ITEM 1. BUSINESS
OUR COMPANY
We are 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.
General information about us can be found at www.oilstatesintl.com. Our annual report on Form 10-K, quarterly reports on Form 10-Q and current reports on Form 8-K, as well as any amendments and exhibits to those reports, are available free of charge through our website as soon as reasonably practicable after we file them with, or furnish them to, the SEC.
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.
In 2002, we acquired the following six businesses for total consideration of approximately $72.0 million, which was financed primarily with borrowings under our credit facility:
- 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.
- 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.
- 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.
- 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 $16.7 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 will be combined with our existing rental tool business within our well site services segment. The remaining two businesses, acquired for aggregate consideration of $6.2 million, were combined with our offshore products segment.
In January 2004, the Company completed the acquisition of several related rental tool companies. 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 will report through the well site services segment. The Company paid a total of $34.7 million in cash for the stock of the companies which was funded by the Company's credit facility.
OUR INDUSTRY
We operate in the oilfield service industry, which provides 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 15 to our Consolidated and Combined 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.
The years 2001 through 2003 were indicative of the cyclical nature of the oilfield service business. For our well site services and tubular services businesses, there was higher activity, as measured by the North American rig count, during the first eight months of 2001 followed by declining activity levels, except for seasonal winter peaks in Canadian activity, through the spring of 2002. The average annual North American rig count declined 27% from 2001 to 2002. During 2003, the average North American rig count was 1,404 and increased by 307 rigs, or 28%, compared to 2002. As of December 31, 2003 the North American rig count was 1,531. See additional rig count information under "Management's Discussion and Analysis of Financial Condition and Results of Operations -Overview" in this Annual Report on Form 10-K. Our offshore products business is more influenced by deepwater development activity and rig construction and repair. Results of operations in this segment of our business has increased throughout the years 2002 and 2003 as we shipped projects from our backlog which had increased in 2001 and 2002.
OFFSHORE PRODUCTS
OVERVIEW
During the year ended December 31, 2003, we generated approximately 32% of our revenue and 39% 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. 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 and Singapore 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, 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 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:
- flexible bearings and connector products;
- subsea pipeline products;
- marine winches, mooring and lifting systems and rig equipment;
- blowout preventor stack assembly, integration, testing and repair services; and
- other products and services.
Flexible Bearings and Connector Products. We are the principal supplier of flexible bearings, or FlexJoints(R), 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(R) 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(R) 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 systems, are a significant means of producing oil and gas, particularly in deepwater environments. We provide many important products for the construction of these systems. 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(R) 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 segments 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.
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:
- forged steel Y-shaped connectors for joining two pipelines into one;
- pressure-balanced safety joints for protecting pipelines from anchor snags or a shifting sea-bottom;
- electrical isolation joints; and
- 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:
- repair clamps used to seal leaks and restore the structural integrity of a pipeline;
- mechanical connectors used in repairing subsea pipelines without having to weld;
- flanges used to correct misalignment and swivel ring flanges; and
- 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(R) hydraulic system. The Hydra-Lok(R) tool, which has been successfully used at depths of 3,000 feet, does not require diver intervention or guidelines.
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:
- elastomer consumable downhole products for onshore drilling and production;
- metal-elastomeric FlexJoints(R) used in a variety of military, marine and aircraft applications; and
- 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 $62.6 million at December 31, 2003, compared to $100.1 million at December 31, 2002 and $72.4 million at December 31, 2001. We expect substantially all our backlog as of December 31, 2003 will be completed in 2004. 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.
Our three largest customers in the offshore products markets in 2003 were ABB Ltd, BP plc and Modec International. None of these customers accounted for greater than 5% of our consolidated revenues during 2003. Our main competitors include ABB Ltd, FMC Technologies, Inc., Energy Cranes International, Ltd. and Rolls-Royce plc.
TUBULAR SERVICES
OVERVIEW
On February 14, 2001, the Company completed its acquisition of Sooner. Sooner's business is reported as our tubular services segment.
During the year ended December 31, 2003, we generated approximately 33% of our revenue and 9% 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:
- distribute a broad range of casing and tubing;
- provide threading, remediation, logistical and inventory services; and
- offer e-commerce pricing, ordering and tracking 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 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 predominately focused in the United States.
OCTG MARKET
Our tubular services segment primarily distributes casing and tubing. Casing forms the structural wall in oil and gas wells to provide support and prevent caving during drilling operations. Casing is 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 five offices and facilities located near areas of oil and gas exploration and development activity. We have distribution relationships with most major domestic and international steel mills.
In this business, inventory management is critical to our success. We maintain on-the-ground inventory in 58 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.
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 for export to other countries, including Canada, Venezuela, Ecuador, Algeria, South Africa and Cameroon.
CUSTOMERS, SUPPLIERS AND COMPETITORS
Our three largest end-user customers in the tubular distribution market in 2003 were El Paso Corporation, Burlington Resources and Conoco Phillips. El Paso Corporation revenues for all of our segments accounted for 6.5% of our consolidated revenues during 2003. Conoco Phillips and Burlington Resources each accounted for less than 5% of our consolidated revenues during 2003. Our three largest suppliers were U.S. Steel Group, Maverick Tube Corporation and Lone Star Technologies. Although we have a leading market share position in tubular services distribution, the market is highly fragmented. Our main competitors in tubular distribution are Total Premier, Red Man Pipe & Supply Co., Inc. and Bourland and Leverich.
WELL SITE SERVICES
OVERVIEW
During the year ended December 31, 2003, we generated approximately 35% of our revenue and 52% 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 expenditures by oil and gas producers which is a function of prices they receive for oil and gas. In general, we expect activity levels to continue to be highly correlated to oil and gas expenditures which is a function of many factors that affect well economics.
Demand for our workover services is impacted significantly by offshore activity both in the United States and international areas. Our hydraulic workover units compete with jackup rigs and conventional workover rigs for shallow water workover projects. Our hydraulic workover units can be operated, at times, at a lower cost than alternatives such as jack-up rigs. Costs to mobilize and set up our hydraulic workover units, for example, are lower than alternative equipment. Some operations on oil and gas wells under pressure situations require the use of a hydraulic workover unit. On the other hand, when activity levels in the oil and gas business decline, our hydraulic units face more competition from larger equipment offered at lower prices which can become more competitive with our equipment.
Our rental equipment fleet which is predominantly located near the U.S. Gulf of Mexico market, is more production oriented and is dependent to a significant degree on the level of development and workover activities in the U.S. Gulf Coast area and the Gulf of Mexico. We face competition from many smaller companies in our rental equipment business in the U.S. Gulf of Mexico market. The lack of increased drilling in the U.S. Gulf of Mexico has resulted in a lower than anticipated increase in rental tool revenues and profitability in 2003.
PRODUCTS AND SERVICES
Workover Services. We provide our workover products and services primarily to customers in the U.S., Venezuela, the Middle East 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 vertically moving tubulars in and out of a wellbore using hydraulic pressure. This unit is used for servicing wells with no pressure at the surface and also has the ability of working safely on wells under pressure. This feature allows these units to be used for underbalanced drilling and workover and also in well control applications. When the 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, 2003 we had 28 "stand alone" hydraulic workover units. Of these 28 units, 16 were located in the U.S., five were located in the Middle East, five were located in Venezuela and two were located in West Africa. 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 30.7% during 2003 compared to 28.5% in 2002. As of December 31, 2003, nine of our hydraulic workover units were working or under contract. The length of time 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 10 to 12 simultaneous jobs involving our hydraulic workover units.
Our three largest customers in workover services in 2003 were Sonatrach, Chevron Texaco Corporation and Total Fina Elf. None of these customers accounted for greater than 5% of our consolidated revenues during 2003. Our main competitors in workover services are Halliburton Company, Cudd Pressure Control, Inc. and Superior Energy Services.
Drilling Services. Our drilling services business is located in Odessa, Texas and Wooster, Ohio and provides drilling services for shallow to medium depths ranging from 2,000 to 10,000 feet. Drilling services are typically used during the exploration and development stages of a field. We have a total of 17 semi-automatic drilling rigs with hydraulic pipe handling booms and lift capacities ranging from 200,000 to 300,000 pounds. We added three of these drilling rigs in 2002, one in December 2003 and one in February 2004. Thirteen of these drilling rigs are located in Odessa, Texas and four are located in Wooster, Ohio. As of December 31, 2003, 15 rigs were working or under contract. Utilization increased from 85.6% in 2002 to 88.4% in 2003.
We market our drilling services directly to a diverse customer base, consisting of both major and independent oil companies. Our largest customers in drilling services in 2003 included Energen Resources Corporation, Apache
Corporation and Chevron Texaco Corporation. None of these customers accounted for greater than 5% of our consolidated revenues. Our main competitors are Patterson-UTI Energy Inc., Key Energy Services, Inc. and Union Drilling, Inc. 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:
- wireline and coiled tubing pressure control equipment;
- pipe recovery systems;
- gravel pack operations on well bores; and,
- 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, 2003, we provided rental equipment at 21 U.S. distribution points in Texas, Louisiana, Oklahoma, Mississippi, New Mexico and Wyoming, an increase of four locations since December 31, 2002. We completed rental tool acquisitions totaling $10.5 million during 2003 and $34.7 million during January 2004. We provide rental equipment on a day rental basis with rates varying depending on the type of equipment and the length of time rented.
Our three largest customers in rental equipment in 2003 were Schlumberger Well Services, Baker Atlas and BP plc. None of these customers accounted for greater than 5% of our consolidated revenues during 2003.
