any recognition of anticipated insurance recoveries is used to offset the original charge to which the insurance relates. The amount of anticipated insurance recoveries is included either in accounts receivable, or as a reduction of Maritech’s decommissioning liabilities in the accompanying consolidated balance sheets. In 2007, we reversed $62.9 million of anticipated insurance recoveries as they were deemed to be not probable of collection. The changes in anticipated insurance recoveries during the most recent two year period, including anticipated insurance recoveries that were unrelated to the 2005 hurricanes, are as follows:
Year Ended December 31, |
||||||
2007 |
2006 |
|||||
(In Thousands) |
||||||
Beginning balance |
$ |
93,456 |
$ |
43,921 |
||
Activity in the period: |
||||||
Storm related expenditures |
14,846 |
108,784 |
||||
Insurance reimbursements |
(34,124 |
) |
(57,729 |
) |
||
Contested insurance recoveries |
(62,899 |
) |
(1,520 |
) |
||
Ending balance at December 31 |
$ |
11,279 |
$ |
93,456 |
||
F-14
Anticipated insurance recoveries that have been reflected as a reduction of our decommissioning liabilities were $0 at December 31, 2007 and $31.6 million at December 31, 2006. The coverage of certain well intervention and debris removal costs incurred and to be incurred on three destroyed Maritech offshore platforms has been questioned by our insurance underwriters. We are pursuing the recovery of these questioned costs, however, during 2007, we reversed the anticipated insurance recoveries related to these items as the timing and amount of these recoveries has become indeterminable and their collection was no longer considered probable. This resulted in a charge to earnings of approximately $60.1 million during the year. A significant portion of this amount was capitalized to oil and gas properties and resulted in increased oil and gas property impairments. See further discussion in Impairment of Long-Lived Assets section, above. In addition, we estimate that future repair efforts related to damaged or destroyed platforms, including other storm related costs, could result in up to approximately $20 million of additional costs.
Uninsured assets that were destroyed during the storms are charged to earnings. Repair costs incurred up to the amount of deductibles are charged to earnings as they are incurred. Repair costs incurred, and the net book value of any destroyed assets which are covered under our insurance policies, are anticipated insurance recoveries which are included in accounts receivable. Repair costs not considered probable of collection are charged to earnings. Insurance recoveries in excess of destroyed asset carrying values and repair costs incurred are credited to earnings when received. During 2007, 2006, and 2005, approximately $3.2 million, $10.6 million, and $1.3 million, respectively, of such excess proceeds were credited to earnings. Intercompany profit on repair work performed by the Company’s WA&D Services segment is not recognized until such time as insurance claim proceeds are received. For further discussion of our contested hurricane damage claims, as well as other non-storm insurance disputes, see Note J – Commitments and Contingencies.
Our Maritech subsidiary also incurred damage to one of its offshore platforms during 2004 as a result of Hurricane Ivan, which was further damaged in 2005 by Hurricane Katrina. We received a $5.7 million insurance settlement payment for the full insured value for these property claims, less a deductible, resulting in a credit to earnings of $1.9 million during 2007.
Stock Compensation
Effective January 1, 2006, we adopted the fair value recognition provisions of Statement of Financial Accounting Standards (SFAS) No. 123(R), “Share-Based Payment” (SFAS No. 123R) using the modified prospective transition method. The adoption of SFAS No. 123R resulted in stock compensation expense related to stock options and restricted stock for the years ended December 31, 2007 and 2006 of $4.4 million and $3.4 million, respectively, which is included in general and administrative expense. Prior to the adoption of SFAS No. 123R, and for the year ended December 31, 2005, we accounted for stock-based compensation using the intrinsic value method, whereby compensation cost for stock options was measured as the excess, if any, of the quoted market price of our stock at the date of the grant over the amount an employee must pay to acquire the stock. For further discussion of our stock option plans, and for pro forma stock compensation expense for the year ended December 31, 2005, see Note L – Equity Based Compensation.
Research and Development
We expense the costs of research and development as they are incurred. Research and development expense for each of the years ended December 31, 2007, 2006, and 2005 was $1.6 million, $1.5 million, and $1.3 million, respectively.
Income Taxes
We account for income taxes in accordance with SFAS No. 109, “Accounting for Income Taxes” (SFAS No. 109). Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis amounts. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences
F-15
are expected to be recovered or settled. The effect of a change in tax rates is recognized as income or expense in the period that includes the enactment date. Effective January 1, 2007, we adopted the provisions of Financial Accounting Standards Board (FASB) Interpretation No. 48, “Accounting for Uncertainty in Income Taxes” (FIN No. 48). FIN No. 48 provides guidance on measurement and recognition in accounting for income tax uncertainties and provides related guidance on derecognition, classification, disclosure, interest, and penalties. SFAS No, 109 and FIN No. 48 require us to make certain estimates about our future operations and uncertain tax positions. Changes in state, federal, and foreign tax laws, as well as changes in our financial condition, could affect these estimates. For a further discussion of our income tax provisions, as well as our deferred tax assets and liabilities, see Note F – Income Taxes.
Income per Common Share
The calculation of basic earnings per share excludes any dilutive effects of options. The calculation of diluted earnings per share includes the dilutive effect of stock options, which is computed using the treasury stock method during the periods such options were outstanding. A reconciliation of the common shares used in the computations of income per common and common equivalent shares is presented in Note P – Income Per Share.
Foreign Currency Translation
We have designated the Euro, the British Pound, the Norwegian Krone, the Canadian dollar, and the Brazilian Real as the functional currency for our 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 our other foreign operations. The cumulative translation effects of translating the accounts from the functional currencies into the U.S. dollar at current exchange rates are included as a separate component of stockholders' equity.
New Accounting Pronouncements
In December 2007, the FASB published Statement of Financial Accounting Standard (SFAS) No. 141R, “Business Combinations,” which established principles and requirements for how an acquirer of a business (1) recognizes and measures, in its financial statements, the identifiable assets acquired, the liabilities assumed, and any noncontrolling interest in the acquiree; (2) recognizes and measures the goodwill acquired in the business combination or a gain from a bargain purchase; and (3) determines what information to disclose to enable users of the financial statements to evaluate the nature and financial effects of the business combination. SFAS No. 141R changes many aspects of the accounting for business combinations and is expected to significantly impact how we account for and disclose future acquisition transactions. SFAS No. 141R applies prospectively to business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008.
In December 2007, the FASB published SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements – an amendment of ARB No. 51,” which establishes accounting and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. It clarifies that a noncontrolling interest in a subsidiary is an ownership interest in the consolidated entity that should be reported as equity in the consolidated financial statements. SFAS No. 160 is effective for fiscal years, and interim periods within those fiscal years, beginning on or after December 15, 2008. We are currently evaluating the impact, if any, the adoption of SFAS No. 160 will have on our financial position and results of operations.
In February 2007, the FASB published SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities,” which permits entities to choose to make an irrevocable election at specific election dates to measure most financial assets and financial liabilities at fair value. The fair value option may be elected on an instrument-by-instrument basis, with a few exceptions, as long as it is applied to the instrument in its entirety. Changes in fair value would be recorded to earnings. SFAS No. 159 applies to fiscal years beginning after November 15, 2007, with early adoption permitted for an entity that has also elected to apply the provisions of SFAS No. 157. Currently, we have elected not to adopt the fair value option provision allowed under SFAS No. 159.
F-16
In September 2006, the FASB published SFAS No. 157, “Fair Value Measurements,” which defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles, and expands disclosures about fair value measurements. SFAS No. 157 applies under other accounting pronouncements that require or permit fair value measurements. SFAS No. 157 establishes a fair value hierarchy and requires disclosure of fair value measurements within that hierarchy. SFAS No. 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. The adoption of SFAS No. 157 is not expected to have a material impact on our financial statements, but will result in additional disclosures related to the use of fair values in the financial statements.
NOTE C — DISCONTINUED OPERATIONS
During the fourth quarter of 2007, we disposed of our process services operations through a sale of the associated assets and operations for total cash proceeds of approximately $58.9 million. Our process services operation provided the technology and services required for the separation and recycling of oily residuals generated from petroleum refining operations. Our process services operation was not considered to be a strategic part of our core business. As a result, we reflected a gain on the sale of our process services business of approximately $25.8 million, net of tax, for the difference between the sales proceeds and the net carrying value of the disposed net assets. The calculation of this gain included $2.7 million of goodwill related to the process services operation. Our process services operation was previously included as a component of our Production Enhancement Division.
During the fourth quarter of 2006, we made the decision to dispose of our fluids and production testing operations in Venezuela, due to several factors, including the country’s changing political climate. Our Venezuelan fluids operation was previously part of our Fluids Division and the production testing operation was previously part of our Production Enhancement Division. A significant majority of the Venezuelan property assets have been sold or transferred to other market locations, and the remaining closure efforts are expected to be finalized during 2008.
We have accounted for our process services business, our Venezuelan fluids and production testing businesses, and our other discontinued businesses as discontinued operations, and have reclassified prior period financial statements to exclude these businesses from continuing operations. A summary of financial information related to our discontinued operations for each of the past three years is as follows:
Year Ended December 31, |
|||||||||
|
2007 |
2006 |
2005 |
|||||||
| (In
Thousands) |
|||||||||
| Revenues |
|||||||||
| Process services operations |
$ |
16,145 |
$ |
17,073 |
$ |
16,087 |
|||
| Venezuelan fluids and production testing operations |
608 |
3,570 |
5,684 |
||||||
|
|
$ |
16,753 |
$ |
20,643 |
$ |
21,771 |
|||
| Income (loss), net of taxes |
|||||||||
| Process services operations, net of taxes of $1,182, $1,719, and $1,543, respectively |
$ |
1,939 |
$ |
2,810 |
$ |
2,487 |
|||
| Venezuelan fluids and production testing operations, net of taxes of $90, $231, and $107, respectively |
(137 |
) |
(915 |
) |
1,041 |
||||
| Other discontinued operations |
(79 |
) |
103 |
(268 |
) |
||||
|
|
$ |
1,723 |
|
$ |
1,998 |
|
$ |
3,260 |
|
| Gain from disposal |
|||||||||
| Process services operation, net of taxes of $14,906 |
$ |
25,827 |
$ |
– |
$ |
– |
|||
|
|
|||||||||
| Total income (loss) from discontinued operations, net of tax |
|||||||||
| Process Services |
$ |
27,766 |
$ |
2,810 |
$ |
2,487 |
|||
| Venezuelan fluids and production testing operations |
(137 |
) |
(915 |
) |
1,041 |
|
|||
| Other discontinued operations |
(79 |
) |
103 |
(268 |
) |
||||
|
|
$ |
27,550 |
$ |
1,998 |
$ |
3,260 |
|||
F-17
Assets and liabilities of discontinued operations consist of the following as of December 31, 2007 and 2006:
December 31, |
||||||
2007 |
2006 |
|||||
(In Thousands) |
||||||
Current assets |
|
|||||
Process services |
$ |
705 |
$ |
3,558 |
||
Venezuelan fluids and testing |
3,146 |
2,503 |
||||
|
3,851 |
6,061 |
||||
Property, plant and equipment, net |
||||||
Process services |
– |
13,548 |
||||
Venezuelan fluids and testing |
48 |
1,583 |
||||
|
48 |
15,131 |
||||
Other long-term assets |
||||||
Process services |
– |
2,687 |
||||
Venezuelan fluids and testing |
143 |
– |
||||
|
143 |
2,687 |
||||
Total assets |
||||||
Process services |
705 |
19,793 |
||||
Venezuelan fluids and testing |
3,337 |
4,086 |
||||
|
$ |
4,042 |
$ |
23,879 |
||
Current liabilities |
||||||
Process services |
$ |
223 |
$ |
419 |
||
Venezuelan fluids and testing |
201 |
464 |
||||
Total liabilities |
$ |
424 |
$ |
883 |
||
NOTE D — ACQUISITIONS AND DISPOSITIONS
In April 2007, we acquired certain assets and the operations of a company that provides fluids transfer and related services in support of high pressure fracturing processes. The acquisition expands our Fluids Division’s existing fluids transfer and related services business by providing such services to customers in the Arkansas, TexOma, and ArkLaTex regions. As consideration for the acquired assets, we paid approximately $8.5 million of cash at closing, with up to an additional $2.5 million to be paid over the next two years, depending on the level of revenues generated by the acquired assets. We allocated the purchase price of this acquisition to the fair value of the assets and liabilities acquired, which consisted of approximately $0.2 million of inventory, $5.5 million of property, plant and equipment; $1.4 million of certain intangible assets; and $1.3 million of goodwill. Intangible assets, other than goodwill, are amortized over their useful lives, ranging from five to six years.
