10-K 1 h65779e10vk.htm FORM 10-K e10vk
Table of Contents

 
 
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(Mark one)
     
þ   ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
FOR THE YEAR ENDED DECEMBER 31, 2008
OR
     
o   TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
Commission file number 1-12317
NATIONAL OILWELL VARCO, INC.
(Exact name of registrant as specified in its charter)
     
Delaware   76-0475815
     
(State or other jurisdiction
of incorporation or organization)
  (IRS Employer
Identification No.)
7909 Parkwood Circle Drive, Houston, Texas 77036-6565
(Address of principal executive offices)

(713) 346-7500
(Registrant’s telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act:
     
Common Stock, par value $.01   New York Stock Exchange
     
(Title of Class)   (Exchange on which registered)
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
Yes þ No o
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15 (d) of the Act.
Yes o No þ
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
Yes þ No o
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
             
Large accelerated filer þ   Accelerated filer o   Non-accelerated filer o   Smaller reporting company o
        (Do not check if a smaller reporting company)    
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No þ
The aggregate market value of voting and non-voting common stock held by non-affiliates of the registrant as of June 30, 2008 was $37.0 billion. As of February 12, 2009, there were 417,375,125 shares of the Company’s common stock ($0.01 par value) outstanding.
Documents Incorporated by Reference
Portions of the Proxy Statement in connection with the 2009 Annual Meeting of Stockholders are incorporated in Part III of this report.
 
 

 


TABLE OF CONTENTS

PART I
ITEM 1. BUSINESS
ITEM 1A. RISK FACTORS
ITEM 1B. UNRESOLVED STAFF COMMENTS
ITEM 3. LEGAL PROCEEDINGS
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
PART II
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
ITEM 6. SELECTED FINANCIAL DATA
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
ITEM 9A. CONTROLS AND PROCEDURES
ITEM 9B. OTHER INFORMATION
PART III
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
ITEM 11. EXECUTIVE COMPENSATION
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
PART IV
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
SIGNATURES
EX-21.1
EX-23.1
EX-31.1
EX-31.2
EX-32.1
EX-32.2


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FORM 10-K
PART I
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 over 800 locations across six continents.
On April 21, 2008 we acquired 100% of the outstanding shares of Grant Prideco, Inc. (“Grant Prideco”) for a combination of $23.20 cash per share and 0.4498 shares of NOV common stock. We have included the financial results of Grant Prideco in our consolidated financial statements beginning on April 21, 2008, the date Grant Prideco common shares were exchanged for National Oilwell Varco common shares and cash. The Grant Prideco operations are included in the Petroleum Services & Supplies segment. We believe the merger with Grant Prideco will advance our strategic goal of providing more products and services to our customers and that Grant Prideco’s product range will add new growth opportunities to us and benefit our customers’ needs worldwide.
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 its 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; rig instrumentation 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 drill pipe, wired drill pipe, transfer pumps, solids control systems, drilling motors, drill bits, reamers and other downhole tools, 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, line pipe, 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.

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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 is determined primarily by the level of drilling, servicing, and oil and gas production activities.
The following table sets forth the contribution to our total revenues of its three operating segments for the years ended December 31, 2008, 2007 and 2006 (in millions):
                         
    Years Ended December 31,  
    2008     2007     2006  
Revenue:
                       
Rig Technology
  $ 7,528.1     $ 5,744.7     $ 3,584.9  
Petroleum Services & Supplies
    4,651.4       3,061.0       2,425.0  
Distribution Services
    1,771.9       1,423.7       1,369.6  
Eliminations
    (520.0 )     (440.4 )     (353.7 )
 
                 
 
                       
Total Revenue
  $ 13,431.4     $ 9,789.0     $ 7,025.8  
 
                 
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. We have 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
See discussion on current worldwide economic environment and related oil and gas activity levels in Item 1A. Risk Factors and Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.
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 11% in 2006, 2% in 2007, and 7% in 2008. 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 2006 and 2007, resulting in higher backlogs for the Company at the end of 2008 compared to the end of 2006 and 2007. Backlog for the Company was at approximately $11.1 billion at December 31, 2008 compared to approximately $9.0 billion and $6.0 billion for December 31, 2007 and 2006, respectively.
In 2008, 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 2008 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.

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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, and (ii) 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.
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; access to external financing; 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, downhole tools and drill pipe 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

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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 (‘BOPs”). 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 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 Rig Technology segment, 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 segment, 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 segment 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 segment 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

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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. The Rig Technology segment 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”). 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

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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.
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. 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,

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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.
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 re-entries 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 “slick line”, 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; 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 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

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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 Rig Technology 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.
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 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 CO 2 , H 2 S 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

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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 — 8000 ä. 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.
Drill Pipe Products. The Company manufactures and sells a variety of drill stem products used for the drilling of oil and gas wells. The principal products sold by this segment are: (1) drill pipe, (2) drill collars and heavyweight drill pipe and (3) drill stem accessories including tool joints. Drill pipe is the principal tool, other than the rig, required for the drilling of an oil or gas well. Its primary purpose is to connect the above-surface drilling rig to the drill bit. A drilling rig will typically have an inventory of 10,000 to 30,000 feet of drill pipe depending on the size and service requirements of the rig. Joints of drill pipe are connected to each other with a welded-on tool joint to form what is commonly referred to as the drill string or drill stem.
When a drilling rig is operating, motors mounted on the rig rotate the drill pipe and drill bit. In addition to connecting the drilling rig to the drill bit, drill pipe provides a mechanism to steer the drill bit and serves as a conduit for drilling fluids and cuttings. Drill pipe is a capital good that can be used for the drilling of multiple wells. Once a well is completed, the drill pipe may be used again in drilling another well until the drill pipe becomes damaged or wears out.
In recent years, the depth and complexity of the wells our customers drill, as well as the specifications and requirements of the drill pipe they purchase, have substantially increased. A majority of the drill pipe we sell is required to meet specifications exceeding minimum American Petroleum Institute (API) standards. We offer a broad line of premium drilling products designed for the offshore, international and domestic drilling markets. Our premium drilling products include our proprietary lines of XT® and TurboTorqueTM connections and 5 7/8-inch drill pipe that delivers hydraulic performance superior to standard 5 1/2-inch drill pipe and weight benefits superior to standard 6 5/8-inch drill pipe.
Drill collars are used in the drilling process to place weight on the drill bit for better control and penetration. Drill collars are located directly above the drill bit and are manufactured from a solid steel bar to provide necessary weight.
Heavyweight drill pipe is a thick-walled seamless tubular product that is less rigid than a drill collar. Heavyweight drill pipe provides a gradual transition between the heavier drill collar and the lighter drill pipe.
We also provide subs, pup joints (short and odd-sized tubular products) and other drill stem accessories. These products all perform special functions within the drill string as part of the drilling process.
IntelliServ. The Company provides well-site data transmission services. IntelliServ’s core product, “The IntelliServ® Network”, was commercialized in February 2006 and incorporates various proprietary mechanical and electrical components into our premium drilling tubulars to allow bi-directional data transfer via the drill string. This network functions at speeds several orders of magnitude higher than current mud pulse and electromagnetic transmission systems and will potentially deliver significant improvements in drilling efficiency and well placement. IntelliServ began its commercial operations in last quarter of 2006 and offers its products and services on a rental basis to oil and gas operators.
Voest-Alpine Tubulars (VAT). VAT is a joint venture between the Company and the Austrian based Voestalpine Group. We have a 50.01% investment in the joint venture which is located in Kindberg, Austria. VAT owns a tubular mill with an annual capacity of approximately 380,000 metric tons and is the primary supplier of green tubes for our U.S. based production. In addition to producing green tubes, VAT produces seamless tubular products for the OCTG market and non-OCTG products used in the automotive, petrochemical, construction, mining, tunneling and transportation industries.
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

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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.
Downhole Tools. The Company 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 Trudrill TM , Vector TM , BlackMax ® , and Prescott TM . This business also maintains a wide variety of motor power sections, including its proprietary rotors and stators marketed under the brand name Mono/Monoflo, 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. Through the acquisition of Grant Prideco in 2008, NOV designs, manufactures and rents the Andergauge brand of downhole tools, which includes variable gauge stabilizers, hydraulically and mechanically actuated under-reamers, and downhole vibration tools. These transactions have expanded NOV’s downhole tools portfolio and increased exposure to directional drilling services.
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 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.
Bit Products. Our Bit Products segment’s products and services are comprised primarily of the operations of ReedHycalog. This segment is a leading global designer, manufacturer and distributor of drill bits, hole-opening or hole enlarging tools, coring services and other related technology to the oil and gas industry. This segment also services its customer base through a technical sales and marketing network in virtually every significant oil and gas-producing region in the world. The drill bit market consists of two product types: fixed-cutter bits and roller-cone bits. We manufacture and sell both product types on a global basis.
We provide fixed-cutter bit types and technology under various brand names including TReX®, Raptorä, SystemMatchedä, Rotary Steerable and many others. One of our most significant drill bit innovations is our TReX and Raptor cutter technology, which significantly increases abrasion resistance (wear life) without sacrificing impact resistance (toughness). This technology provides a

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diamond surface that maintains a sharp, low-wear cutting edge that produces drilling results that exceed conventional standards for PDC bit performance.
ReedHycalog has manufactured roller-cone bits since 1916 and produces roller-cone bits for a wide variety of oil and gas drilling applications. Roller-cone bits consist of three rotating cones that have cutting teeth, which penetrate the formation through a crushing action as the cones rotate in conjunction with the rotation of the drill pipe. This cutting mechanism, while less efficient than fixed-cutter bits, is more versatile in harder formations, or where the geology is changing. We manufacture roller-cone bits with milled teeth and with tungsten carbide insert teeth, which have a longer life in harder formations. We also manufacture a unique patented line of bits using a powder-metal forging technology sold under the brand TuffCutterä. We market our roller-cone products and technology globally under various brand names including RockForce™, Titan™ and TuffCutter™.
ReedHycalog Coring Services provide for the extraction of actual geological formations from a drilled well bore to allow geologists to examine the formations at the surface. One of the coring services utilized at ReedHycalog Coring Services is the Corion Express® system which allows the customer to drill and core a well without tripping pipe. Corion Express utilizes wireline retrievable drilling and coring elements which allow the system to transform from a drilling assembly to a coring assembly and also to wireline retrieve the geological core.
XL Systems. Our XL System’s product line offers the customer an integrated package of large-bore tubular products and services for offshore wells. This product line includes our proprietary line of wedge thread marine connections on large-bore tubulars and related engineering and design services. We provide this product line for drive pipe, jet strings and conductor casing. We also offer weld-on connections and service personnel in connection with the installation of these products. In early 2007, we completed development of our new high-strength Viper™ weld-on connector that we believe will permit us to penetrate traditional markets that do not require the enhanced performance of our proprietary wedge-thread design.

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, 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
The Distribution Services group is a market leader in the provision of supply chain management services to drilling contractors and exploration and production companies around the world. Through its network of over 200 Distribution Service Center locations worldwide, this group stocks and sells a large line of oilfield products including consumable maintenance, repair and operating supplies, valves, fittings, flanges and spare parts that are needed throughout the drilling, completion and production process. The supplies and equipment stocked by our Distribution Service Centers are customized to meet a wide variety of customer demands.
Distribution’s supply chain solutions for customers that choose to outsource the functions of procurement, inventory & warehouse management, logistics, business process, and performance metrics reporting generate a quarter of this group’s revenues. In this solution offering, they leverage the flexible infrastructure of their SAP™ ERP system to streamline the acquisition process from requisition to procurement to payment, by digitally managing approval routing & workflow, and by providing robust reporting functionality.

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NOV RigStore™ is a cutting-edge industry value offering by the Distribution Services group whereby they provide the installation, staffing and management of supply stores on offshore drilling rigs. With the NOV RigStore™ business model, Distribution Services installs its own ERP system onboard in order to access and leverage Distribution’s global inventory, hundreds of support locations, and thousands of vendors across multiple product lines. This business model relieves the average offshore drilling rig’s balance sheet by providing improved accounting of these expense items, lower capital costs, extended payment on part of the driller until the item is actually issued from the onboard supply store, and removed risk of ownership from the customer. Whether it is a smaller, new drilling contractor or larger, established drilling company the benefits of effective supply chain management and reduced total cost of ownership are substantial.
Distribution Services also now provides unique one-stop-shop value propositions in the Exploration and Production market in key areas of artificial lift, measurement & controls, valving & actuation, and flow optimization. Through focused effort, they have built expertise in providing applications engineering, systems & parts integration, optimization solutions, and after-sales service & support in the aforementioned areas. Distribution Services is rapidly diversifying by adding new artificial lift technologies, as well as measurement & controls competencies to become the biggest global provider of equipment and services in the E&P space.
Approximately 70% of the Distribution Services group’s sales in 2008 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. The Distribution Services group has now expanded into oilfields in over 20 countries.
The group works to strategically increase its revenue and enhance its alliances with customers by continuous expansion of product and service solutions and creation of differentiating value propositions. Additionally the group leverages its extensive purchasing power to reduce the cost of the goods. 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.
2008 Acquisitions and Other Investments
In 2008, the Company made the following acquisitions and outside investments:
             
Acquisition   Form   Operating Segment   Date of Transaction
Die Company, Inc.
  Asset   Petroleum Services & Supplies   February 2008 
Welch Power Source, L.L.C.
  Stock   Petroleum Services & Supplies   February 2008 
Hendershot Tool Company
  Stock   Petroleum Services & Supplies   March 2008 
Grant Prideco, Inc.
  Stock   Petroleum Services & Supplies   April 2008 
NOV Fabtech
  Joint Venture   Rig Technology   April 2008 
CKS
  Asset   Petroleum Services & Supplies   April 2008 
Bear Pump & Equipment, Ltd.
  Asset   Petroleum Services & Supplies   August 2008 
Kem-Tron Technologies, Inc.
  Asset   Petroleum Services & Supplies   October 2008 
Sakhalin Outfitters LLC
  Stock   Distribution Services   December 2008 
Mid-South Machine, Inc.
  Stock   Petroleum Services & Supplies   December 2008 
Excluding the Grant Prideco acquisition, the Company paid an aggregate purchase price of $171.7 million, net of cash acquired, ($170.7 million in cash and $ 1.0 million of notes payable) for acquisitions and outside investments in 2008. For the Grant Prideco acquisition, the Company paid an aggregate of $7,198.6 million consisting of $4,135.3 million in stock (56.9 million shares), $2,837.0 million in cash, net of cash acquired and $55.4 million of stock options assumed. See Note 3 of the Notes to the Consolidated Financial Statements for information regarding the Grant Prideco acquisition.
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

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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. 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 oil companies are often made with or through 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 directly 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.

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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, 2008, the Company held a substantial number of United States patents and had several patent applications pending. Expiration dates of such patents range from 2009 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 as important as 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; Manchester and Poole England; Jebel Ali, UAE; and Singapore. Drill Bits are manufactured at facilities in Conroe, Texas; Stonehouse, U.K; and Jurong, Singapore. Drill Stem technology development and drill pipe are manufactured at facilities in Navasota, Texas; Veracruz, Mexico; Turin, Italy; Jurong, Singapore; and Baimi Town, Jiangyan and Jiangsu, China facilities. Solids control equipment and screens are manufactured at facilities in Houston and Conroe, Texas; New Iberia, Louisiana; Aberdeen, Scotland; Nisku, Canada; Trinidad; Shah Alum and Puncak Alam, Malaysia 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 IntelliServ Group manufactures or assembles equipment in Provo, Utah.
The group manufactures tubular inspection equipment and 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 that continued into 2008. During 2008, steel prices stabilized and the Company began to experience some declines in steel prices late in the year. 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, 2007 and 2008 throughout the world to address our

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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 segment 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 defaulted upon by the customer in some instances. 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, 2008, 2007 and 2006 was $11.1 billion, $9.0 billion and $6.0 billion, respectively.
Employees
At December 31, 2008, the Company had a total of 40,205 employees, of which 5,118 were temporary employees. Approximately 179 employees in the Company’s fiberglass tubulars plant in Little Rock, Arkansas, and 140 employees of the Company’s downhole tools product line, are subject to collective bargaining agreements. Additionally, certain of the Company’s employees in various foreign locations are subject to collective bargaining agreements.
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.
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;
 
    level of production from known reserves;
 
    cost of exploring for and producing oil and gas;
 
    level of drilling activity and drilling rig dayrates;
 
    worldwide economic activity;
 
    national government political requirements;
 
    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.

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Volatile oil and gas prices affect demand for our products.
Oil and gas prices have been volatile since 1972. 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. In 2008, oil prices were extremely volatile - oil prices rose to $147 per barrel in July 2008 only to fall into the $35-$45 per barrel range in December 2008. 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 $4.50-12.00 per mmbtu during the last two years. In 2008, spot gas prices continued to be extremely volatile.
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.
Worldwide Financial and Credit Crisis Could Have a Negative Effect on Our Operating Results and Financial Condition.
Recent events have paralyzed credit markets and sparked a serious global banking crisis. Most economists foresee a slow and uncertain recovery of credit markets, given the current global recession. The slowdown in worldwide economic activity caused by the global recession has reduced demand for energy and resulted in lower oil and natural gas prices. Any prolonged reduction in oil and natural gas prices will reduce oil and natural gas drilling activity and result in a corresponding decline in the demand for our products and services, which could adversely impact our operating results and financial condition.
Furthermore, many of our customers access the credit markets to finance their oil and natural gas drilling activity. If the recent crisis and recession reduce the availability of credit to our customers, they may reduce their drilling and production expenditures, thereby decreasing demand for our products and services. Any such reduction in spending by our customers could adversely impact our operating results and financial condition.
There are risks associated with certain contracts for our drilling equipment.
As of December 31, 2008, we had a backlog of approximately $11.1 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 or subject us to contractual penalties:
    our failure to adequately estimate costs for making this drilling equipment;
 
    our inability to deliver equipment that meets contracted technical requirements;
 
    our inability to maintain our quality standards during the design and manufacturing process;
 
    our inability to secure parts made by third party vendors at reasonable costs and within required timeframes;
 
    unexpected increases in the costs of raw materials; and
 
    our inability to manage unexpected delays due to weather, shipyard access, labor shortages or other factors beyond our control.
The Company’s existing contracts for rig equipment carry significant down payment and progress billing terms favorable to the ultimate completion of these projects and generally do not allow customers to cancel projects for convenience. However, unfavorable market conditions or financial difficulties experienced by our customers may result in cancellation of contracts or the delay or abandonment of projects.
Any such developments could have a material adverse effect on our operating results and financial condition.
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. Certain of 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
 
    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 that we will realize 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:
    fluctuations in the oil and gas industry;
 
    competition;
 
    the ability to service the debt obligations of the Company;
 
    the ability to identify strategic acquisitions at reasonable prices;
 
    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, currency restrictions, and trade and economic sanctions.
Approximately 66% of our revenues in 2008 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.
Our operations outside the United States could also expose us to trade and economic sanctions or other restrictions imposed by the United States or other governments or organizations. The U.S. Department of Justice (“DOJ”), the U.S. Securities and Exchange Commission and other federal agencies and authorities have a broad range of civil and criminal penalties they may seek to impose against corporations and individuals for violations of trading sanctions laws, the Foreign Corrupt Practices Act and other federal statutes. Under trading sanctions laws, the DOJ may seek to impose modifications to business practices, including cessation of business activities in sanctioned countries, and modifications to compliance programs, which may increase compliance costs. If any of the risks described above materialize, it could adversely impact our operating results and financial condition.

