Item 1.
Business
Our Company
Oil States International, Inc. (the “Company”), through its subsidiaries, is a leading provider of specialty products and services to oil and gas drilling and production companies throughout the world. We operate in a substantial number of the world’s active oil and gas producing regions, including the Gulf of Mexico, U.S. onshore, West Africa, the North Sea, Canada, South America and Southeast and Central Asia. Our customers include many of the national oil companies, major and independent oil and gas companies and other oilfield service companies.
We operate in three principal business segments - offshore products, tubular services and well site services - and have established a leadership position in certain of our product or service offerings in each segment.
Available Information
The Company maintains a website with the address www.oilstatesintl.com. The Company is not including the information contained on the Company’s website as a part of, or incorporating it by reference into, this Annual Report on Form 10-K. The Company makes available free of charge through its website its Annual Report on Form 10-K, quarterly reports on Form 10-Q and current reports on Form 8-K, and amendments to these reports, as soon as reasonably practicable after the Company electronically files such material with, or furnishes such material to, the Securities and Exchange Commission (SEC). The Board of Directors of the Company documented its governance practices by adopting several corporate governance policies. These governance policies, including the Company’s corporate governance guidelines and its code of business conduct and ethics, as well as the charters for the committees of the Board (Audit Committee, Compensation Committee and Nominating and Corporate Governance Committee) may also be viewed at the Company’s website. Copies of such documents will be sent to shareholders free of charge upon written request of the corporate secretary at the address shown on the cover page of this Form 10-K.
In accordance with New York Stock Exchange (NYSE) Rules, on June 11, 2007, the Company filed the annual certification by our CEO that, as of the date of the certification, the Company was in compliance with the NYSE’s corporate governance listing standards.
Our Background
Oil States International, Inc. was originally incorporated in July 1995. In July 2000, Oil States International, Inc., including its principal operating subsidiaries, Oil States Industries, Inc. (Oil States Industries), HWC Energy Services, Inc. (HWC), PTI Group Inc. (PTI) and Sooner Inc. (Sooner) entered into a Combination Agreement (the Combination Agreement) providing that, concurrently with the closing of our initial public offering, HWC, PTI and Sooner would merge with wholly owned subsidiaries of Oil States (the Combination). As a result, HWC, PTI and Sooner became wholly owned subsidiaries of Oil States in February 2001. In this Annual Report on Form 10-K, references to the “Company” or to “we,” “us,” “our,” and similar terms are to Oil States International, Inc. and its subsidiaries following the Combination.
Our Business Strategy
We have in past years grown and plan to continue to expand our business lines both organically and through strategic acquisitions. Our investments are focused in high growth areas where we can achieve attractive returns. Currently, we see growth opportunities in the oil sands developments in Canada, in the expansion of our capabilities to manufacture and assemble deepwater capital equipment and in the expansion of our product and service offerings supporting our customers’ activities in the key resource plays in the United States.
Acquisitions
Since the completion of our initial public offering in February 2001, we have completed 33 acquisitions for total consideration of $496 million. Acquisitions of other oilfield service businesses have been an important aspect of our growth strategy and plans to increase shareholder value. Our acquisition strategy has primarily been focused in the well site services segment where we have expanded our geographic locations and our product and service offerings, especially in our rental tool business line. This growth strategy has allowed us to leverage our existing and acquired product and service offerings in new geographic locations. We have also made strategic acquisitions in offshore products, tubular services and in other well site services business lines.
In 2002 through 2004, we acquired 19 businesses for total consideration of $178.0 million. Each of the businesses acquired became part of our existing business segments and included rental tool companies, offshore products companies and product lines and a tubular distribution company.
In 2005, we completed nine acquisitions for total consideration of $158.6 million. In our well site services segment, we acquired a Wyoming based land drilling company, five related entities providing wellhead isolation equipment and services, and a Canadian manufacturer of work force accommodations. Our tubular services segment acquired a Texas based OCTG distributor, and our offshore products segment acquired a small product line.
In August 2006, we acquired three drilling rigs operating in West Texas for total consideration of $14.0 million. The rigs acquired, which are classified as part of our capital expenditures in 2006, were added to our existing West Texas drilling fleet in our drilling services business.
In 2007, we acquired two rental tool businesses for total consideration of $112.8 million. In July 2007, we acquired the business of Wire Line Service, Ltd. (“Well Testing”), a Midland, Texas business that primarily provides well testing and flowback services through its locations in Texas and New Mexico for total consideration of $46.4 million. In August 2007, we acquired the business of Schooner Petroleum Services, Inc. (“Schooner”). Schooner, headquartered in Houston, Texas, primarily provides completion-related rental tools and services through eleven locations in Texas, Louisiana, Wyoming and Arkansas. The consideration for the assets acquired totaled approximately $66.4 million. The operations of Well Testing and Schooner have been included in the rental tools business within the well site services segment.
In February 2008, we acquired an accommodations lodge in the oil sands area of Alberta, Canada for cash consideration of C$6.5 million and a waterfront facility on the ship channel in Houston, Texas for use in our offshore products segment for cash consideration of $22.5 million.
Workover Services Business Transaction
Effective March 1, 2006, we completed a transaction to combine our workover services business with Boots & Coots International Well Control, Inc. (AMEX: WEL) (“Boots & Coots”) in exchange for 26.5 million shares of Boots & Coots common stock valued at $1.45 per share at closing and senior subordinated promissory notes totaling $21.2 million. Our workover services business was part of our well site services segment prior to the combination. The closing of the transaction resulted in a non-cash pretax gain of $20.7 million.
As a result of the closing of the transaction, we initially owned 45.6% of Boots & Coots. The senior subordinated promissory notes received in the transaction bear a fixed annual interest rate of 10% and mature on September 1, 2010. In connection with this transaction, we also entered into a Registration Rights Agreement requiring Boots & Coots to file a shelf registration statement. A shelf registration statement was finalized by Boots & Coots effective in the fourth quarter of 2006 and we sold shares in April 2007 as described below. The transaction terms allowed us to designate three additional members to Boots & Coots’ then existing five-member Board of Directors after the closing of the transaction. Currently, two of our designees remain on Boots & Coots eight-member Board.
In April 2007, we sold, pursuant to a registration statement filed by Boots & Coots, 14,950,000 shares of our Boots & Coots stock for net proceeds of $29.4 million and, as a result, we recognized a net after tax gain of $8.4 million, or approximately $0.17 per diluted share, in the second quarter of 2007. After our sale of Boots & Coots shares and the sale of primary shares of stock directly by Boots & Coots in April 2007, our ownership interest in Boots & Coots was reduced to approximately 15%. The equity method of accounting continues to be used to account for the Company’s remaining investment in Boots & Coots common stock (11.5 million shares). The carrying value of the Company’s remaining investment in Boots & Coots stock totals $19.6 million as of December 31, 2007.
Our Industry
We operate in the oilfield services industry and provide a broad range of products and services to our customers through our offshore products, tubular services and well site services business segments. Demand for our products and services is cyclical and substantially dependent upon activity levels in the oil and gas industry, particularly our customers’ willingness to spend capital on the exploration and development of oil and gas reserves. Demand for our products and services by our customers is highly sensitive to current and expected prices for oil and natural gas. See
Note 14 to our Consolidated Financial Statements included in this Annual Report on Form 10-K for financial information by segment and a geographical breakout of revenues and long-lived assets.
Our financial results reflect the cyclical nature of the oilfield services business. Since 2001, there have been periods of increasing and decreasing activity in each of our operating segments.
Our Well Site Services businesses, which are significantly affected by the North American rig count, saw increasing activity from 2003 through 2006. In 2007, the Canadian rig count declined 27% compared to 2006 leading to a relatively flat year-over-year average North American rig count. Acquisitions and capital expenditures made in this segment have created growth opportunities. In addition, increased activity supporting oil sands developments in northern Alberta, Canada by our work force accommodations, catering and logistics business has had a positive impact on this segment’s overall trends.
Our Offshore Products segment, which is more influenced by deepwater development activity and rig and vessel construction and repair, experienced increased activity during 2003 as we shipped projects from our backlog which had increased in 2002. In 2004, activity in this segment slowed; however, backlog increased significantly from 2004 to 2007, which resulted in improved operating results during 2005, 2006 and 2007.
Our Tubular Services business is influenced by some of the same factors as our Well Site Services. In addition, during 2004 and 2005, this segment’s margins were positively affected in a significant manner by increasing prices for steel products, including the OCTG we sell. Prices for steel products remained comparatively stable during 2006 compared to the previous two years and declined in 2007. Volumes shipped have increased during 2006 and 2007 partially offsetting decreased margins compared to 2004 and 2005. Tubular services gross margin percentage in 2007 decreased to levels similar to those seen in years prior to 2004.
Well Site Services
Overview
During the year ended December 31, 2007, we generated approximately 34% of our revenue and 62% of our operating income, before corporate charges, from our well site services segment. Our well site services segment includes a broad range of products and services that are used to establish and maintain the flow of oil and gas from a well throughout its lifecycle and to accommodate personnel in remote locations. Our operations include drilling services, rental equipment, work force accommodations, catering and logistics services and modular building construction services. We use our fleet of drilling rigs, rental equipment and work force accommodation facilities to serve our customers at well sites and project development locations. Our products and services are used in both onshore and offshore applications throughout the exploration, development and production phases of a well’s life. Additionally, our work force accommodations, catering and logistics services are employed to support work forces in the oil sands and a variety of mining and related natural resource applications as well as forest fire fighting and disaster relief efforts.
Well Site Services Market
Demand for our drilling rigs, rental equipment and work force accommodations, catering and logistics services has historically been tied to the level of activity by oil and gas explorationists and producers. The primary driver for this activity is the price of oil and natural gas. Activity levels have been and we expect will continue to be highly correlated with hydrocarbon commodity prices. Our workforce accommodations have grown in recent years due to the increasing demand for accommodations to support workers in the oil sands region of Canada.
Products and Services
Drilling Services. Our drilling services business is located in the United States and provides drilling services for shallow to medium depth wells ranging from 1,500 to 12,500 feet. Drilling services are typically used during the exploration and development stages of a field. We have a total of 35 semi-automatic drilling rigs with hydraulic pipe handling booms and lift capacities ranging from 75,000 to 500,000 pounds. Twenty of these drilling rigs are located in Odessa, Texas, ten in the Rocky Mountains region, four in Wooster, Ohio and one in Northeast Texas. On December 31, 2007, 25 rigs were working or under contract. Utilization decreased from 90.0% in 2006 to 79.3% in
2007. We have assembled nine of our new rigs that have been added to our fleet during 2003 through 2007 in our Odessa, Texas facility with components purchased from specialty vendors. Two additional rigs were under construction in Odessa, Texas at December 31, 2007, one of which commenced working in January 2008. In August 2006, we acquired three drilling rigs which were added to our existing West Texas drilling fleet. We may continue to add rigs depending upon our market outlook.
We market our drilling services directly to a diverse customer base, consisting of both major and independent oil and gas companies. Our largest customers in drilling services in 2007 included Apache Corporation and Energen Resources Corporation. We contract on both footage and dayrate basis. Under a daywork drilling contract, the customer pays for certain costs that the Company would normally provide when drilling on a footage basis, and the customer assumes more risk than on a footage basis. Depending on market conditions and availability of drilling rigs, we will see changes in pricing, utilization and contract terms. The land drilling business is highly fragmented and our competition consists of a small number of large companies and many smaller companies.
Rental Equipment. Our rental equipment business provides a wide range of products and services for use in the offshore and onshore oil and gas industry, including:
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wireline and coiled tubing pressure control equipment;
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wellhead isolation equipment;
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pipe recovery systems;
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thru-tubing fishing services;
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hydraulic chokes and manifolds;
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blow out preventers;
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well testing equipment, including separators and line heaters;
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gravel pack operations on well bores; and
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surface control equipment and down-hole tools utilized by coiled tubing operators.
Our rental equipment is primarily used during the completion and production stages. As of December 31, 2007, we provided rental equipment at 67 U.S. distribution points throughout the United States, Canada, Mexico and Argentina. We provide rental equipment on a day rental basis with rates varying depending on the type of equipment and the length of time rented. In certain operations, we also provide service personnel in connection with the equipment rental. We own patents covering some of our rental tools, particularly, in our wellhead isolation equipment product line. Our customers in the rental equipment business include major and independent oil and gas companies and other large oilfield service companies. Competition in the rental tool business is widespread and include mostly smaller companies, although we do compete with a small number of the larger oilfield service companies, who are also our customers for certain products and services.
Work Force Accommodations, Catering and Logistics and Modular Building Construction. We are a large provider of integrated products and services to support workers in remote locations. Our scalable modular facilities provide temporary and permanent workforce accommodations where traditional hotels and infrastructure are not accessible or cost effective. Catering and food services, housekeeping, facility management, water and wastewater treatment, power generation, communications and redeployment logistics are examples of services that we provide to our customers.
Our workforce accommodations business provides remote site housing primarily in western and northern Canada, but also in the U.S. Rocky Mountain corridor (Wyoming, Colorado, Utah), Fayetteville Shale region of Arkansas and offshore locations in the Gulf of Mexico. We have also served companies operating in international markets including the Middle East, Europe, Asia and South America.
Our customers operate in a diverse mix of industries including oil sands mining and development, drilling, exploration and extraction of oil and gas, pipeline construction, mining, forestry, humanitarian aid and disaster relief, and support for military operations. Our largest customer in the work force accommodations market in 2007
was Albian Sands. Our primary competitors in Canada include Aramark Corporation, Compass Group PLC and Atco Structures Limited.
To a significant extent, the Company’s recent capital expenditures have focused on opportunities in the oil sands region in northern Alberta. Since the beginning of 2005, we have spent $219.3 million, or 48.5%, of our total consolidated capital expenditures in our Canadian accommodations business. Most of these capital investments have been in support of oil sands developments. In addition, as conventional oil and gas drilling has decreased, we have shifted certain accommodations assets, formerly utilized in support of conventional activities, to oil sands support. Oil sands related accommodations revenues have increased from 32.9% of total accommodations revenues in 2005 to 54.7% in 2007.
We own two accommodations manufacturing plants which specialize in the design, production, transportation and installation of a variety of portable modular buildings. We manufacture facilities to suit the climate, terrain and population of a specific project site. There is currently a shortage of modular manufacturing capacity in Canada, and we believe that owning the manufacturing operations gives us a competitive advantage in the market currently. The majority of our manufacturing capacity is being used currently for the manufacturing, assembly and installation of our owned facilities. In addition to our major lodge facilities, we offer a broad range of semi-permanent and mobile options to house workers in remote regions. Our fleet of temporary camps is designed to be deployed on short notice and can be relocated as a project site moves. Our temporary camps range in size from a 25-person drilling camp to a 1,000 person construction camp.
Since mid year 2006, we have installed over 2,000 rooms in three of our major lodge properties supporting oil sands operations in the region. Our growth plan includes the expansion of these lodges. These company-owned properties include Beaver River Executive Lodge, Athabasca Lodge and Wapasu Creek Lodge. Beaver River Executive Lodge was expanded from its initial capacity of 258 rooms in 2006 to 730 rooms at the end of 2007. Athabasca Lodge, which sits on the same lease as Beaver River Executive Lodge, accommodates 1,500 construction workers and contractors working in the region and offers many of the same types of common areas and amenities as the Beaver River Executive Lodge. We are currently expanding Wapasu’s capacity to 1,500 rooms in 2008.
Offshore Products
Overview
During the year ended December 31, 2007, we generated approximately 25% of our revenue and 26% of our operating income, before corporate charges, from our offshore products segment. Through this segment, we design and manufacture a number of cost-effective, technologically advanced products for the offshore energy industry. In addition, we have other lower margin products and services such as fabrication and inspection services. Our products and services are used in both shallow and deepwater producing regions and include flex-element technology, advanced connector systems, blow-out preventor stack integration and repair services, deepwater mooring and lifting systems, offshore equipment and installation services and subsea pipeline products. We have facilities in Arlington, Houston and Lampasas, Texas; Houma, Louisiana; Tulsa, Oklahoma; Scotland; Brazil; England; Singapore and Thailand that support our offshore products segment.
Offshore Products Market
The market for our offshore products and services depends primarily upon development of infrastructure for offshore production activities, drilling rig refurbishments and upgrades and new rig and vessel construction. As demand for oil and gas increases and related drilling and production increases in offshore areas throughout the world, particularly in deeper water, we expect spending on these activities to increase.
The upgrade of existing rigs to equip them with the capability to drill in deeper water and withstand harsh operating conditions, the construction of new deepwater-capable rigs, and the installation of fixed or floating production systems require specialized products and services like the ones we provide.
Products and Services
Our offshore products segment provides a broad range of products and services for use in offshore drilling and development activities. In addition, this segment provides onshore oil and gas, defense and general industrial products and services. Our offshore products segment is dependent in part on the industry’s continuing innovation and creative applications of existing technologies.
We design and build manufacturing and testing systems for many of our new products and services. These testing and manufacturing facilities enable us to provide reliable, technologically advanced products and services. Our Aberdeen facility provides structural testing including full-scale product simulations.
Offshore Development and Drilling Activities. We design, manufacture, fabricate, inspect, assemble, repair, test and market subsea equipment and offshore vessel and rig equipment. Our products are components of equipment used for the drilling and production of oil and gas wells on offshore fixed platforms and mobile production units, including floating platforms and floating production, storage and offloading (FPSO) vessels, and on other marine vessels, floating rigs and jack-ups. Our products and services include:
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flexible bearings and connector products;
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subsea pipeline products;
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marine winches, mooring and lifting systems and rig equipment;
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conductor casing connections and pipe;
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drilling riser repair services;
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blowout preventor stack assembly, integration, testing and repair services; and
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other products and services.
Flexible Bearings and Connector Products. We are the principal supplier of flexible bearings, or FlexJoints®, to the offshore oil and gas industry. We also supply connections and fittings that join lengths of large diameter conductor or casing used in offshore drilling operations. FlexJoints® are flexible bearings that permit the controlled movement of riser pipes or tension leg platform tethers under high tension and pressure. They are used on drilling, production and export risers and are used increasingly as offshore production moves to deeper water areas. Drilling riser systems provide the vertical conduit between the floating drilling vessel and the subsea wellhead. Through the drilling riser, equipment is guided into the well and drilling fluids are returned to the surface. Production riser systems provide the vertical conduit from the subsea wellhead to the floating production platform. Oil and gas flows to the surface for processing through the production riser. Export risers provide the vertical conduit from the floating production platform to the subsea export pipelines. FlexJoints® are a critical element in the construction and operation of production and export risers on floating production systems in deepwater.
Floating production systems, including tension leg platforms, Spars and FPSO facilities, are a significant means of producing oil and gas, particularly in deepwater environments. We provide many important products for the construction of these facilities. A tension leg platform is a floating platform that is moored by vertical pipes, or tethers, attached to both the platform and the sea floor. Our FlexJoint® tether bearings are used at the top and bottom connections of each of the tethers, and our Merlin connectors are used to join shorter pipe sections to form long pipes offshore. A Spar is a floating vertical cylindrical structure which is approximately six to seven times longer than its diameter and is anchored in place. Our FlexJoints® are also used to attach the steel catenary risers to a Spar, FPSO or tension leg platform and for use on import or export risers.
Subsea Pipeline Products. We design and manufacture a variety of fittings and connectors used in offshore oil and gas pipelines. Our products are used for new construction, maintenance and repair applications. New construction fittings include:
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forged steel Y-shaped connectors for joining two pipelines into one;
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pressure-balanced safety joints for protecting pipelines and related equipment from anchor snags or a shifting sea-bottom;
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electrical isolation joints; and
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hot tap clamps that allow new pipelines to be joined into existing lines without interrupting the flow of petroleum product.
