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

10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark one)

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

FOR THE YEAR ENDED DECEMBER 31, 2014

¨	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 x 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 x

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 x 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 x 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. ¨

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 x

The aggregate market value of voting and non-voting common stock held by non-affiliates of the registrant as of June 28, 2014 was $35.4 billion. As of February 12, 2015, there were 409,935,076 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 2015 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 in the design, manufacture and sale of equipment and components used in oil and gas drilling, completion and production operations, and the provision of oilfield services to the upstream oil and gas industry. The Company conducts operations in approximately 900 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. Further information about the Company’s products and services can be found on its website at: 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 the website as soon as reasonably practicable after they 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 four reporting segments: Rig Systems, Rig Aftermarket, Wellbore Technologies and Completion & Production Solutions.

On May 30, 2014, the Company completed the previously announced spin-off of its distribution business into an independent public company named NOW Inc., which trades on the New York Stock Exchange under the symbol “DNOW”. After the close of the New York Stock Exchange on May 30, 2014, stockholders of record as of May 22, 2014 (the “Record Date”) received one share of NOW Inc. common stock for every four NOV common shares they held as of the Record Date. No fractional shares of NOW Inc. common stock were distributed. The transfer agent aggregated any fractional shares into whole shares, sold those whole shares in the open market at prevailing rates and distributed the net cash proceeds, after deducting any taxes required to be withheld and brokerage charges and commissions, pro rata to each holder who would otherwise have been entitled to receive fractional shares in the distribution. Our operating segments were realigned upon separation of NOW Inc., and as a result, all prior periods are presented on this basis. Results of operations related to NOW Inc. have been classified as discontinued operations in all periods presented on Form 10-K.

Rig Systems

The Company’s Rig Systems segment makes and supports the capital equipment and integrated systems needed to drill oil and gas wells on land and offshore. The segment designs, manufactures and sells land rigs, offshore drilling equipment packages, including installation and commissioning services, and drilling rig components that mechanize and automate the drilling process and rig functionality.

Equipment and technologies in Rig Systems include: substructures, derricks, and masts; cranes; pipe lifting, racking, rotating, and assembly systems; fluid transfer technologies, such as mud pumps; pressure control equipment, including blowout preventers; power transmission systems, including drives and generators; and rig instrumentation and control systems.

Rig Systems supports land and offshore drillers. Demand for the segment’s products depends on drilling contractors’ and oil and gas companies’ capital spending plans, specifically capital expenditures on rig construction and refurbishment.

Rig Aftermarket

The Company’s Rig Aftermarket segment provides comprehensive aftermarket products and services to support land and offshore rigs, and drilling rig components manufactured by the Company’s Rig Systems segment.

The segment provides spare parts, repair, and rentals as well as technical support, field service and first well support, field engineering, and customer training through a network of aftermarket service and repair facilities strategically located in major areas of drilling operations.

Rig Aftermarket supports land and offshore drillers. Demand for the segment’s products and services depends on overall levels of oilfield drilling activity, which drives demand for spare parts, service, and repair for Rig Systems’ large installed base of equipment; and secondarily on drilling contractors’ and oil and gas companies’ capital spending plans, specifically capital expenditures on rig refurbishments and re-certifications.

Wellbore Technologies

The Company’s Wellbore Technologies segment designs, manufactures, rents, and sells a variety of equipment and technologies used to perform drilling operations, and offers services that optimize their performance, including: solids control and waste management equipment and services, drilling fluids, premium drill pipe, wired pipe, tubular inspection and coating services, instrumentation, downhole tools, and drill bits.

Wellbore Technologies focuses on oil and gas companies and supports drilling contractors, oilfield service companies, and oilfield equipment rental companies. Demand for the segment’s products and services depends on the level of oilfield drilling activity by oil and gas companies, drilling contractors, and oilfield service companies.

Completion & Production Solutions

The Company’s Completion & Production Solutions segment integrates technologies for well completions and oil and gas production. The segment designs, manufactures, and sells equipment and technologies needed for hydraulic fracture stimulation, including pressure pumping trucks and pumps, blenders, sanders, hydration units, injection units, flowline, manifolds and wellheads; well intervention, including coiled tubing units, coiled tubing, and wireline units and tools; onshore production, including composite pipe, surface transfer and progressive cavity pumps, and artificial lift systems; and, offshore production, including floating production systems and subsea production technologies.

Completion & Production Solutions supports service companies and oil and gas companies. Demand for the segment’s products depends on the level of oilfield completions and workover activity by oilfield service companies and drilling contractors, and capital spending plans by oil and gas companies and oilfield service companies.

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


	Years Ended December 31,
	2014			2013			2012
Revenue:
Rig Systems	$	9,848		$	8,450		$	7,077
Rig Aftermarket		3,222			2,692			2,138
Wellbore Technologies		5,722			5,211			5,184
Completion & Production Solutions		4,645			4,309			3,994
Eliminations		(1,997	)		(1,441	)		(1,199	)

Total Revenue	$	21,440		$	19,221		$	17,194

Sales from one segment to another generally are priced at estimated equivalent commercial selling prices; however, segments originating an external sale are credited with the full profit to the Company. Eliminations include intercompany transactions conducted between the four reporting segments that are eliminated in consolidation. Intercompany transactions within each reporting segment are eliminated within each reporting segment.

See Note 15 to our Consolidated Financial Statements included in this Annual Report on Form 10-K for financial information by segment and a geographical breakout of revenues and long-lived assets. We have also 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 has historically experienced significant volatility. Demand for the Company’s products and services 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 generally spurs demand for the Company’s products and services. 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.

In 2010, as the financial crisis of the preceding three years 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. Each year 2011, 2012 and 2013 saw a further improvement in order rates as commodity prices remained at levels supporting sustained capital spending by our customers. Global rig count increased 5% in 2014 compared to 2013, after falling by 3% in 2013 compared to 2012. During the second half of 2014 the global oil and gas industry entered a cyclical decline causing the Company to experience a decline in new orders. Backlog for Rig Systems at December 31, 2014, 2013 and 2012, was $12.5 billion, $15.0 billion and $10.9 billion, respectively. Backlog for Completion & Production Solutions at December 31, 2014, 2013 and 2012 was $1.8 billion, $1.6 billion and $1.3 billion, respectively.

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 members of the Organization of Petroleum Exporting Countries (“OPEC”) to maintain oil price stability through voluntary production limits; 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, climate change, taxation, and price controls.

See additional discussion on the 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 Construction 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 or 45-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, or 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 Wellbore Technologies, and sells top drives through Rig Systems.

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 rock cuttings drilled out by the bit. The 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.

Rig Systems sells the large “mud pumps” that are used to pump drilling mud through the drill stem, down and back up the hole. Wellbore Technologies 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. Wellbore Technologies manufactures and sells drill pipe and provides drill pipe inspection, coating, and “hard-banding” services.

As the hole depth increases, the kelly must be removed frequently so that additional 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”). Rig Systems 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, another service provided by Wellbore Technologies. Completion & Production Solutions manufactures pressure pumping equipment that is used to cement the casing in place. The rig’s hoisting system raises and lowers the drill stem while drilling or tripping, and lowers casing into the wellbore. A conventional hoisting system is a block and tackle mechanism that works within the drilling rig’s derrick. The mechanism is lifted by a series of pulleys that are attached to the drawworks at the base of the derrick. Rig Systems 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. Containing reservoir pressures is accomplished primarily by the circulation of heavy drilling muds and secondarily by blowout preventers (“BOPs”), should the mud prove inadequate in an emergency situation. Rig Systems sells blowout preventers. Drilling muds are carefully designed to exhibit certain qualities that optimize the drilling process. In addition to containing formation pressure, they must provide power to the drilling motor; carry drilled solids to the surface; protect the drilled formations from being damaged; and, 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 the cost, 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. Wellbore Technologies 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. 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 to the surface. When closed, conventional BOPs prevent normal rig operations so 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. Wellbore Technologies sells and rents drilling rig instrumentation packages that perform these monitoring functions.

During drilling operations the drilling rig and related equipment and tools are subject to severe stresses, pressures and temperatures, as well as a corrosive environment, and require regular repair and maintenance. Rig Aftermarket supplies spare parts and can dispatch field service engineers with the expertise to quickly repair and maintain equipment, minimizing down time.

After the well has reached its total depth and the final section of casing has been set, the drilling rig is moved off 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 Wellbore Technologies. Sometimes operators choose to use corrosion resistant composite materials or alloys, sold by Completion & Production Solutions.

From time to time, a producing well may undergo workover procedures to extend its life and/or 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 Rig Systems. 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, a service Wellbore Technologies 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. The Completion & Production Solutions segment manufactures and sells various types of coiled tubing and wireline equipment and tools.

Rig Systems

The Company’s Rig Systems segment makes and supports the capital equipment and integrated systems needed to drill oil and gas wells on land and offshore. The segment designs, manufactures, and sells land rigs, complete offshore drilling equipment packages, and drilling rig components that mechanize and automate many complex rig processes.

Equipment and technologies in Rig Systems include: power transmission systems, like drives and generators; substructures, derricks, and masts; pipe lifting, racking, rotating, and assembly systems; pressure control equipment, including blowout preventers; cranes; and rig instrumentation and control systems.

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^TM. 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 TDS™ Top Drive Drilling System, originally introduced by the Company in 1982, significantly altered 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, eliminating 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 the use of three or four pre-connected joints of drill pipe at a time, compared to traditional 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 drilling motors for use 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 Systems produces rotary tables as well as kelly and master bushings. 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 from 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 a 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 stored tubulars; 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. Rig Systems 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 thousands of 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, the heart of the hoisting system, 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 AHD™ Active Heave Drilling Drawworks which 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 has a broad collection of crane brand names with international recognition, and 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 and, if necessary, to also shear the drill pipe itself to prevent blowouts (uncontrolled flows of formation fluids and gases to the surface). Rig Systems manufactures a wide array of BOPs used in various applications from deepwater offshore vessels to land rigs. 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 drilling 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.

In 1998, the Company introduced the NXT^TM 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. In 2004, the Company introduced the LXT^TM ram type of BOP, which features many of the design elements of the NXT^TM , but is targeted at the land market. Over the past five years considerable focus has been placed on robustness and reliability in the fundamental design of the equipment with extensive testing being performed in a new R&D facility opened in 2012. In 2013, the Company acquired the T3 BOP product line, further expanding its market offering of reliable, field proven designs for land based drilling applications.

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 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 Systems designs, fabricates and services derricks used in both onshore and offshore applications, and substructures used in onshore applications. Rig Systems also works with shipyards in the fabrication of substructures for offshore drilling rigs.

Offshore Drilling Equipment Packages. Rig Systems also provides the above major pieces of equipment in fully integrated equipment packages for offshore drilling rigs. By purchasing an entire drilling equipment package customers reap the benefits of Rig Systems’ integrated package engineering and installation and commissioning expertise, alleviating many of the potential problems of sourcing complex equipment that must work together from multiple vendors.

Customers and Competition. Rig Systems sells directly to drilling contractors, rig fabricators, well servicing companies, pressure pumping companies, national oil companies, major and independent oil and gas companies, and also through distribution companies. 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 Rig Systems 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 MHWirth; Aker Solutions; American Electric Technologies; American Block; AXON Energy Products; Bentec; Bomco; Canrig (a division of Nabors Industries); Cavins Oil Well Tools; Cameron International; Den-Con Tool Company; Forum Energy Technologies; General Electric; Hitec Products; Honghua; Huisman; Liebherr; Parveen Industries; Omron Corporation; Rolls Royce; Siemens; Stewart & Stevenson; Soilmec and Drillmec (a part of the Trevi Group); Seatrax; Tesco Corporation; Wärtsilä and Weatherford International. Management believes that the principal competitive factors affecting Rig Systems are performance, quality, reputation, customer service, availability of spare parts and consumables, breadth of product line and price.

Rig Aftermarket

The Company’s Rig Aftermarket segment provides comprehensive aftermarket products and services to support a large installed base of land and offshore rigs, and drilling rig components manufactured by the Company’s Rig Systems segment. The segment provides spare parts, repair, and rentals as well as technical support, field service and first well support, field engineering, and customer training through a network of aftermarket service and repair facilities strategically located in major areas of drilling operations.

Spare Parts Rig Aftermarket maintains an inventory of spare parts, manufactured by Rig Systems, across a global network of aftermarket service and repair facilities.

Technical Support Rig Aftermarket’s Technical Support Centers troubleshoot and resolve equipment needs for customers. Cross-disciplinary teams work together with field service technicians and subject matter experts to keep customers’ rigs in operation and utilize web-based applications to record, manage, and resolve issues.

Field Service Field service engineers actively support rig equipment and technologies on location. Based across a global network of aftermarket service and repair facilities, field service engineers can be deployed to operating sites worldwide to resolve equipment issues, whether structural, mechanical, electrical, or software-related.

Repair Rig Aftermarket overhauls, repairs, rebuilds, and recertifies equipment to quality assurance and OEM specifications using only OEM parts.

eHawk Remote Support A subscription service available to customers, eHawk Support Centers provide fast issue response times. Using satellite and computer technology, eHawk Support Centers can diagnose equipment status and work to handle issues remotely, reducing service personnel visits to the field. eHawk utilizes web-based applications to record, manage, and resolve issues.

Field Engineering Rig Aftermarket Field Engineering supports customers by providing rig-specific designs, modifications, and solutions as needed. Services include rig surveys, proposal and design drawings, service manuals, and equipment installation.

Training Centers and Technical Colleges Rig Aftermarket Training Centers offering training for all equipment and technologies designed and manufactured by Rig Systems. Training centers offer a varied curriculum that incorporates hands-on experience, use of equipment simulators, automated classrooms, and enhanced animations with cross-sectional cutouts.

Customers and Competition. Rig Aftermarket supports land and offshore drillers. Demand for the segment’s products and services depends on overall levels of oilfield drilling activity, which drives demand for spare parts, service, and repair for Rig System’s large installed base of equipment; and secondarily on drilling contractors’ and oil and gas companies’ capital spending plans, specifically capital expenditures on rig refurbishments and re-certifications.

The products of Rig Aftermarket 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 MHWirth; American Electric Technologies; American Block; AXON Energy Products; Bentec; Bomco; Canrig (a division of Nabors Industries); Cavins Oil Well Tools; Cameron International; Den-Con Tool Company; Forum Energy Technologies; General Electric; Hitec Products; Honghua; Huisman Liebherr; Parveen Industries; Omron Corporation; Rolls Royce; Siemens; Stewart & Stevenson; Soilmec and Drillmec (a part of the Trevi Group); Seatrax; Sparrows Offshore; Subsea Solutions; Tesco Corporation; Wärtsilä and Weatherford International. Management believes that the principal competitive factors affecting Rig Aftermarket are performance, quality, reputation, customer service, availability of spare parts and consumables, breadth of product line and price.

Wellbore Technologies

The Company’s Wellbore Technologies segment designs, manufactures, rents and sells a variety of equipment and technologies used to perform drilling operations, and offers services that optimize their performance, including: solids control and waste management equipment and services, drilling fluids, premium drill pipe, wired pipe, tubular inspection and coating services, instrumentation, downhole tools, and drill bits.

The Wellbore Technologies segment focuses on oil and gas companies and supports drilling contractors, oilfield service companies, and oilfield rental companies. Demand for Wellbore Technologies’ products and services primarily depends on the level of oilfield drilling activity by oil and gas companies, drilling contractors, and oilfield service companies.

Drill Pipe Products. The Company designs, manufactures, and sells a full range of proprietary and API drill stem products used for the drilling of oil and gas wells. A drilling rig typically carries an inventory of 10,000 to 30,000 feet of drill pipe, which is consumed over time by the drilling process.

During the drilling process, motors mounted on the rig rotate the drill pipe, bottom-hole assembly, and drill bit. In addition to driving the drill bit, drill pipe serves as the conduit for drilling fluids. The Company offers a broad line of premium drilling products designed for the drilling of extended reach, directional, horizontal, deepwater, and ultra-deep wells in both international and domestic markets.

Voest-Alpine Tubulars (“VAT”). VAT is a joint venture between the Company and the Austrian based Voest-Alpine 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. VAT is accounted for under the equity-method of accounting due to the minority owner having substantive participating rights.

Tubular Coating. The Company develops, manufactures and applies its proprietary tubular coatings, known as Tube-Kote^® coatings, to new and used downhole tubulars and line pipe. Tubular coatings help prevent corrosion, which extends the life of tubular assets, and reduces expensive interruptions in production. In addition, coatings are designed to increase the fluid flow rate up to 25%.

Tubular Inspection. Newly manufactured pipe may have serious defects that are not detected at the mill, and pipe can be damaged during handling prior to use at the well site. Exploration and production companies have new tubulars inspected before they are placed in service to reduce the risk of tubular failures during drilling, completion, or production. Used tubulars are inspected to detect service-induced flaws.

Tubular inspection techniques include electromagnetic, ultrasonic, magnetic flux leakage and gamma ray. Inspection services are provided by mobile units at the wellhead as used tubing is removed from a well, and at fixed site locations.

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.

Machining Services. The Company offers a variety of machining services including: thread repair, tool joint rebuilding and sub manufacturing, providing a “one-stop-shop” concept for its drill pipe customers.

Drilling and Intervention. The Company combines a wide array of drilling and intervention tools with drilling, coring, borehole enlargement and other services. The broad spectrum of bottom hole assembly (“BHA”) components offered is the result of the strategic consolidation of key acquisitions.

The Company manufactures fixed cutter and roller cone drill bits and services its customer base in virtually every significant oil and gas producing region of the world.

The Company designs, manufacturers and services a wide array of downhole motors which are capable of achieving higher rotary velocities than can generally be achieved using conventional surface rotary equipment. The AGITATOR™ oscillation tool improves weight transfer to the bit and increases the boundaries of extended reach and horizontal drilling.

Through its Coring Services business line, the Company enables the extraction of actual rock samples from a drilled well bore and allows geologists to examine the formations at the surface.

The Company is well positioned to address the sustained growth of intervention and well workovers with a comprehensive offering of leading fishing and thru-tubing tools. We sell and rent tools to perform retrieval of stuck tools and remove debris, mill bridge plugs and other devices and manipulate well flow control.

Dynamic Drilling Solutions. The Company’s Dynamic Drilling Solutions combines product lines that are focused on instrumentation, eTools, data-driven solutions, managed pressure drilling, and drilling automation and optimization. Dynamic Drilling Solutions generates, collects, aggregates, communicates, and analyzes drilling data to provide our customers effective solutions for their well environments.

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. The Company’s measurement and monitoring systems combine 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 through a secure link.

Directional Sensors, Steering Tools, Magnetic Multi-shot Tools and Electromagnetic Measurement-While-Drilling Systems are offered by the Company. These directional eTools provide measurements and store the data in memory or use a telemetry pathway to transmit downhole data to the surface. At the surface this data is analyzed to optimize well trajectory and improve the drilling rate-of-penetration.

Managed Pressure Drilling equipment and support services enable improved kick detection and help manage wellbore pressures during drilling to permit accessing reserves in certain areas using chokes, manifolds, rotating control devices, continuous circulation systems, downhole sensors and optimized control systems.

Solids Control and Waste Management. The Company offers highly-engineered equipment, and services to 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. Wellsite Services manufactures state-of-the-art patented solids control equipment. Upon the separation of the drill cuttings Wellsite Services provides waste management, including transport and storage.

Fluids Services. The Company is engaged in the provision of drilling fluid systems, drilling fluid products, completion fluids and other related services. Drilling fluids are used to maintain well bore stability while drilling, control downhole pressure, lubricate and cool the drill bit, suspend and release cuttings, and transmit hydraulic energy to drilling tools and bit. Wellsite Services provides water and oil based drilling fluids

Portable Power. The Portable Power division provides rental generators, lighting and other accessories for use in the upstream oil and gas industry, refinery and petrochemical operations, construction sites, events, disaster relief and other industries.

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 manufactures wellbore data transmission products used to deliver high-speed communication up and down the drill string.

