Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities
Act. Yes ☒ No ☐
Indicate by check mark if the registrant is not required
to file reports pursuant to Section 13 or Section 15 (d) of the Act. Yes ☐ No ☒
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act
of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past
90 days. Yes ☒ No ☐
Indicate by check mark whether the registrant
has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation
S-T
during the preceding 12 months
(or for such shorter period that the registrant was required to submit and post such files). Yes ☒ 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 registrants knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form
10-K
or any
amendment to this Form
10-K. ☐
Indicate by check mark whether the registrant is a large
accelerated filer, an accelerated filer, a
non-accelerated
filer, or a smaller reporting company. See the definitions of large accelerated filer, accelerated filer and smaller
reporting company in
Rule 12b-2
of the Exchange Act. (Check one):
Indicate by check mark whether the registrant is a shell company (as defined in
Rule 12b-2
of the Exchange Act). Yes ☐ No ☒
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(a) of the Exchange
Act. ☐
Portions of the Proxy Statement in connection with the 2018 Annual Meeting of Stockholders are incorporated in Part III of this report.
PART I
General
National Oilwell Varco, Inc. (NOV or the Company), a Delaware corporation incorporated in 1995, is a leading independent provider of
equipment and technology 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 industrys full-field drilling,
completion, and production 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 breadth and depth of the Companys 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. To
achieve higher efficiencies and reduce costs, the Company combined its Rig Systems and Rig Aftermarket segments during the fourth quarter of 2017. See Note 2 to the Consolidated Financial Statements.
Business Strategy and Competitive Strengths
NOVs
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 intends 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 Companys competitive strengths:
Leverage NOVs advantages of size, scope, scale, and position in the market
NOVs 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
. NOVs market leadership and global footprint, which spans almost
every major oilfield market, provides the Company with economies of scale. NOVs 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 Companys 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 NOVs footprint also reduces potential volatility in the Companys 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 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. NOVs
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.
NOVs 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,
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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 customers total cost
of ownership for drill floor equipment.
Large 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 industrys 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 common
sources of failures and unplanned costs. Additionally, certain past industry events increased the industrys 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.
NOVs 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. NOVs 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 MaxTM industrial platform, which enables large-scale collection, aggregation, and analytics of real-time equipment data. While the initial 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 offered by the Company and to be used to monitor, analyze, and optimize
many of the Companys own manufacturing operations.
Employ a capital-light business model with the ability to quickly scale operations
NOVs manufacturing operations are capital light and have low fixed-asset intensity. The Companys facilities 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
highestlowering shipping costsor 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 equipment. 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 industrys 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 improving internal efficiencies and advancing technological offerings. NOVs ability to continue, if not accelerate, pursuit of its technological initiatives
throughout industry cycles enhances the Companys 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 and drive end-market fragmentation
A key tenet of NOVs business model is to make its technologies and products available to all 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 NOVs
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 pursuing 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 customers for NOVs equipment.
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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 Companys unmatched cross-business-unit capabilities and expertise uniquely position NOV to pioneer proprietary technologies across its business lines. For example, NOVs 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 volatility associated with the oil and gas industry
NOV maintains a conservative capital structure, with an investment grade credit rating and ample liquidity. The Company carefully 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 conservative 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 segments offerings are provided through the following business units:
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ReedHycalog
is a market-leading designer and manufacturer of drill-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, ReedHycalogs drill-bit offering features both roller-cone and fixed-cutter bits designed to improve drilling times and overall well efficiencies. ReedHycalog also
manufactures tools that enable the precise placement of the wellbore within the desired reservoir location, including measurement-while-drilling tools and dynamic rotary steerable systems. ReedHycalog harnesses NOVs unique ability to link
downhole tools and services with surface equipment to provide the worlds first closed-loop drilling automation and optimization system, combining heuristic functions and machine-learning capabilities to transform drilling performance and
operations.
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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 units offerings enable its customers to achieve
significant increases in efficiency, whether in drilling, workover or intervention operations.
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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.
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Tuboscope
is a 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.
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Grant Prideco
is a leading manufacturer of premium drill-stem tubulars. With an integrated supply chain and a strong position in the competitive premium drillpipe connections, Grant Prideco offers one stop
shopping for all drill stem needs. Armed with a product portfolio that ranges from the needs 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.
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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.
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Completion & Production Solutions
provides the critical technologies necessary to
optimize the well completion process and production phase of a wells life cycle. Completion & Production Solutions business units include:
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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, and wireline service providers. ISE manufactures and assembles all of the 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 also produces essential consumable components that support pressure pumping spreads, including valves, seats, and stainless-steel fluid ends.
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. Additionally, the business unit designs and
manufactures wireline products for electric and slickline line applications, including critical pressure control equipment like wireline lubricators. ISEs equipment offerings are supported by an unmatched global network of aftermarket service
and repair facilities.
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Fiber Glass Systems
is a market leader in the design, manufacture, and delivery of high-end composite piping systems, pressure vessels, and structures engineered to deliver customers with solutions to both
corrosion and weight challenges across a wide array of applications. With manufacturing facilities spanning five continents and a sales and distribution network covering 40 countries, Fiber Glass Systems serves customers in the oil and gas,
chemical, industrial, marine, offshore, subsea, fuel handling, and mining industries.
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Process and Flow Technologies
provides integrated processing, production, and pumping equipment to customers in the oil and gas and industrial markets. The Production and Midstream sub-unit manufactures pumping
technologies, including reciprocating, multistage, and progressive cavity pumps; midstream products, such as closures, transfer pumps, and valves; and artificial lift support systems. The Wellstream Processing sub-unit designs and manufactures
integrated systems that provide water treatment, separation, hydrate inhibition, and gas processing to the oil and gas industry. The Industrial sub-unit manufactures pumping, mixing, and agitation equipment, and heat exchangers for general use in
industrial end-markets.
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Subsea Production Systems
strives to improve subsea infrastructure through technical innovation that improves customer productivity and reduces cost. The business unit is one of 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.
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Floating Production Systems
offers a comprehensive 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 designed 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.
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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 large-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.
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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
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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 bridge pumps.
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Rig Technologies
is the global leader in the engineering, manufacturing, and support of advanced drilling equipment packages and related capital
equipment necessary to drill oil and gas wells anywhere in the world. Rig Technologies includes:
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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
Equipments 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.
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Marine Construction
designs, engineers, and manufactures heavy-lift cranes; a large range of knuckle-boom and lattice boom cranes, including active heave options; mooring, anchor, and deck handling machinery; a
full range and models of jacking systems; and pipelay and construction systems. Marine Construction serves the oil and gas industry as well as other marine-based end markets.
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See Note 15 to the Consolidated Financial Statements 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.
Overview of Oil and Gas
Well-Construction Processes
The well-construction process starts with an operator and its contractors designating a suitable drilling site and placing
a drilling rig at the location. The rigs crew assembles the drill stem, which consists of drillpipe joints, specialized drilling components known as downhole tools, and a drill bit at the end. Modern rigs typically power the drill bit 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. The evolution of drilling motors and top
drives has facilitated operators abilities to drill directionally 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 Technologies.
Heavy drilling fluids, or drilling muds, are pumped down
the drill stem and forced out through jets in the bit. The drilling mud returns to the surface through the space between the borehole wall and the drill stem, carrying with it the rock cuttings drilled out by the bit. The cuttings are removed from
the mud by a solids control system (which can include shakers, centrifuges, and other specialized equipment) and disposed of in an environmentally sound manner. The solids control system permits the mud, which is often comprised of expensive
compounds, to be continuously reused and re-circulated back into the hole. Rig Technologies sells the large mud pumps that are used to pump drilling mud through the drill stem, down, and back up the hole. Wellbore Technologies sells and
rents solids control equipment and provides solids control, waste management and drilling fluids services.
Many operators internally coat the drill stem
to improve its hydraulic efficiency and protect it from the corrosive fluids sometimes encountered during drilling; have hard-facing alloys applied to drillpipe joints, collars, and other components to protect tool joints and casing against wear;
and inspect and assess the integrity of the drillpipe from time to time. Wellbore Technologies manufactures and sells drillpipe and provides coating, hardfacing, and drillpipe inspection and repair. As hole depth increases, additional
joints of drillpipe are continuously added to the drill stem. When the bit becomes dull or the equipment at the bottom of the drill stem including the drilling motors otherwise requires servicing, the entire drill stem is pulled out of
the hole and disassembled by disconnecting the joints of drillpipe. These are set aside or racked, the old bit is replaced or service is performed, and the drill stem is reassembled and lowered back into the hole (a process called
tripping). During drilling and tripping operations, joints of drillpipe 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 Technologies provides drilling equipment to manipulate and maneuver the drillpipe in 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 a specified depth, all the drillpipe is pulled out of the hole, and larger-diameter pipe known as casing is lowered into the
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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. Hole openers from Wellbore Technologies, which mount above the drill bits in the drill stem, open the tolerance of the hole to allow for easier and faster casing installation. Completion & Production Solutions
manufactures cement mixing and pumping equipment that is used to cement the casing in place. The rigs hoisting system raises and lowers the drill stem while drilling or tripping, and lowers casing into the wellbore. A conventional hoisting
system is a block-and-tackle mechanism that works within the drilling rigs derrick. The mechanism is lifted by a series of pulleys that are attached to the drawworks at the base of the derrick. Rig Technologies sells and installs drawworks and
pipe hoisting-systems.
During the course of normal drilling operations, the drill stem passes through different geological formations that 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. 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 bottomhole assembly, 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 solids 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-pressure zone where the mud density is inadequate to maintain sufficient pressure. Should efforts to weight up the mud to contain such a pressure kick fail, a blowout
could result, whereby reservoir fluids would flow uncontrolled into the well. A series of BOPs are positioned at the top of the well and, when activated, form tight seals that prevent the escape of fluids to the surface. Conventional 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 rigs 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 as well
as additional sensors that continuously collect downhole data that can be transmitted back to the 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 Technologies supplies spare parts and can dispatch field service engineers with the expertise to quickly repair and maintain equipment, minimizing down time.
Once a well has been drilled, cased, and cemented, and the operator determines hydrocarbons are present in commercial quantities, the well is then completed,
and sometimes stimulated. After the casing is cemented in place, the well undergoes one of several completion processes to open 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 liner. 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 by 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 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. Due to the corrosive nature of many produced fluids, production tubing is often inspected and coated, services
offered by Wellbore
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Technologies. Increasingly, operators choose to use corrosion-resistant composite materials or alloys in the process, which are also sold by Completion & Production Solutions.
Once the well has been stimulated, it is usually ready to 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 ages, and workover procedures and other services may be necessary to extend its life and 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. As a well continues to mature, 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 a wellbore using one of several types of pump. In addition to reduced pressure, the water cut of a wells production tends to increase as
the well ages, which typically requires the addition of water treatment and separation equipment. The Company offers a comprehensive range of workover rigs through Rig 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. Completion & Production Solutions offers several types of artificial lift and related support systems as
well as integrated systems that provide water treatment, separation, hydrate inhibition, and gas processing.
Markets and Competition
The Companys customers are predominantly service companies and oil and gas companies. Products within Wellbore Technologies and Completion &
Production Solutions are rented and sold worldwide through NOVs sales force and through commissioned representatives. Substantially all of Rig Technologies capital equipment and spare parts sales, and a large portion of smaller pumps and
parts sales, are made through NOVs direct sales force and distribution service centers. Sales to foreign oil companies are often made with or through representative arrangements.
The Companys competition consists primarily of publicly traded oilfield service and equipment companies and smaller independent equipment manufacturers.
The Companys foreign operations, which include significant operations in Canada, Europe, Russia, the Far East, the Middle East, Africa and Latin
America, are subject to the risks normally associated with conducting business in foreign countries, including foreign currency exchange risks and uncertain political and economic environments, which may limit or disrupt markets, restrict the
movement of funds or result in the deprivation of contract rights or the taking of property without fair compensation. Government-owned petroleum companies located in some of the countries in which the Company operates have adopted policies (or are
subject to governmental policies) giving preference to the purchase of goods and services from companies that are majority-owned by local nationals. As a result of such policies, the Company relies on joint ventures, license arrangements, and other
business combinations with local nationals in these countries. See Note 15 to the Consolidated Financial Statements for information regarding geographic revenue information.
2017 Acquisitions and Other Investments
During 2017, the
Company completed a total of eight acquisitions and other investments for an aggregate cash investment of $86 million, net of cash acquired.
Influence of Oil and Gas Activity Levels on the Companys Business
The oil and gas industry has historically experienced significant volatility. Demand for the Companys 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
Companys 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. Managements Discussion and Analysis of Financial Condition and Results of Operations.