We provide diverless connection systems for subsea flowlines and pipelines. Our HydroTech® collet connectors provide a high-integrity, proprietary metal-to-metal sealing system for the final hook-up of deep offshore pipelines and production systems. They also are used in diverless pipeline repair systems and in future pipeline tie-in systems. Our lateral tie-in sled, which is installed with the original pipeline, allows a subsea tie-in to be made quickly and efficiently using proven HydroTech® connectors without costly offshore equipment mobilization and without shutting off product flow.
We provide pipeline repair hardware, including deepwater applications beyond the depth of diver intervention. Our products include:
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repair clamps used to seal leaks and restore the structural integrity of a pipeline;
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mechanical connectors used in repairing subsea pipelines without having to weld;
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flanges used to correct misalignment and swivel ring flanges; and
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pipe recovery tools for recovering dropped or damaged pipelines.
Marine Winches, Mooring and Lifting Systems and Rig Equipment. We design, engineer and manufacture marine winches, mooring and lifting systems and rig equipment. Our Skagit® winches are specifically designed for mooring floating and semi-submersible drilling rigs and positioning pipelay and derrick barges, anchor handling boats and jack-ups, while our Nautilus® marine cranes are used on production platforms throughout the world. We also design and fabricate rig equipment such as automatic pipe racking and blow-out preventor handling equipment. Our engineering teams, manufacturing capability and service technicians who install and service our products provide our customers with a broad range of equipment and services to support their operations. Aftermarket service and support of our installed base of equipment to our customers is also an important source of revenue to us.
BOP Stack Assembly, Integration, Testing and Repair Services. We design and fabricate lifting and protection frames and offer system integration of blow-out preventor stacks and subsea production trees. We can provide complete turnkey and design fabrication services. We also design and manufacture a variety of custom subsea equipment, such as riser flotation tank systems, guide bases, running tools and manifolds. In addition, we also offer blow-out preventor and drilling riser testing and repair services.
Other Products and Services. We provide equipment for securing subsea structures and offshore platform jackets, including our Hydra-Lok® hydraulic system. The Hydra-Lok® tool, which has been successfully used at depths of 3,000 feet, does not require diver intervention or guide lines.
We also provide cost-effective, standardized leveling systems for offshore structures that are anchored by foundation piles, including subsea templates, subsea manifolds and platform jackets.
Our offshore products segment also produces a variety of products for use in applications other than in the offshore oil and gas industry. For example, we provide:
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elastomer consumable downhole products for onshore drilling and production;
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metal-elastomeric FlexJoints® used in a variety of naval and marine applications; and
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drum-clutches and brakes for heavy-duty power transmission in the mining, paper, logging and marine industries.
Backlog. Backlog in our offshore products segment was $362.2 million at December 31, 2007, compared to $349.3 million at December 31, 2006 and $110.7 million at December 31, 2005. We expect in excess of 85% of our backlog at December 31, 2007 to be completed in 2008. Our offshore products backlog consists of firm customer purchase orders for which contractual commitments exist and delivery is scheduled. In some instances, these purchase orders are cancelable by the customer, subject to the payment of termination fees and/or the reimbursement of our costs incurred. Although our backlog is an important indicator of future offshore products shipments
and revenues, backlog as of any particular date may not be indicative of our actual operating results for any future period. We believe that the offshore construction and development business is characterized by lengthy projects and a long “lead-time” order cycle. The change in backlog levels from one period to the next does not necessarily evidence a long-term trend.
Regions of Operations
Our offshore products segment provides products and services to customers in the major offshore oil and gas producing regions of the world, including the Gulf of Mexico, West Africa, Azerbaijan, the North Sea, Brazil and Southeast Asia.
Customers and Competitors
We market our products and services to a broad customer base, including the direct end users, engineering and design companies, prime contractors, and at times, our competitors through outsourcing arrangements. Our largest customer in the offshore products markets in 2007 was Noble Corporation.
Tubular Services
Overview
During the year ended December 31, 2007, we generated approximately 41% of our revenue and 12% of our operating income, before corporate charges, from our tubular services segment. Through this segment, we distribute OCTG and provide associated OCTG finishing and logistics services to the oil and gas industry. OCTG consist of downhole casing and production tubing. Through our tubular services segment, we:
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distribute a broad range of casing and tubing;
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provide threading, remediation, logistical and inventory management services; and
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offer e-commerce pricing, ordering, tracking and financial reporting capabilities.
We serve a customer base ranging from major oil companies to small independents. Through our key relationships with more than 20 domestic and foreign manufacturers and related service providers and suppliers of OCTG we deliver tubular products and ancillary services to oil and gas companies, drilling contractors and consultants predominantly in the United States. The OCTG distribution market is highly fragmented and competitive, and is focused in the United States. We purchase tubular goods from a variety of sources. However, during 2007, we purchased from a single domestic supplier 61% of the tubular goods we distributed and from three domestic suppliers approximately 81% of such tubular goods.
OCTG Market
Our tubular services segment primarily distributes casing and tubing. Casing forms the structural wall in oil and gas wells to provide support, control pressure and prevent caving during drilling operations. Casing is also used to protect water-bearing formations during the drilling of a well. Casing is generally not removed after it has been installed in a well. Production tubing, which is used to bring oil and gas to the surface, may be replaced during the life of a producing well.
A key indicator of domestic demand for OCTG is the aggregate footage of wells drilled onshore and offshore in the United States. The OCTG market at any point in time is also affected by the level of inventories maintained by manufacturers, distributors and end users. Demand for tubular products is positively impacted by increased drilling of deeper, horizontal and offshore wells. Deeper wells require incremental tubular footage and enhanced mechanical capabilities to ensure the integrity of the well. Premium tubulars are used in horizontal drilling to withstand the increased bending and compression loading associated with a horizontal well. Operators typically specify premium tubulars for the completion of offshore wells.
Products and Services
Tubular Products and Services. We distribute various types of OCTG produced by both domestic and foreign manufacturers to major and independent oil and gas exploration and production companies and other OCTG distributors. We do not manufacture any of the tubular goods that we distribute. As a result, gross margins in this segment are generally lower than those reported by our other segments. We operate our tubular services segment from a total of eight offices and facilities located near areas of oil and gas exploration and development activity. We have distribution relationships with most major domestic and certain international steel mills.
In this business, inventory management is critical to our success. We maintain on-the-ground inventory in approximately 60 yards located in the United States, giving us the flexibility to fill our customers’ orders from our own stock or directly from the manufacturer. We have a proprietary inventory management system, designed specifically for the OCTG industry, that enables us to track our product shipments down to the individual joint of pipe.
A-Z Terminal. Our A-Z Terminal pipe maintenance and storage facility in Crosby, Texas is equipped to provide a full range of tubular services, giving us strong customer service capabilities. Our A-Z Terminal is on 109 acres, is an ISO 9001-certified facility and has a rail spur and more than 1,400 pipe racks and two double-ended thread lines. We have exclusive use of a permanent third-party inspection center within the facility. The facility also includes indoor chrome storage capability and patented pipe cleaning machines.
We offer services at our A-Z Terminal facility typically outsourced by other distributors, including the following: threading, inspection, cleaning, cutting, logistics, rig returns, installation of float equipment and non-destructive testing.
Other Facilities. We also offer tubular services at our facilities in Midland, Texas and Godley, Texas. Our Midland, Texas facility covers approximately 60 acres and has more than 400 pipe racks. Our Godley, Texas facility, which services the Barnett shale area, has approximately 60 pipe racks on approximately 13 developed acres and is serviced by a rail spur. Independent third party inspection companies operate within these facilities. In 2007, we opened a facility in Searcy, Arkansas to serve the growing needs of the Fayetteville Shale.
Tubular Products and Services Sales Arrangements. We provide our tubular products and logistics services through a variety of arrangements, including spot market sales and alliances. We provide some of our tubular products and services to independent and major oil and gas companies under alliance (or “program”) arrangements. Although our alliances are generally not as profitable as the spot market and can be cancelled by the customer, they provide us with more stable and predictable revenues and an improved ability to forecast required inventory levels, which allows us to manage our inventory more efficiently.
Regions of Operations
Our tubular services segment provides tubular products and services principally to customers in the United States both for land and offshore applications. However, we also sell a small percentage for export worldwide.
Customers, Suppliers and Competitors
Our largest end-user customers in the tubular distribution market in 2007 were Chesapeake Energy Corporation and ConocoPhillips. Our largest suppliers were U.S. Steel Group and Tenaris Global Services USA Corporation (formerly Maverick Tube Corporation). Although we have a leading market share position in tubular services distribution, the market is highly fragmented. Our main competitors in tubular distribution are privately owned distributors including Premier Pipe L.P., Red Man Pipe & Supply Co., Inc., Bourland and Leverich and Pipeco Services.
Employees
As of December 31, 2007, we had 6,551 full-time employees, 27% of whom are in our offshore products segment, 70% of whom are in our well site services segment, 2% of whom are in our tubular services segment and 1% of whom are in our corporate headquarters. We are party to collective bargaining agreements covering
779 employees located in Canada and the United Kingdom as of December 31, 2007. We believe relations with our employees are good.
Government Regulation
Our business is significantly affected by foreign, federal, state and local laws and regulations relating to the oil and natural gas industry, worker safety and environmental protection. Changes in these laws, including more stringent regulations and increased levels of enforcement of these laws and regulations, could significantly affect our business. We cannot predict changes in the level of enforcement of existing laws and regulations or how these laws and regulations may be interpreted or the effect changes in these laws and regulations may have on us or our future operations or earnings. We also are not able to predict whether additional laws and regulations will be adopted.
We depend on the demand for our products and services from oil and natural gas companies. This demand is affected by changing taxes, price controls and other laws and regulations relating to the oil and gas industry generally, including those specifically directed to oilfield and offshore operations. The adoption of laws and regulations curtailing exploration and development drilling for oil and natural gas in our areas of operation could also adversely affect our operations by limiting demand for our products and services. We cannot determine the extent to which our future operations and earnings may be affected by new legislation, new regulations or changes in existing regulations or enforcement.
Some 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 operate to make the liability limits established under states’ workers’ compensation laws inapplicable to these employees and permit them or their representatives generally to pursue actions against us for damages or job-related injuries with no limitations on our potential liability.
Our operations are subject to numerous foreign, federal, state and local environmental laws and regulations governing the release and/or discharge of materials into the environment or otherwise relating to environmental protection. Numerous governmental agencies issue regulations to implement and enforce these laws, for which compliance is often costly and difficult. The violation of these laws and regulations may result in the denial or revocation of permits, issuance of corrective action orders, modification or cessation of operations, assessment of administrative and civil penalties, and even criminal prosecution. We believe that we are in substantial compliance with applicable environmental laws and regulations. Further, we do not anticipate that compliance with existing environmental laws and regulations will have a material effect on our consolidated financial statements. However, there can be no assurance that substantial costs for compliance will not be incurred in the future. Moreover, it is possible that other developments, such as the adoption of stricter environmental laws, regulations and enforcement policies or more stringent enforcement of existing environmental laws and regulations, could result in additional costs or liabilities that we cannot currently quantify.
We generate wastes, including hazardous wastes, that are subject to the federal Resource Conservation and Recovery Act, or RCRA, and comparable state statutes. The United States Environmental Protection Agency, or EPA, and state agencies have limited the approved methods of disposal for some types of hazardous and nonhazardous wastes. Some wastes handled by us in our field service activities that currently are exempt from treatment as hazardous wastes may in the future be designated as “hazardous wastes” under RCRA or other applicable statutes. This would subject us to more rigorous and costly operating and disposal requirements.
With regard to our U.S. operations, the federal Comprehensive Environmental Response, Compensation, and Liability Act, or CERCLA, also know as the “Superfund” law, and comparable state statutes impose liability, without regard to fault or legality of the original conduct, on classes of persons that are considered to have contributed to the release of a hazardous substance into the environment. These persons include the owner or operator of the disposal site or the site where the release occurred and companies that transported, disposed of, or arranged for the disposal of the hazardous substances at the site where the release occurred. Under CERCLA, these persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources, and it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the
hazardous substances released into the environment. We currently have operations in the United States on properties where activities involving the handling of hazardous substances or wastes may have been conducted prior to our operations on such properties or by third parties whose operations were not under our control. These properties may be subject to CERCLA, RCRA and analogous state laws. Under these laws and related regulations, we could be required to remove or remediate previously discarded hazardous substances and wastes or property contamination that was caused by these third parties. These laws and regulations may also expose us to liability for our acts that were in compliance with applicable laws at the time the acts were performed.
In the course of our domestic operations, some of our equipment may be exposed to naturally occurring radiation associated with oil and gas deposits, and this exposure may result in the generation of wastes containing naturally occurring radioactive materials or “NORM.” NORM wastes exhibiting trace levels of naturally occurring radiation in excess of established state standards are subject to special handling and disposal requirements, and any storage vessels, piping, and work area affected by NORM may be subject to remediation or restoration requirements. Because many of the properties presently or previously owned, operated, or occupied by us have been used for oil and gas production operations for many years, it is possible that we may incur costs or liabilities associated with elevated levels of NORM.
The Federal Water Pollution Control Act and analogous state laws impose restrictions and strict controls regarding the discharge of pollutants into state waters or waters of the United States. The discharge of pollutants into jurisdictional waters is prohibited unless the discharge is permitted by the EPA or applicable state agencies. Many of our domestic properties and operations require permits for discharges of wastewater and/or stormwater, and we have a system for securing and maintaining these permits. In addition, the Oil Pollution Act of 1990 imposes a variety of requirements on responsible parties related to the prevention of oil spills and liability for damages, including natural resource damages, resulting from such spills in waters of the United States. A responsible party includes the owner or operator of a facility or vessel, or the lessee or permittee of the area in which an offshore facility is located. The Federal Water Pollution Control Act and analogous state laws provide for administrative, civil and criminal penalties for unauthorized discharges and, together with the Oil Pollution Act, impose rigorous requirements for spill prevention and response planning, as well as substantial potential liability for the costs of removal, remediation, and damages in connection with any unauthorized discharges.
Some of our operations also result in emissions of regulated air pollutants. The federal Clean Air Act and analogous state laws require permits for facilities in the United States that have the potential to emit substances into the atmosphere that could adversely affect environmental quality. Failure to obtain a permit or to comply with permit requirements could result in the imposition of substantial administrative, civil and even criminal penalties.
In response to recent studies suggesting that emissions of certain gases may be contributing to warming of the Earth’s atmosphere, many foreign nations, including Canada, have agreed to limit emissions of these gases, generally referred to as “greenhouse gases,” pursuant to the United Nations Framework Convention on Climate Change, also known as the “Kyoto Protocol”. The Kyoto Protocol requires Canada to reduce its emissions of greenhouse gases to 6% below 1990 levels by 2012. As a result, it is possible that already stringent air emissions regulations applicable to our operations in Canada will be replaced with even stricter requirements prior to 2012. Methane, a primary component of natural gas, and carbon dioxide, a byproduct of the burning of fossil fuels, are examples of greenhouse gases. Although the United States is not participating in the Kyoto Protocol, the current session of the U.S. Congress is considering climate change-related legislation to restrict greenhouse gas emissions. One bill recently approved by the U.S. Senate Environment and Public Works Committee, known as the Lieberman-Warner Climate Security Act or S.2191, would require a 70% reduction in emissions of greenhouse gases from sources within the United States between 2012 and 2050. The Lieberman-Warner bill proposes a “cap and trade” scheme of regulation of greenhouse gas emissions - a ban on emissions above a defined reducing annual cap. A vote on this bill by the full Senate is expected to occur before mid-year 2008. In addition, at least 17 states have already taken legal measures to reduce emissions of greenhouse gases, primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs. In 2007, the Western Climate Initiative, which is comprised of a number of Western states, including the state of Utah, and Canadian provinces issued a greenhouse gas reduction goal statement in which it announced a goal to collectively reduce regional greenhouse gas emissions to 15% below 2005 levels by 2020. Additionally, the state of New Mexico recently enacted greenhouse gas emissions reporting requirements.
Most of the cap and trade programs work by requiring either major sources of emissions, such as electric power plants, or major producers of fuels, such as refineries or gas processing plants, to acquire and surrender emission allowances. The number of allowances available for purchase is reduced each year until the overall greenhouse gas emission reduction goal is achieved. Depending on the particular program, our customers could be required to purchase and surrender allowances, either for greenhouse gas emissions resulting from their operations or from combustion of fuels (such as oil or natural gas) they produce. A stringent greenhouse gas control program could have an adverse effect on our customers’ cost of doing business and could reduce demand for the oil and gas they produce and thus have an adverse affect on the demand for our products and services.
Also, as a result of the U.S. Supreme Court’s decision on April 2, 2007 in Massachusetts, et al. v. EPA, the EPA may be required to regulate carbon dioxide and other greenhouse gas emissions from mobile sources (such as cars and trucks) even if Congress does not adopt new legislation specifically addressing emissions of greenhouse gases. The EPA has indicated that it will issue a rulemaking notice to address carbon dioxide and other greenhouse gas emissions from vehicles and automobile fuels, although the date for issuance of this notice has not been finalized. The Court’s holding in Massachusetts that greenhouse gases including carbon dioxide fall under the federal Clean Air Act’s definition of “air pollutant” may also result in future regulation of carbon dioxide and other greenhouse gas emissions from stationary sources under certain Clean Air Act programs. New federal or state restrictions on emissions of carbon dioxide that may be imposed in areas of the United States in which we conduct business could also adversely affect our cost of doing business and demand for oil and gas and thus demand for our products and services.
Our operations outside of the United States are potentially subject to similar foreign governmental controls relating to protection of the environment. We believe that, to date, our operations outside of the United States have been in substantial compliance with existing requirements of these foreign governmental bodies and that such compliance has not had a material adverse effect on our operations. However, there is no assurance that this trend of compliance will continue in the future or that such compliance will not be material. For instance, any future restrictions on emissions of greenhouse gases that are imposed in foreign countries in which we operate, such as in Canada, pursuant to the Kyoto Protocol or other locally enforceable requirements could adversely affect demand for our services.
Item 1A.
Item 1A.
Risk Factors
Risks Related to Our Business Generally
Decreased oil and gas industry expenditure levels will adversely affect our results of operations.
We depend upon the oil and gas industry and its ability and willingness to make expenditures which are directly affected by trends in oil and natural gas prices. Demand for our products and services is particularly sensitive to the level of exploration, development and production activity of, and the corresponding capital spending by, oil and natural gas companies, including national oil companies. If our customers’ expenditures decline, our business will suffer. The industry’s willingness to explore, develop and produce depends largely upon the availability of attractive drilling prospects and the prevailing view of future product prices. Prices for oil and natural gas are subject to large fluctuations in response to relatively minor changes in the supply of and demand for oil and natural gas, market uncertainty, and a variety of other factors that are beyond our control. A sudden or long term decline in product pricing could materially adversely affect our results of operations. Any prolonged reduction in oil and natural gas prices will depress levels of exploration, development, and production activity, often reflected as reductions in rig counts. Such lower activity levels could materially adversely affect our revenue and profitability. Additionally, significant new regulatory requirements, including climate change legislation, could have an impact on the demand for and the cost of producing oil and gas. Many factors affect the supply and demand for oil and gas and therefore influence product prices, including:
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the level of production;
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the levels of oil and gas inventories;
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the expected cost of developing new reserves;
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the actual cost of finding and producing oil and gas;
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the availability of attractive oil and gas field prospects which may be affected by governmental actions or environmental activists which may restrict drilling;
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the availability of transportation infrastructure, refining capacity and shifts in end-customer preferences toward fuel efficiency and the use of natural gas;
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depletion rates;
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the level of drilling activity;
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global weather conditions and natural disasters;
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worldwide economic activity including growth in underdeveloped countries, including China and India;
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national government political requirements, including the ability of the Organization of Petroleum Exporting Companies (OPEC) to set and maintain production levels and prices for oil and government policies which could nationalize or expropriate oil and gas exploration, production, refining or transportation assets;
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the impact of armed hostilities involving one or more oil producing nations;
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the timing and extent of alternative energy sources, including liquefied natural gas (LNG) or other alternative fuels;
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environmental regulation; and
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tax policies.