Customers and Competition. Customers for Wellbore Technologies include major and independent oil and gas companies, national oil companies, drilling and workover contractors, oilfield equipment and product distributors and other manufacturers, oilfield service companies, steel mills, and other industrial companies. The Company’s competitors include: Baker Hughes; Drill Pipe Masters; Frank’s International; Future Pipe; Halliburton; Hanwei; Hilong; Patterson Tubular Services; Precision Tube; ShawCor; Schlumberger; Superior Energy Services; Texas Steel Conversion; Vallourec & Mannesmann and Weatherford International, along with a number of smaller regional competitors.

Completion & Production Solutions

The Company’s Completion & Production Solutions segment integrates technologies for well completions and oil and gas production. The segment designs, manufactures, and sells equipment and technologies needed for hydraulic fracture stimulation, including pressure pumping trucks and pumps, blenders, sanders, hydration units, injection units, flowline, manifolds and wellheads; well intervention, including coiled tubing units, coiled tubing, and wireline units and tools; offshore production, including composite pipe, process equipment, floating production systems and subsea production technologies; and, onshore production including surface transfer and progressive cavity pumps, positive displacement reciprocating pumps, pressure vessels, and artificial lift systems.

Completion & Production Solutions primarily supports service companies and oil and gas companies. Demand for Completion & Production Solutions’ products depends on the level of oilfield completions and workover activity by oilfield service companies and drilling contractors and capital spending plans by oil and gas companies and oilfield service companies.

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 Completion & Production Solutions segment manufactures and sells both coiled tubing units and the ancillary pressure control equipment used in these operations. 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 these products. For example, some well operators are now using coiled tubing in drilling applications such as slim-hole re-entries of existing wells.

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 pressure control equipment which permits 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, and skidded masts for offshore rig-up.

Stimulation Equipment. The Company’s stimulation products include fracturing pumps, acid units, frac blenders, frac control systems, sand handling systems, combo units, hydration and chemical additive systems as well as services and parts. Additionally, the Company sells, services, and rents wellheads, frac trees, portable flow line, and well testing equipment.

Turret Mooring Systems. The Company designs and manufacturers Turret Mooring Systems and Spread Moored Systems, and other products for Floating Production, Storage and Offloading (“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 during production.

Flexible Pipe Systems. The Company designs and manufactures flexible pipe products and systems for the offshore oil and gas industry, including products associated with FPSO’s and other offshore production platforms, as well as subsea production systems including flexible risers, flowlines and jumpers. The product range consists of flexible pipe solutions from 2” – 16”, designed to operate under very demanding offshore conditions in all parts of the world. The products remain flexible even under very high working pressure, up to 1,000 bars, and at the same time they are able to withstand working temperatures from minus 50° centigrade up to +130° centigrade. Flexible pipe systems are superior to other pipe solutions in respect of flexibility, ability to withstand different design conditions and capability to convey challenging mixtures of liquid and gaseous fluids. The Company’s products are qualified for use in water depths down to 2,000 meters. The Company also supplies a wide range of additional equipment such as accessories and steel structures required in a given system configuration.

Fiberglass & Composite Tubulars. The Company designs, manufactures and markets filament-wound and molded fiberglass pipe and fittings as well as spoolable fiberglass pipe. These products are used by a wide range of petroleum, petrochemical and other industrial fluid and gas processing industries; for service station piping systems; 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. Some producers manage the corrosive fluids found in oil and gas fields by utilizing composite or fiberglass tubing, casing and line pipe in their operations. The Company is a provider of high pressure fiberglass tubulars used in oilfield applications to prevent corrosion. The Company manufactures fiberglass pipe under the Star™ brand, and was the first manufacturer of high-pressure fiberglass pipe to be licensed by API in 1992. Fiberspar, which is now part of the Company’s fiberglass 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.

XL Systems. The Company’s XL Systems product line offers the customer an integrated package of large-bore tubular products and services for offshore or deep onshore wells. This product line includes the Company’s proprietary line of wedge thread 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 produces large-bore tubulars with a high-strength, high-fatigue Viper™ weld-on connector for use in deep-water and other environments where an extremely robust connector is needed. The Company also offers service personnel in connection with the installation of all of these products.

Process and Production Technologies. The Company serves its customers in various industrial and oil and gas markets by designing, manufacturing and distributing key products including pumping technologies (reciprocating, multistage surface, and progressive cavity pumps), process equipment (dynamic oil recovery, water treatment, sand handling, separation and crude / gas handling), artificial lift solutions (stuffing boxes, drive heads, PCP, control boxes, polished rod accessories, and hydraulic pumping units), mixing and agitation equipment, heat exchangers, pipeline products (closures, expanding gate valves, and plug valves) and general oilfield products (critical service hookups, pumping tees, and production BOP’s). These products are used by a highly diversified customer base with 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 group supports its international market and customer base through a mixed channel to market model, which includes both direct sales and separate partnership relationships.

Pumps & Expendables. The Company designs, manufactures, and sells pumps and expendables 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 piston and plunger pumps and high pressure mud pumps. 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). The Company offers popular industry brand names including: Wheatley, Gaso, National, Oilwell, MSW, and Omega reciprocating pumps.

Customers and Competition. The primary customers for the products and services offered by the Completion & Productions Solutions segment include well servicing companies, major and independent oil and gas companies, and national oil companies. Competitors include: Cameron International; Circor International; Corpro (a division of ALS); Dover; Drilquip; FMC Technologies; Forum Energy Technologies; GE Oil & Gas; Modec; SBM Offshore; Stewart & Stevenson; Technip; Roper Industries; and Weir Group. There are also a large number of regional competitors and, in addition, the Completion & Production Solutions segment sells its products and services into highly competitive markets. Management believes that on-site support is becoming an 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.

2014 Dispositions, Acquisitions and Other Investments

During 2014, the Company made the following acquisitions:


Acquisition	Form	Operating Segment	Date of Transaction
Industrial Rentals, LLC	Asset	Wellbore Technologies	March 2014
Precision Coatings Group	Asset	Wellbore Technologies	April 2014
NC Machine and Fabrication, Inc.	Asset	Completion & Production Solutions	May 2014
Devin International, Inc. and Greene’s Energia
Servicos do Brasil, Ltda.	Stock	Completion & Production Solutions	June 2014
Condor Engineering and Manufacturing, LLC	Asset	Completion & Production Solutions	July 2014
Halliburton’s Surface Safety Valves	Asset	Completion & Production Solutions	August 2014
Bakker Pipe-En Repair Shop Coevorden BV and Gebr Bakker Coevorden BV	Stock	Wellbore Technologies	September 2014
J&M Machine, LLC	Asset	Wellbore Technologies	October 2014
Artex Group, LLC	Asset	Completion & Production Solutions	December 2014
Profab Engineering, Pte. Ltd., Profab Services,
Pte. Ltd. And PT Profab Indonesia	Stock	Completion & Production Solutions	December 2014

The Company paid an aggregate purchase price of $291 million, net of cash acquired for acquisitions in 2014.

Seasonal Nature of the Company’s Business

Historically, activity levels of some of the Company’s segments have followed seasonal trends to some degree. In general, Rig Systems and Rig Aftermarket have 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 these segments.

In Canada, Wellbore Technologies and Completion & Production Solutions 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 Wellbore Technologies and Completion & Production Solutions 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. Wellbore Technologies and Completion & Production Solutions 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. Wellbore Technologies and Completion & Production Solutions revenues in the Rocky Mountain region sometimes decline in the late fourth quarter or early first quarter due to harsh winter weather. The Company’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 remain the same as in prior years.

Marketing and Distribution Network

Substantially all of Rig Systems’ capital equipment and Rig Aftermarket’s 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 Wellbore Technologies and Completion & Production Solutions are rented and sold worldwide through our own sales force and through commissioned representatives.

The Company’s Rig Systems and Rig Aftermarket segments’ 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. Rig Systems supports land and offshore drillers. Demand for Rig Systems products depends on drilling contractors’ and oil and gas companies’ capital spending plans, specifically capital expenditures on rig construction and refurbishment. Rig Aftermarket supports land and offshore drillers. Demand for Rig Aftermarket products and services primarily depends on overall levels of oilfield drilling activity, which drives demand for spare parts, service, and repair for Rig System’s large installed base of equipment; and secondarily on drilling contractors’ and oil and gas companies’ capital spending plans, specifically capital expenditures on rig refurbishment and re-certification. Rig Systems and Rig Aftermarket 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.

Wellbore Technologies’ customers are predominantly oil and gas companies, drilling contractors, oilfield service companies, and oilfield rental companies. Demand for the Company’s Wellbore Technologies segment products and services primarily depends on the level of oilfield drilling activity by oil and gas companies, drilling contractors, and oilfield service companies.

Completion & Production Solutions’ customers are predominantly service companies and oil and gas companies. Demand for the Company’s Completion & Production Solutions segment products depends on the level of oilfield completions and workover activity by oilfield service companies and drilling contractors and capital spending plans by oil and gas companies and oilfield service companies.

The Company’s foreign operations, which include significant operations in Canada, Europe, the Far East, the Middle East, Africa and Latin America, are subject to the risks normally associated with conducting business in foreign countries, including foreign currency exchange risks and uncertain political and economic environments, which may limit or disrupt markets, restrict the movement of funds or result in the deprivation of contract rights or the taking of property without fair compensation. Government-owned petroleum companies located in some of the countries in which the Company operates have adopted policies (or are subject to governmental policies) giving preference to the purchase of goods and services from companies that are majority-owned by local nationals. As a result of such policies, the Company relies on joint ventures, license arrangements and other business combinations with local nationals in these countries. In addition, political considerations may disrupt the commercial relationship between the Company and such government-owned petroleum companies. Although the Company has not experienced any 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, 2014, the Company held a substantial number of United States patents and had additional 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 2015 to 2034. 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.

Manufacturing and Service Locations

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.

Rig Systems provides drilling rig components, as well as complete land drilling rigs, and offshore drilling equipment packages. The primary manufacturing facilities are located in Houston, Galena Park, Sugar Land and Pampa, Texas; McAlester, Oklahoma; Orange, California; Edmonton, Canada; Kristiansand, Stavanger, Sogne, Oslo and Molde, Norway; Etten-Leur, the Netherlands; Carquefou, France; Mexicali, Mexico; Shanghai, China; and Ulsan, South Korea.

Rig Aftermarket provides comprehensive aftermarket products and services to support land rigs and offshore rigs, and drilling rig components manufactured by Rig Systems. Primary facilities are located in Houston, Texas; Lafayette, and New Iberia, Louisiana; Aberdeen and Montrose, Scotland; Singapore; Dubai, UAE; Port Elizabeth and Cape Town, South Africa; Macae, Brazil and Luanda, Angola.

Wellbore Technologies engineers, manufactures and assembles equipment and products which it rents and sells to customers, and which it uses in providing services. Downhole manufactures at facilities in Houston and Conroe, Texas; Stonehouse and Manchester, U.K; Dubai, UAE; Macaé, Brazil and Singapore. Drill Pipe manufactures at facilities in Navasota, Texas; Veracruz, Mexico; Singapore; Jiangyan and Tianjin, China; Batam Island, Indonesia and Abu Dhabi, UAE. Tuboscope manufactures tubular inspection and coating products for internal use and for resale in Houston, Texas, it also renovates and repairs equipment at its manufacturing facilities in Houston, Celle, Germany and Buenos Aires, Argentina. Well Site Services manufactures the Brandt Solids Control product line in Conroe, Texas and Aberdeen, Scotland, and produces shale shaker screens for use in solids / fluid separation process in facilities located in Conroe; Kuala Lumpur, Malaysia; New Iberia, Louisiana; Leduc, Canada and Victoria, Brazil. IntelliServ buys drill pipe from Grant Prideco’s Navasota, Texas facility and ships it to their facility in Provo, Utah where coax cable is installed. IntelliServ’s engineering team is located at the facility in Provo. Dynamic Drilling Solutions manufactures instrumentation and Etools from Cedar Park, Austin and Stafford, Texas and Andoversford, U.K.

Completion & Productions Solutions integrates technologies for well completions and oil and gas production. Pumps and production process equipment are manufactured at facilities in Houston, Odessa and San Angelo, Texas; Harvey, Louisiana; McAlester and Tulsa, Oklahoma; Manchester and Newcastle, England; Melbourne, Australia; Dubai, UAE: and Buenos Aires, Argentina. Fiberglass and composite tubulars and fittings are manufactured at facilities in Houston, 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. The Company’s well intervention and stimulation equipment business brings together engineering and manufacturing divisions in the areas of coiled tubing, nitrogen pumping, snubbing, pressure control, fracturing, cementing, wireline, and associated engineering services. These products are manufactured in Anderson, Houston and Ft Worth Texas; Lafayette, Louisiana; Duncan, Oklahoma; Aberdeen, Newcastle, and Great Yarmouth, UK; Calgary, Canada; Dubai, UAE; Singapore; Perth, Australia; Minsk, Belarus; and Nievwpoort, NL; Flexible pipe for subsea applications is manufactured in Denmark and Brazil. Certain of the Company’s manufacturing facilities and certain of the Company’s products have various certifications, including, ISO 9001, API, APEX and ASME.

Raw Materials

The Company believes that materials and components used in its servicing and manufacturing operations and purchased for sales are generally available from multiple sources. The prices paid by the Company for its raw materials may be affected by, among other things, energy, steel and other commodity prices; tariffs and duties on imported materials; and foreign currency exchange rates. The Company 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 continue 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 continues to expand its supply base throughout the world to address its customers’ needs. For 2012 through 2014, 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 decreases in steel pricing in 2015. 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 Systems and Completion & Production Solutions segments to guide its planning. Backlog includes orders which typically 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 Rig Systems at December 31, 2014, 2013 and 2012, was $12.5 billion, $15.0 billion and $10.9 billion, respectively. Backlog for Completion & Production Solutions at December 31, 2014, 2013 and 2012 was $1.8 billion, $1.6 billion and $1.3 billion, respectively.

Employees

At December 31, 2014, the Company had a total of 63,642 employees, of which 9,102 were temporary employees. Approximately 741 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 products and services 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 exploration and 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.

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.

There are risks associated with certain contracts for our drilling equipment.

As of December 31, 2014, we had a backlog of capital equipment to be manufactured, assembled, tested and delivered by Rig Systems and Completion & Production Solutions in the amount of $12.5 billion and $1.8 billion, respectively. The following factors, in addition to others not listed, could reduce our margins on these contracts, adversely impact completion of 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;

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

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financial challenges for consumers of our capital equipment; and

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credit market conditions for consumers of our capital equipment.

The Company’s existing contracts for rig equipment generally carry significant down payment and progress billing terms favorable to the ultimate completion of these projects and the majority do not allow customers to cancel projects for convenience. However, unfavorable market conditions or financial difficulties experienced by our customers may result in cancellation of contracts or the delay or abandonment of projects.

Any such developments could have a material adverse effect on our operating results and financial condition.

Competition in our industry could ultimately lead to lower revenues and earnings.

The oilfield products and services industry is highly competitive. We compete with national, regional and foreign competitors in each of our current major product lines. Certain of these competitors may have greater financial, technical, manufacturing and marketing resources than us, and may be in a better competitive position. The following competitive actions can each affect our revenues and earnings:

•

price changes;

•

new product and technology introductions; and

•

improvements in availability and delivery.

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

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

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

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

We have experienced fluctuations in quarterly operating results in the past. We cannot assure that we will realize earnings growth or that earnings in any particular quarter will not fall short of either a prior fiscal quarter or investors’ expectations. The following factors, in addition to others not listed, may affect our quarterly operating results in the future:

•

fluctuations in the oil and gas industry;

•

competition;

•

the ability to service the debt obligations of the Company;

•

the ability to identify strategic acquisitions at reasonable prices;

•

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

•

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

•

the ability to protect our intellectual property rights.

There are risks associated with our presence in international markets, including political or economic instability, currency restrictions, and trade and economic sanctions.

Approximately 70% of our revenues in 2014 were derived from operations outside the United States (based on revenue destination). Our foreign operations include significant operations in Argentina, Canada, Brazil, Europe, the Middle East, China, Africa, Nigeria, Southeast Asia, Russia, Latin America, Libya 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 or oilfield service companies.

Our operations outside the United States could also expose us to trade and economic sanctions or other restrictions imposed by the United States as well as non-U.S. Governmental Regulatory Authorities. The U.S. Department of Justice (“DOJ”), the U.S. Securities and Exchange Commission, other U.S. federal agencies and foreign governmental 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 (“FCPA”), other federal statutes, and foreign anti-bribery, anti-corruption and trade laws. Under U.S. trading sanctions laws, the government authorities 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.

Our ability to comply with the FCPA and foreign anti-bribery laws is dependent on the success of our ongoing compliance program, including our ability to continue to supervise, train and retain competent employees. Our compliance program also depends on the efforts of our employees to comply with applicable law. We could be subject to sanctions and civil and criminal prosecution as well as fines and penalties in the event of a finding of a violation of the FCPA or other anti-corruption laws by us or any of our employees. Compliance with, and changes in, laws could be costly and could affect operating results. In addition, government disruptions could negatively impact our ability to conduct our business.

We have operations in the U.S. and in approximately 70 countries that can be impacted by changes in the legal and business environments in which we operate, including new legislation, new regulations, new policies, investigations and legal proceedings and new interpretations of existing legal rules and regulations, Export control laws or exchange control laws, additional restrictions on doing business in countries subject to sanctions, and changes in laws in countries where we operate or intend to operate all could adversely impact our business .

Further, in some instances, direct or indirect consumers of our products and services, entities providing financing for purchases of our products and services or members of the supply chain for our products and services may become involved in governmental investigations, internal investigations, political or other enforcement matters. In such circumstances, such investigations may adversely impact the ability of consumers of our products, entities providing financial support to such consumers or entities in the supply chain to timely perform their business plans or to timely perform under agreements with us. In the event of such circumstances, our operating results and financial condition may be adversely affected.

Sanctions imposed by the United States, European Union and other countries could adversely impact our business activities in or related to Russia and certain Russian companies, including prohibitions of certain sales of goods and services, delay in executing construction or manufacturing projects, credit risk and adverse impacts due to currency fluctuations (as discussed below). To date, we have not identified any material adverse financial impact to our business from these sanctions. Future trade regulations or sanctions, however, could result in adverse impacts on our operating results and financial condition.

We have received U.S. federal grand jury subpoenas and subsequent inquiries from U.S. governmental agencies requesting records related to our compliance with U.S. 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, purchase assets 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 and the South Korean won. Approximately 70% of our 2014 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 $5,103 million (with a fair value of a net liability of $346 million) as of December 31, 2014, 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 $8.5 billion of goodwill and $0.5 billion of other intangible assets with indefinite lives as of December 31, 2014. 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 indicate they might be impaired. Events or circumstances which could indicate a potential impairment include (but are not limited to) a significant reduction in worldwide oil and gas prices or drilling; a significant reduction in profitability or cash flow of oil and gas companies or drilling contractors; a significant reduction in worldwide well remediation activity; a significant reduction in capital investment by other oilfield service companies; or a significant increase in worldwide inventories of oil or gas. The timing and magnitude of any goodwill impairment charge, which could be material, would depend on the timing and severity of the event or events triggering the charge and would require a high degree of management judgment. If we were to determine that any of our remaining balance of goodwill or other indefinite lived intangible assets was impaired, we would record an immediate charge to earnings with a corresponding reduction in stockholders’ equity; resulting in an increase in balance sheet leverage as measured by debt to total capitalization.

See additional discussion on “Goodwill and Other Indefinite – Lived Intangible Assets” in Critical Accounting Estimates of Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

We could be adversely affected if we fail to comply with any of the numerous federal, state and local laws, regulations and policies that govern environmental protection, zoning and other matters applicable to our businesses.

Our businesses are subject to numerous federal, state and local laws, regulations and policies governing environmental protection, zoning and other matters. These laws and regulations have changed frequently in the past and it is reasonable to expect additional changes in the future. If existing regulatory requirements change, we may be required to make significant unanticipated capital and operating expenditures. We cannot assure you that our operations will continue to comply with future laws and regulations. Governmental authorities may seek to impose fines and penalties on us or to revoke or deny the issuance or renewal of operating permits for failure to comply with applicable laws and regulations. Under these circumstances, we might be required to reduce or cease operations or conduct site remediation or other corrective action which could adversely impact our operations and financial condition.

