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, Canada, West Africa, the Middle East, South America and Southeast Asia. Our customers
include many of the 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 each.
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 the 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 May 23, 2005, 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 as CE Holdings, Inc. On August 1, 1995, CE Holdings, Inc. acquired Continental Emsco Company, an operator of oilfield supply stores, including its then wholly owned subsidiary Oil States Industries, Inc. (Oil States Industries). Oil States Industries is a manufacturer of offshore products.
In May 1996, Oil States Industries purchased the construction division of Hunting Oilfield Services, Ltd., which provides a variety of construction products and services to the offshore oil and gas industry as well as certain connector manufacturing technology. In November 1996, CE Holdings, Inc. changed its name to CONEMSCO, Inc. (Conemsco).
In July 1997, Conemsco purchased HydroTech Systems, Inc., a full service provider of engineered products to the offshore pipeline industry, and SMATCO Industries Inc., a manufacturer of marine winches for the offshore service boat industry. In December 1997, Conemsco purchased Gregory Rig Service & Sales Inc., a provider of drilling equipment and services.
In February 1998, Conemsco acquired Subsea Ventures, Inc. (SVI). SVI designs, manufactures and services auxiliary structures for subsea blowout preventors and subsea production systems. In April 1998, Conemsco acquired the assets of Klaper (UK) Limited, a provider of repair and maintenance services for blowout preventors and drilling risers used in offshore drilling.
In July 2000, Conemsco changed its name to Oil States International, Inc. In July 2000, Oil States International, Inc., 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 and references to “Oil States” are to Oil States International, Inc. and its subsidiaries prior to the Combination.
Acquisitions
Since the completion of our initial public offering in February 2001, we have completed 30 acquisitions for total consideration of $340 million. Acquisitions of other oil service businesses have been an important aspect of our growth strategy and plans to increase shareholder value.
In 2002, we acquired the following six businesses for total consideration of approximately $72.1 million, which was financed primarily with borrowings under our credit facility:
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Southeastern Rentals LLC, based in Mississippi, Edge Wireline Rentals Inc. and certain affiliated companies, located in Louisiana, and J.V. Oilfield Rentals & Supply, Inc. and certain affiliated companies, located in Louisiana, all of which are suppliers of rental tools to the oil and gas service industry. These businesses were merged into our existing rental tool business included in our well site services segment.
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Barlow Hunt, Inc., based in Oklahoma, an elastomer molding company which has become part of our existing elastomer business included in the offshore products segment.
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Certain assets and related liabilities of Big Inch Marine Services, Inc., a Texas-based subsidiary of Stolt Offshore, Inc., which provides subsea pipeline equipment and repair services similar to those provided by us in the offshore products segment.
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Applied Hydraulic Systems, Inc., a Louisiana-based offshore crane manufacturer and crane repair service provider, which has become part of our offshore products segment.
In 2003, we spent $16.8 million, financed with borrowings under our credit facility, to acquire five businesses. Three of the businesses were rental tool companies acquired for a total consideration of $10.5 million. The acquired rental tool companies conduct operations in South Texas and Louisiana and were combined with our existing rental tool business within our well site services segment. The remaining two businesses, acquired for aggregate consideration of $6.3 million, were combined with our offshore products segment.
In 2004, we acquired six rental tool businesses, a tubular distribution business and a small tooling line for total consideration of $89.1 million. In January 2004, we acquired the stock of five related rental tool companies for $36.6 million and in April 2004 we acquired the assets of a rental tool business for $4.8 million. In May 2004, we purchased the oil country tubular goods (“OCTG”) distribution business of Hunting Energy Services, L.P for $47.2 million. In October 2004, we acquired a tooling product line into our offshore products segment for $0.5 million.
In 2005, we completed the acquisitions of a land drilling business, a rental tool company, a tubular distributor, a remote accommodation fabrication business and a small offshore products line for total consideration of $158.5 million.
On February 1, 2005, we completed the acquisition of Elenburg Exploration Company, Inc. (Elenburg), a Wyoming based land drilling company for total consideration of $22.1 million, including transaction costs and 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 its land drilling business into different geographic areas.
Effective May 1, 2005 and June 1, 2005, we acquired Stinger Wellhead Protection, Inc., certain affiliated companies and related intellectual property, (collectively, Stinger) for total 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 29 locations in the United States, Canada, Central 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.
On June 2, 2005, we purchased Phillips Casing and Tubing, L.P. (Phillips) for total consideration of $31.2 million including transaction costs. Phillips distributes oil country tubular goods (OCTG), primarily carbon ERW (electronic resistance welded) pipe, from its facilities in Midland and Godley, Texas. Phillips distribution operations were merged into our existing distribution operations in our tubular services segment.
On June 6, 2005, we acquired Noble Structures, Inc. (Noble) for total consideration of $8.7 million, including transaction costs and 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.
In December 2005, we acquired a product line into our offshore products segment for cash consideration of $0.4 million.
The cash consideration paid for all of the Company’s acquisitions during 2005 was initially funded utilizing its existing bank credit facility and a $25 million bridge loan (See Note 7 to the Consolidated Financial Statements included in this Annual Report on Form 10-K).
Workover Business Merger
On November 12, 2005, we announced that one of our subsidiaries signed a definitive agreement to combine its hydraulic workover business with Boots & Coots International Well Control, Inc. (Amex: WEL) (“Boots & Coots”) in exchange for 26.5 million shares of Boots & Coots common stock and senior subordinated promissory notes totaling $15.0 million. The transaction is subject to the approval of Boots & Coots’ shareholders and is expected to close in March 2006.
As discussed herein, our hydraulic workover business is based in Houma, Louisiana, provides live and dead well workover services throughout the world, utilizing a fleet of 27 owned and operated hydraulic workover units. Our workover operations are performed in the U.S., Venezuela, Algeria, West Africa and the Middle East. Financial information for our workover operations is included in Item 7 - Management’s Discussion and Analysis of Financial Condition and Results of Operations and in our Consolidated Financial Statements at Footnote No. 13 - Segment and Related Information under the caption “Hydraulic Workover”.
Upon the closing of the transaction, Oil States will own approximately 44% of the combined company and will receive senior subordinated promissory notes totaling $15.0 million in aggregate principal from Boots & Coots bearing a fixed annual interest rate of 10% and maturing four and one half years from the closing of the transaction. The senior subordinated notes are subject to increase at closing depending upon the level of working capital at closing. In addition, we have the right under the transaction agreement to nominate three additional members to Boots & Coots’ existing five-member Board of Directors.
Our Industry
We operate in the oilfield service industry and provide products and services to oil and gas exploration and production companies for use in the drilling for and production of oil and gas. 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 oil and natural gas prices. See Note 13 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 is significantly affected by the North American rig count, had increased activity during 2001, saw decreased activity in 2002 and early 2003 and has seen increasing activity from 2003 through the current period. Acquisitions and capital expenditures made in this segment have
created additional growth opportunities. In addition, the increased activity supporting oil sands developments in northern Alberta, Canada by our work force accommodations, catering and logistics business in this segment have had an important positive impact on this segment’s overall trends.
Our Offshore Products segment, which is more influenced by deepwater development activity and rig construction and repair, experienced increased activity during 2002 and 2003 as we shipped projects from our backlog which had increased in 2001 and 2002. In 2004, activity in this segment slowed; however, backlog increased during 2004 and 2005, which resulted in improved operating results during 2005.
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 was significantly affected by increasing prices for steel products, including the oil country tubular goods (“OCTG”) we sell.
Well Site Services
Overview
During the year ended December 31, 2005, we generated approximately 36% of our revenue and 51% of our operating income, before corporate charges, from our well site services segment. Our well site services segment provides 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. Our services include workover services, drilling services, rental equipment, work force accommodations, catering and logistics services and modular building construction services. We use our fleet of workover and drilling rigs, rental equipment, work force accommodation facilities and related equipment to service well sites for oil and natural gas companies. Our products and services are used in both onshore and offshore applications through the exploration, development, production and abandonment phases of a well’s life. Additionally, our work force accommodations, catering and logistics services are employed in a variety of mining and related natural resource applications as well as forest fire fighting.
Well Site Services Market
Demand for our workover and 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 product prices.
Products and Services
Workover Services. We provide our workover products and services primarily to customers in the U.S., Venezuela, the Middle East, North and West Africa, for both onshore and offshore applications. Workover products and services are used in operations on a producing well to restore or increase production. Workover services are typically used during the development, production and abandonment stages of the well. Our hydraulic workover units are used for workover operations and snubbing operations in pressure situations.
A hydraulic workover unit is a specially designed rig used for moving tubulars in and out of a wellbore using hydraulic pressure. These units may be used for servicing wells that are not producing or for working on wells under pressure. These units may be used for underbalanced drilling and workover and also in well control applications. When a unit is snubbing, it is pushing pipe or tubulars into the well bore against well bore pressures. Because of their small size and ability to work on wells under pressure, hydraulic workover units offer some advantages over larger workover rigs and conventional drilling rigs. However, most wells where we perform workover service are wells with no pressure.
As of December 31, 2005, we had 27 “stand alone” hydraulic workover units. Of these 27 units, 14 were located in the U.S., five were located in Venezuela, four were located in Dubai, U.A.E., two were located in Egypt and two were located in the Republic of Congo. In addition, we had labor and maintenance contracts on two non-owned hydraulic workover units in Algeria. Typically, our hydraulic workover units are contracted on a short-term dayrate basis. As a result, utilization of our hydraulic workover units varies from period to period.
Our utilization rate for hydraulic workover units was 32.9% in 2005 and 29.1% during 2004. As of December 31, 2005, eleven of our hydraulic workover units were working or under contract and we had crews on two managed units in Algeria. The length of time necessary to complete a job depends on many factors, including the number of wells and the type of workover or pressure control situation involved. Usage of our hydraulic workover units is also affected by the availability of trained personnel. With our current level of trained personnel, we estimate that we have the capability to crew and operate 12 to 14 simultaneous jobs involving our hydraulic workover units.