Extended periods of low oil prices or unsuccessful exploration results may decrease deepwater exploration and production activity or oil sands development and production in Canada and adversely affect our business.
Our offshore products segment depends on exploration and production expenditures in deepwater areas. Because deepwater projects are more capital intensive and take longer to generate first production than shallow water and onshore projects, the economic analyses conducted by exploration and production companies typically assume lower prices for production from such projects to determine economic viability over the long term. The economic analyses conducted by exploration and production companies for very large oil sands developments are similar to those performed for deepwater projects with respect to oil price assumptions. Perceptions of longer-term lower oil prices by these companies can reduce or defer major expenditures given the long-term nature of many large scale development projects, which could adversely affect our revenues and profitability in our offshore products segment and our well site services segment.
Because the oil and gas industry is cyclical, our operating results may fluctuate.
Oil prices, which are presently near historical highs, have been and are expected to remain volatile. This volatility causes oil and gas companies and drilling contractors to change their strategies and expenditure levels. We have experienced in the past, and we may experience in the future, significant fluctuations in operating results based on these changes.
We do business in international jurisdictions whose regulatory environments and compliance regimes differ from those in the United States. Our business may suffer because our efforts to comply with United States laws and regulations could restrict our ability to do business in international jurisdictions, relative to our competitors who are not subject to United States laws and regulations.
Our international business operations include projects in countries where governmental corruption has been known to exist and where our competitors who are not subject to United States laws and regulations, such as the Foreign Corrupt Practices Act, can gain competitive advantages over us by securing business awards, licenses or other preferential treatment in those jurisdictions using methods that United States law and regulations prohibit us from using. For example, our non-U.S. competitors are not subject to the anti-bribery restrictions of the Foreign
Corrupt Practices Act, which make it illegal to give anything of value to foreign officials or employees or agents of nationally owned oil companies in order to obtain or retain any business or other advantage. We may be subject to competitive disadvantages to the extent that our competitors are able to secure business, licenses or other preferential treatment by making payments to government officials and others in positions of influence.
While we and our subsidiaries are committed to conducting business in a legal and ethical manner, there is a risk of violating the U.S. Foreign Corrupt Practices Act or other applicable anti-corruption regulations that generally prohibit the making of improper payments to foreign officials for the purpose of obtaining or retaining business. Violations 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.
We might be unable to employ a sufficient number of technical personnel.
Many of the products that we sell, especially in our offshore products segment, are complex and highly engineered and often must perform in harsh conditions. We believe that our success depends upon our ability to employ and retain technical personnel with the ability to design, utilize and enhance these products. In addition, our ability to expand our operations depends in part on our ability to increase our skilled labor force. The demand for skilled workers is high, and the supply is limited. We have already experienced high demand and increased wages for labor forces serving our well site services segment, notably in our accommodations business in Canada. Significant increases in the wages paid by competing employers could further result in a reduction of our skilled labor force, increases in the wage rates that we must pay or both. When these events occur, our cost structure increases and our growth potential could be impaired.
Our inability to control the inherent risks of acquiring and integrating businesses could adversely affect our operations.
Acquisitions have been, and our management believes acquisitions will continue to be, a key element of our business strategy. We may not be able to identify and acquire acceptable acquisition candidates on favorable terms in the future. We may be required to incur substantial indebtedness to finance future acquisitions and also may issue equity securities in connection with such acquisitions. Such additional debt service requirements could impose a significant burden on our results of operations and financial condition. The issuance of additional equity securities could result in significant dilution to stockholders. Acquisitions may not perform as expected when the acquisition was made and may be dilutive to our overall operating results. Additional risks we could face in connection with acquisitions include:
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retaining key employees of acquired businesses;
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retaining and attracting new customers of acquired businesses;
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increased administrative burden;
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developing our sales and marketing capabilities;
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managing our growth effectively;
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integrating operations;
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operating a new line of business; and
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increased logistical problems common to large, expansive operations.
If we fail to manage these risks successfully, our business could be harmed.
The level and pricing of tubular goods imported into the United States could decrease demand for our tubular goods inventory and adversely impact our results of operations. Also, if steel mills were to sell a substantial amount of goods directly to end users in the United States, our results of operations could be adversely impacted.
Lower-cost tubular goods from a number of foreign countries are imported into the U.S. tubular goods market. If the level of imported lower-cost tubular goods were to otherwise increase, our tubular services segment could be adversely affected to the extent that we then have higher-cost tubular goods in inventory or if prices and margins are driven down by increased supplies of tubular goods. If prices were to decrease significantly, we might not be able to profitably sell our inventory of tubular goods. In addition, significant price decreases could result in a longer holding period for some of our inventory, which could also have a material adverse effect on our tubular services segment.
We do not manufacture any of the tubular goods that we distribute. Historically, users of tubular goods in the United States, in contrast to outside the United States, have purchased tubular goods through distributors. If customers were to purchase tubular goods directly from steel mills, our results of operations could be adversely impacted.
We are subject to extensive and costly environmental laws and regulations that may require us to take actions that will adversely affect our results of operations.
All of our operations, especially our drilling and offshore products businesses, are significantly affected by stringent and complex foreign, federal, provincial, state and local laws and regulations governing the discharge of substances into the environment or otherwise relating to environmental protection. We could be exposed to liability for cleanup costs, natural resource damages and other damages as a result of our conduct that was lawful at the time it occurred or the conduct of, or conditions caused by, prior operators or other third parties. Environmental laws and regulations are subject to change in the future, possibly resulting in more stringent requirements. If existing regulatory requirements or enforcement policies change or are more stringently enforced, we may be required to make significant unanticipated capital and operating expenditures.
Any failure by us to comply with applicable environmental laws and regulations may result in governmental authorities taking actions against our business that could adversely impact our operations and financial condition, including the:
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issuance of administrative, civil and criminal penalties;
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denial or revocation of permits or other authorizations;
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reduction or cessation in operations; and
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performance of site investigatory, remedial or other corrective actions.
We may not have adequate insurance for potential liabilities.
Our operations are subject to many hazards. We face the following risks under our insurance coverage:
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we may not be able to continue to obtain insurance on commercially reasonable terms;
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we may be faced with types of liabilities that will not be covered by our insurance, such as damages from environmental contamination or terrorist attacks;
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the dollar amount of any liabilities may exceed our policy limits; and
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we may incur losses from interruption of our business that exceed our insurance coverage.
Even a partially uninsured or underinsured claim, if successful and of significant size, could have a material adverse effect on our results of operations or consolidated financial position.
We are subject to litigation risks that may not be covered by insurance.
In the ordinary course of business, we become the subject of various claims, lawsuits and administrative proceedings seeking damages or other remedies concerning our commercial operations, products, employees and other matters, including occasional claims by individuals alleging exposure to hazardous materials as a result of our products or operations. Some of these claims relate to the activities of businesses that we have sold, and some relate to the activities of businesses that we have acquired, even though these activities may have occurred prior to our acquisition of such businesses. We maintain insurance to cover many of our potential losses, and we are subject to various self-retentions and deductibles under our insurance. It is possible, however, that a judgment could be rendered against us in cases in which we could be uninsured and beyond the amounts that we currently have reserved or anticipate incurring for such matters.
We might be unable to compete successfully with other companies in our industry.
The markets in which we operate are highly competitive and certain of them have relatively few barriers to entry. The principal competitive factors in our markets are product and service quality and availability, responsiveness, experience, technology, equipment quality, reputation for safety and price. In some of our business segments, we compete with the oil and gas industry’s largest oilfield service providers. These large national and multi-national companies have longer operating histories, greater financial, technical and other resources and greater name recognition than we do. Several of our competitors provide a broader array of services and have a stronger presence in more geographic markets. In addition, we compete with several smaller companies capable of competing effectively on a regional or local basis. Our competitors may be able to respond more quickly to new or emerging technologies and services and changes in customer requirements. Some contracts are awarded on a bid basis, which further increases competition based on price. As a result of competition, we may lose market share or be unable to maintain or increase prices for our present services or to acquire additional business opportunities, which could have a material adverse effect on our business, financial condition and results of operations.
Our operations may suffer due to increased industry-wide capacity of certain types of equipment or assets.
The demand for and pricing of certain types of our assets and equipment, particularly our drilling rigs and some of our rental tool assets, is subject to the overall availability of such assets in the marketplace. If demand for our assets were to decrease or to the extent that we and our competitors increase our fleets in excess of current demand, we may encounter decreased pricing or utilization for our assets and services, which could adversely impact our operations and profits.
In addition, we have significantly increased our accommodations capacity in the oil sands region over the past two years based on our expectation for current and future customer demand for accommodations in the area. Should our customers build their own facilities to meet their accommodations needs or our competitors likewise increase their available accommodations, demand for our accommodations could decrease, negatively impacting the profitability of our well site services segment.
Development of permanent infrastructure in the oil sands region could negatively impact our accommodations business.
Our accommodations business specializes in providing housing and personnel logistics for work forces in remote areas which lack the infrastructure typically available in nearby towns and cities. If permanent towns, cities and municipal infrastructure develop in the oil sands region of Alberta, Canada, the demand for our accommodations could decrease as customer employees move to the region and choose to utilize permanent housing and food services.
We could be adversely affected by a recession in the U.S. or global economy.
A recessionary economic environment could result in lower energy demand and cause decreased oil and gas expenditure levels. A recession could also result in less capital being available to fund future growth. These potential developments could negatively impact profitability or limit our growth.
Risks Related to Our Operations
We may assume contractual risk in developing, manufacturing and delivering products in our offshore products business segment.
Many of our products from our offshore products segment are ordered by customers under frame agreements or project specific contracts. In some cases these contracts stipulate a fixed price for the delivery of our products and impose liquidated damages or late delivery fees if we do not meet specific customer deadlines. In addition, the final delivered products may include customer and third party supplied equipment, the delay of which can negatively impact our ability to deliver our products on time at our anticipated profitability.
In certain cases these orders include new technology or unspecified design elements. In some cases we may not be fully or properly compensated for the cost to develop and design the final products, negatively impacting our profitability on the projects. In addition, our customers, in many cases, request changes to the original design or bid specifications for which we may not be fully or properly compensated.
As is customary for our offshore products segment, we agree to provide products under fixed-price contracts, typically assuming responsibility for cost overruns. Our actual costs and any gross profit realized on these fixed-price contracts may vary from the initially expected contract economics. There is inherent risk in the estimation process and including significant unforeseen technical and logistical challenges or longer than expected lead times. A fixed-price contract may prohibit our ability to mitigate the impact of unanticipated increases in raw material prices (including the price of steel) through increased pricing. Depending on the size of a project, variations from estimated contract performance could have a significant impact on our operating results.
We are susceptible to seasonal earnings volatility due to adverse weather conditions in our regions of operations.
Our operations are directly affected by seasonal differences in weather in the areas in which we operate, most notably in Canada, the Rocky Mountain region and the Gulf of Mexico. A portion of our Canadian work force accommodations, catering and logistics operations is conducted during the winter months when the winter freeze in remote regions is required for exploration and production activity to occur. The spring thaw in these frontier regions restricts operations in the spring months and, as a result, adversely affects our operations and sales of products and services in the second and third quarters. Our operations in the Gulf of Mexico are also affected by weather patterns. Weather conditions in the Gulf Coast region generally result in higher drilling activity in the spring, summer and fall months with the lowest activity in the winter months. As a result of these seasonal differences, full year results are not likely to be a direct multiple of any particular quarter or combination of quarters. In addition, summer and fall drilling activity can be restricted due to hurricanes and other storms prevalent in the Gulf of Mexico and along the Gulf Coast. For example, during 2005, a significant disruption occurred in oil and gas drilling and production operations in the U.S. Gulf of Mexico due to damage inflicted by hurricanes Katrina and Rita.
We might be unable to protect our intellectual property rights.
We rely on a variety of intellectual property rights that we use in our offshore products and well site services segments, particularly our patents relating to our FlexJoint® technology and intervention tools utilized in the completion or workover of oil and gas wells. The market success of our technologies will depend, in part, on our ability to obtain and enforce our proprietary rights in these technologies, to preserve rights in our trade secret and non-public information, and to operate without infringing the proprietary rights of others. We may not be able to successfully preserve these intellectual property rights in the future and these rights could be invalidated, circumvented or challenged. If any of our patents or other intellectual property rights are determined to be invalid or unenforceable, or if a court limits the scope of claims in a patent or fails to recognize our trade secret rights, our competitive advantages could be significantly reduced in the relevant technology, allowing competition for our customer base to increase. In addition, the laws of some foreign countries in which our products and services may be sold do not protect intellectual property rights to the same extent as the laws of the United States. The failure of our
company to protect our proprietary information and any successful intellectual property challenges or infringement proceedings against us could adversely affect our competitive position.
If we do not develop new competitive technologies and products, our business and revenues may be adversely affected.
The market for our offshore products is characterized by continual technological developments to provide better performance in increasingly greater depths and harsher conditions. If we are not able to design, develop and produce commercially competitive products in a timely manner in response to changes in technology, our business and revenues will be adversely affected. In addition, competitors or customers may develop new technology which addresses similar or improved solutions to our existing technology. Should our technology, particularly in offshore products or in our rental tool business, become the less attractive solution, our operations and profitability would be negatively impacted.
Loss of key members of our management could adversely affect our business.
We depend on the continued employment and performance of key members of management. If any of our key managers resign or become unable to continue in their present roles and are not adequately replaced, our business operations could be materially adversely affected. We do not maintain “key man” life insurance for any of our officers.
If we have to write off a significant amount of goodwill, our earnings will be negatively affected.
As of December 31, 2007, goodwill represented approximately 20% of our total assets. We have recorded goodwill because we paid more for some of our businesses than the fair market value of the tangible and separately measurable intangible net assets of those businesses. Current accounting standards, which were effective January 1, 2002, require a periodic review of goodwill for impairment in value and a non-cash charge against earnings with a corresponding decrease in stockholders’ equity if circumstances indicate that the carrying amount will not be recoverable. See Note 6 to our Consolidated Financial Statements included in this Annual Report on Form 10-K.
If we were to lose a significant supplier of our tubular goods, we could be adversely affected.
During 2007, we purchased from a single domestic supplier approximately 61% of the tubular goods we distributed and from three domestic suppliers approximately 81% of such tubular goods. We do not have contracts with any of these suppliers. If we were to lose any of these suppliers or if production at one or more of the suppliers were interrupted, our tubular services segment and our overall business, financial condition and results of operations could be adversely affected. If the extent of the loss or interruption were sufficiently large, the impact on us would be material.
During periods of strong demand, we may be unable to obtain critical project materials on a timely basis.
Our operations depend on our ability to procure on a timely basis certain project materials, such as forgings, to complete projects in an efficient manner. Our inability to procure critical materials during times of strong demand could have a material adverse effect on our business and operations.
Employee and customer labor problems could adversely affect us
We are party to collective bargaining agreements covering 741 employees in Canada and 30 employees in the United Kingdom. In addition, our accommodations facilities serving oil sands development work in Northern Alberta, Canada house both union and non-union customer employees. We have not experienced strikes, work stoppages or other slowdowns in the recent past, but we cannot guarantee that we will not experience such events in the future. A prolonged strike, work stoppage or other slowdown by our employees or by the employees of our customers could cause us to experience a disruption of our operations, which could adversely affect our business, financial condition and results of operations.
Royalty levels imposed by governmental authorities can impact economics of oil and gas producers and, therefore, affect their demand for our accommodations
The government of Alberta increased the royalties payable by oil and gas companies in both traditional hydrocarbon production and in oil sands production. It is too early to determine how these increased royalties will ultimately impact our customers’ longer term spending plans, and, as a result, our oil sands accommodations operations. To the extent any increased royalties cause our customers to curtail their operations or spending plans, our oil sands accommodations operations could be adversely affected. At this time, we have not changed any of our announced plans to expand our oil sands accommodations.
Provisions contained in our certificate of incorporation and bylaws could discourage a takeover attempt, which may reduce or eliminate the likelihood of a change of control transaction and, therefore, the ability of our stockholders to sell their shares for a premium.
Provisions contained in our certificate of incorporation and bylaws, such as a classified board, limitations on the removal of directors, on stockholder proposals at meetings of stockholders and on stockholder action by written consent and the inability of stockholders to call special meetings, could make it more difficult for a third party to acquire control of our company. Our certificate of incorporation also authorizes our board of directors to issue preferred stock without stockholder approval. If our board of directors elects to issue preferred stock, it could increase the difficulty for a third party to acquire us, which may reduce or eliminate our stockholders’ ability to sell their shares of common stock at a premium.
Item 1B.
Item 1B.
Unresolved Staff Comments
None.
Item 2.
Item 2.
Properties
The following table presents information about our principal properties and facilities. Except as indicated below, we own all of these properties or facilities.
We have six tubular sales offices and a total of 67 rental tool supply and distribution points throughout the United States and Canada, Mexico and Argentina. Most of these office locations are leased and provide sales, technical support and personnel services to our customers. We also have various offices supporting our business segments which are both owned and leased.
On February 15, 2008, we acquired a waterfront facility on the Houston ship channel for use in our offshore products segment. The new waterfront facility will expand our ability to manufacture, assemble, test and load out larger subsea production and drilling rig equipment thereby expanding our capabilities. Also in February 2008, we purchased an accommodation lodge, with an existing capacity of 92 persons located on approximately 40 acres, in the oil sands area of Alberta, Canada.
Item 3.
Item 3.
Legal Proceedings
We are a party to various pending or threatened claims, lawsuits and administrative proceedings seeking damages or other remedies concerning our commercial operations, products, employees and other matters, including occasional claims by individuals alleging exposure to hazardous materials as a result of our products or operations. Some of these claims relate to matters occurring prior to our acquisition of businesses, and some relate to businesses we have sold. In certain cases, we are entitled to indemnification from the sellers of businesses and in other cases, we have indemnified the buyers of businesses from us. Although we can give no assurance about the outcome of pending legal and administrative proceedings and the effect such outcomes may have on us, we believe that any ultimate liability resulting from the outcome of such proceedings, to the extent not otherwise provided for or covered by indemnity or insurance, will not have a material adverse effect on our consolidated financial position, results of operations or liquidity.
Item 4.
Item 4.
Submission of Matters to a Vote of Security Holders
No matters were submitted to a vote of security holders during the fourth quarter of 2007.
PART II
Item 5.
Item 5.
Market for Registrant’s Common Equity, Related Stockholder Matters, and Issuer Purchases of Equity Securities
Common Stock Information
Our authorized common stock consists of 200,000,000 shares of common stock. There were 49,395,091 shares of common stock outstanding as of February 12, 2008, including 201,757 shares of common stock issuable upon exercise of exchangeable shares of one of our Canadian subsidiaries. These exchangeable shares, which were issued to certain former shareholders of PTI in the Combination, are intended to have characteristics essentially equivalent to our common stock prior to the exchange. For purposes of this Annual Report on Form 10-K, we have treated the shares of common stock issuable upon exchange of the exchangeable shares as outstanding. The approximate number of record holders of our common stock as of February 12, 2008 was 39. Our common stock is traded on the New York Stock Exchange under the ticker symbol OIS. The closing price of our common stock on February 12, 2008 was $35.42 per share.
The following table sets forth the range of high and low sale prices of our common stock.
We have not declared or paid any cash dividends on our common stock since our initial public offering and do not intend to declare or pay any cash dividends on our common stock in the foreseeable future. Furthermore, our existing credit facilities restrict the payment of dividends. Any future determination as to the declaration and payment of dividends will be at the discretion of our Board of Directors and will depend on then existing conditions, including our financial condition, results of operations, contractual restrictions, capital requirements, business prospects and other factors that our Board of Directors considers relevant. During the first quarter of 2005, our Board of Directors authorized the repurchase of up to $50 million of our common stock, par value $.01 per share, over a two year period. On August 25, 2006, an additional $50 million was approved for the repurchase program and the duration of the program was extended to August 31, 2008. On January 11, 2008, an additional $50 million was approved for the repurchase program and the duration of the program was extended to December 31, 2009. Through February 12, 2008, we have repurchased 2,769,932 shares of our common stock for $80.6 million under the repurchase program, leaving $69.4 million available for future share repurchases.