Our businesses expose us to potential environmental liability.

Our businesses expose us to the risk that harmful substances may escape into the environment, which could result in:

•

personal injury or loss of life;

•

severe damage to or destruction of property; or

•

environmental damage and suspension of operations.

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

•

negligence;

•

strict liability;

•

breach of contract with customers; or

•

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

We may not have adequate insurance for potential environmental liabilities.

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

•

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

•

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

•

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

•

the dollar amount of any liabilities may exceed our policy limits.

Even a partially uninsured claim, if successful and of significant size, could have a material adverse effect on our consolidated financial statements.

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 greater than 10% of total revenue from one of our customers during the years ended December 31, 2013 and 2012.

The loss of this customer (Samsung Heavy Industries) or a significant reduction in its purchases could adversely affect our future revenues and earnings. 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. The Company had revenues of 7% of total revenue from Samsung Heavy Industries for the year ended December 31, 2014.

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.

Tax treatment of spin-off.

The IRS no longer issues private letter rulings regarding whether or not a spin-off transaction qualifies for tax-free treatment under Section 355 of the Code. Notwithstanding the tax opinions we have received from our legal and tax advisors that the distribution of 100% of the shares of NOW Inc. common stock will qualify as tax-free under such section of the Code, the IRS could determine on audit that the distribution should be treated as a taxable transaction, as a result of a significant change in stock or asset ownership after the distribution. If the distribution ultimately is determined to be taxable, we and/or our stockholders that are subject to U.S. federal income tax could incur significant U.S. federal income tax liabilities.

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 approximately 900 facilities worldwide as of December 31, 2014, including the following principal manufacturing, service, distribution and administrative facilities:

Location

Description

Building
Size
(SqFt)

Property
Size
(Acres)

Owned
Leased

Lease
Termination
Date

Rig Systems:

Houston, Texas

Manufacturing Plant of Drilling Equipment

511,964

Leased

4/30/2019

Houston, Texas

West Little York Manufacturing Facility,

483,450

Owned

Repairs, Service, Administrative & Sales Offices

Ulsan, South Korea

Fabrication of Drilling Equipment

380,068

Owned

Orange, California

Manufacturing & Office Facility

351,418

Owned*

12/31/2020

Houston, Texas

Manufacturing, Service, Warehouse &

245,319

Leased

3/31/2018

Administrative Offices (WGB)

Rig Aftermarket:

Houston, Texas

Bammel Facility, Repairs, Service, Parts,

377,750

Leased

6/30/2022

Administrative & Sales Offices

Lafayette, Louisiana

Repair, Services and Spares facility

189,000

Leased

9/28/2025

Aberdeen, Scotland

Pressure Control Manufacturing, Administrative & Sales Offices

188,200

Leased

8/31/2018

Singapore

Manufacturing, Repairs, Service, Field

149,605

Leased

1/5/2024

Service/Training, Administrative & Sales Offices

Dubai, UAE

Repair & Overhaul of Drilling Equipment,

31,633

Owned

Warehouse & Sales Office

Wellbore Technologies:

Navasota, Texas

Manufacturing Facility & Administrative Offices

562,112

196

Owned

Conroe, Texas

Manufacturing Facility of Drill Bits and

341,800

Owned

Downhole Tools, Administrative & Sales Offices

Houston, Texas

Sheldon Road Inspection Facility

319,365

192

Owned

Veracruz, Mexico

Manufacturing Facility of Tool Joints,

303,400

Owned

Warehouse & Administrative Offices

Houston, Texas

Holmes Rd Complex: Manufacturing, Warehouse,

300,000

Owned

Coating Manufacturing Plant & Corporate Office

Cedar Park, Texas

Instrumentation Manufacturing Facility, Administrative & Sales Offices

215,778

Owned

Dubai, UAE

Manufacturing Facility of Downhole Tools, Distribution Warehouse

180,000

Leased

1/29/2021

Conroe, Texas

Solids Control Manufacturing Facility,

153,750

Owned

Warehouse, Administrative & Sales Offices,
and Engineering Labs

Completion & Production Solutions:

Senai, Malaysia

Manufacturing Facility of Fiber Glass Products

595,965

Owned*

Kalundborg, Denmark

Flexibles Manufacturing, Warehouse, Shop & Administrative Offices

485,067

Owned*

Superporto du Acu, Brazil

Flexibles Manufacturing, Warehouse, Shop & Administrative Offices

466737

Owned*

10/20/2031

Manchester, England

Manufacturing, Assembly & Testing of PC Pumps and Expendable Parts, Administrative & Sales Offices

244,000

Owned

Fort Worth, Texas

Coiled Tubing Manufacturing Facility,

233,173

Owned

Warehouse, Administrative & Sales Offices

Tulsa, Oklahoma

Manufacturing Facility of Pumps, Warehouse and Administrative & Sales Offices

212,625

Owned

Houston, Texas

Manufacturing of fiber-reinforced tubular products & Administrative Offices

146,668

Leased

6/30/2016

Corporate:

Houston, Texas

Corporate and Shared Administrative Offices

337,019

Leased

5/31/2017

*	Building owned but land leased.

We own or lease approximately 320 repair and manufacturing facilities that refurbish and manufacture new equipment and parts, 420 service centers that provide inspection and equipment rental and 160 engineering, sales and administration facilities.

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.


	2014								2013
	First		Second		Third		Fourth		First		Second		Third		Fourth
	Quarter		Quarter		Quarter		Quarter		Quarter		Quarter		Quarter		Quarter
Common stock sale price:
High	$	79.81	$	83.47	$	86.43	$	74.54	$	74.14	$	71.57	$	79.83	$	84.30
Low	$	73.03	$	74.19	$	76.10	$	61.55	$	66.26	$	64.14	$	69.40	$	77.77
Cash dividends per share	$	0.26	$	0.46	$	0.46	$	0.46	$	0.13	$	0.26	$	0.26	$	0.26

As of February 12, 2015, there were 3,010 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 $703 million and $389 million for the years ended December 31, 2014 and 2013, 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, future outlook 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.

Share Repurchases

On September 30, 2014, the Company announced that its Board of Directors authorized a share repurchase program to purchase up to $3 billion of the Company’s outstanding common stock. The Company may repurchase its shares on the open market at prevailing market prices. The timing and actual number of shares repurchased will depend on a variety of factors including market conditions and regulatory considerations. The duration of the share repurchase program is 36 months, although it may be increased, extended, suspended or discontinued without prior notice. The Company intends to fund the repurchases using its available U.S. cash balances, which may involve the repatriation of foreign earnings not indefinitely reinvested. However, depending on U.S. cash balances, the Company may choose to borrow against its revolving credit facility, its commercial paper program or new debt issuances to finance the repurchases. As shares are repurchased, they are constructively retired and returned to an unissued state.

Following is a summary of share repurchases for the year ended December 31, 2014:


	Number of				Total Number of Shares
	Shares		Average Price		Purchased as Part of a
Period	Purchased		Per Share		Publicly Announced Plan
November 1 - 30, 2014		3,076,812	$	72.08		3,076,812
December 1 - 31, 2014		8,553,237		65.13		8,553,237

Total		11,630,049	$	66.97		11,630,049

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, 2009 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

12/09

12/10

12/11

12/12

12/13

12/14

National Oilwell Varco, Inc.

100.00

153.97

156.65

158.52

186.71

174.46

S&P 500

100.00

115.06

117.49

136.30

180.44

205.14

S&P Oil & Gas Equipment & Services

100.00

139.28

123.01

160.71

148.18

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,
	2014		2013 (1)		2012 (2)		2011		2010
	(in millions, except per share data)
Operating Data:
Revenue	$	21,440	$	19,221	$	17,194	$	13,475	$	11,101
Operating profit	$	3,613	$	3,199	$	3,389	$	2,809	$	2,363
Income from continuing operations before income taxes	$	3,494	$	3,124	$	3,340	$	2,794	$	2,319
Income from continuing operations	$	2,455	$	2,181	$	2,375	$	1,900	$	1,609
Income from discontinued operations	$	52	$	147	$	108	$	85	$	50
Net income attributable to Company	$	2,502	$	2,327	$	2,491	$	1,994	$	1,667
Per share data:
Basic:
Income from continuing operations	$	5.73	$	5.11	$	5.61	$	4.52	$	3.85

Income from discontinued operations	$	0.12	$	0.35	$	0.25	$	0.21	$	0.14

Net income attributable to Company	$	5.85	$	5.46	$	5.86	$	4.73	$	3.99

Diluted:
Income from continuing operations	$	5.70	$	5.09	$	5.58	$	4.50	$	3.84

Income from discontinued operations	$	0.12	$	0.35	$	0.25	$	0.20	$	0.14

Net income attributable to Company	$	5.82	$	5.44	$	5.83	$	4.70	$	3.98

Cash dividends per share	$	1.64	$	0.91	$	0.49	$	0.45	$	0.41

Other Data:
Depreciation and amortization	$	778	$	738	$	616	$	549	$	503
Capital expenditures	$	699	$	614	$	569	$	479	$	231
Balance Sheet Data:
Working capital	$	8,788	$	9,745	$	10,029	$	6,694	$	5,999
Total assets	$	33,562	$	34,812	$	31,484	$	25,515	$	23,050
Long-term debt, less current maturities	$	3,014	$	3,149	$	3,148	$	159	$	514
Total Company stockholders’ equity	$	20,692	$	22,230	$	20,239	$	17,619	$	15,748

(1)	Financial information for prior periods and dates may not be comparable due to the impact of $2.4 billion in business combinations on our financial position and results of operations during 2013.

(2)	Financial information for prior periods and dates may not be comparable due to the impact of $1.8 billion in business combinations on our financial position and results of operations during 2012.

ITEM 7.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

General Overview

The Company is a leading worldwide provider of highly engineered drilling and well-servicing equipment, products and services to the exploration and production segments of the oil and gas industry. With operations in approximately 900 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; and provide expendables and spare parts used in conjunction with our large installed base of equipment. We also manufacture coiled tubing and 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 Item 1A. “Risk Factors”. We conduct our operations through four business segments: Rig Systems, Rig Aftermarket, Wellbore Technologies and Completion & Production Solutions. See Item 1. “Business”, for a discussion of each of these business segments.

Unless indicated otherwise, results of operations 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 items, operating profit percentage excluding other items, diluted earnings per share excluding other items and operating (non-GAAP) earnings, 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 exploration and production companies and drilling contractors, and worldwide oil and gas inventory levels. Key industry indicators for the past three years include the following:


	2014*		2013*		2012*		% 2014 v 2013			% 2014 v 2012
Active Drilling Rigs:
U.S.		1,862		1,761		1,919		5.7	%		(3.0	%)
Canada		380		354		365		7.3	%		4.1	%
International		1,337		1,296		1,234		3.2	%		8.3	%

Worldwide		3,579		3,411		3,518		4.9	%		1.7	%
West Texas Intermediate Crude Prices (per barrel)	$	93.26	$	97.91	$	94.11		(4.7	%)		(0.9	%)
Natural Gas Prices ($/mmbtu)	$	4.38	$	3.72	$	2.75		17.7	%		59.3	%

*	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, 2014 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 $93.26 in 2014, a decrease of 5% over the average price for 2013 of $97.91 per barrel. The average natural gas price was $4.38 per mmbtu, an increase of 18% compared to the 2013 average of $3.72 per mmbtu. Average rig activity worldwide increased 5% for the full year in 2014 compared to 2013. The average crude oil price for the fourth quarter of 2014 was $73.16 per barrel, and natural gas was $3.77 per mmbtu.

At February 6, 2015, there were 1,456 rigs actively drilling in North America, compared to 1,840 rigs at December 31, 2014; a decrease of 21% from year end 2014 levels. The price of oil decreased to $51.69 per barrel and gas decreased to $2.63 per mmbtu at February 6, 2015, representing a 3% decrease in oil prices and a 12% decrease in gas prices from the end of 2014.

EXECUTIVE SUMMARY

During 2014 National Oilwell Varco, Inc. earned $2.5 billion in income from continuing operations, or $5.70 per fully diluted share. Earnings from continuing operations per diluted share increased 12% from prior year levels of $2.2 billion or $5.09 per fully diluted share. Excluding other items (as defined in the “Non-GAAP Financial Measures and Reconciliations” in Results of Operations) from both years, diluted earnings per share of $6.07 in 2014 increased 17% from $5.17 per share in 2013.

During 2014 revenue grew 12% from 2013, to $21.4 billion, and operating profit increased 13% from 2013, to $3.6 billion. Generally, 2014 benefitted from higher international drilling activity, which saw international rig counts (as measured by Baker Hughes) increase 3% from 2013. This enabled all four of the Company’s reporting segments to post higher year-over-year revenues in 2014.

For its fourth quarter ended December 31, 2014, the Company generated $597 million in net income from continuing operations, or $1.39 per fully diluted share, on $5.7 billion in revenue. Compared to the third quarter of 2014 revenue increased $122 million or 2% and net income from continuing operations decreased $104 million. Compared to the fourth quarter of 2013, revenue increased $407 million or 8%, and net income from continuing operations decreased $33 million or 5%.

During the fourth quarter of 2014, third quarter of 2014, and fourth quarter of 2013, pre-tax other items were $105 million, $1 million and $16 million, respectively. Excluding the other items from all periods, fourth quarter 2014 earnings were $1.69 per fully diluted share, compared to $1.62 per fully diluted share in the third quarter of 2014 and $1.49 per fully diluted share in the fourth quarter of 2013.

Operating profit excluding other items was $1,018 million or 17.8% of sales in the fourth quarter of 2014, compared to $989 million or 17.7% of sales in the third quarter of 2014, and $925 million or 17.4% of sales in the fourth quarter of 2013.

On May 30, 2014, the Company completed the previously announced spin-off of its distribution business into an independent public company named NOW Inc., which trades on the New York Stock Exchange under the symbol “DNOW”. After the close of the New York Stock Exchange on May 30, 2014, the stockholders of record as of May 22, 2014 (the “Record Date”) received one share of NOW Inc. common stock for every four shares of NOV common stock they held as of the Record Date. No fractional shares of NOW Inc. common stock were distributed. The transfer agent aggregated any fractional shares into whole shares, sold those whole shares in the open market at prevailing rates and distributed the net cash proceeds, after deducting any taxes required to be withheld and brokerage charges and commissions, pro rata to each holder who would otherwise have been entitled to receive fractional shares in the distribution. Our operating segments were realigned upon separation of NOW Inc., and as a result, all prior periods are presented on this basis. Results of operations related to NOW Inc. have been classified as discontinued operations in all periods presented on Form 10-K.

Oil & Gas Equipment and Services Market

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 late 2008 and into 2009, the availability of credit tightened as major financial institutions wrote-down significant housing-related assets, leading to a credit-driven worldwide economic recession. Developed economies struggled to recover throughout 2010 and 2011, facing additional economic hardships related to potential sovereign debt defaults in Europe. As a result, commodity prices, including oil and gas prices, were volatile.

As the global economy began to improve, oil prices strengthened enabling a steady increase in worldwide drilling activity during the past three years. While natural gas prices initially recovered as well, prices fell to recent lows in 2012 as supply increased due in part to higher production of unconventional shale reservoir developments in North America. Drillers then redirected their efforts towards unconventional shale plays targeting oil, rather than gas, further contributing to the rise in oil-drilling activity. For the fourth quarter of 2014, oil-directed drilling accounted for over 80% of the total domestic drilling effort.

For the majority of 2014 oil prices and the number of rigs actively drilling worldwide, continued their upward trend. Increased global demand had helped sustain relatively high oil prices and worldwide drilling activity. Within the same time frame, technological improvements in drilling and extraction had unlocked formations that were previously unproduceable, especially in North America. Global supply started to catch up to demand, creating a relatively balanced market. In the second half of 2014, demand in areas such as Asia, Europe and the U.S. weakened, while drilling and production activity held steady. As opposed to limiting supply to stabilize prices, OPEC responded by maintaining similar production levels. As a result, oil prices fell significantly to levels not seen since 2009.

Segment Performance

Rig Systems

The Company’s Rig Systems segment generated $9.8 billion in revenues and $2.0 billion in operating profit, or 20.3% of sales, during 2014. Compared to the prior year, revenues improved 17% and operating profit dollars increased 25% year-over-year. For the fourth quarter of 2014, the segment generated $2.6 billion in revenues and $511 million in operating profit, or 20.0% of sales. Compared to the prior quarter, revenues decreased $98 million or 4%, and operating profit decreased $22 million or 4%. Compared to the fourth quarter of 2013, segment revenues grew $164 million or 7%, and operating profit increased $58 million or 13%. Revenue out of backlog decreased 5% sequentially and increased 7% year-over-year. Orders for three jackup related drilling equipment packages, five land rig equipment packages as well as some offshore and land components contributed to total order additions to backlog of $0.5 billion during the fourth quarter. Year-end backlog for the segment was $12.5 billion a 13% decline sequentially and a 17% decrease year-over-year.

Rig Aftermarket

The Company’s Rig Aftermarket segment generated $3.2 billion in revenues and $882 million in operating profit, or 27.4% of sales, during 2014. Compared to the prior year, revenues improved 20% while operating profit dollars increased 21% year-over-year. For the fourth quarter of 2014, the segment generated $850 million in revenues and $245 million in operating profit, or 28.8% of sales. Compared to the prior quarter, revenues increased $13 million or 2%, and operating profit increased $16 million or 7%. Compared to the fourth quarter of 2013, segment revenues increased $91 million or 12%, and operating profit increased $49 million or 25%. Revenues have increased year-over-year since 2009 on increased demand as the installed base of NOV equipped rigs requiring spare parts, repairs and services has grown. Internal capacity expansions and acquisitions have enabled the group to increase production to better accommodate the large installed base of drilling equipment.

Wellbore Technologies

The Company’s Wellbore Technologies segment generated $5.7 billion in revenue and $937 million in operating profit, or 16.4% of sales, for the full year 2014. Compared to the prior year, revenue increased $511 million and operating profit increased $22 million. For the fourth quarter of 2014, the segment generated $1.5 billion in revenue and $172 million in operating profit, or 11.2% of sales. Compared to the prior quarter, revenue increased $60 million or 4%, and operating profit decreased $106 million. Compared to the fourth quarter of 2013, revenues increased $158 million, and operating profit decreased $71 million. Revenues increased in correlation with higher levels of worldwide drilling activity, which required and consumed more of the segment’s services and product offerings. Year-over-year operating margins declined mainly due to the $104 million impairment charge related to certain indefinite-lived trade names.

Completion & Production Solutions

The Company’s Completion & Production Solutions segment generated $4.6 billion in revenue and $690 million in operating profit, or 14.9% of sales, for the full year 2014. Compared to the prior year, revenue increased 8% and operating profit increased $77 million. Year-over-year revenue increases were attributable to deliveries of intervention and stimulation equipment, floating production equipment, subsea equipment as well as higher incremental sales of fiberglass and composite pipe. For the fourth quarter of 2014, the segment generated $1.3 billion in revenue and $214 million in operating profit, or 16.2% of sales. Compared to the prior quarter, revenue increased $134 million or 11%, and operating profit increased $31 million or 17%. Sequentially, revenues grew on the progression of major floating production projects and increased drilling activity in North America, which enabled record quarterly sales of fiberglass and composite pipe and near record sales of intervention and stimulation equipment. Compared to the fourth quarter of 2013, revenues increased $170 million and operating profit increased $31 million as higher levels of worldwide drilling activity resulted in additional sales in most product lines. For the fourth quarter of 2014, approximately 47% of the segment’s sales were into North American markets, and 53% of sales were into international markets.

Outlook

Beginning in the latter half of 2014, lower commodity prices and lower rig counts presented increasingly challenging prospects to our business as declining dayrates stressed drilling contractors’ and well service firms’ ability to deliver a strong return on invested capital. Consequently, we are cautious in our outlook for 2015, and expect to see revenues out of backlog exceed orders for new rigs and components in our Rig Systems segment, resulting in a book-to-bill ratio well below one for the year. Thinking longer-term, in a low oil price environment, contractors become more hesitant to invest in older rigs which are far less productive and competitive. As a result, the industry expects to see a large number of rigs retired during this cyclical downturn, which could result in a newbuild order recovery when commodity prices recover and drilling activity responds. We expect sales of parts, repair work and service to decline year-over-year in the Rig Aftermarket segment as our customers defer expenditures in favor of cannibalizing idle rigs. However, the growing installed base of NOV equipped rigs may allow the group to partially mitigate the expected activity decline.

