Edgar Filing: NATIONAL OILWELL VARCO INC

Large accelerated filer

Accelerated filer

Non-accelerated filer

¨ (Do not check if a smaller reporting company)

Smaller Reporting Company

Form 10-K

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, 2012

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

Commission file number 1-12317

NATIONAL OILWELL VARCO, INC.

(Exact name of registrant as specified in its charter)

Delaware

76-0475815

(State or other jurisdiction

of incorporation or organization)

(IRS Employer

Identification No.)

7909 Parkwood Circle Drive, Houston, Texas 77036-6565

(Address of principal executive offices)

(713) 346-7500

(Registrant’s telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act:


Common Stock, par value $.01		New York Stock Exchange
(Title of Class)		(Exchange on which registered)

Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes þ No ¨

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 ¨ 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 ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes þ No ¨

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. þ

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):

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No þ

The aggregate market value of voting and non-voting common stock held by non-affiliates of the registrant as of June 29, 2012 was $27.5 billion. As of February 14, 2013, there were 426,639,780 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 2013 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 1,160 locations across six continents.

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 reporting segments: Rig Technology, Petroleum Services & Supplies, and Distribution & Transmission.

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; blowout preventers; coiled tubing equipment and pressure pumping units; well workover rigs; wireline winches; wireline trucks; cranes; flexible pipe for offshore production applications; and turret mooring systems and other products for floating production, storage and offloading vessels (“FPSOs”) and other offshore vessels and terminals. 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, Denmark, the United Kingdom, Brazil, China, Belarus, India, Russia, the Netherlands, Singapore, South Korea, South Africa, and Angola.

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 drill pipe, tubing, casing, 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, drilling fluids, 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, oilfield service companies, 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 fiberglass 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 additional operations in the United States, Canada, the United Kingdom, Brazil, China, Kazakhstan, Mexico, Russia, Argentina, India, Bolivia, the Netherlands, Singapore, Malaysia, Vietnam, Oman, and the United Arab Emirates.

Distribution & Transmission

Our Distribution & Transmission segment provides pipe, maintenance, repair and operating supplies (“MRO”) and spare parts to drill sites and production locations, pipeline operations, and processing plants worldwide. In addition to its comprehensive field location network, which supports land drilling operations throughout North America, the segment supports major land and offshore operations for all the major oil and gas producing regions throughout the world. The segment employs advanced information technologies to provide complete procurement, materials management and logistics services to its customers around the globe. The segment also has a global reach in oil and gas, waste water treatment, chemical, food and beverage, paper and pulp, mining, agriculture, and a variety of municipal markets and is a leading producer of water transmission pipe, fabricated steel products and specialized materials and products used in infrastructure projects. Demand for the segment’s services is determined primarily by the level of drilling, servicing, and oil and gas production activities. It is also influenced by the domestic economy in general, housing starts and government policies. This segment has benefited from several strategic acquisitions and other investments completed around the world during the past few years, including the acquisition of the Wilson distribution business segment from Schlumberger Limited and CE Franklin Ltd. in Canada, both of which were completed in 2012, as well as additional operations in the United States, Canada, the United Kingdom, Kazakhstan, Singapore, Russia, and Malaysia.

The following table sets forth the contribution to our total revenues of our three operating segments (in millions):


	Years Ended December 31,
	2012			2011			2010
Revenue:
Rig Technology	$	10,107		$	7,788		$	6,965
Petroleum Services & Supplies		6,967			5,654			4,182
Distribution & Transmission		3,927			1,873			1,546
Eliminations		(960	)		(657	)		(537	)

Total Revenue	$	20,041		$	14,658		$	12,156

See Note 15 to the 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. “Business” of this Annual Report.

Influence of Oil and Gas Activity Levels on the Company’s Business

The oil and gas industry in which the Company participates has historically experienced significant volatility. Demand for the Company’s services and products depends primarily upon the general level of activity in the oil and gas industry worldwide, including the number of drilling rigs in operation, the number of oil and gas wells being drilled, the depth and drilling conditions of these wells, the volume of production, the number of well completions and the level of well remediation activity. Oil and gas activity is in turn heavily influenced by, among other factors, oil and gas prices worldwide. High levels of drilling and well remediation activity generally spurs 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 oil and gas companies, drilling contractors, oilfield service companies, and manufacturers of oil country tubular goods (“OCTG”) 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 of the Company’s customers, as well as the long-term concerns about supply-demand imbalance and the need to replace aging equipment, market conditions for capital equipment purchases improved significantly between 2006 and 2007, resulting in higher backlogs for the Company at the end of 2008 compared to the end of 2006 and 2007. However, as a result of the financial crisis and significantly lower commodity prices, the worldwide drilling rig count declined 31% in 2009 and customers were far less willing to commit to major capital equipment purchases in 2009. As a result, our order rates were substantially lower in 2009. In 2010, as the financial crisis eased and oil prices recovered, order rates began to improve across a broad array of rig equipment, with a particular focus on continued build out of the deepwater fleet. Both 2011 and 2012 saw a further improvement in order rates as commodity prices remained at levels supporting sustained capital spending by our customers. The global rig count rose 16% in 2011 compared to 2010 and by 1.5% in 2012 compared to 2011. Backlog for the Company was approximately $11.9 billion at December 31, 2012 compared to approximately $10.2 billion and $5.0 billion for December 31, 2011 and 2010, respectively.

In 2010, 2011 and 2012, most of the Company’s revenue from Rig Technology 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. Most of the remainder of the Rig Technology segment’s revenue is 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 revenue from Petroleum Services & Supplies 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 and shipyards, 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 & Transmission is almost entirely driven by drilling activity and oil and gas production activities, with the exception of sales of water pipelines, concrete and pole products which is tied to infrastructure spending. 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 but not limited to: 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, climate change, 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 day-rates; 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.

See additional 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.

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, and a top drive, a device suspended from the derrick that turns the entire drill stem, rather than such force being supplied by the rotary table. The use of drilling motors and top drives permits the drilling contractor to drill directionally, including horizontally. The Company sells and rents drilling motors, drill bits, downhole tools and drill pipe through its Petroleum Services & Supplies segment and sells and rents top drives through its Rig Technology 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 re-circulated 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 segment, the Company sells transfer pumps and mud pump consumables; sells and rents solids control equipment; and provides solids control, waste management and drilling fluids 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 Petroleum Services & Supplies segment. Additionally, the Petroleum Services & Supplies segment manufactures and sells drill pipe.

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 Rig Technology segment 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 Petroleum Services & Supplies segment provides. The 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, is 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 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 reservoir pressures are (i) primarily the circulation of drilling muds while drilling and (ii) secondarily the use of blowout preventers (“BOPs”) should the mud prove inadequate in an emergency situation. The Rig Technology segment sells and services blowout preventers. Drilling muds are carefully designed to exhibit certain qualities that optimize the drilling process. In addition to containing formation pressure, they must (i) provide power to the drilling motor, (ii) carry drilled solids to the surface, (iii) protect the drilled formations from being damaged, and (iv) cool the drill bit. Achieving these objectives often requires a formulation specific to a given well and can involve the use of expensive chemicals as well as natural materials, such as certain types of clay. The fluid itself is often oil or more expensive synthetic mud. Given this expense, it is highly desirable to reuse as much of the drilling mud as possible. Solids control equipment such as shale shakers, centrifuges, cuttings dryers, and mud cleaners help accomplish this objective. The Petroleum Services & Supplies segment 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.

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 & Transmission 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 Petroleum Services & Supplies segment. Sometimes operators choose to use corrosion resistant composite materials, which the Company also offers through its Petroleum Services & Supplies segment, 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 Petroleum Services & Supplies segment 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 multi-strand 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, turret mooring systems and other products for FPSOs and other offshore vessels and terminals, and other drilling equipment for both the onshore and offshore markets. Rig Technology 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 segment 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. Rig Technology 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. The Company 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 Drake Rig, Ideal Rig™ and Rapid Rig ^®. The Company’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 the Company 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.

Electric Rig Motors. The Company has helped lead the application of AC motor technology in the oilfield industry. The Company buys motors from third parties and builds them in its own facilities and is 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. Rig Technology produces rotary tables as well as kelly bushings and master bushings for most sizes of kellys and makes of rotary tables. In 1998, the Company 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 the Company 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 the Company 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 the Company 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 segment 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. The Company 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, the Company 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. The Company 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, the Company has introduced an Active Heave Compensation (“AHC”) System that goes beyond the capabilities of the AHD Drawworks to handle the most severe weather. Additionally, the Company’s 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 between the drill pipe and the borehole to prevent blowouts (uncontrolled flows of formation fluids and gases to the surface). The Rig Technology segment 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. The Company’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, the Company 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, the Company 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.

The ShearMax^TM line of low force BOP shear rams released in 2010 add substantial tubular shearing capability to the Company’s line of pressure control equipment, including the capability to shear large drill pipe tool joints, previously unheard of in the industry. This innovative shear blade design utilizes patented “Puncture Technology” to reduce the shearing pressures 50% or more and in some cases as much as five times lower. The ShearMax^TM Blind shear provides a shear-and-seal design for drill pipe, while the Casing and TJC shears address casing up to 16” OD and most tool joints up to 2” wall thickness, respectively.

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. Rig Technology designs, fabricates and services derricks used in both onshore and offshore applications, and substructures used in onshore applications. The Rig Technology segment 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. 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 allow 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. Complementing 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 the Company has offered since 1929.

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, semi-trailer or skid (steel frames on which portable equipment is mounted to facilitate handling with cranes for offshore use) 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 perform workover operations on a live well. The Rig Technology segment 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. The Company engineered and manufactured the first coiled tubing units built specifically for coiled tubing drilling in 1996.

Generally, the Rig Technology segment supplies customers with the equipment and components necessary to use coiled tubing, which the customers typically purchase separately. The Rig Technology segment’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. The Company’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 single-strand 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.

Stimulation Equipment. The Company’s stimulation products include fracturing pumps, acid units, frac blenders, combo units, hydration, chemical additive systems as well as services and parts. The Company acquired Enerflow Industries, Inc. (“Enerflow”) in May 2012. Enerflow operates out of facilities in Calgary, AB, Tulsa, OK and Houston, TX. Enerflow produces frac pumpers (including truck, trailer, and skid mounted units) as well as cementing units, acidizing units, nitrogen units, and small amounts of well servicing rigs, integrated mud systems and coiled tubing equipment.

Turret Mooring Systems. The Company acquired Advanced Production and Loading PLC (“APL”), in December 2010. APL, based in Norway, designs and manufactures turret mooring systems and other products for FPSOs and other offshore vessels and terminals. A turret mooring system consists of a geostatic part attached to the seabed and a rotating part integrated in the hull of the FPSO, which are connected and allow the ship to weathervane (rotate) around the turret.

Flexible Pipe Systems. The Company acquired NKT Flexibles I/S (“NKT”) in April 2012. NKT designs and manufactures flexible pipe products and systems for the offshore oil and gas industry, including products associated with FPSO’s and other offshore vessels, as well as subsea production systems including flow-lines and flexible risers.

Facilities. The Company’s Rig Technology segment conducts manufacturing operations at major facilities in Houston, Galena Park, Sugar Land, Conroe, Cedar Park, Anderson, Fort Worth and Pampa, Texas; Duncan, Oklahoma; Orange, California; Edmonton, Canada; Aberdeen, Scotland; Kristiansand, Stavanger and Arendal, Norway; Etten-Leur and Groot-Ammers, the Netherlands; Carquefou, France; Singapore; Lanzhou and Shanghai, China; Dubai, UAE; and Ulsan, South Korea. For a more detailed listing of significant facilities see Item 2. “Properties”. The Rig Technology segment maintains sales and service offices in most major oilfield markets, either directly or through agents.

Customers and Competition. Rig Technology 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 segment 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 segment’s primary competitors are Aker Solutions AS; American Block; Bomco; Canrig (a division of Nabors Industries); Cavins Oil Tools; Cameron; DenCon Oil Tools; Forum Oilfield Technologies; General Electric; Hitec Drilling Products; Hong Hua; Huisman; Global Energy Services; M&I Electric; Tesco Corporation; Stewart & Stevenson, Inc.; Huntings, Ltd.; Vanoil; Parveen Industries; Soilmec; TTS Sense; Omron; Bentec; Blohm; Voss; Liebher; Seatrax; McGregor; Rolls Royce and Weatherford International, Inc. Management believes that the principal competitive factors affecting its Rig Technology segment 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. Petroleum Services & Supplies segment sells directly and provides a variety of tubular services, composite tubing, and coiled tubing to oil and gas producers, national oil companies, drilling contractors, well servicing companies, 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 Company also provides internal coating of tubular goods at several coating plants worldwide and through licensees in certain locations. Additionally, the Company designs, manufactures and sells high pressure fiberglass and composite tubulars for use in corrosive applications and coiled tubing for use in well servicing applications and connections for large diameter conductor pipe.

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 Petroleum Services & Supplies segment also provides products and services that are used in the course of drilling oil and gas wells. The NOV Downhole business sells and rents bits, drilling motors and specialized downhole tools that are incorporated into the drill stem during drilling operations, and are also used during fishing, well intervention, re-entry, and well completion operations. The Wellsite Services business provides products and services such as drilling fluids, highly-engineered solids control equipment, waste handling and treatment, completion fluids, power generation equipment, and other ancillary well site equipment and services. Wellsite Services is also engaged in barium sulfate (“barite”) mining operations in the State of Nevada. Barite is an inert powder material used as the primary weighting agent in drilling fluids. 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.

Solids Control and Waste Management. The Company 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.

Fluids Services. The Company acquired the Spirit group of companies in May 2009 (“Spirit”) and Ambar in January 2010. Both are engaged in the provision of drilling fluids, completion fluids and other related services. This division is also engaged in barite mining operations. Drilling fluids are designed and used to maintain well bore stability while drilling, control downhole pressure, drill bit lubrication, and as a drill cuttings displacement medium. Completion fluids are used to clean the well bore and stimulate production.

Portable Power. The acquisition of Welch Sales and Service, Inc. in 2008 placed Wellsite Services in the power generation and temperature control business. The Portable Power division provides rental equipment for use in the upstream oil and gas industry, refinery and petrochemical, construction, events, disaster relief and other industries.

Tubular Coating. The Company develops, manufactures and applies its proprietary tubular coatings, known as Tube-Kote^® coatings, to new and used tubulars. Tubular coatings help prevent corrosion of tubulars by providing a tough plastic shield to isolate steel from corrosive oilfield fluids such as CO₂ , H₂ 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, the Company created a 60%-owned joint venture in China with the Huabei Petroleum Administration Bureau, which coats Chinese produced drill pipe using the Company’s proprietary coatings. In 2007, the joint venture opened a second coating plant in Jiangyin City, China.

In addition to the Company’s TK^® coatings, it also has complementary corrosion control products and services including TK^® Liners, TuboWrap™, and KC-IPC Connections. TK Liners are fiberglass-reinforced tubes which are inserted into steel line pipe. This safeguards the pipe against corrosion and extends the life of the pipeline. In conjunction with the Thru-Kote^® connection system customers can weld a sleeve for a continuous fiberglass lined pipeline. Tubo-Wrap™ is a high performance external coating that protects the pipe during installation and from corrosion once the pipeline is in place. KC-IPC Connections use a modified American Petroleum Institute (“API”) coupling to create a “gas-tight” seal that prevents corrosion and turbulence in the critical connections of tubulars while protecting the internal plastic coating at the highly loaded contact points.

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 Company 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^™. The Company 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.

Machining Services. In 2005, the Company acquired Turner Oilfield Services and expanded our product offering into thread repair, tool joint rebuilding and sub manufacturing. Since then the Company has made strategic acquisitions of Hendershot and Mid-South and has expanded its machining services internally to develop a “one-stop-shop” concept for its drill pipe customers. Thread repair services include rotary shouldered and premium connections. The Company is licensed to perform thread repair services for API and proprietary connections. Tool joint rebuilding is a unique process to restore worn drill pipe tool joints, drill collars and heavy weight drill pipe to the original specifications to extend the service life of those assets. The Company manufactures downhole tools and is API licensed for this process in several locations.

In November 2009, the Company acquired South Seas Inspection (S) Pte. Ltd., (“SSI”) and certain assets of its Brazilian affiliate. SSI provides a wide array of oilfield services including rig and derrick construction, derrick inspection and maintenance, drops surveys and load testing at the rig through the use of rope access technicians. This acquisition adds multiple new services and allows the Company to grow this business by leveraging existing relationships and infrastructure. These operations are based out of Singapore with branch offices in Baku, Azerbaijan and Aktau, Kazkhstan as well as a representative office in Vietnam. The highly trained workforce is completely mobile and provides these services worldwide.

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. As a result of its April 2008 acquisition of Grant Prideco, 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 Drill Pipe Products are: (i) drill pipe, (ii) drill collars and heavyweight drill pipe and (iii) 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 and again to drill other wells until the drill pipe becomes damaged or wears out.

In recent years, the depth and complexity of the wells customers drill, as well as the specifications and requirements of the drill pipe they purchase, have substantially increased. A majority of the drill pipe sold is required to meet specifications exceeding minimum API standards. The Company offers a broad line of premium drilling products designed for the offshore, international and domestic drilling markets. The Company’s premium drilling products include its proprietary lines of XT^® and TurboTorque^TM connections and large diameter drill pipe that delivers hydraulic performance superior to standard sizes.

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.

The Company also provides 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.

NOV IntelliServ. NOV IntelliServ is a joint venture between the Company and Schlumberger, Ltd. in which the Company holds a 55% interest and maintains operational control. NOV IntelliServ provides wellbore data transmission services that enable high-speed communication up and down the drill string throughout drilling and completion operations that are undertaken during the construction of oil and gas wells. NOV IntelliServ’s core product, “The IntelliServ^® Broadband Network”, was commercialized in February 2006 and incorporates various proprietary mechanical and electrical components into the Company’s premium drilling tubulars to enable data transmission rates that are currently up to 20,000 times faster than mud pulse, the current industry standard. The IntelliServ^® Broadband Network also permits virtually unlimited real-time actuation of drilling tools and sensors at the bottom of the drill string, a process that conventionally requires the time consuming return of tools to the surface. NOV IntelliServ 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. The Company has 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.

VAT is accounted for under the equity-method of accounting due to the minority owner having substantive participating rights. Under a limited partnership operating agreement the Company has no rights to unilaterally take any action with respect to its investment and the day to day operations of VAT are under the direction of a Management Board, whose members are determined principally by the minority owner. The Management Board is responsible for planning, production, sales and general personal matters, which represent substantive participating rights that overcome the presumption that the Company should consolidate its 50.01% investment.

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 further 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.

In 2011, the Company acquired Ameron International Corporation (“Ameron”) which allowed it to expand its Fiberglass & Composite Tubulars business. See Note 4 to the Consolidated Financial Statements for information regarding acquisitions made by the Company in 2011. Ameron’s Fiberglass-Composite Pipe business, which is now part of the Company’s Fiber Glass Systems business, develops, manufactures and markets filament-wound and molded fiberglass pipe and fittings. These products are used by a wide range of process industries, including industrial, petroleum, chemical processing and petrochemical industries, and for service station piping systems, but predominantly aboard marine vessels, FPSOs and offshore oil platforms, and are marketed as an alternative to metallic piping systems which ultimately fail under corrosive operating conditions.

In 2012, the Company acquired Fiberspar Corporation (“Fiberspar”). See Note 4 to the Consolidated Financial Statements for information regarding acquisitions made by the Company in 2012. Fiberspar, which is now part of the Company’s Fiber Glass Systems business, manufactures and sells fiberglass-reinforced spoolable pipe to the oil and gas industry. This fiberglass-reinforced spoolable pipe provides a reliable, corrosion-resistant, cost-effective solution for tubulars used during the production and transportation of oil and gas. Fiberspar has its manufacturing plant in Houston, TX, and maintains 17 deployment centers (stocking locations) for its products in the U.S., Canada and Australia.

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. The Company designs, manufactures, and sells coiled tubing under the Quality Tubing brand name at its mill in Houston, Texas.

NOV Downhole. The NOV Downhole business unit combines a wide array of drilling and intervention tool product lines with the drill bit, coring services, borehole enlargement and drilling dynamics/drilling optimization service lines previously consolidated within the ReedHycalog business unit of Grant Prideco.

The broad spectrum of bottom hole assembly (“BHA”) components offered by NOV Downhole is unique within the industry and is the result of the Company’s strategic consolidation of several key acquisitions, including: NQL Energy Services, Inc., a leading manufacturer and provider of downhole drilling tools; Gammaloy Holdings, L.P., a manufacturer and provider of non-magnetic drill collars and other related products; and the ReedHycalog, Corion, and Andergauge business units of Grant Prideco, a global leader in the design, manufacture and provision of drill bits, variable gauge stabilizers, hydraulically and mechanically actuated under-reamers, specialty coring services and downhole vibration mitigation services.

NOV Downhole manufactures fixed cutter and roller cone drill bits and services its customer base through a technical sales and marketing network in virtually every significant oil and gas producing region of the world. It provides fixed-cutter bit technology under various brand names including TReX^®, Raptor™, Helios™, SystemMatched™ and Rotary Steerable. One of its most significant fixed cutter drill bit innovations is the TReX^®, Raptor™, Helios™, and Duraforce family of cutter technologies which significantly increase abrasion resistance (wear life) and thermal abrasion resistance 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 polycrystalline diamond (“PDC”) bit performance. The Company licenses its manufacturing process to most other providers of PDC bits.

The Company 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 TuffCutter™. We market our roller-cone products and technology globally under various brand names including RockForce™, Titan™ and TuffCutter™.

NOV Downhole 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 NOV Downhole brand name. The Company also maintains a wide variety of motor power sections, including its proprietary PowerPlus™ and HemiDril™ rotors and stators which it incorporates into its own motors as well as 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.

NOV Downhole also manufactures and sells drilling jars and fishing tools. 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.

Through its Coring Services business line, NOV Downhole offers coring solutions that enable the extraction of actual rock samples from a drilled well bore and allow geologists to examine the formations at the surface. One of the coring services utilized is the Company’s unique 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. This capability enables customers to save significant time and expense during the drilling and coring process.

NOV Downhole offers a wide variety of industry leading technologies to enable customers to enlarge the diameter of a drilled hole below a restriction (typically a casing string) via its Borehole Enlargement business line. Borehole enlargement services are typically utilized in deep water drilling where customers wish to maximize the size of each successive casing string in order to preserve a relatively large completion hole size through which to produce hydrocarbons from the reservoir. Borehole enlargement is also employed where customers wish to reduce the fluid velocity and pressure within the well-bore annulus to reduce the risk of formation erosion or accidental fracture. Borehole Enlargement provides bi-centered drill bits, expandable reamers (marketed under the AnderReamer™ brand name) and associated equipment along with well-site service technicians who deliver 24 hour support during hole enlargement operations.

NOV Downhole offers drilling optimization services via its Advanced Drilling Solutions (“ADS”) business line. ADS services incorporate various downhole vibration measurement and mitigation tools along with dedicated, highly trained personnel who interpret such data and provide drilling parameter guidance intended to improve drilling efficiency and reduce drilling risk.

Pumps & Expendables. The Company’s Pumps & Expendables business designs, manufactures, and sells pumps that are used in oil and gas drilling operations, well service operations, production applications, as well as industrial applications. These pumps include reciprocating positive displacement and centrifugal 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. The Company 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 Company 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 Company also manufactures a line of commodity and high end valves, chokes, and flow line equipment used in both production and drilling applications. Additionally, these products are used in the fabrication of choke and kill standpipe, cement, and production manifolds. The Company manufactures its pump products in Houston, Odessa and Marble Falls, Texas; Tulsa and McAlester, Oklahoma; Scott, Louisiana; Newcastle, England and Buenos Aires, Argentina.

XL Systems. The Company’s XL Systems product line offers the customer an integrated package of large-bore tubular products and services for offshore wells. This product line includes the Company’s proprietary line of wedge thread marine connections on large-bore tubulars and related engineering and design services. The Company provides this product line for drive pipe, jet strings and conductor casing. The Company also offers weld-on connections and service personnel in connection with the installation of these products. In 2007, the Company completed development of its high-strength Viper™ weld-on connector to permit the Company to penetrate traditional markets that do not require the enhanced performance of its 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, steel mills, and other industrial companies. The Company’s competitors include, among others, EDO Corporation; ShawCor Ltd.; Schlumberger, Ltd.; Frank’s International, Inc.; Baker Hughes Incorporated; Halliburton Company; Weatherford International Ltd.; Patterson Tubular Services; Vallourec & Mannesmann; and Precision Tube (a division of Tenaris). In addition, the Company 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 the Company 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 segment include drilling contractors, well servicing companies, major and independent oil and gas companies, and national oil companies. Competitors in drilling services include Schlumberger, Ltd.; Baker Hughes Incorporated; Halliburton Company; Derrick Manufacturing Corp.; Fluid Systems; Oil Tools Pte. Ltd; Peak Energy Services, Ltd.; Varel; United Diamond; Roper; Southwest Oilfield Products; and a number of regional competitors. The Petroleum Services & Supplies segment 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 & Transmission

Distribution Services (NOV Wilson). The Distribution Services business unit is a market leader in the provision of supply chain management services to drilling contractors, exploration and production, pipeline operators and downstream energy processors) companies around the world. Through its network of approximately 460 branch locations worldwide, this business unit stocks and sells oilfield products including pipe, consumable maintenance, repair and operating supplies, valves, fittings, flanges and spare parts, all of which are needed throughout the drilling, completion and production process, midstream infrastructure development as well as refining and petrochemical businesses. The supplies and equipment stocked by our branches are customized to meet changing and varied local customer demands.