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 mining 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 have activity, currently, in Afghanistan and the Balkans, serving the Canadian peacekeeping forces. During the peak of our operating season, we typically provide these services in over 200 separate locations throughout the world with separate location populations ranging from 20 to 2000 persons.
Work Force Accommodations, Catering and Logistics Services. We sell and lease portable living quarters, galleys, diners and offices and provide portable generators, water, sewage systems and catering services as part of our work force services. We provide various client-specific building configurations to customers for use in both onshore and offshore applications. We provide our integrated work force logistics services to customers under long-term and short-term contractual arrangements.
Modular Building Construction. 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.
In 2003 our three largest customers in work force accommodations, catering, logistics and modular building construction were Syncrude Canada Ltd, SNC-Lavalin Group Inc. and Nabors Drilling. None of these customers accounted for greater than 5% of our consolidated revenues during 2003. Our main competitors are Atco Structures Limited, Eurest Deutschland GmbH, Aramark Corporation and Abbyville Offshore Inc.
EMPLOYEES
As of December 31, 2003, we had approximately 3,900 full-time employees, 35% of whom are in our offshore products segment, 63% 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 452 employees located in Canada and the United Kingdom as of December 31, 2003. 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 administrative 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.
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, or 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.
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.
Although we believe that we are in substantial compliance with existing laws and regulations, 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.
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS
We include the following cautionary statement to take advantage of the "safe harbor" provisions of the Private Securities Litigation Reform Act of 1995 for any forward-looking statement made by us, or on our behalf. The factors identified in this cautionary statement are important factors (but not necessarily all of the important factors) that could cause actual results to differ materially from those expressed in any forward-looking statement made by us, or on our behalf. You can typically identify forward-looking statements by the use of forward-looking words such as "may," "will," "could," "project," "believe," "anticipate," "expect," "estimate," "potential," "plan," "forecast," and other similar words. All statements other than statements of historical facts contained in this Annual Report on Form 10-K, including statements regarding our future financial position, budgets, capital expenditures, projected costs, plans and objectives of management for future operations and possible future acquisitions, are forward-looking statements. Where any such forward-looking statement includes a statement of the assumptions or bases underlying such forward-looking statement, we caution that, while we believe such assumptions or bases to be reasonable and make them in good faith, assumed facts or bases almost always vary from actual results. The differences between assumed facts or bases and actual results can be material, depending upon the circumstances.
Where, in any forward-looking statement, we, or our management, express an expectation or belief as to the future results, such expectation or belief is expressed in good faith and believed to have a reasonable basis. However, there can be no assurance that the statement of expectation or belief will result or be achieved or accomplished. Taking this into account, the following are identified as important factors that could cause actual results to differ materially from those expressed in any forward-looking statement made by, or on behalf of, our company:
- fluctuations in the prices of oil and gas;
- the level of drilling activity;
- the level of offshore oil and gas developmental activities;
- general economic conditions;
- our ability to find and retain skilled personnel;
- the availability of capital; and
- the other factors identified under the captions "Risks Related to Our Business Generally" and "Risks Related to Our Operations" that follow.
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 to explore for, develop and produce oil and gas. If these 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. Many factors affect the supply and demand for oil and gas and therefore influence product prices, including:
- the level of production;
- the levels of oil and gas inventories;
- the expected cost of developing new reserves;
- the cost of producing oil and gas;
- the availability of attractive oil and gas field prospects which may be affected by governmental actions or environmental activists which may restrict drilling;
- the availability of transportation infrastructure;
- depletion rates;
- the level of drilling activity;
- worldwide economic activity;
- 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;
- the impact of armed hostilities involving one or more oil producing nations;
- the cost of developing alternate energy sources;
- environmental regulation; and
- tax policies.
EXTENDED PERIODS OF LOW OIL PRICES 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. If oil prices remain near
or below those levels used to determine economic viability for an extended period of time, deepwater activity and our business will be adversely affected.
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:
- disrupt our operations;
- restrict the movement of funds or limit repatriation of profits;
- lead to U.S. government or international sanctions; and
- limit access to markets for periods of time.
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. A significant increase in the wages paid by competing employers could result in a reduction of our skilled labor force, increases in the wage rates that we must pay or both. If either of these events were to occur, our cost structure could increase 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 from a distributor. 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:
- issuance of administrative, civil and criminal penalties;
- denial or revocation of permits or other authorizations;
- reduction or cessation in operations; and
- 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:
- we may not be able to continue to obtain insurance on commercially reasonable terms;
- 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;
- the dollar amount of any liabilities may exceed our policy limits; and
- 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. 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(R) technology. 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 Douglas E. Swanson and other 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, 2003, goodwill represented approximately 31% 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 5 to our Consolidated and Combined 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 2003, we purchased from a single supplier approximately 49% of the tubular goods we distributed and from three suppliers approximately 75% 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.
RISKS RELATED TO OUR RELATIONSHIP WITH SCF
L.E. SIMMONS, THROUGH SCF, EFFECTIVELY CONTROLS THE OUTCOME OF STOCKHOLDER VOTING AND MAY EXERCISE THIS VOTING POWER IN A MANNER ADVERSE TO OUR STOCKHOLDERS.
SCF-III, L.P. and SCF-IV, L.P., private equity funds that focus on investments in the energy industry (collectively, "SCF"), together hold approximately 40% of the outstanding common stock of our company as of February 27, 2004. L.E. Simmons, the chairman of our board of directors, is the sole owner of L.E. Simmons & Associates, Incorporated, the ultimate general partner of SCF. Accordingly, Mr. Simmons, through his ownership of the ultimate general partner of SCF, is in a position to effectively control the outcome of matters requiring a stockholder vote, including the election of directors, adoption of amendments to our certificate of incorporation or bylaws or approval of transactions involving a change of control. The interests of Mr. Simmons may differ from those of our stockholders, and SCF may vote its common stock in a manner that may adversely affect our stockholders.
SCF'S OWNERSHIP INTEREST AND 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.
In addition to SCF's position of effective control, 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. 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.
WE HAVE RENOUNCED ANY INTEREST IN SPECIFIED BUSINESS OPPORTUNITIES, AND SCF AND ITS DIRECTOR NOMINEES ON OUR BOARD OF DIRECTORS GENERALLY HAVE NO OBLIGATION TO OFFER US THOSE OPPORTUNITIES.
SCF has investments in other oilfield service companies that compete with us, and SCF and its affiliates, other than our company, may invest in other such companies in the future. We refer to SCF, its other affiliates and its portfolio companies as the SCF group. Our certificate of incorporation provides that, so long as SCF and its affiliates continue to own at least 20% of our common stock, we renounce any interest in specified business opportunities. Our certificate of incorporation also provides that if an opportunity in the oilfield services industry is presented to a person who is a member of the SCF group, including any of those individuals who also serves as SCF's director nominee of our Company:
- no member of the SCF group or any of those individuals has any obligation to communicate or offer the opportunity to us; and
- such entity or individual may pursue the opportunity as that entity or individual sees fit, unless:
- it was presented to an SCF director nominee solely in that person's capacity as a director of our company and no other member of the SCF group independently received notice of or otherwise identified such opportunity; or
- the opportunity was identified solely through the disclosure of information by or on behalf of our Company.
These provisions of our certificate of incorporation may be amended only by an affirmative vote of holders of at least 80% of our outstanding common stock. As a result of these charter provisions, our future competitive position and growth potential could be adversely affected.
THE AVAILABILITY OF SHARES OF OUR COMMON STOCK FOR FUTURE SALE COULD DEPRESS OUR STOCK PRICE
Sales by SCF and other stockholders of a substantial number of shares of our common stock in the public markets, or the perception that such sales might occur, could have a material adverse effect on the price of our common stock or could impair our ability to obtain capital through an offering of equity securities. SCF has sold shares recently and may continue to sell shares in the future.
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 five tubular sales offices and a total of 21 rental tool supply and distribution points in Texas, Louisiana, New Mexico, Mississippi, Oklahoma and Wyoming. 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 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.
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 2003.
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 49,187,129 shares of common stock outstanding as of February 27, 2004, including 339,965 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 27, 2004 was 99. Our common stock is traded on the New York Stock Exchange under the ticker symbol OIS. There was no public market for our common stock before February 9, 2001. The closing price of our common stock on February 27, 2004 was $13.62 per share.
The following table sets forth the range of high and low sale prices of the Company's 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. Instead, we currently intend to retain our earnings, if any, to finance our business and to use for general corporate purposes. 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.
EQUITY COMPENSATION PLANS
The information relating to the Company's equity compensation plans required by Item 5 is incorporated by reference to such information as set forth in the Company's Definitive Proxy Statement for the 2004 Annual Meeting of Stockholders and from 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 the years ended December 31, 2003, 2002, 2001, 2000, and 1999. The following data should be read in conjunction with Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations and the Company's financial statements, and related notes included in Item 8, Financial Statements and Supplementary Data of this Annual Report on Form 10-K.
SELECTED FINANCIAL DATA (IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
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(1) The unaudited pro forma statements of operations and other financial data for 1999, 2000 and 2001 give effect to:
- 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;
- 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;
- the three-for-one reverse stock split of Oil States common stock effected in connection with our initial public offering;
- 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, 1999, 2000 and 2001, respectively; and
- the acquisition of Sooner in the Combination using the purchase method of accounting as if the acquisition occurred on January 1, 1999, 2000 and 2001, respectively.
(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 amortize 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 1. Business" above.