In September 2007, we acquired the assets and operations of EOT Rentals, LLC (EOT), a business which provides onshore and offshore cutting services and equipment rentals and services in the U.S. Gulf Coast region. The acquisition of EOT is a strategic expansion of our WA&D Services segment which, in the past, has contracted cutting services from third parties, including EOT, in order to provide such services to its customers. As consideration for the acquired assets, we paid approximately $6.1 million of cash at closing, subject to adjustment, with an additional $1.0 million to be paid at prescribed dates over the next two years. We allocated the purchase price of this acquisition to the preliminary estimate of fair value of the assets and liabilities acquired, which consisted of approximately $0.7 million of net working capital, approximately $2.8 million of property, plant and equipment; $0.9 million of certain intangible assets; and $2.5 million of goodwill. Adjustments to be made to this preliminary allocation of fair value are not expected to be material. Intangible assets, other than goodwill, are amortized over their useful lives, ranging from five to six years.
F-18
During 2007, our Maritech subsidiary entered into seven separate transactions in which it sold interests in certain oil and gas properties and assets. As a result of these transactions, the buyers of these properties assumed an aggregate of approximately $4.0 million of Maritech’s associated decommissioning liabilities. Maritech paid total net cash of approximately $0.5 million in these transactions, and recognized gains totaling approximately $2.4 million. The amount of oil and gas reserve volumes associated with the sold properties was immaterial.
In December 2007, our Maritech subsidiary acquired interests in oil and gas properties located in the offshore Gulf of Mexico from a subsidiary of Cimarex Energy Company (which we refer to as the Cimarex Properties) in exchange for cash of $56.2 million, subject to adjustment, and the assumption of the associated decommissioning liabilities with a fair value of approximately $24.8 million. Also in December 2007, an additional interest in one of the Cimarex Properties was separately acquired from an unrelated third party in exchange for cash of $2.0 million. The acquired properties include numerous development prospects, and strategic opportunities involving a portion of Maritech’s existing infrastructure assets, and other assets to be constructed by Maritech. The acquired oil and gas properties were recorded at a cost of approximately $83.0 million. Our allocation of this purchase price between the acquired proved properties, unproved properties, and infrastructure assets is preliminary, and will be adjusted as certain information related to the fair values of the assets acquired is collected and reviewed.
In January 2008, our Maritech subsidiary acquired oil and gas producing properties located in the offshore Gulf of Mexico from Stone Energy Corporation, in exchange for the assumption of the associated decommissioning obligations with an undiscounted value of approximately $25.0 million and cash of $15.8 million, subject to further adjustment, $2.3 million of which was paid in November 2007.
In December 2007, we sold our process services business for cash. For further discussion, see Note C – Discontinued Operations.
The unaudited pro forma information presented below has been prepared to give effect to the April 2007 acquisition of a fluids transfer operation, the September 2007 acquisition of EOT, the December 2007 acquisition of the Cimarex Properties, and the sale of our process services operation, as if all of these transaction had occurred at the beginning of the periods presented. The pro forma impact of Maritech’s sales of certain other oil and gas properties during 2007 was not material. The pro forma information is presented for illustrative purposes only and is based on estimates and assumptions deemed appropriate by us. The following pro forma information is not necessarily indicative of the historical results that would have been achieved if the acquisition and disposal transactions had occurred in the past, and our operating results may have been different from those reflected in the pro forma information below. The pro forma information is not indicative of our expected future results, therefore, the pro forma information should not be relied upon as an indication of the operating results that we would have achieved if the transactions had occurred at the beginning of the periods presented or the future results that we will achieve after the transactions.
Pro Forma Financial Information (unaudited) |
2007 |
2006 |
||||
(In Thousands, Except Per Share Amounts) |
||||||
Revenues |
$ |
998,362 |
$ |
802,729 |
||
Income before discontinued operations |
$ |
3,989 |
$ |
97,264 |
||
Net income |
$ |
31,539 |
$ |
99,262 |
||
|
||||||
Per share information: |
||||||
Income before discontinued operations |
||||||
Basic |
$ |
0.05 |
$ |
1.36 |
||
Diluted |
$ |
0.05 |
$ |
1.30 |
||
|
||||||
Net income |
||||||
Basic |
$ |
0.43 |
$ |
1.39 |
||
Diluted |
$ |
0.42 |
$ |
1.33 |
||
F-19
In February 2006, our WA&D Services segment purchased a heavy lift derrick barge with a 615-ton capacity crane, the DB-1, from Offshore Specialty Fabricators, Inc. for $20 million. Subsequently, we made a number of modifications to the vessel, which began operating in the Gulf of Mexico in July 2006. The purchase further expanded our WA&D Services segment’s decommissioning operations in the Gulf of Mexico.
In March 2006, our WA&D Services segment acquired the assets and operations of Epic Divers, Inc. and certain associated affiliated companies (Epic), a full service commercial diving operation that included six marine vessels and two saturation diving units. Pursuant to the asset purchase agreement (the Epic Asset Purchase Agreement), we acquired Epic for consideration consisting of approximately $47.7 million of cash paid at closing. In addition, the Epic Asset Purchase Agreement provided for us to pay an additional $0.5 million, which was paid in June 2006, as well as a working capital adjustment of approximately $2.6 million, which was paid in September 2006. In addition, we accrued approximately $0.8 million of additional purchase price adjustments, which we paid to the seller during 2007. On June 7, 2006, we purchased a dynamically positioned dive support vessel, including a saturation diving unit, for an initial purchase price of approximately $6.5 million. Pursuant to the Epic Asset Purchase Agreement, a portion of the net profits earned by this dive support vessel and saturation diving unit over the initial three year term following its purchase is to be paid to the sellers. In addition, approximately $1.6 million, subject to adjustment, of additional purchase consideration is to be paid to the sellers at the end of this three year term. The acquisition of Epic, which provides diving services primarily to customers in the Gulf of Mexico, is a strategic expansion of our WA&D Services segment, which, in the past, contracted diving services from third parties, including Epic, in order to provide its well abandonment and decommissioning services to its customers. While Epic continues to provide diving services to many of its customers, including Maritech, the acquisition helps the WA&D Services segment ensure the availability of these critical services to a substantial portion of its customers. We allocated the purchase price of the Epic acquisition to the fair value of the assets and liabilities acquired, which consisted of approximately $13.8 million of net working capital; $17.6 million of property, plant and equipment; $8.9 million of certain intangible assets; and $12.6 million of goodwill. Intangible assets other than goodwill are amortized over their useful lives, ranging from three to eight years.
In March 2006, we acquired Beacon Resources, LLC (Beacon), a production testing operation, as part of our Production Enhancement Division. The acquisition of Beacon expanded the Division’s production testing services operation into the west Texas and eastern New Mexico markets. We acquired Beacon for approximately $15.6 million paid at closing, with an additional $0.5 million to be paid, subject to adjustment, over a three year period ending in March 2009. In addition, the acquisition provides for additional contingent consideration of up to $19.1 million, to be paid in March 2009, depending on Beacon’s average pretax results of operations for each of the three years following the closing date. Through December 31, 2007, we have estimated the amount of Beacon’s pretax results of operations (as defined in the agreement) to date since the acquisition and have determined that this amount is less than the amount required to generate a payment pursuant to this contingent consideration provision. Any amount payable pursuant to this contingent consideration provision will be reflected as a liability as it becomes fixed and determinable at the end of the three year period. We allocated the purchase price of the Beacon acquisition to the fair value of the assets and liabilities acquired, which consisted of approximately $1.5 million of net working capital; $5.3 million of property, plant and equipment; $4.2 million of certain intangible assets; $0.4 million of other liabilities; and $5.5 million of goodwill. Intangible assets other than goodwill are amortized over their useful lives ranging from five to eight years.
In March 2006, Maritech exercised a contractual right to acquire certain overriding royalty interests related to one of its oil and gas properties in exchange for $5.0 million in cash and a $5.0 million reduction in the amount to be paid to Maritech by the seller upon performance of certain future well abandonment and decommissioning work. Maritech had previously entered into a development agreement with a third party covering the development of this oil and gas property, and, pursuant to this agreement, received $5.0 million cash during March 2006. In March, June, and November 2006, Maritech sold certain oil and gas property assets in four separate transactions in exchange for the buyer’s assumption of the associated decommissioning liabilities, resulting in combined gains totaling approximately $5.1 million.
F-20
In September 2006, we acquired the assets and operations of Arrowhead Oil Field Services, Inc. (Arrowhead), an onshore water transfer company specializing in the transfer of high volumes of water in support of high pressure fracturing processes, as an expansion of our Fluids Division. The acquisition of Arrowhead allows our Fluids Division to expand its capacity for such services to customers in the Texas, Oklahoma, Arkansas, New Mexico, and Louisiana markets. We acquired Arrowhead for approximately $6.5 million of cash paid at closing. We allocated the purchase price of the Arrowhead acquisition to the fair value of the assets acquired, which consisted of approximately $2.3 million of property, plant and equipment; $3.3 million of certain intangible assets; and $0.9 million of goodwill. Intangible assets other than goodwill are amortized over their useful lives, ranging from three to eight years.
In July 2005, our Maritech subsidiary 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 included 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, our Maritech subsidiary 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 received 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.
During 2005, our Maritech subsidiary 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 of 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.
F-21
In May 2005, our Fluids Division sold certain international assets for approximately $1.0 million cash. In July 2005, our WA&D Division sold certain well abandonment equipment located in west Texas for approximately $2.1 million cash. In connection with these transactions, we recorded gains totaling approximately $1.0 million during 2005.
All of our acquisitions have been accounted for, or will be accounted for in the future, as purchases, with operations of the companies and businesses acquired included in the accompanying consolidated financial statements from their respective dates of acquisition. The purchase price has been allocated to the acquired assets and liabilities based on a determination of their respective fair values. The excess of the purchase price over the fair value of the net assets acquired is included in goodwill and assessed for impairment whenever indicators are present. We have not recorded any goodwill in conjunction with our oil and gas property acquisitions.
NOTE E — LEASES
We lease some of our transportation equipment, office space, warehouse space, operating locations and machinery and equipment. The office, warehouse, and operating location leases, which vary from one to ten year terms that expire at various dates through 2017, and are renewable for three and five year periods on similar terms, are classified as operating leases. Transportation equipment leases expire at various dates through 2012 and are also classified as operating leases. The office, warehouse, and operating location leases and machinery and equipment leases generally require us to pay all maintenance and insurance costs.
As of December 31, 2007, we had no significant capital leases outstanding. Future minimum lease payments by year and in the aggregate, under non-cancelable operating leases with terms of one year or more, consist of the following at December 31, 2007:
|
Operating Leases |
||
|
(In Thousands) |
||
2008 |
$ |
6,715 |
|
2009 |
3,280 |
||
2010 |
2,008 |
||
2011 |
1,415 |
||
2012 |
766 |
||
After 2012 |
137 |
||
Total minimum lease payments |
$ |
14,321 |
|
Rental expense for all operating leases was $12.8 million, $12.0 million, and $6.7 million in 2007, 2006, and 2005, respectively.
Through our Compressco subsidiary, as of December 31, 2007, we leased oil and gas wellhead compression equipment to our customers throughout the mid-continent, mid-western, western, Rocky Mountain, and Gulf Coast regions of the United States as well as in western Canada, Mexico, and other Latin American countries. Total compressor equipment leased or available for lease at December 31, 2007 and 2006 is approximately $88.0 million and $68.8 million, respectively. Rental revenues were less than 10% of consolidated revenues for each of the three years ended December 31, 2007, and are included in services and rentals revenue in the accompanying statements of operations. Future minimum rental payments as of December 31, 2007 are not material, as leasing arrangements are typically on a month to month basis.