The Distribution Services business unit also provides one-stop-shop value propositions within the oil and gas exploration and production market in targeted areas of artificial lift, measurement and controls, valving and actuation, and flow optimization. Additionally, Distribution provides warehouse management, vendor integration and various inventory management services. Through focused effort, the business unit has built expertise in providing applications engineering, systems and parts integration, optimization solutions, and after-sales service and support.

Distribution Services’ supply chain solutions for customers include outsourcing the functions of procurement, inventory and warehouse management, logistics, business process, and performance metrics reporting. This solution allows the business unit to leverage the flexible infrastructure of its SAP™ ERP system to streamline the acquisition process from requisition to procurement to payment, by digitally managing approval routing and workflow, and by providing robust reporting functionality.

With its recent acquisitions, more than 80% of Distribution Services segment’s sales 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 business unit has now expanded into oilfields in over 20 countries. Approximately 10% of its revenue is from the resale of goods manufactured by other segments within the Company. The balance is from the sale of goods manufactured by third parties.

Distribution Services increases revenue and enhances customer alliances by continuously expanding product and service solutions and creating differentiated value propositions. The business unit leverages its extensive purchasing power to reduce the cost of goods. It is strategically and selectively expanding its sourcing network into low cost countries globally.

Transmission. The Transmission business unit supplies products and services used in the construction of water pipelines, lining, progressing cavity pumps, grinders, filters, and screens used in industrial applications, and artificial lift equipment and solutions used for increased oil and gas production.

Within the Transmission business unit the Infrastructure Products business manufactures concrete cylinder pipe, prestressed concrete cylinder pipe, steel pipe and reinforced concrete pipe for water transmission, storm and industrial waste water and sewage collection. Products are marketed directly using the Company’s own personnel, typically through competitive bidding. The Company competes with several other manufacturers and also with alternative products such as ductile iron, plastic, and clay pipe; but ordinarily these other materials do not offer the full diameter range produced by the Company. This business unit also includes the manufacturing of polyvinyl chloride and polyethylene sheet lining for the protection of concrete pipe and cast-in-place concrete structures from the corrosive effects of sewer gases, acids and industrial chemicals.

The Infrastructure Products group also supplies ready-mix concrete, crushed and sized basaltic aggregates, dune sand and concrete pipe, primarily to the construction industry in Hawaii. Ample raw materials for the aggregates and concrete products are typically available locally in Hawaii, and the business has exclusive rights to quarries containing many years’ reserves. The Infrastructure Products group also manufactures and markets concrete and steel poles for highway, street and outdoor area lighting and for traffic signals across the U.S. Within its market, there are competitors for each of the business unit’s products. Sales of poles are nationwide, but with a stronger concentration in the western and southeastern U.S. The marketing of poles is handled by the business’ own sales force and by outside sales agents. Competition for poles is mainly based on price and quality, but with some consideration for service and delivery.

Within the Transmission business unit, the Mono business serves its customers in various industrial and oil and gas markets by design, manufacturing and distributing key products including progressing cavity pumps, grinders, screens, filters, well-head drives, hydraulic pumping units, rod pumps, plunger lift systems and production automation systems and engineering related systems solutions. This business is highly diversified through its presence in oil and gas and industrial markets, which include waste water treatment, mining, chemical processing, paper and pulp, agriculture, food and beverage, among others. The Mono business supports its customers through direct sales, in partnership with over 700 channels to market and through National Oilwell Varco’s own network of supply branches. Mono is strengthening its offering by adding new artificial lift technologies, as well as measurement and controls competencies.

Customers and Competition. The primary customers for Distribution Services include drilling contractors, well servicing companies, major and independent oil and gas companies, refineries, pipeline operators, downstream energy processors and national oil companies. Customers for Transmission include local, state and federal agencies, developers, general contractors, major and independent oil and gas companies, and national oil companies. Mono also services a diverse customer base including oil & gas producers who use its products to produce oil and dewater gas wells, waste water treatment plants, cattle ranches, underground mines, wineries, paper mills, and food packaging plants. Competitors for Distribution Services include MRC Global, Inc.; Edgen Murray; Ferguson Enterprises, Inc. (a subsidiary of Wolseley, plc); WESCO International Inc.; KS Energy Limited; Russel Metals Energy Products and a number of large regional or product-specific competitors. Competitors for Transmission include Northwestern Pipe Company, a number of regional competitors for water pipelines, with Valmont, Skycast and Stresscrete as competitors for pole products. Mono competes with well-established European and North American brands like Netzsch, PCM, Kudu, Weatherford and Dover.

2012 Acquisitions and Other Investments

In 2012, the Company made the following acquisitions:


Acquisition	Form	Operating Segment	Date of Transaction
TechDrill LTD/Forth Valley Engineering LTD	Stock	Petroleum Services & Supplies	January 2012
Wyoming Pipe and Tool Corporation	Stock	Petroleum Services & Supplies	January 2012
Interval LLC	Stock	Petroleum Services & Supplies	January 2012
NKT Flexibles I/S	Stock	Rig Technology	April 2012
Spectral, Inc.	Asset	Petroleum Services & Supplies	April 2012
Enerflow Industries, Inc.	Stock/Asset	Rig Technology	May 2012
Wilson Distribution	Stock	Distribution & Transmission	May 2012
Zap-Lok Pipeline Systems, Inc.	Stock	Petroleum Services & Supplies	June 2012
Engco Sales Ltd	Asset	Distribution & Transmission	June 2012
CE Franklin LTD	Stock	Distribution & Transmission	July 2012
DynaWinch Industries Ltd	Stock	Rig Technology	July 2012
Petrex, Inc.	Stock	Petroleum Services & Supplies	August 2012
Fiberspar Corporation	Stock	Petroleum Services & Supplies	October 2012
Algoa Oil & Pipeline Services LTD	Stock	Rig Technology	October 2012
Algoa International Anstalt/Algoa International Angola Anstalt	Stock	Rig Technology	November 2012
GH Services, LLC	Stock	Rig Technology	December 2012
Westpro Fluid Handling Systems	Stock	Distribution & Transmission	December 2012

The Company paid an aggregate purchase price of $2,880 million, net of cash acquired for acquisitions in 2012. On February 20, 2013, the Company completed its previously announced acquisition of Robbins & Myers, Inc. for approximately $2.5 billion in cash. The Company borrowed approximately $1.4 billion under the $3.5 billion revolving credit facility and used approximately $1.1 billion of cash on hand to fund the acquisition.

Seasonal Nature of the Company’s Business

Historically, the level of some of the Company’s segments have followed seasonal trends to some degree. In general, the Rig Technology segment has not experienced significant seasonal fluctuation although orders for new equipment and aftermarket spare parts 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 & Transmission 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 segments 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 slowdowns 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 and 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 Petroleum Service & Supplies are rented and sold worldwide through our own sales force and through commissioned representatives. Distribution & Transmission 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 segment’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 segment’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 segment 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.

The Distribution & Transmission segment’s 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 Distribution & Transmission segment’s customers for transmission products and services primarily include local, state and federal agencies, developers and general contractors.

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 material 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 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, 2012, the Company held a substantial number of United States patents and had several patent applications pending. 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. Expiration dates of such patents range from 2013 to 2032. The Company does not expect significant adverse effects as patents expire.

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. 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, Cedar Park, Anderson, San Angelo, Fort Worth and Pampa, Texas; Duncan, Oklahoma; Orange, California; Edmonton, Canada; Aberdeen, Scotland; Kristiansand, Stavanger and Arendal, Norway; Etten-Leur and Groot-Ammers, the Netherlands; Carquefou, France; Kalundborg and Brondby, Denmark; Singapore; Lanzhou and Shanghai, China; Dubai, UAE; Ulsan, South Korea; Port Elizabeth and Cape Town, South Africa; and Luanda, Angola.

The 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; Manchester, England; Dubai, UAE; Macaé, Brazil 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; Jurong, Singapore; and Baimi Town, Jiangyan and Jiangsu, China. Solids control equipment and screens are manufactured at facilities in Houston and Conroe, Texas; New Iberia, Louisiana; Aberdeen, Scotland; Trinidad; Shah Alum and Puncak Alam, Malaysia; and Macaé, Brazil. Pumps are manufactured at facilities in Houston, Odessa and Marble Falls, Texas; McAlester and Tulsa, Oklahoma; Manchester and Newcastle, England; Melbourne, Australia; and Buenos Aires, Argentina. NOV IntelliServ manufactures and assembles equipment in Provo, Utah. The Company 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; Singapore; and Aberdeen, Scotland. Fiberglass and composite tubulars and fittings are manufactured at facilities in San Antonio, Burkburnett and Mineral Wells, Texas; Little Rock, Arkansas; Tulsa, Oklahoma; Wichita, Kansas; Geldermalsen, the Netherlands; Betim, Brazil; Johor, Malaysia; Singapore and Harbin and Suzhou, China, 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. Since 2006 the Company has experienced rising, declining and stable prices for mild steel and standard grades in line with broader economic activity and has generally seen specialty alloy prices continued to rise, driven primarily by escalation in the price of the alloying agents. 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, the Company continued to expand its supply base starting in 2006 throughout the world to address its customers’ needs. In 2012, the Company witnessed flat to slight increases in steel pricing which was somewhat mitigated by improved sourcing and supply chain practices. The Company anticipates flat to moderate increases in steel pricing in 2013. Higher prices and lower availability of steel and other raw materials 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. Backlog for equipment at December 31, 2012, 2011 and 2010, was $11.9 billion, $10.2 billion and $5.0 billion, respectively.

Employees

At December 31, 2012, the Company had a total of 60,235 employees, of which 8,574 were temporary employees. Approximately 906 employees in the U.S. are subject to collective bargaining agreements. Additionally, certain of the Company’s employees in various foreign locations are subject to collective bargaining agreements. The Company believes its relationship with its employees is good.

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:

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the ability of the members of the Organization of Petroleum Exporting Countries, or OPEC, to maintain price stability through voluntary production limits, the level of production by non-OPEC countries and worldwide demand for oil and gas;

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level of production from known reserves;

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cost of exploring for and producing oil and gas;

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level of drilling activity and drilling rig dayrates;

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worldwide economic activity;

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national government political requirements;

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development of alternate energy sources; and

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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. In 2009, oil prices continued to be volatile, rising to the $70 per barrel range during the year. In 2010 oil prices continued rising to finish the year well above $80 per barrel. Domestic spot gas prices generally ranged between $1.80-$2.60 per mmbtu of gas from 1991 through 1999 then experienced spikes into the $10 range in 2001 and 2003. Prices generally ranged between $4.50-$12.00 per mmbtu during 2005-2008. During 2009 through 2011, spot gas prices generally stabilized, dropping into the $3.00-$4.50 per mmbtu range, but declined below $3.00 late in 2011 and throughout much of 2012 before increasing slightly above $3.00 in late 2012.

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.

Events in 2008 and 2009 constrained credit markets and sparked a serious global banking crisis. The slowdown in worldwide economic activity caused by the global recession reduced demand for energy and resulted in lower oil and natural gas prices. While markets have improved since 2008, recent economic data suggests the potential for another global recession, which could negatively impact oil and natural gas prices and restrict availability to credit markets. 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 availability of credit to our customers is reduced, 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, 2012, we had a backlog of approximately $11.9 billion of drilling equipment to be manufactured, assembled, tested and delivered by our Rig Technology segment. 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:

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our failure to adequately estimate costs for making this drilling equipment;

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our inability to deliver equipment that meets contracted technical requirements;

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our inability to maintain our quality standards during the design and manufacturing process;

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our inability to secure parts made by third party vendors at reasonable costs and within required timeframes;

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unexpected increases in the costs of raw materials; and

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our inability to manage unexpected delays due to weather, shipyard access, labor shortages or other factors beyond our control.

The Company’s existing contracts for rig equipment generally carry down payment and progress billing terms favorable to the ultimate completion of these projects and 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:

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price changes;

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new product and technology introductions; and

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improvements in availability and delivery.

In addition, certain foreign jurisdictions and government-owned petroleum companies located in some of the countries in which we operate have adopted policies or regulations which may give local nationals in these countries competitive advantages. Competition in our industry could lead to lower revenues and earnings.

We have aggressively expanded our businesses and intend to maintain an aggressive growth strategy.

We have aggressively expanded and grown our businesses during the past several years, through acquisitions and investment in internal growth. We anticipate that we will continue to pursue an aggressive growth strategy but we cannot assure you that attractive acquisitions will be available to us at reasonable prices or at all. In addition, we cannot assure you that we will successfully integrate the operations and assets of any acquired business with our own or that our management will be able to manage effectively the increased size of the Company or operate any new lines of business. Any inability on the part of management to integrate and manage acquired businesses and their assumed liabilities could adversely affect our business and financial performance. In addition, we may need to incur substantial indebtedness to finance future acquisitions. We cannot assure you that we will be able to obtain this financing on terms acceptable to us or at all. Future acquisitions may result in increased depreciation and amortization expense, increased interest expense, increased financial leverage or decreased operating income for the Company, any of which could cause our business to suffer.

Our operating results have fluctuated during recent years and these fluctuations may continue.

We have experienced fluctuations in quarterly operating results in the past. We cannot assure 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:

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fluctuations in the oil and gas industry;

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competition;

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the ability to service the debt obligations of the Company;

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the ability to identify strategic acquisitions at reasonable prices;

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the ability to manage and control operating costs of the Company;

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fluctuations in political and economic conditions in the United States and abroad; and

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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 59% of our revenues in 2012 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, Latin 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 statutes. Under trading sanctions laws, the U.S. and other governments 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 and subsequent inquiries from governmental agencies requesting records related to our compliance with export trade laws and regulations. We have cooperated fully with agents from the Department of Justice, the Bureau of Industry and Security, the Office of Foreign Assets Control, and U.S. Immigration and Customs Enforcement in responding to the inquiries. We have also cooperated with an informal inquiry from the Securities and Exchange Commission in connection with the inquiries previously made by the aforementioned federal agencies. We have conducted our own internal review of this matter. At the conclusion of our internal review in the fourth quarter of 2009, we identified possible areas of concern and discussed these areas of concern with the relevant agencies. We are currently negotiating a potential resolution with the agencies involved related to these matters. We currently anticipate that any administrative fine or penalty agreed to as part of a resolution would be within established accruals, and would not have a material effect on our financial position or results of operations. To the extent a resolution is not negotiated as anticipated, we cannot predict the timing or effect that any resulting government actions 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, but not limited to, the Canadian dollar, the Euro, the British pound sterling, the Norwegian krone, the Venezuelan bolivar and the South Korean won. Approximately 59% of our 2012 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 use derivative financial instruments to mitigate our net exposure to currency exchange fluctuations. We had forward contracts with a notional amount of $3,662 million (with a fair value of $86 million) as of December 31, 2012, 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 $7.1 billion of goodwill and $0.6 billion of other intangible assets with indefinite lives as of December 31, 2012. 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:

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personal injury or loss of life;

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severe damage to or destruction of property; or

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environmental damage and suspension of operations.

Our current and past activities, as well as the activities of our former divisions and subsidiaries, could result in our facing substantial environmental, regulatory and other liabilities. These could include the costs of cleanup of contaminated sites and site closure obligations. These liabilities could also be imposed on the basis of one or more of the following theories:

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negligence;

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strict liability;

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breach of contract with customers; or

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as a result of our contractual agreement to indemnify our customers in the normal course of business, which is normally the case.

We may not have adequate insurance for potential environmental liabilities.

While we maintain liability insurance, this insurance is subject to coverage limits. In addition, certain policies do not provide coverage for damages resulting from environmental contamination. We face the following risks with respect to our insurance coverage:

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we may not be able to continue to obtain insurance on commercially reasonable terms;

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we may be faced with types of liabilities that will not be covered by our insurance;

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our insurance carriers may not be able to meet their obligations under the policies; or

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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.

The adoption of climate change legislation or regulations restricting emissions of greenhouse gases could increase our operating costs or reduce demand for our products.

Environmental advocacy groups and regulatory agencies in the United States and other countries have been focusing considerable attention on the emissions of carbon dioxide, methane and other greenhouse gases and their potential role in climate change. The adoption of laws and regulations to implement controls of greenhouse gases, including the imposition of fees or taxes, could adversely impact our operations and financial condition. The U.S. Congress is currently working on legislation to control and reduce emissions of greenhouse gases in the United States, which includes establishing cap-and-trade programs. In addition to the pending climate legislation, the U.S. Environmental Protection Agency has proposed regulations that would require permits for and reductions in greenhouse gas emissions for certain facilities, and may issue final rules this year. These changes in the legal and regulatory environment could 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.

We had revenues of 10% of total revenue from one of our customers for the year ended December 31, 2012.

The loss of this customer (Samsung Heavy Industries) or a significant reduction in its purchases could adversely affect our future revenues and earnings.

The 2010 moratorium on deepwater drilling in the U.S. Gulf of Mexico and its consequences could have a material adverse effect on our business.

A moratorium on deepwater drilling in the U.S. Gulf of Mexico was enacted during the second quarter of 2010 following the Macondo well blowout and oil spill. Even though such moratorium has been lifted, any prolonged reduction in oil and natural gas drilling and production activity as a result of such moratorium or permitting issues in this area could result in a corresponding decline in the demand for our products and services, which could adversely impact our operating results and financial condition.

Our information systems may experience an interruption or breach in security.

We rely heavily on information systems to conduct our business. Any failure, interruption or breach in security of our information systems could result in failures or disruptions in our customer relationship management, general ledger systems and other systems. While we have policies and procedures designed to prevent or limit the effect of the failure, interruption or security breach of our information systems, there can be no assurance that any such failures, interruptions or security breaches will not occur or, if they do occur, that they will be adequately addressed. The occurrence of any failures, interruptions or security breaches of the our information systems could damage our reputation, result in a loss of customer business, subject us to additional regulatory scrutiny, or expose us to civil litigation and possible financial liability, any of which could have a material adverse effect on our financial position or results of operations.

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 raise 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.

Fiberglass-reinforced spoolable pipe		A spoolable glass fiber-reinforced epoxy composite tubular product for onshore oil and gas gathering and injection systems, with superior corrosion resistant properties and lower installed cost than steel.

Flexible pipe		A dynamic riser that connects subsea production equipment to a topside facility allowing for the flow of oil, gas, and/or water.

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.

FPSO		A Floating Production, Storage and Offloading vessel used to receive hydrocarbons from subsea wells, and then produce and store the hydrocarbons until they can be offloaded to a tanker or pipeline.

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.

Hydraulic Fracturing		The process of creating fractures in a formation by pumping fluids, at high pressures, into the reservoir, which allows or enhances the flow of hydrocarbons.

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 2.5 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.

Mooring system		The method by which a vessel or buoy is fixed to a certain position, whether permanently or temporarily.

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		Equipment used in: 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.



Tiebacks (Subsea)		A series of flowlines and pipes that connect numerous subsea wellheads to a single collection point.

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.

Turret		Mechanical device that allows a floating vessel to rotate around stationary flowlines, umbilicals, and other associated risers.

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.

Wellhead		The termination point of a wellbore at surface level or subsea, often incorporating various valves and control instruments.

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 oil well 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 1,160 facilities worldwide as of December 31, 2012, including the following principal manufacturing, service, distribution and administrative facilities:


Location	Description	Building Size (SqFt)	Property Size (Acres)	Owned / Leased	Lease Termination Date
Rig Technology:
Lanzhou, China	Manufacturing Plant (Drilling Equipment) & Administrative Offices)	945,836	44	Owned*	10/20/2020
Pampa, Texas	Manufacturing Plant	549,095	500	Owned
Houston, Texas	Manufacturing Plant of Drilling Equipment	511,964	33	Leased	4/30/2014
Kalundborg, Denmark	Flexibles Manufacturing, Warehouse, Shop & Administrative Offices	485,067	38	Owned
Ulsan, South Korea	Fabrication of Drilling Equipment	380,068	51	Owned
Houston, Texas	Bammel Facility, Repairs, Service, Parts, Administrative & Sales Offices	377,750	19	Leased	6/30/2022
Houston, Texas	West Little York Manufacturing Facility, Repairs, Service, Administrative & Sales Offices	483,450	34	Owned
Orange, California	Manufacturing & Office Facility	351,418	9	Owned*	12/31/2020
Fort Worth, Texas	Coiled Tubing Manufacturing Facility, Warehouse, Administrative & Sales Offices	233,173	24	Owned
Sugar Land, Texas	Manufacturing Plant, Warehouse & Administrative Offices	223,345	24	Owned
Cedar Park, Texas	Instrumentation Manufacturing Facility, Administrative & Sales Offices	215,778	40	Owned
Carquefou, France	Manufacturing Plant of Offshore Equipment	213,000		Owned
Galena Park, Texas	Manufacturing Plant (Drilling Rigs & Components) & Administrative Offices	191,913	22	Owned
Lafayette, Louisiana	Repair, Services and Spares facility	189,000	17	Leased	9/28/2025
Aberdeen, Scotland	Pressure Control Manufacturing, Administrative & Sales Offices	188,200	5	Leased	8/31/2018
Conroe, Texas	Manufacturing Plant, Administrative & Sales Offices	173,800	13	Leased	1/7/2022
Houston, Texas	Manufacturing Plant of Drilling Rigs & Components, Admin & Sales Offices	170,040	11	Owned
Kristiansand, Norway	Warehouse & Administrative/Sales Offices	167,200	1	Owned
Calgary, Canada	Manufacturing Facility & Administrative Offices	161,321	19	Leased	5/10/2017
Singapore	Manufacturing, Repairs, Service, Field Service/Training, Administrative & Sales Offices	149,605	3	Leased	1/5/2024
Anderson, Texas	Rolligon Manufacturing Facility, Administrative & Sales Offices	145,727	77	Leased	5/10/2016
Houston, Texas	Administrative Offices (Westchase)	125,494	4	Leased	9/30/2020
Duncan, Oklahoma	Nitrogen Units Manufacturing Facility, Warehouse & Offices	93,800	14	Owned
Molde, Norway	Manufacturing Facility of Drilling Equipment	78,000	1	Owned
Etten Leur, Netherlands	Manufacturing Plant & Sales Offices (Drilling Equipment)	75,000	6	Owned
Sogne, Norway	Warehouse and Offices	70,959	4	Leased	12/31/2017
Edmonton, Canada	Manufacturing Plant (Drilling Machinery & Equipment)	70,346	18	Owned
Stavanger, Norway	Manufacturing Facility of Drilling Equipment	41,333	1	Leased	9/30/2015
Dubai, UAE	Repair & Overhaul of Drilling Equipment, Warehouse & Sales Office	31,633	2	Owned
Aracaju, Brazil	Fabrication of Drilling Equipment	11,195	1	Leased	7/14/2013
New Iberia, Louisiana	Riser Repair Facility	10,000	2	Leased	M-T-M


Location	Description	Building Size (SqFt)	Property Size (Acres)	Owned / Leased	Lease Termination Date
Petroleum Services & Supplies:
Senai, Malaysia	Manufacturing Facility of Fiber Glass Products	595,965	14	Owned*
Navasota, Texas	Manufacturing Facility & Administrative Offices	562,112	196	Owned
Conroe, Texas	Manufacturing Facility of Drill Bits and Downhole Tools, Administrative & Sales Offices	341,800	35	Owned
Houston, Texas	Sheldon Road Inspection Facility	319,365	192	Owned
Veracruz, Mexico	Manufacturing Facility of Tool Joints, Warehouse & Administrative Offices	303,400	42	Leased	M-T-M
Houston, Texas	Holmes Rd Complex: Manufacturing, Warehouse, Coating Manufacturing Plant & Corporate Offices	300,000	50	Owned
Little Rock, Arkansas	Manufacturing Facility of Fiber Glass Products	271,924	44	Owned
Houston, Texas	Manufacturing, Service, Warehouse & Administrative Offices (WGB)	245,319	14	Leased	3/31/2018
Houston, Texas	QT Coiled Tubing Manufacturing Facility, Warehouse & Offices	238,428	26	Owned
Tulsa, Oklahoma	Manufacturing Facility of Pumps, Warehouse and Administrative & Sales Offices	212,625	10	Owned
Durham, England	Manufacturing Facility, Warehouse & Administrative Offices	183,100	13	Leased	3/30/2066
Dubai, UAE	Manufacturing Facility of Downhole Tools, Distribution Warehouse	180,000	1	Leased	1/29/2021
Conroe, Texas	Solids Control Manufacturing Facility, Warehouse, Administrative & Sales Offices, and Engineering Labs	153,750	35	Owned
Houston, Texas	Manufacturing of fiber-reinforced tubular products & Administrative Offices	146,668	6	Leased	6/30/2016
McAlester, Oklahoma	Manufacturing Facility of Pumps, Service & Administrative Offices	139,359	25	Owned
San Antonio, Texas	Manufacturing Facility of Fiber Glass Products	120,084	20	Owned
Edmonton, Canada	Manufacturing Facility, Repairs, Assembly, Warehouse & Administrative Offices	112,465	11	Owned
Singapore	Manufacturing Plant of Roller Cone Drill Bits, Shop, Warehouse & Administrative Offices	109,663	5	Leased	4/29/2048
Provo, Utah	Manufacturing Facility of Drilling Products, Fabrication, Warehouse & Administrative Offices	109,026	15	Owned
Aberdeenshire, Scotland	Solids Control Manufacturing Facility, Assembly, Administrative & Sales Offices	107,250	6	Owned
Betim, Brazil	Manufacturing Facility of Fiber Glass Products	96,691	18	Owned
Mineral Wells, Texas	Manufacturing Facility of Fiber Glass Products	95,640	15	Owned
Singapore	Manufacturing Facility of Fiber Glass Products	86,941	2	Leased	10/31/2013
Larose, Louisiana	Generator Rentals & Service, Assembly, Warehouse & Administrative Offices	72,993	11	Leased	6/30/2016
Stonehouse, U.K.	Manufacturing Facility, Inspection Plant & Premium Threading Shop	71,000	4	Owned
Groot-Ammers, Netherlands	Workshop, Warehouse & Offices	61,859	3	Leased	12/31/2018
Beaumont, Texas	Pipe Threading Facility, Fabrication, Warehouse & Administrative Offices	42,786	40	Owned
Dubai, UAE	Service Facility of Solids Control Equipment, Screens & Spare Parts, Inventory Warehouse, Sales, Rentals & Administrative Offices	14,569	1	Leased	10/31/2013
Rio de Janeiro, Brazil	Service and Repair Center, and Distribution Operations	12,116	1	Leased	M-T-M


Location	Description	Building Size (SqFt)	Property Size (Acres)	Owned / Leased	Lease Termination Date
Distribution & Transmission:
LaPorte, Texas	Distribution and Warehouse	450,000	20	Leased	8/31/2016
Manchester, England	Manufacturing, Assembly & Testing of PC Pumps and Expendable Parts, Administrative & Sales Offices	244,000	11	Owned
Tracy, California	Water Transmission Group / Northern California	164,735	83	Owned
Bogota, Colombia	APCI Fabrication, Coating, Machine shop	146,904	33	Owned
Rancho Cucamonga, California	Water Transmission Group / Southern California	130,600	73	Owned
Anniston, Alabama	Pole Products Manufacture	121,696	20	Leased	1/31/2015
Houston, Texas	Distribution and Warehouse	120,423	19	Owned*	12/31/2021
Lloydminster, Canada	Lloydminster Distribution Operations; Applied Products Facility	114,100	23	Leased	5/31/2019
Edmonton, Canada	Redistribution Center	100,000	7	Leased	1/31/2014
Kailua, Hawaii	KAAPA Quarry	53,980	163	Owned*	12/31/2052
Estevan, Canada	Distribution & Warehouse	27,842	6	Owned
Honolulu, Hawaii	Hawaii Concrete Division Head Quarters	21,215	3	Leased	12/31/2027
Corporate:
Houston, Texas	Corporate and Shared Administrative Offices	337,019	14	Leased	5/31/2017

*	Building owned but land leased.

