Delaware | | | | 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. Yesx☒ 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¨☐ Nox☒ 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. Yesx☒ 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). Yesx☒ 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, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer”, “smaller reporting company”, and “smaller reporting“emerging growth company” in Rule 12b-2 of the Exchange Act. (Check one): | | | | | | | Large accelerated filer | ☒ | x | | Accelerated filer | | ¨☐ | | | | | Non-accelerated filer | ☐ | ¨ (Do not check if a smaller reporting company) | | Smaller Reporting Company | ☐ | | ¨ | Emerging growth company | ☐ | | | | |
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to section 13(1) of the Exchange Act. ☐ Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes¨☐ Nox☒ The aggregate market value of voting and non-voting common stock held by non-affiliates of the registrant as of June 30, 20152018 was $18.7$16.6 billion. As of February 12, 2016,8, 2019, there were 375,800,956383,433,346 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 20162019 Annual Meeting of Stockholders are incorporated in Part III of this report.
FORM 10-K PART I General National Oilwell Varco, Inc. (“NOV” or the “Company”), a Delaware corporation incorporated in 1995, is a leading worldwideindependent provider in the design, manufacture and sale of equipment and components used intechnology to the upstream oil and gas industry. Over the course of its 156-year history, NOV and its predecessor companies have helped transform the way the industry develops oil and gas fields and improved the cost-effectiveness, efficiency, safety, and environmental impact of global oil and gas operations. Over the past few decades, the Company pioneered and refined key technologies that helped make frontier resources, such as unconventional and deepwater oil and gas, economically viable. NOV owns an extensive proprietary technology portfolio, which the Company uses to support the industry’s full-field drilling, completion, and production operations,needs. By leveraging its unmatched cross-segment capabilities, scope, and scale, NOV continues to develop and introduce technologies that further enhance oilfield economics, with particular focus on those technologies related to drilling automation, multistage completions, predictive analytics and condition-based maintenance, and improved deepwater project economics. Given the provisionbreadth and depth of oilfield servicesthe Company’s technology and product offerings, most oil and gas wells around the world see at least some piece of NOV equipment over the course of their lifetime. NOV serves major-diversified, national, and independent service companies; contractors; and oil and gas operators in 65 countries around the world. The Company currently operates under three segments: Wellbore Technologies, Completion & Production Solutions, and Rig Technologies. Business Strategy and Competitive Strengths NOV’s primary business objective is to further enhance its position in the marketplace as a leading independent provider of technology and equipment to the upstream oil and gas industry. The Company conductsintends to advance this objective and generate above-average returns on its capital over the long term by delivering technologies, equipment, and services that help lower the marginal cost of developing and producing oil and gas resources and by executing the following strategies that leverage the Company’s competitive strengths: Leverage NOV’s advantages of size, scope, scale, and position in the market NOV’s position as a leading independent provider of technology and equipment to the upstream oil and gas industry affords the Company several competitive advantages, as follows: Economies of scale in procurement and manufacturing. NOV’s market leadership and global footprint, which spans almost every major oilfield market, provides the Company with economies of scale. NOV’s scope and scale have enabled it to develop a unique global supply chain, which provides the Company with the ability to procure materials from the lowest-cost sources of supply around the world. The Company’s global manufacturing footprint and flexibility to produce a diverse array of products also enables NOV to rapidly adapt to changes in demand, efficiently leverage manufacturing capacity that is near high-demand areas, and manufacture goods in the lowest-cost jurisdictions. The geographic diversity of NOV’s footprint also reduces potential volatility in the Company’s revenues from shifts in location of oilfield activity around the world, regional differences in hydrocarbon prices, and adverse weather and other events. Scope and scale for distribution and marketing. As a leading independent provider of technology and equipment to the oilfield and with operations in approximately 835 locations across six continents.65 countries, NOV has developed an efficient global distribution network and relationships with virtually every oil and gas operator, service company, and contractor in the world. NOV uses its customer relationships and distribution capabilities to accelerate the commercialization of new products and technologies. NOV routinely develops technologies for use in the global marketplace. NOV’s infrastructure allows the Company to quickly penetrate the global marketplace and can create a first-mover advantage as customers prefer to standardize operations around certain products.
Reputation, experience, and benefits of fleet standardization. NOV’s reputation and experience make its products a lower-risk purchasing decision for customers. The Company benefits from customer efforts to standardize training, maintenance, and spare parts. Standardized fleets of equipment are easier for customers to operate and maintain, resulting in reduced downtime, lower training costs, better safety, and reduced inventory stocking requirements. Customers may prefer to standardize on equipment from a well-capitalized market leader such as NOV. NOV has entered into long-term service agreements with several large offshore drilling contractors whereby NOV will employ big data analytics and condition monitoring to maximize uptime and reduce the customer’s total cost of ownership for drill floor equipment. The Company’s principal executive officesLarge installed base of equipment. As a leading original equipment manufacturer (“OEM”) in the oilfield, NOV is in an excellent position to provide aftermarket support for the industry’s largest installed base of equipment. Most oilfield services customers prefer OEM aftermarket support of their equipment, and many of their E&P customers demand it. Customers frequently encounter higher risk and cost when they purchase and use potentially incompatible products from different vendors, particularly where products must interact through complex interfaces, which are located at 7909 Parkwood Circle Drive, Houston, Texas 77036,common sources of failures and unplanned costs. Additionally, certain past industry events increased the industry’s risk profile with government regulatory bodies, who have shown a strong preference for service contractors maintaining critical equipment through the OEM.
Digital products and technologies. NOV’s size and scale also provides for inherent competitive advantages in the areas of technology and innovation. NOV often develops technologies and solutions that involve multiple segments and businesses within the Company. Many such solutions could not be developed by smaller, less-diverse organizations, as an appropriate return on the cost of investment to develop certain technologies could not be achieved when applied to a more limited product offering. NOV’s efforts in big data, predictive analytics, and associated sensor technologies is an example of one such area. NOV has invested considerable time and resources to develop its telephone number is (713) 346-7500. Further information aboutMaxTM industrial platform, which enables large-scale collection, aggregation, and analytics of real-time equipment data. While the Company’sinitial application of this platform was a predictive analytics and condition-based monitoring solution for subsea blowout preventers, the platform was designed to be the backbone of all big data products and services canoffered by the Company and to be found on its website at:http://www.nov.com .used to monitor, analyze, and optimize many of the Company’s own manufacturing operations. Employ a capital-light business model with the ability to quickly scale operations NOV’s manufacturing operations are capital light and have low fixed-asset intensity. The Company’s annual reportsfacilities require relatively low investment and maintenance expenditures versus the sales they enable. NOV manufactures a diverse array of products across its manufacturing infrastructure and drives efficiency improvements by shifting production runs to facilities where demand is highest—lowering shipping costs—or to facilities that have the lowest-cost operations. The Company also realizes the benefit of serving a customer base that requires technically complex equipment used in extremely harsh environments. Placing sophisticated tools in a bottomhole assembly at the end of drillpipe to precisely place a wellbore several miles into the earth, and then physically cracking open reservoir rock using large volumes of highly abrasive fluids pumped at extremely high pressures, is incredibly hard on Form 10-K, quarterly reportsequipment. This harsh operating environment creates recurring sales opportunities for replacement equipment and aftermarket sales and service. NOV has organized its infrastructure to take advantage of the oil and gas industry’s cyclicality. As commodity prices rise, the oilfield typically enters an expansionary phase where large amounts of capital are deployed quickly and equipment orders increase in line. NOV maintains the ability to ramp up manufacturing capacity quickly to capture the value generated by up-cycles while meeting the demands of its customer base. During industry down-cycles, the Company focuses on Form 10-Qimproving internal efficiencies and current reportsadvancing technological offerings. NOV’s ability to continue, if not accelerate, pursuit of its technological initiatives throughout industry cycles enhances the Company’s ability to drive long-term customer and shareholder value. The Company also outsources non-critical machining operations with lower tolerance requirements during times of increased activity levels and brings the machining operations back into Company-owned facilities during down-cycles to improve asset utilization and lower costs.
Capitalize on Form 8-K, and drive end-market fragmentation A key tenet of NOV’s business model is to make its technologies and products available to all amendments thereto,industry participants. To the extent NOV can provide equipment and technology that is as good, if not better than, products developed by service providers, it will prevent any one organization from having a proprietary advantage and therefore drive fragmentation. This fragmentation expands NOV’s customer base and permits the Company to avoid customer concentration in most of its businesses. NOV has resisted the recent trend toward vertical integration, which has left the Company in an attractive and unique position in the marketplace as the only large-cap independent provider of technology and equipment to the oilfield service space. In the international markets, many countries are available freepursuing initiatives that drive local content and greater local employment in oilfield activity. These actions will likely prompt more local startup enterprises, further expanding the number of chargecustomers for NOV’s equipment. Develop proprietary technologies and solutions that assist oil and gas operators in reducing their marginal cost of supply NOV strives to further develop its substantial technology portfolio and has a reputation for rapidly developing innovative solutions that assist its customers’ pursuit of productivity gains. The Company is well positioned to leverage resources and introduce new breakthrough technologies, including digital products that enhance efficiencies and address industry needs, while generating strong returns. The Company’s unmatched cross-business-unit capabilities and expertise uniquely position NOV to pioneer proprietary technologies across its business lines. For example, NOV’s Wellbore Technologies and Rig Technologies segments jointly introduced closed-loop drilling technologies, which link data from the bottom of the well to the software controls of the drilling rig and use machine learning to drive greater efficiency. NOV works closely with customers to identify needs and its technical experts utilize internal research and development capabilities to develop value-added technologies. Employ a conservative capital structure with ample liquidity to capitalize on its Internet website. These reports are posted on the website as soon as reasonably practicable after they are electronically filedvolatility associated with the Securitiesoil and Exchange Commission (“SEC”). The Company’s Code of Ethics is also posted on its website.gas industry NOV maintains a conservative capital structure, with an investment grade credit rating and ample liquidity. The Company hascarefully manages its capital structure by continuously monitoring cash flow, capital spending, and debt capacity. Maintaining financial strength inspires confidence from customers who provide NOV with large purchase commitments that the Company delivers over multi-year timeframes. This provides NOV with the flexibility to execute its strategy, including advancing technological offerings, through industry volatility and commodity price cycles. The Company intends to maintain a long traditionconservative approach to managing its balance sheet to preserve operational and strategic flexibility. Business Segment Overview Wellbore Technologies provides the critical technologies, equipment, and services required to maximize customer efficiencies and economics associated with oil and gas wells. The segment’s offerings are provided through the following business units: ReedHycalog is a market-leading designer and manufacturer of pioneering innovations whichdrill-bit technology, a provider of borehole enlargement systems, and an independent supplier of directional drilling tools and optimization software and services. Distinguished by its industry-leading cutter technology, ReedHycalog’s drill-bit offering features both fixed-cutter and roller-cone bits designed to improve drilling times and overall well efficiencies. ReedHycalog also manufactures tools that enable the cost-effectiveness, efficiency, safetyprecise placement of the wellbore within the desired reservoir location, including measurement-while-drilling tools and environmental impactdynamic rotary steerable systems. ReedHycalog harnesses NOV’s unique ability to link downhole tools and services with surface equipment to provide the world’s first closed-loop drilling automation and optimization system, combining heuristic functions and machine-learning capabilities to transform drilling performance and operations. Downhole is a leading independent equipment supplier in the drilling and intervention segment of the industry, with engineering teams, manufacturing facilities, supply hubs and service centers situated in regions of oil and gas activity. With a constantly-evolving product portfolio that includes downhole drilling motors, agitator systems, as well as fishing and thrutubing tools, the Downhole business unit’s offerings enable its customers to achieve significant increases in efficiency, whether in drilling, workover or intervention operations. The Company’s common stock
| • | WellSite Services is a leading provider of solids control and waste management equipment and services, drilling and completion fluids, data acquisition and analytics, water management solutions, managed-pressure-drilling systems, and wellsite logistics solutions. WellSite Services manufactures, sells, and rents highly engineered solids control equipment and provides field services that improve customers’ bottom lines by efficiently separating solids and reclaiming drilling fluids for re-use. After separating drill cuttings, WellSite Services provides waste management (both onsite and at centralized locations), including transport and storage. Additionally, WellSite Services provides high-performance drilling fluid and water management solutions with a network of experts that safely work at the wellsite to ensure that operators have the support they need to bring their wells in on-time and on-budget. MD Totco delivers real-time measurement and monitoring of critical parameters required to improve rig safety and efficiency. Access to data and analytics are provided to offsite locations and mobile applications, enabling company personnel to monitor drilling operations through a secure link. WellSite Services offers a diversified range of resources to help manage the full lifecycle of the wellsite from initial preparation to worksite abandonment, including generators, temperature-control equipment, portable lighting, and other wellsite accessories. |
Tuboscope is traded ona leader in tubular coating and inspection services, servicing drill pipe and other oil country tubular goods (“OCTG”) such as casing, production tubing, and line pipe. Backed by an 80-year track record, Tuboscope offers a fully integrated inspection, coating, and repair process that enables customers to be confident that their critical OCTG will behave as they should when needed. In addition, Tuboscope offers artificial lift rod solutions, line-pipe connection systems, and RFID technology for complete drillpipe lifecycle management. Grant Prideco is a leading manufacturer of premium drill-stem tubulars. With an integrated supply chain and a strong position in the New York Stock Exchange undercompetitive premium drillpipe connections, Grant Prideco offers one stop shopping for all drill stem needs. Armed with a product portfolio that ranges from the symbol “NOV”. The Company operates through four reporting segments: Rig Systems, Rig Aftermarket, Wellbore Technologiesneeds of the simplest vertical land well to the challenging needs of deepwater, extended-reach, high-pressure/high-temperature, and factory-drilling applications, Grant Prideco innovates with advanced metallurgical grades and connection technologies. | • | IntelliServ is the only independent commercial provider of wired drillpipe complete with an associated telemetry network that utilizes real-time broadband data transmission to enable instantaneous two-way communication between the bottomhole assembly and surface control system. IntelliServTM wired pipe enables significant rig time savings as surveys, downlinks, slide orientations, and other data-driven activities are performed in a matter of seconds versus minutes with conventional telemetry. |
Completion & Production Solutions. On May 30, 2014,Solutions provides the Company completedcritical technologies necessary to optimize the spin-offwell completion process and production phase of its distributiona well’s life cycle. Completion & Production Solutions 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 sharesunits include:
| • | Intervention and Stimulation Equipment (“ISE”) engineers and manufactures capital equipment and consumables and provides aftermarket service and repair to oilfield pressure pumpers, coiled tubing operators, wireline service companies, and providers of well testing and flowback services. ISE manufactures and assembles all equipment used to execute hydraulic fracturing jobs with particularly strong positions in the higher-valued technologies and complex process equipment, such as hydration units, chemical additive systems, blenders, and control systems. In addition, the business unit produces essential consumable components that support pressure pumping spreads, including centrifugal pumps, fluid ends, valves, seats, and flowline equipment. The business unit also designs and manufactures equipment used to pump, mix, transport, and store cement used in the well construction process. ISE is a leading provider of coiled tubing units, control systems, pressure control equipment, injector heads, and coiled tubing itself. ISE also provides nitrogen equipment and snubbing units. The business unit designs and manufactures wireline products for electric and slickline line applications, including critical pressure control equipment like wireline lubricators. Additionally, ISE designs and manufatures equipment for |
| | surface well-test and flowback operations. ISE supports its equipment offering by providing comprehensive repair, recertification and other support services through an unmatched global network of aftermarket service and repair facilities. |
Fiber Glass Systems is a market leader in the open market at prevailing ratesdesign, manufacture, and distributed the net cash proceeds, after deducting any taxes requireddelivery of high-end composite piping systems, pressure vessels, and structures engineered to be withhelddeliver customers with solutions to both corrosion and brokerage chargesweight challenges across a wide array of applications. With manufacturing facilities spanning five continents and commissions, pro rata to each holder who would otherwise have been entitled to receive fractional sharesa sales and distribution network covering 40 countries, Fiber Glass Systems serves customers in the distribution. Our operating segments were realigned uponoil and gas, chemical, industrial, marine, offshore, subsea, fuel handling, and mining industries. Process and Flow Technologies provides integrated processing, production, and pumping equipment to customers in the oil and gas and industrial markets. For the production space they manufacture pumping technologies, including reciprocating, multistage, and progressive cavity pumps, as well as artificial lift support systems. For the midstream space they manufacture closures, transfer pumps, and valves. In the fluid processing space they design and manufacture integrated systems that provide water treatment, separation, sand management, hydrate inhibition, and gas processing for use both on and offshore. In the Industrial market they manufacture pumping, mixing, agitation equipment, and heat exchangers for general use in industrial end-markets.This equipment is supported by a global aftermarket service organization. Subsea Production Systems strives to improve subsea infrastructure through technical innovation that improves customer productivity and reduces cost. The business unit is one of NOW Inc.,only three global manufacturers of flexible subsea pipe systems, which are designed to operate under demanding offshore conditions around the world. Flexible pipes are highly engineered, complex structures that are helically wound and comprised of multiple unbonded layers of steel and composites, which allow them to withstand the demanding pressures and tensile loads required in deepwater production while remaining resistant to the fatigue induced by wave and tidal action. Subsea Production Systems also provides an assortment of critical equipment necessary for subsea production, such as subsea water injection systems, tie-in connector systems, subsea storage units, and other related equipment. Floating Production Systems offers a result, all prior periodscomprehensive technology suite geared towards improving offshore economics by providing cost-effective ways for operators to get their projects to first oil faster. Floating Production Systems offers turret mooring systems and topside process modules that are presenteddesigned to minimize execution risk and maximize operability and crew safety. Floating Production Systems has the capability to partner with the operator from concept to redeployment as well as to simply operate as the equipment provider. NOV, along with alliance partners, offers complete technology, engineering, and product delivery capabilities to supply comprehensive topside solutions for FPSO projects. XL Systems provides integral and weld-on connectors for oil and gas applications, including conductor strings, surface casing, and liners, in sizes ranging from 16 to 72 inches in diameter. XL Systems is the sole provider of a proprietary line of wedge thread connections on this basis. Resultslarge-bore pipe. In addition, XL Systems supplies connector products in which the threads are machined on high-strength forging material and then welded to pipe. | • | Completion Tools offers a portfolio of differentiated completion tool products and solutions that address the most pressing needs of the global completions marketplace. The Completion Tools business’ product portfolio is highlighted by proprietary technology like the Bulldog Frac Sleeve, which utilizes a coiled tubing annular frac system to isolate and stimulate stages while being lighter and easier to handle than other sleeves on the market. Other proprietary technologies include the BPSTM (Burst Port System) Multistage, the BullmastiffTM Frac System, and i-Frac CEMTM ball-drop-activated multistage frac sleeve. The portfolio also includes liner hanger systems, sub-surface safety valves, and a variety of bridge plugs. |
Rig Technologies is the global leader in the engineering, manufacturing, and support of operationsadvanced drilling equipment packages and 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 needednecessary to drill oil and gas wells onanywhere in the world. Rig Technologies includes:
| • | Rig Equipment designs, manufactures, and sells land rigs, complete offshore drilling packages, and drilling rig components designed to mechanize and automate many complex drilling rig processes. Rig Equipment’s product portfolio includes many equipment designs that changed the way rigs are operated, including the TDS top drive drilling system and automated roughneck. As the oil and gas industry has pushed the boundaries of geology and engineering with the move into the ultra-deepwater and onshore unconventional plays, the Rig Equipment unit has met the increasing challenges of its customer base with constant improvements to both its land and offshore rig equipment offerings. An example of this is the recently introduced NOVOSTM control system that offers drilling process automation, which enables dramatic improvements in drilling efficiency, reliability, and performance. The business unit also provides comprehensive aftermarket products and services to maximize its customers’ rig fleets’ drilling uptime. Aftermarket offerings include spare parts, repair, and rentals as well as comprehensive remote equipment monitoring, technical support, field service, and customer training through an extensive network of aftermarket service and repair facilities strategically located in major areas of drilling operations around the world. |
Marine Construction designs, engineers, and offshore. The segment designs, manufactures heavy-lift cranes; a large range of knuckle-boom and sells land rigs, offshore drilling equipment packages,lattice boom cranes, including installationactive heave options; mooring, anchor, and commissioning services,deck handling machinery; a full range and drilling rig components that mechanizemodels of jacking systems; and automatepipelay and construction systems. Marine Construction serves 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 rentalsindustry 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.other marine-based end markets.
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; portable power generation; premium drill pipe; wired pipe; drilling optimization and automation services; tubular inspection, repair and coating services; rope access inspection; instrumentation; measuring and monitoring; downhole and fishing tools; steerable technologies; hole openers; 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 revenue of our four reporting segments (in millions):
| | | | | | | | | | | | | | | Years Ended December 31, | | | | 2015 | | | 2014 | | | 2013 | | Revenue: | | | | | | | | | | | | | Rig Systems | | $ | 6,964 | | | $ | 9,848 | | | $ | 8,450 | | Rig Aftermarket | | | 2,515 | | | | 3,222 | | | | 2,692 | | Wellbore Technologies | | | 3,718 | | | | 5,722 | | | | 5,211 | | Completion & Production Solutions | | | 3,365 | | | | 4,645 | | | | 4,309 | | Eliminations | | | (1,805 | ) | | | (1,997 | ) | | | (1,441 | ) | | | | | | | | | | | | | | Total Revenue | | $ | 14,757 | | | $ | 21,440 | | | $ | 19,221 | | | | | | | | | | | | | | |
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 ourthe 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 and through 2015 the global oil and gas industry experienced a cyclical decline causing the Company to experience a decline in new orders. Backlog for Rig Systems at December 31, 2015, 2014 and 2013, was $6.1 billion, $12.5 billion and $15.0 billion, respectively. Backlog for Completion & Production Solutions at December 31, 2015, 2014 and 2013 was $1.0 billion, $1.8 billion and $1.6 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: prices for oil and gas; supply and demand for oil and natural gas; the ability or willingness 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; 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 ConstructionWell-Construction Processes OilThe well-construction process starts with an operator and gas wells are usually drilled byits contractors designating a suitable drilling contractors usingsite and placing a drilling rig. A bit is attached torig at the end of alocation. The rig’s crew assembles the drill stem, which is assembled by the drilling rig and its crew from 30 or 45-footconsists of drillpipe joints, of drill pipe and specialized drilling components known as downhole tools. Usingtools, and a drill bit at 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 ofend. Modern rigs typically power the drill stem. Increasingly, drilling is performed usingbit through 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.stem. The useevolution of drilling motors and top drives permits the drilling contractorhas facilitated operators’ abilities to drill directionally including horizontally.and horizontally as opposed to being limited to the traditional vertical trajectory. The Company sells and rents drilling motors, agitators, drill bits, downhole tools and drill pipe through Wellbore Technologies, and sells top drives through Rig Systems.Technologies.
Heavy drilling fluids, or “drilling muds”,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,compounds, to be continuously reused and re-circulated back into the hole. Rig SystemsTechnologies 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;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 the corrosive fluids sometimes encountered during drilling; have hardfacinghard-facing alloys applied to drill pipedrillpipe joints, collars, and other components to protect tool joints and casing against wear; and inspect and assess the integrity of the drill pipedrillpipe from time to time. Wellbore Technologies manufactures and sells drill pipedrillpipe and provides coating, “hard-banding”,“hardfacing,” and drill pipedrillpipe inspection and repair. As the hole depth increases, the kelly must be removed frequently so that additional joints of drill pipe can bedrillpipe are continuously added to the drill stem. When the bit becomes dull or the equipment at the bottom of the drill stem—stem – including the drilling motors—motors – otherwise requires servicing, the entire drill stem is pulled out of the hole and disassembled by disconnecting the joints of drill pipe.drillpipe. These are set aside or “racked”,“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 pipedrillpipe must be screwed together and tightened (“made up”), and loosened and unscrewed (“spun out”)., a process that can create a considerable amount of stress on the pipe connections while also being quite time consuming. Rig SystemsTechnologies provides drilling equipment to manipulate and maneuver the drill pipedrillpipe in this manner.an efficient and safe manner, and Wellbore Technologies manufactures premium connections that are designed to reduce failure downhole and improve the rate of connection on the rig floor. When the hole has reached certain depths,a specified depth, all of the drill pipedrillpipe is pulled out of the hole, and larger diameterlarger-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. Wellbore Technologies drilling optimization and automation maximizes bit performance in the wellbore by mitigating vibrations, dynamic and impact loading, and stick slip which ensures longer bit runs, reducing trips. Hole openers from Wellbore Technologies, thatwhich mount above the drill bits in the drill stem, opensopen the tolerance of the hole to allow for easier and faster casing installation. Completion & Production Solutions manufactures pressurecement mixing and 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 tackleblock-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 SystemsTechnologies sells and installs drawworks and pipe hoisting systems.hoisting-systems. During the course of normal drilling operations, the drill stem passes through different geological formations whichthat 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.inadequate. 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, requires a high level of cleanliness for better bottom holebottomhole assembly, performance 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 provides drilling fluids and rents, sells, operates, and services thissolids control equipment. Rig Technologies manufactures pumps that power the flow of the mud and fluid downhole and back to the surface. Drilling muds are formulated based on expected drilling conditions. However, as the hole is drilled, the drill stem may encounter a high pressurehigh-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 preventersBOPs 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, conventionalConventional BOPs prevent normal rig operations when closed so the BOPs are activated only if drilling mud and normal well control procedures cannot safely contain the pressure. Rig Technologies engineers and manufactures BOPs. 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, weight on bit, etc. Wellbore Technologies sells and rents drilling rig instrumentation packages that perform these monitoring functions. Monitoringfunctions as well as additional sensors that continuously collect downhole data that can be done attransmitted back to the well or remotely from selected centralized operation centers.surface via wired drill pipe. Wellbore Technologies’ also offers drilling optimization and automation software and services that utilize this downhole data to maximize drilling performance by mitigating vibrations, dynamic and impact loading, and stick-slip, which ensures longer bit runs, and reduces the number of necessary trips.
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 AftermarketTechnologies supplies spare parts and can dispatch field service engineers with the expertise to quickly repair and maintain equipment, minimizing down time. After theOnce a well has reached its total depthbeen drilled, cased, and cemented, and the final section of casing has been set, the drilling rig is moved off andoperator determines hydrocarbons are present in commercial quantities, the well is preparedthen completed, and sometimes stimulated. After the casing is cemented in place, the well undergoes one of several completion processes to begin producing oilopen the bottom of the wellbore and allow hydrocarbons to flow from the reservoir and up the well to the surface. The most commonly used technique is known as perforation. The perforating process entails lowering a string of shaped charges to the desired depth in the well using an electric wireline unit and firing the charges to perforate the casing or gas inliner. Wireline units are also used to perform logging operations and other intervention services. At this point, the operator may decide, based on well design and flow rate, to further enhance production by stimulating the well. Unconventional wells almost always require stimulation through multi-stage hydraulic fracturing, a process known as “well completion.” Well completion usually involves installing production tubing concentricallyby which a fluid or slurry is pumped down the well by large pumping units. This causes the underground formation to crack or fracture, opening up space for hydrocarbons to flow more freely out of tight rock formations. A proppant is suspended in the casing.fluid and lodges in the cracks, propping them open and allowing hydrocarbons to flow after the fluid is gone. A coiled tubing unit is often used to drill out bridge plugs that isolate the many stages needed to stimulate a horizontal well. A coiled tubing unit utilizes a large continuous length of steel tubing to enter and traverse long laterals and perform completion and well remediation operations. As drilling laterals have lengthened in recent years, many operators are electing to use larger high-specification well service rigs to assist in several phases of the completion phase by conveying tools downhole and drilling out completion plugs. Workover rigs are similar to drilling rigs in their capabilities to handle tubing but are usually smaller and somewhat less sophisticated. Completion & Production Solutions provides the essential equipment necessary for the entirety of the completion and stimulation process, designing and manufacturing coiled tubing units, wireline units, pressure pumping equipment, completion tools, snubbing units, nitrogen units, and treating iron. In addition, the well completion process creates a large amount of wear and tear on the equipment used, which creates healthy demand for Completion & Production Solutions’ aftermarket services. The use of coiled tubing and wireline equipment typically requires the use of a BOP to ensure safety during operations. Completion & Production Solutions manufactures this well control equipment. Due to the corrosive nature of many produced fluids, production tubing is often inspected and coated, services offered by Wellbore Technologies. SometimesIncreasingly, operators choose to use corrosion resistantcorrosion-resistant composite materials or alloys in the process, which are also sold by Completion & Production Solutions.
From timeOnce the well has been stimulated, it is usually ready to time,be capped with a production wellhead and linked up to a gathering system where it can begin producing and generating cash flow for the operator. This process is significantly more involved offshore, where pipes are often required to reach thousands of feet from the wellhead back to the surface, contending with tides, debris, and weather. The development of flexible pipe solved many of the issues associated with linking offshore wells back to their respective floating production, storage, and offloading vessels (“FPSOs”), which serve as gathering hubs, sometimes in some of the most remote areas of the world. Completion & Production Solutions is one of only three global manufacturers of flexible subsea pipe in addition to offering turret mooring systems and topside process modules for FPSOs.
Natural decline rates set in as a well may undergoages, and workover procedures and other services may be necessary to extend its life and/orand increase its production rate. Over time, downhole equipment, casing, or tubing may need to be serviced or replaced. When producing wells require anything from routine maintenance to major modifications and repair, a well servicing rig is typically needed. 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 similarAs a well continues to drilling rigsmature, its natural reservoir pressure may no longer be enough to force fluids to the surface. Artificial lift equipment is then typically installed, which adds energy to the fluid column in their capabilitiesa wellbore using one of several types of pumps. In addition to handle tubing, but are usually smallerreduced pressure, the water cut of a well’s production tends to increase as the well ages, which typically requires the addition of water treatment and somewhat less sophisticated.separation equipment. The Company offers a comprehensive range of workover rigs through Rig Systems.Technologies. 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 consists 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 variousoffers several types of coiled tubingartificial lift and wireline equipmentrelated support systems as well as integrated systems that provide water treatment, separation, hydrate inhibition, and tools.gas processing.
Rig SystemsMarkets and Competition
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.
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 alsocustomers 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 an 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 ShearMaxTM 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.
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 Ideal Rig™, Drake 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.
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, the majority 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 andre-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; portable power generation; premium drill pipe; wired pipe; drilling optimization and automation services; tubular inspection, repair and coating services; rope access inspection; instrumentation; measuring and monitoring; downhole and fishing tools; steerable technologies; hole openers; 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 premium 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%. In addition, the Company offers a mechanical fit connection that is very quick to field install and combined with internal coatings provides a continuous internal surface of coatings thru the connection. The Company also offers other corrosion solutions such as fiberglass lined tubing that also services our customers as it relates to wells that are injection or enhance oil recovery wells.
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. In addition to our Tubular Inspection product line, we have a Specialty Inspection group that performs rig inspections, drop surveys, lift gear inspections and derrick building services via rope access with locations around the world to service the land and offshore contractors.
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, Repair and 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 & 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™ friction reduction tool delivers improved drilling efficiency along with extending the reach of horizontal drilling applications.
The Company manufactures an extensive range of hole-opening solutions, borehole enlargement, which produce enlarged wellbores in numerous applications and operate in demanding environments around the world.
The Company manufactures steerable technologies that allow for borehole directional control, enabling our customers to drill more efficiently in challenging environments globally.
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 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 for measuring, data-driven solutions used for monitoring, 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 (both at the surface and in the wellbore) 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 (both onsite and at centralized locations), 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 bits. Wellsite Services provides water and oil based drilling fluids
Portable Power Generation. 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, rental companies, 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, 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 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 often extend over twenty 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 pumpers, 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 can fail under corrosive operating conditions. The Company’s Fiberspar™ business, manufactures and sells fiberglass-reinforced spoolable pipe to the oil and gas industry which provides a reliable, corrosion-resistant, cost-effective solution for 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 Flow 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, oil and gas companies, and fabricators, as well as distributors in select markets. 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; Weir Group; and a number of regional competitors. Management believes that on-site support is becoming a more important competitive element in this market, and other competitive factors affecting the business are performance, quality, reputation, customer service, product availability and technology, breadth of product line and price.
2015 Acquisitions and Other Investments
During 2015, the Company completed a total of seven acquisitions and other investments for an aggregate investment of $86 million, net of cash acquired.
2015 Realignment
From time to time the Company realigns the structure of its organization to achieve business goals, including enhanced efficiency and cost reduction. In November, certain of the Company’s subsidiaries completed restructuring transactions intended to achieve these goals, through a strategic realignment of certain business units. These restructuring activities include: (a) a division of National Oilwell Varco, L.P. (“NOV LP”) allocating certain assets and liabilities associated with the Chemineer and Process & Flow Technologies business units to Chemineer, Inc. and NOV Process & Flow Technologies US, Inc., respectively; (b) realignment of the structure of Robbins & Myers, Inc. (“R&M”) and distribution of R&M’s equity ownership in certain subsidiaries to Grant Prideco, Inc. (“Grant Prideco”), a direct subsidiary of the Company; (c) realignment of business units of Ameron International Corporation (“Ameron”) including (i) the contribution of certain assets and liabilities corresponding to two divisions (respectively, the water transmission and pole products divisions) into separate subsidiaries of Ameron, and (ii) the distribution by Ameron of all of the outstanding membership interest in Tubo-FGS, LLC (a fiberglass pipe business unit) and certain intangible intellectual property assets to its parent Grant Prideco for strategic realignment with Grant Prideco’s fiberglass pipe division; (d) distribution of certain intangible intellectual property assets from subsidiaries to a holding company subsidiary; (e) realignment of the ownership structure of National Oilwell DHT; and (f) elimination of certain intercompany balances between subsidiaries through distribution, setoff or assignment, including without limitation intercompany balances between NOV LP and certain divisions of Fiber Glass Systems, L.P., as obligors, and Ameron, as obligee.
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 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 businessesProducts 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,are sold and road bans that curtailed drilling activity (“Canadian Breakup”). However, these segments have typically rebounded in the thirdrented worldwide through NOV’s sales force and fourth quarter. Wellbore Technologies and Completion & Production Solutions activity in the U.S. 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. 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.
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.
Marketing and Distribution Network
through commissioned representatives. Substantially all of Rig Systems’Technologies’ capital equipment and Rig Aftermarket’s spare parts sales, and a large portion of our smaller pumps and parts sales, are made through ourNOV’s direct sales force and distribution service centers. Sales to foreign oil companies are often made with or through representative arrangements. Products within Wellbore Technologies The Company’s competition consists primarily of publicly traded oilfield service and Completion & Production Solutions are rented and sold worldwide through our own sales force and through commissioned representatives. Completion & Production Solutions’ customers are predominantly serviceequipment 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.smaller independent equipment manufacturers.
The Company’s foreign operations, which include significant operations in Canada, Europe, Russia, the Far East, the Middle East, Africa and Latin America, Russia, the Far East, Canada and Europe 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. 2018 Acquisitions and Other Investments During 2018, the Company completed a total of eight acquisitions and other investments for an aggregate cash investment of $280 million, net of cash acquired. 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. 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 OCTG to invest in equipment that the Company sells. 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.” Seasonal Nature of the Company’s Business Historically, activity levels of some of the Company’s segments have followed seasonal trends to some degree. Extremely harsh winter weather can reduce oilfield operations in far northern or high-altitude locations, including parts of Colorado, Canada, Russia and China, and the annual thaw (or “breakup”) in Canada makes some unimproved roads inaccessible to heavy equipment during part of each second quarter. Both situations temporarily reduce demand for the Company’s products and services in the effected geographic area, although revenues generally recover once conditions improve. Fluctuations in customer’s activity levels caused by national or customary holiday seasons and annual budgetary cycles can also affect their spending levels with the Company, leading to both temporary local decreases and increases in sales. 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.
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 tradetrademarks, for both goods and service marks,services, patents, trade secrets, and other proprietary rights. As of December 31, 2015,2018, the Company held a substantial number of United Statesgranted patents and had additionalpending patent applications pending. As of this date, the Company also had foreignworldwide, including US patents and US patent applications as well as patents and patent applications pending relatingin a variety of other countries. Expiration dates of such patents range from 2020 to inventions covered by the United States patents.2039. Additionally, the Company maintains a substantial number of tradetrademarks for both goods and service marksservices and maintains a number of trade secrets. Expiration dates of such patents range from 2016 to 2035. 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 revenue 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, Texas; Orange, California; 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; New Iberia, Louisiana; Aberdeen, Scotland; Singapore; and Dubai, UAE.
Wellbore Technologies 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,drillpipe, wired pipe, drilling optimization services, tubular inspection and coating services, instrumentation, downhole tools, and drill bits. Primary facilities are located in Houston, Conroe, Navasota, and Cedar Park, Texas; Veracruz, Mexico; and Dubai, UAE. Completion & Production Solutions 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;manifolds; well intervention, including coiled tubing units, coiled tubing, and wireline units and tools; cementing products for pumping, mixing, transport, and storage; onshore production, including fluid processing, composite pipe, surface transfer and progressive cavity pumps, and artificial lift systems; and offshore production, including floating production systems and subsea production technologies. Primary facilities are located in Houston, and Fort Worth, Texas; Tulsa, Oklahoma; Senai, Malaysia; Qingdau, Shandong, China; Kalundborg, Denmark; Superporto du Acu, Brazil; Manchester, England; and Manchester, England.Aberdeenshire, Scotland, UK. Rig Technologies provides drilling rig components, complete land drilling rigs, and offshore drilling equipment packages. Primary manufacturing facilities are located in Houston, Texas; Orange, California; New Iberia, Louisiana; Singapore; and Dubai, UAE. Raw Materials The Company believes that materials and components used in its operations 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 mildmilled 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.
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 and Rig Technologies 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 whichthat 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, 2015, 2014 and 2013, was $6.1 billion, $12.5 billion and $15.0 billion, respectively. Backlog for Completion & Production Solutions at December 31, 2015, 20142018, 2017 and 20132016 was $1.0$0.9 billion, $1.8$1.1 billion and $1.6$0.8 billion, respectively. Backlog for Rig Technologies at December 31, 2018, 2017 and 2016, was $3.1 billion, $1.9 billion and $2.5 billion, respectively. Employees At December 31, 2015,2018, the Company had a total of 50,19735,063 employees, of which 5,871843 were temporary employees. Approximately 470 employees in the U.S. areand 294 were subject to collective bargaining agreements.agreements in the U.S. Additionally, certain of the Company’s employees in various foreign locations are subject to collective bargaining agreements. Based upon the geographical diversification of these employees, we do not believe any risk of loss from employee strikes or other collective actions would be material to the conduct of our operations taken as a whole. Available Information The Company believesCompany’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 relationshipwebsite at: http://www.nov.com. The Company’s common stock is traded on the New York Stock Exchange under the symbol “NOV”. The Company’s annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and all related amendments are available free of charge on the Investor Relations portion of the Company’s website, www.nov.com/investor, as soon as reasonably practicable after such material is electronically filed with, or furnished to, the Securities and Exchange Commission (“SEC”). The Company’s Code of Ethics is also posted on its employees is good. website.ITEM 1A.RISK FACTORSYou 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.volatile and has caused, and may cause future, fluctuations in our operating results. 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: including the: the current and anticipated future prices for oil and natural gas; the ability or willingnessvolatility of the membersprices for oil and natural gas;
| • | ability or willingness of the Organization of Petroleum Exporting Countries, or OPEC, to maintain price stability through voluntary production limits;the members of the Organization of Petroleum Exporting Countries (“OPEC”) and other countries, such as Russia, to maintain or influence price stability through voluntary production limits; |
Sanctions and other restrictions placed on certain oil producing countries, such as Russia, Iran, and Venezuela; level of production by non-OPEC countries;countries including production from U.S. shale plays; level of excess production capacity; cost of exploring for and producing oil and gas; level of drilling activity and drilling rig dayrates; worldwide economic activity and associated demand for oil and gas; availability and access to potential hydrocarbon resources; national government political requirements; fluctuations in political conditions in the United States and abroad; currency exchange rate fluctuations and devaluations; development of alternate energy sources; and, environmental regulations. The current significant oil and gas industry downturn has resulted in reduced demand for oilfield services, which has had, and may continue to have, a significant adverse impact on our financial results. If these conditions worsen or oil and gas prices do not improve, further reductions in spending by the oil and gas industry could have a material adverse effect on our financial condition, results of operations and cash flows.