Drilling Services. Our drilling services business is located in Odessa, Texas, Wooster, Ohio and Casper, Wyoming and provides drilling services for shallow to medium depths ranging from 2,000 to 11,500 feet. Drilling services are typically used during the exploration and development stages of a field. We have a total of 27 semi-automatic drilling rigs with hydraulic pipe handling booms and lift capacities ranging from 200,000 to 300,000 pounds. We added one of these drilling rigs in 2003, one in each of February and December 2004, seven in February 2005 (through our acquisition of Elenburg) and one in each of June and August 2005. Fifteen of these drilling rigs are located in Odessa, Texas, eight in the Rocky Mountain region and four are located in Wooster, Ohio. As of December 31, 2005, all 27 rigs were working or under contract. Utilization decreased slightly from 90.5% in 2004 to 87.8% in 2005. We have assembled five of our new rigs that have been added to our fleet during 2003 through 2005 in our Odessa, Texas facility with components purchased from specialty vendors. Two additional rigs were under construction in Odessa, Texas at December 31, 2005, one of which spudded its first well in February 2006 and one which should commence operations by October 2006. 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 companies. During 2005 we switched from billing on a footage basis to billing on a dayrate basis for many of our drilling rigs. Under a daywork drilling contract, the customer pays for certain costs that the Company would normally provide when drilling on a footage basis and assumes more risk than on a footage basis. The land drilling business is highly fragmented and consists of a small number of large companies and many smaller companies.
Rental Equipment. Our rental equipment business provides a wide range of products 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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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 used during the exploration, development, production and abandonment stages. As of December 31, 2005, we provided rental equipment at 52 U.S. distribution points in Texas, Louisiana, Oklahoma, Mississippi, New Mexico, Wyoming, California, Colorado, North Dakota, Utah, 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.
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, including work force accommodation, food services, remote site management services and modular building construction. We provide complete design, manufacture, installation, operation and redeployment logistics services for oil and gas drilling, oil sands development in the Fort McMurray region of Northern Canada, diamond mining in Northern Canada and other mining ventures throughout the world, pipeline construction, forestry, offshore construction, disaster relief services and support services for military operations on a worldwide basis. Our work force products and service operations are primarily focused in Canada and the Gulf of Mexico although we also have performed catering and facilities management activities in other international areas. During the
peak of our operating season, we typically provide these services in over 200 separate locations with separate location populations ranging from 20 to 2,000 persons. We design, construct and install a variety of portable modular buildings, including housing, kitchens, recreational units and offices for lease or sale to the Canadian and Gulf of Mexico markets. Our designers work closely with our clients to build structures that best serve their needs.
Offshore Products
Overview
During the year ended December 31, 2005, we generated approximately 18% of our revenue and 13% 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 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 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 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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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 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 or FPSO 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 revenues 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 military, marine and aircraft 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 $110.7 million at December 31, 2005, compared to $97.5 million at December 31, 2004 and $62.6 million at December 31, 2003. We expect the majority of our backlog at December 31, 2005 to be completed in 2006. Our offshore products backlog consists of firm customer purchase orders for which satisfactory credit or financing arrangements 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, 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.
Tubular Services
Overview
During the year ended December 31, 2005, we generated approximately 46% of our revenue and 36% of our operating income, before corporate charges, from our tubular services segment. Through this segment, we distribute oil country tubular goods, or OCTG, and provide associated OCTG finishing and logistics services
to the oil and gas industry. Oil country tubular goods 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 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 2005, we purchased from a single domestic supplier 52% of the tubular goods we distributed and from three domestic suppliers approximately 73% 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 average number of drilling rigs operating 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 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 which were added in the Phillips acquisition. Our Midland, Texas facility covers approximately 50 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.
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 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 to other countries, including Brazil, Cameroon, Chad, Columbia, Congo, Ecuador, Egypt, Equatorial Guinea, Gabon, Germany, Guatemala, Hungary, Netherlands, Russian Federation, Scotland, Trinidad, Tunisia and Venezuela.
Customers, Suppliers and Competitors
Our three largest end-user customers in the tubular distribution market in 2005 were ChevronTexaco Corporation, Burlington Resources and ConocoPhillips. Our three largest suppliers were U.S. Steel Group, Lone Star Steel and 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 Total Premier, Red Man Pipe & Supply Co., Inc., Bourland and Leverich and Pipeco Services.
Employees
As of December 31, 2005, we had approximately 5,236 full-time employees, 26% of whom are in our offshore products segment, 72% of whom are in our well site services segment and 2% of whom are in our tubular services segment. We are party to collective bargaining agreements covering 780 employees located in Canada and the United Kingdom as of December 31, 2005. 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, 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, 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.
The federal Comprehensive Environmental Response, Compensation, and Liability Act, CERCLA or 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 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 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 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 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 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.
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. Product prices have been at historically high levels over recent months, which has helped to substantially increase our financial results. 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. 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;
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the impact of armed hostilities involving one or more oil producing nations;
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the cost of developing alternate energy sources;
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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 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. Perceptions of longer-term lower oil and natural gas prices by oil and gas companies can reduce or defer major expenditures given the long-term nature of many large scale development projects, which would adversely affect our revenues and profitability.
Because the oil and gas industry is cyclical, our operating results may fluctuate.
Oil prices 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.
Disruptions in the political and economic conditions of the foreign countries in which we operate could adversely affect our business.
We have operations in various international areas, including parts of Africa, South America and the Middle East. Our operations in these areas increase our exposure to risks of war, terrorist attacks, local economic conditions, political disruption, civil disturbance and governmental policies that may:
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disrupt our operations;
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restrict the movement of funds or limit repatriation of profits;
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lead to U.S. government or international sanctions; and
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limit access to markets for periods of time.
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 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.
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.
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 customers in the United States, our results of operations could be adversely impacted.
U.S. law currently restricts imports of low-cost tubular goods from a number of foreign countries into the U.S. tubular goods market, resulting in higher prices for tubular goods. If these restrictions were to be lifted or if the level of imported low-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. 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.
Our hydraulic well control and drilling operations and our offshore products business are significantly affected by stringent and complex foreign, federal, 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 have changed in the past, and they are likely to change in the future. If existing regulatory requirements or enforcement policies change, 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 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.
We sell our products and services in competitive markets. In some of our business segments, we compete with the oil and gas industry’s largest oilfield services providers. These companies have greater financial resources than we do. In addition, our business, particularly our tubular services business, may face competition from business-to-business internet auction activities. Our business will be adversely affected to the extent that these providers are successful in reducing purchases of our products and services.
Risks Related to Our Operations
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 and the Gulf of Mexico. Our Canadian work force accommodations, catering and logistics operations are significantly focused on the winter months when the winter freeze in remote regions permits 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. 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. During 2005, 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. As a result, full year results are not likely to be a direct multiple of any particular quarter or combination of quarters.
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. We may not be able to successfully preserve these intellectual property rights in the future and these rights could be invalidated, circumvented or challenged. 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.
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, 2005, goodwill represented approximately 25% 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 2005, we purchased from a single domestic supplier approximately 52% of the tubular goods we distributed and from three domestic suppliers approximately 73% 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.
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.
Two of our directors may have conflicts of interest because they are also directors or officers of SCF. The resolution of these conflicts of interest may not be in our or our stockholders’ best interests.
Two of our directors, L.E. Simmons and Andrew L. Waite, are also current directors or officers of L.E. Simmons & Associates, Incorporated, the ultimate general partner of SCF-III, L.P. and SCF-IV, L.P., private equity funds that focus on investments in the energy industry (collectively, “SCF”). SCF owned 6.7% of our outstanding common stock as of December 31, 2005. This may create conflicts of interest because these directors have responsibilities to SCF and its owners. Their duties as directors or officers of L.E. Simmons & Associates, Incorporated may conflict with their duties as directors of our company regarding business dealings between SCF and us and other matters. The resolution of these conflicts may not always be in our or our stockholders’ best interest.
Item 1B.
Item 1B.
Unresolved Staff Comments
Not applicable.
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 52 rental tool supply and distribution points in Texas, Louisiana, New Mexico, Mississippi, Oklahoma, Wyoming, California, Colorado, North Dakota, Utah, Canada, Mexico and Argentina. Most of these office locations 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.
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 warranty and product liability claims and 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 insurance, will not have a material adverse effect on our consolidated financial position, results of operations or liquidity.
On February 18, 2005, we announced that we had conducted an internal investigation prompted by the discovery of over billings totaling approximately $400,000 by one of our subsidiaries (the “Subsidiary”) to a government owned oil company in South America. The over billings were detected by the Company during routine financial review procedures, and appropriate financial statement adjustments were included in its previously reported fourth quarter 2004 results. We and independent counsel retained by our audit committee conducted separate investigations consisting of interviews and a thorough examination of the facts and circumstances in this matter. We voluntarily reported the results of our investigation to the Securities and Exchange Commission (the “SEC”) and have fully cooperated with requests for information received from the SEC. The SEC recently completed its informal investigation of this matter. On October 31, 2005, our counsel received a “Wells Notice” from the staff of the SEC indicating that the staff has made a preliminary decision to recommend that the SEC bring a civil action against the Company alleging violations of provisions of the Securities and Exchange Act of 1934 relating to the maintenance of books, records and internal accounting controls and procedures as set forth in Sections 13(b)(2)(A) and (B) of the Act. The alleged violations related to this over billings matter. A “Wells Notice” is not a formal allegation or proof of wrongdoing. The Company has responded to the SEC staff regarding the “Wells Notice” and is in discussions with the SEC staff regarding this matter.
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 2005.
PART II
Item 5.
Item 5.
Market for Registrant’s Common Equity and Related Stockholder Matters
Common Stock Information
Our authorized common stock consists of 200,000,000 shares of common stock. There were 49,192,972 shares of common stock outstanding as of February 10, 2006, including 267,348 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 10, 2006 was 62. 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 10, 2006 was $38.23 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. Our Board of Directors has authorized the repurchase of shares of our common stock, par value $.01 per share. The Board of Directors authorized the expenditure of up to $50 million to repurchase shares over a two-year period ending February 16, 2007. Through February 10, 2006, we have repurchased 1,183,432 shares of our common stock for $30.0 million under the repurchase program.
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 Item 12. “Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters” contained herein.
Item 6.
Item 6.