(3) Our effective tax rate is affected by our net operating loss carry forwards. Our 2003 effective tax rate for financial reporting purposes was approximately 24%. Although there are a number of factors that could affect it, we currently estimate that our 2004 effective tax rate for financial reporting purposes will be approximately 33%. See "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 "Selected Financial Data" and our financial statements and the notes to those statements included elsewhere in this Annual Report on Form 10-K.
This discussion contains forward-looking statements based on our current expectations, assumptions, estimates and projections about us and our industry. These forward-looking statements involve risks and uncertainties. Our actual results could differ materially from those indicated in these forward-looking statements as a result of certain factors, as more fully described under "Cautionary Statement Regarding Forward-Looking Statements" in this Form 10-K. Except to the extent required by law, we undertake no obligation to update publicly any forward-looking statements, even if new information becomes available or other events occur in the future.
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, postretirement benefits, warranty claims and contract claims.
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 record a valuation allowance to reduce our deferred tax assets to the amount that is more likely than not to be realized. While we have considered future taxable income and ongoing prudent and feasible tax planning strategies in assessing the need for the valuation allowance, in the event we were to determine that we would be able to realize our deferred tax assets in the future in excess of our net recorded amount, an adjustment to the deferred tax asset would increase income in the period such determination was made. Likewise, should we determine that we would not likely be able to realize all or part of our net deferred tax asset in the future, an adjustment to the deferred tax asset would be charged to expense in the period such determination was made.
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.
OVERVIEW
We provide a broad range of products and services to the oil and gas industry through our offshore products, well site services and tubular 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. 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. In our well site services business segment, we provide hydraulic well control services, pressure control equipment and rental tools, drilling rigs and work force accommodations, catering and logistics services. Demand for our well site services depends upon the level of worldwide drilling and workover activity. 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 and the types of wells being drilled.
Energy and oilfield service activities are highly cyclical, depending upon crude oil and natural gas pricing, among other things. Beginning in late 1996 and continuing through the early part of 1998, stabilization of oil and gas prices led to increases in drilling activity as well as the refurbishment and new construction of drilling rigs. In the second half of 1998, crude oil prices declined substantially and reached levels below $11 per barrel in early 1999. With this decline in pricing, many of our customers substantially reduced their capital spending and related activities. This industry downturn continued through most of 1999. The price of crude oil and natural gas increased over 1999 levels in 2000 and 2001 due to improved demand for oil, supply reductions by OPEC member countries and reductions in natural gas storage levels. Crude oil and natural gas prices decreased significantly from levels reached in early 2001 by the end of 2001. The economic slowdown in the United States and the rest of the world, moderate weather and the resultant increased inventories of oil and gas, especially in the United States, contributed
to those price declines. With those price reductions, our customers responded with decreased drilling activity and spending on exploration and development. In early 2002, oil and gas prices began to increase and they are currently at relatively high historic levels.
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 is highly correlated to movements in the rig count in the United States. 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.
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(1) Canadian rig counts typically increase during the peak winter drilling season.
The rig count in the United States and Canada, as measured by Baker Hughes Incorporated, fell from 1,481 rigs in February 1998 to 559 rigs in April 1999. The downturn in activity in 1998 and 1999 had a material adverse effect on demand for our products and services, and the results of our operations decreased significantly. Our business benefited from the improvement in crude oil and natural gas pricing in 2000 and early 2001 and the resulting increases in the rig count in 2000 and the first half of 2001. During 2002, the U.S. rig count decreased in the first half of the year. The U.S. rig count reached its lowest level since 1999 when it totaled 738 rigs on April 15, 2002. Since then, the U.S. rig count has risen and totaled 1,404 as of December 31, 2003.
We believe that our offshore products segment lagged the general market recovery in 2000 and 2001 because its sales primarily relate to offshore construction and production facility development which generally occur later in the exploration and development cycle. Worldwide offshore construction and development activity improved in 2002, and backlog in our offshore products segment increased to $100.1 million at December 31, 2002, compared to $72.4 million at December 31, 2001. We reported record results for our offshore product segment in 2002 and 2003 as a result of this increased backlog. Our backlog has decreased to $62.6 million as of December 31, 2003 reflecting decreased activity in support of offshore construction and production facility development. As a result, we expect 2004 activity in the offshore products segment to result in reduced revenues compared to 2003 with smaller projects and lower margin work.
Throughout 2003, North American oilfield activity levels, as measured by rig counts, increased as exploration and production companies spent additional cash flows resulting from higher oil and gas prices. However, the rig count increase resulted primarily from shallow land drilling activity while the U.S. offshore Gulf of Mexico rig count remained relatively flat in 2003. Our tubular services and well site services businesses results of operations are impacted by activity levels in the U.S. Gulf of Mexico. The lack of increased drilling in the U.S. Gulf of Mexico and other more service-oriented areas, versus the shallow land wells being drilled, has resulted in a lower than anticipated increase in oil service revenue and profitability in 2003. We expect strong Canadian and U.S. land drilling activity to continue in 2004. In addition, contributions from late 2003 and early 2004 acquisitions should favorably impact results of operations in our well site services segment in 2004.
Management believes that fundamental oil and gas supply and demand factors will lead to increased drilling activity in North America over time. The combination of declining U.S. natural gas production, relatively high cash flow for exploration and production companies, solid demand growth for both oil and natural gas and expected continued OPEC discipline should lead to continued rise in oilfield activity levels. However, there can be no assurance that these expectations will be realized or that increased activity will be in regions that will benefit our business segments. We view the recent increases in oil and natural gas prices and reduction in related supplies as important steps toward increased demand for oilfield service activity.
THE COMBINATION
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. The combined results of Oil States, HWC and PTI form the basis for the discussion of our results of operations for those periods. The operations of Oil States, HWC and PTI represent two of our business segments, offshore products and well site services. Concurrently with the closing of our initial public offering in February 2001, Oil States acquired Sooner, and the acquisition was accounted for using the purchase method of accounting. The pro forma financial statement for the year ended December 31, 2001 reflects the acquisition of Sooner effective as of January 1, 2001. Following the acquisition of Sooner, we reported under three business segments.
CONSOLIDATED AND PRO FORMA RESULTS OF OPERATIONS
YEAR ENDED DECEMBER 31, 2003 COMPARED TO YEAR ENDED DECEMBER 31, 2002
Revenues. Revenues increased $106.9 million, or 17.3%, to $723.7 million during the year ended December 31, 2003 compared to revenues of $616.8 million during the year ended December 31, 2002. Well site services revenues increased $46.3 million, or 22.1%, and offshore products revenues increased $41.3 million, or 21.7%, during the same period. Well site services revenues increased compared to the prior year primarily due to increased drilling activity in Canada and the United States, favorable Canadian dollar exchange rates, which strengthened compared to the U.S. dollar in 2003 compared to 2002 resulting in an increase of approximately $14.0 million, and the impact of acquisitions completed in the third quarter of 2002. Canadian expenses were also impacted by exchange rate movements in 2003 compared to 2002 and offset some of these revenue gains. Offshore products revenues increased primarily as a result of greater activity supporting offshore production facility construction, primarily in the U.S. Gulf of Mexico, and the impact of acquisitions completed in the third quarter of 2002. Tubular services revenues increased $19.3 million, or 8.9%, in the year ended December 31, 2003 compared to the prior year. This revenue increase resulted from greater quantities shipped caused by higher rig counts partially offset by lower international sales and reduced revenue per ton shipped caused by product mix oriented to shallow land drilling.
Gross Margin. Our gross margins, which we calculate before a deduction for depreciation expense, increased $20.8 million, or 16.0%, from $129.8 million in the year ended December 31, 2002 to $150.6 million in the year ended December 31, 2003.
Well site services gross margins increased $17.8 million, or 28.2%, to $80.9 million in the year ended December 31, 2003. Within our well site services segment, shallow drilling and specialty rental tool businesses' gross margins increased $4.0 million, or 61.9%, and $3.0 million, or 16.2%, respectively, during the year ended December 31, 2003 compared to the year ended December 31, 2002 primarily as a result of rigs added to the fleet and the rental tool acquisitions completed. Also in the well site services segment, our work force accommodations, catering and logistics services and modular building construction services gross margins increased by $11.1 million, or 37.5%, during the year ended December 31, 2003 compared to the year ended December 31, 2002 because of increased camp and catering activity in Canada and work supporting the Canadian military in Afghanistan and Bosnia. Our hydraulic workover gross margins decreased by $0.3 million, or 2.3%, as a result of decreased activity in Venezuela and a reclassification of certain field expenses, formerly classified as selling, general and administrative expenses, to operating expense. These decreases were almost fully offset by increased gross margin from work in Algeria, which commenced in late 2002. Gross margin as a percent of revenues in well site services increased from 30.1% in 2002 to 31.6% in 2003 primarily because of more profitable accommodations operations caused by higher activity levels.
Offshore products gross margins increased $3.1 million, or 5.9%, from $52.9 million in the year ended December 31, 2002 to $56.0 million during 2003 primarily due to increased revenues from shipments and work in progress. Our offshore products gross margin percentage declined by 3.7% due primarily to a greater percentage of lower-margin fabrication work compared to the prior period and to certain project losses incurred in our subsea pipeline operations and to reduced margins in our winch and crane businesses. Tubular services gross margins decreased to $13.7 million, or 5.8% of tubular services revenues in the year ended December 31, 2003 compared to $13.8 million, or 6.4% of tubular services revenues, in the year ended December 31, 2002 as a result of higher margin sales during 2002, especially in the fourth quarter, and foreign sales, which occurred primarily in the first half of 2002, and did not reoccur in 2003.