Seasonal Nature of
the Companys Business
Historically, activity levels of some of the Companys 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 of the Companys products and services in the effected geographic area, although revenues generally recover once conditions
improve. Fluctuations in customers 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 Companys 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 trade and service marks, patents, trade secrets, and other proprietary rights.
8
As of December 31, 2017, the Company held a substantial number of United States patents and had additional
patent applications pending. As of this date, the Company also had foreign patents and patent applications pending relating to inventions covered by the United States patents. Additionally, the Company maintains a substantial number of trade and
service marks and maintains a number of trade secrets. Expiration dates of such patents range from 2018 to 2037.
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 Companys 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.
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 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, 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. Primary facilities are located in Houston, and Fort Worth, Texas; Tulsa, Oklahoma; Senai, Malaysia; Kalundborg, Denmark; Superporto du Acu, Brazil; and Manchester, England.
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
milled 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 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
that 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 Completion & Production Solutions at December 31, 2017, 2016 and 2015 was $1.1 billion, $0.8 billion and $1.0 billion, respectively. Backlog for Rig
Technologies at December 31, 2017, 2016 and 2015, was $1.9 billion, $2.5 billion and $6.1 billion, respectively.
Employees
At December 31, 2017, the Company had a total of 31,889 employees, of which 568 were temporary employees. Approximately 344 employees in the U.S.
are subject to collective bargaining agreements. Additionally, certain 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.
9
Available Information
The Companys principal executive offices are located at 7909 Parkwood Circle Drive, Houston, Texas 77036. Its telephone number is (713)
346-7500.
Further information about the Companys products and services can be found on its website at: http://www.nov.com. The Companys common stock is traded on the New York Stock Exchange under the
symbol NOV. The Companys 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 Companys 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 Companys Code of Ethics is also posted on its website.
10
You should carefully consider the risks described below, in addition to other
information contained or incorporated by reference herein. Realization of any of the following risks could have a material adverse effect on our business, financial condition, cash flows and results of operations.
We are dependent upon the level of activity in the oil and gas industry, which is volatile 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, particularly in the United States and Canada. The willingness of oil and gas operators to make capital expenditures
to explore for and produce oil and natural gas and the willingness of oilfield service companies to invest in capital equipment will continue to be influenced by numerous factors over which we have no control, including the:
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current and anticipated future prices for oil and natural gas;
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volatility of prices for oil and natural gas;
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ability or willingness of 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;
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level of production by
non-OPEC
countries;
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level of excess production capacity;
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cost of exploring for and producing oil and gas;
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level of drilling activity and drilling rig dayrates;
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worldwide economic activity and associated demand for oil and gas;
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availability and access to potential hydrocarbon resources;
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national government political requirements;
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fluctuations in political conditions in the United States and abroad;
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currency exchange rate fluctuations and devaluations;
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development of alternate energy sources; and,
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environmental regulations.
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Expectations for future oil and gas prices cause many shifts in the strategies and
expenditure levels of oil and gas companies, drilling contractors, and other service companies, particularly with respect to decisions to purchase major capital equipment of the type we manufacture. Although oil and gas prices, which are determined
by the marketplace, have increased in recent months, prices may remain below a range that is acceptable to certain of our customers, which could continue the reduced demand for our 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, 2017, we had a backlog of capital equipment to be manufactured, assembled, tested and delivered by Completion & Production
Solutions and Rig Technologies in the amount of $1.1 billion and $1.9 billion, respectively. The following factors, in addition to others not listed, could reduce our margins on these contracts, adversely impact completion of these
contracts, adversely affect our position in the market or subject us to contractual penalties:
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financial challenges for consumers of our capital equipment;
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11
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credit market conditions for consumers of our capital equipment;
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our failure to adequately estimate costs for making this equipment;
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our inability to deliver equipment that meets contracted technical requirements;
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our inability to maintain our quality standards during the design and manufacturing process;
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our inability to secure parts made by third party vendors at reasonable costs and within required timeframes;
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unexpected increases in the costs of raw materials;
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our inability to manage unexpected delays due to weather, shipyard access, labor shortages or other factors beyond our control; and,
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the imposition of tariffs or duties between countries, which could materially affect our global supply chain.
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The Companys 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.
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 can each affect our revenue and earnings:
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improvements in the availability and delivery of products and services by our competitors;
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the introduction of new products and technologies by our competitors; and,
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the expiration of intellectual property rights protecting our products and technologies.
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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.
12
A significant portion of our revenue is derived from our
non-United
States operations, which exposes us to risks inherent in doing business in each of the over 65 countries in which we operate.
Approximately 60%
of our revenues in 2017 were derived from operations outside the United States (based on revenue destination). Our foreign operations include significant operations in every oil producing region in the world. Our revenues and operations are subject
to the risks normally associated with conducting business in foreign countries, including:
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uncertain political, social and economic environments;
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social unrest, acts of terrorism, war and other armed conflict;
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trade and economic sanctions and other restrictions imposed by the United States, European Union or other countries;
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restrictions under the United States Foreign Corrupt Practices Act (FCPA) or similar legislation, as well as foreign anti-bribery and anti-corruption laws;
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confiscatory taxation, tax duties, complex and everchanging tax regimes or other adverse tax policies;
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exposure to expropriation of our assets and other actions by foreign governments;
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deprivation of contract rights;
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restrictions on the repatriation of income or capital;
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currency exchange rate fluctuations and devaluations.
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Our failure to comply with complex U.S. and
foreign laws and regulations could have a material adverse effect on our business and our results of 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 and train our employees to deter prohibited practices. These various laws and regulations can change frequently and significantly. We may become involved in governmental
investigation even if the Company has complied with these laws. If we fail to comply with applicable laws and regulation, we could be subject to investigations, sanctions and civil and criminal prosecution as well as fines and penalties, which could
have a material adverse effect on our reputation and our business, financial condition, results of operations and cash flows. In addition, government disruptions could negatively impact our ability to conduct our business.
We are also required to comply with various complex U.S. and foreign tax laws, regulations and treaties. These laws, regulations and treaties can change
frequently and significantly and it is reasonable to expect changes in the future. If we fail to comply with any of these tax laws, regulations or treaties, we could be subject to, among other things, civil and criminal prosecution, fines, penalties
and confiscation of our assets, which could disrupt our ability to provide our products and services to our customers. Any of these events could have a material adverse effect on our 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.
We could be adversely affected if we fail to
comply with any of the numerous federal, state and local laws, regulations and policies that govern environmental protection, zoning and other matters applicable to our businesses.
Our businesses are subject to numerous federal, state and local laws, regulations and policies governing environmental protection, zoning and other matters.
These laws and regulations have changed frequently in the past and it is reasonable to expect additional changes in the future. If existing regulatory requirements change, we may be required to make significant unanticipated capital and operating
expenditures. We cannot assure you that our operations will continue to comply with future laws and regulations. Governmental authorities may seek to impose fines and penalties on us or to revoke or deny the issuance or renewal of operating permits
for failure to comply with applicable laws and regulations. Under these circumstances, we might be required to reduce or cease operations or conduct site remediation or other corrective action which could adversely impact our operations and
financial condition.
13
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:
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personal injury or loss of life;
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severe damage to or destruction of property; or,
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environmental damage and suspension of operations.
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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:
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breach of contract with customers; or,
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as a result of our contractual agreement to indemnify our customers in the normal course of business, which is normally the case.
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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:
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we may not be able to continue to obtain insurance on commercially reasonable terms;
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we may be faced with types of liabilities that will not be covered by our insurance;
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our insurance carriers may not be able to meet their obligations under the policies; or,
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the dollar amount of any liabilities may exceed our policy limits.
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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, restrictions on emissions of greenhouse gases, or other environmental regulations could increase our operating costs or reduce demand for our products.
Environmental advocacy groups and regulatory agencies in the United States and other countries have been focusing considerable attention on the emissions of
carbon dioxide, methane and other greenhouse gases and their potential role in climate change. The adoption of laws and regulations to implement controls of greenhouse gases, including the imposition of fees or taxes, could adversely impact our
operations and financial condition. The U.S. Congress 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 government officials promulgating regulations to impose
certain operational restrictions and disclosure 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, which could adversely impact our operating results and financial condition.
14
Cybersecurity risks and threats could adversely affect our business.
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 our intellectual property or other proprietary information, including customer data, result in a loss of customer business, subject us to
additional regulatory scrutiny, or expose us to civil litigation and possible financial liability, any of which could have a material adverse effect on our financial position or results of operations.
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 supply 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 Companys 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 material adverse effect to the results of our joint ventures and our consolidated results of
operations.
Our 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 complex and technologically advanced, which enable them to perform in
challenging conditions. Our ability to succeed is, in part, dependent on our success in attracting and retaining qualified personnel to provide service and to design, manufacture, use, install and commission our products. A significant increase in
wages paid by competitors, both within and outside the energy industry, for such highly skilled personnel could result in insufficient availability of skilled labor or increase our labor costs, or both. If the supply of skilled labor is constrained
or our costs increase, our margins could decrease and our growth potential could be impaired.
Severe weather conditions may adversely affect our
operations.
Our business may be materially affected by severe weather conditions in areas where we operate. This may entail the evacuation of
personnel and stoppage of services. In addition, if particularly severe weather affects platforms or structures, this may result in a suspension of activities. Any of these events could adversely affect our financial 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 $6.2 billion of goodwill and $0.4 billion of other intangible assets with indefinite lives as of December 31,
2017. 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.
See additional discussion on Goodwill and Other Indefinite Lived Intangible Assets in Critical Accounting
Estimates of Item 7, Managements Discussion and Analysis of Financial Condition and Results of Operations.
We have expanded
our businesses through acquisitions and intend to maintain a growth strategy.
We have expanded and grown our businesses through acquisitions and
continue to pursue a growth strategy but we cannot assure that attractive acquisitions will be available to us at reasonable prices or at all. In addition, we cannot assure that we will successfully integrate the operations and assets of any
acquired business with our own or that our management will be able to manage effectively 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 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.
15
GLOSSARY OF OILFIELD TERMS
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(Sources: Company management; A Dictionary for the Petroleum Industry, The University of Texas at Austin, 2001.)
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API
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Abbr: American Petroleum Institute
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Annular Blowout Preventer
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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.
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Annulus
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The open space around pipe in a wellbore through which fluids may pass.
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Automatic Pipe Handling
Systems (Automatic Pipe
Racker)
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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.
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Automatic Roughneck
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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.
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Beam pump
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Surface pump that raise and lowers sucker rods continually, so as to operate a downhole pump.
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Bit
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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.
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Blowout
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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.
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Blowout Preventer (BOP)
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Series of valves installed at the wellhead while drilling to prevent the escape of pressurized fluids.
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Blowout Preventer (BOP) Stack
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The assembly of well-control equipment including preventers, spools, valves, and nipples connected to the top of the wellhead.
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Borehole Enlargement (BHE)
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The process of opening up or enlarging the internal diameter of the wellbore. This is typically done with under-reamers, reamers, or hole openers.
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Bottomhole Assembly (BHA)
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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.
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Closed Loop Drilling Systems
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A solids control system in which the drilling mud is reconditioned and recycled through the drilling process on the rig
itself.
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Coiled Tubing
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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.
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Cuttings
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Fragments of rock dislodged by the bit and brought to the surface in the drilling mud. Washed and dried cutting samples are analyzed by geologist to obtain information about the formations drilled.
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Directional Well
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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.
|
16
|
|
|
|
|
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 waters 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 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 or 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.
|
17
|
|
|
|
|
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. 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 establish 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 for 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.
|
18
|
|
|
|
|
Shale shaker
|
|
A piece of drilling rig equipment that uses a vibrating screen to remove cuttings from the circulating fluid in rotary drilling operations. The size of the openings in the screen should be selected carefully to be the smallest
size possible to allow 100 per cent flow of the fluid. Also called a shaker.
|
|
|
Slim-hole completions
(Slim-hole Drilling)
|
|
Drilling in which the size of the hole is smaller than the conventional hole diameter for a given depth. This decrease in hole size enables the operator to run smaller casing, thereby lessening the cost of completion.
|
|
|
Slips
|
|
Wedge-shaped pieces of metal with serrated inserts (dies) or other gripping elements, such as serrated buttons, that suspend the drill pipe or drill collars in the master bushing of the rotary table when it is necessary to
disconnect the drill stem from the kelly or from the
top-drive
units drive shaft. Rotary slips fit around the drill pipe and wedge against the master bushing to support the pipe. Drill collar slips fit
around a drill collar and wedge against the master bushing to support the drill collar. Power slips are pneumatically or hydraulically actuated devices that allow the crew to dispense with the manual handling of slips when making a
connection.
|
|
|
Solids
|
|
See Cuttings
|
|
|
Spinning wrench
|
|
Air-powered
or hydraulically powered wrench used to spin drill pipe in making or breaking connections.
|
|
|
Spinning-in
|
|
The rapid turning of the drill stem when one length of pipe is being joined to another.