Selected Financial Data
The selected financial data on the following pages include selected historical and unaudited pro forma financial information of our company as of and for each of the five years ended December 31, 2005. 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
(1)
The unaudited pro forma statements of operations and other financial data for 2001 give effect to:
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our initial public offering in February 2001 of 10,000,000 shares at $9.00 per share and the application of the net proceeds to us;
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our issuance of 4,275,555 shares of common stock to SCF in exchange for approximately $36.0 million of our indebtedness held by SCF (SCF Exchange) effected in connection with our initial public offering;
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the three-for-one reverse stock split of Oil States common stock effected in connection with our initial public offering;
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the combination of Oil States, HWC and PTI immediately prior to our initial public offering, excluding the minority interest of each company, as entities under common control from the dates such common control was established using reorganization accounting, which yields results similar to pooling of interest accounting;
•
the acquisition of the minority interests of Oil States, HWC and PTI in the Combination using the purchase method of accounting as if the acquisition occurred on January 1, 2001; and
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the acquisition of Sooner in the Combination using the purchase method of accounting as if the acquisition occurred on January 1, 2001.
(2)
In June 2001, the Financial Accounting Standards Board issued Statement of Financial Accounting Standard (“SFAS”) No. 142, “Goodwill and Other Intangible Assets,” which we adopted effective January 1, 2002. Under SFAS 142, goodwill and intangible assets deemed to have indefinite lives are no longer amortized but are subject to annual impairment tests. Accordingly, beginning in 2002, we no
longer amortized goodwill. See “Risks Related to Our Operations - If we have to write off a significant amount of goodwill, our earnings will be negatively affected” in “Item 1A. Risk Factors” above.
(3)
Our effective tax rate was affected by our net operating loss carry forwards in the periods presented.
(4)
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:
(5)
Prior to our initial public offering in February 2001, SCF-III, L.P. owned majority interests in Oil States, HWC and PTI, and SCF-IV, L.P. owned a majority interest in Sooner. L. E. Simmons & Associates, Incorporated is the ultimate general partner of SCF-III, L.P. and SCF-IV, L.P. L.E. Simmons, the chairman of our board of directors, is the sole shareholder of L.E. Simmons & Associates, Incorporated. Immediately prior to the closing of our initial public offering, the Combination closed and HWC, PTI and Sooner merged with wholly owned subsidiaries of Oil States. As a result, HWC, Sooner and PTI became our wholly owned subsidiaries.
The financial results of Oil States, HWC and PTI have been combined from the beginning of calendar 2001 until February 14, 2001 using reorganization accounting, which yields results similar to the pooling of interests method and are the basis of the Combined Financial Information presented herein. The Consolidated and Combined Financial Information presented herein include the combined financial results of Oil States, HWC and PTI until February 14, 2001 and the Consolidated Financial Information of the Company thereafter.
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 than our offshore products segment. 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, repairs and upgrades of existing drilling rigs and construction of new drilling rigs. In this segment, we are particularly influenced by deepwater drilling and production activities, which are driven largely by our customers’ outlook for longer-term future oil prices. Through our tubular services segment, we distribute a broad range of casing and tubing. Sales of tubular products and services depend upon the overall level of drilling activity, the types of wells being drilled and the level of oil country tubular goods (OCTG) pricing. Historically, tubular services gross margins expand during periods of rising OCTG prices and contract during periods of decreasing OCTG prices. In our well site services business segment, we provide shallow land drilling services, hydraulic well control services, work force accommodations, catering and logistics 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 workover services are conducted in the U.S., South America, Africa, and the Middle East and are dependent upon the level of workover activity in those areas. Our rental tools and services depend primarily upon the level and type of drilling, completion and workover activity in the U.S., Canada and Central and South America. Our accommodations business is conducted primarily in Canada and its activity levels have historically been driven by oil and gas drilling and mining activities. In the past year, we have seen increased demand in our work force accommodation business as a result of oil sands development activities in Northern Alberta, Canada. Our revenues derived from oil sands development activities in our accommodations business have increased from $46.8 million, or 24.6% of total accommodations revenues in 2004, to $131.0 million, or 45.6% of total accommodations revenues in 2005. We are continuing to see significant opportunities to make capital investments as a result of oil sands development activities in Alberta, Canada. We support remote accommodations needs primarily in the U.S. and Canada.
We have a diversified product and service offering which has exposure throughout the oil and gas cycle. Demand for our tubular services and well site services segments are highly correlated to changes in the 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, as of and for the periods indicated.
The average North American rig count for the year ended December 31, 2005 increased by 282 rigs, or 18.1%, compared to the year ended December 31, 2004. This overall increase in activity, while tempered somewhat by lower activity levels in the U.S. Gulf of Mexico, did contribute to increased revenues in our tubular services and well site services segments. Our well site services segment results for the year 2005 also benefited from capital spending, which aggregated $73.0 million in the year ended December 31, 2005, the acquisition of Elenburg on February 1, 2005 for total consideration of $22.1 million, the acquisition of Stinger
on May 1, 2005 and June 1, 2005 for total consideration of $96.1 million and the impact of increased activity levels and pricing gains in certain business lines. The Canadian rig count increased 24.1% in the year 2005 compared to the year 2004. Our remote accommodations, catering and logistics services activities benefited from increased activities in the Northern Alberta oil sands area and, to a lesser extent, from the Canadian rig count increase.
Hurricanes Katrina and Rita did not materially affect our operating results in 2005 despite some activity delays and lack of cost absorption in some of our manufacturing facilities. Our activities which were negatively impacted by the storms were offshore tubular (OCTG) sales, offshore rental tools usage and some temporary downtime in our offshore products manufacturing facilities in Houma, Louisiana and Houston, Texas. Repair activity resulting from these hurricanes has benefited our offshore products and U.S. Gulf accommodations businesses. Prolonged periods of reduced offshore activity due to repair efforts could negatively impact offshore drilling and workover activity which would adversely affect our hydraulic workover and rental tool businesses in addition to delaying OCTG sales.
During 2005, the results generated by our Canadian workforce accommodations, catering and logistics operations benefited from the strengthening of the Canadian currency, which we generally do not hedge. For the year ended December 31, 2005, the Canadian dollar averaged $0.83 U.S. dollars to each Canadian dollar compared to $0.77 for the year ended December 31, 2004, an increase of 7.8%.
On May 11, 2004, our tubular services segment purchased the OCTG distribution business of Hunting Energy Services, L.P. (Hunting) for $47.2 million, including purchase price adjustments. On June 2, 2005 we acquired all of the outstanding stock of Phillips for total consideration of $31.2 million. Both of these acquisitions resulted in increased OCTG inventory and revenues from the date of acquisition. Our tubular services segment shipped 405,300 tons of OCTG in 2005 (118,600 tons in the fourth quarter of 2005) compared to 339,800 tons in 2004 (97,800 tons in the fourth quarter of 2004). Our tubular services segment benefited in the past year from an 18.4% year over year increase in average U.S. land drilling activity, the acquisition of the Hunting and Phillips OCTG distribution businesses and increased OCTG prices. Our tubular services gross margins were at historically high levels in 2004 and 2005. The tubular services gross margin as a percent of revenues increased to 12.2% in 2005 compared to a gross margin percent of 11.9% in 2004. In 2002 and 2003, gross margins were 6.4% and 5.8%, respectively. Increases and decreases in gross margins are attributable to many factors including fundamental supply and demand, timing and frequency of price changes for inventory sold and the mix of OCTG grades sold. Typically alloy OCTG grades carry a higher margin than carbon OCTG grades. We increased slightly the percentage of carbon grade OCTG in our inventory with the acquisition of Phillips.
Our offshore products segment reported much improved operating results in 2005 compared to 2004 as a result of increased activity and greater fixed cost absorption. Our offshore products backlog totaled $110.7 million at December 31, 2005 and $97.5 million at December 31, 2004. We believe that the offshore construction and development business is characterized by lengthy projects and a long “lead-time” order cycle. While change in backlog levels from one quarter to the next does not necessarily evidence a long-term trend, we believe activity levels in our offshore products segment will increase in future quarters, given the strength in our backlog at December 31, 2005 in addition to strong business prospects.
Management believes that fundamental oil and gas supply and demand factors will continue to support a high level of drilling activity in North America which should continue to positively impact the Company, particularly its tubular services and well site service segments. However, recent declines in natural gas prices could lead to reduced drilling activity in the near term which would negatively impact our operating and financial results. Our customers are increasing their spending on deepwater offshore exploration and development which should benefit our offshore products segment. However, there can be no assurance that our expectations will be realized and there is a risk that high energy prices could negatively impact worldwide economic growth and, correspondingly, reduce the demand for energy causing oil and gas expenditures to decline which would be adverse to our business.
Consolidated Results of Operations
Year Ended December 31, 2005 Compared to Year Ended December 31, 2004
Revenues. Total revenues increased $560.6 million, or 57.7%, to $1,531.6 million during the year ended December 31, 2005 compared to revenues of $971.0 million during the year ended December 31, 2004. Offshore products revenues increased $64.4 million, or 31.1%, due to higher activity levels supporting offshore production facility construction. Tubular services revenues and tons shipped increased $284.4 million, or 66.6%, and 65,500 tons, or 19.3%, respectively, in the year ended December 31, 2005 compared to the year ended December 31, 2004 due to increased industry demand, higher OCTG prices, the Hunting acquisition completed in May 2004 and the Phillips acquisition that closed in June 2005. Our average OCTG selling prices increased 39.8% from the year 2004 to the year 2005. Well Site services revenues increased $211.8 million, or 62.9%, to $548.7 million for the year 2005 compared to $336.9 million for the year 2004. Our drilling revenues increased $40.3 million, or 86.9%, because of contributions from the Elenburg acquisition, which added seven rigs in February 2005, higher dayrates earned and additional rigs added to the fleet. The Elenburg acquisition contributed $21.8 million of the $40.3 million increase in revenues generated from the Company’s drilling operations. Our hydraulic workover revenues increased by $6.3 million, or 18.8%, in the year 2005 compared to the year 2004 because of higher activity in our primary operating areas, especially the U.S. Gulf of Mexico and Venezuela. Rental tools generated revenues in the year ended December 31, 2005 of $134.8 million, which were $67.9 million, or 101.5%, higher than the year ended December 31, 2004 due to the acquisition of Stinger, capital expenditures made since last year, improving U.S. drilling activity and modest price increases. The Stinger acquisition accounted for $55.3 million of the $67.9 million revenue increase generated by the Company’s rental tools business line. Accommodations revenues in the year ended December 31, 2005 were $287.3 million, an increase of $97.3 million, or 51.2%, over the accommodations revenues reported in the year ended December 31, 2004 primarily because of increased activity in support of the oil sands developments in Canada.