F-22
NOTE F — INCOME TAXES
The income tax provision attributable to continuing operations for the years ended December 31, 2007, 2006, and 2005 consists of the following:
Year Ended December 31, |
|||||||||
|
2007 |
|
2006 |
2005 |
||||||
(In Thousands) |
|||||||||
Current |
|||||||||
Federal |
$ |
(2,319 |
) |
$ |
24,133 |
$ |
17,450 |
||
State |
(1,255 |
) |
747 |
|
1,384 |
||||
Foreign |
3,841 |
4,457 |
1,637 |
||||||
|
267 |
29,337 |
20,471 |
||||||
Deferred |
|||||||||
Federal |
1,325 |
|
20,407 |
(4,261 |
) |
||||
State |
1,257 |
|
1,939 |
|
(119 |
) |
|||
Foreign |
(1,908 |
) |
806 |
1,136 |
|||||
|
674 |
|
23,152 |
|
(3,244 |
) |
|||
|
|||||||||
Total tax provision |
$ |
941 |
$ |
52,489 |
$ |
17,227 |
|||
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, 2007, 2006, and 2005 to income before income taxes and the reported income taxes, is as follows:
Year Ended December 31, |
|||||||||
2007 |
2006 |
2005 |
|||||||
(In Thousands) |
|||||||||
| Income tax provision computed at statutory federal income tax rates |
$ |
757 |
$ |
53,330 |
$ |
18,210 |
|||
State income taxes (net of federal benefit) |
(84 |
) |
1,746 |
822 |
|||||
Nondeductible expenses |
1,320 |
1,052 |
538 |
||||||
Impact of international operations |
(1,045 |
) |
(1,145 |
) |
(1,276 |
) |
|||
Excess depletion |
(279 |
) |
(698 |
) |
(550 |
) |
|||
Other |
272 |
(1,796 |
) |
(517 |
) |
||||
Total tax provision |
$ |
941 |
$ |
52,489 |
$ |
17,227 |
|||
Income before taxes and discontinued operations includes the following components:
Year Ended December 31, |
|||||||||
2007 |
2006 |
2005 |
|||||||
(In Thousands) |
|||||||||
Domestic |
$ |
(8,432 |
) |
$ |
134,241 |
$ |
43,514 |
||
International |
10,594 |
18,128 |
8,515 |
||||||
Total |
$ |
2,162 |
$ |
152,369 |
$ |
52,029 |
|||
We file U.S. federal, state, and foreign income tax returns. We believe we have justification for the tax positions utilized in the various tax returns we file. With few exceptions, we are no longer subject to U.S. federal, state, local, or non-U.S. income tax examinations by tax authorities for years prior to 2002.
F-23
We adopted the provisions of FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes” (FIN No. 48), on January 1, 2007. FIN No. 48 provides guidance on measurement and recognition in accounting for income tax uncertainties and provides related guidance on derecognition, classification, disclosure, interest, and penalties. As a result of the implementation of FIN No. 48, we recognized an approximate $0.1 million increase in the liability for unrecognized tax benefits, which was accounted for as a reduction to the January 1, 2007 balance of retained earnings.
A reconciliation of the beginning and ending amount of our gross unrecognized tax benefit liability is as follows:
Year Ended |
|||
December 31, 2007 |
|||
(In Thousands) |
|||
Gross unrecognized tax benefits at beginning of period |
$ |
2,483 |
|
|
|||
Increases in tax positions for prior years |
– |
||
Decreases in tax positions for prior years |
– |
||
Increases in tax positions for current year |
394 |
||
Settlements |
– |
||
Lapse in statute of limitations |
(311 |
) |
|
Gross unrecognized tax benefits at December 31, 2007 |
$ |
2,566 |
|
We recognize interest and penalties related to uncertain tax positions in income tax expense. During the years ended December 31, 2007, 2006, and 2005, we recognized approximately $0.6 million, $0.4 million, and $0.2 million, respectively, in interest and penalties in provision for income tax. As of January 1, 2007 and December 31, 2007, we had approximately $2.2 million and $2.8 million of accrued potential interest and penalties associated with these uncertain tax positions. The total amount of unrecognized tax benefits that would affect our effective tax rate if recognized is $2.6 million as of December 31, 2007 and $2.4 million as of January 1, 2007.
We use the liability method for reporting income taxes, under which current and deferred tax assets and liabilities are recorded in accordance with enacted tax laws and rates. Under this method, at the end of each period, the amounts of deferred tax assets and liabilities are determined using the tax rate expected to be in effect when the taxes are actually paid or recovered. We will establish a valuation allowance, to reduce the deferred tax assets, when it is more likely than not that some portion or all of the deferred tax assets will not be realized. While we have considered future taxable income and ongoing tax planning strategies in assessing the need for the valuation allowance, there can be no guarantee that we will be able to realize all of our deferred tax assets. Significant components of our deferred tax assets and liabilities as of December 31, 2007 and 2006 are as follows:
Deferred Tax Assets: |
|||||||
|
December 31, |
|||||||
|
2007 |
|
2006 |
|||||
| (In Thousands) |
|||||||
Tax inventory over book |
$ |
864 |
$ |
810 |
|||
Allowance for doubtful accounts |
474 |
287 |
|||||
Accruals |
101,163 |
|
58,237 |
||||
Unrealized currency loss on Euro debt |
2,897 |
981 |
|||||
Net operating loss carryforward |
2,274 |
3,272 |
|||||
All other |
12,534 |
|
5,968 |
||||
Total deferred tax assets |
120,206 |
69,555 |
|||||
Valuation allowance |
(2,167 |
) |
(2,079 |
) |
|||
Net deferred tax assets |
$ |
118,039 |
$ |
67,476 |
|||
F-24
Deferred Tax Liabilities: |
|||||||
|
December 31, |
|||||||
|
2007 |
|
2006 |
|||||
| (In Thousands) |
|||||||
Excess book over tax basis in property, plant and equipment |
$ |
125,777 |
$ |
94,085 |
|||
Goodwill amortization |
2,845 |
2,943 |
|||||
All other |
9,433 |
17,253 |
|||||
Total deferred tax liability |
138,055 |
114,281 |
|||||
Net deferred tax liability |
$ |
20,016 |
$ |
46,805 |
|||
The change in the valuation allowance during 2007 relates to an increase of foreign operating loss carryforwards generated and associated translation adjustments partially offset by a reduction due to the utilization of foreign operating loss carryforwards. We believe the ability to generate sufficient taxable income may not allow us to realize the tax benefits of the deferred tax assets generated in 2007 within the allowable carryforward period. Therefore, an appropriate valuation allowance has been provided.
At December 31, 2007, we had approximately $2.3 million of foreign net operating loss carryforwards. In those countries in which NOLs are subject to an expiration period, our loss carryforwards, if not utilized, will expire at various dates from 2012 through 2016. At December 31, 2007, we had approximately $2.2 million of foreign tax credits available to offset future payment of Federal income taxes. The foreign tax credits expire in varying amounts through 2017.
NOTE G — ACCRUED LIABILITIES
Accrued liabilities are detailed as follows:
December 31, |
||||||
2007 |
2006 |
|||||
(In Thousands) |
||||||
Decommissioning liabilities, current portion |
$ |
37,400 |
$ |
33,402 |
||
Derivative liabilities, current portion |
32,516 |
3 |
||||
Compensation and employee benefits |
18,290 |
19,727 |
||||
Oil and gas producing liabilities |
18,054 |
10,590 |
||||
Accrued inventory supply settlement |
9,250 |
– |
||||
Other accrued liabilities |
18,015 |
18,415 |
||||
|
$ |
133,525 |
$ |
82,137 |
||
F-25
NOTE H — LONG-TERM DEBT AND OTHER BORROWINGS
Long-term debt consists of the following:
December 31, |
||||||
2007 |
2006 |
|||||
(In Thousands) |
||||||
Bank revolving line of credit facility |
$ |
171,783 |
$ |
154,242 |
||
5.07% Senior Notes, Series 2004-A |
55,000 |
55,000 |
||||
| 4.79% Senior Notes, Series 2004-B |
41,241 |
36,969 |
||||
5.90% Senior Notes, Series 2006-A |
90,000 |
90,000 |
||||
European credit facility |
– |
– |
||||
Vehicle loans |
– |
337 |
||||
|
358,024 |
336,548 |
||||
Less current portion |
– |
167 |
||||
Total long-term debt |
$ |
358,024 |
$ |
336,381 |
||
Scheduled maturities for the next five years and thereafter are as follows:
Year Ending |
|||
December 31, |
|||
(In Thousands) |
|||
2008 |
$ |
– |
|
2009 |
– |
||
2010 |
– |
||
2011 |
268,024 |
||
2012 |
– |
||
Thereafter |
90,000 |
||
|
$ |
358,024 |
|
Bank Credit Facilities
In September 2004, we entered into a five year $140 million revolving credit facility with a syndication of banks. We used the initial borrowings under this facility to repay all outstanding obligations under our previous credit facility, and terminated the previous credit facility. The $140 million revolving credit facility was unsecured and was guaranteed by certain of our domestic subsidiaries. Borrowings generally bore interest at LIBOR plus 0.75% to 1.75%, depending on a certain financial ratio, and we paid a commitment fee on unused portions of the facility at a rate from 0.20% to 0.375%, also depending on this financial ratio. The credit facility contained customary covenants and other restrictions, including dollar limits on the amount of our capital expenditures, acquisitions, and asset sales.
In January 2006, we amended our revolving credit facility agreement to increase the facility up to $200 million, thus increasing our availability under the facility by $60 million. During the first quarter of 2006, we borrowed approximately $101.4 million under our bank revolving credit facility, primarily to fund certain first quarter 2006 acquisitions.
In June 2006, we entered into a revolving credit facility (the Restated Credit Facility), which amended and restated our existing credit facility to, among other things, extend the maturity date of the five year $200 million facility from September 7, 2009 to June 27, 2011 and provide for a future expansion of the facility, with the agreement of existing or additional lenders, to a maximum of $300 million. In December 2006, we amended the revolving credit facility to increase the facility to the maximum $300 million. The facility remains unsecured and is guaranteed by our material domestic subsidiaries. Borrowings under the Restated Credit Facility bear interest at the British Bankers Association LIBOR rate
F-26
plus 0.50% to 1.25%, depending on one of our financial ratios. We pay a commitment fee on unused portions of the facility at a rate from 0.15% to 0.30%, also depending on this financial ratio. As of December 31, 2007, the average interest rate on the outstanding balance under the credit facility was 5.76%.
The Restated Credit Facility agreement contains customary covenants and other restrictions, including certain financial ratio covenants that were modified from the previous credit facility agreement. In addition, the Restated Credit Facility also eliminates the previous limitations on aggregate asset sales and capital expenditures. Additionally, the Restated Credit Facility includes cross-default provisions relating to any of our other indebtedness that is greater than a defined amount. If any such indebtedness is not paid or is accelerated and such event is not remedied in a timely manner, a default will occur under the Restated Credit Facility. We are in compliance with all covenants and conditions of our credit facility as of December 31, 2007. Defaults under the Restated 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.
During the first quarter of 2007, we entered into a bank line of credit facility covering the day to day working capital needs of certain of our European operations (the European Credit Facility). The European Credit Facility provides available borrowing capacity of up to 5 million Euros (approximately $7.4 million equivalent as of December 31, 2007), with interest computed on any outstanding borrowings at a rate equal to the lender’s Basis Rate plus 0.75%. The European Credit Facility agreement is cancellable by either party with 14 business days notice, and contains standard provisions in the event of default. As of December 31, 2007, we had no borrowings pursuant to the European Credit Facility.
Senior Notes
In September 2004, we issued, and sold through a private placement, $55.0 million in aggregate principal amount of Series 2004-A Senior Notes and 28 million Euros (approximately $41.2 million equivalent at December 31, 2007) in aggregate principal amount of Series 2004-B Senior Notes pursuant to a Master Note Purchase Agreement. The Series 2004-A Senior Notes and 2004-B Senior Notes were sold in the United States to accredited investors pursuant to an exemption from the Securities Act of 1933. Net proceeds from the sale of the Senior Notes were used to pay down a portion of existing indebtedness under the new revolving credit facility and to fund the acquisition of our European calcium chloride assets.
In April 2006, we issued, and sold through a private placement, $90.0 million in aggregate principal amount of Series 2006-A Senior Notes pursuant to its existing Master Note Purchase Agreement dated September 2004, as supplemented as of April 18, 2006. The Series 2006-A Senior Notes were sold in the United States to accredited investors pursuant to an exemption from the Securities Act of 1933. Net proceeds from the sale of the Series 2006-A Senior Notes were used to pay down a portion of the existing indebtedness under the bank revolving credit facility.
The Series 2004-A Senior Notes bear interest at the fixed rate of 5.07% and mature on September 30, 2011. The Series 2004-B Senior Notes bear interest at the fixed rate of 4.79% and mature on September 30, 2011. Interest on the 2004-A Senior Notes and the 2004-B Senior Notes is due semiannually on March 30 and September 30 of each year. The Series 2006-A Senior Notes bear interest at the fixed rate of 5.90% and mature on April 30, 2016. Interest on the 2006-A Senior Notes is due semiannually on April 30 and October 30 of each year. We may prepay the Senior Notes, in whole or in part, at any time at a price equal to 100% of the principal amount outstanding, plus accrued and unpaid interest and a “make-whole” prepayment premium. The Senior Notes are unsecured and are guaranteed by substantially all of our wholly owned domestic subsidiaries. The Master Note Purchase Agreement, as supplemented, contains customary covenants and restrictions, requires us to maintain certain financial ratios, and contains customary default provisions, as well as a cross-default provision relating to any other of our indebtedness of $20 million or more. We are in compliance with all covenants and conditions of the Master Note Purchase Agreement as of December 31, 2007. Upon the occurrence and during the continuation of an event of default under the Master Note Purchase Agreement, as supplemented, the Senior Notes may become immediately due and payable, either automatically or by declaration of holders of more than 50% in principal amount of the Senior Notes outstanding at the time.