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We have received federal grand jury subpoenas requesting records related to our exports to and other activities in certain countries. We are cooperating fully with agents from the U.S. Department of Commerce, Bureau of Industry and Security, in responding to the subpoenas. Based on available information, we cannot predict what effect the subpoenas or any resulting government action may have on our financial position or results of operations.
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 sterling and the Norwegian krone. Approximately 66% of our 2008 revenue was derived from sales outside the United States. Because our consolidated financial statements are presented in U.S. dollars, we must translate revenues 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 $3,852.4 million (with a fair value of $2.3 million) as of December 31, 2008 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 or other indefinite lived intangible assets could reduce our earnings.
The Company has approximately $5.2 billion of goodwill and $0.8 billion of other intangible assets with indefinite lives on its consolidated balance sheet as of December 31, 2008. Generally accepted accounting principles require the Company to test goodwill and other indefinite lived intangible assets for impairment on an annual basis or whenever events or circumstances occur indicating that goodwill might be impaired. Events or circumstances which could indicate a potential impairment include (but are not limited to) a significant reduction in worldwide oil and gas prices or drilling; a significant reduction in profitability or cash flow of oil and gas companies or drilling contractors; a significant reduction in worldwide well remediation activity; a significant reduction in capital investment by other oilfield service companies; or a significant increase in worldwide inventories of oil or gas. The timing and magnitude of any goodwill impairment charge, which could be material, would depend on the timing and severity of the event or events triggering the charge and would require a high degree of management judgment. If we were to determine that any of our remaining balance of goodwill or other indefinite lived intangible assets was impaired, we would record an immediate charge to earnings with a corresponding reduction in stockholders’ equity; resulting in an increase in balance sheet leverage as measured by debt to total capitalization.
See additional discussion on “Goodwill and Other Indefinite-Lived Intangible Assets” in Critical Accounting Estimates of Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations. ”
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:
    personal injury or loss of life;
 
    severe damage to or destruction of property; or
 
    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;
 
    strict liability;
 
    breach of contract with customers; or
 
    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:
    we may not be able to continue to obtain insurance on commercially reasonable terms;
 
    we may be faced with types of liabilities that will not be covered by our insurance;
 
    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.

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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.

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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).

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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.

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Table of Contents

     
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.

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Table of Contents

     
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. UNRESOLVED STAFF COMMENTS

None.

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Table of Contents

ITEM 2. PROPERTIES
The Company owned or leased over 800 facilities worldwide as of December 31, 2008, including the following principal manufacturing, service, distribution and administrative facilities:
                             
        Building
Size
  Property
Size
  Owned/   Lease
Termination
Location   Description   (sq/ft)   (acres)   Leased   Date
Rig Technology:
                           
Lanzhou, China
  Mfg. Plant (Drilling Equipment) & Administrative Offices     945,836       44     Building Owned*   10/20/2020
Houston, Texas
  West Little York Manufacturing Facility, Repair, Service, Administrative & Sales Offices     619,000       34     Owned    
Pampa, Texas
  Mfg. Plant     548,000       400     Owned    
Houston, Texas
  Mfg. Plant (Drilling Machinery and Equip)     417,000             Leased   Various
Houston, Texas
  Bammel Facility — Repair, Service, Parts, Administrative & Sales Offices     384,358       18.5     Leased   1/7/2022
Fort Worth, Texas

Cedar Park, Texas
  Coiled Tubing Manufacturing Facility, Warehouse, Administrative & Sales Offices
Instrumentation Manufacturing Facility, Administrative & Sales Offices
    297,000

260,000
      24

40
    Owned

Owned
   
Carquefou, France
  Mfg. Plant (Offshore Equipment)     213,000             Owned    
Houston, Texas
  Mfg. Plant (Braking Systems)     200,000       24     Owned    
Houston, Texas
  Mfg. Plant (Electrical Power Systems)     184,000       11     Owned    
Houston, Texas
  Mfg. Plant (Drilling Rigs and Components)     178,000             Owned    
Kristiansand, Norway
  Mfg. (Drilling and Offshore Equipment)     159,429             Owned    
Aberdeen, Scotland
  Pressure Control Manufacturing, Administrative & Sales     143,859       5     Leased   8/31/2018
Orange, California
  Manufacturing & Office Facility — 759 N. Eckhoff     126,000       9     Building Owned*   4/30/2012
Anderson, Texas
  Rolligon Mfg. Facility, Administrative & Sales Offices     123,000       35     Leased   11/6/2011
Conroe, Texas
  Mfg., Administration & Sales     86,000             Leased   12/31/2021
Houston, Texas
  Manufacturing & Admin. (Lockwood)     81,063             Leased   10/31/2021
Molde, Norway
  Mfg. (Marine Handling Equipment)     78,000             Owned    
Mexicali, Mexico
  Mfg. Plant     76,402             Leased   4/1/2014
Calgary, Canada
  Mfg. (Coiled Tubing and Wireline Units)     76,000             Owned    
Etten-Leur, Netherlands
  Mfg. Plant/Sales (Drilling Equipment)     75,000       6     Owned    
Duncan, Oklahoma
  Nitrogen Units Manufacturing Facility, Warehouse & Offices     67,600       13     Owned    
Houston, Texas
  Brittmore Mfg. Plant (Electrical Power Systems)     66,500       6     Leased   1/31/2011
Aberdeen, Scotland
  Rig Solutions Facility     63,076       3     Leased    
Aberdeen, Scotland
  Systems & Shaffer Sales, Service & Distribution Facility     63,000       6     Owned    
Edmonton, Canada
  Mfg. (Drilling Machinery and Equip.)     61,000             Owned    
Nisku, Canada
  Mfg. (Drilling Machinery and Equip.)     60,000             Owned    
Houston, Texas
  Administrative Offices (Corp Ctr Dr)     51,941             Leased   8/31/2015
Minsk, Belarus
  Coiled Tubing Manufacturing Facility, Administrative & Sales Offices     49,800       1     Leased   10/31/2009
Calgary, Canada
  Coiled Tubing Manufacturing Facility, Administrative & Sales Offices     48,040       5     Owned    
Stavanger, Norway
  Drilling Equipment Work Shop, Warehouse & Customer Service Center     41,333       1     Leased   6/1/2009
Dehradun, India
  Mfg. Plant & Admin. Offices (Unit I)     41,086       2     Owned    

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Table of Contents

                     
        Building
Size
  Property
Size
  Owned/   Lease
Termination
Location   Description   (Sq/Ft)   (Acres)   Leased   Date
Tulsa, Oklahoma
  Pumping Manufacturing Facility, Warehouse & Offices   40,700   4   Leased   12/31/2009
Dehradun, India
  Mfg. Plant & Admin. Offices (Unit II)   37,826   2   Owned    
Singapore
  Wireline Products Manufacturing & Offices   35,300   2   Building Owned*   4/15/2014
Singapore
  Systems Offices, Service & Distribution Facility   35,079   1   Building Owned*   7/1/2040
Orange, California
  Administrative Offices—743 N. Eckhoff   35,000   2   Leased   4/30/2012
Great Yarmouth,
  Coiled Tubing & Nitrogen Units   34,400   2   Leased   8/22/2011
England
  Manufacturing, Administrative & Sales Offices                
Houston, Texas
  Technical College & Training Offices   33,600       Leased   12/1/2017
 
Petroleum Services & Supplies:
                 
Navasota, Texas
  Manufacturing & Admin.   347,000       Owned    
Al Khobar, Saudi Arabia
  Reclamation, Inspection Facility & Offices   340,203   8   Leased   11/30/2010
Houston, Texas
  Sheldon Road: Inspection Facility   335,993   192   Owned    
Veracruz, Mexico
  Manufacturing of tool joints   303,400   42   Leased    
Houston, Texas
  Holmes Road Complex: Manufacturing, Warehouse,   300,000   50   Owned    
 
  Corporate Offices, Coating Manufacturing Plant &                
 
  Pipeline Services                
Little Rock, Arkansas
  Fiberglass Tubular Manufacturing Plant, R&D Lab, Administrative Offices   262,784   44   Owned    
 
                 
Houston, Texas
  Manufacturing, Service, Warehouse & Administrative Offices (WGB)   245,319       Leased   3/31/2018
 
                 
Harbin, China
  Fiberglass Tubular Manufacturing Plant,   260,000   11   Owned    
 
  Administrative Offices                
Conroe, Texas
  Solids Control Manufacturing Facility, Warehouse, Administrative & Sales Offices & Engineering Labs   222,000   37   Owned    
Sand Springs, Oklahoma
  Fiberglass Tubular Manufacturing Plant & Administrative Offices   189,173   7   Owned    
Jebel Ali, Dubai
  Mfg. (Downhole Tools) & Distribution Warehouse   180,000       Leased   1/29/2021
Amelia, Louisiana
  Coating Plant & Inspection Facility   179,574   84   Leased   12/31/2016
Houston, Texas
  QT Coiled Tubing Manufacturing Facility, Warehouse and Offices   172,472   27   Owned    
San Antonio, Texas
  Fiberglass Tubular Manufacturing Plant, R & D Lab, Administrative Offices   170,500   20   Owned    
Houston, Texas
  Coating Plant & Inspection Facility   168,683   49   Owned    
Tulsa, Oklahoma
  Mfg. (Pumps and expendable parts)   165,000       Owned    
Edmonton, Canada
  Mfg. (Downhole Tools)   162,000       Owned    
Wichita, Kansas
  Fiberglass Tubular Manufacturing Plant   129,746   15   Owned    
Su Zhou, China
  Fiberglass Tubular Manufacturing Plant,   125,000   5   Owned    
 
  Administrative Offices                

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Table of Contents

                     
        Building
Size
  Property
Size
 
Owned/
  Lease
Termination
Location   Description   (Sq/Ft)   (Acres)   Leased   Date
Nisku, Canada
  Trucking, Rod Plant, Inspection & Storage Facility   122,398   155   Owned    
McAlester, Oklahoma
  Mfg. (Pumps)   120,000       Owned    
 
Big Spring, Texas
  Fiberglass Tubular Manufacturing Plant &   118,600   12   Owned    
 
  Administrative Offices                
Nisku, Canada
  Coating Plant, Inspection & Drill Pipe Facility   110,990   47   Owned    
Jurong, Singapore
  Manufacturing of roller-cone bits   109,663   5.2   Leased   5/15/2011
Nisku, Canada
  Mfg. Downhole Tools   105,000       Owned    
Amelia, Louisiana
  Coating Plant, Inspection & Storage Facilities   102,000   90   Building Owned*   5/31/2011
Houston, Texas
  Warehouse & Adminsitrative Offices (Portable   91,800       Leased   7/31/2023
 
  Power 4310 NSHP)                
Casper, Wyoming
  Inspection Facility   91,720   29   Owned    
Midland, Texas
  Coating Plant   87,000   25   Owned    
Houston, Texas
  Mfg. (Downhole Tools - Air Center)   91,295       Leased   9/30/2022
Houston, Texas
  Highway 90: Coating Plant   83,000   43   Leased   7/31/2011
Aberdeen, Scotland
  Solids Control Manufacturing Facility Assembly,   77,400   6   Owned    
 
  Administrative & Sales                
Houston, Texas
  Engineering/Technical Research Center   76,000   6   Owned    
Stonehouse, UK
  Manufacturing of fixed-cutter bits   71,000       Owned    
Bogota, Colombia
  Solids Control & Inspection Yard & Warehouse   69,966       Leased    
 
Conroe, Texas
  Manufacturing, Warehouse & Admin.   67,000   35   Owned    
Navasota, Texas
  Coating Plant, Inspection Pipe Storage   65,000       Building Owned*   6/30/2013
Marble Falls, Texas
  Mfg. (Expendable parts)   65,000       Owned    
Stafford, Texas
  Mfg. and Service of Downhole tools   65,000       Owned    
Leduc, Canada
  MDT, Shaffer, Chimo, Alberta Instruments, Varco Services & Warehouse Facility   64,056   5   Owned    
Gladbeck, Germany
  Coating Plant   68,641   4   Owned    
Turin, Italy
  Manufacturing of tool joints   60,400       Owned    
Lone Star, Texas
  Inspection Facility   56,700   80   Owned    
Neiva, Colombia
  Inspection Yard & Warehouse   54,898   1   Leased   2/1/2009
 
Aberdeen, Scotland
  Inspection Facility, Coating Plant,   53,425   10   Owned    
 
  Manufacturing, Administrative & Sales                
Coevorden, Netherlands
  Inspection Reclamation & Repair Facility   53,361   2   Leased   12/4/2009
Harvey, Louisiana
  Coating Plant & Inspection Facility   53,000   7   Owned & Leased   1/31/2011
Lockport, Louisiana
  Office & Warehouse (Generator Rentals)   52,000       Leased   6/30/2016
Houston, Texas
  Mfg. (Pumps and expendable parts)   51,000       Leased   12/31/2010
Tuas, Singapore
  Inspection Facility   50,644   8   Building Owned*   6/9/2019
Houston, Texas
  Mfg. (Rotors, Starters & Artificial Lifts)   50,000       Owned    
Baimi Town, Jiangyan,
  Manufacturing of drill pipe   49,428       Leased   12/31/2013
Jiangsu China
                   

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Table of Contents

                     
        Building
Size
  Property
Size
  Owned/   Lease
Termination
Location   Description   (Sq/Ft)   (Acres)   Leased   Date
Houston, Texas
  Warehouse (Pumps and expendable parts)   48,000       Leased   7/31/2016
Odessa, Texas
  Coating Plant & Inspection Facility   45,332   10   Owned    
 
Little Rock, Arkansas
  Fiberglass Tubular Manufacturing Plant   45,000   1.5   Leased   10/1/2009
 
Hebei, China
  Coating Plant   45,000   13   Leased   4/26/2025
Berlaimont, France
  Coating Plant   44,000   16   Owned    
Celle, Germany
  Inspection Facility, Administrative & Engineering Offices   43,560   12   Building Owned*    
Casper, Wyoming
  Inspection Facility   41,030   40   Owned    
Edmond, Oklahoma
  Coating Plant   40,000   19   Owned    
Farmington, New Mexico
  Inspection Storage Facilities   37,725   50   Leased   3/31/2014
Oklahoma City, Oklahoma
  Inspection Facility   36,000   21   Owned    
Macae, Brazil
  Inspection Yard & Rig Service Facility   34,445   5   Owned    
Odessa, Texas
  Inspection Facility   33,910   50   Owned    
Edmonton, Canada
  Oilwell Engine Reclamation   32,550   10   Leased   4/30/2013
Yopal, Colombia
  Inspection and Solids Control   27,674   5   Owned    
 
  Warehouse & Storage                
 
Distribution:
                   
Manchester, England
  Mfg. (Pumps and expendable parts)   244,000       Owned    
Houston, Texas
  Distribution and Warehouse   124,000       Building Owned*   12/31/2021
Edmonton, Canada
  Redistribution Center   100,000       Leased   1/31/2014
Lloydminster, Canada
  Applied Products Facility   110,000       Leased   5/31/2019
 
Corporate:
                   
Houston, Texas
  Corporate Administrative Offices   196,589       Leased   12/1/2017
Houston, Texas
  Administrative Offices (Beechnut)   140,430       Leased   5/31/2017
Houston, Texas
  Administrative Office (Westchase)   125,494       Leased   9/30/2020
Houston, Texas
  Administrative Offices (Greenspoint)   47,536       Leased   7/31/2015
 
*   Building owned but land leased.
We own or lease 159 repair and manufacturing facilities that refurbish and manufacture new equipment and parts, and approximately 212 distribution service centers, and 442 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. 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. 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, 2008.

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Table of Contents

PART II
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.
                                 
    2008   2007
    High   Low   High   Low
First quarter
  $ 76.81     $ 51.49     $ 39.36     $ 27.00  
Second quarter
    91.55       60.17       54.47       39.10  
Third quarter
    90.43       45.61       73.67       51.56  
Fourth quarter
    47.06       17.86       79.28       63.09  
As of February 12, 2009, there were 2,828 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 2009.
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.

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Table of Contents

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, 2003 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.
(PERFORMANCE GRAPH)
                                                                 
 
        12/03     12/04     12/05     12/06     12/07     12/08  
 
National Oilwell Varco, Inc.
      100.00         157.83         280.41         273.61         657.07         218.60    
 
S&P 500
      100.00         110.88         116.33         134.70         142.10         89.53    
 
S&P Oil & Gas Equipment & Services
      100.00         131.87         195.90         226.35         334.76         136.66    
 
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).

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Table of Contents

ITEM 6. SELECTED FINANCIAL DATA
                                         
    Years Ended December 31,  
    2008 (1)     2007     2006     2005 (2)     2004  
            (in millions, except per share data)          
Operating Data:
                                       
Revenue
  $ 13,431.4     $ 9,789.0     $ 7,025.8     $ 4,644.5     $ 2,318.1  
Operating profit
    2,917.5       2,044.4       1,111.1       476.8       176.0  
Income before taxes
    2,961.3       2,028.9       1,049.2       430.0       138.9  
Net income
  $ 1,952.0     $ 1,337.1     $ 684.0     $ 286.9     $ 115.2  
 
                             
 
                                       
Net income per share
                                       
Basic
  $ 4.91     $ 3.77     $ 1.95     $ 0.92     $ 0.67  
 
                             
Diluted
  $ 4.90     $ 3.76     $ 1.93     $ 0.91     $ 0.67  
 
                             
 
                                       
Other Data:
                                       
Depreciation and amortization
  $ 401.6     $ 214.1     $ 160.6     $ 114.6     $ 44.0  
Capital expenditures
  $ 378.5     $ 251.8     $ 200.4     $ 105.0     $ 39.0  
 
                                       
Balance Sheet Data:
                                       
Working capital
  $ 4,033.7     $ 3,567.1     $ 2,300.4     $ 1,811.0     $ 711.0  
Total assets
  $ 21,478.7     $ 12,114.9     $ 9,019.3     $ 6,678.5     $ 2,576.5  
Long-term debt, less current maturities
  $ 869.6     $ 737.9     $ 834.7     $ 835.6     $ 350.0  
Stockholders’ equity
  $ 12,627.6     $ 6,661.4     $ 5,023.5     $ 4,194.2     $ 1,270.2  
 
(1)   Financial results of Grant Prideco, Inc. (“Grant Prideco”) have been included in our consolidated financial statements beginning April 21, 2008, the date the Grant Prideco merger was completed and each of Grant Prideco’s common shares were exchanged for .4498 shares of our common stock and $23.20 in cash. Financial information for prior periods and dates may not be comparable with 2008 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 Grant Prideco merger and related adjusted financial information.
 
(2)   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. 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.

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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 over 800 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:
                                         
                            %   %
                            2008 v   2008 v
    2008*   2007*   2006*   2007   2006
Active Drilling Rigs:
                                       
U.S.
    1,878       1,767       1,648       6.3 %     14.0 %
Canada
    379       344       470       10.2 %     (19.4 %)
International
    1,079       1,005       925       7.4 %     16.6 %
 
                                       
Worldwide
    3,336       3,116       3,043       7.1 %     9.6 %
 
                                       
West Texas Intermediate
                                       
Crude Prices (per barrel)
  $ 99.63     $ 72.33     $ 66.00       37.7 %     51.0 %
 
                                       
Natural Gas Prices ($/mmbtu)
  $ 8.86     $ 6.97     $ 6.74       27.1 %     31.5 %
 
*   Averages for the years indicated. See sources below.

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The following table details the U.S., Canadian, and international rig activity and West Texas Intermediate Oil prices for the past nine quarters ended December 31, 2008 on a quarterly basis:
(BAR GRAPH)
Source: Rig count: Baker Hughes, Inc. (www.bakerhughes.com); West Texas Intermediate Crude Price: Department of Energy, Energy Information Administration (www.eia.doe.gov).
The average price per barrel of West Texas Intermediate Crude reached historic heights in 2008, peaking at just over $147 per barrel in July. The 2008 average price for the year was the highest annual average oil price at $99.63 per barrel, an increase of 37.7% over the average price for 2007. Average natural gas prices were $8.86 per mmbtu, an increase of 27.1% compared to the 2007 average. Higher oil prices led to stronger rig activity worldwide, increasing 7.1% for the full year in 2008 compared to 2007. Although the yearly average for 2008 increased over 2007, during the second half of 2008, prices began to decrease as well as rig count. Average crude oil prices for the fourth quarter of 2008 was $58.18 per barrel and natural gas was $6.40 per mmbtu.
At January 30, 2009, there were 1,472 rigs actively drilling in the U.S., compared to 1,721 rigs at December 26, 2008; a decline of 14.5% from year-end 2008 levels. In addition, the price of oil and gas had dropped to $41.73 per barrel and $4.84 per mmbtu, respectively, at January 30, 2009 representing 6.4% (oil) and 14.0% (gas) declines from the end of 2008.

