ITEM 1. BUSINESS
General
National Oilwell Varco, Inc. (“NOV” or the “Company”), a Delaware corporation incorporated in 1995, is a leading worldwide provider of equipment and components used in oil and gas drilling and production operations, oilfield services, and supply chain integration services to the upstream oil and gas industry. The Company conducts operations in approximately 700 locations across six continents.
On March 11, 2005, we acquired all of the outstanding shares of Varco International, Inc. (“Varco”) with the issuance of 0.8363 shares of National-Oilwell, Inc. common stock for each Varco common share (the “Merger”). The Company then changed its name from National-Oilwell, Inc. to National Oilwell Varco, Inc. We have included the financial results of Varco in our consolidated financial statements beginning March 11, 2005, the date Varco common shares were exchanged for NOV common shares. We believe that the Merger has better positioned us to compete more effectively in the global marketplace and provide greater scale to increase service to our customers, increase our investment in research and development to accelerate innovation, and increase shareholder value. The fiscal year ending December 31, 2006 represented the first full year of operations of the combined entities.
On December 16, 2007, we agreed to acquire 100% of the outstanding shares of Grant Prideco, Inc. for a combination of $23.20 cash per share and 0.4498 shares of National Oilwell Varco, Inc. common stock. Consummation of the merger requires approval by the stockholders of Grant Prideco and also approval from various regulatory agencies. We anticipate completion of the merger during the second quarter of 2008.
The Company’s principal executive offices are located at 7909 Parkwood Circle Drive, Houston, Texas 77036, its telephone number is (713) 346-7500, and its Internet website address is http://www.nov.com. The Company’s annual reports on Form 10-K, quarterly reports on Form 10-Q and current reports on Form 8-K, and all amendments thereto, are available free of charge on its Internet website. These reports are posted on its website as soon as reasonably practicable after such reports are electronically filed with the Securities and Exchange Commission (“SEC”). The Company’s Code of Ethics is also posted on our website.
The Company has a long tradition of pioneering innovations which improve the cost-effectiveness, efficiency, safety and environmental impact of oil and gas operations. The Company’s common stock is traded on the New York Stock Exchange under the symbol “NOV.” The Company operates through three business segments: Rig Technology, Petroleum Services & Supplies, and Distribution Services.
Rig Technology
Our Rig Technology segment designs, manufactures, sells and services complete systems for the drilling, completion, and servicing of oil and gas wells. The segment offers a comprehensive line of highly-engineered equipment that automates complex well construction and management operations, such as offshore and onshore drilling rigs; derricks; pipe lifting, racking, rotating and assembly systems; coiled tubing equipment and pressure pumping units; well workover rigs; wireline winches; and cranes. Demand for Rig Technology products is primarily dependent on capital spending plans by drilling contractors, oilfield service companies, and oil and gas companies, and secondarily on the overall level of oilfield drilling activity, which drives demand for spare parts for the segment’s large installed base of equipment. We have made strategic acquisitions and other investments during the past several years in an effort to expand our product offering and our global manufacturing capabilities, including adding additional operations in the United States, Canada, Norway, the United Kingdom, China, Belarus, and India.
Petroleum Services & Supplies
Our Petroleum Services & Supplies segment provides a variety of consumable goods and services used to drill, complete, remediate and workover oil and gas wells and service pipelines, flowlines and other oilfield tubular goods. The segment manufactures, rents and sells a variety of products and equipment used to perform drilling operations, including transfer pumps, solids control systems, drilling motors and other downhole tools, rig instrumentation systems, and mud pump consumables. Demand for these services and supplies is determined principally by the level of oilfield drilling and workover activity by drilling contractors, major and independent oil and gas companies, and national oil companies. Oilfield tubular services include the provision of inspection and internal coating services and equipment for drill pipe, linepipe, tubing, casing and pipelines; and the design, manufacture and sale of coiled tubing pipe and advanced composite pipe for application in highly corrosive environments. The segment sells its tubular goods and services to oil and gas companies; drilling contractors; pipe distributors, processors and manufacturers; and pipeline operators. This segment has benefited from several strategic acquisitions and other investments completed during the past few years, including adding additional operations in the United States, Canada, the United Kingdom, China, Kazakhstan, Mexico, Russia, Argentina, India, Bolivia, the Netherlands, Singapore, Malaysia, Vietnam, and the United Arab Emirates.
Distribution Services
Our Distribution Services segment provides maintenance, repair and operating supplies (“MRO”) and spare parts to drill site and production locations worldwide. In addition to its comprehensive network of field locations supporting land drilling operations throughout North America, the segment supports major offshore drilling contractors through locations in Mexico, the Middle East, Europe, Southeast Asia and South America. Distribution Services employs advanced information technologies to provide complete procurement, inventory management and logistics services to its customers around the globe. Demand for the segment’s services are determined primarily by the level of drilling, servicing, and oil and gas production activities.
The following table sets forth the contribution to the Company’s total revenues of its three operating segments for December 31, 2007, 2006 and 2005 (in millions):
See Note 15 to our Consolidated Financial Statements included in this Annual Report on Form 10-K for financial information by segment and a geographical breakout of revenues and long-lived assets.
The Company has included a glossary of oilfield terms at the end of Item 1 of this Annual Report.
Influence of Oil and Gas Activity Levels on the Company’s Business
The oil and gas industry in which the Company participates has historically experienced significant volatility. Demand for the Company’s services and products depends primarily upon the general level of activity in the oil and gas industry worldwide, including the number of drilling rigs in operation, the number of oil and gas wells being drilled, the depth and drilling conditions of these wells, the volume of production, the number of well completions and the level of well remediation activity. Oil and gas activity is in turn heavily influenced by, among other factors, oil and gas prices worldwide. High levels of drilling and well-remediation activity generally spur demand for the Company’s products and services used to drill and remediate oil and gas wells. Additionally, high levels of oil and gas activity increase cash flows available for drilling contractors, oilfield service companies, and manufacturers of oil country tubular goods to invest in capital equipment that the Company sells.
Beginning in early 2004, increasing oil and gas prices led to steadily rising levels of drilling activity throughout the world. Concerns about the long-term availability of oil and gas supply also began to build. Consequently, the worldwide rig count increased 15% in 2005, 11% in 2006, and 2% in 2007. As a result of higher cash flows realized by many drilling contractors and other oilfield service companies, as well as the long-term concerns about supply-demand imbalance and the need to replace aging equipment, market conditions for capital equipment purchases have improved significantly since 2005 and 2006, resulting in higher backlogs for the Company at the end of 2007 compared to the end of 2005 and 2006. Backlog for the Company was at approximately $9.0 billion at December 31, 2007 compared to approximately $6.0 billion and $2.3 billion for December 31, 2006 and 2005, respectively.
In 2007, most of the Company’s Rig Technology revenue resulted from major capital expenditures of drilling contractors, well servicing companies, and oil companies on rig construction and refurbishment, and well servicing equipment. These capital expenditures are influenced by the amount of cash flow that contractors and service companies generate from drilling, completion, and remediation activity; as well as by the availability of financing, the outlook for future drilling and well servicing activity, and other factors. Generally the Company believes the demand for capital equipment lags increases in the level of drilling activity. The remainder of the Rig Technology segment’s revenue in 2007 was related to the sale of spare parts and consumables, the provision of equipment-repair services, and the rental of equipment, which the Company believes are generally determined directly by the level of drilling and well servicing activity.
The majority of the Company’s Petroleum Services & Supplies revenue is closely tied to drilling activity, although a portion is related to the sale of capital equipment to drilling contractors, which may somewhat lag the level of drilling activity. Portions of the segment’s revenue that are not tied to drilling activity include (i) the sale of progressive cavity pumps and solids control
equipment for use in industrial applications; (ii) the performance of in-service pipeline inspections; (iii) the sale of fiberglass and composite tubing to industrial customers, which is generally unrelated to drilling or well remediation activity but may be tied somewhat to oil and gas prices; and (iv) the sale of pipe inspection equipment to the manufacturers of oil country tubular goods, which is indirectly related to drilling activity.
The Company’s revenue from Distribution Services is almost entirely driven by drilling activity and oil and gas production activities.
Drilling and well servicing activity can fluctuate significantly in a short period of time. The willingness of oil and gas operators to make capital investments to explore for and produce oil and natural gas will continue to be influenced by numerous factors over which the Company has no control, including: the ability of the members of the Organization of Petroleum Exporting Countries (“OPEC”) to maintain oil price stability through voluntary production limits of oil; the level of oil production by non-OPEC countries; supply and demand for oil and natural gas; general economic and political conditions; costs of exploration and production; the availability of new leases and concessions; and governmental regulations regarding, among other things, environmental protection, taxation, price controls and product allocations. The willingness of drilling contractors and well servicing companies to make capital expenditures for the type of specialized equipment the Company provides is also influenced by numerous factors over which the Company has no control, including: the general level of oil and gas well drilling and servicing; rig dayrates; access to external financing; outlook for future increases in well drilling and well remediation activity; steel prices and fabrication costs; and government regulations regarding, among other things, environmental protection, taxation, and price controls.
Overview of Oil and Gas Well Drilling and Servicing Processes
Oil and gas wells are usually drilled by drilling contractors using a drilling rig. A bit is attached to the end of a drill stem, which is assembled by the drilling rig and its crew from 30-foot joints of drill pipe and specialized drilling components known as downhole tools. Using the conventional rotary drilling method, the drill stem is turned from the rotary table of the drilling rig by torque applied to the kelly, which is screwed into the top of the drill stem. Increasingly, drilling is performed using a drilling motor, which is attached to the bottom of the drill stem and provides rotational force directly to the bit, rather than such force being supplied by the rotary table. The use of a drilling motor permits the drilling contractor to drill directionally, including horizontally. The Company sells and rents drilling motors and downhole tools through its Petroleum Services & Supplies segment.
During drilling, heavy drilling fluids or “drilling muds” are pumped down the drill stem and forced out through jets in the bit. The drilling mud returns to the surface through the space between the borehole wall and the drill stem, carrying with it the drill cuttings drilled out by the bit. The drill cuttings are removed from the mud by a solids control system (which can include shakers, centrifuges and other specialized equipment) and disposed of in an environmentally sound manner. The solids control system permits the mud, which is often comprised of expensive chemicals, to be continuously reused and recirculated back into the hole.
Through its Rig Technology segment, the Company sells the large “mud pumps” that are used to pump drilling mud through the drill stem. Through its Petroleum Services & Supplies business, the Company sells transfer pumps and mud pump consumables; sells and rents solids control equipment; and provides solids control and waste management services. Many operators internally coat the drill stem to improve its hydraulic efficiency and protect it from corrosive fluids sometimes encountered during drilling, and inspect and assess the integrity of the drill pipe from time to time. The Company provides drill pipe inspection and coating services, and applies “hardbanding” material to drill pipe to improve its wear characteristics. These services are provided through the Company’s Petroleum Services & Supplies segment.
As the hole depth increases, the kelly must be removed frequently so that additional 30-foot joints of drill pipe can be added to the drill stem. When the bit becomes dull or the equipment at the bottom of the drill stem - including the drilling motors - otherwise requires servicing, the entire drill stem is pulled out of the hole and disassembled by disconnecting the joints of drill pipe. These are set aside or “racked,” the old bit is replaced or service is performed, and the drill stem is reassembled and lowered back into the hole (a process called “tripping”). During drilling and tripping operations, joints of drill pipe must be screwed together and tightened (“made up”), and loosened and unscrewed (“spun out”). The Company’s Rig Technology business provides drilling equipment to manipulate and maneuver the drill pipe in this manner. When the hole has reached certain depths, all of the drill pipe is pulled out of the hole and larger diameter pipe known as casing is lowered into the hole and permanently cemented in place in order to protect against collapse and contamination of the hole. The casing is typically inspected before it is lowered into the hole, a service the Company’s Petroleum Services & Supplies business provides. The Company’s Rig Technology segment manufactures pressure pumping equipment that is used to cement the casing in place.
The raising and lowering of the drill stem while drilling or tripping, and the lowering of casing into the wellbore, are accomplished with the rig’s hoisting system. A conventional hoisting system is a block and tackle mechanism that works within the drilling rig’s derrick. The lifting of this mechanism is performed via a series of pulleys that are attached to the drawworks at the base of the derrick. The Company’s Rig Technology segment sells and installs drawworks and pipe hoisting systems.
During the course of normal drilling operations, the drill stem passes through different geological formations, which exhibit varying pressure characteristics. If this pressure is not contained, oil, gas and/or water would flow out of these formations to the surface. The two means of containing these pressures are (i) primarily the circulation of drilling muds while drilling and (ii) secondarily the use of blowout preventers should the mud prove inadequate and in an emergency situation. The Company’s Rig Technology group sells and services blowout preventers.
Drilling muds are carefully designed to exhibit certain qualities that optimize the drilling process. In addition to containing formation pressure, they must (i) provide power to the drilling motor, (ii) carry drilled solids to the surface, (iii) protect the drilled formations from being damaged, and (iv) cool the drill bit. Achieving these objectives often requires a formulation specific to a given well and can involve the use of expensive chemicals as well as natural materials such as certain types of clay. The fluid itself is often oil or more-expensive synthetic mud. Given this expense, it is highly desirable to reuse as much of the drilling mud as possible. Solids control equipment such as shale shakers, centrifuges, cuttings dryers, and mud cleaners help accomplish this objective. The Company’s Petroleum Services & Supplies group rents, sells, operates and services this equipment. Drilling muds are formulated based on expected drilling conditions. However, as the hole is drilled, the drill stem may encounter a high pressure zone where the mud density is inadequate to maintain sufficient pressure. Should efforts to “weight up” the mud in order to contain such a pressure kick fail, a blowout could result, whereby reservoir fluids would flow uncontrolled into the well. To prevent blowouts to the surface of the well, a series of high-pressure valves known as blowout preventers (“BOPs”) are positioned at the top of the well and, when activated, form tight seals that prevent the escape of fluids. When closed, conventional BOPs prevent normal rig operations. Therefore, the BOPs are activated only if drilling mud and normal well control procedures cannot safely contain the pressure. BOPs have been designed to contain pressures of up to 20,000 psi.
The operations of the rig and the condition of the drilling mud are closely monitored by various sensors, which measure operating parameters such as the weight on the rig’s hook, the incidence of pressure kicks, the operation of the drilling mud pumps, etc. Through its Petroleum Services & Supplies business, the Company sells and rents drilling rig instrumentation packages that perform these monitoring functions.
During the drilling and completion of a well, there exists an ongoing need for various consumables and spare parts. While most of these items are small, in the aggregate they represent an important element of the process. Since it is impractical for each drilling location to have a full supply of these items, drilling contractors and well service companies tend to rely on third parties to stock and deliver these items. The Company provides this capability through its Distribution Services segment, which stocks and sells spares and consumables made by third parties, as well as spares and consumables made by the Company.
After the well has reached its total depth and the final section of casing has been set, the drilling rig is moved off of the well and the well is prepared to begin producing oil or gas in a process known as “well completion.” Well completion usually involves installing production tubing concentrically in the casing. Due to the corrosive nature of many produced fluids, production tubing is often inspected and coated, services offered by the Company’s Petroleum Services & Supplies business. Sometimes operators choose to use corrosion resistant composite materials (which the Company offers through its Petroleum Services & Supplies business), or corrosion-resistant alloys, or operators sometimes pump fluids into wells to inhibit corrosion.
From time to time, a producing well may undergo workover procedures to extend its life and increase its production rate. Workover rigs are used to disassemble the wellhead, tubing and other completion components of an existing well in order to stimulate or remediate the well. Workover rigs are similar to drilling rigs in their capabilities to handle tubing, but are usually smaller and somewhat less sophisticated. The Company offers a comprehensive range of workover rigs through its Rig Technology segment. Tubing and sucker rods removed from a well during a well remediation operation are often inspected to determine their suitability to be reused in the well, which is a service the Company’s Petroleum Services & Supplies business provides.
Frequently coiled tubing units or wireline units are used to accomplish certain well remediation operations or well completions. Coiled tubing is a recent advancement in petroleum technology consisting of a continuous length of reeled steel tubing which can be injected concentrically into the production tubing all the way to the bottom of most wells. It permits many operations to be performed without disassembling the production tubing, and without curtailing the production of the well. Wireline winch units are devices that utilize single-strand or multistrand wires to perform well-remediation operations, such as lowering tools and transmitting data to the surface. Through the Rig Technology group, the Company sells and rents various types of coiled tubing equipment, and wireline equipment and tools. The Company also manufactures and sells coiled tubing pipe through its Petroleum Services & Supplies segment.
Rig Technology
The Company has a long tradition of pioneering innovations in drilling and well servicing equipment which improve the efficiency, safety, and cost of drilling and well servicing operations. The Rig Technology group designs, manufactures and sells a wide variety of top drives, automated pipe handling systems, motion compensation systems, rig controls, BOPs, handling tools, drawworks, risers, rotary tables, mud pumps, cranes, drilling motors and other drilling equipment for both the onshore and offshore markets. The Rig Technology group also manufactures entire rig packages, both drilling and workover, in addition to well servicing equipment such as coiled tubing units, pressure pumping equipment, and wireline winches.
The Rig Technology group sells directly to drilling contractors, shipyards and other rig fabricators, well servicing companies, national oil companies, major and independent oil and gas companies, supply stores, and pipe-running service providers. Demand for its products, several of which are described below, is strongly dependent upon capital spending plans by oil and gas companies and drilling contractors, and the level of oil and gas well drilling activity.
Land Rig Packages. NOV designs, manufactures, assembles, upgrades, and supplies equipment sets to a variety of land drilling rigs, including those specifically designed to operate in harsh environments such as the Arctic Circle and the desert. Our key land rig product names include the Ideal Rig™ and Rapid Rig®. NOV’s recent rig packages are designed to be safer and fast moving, to utilize AC technology, and to reduce manpower required to operate a rig.
Top Drives. The Top Drive Drilling System (“TDS”), originally introduced by NOV in 1982, significantly alters the traditional drilling process. The TDS rotates the drill stem from its top, rather than by the rotary table, with a large electric motor affixed to rails installed in the derrick that traverses the length of the derrick to the rig floor. Therefore, the TDS eliminates the use of the conventional rotary table for drilling. Components of the TDS also are used to connect additional joints of drill pipe to the drill stem during drilling operations, enabling drilling with three joints of drill pipe compared to traditionally drilling with one joint of drill pipe. Additionally, the TDS facilitates horizontal and extended reach drilling.
Drilling Motors. NOV has helped lead the application of AC motor technology in the oilfield industry. We are now transitioning from buying motors from third parties to building them in our own facilities and further developing motor technology, including the introduction of permanent magnet motor technology to the industry. These permanent magnet motors are being used in top drives, cranes, mud pumps, winches, and drawworks.
Rotary Equipment. The alternative to using a TDS to rotate the drill stem is to use a rotary table, which rotates the pipe at the floor of the rig. The Rig Technology group produces rotary tables as well as kelly bushings and master bushings for most sizes of kellys and makes of rotary tables. In 1998, NOV introduced the Rotary Support Table for use on rigs with a TDS. The Rotary Support Table is used in concert with the TDS to completely eliminate the need for the larger conventional rotary table.
Pipe Handling Systems. Pipe racking systems are used to handle drill pipe, casing and tubing on a drilling rig. Vertical pipe racking systems move drill pipe and casing between the well and a storage (“racking”) area on the rig floor. Horizontal racking systems are used to handle tubulars while stored horizontally (for example, on the pipe deck of an offshore rig) and transport tubulars up to the rig floor and into a vertical position for use in the drilling process.
Vertical pipe racking systems are used predominantly on offshore rigs and are found on almost all floating rigs. Mechanical vertical pipe racking systems greatly reduce the manual effort involved in pipe handling. Pipe racking systems, introduced by NOV in 1985, provide a fully automated mechanism for handling and racking drill pipe during drilling and tripping operations, spinning and torquing drill pipe, and automatic hoisting and racking of disconnected joints of drill pipe. These functions can be integrated via computer controlled sequencing, and operated by a driller in an environmentally secure cabin. An important element of this system is the Iron Roughneck, which was originally introduced by NOV in 1976 and is an automated device that makes pipe connections on the rig floor and requires less direct involvement of rig floor personnel in potentially dangerous operations. The Automated Roughneck is an automated microprocessor-controlled version of the Iron Roughneck.
Horizontal pipe transfer systems were introduced by NOV in 1993. They include the Pipe Deck Machine (“PDM”), which is used to manipulate and move tubulars while stored in a horizontal position; the Pipe Transfer Conveyor (“PTC”), which transports sections of pipe to the rig floor; and a Pickup Laydown System (“PLS”), which raises the pipe to a vertical position for transfer to a vertical racking system. These components may be employed separately, or incorporated together to form a complete horizontal racking system, known as the Pipe Transfer System (“PTS”).
Pipe Handling Tools. The Company’s pipe handling tools are designed to enhance the safety, efficiency and reliability of pipe handling operations. Many of these tools have provided innovative methods of performing the designated task through mechanization of functions previously performed manually. The Rig Technology group manufactures various tools used to grip,
hold, raise, and lower pipe, and in the making up and breaking out of drill pipe, workstrings, casing and production tubulars including spinning wrenches, manual tongs, torque wrenches and kelly spinners.
Mud Pumps. Mud pumps are high pressure pumps located on the rig that force drilling mud down the drill pipe, through the drill bit, and up the space between the drill pipe and the drilled formation (the “annulus”) back to the surface. These pumps, which generate pressures of up to 7,500 psi, must therefore be capable of displacing drilling fluids several thousand feet down and back up the well bore. The conventional mud pump design, known as the triplex pump, uses three reciprocating pistons oriented horizontally. Recently, NOV has introduced the HEX Pump, which uses six pumping cylinders, versus the three used in the triplex pump. Along with other design features, the greater number of cylinders reduces pulsations (or surges) and increases the output available from a given footprint. Reduced pulsation is desirable where downhole measurement equipment is being used during the drilling process, as is often the case in directional drilling.
Hoisting Systems. Hoisting systems are used to raise or lower the drill stem while drilling or tripping, and to lower casing into the wellbore. The drawworks is the heart of the hoisting system. It is a large winch that spools off or takes in the drilling line, which is in turn connected to the drill stem at the top of the derrick. The drawworks also plays an important role in keeping the weight on the drill bit at a desired level. This task is particularly challenging on offshore drilling rigs, which are subject to wave motion. To address this, NOV has introduced the Active Heave Drilling (“AHD”) Drawworks. The AHD Drawworks uses computer-controlled motors to compensate for the motion experienced in offshore drilling operations.
Cranes. NOV provides a comprehensive range of crane solutions, with purpose-built products for all segments of the oil and gas industry as well as many other markets. The Company encompasses a broad collection of brand names with international recognition, and includes a large staff of engineers specializing in the design of cranes and related equipment. The product range extends from small cargo-handling cranes to the world’s largest marine cranes. In all, the Company provides over twenty crane product lines that include standard model configurations as well as custom-engineered and specialty cranes.
Motion Compensation Systems. Traditionally, motion compensation equipment is located on top of the drilling rig and serves to stabilize the bit on the bottom of the hole, increasing drilling effectiveness of floating offshore rigs by compensating for wave and wind action. The AHD Drawworks, discussed above, was introduced to eliminate weight and improve safety, removing the compensator from the top of the rig and integrating it into the drawworks system. In addition to the AHD Drawworks, NOV has introduced an Active Heave Compensation (“AHC”) System that goes beyond the capabilities of the AHD Drawworks to handle the most severe weather. Additionally, NOV tensioning systems provide continuous axial tension to the marine riser pipe (larger diameter pipe which connects floating drilling rigs to the well on the ocean floor) and guide lines on floating drilling rigs, tension leg platforms and jack-up drilling rigs.
Blowout Preventers. BOPs are devices used to seal the space (“annulus”) between the drill pipe and the borehole to prevent blowouts (uncontrolled flows of formation fluids and gases to the surface). The Rig Technology group manufactures a wide array of BOPs used in various situations. Ram and annular BOPs are back-up devices that are activated only if other techniques for controlling pressure in the wellbore are inadequate. When closed, these devices prevent normal rig operations. Ram BOPs seal the wellbore by hydraulically closing rams (thick heavy blocks of steel) against each other across the wellbore. Specially designed packers seal around specific sizes of pipe in the wellbore, shear pipe in the wellbore or close off an open hole. Annular BOPs seal the wellbore by hydraulically closing a rubber packing unit around the drill pipe or kelly or by sealing against itself if nothing is in the hole. NOV’s Pressure Control While Drilling (“PCWD”)® BOP, introduced in 1995, allows operators to drill at pressures up to 2,000 psi without interrupting normal operations, and can act as a normal spherical BOP at pressures up to 5,000 psi.
In 1998, NOV introduced the NXT® ram type BOP which eliminates door bolts, providing significant weight, rig-time, and space savings. Its unique features make subsea operation more efficient through faster ram configuration changes without tripping the BOP stack. In 2004, NOV introduced the LXT, which features many of the design elements of the NXT, but is targeted at the land market. In 2005, the Company began commercializing technology related to a continuous circulation device. This device enables drilling contractors to make and break drill pipe connections without stopping the circulation of drilling fluids, which helps increase drilling efficiency.
Derricks and Substructures. Drilling activities are carried out from a drilling rig. A drilling rig consists of one or two derricks; the substructure that supports the derrick(s); and the rig package, which consists of the various pieces of equipment discussed above. The Rig Technology segment designs, fabricates and services derricks used in both onshore and offshore applications, and substructures used in onshore applications. The Rig Technology group also works with shipyards in the fabrication of substructures for offshore drilling rigs.
Coiled Tubing Equipment. Coiled tubing consists of flexible steel tubing manufactured in a continuous string and spooled on a reel. It can extend several thousand feet in length and is run in and out of the wellbore at a high rate of speed by a hydraulically operated coiled tubing unit. A coiled tubing unit is typically mounted on a truck or skid (steel frames on which portable
equipment is mounted to facilitate handling with cranes or flatbed trucks) and consists of a hydraulically operated tubing reel or drum, an injector head which pushes or pulls the tubing in or out of the wellbore, and various power and control systems. Coiled tubing is typically used with sophisticated pressure control equipment which permits the operator to continue to safely produce the well. The Rig Technology group manufactures and sells both coiled tubing units and the ancillary pressure control equipment used in these operations. Through its acquisition of Rolligon in late 2006, the Company enhanced its portfolio by adding additional pressure pumping and coiled tubing equipment products.
Currently, most coiled tubing units are used in well remediation and completion applications. The Company believes that advances in the manufacturing process of coiled tubing, tubing fatigue protection and the capability to manufacture larger diameter and increased wall thickness coiled tubing strings have resulted in increased uses and applications for coiled tubing products. For example, some well operators are now using coiled tubing in drilling applications such as slim hole reentries of existing wells. NOV engineered and manufactured the first coiled tubing units built specifically for coiled tubing drilling in 1996.
Generally, the Rig Technology group supplies customers with the equipment and components necessary to use coiled tubing, which the customers typically purchase separately. The group’s coiled tubing product line consists of coiled tubing units, coiled tubing pressure control equipment, pressure pumping equipment, snubbing units (which are units that force tubulars into a well when pressure is contained within the wellbore), nitrogen pumping equipment and cementing, stimulation, fracturing and blending equipment.
Wireline Equipment. NOV’s wireline products include wireline drum units, which consist of a spool or drum of wireline cable, mounted in a mobile vehicle or skid, which works in conjunction with a source of power (an engine mounted in the vehicle or within a separate “power pack” skid). The wireline drum unit is used to spool wireline cable into or out of a well, in order to perform surveys inside the well, sample fluids from the bottom of the well, retrieve or replace components from inside the well, or to perform other well remediation or survey operations. The wireline used may be “slickline,” which is conventional steel cable used to convey tools in or out of the well, or “electric line,” which contains an imbedded single-conductor or multi-conductor electrical line which permits communication between the surface and electronic instruments attached to the end of the wireline at the bottom of the well.
Wireline units are usually used in conjunction with a variety of other pressure control equipment which permit safe access into wells while they are flowing and under pressure at the surface. The company engineers and manufactures a broad range of pressure control equipment for wireline operations, including wireline blowout preventers, strippers, packers, lubricators and grease injection units. Additionally, the Company makes wireline rigging equipment such as mast trucks.
Facilities. The Company conducts Rig Technology manufacturing operations at major facilities in Houston, Galena Park, Sugar Land, Conroe, Anderson, Fort Worth and Pampa, Texas; Tulsa and Duncan, Oklahoma; Orange, California; Calgary, Nisku and Edmonton, Canada; Mexicali, Mexico; Kristiansand and Stavanger, Norway; Etten-Leur, the Netherlands; Carquefou, France; Lanzhou and Shanghai, China; Jebel Ali, UAE; Minsk, Belarus; and Dehradun, India. The Rig Technology group maintains sales and service offices in most major oilfield markets, either directly or through agents.
Customers and Competition. The Rig Technology segment sells directly to drilling contractors, other rig fabricators, well servicing companies, pressure pumping companies, national oil companies, major and independent oil and gas companies, supply stores, and pipe-running service providers. Demand for its products is strongly dependent upon capital spending plans by oil and gas companies and drilling contractors, and the level of oil and gas well drilling activity.
The products of the Rig Technology group are sold in highly competitive markets and its sales and earnings can be affected by competitive actions such as price changes, new product development, or improved availability and delivery. The group’s primary competitors are Access Oil Tools; Aker Kvaerner AS; American Block; Bomco; Canrig (a division of Nabors Industries); Cavins Oil Tools; Cameron; DenCon Oil Tools; Forum Oilfield Technologies; General Electric; Hong Hua; IDM; LTI (a division of Rowan Companies); M&I Electric; Tesco Corporation; Wirth M&B GmbH; Stewart & Stevenson, Inc.; ASEP; Crown Energy Technologies; Huntings, Ltd.; Vanoil; Parveen Industries; and Weatherford International, Inc. Management believes that the principal competitive factors affecting its Drilling Equipment business are performance, quality, reputation, customer service, availability of products, spare parts, and consumables, breadth of product line and price.