We own or lease more than 170 repair and manufacturing facilities that refurbish and manufacture new equipment and parts, approximately 460 distribution service centers and 530 service centers that provide inspection and equipment rental worldwide.

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. See Note 12 to the Consolidated Financial Statements.

ITEM 4.

MINE SAFETY DISCLOSURES

Information regarding mine safety and other regulatory actions at our mines is included in Exhibit 95 to this Form 10-K.

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 and the cash dividends declared per share.


	2012								2011
	First Quarter		Second Quarter		Third Quarter		Fourth Quarter		First Quarter		Second Quarter		Third Quarter		Fourth Quarter
Common stock sale price:
High	$	87.18	$	80.67	$	84.83	$	82.03	$	82.26	$	81.46	$	83.31	$	75.73
Low	$	70.75	$	60.00	$	64.40	$	64.87	$	63.72	$	65.40	$	51.22	$	50.23
Cash dividends per share	$	0.12	$	0.12	$	0.12	$	0.13	$	0.11	$	0.11	$	0.11	$	0.12

As of February 14, 2013, there were 3,375 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.

Cash dividends aggregated $209 million and $191 million for the years ended December 31, 2012 and 2011, respectively. The declaration and payment of future dividends is at the discretion of the Company’s Board of Directors and will be dependent upon the Company’s results of operations, financial condition, capital requirements and other factors deemed relevant by the Company’s Board of Directors.

The information relating to our equity compensation plans required by Item 5. “Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities” 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, 2007 in National Oilwell Varco, Inc., 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.

LOGO

12/07

12/08

12/09

12/10

12/11

12/12

National Oilwell Varco, Inc.

100.00

33.27

61.55

94.77

96.42

97.58

S&P 500

100.00

63.00

79.67

91.67

93.61

108.59

S&P Oil & Gas Equipment & Services

100.00

40.82

65.23

90.86

80.24

80.25

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,
	2012 (1)		2011		2010		2009		2008 (2)
	(in millions, except per share data)
Operating Data:
Revenue	$	20,041	$	14,658	$	12,156	$	12,712	$	13,431
Operating profit		3,557		2,937		2,447		2,315		2,918
Income before taxes		3,505		2,922		2,397		2,208		2,961
Net income attributable to Company	$	2,491	$	1,994	$	1,667	$	1,469	$	1,952

Net income per share
Basic	$	5.86	$	4.73	$	3.99	$	3.53	$	4.91

Diluted	$	5.83	$	4.70	$	3.98	$	3.52	$	4.90

Cash dividends per share	$	0.49	$	0.45	$	0.41	$	1.10	$	—

Other Data:
Depreciation and amortization	$	628	$	555	$	507	$	490	$	402
Capital expenditures	$	583	$	483	$	232	$	250	$	379

Balance Sheet Data:
Working capital	$	10,029	$	6,694	$	5,999	$	5,084	$	4,034
Total assets	$	31,484	$	25,515	$	23,050	$	21,532	$	21,479
Long-term debt, less current maturities	$	3,148	$	159	$	514	$	876	$	870
Total Company stockholders’ equity	$	20,239	$	17,619	$	15,748	$	14,113	$	12,628

(1)	Financial information for prior periods and dates may not be comparable due to the impact of $2.9 billion in business combinations on our financial position and results of operations during 2012.

(2)	Financial results of Grant Prideco have been included in our Consolidated Financial Statements beginning April 21, 2008, the date the Grant Prideco merger was completed and each of Grant Prideco’s common shares were exchanged for .4498 shares of our common stock and $23.20 in cash.

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 1,160 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, 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 & Transmission. See Item 1. “Business” for a discussion of each of these business segments.

Unless indicated otherwise, results of operations data are presented in accordance with accounting principles generally accepted in the United States (“GAAP”). In an effort to provide investors with additional information regarding our results of operations, certain non-GAAP financial measures, including operating profit excluding other costs, operating profit percentage excluding other costs and diluted earnings per share excluding other costs, are provided. See “Non-GAAP Financial Measures and Reconciliations” in Results of Operations for an explanation of our use of non-GAAP financial measures and reconciliations to their corresponding measures calculated in accordance with GAAP.

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, and the worldwide oil and gas inventory levels. Key industry indicators for the past three years include the following:


	2012*		2011*		2010*		% 2012 v 2011			% 2012 v 2010
Active Drilling Rigs:
U.S.		1,919		1,875		1,541		2.3	%		24.5	%
Canada		365		423		351		(13.7	%)		4.0	%
International		1,234		1,168		1,094		5.7	%		12.8	%

Worldwide		3,518		3,466		2,986		1.5	%		17.8	%

West Texas Intermediate Crude Prices (per barrel)	$	94.11	$	94.90	$	79.40		(0.8	%)		18.5	%

Natural Gas Prices ($/mmbtu)	$	2.75	$	4.00	$	4.39		(31.3	%)		(37.4	%)

*	Averages for the years indicated. See sources below.

The following table details the U.S., Canadian, and international rig activity and West Texas Intermediate Oil prices for the past nine quarters ended December 31, 2012 on a quarterly basis:

LOGO

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 was $94.11 per barrel in 2012, a slight decrease of 0.8% over the average price for 2011 of $94.90 per barrel. Average natural gas prices were $2.75 per mmbtu, a decrease of 31.3% compared to the 2011 average of $4.00 per mmbtu. Average rig activity worldwide increased 1.5% for the full year in 2012 compared to 2011. Average crude oil prices for the fourth quarter of 2012 was $87.96 per barrel and natural gas was $3.40 per mmbtu.

At February 8, 2013, there were 2,390 rigs actively drilling in North America, compared to 1,967 rigs at December 31, 2012; an increase of 21.5% from year end 2012 levels. The price of oil increased to $95.72 per barrel and gas decreased to $3.27 per mmbtu at February 8, 2013, representing a 4.2% increase in oil prices and a 4.6% decrease in gas prices from the end of 2012.

EXECUTIVE SUMMARY

During 2012 National Oilwell Varco, Inc. earned $2.5 billion in net income attributable to Company, or $5.83 per fully diluted share. Earnings per diluted share increased 24% from prior year levels of $2.0 billion or $4.70 per fully diluted share. Excluding other costs (as defined in the “Non-GAAP Financial Measures and Reconciliations” in Results of Operations) from both years, diluted earnings per share of $5.91 in 2012 increased 24% from $4.77 per share in 2011.

During 2012 revenue grew 37% from 2011, to $20.0 billion, and operating profit grew 21% from 2011 as well, to $3.6 billion. Generally 2012 benefitted from strategic acquisitions as well as higher international drilling activity, which saw international rig counts (as measured by Baker Hughes) increase 6% from 2011. This enabled all three of the Company’s reporting segments to post higher year-over-year revenues in 2012.

For its fourth quarter ended December 31, 2012, the Company generated $668 million in net income attributable to Company, or $1.56 per fully diluted share, on $5.7 billion in revenue. Compared to the third quarter of 2012 revenue increased $366 million or 7% and net income attributable to Company increased $56 million. Compared to the fourth quarter of 2011, revenue increased $1.4 billion or 33%, and net income attributable to Company increased $94 million or 16%.

The fourth quarter of 2012 included pre-tax other costs of $51 million, the third quarter of 2012 included pre-tax other costs of $48 million, and the fourth quarter of 2011 included pre-tax other costs of $12 million. The fourth quarter of 2012 also included a net $69 million tax benefit related to certain U.S. foreign tax credits in the quarter. Excluding the tax benefit and the other costs from all periods, fourth quarter 2012 earnings were $1.49 per fully diluted share, compared to $1.52 per fully diluted share in the third quarter of 2012 and $1.37 per fully diluted share in the fourth quarter of 2011.

Operating profit excluding other costs was $954 million or 16.8% of sales in the fourth quarter of 2012, compared to $946 million or 17.8% of sales in the third quarter of 2012, and $860 million or 20.2% of sales in the fourth quarter of 2011. Fourth quarter 2012 results include full quarter results for several businesses acquired since the beginning of the year, including three lower-margin distribution businesses, which resulted in lower margins for the fourth quarter of 2012 as compared to the fourth quarter of 2011 year-over-year. Operating leverage or flow-through (the change in operating profit divided by the change in revenue) was 2% on the sequential revenue increase, and 7% on the year-over-year fourth quarter sales increase.

Also of note, in the fourth quarter of 2012, National Oilwell Varco issued $3 billion of Senior Notes with an effective yield of 2.92%, with $500 million due in 5 years, $1.4 billion due in 10 years, and $1.1 billion due in 30 years.

Oil & Gas Equipment and Services Market

Worldwide, developed economies turned down in late 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 responded vigorously through 2009, but a credit-driven worldwide economic recession developed nonetheless. Developed economies struggled to recover throughout 2010 and 2011, facing additional economic weakness related to potential sovereign debt defaults in Europe. As a result, commodity prices, including oil and gas prices, have been volatile. After rising steadily for six years to peak at around $140 per barrel (West Texas Intermediate Crude Prices) earlier in 2008, oil prices collapsed back to average $43 per barrel during the first quarter of 2009, but have slowly recovered into the $100 per barrel range by mid-2011 where they held relatively steady since (although the fourth quarter of 2012 dipped to average $88 per barrel). After trading in the range of $6 to $9 an mmbtu from 2004 to 2008, North American gas prices declined to average $3.17 per mmbtu in the third quarter of 2009. Gas prices recovered modestly, trading up above $5 six months later, but then slowly settled into the $3 to $4 per mmbtu through 2011 before turning down sharply in early 2012 to the $2 range (fourth quarter 2012 recovered to average $3.40 per mmbtu). The recent gas price collapse appears to be a direct result of rising gas supply out of unconventional shale reservoir development across North America, including gas associated with liquids production from shales.

The steadily rising oil and gas prices seen between 2003 and 2008 led to high levels of exploration and development drilling in many oil and gas basins around the globe by 2008, but activity slowed sharply in 2009 with lower oil and gas prices and tightening credit availability. Strengthening oil prices since then have led to steadily rising oil-drilling activity over the past two years.

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 in September 2008, but decreased to a low of 876 in June, 2009. U.S. rig count increased steadily to 2,026 by late 2011, but began to decline with lower gas prices to average 1,809 rigs during the fourth quarter of 2012. Many oil and gas operators reliant on external financing to fund their drilling programs significantly curtailed their drilling activity in 2009, but drilling recovered across North America as gas prices improved. Recently low gas prices have caused operators to trim drilling, driving the average U.S. gas rig count down 52% from the fourth quarter of 2011, to an average of 423 in the fourth quarter of

2012. However, with high oil prices, many have redirected drilling efforts towards unconventional shale plays targeting oil, rather than gas. For the fourth quarter of 2012, oil-directed drilling rose to almost 77% of the total domestic drilling effort, and, while the average oil-directed drilling rig count declined by 2% from the third quarter to 1,383 rigs, it remains near its highest levels in the U.S. since the early 1980’s.

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; but, the international rig count exhibited modest declines nonetheless, falling from its September 2008 peak of 1,108 to 947 in August 2009. Recently international drilling rebounded due to high oil prices, climbing back to 1,285 in June 2012 before falling back to 1,253 in December.

During 2009 the Company saw its Petroleum Services & Supplies and its Distribution & Transmission margins affected most acutely by a drilling downturn, through both volume and price declines. Resumption of drilling activity since enabled both of these segments to gain volume, stabilize and lift pricing, and improve margins since the fourth quarter of 2009. The Company’s Rig Technology segment was less impacted by the 2009 downturn owing to its high level of contracted backlog, which it executed well. It posted higher revenues in 2009 than 2008 as a result. Its revenues declined in 2010 as its backlog declined, but increased 12% in 2011 as orders for new offshore rigs began to increase.

The recent economic decline beginning in late 2008 followed an extended period of high drilling activity which fueled strong demand for oilfield services between 2003 and 2008. Incremental drilling activity through the upswing shifted toward harsh environments, employing increasingly sophisticated technology to find and produce reserves. Higher utilization of drilling rigs 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 was 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 1.) retool the existing fleet of jackup rigs (according to RigLogix, nearly 65% of the existing 494 jackup rigs are more than 25 years old); 2.) replace older mechanical and DC electric land rigs with improved AC power, electronic controls, automatic pipe handling and rapid rigup and rigdown technology; and 3.) build out additional deepwater 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 June 30, 2005, to $11.8 billion at September 30, 2008. However, as a result of the credit crisis and slowing drilling activity, orders declined below amounts flowing out of backlog as revenue, causing the backlog to decline to $4.9 billion by June 30, 2010. The backlog increased steadily since, as drillers began ordering more than the Company shipped out of backlog, and finished the fourth quarter of 2012 at a record $11.9 billion. Approximately $7.4 billion of these orders are scheduled to flow out as revenue during 2013, with the balance flowing out in 2014 and beyond. Of this backlog, 91% of the total is for equipment destined for offshore operations, with 9% destined for land. Equipment destined for international markets totaled 94% of the backlog.

Segment Performance

The Rig Technology segment generated $10.1 billion in revenues and $2.3 billion in operating profit or 23.1% of sales during 2012. Compared to the prior year revenues improved 30%, however, operating profit improved 14% year-over-year due to a broad change in the segment’s business mix, which led to lower margins. Offshore projects contracted at high prices in 2007 and 2008 were manufactured in low cost environments in 2010, resulting in high margins (29.6%) for the group. As these projects were completed and replaced with lower priced projects, 2011 margins declined 330 basis points from the prior year. For the fourth quarter of 2012, the segment generated $2.9 billion in revenues and $636 million in operating profit or 22.0% of sales. Compared to the prior quarter revenues increased $349 million or 14%, and operating profit increased $38 million. Operating leverage or flow-through was 11% from the third quarter to the fourth quarter. Compared to the fourth quarter of 2011 segment revenues grew $580 million or 25%, and operating profit increased $39 million. Year-over-year operating leverage or flow-through was 7%. Margins have moved down steadily since mid-2010 due to an adverse mix shift in the segment, the addition of lower-margin acquisitions, and incremental expenses to support several strategic growth initiatives. The mix shift arises from offshore projects contracted at high prices in 2007 and 2008, which were subsequently manufactured in low cost environments in 2009 and 2010, resulting in high margins for the group which peaked in the third quarter of 2010. As these projects have been completed and replaced with lower priced projects, margins have gradually declined. Revenue out of backlog increased 16% sequentially and increased 25% year-over-year. Non-backlog revenue, which is predominantly aftermarket spares and services, increased 8% sequentially and increased 27% from the fourth

quarter of 2011. Orders for seven deepwater floating rig equipment packages, and three spare BOP stacks contributed to total order additions to backlog of $2.4 billion during the fourth quarter. Interest in offshore rig construction has remained strong as announced dayrates for deepwater offshore rigs are increasing, rig building costs have stabilized at attractive levels, and financing appears to be available for most established drillers. The Company continues to tender additional new offshore rig projects for Petrobras to shipyards and drilling contractors, which are to be built in Brazil. However, further potential bookings of any additional offshore rigs for Brazil may continue to be subject to delays. The segment’s well intervention and stimulation product sales increased 25% sequentially, as the delivery of several large projects to international customers more than offset a continued decline in demand for pressure pumping equipment.

The Petroleum Services & Supplies segment generated $7.0 billion in revenue and $1.5 billion in operating profit, or 21.5% of sales, for the full year 2012. Compared to the prior year revenue increased 23%, and operating leverage or flow-through was 33%. For the fourth quarter of 2012, the segment generated $1.8 billion in revenue and $340 million in operating profit, or 19.2% of sales. Compared to the prior quarter revenue increased $53 million or 3%, but operating profit declined $43 million. Sequentially, high year-end sales of drill pipe and large outside diameter (“O.D.”) connectors, combined with revenue growth in the international coating business, more than offset the lower sales of downhole tools, fluid-end expendables and coiled tubing, which were directly attributable to the reduction in U.S. land drilling and well service activity. Compared to the fourth quarter of 2011 revenues increased $200 million or 13% and operating leverage or flow-through was 23%. Approximately 55% of the segment’s fourth quarter sales were into North American markets, and 45% of sales were into international markets.

The Distribution & Transmission segment generated $3.9 billion in revenue and $185 million in operating profit or 4.7% of sales during 2012. Revenues improved 110% from 2011. For the fourth quarter of 2012, the segment generated $1.3 billion in revenue and $54 million in operating profit or 4.3% of sales. Revenues declined $47 million or 4% from the third quarter of 2012 while operating profit increased $12 million. Compared to the fourth quarter of 2011, revenues increased $708 million or 126% and flow-through or operating leverage was 1%. Sequentially, the overall decline in U.S. drilling and well service activity negatively impacted day-to-day sales of maintenance, repair and operating consumables, as well as sales of tubular products. The year over year revenue growth was due primarily to the acquisitions of Wilson and CE Franklin, made during the second and third quarters of 2012, respectively. Approximately 84% of the group’s fourth quarter sales were into North American markets and 16% into international markets.

Outlook

Following the credit market downturn, global recession, and lower commodity prices of 2009, we saw signs of stabilization and recovery in many of our markets in 2010 and into 2011, led by higher drilling activity in North America and slowly improving international drilling activity. Order levels for new deepwater drilling rigs have rebounded sharply, and the Rig Technology segment continues to experience a high level of interest as dayrates for deepwater offshore rigs continue to improve. Still, margins, which were 22.4% in the fourth quarter of 2012, may be temporarily challenged to expand, due to lower-margin contributions from recent subsea production equipment acquisitions, a soft outlook for land drilling, workover and pressure pumping equipment markets in North America, in view of low gas and natural gas liquids prices, and by incremental expenses to support long-term strategic growth initiatives.

Our outlook for the Company’s Petroleum Services & Supplies segment and Distribution & Transmission segment remains closely tied to the rig count, particularly in North America. The fourth quarter saw domestic rig counts continue to decline, resulting in an average U.S. rig count in December 2012 that was down 11% from the average U.S. rig count in January of 2012, and an average Canadian rig count in December 2012 that was down 18% from the same period in 2011. As a result, pricing and volumes are beginning to come under pressure as pressure pumpers, drilling contractors and oil companies reduce operating and capital expenditures. Additionally, economic weakness may pressure oil prices, which could lead to further activity declines, particularly among North American operators which may rely on cash flows from gas production and/or external financing to fund their drilling operations. In contrast, activity generally seems to be continuing to increase in most international markets outside North America.

The Company believes it is well positioned, and should benefit from its strong balance sheet and capitalization, access to credit, global infrastructure, broad product and service offering, installed base of equipment, and a record level of contracted orders. In the event of a market downturn, the Company also believes that its long history of cost-control and downsizing in response to slowing market conditions, and of executing strategic acquisitions during difficult periods will enable it to capitalize on new opportunities to effect new organic growth and acquisition initiatives.

Still the recovery of the world economy continues to move forward with a great deal of uncertainty as the world watches the sovereign debt crises in several European countries unfold, market turbulence and general global economic worries. If such global economic uncertaintanties develop adversely, world oil and gas prices could be impacted which in turn could negatively impact the worldwide rig count and the Company’s future financial results.

Results of Operations

Years Ended December 31, 2012 and December 31, 2011

The following table summarizes the Company’s revenue and operating profit by operating segment in 2012 and 2011 (in millions):


	Years Ended December 31,						Variance
	2012			2011			$			%
Revenue:
Rig Technology	$	10,107		$	7,788		$	2,319			29.8	%
Petroleum Services & Supplies		6,967			5,654			1,313			23.2	%
Distribution & Transmission		3,927			1,873			2,054			109.7	%
Eliminations		(960	)		(657	)		(303	)		46.1	%

Total Revenue	$	20,041		$	14,658		$	5,383			36.7	%

Operating Profit:
Rig Technology	$	2,335		$	2,053		$	282			13.7	%
Petroleum Services & Supplies		1,501			1,072			429			40.0	%
Distribution & Transmission		185			135			50			37.0	%
Unallocated expenses and eliminations		(464	)		(323	)		(141	)		43.7	%

Total Operating Profit	$	3,557		$	2,937		$	620			21.1	%

Operating Profit %:
Rig Technology		23.1	%		26.4	%
Petroleum Services & Supplies		21.5	%		19.0	%
Distribution & Transmission		4.7	%		7.2	%

Total Operating Profit %		17.7	%		20.0	%

Rig Technology

Revenue from Rig Technology for the year ended December 31, 2012 was $10,107 million, an increase of $2,319 million (29.8%) compared to the year ended December 31, 2011. Deepwater offshore drilling worldwide and active shale plays in North America were the primary driving forces for the increase in revenue for this segment during the first half of 2012, resulting in increased rig construction as well as demand for well intervention and stimulation equipment and aftermarket spare parts. In addition, the acquisitions of NKT and Enerflow, occurring towards the beginning of the second quarter of 2012, contributed to the increase in revenue for Rig Technology. As the segment moved into the second half of 2012, it saw continued strong deepwater offshore demand as well as a strong demand in international markets with strong revenue growth in coiled tubing equipment, wireline equipment and land rigs sold internationally. North American markets, however, saw a decrease in demand for land drilling as both gas and oil plays have decreased production. This is evidenced by a decrease in rig count in the U.S. during 2012 and has resulted in lower sales of land rigs and jackups in the U.S. as the segment moved into the second half of 2012. The average rig count in the U.S. during the fourth quarter of 2012 decreased to 1,809 rigs (9%) from the first quarter 2012 average of 1,991 rigs. Rig Technology revenues could decrease as it enters 2013 due to the decrease in demand for pressure pumping equipment.