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Executive Summary
National Oilwell Varco generated earnings of $2.0 billion or $4.90 per fully diluted share in 2008, on revenues of $13.4 billion. Earnings per share increased 30 percent and revenue increased 37 percent from the Company’s 2007 earnings and revenues, respectively, due in part to our acquisition of Grant Prideco, Inc., discussed below. Operating income was $2.9 billion or 22 percent of sales for the year, including charges of $110.6 million before tax or $0.18 per share after-tax related to the acquisition. Excluding these transaction related charges earnings would have been $5.08 per diluted share for the year, an increase of 35 percent.
Grant Prideco Acquisition
On April 21, 2008 the Company completed its acquisition of Grant Prideco, Inc. for a combination of approximately $3.0 billion in cash and the issuance of 56.9 million shares of National Oilwell Varco common stock. The Grant Prideco merger further strengthened National Oilwell Varco’s position as manufacturer to the oilfield. Its drill bits and reamers are being integrated into the Company’s offering of drilling motors, non-magnetic drill collars, jars and shock tools, to complement its comprehensive package of bottomhole assembly tools used to drill complex wellpaths. Additionally, Grant Prideco’s drillpipe products are purchased and consumed by the Company’s existing drilling contractor customer base. The Company believes that consumption of drillpipe per foot of hole drilled, or per rig running, has been increasing due to the rising complexity of wellpath designs. Overall the acquisition better positioned National Oilwell Varco to capitalize on continued application of horizontal, directional and extended-reach drilling, through both drillpipe and drill bit product sales. Integration of the business has proceeded well. The Company is introducing new drillpipe tracking products, and expanding OEM drillpipe repair and maintenance offerings through its worldwide network of pipe service operations. The Company is also consolidating of a number of bit and downhole tool sales facilities worldwide, and leveraging combined manufacturing and marketing capabilities.
Oil & Gas Equipment and Services Market
Worldwide developed economies turned down sharply late in 2008 as looming housing-related asset write-downs at major financial institutions paralyzed credit markets and sparked a serious global banking crisis. Major central banks are responding vigorously, but credit and financial markets have not yet recovered, and a credit-driven worldwide economic recession is in full force. Asset and commodity prices, including oil and gas prices, have declined sharply. After rising steadily for six years to peak at around $147 per barrel in July 2008, oil prices collapsed back to the $35 to $50 per barrel range recently. Higher oil and gas prices over the past several years have led to high levels of exploration and development drilling in many oil and gas basins around the globe, but this is slowing, at least in the near term. The count of rigs actively drilling in the U.S. as measured by Baker Hughes (a good measure of the level of oilfield activity and spending) peaked at 2,031 rigs on September 12, 2008, but has decreased to 1,399 rigs as of February 6, 2009, as a result of the lower commodity prices and tight credit. Many oil and gas operators reliant on external financing to fund their drilling programs are curtailing some of their drilling activity in view of tighter credit markets and lower commodity prices. So far this appears to be having the greatest impact on gas drilling across North America. Most international activity is driven by oil exploration and production by national oil companies, which has historically been less susceptible to short-term commodity price swings. Therefore we expect international drilling activity to be less impacted by the credit crisis, but the international rig count may show some declines nonetheless. The Company believes its Petroleum Services & Supplies segment and its Distribution Services segment will be affected by a drilling downturn first and most acutely, while the Company’s Rig Technology segment would largely be less impacted in the short term owing to its high level of backlog.
Recent downturns follow an extended period of high drilling activity which fueled strong demand for oilfield services since 2003. Incremental drilling activity through the upswing shifted toward harsh environments, employing 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. 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. 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.
The industry responded by launching many new rig construction projects since 2005, to retool the existing fleet of jackup rigs (349 of the existing 440 jackup rigs are more than 20 years old); to replace older mechanical and DC electric land rigs with improved AC power, electronic controls, automatic pipe handling and rapid rigup and rigdown technology; and to build out additional ultradeep floating drilling rigs, including semisubmersibles and drillships, to employ recent advancements in deepwater drilling to exploit unexplored deepwater basins. 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. As a result of these trends the Company’s Rig Technology segment grew

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its backlog of capital equipment orders from $0.9 billion at March 31, 2005, to $11.1 billion at December 31, 2008. However, as a result of the credit crisis and slowing drilling activity, the backlog declined six percent from its third quarter 2008 peak of $11.8 billion. This was the first decline since National Oilwell and Varco merged in 2005. The Company expects the backlog to decline during 2009 as revenue out of backlog is likely to exceed inbound new orders.
The land rig backlog comprised 14 percent and equipment destined for offshore operations comprised 86 percent of the total backlog as of December 31, 2008. Equipment destined for international markets totaled 90 percent of the backlog. The Company believes that its existing contracts for rig equipment are strong in that they carry significant down payment and progress billing terms favorable to the ultimate completion of these projects, and generally do not allow customers to cancel projects for convenience. For this reason we do not expect the credit crisis or softer market conditions to result in material cancelations of contracts or abandonment of major projects; however, there can be no assurance that such discontinuance of projects will not occur, particularly if the credit crisis or economic downturn deepens significantly.
Segment Performance
Rig Technology generated $7.5 billion in revenue and $2.0 billion in operating profit in 2008, yielding an operating margin of 26.2%. The group generated 32 percent operating leverage or flowthrough (the increase in operating profit divided by the increase in revenue) on 31 percent revenue growth from 2007. As of December 31, 2008 the scheduled outflow of revenue from backlog is expected to be in the range of $1.3 billion per quarter in 2009, or $5.3 billion for the full year. Non-backlog revenue for the segment totaled $2.2 billion or 29.6 percent of the segment total for 2008. From 2005 through the end of 2008, the segment has delivered a total of 41 newly built offshore rigs.
The Petroleum Services & Supplies segment generated revenues of $4.7 billion and operating profit of $1.0 billion in 2008, which included only a partial year contribution from the acquired Grant Prideco businesses. On an adjusted basis for a full year contribution of Grant Prideco, Inc., including estimated fixed asset and intangible asset stepup impact but excluding transaction charges and inventory step up amortization, the segment generated $5.3 billion in revenue and $1.3 billion in operating profit, yielding an operating margin of 24.4 percent. Operating profit leverage or flowthrough from 2007, on the same adjusted basis, was 35 percent on six percent sales growth. North America accounted for approximately 57.5 percent of Petroleum Services & Supplies segment revenues during the year.
Distribution Services segment revenues were $1.8 billion during 2008, an increase of 24 percent from the prior year. Operating profit was $129.7 million or 7.3 percent of sales, and operating profit leverage or flowthrough was 10 percent from the prior year. The U.S. accounted for about 57 percent of the segment’s 2008 revenues overall, and Canadian sales accounted for about 18.2 percent of the 2008 mix. International sales benefitted from a number of expansion initiatives in new geographic markets undertaken in 2008 and prior, and total international sales were approximately 24.8 percent of the mix in 2008. Included in these initiatives were the Company’s unique rig store concept.
Outlook
The recent emergence of a serious banking crisis, a global recession, and lower commodity prices are presenting increasingly challenging prospects to our business. Consequently we are cautious in our outlook for 2009, and believe we will see orders for new rigs fall by half or more in 2009. Drilling activity, particularly by independent gas producers reliant on external financing, will likely continue to decline through at least the first half of the year.
As a result our outlook for the Company’s Petroleum Services & Supplies segment and Distribution Services segment remains very guarded. We expect revenues for both groups to decline sharply in the first quarter, due mostly to North American drilling activity declines, and we are uncertain when they may recover to prior levels. Decremental leverage for both groups is expected to be above our long term estimated levels (30 percent for Petroleum Services & Supplies; 10 percent for Distribution Services) due to rising pricing pressure we are experiencing, particularly in North America. Our outlook for international markets, which are more driven by national oil company activity, are historically less volatile and expected to see better market conditions. The Rig Technology segment is expected to be less affected by the downturn due to the strength of its backlog.
The Company is nevertheless well positioned to manage through this uncertain period, and should benefit from its strong balance sheet and capitalization, access to credit, and a high level of contracted orders which are expected to continue to generate good earnings well into the downturn. The Company has a long history of cost-control and downsizing in response to depressed market conditions, and of executing strategic acquisitions during difficult periods. Steel prices have begun to decline in many areas, and the Company is reducing outsourcing, overtime, and discretionary expenditures in view of the market. Such a period may present opportunities to the Company to effect new organic growth and acquisition initiatives, and we remain hopeful that a downturn will generate new opportunities.

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Results of Operations
Years Ended December 31, 2008 and December 31, 2007
The following table summarizes the Company’s revenue and operating profit by operating segment in 2008 and 2007. The actual results include results from Grant Prideco operations from the acquisition date of April 21, 2008 (in millions):
                                 
    Years Ended December 31,     Variance  
    2008     2007     $     %  
Revenue:
                               
Rig Technology
  $ 7,528.1     $ 5,744.7     $ 1,783.4       31.0 %
Petroleum Services & Supplies
    4,651.4       3,061.0       1,590.4       52.0 %
Distribution Services
    1,771.9       1,423.7       348.2       24.5 %
Eliminations
    (520.0 )     (440.4 )     (79.6 )     18.1 %
 
                       
Total Revenue
  $ 13,431.4     $ 9,789.0     $ 3,642.4       37.2 %
 
                       
 
                               
Operating Profit:
                               
Rig Technology
  $ 1,969.5     $ 1,393.6     $ 575.9       41.3 %
Petroleum Services & Supplies
    1,043.9       731.6       312.3       42.7 %
Distribution Services
    129.7       94.0       35.7       38.0 %
Unallocated expenses and eliminations
    (225.6 )     (174.8 )     (50.8 )     29.1 %
 
                       
Total Operating Profit
  $ 2,917.5     $ 2,044.4     $ 873.1       42.7 %
 
                       
 
                               
Operating Profit %:
                               
Rig Technology
    26.2 %     24.3 %                
Petroleum Services & Supplies
    22.4 %     23.9 %                
Distribution Services
    7.3 %     6.6 %                
 
                           
Total Operating Profit %
    21.7 %     20.9 %                
 
                           
Rig Technology
Rig Technology revenue for the year ended December 31, 2008 was $7,528.1 million, an increase of $1,783.4 million (31.0%) compared to 2007. Revenue out of backlog increased $1,216.5 million or 29.8% from 2007 due to the growing market for capital equipment, as evidenced by backlog growth during the first three quarters of 2008. The increase in orders and backlog resulted from continued capital investments by drilling contractors in 2008, primarily related to the international offshore market. Non-backlog revenue increased $566.9 million or 34.1% over 2007, largely due to increased spare parts sales and service revenues related to the increased drilling activity during the year.
Operating profit from Rig Technology was $1,969.5 million for the year ended December 31, 2008, an increase of $575.9 million (41.3%) over the same period of 2007. The increase in operating profit was largely due to the increased activity discussed above as well as improved pricing on large rig contracts and after market products.
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 $11.1 billion at December 31, 2008, an increase of $2.1 billion (23.3%) over backlog of $9.0 billion at December 31, 2007. Approximately $5.2 billion of the current backlog is expected to be delivered in 2009.
Petroleum Services & Supplies
Revenue from Petroleum Services & Supplies was $4,651.4 million for 2008 compared to $3,061.0 million for 2007, an increase of $1,590.4 million (52.0%). The increase was mostly attributable to the acquisition of Grant Prideco, Inc. which contributed sales of $1,434.9 million since the acquisition date of April 21, 2008. Higher demand for most of the products and services offered by the segment also contributed to the higher revenue compared to 2007. Rig count in North America and international markets during 2008 were up 6.9% and 7.3% respectively compared to 2007 averages, prompting higher demand from our services group.
Operating profit from Petroleum Services & Supplies was $1,043.9 million for 2008 compared to $731.6 million for 2007, an increase

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of $312.3 million (42.7%). Grant Prideco, Inc. contributed $296.9 million of operating profit since April 21, 2008. Included in the Grant Prideco operating profit was $89.1 million of expense recorded in cost of revenue that resulted from the fair value step up of inventory as part of the purchase accounting valuation of Grant Prideco. The increase was also attributable to higher profitability across most product lines.
Distribution Services
Revenue from Distribution Services totaled $1,771.9 million, an increase of $348.2 million (24.5%) 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 7.1% in 2008 compared to 2007, with increases of 10.3%, 7.3% and 6.3% in Canada, international and the U.S. rig activity, respectively. The Company’s Distribution Services segment continued efforts to expand in international markets resulted in a 25% increase in international revenue. The expansion primarily consisted of opening rig stores or facilities that maintain levels of consumables used on rigs, in centrally located areas. In addition, the Company has begun to open stores on individual rigs. After opening its first rig store in 2007, the Company opened eight additional stores during 2008 continuing the efforts to expand its presence both in the U.S. and internationally.
Operating income increased in 2008 to $129.7 million compared to $94.0 million in 2007. Margins increased slightly to 7.3% of revenue in 2008 compared to 6.6% of revenue in 2007. The increase in margin was primarily due to the cost reduction actions taken in Canada to offset the weakening demand seen in the later part of 2007 combined with the increase in profit margins from international locations.
Unallocated expenses and eliminations
Unallocated expenses and eliminations were $225.6 million for the year ended December 31, 2008 compared to $174.8 million for 2007. The increase in unallocated expenses and eliminations was primarily due to greater inter-segment profit eliminations and greater stock-based compensation expense. The stock-based compensation expense was $60.8 million and $43.1 million for the years ended December 31, 2008 and 2007, respectively. The 2008 results also included $10.9 million of integration costs related to the 2008 acquisition of Grant Prideco, Inc.
Interest and financial costs
Interest and financial costs were $67.3 million for 2008 compared to $50.3 million for 2007. The increase was primarily due to the borrowings related to the merger with Grant Prideco, Inc.
Equity Income in Unconsolidated Affiliate
Equity income in unconsolidated affiliate was $42.4 million for 2008 and was related to the April 21, 2008 acquisition of Grant Prideco. The income was related to the equity earnings from the Company’s 50.01% investment in Voest-Alpine Tubulars (“VAT”) located in Kindberg, Austria. The Company’s investment in VAT is accounted for under the equity method of accounting due to the minority owner having substantive participating rights. Step-up depreciation and amortization of $7.5 million was recorded in 2008 related to VAT and charges of $10.6 million were recorded related to inventory step-up.
Other income (expense), net
Other income (expense), net was an income, net of $24.1 million and an expense of $17.8 million for the years ended December 31, 2008 and December 31, 2007, respectively. The 2008 income was primarily due to a net foreign exchange gain which was $50.2 million for the year ended December 31, 2008, as compared to a net foreign exchange loss of $7.0 million for the year ended December 31, 2007. The 2008 foreign exchange gains were primarily due to the weakening of the British pound sterling, Canadian dollar and Norwegian kroner compared to the U.S. dollar. See Item 7A. “Quantitative and Qualitative Disclosures About Market Risk” Foreign Currency Exchange Rates.
Provision for income taxes
The effective tax rate for the year ended December 31, 2008 was 33.5% compared to 33.3% for 2007. The 2008 rate reflects increasing benefits in the U.S. from the tax incentive for manufacturing activities and a higher percentage of earnings in foreign jurisdictions with lower tax rates. This was partially offset by additional tax provisions related to the Company’s decision to repatriate earnings from certain foreign subsidiaries during the year and net higher tax expense in Norway related to movement in exchange rates after the change of the functional currency to the U.S. dollar. The net additional tax expense in Norway included a $45.8 million charge resulting from realized foreign exchange gains on U.S. dollar denominated assets and liabilities. This was partially offset by a $30.3 million benefit for the same period, which was reported as provision for income tax, from the remeasurement into U.S. dollars

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of foreign currency denominated deferred tax assets and liabilities in the balance sheet.
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).
                                 
    Years Ended December 31,     Variance  
    2007     2006     $     %  
Revenue:
                               
Rig Technology
  $ 5,744.7     $ 3,584.9     $ 2,159.8       60.2 %
Petroleum Services & Supplies
    3,061.0       2,425.0       636.0       26.2 %
Distribution Services
    1,423.7       1,369.6       54.1       4.0 %
Eliminations
    (440.4 )     (353.7 )     (86.7 )     24.5 %
 
                       
Total Revenue
  $ 9,789.0     $ 7,025.8     $ 2,763.2       39.3 %
 
                       
 
                               
Operating Profit:
                               
Rig Technology
  $ 1,393.6     $ 608.5     $ 785.1       129.0 %
Petroleum Services & Supplies
    731.6       545.6       186.0       34.1 %
Distribution Services
    94.0       94.0             0.0 %
Unallocated expenses and eliminations
    (174.8 )     (137.0 )     (37.8 )     27.6 %
 
                       
Total Operating Profit
  $ 2,044.4     $ 1,111.1     $ 933.3       84.0 %
 
                       
 
                               
Operating Profit %:
                               
Rig Technology
    24.3 %     17.0 %                
Petroleum Services & Supplies
    23.9 %     22.5 %                
Distribution Services
    6.6 %     6.9 %                
 
                           
Total Operating Profit %
    20.9 %     15.8 %                
 
                           
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.

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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. “Quantitative and Qualitative Disclosures About Market Risk” Foreign Currency Exchange Rates.
Provision for income taxes
The effective tax rate for the year ended December 31, 2007 was 33.3% compared to 33.9% for 2006. The lower 2007 tax rate was due primarily to a higher percentage of earnings in foreign jurisdictions with lower tax rates, favorable resolution of uncertain tax positions associated with prior years and increased tax benefits in the U.S. from manufacturing activities. These benefits were partially offset by increased state income tax in the U.S. from the new Texas Margins tax, incremental U.S. tax on repatriated foreign earnings and the loss of tax benefits in the U.S. associated with export sales in 2006 that was fully terminated for 2007. The U.S. laws granting this export tax benefit were modified as part of the American Jobs Creation Act of 2004 and this benefit is no longer available. A new tax benefit associated with U.S. manufacturing operations passed into law under the same Act will be phased in over a five year period beginning in 2005. Whereas the timing of the phase out of the export tax benefit and the phase in of the manufacturing tax benefit may differ, we expect the tax reduction associated with the new manufacturing deduction, when fully implemented, to be similar in amount to the export benefit. We anticipate our tax rate for 2008 to be in the range of approximately 32% to 34% for continuing operations.