Drilling activity is expected to continue to decline in this cyclical downturn during the first part of 2015, and as a result, our outlook for the Company’s Wellbore Technologies and Completion and Production Solutions segments remains cautious. In order to keep contracted rigs running, our customers could begin to reposition components and consumables, including drill pipe, bits, jars and shakers off of idle rigs within their fleets, as opposed to placing new orders for these items with NOV. Drilling consumes rigs, and the rate of capital equipment and consumables consumption will decline with drilling activity, while customers will live off of current inventory and postpone maintenance and upgrades when possible. However, this behavior is not sustainable over the long term. When customers exhaust current on-hand inventory, demand could recover for the equipment and services NOV provides once drilling activity recovers.

The Company expects to manage through this uncertain period, and should benefit from its strong balance sheet and capitalization, access to credit, and a high level of contracted orders which are expected to continue to generate good earnings well into this cyclical downturn. The Company has a long history of cost-control and downsizing in response to depressed market conditions, and of executing strategic acquisitions during difficult periods. As in prior cyclical downturns, we expect to manage our business efficiently through insourcing certain manufacturing processes and developing new products and technologies, while continuing to pursue acquisition opportunities to support our strategic objectives.

Results of Operations

Years Ended December 31, 2014 and December 31, 2013

The following table summarizes the Company’s revenue and operating profit by operating segment in 2014 and 2013 (in millions):


	Years Ended December 31,						Variance
	2014			2013			$			%
Revenue:
Rig Systems	$	9,848		$	8,450		$	1,398			16.5	%
Rig Aftermarket		3,222			2,692			530			19.7	%
Wellbore Technologies		5,722			5,211			511			9.8	%
Completion & Production Solutions		4,645			4,309			336			7.8	%
Eliminations		(1,997	)		(1,441	)		(556	)		38.6	%

Total Revenue	$	21,440		$	19,221		$	2,219			11.5	%

Operating Profit:
Rig Systems	$	1,996		$	1,594		$	402			25.2	%
Rig Aftermarket		882			729			153			21.0	%
Wellbore Technologies		937			915			22			2.4	%
Completion & Production Solutions		690			613			77			12.6	%
Eliminations and other		(892	)		(652	)		(240	)		36.8	%

Total Operating Profit	$	3,613		$	3,199		$	414			12.9	%

Operating Profit %:
Rig Systems		20.3	%		18.9	%
Rig Aftermarket		27.4	%		27.1	%
Wellbore Technologies		16.4	%		17.6	%
Completion & Production Solutions		14.9	%		14.2	%
Total Operating Profit %		16.9	%		16.6	%

Rig Systems

Revenue from Rig Systems for the year ended December 31, 2014 was $9,848 million, an increase of $1,398 million (16.5%) compared to the year ended December 31, 2013. Increased demand for high-spec land rigs and equipment resulted in higher revenues for Rig Systems in 2014. In addition, increased capacity enabled Rig Systems to generate revenue out of backlog of $8,689 million during 2014, compared to revenue out of backlog of $7,385 million during 2013.

Operating profit from Rig Systems was $1,996 million for the year ended December 31, 2014, an increase of $402 million (25.2%) compared to 2013. Operating profit percentage increased to 20.3%, from 18.9% in 2013. Increased demand for high-spec land rigs and equipment generated higher operating profit percentages.

Included in operating profit are certain Other items which include items such as transaction costs and inventory that was stepped up during purchase accounting. Other items included in operating profit for Rig Systems were nil for the year ended December 31, 2014 and $21 million for the year ended December 31, 2013.

Rig Systems 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 $12.5 billion at December 31, 2014, a decrease of $2.5 billion (17%) from backlog of $15.0 billion at December 31, 2013.

Rig Aftermarket

Revenue from Rig Aftermarket for the year ended December 31, 2014 was $3,222 million, an increase of $530 million (19.7%) compared to the year ended December 31, 2013. This increase is primarily due to increased demand for spare parts, repairs and services as a result of high levels of drilling activity and our large installed base of equipment.

Operating profit from Rig Aftermarket was $882 million for the year ended December 31, 2014, an increase of $153 million (21.0%) compared to 2013. Operating profit percentage increased slightly to 27.4%, from 27.1% in 2013.

Wellbore Technologies

Revenue from Wellbore Technologies for the year ended December 31, 2014 was $5,722 million, an increase of $511 million (9.8%) compared to the year ended December 31, 2013. This increase is primarily due to a strengthening in the U.S. market coupled with the fact that customers worked through excess inventory that they had carried into 2013.

Operating profit from Wellbore Technologies was $937 million for the year ended December 31, 2014 compared to $915 million for 2013, an increase of $22 million (2.4%). Operating profit percentage decreased to 16.4% from 17.6% in 2013. Operating profit decreased mainly due to a $104 million impairment charge incurred on the carrying value of certain indefinite-lived trade names associated with this segment in the fourth quarter of 2014.

Included in operating profit are certain Other items which include items such as impairment charges, transaction costs and the amortization of inventory that was stepped up during purchase accounting. Other items included in operating profit for Wellbore Technologies were $110 million for the year ended December 31, 2014 and $41 million for the year ended December 31, 2013.

Completion & Production Solutions

Revenue from Completion & Production Solutions for the year ended December 31, 2014 was $4,645 million, an increase of $336 million (7.8%) compared to the year ended December 31, 2013. The increase in revenue was primarily driven by increased demand for well intervention and stimulation equipment, fiberglass pipe, and continued growth in both our floating production and subsea businesses.

Operating profit from Completion & Production Solutions was $690 million for the year ended December 31, 2014 compared to $613 million for 2013, an increase of $77 million (12.6%). Operating profit percentage increased to 14.9% from 14.2% in 2013. This increase was primarily related to lower integration costs during 2014 compared to 2013 offset by a decrease in operating profit percentage due to product mix with increased revenues from floating production and subsea products.

Included in operating profit are certain Other items which include items such as transaction costs and the amortization of assets that were stepped up during purchase accounting. Other items included in operating profit for Completion & Production Solutions were $10 million for the year ended December 31, 2014 and $82 million for the year ended December 31, 2013.

Completion & Production Solutions 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 components or a signed contract related to a construction project. The capital equipment backlog was $1.8 billion at December 31, 2014, an increase of $0.2 million (12%) from backlog of $1.6 billion at December 31, 2013.

Eliminations

Eliminations in operating profit were $892 million for the year ended December 31, 2014 compared to $652 million for the year ended December 31, 2013. This increase was primarily due to increased intercompany sales activity for all segments resulting in higher intersegment eliminations. Sales from one segment to another generally are priced at estimated equivalent commercial selling prices; however, segments originating an external sale are credited with the full profit to the Company. Eliminations include intercompany transactions conducted between the four reporting segments that are eliminated in consolidation. Intercompany transactions within each reporting segment are eliminated within each reporting segment.

Other income (expense), net

Other income (expense), net were expenses of $90 million for the year ended December 31, 2014 compared to expenses of $39 million for the year ended December 31, 2013. The increase was primarily due to losses on the sale of certain non-core industrial assets as well as increased bank fees, partially offset by foreign exchange gains.

Provision for income taxes

The effective tax rate for the year ended December 31, 2014 was 29.7%, compared to 30.2% for 2013. 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, a reduction in valuation allowance on deferred taxes, and the deduction in the U.S. for manufacturing activities. The effective tax rate was negatively impacted by foreign dividends net of foreign tax credits, and nondeductible expenses.

Years Ended December 31, 2013 and December 31, 2012

The following table summarizes the Company’s revenue and operating profit by operating segment in 2013 and 2012 (in millions):


	Years Ended December 31,						Variance
	2013			2012			$			%
Revenue:
Rig Systems	$	8,450		$	7,077		$	1,373			19.4	%
Rig Aftermarket		2,692			2,138			554			25.9	%
Wellbore Technologies		5,211			5,184			27			0.5	%
Completion & Production Solutions		4,309			3,994			315			7.9	%
Eliminations		(1,441	)		(1,199	)		(242	)		20.2	%

Total Revenue	$	19,221		$	17,194		$	2,027			11.8	%

Operating Profit:
Rig Systems	$	1,594		$	1,685		$	(91	)		(5.4	%)
Rig Aftermarket		729			594			135			22.7	%
Wellbore Technologies		915			983			(68	)		(6.9	%)
Completion & Production Solutions		613			684			(71	)		(10.4	%)
Eliminations and other		(652	)		(557	)		(95	)		17.1	%

Total Operating Profit	$	3,199		$	3,389		$	(190	)		-5.6	%

Operating Profit %:
Rig Systems		18.9	%		23.8	%
Rig Aftermarket		27.1	%		27.8	%
Wellbore Technologies		17.6	%		19.0	%
Completion & Production Solutions		14.2	%		17.1	%
Total Operating Profit %		16.6	%		19.7	%

Rig Systems

Revenue from Rig Systems for the year ended December 31, 2013 was $8,450 million, an increase of $1,373 million (19.4%) compared to the year ended December 31, 2012. Deepwater offshore demand as well as demand in international markets continues to be a driving force for the increase in revenue for Rig Systems as revenue out of backlog contributed $7,385 million in 2013. Increased sales of individual capital components and the acquisition of Robbins & Myers also contributed to the increase in revenue for Rig Systems. North American markets continue to see a decrease in demand for land drilling equipment. This is evidenced by a decrease in rig count in North America from 2012 and has resulted in a steady decline in sales of land rigs in the U.S. and Canada. The average rig count in the U.S. for the year ended 2013 decreased over 8% compared to the year ended 2012 and decreased 3% in Canada over the same period.

Operating profit from Rig Systems was $1,594 million for the year ended December 31, 2013, a decrease of $91 million (5.4%) compared to 2012. Operating profit percentage decreased to 18.9%, from 23.8% in 2013. The decrease in operating profit percentage continues to be primarily due to a shift in product mix as lower priced offshore projects replace projects contracted at higher prices in 2007 and 2008. In addition, our shipyard customers are compressing delivery schedules which have been leading to increased freight and personnel costs. Expenses associated with acquisition integration efforts, numerous strategic growth initiatives and capacity expansions worldwide have also contributed to the decrease in operating profit percentage.

Included in operating profit are certain Other items which include items such as transaction costs and inventory that was stepped up during purchase accounting. Other items included in operating profit for Rig Systems were $21 million for the year ended December 31, 2013 and nil for the year ended December 31, 2012.

The Rig Systems 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 $15.0 billion at December 31, 2013, an increase of $4.1 billion (38%) from backlog of $10.9 billion at December 31, 2012.

Rig Aftermarket

Revenue from Rig Aftermarket for the year ended December 31, 2013 was $2,692 million, an increase of $554 million (25.9%) compared to the year ended December 31, 2012. A growing installed base of NOV equipped rigs needing replacement parts and repair work, a fleet that continues to require re-certifications and additional aftermarket work required to comply with post Macondo regulations were the primary driving forces for the increase in revenue for this segment during 2013. North American markets continue to see a decrease in demand for land drilling equipment. This is evidenced by a decrease in rig count in North America from 2012 and has resulted in a steady decline in sales of land rigs in the U.S. and Canada. The average rig count in the U.S. for the year ended 2013 decreased over 8% compared to the year ended 2012 and decreased 3% in Canada over the same period.

Operating profit from Rig Aftermarket was $729 million for the year ended December 31, 2013, an increase of $135 million (22.7%) compared to 2012. Operating profit percentage decreased to 27.1%, from 27.8% in 2013. This decrease is attributed to the overall decline in the North America market activity which has led to pricing pressures and reduced operating profit percentage for the repair business. Operating profit percentage was also impacted in the North America with the integration of the Robbins & Myers repair business.

Wellbore Technologies

Revenue from Wellbore Technologies for the year ended December 31, 2013 was $5,211 million, an increase of $27 million (0.5%) compared to the year ended December 31, 2012. A nonrecurring gain of $102 million was recognized in the third quarter of 2013 related to a legal settlement. Offsetting this gain was lower revenue primarily due to lower North American drilling activity.

Operating profit from Wellbore Technologies was $915 million for the year ended December 31, 2013 compared to $983 million for 2012, a decrease of $68 million (6.9%). Operating profit percentage decreased to 17.6% from 19.0% in 2013. This decrease is primarily due to the overall decline in North American market activity which has led to pricing pressures across a number of products in the North American land market, as well as volume declines. Expenses associated with integrating recently acquired companies also contributed to the decrease in operating profit percentages.

Included in operating profit are certain Other items which include items such as transaction costs and the amortization of inventory that was stepped up during purchase accounting. Other items included in operating profit for Wellbore Technologies were $41 million for the year ended December 31, 2013 and nil for the year ended December 31, 2012.

Completion & Production Solutions

Revenue from Completion & Production Solutions for the year ended December 31, 2013 was $4,309 million, an increase of $315 million (7.9%) compared to the year ended December 31, 2012. The increase is primarily due to the acquisition of Robbins & Myers during the first quarter of 2013, as well as having a full year of NOV Flexibles which was acquired in June of 2012. This was offset by the decline in pressure pumping equipment resulting from reduced capital spending by service companies.

Operating profit from Completion & Production Solutions was $613 million for the year ended December 31, 2013 compared to $684 million for 2012, a decrease of $71 million (10.4%). Operating profit percentage decreased to 14.2% from 17.1% in 2013. This decrease is primarily due to the overall decline in North American market activity which led to pricing pressures across a number of product lines, as well as volume declines affecting efficiencies. Expenses associated with integrating recently acquired companies as well as start-up expenses for our NOV Flexibles Brazil plant also contributed to the decrease in operating profit percentages.

Included in operating profit are certain Other items which include items such as transaction costs and the amortization of assets that were stepped up during purchase accounting. Other items included in operating profit for Completion & Production Solutions were $82 million for the year ended December 31, 2013 and $90 million for the year ended December 31, 2012.

The Completion & Production Solutions 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 components or a signed contract related to a construction project. The capital equipment backlog was $1.6 billion at December 31, 2013, an increase of $0.3 million (23%) from backlog of $1.3 billion at December 31, 2012.

Eliminations

Eliminations in operating profit were $652 million for the year ended December 31, 2013 compared to $557 million for the year ended December 31, 2012. This increase was primarily due to increased intercompany sales activity for all segments resulting in higher intersegment eliminations. Sales from one segment to another generally are priced at estimated equivalent commercial selling prices; however, segments originating an external sale are credited with the full profit to the Company. Eliminations include intercompany transactions conducted between the four reporting segments that are eliminated in consolidation. Intercompany transactions within each reporting segment are eliminated within each reporting segment.

Interest and financial costs

Interest and financial costs were $111 million for the year ended December 31, 2013 compared to $49 million for the year ended December 31, 2012. This increase is primarily due to an overall increase in average debt during 2013 compared to 2012.

Equity Income in Unconsolidated Affiliates

Equity income in unconsolidated affiliates was $63 million for the year ended December 31, 2013 compared to $58 million for the year ended December 31, 2012. 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 $39 million for the year ended December 31, 2013 compared to expenses of $68 million for the year ended December 31, 2012. The change was primarily due to gains on the sale of certain assets during the second quarter of 2013, offset by foreign exchange losses and increased bank charges and fees.

Provision for income taxes

The effective tax rate for the year ended December 31, 2013 was 30.2%, compared to 28.9% for 2012. 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, that is considered to be permanently reinvested, a reduced tax rate in the U.K. and Norway, and the deduction in the U.S. for manufacturing activities. The effective tax rate was negatively impacted by foreign dividends net of foreign tax credits, foreign exchange gains for tax reporting in Norway, and the recognition of increased valuation allowances on certain deferred tax assets associated with excess foreign tax credits carried to future periods.

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 items, (ii) operating profit percentage excluding other items, (iii) diluted earnings per share excluding other items and operating (non-GAAP) earnings. Each of these financial measures excludes the impact of certain amounts as further identified below and 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,			Years Ended December 31,
	2014			2013			2014			2014			2013			2012
Reconciliation of operating profit:
GAAP operating profit	$	913		$	909		$	988		$	3,613		$	3,199		$	3,389
Litigation gain (1):
Wellbore Technologies		—			—			—			—			(102	)		—
Other costs (2):
Rig Systems		—			5			—			—			21			—
Rig Aftermarket		—			—			—			—			—			—
Wellbore Technologies		104			2			—			110			41			—
Completion & Production Solutions		1			9			(1	)		10			82			90
Eliminations and other		—			—			2			36			2			41

Operating profit excluding other items	$	1,018		$	925		$	989		$	3,769		$	3,243		$	3,520


	Three Months Ended									Years Ended December 31,
	December 31,						September 30,			Years Ended December 31,
	2014			2013			2014			2014			2013			2012
Reconciliation of operating profit %:
GAAP operating profit %		16.0	%		17.1	%		17.7	%		16.9	%		16.6	%		19.7	%
Other items %		1.8	%		0.3	%		0.0	%		0.7	%		0.4	%		0.8	%

Operating profit % excluding other items		17.8	%		17.4	%		17.7	%		17.6	%		17.0	%		20.5	%


	Three Months Ended									Years Ended December 31,
	December 31,						September 30,			Years Ended December 31,
	2014			2013			2014			2014			2013			2012
Reconciliation of diluted earnings per share:
GAAP earnings per share (continuing operations)	$	1.39		$	1.46		$	1.62		$	5.70		$	5.09		$	5.58
Litigation gain (1)		—			—			—			—			(0.17	)		—
Other costs (2)		0.30			0.03			—			0.37			0.25			0.17
Tax Benefits (3)		—			—			—			—			—			(0.16	)

Earnings per share excluding other items		1.69			1.49			1.62			6.07			5.17			5.59
Amortization of intangible assets per share		0.15			0.15			0.14			0.57			0.57			0.48

Operating (non-GAAP) earnings per share	$	1.84		$	1.64		$	1.76		$	6.64		$	5.74		$	6.07

(1)	Included in Wellbore Technologies revenue and operating profit for the year ended December 31, 2013, is a $102 million gain resulting from a legal settlement.

(2)

Other items primarily include items such as impairment charges, transaction costs and the amortization 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 and for the year ended December 31, 2014, Other items included in operating profit were $105 million and $156 million, respectively. For the three months and for the year ended December, 2013, Other items included in operating profit were $16 million and $146 million, respectively. Other items for the three months ended September 30, 2014 totaled $1 million. Other items that are included in other income (expense), net were $58 million for each of the three months and for the year ended December 31, 2014, respectively; nil and $9 million for the three months and for the year ended December 31, 2013, respectively; and nil for the three months ended September, 2014.

(3)	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 including capital expenditures, debt and interest payments and dividend payments for the foreseeable future.

At December 31, 2014, the Company had cash and cash equivalents of $3,536 million, and total debt of $3,166 million. At December 31, 2013, cash and cash equivalents were $3,436 million and total debt was $3,150 million. 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 $3,536 million of cash and cash equivalents at December 31, 2014, approximately $2,979 million is held outside the U.S. If opportunities to invest in the U.S. are greater than available cash balances, the Company may choose to borrow against its $3.5 billion revolving credit facility. In August 2013, the Company initiated a commercial paper program, supported by its revolving credit facility.

The Company’s outstanding debt at December 31, 2014 was $3,166 million and consisted of $151 million in 6.125% Senior Notes, $500 million in 1.35% Senior Notes, $1,396 million in 2.60% Senior Notes, $1,096 million in 3.95% Senior Notes, and other debt of $23 million.

At December 31, 2014, there were $1,019 million in outstanding letters of credit issued, resulting in $2,481 million of funds available under the Company’s revolving credit facility.

The Company also had $2,969 million of additional outstanding letters of credit at December 31, 2014, primarily in Norway, that are under various bilateral committed letter of credit facilities. Other letters of credit are issued as bid bonds, advance payment bonds and performance bonds.