Spinning-out
refers to separating the pipe.
|
|
|
Stand
|
|
The connected joints of pipe racked in the derrick or mast when making a trip. On a rig, the usual stand is about 90 feet (about 27 meters) long (three lengths of drill pipe screwed together), or a treble.
|
|
|
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.
|
19
|
|
|
|
|
Trouble cost
|
|
Costs incurred as a result of unanticipated complications while drilling a well. These costs are often referred to as contingency costs during the planning phase of a well.
|
|
|
Turret
|
|
Mechanical device that allows a floating vessel to rotate around stationary flowlines, umbilicals, and other associated risers.
|
|
|
Well completion
|
|
1. The activities and methods of preparing a well for the production of oil and gas or for other purposes, such as injection; the method by which one or more flow paths for hydrocarbons are established between the reservoir
and the surface. 2. The system of tubulars, packers, and other tools installed beneath the wellhead in the production casing; that is, the tool assembly that provides the hydrocarbon flow path or paths.
|
|
|
Wellhead
|
|
The termination point of a wellbore at surface level or subsea, often incorporating various valves and control instruments.
|
|
|
Well stimulation
|
|
Any of several operations used to increase the production of a well, such as acidizing or fracturing.
|
|
|
Well workover
|
|
The performance of one or more of a variety of remedial operations on a producing oil well to try to increase production. Examples of workover jobs are deepening, plugging back, pulling and resetting liners, and squeeze
cementing.
|
|
|
Wellbore
|
|
A borehole; the hole drilled by the bit. A wellbore may have casing in it or it may be open (uncased); or part of it may be cased, and part of it may be open. Also called a borehole or hole.
|
|
|
Wireline
|
|
A slender, rodlike or threadlike piece of metal usually small in diameter, that is used for lowering special tools (such as logging sondes, perforating guns, and so forth) into the well. Also called slick line.
|
ITEM 1B.
|
UNRESOLVED STAFF COMMENTS
|
None.
20
The Company owned or leased approximately 611 facilities worldwide as of December 31,
2017, including the following principal manufacturing, service, distribution and administrative facilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Location
|
|
Description
|
|
Building
Size
(SqFt)
|
|
|
Property
Size
(Acres)
|
|
|
Owned /
Leased
|
|
Lease
Termination
Date
|
|
|
|
|
|
|
|
Wellbore Technologies:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Navasota, Texas
|
|
Manufacturing Facility & Administrative Offices
|
|
|
562,112
|
|
|
|
196
|
|
|
Owned
|
|
|
|
|
Conroe, Texas
|
|
Manufacturing Facility of Drill Bits and Downhole Tools, Administrative & Sales Offices
|
|
|
410,623
|
|
|
|
35
|
|
|
Owned
|
|
|
|
|
Houston, Texas
|
|
Sheldon Road Inspection Facility
|
|
|
319,365
|
|
|
|
192
|
|
|
Owned
|
|
|
|
|
Veracruz, Mexico
|
|
Manufacturing Facility of Tool Joints, Warehouse & Administrative Offices
|
|
|
303,400
|
|
|
|
42
|
|
|
Owned
|
|
|
|
|
Houston, Texas
|
|
Holmes Rd Complex: Manufacturing, Warehouse, Coating Manufacturing Plant & Corporate Office
|
|
|
300,000
|
|
|
|
50
|
|
|
Owned
|
|
|
|
|
Cedar Park, Texas
|
|
Instrumentation Manufacturing Facility, Administrative & Sales Offices
|
|
|
215,778
|
|
|
|
38
|
|
|
Owned
|
|
|
|
|
Dubai, UAE
|
|
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
|
|
|
|
|
|
|
|
|
|
Completion & Production Solutions:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Senai, Malaysia
|
|
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
|
|
|
|
|
Superporto du Acu, Brazil
|
|
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
|
|
|
|
|
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
|
|
|
342,999
|
|
|
|
24
|
|
|
Owned
|
|
|
|
|
Qingdau, Shagdong, 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
|
|
|
|
|
Houston, Texas
|
|
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, Administrative & Sales Offices
|
|
|
602,110
|
|
|
|
33
|
|
|
Leased
|
|
|
6/30/2028
|
|
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
|
|
|
|
|
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 Service/Training, Administrative & Sales Offices
|
|
|
133,659
|
|
|
|
4
|
|
|
Leased
|
|
|
1/5/2024
|
|
Dubai, UAE
|
|
Repair & Overhaul of Drilling Equipment, Warehouse & Sales Office
|
|
|
39,433
|
|
|
|
2
|
|
|
Owned
|
|
|
|
|
|
|
|
|
|
|
Corporate:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Houston, Texas
|
|
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 218 repair and manufacturing facilities that
refurbish and manufacture new equipment and parts, 239 service centers that provide inspection and equipment rental and 154 engineering, sales and administration facilities.
21
ITEM 3.
|
LEGAL PROCEEDINGS
|
We have various claims, lawsuits, arbitrations and administrative proceedings that
are pending or threatened, arising in the ordinary course of business. Such claims, threatened and actual litigation, and arbitrations involve 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 Companys 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. Such disputes arise in locations around the world
and include proceedings in civil courts and arbitrations.
Forecasting the ultimate outcome of such matters requires a combination of judgment, experience
and involves inherent uncertainties. In some instances, parties assert baseless or
far-fetched
damage claims or inflate their claimed damages in an effort to exert leverage in settlement discussions, such
assertions can involve unsubstantiated claims that if ultimately accepted by an arbitrator, jury or tribunal could materially impact the Company on a financial and reputational basis. The Company vigorously defends against such claims and tactics.
In those instances, in which we believe that incurrence of a loss is probable and the amount can be reasonably estimated, we estimate a range of probable
outcomes and record a reserve within that range, including accruals for self-insured losses which may be calculated based on historical claim data, specific loss development factors and other information. We have many product liability, premises
liability and commercial claims pending against our subsidiaries. A range of total possible losses for all litigation matters cannot be reasonably estimated because of the number of uncertainties and incomplete information for individual claims.
Based on our considered judgment as to pertinent facts and circumstances, including the inputs and advice of experienced and knowledgeable advisors, we do not expect the ultimate outcome of any currently pending lawsuits or claims against us will
have a material adverse effect on our financial position, results of operations or cash flows. However, no assurance as to the ultimate outcome of these matters can be provided.
For many commercial and regulatory claims and disputes, we do not have insurance or our insurance may contain an exclusion under the terms of our policies of
insurance. The Company maintains substantial insurance against risks arising from our business based on market availability of insurance and our judgment concerning such risks, for example risks arising from product liability claims. No assurance
can be given that the amount of that insurance will be sufficient to fully indemnify us against liabilities arising out of pending or future legal proceedings or other claims. Typically, our insurance policies contain deductibles or self-insured
retentions, for which we are responsible for payment. In determining whether to, and the amount of self-insurance, it is our policy to self-insure at a level that we deem appropriate considering the cost of self-insuring compared to premiums for
insurance with lower deductibles or self-insured retentions.
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.
In the fourth quarter of 2016, one of our subsidiaries settled a product liability
claim for CAD 42 million ($31 million at December 31, 2016), in Canada. The settlement was paid in 2017 by our insurers under a reservation of rights. In 2017, we resolved our claims against our insurer asserting that our existing
policies of insurance covered all settled claims. The outcome of this settlement did not have a material adverse impact on our earnings.
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.
22
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 2017 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.
The
Company combined its Rig Systems and Rig Aftermarket reporting segments into a single segment called Rig Technologies, effective October 1, 2017. The restructuring better aligns operations with the current and anticipated market environments,
reduces administrative burden, and eliminates reported intercompany transactions between Rig Technologies capital equipment and aftermarket operations. The Companys reporting segments are Wellbore Technologies, Completion &
Production Solutions, and Rig Technologies. As a result of the reorganization, all prior periods are presented on this basis.
2. Summary of
Significant Accounting Policies
Fair Value of Financial Instruments
The carrying amounts of financial instruments including cash and cash equivalents, receivables, and payables approximated fair value because of the relatively
short maturity of these instruments. Cash equivalents include only those investments having a maturity date of three months or less at the time of purchase.
Derivative Financial Instruments
Accounting Standards
Codification (ASC) Topic 815, Derivatives and Hedging (ASC Topic 815) requires companies to recognize all derivative instruments as either assets or liabilities in the Consolidated Balance Sheet at fair value. The
accounting for changes in the fair value (i.e., gains or losses) of a derivative instrument depends on whether it has been designated and qualifies as part of a hedging relationship and further, on the type of hedging relationship. For those
derivative instruments that are designated and qualify as hedging instruments, a company must designate the hedging instrument, based upon the exposure being hedged, as a fair value hedge, cash flow hedge, or a hedge of a net investment in a foreign
operation.
The Company records all derivative financial instruments at their fair value in its Consolidated Balance Sheet. Except for certain
non-designated
hedges discussed below, all derivative financial instruments that the Company holds are designated as cash flow hedges and are highly effective in offsetting movements in the underlying risks. Such
arrangements typically have terms between two and 24 months, but may have longer terms depending on the underlying cash flows being hedged, typically related to the projects in our backlog.
Inventories
Inventories consist of raw materials,
work-in-process
and oilfield and industrial finished products, manufactured equipment and spare parts. Inventories are stated at the lower of cost or estimated net realizable
value using the
first-in,
first-out
or average cost methods. 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 limited. The Companys inventory consists of spare parts, work in process, and raw
materials to support ongoing manufacturing operations and the Companys large installed base of highly specialized oilfield equipment. The Companys estimated carrying value of inventory depends upon demand largely driven by levels of oil
and gas well drilling and remediation activity, which depends in turn upon oil and gas prices, the general outlook for economic growth worldwide, available financing for the Companys 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.
61
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
mid-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 2017 and 2016 we recorded charges for additions to inventory reserves of $114 million and $606 million, respectively, consisting primarily of
obsolete and surplus inventories. At December 31, 2017 and 2016, inventory reserves totaled $800 million and $1,017 million, or 21.0% and 23.4% 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 $359 million, $370 million and $391 million for the years ended December 31, 2017, 2016 and 2015, respectively. Accumulated depreciation of $2,559 million as of
December 31, 2017 included accumulated depreciation of $18 million for capital leases. The estimated useful lives of the major classes of property, plant and equipment are included in Note 6 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 were $10 million and $54 million in impairments of long-lived
assets for the years ended December 31, 2017 and 2016, respectively, and nil for the year ended December 31, 2015.
Intangible Assets
The Company has approximately $6.2 billion of goodwill and $3.3 billion of identified intangible assets at December 31, 2017. Goodwill
is identified by segment as follows (in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Wellbore
Technologies
|
|
|
Completion &
Production
Solutions
|
|
|
Rig
Technologies
|
|
|
Total
|
|
Balance at December 31, 2015
|
|
$
|
2,874
|
|
|
$
|
1,997
|
|
|
$
|
2,109
|
|
|
$
|
6,980
|
|
|
|
|
|
|
Goodwill acquired and adjusted during period
|
|
|
4
|
|
|
|
70
|
|
|
|
|
|
|
|
74
|
|
Impairment
|
|
|
|
|
|
|
|
|
|
|
(972
|
)
|
|
|
(972
|
)
|
Currency translation adjustments
|
|
|
(4
|
)
|
|
|
(9
|
)
|
|
|
(2
|
)
|
|
|
(15
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 (1)
|
|
$
|
2,956
|
|
|
$
|
2,122
|
|
|
$
|
1,149
|
|
|
$
|
6,227
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
Accumulated goodwill impairment was $2,457 million as of December 31, 2017.
|
Identified intangible assets with determinable lives consist primarily of customer relationships, trademarks, trade names, patents, and technical drawings
acquired in acquisitions, and are being amortized on a straight-line basis over the estimated useful lives of
2-30 years.
Amortization expense of identified intangibles is expected to be approximately
$320 million in each of the next five years. Included in intangible assets are $384 million of indefinite-lived trade names.