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, and other service companies, 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 fallremain below a range that is acceptable to certain of our customers, which could reducecontinue the reduced demand for our products.products and have a material adverse effect on our financial condition, results of operations and cash flows. There are risks associated with certain contracts for our equipment. As of December 31, 2015,2018, we had a backlog of capital equipment to be manufactured, assembled, tested and delivered by Rig Systems and Completion & Production Solutions and Rig Technologies in the amount of $6.1$0.9 billion and $1.0$3.1 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: financial challenges for consumers of our capital equipment; credit market conditions for consumers of our capital equipment; our failure to adequately estimate costs for making this equipment; our inability to deliver equipment that meets contracted technical requirements; our inability to maintain our quality standards during the design and manufacturing process; our inability to secure parts made by third party vendors at reasonable costs and within required timeframes; unexpected increases in the costs of raw materials; and our inability to manage unexpected delays due to weather, shipyard access, labor shortages or other factors beyond our control.control; and, the imposition of tariffs or duties between countries, which could materially affect our global supply chain. For example, section 232 tariffs on steel may increase our costs, reduce margins or otherwise adversely affect the Company.
The Company’s existing contracts for rig and production 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. We consummated a settlement with a shipyard customer on December 28, 2015 concerning seven contracts for the supply of drilling equipment packages for drillship construction projects in Brazil (collectively the “Supply Contracts”). Pursuant to the terms of the settlement, the Supply Contracts have been terminated. We did not take a charge as a result of the settlement; however we did reduce the Rig Systems segment backlog by $1.2 billion in the quarter. At December 31, 2015, our backlog included $1.8 billion for the remaining 15 rigs across three shipyards in Brazil. Competition in our industry, including the introduction of new products and technologies by our competitors, as well as the expiration of the intellectual property rights protecting our products and technologies, could ultimately lead to lower revenue 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 revenue and earnings: new product and technology introductions; and
improvements in the availability and delivery.delivery of products and services by our competitors; the introduction of new products and technologies by our competitors; and, the expiration of intellectual property rights protecting our products and technologies. We are a leader in the development of new technology and equipment to enhance the safety and productivity of drilling and well servicing processes. If we are unable to maintain our technology leadership position, it could adversely affect our competitive advantage for certain products and services. Our revenues and operating results have been dependent, in part, upon the successful introduction of new or improved products. Through our internal development programs and acquisitions, we have assembled an extensive array of technologies protected by a substantial number of trade and service marks, patents, trade secrets, and other proprietary rights, some of which expire in the near future. The expiration of these rights could have a material adverse effect on our operating results. Furthermore, 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 revenue from new products. The tools, techniques, methodologies, programs and components we use to provide our services may infringe upon the intellectual property rights of others. Infringement claims generally result in significant legal and other costs and may distract management from running our core business. Royalty payments under licenses from third parties, if available, would increase our costs. Additionally, developing non-infringing technologies would increase our costs. If a license were not available, we might not be able to continue providing a particular service or product, which could adversely affect our financial condition, results of operations and cash flows. 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. Actions taken by our competitors and changes in local policies, preferences or regulations could impact our ability to compete in certain markets and adversely affect our financial results. We have expandedA significant portion of our businesses through acquisitions and internal growth and intendrevenue is derived from our non-United States operations, which exposes us to maintain a growth strategy.
We have expanded and grown our businesses during the past several years, through acquisitions and investmentrisks inherent in internal growth and continue to pursue a 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 acquireddoing business with our own or that our management will be able to manage effectively 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 obligationseach of the Company;
the ability to identify strategic acquisitions at reasonable prices;
the ability to manage and control operating costs of the Company;
fluctuationsover 65 countries 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.which we operate.
Approximately 75%60% of our revenues in 20152018 were derived from operations outside the United States (based on revenue destination). Our foreign operations include significant operations in Argentina, Canada, Brazil, Europe,every oil producing region in the Middle East, China, Africa, Nigeria, Southeast Asia, Russia, Latin America and other international markets.world. Our revenues and operations are subject to the risks normally associated with conducting business in foreign countries, including including: uncertain political, social and economic environments, which may limit or disrupt markets, restrict the movementenvironments; social unrest, acts 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 arrangementsterrorism, war 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.armed conflict;
| • | trade and economic sanctions and other restrictions imposed by the United States, European Union or other countries; |
Our operations outsiderestrictions under 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”), or similar legislation, as well as foreign anti-bribery and anti-corruption laws;
confiscatory taxation, tax duties, complex and everchanging tax regimes or other federal statutes,adverse tax policies; | • | exposure to expropriation of our assets and other actions by foreign governments; |
deprivation of contract rights; restrictions on the repatriation of income or capital; currency exchange rate fluctuations and devaluations. Our failure to comply with complex U.S. and foreign anti-bribery, anti-corruptionlaws and trade laws. Under U.S. trading sanctions laws, the government authorities may seek to impose modifications toregulations could have a material adverse effect on our business practices, including cessationand our results 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.operations. Our ability to comply with various complex U.S. and foreign laws and regulations, such as the FCPA, the U.K. Bribery Act and other foreign anti-bribery and anti-corruption laws, as well as various trade control regulations, is dependent on the success of our ongoing compliance program, including our ability to continue to effectively supervise train and retain competent employees. Our compliance program also depends on the efforts oftrain our employees to deter prohibited practices. These various laws and regulations can change frequently and significantly. We may become involved in a governmental investigation even if the Company has complied with these laws. If we fail to comply with applicable law. Welaws and regulation, we could be subject to investigations, sanctions and civil and criminal prosecution as well as fines and penalties, in the eventwhich could have a material adverse effect on our reputation and our business, financial condition, results of a finding of a violation of the FCPA or other anti-corruption laws by us or any of our employees. Compliance with,operations and changes in, laws could be costly and could affect operating results.cash flows. In addition, government disruptions could negatively impact our ability to conduct our business. We have operations in theare also required to comply with various complex U.S. and in approximately 70 countries thatforeign tax laws, regulations and treaties. These laws, regulations and treaties can be impacted bychange frequently and significantly and it is reasonable to expect changes in the legal and business environments in whichfuture. If we operate, including new legislation, newfail to comply with any of these tax laws, 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 countriestreaties, we could be subject to, sanctions,among other things, civil and changes in laws in countries where we operate or intendcriminal prosecution, fines, penalties and confiscation of our assets, which could disrupt our ability to operate allprovide our products and services to our customers. Any of these events could adversely impacthave a material adverse effect on our business.business, financial condition, results of operations and cash flows. 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. The Company could also become involved in investigations of consumers of our products at significant cost to the Company. The on-going, publicly disclosed investigationsWe 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 Brazilthe 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 shipyard customers, their customers, entities providing financing for our shipyard customers and/operations and financial condition.
Our businesses expose us to potential environmental, product or entities in the supply chain. We consummated a settlement with a shipyard customer on December 28, 2015 concerning seven contracts for the supply of drilling equipment packages for drillship construction projects in Brazil (collectively the “Supply Contracts”). Pursuantpersonal injury liability. Our businesses expose us to the termsrisk that harmful substances may escape into the environment or a product could fail to perform or cause personal injury, 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 litigation and 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 settlement, the Supply Contracts have been terminated. We did not take a charge following theories: breach of contract with customers; or, as a result of our contractual agreement to indemnify our customers in the settlement and, on a net basis, there was no changenormal course of business, which is normally the case. We may not have adequate insurance for potential environmental, product or personal injury 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 or may exclude coverage for other reasons. We face the following risks with respect to our prior estimates on our Brazil contracts impacting income; however insurance coverage: we did reduce the Rig Systems segment backlog by $1.2 billion in the quarter. At December 31, 2015, our backlog included $1.8 billion for the remaining 15 rigs across three shipyards in Brazil. The investigations in Brazil have led to, and are expectedmay not be able to continue to leadobtain 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 delays in deliveries tomeet their obligations under the policies; or, the dollar amount of any liabilities may exceed our shipyard customers in Brazil, along with temporary suspensionpolicy limits. Even a partially uninsured claim, if successful and of performance undersignificant size, could have a material adverse effect on our supply contracts, and could result in additional cancellationsconsolidated financial statements. The adoption of climate change legislation, restrictions on emissions of greenhouse gases, or other breaches of our contracts by our shipyard customers. Our shipyard customers’ customer in Brazil has stated its intent to build some of the drillships it originally contracted for with our shipyard customers. Customers (typically drillship owners or drilling contractors) of our shipyard customers have sought and may in the future seek to suspend, delay or cancel their contracts or payments due to such shipyards. As a result, our shipyard customers have sought and may in the future seek to suspend, delay or cancel deliveries of our drilling equipment packages for the affected drillships. To the extent our shipyard customers and their customers become engaged in disputes or litigation related to any such suspensions, delays or cancellations, we may also become involved, either directly or indirectly, in such disputes or litigation, as we enforce the terms of our contracts with our shipyard customers. Even though the contracts with our shipyard customers for the supply of drilling equipment packages do not provide for cancellation for convenience, in light of the decline in oil prices and the deterioration in the energy markets, we are starting to experience suspensions, delays and attempted cancellations with greater frequency. While we manage equipment deliveries and collection of payment to achieve milestone payments that mitigate our financial risk, such delays, suspensions, attempted cancellations, breaches of contract or other similar circumstances,environmental regulations could adversely affectincrease our operating resultscosts or reduce demand for our products.
Environmental advocacy groups and could reduce our backlog. Sanctions imposed byregulatory agencies in the United States European Union 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 businessoperations and financial condition. The U.S. Congress and other governments routinely consider legislation to control and reduce emissions of greenhouse gasses and other climate change related legislation, which could require significant reductions in emissions from oil and gas related operations. Additionally, recent concerns regarding the potential impact of hydraulic stimulation, or “fracking”, activities have resulted in or relatedgovernment officials promulgating regulations to Russiaimpose certain operational restrictions and certain Russian companies, including prohibitions of certain sales of goodsdisclosure requirements on oil and gas companies. 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, delays in executing construction or manufacturing projects, credit risk and adverse impacts due to currency fluctuations. To date, we have not identified any material adverse financialwhich could adversely 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.
Cybersecurity risks and threats could adversely affect our business. We have received U.S. federal grand jury subpoenas and subsequent inquiries from U.S. governmental agencies requesting records relatedrely heavily on information systems to conduct 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 Enforcementbusiness. Any failure, interruption or breach 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 conclusionsecurity of our internal reviewinformation 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 fourth quartereffect of 2009, we identified possible areasthe failure, interruption or security breach 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 anticipateour information systems, there can be no assurance that any administrative finesuch failures, interruptions or penalty agreedsecurity breaches will not occur or, if they do occur, that any breach or interruption will be sufficiently
limited. The occurrence of any failures, interruptions or security breaches of our information systems could damage our reputation, result in a loss of our intellectual property or other proprietary information, including customer data, result in a loss of customer business, subject us to as partadditional regulatory scrutiny, or expose us to civil litigation and possible financial liability, any of a resolution would be within established accruals, and would notwhich could have a material adverse effect on our financial position or results of operations. Local content requirements imposed in certain jurisdictions may increase the complexity of our operations and impact the demand for our services. A growing number of nations are requiring equipment providers and contractors to meet local content requirements or other local standards. To meet many of these local content and other requirements, we are required to attract and retain qualified local personnel. If we are unable to do so because the extentsupply of qualified local personnel is constrained for any reason, the growth and profitability of our business may be adversely affected. In addition, our ability to work in certain jurisdictions is sometimes subject to our ability to successfully negotiate and agree upon acceptable joint venture agreements. The failure to reach acceptable agreements could adversely impact the Company’s operations in certain countries. Additionally, we may share control of joint ventures with unaffiliated third parties. Differences in views, and disagreements, among joint venture parties may result in delayed decision making and disputes on important issues. In some instances, we could suffer a resolution is not negotiated as anticipated, we cannot predictmaterial adverse effect to the timing or effect that any resulting government actions may have onresults of our financial position orjoint ventures and our consolidated results of operations. The results ofOur ability to hire and retain qualified personnel at competitive cost could materially affect our operations and growth potential.
Many of the products we sell, and related services that we provide, are subjectcomplex and technologically advanced, which enable them to market risk from changesperform in foreign currency exchange rates. We earn revenues, pay expenses, purchase assetschallenging conditions. Our ability to succeed is, in part, dependent on our success in attracting and incur liabilitiesretaining qualified personnel to provide service and to design, manufacture, use, install and commission our products. A significant increase 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 kronewages paid by competitors, both within and the South Korean won. Approximately 75% of our 2015 revenue was derived from sales outside the United States. Becauseenergy industry, for such highly skilled personnel could result in insufficient availability of skilled labor or increase our Consolidated Financial Statements are presented in U.S. dollars, we must translate revenueslabor costs, or both. If the supply of skilled labor is constrained or our costs increase, our margins could decrease 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 willgrowth potential could be impaired.
Severe weather conditions may adversely affect our revenueoperations. Our business may be materially affected by severe weather conditions in areas where we operate. This may entail the evacuation of personnel and operating income. Becausestoppage of the geographic diversityservices. In addition, if particularly severe weather affects platforms or structures, this may result in a suspension 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 amountactivities. Any of $3,545 million (with a fair value of a net liability of $260 million) as of December 31, 2015, 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 notevents could adversely affect our financial results.condition, results of operations and cash flows. An impairment of goodwill or other indefinite lived intangible assets could reduce our earnings. The Company has approximately $7.0$6.3 billion of goodwill and $0.4 billion of other intangible assets with indefinite lives as of December 31, 2015.2018. 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 sustained reduction in worldwide oil and gas prices or drilling; a significant sustained reduction in profitability or cash flow of oil and gas companies or drilling contractors; a significant sustained 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 a possible increase in balance sheet leverage as measured by debt to total capitalization. In the fourth quarter of 2015, the Company impaired $1.6 billion of goodwill and other indefinite lived intangible assets. See additional discussion on “Goodwill and Other Indefinite—Indefinite – Lived Intangible Assets” in Critical Accounting Estimates of Item 7.7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”
We couldhave expanded and grown our businesses through acquisitions and continue to pursue a growth strategy but we cannot assure that attractive acquisitions will be adversely affected if we failavailable 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.us at reasonable prices or at all. 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 youthat we will successfully integrate the operations and assets of any acquired business with our own or that our operationsmanagement 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, product or personal injury liability.
Our businesses expose us to the risk that harmful substances may escape into the environment or a product could fail to perform or cause personal injury 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 litigation and 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, product or personal injury 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 or may exclude coverage for other reasons. 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 typesmanage effectively any new lines 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 attentionbusiness. Any inability on the emissionspart of carbon dioxide, methanemanagement to integrate and other greenhouse gasesmanage acquired businesses 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 year ended December 31, 2013.
The loss of this customer (Samsung Heavy Industries) or a significant reduction in its purchasesassumed liabilities could adversely affect our business and financial performance. In addition, we may need to incur substantial indebtedness to finance future revenuesacquisitions. We cannot assure 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 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 4% of total revenue and 7% of total revenue from Samsung Heavy Industriesamortization expense, increased interest expense, increased financial leverage or decreased operating income for the years ended December 31, 2015 and 2014, respectively.
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 any breach or interruption will be sufficiently limited. The occurrence of any failures, interruptions or security breaches of 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,Company, any of which could have a material adverse effect oncause our financial position or results of operations.business to suffer.
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. |
| | Borehole Enlargement (“BHE”) | | The process of opening up or enlarging the internal diameter of the wellbore. This is typically done with under-reamers, reamers, or hole openers. |
Bottomhole Assembly (“BHA”) Closed Loop Drilling Systems | | The lower portion of the drillstring including (if used): the bit, bit sub, mud motor, stabilizers, drillcollar, heavy-weight drillpipe, jarring devices, and crossovers for various thread forms. 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. Also used on the seafloor to tie wells and subsea equipment together. |
| | | 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.turns. 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 toor 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 establishedestablish 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 orfor 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. |
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 (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. |
| | | | 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. |
| | | Steerable Technologies | | Tools that allow for steering the BHA towards a target while rotating from surface. |
| | | 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.
ITEM 1B. | UNRESOLVED STAFF COMMENTS |
None.
ITEM 2. | PROPERTIESPROPERTIES |
The Company owned or leased approximately 835620 facilities worldwide as of December 31, 2015,2018, including the following principal manufacturing, service, distribution and administrative facilities: | | | | | Building | | | Property | | | | | Lease | | | | | | | | | | | | | | | Size | | | Size | | | Owned / | | Termination | Location | | Description | | Building Size (SqFt) | | | Property Size (Acres) | | | Owned | | Lease Termination Date | | Description | | (SqFt) | | | (Acres) | | | Leased | | Date | Rig Systems: | | | Houston, Texas | | Manufacturing Plant of Drilling Equipment | | | 511,964 | | | | 33 | | | | Leased | | | 4/30/2019 | | Houston, Texas | | West Little York Manufacturing Facility, Repairs, Service, Administrative & Sales Offices | | | 483,450 | | | | 34 | | | | Owned | | | | | Ulsan, South Korea | | Fabrication of Drilling Equipment | | | 380,068 | | | | 51 | | | | Owned | | | | | Orange, California | | Manufacturing & Office Facility | | | 351,418 | | | | 9 | | | | Owned | * | | 12/31/2020 | | Houston, Texas | | Manufacturing, Service, Warehouse & Administrative Offices (WGB) | | | 245,319 | | | | 14 | | | | Leased | | | 3/31/2018 | | | Rig Aftermarket: | | | Houston, Texas | | Bammel Facility, Repairs, Service, Parts, Administrative & Sales Offices | | | 377,750 | | | | 19 | | | | Leased | | | 6/30/2028 | | New Iberia, Louisiana | | Repair, Services and Spares facility | | | 189,000 | | | | 17 | | | | Leased | | | 10/1/2025 | | Aberdeen, Scotland | | Pressure Control Manufacturing, Administrative & Sales Offices | | | 188,200 | | | | 5 | | | | Leased | | | 8/31/2018 | | Singapore | | Manufacturing, Repairs, Service, Field Service/Training, Administrative & Sales Offices | | | 149,605 | | | | 3 | | | | Leased | | | 1/5/2024 | | Dubai, UAE | | Repair & Overhaul of Drilling Equipment, Warehouse & Sales Office | | | 31,633 | | | | 2 | | | | Owned | | | | | | Wellbore Technologies: | Wellbore Technologies: | Wellbore Technologies: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Navasota, Texas | | Manufacturing Facility & Administrative Offices | | | 562,112 | | | | 196 | | | | Owned | | | | | Manufacturing Facility & Administrative Offices | | 562,112 | | | 196 | | | Owned | | | Conroe, Texas | | Manufacturing Facility of Drill Bits and Downhole Tools, Administrative & Sales Offices | | | 341,800 | | | | 35 | | | | Owned | | | | | Manufacturing Facility of Drill Bits and | | 410,623 | | | 35 | | | Owned | | | | | | Downhole Tools, Administrative & Sales Offices | | | | | | | | | | | | | Houston, Texas | | Sheldon Road Inspection Facility | | | 319,365 | | | | 192 | | | | Owned | | | | | Sheldon Road Inspection Facility | | 319,365 | | | 192 | | | Owned | | | Veracruz, Mexico | | Manufacturing Facility of Tool Joints, Warehouse & Administrative Offices | | | 303,400 | | | | 42 | | | | Owned | | | | | Manufacturing Facility of Tool Joints, | | 303,400 | | | 42 | | | Owned | | | | | | Warehouse & Administrative Offices | | | | | | | | | | | | | Houston, Texas | | Holmes Rd Complex: Manufacturing, Warehouse, Coating Manufacturing Plant & Corporate Office | | | 300,000 | | | | 50 | | | | Owned | | | | | Holmes Rd Complex: Manufacturing, Warehouse, | | 300,000 | | | 50 | | | Owned | | | | | | Coating Manufacturing Plant & Corporate Office | | | | | | | | | | | | | Cedar Park, Texas | | Instrumentation Manufacturing Facility, Administrative & Sales Offices | | | 215,778 | | | | 40 | | | | Owned | | | | | Instrumentation Manufacturing Facility, Administrative & Sales Offices | | 215,778 | | | 34 | | | Owned | | | Dubai, UAE | | Manufacturing Facility of Downhole Tools, Distribution Warehouse | | | 180,000 | | | | 8 | | | | Leased | | | 1/29/2021 | | Manufacturing Facility of Downhole Tools, Distribution Warehouse | | 184,492 | | | 8 | | | Leased | | 1/29/2021 | Conroe, Texas | | Solids Control Manufacturing Facility, Warehouse, Administrative & Sales Offices, and Engineering Labs | | | 153,750 | | | | 35 | | | | Owned | | | | | Solids Control Manufacturing Facility, Warehouse, | | 153,750 | | | 42 | | | Owned | | | | | | Administrative & Sales Offices, and Engineering Labs | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Completion & Production Solutions: | Completion & Production Solutions: | Completion & Production Solutions: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Senai, Malaysia | | Manufacturing Facility of Fiber Glass Products | | | 595,965 | | | | 14 | | | | Owned | * | | | | Manufacturing Facility of Fiber Glass Products | | | 595,965 | | | | 14 | | | Owned* | | 10/31/2027 | Kalundborg, Denmark | | Flexibles Manufacturing, Warehouse, Shop & Administrative Offices | | | 485,067 | | | | 38 | | | | Owned | * | | | | Flexibles Manufacturing, Warehouse, Shop & Administrative Offices | | | 485,067 | | | | 38 | | | Owned | | | Superporto du Acu, Brazil | | Flexibles Manufacturing, Warehouse, Shop & Administrative Offices | | | 464,885 | | | | 30 | | | | Owned | * | | 10/20/2031 | | Flexibles Manufacturing, Warehouse, Shop & Administrative Offices | | 464,885 | | | 30 | | | Owned* | | 10/20/2031 | Manchester, England | | Manufacturing, Assembly & Testing of PC Pumps and Expendable Parts, Administrative & Sales Offices | | | 464,000 | | | | 28 | | | | Owned | | | | | Manufacturing, Assembly & Testing of PC Pumps and Expendable Parts, Administrative & Sales Offices | | | 464,000 | | | 28 | | | Owned | | | Houston, Texas | | | Manfufacturing of Wireline and Pressure Performance Equipment, Warehouse and Administrative Offices | | 383,750 | | | 26 | | | Leased | | 6/30/2041 | Fort Worth, Texas | | Coiled Tubing Manufacturing Facility, Warehouse, Administrative & Sales Offices | | | 233,173 | | | | 24 | | | | Owned | | | | | Coiled Tubing Manufacturing Facility, | | 342,999 | | | 24 | | | Owned | | | | | | Warehouse, Administrative & Sales Offices | | | | | | | | | | | | | Qingdau, Shandong, China | | | Manufacturing of fiber-reinforced tubular products | | 309,150 | | | 25 | | | Leased | | 10/26/2036 | Tulsa, Oklahoma | | Manufacturing Facility of Pumps, Warehouse and Administrative & Sales Offices | | | 222,625 | | | | 10 | | | | Owned | | | \ | | Manufacturing Facility of Pumps, Warehouse and Administrative & Sales Offices | | | 222,625 | | | | 10 | | | Owned | | | Kintore, Aberdeenshire, Scotland, UK | | | Manufacturing & Servicing of Elmar, ASEP and Anson Equipment | | | 210,000 | | | | 13 | | | Leased | | 9/3/2037 | Houston, Texas | | Manufacturing of fiber-reinforced tubular products & Administrative Offices | | | 146,668 | | | | 6 | | | | Leased | | | 8/31/2018 | | Manufacturing of fiber-reinforced tubular products & Administrative Offices | | | 130,873 | | | | 6 | | | Leased | | 4/30/2021 | | | | | | | | | | | | | | | | | Rig Technologies: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Houston, Texas | | | Bammel Facility, Repairs, Service, Aftermarket Parts, | | 602,110 | | | 33 | | | Leased | | 6/30/2028 | | | | Administrative & Sales Offices | | | | | | | | | | | | | Houston, Texas | | | Manufacturing Plant of Drilling Equipment | | 511,964 | | | 33 | | | Leased | | 4/30/2020 | Houston, Texas | | | West Little York Manufacturing Facility, | | | 483,450 | | | 34 | | | Owned | | | | | | Repairs, Service, Administrative & Sales Offices | | | | | | | | | | | | | Orange, California | | | Manufacturing & Office Facility | | 338,337 | | | 9 | | | Owned* | | 12/31/2020 | New Iberia, Louisiana | | | Repair, Services and Spares facility | | 189,000 | | | 17 | | | Leased | | 10/1/2025 | Singapore | | | Manufacturing, Repairs, Service, Field | | 133,659 | | | 4 | | | Leased | | 1/5/2024 | | | | Service/Training, Administrative & Sales Offices | | | | | | | | | | | | | Dubai, UAE | | | Repair & Overhaul of Drilling Equipment, | | 39,433 | | | 2 | | | Owned | | | | | | Warehouse & Sales Office | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Corporate: | Corporate: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Houston, Texas | | Corporate and Shared Administrative Offices | | | 337,019 | | | | 14 | | | | Leased | | | 5/31/2037 | | Corporate and Shared Administrative Offices | | 337,019 | | | 14 | | | Leased | | 5/31/2037 | Houston, Texas | | | Corporate and Shared Administrative Offices | | 441,029 | | | 3 | | | Leased | | 1/31/2041 |
* | Building owned but land leased. |
We own or lease approximately 300342 repair and manufacturing facilities that refurbish and manufacture new equipment and parts, 400114 service centers that provide inspection and equipment rental and 135164 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.11 – Commitments and Contingencies (Part IV, Item 15 of this Form 10-K) for further discussion.
| | 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 |
PART II ITEM 5.MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER ATTERS 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. | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 2015 | | | 2014 | | | | First Quarter | | | Second Quarter | | | Third Quarter | | | Fourth Quarter | | | First Quarter | | | Second Quarter | | | Third Quarter | | | Fourth Quarter | | Common stock sale price: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | High | | $ | 66.02 | | | $ | 56.00 | | | $ | 46.95 | | | $ | 40.80 | | | $ | 79.81 | | | $ | 83.47 | | | $ | 86.43 | | | $ | 74.54 | | Low | | $ | 47.46 | | | $ | 47.90 | | | $ | 36.72 | | | $ | 33.27 | | | $ | 73.03 | | | $ | 74.19 | | | $ | 76.10 | | | $ | 61.55 | | Cash dividends per share | | $ | 0.46 | | | $ | 0.46 | | | $ | 0.46 | | | $ | 0.46 | | | $ | 0.26 | | | $ | 0.46 | | | $ | 0.46 | | | $ | 0.46 | |
As of February 12, 2016,8, 2019, there were 3,1223,218 holders of record of our common stock. Many stockholders choose to own shares through brokerage accounts and other intermediaries rather than as holders of record (excluding individual participants in securities positions listing) so the actual number of stockholders is unknown but significantly higher. Cash dividends aggregated $710declared were $0.05 per quarter, aggregating $76 million and $703 million for each of the years ended December 31, 20152018 and 2014, respectively.2017. 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
During the third quarter of 2015 the Company completed its $3 billion share repurchase program. As shares were repurchased, they were constructively retired and returned to an unissued state. During the years ended December 31, 2015 and 2014, the Company repurchased 44.0 million and 11.6 million shares, respectively, under the program for an average price of $50.53 and $66.97 per share, respectively, for an aggregate amount of $2,221 million and $799 million, respectively.
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, 20102013 in National Oilwell Varco, Inc., the S&P Oil & Gas Equipment Select Index, 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. ![](https://files.docoh.com/10-K/0001564590-19-002967/g5cs3lcnncbw000001.jpg)
![](https://files.docoh.com/10-K/0001193125-16-469696/g118658g55h56.jpg)
ILLEGIBLE
| | 12/13 | | | 12/14 | | | 12/15 | | | 12/16 | | | 12/17 | | | 12/18 | | National Oilwell Varco, Inc. | | | 100.00 | | | | 93.44 | | | | 49.83 | | | | 56.76 | | | | 54.93 | | | | 39.40 | | S&P 500 | | | 100.00 | | | | 113.69 | | | | 115.26 | | | | 129.05 | | | | 157.22 | | | | 150.33 | | S&P Oil & Gas Equipment & Services | | | 100.00 | | | | 92.20 | | | | 74.91 | | | | 98.83 | | | | 84.32 | | | | 49.36 | | S&P Oil & Gas Equipment Select | | | 100.00 | | | | 65.43 | | | | 41.45 | | | | 53.34 | | | | 41.70 | | | | 22.09 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | 12/10 | | | 12/11 | | | 12/12 | | | 12/13 | | | 12/14 | | | 12/15 | | National Oilwell Varco, Inc. | | | 100.00 | | | | 101.74 | | | | 102.96 | | | | 121.26 | | | | 113.31 | | | | 60.42 | | S&P 500 | | | 100.00 | | | | 102.11 | | | | 118.45 | | | | 156.82 | | | | 178.29 | | | | 180.75 | | S&P Oil & Gas Equipment & Services | | | 100.00 | | | | 88.32 | | | | 88.32 | | | | 115.39 | | | | 106.39 | | | | 86.44 | |
This information shall not be deemed to be “soliciting material”‘‘soliciting material’’ or to be “filed”‘‘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). In 2018, NOV determined that it should add the Oil & Gas Equipment and Services Select Index to benchmark its performance as it is comprised of approximately 40 companies, giving a more representative view of the industry. Whereas, the Oil & Gas and Equipment Services Index consists of a limited number of companies and is heavily weighted by one or two members.
ITEM 6. SELECTED FINANCIAL DATA | | Years Ended December 31, | | | | 2018 | | | 2017 | | | 2016 | | | 2015 | | | 2014 | | | | (in millions, except per share data) | | Operating Data: | | | | | | | | | | | | | | | | | | | | | Revenue | | $ | 8,453 | | | $ | 7,304 | | | $ | 7,251 | | | $ | 14,757 | | | $ | 21,440 | | Operating profit (loss) | | $ | 211 | | | $ | (277 | ) | | $ | (2,411 | ) | | $ | (390 | ) | | $ | 3,613 | | Income (loss) before income taxes | | $ | 41 | | | $ | (392 | ) | | $ | (2,623 | ) | | $ | (589 | ) | | $ | 3,494 | | Income (loss) from continuing operations | | $ | (22 | ) | | $ | (236 | ) | | $ | (2,416 | ) | | $ | (767 | ) | | $ | 2,455 | | Income from discontinued operations | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | 52 | | Net income (loss) attributable to Company | | $ | (31 | ) | | $ | (237 | ) | | $ | (2,412 | ) | | $ | (769 | ) | | $ | 2,502 | | Per share data: | | | | | | | | | | | | | | | | | | | | | Basic: | | | | | | | | | | | | | | | | | | | | | Income (loss) from continuing operations | | $ | (0.08 | ) | | $ | (0.63 | ) | | $ | (6.41 | ) | | $ | (1.99 | ) | | $ | 5.73 | | Income from discontinued operations | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | 0.12 | | Net income (loss) attributable to Company | | $ | (0.08 | ) | | $ | (0.63 | ) | | $ | (6.41 | ) | | $ | (1.99 | ) | | $ | 5.85 | | Diluted: | | | | | | | | | | | | | | | | | | | | | Income (loss) from continuing operations | | $ | (0.08 | ) | | $ | (0.63 | ) | | $ | (6.41 | ) | | $ | (1.99 | ) | | $ | 5.70 | | Income from discontinued operations | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | 0.12 | | Net income (loss) attributable to Company | | $ | (0.08 | ) | | $ | (0.63 | ) | | $ | (6.41 | ) | | $ | (1.99 | ) | | $ | 5.82 | | Cash dividends per share | | $ | 0.20 | | | $ | 0.20 | | | $ | 0.61 | | | $ | 1.84 | | | $ | 1.64 | | Other Data: | | | | | | | | | | | | | | | | | | | | | Depreciation and amortization | | $ | 690 | | | $ | 698 | | | $ | 703 | | | $ | 747 | | | $ | 778 | | Capital expenditures | | $ | 244 | | | $ | 192 | | | $ | 284 | | | $ | 453 | | | $ | 699 | | Balance Sheet Data: | | | | | | | | | | | | | | | | | | | | | Working capital | | $ | 4,938 | | | $ | 4,863 | | | $ | 4,829 | | | $ | 7,552 | | | $ | 8,788 | | Total assets | | $ | 19,796 | | | $ | 20,206 | | | $ | 21,140 | | | $ | 26,725 | | | $ | 33,562 | | Long-term debt, less current maturities | | $ | 2,704 | | | $ | 2,706 | | | $ | 2,708 | | | $ | 3,928 | | | $ | 3,014 | | Total Company stockholders' equity | | $ | 13,819 | | | $ | 14,094 | | | $ | 13,940 | | | $ | 16,383 | | | $ | 20,692 | |
ITEM 6. | SELECTED FINANCIAL DATA |
| | | | | | | | | | | | | | | | | | | | | | | Years Ended December 31, | | | | 2015 | | | 2014 | | | 2013 (1) | | | 2012 (2) | | | 2011 | | | | (in millions, except per share data) | | Operating Data: | | | | | | | | | | | | | | | | | | | | | Revenue | | $ | 14,757 | | | $ | 21,440 | | | $ | 19,221 | | | $ | 17,194 | | | $ | 13,475 | | Operating profit (loss) | | $ | (390 | ) | | $ | 3,613 | | | $ | 3,199 | | | $ | 3,389 | | | $ | 2,809 | | Income (loss) from continuing operations before income taxes | | $ | (589 | ) | | $ | 3,494 | | | $ | 3,124 | | | $ | 3,340 | | | $ | 2,794 | | Income (loss) from continuing operations | | $ | (767 | ) | | $ | 2,455 | | | $ | 2,181 | | | $ | 2,375 | | | $ | 1,900 | | Income from discontinued operations | | $ | — | | | $ | 52 | | | $ | 147 | | | $ | 108 | | | $ | 85 | | Net income (loss) attributable to Company | | $ | (769 | ) | | $ | 2,502 | | | $ | 2,327 | | | $ | 2,491 | | | $ | 1,994 | | | | | | | | Per share data: | | | | | | | | | | | | | | | | | | | | | Basic: | | | | | | | | | | | | | | | | | | | | | Income (loss) from continuing operations | | $ | (1.99 | ) | | $ | 5.73 | | | $ | 5.11 | | | $ | 5.61 | | | $ | 4.52 | | | | | | | | | | | | | | | | | | | | | | | Income from discontinued operations | | $ | — | | | $ | 0.12 | | | $ | 0.35 | | | $ | 0.25 | | | $ | 0.21 | | | | | | | | | | | | | | | | | | | | | | | Net income (loss) attributable to Company | | $ | (1.99 | ) | | $ | 5.85 | | | $ | 5.46 | | | $ | 5.86 | | | $ | 4.73 | | | | | | | | | | | | | | | | | | | | | | | Diluted: | | | | | | | | | | | | | | | | | | | | | Income (loss) from continuing operations | | $ | (1.99 | ) | | $ | 5.70 | | | $ | 5.09 | | | $ | 5.58 | | | $ | 4.50 | | | | | | | | | | | | | | | | | | | | | | | Income from discontinued operations | | $ | — | | | $ | 0.12 | | | $ | 0.35 | | | $ | 0.25 | | | $ | 0.20 | | | | | | | | | | | | | | | | | | | | | | | Net income (loss) attributable to Company | | $ | (1.99 | ) | | $ | 5.82 | | | $ | 5.44 | | | $ | 5.83 | | | $ | 4.70 | | | | | | | | | | | | | | | | | | | | | | | Cash dividends per share | | $ | 1.84 | | | $ | 1.64 | | | $ | 0.91 | | | $ | 0.49 | | | $ | 0.45 | | | | | | | | | | | | | | | | | | | | | | | Other Data: | | | | | | | | | | | | | | | | | | | | | Depreciation and amortization | | $ | 747 | | | $ | 778 | | | $ | 738 | | | $ | 616 | | | $ | 549 | | Capital expenditures | | $ | 453 | | | $ | 699 | | | $ | 614 | | | $ | 569 | | | $ | 479 | | | | | | | | Balance Sheet Data: | | | | | | | | | | | | | | | | | | | | | Working capital | | $ | 7,552 | | | $ | 8,788 | | | $ | 9,745 | | | $ | 10,029 | | | $ | 6,694 | | Total assets | | $ | 26,725 | | | $ | 33,562 | | | $ | 34,812 | | | $ | 31,484 | | | $ | 25,515 | | Long-term debt, less current maturities | | $ | 3,928 | | | $ | 3,014 | | | $ | 3,149 | | | $ | 3,148 | | | $ | 159 | | Total Company stockholders’ equity | | $ | 16,383 | | | $ | 20,692 | | | $ | 22,230 | | | $ | 20,239 | | | $ | 17,619 | |
(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 worldwideindependent provider of highly engineered drillingequipment and well-servicing equipment, products and servicestechnology to the exploration and production segments of theupstream oil and gas industry. With operations in approximately 835620 locations across six continents, we design, manufactureNOV designs, manufactures and serviceservices a comprehensive line of drilling and well servicing equipment; sellsells and rentrents drilling motors, specialized downhole tools, and rig instrumentation; performperforms inspection and internal coating of oilfield tubular products; provideprovides drill cuttings separation, management and disposal systems and services; and provideprovides expendables and spare parts used in conjunction with ourthe Company’s large installed base of equipment. WeNOV also manufacturemanufactures coiled tubing and high pressurehigh-pressure fiberglass and composite tubing, and sellsells and rentrents advanced in-line inspection equipment to makers of oil country tubular goods. We haveThe Company has a long tradition of pioneering innovations which improve the cost-effectiveness, efficiency, safety, and environmental impact of oil and gas operations. OurNOV’s revenue 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 ourThe Company conducts its operations through fourthree business segments: Rig Systems, Rig Aftermarket, Wellbore Technologies, and Completion & Production Solutions.Solutions and Rig Technologies. 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 effortCertain reclassifications have been made to the prior year financial statements in order for them to conform with the 2018 presentation. The Company discloses Adjusted EBITDA (defined as Operating Profit excluding Depreciation, Amortization and Other Items) in its periodic earnings press releases and other public disclosures to provide investors with additional information regarding ourabout the 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.ongoing operations. 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 OurNOV’s 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:
| | | 2015* | | | 2014* | | | 2013* | | | % 2015 v 2014 | | | % 2015 v 2013 | | | | | | | | | | | | | | | % increase (decrease) | | | | | | | | | | | | | | | | | | 2018 v | | | 2018 v | | | | | | 2018* | | | 2017* | | | 2016* | | | 2017 | | | 2016 | | Active Drilling Rigs: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | U.S. | | | 977 | | | | 1,862 | | | | 1,761 | | | | (47.5 | %) | | (44.5 | %) | | | 1,031 | | | | 875 | | | | 510 | | | | 17.8 | % | | | 102.2 | % | Canada | | | 194 | | | | 380 | | | | 354 | | | | (48.9 | %) | | (45.2 | %) | | 191 | | | 207 | | | 128 | | | | (7.7 | %) | | | 49.2 | % | International | | | 1,167 | | | | 1,337 | | | | 1,296 | | | | (12.7 | %) | | (10.0 | %) | | | 988 | | | | 947 | | | | 956 | | | | 4.3 | % | | | 3.3 | % | | | | | | | | | | | | | | | | | | Worldwide | | | 2,338 | | | | 3,579 | | | | 3,411 | | | | (34.7 | %) | | (31.5 | %) | | | 2,210 | | | | 2,029 | | | | 1,594 | | | | 8.9 | % | | | 38.6 | % | | West Texas Intermediate Crude Prices (per barrel) | | $ | 48.71 | | | $ | 93.26 | | | $ | 97.91 | | | | (47.8 | %) | | (50.3 | %) | | $ | 64.94 | | | $ | 50.88 | | | $ | 43.15 | | | | 27.6 | % | | | 50.5 | % | | Natural Gas Prices ($/mmbtu) | | $ | 2.61 | | | $ | 4.38 | | | $ | 3.72 | | | | (40.4 | %) | | (29.8 | %) | | $ | 3.13 | | | $ | 2.96 | | | $ | 2.49 | | | | 5.7 | % | | | 25.7 | % |
* | 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, 20152018 on a quarterly basis: ![](https://files.docoh.com/10-K/0001564590-19-002967/g5cs3lcnncbw000002.jpg)
![](https://files.docoh.com/10-K/0001193125-16-469696/g118658g55d59.jpg)
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 $48.71$64.94 in 2015, a decrease2018, an increase of 48%28% over the average price for 20142017 of $93.26$50.88 per barrel. The average natural gas price in 2018 was $2.61$3.13 per mmbtu, a decreasean increase of 40%six percent compared to the 20142017 average of $4.38$2.96 per mmbtu. Average rig activity worldwide decreased 35%increased nine percent for the full year in 20152018 compared to 2014.2017. The average crude oil price for the fourth quarter of 20152018 was $41.95$59.08 per barrel, and natural gas was $2.11$3.77 per mmbtu. At February 12, 2016,8, 2019, there were 7631,289 rigs actively drilling in North America, compared to 781the fourth quarter average of 1,249 rigs, an increase of three percent. The price for West Texas Intermediate Crude Oil was $52.72 per barrel at December 31, 2015;February 8, 2019, a decrease of 2%11% from year end 2015 levels.the fourth quarter of 2018 average. The price of oil decreased to $29.76 per barrel andfor natural gas decreased to $1.99was $2.58 per mmbtu at February 12, 2016, representing8, 2019, a 22% decrease in oil prices and a 17% decrease in gas pricesof 32% from the endfourth quarter of 2015.2018 average.