Operating profit from Rig Technology was $2,335 million (which included $45 million in other costs related to acquisitions) for the year ended December 31, 2012, an increase of $282 million (13.7%) compared to 2011. Operating profit percentage decreased to 23.1%, from 26.4% in 2011. Partially contributing to the decrease in operating profit percentage was a decrease in the average margin of revenue out of backlog as contracts signed during 2009 and 2010 contain less favorable margins compared to contracts won during the order ramp-up from 2005 to 2008. Also contributing to the decrease in operating profit percentage were integration costs related to the NKT and Enerflow acquisitions made during the second quarter of 2012 as well as considerable start-up costs associated with construction of an NOV Flexibles plant in Brazil, and the opening of a new Technical College in Korea. Coiled tubing equipment, wireline equipment and land rigs sold later in the year were primarily driven by large international projects that were secured at lower than average margins. Finally, increased FPSO related revenues, with operating profit lower than other parts of this segment, were dilutive to overall Rig Technology operating profit margins. As the segment enters 2013, we anticipate continued pricing pressures in North America coupled with a continuing shift in product mix that includes a growing percentage of Brazil and FPSO related revenues.

The Rig Technology segment monitors its capital equipment backlog to plan its business. New orders are added to backlog only when the Company receives a firm written order for major drilling rig components or a signed contract related to a construction project. The capital equipment backlog was $11.9 billion at December 31, 2012, an increase of $1.7 billion (17%) from backlog of $10.2 billion at December 31, 2011.

Petroleum Services & Supplies

Revenue from Petroleum Services & Supplies for the year ended December 31, 2012 was $6,967 million, an increase of $1,313 million (23.2%) compared to the year ended December 31, 2011. Strong shale plays in North America lead to an increase in revenue for the Petroleum Services & Supplies segment during the first half of 2012 compared to 2011. Acquisitions made during the year such as Fiberspar Corporation and Zap-Lok Pipeline Systems, Inc. contributed to the increase in revenue for 2012 compared to 2011. Full period results of Ameron as well as other strategic acquisitions made during 2011 in the U.S., the U.K., the Netherlands, Singapore, Malaysia and Brazil also contributed to the increase in revenue for this segment in 2012 compared to 2011. Moving into the second half of 2012, while stronger than in 2011, compared to the first half of 2012, the segment saw a decrease in North American activity as evidenced in the decrease in U.S. rig count throughout the year. Petroleum Services & Supplies revenues could decrease as it enters 2013 as many of its businesses enter 2013 with diminished backlog and U.S. based drilling contractors as well as service firms have been hesitant to release new orders.

Operating profit from Petroleum Services & Supplies was $1,501 million (which included $18 million in other costs related to acquisitions) for the year ended December 31, 2012 compared to $1,072 million for 2011, an increase of $429 million (40.0%). Operating profit percentage increased to 21.5% up from 19.0% in 2011. This increase is primarily due to increased volume, favorable pricing and cost reductions within most business units within the segment during the first half of 2012 compared to the same period in 2011. However, as the segment moved into the second half of the year, due to the decrease in North American market activity, it began to experience pricing pressures across a number of products in the North American land market, coupled with a shift in product mix, which led to lower margins. Most notably, the continued reduction of North American land activity led to pricing pressures and an overall reduction in volume for the segments downhole tools, fiberglass pipe, coiled dubing, and fluid end expendables products. While declines in various product lines were offset partially with growth in the drill pipe, XL Systems and Tuboscope products, overall margins still continued to decline towards the end of the year. As the segment enters 2013, we anticipate continued pricing pressures in North America coupled with a possible decrease in volume.

Distribution & Transmission

Revenue from Distribution & Transmission was $3,927 million for the year ended December 31, 2012, an increase of $2,054 million (109.7%) compared to the year ended December 31, 2011. This increase was primarily attributable to the acquisitions of Wilson during the second quarter of 2012 and CE Franklin during the third quarter of 2012. Distribution & Transmission revenues are expected to increase as it enters 2013 as it realizes full period results for its 2012 acquisitions.

Operating profit from Distribution & Transmission was $185 million (which included $68 million in other costs related to acquisitions) for the year ended December 31, 2012, an increase of $50 million (37.0%) compared to $135 million for the year ended December 31, 2011. Operating profit percentage decreased to 4.7%, from 7.2% in 2011. Increased volume, greater cost efficiencies and continued favorable pricing which related to strong demand for this segment contributed to an increase in operating profit percentages for this segment during the first half of 2012. However, the impact of businesses acquired during 2012 combined with lower market activity resulted in margins dropping slightly for the year. In addition, other costs incurred for the expense recognition associated with acquired current assets stepped up to fair value during purchase accounting also contributed to the decrease in operating profit percentage. The majority of the stepped up value related to inventory and was fully recognized by December 31, 2012. As the segment enters 2013, we anticipate continued pricing pressures in North America coupled with a possible decrease in volume.

Unallocated expenses and eliminations

Unallocated expenses and eliminations in operating profit were $464 million for the year ended December 31, 2012 compared to $323 million for the year ended December 31, 2011. This increase was primarily due to the increased activity along all segments which in turn resulted in higher intersegment eliminations.

Equity Income in Unconsolidated Affiliates

Equity income in unconsolidated affiliates was $58 million for the year ended December 31, 2012 compared to $46 million for the year ended December 31, 2011. This increase was primarily due to increased equity earnings from the Company’s 50.01% investment in Voest-Alpine Tubulars (“VAT”) located in Kindberg, Austria.

Other income (expense), net

Other income (expense), net were expenses of $71 million for the year ended December 31, 2012 compared to $39 million for the year ended December 31, 2011. This increase was primarily due to foreign exchange losses and increased bank charges and fees.

Provision for income taxes

The effective tax rate for the year ended December 31, 2012 was 29.2%, compared to 32.1% for 2011. Compared to the U.S. statutory rate, the effective tax rate was positively impacted in the period by the effect of lower tax rates on income earned in foreign jurisdictions, foreign dividends net of foreign tax credits, the deduction in the U.S. for manufacturing activities and foreign exchange losses for tax reporting in Norway. The effective tax rate was negatively impacted by the recognition of increased valuation allowances on certain deferred tax assets associated with excess foreign tax credits carried to future periods.

During 2012, the Company recorded certain tax benefits totaling $138 million primarily from the repatriation of certain non-U.S. earnings that increased our U.S. foreign tax credits. These credits are available to be used by the Company as foreign tax credits in the U.S. over a 10 year period. These excess foreign tax credits were recognized as deferred tax assets in the balance sheet and would be realized as a reduction of future income tax payments in the U.S. However, because of uncertainty associated with the Company’s ability to fully utilize these credits in the future, a valuation allowance of $69 million was recorded in the period. The net result of these transactions reduced income tax expense by $69 million in the period.

Years Ended December 31, 2011 and December 31, 2010

The following table summarizes the Company’s revenue and operating profit by operating segment in 2011 and 2010 (in millions):


	Years Ended December 31,						Variance
	2011			2010			$			%
Revenue:
Rig Technology	$	7,788		$	6,965		$	823			11.8	%
Petroleum Services & Supplies		5,654			4,182			1,472			35.2	%
Distribution & Transmission		1,873			1,546			327			21.2	%
Eliminations		(657	)		(537	)		(120	)		22.3	%

Total Revenue	$	14,658		$	12,156		$	2,502			20.6	%

Operating Profit:
Rig Technology	$	2,053		$	2,064		$	(11	)		(0.5	%)
Petroleum Services & Supplies		1,072			585			487			83.2	%
Distribution & Transmission		135			78			57			73.1	%
Unallocated expenses and eliminations		(323	)		(280	)		(43	)		15.4	%

Total Operating Profit	$	2,937		$	2,447		$	490			20.0	%

Operating Profit %:
Rig Technology		26.4	%		29.6	%
Petroleum Services & Supplies		19.0	%		14.0	%
Distribution & Transmission		7.2	%		5.0	%

Total Operating Profit %		20.0	%		20.1	%

Rig Technology

Rig Technology revenue for the year ended December 31, 2011 was $7,788 million, an increase of $823 million (11.8%) compared to 2010. Deepwater offshore drilling world-wide and active shale plays in the U.S. continue to be the driving force for the increase in revenue for this segment resulting in both increased rig construction as well as demand for aftermarket spare parts and services. In addition, strategic acquisitions in the U.S. and Singapore contributed to the increase in revenue for this segment.

Operating profit from Rig Technology was $2,053 million for the year ended December 31, 2011, a decrease of $11 million (0.5%) over the same period of 2010. Operating profit percentage decreased to 26.4%, from 29.6% in 2010 primarily due to decrease in the average margin of revenue out of backlog as contracts signed during 2009 and 2010 contain less favorable margins compared to contracts won during the order ramp-up from 2005 to 2008. This decrease in margins was partially offset by the increase in demand for aftermarket spare parts and services.

The Rig Technology segment monitors its capital equipment backlog to plan its business. New orders are added to backlog only when the Company receives a firm written order for major drilling rig components or a signed contract related to a construction project. The capital equipment backlog was $10.2 billion at December 31, 2011, an increase of $5.2 billion (104.0%) from backlog of $5.0 billion at December 31, 2010. The $5.2 billion increase in backlog included the largest order in the Company’s history in the amount of approximately $1.5 billion won during the third quarter of 2011.

Petroleum Services & Supplies

Revenue from Petroleum Services & Supplies was $5,654 million for 2011 compared to $4,182 million for 2010, an increase of $1,472 million (35.2%). The increase was primarily attributable to shale plays leading to a strong North American market with a 21.7% increase in U.S. rig activity and a 20.5% increase in Canada rig activity compared to 2010. North American shale plays continue to be a driving force in the increase in revenues across most business units within this segment. In addition, strategic acquisitions in the U.S., the U.K., the Netherlands, Singapore, Malaysia and Brazil contributed to the increase in revenue for this segment.

Operating profit from Petroleum Services & Supplies was $1,072 million for 2011 compared to $585 million for 2010, an increase of $487 million (83.2%). Operating profit percentage increased to 19.0%, up from 14.0% in 2010. This increase is primarily due to increased volume with a strong North American demand fueled by an increase in rig count as well as continued favorable pricing within most business units within the segment. The increase was partially offset by lower levels of activity in the Middle East due to continued unrest in that region. This unrest resulted in the write-down, in the first quarter, of Libyan assets of $15 million, mostly related to accounts receivable affected by sanctions enacted during the quarter along with the write off of certain inventory and fixed assets in the country. The Company’s Rig Technology and Distribution & Transmission segments incurred $2 million of such asset write-downs during the first quarter for a total of $17 million in Libyan asset write-downs incurred by the Company.

Distribution & Transmission

Revenue from Distribution & Transmission totaled $1,873 million for 2011, an increase of $327 million (21.2%) from 2010. This increase was primarily attributable to increased rig count activity in Canada and the U.S. Internationally, the segments Mono business unit also contributed to the increase in revenues as demand for its power sections and artificial lift products increased in 2011 compared to 2010. In addition, strategic acquisitions in the U.S. and the U.K. contributed to the increase in revenue for this segment.

Operating profit from Distribution & Transmission, increased in 2011 to $135 million compared to $78 million in 2010. Operating profit percentage increased to 7.2% in 2011 from 5.0% in 2010 primarily due to greater cost efficiencies and better pricing related to strong demand fueled by an increase in Canada and U.S. rig count activity. This increase was partially offset by rig moves towards liquid shale plays, drill site construction delays and weather issues towards the end of the year in certain markets in which this segment participates.

Unallocated expenses and eliminations

Unallocated expenses and eliminations in operating profit were $323 million for the year ended December 31, 2011 compared to $280 million for 2010. This increase is primarily due to the increased activity along all segments which in turn resulted in higher intersegment eliminations and higher incentive compensation.

Equity Income in Unconsolidated Affiliates

Equity income in unconsolidated affiliates was $46 million for 2011 compared to $36 million for 2010, a $10 million increase which was primarily related to increased equity earnings from the Company’s 50.01% investment in Voest-Alpine Tubulars (“VAT”) located in Kindberg, Austria.

Other income (expense), net

Other income (expense), net was expense of $39 million in 2011 compared to expense of $49 million in 2010. The decrease in expense was primarily due to lower foreign exchange losses in 2011 compared to 2010. The Venezuelan government officially devalued the Venezuelan bolivar against the U.S. dollar in 2010. The Company converted its Venezuela ledgers to U.S. dollar functional currency and devalued monetary assets resulting in a $27 million foreign exchange loss during 2010. See Item 7A. “Quantitative and Qualitative Disclosures About Market Risk” Foreign Currency Exchange Rates. Lower exchange losses were partially offset by increased bank charges. The increase in bank charges is primarily due to an increase in our standby letters of credit coupled with increased bank activity through growth both internally and through.

Provision for income taxes

The effective tax rate for the year ended December 31, 2011 was 32.1%, compared to 30.8% for 2010. Compared to the U.S. statutory rate, the effective tax rate was positively impacted in the period by the effect of lower tax rates on income in foreign jurisdictions, an increase in the benefit of the manufacturing deduction as a result of increasing income in the U.S., plus the effect of tax rate reductions on timing differences in foreign jurisdictions. This was partially offset by additional prior period taxes on foreign dividends. The impact of these prior period discrete items is not material to any individual prior period.

Non-GAAP Financial Measures and Reconciliations

In an effort to provide investors with additional information regarding our results as determined by GAAP, we disclose various non-GAAP financial measures in our quarterly earnings press releases and other public disclosures. The primary non-GAAP financial measures we focus on are: (i) operating profit excluding other costs, (ii) operating profit percentage excluding other costs, and (iii) diluted earnings per share excluding other costs. Each of these financial measures excludes the impact of certain other costs and therefore has not been calculated in accordance with GAAP. A reconciliation of each of these non-GAAP financial measures to its most comparable GAAP financial measure is included below.

We use these non-GAAP financial measures internally to evaluate and manage the Company’s operations because we believe it provides useful supplemental information regarding the Company’s on-going economic performance. We have chosen to provide this information to investors to enable them to perform more meaningful comparisons of operating results and as a means to emphasize the results of on-going operations.

The following tables set forth the reconciliations of these non-GAAP financial measures to their most comparable GAAP financial measures (in millions, except per share data):


	Three Months Ended									Years Ended December 31,
	December 31,						September 30, 2012			Years Ended December 31,
	2012			2011			September 30, 2012			2012			2011			2010
Reconciliation of operating profit:
GAAP operating profit	$	903		$	848		$	898		$	3,557		$	2,937		$	2,447
Other costs (1):
Rig Technology		12			6			12			45			17			8
Petroleum Services & Supplies		15			6			—			18			23			9
Distribution & Transmission		24			—			36			68			1			1

Operating profit excluding other costs	$	954		$	860		$	946		$	3,688		$	2,978		$	2,465


	Three Months Ended									Years Ended December 31,
	December 31,						September 30, 2012			Years Ended December 31,
	2012			2011			September 30, 2012			2012			2011			2010
Reconciliation of operating profit %:
GAAP operating profit %		15.9	%		19.9	%		16.9	%		17.7	%		20.0	%		20.1	%
Other costs %		0.9	%		0.3	%		0.9	%		0.7	%		0.3	%		0.2	%

Operating profit % excluding other costs		16.8	%		20.2	%		17.8	%		18.4	%		20.3	%		20.3	%


	Three Months Ended									Years Ended December 31,
	December 31,						September 30, 2012			Years Ended December 31,
	2012			2011			September 30, 2012			2012			2011			2010
Reconciliation of diluted earnings per share:
GAAP earnings per share	$	1.56		$	1.35		$	1.43		$	5.83		$	4.70		$	3.98
Other costs (1)		0.09			0.02			0.09			0.24			0.07			0.11
Tax benefits (2)		(0.16	)		—			—			(0.16	)		—			—

Earnings per share excluding other costs (benefits)	$	1.49		$	1.37		$	1.52		$	5.91		$	4.77		$	4.09

(1)	Other costs primarily include items such as the expense recognition of backlog and inventory that was stepped up to fair value during purchase accounting, items which are included in operating profit.

For the three months ended December 31, 2012 and 2011 and September 30, 2012, other costs included in operating profit were $51 million, $12 million and $48 million, respectively. Certain other costs are included in other income (expense), net as well as interest and financial costs and were nil, nil and $9 million for the three months ended December 31, 2012 and 2011 and September 30, 2012, respectively.

For the years ended December 31, 2012, 2011 and 2010, other costs included in operating profit were $131 million, $41 million and $18 million, respectively. Certain other costs are included in other income (expense), net as well as interest and financial costs and were $12 million, nil and $27 million for the years ended December 31, 2012, 2011 and 2010, respectively.

(2)	Includes a net $69 million tax benefit related to certain U.S. foreign tax credits arising in the three months ended December 31, 2012. These credits resulted from a strategic reorganization of certain foreign operations to more fully integrate recently acquired businesses.

Liquidity and Capital Resources

The Company assesses liquidity in terms of its ability to generate cash to fund operating, investing and financing activities. The Company remains in a strong financial position, with resources available to reinvest in existing businesses, strategic acquisitions and capital expenditures to meet short- and long-term objectives. The Company believes that cash on hand, cash generated from expected results of operations and amounts available under its revolving credit facility will be sufficient to fund operations, anticipated working capital needs and other cash requirements such as capital expenditures, debt and interest payments and dividend payments for the foreseeable future.

At December 31, 2012, the Company had cash and cash equivalents of $3,319 million, and total debt of $3,149 million. At December 31, 2011, cash and cash equivalents were $3,535 million and total debt was $510 million. The $2,855 million reduction in the net cash (cash less debt) balance in 2012 was due primarily to $2,880 million in cash paid for 2012 acquisitions. A significant portion of the consolidated cash balances are maintained in accounts in various foreign subsidiaries and, if such amounts were transferred among countries or repatriated to the U.S., such amounts may be subject to additional tax obligations. Of the $3,319 million of cash and cash equivalents at December 31, 2012, approximately $1,994 million is held outside the U.S. Of this amount, approximately $1,785 million is considered permanently reinvested and is available to fund operations and other growth of foreign subsidiaries including, but not limited to, capital expenditures, acquisitions and working capital needs. Of the $3,535 million of cash and cash equivalents at December 31, 2011, approximately $3,300 million was held outside the U.S. and approximately $1,900 million was considered permanently reinvested. If opportunities to invest in the U.S. are greater than available cash balances, rather than repatriating this cash, the Company may choose to borrow against its revolving credit facility.

New Revolving Credit Facility

On September 28, 2012, the Company entered into a new five-year unsecured revolving credit facility with a syndicate of financial institutions. This new credit facility replaced early the Company’s previous $2.0 billion revolving credit facility and provides for aggregate multicurrency borrowings up to $3.5 billion. In addition, the Company has the option to increase aggregate borrowing availability by an additional $1.0 billion, subject to syndication approval. Interest under the new credit facility is based upon LIBOR, NIBOR or EURIBOR plus 0.875% subject to a ratings-based grid, or the prime rate. The terms of the new credit facility provide for a financial covenant regarding maximum debt to capitalization. At December 31, 2012, the Company was in compliance with the financial covenant under the new credit facility.

Redemption of unsecured Senior Notes Due 2012

On November 15, 2012, the Company repaid $200 million of its 5.65% unsecured Senior Notes and $150 million of its 5.50% unsecured Senior Notes. Both series of unsecured Senior Notes were repaid using available cash balances.

Issuance of unsecured Senior Notes Due 2017, 2022 and 2042

On November 20, 2012, the Company issued the following; $500 million of 1.35% unsecured Senior Notes due 2017, $1.4 billion of 2.60% unsecured Senior Notes due 2022 and $1.1 billion of 3.95% unsecured Senior Notes due 2042. The net proceeds were $2,969 million, after deducting $22 million in underwriting fees and a $9 million discount. Interest on each series of notes is due on June 1 and December 1 of each year, beginning on June 1, 2013. The Company may redeem some or all of the Senior Notes at any time at the applicable redemption, plus accrued interest, if any, to the redemption date. At December 31, 2012, the Company was in compliance with the covenants under the indenture governing the Senior Notes.

The Company’s outstanding debt at December 31, 2012 was $3,149 million and consisted of $151 million in 6.125% Senior Notes, $500 million in 1.35% Senior Notes, $1,395 million in 2.60% Senior Notes and $1,096 million in 3.95% Senior Notes, and other debt of $7 million.

At December 31, 2012, there were no borrowings under the new $3.5 billion credit facility, however, there were $938 million in outstanding letters of credit issued, resulting in $2,562 million of funds available.

The Company also had $2,254 million of additional outstanding letters of credit at December 31, 2012, primarily in Norway, that are under various bilateral committed letter of credit facilities. Other letters of credit are issued as bid bonds and performance bonds.

The following table summarizes our net cash flows provided by operating activities, net cash used in investing activities and net cash provided by (used in) financing activities for the periods presented (in millions):


	Years Ended December 31,
	2012			2011			2010
Net cash provided by operating activities	$	620		$	2,143		$	1,542
Net cash used in investing activities		(3,428	)		(1,458	)		(743	)
Net cash provided by (used in) financing activities		2,583			(464	)		(102	)

Operating Activities

Net cash provided by operating activities was $620 million in 2012 compared to net cash provided by operating activities of $2,143 million in 2011. Before changes in operating assets and liabilities, net of acquisitions, cash was provided by operations primarily through net income of $2,483 million plus non-cash charges of $628 million and $61 million in a dividend received from Voest-Alpine Tubulars, an unconsolidated affiliate, less $58 million in equity income.

Net changes in operating assets and liabilities, net of acquisitions, used $2,536 million in 2012 compared to $164 million used in 2011. Due to an increase in market activity during 2012 compared to 2011, revenue and backlog increased which is reflected in increased accounts receivable as well as a buildup in inventory. Increased market activity during 2012 also resulted in higher taxes paid, higher accounts payable and an increase in both costs in excess of billings and billings in excess of costs with costs incurred on major rig projects outpacing customer progress and milestone invoicing.

Investing Activities

Net cash used in investing activities was $3,428 million in 2012 compared to net cash used in investing activities of $1,458 million in 2011. Net cash used in investing activities continued to primarily be the result of acquisition activity and capital expenditures both of which increased in 2012 compared to 2011. The Company used $2,880 million for the purpose of strategic acquisitions during 2012 compared to $1,038 million in 2011. In addition, due to the continued growth in the Company worldwide, both organically and through acquisition, the Company used $583 million during 2012 for capital expenditures compared to $483 million in 2011. During 2012, the Company used a combination of its cash on hand, borrowings from its revolving credit facility and the issuance of Senior Notes to fund its acquisitions and capital expenditures.

Financing Activities

Net cash provided by financing activities was $2,583 million in 2012 compared to net cash used in financing activities of $464 million in 2011. The change related to a shift from the Company primarily repaying debt during 2011 to the Company refinancing its revolving credit facility, expanding it to $3.5 billion, and issuing three truanches of Senior Notes for a total of $3.0 billion in Senior Notes during 2012. Funds received as a result of borrowing in 2012 were used to finance working capital and acquisitions and to make tax payments. Proceeds from stock options exercised increased to $113 million during the year ended December 31, 2012 compared to $96 million for the year ended December 31, 2011. The Company again increased its dividend to $209 million during the year ended December 31, 2012 compared to $191 million for the year ended December 31, 2011.

The effect of the change in exchange rates on cash flows was a positive $9 million and a negative $19 million for the years ended December 31, 2012 and 2011, respectively.

We believe that cash on hand, cash generated from operations and amounts available under our credit facilities and from other sources of debt will be sufficient to fund operations, working capital needs, capital expenditure requirements, dividends and financing obligations.

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. We continue to expect to fund future cash acquisitions 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.

A summary of the Company’s outstanding contractual obligations at December 31, 2012 is as follows (in millions):


			Payment Due by Period
	Total		Less than 1 Year		1-3 Years		4-5 Years		After 5 Years
Contractual Obligations:
Total debt	$	3,149	$	1	$	154	$	500	$	2,494
Operating leases		1,119		220		322		202		375

Total Contractual Obligations	$	4,268	$	221	$	476	$	702	$	2,869

Commercial Commitments:
Standby letters of credit	$	3,192	$	1,715	$	960	$	411	$	106

As of December 31, 2012, the Company had $128 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 to the Consolidated Financial Statements included in this Report.

Critical Accounting Policies and 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; service and product warranties 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 segment. These long-term construction contracts include the following characteristics:

•

the contracts include custom designs for customer specific applications;

•

the structural design is unique and requires significant engineering efforts; and

•

construction projects often have progress payments.

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, 2011 and 2010, adjustments (representing the differences between the estimated and actual results) to all outstanding contracts resulted in net increases to gross profit margins of 0.78% ($75 million on $9.6 billion of outstanding contracts) and 2.0% ($185 million on $9.3 billion of outstanding contracts) for the years ended December 31, 2012 and 2011, respectively. While the Company believes that its estimates on outstanding contracts at 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 $8.4 billion at December 31, 2012.

Allowance for Doubtful Accounts

The determination of the collectability 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 basis taking into account current market conditions and trends. 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. 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, 2012 and 2011, allowance for bad debts totaled $120 million and $107 million, or 2.7% and 3.1% 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 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, 2012 and 2011, inventory reserves totaled $338 million and $281 million, or 5.4% and 6.5% 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 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: sustained declines in worldwide rig counts below current analysts’ forecasts, collapse of spot and futures prices for oil and gas, significant 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.