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Liquidity and Capital Resources
At December 31, 2008, the Company had cash and cash equivalents of $1,542.8 million, and total debt of $873.9 million. At December 31, 2007, cash and cash equivalents were $1,841.8 million and total debt was $890.7 million. The decrease in cash holdings was primarily due to the acquisition of Grant Prideco largely offset by increased operating activities and securing project orders that require large down payments and early payment terms. The Company’s outstanding debt at December 31, 2008 consisted of $200.0 million of 5.65% Senior Notes due 2012, $200.0 million of 7.25% Senior Notes due 2011, $150.0 million of 6.5% Senior Notes due 2011, $150.0 million of 5.5% Senior Notes due 2012, $151.0 million of 6.125% Senior Notes due 2015 and other debt of $22.9 million.
Cash provided by operating activities in 2008 was $2,294.1 million compared to cash provided by operating activities of $1,188.0 million in 2007. Cash was used by operations primarily through increases in inventories of $643.0 million and receivables of $625.9 million. These negative cash flows were offset by net income of $1,952.0 million, an increase in billings in excess of costs of $764.6 million and non-cash charges of $401.6 million. Receivables increased due to greater revenue in 2008 compared to 2007 as the fourth quarter 2008 revenue was $3,810.2 million compared to $2,658.9 million for the fourth quarter of 2007. Inventory increased due to continued higher activity and growing backlog orders. Billings in excess of costs increased due to early payment terms in relation to construction projects.
For the year ended December 31, 2008, cash used by investing activities was $2,473.3 million compared to $574.9 million used for 2007. We used $3,007.9 million to complete ten acquisitions during 2008, with the acquisition of Grant Prideco, Inc. amounting to $2,837.2 million, net of cash acquired. Capital spending of $378.5 million was primarily related to rental assets associated with the Company’s Petroleum Services & Supplies operations.
For the year ended December 31, 2008, cash used by financing activities was $74.0 million compared to $149.6 million provided in 2007. The Company borrowed $2,730.8 million of funds during 2008, $2,000.0 million of which was for the acquisition of Grant Prideco on April 21, 2008. The Company repaid the amount borrowed for the Grant Prideco acquisition and other debt in the amount of $2,919.9 million in 2008. The Company also generated cash proceeds from stock options exercised of $78.0 million and excess tax benefit from exercise of stock options of $37.1 million during 2008.
We believe cash on hand, cash generated from operations, and amounts available under the credit facilities and from other sources of debt will be sufficient to fund operations, working capital needs, capital expenditure requirements and financing obligations. At December 31, 2008, the Company had $2,396.9 million of available funds under its two revolving credit facilities. We also believe increases in capital expenditures caused by any need to increase manufacturing capacity can be funded from operations or through debt financing.
A summary of the Company’s outstanding contractual obligations at December 31, 2008 is as follows (in millions):
                                         
            Payment Due by Period  
            Less than                     After  
    Total     1 Year     1-3 Years     4-5 Years     5 Years  
Contractual Obligations:
                                       
Total debt
  $ 873.9     $ 4.3     $ 364.5     $ 354.0     $ 151.1  
Operating leases
    520.8       114.1       158.0       91.8       156.9  
 
                             
Total Contractual Obligations
  $ 1,394.7     $ 118.4     $ 522.5     $ 445.8     $ 308.0  
 
                             
 
                                       
Commercial Commitments:
                                       
Standby letters of credit
  $ 3,167.8     $ 1,184.1     $ 1,559.4     $ 422.7     $ 1.6  
 
                             
As of December 31, 2008, the Company had $69.0 million of unrecognized tax benefits. This represents the tax benefits associated with various tax positions taken, or expected to be taken, on domestic and international tax returns that have not been recognized in our financial statements due to uncertainty regarding their resolution. Due to the uncertainty of the timing of future cash flows associated with these unrecognized tax benefits, we are unable to make reasonably reliable estimates of the period of cash settlement, if any, with the respective taxing authorities. Accordingly, unrecognized tax benefits have been excluded from the contractual obligations table above. For further information related to unrecognized tax benefits, see Note 14, “Income Tax,” to the consolidated financial statements included in this Report.

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We intend to pursue additional acquisition candidates, but the timing, size or success of any acquisition effort and the related potential capital commitments cannot be predicted. The Company expects to reduce its capital spending approximately 20% in 2009 to the $300 million range. We expect to fund future cash acquisitions and capital spending primarily with cash flow from operations and borrowings, including the unborrowed portion of the credit facility or new debt issuances, but may also issue additional equity either directly or in connection with acquisitions. There can be no assurance that additional financing for acquisitions will be available at terms acceptable to us.
Inflation has had an impact on certain of our operations in recent years. We believe that the higher costs for energy, steel and other commodities experienced in 2008 have largely been mitigated by increased prices and component surcharges for the products we sell. However, higher steel, labor, energy or other commodity prices may adversely impact future periods.
Critical Accounting Estimates
In preparing the financial statements, we make assumptions, estimates and judgments that affect the amounts reported. We periodically evaluate our estimates and judgments that are most critical in nature which are related to revenue recognition under long-term construction contracts; allowance for doubtful accounts; inventory reserves; impairments of long-lived assets (excluding goodwill and other indefinite-lived intangible assets); goodwill and other indefinite-lived intangible assets and income taxes. Our estimates are based on historical experience and on our future expectations that we believe are reasonable. The combination of these factors forms the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results are likely to differ from our current estimates and those differences may be material.
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 to complete estimates at the beginning of each project, taking into account all factors considered likely to affect gross margin. 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 as mentioned in “Risk Factors.” These factors can significantly impact the accuracy of the Company’s estimates and materially impact the Company’s future reported earnings.
Historically, the Company’s estimates have been reasonably dependable regarding the recognition of revenues and gross profits on percentage of completion contracts. Based upon an analysis of percentage of completion contracts for all open contracts outstanding at December 31, 2007 and 2006, adjustments (representing the differences between the estimated and actual results) to all outstanding contracts resulted in net changes to gross profit margins of 0.8% ($31.3 million on $3.8 billion of outstanding contracts) and 0.3% ($4.3 million on $1.6 billion of outstanding contracts), respectively. While the Company believes that its estimates on outstanding contracts at December 31, 2008 and in future periods will continue to be reasonably dependable under percentage of completion accounting, the factors identified in the preceding paragraph could result in significant adjustments in future periods. The Company has recorded revenue on outstanding contracts (on a contract-to-date basis) of $4.9 billion at December 31, 2008.
Allowance for Doubtful Accounts
The determination of the collectibility of amounts due from customer accounts requires the Company to make judgments regarding future events and trends. 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. A substantial portion of the Company’s revenues come from international oil companies, international shipyards, international oilfield service

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companies, and government-owned or government-controlled oil companies. Therefore, the Company has significant receivables in many foreign jurisdictions. If worldwide oil and gas drilling activity or changes in economic conditions in foreign jurisdictions deteriorate, the creditworthiness of the Company’s customers could also deteriorate and they may be unable to pay these receivables, and additional allowances could be required. At December 31, 2008 and 2007, allowance for bad debts totaled $72.7 million and $44.8 million, or 2.3% and 2.1% of gross accounts receivable, respectively.
Historically, the Company’s charge-offs and provisions for the allowance for doubtful accounts have been immaterial to the Company’s consolidated financial statements. However, because of the risk factors mentioned above, changes in our estimates could become material in future periods.
Inventory Reserves
Inventory is carried at the lower of cost or estimated net realizable value. The Company determines reserves for inventory based on historical usage of inventory on-hand, assumptions about future demand and market conditions, and estimates about potential alternative uses, which are usually limited. The Company’s inventory consists of specialized spare parts, work in process, and raw materials to support ongoing manufacturing operations and the Company’s large installed base of specialized equipment used throughout the oilfield. Customers rely on the Company to stock these specialized items to ensure that their equipment can be repaired and serviced in a timely manner. The Company’s estimated carrying value of inventory therefore depends upon demand driven by oil and gas drilling and well remediation activity, which depends in turn upon oil and gas prices, the general outlook for economic growth worldwide, available financing for the Company’s customers, political stability in major oil and gas producing areas, and the potential obsolescence of various types of equipment we sell, among other factors. At December 31, 2008 and 2007, inventory reserves totaled 3.1% and 3.7% of gross inventory, respectively.
While inventory reserves and accruals have not had a material impact on the Company’s financial results for the periods covered in this report, changes in worldwide oil and gas activity, or the development of new technologies which make older drilling technologies obsolete, could require the Company to record additional allowances to reduce the value of its inventory. Such changes in our estimates could be material under weaker market conditions or outlook.
Impairment of Long-Lived Assets (Excluding Goodwill and Other Indefinite-Lived Intangible Assets)
Long-lived assets, which include property, plant and equipment and identified intangible assets, comprise a significant amount of the Company’s total assets. The Company makes judgments and estimates in conjunction with the carrying value of these assets, including amounts to be capitalized, depreciation and amortization methods and estimated useful lives.
The carrying values of these assets are reviewed for impairment at least annually or more frequently whenever events or changes in circumstances indicate that the carrying amounts may not be recoverable. An impairment loss is recorded in the period in which it is determined that the carrying amount is not recoverable. We estimate the fair value of these intangible and fixed assets using an income approach. This requires the Company to make long-term forecasts of its future revenues and costs related to the assets subject to review. These forecasts require assumptions about demand for the Company’s products and services, future market conditions and technological developments. The forecasts are dependent upon assumptions regarding oil and gas prices, the general outlook for economic growth worldwide, available financing for the Company’s customers, political stability in major oil and gas producing areas, and the potential obsolescence of various types of equipment we sell, among other factors. The financial and credit market volatility directly impacts our fair value measurement through our income forecast as well as our weighted-average cost of capital, both key assumptions used in our calculation. Changes to these assumptions, including, but not limited to: further sustained declines in worldwide rig counts below current analysts’ forecasts, further collapse of spot and futures prices for oil and gas, significant additional deterioration of external financing for our customers, higher risk premiums or higher cost of equity, or any other significant adverse economic news could require a provision for impairment in a future period. Due to further significant declines in the Company’s stock price and oil and gas commodity prices, coupled with unprecedented turbulence in the credit markets, the Company determined a triggering event occurred in the fourth quarter of 2008. We performed an impairment analysis at December 31, 2008 which did not result in an impairment charge.
Goodwill and Other Indefinite-Lived Intangible Assets
The Company has approximately $5.2 billion of goodwill and $0.8 billion of other intangible assets with indefinite lives on its consolidated balance sheet as of December 31, 2008. Generally accepted accounting principles require the Company to test goodwill and other indefinite-lived intangible assets for impairment at least annually or more frequently whenever events or circumstances occur indicating that goodwill or other indefinite-lived intangible assets might be impaired. Events or circumstances which could indicate a potential impairment include, but not limited to: further sustained declines in worldwide rig counts below current analysts’ forecasts, further collapse of spot and futures prices for oil and gas, significant additional deterioration of external financing for our customers, higher risk premiums or higher cost of equity. The timing and magnitude of any goodwill impairment charge, which could be material, would depend on the timing and severity of the event or events triggering the charge and would require a high degree of management judgment.
The Company performs a review of goodwill for impairment annually or earlier if indicators of potential impairment exist. The annual impairment tests are performed during the fourth quarter of each year. If it is determined that goodwill is impaired the impairment is measured 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 the Company encounters events or changes in circumstances that would indicate that the carrying amount of goodwill and identified intangibles has been impaired.
Fair value of the reporting units is determined based on internal management estimates, forecasts and judgments, using a combination of three methods: discounted cash flow, comparable companies, and representative transactions. While the Company primarily uses the discounted cash flow method to assess fair value, the Company uses the comparable companies and representative transaction methods to validate the discounted cash flow analysis and further support management’s expectations where possible. The discounted cash flow is based on management’s short-term and long-term forecast of operating performance for each reporting unit. The two main assumptions used in measuring goodwill impairment which bears the risk of change and could impact the Company’s goodwill impairment analysis include the cash flow from operations from each of the Company’s individual business units and the weighted average costs of capital for the discount rate. The starting point for each of the fourteen reporting unit’s cash flow from operations is the detailed annual plan. The detailed planning process takes into consideration a multitude of factors including worldwide rig activity, inflationary forces, pricing strategies, customer analysis, operational issues, competitor analysis, capital spending requirements, working capital needs, customer needs to replacing aging equipment, increased complexity of drilling, new technology, and existing backlog among other items which impact the individual reporting unit projections. Cash flows beyond the specific operating plans were estimated using a terminal value calculation, which incorporated historical and forecasted financial cyclical trends for each reporting unit and considered long-term earnings growth rates. The financial and credit market volatility directly impacts our fair value measurement through our weighted-average cost of capital that we use to determine our discount rate. During times of volatility, significant judgment must be applied to determine whether credit changes are a short term or long-term trend.

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In the fourth quarter of 2008 and in the early stages of 2009, both commodity prices and rig activity dropped significantly and as a result, projections for the remainder of 2009 also reflected substantial declines compared to 2008. The Company updated its operating plans and discounted cash flows based on this information. The goodwill impairment analysis which we performed during the fourth quarter of 2008 and updated as of December 31, 2008, did not result in an impairment in the current year. The Company had no impairment of goodwill for the years ended December 31, 2007 and 2006.
The Company performed a sensitivity analysis on the projected results and goodwill impairment analysis assuming revenue for each individual reporting unit decreased an additional 20% from the current projections for each of the next three years (2009, 2010, and 2011), while holding all other factors constant, and no goodwill impairment was identified for any of the reporting units. The Company believes that such a 20% drop approximately corresponds to a three-year worldwide average rig count in the range of 2,300 to 2,400 active drilling rigs, a level of activity last seen approximately five years ago. The worldwide rig count has been volatile, is reasonably likely to continue to be so in the future, and has varied from a low of 1,458 rigs in 1999 to a high of 5,624 rigs in 1981. In 2008 worldwide rig activity averaged 3,336 active rigs. Additionally, if the Company were to increase their discount rate 200 basis points, while keeping all other assumptions constant, there would be no impairments in any of the reporting units. Inherent in our projections are key assumptions relative to how long the current downward cycle might last. While we believe these assumptions are reasonable and appropriate, we will continue to monitor these, and update our impairment analysis if the cycle downturn continues for longer than expected. While the Company does not believe that these events or changes are likely to occur, it is reasonably possible these events could transpire if market conditions worsen and if the market fails to recover in 2010 and/or 2011. Any significant changes to these assumptions and factors could have a material impact on the Company’s goodwill impairment analysis.
Other indefinite-lived intangible assets, representing trade names management intends to use indefinitely, were valued and are tested for impairment using the Relief from Royalty Method, a form of the Income Approach. An impairment is measured and recognized based on the amount the book value of the indefinite-lived intangible assets exceeds its calculated fair value as of the date of the impairment test. Included in the impairment test are assumptions, for each trade name, regarding the related revenue streams attributable to the trade names, the royalty rate, and the discount rate applied. Based on the Company’s indefinite-lived intangible asset impairment analysis performed during the fourth quarter of 2008, the Company had no impairment of other indefinite-lived intangible assets for the years ended December 31,2008,2007 and 2006.
If any of the above assumptions change, including in some cases insignificantly, or fails to materialize, the resulting decline in our trade name’s estimated fair value could result in a material impairment charge. The Company performed a sensitivity analysis on the projected results and indefinite-lived intangible asset impairment assuming revenue for each individual trade name decreased an additional 20% from the current projections for each of the next three years (2009, 2010, and 2011), while holding all other factors constant, and a pre-tax non-cash impairment charge of approximately $39 million would be incurred under those assumptions. If the discount rate applied to the fair value calculation increased by 200 basis points, and all other assumptions remained constant, a pre-tax, non-cash impairment charge of approximately $94 million would be incurred under those assumptions.
Income Taxes
The Company is a U.S. registered company and is subject to income taxes in the U.S. The Company operates through various subsidiaries in a number of countries throughout the world. Income taxes have been provided based upon the tax laws and rates of the countries in which the Company operates and income is earned.
The Company’s annual tax provision is based on expected taxable income, statutory rates and tax planning opportunities available in the various jurisdictions in which it operates. The determination and evaluation of the annual tax provision and tax positions involves the interpretation of the tax laws in the various jurisdictions in which the Company operates. It requires significant judgment and the use of estimates and assumptions regarding significant future events such as the amount, timing and character of income, deductions and tax credits. Changes in tax laws, regulations, and treaties, foreign currency exchange restrictions or the Company’s level of operations or profitability in each jurisdiction could impact the tax liability in any given year. The Company also operates in many jurisdictions where the tax laws relating to the pricing of transactions between related parties are open to interpretation, which could potentially result in aggressive tax authorities asserting additional tax liabilities with no offsetting tax recovery in other countries.

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The Company maintains liabilities for estimated tax exposures in jurisdictions of operation. The annual tax provision includes the impact of income tax provisions and benefits for changes to liabilities that the Company considers appropriate, as well as related interest. Tax exposure items primarily include potential challenges to intercompany pricing and certain tax credits which may not be ultimately sustained. These exposures are resolved primarily through the settlement of audits within these tax jurisdictions or by judicial means. The Company is subject to audits by federal, state and foreign jurisdictions which may result in proposed assessments. The Company believes that an appropriate liability has been established for estimated exposures under the guidance in FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes, which is an interpretation of the Statement of Financial Accounting Standards (“SFAS”) No. 109, Accounting for Income Taxes. However, actual results may differ materially from these estimates. The Company reviews these liabilities quarterly and to the extent audits or other events result in an adjustment to the liability accrued for a prior year, the effect will be recognized in the period of the event.
The Company currently has recorded valuation allowances that the Company intends to maintain until it is more likely than not the deferred tax assets will be realized. Income tax expense recorded in the future will be reduced to the extent of decreases in the Company’s valuation allowances. The realization of remaining deferred tax assets is primarily dependent on future taxable income. Any reduction in future taxable income including but not limited to any future restructuring activities may require that the Company record an additional valuation allowance against deferred tax assets. An increase in the valuation allowance would result in additional income tax expense in such period and could have a significant impact on future earnings.
The Company has not provided for deferred taxes on the unremitted earnings of certain subsidiaries that are permanently reinvested. Should the Company make a distribution from the unremitted earnings of these subsidiaries, the Company may be required to record additional taxes. Unremitted earnings of these subsidiaries were $2,254.5 million and $1,580.0 million at December 31, 2008 and 2007, respectively. The Company makes an annual determination whether to permanently reinvest these earnings. If, as a result of these reassessments, the Company distributes these earnings in the future, additional tax liability would result, offset by any available foreign tax credits.
The Company does not believe it is possible to reasonably estimate the potential impact of changes to the assumptions and estimates identified because the resulting change to our tax liability, if any, is dependent on numerous factors which cannot be reasonably estimated. These include, among others, the amount and nature of additional taxes potentially asserted by local tax authorities; the willingness of local tax authorities to negotiate a fair settlement through an administrative process; the impartiality of the local courts; and the potential for changes in the tax paid to one country to either produce, or fail to produce, an offsetting tax change in other countries.
Recently Issued Accounting Standards
In September 2006, the Financial Accounting Standards Board (“FASB”) 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. In February 2008, the FASB issued FSP 157-2, which delays the effective date of SFAS 157 for all nonfinancial assets and liabilities that are not recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually) until fiscal years beginning after November 15, 2008, and interim periods within those fiscal years. The Company adopted the provisions of SFAS 157 for financial assets and liabilities as of January 1, 2008. At December 31, 2008, the Company has determined that its financial assets of $31.6 million and liabilities of $83.1 million (primarily currency related derivatives) are level 2 in the fair value hierarchy. At December 31, 2008, the fair value of the Company’s foreign currency forward contracts totaled $2.3 million. There was no significant impact to the Company’s consolidated financial statements from the adoption of SFAS 157.
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. On January 1, 2008, the Company adopted SFAS 159 and elected not to measure any of its currently eligible assets and liabilities at fair value.
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 expects 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

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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.
In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities — an amendment of FASB Statement No. 133” (“SFAS 161”). SFAS 161 amends and expands the disclosure requirements for derivative instruments and hedging activities, with the intent to provide users of financial statements with an enhanced understanding of how and why an entity uses derivative instruments, how derivative instruments and related hedged items are accounted for, and how derivative instruments and related hedged items affect an entity’s financial statements. SFAS 161 is effective for fiscal years and interim periods beginning after November 15, 2008. The Company is currently evaluating the potential impact that the application of SFAS 161 to its nonfinancial assets and liabilities will have on its consolidated financial statements.
In April 2008, the FASB issued FASB Staff Position (“FSP”) SFAS 142-3, “Determination of the Useful Life of Intangible Assets” (“FSP SFAS 142-3”). FSP SFAS 142-3 amends the factors that should be considered in developing renewal or extension assumptions used to determine the useful life of a recognized intangible asset under FASB Statement No. 142, “Goodwill and Other Intangible Assets". The objective of this FSP is to improve the consistency between the useful life of a recognized intangible asset under Statement No. 142 and the period of expected cash flows used to measure the fair value of the asset under SFAS 141R, “Business Combinations", and other U.S. GAAP principles. FSP SFAS 142-3 is effective for fiscal years beginning after December 15, 2008. The Company is currently assessing the impact of FSP SFAS 142-3 on its consolidated financial position and results of operations.
Forward-Looking Statements
Some of the information in this document contains, or has incorporated by reference, forward-looking statements. Statements that are not historical facts, including statements about our beliefs and expectations, are forward-looking statements. Forward-looking statements typically are identified by use of terms such as “may,” “will,” “expect,” “anticipate,” “estimate,” and similar words, although some forward-looking statements are expressed differently. All statements herein regarding expected merger synergies are forward looking statements. You should be aware that our actual results could differ materially from results anticipated in the forward-looking statements due to a number of factors, including but not limited to changes in oil and gas prices, customer demand for our products and worldwide economic activity. You should also consider carefully the statements under “Risk Factors” which address additional factors that could cause our actual results to differ from those set forth in the forward-looking statements. Given these uncertainties, current or prospective investors are cautioned not to place undue reliance on any such forward-looking statements. We undertake no obligation to update any such factors or forward-looking statements to reflect future events or developments.