62
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, 2015
|
|
$
|
2,254
|
|
|
$
|
1,296
|
|
|
$
|
299
|
|
|
$
|
3,849
|
|
|
|
|
|
|
Additions to intangible assets
|
|
|
15
|
|
|
|
9
|
|
|
|
|
|
|
|
24
|
|
Amortization
|
|
|
(205
|
)
|
|
|
(106
|
)
|
|
|
(22
|
)
|
|
|
(333
|
)
|
Currency translation adjustments
|
|
|
|
|
|
|
(8
|
)
|
|
|
(2
|
)
|
|
|
(10
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Identified intangible assets by major classification consist of the following (in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross
|
|
|
Accumulated
Amortization
|
|
|
Net Book
Value
|
|
December 31, 2016:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Customer relationships
|
|
$
|
4,024
|
|
|
$
|
(1,874
|
)
|
|
$
|
2,150
|
|
Trademarks
|
|
|
878
|
|
|
|
(290
|
)
|
|
|
588
|
|
Patents
|
|
|
585
|
|
|
|
(345
|
)
|
|
|
240
|
|
Indefinite-lived trade names
|
|
|
384
|
|
|
|
|
|
|
|
384
|
|
Other
|
|
|
463
|
|
|
|
(295
|
)
|
|
|
168
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total identified intangibles
|
|
$
|
6,334
|
|
|
$
|
(2,804
|
)
|
|
$
|
3,530
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset Impairment
Generally Accepted Accounting Principles require the Company test goodwill and other indefinite-lived intangible assets for impairment at least annually or
more frequently whenever events or circumstances occur indicating that those assets might be impaired. Prior to 2017, the impairment analysis was a two-step process as the Company early adopted Accounting Standard Update No. 2017-04
Simplifying the Test for Goodwill Impairment, which eliminates step two effective July 1, 2017.
63
The impairment analysis compares the reporting units carrying value to the respective fair value. Fair
value of the reporting unit 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.
The discounted cash flow is based on managements 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 Companys 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 units 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.
Based on the Companys step one impairment analysis, as of July 1, 2016, completed as a result of market indicators identified in
the third quarter, the Rig Offshore reporting unit had a calculated fair value below its carrying value, and required a step two analysis, which 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 units identifiable assets and liabilities from the fair value of that reporting unit as a whole. Consistent with the step one
analysis, fair value of the assets and liabilities was determined in accordance with ASC Topic 820. 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.
On July 1, 2017, the Companys Wellbore Technologies segment reorganized three of its reporting units, moving various operations
between them. The goodwill impairment analyses performed prior to and subsequent 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 current
and anticipated market environments, reduces administrative burden, and eliminates reported intercompany transactions between Rig Technologies capital equipment and aftermarket operations. The Company tested the Rig Systems and Rig Aftermarket
reporting units for impairment prior to combining, and the two, new reporting units under the Rig Technologies segment for impairment after combining, and concluded all fair values of the reporting units were substantially in excess of their
carrying values.
During the fourth quarter of 2017, the Company performed its annual impairment test, as described in ASC Topic 350, as of October 1,
2017. Based on the Companys annual impairment test, the calculated fair values for all of the Companys reporting units were substantially in excess of the respective reporting units carrying value. Additionally, the fair value for
all of the Companys intangible assets with indefinite lives were substantially in excess of the respective asset carrying values.
Foreign
Currency
Certain foreign operations, including our operations in Norway, use the U.S. dollar as the 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. Accordingly, financial statements of these foreign subsidiaries are remeasured to U.S. dollars for consolidation purposes using current rates of
exchange for monetary assets and liabilities and historical rates of exchange for nonmonetary assets and related elements of expense. Revenue and expense elements are remeasured at rates that approximate the rates in effect on the transaction dates.
For all operations, gains or losses from remeasuring foreign currency transactions into the functional currency are included in income. Net foreign currency transaction gains (losses) were $(3) million, $(10) million and $(47) million for the
years ending December 31, 2017, 2016 and 2015, respectively, and are included in other income (expense) in the accompanying statement of income.
64
Historically, the Venezuelan government has devalued the countrys currency. During the first quarter of
2015, the Venezuelan government officially devalued the Venezuelan bolivar against the U.S. dollar. As a result, the Company incurred approximately $9 million in devaluation charges in the first quarter of 2015. The reporting currency of all of the
Companys Venezuelan entities is the U.S. dollar. The Companys net remaining investment in Venezuela, which is largely U.S. dollar, was nil at December 31, 2017.
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 devaluation charges in the fourth quarter of 2015. The reporting currency of all of the Companys Argentinian entities is the Argentine peso.
Revenue Recognition
The Companys products and
services are sold based upon purchase orders or contracts with the customer that include fixed or determinable prices and that do not generally include right of return or other similar provisions or other significant post delivery obligations.
Except for certain construction contracts and drill pipe sales described below, the Company records revenue at the time its manufacturing process is complete, the customer has been provided with all proper inspection and other required
documentation, title and risk of loss has passed to the customer, collectability is reasonably assured and the product has been delivered. Customer advances or deposits are deferred and recognized as revenue when the Company has completed all of its
performance obligations related to the sale. The Company also recognizes revenue as services are performed. The amounts billed for shipping and handling costs are included in revenue and related costs are included in cost of sales.
Revenue Recognition under Long-term Construction Contracts
The Company uses the percentage-of-completion method to account for certain long-term construction contracts in the 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;
|
|
|
|
the structural design is unique and requires significant engineering efforts; and
|
|
|
|
construction projects often have progress payments.
|
This method requires the Company to make estimates
regarding the total costs of the project, progress against the project schedule and the estimated completion date, all of which impact the amount of revenue and gross margin the Company recognizes in each reporting period. The Company prepares
detailed cost estimates at the beginning of each project. Significant projects and their related costs and profit margins are updated and reviewed at least quarterly by senior management. Factors that may affect future project costs and margins
include shipyard access, weather, production efficiencies, availability and costs of labor, materials and subcomponents and other factors. These factors can impact the accuracy of the Companys estimates and materially impact the Companys
current and future reported earnings.
The asset, Costs in excess of billings, represents revenues recognized in excess of amounts billed. The
liability, Billings in excess of costs, represents billings in excess of revenues recognized.
Drill Pipe Sales
For drill pipe sales, if requested in writing by the customer, delivery may be satisfied through delivery to the Companys customer storage location or to
a third-party storage facility. For sales transactions where title and risk of loss have transferred to the customer but the supporting documentation does not meet the criteria for revenue recognition prior to the products being in the physical
possession of the customer, the recognition of the revenues and related inventory costs from these transactions are deferred until the customer takes physical possession.
Service and Product Warranties
The Company provides
service and warranty policies on certain of its products. The Company accrues liabilities under service and warranty policies based upon specific claims and a review of historical warranty and service claim experience in accordance with ASC Topic
450 Contingencies (ASC Topic 450). Adjustments are made to accruals as claim data and historical experience change. In addition, the Company incurs discretionary costs to service its products in connection with product
performance issues and accrues for them when they are encountered. The Company monitors the actual cost of performing these discretionary services and adjusts the accrual based on the most current information available.
65
The changes in the carrying amount of service and product warranties are as follows (in millions):
|
|
|
|
|
Balance at December 31, 2015
|
|
$
|
244
|
|
|
|
|
|
|
Net provisions for warranties issued during the year
|
|
|
50
|
|
Amounts incurred
|
|
|
(127
|
)
|
Currency translation adjustments and other
|
|
|
5
|
|
|
|
|
|
|
Balance at December 31, 2016
|
|
$
|
172
|
|
|
|
|
|
|
Net provisions for warranties issued during the year
|
|
|
46
|
|
Amounts incurred
|
|
|
(86
|
)
|
Currency translation adjustments and other
|
|
|
3
|
|
|
|
|
|
|
Balance at December 31, 2017
|
|
$
|
135
|
|
|
|
|
|
|
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 Companys 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 Companys 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 $187 million and $209 million at December 31, 2017 and 2016, respectively.
Stock-Based Compensation
Compensation expense for the
Companys stock-based compensation plans is measured using the fair value method required by ASC Topic 718 Compensation Stock Compensation (ASC Topic 718). Under this guidance the fair value of stock option grants
and restricted stock is amortized to expense using the straight-line method over the shorter of the vesting period or the remaining employee service period.
The Company provides compensation benefits to employees and
non-employee
directors under share-based payment
arrangements, including various employee stock option plans.
66
Environmental Liabilities
When environmental assessments or remediations are probable and the costs can be reasonably estimated, remediation liabilities are
recorded on an undiscounted basis and are adjusted as further information develops or circumstances change.
Use of Estimates
The preparation of financial statements
in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect reported and contingent amounts of assets and liabilities as of the date of the financial statements
and reported amounts of revenues and expenses during the reporting period. Such estimates include but are not limited to, estimated losses on accounts receivable, estimated costs and related margins of projects accounted for under
percentage-of-completion,
estimated realizable value on excess and obsolete inventory, contingencies, estimated liabilities for litigation exposures and liquidated damages,
estimated warranty costs, estimates related to pension accounting, estimates related to the fair value of reporting units for purposes of assessing goodwill and other indefinite-lived intangible assets for impairment and estimates related to
deferred tax assets and liabilities, including valuation allowances on deferred tax assets. Actual results could differ from those estimates.
Contingencies
The Company accrues for costs relating to
litigation claims and other contingent matters, including liquidated damage liabilities, when such liabilities become probable and reasonably estimable. In circumstances where the most likely outcome of a contingency can be reasonably estimated, we
accrue a liability for that amount. Where the most likely outcome cannot be estimated, a range of potential losses is established and if no one amount in that range is more likely than others, the low end of the range is accrued. Such estimates may
be based on advice from third parties or on managements 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 Companys 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 Loss 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,
|
|
|
|
2017
|
|
|
2016
|
|
|
2015
|
|
Numerator:
|
|
|
|
|
|
|
|
|
|
|
|
|
Net loss attributable to Company
|
|
$
|
(237
|
)
|
|
$
|
(2,412
|
)
|
|
$
|
(769
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Denominator:
|
|
|
|
|
|
|
|
|
|
|
|
|
Basicweighted average common shares outstanding
|
|
|
377
|
|
|
|
376
|
|
|
|
387
|
|
Dilutive effect of employee stock options and other unvested stock awards
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted outstanding shares
|
|
|
377
|
|
|
|
376
|
|
|
|
387
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic loss attributable to Company per share
|
|
$
|
(0.63
|
)
|
|
$
|
(6.41
|
)
|
|
$
|
(1.99
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted loss attributable to Company per share
|
|
$
|
(0.63
|
)
|
|
$
|
(6.41
|
)
|
|
$
|
(1.99
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash dividends per share
|
|
$
|
0.20
|
|
|
$
|
0.61
|
|
|
$
|
1.84
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
ASC Topic 260, Earnings Per Share (ASC Topic 260) requires companies with unvested participating
securities to utilize a
two-class
method for the computation of net income attributable to Company per share. The
two-class
method requires a portion of net income
attributable to Company to be allocated to participating securities, which are unvested awards of share-based payments with
non-forfeitable
rights to receive dividends or dividend equivalents, if declared. Net
income attributable to Company allocated to these participating securities was immaterial for the years ended December 31, 2017, 2016 and 2015 and therefore not excluded from net income attributable to Company per share calculation. The Company
had stock options outstanding that were anti-dilutive totaling 12 million, 14 million, and 13 million at December 31, 2017, 2016 and 2015, respectively.
67
Recently Adopted Accounting Standards
In July 2015, the FASB issued Accounting Standard Update
No. 2015-11
Simplifying the Measurement of
Inventory (ASU
2015-11).
This update requires inventory measured using the first in, first out (FIFO) or average cost methods to be subsequently measured at the lower of cost and net realizable value.
Net realizable value is the estimated selling price in the ordinary course of business, less reasonably predictable cost of completion, disposal and transportation. ASU
2015-11
is effective for fiscal
years beginning after December 15, 2016, and for interim periods within those fiscal years. The Company adopted this update on January 1, 2017 with no material impact.
In March 2016, the FASB issued Accounting Standard Update
No. 2016-09
Improvements to Employee Share-Based
Payment Accounting (ASU
2016-09).
This update simplifies several aspects of accounting for share-based payment transactions, including the income tax consequences, forfeitures, and the classification on
the statement of cash flows. ASU
2016-09
is effective for fiscal periods beginning after December 15, 2016, and for interim periods within those fiscal years. The Company adopted this update on
January 1, 2017. The cumulative impact of the adoption of this standard was $1 million to retained earnings, and the classification on the statement of cash flows was applied on a prospective basis.
In October 2016, the FASB issued Accounting Standard Update
No. 2016-16
Intra-Entity Transfers of Assets
Other Than Inventory (ASU
2016-16).
This update requires an entity to recognize the income tax consequences of an intra-entity transfer of an asset other than inventory when the transfer occurs. ASU
2016-16
is effective for fiscal years beginning after December 15, 2017, and for interim reporting periods within those fiscal years. The Company has early adopted this update on January 1, 2017 and
recorded a $5 million reduction to retained earnings and receivables. The effect of the change on net income is not significant.
In January 2017,
the FASB issued Accounting Standard Update
No. 2017-04
Simplifying the Test for Goodwill Impairment (ASU
2017-04).