Goodwill and Other Indefinite-Lived Intangible Assets

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. Fair value of the reporting units is determined in accordance with ASC Topic 820 “Fair Value Measurements and Disclosures” using significant unobservable inputs, or level 3 in the fair value hierarchy. These inputs are 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 bear 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 cost of capital. The starting point for each of the reporting unit’s cash flow from operations is the detailed annual plan or updated forecast. The detailed planning and forecasting 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 replace 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.

The annual impairment test is performed during the fourth quarter of each year. The valuation techniques used in the annual test were consistent with those used during previous testing. The inputs used in the annual test were updated for current market conditions and forecasts. Based on its analysis, the Company did not report any impairment of goodwill and other indefinite-lived intangible assets for the years ended December 31, 2012, 2011 and 2010.

Purchase Price Allocation of Acquisitions

The Company allocates the purchase price of an acquired business to its identifiable assets and liabilities based on estimated fair values. The excess of the purchase price over the amount allocated to the assets and liabilities, if any, is recorded as goodwill. The Company uses all available information to estimate fair values including quoted market prices, the carrying value of acquired assets, and widely accepted valuation techniques such as discounted cash flows (all level 3 unobservable inputs). The Company engages third-party appraisal firms to assist in fair value determination of inventories, identifiable intangible assets, and any other significant assets or liabilities when appropriate. The judgments made in determining the estimated fair value assigned to each class of assets acquired and liabilities assumed, as well as asset lives, could materially impact the Company’s results of operations.

Service and Product Warranties

The Company provides service and warranty policies on certain of its products. The Company accrues liabilities under service and warranty policies based upon specific claims and a review of historical warranty and service claim experience in accordance with ASC Topic 450 “Contingencies” (“ASC Topic 450”). Adjustments are made to accruals as claim data and historical experience change. In addition, the Company incurs discretionary costs to service its products in connection with product performance issues and accrues for them when they are encountered. The Company monitors the actual cost of performing these discretionary services and adjusts the accrual based on the most current information available. At December 31, 2012 and 2011, service and product warranties totaled $194 million and $211 million, respectively.

Income Taxes

The Company is a U.S. registered company and is subject to income taxes in the U.S. and other jurisdictions in which it operates. 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 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 operating expenses that may not be deductible in foreign jurisdictions. 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 ASC Topic 740 “Income Taxes” (“ASC Topic 740”). 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 $4,620 million and $3,789 million at December 31, 2012 and 2011, respectively. The Company makes a determination each period whether to permanently reinvest these earnings. If, as a result of these reassessments, the Company distributes these earnings in the future, additional tax liabilities would result, offset by any available foreign tax credits.

Recently Issued Accounting Standards

In July 2012, the Financial Accounting Standards Board issued Accounting Standard Update No. 2012-02 “Intangibles—Goodwill and Other (Topic 350)” that amends the accounting guidance on testing indefinite-lived intangible assets for impairment. The amendments in this accounting standard update are intended to reduce complexity and costs by allowing an entity the option to make a qualitative evaluation about the likelihood that an indefinite-lived intangible asset is impaired to determine whether it should perform a quantitative impairment test. The amendments also enhance the consistency of impairment testing guidance among long-lived asset categories by permitting an entity to assess qualitative factors to determine whether it is necessary to calculate the asset’s fair value when testing an indefinite-lived intangible asset for impairment, which is equivalent to the impairment testing requirements for other long-lived assets. The amendments in this accounting standard update are effective for interim and annual impairment tests performed for fiscal years beginning after September 15, 2012. The Company tests its indefinite-lived intangible assets for impairment annually in the fourth quarter or more frequently when events or changes in circumstances indicate that impairment may have occurred.

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 impact income. During the years ended December 31, 2012, 2011 and 2010, the Company reported foreign currency losses of $21 million, $10 million and $30 million, respectively. Gains and losses are primarily due to exchange rate fluctuations related to monetary asset balances denominated in currencies other than the functional currency and adjustments to our hedged positions as a result of changes in foreign currency exchange rates. Strengthening of currencies against the U.S. dollar may create losses in future periods to the extent we maintain net assets and liabilities not denominated in the functional currency of the countries using the local currency as their functional currency.

Some of our 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 give 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.

The following table details the Company’s foreign currency exchange risk grouped by functional currency and their expected maturity periods as of December 31, 2012 (in millions except for rates):


	As of December 31, 2012								December 31,
Functional Currency	2013		2014		2015		Total		2011
CAD Buy USD/Sell CAD:
Notional amount to buy (in Canadian dollars)		511		—		—		511		274
Average USD to CAD contract rate		0.9895		—		—		0.9895		1.0315
Fair Value at December 31, 2012 in U.S. dollars		5		—		—		5		(3	)
Sell USD/Buy CAD:
Notional amount to sell (in Canadian dollars)		241		14		—		255		239
Average USD to CAD contract rate		1.0238		1.0098		—		1.0230		1.0196
Fair Value at December 31, 2012 in U.S. dollars		6		—		—		6		(1	)
EUR Buy USD/Sell EUR:
Notional amount to buy (in euros)		7		—		—		7		10
Average USD to EUR contract rate		0.7711		—		—		0.7711		1.4035
Fair Value at December 31, 2012 in U.S. dollars		—		—		—		—		1
Sell USD/Buy EUR:
Notional amount to buy (in euros)		180		25		—		205		120
Average USD to EUR contract rate		0.7693		0.7645		—		0.7687		1.3846
Fair Value at December 31, 2012 in U.S. dollars		4		—		—		4		(11	)
KRW Buy USD/Sell KRW:
Notional amount to buy (in South Korean won)		261		—		—		261		385
Average USD to KRW contract rate		919		—		—		919		920
Fair Value at December 31, 2012 in U.S. dollars		—		—		—		—		—
Sell USD/Buy KRW:
Notional amount to buy (in South Korean won)		639		58		—		697		53,825
Average USD to KRW contract rate		1,020		941		—		1,013		1,152
Fair Value at December 31, 2012 in U.S. dollars		—		—		—		—		—


	As of December 31, 2012											December 31,
Functional Currency	2013			2014			2015		Total			2011
GBP Buy USD/Sell GBP:
Notional amount to buy (in British Pounds Sterling)		47			—			—		47			45
Average USD to GBP contract rate		0.6149			—			—		0.6149			1.5499
Fair Value at December 31, 2012 in U.S. dollars		—			—			—		—			—
Sell USD/Buy GBP:
Notional amount to buy (in British Pounds Sterling)		37			—			—		37			44
Average USD to GBP contract rate		0.6347			—			—		0.6347			1.5818
Fair Value at December 31, 2012 in U.S. dollars		2			—			—		2			(2	)
USD Buy DKK/Sell USD:
Notional amount to buy (in U.S. dollars)		38			4			—		42			27
Average DKK to USD contract rate		0.1741			0.1761			—		0.1743			5.4213
Fair Value at December 31, 2012 in U.S. dollars		—			—			—		—			(1	)
Buy EUR/Sell USD:
Notional amount to buy (in U.S. dollars)		608			56			—		664			710
Average EUR to USD contract rate		1.3111			1.2921			—		1.3095			1.3783
Fair Value at December 31, 2012 in U.S. dollars		6			2			—		8			(40	)
Buy GBP/Sell USD:
Notional amount to buy (in U.S. dollars)		18			—			—		18			15
Average GBP to USD contract rate		1.6044			—			—		1.6044			1.5737
Fair Value at December 31, 2012 in U.S. dollars		—			—			—		—			—
Buy NOK/Sell USD:
Notional amount to buy (in U.S. dollars)		772			293			—		1,065			1,336
Average NOK to USD contract rate		0.1684			0.1637			—		0.1671			5.9427
Fair Value at December 31, 2012 in U.S. dollars		44			22			—		66			(22	)
Buy SGD/Sell USD:
Notional amount to buy (in U.S. dollars)		28			3			—		31			10
Average SGD to USD contract rate		0.8139			0.7920			—		0.8115			1.3022
Fair Value at December 31, 2012 in U.S. dollars		—			—			—		—			—
Sell DKK/Buy USD:
Notional amount to buy (in U.S. dollars)		12			—			—		12			3
Average DKK to USD contract rate		0.1749			—			—		0.1749			5.5036
Fair Value at December 31, 2012 in U.S. dollars		—			—			—		—			—
Sell EUR/Buy USD:
Notional amount to sell (in U.S. dollars)		141			—			—		141			137
Average EUR to USD contract rate		1.3109			—			—		1.3109			1.3517
Fair Value at December 31, 2012 in U.S. dollars		(1	)		—			—		(1	)		5
Sell NOK/Buy USD:
Notional amount to sell (in U.S. dollars)		244			30			—		274			173
Average NOK to USD contract rate		0.1722			0.1727			—		0.1723			5.8173
Fair Value at December 31, 2012 in U.S. dollars		(9	)		(1	)		—		(10	)		6
Sell SGD/Buy USD:
Notional amount to sell (in U.S. dollars)		—			—			—		—			2
Average SGD to USD contract rate		—			—			—		—			0.7674
Fair Value at December 31, 2012 in U.S. dollars		—			—			—		—			—
Sell RUB/Buy USD:
Notional amount to sell (in U.S. dollars)		47			—			—		47			24
Average RUB to USD contract rate		0.0320			—			—		0.0320			32.7613
Fair Value at December 31, 2012 in U.S. dollars		—			—			—		—			—
DKK Sell DKK/Buy USD:
Notional amount to buy (in U.S. dollars)		111			—			—		111			96
Average DKK to USD contract rate		5.61			—			—		5.6126			5.6717
Fair Value at December 31, 2012 in U.S. dollars		—			—			—		—			—
Other Currencies
Fair Value at December 31, 2012 in U.S. dollars		6			—			—		6			(2	)

Total Fair Value at December 31, 2012 in U.S. dollars		63			23			—		86			(70	)

The Company had other financial market risk sensitive instruments denominated in foreign currencies for transactional exposures totaling $567 million and translation exposures totaling $397 million as of December 31, 2012, excluding trade receivables and payables, which approximate fair value. These market risk sensitive instruments consisted of cash balances and overdraft facilities. The Company estimates that a hypothetical 10% movement of all applicable foreign currency exchange rates on the transactional exposures financial market risk sensitive instruments could affect net income by $37 million and the translational exposures financial market risk sensitive instruments could affect the future fair value by $40 million.

The counterparties to forward contracts are major financial institutions. The credit ratings and concentration of risk of these financial institutions are monitored on a continuing basis. In the event that the counterparties fail to meet the terms of a foreign currency contract, our exposure is limited to the foreign currency rate differential.

During the first quarter of 2010, the Venezuelan government officially devalued the Venezuelan bolivar against the U.S. dollar. As a result the Company converted its Venezuela ledgers to U.S. dollar functional currency, devalued monetary assets resulting in a $27 million charge, and wrote-down certain accounts receivable in view of deteriorating business conditions in Venezuela, resulting in an additional $11 million charge. During the first quarter of 2013, the Venezuelan government again officially devalued the Venezuelan bolivar against the U.S. dollar. As a result, the Company expects to incur approximately $12 million in devaluation charges in the first quarter of 2013. The Company’s net investment in Venezuela was $34 million at December 31, 2012.

Interest Rate Risk

At December 31, 2012, our long term borrowings consisted of $151 million in 6.125% Senior Notes, $500 million in 1.35% Senior Notes, $1,400 million in 2.60% Senior Notes and $1,100 million in 3.95% Senior Notes. We occasionally have borrowings under our credit facility, and a portion of these borrowings could be denominated in multiple currencies which could expose us to market risk with exchange rate movements. These instruments carry interest at a pre-agreed upon percentage point spread from either LIBOR, NIBOR or EURIBOR, or at the prime interest rate. Under our credit facility, we may, at our option, fix the interest rate for certain borrowings based on a spread over LIBOR, NIBOR or EURIBOR for 30 days to six months.

ITEM 8.

FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Attached hereto and a part of this report are financial statements and supplementary data listed in Item 15. “Exhibits and Financial Statement Schedules”.

ITEM 9.

CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE.

None.

ITEM 9A.

CONTROLS AND PROCEDURES

(i) Evaluation of disclosure controls and procedures

As required by SEC Rule 13a-15(b), we have evaluated, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this report. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by the Company in reports that it files under the Exchange Act is accumulated and communicated to the Company’s management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. Our principal executive officer and principal financial officer have concluded that our current disclosure controls and procedures were effective as of December 31, 2012 at the reasonable assurance level.

Pursuant to section 302 of the Sarbanes-Oxley Act of 2002, our Chief Executive Officer and Chief Financial Officer have provided certain certifications to the Securities and Exchange Commission. These certifications are included herein as Exhibits 31.1 and 31.2.

(ii) Internal Control Over Financial Reporting

(a) Management’s annual report on internal control over financial reporting.

The Company’s management report on internal control over financial reporting is set forth in this annual report on Page 62 and is incorporated herein by reference.

(b) Changes in internal control

There were no changes in the Company’s internal control over financial reporting that occurred during the Company’s last fiscal quarter covered by this report that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

ITEM 9B.

OTHER INFORMATION

None.

PART III

ITEM 10.

DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Incorporated by reference to the definitive Proxy Statement for the 2013 Annual Meeting of Stockholders.

ITEM 11.

EXECUTIVE COMPENSATION

Incorporated by reference to the definitive Proxy Statement for the 2013 Annual Meeting of Stockholders.

ITEM 12.

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

Incorporated by reference to the definitive Proxy Statement for the 2013 Annual Meeting of Stockholders.

Securities Authorized for Issuance Under Equity Compensation Plans.

The following table sets forth information as of our fiscal year ended December 31, 2012, with respect to compensation plans under which our common stock may be issued:


Plan Category	Number of securities to be issued upon exercise of warrants and rights (a)		Weighted-average exercise price of outstanding rights (b)		Number of securities remaining available for equity compensation plans (excluding securities reflected in column (a)) (c) (1)
Equity compensation plans approved by security holders		9,473,482	$	58.69		3,591,119
Equity compensation plans not approved by security holders		—		—		—

Total		9,473,482	$	58.69		3,591,119

(1)	Shares could be issued through equity instruments other than stock options, warrants or rights; however, none are anticipated during 2013.

ITEM 13.

CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

Incorporated by reference to the definitive Proxy Statement for the 2013 Annual Meeting of Stockholders.

ITEM 14.

PRINCIPAL ACCOUNTANT FEES AND SERVICES

Incorporated by reference to the definitive Proxy Statement for the 2013 Annual Meeting of Stockholders.

PART IV

ITEM 15.

EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

Financial Statements and Exhibits

(1) Financial Statements

The following financial statements are presented in response to Part II, Item 8:


	Page
Consolidated Balance Sheets		65
Consolidated Statements of Income		66
Consolidated Statements of Comprehensive Income		67
Consolidated Statements of Cash Flows		68
Consolidated Statements of Stockholders’ Equity		69
Notes to Consolidated Financial Statements		70

(2) Financial Statement Schedule

Schedule II – Valuation and Qualifying Accounts		99

All schedules, other than Schedule II, are omitted because they are not applicable, not required or the information is included in the financial statements or notes thereto.

(3)

Exhibits



2.1		Amended and Restated Agreement and Plan of Merger, effective as of August 11, 2004 between National-Oilwell, Inc. and Varco International, Inc. (4)

2.2		Agreement and Plan of Merger, effective as of December 16, 2007, between National Oilwell Varco, Inc., NOV Sub, Inc., and Grant Prideco, Inc. (8)

3.1		Fifth Amended and Restated Certificate of Incorporation of National Oilwell Varco, Inc. (Exhibit 3.1) (1)

3.2		Amended and Restated By-laws of National Oilwell Varco, Inc. (Exhibit 3.1) (9)

10.1		Employment Agreement dated as of January 1, 2002 between Merrill A. Miller, Jr. and National Oilwell. (Exhibit 10.1) (2)

10.2		Employment Agreement dated as of January 1, 2002 between Dwight W. Rettig and National Oilwell, with similar agreement with Mark A. Reese. (Exhibit 10.2) (2)

10.3		Form of Amended and Restated Executive Agreement of Clay C. Williams. (Exhibit 10.12) (3)

10.4		National Oilwell Varco Long-Term Incentive Plan, as amended and restated. (5)*

10.5		Form of Employee Stock Option Agreement. (Exhibit 10.1) (6)

10.6		Form of Non-Employee Director Stock Option Agreement. (Exhibit 10.2) (6)

10.7		Form of Performance-Based Restricted Stock. (18 Month) Agreement (Exhibit 10.1) (7)

10.8		Form of Performance-Based Restricted Stock. (36 Month) Agreement (Exhibit 10.2) (7)

10.9		Credit Agreement, dated as of September 28, 2012, among National Oilwell Varco, Inc., the financial institutions signatory thereto, including Wells Fargo Bank, N.A., in their capacities as Administrative Agent, Co-Lead Arranger and Joint Book Runner. (Exhibit 10.1) (10)



10.10		First Amendment to Employment Agreement dated as of December 22, 2008 between Merrill A. Miller, Jr. and National Oilwell Varco. (Exhibit 10.1) (11)

10.11		Second Amendment to Executive Agreement, dated as of December 22, 2008 of Clay Williams and National Oilwell Varco. (Exhibit 10.2) (11)

10.12		First Amendment to Employment Agreement dated as of December 22, 2008 between Mark A. Reese and National Oilwell Varco. (Exhibit 10.3) (11)

10.13		First Amendment to Employment Agreement dated as of December 22, 2008 between Dwight W. Rettig and National Oilwell Varco. (Exhibit 10.4) (11)

10.14		Employment Agreement dated as of December 22, 2008 between Robert W. Blanchard and National Oilwell Varco. (Exhibit 10.5) (11)

10.16		Second Amendment to Employment Agreement dated as of December 31, 2009 between Merrill A. Miller, Jr. and National Oilwell Varco. (Exhibit 10.1) (12)

10.17		Third Amendment to Executive Agreement, dated as of December 31, 2009, of Clay Williams and National Oilwell Varco. (Exhibit 10.2) (12)

10.18		Second Amendment to Employment Agreement dated as of December 31, 2009 between Mark A. Reese and National Oilwell Varco. (Exhibit 10.3) (12)

10.19		Second Amendment to Employment Agreement dated as of December 31, 2009 between Dwight W. Rettig and National Oilwell Varco. (Exhibit 10.4) (12)

10.20		First Amendment to Employment Agreement dated as of December 31, 2009 between Robert W. Blanchard and National Oilwell Varco. (Exhibit 10.5) (12)

10.21		Employment Agreement dated as of January 1, 2004 between Jeremy Thigpen and National Oilwell. (Exhibit 10.1) (13)

10.22		First Amendment to Employment Agreement dated as of December 22, 2008 between Jeremy Thigpen and National Oilwell Varco. (Exhibit 10.2) (13)

10.23		Second Amendment to Employment Agreement dated as of December 31, 2009 between Jeremy Thigpen and National Oilwell Varco. (Exhibit 10.3) (13)

21.1		Subsidiaries of the Registrant.

23.1		Consent of Ernst & Young LLP.

24.1		Power of Attorney. (included on signature page hereto)

31.1		Certification pursuant to Rule 13a-14a and Rule 15d-14(a) of the Securities and Exchange Act, as amended.

31.2		Certification pursuant to Rule 13a-14a and Rule 15d-14(a) of the Securities and Exchange Act, as amended.

32.1		Certification pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.2		Certification pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

95		Mine Safety Information persuant to section 1503 of the Dodd-Frank Act.

101		The following materials from our Annual Report on Form 10-K for the period ended December 31, 2012 formatted in eXtensible Business Reporting Language (XBRL): (i) Consolidated Balance Sheets, (ii) Consolidated Statements of Income, (iii) Consolidated Statements of Cash Flows, and (iv) Notes to the Consolidated Financial Statements, tagged as block text. (14)

*	Compensatory plan or arrangement for management or others.

(1)	Filed as an Exhibit to our Quarterly Report on Form 10-Q filed on August 5, 2011.

(2)	Filed as an Exhibit to our Annual Report on Form 10-K filed on March 28, 2002.

(3)	Filed as an Exhibit to Varco International, Inc.’s Quarterly Report on Form 10-Q filed on May 6, 2004.

(4)	Filed as Annex A to our Registration Statement on Form S-4 filed on September 16, 2004.

(5)	Filed as an Exhibit to our Current Report on Form 8-K filed on February 24, 2012.

(6)	Filed as an Exhibit to our Current Report on Form 8-K filed on February 23, 2006.

(7)	Filed as an Exhibit to our Current Report on Form 8-K filed on March 27, 2007.

(8)	Filed as Annex A to our Registration Statement on Form S-4 filed on January 28, 2008.

(9)	Filed as an Exhibit to our Current Report on Form 8-K filed on August 17, 2011.

(10)	Filed as an Exhibit to our Current Report on Form 8-K filed on October 1, 2012

(11)	Filed as an Exhibit to our Current Report on Form 8-K filed on December 23, 2008.

(12)	Filed as an Exhibit to our Current Report on Form 8-K filed on January 5, 2010.

(13)	Filed as an Exhibit to our Current Report on Form 8-K filed on December 7, 2012.

(14)	As provided in Rule 406T of Regulation S-T, this information is furnished and not filed for purposes of Sections 11 and 12 of the Securities Act of 1933 and Section 18 of the Securities Exchange Act of 1934.

We hereby undertake, pursuant to Regulation S-K, Item 601(b), paragraph (4) (iii), to furnish to the U.S. Securities and Exchange Commission, upon request, all constituent instruments defining the rights of holders of our long-term debt not filed herewith.

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

Each person whose signature appears below in so signing, constitutes and appoints Merrill A. Miller, Jr. and Jeremy D. Thigpen, and each of them acting alone, his true and lawful attorney-in-fact and agent, with full power of substitution, for him and in his name, place and stead, in any and all capacities, to execute and cause to be filed with the Securities and Exchange Commission any and all amendments to this report, and in each case to file the same, with all exhibits thereto and other documents in connection therewith, and hereby ratifies and confirms all that said attorney-in-fact or his substitute or substitutes may do or cause to be done by virtue hereof.


Signature	Title	Date

/s/ MERRILL A. MILLER, JR. Merrill A. Miller, Jr.	Chairman and Chief Executive Officer	February 22, 2013

/s/ JEREMY D. THIGPEN Jeremy D. Thigpen	Senior Vice President and Chief Financial Officer	February 22, 2013

/s/ ROBERT W. BLANCHARD Robert W. Blanchard	Vice President, Corporate Controller and Chief Accounting Officer	February 22, 2013

/s/ GREG L. ARMSTRONG	Director	February 22, 2013
Greg L. Armstrong

/s/ ROBERT E. BEAUCHAMP	Director	February 22, 2013
Robert E. Beauchamp

/s/ BEN A. GUILL	Director	February 22, 2013
Ben A. Guill

/s/ DAVID D. HARRISON	Director	February 22, 2013
David D. Harrison

/s/ ROGER L. JARVIS	Director	February 22, 2013
Roger L. Jarvis

/s/ ERIC L. MATTSON	Director	February 22, 2013
Eric L. Mattson

/s/ JEFFERY A. SMISEK	Director	February 22, 2013
Jeffery A. Smisek

MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

National Oilwell Varco, Inc.’s management is responsible for establishing and maintaining adequate internal control over financial reporting. National Oilwell Varco, Inc.’s internal control system was designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.

Internal control over financial reporting cannot provide absolute assurance of achieving financial reporting objectives because of its inherent limitations. Internal control over financial reporting is a process that involves human diligence and compliance and is subject to lapses in judgment and breakdowns resulting from human failures. Internal control over financial reporting also can be circumvented by collusion or improper management override. Because of such limitations, there is a risk that material misstatements may not be prevented or detected on a timely basis by internal control over financial reporting. However, these inherent limitations are known features of the financial reporting process. Therefore, it is possible to design into the process safeguards to reduce, though not eliminate, this risk.

On May 16, 2012, the Company acquired Enerflow, on May 31, 2012, acquired Wilson, and on July 19, 2012, acquired CE Franklin. For purposes of determining the effectiveness of the Company’s internal control over financial reporting, as disclosed in this report, management has excluded these acquisitions from its evaluation. The acquired businesses represented approximately 6% of our consolidated total assets at December 31, 2012, 8% of consolidated revenues and 2% of our consolidated operating profit for the year ended December 31, 2012.

Management has used the framework set forth in the report entitled “Internal Control—Integrated Framework” published by the Committee of Sponsoring Organizations (“COSO”) of the Treadway Commission to evaluate the effectiveness of the Company’s internal control over financial reporting. Management has concluded that the Company’s internal control over financial reporting was effective as of December 31, 2012.

The effectiveness of our internal control over financial reporting as of December 31, 2012, has been audited by Ernst & Young LLP, the independent registered public accounting firm which also has audited the Company’s Consolidated Financial Statements included in this Annual Report on Form 10-K.

/s/ Merrill A. Miller, Jr.