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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, 2008, 2007 and 2006, the Company reported foreign currency gains (losses) of $50.2 million, ($7.0) million, and ($21.0) 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 2008 foreign exchange gain is primarily the result in the weakening of the following major currencies of which the Company has material exposure against the U.S. dollar: British pound sterling — 27.5%, Canadian dollar — 19.7%, Euro — 4.3% and the Norwegian krone — 21.7%. Further weakening of these currencies against the U.S. dollar may continue to create similar gains 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, 2008, we had entered into foreign currency forward contracts with notional amounts aggregating $2,743.4 million to hedge cash flow exposure to foreign currency exchange risk of forecasted or firm commitments. 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, 2008 and 2007 for contracts with similar terms and maturity dates, we have recorded a gain (loss) of ($142.1) million and $11.2 million, respectively, to adjust these foreign currency forward contracts to their fair market value of ($21.2) million and $14.1 million respectively. This loss is included in accumulated other comprehensive income (loss) in the consolidated balance sheet. It is expected that $48.2 million of the loss will be reclassified into earnings within the next 12 months with an offset by gains from the underlying transactions resulting in no impact to earnings or cash flow. At December 31, 2008, the Company has cash flow hedges in place through the second quarter of 2011. A gain (loss) from ineffectiveness of ($6.1) million and $4.6 million is included in earnings related to these foreign currency contracts for the years ending December 31, 2008 and 2007 respectively. Ineffectiveness for 2006 was not material.
At December 31, 2008, the Company had foreign currency forward contracts with notional amounts aggregating $131.9 million designated and qualifying as fair value hedges to hedge exposure to foreign currency exchange risk of firm commitments. Based on quoted market prices as of December 31, 2008 and 2007 for contracts with similar terms and maturity dates, we recorded a gain (loss) of ($8.5) million and $79.9 million, respectively, to adjust these foreign currency forward contracts to their fair market value of ($5.6) million and $79.9 million, respectively. This loss is offset by designated gains on the firm commitments. Ineffectiveness for 2008, 2007 and 2006 was not material.
At December 31, 2008, the Company had foreign currency forward contracts with notional amounts aggregating $977.1 million to offset exposures to foreign currency exchange risk 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 $29.1 million for 2008 and $0.5 million for 2007 of these contracts are recorded each period in current earnings.
 
On January 4, 2008, the Company settled the net investment hedges with notional amounts aggregating $1,221.6 million by delivering Norwegian kroner and receiving U.S. dollars. The related cumulative tax-effected gain of $7.5 million was recorded in accumulated other comprehensive income (loss).

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The following table details the Company’s foregin currency exchange risk grouped by functional currency and their expected maturity periods as of December 31, 2008 (in millions except for rates):
                                         
    As of December 31, 2008           December 31,
Functional Currency   2009   2010   2011   Total   2007
CAD Buy USD/Sell CAD:
                                       
Notional amount to buy (in Canadian dollars)
    526.6                   526.6       15.7  
Average CAD to USD contract rate
    1.1843                   1.1843       0.9895  
Fair Value at December 31, 2008 in U.S. dollars
    13.9                   13.9       (0.1 )
 
                                       
Sell USD/Buy CAD:
                                       
Notional amount to sell (in Canadian dollars)
    221.5       19.7             241.2       106.7  
Average CAD to USD contract rate
    1.1248       1.0638             1.1196       1.0530  
Fair Value at December 31, 2008 in U.S. dollars
    (15.7 )     (2.2 )           (17.9 )     7.3  
 
                                       
Sell NOK/Buy CAD:
                                       
Notional amount to buy (in Canadian dollars)
                            590.0  
Average CAD to USD contract rate
                            5.7916  
Fair Value at December 31, 2008 in U.S. dollars
                            (18.7 )
 
                                       
EUR Buy USD/Sell EUR:
                                       
Notional amount to buy (in euros)
    11.3                   11.3       10.7  
Average USD to EUR contract rate
    1.4397                   1.4397       1.3997  
Fair Value at December 31, 2008 in U.S. dollars
    0.4                   0.4       (0.7 )
 
                                       
Sell USD/Buy EUR:
                                       
Notional amount to buy (in euros)
    208.5       36.2       0.5       245.2       109.5  
Average USD to EUR contract rate
    1.4083       1.3420       1.4431       1.3986       1.3719  
Fair Value at December 31, 2008 in U.S. dollars
    (0.9 )     2.0             1.1       10.6  
 
                                       
GBP Sell USD/Buy GBP:
                                       
Notional amount to buy (in British Pounds Sterling)
    32.7       1.0             33.7       13.2  
Average USD to GBP contract rate
    1.5630       1.6166               1.5647       2.0418  
Fair Value at December 31, 2008 in U.S. dollars
    (3.9 )     (0.2 )           (4.1 )     (0.6 )
 
                                       
NOK Buy EUR/Sell NOK:
                                       
Notional amount to buy (in Norwegian krone)
                            1,285.6  
Average NOK to EUR contract rate
                            8.1111  
Fair Value at December 31, 2008 in U.S. dollars
                            1.9  
 
                                       
Buy GBP/Sell NOK:
                                       
Notional amount to buy (in Norwegian krone)
                            171.3  
Average NOK to GBP contract rate
                            11.4289  
Fair Value at December 31, 2008 in U.S. dollars
                            (1.0 )
 
                                       
Buy USD/Sell NOK:
                                       
Notional amount to buy (in Norwegian krone)
                            994.3  
Average NOK to USD contract rate
                            5.8346  
Fair Value at December 31, 2008 in U.S. dollars
                            (8.3 )
 
                                       
Sell USD/Buy NOK:
                                       
Notional amount to buy (in Norwegian krone)
                            11,976.3  
Average NOK to USD contract rate
                            5.8365  
Fair Value at December 31, 2008 in U.S. dollars
                            87.5  
 
                                       
USD Buy DKK/Sell USD:
                                       
Notional amount to buy (in U.S. dollars)
    46.6                   46.6        
Average DKK to USD contract rate
    5.4968                   5.4968        
Fair Value at December 31, 2008 in U.S. dollars
    1.8                   1.8        
 
                                       
Buy EUR/Sell USD:
                                       
Notional amount to buy (in U.S. dollars)
    748.0       1.0             749.0        
Average USD to EUR contract rate
    1.3790       1.4540               1.3791        
Fair Value at December 31, 2008 in U.S. dollars
    14.3                   14.3        
USD Buy GBP/Sell USD:
                                       
Notional amount to buy (in U.S. dollars)
    108.0                   108.0        
Average USD to GBP contract rate
    1.5623                   1.5623        
Fair Value at December 31, 2008 in U.S. dollars
    (8.1 )                 (8.1 )      
 
                                       
Buy NOK/Sell USD:
                                       
Notional amount to buy (in U.S. dollars)
    964.5       360.8             1,325.3        
Average NOK to USD contract rate
    6.5855       6.3957               6.5338        
Fair Value at December 31, 2008 in U.S. dollars
    (64.5 )     (36.0 )           (100.5 )      
 
                                       
Sell CAD/Buy USD:
                                       
Notional amount to sell (in U.S. dollars)
                            632.0  
Average CAD to USD contract rate
                            1.0713  
Fair Value at December 31, 2008 in U.S. dollars
                            30.6  
 
                                       
Sell EUR/Buy USD:
                                       
Notional amount to sell (in U.S. dollars)
    72.4             3.5       75.9       3.4  
Average USD to EUR contract rate
    1.3832             1.2715       1.3777       1.3340  
Fair Value at December 31, 2008 in U.S. dollars
    (1.2) -               (0.3 )     (1.5 )     (0.3 )
 
                                       
Sell NOK/Buy USD:
                                       
Notional amount to sell (in U.S. dollars)
    513.3       76.0             589.3        
Average NOK to USD contract rate
    5.8532       5.9424               5.8647        
Fair Value at December 31, 2008 in U.S. dollars
    90.5       13.1             103.6        
 
                                       
Other Currencies
                                       
Fair Value at December 31, 2008 in U.S. dollars
    (0.6 )     (0.1 )           (0.7 )     (1.8 )
 
                                       
 
                                       
Total Fair Value
    26.0       (23.4 )     (0.3 )     2.3       106.4  
 
                                       
The Company had other financial market risk sensitive instruments denominated in foreign currencies totaling $46.4 million as of December 31, 2008 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 $3.0 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 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 krone 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 denominated in U.S. dollars. As a Norwegian krone 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 foreign currency forward contracts with notional amounts aggregating $2,550.5 million with a fair value of $91.3 million 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 gain position of $108.8 million associated with the terminated hedges has been deferred and is being recognized into earnings in the future period(s) the forecasted transactions affect earnings, of which $64.3 million has been recognized into earnings at December 31, 2008. 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. At December 31, 2008, our Norway operations had derivatives with $2,547.5 million in notional value with a fair value of $6.3 million, included in the table above.

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Interest Rate Risk
At December 31, 2008, our long term borrowings consisted $200.0 million of 5.65% Senior Notes, $200.0 million of 7.25% Senior Notes, $150.0 million of 6.5% Senior Notes, $150.0 million of 5.5% Senior Notes and $151.0 million of 6.125% Senior Notes. We had $22.9 million of other borrowings at December 31, 2008. 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.
On February 15, 2008, we settled and terminated our three interest rate swap agreements with an aggregate notional amount of $100 million associated with our 2008 Senior Notes. Under this agreement, we received 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 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 increase in interest expense for the period ended December 31, 2008.
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. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE.
None.
ITEM 9A. CONTROLS AND PROCEDURES
(i) Evaluation of disclosure controls and procedures
As required by SEC Rule 13a-15(b), we have evaluated, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this report. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by the Company in reports that it files under the Exchange Act is accumulated and communicated to the Company’s management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. Our principal executive officer and principal financial officer have concluded that our current disclosure controls and procedures were effective as of December 31, 2008 at the reasonable assurance level.
On April 21, 2008, the Company acquired Grant Prideco. For purposes of determining the effectiveness of the Company’s disclosure controls and procedures and in the Company’s internal control over financial reporting, as disclosed in this report, management has excluded Grant Prideco from its evaluation of these matters. The acquired business represented approximately 36% of our consolidated total assets at December 31, 2008 and 11% of consolidated revenues and 10% of our consolidated operating profit for the year ended December 31, 2008.
Pursuant to section 302 of the Sarbanes-Oxley Act of 2002, our Chief Executive Officer and Chief Financial Officer have provided certain certifications to the Securities and Exchange Commission. These certifications are included herein as Exhibits 31.1 and 31.2.
(ii) Internal Control Over Financial Reporting
(a) Management’s annual report on internal control over financial reporting.
The Company’s management report on internal control over financial reporting is set forth in this annual report on Page 56 and is incorporated herein by reference.

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(b) Changes in internal control
There were no changes in the Company’s internal control over financial reporting that occurred during the Company’s last fiscal quarter covered by this report that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.
ITEM 9B. OTHER INFORMATION
None.

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PART III
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
Incorporated by reference to the definitive Proxy Statement for the 2009 Annual Meeting of Stockholders.
ITEM 11. EXECUTIVE COMPENSATION
Incorporated by reference to the definitive Proxy Statement for the 2009 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 2009 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, 2008, with respect to compensation plans under which our common stock may be issued:
                         
    Number of securities     Weighted-average     Number of securities  
    to be issued upon     exercise price of     remaining available for equity  
    exercise of warrants     outstanding     compensation plans (excluding  
    and rights     rights     securities reflected in column (a)) (c)  
Plan Category   (a)     (b)     (1)  
Equity compensation plans approved by security holders
    7,547,822     $ 37.24       5,315,252  
Equity compensation plans not approved by security holders
                 
 
                 
Total
    7,547,822     $ 37.24       5,315,252  
 
                 
 
(1)   Shares could be issued other than upon the exercise of stock options, warrants or rights; however, none are anticipated during 2009.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
Incorporated by reference to the definitive Proxy Statement for the 2009 Annual Meeting of Stockholders.
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
Incorporated by reference to the definitive Proxy Statement for the 2009 Annual Meeting of Stockholders.

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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
    59  
Consolidated Statements of Income
    60  
Consolidated Statements of Cash Flows
    61  
Consolidated Statements of Stockholders’ Equity and Comprehensive Income
    62  
Notes to Consolidated Financial Statements
    63  
 
(2) Financial Statement Schedule
       
 
Schedule II — Valuation and Qualifying Accounts
    90  
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.
  (3)   Exhibits

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2.1   Amended and Restated Agreement and Plan of Merger, effective as of August 11, 2004 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. (8)
 
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) (9).
 
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) (6)
 
10.6   Form of Non-Employee Director Stock Option Agreement (Exhibit 10.2) (6).
 
10.7   Form of Performance-Based Restricted Stock (18 Month) Agreement (Exhibit 10.1) (7).
 
10.8   Form of Performance-Based Restricted Stock (36 Month) Agreement (Exhibit 10.2) (7).
 
10.9   Five-Year Credit Agreement, dated as of April 21, 2008, among National Oilwell Varco, Inc., the financial institutions signatory thereto, including Wells Fargo Bank, N.A., in their capacities as Administrative Agent, Co-Lead Arranger and Joint Book Runner, DnB Nor Bank ASA, as Co-Lead Arranger and Joint Book Runner, and Fortis Capital Corp., The Bank of Nova Scotia and The Bank of Tokyo — Mitsubishi UFJ, Ltd., as Co-Documentation Agents. (Exhibit 10.1) (10).
 
10.10   First Amendment to Employment Agreement dated as of December 22, 2008 between Merrill A. Miller, Jr. and National Oilwell Varco (Exhibit 10.1) (11)
 
10.11   Second Amendment to Executive Agreement, dated as of December 22, 2008, of Clay Williams and National Oilwell Varco (Exhibit 10.2) (11)
 
10.12   First Amendment to Employment Agreement dated as of December 22, 2008 between Mark A. Reese and National Oilwell Varco (Exhibit 10.3) (11)
 
10.13   First Amendment to Employment Agreement dated as of December 22, 2008 between Dwight W. Rettig and National Oilwell Varco (Exhibit 10.4) (11)
 
10.14   Employment Agreement dated as of December 22, 2008 between Robert W. Blanchard and National Oilwell Varco (Exhibit 10.5) (11)

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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.
 
*   Compensatory plan or arrangement for management or others
 
(1)   Filed as an Exhibit to our Quarterly Report on Form 10-Q filed on August 11, 2000.
 
(2)   Filed as an Exhibit to our Annual Report on Form 10-K filed on March 28, 2002.
 
(3)   Filed as an Exhibit to Varco International, Inc.’s Quarterly Report on Form 10-Q filed on May 6, 2004.
 
(4)   Filed as Annex A to our Registration Statement on Form S-4 filed on September 16, 2004.
 
(5)   Filed as Annex D to our Amendment No. 1 to Registration Statement on Form S-4 filed on January 31, 2005.
 
(6)   Filed as an Exhibit to our Current Report on Form 8-K filed on February 23, 2006.
 
(7)   Filed as an Exhibit to our Current Report on Form 8-K filed on March 27, 2007.
 
(8)   Filed as Annex A to our Registration Statement on Form S-4 filed on January 28, 2008.
 
(9)   Filed as an Exhibit to our Current Report on Form 8-K filed on February 21, 2008.
 
(10)   Filed as an Exhibit to our Current Report on Form 8-K filed on April 22, 2008.
 
(11)   Filed as an Exhibit to our Current Report on Form 8-K filed on December 23, 2008.

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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.
             
 
           
    NATIONAL OILWELL VARCO, INC.
 
           
Dated: February 28, 2009
  By:   /s/ MERRILL A. MILLER, JR.    
 
           
 
      Merrill A. Miller, Jr.    
 
      Chairman, President and Chief Executive Officer    
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.
         
Signature   Title   Date
 
/s/ MERRILL A. MILLER, JR.
Merrill A. Miller, Jr.
  Chairman, President and Chief Executive Officer   February 28, 2009
 
       
/s/ CLAY C. WILLIAMS
Clay C. Williams
  Senior Vice President and Chief Financial Officer   February 28, 2009
 
       
/s/ ROBERT W. BLANCHARD
Robert W. Blanchard
  Vice President, Corporate Controller and Chief Accounting Officer   February 28, 2009
 
       
/s/ GREG L. ARMSTRONG
Greg L. Armstrong
  Director   February 28, 2009
 
       
/s/ ROBERT E. BEAUCHAMP
Robert E. Beauchamp
  Director   February 28, 2009
 
       
/s/ BEN A. GUILL
Ben A. Guill
  Director   February 28, 2009
 
       
/s/ DAVID D. HARRISON
David D. Harrison
  Director   February 28, 2009
 
       
/s/ ROGER L. JARVIS
Roger L. Jarvis
  Director   February 28, 2009
 
       
/s/ ERIC L. MATTSON
Eric L. Mattson
  Director   February 28, 2009
 
       
/s/ JEFFERY A. SMISEK
Jeffery A. Smisek
  Director   February 28, 2009

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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, 2008
On April 21, 2008, the Company acquired Grant Prideco. For purposes of determining the effectiveness of the Company’s disclosure controls and procedures and in the Company’s internal control over financial reporting, as disclosed in this report, management has excluded Grant Prideco from its evaluation of these matters. The acquired business represented approximately 36% of our consolidated total assets at December 31, 2008 and 11% of consolidated revenues and 10% of our consolidated operating profit for the year ended December 31, 2008.
The effectiveness of our internal control over financial reporting as of December 31, 2008, 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.
/s/ Merrill A. Miller, Jr.
Merrill A. Miller, Jr.
Chairman, President and Chief Executive Officer
/s/ Clay C. Williams
Clay C. Williams
Senior Vice President and Chief Financial Officer
Houston, Texas
February 25, 2009

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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, 2008 and 2007 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, 2008. 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, 2008 and 2007, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2008, 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 10, effective January 1, 2008 the Company adopted the measurement date provisions of 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, 2008, 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 25, 2009 expressed an unqualified opinion thereon.
/s/ ERNST & YOUNG LLP
Houston, Texas
February 25, 2009

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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, 2008, 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.
As indicated in the accompanying Management’s Report on Internal Control over Financial Reporting, management’s assessment of and conclusion on the effectiveness of internal control over financial reporting did not include the internal controls of the Grant Prideco business acquired in 2008, which are included in the 2008 consolidated financial statements of National Oilwell Varco, Inc. The Grant Prideco businesses represented approximately 36% of consolidated assets at December 31, 2008, 11% of consolidated revenues and 10% of consolidated operating profit for the year ended December 31, 2008. Our audit of internal control over financial reporting of National Oilwell Varco, Inc. also did not include an evaluation of the internal control over financial reporting of the Grant Prideco businesses.
In our opinion, National Oilwell Varco, Inc. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2008 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, 2008 and 2007 and the related consolidated statements of income, stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2008, and our report dated February 25, 2009 expressed an unqualified opinion thereon.
/s/ ERNST & YOUNG LLP
Houston, Texas
February 25, 2009

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NATIONAL OILWELL VARCO, INC.
CONSOLIDATED BALANCE SHEETS
(In millions, except share data)
                 
    December 31,  
    2008     2007  
ASSETS
Current assets:
               
Cash and cash equivalents
  $ 1,542.8     $ 1,841.8  
Receivables, net
    3,135.9       2,099.8  
Inventories, net
    3,806.0       2,574.7  
Costs in excess of billings
    618.5       643.5  
Deferred income taxes
    270.9       131.5  
Prepaid and other current assets
    283.1       302.5  
 
           
Total current assets
    9,657.2       7,593.8  
 
               
Property, plant and equipment, net
    1,676.7       1,197.3  
Deferred income taxes
    126.0       55.6  
Goodwill
    5,225.0       2,445.1  
Intangibles, net
    4,300.3       774.1  
Investment in unconsolidated affiliate
    420.8        
Other assets
    72.7       49.0  
 
           
Total assets
  $ 21,478.7     $ 12,114.9  
 
           
 
               
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
               
Accounts payable
  $ 851.9     $ 604.0  
Accrued liabilities
    2,376.3       1,761.4  
Billings in excess of costs
    2,160.7       1,396.1  
Current portion of long-term debt and short-term borrowings
    4.3       152.8  
Accrued income taxes
    230.3       112.4  
 
           
Total current liabilities
    5,623.5       4,026.7  
 
               
Long-term debt
    869.6       737.9  
Deferred income taxes
    2,134.4       564.3  
Other liabilities
    127.7       61.8  
 
           
Total liabilities
    8,755.2       5,390.7  
 
           
 
               
Commitments and contingencies
               
 
               
Minority interest
    95.9       62.8  
 
           
 
               
Stockholders’ equity:
               
Common stock - par value $.01; 417,350,924 and 356,867,498 shares issued and ouststanding at December 31, 2008 and December 31, 2007
    4.2       3.6  
Additional paid-in capital
    7,989.1       3,617.2  
Accumulated other comprehensive income (loss)
    (161.8 )     195.0  
Retained earnings
    4,796.1       2,845.6  
 
           
Total stockholders’ equity
    12,627.6       6,661.4  
 
           
Total liabilities and stockholders’ equity
  $ 21,478.7     $ 12,114.9  
 
           
The accompanying notes are an integral part of these statements.