This update eliminates the
requirement to compute the implied fair value of goodwill under Step 2 of the goodwill impairment test. ASU
2017-04
is effective for fiscal periods beginning after December 15, 2019. Early adoption is
permitted for interim or annual goodwill impairment tests performed on testing dates after January 1, 2017. The Company has early adopted this update on July 1, 2017 with no material impact.
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 is
currently assessing the impact of the adoption of ASU
No. 2017-12
on its consolidated financial position and results of operations.
In March 2017, the FASB issued Accounting Standard Update
No. 2017-07
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 other 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 does
not expect the impact of the adoption of ASU
No. 2017-07
to have a material impact on its consolidated financial position.
In August 2016, the FASB issued Accounting Standard Update
No. 2016-15
Classification of Certain Cash
Receipts and Cash Payments (ASU
2016-15).
This update amends Accounting Standard Codification Topic No. 230 Statement of Cash Flows and provides guidance and clarification on
presentation of certain cash flow issues. ASU
No. 2016-15
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. 2016-15
on its consolidated statement of cash flows.
In
March 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.
In preparing for the
adoption of this new standard, the Company has established an internal team to centralize the implementation process as well as engaged external resources to assist in our approach. We are currently utilizing a software program to consolidate and
accumulate leases with documentation as required by the new standard. We have assessed the changes to the Companys current accounting practices and are currently investigating the related tax impact and process changes. We are also
in the process of quantifying the impact of the new standard on our balance sheet.
68
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 recognized. 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.
The standard permits either a full retrospective adoption, in which the standard is
applied to all the periods presented, or a modified retrospective adoption, in which the standard is applied only to the current period with a cumulative-effect adjustment reflected in retained earnings. ASU
2014-09
is effective for fiscal periods beginning after December 15, 2017. The Company will follow the modified retrospective adoption.
In 2015, the Company assembled an internal team to study the provisions of ASU
2014-09,
began assessing the potential
impacts on the Company and educating the organization. In 2016, the Company engaged external resources to complete the assessment of potential changes to current accounting practices related to material revenue streams. Potential impacts
were identified based on required changes to current processes to accommodate provisions in the new standard. We have designed and implemented process, system, control and data requirement changes to address the impacts identified in our
assessments.
Based on an analysis of revenue streams, customer contracts and transactions, the Company does not expect a material change in the timing or
other impacts to revenue recognition across most of our businesses. Certain service and repair revenue will change from point-in-time to over-time revenue recognition, and the timing of including uninstalled materials in projects will shift,
changing only the timing of revenue recognition and not the total amount. We expect the cumulative-effect adjustment we will record in the first quarter of 2018, as required by the modified retrospective method, to be less than $50 million. The
final adjustment is subject to concluding on the available practical expediants.
69
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, 2017, the Company has determined that the fair value of its derivative financial instruments representing assets of $33 million and liabilities of $11 million (primarily currency related derivatives) are determined using
level 2 inputs (inputs other than quoted prices in active markets for identical assets and liabilities that are observable either directly or indirectly for substantially the full term of the asset or liability) in the fair value hierarchy as the
fair value is based on publicly available foreign exchange and interest rates at each financial reporting date. At December 31, 2017, the net fair value of the Companys foreign currency forward contracts totaled a net asset of
$22 million.
At December 31, 2017, the Companys financial instruments do not contain any credit-risk-related or other contingent features
that could cause accelerated payments when the Companys 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
|
|
Foreign Currency
|
|
December 31,
2017
|
|
|
December 31,
2016
|
|
Norwegian Krone
|
|
NOK
|
4,013
|
|
|
NOK
|
5,621
|
|
Japanese Yen
|
|
JPY
|
982
|
|
|
JPY
|
1,462
|
|
U.S. Dollar
|
|
USD
|
163
|
|
|
USD
|
321
|
|
Euro
|
|
EUR
|
120
|
|
|
EUR
|
279
|
|
Danish Krone
|
|
DKK
|
30
|
|
|
DKK
|
29
|
|
British Pound Sterling
|
|
GBP
|
11
|
|
|
GBP
|
1
|
|
Singapore Dollar
|
|
SGD
|
|
|
|
SGD
|
2
|
|
70
Non-designated
Hedging Strategy
The Company enters into forward exchange contracts to hedge certain nonfunctional currency monetary accounts. The purpose of the Companys 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 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
|
|
Foreign Currency
|
|
December 31,
2017
|
|
|
December 31,
2016
|
|
Russian Ruble
|
|
RUB
|
2,699
|
|
|
RUB
|
1,893
|
|
Norwegian Krone
|
|
NOK
|
1,734
|
|
|
NOK
|
538
|
|
U.S. Dollar
|
|
USD
|
463
|
|
|
USD
|
457
|
|
South African Rand
|
|
ZAR
|
150
|
|
|
ZAR
|
150
|
|
Euro
|
|
EUR
|
99
|
|
|
EUR
|
272
|
|
Danish Krone
|
|
DKK
|
15
|
|
|
DKK
|
49
|
|
British Pound Sterling
|
|
GBP
|
3
|
|
|
GBP
|
3
|
|
Singapore Dollar
|
|
SGD
|
|
|
|
SGD
|
7
|
|
Canadian Dollar
|
|
CAD
|
|
|
|
CAD
|
1
|
|
71
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
|
|
Fair Value
December 31,
|
|
|
Balance Sheet
|
|
Fair Value
December 31,
|
|
|
|
Location
|
|
2017
|
|
|
2016
|
|
|
Location
|
|
2017
|
|
|
2016
|
|
Derivatives designated as hedging instruments under ASC Topic 815
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Foreign exchange contracts
|
|
Prepaid and other current assets
|
|
$
|
13
|
|
|
$
|
24
|
|
|
Accrued liabilities
|
|
$
|
3
|
|
|
$
|
37
|
|
Foreign exchange contracts
|
|
Other Assets
|
|
|
8
|
|
|
|
6
|
|
|
Other Liabilities
|
|
|
2
|
|
|
|
11
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total derivatives designated as hedging instruments under ASC Topic 815
|
|
|
|
$
|
21
|
|
|
$
|
30
|
|
|
|
|
$
|
5
|
|
|
$
|
48
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivatives not designated as hedging instruments under ASC Topic 815
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Foreign exchange contracts
|
|
Prepaid and other current assets
|
|
$
|
10
|
|
|
$
|
32
|
|
|
Accrued liabilities
|
|
$
|
5
|
|
|
$
|
29
|
|
Foreign exchange contracts
|
|
Other Assets
|
|
|
2
|
|
|
|
|
|
|
Other Liabilities
|
|
|
1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total derivatives not designated as hedging instruments under ASC Topic 815
|
|
|
|
$
|
12
|
|
|
$
|
32
|
|
|
|
|
$
|
6
|
|
|
$
|
29
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total derivatives
|
|
|
|
$
|
33
|
|
|
$
|
62
|
|
|
|
|
$
|
11
|
|
|
$
|
77
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The Effect of Derivative Instruments on the Consolidated Statements of Income (Loss)
($ in millions)
|
|
Derivatives Designated as
Hedging Instruments under
ASC Topic 815
|
|
Amount of Gain (Loss)
Recognized in OCI on
Derivatives (Effective Portion) (a)
|
|
|
Location of Gain (Loss)
Reclassified from
Accumulated OCI into
Income
(Effective Portion)
|
|
Amount of Gain (Loss)
Reclassified from
Accumulated OCI into
Income (Effective Portion)
|
|
|
Location of Gain (Loss)
Recognized in Income on
Derivatives (Ineffective
Portion and Amount
Excluded
from
Effectiveness
Testing)
|
|
Amount of Gain (Loss)
Recognized in Income on
Derivatives (Ineffective
Portion and Amount
Excluded from
Effectiveness
Testing) (b)
|
|
|
|
Years Ended
December 31,
|
|
|
|
|
Years Ended
December 31,
|
|
|
|
|
Years Ended
December 31,
|
|
|
|
2017
|
|
|
2016
|
|
|
|
|
2017
|
|
|
2016
|
|
|
|
|
2017
|
|
|
2016
|
|
|
|
|
|
|
|
|
|
|
|
Revenue
|
|
|
8
|
|
|
|
5
|
|
|
Cost of revenue
|
|
|
7
|
|
|
|
(21
|
)
|
Foreign exchange contracts
|
|
|
56
|
|
|
|
45
|
|
|
Cost of
revenue
|
|
|
(19
|
)
|
|
|
(170
|
)
|
|
Other income
(expense), net
|
|
|
2
|
|
|
|
8
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
56
|
|
|
|
45
|
|
|
|
|
|
(11
|
)
|
|
|
(165
|
)
|
|
|
|
|
9
|
|
|
|
(13
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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,
|
|
|
|
|
|
|
2017
|
|
|
2016
|
|
Foreign exchange contracts
|
|
|
Other income (expense), net
|
|
|
|
58
|
|
|
|
(33
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
|
|
|
58
|
|
|
|
(33
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a)
|
The Company expects that $5 million of the Accumulated Other Comprehensive Income (Loss) will be reclassified into earnings within the next twelve months with an offset by losses from the underlying transactions
resulting in no impact to earnings or cash flow.
|
(b)
|
The amount of gain (loss) recognized in income represents $7 million and $(21) million related to the ineffective portion of the hedging relationships for the years ended December 31, 2017 and 2016,
respectively, and $2 million and $8 million related to the amount excluded from the assessment of the hedge effectiveness for the years ended December 31, 2017 and 2016, respectively.
|
72
4. Acquisitions and Investments
2017
In the year ended December 31, 2017, the
Company completed a total of eight acquisitions and other investments for an aggregate cash investment of $86 million, net of cash acquired. The Company has preliminarily allocated $61 million to identifiable intangible assets and
$89 million to goodwill for current and prior year acquisitions.
2016
In the year ended December 31, 2016, the Company completed a total of 10 acquisitions and other investments for an aggregate cash investment of
$230 million, net of cash acquired and $18 million of NOV stock. The Company allocated $24 million to identifiable intangible assets and $74 million to goodwill.