EXECUTIVE SUMMARY National Oilwell Varco, Inc. generated revenue of $14.8$8.45 billion in 2015, a decrease2018, an increase of 31%16% from the prior year due to decliningas improving oil and gas prices resultingresulted in reducedincreased drilling activity and demand for certain oilfield equipment and services. Average 20152018 worldwide rig count (as measured by Baker Hughes) decreased 35%increased nine percent in comparison to 2014.2017. The broad-based declineincrease in activity led to increased revenues across all four of the Company’s reporting segments to post lower year-over-year revenues in comparison to 2014.segments. For the year ended December 201531, 2018, the Company reported an operating lossprofit of $390$211 million compared to an operating profitloss of $3.6 billion$277 million in 20142017, and a net loss from continuing operationsattributable to the Company of $769$31 million, or $1.99$0.08 per share compared to a net incomeloss of $2.5 billion$237 million or $5.70$0.63 per fully diluted share during 2014. Operating profit excluding other items (as defined in the “Non-GAAP Financial Measures and Reconciliations” in Results of Operations) was $1,634 million in 2015 and earnings per share excluding other items was $2.80 in 2015, a 54% decrease from $6.07 per diluted share in 2014.2017. For the fourth quarter ended December 31, 2015,2018, revenue was $2.7$2.40 billion, a $584$244 million or 18% decrease11% increase compared to the third quarter of 2015.2018. The Company reported a net lossincome of $1,523$12 million, from continuing operations, or $4.06$0.03 per fully diluted share, a decreasean increase of $1,678$11 million, or $4.47$0.03 per fully diluted share.share, from the third quarter of 2018. Compared to the fourth quarter of 2014,2017, revenue decreased $2,987increased $429 million or 52%22%, and net income from continuing operations decreased $2,118increased $26 million. During the fourth quarter of 2015,2018, third quarter of 2015,2018, and fourth quarter of 2014,2017, pre-tax other items (severance, facility closures, asset impairments, write-downs, and other) were $1,773$21 million, $112 millionnil, and $105$133 million, respectively. Excluding the other items from all periods, fourth quarter 2015 earnings were $0.23 per fully diluted share,2018 Adjusted EBITDA was $279 million, compared to $0.61 per fully diluted share$245 million in the third quarter of 20152018 and $1.69 per fully diluted share$197 million in the fourth quarter of 2014.2017. Operating profit excluding other items was $141Segment Performance
Wellbore Technologies Wellbore Technologies generated revenues of $884 million or 5.2% of sales in the fourth quarter of 2015, compared to $346 million or 10.5%2018, an increase of sales infour percent from the third quarter of 2015,2018 and $1,018an increase of 24 percent from the fourth quarter of 2017. The segment’s revenue growth continued to outpace domestic and global drilling activity levels, with sales increasing 4.5 percent in the U.S. and 2.1 percent in international markets. The segment’s WellSite Services and Grant Prideco business units each posted double-digit percent sequential revenue increases supported by bookings of solids control equipment and drill pipe, which improved throughout the first three quarters of 2018. Operating profit was $41 million, or 17.8%4.6 percent of salessales. Adjusted EBITDA increased 15 percent sequentially and 45 percent from the prior year to $155 million, or 17.5 percent of sales. An improved mix of business and higher volumes resulted in 54 percent sequential Adjusted EBITDA incrementals (the change in Adjusted EBITDA divided by the change in revenue). Completion & Production Solutions Completion & Production Solutions generated revenues of $788 million in the fourth quarter of 2014.2018, an increase of seven percent from the third quarter of 2018 and an increase of 14 percent from the fourth quarter of 2017. The sequential increase in revenue was the result of improved progress and deliveries on projects and continued growth in demand for coiled tubing and wireline equipment. Operating profit was $64 million, or 8.1 percent of sales. Adjusted EBITDA increased 13 percent sequentially and 51 percent from the prior year to $112 million, or 14.2 percent of sales. Anticipated resin supply shortages in the Company’s Fiber Glass Systems business unit and holiday slowdowns impacted manufacturing plant absorption, limiting sequential Adjusted EBITDA incrementals to 25 percent. New orders booked during the quarter were $470 million, representing a book-to-bill of 103 percent when compared to the $456 million of orders shipped from backlog. Backlog for capital equipment orders for Completion & Production Solutions at December 31, 2018 was $894 million. Rig Technologies Rig Technologies generated revenues of $804 million in the fourth quarter of 2018, an increase of 26 percent from the third quarter of 2018 and an increase of 31 percent from the fourth quarter of 2017. Better progress on projects, delivery of two land rigs, and improved aftermarket sales resulted in the sequential revenue increase. Operating profit was $75 million, or 9.3 percent of sales. Adjusted EBITDA increased 31 percent sequentially and 46 percent from the prior year to $102 million, or 12.7 percent of sales. Adjusted EBITDA leverage was limited to 14 percent due to a change in product mix. New orders booked during the quarter totaled $119 million, representing a book-to-bill of 30 percent when compared to the $403 million of orders shipped from backlog. At December 31, 2018, backlog for capital equipment orders for Rig Technologies was $3.1 billion.
Oil & Gas Equipment and Services Market and Outlook Over the past decade, technologicalTechnological advancements in the oilfield equipment and service spaceservices unlocked production from previously uneconomic formations that were previously deemed uneconomic, especially in North America. According to the Rystad Energy DCube, from 2004 to 2014 global oil and liquids supply increased by 9.9 million barrels per day, 5.8 million barrels per day from U.S. unconventional resources, 1.7 million barrels per day from deep-water (defined as water depths greater than 400 feet) resources and 2.4 million barrels per day from other sources. The advances in technologywhich, combined with relatively high commodity demand and prices, caused by growing demand enabled and sustained an increase in global drilling activity.activity that dramatically grew oil supplies from 2004 to 2014. In recent years, global supply started to catch up to demand, and in the lattersecond half of 2014 demand growth in areas such as Asia, Europe and the U.S. weakened while drilling activity remained strong and production continued to grow. As a result, the first signsinventories of an oversupply-related imbalance appearedcrude and prices began to decline. Unlike previous cycles, when the Organization of the Petroleum Exporting Countries (OPEC) curtailed production levels to defend pricing, certain members of OPECrefined products increased, production in an effort to increase market share and financially stress higher cost producers, most notably those operating in the North American shale market. As a result, the price of oil declined significantly during early 2015, the beginning of a generational market downturn.
The Company aggressively sized its operations to the market and reduced operating expenses, while continuing to invest in developing and acquiring new products, technologies and operations that advanced longer term strategic goals. The Company successfully pivoted towards the industry’s increased focus on onshore unconventional developments, while strategically maintaining a leading position in offshore equipment. The market downturn stabilized during the second half of 2016. Through 2017 and into the first nine months of 2018, drilling activity increased for North America land, stabilized in international land markets, and remained depressed throughout the year, and underwent another major reduction toward the end of 2015. In early 2016, the market witnessed oil trading in the high $20 per barrel range, a price range not seen since 2003. In response to rapidly deteriorating market conditions, operators adjusted accordingly by acutely reducing both operating and capital expenditures. Orders for our equipment and services slowed and rig counts declined rapidly. For the fourth quarter of 2015, the average number of active rigs drilling worldwide decreased 44% year-over-year, with a 60% decline in the North American market alone.
Segment Performance
Rig Systems
The Company’s Rig Systems segment generated $7.0 billion in revenue and $1.2 billion in operating profit, or 17.3% of revenue, during 2015. Compared to the prior year, revenue decreased 29% and operating profit dollars decreased 40%. For the fourth quarter of 2015, the segment generated $1.0 billion in revenue and $113 million in operating profit, or 11.1% of revenue. Compared to the prior quarter, revenue decreased $481 million or 32%,
and operating profit decreased $140 million or 55%. Compared to the fourth quarter of 2014, segment revenue decreased $1,546 million or 60%, and operating profit decreased $398 million or 78%. Fourth quarter 2015 revenue out of backlog for the Rig Systems segment decreased 35% sequentially and 63% year-over-year on fewer shipments of land rigs and postponed delivery dates of some offshore projects.offshore. During the fourth quarter of 2015, the segment received $89 million in new orders, primarily composed2018 oil prices declined sharply due to heavier than expected US shale production combined with market concerns about global growth, geopolitics (including trade wars) and interest rates. The average price of discreet capital equipment components including top drives, blowout preventers and offshore cranes. Year-end backlogWest Texas Intermediate Cushing Crude for the segment was $6.1 billion a 24% decline sequentially and a 52% decrease year-over-year.
Rig Aftermarket
The Company’s Rig Aftermarket segment generated $2.5 billion in revenue and $605 million in operating profit, or 24.1% of revenue, during 2015. Compared to the prior year, revenue decreased 22% and operating profit dollars decreased 31% year-over-year. For the fourth quarter of 2015,2018 was $59.08 a barrel, but ended the segment generated $569 millionyear at $45.15.
Despite a surge in revenue and $126 millionDecember equipment deliveries that resulted in operating profit, or 22.1% of revenue. Compared to the priorNOV’s strong fourth quarter revenue, decreased $1 million,many customers have indicated a reduced spending outlook into the beginning of 2019. NOV’s customer base has become much faster at reacting to market swings, and operating profit decreased $19 million or 13%. Compared towe believe the fourth quarter of 2014, segment revenue decreased $281 million or 33%, and operating profit decreased $119 million or 49%. Revenue decreased year-over-year as drilling contractors reduced spending and depleted existing spares inventories rather than purchase new, and deferred repair and maintenance work on their rig fleets when possible. Wellbore Technologies
The Company’s Wellbore Technologies segment generated $3.7 billion in revenue and $1,613 million in operating loss, or a negative 43.4% of revenue, for the full year 2015. Compareddip will lead to the prior year, revenue decreased $2,004 million and operating profit decreased $2,550 million. For the fourthlower first quarter of 2015, the segment generated $757 million in revenue and $1,723 million in operating loss, or a negative 227.6% of revenue. Compared to the prior quarter, revenue decreased $77 million or 9%, and operating profit decreased $1,716 million. Compared to the fourth quarter of 2014, revenue decreased $772 million, and operating profit decreased $1,895 million. Revenue decreased in correlation with lower levels of worldwide drilling activity, which required and consumed less of the segment’s services and product offerings. Year-over-year operating margins declined on lower volumes, a market decline that outpaced cost reduction efforts and a $1,634 million impairment charge related to goodwill and a certain indefinite-lived trade name.
Completion & Production Solutions
The Company’s Completion & Production Solutions segment generated $3.4 billion in revenue and $161 million in operating profit, or 4.8% of revenue, for the full year 2015. Compared to the prior year, revenue decreased 28% and operating profit decreased $529 million. Year-over-year revenue decreases were attributable to reduced demand and customers delaying receipt of finished orders for onshore completion and production equipment in response to commodity price declines. For the fourth quarter of 2015, the segment generated $746 million in revenue and $1 million in operating profit, or 0.1% of revenue. Compared to the prior quarter, revenue decreased $52 million or 7%, and operating profit decreased $2 million. Sequentially, revenue and operating profit decreased on lower activity levels and pricing pressures. Compared to the fourth quarter of 2014, revenue decreased $579 million and operating profit decreased $213 million as lower levels of worldwide drilling activity resulted in reduced sales across most product lines.
Outlook
The persistent supply and demand imbalance has led to low commodity prices and significantly reduced activity by exploration and production companies. The reduced activity has created an oversupply of service capacity and capital equipment resulting in increasingly challenging prospects for many of our customers in the form of reduced volumes and pricing pressures. Consequently, we are cautious in our outlook for 2016, and anticipate that our customers will minimize capital expenditures until they see the early signs of a recovery in commodity
prices and overall activity levels. We also expect them to minimize parts purchases and postpone maintenance using existing stocks of spares and cannibalizing idle equipment whenever possible.
In the current environment, contractors are hesitant to invest in older equipment which can be far less productive and competitive. As a result, we anticipate that the industry will retire a significant portion of the current base of capital equipment during this cyclical downturn, which could result in newbuild orders when commodity prices recover and activity increases. However, a meaningful increase in drilling activity is not expected in early 2016 as commodity prices remain at decade lows. As a result, our near-term outlook remains cautious and visibility beyond the early part of 2016 remains limited as the duration of the current market downturn is uncertain.
We expect the slope and timing of revenue decline, stabilization and recovery will be differentrevenues across our four business segments. Likewise, oursegments, particularly in North America.
NOV’s global customer base includes national oil companies, international oil companies, independent oil and gas companies, onshore and offshore drilling contractors and service companies and others whose strategies and reactions to low or volatile commodity prices vary. OurThe timing and slope of revenue impacts from market changes will be different across its geographic regions and three operating segments. NOV’s Wellbore Technologies segment and certain elements of its Completion & Production Solutions segment is expected to see an increase in activity when decisions are made to complete and produce the inventory of already drilled wells. Our Wellbore Technologies and Rig AftermarketTechnologies segments are expectedrealize a faster response to see stronger recovery aschanges in drilling activity, while its more capital equipment-oriented businesses tend to respond to increased drilling activity more slowly. The Company anticipates that land drilling customers will reduce spending through the first part of new wells increases, while orders for newbuild rigs2019, then continue investing in our Rig Systems segment may come laterNOV’s equipment and services to enhance their competitiveness. North American pressure pumping customers will proceed cautiously in the cycle. Throughout 2016 we will continue to focus on what we can control, in the formface of sizing our operations with anticipated levels of activity while continuing to advance our longer term strategic goals. The Company has a history of implementing cost-controls measures and downsizing in response to depressed market conditions and has a track record of executing strategic acquisitions and developing new products and technologies.lower well stimulation day rates. The Company remains optimistic regarding longer-term market fundamentals as existing oil and gas fields continue to deplete and numerous major projects to replenish supply arehave been deferred or canceled while global demand continues to grow. After a lower first quarter, there may be stronger activity in the second half of 2019, particularly if global growth, supply and demand balance, and geopolitical concerns ease.NOV expects unconventional resources will continue to gain a greater share of global production, and the Company will continue to enhance its unconventional resource focused products and technologies, including advanced, automated drilling rigs; premium drillpipe and directional drilling technologies; hydraulic fracture stimulation equipment; and multistage completion tools. NOV expects big data and predictive analytics to improve uptime and operating efficiency, and the Company remains at the forefront of applying this promising technology to oilfield drilling and completion equipment. The Company has used the recent downturn to vigorously advance these strategic initiatives and is encouraged by its progress.
Results of Operations Years Ended December 31, 2015 and December 31, 2014
The following table summarizes the Company’s revenue and operating profit (loss) by operating segment in 2015 and 2014 (in millions): | | | Years Ended December 31, | | Variance | | | Years Ended December 31, | | | % Change | | | | 2015 | | 2014 | | $ | | | % | | | 2018 | | | 2017 | | | 2016 | | | 2018 vs. 2017 | | | 2017 vs. 2016 | | Revenue: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Rig Systems | | $ | 6,964 | | | $ | 9,848 | | | $ | (2,884 | ) | | | (29.3 | %) | | Rig Aftermarket | | | 2,515 | | | 3,222 | | | (707 | ) | | | (21.9 | %) | | Wellbore Technologies | | | 3,718 | | | 5,722 | | | (2,004 | ) | | | (35.0 | %) | | $ | 3,235 | | | $ | 2,577 | | | $ | 2,199 | | | | 25.5 | % | | | 17.2 | % | Completion & Production Solutions | | | 3,365 | | | 4,645 | | | (1,280 | ) | | | (27.6 | %) | | | 2,931 | | | | 2,672 | | | | 2,241 | | | | 9.7 | % | | | 19.2 | % | Rig Technologies | | | | 2,575 | | | | 2,252 | | | | 3,110 | | | | 14.3 | % | | | (27.6 | %) | Eliminations | | | (1,805 | ) | | (1,997 | ) | | 192 | | | | (9.6 | %) | | | (288 | ) | | | (197 | ) | | | (299 | ) | | | 46.2 | % | | | (34.1 | %) | | | | | | | | | | | | | | | Total Revenue | | $ | 14,757 | | | $ | 21,440 | | | $ | (6,683 | ) | | | (31.2 | %) | | $ | 8,453 | | | $ | 7,304 | | | $ | 7,251 | | | | 15.7 | % | | | 0.7 | % | | | | | | | | | | | | | | | Operating Profit (Loss): | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Rig Systems | | $ | 1,206 | | | $ | 1,996 | | | $ | (790 | ) | | | (39.6 | %) | | Rig Aftermarket | | | 605 | | | 882 | | | (277 | ) | | | (31.4 | %) | | Wellbore Technologies | | | (1,613 | ) | | 937 | | | (2,550 | ) | | | (272.1 | %) | | $ | 131 | | | $ | (102 | ) | | $ | (770 | ) | | | (228.4 | %) | | | (86.8 | %) | Completion & Production Solutions | | | 161 | | | 690 | | | (529 | ) | | | (76.7 | %) | | | 166 | | | | 98 | | | | (266 | ) | | | 69.4 | % | | | (136.8 | %) | Eliminations and other | | | (749 | ) | | (892 | ) | | 143 | | | | (16.0 | %) | | | | | | | | | | | | | | | | Rig Technologies | | | | 213 | | | | (14 | ) | | | (1,033 | ) | | | (1621.4 | %) | | | (98.6 | %) | Eliminations and corporate costs | | | | (299 | ) | | | (259 | ) | | | (342 | ) | | | 15.4 | % | | | (24.3 | %) | Total Operating Profit (Loss) | | $ | (390 | ) | | $ | 3,613 | | | $ | (4,003 | ) | | | (110.8 | %) | | $ | 211 | | | $ | (277 | ) | | $ | (2,411 | ) | | | (176.2 | %) | | | (88.5 | %) | | | | | | | | | | | | | | | Operating Profit (Loss)%: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Rig Systems | | | 17.3 | % | | 20.3 | % | | | | | | Rig Aftermarket | | | 24.1 | % | | 27.4 | % | | | | | | Wellbore Technologies | | | (43.4 | %) | | 16.4 | % | | | | | | | 4.0 | % | | | (4.0 | %) | | | (35.0 | %) | | | | | | | | | Completion & Production Solutions | | | 4.8 | % | | 14.9 | % | | | | | | | 5.7 | % | | | 3.7 | % | | | (11.9 | %) | | | | | | | | | Total Operating Profit (Loss)% | | | (2.6 | %) | | 16.9 | % | | | | | | Rig Technologies | | | | 8.3 | % | | | (0.6 | %) | | | (33.2 | %) | | | | | | | | | Total Operating Profit (Loss) % | | | | 2.5 | % | | | (3.8 | %) | | | (33.3 | %) | | | | | | | | |
Rig Systems
Years Ended December 31, 2018 and December 31, 2017 Wellbore Technologies Revenue from Rig SystemsWellbore Technologies for the year ended December 31, 20152018 was $6,964$3,235 million, a decreasean increase of $2,884$658 million (29.3%(25.5%) compared to the year ended December 31, 2014.2017. The decreaseincrease was due to lower land rig shipmentsan increase in global drilling activity and delayed delivery dates ofincreased market share in certain offshore projects.product lines. Operating profit from Rig SystemsWellbore Technologies was $1,206$131 million for the year ended December 31, 2015, a decrease2018, an increase of $790$233 million (39.6%) compared to 2014.the year ended December 31, 2017. Operating profit percentage decreasedfor 2018 was 4.0% compared to 17.3%, from 20.3%operating loss percentage 4.0% in 2014. Operating profit percentage decreased primarily due to lower volumes. Despite the strong fall off in revenue, strategic cost management efforts significantly reduced the decline in operating profit percentage.2017. Included in operating profit are certain restructuring and other items related to costs associated with a Voluntary Early Retirement Plan established byfacility closures and inventory recoveries. Other items included in operating profit (loss) for Wellbore Technologies were $21 million for the Company duringyear ended December 31, 2018 and $28 million for the first quarteryear ended December 31, 2017. Completion & Production Solutions Revenue from Completion & Production Solutions for the year ended December 31, 2018 was $2,931 million, an increase of 2015$259 million (9.7%) compared to the year ended December 31, 2017. The increase was due to improved progress and costs relateddeliveries on projects and continued growth in demand for coiled tubing and wireline equipment and conductor pipe. Operating profit from Completion & Production Solutions was $166 million for the year ended December 31, 2018 compared to severance and facility closures. Restructuring and$98 million for 2017, an increase of $68 million (69.4%). Operating profit percentage increased to 5.7% from 3.7% in 2017. There were no other items included in operating profit for Rig Systems were $105Completion & Production Solutions for the year ended December 31, 2018 compared to $33 million for the year ended December 31, 20152017. The Completion & Productions 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 completion and nilproduction
components or a signed contract related to a construction project. The capital equipment backlog was $894 million at December 31, 2018, a decrease of $172 million, or 16 percent from backlog of $1,066 million at December 31, 2017. Numerous factors may affect the timing of revenue out of backlog. Considering these factors, the Company reasonably expects approximately $0.8 billion of revenue out of backlog in 2019 and approximately $122 million of revenue out of backlog in 2020 and thereafter. At December 31, 2018, approximately 58 percent of the capital equipment backlog was for offshore products and approximately 70 percent of the capital equipment backlog was destined for international markets. Rig Technologies Revenue from Rig Technologies for the year ended December 31, 2014.2018 was $2,575 million, an increase of $323 million (14.3%) compared to the year ended December 31, 2017. The increase was due to better progress on projects and improved aftermarket sales. Operating profit from Rig Technologies was $213 million for the year ended December 31, 2018, an increase of $227 million compared to 2017. Operating profit percentage for 2018 was 8.3% compared to an operating loss percentage of 0.6% in 2017. Included in operating profit are other items related to severance and facility closures, and asset write-downs. Other items included in operating profit for Rig Technologies were $6 million for the year ended December 31, 2018 and $129 million for the year ended December 31, 2017. The Rig SystemsTechnologies 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 $6.1$3.1 billion at December 31, 2015, a decrease2018, an increase of $6.4$1.2 billion, or 52%63%, from backlog of $12.5$1.9 billion at December 31, 2014.2017. Numerous factors may affect the timing of revenue out of backlog. Considering these factors, the Company reasonably expects approximately $2.2$0.8 billion of revenue out of backlog in 20162019 and approximately $3.9$2.3 billion of revenue out of backlog in 20172020 and thereafter. At December 31, 2015,2018, approximately 90%31% of the capital equipment backlog was for offshore products and approximately 93%90% of the capital equipment backlog was destined for international markets. Rig AftermarketEliminations and corporate costs
Revenue from Rig AftermarketEliminations and corporate costs were $299 million for the year ended December 31, 20152018 compared to $259 million for the year ended December 31, 2017. This change is primarily due to an increase in intersegment sales. 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 and corporate costs include intercompany transactions conducted between the three reporting segments that are eliminated in consolidation, as well as corporate costs not allocated to the segments. Intercompany transactions within each reporting segment are eliminated within each reporting segment.
Other income (expense), net Other income (expense), net were expenses of $99 million for the year ended December 31, 2018 compared to expenses of $33 million for the year ended December 31, 2017. The increase in expense was $2,515primarily due to higher foreign exchange losses for 2018. Provision for income taxes The effective tax rate for the year ended December 31, 2018 was 153.7%, compared to 39.8% for 2017. For the year ended December 31, 2018, valuation allowances established on foreign tax credits generated during the year resulted in a higher effective tax rate than the U.S. statutory rate. For the year ended December 31, 2017, the revaluation of net deferred tax liabilities in the U.S. partially offset by valuation allowances established on foreign tax credits generated during the year, when applied to losses resulted in a higher effective tax rate than the U.S. statutory rate.
Years Ended December 31, 2017 and December 31, 2016 Wellbore Technologies Revenue from Wellbore Technologies for the year ended December 31, 2017 was $2,577 million, a decreasean increase of $707$378 million (21.9%(17.2%) compared to the year ended December 31, 2014.2016. The decreaseincrease was due to lower globalhigher drilling activity which has caused customers to use existing inventories and components from idle and unused rigs to repair better utilized rigs rather than purchase new.activity. Operating profitloss from Rig AftermarketWellbore Technologies was $605$102 million for the year ended December 31, 2015,2017, a decrease of $277$668 million (31.4%(86.8%) compared to 2014.the year ended December 31, 2016. Operating profitloss percentage decreased to 24.1%,4.0% from 27.4%35.0% in 2014.2016. Operating profit percentageloss decreased primarily due to lower volumes and pricing pressure.higher drilling activity in 2017. Included in operating profit are certain restructuring and other items related to costs associated with a Voluntary Early Retirement Plan established by the Company during the first quarter of 2015 and2016, costs related to severance and facility closures. Restructuringclosures, and otherasset write-downs. Other items included in operating profit for Rig AftermarketWellbore Technologies were $12$28 million for the year ended December 31, 20152017 and nil$476 million for the year ended December 31, 2014.2016. Wellbore TechnologiesCompletion & Production Solutions
Revenue from Wellbore TechnologiesCompletion & Production Solutions for the year ended December 31, 20152017 was $3,718$2,672 million, a decreasean increase of $2,004$431 million (35.0%(19.2%) compared to the year ended December 31, 2014.2016. The decreaseincrease was due to lower drillinghigher market activity. Operating lossprofit (loss) from Wellbore TechnologiesCompletion & Production Solutions was $1,613$98 million for the year ended December 31, 20152017 compared to operating profit of $937($266) million for 2014, a decrease2016, an increase of $2,550$364 million (272.1%(136.8%). Operating profit (loss) percentage decreasedincreased to negative 43.4%3.7% from 16.4%(11.9)% in 2014. Operating profit decreased mainly2016. This increase was due to a $1,658 million impairment charge incurred on the carrying value of goodwillan overall increase in the segment’s Drilling & Intervention and Drill Pipe business units as well as a certain indefinite-lived trade name associated with this segment in the fourth quarter of 2015, as well as the overall decrease in drillingmarket activity. Included in operating profit are certain restructuring and other items related to costs associated with a Voluntary Early Retirement Plan established by the Company during the first quarter of 2015 and2016; costs related to severance and facility closures. Restructuring and other items included in operating profit for Wellbore Technologies were $117 million for the year ended December 31, 2015 and $6 million for the year ended December 31, 2014. Completion & Production Solutions
Revenue from Completion & Production Solutions for the year ended December 31, 2015 was $3,365 million, a decrease of $1,280 million (27.6%) compared to the year ended December 31, 2014. The decrease was due lower market activity.
Operating profit from Completion & Production Solutions was $161 million for the year ended December 31, 2015 compared to $690 million for 2014, a decrease of $529 million (76.7%). Operating profit percentage decreased to 4.8% from 14.9% in 2014. This decrease was due to the overall decrease in market activity as well as $24 million in impairment charges incurred on intangible assets.
Included in operating profit are certain restructuring and other items related to costs associated with a Voluntary Early Retirement Plan established by the Company during the first quarter of 2015; costs related to severance and
facility closures; items related to acquisitions, such as transaction costs, the amortization of backlog and inventory that was stepped up to fair value during purchase accounting. Restructuringaccounting; and otherasset write-downs. Other items included in operating profit for Completion & Production Solutions were $101$33 million for the year ended December 31, 20152017 and $10$274 million for the year ended December 31, 2014.2016. The Completion & Productions 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 completion and production components or a signed contract related to a construction project. The capital equipment backlog was $969$1,066 million at December 31, 2015, a decrease2017, an increase of $810$248 million, or 46%30% from backlog of $1,780$818 million at December 31, 2014.2016. Numerous factors may affect the timing of revenue out of backlog. Considering these factors, the Company reasonably expects approximately $778$953 million of revenue out of backlog in 20162018 and approximately $191$113 million of revenue out of backlog in 20172019 and thereafter. At December 31, 2015,2017, approximately 75%59% of the capital equipment backlog was for offshore products and approximately 87%73% of the capital equipment backlog was destined for international markets. EliminationsRig Technologies
Eliminations in operating profit were $749 millionRevenue from Rig Technologies for the year ended December 31, 2015 compared to $8922017 was $2,252 million, for the year ended December 31, 2014. This change is primarily due to lower intersegment sales. 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 expensesa decrease of $123$858 million for the year ended December 31, 2015 compared to expenses of $90 million for the year ended December 31, 2014. The increase was primarily due to higher foreign exchange losses.
Provision for income taxes
The effective tax rate for the year ended December 31, 2015 was (30.2)%, compared to 29.7% for 2014. Compared to the U.S. statutory rate, the effective tax rate was positively impacted in the period by a domestic loss, the effect of lower tax rates on income earned in foreign jurisdictions, a reduction of deferred taxes due to decreases in statutory tax rates of foreign jurisdictions, and foreign exchange losses for tax reporting in Norway. The effective tax rate was negatively impacted by additional U.S. tax on foreign dividends net of foreign tax credits, the recognition and settlement of an uncertain tax position in a foreign jurisdiction, and nondeductible expenses. The nondeductible expenses primarily consist of non-deductible goodwill impaired during the year ended December 31, 2015.
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%(27.6%) compared to the year ended December 31, 2013. Increased demand for high-spec land rigs and equipment resulted2016. The decrease was due to lower volumes 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.all areas.
Operating profitloss from Rig SystemsTechnologies was $1,996$14 million for the year ended December 31, 2014,2017, an increaseimprovement of $402$1,019 million (25.2%(98.6%) compared to 2013.2016. Operating profitloss percentage increaseddecreased to 20.3%0.6%, from 18.9%33.2% in 2013. Increased demand for high-spec land rigs and equipment generated higher operating profit percentages.2016. Operating loss decreased primarily due to a $972 million impairment charge incurred on the carrying value of goodwill during the third quarter of 2016 that did not repeat in 2017, partially offset by lower volumes. Included in operating profit are certain Otherother items which include items such as transactionrelated to costs associated with a Voluntary Early Retirement Plan established by the Company during the first quarter of 2016, costs related to severance and inventory that was stepped up during purchase accounting.facility closures, and asset write-downs, including the impairment charge mentioned above. Other items included in operating profit for Rig Systems
Technologies were nil for the year ended December 31, 2014 and $21$129 million for the year ended December 31, 2013.2017 and $1,255 million for the year ended December 31, 2016. The Rig SystemsTechnologies 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$1.9 billion at December 31, 2014,2017, a decrease of $2.5$0.6 billion, (17%)or 24%, from backlog of $15.0$2.5 billion at December 31, 2013. Rig Aftermarket
Revenue from Rig Aftermarket for2016. Numerous factors may affect the year endedtiming of revenue out of backlog. Considering these factors, the Company reasonably expects approximately $0.8 billion of revenue out of backlog in 2018 and approximately $1.1 billion of revenue out of backlog in 2019 and thereafter. At December 31, 20142017, approximately 78% of the capital equipment backlog was $3,222 million, an increasefor offshore products and approximately 81% of $530 million (19.7%) compared to the year ended December 31, 2013. This increase is primarily due to increased demandcapital equipment backlog was destined for spare parts, repairsinternational markets.
Eliminations and services as a result of high levels of drilling activitycorporate costs Eliminations and our large installed base of equipment. Operating profit from Rig Aftermarket was $882corporate costs in operating loss were $259 million for the year ended December 31, 2014, an increase of $153 million (21.0%)2017 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$342 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 2013.2016. 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 waschange is primarily due to increased intercompany sales activity for all segments resulting in higherlower intersegment eliminations.sales. 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 and corporate costs include intercompany transactions conducted between the fourthree reporting segments that are eliminated in consolidation.consolidation, as well as corporate costs not allocated to the segments. Intercompany transactions within each reporting segment are eliminated within each reporting segment.
Other income (expense), net Other income (expense), net were expenses of $90$33 million for the year ended December 31, 20142017 compared to expenses of $39$101 million for the year ended December 31, 2013.2016. The increasedecrease 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.lower asset disposals. Provision for income taxes The effective tax rate for the year ended December 31, 20142017 was 29.7%39.8%, compared to 30.2%7.9% for 2013. Compared2016. For the year ended December 31, 2017, the revaluation of net deferred tax liabilities in the U.S. partially offset by valuation allowances established on foreign tax credits generated during the year, when applied to losses resulted in a higher effective tax rate than the U.S. statutory rate,rate. For the effectiveyear ended December 31, 2016, the impairment of goodwill not deductible for tax rate was positively impacted in the period by the effect ofpurposes, lower tax rates on income earnedlosses incurred in foreign jurisdictions, a reduction in valuation allowance on deferred taxes, and the deductionestablishment of valuation allowances, when applied to losses resulted in the U.S. for manufacturing activities. Thea lower effective tax rate was negatively impacted by foreign dividends net of foreign tax credits, and nondeductible expenses.than the U.S. statutory rate. Non-GAAP Financial Measures and Reconciliations In an effort to provide investors with additional information regarding our resultsThe Company discloses Adjusted EBITDA (defined as determined by GAAP, we disclose various non-GAAP financial measuresOperating Profit excluding Depreciation, Amortization and, when applicable, Other Items) in our quarterlyits periodic earnings press releases and other public disclosures.disclosures to provide investors additional information about the results of ongoing operations. The primary non-GAAPCompany uses Adjusted EBITDA internally to evaluate and manage the business. Adjusted EBITDA is not intended to replace GAAP financial measures, we focus on are: (i) operating profit excluding othersuch as Net Income. Other items (ii) operating profit percentage excluding other items, (iii) diluted earnings per share excluding other itemsin the three and operating (non-GAAP) earnings. Each of these financial measures excludestwelve months ended December 31, 2018 were $21 and $9 million, pre-tax, respectively, primarily from the impactadjustment of certain amounts as further identified belowaccruals, restructure charges, and has not been calculatedseverance payments. Other items in accordance with GAAP. A2017 consisted primarily of restructure charges for inventory write-downs, facility closures and severance payments.