Gross Margin. Our gross margins, which we calculate before a deduction for depreciation expense, increased $129.1 million, or 65.7%, from $196.4 million in the year ended December 31, 2004 to $325.5 million in the year ended December 31, 2005. Our overall gross margin as a percent of revenues was 21.3% in the year 2005 compared to 20.2% in 2004. Gross margin percentages increased in all businesses except accommodations where a greater percentage of revenues was generated by manufacturing activities which generally earn a significantly lower margin than accommodations rental and service activities.
Total gross margins at offshore products were $61.7 million in the year 2005 compared to $37.6 million in 2004, representing an increase of 64.1%. Offshore products gross margin percentage improved from 18.2% in 2004 to 22.8% in 2005 due to higher activity, which resulted in greater overhead absorption, and cost savings and efficiencies resulting from manufacturing facility consolidations that occurred in 2004.
Tubular services gross margins increased $35.8 million, or 70.6%, in the year ended December 31, 2005 compared to the year ended December 31, 2004 as a result of price increases and increased oil and gas drilling activity which strengthened demand for our tubular products and services. Our tubular services segment gross margin as a percent of revenues increased from 11.9% in 2004 to 12.2% in 2005.
Well Site services gross margins increased by $69.2 million, or 64.0%, in the year 2005 compared to the year 2004. Well Site services gross margin as a percentage of revenues increased slightly to 32.3% in 2005 compared to 32.1% in 2004. Drilling gross margins in the year ended December 31, 2005 totaled $32.9 million compared to $14.6 million in the year ended December 31, 2004, an increase of $18.3 million, or 125.3%. Of the $18.3 million increase in drilling gross margins, $8.7 million was generated by the Elenburg acquisition and one of our newly constructed rigs placed in service in June 2005 in the Rocky Mountain area. Our drilling services gross margin percentage improved to 37.9% of revenues in 2005 from 31.5% of revenues in 2004 due to higher dayrates and a move from billing on a footage rate basis to billing on a dayrate basis for many of our drilling rigs. Under a daywork drilling contract, the customer pays for certain costs that the Company would normally provide when drilling on a footage basis and assumes more risks than on a footage basis. Workover gross margins improved by $4.2 million, or 55.3%, in the year 2005 compared to the prior year because of higher activity in the U.S. Gulf of Mexico and Venezuela. The workover gross margin percentage increased to 29.6% of revenues for 2005 compared to 22.6% in the year 2004 due primarily to higher utilization and
dayrates. Rental tools gross margins totaled $66.4 million in the year ended December 31, 2005 compared to $30.4 million in the year ended December 31, 2004, an increase of $36.0 million, or 118.4%. Rental tools gross margin percentage increased from 45.4% for the year 2004 to 49.3% in 2005. The improvement resulted from higher utilization of tools, modestly higher rental rates and the positive impact of the Stinger acquisition. Accommodations gross margins in the year ended December 31, 2005 totaled $66.2 million compared to $55.5 million in the year ended December 31, 2004, an increase of $10.7 million, or 19.3%. The gross margin percentage declined to 23.0% during 2005 compared to the 29.2% gross margin percentage realized during 2004 due to a higher relative mix of lower margin manufacturing revenues, extended warm weather during the fourth quarter and increased mobilization costs in late 2005 compared to late 2004.
Selling, General and Administrative Expenses. Selling, general and administrative expenses (SG&A) increased $19.9 million, or 30.6%, for the year 2005 compared to 2004. During the year ended December 31, 2005, SG&A totaled $84.7 million, or 5.5% of revenues, compared to SG&A of $64.8 million, or 6.7% of revenues, for the year ended December 31, 2004. SG&A did not increase at the same rate as revenues as we were able to successfully leverage our fixed cost structure. Increased SG&A expense associated with acquisitions completed since 2004, higher ad valorem taxes for increased levels of OCTG inventory, increased incentive compensation expense, and higher professional fees associated with Sarbanes-Oxley compliance were the primary factors causing increased SG&A in 2005 compared to 2004.
Depreciation and Amortization. Depreciation and amortization expense increased $10.7 million, or 29.8%, in the year 2005 compared to the year 2004 due primarily to acquisitions of businesses and capital expenditures made in the past year.
Operating Income. Our operating income represents revenues less (i) cost of sales, (ii) selling, general and administrative expenses, (iii) depreciation and amortization expense, and (iv) other operating (income) expense. Our operating income increased $99.5 million, or 104.6%, to $194.6 million for the year ended December 31, 2005 from $95.1 million for the year ended December 31, 2004. Offshore products operating income increased $19.4 million, tubular services operating income increased $34.0 million and well site services operating income increased $49.2 million. These increases were partially offset by higher corporate costs of $3.1 million.
Interest Expense. Interest expense increased $6.2 million, or 81.3%, for the year ended December 31, 2005 compared to the year ended December 31, 2004. Interest expense increased due to higher debt levels resulting from acquisitions completed since December 31, 2004 and capital expenditures, combined with higher interest rates.
Income Tax Expense. Income tax expense totaled $60.7 million, or 33.3% of pretax income, during the year ended December 31, 2005 compared to $29.4 million, or 33.1% of pretax income, during the year ended December 31, 2004. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Tax Matters” discussion below.
Year Ended December 31, 2004 Compared to Year Ended December 31, 2003
Revenues. Revenues increased $247.3 million, or 34.2%, to $971.0 million during the year ended December 31, 2004 compared to revenues of $723.7 million during the year ended December 31, 2003. Tubular services revenues and tons shipped increased $191.6 million, or 81.3%, and 70.8 thousand tons, or 26.3%, respectively, in the year ended December 31, 2004 compared to revenues and tons shipped in the year ended December 31, 2003 due to increased industry demand, higher OCTG prices, and contributions from the acquisition of the Hunting OCTG distribution business which was closed in May 2004. Well site services revenues increased $80.8 million, or 31.6%, while offshore products revenues decreased $25.1 million, or 10.8%, during the same period. Well site services revenues increased compared to the prior year due primarily to increased drilling activity in the United States, increased oil sands development activity in Canada, an international catering and facilities management contract, favorable Canadian dollar exchange rates, the impact of capital expenditures made since December 31, 2003 and rental tool acquisitions which were acquired for total consideration of $52.0 million. These rental tool acquisitions were completed in the fourth quarter of 2003 and in January and April of 2004. Offshore products revenues decreased as a result of lower
activity supporting offshore production facility construction given the typical lengthy time period between offshore discoveries and installation of production facilities.
Gross Margin. Our gross margins, which we calculate before a deduction for depreciation expense, increased $45.8 million, or 30.4%, from $150.6 million in the year ended December 31, 2003 to $196.4 million in the year ended December 31, 2004. Our overall gross margin as a percent of revenues was essentially flat in 2004 compared to 2003. Well site services gross margins increased $27.2 million, or 33.6%, to $108.1 million in the year ended December 31, 2004 compared to the year ended December 31, 2003. Within our well site services segment, our shallow drilling and specialty rental tool businesses’ gross margins increased $4.3 million, or 41.7%, and $9.0 million, or 42.1%, respectively, during the year ended December 31, 2004 compared to the year 2003. Three drilling rigs were added in our shallow drilling business (added in December 2003, February 2004 and December 2004). In addition, we realized higher utilization and footage drilling rates for all of our drilling rigs and contributions from rental tool acquisitions completed in the fourth quarter of 2003 and in January and April 2004. Also in well site services, our work force accommodations, catering and logistics services and modular building construction services gross margins increased by $14.8 million, or 36.4%, in the year ended December 31, 2004 compared to the year ended December 31, 2003 primarily because of increased camp and catering activity supporting oil sands development in Canada and an international catering and facilities management contract. Our hydraulic workover gross margins decreased by $0.9 million, or 10.6%, as a result of decreased utilization, especially in West Africa and the Middle East. Our well site services gross margin percent increased slightly to 32.1% in the year ended December 31, 2004 compared to 31.6% in the year ended December 31, 2003.
Offshore products gross margins decreased $18.4 million, or 32.9%, from $56.0 million in the year ended December 31, 2003 to $37.6 million in the year ended December 31, 2004 due to decreased activity, reduced fixed cost absorption and inefficiencies associated with various facilities consolidations undertaken during 2004. Additionally, offshore products margins were lower in 2004 compared to 2003 due to a less favorable mix of higher margin connector products. These factors caused offshore products gross margin percent to decline from 24.1% of revenues in the year 2003 to 18.2% in the year 2004.
Tubular services gross margins increased to $50.7 million, or 11.9% of tubular services revenues, in the year ended December 31, 2004 compared to $13.7 million, or 5.8% of tubular services revenues, in the year ended December 31, 2003 as a result of increased oil and gas drilling activity which increased demand for our tubular products and services, a significant increase in OCTG prices during 2004 and the acquisition of the OCTG distribution business of Hunting for $47.2 million in May 2004, including a purchase price adjustment settled in October 2004. Tubular services margins expanded during 2004 and reached historically high levels given the significant increase in OCTG prices coupled with strong demand.
Selling, General and Administrative Expenses. During the year ended December 31, 2004, selling, general and administrative expenses (SG&A) totaled $64.8 million, or 6.7% of revenues, compared to SG&A of $57.7 million, or 8.0% of revenues, for the year ended December 31, 2003. SG&A expense increased primarily as a result of acquisitions completed in 2003 and 2004, higher postretirement benefit costs in 2004 due to the recording of a gain upon settlement of plan liabilities in 2003, higher professional fees and higher bonus accruals under the incentive compensation plan. The increase in professional fees was largely attributable to costs associated with Sarbanes-Oxley compliance.
Depreciation and Amortization. Depreciation and amortization expense increased $8.1 million in 2004 compared to 2003 due primarily to acquisitions of businesses completed since 2003 and capital expenditures made in 2003.