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NATIONAL OILWELL VARCO, INC.
CONSOLIDATED STATEMENTS OF INCOME
(In millions, except per share data)
                         
    Years Ended December 31,  
    2008     2007     2006  
Revenue
                       
Sales
  $ 11,162.5     $ 7,873.3     $ 5,472.5  
Services
    2,268.9       1,915.7       1,553.3  
 
                 
Total
    13,431.4       9,789.0       7,025.8  
 
                 
 
                       
Cost of revenue
                       
Cost of sales
    7,783.9       5,675.3       4,230.4  
Cost of services
    1,576.0       1,283.5       1,034.8  
 
                 
Total
    9,359.9       6,958.8       5,265.2  
 
                 
 
                       
Gross profit
    4,071.5       2,830.2       1,760.6  
Selling, general and administrative
    1,154.0       785.8       649.5  
 
                 
Operating profit
    2,917.5       2,044.4       1,111.1  
 
                       
Interest and financial costs
    (67.3 )     (50.3 )     (48.7 )
Interest income
    44.6       52.6       18.1  
Equity income in unconsolidated affiliate
    42.4              
Other income (expense), net
    24.1       (17.8 )     (31.3 )
 
                 
Income before income taxes and minority interest
    2,961.3       2,028.9       1,049.2  
Provision for income taxes
    992.8       675.8       355.7  
 
                 
Income before minority interest
    1,968.5       1,353.1       693.5  
Minority interest in income of consolidated subsidiaries
    16.5       16.0       9.5  
 
                 
Net income
  $ 1,952.0     $ 1,337.1     $ 684.0  
 
                 
 
                       
Net income per share:
                       
Basic
  $ 4.91     $ 3.77     $ 1.95  
 
                 
Diluted
  $ 4.90     $ 3.76     $ 1.93  
 
                 
 
                       
Weighted average shares outstanding:
                       
Basic
    397.3       354.4       350.4  
 
                 
Diluted
    398.7       355.4       353.6  
 
                 
The accompanying notes are an integral part of these statements.

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NATIONAL OILWELL VARCO, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In millions)
                         
    Years Ended December 31,  
    2008     2007     2006  
Cash flows from operating activities:
                       
Net income
  $ 1,952.0     $ 1,337.1     $ 684.0  
Adjustments to reconcile net income to net cash provided by operating activities:
                       
Depreciation and amortization
    401.6       214.1       160.6  
Stock-based compensation
    66.8       43.1       31.2  
Excess benefit from the exercise of stock options
    (37.1 )     (22.9 )     (13.5 )
Equity income in unconsolidated affiliate
    (42.4 )            
Other non-cash items, net
    98.6       63.8       27.2  
Change in operating assets and liabilities, net of acquisitions:
                       
Receivables
    (625.9 )     (464.8 )     (442.1 )
Inventories
    (643.0 )     (757.6 )     (619.9 )
Costs in excess of billings
    25.0       (334.6 )     33.0  
Prepaid and other current assets
    230.3       (143.6 )     (101.7 )
Accounts payable
    95.3       84.2       (93.5 )
Billings in excess of costs
    764.6       831.6       466.4  
Other assets/liabilities, net
    8.3       337.6       1,085.0  
 
                 
 
                       
Net cash provided by operating activities
    2,294.1       1,188.0       1,216.7  
 
                 
 
                       
Cash flows from investing activities:
                       
Purchases of property, plant and equipment
    (378.5 )     (251.8 )     (200.4 )
Business acquisitions, net of cash acquired
    (3,007.9 )     (323.9 )     (329.7 )
Business divestitures, net of cash disposed
    800.9              
Dividend from unconsolidated affiliate
    112.7              
Other, net
    (0.5 )     0.8        
 
                 
 
                       
Net cash used in investing activities
    (2,473.3 )     (574.9 )     (530.1 )
 
                 
 
                       
Cash flows from financing activities:
                       
Borrowings against lines of credit and other debt
    2,730.8       47.0       30.0  
Payments against lines of credit and other debt
    (2,919.9 )     (11.6 )     (35.1 )
Excess tax benefits from exercise of stock options
    37.1       22.9       13.5  
Proceeds from stock options exercised
    78.0       91.3       32.7  
 
                 
 
                       
Net cash provided by (used in) financing activities
    (74.0 )     149.6       41.1  
 
                 
 
                       
Effect of exchange rates on cash
    (45.8 )     121.7       20.3  
 
                 
Increase (decrease) in cash equivalents
    (299.0 )     884.4       748.0  
Cash and cash equivalents, beginning of period
    1,841.8       957.4       209.4  
 
                 
Cash and cash equivalents, end of period
  $ 1,542.8     $ 1,841.8     $ 957.4  
 
                 
 
                       
Supplemental disclosures of cash flow information:
                       
Cash payments during the period for:
                       
Interest
  $ 75.6     $ 56.8     $ 56.2  
Income taxes
  $ 1,260.7     $ 703.4     $ 272.4  
The accompanying notes are an integral part of these statements.

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NATIONAL OILWELL VARCO, INC.
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY AND COMPREHENSIVE INCOME
(In millions)
                                                         
                                    Accumulated        
                    Additional   Unearned   Other        
    Shares   Common   Paid-in   Stock-Based   Comprehensive   Retained    
    Outstanding   Stock   Capital   Compensation   Income (Loss)   Earnings   Total
     
Balance at December 31, 2005
    348.7     $ 3.5     $ 3,399.1     $ (16.5 )   $ (21.8 )   $ 829.9     $ 4,194.2  
     
 
                                                       
Net income
                                  684.0       684.0  
Other comprehensive income:
                                                       
Currency translation adjustments
                            66.8             66.8  
Derivative financial instruments
                            8.0             8.0  
Change in defined benefit plans
                            (6.6 )           (6.6 )
 
                                                       
Comprehensive income
                                                    752.2  
Adoption of FAS158, net of tax
                            (0.3 )           (0.3 )
Adoption of FAS123R
                  (16.5 )     16.5                    
Stock-based compensation
                31.2                         31.2  
Common stock issued
    2.4             32.7                         32.7  
Excess tax benefit of options exercised
                13.5                         13.5  
     
 
                                                       
Balance at December 31, 2006
    351.1     $ 3.5     $ 3,460.0     $     $ 46.1     $ 1,513.9     $ 5,023.5  
     
 
                                                       
Net income
                                  1,337.1       1,337.1  
Other comprehensive income:
                                                       
Currency translation adjustments
                            136.6             136.6  
Derivative financial instruments
                            17.7             17.7  
Change in defined benefit plans
                            (5.4 )           (5.4 )
 
                                                       
Comprehensive income
                                                    1,486.0  
Adoption of FIN48
                                  (5.4 )     (5.4 )
Stock-based compensation
                43.1                         43.1  
Common stock issued
    4.8       0.1       91.2                         91.3  
Excess tax benefit of options exercised
                22.9                         22.9  
     
 
                                                       
Balance at December 31, 2007
    355.9     $ 3.6     $ 3,617.2     $     $ 195.0     $ 2,845.6     $ 6,661.4  
     
 
                                                       
Net income
                                  1,952.0       1,952.0  
Other comprehensive income:
                                                       
Currency translation adjustments
                            (176.4 )           (176.4 )
Derivative financial instruments
                            (160.6 )           (160.6 )
Change in defined benefit plans
                            (19.8 )           (19.8 )
 
                                                       
Comprehensive income
                                                    1,595.2  
Adoption of FAS158, net of tax
                                  (1.5 )     (1.5 )
Stock issued in acquisition
    56.9       0.6       4,190.1                         4,190.7  
Stock-based compensation
                66.8                         66.8  
Common stock issued
    4.6             77.9                         77.9  
Excess tax benefit of options exercised
                37.1                         37.1  
     
 
                                                       
Balance at December 31, 2008
    417.4     $ 4.2     $ 7,989.1     $     $ (161.8 )   $ 4,796.1     $ 12,627.6  
     
The accompanying notes are an integral part of these statements.

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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 2007 and 2006 consolidated financial statements in order for them to conform with the 2008 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 non-designated 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, 2008, we had entered into foreign currency forward contracts with notional amounts aggregating $2,743.4 million to hedge cash flow exposure to foreign currency exchange risk of forecasted or firm commitments. 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, 2008 and 2007 for contracts with similar terms and maturity dates, we have recorded a gain (loss) of ($142.1) million and $11.2 million, respectively, to adjust these foreign currency forward contracts to their fair market value of $21.2 million and $14.1 million, respectively. This loss is included in accumulated other comprehensive income (loss) in the consolidated balance sheet. It is expected that $48.2 million of the loss will be reclassified into earnings within the next 12 months with an offset by gains from the underlying transactions resulting in no impact to earnings or cash flow. At December 31, 2008, the Company has cash flow hedges in place through the second quarter of 2011. A gain (loss) from ineffectiveness of ($6.1) million and $4.6 million is included in earnings related to these foreign currency contracts for the years ending December 31, 2008 and 2007, respectively. Ineffectiveness for 2006 was not material.
At December 31, 2008, the Company had foreign currency forward contracts with notional amounts aggregating $131.9 million designated and qualifying as fair value hedges to hedge exposure to foreign currency exchange risk of firm commitments. Based on quoted market prices as of December 31, 2008 and 2007 for contracts with similar terms and maturity dates, we recorded a gain (loss) 

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of ($8.5) million and $79.9 million, respectively, to adjust these foreign currency forward contracts to their fair market value of ($5.6) million and $79.9 million, respectively. This loss offsets designated gains on firm commitments. At December 31, 2008, the Company has fair value hedges in place through the first quarter of 2011. Ineffectiveness for 2008, 2007 and 2006 was not material.
At December 31, 2008, the Company had foreign currency forward contracts with notional amounts aggregating $977.1 million to offset exposures to foreign currency exchange risk 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 $29.1 million for 2008 and $0.5 million for 2007 of these contracts are recorded each period in current earnings.
On January 4, 2008, the Company settled the net investment hedges with notional amounts aggregating $1,221.6 million by delivering Norwegian kroner and receiving U.S. dollars. The related cumulative tax-effected gain of $7.5 million was recorded in accumulated other comprehensive income (loss).
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 krone 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 denominated in U.S. dollars. As a Norwegian krone 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 foreign currency forward contracts with notional amounts aggregating $2,550.5 million with a fair value of $91.3 million 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 gain position of $108.8 million associated with the terminated hedges has been deferred and is being recognized into earnings in the future period(s) the forecasted transactions affect earnings, of which $64.3 million has been recognized into earnings at December 31, 2008. 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. At December 31, 2008, our Norway operations had derivatives with $2,547.5 million in notional value with a fair value of $6.3 million.
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 $123.2 million and $99.3 million at December 31, 2008 and 2007, respectively, 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 $221.9 million, $153.1 million and $119.2 million for the years ended December 31, 2008, 2007 and 2006, respectively. 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 are 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.

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Intangible Assets
On at least an annual basis, we assess whether goodwill and other indefinite-lived intangible assets are impaired. Our annual impairment tests are performed during 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. In the fourth quarter of 2008 and in the early stages of 2009, both commodity prices and rig activity dropped significantly and as a result, projections for the remainder of 2009 also reflected substantial declines compared to 2008. The Company updated its operating plans and discounted cash flows based on this information. The goodwill impairment analysis which we performed during the fourth quarter of 2008 and updated as of December 31, 2008, did not result in an impairment in the current year. The Company had no impairment of goodwill for the years ended December 31, 2007 and 2006. 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. While the Company primarily uses the discounted cash flow method to assess fair value, the Company uses the comparable companies and representative transaction methods to validate the discounted cash flow analysis and further support management’s expectations.
Goodwill is identified by segment as follows (in millions):
                                         
            Petroleum                    
    Rig     Services &     Distribution     Corporate/        
    Technology     Supplies     Services     Eliminations     Total  
Balance, December 31, 2006
  $ 1,168.3     $ 1,034.9     $ 35.2     $ 6.3     $ 2,244.7  
 
                                       
Purchase price and other adjustments
    (27.9 )     29.8                   1.9  
Goodwill acquired during period
    44.8       96.8                   141.6  
Translation adjustments
    45.5       7.5       3.9             56.9  
 
                             
 
                                       
Balance, December 31, 2007
    1,230.7       1,169.0       39.1       6.3       2,445.1  
 
                                       
Reorganization of segments
    231.8       (256.4 )     24.6              
Goodwill acquired
          2,812.5       2.7             2,815.2  
Translation adjustments
    (4.7 )     (25.9 )     (4.7 )           (35.3 )
 
                             
 
Balance, December 31, 2008
  $ 1,457.8     $ 3,699.2     $ 61.7     $ 6.3     $ 5,225.0  
 
                             
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 $240 million in each of the next five years. Included in intangible assets are approximately $790 million of indefinite-lived intangible assets.
Identified intangible assets are identified by segment as follows (in millions):
                                         
            Petroleum                    
    Rig     Services &     Distribution     Corporate/        
    Technology     Supplies     Services     Eliminations     Total  
Balance, December 31, 2006
  $ 264.2     $ 439.1     $ 1.9     $     $ 705.2  
 
Additions to intangible assets
    38.7       75.5                   114.2  
Amortization
    (20.7 )     (39.6 )     (0.3 )           (60.6 )
Translation
    6.6       8.4       0.3             15.3  
 
                             
 
                                       
Balance, December 31, 2007
    288.8       483.4       1.9             774.1  
 
                                       
Reorganization of segments
    97.0       (104.6 )     7.6              
Additions to intangible assets
    7.0       3,716.0                   3,723.0  
Amortization
    (30.8 )     (147.2 )     (1.2 )           (179.2 )
Translation
    (0.7 )     (14.9 )     (2.0 )           (17.6 )
 
                             
 
Balance, December 31, 2008
  $ 361.3     $ 3,932.7     $ 6.3     $     $ 4,300.3  
 
                             

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Identified intangible assets by major classification consist of the following (in millions):
                         
            Accumulated     Net Book  
    Gross     Amortization     Value  
December 31, 2007:
                       
 
                       
Customer relationships
  $ 554.1     $ (81.9 )   $ 472.2  
Trademarks
    214.6       (22.8 )     191.8  
Other
    143.0       (32.9 )     110.1  
 
                 
 
                       
Total identified intangibles
  $ 911.7     $ (137.6 )   $ 774.1  
 
                 
 
                       
December 31, 2008:
                       
 
                       
Customer relationships
  $ 2,751.5     $ (210.4 )   $ 2,541.1  
Trademarks
    1,373.8       (39.5 )     1,334.3  
Other
    493.7       (68.8 )     424.9  
 
                 
 
                       
Total identified intangibles
  $ 4,619.0     $ (318.7 )   $ 4,300.3  
 
                 
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 (loss). 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 $50.2 million, ($7.0 million) and ($21.0 million) for the years ending December 31, 2008, 2007 and 2006, 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 krone 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 and drill pipe sales 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, collectability 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 segment. 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.

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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.
Drill Pipe Sales
For drill pipe sales, if requested in writing by the customer, delivery may be satisfied through delivery to the Company’s customer storage location or to a third-party storage facility. For sales transactions where title and risk of loss have transferred to the customer but the supporting documentation does not meet the criteria for revenue recognition prior to the products being in the physical possession of the customer, the recognition of the revenues and related inventory costs from these transactions are deferred until the customer takes physical possession.
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):
         
Balance, December 31, 2006
  $ 57.3  
 
     
 
       
Net provisions for warranties issued during the year
    78.2  
Payments
    (45.9 )
Foreign currency translation
    1.9  
 
     
 
       
Balance, December 31, 2007
  $ 91.5  
 
     
 
Net provisions for warranties issued during the year
    77.4  
Payments
    (53.9 )
Foreign currency translation
    (1.1 )
 
     
 
       
Balance, December 31, 2008
  $ 113.9  
 
     
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

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receivable are net of allowances for doubtful accounts of approximately $72.7 million and $44.8 million at December 31, 2008 and 2007, 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, 2006, but for which the requisite service period had not been completed as of January 1, 2006 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, 2006 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 $60.8 million, $43.1 million and $31.2 million for 2008, 2007 and 2006, respectively. The total income tax benefit recognized in the income statement for all share-based compensation arrangements was $18.8 million, $13.2 million and $8.6 million for 2008, 2007 and 2006, respectively.
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 costs and related margins of projects accounted for under percentage- of-completion (“POC”), 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, estimates related to the fair value of reporting units for purposes of assessing goodwill and other Indefinite Lived Intangible Assets for impairment 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 liabilities 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.
In circumstances where the most likely outcome of a contingency can be reasonably estimated, we accrue a liability for that amount. Where the most likely outcome cannot be estimated, a range of potential losses is established and if no one amount in that range is more likely than other, the low end of the range is accrued.