F-27
NOTE I — DECOMMISSIONING AND OTHER ASSET RETIREMENT OBLIGATIONS
We account for asset retirement obligations in accordance with SFAS No. 143, “Accounting for Asset Retirement Obligations.” The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. The large majority of these asset retirement costs consists of the future well abandonment and decommissioning costs for offshore oil and gas properties and platforms owned by our Maritech subsidiary. The amount of decommissioning liabilities recorded by Maritech is reduced by amounts allocable to joint interest owners, anticipated insurance recoveries, and any contractual amount to be paid by the previous owner of the oil and gas property when the liabilities are satisfied. We also operate facilities in various U.S. and foreign locations in the manufacture, storage, and sale of our products, inventories, and equipment, including offshore oil and gas production facilities and equipment. These facilities are a combination of owned and leased assets. We are required to take certain actions in connection with the retirement of these assets. We have reviewed our obligations in this regard in detail and estimated the cost of these actions. These estimates are the fair values that have been recorded for retiring these long-lived assets. These fair value amounts have been capitalized as part of the cost basis of these assets. The costs are depreciated on a straight-line basis over the life of the asset for non-oil and gas assets and on a unit of production basis for oil and gas properties. The market risk premium for a significant majority of the asset retirement obligations is considered small, relative to the related estimated cash flows, and has not been used in the calculation of asset retirement obligations.
The changes in the asset retirement obligations during the most recent two year period are as follows:
Year Ended December 31, |
||||||
2007 |
2006 |
|||||
(In Thousands) |
||||||
Beginning balance for the period, as reported |
$ |
138,340 |
$ |
136,843 |
||
|
||||||
Activity in the period: |
||||||
Accretion of liability |
7,044 |
6,989 |
||||
Retirement obligations incurred |
27,204 |
2,823 |
||||
Revisions in estimated cash flows |
63,364 |
15,853 |
||||
Settlement of retirement obligations |
(36,446 |
) |
(24,168 |
) |
||
|
||||||
Ending balance at December 31 |
$ |
199,506 |
$ |
138,340 |
||
NOTE J — COMMITMENTS AND CONTINGENCIES
Litigation – We are named defendants in several lawsuits and respondents in certain governmental proceedings arising in the ordinary course of business. While the outcome of lawsuits or other proceedings against us cannot be predicted with certainty, management does not expect these matters to have a material adverse impact on the financial statements.
As previously disclosed, our Maritech subsidiary incurred significant damage as a result of hurricanes Katrina and Rita. Although portions of the well intervention costs previously expended on these facilities and submitted to our insurers have been reimbursed, our insurance underwriters have continued to maintain that well intervention costs for certain of the damaged wells do not qualify as covered costs and that certain well intervention costs for qualifying wells are not covered under the policies. In addition, the underwriters have also maintained that there is no additional coverage provided under an endorsement we obtained in August 2005 for the cost of removal of these platforms and for other damage repairs on certain properties in excess of the insured values provided by our property damage policy. On November 16, 2007, we filed a lawsuit in the 359th Judicial District Court, Montgomery County, Texas, entitled Maritech Resources, Inc. v. Certain Underwriters and Insurance Companies at Lloyd’s, London subscribing to Policy no. GA011150U and Steege Kingston, in which we are seeking damages for breach of contract and various related claims and a declaration of the extent of coverage of
F-28
an endorsement to the policy. We cannot predict the outcome of this lawsuit; however, the ultimate resolution could have a significant impact upon our future operating cash flow.
Environmental - One of our subsidiaries, TETRA Micronutrients, Inc. (TMI), previously owned and operated a production facility located in Fairbury, Nebraska. TMI is subject to an Administrative Order on Consent issued to American Microtrace, Inc. (n/k/a/ TETRA Micronutrients, Inc.) in the proceeding styled In the Matter of American Microtrace Corporation, EPA I.D. No. NED00610550, Respondent, Docket No. VII-98-H-0016, dated September 25, 1998 (the Consent Order), with regard to the Fairbury facility. TMI is liable for future remediation costs at the Fairbury facility under the Consent Order; however, the current owner of the Fairbury facility is responsible for costs associated with the closure of that facility. We have reviewed estimated remediation costs prepared by our independent, third-party environmental engineering consultant, based on a detailed environmental study. Based upon our review and discussions with our third-party consultants, we established a reserve for such remediation costs. As of December 31, 2007, and following the performance of certain remediation activities at the site, the amount of the reserve for these remediation costs, included in current liabilities, is approximately $0.5 million. The reserve will be further adjusted as information develops or conditions change.
We have not been named a potentially responsible party by the EPA or any state environmental agency.
Product Purchase Obligations - In the normal course of our Fluids Division operations, we enter into supply agreements with certain manufacturers of various raw materials and finished products. Some of these agreements have terms and conditions that specify a minimum or maximum level of purchases over the term of the agreement. Other agreements require us to purchase the entire output of the raw material or finished product produced by the manufacturer. Our purchase obligations under these agreements apply only with regard to raw materials and finished products that meet specifications set forth in the agreements. We recognize a liability for the purchase of such products at the time we receive them. During 2006, we significantly increased our purchase obligations as a result of the execution of a long-term supply agreement with Chemtura Corporation, and the amendment of a previous supply agreement. Under the amended agreement with the previous supplier, we remained committed to purchase certain volumes of product through 2008. In December 2007, we were released from these further purchase obligations pursuant to an agreement terminating the amended agreement in exchange for our agreement to pay $9.3 million, which was charged to earnings during 2007 and which will be paid in five installments during 2008 and early 2009. As of December 31, 2007, the aggregate amount of the fixed and determinable portion of the purchase obligation pursuant to our Fluids Division’s supply agreements, including the 2008 buyout installments, was approximately $247.3 million, including $19.4 million during 2008, $13.6 million during 2009, $11.9 million during 2010, $11.9 million during 2011, $11.9 million during 2012, and $178.6 million thereafter, extending through 2029. Amounts purchased under these agreements for each of the years ended December 31, 2007, 2006, and 2005 was $16.7 million, $1.0 million, and $2.0 million, respectively.
Insurance Contingencies - Through December 31, 2007, we have expended approximately $47.8 million of well intervention work on certain wells associated with two of the three Maritech offshore platforms which were destroyed as a result of Hurricanes Katrina and Rita in 2005. We estimate that future repair and well intervention efforts related to these destroyed platforms, including platform debris removal and other storm related costs, will result in approximately $50 to $70 million of additional costs. Approximately $28.6 million of the well intervention costs previously expended and submitted to insurance have been reimbursed; however, our insurance underwriters have continued to maintain that well intervention costs for certain of the damaged wells do not qualify as covered costs and that certain well intervention costs for qualifying wells are not covered under the policy. In addition, the underwriters have also maintained that there is no additional coverage provided under an endorsement we obtained in August 2005 for the cost of removal of these platforms or for other damage repairs on certain properties in excess of the insured values provided by our property damage policy. After continuing to provide requested information to the underwriters regarding the damaged wells, and having numerous discussions with the underwriters, brokers, and insurance adjusters, we have yet to receive the requested reimbursement for these contested costs. In late 2007, we filed a lawsuit against the underwriters in an attempt to collect the reimbursement of these well intervention costs incurred as well as future well intervention and debris removal costs to be incurred. We continue to believe that these costs are covered
F-29
costs pursuant to the policy. However, during the fourth quarter of 2007, we reversed the anticipated insurance recoveries previously included in estimating Maritech’s decommissioning liability, increasing the decommissioning liability to $48.4 million for well intervention and debris removal work to be performed, assuming no insurance reimbursements will be received. In addition, we have reversed a portion of our anticipated insurance recoveries previously included in accounts receivable related to certain damage repair costs incurred, as the amount and timing of further reimbursements from our insurance providers are now indeterminable. As a result of the increase to the decommissioning liability, certain capitalized property costs were not realizable, resulting in impairments in accordance with the successful efforts method of accounting. See Note B – Summary of Significant Accounting Policies, Oil and Gas Properties, for further discussion.
If we successfully collect our reimbursement from our insurance providers, such reimbursements will be credited to operations in the period collected. In the event that our actual well intervention costs are more or less than the associated decommissioning liabilities, as adjusted, the difference may be reported in income in the period in which the work is performed.
In October 2005, one of our drilling rig barges was damaged by a fire, and a claim was submitted pursuant to our insurance coverage. The drilling rig barge was repaired during 2006 for a cost of approximately $8.4 million. In January 2007, we collected approximately $2.1 million of insurance reimbursements as a result of our claim for the repair costs incurred. In February 2007, we received a notice from our insurance underwriters, stating that they consider that approximately $3.7 million of this claim is not covered under the applicable policy. We have reviewed the underwriters’ position with regard to this claim, and believe it is without merit. In August 2007, the underwriters responded to our position with regard to this claim, requested additional information on a portion of the remaining costs incurred, and agreed to continue discussions. In September 2007, we met with underwriters to discuss the claim and delivered the additional requested information, and we are currently awaiting any further questions. As of December 31, 2007, approximately $4.3 million is included in our accounts receivable associated with the repair costs incurred for this asset, as such costs are considered probable of being reimbursed pursuant to our applicable insurance policy. This amount is net of the approximately $2.1 million of insurance reimbursements received, and approximately $2.0 million of costs that were charged to expense during 2007. We continue to work with the underwriters to pursue reimbursement of our repair costs.
NOTE K — CAPITAL STOCK
Our Restated Certificate of Incorporation authorizes us to issue 100,000,000 shares of common stock, par value $.01 per share, and 5,000,000 shares of preferred stock, par value $.01 per share. As of December 31, 2007, we had 74,370,765 shares of common stock outstanding, with 1,550,962 shares held in treasury, and no shares of preferred stock outstanding. The voting, dividend, and liquidation rights of the holders of common stock are subject to the rights of the holders of preferred stock. The holders of common stock are entitled to one vote for each share held. There is no cumulative voting. Dividends may be declared and paid on common stock as determined by our Board of Directors, subject to any preferential dividend rights of any then outstanding preferred stock.
Our Board of Directors is empowered, without approval of the stockholders, to cause shares of preferred stock to be issued in one or more series and to establish the number of shares to be included in each such series and the rights, powers, preferences and limitations of each series. Because the Board of Directors has the power to establish the preferences and rights of each series, it may afford the holders of any series of preferred stock preferences, powers and rights, voting or otherwise, senior to the rights of holders of common stock. The issuance of the preferred stock could have the effect of delaying or preventing a change in control of the Company.
Upon our dissolution or liquidation, whether voluntary or involuntary, holders of our common stock will be entitled to receive all of our assets available for distribution to our stockholders, subject to any preferential rights of any then outstanding preferred stock.
F-30
In January 2004, our Board of Directors authorized the repurchase of up to $20.0 million of our common stock. During 2006 and 2007, we made no purchases of our common stock pursuant to this authorization. During 2005, we purchased 261,900 shares of our common stock for aggregate consideration of approximately $2.4 million pursuant to this authorization.
During the past three years, we have declared a 2-for-1 stock split and a 3-for-2 stock split, which were each effected in the form of stock dividends, whereby stockholders of record received additional shares of our common stock, with any fractional shares paid in cash based on the closing price per share of the common stock as of the record date. In May 2006, we declared a 2-for-1 stock split to all stockholders of record as of May 16, 2006, resulting in the May 22, 2006 issuance of 36,740,501 additional shares outstanding. In August 2005, we declared a 3-for-2 stock split to all stockholders of record as of August 19, 2005, resulting in the August 26, 2005 issuance of 22,806,032 additional shares outstanding. The consolidated financial statements retroactively reflect the effect of each of the above 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 — EQUITY-BASED COMPENSATION
Adoption of SFAS 123(R)
Effective January 1, 2006, we adopted the fair value recognition provisions of SFAS No. 123(R), “Share-Based Payment” (SFAS No. 123R) using the modified prospective transition method. In addition, the SEC issued Staff Accounting Bulletin No. 107, “Share-Based Payment” (SAB No. 107) in March, 2005, which provides supplemental SFAS No. 123R application guidance based on the views of the SEC. Under the modified prospective transition method, compensation cost recognized during the years ended December 31, 2007 and 2006 includes: (a) compensation cost for all share-based payments granted prior to, but not yet vested as of January 1, 2006, based on the grant date fair value estimated in accordance with the original provisions of SFAS No. 123 (as amended), “Accounting for Share-Based Compensation” (SFAS No. 123), and (b) compensation cost for all share-based payments granted beginning January 1, 2006, based on the grant date fair value estimated in accordance with the provisions of SFAS No. 123R. In accordance with the modified prospective transition method, results for prior periods have not been restated.