PERFORMANCE GRAPH
The following performance graph and chart compare the cumulative total stockholder return on the Company’s common stock to the cumulative total return on the Standard & Poor’s 500 Stock Index and Philadelphia OSX Index, an index of oil and gas related companies which represent an industry composite of the Company’s peer group, for the period from December 31, 2002 to December 31, 2007. The graph and chart show the value at the dates indicated of $100 invested at December 31, 2002 and assume the reinvestment of all dividends.
COMPARISON OF 5 YEAR CUMULATIVE TOTAL RETURN*
Among Oil States International, Inc., The S&P 500 Index
And The PHLX Oil Service Sector Index
Oil States International - NYSE
*
$100 invested on 12/31/02 in stock or index-including reinvestment of dividends. Fiscal year ending December 31.
(1)
This graph is not “soliciting material,” is not deemed filed with the SEC and is not to be incorporated by reference in any filing by us under the Securities Act of 1933, as amended (the “Securities Act”), or the Exchange Act, whether made before or after the date hereof and irrespective of any general incorporation language in any such filing.
(2)
The stock price performance shown on the graph is not necessarily indicative of future price performance. Information used in the graph was obtained from Research Data Group, Inc., a source believed to be reliable, but we are not responsible for any errors or omissions in such information.
Copyright © 2008, Standard & Poor’s, a division of The McGraw-Hill Companies, Inc. All rights reserved. www.researchdatagroup.com/S&P.htm
Equity Compensation Plans
The information relating to our equity compensation plans required by Item 5 is incorporated by reference to such information as set forth in Item 12. “Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters” contained herein.
Unregistered Sales of Equity Securities and Use of Proceeds
None.
Purchases of Equity Securities by the Issuer and Affiliated Purchases
(1)
On January 11, 2008, an additional $50 million was approved for the repurchase program and the duration of the program was extended to December 31, 2009, resulting in $69.4 million available for future share repurchases under the share repurchase program as of February 12, 2008.
Item 6.
Item 6.
Selected Financial Data
The selected financial data on the following pages include selected historical financial information of our company as of and for each of the five years ended December 31, 2007. The following data should be read in conjunction with Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations
and the Company’s financial statements, and related notes included in Item 8, Financial Statements and Supplementary Data of this Annual Report on Form 10-K.
Selected Financial Data
(In thousands, except per share amounts)
(1)
Our effective tax rate was affected by our net operating loss carry forwards in certain of the periods presented.
(2)
The term EBITDA as defined consists of net income plus interest, taxes, depreciation and amortization. EBITDA as defined is not a measure of financial performance under generally accepted accounting principles. You should not consider it in isolation from or as a substitute for net income or cash flow measures prepared in accordance with generally accepted accounting principles or as a measure of profitability or liquidity. Additionally, EBITDA as defined may not be comparable to other similarly titled measures of other companies. The Company has included EBITDA as defined as a supplemental disclosure because its management believes that EBITDA as defined provides useful information regarding its ability to service debt and to fund capital expenditures and provides investors a helpful measure for comparing its operating performance with the performance of other companies that have different financing and capital structures or tax rates. The Company uses EBITDA as defined to compare and to monitor the performance of its business segments to other comparable public companies and as one of the primary measures to benchmark for the award of incentive compensation under its annual incentive compensation plan.
We believe that net income is the financial measure calculated and presented in accordance with generally accepted accounting principles that is most directly comparable to EBITDA as defined. The following table reconciles EBITDA as defined with our net income, as derived from our financial information (in thousands):
Item 7.
Item 7.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
You should read the following discussion and analysis together with our consolidated financial statements and the notes to those statements included elsewhere in this Annual Report on Form 10-K.
Overview
We provide a broad range of products and services to the oil and gas industry through our offshore products, tubular services and well site services business segments. Demand for our products and services is cyclical and substantially dependent upon activity levels in the oil and gas industry, particularly our customers’ willingness to spend capital on the exploration for and development of oil and gas reserves. Demand for our products and services by our customers is highly sensitive to current and expected oil and natural gas prices. Generally, our tubular services and well site services segments respond more rapidly to shorter-term movements in oil and natural gas prices except for our accommodations activities supporting oil sands developments which are more tied to the long-term outlook for crude oil prices. Our offshore products segment provides highly engineered and technically
designed products for offshore oil and gas development and production systems and facilities. Sales of our offshore products and services depend upon the development of offshore production systems and pipelines, repairs and upgrades of existing offshore drilling rigs and construction of new offshore drilling rigs and vessels. In this segment, we are particularly influenced by deepwater drilling and production activities, which are driven largely by our customers’ longer-term outlook for oil and natural gas prices. Through our tubular services segment, we distribute a broad range of casing and tubing. Sales and gross margins of our tubular services segment depend upon the overall level of drilling activity, the types of wells being drilled (for example, deepwater wells usually require higher priced seamless alloy tubulars) and the level of OCTG inventory and pricing. Historically, tubular services’ gross margin expands during periods of rising OCTG prices and contracts during periods of decreasing OCTG prices. In our well site services business segment, we provide land drilling services, work force accommodations, catering and logistics and modular building construction services and rental tools. Demand for our drilling services is driven by land drilling activity in Texas, New Mexico, Ohio and in the Rocky Mountains area in the U.S. Our rental tools and services depend primarily upon the level of drilling, completion and workover activity in the U.S. and Canada. Our accommodations business is conducted primarily in Canada and its activity levels are currently being driven primarily by oil sands development activities in Northern Alberta.
We have a diversified product and service offering which has exposure to activities conducted throughout the oil and gas cycle. Demand for our tubular services and well site services segments are highly correlated to changes in the drilling rig count in the United States and Canada. The table below sets forth a summary of North American rig activity, as measured by Baker Hughes Incorporated, for the periods indicated.
The average North American rig count for the year ended December 31, 2007 was almost flat compared to the year ended December 31, 2006. The increases in the average U.S. land rig counts have contributed to increased well site services revenues, particularly in our U.S. rental tool and land drilling businesses. However, decreases in Canadian rig counts compared to 2006 have adversely impacted our rental tools and accommodations, catering and logistical services which support Canadian oil and gas drilling operations. For the year 2007, increased our accommodations, catering and logistical services revenues in support of oil sands developments in Canada compared to the year 2006 more than offset the impact of decreased Canadian conventional oil and gas drilling operations. Our well site services segment results for the year 2007 also benefited from capital spending, which aggregated $222 million in the twelve months ended December 31, 2007 in that segment and included $43 million invested in our drilling services business, $48 million in our rental tools business and $131 million invested in our accommodations business, primarily in support of oil sands development in Canada. In addition, well site services benefited from the acquisitions discussed below of two rental tool companies for aggregate consideration of $113 million.
During 2007, the results generated by our Canadian workforce accommodations, catering and logistics operations benefited from the strengthening of the Canadian currency. For the year ended December 31, 2007, the Canadian dollar was valued at an average exchange rate of $0.94 U.S. dollars compared to $0.88 for the year ended December 31, 2006, an increase of 6.8%.
We continue to seek to acquire businesses that we believe are a good strategic fit with our existing businesses. In July and August 2007, we acquired two rental tool businesses for total consideration of approximately $113 million, which was funded primarily with borrowings under our bank credit facility. The acquired businesses provide well testing and flowback services and completion - related rental tools in the U.S. market. The results of
operations of the acquired businesses have been included in the rental tools business within the well site services segment since the date of acquisition.
Forecasts of economic slowdowns and a potential recession in the U.S. and elsewhere in the world have been widely reported recently. Such an economic slowdown or recession could negatively impact the demand for and price of crude oil in the near term, and correspondingly have a negative impact on our operations. However, management believes that the longer term economic environment will recover, and oil and gas producers will continue to explore for and develop oil and gas reserves at an active pace based on their longer term views of supply and demand fundamentals and higher oil and gas price expectations compared to those expectations five years ago. Management estimates that approximately 55% to 65% of the Company’s revenues are dependent on North American natural gas drilling and completion activity with a significant amount of such revenues being derived from lower margin OCTG sales. As such, we estimate that our profitability is more evenly impacted by oil driven activity and natural gas driven activity. Our customers have increased their spending and commitments for deepwater offshore exploration and development which has benefited our offshore products segment. Our customers have also announced significant levels of expenditures for oil sands related projects in Canada, benefiting our well site services segment. We currently expect continued growth in activity for our accommodations business in the oil sands region as labor needs in the region are expected to double over the next three to five years, even after considering recent legislation increasing oil and gas royalty levels in the province of Alberta. We continue to focus on expansion opportunities and execution initiatives in these high growth markets supporting deepwater development and Canadian oil sands spending.
There can be no assurance that these trends will continue, and there is a risk that lower energy prices for sustained periods could negatively impact drilling and completion activity and, correspondingly, reduce oil and gas expenditures. Such a decline would be adverse to our business. In addition, particularly in our well site services segment, we must continue to monitor industry capacity additions in relationship to our own capital expenditures and expected returns, considering project risks and expected cash flows from such investments. In tubular services, we continue to monitor industry wide OCTG inventory levels, mill shipments, OCTG pricing and our inventory turnover levels.
Consolidated Results of Operations
YEAR ENDED DECEMBER 31, 2007 COMPARED TO YEAR ENDED DECEMBER 31,
We reported increased net income for the year ended December 31, 2007 of $203.4 million, or $3.99 per diluted share, as compared to $197.6 million, or $3.89 per diluted share, reported for the year ended December 31, 2006. Net income in 2007 included a pre-tax gain of $12.8 million, or an after tax gain of $0.17 per diluted share, on the sale of 14.95 million shares of Boots & Coots common stock. Net income in 2006 included the recognition of a non-cash, pre-tax gain of $11.3 million, or an after-tax gain of $0.12 per diluted share, on the sale of the Company’s workover services business to Boots & Coots. See Note 7 to the Consolidated Financial Statements included in this Annual Report on Form 10-K.
Revenues. Consolidated revenues increased $164.8 million, or 9%, in 2007 compared to 2006.
Our well site services revenues increased $58.7 million, or 9%, in 2007 compared to 2006.
Our accommodations business revenues decreased $1.2 million, or 0.4%, as a result of decreased oil and gas drilling activity levels in Canada and lower third party accommodations manufacturing revenues in the U.S. and Canada, which were only partially offset by higher revenues driven by increased activity in support of the oil sands developments in Canada.
Rental tools revenues increased $59.8 million, or 30%, in 2007 compared to 2006 as a result of two rental tool acquisitions completed during the third quarter, increased prices realized and capital additions made in both years, which were partially offset by decreased Canadian rental tool revenues in 2007 caused by reduced Canadian drilling and completion activity when compared to 2006.
Our drilling revenues increased $8.7 million, or 6%, in 2007 compared to 2006 as a result of an increased rig fleet size (three additional rigs) and higher dayrates, partially offset by lower utilization in 2007. Our utilization declined from 90.0% in 2006 to 79.3% in 2007 due primarily to softness in demand in West Texas, the impact of industry capacity additions and extended holiday downtime in the fourth quarter. The sale of our workover services business in March 2006 caused an $8.6 million decrease in revenues in 2007 compared to 2006.
Our offshore products revenues increased $138.1 million, or 35%, due to increased deepwater development spending and capital equipment upgrades by our customers which increased demand for our products and services.
Tubular services revenues decreased $32.0 million, or 4%, in 2007 compared to 2006 as a result of a 4.6% decrease in average selling prices per ton of OCTG partially offset by a 1% increase in tons shipped.
Cost of Sales and Service. Our consolidated cost of sales increased $134.2 million, or 9%, in 2007 compared to 2006 primarily as a result of an increase at offshore products of $109.2 million, or 37%. Our overall gross margin as a percent of revenues decreased to 23% in 2007 from 24% in 2006.
Our well site services gross margin as a percent of revenues was 43% in both 2007 and 2006. Our accommodations cost of sales decreased due to lower costs associated with fewer third party manufacturing projects in 2007 compared to 2006 and reduced activity in support of conventional Canadian drilling operations in 2007. Our accommodations gross margin as a percentage of revenues improved from 34% in 2006 to 42% in 2007 primarily because of capacity additions and economies of scale in our major oil sands lodges and lower manufacturing revenues, which generally earn lower margins than accommodations rentals or catering work.
Our rental tool cost of sales increased $41.1 million, or 44%, in 2007 compared to 2006 primarily as a result of operating costs associated with two acquisitions made in the third quarter of 2007 and higher costs associated with increased revenue at our existing rental tool businesses. Our rental tool gross margin decreased from 53% in 2006 to 48% in 2007 primarily as a result of margins attributable to one of the acquired business lines which are typically lower than our existing rental tool businesses and due to the mix of rental equipment and service personnel used in the business. In addition, cost of sales and gross margins decreased in Canada due to reduced rental activity.
Our drilling services cost of sales increased $19.2 million, or 28%, in 2007 compared to 2006 as a result of an increase in the number of rigs that we operate, increased wages paid to our employees and increased costs associated with footage-based drilling contracts in 2007. Increased costs coupled with lower utilization reduced our drilling services gross margin from 49% in 2006 to 38% in 2007.
Our offshore products cost of sales, on a percentage basis, increased approximately in line with the increase in offshore products revenues resulting in no change in the gross margin percentage for that segment.
Our tubular services gross margin as a percentage of revenues decreased from 9% to 6% in 2007 compared to 2006 primarily as a result of lower OCTG mill pricing and a more competitive tubular marketplace.
Selling, General and Administrative Expenses. SG&A increased $11.2 million, or 10%, in 2007 compared to 2006 due primarily to SG&A expense associated with two acquisitions made in the third quarter of 2007, increased salaries, wages and benefits and an increase in headcount. SG&A was 5.7% of revenues in the 2007 compared to 5.6% of revenues in 2006.
Depreciation and Amortization. Depreciation and amortization expense increased $16.4 million, or 30%, in 2007 compared to 2006 due primarily to capital expenditures made during the previous twelve months.
Operating Income. Consolidated operating income decreased $0.2 million, or 0.1%, in 2007 compared to 2006 primarily as a result of decreased tubular services operating income of $28.0 million, or 42%, which was partially offset by increases at offshore products of $26.5 million, or 47%, and at well site services of $2.5 million, or 1%.
Interest Expense and Interest Income. Interest expense decreased by $1.4 million, or 7% in 2007 compared to 2006 due to lower average debt levels. The weighted average interest rate on the Company’s revolving credit facility was 6.0% in 2007 compared to 6.2% in 2006. Interest income in 2007 and 2006 relates primarily to the subordinated notes receivable obtained in consideration for the sale of our hydraulic workover business. See Note 7 to the Consolidated Financial Statements included in this Annual Report on Form 10-K.
Equity in Earnings of Unconsolidated Affiliates. Our equity in earnings of unconsolidated affiliates is lower in 2007 than in 2006 due to lower earnings of Boots & Coots and the sale of 14.95 million shares of our investment in Boots & Coots in April 2007. Following this sale, our ownership interest decreased from 45.6% to approximately 15%.
Income Tax Expense. Our income tax provision for the year ended December 31, 2007 totaled $97.0 million, or 32.3% of pretax income, compared to $104.0 million, or 34.5% of pretax income, for the year ended December 31, 2006. Lower Canadian and other foreign taxes on income and dividends, a higher allowable manufacturing credit and the completion of the IRS audit of the Company’s 2004 federal income tax return, which resulted in a favorable adjustment in the Company’s allowance for uncertain tax positions, lowered the effective tax rate in the year ended December 31, 2007. In addition, our effective tax rates were higher in 2006 than 2007 because of the higher effective tax rate applicable to the gain on the sale of the workover services business recognized in 2006.
YEAR ENDED DECEMBER 31, 2006 COMPARED TO YEAR ENDED DECEMBER 31,
Revenues. Consolidated revenues increased $391.8 million, or 26%, in 2006 compared to 2005.
Our well site services revenues increased $109.0 million, or 20%, in 2006 compared to 2005.
Our accommodations business revenues increased $26.7 million, or 9%, in 2006 compared to 2005 primarily as a result of increased oil and gas drilling activity levels in Canada partially offset by lower third party accommodations manufacturing revenues in Canada.
Rental tools revenues increased $65.8 million, or 49%, in 2006 compared to 2005 due to year-over-year improvements in North American drilling and completion activity, contributions from capital expenditures in both years and acquisitions. Our drilling revenues increased $47.8 million, or 55%, in 2006 compared to 2005 as a result of an increased rig fleet size (four additional rigs), higher rates and higher utilization in 2006. The sale of our workover services business in March 2006 caused a $31.3 million decrease in revenues in 2006 compared to 2005.
Our offshore products revenues increased $118.5 million, or 44%, due to increased deepwater development spending and capital equipment upgrades by our customers.
Tubular services revenues increased $164.3 million, or 23%, in 2006 compared to 2005 due to increased U.S. drilling activity and contributions from an acquisition that closed in June 2005. For the year ended December 31, 2006, tons shipped increased by 19% compared to the same period in 2005. Our average OCTG selling prices increased 3.5% from the year 2005 to the year 2006.
Cost of Sales and Service. Our consolidated cost of sales increased $261.8 million, or 22%, in 2006 compared to 2005 primarily as a result of an increase at tubular services of $171.5 million, or 27%, and at offshore products of $84.4 million, or 40%. Our overall gross margin as a percent of revenues was 24% in 2006 compared to 21% in 2005.
Our well site services gross margin as a percent of revenues increased from 32% to 43% in 2006 compared to 2005. Our accommodations cost of sales decreased due to a large fabrication project delivered to a customer on a sale basis in 2005. Our accommodations gross margin as a percentage of revenues improved from 23% in 2005 to 34% in 2006 primarily because of lower manufacturing revenues, which generally earn lower margins than accommodations rentals or catering work.
Our rental tool cost of sales increased $26.0 million, or 38%, in 2006 compared to 2005 primarily as a result of operating costs associated with acquisitions made in the second quarter of 2005 and higher costs associated with increased revenue at our existing rental tool businesses. Our rental tool gross margin increased from 49% in 2005 to 53% in 2006 primarily as a result of increased prices realized.
Our drilling services cost of sales increased $15.2 million, or 28%, in 2006 compared to 2005 as a result of an increase in the number of rigs that we operate and increased wages paid to our employees. Increased rates coupled with higher utilizations increased our drilling services gross margin from 38% in 2005 to 49% in 2006.
Our offshore products cost of sales, on a percentage basis, increased approximately in line with the increase in offshore products revenues.
Our tubular services gross margin as a percent of revenues decreased from 12% to 9% in 2006 compared to 2005 as a result of an increase in relatively low margin carbon grade sales when compared to premium grade OCTG sales and less frequent OCTG mill price increases in 2006 when compared to 2005.
Selling, General and Administrative Expenses. SG&A increased $22.5 million, or 27%, in 2006 compared to 2005 due primarily to SG&A expense associated with acquisitions, higher ad valorem taxes for OCTG inventory, increased incentive compensation accruals, and higher stock compensation costs due, in part, to the adoption of SFAS 123R. SG&A was 5.6% of revenues in the 2006 compared to 5.5% of revenues in 2005.
Depreciation and Amortization. Depreciation and amortization expense increased $7.6 million, or 16%, in 2006 compared to 2005 due primarily to acquisitions and capital expenditures made during the previous twelve months.
Operating Income. Consolidated operating income increased $103.4 million, or 53%, in 2006 compared to 2005 primarily as a result of increases at well site services of $90.7 million, or 87%, and at offshore products of $29.4 million, or 111%, which were partially offset by decreased tubular services operating income of $8.4 million, or 11%.
Interest Expense and Interest Income. Interest expense increased by $5.5 million, or 39% in 2006 compared to 2005 due to higher average debt levels resulting from acquisitions and capital expenditures, combined with higher interest rates. The weighted average interest rate on the Company’s revolving credit facility was 6.2% for 2006 and 4.7% for 2005. Interest income increased in 2006 primarily because of the notes receivable resulting from the sale of our workover services business. See Note 7 to the Consolidated Financial Statements included in this Annual Report on Form 10-K.