Selling, General and Administrative Expenses. During the year ended December 31, 2003, selling, general and administrative expenses (SG&A) totaled $57.7 million, or 8.0% of revenues, compared to SG&A of $51.8 million, or 8.4% of revenues, for the year ended December 31, 2002. Increased SG&A expense primarily resulted from acquisitions completed in the third quarter of 2002. This increase was only partially offset by lower post employment benefit costs caused by the settlement of certain plan liabilities during the current year as explained in Footnote 7 to the Consolidated and Combined Financial Statements contained in this Annual Report on Form 10-K.
Depreciation and Amortization. Depreciation and amortization expense increased $4.6 million in 2003 compared to 2002 due primarily to acquisitions of businesses completed in 2002 and capital expenditures made in 2002 and 2003.
Operating Income. Our operating income represents revenues less (i) cost of sales, (ii) selling, general and administrative expenses and (iii) depreciation and amortization expense plus other operating income. Our operating income increased $10.6 million, or 19.4%, to $65.2 million for the year ended December 31, 2003 from $54.6 million during 2002. Well site services operating income increased by $9.8 million, or 35.8%, while offshore products operating income increased by $0.6 million, or 2.2%. Tubular Services operating income was $6.0 million during the year ended December 31, 2003 compared to $5.4 million for the year ended December 31, 2002, an increase of $0.6 million, or 11.1%. Corporate and other charges increased by $0.4 million in 2003 compared to 2002.
Interest Expense. Interest expense increased $3.0 million, or 61.2%, to $7.9 million for the year ended December 31, 2003 compared to $4.9 million for the year ended December 31, 2002. Increased interest expense was attributable to higher debt levels resulting from acquisitions completed during the third quarter of 2002, capital expenditures made during 2002 and 2003 and the write-off of $1.2 million, after taxes, of unamortized debt issue costs in the fourth quarter of 2003 upon the closing of a new bank credit agreement.
Income Tax Expense. Income tax expense totaled $14.2 million, or 24.2% of pretax income, during the year ended December 31, 2003 compared to $11.4 million, or 22.3% of pretax income, during the year ended December
31, 2002. Decreased amounts of net operating loss carryforwards available to offset currently taxable income has resulted in a higher annual effective tax rate for the year 2003 compared to 2002.
YEAR ENDED DECEMBER 31, 2002 COMPARED TO PRO FORMA YEAR ENDED DECEMBER 31, 2001
Revenues. Revenues decreased $102.9 million, or 14.3%, during the year ended December 31, 2002 to $616.8 million compared to the year ended December 31, 2001. Revenues in our well site services segment decreased $30.0 million, or 12.5%, in the year ended December 31, 2002 compared to the previous year. Within well site services, comparing the year 2002 to the year 2001, our work force accommodations, catering and logistics services and modular building construction services revenues decreased $18.5 million, or 13.6%, due to lower activity in Canada and the U.S. Gulf of Mexico, our land drilling revenues decreased $3.1 million, or 10.1%, due to lower activity and drilling rates, primarily in West Texas, our rental tool services revenues decreased $0.3 million, or 0.8%, because lower activity in our U.S. Gulf of Mexico locations was partially offset by the impact of acquisitions made by the Company in March and August 2002 and our workover services revenues decreased $8.1 million, or 21.8%, as activity, especially in the U.S. Gulf of Mexico, decreased compared to 2001. Our offshore products segment revenues increased $61.3 million, or 47.4%, in the year 2002 compared to the year 2001, due to significantly increased activity supporting offshore production facility construction, primarily in deepwater locations. Our tubular services segment revenues in the year 2002 were $134.2 million, or 38.3%, lower than in the year 2001 because of decreased drilling activity in the United States and significantly lower foreign sales in 2002 compared to 2001.
Gross Margins. Our gross margins, which we calculate before a deduction for depreciation and amortization expense, decreased $7.0 million, or 5.1%, to $129.8 million in the year 2002 compared to the year 2001. Our gross margin as a percent of revenue improved from 19.0% in the year 2001 to 21.0% in 2002 due to a more favorable mix of our revenues consisting of higher margin offshore products and well site services activities with less of our 2002 revenues consisting of tubular sales. Our offshore products' gross margins increased $23.4 million, or 79.3%, in the year 2002 compared to the year 2001 and our gross margin percentage increased to 27.8% in the year 2002 compared to 22.8% in the year 2001 as higher volumes of product shipments lead to increased operating efficiencies in the year 2002. Our well site services gross margins decreased $23.1 million, or 26.8%, to $63.1 million in the year 2002 compared to the year 2001. The gross margin percentage for well site services declined to 30.1% in the year 2002 compared to 35.9% in 2001. Within our well site services segment, our land drilling business gross margins decreased $5.1 million, or 44.7%, to $6.3 million in 2002 compared to total gross margin of $11.4 million in 2001 because of decreased drilling activity and lower prices obtained for drilling services; our rental tool business reported 2002 gross margins totaling $18.4 million, or 51.5% of revenue, compared to 2001 gross margins totaling $18.9 million, or 52.5% of revenue in 2001 as we saw increased price competition for rental tools which offset the positive effect of our 2002 rental tool business acquisitions; our workover services gross margins in the year 2002 totaled $8.7 million, or 30.3% of revenues, compared to 2001 gross margins of $13.4 million, or 36.1% of revenues, as decreased U.S. Gulf of Mexico margins and activity more than offset the positive effect of higher international activity; and our work force accommodations, catering and logistics services and modular building construction services businesses gross margin decreased in 2002 to $29.6 million, or 25.2% of revenue, compared to $42.4 million, or 31.2% of revenue, in the previous year because of the impact of lower drilling activity in 2002 in Canada and the U.S. Gulf of Mexico and because a greater percentage of revenues resulted from relatively low margin construction activity. Our tubular services margins in the year 2002 totaled $13.8 million, a decrease of $8.3 million, or 37.6%, compared to the year 2001. While tubular services gross margins were approximately the same in each of the last two years, the volume of tubular products shipped in 2002 decreased by approximately 29% compared to 2001.
Selling, General and Administrative Expense. During the year 2002, selling, general and administrative expenses (SG&A) increased $0.6 million, or 1.2%, to $51.8 million from $51.2 million in the year 2001. As a percent of revenues, SG&A increased to 8.4% in 2002 compared to 7.1% in 2001. Increased costs in the year 2002 compared to 2001 at our offshore products segment, driven by higher activity and increased employee incentive costs were only partially offset by lower well site services segment costs associated with decreased activity within that segment.
Depreciation and Amortization. Depreciation and amortization expense totaled $23.3 million in the year 2002 compared to $28.7 million in 2001. The $5.4 million decrease is principally related to the elimination of goodwill amortization in 2002 (in comparison, we amortized $7.5 million of goodwill in the year 2001) partially offset by
additional depreciation and amortization associated with capital additions and intangibles recorded as part of business acquisitions in the years 2001 and 2002.
Operating Income. Our operating income represents revenues less (i) cost of sales, (ii) SG&A, and (iii) depreciation and amortization expense plus other operating income. Our operating income decreased $2.7 million, or 4.7%, to $54.6 million for 2002 from $57.3 million in 2001. Operating income from our well site services segment decreased $20.0 million from $47.4 million for 2001 to $27.4 million for 2002. Operating income for our offshore products segment increased $20.7 million to $27.3 million for 2002 compared to $6.6 million in 2001. Operating income in our tubular services segment decreased $7.1 million from $12.5 million in 2001 to $5.4 million in 2002. Corporate/other operating loss improved from a loss of $9.2 million in 2001 to a loss of $5.5 million in 2002 primarily because of the discontinuance of goodwill amortization in 2002.
Net Interest Expense. Net interest expense totaled $4.4 million in the year 2002, a decrease of $5.1 million, or 53.6%, compared to net interest expense of $9.5 million in 2001. Both interest rates and average debt balances were lower during 2002 when compared to 2001. Additionally, a total of $0.8 million of unamortized debt issue costs were expensed in 2001 upon the execution of a new credit facility.
Income Tax Expense. Our income tax expense totaled $11.4 million, or 22.3% of pretax income, in the year 2002 compared to $2.1 million, or 4.3% of pretax income in the year 2001. The increased tax expense is primarily due to the higher effective tax rate which increased in 2002 compared to 2001 as a result of a lower amount of net operating loss carryforwards available to offset taxable income.
LIQUIDITY AND CAPITAL RESOURCES
Our primary liquidity needs are to fund capital expenditures, such as expanding and upgrading our manufacturing facilities and equipment, increasing and replacing our drilling rig, rental tool and workover assets and our accommodation units, 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 and proceeds from borrowings under our bank facilities.
Cash was provided by operations during the years ended December 31, 2003 and 2002 in the amounts of $58.7 million and $45.4 million, respectively. Cash provided by operations in 2003 was generated by our net income plus depreciation and amortization which was partially offset by working capital invested in 2003 in our offshore products and tubular services businesses.
Cash was used in investing activities during the years ended December 31, 2003 and 2002 in the amounts of $54.9 million and $89.4 million, respectively. Capital expenditures totaled $41.3 million and $26.1 million during the years ended December 31, 2003 and 2002, respectively. Capital expenditures in 2003 and 2002 consisted principally of purchases of assets for our well site services businesses and for expansion of our offshore products manufacturing capacity. We completed acquisitions for cash consideration totaling $16.3 million and $64.8 million, respectively, during the years ended December 31, 2003 and 2002. We currently expect to spend a total of approximately $35.0 million during 2004 to upgrade our equipment and facilities and 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. In January 2004, the Company completed the acquisition of several related rental tool companies for cash consideration of $34.7 million. This acquisition was funded by the Company's revolving credit facility. See Note 18 to the Consolidated and Combined financial statements contained in this Annual Report on Form 10K.