Operating Income. Our operating income represents revenues less (i) cost of sales, (ii) selling, general and administrative expenses, (iii) depreciation and amortization expense, and (iv) other operating expense (income). Our operating income increased $29.9 million, or 45.9%, to $95.1 million for the year ended December 31, 2004 from $65.2 million for the year ended December 31, 2003. Well site services operating income increased $18.3 million from 2003 to 2004. Offshore products operating income decreased $20.7 million while tubular services operating income increased $34.9 million. Corporate and other charges increased by $2.6 million in 2004 compared to 2003.
Interest Expense. Interest expense was lower by $0.2 million in the year ended December 31, 2004 compared to the year ended December 31, 2003. Increased interest expense attributable to higher debt levels resulting from acquisitions completed during the first half of 2004 and higher interest rates in 2004 was more than offset by lower debt issuance cost amortization compared to 2003.
Income Tax Expense. Income tax expense totaled $29.4 million, or 33.1% of pretax income, during the year ended December 31, 2004 compared to $14.2 million, or 24.2% of pretax income, during the year ended December 31, 2003. 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, increasing and replacing our drilling rig, rental tool and workover assets, funding new product development and funding 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, more recently, proceeds from our convertible note offering (see Note 7 to Consolidated Financial Statements included in this Annual Report on Form 10-K).
Cash totaling $33.4 million was provided by operations during the year ended December 31, 2005 compared to cash totaling $97.2 million provided by operations in the year ended December 31, 2004. During 2005, $138.2 million was used to fund working capital. Significantly increased working capital was invested in tubular services inventory ($129.1 million of total working capital invested for 2005) due to increased volumes and prices paid. At December 31, 2005, our tubular services inventory increased 70,000 tons from December 31, 2004 and the per ton cost of inventory also increased from $1,192 per ton at December 31, 2004 to $1,578 per ton at December 31, 2005. Additionally, trade receivables increased as a result of higher revenues and were only partially offset by higher accounts payable and accrued liability levels.
Cash was used in investing activities during the years ended December 31, 2005 and 2004 in the amount of $229.9 million and $137.7 million, respectively. Capital expenditures totaled $83.4 million and $60.0 million during the years ended December 31, 2005 and 2004, respectively. Capital expenditures in both years consisted principally of purchases of assets for our well site services segment. In addition, we completed various acquisitions totaling $147.6 million and $80.8 million net of cash acquired, during the years 2005 and 2004, respectively.
On February 1, 2005, we completed the acquisition of Elenburg Exploration Company, Inc. (Elenburg), a Wyoming based land drilling company for cash consideration of $21.3 million, net of cash acquired and including transaction costs, but excluding a note payable to the former owners of $0.8 million. Elenburg owned and operated 7 rigs which provide shallow land drilling services in Montana, Wyoming, Colorado, and Utah.
Effective May 1, 2005 we acquired Stinger Wellhead Protection, Inc., certain affiliated companies and related intellectual property and, effective June 1, 2005, we completed the acquisition of Stinger’s international operations (collectively, Stinger) for cash consideration of $84.7 million, net of cash acquired and including transaction costs, but excluding a note payable to the former owners of $5.0 million. Stinger provides wellhead isolation equipment and services through its 29 locations in the United States, Canada, Central 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.
On June 2, 2005, we purchased Phillips Casing and Tubing, L.P. (Phillips) for cash consideration of $31.2 million, including transaction costs. Phillips distributes oil country tubular goods (OCTG), primarily carbon ERW (electronic resistance welded) pipe, from its facilities in Midland and Godley, Texas.
On June 6, 2005, we acquired Noble Structures, Inc. for cash consideration of $7.9 million, including transaction costs, but excluding a note payable of $0.8 million. The acquisition expanded our accommodation
manufacturing capabilities in Canada in order to meet increased demand for remote site facilities, principally in the oil sands region.
The cash consideration paid for all of our acquisitions in the period was initially funded utilizing our existing bank credit facility and a $25 million bridge loan (See Note 7 to the Consolidated Financial Statements included in this annual report on Form 10-K). Accounting for the acquisitions made in the period 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.
We currently expect to spend a total of approximately $125.0 million for capital expenditures during 2006, for maintenance and upgrade of our equipment and facilities and also to expand our product and service offerings. We expect to fund these capital expenditures with internally generated funds and proceeds from borrowings under our revolving credit facilities.
Net cash of $195.3 million was provided by financing activities during the year ended December 31, 2005, primarily as a result of revolving credit borrowings and the issuance of $175 million aggregate principal amount of 2 3/8% contingent convertible senior notes due in 2025 (23/8% notes) in the second and third quarters of 2005. See Note 7 to the Consolidated Financial Statements included in this Annual Report on Form 10-K. Net proceeds from the 23/8% notes were utilized to repurchase $30 million of our common stock, which was classified as treasury stock at December 31, 2005, to repay an outstanding bridge loan of $25 million and to repay indebtedness of $114.5 million under our revolving credit facility. 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. Through December 31, 2005, a total of $30 million of our stock (1,183,432 shares), acquired with a portion of the proceeds from the issuance of the 23/8% notes, has been repurchased under this program. No shares of our stock were repurchased during the three months ended December 31, 2005 and a total of up to $20 million remains available under the program.
Our primary bank credit facility (the Credit Facility), which matures in January 2010, provides for $325 million of revolving credit. The credit agreement, which governs our Credit Facility (the Credit Agreement), 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 2005, our applicable margin over LIBOR ranged from 1% to 2% and it was 1.25% as of December 31, 2005. Our weighted average interest rate paid under the Credit Agreement was 4.6% during the year ended December 31, 2005 and 3.6% for the year ended December 31, 2004.
As of December 31, 2005, we had $222.5 million outstanding under the Credit Facility and an additional $12.0 million of outstanding letters of credit, leaving $90.5 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 $8.4 million. We had no borrowings outstanding under these other facilities as of December 31, 2005. Our total debt represented 39.0% of our total capitalization at December 31, 2005.
We believe that cash from operations and available borrowings under our credit facilities will be sufficient to meet our liquidity needs in the coming twelve months. 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 debt and lease obligations at December 31, 2005 (in thousands):
Our debt obligations at December 31, 2005 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, 2005. We do not have any off balance sheet arrangements.
Tax Matters
Our primary deferred tax asset, which totaled $9.8 million at December 31, 2005, is related to $27.9 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 generated. Our ability to utilize a significant portion of the 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 NOL’s will be utilized.
Our income tax provision for the year ended December 31, 2005 totaled $60.7 million or 33.3% of pretax income. The income tax provision for the year 2005 included a $4.7 million income tax benefit related to the reversal of substantially all of the remaining valuation allowance applied against NOLs which were recorded as of the prior year end. Based upon a review of the potential effects of all pertinent evidence, we have concluded that substantially all of the remaining valuation allowance which we had recorded against our NOL deferred tax asset was unnecessary.
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, fines, penalties, interest, warranty claims, contract claims and discontinued operations.
The determination of impairment on long-lived assets, including goodwill, is conducted when indicators of impairment are present. If such indicators were present, the determination of the amount of impairment would be based on 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, 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 9 - Income Taxes” 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.
In purchase transactions, we must estimate the fair values of assets and liabilities acquired. Judgment is required to determine these valuations and amounts assigned to individual assets and liabilities will impact future results of operations.
Recent Accounting Pronouncements
In November 2004, the FASB issued Statement of Financial Accounting Standards No. 151, “Inventory Costs - an amendment of ARB 43, Chapter 4” (“SFAS 151”). SFAS 151 clarifies the accounting for abnormal amounts of idle facility expense, freight, handling costs and wasted material. Paragraph 5 of Accounting Research Bulletin (“ARB”) 43, Chapter 4 “Inventory Pricing,” previously stated that “. . .under certain circumstances, items such as idle facility expense, excessive spoilage, double freight, and rehandling costs may be so abnormal as to require treatment as current-period charges. . .” SFAS 151 requires that those items be recognized as current-period charges regardless of whether they meet the criterion of “so abnormal.” In addition, SFAS 151 requires that the allocation of fixed production overheads to the costs of conversion be based on the normal capacity of the production facilities. SFAS 151 is effective for fiscal years beginning after June 15, 2005. The Company does not believe the implementation of SFAS 151 will have a material impact on the Company’s financial position, results of operations or cash flows.
On December 16, 2004, the FASB issued FASB Statement No. 123 (revised 2004), Share-Based Payment, which is a revision of FASB Statement No. 123, Accounting for Stock-Based Compensation. Statement 123(R) supersedes APB Opinion No. 25, Accounting for Stock Issued to Employees, and amends FASB Statement No. 95, Statement of Cash Flows. Generally, the approach in Statement 123(R) is similar to the approach described in Statement 123. However, Statement 123(R) requires all share-based payments to employees, including grants of employee stock options, to be recognized in the income statement based on their fair values. Pro forma disclosure is no longer an acceptable alternative.
As permitted by SFAS No. 123, the Company currently accounts for share-based payments to employees using the APB No. 25 intrinsic value method and, as such, generally recognizes no compensation cost for employee stock options. Accordingly, the adoption of SFAS No. 123(R)’s fair value method will have an impact on our results of operations, although it will have no impact on our overall financial position. Had we adopted SFAS No. 123(R) in prior periods, the impact of that standard would have approximated the impact of SFAS No. 123 as described in the disclosure of pro forma net income and earnings per share in Note 12 of this Annual Report on Form 10-K. Statement No. 123(R) also requires the benefits of tax deductions in excess of recognized compensation cost to be reported as a financing cash flow, rather than as an operating cash flow. This requirement will reduce net operating cash flows and increase net financing cash flows in
periods after adoption. While the company cannot estimate what those amounts will be in the future (because they depend on, among other things, when employees exercise stock options), the amount of operating cash flows recognized in prior periods for such excess tax deductions for stock option exercises were $3.7 million, $1.1 million and $1.8 million in 2005, 2004 and 2003, respectively. We adopted the provisions of this Statement on January 1, 2006, using the modified prospective method, and continue to study the provisions of this new pronouncement to determine the impact on our financial statements.
In May 2005, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards (SFAS) No. 154, “Accounting Changes and Error Corrections, a replacement of APB Opinion No. 20 and FASB Statement No. 3.” Among other changes, this Statement requires retrospective application for voluntary changes in accounting principles, unless it is impractical to do so. Guidance is provided on how to account for changes when retrospective application is impractical. This Statement is effective on a prospective basis beginning January 1, 2006.