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 allocated $13 million to identifiable intangible assets and $51 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. 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 (Loss) from the date of acquisition. A summary of the acquisitions follows (in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2017
|
|
|
2016
|
|
|
2015
|
|
Fair value of assets acquired, net of cash acquired
|
|
$
|
154
|
|
|
$
|
357
|
|
|
$
|
116
|
|
Cash paid, net of cash acquired
|
|
|
(86
|
)
|
|
|
(230
|
)
|
|
|
(86
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities assumed, debt issued and noncontrolling interest
|
|
$
|
68
|
|
|
$
|
127
|
|
|
$
|
30
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Excess purchase price over fair value of net assets acquired
|
|
$
|
89
|
|
|
$
|
74
|
|
|
$
|
51
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
5. Inventories, net
Inventories consist of (in millions):
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2017
|
|
|
2016
|
|
Raw materials and supplies
|
|
$
|
656
|
|
|
$
|
961
|
|
Work in process
|
|
|
513
|
|
|
|
561
|
|
Finished goods and purchased products
|
|
|
1,834
|
|
|
|
1,803
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
3,003
|
|
|
$
|
3,325
|
|
|
|
|
|
|
|
|
|
|
73
6. Property, Plant and Equipment
Property, plant and equipment consist of (in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
Estimated
Useful Lives
|
|
December 31,
|
|
|
|
|
2017
|
|
|
2016
|
|
Land and buildings
|
|
5-35 Years
|
|
$
|
1,592
|
|
|
$
|
1,570
|
|
Operating equipment
|
|
3-15
Years
|
|
|
3,169
|
|
|
|
3,102
|
|
Rental equipment
|
|
3-12
Years
|
|
|
581
|
|
|
|
557
|
|
Capital leases
|
|
20-24 Years
|
|
|
219
|
|
|
|
219
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
5,561
|
|
|
|
5,448
|
|
Less: Accumulated Depreciation
|
|
|
|
|
(2,559
|
)
|
|
|
(2,298
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
3,002
|
|
|
$
|
3,150
|
|
|
|
|
|
|
|
|
|
|
|
|
7. Accrued Liabilities
Accrued liabilities consist of (in millions):
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2017
|
|
|
2016
|
|
Vendor costs
|
|
$
|
150
|
|
|
$
|
235
|
|
Customer prepayments and billings
|
|
|
240
|
|
|
|
222
|
|
Compensation
|
|
|
345
|
|
|
|
181
|
|
Taxes (non income)
|
|
|
152
|
|
|
|
176
|
|
Warranty
|
|
|
135
|
|
|
|
172
|
|
Insurance
|
|
|
74
|
|
|
|
103
|
|
Fair value of derivatives
|
|
|
8
|
|
|
|
66
|
|
Commissions
|
|
|
58
|
|
|
|
57
|
|
Interest
|
|
|
7
|
|
|
|
8
|
|
Other
|
|
|
309
|
|
|
|
348
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
1,478
|
|
|
$
|
1,568
|
|
|
|
|
|
|
|
|
|
|
8. Costs and Estimated Earnings on Uncompleted Contracts
Costs and estimated earnings on uncompleted contracts consist of (in millions):
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2017
|
|
|
2016
|
|
Costs incurred on uncompleted contracts
|
|
$
|
6,395
|
|
|
$
|
8,132
|
|
Estimated earnings
|
|
|
3,023
|
|
|
|
3,869
|
|
|
|
|
|
|
|
|
|
|
|
|
|
9,418
|
|
|
|
12,001
|
|
Less: Billings to date on uncompleted contracts
|
|
|
9,202
|
|
|
|
11,776
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
216
|
|
|
$
|
225
|
|
|
|
|
|
|
|
|
|
|
Costs and estimated earnings in excess of billings on uncompleted contracts
|
|
$
|
495
|
|
|
$
|
665
|
|
Billings in excess of costs and estimated earnings on uncompleted contracts
|
|
|
(279
|
)
|
|
|
(440
|
)
|
|
|
|
|
|
|
|
|
|
|
|
$
|
216
|
|
|
$
|
225
|
|
|
|
|
|
|
|
|
|
|
74
9. Debt
Debt consists of (in millions):
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2017
|
|
|
2016
|
|
$500 million in Senior Notes, interest at 1.35% payable semiannually, principal due on
December 1, 2017
|
|
|
|
|
|
|
499
|
|
|
|
|
$1.4 billion in Senior Notes, interest at 2.60% payable semiannually, principal due on
December 1, 2022
|
|
|
1,392
|
|
|
|
1,391
|
|
|
|
|
$1.1 billion in Senior Notes, interest at 3.95% payable semiannually, principal due
on December 1, 2042
|
|
|
1,088
|
|
|
|
1,087
|
|
|
|
|
Capital Leases and other debt
|
|
|
232
|
|
|
|
237
|
|
|
|
|
|
|
|
|
|
|
Total debt
|
|
|
2,712
|
|
|
|
3,214
|
|
Less current portion
|
|
|
6
|
|
|
|
506
|
|
|
|
|
|
|
|
|
|
|
Long-term debt
|
|
$
|
2,706
|
|
|
$
|
2,708
|
|
|
|
|
|
|
|
|
|
|
Principal payments of debt and capital leases for years subsequent to 2017 are as follows (in millions):
|
|
|
|
|
2018
|
|
$
|
6
|
|
2019
|
|
|
5
|
|
2020
|
|
|
5
|
|
2021
|
|
|
5
|
|
2022
|
|
|
1,405
|
|
Thereafter
|
|
|
1,286
|
|
|
|
|
|
|
|
|
$
|
2,712
|
|
|
|
|
|
|
See Note 12 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 Companys 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, 2017, the Company was in compliance with a
debt-to-capitalization
ratio of 16.1%.
On November 29, 2017, the Company repaid in its entirety the $500 million of its 1.35% unsecured Senior Notes using available cash balances.
The Company has a commercial paper program under which borrowings are classified as long-term since the program is supported by the $3.0 billion,
five-year credit facility. At December 31, 2017, there were no commercial paper borrowings, and there were no outstanding letters of credit issued under the credit facility, resulting in $3.0 billion of funds available under this credit
facility.
The Company had $658 million of outstanding letters of credit at December 31, 2017, primarily in the U.S. and Norway, that are under
various bilateral committed letter of credit facilities. Letters of credit are issued as bid bonds, advanced payment bonds and performance bonds.
At
December 31, 2017 and 2016, the fair value of the Companys unsecured Senior Notes approximated $2,346 million and $2,669 million, respectively. The fair value of the Companys 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, 2017 and 2016, the carrying value of the Companys unsecured Senior Notes approximated $2,480 million and
$2,977 million, respectively.
75
10. Employee Benefit Plans
We have benefit plans covering substantially all of our employees. Defined-contribution benefit plans cover most of the U.S. and Canadian employees, and
benefits are based on years of service, a percentage of current earnings and matching of employee contributions. We also have defined contribution plans in Norway and the United Kingdom. For the years ended December 31, 2017, 2016 and 2015,
expenses for defined-contribution plans were $64 million, $66 million, and $95 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 40 employees represented by certain collective bargaining agreements continue to accrue benefits under the
plan. In addition, approximately 1,950 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.
During 2016, the Company settled its Norway defined benefit plan and transferred all participants to the defined-contribution plan. The impact on
the defined benefit plans is reflected in the table below.
Net periodic benefit cost for our defined benefit plans aggregated $1 million,
$5 million and $5 million for the years ended December 31, 2017, 2016 and 2015, 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,
2017 and 2016, is as follows (in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pension benefits
|
|
|
Postretirement benefits
|
|
At year end
|
|
2017
|
|
|
2016
|
|
|
2017
|
|
|
2016
|
|
Benefit obligation at beginning of year
|
|
$
|
622
|
|
|
$
|
703
|
|
|
$
|
92
|
|
|
$
|
90
|
|
Service cost
|
|
|
1
|
|
|
|
5
|
|
|
|
|
|
|
|
|
|
Interest cost
|
|
|
20
|
|
|
|
25
|
|
|
|
3
|
|
|
|
3
|
|
Actuarial loss (gain)
|
|
|
6
|
|
|
|
42
|
|
|
|
(17
|
)
|
|
|
(29
|
)
|
Benefits paid
|
|
|
(31
|
)
|
|
|
(30
|
)
|
|
|
(14
|
)
|
|
|
(16
|
)
|
Participants contributions
|
|
|
|
|
|
|
|
|
|
|
2
|
|
|
|
2
|
|
Exchange rate loss (gain)
|
|
|
30
|
|
|
|
(37
|
)
|
|
|
|
|
|
|
|
|
Acquisitions (disposals)
|
|
|
|
|
|
|
2
|
|
|
|
|
|
|
|
|
|
Curtailments
|
|
|
|
|
|
|
(17
|
)
|
|
|
(4
|
)
|
|
|
|
|
Settlements
|
|
|
(15
|
)
|
|
|
(71
|
)
|
|
|
|
|
|
|
|
|
Other
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
42
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Benefit obligation at end of year
|
|
$
|
633
|
|
|
$
|
622
|
|
|
$
|
62
|
|
|
$
|
92
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair value of plan assets at beginning of year
|
|
$
|
543
|
|
|
$
|
601
|
|
|
$
|
|
|
|
$
|
|
|
Actual return
|
|
|
57
|
|
|
|
60
|
|
|
|
|
|
|
|
|
|
Benefits paid
|
|
|
(31
|
)
|
|
|
(30
|
)
|
|
|
(14
|
)
|
|
|
(16
|
)
|
Company contributions
|
|
|
11
|
|
|
|
16
|
|
|
|
12
|
|
|
|
14
|
|
Participants contributions
|
|
|
|
|
|
|
|
|
|
|
2
|
|
|
|
2
|
|
Exchange rate gain (loss)
|
|
|
24
|
|
|
|
(34
|
)
|
|
|
|
|
|
|
|
|
Settlements
|
|
|
(15
|
)
|
|
|
(71
|
)
|
|
|
|
|
|
|
|
|
Acquisitions (disposals)
|
|
|
|
|
|
|
1
|
|
|
|
|
|
|
|
|
|
Other
|
|
|
(1
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair value of plan assets at end of year
|
|
$
|
588
|
|
|
$
|
543
|
|
|
$
|
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Funded status
|
|
$
|
(45
|
)
|
|
$
|
(79
|
)
|
|
$
|
(62
|
)
|
|
$
|
(92
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated benefit obligation at end of year
|
|
$
|
630
|
|
|
$
|
617
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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.
76
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,
|
|
|
2017
|
|
2016
|
Discount rate:
|
|
|
|
|
United States plan
|
|
3.00% - 3.60%
|
|
3.10% - 4.00%
|
International plans
|
|
1.80% - 2.40%
|
|
1.80% - 2.80%
|
|
|
|
Salary increase:
|
|
|
|
|
United States plan
|
|
N/A
|
|
N/A
|
International plans
|
|
1.80% - 3.30%
|
|
1.80% - 3.50%
|
The assumption rates used for net periodic benefit costs are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2017
|
|
|
2016
|
|
|
2015
|
|
Discount rate:
|
|
|
|
|
|
|
|
|
|
|
|
|
United States plan
|
|
|
3.10% - 4.00%
|
|
|
|
3.20% - 4.20%
|
|
|
|
3.70% - 4.20%
|
|
International plans
|
|
|
1.80% - 2.80%
|
|
|
|
2.20% - 3.70%
|
|
|
|
2.20% - 3.70%
|
|
|
|
|
|
Salary increase:
|
|
|
|
|
|
|
|
|
|
|
|
|
United States plan
|
|
|
N/A
|
|
|
|
N/A
|
|
|
|
N/A
|
|
International plans
|
|
|
1.80% - 3.50%
|
|
|
|
2.00% - 4.20%
|
|
|
|
2.00% - 4.20%
|
|
|
|
|
|
Expected return on assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
United States plan
|
|
|
5.60%
|
|
|
|
5.60%
|
|
|
|
5.50%
|
|
International plans
|
|
|
1.80% - 3.00%
|
|
|
|
1.80% - 3.00%
|
|
|
|
2.30% - 5.12%
|
|
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 $33 million for each of the next five years and aggregate
payments of $324 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 Companys 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.
77
The following table sets forth by level, within the fair value hierarchy, the Plans assets carried at fair
value (in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value Measurements
|
|
|
|
Total
|
|
|
Level 1
|
|
|
Level 2
|
|
|
Level 3
|
|
December 31, 2016:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity securities
|
|
$
|
181
|
|
|
$
|
|
|
|
$
|
181
|
|
|
$
|
|
|
Bonds
|
|
|
262
|
|
|
|
|
|
|
|
262
|
|
|
|
|
|
Other (insurance contracts)
|
|
|
100
|
|
|
|
|
|
|
|
47
|
|
|
|
53
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Fair Value Measurements
|
|
$
|
543
|
|
|
$
|
|
|
|
$
|
490
|
|
|
$
|
53
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2017:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity securities
|
|
$
|
161
|
|
|
$
|
|
|
|
$
|
161
|
|
|
$
|
|
|
Bonds
|
|
|
284
|
|
|
|
|
|
|
|
284
|
|
|
|
|
|
Other (insurance contracts)
|
|
|
143
|
|
|
|
|
|
|
|
82
|
|
|
|
61
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Fair Value Measurements
|
|
$
|
588
|
|
|
$
|
|
|
|
$
|
527
|
|
|
$
|
61
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Level 3 inputs are unobservable (i.e., supported by little or no market activity). Level 3 inputs include
managements 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 Plans
Level 3 assets (in millions):
|
|
|
|
|
|
|
Level 3
Plan
Assets
|
|
Balance at December 31, 2015
|
|
$
|
99
|
|
|
|
|
|
|
Actual return on plan assets still held at reporting date
|
|
|
5
|
|
Purchases, sales and settlements
|
|
|
(50
|
)
|
Currency translation adjustments
|
|
|
(1
|
)
|
|
|
|
|
|
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
|
|
|
|
|
|
|
78
11. Accumulated Other Comprehensive Income (Loss)
The components of accumulated other comprehensive income (loss) are as follows (in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Currency
Translation
Adjustments
|
|
|
Derivative
Financial
Instruments,
Net of Tax
|
|
|
Defined
Benefit
Plans,
Net of Tax
|
|
|
Total
|
|
Balance at December 31, 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
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The components of amounts reclassified from accumulated other comprehensive income (loss) are as follows (in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2017
|
|
|
2016
|
|
|
2015
|
|
|
|
Currency
Translation
Adjustments
|
|
|
Derivative
Financial
Instruments
|
|
|
Defined
Benefit
Plans
|
|
|
Total
|
|
|
Currency
Translation
Adjustments
|
|
|
Derivative
Financial
Instruments
|
|
|
Defined
Benefit
Plans
|
|
|
Total
|
|
|
Currency
Translation
Adjustments
|
|
|
Derivative
Financial
Instruments
|
|
|
Defined
Benefit
Plans
|
|
|
Total
|
|
Revenue
|
|
$
|
|
|
|
$
|
(8
|
)
|
|
$
|
|
|
|
$
|
(8
|
)
|
|
$
|
|
|
|
$
|
(5
|
)
|
|
$
|
|
|
|
$
|
(5
|
)
|
|
$
|
|
|
|
$
|
(19
|
)
|
|
$
|
|
|
|
$
|
(19
|
)
|
Cost of revenue
|
|
|
|
|
|
|
12
|
|
|
|
|
|
|
|
12
|
|
|
|
|
|
|
|
191
|
|
|
|
|
|
|
|
191
|
|
|
|
|
|
|
|
295
|
|
|
|
|
|
|
|
295
|
|
Selling, general, and administrative
|
|
|
|
|
|
|
|
|
|
|
(1
|
)
|
|
|
(1
|
)
|
|
|
|
|
|
|
|
|
|
|
(5
|
)
|
|
|
(5
|
)
|
|
|
|
|
|
|
|
|
|
|
(6
|
)
|
|
|
(6
|
)
|
Tax effect
|
|
|
|
|
|
|
1
|
|
|
|
|
|
|
|
1
|
|
|
|
|
|
|
|
(52
|
)
|
|
|
2
|
|
|
|
(50
|
)
|
|
|
|
|
|
|
(77
|
)
|
|
|
2
|
|
|
|
(75
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
|
|
|
$
|
5
|
|
|
$
|
(1
|
)
|
|
$
|
4
|
|
|
$
|
|
|
|
$
|
134
|
|
|
$
|
(3
|
)
|
|
$
|
131
|
|
|
$
|
|
|
|
$
|
199
|
|
|
$
|
(4
|
)
|
|
$
|
195
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The Companys reporting currency is the U.S. dollar. A majority of the Companys international entities in which
there is a substantial investment have the local currency as their functional currency. As a result, currency translation adjustments resulting from the process of translating the entities financial statements into the reporting currency are
reported in other comprehensive income or loss in accordance with ASC Topic 830 Foreign Currency Matters (ASC Topic 830). For the year ended December 31, 2017, a majority of these local currencies strengthened against
the U.S. dollar, resulting in net other comprehensive income of $272 million upon the translation from local currencies to the U.S. dollar. For the years ended December 31, 2016 and 2015, a majority of these local currencies weakened
against the U.S. dollar, resulting in a net other comprehensive loss of $97 million and $764 million, respectively, upon the translation from local currencies to the U.S. dollar.