The adoption of SFAS No. 123R resulted in stock compensation expense related to stock options and restricted stock for the year ended December 31, 2007 and 2006 of $4.4 million and $3.4 million, respectively, which is included in general and administrative expense. This expense reduced net income by $2.8 million and $2.2 million and reduced basic and diluted earnings per share by $0.04 and $0.03 for the years ended December 31, 2007 and 2006, respectively.
The Black-Scholes option-pricing model was used to estimate the option fair values. The option-pricing model requires a number of assumptions, of which the most significant are: expected stock price volatility, the expected pre-vesting forfeiture rate, and the expected option term (the amount of time from the grant date until the options are exercised or expire). Expected volatility was calculated based upon actual historical stock price movements over the most recent periods ending December 31, 2007 equal to the expected option term. Expected pre-vesting forfeitures were estimated based on actual historical pre-vesting forfeitures over the most recent periods ending December 31, 2007 for the expected option term.
Prior to the adoption of SFAS No. 123R, we presented any tax benefits of deductions resulting from the exercise of stock options within operating cash flows in our consolidated statements of cash flows. SFAS No. 123R requires tax benefits resulting from tax deductions in excess of the compensation cost recognized for those options (excess tax benefits) to be classified and reported as a financing cash inflow upon adoption of SFAS No. 123R.
In November 2005, the FASB issued Staff Position No. FAS 123(R)-3, “Transition Election Related to Accounting for the Tax Effects of Share-Based Payment Awards” (FSP 123R-3). We have elected to adopt the alternative transition method provided in FSP 123R-3 for calculating the tax effects of stock-based compensation under SFAS No. 123 R. The alternative transition method includes simplified methods to establish the beginning balance of the additional paid-in capital pool (APIC Pool) related to
F-31
the tax effects of stock-based compensation, and for determining the subsequent impact on the APIC Pool and consolidated statements of cash flows of the tax effects of stock-based compensation awards that are outstanding upon adoption of SFAS No. 123R.
Pro Forma Stock Compensation Expense for the Period Ended December 31, 2005
Prior to the adoption of SFAS No. 123R, and for the year ended December 31, 2005, we accounted for stock-based compensation using the intrinsic value method, whereby compensation cost for stock options was measured as the excess, if any, of the quoted market price of our stock at the date of the grant over the amount an employee must pay to acquire the stock. If compensation expense had been recognized based on the estimated fair value of each option granted in accordance with the provisions of SFAS No. 123 and been amortized over the options’ vesting periods, net income and earnings per share would have been as follows:
Year Ended |
|||
December 31, 2005 |
|||
(In Thousands, Except Per Share Amounts) |
|||
|
Net income - as reported |
$ |
38,062 |
|
|
Stock-based employee compensation expense in reported net income, net of related tax effects |
– |
||
|
Total stock-based employee compensation expense determined under fair value based method for all awards, net of related tax effects |
(2,608 |
) |
|
|
Net income - pro forma |
$ |
35,454 |
|
|
|
|
||
|
Net income per share - as reported |
$ |
0.55 |
|
|
Net income per share - pro forma |
$ |
0.52 |
|
|
|
|
||
|
Net income per diluted share - as reported |
$ |
0.53 |
|
|
Net income per diluted share - pro forma |
$ |
0.49 |
|
Equity-Based Compensation as of December 31, 2007
We have various stock option plans which provide for the granting of options for the purchase of our common stock and other performance-based awards to our executive officers, key employees, nonexecutive officers, consultants, and directors. Incentive stock options are exercisable for periods up to ten years.
The TETRA Technologies, Inc. 1990 Stock Option Plan (the 1990 Plan) was initially adopted in 1985 and subsequently amended to change the name, the number, and the type of options that could be granted as well as the time period for granting stock options. As of December 31, 2004, no further options may be granted under the 1990 Plan. We granted performance stock options under the 1990 Plan to certain executive officers. These granted options have an exercise price per share of not less than the market value at the date of issuance and are fully vested and exercisable.
In 1993, we adopted the TETRA Technologies, Inc. Director Stock Option Plan (the Directors’ Plan). In 1996, the Directors’ Plan was amended to increase the number of shares issuable under automatic grants thereunder. In 1998, we adopted the TETRA Technologies, Inc. 1998 Director Stock Option Plan as amended (the 1998 Director Plan). The purpose of the Directors’ Plan and the 1998 Director Plan (together the Director Stock Option Plans) is to enable us to attract and retain qualified individuals to serve as our directors and to align their interests more closely with our interests. The 1998 Director Plan is funded with our treasury stock and was amended and restated effective December 18, 2002 to increase the number of shares issuable thereunder, to change the types of options that may be granted thereunder, and to increase the number of shares issuable under automatic grants thereunder. The 1998 Director Plan was amended and restated effective June 27, 2003, and was further amended in
F-32
December 2005 to increase the number of shares issuable thereunder. As of May 2, 2006, no further options may be granted under the Director Stock Option Plans.
During 1996, we adopted the 1996 Stock Option Plan for Nonexecutive Employees and Consultants (the Nonqualified Plan) to enable us to award nonqualified stock options to nonexecutive employees and consultants who are key to our performance. As of May 2, 2006, no further options may be granted under the Nonqualified Plan.
In May 2006, our stockholders approved the adoption of the TETRA Technologies, Inc. 2006 Equity Incentive Compensation Plan. Pursuant to the TETRA Technologies, Inc. 2006 Equity Incentive Compensation Plan, we are authorized to grant up to 1,300,000 shares in the form of stock options (including incentive stock options and nonqualified stock options); restricted stock; bonus stock; stock appreciation rights; and performance awards to employees, consultants, and non-employee directors. As a result of the adoption and approval of the TETRA Technologies, Inc. 2006 Equity Incentive Compensation Plan, no further awards may be granted under our other previously existing plans.
In May 2007, our stockholders approved the adoption of the TETRA Technologies, Inc. 2007 Equity Incentive Compensation Plan. Pursuant to the TETRA Technologies, Inc. 2007 Equity Incentive Compensation Plan, we are authorized to grant up to 90,000 shares in the form of stock options (including incentive stock options and nonqualified stock options); restricted stock; bonus stock; stock appreciation rights; and performance awards to employees, consultants and non-employee directors.
In 2007 and 2006, we granted to certain officers and employees a total of 258,750 and 83,708 restricted shares, respectively, which generally vest 20% per year over a five year period. The average market value (equal to the quoted closing price of the common stock on the dates of grant) of the restricted shares granted during 2007 was $27.66 per share, or an aggregate of approximately $7.2 million, at the date of grant. The average market value of the restricted shares granted during 2006 was $29.47 per share, or an aggregate of approximately $2.5 million, at the date of grant.
The following is a summary of stock option activity for the year ended December 31, 2007:
| |
Weighted Average Option |
||||
|
Shares Under Option |
|
Price Per Share |
|||
|
(In Thousands) |
||||
Outstanding at December 31, 2006 |
6,359 |
$ |
9.25 |
||
|
|||||
Options granted |
132 |
22.76 |
|||
Options cancelled |
(89 |
) |
16.56 |
||
Options exercised |
(2,213 |
) |
5.58 |
||
Outstanding at December 31, 2007 |
4,189 |
$ |
11.45 |
||
The following is a summary of restricted stock activity for the year ended December 31, 2007:
| |
Weighted Average Grant Date |
||||
|
Shares |
|
Fair Value Per Share |
|||
|
(In Thousands) |
||||
Nonvested shares outstanding at December 31, 2006 |
84 |
$ |
29.47 |
||
|
|||||
Shares granted |
259 |
24.21 |
|||
Shares cancelled |
(25 |
) |
27.94 |
||
Shares vested |
(31 |
) |
29.44 |
||
Nonvested shares outstanding at December 31, 2007 |
287 |
$ |
27.98 |
||
F-33
The total intrinsic value, or the difference between the exercise price and the market price on the date of exercise, of all options exercised during the years ended December 31, 2007 and 2006, was approximately $43.2 million and $41.0 million, respectively. Cash received from stock options exercised during the years ended December 31, 2007 and 2006 was $12.1 million and $11.4 million, respectively. Recognized excess tax benefits related to the exercise of stock options during the years ended December 31, 2007 and 2006 were $13.2 million and $12.5 million, respectively.
Stock options authorized for issuance, outstanding and currently exercisable at December 31, 2007, 2006, and 2005 are as follows:
|
2007 |
2006 |
2005 |
|||||||
| (In Thousands, Except Per Share Amounts) |
|||||||||
| TETRA Technologies, Inc. 2007 Equity Incentive Compensation Plan |
|||||||||
| Maximum number of shares authorized for issuance |
90 |
– |
– |
||||||
| Shares reserved for future grants |
63 |
– |
– |
||||||
| Options exercisable at period end |
6 |
– |
– |
||||||
| Weighted average exercise price of options exercisable at period end |
$ |
18.50 |
$ |
– |
$ |
– |
|||
|
|
|||||||||
| TETRA Technologies, Inc. 2006 Equity Incentive Compensation Plan |
|||||||||
| Maximum number of shares authorized for issuance |
1,300 |
1,300 |
– |
||||||
| Shares reserved for future grants |
48 |
589 |
– |
||||||
| Options exercisable at period end |
257 |
– |
– |
||||||
| Weighted average exercise price of options exercisable at period end |
$ |
26.61 |
$ |
– |
$ |
– |
|||
|
|
|||||||||
| 1990 TETRA Technologies, Inc. Employee Plan (as amended) |
|||||||||
| Maximum number of shares authorized for issuance |
17,775 |
17,775 |
17,775 |
||||||
| Shares reserved for future grants |
– |
– |
– |
||||||
| Options exercisable at period end |
1,955 |
3,297 |
4,910 |
||||||
| Weighted average exercise price of options exercisable at period end |
$ |
6.52 |
$ |
6.05 |
$ |
5.62 |
|||
|
|
|||||||||
| Director Stock Option Plans (as amended) |
|||||||||
| Maximum number of shares authorized for issuance |
2,138 |
2,138 |
2,138 |
||||||
| Shares reserved for future grants |
– |
– |
282 |
||||||
| Options exercisable at period end |
342 |
770 |
890 |
||||||
| Weighted average exercise price of options exercisable at period end |
$ |
11.74 |
$ |
8.30 |
$ |
6.30 |
|||
|
|
|||||||||
| All Other Plans |
|||||||||
| Maximum number of shares authorized for issuance |
3,615 |
3,615 |
3,615 |
||||||
| Shares reserved for future grants |
– |
– |
274 |
||||||
| Options exercisable at period end |
936 |
904 |
810 |
||||||
| Weighted average exercise price of options exercisable at period end |
$ |
12.13 |
$ |
8.74 |
$ |
7.48 |
|||
F-34
Options Outstanding |
Options Exercisable |
||||||||||||||
|
Range of Exercise Price |
|
Shares |
|
Weighted Average Remaining Contracted Life |
|
Weighted Average Exercise Price |
|
Shares |
|
Weighted Average Remaining Contracted Life |
|
Weighted Average Exercise Price |
|||
| (In Thousands) |
(In Years) |
|
(In Thousands) |
(In
Years) |
|||||||||||
$1.61 to $4.37 |
910 |
3.6 |
$ |
3.43 |
882 |
3.5 |
$ |
3.40 |
|||||||
$4.37 to $8.11 |
447 |
3.9 |
$ |
5.79 |
428 |
3.8 |
$ |
5.73 |
|||||||
$8.11 to $9.21 |
1,510 |
4.9 |
$ |
9.05 |
1,472 |
4.9 |
$ |
9.05 |
|||||||
$9.21 to $20.85 |
499 |
7.6 |
$ |
13.24 |
399 |
7.6 |
$ |
13.00 |
|||||||
$20.85 to $30.00 |
823 |
8.5 |
$ |
26.61 |
315 |
8.5 |
$ |
26.02 |
|||||||
|
|
4,189 |
|
5.5 |
|
$ |
11.45 |
3,496 |
5.1 |
$ |
9.20 |
|||||
The fair value of each option grant is estimated on the date of grant using the Black-Scholes option pricing model with the following assumptions: expected stock price volatility 31% to 36%, expected life of options 4.4 to 5.4 years, risk-free interest rate 4.3% to 5.0%, and no expected dividend yield. The weighted average fair value of options granted during the years ended December 31, 2007, 2006 and 2005, using the Black-Scholes model, was $7.13, $8.17, and $3.71 per share, respectively. Total estimated unrecognized compensation cost from unvested stock options and restricted stock as of December 31, 2007 was approximately $12.8 million, which is expected to be recognized over a weighted average period of approximately 2.6 years.