Petroleum Services & Supplies
The Company provides a broad range of support equipment, spare parts, consumables and services through the Petroleum Services & Supplies segment. The Petroleum Services & Supplies group sells directly to drilling contractors; well servicing companies; oil and gas producers; national oil companies; tubular processors, manufacturers and distributors; oilfield distributors; and pipeline operators.
The Petroleum Services & Supplies group provides a variety of tubular services, composite tubing, and coiled tubing to oil and gas producers, national oil companies, drilling contractors, well servicing companies, pipeline operators, and tubular processors, manufacturers and distributors. These include inspection and reclamation services for drill pipe, casing, production tubing, sucker rods and line pipe at drilling and workover rig locations, at yards owned by its customers, at steel mills and processing facilities that manufacture tubular goods, and at facilities which it owns. The group also provides internal coating of tubular goods at several coating plants worldwide and through licensees in certain locations. Additionally, the Company designs, manufactures and sells high pressure fiberglass and composite tubulars for use in corrosive applications and coiled tubing for use in well servicing applications; and provides in-service inspection of oil, gas and product transmission pipelines through its application of instrumented survey tools (“smart pigs”) which it engineers, manufactures and operates.
The Company’s customers rely on tubular inspection services to avoid failure of tubing, casing, flowlines, pipelines and drill pipe. Such tubular failures are expensive and in some cases catastrophic. The Company’s customers rely on internal coatings of tubular goods to prolong the useful lives of tubulars and to increase the volumetric throughput of in-service tubular goods. The Company’s customers sometimes use fiberglass or composite tubulars in lieu of conventional steel tubulars, due to the corrosion-resistant properties of fiberglass and other composite materials. Tubular inspection and coating services are used most frequently in operations in high-temperature, deep, corrosive oil and gas environments. In selecting a provider of tubular inspection and tubular coating services, oil and gas operators consider such factors as reputation, experience, technology of products offered, reliability and price.
The Company’s Petroleum Services & Supplies group also provides products and services that are used in the course of drilling oil and gas wells. The Downhole Tools business sells and rents drilling motors and specialized downhole tools that are incorporated into the drill stem during drilling operations (“Downhole Tools”), and are also used during fishing, well intervention, re-entry, and well completion operations. The Solids Control business is engaged in the provision of highly-engineered equipment, products and services which separate and manage drill cuttings produced by the drilling process (“Solids Control”). Drill cuttings are usually contaminated with petroleum or drilling fluids, and must be disposed of in an environmentally sound manner. Additionally, efficient separation of drill cuttings enables the re-use of often costly drilling fluids. The Instrumentation business rents and sells proprietary drilling rig instrumentation packages and control systems which monitor various processes throughout the drilling operation, under the name MD®/Totco® (“Instrumentation”). The Pumps & Expendables business provides centrifugal, reciprocating, and progressing cavity pumps and pump expendables (“Pumps & Expendables”) into the global oil and gas and industrial markets.
Tubular Coating. The Company develops, manufactures and applies its proprietary tubular coatings, known as Tube-Kote® coatings, to new and used tubulars. Tubular coatings help prevent corrosion of tubulars by providing a tough plastic shield to isolate steel from corrosive oilfield fluids such as CO2, H2S and brine. Delaying or preventing corrosion extends the life of existing tubulars, reduces the frequency of well remediation and reduces expensive interruptions in production. In addition, coatings are designed to increase the fluid flow rate through tubulars by decreasing or eliminating paraffin and scale build-up, which can reduce or block oil flow in producing wells. The smooth inner surfaces of coated tubulars often increase the fluid through-put on certain high-rate oil and gas wells by reducing friction and turbulence. The Company’s reputation for supplying quality internal coatings is an important factor in its business, since the failure of coatings can lead to expensive production delays and premature tubular failure. In 2005, NOV created a 60%-owned joint venture in China with the Huabei Petroleum Administration Bureau, which coats Chinese produced drill pipe using NOV’s proprietary coatings. In 2007, the joint venture opened a second coating plant in Jiangyin City, China.
Tubular Inspection. Newly manufactured pipe sometimes contains serious defects that are not detected at the mill. In addition, pipe can be damaged in transit and during handling prior to use at the well site. As a result, exploration and production companies often have new tubulars inspected before they are placed in service to reduce the risk of tubular failures during drilling, completion, or production of oil and gas wells. Used tubulars are inspected by the Company to detect service-induced flaws after the tubulars are removed from operation. Used drill pipe and used tubing inspection programs allow operators to replace defective lengths, thereby prolonging the life of the remaining pipe and saving the customer the cost of unnecessary tubular replacements and expenses related to tubular failures.
Tubular inspection services employ all major non-destructive inspection techniques, including electromagnetic, ultrasonic, magnetic flux leakage and gamma ray. These inspection services are provided both by mobile units which work at the wellhead as used tubing is removed from a well, and at fixed site tubular inspection locations. The group provides an ultrasonic inspection service for detecting potential fatigue cracks in the end area of used drill pipe, the portion of the pipe that traditionally has been the most difficult to inspect. Tubular inspection facilities also offer a wide range of related services, such as API thread inspection, ring and plug gauging, and a complete line of reclamation services necessary to return tubulars to useful service, including tubular cleaning and straightening, hydrostatic testing and re-threading.
In addition, the Company applies hardbanding material to drill pipe, to enhance its wear characteristics and reduce downhole casing wear as a result of the drilling process. In 2002, the Company introduced its proprietary line of hardbanding material, TCS - 8000ä. The group also cleans, straightens, inspects and coats sucker rods at 11 facilities throughout the Western Hemisphere. Additionally, new sucker rods are inspected before they are placed into service, to avoid premature failure, which can cause the oil well operator to have to pull and replace the sucker rod.
Mill Systems and Sales. The Company engineers and fabricates inspection equipment for steel mills, which it sells and rents. The equipment is used for quality control purposes to detect defects in the pipe during the high-speed manufacturing process. Each piece of mill inspection equipment is designed to customer specifications and is installed and serviced by the Company.
Fiberglass & Composite Tubulars. When compared to conventional carbon steel and even corrosion-resistant alloys, resin-impregnated fiberglass and other modern plastic composites often exhibit superior resistance to corrosion. Some producers manage the corrosive fluids sometimes found in oil and gas fields by utilizing composite or fiberglass tubing, casing and line pipe in the operations of their fields. In 1997, the Company acquired Fiber Glass Systems, a leading provider of high pressure fiberglass tubulars used in oilfield applications, to further serve the tubular corrosion prevention needs of its customers. Fiber Glass Systems has manufactured fiberglass pipe since 1968 under the name “Star®,” and was the first manufacturer of high-pressure fiberglass pipe to be licensed by the API in 1992. Through acquisitions and investments in technologies, the Company has extended its fiberglass and composite tubing offering into industrial and marine applications, in addition to its oilfield market.
Coiled Tubing. Coiled tubing provides a number of significant functional advantages over the principal alternatives of conventional drill pipe and workover pipe. Coiled tubing allows faster “tripping,” since the coiled tubing can be reeled quickly on and off a drum and in and out of a wellbore. In addition, the small size of the coiled tubing unit compared to an average workover rig or drilling rig reduces preparation time at the well site. Coiled tubing permits a variety of workover and other operations to be performed without having to pull the existing production tubing from the well and allows ease of operation in horizontal or highly deviated wells. Thus, operations using coiled tubing can be performed much more quickly and, in many instances, at a significantly lower cost. Finally, use of coiled tubing generally allows continuous production of the well, eliminating the need to temporarily stop the flow of hydrocarbons. As a result, the economics of a workover are improved because the well can continue to produce hydrocarbons and thus produce revenues while the well treatments are occurring. Continuous production also reduces the risk of formation damage which can occur when the flow of fluids is stopped or isolated. Under normal operating conditions, the coiled tubing string must be replaced every three to four months. NOV designs, manufactures, and sells coiled tubing under the Quality Tubing brand name at its mill in Houston, Texas.
Pipeline Inspection. In-service inspection services for oil and gas pipelines identify anomalies in pipelines without removing or dismantling the pipelines or stopping the product flow, giving customers a convenient and cost-effective method of identifying potential defects. The Petroleum Services & Supplies group inspects pipelines by launching a sophisticated survey instrument into the pipeline. Propelled by the product flow, the instrument uses electromagnetics, ultrasonics, and mechanical measurements received on digital and analog media to monitor the severity and location of internal and external pitting-type corrosion as well as other mechanical anomalies in the pipeline, providing a basis for evaluation and repair by the customer. Once the test is complete, the survey instrument is returned to the Company, refurbished and used for future pipeline inspections.
Downhole Tools. NOV designs, manufacturers and services a wide array of downhole motors used in straight hole, directional, slim hole, and coiled tubing drilling applications. These motors are sold or leased under the brand names TrudrillTM, VectorTM, BlackMax®, and PrescottTM. This business also maintains a wide variety of motor power sections, which it incorporates into its own motors and also sells to third parties. Downhole drilling motors utilize hydraulic horsepower from the drilling fluid pumped down the drill stem to develop torque at the bit. Motors are capable of achieving higher rotary velocities than can generally be achieved using conventional surface rotary equipment. Motors are often used in conjunction with high speed PDC bits to improve rates of penetration.
The Downhole Tools group also manufactures and sells drilling jars and fishing tools, which are marketed under the GriffithTM and Bowen® brand names. Drilling jars are placed in the drill string, where they can be used to generate a sudden, jarring motion to free the drill string should it become stuck in the wellbore during the drilling process. This jarring motion is generated using hydraulic and/or mechanical force provided at the surface. In the event that a portion of the drill string becomes stuck and cannot be jarred loose, fishing tools are run into the wellbore on the end of the drill string to retrieve the portion that is stuck.
NOV acquired NQL Energy Services, Inc. (“NQL”) in late 2006 for approximately $300 million in cash. NQL manufactures, leases, sells and services downhole tools - including drilling motors, jars, shock tools, reamers, and EM-MWD systems - in 23 locations across seven countries. NOV acquired the assets of Gammaloy Holdings, L.P. in 2007. Gammaloy™ manufactures, sells and rents non-magnetic drill collars and other related products. These transactions have expanded NOV’s downhole tools portfolio and increased exposure to directional drilling services.
Solids Control. The Solids Control product line uses a variety of technologies to separate drill cuttings from drilling fluids, and to transport, dry and refine drill cuttings for safe disposal under the Brandt NOV brand name. The Company believes the regulatory and industry trends toward minimizing the environmental impact of drilling operations in a number of environmentally sensitive oil and gas producing regions will lead to greater demand for solids control products and waste management services. Waste management services cover many areas associated with the drilling of a well including solids removal, solids transport, solids treatment and solids disposal. The Company further believes the trend towards more technically complex drilling, including highly deviated directional wells and slim-hole completions, will favorably impact the demand for solids control technology because of its ability to reduce costly downhole problems. As environmental constraints are increased and as awareness of environmental protection grows, the Company believes that its drill cuttings separation, cuttings transport and treating processes will experience increased demand.
The Company has a history of introducing new solids control products and services obtained both through its internal development and through acquiring or licensing technologies from others. Current product offerings are circular, elliptical and linear motion shale shakers and shale shaker screens that comply with the November 2004 API Recommended Practice 13C, degassers, desanders, desilters, high speed/high capacity centrifuges and conventional centrifuges, thermal desorption units, cuttings conveyance systems and closed loop drilling fluids systems at its facilities in Conroe and Houston, Texas; Aberdeen, Scotland; Leduc, Canada; Trinidad; Singapore; and Dubai, UAE.
Through development of new product offerings and strategic acquisitions the Company has become a leading provider of thermal desorption cuttings processing services to the drilling industry. Similar efforts have been successful in developing a broad range of services, including centrifugal dryers, and the Brandt NOV FreeFlow system.
Instrumentation. The Company’s Instrumentation business provides drilling rig operators real time measurement and monitoring of critical parameters required to improve rig safety and efficiency. In 1999, the Company introduced its RigSense® Wellsite Information System, which combines leading hardware and software technologies into an integrated drilling rig package. Access of drilling data is provided to offsite locations, enabling company personnel to monitor drilling operations from an office environment, through a secure link. Systems are both sold and rented, and are comprised of hazardous area sensors placed throughout the rig to measure critical drilling parameters; all networked back to a central command station for review, recording and interpretation. This allows key rig personnel to perform individual jobs more effectively. The Company has evolved from data collection to a leading drilling information provider by using state-of-the-art satellite communications to increase operational efficiencies between drilling rigs and their corporate office. The Company offers unique business integration services to directly integrate information into business applications that improves accuracy and assists drilling contractors in managing their drilling business. Cost of compliance for Sarbanes-Oxley is minimized through the Company’s DrillSuite™ and RigMS offerings. Reports on drilling activities and processes are now provided from the rig site as a part of the DrillSuite business solution to assist the drilling contractor in managing their business of drilling. DrillSuite allows contractors to streamline administration by eliminating manual entry of data, promotes accurate payroll processing and invoicing, and includes asset tracking and preventive maintenance management through its RigMS solution. The real time information provided also allows the Company to advance the drilling process using advanced drilling algorithms and electronic controls such as our Wildcat Auto Drilling System for better execution of the well plan, enhanced rates of penetration, reduced program costs, and improved wellbore quality. Complimenting the Company’s surface solutions is a portfolio of Down-Hole Instrumentation (DHI) products for both straight-hole and directional markets. Key advancements in this area include the introduction of the Company’s time saving ETotco™ Electronic Drift Recorder, which serves as an electronic equivalent to the traditional mechanical drift tool that helped to launch the Company in 1929. As a pioneer in down-hole electromagnetic (EM) communications for MWD tools, the Company serves the market of independent directional drillers with sales and rental business models via its BlackStar® EM MWD group. The EM advantage allows the benefits of MWD operations to be realized for drilling situations where traditional mud-pulsed communications are problematic with respect to wellbore quality.
Pumps & Expendables. The Company’s Pumps & Expendables business designs, manufactures, and sells pumps that are used in oil and gas drilling operations and production applications. These pumps include reciprocating, centrifugal, and progressive cavity pumps. (High pressure mud pumps are sold within the Rig Technology segment.) These pumps are sold as individual units and unitized packages with drivers, controls and piping. This group also manufactures fluid end expendables (liners, valves, pistons, and plungers) fluid end modules, and a complete line of dies and inserts for pipe handling. The group offers popular industry brand names like Wheatley, Gaso, and Omega reciprocating pumps, acquired in 2000; Halco Centrifugal Pumps, acquired in 2002; Petroleum Expendable Products (PEP), acquired in 1997; and Phoenix Energy Products, acquired in 1998.
The group, through its Mono/Monoflo® business, is also a worldwide leader in the design and manufacture of a wide range of progressive cavity pumps, grinders and screens used in various industrial applications. Mono/Monoflo also manufactures a broad range of oilfield products which include fluid transfer, artificial lift and power sections.
The group also manufactures a line of commodity and high end valves and chokes used in both production and drilling applications. Additionally these products are used in the fabrication of choke and kill manifolds as well as standpipe manifolds.
The group manufactures its pump products in Houston, Odessa and Marble Falls, Texas; Tulsa and McAlester, Oklahoma; Scott, Louisiana; Manchester, England; Melbourne, Australia; and Buenos Aires, Argentina.
Customers and Competition. Customers for the Petroleum Services & Supplies’ tubular services include major and independent oil and gas companies, national oil companies, drilling and workover contractors, oilfield equipment and product distributors and manufacturers, oilfield service companies, pipeline operators, steel mills, and other industrial companies. The Company’s competitors include, among others, Ameron International Corp, EDO Corporation, Pipeline Integrity International Ltd. (a division of General Electric), ShawCor Ltd., Smith International, Inc., Frank’s International, Inc., H. Rosen Engineering, GmbH; T.D. Williamson, Inc.; Baker Hughes Incorporated; Diascan; Magpie; Weatherford International Ltd.; Patterson Tubular Services; and Precision Tube (a division of Tenaris). In addition, the group competes with a number of smaller regional competitors in tubular inspection. Certain foreign jurisdictions and government-owned petroleum companies located in some of the countries in which this group operates have adopted policies or regulations that may give local nationals in these countries certain competitive advantages. Within the Company’s corrosion control products, certain substitutes such as non-metallic tubulars, inhibitors, corrosion resistant alloys, cathodic protection systems, and non-metallic liner systems also compete with the Company’s products. Management believes that the principal competitive factors affecting this business are performance, quality, reputation, customer service, availability of products, spare parts, and consumables, breadth of product line and price.
The primary customers for drilling services offered by the Petroleum Services & Supplies group include drilling contractors, well servicing companies, major and independent oil and gas companies, and national oil companies. Competitors in drilling services include Smith International (“SWACO”); Derrick Manufacturing Corp.; Fluid Systems; Oil Tools Pte. Ltd; Peak Energy Services, Ltd.; Petron Industries, Inc.; Epoch (a division of Nabors Industries); Pason Systems, Inc.; Robbins & Myers; Kem-Tron, Inc.; Double Life Corporation, Inc.; Oteco, Inc.; Southwest Oilfield Products; Forum Oilfield Technologies; P-Quip Oilfield Products; and a number of regional competitors. The Petroleum Services & Supplies group sells drilling services into highly competitive markets. Management believes that on-site service is becoming an increasingly important competitive element in this market, and that the principal competitive factors affecting the business are performance, quality, reputation, customer service, product availability and technology, breadth of product line and price.
Distribution Services
Through its network of over 180 locations worldwide, the Distribution Services group provides supply chain management services to drilling contractors and operators around the world. This group stocks and sells consumable maintenance, repair and operating supplies and spare parts that are needed throughout the drilling, completion and production process. The supplies and equipment stocked by our distribution service centers vary by location. Each distribution point generally offers a large line of oilfield products including valves, fittings, flanges, spare parts for oilfield equipment and miscellaneous expendable items. This group’s procurement and supply chain solutions for customers that choose to outsource these functions generate a quarter of this group’s revenues.
A new industry value offering by the Distribution Services group is the installation, staffing and management of supply stores on offshore drilling rigs. When NOV assumes the responsibility of operating these stores, it installs its own ERP system onboard to access NOV’s distribution locations around the world, its base of thousands of vendors globally and NOV’s global inventory. This relieves the average offshore drilling rig’s balance sheet, provides substantially better accounting of these expense items, extends payment on part of the driller until the item is actually issued from the onboard supply store, and removes risk of ownership from the buyer. Drillers reduce lead-times since NOV’s materials planning process now has access to real-time demand patterns specific to the rig. This also enables standardization between rigs and across the industry. In today’s world of tight supply, critical spares can be more efficiently managed between rigs in centralized NOV locations, eliminating the need to carry expensive “just-in-case” duplicate assets on every rig. While the benefits are substantial for smaller/new drilling contractors, or rigs in remote locations around the world, large established drilling companies also benefit from more effective supply chain management and reduced total cost of ownership.
NOV’s e-Distribution solutions leverage the flexible infrastructure of SAP™ to extend the customer’s investment in systems and address the total cost of ownership by streamlining the acquisition process from requisition to procurement to payment, by digitally managing approval routing and workflow, and by providing robust reporting functionality.
Approximately 77% of the Distribution Services group’s sales in 2007 were in the United States and Canada. The remainder comes from key international markets in Latin America, the North Sea, Middle East, Africa and the Far East.
Strategically the group enhanced its alliances with oil and gas companies and certain drilling contractors, and is continually expanding its offerings, like setting up and operating supply stores on offshore rigs, to increase its revenues and offer differentiating value propositions. Additionally the group continues to leverage its extensive purchasing power to reduce the costs of the goods it purchases. The group is strategically expanding its sourcing network into low cost countries globally.
Customers and Competition. The primary customers for Distribution Services include drilling contractors, well servicing companies, major and independent oil and gas companies, and national oil companies. Competitors in Distribution Services include Wilson Supply (a division of Smith International), CE Franklin, McJunkin Red Man, and a number of regional competitors.
2007 Acquisitions and Other Investments
In 2007, the Company made the following acquisitions and outside investments:
In 2007, the Company paid an aggregate purchase price of $325.0 million ($323.9 million in net cash and $1.1 million of notes payable) for acquisitions and outside investments including final payment for NQL Energy Services, Inc. purchased in 2006.
Seasonal Nature of the Company’s Business
Historically, the level of some of the Company’s businesses has followed seasonal trends to some degree. In general the Rig Technology group has not experienced significant seasonal fluctuation although orders for new equipment may be modestly affected by holiday schedules. There can be no guarantee that seasonal effects will not influence future sales in this segment.
In Canada, the Petroleum Services & Supplies segment has typically realized high first quarter activity levels, as operators take advantage of the winter freeze to gain access to remote drilling and production areas. In past years, certain Canadian businesses within Petroleum Services & Supplies and Distribution Services have declined during the second quarter due to warming weather conditions which resulted in thawing, softer ground, difficulty accessing drill sites, and road bans that curtailed drilling activity (“Canadian Breakup”). However, these businesses have typically rebounded in the third and fourth quarter. Petroleum Services & Supplies activity in both the U.S. and Canada sometimes increases during the third quarter and then peaks in the fourth quarter as operators spend the remaining drilling and/or production capital budgets for that year. Petroleum Services & Supplies revenues in the Rocky Mountain region sometimes decline in the late fourth quarter or early first quarter due to harsh winter weather.
Within Petroleum Services & Supplies, the Pipeline Inspection business has typically experienced reduced activity during the first quarter of the calendar year. The high winter demand for gas and petroleum products in the northern hemisphere and the consequent curtailment of pipeline maintenance and inspection programs often results in less opportunity to perform pipeline inspection during this time. The segment’s fiberglass and composite tubulars business in China has typically declined in the first quarter due to the impact of weather on manufacturing and installation operations, and due to business slow downs associated with the Chinese New Year.
The Company anticipates that the seasonal trends described above will continue. However, there can be no guarantee that spending by the Company’s customers will continue to follow patterns seen in the past or that spending by other customers will remain the same as in prior years.
Marketing & Distribution Network
Substantially all of our Rig Technology capital equipment and spare parts sales, and a large portion of our smaller pumps and parts sales, are made through our direct sales force and distribution service centers. Sales to foreign state-owned oil companies are typically made in conjunction with agent or representative arrangements. Products within our Petroleum Service & Supplies segment are rented and sold worldwide through our own sales force and through commissioned representatives. Distribution Services sales are made through our network of distribution service centers.
The Rig Technology segment’s customers include drilling contractors, shipyards and other rig fabricators, well servicing companies, pressure pumpers, national oil companies, major and independent oil and gas companies, supply stores, and pipe-running service providers. Demand for its products is strongly dependent upon capital spending plans by oil and gas companies and drilling contractors, and the level of oil and gas well drilling activity. Rig Technology purchases can represent significant capital expenditures, and are often sold as part of a rig fabrication or major rig refurbishment package. Sometimes these packages cover multiple rigs, and often the Company bids jointly with other related product and services providers, such as rig fabrication yards and rig design firms.
The Petroleum Services & Supplies group’s customers for tubular services include major and independent oil and gas companies, national oil companies, oilfield equipment and product distributors and manufacturers, drilling and workover contractors, oilfield service companies, pressure pumpers, pipeline operators, pipe mills, manufacturers and processors, and other industrial companies. Certain tubular inspection and tubular coating products and services often are incorporated as a part of a tubular package sold by tubular supply stores to end users. The Company primarily has direct operations in the international marketplace, but operates through agents in certain markets.
The Petroleum Services & Supplies group’s customers for drilling services are predominantly major and independent oil and gas companies, national oil companies, drilling contractors, well servicing companies, providers of drilling fluids, and other oilfield service companies. This group operates sales and distribution facilities at strategic locations worldwide to service areas with high drilling activity. Strategically located service and engineering facilities provide specialty repair and maintenance services to customers. Sales of capital equipment are sometimes made through rig fabricators, and often are bid as part of a rig fabrication package or rig refurbishment package. Sometimes these packages cover multiple rigs, and often the Company bids jointly with other related service providers.
Distribution Services sales are made through our network of distribution service centers. Customers for our products and services include drilling and other service contractors, exploration and production companies, supply companies and nationally owned or controlled drilling and production companies.
The Company’s foreign operations, which include significant operations in Canada, Europe, the Far East, the Middle East, Africa and Latin America, are subject to the risks normally associated with conducting business in foreign countries, including foreign currency exchange risks and uncertain political and economic environments, which may limit or disrupt markets, restrict the movement of funds or result in the deprivation of contract rights or the taking of property without fair compensation. Government-owned petroleum companies located in some of the countries in which the Company operates have adopted policies (or are subject to governmental policies) giving preference to the purchase of goods and services from companies that are majority-owned by local nationals. As a result of such policies, the Company relies on joint ventures, license arrangements and other business combinations with local nationals in these countries. In addition, political considerations may disrupt the commercial relationship between the Company and such government-owned petroleum companies. Although the Company has not experienced any significant problems in foreign countries arising from nationalistic policies, political instability, economic instability or currency restrictions, there can be no assurance that such a problem will not arise in the future. See Note 15 of the Notes to the Consolidated Financial Statements for information regarding geographic revenue information.
Research and New Product Development and Intellectual Property
The Company believes that it has been a leader in the development of new technology and equipment to enhance the safety and productivity of drilling and well servicing processes and that its sales and earnings have been dependent, in part, upon the successful introduction of new or improved products. Through its internal development programs and certain acquisitions, the Company has assembled an extensive array of technologies protected by a substantial number of trade and service marks, patents, trade secrets, and other proprietary rights.
As of December 31, 2007, the Company held a substantial number of United States patents and had several patent applications pending. Expiration dates of such patents range from 2008 to 2027. As of this date, the Company also had foreign patents and patent applications pending relating to inventions covered by the United States patents. Additionally, the Company maintains a substantial number of trade and service marks and maintains a number of trade secrets.
Although the Company believes that this intellectual property has value, competitive products with different designs have been successfully developed and marketed by others. The Company considers the quality and timely delivery of its products, the service it provides to its customers and the technical knowledge and skills of its personnel to be more important than its intellectual property in its ability to compete. While the Company stresses the importance of its research and development programs, the technical challenges and market uncertainties associated with the development and successful introduction of new products are such that there can be no assurance that the Company will realize future revenues from new products.
Engineering and Manufacturing
The manufacturing processes for the Company’s products generally consist of machining, welding and fabrication, heat treating, assembly of manufactured and purchased components and testing. Most equipment is manufactured primarily from alloy steel, and the availability and price of alloy steel castings, forgings, purchased components and bar stock is critical to the production and timing of shipments. Primary manufacturing facilities for the Rig Technology segment are located in Houston, Galena Park, Sugar Land, Conroe, Anderson, Fort Worth and Pampa, Texas; Duncan and Tulsa, Oklahoma; Orange, California; Calgary, Nisku and Edmonton, Canada; Mexicali, Mexico; Aberdeen, Scotland; Kristiansand, and Stavanger, Norway; Etten-Leur, the Netherlands; Carquefou, France; Singapore; Perth, Australia; Lanzhou and Shanghai, China; Jebel Ali, UAE; and Dehradun, India.
The Company’s Petroleum Services & Supplies segment manufactures or assembles the equipment and products which it rents and sells to customers, and which it uses in providing services. Downhole tools are manufactured at facilities in Houston, Texas; Nisku and Edmonton, Alberta; Jebel Ali, UAE; and Singapore. Solids control equipment and screens are manufactured at facilities in Houston and Conroe, Texas; New Iberia, Louisiana; Aberdeen, Scotland; Nisku, Canada; Trinidad; and Macae, Brazil. Instrumentation equipment is manufactured at Cedar Park and Houston, Texas facilities. Pumps are manufactured at facilities in Houston, Odessa and Marble Falls, Texas; McAlester and Tulsa, Oklahoma; Manchester, England; Melbourne, Australia; and Buenos Aires, Argentina.
The group manufactures tubular inspection equipment and instrumented pipeline inspection tools at its Houston, Texas facility for resale, and renovates and repairs equipment at its manufacturing facilities in Houston, Texas; Celle, Germany; Nisku, Canada; and Aberdeen, Scotland. Fiberglass and composite tubulars and fittings are manufactured at facilities in San Antonio and Big Spring, Texas; Little Rock, Arkansas; Tulsa, Oklahoma; Wichita, Kansas; and Harbin and Suzhou, China facilities, while tubular coatings are manufactured in its Houston, Texas facility, or through restricted sale agreements with third party manufacturers.
Certain of the Company’s manufacturing facilities and certain of the Company’s products have various certifications, including, ISO 9001, API, APEX and ASME.
Raw Materials
The Company believes that materials and components used in its servicing and manufacturing operations and purchased for sales are generally available from multiple sources. The prices paid by the Company for its raw materials may be affected by, among other things, energy, steel and other commodity prices; tariffs and duties on imported materials; and foreign currency exchange rates. The Company experienced higher steel prices and greater difficulty securing necessary steel supplies in 2004 and 2005 than it experienced during the preceding several years. In 2006 and 2007, the price for mild steel and standard grades stabilized while specialty alloy prices continued to rise driven primarily by escalation in the price of the alloying agents. However, toward the end of 2007, the Company began to see price escalations in all grades of steel. The Company has generally been successful in its effort to mitigate the financial impact of higher raw materials costs on its operations by applying surcharges to and adjusting prices on the products it sells. Furthermore, NOV continued to expand its supply base in 2006 and 2007 throughout the world to address our customers’ needs. Higher prices and lower availability of steel and other raw material the Company uses in its business may adversely impact future periods.
Backlog
The Company monitors its backlog of orders within its Rig Technology group to guide its planning. Backlog includes orders greater than $250,000 for most items and orders for wireline units in excess of $75,000, and which require more than three months to manufacture and deliver.