Merrill A. Miller, Jr.

Chairman and Chief Executive Officer

/s/ Jeremy D. Thigpen

Jeremy D. Thigpen

Senior Vice President and Chief Financial Officer

Houston, Texas

February 22, 2013

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Shareholders

National Oilwell Varco, Inc.

We have audited National Oilwell Varco, Inc.’s internal control over financial reporting as of December 31, 2012, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). National Oilwell Varco, Inc’s management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

As indicated in the accompanying Management’s Report on Internal Control Over Financial Reporting, management’s assessment of and conclusion on the effectiveness of internal control over financial reporting did not include the internal controls related to the acquisitions of Wilson, Enerflow and CE Franklin. The acquired businesses represented approximately 6% of consolidated total assets at December 31, 2012, 8% of consolidated revenues and 2% of consolidated operating profit for the year ended December 31, 2012. Our audit of internal control over financial reporting of the Company also did not include the evaluation of internal control over financial reporting of these acquisitions referred to above.

In our opinion, National Oilwell Varco, Inc. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2012, based on the COSO criteria.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets as of December 31, 2012 and 2011, and the related consolidated statements of income, comprehensive income, stockholders’ equity and cash flows for each of the three years in the period ended December 31, 2012 of National Oilwell Varco, Inc. and our report dated February 22, 2013 expressed an unqualified opinion thereon.

/s/ ERNST & YOUNG LLP

Houston, Texas

February 22, 2013

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders

National Oilwell Varco, Inc.

We have audited the accompanying consolidated balance sheets of National Oilwell Varco, Inc. as of December 31, 2012 and 2011, and the related consolidated statements of income, comprehensive income, stockholders’ equity and cash flows for each of the three years in the period ended December 31, 2012. Our audits also included the financial statement schedule listed in the index at item 15(2). These financial statements and schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and schedule based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of National Oilwell Varco, Inc. as of December 31, 2012 and 2011, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2012, in conformity with U.S. generally accepted accounting principles. Also in our opinion, the related financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), National Oilwell Varco, Inc.’s internal control over financial reporting as of December 31, 2012, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 22, 2013, expressed an unqualified opinion thereon.

/s/ ERNST & YOUNG LLP

Houston, Texas

February 22, 2013

NATIONAL OILWELL VARCO, INC.

CONSOLIDATED BALANCE SHEETS

(In millions, except share data)


	December 31,
	2012		2011
ASSETS
Current assets:
Cash and cash equivalents	$	3,319	$	3,535
Receivables, net		4,320		3,291
Inventories, net		5,891		4,030
Costs in excess of billings		1,225		593
Deferred income taxes		349		336
Prepaid and other current assets		574		325

Total current assets		15,678		12,110
Property, plant and equipment, net		2,945		2,445
Deferred income taxes		413		267
Goodwill		7,172		6,151
Intangibles, net		4,743		4,073
Investment in unconsolidated affiliates		393		391
Other assets		140		78

Total assets	$	31,484	$	25,515

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	1,200	$	901
Accrued liabilities		2,571		2,376
Billings in excess of costs		1,189		865
Current portion of long-term debt and short-term borrowings		1		351
Accrued income taxes		355		709
Deferred income taxes		333		214

Total current liabilities		5,649		5,416
Long-term debt		3,148		159
Deferred income taxes		1,997		1,852
Other liabilities		334		360

Total liabilities		11,128		7,787

Commitments and contingencies
Stockholders’ equity:
Common stock—par value $.01; 1 billion shares authorized; 426,928,322 and 423,900,601 shares issued and outstanding at December 31, 2012 and December 31, 2011		4		4
Additional paid-in capital		8,743		8,535
Accumulated other comprehensive income (loss)		107		(23	)
Retained earnings		11,385		9,103

Total Company stockholders’ equity		20,239		17,619
Noncontrolling interests		117		109

Total stockholders’ equity		20,356		17,728

Total liabilities and stockholders’ equity	$	31,484	$	25,515

The accompanying notes are an integral part of these statements.

NATIONAL OILWELL VARCO, INC.

CONSOLIDATED STATEMENTS OF INCOME

(In millions, except per share data)


	Years Ended December 31,
	2012			2011			2010
Revenue
Sales	$	16,641		$	11,842		$	9,956
Services		3,400			2,816			2,200

Total		20,041			14,658			12,156

Cost of revenue
Cost of sales		11,886			8,037			6,598
Cost of services		2,816			2,124			1,726

Total		14,702			10,161			8,324

Gross profit		5,339			4,497			3,832
Selling, general and administrative		1,782			1,560			1,385

Operating profit		3,557			2,937			2,447
Interest and financial costs		(49	)		(40	)		(50	)
Interest income		10			18			13
Equity income in unconsolidated affiliates		58			46			36
Other income (expense), net		(71	)		(39	)		(49	)

Income before income taxes		3,505			2,922			2,397
Provision for income taxes		1,022			937			738

Net income		2,483			1,985			1,659
Net loss attributable to noncontrolling interests		(8	)		(9	)		(8	)

Net income attributable to Company	$	2,491		$	1,994		$	1,667

Net income attributable to Company per share:
Basic	$	5.86		$	4.73		$	3.99

Diluted	$	5.83		$	4.70		$	3.98

Cash dividends per share	$	0.49		$	0.45		$	0.41

Weighted average shares outstanding:
Basic		425			422			417

Diluted		427			424			419

The accompanying notes are an integral part of these statements.

NATIONAL OILWELL VARCO, INC.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(In millions)


	Years Ended December 31,
	2012			2011			2010
Net income attributable to Company	$	2,491		$	1,994		$	1,667
Other comprehensive income (loss) (net of tax):
Currency translation adjustments		64			(65	)		13
Derivative financial instruments		99			(63	)		(13	)
Change in defined benefit plans		(33	)		14			1

Comprehensive income attributable to Company		2,621			1,880			1,668
Net loss attributable to noncontrolling interests		(8	)		(9	)		(8	)


Comprehensive income	$	2,613		$	1,871		$	1,660

The accompanying notes are an integral part of these statements.

NATIONAL OILWELL VARCO, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In millions)


	Years Ended December 31,
	2012			2011			2010
Cash flows from operating activities:
Net income	$	2,483		$	1,985		$	1,659
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		628			555			507
Deferred income taxes		(97	)		(352	)		(165	)
Stock-based compensation		80			73			66
Excess tax benefit from the exercise of stock options		(25	)		(22	)		(10	)
Equity income in unconsolidated affiliates		(58	)		(46	)		(36	)
Dividend from unconsolidated affiliates		61			45			17
Other		84			69			135
Change in operating assets and liabilities, net of acquisitions:
Receivables		(517	)		(696	)		(189	)
Inventories		(1,061	)		(591	)		39
Costs in excess of billings		(632	)		222			(4	)
Prepaid and other current assets		(224	)		(44	)		15
Accounts payable		(19	)		205			40
Billings in excess of costs		324			354			(620	)
Income taxes payable		(409	)		283			286
Other assets/liabilities, net		2			103			(198	)

Net cash provided by operating activities		620			2,143			1,542

Cash flows from investing activities:
Purchases of property, plant and equipment		(583	)		(483	)		(232	)
Business acquisitions, net of cash acquired		(2,880	)		(1,038	)		(556	)
Dividend from unconsolidated affiliate		—			13			16
Other, net		35			50			29

Net cash used in investing activities		(3,428	)		(1,458	)		(743	)

Cash flows from financing activities:
Borrowings against lines of credit and other debt		5,575			—			3
Payments against lines of credit and other debt		(2,938	)		(391	)		(16	)
Cash dividends paid		(209	)		(191	)		(172	)
Proceeds from stock options exercised		113			96			73
Excess tax benefit from the exercise of stock options		25			22			10
Other		17			—			—

Net cash provided by (used in) financing activities		2,583			(464	)		(102	)

Effect of exchange rates on cash		9			(19	)		14

Increase (decrease) in cash and cash equivalents		(216	)		202			711
Cash and cash equivalents, beginning of period		3,535			3,333			2,622

Cash and cash equivalents, end of period	$	3,319		$	3,535		$	3,333

Supplemental disclosures of cash flow information:
Cash payments during the period for:
Interest	$	40		$	44		$	56
Income taxes	$	1,572		$	945		$	551

The accompanying notes are an integral part of these statements.

NATIONAL OILWELL VARCO, INC.

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

(In millions)


	Shares Outstanding		Common Stock		Additional Paid in Capital			Accumulated Other Comprehensive Income (Loss)			Retained Earnings			Total Company Stockholders’ Equity			Noncontrolling Interests			Total Stockholders’ Equity
Balance at December 31, 2009		418	$	4	$	8,214		$	90		$	5,805		$	14,113		$	115		$	14,228

Net income		—		—		—			—			1,667			1,667			(8	)		1,659
Other comprehensive income, net		—		—		—			1			—			1			—			1
Cash dividends, $.41 per common share		—		—		—			—			(172	)		(172	)		—			(172	)
Dividends to noncontrolling interests		—		—		—			—			—			—			(2	)		(2	)
Noncontrolling interest contribution		—		—		—			—			—			—			9			9
Stock-based compensation		—		—		66			—			—			66			—			66
Common stock issued		3		—		73			—			—			73			—			73
Withholding taxes		—		—		(10	)		—			—			(10	)		—			(10	)
Excess tax benefit of options exercised		—		—		10			—			—			10			—			10

Balance at December 31, 2010		421	$	4	$	8,353		$	91		$	7,300		$	15,748		$	114		$	15,862

Net income		—		—		—			—			1,994			1,994			(9	)		1,985
Other comprehensive loss, net		—		—		—			(114	)		—			(114	)		—			(114	)
Cash dividends, $.45 per common share		—		—		—			—			(191	)		(191	)		—			(191	)
Dividends to noncontrolling interests		—		—		—			—			—			—			(17	)		(17	)
Noncontrolling interest contribution		—		—		—			—			—			—			21			21
Stock-based compensation		—		—		73			—			—			73			—			73
Common stock issued		3		—		96			—			—			96			—			96
Withholding taxes		—		—		(9	)		—			—			(9	)		—			(9	)
Excess tax benefit of options exercised		—		—		22			—			—			22			—			22

Balance at December 31, 2011		424	$	4	$	8,535		$	(23	)	$	9,103		$	17,619		$	109		$	17,728

Net income		—		—		—			—			2,491			2,491			(8	)		2,483
Other comprehensive income, net		—		—		—			130			—			130			—			130
Cash dividends, $.49 per common share		—		—		—			—			(209	)		(209	)		—			(209	)
Dividends to noncontrolling interests		—		—		—			—			—			—			(4	)		(4	)
Noncontrolling interest contribution		—		—		—			—			—			—			20			20
Stock-based compensation		—		—		80			—			—			80			—			80
Common stock issued		3		—		113			—			—			113			—			113
Withholding taxes		—		—		(10	)		—			—			(10	)		—			(10	)
Excess tax benefit of options exercised		—		—		25			—			—			25			—			25

Balance at December 31, 2012		427	$	4	$	8,743		$	107		$	11,385		$	20,239		$	117		$	20,356

The accompanying notes are an integral part of these statements.

NATIONAL OILWELL VARCO, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. Organization and Basis of Presentation

Nature of Business

We design, construct, manufacture and sell comprehensive systems, components, and products used in oil and gas drilling and production, provide oilfield services and supplies, and distribute products and provide supply chain integration services to the upstream oil and gas industry. Our revenues and operating results are directly related to the level of worldwide oil and gas drilling and production activities and the profitability and cash flow of oil and gas companies, drilling contractors and oilfield service companies, which in turn are affected by current and anticipated prices of oil and gas. Oil and gas prices have been, and are likely to continue to be, volatile.

Basis of Consolidation

The accompanying Consolidated Financial Statements include the accounts of National Oilwell Varco, Inc. and its consolidated subsidiaries. All significant intercompany transactions and balances have been eliminated in consolidation. Investments that are not wholly-owned, but where we exercise control, are fully consolidated with the equity held by minority owners and their portion of net income (loss) reflected as noncontrolling interests in the accompanying consolidated financial statements. Investments in unconsolidated affiliates, over which we exercise significant influence, but not control, are accounted for by the equity method.

2. Summary of Significant Accounting Policies

Fair Value of Financial Instruments

The carrying amounts of cash and cash equivalents, receivables, and payables approximated fair value because of the relatively short maturity of these instruments. Cash equivalents include only those investments having a maturity date of three months or less at the time of purchase. See Note 3 for the fair value of derivative financial instruments, Note 9 for the fair value of long-term debt and Note 10 for the fair value of employee benefit plan assets.

Derivative Financial Instruments

Accounting Standards Codification (“ASC”) Topic 815, “Derivatives and Hedging” (“ASC Topic 815”) requires companies to recognize all of its derivative instruments as either assets or liabilities in the Consolidated Balance Sheet at fair value. The accounting for changes in the fair value (i.e., gains or losses) of a derivative instrument depends on whether it has been designated and qualifies as part of a hedging relationship, and further, on the type of hedging relationship. For those derivative instruments that are designated and qualify as hedging instruments, a company must designate the hedging instrument, based upon the exposure being hedged, as a fair value hedge, cash flow hedge, or a hedge of a net investment in a foreign operation.

The Company records all derivative financial instruments at their fair value in its Consolidated Balance Sheet. Except for certain non-designated hedges discussed below, all derivative financial instruments that the Company holds are designated as cash flow and are highly effective in offsetting movements in the underlying risks. Such arrangements typically have terms between two and 24 months, but may have longer terms depending on the underlying cash flows being hedged, typically related to the projects in our backlog. The Company may also use interest rate contracts to mitigate its exposure to changes in interest rates on anticipated long-term debt issuances.

At December 31, 2012, the Company has determined that the fair value of its derivative financial instruments representing assets of $105 million and liabilities of $19 million (primarily currency related derivatives) are determined using level 2 inputs (inputs other than quoted prices in active markets for identical assets and liabilities that are observable either directly or indirectly for substantially the full term of the asset or liability) in the fair value hierarchy as the fair value is based on publicly available foreign exchange and interest rates at each financial reporting date. At December 31, 2012, the net fair value of the Company’s foreign currency forward contracts totaled a net asset of $86 million.

Inventories

Inventories consist of raw materials, work-in-process and oilfield and industrial finished products, manufactured equipment and spare parts. Inventories are stated at the lower of cost or market using the first-in, first-out or average cost methods. Allowances for excess and obsolete inventories are determined based on our historical usage of inventory on-hand as well as our future expectations related to our installed base and the development of new products. The allowance, which totaled $338 million and $281 million at December 31, 2012 and 2011, respectively, is the amount necessary to reduce the cost of the inventory to its net realizable value.

Property, Plant and Equipment

Property, plant and equipment are recorded at cost. Expenditures for major improvements that extend the lives of property and equipment are capitalized while minor replacements, maintenance and repairs are charged to operations as incurred. Disposals are removed at cost less accumulated depreciation with any resulting gain or loss reflected in operations. Depreciation is provided using the straight-line method over the estimated useful lives of individual items. Depreciation expense was $323 million, $279 million and $262 million for the years ended December 31, 2012, 2011 and 2010, respectively. The estimated useful lives of the major classes of property, plant and equipment are included in Note 6 to the consolidated financial statements.

Long-lived Assets

We record impairment losses on long-lived assets used in operations when events and circumstances indicate that the assets are impaired and the undiscounted cash flows estimated to be generated by those assets are less than the carrying amount of those assets. The carrying value of assets used in operations that are not recoverable is reduced to fair value if lower than carrying value. In determining the fair market value of the assets, we consider market trends and recent transactions involving sales of similar assets, or when not available, discounted cash flow analysis. There have been no impairments of long-lived assets for the years ended December 31, 2012, 2011 and 2010.

Intangible Assets

The Company has approximately $7.1 billion of goodwill and $4.7 billion of identified intangible assets at December 31, 2012. 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 such assets might be impaired.

Goodwill is identified by segment as follows (in millions):


	Rig Technology			Petroleum Services & Supplies			Distribution & Transmission			Total
Balance at December 31, 2010	$	1,854		$	3,859		$	77		$	5,790
Goodwill acquired during period		117			233			27			377
Currency translation adjustments and other		(12	)		(3	)		(1	)		(16	)

Balance at December 31, 2011	$	1,959		$	4,089		$	103		$	6,151
Goodwill acquired during the period		412			241			347			1,000
Currency translation adjustments and other		15			3			3			21

Balance at December 31, 2012	$	2,386		$	4,333		$	453		$	7,172

Identified intangible assets with determinable lives consist primarily of customer relationships, trademarks, trade names, patents, and technical drawings acquired in acquisitions, and are being amortized on a straight-line basis over the estimated useful lives of 2-30 years. Amortization expense of identified intangibles is expected to be approximately $300 million in each of the next five years. Included in intangible assets are approximately $643 million of indefinite-lived trade names.

The net book value of identified intangible assets are identified by segment as follows (in millions):


	Rig Technology			Petroleum Services & Supplies			Distribution & Transmission			Total
Balance at December 31, 2010	$	666		$	3,432		$	5		$	4,103
Additions to intangible assets		70			176			27			273
Amortization		(60	)		(213	)		(3	)		(276	)
Currency translation adjustments and other		(22	)		(4	)		(1	)		(27	)

Balance at December 31, 2011	$	654		$	3,391		$	28		$	4,073
Additions to intangible assets		545			380			56			981
Amortization		(76	)		(224	)		(5	)		(305	)
Currency translation adjustments and other		(11	)		3			2			(6	)

Balance at December 31, 2012	$	1,112		$	3,550		$	81		$	4,743

Identified intangible assets by major classification consist of the following (in millions):


	Gross		Accumulated Amortization			Net Book Value
December 31, 2011:
Customer relationships	$	3,044	$	(717	)	$	2,327
Trademarks		716		(122	)		594
Indefinite-lived trade names		643		—			643
Other		751		(242	)		509

Total identified intangibles	$	5,154	$	(1,081	)	$	4,073

December 31, 2012:
Customer relationships	$	3,522	$	(907	)	$	2,615
Trademarks		877		(152	)		725
Indefinite-lived trade names		643		—			643
Other		1,087		(327	)		760

Total identified intangibles	$	6,129	$	(1,386	)	$	4,743

The Company performed its annual impairment analysis for its goodwill and indefinite-lived intangible assets during the fourth quarter of 2012, 2011 and 2010, each resulting in no impairment. The valuation techniques used in the annual test were consistent with those used during previous testing. The inputs used in the annual test were updated for current market conditions and forecasts.

Foreign Currency

The functional currency for most of our foreign operations is the local currency. The cumulative effects of translating the balance sheet accounts from the functional currency into the U.S. dollar at current exchange rates are included in accumulated other comprehensive income (loss). Revenues and expenses are translated at average exchange rates in effect during the period. Certain other foreign operations, including our operations in Norway, use the U.S. dollar as the functional currency. Accordingly, financial statements of these foreign subsidiaries are remeasured to U.S. dollars for consolidation purposes using current rates of exchange for monetary assets and liabilities and historical rates of exchange for nonmonetary assets and related elements of expense. Revenue and expense elements are remeasured at rates that approximate the rates in effect on the transaction dates. For all operations, gains or losses from remeasuring foreign currency transactions into the functional currency are included in income. Net foreign currency transaction losses were $21 million, $10 million and $30 million for the years ending December 31, 2012, 2011 and 2010, respectively, and are included in other income (expense) in the accompanying statement of operations.

Revenue Recognition

The Company’s products and services are sold based upon purchase orders or contracts with the customer that include fixed or determinable prices and that do not generally include right of return or other similar provisions or other significant post delivery obligations. Except for certain construction contracts and drill pipe sales described below, the Company records revenue at the time its manufacturing process is complete, the customer has been provided with all proper inspection and other required documentation, title and risk of loss has passed to the customer, collectability is reasonably assured and the product has been delivered. Customer advances or deposits are deferred and recognized as revenue when the Company has completed all of its performance obligations related to the sale. The Company also recognizes revenue as services are performed. The amounts billed for shipping and handling cost are included in revenue and related costs are included in cost of sales.

Revenue Recognition under Long-term Construction Contracts

•

the contracts include custom designs for customer specific applications;

•

the structural design is unique and requires significant engineering efforts; and

•

construction projects often have progress payments.

This method requires the Company to make estimates regarding the total costs of the project, progress against the project schedule and the estimated completion date, all of which impact the amount of revenue and gross margin the Company recognizes in each reporting period. The Company prepares detailed cost estimates at the beginning of each project. Significant projects and their related costs and profit margins are updated and reviewed at least quarterly by senior management. Factors that may affect future project costs and margins include shipyard access, weather, production efficiencies, availability and costs of labor, materials and subcomponents and other factors. These factors can impact the accuracy of the Company’s estimates and materially impact the Company’s current and future reported earnings.

The asset, “Costs in excess of billings,” represents revenues recognized in excess of amounts billed. The liability, “Billings in excess of costs,” represents billings in excess of revenues recognized.

Drill Pipe Sales

For drill pipe sales, if requested in writing by the customer, delivery may be satisfied through delivery to the Company’s customer storage location or to a third-party storage facility. For sales transactions where title and risk of loss have transferred to the customer but the supporting documentation does not meet the criteria for revenue recognition prior to the products being in the physical possession of the customer, the recognition of the revenues and related inventory costs from these transactions are deferred until the customer takes physical possession.

Service and Product Warranties

The changes in the carrying amount of service and product warranties are as follows (in millions):


Balance at December 31, 2010	$	215

Net provisions for warranties issued during the year		40
Amounts incurred		(47	)
Currency translation adjustments and other		3

Balance at December 31, 2011	$	211

Net provisions for warranties issued during the year		51
Amounts incurred		(76	)
Currency translation adjustments and other		8

Balance at December 31, 2012	$	194

Income Taxes

The liability method is used to account for income taxes. Deferred tax assets and liabilities are determined based on differences between the financial reporting and tax basis of assets and liabilities and are measured using the enacted tax rates that will be in effect when the differences are expected to reverse. Valuation allowances are established when necessary to reduce deferred tax assets to amounts which are more likely than not to be realized.

Concentration of Credit Risk

We grant credit to our customers, which operate primarily in the oil and gas industry. Concentrations of credit risk are limited because we have a large number of geographically diverse customers, thus spreading trade credit risk. We control credit risk through credit evaluations, credit limits and monitoring procedures. We perform periodic credit evaluations of our customers’ financial condition and generally do not require collateral, but may require letters of credit for certain international sales. Credit losses are provided for in the financial statements. Allowances for doubtful accounts are determined based on a continuous process of assessing the Company’s portfolio on an individual customer basis taking into account current market conditions and trends. 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. Accounts receivable are net of allowances for doubtful accounts of approximately $120 million and $107 million at December 31, 2012 and 2011.

Stock-Based Compensation

Compensation expense for the Company’s stock-based compensation plans is measured using the fair value method required by ASC Topic 718 “Compensation – Stock Compensation” (“ASC Topic 718”). Under this guidance the fair value of stock option grants and restricted stock is amortized to expense using the straight-line method over the shorter of the vesting period or the remaining employee service period.

The Company provides compensation benefits to employees and non-employee directors under share-based payment arrangements, including various employee stock option plans.

Total compensation cost that has been charged against income for all share-based compensation arrangements was $80 million, $73 million and $66 million for 2012, 2011 and 2010, respectively. The total income tax benefit recognized in the income statement for all share-based compensation arrangements was $24 million, $17 million and $20 million for 2012, 2011 and 2010, respectively.

Environmental Liabilities

When environmental assessments or remediations are probable and the costs can be reasonably estimated, remediation liabilities are recorded on an undiscounted basis and are adjusted as further information develops or circumstances change.

Use of Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect reported and contingent amounts of assets and liabilities as of the date of the financial statements and reported amounts of revenues and expenses during the reporting period. Such estimates include but are not limited to, estimated losses on accounts receivable, estimated costs and related margins of projects accounted for under percentage-of-completion, estimated realizable value on excess and obsolete inventory, contingencies, estimated liabilities for litigation exposures and liquidated damages, estimated warranty costs, estimates related to pension accounting, estimates related to the fair value of reporting units for purposes of assessing goodwill and other indefinite-lived intangible assets for impairment and estimates related to deferred tax assets and liabilities, including valuation allowances on deferred tax assets. Actual results could differ from those estimates.

Contingencies

The Company accrues for costs relating to litigation claims and other contingent matters, including liquidated damage liabilities, when such liabilities become probable and reasonably estimable. Such estimates may be based on advice from third parties or on management’s judgment, as appropriate. Revisions to contingent liabilities are reflected in income in the period in which different facts or information become known or circumstances change that affect the Company’s previous judgments with respect to the likelihood or amount of loss. Amounts paid upon the ultimate resolution of contingent liabilities may be materially different from previous estimates and could require adjustments to the estimated reserves to be recognized in the period such new information becomes known.

In circumstances where the most likely outcome of a contingency can be reasonably estimated, we accrue a liability for that amount. Where the most likely outcome cannot be estimated, a range of potential losses is established and if no one amount in that range is more likely than others, the low end of the range is accrued.