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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):
                         
    Years Ended December 31,  
    2008     2007     2006  
Numerator:
                       
Net income
  $ 1,952.0     $ 1,337.1     $ 684.0  
 
                 
Denominator:
                       
Basic—weighted average common shares outstanding
    397.3       354.4       350.4  
Dilutive effect of employee stock options and other unvested stock awards
    1.4       1.0       3.2  
 
                 
Diluted outstanding shares
    398.7       355.4       353.6  
 
                 
 
                       
Basic earnings per share
  $ 4.91     $ 3.77     $ 1.95  
 
                 
Diluted earnings per share
  $ 4.90     $ 3.76     $ 1.93  
 
                 
In addition, we had stock options outstanding that were anti-dilutive totaling 0.4 million at December 31, 2008, 0.1 million at December 31, 2007 and 4.6 million at December 31, 2006.
Recently Issued Accounting Standards
In September 2006, the Financial Accounting Standards Board (“FASB”) 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. In February 2008, the FASB issued FSP 157-2, which delays the effective date of SFAS 157 for all nonfinancial assets and liabilities that are not recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually) until fiscal years beginning after November 15, 2008, and interim periods within those fiscal years. The Company adopted the provisions of SFAS 157 for financial assets and liabilities as of January 1, 2008. At December 31, 2008, the Company has determined that its financial assets of $31.6 million and liabilities of $83.1 million (primarily currency related derivatives) are level 2 in the fair value hierarchy. At December 31, 2008, the fair value of the Company’s foreign currency forward contracts totaled $2.3 million. There was no significant impact to the Company’s consolidated financial statements from the adoption of SFAS 157.
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. On January 1, 2008, the Company adopted SFAS 159 and elected not to measure any of its currently eligible assets and liabilities at fair value.
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 expects 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.
In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities — an amendment of FASB Statement No. 133” (“SFAS 161”). SFAS 161 amends and expands the disclosure requirements for derivative instruments

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and hedging activities, with the intent to provide users of financial statements with an enhanced understanding of how and why an entity uses derivative instruments, how derivative instruments and related hedged items are accounted for, and how derivative instruments and related hedged items affect an entity’s financial statements. SFAS 161 is effective for fiscal years and interim periods beginning after November 15, 2008. The Company is currently evaluating the potential impact that the application of SFAS 161 to its nonfinancial assets and liabilities will have on its consolidated financial statements.
In April 2008, the FASB issued FASB Staff Position (“FSP”) SFAS 142-3, “Determination of the Useful Life of Intangible Assets” (“FSP SFAS 142-3”). FSP SFAS 142-3 amends the factors that should be considered in developing renewal or extension assumptions used to determine the useful life of a recognized intangible asset under FASB Statement No. 142, “Goodwill and Other Intangible Assets". The objective of this FSP is to improve the consistency between the useful life of a recognized intangible asset under Statement No. 142 and the period of expected cash flows used to measure the fair value of the asset under SFAS 141R, “Business Combinations", and other U.S. GAAP principles. FSP SFAS 142-3 is effective for fiscal years beginning after December 15, 2008. The Company is currently assessing the impact of FSP SFAS 142-3 on its consolidated financial position and results of operations.
3. Grant Prideco Merger
Pursuant to the Agreement and Plan of Merger with Grant Prideco, Inc. (“Grant Prideco”) (the “Merger”), a Delaware Corporation, effective December 16, 2007 (the “Agreement Date”), the Company issued .4498 shares of National Oilwell Varco, Inc. common stock and $23.20 in cash (the “Exchange Ratio”) for each Grant Prideco common share outstanding on April 21, 2008 (the “Merger Date”) totaling approximately 56.9 million shares and $2.9 billion in cash. The Company has included the financial results of Grant Prideco in its consolidated financial statements beginning on the Merger Date, the date Grant Prideco common shares were exchanged for National Oilwell Varco common shares and cash. The Grant Prideco operations are included in the Petroleum Services & Supplies segment.
Grant Prideco is a world leader in drill stem technology development and drill pipe manufacturing, sales and service and a global leader in drill bit and specialty tools, manufacturing, sales and service. The Company believes the Merger with Grant Prideco advances its strategic goal of providing more products and services to its customers and that Grant Prideco’s product range adds new growth opportunities to the Company and benefit its customers’ needs worldwide.
The Merger has been accounted for as a purchase business combination. Assets acquired and liabilities assumed were recorded at their estimated fair values as of April 21, 2008. The total preliminary purchase price is $7,198.6 million, including Grant Prideco stock options assumed and acquisition related transaction costs and is comprised of (in millions):
Consideration given to acquire the outstanding common stock of Grant Prideco:
         
Shares issued totaled approximately 56.9 million shares at $72.74 per share
  $ 4,135.3  
Cash paid at $23.20 per share
    2,932.3  
Grant Prideco stock options assumed
    55.4  
Merger related transaction costs
    75.6  
 
     
Total preliminary purchase price
  $ 7,198.6  
 
     
The fair value of shares issued was determined using an average price of $72.74, which represents the average closing price of the Company’s common stock for a five-day period beginning two available trading days before the public announcement of the transaction. For all stock options and restricted stock granted prior to 2008, vesting was accelerated under the terms of the stock option and restricted stock agreements; therefore, there was no modification of the awards as defined under SFAS 123(R). For stock options and restricted stock granted by Grant Prideco in 2008, 320,500 Grant Prideco stock options and 388,000 shares of restricted stock were replaced with 250,402 National Oilwell Varco stock options and 303,212 shares of National Oilwell Varco restricted stock, respectively. For the 2008 Grant Prideco grants, vesting was not accelerated in connection with the Merger, under the terms of the stock option and restricted stock agreements, except for certain recipients of the 2008 Grant Prideco restricted stock grant.
Merger related costs of $75.6 million include severance and other external costs directly related to the Merger.
Transaction costs of $10.9 million for the year ending December 31, 2008 were comprised of $6.0 million for accelerated vesting of stock-based compensation, $4.0 million for bridge loan fees and $0.9 million of other costs and are included in selling, general and administrative expense in the Consolidated Statements of Income.
Preliminary Purchase Price Allocation
Under the purchase method of accounting, the total preliminary purchase price was allocated to Grant Prideco’s net tangible and identifiable intangible assets based on their estimated fair values as of April 21, 2008. The excess of the purchase price over the net tangible and identifiable intangible assets was recorded as goodwill. The preliminary allocation of the purchase price was based upon preliminary valuations, and our estimates and assumptions are subject to change upon the receipt and management’s review of the final valuations. The primary areas of the purchase price allocation, which are not yet finalized, relate to identifiable intangible assets,

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goodwill, certain preacquisition contingencies and related adjustments to deferred taxes. The final valuation of net assets is expected to be completed as soon as possible, but no later than one year from the acquisition date. The following table, set forth below, displays the total preliminary purchase price allocated to Grant Prideco’s net tangible and identifiable intangible assets based on their estimated fair values as of April 21, 2008 (in millions):
         
Cash and cash equivalents
  $ 170.9  
Receivables
    419.7  
Assets held for sale, net
    783.9  
Inventories
    616.7  
Prepaid and other current assets
    209.6  
Property, plant and equipment
    392.0  
Goodwill
    2,739.0  
Intangibles
    3,695.9  
Investment in unconsolidated affiliate
    511.6  
Other assets
    97.5  
Accounts payable and accrued liabilities
    (316.4 )
Accrued income taxes
    (623.9 )
Long-term debt
    (176.4 )
Deferred income taxes
    (1,278.0 )
Minority interest
    (24.8 )
Other liabilities
    (18.7 )
 
     
Total preliminary purchase price
  $ 7,198.6  
 
     
Under purchase accounting, a fair value step up adjustment of $89.1 million was made to inventory and is being charged to “Cost of sales” as the applicable inventory is sold. Cost of sales includes $89.1 million of these inventory charges for the year ended December 31, 2008.
Additionally, the Company identified other intangible assets associated with tradenames, patents, and customer relationships, and the preliminary fair values assigned were $1.2 billion, $0.3 billion, and $2.2 billion, respectively. The initial range of useful lives associated with trade names, patents, and customer relationships were 40 years to an indefinite life, 5 to 15 years and 16 to 17 years, respectively. Of the $1.2 billion associated with trade names, $0.8 billion has been initially identified as having an indefinite life.
Disposition of Certain Grant Prideco Businesses
Prior to the Merger, Grant Prideco had entered into a definitive Purchase and Sale Agreement with Vallourec S.A. and Vallourec & Mannesman Holdings, Inc. (collectively referred to as “Vallourec”) to sell four of its tubular businesses for approximately $800 million in cash, subject to final working capital adjustments and standard closing conditions (including regulatory approval). The transaction closed May 16, 2008. The amount included in “Assets held for sale, net” included in the preliminary purchase price allocation above, relates to this disposition. Additionally, $255.8 million is included above in “Accrued income taxes” for taxes related to the disposition.
Unaudited Pro Forma Financial Information
The unaudited financial information in the table below summarizes the combined results of operations of National Oilwell Varco and Grant Prideco, on a pro forma basis, as though the companies had been combined as of the beginning of each of the periods presented. 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 the beginning of each of the periods presented. The pro forma financial information for all periods presented includes the business combination accounting effect on historical Grant Prideco revenues, adjustments to depreciation on acquired property, amortization charges from acquired intangible assets, financing costs on new debt in connection with the Merger and related tax effects.

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The unaudited pro forma financial information for the years ended December 31, 2008 and 2007 combines the historical results for National Oilwell Varco for the years ended December 31, 2008 and 2007 and the historical results for Grant Prideco for the years ended December 31, 2008 and 2007 (in millions):
                 
    Years Ended December 31,  
    2008     2007  
Total revenues
  $ 14,035.1     $ 11,192.2  
 
           
Net income
  $ 2,080.1     $ 1,533.7  
 
           
Basic net income per share
  $ 5.02     $ 3.88  
 
           
Diluted net income per share
  $ 4.99     $ 3.86  
 
           
4. Other Acquisitions
2008
In addition to the Grant Prideco Merger, The Company completed nine acquisitions for an aggregate purchase price of $170.7 million net of cash acquired. These acquisitions included:
    Welch Power Source, L.L.C., a Louisiana-based manufacturer of power generation equipment.
 
    CKS, a France-based solids control company.
 
    Mid-South Machine, Inc., a Louisiana-based machine shop.
The following table summarizes the estimated fair values of the assets acquired and liabilities assumed at the date of acquisition of the 2008 acquisitions (in millions):
         
    Total  
Current assets, net of cash acquired
  $ 32.1  
Property, plant and equipment
    61.2  
Intangible assets
    38.1  
Goodwill
    76.2  
 
       
Total assets acquired
    207.6  
 
     
 
       
Current liabilities
    11.2  
Long-term debt
    25.7  
 
     
 
       
Total liabilities
    36.9  
 
     
 
       
Cash consideration, net of cash acquired
  $ 170.7  
 
     
The Company allocated $38.1 million to intangible assets (9.1 year weighted-average life), comprised of: $30.2 million of customer relationships (14.7 year weighted-average life), $0.6 million of trademarks (15.8 year weighted-average life), and $7.3 million of other intangible assets (3.5 year weighted-average life).

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2007
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:
    Gammaloy Holdings, L.P., a Texas-based manufacturer of downhole tools.
 
    Kreiter Geartech, a Texas-based manufacturer of gearing products.
 
    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):
         
    Total  
Current assets, net of cash acquired
  $ 49.9  
Property, plant and equipment
    48.9  
Intangible assets
    114.2  
Goodwill
    141.6  
 
     
 
       
Total assets acquired
    354.6  
 
     
 
       
Current liabilities
    37.4  
Long-term debt
    20.0  
 
     
 
       
Total liabilities
    57.4  
 
     
 
       
Minority interest
    11.4  
 
     
 
       
Cash consideration, net of cash acquired
  $ 285.8  
 
     
Based on 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).
In January 2007, the Company also acquired the remaining 13% of NQL Energy Services, Inc.’s outstanding shares for $38.1 million.
2006
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:
    Rolligon Ltd., a Texas-based manufacturer of coiled tubing support units and related equipment.
 
    Soil Recovery A/S, a Danish-based designer and manufacturer of soil recovery units used to process drilled cuttings for final disposal.

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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):
                         
            All Other        
    NQL     Acquisitions     Total  
     
Current assets, net of cash acquired
  $ 68.9     $ 30.5     $ 99.4  
Property, plant and equipment
    64.3       13.6       77.9  
Intangible assets
    126.6       3.9       130.5  
Goodwill
    60.1       56.7       116.8  
 
                 
 
                       
Total assets acquired
    319.9       104.7       424.6  
 
                 
 
Current liabilities
    65.7       19.4       85.1  
Long-term debt
    0.4       9.4       9.8  
 
                 
 
                       
Total liabilities
    66.1       28.8       94.9  
 
                 
 
                       
Cash consideration, net of cash acquired
  $ 253.8     $ 75.9     $ 329.7  
 
                 
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. Excluding the Grant Prideco merger, a summary of the acquisitions follows (in millions):
                         
    2008     2007     2006  
Fair value of assets acquired, net of cash acquired
  $ 207.6     $ 354.6     $ 424.6  
Cash paid, net of cash acquired
    (170.7 )     (285.8 )     (329.7 )
 
                 
Liabilities assumed, debt issued and minority interest
  $ 36.9     $ 68.8     $ 94.9  
 
                 
Excess purchase price over fair value of net assets acquired
  $ 76.2     $ 141.6     $ 116.8  
 
                 
5. Inventories, net
At December 31, inventories consist of (in millions):
                 
    December 31,  
    2008     2007  
Raw materials and supplies
  $ 739.0     $ 420.4  
Work in process
    1,326.2       939.2  
Finished goods and purchased products
    1,740.8       1,215.1  
 
           
Total
  $ 3,806.0     $ 2,574.7  
 
           
6. Property, Plant and Equipment
At December 31, property, plant and equipment consist of the following (in millions):
                         
    Estimated     December 31,  
    Useful Lives     2008     2007  
Land and buildings
  5-35 Years   $ 543.7     $ 412.3  
Operating equipment
  3-15 Years     1,258.7       927.3  
Rental equipment
  3-12 Years     526.8       370.5  
 
                   
 
            2,329.2       1,710.1  
Less: Accumulated Depreciation
            (652.5 )     (512.8 )
 
                   
 
          $ 1,676.7     $ 1,197.3  
 
                   

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7. Accrued Liabilities
At December 31, accrued liabilities consist of (in millions):
                 
    December 31,  
    2008     2007  
Compensation
  $ 258.3     $ 214.7  
Customer prepayments and billings
    912.1       500.3  
Warranty
    114.0       91.5  
Interest
    11.4       13.8  
Taxes (non income)
    75.6       47.3  
Insurance
    50.4       42.4  
Accrued purchase orders
    688.0       582.5  
Fair value of derivatives
    59.3       111.3  
Other
    207.2       157.6  
 
           
Total
  $ 2,376.3     $ 1,761.4  
 
           
8. Costs and Estimated Earnings on Uncompleted Contracts
At December 31, costs and estimated earnings on uncompleted contracts consist of (in millions):
                 
    December 31,  
    2008     2007  
Costs incurred on uncompleted contracts
  $ 4,776.6     $ 3,167.2  
Estimated earnings
    2,277.0       1,208.3  
 
           
 
    7,053.6       4,375.5  
Less: Billings to date
    8,595.8       5,128.1  
 
           
 
  $ (1,542.2 )   $ (752.6 )
 
           
 
               
Costs and estimated earnings in excess of billings on uncompleted contracts
  $ 618.5     $ 643.5  
Billings in excess of costs and estimated earnings on uncompleted contracts
    (2,160.7 )     (1,396.1 )
 
           
 
  $ (1,542.2 )   $ (752.6 )
 
           

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9. Long-Term Debt
At December 31, debt consists of (in millions):
                 
    December 31,  
    2008     2007  
$100.0 million Senior Notes, interest at 7.5% payable semiannually, principal due on February 15, 2008
  $     $ 100.2  
 
               
$150.0 million Senior Notes, interest at 6.5% payable semiannually, principal due on March 15, 2011
    150.0       150.0  
 
               
$200.0 million Senior Notes, interest at 7.25% payable semiannually, principal due on May 1, 2011
    208.2       211.7  
 
               
$200.0 million Senior Notes, interest at 5.65% payable semiannually, principal due on November 15, 2012
    200.0       200.0  
 
               
$150.0 million Senior Notes, interest at 5.5% payable semiannually, principal due on November 19, 2012
    151.0       151.3  
 
               
Senior Notes, interest at 6.125% payable semiannually, principal due on August 15, 2015
    151.0        
 
               
Other
    13.7       77.5  
 
           
Total debt
    873.9       890.7  
Less current portion
    4.3       152.8  
 
           
Long-term debt
  $ 869.6     $ 737.9  
 
           
Principal payments of debt for years subsequent to 2008 are as follows (in millions):
         
2009
  $ 4.3  
2010
    11.4  
2011
    353.1  
2012
    351.2  
2013
    2.8  
Thereafter
    151.1  
 
     
 
  $ 873.9  
 
     
Senior Notes
In connection with the Grant Prideco merger, the Company completed an exchange offer relative to the $174.6 million of 6.125% Senior Notes due 2015 previously issued by Grant Prideco. On April 21, 2008, $150.8 million of Grant Prideco Senior Notes were exchanged for National Oilwell Varco Senior Notes. The National Oilwell Varco Senior Notes have the same interest rate, interest payment dates, redemption terms and maturity as the Grant Prideco Senior Notes. In November 2008, the Company repurchased $23.6 million of the unexchanged Grant Prideco Senior Notes.
Revolving Credit Facilities
On April 21, 2008, the Company replaced its existing $500.0 million unsecured revolving credit facility with an aggregate of $3.0 billion of unsecured credit facilities and borrowed $2.0 billion to finance the cash portion of the Grant Prideco acquisition. These facilities consist of a $2.0 billion, five-year revolving credit facility and a $1.0 billion, 364-day revolving credit facility. At December 31, 2008, there were no borrowings against these facilities, and there were $603.1 million in outstanding letters of credit issued under these facilities, resulting in $2,396.9 million of funds available under this revolving credit facility at year-end. Interest under this multicurrency facility is based upon LIBOR, NIBOR or EURIBOR plus 0.26% or 0.28% subject to a ratings-based grid, or the prime rate. In early February 2009, we terminated the $1.0 billion, 364-day revolving credit facility, which matured April 20, 2009.