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


	Years Ended December 31,
	2014			2013			2012
Net cash provided by continuing operating activities	$	2,525		$	3,080		$	632
Net cash used in continuing investing activities		(1,092	)		(2,910	)		(2,301	)
Net cash provided by (used in) continuing financing activities		(1,343	)		(304	)		2,584

Operating Activities

2014 vs 2013. Net cash provided by continuing operating activities was $2,525 million in 2014 compared to net cash provided by continuing operating activities of $3,080 million in 2013. Before changes in operating assets and liabilities, net of acquisitions, cash was provided by operations primarily through net income from continuing operations of $2,455 million plus non-cash charges of $484 million and a $73 million 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 $794 million in 2014 compared to $350 million provided in 2013. Due to an increase in market activity during 2014 compared to 2013, revenue and backlog increased which is reflected in increased accounts receivable as well as a buildup in inventory. Increased market activity during 2014 also resulted in higher taxes paid, 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.

2013 vs 2012. Net cash provided by continuing operating activities was $3,080 million in 2013 compared to net cash provided by continuing operating activities of $632 million in 2012. Before changes in operating assets and liabilities, net of acquisitions, cash was provided by operations primarily through net income from operations of $2,181 million plus non-cash charges of $402 million and a $66 million dividend received from Voest-Alpine Tubulars, an unconsolidated affiliate, less $63 million in equity income. Net changes in operating assets and liabilities, net of acquisitions, provided $350 million in 2013 compared to $2,404 million used in 2012. This shift was primarily the result of increased cash collections in 2013, as prepayments and milestone invoicing outpaced costs incurred on projects. Further, greater fourth quarter 2013 equipment and product sales combined with improved inventory management lead to a $396 million inventory reduction in 2013. Cash tax payments in 2013 were also down compared to 2012.

Investing Activities

2014 vs 2013. Net cash used in continuing investing activities was $1,092 million in 2014 compared to net cash used in continuing investing activities of $2,910 million in 2013. Net cash used in continuing investing activities continued to be the result of acquisition activity as well as capital expenditures. The Company used approximately $291 million for acquisitions in 2014, a significant decrease compared to approximately $2.4 billion for the purpose of acquiring Robbins & Myers during 2013. Capital expenditures however increased to $699 million during 2014 compared to $614 million during 2013. In addition, the Company’s cash and cash equivalents decreased $253 million as a result of the spin-off of its distribution business on May 30, 2014.

2013 vs 2012. Net cash used in continuing investing activities was $2,910 million in 2013 compared to net cash used in continuing investing activities of $2,301 million in 2012. Net cash used in investing activities continued to primarily be the result of acquisition activity and capital expenditures. The Company used approximately $2.5 billion for the purpose of acquiring Robbins & Myers during the first quarter of 2013. For the acquisition of Robbins & Myers, 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. By the end of 2013, the Company repaid all of $1.4 billion initially borrowed under its revolving credit facility. Due to the continued growth in the Company worldwide both organically and through acquisitions, the Company used $614 million during 2013 for capital expenditures compared to $569 million in 2012.

Financing Activities

2014 vs 2013. Net cash used in continuing financing activities was $1,343 million in 2014 compared to $304 million in 2013. The increase was primarily due to increased dividend payments and the implementation of a share repurchase program. The change was partially offset by increased proceeds from stock options exercised to $108 million during 2014, from $58 million during 2013.

2013 vs 2012. Net cash used in continuing financing activities was $304 million in 2013 shifting from net cash provided by continuing financing activities of $2,584 million in 2012. The change was primarily due to a decrease in net borrowings during 2013 and the Company receiving lower proceeds from stock options exercised compared to 2012. In addition, the Company doubled its quarterly dividend beginning in the second quarter of 2013.

Other

The effect of the change in exchange rates on cash flows was a decrease of $67 million, a decrease of $11 million and an increase of $9 million for the years ended December 31, 2014, 2013 and 2012, 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 revolving 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, 2014 is as follows (in millions):


			Payment Due by Period
			Less
	Total		than 1 Year		1-3 Years		4-5 Years		After 5 Years
Contractual Obligations:
Total debt	$	3,166	$	152	$	502	$	—	$	2,512
Operating leases		1,071		215		261		150		445

Total Contractual Obligations	$	4,237	$	367	$	763	$	150	$	2,957

Commercial Commitments:
Standby letters of credit	$	3,989	$	2,181	$	1,549	$	152	$	107

As of December 31, 2014, the Company entered into a capital lease agreement covering a period of 25 years, totaling approximately $230 million. This lease becomes effective in 2016.

As of December 31, 2014, the Company had $115 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; purchase price allocation of acquisitions; 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 Systems 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, 2013 and 2012 adjustments (representing the differences between the estimated and actual results) to all outstanding contracts resulted in net decreases to gross profit margins of 0.19% ($26 million on $13.8 billion of outstanding contracts) and 0.69% ($58 million on $8.4 billion of outstanding contracts) for the years ended December 31, 2014 and 2013, 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 $15 billion at December 31, 2014.

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, 2014 and 2013, allowance for bad debts totaled $125 million and $132 million, or 2.7% and 2.6% 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, 2014 and 2013, inventory reserves totaled $370 million and $396 million, or 6.7% and 6.6% 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 based on estimated future undiscounted cash flows. 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. During the review of its 2014 annual impairment test, the calculated fair values for all of the Company’s reporting units were in excess of the respective reporting unit’s carrying value. Also, the fair value for all of the Company’s intangible assets with indefinite lives were in excess of the respective asset carrying values, with two exceptions. These intangible assets, which represent indefinite-lived trade names within the Company’s Wellbore Technologies segment, had a calculated fair value approximately $104 million below carrying value. The impairment charge was primarily the result of the substantial decline in oil prices during the fourth quarter of 2014, declines in forecasts in rig activity for 2015, and a decline in the revenue forecast for the segment for 2015.

Based on its analysis, the Company did not report any impairment of goodwill and other indefinite-lived intangible assets, other than those mentioned above, for the years ended December 31, 2014, 2013 and 2012.

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. 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 recognizes them when they are incurred. At December 31, 2014 and 2013, service and product warranties totaled $272 million and $228 million, respectively.

Income Taxes

The Company is a U.S. registered company and is subject to income taxes in the U.S. The Company operates through various subsidiaries in a number of countries throughout the world. Income taxes have been provided based upon the tax laws and rates of the countries in which the Company operates and income is earned.

The Company’s annual tax provision is based on 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 $5,874 million and $6,045 million at December 31, 2014 and 2013, 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 April 2014, the Financial Accounting Standards Board issued Accounting Standard Update No. 2014-08 “Reporting Discontinued Operations and Disclosures of Disposals of Components of and Entity” (ASU No. 2014-08), which is an update for Accounting Standards Codification Topic No. 205 “Presentation of Financial Statements” and Topic No. 360 “Property, Plant and Equipment’. This update changes the requirements of reporting discontinued operations. Under the amended guidance, a disposal of a component of an entity or a group of components of an entity is required to be reported in discontinued operations if the disposal represents a strategic shift that has (or will have) a major effect on an entity’s operations and financial results. The amendments in this update are effective for all disposals (or classifications as held for sale) of components of an entity that occur within annual periods beginning on or after December 15, 2014, and interim periods within those years. Although early adoption is permitted, the Company did not elect to apply the guidance of ASU No. 2014-08 to the spin-off of NOW. The adoption of this update concerns presentation and disclosure only as it relates to our consolidated financial statements. The Company expects the impact of ASU No. 2014-08 on its consolidated financial position and results of operations to be immaterial.

In May 2014, the FASB issued Accounting Standard Update No. 2014-09 “Revenue from Contracts with Customers” (ASU No. 2014-09), which supersedes the revenue recognition requirements in Accounting Standard Codification Topic No. 605 “Revenue Recognition” and most industry-specific guidance. This update requires that entities recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which a company expects to be entitled in exchange for those goods or services. ASU No. 2014-09 is effective for fiscal years beginning after December 15, 2016, and for interim periods within those fiscal years. The Company is currently assessing the impact of the adoption of ASU No. 2014-09 on its consolidated financial position and results of operations.

Forward–Looking Statements

Some of the information in this document contains, or has incorporated by reference, forward-looking statements. Statements that are not historical facts, including statements about our beliefs and expectations, are forward-looking statements. Forward-looking statements typically are identified by use of terms such as “may,” “will,” “expect,” “anticipate,” “estimate,” and similar words, although some forward-looking statements are expressed differently. All statements herein regarding expected merger synergies are forward looking statements. You should be aware that our actual results could differ materially from results anticipated in the forward-looking statements due to a number of factors, including but not limited to changes in oil and gas prices, customer demand for our products and worldwide economic activity. You should also consider carefully the statements under “Risk Factors” which address additional factors that could cause our actual results to differ from those set forth in the forward-looking statements. Given these uncertainties, current or prospective investors are cautioned not to place undue reliance on any such forward-looking statements. We undertake no obligation to update any such factors or forward-looking statements to reflect future events or developments.

ITEM 7A.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We are exposed to changes in foreign currency exchange rates and interest rates. Additional information concerning each of these matters follows:

Foreign Currency Exchange Rates

We have extensive operations in foreign countries. The net assets and liabilities of these operations are exposed to changes in foreign currency exchange rates, although such fluctuations generally do not affect income since their functional currency is typically the local currency. These operations also have net assets and liabilities not denominated in the functional currency, which exposes us to changes in foreign currency exchange rates that impact income. During the years ended December 31, 2014, 2013 and 2012, the Company reported foreign currency gains (losses) were $20 million, ($24) million and ($18) 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, 2014 (in millions except for rates):


		As of December 31, 2014								December 31,
Functional Currency		2015			2016		Total			2013
CAD	Buy USD/Sell CAD:
	Notional amount to buy (in Canadian dollars)		66			—		66			229
	Average USD to CAD contract rate		1.1632			—		1.1632			1.0669
	Fair Value at December 31, 2014 in U.S. dollars		—			—		—			1
	Sell USD/Buy CAD:
	Notional amount to sell (in Canadian dollars)		285			—		285			51
	Average USD to CAD contract rate		1.1511			—		1.1511			1.0230
	Fair Value at December 31, 2014 in U.S. dollars		(3	)		—		(3	)		(1	)
EUR	Buy USD/Sell EUR:
	Notional amount to buy (in Euros)		4			—		4			9
	Average USD to EUR contract rate		0.7933			—		0.7933			0.7590
	Fair Value at December 31, 2014 in U.S. dollars		—			—		—			1
	Sell USD/Buy EUR:
	Notional amount to buy (in Euros)		425			5		430			344
	Average USD to EUR contract rate		0.7831			0.7832		0.7832			0.7401
	Fair Value at December 31, 2014 in U.S. dollars		(25	)		—		(25	)		9
	Sell USD/Buy KRW:
	Notional amount to buy (in South Korean won)		143,488			—		143,488			195,020
	Average USD to KRW contract rate		1,104			—		1,104			1,114
	Fair Value at December 31, 2014 in U.S. dollars		—			—		—			10


		As of December 31, 2014									December 31,
Functional Currency		2015			2016			Total			2013
GBP	Buy USD/Sell GBP:
	Notional amount to buy (in British Pounds Sterling)		—			—			—			11
	Average USD to GBP contract rate		—			—			0.6142			0.6142
	Fair Value at December 31, 2014 in U.S. dollars		—			—			—			—
	Sell USD/Buy GBP:
	Notional amount to buy (in British Pounds Sterling)		205			—			205			73
	Average USD to GBP contract rate		0.6331			—			0.6201			0.6201
	Fair Value at December 31, 2014 in U.S. dollars		(6	)		—			(6	)		2
USD	Buy CAD/Sell USD:
	Notional amount to buy (in U.S. dollars)		16			—			16			15
	Average CAD to USD contract rate		0.9135			—			0.9431			0.9431
	Fair Value at December 31, 2014 in U.S. dollars		(1	)		—			(1	)		—
	Buy DKK/Sell USD:
	Notional amount to buy (in U.S. dollars)		68			7			75			71
	Average DKK to USD contract rate		0.1789			0.1802			0.1813			0.1813
	Fair Value at December 31, 2014 in U.S. dollars		(5	)		(1	)		(6	)		1
	Buy EUR/Sell USD:
	Notional amount to buy (in U.S. dollars)		748			136			884			773
	Average EUR to USD contract rate		1.3347			1.3426			1.3411			1.3411
	Fair Value at December 31, 2014 in U.S. dollars		(65	)		(12	)		(77	)		21
	Buy GBP/Sell USD:
	Notional amount to buy (in U.S. dollars)		141			6			147			42
	Average GBP to USD contract rate		1.5809			1.6426			1.5779			1.5779
	Fair Value at December 31, 2014 in U.S. dollars		(3	)		—			(3	)		1
	Buy NOK/Sell USD:
	Notional amount to buy (in U.S. dollars)		1,345			616			1,961			1,877
	Average NOK to USD contract rate		0.1556			0.1571			0.1642			0.1642
	Fair Value at December 31, 2014 in U.S. dollars		(186	)		(90	)		(276	)		(28	)
	Buy SGD/Sell USD:
	Notional amount to buy (in U.S. dollars)		30			6			36			15
	Average SGD to USD contract rate		0.7865			0.7925			0.7966			0.7966
	Fair Value at December 31, 2014 in U.S. dollars		(1	)		—			(1	)		—
	Sell CAD/Buy USD:
	Notional amount to buy (in U.S. dollars)		—			—			—			2
	Average CAD to USD contract rate		—			—			1.3625			1.3625
	Fair Value at December 31, 2014 in U.S. dollars		—			—			—			—
	Sell DKK/Buy USD:
	Notional amount to buy (in U.S. dollars)		22			—			22			11
	Average DKK to USD contract rate		0.1689			—			1.3625			1.3625
	Fair Value at December 31, 2014 in U.S. dollars		1			—			1			—
	Sell EUR/Buy USD:
	Notional amount to sell (in U.S. dollars)		245			6			251			190
	Average EUR to USD contract rate		1.2493			1.3772			1.3109			1.3109
	Fair Value at December 31, 2014 in U.S. dollars		6			1			7			(2	)
	Sell NOK/Buy USD:
	Notional amount to sell (in U.S. dollars)		307			41			348			385
	Average NOK to USD contract rate		0.1525			0.1623			0.1634			0.1634
	Fair Value at December 31, 2014 in U.S. dollars		37			7			44			6


		As of December 31, 2014									December 31,
Functional Currency		2015			2016			Total			2013
	Sell SGD/Buy USD:
	Notional amount to sell (in U.S. dollars)		2			—			2			1
	Average SGD to USD contract rate		0.7678			—			0.7678			0.8000
	Fair Value at December 31, 2014 in U.S. dollars		—			—			—			—
	Sell RUB/Buy USD:
	Notional amount to sell (in U.S. dollars)		—			—			—			64
	Average RUB to USD contract rate		—			—			—			0.0298
	Fair Value at December 31, 2014 in U.S. dollars		—			—			—			(1	)
	Sell SEK/Buy USD:
	Notional amount to sell (in U.S. dollars)		—			—			—			1
	Average SEK to USD contract rate		—			—			—			0.1529
	Fair Value at December 31, 2014 in U.S. dollars		—			—			—			—
DKK	Sell DKK/Buy USD:
	Notional amount to buy (in U.S. dollars)		59			—			59			111
	Average DKK to USD contract rate		5.93			—			5.9300			6
	Fair Value at December 31, 2014 in U.S. dollars		—			—			—			—
Other Currencies
	Fair Value at December 31, 2014 in U.S. dollars		—			—			—			(1	)

Total Fair Value at December 31, 2014 in U.S. dollars			(251	)		(95	)		(346	)		19

The Company had other financial market risk sensitive instruments denominated in foreign currencies for transactional exposures totaling $206 million and translation exposures totaling $427 million as of December 31, 2014, 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 $13 million and the translational exposures financial market risk sensitive instruments could affect the future fair value by $42 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.

Historically, the Venezuelan government has devalued the country’s currency. 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 incurred approximately $12 million in devaluation charges in the first quarter of 2013. The reporting currency of all of the Company’s Venezuelan entities is the U.S. dollar. The Company’s net investment in Venezuela was $45 million at December 31, 2014.

Interest Rate Risk

At December 31, 2014, long term borrowings consisted of $151 million in 6.125% Senior Notes, $500 million in 1.35% Senior Notes, $1,396 million in 2.60% Senior Notes and $1,096 million in 3.95% Senior Notes, no commercial paper borrowings and no borrowings against our revolving credit facility. Occasionally a portion of borrowings under our credit facility 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 U.S. prime 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. Our objective is to maintain a portion of our debt in variable rate borrowings for the flexibility obtained regarding early repayment without penalties and lower overall cost as compared with fixed-rate borrowings.

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, 2014 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 59 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 2015 Annual Meeting of Stockholders.

ITEM 11.

EXECUTIVE COMPENSATION

Incorporated by reference to the definitive Proxy Statement for the 2015 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 2015 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, 2014, with respect to compensation plans under which our common stock may be issued:

Number of securities

Weighted-average

Number of securities

to be issued upon

exercise price of

remaining available for equity

exercise of warrants

outstanding

compensation plans (excluding

and rights

rights

securities reflected in column (a)) (c)

Plan Category

( a )

( b )

(1)

Equity compensation plans approved by security holders

10,881,133

55.06

11,871,884

Equity compensation plans not approved by security holders

—

Total

10,881,133

55.06

11,871,884

(1)	Shares could be issued through equity instruments other than stock options, warrants or rights; however, none are anticipated during 2015.

ITEM 13.

CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

Incorporated by reference to the definitive Proxy Statement for the 2015 Annual Meeting of Stockholders.

ITEM 14.

PRINCIPAL ACCOUNTANT FEES AND SERVICES

Incorporated by reference to the definitive Proxy Statement for the 2015 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		62
Consolidated Statements of Income		63
Consolidated Statements of Comprehensive Income		64
Consolidated Statements of Cash Flows		65
Consolidated Statements of Stockholders’ Equity		66
Notes to Consolidated Financial Statements		67


(2) Financial Statement Schedule

Schedule II – Valuation and Qualifying Accounts			100

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


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) (2)

10.1		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) (3)

10.2		National Oilwell Varco Long-Term Incentive Plan, as amended and restated. (4)*

10.3		Form of Employee Stock Option Agreement. (Exhibit 10.1) (5)

10.4		Form of Non-Employee Director Stock Option Agreement. (Exhibit 10.2) (5)

10.5		Form of Performance-Based Restricted Stock. (18 Month) Agreement (Exhibit 10.1) (6)

10.6		Form of Performance-Based Restricted Stock. (36 Month) Agreement (Exhibit 10.2) (6)

10.7		Form of Performance Award Agreement (Exhibit 10.1) (7)

10.8		Form of Executive Employment Agreement. (Exhibit 10.1) (8)

10.9		Form of Executive Severance Agreement. (Exhibit 10.2) (8)

21.1		Subsidiaries of the Registrant.

23.1		Consent of Ernst & Young LLP.

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

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

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


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

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

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, 2014 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. (9)

*	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 Current Report on Form 8-K filed on August 17, 2011.

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

(4)	Filed as Appendix I to our Proxy Statement filed on April 10, 2013.

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

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

(7)	Filed as an Exhibit to our Current Report on Form 8-K filed on March 27, 2013.

(8)	Filed as an Exhibit to our Current Report on Form 8-K filed on November 24, 2014.

(9)	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 Clay C. Williams 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/ CLAY C. WILLIAMS Clay C. Williams	Chairman, President and Chief Executive Officer	February 17, 2015

/s/ JEREMY D. THIGPEN Jeremy D. Thigpen	Senior Vice President and Chief Financial Officer	February 17, 2015

/s/ SCOTT K. DUFF Scott K. Duff	Vice President, Corporate Controller and Chief Accounting Officer	February 17, 2015

/s/ GREG L. ARMSTRONG	Director	February 17, 2015
Greg L. Armstrong

/s/ ROBERT E. BEAUCHAMP	Director	February 17, 2015
Robert E. Beauchamp

/s/ MARCELA E. DONADIO	Director	February 17, 2015
Marcela E. Donadio

/s/ BEN A. GUILL	Director	February 17, 2015
Ben A. Guill

/s/ DAVID D. HARRISON	Director	February 17, 2015
David D. Harrison

/s/ ROGER L. JARVIS	Director	February 17, 2015
Roger L. Jarvis

/s/ ERIC L. MATTSON	Director	February 17, 2015
Eric L. Mattson

/s/ JEFFERY A. SMISEK	Director	February 17, 2015
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.