Net Income Attributable to Company Per Share

The following table sets forth the computation of weighted average basic and diluted shares outstanding (in millions, except per share data):


	Years Ended December 31,
	2012		2011		2010
Numerator:
Net income attributable to Company	$	2,491	$	1,994	$	1,667

Denominator:
Basic—weighted average common shares outstanding		425		422		417
Dilutive effect of employee stock options and other unvested stock awards		2		2		2

Diluted outstanding shares		427		424		419

Basic earnings attributable to Company per share	$	5.86	$	4.73	$	3.99

Diluted earnings attributable to Company per share	$	5.83	$	4.70	$	3.98

Cash dividends per share	$	0.49	$	0.45	$	0.41

ASC Topic 260, “Earnings Per Share” (“ASC Topic 260”) requires companies with unvested participating securities to utilize a two-class method for the computation of net income attributable to Company per share. The two-class method requires a portion of net income attributable to Company to be allocated to participating securities, which are unvested awards of share-based payments with non-forfeitable rights to receive dividends or dividend equivalents, if declared. Net income attributable to Company allocated to these participating securities was immaterial for the years ended December 31, 2012, 2011 and 2010 and therefore not excluded from net income attributable to Company per share calculation.

The Company had stock options outstanding that were anti-dilutive totaling 5 million, 3 million, and 8 million at December 31, 2012, 2011 and 2010, respectively.

Recently Issued Accounting Standards

3. Derivative Financial Instruments

ASC Topic 815, “Derivatives and Hedging” (“ASC Topic 815”) requires a company to recognize all of its derivative instruments as either assets or liabilities in the Consolidated Balance Sheet at fair value. The accounting for changes in the fair value (i.e., gains or losses) of a derivative instrument depends on whether it has been designated and qualifies as part of a hedging relationship and further, on the type of hedging relationship. For those derivative instruments that are designated and qualify as hedging instruments, a company must designate the hedging instrument, based upon the exposure being hedged, as a fair value hedge, cash flow hedge, or a hedge of a net investment in a foreign operation.

The Company is exposed to certain risks relating to its ongoing business operations. The primary risk managed by using derivative instruments is foreign currency exchange rate risk. Forward contracts against various foreign currencies are entered into to manage the foreign currency exchange rate risk on forecasted revenues and expenses denominated in currencies other than the functional currency of the operating unit (cash flow hedge). Other forward exchange contracts against various foreign currencies are entered into to manage the foreign currency exchange rate risk associated with certain firm commitments denominated in currencies other than the functional currency of the operating unit (fair value hedge). In addition, the Company will enter into non-designated forward contracts against various foreign currencies to manage the foreign currency exchange rate risk on recognized nonfunctional currency monetary accounts (non-designated hedge).

The Company records all derivative financial instruments at their fair value in its Consolidated Balance Sheet. Except for certain non-designated hedges discussed below, all derivative financial instruments that the Company holds are designated as cash flow hedges and are highly effective in offsetting movements in the underlying risks. Such arrangements typically have terms between 2 and 24 months, but may have longer terms depending on the underlying cash flows being hedged, typically related to the projects in our backlog. The Company may also use interest rate contracts to mitigate its exposure to changes in interest rates on anticipated long-term debt issuances.

At December 31, 2012, the Company did not have any interest rate swaps and its financial instruments do not contain any credit-risk-related or other contingent features that could cause accelerated payments when the Company’s financial instruments are in net liability positions. We do not use derivative financial instruments for trading or speculative purposes.

Cash Flow Hedging Strategy

To protect against the volatility of forecasted foreign currency cash flows resulting from forecasted revenues and expenses, the Company has instituted a cash flow hedging program. The Company hedges portions of its forecasted revenues and expenses denominated in nonfunctional currencies with forward contracts. When the U.S. dollar strengthens against the foreign currencies, the decrease in present value of future foreign currency revenues and expenses is offset by gains in the fair value of the forward contracts designated as hedges. Conversely, when the U.S. dollar weakens, the increase in the present value of future foreign currency cash flows is offset by losses in the fair value of the forward contracts.

For derivative instruments that are designated and qualify as a cash flow hedge (i.e., hedging the exposure to variability in expected future cash flows that is subject to a particular currency risk), the effective portion of the gain or loss on the derivative instrument is reported as a component of Other Comprehensive Income and reclassified into earnings in the same line item associated with the forecasted transaction and in the same period or periods during which the hedged transaction affects earnings (e.g., in “revenues” when the hedged transactions are cash flows associated with forecasted revenues). The remaining gain or loss on the derivative instrument in excess of the cumulative change in the present value of future cash flows of the hedged item, if any (i.e., the ineffective portion), or hedge components excluded from the assessment of effectiveness, is recognized in the Consolidated Statements of Income during the current period.

At December 31, 2012 and 2011, the Company had the following outstanding foreign currency forward contracts that were entered into to hedge nonfunctional currency cash flows from forecasted revenues and expenses (in millions):


	Currency Denomination
Foreign Currency	December 31, 2012		December 31, 2011
Norwegian Krone	NOK	6,281	NOK	6,639
U.S. Dollar	$	331	$	402
Euro	€	389	€	456
Mexican Peso	MXN	—	MXN	—
Danish Krone	DKK	134	DKK	98
Singapore Dollar	SGD	14	SGD	10
British Pound Sterling	£	6	£	2

Non-designated Hedging Strategy

The Company enters into forward exchange contracts to hedge certain nonfunctional currency monetary accounts. The purpose of the Company’s foreign currency hedging activities is to protect the Company from risk that the eventual U.S. dollar equivalent cash flows from the nonfunctional currency monetary accounts will be adversely affected by changes in the exchange rates.

For derivative instruments that are non-designated, the gain or loss on the derivative instrument subject to the hedged risk (i.e., nonfunctional currency monetary accounts) is recognized in other income (expense), net in current earnings.

The Company had the following outstanding foreign currency forward contracts that hedge the fair value of nonfunctional currency monetary accounts (in millions):


	Currency Denomination
Foreign Currency	December 31, 2012		December 31, 2011
Norwegian Krone	NOK	1,684	NOK	2,310
Russian Ruble	RUB	1,467	RUB	786
U.S. Dollar	$	967	$	483
Euro	€	225	€	161
Danish Krone	DKK	177	DKK	67
Brazilian Real	BRL	135	BRL	—
Singapore Dollar	SGD	24	SGD	5
British Pound Sterling	£	9	£	9
Canadian Dollar	CAD	2	CAD	—
Swedish Krone	SEK	5	SEK	4

The Company has the following fair values of its derivative instruments and their balance sheet classifications (in millions):


	Asset Derivatives					Liability Derivatives
		Fair Value					Fair Value
	Balance Sheet	December 31,				Balance Sheet	December 31,
	Location	2012		2011		Location	2012		2011
Derivatives designated as hedging instruments under ASC Topic 815
Foreign exchange contracts	Prepaid and other current assets	$	57	$	16	Accrued liabilities	$	5	$	62
Foreign exchange contracts	Other Assets		24		1	Other Liabilities		1		13

Total derivatives designated as hedging instruments under ASC Topic 815		$	81	$	17		$	6	$	75

Derivatives not designated as hedging instruments under ASC Topic 815
Foreign exchange contracts	Prepaid and other current assets	$	24	$	9	Accrued liabilities	$	13	$	21

Total derivatives not designated as hedging instruments under ASC Topic 815		$	24	$	9		$	13	$	21

Total derivatives		$	105	$	26		$	19	$	96

The Effect of Derivative Instruments on the Consolidated Statements of Income

($ in millions)


Derivatives Designated as Hedging Instruments under ASC Topic 815	Amount of Gain (Loss) Recognized in OCI on Derivatives (Effective Portion) (a)				Location of Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)	Amount of Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)				Location of Gain (Loss) Recognized in Income on Derivatives (Ineffective Portion and Amount Excluded from Effectiveness Testing)	Amount of Gain (Loss) Recognized in Income on Derivatives (Ineffective Portion and Amount Excluded from Effectiveness Testing) (b)
	Years Ended December 31,					Years Ended December 31,					Years Ended December 31,
	2012		2011			2012		2011			2012		2011
					Revenue		6		11
Foreign exchange contracts		105		6	Cost of revenue		26		38	Other income (expense), net		8		11

Total		105		6			32		49			8		11


Derivatives Not Designated as Hedging Instruments under ASC Topic 815	Location of Gain (Loss) Recognized in Income on Derivatives	Amount of Gain (Loss) Recognized in Income on Derivatives
		Years Ended December 31,
		2012		2011
Foreign exchange contracts	Other income (expense), net		19		—

Total			19		—

(a)	The Company expects that $(35) million of the Accumulated Other Comprehensive Income (Loss) will be reclassified into earnings within the next twelve months with an offset by gains from the underlying transactions resulting in no impact to earnings or cash flow.

(b)

The amount of gain (loss) recognized in income represents nil and $17 million related to the ineffective portion of the hedging relationships for the years ended December 31, 2012 and 2011, respectively, and $8 million and $18 million related to the amount excluded from the assessment of the hedge effectiveness for the years ended December 31, 2012 and 2011, respectively.

4. Acquisitions and Investments

2012

In the year ended December 31, 2012, the Company completed 17 acquisitions for an aggregate purchase price of $2,880 million, net of cash acquired. These acquisitions included:

•

All the shares of NKT Flexibles I/S (“NKT”), a Denmark-based designer and manufacturer of flexible pipe products and systems for the offshore oil and gas industry, acquired on April 4, 2012. The Company reported the NKT results within its Rig Technology segment from the date of acquisition.

•

All the shares of Enerflow Industries Inc. (U.S.) and certain assets of Enerflow Industries Inc. (Canada) (“Enerflow”), a Canada-based fabricator and manufacturer of pressure pumping, blending, and cementing equipment for use primarily in Canada and the U.S., acquired on May 16, 2012. The Company reported the Enerflow results within its Rig Technology segment from the date of acquisition.

•

All the shares of Wilson Distribution Holdings (“Wilson”), a U.S.-based distributor of pipe, valves and fittings as well as mill, tool and safety products and services, acquired on May 31, 2012. The Company reported the Wilson results within its Distribution & Transmission segment from the date of acquisition.

•

All the shares of CE Franklin Ltd. (“CE Franklin”), a Canada-based distributor of pipe, valves, flanges, fittings, production equipment, tubular products and other general oilfield supplies to oil and gas producers in Canada as well as to the oil sands, refining, heavy oil, petrochemical, forestry and mining industries, acquired on July 19, 2012. The Company reported the CE Franklin results within its Distribution & Transmission segment from the date of acquisition.

•

All the shares of Fiberspar Corporation (“Fiberspar”), a U.S.-based manufacturer of fiberglass-reinforced spoolable pipe for the oil and gas industry, acquired on October 10, 2012. The Company reported the Fiberspar results within its Petroleum Services & Supplies segment from the date of acquisition.

The purchase price allocation is complete for the majority of the 2012 acquisitions. Acquisitions made during the fourth quarter of 2012 remain preliminary until the valuations are complete. The following table displays the total preliminary purchase price allocation for the 2012 acquisitions and summarizes the estimated fair values of the assets acquired and liabilities assumed at the date of acquisition (in millions):


Current assets, net of cash acquired	$	1,441
Property, plant and equipment		248
Intangible assets		981
Goodwill		1,000
Other assets		2

Total assets acquired		3,672

Current liabilities		585
Long-term debt		1
Other liabilities		206

Total liabilities		792

Cash consideration, net of cash acquired	$	2,880

The Company allocated $981 million to intangible assets (18 year weighted-average life). The intangible assets are expected to be amortizable and are comprised of: $473 million of customer relationships (20 year weighted-average life),$159 million of trademarks (16 year weighted-average life), and $348 million of other intangible assets (17 year weighted-average life). Goodwill specifically includes the expected synergies and other benefits that the Company believes will result from combining its operations with those of businesses acquired and other intangible assets that do not qualify for separate recognition, such as assembled workforce in place at the date of each acquisition. The $1,000 million allocated to goodwill represents the excess of the purchase price over the fair value of the net assets acquired. Goodwill resulting from the NKT and CE Franklin acquisitions and a portion of the Enerflow acquisition is not expected to be deductible for tax purposes.

2011

The Company completed nine acquisitions for an aggregate purchase price of $1,038 million, net of cash acquired. These acquisitions included:

•

The shares of Ameron International Corporation (“Ameron”), a U.S.-based manufacturer of highly engineered products and materials for the chemical, industrial, energy, transportation and infrastructure markets.

•

The shares of Conner Steel Products Holding Company, a U.S.-based manufacturer of storage and handling equipment for the oilfield services industry.

The allocation of the purchase price of each acquisition was based upon valuations. The following table summarizes the fair values of the assets acquired and liabilities assumed at the date of acquisition of the 2011 acquisitions (in millions):


	Ameron		All Other Acquisitions		Total
Current assets, net of cash acquired	$	245	$	106	$	351
Property, plant and equipment		402		41		443
Intangible assets		142		131		273
Goodwill		199		178		377
Other assets		59		14		73

Total assets acquired		1,047		470		1,517


Current liabilities		154		80		234
Long-term debt		16		—		16
Other liabilities		173		56		229

Total liabilities		343		136		479

Cash consideration, net of cash acquired	$	704	$	334	$	1,038

The Company allocated $273 million to intangible assets (16 year weighted-average life), comprised of: $119 million of customer relationships (14 year weighted-average life), $39 million of trademarks (35 year weighted-average life), and $115 million of other intangible assets (12 year weighted-average life).

2010

The Company completed 12 acquisitions for an aggregate purchase price of $556 million, net of cash acquired. These acquisitions included:

•

The shares of Advanced Production and Loading PLC, a Norway-based designer and manufacturer of turret mooring systems and other products for Floating Production, Storage and Offloading vessels (“FPSOs”) and other offshore vessels and terminals for a purchase price of approximately $500 million.

•

The business and assets of Ambar Lone Star Fluids Services, LLP, a U.S.-based Drilling and Completions Fluids company.

The following table summarizes the fair values of the assets acquired and liabilities assumed at the date of acquisition of the 2010 acquisitions (in millions):


Current assets, net of cash acquired	$	136
Cost in excess of billings		71
Property, plant and equipment		38
Intangible assets		299
Goodwill		298
Other assets		8

Total assets acquired		850

Current liabilities		142
Billings in excess of cost		41
Other liabilities		111

Total liabilities		294

Cash consideration, net of cash acquired	$	556

The Company allocated $299 million to intangible assets (18 year weighted-average life), comprised of: $116 million of customer relationships (15 year weighted-average life), $59 million of trademarks (30 year weighted-average life), and $124 million of other intangible assets (15 year weighted-average life).

Each of the acquisitions were accounted for using the purchase method of accounting and, accordingly, the results of operations of each business are included in the consolidated results of operations from the date of acquisition. A summary of the acquisitions follows (in millions);


	Years Ended December 31,
	2012			2011			2010
Fair value of assets acquired, net of cash acquired	$	3,672		$	1,517		$	850
Cash paid, net of cash acquired		(2,880	)		(1,038	)		(556	)

Liabilities assumed, debt issued and minority interest	$	792		$	479		$	294

Excess purchase price over fair value of net assets acquired	$	1,000		$	377		$	298

5. Inventories, net

Inventories consist of (in millions):


	December 31,
	2012		2011
Raw materials and supplies	$	1,268	$	907
Work in process		905		852
Finished goods and purchased products		3,718		2,271

Total	$	5,891	$	4,030

6. Property, Plant and Equipment

Property, plant and equipment consist of (in millions):


	Estimated		December 31,
	Useful Lives		2012			2011
Land and buildings		5-35 Years	$	1,348		$	1,069
Operating equipment		3-15 Years		2,463			1,955
Rental equipment		3-12 Years		712			636

				4,523			3,660
Less: Accumulated Depreciation				(1,578	)		(1,215	)

			$	2,945		$	2,445

7. Accrued Liabilities

Accrued liabilities consist of (in millions):


	December 31,
	2012		2011
Customer prepayments and billings	$	699	$	686
Compensation		511		468
Accrued vendor costs		444		280
Warranty		194		211
Taxes (non income)		150		119
Insurance		108		103
Fair value of derivatives		18		83
Interest		14		7
Other		433		419

Total	$	2,571	$	2,376

8. Costs and Estimated Earnings on Uncompleted Contracts

Costs and estimated earnings on uncompleted contracts consist of (in millions):


	December 31,
	2012			2011
Costs incurred on uncompleted contracts	$	5,731		$	5,839
Estimated earnings		3,160			3,775

		8,891			9,614
Less: Billings to date		8,855			9,886

	$	36		$	(272	)

Costs and estimated earnings in excess of billings on uncompleted contracts	$	1,225		$	593
Billings in excess of costs and estimated earnings on uncompleted contracts		(1,189	)		(865	)

	$	36		$	(272	)

9. Debt

Debt consists of (in millions):


	December 31,
	2012		2011
Senior Notes, interest at 5.65% payable semiannually, principal due on November 15, 2012	$	—	$	200
Senior Notes, interest at 5.5% payable semiannually, principal due on November 19, 2012		—		150
Senior Notes, interest at 6.125% payable semiannually, principal due on August 15, 2015		151		151
Senior Notes, interest at 1.35% payable semiannually, principal due on December 1, 2017		500		—
Senior Notes, interest at 2.6% payable semiannually, principal due on December 1, 2022		1,395		—
Senior Notes, interest at 3.95% payable semiannually, principal due on December 1, 2042		1,096		—
Other		7		9

Total debt		3,149		510
Less current portion		1		351

Long-term debt	$	3,148	$	159

Principal payments of debt for years subsequent to 2012 are as follows (in millions):


2013	$	1
2014		3
2015		151
2016		—
2017		500
Thereafter		2,494

	$	3,149

New Revolving Credit Facility

On September 28, 2012, the Company entered into a new five-year unsecured revolving credit facility with a syndicate of financial institutions. This new credit facility replaced early the Company’s previous $2.0 billion revolving credit facility and provides for aggregate multicurrency borrowings up to $3.5 billion. In addition, the Company has an accordion option to increase aggregate borrowing availability by an additional $1.0 billion, subject to obtaining additional or increased lender commitments from members of the syndication. Interest under the new credit facility is based upon LIBOR, NIBOR or EURIBOR plus 0.875% subject to a ratings-based grid, or the prime rate. The terms of the new credit facility provide for a financial covenant regarding maximum debt to capitalization. At December 31, 2012, the Company was in compliance with the financial covenant under the new credit facility.

Redemption of unsecured Senior Notes Due 2012

Issuance of unsecured Senior Notes Due 2017, 2022 and 2042

The fair value of the Company’s debt is estimated using Level 2 inputs in the fair value hierarchy and is based on quoted prices for those or similar instruments. At December 31, 2012 and 2011, the fair value of the Company’s unsecured Senior Notes approximated $3,190 million and $526 million, respectively. At December 31, 2012 and 2011, the carrying value of the Company’s unsecured Senior Notes approximated $3,142 million and $501 million, respectively.

10. Employee Benefit Plans

We have benefit plans covering substantially all of our employees. Defined-contribution benefit plans cover most of the U.S. and Canadian employees, and benefits are based on years of service, a percentage of current earnings and matching of employee contributions. Employees in our Norwegian operations can elect to participate in a defined-contribution plan in lieu of a local defined benefit plan. For the years ended December 31, 2012, 2011 and 2010, expenses for defined-contribution plans were $82 million, $54 million, and $41 million, respectively, and all funding is current.

Certain retired or terminated employees of predecessor or acquired companies participate in a defined benefit plan in the United States. None of the participants in this plan are eligible to accrue benefits. In addition, 1,105 U.S. retirees and spouses participate in defined benefit health care plans of predecessor or acquired companies that provide postretirement medical and life insurance benefits. Active employees are ineligible to participate in any of these defined benefit plans. Our subsidiaries in the United Kingdom and Norway also have defined benefit pension plans covering virtually all of their employees.

As a result of the Ameron acquisition in October of 2011, the Company acquired a qualified, defined benefit, noncontributory pension plan for certain U.S. employees as well as the obligation to provide defined retirement benefits to eligible employees in the Netherlands. The U.S. plan at December 31, 2011 was closed to new participants not covered by a collective bargaining agreement and ceased all benefit accruals under the plan with respect to employees that are not covered by a collective bargaining agreement. In addition, 232 U.S. employees covered by a collective bargaining agreement participate in defined benefit health care plans that provide postretirement medical benefits.

Net periodic benefit cost for our defined benefit plans aggregated $10 million, $14 million and $10 million for the years ended December 31, 2012, 2011 and 2010, respectively.

The change in benefit obligation, plan assets and the funded status of the defined benefit pension plans in the United States, United Kingdom, Norway and the Netherlands and defined postretirement plans in the United States, using a measurement date of December 31, 2012 and December 31, 2011, is as follows (in millions):


	Pension benefits						Postretirement benefits
At year end	2012			2011			2012			2011
Benefit obligation at beginning of year	$	556		$	272		$	35		$	33
Service cost		6			7			—			—
Interest cost		27			19			1			1
Actuarial loss (gain)		76			(14	)		(2	)		1
Benefits paid		(26	)		(14	)		(4	)		(5	)
Participants contributions		1			1			—			—
Exchange rate loss (gain)		12			(6	)		—			—
Acquisitions		11			299			—			5
Curtailments		(8	)		(9	)		—			—
Other		—			1			—			—

Benefit obligation at end of year	$	655		$	556		$	30		$	35

Fair value of plan assets at beginning of year	$	419		$	203		$	—		$	—
Actual return		49			19			—			—
Benefits paid		(26	)		(14	)		(4	)		(5	)
Company contributions		53			19			4			5
Participants contributions		1			1			—			—
Exchange rate gain (loss)		12			(5	)		—			—
Acquisitions		9			196			—			—

Fair value of plan assets at end of year	$	517		$	419		$	—		$	—

Funded status	$	(138	)	$	(137	)	$	(30	)	$	(35	)

Accumulated benefit obligation at end of year	$	635		$	527

Liabilities associated with the funded status of the defined benefit pension plans are included in the balances of accrued liabilities and other liabilities in the Consolidated Balance Sheet.

Defined Benefit Pension Plans

Assumed long-term rates of return on plan assets, discount rates and rates of compensation increases vary for the different plans according to the local economic conditions. The assumption rates used for benefit obligations are as follows:


	Years Ended December 31,
	2012	2011
Discount rate:
United States plan	3.78%	4.58%
International plans	3.30%-4.40%	4.50%-5.60%
Salary increase:
United States plan	N/A	N/A
International plans	2.00%-3.87%	2.50%-4.00%

The assumption rates used for net periodic benefit costs are as follows:


	Years Ended December 31,
	2012	2011	2010
Discount rate:
United States plan	4.58%	4.95%	5.26%
International plans	4.50%-5.60%	5.25%-5.65%	5.25%-5.75%
Salary increase:
United States plan	N/A	N/A	N/A
International plans	2.00%-4.00%	2.00%-4.33%	2.50%-4.25%
Expected return on assets:
United States plan	6.33%	5.50%-6.50%	7.50%
International plans	4.50%-6.51%	4.50%-7.06%	6.00%-6.85%

In determining the overall expected long-term rate of return for plan assets, the Company takes into consideration the historical experience as well as future expectations of the asset mix involved. As different investments yield different returns, each asset category is reviewed individually and then weighted for significance in relation to the total portfolio.

The majority of our plans have projected benefit obligations in excess of plan assets.

The Company expects to pay future benefit amounts on its defined benefit plans of $32 million for each of the next five years and aggregate payments of $326 million.

Plan Assets

The Company and its investment advisers collaboratively reviewed market opportunities using historic and statistical data, as well as the actuarial valuation reports for the plans, to ensure that the levels of acceptable return and risk are well-defined and monitored. Currently, the Company’s management believes that there are no significant concentrations of risk associated with plan assets. Our pension investment strategy worldwide prohibits a direct investment in our own stock.