Certain options exercised during 2007, 2006, and 2005 were exercised through the surrender of 4,655, 15,559, and 31,416 shares, respectively, of our common stock previously owned by the option holder for a period of at least six months prior to exercise. In addition, we received 27,784 shares of our common stock during 2007 related to the vesting of certain employee restricted stock. Such surrendered shares received by us are included in treasury stock. At December 31, 2007, net of options previously exercised pursuant to our various stock option plans, we have a maximum of 4,586,179 shares of common stock issuable pursuant to stock options previously granted and outstanding and stock options authorized to be granted in the future.
NOTE M — 401(k) PLAN
We have a 401(k) retirement plan (the Plan) that covers substantially all employees and entitles them to contribute up to 70% of their annual compensation, subject to maximum limitations imposed by the Internal Revenue Code. We match 50% of each employee’s contribution up to 6% of annual compensation, subject to certain limitations as outlined in the Plan. In addition, we can make discretionary contributions which are allocable to participants in accordance with the Plan. Total expense related to our 401(k) plan was $2.7 million, $2.0 million, and $1.5 million in 2007, 2006, and 2005, respectively.
NOTE N — DEFERRED COMPENSATION PLAN
We provide our officers, directors and certain key employees with the opportunity to participate in an unfunded, deferred compensation program. There were twenty-six participants in the program at December 31, 2007. Under the program, participants may defer up to 100% of their yearly total cash compensation. The amounts deferred remain our sole property, and we use a portion of the proceeds to purchase life insurance policies on the lives of certain of the participants. The insurance policies, which also remain our sole property, are payable to us upon the death of the insured. We separately contract with the participant to pay to the participant the amount of deferred compensation, as adjusted for gains or losses, invested in participant-selected investment funds. Participants may elect to receive deferrals 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, 2007, the amounts payable under the plan approximated the value of the corresponding assets we owned.
F-35
NOTE O — HEDGE CONTRACTS
We have market risk exposure in the sales prices we receive for our oil and gas production and currency exchange rate risk exposure related to specific transactions denominated in a foreign currency as well as to investments in certain of our international operations. Our financial risk management activities involve, among other measures, the use of derivative financial instruments, such as swap and collar agreements, to hedge the impact of market price risk exposures for a significant portion of our oil and gas production and for certain foreign currency transactions. Under SFAS No. 133, as amended by SFAS Nos. 137 and 138, all derivative instruments are required to be recognized on the balance sheet at their fair value, and criteria must be established to determine the effectiveness of the hedging relationship. Hedging activities may include hedges of fair value exposures, hedges of cash flow exposures, and hedges of a net investment in a foreign operation. A fair value hedge requires that the effective portion of the change in the fair value of a derivative instrument be offset against the change in the fair value of the underlying asset, liability, or firm commitment being hedged through earnings. Hedges of cash flow exposure are undertaken to hedge a forecasted transaction or the variability of cash flows to be received or paid related to a recognized asset or liability. A cash flow hedge requires that the effective portion of the change in the fair value of a derivative instrument be recognized in other comprehensive income, a component of stockholders’ equity, and then be reclassified into earnings in the period or periods during which the hedged transaction affects earnings. Transaction gains and losses attributable to a foreign currency transaction that is designated as, and is effective as, an economic hedge of a net investment in a foreign entity is subject to the same accounting as translation adjustments. As such, the effect of a rate change on a foreign currency hedge is the same as the accounting for the effect of the rate change on the net foreign investment; both are recorded in the cumulative translation account, a component of stockholders’ equity, and are partially or fully offsetting. Any ineffective portion of a derivative instrument’s change in fair value is immediately recognized in earnings.
As required by SFAS No. 133, we formally document all relationships between hedging instruments and hedged items, as well as our risk management objectives, our strategies for undertaking various hedge transactions, and our methods for assessing and testing correlation and hedge ineffectiveness. All hedging instruments are linked to the hedged asset, liability, firm commitment or forecasted transaction. We also assess, both at the inception of the hedge and on an ongoing basis, whether the derivatives that are used in these hedging transactions are highly effective in offsetting changes in cash flows of the hedged items.
The fair value of hedging instruments reflects our best estimate and is based upon exchange or over-the-counter quotations, whenever they are available. Quoted valuations may not be available. Where quotes are not available, we utilize other valuation techniques or models to estimate fair values. These modeling techniques require us to make estimations of future prices, price correlation, and market volatility and liquidity. The actual results may differ from these estimates, and these differences can be positive or negative.
We believe that our swap and collar agreements are “highly effective cash flow hedges,” as defined by SFAS No. 133, in managing the volatility of future cash flows associated with our oil and gas production. The effective portion of the change in the derivative’s fair value (i.e., that portion of the change in the derivative’s fair value that offsets the corresponding change in the cash flows of the hedged transaction) is initially reported as a component of accumulated other comprehensive income (loss) and will be subsequently reclassified into product sales revenues utilizing the specific identification method when the hedged exposure affects earnings (i.e., when hedged oil and gas production volumes are reflected in revenues). Any “ineffective” portion of the change in the derivative’s fair value is recognized in earnings immediately.
During the years ended December 31, 2007, 2006, and 2005, we entered into certain cash flow hedging swap and collar contracts to fix cash flows relating to a portion of our oil and gas production. Each of these contracts qualified for hedge accounting. As of December 31, 2007, twelve swap contracts remain outstanding, with various expiration dates through December 2010. In addition, in January and February 2008, we entered into four additional swap contracts for an additional portion of our 2008 and 2009 gas production. The fair value of the asset for outstanding cash flow hedge natural gas swap contracts at
F-36
December 31, 2007 was $1.3 million, and is included in prepaid expenses and other current assets in the accompanying consolidated balance sheet. We had no natural gas swap contracts outstanding at December 31, 2006. The fair value of the liability for the outstanding cash flow hedge oil swap contract at December 31, 2007 was $53.4 million. Approximately $32.5 million of this liability, representing the portion associated with 2008 production, is included in accrued liabilities in the accompanying consolidated balance sheets. The remaining portion of this liability is included in other long-term liabilities. The fair value of the asset for outstanding cash flow hedge oil swap contracts at December 31, 2006 was $4.6 million, and is included in prepaid expenses and other current assets in the accompanying consolidated balance sheets. The derivative fair value amounts at December 31, 2007 will be reclassified into earnings over the term of the hedge swap contracts. As the hedge contracts were highly effective, the entire gain (loss) of $(32.9) million and $2.9 million from changes in contract fair value, net of taxes, as of December 31, 2007 and 2006, respectively, are included in other comprehensive income (loss) within stockholders’ equity. Approximately $(19.7) million 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, we borrowed 35 million Euros to fund the acquisition of the TCE calcium chloride assets. This debt is designated as a hedge of our net investment in that foreign operation. The hedge is considered to be effective since the debt balance designated as the hedge is less than or equal to the net investment in the foreign operation. At December 31, 2007, the Company had 35 million Euros (approximately $53.0 million equivalent) designated as a hedge of a net investment in a foreign operation. Changes in the foreign currency exchange rate have resulted in a cumulative change to the cumulative translation adjustment account of $(5.6) million and $(2.0) million, net of taxes, as of December 31, 2007 and 2006, 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:
Year Ended December 31, |
||||||
2007 |
2006 |
2005 |
||||
(In Thousands) |
||||||
Number of weighted average common shares outstanding |
73,573 |
71,632 |
68,588 |
|||
Assumed exercise of stock options |
2,348 |
3,192 |
3,548 |
|||
Average diluted shares outstanding |
75,921 |
74,824 |
72,136 |
|||
For the year ended December 31, 2007, the average diluted shares outstanding excludes the impact of 716,354 average outstanding stock options that have exercise prices in excess of the average market price, as the inclusion of these shares would have been antidilutive. There were no stock options or other dilutive securities excluded in the computation of diluted earnings per share for the years ended December 31, 2006, or 2005.
NOTE Q — INDUSTRY SEGMENTS AND GEOGRAPHIC INFORMATION
We manage our operations through four operating segments: Fluids, WA&D Services, Maritech and Production Enhancement.
Our Fluids Division manufactures and markets clear brine fluids, additives, and other associated products and services to the oil and gas industry for use in well drilling, completion, and workover operations both domestically and in certain regions of Europe, Asia (including the Middle East), 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.
Our 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. Our WA&D Services segment also provides diving, marine, engineering, cutting, workover, drilling, and other
F-37
services. The WA&D Services segment operates primarily in the onshore U.S. Gulf Coast region and the inland waters and offshore markets of the Gulf of Mexico.
The Maritech segment consists of our Maritech subsidiary, which, with its subsidiaries, is a producer of oil and gas from properties acquired 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 that are intended to increase the cash flows on such properties prior to their ultimate abandonment.
Our Production Enhancement Division provides production testing services to markets in Texas, New Mexico, Colorado, Oklahoma, Arkansas, Louisiana, offshore Gulf of Mexico, and certain international locations. In addition, it provides wellhead compression services to customers to enhance production from mature, low pressure natural gas wells located principally in the mid-continent, mid-western, western, Rocky Mountain, and Gulf Coast regions of the United States as well as in western Canada, Mexico, and other Latin American countries.
We generally evaluate performance and allocate resources based on profit or loss from operations before income taxes and nonrecurring charges, return on investment and other criteria. The accounting policies of the reportable segments are the same as those described in the summary of significant accounting policies. Transfers between segments, as well as geographic areas, are priced at the estimated fair value of the products or services as negotiated between the operating units. “Corporate overhead” includes corporate general and administrative expenses, corporate depreciation and amortization, interest income and expense and other income and expense.