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The Company also had $2.6 billion of additional outstanding letters of credit at December 30, 2008, primarily in Norway, that are essentially under various bilateral committed letter of credit facilities. The $1.3 billion increase in letters of credit since December 31, 2007 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. The Senior Notes contain reporting covenants and the credit facility contains a financial covenant regarding maximum debt to capitalization. We were in compliance with all covenants at December 31, 2008.
Other
Other debt includes approximately $5.5 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, 2008, 2007 and 2006, expenses for defined-contribution plans were $36.6 million, $30.7 million, and $16.8 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 364 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.
As part of the purchase of Grant Prideco, Inc in 2008, National Oilwell Varco, Inc acquired the Reed Hourly Pension Plan which covers approximately 129 employees and was frozen in 2007 prior to the acquisition. The Plan is included in the consolidated National Oilwell Varco, Inc US Plan at December 31, 2008.
Implementation of SFAS 158
SFAS 158 measurement of 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, which the Company adopted effective December 31, 2008. The following table summarizes the impact stemming from the adoption of SFAS 158 on December 31, 2008. Net periodic benefit cost for our defined benefit pension plans in the United States, the United Kingdom and Norway was as follows (in millions):
                                                                                 
    Pension benefits     Postretirement benefits  
For the year   2008     2007     2006     2008     2007     2006  
    15 Months     12 Months     3 Months                     15 Months     12 Months     3 Months                  
Service cost — benefits earned during the period
  $ 4.8     $ 3.8     $ 1.0     $ 5.1     $ 3.8     $     $     $     $     $  
Interest cost on projected benefit obligation
    11.9       9.5       2.4       12.2       10.7       0.8       0.6       0.2       1.0       1.0  
Expected return on plan assets
    (11.7 )     (9.4 )     (2.3 )     (12.5 )     (10.5 )                              
 
                                                           
Total service cost, interest cost , and expected return on plan assets
    5.0       3.9       1.1       4.8       4.0       0.8       0.6       0.2       1.0       1.0  
 
                                                           
Net amortization and deferral
    1.2       1.0       0.2       1.9       0.8                         0.1       0.2  
Curtailment/settlement gain
                            (0.4 )                                
 
                                                           
Total amortization, curtailment/settlement
    1.2       1.0       0.2       1.9       0.4                         0.1       0.2  
 
                                                           
Net periodic benefit cost
  $ 6.2     $ 4.9     $ 1.3     $ 6.7     $ 4.4     $ 0.8     $ 0.6     $ 0.2     $ 1.1     $ 1.2  
 
                                                           

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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 December 31, 2008 and September 30, 2007, follows (in millions):
                                 
    Pension benefits     Postretirement benefits  
At year end   2008     2007     2008     2007  
Benefit obligation at beginning of year
  $ 246.3     $ 229.9     $ 14.0     $ 17.0  
Service cost
    4.7       5.1              
Interest cost
    12.3       12.2       1.0       1.0  
Actuarial gain
    (6.2 )     (0.7 )     5.2       (1.3 )
Benefits paid
    (12.6 )     (10.4 )     (1.9 )     (1.3 )
Participants contributions
    1.1       0.9              
Exchange rate (loss) gain
    (49.9 )     10.0              
Curtailments/settlements
          (0.7 )            
Acquisitions/divestitures, net
    17.4                    
Other
    1.3             2.0       (1.4 )
 
                       
Benefit obligation at end of year
  $ 214.4     $ 246.3     $ 20.3     $ 14.0  
 
                       
 
                               
Accumulated benefit obligation at end of year
  $ 198.3     $ 222.7                  
 
                           
 
                               
Fair value of plan assets at beginning of year
  $ 206.1     $ 183.4     $     $  
Actual return
    (23.4 )     14.7              
Benefits paid
    (12.5 )     (9.2 )     (1.9 )     (1.3 )
Company contributions
    17.3       9.9       1.9       1.3  
Participants contributions
    1.1       0.9              
Exchange rate (loss) gain
    (49.5 )     6.4              
Acquisitions/divestitures, net
    16.3                    
Other
    (1.9 )                  
 
                       
Fair value of plan assets at end of year
  $ 153.5     $ 206.1     $     $  
 
                       
Funded status
  $ (60.9 )   $ (41.9 )   $ (20.3 )   $ (13.7 )
Unrecognized actuarial net loss
    51.8       28.6       6.3       0.7  
Prior service costs not yet recognized
    1.0       0.8       (0.6 )     (0.7 )
 
                       
Accrued benefit cost
  $ (8.1 )   $ (12.5 )   $ (14.6 )   $ (13.7 )
 
                       
Amounts recognized in the consolidated balance sheets consist of (in millions):
                                 
    Pension benefits     Postretirement benefits  
    2008     2007     2008     2007  
Current assets
  $     $     $     $  
Non current assets
    0.4       0.9              
Non current liabilities
    (61.3 )     (42.8 )     (20.3 )     (13.7 )
Accumulated other comprehensive income
    52.8       29.4              
 
                       
Accrued benefit cost
  $ (8.1 )   $ (12.5 )   $ (20.3 )   $ (13.7 )
 
                       

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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:
         
    Years ending December 31,
    2008   2007
Discount rate:
       
United States plan
  6.23%   6.34%
International plans
  5.75% - 6.50%   5.50% - 5.75%
 
Salary increase:
       
United States plan
  N/A   N/A
International plans
  2.50% - 4.50%   2.50% - 4.50%
The assumption rates used for net periodic benefit costs are as follows:
                         
    Years ending December 31,  
    2008     2007     2006  
Discount rate:
                       
United States plan
    6.34%     5.97%     5.66%
International plans
    5.50% - 5.75 %     4.75% - 5.25 %     5.66%
 
Salary increase:
                       
United States plan
    N/A       N/A       N/A  
International plans
    2.50% - 4.50 %     2.25% - 3.00 %     2.00% - 2.75 %
 
Expected return on assets:
                       
United States plan
    7.75%     7.75%     7.75%
International plans
    5.50% - 6.86 %     5.17% - 6.86 %     5.25% - 6.85 %
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, 2008 and 2007, by asset category are as follows:
                                 
    For the years ending December 31,  
    2008     2007    
    United States     International     United States     International  
Equity securities
    49.8 %     43.3 %     61.0 %     46.3 %
Debt securities
    34.7 %     32.9 %     38.8 %     32.7 %
Real estate
    0.8 %     0.0 %     0.0 %     4.8 %
Other
    14.7 %     23.8 %     0.2 %     16.2 %
 
                       
Total
    100.0 %     100.0 %     100.0 %     100.0 %
 
                       
In the U.S., our investment strategy includes a balanced approach with target allocation percentages of 50-60% equity investments and 40-50% 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.

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Information for pension plans with projected benefit obligations in excess of plan assets (in millions):
                                 
    For the years ending December 31,
    2008   2007
    United States   International   United States   International
Projected benefit obligation
  $ 44.4     $ 167.3     $ 10.5     $ 216.5  
Accumulated benefit obligation
    44.4       151.6       10.5       192.4  
Fair value of assets
    25.8       124.6             183.1  
Information for pension plans with accumulated benefit obligations in excess of plan assets (in millions):
                                 
    For the years ending December 31,
    2008   2007
    United States   International   United States   International
Projected benefit obligation
  $ 44.4     $ 140.0     $ 10.5     $ 24.4  
Accumulated benefit obligation
    44.4       135.0       10.5       22.3  
Fair value of assets
    25.8       103.4              
In 2009, the Company expects to contribute $4.0 million in the U.S. and $5.7 million internationally to its pension plans and $1.7 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):
                         
    United States   International   Post-Retirement
    Plan   Plans   Benefit Plans
2009
  $ 4.2     $ 7.0     $ 1.7  
2010
    4.2       7.3       1.8  
2011
    4.2       7.6       1.8  
2012
    4.2       7.9       1.8  
2013
    4.2       8.3       1.7  
Thereafter
    17.3       47.5       8.0  
11. Accumulated Other Comprehensive Income (Loss)
The components of accumulated other comprehensive income (loss) are as follows (in millions):
                                 
    Change in     Cumulative Currency     Derivative        
    Defined     Translation     Financial        
    Benefit Plans     Adjustments     Instruments     Total  
Balance at December 31, 2005
  $ (8.4 )   $ (6.8 )   $ (6.6 )   $ (21.8 )
 
                       
 
                               
Adoption of FAS 158, net of tax
    (0.3 )                 (0.3 )
Current period activity
    (9.3 )     61.2       11.3       63.2  
Tax effect
    2.7       5.6       (3.3 )     5.0  
 
                       
 
                               
Balance at December 31, 2006
  $ (15.3 )   $ 60.0     $ 1.4     $ 46.1  
 
                       
 
                               
Current period activity
    (8.3 )     210.6       25.3       227.6  
Tax effect
    2.9       (74.0 )     (7.6 )     (78.7 )
 
                       
 
                               
Balance at December 31, 2007
  $ (20.7 )   $ 196.6     $ 19.1     $ 195.0  
 
                       
 
                               
Current period activity
    (29.8 )     (265.4 )     (241.6 )     (536.8 )
Tax effect
    10.0       89.0       81.0       180.0  
 
                       
 
                               
Balance at December 31, 2008
  $ (40.5 )   $ 20.2     $ (141.5 )   $ (161.8 )
 
                       

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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, 2008 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.
We have received federal grand jury subpoenas requesting records related to our exports to and other activities in certain countries. We are cooperating fully with agents from the U.S. Department of Commerce, Bureau of Industry and Security, in responding to the subpoenas. Based on available information, we cannot predict what effect the subpoenas or any resulting government action may have on our financial position or results of operations.
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 $183.5 million, $128.4 million, and $95.4 million in 2008, 2007 and 2006, respectively.
Future minimum lease commitments under noncancellable operating leases with initial or remaining terms of one year or more at December 31, 2008 are payable as follows (in millions):
         
2009
  $ 114.1  
2010
    93.2  
2011
    64.8  
2012
    49.9  
2013
    41.9  
Thereafter
    156.9  
 
     
Total future lease commitments
  $ 520.8  
 
     
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, 2008, approximately 5.3 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, Varco International, Inc. in 2005 and Grant Prideco Inc in 2008. We converted the outstanding stock options under these plans to options to acquire our common stock and no further options are being issued 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, 2008 under the stock option plans have exercise prices between $5.72 and $73.98 per share, and expire at various dates from February 8, 2009 to May 15, 2018.

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The following summarizes options activity:
                                                 
    Years Ended December 31,  
    2008     2007     2006  
    Number     Average     Number     Average     Number     Average  
    of     Exercise     of     Exercise     of     Exercise  
    Shares     Price     Shares     Price     Shares     Price  
Shares under option at beginning of year
    7,903,832     $ 29.12       10,559,862     $ 23.28       8,681,684     $ 15.18  
Granted
    2,993,000       48.59       2,381,300       35.55       4,680,000       33.29  
Cancelled
    (218,560 )     30.90       (301,608 )     30.55       (415,396 )     23.43  
Exercised
    (3,130,450 )     27.08       (4,735,722 )     19.28       (2,386,426 )     13.58  
 
                                   
 
                                               
Shares under option at end of year
    7,547,822     $ 37.24       7,903,832     $ 29.12       10,559,862     $ 23.28  
 
                                   
 
                                               
Exercisable at end of year
    3,110,462     $ 26.17       1,619,374     $ 19.55       2,688,298     $ 13.85  
 
                                   
The following summarizes information about stock options outstanding as of December 31, 2008:
                                         
            Options Outstanding     Options Exercisable  
    Weighted-Avg                              
    Ramaining             Weighted-Avg             Weighted-Avg  
Range of Exercise Price   Contractual Life     Shares     Exercise Price     Shares     Exercise Price  
$4.72 to $12.75
    3.91       366,523     $ 9.93       366,523     $ 9.93  
$13.08 to $28.04
    4.61       1,224,732       18.03       1,224,732       18.03  
$29.13 to $73.98
    8.00       5,956,567       42.88       1,519,207       36.66  
 
                             
 
                                       
Total
    7.25       7,547,822     $ 37.24       3,110,462     $ 26.17  
 
                             
The weighted-average fair value of options granted during 2008, 2007 and 2006 was approximately $22.16, $11.99 and $11.90 (excluding options assumed in the Grant Prideco merger) per share, respectively, as determined using the Black-Scholes option-pricing model. The total intrinsic value of options exercised during 2008 and 2007 was $154.5 million and $114.2 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.
                         
    Years Ended December 31,
    2008   2007   2006
Valuation Assumptions:
                       
Expected volatility
    41.8 %     38.6 %     39.4 %
Risk-free interest rate
    2.9 %     4.6 %     4.6 %
Expected dividends
  $     $     $  
Expected term (in years)
    3.6       3.5       3.8  
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.

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As stock-based compensation expense recognized in the Consolidated Statement of Income in 2008 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, 2008 and changes during 2008 with regard to options under all stock option plans:
                                 
                    Weighted    
                    Remaining    
            Weighted Average   Contractual   Aggregate
    Shares   Exercise Price   (years)   Intrinsic Value
Outstanding at December 31, 2007
    7,903,832     $ 29.12                  
Granted
    2,993,000     $ 48.59                  
Exercised
    (3,130,450 )   $ 27.08                  
Cancelled
    (218,560 )   $ 30.90                  
 
                               
 
                               
Outstanding at December 31, 2008
    7,547,822     $ 37.24       7.25     $ 13,473,682  
 
                               
 
                               
Vested or expected to vest
    7,313,840     $ 37.24       7.25     $ 13,055,998  
 
                               
 
                               
Exercisable at December 31, 2008
    3,110,462     $ 26.17       5.90     $ 13,473,682  
 
                               
As of December 31, 2008, total unrecognized compensation cost related to nonvested stock options was $36.2 million. This cost is expected to be recognized over a weighted average period of 2.0 years. The total fair value of stock options vested in 2008, 2007 and 2006 was approximately $42.9 million, $33.5 million and $22.1 million, respectively. Cash received from option exercises for 2008, 2007 and 2006 was $78.0 million, $91.3 million and $32.7 million respectively. The actual tax benefit realized for the tax deductions from option exercises totaled $45.9 million, $34.2 million and $15.2 million for 2008, 2007 and 2006, respectively. Cash used to settle equity instruments granted under all share-based payment arrangements for 2008, 2007 and 2006 was not material for any period.
Restricted Shares
The Company sometimes issues restricted stock awards (“RSA”) with no exercise price to officers and key employees in addition to stock options. The Company granted 325,300 restricted shares to key employees on February 19, 2008 at $64.16. 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 February 19, 2008 at $64.16. These shares will not vest until the third anniversary of the date of the grant, at which time they will be 100% vested, with a performance condition of the Company’s operating income level growth from January 1, 2008 to December 31, 2010 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, 2008, and 2007, and changes during 2008, and 2007:
                 
            Weighted Average  
            Grant  
Restricted Shares
  Units     Date Fair Value  
Non Vested at January 1, 2007
    72,000     $ 29.13  
Granted
    1,028,402     $ 37.06  
Vested
      $  
Forfeited
    (39,400 )   $ 37.40  
 
             
 
               
Non Vested at December 31, 2007
    1,061,002     $ 36.56  
 
               
Granted
    755,535     $ 64.33  
Vested
    (307,905 )   $ 68.12  
Forfeited
    (48,136 )   $ 42.32  
 
             
 
               
Non Vested at December 31, 2008
    1,460,496     $ 47.34  
 
             

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The weighted-average grant day fair value of RSA’s granted during the years ended 2008, 2007 and 2006 was $64.16, $37.06 and nil (excluding RSA’s assumed in the Grant Prideco merger) per share, respectively. There were 307,905, nil and nil RSA’s that vested during 2008, 2007 and 2006, respectively. As of December 31, 2008, there was $37.4 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):
                         
    Years Ended December 31,  
    2008     2007     2006  
Domestic
  $ 1,577.0     $ 1,243.5     $ 627.1  
Foreign
    1,384.3       785.4       422.1  
 
                 
 
  $ 2,961.3     $ 2,028.9     $ 1,049.2  
 
                 
The components of the provision for income taxes consisted of (in millions):
                         
    Years Ended December 31,  
    2008     2007     2006  
Current:
                       
Federal
  $ 690.9     $ 490.2     $ 255.8  
State
    54.7       38.8       14.4  
Foreign
    280.3       136.0       99.3  
 
                 
Total current income tax provision
    1,025.9       665.0       369.5  
 
                 
 
                       
Deferred:
                       
Federal
    (93.1 )     (66.0 )     (36.5 )
State
    (1.5 )     (3.3 )     (2.0 )
Foreign
    61.5       80.1       24.7  
 
                 
Total deferred income tax provision
    (33.1 )     10.8       (13.8 )
 
                 
 
                       
Total income tax provision
  $ 992.8     $ 675.8     $ 355.7  
 
                 
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):
                         
    Years Ended December 31,  
    2008     2007     2006  
Federal income tax at statutory rate
  $ 1,036.5     $ 710.1     $ 367.2  
Foreign income tax rate differential
    (124.5 )     (65.9 )     (28.6 )
State income tax, net of federal benefit
    33.8       23.1       9.3  
Tax benefit of foreign sales income
                (5.2 )
Nondeductible expenses
    11.9       9.5       7.3  
Tax benefit of manufacturing deduction
    (16.7 )     (10.5 )     (1.2 )
Foreign dividends net of foreign tax credits
    45.8       9.0       3.4  
Change in deferred tax valuation allowance
    (0.4 )     2.5       2.7  
Other
    6.4       (2.0 )     0.8  
 
                 
Total income tax provision
  $ 992.8     $ 675.8     $ 355.7  
 
                 

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At December 31, significant components of our deferred tax assets and liabilities were as follows (in millions):
                         
    December 31,  
    2008     2007     2006  
Deferred tax assets:
                       
Allowances and operating liabilities
  $ 364.2     $ 152.1     $ 115.4  
Net operating loss carryforwards
    6.0       8.2       28.5  
Postretirement benefits
    12.1       16.5       0.6  
Capital loss carryforwards
    3.2       6.9       0.2  
Other
    21.8       17.8       19.8  
 
                 
Total deferred tax assets
    407.3       201.5       164.5  
 
                       
Valuation allowance for deferred tax assets
    (10.4 )     (14.4 )     (6.8 )
 
                 
 
    396.9       187.1       157.7  
 
                       
Deferred tax liabilities:
                       
Tax over book depreciation
    146.2       94.7       89.0  
Intangible assets
    1,542.3       218.0       210.0  
Deferred income
    214.9       166.3       55.4  
Other
    231.0       85.3       34.6  
 
                 
Total deferred tax liabilities
    2,134.4       564.3       389.0  
 
                 
 
                       
Net deferred tax liability
  $ (1,737.5 )   $ (377.2 )   $ (231.3 )
 
                 
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.The balance of unrecognized tax benefits at December 31, 2008 and 2007 are $61.1 million and $47.0 million, respectively. These unrecognized tax benefits, if recognized in future periods, would impact the Company’s effective tax rate. Included in the change in the balance of unrecognized tax benefits for the period ended December 31, 2008 was an increase of $9.1 million of unrecognized tax benefits associated with the acquisition of Grant Prideco, which was charged to Goodwill, and a net increase of $5.0 million which impacted the Company’s effective tax rate in the current year. These unrecognized tax benefits are included in the balance of Accrued Income Taxes in the balance sheet as of December 31, 2008.
A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows (in millions):
         
Balance at January 1, 2008
  $ 47.0  
 
Additions based on tax positions related to the current year
    8.5  
Additions for tax positions of prior years
    9.1  
Reductions for tax positions of prior years
    (3.5 )
Settlements
     
Reductions for lapse of applicable statutes of limitations
     
 
     
 
Balance at December 31, 2008
  $ 61.1  
 
     
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, 2008, the Company recognized $2.0 million of additional interest and penalties related to uncertain tax positions as part of income tax expense. As of December 31, 2008, the Company has accrued approximately $6.6 million of interest and penalties relating to unrecognized tax benefits.

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These interest and penalties are included in the balance of Accrued Income Taxes in the balance sheet as of December 31, 2008.
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 2004 and outside the U.S. for the tax years ending after 2001. Norway also remains open for the 2001 tax year.
In the United States, the Company has $17.2 million of net operating loss carryforwards as of December 31, 2008, which expire at various dates through 2026. The potential benefit of $6.0 million has been recorded with $6.0 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 $ 6.0 million would reduce future income tax expense.
During 2008 the Company recorded $1,479.9 million in net deferred tax liabilities with a corresponding increase in goodwill related to Grant Prideco purchase accounting. During 2007 the Company recorded $42.5 million in net deferred tax liabilities with a corresponding increase in goodwill related to NQL purchase accounting.
Also in the United States, the Company has $0.7 million of excess foreign tax credits as of December 31, 2008, which expire at various dates through 2017. These credits have been allotted a full 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 $0.7 million would reduce future income tax expense.
Also in the United States, the Company has $8.6 million of capital loss carryforwards as of December 31, 2008, which will expire in 2009. The related potential benefit of $3.0 million has been recorded with a valuation allowance of $3.0 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 income tax expense.
Outside the United States, the Company has $0.4 million of net operating loss carryforwards as of December 31, 2008, which will expire in 2009. Also outside the United States, the Company has $0.7 million of capital loss carryforwards as of December 31, 2008, 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 decreased $4.0 million for the period ending December 31, 2008. Of the net decrease recorded in 2008, $0.4 million was recorded as a decrease of income tax expense and $3.6 million was recorded as a decrease in goodwill.
Undistributed earnings of certain of the Company’s foreign subsidiaries amounted to $2,254.5 million and $1,580.0 million at December 31, 2008 and 2007, 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 $107.3 million would be payable upon remittance of all previously unremitted earnings at December 31, 2008.
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.
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 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; rig instrumentation systems; coiled tubing equipment and pressure pumping units; well workover rigs; wireline winches; and cranes.

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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 drill pipe, transfer pumps, solids control systems, drilling motors, drill bits, reamers and other downhole tools, and 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 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.
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. During the second quarter of 2008, certain products previously reported in the Petroleum Services & Supplies segment were transferred to the Company’s other two segments, due to a realignment of management responsibilities. Prior periods have not been restated for this change as the impact of the change was not material to any of the Company’s segments.
No single customer accounted for 10% or more of consolidated revenues during the three years ended December 31, 2008.
Summarized financial information is as follows (in millions):
Geographic Areas:
                                                 
    United                   United        
    States   Canada   Norway   Kingdom   Other   Total
December 31, 2008:
                                               
Revenues
  $ 7,647.6     $ 805.4     $ 2,117.3     $ 657.5     $ 2,203.6     $ 13,431.4  
Long-lived assets
    1,049.7       107.3       43.5       89.2       387.0       1,676.7  
 
                                               
December 31, 2007:
                                               
Revenues
  $ 5,555.5     $ 700.5     $ 1,698.8     $ 496.8     $ 1,337.4     $ 9,789.0