Backlog measurements are made on the basis of written orders which are firm, but may be cancelable by the customer. Most require reimbursement to the Company for costs incurred in such an event. There can be no assurance that the backlog amounts will ultimately be realized as revenue, or that the Company will earn a profit on backlog work. Our backlog for equipment at December 31, 2007, 2006 and 2005 was $9.0 billion, $6.0 billion and $2.3 billion, respectively.
Employees
At December 31, 2007, the Company had a total of 31,198 employees, of which 4,467 were temporary employees. Approximately 178 employees in the Company’s fiberglass tubulars plant in Little Rock, Arkansas, and 115 employees of the Company’s downhole tools product line, are subject to collective bargaining agreements. Additionally, certain of the Company’s employees in certain foreign locations are subject to collective bargaining agreements.
ITEM 1A.
ITEM 1A. RISK FACTORS
You should carefully consider the risks described below, in addition to other information contained or incorporated by reference herein. Realization of any of the following risks could have a material adverse effect on our business, financial condition, cash flows and results of operations.
Risks Related to the Grant Prideco Merger and the Related Transactions
On December 16, 2007, we agreed to acquire 100% of the outstanding shares of Grant Prideco, Inc. for a combination of $23.20 cash per share and 0.4498 shares of National Oilwell Varco, Inc. common stock. Consummation of the merger requires approval by the stockholders of Grant Prideco and also approval from various regulatory agencies. We anticipate completion of the merger during the second quarter of 2008; however, we cannot assure you that the acquisition will be completed at this time or at all.
We may not be able to successfully integrate the operations of the two companies and realize the anticipated benefits of the Grant Prideco merger.
Achieving the benefits we expect from the merger will depend in large part on integrating our technology, operations and personnel in a timely and efficient manner to minimize the impact on customers, employees and management. Integration of the two previously independent companies will be a complex, time consuming and costly process. Failure to timely and successfully integrate these companies may have a material adverse effect on the combined company’s business, financial condition and results of operations. The difficulties of combining the companies will present challenges to the combined company’s management, including:
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operating a significantly larger combined company with operations in more geographic areas and with more business lines;
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integrating personnel with diverse backgrounds and organizational cultures;
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coordinating sales and marketing functions;
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retaining key employees, customers or suppliers;
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preserving the research and development, collaboration, distribution, marketing, promotion and other important relationships of National Oilwell Varco and Grant Prideco;
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integrating the internal controls and procedures that National Oilwell Varco will be required to maintain under the Sarbanes-Oxley Act of 2002; and
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consolidating other corporate and administrative functions.
The combined company will also be exposed to other risks that are commonly associated with transactions similar to the merger, such as unanticipated liabilities and costs, some of which may be material, and diversion of management’s attention. As a result, we cannot assure you that we will realize any of the anticipated benefits of the merger, including anticipated cost savings, and failure to do so could adversely affect the business of the combined company after the merger.
The costs of the Grant Prideco merger could adversely affect combined financial results.
We expect the total merger-related costs, including executive severance but exclusive of other employee benefit costs, to be approximately $110 million, consisting primarily of executive severance, financial advisory, legal and accounting fees, financial printing costs and other related charges. The amount of these expenses is a preliminary estimate and is subject to change. In addition, the combined company will incur certain integration costs, including, but not limited to, costs associated with consolidating administrative and operational functions and the closure of certain facilities. If the benefits of the merger do not exceed the costs associated with the merger, including any dilution to the stockholders of both companies resulting from the issuance of shares in connection with the merger, the combined company’s financial results, including earnings per share, could be adversely affected.
National Oilwell Varco shareholders will be diluted by the Grant Prideco merger
The merger will dilute the ownership positions of the present stockholders of National Oilwell Varco. Based on the number of Grant Prideco shares outstanding as of December 17, 2007, National Oilwell Varco will issue to Grant Prideco shareholders approximately 56.3 million shares of National Oilwell Varco common stock in the merger. As a result, National Oilwell Varco stockholders and Grant Prideco stockholders will own approximately 86% and 14%, respectively, of the combined company’s common stock outstanding after the completion of the merger, based on the common stock of National Oilwell Varco and Grant Prideco outstanding as of December 17, 2007.
Failure to complete the Grant Prideco merger or delays in completing the Grant Prideco merger could negatively impact National Oilwell Varco’s and Grant Prideco’s stock prices and future business and operations.
If the merger is not completed for any reason, National Oilwell Varco and Grant Prideco may be subject to a number of material risks, including the following:
•
the individual companies will not realize the benefits expected from becoming part of a combined company, including potentially enhanced financial and competitive position;
•
under certain circumstances, Grant Prideco may be required to pay National Oilwell Varco a termination fee of $185.0 million, and under certain other circumstances, either of the companies may be required to reimburse the other party for up to $5.0 million in merger-related expenses;
•
the price of common stock of National Oilwell Varco or Grant Prideco may decline to the extent that the current market price of the common stock reflects a market assumption that the merger will be completed; and
•
some costs related to the merger, such as legal, accounting and financial advisor fees, must be paid even if the merger is not completed.
Whether or not the Grant Prideco merger is completed, the pendency of the transaction could cause disruptions in the businesses of National Oilwell Varco, which could have an adverse effect on their businesses and financial results.
In response to the announcement of the merger, National Oilwell Varco’s customers may delay or defer purchasing decisions. Any delay or deferral of purchasing decisions by customers could negatively affect the business and results of operations of National Oilwell Varco, regardless of whether the merger is ultimately completed. Similarly, current and prospective employees of National Oilwell Varco may experience uncertainty about their future roles with the companies until after the merger is completed or if the merger is not completed. This may adversely affect the ability of National Oilwell Varco to attract and retain key management, marketing and technical personnel. In addition, the diversion of the attention of the companies’ respective management teams away from the day-to-day operations during the pendency of the transaction could have an adverse effect on the financial condition and operating results of either company.
National Oilwell Varco and Grant Prideco could be required to divest, hold separate or license assets to complete the Grant Prideco merger.
We cannot complete the merger until the waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976 (“HSR”) or any other applicable waiting period has expired or is otherwise terminated. On February 6, 2008 National Oilwell Varco and Grant Prideco refiled antitrust documents relating to the merger with the FTC and the DOJ. National Oilwell Varco and Grant Prideco have also made, or are in the process of making, the required filings relating to the merger with various government authorities in a number of foreign jurisdictions in which one or both companies have sufficient market presence to require filings. We continue to work with these various governmental agencies to obtain regulatory clearance to complete the merger. As a prerequisite to obtaining the expiration or termination of this waiting period, or to avoid an injunction by the Department of Justice or another governmental entity, whether foreign or domestic, National Oilwell Varco, Grant Prideco or both companies may be required to divest, hold separate or license certain assets. Although each of National Oilwell Varco and Grant Prideco have agreed to use their reasonable best efforts to obtain the expiration or termination of this waiting period and to obtain any other governmental clearance or approvals under federal, state or foreign antitrust laws, neither National Oilwell Varco nor Grant Prideco is required to divest, hold separate or license any of their respective businesses, product lines or assets, take or agree to take any other action or agree to any limitation, that would reasonably be expected to have a material adverse effect on the financial condition, results of operations or prospects of National Oilwell Varco or Grant Prideco or that is not conditioned upon completion of the merger.
Divestitures or licensing of assets can be time consuming and may delay or prevent completion of the proposed merger. Because there may be a limited number of potential buyers or licensees for the assets subject to divestiture or license and because potential buyers will likely be aware of the circumstances of the sale or license, these assets could be sold or licensed at prices or rates lower than their fair market values or the prices National Oilwell Varco or Grant Prideco paid for these assets. Asset divestitures or licenses of National Oilwell Varco’s or Grant Prideco’s assets could also significantly reduce the value of the combined company, eliminate potential cost savings opportunities or lessen the anticipated benefits of the merger.
If National Oilwell Varco or Grant Prideco fails to obtain all required consents and waivers, third parties may terminate or alter existing contracts.
Certain agreements with suppliers, customers, licensors or other business partners may require National Oilwell Varco or Grant Prideco to obtain the approval or waiver of these other parties in connection with the merger. National Oilwell Varco and Grant Prideco have agreed to use reasonable efforts to secure the necessary approvals and waivers. However, we cannot assure you that National Oilwell Varco and/or Grant Prideco will be able to obtain all of the necessary approvals and waivers, and failure to do so could have a material adverse effect on the business of the combined company after the merger.
Certain litigation against Grant Prideco, its directors and National Oilwell Varco has been instituted. This litigation could delay or prevent the Grant Prideco merger. Similar litigation could also be instituted in the future.
As of February 28, 2008, National Oilwell Varco and Grant Prideco are aware of five lawsuits that have been filed in connection with the proposed merger. All five cases were filed in the district court of Harris County, Texas.
The plaintiffs in these lawsuits are stockholders of Grant Prideco. They allege, among other things, breaches of fiduciary duties of the directors of Grant Prideco owed to the stockholders of Grant Prideco in connection with the proposed merger. In one of the complaints, the plaintiffs also allege aiding and abetting of the breaches by National Oilwell Varco. The plaintiffs seek to enjoin the merger and ask for other legal and equitable relief. National Oilwell Varco and Grant Prideco believe that these lawsuits are without merit and intend to defend against them. This litigation could, however, delay or prevent the proposed merger. It is also possible that additional suits seeking to enjoin the proposed merger could be filed. Any such suit could delay or prevent the proposed merger.
Risks Related to National Oilwell Varco
We are dependent upon the level of activity in the oil and gas industry, which is volatile.
The oil and gas industry historically has experienced significant volatility. Demand for our services and products depends primarily upon the number of oil rigs in operation, the number of oil and gas wells being drilled, the depth and drilling conditions of these wells, the volume of production, the number of well completions, capital expenditures of other oilfield service companies and the level of workover activity. Drilling and workover activity can fluctuate significantly in a short period of time, particularly in the United States and Canada. The willingness of oil and gas operators to make capital expenditures to explore for and produce oil and natural gas and the willingness of oilfield service companies to invest in capital equipment will continue to be influenced by numerous factors over which we have no control, including:
•
the ability of the members of the Organization of Petroleum Exporting Countries, or OPEC, to maintain price stability through voluntary production limits, the level of production by non-OPEC countries and worldwide demand for oil and gas;
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level of production from known reserves;
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cost of exploring for and producing oil and gas;
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level of drilling activity and drilling rig dayrates;
•
worldwide economic activity;
•
national government political requirements;
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development of alternate energy sources; and
•
environmental regulations.
If there is a significant reduction in demand for drilling services, in cash flows of drilling contractors, well servicing companies, or production companies or in drilling or well servicing rig utilization rates, then demand for the products and services of the Company will decline.
Volatile oil and gas prices affect demand for our products.
Oil and gas prices have been volatile since 1990. In general, oil prices approximated $18-22 per barrel from 1991 through 1997, experienced a decline into the low teens in 1998 and 1999, and have generally ranged between $25-100 per barrel since 2000. Spot gas prices generally ranged between $1.80-2.60 per mmbtu of gas from 1991 through 1999, then experienced severe spikes into the $10 range in 2001 and 2003. Absent occasional spikes and dips due to imbalances in supply and demand, prices have generally ranged between $5.00-10.00 per mmbtu during the last two years.
Expectations for future oil and gas prices cause many shifts in the strategies and expenditure levels of oil and gas companies and drilling contractors, particularly with respect to decisions to purchase major capital equipment of the type we manufacture. Oil and gas prices, which are determined by the marketplace, may fall below a range that is acceptable to our customers, which could reduce demand for our products.
Competition in our industry could ultimately lead to lower revenues and earnings.
The oilfield products and services industry is highly competitive. We compete with national, regional and foreign competitors in each of our current major product lines. These competitors may have greater financial, technical, manufacturing and marketing resources than us, and may be in a better competitive position. The following competitive actions can each affect our revenues and earnings:
•
price changes;
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new product and technology introductions; and
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improvements in availability and delivery.
In addition, certain foreign jurisdictions and government-owned petroleum companies located in some of the countries in which we operate have adopted policies or regulations which may give local nationals in these countries competitive advantages. Competition in our industry could lead to lower revenues and earnings.
We have aggressively expanded our businesses and intend to maintain an aggressive growth strategy.
We have aggressively expanded and grown our businesses during the past several years, through acquisitions and investment in internal growth. We anticipate that we will continue to pursue an aggressive growth strategy but we cannot assure you that attractive acquisitions will be available to us at reasonable prices or at all. In addition, we cannot assure you that we will successfully integrate the operations and assets of any acquired business with our own or that our management will be able to manage effectively the increased size of the Company or operate any new lines of business. Any inability on the part of management to integrate and manage acquired businesses and their assumed liabilities could adversely affect our business and financial performance. In addition, we may need to incur substantial indebtedness to finance future acquisitions. We cannot assure you that we will be able to obtain this financing on terms acceptable to us or at all. Future acquisitions may result in increased depreciation and amortization expense, increased interest expense, increased financial leverage or decreased operating income for the Company, any of which could cause our business to suffer.
Our operating results have fluctuated during recent years and these fluctuations may continue.
We have experienced fluctuations in quarterly operating results in the past. We cannot assure you that we will realize expected earnings growth or that earnings in any particular quarter will not fall short of either a prior fiscal quarter or investors’ expectations. The following factors, in addition to others not listed, may affect our quarterly operating results in the future:
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fluctuations in the oil and gas industry;
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competition;
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the ability to service the debt obligations of the Company;
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the ability to identify strategic acquisitions at reasonable prices;
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the ability to manage and control operating costs of the Company;
•
fluctuations in political and economic conditions in the United States and abroad; and
•
the ability to protect our intellectual property rights.
There are risks associated with our presence in international markets, including political or economic instability and currency restrictions.
Approximately 59% of our revenues in 2007 were derived from operations outside the United States (based on revenue destination). Our foreign operations include significant operations in Canada, Europe, the Middle East, Africa, Southeast Asia, South America and other international markets. Our revenues and operations are subject to the risks normally associated with conducting business in foreign countries, including uncertain political and economic environments, which may limit or disrupt markets, restrict the movement of funds or result in the deprivation of contract rights or the taking of property without fair compensation. Government-owned petroleum companies located in some of the countries in which we operate have adopted policies, or are subject to governmental policies, giving preference to the purchase of goods and services from companies that are majority-owned by local nationals. As a result of these policies, we may rely on joint ventures, license arrangements and other business combinations with local nationals in these countries. In addition, political considerations may disrupt the commercial relationships between us and government-owned petroleum companies.
Under broad powers granted to the President of Venezuela by the National Assembly on January 31, 2007, the Venezuelan government began asserting closer government control over its oil and gas reserves. The Company generated revenue of $69.6 million from its Venezuelan operations in 2007, and as of December 31, 2007 had a net equity investment in Venezuela of $53.7 million. These political events could adversely affect our operations in Venezuela (where we have operated for nearly 40 years) and financial results in the future.
The results of our operations are subject to market risk from changes in foreign currency exchange rates.
We earn revenues, pay expenses and incur liabilities in countries using currencies other than the U.S. dollar, including the Canadian dollar, the Euro, the British Pound and the Norwegian Kroner. Approximately 59% of our 2007 revenue was derived from sales outside the United States. Because our consolidated financial statements are presented in U.S. dollars, we must translate revenues, income and expenses into U.S. dollars at exchange rates in effect during or at the end of each reporting period. Thus, increases or decreases in the value of the U.S. dollar against other currencies in which our operations are conducted will affect our revenues and operating income. Because of the geographic diversity of our operations, weaknesses in some currencies might be offset by strengths in others over time. We also use derivative financial instruments to further reduce our net exposure to currency exchange fluctuations. We had forward contracts with a notional amount of $4,104.1 million (with a fair value of $103.0 million) as of December 31, 2007 to reduce the impact of foreign currency exchange rate movements. We are also subject to risks that the counterparties to these contracts fail to meet the terms of our foreign currency contracts. We cannot assure you that fluctuations in foreign currency exchange rates would not affect our financial results.
An impairment of goodwill could reduce our earnings.
We recorded approximately $2.4 billion of goodwill on the consolidated balance sheet as of December 31, 2007. Goodwill is recorded when the purchase price of a business exceeds the fair market value of the tangible and separately measurable intangible net assets. Generally accepted accounting principles requires us to test goodwill for impairment on an annual basis or when events or circumstances occur indicating that goodwill might be impaired. If we were to determine that any of our remaining balance of goodwill was impaired, we would record an immediate charge to earnings with a corresponding reduction in stockholders’ equity and increase in balance sheet leverage as measured by debt to total capitalization.
We could be adversely affected if we fail to comply with any of the numerous federal, state and local laws, regulations and policies that govern environmental protection, zoning and other matters applicable to our businesses.
Our businesses are subject to numerous federal, state and local laws, regulations and policies governing environmental protection, zoning and other matters. These laws and regulations have changed frequently in the past and it is reasonable to expect additional changes in the future. If existing regulatory requirements change, we may be required to make significant unanticipated capital and operating expenditures. We cannot assure you that our operations will continue to comply with future laws and regulations. Governmental authorities may seek to impose fines and penalties on us or to revoke or deny the issuance or renewal of operating permits for failure to comply with applicable laws and regulations. Under these circumstances, we might be required to reduce or cease operations or conduct site remediation or other corrective action which could adversely impact our operations and financial condition.
Our businesses expose us to potential environmental liability.
Our businesses expose us to the risk that harmful substances may escape into the environment, which could result in:
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personal injury or loss of life;
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severe damage to or destruction of property; or
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environmental damage and suspension of operations.
Our current and past activities, as well as the activities of our former divisions and subsidiaries, could result in our facing substantial environmental, regulatory and other liabilities. These could include the costs of cleanup of contaminated sites and site closure obligations. These liabilities could also be imposed on the basis of one or more of the following theories:
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negligence;
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strict liability;
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breach of contract with customers; or
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as a result of our contractual agreement to indemnify our customers in the normal course of business, which is normally the case.
We may not have adequate insurance for potential environmental liabilities.
While we maintain liability insurance, this insurance is subject to coverage limits. In addition, certain policies do not provide coverage for damages resulting from environmental contamination. We face the following risks with respect to our insurance coverage:
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we may not be able to continue to obtain insurance on commercially reasonable terms;
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we may be faced with types of liabilities that will not be covered by our insurance;
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our insurance carriers may not be able to meet their obligations under the policies; or
•
the dollar amount of any liabilities may exceed our policy limits.
Even a partially uninsured claim, if successful and of significant size, could have a material adverse effect on our consolidated financial statements.
There are risks associated with certain contracts for our drilling equipment.
As of December 31, 2007, we had a backlog of approximately $9 billion of drilling equipment to be manufactured, assembled, tested and delivered by our Rig Technology group. The following factors, in addition to others not listed, could reduce our margins on these contracts, adversely affect our position in the market and subject us to contractual penalties:
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our failure to adequately estimate costs for making this drilling equipment;
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our inability to deliver equipment that meets contracted technical requirements;
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our inability to maintain our quality standards during the design and manufacturing process;
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our inability to secure parts made by third party vendors at reasonable costs and within required timeframes;
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unexpected increases in the costs of raw materials; and
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our inability to manage unexpected delays due to weather, shipyard access, labor shortages or other factors beyond our control.
Such developments could have a material adverse effect on our consolidated financial statements.
GLOSSARY OF OILFIELD TERMS
(Sources: Company management; “A Dictionary for the Petroleum Industry,” The University of Texas at Austin, 2001.)
API
Abbr: American Petroleum Institute
Annular Blowout Preventer
A large valve, usually installed above the ram blowout preventers, that forms a seal in the annular space between the pipe and the wellbore or, if no pipe is present, in the wellbore itself.
Annulus
The open space around pipe in a wellbore through which fluids may pass.
Automatic Pipe Handling
Systems (Automatic Pipe
Racker)
A device used on a drilling rig to automatically remove and insert drill stem components from and into the hole. It replaces the need for a person to be in the derrick or mast when tripping pipe into or out of the hole.
Automatic Roughneck
A large, self-contained pipe-handling machine used by drilling crew members to make up and break out tubulars. The device combines a spinning wrench, torque wrench, and backup wrenches.
Beam pump
Surface pump that raises and lowers sucker rods continually, so as to operate a downhole pump.
Bit
The cutting or boring element used in drilling oil and gas wells. The bit consists of a cutting element and a circulating element. The cutting element is steel teeth, tungsten carbide buttons, industrial diamonds, or polycrystalline diamonds (PDCs). These teeth, buttons, or diamonds penetrate and gouge or scrape the formation to remove it. The circulating element permits the passage of drilling fluid and utilizes the hydraulic force of the fluid stream to improve drilling rates. In rotary drilling, several drill collars are joined to the bottom end of the drill pipe column, and the bit is attached to the end of the drill collars. Drill collars provide weight on the bit to keep it in firm contact with the bottom of the hole. Most bits used in rotary drilling are roller cone bits, but diamond bits are also used extensively.
Blowout
An uncontrolled flow of gas, oil or other well fluids into the atmosphere. A blowout, or gusher, occurs when formation pressure exceeds the pressure applied to it by the column of drilling fluid. A kick warns of an impending blowout.
Blowout Preventer (BOP)
Series of valves installed at the wellhead while drilling to prevent the escape of pressurized fluids.
Blowout Preventer (BOP) Stack
The assembly of well-control equipment including preventers, spools, valves, and nipples connected to the top of the wellhead.
Closed Loop Drilling Systems
A solids control system in which the drilling mud is reconditioned and recycled through the drilling process on the rig itself.
Coiled Tubing
A continuous string of flexible steel tubing, often hundreds or thousands of feet long, that is wound onto a reel, often dozens of feet in diameter. The reel is an integral part of the coiled tubing unit, which consists of several devices that ensure the tubing can be safely and efficiently inserted into the well from the surface. Because tubing can be lowered into a well without having to make up joints of tubing, running coiled tubing into the well is faster and less expensive than running conventional tubing. Rapid advances in the use of coiled tubing make it a popular way in which to run tubing into and out of a well. Also called reeled tubing.
Cuttings
Fragments of rock dislodged by the bit and brought to the surface in the drilling mud. Washed and dried cutting samples are analyzed by geologist to obtain information about the formations drilled.
Directional Well
Well drilled in an orientation other than vertical in order to access broader portions of the formation.
Drawworks
The hoisting mechanism on a drilling rig. It is essentially a large winch that spools off or takes in the drilling line and thus raises or lowers the drill stem and bit.
Drill Pipe Elevator (Elevator)
On conventional rotary rigs and top-drive rigs, hinged steel devices with manual operating handles that crew members latch onto a tool joint (or a sub). Since the elevators are directly connected to the traveling block, or to the integrated traveling block in the top drive, when the driller raises or lowers the block or the top-drive unit, the drill pipe is also raised or lowered.
Drilling jars
A percussion tool operated manually or hydraulically to deliver a heavy downward blow to free a stuck drill stem.
Drilling mud
A specially compounded liquid circulated through the wellbore during rotary drilling operations.
Drilling riser
A conduit used in offshore drilling through which the drill bit and other tools are passed from the rig on the water’s surface to the sea floor.
Drill stem
All members in the assembly used for rotary drilling from the swivel to the bit, including the Kelly, the drill pipe and tool joints, the drill collars, the stabilizers, and various specialty items.
Formation
A bed or deposit composed throughout of substantially the same kind of rock; often a lithologic unit. Each formation is given a name, frequently as a result of the study of the formation outcrop at the surface and sometimes based on fossils found in the formation.
Hardbanding
A special wear-resistant material often applied to tool joints to prevent abrasive wear to the area when the pipe is being rotated downhole.
Iron roughneck
A floor-mounted combination of a spinning wrench and a torque wrench. The Iron Roughneck moves into position hydraulically and eliminates the manual handling involved with suspended individual tools.
Jack-up rig
A mobile bottom-supported offshore drilling structure with columnar or open-truss legs that support the deck and hull. When positioned over the drilling site, the bottoms of the legs penetrate the seafloor.
Jar
A mechanical device placed near the top of the drill stem which allows the driller to strike a very heavy blow upward or downward on stuck pipe.
Joint
1) In drilling, a single length (from 16 feet to 45 feet, or 5 meters to 14.5 meters, depending on its range length) of drill pipe, drill collar, casing or tubing that has threaded connections at both ends. Several joints screwed together constitute a stand of pipe. 2) In pipelining, a single length (usually 40 feet-12 meters) of pipe. 3) In sucker rod pumping, a single length of sucker rod that has threaded connections at both ends.
Kelly
The heavy steel tubular device, four- or six-sided, suspended from the swivel through the rotary table and connected to the top joint of drill pipe to turn the drill stem as the rotary table returns. It has a bored passageway that permits fluid to be circulated into the drill stem and up the annulus, or vice versa. Kellys manufactured to API specifications are available only in four- or six-sided versions, are either 40 or 54 feet (12 to 16 meters) long, and have diameters as small as 2 1/2 inches (6 centimeters) and as large as 6 inches (15 centimeters).
Kelly bushing
A special device placed around the kelly that mates with the kelly flats and fits into the master bushing of the rotary table. The kelly bushing is designed so that the kelly is free to move up or down through it. The bottom of the bushing may be shaped to fit the opening in
the master bushing or it may have pins that fit into the master bushing. In either case, when the kelly bushing is inserted into the master bushing and the master bushing is turned, the kelly bushing also turns. Since the kelly bushing fits onto the kelly, the kelly turns, and since the kelly is made up to the drill stem, the drill stem turns. Also called the drive bushing.
Kelly spinner
A pneumatically operated device mounted on top of the kelly that, when actuated, causes the kelly to turn or spin. It is useful when the kelly or a joint of pipe attached to it must be spun up, that is, rotated rapidly for being made up.
Kick
An entry of water, gas, oil, or other formation fluid into the wellbore during drilling. It occurs because the pressure exerted by the column of drilling fluid is not great enough to overcome the pressure exerted by the fluids in the formation drilled. If prompt action is not taken to control the kick, or kill the well, a blowout may occur.
Making-up
1. To assemble and join parts to form a complete unit (e.g., to make up a string of drill pipe). 2. To screw together two threaded pieces. Compare break out. 3. To mix or prepare (e.g., to make up a tank of mud). 4. To compensate for (e.g., to make up for lost time).
Manual tongs (Tongs)
The large wrenches used for turning when making up or breaking out drill pipe, casing, tubing, or other pipe; variously called casing tongs, pipe tongs, and so forth, according to the specific use. Power tongs or power wrenches are pneumatically or hydraulically operated tools that serve to spin the pipe up tight and, in some instances to apply the final makeup torque.
Master bushing
A device that fits into the rotary table to accommodate the slips and drive the kelly bushing so that the rotating motion of the rotary table can be transmitted to the kelly. Also called rotary bushing.
Motion compensation
equipment
Any device (such as a bumper sub or heave compensator) that serves to maintain constant weight on the bit in spite of vertical motion of a floating offshore drilling rig.
Mud pump
A large, high-pressure reciprocating pump used to circulate the mud on a drilling rig.
Plug gauging
The mechanical process of ensuring that the inside threads on a piece of drill pipe comply with API standards.
Pressure control equipment
1. The act of preventing the entry of formation fluids into a wellbore. 2. The act of controlling high pressures encountered in a well.
Pressure pumping
Pumping fluids into a well by applying pressure at the surface.
Ram blowout preventer
A blowout preventer that uses rams to seal off pressure on a hole that is with or without pipe. Also called a ram preventer.
Ring gauging
The mechanical process of ensuring that the outside threads on a piece of drill pipe comply with API standards.
Riser
A pipe through which liquids travel upward.
Riser pipe
The pipe and special fitting used on floating offshore drilling rigs to established a seal between the top of the wellbore, which is on the ocean floor, and the drilling equipment located above the surface of the water. A riser pipe serves as a guide for the drill stem from the drilling vessel to the wellhead and as a conductor or drilling fluid from the well to the vessel. The riser consists of several sections of pipe and includes special devices to compensate for any movement of the drilling rig caused by waves. Also called marine riser pipe, riser joint.
Rotary table
The principal piece of equipment in the rotary table assembly; a turning device used to impart rotational power to the drill stem while permitting vertical movement of the pipe for rotary drilling. The master bushing fits inside the opening of the rotary table; it turns the kelly bushing, which permits vertical movement of the kelly while the stem is turning.
Rotating blowout
preventer (Rotating Head)
A sealing device used to close off the annular space around the kelly in drilling with pressure at the surface, usually installed above the main blowout preventers. A rotating head makes it possible to drill ahead even when there is pressure in the annulus that the weight of the drilling fluid is not overcoming; the head prevents the well from blowing out. It is used mainly in the drilling of formations that have low permeability. The rate of penetration through such formations is usually rapid.
Safety clamps
A clamp placed very tightly around a drill collar that is suspended in the rotary table by drill collar slips. Should the slips fail, the clamp is too large to go through the opening in the rotary table and therefore prevents the drill collar string from falling into the hole. Also called drill collar clamp.
Shaker
See “Shale Shaker”
Shale shaker
A piece of drilling rig equipment that uses a vibrating screen to remove cuttings from the circulating fluid in rotary drilling operations. The size of the openings in the screen should be selected carefully to be the smallest size possible to allow 100 per cent flow of the fluid. Also called a shaker.
Slim-hole completions
(Slim-hole Drilling)
Drilling in which the size of the hole is smaller than the conventional hole diameter for a given depth. This decrease in hole size enables the operator to run smaller casing, thereby lessening the cost of completion.
Slips
Wedge-shaped pieces of metal with serrated inserts (dies) or other gripping elements, such as serrated buttons, that suspend the drill pipe or drill collars in the master bushing of the rotary table when it is necessary to disconnect the drill stem from the kelly or from the top-drive unit’s drive shaft. Rotary slips fit around the drill pipe and wedge against the master bushing to support the pipe. Drill collar slips fit around a drill collar and wedge against the master bushing to support the drill collar. Power slips are pneumatically or hydraulically actuated devices that allow the crew to dispense with the manual handling of slips when making a connection.