Summarized financial information concerning the business segments from continuing operations is as follows:
Year Ended December 31, |
|||||||||
2007 |
2006 |
2005 |
|||||||
(In Thousands) |
|||||||||
Revenues from external customers |
|||||||||
Product sales |
|||||||||
Fluids Division |
$ |
226,399 |
$ |
209,829 |
$ |
201,127 |
|||
WA&D Division |
|||||||||
WA&D Services |
4,860 |
3,448 |
4,021 |
||||||
Maritech |
213,338 |
164,099 |
62,876 |
||||||
Intersegment eliminations |
– |
– |
– |
||||||
Total WA&D Division |
218,198 |
167,547 |
66,897 |
||||||
Production Enhancement Division |
12,641 |
10,881 |
11,459 |
||||||
Consolidated |
457,238 |
388,257 |
279,483 |
||||||
|
|||||||||
Services and rentals |
|||||||||
Fluids Division |
54,353 |
34,158 |
20,052 |
||||||
WA&D Division |
|||||||||
WA&D Services |
306,174 |
220,878 |
131,895 |
||||||
Maritech |
816 |
3,709 |
2,276 |
||||||
Intersegment eliminations |
– |
– |
– |
||||||
Total WA&D Division |
306,990 |
224,587 |
134,171 |
||||||
Production Enhancement Division |
163,902 |
120,793 |
75,543 |
||||||
Consolidated |
525,245 |
379,538 |
229,766 |
||||||
F-38
Year Ended December 31, |
|||||||||
2007 |
2006 |
2005 |
|||||||
(In Thousands) |
|||||||||
Revenues from external customers |
|||||||||
Intersegment revenues |
|||||||||
Fluids Division |
1,322 |
562 |
189 |
||||||
WA&D Division |
|||||||||
WA&D Services |
30,048 |
73,859 |
6,031 |
||||||
Maritech |
– |
– |
– |
||||||
Intersegment eliminations |
(29,057 |
) |
(73,859 |
) |
(6,031 |
) |
|||
Total WA&D Division |
991 |
– |
– |
||||||
Production Enhancement Division |
141 |
|
175 |
102 |
|||||
Intersegment eliminations |
(2,454 |
) |
(737 |
) |
(291 |
) |
|||
Consolidated |
– |
– |
– |
||||||
|
|||||||||
Total revenues |
|||||||||
Fluids Division |
282,074 |
244,549 |
221,368 |
||||||
WA&D Division |
|||||||||
WA&D Services |
341,082 |
298,185 |
141,947 |
||||||
Maritech |
214,154 |
167,808 |
65,152 |
||||||
Intersegment eliminations |
(29,057 |
) |
(73,859 |
) |
(6,031 |
) |
|||
Total WA&D Division |
526,179 |
392,134 |
201,068 |
||||||
Production Enhancement Division |
176,684 |
131,849 |
87,104 |
||||||
Intersegment eliminations |
(2,454 |
) |
(737 |
) |
(291 |
) |
|||
Consolidated |
$ |
982,483 |
$ |
767,795 |
$ |
509,249 |
|||
Year Ended December 31, |
|||||||||
2007 |
2006 |
2005 |
|||||||
(In Thousands) |
|||||||||
|
|||||||||
Depreciation, depletion, amortization, and accretion |
|||||||||
Fluids Division |
$ |
12,758 |
$ |
9,180 |
$ |
8,158 |
|||
WA&D Division |
|||||||||
WA&D Services |
16,279 |
11,958 |
5,888 |
||||||
Maritech |
82,800 |
46,988 |
18,498 |
||||||
Intersegment eliminations |
(891 |
) |
(127 |
) |
(271 |
) |
|||
Total WA&D Division |
98,188 |
58,819 |
|
24,115 |
|||||
Production Enhancement Division |
17,398 |
11,936 |
8,462 |
||||||
Corporate overhead |
1,500 |
996 |
904 |
||||||
Consolidated |
$ |
129,844 |
$ |
80,931 |
$ |
41,639 |
|||
|
|
|||||||||
|
Interest Expense |
|||||||||
|
Fluids Division |
$ |
159 |
$ |
1 |
$ |
3 |
|||
|
WA&D Division |
|||||||||
|
WA&D Services |
75 |
62 |
9 |
||||||
|
Maritech |
57 |
4 |
– |
||||||
|
Intersegment eliminations |
– |
– |
– |
||||||
|
Total WA&D Division |
132 |
66 |
9 |
||||||
|
Production Enhancement Division |
21 |
89 |
– |
||||||
|
Corporate overhead |
17,574 |
13,481 |
6,297 |
||||||
|
Consolidated |
$ |
17,886 |
$ |
13,637 |
$ |
6,309 |
|||
F-39
Year Ended December 31, |
|||||||||
2007 |
|
2006 |
2005 |
||||||
|
|
(In Thousands) |
||||||||
|
Income before taxes and discontinued operations |
|||||||||
| Fluids Division |
$ |
10,897 |
$ |
60,939 |
$ |
33,805 |
|||
| WA&D Division |
|||||||||
| WA&D Services |
33,496 |
51,007 |
21,370 |
||||||
| Maritech |
(49,815 |
) |
55,105 |
4,871 |
|||||
| Intersegment elimination |
6,225 |
(7,865 |
) |
(34 |
) |
||||
| Total WA&D Division |
(10,094 |
) |
98,247 |
26,207 |
|||||
| Production Enhancement Division |
52,302 |
39,141 |
22,131 |
||||||
| Corporate overhead |
(50,943 |
)(1) |
(45,958 |
)(1) |
(30,114 |
)(1) |
|||
| Consolidated |
$ |
2,162 |
$ |
152,369 |
$ |
52,029 |
|||
|
|
|||||||||
|
Total assets |
|||||||||
| Fluids Division |
$ |
285,882 |
$ |
270,152 |
$ |
207,363 |
|||
| WA&D Division |
|||||||||
| WA&D Services |
262,729 |
279,541 |
117,244 |
||||||
| Maritech |
391,703 |
302,381 |
194,593 |
||||||
| Intersegment eliminations |
(2,119 |
) |
(41,618 |
) |
(12,487 |
) |
|||
| Total WA&D Division |
652,313 |
540,304 |
299,350 |
||||||
| Production Enhancement Division |
266,729 |
223,931 |
165,476 |
||||||
| Corporate overhead |
90,612 |
(2) |
51,803 |
(2) |
54,661 |
(2) |
|||
| Consolidated |
$ |
1,295,536 |
$ |
1,086,190 |
$ |
726,850 |
|||
|
|
|||||||||
|
Capital expenditures |
|||||||||
| Fluids Division |
$ |
18,877 |
$ |
11,679 |
$ |
8,363 |
|||
| WA&D Division |
|||||||||
| WA&D Services |
29,732 |
59,335 |
3,905 |
||||||
| Maritech |
178,392 |
60,660 |
41,023 |
||||||
| Intersegment eliminations |
(5,113 |
) |
(1,635 |
) |
(233 |
) |
|||
| Total WA&D Division |
203,011 |
118,360 |
44,695 |
||||||
| Production Enhancement Division |
46,189 |
38,226 |
22,827 |
||||||
| Corporate overhead |
7,997 |
4,150 |
1,108 |
||||||
| Consolidated |
$ |
276,074 |
$ |
172,415 |
$ |
76,993 |
|||
(1) Amounts reflected include the following general corporate expenses:
2007 |
2006 |
2005 |
|||||||
General and administrative expense |
$ |
31,533 |
$ |
31,149 |
$ |
22,495 |
|||
Depreciation and amortization |
1,500 |
997 |
903 |
||||||
Interest expense |
17,574 |
13,481 |
6,297 |
||||||
Other general corporate (income) expense, net |
336 |
331 |
419 |
||||||
Total |
$ |
50,943 |
$ |
45,958 |
$ |
30,114 |
|||
(2) Includes assets of discontinued operations.
F-40
Summarized financial information concerning the geographic areas of our customers and in which we operate at December 31, 2007, 2006, and 2005 is presented below:
Year Ended December 31, |
|||||||||
2007 |
2006 |
2005 |
|||||||
(In Thousands) |
|||||||||
| Revenues from external customers: |
|||||||||
| U.S. |
$ |
850,857 |
$ |
646,172 |
$ |
409,298 |
|||
| Canada and Mexico |
25,330 |
22,001 |
17,737 |
||||||
| South America |
9,307 |
12,881 |
2,690 |
||||||
| Europe |
80,495 |
74,292 |
68,107 |
||||||
| Africa |
2,498 |
3,421 |
4,781 |
||||||
| Asia and other |
13,996 |
9,028 |
6,636 |
||||||
| Total |
982,483 |
767,795 |
509,249 |
||||||
|
|
|||||||||
| Transfers between geographic areas: |
|||||||||
| U.S. |
318 |
1,425 |
1,556 |
||||||
| Canada and Mexico |
– |
– |
– |
||||||
| South America |
– |
– |
– |
||||||
| Europe |
1,548 |
256 |
608 |
||||||
| Africa |
– |
– |
– |
||||||
| Asia and other |
– |
112 |
– |
||||||
| Eliminations |
(1,866 |
) |
(1,793 |
) |
(2,164 |
) |
|||
| Total revenues |
$ |
982,483 |
$ |
767,795 |
$ |
509,249 |
|||
|
|
|||||||||
| Identifiable assets: |
|||||||||
| U.S. |
$ |
1,163,604 |
$ |
965,975 |
$ |
619,011 |
|||
| Canada and Mexico |
22,482 |
12,515 |
10,943 |
||||||
| South America |
17,843 |
17,823 |
12,974 |
||||||
| Europe |
79,972 |
73,816 |
63,896 |
||||||
| Africa |
1,821 |
2,136 |
5,030 |
||||||
| Asia and other |
5,772 |
637 |
539 |
||||||
| Eliminations and discontinued operations |
4,042 |
|
13,288 |
14,457 |
|||||
| Total |
$ |
1,295,536 |
|
$ |
1,086,190 |
$ |
726,850 |
||
In 2007, a single purchaser of Maritech’s oil and gas production, Shell Trading (US) Company, accounted for approximately 12.5% of our consolidated revenues. In 2006 and 2005, no single customer accounted for more than 10% of our consolidated revenues.
NOTE R — SUPPLEMENTAL OIL AND GAS DISCLOSURES (Unaudited)
The following information regarding the activities of our Maritech segment is presented pursuant to SFAS No. 69, “Disclosures About Oil and Gas Producing Activities (SFAS No. 69).” As part of the WA&D Division activities, Maritech and its subsidiaries generally acquire oil and gas reserves and operate the properties in exchange for assuming the proportionate share of the well abandonment obligations associated with such properties. Accordingly, our Maritech segment is included within our 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, and any subsequent revision, of the amount of the proportionate share of the well abandonment and decommissioning obligations associated with the properties.
F-41
Year Ended December 31, |
|||||||||
2007 |
2006 |
2005 |
|||||||
(In Thousands) |
|||||||||
Acquisition |
$ |
82,976 |
$ |
8,561 |
$ |
115,795 |
|||
Exploration |
– |
|
– |
– |
|||||
Development |
152,372 |
78,774 |
26,185 |
||||||
Total costs incurred |
$ |
235,348 |
$ |
87,335 |
$ |
141,980 |
|||
Capitalized Costs Related to Oil and Gas Producing Activities:
Aggregate amounts of capitalized costs relating to our oil and gas producing activities and the aggregate amounts of related accumulated depletion, depreciation, and amortization as of the dates indicated, are presented below.
December 31, |
|||||||||
2007 |
2006 |
2005 |
|||||||
(In Thousands) |
|||||||||
Properties not being amortized |
$ |
7,599 |
$ |
8,377 |
$ |
10,567 |
|||
Proved developed properties being amortized |
565,568 |
275,890 |
187,540 |
||||||
Total capitalized costs |
573,167 |
284,267 |
198,107 |
||||||
Less accumulated depletion, depreciation, and amortization |
(233,829 |
) |
(81,709 |
) |
(41,886 |
) |
|||
Net capitalized costs |
$ |
339,338 |
$ |
202,558 |
$ |
156,221 |
|||
Included in capitalized costs of proved developed properties being amortized is our estimate of our proportionate share of decommissioning liabilities assumed relating to these properties, which is also reflected as decommissioning and other asset retirement obligations in the accompanying consolidated balance sheets.
Results of Operations for Oil and Gas Producing Activities:
Results of operations for oil and gas producing activities excludes general and administrative and interest expenses directly related to such activities as well as any allocation of corporate or divisional overhead.
Year Ended December 31, |
|||||||||
2007 |
2006 |
2005 |
|||||||
(In Thousands) |
|||||||||
Oil and gas sales revenues |
$ |
213,338 |
$ |
164,099 |
$ |
62,876 |
|||
Production (lifting) costs (1) |
89,605 |
63,665 |
34,706 |
||||||
Depreciation, depletion, and amortization |
73,835 |
38,550 |
14,878 |
||||||
Impairments of properties (2) |
76,094 |
3,405 |
|
1,907 |
|||||
Excess decommissioning and abandonment costs |
12,153 |
3,755 |
2,941 |
||||||
Exploration expenses |
1,174 |
8 |
84 |
||||||
Accretion expense |
6,841 |
6,825 |
3,230 |
||||||
Dry hole costs |
1,699 |
1,145 |
– |
||||||
Gain on insurance recoveries |
(3,245 |
) |
(10,555 |
) |
(1,333 |
) | |||
Pretax income from producing activities |
(44,818 |
) |
57,301 |
6,463 |
|||||
Income tax expense |
(16,549 |
) |
20,605 |
1,782 |
|||||
Results of oil and gas producing activities |
$ |
(28,269 |
) |
$ |
36,696 |
$ |
4,681 |
||
(1) Production costs during 2007 include certain hurricane repair expenses of $13.5 million, which were previously included in insurance receivable.
(2) Impairments of oil and gas properties during 2007 were primarily due to the increase in Maritech’s decommissioning liability as a result of contested insurance coverage.
F-42
Estimated Quantities of Proved Oil and Gas Reserves (Unaudited):
Proved oil and gas reserves are defined as the estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Reservoirs are considered proved if economic productibility is supported by either actual production or conclusive formation tests. The area of a reservoir considered proved includes (a) that portion delineated by drilling and defined by gas-oil and/or gas-water contacts, if any, and (b) the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data. Reserves which can be produced economically through the application of improved recovery techniques are included in the “proved” classification when successful testing by a pilot project, or the operation of an installed program in the reservoir, provides support for the engineering analysis on which the project or program was based.
The reliability of reserve information is considerably affected by several factors. Reserve information is imprecise due to the inherent uncertainties in, and the limited nature of, the database upon which the estimating of reserve information is predicated. Moreover, the methods and data used in estimating reserve information are often necessarily indirect or analogical in character, rather than direct or deductive. Furthermore, estimating reserve information, by applying generally accepted petroleum engineering and evaluation principles, involves numerous judgments based upon the engineer’s educational background, professional training, and professional experience. The extent and significance of the judgments to be made are, in themselves, sufficient to render reserve information inherently imprecise.