The following table sets forth by level, within the fair value hierarchy, the Plan’s assets carried at fair value (in millions):


	Fair Value Measurements
	Total		Level 1		Level 2		Level 3
December 31, 2011:
Equity securities	$	212	$	—	$	212	$	—
Bonds		100		—		100		—
Other (insurance contracts)		107		—		30		77

Total Fair Value Measurements	$	419	$	—	$	342	$	77

December 31, 2012:
Equity securities	$	204	$	—	$	204	$	—
Bonds		139		—		139		—
Other (insurance contracts)		174		—		74		100

Total Fair Value Measurements	$	517	$	—	$	417	$	100

The following table sets forth a summary of changes in the fair value of the Plan’s Level 3 assets (in millions):


	Level 3 Plan Assets
Balance at December 31, 2010	$	32

Actual return on plan assets still held at reporting date		4
Purchases, sales and settlements		45
Currency translation adjustments		(4	)

Balance at December 31, 2011	$	77

Actual return on plan assets still held at reporting date		10
Purchases, sales and settlements		8
Currency translation adjustments		5

Balance at December 31, 2012	$	100

11. Accumulated Other Comprehensive Income (Loss)

The components of accumulated other comprehensive income (loss) are as follows (in millions):


	Defined			Currency			Derivative
	Benefit			Translation			Financial
	Plans			Adjustments			Instruments			Total
Balance at December 31, 2009	$	(49	)	$	120		$	19		$	90

Current period activity		1			19			(17	)		3
Tax effect		—			(6	)		4			(2	)

Balance at December 31, 2010	$	(48	)	$	133		$	6		$	91

Current period activity		19			(86	)		(88	)		(155	)
Tax effect		(5	)		21			25			41

Balance at December 31, 2011	$	(34	)	$	68		$	(57	)	$	(23	)

Current period activity		(47	)		64			138			155
Tax effect		14			—			(39	)		(25	)

Balance at December 31, 2012	$	(67	)	$	132		$	42		$	107

12. Commitments and Contingencies

In addition, we are involved in various other claims, regulatory agency audits and pending or threatened legal actions involving a variety of matters. At December 31, 2012, the Company recorded an immaterial amount for contingent liabilities representing all contingencies believed to be probable. The Company has also assessed the potential for additional losses above the amounts accrued as well as potential losses for matters that are not probable but are reasonably possible. The total potential loss on these matters cannot be determined; however, in our opinion, any ultimate liability, to the extent not otherwise provided for and except for the specific case referred to above, will not materially affect our financial position, cash flow or results of operations. As it relates to the specific case referred to above we currently anticipate that any administrative fine or penalty agreed to as part of a resolution would be within established accruals, and would not have a material effect on our financial position or results of operations. To the extent a resolution is not negotiated as anticipated, we cannot predict the timing or effect that any resulting government actions may have on our financial position, cash flow or results of operations. These estimated liabilities are based on the Company’s assessment of the nature of these matters, their progress toward resolution, the advice of legal counsel and outside experts as well as management’s intention and experience.

In 2011, the Company acquired Ameron. On or about November 21, 2008, OFAC sent a Requirement to Furnish Information to Ameron. Ameron retained counsel and conducted an internal investigation. In 2009, Ameron, through its counsel, responded to OFAC. On or about January 21, 2011, OFAC issued an administrative subpoena to Ameron. OFAC and Ameron have entered into tolling agreements. All of the conduct under review occurred before acquisition of Ameron by the Company. We currently anticipate that any administrative fine or penalty agreed to as part of a resolution would be within established accruals, and would not have a material effect on our financial position or results of operations. To the extent a resolution is not negotiated, we cannot predict the timing or effect that any resulting government actions may have on our financial position or results of operations.

Our business is affected both directly and indirectly by governmental laws and regulations relating to the oilfield service industry in general, as well as by environmental and safety regulations that specifically apply to our business. Although we have not incurred material costs in connection with our compliance with such laws, there can be no assurance that other developments, such as new environmental laws, regulations and enforcement policies hereunder may not result in additional, presently unquantifiable, costs or liabilities to us.

The Company leases certain facilities and equipment under operating leases that expire at various dates through 2066. These leases generally contain renewal options and require the lessee to pay maintenance, insurance, taxes and other operating expenses in addition to the minimum annual rentals. Rental expense related to operating leases approximated $331 million, $256 million, and $215 million in 2012, 2011 and 2010, respectively.

Future minimum lease commitments under noncancellable operating leases with initial or remaining terms of one year or more at December 31, 2012, are payable as follows (in millions):


2013	$	220
2014		176
2015		146
2016		111
2017		91
Thereafter		375

Total future lease commitments	$	1,119

13. Common Stock

National Oilwell Varco has authorized 1 billion shares of $.01 par value common stock. The Company also has authorized 10 million shares of $.01 par value preferred stock, none of which is issued or outstanding.

Stock Options

Under the terms of National Oilwell Varco’s Long-Term Incentive Plan, as amended, 25.5 million shares of common stock are authorized for the grant of options to officers, key employees, non-employee directors and other persons. Options granted under our stock option plan generally vest over a three-year period starting one year from the date of grant and expire ten years from the date of grant. The purchase price of options granted may not be less than the closing market price of National Oilwell Varco common stock on the date of grant. At December 31, 2012, approximately 3.5 million shares were available for future grants.

We also have inactive stock option plans that were acquired in connection with the acquisitions of Varco International, Inc. in 2005 and Grant Prideco in 2008. We converted the outstanding stock options under these plans to options to acquire our common stock and no further options are being issued under these plans. Stock option information summarized below includes amounts for the National Oilwell Varco Long-Term Incentive Plan and stock plans of acquired companies. Options outstanding at December 31, 2012 under the stock option plans have exercise prices between $9.14 and $84.58 per share, and expire at various dates from January 29, 2013 to February 22, 2022.

The following summarizes options activity:


	Years Ended December 31,
	2012					2011					2010
	Number			Average		Number			Average		Number			Average
	of			Exercise		of			Exercise		of			Exercise
	Shares			Price		Shares			Price		Shares			Price
Shares under option at beginning of year		10,481,750		$	47.20		11,039,544		$	38.01		10,255,982		$	34.19
Granted		2,239,088			84.58		2,277,946			79.68		3,485,283			44.03
Cancelled		(228,137	)		60.28		(241,174	)		40.20		(232,488	)		40.53
Exercised		(3,019,219	)		82.26		(2,594,566	)		36.84		(2,469,233	)		30.35

Shares under option at end of year		9,473,482		$	58.69		10,481,750		$	47.20		11,039,544		$	38.01

Exercisable at end of year		4,823,331		$	43.99		5,073,965		$	38.47		5,067,186		$	36.31

The following summarizes information about stock options outstanding at December 31, 2012:


	Weighted-Avg		Options Outstanding				Options Exercisable
	Remaining				Weighted-Avg				Weighted-Avg
Range of Exercise Price	Contractual Life		Shares		Exercise Price		Shares		Exercise Price
$9.14—$40.00		4.16		2,436,289	$	27.79		2,436,289	$	27.79
$40.01—$65.00		6.47		2,738,151		49.42		1,690,555		52.75
$65.01—$84.58		8.63		4,299,042		82.12		696,487		79.40

Total		6.86		9,473,482	$	58.69		4,823,331	$	43.99

The weighted-average fair value of options granted during 2012, 2011 and 2010, was approximately $30.01, $29.52 and $16.73 per share, respectively, as determined using the Black-Scholes option-pricing model. The total intrinsic value of options exercised during 2012 and 2011, was $120 million and $102 million, respectively.

The determination of fair value of share-based payment awards on the date of grant using an option-pricing model is affected by our stock price as well as assumptions regarding a number of highly complex and subjective variables. These variables include, but are not limited to, the expected stock price volatility over the term of the awards, and actual and projected employee stock option exercise activity. The use of the Black Scholes model requires the use of extensive actual employee exercise activity data and the use of a number of complex assumptions including expected volatility, risk-free interest rate, expected dividends and expected term.


	Years Ended December 31,
	2012			2011			2010
Valuation Assumptions:
Expected volatility		51.7	%		53.2	%		55.0	%
Risk-free interest rate		0.9	%		2.1	%		2.3	%
Expected dividends	$	0.57		$	0.44		$	0.40
Expected term (in years)		3.2			3.1			3.2

The Company used the actual volatility for traded options for the past 10 years prior to option date as the expected volatility assumption required in the Black Scholes model.

The risk-free interest rate assumption is based upon observed interest rates appropriate for the term of our employee stock options. The dividend yield assumption is based on the history and expectation of dividend payouts. The estimated expected term is based on actual employee exercise activity for the past ten years.

As stock-based compensation expense recognized in the Consolidated Statement of Income in 2012 is based on awards ultimately expected to vest, it has been reduced for estimated forfeitures. ASC Topic 718 requires forfeitures to be estimated at the time of grant and revised, if necessary, in subsequent periods if actual forfeitures differ from those estimates. Forfeitures were estimated based on historical experience.

The following summary presents information regarding outstanding options at December 31, 2012 and changes during 2012 with regard to options under all stock option plans:


	Shares			Weighted- Average Exercise Price		Remaining Contractual Term (years)		Aggregate Intrinsic Value
Outstanding at December 31, 2011		10,481,750		$	47.20		7.03	$	217,950,989
Granted		2,239,088		$	84.58
Exercised		(228,137	)	$	60.28
Cancelled		(3,019,219	)	$	82.26
Outstanding at December 31, 2012		9,473,482		$	58.69		6.86	$	150,667,018

Vested or expected to vest		9,321,906		$	58.69		6.86	$	148,256,346

Exercisable at December 31, 2012		4,823,331		$	43.99		5.38	$	125,192,433

At December 31, 2012, total unrecognized compensation cost related to nonvested stock options was $78 million. This cost is expected to be recognized over a weighted-average period of two years. The total fair value of stock options vested in 2012, 2011 and 2010 was approximately $55 million, $54 million and $78 million, respectively. Cash received from option exercises for 2012, 2011 and 2010 was $113 million, $96 million and $73 million, respectively. The actual tax benefit realized for the tax deductions from option exercises totaled $42 million, $43 million and $16 million for 2012, 2011 and 2010, respectively. Cash used to settle equity instruments granted under all share-based payment arrangements for 2012, 2011 and 2010 was not material for any period.

Restricted Shares

The Company issues restricted stock awards and restricted stock units with no exercise price to officers and key employees in addition to stock options. During the year ended December 31, 2012, the Company granted 482,428 shares of restricted stock and restricted stock units, which includes 148,550 performance-based restricted stock awards. Out of the total number of restricted stock and restricted stock units, 464,270 were granted February 21, 2012 and vest on the third anniversary of the date of grant. On May 16, 2012, 18,158 restricted stock awards were granted to the non-employee members of the board of directors. These restricted stock awards vest in equal thirds over three years on the anniversary of the grant date. The performance-based restricted stock awards were granted February 21, 2012. The performance-based restricted stock awards granted will be 100% vested 36 months from the date of grant, subject to the performance condition of the Company’s operating income growth, measured on a percentage basis, from January 1, 2012 through December 31, 2014 exceeding the median operating income growth for the designated peer group over the same period. The estimated forfeiture rate of restricted stock awards and restricted stock units is factored into the share-based compensation expense the Company recognizes.

The following summary presents information regarding outstanding restricted shares:


	Years Ended December 31,
	2012					2011					2010
	Number of Units			Weighted-Average Grant Date Fair Value		Number of Units			Weighted-Average Grant Date Fair Value		Number of Units			Weighted-Average Grant Date Fair Value
Nonvested at beginning of year		1,606,047		$	44.21		1,765,837		$	42.15		2,181,244		$	40.51
Granted		482,428			83.79		374,425			79.53		558,531			43.99
Vested		(406,844	)		83.34		(496,642	)		64.22		(921,454	)		43.28
Cancelled		(344,965	)		30.39		(37,573	)		44.02		(52,484	)		35.11

Nonvested at end of year		1,336,666		$	67.56		1,606,047		$	44.21		1,765,837		$	42.15

The weighted-average grant day fair value of restricted stock awards and restricted stock units granted during the years ended 2012, 2011 and 2010 was $83.79, $79.53 and $43.99 per share, respectively. There were 406,844; 496,642 and 921,454 restricted stock awards that vested during 2012, 2011 and 2010, respectively. At December 31, 2012, there was approximately $37 million of unrecognized compensation cost related to nonvested restricted stock awards and restricted stock units, which is expected to be recognized over a weighted-average period of two years.

14. Income Taxes

The domestic and foreign components of income before income taxes were as follows (in millions):


	Years Ended December 31,
	2012		2011		2010
Domestic	$	1,812	$	1,282	$	727
Foreign		1,693		1,640		1,670

	$	3,505	$	2,922	$	2,397

The components of the provision for income taxes consisted of (in millions):


	Years Ended December 31,
	2012			2011			2010
Current:
Federal	$	700		$	484		$	421
State		48			37			34
Foreign		371			768			448

Total current income tax provision		1,119			1,289			903

Deferred:
Federal		(151	)		(28	)		(260	)
State		—			(3	)		(8	)
Foreign		54			(321	)		103

Total deferred income tax provision		(97	)		(352	)		(165	)

Total income tax provision	$	1,022		$	937		$	738

The difference between the effective tax rate reflected in the provision for income taxes and the U.S. federal statutory rate was as follows (in millions):


	Years Ended December 31,
	2012			2011			2010
Federal income tax at U.S. statutory rate	$	1,227		$	1,023		$	839
Foreign income tax rate differential		(154	)		(152	)		(117	)
State income tax, net of federal benefit		31			22			17
Nondeductible expenses		30			42			40
Tax benefit of manufacturing deduction		(29	)		(37	)		(19	)
Foreign dividends, net of foreign tax credits		(115	)		9			15
Change in deferred tax valuation allowance		80			(18	)		—
Other		(48	)		48			(37	)

Total income tax provision	$	1,022		$	937		$	738

Significant components of our deferred tax assets and liabilities were as follows (in millions):


	December 31,
	2012			2011			2010
Deferred tax assets:
Allowances and operating liabilities	$	368		$	331		$	344
Net operating loss carryforwards		25			14			10
Postretirement benefits		54			14			17
Foreign tax credit carryforwards		259			106			220
Other		149			151			75

		855			616			666
Valuation allowance for deferred tax assets		(93	)		(13	)		(9	)

Total deferred tax assets		762			603			657

Deferred tax liabilities:
Tax over book depreciation		268			204			213
Intangible assets		1,448			1,398			1,307
Deferred income		314			226			456
Accrued U.S. tax on unremitted earnings		92			70			149
Other		208			168			211

Total deferred tax liabilities		2,330			2,066			2,336

Net deferred tax liability	$	1,568		$	1,463		$	1,679

The balance of unrecognized tax benefits at December 31, 2012 and 2011 was $128 million and $131 million, respectively. These unrecognized tax benefits are included in the balance of other liabilities in the Consolidated Balance Sheet. If the $128 million of unrecognized tax benefits accrued at December 31, 2012 are ultimately realized, $55 million would be recorded as a reduction of income tax expense.

A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows (in millions):


	2012			2011			2010
Unrecognized tax benefit at beginning of year	$	131		$	118		$	58
Additions based on tax positions related to the current year		2			9			1
Additions for tax positions of prior years		—			13			82
Reductions for tax positions of prior years		—			—			(5	)
Reductions for lapse of applicable statutes of limitations		(5	)		(9	)		(18	)

Unrecognized tax benefit at end of year	$	128		$	131		$	118

The Company does not anticipate that the total unrecognized tax benefits will significantly change due to the settlement of audits or the expiration of statutes of limitation within 12 months of this reporting date.

To the extent penalties and interest would be assessed on any underpayment of income tax, such accrued amounts have been classified as a component of income tax expense in the financial statements consistent with the Company’s policy. During the year ended December 31, 2012, the Company recorded as an increase of income tax expense a $1 million net increase of accrued interest and penalties related to uncertain tax positions. At December 31, 2012, the Company has accrued approximately $7 million of interest and penalties relating to unrecognized tax benefits. These interest and penalties are included in the balance of other liabilities in the Consolidated Balance Sheet at December 31, 2012.

The Company is subject to taxation in the United States, various states and foreign jurisdictions. The Company has significant operations in the United States, Canada, the United Kingdom, the Netherlands and Norway. Tax years that remain subject to examination by major tax jurisdictions vary by legal entity, but are generally open in the U.S. for the tax years ending after 2007 and outside the U.S. for the tax years ending after 2005.

In the United States, the Company has $20 million of net operating loss carryforwards as of December 31, 2012, which expire at various dates through 2030. The potential benefit of $7 million has been reduced by a $7 million valuation allowance. Future income tax payments will be reduced in the event the Company ultimately realizes the benefit of these net operating losses. If the Company ultimately realizes the benefit of these net operating loss carryforwards, the valuation allowance of $7 million would reduce future income tax expense.

Outside the United States, the Company has $76 million of net operating loss carryforwards as of December 31, 2012, which expire at various dates through the year 2022. The potential benefit of $18 million has been reduced by a $16 million valuation allowance. Future income tax payments will be reduced in the event the Company ultimately realizes the benefit of these net operating losses. If the Company ultimately realizes the benefit of these net operating loss carryforwards, the valuation allowance of $16 million would reduce future income tax expense.

Also in the United States, the Company has $259 million of excess foreign tax credits as of December 31, 2012, which expire at various dates through 2021. These credits have been allotted a valuation allowance of $70 million and would be realized as a reduction of future income tax payments.

During 2012, the Company recorded $118 million in net deferred tax liabilities with a corresponding increase in goodwill related to the 2011 acquisition of Ameron and the 2012 acquisition of NKT.

Undistributed earnings of certain of the Company’s foreign subsidiaries amounted to $4,620 million and $3,789 million at December 31, 2012 and 2011, respectively. Those earnings are considered to be permanently reinvested and no provision for U.S. federal and state income taxes has been made. Distribution of these earnings in the form of dividends or otherwise could result in U.S. federal taxes (subject to an adjustment for foreign tax credits) and withholding taxes payable in various foreign countries. Determination of the amount of unrecognized deferred U.S. income tax liability is not practical; however, unrecognized foreign tax credit carryforwards would be available to reduce some portion of the U.S. liability.

Because of the number of tax jurisdictions in which the Company operates, its effective tax rate can fluctuate as operations and the local country tax rates fluctuate. The Company is also subject to audits by federal, state and foreign jurisdictions which may result in proposed assessments. The Company’s future tax provision will reflect any favorable or unfavorable adjustments to its estimated tax liabilities when resolved. The Company is unable to predict the outcome of these matters. However, the Company believes that none of these matters will have a material adverse effect on the results of operations or financial condition of the Company.

15. Business Segments and Geographic Areas

The Company’s operations consist of three reportable segments: Rig Technology, Petroleum Services & Supplies and Distribution & Transmission. Within the three reporting segments, the Company has aggregated two business units under Rig Technology, nine business units under Petroleum Services & Supplies and two under Distribution & Transmission for a total of 13 business units, one of which was added during 2011 as a result of the Company’s acquisition of Ameron. Prior to the Company’s acquisition of Ameron in October 2011, the Company’s Distribution & Transmission segment was called Distribution Services with one business unit. Distribution Services was expanded as a result of certain business operations of the Ameron acquisition adding an additional business unit to the segment called Transmission and changing the name of the segment to Distribution & Transmission. The Company has aggregated each of its business units in one of the three reporting segments based on the guidelines of ASC Topic 280, “Segment Reporting” (“ASC Topic 280”).

Rig Technology: The 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; wireline trucks; cranes; flexible pipe for offshore production applications; and turret mooring systems and other products for floating production, storage and offloading vessels and other offshore vessels and terminals.

Petroleum Services & Supplies: The 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 drill pipe, tubing, casing, 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, drilling fluids, drill bits, reamers and other downhole tools, and mud pump consumables. 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 fiberglass composite pipe for application in highly corrosive environments.

Distribution & Transmission: The Distribution & Transmission segment provides pipe, maintenance, repair and operating supplies and spare parts to drill sites and production locations, pipeline operations, and processing plants worldwide. In addition to its comprehensive field location network, which supports land drilling operations throughout North America, the segment supports major land and offshore operations for all the major oil and gas producing regions throughout the world. The segment employs advanced information technologies to provide complete procurement, materials management and logistics services to its customers around the globe. The segment also has a global reach in oil and gas, waste water treatment, chemical, food and beverage, paper and pulp, mining, agriculture, and a variety of municipal markets and is a leading producer of water transmission pipe, fabricated steel products and specialized materials and products used in infrastructure projects.

The accounting policies of the reportable segments are the same as those described in the summary of significant accounting policies of the Company. The Company evaluates performance of each reportable segment based upon its operating income, excluding non-recurring items.

The Company had revenues of 10% and 12% of total revenue from one of its customers for the years ended December 31, 2012 and 2011, respectively. This customer, Samsung Heavy Industries, is a shipyard acting as a general contractor for its customers, who are drillship owners and drilling contractors. This shipyard’s customers have specified that the Company’s drilling equipment be installed on their drillships and have required the shipyard to issue contracts to the Company.

Geographic Areas:

The following table presents consolidated revenues by country based on sales destination of the use of the products or services (in millions):


	Years Ended December 31,
	2012		2011		2010
United States	$	8,297	$	5,449	$	4,104
South Korea		3,121		2,257		2,616
Canada		1,319		913		656
Singapore		1,118		721		491
Norway		736		689		495
China		533		430		366
United Kingdom		523		465		421
Brazil		503		397		262
Other Countries		3,891		3,337		2,745

Total	$	20,041	$	14,658	$	12,156

The following table presents long-lived assets by country based on the location (in millions):


	December 31,
	2012		2011
United States	$	1,606	$	1,493
Denmark		174		3
United Kingdom		173		131
Brazil		162		92
Canada		131		113
South Korea		112		97
Singapore		93		86
Other Countries		494		430

Total	$	2,945	$	2,445

Business Segments:


	Rig Technology		Petroleum Services & Supplies		Distribution & Transmission		Unallocated/ Eliminations			Total
December 31, 2012:
Revenues	$	10,107	$	6,967	$	3,927	$	(960	)	$	20,041
Operating profit (1)		2,335		1,501		185		(464	)		3,557
Capital expenditures		150		310		64		59			583
Depreciation and amortization		148		424		25		31			628
Goodwill		2,386		4,333		453		—			7,172
Total assets		11,758		13,463		2,784		3,479			31,484
December 31, 2011:
Revenues	$	7,788	$	5,654	$	1,873	$	(657	)	$	14,658
Operating profit (1)		2,053		1,072		135		(323	)		2,937
Capital expenditures		125		299		17		42			483
Depreciation and amortization		120		397		14		24			555
Goodwill		1,959		4,089		103		—			6,151
Total assets		8,375		13,019		1,420		2,701			25,515
December 31, 2010:
Revenues	$	6,965	$	4,182	$	1,546	$	(537	)	$	12,156
Operating profit (1)		2,064		585		78		(280	)		2,447
Capital expenditures		59		152		2		19			232
Depreciation and amortization		95		384		7		21			507
Goodwill		1,854		3,859		77		—			5,790
Total assets		7,778		11,807		923		2,542			23,050

(1)	Included in operating profit are other costs related to acquisitions, such as the amortization of backlog and inventory that was stepped up to fair value during purchase accounting. Other costs by segment are as follows (in millions):


	Years Ended December 31,
	2012		2011		2010
Other costs:
Rig Technology	$	45	$	17	$	8
Petroleum Services & Supplies		18		23		9
Distribution & Transmission		68		1		1

Total other costs	$	131	$	41	$	18

For the year ended December 31, 2012, 2011 and 2010, other costs included in operating profit were $131 million, $41 million and $18 million, respectively. Certain other costs are included in other income (expense), net as well as interest and financial costs and were $12 million, nil and $27 million for the years ended December 31, 2012, 2011 and 2010, respectively.

16. Quarterly Financial Data (Unaudited)

Summarized quarterly results, were as follows (in millions, except per share data):


	First Quarter		Second Quarter		Third Quarter		Fourth Quarter
Year ended December 31, 2012
Revenues	$	4,303	$	4,734	$	5,319	$	5,685
Gross profit		1,267		1,306		1,371		1,395
Net income attributable to Company		606		605		612		668
Net income attributable to Company per basic share		1.43		1.42		1.44		1.57
Net income attributable to Company per diluted share		1.42		1.42		1.43		1.56
Cash dividends per share		0.12		0.12		0.12		0.13
Year ended December 31, 2011
Revenues	$	3,146	$	3,513	$	3,740	$	4,259
Gross profit		975		1,083		1,164		1,275
Net income attributable to Company		407		481		532		574
Net income attributable to Company per basic share		0.97		1.14		1.26		1.36
Net income attributable to Company per diluted share		0.96		1.13		1.25		1.35
Cash dividends per share		0.11		0.11		0.11		0.12

17. Subsequent Event

On February 20, 2013, the Company completed its previously announced acquisition of Robbins & Myers, Inc. for approximately $2.5 billion in cash. The Company borrowed approximately $1.4 billion under the $3.5 billion revolving credit facility and used approximately $1.1 billion of cash on hand to fund the acquisition. Robbins & Myers, Inc. is a leading supplier of engineered, application-critical equipment and systems for global energy, chemical and other industrial markets. The company provides products and services for upstream oil and gas markets, along with a portfolio of industrial process and flow control products.

SCHEDULE II

NATIONAL OILWELL VARCO, INC.

VALUATION AND QUALIFYING ACCOUNTS

Years Ended December 31, 2012, 2011 and 2010

(in millions)


	Balance beginning of year		Additions (Deductions) charged to costs and expenses		Charge off’s and other			Balance end of year
Allowance for doubtful accounts:
2012	$	107	$	6	$	7		$	120
2011		107		9		(9	)		107
2010		95		39		(27	)		107

Allowance for excess and obsolete inventories:
2012	$	281	$	99	$	(42	)	$	338
2011		270		70		(59	)		281
2010		206		106		(42	)		270

Valuation allowance for deferred tax assets:
2012	$	13	$	80	$	—		$	93
2011		9		4		—			13
2010		8		1		—			9

Warranty reserve:
2012	$	211	$	51	$	(68	)	$	194
2011		215		40		(44	)		211
2010		217		52		(54	)		215