Solids
See “Cuttings”
Spinning wrench
Air-powered or hydraulically powered wrench used to spin drill pipe in making or breaking connections.
Spinning-in
The rapid turning of the drill stem when one length of pipe is being joined to another. “Spinning-out” refers to separating the pipe.
Stand
The connected joints of pipe racked in the derrick or mast when making a trip. On a rig, the usual stand is about 90 feet (about 27 meters) long (three lengths of drill pipe screwed together), or a treble.
String
The entire length of casing, tubing, sucker rods, or drill pipe run into a hole.
Sucker rod
A special steel pumping rod. Several rods screwed together make up the link between the pumping unit on the surface and the pump at the bottom of the well.
Tensioner
A system of devices installed on a floating offshore drilling rig to maintain a constant tension on the riser pipe, despite any vertical motion made by the rig. The guidelines must also be tensioned, so a separate tensioner system is provided for them.
Thermal desorption
The process of removing drilling mud from cuttings by applying heat directly to drill cuttings.
Top drive
A device similar to a power swivel that is used in place of the rotary table to turn the drill stem. It also includes power tongs. Modern top drives combine the elevator, the tongs, the swivel, and the hook. Even though the rotary table assembly is not used to rotate the drill stem and bit, the top-drive system retains it to provide a place to set the slips to suspend the drill stem when drilling stops.
Torque wrench
Spinning wrench with a gauge for measuring the amount of torque being applied to the connection.
Trouble cost
Costs incurred as a result of unanticipated complications while drilling a well. These costs are often referred to as contingency costs during the planning phase of a well.
Well completion
1. The activities and methods of preparing a well for the production of oil and gas or for other purposes, such as injection; the method by which one or more flow paths for hydrocarbons are established between the reservoir and the surface. 2. The system of tubulars, packers, and other tools installed beneath the wellhead in the production casing; that is, the tool assembly that provides the hydrocarbon flow path or paths.
Well stimulation
Any of several operations used to increase the production of a well, such as acidizing or fracturing.
Well workover
The performance of one or more of a variety of remedial operations on a producing oilwell to try to increase production. Examples of workover jobs are deepening, plugging back, pulling and resetting liners, and squeeze cementing.
Wellbore
A borehole; the hole drilled by the bit. A wellbore may have casing in it or it may be open (uncased); or part of it may be cased, and part of it may be open. Also called a borehole or hole.
Wireline
A slender, rodlike or threadlike piece of metal usually small in diameter, that is used for lowering special tools (such as logging sondes, perforating guns, and so forth) into the well. Also called slick line.
ITEM 1B.
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.
ITEM 2.
ITEM 2. PROPERTIES
The Company owned or leased approximately 700 facilities worldwide as of December 31, 2007, including the following principal manufacturing, service, distribution and administrative facilities:
We own or lease 228 repair and manufacturing facilities that refurbish and manufacture new equipment and parts, and approximately 190 distribution service centers, and 276 service centers that provide inspection and equipment rental worldwide.
We own undeveloped acreage next to several of our facilities, including over 100 acres of undeveloped property located in Houston, Texas. Machinery, equipment, buildings, and other facilities owned and leased are considered by management to be adequately maintained and adequate for our operations.
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS
We have various claims, lawsuits and administrative proceedings that are pending or threatened, all arising in the ordinary course of business, with respect to commercial, product liability and employee matters. Although no assurance can be given with respect to the outcome of these or any other pending legal and administrative proceedings and the effect such outcomes may have, we believe any ultimate liability resulting from the outcome of such claims, lawsuits or administrative proceedings will not have a material adverse effect on our consolidated financial position, results of operations or cash flows.
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 quarter ended December 31, 2007.
PART II
ITEM 5.
ITEM 5.
MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
Market Information
Our common stock is traded on the New York Stock Exchange (NYSE) under the symbol “NOV”. The following table sets forth, for the calendar periods indicated, the range of high and low closing prices for the common stock, as reported by the NYSE. All periods reflect a two-for-one stock split effected as a 100 percent stock dividend in September 2007.
As of February 15, 2008, there were 1,889 holders of record of our common stock. Many stockholders choose to own shares through brokerage accounts and other intermediaries rather than as holders of (excluding individual participants in securities positions listing) record so the actual number of stockholders is unknown but significantly higher. We have never paid cash dividends, and none are anticipated during 2008.
On August 22, 2007, the Company’s Board of Directors approved a two-for-one stock split in the form of a stock dividend to the Company’s stockholders of record on September 7, 2007, with distribution of shares on September 28, 2007. The total number of authorized common stock shares and associated par value were unchanged by this action. All per-share amounts in the financial statements reflect the stock split for all periods presented. The effect of the common stock split is reflected on the Consolidated Balance Sheet in “Common stock” and “Additional paid-in capital.”
The information relating to our equity compensation plans required by Item 5 is incorporated by reference to such information as set forth in Item 12. “Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters” contained herein.
PERFORMANCE GRAPH
The graph below compares the cumulative total shareholder return on our common stock to the S&P 500 Index and the S&P Oil & Gas Equipment & Services Index. The total shareholder return assumes $100 invested on December 31, 2002 in National Oilwell Varco, the S&P 500 Index and the S&P Oil & Gas Equipment & Services Index. It also assumes reinvestment of all dividends. The peer group is weighted based on the market capitalization of each company. The results shown in the graph below are not necessarily indicative of future performance.
COMPARISON OF 5 YEAR CUMULATIVE TOTAL RETURN*
Among National Oilwell Varco, Inc., The S&P 500 Index
And The S&P Oil & Gas Equipment & Services Index
This information shall not be deemed to be ''soliciting material’’ or to be ''filed’’ with the Commission or subject to Regulation 14A (17 CFR 240.14a-1-240.14a-104), other than as provided in Item 201(e) of Regulation S-K, or to the liabilities of section 18 of the Exchange Act (15 U.S.C. 78r).
ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA
(1)
Financial results of Varco International, Inc. (“Varco”) have been included in our consolidated financial statements beginning March 11, 2005, the date the Varco merger was completed and Varco common shares were exchanged for our common shares. Financial information for prior periods and dates may not be comparable with 2005 due to the impact of this business combination on our financial position and results of operation. See Note 3 of the Notes to the Consolidated Financial Statements for a description of the Varco merger and related adjusted financial information. Results for the year ended December 31, 2005 include integration costs associated with the Varco merger of $31.7 million and stock-based compensation costs of $15.6 million related to the amortization expense of options assumed in the Varco merger.
ITEM 7.
ITEM 7.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
General Overview
The Company is a leading worldwide provider of highly engineered drilling and well-servicing equipment, products and services to the exploration and production segments of the oil and gas industry. With operations in approximately 700 locations across six continents, we design, manufacture and service a comprehensive line of drilling and well servicing equipment; sell and rent drilling motors, specialized downhole tools, and rig instrumentation; perform inspection and internal coating of oilfield tubular products; provide drill cuttings separation, management and disposal systems and services; provide expendables and spare parts used in conjunction with our large installed base of equipment; and provide supply chain management services through our distribution network. We also manufacture coiled tubing, provide in-service pipeline inspections, manufacture high pressure fiberglass and composite tubing, and sell and rent advanced in-line inspection equipment to makers of oil country tubular goods. We have a long tradition of pioneering innovations which improve the cost-effectiveness, efficiency, safety, and environmental impact of oil and gas operations.
Our revenues and operating results are directly related to the level of worldwide oil and gas drilling and production activities and the profitability and cash flow of oil and gas companies and drilling contractors, which in turn are affected by current and anticipated prices of oil and gas. Oil and gas prices have been and are likely to continue to be volatile. See “Risk Factors”. We conduct our operations through three business segments: Rig Technology, Petroleum Services & Supplies and Distribution Services. See Item 1. Business for a discussion of each of these business segments.
Operating Environment Overview
Our results are dependent on, among other things, the level of worldwide oil and gas drilling, well remediation activity, the price of crude oil and natural gas, capital spending by other oilfield service companies and drilling contractors, pipeline maintenance activity, and the worldwide oil and gas inventory levels. Key industry indicators for the past three years include the following:
*
Averages for the years indicated. See sources below.
The following table details the U.S., Canadian, and international rig activity and West Texas Intermediate Oil prices for the three years ended December 31, 2007 on a quarterly basis:
Source: Rig count: Baker Hughes, Inc. (www.bakerhughes.com); West Texas Intermediate Crude Price: Department of Energy, Energy Information Administration (www.eia.doe.gov).
Natural gas prices increased slightly in 2007 in comparison to 2006, and oil prices generally increased throughout 2007. The average price per barrel of West Texas Intermediate Crude reached historic heights in 2007, peaking at just over $99 in November. The 2007 average price for the year was the highest ever-annual average oil price at $72.33 per barrel, an increase of 9.6% over the average price for 2006. Natural gas prices were $6.97 per mmbtu, an increase of 3.4% compared to the 2006 average. Higher oil prices led to stronger rig activity worldwide, increasing 2.4% for the full year in 2007 compared to 2006.
At February 15, 2008, there were 1,773 rigs actively drilling in the U.S., compared to 1,782 rigs at December 28, 2007. The company believes that most current industry projections are forecasting commodity prices to remain strong, and, as a result, U.S. and international drilling rig activity is expected to continue at a high level. However, numerous events could significantly alter these projections including political tensions in the Middle East, the acceleration or deceleration of the recovery of the U.S. and world economies, a build-up in the world inventory levels, or numerous other events or circumstances.
Executive Summary
National Oilwell Varco generated earnings of $1,337.1 million or $3.76 per fully diluted share in its fiscal year ended December 31, 2007, on revenues of $9,789.0 million. Earnings per share increased 95 percent and revenue increased 39 percent from the Company’s 2006 earnings and revenues, respectively, as we experienced rising demand for our products and services through the year. Our backlog for capital equipment increased 50 percent throughout the year, despite steadily rising shipments out of backlog, due principally to growing numbers of new offshore drilling rig construction projects initiated during 2007 which placed orders with the Company.
Oil & Gas Equipment and Services Market
Oil and gas prices have increased significantly over the past five years and remain near historic highs, which have led to high levels of exploration and development drilling in many oil and gas basins around the globe. The count of rigs actively drilling during 2007 as measured by Baker Hughes (a good measure of the level of oilfield activity and spending) increased 2.4 percent from 2006, representing the fifth straight year of increasing average annual rig count. Year-to-year growth in domestic, Latin American and Eastern Hemisphere drilling activity was partly offset by Canadian activity declines. Activity in the U.S. and the Eastern Hemisphere grew modestly throughout the year, while Canada declined sharply during the second quarter, as it typically does, and remained weak throughout the second half of 2007. Latin American drilling activity was essentially flat throughout the year.
The level of drilling activity underway is the highest seen since the early 1980’s, which is fueling high demand for oilfield services. Much of the new incremental drilling activity is occurring in harsh environments, and employs increasingly sophisticated technology to find and produce reserves. Higher utilization of drilling rigs has tested the capability of the world’s fleet of rigs, much of which is old and of limited capability. Technology has advanced significantly since most of the existing rig fleet was built. The industry invested little during the late 1980’s and 1990’s on new drilling equipment, but drilling technology progressed steadily nonetheless, as the Company and its competitors continued to invest in new and better ways of drilling. As a consequence, the safety, reliability, and efficiency of new, modern rigs surpass the performance of most of the older rigs at work today.
The rise in demand for drilling rigs has driven rig dayrates higher over the past few years, which has increased cash flows and available financing to drilling contractors. Many have invested in new rigs or placed older rigs back into service. The Company has played an important role in providing both new rigs as well as the equipment, consumables and services needed to reactivate many older rigs. Oil and gas producers demand top performance from drilling rigs, particularly at the premium dayrates that are being paid today. As a result of this trend, the Company has benefited from incremental demand for new products (such as our small iron roughnecks for land rigs, our LXT BOP’s, our Safe-T-Lite pump liner systems, among others) to upgrade certain rig functions to make them safer and more efficient.
Drilling rigs are now being pushed to drill deeper wells, more complex wells, highly deviated wells and horizontal wells; tasks which require larger rigs with more capabilities. Higher dayrates magnify the opportunity cost of rig downtime, and rigs are being pushed to maximize revenue days for their drilling contractor owners. The drilling process effectively consumes the mechanical components of a rig, which wear out and need periodic repair or replacement. This process has been accelerated by very high rig utilization and wellbore complexity. Drilling consumes rigs; more complex and challenging drilling consumes rigs faster.
Changing methods of drilling have further benefited the Company’s business. Increasingly, hydraulic power - in addition to conventional mechanical rotary power - is being used to apply torque to the drill bit. This is done using downhole drilling motors powered by drilling fluids. We are a major provider of downhole drilling motors, and we have seen demand for this application of our drilling motors increase over the last few years. This trend has also increased demand for our high pressure mud pumps, which create the hydraulic power in the drilling fluid which drive the drilling motors.
While the increasingly efficient equipment provided by us has mitigated the effect, high activity levels have increased demand for personnel in the oilfield. Consequently, the Company, its customers and its suppliers have experienced wage inflation in certain markets. Hiring experienced drilling crews has been challenging for the drilling industry; however, we believe crews generally prefer working on newer, more modern rigs. Our products which save labor and increase efficiency (such as its automatic slips and pipe handling equipment) also make the rig crew’s jobs safer and easier, and make the rig a more desirable place to work.
The world is actively building nearly 170 new offshore rigs, and schedules call for 27 new drillships, 45 new semisubmersibles, and 80 new jackup rigs to be delivered into the fleet by the end of 2011. The 628 offshore rig fleet they will join is old; the average age is approximately 25 years. The existing fleet was engineered and constructed prior to many technical advancements,
and we believe that the newer rigs offer considerably higher efficiency, safety, and capability, and that many will effectively replace a portion of the existing fleet. Additionally, the large number of floating rig construction projects will add new capacity required to press exploration into new deepwater frontiers.
Land rig construction is strong, and new orders brisk, with most interest directed towards international markets where customers are adopting newer rig technologies. Our domestic land rig backlog has fallen by about half from peak 2006 levels due to lower dayrates in the U.S. as compared to early 2007; however, newer, better rigs are consistently posting meaningfully higher dayrates and utilization than older rigs in the domestic market. We believe the retooling of the U.S. land rig market will continue as favorable operator experience with higher technology rigs will continue to “pull” more of these into the marketplace.
Overall we expect to continue to sell into three important trends in the rig fleet worldwide: the secular buildout of additional deepwater capabilities, the retooling of the jackup fleet with newer, more capable rigs, and the replacement of older land rigs with improved technology.
Segment Performance
Revenues for the Rig Technology group in 2007 were $5,744.7 million, up 60 percent from 2006 group revenues of $3,584.9 million. Operating profit was $1,393.6 million or 24.3 percent of revenue in 2007, compared to $608.5 million or 17.0 percent of sales in 2006. Operating profit flow-through or leverage (the period-to-period increase in operating profit divided by the increase in revenue) was 36 percent from 2006 to 2007. The 2007 results benefited from higher new rig construction volumes, higher sales of aftermarket goods and services, rising manufacturing efficiencies and improving pricing, partly offset by higher employee and material costs.
The Company’s Rig Technology group reported a backlog of capital equipment orders totaling $9,003.5 million at December 31, 2007, up 50 percent from December 31, 2006. The group was awarded $7,080.1 million in new capital equipment orders in 2007, an increase of 18 percent over orders won in 2006. Fourth quarter 2007 orders of $2,192.1 million were the largest quarterly order level ever achieved by the group, and year-ending backlog achieved record levels as well. The Company has the capability to supply up to $50 million of equipment for a jackup rig, more than $250 million of equipment for a new floating rig, and effectively all of a new land rig (which can range in price from less than $1 million for a well service rig to over $50 million for a large harsh environment rig). Backlog for drilling equipment at December 31, 2007 was approximately 85 percent offshore and 15 percent land rig equipment. The delivery of this equipment is typically tied to the construction schedule of the rig, which can take as long as four years to complete. While substantially all of the current backlog will be delivered by the end of 2009, a portion extends out as far as 2011. Approximately 88 percent of the drilling equipment in backlog is destined for international markets.
The Company’s Rig Technology group manufacturing base relies on a combination of internal and external capabilities, and we have significantly increased the output of our manufacturing plants in response to the high demand. This has been accomplished by optimizing the manufacturing infrastructure between Varco and National Oilwell to enhance efficiency following the March 2005 merger, the rollout of Quick Response Manufacturing (QRM) and lean manufacturing techniques across a number of facilities, and a 37 percent increase in capital expenditures in the group as compared to 2006. We are also providing our vendors with longer range forecasts to assist their planning, placing longer term orders to match our backlog, and qualifying new suppliers throughout North America, Europe and Asia.
The Company’s Petroleum Services & Supplies generated $3,061.0 million in revenue in 2007, an increase of 26 percent from 2006 revenues of $2,425.0 million, due to rising demand for oilfield goods and services the group provides, the impact of acquisitions, and several international expansion initiatives launched by the group including new facilities opened in the Middle East and Far East. Additionally the group benefited from investments made in its coiled tubing and composite pipe manufacturing infrastructure last year. The group’s operating profit for the year was $731.6 million or 23.9 percent of sales, an increase from 2006 operating profit of $545.6 million or 22.5 percent of sales. The group generated 29 percent operating profit flow-through from 2006 to 2007.
Margins for the Petroleum Services & Supplies group improved in 2007 as a result of the higher volumes and better pricing, offset by higher personnel and materials costs. The strong results were broad-based, with all major product and service lines up year-over-year. Domestic and international revenues continued to grow throughout the year; however, results in Canada softened on a seasonally-adjusted basis as many of our customers in Canada reduced activity in response to lower gas prices, a stronger Canadian dollar, and higher royalty expenses in Alberta. The group’s mix of non-North American revenue rose steadily throughout the year, from 38 percent in the first quarter to 43 percent in the fourth quarter, as overseas business grew. The flattening of the rig count in the U.S., and the declining level of activity in Canada compared to the prior year, reduced overall pricing leverage in North America; however, pricing trends remain very regional and product line specific, with pricing of certain products continuing to increase.
The Company’s Distribution Services group generated revenues of $1,423.7 million in 2007, a four percent increase from 2006 revenues of $1,369.6 million. Operating profit was $94.0 million, unchanged from the prior year. Operating margins were 6.6 percent, down slightly from 2006 operating margins of 6.9 percent. The group generated no incremental operating profit flow-through in 2007, due mostly to a sharp decline in business in its Canadian operations. Revenue growth in overseas markets fully offset lower Canadian sales, but startup costs in several new international locations led to lower flow-throughs from these areas. Domestic operations posted good year-over-year growth at strong flow-throughs, but the business began to experience increasing domestic price pressure through the second half of 2007.
Strategic alliance agreements with new customers fueled much of the Distribution Services group’s international growth. Once in place the strategic alliances provide the group a stable platform of business around which it can open new locations at lower risk and cost. The group has expanded around the world by following our customers’ rigs into new regions. The group is also selling more MRO supplies internally to legacy Varco organizations, which increased our leverage through greater purchase volumes.
Outlook
We believe that the outlook for the Company for 2008 remains positive, as historically high commodity prices are expected to keep overall oil and gas activity high, and as the Company enters 2008 with a record level of backlog for capital equipment for its Rig Technology group.
Oil prices and supply remain subject to significant political risk in many international regions. The growth of China and other emerging economies has added significant demand to the oil markets, and new sources of supply continue to prove challenging to find and produce economically. The Company expects the high oil prices that have resulted to sustain high levels of oilfield activity in 2008, provided the world’s major economies remain strong, and OPEC discipline keeps oil prices high. High commodity prices, drilling activity levels, and drilling rig dayrates are expected to continue to fuel demand for the Company’s Rig Technology group. The supply of offshore rigs remains tight in many markets, and quotation activity for the Rig Technology group remains brisk. In particular, the Company expects recent deepwater lease awards and announcements of discoveries in Brazil to continue to fuel a high level of interest in floating drilling rig construction projects. Additionally, interest in new international land rigs remains very high, while domestic rig demand has stabilized.
Our outlook for the Company’s Petroleum Services & Supplies segment remains good, given continuation of high levels of drilling across the U.S., Middle East, North Africa, the Far East, Latin America and the North Sea. While Canadian activity remains slow, we believe the long term outlook there is good given the difficulties the industry has faced in meaningfully growing gas production across North America. Gas production from resource plays (coal bed methane, tight sands and shales) has increased to about 40 percent of total U.S. gas production, and is believed to exhibit higher decline rates than conventional reservoirs.
The Company’s Distribution Services segment operates in very competitive markets, but we are targeting further international expansion underpinned by new strategic alliances in 2008 to fuel additional growth. The business also continues to be challenged by weak demand in Canada.
Results of Operations
Years Ended December 31, 2007 and December 31, 2006
The following table summarizes the Company’s revenue and operating profit by operating segment in 2007 and 2006 (in millions):
Rig Technology
Rig Technology revenue for the year ended December 31, 2007 was $5,744.7 million, an increase of $2,159.8 million (60.2%) compared to 2006. The increase is due to the growing market for capital equipment, as evidenced by backlog growth, price increases implemented in 2006, and increases in spare parts and service revenue. The increase in orders and backlog resulted from increased rig construction projects and higher capital investment by drilling contractors in 2007 as compared to 2006.
Operating profit from Rig Technology was $1,393.6 million for the year ended December 31, 2007, an increase of $785.1 million (129.0%) over the same period of 2006. The increase in operating profit was largely due to the increased activity and pricing discussed above.
The Rig Technology group monitors its capital equipment backlog to plan its business. New orders are added to backlog only when we receive a firm written order for major drilling rig components or a signed contract related to a construction project. The capital equipment backlog was $9.0 billion at December 31, 2007, an increase of $3.0 billion (50.0%) over backlog of $6.0 billion at December 31, 2006. Substantially all of the current backlog will be delivered by the end of 2009.
Petroleum Services & Supplies
Revenue from Petroleum Services & Supplies was $3,061.0 million for 2007 compared to $2,425.0 million for 2006, an increase of $636.0 million (26.2%). The increase was attributable to the higher demand for all products and services offered by the segment. Downhole tools sales and rentals, drill pipe coating services, and inspection equipment sales achieved revenue increases ranging from 40% to 72%.
Operating profit from Petroleum Services & Supplies was $731.6 million for 2007 compared to $545.6 million for 2006, an increase of $186.0 million (34.1%). The increase was attributable to higher profitability across virtually all product lines, driven
by higher volumes discussed above. Operating profit dollar increases ranging from 48% to 144% were achieved from downhole tool sales and rentals, drill pipe coating services and pipeline inspections.
Distribution Services
Revenue from Distribution Services totaled $1,423.7 million, an increase of $54.1 million (4.0%) from the prior period. The number of drilling rigs actively searching for oil and gas is a key metric for this business segment. Worldwide rig count increased 2.4% in 2007 compared to 2006, with increases of 7.2% and 8.6% in the U.S. and international rig activity, offset almost entirely by a 26.8% decline in Canada rig activity. The Company’s Distribution Services segment efforts to expand in international markets along with the increasing international market activity resulted in a 22% increase in international revenue. The international revenue growth over the prior period reflects additional large contract awards, the extension of US-based contracts into the international arena, increased volume from our global alliance customers and increased export activity.
Operating income remained the same in 2007 at $94.0 million while margins decreased slightly to 6.6% of revenue in 2007 compared to 6.9% of revenue in 2006. The decrease in margin was primarily due to weak demand in Canada and resulting lower operating profit in Canada.
Unallocated expenses and eliminations
Unallocated expenses and eliminations were $174.8 million for the year ended December 31, 2007 compared to $137.0 million for 2006. The increase in operations costs was primarily due to greater inter-segment profit eliminations, an increase in employee compensation expense and greater stock-based compensation expense. The stock-based compensation expense was $43.1 million and $31.2 million for the years ended December 31, 2007 and 2006, respectively. The 2006 results also included $7.9 million of integration costs related to the 2005 merger with Varco.
Interest and financial costs
Interest and financial costs were $50.3 million for 2007 compared to $48.7 million for 2006. The increase was primarily due to unfavorable interest rate movements on the Company’s outstanding interest rate swap agreements.
Other income (expense), net
Other income (expense), net was an expense of $17.8 million and $31.3 million for the years ended December 31, 2007 and December 31, 2006, respectively. The decrease in expense was primarily due to a net foreign exchange loss which was $7.0 million for the year ended December 31, 2007, as compared to a net foreign exchange loss of $21.0 million for the year ended December 31, 2006. The 2007 foreign exchange losses were primarily due to the strengthening in Norwegian Kroner, British Pound Sterling, and Euro currencies compared to the U.S. Dollar. See Item 7A.
ITEM 7A.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
We are exposed to changes in foreign currency exchange rates and interest rates. Additional information concerning each of these matters follows:
Foreign Currency Exchange Rates
We have extensive operations in foreign countries. The net assets and liabilities of these operations are exposed to changes in foreign currency exchange rates, although such fluctuations generally do not affect income since their functional currency is typically the local currency. These operations also have net assets and liabilities not denominated in the functional currency, which exposes us to changes in foreign currency exchange rates that do impact income. During the years ended December 31, 2007, 2006 and 2005, the Company reported foreign currency gains (losses) of ($7.0) million, ($21.0) million, and $2.9 million, respectively. The gains (losses) were primarily due to exchange rate fluctuations related to monetary asset balances denominated in currencies other than the functional currency. The 2007 foreign exchange loss is primarily the result in the strengthening of the following major currencies against the U.S. dollar: British Pound - 1.9%, Canadian Dollar - 18.8%, Euro - 11.6% and the Norwegian Kroner - 13.0%. Further strengthening of these currencies against the U.S. dollar may continue to create similar losses in future periods to the extent we maintain net assets and liabilities not denominated in the functional currency of the countries using the above currencies as their functional currency.
Certain revenues in foreign countries are denominated in U.S. dollars, and therefore, changes in foreign currency exchange rates impact our earnings to the extent that costs associated with those U.S. dollar revenues are denominated in the local currency. Similarly, some of our revenues are denominated in foreign currencies, but have associated U.S. dollar costs, which also gives rise to foreign currency exchange rate exposure. In order to mitigate that risk, we may utilize foreign currency forward contracts to better match the currency of our revenues and associated costs. We do not use foreign currency forward contracts for trading or speculative purposes.
At December 31, 2007, we had entered into foreign currency forward contracts with notional amounts aggregating $1,024.2 million to hedge cash flow exposure to currency fluctuations in various foreign currencies. These exposures arise when local currency operating expenses are not in balance with local currency revenue collections. Based on quoted market prices as of December 31, 2007 and 2006 for contracts with similar terms and maturity dates, we have recorded a gain of $11.2 million and $1.0 million, respectively, to adjust these foreign currency forward contracts to their fair market value. This gain is included in other comprehensive income in the consolidated balance sheet. It is expected that $6.4 million of the gain will be reclassified into earnings within the next 12 months. At December 31, 2007, the Company has cash flow hedges in place through the first quarter of 2011. A gain from ineffectiveness of $4.6 million is included in earnings related to these foreign currency contracts as of December 31, 2007. Ineffectiveness for 2006 and 2005 was not material.
At December 31, 2007, the Company had foreign currency forward contracts with notional amounts aggregating $1,579.1 million designated and qualifying as fair value hedges to hedge exposure to currency fluctuations in various foreign currencies. Based on quoted market prices as of December 31, 2007 and 2006 for contracts with similar terms and maturity dates, we recorded a gain of $79.9 million and $25.0 million, respectively, to adjust these foreign currency forward contracts to their fair market value. This gain is offset by designated losses on the firm commitments. A loss from ineffectiveness of ($0.6) million is included in earnings related to these foreign currency contracts as of December 31, 2007. Ineffectiveness for 2006 and 2005 was not material.
At December 31, 2007, the Company had foreign currency forward contracts with notional amounts aggregating $279.2 million to offset exposures to the currency fluctuation of nonfunctional currency balance sheet accounts, primarily consisting of account receivables and account payables, and are not designated as hedges. Therefore, changes in the fair value of these contracts are recorded each period in current earnings.
At December 31, 2007, the Company had foreign currency forward contracts with notional amounts aggregating $1,221.6 million designated and qualifying as net investment hedges of our Norwegian operations. Based on market prices as of December 31, 2007 for contracts with similar terms and maturity dates, we have recorded a gain of $7.5 million, net of tax of $4.4 million to adjust these foreign contracts to their fair market value. This gain is included in other comprehensive income in the consolidated balance sheet.
The maturity of the above forward contracts by currency is (in millions):
The Company had other financial market risk sensitive instruments denominated in foreign currencies totaling $87.7 million as of December 31, 2007 excluding trade receivables and payables, which approximate fair value. These market risk sensitive instruments consisted of cash balances and overdraft facilities. The Company estimates that a hypothetical 10% movement of all applicable foreign currency exchange rates on these financial market risk sensitive instruments could affect net income by $5.7 million.
The counterparties to forward contracts are major financial institutions. The credit ratings and concentration of risk of these financial institutions are monitored on a continuing basis. In the unlikely event that the counterparties fail to meet the terms of a foreign currency contract, our exposure is limited to the foreign currency rate differential.