Equity in Earnings of Unconsolidated Affiliates. Our equity in earnings of unconsolidated affiliates was higher in 2006 than in 2005 primarily because of the sale of our workover services business and resultant interest in Boots & Coots common stock, which we account for under the equity method. See Note 7 to the Consolidated Financial Statements included in this Annual Report on Form 10-K.
Income Tax Expense. Our income tax provision for the year ended December 31, 2006 totaled $104.0 million, or 34.5% of pretax income, compared to $60.7 million, or 33.3% of pretax income, for the year ended December 31, 2005. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Tax Matters” discussion below.
Liquidity and Capital Resources
Our primary liquidity needs are to fund capital expenditures, such as expanding our accommodations facilities, expanding and upgrading our manufacturing facilities and equipment, adding drilling rigs and increasing and replacing rental tool assets, funding new product development and general working capital needs. In addition, capital is needed to fund strategic business acquisitions. Our primary sources of funds have been cash flow from operations, proceeds from borrowings under our bank facilities and proceeds from our $175 million convertible note offering in 2005. See Note 8 to Consolidated Financial Statements included in this Annual Report on Form 10-K.
Cash totaling $247.9 million was provided by operations during the year ended December 31, 2007 compared to cash totaling $137.4 million provided by operations during the year ended December 31, 2006. During 2007, $15.9 million was used to fund working capital due primarily to growth in activity in our offshore products and Canadian accommodations segments. These increases in working capital were partially offset by a $70.0 million reduction in working capital for inventories in our tubular services segment in 2007. During 2006, $95.1 million was used to fund working capital due in part to increases in receivables and inventories in our offshore products segment given the growth in activity.
Cash was used in investing activities during the years ended December 31, 2007 and 2006 in the amount of $310.8 million and $114.2 million, respectively. Capital expenditures, including capitalized interest, totaled $239.6 million and $129.1 million during the years ended December 31, 2007 and 2006, respectively. Capital expenditures in both years consisted principally of purchases of assets for our well site services segment, particularly for accommodations investments made in support of Canadian oil sands development. Net proceeds from the sale of 14.95 million shares of Boots & Coots common stock totaled $29.4 million during the year ended December 31, 2007. See Note 7 to the Consolidated Financial Statements included in this Annual Report on Form 10-K.
During the year ended December 31, 2007, we expended cash of $103.1 million to acquire two rental tool businesses. Cash consideration paid for all of our acquisitions in the period was funded utilizing our existing bank credit facility.
Net cash of $60.6 million was provided by financing activities during the year ended December 31, 2007, primarily as a result of revolving credit borrowings partially offset by treasury stock purchases. A total of $11.2 million was used in financing activities during the year ended December 31, 2006, primarily as a result of treasury stock purchases and debt repayments partially offset by proceeds from stock option exercises.
During the first quarter of 2005, our Board of Directors authorized the repurchase of up to $50.0 million of our common stock, par value $.01 per share, over a two year period. On August 25, 2006, an additional $50.0 million was approved and the duration of the program was extended to August 31, 2008. On January 11, 2008, an additional $50.0 million was approved for the repurchase program and the duration of the program was again extended to December 31, 2009. Through February 12, 2008, a total of $80.6 million of our stock (2,769,932 shares), has been repurchased under this program, leaving a total of up to approximately $19.4 million ($69.4 million after the January 2008 authorization) remaining available under the program for share repurchases.
On December 13, 2007, we entered into an Incremental Assumption Agreement (the “Agreement”) with the lenders and other parties to our existing credit agreement dated as of October 30, 2003 (the “Credit Agreement”) in order to exercise the accordion feature (the “Accordion”) available under the Credit Agreement. The Accordion increased the total commitments under the Credit Agreement from $400 million to $500 million. In connection with the execution of the Agreement, the Total U.S. Commitments (as defined in the Credit Agreement) were increased from U.S. $300,000,000 to U.S. $325,000,000, and the Total Canadian Commitments (as defined in the Credit Agreement) were increased from U.S. $100,000,000 to U.S. $175,000,000. The Credit Agreement, which governs
our credit facility, contains customary financial covenants and restrictions, including restrictions on our ability to declare and pay dividends. Borrowings under the Credit Agreement are secured by a pledge of substantially all of our assets and the assets of our subsidiaries. Our obligations under the Credit Agreement are guaranteed by our significant subsidiaries. Borrowings under the Credit Agreement accrue interest at a rate equal to either LIBOR or another benchmark interest rate (at our election) plus an applicable margin based on our leverage ratio (as defined in the Credit Agreement). We must pay a quarterly commitment fee, based on our leverage ratio, on the unused commitments under the Credit Agreement. During the year 2007, our applicable margin over LIBOR ranged from 0.5% to 0.75% and it was 0.75% as of December 31, 2007. Our weighted average interest rate paid under the Credit Agreement was 6.0% during the year ended December 31, 2007 and 6.2% for the year ended December 31, 2006.
As of December 31, 2007, we had $303.9 million outstanding under the Credit Facility and an additional $10.8 million of outstanding letters of credit, leaving $185.3 million available to be drawn under the facility. In addition, we have other floating rate bank credit facilities in the U.S. and the U.K. that provide for an aggregate borrowing capacity of $9.0 million. As of December 31, 2007, we had $3.3 million outstanding under these other facilities and an additional $1.4 million of outstanding letters of credit leaving $4.3 million available to be drawn under these facilities. Our total debt represented 31.2% of our total debt and shareholder’s equity at December 31, 2007 compared to 32.2% at December 31, 2006.
In June 2005, we sold $175 million aggregate principal amount of 23/8% contingent convertible notes due 2025. The notes provide for a net share settlement, and therefore may be convertible, under certain circumstances, into a combination of cash, up to the principal amount of the notes, and common stock of the company, if there is any excess above the principal amount of the notes, at an initial conversion price of $31.75 per share. Shares underlying the notes were included in the calculation of diluted earnings per share during the year because our stock price exceeded the initial conversion price of $31.75 during the period. The terms of the notes require that our stock price in any quarter, for any period prior to July 1, 2023, be above 120% of the initial conversion price (or $38.10 per share) for at least 20 trading days in a defined period before the notes are convertible. Assuming the stock price contingency feature is met and the holders of the notes elect to convert when the stock price is $38.10 per share, we would be required to deliver $175 million in cash plus accrued interest and approximately 919,000 shares of common stock. For a more detailed description of our 23/8% contingent convertible notes, please see Note 8 to the Consolidated Financial Statements included in this annual report on Form 10-K.
As of December 31, 2007, we have classified the $175.0 million principal amount of our 23/8% Notes as a noncurrent liability because certain contingent conversion thresholds based on the Company’s stock price were not met at that date and, as a result, note holders could not present their notes for conversion during the quarter following the December 31, 2007 measurement date. The future convertibility and resultant balance sheet classification of this liability will be monitored at each quarterly reporting date and will be analyzed dependent upon market prices of the Company common stock during the prescribed measurement periods. As of December 31, 2007, the recent trading prices of the 23/8% Notes exceeded their conversion value due to the remaining imbedded conversion option of the holder. The trading price for the 23/8% Notes is dependent on current market conditions, the length of time until the first put / call date of the 23/8% Notes and general market liquidity, among other factors. Based on recent trading patterns of the 23/8% Notes, we do not currently expect any significant amount of the 23/8% Notes to convert over the next twelve months. In August 2007, the FASB issued proposed FASB Staff Position (FSP) No. APB 14-a, “Accounting for Convertible Debt Instruments That May Be Settled in Cash Upon Conversion (Including Partial Cash Settlement)” which, if issued, would change the accounting for our 23/8% Notes. Under the proposed new rules, for convertible debt instruments that may be settled entirely or partially in cash upon conversion, an entity would be required to separately account for the liability and equity components of the instrument in a manner that reflects the issuer’s nonconvertible debt borrowing rate. The effect of the proposed new rules on our 23/8% Notes is that the equity component would be classified as part of stockholders’ equity on our balance sheet and the value of the equity component would be treated as an original issue discount for purposes of accounting for the debt component of the 23/8% Notes. Higher non-cash interest expense would result by recognizing the accretion of the discounted carrying value of the debt component of the 23/8% Notes as interest expense over the estimated life of the 23/8% Notes using an effective interest rate method of amortization. However, there would be no effect on our cash interest payments. The proposed FSP has been delayed once to be effective in 2008; however it is expected to be delayed further and be effective for fiscal years beginning after December 15, 2008. This rule, if
enacted as proposed, will require retrospective application. The Company is currently evaluating the impact of this proposed FSP.
We currently expect to spend a total of approximately $282 million for capital expenditures during 2008 to expand our Canadian oil sands related accommodations facilities, to fund our other product and service offerings, and for maintenance and upgrade of our equipment and facilities. We expect to fund these capital expenditures with internally generated funds and proceeds from borrowings under our revolving credit facilities.
We believe that cash from operations and available borrowings under our credit facilities will be sufficient to meet our liquidity needs in 2008. If our plans or assumptions change or are inaccurate, or if we make further acquisitions, we may need to raise additional capital. However, there is no assurance that we will be able to raise additional funds or be able to raise such funds on favorable terms.
The following summarizes our contractual obligations at December 31, 2007 (in thousands):
(1)
Excludes interest on debt.
In September 2006, we entered into a construction agreement to build a new office facility for our offshore products operations in Houston, Texas. The total cost of this facility is expected to be approximately $7.0 million and is expected to be completed by March 2008. Upon completion of this facility, we will enter into a 21 year capital lease, which is not yet included in the table above, with annual payments totaling approximately $725 thousand.
Our debt obligations at December 31, 2007 are included in our consolidated balance sheet, which is a part of our consolidated financial statements included in this Annual Report on Form 10-K. We have not entered into any material leases subsequent to December 31, 2007.
Off-Balance Sheet Arrangements
As of December 31, 2007, we had no off-balance sheet arrangements as defined in Item 303(a)(4) of Regulation S-K.
Tax Matters
Our primary deferred tax assets at December 31, 2007, are related to employee benefit costs for our Equity Participation Plan and our Annual Incentive Compensation Plan and to $19 million in available federal net operating loss carryforwards, or NOLs, as of that date. The NOLs will expire in varying amounts during the years 2010 through 2011 if they are not first used to offset taxable income that we generate. Our ability to utilize a significant portion of the available NOLs is currently limited under Section 382 of the Internal Revenue Code due to a change of control that occurred during 1995. We currently believe that substantially all of our NOLs will be utilized. The Company has federal alternative minimum tax net operating loss carryforwards of $1.5 million, which will expire in the years 2011 through 2020.
Our income tax provision for the year ended December 31, 2007 totaled $97.0 million, or 32.3% of pretax income. During the year ended December 31, 2007, the Company recognized a tax benefit triggered by employee exercises of stock options totaling $8.1 million. Such benefit, which lowered cash paid for taxes, was credited to additional paid-in capital. Our income tax provision for the year ended December 31, 2006 totaled $104.0 million, or 34.5% of pretax income.
Critical Accounting Policies
In our selection of critical accounting policies, our objective is to properly reflect our financial position and results of operations in each reporting period in a manner that will be understood by those who utilize our financial statements. Often we must use our judgment about uncertainties.
There are several critical accounting policies that we have put into practice that have an important effect on our reported financial results.
We have contingent liabilities and future claims for which we have made estimates of the amount of the eventual cost to liquidate these liabilities or claims. These liabilities and claims sometimes involve threatened or actual litigation where damages have been quantified and we have made an assessment of our exposure and recorded a provision in our accounts to cover an expected loss. Other claims or liabilities have been estimated based on our experience in these matters and, when appropriate, the advice of outside counsel or other outside experts. Upon the ultimate resolution of these uncertainties, our future reported financial results will be impacted by the difference between our estimates and the actual amounts paid to settle a liability. Examples of areas where we have made important estimates of future liabilities include litigation, taxes, interest, insurance claims, warranty claims, contract claims and discontinued operations.
The assessment of impairment on long-lived assets, including goodwill, intangibles and investments in unconsolidated subsidiaries, is conducted whenever changes in the facts and circumstances indicate a loss in value has occurred. The determination of the amount of impairment, which is other than a temporary decline in value, would be based on quoted market prices, if available, or upon our judgments as to the future operating cash flows to be generated from these assets throughout their estimated useful lives. Our industry is highly cyclical and our estimates of the period over which future cash flows will be generated, as well as the predictability of these cash flows and our determination of whether an other than temporary decline in value of our investment has occurred, can have a significant impact on the carrying value of these assets and, in periods of prolonged down cycles, may result in impairment charges.
We recognize revenue and profit as work progresses on long-term, fixed price contracts using the percentage-of-completion method, which relies on estimates of total expected contract revenue and costs. We follow this method since reasonably dependable estimates of the revenue and costs applicable to various stages of a contract can be made. Recognized revenues and profit are subject to revisions as the contract progresses to completion. Revisions in profit estimates are charged to income or expense in the period in which the facts and circumstances that give rise to the revision become known. Provisions for estimated losses on uncompleted contracts are made in the period in which losses are determined.
Our valuation allowances, especially related to potential bad debts in accounts receivable and to obsolescence or market value declines of inventory, involve reviews of underlying details of these assets, known trends in the marketplace and the application of historical factors that provide us with a basis for recording these allowances. If market conditions are less favorable than those projected by management, or if our historical experience is materially different from future experience, additional allowances may be required. We have, in past years, recorded a valuation allowance to reduce our deferred tax assets to the amount that is more likely than not to be realized (see Note 10 - Income Taxes in the Consolidated Financial Statements included in this Annual Report on Form 10-K and Tax Matters herein).
The selection of the useful lives of many of our assets requires the judgments of our operating personnel as to the length of these useful lives. Should our estimates be too long or short, we might eventually report a disproportionate number of losses or gains upon disposition or retirement of our long-lived assets. We believe our estimates of useful lives are appropriate.
Since the adoption of SFAS No. 123R, we are required to estimate the fair value of stock compensation made pursuant to awards under our 2001 Equity Participation Plan (Plan). An initial estimate of fair value of each stock option or restricted stock award determines the amount of stock compensation expense we will recognize in the future. To estimate the value of stock option awards under the Plan, we have selected a fair value calculation model. We have chosen the Black Scholes “closed form” model to value stock options awarded under the Plan. We have chosen this model because our option awards have been made under straightforward and consistent vesting terms,
option prices and option lives. Utilizing the Black Scholes model requires us to estimate the length of time options will remain outstanding, a risk free interest rate for the estimated period options are assumed to be outstanding, forfeiture rates, future dividends and the volatility of our common stock. All of these assumptions affect the amount and timing of future stock compensation expense recognition. We will continually monitor our actual experience and change assumptions for future awards as we consider appropriate.
In accounting for income taxes, we are required by the provisions of FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes, to estimate a liability for future income taxes. The calculation of our tax liabilities involves dealing with uncertainties in the application of complex tax regulations. We recognize liabilities for anticipated tax audit issues in the U.S. and other tax jurisdictions based on our estimate of whether, and the extent to which, additional taxes will be due. If we ultimately determine that payment of these amounts is unnecessary, we reverse the liability and recognize a tax benefit during the period in which we determine that the liability is no longer necessary. We record an additional charge in our provision for taxes in the period in which we determine that the recorded tax liability is less than we expect the ultimate assessment to be.
Recent Accounting Pronouncements
In September 2006, the FASB issued Statement of Financial Accounting Standards No. 157 (SFAS 157), “Fair Value Measurements,” which defines fair value, establishes guidelines for measuring fair value and expands disclosures regarding fair value measurements. SFAS 157 does not require any new fair value measurements but rather eliminates inconsistencies in guidance found in various prior accounting pronouncements. SFAS 157 is effective for fiscal years beginning after November 15, 2007. In February 2008, the FASB issued FASB Staff Position (FSP) 157-2, “Effective Date of FASB Statement No. 157,” which defers the effective date of Statement 157 for nonfinancial assets and nonfinancial liabilities, except for items that are recognized or disclosed at fair value in an entity’s financial statements on a recurring basis (at least annually), to fiscal years beginning after November 15, 2008, and interim periods within those fiscal years. Earlier adoption is permitted, provided the company has not yet issued financial statements, including for interim periods, for that fiscal year. As of January 1, 2008, the Company does not have any recurring fair value measurements and has opted for the deferral. Accordingly, the Company has not implemented and is currently evaluating the impact of SFAS 157, but does not expect the adoption of SFAS 157 to have a material impact on its results from operations or financial position.
In February 2007, the FASB issued Statement of Financial Accounting Standards No. 159 (SFAS 159), “The Fair Value Option for Financial Assets and Financial Liabilities - Including an amendment of FASB Statement No. 115.” SFAS 159 permits entities to measure eligible assets and liabilities at fair value. Unrealized gains and losses on items for which the fair value option has been elected are reported in earnings. SFAS 159 is effective for fiscal years beginning after November 15, 2007. As of January 1, 2008, the Company did not elect the fair value option on any financial instruments or certain other items as permitted by SFAS 159.
In August 2007, the FASB issued proposed FASB Staff Position (FSP) No. APB 14-a, “Accounting for Convertible Debt Instruments That May Be Settled in Cash Upon Conversion (Including Partial Cash Settlement)” which, if issued, would change the accounting for our 23/8% Contingent Convertible Senior Notes (2 3/8% Notes). Under the proposed new rules, for convertible debt instruments that may be settled entirely or partially in cash upon conversion, an entity would be required to separately account for the liability and equity components of the instrument in a manner that reflects the issuer’s nonconvertible debt borrowing rate. The effect of the proposed new rules on our 23/8% Notes is that the equity component would be classified as part of stockholders’ equity on our balance sheet and the value of the equity component would be treated as an original issue discount for purposes of accounting for the debt component of the 23/8% Notes. Higher non-cash interest expense would result by recognizing the accretion of the discounted carrying value of the 23/8% Notes as interest expense over the estimated life of the 23/8% Notes using an effective interest rate method of amortization. However, there would be no effect on our cash interest payments. The proposed FSP has been delayed once to be effective in 2008; however it is expected to be delayed further and be effective for fiscal years beginning after December 15, 2008. This rule, if enacted as proposed, will require retrospective application. The Company is currently evaluating the impact of this proposed FSP.
In December 2007, the FASB issued Statement of Financial Accounting Standards No. 141 (revised 2007) (SFAS 141R), “Business Combinations,” which replaces SFAS 141. SFAS 141R establishes principles and requirements for how an acquirer recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, any non-controlling interest in the acquiree and the goodwill acquired. The Statement also establishes disclosure requirements that will enable users to evaluate the nature and financial effects of the business combination. SFAS 141R is effective for fiscal years beginning after December 15, 2008. The adoption of SFAS 141R is not expected to have a material impact on the Company’s results from operations or financial position.
In December 2007, the FASB also issued Statement of Financial Accounting Standards No. 160 (SFAS 160), “Noncontrolling Interests in Consolidated Financial Statements - an amendment of ARB No. 51.” SFAS 160 requires that accounting and reporting for minority interests be recharacterized as noncontrolling interests and classified as a component of equity. SFAS 160 also establishes reporting requirements that provide sufficient disclosures that clearly identify and distinguish between the interests of the parent and the interests of the noncontrolling owners. SFAS 160 applies to all entities that prepare consolidated financial statements, except not-for-profit organizations, but will affect only those entities that have an outstanding noncontrolling interest in one or more subsidiaries or that deconsolidate a subsidiary. This statement is effective for fiscal years beginning after December 15, 2008. The adoption of SFAS 160 is not expected to have a material impact on our results from operations or financial position.
See also Note 10 - Income Taxes and Change in Accounting Principle for a discussion of the FASB’s Interpretation No. 48 - Accounting for Uncertainty in Income Taxes.
Item 7A.
Item 7A.