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 of $46 million (net of tax of $13
million) for the year ended December 31, 2017, other comprehensive income of $166 million (net of tax of $65 million) for the year ended December 31, 2016 and other comprehensive income of $23 million (net of tax of $14 million)
for the year ended December 31, 2015.
79
12. 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. 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.
In November 2016, the
Company executed documents following a 2009-2010 internal investigation settling with U.S. governmental agencies related to our compliance with U.S. export trade laws and regulations. As anticipated, the administrative fines and penalties agreed to
as part of a resolution were within established accruals, and had no material effect on our financial position or results of operations. The investigation and settlement are now closed.
The Company is 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 Companys 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 Companys 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, 2017, the Company recorded reserves in an amount
believed to be sufficient for contingent liabilities representing all contingencies believed to be probable to cover liabilities. 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. These estimated liabilities are based on the Companys assessment of the nature of these matters, their progress toward resolution,
the advice of legal counsel and outside experts as well as managements intention and experience.
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 have 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 have executed settlements with several shipyard customers since December 28, 2015 concerning 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 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. The investigations in Brazil have led to, 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 remaining supply contracts, and could result in additional cancellations 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. In 2016, in light of the vote by the shareholders of SETE Brasil Participacoes SA to authorize Sete to file for bankruptcy, and a further decline in drilling activity
during the first half of the year to record lows and the resulting effect on certain other customers, the Company removed $2.1 billion (unaudited) of orders from its backlog in the first quarter of 2016. Some of the contracts for these orders remain
in place and are enforceable. If these customers obtain funding to continue their projects, the Company will pursue resumption of construction and update the backlog accordingly.
In other instances, 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. 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. While we manage equipment deliveries and collection of payment to 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.
80
The Company leases certain facilities and equipment under operating leases that expire at various dates through
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
$209 million, $246 million, and $327 million in 2017, 2016 and 2015, 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, 2017, are payable as follows (in millions):
|
|
|
|
|
|
|
|
|
|
|
Capital Lease
Payments
|
|
|
Operating Lease
Payments
|
|
2018
|
|
$
|
15
|
|
|
$
|
130
|
|
2019
|
|
|
15
|
|
|
|
98
|
|
2020
|
|
|
15
|
|
|
|
82
|
|
2021
|
|
|
15
|
|
|
|
67
|
|
2022
|
|
|
15
|
|
|
|
55
|
|
Thereafter
|
|
|
273
|
|
|
|
339
|
|
|
|
|
|
|
|
|
|
|
Total future lease commitments
|
|
$
|
348
|
|
|
$
|
771
|
|
|
|
|
|
|
|
|
|
|
81
13. 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 $76 million and $230 million for the years ended
December 31, 2017 and 2016, respectively. The declaration and payment of future dividends is at the discretion of the Companys Board of Directors and will be dependent upon the Companys results of operations, financial condition,
capital requirements and other factors deemed relevant by the Companys Board of Directors.
Total compensation cost that has been charged against
income for all share-based compensation arrangements was $124 million, $107 million and $109 million for 2017, 2016 and 2015, respectively. The total income tax benefit recognized in the consolidated statements of income for all
share-based compensation arrangements was $24 million, $30 million and $32 million for 2017, 2016 and 2015, respectively.
Under the terms
of National Oilwell Varcos Long-Term Incentive Plan, as amended during the second quarter of 2016, 69.4 million shares of common stock are authorized for the grant of options to officers, key employees,
non-employee
directors and other persons. 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 Plan is now 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. At December 31, 2017, approximately 17.8 million shares were available for 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.
We also have an inactive stock option plan that was acquired in connection with the acquisition of Grant Prideco in 2008. We
converted the outstanding stock options under this plan to options to acquire our common stock and no further options are being issued under 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, 2017 under the stock option plans have exercise prices between $23.94 and $77.99 per share, and expire at various dates from February 8,
2018 to April 1, 2027.
The following summarizes options activity:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2017
|
|
|
2016
|
|
|
2015
|
|
|
|
Number
|
|
|
Average
|
|
|
Number
|
|
|
Average
|
|
|
Number
|
|
|
Average
|
|
|
|
of
|
|
|
Exercise
|
|
|
of
|
|
|
Exercise
|
|
|
of
|
|
|
Exercise
|
|
|
|
Shares
|
|
|
Price
|
|
|
Shares
|
|
|
Price
|
|
|
Shares
|
|
|
Price
|
|
Shares under option at beginning of year
|
|
|
17,439,060
|
|
|
$
|
54.08
|
|
|
|
15,430,307
|
|
|
$
|
59.50
|
|
|
|
10,881,133
|
|
|
$
|
61.22
|
|
Granted
|
|
|
6,961,041
|
|
|
|
36.51
|
|
|
|
3,672,411
|
|
|
|
28.26
|
|
|
|
5,746,153
|
|
|
|
54.74
|
|
Forfeited
|
|
|
(1,482,531
|
)
|
|
|
55.22
|
|
|
|
(1,517,065
|
)
|
|
|
49.95
|
|
|
|
(886,356
|
)
|
|
|
62.73
|
|
Exercised
|
|
|
(445,523
|
)
|
|
|
29.83
|
|
|
|
(146,593
|
)
|
|
|
28.53
|
|
|
|
(310,623
|
)
|
|
|
22.56
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Shares under option at end of year
|
|
|
22,472,047
|
|
|
$
|
48.99
|
|
|
|
17,439,060
|
|
|
$
|
54.08
|
|
|
|
15,430,307
|
|
|
$
|
59.50
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exercisable at end of year
|
|
|
14,309,944
|
|
|
$
|
55.00
|
|
|
|
9,828,897
|
|
|
$
|
61.56
|
|
|
|
7,498,414
|
|
|
$
|
60.30
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
82
The following summarizes information about stock options outstanding at December 31, 2017:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted-Avg
|
|
|
Options Outstanding
|
|
|
Options Exercisable
|
|
|
|
Remaining
|
|
|
|
|
|
Weighted-Avg
|
|
|
|
|
|
Weighted-Avg
|
|
Range of Exercise Price
|
|
Contractual Life
|
|
|
Shares
|
|
|
Exercise Price
|
|
|
Shares
|
|
|
Exercise Price
|
|
$23.94 - $55.00
|
|
|
7.55
|
|
|
|
15,797,683
|
|
|
$
|
40.25
|
|
|
|
7,635,580
|
|
|
$
|
42.19
|
|
$55.01 - $70.00
|
|
|
5.09
|
|
|
|
4,301,953
|
|
|
|
66.20
|
|
|
|
4,301,953
|
|
|
|
66.20
|
|
$70.01 - $77.99
|
|
|
3.59
|
|
|
|
2,372,411
|
|
|
|
75.94
|
|
|
|
2,372,411
|
|
|
|
75.94
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
6.66
|
|
|
|
22,472,047
|
|
|
$
|
48.99
|
|
|
|
14,309,944
|
|
|
$
|
55.00
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The weighted-average fair value of options granted during 2017, 2016 and 2015, was approximately $9.68, $6.44 and $15.41 per
share, respectively, as determined using the Black-Scholes option-pricing model. The total intrinsic value of options exercised during 2017 and 2016 was $13 million and $4 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 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,
|
|
|
|
2017
|
|
|
2016
|
|
|
2015
|
|
Valuation Assumptions:
|
|
|
|
|
|
|
|
|
|
|
|
|
Expected volatility
|
|
|
36.1
|
%
|
|
|
48.6
|
%
|
|
|
49.1
|
%
|
Risk-free interest rate
|
|
|
2.2
|
%
|
|
|
1.2
|
%
|
|
|
1.5
|
%
|
Expected dividend yield
|
|
|
0.6
|
%
|
|
|
6.5
|
%
|
|
|
3.4
|
%
|
Expected term (in years)
|
|
|
3.0
|
|
|
|
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. Forfeitures are
accounted for as they occur.
The following summary presents information regarding outstanding options at December 31, 2017 and changes during 2017
with regard to options under all stock option plans:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
|
|
|
|
Weighted-
Average
|
|
|
Remaining
Contractual
|
|
|
|
|
|
|
Shares
|
|
|
Exercise
Price
|
|
|
Term
(years)
|
|
|
Aggregate
Intrinsic Value
|
|
Outstanding at December 31, 2016
|
|
|
17,439,060
|
|
|
$
|
54.08
|
|
|
|
5.42
|
|
|
$
|
6,700,856
|
|
Granted
|
|
|
6,961,041
|
|
|
$
|
36.51
|
|
|
|
|
|
|
|
|
|
Forfeited
|
|
|
(1,482,531
|
)
|
|
$
|
55.22
|
|
|
|
|
|
|
|
|
|
Exercised
|
|
|
(445,523
|
)
|
|
$
|
29.83
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at December 31, 2017
|
|
|
22,472,047
|
|
|
$
|
48.99
|
|
|
|
6.66
|
|
|
$
|
34,186,368
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exercisable at December 31, 2017
|
|
|
14,309,944
|
|
|
$
|
55.00
|
|
|
|
5.70
|
|
|
$
|
15,557,324
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
83
At December 31, 2017, total unrecognized compensation cost related to nonvested stock options was
$36 million. This cost is expected to be recognized over a weighted-average period of two years. The total fair value of stock options vested in 2017, 2016 and 2015 was approximately $70 million, $61 million and $72 million,
respectively. Cash received from option exercises for 2017, 2016 and 2015 was $13 million, $4 million and $7 million, respectively. The actual tax benefit (expense) realized for the tax deductions from option exercises totaled $(2)
million, nil and $3 million for 2017, 2016 and 2015, 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 Companys 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. As a result of exchanging the 2016 SARs for cash and new stock options, the Company recorded $11 million of compensation expense and an increase of $20 million to additional
paid-in capital in the fourth quarter of 2017.
The following summary presents information regarding outstanding SARs:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2017
|
|
|
2016
|
|
|
|
Number
|
|
|
Average
|
|
|
Number
|
|
|
Average
|
|
|
|
of
|
|
|
Exercise
|
|
|
of
|
|
|
Exercise
|
|
|
|
Shares
|
|
|
Price
|
|
|
Shares
|
|
|
Price
|
|
Shares under SARs at beginning of year
|
|
|
4,341,740
|
|
|
$
|
28.32
|
|
|
|
|
|
|
$
|
|
|
Granted
|
|
|
14,400
|
|
|
|
38.86
|
|
|
|
4,618,400
|
|
|
|
28.32
|
|
Forfeited
|
|
|
(283,822
|
)
|
|
|
28.35
|
|
|
|
(276,660
|
)
|
|
|
28.24
|
|
Exercised
|
|
|
(2,578,629
|
)
|
|
|
34.72
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Shares under SARs at end of year
|
|
|
1,493,689
|
|
|
$
|
28.41
|
|
|
|
4,341,740
|
|
|
$
|
28.32
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exercisable at end of year
|
|
|
75,102
|
|
|
$
|
28.33
|
|
|
|
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31, 2017, there was $16 million of unrecognized compensation expense related to nonvested SARs, which
is expected to be recognized over a weighted-average period of approximately two years. The expense recognized in 2017 and 2016 was $8 million and $20 million, respectively. The liability for cash-settled SARs was $2 million at
December 31, 2017.