Net cash of $4.3 million was provided from financing activities during the year ended December 31, 2003, primarily as a result of revolving credit borrowings and proceeds from stock option exercises.
As of December 31, 2003, we had $128.7 million outstanding under our primary bank credit facility and an additional $10.3 million of outstanding letters of credit, leaving $86.0 million available to be drawn under the facility. Our total debt represented 23.2% of our total capitalization at December 31, 2003.
The following summarizes our debt and lease obligations at December 31, 2003 (in thousands):
Our debt obligations at December 31, 2003 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, 2003. We do not have any off balance sheet arrangements.
In October 2003, we entered into a new $225 million senior secured revolving credit facility with a group of banks. Up to $45.0 million of commitments under the credit facility are available in the form of loans denominated in Canadian dollars and may be made to our principal Canadian operating subsidiaries. This credit facility replaced the existing facility and matures on October 30, 2007, unless extended for an additional one year period with the consent of the lenders. The Company has the option to expand the facility to $250 million. Amounts borrowed under this facility bear interest, at our 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 1.5% to 2.5%; 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 from 0.5% to 1.5%, depending upon the ratio of total debt to EBITDA (as defined in the credit facility).
We pay commitment fees ranging from 0.375% to 0.5% per year on the undrawn portion of the facility, depending upon our leverage ratio. Our weighted average interest rate on the Company's outstanding borrowings under this facility at December 31, 2003 was 3.6%.
Our credit facility is guaranteed by all of our active domestic subsidiaries and, in some cases, our Canadian and other foreign subsidiaries. Our credit facility is secured by a first priority lien on all our inventory, accounts receivable and other material tangible and intangible assets, as well as those of our 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.
Our ability to borrow under the facility is subject to certain customary conditions, including the continuing accuracy of representations and warranties, the lack of material adverse changes, our continuing compliance with laws and the lack of defaults under the facility.
Our credit facility contains negative covenants that restrict our ability to borrow additional funds, encumber assets, pay dividends, sell assets except in the normal course of business and enter into other significant transactions.
In addition, our credit facility requires us to maintain:
- a ratio of EBITDA, less maintenance capital expenditures, to interest expense and certain current maturities of debt of not less than 2.5 to 1.0;
- a level of consolidated net worth of not less than $370 million, plus 50% of each quarter's consolidated net income (but not loss) and 75% of equity offerings;
- a maximum ratio of total debt to EBITDA of not greater than 3.0 to 1.0.
Under our 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.
We had an aggregate of approximately $8.4 million of subordinated debt and capital leases outstanding at December 31, 2003. The subordinated debt will become due and payable at various times through September 2007. See Note 6 to our Consolidated and Combined Financial Statements included in this Annual Report on Form 10-K.
We believe that cash from operations and available borrowings under our credit facility will be sufficient to meet our liquidity needs for the foreseeable future. If our plans or assumptions change or are inaccurate, or we make significant acquisitions, individually or in the aggregate, 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.
TAX MATTERS
For the year ended December 31, 2003, we had deferred tax liabilities, net of deferred tax assets, of approximately $4.3 million for federal income tax purposes before application of valuation allowances. Our primary deferred tax assets are net operating loss carry forwards, or NOLs, which total approximately $63 million. A valuation allowance is currently provided against the majority of our NOLs. The NOLs expire over a period through 2020. Our NOLs are currently limited under Section 382 of the Internal Revenue Code due to a change of control that occurred during 1995. In 2004, approximately $31 million of NOLs are available for use if sufficient income is generated. A successive change in control was triggered in 2003 pursuant to Section 382; however it did not significantly lessen the amount of NOLs available.
Our 2003 effective tax rate was approximately 24%. This low effective tax rate was due to the partial utilization of net operating losses which benefited the consolidated group after the Combination. During 2003, we paid cash taxes of $12.9 million.
RECENT ACCOUNTING PRONOUNCEMENTS
In June 2001, the Financial Accounting Standards Board issued Statements of Financial Accounting Standards (SFAS) No. 141, "Business Combinations," and No. 142, "Goodwill and Other Intangible Assets" (the "Statements"), effective for fiscal years beginning after December 15, 2001. Under the new rules, goodwill and intangible assets deemed to have indefinite lives will no longer be amortized but will be subject to annual impairment tests in accordance with the Statements. Other intangible assets will continue to be amortized over their useful lives.
We began applying the new rules on accounting for goodwill and other intangible assets in the first quarter of 2002. Application of the nonamortization provisions of the Statements resulted in an increase in net income of approximately $8.0 million ($.16 per diluted share) for year 2002. We have performed the required impairment tests of goodwill and indefinite lived intangible assets as of December 31, 2002 and 2003 and there was no impairment of assets indicated.
In June 2001, the Financial Accounting Standards Board issued SFAS No. 143, "Accounting for Asset Retirement Obligations." We were required to adopt this Statement effective January 1, 2003, and it did not have an impact on our consolidated financial statements.
In August 2001, the Financial Accounting Standards Board issued SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets." We were required to adopt this Statement effective January 1, 2002, and it did not have an impact on our consolidated financial statements.
In April 2002, the Financial Accounting Standards Board issued SFAS No. 145 which, among other things, rescinded SFAS No. 4, "Reporting Gains and Losses from Extinguishment of Debt." We adopted this statement in 2003, and as a result, classified as interest expense a $1.2 million non-cash write-off, after taxes, of unamortized
debt issue costs resulting from a new financing completed in October 2003. We reclassified $0.8 million of losses incurred in 2001 on debt restructuring, formerly classified as an extraordinary loss, to interest expense.
We have adopted the disclosure requirements of SFAS No. 148, "Accounting for Stock Based Compensation -- Transition and Disclosure," issued in December 2002, effective with our December 31, 2002 consolidated and combined financial statements and related footnotes.
In January 2003, the Financial Accounting Standards Board (FASB) issued FASB Interpretation No. 46 (FIN 46), "Consolidation of Variable Interest Entities, an interpretation of ARB No. 51." FIN 46 provides guidance on: 1) the identification of entities for which control is achieved through means other than through voting rights, known as "variable interest entities" (VIEs); and 2) which business enterprise is the primary beneficiary and when it should consolidate a VIE. This new requirement for consolidation applies to entities: 1) where the equity investors (if any) do not have a controlling financial interest; or 2) whose equity investment at risk is insufficient to finance that entity's activities without receiving additional subordinated financial support from other parties. In addition, FIN 46 requires that both the primary beneficiary and all other enterprises with a significant variable interest in a VIE make additional disclosures. FIN 46 is effective for all new VIEs created or acquired after January 31, 2003. For VIEs created or acquired prior to February 1, 2003, the provisions of FIN 46 must be applied for the first interim or annual period ending after December 15, 2003. Certain disclosures are effective immediately. Implementation of FIN 46 did not affect the Company.
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, 2003, we had floating rate obligations totaling approximately $128.7 million for amounts borrowed under our revolving credit facility. 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, 2003 levels, our consolidated interest expense would increase by a total of approximately $1.3 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. 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. As of December 31, 2003, we had a foreign currency forward purchase option contract totaling $5.0 million which served as a cash flow hedge for our UK operations. We have incurred no material gains or losses from foreign currency hedging activities.
ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Our combined, pro forma combined and consolidated financial statements and supplementary data of the Company appear on pages 41 through 74 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 16 to our Consolidated and Combined 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
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, 2003 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. During the three-months ended December 31, 2003 we have made no changes in our internal controls over financial reporting or in other factors that could significantly affect our internal controls over financial reporting.
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.
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, 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, 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, under "Section 16(a) Beneficial Ownership Reporting Compliance." This portion of the Definitive Proxy Statement is incorporated herein by reference.
The Company has adopted the Corporate Code of Business Conduct and Ethics, a code of ethics with which every director and employee of the Company is expected to comply. The Corporate Code of Business Conduct and Ethics is publicly available on the Company's website under Investors Relations at www.oilstatesintl.com and is available in print to any stockholder who requests it. If any substantive amendments are made to the Corporate Code of Business Conduct and Ethics or if there is a grant of a waiver, including any implicit waiver, from a provision of the code to the Company's Chief Executive Officer, Chief Financial Officer or Chief Accounting Officer or Controller, the Company will disclose the nature of such amendment or waiver on the Company's website or in a report on Form 8-K.
The Company has also adopted Corporate Governance Guidelines, a set of guidelines by which the Company and its officers and directors are expected to govern the affairs of the Company. The Corporate Governance Guidelines, as well as the charter of the Company's audit, compensation and nominating and corporate governance committees, are available on the Company's website and in print to any stockholder who requests them. This website address is intended to be an inactive, textual reference only. None of the material on this website is incorporated by reference into this report.
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 2004 Annual Meeting of Stockholders.
ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
The table below provides information relating to our equity compensation plans as of December 31, 2003:
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 2004 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 under the heading "Fees Paid to Ernst & Young LLP" and is incorporated herein by reference.
PART IV
ITEM 15.
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
(a) Index to Financial Statements, Financial Statement Schedules and Exhibits
(1) Financial Statements: Reference is made to the index set forth on page 41 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 and Combined 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) Reports on Form 8-K.
(1) Form 8-K dated October 28, 2003 - Item 12. Results of Operations and Financial Condition (Quarter ended September 30, 2003 Earnings Press Release)
(2) Form 8-K dated November 3, 2003 - Item 5. Other Events (New Credit Agreement).