Management has used the 2013 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, 2014.

The effectiveness of our internal control over financial reporting as of December 31, 2014, 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/ Clay C. Williams

Clay C. Williams

Chairman, President and Chief Executive Officer

/s/ Jeremy D. Thigpen

Jeremy D. Thigpen

Senior Vice President and Chief Financial Officer

Houston, Texas

February 17, 2015

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, 2014, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) (the COSO criteria). National Oilwell Varco, Inc’s management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.

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

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

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

In our opinion, National Oilwell Varco, Inc. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2014, 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, 2014 and 2013, 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, 2014 of National Oilwell Varco, Inc., and our report dated February 17, 2015, expressed an unqualified opinion thereon.

/s/ ERNST & YOUNG LLP

Houston, Texas

February 17, 2015

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, 2014 and 2013, 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, 2014. 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 audit provides 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, 2014 and 2013, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2014, 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, 2014, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) and our report dated February 17, 2015, expressed an unqualified opinion thereon.

/s/ ERNST & YOUNG LLP

Houston, Texas

February 17, 2015

NATIONAL OILWELL VARCO, INC.

CONSOLIDATED BALANCE SHEETS

(In millions, except share data)


	December 31,
	2014			2013
ASSETS
Current assets:
Cash and cash equivalents	$	3,536		$	3,436
Receivables, net		4,416			4,896
Inventories, net		5,281			5,603
Costs in excess of billings		1,878			1,539
Deferred income taxes		447			373
Prepaid and other current assets		604			576

Total current assets		16,162			16,423

Property, plant and equipment, net		3,362			3,408
Deferred income taxes		503			372
Goodwill		8,539			9,049
Intangibles, net		4,444			5,055
Investment in unconsolidated affiliates		362			390
Other assets		190			115

Total assets	$	33,562		$	34,812

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	1,189		$	1,275
Accrued liabilities		3,518			2,763
Billings in excess of costs		1,775			1,771
Current portion of long-term debt and short-term borrowings		152			1
Accrued income taxes		431			556
Deferred income taxes		309			312

Total current liabilities		7,374			6,678

Long-term debt		3,014			3,149
Deferred income taxes		1,972			2,292
Other liabilities		430			363

Total liabilities		12,790			12,482

Commitments and contingencies

Stockholders’ equity:
Common stock - par value $.01; 1 billion shares authorized; 418,977,608 and 428,433,703 shares issued and outstanding at December 31, 2014 and December 31, 2013		4			4
Additional paid-in capital		8,341			8,907
Accumulated other comprehensive loss		(834	)		(4	)
Retained earnings		13,181			13,323

Total Company stockholders’ equity		20,692			22,230
Noncontrolling interests		80			100

Total stockholders’ equity		20,772			22,330

Total liabilities and stockholders’ equity	$	33,562		$	34,812

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,
	2014			2013			2012
Revenue
Sales	$	17,173		$	15,489		$	13,794
Services		4,267			3,732			3,400

Total		21,440			19,221			17,194

Cost of revenue
Cost of sales		12,407			11,107			9,335
Cost of services		3,224			3,010			2,816

Total		15,631			14,117			12,151

Gross profit		5,809			5,104			5,043
Selling, general and administrative		2,092			1,905			1,654
Intangible asset impairment		104			—			—

Operating profit		3,613			3,199			3,389

Interest and financial costs		(105	)		(111	)		(49	)
Interest income		18			12			10
Equity income in unconsolidated affiliates		58			63			58
Other income (expense), net		(90	)		(39	)		(68	)

Income from continuing operations before income taxes		3,494			3,124			3,340
Provision for income taxes		1,039			943			965

Income from continuing operations		2,455			2,181			2,375
Income from discontinued operations		52			147			108

Net income		2,507			2,328			2,483
Net income (loss) attributable to noncontrolling interests		5			1			(8	)

Net income attributable to Company	$	2,502		$	2,327		$	2,491

Per share data:
Basic:
Income from continuing operations	$	5.73		$	5.11		$	5.61

Income from discontinued operations	$	0.12		$	0.35		$	0.25

Net income attributable to Company	$	5.85		$	5.46		$	5.86

Diluted:
Income from continuing operations	$	5.70		$	5.09		$	5.58

Income from discontinued operations	$	0.12		$	0.35		$	0.25

Net income attributable to Company	$	5.82		$	5.44		$	5.83

Cash dividends per share	$	1.64		$	0.91		$	0.49

Weighted average shares outstanding:
Basic		428			426			425

Diluted		430			428			427

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,
	2014			2013			2012
Net income	$	2,507		$	2,328		$	2,483

Other comprehensive income (loss) (net of tax):
Currency translation adjustments		(532	)		(115	)		64
Derivative financial instruments		(233	)		(37	)		99
Change in defined benefit plans		(65	)		41			(33	)

Comprehensive income		1,677			2,217			2,613
Net income (loss) attributable to noncontrolling interests		5			1			(8	)

Comprehensive income attributable to Company	$	1,672		$	2,216		$	2,621

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,
	2014			2013			2012
Cash flows from operating activities:
Income from continuing operations	$	2,455		$	2,181		$	2,375
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		778			738			616
Deferred income taxes		(300	)		(336	)		(90	)
Stock-based compensation		101			92			80
Excess tax benefit from stock-based compensation		(15	)		(20	)		(25	)
Equity income in unconsolidated affiliates		(58	)		(63	)		(58	)
Dividend from unconsolidated affiliate		73			66			61
Intangible asset impairment		104			—			—
Other		181			72			77
Change in operating assets and liabilities, net of acquisitions:
Receivables		(153	)		(516	)		(492	)
Inventories		(710	)		238			(974	)
Costs in excess of billings		(262	)		(314	)		(632	)
Prepaid and other current assets		(60	)		41			(221	)
Accounts payable		95			18			40
Billings in excess of costs		(59	)		582			324
Income taxes payable		(124	)		217			(408	)
Other assets/liabilities, net		479			84			(41	)

Net cash provided by continuing operating activities		2,525			3,080			632
Discontinued operations		89			317			(12	)

Net cash provided by operating activities		2,614			3,397			620

Cash flows from investing activities:
Purchases of property, plant and equipment		(699	)		(614	)		(569	)
Business acquisitions, net of cash acquired		(291	)		(2,397	)		(1,767	)
Cash distributed in spin-off		(253	)		—			—
Other, net		151			101			35

Net cash used in continuing investing activities		(1,092	)		(2,910	)		(2,301	)
Discontinued operations		(12	)		(54	)		(1,127	)

Net cash used in investing activities		(1,104	)		(2,964	)		(3,428	)

Cash flows from financing activities:
Borrowings against lines of credit and other debt		173			2,609			5,575
Payments against lines of credit and other debt		(155	)		(2,609	)		(2,937	)
Cash dividends paid		(703	)		(389	)		(209	)
Share repurchases		(779	)		—			—
Proceeds from stock options exercised		108			58			113
Excess tax benefit from stock-based compensation		15			20			25
Other		(2	)		7			17

Net cash provided by (used in) continuing financing activities		(1,343	)		(304	)		2,584
Discontinued operations		—			(1	)		(1	)

Net cash provided by (used in) financing activities		(1,343	)		(305	)		2,583

Effect of exchange rates on cash		(67	)		(11	)		9

Increase (decrease) in cash and cash equivalents		100			117			(216	)
Cash and cash equivalents, beginning of period		3,436			3,319			3,535

Cash and cash equivalents, end of period	$	3,536		$	3,436		$	3,319

Supplemental disclosures of cash flow information:
Cash payments during the period for:
Interest	$	102		$	111		$	40
Income taxes	$	1,380		$	1,099		$	1,572

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, 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 from stock-based compensation		—			—		25			—			—			25			—			25

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

Net income		—			—		—			—			2,327			2,327			1			2,328
Other comprehensive loss, net		—			—		—			(111	)		—			(111	)		—			(111	)
Cash dividends, $.91 per common share		—			—		—			—			(389	)		(389	)		—			(389	)
Dividends to noncontrolling interests		—			—		—			—			—			—			(3	)		(3	)
Noncontrolling interest contribution		—			—		—			—			—			—			10			10
Disposal of noncontrolling interest, net		—			—		—			—			—			—			(25	)		(25	)
Stock-based compensation		—			—		92			—			—			92			—			92
Common stock issued		1			—		58			—			—			58			—			58
Withholding taxes		—			—		(6	)		—			—			(6	)		—			(6	)
Excess tax benefit from stock-based compensation		—			—		20			—			—			20			—			20

Balance at December 31, 2013		428		$	4	$	8,907		$	(4	)	$	13,323		$	22,230		$	100		$	22,330

Net income		—			—		—			—			2,502			2,502			5			2,507
Other comprehensive loss, net		—			—		—			(830	)		—			(830	)		—			(830	)
Cash dividends, $1.64 per common share		—			—		—			—			(703	)		(703	)		—			(703	)
Dividends to noncontrolling interests		—			—		—			—			—			—			(20	)		(20	)
Noncontrolling interest contribution		—			—		—			—			—			—			16			16
Disposal of noncontrolling interest, net		—			—		—			—			—			—			(21	)		(21	)
Spin-off of distribution business		—			—		—			—			(1,941	)		(1,941	)		—			(1,941	)
Stock-based compensation		—			—		101			—			—			101			—			101
Common stock issued		3			—		108			—			—			108			—			108
Withholding taxes		—			—		(11	)		—			—			(11	)		—			(11	)
Share repurchases		(12	)		—		(779	)		—			—			(779	)		—			(779	)
Excess tax benefit from stock-based compensation		—			—		15			—			—			15			—			15

Balance at December 31, 2014		419		$	4	$	8,341		$	(834	)	$	13,181		$	20,692		$	80		$	20,772

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.

On May 30, 2014, the Company completed the spin-off of its distribution business into an independent public company named NOW Inc. In conjunction with the spin-off of NOW Inc. the Company reviewed its reporting and management structure, and effective April 1, 2014, reorganized the Rig Technology, Petroleum Services & Supplies and remaining operations of Distribution & Transmission reporting segments into four new reporting segments. The new reporting segments are Rig Systems, Rig Aftermarket, Wellbore Technologies and Completion & Production Solutions. As a result of the reorganization, all prior periods are presented on this basis. Results of operations related to NOW Inc. have been classified as discontinued operations in all periods presented on Form 10-K.

2. Summary of Significant Accounting Policies

Fair Value of Financial Instruments

The carrying amounts of financial instruments including cash and cash equivalents, receivables, and payables approximated fair value because of the relatively short maturity of these instruments. Cash equivalents include only those investments having a maturity date of three months or less at the time of purchase.

Derivative Financial Instruments

Accounting Standards Codification (“ASC”) Topic 815, “Derivatives and Hedging” (“ASC Topic 815”) requires companies to recognize all 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 hedges 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.

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 $370 million and $396 million at December 31, 2014 and 2013, 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 $413 million, $381 million and $315 million for the years ended December 31, 2014, 2013 and 2012, 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, 2014, 2013 and 2012.

Intangible Assets

The Company has approximately $8.5 billion of goodwill and $4.4 billion of identified intangible assets at December 31, 2014.

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


	Rig Systems			Rig Aftermarket			Wellbore Technologies			Completion & Production Solutions			Discontinued Operations			Total
Balance at December 31, 2012	$	1,097		$	649		$	3,769		$	1,314		$	343		$	7,172

Goodwill acquired during period		179			256			665			803			—			1,903
Currency translation adjustments and other		3			1			(9	)		(11	)		(10	)		(26	)

Balance at December 31, 2013	$	1,279		$	906		$	4,425		$	2,106		$	333		$	9,049

Goodwill acquired during the period		—			—			17			150			—			167
Goodwill disposed of during the period		—			—			—			(71	)		(332	)		(403	)
Currency translation adjustments and other		(43	)		(29	)		(85	)		(116	)		(1	)		(274	)

Balance at December 31, 2014	$	1,236		$	877		$	4,357		$	2,069		$	—		$	8,539

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 $340 million in each of the next five years. Included in intangible assets are approximately $540 million of indefinite-lived trade names.

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


	Rig Systems			Rig Aftermarket			Wellbore Technologies			Completion & Production Solutions			Discontinued Operations			Total
Balance at December 31, 2012	$	62		$	89		$	2,942		$	1,576		$	74		$	4,743

Additions to intangible assets		190			59			286			161			—			696
Amortization		(21	)		(6	)		(217	)		(113	)		(6	)		(363	)
Currency translation adjustments and other		1			—			(12	)		(10	)		—			(21	)

Balance at December 31, 2013	$	232		$	142		$	2,999		$	1,614		$	68		$	5,055

Additions to intangible assets		—			—			5			54			—			59
Disposal of intangible assets		—			—			—			(50	)		(67	)		(117	)
Asset impairment		—			—			(104	)		—			—			(104	)
Amortization		(22	)		(6	)		(218	)		(119	)		(1	)		(366	)
Currency translation adjustments and other		(2	)		(3	)		(16	)		(62	)		—			(83	)

Balance at December 31, 2014	$	208		$	133		$	2,666		$	1,437		$	—		$	4,444

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


	Gross		Accumulated Amortization			Net Book Value
December 31, 2013:

Customer relationships	$	4,093	$	(1,147	)	$	2,946
Trademarks		893		(195	)		698
Indefinite-lived trade names		643		—			643
Other		1,175		(407	)		768

Total identified intangibles	$	6,804	$	(1,749	)	$	5,055

December 31, 2014:

Customer relationships	$	4,094	$	(1,379	)	$	2,715
Trademarks		871		(226	)		645
Indefinite-lived trade names		536		—			536
Other		1,058		(510	)		548

Total identified intangibles	$	6,559	$	(2,115	)	$	4,444

Asset Impairment

Generally accepted accounting principles require the Company to test goodwill and other indefinite-lived intangible assets for impairment at least annually or more frequently whenever events or circumstances occur indicating that goodwill or other indefinite-lived intangible assets might be impaired. Events or circumstances which could indicate a potential impairment include (but 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 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. During the review of its 2014 annual impairment test, the calculated fair values for all of the Company’s reporting units were in excess of the respective reporting unit’s carrying value. Also, the fair value for all of the Company’s intangible assets with indefinite lives were in excess of the respective asset carrying values, with two exceptions. These intangible assets, which represents a trade names within the Company’s Wellbore Technologies segment, had a calculated fair value approximately $104 million below its carrying value. The impairment charge was primarily the result of the substantial decline in oil prices during the fourth quarter of 2014, declines in forecasts in rig activity for 2015 and a decline in revenue forecast for the segment for 2015.

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 gains (losses) were $20 million, ($24) million and ($18) million for the years ending December 31, 2014, 2013 and 2012, respectively, and are included in other income (expense) in the accompanying statement of operations.

Historically, the Venezuelan government has devalued the country’s currency. 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 incurred approximately $12 million in devaluation charges in the first quarter of 2013. The reporting currency of all of the Company’s Venezuela entities is the U.S. dollar. The Company’s net investment in Venezuela was $45 million at December 31, 2014.

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 Company uses the percentage-of-completion method to account for certain long-term construction contracts in the Rig Systems and Completion & Production Solutions segments. These long-term construction contracts include the following characteristics:

•

the contracts include custom designs for customer specific applications;

•

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

•

construction projects often have progress payments.

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

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

Drill Pipe Sales

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

Service and Product Warranties

The Company provides service and warranty policies on certain of its products. The Company accrues liabilities under service and warranty policies based upon specific claims and a review of historical warranty and service claim experience in accordance with 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.

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


Balance at December 31, 2012	$	194

Net provisions for warranties issued during the year		101
Amounts incurred		(73	)
Currency translation adjustments and other		6

Balance at December 31, 2013	$	228

Net provisions for warranties issued during the year		123
Amounts incurred		(78	)
Currency translation adjustments and other		(1	)

Balance at December 31, 2014	$	272

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 $125 million and $132 million at December 31, 2014 and 2013.

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 $101 million, $92 million and $80 million for 2014, 2013 and 2012, respectively. The total income tax benefit recognized in the income statement for all share-based compensation arrangements was $35 million, $28 million and $24 million for 2014, 2013 and 2012, 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. 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. 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.

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,
	2014		2013		2012
Numerator:
Income from continuing operations	$	2,450	$	2,180	$	2,383

Income from discontinued operations	$	52	$	147	$	108

Net income attributable to Company	$	2,502	$	2,327	$	2,491

Denominator:
Basic—weighted average common shares outstanding		428		426		425
Dilutive effect of employee stock options and other unvested stock awards		2		2		2

Diluted outstanding shares		430		428		427

Per share data:
Basic:
Income from continuing operations	$	5.73	$	5.11	$	5.61

Income from discontinued operations	$	0.12	$	0.35	$	0.25

Net income attributable to Company	$	5.85	$	5.46	$	5.86

Diluted:
Income from continuing operations	$	5.70	$	5.09	$	5.58

Income from discontinued operations	$	0.12	$	0.35	$	0.25

Net income attributable to Company	$	5.82	$	5.44	$	5.83

Cash dividends per share	$	1.64	$	0.91	$	0.49

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, 2014, 2013 and 2012 and therefore not excluded from net income attributable to Company per share calculation. The Company had stock options outstanding that were anti-dilutive totaling 8 million, 7 million, and 5 million at December 31, 2014, 2013 and 2012, respectively.

Recently Issued Accounting Standards

3. Derivative Financial Instruments

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).

At December 31, 2014, the Company has determined that the fair value of its derivative financial instruments representing assets of $53 million and liabilities of $399 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, 2014, the net fair value of the Company’s foreign currency forward contracts totaled a net liability of $346 million.

At December 31, 2014, the Company’s 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, 2014 and 2013, 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, 2014		December 31, 2013
Norwegian Krone	NOK	10,781	NOK	10,503
Euro	€	462	€	406
U.S. Dollar	$	231	$	357
Danish Krone	DKK	227	DKK	278
British Pound Sterling	£	80	£	23
Singapore Dollar	SGD	44	SGD	17
Canadian Dollar	CAD	14	CAD	16

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, 2014		December 31, 2013
Norwegian Krone	NOK	4,052	NOK	3,257
U.S. Dollar	$	1,092	$	715
Euro	€	401	€	310
Danish Krone	DKK	322	DKK	177
Mexican Peso	MXN	118	MXN	—
Brazilian Real	BRL	57	BRL	—
British Pound Sterling	£	19	£	14
Singapore Dollar	SGD	4	SGD	3
Canadian Dollar	CAD	4	CAD	3
Swedish Krone	SEK	3	SEK	4
Russian Ruble	RUB	—	RUB	2,149

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


	Asset Derivatives					Liability Derivatives
	Balance Sheet Location	Fair Value December 31,				Balance Sheet Location	Fair Value December 31,
	Balance Sheet Location	2014		2013		Balance Sheet Location	2014		2013
Derivatives designated as hedging instruments under ASC Topic 815

Foreign exchange contracts	Prepaid and other current assets	$	18	$	35	Accrued liabilities	$	204	$	18
Foreign exchange contracts	Other Assets		8		5	Other Liabilities		102		9

Total derivatives designated as hedging instruments under ASC Topic 815		$	26	$	40		$	306	$	27

Derivatives not designated as hedging instruments under ASC Topic 815

Foreign exchange contracts	Prepaid and other current assets	$	27	$	19	Accrued liabilities	$	93	$	13

Total derivatives not designated as hedging instruments under ASC Topic 815		$	27	$	19		$	93	$	13

Total derivatives		$	53	$	59		$	399	$	40

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,
	2014			2013								2014			2013				2014		2013
								Revenue					26			16
Foreign exchange contracts		(340	)		(42	)		Cost of revenue					(43	)		(6	)	Other income (expense), net		35		12

Total		(340	)		(42	)							(17	)		10				35		12


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,
							2014			2013
Foreign exchange contracts		Other income (expense), net						(61	)		18

Total								(61	)		18

(a)	The Company expects that $214 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 related to the ineffective portion of the hedging relationships for the each of the years ended December 31, 2014 and 2013, and $35 million and $12 million related to the amount excluded from the assessment of the hedge effectiveness for the years ended December 31, 2014 and 2013, respectively.