Item 7A.
Item 7A.
Quantitative And Qualitative Disclosures About Market Risk
Interest Rate Risk. We have long-term debt and revolving lines of credit subject to the risk of loss associated with movements in interest rates. As of December 31, 2005, we had floating rate obligations totaling approximately $222.5 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, 2005 levels, our consolidated interest expense would increase by a total of approximately $2.2 million annually.
Foreign Currency Exchange Rate Risk. Our operations are conducted in various countries around the world 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 2005, our realized foreign exchange gains were $0.2 million. These gains 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 42 through 71 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 14 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)
Disclosure Controls and Procedures
Our Chief Executive Officer and Chief Financial Officer performed an evaluation of our disclosure controls and procedures, which have been designed to permit us to effectively identify and timely disclose important information. They concluded that the controls and procedures were effective as of December 31, 2005 to ensure that material information was accumulated and communicated to the Company’s management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure.
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 45 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 management’s assessment of the effectiveness of the Company’s internal control over financial reporting and the effectiveness of the Company’s internal control over financial reporting is set forth in this Annual Report on Form 10-K on Page 47 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, 2005 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 2005 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 2006 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 2006 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 2006 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 2006 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 2006 Annual Meeting of Stockholders.
The table below provides information relating to our equity compensation plans as of December 31, 2005:
*
We do not have any equity compensation plans not approved by our 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 2006 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 2006 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 44 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/ DOUGLAS E. SWANSON
Douglas E. Swanson
President and 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 March 1, 2006.
OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES
INDEX TO
CONSOLIDATED FINANCIAL STATEMENTS
Management’s Annual Report on Internal Control Over Financial Reporting
Report of Independent Registered Public Accounting Firm on Consolidated Financial Statements
Report of Independent Registered Public Accounting Firm on Management’s Assessment of the Effectiveness of the Company’s Internal Control Over Financial Reporting and on the Effectiveness of the Company’s Internal Control Over Financial Reporting
47-48
Consolidated Statements of Income for the Years Ended December 31, 2005, 2004, and 2003
Consolidated Balance Sheets at December 31, 2005 and 2004
Consolidated Statements of Stockholders’ Equity and Comprehensive Income for the Years Ended December 31, 2005, 2004 and 2003
Consolidated Statements of Cash Flows for the Years Ended December 31, 2005, 2004, and 2003
Notes to Consolidated Financial Statements
53-76
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.:
The management of Oil States International, Inc. and subsidiaries (Oil States International, Inc. or the Company) is responsible for establishing and maintaining adequate internal control over financial reporting. Oil States International, Inc.’s internal control system was designed to provide reasonable assurance to the Company’s management and Board of Directors regarding the preparation and fair presentation of published financial statements.
All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation.
Oil States International, Inc.’s management assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2005. 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, 2005, the Company’s internal control over financial reporting is effective based on those criteria.
During 2005, the Company acquired Elenburg Exploration Company, Inc., Stinger Wellhead Protection, Inc. and related companies, and Noble Structures, Inc., in separate purchase business combinations. 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 Elenburg Exploration Company, Inc., Stinger Wellhead Protection, Inc. and related companies, and Noble Structures, Inc., from the scope of our assessment of the effectiveness of the Company’s internal control over financial reporting as of December 31, 2005. These entities are wholly-owned subsidiaries of the Company at December 31, 2005. The total assets and total revenues of Elenburg Exploration Company, Inc., Stinger Wellhead Protection, Inc. and related companies, and Noble Structures, Inc., represent approximately 10.9% and 5.2%, respectively, of the total consolidated assets and total consolidated revenues of the Company as of and for the year ended December 31, 2005.
Oil States International, Inc.’s independent registered public accounting firm has audited our assessment and the effectiveness of the Company’s internal control over financial reporting. This report appears on Page 47.
OIL STATES INTERNATIONAL, INC.
Houston, Texas
March 1, 2006
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, 2005 and 2004, 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, 2005. 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, 2005 and 2004, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2005, in conformity with U.S. generally accepted accounting principles.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of the Company’s internal control over financial reporting as of December 31, 2005, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 1, 2006 expressed an unqualified opinion thereon.
ERNST & YOUNG LLP
Houston, Texas
March 1, 2006
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 management’s assessment, included in the accompanying Management’s Annual Report on Internal Control Over Financial Reporting, that Oil States International, Inc. and subsidiaries (Oil States International, Inc. or the “Company”) maintained effective internal control over financial reporting as of December 31, 2005, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). 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. Our responsibility is to express an opinion on management’s assessment and an opinion on the effectiveness of the Company’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
As indicated in the accompanying Management’s 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 Elenburg Exploration Company, Inc., Stinger Wellhead Protection, Inc. and related companies, and Noble Structures, Inc., which are included in the 2005 consolidated financial statements of Oil States International, Inc. and constituted approximately 10.9% and 5.2%, respectively, of total consolidated assets and total consolidated revenues of the Company as of and for the year ended December 31, 2005. Management elected not to assess the effectiveness of internal control over financial reporting at these entities because Oil States International, Inc. acquired these entities in purchase business combinations during 2005. Our audit of internal control over financial reporting of Oil States International, Inc. also did not include an evaluation of the internal control over financial reporting of Elenburg Exploration Company, Inc., Stinger Wellhead Protection, Inc. and related companies, and Noble Structures, Inc.
In our opinion, management’s assessment that the Company maintained effective internal control over financial reporting as of December 31, 2005 is fairly stated, in all material respects, based on the COSO criteria. Also, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2005 based on the COSO criteria.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the accompanying consolidated balance sheets of the Company as of December 31, 2005 and 2004 and the related consolidated statements of income, stockholders’ equity and other comprehensive income and cash flows for each of the three years in the period ended December 31, 2005 and our report dated March 1, 2006 expressed an unqualified opinion thereon.
ERNST & YOUNG LLP
Houston, Texas
March 1, 2006
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
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. 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 is principally comprised of the following entities and their respective subsidiaries.
Oil States Industries, Inc.
Oil States Industries, Inc. (OSI), a subsidiary of Oil States, is a leading designer and manufacturer of a diverse range of products for offshore platforms, subsea pipelines, and defense and general industrial applications. Major product lines include flexible bearings, advanced connectors, winches, mooring and lifting systems, services for installing and removing offshore platforms, downhole production equipment, and custom molded products. Sales are made primarily to major oil companies, large and small independent oil and gas companies, drilling contractors, and well service and workover operators on a worldwide basis. OSI has facilities in Arlington, Houston and Lampasas, Texas; Houma, Louisiana; Tulsa, Oklahoma; Scotland; Brazil; England; Singapore and Thailand.
PTI Group, Inc.
PTI is located in Alberta, Canada and is a supplier of integrated housing, food, site management and logistics support services to remote sites utilized by extractive and other industries primarily in Canada, Europe, the Middle East and the United States.
HWC Energy Services, Inc.
HWC provides worldwide well control services, drilling services and rental equipment to the oil and gas industry. HWC operates primarily in Texas, Louisiana, Ohio, Oklahoma, New Mexico and Wyoming, along with foreign operations conducted in Venezuela, the Middle East, and Africa. Its hydraulic well control operations provide, globally, hydraulic workover (snubbing) units for emergency well control situations and, in selected markets, various hydraulic well control solutions involving well drilling and workover and completion activities. In West Texas, Ohio, and the Rocky Mountain area, HWC operates, through its subsidiaries Capstar Drilling, L.P. and Elenburg Exploration Company, shallow well drilling rigs with automated pipe handling capabilities. Specialty Rental Tools and Supply, L.P., a subsidiary of HWC, provides rental equipment for drilling and workover operations in Texas, Louisiana, Mississippi, New Mexico, Oklahoma and Wyoming. Stinger Wellhead Protection, Inc. and affiliates (Stinger), a subsidiary of HWC, provides wellhead isolation equipment and services in the U.S., Canada, South America and Central America.
Sooner, Inc.
Sooner is a distributor of oilfield tubular products with operations located primarily in the United States. The majority of sales are to large fully integrated and independent oil companies headquartered in the U.S.
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.
OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Fair Value of Financial Instruments
The Company’s financial instruments consist of cash and cash equivalents, investments, receivables, payables, and debt instruments. The Company believes that the carrying values of these instruments on the accompanying consolidated balance sheets approximate their fair values.
Inventories
Inventories consist of tubular and other oilfield products, manufactured equipment, spare parts for manufactured equipment and supplies for remote accommodation facilities. Inventories include raw materials, labor, 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 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.
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 $18.3 million at December 31, 2005 and 2004.
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. 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.
OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
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. Foreign exchange risk is also 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, 2004. 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 $0.2 million gain in 2005, a $1.3 million loss in 2004 and a $0.2 million gain in 2003 and are included in other operating expense (income).
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 revenues. For drilling services contracts based on footage drilled, we recognize revenues as footage is drilled.
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
OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
realized. Management will continue to evaluate the appropriateness of the reserve in the future based upon the operating results of the Company.
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.
We purchased 73% of our oilfield tubular goods from three suppliers in 2005, with the largest supplier representing 52% of our purchases in the period. The loss of any significant supplier in our tubular services segment could adversely affect us.
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 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 267,348 and 277,183 shares of common stock as of December 31, 2005 and 2004, 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 Notes averaged 240,138 during the fourth quarter of 2005 and are included in the calculation of fully diluted earnings per share.
Stock-Based Compensation
The Company accounts for its stock-based compensation plans under the principles prescribed by the Accounting Principles Board’s Opinion No. 25 (“APB No. 25”), “Accounting for Stock Issued to Employees.” Stock options awarded under the Equity Participation Plan normally do not result in recognition of compensation expense. Shares of restricted stock awarded under the Equity Participation Plan are
OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
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, $0.1 million and $0.3 million in the years ended December 31, 2005, 2004 and 2003, respectively. An additional $0.1 million was recognized in 2004 for a stock option performance award. Effective January 1, 2006, the Company will begin recording stock-based compensation expense in accordance with FASB Statement No. 123(R). See Note 4. The Company accounts for assets held in a rabbi trust for certain participants under the Company’s deferred compensation plan in accordance with EITF 97-14. See Note 12.