Through our Maritech subsidiary, we employ full-time experienced reservoir engineers and geologists who are responsible for determining proved reserves in conformance with SEC guidelines. Reserve estimates were prepared by Maritech engineers based upon their interpretation of production performance data and geologic interpretation of sub-surface information derived from the drilling of wells. In addition to the complete analysis by Maritech’s internal reservoir engineers, independent petroleum engineers and geologists performed reserve audits of approximately 81.9% of our proved reserve volumes as of December 31, 2007. The use of the term reserve audit is intended only to refer to the collective application of the engineering and geologic procedures which the independent petroleum engineering firms were engaged to perform and may be defined and used differently by other companies.
A reserve audit is a process whereby an independent petroleum engineering firm performs extensive visits, collects and includes all necessary geologic, geophysical, engineering, and economic data, followed by an independent reserve evaluation. The reserve audit of our oil and gas reserves involves the rigorous examination of our technical evaluation, as well as the interpretation, and extrapolation of well information such as flow rates, reservoir pressure declines, and other technical information and measurements. Maritech’s internal reservoir engineers interpret this data to determine the nature of the reservoir and, ultimately, the quantity of proved oil and gas reserves attributable to the specific property. Our proved reserves, as reflected in this Annual Report, include only quantities that Maritech expects to recover commercially using current technology, prices, and costs, and within existing regulatory and environmental limits. While Maritech can be reasonably certain that the proved reserves will be produced, the timing and ultimate recovery can be affected by a number of factors, including completion of development projects, reservoir performance, regulatory approvals, and changes in projections of long-term oil and gas prices. Revisions can include upward or downward changes in the previously estimated volumes of proved reserves for existing fields due to evaluation of (1) already available geologic, reservoir, or production data or (2) new geologic or reservoir data obtained from wells. Revisions can also occur associated with significant changes in development strategy, oil and gas prices, or the related production equipment/facility capacity. Maritech’s independent petroleum engineers also examined the reserve estimates with respect to reserve categorization, using the definitions for proved reserves set forth in Regulation S-X Rule 4-10(a) and subsequent SEC staff interpretations and guidance.
F-43
Maritech engaged Ryder Scott Company, L.P. and DeGolyer and McNaughton to perform the engineering audits of our oil and gas reserves as of December 31, 2007. In the conduct of these reserve audits, these independent petroleum engineering firms did not independently verify the accuracy and completeness of information and data furnished by Maritech with respect to property interests owned, oil and gas production and well tests from examined wells, or historical costs of operation and development; however, they did verify product prices, geological structural and isopach maps, well logs, core analyses, and pressure measurements. If, in the course of the examinations, a matter of question arose regarding the validity or sufficiency of any such information or data, the independent petroleum engineering firms did not accept such information or data until all questions relating thereto were satisfactorily resolved. Furthermore, in instances where decline curve analysis was not adequate in determining proved producing reserves, the independent petroleum engineering firms performed volumetric analysis, which included the analysis of geologic, reservoir, and fluids data. Proved undeveloped reserves were analyzed by volumetric analysis, which takes into consideration recovery factors relative to the geology of the location and similar reservoirs. Where applicable, the independent petroleum engineering firms examined data related to well spacing, including potential drainage from offsetting producing wells, in evaluating proved reserves of undrilled well locations.
The reserve audit performed by Ryder Scott Company, L.P. included certain properties selected by Maritech, including all of our most significant properties, excluding the Cimarex Properties, and represented approximately 61.1% of our total proved oil and gas reserve volumes (81.1% of discounted future net pretax cash flows). The reserve audit performed by DeGolyer and McNaughton included the Cimarex Properties acquired in December 2007 and represented approximately 20.8% of our total proved oil and gas reserve volumes (11.9% of discounted future net pretax cash flows). The independent petroleum engineers represent in their audit reports that they believe Maritech’s estimates of future reserves were prepared in accordance with generally accepted petroleum engineering and evaluation principles for the estimation of future reserves as set forth in Society of Petroleum Engineers (SPE) standards. In each case, the independent petroleum engineers concluded that the overall proved reserves for the reviewed properties as estimated by Maritech, were, in the aggregate, reasonable within the established audit tolerance guidelines of 10% as set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the SPE. There were no limitations imposed or encountered by Maritech or the independent petroleum engineers in the preparation of our estimated reserves or in the performance of the reserve audits by the independent petroleum engineers.
The following information is presented with regard to our proved oil and gas reserves. The reserve values and cash flow amounts reflected in the following reserve disclosures are based on prices as of year end. Proved oil and gas reserve quantities are reported in accordance with guidelines established by the SEC. Ryder Scott Company, L.P. prepared the estimates for our reserves at December 31, 2006, and 2005, except for two producing fields (representing approximately 43% of proved reserves volumes) as of December 31, 2006 and one producing field (representing approximately 31% of proved reserves volumes) as of December 31, 2005, which were prepared by Maritech. All of Maritech’s reserves are located in U. S. state and federal offshore waters of the Gulf of Mexico and onshore Louisiana.
Reserve Quantity Information |
Oil |
Gas |
||
(MBbls) |
(MMcf) |
|||
Total proved reserves at December 31, 2004 |
2,646 |
22,405 |
||
Revisions of previous estimates |
63 |
(3,421 |
) |
|
Production |
(484 |
) |
(5,088 |
) |
Extensions and discoveries |
859 |
3,195 |
||
Purchases of reserves in place |
5,703 |
29,900 |
||
Sales of reserves in place |
(800 |
) |
(4,717 |
) |
F-44
|
Oil |
Gas |
||
(MBbls) |
(MMcf) |
|||
|
||||
Total proved reserves at December 31, 2005 |
7,987 |
42,274 |
||
Revisions of previous estimates |
732 |
(44 |
) |
|
Production |
(1,356 |
) |
(7,812 |
) |
Extensions and discoveries |
1,299 |
5,230 |
||
Purchases of reserves in place |
180 |
163 |
||
Sales of reserves in place |
(13 |
) |
(73 |
) |
Total proved reserves at December 31, 2006 |
8,829 |
39,738 |
||
Revisions of previous estimates |
(760 |
) |
(6,280 |
) |
Production |
(1,985 |
) |
(9,515 |
) |
Extensions and discoveries |
584 |
2,766 |
||
Purchases of reserves in place |
174 |
20,621 |
||
Sales of reserves in place |
(107 |
) |
(523 |
) |
|
||||
Total proved reserves at December 31, 2007 |
6,735 |
46,807 |
||
|
||||
|
Oil |
Gas |
||
Proved Developed Reserves |
(MBbls) |
(MMcf) |
||
|
||||
December 31, 2005 |
6,372 |
35,091 |
||
December 31, 2006 |
7,872 |
36,373 |
||
December 31, 2007 |
6,646 |
43,898 |
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 our oil and gas properties is as follows:
December 31, |
||||||
2007 |
2006 |
|||||
(In Thousands) |
||||||
Future cash inflows |
$ |
962,734 |
$ |
752,500 |
||
Future costs |
||||||
Production |
237,835 |
244,694 |
||||
Development and abandonment |
226,842 |
196,736 |
||||
Future net cash flows before income taxes |
498,057 |
311,070 |
||||
Future income taxes |
(134,950 |
) |
(104,832 |
) |
||
Future net cash flows |
363,107 |
206,238 |
||||
Discount at 10% annual rate |
(64,428 |
) |
(20,148 |
) |
||
Standardized measure of discounted future net cash flows |
$ |
298,679 |
$ |
186,090 |
||
F-45
Changes in Standardized Measure of Discounted Future Net Cash Flows:
Year Ended December 31, |
|||||||||
|
2007 |
|
2006 |
2005 |
||||||
(In Thousands) |
|||||||||
Standardized measure,beginning of year |
$ |
186,090 |
$ |
233,988 |
$ |
69,891 |
|||
|
|||||||||
Sales, net of production costs |
(111,580 |
) |
(103,829 |
) |
(26,562 |
) |
|||
Net change in prices, net of production costs |
179,079 |
|
(143,181 |
) |
33,495 |
||||
Changes in future development costs |
10,635 |
9,127 |
993 |
||||||
Development costs incurred |
26,615 |
13,148 |
4,596 |
||||||
Accretion of discount |
27,569 |
34,742 |
10,371 |
||||||
Net change in income taxes |
(24,171 |
) |
23,835 |
(79,612 |
) |
||||
Purchases of reserves in place |
55,673 |
|
6,585 |
206,331 |
|||||
Extensions and discoveries |
53,504 |
86,223 |
71,423 |
||||||
Sales of reserves in place |
4,114 |
3,885 |
(28,931 |
) |
|||||
Net change due to revision in quantity estimates |
(83,826 |
) |
17,534 |
(18,813 |
) |
||||
Changes in production rates (timing) and other |
(25,023 |
) |
4,033 |
|
(9,194 |
) |
|||
Subtotal |
112,589 |
(47,898 |
) |
164,097 |
|||||
|
|||||||||
Standardized measure, end of year |
$ |
298,679 |
$ |
186,090 |
$ |
233,988 |
|||
NOTE S — QUARTERLY FINANCIAL INFORMATION (Unaudited)
Summarized quarterly financial data for 2007 and 2006 is as follows:
Three
Months Ended 2007 |
||||||||||||
March 31 |
June 30 |
September 30 |
December 31 |
|||||||||
(In
Thousands, Except Per Share Amounts) |
||||||||||||
Total revenues |
$ |
243,596 |
$ |
254,054 |
$ |
238,858 |
$ |
245,975 |
||||
Gross profit (loss) |
57,465 |
60,606 |
35,650 |
(37,338 |
) |
|||||||
Income (loss) before discontinued operations |
20,346 |
22,167 |
3,046 |
(44,338 |
) |
|||||||
Net income (loss) |
20,661 |
22,871 |
3,862 |
(18,623 |
) |
|||||||
|
||||||||||||
Net income (loss) per share before discontinued operations |
$ |
0.28 |
$ |
0.30 |
$ |
0.04 |
$ |
(0.60 |
) |
|||
|
||||||||||||
Net income (loss) per diluted share before discontinued operations |
$ |
0.27 |
$ |
0.29 |
$ |
0.04 |
$ |
(0.60 |
) |
|||
Three
Months Ended 2006 |
||||||||||||
March 31 |
June 30 |
September 30 |
December 31 |
|||||||||
(In
Thousands, Except Per Share Amounts) |
||||||||||||
Total revenues |
$ |
147,142 |
$ |
202,557 |
$ |
212,450 |
$ |
205,646 |
||||
Gross profit (1) |
52,130 |
67,261 |
70,562 |
62,851 |
||||||||
Income before discontinued operations |
18,931 |
28,617 |
28,535 |
23,797 |
||||||||
Net income |
19,517 |
29,225 |
29,430 |
23,706 |
||||||||
|
||||||||||||
| Net income per share before discontinued operations |
$ |
0.27 |
$ |
0.40 |
$ |
0.40 |
$ |
0.33 |
||||
|
||||||||||||
Net income per diluted share before discontinued operations |
$ |
0.25 |
$ |
0.38 |
$ |
0.38 |
$ |
0.32 |
||||
(1) The amounts for gross profit for each of the periods presented for 2006 reflect the reclassification into cost of revenues of certain billed expenses which had previously been credited to general and administrative expense. The reclassified amounts were $441, $545, $849, and $854 during the quarters ended March 31, June 30, September 30 and December 31, 2006, respectively. The reclassification conforms to the current year presentation and had no effect on net income for the periods presented.
F-46
NOTE T — STOCKHOLDERS’ RIGHTS PLAN
On October 27, 1998, the Board of Directors adopted a stockholders’ rights plan (the Rights Plan) designed to assure that all of our stockholders receive fair and equal treatment in the event of a proposed takeover. The Rights Plan helps to guard against partial tender offers, open market accumulations and other abusive tactics to gain control of our company without paying an adequate and fair price in any takeover attempt. The Rights are not presently exercisable and are not represented by separate certificates. We are currently not aware of any effort of any kind to acquire control of our company.
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 our common stock and would entitle holders of the Rights to purchase either our stock or shares in an acquiring entity at half of market value. Each Right entitles the holder thereof to purchase 1/100 of a share of Series One Junior Participating Preferred Stock for $50.00 per share, subject to adjustment. We would generally be entitled to redeem the Rights at $.01 per Right at any time until the tenth day following the time the Rights become exercisable. The Rights will expire on November 6, 2008.
For a more detailed description of the Rights Plan, refer to our Form 8-K filed with the SEC on October 28, 1998.
F-47