We assess the functional currencies of our operating units to ensure that the appropriate currencies are utilized in accordance with the guidance of SFAS No. 52, Foreign Currency Translation. Effective January 1, 2008, we changed the functional currency of our Rig Technology unit in Norway from the Norwegian Kroner to the U.S. dollar to more appropriately reflect the primary economic environment in which they operate. This change was precipitated by significant changes in the economic facts and circumstances, including: the increased order rate for large drilling platforms and components technology, the use of our Norway unit as our preferred project manager of these projects, increasing revenue and cost base in U.S. dollars, and the implementation of an international cash pool. As a Norwegian Kroner functional unit, Norway was subject to increasing foreign currency exchange risk as a result of these changes in its economic environment and was dependent upon significant hedging transactions to offset its non-functional currency positions. At December 31, 2007, our Norway operations had derivatives with $2,550.5 million in notional value with a fair value of $91.3 million as compared to $1,394.6 million and $48.5 million at December 31, 2006, respectively, to mitigate foreign currency exchange risk against the U.S. dollar, our reporting currency. Effective with the change in the functional currency, the Company terminated these hedges. The related net position of $108.8 million associated with the terminated hedges will be recognized into earnings in the future periods the forecasted transactions affect earnings. The Company has subsequent to January 1, 2008, entered into new hedges to cover the exposures as a result of the changes to U.S. dollar functional.
Interest Rate Risk
At December 31, 2007, our long term borrowings consisted of $100 million in 7.5% Senior Notes, $150 million in 6.5% Senior Notes, $200 million in 7.25% Senior Notes, $200 million in 5.65% Senior Notes and $150 million in 5.5% Senior Notes. We had $90.7 million of other borrowings at December 31, 2007. We occasionally have borrowings under our other credit facilities, and a portion of these borrowings could be denominated in multiple currencies which could expose us to market risk with exchange rate movements. These instruments carry interest at a pre-agreed upon percentage point spread from either LIBOR, NIBOR or EURIBOR, or at the prime interest rate. Under our credit facilities, we may, at our option, fix the interest rate for certain borrowings based on a spread over LIBOR, NIBOR or EURIBOR for 30 days to 6 months. Our objective is to maintain a portion of our debt in variable rate borrowings for the flexibility obtained regarding early repayment without penalties and lower overall cost as compared with fixed-rate borrowings.
As of December 31, 2007, we had three interest rate swap agreements with an aggregate notional amount of $100 million associated with our 2008 Senior Notes. Under this agreement, we receive interest at a fixed rate of 7.5% and pay interest at a floating rate of six-month LIBOR plus a weighted average spread of approximately 4.675%. The swap agreements will settle semi-annually and will terminate in February 2008. The swap agreements originally entered into by Varco were recorded at their fair market value at the date of the Merger and no longer qualify as effective hedges under FAS 133. The swaps have been marked-to-market for periods subsequent to the Merger and any change in their value has been reported as an adjustment to interest expense. The change in the fair market value of the interest swap agreements resulted in a $0.3 million decrease in interest expense for the period ended December 31, 2007.
ITEM 8.
ITEM 8.
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Attached hereto and a part of this report are financial statements and supplementary data listed in Item 15.
ITEM 9.
ITEM 9.
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE.
None.
ITEM 9A.
ITEM 10.
DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
Incorporated by reference to the definitive Proxy Statement for the 2008 Annual Meeting of Stockholders.
Incorporated by reference to the definitive Proxy Statement for the 2008 Annual Meeting of Stockholders.
ITEM 12.
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
Incorporated by reference to the definitive Proxy Statement for the 2008 Annual Meeting of Stockholders.
Securities Authorized for Issuance Under Equity Compensation Plans
The following table sets forth information as of our fiscal year ended December 31, 2007, with respect to compensation plans under which our common stock may be issued:
(1)
Shares could be issued other than upon the exercise of stock options, warrants or rights; however, none are anticipated during 2008.
ITEM 13.
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
Incorporated by reference to the definitive Proxy Statement for the 2008 Annual Meeting of Stockholders.
ITEM 14.
PRINCIPAL ACCOUNTANT FEES AND SERVICES
Incorporated by reference to the definitive Proxy Statement for the 2008 Annual Meeting of Stockholders.
PART IV
ITEM 15.
EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
Financial Statements and Exhibits
(1)
Financial Statements
The following financial statements are presented in response to Part II, Item 8:
Page
Consolidated Balance Sheets
Consolidated Statements of Income
Consolidated Statements of Cash Flows
Consolidated Statements of Stockholders’ Equity and Comprehensive Income
Notes to Consolidated Financial Statements
(2)
Financial Statement Schedule
Schedule II - Valuation and Qualifying Accounts
All schedules, other than Schedule II, are omitted because they are not applicable, not required or the information is included in the financial statements or notes thereto.
2.1
Amended and Restated Agreement and Plan of Merger, effective as of August 11, between National-Oilwell, Inc. and Varco International, Inc. (4).
2.2
Agreement and Plan of Merger, effective as of December 16, 2007, between National Oilwell Varco, Inc., NOV Sub, Inc., and Grant Prideco, Inc. (9)
3.1
Amended and Restated Certificate of Incorporation of National-Oilwell, Inc. (Exhibit 3.1) (1).
3.2
Amended and Restated By-laws of National Oilwell Varco, Inc. (Exhibit 3.1) (10).
10.1
Employment Agreement dated as of January 1, 2002 between Merrill A. Miller, Jr. and National Oilwell. (Exhibit 10.1) (2).
10.2
Employment Agreement dated as of January 1, 2002 between Dwight W. Rettig and National Oilwell, with similar agreement with Mark A. Reese. (Exhibit 10.2) (2).
10.3
Form of Amended and Restated Executive Agreement of Clay C. Williams. (Exhibit 10.12) (3).
10.4
National Oilwell Varco Long-Term Incentive Plan (5)*.
10.5
Form of Employee Stock Option Agreement (Exhibit 10.1) (7)
10.6
Form of Non-Employee Director Stock Option Agreement (Exhibit 10.2) (7).
10.7
Amended and Restated Credit Agreement, dated as of June 21, 2005, among National Oilwell Varco, Inc., the financial institutions signatory thereto, including Wells Fargo Bank, National Association, in their capacities as lenders thereunder, as US administrative agent for the lenders, as Lead Arranger and Sole Book Runner, DnB NOR Bank ASA, as Norwegian Administrative Agent, DnB NOR Bank ASA and the Bank of Nova Scotia as Co-Documentation Agents, and Comerica Bank and JPMorgan Chase Bank, N.A. as Co-Syndication Agents. (Exhibit 10.1) (6).
10.8
Form of Performance-Based Restricted Stock (18 Month) Agreement (Exhibit 10.1) (8).
10.9
Form of Performance-Based Restricted Stock (36 Month) Agreement (Exhibit 10.2) (8).
21.1
Subsidiaries of the Registrant
23.1
Consent of Ernst & Young LLP
24.1
Power of Attorney (included on signature page hereto).
31.1
Certification pursuant to Rule 13a-14a and Rule 15d-14(a) of the Securities and Exchange Act, as amended
31.2
Certification pursuant to Rule 13a-14a and Rule 15d-14(a) of the Securities and Exchange Act, as amended
32.1
Certification pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2
Certification pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
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.
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
Each person whose signature appears below in so signing, constitutes and appoints Merrill A. Miller, Jr. and Clay C. Williams, and each of them acting alone, his true and lawful attorney-in-fact and agent, with full power of substitution, for him and in his name, place and stead, in any and all capacities, to execute and cause to be filed with the Securities and Exchange Commission any and all amendments to this report, and in each case to file the same, with all exhibits thereto and other documents in connection therewith, and hereby ratifies and confirms all that said attorney-in-fact or his substitute or substitutes may do or cause to be done by virtue hereof.
MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
National Oilwell Varco, Inc.’s management is responsible for establishing and maintaining adequate internal control over financial reporting. National Oilwell Varco, Inc.’s internal control system was designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.
Internal control over financial reporting cannot provide absolute assurance of achieving financial reporting objectives because of its inherent limitations. Internal control over financial reporting is a process that involves human diligence and compliance and is subject to lapses in judgment and breakdowns resulting from human failures. Internal control over financial reporting also can be circumvented by collusion or improper management override. Because of such limitations, there is a risk that material misstatements may not be prevented or detected on a timely basis by internal control over financial reporting. However, these inherent limitations are known features of the financial reporting process. Therefore, it is possible to design into the process safeguards to reduce, though not eliminate, this risk.
Management has used the framework set forth in the report entitled “Internal Control-Integrated Framework” published by the Committee of Sponsoring Organizations (“COSO”) of the Treadway Commission to evaluate the effectiveness of the Company’s internal control over financial reporting. Management has concluded that the Company’s internal control over financial reporting was effective as of December 31, 2007.
The effectiveness of our internal control over financial reporting as of December 31, 2007, has been audited by Ernst & Young LLP, the independent registered public accounting firm who also has audited the Company’s consolidated financial statements included in this Annual Report on Form 10-K.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors and Stockholders
National Oilwell Varco, Inc.
We have audited the accompanying consolidated balance sheets of National Oilwell Varco, Inc. as of December 31, 2007 and 2006 and the related consolidated statements of income, stockholders’ equity and comprehensive income, and cash flows for each of the three years in the period ended December 31, 2007. Our audits also included the financial statement schedule listed in the index at Item 15(a). These financial statements and schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and schedule based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the consolidated financial position of National Oilwell Varco, Inc. at December 31, 2007 and 2006, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2007, in conformity with U.S generally accepted accounting principles. Also, in our opinion, the related financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein.
As discussed in Note 14 to the consolidated financial statements, effective January 1, 2007, the Company adopted FASB Interpretations - FIN 48: Accounting for Uncertainty in Income Taxes an Interpretation of FASB Statement No. 109 and, as discussed in Note 2 to the consolidated financial statements, effective January 1, 2006, the Company adopted Statement of Financial Accounting Standards No. 123 (revised 2004), Share Based Payment, and, as discussed in Note 10, effective December 31, 2006 the Company adopted Statement of Financial Accounting Standards No. 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans, an amendment of FASB Statements No. 87, 88, 106, and 132(R).
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), National Oilwell Varco, Inc.’s internal control over financial reporting as of December 31, 2007, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 28, 2008 expressed an unqualified opinion thereon.
/s/ ERNST & YOUNG LLP
Houston, Texas
February 28, 2008
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors and Stockholders
National Oilwell Varco, Inc.
We have audited National Oilwell Varco, Inc.’s internal control over financial reporting as of December 31, 2007, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). National Oilwell Varco, Inc.’s management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the company’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, National Oilwell Varco, Inc. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2007 based on the COSO criteria.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of National Oilwell Varco, Inc. as of December 31, 2007 and 2006 and the related consolidated statements of income, stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2007, and our report dated February 28, 2008 expressed an unqualified opinion thereon.
/s/ ERNST & YOUNG LLP
Houston, Texas
February 28, 2008
NATIONAL OILWELL VARCO, INC.
CONSOLIDATED BALANCE SHEETS
(In millions, except share data)
The accompanying notes are an integral part of these statements.
NATIONAL OILWELL VARCO, INC.
CONSOLIDATED STATEMENTS OF INCOME
(In millions, except per share data)
The accompanying notes are an integral part of these statements.
NATIONAL OILWELL VARCO, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In millions)
The accompanying notes are an integral part of these statements.
NATIONAL OILWELL VARCO, INC.
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY AND COMPREHENSIVE INCOME
(In millions)
The accompanying notes are an integral part of these statements.
NATIONAL OILWELL VARCO, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. Organization and Basis of Presentation
Nature of Business
We design, construct, manufacture and sell comprehensive systems, components, and products used in oil and gas drilling and production, provide oilfield services and supplies, and distribute products and provide supply chain integration services to the upstream oil and gas industry. Our revenues and operating results are directly related to the level of worldwide oil and gas drilling and production activities and the profitability and cash flow of oil and gas companies, drilling contractors and oilfield service companies, which in turn are affected by current and anticipated prices of oil and gas. Oil and gas prices have been and are likely to continue to be volatile.
Basis of Consolidation
The accompanying consolidated financial statements include the accounts of National Oilwell Varco, Inc. and its majority-owned subsidiaries. All significant intercompany transactions and balances have been eliminated in consolidation. Investments that are not wholly-owned, but where we exercise control, are fully consolidated with the equity held by minority owners and their portion of net income (loss) reflected as minority interest in the accompanying consolidated financial statements. Investments in unconsolidated affiliates, over which we exercise significant influence, but not control, are accounted for by the equity method. Investments in which we exercise no control or significant influence would be accounted for under the cost method. Certain reclassifications have been made to the 2006 and 2005 consolidated financial statements in order for them to conform with the 2007 presentation.
2. Summary of Significant Accounting Policies
Fair Value of Financial Instruments
The carrying amounts of financial instruments including cash and cash equivalents, receivables, and payables approximated fair value because of the relatively short maturity of these instruments. Cash equivalents include only those investments having a maturity date of three months or less at the time of purchase. The carrying values of other financial instruments approximate their respective fair values.
Derivative Financial Instruments
We record all derivative financial instruments at their fair value in our consolidated balance sheet. Except for certain balance sheet hedges and interest rate swap agreements discussed below, all derivative financial instruments we hold are designated as either cash flow or fair value hedges and are highly effective in offsetting movements in the underlying risks. Accordingly, gains and losses from changes in the fair value of designated derivative financial instruments are deferred and recognized in earnings as revenues or costs of sales as the underlying transactions occur. Any ineffective portion of the change in the fair value is recorded in earnings as incurred.
We use foreign currency forward contracts to mitigate our exposure to changes in foreign currency exchange rates on recognized nonfunctional currency monetary accounts, forecasted transactions and firm sale and purchase commitments to better match the local currency cost components of non-functional currency transactions. Such arrangements typically have terms between two and 24 months, but may have longer terms depending on the project and our backlog. We may also use interest rate contracts to mitigate our exposure to changes in interest rates on anticipated long-term debt issuances. We do not use derivative financial instruments for trading or speculative purposes.
At December 31, 2007, we had entered into foreign currency forward contracts with notional amounts aggregating $1,024.2 million designated and qualifying as cash flow hedges to hedge exposure to currency fluctuations in various foreign currencies. These exposures arise when local currency operating expenses are not in balance with local currency revenue collections. Based on quoted market prices as of December 31, 2007 for contracts with similar terms and maturity dates, we have recorded a gain of $11.2 million, net of tax of $4.0 million, to adjust these foreign currency forward contracts to their fair market value. This gain is included in other comprehensive income in the consolidated balance sheet. It is expected that $6.4 million of this gain will be reclassified into earnings within the next 12 months. At December 31, 2007, the Company has cash flow hedges in place through the first quarter of 2011. A gain from ineffectiveness of $4.6 million is included in earnings related to these foreign currency contracts for the year ending December 31, 2007. Ineffectiveness for 2006 and 2005 was not material.
At December 31, 2007, the Company had foreign currency forward contracts with notional amounts aggregating $1,579.1 million designated and qualifying as fair value hedges to hedge exposure to currency fluctuations in various foreign currencies. Based on quoted market prices as of December 31, 2007 for contracts with similar terms and maturity dates, we recorded a gain of $79.9 million to adjust these foreign currency forward contracts to their fair market value. This gain offsets designated losses on firm commitments. At December 31, 2007, the Company has fair value hedges in place through the first quarter of 2011. A loss from ineffectiveness of ($0.6) million is included in earnings related to these foreign currency contracts for the year ending December 31, 2007. Ineffectiveness for 2006 and 2005 was not material.
At December 31, 2007, the Company had foreign currency forward contracts with notional amounts aggregating $279.2 million to offset exposures to currency fluctuation of nonfunctional currency balance sheet accounts, primarily consisting of accounts receivable and accounts payable and are not designated as hedges. Therefore, changes in the fair value of these contracts are recorded each period in current earnings.
At December 31, 2007, the Company had foreign currency forward contracts with notional amounts aggregating $1,221.6 million designated and qualifying as net investment hedges of our Norwegian operations. Based on market prices as of December 31, 2007 for contracts with similar terms and maturity dates, we have recorded a gain of $7.5 million, net of tax of $4.4 million to adjust these foreign contracts to their fair market value. This gain is included in other comprehensive income in the consolidated balance sheet and was settled in 2008.
We assess the functional currencies of our operating units to ensure that the appropriate currencies are utilized in accordance with the guidance of SFAS No. 52, Foreign Currency Translation. Effective January 1, 2008, we changed the functional currency of our Rig Technology unit in Norway from the Norwegian Kroner to the U.S. dollar to more appropriately reflect the primary economic environment in which they operate. This change was precipitated by significant changes in the economic facts and circumstances including, the increased order rate for large drilling platforms and components technology, the use of our Norway unit as our preferred project manager of these projects, increasing revenue and cost base in U.S. dollars, and the implementation of an international cash pool. As a Norwegian Kroner functional unit, Norway was subject to increasing foreign currency exchange risk as a result of these changes in its economic environment and was dependent upon significant hedging transactions to offset its non-functional currency positions. At December 31, 2007, our Norway operations had derivatives with $2,550.5 million in notional value with a fair value of $91.3 million as compared to $1,394.6 million and $48.5 million at December 31, 2006, respectively, to mitigate foreign currency exchange risk against the U.S. dollar, our reporting currency. Effective with the change in the functional currency the Company terminated these hedges, the related net position of $108.8 million associated with the terminated hedges will be recognized into earnings in the future period(s) the forecasted transactions affect earnings.
Inventories
Inventories consist of raw materials, work-in-process and oilfield and industrial finished products, manufactured equipment and spare parts. Inventories are stated at the lower of cost or market using the first-in, first-out or average cost methods. Allowances for excess and obsolete inventories are determined based on our historical usage of inventory on-hand as well as our future expectations related to our installed base and the development of new products. The allowance, which totaled $99.3 million and $86.1 million at December 31, 2007 and 2006, is the amount necessary to reduce the cost of the inventory to its estimated realizable value.
Property, Plant and Equipment
Property, plant and equipment are recorded at cost. Expenditures for major improvements that extend the lives of property and equipment are capitalized while minor replacements, maintenance and repairs are charged to operations as incurred. Disposals are removed at cost less accumulated depreciation with any resulting gain or loss reflected in operations. Depreciation is provided using the straight-line method over the estimated useful lives of individual items. Depreciation expense was $153.1 million, $119.2 million and $83.0 million for the years ended December 31, 2007, 2006 and 2005. The estimated useful lives of the major classes of property, plant and equipment are included in Note 6 to the consolidated financial statements.
Long-lived Assets
We record impairment losses on long-lived assets used in operations when events and circumstances indicate that the assets might be impaired and the undiscounted cash flows estimated to be generated by those assets are less than the carrying amount of those assets. The carrying value of assets used in operations that is not recoverable is reduced to fair value if lower than carrying value. In determining the fair market value of the assets, we consider market trends and recent transactions involving sales of similar assets, or when not available, discounted cash flow analysis.
Intangible Assets
On at least an annual basis, we assess whether goodwill is impaired. Our annual impairment tests are performed at the beginning of the fourth quarter of each year and have indicated no impairment. If we determine that goodwill is impaired, we measure that impairment based on the amount by which the book value of goodwill exceeds its implied fair value. The implied fair value of goodwill is determined by deducting the fair value of a reporting unit’s identifiable assets and liabilities from the fair value of that reporting unit as a whole. Additional impairment assessments may be performed on an interim basis if we encounter events or changes in circumstances that would indicate that, more likely than not, the carrying amount of goodwill has been impaired. Fair value of the reporting units is determined based on internal management estimates using a combination of three methods: discounted cash flows, comparable companies and representative transactions.
Goodwill is identified by segment as follows (in millions):
During 2006 we recorded adjustments reducing goodwill by $22.1 million related to the finalization of Varco purchase accounting.
Identified intangible assets with determinable lives consist primarily of customer relationships, trademarks, trade names, patents, and technical drawings acquired in acquisitions, and are being amortized on a straight-line basis over the estimated useful lives of 2-30 years. Amortization expense of identified intangibles is expected to be approximately $60 million in each of the next five years.
Identified intangible assets are identified by segment as follows (in millions):
Identified intangible assets by major classification consist of the following (in millions):
Foreign Currency
The functional currency for most of our foreign operations is the local currency. The cumulative effects of translating the balance sheet accounts from the functional currency into the U.S. dollar at current exchange rates are included in accumulated other comprehensive income. Revenues and expenses are translated at average exchange rates in effect during the period. Certain other foreign operations use the U.S. dollar as the functional currency. Accordingly, financial statements of these foreign subsidiaries are remeasured to U.S. dollars for consolidation purposes using current rates of exchange for monetary assets and liabilities and historical rates of exchange for nonmonetary assets and related elements of expense. Revenue and expense elements are remeasured at rates that approximate the rates in effect on the transaction dates. For all operations, gains or losses from remeasuring foreign currency transactions into the functional currency are included in income. Net foreign currency transaction gains (losses) were ($7.0) million, ($21.0) million and $2.9 million for the years ending December 31, 2007, 2006 and 2005, respectively, and are included in other income (expense) in the accompanying statement of operations.
As previously discussed, effective January 1, 2008, we changed the functional currency of our Rig Technology unit in Norway from the Norwegian Kroner to the U.S. dollar to more appropriately reflect the primary economic environment in which they currently operate.
Revenue Recognition
The Company’s products and services are sold based upon purchase orders or contracts with the customer that include fixed or determinable prices and that do not generally include right of return or other similar provisions or other significant post delivery obligations. Except for certain construction contracts described below, the Company records revenue at the time its manufacturing process is complete, the customer has been provided with all proper inspection and other required documentation, title and risk of loss has passed to the customer, collectibility is reasonably assured and the product has been delivered. Customer advances or deposits are deferred and recognized as revenue when the Company has completed all of its performance obligations related to the sale. The Company also recognizes revenue as services are performed. The amounts billed for shipping and handling cost are included in revenue and related costs are included in costs of sales.
Revenue Recognition under Long-term Construction Contracts
The Company uses the percentage-of-completion method to account for certain long-term construction contracts in the Rig Technology group. These long-term construction contracts include the following characteristics:
•
the contracts include custom designs for customer specific applications;
•
the structural design is unique and requires significant engineering efforts; and
•
construction projects often have progress payments.
This method requires the Company to make estimates regarding the total costs of the project, progress against the project schedule and the estimated completion date, all of which impact the amount of revenue and gross margin the Company recognizes in each reporting period. The Company prepares detailed cost estimates at the beginning of each project. Significant projects and their related costs and profit margins are updated and reviewed at least quarterly by senior management. Factors that
may affect future project costs and margins include shipyard access, weather, production efficiencies, availability and costs of labor, materials and subcomponents and other factors. These factors can impact the accuracy of the Company’s estimates and materially impact the Company’s current and future reported earnings.
The asset, “Costs in excess of billings,” represents revenues recognized in excess of amounts billed. The liability, “Billings in excess of costs,” represents billings in excess of revenues recognized.
Service and Product Warranties
The Company provides service and warranty policies on certain of its products. The Company accrues liabilities under service and warranty policies based upon specific claims and a review of historical warranty and service claim experience in accordance with SFAS 5. Adjustments are made to accruals as claim data and historical experience change. In addition, the Company incurs discretionary costs to service its products in connection with product performance issues and accrues for them when they are encountered.
The changes in the carrying amount of service and product warranties are as follows (in millions):
Income Taxes
The liability method is used to account for income taxes. Deferred tax assets and liabilities are determined based on differences between the financial reporting and tax bases of assets and liabilities and are measured using the enacted tax rates that will be in effect when the differences are expected to reverse. Valuation allowances are established when necessary to reduce deferred tax assets to amounts which are more likely than not to be realized.
Concentration of Credit Risk
We grant credit to our customers, which operate primarily in the oil and gas industry. Concentrations of credit risk are limited because we have a large number of geographically diverse customers, thus spreading trade credit risk. We control credit risk through credit evaluations, credit limits and monitoring procedures. We perform periodic credit evaluations of our customers’ financial condition and generally do not require collateral, but may require letters of credit for certain international sales. Credit losses are provided for in the financial statements. Allowances for doubtful accounts are determined based on a continuous process of assessing the Company’s portfolio on an individual customer and overall basis. This process consists of a thorough review of historical collection experience, current aging status of the customer accounts, and financial condition of the Company’s customers. Based on a review of these factors, the Company will establish or adjust allowances for specific customers and the accounts receivable portfolio as a whole. Accounts receivable are net of allowances for doubtful accounts of approximately $44.8 million and $30.4 million at December 31, 2007 and 2006, respectively.
Stock-Based Compensation
Prior to January 1, 2006, the Company accounted for its stock option plans using the intrinsic value method of accounting provided under APB Opinion No. 25, “Accounting for Stock Issued to Employees,” (“APB 25”) and related interpretations, as permitted by FASB Statement No. 123, “Accounting for Stock-Based Compensation,” (“SFAS 123”) under which no compensation expense was recognized for stock option grants. Stock-based compensation was a pro forma disclosure in the financial statement footnotes and continues to be for periods prior to January 1, 2006.
Effective January 1, 2006, the Company adopted the fair value recognition provisions of FASB Statement No. 123(R), “Share-Based Payment,” (“SFAS 123(R)”) using the modified-prospective transition method. Under this transition method, compensation cost recognized in 2007 includes: a) compensation cost for all share-based payments granted prior to January 1, 2007, but for which the requisite service period had not been completed as of January 1, 2007 based on the grant date fair value estimated in accordance with the original provisions of SFAS 123, and b) compensation cost for all share-based payments granted subsequent to January 1, 2007 based on the grant date fair value estimated in accordance with the provisions of SFAS 123(R).
Prior to the adoption of SFAS 123(R), the Company presented all tax benefits of deductions resulting from the exercise of options as operating cash flows in the Statement of Consolidated Cash Flows. SFAS 123(R) requires the cash flows resulting from tax deductions in excess of the compensation cost recognized for those options (excess tax benefits) to be classified as financing cash flows.
The Company provides compensation benefits to employees and non-employee directors under share-based payment arrangements, including various employee stock option plans.
Total compensation cost that has been charged against income for all share-based compensation arrangements was $43.1 million and $31.2 million for 2007 and 2006, respectively. The total income tax benefit recognized in the income statement for all share-based compensation arrangements was $13.2 million and $8.6 million for 2007 and 2006, respectively.
Pro Forma Net Income
The following table provides pro forma net income and income per share had the Company applied the fair value method of SFAS 123(R) for the year ended December 31, 2005 (in millions, except per share data):
Environmental Liabilities
When environmental assessments or remediations are probable and the costs can be reasonably estimated, remediation liabilities are recorded on an undiscounted basis and are adjusted as further information develops or circumstances change.
Use of Estimates
The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect reported and contingent amounts of assets and liabilities as of the date of the financial statements and reported amounts of revenues and expenses during the reporting period. Such estimates include but are not limited to, estimated losses on accounts receivable, estimated realizable value on excess and obsolete inventory, contingencies, estimated liabilities for litigation exposures and liquidated damages, estimated warranty costs, estimates related to
pension accounting, and estimates related to deferred tax assets and liabilities, including valuation allowances on deferred tax assets. Actual results could differ from those estimates.
Contingencies
The Company accrues for costs relating to litigation claims and other contingent matters, including liquidated damage liabilities, when such liabilities become probable and reasonably estimable. Such estimates may be based on advice from third parties or on management’s judgment, as appropriate. Revisions to contingent liability reserves are reflected in income in the period in which different facts or information become known or circumstances change that affect the Company’s previous assumptions with respect to the likelihood or amount of loss. Amounts paid upon the ultimate resolution of contingent liabilities may be materially different from previous estimates and could require adjustments to the estimated reserves to be recognized in the period such new information becomes known.
Net Income Per Share
The following table sets forth the computation of weighted average basic and diluted shares outstanding (in millions, except per share data):
In addition, we had stock options outstanding that were anti-dilutive totaling 0.1 million at December 31, 2007, 4.6 million at December 31, 2006 and nil at December 31, 2005.
Recently Issued Accounting Standards
In September 2006, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 157, “Fair Value Measurements” (“SFAS 157”). SFAS 157 establishes a framework for fair value measurements in the financial statements by providing a single definition of fair value, provides guidance on the methods used to estimate fair value and increases disclosures about estimates of fair value. SFAS 157 is effective for fiscal years beginning after November 15, 2007. We are currently evaluating the effect, if any, SFAS 157 will have on our financial disclosures as well as our consolidated financial position, cash flows, and results from operations.
In September 2006, the FASB issued SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans - An amendment of FASB Statements No. 87, 88, 106, and 132(R)” (“SFAS 158”). SFAS 158 requires employers to recognize the overfunded or underfunded status of a defined benefit postretirement plan as an asset or liability in its statement of financial position and to recognize changes in that funded status in the year in which the changes occur through comprehensive income of a business entity for fiscal years ending after December 15, 2006. The requirement to measure plan assets and benefit obligations as of the end of the employer’s fiscal year is effective for fiscal years ending after December 15, 2008. The Company adopted the provisions of SFAS 158 recognizing the overfunded or underfunded status of a defined benefit postretirement plan as an asset or liability in the statement of financial position and recognized changes in the funded status in the year in which they occurred through comprehensive income effective December 31, 2006 with no material impact on the Consolidated Financial Statements. We did not elect early adoption of the requirement to measure plan assets and benefit obligations as of our fiscal year end. See Note 10 of the Notes to the Consolidated Financial Statements.
In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities” (“SFAS 159”). SFAS 159 provides entities with an option to measure many financial assets and liabilities and certain other items at fair value as determined on an instrument by instrument basis. The Company has not yet evaluated the impact, if any, this standard might have on the Company’s consolidated financial statements once it becomes effective on January 1, 2008.
In December 2007, the FASB issued SFAS No. 141R, “Business Combinations” (“SFAS 141R”). SFAS 141R provides revised guidance on how acquirers recognize and measure the consideration transferred, identifiable assets acquired, liabilities assumed, noncontrolling interests, and goodwill acquired in a business combination. SFAS 141R also expands required disclosures surrounding the nature and financial effects of business combinations. SFAS 141R is effective, on a prospective basis, for fiscal years beginning after December 15, 2008. The Company does expect that this new standard will impact certain aspects of its accounting for business combinations on a prospective basis, including the determination of fair values assigned to certain purchased assets and liabilities.