Guarantees
The Company adopted FASB Interpretation No. 45 (FIN 45), “Guarantor’s Accounting and Disclosure Requirements for Guarantees, including Indirect Indebtedness of Others,” during 2003. FIN 45 requires disclosures and accounting 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 between 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 2004, the Company recorded a $1.0 million increase in its warranty reserves related to a potential warranty claim associated with an international subsea pipeline project installed during 2000 in addition to smaller accruals of a more recurring nature. The international subsea pipeline project warranty issue was settled in 2005 for an amount approximately equal to the amount reserved for this issue.
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, 2005, the maximum potential amount of future payments that the Company could be required to make under these guarantee agreements was approximately $12.0 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.
OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
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, the valuation allowance recorded on net deferred tax assets, warranty, inventory and bad debt reserves. Actual results could differ from those estimates.
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, 2005 and 2004 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, 2005 and 2004, is presented below (in thousands):
OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Depreciation expense was $43.3 million, $33.7 million and $26.7 million in the years ended December 31, 2005, 2004 and 2003, respectively.
4.
Recent Accounting Pronouncements
In November 2004, the FASB issued Statement of Financial Accounting Standards No. 151, “Inventory Costs - an amendment of ARB 43, Chapter 4” (“SFAS 151”). SFAS 151 clarifies the accounting for abnormal amounts of idle facility expense, freight, handling costs and wasted material. Paragraph 5 of Accounting Research Bulletin (“ARB”) 43, Chapter 4 “Inventory Pricing,” previously stated that “. . .under certain circumstances, items such as idle facility expense, excessive spoilage, double freight, and rehandling costs may be so abnormal as to require treatment as current-period charges. . .” SFAS 151 requires that those items be recognized as current-period charges regardless of whether they meet the criterion of “so abnormal.” In addition, SFAS 151 requires that the allocation of fixed production overheads to the costs of conversion be based on the normal capacity of the production facilities. SFAS 151 is effective for fiscal years beginning after June 15, 2005. The Company does not believe the implementation of SFAS 151 will have a material impact on the Company’s financial position, results of operations or cash flows.
On December 16, 2004, the FASB issued FASB Statement No. 123 (revised 2004), Share-Based Payment, which is a revision of FASB Statement No. 123, Accounting for Stock-Based Compensation. Statement 123(R) supersedes APB Opinion No. 25, Accounting for Stock Issued to Employees, and amends FASB Statement No. 95, Statement of Cash Flows. Generally, the approach in Statement 123(R) is similar to the approach described in Statement 123. However, Statement 123(R) requires all share-based payments
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
to employees, including grants of employee stock options, to be recognized in the income statement based on their fair values. Pro forma disclosure is no longer an acceptable alternative.
As permitted by SFAS No. 123, the Company currently accounts for share-based payments to employees using the APB No. 25 intrinsic value method and, as such, generally recognizes no compensation cost for employee stock options. Accordingly, the adoption of SFAS No. 123(R)’s fair value method will have an impact on our results of operations, although it will have no impact on our overall financial position. Had we adopted SFAS No. 123(R) in prior periods, the impact of that standard would have approximated the impact of SFAS No. 123 as described in the disclosure of pro forma net income and earnings per share in Note 12 of this Annual Report on Form 10-K. Statement No. 123(R) also requires the benefits of tax deductions in excess of recognized compensation cost to be reported as a financing cash flow, rather than as an operating cash flow. This requirement will reduce net operating cash flows and increase net financing cash flows in periods after adoption. While the company cannot estimate what those amounts will be in the future (because they depend on, among other things, when employees exercise stock options), the amount of operating cash flows recognized in prior periods for such excess tax deductions for stock option exercises were $3.7 million, $1.1 million and $1.8 million in 2005, 2004 and 2003, respectively. We adopted the provisions of this Statement on January 1, 2006, using the modified prospective method, and continue to study the provisions of this new pronouncement to determine the impact on our financial statements.
In May 2005, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards (SFAS) No. 154, “Accounting Changes and Error Corrections, a replacement of APB Opinion No. 20 and FASB Statement No. 3.” Among other changes, this Statement requires retrospective application for voluntary changes in accounting principles, unless it is impractical to do so. Guidance is provided on how to account for changes when retrospective application is impractical. This Statement is effective on a prospective basis beginning January 1, 2006.
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
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
approach, at the “reporting unit” level. A reporting unit is the operating segment, or a business one level below that operating segment (the “component” level) if discrete financial information is prepared and regularly reviewed by management at the component level. We have seven reporting units as of December 31, 2005, an increase of one since December 31, 2004 and 2003. Goodwill is allocated to each of the reporting units based on actual acquisitions made by the Company and its subsidiaries. We 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 amortizes the cost of other intangibles over their estimated useful lives unless such lives are deemed indefinite. Amortizable intangible assets are tested 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. No provision for impairment was required based on the evaluations performed.
Changes in the carrying amount of goodwill for the year ended December 31, 2005 and 2004, are as follows (in thousands):
The portion of goodwill deductible for tax purposes totals approximately $19.9 million at December 31, 2005. The following table presents the total amount assigned and the total amount amortized for major intangible asset classes as of December 31, 2005 and 2004 (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 6.7 years and 3.6 years as of December 31, 2005 and 2004, respectively. Total amortization expense is expected to be $3.8 million, $3.4 million, $2.0 million, $1.6 million and $0.7 million in 2006, 2007, 2008, 2009 and 2010, respectively. Amortization expense was $3.4 million, $2.3 million and $1.2 million in the years ended December 31, 2005, 2004 and 2003, respectively.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
7.
Long-term Debt
As of December 31, 2005 and 2004, long-term debt consisted of the following (in thousands):
Scheduled maturities of combined long-term debt as of December 31, 2005, 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 $2.2 million and $1.3 million, respectively, at December 31, 2005. The value of capitalized leases and the related accumulated depreciation totaled $3.1 million and $1.6 million, respectively, at December 31, 2004.
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.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
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 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 fourth quarter 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. The notes were not callable by the Company or convertible by the note holders at anytime in 2005. 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. If the Company does not keep the registration statement effective for approximately the next eighteen months, additional contingent interest would have to be paid to the note holders, subject to certain provisions. 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.
The Company utilized $30 million of the net proceeds of the offering on June 15, 2005 to repurchase 1,183,432 shares of its common stock and the remaining portion of the net proceeds to repay a $25.0 million bridge loan and to repay approximately $66.0 million of borrowings under its senior secured credit facility. Net proceeds of the additional notes sold in July 2005, totaling $48.5 million, were utilized to repay borrowings under the Company’s senior secured credit facility.
On May 11, 2005 the Company borrowed $25 million under a bridge loan with a bank which was due in 2010. The loan was unsecured and was repaid in full on June 21, 2005. The average interest rate on this bridge loan for the period it was outstanding was 6.0%.
Revolving Credit Facility
On January 31, 2005, the Company amended its Credit Agreement dated October 30, 2003. The Company’s credit facility totals $325.0 million. Under this senior secured revolving credit facility with a group of banks, up to $45.0 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 January 31, 2010. 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 1.0% to 1.75%; or
•
an alternate base rate equal to the higher of the bank’s prime rate and the federal funds effective rate plus 0.5% (or, in the case of Canadian dollar denominated loans, the Canadian Prime Rate) plus a margin ranging up to 0.75%, depending upon the ratio of total debt to EBITDA as defined in the credit facility.
Commitment fees ranging from 0.375% to 0.5% 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
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
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 restrict the Company’s ability to borrow additional funds, encumber assets, pay dividends, sell assets except in the normal course of business 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, 2005, we had $222.5 million outstanding under this facility and an additional $12.0 million of outstanding letters of credit leaving $90.5 million available to be drawn under the facility.
In conjunction with executing the senior secured revolving credit facility on October 30, 2003, the Company recognized additional non-cash interest expense of $1.2 million, after taxes, for the write-off of deferred financing costs related to its prior credit 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, 2005.
8.
Retirement Plans
The Company sponsors defined contribution plans. Participation in these plans is available to substantially all employees. The Company recognized expense of $4.3 million, $3.1 million and $2.9 million, respectively, related to its various defined contribution plans during the years ended December 31, 2005, 2004 and 2003, respectively.
9.
Income Taxes
Consolidated pre-tax income for the years ended December 31, 2005, 2004 and 2003 consisted of the following (in thousands):
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
The components of the income tax provision for the years ended December 31, 2005, 2004 and 2003 consisted of the following (in thousands):
The provision for taxes differs from an amount computed at statutory rates as follows for the years ended December 31, 2005, 2004 and 2003 (in thousands):
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
The significant items giving rise to the deferred tax assets and liabilities as of December 31, 2005 and 2004 are as follows (in thousands):
Reclassifications of the Company’s deferred tax balance based on net current items and net non-current items as of December 31, 2005 and 2004 are as follows (in thousands):
Our primary deferred tax asset, which totaled $9.8 million at December 31, 2005, is related to $27.9 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 NOL’s will be utilized.
Our income tax provision for the year ended December 31, 2005 totaled $60.7 million, or 33.3% of pretax income. The income tax provision for the year 2005 included a $4.7 million income tax benefit related to the reversal of substantially all of the remaining valuation allowance applied against NOLs which were recorded
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
as of the prior year end. Based upon a review of the potential effects of all pertinent evidence, we have concluded that substantially all of the remaining valuation allowance which we had recorded against our NOL deferred tax asset was unnecessary. We believe that we will more likely than not generate sufficient taxable income in future years to realize the benefit of substantially all of the deferred tax asset associated with these net operating losses. The Company has federal alternative minimum tax net operating loss carryforwards of $10.4 million, which will expire in the years 2010 through 2020.
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 $192 million at December 31, 2005 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.
During the year ended December 31, 2005, the Company recognized a tax benefit triggered by employee exercises of stock options totaling $3.7 million. Such benefit was credited to additional paid-in capital.
The American Jobs Creation Act of 2004 (the “Jobs Act”) that was signed into law in October 2004, introduced a special one-time dividends received deduction on the repatriation of foreign earnings to a U.S. taxpayer (repatriation provision), provided certain criteria are met. The Act provides for a special one-time deduction of 85 percent of certain foreign earnings that are repatriated in either the Company’s last tax year that began before the enactment date, or the first tax year that begins during the one-year period beginning on the date of enactment. The Company did not use the one time dividend received deduction incentive.