The following tables set forth the reconciliation of each of these non-GAAP financial measuresAdjusted EBITDA 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)millions):
| | | | | | | | | | | | | | | | | | | | | | | | | | | Three Months Ended | | | Years Ended December 31, | | | | December 31, | | | September 30, | | | | | 2015 | | | 2014 | | | 2015 | | | 2015 | | | 2014 | | | 2013 | | Reconciliation of operating profit (loss): | | | | | | | | | | | | | | | | | | | | | | | | | GAAP operating profit (loss) | | $ | (1,632 | ) | | $ | 913 | | | $ | 234 | | | $ | (390 | ) | | $ | 3,613 | | | $ | 3,199 | | Litigation gain (1): | | | | | | | | | | | | | | | | | | | | | | | | | Wellbore Technologies | | | — | | | | — | | | | — | | | | — | | | | — | | | | (102 | ) | Goodwill and other intangible asset write-downs (2): | | | | | | | | | | | | | | | | | | | | | | | | | Rig Systems | | | — | | | | — | | | | 7 | | | | 7 | | | | — | | | | — | | Wellbore Technologies | | | 1,634 | | | | 104 | | | | 24 | | | | 1,658 | | | | 104 | | | | — | | Completion & Production Solutions | | | — | | | | — | | | | 24 | | | | 24 | | | | — | | | | — | | Restructuring and other items (3): | | | | | | | | | | | | | | | | | | | | | | | | | Rig Systems | | | 47 | | | | — | | | | 15 | | | | 105 | | | | — | | | | 21 | | Rig Aftermarket | | | 1 | | | | — | | | | 1 | | | | 12 | | | | — | | | | — | | Wellbore Technologies | | | 58 | | | | — | | | | 5 | | | | 117 | | | | 6 | | | | 41 | | Completion & Production Solutions | | | 33 | | | | 1 | | | | 36 | | | | 101 | | | | 10 | | | | 82 | | Eliminations and other | | | — | | | | — | | | | — | | | | — | | | | 36 | | | | 2 | | | | | | | | | | | | | | | | | | | | | | | | | | | Operating profit excluding other items | | $ | 141 | | | $ | 1,018 | | | $ | 346 | | | $ | 1,634 | | | $ | 3,769 | | | $ | 3,243 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Three Months Ended | | | Years Ended December 31, | | | | December 31, | | | September 30, | | | | | 2015 | | | 2014 | | | 2015 | | | 2015 | | | 2014 | | | 2013 | | Reconciliation of operating profit (loss)%: | | | | | | | | | | | | | | | | | | | | | | | | | GAAP operating profit (loss)% | | | (60.0 | %) | | | 16.0 | % | | | 7.1 | % | | | (2.6 | %) | | | 16.9 | % | | | 16.6 | % | Asset write-downs, restructuring and other items (2) (3)% | | | 65.2 | % | | | 1.8 | % | | | 3.4 | % | | | 13.7 | % | | | 0.7 | % | | | 0.4 | % | | | | | | | | | | | | | | | | | | | | | | | | | | Operating profit % excluding other items | | | 5.2 | % | | | 17.8 | % | | | 10.5 | % | | | 11.1 | % | | | 17.6 | % | | | 17.0 | % | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Three Months Ended | | | Years Ended December 31, | | | | December 31, | | | September 30, | | | | | 2015 | | | 2014 | | | 2015 | | | 2015 | | | 2014 | | | 2013 | | Reconciliation of diluted earnings (loss) per share: | | | | | | | | | | | | | | | | | | | | | | | | | GAAP earnings (loss) per share (continuing operations) | | $ | (4.06 | ) | | $ | 1.39 | | | $ | 0.41 | | | $ | (1.99 | ) | | $ | 5.70 | | | $ | 5.09 | | Litigation gain (1) | | | — | | | | — | | | | — | | | | — | | | | — | | | | (0.17 | ) | Goodwill and other intangible asset write-downs (2) | | | 4.21 | | | | — | | | | 0.10 | | | | 4.18 | | | | 0.13 | | | | — | | Restructuring and other items (3) | | | 0.25 | | | | 0.30 | | | | 0.10 | | | | 0.57 | | | | 0.24 | | | | 0.23 | | Argentina/Venezuela asset write-down (Other income (expense), net) | | | 0.01 | | | | — | | | | — | | | | 0.04 | | | | — | | | | 0.02 | | Tax items (Provision for income taxes) | | | (0.18 | ) | | | — | | | | — | | | | — | | | | — | | | | — | | | | | | | | | | | | | | | | | | | | | | | | | | | Operating (non-GAAP) earnings per share | | $ | 0.23 | | | $ | 1.69 | | | $ | 0.61 | | | $ | 2.80 | | | $ | 6.07 | | | $ | 5.17 | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended | | | Years Ended | | | | December 31, | | | September 30, | | | December 31, | | | | 2018 | | | 2017 | | | 2018 | | | 2018 | | | 2017 | | Operating profit (loss): | | | | | | | | | | | | | | | | | | | | | Wellbore Technologies | | $ | 41 | | | $ | (21 | ) | | $ | 40 | | | $ | 131 | | | $ | (102 | ) | Completion & Production Solutions | | | 64 | | | | 19 | | | | 46 | | | | 166 | | | | 98 | | Rig Technologies | | | 75 | | | | (51 | ) | | | 58 | | | | 213 | | | | (14 | ) | Eliminations and corporate costs | | | (93 | ) | | | (58 | ) | | | (71 | ) | | | (299 | ) | | | (259 | ) | Total operating profit (loss) | | $ | 87 | | | $ | (111 | ) | | $ | 73 | | | $ | 211 | | | $ | (277 | ) | | | | | | | | | | | | | | | | | | | | | | Other items: | | | | | | | | | | | | | | | | | | �� | | | Wellbore Technologies | | $ | 24 | | | $ | 32 | | | $ | — | | | $ | 21 | | | $ | 28 | | Completion & Production Solutions | | | (3 | ) | | | 1 | | | | — | | | | — | | | | 33 | | Rig Technologies | | | — | | | | 100 | | | | — | | | | 6 | | | | 129 | | Corporate | | | — | | | | — | | | | — | | | | (18 | ) | | | — | | Total other items | | $ | 21 | | | $ | 133 | | | $ | — | | | $ | 9 | | | $ | 190 | | | | | | | | | | | | | | | | | | | | | | | Depreciation & amortization: | | | | | | | | | | | | | | | | | | | | | Wellbore Technologies | | $ | 90 | | | $ | 96 | | | $ | 95 | | | $ | 374 | | | $ | 379 | | Completion & Production Solutions | | | 51 | | | | 54 | | | | 53 | | | | 212 | | | | 215 | | Rig Technologies | | | 27 | | | | 21 | | | | 20 | | | | 90 | | | | 88 | | Corporate | | | 3 | | | | 4 | | | | 4 | | | | 14 | | | | 16 | | Total depreciation & amortization | | $ | 171 | | | $ | 175 | | | $ | 172 | | | $ | 690 | | | $ | 698 | | | | | | | | | | | | | | | | | | | | | | | Adjusted EBITDA: | | | | | | | | | | | | | | | | | | | | | Wellbore Technologies | | $ | 155 | | | $ | 107 | | | $ | 135 | | | $ | 526 | | | $ | 305 | | Completion & Production Solutions | | | 112 | | | | 74 | | | | 99 | | | | 378 | | | | 346 | | Rig Technologies | | | 102 | | | | 70 | | | | 78 | | | | 309 | | | | 203 | | Eliminations and corporate costs | | | (90 | ) | | | (54 | ) | | | (67 | ) | | | (303 | ) | | | (243 | ) | Total adjusted EBITDA | | $ | 279 | | | $ | 197 | | | $ | 245 | | | $ | 910 | | | $ | 611 | | | | | | | | | | | | | | | | | | | | | | | Reconciliation of Adjusted EBITDA: | | | | | | | | | | | | | | | | | | | | | GAAP net income (loss) attributable to Company | | $ | 12 | | | $ | (14 | ) | | $ | 1 | | | $ | (31 | ) | | $ | (237 | ) | Noncontrolling interests | | | 3 | | | | (1 | ) | | | 3 | | | | 9 | | | | 1 | | Provision (benefit) for income taxes | | | 26 | | | | (123 | ) | | | 29 | | | | 63 | | | | (156 | ) | Interest expense | | | 22 | | | | 25 | | | | 24 | | | | 93 | | | | 102 | | Interest income | | | (7 | ) | | | (6 | ) | | | (6 | ) | | | (25 | ) | | | (25 | ) | Equity (income) loss in unconsolidated affiliate | | | 2 | | | | 1 | | | | 2 | | | | 3 | | | | 5 | | Other (income) expense, net | | | 29 | | | | 7 | | | | 20 | | | | 99 | | | | 33 | | Depreciation and amortization | | | 171 | | | | 175 | | | | 172 | | | | 690 | | | | 698 | | Other items | | | 21 | | | | 133 | | | - | | | | 9 | | | | 190 | | Total Adjusted EBITDA | | $ | 279 | | | $ | 197 | | | $ | 245 | | | $ | 910 | | | $ | 611 | |
(1) | Included in revenue and operating profit for the year ended December 31, 2013, is a $102 million gain resulting from a legal settlement. |
(2) | Included in operating profit are other items related to goodwill and intangible asset impairments. |
(3) | Included in operating profit are restructuring and other items related to costs associated with a Voluntary Early Retirement Plan established by the Company during the first quarter of 2015; costs related to severance and facility closures; items related to acquisitions, such as transaction costs, the amortization of backlog and inventory that was stepped up to fair value during purchase accounting; the costs of the spin-off of the Company’s distribution business and certain legal costs. See Note 7. Restructuring and other items that are included in other income (expense), net were nil for each of the three months and for the year ended December 31, 2015, respectively; $58 million for each of the three months and for the year ended December 31, 2014, respectively; and nil for the three months ended September, 2015. |
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, 2015,2018, the Company had cash and cash equivalents of $2,080$1,427 million, and total debt of $3,930$2,711 million. At December 31, 2014,2017, cash and cash equivalents were $3,536$1,437 million and total debt was $3,166$2,712 million. A significant portionAs of December 31, 2018, approximately $979 million 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 $2,080$1,427 million of cash and cash equivalents at December 31, 2015, approximately $2,034 million iswas held outsideby our foreign subsidiaries and the earnings associated with this cash were subject to U.S. taxation under the Act defined in Note 14 to the Consolidated Financial Statements. If opportunities to invest in the U.S. are greater than available cash balances that are not subject to income tax, rather than repatriating this cash, the Company may choose to borrow against its revolving credit facility or utilize its commercial paper program. On August 15, 2015,June 27, 2017, the Company entered into a new $3.0 billion credit agreement evidencing a five-year unsecured revolving credit facility, which expires on June 27, 2022, with a syndicate of financial institutions. This new credit facility replaced the Company’s previous $4.5 billion revolving credit facility. The Company has the right to increase the aggregate commitments under this new agreement to an aggregate amount of up to $4.0 billion upon the consent of only those lenders holding any such increase. Interest under the new multicurrency facility is based upon LIBOR, NIBOR or CDOR plus 1.125% subject to a ratings-based grid or the U.S. prime rate. The new credit facility contains a financial covenant regarding maximum debt-to-capitalization ratio of 60%. As of December 31, 2018, the Company was in compliance with a debt-to-capitalization ratio of 16.3%. On November 29, 2017, the Company repaid $151in its entirety the $500 million of its 6.125%1.35% unsecured Senior Notes using available cash balances. The Company’s outstanding debt at December 31, 20152018 was $3,930$2,711 million and consisted of $500 million in 1.35% Senior Notes, $1,396$1,394 million in 2.60% Senior Notes, $1,096$1,088 million in 3.95% Senior Notes, $893 million inno commercial paper borrowings, and other debt of $45$229 million. The Company was in compliance with all covenants at December 31, 2015.2018. During the second quarter of 2015, the Company exercised its accordion option to increase aggregate borrowing capacity under its five-year unsecured revolving credit facility by an additional $1.0 billion, bringing the aggregate borrowing capacity to $4.5 billion. In addition to the $893 million inAt December 31, 2018, there were no commercial paper borrowings supported by the $3.0 billion credit facility there wereand no outstanding letters of credit issued under the credit facility, resulting in $3,607 million$3.0 billion of funds available under this revolving credit facility.
The Company also had $2,378$480 million of additional outstanding letters of credit at December 31, 20152018 that are under various bilateral letter of credit facilities. Other lettersLetters of credit are issued as bid bonds, advanced 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 used in continuing financing activities for the periods presented (in millions): | | | | | | | | | | | | | | | Years Ended December 31, | | | | 2015 | | | 2014 | | | 2013 | | Net cash provided by continuing operating activities | | $ | 1,332 | | | $ | 2,525 | | | $ | 3,080 | | Net cash used in continuing investing activities | | | (514 | ) | | | (1,092 | ) | | | (2,910 | ) | Net cash used in continuing financing activities | | | (2,163 | ) | | | (1,343 | ) | | | (304 | ) |
| | Years Ended December 31, | | | | 2018 | | | 2017 | | | 2016 | | Net cash provided by operating activities | | $ | 521 | | | $ | 832 | | | $ | 960 | | Net cash used in investing activities | | | (457 | ) | | | (245 | ) | | | (488 | ) | Net cash used in financing activities | | | (30 | ) | | | (595 | ) | | | (1,141 | ) |
Operating Activities 20152018 vs 2014.2017. Net cash provided by continuing operating activities was $1,332$521 million in 20152018 compared to net cash provided by continuing operating activities of $3,080$832 million in 2014.2017. Before changes in operating assets and liabilities, net of acquisitions, cash was provided primarily by continuing operations primarily throughnet loss from continuing operations of $74$22 million plus non-cash charges of $505$779 million plus $34 million in a dividend received from Voest-Alpine Tubulars, an unconsolidated affiliate, less $13and $3 million in equity income.loss in unconsolidated affiliates.
The change in operating assets and liabilities in 2018 compared to the same period in 2017 was primarily due to declines in inventory and contract assets. Net changes in operating assets and liabilities, net of acquisitions, used $466$400 million of cash in 20152018 compared to $794cash provided of $448 million used in the same period in 2014. The decrease2017. From time to time, we participate in cash used in 2015 comparedfactoring arrangements to the same period in 2014 was the result of a decline insell accounts receivable to third-party financial institutions. In 2018, we sold accounts receivable of $248 million at a cost of approximately $2 million, receiving cash proceeds totaling $246 million. Our factoring transactions in 2018 were recognized as sales, and inventory; partially offset by a declinethe proceeds are included as operating cash flows in accounts payable and decreased orders inour Consolidated Statements of Cash Flows. We did not factor any receivables during the Rig Systems segment which is reflected in customer financing, where revenue recognized outpaced prepayments and milestone invoicing on major projects.fourth quarter 2018. 20142017 vs 2013.2016. Net cash provided by continuing operating activities was $2,525$832 million in 20142017 compared to net cash provided by continuing operating activities of $3,080$960 million in 2013. 2016. Before changes in operating assets and liabilities, net of acquisitions, cash was provided by operations in 2017 primarily through net income from continuing operations of $2,455 million plusoperating activities that generated earnings before non-cash charges of $484$379 million and a $73 million dividend received from Voest-Alpine Tubulars, an unconsolidated affiliate, less $58$5 million in equity income. loss in unconsolidated affiliates.
Net changes in operating assets and liabilities, net of acquisitions, used $794provided $448 million of cash in 20142017 compared to $350$1,044 million provided in 2013. Due to an increase2016. The decrease in market activity during 2014cash provided in 2017 compared to 2013, revenue and backlog increased which is reflected2016 was primarily due to declines in increasedcash provided by accounts receivable, as well as a buildup in inventory. Increased market activity during 2014 also resulted in higher taxes paid,inventory and an increase in both costs in excess of billings, partially offset by declines in cash used by accrued liabilities and billings in excess of costs with costs incurred on major rig projects outpacing customer progress and milestone invoicing.by accounts payable providing cash in 2017 compared to using cash in 2016. Investing Activities 20152018 vs 2014.2017. Net cash used in continuing investing activities was $514$457 million in 20142018 compared to net$245 million in 2017. The increase in net cash used in continuing investing activities of $1,092 million in 2014. Net cash used in continuing investing activities was primarily the result of increased acquisitions and capital expenditures and acquisition activity both of which decreased in 20152018 compared to 2014.2017. The Company used $453$280 million during 20152018 for acquisitions compared to $86 million in 2017 and $244 million for capital expenditures during 2018, compared to $699$192 million in 2014 and $86 million for acquisitions during 2015, compared to $291 million in 2014.2017.
20142017 vs 2013.2016. Net cash used in continuing investing activities was $1,092$245 million in 20142017 compared to net cash used in continuing investing activities of $2,910$488 million in 2013. Net2016. The decrease in 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.
Financing Activities
2015 vs 2014. Net cash used in continuing financing activities was $2,163 million in 2015 compared to $1,343 million in 2014. This increase was primarily the result of $2,221decreased acquisitions and capital expenditures in 2017 compared to 2016. The Company used $86 million during 2017 for acquisitions compared to $230 million in 2016 and $192 million for capital expenditures during 2017, compared to $284 million in 2016.
Financing Activities 2018 vs 2017. Net cash used in financing activities was $30 million in 2018 compared to $595 million in 2017. This decrease was primarily the result of lower debt payments in 2018 compared to 2017. 2017 vs 2016. Net cash used in financing activities was $595 million in 2017 compared to $1,141 million in 2016. This decrease was primarily the result of $506 million of debt payments in 2017 compared to $900 million used to repurchase and retire 44.0 million of the Company’s common shares outstanding during 2015. In order to fund a large portion of the share repurchases, the Company entered intomake payments on net commercial paper borrowings of $893 million during 2015. The Company repaid $151 million of Senior Notes in the third quarter of 2015.2016. In addition, the Company increaseddecreased its dividend to $710$76 million during 20152017 compared to $703$230 million in 2014.2016. 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.
Other The effect of the change in exchange rates on cash was a decreasean increase (decrease) of $111($44) million, $67$37 million and $11($3) million for the years ended December 31, 2015, 20142018, 2017 and 2013, respectively. During the third quarter of 2015 the Company completed its $3 billion share repurchase program. As shares were repurchased, they were constructively retired and returned to an unissued state. During the years ended December 31, 2015 and 2014, the Company repurchased 44.0 million and 11.6 million shares, respectively, under the program for an average price of $50.53 and $66.97 per share, respectively, for an aggregate amount of $2,221 million and $779 million,2016, 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, 20152018 is as follows (in millions): | | | | | | | | | | | | | | | | Payment Due by Period | | | | | | | Payment Due by Period | | | | | | | Less | | | | | | | | | | | | | | | | Total | | | Less than 1 Year | | | 1-3 Years | | | 4-5 Years | | | After 5 Years | | | Total | | | than 1 Year | | | 1-3 Years | | | 4-5 Years | | | After 5 Years | | Contractual Obligations: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Total debt | | $ | 3,930 | | | $ | 2 | | | $ | 1,404 | | | $ | 10 | | | $ | 2,514 | | | $ | 2,711 | | | $ | 7 | | | $ | 14 | | | $ | 1,410 | | | $ | 1,280 | | Operating leases | | | 922 | | | | 202 | | | | 211 | | | | 140 | | | | 369 | | | | 732 | | | | 126 | | | | 194 | | | | 119 | | | | 293 | | | | | | | | | | | | | | | | | | | Total Contractual Obligations | | $ | 4,852 | | | $ | 204 | | | $ | 1,615 | | | $ | 150 | | | $ | 2,883 | | | $ | 3,443 | | | $ | 133 | | | $ | 208 | | | $ | 1,529 | | | $ | 1,573 | | | | | | | | | | | | | | | | | | | Commercial Commitments: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Standby letters of credit | | $ | 2,378 | | | $ | 1,399 | | | $ | 923 | | | $ | 54 | | | $ | 2 | | | $ | 480 | | | $ | 357 | | | $ | 95 | | | $ | 17 | | | $ | 11 | | | | | | | | | | | | | | | | | | |
As of December 31, 2015, the Company entered into a capital lease agreement covering a period of 25 years, totaling approximately $270 million. This lease becomes effective in 2016.
As of December 31, 2015,2018, the Company had $46$98 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.Statements. 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); impairment of 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 The majority of the Company’s revenue streams record revenue at a point in time when a performance obligation has been satisfied by transferring control of promised goods or services to a customer. Products and services are sold or rented based upon a fixed or determinable price and do not generally include significant post-delivery obligations. Payment terms and conditions vary by contract type. We have elected to apply the practical expedient that does not require an adjustment for a financing component if, at contract inception, the period between when we transfer the promised goods or service to the customer and when the customer pays for the goods or service is one year or less. Shipping and handling costs are recognized when incurred and are treated as costs to fulfill the original performance obligation. Revenue is often generated from contracts that include multiple performance obligations. Using significant judgement, the Company considers the degree of customization, integration and interdependency of the related products and services when assessing distinct performance obligations within one contract. Stand-alone selling price (“SSP”) for each distinct performance obligation is generally determined using the price at which the products and services would be sold separately to the customer. Discounts, when provided, are allocated based on the relative SSP of the various products and services.
For revenue that is not recognized at a point in time, the Company follows accounting guidance for revenue recognized over time, as follows: Revenue Recognition under Long-term Construction Contracts The Company uses the percentage-of-completion method to accountRevenue is recognized over-time for certain long-term construction contracts in the Rig Systems and Completion & Production Solutions and Rig Technologies segments. These long-term construction contracts include the following characteristics:
the contracts include custom designs for customer-specific applications that are unique and require significant engineering efforts. Revenue is recognized as work progresses on each contract. Right to payment is enforceable for performance completed to date, including a reasonable profit.We generally use the cost-to-cost (input) measure of progress for our contracts because it best depicts the transfer of assets to the customer specific applications; which occurs as we incur costs. Under the structural designcost-to-cost measure of progress, progress towards completion of each contract is uniquemeasured based on the ratio of costs incurred to date to the total estimated costs at completion of the performance obligation. Revenues, including estimated fees or profits, are recorded proportionally as costs are incurred. These costs include labor, materials, subcontractors’ costs, and other direct costs. Any expected losses on a project are recorded in full in the period in which the loss becomes probable.These long-term construction contracts generally include a significant service of integrating a complex set of tasks and components into a single project or capability, so are accounted for as one performance obligation. Estimating total revenue and cost at completion of long-term construction contracts is complex, subject to many variables and requires significant engineering efforts;judgment. It is common for our long-term contracts to contain late delivery fees, work performance guarantees, and construction projects often have progress payments.
This method requires other provisions that can either increase or decrease the Companytransaction price. We estimate variable consideration as the most likely amount we expect to make estimates regarding the total costs of the project, progress against the project schedule andreceive. We include variable consideration in the estimated completion date, alltransaction price to the extent it is probable that a significant reversal of which impactcumulative revenue recognized will not occur, or when the amountuncertainty associated with the variable consideration is resolved. Our estimates of variable consideration and determination of whether to include estimated amounts in the transaction price are based on an assessment of our anticipated performance and historical, current and forecasted information that is reasonably available to us. Net revenue and gross marginrecognized from performance obligations satisfied in previous periods was $65 million for 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. For the yearsyear ended December 31, 20152018 primarily due to change orders.
Service and 2014,Repair Work For service and repair contracts, revenue is recognized over time. We generally use the difference betweenoutput method to measure progress on service contracts due to the priormanner in which the customer receives and derives value from the services provided. For repair contracts, we generally use the cost-to-cost measure of progress because it best depicts the transfer of assets to the customer. Remaining Performance Obligations Remaining performance obligations represent the transaction price of firm orders for all revenue streams for which work has not been performed on contracts with an original expected duration of one year estimated margin on openor more. We do not disclose the remaining performance obligations of royalty contracts, service contracts for which there is a right to invoice, and actual results achievedshort-term contracts that are expected to have a duration of one year or less. As of December 31, 2018, the aggregate amount of the transaction price allocated to remaining performance obligations was $1,813 million. The Company expects to recognize approximately $887 million in revenue for the years indicated wasremaining performance obligations in 2019 and $926 million in 2020 and thereafter. Costs to Obtain and Fulfill a net decrease to gross profit marginsContract We recognize an asset for the incremental costs of 0.53% ($92 million on $17.3 billionobtaining a contract, such as sales commissions, with a customer when we expect the benefit of outstanding contracts) and 0.19% ($26 million on $13.8 billion of outstanding contracts), respectively. While the Company believes that its estimates on outstanding contracts at and in future periods will continuethose costs to be reasonably dependable under percentage-of-completion accounting,longer than one year. Costs to fulfill a contract, such as set-up and mobilization costs, are also capitalized when we expect to recover those costs. These contract costs are deferred and amortized over the factors identifiedperiod of contract performance. Total capitalized costs to obtain and fulfill a contract and the related amortization were immaterial during the periods presented and are included in other current and long-term
assets on our consolidated balance sheets. We apply the preceding paragraph could result in significant adjustments in future periods. The Company has recorded revenue on outstanding contracts (onpractical expedient to expense costs as incurred for costs to obtain a contract-to-date basis) of $13 billion at December 31, 2015.contract with a customer when the amortization period would have been one year or less. 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 revenue comecomes 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, 20152018 and 2014,2017, allowance for bad debts totaled $159$161 million and $125$187 million, or 5.2%7.1% and 2.7%8.5% 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 specializedfinished goods, spare parts, work in process, and raw materials to support ongoing manufacturing operations and the Company’s large installed base of highly 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.oilfield equipment. The Company’s estimated carrying value of inventory therefore depends upon demand largely driven by levels of oil and gas well 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 and governmental regulation in major oil and gas producing areas, and the potential obsolescence of various types of equipment we sell, among other factors. The Company evaluates inventory quarterly using the best information available at the time to inform our assumptions and estimates about future demand and resulting sales volumes, and recognizes reserves as necessary to properly state inventory. The historically severe oil-industry downturn that started in late 2014 began to stabilize during the second half of 2016, and showed early signs of improvement in many areas in the fourth quarter of 2016 and the first quarter of 2017, before declining slightly in the second quarter of 2017. The fourth quarter of 2017 saw improvement in oil prices. These signs of improvement, including conversations with customers about their plans, as well as inquiries and orders for products, provided the Company information with which to assess and adjust assumptions about future demand and market conditions. We saw clear evidence that a market recovery will favor newer technology and the most efficient equipment, and that certain products across our portfolio, for both land and offshore environments, were less likely to be successful going forward as our customers find footing in their newly competitive landscape. Based on an update of our assumptions at each point in time related to estimates of future demand, during 2018, 2017, and 2016 we recorded charges for additions to inventory reserves of $49 million, $114 million, and $606 million, respectively, consisting primarily of obsolete and surplus inventories. At December 31, 20152018 and 2014,2017, inventory reserves totaled $500$644 million and $370$800 million, or 9.7%17.7% and 6.7%21.0% of gross inventory, respectively. Changes Throughout the downturn the Company has continued to invest in worldwide oildeveloping and gas activity, oradvancing products and technologies, contributing to the developmentobsolescence of new technologiescertain older products in a dramatically-shifted and more highly competitive recovering market, but also ensuring that the portfolio of products and services offered by the Company will meet customer needs in 2019 and beyond.
We will continue to assess our inventory levels and inventory offerings for our customers, 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 or assumptions 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. 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. During the third quarter of 2015, the Company incurred $55 million in impairment charges on identified intangible assets with finite lives that were impaired and written off.
Goodwill and Other Indefinite-Lived Intangible Assets The Company has approximately $7.0$6.3 billion of goodwill and $0.4 billion of other intangible assets with indefinite lives as of December 31, 2015.2018. 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 sustained reduction in worldwide oil and gas prices or drilling; a significant sustained reduction in profitability or cash flow of oil and gas companies or drilling contractors; a sustained reduction in the market capitalization of the Company; a significant sustained reduction in capital investment by drilling companies and oil and gas companies; or a significant sustained increase in worldwide inventories of oil or gas. The discounted cash flow is based on management’s 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 businessreporting 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. 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 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 reviewthird quarter of its 2014 annual2016, market factors indicated a more prolonged downturn associated with newbuild offshore drilling rigs, and we reduced our forecast accordingly, which indicated a goodwill impairment test,in the calculated fair values for all ofRig Offshore reporting unit was possible. Based on the Company’s step one interim goodwill impairment analysis as of
July 1, 2016, the Rig Offshore 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,unit had a calculated fair value approximately $104 million below its carrying value. The impairment charge was primarilyvalue, and required a step two analysis, which compares the resultimplied fair value of goodwill of a reporting unit to the substantial decline in oil prices during the fourth quartercarrying value of 2014, declines in forecasts in rig activity for 2015, and a decline in the revenue forecastgoodwill for the segment for 2015. During the fourth quarter of 2015, the worldwide average rig count was 2,034 rigs, down 7% from the third quarter 2015 average of 2,188 and down 44% from the fourth quarter 2014 average of 3,632. The fourth quarter 2015 average rig count represented the lowest quarterly average in the past six years. The annual impairment test, as described in ASC Topic 350, “Intangibles—Goodwill and Other” (“ASC Topic 350”), is performed as of October 1 of each year.
Based on the Company’s impairment test performed in the fourth quarter of 2015, the calculated fair values for all of the Company’s reporting units were in excess of the respective reporting unit’s carrying value, with two exceptions. The Drilling & Intervention and Drill Pipe reporting units within the Company’s Wellbore Technologies segment, had calculated fair values below carrying value, resulting in a $1,485 million write-down in goodwill.
In addition, the Company’s Rig Offshore, Dynamic Drilling Solutions, Process and Flow Technologies and Fiberglass reporting units each had calculated fair values that were between 15% and 30% in excess of the respective carrying values. We continue to monitor the cash flows for these reporting units as they each contain material goodwill.
unit. 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. FairConsistent with the step one analysis, fair value of the reporting units isassets and liabilities was determined in accordance with ASC Topic 820 “Fair Value Measurements820. Based on the step two analysis performed for the Rig Offshore reporting unit, the Company recorded a $972 million write-down of goodwill during the third quarter of 2016. On July 1, 2017, the Company’s Wellbore Technologies segment reorganized three of its reporting units, moving various operations between them. The goodwill impairment analyses performed prior to and Disclosures” using significant unobservable inputs, or level 3subsequent to the restructuring of the three reporting units, concluded that the calculated fair values of these reporting units were substantially in excess of their carrying value. The restructuring had no effect on Wellbore Technologies consolidated financial position and results of operations. The Company combined its Rig Systems and Rig Aftermarket reporting units into two different reporting units, Rig Equipment and Marine Construction, under a segment called Rig Technologies, effective October 1, 2017. The restructuring better aligns operations with the fair value hierarchy. These inputs are based on internal management estimates, forecastscurrent and judgments, using discounted cash flow. Other indefinite-lived intangible assets, representing trade names management intends to use indefinitely, were valued using significant unobservable inputs (level 3)anticipated market environments, reduces administrative burden, and areeliminates reported intercompany transactions between Rig Technologies’ capital equipment and aftermarket operations. The Company tested the Rig Systems and Rig Aftermarket reporting units for impairment usingprior to combining, and the Relief from Royalty Method, a formtwo, new reporting units under the Rig Technologies segment for impairment after combining, and concluded all fair values of the Income Approach. An impairment is measured and recognizedreporting units were substantially in excess of their carrying values.
In 2017, based on the amountCompany’s annual impairment test performed as of October 1, the book valuecalculated fair values for all of the indefinite-lived intangible assets exceeds its estimated fair value asCompany’s reporting units were substantially in excess of the date of the impairment test. Included in the impairment test are assumptions, for each trade name, regarding the related revenue streams attributable to the trade names, which are determined in a manner consistent with the forecasting process described above, the royalty rate, and the discount rate applied. Based on the Company’s indefinite-lived intangible asset impairment analysis performed during the fourth quarter of 2015,respective reporting unit’s carrying value. Additionally, the fair value for all of the Company’s intangible assets with indefinite lives were substantially in excess of the respective asset carrying values.
In 2018, based on the annual impairment test, the calculated fair values with one exception. This intangible asset, which represents a trade name withinfor all of the Company’s Wellbore Technologies segment, had a calculated fairreporting units were substantially in excess of the respective reporting unit’s carrying value approximately $149 million below its carrying value. Impairment chargeswith the exception of the Company’s Floating Production Systems business unit. Further deterioration in the fourth quarter of 2015 were primarily the result of the substantial declineoffshore turret mooring systems and topside process modules market could lead to an impairment. This business unit has approximately $277 million in worldwide rig counts through the fourth quarter of 2015, declines in forecasts in rig activity, and a decline in the revenue forecast for the Company for 2016.goodwill.
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, 2015, 2014 and 2013.
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”).experience. 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, 20152018 and 2014,2017, service and product warranty accruals totaled $244$105 million and $272$135 million, respectively. Income Taxes The Company is U.S. registered 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 recorded 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 $8,187 million and $5,874$3,254 million at December 31, 2015 and 2014, respectively.2018. 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.result. Recently Issued and Recently Adopted Accounting Standards In November 2015, the FASB issued ASU 2015-17 “Balance Sheet ClassificationSee Note 2 – Summary of Deferred Taxes” (ASU No. 2015-17), which amends existing guidance on income taxes to require the classificationSignificant Accounting Policies (Part IV, Item 15 of all deferred tax assets and liabilities as non-current on the balance sheet. ASU No. 2015-17 is effectivethis Form 10-K) for fiscal years beginning after December 15, 2017, with early adoption permitted, and the guidance may be applied either prospectively or retrospectively. The Company does not expect the adoption of ASU No. 2015-17 will have a material effect on its consolidated financial position and results of operations. further discussion.In April 2015, the FASB issued an ASU 2015-03 “Simplifying the Presentation of Debt Issuance Costs” to simplify the presentation of debt issuance costs. The update requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts, as opposed to current presentation of an asset on the balance sheet. ASU No. 2015-03 is effective for fiscal years beginning after December 15, 2015, with early adoption permitted. The Company does not expect the adoption of ASU No. 2015-03 will have a material effect on its consolidated financial position and results of operations.
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, 2017, 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—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, 2015, 20142018, 2017 and 2013,2016, the Company reported foreign currency gains (losses)losses of ($47)$52 million, $20$3 million and ($24)$10 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. dollarCurrency fluctuations may create losses in future periods to the extent we maintain net assets and liabilities not denominated in the functional currency of our subsidiaries 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, 2015 (in millions except for rates):
| | | | | | | | | | | | | | | | | | | December 31, 2015 | | | December 31, | | Functional Currency | | 2016 | | | 2017 | | | Total | | | 2014 | | CAD Buy USD/Sell CAD: | | | | | | | | | | | | | | | | | Notional amount to buy (in Canadian dollars) | | | 10 | | | | — | | | | 10 | | | | 66 | | Average USD to CAD contract rate | | | 1.3759 | | | | — | | | | 1.3759 | | | | 1.1632 | | Fair Value at December 31, 2015 in U.S. dollars | | | — | | | | — | | | | — | | | | — | | Sell USD/Buy CAD: | | | | | | | | | | | | | | | | | Notional amount to sell (in Canadian dollars) | | | 136 | | | | — | | | | 136 | | | | 285 | | Average USD to CAD contract rate | | | 1.3554 | | | | — | | | | 1.3554 | | | | 1.1511 | | Fair Value at December 31, 2015 in U.S. dollars | | | (2 | ) | | | — | | | | (2 | ) | | | (3 | ) | EUR Buy USD/Sell EUR: | | | | | | | | | | | | | | | | | Notional amount to buy (in Euros) | | | 10 | | | | 1 | | | | 11 | | | | 4 | | Average USD to EUR contract rate | | | 0.8516 | | | | 0.8843 | | | | 0.8528 | | | | 0.7933 | | Fair Value at December 31, 2015 in U.S. dollars | | | 1 | | | | — | | | | 1 | | | | — | | Sell USD/Buy EUR: | | | | | | | | | | | | | | | | | Notional amount to buy (in Euros) | | | 198 | | | | 1 | | | | 199 | | | | 430 | | Average USD to EUR contract rate | | | 0.8954 | | | | 0.8771 | | | | 0.8953 | | | | 0.7832 | | Fair Value at December 31, 2015 in U.S. dollars | | | (5 | ) | | | — | | | | (5 | ) | | | (25 | ) | KRW Sell USD/Buy KRW: | | | | | | | | | | | | | | | | | Notional amount to buy (in South Korean won) | | | 23,613 | | | | — | | | | 23,613 | | | | 143,488 | | Average USD to KRW contract rate | | | 1,181 | | | | — | | | | 1,181 | | | | 1,104 | | Fair Value at December 31, 2015 in U.S. dollars | | | — | | | | — | | | | — | | | | — | | GBP Buy USD/Sell GBP: | | | | | | | | | | | | | | | | | Notional amount to buy (in British Pounds Sterling) | | | 2 | | | | — | | | | 2 | | | | — | | Average USD to GBP contract rate | | | 0.6416 | | | | — | | | | 0.6416 | | | | — | | Fair Value at December 31, 2015 in U.S. dollars | | | — | | | | — | | | | — | | | | — | | GBP Sell USD/Buy GBP: | | | | | | | | | | | | | | | | | Notional amount to buy (in British Pounds Sterling) | | | 170 | | | | — | | | | 170 | | | | 205 | | Average USD to GBP contract rate | | | 0.6613 | | | | — | | | | 0.6613 | | | | 0.6201 | | Fair Value at December 31, 2015 in U.S. dollars | | | (5 | ) | | | — | | | | (5 | ) | | | (6 | ) | USD Buy CAD/Sell USD: | | | | | | | | | | | | | | | | | Notional amount to buy (in U.S. dollars) | | | 7 | | | | — | | | | 7 | | | | 16 | | Average CAD to USD contract rate | | | 0.7635 | | | | — | | | | 0.7635 | | | | 0.9431 | | Fair Value at December 31, 2015 in U.S. dollars | | | — | | | | — | | | | — | | | | (1 | ) | Buy DKK/Sell USD: | | | | | | | | | | | | | | | | | Notional amount to buy (in U.S. dollars) | | | 24 | | | | — | | | | 24 | | | | 75 | | Average DKK to USD contract rate | | | 0.1553 | | | | — | | | | 0.1553 | | | | 0.1813 | | Fair Value at December 31, 2015 in U.S. dollars | | | (1 | ) | | | — | | | | (1 | ) | | | (6 | ) | Buy EUR/Sell USD: | | | | | | | | | | | | | | | | | Notional amount to buy (in U.S. dollars) | | | 278 | | | | — | | | | 278 | | | | 884 | | Average EUR to USD contract rate | | | 1.1925 | | | | — | | | | 1.1925 | | | | 1.3411 | | Fair Value at December 31, 2015 in U.S. dollars | | | (23 | ) | | | — | | | | (23 | ) | | | (77 | ) | Buy GBP/Sell USD: | | | | | | | | | | | | | | | | | Notional amount to buy (in U.S. dollars) | | | 20 | | | | — | | | | 20 | | | | 147 | | Average GBP to USD contract rate | | | 1.5568 | | | | — | | | | 1.5568 | | | | 1.5779 | | Fair Value at December 31, 2015 in U.S. dollars | | | (1 | ) | | | — | | | | (1 | ) | | | (3 | ) | Buy NOK/Sell USD: | | | | | | | | | | | | | | | | | Notional amount to buy (in U.S. dollars) | | | 1,216 | | | | 285 | | | | 1,501 | | | | 1,961 | | Average NOK to USD contract rate | | | 0.1380 | | | | 0.1252 | | | | 0.1353 | | | | 0.1642 | | Fair Value at December 31, 2015 in U.S. dollars | | | (214 | ) | | | (25 | ) | | | (239 | ) | | | (276 | ) |
| | | | | | | | | | | | | | | | | | | December 31, 2015 | | | December 31, | | Functional Currency | | 2016 | | | 2017 | | | Total | | | 2014 | | Buy SGD/Sell USD: | | | | | | | | | | | | | | | | | Notional amount to buy (in U.S. dollars) | | | 7 | | | | 5 | | | | 12 | | | | 36 | | Average SGD to USD contract rate | | | 0.7716 | | | | 0.7262 | | | | 0.7534 | | | | 0.7966 | | Fair Value at December 31, 2015 in U.S. dollars | | | (1 | ) | | | — | | | | (1 | ) | | | (1 | ) | Sell DKK/Buy USD: | | | | | | | | | | | | | | | | | Notional amount to buy (in U.S. dollars) | | | 8 | | | | — | | | | 8 | | | | 22 | | Average DKK to USD contract rate | | | 0.1510 | | | | — | | | | 0.1510 | | | | 1.3625 | | Fair Value at December 31, 2015 in U.S. dollars | | | — | | | | — | | | | — | | | | 1 | | Sell EUR/Buy USD: | | | | | | | | | | | | | | | | | Notional amount to sell (in U.S. dollars) | | | 89 | | | | — | | | | 89 | | | | 251 | | Average EUR to USD contract rate | | | 1.1075 | | | | — | | | | 1.1075 | | | | 1.3109 | | Fair Value at December 31, 2015 in U.S. dollars | | | 1 | | | | — | | | | 1 | | | | 7 | | Sell GBP/Buy USD: | | | | | | | | | | | | | | | | | Notional amount to sell (in U.S. dollars) | | | 3 | | | | — | | | | 3 | | | | — | | Average GBP to USD contract rate | | | 1.4961 | | | | — | | | | 1.4961 | | | | — | | Fair Value at December 31, 2015 in U.S. dollars | | | — | | | | — | | | | — | | | | — | | Sell NOK/Buy USD: | | | | | | | | | | | | | | | | | Notional amount to sell (in U.S. dollars) | | | 107 | | | | 3 | | | | 110 | | | | 348 | | Average NOK to USD contract rate | | | 0.1325 | | | | 0.1187 | | | | 0.1321 | | | | 0.1634 | | Fair Value at December 31, 2015 in U.S. dollars | | | 15 | | | | — | | | | 15 | | | | 44 | | Sell RUB/Buy USD: | | | | | | | | | | | | | | | | | Notional amount to sell (in U.S. dollars) | | | 30 | | | | — | | | | 30 | | | | — | | Average RUB to USD contract rate | | | 0.0139 | | | | — | | | | 0.0139 | | | | — | | Fair Value at December 31, 2015 in U.S. dollars | | | 1 | | | | — | | | | 1 | | | | — | | Sell SGD/Buy USD: | | | | | | | | | | | | | | | | | Notional amount to sell (in U.S. dollars) | | | 2 | | | | — | | | | 2 | | | | 2 | | Average SGD to USD contract rate | | | 0.7082 | | | | — | | | | 0.7082 | | | | 0.7678 | | Fair Value at December 31, 2015 in U.S. dollars | | | — | | | | — | | | | — | | | | — | | BRL Buy EUR/Sell BRL: | | | | | | | | | | | | | | | | | Notional amount to sell (in U.S. dollars) | | | 199 | | | | — | | | | 199 | | | | — | | Average EUR to BRL contract rate | | | 4.3679 | | | | — | | | | 4.3679 | | | | — | | Fair Value at December 31, 2015 in U.S. dollars | | | 1 | | | | — | | | | 1 | | | | — | | Sell EUR/Buy BRL: | | | | | | | | | | | | | | | | | Notional amount to sell (in U.S. dollars) | | | 427 | | | | — | | | | 427 | | | | — | | Average EUR to BRL contract rate | | | 4.6985 | | | | — | | | | 4.6985 | | | | — | | Fair Value at December 31, 2015 in U.S. dollars | | | 4 | | | | — | | | | 4 | | | | — | | DKK Sell DKK/Buy USD: | | | | | | | | | | | | | | | | | Notional amount to buy (in U.S. dollars) | | | 1,396 | | | | — | | | | 1,396 | | | | 59 | | Average DKK to USD contract rate | | | 6.5618 | | | | — | | | | 6.5618 | | | | 5.9300 | | Fair Value at December 31, 2015 in U.S. dollars | | | (8 | ) | | | — | | | | (8 | ) | | | — | | Other Currencies | | | | | | | | | | | | | | | | | Fair Value at December 31, 2015 in U.S. dollars | | | 2 | | | | — | | | | 2 | | | | — | | | | | | | | | | | | | | | | | | | Total Fair Value at December 31, 2015 in U.S. dollars | | | (235 | ) | | �� | (25 | ) | | | (260 | ) | | | (346 | ) | | | | | | | | | | | | | | | | | |
The Company had other financial market risk sensitive instruments denominated in foreign currencies for transactional exposures totaling $157$24 million and translation exposures totaling $323$157 million as of December 31, 2015,2018, 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 $10$2 million and the translational exposures financial market risk sensitive instruments could affect the future fair value by $32$16 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 quarters of 2015 and 2013, the Venezuelan government again officially devalued the Venezuelan bolivar against the U.S. dollar. As a result, the Company incurred approximately $9 million and $12 million in devaluation charges in the first quarter of 2015 and 2013, respectively. The reporting currency of all of the Company’s Venezuelan entities is the U.S. dollar. The Company’s remaining net investment in Venezuela, which is largely U.S. dollar, was $25 million at December 31, 2015.
