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

o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

NATIONAL OILWELL VARCO, INC.

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.

 

 

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.

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.

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

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

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

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,

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

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

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 TurboTorque^TM 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

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 Griffith^TM 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

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.

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

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.

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

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.

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;

	•		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.

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:

	•		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.

GLOSSARY OF OILFIELD TERMS

		(Sources: Company management; “A Dictionary for the Petroleum Industry,” The University of Texas at Austin, 2001.)
API		Abbr: American Petroleum Institute
Annular Blowout Preventer		A large valve, usually installed above the ram blowout preventers, that forms a seal in the annular space between the pipe and the wellbore or, if no pipe is present, in the wellbore itself.
Annulus		The open space around pipe in a wellbore through which fluids may pass.
Automatic Pipe Handling Systems (Automatic Pipe Racker)		A device used on a drilling rig to automatically remove and insert drill stem components from and into the hole. It replaces the need for a person to be in the derrick or mast when tripping pipe into or out of the hole.
Automatic Roughneck		A large, self-contained pipe-handling machine used by drilling crew members to make up and break out tubulars. The device combines a spinning wrench, torque wrench, and backup wrenches.
Beam pump		Surface pump that raises and lowers sucker rods continually, so as to operate a downhole pump.
Bit		The cutting or boring element used in drilling oil and gas wells. The bit consists of a cutting element and a circulating element. The cutting element is steel teeth, tungsten carbide buttons, industrial diamonds, or polycrystalline diamonds (PDCs). These teeth, buttons, or diamonds penetrate and gouge or scrape the formation to remove it. The circulating element permits the passage of drilling fluid and utilizes the hydraulic force of the fluid stream to improve drilling rates. In rotary drilling, several drill collars are joined to the bottom end of the drill pipe column, and the bit is attached to the end of the drill collars. Drill collars provide weight on the bit to keep it in firm contact with the bottom of the hole. Most bits used in rotary drilling are roller cone bits, but diamond bits are also used extensively.
Blowout		An uncontrolled flow of gas, oil or other well fluids into the atmosphere. A blowout, or gusher, occurs when formation pressure exceeds the pressure applied to it by the column of drilling fluid. A kick warns of an impending blowout.
Blowout Preventer (BOP)		Series of valves installed at the wellhead while drilling to prevent the escape of pressurized fluids.
Blowout Preventer (BOP) Stack		The assembly of well-control equipment including preventers, spools, valves, and nipples connected to the top of the wellhead.
Closed Loop Drilling Systems		A solids control system in which the drilling mud is reconditioned and recycled through the drilling process on the rig itself.
Coiled Tubing		A continuous string of flexible steel tubing, often hundreds or thousands of feet long, that is wound onto a reel, often dozens of feet in diameter. The reel is an integral part of the coiled tubing unit, which consists of several devices that ensure the tubing can be safely and efficiently inserted into the well from the surface. Because tubing can be lowered into a well without having to make up joints of tubing, running coiled tubing into the well is faster and less expensive than running conventional tubing. Rapid advances in the use of coiled tubing make it a popular way in which to run tubing into and out of a well. Also called reeled tubing.
Cuttings		Fragments of rock dislodged by the bit and brought to the surface in the drilling mud. Washed and dried cutting samples are analyzed by geologist to obtain information about the formations drilled.