4. Acquisitions and Investments

2014

In the year ended December 31, 2014, the Company completed 10 acquisitions for an aggregate purchase price of $291 million, net of cash acquired. The Company has preliminarily allocated $ 59 million to identifiable intangible assets and $167 million to goodwill. The amount allocated to goodwill represents the excess of the purchase price over the fair value of the net assets acquired. 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 acquisition. Goodwill resulting from the acquisitions is not deductible for tax purposes.

2013

On February 20, 2013, the Company completed its acquisition of all of the shares of Robbins & Myers, Inc. (“R&M”), a U.S.-based designer and manufacturer of products and systems for the oil and gas industry. Under the merger agreement for this transaction, R&M shareholders received $60.00 in cash for each common share for an aggregate purchase price of $2,378 million, net of cash acquired. In addition to R&M, the Company completed five acquisitions and other investments for an aggregate purchase price of $19 million, net of cash acquired.

The Company has included the financial results of R&M in its consolidated financial statements as of the date of acquisition with components of the R&M operations included in each of the Company’s segments. The Company believes the acquisition of R&M will advance its strategic goal of providing a broader selection of products and services to its customers.

The following table displays the total purchase price allocation for the R&M acquisition. The table summarizes the fair values of the assets acquired and liabilities assumed at the date of acquisition (in millions):


Current assets, net of cash acquired	$	428
Property, plant and equipment		250
Intangible assets		894
Goodwill		1,590
Other assets		49
Total assets acquired		3,211
Current liabilities		186
Deferred taxes		524
Other liabilities		123
Total liabilities		833
Cash consideration, net of cash acquired	$	2,378

The Company has allocated $894 million to identifiable intangible assets (19 year weighted-average life). The intangible assets are amortizable and are comprised of: $635 million of customer relationships (18 year weighted-average life), $170 million of patents (20 year weighted-average life), $86 million of trademarks (20 year weighted-average life), and $3 million of other intangible assets (1 year weighted-average life). The amount allocated to goodwill represents the excess of the purchase price over the fair value of the net assets acquired. 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 acquisition. Goodwill resulting from the R&M acquisition is not deductible for tax purposes. Pro forma information is not included because the results of the acquired operations would not have materially impacted the Company’s consolidated operating results.

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 Completion & Production Solutions 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 Completion & Production Solutions 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 discontinued operations from the date of acquisition through May 30, 2014, the date of the spin-off of NOW Inc.

•

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 discontinued operations from the date of acquisition through May 30, 2014, the date of the spin-off of NOW Inc.

•

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 Wellbore Technologies segment from the date of acquisition.

The following table displays the total purchase price allocation for the 2012 acquisitions and summarizes the 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 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 deductible for tax purposes. Pro forma information is not included because the results of the acquired operations would not have materially impacted the Company’s consolidated operating results.

Each of the acquisitions was 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,
	2014			2013			2012
Fair value of assets acquired, net of cash acquired	$	406		$	3,329		$	3,672
Cash paid, net of cash acquired		(291	)		(2,397	)		(2,880	)

Liabilities assumed, debt issued and noncontrolling interest	$	115		$	932		$	792

Excess purchase price over fair value of net assets acquired	$	167		$	1,903		$	1,000

5. Inventories, net

Inventories consist of (in millions):


	December 31,
	2014		2013
Raw materials and supplies	$	1,255	$	1,175
Work in process		1,027		798
Finished goods and purchased products		2,999		3,630

Total	$	5,281	$	5,603

6. Property, Plant and Equipment

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


	Estimated Useful Lives		December 31,
	Estimated Useful Lives		2014			2013
Land and buildings		5-35 Years	$	1,528		$	1,494
Operating equipment		3-15 Years		3,060			2,960
Rental equipment		3-12 Years		817			758

				5,405			5,212
Less: Accumulated Depreciation				(2,043	)		(1,804	)

			$	3,362		$	3,408

7. Accrued Liabilities

Accrued liabilities consist of (in millions):


	December 31,
	2014		2013
Accrued vendor costs	$	815	$	531
Customer prepayments and billings		703		673
Compensation		662		516
Fair value of derivatives		297		31
Warranty		272		228
Taxes (non income)		211		188
Insurance		126		131
Accrued commissions		97		97
Interest		11		11
Other		324		357

Total	$	3,518	$	2,763

8. Costs and Estimated Earnings on Uncompleted Contracts

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


	December 31,
	2014			2013
Costs incurred on uncompleted contracts	$	10,442		$	7,608
Estimated earnings		4,699			3,553

		15,141			11,161
Less: Billings to date		15,038			11,393

	$	103		$	(232	)

Costs and estimated earnings in excess of billings on uncompleted contracts	$	1,878		$	1,539
Billings in excess of costs and estimated earnings on uncompleted contracts		(1,775	)		(1,771	)

	$	103		$	(232	)

9. Debt

Debt consists of (in millions):


	December 31,
	2014		2013
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		500
Senior Notes, interest at 2.6% payable semiannually, principal due on December 1, 2022		1,396		1,396
Senior Notes, interest at 3.95% payable semiannually, principal due on December 1, 2042		1,096		1,096
Other		23		7

Total debt		3,166		3,150
Less current portion		152		1

Long-term debt	$	3,014	$	3,149

Principal payments of debt for years subsequent to 2014 are as follows (in millions):


2015	$	152
2016		2
2017		500
2018		—
2019		—
Thereafter		2,512

	$	3,166

The Company has a $3.5 billion, five-year unsecured revolving credit facility which expires September 28, 2018. The Company also has a commercial paper program that is supported by its revolving credit facility. At December 31, 2014, the Company had no commercial paper borrowings and no borrowings against its revolving credit facility. Funds available under the Company’s revolving credit facility were $2,481 million due to $1,019 million in outstanding letters of credit issued under the facility. Interest under this multicurrency facility is based upon LIBOR, NIBOR or EURIBOR plus 0.875% subject to a ratings-based grid, or the U.S. prime rate. The credit facility contains a financial covenant regarding maximum debt to capitalization and the Company was in compliance at December 31, 2014.

At December 31, 2014 and 2013, the fair value of the Company’s unsecured Senior Notes approximated $2,974 million and $3,023 million, respectively. 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 both December 31, 2014 and 2013, the carrying value of the Company’s unsecured Senior Notes approximated $3,143 million.

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, 2014, 2013 and 2012, expenses for defined-contribution plans were $115 million, $96 million, and $82 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, 1,081 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 Robbins & Myers acquisition in February of 2013, the Company acquired four qualified, defined benefit, noncontributory pension plans for certain U.S. employees, an unfunded defined benefit pension plan for eligible employees in Germany, as well as two defined benefit, one contributory, pension plans in the U.K. The U.S. pension plans are closed to all new participants and there are no further benefit accruals under these plans. In addition, 230 U.S. employees covered by a collective bargaining agreement participate in a health care plan that provides postretirement medical benefits (which also covers approximately 400 retirees and dependents). The arrangements in Germany and the U.K. are all closed to new entrants, but benefits continue to accrue for current participants.

During 2014 the Company sold certain industrial assets and the impact on defined benefit plans is reflected in the table below.

Net periodic benefit cost for our defined benefit plans aggregated $7 million, $10 million and $10 million for the years ended December 31, 2014, 2013 and 2012, 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, Germany and the Netherlands and defined postretirement plans in the United States, using a measurement date of December 31, 2014 and 2013, is as follows (in millions):


	Pension benefits						Postretirement
At year end	2014			2013			2014			2013
Benefit obligation at beginning of year	$	846		$	655		$	45		$	30
Service cost		8			7			—			1
Interest cost		35			31			2			2
Actuarial loss (gain)		116			(10	)		15			(12	)
Benefits paid		(43	)		(38	)		(4	)		(4	)
Participants contributions		—			—			1			—
Exchange rate loss (gain)		(51	)		7			—			—
Acquisitions (disposals)		(118	)		194			(6	)		28
Curtailments		(1	)		—			—			—

Benefit obligation at end of year	$	792		$	846		$	53		$	45

Fair value of plan assets at beginning of year	$	706		$	517		$	—		$	—
Actual return		68			72			—			—
Benefits paid		(43	)		(38	)		(4	)		(4	)
Company contributions		21			28			3			4
Participants contributions		—			—			1			—
Exchange rate gain (loss)		(31	)		4			—			—
Acquisitions (disposals)		(61	)		123			—			—

Fair value of plan assets at end of year	$	660		$	706		$	—		$	—

Funded status	$	(132	)	$	(140	)	$	(53	)	$	(45	)

Accumulated benefit obligation at end of year	$	764		$	811

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,
	2014	2013
Discount rate:
United States plan	3.40% - 3.90%	4.65%
International plans	2.10% - 3.60%	3.50% - 4.40%
Salary increase:
United States plan	N/A	N/A
International plans	2.00% - 4.20%	2.00% - 4.40%

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


	Years Ended December 31,
	2014	2013	2012
Discount rate:
United States plan	3.99% - 4.67%	3.80%	4.58%
International plans	3.50% - 4.40%	3.46% - 4.40%	4.50% - 5.60%
Salary increase:
United States plan	N/A	N/A	N/A
International plans	2.00% - 4.40%	2.00% - 3.53%	2.00% - 4.00%
Expected return on assets:
United States plan	6.50%	6.30%	6.33%
International plans	3.50% - 5.53%	3.50% - 5.82%	4.50% - 6.51%

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 $41 million for each of the next five years and aggregate payments of $420 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, 2013:
Equity securities	$	296	$	—	$	296	$	—
Bonds		172		—		172		—
Other (insurance contracts)		238		—		131		107

Total Fair Value Measurements	$	706	$	—	$	599	$	107

December 31, 2014:
Equity securities	$	116	$	—	$	116	$	—
Bonds		323		—		323		—
Other (insurance contracts)		221		—		113		108

Total Fair Value Measurements	$	660	$	—	$	552	$	108

Level 3 inputs are unobservable (i.e., supported by little or no market activity). Level 3 inputs include management’s own judgement about the assumptions that market participants would use in pricing the asset or liability (including assumptions about risk). 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, 2012	$	100

Actual return on plan assets still held at reporting date		5
Purchases, sales and settlements		5
Currency translation adjustments		(3	)

Balance at December 31, 2013	$	107

Actual return on plan assets still held at reporting date		14
Purchases, sales and settlements		5
Currency translation adjustments		(18	)

Balance at December 31, 2014	$	108

11. Accumulated Other Comprehensive Income (Loss)

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


	Currency Translation Adjustments			Derivative Financial Instruments, Net of Tax			Defined Benefit Plans, Net of Tax			Total
Balance at December 31, 2011	$	68		$	(57	)	$	(34	)	$	(23	)

Accumulated other comprehensive income (loss) before reclassifications		64			77			(29	)		112
Amounts reclassified from accumulated other comprehensive income (loss)		—			22			(4	)		18

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

Accumulated other comprehensive income (loss) before reclassifications		(90	)		(29	)		48			(71	)
Amounts reclassified from accumulated other comprehensive income (loss)		(25	)		(8	)		(7	)		(40	)

Balance at December 31, 2013	$	17		$	5		$	(26	)	$	(4	)

Accumulated other comprehensive income (loss) before reclassifications		(543	)		(245	)		(59	)		(847	)
Amounts reclassified from accumulated other comprehensive income (loss)		11			12			(6	)		17

Balance at December 31, 2014	$	(515	)	$	(228	)	$	(91	)	$	(834	)

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


	Years Ended December 31,
	2014											2013												2012
	Currency Translation Adjustments		Derivative Financial Instruments			Defined Benefit Plans			Total			Currency Translation Adjustments			Derivative Financial Instruments			Defined Benefit Plans			Total			Currency Translation Adjustments		Derivative Financial Instruments			Defined Benefit Plans			Total
Revenue	$	—	$	(26	)	$	—		$	(26	)	$	—		$	(16	)	$	—		$	(16	)	$	—	$	6		$	—		$	6
Cost of revenue		—		43			—			43			—			6			—			6			—		26			—			26
Selling, general, and administrative		—		—			(8	)		(8	)		—			—			(8	)		(8	)		—		—			(6	)		(6	)
Other income (expense), net		11		—			—			11			(25	)		—			—			(25	)		—		—			—			—
Tax effect		—		(5	)		2			(3	)		—			2			1			3			—		(10	)		2			(8	)

	$	11	$	12		$	(6	)	$	17		$	(25	)	$	(8	)	$	(7	)	$	(40	)	$	—	$	22		$	(4	)	$	18

The Company’s reporting currency is the U.S. dollar. A majority of the Company’s international entities in which there is a substantial investment have the local currency as their functional currency. As a result, currency translation adjustments resulting from the process of translating the entities’ financial statements into the reporting currency are reported in other comprehensive income or loss in accordance with ASC Topic 830 “Foreign Currency Matters” (“ASC Topic 830”). For the years ended December 31, 2014 and 2013 a majority of these local currencies weakened against the U.S. dollar resulting in a net other comprehensive loss of $543 million and $90 million, respectively, upon the translation from local currencies to the U.S. dollar. Due to the sale of non-core industrial businesses, $11 million of currency translation losses and $25 million of currency translation gains were reclassified from accumulated other comprehensive income (loss) into other income (expense), net in the Consolidated Statements of Income for the years ended December 31, 2014 and 2013 respectively. For the year ended December 31, 2012 a majority of these local currencies strengthened against the U.S. dollar resulting in a net other comprehensive income of $64 million.

The effect of changes in the fair values of derivatives designated as cash flow hedges are accumulated in other comprehensive income (loss), net of tax, until the underlying transactions to which they are designed to hedge are realized. The movement in other comprehensive income (loss) from period to period will be the result of the combination of changes in fair value for open derivatives and the outflow of other comprehensive income (loss) related to cumulative changes in the fair value of derivatives that have settled in the current or prior periods. The accumulated effect was other comprehensive loss of $233 million (net of tax of $89 million) for the year ended December 31, 2014, other comprehensive loss of $37 million (net of tax of $18 million) for the year ended December 31, 2013, and other comprehensive income of $99 million (net of tax of $39 million) for the year ended December 31, 2012.

12. Commitments and Contingencies

We have received U.S. federal grand jury subpoenas and subsequent inquiries from U.S. governmental agencies requesting records related to our compliance with U.S. export trade laws and regulations. We have cooperated fully with agents from the U.S. Department of Justice (“DOJ”), the Department of Commerce Bureau of Industry and Security (“BIS”), the United States Department of Treasury, Office of Foreign Assets Control (“OFAC”), 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, we cannot predict the timing or effect that any resulting government actions may have on our financial position or results of operations.

On February 20, 2013, the Company acquired Robbins & Myers, Inc. (“R&M”). R&M was subject to an ongoing investigation by the DOJ and the BIS regarding potential export controls violations arising from certain shipments by R&M’s Belgian (“RMB”) subsidiary. The alleged violations involved less than $75,000 in goods in 2005 and 2006. The settlement was negotiated by R&M before NOV’s acquisition of R&M. During the third quarter of 2014, the parties executed a Non-Prosecution Agreement (“NPA”) to memorialize the previously negotiated settlement. Accordingly, in the third quarter of 2014, R&M paid a fine of $1,033,000 to the DOJ and $600,000 to BIS, and RMB pleaded guilty to criminal violations of U.S. trade restrictions. RMB entered into a Plea Agreement and was sentenced to five years probation. Under the NPA, R&M, for two years unless otherwise changed pursuant to the NPA, must implement a specified compliance program and periodically certify compliance with U.S. Trade Sanction Laws.

A gain of $102 million was recognized in the third quarter of 2013 related to a legal settlement. The gain was included in revenue of the Company’s Wellbore Technologies segment.

In addition, we are involved in various other claims, regulatory agency audits and pending or threatened legal actions involving a variety of matters. As of December 31, 2014, 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 cases referred to above, will not materially affect our financial position, cash flow or results of operations. As it relates to the specific cases 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.

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 $390 million, $336 million, and $281 million in 2014, 2013 and 2012, respectively.

Future minimum lease commitments under noncancellable operating leases with initial or remaining terms of one year or more at December 31, 2014, are payable as follows (in millions):


2015	$	215
2016		151
2017		110
2018		86
2019		64
Thereafter		445

Total future lease commitments	$	1,071

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.

Cash dividends aggregated $703 million and $389 million for the years ended December 31, 2014 and 2013, 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.

Stock Options

Under the terms of National Oilwell Varco’s Long-Term Incentive Plan, as amended, 39.5 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, 2014, approximately 11.9 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, 2014 under the stock option plans have exercise prices between $8.43 and $77.99 per share, and expire at various dates from January 26, 2015 to December 4, 2024.

On June 2, 2014, as a result of the spin-off and pursuant to the terms of the Employee Matters Agreement and the Plan, outstanding NOV stock-based awards held by continuing NOV employees were adjusted to generally preserve the intrinsic value of the original award. Outstanding NOV stock-based awards held by employees of NOW were converted into similar NOW stock-based awards, each appropriately adjusted to generally preserve the intrinsic value of the original award. Adjustments to the awards are reflected in the following tables and did not have a material impact to compensation expense.

Stock Options

The following summarizes options activity:


	Years Ended December 31,
	2014					2013					2012
	Number of Shares			Average Exercise Price		Number of Shares			Average Exercise Price		Number of Shares			Average Exercise Price
Shares under option at beginning of year		11,535,566		$	58.36		10,274,477		$	54.11		11,367,995		$	43.52
Granted		3,389,547			69.00		3,072,086			63.96		2,428,406			77.99
Spin-off		(1,567,348	)				—			—		—			—
Cancelled		(498,967	)		70.32		(329,002	)		66.78		(247,426	)		55.58
Exercised		(1,977,665	)		53.56		(1,481,995	)		38.75		(3,274,498	)		34.59

Shares under option at end of year		10,881,133		$	61.22		11,535,566		$	58.36		10,274,477		$	54.11

Exercisable at end of year		5,903,712		$	55.06		6,324,117		$	49.29		5,231,150		$	40.56

The following summarizes information about stock options outstanding at December 31, 2014:


	Weighted-Avg		Options Outstanding				Options Exercisable
Range of Exercise Price	Remaining Contractual		Shares		Weighted- Exercise		Shares		Weighted- Exercise
$8.43 - $45.00		3.49		2,428,973	$	32.39		2,428,973	$	32.39
$45.01 - $70.00		8.19		5,458,369		65.94		1,102,784		61.06
$70.01 - $77.99		6.68		2,993,791		75.99		2,371,955		75.49

Total		6.72		10,881,133	$	61.22		5,903,712	$	55.06

The weighted-average fair value of options granted during 2014, 2013 and 2012, was approximately $25.60, $24.11 and $30.01 per share, respectively, as determined using the Black-Scholes option-pricing model. The total intrinsic value of options exercised during 2014 and 2013, was $111 million and $64 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,
	2014			2013			2012
Valuation Assumptions:
Expected volatility		49.4	%		50.1	%		51.7	%
Risk-free interest rate		1.5	%		0.9	%		0.9	%
Expected dividends	$	1.39		$	0.75		$	0.57
Expected term (in years)		3.7			3.4			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 2014 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, 2014 and changes during 2014 with regard to options under all stock option plans:


	Shares			Weighted- Average Exercise Price		Weighted Remaining Contractual Term (years)		Aggregate Intrinsic Value
Outstanding at December 31, 2013		11,535,566		$	58.36		5.37	$	155,892,094
Granted		3,389,547		$	69.00
Spin-off		(1,567,348	)	$	—
Cancelled		(498,967	)	$	70.32
Exercised		(1,977,665	)	$	53.56

Outstanding at December 31, 2014		10,881,133		$	61.22		6.72	$	87,998,114

Vested or expected to vest		10,739,679		$	61.22		6.72	$	86,854,138

Exercisable at December 31, 2014		5,903,712		$	55.06		5.15	$	85,503,217

At December 31, 2014, total unrecognized compensation cost related to nonvested stock options was $69 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 2014, 2013 and 2012 was approximately $67 million, $64 million and $55 million, respectively. Cash received from option exercises for 2014, 2013 and 2012 was $108 million, $58 million and $113 million, respectively. The actual tax benefit realized for the tax deductions from option exercises totaled $44 million, $39 million and $42 million for 2014, 2013 and 2012, respectively. Cash used to settle equity instruments granted under all share-based payment arrangements for 2014, 2013 and 2012 was not material for any period.