During the fourth quarter of 2015, the Argentinian government officially devalued the Argentine peso against the U.S. dollar. As a result, the Company incurred approximately $7 million of devaluation charges in the fourth quarter of 2015. The reporting currency of all of the Company’s Argentinian entities is the Argentine peso.
Interest Rate Risk At December 31, 2015,2018, long term borrowings consisted of $500 million in 1.35% Senior Notes, $1,396$1,394 million in 2.60% Senior Notes and $1,096$1,088 million in 3.95% Senior Notes, $893 million ofno 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,CDOR, 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 EURIBORCDOR 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”.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, 20152018 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 6752 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 PART III
ITEM 10. | DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE |
Incorporated by reference to the definitive Proxy Statement for the 20162019 Annual Meeting of Stockholders. ITEM 11. | EXECUTIVE COMPENSATION |
Incorporated by reference to the definitive Proxy Statement for the 20162019 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 20162019 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, 2015,2018, 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 | | Number of securities to be issued upon exercise of warrants and rights (a) | | | Weighted-average exercise price of outstanding rights (b) | | | Number of securities remaining available for equity compensation plans (excluding securities reflected in column (a)) (c) (1) | | | (a) | | | (b) | | | (1) | | Equity compensation plans approved by security holders | | | 15,430,307 | | | $ | 60.30 | | | | 6,178,896 | | | | 21,009,508 | | | $ | 54.13 | | | | 17,705,830 | | Equity compensation plans not approved by security holders | | | — | | | | — | | | | — | | | | — | | | | — | | | | — | | | | | | | | | | | | | Total | | | 15,430,307 | | | $ | 60.30 | | | | 6,178,896 | | | | 21,009,508 | | | $ | 54.13 | | | | 17,705,830 | | | | | | | | | | | | |
(1) | Shares could be issued through equity instruments other than stock options, warrants or rights. |
ITEM 13. | CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE |
Incorporated by reference to the definitive Proxy Statement for the 20162019 Annual Meeting of Stockholders. ITEM 14. | PRINCIPAL ACCOUNTANTACCOUNTING FEES AND SERVICES |
Incorporated by reference to the definitive Proxy Statement for the 20162019 Annual Meeting of Stockholders.
PART IV ITEM 15. | EXHIBITS AND FINANCIAL STATEMENT SCHEDULES |
ITEM 15. | EXHIBITS ANDFINANCIAL STATEMENT SCHEDULES |
Financial Statements and Exhibits The following financial statements are presented in response to Part II, Item 8: (2) | Financial Statement Schedule | |
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. | | | 3.1 | | 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,June 27, 2017, among National Oilwell Varco, Inc., the financial institutions signatory thereto, including Wells Fargo Bank, N.A., in their capacitiesits capacity, among others, as Administrative Agent, Co-Lead Arranger and Joint Book Runner. (Exhibit 10.1) (3) | | | | 10.2 | | Amendment No. 2 to the Credit Agreement, dated as of September 28, 2012, among National Oilwell Varco, Inc., the financial institutions signatory thereto, including Wells Fargo Bank, N.A., as Administrative Agent, the other agents named therein, and the lenders parties thereto. (Exhibit 10.1) (4) | | | 10.3 | | National Oilwell Varco Long-Term Incentive Plan, as amended and restated. (5)(4)* | | | | 10.410.3 | | Form of Employee Stock Option Agreement. (Exhibit 10.1) (6)(5) | | | | 10.510.4 | | Form of Non-Employee Director Stock Option Agreement. (Exhibit 10.2) (6)(5) | | | | 10.610.5 | | Form of Performance-Based Restricted Stock. (18 Month) Agreement (Exhibit 10.1) (7)(6) | | | | 10.710.6 | | Form of Performance-Based Restricted Stock. (36 Month) Agreement (Exhibit 10.2) (7)(6) | | | | 10.810.7 | | Form of Performance Award Agreement (Exhibit 10.1) (8)(7) | | | | 10.910.8 | | Form of Executive Employment Agreement. (Exhibit 10.1) (9)(8) | | | | 10.1010.9 | | Form of Executive Severance Agreement. (Exhibit 10.2) (9)(8) | | | | 21.110.10 | | Form of Employee Nonqualified Stock Option Grant Agreement (9) | | | | 10.11 | | Form of Restricted Stock Agreement (9) | | | | 10.12 | | Form of Performance Award Agreement (9) | | | | 21.1 | | Subsidiaries of the Registrant.Registrant | | | | 23.1 | | Consent of Ernst & Young LLP. |
* | 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, 2011.11, 2017. |
(3) | Filed as an Exhibit to our Current Report on Form 8-K filed on October 1, 2012June 28, 2017 |
(4) | Filed as an Exhibit to our Current Report on Form 8-K filed on May 13, 2015. |
(5) | Filed as Appendix I to our Proxy Statement filed on April 10, 2013.March 30, 2018. |
(6)(5) | Filed as an Exhibit to our Current Report on Form 8-K filed on February 23, 2006. |
(7)(6) | Filed as an Exhibit to our Current Report on Form 8-K filed on March 27, 2007. |
(8)(7) | Filed as an Exhibit to our Current Report on Form 8-K filed on March 27, 2013. |
(9)(8) | Filed as an Exhibit to our Current Report on Form 8-K filed on November 24, 2014.21, 2017. |
(10)(9) | Filed as an Exhibit to our Current Report on Form 8-K filed on February 26, 2016. |
(10) | 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.
SIGNATURESSIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. | | | | | | | | | | NATIONAL OILWELL VARCO, INC. | | | | | | Dated: February 19, 201614, 2019 | | By: | By: | | | /s/ CLAY C. WILLIAMS | | | | | | | Clay C. Williams | | | | | | | Chairman, President and Chief Executive Officer |
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. Each person whose signature appears below in so signing, constitutes and appoints Clay C. Williams and Jose A. Bayardo, and each of them acting alone, his/her true and lawful attorney-in-fact and agent, with full power of substitution, for him/her and in his/her 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/her substitute or substitutes may do or cause to be done by virtue hereof. | | | | | Signature | | Title | | Date | | | | | | /s/ CLAY C. WILLIAMS Clay Clay C. Williams
| | Chairman, President and Chief Executive Officer | | February 19, 201614, 2019 | | | | | | /s/ JOSE A. BAYARDO Jose A. Bayardo | | Senior Vice President and Chief Financial Officer | | February 19, 201614, 2019 | | | | | | /s/ SCOTT K. DUFF Scott K. Duff | | Vice President, Corporate Controller and Chief Accounting Officer | | February 19, 201614, 2019 | | | | | | /s/ GREG L. ARMSTRONG | | Director | | February 14, 2019 | Greg L. Armstrong | | Director | | February 19, 2016 | | | | | | /s/ MARCELA E. DONADIO | | Director | | February 14, 2019 | Marcela E. Donadio | | Director | | February 19, 2016 | | | | | | /s/ BEN A. GUILL | | Director | | February 14, 2019 | Ben A. Guill | | Director | | February 19, 2016 | | | | | | /s/ JAMES T. HACKETT | | Director | | February 14, 2019 | James T. Hackett | | | | | /s/ DAVID D. HARRISON | | Director | | February 14, 2019 | David D. Harrison | | Director | | February 19, 2016 | | | | /s/ ROGER L. JARVIS
Roger L. Jarvis
| | Director | | February 19, 2016 | | | | /s/ ERIC L. MATTSON | | Director | | February 14, 2019 | Eric L. Mattson | | Director | | February 19, 2016 | | | | | | /s/ MELODY B. MEYER | | Director | | February 14, 2019 | Melody B. Meyer | | | | | | | | | | /s/ WILLIAM R. THOMAS | | Director | | February 14, 2019 | William R. Thomas | | Director | | February 19, 2016 |
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, 2015.2018. The effectiveness of our internal control over financial reporting as of December 31, 2015,2018, 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/ Jose A. Bayardo | | Jose A. Bayardo | | Senior Vice President and Chief Financial Officer | | Houston, Texas
| February 19, 2016
|
Houston, Texas February 14, 2019
REPORT OF INDEPENDENT REGISTEREDREGISTERED PUBLIC ACCOUNTING FIRM TheTo the Shareholders and Board of Directors and Shareholders
of National Oilwell Varco, Inc. Opinion on Internal Control over Financial Reporting We have audited National Oilwell Varco, Inc.’s internal control over financial reporting as of December 31, 2015,2018, 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). In our opinion, National Oilwell Varco, Inc’sInc. (the Company) maintained, in all material respects, effective internal control over financial reporting as of December 31, 2018, based on the COSO criteria. We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the 2018 consolidated financial statements of the Company and our report dated February 14, 2019, expressed an unqualified opinion thereon. Basis for Opinion The Company’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 Overover Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States).PCAOB. 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. Definition and Limitations of Internal Control over Financial Reporting 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,
/s/ Ernst & Young LLP Houston, Texas February 14, 2019
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM To the Shareholders and Board of Directors of National Oilwell Varco, Inc. maintained, in all material respects, effective internal control over financial reporting Opinion on the Financial Statements We have audited the accompanying consolidated balance sheets of National Oilwell Varco, Inc. (the Company) as of December 31, 2015, 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, 20152018 and 2014,2017, and the related consolidated statements of income (loss), comprehensive income (loss), stockholders’ equity and cash flows for each of the three years in the period ended December 31, 2015 of National Oilwell Varco, Inc., and our report dated February 19, 2016, expressed an unqualified opinion thereon.
/s/ ERNST & YOUNG LLP
Houston, Texas
February 19, 2016
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, 2015 and 2014,2018, and the related consolidated statements of income, comprehensive income, stockholders’ equitynotes and cash flows for each of the three years in the period ended December 31, 2015. Our audits also included the financial statement schedule listed in the indexIndex at itemItem 15(2) (collectively referred to as the “consolidated financial statements”). 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 consolidated financial statements referred to above present fairly, in all material respects, the consolidated financial position of National Oilwell Varco, Inc. as ofthe Company at December 31, 20152018 and 2014,2017, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2015,2018, 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) (PCAOB), National Oilwell Varco, Inc.’sthe Company’s internal control over financial reporting as of December 31, 2015,2018, 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 19, 2016,14, 2019, expressed an unqualified opinion thereon. Basis of Opinion These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion. /s/ ERNSTErnst & YOUNGYoung LLP We have served as the Company’s auditor since at least 1995, but we are unable to determine the specific year. Houston, Texas February 19, 201614, 2019
NATIONAL OILWELL VARCO, INC. CONSOLIDATED BALANCE SHEETS (In millions, except share data) | | | December 31, | | | December 31, | | | | 2015 | | 2014 | | | 2018 | | | 2017 | | ASSETS | | | | | | | | | | | | | Current assets: | | | | | | | | | | | | | Cash and cash equivalents | | $ | 2,080 | | | $ | 3,536 | | | $ | 1,427 | | | $ | 1,437 | | Receivables, net | | | 2,926 | | | 4,416 | | | | 2,101 | | | | 2,015 | | Inventories, net | | | 4,678 | | | 5,281 | | | | 2,986 | | | | 3,003 | | Costs in excess of billings | | | 1,250 | | | 1,878 | | | Deferred income taxes | | | 376 | | | 447 | | | Contract assets | | | | 565 | | | | 495 | | Prepaid and other current assets | | | 491 | | | 604 | | | | 200 | | | | 267 | | | | | | | | | | Total current assets | | | 11,801 | | | 16,162 | | | | 7,279 | | | | 7,217 | | | Property, plant and equipment, net | | | 3,124 | | | 3,362 | | | | 2,797 | | | | 3,002 | | Deferred income taxes | | | 488 | | | 503 | | | | 11 | | | | 13 | | Goodwill | | | 6,980 | | | 8,539 | | | | 6,264 | | | | 6,227 | | Intangibles, net | | | 3,849 | | | 4,444 | | | | 3,020 | | | | 3,301 | | Investment in unconsolidated affiliates | | | 327 | | | 362 | | | | 301 | | | | 309 | | Other assets | | | 156 | | | 190 | | | | 124 | | | | 137 | | | | | | | | | | Total assets | | $ | 26,725 | | | $ | 33,562 | | | $ | 19,796 | | | $ | 20,206 | | | | | | | | | | LIABILITIES AND STOCKHOLDERS’ EQUITY | | | | | | LIABILITIES AND STOCKHOLDERS' EQUITY | | | | | | | | | | Current liabilities: | | | | | | | | | | | | | Accounts payable | | $ | 623 | | | $ | 1,189 | | | $ | 722 | | | $ | 510 | | Accrued liabilities | | | 2,284 | | | 3,518 | | | | 1,088 | | | | 1,238 | | Billings in excess of costs | | | 785 | | | 1,775 | | | Contract liabilities | | | | 458 | | | | 519 | | Current portion of long-term debt and short-term borrowings | | | 2 | | | 152 | | | | 7 | | | | 6 | | Accrued income taxes | | | 264 | | | 431 | | | | 66 | | | | 81 | | Deferred income taxes | | | 291 | | | 309 | | | | | | | | | | | Total current liabilities | | | 4,249 | | | 7,374 | | | | 2,341 | | | | 2,354 | | | Long-term debt | | | 3,928 | | | 3,014 | | | | 2,704 | | | | 2,706 | | Deferred income taxes | | | 1,805 | | | 1,972 | | | | 564 | | | | 677 | | Other liabilities | | | 283 | | | 430 | | | | 298 | | | | 309 | | | | | | | | | | Total liabilities | | | 10,265 | | | 12,790 | | | | 5,907 | | | | 6,046 | | | | | | | | | | Commitments and contingencies | | | | | | | | | | | | | | Stockholders’ equity: | | | | | | | | | | | | | Common stock—par value $.01; 1 billion shares authorized; 375,764,794 and 418,977,608 shares issued and outstanding at December 31, 2015 and December 31, 2014 | | | 4 | | | 4 | | | Common stock - par value $.01; 1 billion shares authorized; 383,426,654 and 380,104,970 shares issued and outstanding at December 31, 2018 and December 31, 2017 | | | | 4 | | | | 4 | | Additional paid-in capital | | | 8,005 | | | 8,341 | | | | 8,390 | | | | 8,234 | | Accumulated other comprehensive loss | | | (1,553 | ) | | (834 | ) | | | (1,437 | ) | | | (1,110 | ) | Retained earnings | | | 9,927 | | | 13,181 | | | | 6,862 | | | | 6,966 | | | | | | | | | | Total Company stockholders’ equity | | | 16,383 | | | 20,692 | | | Total Company stockholders' equity | | | | 13,819 | | | | 14,094 | | Noncontrolling interests | | | 77 | | | 80 | | | | 70 | | | | 66 | | | | | | | | | | Total stockholders’ equity | | | 16,460 | | | 20,772 | | | | 13,889 | | | | 14,160 | | | | | | | | | | Total liabilities and stockholders’ equity | | $ | 26,725 | | | $ | 33,562 | | | $ | 19,796 | | | $ | 20,206 | | | | | | | | | |
The accompanying notes are an integral part of these statements.
NATIONAL OILWELL VARCO, INC. CONSOLIDATED STATEMENTS OF INCOME (LOSS) (In millions, except per share data) | | | | | | | | | | | | | | | Years Ended December 31, | | | | 2015 | | | 2014 | | | 2013 | | Revenue | | | | | | | | | | | | | Sales | | $ | 11,707 | | | $ | 17,173 | | | $ | 15,489 | | Services | | | 3,050 | | | | 4,267 | | | | 3,732 | | | | | | | | | | | | | | | Total | | | 14,757 | | | | 21,440 | | | | 19,221 | | | | | | | | | | | | | | | Cost of revenue | | | | | | | | | | | | | Cost of sales | | | 9,362 | | | | 12,407 | | | | 11,107 | | Cost of services | | | 2,332 | | | | 3,224 | | | | 3,010 | | | | | | | | | | | | | | | Total | | | 11,694 | | | | 15,631 | | | | 14,117 | | | | | | | | | | | | | | | Gross profit | | | 3,063 | | | | 5,809 | | | | 5,104 | | Selling, general and administrative | | | 1,764 | | | | 2,092 | | | | 1,905 | | Goodwill and intangible asset impairment | | | 1,689 | | | | 104 | | | | — | | | | | | | | | | | | | | | Operating profit (loss) | | | (390 | ) | | | 3,613 | | | | 3,199 | | | | | | Interest and financial costs | | | (103 | ) | | | (105 | ) | | | (111 | ) | Interest income | | | 14 | | | | 18 | | | | 12 | | Equity income in unconsolidated affiliates | | | 13 | | | | 58 | | | | 63 | | Other income (expense), net | | | (123 | ) | | | (90 | ) | | | (39 | ) | | | | | | | | | | | | | | Income (loss) from continuing operations before income taxes | | | (589 | ) | | | 3,494 | | | | 3,124 | | Provision for income taxes | | | 178 | | | | 1,039 | | | | 943 | | Income (loss) from continuing operations | | | (767 | ) | | | 2,455 | | | | 2,181 | | Income from discontinued operations | | | — | | | | 52 | | | | 147 | | | | | | | | | | | | | | | Net income (loss) | | | (767 | ) | | | 2,507 | | | | 2,328 | | Net income attributable to noncontrolling interests | | | 2 | | | | 5 | | | | 1 | | | | | | | | | | | | | | | Net income (loss) attributable to Company | | $ | (769 | ) | | $ | 2,502 | | | $ | 2,327 | | | | | | | | | | | | | | | Per share data: | | | | | | | | | | | | | Basic: | | | | | | | | | | | | | Income (loss) from continuing operations | | $ | (1.99 | ) | | $ | 5.73 | | | $ | 5.11 | | | | | | | | | | | | | | | Income from discontinued operations | | $ | — | | | $ | 0.12 | | | $ | 0.35 | | | | | | | | | | | | | | | Net income (loss) attributable to Company | | $ | (1.99 | ) | | $ | 5.85 | | | $ | 5.46 | | | | | | | | | | | | | | | Diluted: | | | | | | | | | | | | | Income (loss) from continuing operations | | $ | (1.99 | ) | | $ | 5.70 | | | $ | 5.09 | | | | | | | | | | | | | | | Income from discontinued operations | | $ | — | | | $ | 0.12 | | | $ | 0.35 | | | | | | | | | | | | | | | Net income (loss) attributable to Company | | $ | (1.99 | ) | | $ | 5.82 | | | $ | 5.44 | | | | | | | | | | | | | | | Cash dividends per share | | $ | 1.84 | | | $ | 1.64 | | | $ | 0.91 | | | | | | | | | | | | | | | Weighted average shares outstanding: | | | | | | | | | | | | | Basic | | | 387 | | | | 428 | | | | 426 | | | | | | | | | | | | | | | Diluted | | | 387 | | | | 430 | | | | 428 | | | | | | | | | | | | | | |
| | Years Ended December 31, | | | | 2018 | | | 2017 | | | 2016 | | Revenue | | | | | | | | | | | | | Sales | | $ | 5,699 | | | $ | 4,948 | | | $ | 5,351 | | Services | | | 1,612 | | | | 1,472 | | | | 1,296 | | Rental | | | 1,142 | | | | 884 | | | | 604 | | Total | | | 8,453 | | | | 7,304 | | | | 7,251 | | Cost of revenue | | | | | | | | | | | | | Sales | | | 4,883 | | | | 4,499 | | | | 5,671 | | Services | | | 1,257 | | | | 1,127 | | | | 835 | | Rental | | | 869 | | | | 786 | | | | 846 | | Total | | | 7,009 | | | | 6,412 | | | | 7,352 | | Gross profit (loss) | | | 1,444 | | | | 892 | | | | (101 | ) | Selling, general and administrative | | | 1,233 | | | | 1,169 | | | | 1,338 | | Goodwill and intangible asset impairment | | | — | | | | — | | | | 972 | | Operating profit (loss) | | | 211 | | | | (277 | ) | | | (2,411 | ) | Interest and financial costs | | | (93 | ) | | | (102 | ) | | | (105 | ) | Interest income | | | 25 | | | | 25 | | | | 15 | | Equity loss in unconsolidated affiliates | | | (3 | ) | | | (5 | ) | | | (21 | ) | Other expense, net | | | (99 | ) | | | (33 | ) | | | (101 | ) | Income (loss) before income taxes | | | 41 | | | | (392 | ) | | | (2,623 | ) | Provision (benefit) for income taxes | | | 63 | | | | (156 | ) | | | (207 | ) | Net loss | | | (22 | ) | | | (236 | ) | | | (2,416 | ) | Net income (loss) attributable to noncontrolling interests | | | 9 | | | | 1 | | | | (4 | ) | Net loss attributable to Company | | $ | (31 | ) | | $ | (237 | ) | | $ | (2,412 | ) | Net loss attributable to Company per share: | | | | | | | | | | | | | Basic | | $ | (0.08 | ) | | $ | (0.63 | ) | | $ | (6.41 | ) | Diluted | | $ | (0.08 | ) | | $ | (0.63 | ) | | $ | (6.41 | ) | Cash dividends per share | | $ | 0.20 | | | $ | 0.20 | | | $ | 0.61 | | Weighted average shares outstanding: | | | | | | | | | | | | | Basic | | | 378 | | | | 377 | | | | 376 | | Diluted | | | 378 | | | | 377 | | | | 376 | |
The accompanying notes are an integral part of these statements.
NATIONAL OILWELL VARCO, INC. CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (In millions) | | | | | | | | | | | | | | | Years Ended December 31, | | | | 2015 | | | 2014 | | | 2013 | | Net income (loss) | | $ | (767 | ) | | $ | 2,507 | | | $ | 2,328 | | | | | | Other comprehensive income (loss) (net of tax): | | | | | | | | | | | | | Currency translation adjustments | | | (764 | ) | | | (532 | ) | | | (115 | ) | Derivative financial instruments | | | 23 | | | | (233 | ) | | | (37 | ) | Change in defined benefit plans | | | 22 | | | | (65 | ) | | | 41 | | | | | | | | | | | | | | | Comprehensive income (loss) | | | (1,486 | ) | | | 1,677 | | | | 2,217 | | Net income attributable to noncontrolling interests | | | 2 | | | | 5 | | | | 1 | | | | | | | | | | | | | | | Comprehensive income (loss) attributable to Company | | $ | (1,488 | ) | | $ | 1,672 | | | $ | 2,216 | | | | | | | | | | | | | | |
| | Years Ended December 31, | | | | 2018 | | | 2017 | | | 2016 | | Net loss | | $ | (22 | ) | | $ | (236 | ) | | $ | (2,416 | ) | Other comprehensive income (loss): | | | | | | | | | | | | | Currency translation adjustments | | | (292 | ) | | | 272 | | | | (97 | ) | Derivative financial instruments, net of tax | | | (21 | ) | | | 46 | | | | 166 | | Change in defined benefit plans, net of tax | | | (14 | ) | | | 24 | | | | 32 | | Comprehensive income (loss) | | | (349 | ) | | | 106 | | | | (2,315 | ) | Net income (loss) attributable to noncontrolling interests | | | 9 | | | | 1 | | | | (4 | ) | Comprehensive income (loss) attributable to Company | | $ | (358 | ) | | $ | 105 | | | $ | (2,311 | ) |
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, | | | Years Ended December 31, | | | | 2015 | | 2014 | | 2013 | | | 2018 | | | 2017 | | | 2016 | | Cash flows from operating activities: | | | | | | | | | | | | Income (loss) from continuing operations | | $ | (767 | ) | | $ | 2,455 | | | $ | 2,181 | | | Adjustments to reconcile net income to net cash provided by operating activities: | | | | | | | | Net loss | | | $ | (22 | ) | | $ | (236 | ) | | $ | (2,416 | ) | Adjustments to reconcile net loss to net cash provided by operating activities: | | | | | | | | | | | | | | Depreciation and amortization | | | 747 | | | 778 | | | 738 | | | | 690 | | | | 698 | | | | 703 | | Deferred income taxes | | | (258 | ) | | (300 | ) | | (336 | ) | | | (63 | ) | | | (341 | ) | | | (198 | ) | Stock-based compensation | | | 109 | | | 101 | | | 92 | | | | 110 | | | | 124 | | | | 107 | | Excess tax benefit from stock-based compensation | | | 1 | | | (15 | ) | | (20 | ) | | | — | | | | — | | | | 7 | | Equity income in unconsolidated affiliates | | | (13 | ) | | (58 | ) | | (63 | ) | | Equity (income) loss in unconsolidated affiliates | | | | 3 | | | | 5 | | | | 21 | | Dividend from unconsolidated affiliate | | | 34 | | | 73 | | | 66 | | | | — | | | | — | | | | 6 | | Goodwill and intangible asset impairment | | | 1,689 | | | 104 | | | | — | | | | — | | | | — | | | | 972 | | Other | | | 256 | | | 181 | | | 72 | | | Provision for inventory losses | | | | 49 | | | | 114 | | | | 606 | | Other, net | | | | (7 | ) | | | 20 | | | | 108 | | Change in operating assets and liabilities, net of acquisitions: | | | | | | | | | | | | | | | | | | | Receivables | | | 1,091 | | | (153 | ) | | (516 | ) | | | (72 | ) | | | 72 | | | | 845 | | Inventories | | | 410 | | | (710 | ) | | 238 | | | | (7 | ) | | | 229 | | | | 782 | | Costs in excess of billings | | | 548 | | | (262 | ) | | (314 | ) | | Contract assets | | | | (68 | ) | | | 170 | | | | 646 | | Prepaid and other current assets | | | 112 | | | (60 | ) | | 41 | | | | 67 | | | | 130 | | | | 102 | | Accounts payable | | | (570 | ) | | 95 | | | 18 | | | | 196 | | | | 86 | | | | (243 | ) | Accrued liabilities | | | (1,137 | ) | | 879 | | | 76 | | | | (186 | ) | | | (130 | ) | | | (773 | ) | Billings in excess of costs | | | (686 | ) | | (59 | ) | | 582 | | | Contract liabilities | | | | (62 | ) | | | (160 | ) | | | (366 | ) | Income taxes payable | | | (167 | ) | | (124 | ) | | 217 | | | | (15 | ) | | | (44 | ) | | | (146 | ) | Other assets/liabilities, net | | | (67 | ) | | (400 | ) | | 8 | | | | (92 | ) | | | 95 | | | | 197 | | | | | | | | | | | | | Net cash provided by continuing operating activities | | | 1,332 | | | 2,525 | | | 3,080 | | | Discontinued operations | | | — | | | 89 | | | 317 | | | | | | | | | | | | | | Net cash provided by operating activities | | | 1,332 | | | 2,614 | | | 3,397 | | | | 521 | | | | 832 | | | | 960 | | | | | | | | | | | | | Cash flows from investing activities: | | | | | | | | | | | | | | | | | | | Purchases of property, plant and equipment | | | (453 | ) | | (699 | ) | | (614 | ) | | | (244 | ) | | | (192 | ) | | | (284 | ) | Business acquisitions, net of cash acquired | | | (86 | ) | | (291 | ) | | (2,397 | ) | | | (280 | ) | | | (86 | ) | | | (230 | ) | Cash distributed in spin-off | | | — | | | (253 | ) | | | — | | | Other, net | | | 25 | | | 151 | | | 101 | | | | 67 | | | | 33 | | | | 26 | | | | | | | | | | | | | Net cash used in continuing investing activities | | | (514 | ) | | (1,092 | ) | | (2,910 | ) | | Discontinued operations | | | — | | | (12 | ) | | (54 | ) | | | | | | | | | | | | | Net cash used in investing activities | | | (514 | ) | | (1,104 | ) | | (2,964 | ) | | | (457 | ) | | | (245 | ) | | | (488 | ) | | | | | | | | | | | | Cash flows from financing activities: | | | | | | | | | | | | | | | | | | | Borrowings against lines of credit and other debt | | | 11,377 | | | 173 | | | 2,609 | | | | — | | | | — | | | | 3,972 | | Payments against lines of credit and other debt | | | (10,615 | ) | | (155 | ) | | (2,609 | ) | | | (8 | ) | | | (506 | ) | | | (4,872 | ) | Cash dividends paid | | | (710 | ) | | (703 | ) | | (389 | ) | | | (76 | ) | | | (76 | ) | | | (230 | ) | Share repurchases | | | (2,221 | ) | | (779 | ) | | | — | | | Proceeds from stock options exercised | | | 7 | | | 108 | | | 58 | | | Activity under stock incentive plans | | | | 54 | | | | (3 | ) | | | 4 | | Excess tax benefit from stock-based compensation | | | (1 | ) | | 15 | | | 20 | | | | — | | | | — | | | | (7 | ) | Other | | | — | | | (2 | ) | | 7 | | | | — | | | | (10 | ) | | | (8 | ) | | | | | | | | | | | | Net cash used in continuing financing activities | | | (2,163 | ) | | (1,343 | ) | | (304 | ) | | Discontinued operations | | | — | | | | — | | | (1 | ) | | | | | | | | | | | | | Net cash used in financing activities | | | (2,163 | ) | | (1,343 | ) | | (305 | ) | | | (30 | ) | | | (595 | ) | | | (1,141 | ) | | | | | | | | | | | | Effect of exchange rates on cash | | | (111 | ) | | (67 | ) | | (11 | ) | | | (44 | ) | | | 37 | | | | (3 | ) | | | | | | | | | | | | Increase (decrease) in cash and cash equivalents | | | (1,456 | ) | | 100 | | | 117 | | | | (10 | ) | | | 29 | | | | (672 | ) | Cash and cash equivalents, beginning of period | | | 3,536 | | | 3,436 | | | 3,319 | | | | 1,437 | | | | 1,408 | | | | 2,080 | | | | | | | | | | | | | Cash and cash equivalents, end of period | | $ | 2,080 | | | $ | 3,536 | | | $ | 3,436 | | | $ | 1,427 | | | $ | 1,437 | | | $ | 1,408 | | | | | | | | | | | | | Supplemental disclosures of cash flow information: | | | | | | | | | | | | | | | | | | | Cash payments during the period for: | | | | | | | | | | | | | | | | | | | Interest | | $ | 103 | | | $ | 102 | | | $ | 111 | | | $ | 90 | | | $ | 97 | | | $ | 101 | | Income taxes | | $ | 782 | | | $ | 1,380 | | | $ | 1,099 | | | $ | 64 | | | $ | 50 | | | $ | 181 | |
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 (Loss) | | | Total Company Stockholders’ Equity | | | Noncontrolling Interests | | | Total Stockholders’ Equity | | 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 income (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 income (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 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Net loss | | | — | | | | — | | | | — | | | | — | | | | (769 | ) | | | (769 | ) | | | 2 | | | | (767 | ) | Other comprehensive income (loss), net | | | — | | | | — | | | | — | | | | (719 | ) | | | — | | | | (719 | ) | | | — | | | | (719 | ) | Cash dividends, $1.84 per common share | | | — | | | | — | | | | — | | | | — | | | | (710 | ) | | | (710 | ) | | | — | | | | (710 | ) | Dividends to noncontrolling interests | | | — | | | | — | | | | — | | | | — | | | | — | | | | — | | | | (8 | ) | | | (8 | ) | Noncontrolling interest contribution | | | — | | | | — | | | | — | | | | — | | | | — | | | | — | | | | 3 | | | | 3 | | Stock-based compensation | | | — | | | | — | | | | 109 | | | | — | | | | — | | | | 109 | | | | — | | | | 109 | | Common stock issued | | | 1 | | | | — | | | | 7 | | | | — | | | | — | | | | 7 | | | | — | | | | 7 | | Withholding taxes | | | — | | | | — | | | | (6 | ) | | | — | | | | — | | | | (6 | ) | | | — | | | | (6 | ) | Share repurchases | | | (44 | ) | | | — | | | | (446 | ) | | | — | | | | (1,775 | ) | | | (2,221 | ) | | | — | | | | (2,221 | ) | Excess tax benefit from stock-based compensation | | | — | | | | — | | | | — | | | | — | | | | — | | | | — | | | | — | | | | — | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Balance at December 31, 2015 | | | 376 | | | $ | 4 | | | $ | 8,005 | | | $ | (1,553 | ) | | $ | 9,927 | | | $ | 16,383 | | | $ | 77 | | | $ | 16,460 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Shares Outstanding | | | Common Stock | | | Additional Paid in Capital | | | Accumulated Other Comprehensive Income (Loss) | | | Retained Earnings (Loss) | | | Total Company Stockholders' Equity | | | Noncontrolling Interests | | | Total Stockholders' Equity | | Balance at December 31, 2015 | | | 376 | | | $ | 4 | | | $ | 8,005 | | | $ | (1,553 | ) | | $ | 9,927 | | | $ | 16,383 | | | $ | 77 | | | $ | 16,460 | | Net income (loss) | | | — | | | | — | | | | — | | | | — | | | | (2,412 | ) | | | (2,412 | ) | | | (4 | ) | | | (2,416 | ) | Other comprehensive income (loss), net | | | — | | | | — | | | | — | | | | 101 | | | | — | | | | 101 | | | | — | | | | 101 | | Cash dividends, $0.61 per common share | | | — | | | | — | | | | — | | | | — | | | | (230 | ) | | | (230 | ) | | | — | | | | (230 | ) | Noncontrolling interest | | | — | | | | — | | | | — | | | | — | | | | — | | | | — | | | | (10 | ) | | | (10 | ) | Stock-based compensation | | | — | | | | — | | | | 87 | | | | — | | | | — | | | | 87 | | | | — | | | | 87 | | Common stock issued | | | 2 | | | | — | | | | 4 | | | | — | | | | — | | | | 4 | | | | — | | | | 4 | | Stock issued in acquisition | | | 1 | | | | — | | | | 18 | | | | — | | | | — | | | | 18 | | | | — | | | | 18 | | Withholding taxes | | | — | | | | — | | | | (4 | ) | | | — | | | | — | | | | (4 | ) | | | — | | | | (4 | ) | Excess tax benefit from stock-based compensation | | | — | | | | — | | | | (7 | ) | | | — | | | | — | | | | (7 | ) | | | — | | | | (7 | ) | Balance at December 31, 2016 | | | 379 | | | $ | 4 | | | $ | 8,103 | | | $ | (1,452 | ) | | $ | 7,285 | | | $ | 13,940 | | | $ | 63 | | | $ | 14,003 | | Net income (loss) | | | — | | | | — | | | | — | | | | — | | | | (237 | ) | | | (237 | ) | | | 1 | | | | (236 | ) | Other comprehensive income (loss), net | | | — | | | | — | | | | — | | | | 342 | | | | — | | | | 342 | | | | — | | | | 342 | | Cash dividends, $0.20 per common share | | | — | | | | — | | | | — | | | | — | | | | (76 | ) | | | (76 | ) | | | — | | | | (76 | ) | Adoption of new accounting standards | | | — | | | | — | | | | 1 | | | | — | | | | (6 | ) | | | (5 | ) | | | — | | | | (5 | ) | Noncontrolling interest | | | — | | | | — | | | | — | | | | — | | | | — | | | | — | | | | 2 | | | | 2 | | Stock-based compensation on tender offer | | | — | | | | — | | | | 20 | | | | — | | | | — | | | | 20 | | | | — | | | | 20 | | Stock-based compensation | | | — | | | | — | | | | 105 | | | | — | | | | — | | | | 105 | | | | — | | | | 105 | | Common stock issued | | | 1 | | | | — | | | | 13 | | | | — | | | | — | | | | 13 | | | | — | | | | 13 | | Withholding taxes | | | — | | | | — | | | | (8 | ) | | | — | | | | — | | | | (8 | ) | | | — | | | | (8 | ) | Balance at December 31, 2017 | | | 380 | | | $ | 4 | | | $ | 8,234 | | | $ | (1,110 | ) | | $ | 6,966 | | | $ | 14,094 | | | $ | 66 | | | $ | 14,160 | | Net loss | | | — | | | | — | | | | — | | | | — | | | | (31 | ) | | | (31 | ) | | | 9 | | | | (22 | ) | Other comprehensive loss, net | | | — | | | | — | | | | — | | | | (327 | ) | | | — | | | | (327 | ) | | | — | | | | (327 | ) | Cash dividends, $0.20 per common share | | | — | | | | — | | | | — | | | | — | | | | (76 | ) | | | (76 | ) | | | — | | | | (76 | ) | Adoption of new accounting standards | | | — | | | | — | | | | — | | | | — | | | | 3 | | | | 3 | | | | — | | | | 3 | | Noncontrolling interest | | | — | | | | — | | | | — | | | | — | | | | — | | | | — | | | | (5 | ) | | | (5 | ) | Stock-based compensation on tender offer | | | — | | | | — | | | | — | | | | — | | | | — | | | | — | | | | — | | | | — | | Stock-based compensation | | | — | | | | — | | | | 110 | | | | — | | | | — | | | | 110 | | | | — | | | | 110 | | Common stock issued | | | 3 | | | | — | | | | 54 | | | | — | | | | — | | | | 54 | | | | — | | | | 54 | | Withholding taxes | | | — | | | | — | | | | (8 | ) | | | — | | | | — | | | | (8 | ) | | | — | | | | (8 | ) | Balance at December 31, 2018 | | | 383 | | | $ | 4 | | | $ | 8,390 | | | $ | (1,437 | ) | | $ | 6,862 | | | $ | 13,819 | | | $ | 70 | | | $ | 13,889 | |
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. Certain reclassifications have been made to the prior year financial statements in order for them to conform with the 2018 presentation. 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
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 marketestimated net realizable value using the first-in, first-out or average cost methods. AllowancesInventories consist of raw materials and supplies, work-in-process and finished goods and purchased products. The Company determines reserves for excess and obsolete inventories are determinedinventory based on our historical usage of inventory on-hand, assumptions about future demand and market conditions, and estimates about potential alternative uses, which are limited. The Company evaluates inventory quarterly using the best information available at the time to inform our assumptions and estimates about future demand and resulting sales volumes, and recognizes reserves as well asnecessary to properly state inventory.
Based on an update of our future expectationsassumptions at each point in time related to our installed base, the developmentestimates of new products and considerationfuture demand, we recorded charges for additions to inventory reserves of current market conditions. The allowance, which totaled $500$49 million, $114 million, and $370$606 million atfor the years ended December 31, 20152018, 2017, and 2014,2016, respectively, is the amount necessary to reduce the costconsisting primarily of theobsolete and surplus inventories. At December 31, 2018 and 2017, inventory to its estimated net realizable value.reserves totaled $644 million and $800 million, or 17.7% and 21.0% of gross inventory, respectively.
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, which includes the amortization of assets recorded under capital leases, was $391$349 million, $413$359 million and $381$370 million for the years ended December 31, 2015, 20142018, 2017 and 2013,2016, respectively. Accumulated depreciation of $2,687 million as of December 31, 2018 included accumulated depreciation of $30 million for capital leases. The estimated useful lives of the major classes of property, plant and equipment are included in Note 65 to the consolidated financial statements. 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 impairmentsImpairments of long-lived assets were $21 million, $10 million and $54 million for the years ended December 31, 2015, 20142018, 2017 and 2013.2016, respectively. Intangible AssetsAcquisitions and Investments
Acquisitions of businesses are accounted for using the acquisition method of accounting, and the financial statements include the results of the acquired operations from the respective dates of acquisition. The Company has approximately $7.0 billionpurchase price of goodwillthe acquired entities is preliminarily allocated to the net assets acquired and $3.8 billion of identified intangible assets at December 31, 2015. 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, 2013 | | $ | 1,279 | | | $ | 906 | | | $ | 4,425 | | | $ | 2,106 | | | $ | 333 | | | $ | 9,049 | | Goodwill acquired and adjusted during 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 | | Goodwill acquired and adjusted during period | | | — | | | | — | | | | 8 | | | | (8 | ) | | | — | | | | — | | Impairment | | | — | | | | — | | | | (1,485 | ) | | | — | | | | — | | | | (1,485 | ) | Currency translation adjustments and other | | | (4 | ) | | | — | | | | (6 | ) | | | (64 | ) | | | — | | | | (74 | ) | | | | | | | | | | | | | | | | | | | | | | | | | | Balance at December 31, 2015 | | $ | 1,232 | | | $ | 877 | | | $ | 2,874 | | | $ | 1,997 | | | $ | — | | | $ | 6,980 | | | | | | | | | | | | | | | | | | | | | | | | | | |
Identified intangible assets with determinable lives consist primarily of customer relationships, trademarks, trade names, patents, and technical drawings acquired in acquisitions, and are being amortizedliabilities assumed based 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 $384 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, 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 | | Additions to intangible assets | | | — | | | | — | | | | 2 | | | | 57 | | | | — | | | | 59 | | Asset impairment | | | (7 | ) | | | — | | | | (173 | ) | | | (24 | ) | | | — | | | | (204 | ) | Amortization | | | (22 | ) | | | (6 | ) | | | (214 | ) | | | (114 | ) | | | — | | | | (356 | ) | Currency translation adjustments and other | | | (3 | ) | | | (4 | ) | | | (27 | ) | | | (60 | ) | | | — | | | | (94 | ) | | | | | | | | | | | | | | | | | | | | | | | | | | Balance at December 31, 2015 | | $ | 176 | | | $ | 123 | | | $ | 2,254 | | | $ | 1,296 | | | $ | — | | | $ | 3,849 | | | | | | | | | | | | | | | | | | | | | | | | | | |
Identified intangible assets by major classification consist of the following (in millions):
| | | | | | | | | | | | | | | Gross | | | Accumulated Amortization | | | Net Book Value | | 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 | | | | | | | | | | | | | | | December 31, 2015: | | | | | | | | | | | | | Customer relationships | | $ | 4,016 | | | $ | (1,630 | ) | | $ | 2,386 | | Trademarks | | | 880 | | | | (265 | ) | | | 615 | | Indefinite-lived trade names | | | 384 | | | | — | | | | 384 | | Other | | | 1,040 | | | | (576 | ) | | | 464 | | | | | | | | | | | | | | | Total identified intangibles | | $ | 6,320 | | | $ | (2,471 | ) | | $ | 3,849 | | | | | | | | | | | | | | |
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 sustained reduction in worldwide oil and gas prices or drilling; a significant sustained reduction in profitability or cash flow of oil and
gas companies or drilling contractors; a significant sustained reduction in capital investment by drilling companies and oil and gas companies; or a significant sustained increase in worldwide inventories of oil or gas.