In December 2007, the FASB issued SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements” (“SFAS 160”). SFAS 160 establishes requirements for ownership interests in subsidiaries held by parties other than the Company (previously called minority interests) be clearly identified, presented, and disclosed in the consolidated statement of financial position within equity, but separate from the parent’s equity. All changes in the parent’s ownership interests are required to be accounted for consistently as equity transactions and any noncontrolling equity investments in deconsolidated subsidiaries must be measured initially at fair value. SFAS 160 is effective, on a prospective basis, for fiscal years beginning after December 15, 2008. However, presentation and disclosure requirements must be retrospectively applied to comparative financial statements. The Company is currently assessing the impact of SFAS 160 on its consolidated financial position and results of operations.
3. Varco Merger
All share quantities, share ratios, share prices and Black-Scholes assumptions in this footnote are historical and have not been adjusted to reflect the Company’s two-for-one stock split effected as a 100 percent stock dividend in September 2007, unless otherwise noted.
Pursuant to our Amended and Restated Agreement and Plan of Merger with Varco International, Inc. (“Varco”), a Delaware corporation, effective as of August 11, 2004 (the “Agreement Date”), we issued 0.8363 shares of National Oilwell common stock for each Varco common share on March 11, 2005 (the “Merger”) and changed our name to National Oilwell Varco, Inc. We have included the financial results of Varco in our consolidated financial statements beginning March 11, 2005 (the “Merger Date”), the date Varco common shares were exchanged for National Oilwell common shares.
The Merger has been accounted for as a purchase business combination. Assets acquired and liabilities assumed were recorded at their fair values as of March 11, 2005. The total purchase price is $2,579.3 million, including the fair value of Varco stock options assumed and merger related transaction costs, and is comprised of (in millions):
The fair value of shares issued was determined using an average price of $29.99, which represented the average closing price of our common stock from five trading days before to five trading days after the Agreement Date. The fair value of options assumed was calculated using the Black-Scholes valuation model with the following assumptions as of the Merger Date: expected life from vest date ranging from 0.64 years to 3.6 years, risk-free interest rate of 2.0% - 3.1%, expected volatility of 34% to 47% and no dividend yield. In accordance with our Agreement and Plan of Merger, the number of Varco options exchanged was determined by multiplying the number of Varco options outstanding at closing by 0.8363. Approximately 2.2 million of the 4.0 million Varco options outstanding were fully vested as of the Merger. The portion of the intrinsic value of unvested Varco options related to future service has been allocated to unearned compensation cost and is being amortized using the remaining vesting period of 2.3 years. Stock-based compensation expense of $15.6 million related to the amortization of the unvested options was recognized in the year ended December 31, 2005. The $16.5 million of unearned stock-based compensation on the company’s balance sheet at December 31, 2005 was reclassified to paid-in-capital upon the adoption of SFAS 123(R).
Merger related transaction costs include severance and other external costs directly related to the Merger.
Integration costs of $31.7 million in 2005 were comprised of $11.9 million for severance cost, $11.2 million for discontinued inventory, $4.8 million for combining operations and $3.8 million of other. Integration costs of $7.9 million in the first quarter of 2006 were comprised of $6.6 million for discontinued inventory, $0.5 million for combining operations and $0.8 million of other.
Pro Forma Financial Information
The unaudited financial information in the table below summarizes the combined results of operations of National-Oilwell and Varco, on a pro forma basis, as though the companies had been combined as of January 1, 2005. The pro forma financial information is presented for informational purposes only and may not be indicative of the results of operations that would have been achieved if the Merger had taken place at January 1, 2005. The pro forma financial information for the year ended December 31, 2005 includes certain merger-related items of $47.3 million such as charges associated with integration expenses, stock-based compensation charges for unvested options assumed, and severance expenses recorded by National-Oilwell in its statements of operations related to change in control provisions that were triggered as part of our Agreement and Plan of Merger in March 2005. The pro forma financial information includes the business combination accounting effect on historical Varco revenues, adjustments to depreciation on acquired property, and amortization charges from acquired intangible assets, and related tax effects.
The unaudited pro forma financial information below combines the historical results for National-Oilwell for the year ended December 31, 2005 and the historical results for Varco for the year ended December 31, 2005 (in millions):
4. Other Acquisitions
On December 16, 2007, we agreed to combine our wholly-owned subsidiary, NOV Sub, Inc., with Grant Prideco, Inc. by merging Grant Prideco with and into NOV Sub, with NOV Sub continuing as the surviving corporation. Consummation of the merger requires approval by the stockholders of Grant Prideco and also approval from various regulatory agencies. We anticipate completion of the merger will occur in the second quarter of 2008.
The Company completed eight acquisitions for an aggregate purchase price of $286.9 million consisting of cash of $285.8 million and notes payable of $1.1 million. These acquisitions included:
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Gammaloy Holdings, L.P., a Texas-based manufacturer of downhole tools.
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Kreiter Geartech, a Texas-based manufacturer of gearing products.
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Sara Services and Engineers Pvt. Ltd., an India-based manufacturer of oil field equipment.
The following table summarizes the estimated fair values of the assets acquired and liabilities assumed at the date of acquisition of the 2007 acquisitions (in millions):
Based on preliminary independent third-party valuations, the Company allocated $114.2 million to intangible assets (13.1 year weighted-average life), comprised of: $93.9 million of customer relationships (13.0 year weighted-average life), $9.1 million of trademarks (9.3 year weighted-average life), and $11.2 million of other intangible assets (19.5 year weighted-average life). These preliminary valuations are subject to change based on the final valuations by the Company’s independent valuation experts.
In January 2007, the Company also acquired the remaining 13% of NQL Energy Services, Inc.’s outstanding shares for $38.1 million.
In December 2006, the Company acquired 87% of the outstanding shares of NQL Energy Services Inc. (“NQL”), a provider of downhole tools, technology and services used primarily in drilling applications in the oil and gas and utility industries on a worldwide basis, for an aggregate cash purchase price of approximately $253.8 million. Based on independent third-party valuations, the Company allocated $126.6 million to intangible assets (12.1 year weighted-average life), comprised of: $107.5 million of customer relationships (15.5 year weighted-average life), $3.1 million of trademarks (5.2 year weighted-average life), and $16.0 million of other intangible assets (5.5 year weighted-average life). The remaining 13% of NQL’s outstanding shares were acquired in January 2007. Due to this subsequent event, the $38.1 million purchase price of the remaining shares is included in current liabilities on the December 31, 2006 balance sheet. This acquisition complements our comprehensive offering of downhole tools.
The Company also completed nine additional acquisitions for an aggregate purchase price of $85.3 million consisting of cash of $75.9 million and notes and accrued payables of $9.4 million. These acquisitions included:
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Rolligon Ltd., a Texas-based manufacturer of coiled tubing support units and related equipment.
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Soil Recovery A/S, a Danish-based designer and manufacturer of soil recovery units used to process drilled cuttings for final disposal.
The following table summarizes the estimated fair values of the assets acquired and liabilities assumed at the date of acquisition of the 2006 acquisitions (in millions):
Excluding the Varco Merger, the Company paid an aggregate purchase price of $20.7 million ($16.0 million in cash and $4.7 million of notes payable) for acquisitions and equity investments in 2005.
Each of the acquisitions were accounted for using the purchase method of accounting and, accordingly, the results of operations of each business is included in the consolidated results of operations from the date of acquisition. A summary of the acquisitions follows (in millions):
5. Inventories
At December 31, inventories consist of (in millions):
6. Property, Plant and Equipment
At December 31, property, plant and equipment consist of the following (in millions):
7. Accrued Liabilities
At December 31, accrued liabilities consist of (in millions):
8. Costs and Estimated Earnings on Uncompleted Contracts
At December 31, costs and estimated earnings on uncompleted contracts consist of (in millions):
9. Long-Term Debt
At December 31, debt consists of (in millions):
Principal payments of debt for years subsequent to 2007 are as follows (in millions):
Senior Notes
The unsecured Senior Notes contain reporting covenants, and the credit facility contains financial covenants regarding maximum debt to capitalization and minimum interest coverage. We were in compliance with all covenants at December 31, 2007.
Revolver Facilities
On June 21, 2005, we amended and restated our existing $150 million revolving credit facility with a syndicate of lenders to provide the Company a $500 million unsecured revolving credit facility. This facility will expire in July 2010. The Company has
the right to increase the facility by an amount not greater than $250 million, (to $750 million), at any time during the term of this facility, and to extend the term of the facility for an additional year during the final 90 days of the facility. At December 31, 2007, there were no borrowings against this facility, and there were $360 million in outstanding letters of credit. Interest under this multicurrency facility is based upon LIBOR, NIBOR or EURIBOR plus 0.30% subject to a ratings-based grid, or the prime rate.
At December 31, 2007, there were $140 million of funds available under the revolving credit facility. The Company also has $1,352 million of additional outstanding letters of credit at December 31, 2007, primarily in Norway, that are essentially under various bilateral committed letters of credit. The increase in letters of credit is the result of significant down payments from our customers, which in turn require our issuing to our customers advance payment guarantees in the form of letters of credit. Other letters of credit are issued as bid bonds and performance bonds.
Other
Other debt includes approximately $21.6 million in promissory notes due to former owners of businesses acquired who remain employed by the company.
10. Employee Benefit Plans
We have benefit plans covering substantially all of our employees. Defined-contribution benefit plans cover most of the U.S. and Canadian employees, and benefits are based on years of service, a percentage of current earnings and matching of employee contributions. Employees in our Norwegian operations can elect to participate in a defined-contribution plan in lieu of a local defined benefit plan. For the years ended December 31, 2007, 2006 and 2005, expenses for defined-contribution plans were $30.7 million, $16.8 million, and $19.9 million, and all funding is current.
Certain retired or terminated employees of predecessor or acquired companies participate in a defined benefit plan in the United States. None of the participants in this plan are eligible to accrue benefits. In addition, approximately 353 U.S. retirees and spouses participate in defined benefit health care plans of predecessor or acquired companies that provide postretirement medical and life insurance benefits. Active employees are ineligible to participate in any of these defined benefit plans. Our subsidiaries in the United Kingdom and Norway also have defined benefit pension plans covering virtually all of their employees.
Net periodic benefit cost for our defined benefit pension plans in the United States, the United Kingdom and Norway was as follows (in millions):
The change in benefit obligation, plan assets and the funded status of the defined benefit pension plans in the United States, United Kingdom, and Norway and defined postretirement plans in the United States, using a measurement date of September 30, 2007 or 2006, follows (in millions):
Amounts recognized in the consolidated balance sheets consist of (in millions):
Defined Benefit Pension Plans
Assumed long-term rates of return on plan assets, discount rates and rates of compensation increases vary for the different plans according to the local economic conditions.
The assumption rates used for benefit obligations are as follows:
The assumption rates used for net periodic benefit costs are as follows:
In determining the overall expected long-term rate of return for plan assets, the Company takes into consideration the historical experience as well as future expectations of the asset mix involved. As different investments yield different returns, each asset category is reviewed individually and then weighted for significance in relation to the total portfolio.
The weighted-average asset allocations at December 31, 2007 and 2006, by asset category are as follows:
In the U.S., our investment strategy includes a balanced approach with target allocation percentages of 60% equity investments and 40% debt securities. Our target allocation percentages in the United Kingdom plans are 50-60% equity securities and 40-50% debt securities. The Norwegian target investment allocation percentage is 100% insurance contracts. Our pension investment strategy worldwide prohibits a direct investment in our own stock.
Information for pension plans with projected benefit obligations in excess of plan assets (in millions):
Information for pension plans with accumulated benefit obligations in excess of plan assets (in millions):
In 2008, the Company expects to contribute $2.0 million in the U.S. and $6.8 million internationally to its pension plans and $1.3 million to its other postretirement benefit plans.
In addition, the following benefit payments, which reflect expected future service, as appropriate, are expected to be paid (in millions):
11. Accumulated Other Comprehensive Income (Loss)
The components of other comprehensive income (loss) are as follows (in millions):
12. Commitments and Contingencies
We are involved in various claims, regulatory agency audits and pending or threatened legal actions involving a variety of matters. The total liability on these matters at December 31, 2007 cannot be determined; however, in our opinion, any ultimate liability, to the extent not otherwise provided for, should not materially affect our financial position, cash flow or results of operations.
Our business is affected both directly and indirectly by governmental laws and regulations relating to the oilfield service industry in general, as well as by environmental and safety regulations that specifically apply to our business. Although we have not incurred material costs in connection with our compliance with such laws, there can be no assurance that other developments, such as new environmental laws, regulations and enforcement policies thereunder may not result in additional, presently unquantifiable, costs or liabilities to us.
The Company leases certain facilities and equipment under operating leases that expire at various dates through 2049. These leases generally contain renewal options and require the lessee to pay maintenance, insurance, taxes and other operating expenses in addition to the minimum annual rentals. Rental expense related to operating leases approximated $128.4 million, $95.4 million, and $59.1 million in 2007, 2006 and 2005, respectively.
Future minimum lease commitments under noncancellable operating leases with initial or remaining terms of one year or more at December 31, 2007 are payable as follows (in millions):
13. Common Stock
National Oilwell Varco has authorized 500 million shares of $.01 par value common stock. We also have authorized 10 million shares of $.01 par value preferred stock, none of which is issued or outstanding.
On August 22, 2007, the Company’s Board of Directors approved a two-for-one stock split in the form of a stock dividend to the Company’s stockholders of record on September 7, 2007, with distribution of shares on September 28, 2007. The total number of authorized common stock shares and associated par value were unchanged by this action. All per-share amounts in the financial statements reflect the stock split for all periods presented unless indicated otherwise.
Stock Options
Under the terms of National Oilwell Varco’s Long-Term Incentive Plan, as amended, 15 million shares of common stock are authorized for the grant of options to officers, key employees, non-employee directors and other persons. Options granted under our stock option plan generally vest over a three-year period starting one year from the date of grant and expire ten years from the date of grant. The purchase price of options granted may not be less than the closing market price of National Oilwell Varco common stock on the date of grant. At December 31, 2007, approximately 7.0 million shares were available for future grants.
We also have inactive stock option plans that were acquired in connection with the acquisitions of IRI International Corporation in 2000 and Varco International, Inc. in March 2005. We converted the outstanding stock options under these plans to options to acquire our common stock and no further options are being issued or are outstanding under these plans. Stock option information summarized below includes amounts for the National Oilwell Varco Long-Term Incentive Plan and stock plans of acquired companies.
Options outstanding at December 31, 2007 under the stock option plans have exercise prices between $4.53 and $49.07 per share, and expire at various dates from February 11, 2008 to June 6, 2017.
The following summarizes options activity:
The following summarizes information about stock options outstanding as of December 31, 2007:
The weighted-average fair value of options granted during 2007, 2006 and 2005 was approximately $11.99, $11.90 and $8.43 (excluding options assumed in the Varco merger) per share, respectively, as determined using the Black-Scholes option-pricing model. The total intrinsic value of options exercised during 2007 and 2006 was $114.2 million and $49.6 million, respectively.
Upon adoption of SFAS 123(R), we began recording expense related to the value of employee stock options on the date of grant using the Black Scholes model. Prior to the adoption of SFAS 123(R), the value of each employee stock option was estimated on the date of grant using the Black-Scholes model for the purpose of the pro forma financial information in accordance with SFAS 123. The determination of fair value of share-based payment awards on the date of grant using an option-pricing model is affected by our stock price as well as assumptions regarding a number of highly complex and subjective variables. These variables include, but are not limited to, the expected stock price volatility over the term of the awards, and actual and projected employee stock option exercise activity. The use of the Black Scholes model requires the use of extensive actual employee exercise activity data and the use of a number of complex assumptions including expected volatility, risk-free interest rate, expected dividends and expected term.
We used the actual volatility for traded options on our stock since March 11, 2005 (the Varco merger date) as the expected volatility assumption required in the Black Scholes model, which is consistent with SFAS 123(R) and SAB 107. Prior to the first quarter of fiscal 2006, we used our historical stock price volatility in accordance with SFAS 123 for purposes of our pro forma information.
The risk-free interest rate assumption is based upon observed interest rates appropriate for the term of our employee stock options. The dividend yield assumption is based on the history and expectation of dividend payouts. The estimated expected term is based on actual employee exercise activity for the past ten years.
As stock-based compensation expense recognized in the Consolidated Statement of Income in 2007 is based on awards ultimately expected to vest, it has been reduced for estimated forfeitures. SFAS 123(R) requires forfeitures to be estimated at the time of grant and revised, if necessary, in subsequent periods if actual forfeitures differ from those estimates. Forfeitures were estimated based on historical experience.
The following summary presents information regarding outstanding options as of December 31, 2007 and changes during 2007 with regard to options under all stock option plans:
As of December 31, 2007, total unrecognized compensation cost related to nonvested stock options was $60.1 million. This cost is expected to be recognized over a weighted average period of 2.0 years. The total fair value of stock vested in 2007 and 2006 was approximately $33.5 million and $22.1 million, respectively. Cash received from option exercises for 2007 and 2006 was $91.3 million and $32.7 million, respectively. The actual tax benefit realized for the tax deductions from option exercises totaled $34.2 million and $15.2 million, for 2007 and 2006, respectively. Cash used to settle equity instruments granted under all share-based payment arrangements for 2007 and 2006 was not material in both periods.
The impact of adopting SFAS 123(R) on January 1, 2006, on the Company’s income before income taxes, net income and basic and diluted earnings per share for 2007 was not material.
Restricted Shares
During 2007, the Company began issuing restricted stock award (“RSA”) with no exercise price to officers and key employees in addition to stock options. The company granted restricted shares to key employees on March 1, 2007 at $35.23. These shares will not vest until the third anniversary of the date of the grant, at which time they will be 100% vested. The company also granted performance-based restricted shares to senior management and officers on March 26, 2007 at $39.04. Of the total amount of 400,500 performance-based shares granted, 133,500 will be 100% vested 18 months from date of grant, with a performance condition of the Company’s operating income level growth from January 1, 2007 to June 30, 2008 needing to exceed the median operating income level growth of a designated peer group over the same period. The remaining 267,000 performance-based shares will be 100% vested 36 months from date of grant, with a performance condition of the Company’s operating income level growth from January 1, 2007 to December 31, 2009 needing to exceed the median operating income level growth of a designated peer group over the same period.
The following summary presents information regarding outstanding restricted shares as of December 31, 2007, and changes during 2007.
The weighted-average grant day fair value of RSA’s granted during the years ended 2007, 2006 and 2005 was $37.06, nil and $29.13 per share, respectively. There were no RSA’s that vested during years ended 2007, 2006 and 2005. As of December 31, 2007, there was $23.9 million of unrecognized compensation cost related to non-vested RSA which is expected to be recognized over a weighted-average period of 2.0 years.
14. Income Taxes
The domestic and foreign components of income before income taxes were as follows (in millions):
The components of the provision for income taxes consisted of (in millions):
The difference between the effective tax rate reflected in the provision for income taxes and the U.S. federal statutory rate was as follows (in millions):
At December 31, significant components of our deferred tax assets and liabilities were as follows (in millions):
On July 13, 2006, the FASB issued FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes - An Interpretation of FASB No. 109” (“FIN 48”). FIN 48 clarifies the accounting for uncertainty in income taxes recognized in an entity’s financial statements in accordance with FASB Statement No. 109, “Accounting for Income Taxes” and prescribes a recognition threshold and measurement attributes for financial statement disclosure of tax positions taken or expected to be taken on a return. Under FIN 48, the impact of an uncertain income tax position, in management’s opinion, on the income tax return must be recognized at the largest amount that is more-likely-than not to be sustained upon audit by the relevant taxing authority. An uncertain income tax position will not be recognized if it has a less than 50% likelihood of being sustained. Additionally, FIN 48 provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition. FIN 48 became effective January 1, 2007 for the Company. As required, the Company has recorded the cumulative effect of adopting FIN 48 as an adjustment to the January 1, 2007 beginning balance of retained earnings.
The total amount of unrecognized tax benefits as of the date of adoption was $54.5 million. As a result of the implementation of FIN 48, the Company recognized a $9.3 million increase in the liability for unrecognized tax benefits and a $0.6 million increase for accrued interest and penalty which was accounted for as follows (in millions):
A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows (in millions):
Included in the balance of unrecognized tax benefits at January 1, 2007 and December 31, 2007 are $30.5 million and $29.5 million of tax benefits, respectively, that, if recognized in future periods, would impact the Company’s effective tax rate. Also included in the balance of unrecognized tax benefits at January 1, 2007 and December 31, 2007 are $24.0 million and $17.5 million of tax benefits, respectively, that, if recognized, would result in a decrease to goodwill in purchase business combinations. The reduction in the balance of unrecognized tax benefits resulted from the completion in the U.S. of prior year audits and appeals. These unrecognized tax benefits are included in the balance of Accrued Income Taxes in the balance sheet as of December 31, 2007.
The Company does not anticipate that the total unrecognized tax benefits will significantly change due to the settlement of audits or the expiration of statutes of limitation within 12 months of this reporting date.
To the extent penalties and interest would be assessed on any underpayment of income tax, such accrued amounts have been classified as a component of income tax expense in the financial statements. This is an accounting policy election made by the Company that is a continuation of the Company’s historical policy and will continue to be consistently applied in the future. During the year ended December 31, 2007, the Company recognized $2.7 million of additional interest and penalties related to uncertain tax positions as part of income tax expense. As of December 31, 2007, the Company has accrued approximately $4.6 million of interest and penalties relating to unrecognized tax benefits. These interest and penalties are included in the balance of Accrued Income Taxes in the balance sheet as of December 31, 2007.
The Company is subject to taxation in the United States, various states and foreign jurisdictions. The Company has significant operations in the United States, Canada, the United Kingdom, the Netherlands and Norway. Tax years that remain subject to examination by major tax jurisdictions vary by legal entity, but are generally open in the U.S. for the tax years ending after 2003 and outside the U.S. for the tax years ending after 2001. Norway also remains open for the 2001 tax year.
During the quarter ended June 30, 2007 the Internal Revenue Service completed its audit of the Company’s 2003 tax year. There were no adjustments resulting from this examination that will have a material impact on the Company’s financial position, cash flows or results of operations.
In the United States, the Company has $20.3 million of net operating loss carryforwards as of December 31, 2007, which expire at various dates through 2026. The potential benefit of $7.1 million has been recorded with $5.8 million valuation allowance. Future income tax payments will be reduced when the Company ultimately realizes the benefit of these net operating losses. If the Company ultimately realizes the benefit of these net operating loss carryforwards, the valuation allowance of $5.8 million would reduce future income tax expense.
During 2007 the Company recorded $42.5 million in net deferred tax liabilities with a corresponding increase in goodwill related to NQL purchase accounting. During 2006 the Company recorded $32.1 million in deferred tax assets with a corresponding reduction in goodwill related to the finalization of Varco purchase accounting.
Also in the United States, the Company has $0.7 million of excess foreign tax credits as of December 31, 2007, which expire at various dates through 2017. These credits have been allotted a valuation allowance and would be realized as a reduction of future income tax payments. If the Company ultimately realizes the benefit of these excess foreign tax credits, the valuation allowance of $0.1 million would reduce future income tax expense and $0.6 million would reduce goodwill.
Also in the United States, the company has $19.3 million of capital loss carryforwards as of December 31, 2007, which will expire in 2009. The related potential benefit of $6.8 million has been recorded with a valuation allowance of $6.8 million. These capital losses are not available to reduce future operating income but if realized will reduce future capital gains and will result in a reduction of goodwill.
Outside the United States, the company has $3.6 million of net operating loss carryforwards as of December 31, 2007. Of this amount, $3.2 million will expire at various dates through 2016 and $0.4 million is available indefinitely. The related potential benefit available of $1.1 million has been recorded with a valuation allowance of $0.9 million. If the Company ultimately realizes the benefit of these net operating losses, the valuation allowance of $0.9 million would reduce income tax expense.
Also outside the United States, the company has $0.7 million of capital loss carryforwards as of December 31, 2007, which can be carried forward indefinitely. The related potential benefit of $0.2 million has been recorded with a full valuation allowance of $0.2 million. These capital losses are not available to reduce future operating income but if realized will reduce future capital gains and will result in a reduction of future income tax expense.
The deferred tax valuation allowance increased $7.6 million and $4.9 million for the periods ending December 31, 2007 and 2006, respectively. Of the net increase recorded in 2007, $2.5 million was recorded as an increase of income tax expense, $1.7 million was recorded as a decrease in deferred tax assets and $6.8 million was recorded as an increase in goodwill. Of the net increase recorded in 2006, $2.7 was recorded as an increase in income tax expense, $1.6 million was recorded as an increase in deferred tax assets and $0.6 as an increase of goodwill. The increase recorded in 2007 resulted from losses sustained in the U.S. by a subsidiary that reports its taxes separately from the consolidated group and from capital losses obtained in the acquisition of NQL which were originally incurred in the U.S. The increase recorded in 2006 resulted from losses sustained in the U.S. by a subsidiary that reports its taxes separately from the consolidated group.
Undistributed earnings of the Company’s foreign subsidiaries amounted to $1,580.0 million and $1,116.3 million at December 31, 2007 and 2006, respectively. Those earnings are considered to be permanently reinvested and no provision for U.S. federal and state income taxes has been made. Distribution of these earnings in the form of dividends or otherwise could result in either U.S. federal taxes (subject to an adjustment for foreign tax credits) and withholding taxes payable in various foreign countries. Determination of the amount of unrecognized deferred U.S. income tax liability is not practical; however, unrecognized foreign tax credit carryforwards would be available to reduce some portion of the U.S. liability. Withholding taxes of approximately $67.9 million would be payable upon remittance of all previously unremitted earnings at December 31, 2007.
Because of the number of tax jurisdictions in which the Company operates, its effective tax rate can fluctuate as operations and the local country tax rates fluctuate. The Company is also subject to audits by federal, state and foreign jurisdictions which may result in proposed assessments. The Company’s future tax provision will reflect any favorable or unfavorable adjustments to its estimated tax liabilities when resolved. The Company is unable to predict the outcome of these matters. However, we believe that none of these matters will have a material adverse effect on the results of operations or financial condition of the Company.
In October of 2004, the American Jobs Creation Act of 2004 (the “Jobs Act”) was signed into law which introduced a special one-time dividends received deduction on the repatriation of foreign earnings to a U.S. taxpayer (repatriation provision), provided certain criteria are net. The Act provides for a special one-time deduction of 85 percent of certain foreign earnings that are repatriated in either the Company’s last tax year that began before the enactment date, or the first tax year that begins during the one-year period beginning on the date of enactment. The maximum amount of the Company’s foreign earnings that qualify for temporary deduction is $408.2 million. The Company repatriated none of its foreign earnings in 2005 under the repatriation provisions of the Jobs Act.
15. Business Segments and Geographic Areas
The Company’s operations consist of three reportable segments: Rig Technology, Petroleum Services & Supplies and Distribution Services.
Rig Technology: Our Rig Technology Group designs, manufactures, sells and services complete rig systems for the drilling, completion, and remediation of oil and gas wells. The Group offers a comprehensive line of highly-engineered machinery which automates complex well construction and management operations, such as offshore and onshore drilling rigs; pipe racking, rotating and assembly systems; coiled tubing equipment and pressure pumping units; well workover rigs; wireline winches; and cranes.
Petroleum Services & Supplies: Our Petroleum Services & Supplies Group provides a variety of consumable goods and services used to drill, complete, remediate and workover oil and gas wells, and manage pipelines, flowlines and other oilfield tubular goods. The Group manufactures, rents and sells a variety of products and equipment used to perform drilling operations; including solids control systems, drilling motors, rig instrumentation systems, and drilling mud pump consumables.
Distribution Services: Our Distribution Services segment provides maintenance, repair and operating supplies and spare parts to drill site and production locations worldwide. In addition to its comprehensive network of field locations supporting upstream activity throughout North America, the segment supports major land and offshore operations through locations in Mexico, the Middle East, Africa, Europe, Southeast Asia and South America. Distribution Services employs advanced information technologies to provide complete procurement, inventory management and logistics services to its customers around the globe.
The accounting policies of the reportable segments are the same as those described in the summary of significant accounting policies of the Company. The Company evaluates performance of each reportable segment based upon its operating income, excluding non-recurring items.
No single customer accounted for 10% or more of consolidated revenues during the three years ended December 31, 2007.
Summarized financial information is as follows (in millions):
Geographic Areas:
Business Segments:
16. Quarterly Financial Data (Unaudited)
Summarized quarterly results, were as follows (in millions, except per share data):
SCHEDULE II
NATIONAL OILWELL VARCO, INC.
VALUATION AND QUALIFYING ACCOUNTS
Years Ended December 31, 2007, 2006 and 2005
Exhibit Index
2.1
Amended and Restated Agreement and Plan of Merger, effective as of August 11, between National-Oilwell, Inc. and Varco International, Inc. (4).
2.2
Agreement and Plan of Merger, effective as of December 16, 2007, between National Oilwell Varco, Inc., NOV Sub, Inc., and Grant Prideco, Inc. (9)
3.1
Amended and Restated Certificate of Incorporation of National-Oilwell, Inc. (Exhibit 3.1) (1).
3.2
Amended and Restated By-laws of National Oilwell Varco, Inc. (Exhibit 3.1) (10).
10.1
Employment Agreement dated as of January 1, 2002 between Merrill A. Miller, Jr. and National Oilwell. (Exhibit 10.1) (2).
10.2
Employment Agreement dated as of January 1, 2002 between Dwight W. Rettig and National Oilwell, with similar agreement with Mark A. Reese. (Exhibit 10.2) (2).
10.3
Form of Amended and Restated Executive Agreement of Clay C. Williams. (Exhibit 10.12) (3).
10.4
National Oilwell Varco Long-Term Incentive Plan (5)*.