Quantitative And Qualitative Disclosures About Market Risk
Interest Rate Risk. We have long-term debt and revolving lines of credit that are subject to the risk of loss associated with movements in interest rates. As of December 31, 2007, we had floating rate obligations totaling approximately $307.2 million for amounts borrowed under our revolving credit facilities. These floating-rate obligations expose us to the risk of increased interest expense in the event of increases in short-term interest rates. If the floating interest rate were to increase by 1% from December 31, 2007 levels, our consolidated interest expense would increase by a total of approximately $3.1 million annually.
Foreign Currency Exchange Rate Risk. Our operations are conducted in various countries around the world and we receive revenue from these operations in a number of different currencies. As such, our earnings are subject to movements in foreign currency exchange rates when transactions are denominated in currencies other than the U.S. dollar, which is our functional currency, or the functional currency of our subsidiaries, which is not necessarily the U.S. dollar. In order to mitigate the effects of exchange rate risks, we generally pay a portion of our expenses in local currencies and a substantial portion of our contracts provide for collections from customers in U.S. dollars. During 2007, our realized foreign exchange losses were $0.9 million and are included in other operating expense (income) in the consolidated statements of income.
Item 8.
Item 8.
Financial Statements and Supplementary Data
Our consolidated financial statements and supplementary data of the Company appear on pages 51 through 79 of this Annual Report on Form 10-K and are incorporated by reference into this Item 8. Selected quarterly financial data is set forth in Note 15 to our Consolidated Financial Statements, which is incorporated herein by reference.
Item 9.
Item 9.
Changes in and Disagreements With Accountants on Accounting and Financial Disclosure
There were no changes in or disagreements on any matters of accounting principles or financial statement disclosure between us and our independent auditors during our two most recent fiscal years or any subsequent interim period.
Item 9A.
Item 9A.
Controls and Procedures
(i)
Evaluation of Disclosure Controls and Procedures
Evaluation of Disclosure Controls and Procedures. As of the end of the period covered by this Annual Report on Form 10-K, we carried out an evaluation, under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rule 13a-15(e) of the Securities Exchange Act of 1934, as amended). Based upon that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of December 31, 2007 in ensuring that material information was accumulated and communicated to management, and made known to our Chief Executive Officer and Chief Financial Officer, on a timely basis to ensure that information required to be disclosed in reports that we file or submit under the Exchange Act, including this Annual Report on Form 10-K, is recorded, processed, summarized and reported within the time periods specified in the Commission rules and forms.
Pursuant to section 906 of The Sarbanes-Oxley Act of 2002, our Chief Executive Officer and Chief Financial Officer have provided certain certifications to the Securities and Exchange Commission. These certifications accompanied this report when filed with the Commission, but are not set forth herein.
(ii)
Internal Control Over Financial Reporting
(a)
Management’s annual report on internal control over financial reporting.
The Company’s management report on internal control over financial reporting is set forth in this Annual Report on Form 10-K on Page 48 and is incorporated herein by reference.
(b)
Attestation report of the registered public accounting firm.
The attestation report of Ernst & Young LLP, the Company’s independent registered public accounting firm, on the Company’s internal control over financial reporting is set forth in this Annual Report on Form 10-K on Page 50 and is incorporated herein by reference.
(c)
Changes in internal control over financial reporting.
There was no change in the Company’s internal control over financial reporting during the Company’s fourth fiscal quarter ended December 31, 2007 that has materially affected, or is reasonably likely to affect, the Company’s internal control over financial reporting.
Item 9B.
Item 9B.
Other Information
There was no information required to be disclosed in a report on Form 8-K during the fourth quarter of 2007 that was not reported on a Form 8-K during such time.
PART III
Item 10.
Item 10.
Directors and Executive Officers of the Registrant
(1) Information concerning directors, including the Company’s audit committee financial expert, appears in the Company’s Definitive Proxy Statement for the 2008 Annual Meeting of Stockholders, under “Election of Directors.” This portion of the Definitive Proxy Statement is incorporated herein by reference.
(2) Information with respect to executive officers appears in the Company’s Definitive Proxy Statement for the 2008 Annual Meeting of Stockholders, under “Executive Officers of the Registrant.” This portion of the Definitive Proxy Statement is incorporated herein by reference.
(3) Information concerning Section 16(a) beneficial ownership reporting compliance appears in the Company’s Definitive Proxy Statement for the 2008 Annual Meeting of Stockholders, under “Section 16(a) Beneficial Ownership Reporting Compliance.” This portion of the Definitive Proxy Statement is incorporated herein by reference.
Item 11.
Item 11.
Executive Compensation
The information required by Item 11 hereby is incorporated by reference to such information as set forth in the Company’s Definitive Proxy Statement for the 2008 Annual Meeting of Stockholders.
Item 12.
Item 12.
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
The information required by Item 12 hereby is incorporated by reference to such information as set forth in the Company’s Definitive Proxy Statement for the 2008 Annual Meeting of Stockholders.
Item 13.
Item 13.
Certain Relationships and Related Transactions
The information required by Item 13 hereby is incorporated by reference to such information as set forth in the Company’s Definitive Proxy Statement for the 2008 Annual Meeting of Stockholders.
Item 14.
Item 14.
Principal Accounting Fees and Services
Information concerning principal accountant fees and services and the audit committee’s preapproval policies and procedures appear in the Company’s Definitive Proxy Statement for the 2008 Annual Meeting of Stockholders under the heading “Fees Paid to Ernst & Young LLP” and is incorporated herein by reference.
PART IV
Item 15.
Item 15.
Exhibits and Financial Statement Schedules
(a) Index to Financial Statements, Financial Statement Schedules and Exhibits
(1) Financial Statements: Reference is made to the index set forth on page 47 of this Annual Report on Form 10-K.
(2) Financial Statement Schedules: No schedules have been included herein because the information required to be submitted has been included in the Consolidated Financial Statements or the Notes thereto, or the required information is inapplicable.
(3) Index of Exhibits: See Index of Exhibits, below, for a list of those exhibits filed herewith, which index also includes and identifies management contracts or compensatory plans or arrangements required to be filed as exhibits to this Annual Report on Form 10-K by Item 601(10)(iii) of Regulation S-K.
(b) Index of Exhibits
*
Filed herewith
**
Management contracts or compensatory plans or arrangements
***
Furnished herewith.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
OIL STATES INTERNATIONAL, INC.
By
/s/ CINDY B. TAYLOR
Cindy B. Taylor
Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of the registrant in the capacities indicated on February 22, 2008.
OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES
INDEX TO
CONSOLIDATED FINANCIAL STATEMENTS
OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES
MANAGEMENT’S ANNUAL REPORT ON INTERNAL CONTROL
OVER FINANCIAL REPORTING
To the Stockholders and Board of Directors of Oil States International, Inc.:
Our management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act. Our internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of consolidated financial statements for external purposes in accordance with accounting principles generally accepted in the United States (GAAP). Our internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of our assets; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with GAAP, and that our receipts and expenditures are being made only in accordance with authorizations of management and our directors; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of our assets that could have a material effect on the consolidated 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. Accordingly, even effective internal control over financial reporting can only provide reasonable assurance of achieving their control objectives.
Oil States International, Inc.’s management assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2007. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control - Integrated Framework. Based on our assessment we believe that, as of December 31, 2007, the Company’s internal control over financial reporting is effective based on those criteria.
During 2007, the Company acquired the businesses of Wire Line Service, Ltd. (Well Testing) and Schooner Petroleum Services, Inc. in separate purchase transactions. In reliance on guidance contained in a “Frequently Asked Questions” interpretive release issued by the staff of the SEC’s Office of Chief Accountant and Division of Corporation Finance in June 2004 (and revised on October 6, 2004), our management has elected to exclude Wire Line Service, Ltd. (Well Testing) and Schooner Petroleum Services, Inc. from the scope of our assessment of the effectiveness of the Company’s internal control over financial reporting as of December 31, 2007. These entities are wholly-owned subsidiaries of the Company at December 31, 2007. The total assets, net assets, revenues and operating income of Wire Line Service, Ltd. (Well Testing) and Schooner Petroleum Services, Inc. represent approximately 7.0%, 10.6%, 2.2% and 3.0%, respectively, of the consolidated total assets, net assets, revenues and operating income of the Company as of and for the year ended December 31, 2007.
Oil States International, Inc.’s independent registered public accounting firm has audited the Company’s internal control over financial reporting. This report appears on Page 50.
OIL STATES INTERNATIONAL, INC.
Houston, Texas
OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders of Oil States International, Inc.:
We have audited the accompanying consolidated balance sheets of Oil States International, Inc. and subsidiaries (the “Company”) as of December 31, 2007 and 2006, and the related consolidated statements of income, stockholders’ equity and comprehensive income, 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 the Company at December 31, 2007 and 2006, and the consolidated results of its operations and its 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 Note 10 to the consolidated financial statements, effective January 1, 2007 the Company adopted the provisions of Financial Accounting Standards Board Interpretation No. 48, Accounting for Uncertainty in Income Taxes an interpretation of FASB Statement No. 109 and as discussed in Note 2 to the consolidated financial statements and effective January 1, 2006 the Company adopted the provisions of Statement of Financial Accounting Standards No. 123 (revised 2004), Share-Based Payment.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company’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 19, 2008 expressed an unqualified opinion thereon.
ERNST & YOUNG LLP
Houston, Texas
February 19, 2008
OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders of Oil States International, Inc.:
We have audited Oil States International, Inc. and subsidiaries’ (the “Company”) 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”). The Company’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 Management’s Annual Report 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.
As indicated in the accompanying Management’s Annual Report on Internal Control Over Financial Reporting, management’s assessment of and conclusion on the effectiveness of internal control over financial reporting did not include the internal controls of Wire Line Services, Ltd. (“Well Testing”) and Schooner Petroleum Services, Inc. (“Schooner”), which are included in the 2007 consolidated financial statements of the Company and together constituted 7.0% and 10.6% of total and net assets, respectively, as of December 31, 2007 and 2.2% and 3.0% of revenues and operating income, respectively, for the year then ended. Our audit of internal control over financial reporting of the Company also did not include an evaluation of the internal control over financial reporting of Well Testing and Schooner.
In our opinion, the Company 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 the Company as of December 31, 2007 and 2006, and the related consolidated statements of income, stockholders’ equity and comprehensive income, and cash flows for each of the three years in the period ended December 31, 2007 and our report dated February 19, 2008 expressed an unqualified opinion thereon.
ERNST & YOUNG LLP
Houston, Texas
February 19, 2008
OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
The accompanying notes are an integral part of these financial statements.
OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
The accompanying notes are an integral part of these financial statements.
OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
AND COMPREHENSIVE INCOME
(In thousands)
The accompanying notes are an integral part of these financial statements.
OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
The accompanying notes are an integral part of these financial statements.
OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1.
Organization and Basis of Presentation
The consolidated financial statements include the accounts of Oil States International, Inc. (Oil States or the Company) and its consolidated subsidiaries. Investments in unconsolidated affiliates, in which the Company is able to exercise significant influence, are accounted for using the equity method. The Company’s operations prior to 2001 were conducted by Oil States Industries, Inc. (OSI). On February 14, 2001, the Company acquired three companies (HWC Energy Services, Inc. (HWC); PTI Group, Inc. (PTI) and Sooner Inc. (Sooner)). All significant intercompany accounts and transactions between the Company and its consolidated subsidiaries have been eliminated in the accompanying consolidated financial statements.
The Company, through its subsidiaries, is a leading provider of specialty products and services to oil and gas drilling and production companies throughout the world. It operates in a substantial number of the world’s active oil and gas producing regions, including the Gulf of Mexico, U.S. onshore, West Africa, the North Sea, Canada, South America and Southeast Asia. The Company operates in three principal business segments - offshore products, tubular services and well site services. The Company’s well site services segment includes the accommodations, rental tools and drilling services businesses.
2.
Summary of Significant Accounting Policies
Cash and Cash Equivalents
The Company considers all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents.
Fair Value of Financial Instruments
The Company’s financial instruments consist of cash and cash equivalents, investments, receivables, notes receivable, payable, and debt instruments. The Company believes that the carrying values of these instruments, other than our fixed rate contingent convertible senior notes, on the accompanying consolidated balance sheets approximate their fair values.
The fair value of our 23/8% contingent convertible senior notes is estimated based on prices quoted from third-party financial institutions. The carrying and fair values of these notes are as follows (in thousands):
Inventories
Inventories consist of tubular and other oilfield products, manufactured equipment, spare parts for manufactured equipment, raw materials and supplies and raw materials for accommodation facilities. Inventories include raw materials, labor, subcontractor charges and manufacturing overhead and are carried at the lower of cost or market. The cost of inventories is determined on an average cost or specific-identification method.
Property, Plant, and Equipment
Property, plant, and equipment are stated at cost, or at estimated fair market value at acquisition date if acquired in a business combination, and depreciation is computed, for assets owned or recorded under capital lease, using the straight-line method over the estimated useful lives of the assets. Leasehold improvements are capitalized and amortized over the lesser of the life of the lease or the estimated useful life of the asset.
OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Expenditures for repairs and maintenance are charged to expense when incurred. Expenditures for major renewals and betterments, which extend the useful lives of existing equipment, are capitalized and depreciated. Upon retirement or disposition of property and equipment, the cost and related accumulated depreciation are removed from the accounts and any resulting gain or loss is recognized in the statements of income.
Goodwill
Goodwill represents the excess of the purchase price for acquired businesses over the allocated value of the related net assets. Goodwill is stated net of accumulated amortization of $18.0 million at December 31, 2007 and $17.4 million at December 31, 2006.
Impairment of Long-Lived Assets
In compliance with Statement of Financial Accounting Standards (SFAS) No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets” the recoverability of the carrying values of property, plant and equipment is assessed at a minimum annually, or whenever, in management’s judgment, events or changes in circumstances indicate that the carrying value of such assets may not be recoverable based on estimated future cash flows. If this assessment indicates that the carrying values will not be recoverable, as determined based on undiscounted cash flows over the remaining useful lives, an impairment loss is recognized. The impairment loss equals the excess of the carrying value over the fair value of the asset. The fair value of the asset is based on prices of similar assets, if available, or discounted cash flows. Based on the Company’s review, the carrying value of its assets are recoverable, and no impairment losses have been recorded for the periods presented.
Foreign Currency and Other Comprehensive Income
Gains and losses resulting from balance sheet translation of foreign operations where a foreign currency is the functional currency are included as a separate component of accumulated other comprehensive income within stockholders’ equity representing substantially all of the balances within accumulated other comprehensive income. Gains and losses resulting from balance sheet translation of foreign operations where the U.S. dollar is the functional currency are included in the consolidated statements of income as incurred.
Foreign Exchange Risk
A portion of revenues, earnings and net investments in foreign affiliates are exposed to changes in foreign exchange rates. We seek to manage our foreign exchange risk in part through operational means, including managing expected local currency revenues in relation to local currency costs and local currency assets in relation to local currency liabilities. In the past, foreign exchange risk has also been managed through the use of derivative financial instruments and foreign currency denominated debt. These financial instruments serve to protect net income against the impact of the translation into U.S. dollars of certain foreign exchange denominated transactions. The financial instruments employed to manage foreign exchange risk consisted of forward exchange contracts with notional amounts of $1.5 million at December 31, 2005. The Company had no such contracts outstanding at December 31, 2007 or December 31, 2006. Net gains or losses from foreign currency exchange contracts that are designated as hedges are recognized in the income statement to offset the foreign currency gain or loss on the underlying transaction. Exchange gains and losses have totaled $0.9 million loss in 2007, a $0.4 million loss in 2006 and a $0.2 million gain in 2005 and are included in other operating income.
Interest Capitalization
Interest costs for the construction of certain long-term assets are capitalized and amortized over the related assets’ estimated useful lives. For the years ended December 31, 2007 and December 31, 2006, $1.0 million and $0.1 million was capitalized, respectively. No interest was capitalized in 2005.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Revenue and Cost Recognition
Revenue from the sale of products, not accounted for utilizing the percentage-of-completion method, is recognized when delivery to and acceptance by the customer has occurred, when title and all significant risks of ownership have passed to the customer, collectibility is probable and pricing is fixed and determinable. Our product sales terms do not include significant post delivery obligations. For significant projects built to customer specifications, revenues are recognized under the percentage-of-completion method, measured by the percentage of costs incurred to date to estimated total costs for each contract (cost-to-cost method). Billings on such contracts in excess of costs incurred and estimated profits are classified as deferred revenue. Management believes this method is the most appropriate measure of progress on large contracts. Provisions for estimated losses on uncompleted contracts are made in the period in which such losses are determined. In drilling services and rental tool services, revenues are recognized based on a periodic (usually daily) rental rate or when the services are rendered. Proceeds from customers for the cost of oilfield rental equipment that is damaged or lost downhole are reflected as gains or losses on the disposition of assets. For drilling services contracts based on footage drilled, we recognize revenues as footage is drilled. Revenues exclude taxes assessed based on revenues such as sales or value added taxes.
Cost of goods sold includes all direct material and labor costs and those costs related to contract performance, such as indirect labor, supplies, tools and repairs. Selling, general, and administrative costs are charged to expense as incurred.
Income Taxes
The Company follows the liability method of accounting for income taxes in accordance with SFAS No. 109, “Accounting for Income Taxes.” Under this method, deferred income taxes are recorded based upon the differences between the financial reporting and tax bases of assets and liabilities and are measured using the enacted tax rates and laws that will be in effect when the underlying assets or liabilities are recovered or settled.
When the Company’s earnings from foreign subsidiaries are considered to be indefinitely reinvested, no provision for U.S. income taxes is made for these earnings. If any of the subsidiaries have a distribution of earnings in the form of dividends or otherwise, the Company would be subject to both U.S. income taxes (subject to an adjustment for foreign tax credits) and withholding taxes payable to the various foreign countries.
In accordance with SFAS No. 109, the Company records a valuation reserve in each reporting period when management believes that it is more likely than not that any deferred tax asset created will not be realized. Management will continue to evaluate the appropriateness of the reserve in the future based upon the operating results of the Company.
In accounting for income taxes, we are required by the provisions of FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes,” to estimate a liability for future income taxes. The calculation of our tax liabilities involves dealing with uncertainties in the application of complex tax regulations. We recognize liabilities for anticipated tax audit issues in the U.S. and other tax jurisdictions based on our estimate of whether, and the extent to which, additional taxes will be due. If we ultimately determine that payment of these amounts is unnecessary, we reverse the liability and recognize a tax benefit during the period in which we determine that the liability is no longer necessary. We record an additional charge in our provision for taxes in the period in which we determine that the recorded tax liability is less than we expect the ultimate assessment to be.
Receivables and Concentration of Credit Risk, Concentration of Suppliers
Based on the nature of its customer base, the Company does not believe that it has any significant concentrations of credit risk other than its concentration in the oil and gas industry. The Company evaluates the credit-worthiness of its major new and existing customers’ financial condition and, generally, the Company does not require significant collateral from its domestic customers.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
The Company purchased 81% of its oilfield tubular goods from three suppliers in 2007, with the largest supplier representing 61% of its purchases in the period. The loss of any significant supplier in the tubular services segment could adversely affect it.
Allowances for Doubtful Accounts
The Company maintains allowances for doubtful accounts for estimated losses resulting from the inability of the Company’s customers to make required payments. If a trade receivable is deemed to be uncollectible, such receivable is charged-off against the allowance for doubtful accounts. The Company considers the following factors when determining if collection of revenue is reasonably assured: customer credit-worthiness, past transaction history with the customer, current economic industry trends, customer solvency and changes in customer payment terms. If the Company has no previous experience with the customer, the Company typically obtains reports from various credit organizations to ensure that the customer has a history of paying its creditors. The Company may also request financial information, including financial statements or other documents to ensure that the customer has the means of making payment. If these factors do not indicate collection is reasonably assured, the Company would require a prepayment or other arrangement to support revenue recognition and recording of a trade receivable. If the financial condition of the Company’s customers were to deteriorate, adversely affecting their ability to make payments, additional allowances would be required.