The discounted cash flow is based on management’s 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 costat the dates 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.
During the fourth quarter of 2015, the worldwide average rig count was 2,034 rigs, down 7% from the third quarter 2015 average of 2,188 and down 44% from the fourth quarter 2014 average of 3,632. The fourth quarter 2015 average rig count represented the lowest quarterly average in the past six years. The annual impairment test, as described in ASC Topic 350, “Intangibles—Goodwill and Other” (“ASC Topic 350”), is performed as of October 1 of each year.
Based on the Company’s annual impairment test performed in the fourth quarter of 2015, the calculated fair values for all of the Company’s reporting units were inacquisition, with any excess of the respective reporting unit’s carrying value, with two exceptions. Two reporting units within the Company’s Wellbore Technologies segment, had a calculated fair value below carrying value, and were required to perform step two resulting in a $1,485 million write-down in goodwill.
The implied fair value of goodwill is determined by deductingcost over the fair value of net assets acquired, including intangibles, recognized as goodwill. Subsequent changes to preliminary amounts are made prospectively.
The Company paid cash of $280 million, $86 million and $230 million for acquisitions for the years ended December 31, 2018, 2017 and 2016, respectively. These acquisitions did not have 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 discounted cash flow. Other indefinite-lived intangible assets, representing trade names management intends to use indefinitely, were valued using significant unobservable inputs (level 3) and are tested for impairment using the Relief from Royalty Method, a form of the Income Approach. An impairment is measured and recognized based on the amount the book value of the indefinite-lived intangible assets exceeds its estimated fair value as of the date of the impairment test. Included in the impairment test are assumptions, for each trade name, regarding the related revenue streams attributable to the trade names, which are determined in a manner consistent with the forecasting process described above, the royalty rate, and the discount rate applied.
Basedmaterial effect on the Company’s annual indefinite-lived intangible asset impairment analysis performed duringoperating results, cash flows or financial position
Foreign Currency Certain foreign operations, including our operations in Norway, use the fourth quarter of 2015,U.S. dollar as the fair value for all of the Company’s intangible assets with indefinite lives were in excess of the respective asset carrying values, with one exception. This intangible asset, which represents a trade name within the Company’s Wellbore Technologies segment, had a calculated fair value approximately $149 million below its carrying value. In addition, during the third quarter of 2015, the Company incurred $55 million in impairment charges on identified intangible assets with finite lives that were impaired and written off.
These impairment charges were primarily the result of the substantial decline in oil prices and worldwide rig counts continuing in the fourth quarter of 2015, declines in forecasts in rig activity, and a decline in the revenue forecast for the Company for 2016.
Foreign Currency
functional 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)losses were ($47)$52 million, $20$3 million and ($24)$10 million for the years ending December 31, 2015, 20142018, 2017 and 2013,2016, respectively, and are included in other income (expense) in the accompanying statement of income. Historically, the Venezuelan government has devalued the country’s currency. During the first quarters of 2015 and 2013, the Venezuelan government again officially devalued the Venezuelan bolivar against the U.S. dollar. As a result, the Company incurred approximately $9 million and $12 million in devaluation charges in the first quarter of 2015 and 2013, respectively. Revenue Recognition
The reporting currency of allmajority of the Company’s Venezuelan entities is the U.S. dollar. The Company’s net remaining investmentrevenue streams record revenue at a point in Venezuela, which is largely U.S. dollar, was $25 million at December 31, 2015. During the fourth quartertime when a performance obligation has been satisfied by transferring control of 2015, the Argentinian government officially devalued the Argentine peso against the U.S. dollar. Aspromised goods or services to a result, the Company incurred approximately $7 million devaluation charges in the fourth quarter of 2015. The reporting currency of all of the Company’s Argentinian entities is the Argentine peso.
Revenue Recognition
The Company’s productscustomer. Products and services are sold or rented based upon purchase orders or contracts with the customer that includea fixed or determinable pricesprice and that do not generally include right of return or other similar provisionssignificant post-delivery obligations. Revenue is recognized net of any taxes collected from customers, which are subsequently remitted to governmental authorities. Payment terms and conditions vary by contract type. We have elected to apply the practical expedient that does not require an adjustment for a financing component if, at contract inception, the period between when we transfer the promised goods 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 passedservice 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 customer pays for the
goods or service is one year or less. Shipping and handling costs are recognized when incurred and are treated as costs to fulfill the original performance obligation instead of as a separate performance obligation. Revenue is often generated from contracts that include multiple performance obligations. Using significant judgement, the Company has completed allconsiders the degree of itscustomization, integration and interdependency of the related products and services when assessing distinct performance obligations relatedwithin one contract. Stand-alone selling price (“SSP”) for each distinct performance obligation is generally determined using the price at which the products and services would be sold separately to the sale. Thecustomer. Discounts, when provided, are allocated based on the relative SSP of the various products and services. For revenue that is not recognized at a point in time, the Company also recognizesfollows accounting guidance for revenue recognized over time, 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.follows: Revenue Recognition under Long-term Construction Contracts The Company uses the percentage-of-completion method to accountRevenue is recognized over-time for certain long-term construction contracts in the Rig Systems and Completion & Production Solutions and Rig Technologies segments. These long-term construction contracts include the following characteristics:
the contracts include custom designs for customer-specific applications that are unique and require significant engineering efforts. Revenue is recognized as work progresses on each contract. Right to payment is enforceable for performance completed to date, including a reasonable profit.Because of control transferring over time, revenue is recognized based on the extent of progress towards completion of the performance obligation. We generally use the cost-to-cost (input) measure of progress for our contracts because it best depicts the transfer of assets to the customer specific applications; which occurs as we incur costs. Under the structural designcost-to-cost measure of progress, progress towards completion of each contract is uniquemeasured based on the ratio of costs incurred to date to the total estimated costs at completion of the performance obligation. Revenues, including estimated fees or profits, are recorded proportionally as costs are incurred. These costs include labor, materials, subcontractors’ costs, and other direct costs. Any expected losses on a project are recorded in full in the period in which the loss becomes probable.These long-term construction contracts generally include a significant service of integrating a complex set of tasks and components into a single project or capability, so are accounted for as one performance obligation. Estimating total revenue and cost at completion of long-term construction contracts is complex, subject to many variables and requires significant engineering efforts;judgment. It is common for our long-term contracts to contain late delivery fees, work performance guarantees, and other provisions that can either increase or decrease the transaction price. We estimate variable consideration as the most likely amount we expect to receive. We include variable consideration in the estimated transaction price to the extent it is probable that a significant reversal of cumulative revenue recognized will not occur, or when the uncertainty associated with the variable consideration is resolved. Our estimates of variable consideration and determination of whether to include estimated amounts in the transaction price are based on an assessment of our anticipated performance and historical, current and forecasted information that is reasonably available to us. Net revenue recognized from performance obligations satisfied in previous periods was $65 million for the year ended December 31, 2018 primarily due to change orders. Service and Repair Work For service and repair contracts, revenue is recognized over time. We generally use the output method to measure progress on service contracts due to the manner in which the customer receives and derives value from the services provided. For repair contracts, we generally use the cost-to-cost measure of progress because it best depicts the transfer of assets to the customer. Remaining Performance Obligations Remaining performance obligations represent the transaction price of firm orders for all revenue streams for which work has not been performed on contracts with an original expected duration of one year or more. We do not disclose the remaining performance obligations of royalty contracts, service contracts for which there is a right to invoice, and short-term contracts that are expected to have a duration of one year or less. As of December 31, 2018, the aggregate amount of the transaction price allocated to remaining performance obligations was $1,813 million. The Company expects to recognize approximately $887 million in revenue for the
remaining performance obligations in 2019 and $926 million in 2020 and thereafter. construction projects often have progress payments.
This method requiresCosts to Obtain and Fulfill a Contract
We recognize an asset for the Company to make estimates regarding the totalincremental costs of obtaining a contract, such as sales commissions, with a customer when we expect the project, progress againstbenefit of those costs to be longer than one year. Costs to fulfill a contract, such as set-up and mobilization costs, are also capitalized when we expect to recover those costs. These contract costs are deferred and amortized over the project scheduleperiod of contract performance. Total capitalized costs to obtain and fulfill a contract and the estimated completion date, all of which impactrelated amortization were immaterial during the amount of revenueperiods presented and gross margin the Company recognizesare included 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.long-term assets on our consolidated balance sheets. We apply the practical expedient to expense costs as incurred for costs to obtain a contract with a customer when the amortization period would have been one year or less.
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”).experience. 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, 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 | | | | | | | Net provisions for warranties issued during the year | | | 92 | | Amounts incurred | | | (117 | ) | Currency translation adjustments and other | | | (3 | ) | | | | | | Balance at December 31, 2015 | | $ | 244 | | | | | | |
Balance at December 31, 2016 | | $ | 172 | | Net provisions for warranties issued during the year | | | 46 | | Amounts incurred | | | (86 | ) | Currency translation adjustments | | | 3 | | Balance at December 31, 2017 | | $ | 135 | | Net provisions for warranties issued during the year | | | 38 | | Amounts incurred | | | (67 | ) | Currency translation adjustments | | | (1 | ) | Balance at December 31, 2018 | | $ | 105 | |
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 $159$161 million and $125$187 million at December 31, 20152018 and 2014.2017, respectively.
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 themethod. 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. 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,over time, 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 IncomeLoss 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, | | | | 2015 | | | 2014 | | | 2013 | | Numerator: | | | | | | | | | | | | | Income (loss) from continuing operations | | $ | (769 | ) | | $ | 2,450 | | | $ | 2,180 | | | | | | | | | | | | | | | Income from discontinued operations | | $ | — | | | $ | 52 | | | $ | 147 | | | | | | | | | | | | | | | Net income (loss) attributable to Company | | $ | (769 | ) | | $ | 2,502 | | | $ | 2,327 | | | | | | | | | | | | | | | Denominator: | | | | | | | | | | | | | Basic—weighted average common shares outstanding | | | 387 | | | | 428 | | | | 426 | | Dilutive effect of employee stock options and other unvested stock awards | | | — | | | | 2 | | | | 2 | | | | | | | | | | | | | | | Diluted outstanding shares | | | 387 | | | | 430 | | | | 428 | | | | | | | | | | | | | | | Per share data: | | | | | | | | | | | | | Basic: | | | | | | | | | | | | | Income (loss) from continuing operations | | $ | (1.99 | ) | | $ | 5.73 | | | $ | 5.11 | | | | | | | | | | | | | | | Income from discontinued operations | | $ | — | | | $ | 0.12 | | | $ | 0.35 | | | | | | | | | | | | | | | Net income (loss) attributable to Company | | $ | (1.99 | ) | | $ | 5.85 | | | $ | 5.46 | | | | | | | | | | | | | | | Diluted: | | | | | | | | | | | | | Income (loss) from continuing operations | | $ | (1.99 | ) | | $ | 5.70 | | | $ | 5.09 | | | | | | | | | | | | | | | Income from discontinued operations | | $ | — | | | $ | 0.12 | | | $ | 0.35 | | | | | | | | | | | | | | | Net income (loss) attributable to Company | | $ | (1.99 | ) | | $ | 5.82 | | | $ | 5.44 | | | | | | | | | | | | | | | Cash dividends per share | | $ | 1.84 | | | $ | 1.64 | | | $ | 0.91 | | | | | | | | | | | | | | |
| | Years Ended December 31, | | | | 2018 | | | 2017 | | | 2016 | | Numerator: | | | | | | | | | | | | | Net loss attributable to Company | | $ | (31 | ) | | $ | (237 | ) | | $ | (2,412 | ) | Denominator: | | | | | | | | | | | | | Basic—weighted average common shares outstanding | | | 378 | | | | 377 | | | | 376 | | Dilutive effect of employee stock options and other unvested stock awards | | | — | | | | — | | | | — | | Diluted outstanding shares | | | 378 | | | | 377 | | | | 376 | | Basic loss attributable to Company per share | | $ | (0.08 | ) | | $ | (0.63 | ) | | $ | (6.41 | ) | Diluted loss attributable to Company per share | | $ | (0.08 | ) | | $ | (0.63 | ) | | $ | (6.41 | ) | Cash dividends per share | | $ | 0.20 | | | $ | 0.20 | | | $ | 0.61 | |
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 incomeloss attributable to Company allocated to these participating securities was immaterial for the years ended December 31, 2015, 20142018, 2017 and 20132016 and therefore not excluded from net incomeloss attributable to Company per share calculation. The Company had stock options outstanding that were anti-dilutive totaling 1320 million, 812 million, and 714 million at December 31, 2015, 20142018, 2017 and 2013,2016, respectively. Recently IssuedAdopted Accounting Standards In November 2015, the FASB issued ASU 2015-17 “Balance Sheet Classification of Deferred Taxes” (ASU No. 2015-17), which amends existing guidance on income taxes to require the classification of all deferred tax assets and liabilities as non-current on the balance sheet. ASU No. 2015-17 is effective for fiscal years beginning after December 15,March 2017, with early adoption permitted, and the guidance may be applied either prospectively or retrospectively. The Company does not expect the adoption of ASU No. 2015-17 will have a material effect on its consolidated financial position and results of operations. In April 2015, the FASB issued an ASU 2015-03 “Simplifying the Presentation of Debt Issuance Costs” to simplify the presentation of debt issuance costs. The update requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that
debt liability, consistent with debt discounts, as opposed to current presentation of an asset on the balance sheet. ASU No. 2015-03 is effective for fiscal years beginning after December 15, 2015, with early adoption permitted. The Company does not expect the adoption of ASU No. 2015-03 will have a material effect on its consolidated financial position and results of operations.
In May 2014, the FASB issued Accounting Standard Update No. 2014-09 “Revenue2017-07 “Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost” (ASU 2017-07). This update requires that an employer report the service cost component in the same line item as other compensation costs and separately from Contractsother components of net benefit cost. ASU 2017-07 is effective for fiscal periods beginning after December 15, 2017, and for interim periods within those fiscal years. The Company adopted this update on January 1, 2018 with Customers”no material impact.
In August 2016, the FASB issued Accounting Standard Update No. 2016-15 “Classification of Certain Cash Receipts and Cash Payments” (ASU No. 2014-09), which supersedes the revenue recognition requirements in2016-15). This update amends Accounting Standard Codification Topic No. 605 “Revenue Recognition”230 “Statement of Cash Flows” and most industry-specific guidance. This update requires that entities recognize revenue to depict the transferprovides guidance and clarification on presentation 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.certain cash flow issues. ASU No. 2014-092016-15 is effective for fiscal years beginning after December 15, 2017, and for interim periods within those fiscal years. The Company adopted this update on January 1, 2018 with no material impact. In May 2014, the FASB issued Accounting Standard Update No. 2014-09, “Revenue from Contracts with Customers” (ASU 2014-09), which supersedes the revenue recognition requirements in FASB ASC Topic 605, “Revenue Recognition,” and most industry-specific guidance. This ASU proscribes a five-step model for determining when and how revenue is currently assessingrecognized. Under the model, an entity will recognize revenue to depict the transfer of goods or services to a customer at an amount reflecting the consideration it expects to receive in exchange for those goods or services. ASU 2014-09 is effective for fiscal periods beginning after December 15, 2017. The Company adopted this update on January 1, 2018, using the modified retrospective approach, in which an immaterial cumulative effect adjustment was made to retained earnings. The adoption of ASU 2014-09 did not have a material impact on the Company’s consolidated financial position, results of operations, equity or cash flows as of the adoption date or for the year ended December 31, 2018. Recently Issued Accounting Standards In August 2017, the FASB issued Accounting Standard Update No. 2017-12 “Derivatives and Hedging – Targeted Improvements to Accounting for Hedging Activities” (ASU 2017-12). This update improves the financial reporting of hedging relationships and simplifies the application of the hedge accounting guidance. ASU 2017-12 is effective for fiscal periods beginning after December 15, 2018, and for interim periods within those fiscal years. Early adoption
is permitted in any interim period after issuance of ASU 2017-12. The Company will adopt ASU No. 2014-092017-12 effective January 1, 2019 with an immaterial effect on its consolidated financial position and results of operations. In February 2016, the FASB issued ASC Topic 842, “Leases” (ASC Topic 842), which supersedes the lease requirements in ASC Topic No. 840 “Leases” and most industry-specific guidance. This update increases transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. ASC Topic 842 is effective for fiscal years beginning after December 15, 2018, and for interim periods within those fiscal years. The Company’s internal team, assisted by an accounting and consulting firm, has implemented and is testing new software, processes, procedures and controls to correctly account for leases under the new requirements. We currently estimate implementing ASC Topic 842 in the first quarter of 2019 will gross-up the Company’s balance sheet with additional assets and liabilities in the range of approximately $500 to $650 million. Implementing the new standard will not affect the Company’s compliance with the debt-to-capitalization covenant of our $3 billion revolving credit facility (see Note 8) because that agreement grandfathers the prior treatment of operating leases for purposes of the calculation. 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, 2015,2018, the Company has determined that the fair value of its derivative financial instruments representing assets of $26$6 million and liabilities of $286$36 million (primarily currency(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, 2015,2018, the net fair value of the Company’s foreign currency forward contracts totaled a net liability of $260$30 million. At December 31, 2015,2018, 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 (Loss) 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 (Loss) during the current period. 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 | | | Currency Denomination | | Foreign Currency | | December 31, 2015 | | | December 31, 2014 | | | December 31, 2018 | | | December 31, 2017 | | Norwegian Krone | | NOK | | | 9,655 | | | NOK | | | 10,781 | | | NOK | | | 4,118 | | | NOK | | | 4,013 | | Japanese Yen | | | JPY | | | 121 | | | JPY | | | 982 | | U.S. Dollar | | USD | | | 321 | | | USD | | | 231 | | | USD | | | 96 | | | USD | | | 163 | | Euro | | EUR | | | 78 | | | EUR | | | 462 | | | EUR | | | 71 | | | EUR | | | 120 | | Danish Krone | | DKK | | | 57 | | | DKK | | | 227 | | | DKK | | | 14 | | | DKK | | | 30 | | Singapore Dollar | | SGD | | | 14 | | | SGD | | | 44 | | | British Pound Sterling | | GBP | | | 4 | | | GBP | | | 80 | | | GBP | | | 9 | | | GBP | | | 11 | | Canadian Dollar | | CAD | | | 2 | | | CAD | | | 14 | | |
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 Consolidated Statement of Income (Loss). The Company had the following outstanding foreign currency forward contracts that hedge the fair value of nonfunctional currency monetary accounts (in millions): | | | Currency Denomination | | | Currency Denomination | | Foreign Currency | | December 31, 2015 | | | December 31, 2014 | | | December 31, 2018 | | | December 31, 2017 | | Norwegian Krone | | NOK | | | 2,265 | | | NOK | | | 4,052 | | | NOK | | | 1,111 | | | NOK | | | 1,734 | | Russian Ruble | | RUB | | | 2,164 | | | RUB | | | — | | | U.S. Dollar | | USD | | | 515 | | | USD | | | 1,092 | | | USD | | | 535 | | | USD | | | 463 | | Mexican Peso | | | MXN | | | 204 | | | MXN | | | — | | South African Rand | | | ZAR | | | 124 | | | ZAR | | | 150 | | Euro | | EUR | | | 371 | | | EUR | | | 401 | | | EUR | | | 101 | | | EUR | | | 99 | | Danish Krone | | DKK | | | 153 | | | DKK | | | 322 | | | DKK | | | 21 | | | DKK | | | 15 | | British Pound Sterling | | GBP | | | 11 | | | GBP | | | 19 | | | GBP | | | 3 | | | GBP | | | 3 | | Canadian Dollar | | CAD | | | 7 | | | CAD | | | 4 | | | Singapore Dollar | | SGD | | | 5 | | | SGD | | | 4 | | | Mexican Peso | | MXN | | | — | | | MXN | | | 118 | | | Brazilian Real | | BRL | | | — | | | BRL | | | 57 | | | Swedish Krone | | SEK | | | — | | | SEK | | | 3 | | | Russian Ruble | | | RUB | | | — | | | RUB | | | 2,699 | |
The Company has the following fair values of its derivative instruments and their balance sheet classifications (in millions): Fair Values of Derivative Instruments
(In millions)
| | | | | | | | | | | | | | | | | | | | | | | Asset Derivatives | | | Liability Derivatives | | | | Balance Sheet Location | | Fair Value December 31, | | | Balance Sheet Location | | Fair Value December 31, | | | | | | | | | | 2015 | | | 2014 | | | | 2015 | | | 2014 | | Derivatives designated as hedging instruments under ASC Topic 815 | | | | | | | | | | | | | | | | | | | | | Foreign exchange contracts | | Prepaid and other current assets | | $ | 5 | | | $ | 18 | | | Accrued liabilities | | $ | 212 | | | $ | 204 | | Foreign exchange contracts | | Other Assets | | | — | | | | 8 | | | Other Liabilities | | | 25 | | | | 102 | | | | | | | | | | | | | | | | | | | | | | | Total derivatives designated as hedging instruments under ASC Topic 815 | | | | $ | 5 | | | $ | 26 | | | | | $ | 237 | | | $ | 306 | | | | | | | | | | | | | | | | | | | | | | | Derivatives not designated as hedging instruments under ASC Topic 815 | | | | | | | | | | | | | | | | | | | | | Foreign exchange contracts | | Prepaid and other current assets | | $ | 21 | | | $ | 27 | | | Accrued liabilities | | $ | 49 | | | $ | 93 | | | | | | | | | | | | | | | | | | | | | | | Total derivatives not designated as hedging instruments under ASC Topic 815 | | | | $ | 21 | | | $ | 27 | | | | | $ | 49 | | | $ | 93 | | | | | | | | | | | | | | | | | | | | | | | Total derivatives | | | | $ | 26 | | | $ | 53 | | | | | $ | 286 | | | $ | 399 | | | | | | | | | | | | | | | | | | | | | | |
The Effect of Derivative Instruments on the Consolidated Statements of Income (Loss)
($ in millions)
| | Fair Values of Derivative Instruments (In millions) | | | | | | | | | | | | | | Asset Derivatives | | | Liability Derivatives | | | | | | Fair Value | | | | | Fair Value | | | | Balance Sheet | | December 31, | | | Balance Sheet | | December 31, | | | | Location | | 2018 | | | 2017 | | | Location | | 2018 | | | 2017 | | Derivatives designated as hedging instruments under ASC Topic 815 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Foreign exchange contracts | | Prepaid and other current assets | | $ | 2 | | | $ | 13 | | | Accrued liabilities | | $ | 17 | | | $ | 3 | | Foreign exchange contracts | | Other Assets | | | — | | | | 8 | | | Other Liabilities | | | 11 | | | | 2 | | Total derivatives designated as hedging instruments under ASC Topic 815 | | | | $ | 2 | | | $ | 21 | | | | | $ | 28 | | | $ | 5 | | Derivatives not designated as hedging instruments under ASC Topic 815 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Foreign exchange contracts | | Prepaid and other current assets | | $ | 4 | | | $ | 10 | | | Accrued liabilities | | $ | 6 | | | $ | 5 | | Foreign exchange contracts | | Other Assets | | | — | | | | 2 | | | Other Liabilities | | | 2 | | | | 1 | | Total derivatives not designated as hedging instruments under ASC Topic 815 | | | | $ | 4 | | | $ | 12 | | | | | $ | 8 | | | $ | 6 | | Total derivatives | | | | $ | 6 | | | $ | 33 | | | | | $ | 36 | | | $ | 11 | |
The Effect of Derivative Instruments on the Consolidated Statements of Income (Loss) ($ in millions) | | The Effect of Derivative Instruments on the Consolidated Statements of Income (Loss) ($ in millions) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Location of Gain (Loss) | | | | | 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) | | | | | | | | | | | | | | | | | | Recognized in Income on | | Amount of Gain (Loss) | | | | | | | | Location of Gain (Loss) | | | | | | Derivatives (Ineffective | | Recognized in Income on | | | | | | | | Reclassified from | | Amount of Gain (Loss) | | Portion and Amount | | Derivatives (Ineffective | Derivatives Designated as | | | Amount of Gain (Loss) | | Accumulated OCI into | | Reclassified from | | Excluded from | | Portion and Amount | Hedging Instruments under | | | Recognized in OCI on | | Income | | Accumulated OCI into | | Effectiveness | | Excluded from | ASC Topic 815 | | | Derivatives (Effective Portion) (a) | | (Effective Portion) | | Income (Effective Portion) | | Testing) | | Effectiveness Testing) (b) | | | Years Ended December 31, | | | | Years Ended December 31, | | Years Ended December 31, | | | Years Ended December 31, | | | | | | Years Ended December 31, | | | | Years Ended December 31, | | | 2015 | | 2014 | | | | 2015 | | 2014 | | 2015 | | 2014 | | | 2018 | | 2017 | | | | | | 2018 | | 2017 | | | | 2018 | | 2017 | | | | | | | | Revenue | | | 19 | | | 26 | | | Cost of revenue | | (33 | ) | | (1 | ) | | | | | | Revenue | | (2) | | 8 | | Cost of revenue | | 2 | | 7 | Foreign exchange contracts | | (243 | ) | | (340 | ) | | | Cost of revenue | | | (262 | ) | | (43 | ) | | Other income (expense), net | | 4 | | | 36 | | | (25) | | 56 | | Cost of revenue | | 4 | | (19) | | Other income (expense), net | | (9) | | 2 | | | | | | | | | | | | | | | | | | | | | | | | | | | Total | | (243 | ) | | (340 | ) | | | | | | (243 | ) | | (17 | ) | | | | (29 | ) | | 35 | | | (25) | | 56 | | | | | | 2 | | (11) | | | | (7) | | 9 | | | | | | | | | | | | | | | | | | | | | | | | | | | | 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, | | | | | | | | | | | | | | | | | 2015 | | 2014 | | | | | | | | | | | Foreign exchange contracts | | | Other income (expense), net | | | (97 | ) | | (61 | ) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Total | | | | | | (97 | ) | | (61 | ) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
(a) | The Company expects that $(223) 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 $(33) million and $(1) million related to the ineffective portion of the hedging relationships for the years ended December 31, 2015 and 2014, respectively, and $4 million and $36 million related to the amount excluded from the assessment of the hedge effectiveness for the years ended December 31, 2015 and 2014, respectively. |
4. Acquisitions and Investments
2015
In the year ended December 31, 2015, the Company completed seven acquisitions and other investments for an aggregate purchase price of $86 million, net of cash acquired. The Company has preliminarily allocated $12 million to identifiable intangible assets and $56 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.
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 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):
Derivatives Not Designated as | | Location of Gain (Loss) | | Amount of Gain (Loss) | Hedging Instruments under | | Recognized in Income | | Recognized in Income on | ASC Topic 815 | | on Derivatives | | Derivatives | | | | | | | Years Ended December 31, | | | | | | | 2018 | | 2017 | Foreign exchange contracts | | Other income (expense), net | | (30) | | 58 | Total | | | | | | (30) | | 58 |
| | | | | | | 2013 | | 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.
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 statements of income from the date of acquisition. A summary of the acquisitions follows (in millions):
| | | | | | | | | | | | | | | Years Ended December 31, | | | | 2015 | | | 2014 | | | 2013 | | Fair value of assets acquired, net of cash acquired | | $ | 116 | | | $ | 406 | | | $ | 3,329 | | Cash paid, net of cash acquired | | | (86 | ) | | | (291 | ) | | | (2,397 | ) | | | | | | | | | | | | | | Liabilities assumed, debt issued and noncontrolling interest | | $ | 30 | | | $ | 115 | | | $ | 932 | | | | | | | | | | | | | | | Excess purchase price over fair value of net assets acquired | | $ | 56 | | | $ | 167 | | | $ | 1,903 | | | | | | | | | | | | | | |
5.4. Inventories, net
Inventories consist of (in millions): | | | December 31, | | | December 31, | | | | 2015 | | | 2014 | | | 2018 | | | 2017 | | Raw materials and supplies | | $ | 1,069 | | | $ | 1,255 | | | $ | 614 | | | $ | 656 | | Work in process | | | 632 | | | | 1,027 | | | | 501 | | | | 513 | | Finished goods and purchased products | | | 2,977 | | | | 2,999 | | | | 1,871 | | | | 1,834 | | | | | | | | | | Total | | $ | 4,678 | | | $ | 5,281 | | | $ | 2,986 | | | $ | 3,003 | | | | | | | | | |
6.
5. Property, Plant and Equipment, net Property, plant and equipment consist of (in millions): | | | | | | | | Estimated | | December 31, | | | | Estimated Useful Lives | | | December 31, | | | Useful Lives | | 2018 | | | 2017 | | | | 2015 | | | 2014 | | | Land and buildings | | | 5-35 Years | | | $ | 1,582 | | | $ | 1,528 | | | Land | | | | | $ | 227 | | | $ | 252 | | Buildings and improvements | | | 5-35 Years | | | 1,271 | | | | 1,340 | | Operating equipment | | | 3-15 Years | | | | 3,055 | | | | 3,060 | | | 3-15 Years | | | 3,140 | | | | 3,169 | | Rental equipment | | | 3-12 Years | | | | 639 | | | | 817 | | | 3-12 Years | | | 597 | | | | 581 | | | | | | | | | | | | Capital leases | | | 20-24 Years | | | 249 | | | | 219 | | | | | | | 5,276 | | | | 5,405 | | | | | | 5,484 | | | | 5,561 | | Less: Accumulated Depreciation | | | | | (2,152 | ) | | | (2,043 | ) | | | | | (2,687 | ) | | | (2,559 | ) | | | | | | | | | | | | | $ | 2,797 | | | $ | 3,002 | | | | | | $ | 3,124 | | | $ | 3,362 | | | | | | | | | | | | |
6. Goodwill and Intangible Assets Intangible Assets The Company has approximately $6.3 billion of goodwill and $3.0 billion of identified intangible assets at December 31, 2018. Goodwill is identified by segment as follows (in millions): | | Wellbore Technologies | | | Completion & Production Solutions | | | Rig Technologies | | | Total | | Balance at December 31, 2016 | | $ | 2,874 | | | $ | 2,058 | | | $ | 1,135 | | | $ | 6,067 | | Goodwill acquired and adjusted during period | | | 37 | | | | 41 | | | | 11 | | | | 89 | | Currency translation adjustments | | | 45 | | | | 23 | | | | 3 | | | | 71 | | Balance at December 31, 2017 | | $ | 2,956 | | | $ | 2,122 | | | $ | 1,149 | | | $ | 6,227 | | Goodwill acquired and adjusted during period | | | 64 | | | | (33 | ) | | | 71 | | | | 102 | | Currency translation adjustments | | | (9 | ) | | | (48 | ) | | | (8 | ) | | | (65 | ) | Balance at December 31, 2018 (1) | | $ | 3,011 | | | $ | 2,041 | | | $ | 1,212 | | | $ | 6,264 | |
| (1) | Accumulated goodwill impairment was $2,457 million as of December 31, 2018. |
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 in a manner consistent with the underlying cash flows over the estimated useful lives of 2-30 years. Amortization expense of identified intangibles is expected to be approximately $336 million, $319 million, $308 million, $302 million, and $280 million for the next five years. Included in intangible assets are $383 million of indefinite-lived trade names.
The net book values of identified intangible assets are identified by segment as follows (in millions): | | Wellbore Technologies | | | Completion & Production Solutions | | | Rig Technologies | | | Total | | Balance at December 31, 2016 | | $ | 2,064 | | | $ | 1,191 | | | $ | 275 | | | $ | 3,530 | | Additions to intangible assets | | | 18 | | | | 41 | | | | 2 | | | | 61 | | Amortization | | | (208 | ) | | | (108 | ) | | | (23 | ) | | | (339 | ) | Currency translation adjustments | | | 9 | | | | 36 | | | | 4 | | | | 49 | | Balance at December 31, 2017 | | $ | 1,883 | | | $ | 1,160 | | | $ | 258 | | | $ | 3,301 | | Additions to intangible assets | | | 41 | | | | 3 | | | | 55 | | | | 99 | | Amortization | | | (201 | ) | | | (111 | ) | | | (29 | ) | | | (341 | ) | Currency translation adjustments | | | 12 | | | | (47 | ) | | | (4 | ) | | | (39 | ) | Balance at December 31, 2018 | | $ | 1,735 | | | $ | 1,005 | | | $ | 280 | | | $ | 3,020 | |
Identified intangible assets by major classification consist of the following (in millions): | | Gross | | | Accumulated Amortization | | | Net Book Value | | December 31, 2017: | | | | | | | | | | | | | Customer relationships | | $ | 4,074 | | | $ | (2,118 | ) | | $ | 1,956 | | Trademarks | | | 885 | | | | (317 | ) | | | 568 | | Patents | | | 602 | | | | (384 | ) | | | 218 | | Indefinite-lived trade names | | | 384 | | | | — | | | | 384 | | Other | | | 499 | | | | (324 | ) | | | 175 | | Total identified intangibles | | $ | 6,444 | | | $ | (3,143 | ) | | $ | 3,301 | | December 31, 2018: | | | | | | | | | | | | | Customer relationships | | $ | 4,078 | | | $ | (2,352 | ) | | $ | 1,726 | | Trademarks | | | 891 | | | | (341 | ) | | | 550 | | Patents | | | 661 | | | | (414 | ) | | | 247 | | Indefinite-lived trade names | | | 383 | | | | — | | | | 383 | | Other | | | 491 | | | | (377 | ) | | | 114 | | Total identified intangibles | | $ | 6,504 | | | $ | (3,484 | ) | | $ | 3,020 | |
Goodwill represents the excess of cost over the fair value of net assets acquired. Goodwill and intangibles with indefinite lives are not amortized. Goodwill is assigned to the reporting units that are expected to benefit from the synergies of a business combination. The recoverability of goodwill and indefinite-lived intangibles is assessed annually, or more frequently as needed when events or changes have occurred that would suggest an impairment of carrying value, by determining whether the fair values of the applicable reporting units exceed their carrying values. The impairment analysis compares the reporting unit’s carrying value to the respective fair value. Fair value of the reporting unit is determined using significant unobservable inputs, or level 3 in the fair value hierarchy. These inputs are based on internal management estimates, forecasts and judgments, using discounted cash flow. The discounted cash flow is based on management’s forecast of operating performance for the 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 reporting unit and its 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. Cash flows beyond the updated forecasted operating plans were estimated using a terminal value calculation, which incorporated historical and forecasted financial cyclical trends for each reporting unit and considered long-term earnings growth rates. The financial and credit market volatility directly impacts our fair value measurement through our weighted average cost of capital that we use to determine our discount rate. During times of volatility, significant judgment must be applied to determine whether credit changes are a short-term or long-term trend.
In 2018, based on the annual impairment test, the calculated fair values for all of the Company’s reporting units were substantially in excess of the respective reporting unit’s carrying value with the exception of the Company’s Floating Production Systems business unit. Further deterioration in the offshore turret mooring systems and topside process modules market could lead to an impairment. This business unit has approximately $277 million in goodwill. In July 2016, as a result of market indicators identified in the third quarter, the Company completed a step one impairment analysis for its Rig Offshore reporting unit and calculated a fair value below its carrying value requiring a step two analysis. The analysis compares the implied fair value of goodwill of a reporting unit to the carrying value of goodwill for the reporting unit. 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. Based on the step two analysis performed for the Rig Offshore reporting unit, the Company recorded a $972 million write-down of goodwill during the third quarter. Management reviews finite-lived intangibles for indicators of impairment whenever events or changes in circumstances indicate that the carrying value may not be recoverable. Cash flows expected to be generated by the finite-lived intangibles are estimated over the intangible asset’s useful life based on updated projections on an undiscounted basis. If the evaluation indicates that the carrying value of the finite-lived intangible asset may not be recoverable, the potential impairment is measured at fair value. 7. Accrued Liabilities Accrued liabilities consist of (in millions): | | | | | | December 31, | | | | December 31, | | | 2018 | | | 2017 | | | | 2015 | | | 2014 | | | Accrued vendor costs | | $ | 449 | | | $ | 815 | | | Customer prepayments and billings | | | 426 | | | | 703 | | | Fair value of derivatives | | | 261 | | | | 297 | | | Warranty | | | 244 | | | | 272 | | | Vendor costs | | | $ | 127 | | | $ | 150 | | Compensation | | | 241 | | | | 662 | | | | 331 | | | | 345 | | Taxes (non income) | | | 175 | | | | 211 | | | | 124 | | | | 152 | | Warranty | | | | 105 | | | | 135 | | Insurance | | | 113 | | | | 126 | | | | 55 | | | | 74 | | Accrued commissions | | | 73 | | | | 97 | | | Fair value of derivatives | | | | 23 | | | | 8 | | Commissions | | | | 34 | | | | 58 | | Interest | | | 8 | | | | 11 | | | | 7 | | | | 7 | | Other | | | 294 | | | | 324 | | | | 282 | | | | 309 | | | | | | | | | | Total | | $ | 2,284 | | | $ | 3,518 | | | $ | 1,088 | | | $ | 1,238 | | | | | | | | | |
8. Costs and Estimated Earnings on Uncompleted Contracts
Costs and estimated earnings on uncompleted contracts consist of (in millions):
| | | | | | | | | | | December 31, | | | | 2015 | | | 2014 | | Costs incurred on uncompleted contracts | | $ | 9,082 | | | $ | 10,442 | | Estimated earnings | | | 4,080 | | | | 4,699 | | | | | | | | | | | | | | 13,162 | | | | 15,141 | | Less: Billings to date on uncompleted contracts | | | 12,697 | | | | 15,038 | | | | | | | | | | | | | $ | 465 | | | $ | 103 | | | | | | | | | | | Costs and estimated earnings in excess of billings on uncompleted contracts | | $ | 1,250 | | | $ | 1,878 | | Billings in excess of costs and estimated earnings on uncompleted contracts | | | (785 | ) | | | (1,775 | ) | | | | | | | | | | | | $ | 465 | | | $ | 103 | | | | | | | | | | |
9.8. Debt
Debt consists of (in millions): | | | | | | | | | | | December 31, | | | | 2015 | | | 2014 | | Senior Notes, interest at 6.125% payable semiannually, principal due on August 15, 2015 | | | — | | | | 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 | | Commercial paper | | | 893 | | | | — | | Other | | | 45 | | | | 23 | | | | | | | | | | | Total debt | | | 3,930 | | | | 3,166 | | Less current portion | | | 2 | | | | 152 | | | | | | | | | | | Long-term debt | | $ | 3,928 | | | $ | 3,014 | | | | | | | | | | |
| | December 31, | | | | 2018 | | | 2017 | | $1.4 billion in Senior Notes, interest at 2.60% payable semiannually, principal due on December 1, 2022 | | | 1,394 | | | | 1,392 | | $1.1 billion in Senior Notes, interest at 3.95% payable semiannually, principal due on December 1, 2042 | | | 1,088 | | | | 1,088 | | Capital Leases and other debt | | | 229 | | | | 232 | | Total debt | | | 2,711 | | | | 2,712 | | Less current portion | | | 7 | | | | 6 | | Long-term debt | | $ | 2,704 | | | $ | 2,706 | |
Principal payments of debt and capital leases for years subsequent to 20152018 are as follows (in millions): | 2016 | | $ | 2 | | | 2017 | | | 506 | | | 2018 | | | 898 | | | 2019 | | | 5 | | | $ | 7 | | 2020 | | | 5 | | | | 7 | | 2021 | | | | 7 | | 2022 | | | | 1,402 | | 2023 | | | | 8 | | Thereafter | | | 2,514 | | | | 1,280 | | | | | | | $ | 2,711 | | | | $ | 3,930 | | | | | | | |
See Note 11 for additional details on future lease payments specific to capital leases. On June 27, 2017, the Company entered into a new $3.0 billion credit agreement evidencing a five-year unsecured revolving credit facility, which expires on June 27, 2022, with a syndicate of financial institutions. This new credit facility replaced the Company’s previous $4.5 billion revolving credit facility. The Company has the right to increase the aggregate commitments under this new agreement to an aggregate amount of up to $4.0 billion upon the consent of only those lenders holding any such increase. Interest under the new multicurrency facility is based upon LIBOR, NIBOR or CDOR plus 1.125% subject to a ratings-based grid or the U.S. prime rate. The new credit facility contains a financial covenant regarding maximum debt-to-capitalization ratio of 60%. As of December 31, 2018, the Company was in compliance with a debt-to-capitalization ratio of 16.3%. On August 15, 2015,November 29, 2017, the Company repaid $151in its entirety the $500 million of its 6.125%1.35% unsecured Senior Notes using available cash balances. During the second quarter of 2015, the Company exercised its accordion option to increase aggregate borrowing capacity under its five-year unsecured revolving credit facility by an additional $1.0 billion, bringing the aggregate borrowing capacity to $4.5 billion. The facility expires September 28, 2018. The Company also has a commercial paper program under which borrowings are classified as long-term since the program is supported by the $4.5$3.0 billion, five-year unsecured revolving credit facility. At December 31, 2015,2018, there were $893 million inno commercial paper borrowings, and there were no outstanding letters of credit issued under the credit facility, resulting in $3,607 million$3.0 billion of funds available under this revolving credit 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, 2015.