(c) 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 5, 2004.
*By: /s/ CINDY B. TAYLOR -------------------------------------------------- Cindy B. Taylor, pursuant to a power of attorney filed as Exhibit 24.1 to this Annual Report on Form 10-K
OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES
INDEX TO COMBINED, PRO FORMA COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS
UNAUDITED PRO FORMA CONSOLIDATED AND COMBINED FINANCIAL STATEMENT
The consolidated financial statements of Oil States International, Inc. reflect the Company's financial position, results of operations and changes in stockholders' equity for periods subsequent to February 14, 2001, the date of the Company's initial public offering and the combination of Oil States International, Inc. (Oil States), HWC Energy Services, Inc. (HWC) and PTI Group Inc. (PTI) (collectively the Controlled Group), among other things.
As more fully described below, and in footnotes that follow, the combined financial statements reflect the financial position, results of operations and changes in stockholders' equity of the predecessor entities that now comprise Oil States International, Inc. based on reorganization accounting. The pro forma financial information that follows reflect the Company's historical consolidated or combined statements of operations, depending upon the period involved, and give effect to the pro forma transactions and adjustments more fully described below.
The following tables set forth unaudited pro forma consolidated and combined financial information for Oil States giving effect to:
- the combination of Oil States, HWC and PTI as entities under the common control of SCF-III L.P. (SCF III), based upon reorganization accounting, which yields results similar to pooling of interest accounting, effective from the dates each of these entities became controlled by SCF III;
- the conversion of the common stock held by the minority interests of each entity in the Controlled Group into shares of the Company's common stock, based on the purchase method of accounting;
- the conversion of all of the outstanding common stock of Sooner Inc. (Sooner) into shares of the Company's common stock, based on the purchase method of accounting; and
- the exchange of 4,275,555 shares of common stock for $36.0 million of debt of Sooner and Oil States; and
- the Company's sale of 10,000,000 shares of common stock (the Offering) and the application of the net proceeds totaling $84.1 million. With the proceeds received in the Offering, the Company repaid $43.7 million of outstanding subordinated debt of the Controlled Group and Sooner, redeemed $21.8 million of preferred stock of Oil States, paid accrued interest on subordinated debt and accrued dividends on preferred stock aggregating $7.1 million, and repurchased common stock from non-accredited shareholders and shareholders holding pre-emptive stock purchase rights for $1.6 million. The balance of the proceeds was used to reduce amounts outstanding under bank lines of credit.
The unaudited pro forma consolidated and combined statement of operations for the years ended December 31, 2001 was prepared based upon the historical consolidated and combined financial statements of the Controlled Group, adjusted to conform accounting policies, and give effect to:
- the Company's acquisition of minority interests of the Controlled Group;
- the Company's acquisition of Sooner;
- the Company's exchange of shares of common stock for debt of Sooner and Oil States; and
- the Company's sale of shares in the Offering,
as if these transactions had occurred on January 1, 2001.
The unaudited pro forma combined financial statement does not purport to be indicative of the results that would have been obtained had the transactions described above been completed on the indicated date or that may be obtained in the future. The unaudited pro forma combined financial statement should be read in conjunction with the historical consolidated and combined financial statements and notes thereto included elsewhere in this Annual Report on Form 10-K.
OIL STATES INTERNATIONAL, INC.
PRO FORMA CONSOLIDATED AND COMBINED STATEMENT OF OPERATIONS FOR THE YEAR ENDED DECEMBER 31, 2001
OIL STATES INTERNATIONAL, INC.
NOTES TO UNAUDITED PRO FORMA CONSOLIDATED AND COMBINED FINANCIAL STATEMENT
BASIS OF PRESENTATION
The purchase method of accounting has been used to reflect the acquisition of the minority interests of each company in the Controlled Group concurrent with the closing of the Offering. The purchase price is based on the fair value of the shares owned by the minority interests, valued at the initial public offering price of $9.00 per share. Under this accounting method, the excess of the purchase price over the fair value of the assets and liabilities allocable to the minority interests acquired has been reflected as goodwill. Where book value of minority interests exceeded the purchase price, such excess reduced property, plant and equipment. For purposes of the pro forma combined financial statement, the goodwill recorded in connection with this transaction was initially being amortized over 20 years using the straight-line method based on management's evaluation of the nature and duration of customer relationships and considering competitive and technological developments in the industry. Note, however, that accounting for goodwill changed under new accounting pronouncements (See Note 3 to Consolidated and Combined Financial Statements). The unaudited pro forma statement of operations for the year ended December 31, 2001 has been adjusted for the effects of purchase accounting, as described below.
The purchase method of accounting was also used to reflect the acquisition of the outstanding common stock of Sooner concurrent with the closing of the Offering. The purchase price is based on the fair value of the shares of Sooner, valued at the initial public offering price of $9.00 per share. The excess of the purchase price over the fair value of the assets and liabilities of Sooner has been reflected as goodwill. For purposes of the pro forma combined financial statement, the goodwill recorded in connection with this transaction was initially being amortized over 15 years using the straight-line method based on management's evaluation of the nature and duration of customer relationships and considering competitive and technological developments in the industry. Note, however, that accounting for goodwill changed under new accounting pronouncements (See Note 3 to Consolidated and Combined Financial Statements). The unaudited pro forma statement of operations for the year ended December 31, 2001 includes the historical financial statements of Sooner, converted to a calendar year end and adjusted for the effects of purchase accounting, as presented below.
NOTE 1. COMBINING ADJUSTMENTS
Minority interest in (income) loss and related tax effect of the Controlled Group are presented below (in thousands):
NOTE 2. ACQUISITION OF SOONER
Certain reclassifications have been made to conform the presentation of Sooner's financial statements to the Controlled Group.
To reflect the acquisition of all outstanding common shares of Sooner in exchange for 7,597,152 shares of Oil States common stock valued at the estimated offering price per share of $9.00 (in millions):
- -----------------
(1) The purchase price for Sooner includes the estimated fair value of Sooner stock options ($1.1 million) converted into Oil States stock options.
NOTE 3. ACQUISITION OF MINORITY INTERESTS
To reflect the acquisition of the minority interests of each company in the Controlled Group in exchange for shares of Oil States common stock and elimination of the historical amounts reflected for the combined group (in millions, except share and per share information):
NOTE 4. OFFERING
(A) To adjust interest expense for debt repaid with Offering proceeds and as a result of the exchange of shares for subordinated debt.
(B) To eliminate preferred stock dividends due to the redemption of the preferred stock.
(C) To adjust income tax expense for the reduction of deferred taxes due to the formation of the combined group.
OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES
REPORT OF INDEPENDENT AUDITORS
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 as of December 31, 2003 and 2002, and the related consolidated statements of income, stockholders' equity and comprehensive income (loss), and cash flows for each of the two years in the period ended December 31, 2003 and the related consolidated and combined statements of income, stockholders' equity and comprehensive income (loss) and cash flows for the year ended December 31, 2001. 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 auditing standards generally accepted in the 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 Oil States International, Inc. and subsidiaries at December 31, 2003 and 2002, and the consolidated results of their operations and their cash flows for each of the two years in the period ended December 31, 2003 and the consolidated and combined results of their operations and their cash flows for the year ended December 31, 2001, in conformity with accounting principles generally accepted in the United States.
As discussed in Note 3 to the consolidated and combined financial statements, effective January 1, 2002, the Company adopted Statement of Financial Accounting Standards No. 142, "Goodwill and Other Intangible Assets."
ERNST & YOUNG LLP
Houston, Texas February 2, 2004
OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES
CONSOLIDATED AND COMBINED 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 AND COMBINED STATEMENTS OF STOCKHOLDERS' EQUITY AND COMPREHENSIVE INCOME (LOSS)
The accompanying notes are an integral part of these financial statements.
OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES
CONSOLIDATED AND COMBINED STATEMENTS OF CASH FLOWS
The accompanying notes are an integral part of these financial statements.
OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED AND COMBINED 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 since February 14, 2001. On February 14, 2001, the Company acquired the three companies (HWC Energy Services, Inc. -- HWC; PTI Group, Inc. -- PTI and Sooner Inc. -- Sooner) reported in the Combined financial statements presented herein. The combined financial statements include the activities of Oil States, HWC and PTI, (collectively, the Controlled Group) for the period prior to February 14, 2001, utilizing reorganization accounting. The reorganization accounting method, which yields results similar to the pooling of interests method, has been used in the preparation of the combined financial statements of the Controlled Group (entities under common control of SCF-III L.P. (SCF-III), a private equity fund that focuses on investments in the energy industry). Under this method of accounting, the historical financial statements of HWC and PTI are combined with Oil States for the period until February 14, 2001 when Oil States, HWC and PTI merged and Oil States acquired Sooner in exchange for its common stock. After February 14, 2001, the consolidated financial statements of Oil States include the results of all its subsidiaries including HWC, PTI and Sooner. The combined financial statements have been adjusted to reflect minority interests in the Controlled Group. All significant intercompany accounts and transactions between the entities have been eliminated in the accompanying consolidated and combined financial statements.
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 and Singapore.
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 natural resources and other industries primarily in Canada 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 and Ohio, HWC operates, through its subsidiary Capstar Drilling, L.P., 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.