Earnings per Share
The Company’s basic income per share (EPS) amounts have been computed based on the average number of common shares outstanding, including 201,757 and 256,787 shares of common stock as of December 31, 2007 and 2006, respectively, issuable upon exercise of exchangeable shares of one of the Company’s Canadian subsidiaries. These exchangeable shares, which were issued to certain former shareholders of PTI in connection with the Company’s IPO and the combination of PTI into the Company, are intended to have characteristics essentially equivalent to the Company’s common stock prior to the exchange. We have treated the shares of common stock issuable upon exchange of the exchangeable shares as outstanding. Diluted EPS amounts include the effect of the Company’s outstanding stock options under the treasury stock method. All shares of restricted stock awarded under the Company’s Equity Participation Plan are included in the Company’s fully diluted shares.
Shares assumed issued upon conversion of the Company’s 23/8% Contingent Convertible Senior Subordinated Notes averaged 729,830 and 391,434 during the years ended December 31, 2007 and December 31, 2006, respectively, and are included in the calculation of fully diluted shares outstanding and fully diluted earnings per share.
Stock-Based Compensation
We adopted Statement of Financial Accounting Standards No. 123R (SFAS 123R), “Share-based Payment,” effective January 1, 2006. This pronouncement requires companies to measure the cost of employee services received in exchange for an award of equity instruments (typically stock options) based on the grant-date fair value of the award. The fair value is estimated using option-pricing models. The resulting cost is recognized over the period during which an employee is required to provide service in exchange for the awards, usually the vesting period. Prior to the adoption of SFAS 123R, this accounting treatment was optional with pro forma disclosures required. During the years ended December 31, 2007 and December 31, 2006, the Company recognized non-cash general and administrative expenses for stock options and restricted stock awards totaling $8.0 million and $7.6 million, respectively. Prior to the adoption of SFAS 123R, only shares of restricted stock awarded under The 2001 Equity Participation Plan of Oil States International Inc. (Equity Participation Plan) were considered to be compensatory in nature. Accordingly, the Company recognized non-cash general and administrative expenses for restricted stock awards that totaled $0.6 million in the year ended December 31, 2005. The Company accounts for
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
assets held in a rabbi trust for certain participants under the Company’s deferred compensation plan in accordance with EITF 97-14. See Note 13.
Guarantees
The Company applies FASB Interpretation No. 45 (FIN 45), “Guarantor’s Accounting and Disclosure Requirements for Guarantees, including Indirect Indebtedness of Others,” for the Company’s obligations under certain guarantees.
Pursuant to FIN 45, the Company is required to disclose the changes in product warranty reserves. Some of our products in our offshore products and accommodations businesses are sold with a warranty, generally ranging from 12 to 18 months. Parts and labor are covered under the terms of the warranty agreement. Warranty provisions are based on historical experience by product, configuration and geographic region.
Changes in the warranty reserves were as follows (in thousands):
Current warranty provisions are typically related to the current year’s sales, while warranty consumption is associated with current and prior year’s net sales.
During the ordinary course of business, the Company also provides standby letters of credit or other guarantee instruments to certain parties as required for certain transactions initiated by either the Company or its subsidiaries. As of December 31, 2007, the maximum potential amount of future payments that the Company could be required to make under these guarantee agreements was approximately $12.2 million. The Company has not recorded any liability in connection with these guarantee arrangements beyond that required to appropriately account for the underlying transaction being guaranteed. The Company does not believe, based on historical experience and information currently available, that it is probable that any amounts will be required to be paid under these guarantee arrangements.
Reclassifications
Certain amounts in prior years’ financial statements have been reclassified to conform with the current year presentation.
Use of Estimates
The preparation of consolidated financial statements in conformity with accounting principles generally accepted in the United States requires the use of estimates and assumptions by management in determining the reported amounts of assets and liabilities and disclosures of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Examples of a few such estimates include the costs associated with the disposal of discontinued operations, including potential future adjustments as a result of contractual agreements, revenue and income recognized on the percentage-of-completion method, estimate of the Company’s share of earnings from equity method investments, the valuation allowance recorded on net deferred tax assets, warranty, inventory and bad debt reserves. Actual results could differ from those estimates.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Discontinued Operations
Prior to our initial public offering in February 2001, we sold businesses and reported the operating results of those businesses as discontinued operations. Existing reserves related to the discontinued operations as of December 31, 2007 and 2006 represent an estimate of the remaining contingent liabilities associated with the Company’s exit from those businesses.
3.
Details of Selected Balance Sheet Accounts
Additional information regarding selected balance sheet accounts at December 31, 2007 and 2006 is presented below (in thousands):
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Depreciation expense was $66.5 million, $50.5 million and $43.3 million in the years ended December 31, 2007, 2006 and 2005, respectively.
4.
Recent Accounting Pronouncements
In September 2006, the FASB issued Statement of Financial Accounting Standards No. 157 (SFAS 157), “Fair Value Measurements,” which defines fair value, establishes guidelines for measuring fair value and expands disclosures regarding fair value measurements. SFAS 157 does not require any new fair value measurements but rather eliminates inconsistencies in guidance found in various prior accounting pronouncements. SFAS 157 is effective for fiscal years beginning after November 15, 2007. In February 2008, the FASB issued FASB Staff Position (FSP) 157-2, “Effective Date of FASB Statement No. 157,” which defers the effective date of Statement 157 for nonfinancial assets and nonfinancial liabilities, except for items that are recognized or disclosed at fair value in an entity’s financial statements on a recurring basis (at least annually), to fiscal years beginning after November 15, 2008, and interim periods within those fiscal years. Earlier adoption is permitted, provided the company has not yet issued financial statements, including for interim periods, for that fiscal year. As of January 1, 2008, the Company does not have any recurring fair value measurements and has opted for the deferral. Accordingly, the Company has not implemented and is currently evaluating the impact of SFAS 157, but does not expect the adoption of SFAS 157 to have a material impact on its results from operations or financial position.
In February 2007, the FASB issued Statement of Financial Accounting Standards No. 159 (SFAS 159), “The Fair Value Option for Financial Assets and Financial Liabilities - Including an amendment of FASB Statement No. 115.” SFAS 159 permits entities to measure eligible assets and liabilities at fair value. Unrealized gains and losses on items for which the fair value option has been elected are reported in earnings. SFAS 159 is effective for fiscal years beginning after November 15, 2007. As of January 1, 2008, the Company did not elect the fair value option on any financial instruments or certain other items as permitted by SFAS 159.
In August 2007, the FASB issued proposed FASB Staff Position (FSP) No. APB 14-a, “Accounting for Convertible Debt Instruments That May Be Settled in Cash Upon Conversion (Including Partial Cash Settlement)” which, if issued, would change the accounting for the Company’s 23/8% Contingent Convertible Senior Subordinated Notes (23/8% Notes). Under the proposed new rules, for convertible debt instruments that may be settled entirely or partially in cash upon conversion, an entity would be required to separately account for the liability and equity components of the instrument in a manner that reflects the issuer’s nonconvertible debt borrowing rate. The effect of the proposed new rules on the 23/8% Notes is that the equity component would be classified as part of stockholders’ equity on the balance sheet and the value of the equity component would be treated as an original issue discount for purposes of accounting for the debt component of the 23/8% Notes. Higher non-cash interest expense would result by recognizing the accretion of the discounted carrying value of the 23/8% Notes as interest expense over the estimated life of the 23/8% Notes using an effective interest rate method of amortization. However, there would be no effect on the Company’s cash interest payments. The proposed FSP has been delayed once to be effective in 2008; however it is expected to be delayed further and be effective for fiscal years beginning after
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
December 15, 2008. This rule, if enacted as proposed, will require retrospective application. The Company is currently evaluating the impact of this proposed FSP.
In December 2007, the FASB issued Statement of Financial Accounting Standards No. 141 (revised 2007) (SFAS 141R), “Business Combinations,” which replaces SFAS 141. SFAS 141R establishes principles and requirements for how an acquirer recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, any non-controlling interest in the acquiree and the goodwill acquired. The Statement also establishes disclosure requirements that will enable users to evaluate the nature and financial effects of the business combination. SFAS 141R is effective for fiscal years beginning after December 15, 2008. The adoption of SFAS 141R is not expected to have a material impact on the Company’s results from operations or financial position.
In December 2007, the FASB also issued Statement of Financial Accounting Standards No. 160 (SFAS 160), “Noncontrolling Interests in Consolidated Financial Statements - an amendment of ARB No. 51.” SFAS 160 requires that accounting and reporting for minority interests be recharacterized as noncontrolling interests and classified as a component of equity. SFAS 160 also establishes reporting requirements that provide sufficient disclosures that clearly identify and distinguish between the interests of the parent and the interests of the noncontrolling owners. SFAS 160 applies to all entities that prepare consolidated financial statements, except not-for-profit organizations, but will affect only those entities that have an outstanding noncontrolling interest in one or more subsidiaries or that deconsolidate a subsidiary. This statement is effective for fiscal years beginning after December 15, 2008. The adoption of SFAS 160 is not expected to have a material impact on our results from operations or financial position.
See also Note 10 - Income Taxes and Change in Accounting Principle for a discussion of the FASB’s Interpretation No. 48 - Accounting for Uncertainty in Income Taxes.
5.
Earnings Per Share (EPS)
6.
Goodwill and Other Intangible Assets
Effective January 1, 2002, the Company adopted SFAS No. 142, “Goodwill and Other Intangible Assets” (SFAS No. 142). In connection with the adoption of SFAS No. 142, the Company ceased amortizing goodwill. Under SFAS No. 142, goodwill is no longer amortized but is tested for impairment using a fair value approach, at the “reporting unit” level. A reporting unit is the operating segment, or a business one level below that operating
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
segment (the “component” level) if discrete financial information is prepared and regularly reviewed by management at the component level. The Company had five reporting units as of December 31, 2007. Goodwill is allocated to each of the reporting units based on actual acquisitions made by the Company and its subsidiaries. The Company would recognize an impairment charge for any amount by which the carrying amount of a reporting unit’s goodwill exceeds the unit’s fair value. The Company uses comparative market multiples to establish fair values. The Company has never recognized a goodwill impairment.
The Company amortizes the cost of other intangibles over their estimated useful lives unless such lives are deemed indefinite. Amortizable intangible assets are reviewed for impairment based on undiscounted cash flows and, if impaired, written down to fair value based on either discounted cash flows or appraised values. Intangible assets with indefinite lives are tested for impairment, and written down to fair value as required. As of December 31, 2007, no provision for impairment was required based on the evaluations performed.
Changes in the carrying amount of goodwill for the year ended December 31, 2007 and 2006 are as follows (in thousands):
(1)
Effective March 1, 2006, the Company sold its workover services business - See Note 7. A total of $9,340 of goodwill was removed in connection with the workover services business sold and considered in the calculation of the gain recognized in that transaction. The remainder of this change for well site services segment relates to foreign currency and other changes.
The portion of goodwill deductible for tax purposes totals approximately $5.7 million at December 31, 2007. The following table presents the total amount assigned and the total amount amortized for major intangible asset classes as of December 31, 2007 and 2006 (in thousands):
Intangible assets, other than goodwill, are included within Other noncurrent assets in the Consolidated Balance Sheet. The weighted average remaining amortization period for all intangible assets, other than goodwill and indefinite lived intangibles, is 11.8 years and 6.5 years as of December 31, 2007 and 2006, respectively. Total amortization expense is expected to be $3.7 million, $3.1 million, $2.2 million, $1.8 million and $1.6 million in 2008, 2009, 2010, 2011 and 2012, respectively. Amortization expense was $4.2 million, $3.9 million and $3.4 million in the years ended December 31, 2007, 2006 and 2005, respectively.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
7.
Workover Services Business Transaction, Investment in Boots & Coots and Notes Receivable from Boots & Coots
Effective March 1, 2006, the Company completed a transaction to combine our workover services business with Boots & Coots in exchange for 26.5 million shares of Boots & Coots common stock valued at $1.45 per share at closing and senior subordinated promissory notes totaling $21.2 million.
As a result of the closing of the transaction, the Company initially owned 45.6% of Boots & Coots. The senior subordinated promissory notes received in the transaction, classified as other noncurrent assets as of December 31, 2007 and 2006, bear a fixed annual interest rate of 10% and mature on September 1, 2010. In connection with this transaction, the Company also entered into a Registration Rights Agreement requiring Boots & Coots to file a shelf registration statement within 30 days for all of their shares the Company received in the transaction and also allowing the Company certain rights to include our shares of common stock of Boots & Coots in a registration statement they filed. A shelf registration statement was filed by Boots and Coots and it was finalized and effective in the fourth quarter of 2006. The transaction terms also allowed the Company to designate three additional members to Boots & Coots’ existing five-member Board of Directors, which we did. Presently, the Company has two remaining representatives on the Boots & Coots eight-member Board of Directors.
The closing of the transaction resulted in a non-cash pretax gain of $20.7 million of which, in accordance with the guidance in Emerging Issues Task Force Issue No. 01-2 covering gain recognition involving non-cash transactions and retained equity interests, $9.4 million ($9.6 million as of March 31, 2006) was not recognized in connection with the initial sale of our workover services business. After the gain adjustment and income taxes, the transaction contributed a gain of $5.9 million, or $0.12 per diluted share, to net income and earnings per share, respectively, in the first quarter of 2006. The Company accounts for our investment in Boots & Coots utilizing the equity method of accounting. Differences between Boots & Coots’ total book equity after the transaction, net to the Company’s interest, and the carrying value of our investment in Boots & Coots are principally attributable to the unrecognized gain on the sale of the workover services business and to goodwill.
In April 2007, the Company sold, pursuant to a registration statement filed by Boots & Coots, 14,950,000 shares of Boots & Coots stock that it owned for net proceeds of $29.4 million and, as a result, the Company recognized a net after tax gain of $8.4 million, or approximately $0.17 per diluted share, in the second quarter of 2007. After the sale of Boots & Coots shares by the Company and the sale of primary shares of stock directly by Boots & Coots in April 2007, the Company’s ownership interest in Boots & Coots was reduced to approximately 15%. The equity method of accounting continues to be used to account for the Company’s remaining investment in Boots & Coots common stock (11.5 million shares). The carrying value and the fair value of the Company’s remaining investment in Boots & Coots stock totals $19.6 million and $18.8 million, respectively, as of December 31, 2007.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
8.
Long-term Debt
As of December 31, 2007 and 2006, long-term debt consisted of the following (in thousands):
Scheduled maturities of combined long-term debt as of December 31, 2007, are as follows (in thousands):
The Company’s capital leases consist primarily of plant facilities and equipment. The value of capitalized leases and the related accumulated depreciation totaled $1.1 million and $0.5 million, respectively, at December 31, 2007. The value of capitalized leases and the related accumulated depreciation totaled $1.0 million and $0.5 million, respectively, at December 31, 2006.
23/8% Contingent Convertible Senior Notes
On June 15, 2005, the Company sold $125 million aggregate principal amount of 23/8% contingent convertible senior notes due 2025 through a placement to qualified institutional buyers pursuant to the SEC’s Rule 144A. The Company granted the initial purchaser of the notes a 30-day option to purchase up to an additional $50 million aggregate principal amount of the notes. This option was exercised in July 2005 and an additional $50 million of the notes were sold at that time.
The notes are senior unsecured obligations of the Company and bear interest at a rate of 23/8% per annum. The notes mature on July 1, 2025, and may not be redeemed by the Company prior to July 6, 2012. Holders of the notes may require the Company to repurchase some or all of the notes on July 1, 2012, 2015, and 2020. The notes provide
OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
for a net share settlement, and therefore may be convertible, under certain circumstances, into a combination of cash, up to the principal amount of the notes, and common stock of the company, if there is any excess above the principal amount of the notes, at an initial conversion price of $31.75 per share. Shares underlying the notes were included in the calculation of diluted earnings per share during the year because the Company’s stock price exceeded the initial conversion price of $31.75 during the period. The terms of the notes require that the Company’s stock price in any quarter, for any period prior to July 1, 2023, be above 120% of the initial conversion price (or $38.10 per share) for at least 20 trading days in a defined period before the notes are convertible. Assuming the stock price contingency feature is met and the holders of the notes elect to convert when the stock price is $38.10 per share, the Company would be required to deliver $175 million in cash plus accrued interest and approximately 919,000 shares of common stock. In connection with the note offering, the Company agreed to register the notes within 180 days of their issuance and to keep the registration effective for up to two years subsequent to the initial issuance of the notes. The notes were so registered in November 2005. The maximum amount of contingent interest that could potentially inure to the note holders during such time period is not material to the consolidated financial position or the results of operations of the Company.
Revolving Credit Facility
On December 13, 2007, the Company exercised the accordion feature available under its Credit Agreement dated October 30, 2003, as amended. The Company’s credit facility currently totals $500 million of available commitments. Under this senior secured revolving credit facility with a group of banks, up to $175 million is available in the form of loans denominated in Canadian dollars and may be made to the Company’s principal Canadian operating subsidiaries. The facility matures on December 5, 2011. Amounts borrowed under this facility bear interest, at the Company’s election, at either:
•
a variable rate equal to LIBOR (or, in the case of Canadian dollar denominated loans, the Bankers’ Acceptance discount rate) plus a margin ranging from 0.5% to 1.25%; or
•
an alternate base rate equal to the higher of the bank’s prime rate and the federal funds effective rate (or, in the case of Canadian dollar denominated loans, the Canadian Prime Rate).
Commitment fees ranging from 0.175% to 0.25% per year are paid on the undrawn portion of the facility, depending upon our leverage ratio.
The credit facility is guaranteed by all of the Company’s active domestic subsidiaries and, in some cases, the Company’s Canadian and other foreign subsidiaries. The credit facility is secured by a first priority lien on all the Company’s inventory, accounts receivable and other material tangible and intangible assets, as well as those of the Company’s active subsidiaries. However, no more than 65% of the voting stock of any foreign subsidiary is required to be pledged if the pledge of any greater percentage would result in adverse tax consequences.
The credit facility contains negative covenants that limit the Company’s ability to borrow additional funds, encumber assets, pay dividends, sell assets and enter into other significant transactions.
Under the Company’s credit facility, the occurrence of specified change of control events involving our company would constitute an event of default that would permit the banks to, among other things, accelerate the maturity of the facility and cause it to become immediately due and payable in full.
As of December 31, 2007, we had $303.9 million outstanding under this facility and an additional $10.8 million of outstanding letters of credit leaving $185.3 million available to be drawn under the facility.
On January 11, 2005 the Company renewed its overdraft credit facility providing for borrowings totaling £2.0 million for UK operations. Interest is payable quarterly at a margin of 1.5% per annum over the bank’s variable base rate. All borrowings under this facility are payable on demand. No amounts were outstanding under this facility at December 31, 2007. Letters of credit totaling £0.7 million were outstanding as of December 31, 2007, leaving £1.3 million available to be drawn under this facility.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
A subsidiary of the Company maintains an additional revolving credit facility with a bank. A total of $3.3 million was outstanding under this facility as of December 31, 2007. This facility consists of a swing line with a bank, borrowings under which are used for working capital efficiencies.
9.
Retirement Plans
The Company sponsors defined contribution plans. Participation in these plans is available to substantially all employees. The Company recognized expense of $6.1 million, $5.4 million and $4.3 million, respectively, related to its various defined contribution plans during the years ended December 31, 2007, 2006 and 2005, respectively.
10.