The Company also had $2,378$480 million of additional outstanding letters of credit at December 31, 2015,2018, primarily in the U.S., and Norway, that are under various bilateral committed letter of credit facilities. Other lettersLetters of credit are issued as bid bonds, advanced payment bonds and performance bonds. At December 31, 20152018 and 2014,2017, the fair value of the Company’s unsecured Senior Notes approximated $2,551$2,211 million and $2,974$2,346 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 December 31, 20152018 and 2014,2017, the carrying value of the Company’s unsecured Senior Notes approximated $2,992$2,482 million and $3,143$2,480 million, respectively. 10.9. 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. We also have defined contribution plans in Norway and the United Kingdom. For the years ended December 31, 2015, 20142018, 2017 and 2013,2016, expenses for defined-contribution plans were $95$68 million, $115$64 million, and $96$66 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. Approximately 7543 employees represented by certain collective bargaining agreements continue to accrue benefits under the plan. In addition, approximately 1,9001,694 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. Except for two locations represented by certain collective bargaining agreements, active employees are ineligible to participate in any of these U.S. defined benefit plans. Active employees based in the United Kingdom are ineligible to participate in any defined benefit plans. In During 2016, the Company settled its Norway a small number of active employees (approximately 300) continue to participate in a defined benefit plan whileand transferred all participants to the other employees, including new hires, participate in a defined contributiondefined-contribution plan. During 2014, the Company sold certain industrial assets of which the The impact on the defined benefit plans is reflected in the table below.
Net periodic benefit cost for our defined benefit plans aggregated $5($3) million, $7$1 million and $10$5 million for the years ended December 31, 2015, 20142018, 2017 and 2013,2016, 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, 20152018 and 2014,2017, is as follows (in millions): | | | Pension benefits | | | Postretirement benefits | | | Pension benefits | | | Postretirement benefits | | At year end | | 2015 | | | 2014 | | | 2015 | | | 2014 | | | 2018 | | | 2017 | | | 2018 | | | 2017 | | Benefit obligation at beginning of year | | $ | 792 | | | $ | 846 | | | $ | 53 | | | $ | 45 | | | $ | 633 | | | $ | 622 | | | $ | 62 | | | $ | 92 | | Service cost | | | 6 | | | | 8 | | | | — | | | | — | | | | 1 | | | | 1 | | | | — | | | | — | | Interest cost | | | 26 | | | | 35 | | | | 3 | | | | 2 | | | | 18 | | | | 20 | | | | 2 | | | | 3 | | Actuarial loss (gain) | | | (38 | ) | | | 116 | | | | (7 | ) | | | 15 | | | | (24 | ) | | | 6 | | | | (8 | ) | | | (17 | ) | Benefits paid | | | (34 | ) | | | (43 | ) | | | (5 | ) | | | (4 | ) | | | (40 | ) | | | (31 | ) | | | (13 | ) | | | (14 | ) | Participants contributions | | | — | | | | — | | | | 1 | | | | 1 | | | | — | | | | — | | | | 2 | | | | 2 | | Exchange rate loss (gain) | | | (33 | ) | | | (51 | ) | | | — | | | | — | | | | (15 | ) | | | 30 | | | | — | | | | — | | Acquisitions (disposals) | | | — | | | | (118 | ) | | | — | | | | (6 | ) | | Plan amendments | | | | 4 | | | | — | | | | — | | | | — | | Curtailments | | | (16 | ) | | | (1 | ) | | | — | | | | — | | | | — | | | | — | | | | — | | | | (4 | ) | Other | | | — | | | | — | | | | 45 | | | | — | | | | | | | | | | | | | | | | | Settlements | | | | (2 | ) | | | (15 | ) | | | — | | | | — | | Benefit obligation at end of year | | $ | 703 | | | $ | 792 | | | $ | 90 | | | $ | 53 | | | $ | 575 | | | $ | 633 | | | $ | 45 | | | $ | 62 | | | | | | | | | | | | | | | | Fair value of plan assets at beginning of year | | $ | 660 | | | $ | 706 | | | $ | — | | | $ | — | | | $ | 588 | | | $ | 543 | | | $ | — | | | $ | — | | Actual return | | | 3 | | | | 68 | | | | — | | | | — | | | | (21 | ) | | | 57 | | | | — | | | | — | | Benefits paid | | | (34 | ) | | | (43 | ) | | | (5 | ) | | | (4 | ) | | | (40 | ) | | | (31 | ) | | | (13 | ) | | | (14 | ) | Company contributions | | | 12 | | | | 21 | | | | 4 | | | | 3 | | | | 5 | | | | 11 | | | | 11 | | | | 12 | | Participants contributions | | | — | | | | — | | | | 1 | | | | 1 | | | | — | | | | — | | | | 2 | | | | 2 | | Exchange rate gain (loss) | | | (23 | ) | | | (31 | ) | | | — | | | | — | | | | (13 | ) | | | 24 | | | | — | | | | — | | Acquisitions (disposals) | | | (17 | ) | | | (61 | ) | | | — | | | | — | | | | | | | | | | | | | | | | | Settlements | | | | (2 | ) | | | (15 | ) | | | — | | | | — | | Other | | | | — | | | | (1 | ) | | | — | | | | — | | Fair value of plan assets at end of year | | $ | 601 | | | $ | 660 | | | $ | — | | | $ | — | | | $ | 517 | | | $ | 588 | | | $ | — | | | $ | — | | | | | | | | | | | | | | | | Funded status | | $ | (102 | ) | | $ | (132 | ) | | $ | (90 | ) | | $ | (53 | ) | | $ | (58 | ) | | $ | (45 | ) | | $ | (45 | ) | | $ | (62 | ) | | | | | | | | | | | | | | | Accumulated benefit obligation at end of year | | $ | 685 | | | $ | 764 | | | | | | | $ | 572 | | | $ | 630 | | | | | | | | | | | | | | | | | | | | | |
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, | | | Years Ended December 31, | | | 2015 | | | 2014 | | | 2018 | | 2017 | Discount rate: | | | | | | | | | United States plan | | | 3.40% - 3.90% | | | | 3.40% - 3.90% | | | 3.90% - 4.20% | | 3.00% - 3.60% | International plans | | | 2.10% - 3.60% | | | | 2.10% - 3.60% | | | 1.80% - 2.90% | | 1.80% - 2.40% | | Salary increase: | | | | | | | | | United States plan | | | N/A | | | | N/A | | | N/A | | N/A | International plans | | | 2.00% - 4.20% | | | | 2.00% - 4.20% | | | 1.80% - 3.40% | | 1.80% - 3.30% |
The assumption rates used for net periodic benefit costs are as follows: | | | Years Ended December 31, | | Years Ended December 31, | | | | 2015 | | 2014 | | 2013 | | 2018 | | | 2017 | | | 2016 | | Discount rate: | | | | | | | | | | | | | | | | | | | United States plan | | 3.70% - 4.20% | | 3.99% - 4.67% | | 3.80% | | 3.00% - 3.60% | | | 3.10% - 4.00% | | | 3.20% - 4.20% | | International plans | | 2.20% - 3.70% | | 3.50% - 4.40% | | 3.46% - 4.40% | | 1.80% - 2.40% | | | 1.80% - 2.80% | | | 2.20% - 3.70% | | | Salary increase: | | | | | | | | | | | | | | | | | | | United States plan | | N/A | | N/A | | N/A | | N/A | | | N/A | | | N/A | | International plans | | 2.00% - 4.20% | | 2.00% - 4.40% | | 2.00% - 3.53% | | 1.80% - 3.30% | | | 1.80% - 3.50% | | | 2.00% - 4.20% | | | Expected return on assets: | | | | | | | | | | | | | | | | | | | United States plan | | 5.50% | | 6.50% | | 6.30% | | 5.60% | | | 5.60% | | | 5.60% | | International plans | | 2.30% - 5.12% | | 3.50% - 5.53% | | 3.50% - 5.82% | | 1.80% - 4.00% | | | 1.80% - 3.00% | | | 1.80% - 3.00% | |
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 approximately $35$33 million for each of the next five years and aggregate payments of $370$319 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 | | | | Fair Value Measurements | | | Total | | | Level 1 | | | Level 2 | | | Level 3 | | | | Total | | | Level 1 | | | Level 2 | | | Level 3 | | | December 31, 2014: | | | | | | | | | | December 31, 2017: | | | | | | | | | | | | | | | | | | Equity securities | | $ | 116 | | | $ | — | | | $ | 116 | | | $ | — | | | $ | 161 | | | $ | — | | | $ | 161 | | | $ | — | | Bonds | | | 323 | | | | — | | | | 323 | | | | — | | | | 284 | | | | — | | | | 284 | | | | — | | Other (insurance contracts) | | | 221 | | | | — | | | | 113 | | | | 108 | | | | 143 | | | | — | | | | 82 | | | | 61 | | | | | | | | | | | | | | | | Total Fair Value Measurements | | $ | 660 | | | $ | — | | | $ | 552 | | | $ | 108 | | | $ | 588 | | | $ | — | | | $ | 527 | | | $ | 61 | | | | | | | | | | | | | | | | December 31, 2015: | | | | | | | | | | December 31, 2018: | | | | | | | | | | | | | | | | | | Equity securities | | $ | 186 | | | $ | — | | | $ | 186 | | | $ | — | | | $ | 140 | | | $ | — | | | $ | 140 | | | $ | — | | Bonds | | | 259 | | | | — | | | | 259 | | | | — | | | | 209 | | | | — | | | | 209 | | | | — | | Other (insurance contracts) | | | 156 | | | | — | | | | 57 | | | | 99 | | | | 168 | | | | — | | | | 113 | | | | 55 | | | | | | | | | | | | | | | | Total Fair Value Measurements | | $ | 601 | | | $ | — | | | $ | 502 | | | $ | 99 | | | $ | 517 | | | $ | — | | | $ | 462 | | | $ | 55 | | | | | | | | | | | | | | | |
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, 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 | | | | | | | Actual return on plan assets still held at reporting date | | | 3 | | Purchases, sales and settlements | | | 2 | | Currency translation adjustments | | | (14 | ) | | | | | | Balance at December 31, 2015 | | $ | 99 | | | | | | |
| | Level 3 Plan Assets | | Balance at December 31, 2016 | | $ | 53 | | Actual return on plan assets still held at reporting date | | | 2 | | Purchases, sales and settlements | | | (1 | ) | Currency translation adjustments | | | 7 | | Balance at December 31, 2017 | | $ | 61 | | Actual return on plan assets still held at reporting date | | | (1 | ) | Purchases, sales and settlements | | | (2 | ) | Currency translation adjustments | | | (3 | ) | Balance at December 31, 2018 | | $ | 55 | |
11.
10. 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, 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 | ) | | | | | | | | | | | | | | | | | | Accumulated other comprehensive income (loss) before reclassifications | | | (764 | ) | | | (176 | ) | | | 26 | | | | (914 | ) | Amounts reclassified from accumulated other comprehensive income (loss) | | | — | | | | 199 | | | | (4 | ) | | | 195 | | | | | | | | | | | | | | | | | | | Balance at December 31, 2015 | | $ | (1,279 | ) | | $ | (205 | ) | | $ | (69 | ) | | $ | (1,553 | ) | | | | | | | | | | | | | | | | | |
| | | | | | Derivative | | | Defined | | | | | | | | Currency | | | Financial | | | Benefit | | | | | | | | Translation | | | Instruments, | | | Plans, | | | | | | | | Adjustments | | | Net of Tax | | | Net of Tax | | | Total | | Balance at December 31, 2015 | | $ | (1,279 | ) | | $ | (205 | ) | | $ | (69 | ) | | $ | (1,553 | ) | Accumulated other comprehensive income (loss) before reclassifications | | | (97 | ) | | | 32 | | | | 35 | | | | (30 | ) | Amounts reclassified from accumulated other comprehensive income (loss) | | | — | | | | 134 | | | | (3 | ) | | | 131 | | Balance at December 31, 2016 | | $ | (1,376 | ) | | $ | (39 | ) | | $ | (37 | ) | | $ | (1,452 | ) | Accumulated other comprehensive income (loss) before reclassifications | | | 272 | | | | 41 | | | | 25 | | | | 338 | | Amounts reclassified from accumulated other comprehensive income (loss) | | | — | | | | 5 | | | | (1 | ) | | | 4 | | Balance at December 31, 2017 | | $ | (1,104 | ) | | $ | 7 | | | $ | (13 | ) | | $ | (1,110 | ) | Accumulated other comprehensive income (loss) before reclassifications | | | (298 | ) | | | (19 | ) | | | (13 | ) | | | (330 | ) | Amounts reclassified from accumulated other comprehensive income (loss) | | | 6 | | | | (2 | ) | | | (1 | ) | | | 3 | | Balance at December 31, 2018 | | $ | (1,396 | ) | | $ | (14 | ) | | $ | (27 | ) | | $ | (1,437 | ) |
The components of amounts reclassified from accumulated other comprehensive income (loss) are as follows (in millions): | | | Years Ended December 31, | | | | | | | | | | | | | | | | | | | | | | | | | | | | 2018 | | | 2017 | | | 2016 | | | | Years Ended December 31, | | | Currency | | | Derivative | | | Defined | | | | | | | Currency | | | Derivative | | | Defined | | | | | | | Currency | | | Derivative | | | Defined | | | | | | | | 2015 | | 2014 | | 2013 | | | Translation | | | Financial | | | Benefit | | | | | | | Translation | | | Financial | | | Benefit | | | | | | | Translation | | | Financial | | | Benefit | | | | | | | | 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 | | | Adjustments | | | Instruments | | | Plans | | | Total | | | Adjustments | | | Instruments | | | Plans | | | Total | | | Adjustments | | | Instruments | | | Plans | | | Total | | Revenue | | $ | — | | | $ | (19 | ) | | $ | — | | | $ | (19 | ) | | $ | — | | | $ | (26 | ) | | $ | — | | | $ | (26 | ) | | $ | — | | | $ | (16 | ) | | $ | — | | | $ | (16 | ) | | $ | — | | | $ | 2 | | | $ | — | | | $ | 2 | | | $ | — | | | $ | (8 | ) | | $ | — | | | | (8 | ) | | $ | — | | | $ | (5 | ) | | $ | — | | | $ | (5 | ) | Cost of revenue | | | — | | | 295 | | | | — | | | 295 | | | | — | | | 43 | | | | — | | | 43 | | | | — | | | 6 | | | | — | | | 6 | | | | — | | | | (6 | ) | | | — | | | | (6 | ) | | | — | | | | 12 | | | | — | | | | 12 | | | | — | | | | 191 | | | | — | | | | 191 | | | | | | | | | | | — | | | | | | | | | | — | | | | | | | | | | — | | | Selling, general, and administrative | | | — | | | | — | | | (6 | ) | | (6 | ) | | | — | | | | — | | | (8 | ) | | (8 | ) | | | — | | | | — | | | (8 | ) | | (8 | ) | | | — | | | | — | | | | (1 | ) | | | (1 | ) | | | — | | | | — | | | | (1 | ) | | | (1 | ) | | | — | | | | — | | | | (5 | ) | | | (5 | ) | | | | | | | | | | | | | | | | | | | | | | | | | | — | | | Other income (expense), net | | | — | | | | — | | | | — | | | | — | | | 11 | | | | — | | | | — | | | 11 | | | (25 | ) | | | — | | | | — | | | (25 | ) | | | 6 | | | | — | | | | — | | | | 6 | | | | — | | | | — | | | | — | | | | — | | | | — | | | | — | | | | — | | | | — | | Tax effect | | | — | | | (77 | ) | | 2 | | | (75 | ) | | | — | | | (5 | ) | | 2 | | | (3 | ) | | | — | | | 2 | | | 1 | | | 3 | | | | — | | | | 2 | | | | — | | | | 2 | | | | — | | | | 1 | | | | — | | | | 1 | | | | — | | | | (52 | ) | | | 2 | | | | (50 | ) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | $ | 6 | | | $ | (2 | ) | | $ | (1 | ) | | $ | 3 | | | $ | — | | | $ | 5 | | | $ | (1 | ) | | $ | 4 | | | $ | — | | | $ | 134 | | | $ | (3 | ) | | $ | 131 | | | | $ | — | | | $ | 199 | | | $ | (4 | ) | | $ | 195 | | | $ | 11 | | | $ | 12 | | | $ | (6 | ) | | $ | 17 | | | $ | (25 | ) | | $ | (8 | ) | | $ | (7 | ) | | $ | (40 | ) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
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”)(loss). For the years ended December 31, 2015, 20142018 and 20132016, a majority of these local currencies weakened against the U.S. dollar, resulting inwhile for the year ended December 31, 2017, a net othermajority of these local currencies strengthened against the U.S. dollar. Other comprehensive loss of $764income (loss) was ($298) million, $543$272 million and $90($97) million respectively, uponfor the translation from local currencies to the U.S. dollar.years ended December 31, 2018, 2017 and 2016, respectively. Due to the sale of a non-core industrial businesses, $11business, $6 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 (Loss) for the yearsyear ended December 31, 2014 and 2013 respectively.2018. 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 income (loss) of $23($21) million (net of tax$2 million tax), $46 million (net of $14 million)$13 million tax) and $166 million (net of $65 million tax) for the yearyears ended December 31, 2015, other comprehensive loss of $233 million (net of tax of $89 million) for the year ended December 31, 20142018, 2017 and other comprehensive loss of $37 million (net of tax of $18 million) for the year ended December 31, 2013.2016. 12.11. Commitments and Contingencies
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. We have received U.S. federal grand jury subpoenas and subsequent inquiries from U.S. governmental agencies requesting records related tonot incurred material unreserved costs in connection with our compliance with U.S. export tradesuch laws. However, there can be no assurance that other developments, such as new environmental laws, regulations and regulations. We have cooperated fully with agents from the U.S. Department of Justice, the Department of Commerce Bureau of Industry and Security, the United States Department of Treasury, Office of Foreign Assets Control, and U.S. Immigration and Customs Enforcementenforcement policies may not result in respondingadditional, presently unquantifiable, costs or liabilities 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 resolutionus. The Company 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. In addition, we are involved in various other claims, internal investigations, regulatory agency audits and pending or threatened legal actions involving a variety of matters. In many instances, the Company maintains insurance that covers claims arising from risks associated with the business activities of the Company, including claims for premises liability, product liability and other such claims. The Company carries substantial insurance to cover such risks above a self-insured retention. The Company believes, and the Company’s experience has been, that such insurance has been sufficient to cover such risks. See Item 1A. Risk Factors.
The Company is also a party to claims, threatened and actual litigation, and private arbitration arising from ordinary day to day business activities, in which parties assert claims against the Company for a broad spectrum of potential liabilities, including: individual employment law claims, collective actions under federal employment laws, intellectual property claims, including alleged patent infringement, and/or misappropriation of trade secrets, premises liability claims, personal injuries arising from allegedly defective products, alleged improper payments under anti-corruption and anti-bribery laws and other commercial claims seeking recovery for alleged actual or exemplary damages. For many such contingent claims, the Company’s insurance coverage is inapplicable or an exclusion to
coverage may apply. In such instances, settlement or other resolution of such contingent claims could have a material financial or reputational impact on the Company. As of December 31, 2015,2018, the Company recorded reserves in an amount believed to be sufficient for contingent liabilities representing all contingencies believed to be probable to cover liabilities.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. Of course, because of uncertainty and risk inherent to litigation and arbitration, the actual liabilities incurred may exceed our estimated liabilities and reserves, which could have a material financial or reputational impact on the Company. 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 may not result in additional, presently unquantifiable, costs or liabilities to us.
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 mayhave 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. We may also become involved in these investigations, at substantial cost to the Company. The on-going, publicly disclosed investigations in Brazil may continue to adversely impact our shipyard customers, their customers, entities providing financing for our shipyard customers and/or entities in the supply chain. We consummated a settlementhave executed settlements with aseveral shipyard customer oncustomers since December 28, 2015 concerning seven contracts for the supply of drilling equipment packages for 16 drillship construction projects in Brazil (collectively the “Supply Contracts”). Pursuant to the terms of the settlement,settlements, the Supply Contracts have been terminated. We did not take a charge as a result of the settlement and, on a net basis, there was no change to our prior estimates on our Brazil contracts impacting income; however we did reduceincome. Though there have not been any material developments in some time, the Rig Systems segment backlog by $1.2 billion in the quarter. At December 31, 2015, our backlog included $1.8 billion for the remaining 15 rigs across three shipyards in Brazil. The investigationssituation in Brazil have led to,involves political and are expected to continue to lead to, delays in deliveries to our shipyard customers in Brazil, along with temporary suspension of performance under our supply contracts,judicial uncertainty and could resultdevelop in additional cancellationsways that are presently unknown or other breaches of our contracts by our shipyard customers. Our shipyard customers’ customer in Brazil has stated its intent to build some of the drillships it originally contracted for with our shipyard customers. Customers (typically drillship owners or drilling contractors) of our shipyard customers have sought, and may in the future seek, to suspend, delay or cancel their contracts or payments due to such shipyards. As a result, our shipyard customers have sought and may in the future seek to suspend, delay or cancel deliveries of our drilling equipment packages for the affected drillships. To the extent our shipyard customers
and their customers become engaged in disputes or litigation related to any such suspensions, delays or cancellations, we may also become involved, either directly or indirectly, in such disputes or litigation, as we enforce the terms of our contracts with our shipyard customers. Even though the contracts with our shipyard customers for the supply of drilling equipment packages do not provide for cancellation for convenience, in light of the decline in oil prices and the deterioration in the energy markets, we are starting to experience suspensions, delays and attempted cancellations with greater frequency. While we manage equipment deliveries and collection of payment to achieve milestone payments that mitigate our financial risk, such delays, suspensions, attempted cancellations, breaches of contract or other similar circumstances, could adversely affect our operating results and could reduce our backlog.unforeseen.
The Company leases certain facilities and equipment under operating leases that expire at various dates through 2066.2041. 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 $327$212 million, $390$209 million, and $336$246 million in 2015, 20142018, 2017 and 2013,2016, respectively. Future minimum lease commitments under capital leases and noncancellable operating leases with initial or remaining terms of one year or more at December 31, 2015,2018, are payable as follows (in millions): | | | | Capital Lease | | | Operating Lease | | 2016 | | $ | 202 | | | 2017 | | | 120 | | | 2018 | | | 91 | | | | | | Payments | | | Payments | | 2019 | | | 71 | | | $ | 15 | | | $ | 126 | | 2020 | | | 69 | | | | 15 | | | | 106 | | 2021 | | | | 15 | | | | 88 | | 2022 | | | | 15 | | | | 68 | | 2023 | | | | 15 | | | | 51 | | Thereafter | | | 369 | | | | 262 | | | | 293 | | | | | | | Total future lease commitments | | $ | 922 | | | $ | 337 | | | $ | 732 | | | | | | |
13.
12. Common Stock National Oilwell Varco has authorized 1 billion shares of $0.01 par value common stock. The Company also has authorized 10 million shares of $0.01 par value preferred stock, none of which is issued or outstanding. Cash dividends aggregated $710$76 million and $703 million for each of the years ended December 31, 20152018 and 2014, respectively.2017. 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. During the third quarter of 2015 the Company completed its $3 billion share repurchase program. As shares were repurchased, they were constructively retired and returned to an unissued state. During the years ended December 31, 2015 and 2014, the Company repurchased 44.0 million and 11.6 million shares, respectively, under the program for an average price of $50.53 and $66.97 per share, respectively, for an aggregate amount of $2,221 million and $779 million, respectively.
Total compensation cost that has been charged against income for all share-based compensation arrangements was $109$110 million, $101$124 million and $92$107 million for 2015, 20142018, 2017 and 2013,2016, respectively. The total income tax benefit recognized in the consolidated statementstatements of income for all share-based compensation arrangements was $28$16 million, $35$24 million and $28$30 million for 2015, 20142018, 2017 and 2013,2016, respectively. Stock Options
UnderThe Company has a stock-based compensation plan known as the terms of National Oilwell Varco’sVarco, Inc. Long-Term Incentive Plan (the “Plan”). The Plan provides for the granting of stock options, performance-based share awards, restricted stock, phantom shares, stock payments and stock appreciation rights (“SARs”). The number of shares authorized under the Plan is 69.4 million. The Plan is subject to a fungible ratio concept, such that the issuance of stock options and SARs reduces the number of available shares under the Plan on a 1-for-1 basis, and the issuance of other awards reduces the number of available shares under the Plan on a 3-for-1 basis.
The Company’s other stock-based compensation plan, known as amended, 39.5the National Oilwell Varco, Inc. 2018 Long-Term Incentive Plan (the “2018 Plan”), was approved by shareholders on May 11, 2018. The 2018 Plan provides for the granting of stock options, restricted stock, restricted stock units, performance awards, phantom shares, stock appreciation rights, stock payments and substitute awards. The number of shares authorized under the 2018 Plan is 17.8 million. The 2018 Plan is also subject to a fungible ratio concept, such that the issuance of stock options and SARs reduces the number of available shares under the 2015 Plan on a 1-for-1 basis, and the issuance of other awards reduces the number of available shares under the 2018 Plan on a 2.5-for-1 basis. At December 31, 2018, approximately 17.7 million shares of common stock are authorizedwere available for the grant of options to officers, key employees, non-employee directors and other persons. future grants. Stock Options 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, 2015, approximately 6.2 million shares were available for future grants. We also have an inactive stock option plansplan that werewas acquired in connection with the acquisitionsacquisition of Varco International, Inc. in 2005 and Grant Prideco in 2008. We converted the outstanding stock options under these plansthis plan to options to acquire our common stock and no further options are being issued under these plans.this plan. 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, 20152018 under the stock option plans have exercise prices between $12.15$23.94 and $77.99 per share, and expire at various dates from January 13, 2016February 21, 2019 to February 26, 2025. 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.29, 2028.
The following summarizes options activity: | | | Years Ended December 31, | | | | | | | | | | | | | | | | 2018 | | | 2017 | | | 2016 | | | | Years Ended December 31, | | | Number | | | Average | | | Number | | | Average | | | Number | | | Average | | | | 2015 | | | 2014 | | | 2013 | | | of | | | Exercise | | | of | | | Exercise | | | of | | | Exercise | | | | Number of Shares | | Average Exercise Price | | | Number of Shares | | Average Exercise Price | | | Number of Shares | | Average Exercise Price | | | Shares | | | Price | | | Shares | | | Price | | | Shares | | | Price | | Shares under option at beginning of year | | | 10,881,133 | | | $ | 61.22 | | | | 11,535,566 | | | $ | 58.36 | | | | 10,274,477 | | | $ | 54.11 | | | | 22,472,047 | | | $ | 48.99 | | | | 17,439,060 | | | $ | 54.08 | | | | 15,430,307 | | | $ | 59.50 | | Granted | | | 5,746,153 | | | 54.74 | | | | 3,389,547 | | | 69.00 | | | | 3,072,086 | | | 63.96 | | | | 1,610,599 | | | | 35.09 | | | | 6,961,041 | | | | 36.51 | | | | 3,672,411 | | | | 28.26 | | Spun-off | | | — | | | | — | | | | (1,567,348 | ) | | 70.56 | | | | — | | | | — | | | Cancelled | | | (886,356 | ) | | 62.73 | | | | (498,967 | ) | | 70.32 | | | | (329,002 | ) | | 66.78 | | | Forfeited | | | | (1,318,380 | ) | | | 57.56 | | | | (1,482,531 | ) | | | 55.22 | | | | (1,517,065 | ) | | | 49.95 | | Exercised | | | (310,623 | ) | | 22.56 | | | | (1,977,665 | ) | | 53.56 | | | | (1,481,995 | ) | | 38.75 | | | | (1,754,758 | ) | | | 44.12 | | | | (445,523 | ) | | | 29.83 | | | | (146,593 | ) | | | 28.53 | | | | | | | | | | | | | | | | | | | | | | Shares under option at end of year | | | 15,430,307 | | | $ | 59.50 | | | | 10,881,133 | | | $ | 61.22 | | | | 11,535,566 | | | $ | 58.36 | | | | 21,009,508 | | | $ | 48.88 | | | | 22,472,047 | | | $ | 48.99 | | | | 17,439,060 | | | $ | 54.08 | | | | | | | | | | | | | | | | | | | | | | Exercisable at end of year | | | 7,498,414 | | | $ | 60.30 | | | | 5,903,712 | | | $ | 55.06 | | | | 6,324,117 | | | $ | 49.29 | | | | 15,223,029 | | | $ | 54.13 | | | | 14,309,944 | | | $ | 55.00 | | | | 9,828,897 | | | $ | 61.56 | | | | | | | | | | | | | | | | | | | | | |
The following summarizes information about stock options outstanding at December 31, 2015:2018: | | | Weighted-Avg | | | Options Outstanding | | | Options Exercisable | | | | | | | | | | | | | | Remaining | | | | | | | Weighted-Avg | | | | | | | Weighted-Avg | | Range of Exercise Price | | Weighted-Avg Remaining Contractual Life | | | Options Outstanding | | | Options Exercisable | | | Contractual Life | | | Shares | | | Exercise Price | | | Shares | | | Exercise Price | | | | Shares | | | Weighted-Avg Exercise Price | | | Shares | | | Weighted-Avg Exercise Price | | | $12.15 - $55.00 | | | 7.34 | | | | 7,599,928 | | | $ | 48.99 | | | | 2,148,275 | | | $ | 34.39 | | | $23.94 - $55.00 | | | | 6.81 | | | | 15,179,485 | | | $ | 40.68 | | | | 9,393,006 | | | $ | 44.14 | | $55.01 - $70.00 | | | 7.25 | | | | 5,045,298 | | | | 66.22 | | | | 2,569,643 | | | | 64.98 | | | | 4.69 | | | | 3,658,652 | | | | 66.82 | | | | 3,658,652 | | | | 66.82 | | $70.01 - $77.99 | | | 5.68 | | | | 2,785,081 | | | | 76.00 | | | | 2,780,496 | | | | 76.00 | | | | 2.69 | | | | 2,171,371 | | | | 75.95 | | | | 2,171,371 | | | | 75.95 | | | | | | | | | | | | | | | | | | | Total | | | 7.01 | | | | 15,430,307 | | | $ | 59.50 | | | | 7,498,414 | | | $ | 60.30 | | | | 6.01 | | | | 21,009,508 | | | $ | 48.88 | | | | 15,223,029 | | | $ | 54.13 | | | | | | | | | | | | | | | | | | |
The weighted-average fair value of options granted during 2015, 20142018, 2017 and 2013,2016, was approximately $15.41, $25.60$10.01, $9.68 and $24.11$6.44 per share, respectively, as determined using the Black-Scholes option-pricing model. The total intrinsic value of options exercised during 20152018 and 2014,2017 was $9$54 million and $111$13 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, | | | | | 2015 | | 2014 | | 2013 | | | Years Ended December 31, | | Valuation Assumptions: | | | | | | | | 2018 | | | 2017 | | | 2016 | | Expected volatility | | | 49.1 | % | | 49.4 | % | | 50.1 | % | | | 31.8 | % | | | 36.1 | % | | | 48.6 | % | Risk-free interest rate | | | 1.5 | % | | 1.5 | % | | 0.9 | % | | | 2.7 | % | | | 2.2 | % | | | 1.2 | % | Expected dividends | | $ | 3.36 | | | $ | 1.39 | | | $ | 0.75 | | | Expected dividend yield | | | | 0.6 | % | | | 0.6 | % | | | 6.5 | % | Expected term (in years) | | | 3.0 | | | 3.7 | | | 3.4 | | | | 4.3 | | | | 3.0 | | | | 3.0 | |
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 2015 is based on awards ultimately expected to vest, it has been reduced Forfeitures are accounted 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.as they occur.
The following summary presents information regarding outstanding options at December 31, 20152018 and changes during 20152017 with regard to options under all stock option plans: | | | | | | | | | | | | | | | | | | | Shares | | | Weighted- Average Exercise Price | | | Weighted Average Remaining Contractual Term (years) | | | Aggregate Intrinsic Value | | Outstanding at December 31, 2014 | | | 10,881,133 | | | $ | 61.22 | | | | 5.15 | | | $ | 85,503,217 | | Granted | | | 5,746,153 | | | $ | 54.74 | | | | | | | | | | Cancelled | | | (886,356 | ) | | $ | 62.73 | | | | | | | | | | Exercised | | | (310,623 | ) | | $ | 22.56 | | | | | | | | | | | | | | | | | | | | | | | | | | | Outstanding at December 31, 2015 | | | 15,430,307 | | | $ | 59.50 | | | | 7.01 | | | $ | 5,894,977 | | | | | | | | | | | | | | | | | | | Vested or expected to vest | | | 15,229,713 | | | $ | 59.50 | | | | 7.01 | | | $ | 5,814,216 | | | | | | | | | | | | | | | | | | | Exercisable at December 31, 2015 | | | 7,498,414 | | | $ | 60.30 | | | | 5.16 | | | $ | 5,894,977 | | | | | | | | | | | | | | | | | | |
| | | | | | Weighted- Average | | | Weighted Average Remaining Contractual | | | Aggregate | | | | Shares | | | Exercise Price | | | Term (years) | | | Intrinsic Value | | Outstanding at December 31, 2017 | | | 22,472,047 | | | $ | 48.99 | | | | 6.66 | | | $ | 34,186,368 | | Granted | | | 1,610,599 | | | $ | 35.09 | | | | | | | | | | Forfeited | | | (1,318,380 | ) | | $ | 57.56 | | | | | | | | | | Exercised | | | (1,754,758 | ) | | $ | 44.12 | | | | | | | | | | Outstanding at December 31, 2018 | | | 21,009,508 | | | $ | 48.88 | | | | 6.01 | | | $ | 458,576 | | Exercisable at December 31, 2018 | | | 15,223,029 | | | $ | 54.13 | | | | 5.24 | | | $ | 458,576 | |
At December 31, 2015,2018, total unrecognized compensation cost related to nonvested stock options was $95$25 million. This cost is expected to be recognized over a weighted-average period of twothree years. The total fair value of stock options vested in 2015, 20142018, 2017 and 20132016 was approximately $72$26 million, $67$70 million and $64$61 million, respectively. Cash received from option exercises for 2015, 20142018, 2017 and 20132016 was $7$54 million, $108$13 million and $58$4 million, respectively. The actual tax benefit (expense) realized for the tax deductions from option exercises totaled $7$2 million, $44(2) million, and $39$nil for 2018, 2017 and 2016, respectively. Stock Appreciation Rights On December 20, 2017, the Company made a tender offer to exchange SARs issued to certain employees on February 24, 2016 (“2016 SARs”) for cash, amended SARs, and new stock options. The transaction was structured to provide the employees an equal long-term incentive compensation value, while alleviating volatility in the Company’s earnings caused by required mark-to-market accounting on outstanding SARS. Of the outstanding 2016 SARs, 94.75% were exchanged resulting in a total cash payment of $14 million and granting of 3,613,707 new stock options on the exchange date with an exercise price of $34.32 and a fair value of $8.47, with vesting matched to the exchanged 2016 SARs. The following summary presents information regarding outstanding SARs: | | Year Ended December 31, | | | | 2018 | | | 2017 | | | | Number | | | Average | | | Number | | | Average | | | | of | | | Exercise | | | of | | | Exercise | | | | Shares | | | Price | | | Shares | | | Price | | Shares under SARs at beginning of year | | | 1,493,689 | | | $ | 28.41 | | | | 4,341,740 | | | $ | 28.32 | | Granted | | | 14,228 | | | | 35.09 | | | | 14,400 | | | | 38.86 | | Forfeited | | | (83,124 | ) | | | 28.32 | | | | (283,822 | ) | | | 28.35 | | Exercised | | | (25,491 | ) | | | 42.61 | | | | (2,578,629 | ) | | | 34.72 | | Shares under SARs at end of year | | | 1,399,302 | | | $ | 28.49 | | | | 1,493,689 | | | $ | 28.41 | | Exercisable at end of year | | | 165,755 | | | $ | 28.57 | | | | 75,102 | | | $ | 28.33 | |
The expense recognized in 2018, 2017, and 2016 was nil, $8 million, and $20 million, respectively. There was no liability for 2015, 2014 and 2013, respectively. Cash used to settle equity instruments granted under all share-based payment arrangements for 2015, 2014 and 2013 was not material for any period. cash-settled SARs at December 31, 2018. 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, 2015,28, 2018, the Company granted 653,7502,391,933 shares of restricted stock and restricted stock units with a fair value of $54.74$35.09 per share; and performance share awards to senior management employees with potential payouts varying from zero to 396,666449,532 shares. The stock options vest over a three-year period from the grant date while the restricted stock and restricted stock units vest in three equal annual installments commencing on the thirdfirst 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% withbased entirely on a TSR (total shareholder return) goal (the “TSR Award”) and 50% with an internal ROC (return on capital) goal (the “ROC Award”). goal. 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 (Oil Service Sector) index for the three yearthree-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 13, 2015,11, 2018, the Company granted 26,99235,432 restricted stock awards under the 2018 Plan with a fair value of $51.88$40.65 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.
On August 28, 2015, the Company granted 75,000 restricted stock awards with a fair value of $41.65 per share. The awards were granted to an officer of the Company and vest over a three-year period from the grant date.