Directional Well		Well drilled in an orientation other than vertical in order to access broader portions of the formation.
Drawworks		The hoisting mechanism on a drilling rig. It is essentially a large winch that spools off or takes in the drilling line and thus raises or lowers the drill stem and bit.
Drill Pipe Elevator (Elevator)		On conventional rotary rigs and top-drive rigs, hinged steel devices with manual operating handles that crew members latch onto a tool joint (or a sub). Since the elevators are directly connected to the traveling block, or to the integrated traveling block in the top drive, when the driller raises or lowers the block or the top-drive unit, the drill pipe is also raised or lowered.
Drilling jars		A percussion tool operated manually or hydraulically to deliver a heavy downward blow to free a stuck drill stem.
Drilling mud		A specially compounded liquid circulated through the wellbore during rotary drilling operations.
Drilling riser		A conduit used in offshore drilling through which the drill bit and other tools are passed from the rig on the water’s surface to the sea floor.
Drill stem		All members in the assembly used for rotary drilling from the swivel to the bit, including the Kelly, the drill pipe and tool joints, the drill collars, the stabilizers, and various specialty items.
Formation		A bed or deposit composed throughout of substantially the same kind of rock; often a lithologic unit. Each formation is given a name, frequently as a result of the study of the formation outcrop at the surface and sometimes based on fossils found in the formation.
Hardbanding		A special wear-resistant material often applied to tool joints to prevent abrasive wear to the area when the pipe is being rotated downhole.
Iron roughneck		A floor-mounted combination of a spinning wrench and a torque wrench. The Iron Roughneck moves into position hydraulically and eliminates the manual handling involved with suspended individual tools.
Jack-up rig		A mobile bottom-supported offshore drilling structure with columnar or open-truss legs that support the deck and hull. When positioned over the drilling site, the bottoms of the legs penetrate the seafloor.
Jar		A mechanical device placed near the top of the drill stem which allows the driller to strike a very heavy blow upward or downward on stuck pipe.
Joint		1. In drilling, a single length (from 16 feet to 45 feet, or 5 meters to 14.5 meters, depending on its range length) of drill pipe, drill collar, casing or tubing that has threaded connections at both ends. Several joints screwed together constitute a stand of pipe. 2. In pipelining, a single length (usually 40 feet-12 meters) of pipe. 3. In sucker rod pumping, a single length of sucker rod that has threaded connections at both ends.
Kelly		The heavy steel tubular device, four- or six-sided, suspended from the swivel through the rotary table and connected to the top joint of drill pipe to turn the drill stem as the rotary table returns. It has a bored passageway that permits fluid to be circulated into the drill stem and up the annulus, or vice versa. Kellys manufactured to API specifications are available only in four- or six-sided versions, are either 40 or 54 feet (12 to 16 meters) long, and have diameters as small as 2 1 /2 inches (6 centimeters) and as large as 6 inches (15 centimeters).

Kelly bushing		A special device placed around the kelly that mates with the kelly flats and fits into the master bushing of the rotary table. The kelly bushing is designed so that the kelly is free to move up or down through it. The bottom of the bushing may be shaped to fit the opening in the master bushing or it may have pins that fit into the master bushing. In either case, when the kelly bushing is inserted into the master bushing and the master bushing is turned, the kelly bushing also turns. Since the kelly bushing fits onto the kelly, the kelly turns, and since the kelly is made up to the drill stem, the drill stem turns. Also called the drive bushing.
Kelly spinner		A pneumatically operated device mounted on top of the kelly that, when actuated, causes the kelly to turn or spin. It is useful when the kelly or a joint of pipe attached to it must be spun up, that is, rotated rapidly for being made up.
Kick		An entry of water, gas, oil, or other formation fluid into the wellbore during drilling. It occurs because the pressure exerted by the column of drilling fluid is not great enough to overcome the pressure exerted by the fluids in the formation drilled. If prompt action is not taken to control the kick, or kill the well, a blowout may occur.
Making-up		1. To assemble and join parts to form a complete unit (e.g., to make up a string of drill pipe). 2. To screw together two threaded pieces. Compare break out. 3. To mix or prepare (e.g., to make up a tank of mud). 4. To compensate for (e.g., to make up for lost time).
Manual tongs (Tongs)		The large wrenches used for turning when making up or breaking out drill pipe, casing, tubing, or other pipe; variously called casing tongs, pipe tongs, and so forth, according to the specific use. Power tongs or power wrenches are pneumatically or hydraulically operated tools that serve to spin the pipe up tight and, in some instances to apply the final makeup torque.
Master bushing		A device that fits into the rotary table to accommodate the slips and drive the kelly bushing so that the rotating motion of the rotary table can be transmitted to the kelly. Also called rotary bushing.
Motion compensation equipment		Any device (such as a bumper sub or heave compensator) that serves to maintain constant weight on the bit in spite of vertical motion of a floating offshore drilling rig.
Mud pump		A large, high-pressure reciprocating pump used to circulate the mud on a drilling rig.
Plug gauging		The mechanical process of ensuring that the inside threads on a piece of drill pipe comply with API standards.
Pressure control equipment		1. The act of preventing the entry of formation fluids into a wellbore. 2. The act of controlling high pressures encountered in a well.
Pressure pumping		Pumping fluids into a well by applying pressure at the surface.
Ram blowout preventer		A blowout preventer that uses rams to seal off pressure on a hole that is with or without pipe. Also called a ram preventer.
Ring gauging		The mechanical process of ensuring that the outside threads on a piece of drill pipe comply with API standards.
Riser		A pipe through which liquids travel upward.
Riser pipe		The pipe and special fitting used on floating offshore drilling rigs to established a seal between the top of the wellbore, which is on the ocean floor, and the drilling equipment located above the surface of the water. A riser pipe serves as a guide for the drill stem from the drilling vessel to the wellhead and as a conductor or drilling fluid from the well to the vessel. The riser consists of several sections of pipe and includes special devices to compensate for any movement of the drilling rig caused by waves. Also called marine riser pipe, riser joint.