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. INITIAL PUBLIC OFFERING, MERGER TRANSACTIONS AND REFINANCING
On February 9, 2001, the Company's common stock began trading on the New York Stock Exchange under the symbol "OIS" pursuant to completion of its initial public offering (the Offering). On February 14, 2001, the Company closed the business combination and the Offering thereby acquiring the minority interests in PTI and HWC and 100% of the Sooner operations. The Company recorded additional goodwill of $61.9 million as a result of the acquisition of these minority interests.
Concurrently with the Offering, the Company acquired Sooner for $69.5 million. The Company exchanged 7,597,152 shares of its common stock for all the outstanding common shares of Sooner. The Company accounted for the acquisition using the purchase method of accounting and recorded approximately $40 million in goodwill.
Concurrently with the closing of the Offering, the Company issued 4,275,555 shares of common stock to SCF-III and SCF-IV L.P. (SCF-IV) in exchange for approximately $36.0 million of indebtedness of Oil States and Sooner which was held by SCF-III and SCF-IV (the SCF Exchange).
With the proceeds received in the Offering, the Company repaid $43.7 million of outstanding subordinated debt of the Controlled Group and Sooner, redeemed $21.8 million of preferred stock of Oil States, paid accrued interest on subordinated debt and accrued dividends on preferred stock aggregating $7.1 million, and repurchased common stock from non-accredited shareholders and shareholders holding pre-emptive stock purchase rights for $1.6 million. The balance of the proceeds was used to reduce amounts outstanding under bank lines of credit.
3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
CASH AND CASH EQUIVALENTS
The Company considers all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents.
FAIR VALUE OF FINANCIAL INSTRUMENTS
The Company's financial instruments consist of cash and cash equivalents, investments, receivables, 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, and spare parts for manufactured equipment. Inventories include raw materials, labor, and manufacturing overhead. The cost of tubular goods inventories is determined using the first-in, first-out (FIFO) method and the cost for the remaining 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. Prior to 2002, goodwill was amortized on a straight-line basis over a period of 15 to 40 years based on management's evaluation of the nature and duration of customer relationships and considering competitive and technological developments in the industry. Goodwill is stated net of accumulated amortization of $18.0 million and $17.4 million at December 31, 2003 and 2002, respectively. The amount of accumulated amortization of goodwill increased in 2003 compared to 2002 because of changes in foreign currency exchange rates. In 2001, the Financial Accounting Standards Board issued a new standard that affected goodwill amortization (See "Recent Accounting Pronouncements" below).
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.
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. At December 31, 2003 and 2002, the financial instruments employed to manage foreign exchange risk consisted of forward exchange contracts with notional amounts of $5 million at each year-end. 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 not been material to the results of operations of the Company.
REVENUE AND COST RECOGNITION
Revenue from the sale of products, not accounted for utilizing the percentage of completion method, is recognized upon shipment to the customer or when all significant risks of ownership have passed to the customer. For significant fabrication 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 fabrication contracts. Provisions for estimated losses on uncompleted contracts are made in the period in which such losses are determined. In rental equipment and 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 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 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
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.
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 (loss) per share (EPS) amounts have been computed based on the average number of common shares outstanding, including 340,971 and 824,546 shares of common stock as of December 31, 2003 and 2002, 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 and the effect of convertible preferred stock
in periods when such preferred shares were outstanding. All shares awarded under the Company's Equity Participation Plan are included in the Company's fully diluted shares.
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. However, 100,000 shares of restricted stock awarded under the Equity Participation Plan in February 2001 are considered to be compensatory in nature. Accordingly, the Company recognized $0.3 million of non-cash general and administrative expenses for that award in each of the three years ended December 31, 2003. An additional $0.1 million was recognized in 2003 for a stock option performance award. 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 14.
GUARANTEES
The Company adopted FASB Interpretation No. 45 (FIN 45), "Guarantor's Accounting and Disclosure Requirements for Guarantees, including Indirect Indebtedness of Other," 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. The warranty provision is based on historical experience by product, configuration and geographic region.
Changes in the warranty reserves were as follows (in thousands):
As noted above, certain of our products are sold with a 12 to 18 month warranty. Accordingly, current warranty provisions are related to the current year's sales, and warranty consumption is associated with current and prior year's net sales.
During the ordinary course of business, the Company also provides standby letters of credit or other guarantee instruments to certain parties as required for certain transactions initiated by either the Company or its subsidiaries. As of December 31, 2003, the maximum potential amount of future payments that the Company could be required to make under these guarantee agreements was approximately $10.3 million. The Company has not recorded any liability in connection with these guarantee arrangements beyond that required to appropriately account for the underlying transaction being guaranteed. The Company does not believe, based on historical experience and information currently available, that it is probable that any amounts will be required to be paid under these guarantee arrangements.
RECLASSIFICATIONS
Certain amounts in prior years' financial statements have been reclassified to conform with the current year presentation.
USE OF ESTIMATES
The preparation of consolidated financial statements in conformity with accounting principles generally accepted in the United States requires the use of estimates and assumptions by management in determining the reported amounts of assets and liabilities and disclosures of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Examples of a few such estimates include the costs associated with the disposal of discontinued operations, including potential future adjustments as a result of contractual agreements, revenue and income recognized on the percentage-of-completion method, the valuation allowance recorded on net deferred tax assets and warranty and bad debt reserves. Actual results could differ from those estimates.
4. DETAILS OF SELECTED BALANCE SHEET ACCOUNTS
Additional information regarding selected balance sheet accounts at December 31, 2003 and 2002, is presented below (in thousands):
5. RECENT ACCOUNTING PRONOUNCEMENTS
Effective January 1, 2002, the Company adopted SFAS No. 142, "Goodwill and Other Intangible Assets" (SFAS No. 142). In connection with the adoption of SFAS No. 142, the Company ceased amortizing goodwill. Under SFAS No. 142, goodwill is no longer amortized but is tested for impairment using a fair value approach, at the "reporting unit" level. A reporting unit is the operating segment, or a business one level below that operating segment (the "component" level) if discrete financial information is prepared and regularly reviewed by management at the component level. We recognize an impairment charge for any amount by which the carrying amount of a reporting unit's goodwill exceeds its 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 goodwill or other intangibles impairment was required based on the evaluations performed.
Changes in the carrying amount of goodwill for the year ended December 31, 2002 and 2003, are as follows (in thousands):
The following table presents what reported income available to common stockholders and net income per share would have been in all periods presented exclusive of amortization expense recognized in those periods related to goodwill (in thousands, except per share amounts):
The following table presents the total amount assigned and the total amount amortized for major intangible asset classes as of December 31, 2003 and 2002 (in thousands):
The weighted average remaining amortization period for all intangible assets is 4.4 years and 5.8 years as of December 31, 2003 and 2002, respectively. Total amortization expense is expected to be $1.6 million, $1.4 million and $1.3 million in 2004, 2005 and 2006, respectively.
In April 2002, the Financial Accounting Standards Board issued SFAS No. 145 which, among other things, rescinded SFAS No. 4, "Reporting Gains and Losses from Extinguishment of Debt". The Company adopted this statement in 2003, and, in conjunction with executing a new 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. We reclassified $0.8 million of losses incurred in 2001 on debt restructuring, formerly classified as an extraordinary loss, to interest expense.
The Company has adopted the disclosure requirements of SFAS No. 148, "Accounting for Stock Based Compensation -- Transition and Disclosure," issued in December 2002, effective with its December 31, 2002 consolidated and combined financial statements and related footnotes.
In January 2003, the Financial Accounting Standards Board (FASB) issued FASB Interpretation No. 46 (FIN 46), "Consolidation of Variable Interest Entities, an interpretation of ARB No. 51." FIN 46 provides guidance on: 1) the identification of entities for which control is achieved through means other than through voting rights, known as "variable interest entities" (VIEs); and 2) which business enterprise is the primary beneficiary and when it should consolidate a VIE. This new requirement for consolidation applies to entities: 1) where the equity investors (if any) do not have a controlling financial interest; or 2) whose equity investment at risk is insufficient to finance that entity's activities without receiving additional subordinated financial support from other parties. In addition, FIN 46 requires that both the primary beneficiary and all other enterprises with a significant variable interest in a VIE make additional disclosures. FIN 46 is effective for all new VIEs created or acquired after January 31, 2003. For VIEs created or acquired prior to February 1, 2003, the provisions of FIN 46 must be applied for the first interim or annual period ending after December 15, 2003. Certain disclosures are effective immediately. Implementation of FIN 46 did not affect the Company.
6. LONG-TERM DEBT
As of December 31, 2003 and 2002, long-term debt consisted of the following (in thousands):
Scheduled maturities of combined long-term debt as of December 31, 2003, are as follows (in thousands):
The Company's capital leases consist primarily of plant facilities and equipment. Capitalized lease assets value and related accumulated depreciation totaled $4.3 million and $1.5 million at December 31, 2003, respectively. Capitalized lease assets value and related accumulated depreciation totaled $4.2 million and $1.1 million at December 31, 2002, respectively.
CURRENT DEBT INSTRUMENTS
On October 30, 2003, the Company replaced its existing credit facility with a $225.0 million senior secured revolving credit facility with a group of banks. Up to $45.0 million of the credit facility is available in the form of loans denominated in Canadian dollars and may be made to the Company's principal Canadian operating subsidiaries. The Company has an option to increase the maximum borrowings under the new facility to $250 million prior to its maturity. The facility matures on October 30, 2007, unless extended for up to one additional year period with the consent of the lenders. 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 1.5% to 2.5%; 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 from 0.5% to 1.5%, 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 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, 2003, we had $128.7 million outstanding under this facility and an additional $10.3 million of outstanding letters of credit leaving $86.0 million available to be drawn under the facility. The Company's weighted average interest rate on the Company's outstanding borrowings under this facility at December 31, 2003 was 3.6%.