The following summary presents information regarding outstanding restricted shares: | | Years Ended December 31, | | | | 2018 | | | 2017 | | | 2016 | | | | | | | | | | | | | | | | | | | Weighted- | | | | | | | Weighted- | | | | | | | Weighted- | | | | Years Ended December 31, | | Number | | | Average | | | Number | | | Average | | | Number | | | Average | | | | 2015 | | | 2014 | | | 2013 | | of | | | Grant Date | | | of | | | Grant Date | | | of | | | Grant Date | | | | 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 | | Units | | | Fair Value | | | Units | | | Fair Value | | | Units | | | Fair Value | | Nonvested at beginning of year | | | 1,569,141 | | | $ | 73.73 | | | | 1,643,193 | | | $ | 67.98 | | | | 1,449,683 | | | $ | 62.29 | | | 4,889,678 | | | $ | 37.04 | | | | 4,563,983 | | | $ | 41.10 | | | | 1,969,250 | | | $ | 61.53 | | Granted | | | 954,075 | | | 53.27 | | | | 708,821 | | | 70.14 | | | | 822,281 | | | 63.69 | | | 2,657,115 | | | | 35.17 | | | | 1,738,589 | | | | 38.74 | | | | 3,384,325 | | | | 31.59 | | Spin-off | | | — | | | | — | | | | (319,949 | ) | | 70.56 | | | | — | | | | — | | | Vested | | | (405,327 | ) | | 54.30 | | | | (348,981 | ) | | 74.97 | | | | (368,984 | ) | | 63.89 | | | (1,242,682 | ) | | | 34.86 | | | | (1,018,206 | ) | | | 34.84 | | | | (565,202 | ) | | | 29.32 | | Cancelled | | | (148,639 | ) | | 62.73 | | | | (113,943 | ) | | 70.32 | | | | (259,787 | ) | | 37.78 | | | | | | | | | | | | | | | | | | | | | | | Forfeited | | | (389,251 | ) | | | 57.56 | | | | (394,688 | ) | | | 55.22 | | | | (224,390 | ) | | | 49.95 | | Nonvested at end of year | | | 1,969,250 | | | $ | 61.53 | | | | 1,569,141 | | | $ | 73.73 | | | | 1,643,193 | | | $ | 67.98 | | | 5,914,860 | | | $ | 34.41 | | | | 4,889,678 | | | $ | 37.04 | | | | 4,563,983 | | | $ | 41.10 | | | | | | | | | | | | | | | | | | | | | |
The weighted-average grant day fair value of restricted stock awards and restricted stock units granted during the years ended 2015, 20142018, 2017 and 20132016 was $53.27, $70.14$35.17, $38.74 and $63.69$31.59 per share, respectively. There were 405,327; 348,9811,242,682, 1,018,206 and 368,984565,202 restricted stock awards that vested during 2015, 20142018, 2017 and 2013,2016, respectively. At December 31, 2015,2018, there was approximately $57$108 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. Disaggregation of Revenue The following tables disaggregate our revenue by destinations, as we believe it best depicts how the nature, amount, timing and uncertainty of our revenue and cash flows are affected by economic factors. In the tables below, North America includes only the U.S. and Canada (in millions): | | Year Ended December 31, 2018 | | | | | | | | Completion | | | | | | | | | | | | | | | | Wellbore | | | & Production | | | Rig | | | | | | | | | | | | Technologies | | | Solutions | | | Technologies | | | Eliminations | | | Total | | North America | | $ | 1,817 | | | $ | 1,302 | | | $ | 663 | | | $ | — | | | $ | 3,782 | | International | | | 1,345 | | | | 1,543 | | | | 1,783 | | | | — | | | | 4,671 | | Eliminations | | | 73 | | | | 86 | | | | 129 | | | | (288 | ) | | | — | | | | $ | 3,235 | | | $ | 2,931 | | | $ | 2,575 | | | $ | (288 | ) | | $ | 8,453 | | | | | | | | | | | | | | | | | | | | | | | Land | | $ | 2,683 | | | $ | 1,985 | | | $ | 854 | | | $ | — | | | $ | 5,522 | | Offshore | | | 479 | | | | 860 | | | | 1,592 | | | | — | | | | 2,931 | | Eliminations | | | 73 | | | | 86 | | | | 129 | | | | (288 | ) | | | — | | | | $ | 3,235 | | | $ | 2,931 | | | $ | 2,575 | | | $ | (288 | ) | | $ | 8,453 | |
| | Year Ended December 31, 2017 | | | | | | | | Completion | | | | | | | | | | | | | | | | Wellbore | | | & Production | | | Rig | | | | | | | | | | | | Technologies | | | Solutions | | | Technologies | | | Eliminations | | | Total | | North America | | $ | 1,408 | | | $ | 1,093 | | | $ | 545 | | | $ | — | | | $ | 3,046 | | International | | | 1,116 | | | | 1,528 | | | | 1,614 | | | | — | | | | 4,258 | | Eliminations | | | 53 | | | | 51 | | | | 93 | | | | (197 | ) | | | — | | | | $ | 2,577 | | | $ | 2,672 | | | $ | 2,252 | | | $ | (197 | ) | | $ | 7,304 | | | | | | | | | | | | | | | | | | | | | | | Land | | $ | 2,047 | | | $ | 1,752 | | | $ | 740 | | | $ | — | | | $ | 4,539 | | Offshore | | | 477 | | | | 869 | | | | 1,419 | | | | — | | | | 2,765 | | Eliminations | | | 53 | | | | 51 | | | | 93 | | | | (197 | ) | | | — | | | | $ | 2,577 | | | $ | 2,672 | | | $ | 2,252 | | | $ | (197 | ) | | $ | 7,304 | |
| | Year Ended December 31, 2016 | | | | | | | | Completion | | | | | | | | | | | | | | | | Wellbore | | | & Production | | | Rig | | | | | | | | | | | | Technologies | | | Solutions | | | Technologies | | | Eliminations | | | Total | | North America | | $ | 925 | | | $ | 793 | | | $ | 460 | | | $ | — | | | $ | 2,178 | | International | | | 1,104 | | | | 1,404 | | | | 2,565 | | | | — | | | | 5,073 | | Eliminations | | | 170 | | | | 44 | | | | 85 | | | | (299 | ) | | | — | | | | $ | 2,199 | | | $ | 2,241 | | | $ | 3,110 | | | $ | (299 | ) | | $ | 7,251 | | | | | | | | | | | | | | | | | | | | | | | Land | | $ | 1,497 | | | $ | 1,342 | | | $ | 819 | | | $ | — | | | $ | 3,658 | | Offshore | | | 532 | | | | 855 | | | | 2,206 | | | | — | | | | 3,593 | | Eliminations | | | 170 | | | | 44 | | | | 85 | | | | (299 | ) | | | — | | | | $ | 2,199 | | | $ | 2,241 | | | $ | 3,110 | | | $ | (299 | ) | | $ | 7,251 | |
The Company did not have any customers with revenues greater than 10% of total revenue for the years ended December 31, 2018, 2017, or 2016. Contract Assets and Liabilities Contract assets include unbilled amounts resulting from sales under long-term contracts when the cost-to-cost method of revenue recognition is utilized and revenue recognized exceeds the amount billed to the customer, and right to payment is not only subject to the passage of time. There were no impairment losses recorded on contract assets for the years ending December 31, 2018 and 2017. Contract liabilities consist of advance payments, billings in excess of revenue recognized and deferred revenue. For the balance at December 31, 2017, we reclassified $240 million of advance payments and deferred revenue from accrued liabilities to contract liabilities to conform with the 2018 presentation. The changes in the carrying amount of contract assets and contract liabilities are as follows (in millions): Contract Assets | | | | Balance at December 31, 2017 | $ | 495 | | Additions and Milestone Billings | | (948 | ) | Revenue Recognized | | 1,094 | | Currency translation adjustments and other | | (76 | ) | Balance at December 31, 2018 | $ | 565 | |
Contract Liabilities | | | | Balance at December 31, 2017 | $ | 519 | | Additions and Milestone Billings | | 861 | | Revenue Recognized | | (798 | ) | Currency translation adjustments and other | | (124 | ) | Balance at December 31, 2018 | $ | 458 | |
14. Income Taxes The Tax Cuts and Jobs Act (the “Act”) was enacted on December 22, 2017. The Act reduced the U.S. federal corporate tax rate from 35% to 21%, effective January 1, 2018. We recognized an income tax benefit of $242 million in the year ended December 31, 2017 associated with the revaluation of our net deferred tax liability. The one-time Transition Tax, Global Intangible Low Taxed Income (“GILTI”), Foreign Derived Intangible Income (“FDII”), Base Erosion and Anti-Abuse Tax (“BEAT”) and IRC Section 163(j) interest limitation do not impact our cash taxes or total tax expense for the years ended December 31, 2018 and 2017, respectively. The accounting for the initial impact of the Act is complete. SAB 118 provided for a one-year period to complete the accounting for this expansive new law. Final accounting did not have a material impact to cash tax or total tax expense, but the finalization of the transition tax inclusions in our 2017 and 2018 tax returns, along with recording the impact of tax regulations released in 2018, impacted our foreign tax credit carryforward position. However, our excess foreign tax credits carry a full valuation allowance as we currently estimate that they will expire unutilized. Accordingly, the true-ups only impact the total foreign tax credits recorded and related valuation allowance and do not impact the income tax provision on a net basis. The movement in the valuation allowance during 2018 included the impact of our foreign tax credit carryover position in response to new treasury regulations and finalization of our transition tax calculations. The domestic and foreign components of income (loss) before income taxes were as follows (in millions): | | | Years Ended December 31, | | | Years Ended December 31, | | | | 2015 | | | 2014 | | | 2013 | | | 2018 | | | 2017 | | | 2016 | | Domestic | | $ | (1,577 | ) | | $ | 1,415 | | | $ | 1,362 | | | $ | (168 | ) | | $ | (470 | ) | | $ | (2,095 | ) | Foreign | | | 988 | | | | 2,079 | | | | 1,762 | | | | 209 | | | | 78 | | | | (528 | ) | | | | | | | | | | | | $ | 41 | | | $ | (392 | ) | | $ | (2,623 | ) | | | $ | (589 | ) | | $ | 3,494 | | | $ | 3,124 | | | | | | | | | | | | | |
The components of the provision for income taxes consisted of (in millions): | | | Years Ended December 31, | | | Years Ended December 31, | | | | 2015 | | | 2014 | | | 2013 | | | 2018 | | | 2017 | | | 2016 | | Current: | | | | | | | | | | | | | | | | | | | Federal | | $ | 30 | | | $ | 681 | | | $ | 632 | | | $ | (5 | ) | | $ | 23 | | | $ | (79 | ) | State | | | (58 | ) | | | 43 | | | | 55 | | | | (3 | ) | | | 1 | | | | (4 | ) | Foreign | | | 464 | | | | 615 | | | | 592 | | | | 134 | | | | 161 | | | | 74 | | | | | | | | | | | | | Total current income tax provision | | | 436 | | | | 1,339 | | | | 1,279 | | | | 126 | | | | 185 | | | | (9 | ) | | | | | | | | | | | | Deferred: | | | | | | | | | | | | | | | | | | | Federal | | | (41 | ) | | | (309 | ) | | | (157 | ) | | | 11 | | | | (332 | ) | | | (132 | ) | State | | | (38 | ) | | | (5 | ) | | | (12 | ) | | | - | | | | (2 | ) | | | (7 | ) | Foreign | | | (179 | ) | | | 14 | | | | (167 | ) | | | (74 | ) | | | (7 | ) | | | (59 | ) | | | | | | | | | | | | Total deferred income tax benefit | | | (258 | ) | | | (300 | ) | | | (336 | ) | | | | | | | | | | | | | Total deferred income tax provision | | | | (63 | ) | | | (341 | ) | | | (198 | ) | Total income tax provision | | $ | 178 | | | $ | 1,039 | | | $ | 943 | | | $ | 63 | | | $ | (156 | ) | | $ | (207 | ) | | | | | | | | | | | |
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, | | Years Ended December 31, | | | | 2015 | | | 2014 | | | 2013 | | 2018 | | | 2017 | | | 2016 | | Federal income tax at U.S. statutory rate | | $ | (206 | ) | | $ | 1,223 | | | $ | 1,093 | | $ | 9 | | | $ | (137 | ) | | $ | (918 | ) | Foreign income tax rate differential | | | (110 | ) | | | (261 | ) | | | (216 | ) | | (3 | ) | | | (21 | ) | | | 32 | | State income tax, net of federal benefit | | | (4 | ) | | | 25 | | | | 27 | | | Goodwill impairment | | | — | | | | — | | | | 271 | | Nondeductible expenses | | | 528 | | | | 24 | | | | 26 | | | 20 | | | | 38 | | | | 30 | | Tax benefit of manufacturing deduction | | | (1 | ) | | | (37 | ) | | | (33 | ) | | Foreign dividends, net of foreign tax credits | | | 28 | | | | 132 | | | | 32 | | | 27 | | | | (132 | ) | | | (25 | ) | Tax rate change on timing differences | | | (45 | ) | | | (2 | ) | | | (22 | ) | | (7 | ) | | | (245 | ) | | | (8 | ) | Change in tax reserve | | | 69 | | | | (11 | ) | | | (1 | ) | | Change in uncertain tax positions | | | (5 | ) | | | 81 | | | | 11 | | Prior years taxes | | | (47 | ) | | | (11 | ) | | | (40 | ) | | (13 | ) | | | (26 | ) | | | (29 | ) | Foreign exchange losses | | | (46 | ) | | | 28 | | | | 25 | | | Tax impact on foreign exchange | | | (3 | ) | | | 5 | | | | (4 | ) | Change in deferred tax valuation allowance | | | 15 | | | | (83 | ) | | | 40 | | | 49 | | | | 280 | | | | 476 | | State income taxes - net of federal benefit | | | (3 | ) | | | (1 | ) | | | (10 | ) | Tax exempt income | | | (5 | ) | | | - | | | | (7 | ) | Income tax credits | | | (3 | ) | | | (4 | ) | | | - | | Other | | | (3 | ) | | | 12 | | | | 12 | | | — | | | | 6 | | | | (26 | ) | | | | | | | | | | | | Total income tax provision | | $ | 178 | | | $ | 1,039 | | | $ | 943 | | $ | 63 | | | $ | (156 | ) | | $ | (207 | ) | | | | | | | | | | | |
The effective tax rate for the year ended December 31, 2018 was 153.7%, compared to 39.8% for 2017. For the year ended December 31, 2018, valuation allowances established on deferred tax assets and tax due on foreign income not offset by foreign tax credits resulted in a higher effective tax rate than the U.S. statutory rate. For the year ended December 31, 2017, the revaluation of net deferred tax liabilities in the U.S. partially offset by valuation allowances established on foreign tax credits generated during the year, when applied to losses resulted in a higher effective tax rate than the U.S. statutory rate. Significant components of our deferred tax assets and liabilities were as follows (in millions): | | | December 31, | | | December 31, | | | | 2015 | | | 2014 | | | 2013 | | | 2018 | | | 2017 | | Deferred tax assets: | | | | | | | | | | | | | | | Allowances and operating liabilities | | $ | 491 | | | $ | 542 | | | $ | 439 | | | $ | 293 | | | $ | 355 | | Net operating loss carryforwards | | | 170 | | | | 118 | | | | 51 | | | | 182 | | | | 182 | | Postretirement benefits | | | 79 | | | | 79 | | | | 49 | | | | 30 | | | | 31 | | Foreign tax credit carryforwards | | | 166 | | | | 244 | | | | 300 | | | Tax credit carryforwards | | | | 768 | | | | 1,002 | | Other | | | 21 | | | | 15 | | | | 39 | | | | 95 | | | | 78 | | | | | | | | | | | | | | | | 927 | | | | 998 | | | | 878 | | | Valuation allowance for deferred tax assets | | | (63 | ) | | | (48 | ) | | | (133 | ) | | | | | | | | | | | | | Valuation allowance | | | | (955 | ) | | | (1,202 | ) | Total deferred tax assets | | | 864 | | | | 950 | | | | 745 | | | | 413 | | | | 446 | | | | | | | | | | | | | Deferred tax liabilities: | | | | | | | | | | | | | | | Tax over book depreciation | | | 277 | | | | 236 | | | | 306 | | | | 139 | | | | 174 | | Intangible assets | | | 1,323 | | | | 1,304 | | | | 1,757 | | | | 688 | | | | 716 | | Deferred income | | | 232 | | | | 257 | | | | 285 | | | | 70 | | | | 111 | | Accrued U.S. tax on unremitted earnings | | | 55 | | | | 107 | | | | 92 | | | Accrued tax on unremitted earnings | | | | 17 | | | | 17 | | Other | | | 209 | | | | 377 | | | | 164 | | | | 52 | | | | 92 | | | | | | | | | | | | | Total deferred tax liabilities | | | 2,096 | | | | 2,281 | | | | 2,604 | | | | 966 | | | | 1,110 | | | | | | | | | | | | | Net deferred tax liability | | $ | 1,232 | | | $ | 1,331 | | | $ | 1,859 | | | $ | 553 | | | $ | 664 | | | | | | | | | | | | |
The balance of unrecognized tax benefits at December 31, 2015 and 2014 was $46 million and $115 million, respectively. Included in the increase in the balance of unrecognized tax benefits for the period ended December 31, 2015 was an uncertain tax position identified in a foreign jurisdiction totaling $69 million, of which the Company has settled and paid $69 million in the period. There was an increase of $14 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 $75 million reduction in the balance resulted from the completion of audits in foreign jurisdictions, and an $8 million reduction in the balance resulted from the lapse of applicable statutes of limitations in the U.S. and foreign jurisdictions. Of the decrease of $152 million in the balance of unrecognized tax benefits, $14 million was recorded as a reduction of income tax expense in the current year and is reflected in the “Change in tax reserve” 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, 2015. If the $46 million of unrecognized tax benefits accrued at December 31, 2015 are ultimately realized, the entire $46 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): | | | | | | | | | | | | | | | 2015 | | | 2014 | | | 2013 | | Unrecognized tax benefit at beginning of year | | $ | 115 | | | $ | 127 | | | $ | 128 | | Additions based on tax positions related to the current year | | | 83 | | | | 3 | | | | — | | Reductions for tax positions of prior years | | | (75 | ) | | | — | | | | — | | Settlements of audits | | | (69 | ) | | | — | | | | — | | Reductions for lapse of applicable statutes of limitations | | | (8 | ) | | | (15 | ) | | | (1 | ) | | | | | | | | | | | | | | Unrecognized tax benefit at end of year | | $ | 46 | | | $ | 115 | | | $ | 127 | | | | | | | | | | | | | | |
| | 2018 | | | 2017 | | | 2016 | | Unrecognized tax benefit at beginning of year | | $ | 132 | | | $ | 78 | | | $ | 46 | | Gross increase for current period tax positions | | | 15 | | | | 10 | | | | 3 | | Gross increase for tax positions in prior years | | | 31 | | | | 64 | | | | 65 | | Gross decrease for tax positions in prior years | | | (10 | ) | | | (14 | ) | | | (21 | ) | Settlements | | | (69 | ) | | | — | | | | (3 | ) | Lapse of statute of limitations | | | (1 | ) | | | (6 | ) | | | (12 | ) | Unrecognized tax benefit at end of year | | $ | 98 | | | $ | 132 | | | $ | 78 | |
The Company does not anticipate that the totalbalance of unrecognized tax benefits will significantly change due toat December 31, 2018, 2017 and 2016 was $98 million, $132 million and $78 million, respectively. For the year ended December 31, 2018, the settlement of a foreign jurisdiction audit resulted in a $69 million decrease in uncertain tax provisions. Accruals related to foreign jurisdiction audits orof prior years resulted in uncertain tax position increases of $64 million and $65 million in 2017 and 2016. Substantially all of the expirationunrecognized tax benefits, if ultimately realized, would be recorded as a benefit to the effective tax rate. The Company anticipates that it is reasonably possible that the amount of statutesunrecognized tax benefits may decrease by up to $7 million in the next twelve months due to settlements and conclusions of limitation within 12 months of this reporting date. tax examinations. 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. DuringFor the yearyears ended December 31, 2015, the Company2018, 2017 and 2016, we recorded as an increase of income tax expense a $0.6of nil, $17 million net increase of accruedand $10 million, respectively, for interest and penaltiespenalty related to uncertainunrecognized tax positions. Atbenefits. As of December 31, 2015,2018 and 2017, the Company hashad accrued approximately $3.8$12 million and $32 million, respectively, of interest and penaltiespenalty 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, 2015. 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 20092013 and outside the U.S. for the tax years ending after 2008.2010. In the United States, the Company has $21 million of netNet operating loss carryforwards by jurisdiction and expiration as of December 31, 2015, of which $5 million will expire in 2020, $1 million will expire in 2024, $13 million will expire in 2025, $1 million will expire in 2026, and $1 million will expire in 2028. The potential benefit of $7 million has been reduced by a $5 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 $5 million would reduce future income tax expense.2018 were as follows (in millions):
Outside the United States, the
| | | | | | | | | | | | | | | | | | | Federal | | | State | | | Foreign | | | Total | | 2019 - 2021 Expiration | | $ | 6 | | | $ | 2 | | | $ | 51 | | | $ | 59 | | 2022 - 2033 Expiration | | | 16 | | | | 20 | | | | 142 | | | | 178 | | 2034 - 2038 Expiration | | | 12 | | | | 122 | | | | 94 | | | | 228 | | Unlimited Expiration | | | — | | | | — | | | | 428 | | | | 428 | | Total Net Operating Loss (NOL) | | $ | 34 | | | $ | 144 | | | $ | 715 | | | $ | 893 | | Tax Effected NOL | | $ | 7 | | | $ | 8 | | | $ | 167 | | | $ | 182 | | Valuation Allowance (VA) | | | (6 | ) | | | (8 | ) | | | (140 | ) | | | (154 | ) | Tax Effected NOL Net of VA | | $ | 1 | | | $ | — | | | $ | 27 | | | $ | 28 | |
The Company has $765 million of net operating loss carryforwards as of December 31, 2015, of which $9 million will expire in 2016, $34 million will expire in 2017, $31 million will expire in 2018, $5 million will expire in 2019, $20 million will expire in 2020, $20 million will expire in 2021, $6 million will expire in 2022, $9 million will expire in 2023, $208 million will expire in 2024, $67 million will expire in 2025, $4 million will expire in 2034, $43 million will expire in 2035 and $309 million will carry forward indefinitely. The potential benefit of $162 million has been reduced by a $58 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 $58 million would reduce future income tax expense. Also in the United States, the Company has $166$766 million of excess foreign tax credits in the United States as of December 31, 2015,2018, of which $24$10 million, $141 million, $286 million, $142 million, and $187 million will expire in 2020, 2022, 2026, 2027, and $1422028, respectively. As of December 31, 2018, the Company has remaining tax-deductible goodwill of $133 million, will expire in 2022.resulting from acquisitions. The amortization of this goodwill is deductible over various periods ranging up to 12 years.
Undistributed earnings of certain of the Company’s foreign subsidiaries amounted to $8,187 million and $5,874$3,254 million at December 31, 2015 and 2014, respectively. Those2018. These earnings are considered to be permanentlyindefinitely 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 incremental U.S. federal and state taxes (subject to an adjustment for foreign tax credits)at statutory rates 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 SegmentsSegments. and Geographic Areas The Company’s operations are organized into four reportablethree operating 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”).and Rig Technologies.
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 refurbishment and re-certification.
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; portable power generation; premium drill pipe; wired pipe; drilling optimization and automation services; tubular inspection, repair and coating services; rope access inspection; instrumentation; measuring and monitoring; downhole and fishing tools; steerable technologies; hole openers; 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, blenders, sanders, hydration units, injection units, flowline, manifolds and wellheads;manifolds; well intervention, including coiled tubing units, coiled tubing, and wireline units, BOPs, and tools; onshore production, including fluid processing systems, composite pipe, surface transfer and progressive cavity pumps, and artificial lift systems; and, offshore production, including fluid processing systems, floating production systems, and subsea production technologies.technologies, and connectors for conductor pipe. 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. Rig Technologies The Company had revenuesCompany’s Rig Technologies segment makes and supports the capital equipment and integrated systems needed to drill oil and gas wells on land and offshore as well as other marine-based markets, including offshore wind vessels. 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 Technologies include: substructures, derricks, and masts; cranes; jacking systems; 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; rig instrumentation and control systems; mooring, anchor, and deck handling machinery; and pipelay and construction systems. The segment also provides spare parts, repair, and rentals as well as comprehensive remote equipment monitoring, technical support, field service, and customer training through an extensive network of 4%, 7%aftermarket service and 11%repair facilities strategically located in major areas of total revenue from one of its customersdrilling operations around the world. Rig Technologies supports land and offshore drillers. Demand for the years ended December 31, 2015, 2014,segment’s products depends on drilling contractors’ and 2013, respectively. This customer, Samsung Heavy Industries, is a shipyard acting as a general contractoroil and gas companies’ capital spending plans, specifically capital expenditures on rig construction and refurbishment; and secondarily on the overall level of oilfield drilling activity, which drives demand for its customers, who are drillship ownersspare parts, service, and drilling contractors. This shipyard’s customers have specified thatrepair for the Company’s drilling equipment besegment’s large installed on their drillships and have required the shipyard to issue contracts to the Company.base of equipment.
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, | | | Years Ended December 31, | | | | 2015 | | | 2014 | | | 2013 | | | 2018 | | | 2017 | | | 2016 | | United States | | $ | 3,640 | | | $ | 6,097 | | | $ | 5,140 | | | $ | 3,480 | | | $ | 2,760 | | | $ | 1,961 | | South Korea | | | 1,835 | | | | 3,472 | | | | 3,219 | | | China | | | 1,623 | | | | 1,905 | | | | 1,007 | | | Saudi Arabia | | | | 444 | | | | 310 | | | | 258 | | Brazil | | | | 415 | | | | 498 | | | | 242 | | Norway | | | | 368 | | | | 295 | | | | 339 | | Singapore | | | 1,035 | | | | 1,157 | | | | 1,850 | | | | 321 | | | | 188 | | | | 340 | | United Kingdom | | | 634 | | | | 715 | | | | 705 | | | | 309 | | | | 279 | | | | 299 | | Brazil | | | 605 | | | | 1,299 | | | | 811 | | | Norway | | | 555 | | | | 881 | | | | 1,102 | | | Canada | | | 365 | | | | 645 | | | | 625 | | | | 302 | | | | 286 | | | | 217 | | United Arab Emirates | | | | 248 | | | | 223 | | | | 334 | | China | | | | 231 | | | | 298 | | | | 557 | | South Korea | | | | 169 | | | | 261 | | | | 495 | | Other Countries | | | 4,465 | | | | 5,269 | | | | 4,762 | | | | 2,166 | | | | 1,906 | | | | 2,209 | | | | | | | | | | | | | Total | | $ | 14,757 | | | $ | 21,440 | | | $ | 19,221 | | | $ | 8,453 | | | $ | 7,304 | | | $ | 7,251 | | | | | | | | | | | | |
The following table presents long-lived assets by country based on the location (in millions): | | | December 31, | | | December 31, | | | | 2015 | | | 2014 | | | 2018 | | | 2017 | | United States | | $ | 1,735 | | | $ | 1,818 | | | $ | 1,603 | | | $ | 1,675 | | Brazil | | | 226 | | | | 290 | | | | 217 | | | | 269 | | United Kingdom | | | 163 | | | | 196 | | | | 125 | | | | 140 | | Denmark | | | 128 | | | | 144 | | | | 119 | | | | 128 | | South Korea | | | 102 | | | | 113 | | | | 91 | | | | 97 | | Canada | | | | 79 | | | | 84 | | Russia | | | | 69 | | | | 90 | | United Arab Emirates | | | | 60 | | | | 65 | | Mexico | | | 93 | | | | 110 | | | | 48 | | | | 71 | | Canada | | | 78 | | | | 99 | | | Singapore | | | 78 | | | | 87 | | | | 47 | | | | 59 | | Other Countries | | | 521 | | | | 505 | | | | 339 | | | | 324 | | | | | | | | | | Total | | $ | 3,124 | | | $ | 3,362 | | | $ | 2,797 | | | $ | 3,002 | | | | | | | | | |
Business Segments: The following table presents selected financial data by business segment (in millions): | | | | | | | | | | | | | | | Wellbore Technologies | | | Completion & Production Solutions | | | Rig Technologies | | | Eliminations and corporate costs (1) | | | Total | | | | Rig Systems | | Rig Aftermarket | | Wellbore Technologies | | Completion & Production Solutions | | Eliminations (1) | | Discontinued Operations | | Total | | | December 31, 2015: | | | | | | | | | | | | | | | | December 31, 2018 | | | | | | | | | | | | | | | | | | | | | Revenue | | $ | 6,964 | | | $ | 2,515 | | | $ | 3,718 | | | $ | 3,365 | | | $ | (1,805 | ) | | $ | — | | | $ | 14,757 | | $ | 3,235 | | | $ | 2,931 | | | $ | 2,575 | | | $ | (288 | ) | | $ | 8,453 | | Operating profit (loss) | | 1,206 | | | 605 | | | (1,613 | ) | | 161 | | | (749 | ) | | | — | | | (390 | ) | | 131 | | | | 166 | | | | 213 | | | | (299 | ) | | | 211 | | Capital expenditures | | 81 | | | 10 | | | 180 | | | 87 | | | 95 | | | | — | | | 453 | | | 135 | | | | 87 | | | | 17 | | | | 5 | | | | 244 | | Depreciation and amortization | | 96 | | | 30 | | | 400 | | | 221 | | | | — | | | | — | | | 747 | | | 374 | | | | 212 | | | | 90 | | | | 14 | | | | 690 | | Goodwill | | 1,232 | | | 877 | | | 2,874 | | | 1,997 | | | | — | | | | — | | | 6,980 | | | 3,011 | | | | 2,041 | | | | 1,212 | | | | — | | | | 6,264 | | Total assets | | 6,772 | | | 2,455 | | | 8,766 | | | 5,916 | | | 2,816 | | | | — | | | 26,725 | | | 7,929 | | | | 6,233 | | | | 3,906 | | | | 1,728 | | | | 19,796 | | | December 31, 2014: | | | | | | | | | | | | | | | | December 31, 2017 | | | | | | | | | | | | | | | | | | | | | Revenue | | $ | 9,848 | | | $ | 3,222 | | | $ | 5,722 | | | $ | 4,645 | | | $ | (1,997 | ) | | $ | — | | | $ | 21,440 | | $ | 2,577 | | | $ | 2,672 | | | $ | 2,252 | | | $ | (197 | ) | | $ | 7,304 | | Operating profit | | 1,996 | | | 882 | | | 937 | | | 690 | | | (892 | ) | | | — | | | 3,613 | | | Operating profit (loss) | | | (102 | ) | | | 98 | | | | (14 | ) | | | (259 | ) | | | (277 | ) | Capital expenditures | | 133 | | | 12 | | | 262 | | | 184 | | | 108 | | | | — | | | 699 | | | 99 | | | | 69 | | | | 16 | | | | 8 | | | | 192 | | Depreciation and amortization | | 88 | | | 27 | | | 439 | | | 224 | | | | — | | | | — | | | 778 | | | 379 | | | | 215 | | | | 88 | | | | 16 | | | | 698 | | Goodwill | | 1,236 | | | 877 | | | 4,357 | | | 2,069 | | | | — | | | | — | | | 8,539 | | | 2,956 | | | | 2,122 | | | | 1,149 | | | | — | | | | 6,227 | | Total assets | | 8,052 | | | 2,789 | | | 11,687 | | | 7,072 | | | 3,962 | | | | — | | | 33,562 | | | 7,848 | | | | 5,782 | | | | 4,625 | | | | 1,951 | | | | 20,206 | | | December 31, 2013: | | | | | | | | | | | | | | | | December 31, 2016 | | | | | | | | | | | | | | | | | | | | | Revenue | | $ | 8,450 | | | $ | 2,692 | | | $ | 5,211 | | | $ | 4,309 | | | $ | (1,441 | ) | | $ | — | | | $ | 19,221 | | $ | 2,199 | | | $ | 2,241 | | | $ | 3,110 | | | $ | (299 | ) | | $ | 7,251 | | Operating profit | | 1,594 | | | 729 | | | 915 | | | 613 | | | (652 | ) | | | — | | | 3,199 | | | Operating profit (loss) | | | (770 | ) | | | (266 | ) | | | (1,033 | ) | | | (342 | ) | | | (2,411 | ) | Capital expenditures | | 61 | | | 24 | | | 226 | | | 212 | | | 91 | | | | — | | | 614 | | | 124 | | | | 61 | | | | 24 | | | | 75 | | | | 284 | | Depreciation and amortization | | 82 | | | 26 | | | 420 | | | 210 | | | | — | | | | — | | | 738 | | | 384 | | | | 209 | | | | 94 | | | | 16 | | | | 703 | | Goodwill | | 1,279 | | | 906 | | | 4,425 | | | 2,106 | | | | — | | | 333 | | | 9,049 | | | 2,874 | | | | 2,058 | | | | 1,135 | | | | — | | | | 6,067 | | Total assets | | 7,654 | | | 2,475 | | | 11,862 | | | 7,287 | | | 3,351 | | | 2,183 | | | 34,812 | | | 7,911 | | | | 5,765 | | | | 5,327 | | | | 2,137 | | | | 21,140 | |
(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.Company. Eliminations and corporate costs include intercompany transactions conducted between the fourthree reporting segments that are eliminated in consolidation.consolidation, as well as corporate costs not allocated to the segments. Intercompany transactions within each reporting segment are eliminated within each reporting segment. Also included in the eliminations and corporate costs 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 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.
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 | | Revenue from discontinued operations | | $ | 1,701 | | | $ | 4,296 | | | | | | | | | | | Income from discontinued operations before income taxes | | | 83 | | | | 222 | | | | | | | | | | | Income tax expense | | | 31 | | | | 75 | | | | | | | | | | | Income from discontinued operations | | $ | 52 | | | $ | 147 | | | | | | | | | | |
Prior to the spin-off, sales to NOW were $231 million for the period ended May 30, 2014 and purchases from NOW were $82 million for the period ended May 30, 2014. 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, 2015 | | | | | | | | | | | | | | | | | Revenue | | $ | 4,820 | | | $ | 3,909 | | | $ | 3,306 | | | $ | 2,722 | | Gross profit | | | 1,177 | | | | 855 | | | | 672 | | | | 359 | | Income (loss) from continuing operations | | | 313 | | | | 286 | | | | 156 | | | | (1,522 | ) | Income from discontinued operations | | | — | | | | — | | | | — | | | | — | | Net income (loss) attributable to Company | | | 310 | | | | 289 | | | | 155 | | | | (1,523 | ) | Per share data: | | | | | | | | | | | | | | | | | Basic: | | | | | | | | | | | | | | | | | Income (loss) from continuing operations | | | 0.76 | | | | 0.75 | | | | 0.41 | | | | (4.06 | ) | Income from discontinued operations | | | — | | | | — | | | | — | | | | — | | Net income (loss) attributable to Company | | | 0.76 | | | | 0.75 | | | | 0.41 | | | | (4.06 | ) | Diluted: | | | | | | | | | | | | | | | | | Income (loss) from continuing operations | | | 0.76 | | | | 0.74 | | | | 0.41 | | | | (4.06 | ) | Income from discontinued operations | | | — | | | | — | | | | — | | | | — | | Net income (loss) attributable to Company | | | 0.76 | | | | 0.74 | | | | 0.41 | | | | (4.06 | ) | Cash dividends per share | | | 0.46 | | | | 0.46 | | | | 0.46 | | | | 0.46 | | | | | | | 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 | |
| | First | | | Second | | | Third | | | Fourth | | | | Quarter | | | Quarter | | | Quarter | | | Quarter | | Year ended December 31, 2018 | | | | | | | | | | | | | | | | | Revenue | | $ | 1,795 | | | $ | 2,106 | | | $ | 2,154 | | | $ | 2,398 | | Gross profit | | | 287 | | | | 355 | | | | 393 | | | | 409 | | Net profit (loss) attributable to Company | | | (68 | ) | | | 24 | | | | 1 | | | | 12 | | Net profit (loss) attributable to Company per basic share | | | (0.18 | ) | | | 0.06 | | | | 0.00 | | | | 0.03 | | Net profit (loss) attributable to Company per diluted share | | | (0.18 | ) | | | 0.06 | | | | 0.00 | | | | 0.03 | | Cash dividends per share | | | 0.05 | | | | 0.05 | | | | 0.05 | | | | 0.05 | | Year ended December 31, 2017 | | | | | | | | | | | | | | | | | Revenue | | $ | 1,741 | | | $ | 1,759 | | | $ | 1,835 | | | $ | 1,969 | | Gross profit (loss) | | | 209 | | | | 231 | | | | 285 | | | | 167 | | Net loss attributable to Company | | | (122 | ) | | | (75 | ) | | | (26 | ) | | | (14 | ) | Net loss attributable to Company per basic share | | | (0.32 | ) | | | (0.20 | ) | | | (0.07 | ) | | | (0.04 | ) | Net loss attributable to Company per diluted share | | | (0.32 | ) | | | (0.20 | ) | | | (0.07 | ) | | | (0.04 | ) | Cash dividends per share | | | 0.05 | | | | 0.05 | | | | 0.05 | | | | 0.05 | |
SCHEDULESCHEDULE II
NATIONAL OILWELL VARCO, INC. VALUATION AND QUALIFYING ACCOUNTS Years Ended December 31, 2015, 20142018, 2017 and 20132016 (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: | | | | | | | | | | | | | | | | | 2015 | | $ | 125 | | | $ | 77 | | | $ | (43 | ) | | $ | 159 | | 2014 | | | 132 | | | | 31 | | | | (38 | ) | | | 125 | | 2013 | | | 120 | | | | 32 | | | | (20 | ) | | | 132 | | | | | | | Allowance for excess and obsolete inventories: | | | | | | | | | | | | | | | | | 2015 | | $ | 370 | | | $ | 186 | | | $ | (56 | ) | | $ | 500 | | 2014 | | | 396 | | | | 128 | | | | (154 | ) | | | 370 | | 2013 | | | 338 | | | | 89 | | | | (31 | ) | | | 396 | | | | | | | Valuation allowance for deferred tax assets: | | | | | | | | | | | | | | | | | 2015 | | $ | 48 | | | $ | 15 | | | $ | — | | | $ | 63 | | 2014 | | | 133 | | | | (83 | ) | | | (2 | ) | | | 48 | | 2013 | | | 93 | | | | 40 | | | | — | | | | 133 | | | | | | | Warranty reserve: | | | | | | | | | | | | | | | | | 2015 | | $ | 272 | | | $ | 92 | | | $ | (120 | ) | | $ | 244 | | 2014 | | | 228 | | | | 123 | | | | (79 | ) | | | 272 | | 2013 | | | 194 | | | | 101 | | | | (67 | ) | | | 228 | |
| | Balance beginning of year | | | Additions (Deductions) charged to costs and expenses | | | Charge off's and other | | | Balance end of year | | Allowance for doubtful accounts: | | | | | | | | | | | | | | | | | 2018 | | $ | 187 | | | $ | 17 | | | $ | (43 | ) | | $ | 161 | | 2017 | | | 209 | | | | 6 | | | | (28 | ) | | | 187 | | 2016 | | | 159 | | | | 52 | | | | (2 | ) | | | 209 | | Reserve for excess and obsolete inventories: | | | | | | | | | | | | | | | | | 2018 | | $ | 800 | | | $ | 49 | | | $ | (205 | ) | | $ | 644 | | 2017 | | | 1,017 | | | | 114 | | | | (331 | ) | | | 800 | | 2016 | | | 500 | | | | 606 | | | | (89 | ) | | | 1,017 | | Valuation allowance for deferred tax assets: | | | | | | | | | | | | | | | | | 2018 | | $ | 1,202 | | | $ | 49 | | | $ | (296 | ) | | $ | 955 | | 2017 | | | 544 | | | | 280 | | | | 378 | | | | 1,202 | | 2016 | | | 63 | | | | 476 | | | | 5 | | | | 544 | | Warranty reserve: | | | | | | | | | | | | | | | | | 2018 | | $ | 135 | | | $ | 38 | | | $ | (68 | ) | | $ | 105 | | 2017 | | | 172 | | | | 46 | | | | (83 | ) | | | 135 | | 2016 | | | 244 | | | | 50 | | | | (122 | ) | | | 172 | |
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