The Jobs Act also introduced a requirement for companies to disclose any penalties imposed on them or any of their consolidated subsidiaries by the Internal Revenue Service (“IRS”) for failing to satisfy tax disclosure requirements relating to “reportable transactions”. During the year ended December 31, 2005, 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.
10.
Supplemental Cash Flow Information
Cash paid during the years ended December 31, 2005, 2004 and 2003 for interest and income taxes was as follows (in thousands):
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Components of cash used for acquisitions as reflected in the consolidated statements of cash flows for the years ended December 31, 2005, 2004 and 2003 are summarized as follows (in thousands):
In connection with acquisitions made in 2005 and 2004, the Company had non-cash transactions consisting of the issuance of $6.6 million and $4.6 million, respectively, of notes payable to sellers.
In 2003, we spent $16.8 million, including acquisition costs, to acquire five businesses. Three of the businesses were rental tool companies acquired for a total consideration, excluding cash acquired, of $10.5 million. The acquired rental tool companies conduct operations in South Texas and Louisiana and were combined with our existing rental tool business within our well site services segment. The remaining two businesses, acquired for aggregate consideration of $6.3 million, excluding cash acquired, were combined with our offshore products segment.
In January 2004, we completed the acquisition of several related rental tool companies for $36.6 million. The companies, based in South Texas are leading providers of thru-tubing services and ancillary equipment rentals. These companies have been combined with our rental tool subsidiary, and report through the well site services segment. We completed an additional acquisition of a rental tool company in April 2004 for $4.8 million. In May 2004, we purchased the oil country tubular goods (“OCTG”) distribution business of Hunting Energy Services, L.P., a wholly-owned affiliate of Hunting plc, for $47.2 million, including a purchase price adjustment settled in October 2004. In connection with the transaction, we purchased Hunting’s U.S. tubular inventory, assumed certain customer contracts and entered into supply and distribution relationships with Hunting for the future. Hunting’s distribution operations were merged into our tubular services segment. In October 2004, our offshore products segment acquired a small business for $0.5 million which has become part of our existing elastomers business.
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. Elenburg owns and operates 7 rigs which provide shallow land drilling services in Montana, Wyoming, Colorado, and Utah. The Elenburg acquisition allowed us to expand its drilling business into different geographic areas. The operations of Elenburg have been included in the drilling services business within the well site services segment.
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 29 locations in the United States, Canada, Central 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.
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 oil country tubular
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
goods (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.
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 cash consideration paid for all of the Company’s acquisitions in the period was initially funded utilizing its existing bank credit facility and a $25 million bridge loan (See Note 7 to the Consolidated Financial Statements included in this Annual Report on Form 10-K). The operations of Noble have been included in the accommodations business within our well site services segments.
11.
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, 2005, are as follows (in thousands):
Rental expense under operating leases was $5.7 million, $4.5 million and $4.9 million for the years ended December 31, 2005, 2004 and 2003, respectively.
As of December 31, 2005, the Company had an outstanding forward purchase option contract through January 2006 with a bank totaling $1.5 million for the purchase of foreign currency as a hedge to expected future billings. There was no significant unrealized gain or loss associated with this contract.
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.
On February 18, 2005, the Company announced that it had conducted an internal investigation prompted by the discovery of over billings totaling approximately $400,000 by one of its subsidiaries (the “Subsidiary”)
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
to a government owned oil company in South America. The over billings were detected by the Company during routine financial review procedures, and appropriate financial statement adjustments were included in its previously reported fourth quarter 2004 results. The Company and independent counsel retained by the Company’s audit committee conducted separate investigations consisting of interviews and a thorough examination of the facts and circumstances in this matter. The Company voluntarily reported the results of its investigation to the Securities and Exchange Commission (the “SEC”) and has fully cooperated with requests for information received from the SEC. The SEC recently completed its informal investigation of this matter. On October 31, 2005, the Company’s counsel received a “Wells Notice” from the staff of the SEC indicating that the staff has made a preliminary decision to recommend that the SEC bring a civil action against the Company alleging violations of provisions of the Securities and Exchange Act of 1934 relating to the maintenance of books, records and internal accounting controls and procedures as set forth in Sections 13(b)(2)(A) and (B) of the Act. The alleged violations related to this over billings matter. A “Wells Notice” is not a formal allegation or proof of wrongdoing. The Company has responded to the SEC staff regarding the “Wells Notice” and is currently in discussions with the SEC staff regarding this matter.
12.
Stock-Based Compensation
In October 1995, the FASB issued SFAS No. 123, “Accounting for Stock-Based Compensation,” which requires the Company to record stock-based compensation at fair value. In December 2002, the FASB issued SFAS No. 148, “Accounting for Stock Based Compensation - Transition and Disclosure.” The Company has adopted the disclosure requirements of SFAS No. 148 and has elected to record employee compensation expense utilizing the intrinsic value method permitted under Accounting Principles Board (APB) Opinion No. 25, “Accounting for Stock Issued to Employees.”
The Company accounts for its employee stock-based compensation plan under APB Opinion No. 25 and its related interpretations. Accordingly, any deferred compensation expense would be recorded for stock options based on the excess of the market value of the common stock on the date the options were granted over the aggregate exercise price of the options. This deferred compensation would be amortized over the vesting period of each option. The Company is authorized to grant common stock based awards covering 7,700,000 shares of common stock under the 2001 Equity Participation Plan, as amended and restated, (the Equity Participation Plan), to employees, consultants and directors with amounts, exercise prices and vesting schedules determined by the Company’s compensation committee of its Board of Directors. Since February 2001, all option grants have been priced at the closing price on the day of grant, except a variable option award granted in 2002 for up to 100,000 shares based on various performance criteria whose outcome was determined in 2003. This specific award ultimately totaled 67,000 option shares which were priced based on the 2002 award date price. In addition, all options vest 25% per year and have a life ranging from six to ten years. When the exercise price of options granted under the Equity Participation Plan has been equal to or greater than the market price of the Company’s shares of common stock on the date of grant, no compensation expense, related to this plan has been recorded. When the exercise price per share of the option award has been lower than the current market price per share, as was the case in the one instance of the 2002 variable option award, compensation expense was recognized for the intrinsic value of the award as required by APB Opinion No. 25.
A total of 56,952 shares of restricted stock were awarded in 2005 to employees and directors with an aggregate value of $1.2 million. No restricted stock awards were made in 2003 or 2004. The fair market value of the awards are being charged to expense over the vesting period of the restricted stock awards. Had compensation expense for the Equity Participation Plan been determined consistent with SFAS No. 123
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
utilizing the fair value method, the Company’s net income and earnings per share at December 31, 2005, 2004 and 2003, would have been as follow (in thousands, except per share amounts):
The following table summarizes stock option activity for each of the three years ended December 31, 2005:
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
The following table summarizes information for stock options outstanding at December 31, 2005:
At December 31, 2005, 2,732,383 shares were available for future grant under the Stock Option Plan.
The weighted average fair values of options granted during 2005, 2004, and 2003 were $8.32, $5.18, and $4.55 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 2005, 2004, and 2003, respectively: risk-free interest rates of 3.9%, 3.1%, and 3.0%, no expected dividend yield, expected lives of 5.0, 5.0, and 5.5 years, and an expected volatility of 37%, 37% and 37%.
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. All contributions to the participants’ accounts vest immediately. 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, 2005, the balance of the assets in the Trust totaled $4.2 million, including 31,000 shares of common stock of the Company reflected as treasury stock at a value of $0.3 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
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
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, 2005 was $3.9 million and is classified as “Other noncurrent assets” in the consolidated balance sheet. Amounts payable to the plan participants at December 31, 2005, including the market value of the shares of the Company’s common stock that are reflected as treasury stock, was $4.9 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 $0.4 million in 2005, $0.2 million in 2004 and $0.1 million in 2003.
13.
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, wellsite 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.
Financial information by industry segment for each of the three years ended December 31, 2005, 2004 and 2003, 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.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Financial information by geographic segment for each of the three years ended December 31, 2005, 2004 and 2003, 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, 2005, 2004 and 2003.
OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
14.
Quarterly Financial Information (Unaudited)
The following table summarizes quarterly financial information for 2005, 2004 and 2003 (in thousands, except per share amounts):
Earnings per share are computed independently for each of the quarters presented. Therefore, the sum of the quarterly earnings per share may not equal the total computed for the year.
*
Represents “revenues” less “product costs” and “service and other costs” included in the Company’s consolidated statements of operations.
15.
Valuation Allowances
Activity in the valuation accounts was as follows (in thousands):
OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
16.
Workover Business Merger
On November 12, 2005 we announced that one of our subsidiaries signed a definitive agreement to combine its hydraulic workover business (Hydraulic Well Control) with Boots & Coots International Well Control, Inc. (Amex: WEL) (Boots & Coots) in exchange for 26.5 million shares of Boots & Coots common stock and senior subordinated promissory notes totaling $15.0 million. The transaction is subject to the approval of Boots & Coots’ shareholders and is expected to close in March 2006.
As discussed herein, Hydraulic Well Control, based in Houma, Louisiana, provides live and dead well workover services throughout the world, utilizing a fleet of 27 owned and operated hydraulic workover units. Hydraulic Well Control has operations in the U.S., Venezuela, Algeria, West Africa and the Middle East. Hydraulic Well Control financial information is included in Item 7 - Management’s Discussion and Analysis of Financial Condition and Results of Operations and in our Consolidated Financial Statements Footnote No. 11 - Segment and Related Information under the caption “Hydraulic Workover”.
Upon the closing of the transaction, Oil States will own approximately 44% of the combined company and will receive senior subordinated promissory notes totaling $15.0 million in aggregate principal from Boots & Coots bearing a fixed annual interest rate of 10% and maturing four and one half years from the closing of the transaction. In addition, we have the right under the transaction agreement to nominate three additional members to Boots & Coots’ existing five-member Board of Directors.
INDEX OF EXHIBITS
*
Filed herewith
**
Management contracts or compensatory plans or arrangements
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Furnished herewith.