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 February 28, 2003, the Company renewed its overdraft credit facility providing for borrowings totaling (pound)5.0 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, 2003.
7. POSTRETIREMENT HEALTHCARE AND OTHER INSURANCE BENEFITS
The Company provides healthcare and other insurance benefits for approximately 360 eligible retired employees and dependent spouses. This plan is no longer available to current employees. The healthcare plans are contributory and contain other cost-sharing features such as deductibles, lifetime maximums, and co-payment requirements.
The healthcare plans are not funded, and the Company's policy is to pay these benefits as they are incurred.
In 2003, the Company terminated Medicare Part B benefits and offered a buy-out to plan participants, which resulted in a total reduction of $3.3 million in the accumulated benefit obligation and a gain of $1.4 million. The gain was credited to expense during the second and third quarters of 2003.
The 2003 net periodic benefit cost and the accumulated benefit obligation was determined under an actuarial assumption using a healthcare cost trend rate of 9.0% for medical and 12.0% for prescription drugs, gradually declining to approximately 5% in the year 2009 and thereafter over the projected payout period of the benefits. The accumulated benefit obligations were determined using an assumed discount rate of 6.00% and 6.75% at December 31, 2003 and 2002, respectively. Under the plan's provisions, the Company's prescription costs are capped at annual benefit limits.
A one percentage-point increase or decrease in the assumed healthcare cost trend rates would be immaterial to the accumulated postretirement benefit obligation and net periodic benefit cost at December 31, 2003.
In January 2004, Financial Staff Position No. FAS 106-1 was issued which addresses the accounting and disclosure requirements related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the "Act") which was enacted on December 8, 2003. The Act introduced both a Medicare prescription drug benefit and a federal subsidy to sponsors of retiree health-care plans that provide a benefit at least "actuarially equivalent" to the Medicare benefit. The effects of the Act are not reflected in the measurement of our accumulated postretirement benefit obligation or net periodic benefit cost as the Company has elected to defer recognizing the effects of the Act until authoritative guidance on the accounting for the federal subsidy is issued, or until certain other events occur that would require remeasurement of the plan's benefit obligation. The Company does not believe the Act will have a material impact on the measurement of our accumulated postretirement benefit obligation or net periodic benefit cost; however, when the authoritative guidance is issued, it could require us to change previously reported information.
8. RETIREMENT PLANS
Prior to January 2002, the Company sponsored a number of defined contribution plans. Effective in January 2002, the Company merged its domestic defined contribution plans into a single plan sponsored by the Company. Participation in these plans is available to substantially all employees.
The Company recognized expense of $2.9 million, $2.5 million and $1.7 million related to its various defined contribution plans during the years ended December 31, 2003, 2002 and 2001, respectively.
9. PREFERRED STOCK
Cash dividends paid on preferred stock in 2001 related to preferred stock that was either repaid in cash or converted to common stock in connection with the Offering completed in February 2001 (See Note 2).
10. INCOME TAXES
Consolidated pre-tax income for the years ended December 31, 2003, 2002 and 2001 consisted of the following (in thousands):
The components of the income tax provision (benefit) for the years ended December 31, 2003, 2002 and 2001 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, 2003, 2002 and 2001 (in thousands):
The significant items giving rise to the deferred tax assets and liabilities as of December 31, 2003 and 2002 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, 2003 is as follows (in thousands):
For US federal income tax purposes, the Company has net operating loss carryforwards of approximately $63.2 million for regular income taxes that will expire in the years 2008 through 2020. The Company's net operating loss carryforwards are subject to limitations under Section 382 of the Internal Revenue Code of 1986, as amended. Based on these limitations, the years the carryforwards expire, and the uncertainty in achieving levels of taxable income required for their utilization, the Company has provided a valuation allowance on a portion of these carryforwards. The Company has federal alternative minimum tax net operating loss carryforwards of $44.5 million, which will expire in the years 2010 through 2020.
The Company has $2.9 million of net operating loss carryforwards associated with its Canadian subsidiary's Chilean operations as of December 31, 2003. These losses may be carried forward indefinitely; however, such losses may only be used to offset future Chilean taxable income. Accordingly, the Company has provided a full valuation allowance against the associated deferred tax asset.
Appropriate US 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 $98.7 million at December 31, 2003. Upon distribution of these earnings in the form of dividends or otherwise, the Company may be subject to US income taxes 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.
At December 31, 2003, the Company had a valuation allowance of $12.0 million, which reflects a $7.6 million decrease from the amount at December 31, 2002. The reduction in the valuation allowance is being made because management believes, based on the weight of available evidence, that it is more likely than not that this additional portion of the Company's net operating losses will be utilized prior to the expiration of its carryforward period.
During the year ended December 31, 2003, the Company recognized a tax benefit triggered by employee exercises of stock options totaling $1.6 million. Such benefit was credited to additional paid-in capital.
11. SUPPLEMENTAL CASH FLOW INFORMATION
Cash paid during the years ended December 31, 2003, 2002 and 2001 for interest and income taxes was as follows (in thousands):
Components of cash used for acquisitions as reflected in the consolidated statements of cash flows for the years ended December 31, 2003, 2002 and 2001 are summarized as follows (in thousands):
In connection with acquisitions made in 2002, the Company had non-cash transactions consisting of the issuance of $2.0 million of notes payable and the assumption of capital leases totaling $3.3 million.
12. COMMITMENTS AND CONTINGENCIES
The Company leases a portion of its equipment, office space, computer equipment, automobiles and trucks under leases which expire at various dates.
Minimum future operating lease obligations in effect at December 31, 2003, are as follows (in thousands):
Rental expense under operating leases was $4.9 million, $4.3 million and $3.9 million for the years ended December 31, 2003, 2002 and 2001, respectively.
As of December 31, 2003, the Company had entered into forward purchase option contracts through February 25, 2004 with a bank totaling $5.0 million for the purchase of foreign currency as a hedge to expected future billings. The contract purchase rate was favorable to the December 31, 2003 currency exchange rate by almost 15%. We have incurred no material gains or losses from foreign currency hedging activities.
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 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.
13. RELATED-PARTY TRANSACTIONS
The Company incurred legal fees totaling $240,000 in 2001 for services rendered by a law firm in connection with a possible acquisition of a company. A member of the Company's Board of Directors is a partner with that law firm. No transaction resulted from the acquisition effort.
The company currently rents land and buildings from a former officer of a subsidiary of the Company and pays a monthly rent of $5,556. Such officer was the previous owner of a business acquired by Oil States.
14. 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 5,700,000 shares of common stock under the 2001 Equity Participation Plan, as amended and restated, (the Stock Option 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. All option grants made from February 2001 to December 2003 have been priced at the closing price on the day of grant, vest 25% per year and have a ten-year life. Because the exercise price of options granted under the Stock Option Plan have been equal to or greater than the market price of the Company's stock on the date of grant, no compensation expense related to this plan has been recorded. Had compensation expense for its Stock Option Plan been determined consistent with SFAS No. 123 utilizing the fair value method, the Company's net income and earnings per share at December 31, 2003, 2002 and 2001, would have been as follows (in thousands, except per share amounts):
The following table summarizes stock option activity for each of the years ended December 31, 2001, 2002 and 2003:
The following table summarizes information for stock options outstanding at December 31, 2003:
At December 31, 2003, 2,014,044 options were available for future grant under the Stock Option Plan.
The weighted average fair values of options granted during 2003, 2002, and 2001 were $4.55, $5.31, and $5.48 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 2003, 2002, and 2001, respectively: risk-free interest rates of 3.0%, 5.2%, and 5.0%, no expected dividend yield, expected lives of 5.5, 10.0, and 8.3 years, and an expected volatility of 37%, 45% and 45%.
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 participant's account. 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, 2003, the balance of the assets in the Trust totaled $2.4 million, including 33,423 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 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, 2003 was $2.0 million and is classified as "Other noncurrent assets" in the consolidated balance sheet. Amounts payable to the plan participants at December 31, 2003, including the market value of the shares of the Company's common stock that are reflected as treasury stock, was $2.5 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 and combined 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 and combined 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 $0.1 million in both 2003 and 2002.
15. 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, 2003, 2002 and 2001, 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.
Financial information by geographic segment for each of the three years ended December 31, 2003, 2002 and 2001, 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.
One customer accounted for between 5% and 7% of the Company's revenues in each of the years ended December 31, 2003, 2002 and 2001. No other customer accounted for more than 5% of the Company's revenues in the periods presented.
16. QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
The following table summarizes quarterly financial information for 2003, 2002 and 2001 (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.
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* Represents "revenues" less "product costs" and "service and other costs" included in the Company's consolidated and combined statements of operations.
(1) The Company's business in the well site services segment, particularly in Canada, is seasonal with the highest activity occurring in the winter months.
(2) Effective February 14, 2001, the Company acquired Sooner and results of Sooner are included from acquisition date.
17. VALUATION ALLOWANCES
Activity in the valuation accounts was as follows (in thousands):
18. SUBSEQUENT EVENT (UNAUDITED)
In January 2004, the Company completed the acquisition of several related rental tool companies. 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 will report through the Well Site Services segment. The Company paid a total of $34.7 million in cash for the stock of the companies which was funded by the Company's credit facility. Combined revenues for the acquired companies for the year ended December 31, 2003 were approximately $15.4 million.
EXHIBIT INDEX
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** Management contracts or compensatory plans or arrangements
*** Furnished herewith