10.5
Form of Employee Stock Option Agreement (Exhibit 10.1) (7)
10.6
Form of Non-Employee Director Stock Option Agreement (Exhibit 10.2) (7).
10.7
Amended and Restated Credit Agreement, dated as of June 21, 2005, among National Oilwell Varco, Inc., the financial institutions signatory thereto, including Wells Fargo Bank, National Association, in their capacities as lenders thereunder, as US administrative agent for the lenders, as Lead Arranger and Sole Book Runner, DnB NOR Bank ASA, as Norwegian Administrative Agent, DnB NOR Bank ASA and the Bank of Nova Scotia as Co-Documentation Agents, and Comerica Bank and JPMorgan Chase Bank, N.A. as Co-Syndication Agents. (Exhibit 10.1) (6).
10.8
Form of Performance-Based Restricted Stock (18 Month) Agreement (Exhibit 10.1) (8).
10.9
Form of Performance-Based Restricted Stock (36 Month) Agreement (Exhibit 10.2) (8).
21.1
Subsidiaries of the Registrant
23.1
Consent of Ernst & Young LLP
24.1
Power of Attorney (included on signature page hereto).
31.1
Certification pursuant to Rule 13a-14a and Rule 15d-14(a) of the Securities and Exchange Act, as amended
31.2
Certification pursuant to Rule 13a-14a and Rule 15d-14(a) of the Securities and Exchange Act, as amended
32.1
Certification pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2
Certification pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
ITEM 12.
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
Incorporated by reference to the definitive Proxy Statement for the 2008 Annual Meeting of Stockholders.
Securities Authorized for Issuance Under Equity Compensation Plans
The following table sets forth information as of our fiscal year ended December 31, 2007, with respect to compensation plans under which our common stock may be issued:
(1)
Shares could be issued other than upon the exercise of stock options, warrants or rights; however, none are anticipated during 2008.
ITEM 13.
ITEM 13.
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
Incorporated by reference to the definitive Proxy Statement for the 2008 Annual Meeting of Stockholders.
ITEM 14.
ITEM 14.
PRINCIPAL ACCOUNTANT FEES AND SERVICES
Incorporated by reference to the definitive Proxy Statement for the 2008 Annual Meeting of Stockholders.
PART IV
ITEM 15.
ITEM 15.
EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
Financial Statements and Exhibits
(1)
Financial Statements
The following financial statements are presented in response to Part II, Item 8:
Page
Consolidated Balance Sheets
Consolidated Statements of Income
Consolidated Statements of Cash Flows
Consolidated Statements of Stockholders’ Equity and Comprehensive Income
Notes to Consolidated Financial Statements
(2)
Financial Statement Schedule
Schedule II - Valuation and Qualifying Accounts
All schedules, other than Schedule II, are omitted because they are not applicable, not required or the information is included in the financial statements or notes thereto.
2.1
Amended and Restated Agreement and Plan of Merger, effective as of August 11, between National-Oilwell, Inc. and Varco International, Inc. (4).
2.2
Agreement and Plan of Merger, effective as of December 16, 2007, between National Oilwell Varco, Inc., NOV Sub, Inc., and Grant Prideco, Inc. (9)
3.1
Amended and Restated Certificate of Incorporation of National-Oilwell, Inc. (Exhibit 3.1) (1).
3.2
Amended and Restated By-laws of National Oilwell Varco, Inc. (Exhibit 3.1) (10).
10.1
Employment Agreement dated as of January 1, 2002 between Merrill A. Miller, Jr. and National Oilwell. (Exhibit 10.1) (2).
10.2
Employment Agreement dated as of January 1, 2002 between Dwight W. Rettig and National Oilwell, with similar agreement with Mark A. Reese. (Exhibit 10.2) (2).
10.3
Form of Amended and Restated Executive Agreement of Clay C. Williams. (Exhibit 10.12) (3).
10.4
National Oilwell Varco Long-Term Incentive Plan (5)*.
10.5
Form of Employee Stock Option Agreement (Exhibit 10.1) (7)
10.6
Form of Non-Employee Director Stock Option Agreement (Exhibit 10.2) (7).
10.7
Amended and Restated Credit Agreement, dated as of June 21, 2005, among National Oilwell Varco, Inc., the financial institutions signatory thereto, including Wells Fargo Bank, National Association, in their capacities as lenders thereunder, as US administrative agent for the lenders, as Lead Arranger and Sole Book Runner, DnB NOR Bank ASA, as Norwegian Administrative Agent, DnB NOR Bank ASA and the Bank of Nova Scotia as Co-Documentation Agents, and Comerica Bank and JPMorgan Chase Bank, N.A. as Co-Syndication Agents. (Exhibit 10.1) (6).
10.8
Form of Performance-Based Restricted Stock (18 Month) Agreement (Exhibit 10.1) (8).
10.9
Form of Performance-Based Restricted Stock (36 Month) Agreement (Exhibit 10.2) (8).
21.1
Subsidiaries of the Registrant
23.1
Consent of Ernst & Young LLP
24.1
Power of Attorney (included on signature page hereto).
31.1
Certification pursuant to Rule 13a-14a and Rule 15d-14(a) of the Securities and Exchange Act, as amended
31.2
Certification pursuant to Rule 13a-14a and Rule 15d-14(a) of the Securities and Exchange Act, as amended
32.1
Certification pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2
Certification pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
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.
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
Each person whose signature appears below in so signing, constitutes and appoints Merrill A. Miller, Jr. and Clay C. Williams, and each of them acting alone, his true and lawful attorney-in-fact and agent, with full power of substitution, for him and in his name, place and stead, in any and all capacities, to execute and cause to be filed with the Securities and Exchange Commission any and all amendments to this report, and in each case to file the same, with all exhibits thereto and other documents in connection therewith, and hereby ratifies and confirms all that said attorney-in-fact or his substitute or substitutes may do or cause to be done by virtue hereof.
MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
National Oilwell Varco, Inc.’s management is responsible for establishing and maintaining adequate internal control over financial reporting. National Oilwell Varco, Inc.’s internal control system was designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.
Internal control over financial reporting cannot provide absolute assurance of achieving financial reporting objectives because of its inherent limitations. Internal control over financial reporting is a process that involves human diligence and compliance and is subject to lapses in judgment and breakdowns resulting from human failures. Internal control over financial reporting also can be circumvented by collusion or improper management override. Because of such limitations, there is a risk that material misstatements may not be prevented or detected on a timely basis by internal control over financial reporting. However, these inherent limitations are known features of the financial reporting process. Therefore, it is possible to design into the process safeguards to reduce, though not eliminate, this risk.
Management has used the framework set forth in the report entitled “Internal Control-Integrated Framework” published by the Committee of Sponsoring Organizations (“COSO”) of the Treadway Commission to evaluate the effectiveness of the Company’s internal control over financial reporting. Management has concluded that the Company’s internal control over financial reporting was effective as of December 31, 2007.
The effectiveness of our internal control over financial reporting as of December 31, 2007, has been audited by Ernst & Young LLP, the independent registered public accounting firm who also has audited the Company’s consolidated financial statements included in this Annual Report on Form 10-K.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors and Stockholders
National Oilwell Varco, Inc.
We have audited the accompanying consolidated balance sheets of National Oilwell Varco, Inc. as of December 31, 2007 and 2006 and the related consolidated statements of income, stockholders’ equity and comprehensive income, and cash flows for each of the three years in the period ended December 31, 2007. Our audits also included the financial statement schedule listed in the index at Item 15(a). These financial statements and schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and schedule based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the consolidated financial position of National Oilwell Varco, Inc. at December 31, 2007 and 2006, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2007, in conformity with U.S generally accepted accounting principles. Also, in our opinion, the related financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein.
As discussed in Note 14 to the consolidated financial statements, effective January 1, 2007, the Company adopted FASB Interpretations - FIN 48: Accounting for Uncertainty in Income Taxes an Interpretation of FASB Statement No. 109 and, as discussed in Note 2 to the consolidated financial statements, effective January 1, 2006, the Company adopted Statement of Financial Accounting Standards No. 123 (revised 2004), Share Based Payment, and, as discussed in Note 10, effective December 31, 2006 the Company adopted Statement of Financial Accounting Standards No. 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans, an amendment of FASB Statements No. 87, 88, 106, and 132(R).
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), National Oilwell Varco, Inc.’s internal control over financial reporting as of December 31, 2007, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 28, 2008 expressed an unqualified opinion thereon.
/s/ ERNST & YOUNG LLP
Houston, Texas
February 28, 2008
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors and Stockholders
National Oilwell Varco, Inc.
We have audited National Oilwell Varco, Inc.’s internal control over financial reporting as of December 31, 2007, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). National Oilwell Varco, Inc.’s management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the company’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, National Oilwell Varco, Inc. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2007 based on the COSO criteria.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of National Oilwell Varco, Inc. as of December 31, 2007 and 2006 and the related consolidated statements of income, stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2007, and our report dated February 28, 2008 expressed an unqualified opinion thereon.
/s/ ERNST & YOUNG LLP
Houston, Texas
February 28, 2008
NATIONAL OILWELL VARCO, INC.
CONSOLIDATED BALANCE SHEETS
(In millions, except share data)
The accompanying notes are an integral part of these statements.
NATIONAL OILWELL VARCO, INC.
CONSOLIDATED STATEMENTS OF INCOME
(In millions, except per share data)
The accompanying notes are an integral part of these statements.
NATIONAL OILWELL VARCO, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In millions)
The accompanying notes are an integral part of these statements.
NATIONAL OILWELL VARCO, INC.
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY AND COMPREHENSIVE INCOME
(In millions)
The accompanying notes are an integral part of these statements.
NATIONAL OILWELL VARCO, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. Organization and Basis of Presentation
Nature of Business
We design, construct, manufacture and sell comprehensive systems, components, and products used in oil and gas drilling and production, provide oilfield services and supplies, and distribute products and provide supply chain integration services to the upstream oil and gas industry. Our revenues and operating results are directly related to the level of worldwide oil and gas drilling and production activities and the profitability and cash flow of oil and gas companies, drilling contractors and oilfield service companies, which in turn are affected by current and anticipated prices of oil and gas. Oil and gas prices have been and are likely to continue to be volatile.
Basis of Consolidation
The accompanying consolidated financial statements include the accounts of National Oilwell Varco, Inc. and its majority-owned subsidiaries. All significant intercompany transactions and balances have been eliminated in consolidation. Investments that are not wholly-owned, but where we exercise control, are fully consolidated with the equity held by minority owners and their portion of net income (loss) reflected as minority interest in the accompanying consolidated financial statements. Investments in unconsolidated affiliates, over which we exercise significant influence, but not control, are accounted for by the equity method. Investments in which we exercise no control or significant influence would be accounted for under the cost method. Certain reclassifications have been made to the 2006 and 2005 consolidated financial statements in order for them to conform with the 2007 presentation.
2. Summary of Significant Accounting Policies
Fair Value of Financial Instruments
The carrying amounts of financial instruments including cash and cash equivalents, receivables, and payables approximated fair value because of the relatively short maturity of these instruments. Cash equivalents include only those investments having a maturity date of three months or less at the time of purchase. The carrying values of other financial instruments approximate their respective fair values.
Derivative Financial Instruments
We record all derivative financial instruments at their fair value in our consolidated balance sheet. Except for certain balance sheet hedges and interest rate swap agreements discussed below, all derivative financial instruments we hold are designated as either cash flow or fair value hedges and are highly effective in offsetting movements in the underlying risks. Accordingly, gains and losses from changes in the fair value of designated derivative financial instruments are deferred and recognized in earnings as revenues or costs of sales as the underlying transactions occur. Any ineffective portion of the change in the fair value is recorded in earnings as incurred.
We use foreign currency forward contracts to mitigate our exposure to changes in foreign currency exchange rates on recognized nonfunctional currency monetary accounts, forecasted transactions and firm sale and purchase commitments to better match the local currency cost components of non-functional currency transactions. Such arrangements typically have terms between two and 24 months, but may have longer terms depending on the project and our backlog. We may also use interest rate contracts to mitigate our exposure to changes in interest rates on anticipated long-term debt issuances. We do not use derivative financial instruments for trading or speculative purposes.
At December 31, 2007, we had entered into foreign currency forward contracts with notional amounts aggregating $1,024.2 million designated and qualifying as cash flow hedges to hedge exposure to currency fluctuations in various foreign currencies. These exposures arise when local currency operating expenses are not in balance with local currency revenue collections. Based on quoted market prices as of December 31, 2007 for contracts with similar terms and maturity dates, we have recorded a gain of $11.2 million, net of tax of $4.0 million, to adjust these foreign currency forward contracts to their fair market value. This gain is included in other comprehensive income in the consolidated balance sheet. It is expected that $6.4 million of this gain will be reclassified into earnings within the next 12 months. At December 31, 2007, the Company has cash flow hedges in place through the first quarter of 2011. A gain from ineffectiveness of $4.6 million is included in earnings related to these foreign currency contracts for the year ending December 31, 2007. Ineffectiveness for 2006 and 2005 was not material.
At December 31, 2007, the Company had foreign currency forward contracts with notional amounts aggregating $1,579.1 million designated and qualifying as fair value hedges to hedge exposure to currency fluctuations in various foreign currencies. Based on quoted market prices as of December 31, 2007 for contracts with similar terms and maturity dates, we recorded a gain of $79.9 million to adjust these foreign currency forward contracts to their fair market value. This gain offsets designated losses on firm commitments. At December 31, 2007, the Company has fair value hedges in place through the first quarter of 2011. A loss from ineffectiveness of ($0.6) million is included in earnings related to these foreign currency contracts for the year ending December 31, 2007. Ineffectiveness for 2006 and 2005 was not material.
At December 31, 2007, the Company had foreign currency forward contracts with notional amounts aggregating $279.2 million to offset exposures to currency fluctuation of nonfunctional currency balance sheet accounts, primarily consisting of accounts receivable and accounts payable and are not designated as hedges. Therefore, changes in the fair value of these contracts are recorded each period in current earnings.
At December 31, 2007, the Company had foreign currency forward contracts with notional amounts aggregating $1,221.6 million designated and qualifying as net investment hedges of our Norwegian operations. Based on market prices as of December 31, 2007 for contracts with similar terms and maturity dates, we have recorded a gain of $7.5 million, net of tax of $4.4 million to adjust these foreign contracts to their fair market value. This gain is included in other comprehensive income in the consolidated balance sheet and was settled in 2008.
We assess the functional currencies of our operating units to ensure that the appropriate currencies are utilized in accordance with the guidance of SFAS No. 52, Foreign Currency Translation. Effective January 1, 2008, we changed the functional currency of our Rig Technology unit in Norway from the Norwegian Kroner to the U.S. dollar to more appropriately reflect the primary economic environment in which they operate. This change was precipitated by significant changes in the economic facts and circumstances including, the increased order rate for large drilling platforms and components technology, the use of our Norway unit as our preferred project manager of these projects, increasing revenue and cost base in U.S. dollars, and the implementation of an international cash pool. As a Norwegian Kroner functional unit, Norway was subject to increasing foreign currency exchange risk as a result of these changes in its economic environment and was dependent upon significant hedging transactions to offset its non-functional currency positions. At December 31, 2007, our Norway operations had derivatives with $2,550.5 million in notional value with a fair value of $91.3 million as compared to $1,394.6 million and $48.5 million at December 31, 2006, respectively, to mitigate foreign currency exchange risk against the U.S. dollar, our reporting currency. Effective with the change in the functional currency the Company terminated these hedges, the related net position of $108.8 million associated with the terminated hedges will be recognized into earnings in the future period(s) the forecasted transactions affect earnings.
Inventories
Inventories consist of raw materials, work-in-process and oilfield and industrial finished products, manufactured equipment and spare parts. Inventories are stated at the lower of cost or market using the first-in, first-out or average cost methods. Allowances for excess and obsolete inventories are determined based on our historical usage of inventory on-hand as well as our future expectations related to our installed base and the development of new products. The allowance, which totaled $99.3 million and $86.1 million at December 31, 2007 and 2006, is the amount necessary to reduce the cost of the inventory to its estimated realizable value.
Property, Plant and Equipment
Property, plant and equipment are recorded at cost. Expenditures for major improvements that extend the lives of property and equipment are capitalized while minor replacements, maintenance and repairs are charged to operations as incurred. Disposals are removed at cost less accumulated depreciation with any resulting gain or loss reflected in operations. Depreciation is provided using the straight-line method over the estimated useful lives of individual items. Depreciation expense was $153.1 million, $119.2 million and $83.0 million for the years ended December 31, 2007, 2006 and 2005. The estimated useful lives of the major classes of property, plant and equipment are included in Note 6 to the consolidated financial statements.
Long-lived Assets
We record impairment losses on long-lived assets used in operations when events and circumstances indicate that the assets might be impaired and the undiscounted cash flows estimated to be generated by those assets are less than the carrying amount of those assets. The carrying value of assets used in operations that is not recoverable is reduced to fair value if lower than carrying value. In determining the fair market value of the assets, we consider market trends and recent transactions involving sales of similar assets, or when not available, discounted cash flow analysis.
Intangible Assets
On at least an annual basis, we assess whether goodwill is impaired. Our annual impairment tests are performed at the beginning of the fourth quarter of each year and have indicated no impairment. If we determine that goodwill is impaired, we measure that impairment based on the amount by which the book value of goodwill exceeds its implied fair value. The implied fair value of goodwill is determined by deducting the fair value of a reporting unit’s identifiable assets and liabilities from the fair value of that reporting unit as a whole. Additional impairment assessments may be performed on an interim basis if we encounter events or changes in circumstances that would indicate that, more likely than not, the carrying amount of goodwill has been impaired. Fair value of the reporting units is determined based on internal management estimates using a combination of three methods: discounted cash flows, comparable companies and representative transactions.
Goodwill is identified by segment as follows (in millions):
During 2006 we recorded adjustments reducing goodwill by $22.1 million related to the finalization of Varco purchase accounting.
Identified intangible assets with determinable lives consist primarily of customer relationships, trademarks, trade names, patents, and technical drawings acquired in acquisitions, and are being amortized on a straight-line basis over the estimated useful lives of 2-30 years. Amortization expense of identified intangibles is expected to be approximately $60 million in each of the next five years.
Identified intangible assets are identified by segment as follows (in millions):
Identified intangible assets by major classification consist of the following (in millions):
Foreign Currency
The functional currency for most of our foreign operations is the local currency. The cumulative effects of translating the balance sheet accounts from the functional currency into the U.S. dollar at current exchange rates are included in accumulated other comprehensive income. Revenues and expenses are translated at average exchange rates in effect during the period. Certain other foreign operations use the U.S. dollar as the functional currency. Accordingly, financial statements of these foreign subsidiaries are remeasured to U.S. dollars for consolidation purposes using current rates of exchange for monetary assets and liabilities and historical rates of exchange for nonmonetary assets and related elements of expense. Revenue and expense elements are remeasured at rates that approximate the rates in effect on the transaction dates. For all operations, gains or losses from remeasuring foreign currency transactions into the functional currency are included in income. Net foreign currency transaction gains (losses) were ($7.0) million, ($21.0) million and $2.9 million for the years ending December 31, 2007, 2006 and 2005, respectively, and are included in other income (expense) in the accompanying statement of operations.
As previously discussed, effective January 1, 2008, we changed the functional currency of our Rig Technology unit in Norway from the Norwegian Kroner to the U.S. dollar to more appropriately reflect the primary economic environment in which they currently operate.
Revenue Recognition
The Company’s products and services are sold based upon purchase orders or contracts with the customer that include fixed or determinable prices and that do not generally include right of return or other similar provisions or other significant post delivery obligations. Except for certain construction contracts described below, the Company records revenue at the time its manufacturing process is complete, the customer has been provided with all proper inspection and other required documentation, title and risk of loss has passed to the customer, collectibility is reasonably assured and the product has been delivered. Customer advances or deposits are deferred and recognized as revenue when the Company has completed all of its performance obligations related to the sale. The Company also recognizes revenue as services are performed. The amounts billed for shipping and handling cost are included in revenue and related costs are included in costs of sales.
Revenue Recognition under Long-term Construction Contracts
The Company uses the percentage-of-completion method to account for certain long-term construction contracts in the Rig Technology group. These long-term construction contracts include the following characteristics:
•
the contracts include custom designs for customer specific applications;
•
the structural design is unique and requires significant engineering efforts; and
•
construction projects often have progress payments.
This method requires the Company to make estimates regarding the total costs of the project, progress against the project schedule and the estimated completion date, all of which impact the amount of revenue and gross margin the Company recognizes in each reporting period. The Company prepares detailed cost estimates at the beginning of each project. Significant projects and their related costs and profit margins are updated and reviewed at least quarterly by senior management. Factors that
may affect future project costs and margins include shipyard access, weather, production efficiencies, availability and costs of labor, materials and subcomponents and other factors. These factors can impact the accuracy of the Company’s estimates and materially impact the Company’s current and future reported earnings.
The asset, “Costs in excess of billings,” represents revenues recognized in excess of amounts billed. The liability, “Billings in excess of costs,” represents billings in excess of revenues recognized.
Service and Product Warranties
The Company provides service and warranty policies on certain of its products. The Company accrues liabilities under service and warranty policies based upon specific claims and a review of historical warranty and service claim experience in accordance with SFAS 5. Adjustments are made to accruals as claim data and historical experience change. In addition, the Company incurs discretionary costs to service its products in connection with product performance issues and accrues for them when they are encountered.
The changes in the carrying amount of service and product warranties are as follows (in millions):
Income Taxes
The liability method is used to account for income taxes. Deferred tax assets and liabilities are determined based on differences between the financial reporting and tax bases of assets and liabilities and are measured using the enacted tax rates that will be in effect when the differences are expected to reverse. Valuation allowances are established when necessary to reduce deferred tax assets to amounts which are more likely than not to be realized.
Concentration of Credit Risk
We grant credit to our customers, which operate primarily in the oil and gas industry. Concentrations of credit risk are limited because we have a large number of geographically diverse customers, thus spreading trade credit risk. We control credit risk through credit evaluations, credit limits and monitoring procedures. We perform periodic credit evaluations of our customers’ financial condition and generally do not require collateral, but may require letters of credit for certain international sales. Credit losses are provided for in the financial statements. Allowances for doubtful accounts are determined based on a continuous process of assessing the Company’s portfolio on an individual customer and overall basis. This process consists of a thorough review of historical collection experience, current aging status of the customer accounts, and financial condition of the Company’s customers. Based on a review of these factors, the Company will establish or adjust allowances for specific customers and the accounts receivable portfolio as a whole. Accounts receivable are net of allowances for doubtful accounts of approximately $44.8 million and $30.4 million at December 31, 2007 and 2006, respectively.
Stock-Based Compensation
Prior to January 1, 2006, the Company accounted for its stock option plans using the intrinsic value method of accounting provided under APB Opinion No. 25, “Accounting for Stock Issued to Employees,” (“APB 25”) and related interpretations, as permitted by FASB Statement No. 123, “Accounting for Stock-Based Compensation,” (“SFAS 123”) under which no compensation expense was recognized for stock option grants. Stock-based compensation was a pro forma disclosure in the financial statement footnotes and continues to be for periods prior to January 1, 2006.
Effective January 1, 2006, the Company adopted the fair value recognition provisions of FASB Statement No. 123(R), “Share-Based Payment,” (“SFAS 123(R)”) using the modified-prospective transition method. Under this transition method, compensation cost recognized in 2007 includes: a) compensation cost for all share-based payments granted prior to January 1, 2007, but for which the requisite service period had not been completed as of January 1, 2007 based on the grant date fair value estimated in accordance with the original provisions of SFAS 123, and b) compensation cost for all share-based payments granted subsequent to January 1, 2007 based on the grant date fair value estimated in accordance with the provisions of SFAS 123(R).
Prior to the adoption of SFAS 123(R), the Company presented all tax benefits of deductions resulting from the exercise of options as operating cash flows in the Statement of Consolidated Cash Flows. SFAS 123(R) requires the cash flows resulting from tax deductions in excess of the compensation cost recognized for those options (excess tax benefits) to be classified as financing cash flows.
The Company provides compensation benefits to employees and non-employee directors under share-based payment arrangements, including various employee stock option plans.
Total compensation cost that has been charged against income for all share-based compensation arrangements was $43.1 million and $31.2 million for 2007 and 2006, respectively. The total income tax benefit recognized in the income statement for all share-based compensation arrangements was $13.2 million and $8.6 million for 2007 and 2006, respectively.
Pro Forma Net Income
The following table provides pro forma net income and income per share had the Company applied the fair value method of SFAS 123(R) for the year ended December 31, 2005 (in millions, except per share data):
Environmental Liabilities
When environmental assessments or remediations are probable and the costs can be reasonably estimated, remediation liabilities are recorded on an undiscounted basis and are adjusted as further information develops or circumstances change.
Use of Estimates
The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect reported and contingent amounts of assets and liabilities as of the date of the financial statements and reported amounts of revenues and expenses during the reporting period. Such estimates include but are not limited to, estimated losses on accounts receivable, estimated realizable value on excess and obsolete inventory, contingencies, estimated liabilities for litigation exposures and liquidated damages, estimated warranty costs, estimates related to
pension accounting, and estimates related to deferred tax assets and liabilities, including valuation allowances on deferred tax assets. Actual results could differ from those estimates.
Contingencies
The Company accrues for costs relating to litigation claims and other contingent matters, including liquidated damage liabilities, when such liabilities become probable and reasonably estimable. Such estimates may be based on advice from third parties or on management’s judgment, as appropriate. Revisions to contingent liability reserves are reflected in income in the period in which different facts or information become known or circumstances change that affect the Company’s previous assumptions with respect to the likelihood or amount of loss. Amounts paid upon the ultimate resolution of contingent liabilities may be materially different from previous estimates and could require adjustments to the estimated reserves to be recognized in the period such new information becomes known.
Net Income Per Share
The following table sets forth the computation of weighted average basic and diluted shares outstanding (in millions, except per share data):
In addition, we had stock options outstanding that were anti-dilutive totaling 0.1 million at December 31, 2007, 4.6 million at December 31, 2006 and nil at December 31, 2005.
Recently Issued Accounting Standards
In September 2006, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 157, “Fair Value Measurements” (“SFAS 157”). SFAS 157 establishes a framework for fair value measurements in the financial statements by providing a single definition of fair value, provides guidance on the methods used to estimate fair value and increases disclosures about estimates of fair value. SFAS 157 is effective for fiscal years beginning after November 15, 2007. We are currently evaluating the effect, if any, SFAS 157 will have on our financial disclosures as well as our consolidated financial position, cash flows, and results from operations.
In September 2006, the FASB issued SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans - An amendment of FASB Statements No. 87, 88, 106, and 132(R)” (“SFAS 158”). SFAS 158 requires employers to recognize the overfunded or underfunded status of a defined benefit postretirement plan as an asset or liability in its statement of financial position and to recognize changes in that funded status in the year in which the changes occur through comprehensive income of a business entity for fiscal years ending after December 15, 2006. The requirement to measure plan assets and benefit obligations as of the end of the employer’s fiscal year is effective for fiscal years ending after December 15, 2008. The Company adopted the provisions of SFAS 158 recognizing the overfunded or underfunded status of a defined benefit postretirement plan as an asset or liability in the statement of financial position and recognized changes in the funded status in the year in which they occurred through comprehensive income effective December 31, 2006 with no material impact on the Consolidated Financial Statements. We did not elect early adoption of the requirement to measure plan assets and benefit obligations as of our fiscal year end. See Note 10 of the Notes to the Consolidated Financial Statements.
In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities” (“SFAS 159”). SFAS 159 provides entities with an option to measure many financial assets and liabilities and certain other items at fair value as determined on an instrument by instrument basis. The Company has not yet evaluated the impact, if any, this standard might have on the Company’s consolidated financial statements once it becomes effective on January 1, 2008.
In December 2007, the FASB issued SFAS No. 141R, “Business Combinations” (“SFAS 141R”). SFAS 141R provides revised guidance on how acquirers recognize and measure the consideration transferred, identifiable assets acquired, liabilities assumed, noncontrolling interests, and goodwill acquired in a business combination. SFAS 141R also expands required disclosures surrounding the nature and financial effects of business combinations. SFAS 141R is effective, on a prospective basis, for fiscal years beginning after December 15, 2008. The Company does expect that this new standard will impact certain aspects of its accounting for business combinations on a prospective basis, including the determination of fair values assigned to certain purchased assets and liabilities.
In December 2007, the FASB issued SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements” (“SFAS 160”). SFAS 160 establishes requirements for ownership interests in subsidiaries held by parties other than the Company (previously called minority interests) be clearly identified, presented, and disclosed in the consolidated statement of financial position within equity, but separate from the parent’s equity. All changes in the parent’s ownership interests are required to be accounted for consistently as equity transactions and any noncontrolling equity investments in deconsolidated subsidiaries must be measured initially at fair value. SFAS 160 is effective, on a prospective basis, for fiscal years beginning after December 15, 2008. However, presentation and disclosure requirements must be retrospectively applied to comparative financial statements. The Company is currently assessing the impact of SFAS 160 on its consolidated financial position and results of operations.
3. Varco Merger
All share quantities, share ratios, share prices and Black-Scholes assumptions in this footnote are historical and have not been adjusted to reflect the Company’s two-for-one stock split effected as a 100 percent stock dividend in September 2007, unless otherwise noted.
Pursuant to our Amended and Restated Agreement and Plan of Merger with Varco International, Inc. (“Varco”), a Delaware corporation, effective as of August 11, 2004 (the “Agreement Date”), we issued 0.8363 shares of National Oilwell common stock for each Varco common share on March 11, 2005 (the “Merger”) and changed our name to National Oilwell Varco, Inc. We have included the financial results of Varco in our consolidated financial statements beginning March 11, 2005 (the “Merger Date”), the date Varco common shares were exchanged for National Oilwell common shares.