Rotary table		The principal piece of equipment in the rotary table assembly; a turning device used to impart rotational power to the drill stem while permitting vertical movement of the pipe for rotary drilling. The master bushing fits inside the opening of the rotary table; it turns the kelly bushing, which permits vertical movement of the kelly while the stem is turning.
Rotating blowout preventer (Rotating Head)		A sealing device used to close off the annular space around the kelly in drilling with pressure at the surface, usually installed above the main blowout preventers. A rotating head makes it possible to drill ahead even when there is pressure in the annulus that the weight of the drilling fluid is not overcoming; the head prevents the well from blowing out. It is used mainly in the drilling of formations that have low permeability. The rate of penetration through such formations is usually rapid.
Safety clamps		A clamp placed very tightly around a drill collar that is suspended in the rotary table by drill collar slips. Should the slips fail, the clamp is too large to go through the opening in the rotary table and therefore prevents the drill collar string from falling into the hole. Also called drill collar clamp.
Shaker		See “Shale Shaker”
Shale shaker		A piece of drilling rig equipment that uses a vibrating screen to remove cuttings from the circulating fluid in rotary drilling operations. The size of the openings in the screen should be selected carefully to be the smallest size possible to allow 100 per cent flow of the fluid. Also called a shaker.
Slim-hole completions (Slim-hole Drilling)		Drilling in which the size of the hole is smaller than the conventional hole diameter for a given depth. This decrease in hole size enables the operator to run smaller casing, thereby lessening the cost of completion.
Slips		Wedge-shaped pieces of metal with serrated inserts (dies) or other gripping elements, such as serrated buttons, that suspend the drill pipe or drill collars in the master bushing of the rotary table when it is necessary to disconnect the drill stem from the kelly or from the top-drive unit’s drive shaft. Rotary slips fit around the drill pipe and wedge against the master bushing to support the pipe. Drill collar slips fit around a drill collar and wedge against the master bushing to support the drill collar. Power slips are pneumatically or hydraulically actuated devices that allow the crew to dispense with the manual handling of slips when making a connection.
Solids		See “Cuttings”
Spinning wrench		Air-powered or hydraulically powered wrench used to spin drill pipe in making or breaking connections.
Spinning-in		The rapid turning of the drill stem when one length of pipe is being joined to another. “Spinning-out” refers to separating the pipe.
Stand		The connected joints of pipe racked in the derrick or mast when making a trip. On a rig, the usual stand is about 90 feet (about 27 meters) long (three lengths of drill pipe screwed together), or a treble.
String		The entire length of casing, tubing, sucker rods, or drill pipe run into a hole.
Sucker rod		A special steel pumping rod. Several rods screwed together make up the link between the pumping unit on the surface and the pump at the bottom of the well.
Tensioner		A system of devices installed on a floating offshore drilling rig to maintain a constant tension on the riser pipe, despite any vertical motion made by the rig. The guidelines must also be tensioned, so a separate tensioner system is provided for them.

Thermal desorption		The process of removing drilling mud from cuttings by applying heat directly to drill cuttings.
Top drive		A device similar to a power swivel that is used in place of the rotary table to turn the drill stem. It also includes power tongs. Modern top drives combine the elevator, the tongs, the swivel, and the hook. Even though the rotary table assembly is not used to rotate the drill stem and bit, the top-drive system retains it to provide a place to set the slips to suspend the drill stem when drilling stops.
Torque wrench		Spinning wrench with a gauge for measuring the amount of torque being applied to the connection.
Trouble cost		Costs incurred as a result of unanticipated complications while drilling a well. These costs are often referred to as contingency costs during the planning phase of a well.
Well completion		1. The activities and methods of preparing a well for the production of oil and gas or for other purposes, such as injection; the method by which one or more flow paths for hydrocarbons are established between the reservoir and the surface. 2. The system of tubulars, packers, and other tools installed beneath the wellhead in the production casing; that is, the tool assembly that provides the hydrocarbon flow path or paths.
Well stimulation		Any of several operations used to increase the production of a well, such as acidizing or fracturing.
Well workover		The performance of one or more of a variety of remedial operations on a producing oilwell to try to increase production. Examples of workover jobs are deepening, plugging back, pulling and resetting liners, and squeeze cementing.
Wellbore		A borehole; the hole drilled by the bit. A wellbore may have casing in it or it may be open (uncased); or part of it may be cased, and part of it may be open. Also called a borehole or hole.
Wireline		A slender, rodlike or threadlike piece of metal usually small in diameter, that is used for lowering special tools (such as logging sondes, perforating guns, and so forth) into the well. Also called slick line.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

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

				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

				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

				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

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.

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.

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.

				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).

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

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	%

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:

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.

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

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.

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

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

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.

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.

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.

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

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.

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.

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

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.

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).

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