Restricted Shares

The Company issues restricted stock awards and restricted stock units to officers and key employees in addition to stock options. On February 25, 2014, the Company granted 426,272 shares of restricted stock and restricted stock units with a fair value of $69.00 per share; and performance share awards to senior management employees with potential payouts varying from zero to 436,390 shares. The stock options vest over a three-year period from the grant date while the restricted stock and restricted stock units vest on the third anniversary of the date of grant. The performance share awards can be earned based on performance against established goals over a three-year performance period. The performance share awards are divided into two equal, independent parts that are subject to two separate performance metrics: 50% with a TSR (total shareholder return) goal (the “TSR Award”) and 50% with an internal ROC (return on capital) goal (the “ROC Award”).

Performance against the TSR goal is determined by comparing the performance of the Company’s TSR with the TSR performance of the members of the OSX index for the three year performance period. Performance against the ROC goal is determined by comparing the performance of the Company’s actual ROC performance average for each of the three years of the performance period against the ROC goal set by the Company’s Compensation Committee.

On May 14, 2014, the Company granted 18,736 restricted stock awards with a fair value of $68.89 per share. The awards were granted to non-employee members of the board of directors and vest on the first anniversary of the grant date.

The following summary presents information regarding outstanding restricted shares:


	Years Ended December 31,
	2014					2013					2012
	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		1,643,193		$	67.98		1,449,683		$	62.29		1,741,840		$	40.76
Granted		708,821			70.14		822,281			63.69		523,218			77.26
Spin-off		(319,949	)		70.56		—			—		—			—
Vested		(348,981	)		74.97		(368,984	)		63.89		(441,243	)		76.85
Cancelled		(113,943	)		70.32		(259,787	)		37.78		(374,132	)		28.02

Nonvested at end of year		1,569,141		$	73.73		1,643,193		$	67.98		1,449,683		$	62.29

The weighted-average grant day fair value of restricted stock awards and restricted stock units granted during the years ended 2014, 2013 and 2012 was $70.14, $63.69 and $77.26 per share, respectively. There were 348,981; 368,984 and 441,243 restricted stock awards that vested during 2014, 2013 and 2012, respectively. At December 31, 2014, there was approximately $44 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,
	2014		2013		2012
Domestic	$	1,415	$	1,362	$	1,697
Foreign		2,079		1,762		1,643

	$	3,494	$	3,124	$	3,340

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


	Years Ended December 31,
	2014			2013			2012
Current:
Federal	$	681		$	632		$	654
State		43			55			44
Foreign		615			592			357

Total current income tax provision		1,339			1,279			1,055

Deferred:
Federal		(309	)		(157	)		(147	)
State		(5	)		(12	)		(1	)
Foreign		14			(167	)		58

Total deferred income tax provision		(300	)		(336	)		(90	)

Total income tax provision	$	1,039		$	943		$	965

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,
	2014			2013			2012
Federal income tax at U.S. statutory rate	$	1,223		$	1,093		$	1,169
Foreign income tax rate differential		(261	)		(216	)		(149	)
State income tax, net of federal benefit		25			27			29
Nondeductible expenses		24			26			29
Tax benefit of manufacturing deduction		(37	)		(33	)		(29	)
Foreign dividends, net of foreign tax credits		132			32			(116	)
Change in deferred tax valuation allowance		(83	)		40			80
Other		16			(26	)		(48	)

Total income tax provision	$	1,039		$	943		$	965

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


	December 31,
	2014			2013			2012
Deferred tax assets:
Allowances and operating liabilities	$	542		$	439		$	368
Net operating loss carryforwards		118			51			25
Postretirement benefits		79			49			54
Foreign tax credit carryforwards		244			300			259
Other		15			39			149

		998			878			855
Valuation allowance for deferred tax assets		(48	)		(133	)		(93	)

Total deferred tax assets		950			745			762

Deferred tax liabilities:
Tax over book depreciation		236			306			268
Intangible assets		1,304			1,757			1,448
Deferred income		257			285			314
Accrued U.S. tax on unremitted earnings		107			92			92
Other		377			164			208

Total deferred tax liabilities		2,281			2,604			2,330

Net deferred tax liability	$	1,331		$	1,859		$	1,568

The balance of unrecognized tax benefits at December 31, 2014 and 2013 was $115 million and $127 million, respectively. Included in the change in the balance of unrecognized tax benefits for the period ended December 31, 2014 was an increase of $3 million of unrecognized tax benefits associated with potential transfer pricing adjustments between foreign jurisdictions and certain operating expenses that may not be deductible in foreign jurisdictions. A $15 million reduction in the balance of unrecognized tax benefits resulted from the lapse of applicable statutes of limitations in the U.S. and foreign jurisdictions, as well as the completion of audits in the U.S. Of the net decrease of $12 million in the balance of unrecognized tax benefits, the entire $12 million was recorded as a decrease of income tax expense in the current year and is reflected in the “other” category in the income tax rate schedule above. These unrecognized tax benefits are included in the balance of other liabilities in the Consolidated Balance Sheet at December 31, 2014. If the $115 million of unrecognized tax benefits accrued at December 31, 2014 are ultimately realized, $42 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):


	2014			2013			2012
Unrecognized tax benefit at beginning of year	$	127		$	128		$	131
Additions based on tax positions related to the current year		3			—			2
Reductions for lapse of applicable statutes of limitations		(15	)		(1	)		(5	)

Unrecognized tax benefit at end of year	$	115		$	127		$	128

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, 2014, the Company recorded as an increase of income tax expense a $0.5 million net increase of accrued interest and penalties related to uncertain tax positions. At December 31, 2014, the Company has accrued approximately $8.5 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, 2014.

The Company is subject to taxation in the United States, various states and foreign jurisdictions. The Company has significant operations in the United States, Norway, Canada, the United Kingdom, the Netherlands, France and Denmark. 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 2009 and outside the U.S. for the tax years ending after 2007.

In the United States, the Company has $20 million of net operating loss carryforwards as of December 31, 2014, of which $4 million will expire in 2025, $13 million will expire in 2026, $1 million will expire in 2027, $1 million will expire in 2029 and $1 million will expire in 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 $381 million of net operating loss carryforwards as of December 31, 2014, of which $5 million will expire in 2015, $4 million will expire in 2016, $34 million will expire in 2017, $16 million will expire in 2018, $4 million will expire in 2019, $6 million will expire in 2020, $20 million will expire in 2021, $10 million will expire in 2022, $9 million will expire in 2023, $41 million will expire in 2024, $4 million will expire in 2034 and $228 million will carry forward indefinitely. The potential benefit of $98 million has been reduced by a $41 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 $41 million would reduce future income tax expense.

Also in the United States, the Company has $243 million of excess foreign tax credits as of December 31, 2014, of which $73 million will expire in 2018, $28 million will expire in 2020, and $142 million will expire in 2022. A valuation allowance of $101 million was reversed in 2014, as it is more likely than not these excess foreign tax credits will be utilized before they expire. There is a reserve for uncertain tax positions of $73 million against a portion of these credits.

Undistributed earnings of certain of the Company’s foreign subsidiaries amounted to $5,874 million and $6,045 million at December 31, 2014 and 2013, 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

Effective April 1, 2014, the Company’s operations were reorganized into four reportable segments: Rig Systems, Rig Aftermarket, Wellbore Technologies and Completion & Production Solutions. Within the four reporting segments, the Company has aggregated two business units under Rig Systems, one business unit under Rig Aftermarket, six business units under Wellbore Technologies and six business units under Completion & Production Solutions for a total of 15 business units. The Company has aggregated each of its business units in one of the four reporting segments based on the guidelines of ASC Topic 280, “Segment Reporting” (“ASC Topic 280”).

Rig Systems

The Company’s Rig Systems segment makes and supports the capital equipment and integrated systems needed to drill oil and gas wells on land and offshore. The segment designs, manufactures, and sells land rigs, offshore drilling equipment packages, including installation and commissioning services, and drilling rig components that mechanize and automate the rig process and functionality.

Rig Systems primarily supports land and offshore drillers. Demand for Rig Systems products primarily depends on drilling contractors’ and oil and gas companies’ capital spending plans, specifically capital expenditures on rig construction and refurbishment.

Rig Aftermarket

The Company’s Rig Aftermarket segment provides comprehensive aftermarket products and services to support land rigs and offshore rigs, and drilling rig components manufactured by the Rig Systems segment.

Rig Aftermarket primarily supports land and offshore drillers. Demand for Rig Aftermarket products and services primarily depends on overall levels of oilfield drilling activity, which drives demand for spare parts, service, and repair for Rig System’s large installed base of equipment; and secondarily on drilling contractors’ and oil and gas companies’ capital spending plans, specifically capital expenditures on rig refurbishment and re-certification.

Wellbore Technologies

Wellbore Technologies focuses on oil and gas companies and supports drilling contractors, oilfield service companies, and oilfield rental companies. Demand for Wellbore Technologies products and services primarily depends on the level of oilfield drilling activity by oil and gas companies, drilling contractors, and oilfield service companies.

Completion & Production Solutions

The Company’s Completion & Production Solutions segment integrates technologies for well completions and oil and gas production. The segment designs, manufactures, and sells equipment and technologies needed for hydraulic fracture stimulation, including pressure pumping trucks and pumps, blenders, sanders, hydration units, injection units, flowline, manifolds and wellheads; well intervention, including coiled tubing units, coiled tubing, and wireline units and tools; onshore production, including composite pipe, surface transfer and progressive cavity pumps, and artificial lift systems; and offshore production, including floating production systems and subsea production technologies.

Completion & Production Solutions primarily supports service companies and oil and gas companies. Demand for Completion & Production Solutions products depends on the level of oilfield completions and workover activity by oilfield service companies and drilling contractors and capital spending plans by oil and gas companies and oilfield service companies.

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 7%, 11% and 11% of total revenue from one of its customers for the years ended December 31, 2014, 2013, and 2012, 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,
	2014		2013		2012
United States	$	6,097	$	5,140	$	6,040
South Korea		3,472		3,219		3,121
China		1,905		1,007		533
Brazil		1,299		811		503
Singapore		1,157		1,850		1,118
Norway		881		1,102		736
United Kingdom		715		705		523
Canada		645		625		728
Other Countries		5,269		4,762		3,892

Total	$	21,440	$	19,221	$	17,194

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


	December 31,
	2014		2013
United States	$	1,818	$	1,830
Brazil		290		270
United Kingdom		196		200
Denmark		144		166
South Korea		113		115
Mexico		110		101
Canada		99		123
Singapore		87		94
Other Countries		505		509

Total	$	3,362	$	3,408

Business Segments:


	Rig Systems		Rig Aftermarket		Wellbore Technologies		Completion & Production Solutions		Eliminations (1)			Discontinued Operations		Total
December 31, 2014:
Revenues	$	9,848	$	3,222	$	5,722	$	4,645	$	(1,997	)	$	—	$	21,440
Operating profit		1,996		882		937		690		(892	)		—		3,613
Capital expenditures		133		12		262		184		108			—		699
Depreciation and amortization		88		27		439		224		—			—		778
Goodwill		1,237		878		4,357		2,067		—			—		8,539
Total assets		8,052		2,789		11,687		7,072		3,962			—		33,562

December 31, 2013:
Revenues	$	8,450	$	2,692	$	5,211	$	4,309	$	(1,441	)	$	—	$	19,221
Operating profit		1,594		729		915		613		(652	)		—		3,199
Capital expenditures		61		24		226		212		91			—		614
Depreciation and amortization		82		26		420		210		—			—		738
Goodwill		1,279		906		4,425		2,106		—			333		9,049
Total assets		7,654		2,475		11,862		7,287		3,351			2,183		34,812

December 31, 2012:
Revenues	$	7,077	$	2,138	$	5,184	$	3,994	$	(1,199	)	$	—	$	17,194
Operating profit		1,685		594		983		684		(557	)		—		3,389
Capital expenditures		81		13		247		169		59			—		569
Depreciation and amortization		64		18		389		145		—			—		616
Goodwill		1,097		649		3,769		1,314		—			343		7,172
Total assets		6,563		1,930		11,032		6,192		3,394			2,373		31,484

(1)

Sales from one segment to another generally are priced at estimated equivalent commercial selling prices; however, segments originating an external sale are credited with the full profit to the company. Eliminations include intercompany transactions conducted between the four reporting segments that are eliminated in consolidation. Intercompany transactions within each reporting segment are eliminated within each reporting segment. Also included in the eliminations column are capital expenditures and total assets related to corporate. Corporate assets consist primarily of cash and fixed assets.

16. Spin-off of distribution business

On May 30, 2014, the Company completed the previously announced spin-off (the “spin-off”) of its distribution business into an independent public company named NOW Inc., which trades on the New York Stock Exchange under the symbol “DNOW”. After the close of the New York Stock Exchange on May 30, 2014, the stockholders of record as of May 22, 2014 (the “Record Date”) received one share of NOW Inc. common stock for every four shares of NOV common stock held on the Record Date. No fractional shares of NOW Inc. common stock were distributed. Instead, the transfer agent aggregated any fractional shares into whole shares, sold those whole shares in the open market at prevailing rates and distributed the net cash proceeds, after deducting any taxes required to be withheld and any amount equal to all brokerage charges and commissions, pro rata to each holder who would otherwise have been entitled to receive fractional shares in the distribution.

In order to effect the spin-off and govern its relationship with NOW after the spin-off, the Company entered into a Separation and Distribution Agreement, a Tax Matters Agreement, an Employee Matters Agreement, a Transition Services Agreement, a Master Distributor Agreement, and a Master Supply Agreement. The Separation and Distribution Agreement governs the terms of the separation of the distribution business from NOV’s other businesses. Generally, the Separation and Distribution Agreement includes agreements between NOW and NOV relating to the restructuring steps needed to be taken to complete the separation, including the assets, equity interests and rights to be transferred, liabilities to be assumed, contracts to be assigned and related matters. The Separation and Distribution Agreement also governs matters relating to indemnification, insurance, litigation responsibility, confidentiality, management, intellectual property (including trademarks) and cooperation.

The Tax Matters Agreement governs respective rights, responsibilities and obligations of NOV and NOW with respect to deficiencies and refunds, if any, of federal, state, local, and foreign taxes for periods before and after the distribution, as well as taxes attributable to the separation and distribution, and related matters such as the filing of tax returns and the conduct of IRS and other audits. In addition, the Tax Matters Agreement imposes certain restrictions on NOW and its subsidiaries (including restrictions on share issuances, business combinations, sales of assets and similar transactions) that are designed to preserve the generally tax-free status of the separation and distribution.

The Employee Matters Agreement governs the compensation and employee benefit obligations with respect to the current and former employees of NOV and NOW and generally allocates liabilities and responsibilities relating to employee compensation and benefit plans and programs. The Employee Matters Agreement provides for the treatment of outstanding NOV equity awards. The Employee Matters Agreement also sets forth the general principles relating to employee matters, including with respect to the assignment of employees and the transfer of employees from us to NOW, the assumption and retention of liabilities and related assets, expense reimbursements, workers’ compensation, leaves of absence, the provision of comparable benefits, employee service credits, the sharing of employee information and the duplication or acceleration of benefits.

The Transition Services Agreement sets forth the terms on which NOV will provide to NOW, and NOW will provide to NOV, on a temporary basis, certain services or functions that the companies historically have shared. Transition services may include administrative, payroll, human resources, data processing, environmental health and safety, financial audit support, financial transaction support, legal support services, IT and network infrastructure systems and various other support and corporate services. The Transition Services Agreement provides for the provision of specified transition services generally for a period of up to 18 months.

The Master Distributor Agreement provides that NOW will act as a distributor of certain of NOV’s products. Under the Master Supply Agreement, NOW will supply products and provide solutions, including supply chain management solutions, to NOV.

The following table presents the carrying value of assets and liabilities of NOW (in millions):


	May 30, 2014		December 31, 2013
Current assets:
Cash and cash equivalents	$	253	$	101
Receivables, net		753		661
Inventories, net		844		850
Deferred income taxes		30		21
Prepaid and other current assets		35		29

Total current assets of discontinued operations		1,915		1,662
Property, plant and equipment, net		115		102
Deferred income taxes		15		15
Goodwill		332		333
Intangibles, net		67		68
Other assets		2		3

Total assets of discontinued operations	$	2,446	$	2,183

Current liabilities:
Accounts payable	$	384	$	264
Accrued liabilities		90		99
Accrued income taxes		5		—

Total current liabilities of discontinued operations		479		363
Deferred income taxes		17		16
Other liabilities		9		2

Total liabilities of discontinued operations	$	505	$	381

Other items incurred as a result of the spin-off were $36 million for the year ended December 31, 2014 and are included in continuing operations. The following table presents selected financial information, through May 30, 2014, regarding the results of operations of our distribution business, which is reported as discontinued operations (in millions):


	Years Ended December 31,
	2014		2013		2012
Revenue from discontinued operations	$	1,701	$	4,296	$	3,414

Income from discontinued operations before income taxes		83		222		165

Income tax expense		31		75		57

Income from discontinued operations	$	52	$	147	$	108

Prior to the spin-off, sales to NOW were $231 million for the period ended May 30, 2014 and $499 million and $450 million for the years ended December 31, 2013 and 2012, respectively. Prior to the spin-off, purchases from NOW $82 million for the period ended May 30, 2014 and $149 million and $117 million for the years ended December 31, 2013 and 2012, respectively. Prior to May 30, 2014, the spin-off date, revenue and related cost of revenue were eliminated in consolidation between NOV and NOW. Beginning May 31, 2014, this revenue and cost of revenue represent third-party transactions with NOW.

17. 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, 2014
Revenue	$	4,889	$	5,255	$	5,587	$	5,709
Gross profit		1,290		1,455		1,528		1,536
Income from continuing operations		548		609		701		597
Income from discontinued operations		41		11		—		—
Net income attributable to Company		589		619		699		595
Per share data:
Basic:
Income from continuing operations		1.28		1.42		1.63		1.39
Income from discontinued operations		0.10		0.03		—		—
Net income attributable to Company		1.38		1.45		1.63		1.39
Diluted:
Income from continuing operations		1.28		1.42		1.62		1.39
Income from discontinued operations		0.09		0.02		—		—
Net income attributable to Company		1.37		1.44		1.62		1.39
Cash dividends per share		0.26		0.46		0.46		0.46

Year ended December 31, 2013
Revenue	$	4,376	$	4,680	$	4,863	$	5,302
Gross profit		1,167		1,173		1,360		1,404
Income from continuing operations		461		494		598		627
Income from discontinued operations		41		37		38		31
Net income attributable to Company		502		531		636		658
Per share data:
Basic:
Income from continuing operations		1.08		1.16		1.40		1.47
Income from discontinued operations		0.10		0.09		0.09		0.07
Net income attributable to Company		1.18		1.25		1.49		1.54
Diluted:
Income from continuing operations		1.07		1.15		1.40		1.46
Income from discontinued operations		0.10		0.09		0.09		0.07
Net income attributable to Company		1.17		1.24		1.49		1.53
Cash dividends per share		0.13		0.26		0.26		0.26

SCHEDULE II

NATIONAL OILWELL VARCO, INC.

VALUATION AND QUALIFYING ACCOUNTS

Years Ended December 31, 2014, 2013 and 2012

(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:
2014	$	132	$	31		$	(38	)	$	125
2013		120		32			(20	)		132
2012		107		6			7			120
Allowance for excess and obsolete inventories:
2014	$	396	$	128		$	(154	)	$	370
2013		338		89			(31	)		396
2012		281		99			(42	)		338
Valuation allowance for deferred tax assets:
2014	$	133	$	(83	)	$	(2	)	$	48
2013		93		40			—			133
2012		13		80			—			93
Warranty reserve:
2014	$	228	$	123		$	(79	)	$	272
2013		194		101			(67	)		228
2012		211		51			(68	)		194

100