The Merger has been accounted for as a purchase business combination. Assets acquired and liabilities assumed were recorded at their fair values as of March 11, 2005. The total purchase price is $2,579.3 million, including the fair value of Varco stock options assumed and merger related transaction costs, and is comprised of (in millions):
The fair value of shares issued was determined using an average price of $29.99, which represented the average closing price of our common stock from five trading days before to five trading days after the Agreement Date. The fair value of options assumed was calculated using the Black-Scholes valuation model with the following assumptions as of the Merger Date: expected life from vest date ranging from 0.64 years to 3.6 years, risk-free interest rate of 2.0% - 3.1%, expected volatility of 34% to 47% and no dividend yield. In accordance with our Agreement and Plan of Merger, the number of Varco options exchanged was determined by multiplying the number of Varco options outstanding at closing by 0.8363. Approximately 2.2 million of the 4.0 million Varco options outstanding were fully vested as of the Merger. The portion of the intrinsic value of unvested Varco options related to future service has been allocated to unearned compensation cost and is being amortized using the remaining vesting period of 2.3 years. Stock-based compensation expense of $15.6 million related to the amortization of the unvested options was recognized in the year ended December 31, 2005. The $16.5 million of unearned stock-based compensation on the company’s balance sheet at December 31, 2005 was reclassified to paid-in-capital upon the adoption of SFAS 123(R).
Merger related transaction costs include severance and other external costs directly related to the Merger.
Integration costs of $31.7 million in 2005 were comprised of $11.9 million for severance cost, $11.2 million for discontinued inventory, $4.8 million for combining operations and $3.8 million of other. Integration costs of $7.9 million in the first quarter of 2006 were comprised of $6.6 million for discontinued inventory, $0.5 million for combining operations and $0.8 million of other.
Pro Forma Financial Information
The unaudited financial information in the table below summarizes the combined results of operations of National-Oilwell and Varco, on a pro forma basis, as though the companies had been combined as of January 1, 2005. The pro forma financial information is presented for informational purposes only and may not be indicative of the results of operations that would have been achieved if the Merger had taken place at January 1, 2005. The pro forma financial information for the year ended December 31, 2005 includes certain merger-related items of $47.3 million such as charges associated with integration expenses, stock-based compensation charges for unvested options assumed, and severance expenses recorded by National-Oilwell in its statements of operations related to change in control provisions that were triggered as part of our Agreement and Plan of Merger in March 2005. The pro forma financial information includes the business combination accounting effect on historical Varco revenues, adjustments to depreciation on acquired property, and amortization charges from acquired intangible assets, and related tax effects.
The unaudited pro forma financial information below combines the historical results for National-Oilwell for the year ended December 31, 2005 and the historical results for Varco for the year ended December 31, 2005 (in millions):
4. Other Acquisitions
On December 16, 2007, we agreed to combine our wholly-owned subsidiary, NOV Sub, Inc., with Grant Prideco, Inc. by merging Grant Prideco with and into NOV Sub, with NOV Sub continuing as the surviving corporation. Consummation of the merger requires approval by the stockholders of Grant Prideco and also approval from various regulatory agencies. We anticipate completion of the merger will occur in the second quarter of 2008.
The Company completed eight acquisitions for an aggregate purchase price of $286.9 million consisting of cash of $285.8 million and notes payable of $1.1 million. These acquisitions included:
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Gammaloy Holdings, L.P., a Texas-based manufacturer of downhole tools.
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Kreiter Geartech, a Texas-based manufacturer of gearing products.
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Sara Services and Engineers Pvt. Ltd., an India-based manufacturer of oil field equipment.
The following table summarizes the estimated fair values of the assets acquired and liabilities assumed at the date of acquisition of the 2007 acquisitions (in millions):
Based on preliminary independent third-party valuations, the Company allocated $114.2 million to intangible assets (13.1 year weighted-average life), comprised of: $93.9 million of customer relationships (13.0 year weighted-average life), $9.1 million of trademarks (9.3 year weighted-average life), and $11.2 million of other intangible assets (19.5 year weighted-average life). These preliminary valuations are subject to change based on the final valuations by the Company’s independent valuation experts.
In January 2007, the Company also acquired the remaining 13% of NQL Energy Services, Inc.’s outstanding shares for $38.1 million.
In December 2006, the Company acquired 87% of the outstanding shares of NQL Energy Services Inc. (“NQL”), a provider of downhole tools, technology and services used primarily in drilling applications in the oil and gas and utility industries on a worldwide basis, for an aggregate cash purchase price of approximately $253.8 million. Based on independent third-party valuations, the Company allocated $126.6 million to intangible assets (12.1 year weighted-average life), comprised of: $107.5 million of customer relationships (15.5 year weighted-average life), $3.1 million of trademarks (5.2 year weighted-average life), and $16.0 million of other intangible assets (5.5 year weighted-average life). The remaining 13% of NQL’s outstanding shares were acquired in January 2007. Due to this subsequent event, the $38.1 million purchase price of the remaining shares is included in current liabilities on the December 31, 2006 balance sheet. This acquisition complements our comprehensive offering of downhole tools.
The Company also completed nine additional acquisitions for an aggregate purchase price of $85.3 million consisting of cash of $75.9 million and notes and accrued payables of $9.4 million. These acquisitions included:
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Rolligon Ltd., a Texas-based manufacturer of coiled tubing support units and related equipment.
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Soil Recovery A/S, a Danish-based designer and manufacturer of soil recovery units used to process drilled cuttings for final disposal.
The following table summarizes the estimated fair values of the assets acquired and liabilities assumed at the date of acquisition of the 2006 acquisitions (in millions):
Excluding the Varco Merger, the Company paid an aggregate purchase price of $20.7 million ($16.0 million in cash and $4.7 million of notes payable) for acquisitions and equity investments in 2005.
Each of the acquisitions were accounted for using the purchase method of accounting and, accordingly, the results of operations of each business is included in the consolidated results of operations from the date of acquisition. A summary of the acquisitions follows (in millions):
5. Inventories
At December 31, inventories consist of (in millions):
6. Property, Plant and Equipment
At December 31, property, plant and equipment consist of the following (in millions):
7. Accrued Liabilities
At December 31, accrued liabilities consist of (in millions):
8. Costs and Estimated Earnings on Uncompleted Contracts
At December 31, costs and estimated earnings on uncompleted contracts consist of (in millions):
9. Long-Term Debt
At December 31, debt consists of (in millions):
Principal payments of debt for years subsequent to 2007 are as follows (in millions):
Senior Notes
The unsecured Senior Notes contain reporting covenants, and the credit facility contains financial covenants regarding maximum debt to capitalization and minimum interest coverage. We were in compliance with all covenants at December 31, 2007.
Revolver Facilities
On June 21, 2005, we amended and restated our existing $150 million revolving credit facility with a syndicate of lenders to provide the Company a $500 million unsecured revolving credit facility. This facility will expire in July 2010. The Company has
the right to increase the facility by an amount not greater than $250 million, (to $750 million), at any time during the term of this facility, and to extend the term of the facility for an additional year during the final 90 days of the facility. At December 31, 2007, there were no borrowings against this facility, and there were $360 million in outstanding letters of credit. Interest under this multicurrency facility is based upon LIBOR, NIBOR or EURIBOR plus 0.30% subject to a ratings-based grid, or the prime rate.
At December 31, 2007, there were $140 million of funds available under the revolving credit facility. The Company also has $1,352 million of additional outstanding letters of credit at December 31, 2007, primarily in Norway, that are essentially under various bilateral committed letters of credit. The increase in letters of credit is the result of significant down payments from our customers, which in turn require our issuing to our customers advance payment guarantees in the form of letters of credit. Other letters of credit are issued as bid bonds and performance bonds.
Other
Other debt includes approximately $21.6 million in promissory notes due to former owners of businesses acquired who remain employed by the company.
10. Employee Benefit Plans
We have benefit plans covering substantially all of our employees. Defined-contribution benefit plans cover most of the U.S. and Canadian employees, and benefits are based on years of service, a percentage of current earnings and matching of employee contributions. Employees in our Norwegian operations can elect to participate in a defined-contribution plan in lieu of a local defined benefit plan. For the years ended December 31, 2007, 2006 and 2005, expenses for defined-contribution plans were $30.7 million, $16.8 million, and $19.9 million, and all funding is current.
Certain retired or terminated employees of predecessor or acquired companies participate in a defined benefit plan in the United States. None of the participants in this plan are eligible to accrue benefits. In addition, approximately 353 U.S. retirees and spouses participate in defined benefit health care plans of predecessor or acquired companies that provide postretirement medical and life insurance benefits. Active employees are ineligible to participate in any of these defined benefit plans. Our subsidiaries in the United Kingdom and Norway also have defined benefit pension plans covering virtually all of their employees.
Net periodic benefit cost for our defined benefit pension plans in the United States, the United Kingdom and Norway was as follows (in millions):
The change in benefit obligation, plan assets and the funded status of the defined benefit pension plans in the United States, United Kingdom, and Norway and defined postretirement plans in the United States, using a measurement date of September 30, 2007 or 2006, follows (in millions):
Amounts recognized in the consolidated balance sheets consist of (in millions):
Defined Benefit Pension Plans
Assumed long-term rates of return on plan assets, discount rates and rates of compensation increases vary for the different plans according to the local economic conditions.
The assumption rates used for benefit obligations are as follows:
The assumption rates used for net periodic benefit costs are as follows:
In determining the overall expected long-term rate of return for plan assets, the Company takes into consideration the historical experience as well as future expectations of the asset mix involved. As different investments yield different returns, each asset category is reviewed individually and then weighted for significance in relation to the total portfolio.
The weighted-average asset allocations at December 31, 2007 and 2006, by asset category are as follows:
In the U.S., our investment strategy includes a balanced approach with target allocation percentages of 60% equity investments and 40% debt securities. Our target allocation percentages in the United Kingdom plans are 50-60% equity securities and 40-50% debt securities. The Norwegian target investment allocation percentage is 100% insurance contracts. Our pension investment strategy worldwide prohibits a direct investment in our own stock.
Information for pension plans with projected benefit obligations in excess of plan assets (in millions):
Information for pension plans with accumulated benefit obligations in excess of plan assets (in millions):
In 2008, the Company expects to contribute $2.0 million in the U.S. and $6.8 million internationally to its pension plans and $1.3 million to its other postretirement benefit plans.
In addition, the following benefit payments, which reflect expected future service, as appropriate, are expected to be paid (in millions):
11. Accumulated Other Comprehensive Income (Loss)
The components of other comprehensive income (loss) are as follows (in millions):
12. Commitments and Contingencies
We are involved in various claims, regulatory agency audits and pending or threatened legal actions involving a variety of matters. The total liability on these matters at December 31, 2007 cannot be determined; however, in our opinion, any ultimate liability, to the extent not otherwise provided for, should not materially affect our financial position, cash flow or results of operations.
Our business is affected both directly and indirectly by governmental laws and regulations relating to the oilfield service industry in general, as well as by environmental and safety regulations that specifically apply to our business. Although we have not incurred material costs in connection with our compliance with such laws, there can be no assurance that other developments, such as new environmental laws, regulations and enforcement policies thereunder may not result in additional, presently unquantifiable, costs or liabilities to us.
The Company leases certain facilities and equipment under operating leases that expire at various dates through 2049. These leases generally contain renewal options and require the lessee to pay maintenance, insurance, taxes and other operating expenses in addition to the minimum annual rentals. Rental expense related to operating leases approximated $128.4 million, $95.4 million, and $59.1 million in 2007, 2006 and 2005, respectively.
Future minimum lease commitments under noncancellable operating leases with initial or remaining terms of one year or more at December 31, 2007 are payable as follows (in millions):
13. Common Stock
National Oilwell Varco has authorized 500 million shares of $.01 par value common stock. We also have authorized 10 million shares of $.01 par value preferred stock, none of which is issued or outstanding.
On August 22, 2007, the Company’s Board of Directors approved a two-for-one stock split in the form of a stock dividend to the Company’s stockholders of record on September 7, 2007, with distribution of shares on September 28, 2007. The total number of authorized common stock shares and associated par value were unchanged by this action. All per-share amounts in the financial statements reflect the stock split for all periods presented unless indicated otherwise.
Stock Options
Under the terms of National Oilwell Varco’s Long-Term Incentive Plan, as amended, 15 million shares of common stock are authorized for the grant of options to officers, key employees, non-employee directors and other persons. Options granted under our stock option plan generally vest over a three-year period starting one year from the date of grant and expire ten years from the date of grant. The purchase price of options granted may not be less than the closing market price of National Oilwell Varco common stock on the date of grant. At December 31, 2007, approximately 7.0 million shares were available for future grants.
We also have inactive stock option plans that were acquired in connection with the acquisitions of IRI International Corporation in 2000 and Varco International, Inc. in March 2005. We converted the outstanding stock options under these plans to options to acquire our common stock and no further options are being issued or are outstanding under these plans. Stock option information summarized below includes amounts for the National Oilwell Varco Long-Term Incentive Plan and stock plans of acquired companies.
Options outstanding at December 31, 2007 under the stock option plans have exercise prices between $4.53 and $49.07 per share, and expire at various dates from February 11, 2008 to June 6, 2017.
The following summarizes options activity:
The following summarizes information about stock options outstanding as of December 31, 2007:
The weighted-average fair value of options granted during 2007, 2006 and 2005 was approximately $11.99, $11.90 and $8.43 (excluding options assumed in the Varco merger) per share, respectively, as determined using the Black-Scholes option-pricing model. The total intrinsic value of options exercised during 2007 and 2006 was $114.2 million and $49.6 million, respectively.
Upon adoption of SFAS 123(R), we began recording expense related to the value of employee stock options on the date of grant using the Black Scholes model. Prior to the adoption of SFAS 123(R), the value of each employee stock option was estimated on the date of grant using the Black-Scholes model for the purpose of the pro forma financial information in accordance with SFAS 123. The determination of fair value of share-based payment awards on the date of grant using an option-pricing model is affected by our stock price as well as assumptions regarding a number of highly complex and subjective variables. These variables include, but are not limited to, the expected stock price volatility over the term of the awards, and actual and projected employee stock option exercise activity. The use of the Black Scholes model requires the use of extensive actual employee exercise activity data and the use of a number of complex assumptions including expected volatility, risk-free interest rate, expected dividends and expected term.
We used the actual volatility for traded options on our stock since March 11, 2005 (the Varco merger date) as the expected volatility assumption required in the Black Scholes model, which is consistent with SFAS 123(R) and SAB 107. Prior to the first quarter of fiscal 2006, we used our historical stock price volatility in accordance with SFAS 123 for purposes of our pro forma information.
The risk-free interest rate assumption is based upon observed interest rates appropriate for the term of our employee stock options. The dividend yield assumption is based on the history and expectation of dividend payouts. The estimated expected term is based on actual employee exercise activity for the past ten years.
As stock-based compensation expense recognized in the Consolidated Statement of Income in 2007 is based on awards ultimately expected to vest, it has been reduced for estimated forfeitures. SFAS 123(R) requires forfeitures to be estimated at the time of grant and revised, if necessary, in subsequent periods if actual forfeitures differ from those estimates. Forfeitures were estimated based on historical experience.
The following summary presents information regarding outstanding options as of December 31, 2007 and changes during 2007 with regard to options under all stock option plans:
As of December 31, 2007, total unrecognized compensation cost related to nonvested stock options was $60.1 million. This cost is expected to be recognized over a weighted average period of 2.0 years. The total fair value of stock vested in 2007 and 2006 was approximately $33.5 million and $22.1 million, respectively. Cash received from option exercises for 2007 and 2006 was $91.3 million and $32.7 million, respectively. The actual tax benefit realized for the tax deductions from option exercises totaled $34.2 million and $15.2 million, for 2007 and 2006, respectively. Cash used to settle equity instruments granted under all share-based payment arrangements for 2007 and 2006 was not material in both periods.
The impact of adopting SFAS 123(R) on January 1, 2006, on the Company’s income before income taxes, net income and basic and diluted earnings per share for 2007 was not material.
Restricted Shares
During 2007, the Company began issuing restricted stock award (“RSA”) with no exercise price to officers and key employees in addition to stock options. The company granted restricted shares to key employees on March 1, 2007 at $35.23. These shares will not vest until the third anniversary of the date of the grant, at which time they will be 100% vested. The company also granted performance-based restricted shares to senior management and officers on March 26, 2007 at $39.04. Of the total amount of 400,500 performance-based shares granted, 133,500 will be 100% vested 18 months from date of grant, with a performance condition of the Company’s operating income level growth from January 1, 2007 to June 30, 2008 needing to exceed the median operating income level growth of a designated peer group over the same period. The remaining 267,000 performance-based shares will be 100% vested 36 months from date of grant, with a performance condition of the Company’s operating income level growth from January 1, 2007 to December 31, 2009 needing to exceed the median operating income level growth of a designated peer group over the same period.
The following summary presents information regarding outstanding restricted shares as of December 31, 2007, and changes during 2007.
The weighted-average grant day fair value of RSA’s granted during the years ended 2007, 2006 and 2005 was $37.06, nil and $29.13 per share, respectively. There were no RSA’s that vested during years ended 2007, 2006 and 2005. As of December 31, 2007, there was $23.9 million of unrecognized compensation cost related to non-vested RSA which is expected to be recognized over a weighted-average period of 2.0 years.
14. Income Taxes
The domestic and foreign components of income before income taxes were as follows (in millions):
The components of the provision for income taxes consisted of (in millions):
The difference between the effective tax rate reflected in the provision for income taxes and the U.S. federal statutory rate was as follows (in millions):
At December 31, significant components of our deferred tax assets and liabilities were as follows (in millions):
On July 13, 2006, the FASB issued FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes - An Interpretation of FASB No. 109” (“FIN 48”). FIN 48 clarifies the accounting for uncertainty in income taxes recognized in an entity’s financial statements in accordance with FASB Statement No. 109, “Accounting for Income Taxes” and prescribes a recognition threshold and measurement attributes for financial statement disclosure of tax positions taken or expected to be taken on a return. Under FIN 48, the impact of an uncertain income tax position, in management’s opinion, on the income tax return must be recognized at the largest amount that is more-likely-than not to be sustained upon audit by the relevant taxing authority. An uncertain income tax position will not be recognized if it has a less than 50% likelihood of being sustained. Additionally, FIN 48 provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition. FIN 48 became effective January 1, 2007 for the Company. As required, the Company has recorded the cumulative effect of adopting FIN 48 as an adjustment to the January 1, 2007 beginning balance of retained earnings.
The total amount of unrecognized tax benefits as of the date of adoption was $54.5 million. As a result of the implementation of FIN 48, the Company recognized a $9.3 million increase in the liability for unrecognized tax benefits and a $0.6 million increase for accrued interest and penalty which was accounted for as follows (in millions):
A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows (in millions):
Included in the balance of unrecognized tax benefits at January 1, 2007 and December 31, 2007 are $30.5 million and $29.5 million of tax benefits, respectively, that, if recognized in future periods, would impact the Company’s effective tax rate. Also included in the balance of unrecognized tax benefits at January 1, 2007 and December 31, 2007 are $24.0 million and $17.5 million of tax benefits, respectively, that, if recognized, would result in a decrease to goodwill in purchase business combinations. The reduction in the balance of unrecognized tax benefits resulted from the completion in the U.S. of prior year audits and appeals. These unrecognized tax benefits are included in the balance of Accrued Income Taxes in the balance sheet as of December 31, 2007.
The Company does not anticipate that the total unrecognized tax benefits will significantly change due to the settlement of audits or the expiration of statutes of limitation within 12 months of this reporting date.
To the extent penalties and interest would be assessed on any underpayment of income tax, such accrued amounts have been classified as a component of income tax expense in the financial statements. This is an accounting policy election made by the Company that is a continuation of the Company’s historical policy and will continue to be consistently applied in the future. During the year ended December 31, 2007, the Company recognized $2.7 million of additional interest and penalties related to uncertain tax positions as part of income tax expense. As of December 31, 2007, the Company has accrued approximately $4.6 million of interest and penalties relating to unrecognized tax benefits. These interest and penalties are included in the balance of Accrued Income Taxes in the balance sheet as of December 31, 2007.
The Company is subject to taxation in the United States, various states and foreign jurisdictions. The Company has significant operations in the United States, Canada, the United Kingdom, the Netherlands and Norway. Tax years that remain subject to examination by major tax jurisdictions vary by legal entity, but are generally open in the U.S. for the tax years ending after 2003 and outside the U.S. for the tax years ending after 2001. Norway also remains open for the 2001 tax year.
During the quarter ended June 30, 2007 the Internal Revenue Service completed its audit of the Company’s 2003 tax year. There were no adjustments resulting from this examination that will have a material impact on the Company’s financial position, cash flows or results of operations.
In the United States, the Company has $20.3 million of net operating loss carryforwards as of December 31, 2007, which expire at various dates through 2026. The potential benefit of $7.1 million has been recorded with $5.8 million valuation allowance. Future income tax payments will be reduced when the Company ultimately realizes the benefit of these net operating losses. If the Company ultimately realizes the benefit of these net operating loss carryforwards, the valuation allowance of $5.8 million would reduce future income tax expense.
During 2007 the Company recorded $42.5 million in net deferred tax liabilities with a corresponding increase in goodwill related to NQL purchase accounting. During 2006 the Company recorded $32.1 million in deferred tax assets with a corresponding reduction in goodwill related to the finalization of Varco purchase accounting.
Also in the United States, the Company has $0.7 million of excess foreign tax credits as of December 31, 2007, which expire at various dates through 2017. These credits have been allotted a valuation allowance and would be realized as a reduction of future income tax payments. If the Company ultimately realizes the benefit of these excess foreign tax credits, the valuation allowance of $0.1 million would reduce future income tax expense and $0.6 million would reduce goodwill.
Also in the United States, the company has $19.3 million of capital loss carryforwards as of December 31, 2007, which will expire in 2009. The related potential benefit of $6.8 million has been recorded with a valuation allowance of $6.8 million. These capital losses are not available to reduce future operating income but if realized will reduce future capital gains and will result in a reduction of goodwill.
Outside the United States, the company has $3.6 million of net operating loss carryforwards as of December 31, 2007. Of this amount, $3.2 million will expire at various dates through 2016 and $0.4 million is available indefinitely. The related potential benefit available of $1.1 million has been recorded with a valuation allowance of $0.9 million. If the Company ultimately realizes the benefit of these net operating losses, the valuation allowance of $0.9 million would reduce income tax expense.
Also outside the United States, the company has $0.7 million of capital loss carryforwards as of December 31, 2007, which can be carried forward indefinitely. The related potential benefit of $0.2 million has been recorded with a full valuation allowance of $0.2 million. These capital losses are not available to reduce future operating income but if realized will reduce future capital gains and will result in a reduction of future income tax expense.
The deferred tax valuation allowance increased $7.6 million and $4.9 million for the periods ending December 31, 2007 and 2006, respectively. Of the net increase recorded in 2007, $2.5 million was recorded as an increase of income tax expense, $1.7 million was recorded as a decrease in deferred tax assets and $6.8 million was recorded as an increase in goodwill. Of the net increase recorded in 2006, $2.7 was recorded as an increase in income tax expense, $1.6 million was recorded as an increase in deferred tax assets and $0.6 as an increase of goodwill. The increase recorded in 2007 resulted from losses sustained in the U.S. by a subsidiary that reports its taxes separately from the consolidated group and from capital losses obtained in the acquisition of NQL which were originally incurred in the U.S. The increase recorded in 2006 resulted from losses sustained in the U.S. by a subsidiary that reports its taxes separately from the consolidated group.
Undistributed earnings of the Company’s foreign subsidiaries amounted to $1,580.0 million and $1,116.3 million at December 31, 2007 and 2006, respectively. Those earnings are considered to be permanently reinvested and no provision for U.S. federal and state income taxes has been made. Distribution of these earnings in the form of dividends or otherwise could result in either U.S. federal taxes (subject to an adjustment for foreign tax credits) and withholding taxes payable in various foreign countries. Determination of the amount of unrecognized deferred U.S. income tax liability is not practical; however, unrecognized foreign tax credit carryforwards would be available to reduce some portion of the U.S. liability. Withholding taxes of approximately $67.9 million would be payable upon remittance of all previously unremitted earnings at December 31, 2007.
Because of the number of tax jurisdictions in which the Company operates, its effective tax rate can fluctuate as operations and the local country tax rates fluctuate. The Company is also subject to audits by federal, state and foreign jurisdictions which may result in proposed assessments. The Company’s future tax provision will reflect any favorable or unfavorable adjustments to its estimated tax liabilities when resolved. The Company is unable to predict the outcome of these matters. However, we believe that none of these matters will have a material adverse effect on the results of operations or financial condition of the Company.
In October of 2004, the American Jobs Creation Act of 2004 (the “Jobs Act”) was signed into law which introduced a special one-time dividends received deduction on the repatriation of foreign earnings to a U.S. taxpayer (repatriation provision), provided certain criteria are net. The Act provides for a special one-time deduction of 85 percent of certain foreign earnings that are repatriated in either the Company’s last tax year that began before the enactment date, or the first tax year that begins during the one-year period beginning on the date of enactment. The maximum amount of the Company’s foreign earnings that qualify for temporary deduction is $408.2 million. The Company repatriated none of its foreign earnings in 2005 under the repatriation provisions of the Jobs Act.
15. Business Segments and Geographic Areas
The Company’s operations consist of three reportable segments: Rig Technology, Petroleum Services & Supplies and Distribution Services.
Rig Technology: Our Rig Technology Group designs, manufactures, sells and services complete rig systems for the drilling, completion, and remediation of oil and gas wells. The Group offers a comprehensive line of highly-engineered machinery which automates complex well construction and management operations, such as offshore and onshore drilling rigs; pipe racking, rotating and assembly systems; coiled tubing equipment and pressure pumping units; well workover rigs; wireline winches; and cranes.
Petroleum Services & Supplies: Our Petroleum Services & Supplies Group provides a variety of consumable goods and services used to drill, complete, remediate and workover oil and gas wells, and manage pipelines, flowlines and other oilfield tubular goods. The Group manufactures, rents and sells a variety of products and equipment used to perform drilling operations; including solids control systems, drilling motors, rig instrumentation systems, and drilling mud pump consumables.
Distribution Services: Our Distribution Services segment provides maintenance, repair and operating supplies and spare parts to drill site and production locations worldwide. In addition to its comprehensive network of field locations supporting upstream activity throughout North America, the segment supports major land and offshore operations through locations in Mexico, the Middle East, Africa, Europe, Southeast Asia and South America. Distribution Services employs advanced information technologies to provide complete procurement, inventory management and logistics services to its customers around the globe.
The accounting policies of the reportable segments are the same as those described in the summary of significant accounting policies of the Company. The Company evaluates performance of each reportable segment based upon its operating income, excluding non-recurring items.
No single customer accounted for 10% or more of consolidated revenues during the three years ended December 31, 2007.
Summarized financial information is as follows (in millions):
Geographic Areas:
Business Segments:
16. Quarterly Financial Data (Unaudited)
Summarized quarterly results, were as follows (in millions, except per share data):
SCHEDULE II
NATIONAL OILWELL VARCO, INC.
VALUATION AND QUALIFYING ACCOUNTS
Years Ended December 31, 2007, 2006 and 2005
Exhibit Index
2.1
Amended and Restated Agreement and Plan of Merger, effective as of August 11, between National-Oilwell, Inc. and Varco International, Inc. (4).
2.2
Agreement and Plan of Merger, effective as of December 16, 2007, between National Oilwell Varco, Inc., NOV Sub, Inc., and Grant Prideco, Inc. (9)
3.1
Amended and Restated Certificate of Incorporation of National-Oilwell, Inc. (Exhibit 3.1) (1).
3.2
Amended and Restated By-laws of National Oilwell Varco, Inc. (Exhibit 3.1) (10).
10.1
Employment Agreement dated as of January 1, 2002 between Merrill A. Miller, Jr. and National Oilwell. (Exhibit 10.1) (2).
10.2
Employment Agreement dated as of January 1, 2002 between Dwight W. Rettig and National Oilwell, with similar agreement with Mark A. Reese. (Exhibit 10.2) (2).
10.3
Form of Amended and Restated Executive Agreement of Clay C. Williams. (Exhibit 10.12) (3).
10.4
National Oilwell Varco Long-Term Incentive Plan (5)*.
10.5
Form of Employee Stock Option Agreement (Exhibit 10.1) (7)
10.6
Form of Non-Employee Director Stock Option Agreement (Exhibit 10.2) (7).
10.7
Amended and Restated Credit Agreement, dated as of June 21, 2005, among National Oilwell Varco, Inc., the financial institutions signatory thereto, including Wells Fargo Bank, National Association, in their capacities as lenders thereunder, as US administrative agent for the lenders, as Lead Arranger and Sole Book Runner, DnB NOR Bank ASA, as Norwegian Administrative Agent, DnB NOR Bank ASA and the Bank of Nova Scotia as Co-Documentation Agents, and Comerica Bank and JPMorgan Chase Bank, N.A. as Co-Syndication Agents. (Exhibit 10.1) (6).
10.8
Form of Performance-Based Restricted Stock (18 Month) Agreement (Exhibit 10.1) (8).
10.9
Form of Performance-Based Restricted Stock (36 Month) Agreement (Exhibit 10.2) (8).
21.1
Subsidiaries of the Registrant
23.1
Consent of Ernst & Young LLP
24.1
Power of Attorney (included on signature page hereto).
31.1
Certification pursuant to Rule 13a-14a and Rule 15d-14(a) of the Securities and Exchange Act, as amended
31.2
Certification pursuant to Rule 13a-14a and Rule 15d-14(a) of the Securities and Exchange Act, as amended
32.1
Certification pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2
Certification pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.