Income Taxes
Consolidated pre-tax income for the years ended December 31, 2007, 2006 and 2005 consisted of the following (in thousands):
The components of the income tax provision for the years ended December 31, 2007, 2006 and 2005 consisted of the following (in thousands):
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
The provision for taxes differs from an amount computed at statutory rates as follows for the years ended December 31, 2007, 2006 and 2005 (in thousands):
The significant items giving rise to the deferred tax assets and liabilities as of December 31, 2007 and 2006 are as follows (in thousands):
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Reclassifications of the Company’s deferred tax balance based on net current items and net non-current items as of December 31, 2007 and 2006 are as follows (in thousands):
Our primary deferred tax assets at December 31, 2007, are related to employee benefit costs for our Equity Participation Plan and our Annual Incentive Compensation Plan and to $19 million in available federal net operating loss carryforwards, or NOLs, as of that date. The NOLs will expire in varying amounts during the years 2010 through 2011 if they are not first used to offset taxable income that we generate. Our ability to utilize a significant portion of the available NOLs is currently limited under Section 382 of the Internal Revenue Code due to a change of control that occurred during 1995. We currently believe that substantially all of our NOLs will be utilized. The Company has federal alternative minimum tax net operating loss carryforwards of $1.5 million, which will expire in the years 2011 through 2020.
Our income tax provision for the year ended December 31, 2007 totaled $97.0 million, or 32.3% of pretax income, compared to $104.0 million, or 34.5% of pretax income, for the year ended December 31, 2006. Lower foreign taxes on income and dividends, a higher allowable manufacturing credit and the completion of the IRS audit of the Company’s 2004 federal income tax return lowered the effective tax rate in the year ended December 31, 2007. In addition, our effective tax rates were higher in 2006 than 2007 because of the higher effective tax rate applicable to the gain on the sale of the workover services business recognized in 2006.
Appropriate U.S. and foreign income taxes have been provided for earnings of foreign subsidiary companies that are expected to be remitted in the near future. The cumulative amount of undistributed earnings of foreign subsidiaries that the Company intends to permanently reinvest and upon which no deferred US income taxes have been provided is $363 million at December 31, 2007 the majority of which has been generated in Canada. Upon distribution of these earnings in the form of dividends or otherwise, the Company may be subject to US income taxes (subject to adjustment for foreign tax credits) and foreign withholding taxes. It is not practical, however, to estimate the amount of taxes that may be payable on the eventual remittance of these earnings after consideration of available foreign tax credits.
The American Jobs Creation Act of 2004 that was signed into law in October 2004, introduced a requirement for companies to disclose any penalties imposed on them or any of their consolidated subsidiaries by the IRS for failing to satisfy tax disclosure requirements relating to “reportable transactions.” During the year ended December 31, 2007, no penalties were imposed on the Company or its consolidated subsidiaries for failure to disclose reportable transactions to the IRS.
The Company files tax returns in the jurisdictions in which they are required. All of these returns are subject to examination or audit and possible adjustment as a result of assessments by taxing authorities. The Company believes that it has recorded sufficient tax liabilities and does not expect the resolution of any examination or audit of its tax returns would have a material adverse effect on its operating results, financial condition or liquidity.
An examination of the Company’s consolidated U.S. federal tax return for the year 2004 by the Internal Revenue Service was completed during the third quarter of 2007. No significant adjustments were proposed as a result of this examination. Tax years subsequent to 2004 remain open to U.S. federal tax audit and, because of net operating losses (NOL’s) utilized by the Company, years from 1994 to 2002 remain subject to federal tax audit with respect to NOL’s available for tax carryforward. Our Canadian subsidiaries’ federal tax returns subsequent to 2003 are subject to audit by Canada Revenue Agency.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
In June 2006, the FASB issued Interpretation No. 48, Accounting for Uncertainty in Income Taxes - an interpretation of FASB Statement No. 109 (FIN 48), which clarifies the accounting and disclosure for uncertain tax positions, as defined. The interpretation prescribes a recognition threshold and a measurement attribute for the financial statement recognition and measurement of tax positions taken or expected to be taken in a tax return. For those benefits to be recognized, a tax position must be more-likely-than-not to be sustained upon examination by taxing authorities. The amount recognized is measured as the largest amount of benefit that is greater than 50 percent likely of being realized upon ultimate settlement. The interpretation seeks to reduce the diversity in practice associated with certain aspects of the recognition and measurement related to accounting for income taxes.
The Company adopted the provisions of FIN 48 on January 1, 2007. The adoption of FIN 48 has resulted in a transition adjustment reducing beginning retained earnings by $0.3 million consisting of $0.2 million in taxes and $0.1 million in interest. The total amount of unrecognized tax benefits as of December 31, 2007 was $2.5 million. Of this amount, $1.1 million of the unrecognized tax benefits that, if recognized, would affect the effective tax rate. The Company recognizes interest and penalties accrued related to unrecognized tax benefits as a component of the Company’s provision for income taxes. As of December 31, 2007, the Company has accrued $0.7 million of interest expense. During the year ended December 31, 2007, the Company recognized $0.4 million of interest expense, excluding the $0.5 million of interest benefit as a result of a settlement with a taxing authority.
A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows (in thousand):
It is reasonably possible that the amount of unrecognized tax benefits will change during the next twelve months due to the closing of the statute of limitations and that change, if it were to occur, could have a favorable impact on our results of operation.
11.
Acquisitions and Supplemental Cash Flow Information
Components of cash used for acquisitions as reflected in the consolidated statements of cash flows for the years ended December 31, 2007, 2006 and 2005 are summarized as follows (in thousands):
On February 1, 2005, the Company completed the acquisition of Elenburg Exploration Company, Inc. (Elenburg), a Wyoming based land drilling company for cash consideration of $22.1 million, including transaction costs, plus a note payable to the former owners of $0.8 million. At the date of acquisition, Elenburg owned and operated seven rigs which provided shallow land drilling services in Montana, Wyoming, Colorado, and Utah. The Elenburg acquisition allowed us to expand our drilling business into different geographic areas. The operations of
OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Elenburg have been included in the drilling services business within the well site services segment since the date of acquisition.
Effective May 1, 2005 and June 1, 2005 we acquired Stinger Wellhead Protection, Inc., certain affiliated companies and related intellectual property, (collectively, Stinger) for consideration of $96.1 million, including transaction costs and a note payable to the former owners of $5.0 million. Stinger provides wellhead isolation equipment and services through its 31 locations in the United States, Canada and South America. Stinger’s patented equipment is utilized during pressure pumping operations and isolates the customers’ blow-out preventers or wellheads from the pressure and abrasion experienced during the fracturing process of an oil or gas well. The Stinger acquisition expanded our rental tool and services capabilities, especially in the pressure pumping market. The operations of Stinger have been included in the rental tools business within the well site services segment since the date of acquisition.
On June 2, 2005, we purchased Phillips Casing and Tubing, L.P. (Phillips) for cash consideration of $31.2 million, net of cash acquired and including transaction costs. Phillips distributes OCTG, primarily carbon ERW (electronic resistance welded) pipe, from its facilities in Midland and Godley, Texas. The operations of Phillips have been combined with our tubular services segment since the date of acquisition.
On June 6, 2005, we acquired Noble Structures, Inc. (Noble) for cash consideration of $8.7 million, plus a note payable of $0.8 million. The acquisition expanded the Company’s accommodation manufacturing capabilities in Canada in order to meet increased demand for remote site facilities, principally in the oil sands region. The operations of Noble have been included in the accommodations business within our well site services segment since the date of acquisition.
In August 2006, we acquired three drilling rigs operating in West Texas from Eagle Rock Drilling for total consideration of $14.0 million, including a note payable to the seller of $0.5 million. The rigs acquired, which are classified as part of our capital expenditures in 2006, were added to our existing West Texas drilling fleet in our drilling services business.
On July 1, 2007, we acquired the business of Wire Line Service, Ltd. (Well Testing) for cash consideration of $43.4 million, including transaction costs, plus a note payable to the former owner of $3.0 million. Well Testing provides well testing and flowback services through its locations in Texas and New Mexico. The operations of Well Testing have been included in the rental tools business within the well site services segment since the date of acquisition.
On August 1, 2007, we acquired the business of Schooner Petroleum Services, Inc. (Schooner) for cash consideration of $59.7 million, net of cash acquired, including transactions costs, plus a note payable to the former owner of $6.0 million. Schooner, headquartered in Houston, Texas, primarily provides completion-related rental tools and services through eleven locations in Texas, Louisiana, Wyoming and Arkansas. The operations of Schooner have been included in the rental tools business within the well site services segment since the date of acquisition.
Accounting for the two acquisitions made in 2007 has not been finalized and is subject to adjustments during the purchase price allocation period, which is not expected to exceed a period of one year from the respective acquisition dates.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Cash paid during the years ended December 31, 2007, 2006 and 2005 for interest and income taxes was as follows (in thousands):
12.
Commitments and Contingencies
The Company leases a portion of its equipment, office space, computer equipment, automobiles and trucks under leases which expire at various dates.
Minimum future operating lease obligations in effect at December 31, 2007, are as follows (in thousands):
Rental expense under operating leases was $7.9 million, $6.7 million and $5.7 million for the years ended December 31, 2007, 2006 and 2005, respectively.
In September 2006, we entered into a construction agreement to build a new office facility for our offshore products operations in Houston, Texas. The total cost of this facility is expected to be approximately $7.0 million and is expected to be completed by March 2008. Upon completion of this facility, we will enter into a 21 year capital lease with annual payments totaling approximately $0.7 million.
The Company is a party to various pending or threatened claims, lawsuits and administrative proceedings seeking damages or other remedies concerning its commercial operations, products, employees and other matters, including warranty and product liability claims and occasional claims by individuals alleging exposure to hazardous materials as a result of its products or operations. Some of these claims relate to matters occurring prior to its acquisition of businesses, and some relate to businesses it has sold. In certain cases, the Company is entitled to indemnification from the sellers of businesses and in other cases, it has indemnified the buyers of businesses from it. Although the Company can give no assurance about the outcome of pending legal and administrative proceedings and the effect such outcomes may have on it, management believes that any ultimate liability resulting from the outcome of such proceedings, to the extent not otherwise provided for or covered by insurance, will not have a material adverse effect on its consolidated financial position, results of operations or liquidity.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
13.
Stock-Based Compensation
We adopted SFAS 123R effective January 1, 2006. This pronouncement requires companies to measure the cost of employee services received in exchange for an award of equity instruments (typically stock options) based on the grant-date fair value of the award. The fair value is estimated using option-pricing models. The resulting cost is recognized over the period during which an employee is required to provide service in exchange for the awards, usually the vesting period. Prior to the adoption of SFAS 123R, this accounting treatment was optional with pro forma disclosures required. We adopted SFAS 123R using the modified prospective transition method, which is explained below.
SFAS 123R is effective for all stock options we grant beginning January 1, 2006. For those stock option awards granted prior to January 1, 2006, but for which the vesting period is not complete, we used the modified prospective transition method permitted by SFAS 123R. Under this method of accounting, the remaining unamortized value of non-vested options will be expensed over the remaining vesting period using the grant-date fair values. Our options typically vest in equal annual installments over a four year service period. Expense related to an option grant is recognized on a straight line basis over the specific vesting period for those options.
The fair value of options is determined at the grant date using a Black-Scholes option pricing model, which requires us to make several assumptions, including risk-free interest rate, dividend yield, volatility and expected term. The risk-free interest rate is based on the U.S. Treasury yield curve in effect for the expected term of the option at the time of grant. The dividend yield on our common stock is assumed to be zero since we do not pay dividends and have no current plans to do so in the future. The expected market price volatility of our common stock is based on an estimate made by us that considers the historical and implied volatility of our common stock as well as a peer group of companies over a time period equal to the expected term of the option. The expected life of the options awarded in 2006 and 2007 was based on a formula considering the vesting period and term of the options awarded as permitted by U.S. Securities and Exchange Commission regulations.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
The following table summarizes stock option activity for each of the three years ended December 31, 2007:
The total intrinsic value of options exercised during 2007, 2006 and 2005 were $26.9 million, $18.3 million and $13.1 million, respectively. Cash received by the Company from option exercises during 2007, 2006 and 2005 totaled $13.8 million, $8.5 million and $7.5 million, respectively.
The weighted average fair values of options granted during 2007, 2006, and 2005 were $11.16, $12.89, and $8.32 per share, respectively. The fair value of each option grant is estimated on the date of grant using the Black-Scholes option pricing model with the following weighted average assumptions used for grants in 2007, 2006, and 2005, respectively: risk-free weighted interest rates of 4.7%, 4.6%, and 3.9%, no expected dividend yield, expected lives of 4.3, 4.3, and 5.0 years, and an expected volatility of 37%, 37% and 37%.
OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
The following table summarizes information for stock options outstanding at December 31, 2007:
At December 31, 2007, a total of 1,497,547 shares were available for future grant under the Equity Participation Plan.
During 2007, we granted restricted stock awards totaling 197,563 shares valued at a total of $6.3 million. A total of 162,707 of these awards vest in four equal annual installments, 15,860 of these awards vest in three equal annual installments, 3,800 of these awards vest in two annual installments and the remaining 15,196 awards vest after one year. All options awarded in 2007 had a term of six years and were granted with exercise prices at the grant date closing market price. The total fair value of restricted stock awards vesting during the year ended December 31, 2007, was $2.2 million. A total of 113,787 shares of restricted stock were awarded in 2006 with an aggregate value of $3.9 million. A total of 56,952 shares of restricted stock were awarded in 2005 with an aggregate value of $1.2 million.
Impact of Adoption of SFAS 123R. Stock based compensation pre-tax expense recognized under SFAS 123R in the year ended December 31, 2007 totaled $8.0 million, or $0.11 per basic and diluted share. Stock based compensation pre-tax expense recognized under SFAS 123R in the year ended December 31, 2006 totaled $7.6 million, or $0.10 per basic and diluted share. For the year ended December 31, 2005, our stock compensation expense related primarily to restricted stock awards and totaled $558,000. At December 31, 2007, $14.1 million of compensation cost related to unvested stock options and restricted stock awards attributable to future performance had not yet been recognized.
The following table illustrates the pro forma effect on net income and income per share for the year ended December 31, 2005 had we applied the fair value recognition provisions of SFAS No. 123, “Accounting for Stock-Based Compensation” (in thousands except per share amounts):
OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Deferred Compensation Plan
The Company maintains a deferred compensation plan (“Deferred Compensation Plan”). This plan is available to directors and certain officers and managers of the Company. The plan allows participants to defer all or a portion of their directors fees and/or salary and annual bonuses, as applicable, and it permits the Company to make discretionary contributions to any employee’s account. Since inception of the plan, this discretionary contribution provision has been limited to a matching of the employee participants contribution on a basis equivalent to matching permitted under the Company’s 401(k) Retirement Savings Plan. The vesting of contributions to the participants’ accounts are also equivalent to the vesting requirements of the Company’s 401(k) Retirement Savings Plan. The Deferred Compensation Plan does not have dollar limits on tax-deferred contributions. The assets of the Deferred Compensation Plan are held in a Rabbi Trust (“Trust”) and, therefore, are available to satisfy the claims of the Company’s creditors in the event of bankruptcy or insolvency of the Company. Participants have the ability to direct the Plan Administrator to invest the assets in their accounts, including any discretionary contributions by the Company, in pre-approved mutual funds held by the Trust. Prior to November 1, 2003, participants also had the ability to direct the Plan Administrator to invest the assets in their accounts in Company common stock. In addition, participants currently have the right to request that the Plan Administrator re-allocate the portfolio of investments (i.e. cash or mutual funds) in the participants’ individual accounts within the Trust. Current balances invested in Company common stock may not be further increased. Company contributions are in the form of cash. Distributions from the plan are generally made upon the participants’ termination as a director and/or employee, as applicable, of the Company. Participants receive payments from the Plan in cash. At December 31, 2007, the balance of the assets in the Trust totaled $6.8 million, including 17,850 shares of common stock of the Company reflected as treasury stock at a value of $0.2 million. The Company accounts for the Deferred Compensation Plan in accordance with EITF 97-14, “Accounting for Deferred Compensation Arrangements Where Amounts Earned are Held in a Rabbi Trust and Invested.”
Assets of the Trust, other than common stock of the Company, are invested in nine funds covering a variety of securities and investment strategies. These mutual funds are publicly quoted and reported at market value. The Company accounts for these investments in accordance with SFAS No. 115, “Accounting for Certain Investments in Debt and Equity Securities.” The Trust also holds common shares of the Company. The Company’s common stock that is held by the Trust has been classified as treasury stock in the stockholders’ equity section of the consolidated balance sheet. The market value of the assets held by the Trust, exclusive of the market value of the shares of the Company’s common stock that are reflected as treasury stock, at December 31, 2007 was $6.6 million and is classified as “Other noncurrent assets” in the consolidated balance sheet. Amounts payable to the plan participants at December 31, 2007, including the market value of the shares of the Company’s common stock that are reflected as treasury stock, was $7.2 million and is classified as “Other liabilities” in the consolidated balance sheet.
In accordance with EITF 97-14, all market value fluctuations of the Trust assets have been reflected in the consolidated statements of income. Increases or decreases in the value of the plan assets, exclusive of the shares of common stock of the Company, have been included as compensation adjustments in the respective statements of income. Increases or decreases in the market value of the deferred compensation liability, including the shares of common stock of the Company held by the Trust, while recorded as treasury stock, are also included as compensation adjustments in the consolidated statements of income. In response to the changes in total market value of the Company’s common stock held by the Trust, the Company recorded net compensation expense adjustments of $44.2 thousand in 2007, $28.3 thousand in 2006 and $0.4 million in 2005.
14.
Segment and Related Information
In accordance with SFAS No. 131, “Disclosures about Segments of an Enterprise and Related Information,” the Company has identified the following reportable segments: offshore products, well site services and tubular services. The Company’s reportable segments are strategic business units that offer different products and services. They are managed separately because each business requires different technology and marketing strategies. Most of the businesses were acquired as a unit, and the management at the time of the acquisition was retained.
OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Financial information by industry segment for each of the three years ended December 31, 2007, 2006 and 2005, is summarized in the following table in thousands. The accounting policies of the segments are the same as those described in the summary of significant accounting policies.
(1)
Subsequent to March 1, 2006, the effective date of the sale of our workover services business (See Note 7), we have classified our equity interest in Boots & Coots and the notes receivable acquired in the transaction as “Drilling and Other “.
(2)
Includes $0.5 million of non-cash capital expenditures related to the acquisition of the drilling assets of Eagle Rock.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Financial information by geographic segment for each of the three years ended December 31, 2007, 2006 and 2005, is summarized below in thousands. Revenues in the US include export sales. Revenues are attributable to countries based on the location of the entity selling the products or performing the services. Total assets are attributable to countries based on the physical location of the entity and its operating assets and do not include intercompany balances.
No customers accounted for more than 10% of the Company’s revenues in any of the years ended December 31, 2007, 2006 and 2005. Equity in net income of unconsolidated affiliates is not included in operating income.
15.
Quarterly Financial Information (Unaudited)
The following table summarizes quarterly financial information for 2007 and 2006 (in thousands, except per share amounts):
Amounts are calculated independently for each of the quarters presented. Therefore, the sum of the quarterly amounts may not equal the total calculated for the year.
*
Represents “revenues” less “product costs” and “service and other costs” included in the Company’s consolidated statements of income.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
16.
Valuation Allowances
Activity in the valuation accounts was as follows (in thousands):
17.
Subsequent Events
On January 11, 2008, an additional $50 million was approved by the Board for the share repurchase program and the duration of the program was extended to December 31, 2009.
On February 1, 2008, we purchased all of the equity of Christina Lake Enterprises Ltd., the owners of an accommodations lodge (“Christina Lake Lodge”) in the Conklin area of Alberta, Canada. Christina Lake Lodge provides lodging and catering for up to 92 people in the southern area of the oil sands region and can be expanded to accommodate future growth. Consideration for the lodge consisted of C$6.5 million in cash, funded from borrowings under the Company’s existing credit facility, and is subject to post-closing working capital adjustments.
On February 15, 2008, we acquired a waterfront facility on the Houston ship channel for use in our offshore products segment. The new waterfront facility will expand our ability to manufacture, assemble, test and load out larger subsea production and drilling rig equipment thereby expanding our capabilities. The consideration for the facility was approximately $22.5 million in cash funded from borrowings under the Company’s existing credit facility.
EXHIBIT INDEX
*
Filed herewith
**
Management contracts or compensatory plans or arrangements
***
Furnished herewith.