Restricted Shares
The
Company issues restricted stock awards and restricted stock units to officers and key employees in addition to stock options. On February 22, 2017, the Company granted 1,504,450 shares of restricted stock and restricted stock units with a fair
value of $38.86 per share; and performance share awards to senior management employees with potential payouts varying from zero to 388,380 shares. The restricted stock and restricted stock units vest on the third anniversary of the date of grant or
in three equal annual installments commencing on the first 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 based entirely on a TSR (total shareholder return) goal. Performance against the TSR goal is determined by comparing the performance of the Companys TSR with the TSR performance of the members of the OSX index for the three-year
performance period.
On May 17, 2017, the Company granted 36,701 restricted stock awards with a fair value of $33.38 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.
84
The following summary presents information regarding outstanding restricted shares:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2017
|
|
|
2016
|
|
|
2015
|
|
|
|
|
|
|
Weighted-
|
|
|
|
|
|
Weighted-
|
|
|
|
|
|
Weighted-
|
|
|
|
Number
|
|
|
Average
|
|
|
Number
|
|
|
Average
|
|
|
Number
|
|
|
Average
|
|
|
|
of
|
|
|
Grant Date
|
|
|
of
|
|
|
Grant Date
|
|
|
of
|
|
|
Grant Date
|
|
|
|
Units
|
|
|
Fair Value
|
|
|
Units
|
|
|
Fair Value
|
|
|
Units
|
|
|
Fair Value
|
|
Nonvested at beginning of year
|
|
|
4,563,983
|
|
|
$
|
41.10
|
|
|
|
1,969,250
|
|
|
$
|
61.53
|
|
|
|
1,569,141
|
|
|
$
|
73.73
|
|
Granted
|
|
|
1,738,589
|
|
|
|
38.74
|
|
|
|
3,384,325
|
|
|
|
31.59
|
|
|
|
954,075
|
|
|
|
53.27
|
|
Vested
|
|
|
(1,018,206
|
)
|
|
|
34.84
|
|
|
|
(565,202
|
)
|
|
|
29.32
|
|
|
|
(405,327
|
)
|
|
|
54.30
|
|
Forfeited
|
|
|
(394,688
|
)
|
|
|
55.22
|
|
|
|
(224,390
|
)
|
|
|
49.95
|
|
|
|
(148,639
|
)
|
|
|
62.73
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nonvested at end of year
|
|
|
4,889,678
|
|
|
$
|
37.04
|
|
|
|
4,563,983
|
|
|
$
|
41.10
|
|
|
|
1,969,250
|
|
|
$
|
61.53
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The weighted-average grant day fair value of restricted stock awards and restricted stock units granted during the years ended
2017, 2016 and 2015 was $38.74, $31.59 and $53.27 per share, respectively. There were 1,018,206; 565,202 and 405,327 restricted stock awards that vested during 2017, 2016 and 2015, respectively. At December 31, 2017, there was approximately
$99 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.
85
14. Income Taxes
On December 22, 2017 the United States enacted significant changes to the U.S. tax law following the passage and signing of H.R.1, An Act to Provide
the Reconciliation Pursuant to Titles II and V of the Concurrent Resolution on the Budget for Fiscal Year 2018 (the Act) (previously known as The Tax Cuts and Jobs Act). The Act reduces the U.S. federal corporate tax
rate from 35% to 21% and requires companies to pay a one-time transition tax on earnings of certain foreign subsidiaries that were previously tax deferred. The Act includes new anti-deferral provisions on Global Intangible Low Taxed Income
(GILTI). Beginning in 2018 these provisions result in incremental taxability of our foreign subsidiaries income in excess of an allowed return on certain tangible property. The FASB has determined that filers have a policy choice to
account for this tax on either a period basis or a deferred tax basis. We are still evaluating the impacts of GILTI on our business model and have not yet made any accounting adjustments or policy decisions regarding this new source of incremental
US taxable income. Due to the timing of the enactment and the complexity involved in applying the provision of the Act, we have made reasonable estimates of the effects and recorded provisional amounts in our financial statement as of
December 31, 2017. As we collect and prepare necessary data, and interpret the Act and any additional guidance issued by the U.S. Treasury Department, the IRS, and other standard-setting bodies, we may make adjustments to the provisional
amounts. 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. Our provisional estimate of the one-time transition tax resulted in no
additional tax expense and has been considered in our disclosure of undistributed earnings. The accounting for the tax effects of the Act will be completed in 2018.
The domestic and foreign components of income (loss) before income taxes were as follows (in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2017
|
|
|
2016
|
|
|
2015
|
|
Domestic
|
|
$
|
(470
|
)
|
|
$
|
(2,095
|
)
|
|
$
|
(1,577
|
)
|
Foreign
|
|
|
78
|
|
|
|
(528
|
)
|
|
|
988
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
(392
|
)
|
|
$
|
(2,623
|
)
|
|
$
|
(589
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The components of the provision for income taxes consisted of (in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2017
|
|
|
2016
|
|
|
2015
|
|
Current:
|
|
|
|
|
|
|
|
|
|
|
|
|
Federal
|
|
$
|
23
|
|
|
$
|
(79
|
)
|
|
$
|
30
|
|
State
|
|
|
1
|
|
|
|
(4
|
)
|
|
|
(58
|
)
|
Foreign
|
|
|
161
|
|
|
|
74
|
|
|
|
464
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current income tax provision
|
|
|
185
|
|
|
|
(9
|
)
|
|
|
436
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred:
|
|
|
|
|
|
|
|
|
|
|
|
|
Federal
|
|
|
(332
|
)
|
|
|
(132
|
)
|
|
|
(41
|
)
|
State
|
|
|
(2
|
)
|
|
|
(7
|
)
|
|
|
(38
|
)
|
Foreign
|
|
|
(7
|
)
|
|
|
(59
|
)
|
|
|
(179
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total deferred income tax provision
|
|
|
(341
|
)
|
|
|
(198
|
)
|
|
|
(258
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total income tax provision
|
|
$
|
(156
|
)
|
|
$
|
(207
|
)
|
|
$
|
178
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
86
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,
|
|
|
|
2017
|
|
|
2016
|
|
|
2015
|
|
Federal income tax at U.S. statutory rate
|
|
$
|
(137
|
)
|
|
$
|
(918
|
)
|
|
$
|
(206
|
)
|
Foreign income tax rate differential
|
|
|
(21
|
)
|
|
|
32
|
|
|
|
(110
|
)
|
Goodwill impairment
|
|
|
|
|
|
|
271
|
|
|
|
462
|
|
Nondeductible expenses
|
|
|
38
|
|
|
|
30
|
|
|
|
66
|
|
Foreign dividends, net of foreign tax credits
|
|
|
(132
|
)
|
|
|
(25
|
)
|
|
|
28
|
|
Tax rate change on timing differences
|
|
|
(245
|
)
|
|
|
(8
|
)
|
|
|
(45
|
)
|
Change in uncertain tax positions
|
|
|
81
|
|
|
|
11
|
|
|
|
69
|
|
Prior years taxes
|
|
|
(26
|
)
|
|
|
(29
|
)
|
|
|
(47
|
)
|
Tax impact on foreign exchange
|
|
|
5
|
|
|
|
(4
|
)
|
|
|
(46
|
)
|
Change in deferred tax valuation allowance
|
|
|
280
|
|
|
|
476
|
|
|
|
15
|
|
Other
|
|
|
1
|
|
|
|
(43
|
)
|
|
|
(8
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total income tax provision
|
|
$
|
(156
|
)
|
|
$
|
(207
|
)
|
|
$
|
178
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The effective tax rate for the year ended December 31, 2017 was 39.8%, compared to 7.9% for 2016. 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. For the year ended December 31, 2016, the impairment of goodwill not deductible for tax purposes, lower tax rates on losses incurred in foreign jurisdictions, and the establishment of valuation allowances, when
applied to losses resulted in a lower 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,
|
|
|
|
2017
|
|
|
2016
|
|
Deferred tax assets:
|
|
|
|
|
|
|
|
|
Allowances and operating liabilities
|
|
$
|
355
|
|
|
$
|
534
|
|
Net operating loss carryforwards
|
|
|
182
|
|
|
|
153
|
|
Postretirement benefits
|
|
|
31
|
|
|
|
60
|
|
Tax credit carryforwards
|
|
|
1,002
|
|
|
|
405
|
|
Other
|
|
|
78
|
|
|
|
164
|
|
Valuation allowance
|
|
|
(1,202
|
)
|
|
|
(544
|
)
|
|
|
|
|
|
|
|
|
|
Total deferred tax assets
|
|
|
446
|
|
|
|
772
|
|
|
|
|
|
|
|
|
|
|
Deferred tax liabilities:
|
|
|
|
|
|
|
|
|
Tax over book depreciation
|
|
|
174
|
|
|
|
267
|
|
Intangible assets
|
|
|
716
|
|
|
|
1,148
|
|
Deferred income
|
|
|
111
|
|
|
|
185
|
|
Accrued tax on unremitted earnings
|
|
|
17
|
|
|
|
53
|
|
Other
|
|
|
92
|
|
|
|
97
|
|
|
|
|
|
|
|
|
|
|
Total deferred tax liabilities
|
|
|
1,110
|
|
|
|
1,750
|
|
|
|
|
|
|
|
|
|
|
Net deferred tax liability
|
|
$
|
664
|
|
|
$
|
978
|
|
|
|
|
|
|
|
|
|
|
87
A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows (in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2017
|
|
|
2016
|
|
|
2015
|
|
Unrecognized tax benefit at beginning of year
|
|
$
|
78
|
|
|
$
|
46
|
|
|
$
|
115
|
|
Gross increase for current period tax positions
|
|
|
10
|
|
|
|
3
|
|
|
|
8
|
|
Gross increase for tax positions in prior years
|
|
|
64
|
|
|
|
65
|
|
|
|
75
|
|
Gross decrease for tax positions in prior years
|
|
|
(14
|
)
|
|
|
(21
|
)
|
|
|
(75
|
)
|
Settlements
|
|
|
|
|
|
|
(3
|
)
|
|
|
(69
|
)
|
Lapse of statute of limitations
|
|
|
(6
|
)
|
|
|
(12
|
)
|
|
|
(8
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unrecognized tax benefit at end of year
|
|
$
|
132
|
|
|
$
|
78
|
|
|
$
|
46
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The balance of unrecognized tax benefits at December 31, 2017, 2016 and 2015 was $132 million, $78 million and $46
million, respectively. Accruals related to foreign jurisdiction audits of prior years resulted in uncertain tax position increases of $64 million and $65 million in 2017 and 2016, respectively. For the year ended December 31, 2015 a $69
million uncertain tax position was identified in a foreign jurisdiction that was included as an increase and settlement during the year and the completion of audits in foreign jurisdictions resulted in a $75 million decrease in uncertain tax
positions.
Substantially all of the unrecognized 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 unrecognized tax benefits may decrease by up to $75 million in the next twelve months due to settlements and conclusions of 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 Companys policy. For the years ended December 31,
2017, 2016 and 2015, we recorded income tax expense of $17 million, $10 million and $1 million, respectively, for interest and penalty related to unrecognized tax benefits. As of December 31, 2017 and 2016, the Company had accrued $32 million
and $15 million, respectively, of interest and penalty relating to unrecognized tax benefits.
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 tax years ending after 2012 and outside the U.S. for tax years ending after 2010.
Net
operating loss carryforwards by jurisdiction and expiration as of December 31, 2017 were as follows (in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Federal
|
|
|
State
|
|
|
Foreign
|
|
|
Total
|
|
2018 - 2021 Expiration
|
|
$
|
6
|
|
|
$
|
2
|
|
|
$
|
57
|
|
|
$
|
65
|
|
2022 - 2033 Expiration
|
|
|
16
|
|
|
|
16
|
|
|
|
123
|
|
|
|
155
|
|
2034 - 2037 Expiration
|
|
|
|
|
|
|
127
|
|
|
|
97
|
|
|
|
224
|
|
Unlimited Expiration
|
|
|
|
|
|
|
|
|
|
|
372
|
|
|
|
372
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Net Operating Loss (NOL)
|
|
$
|
22
|
|
|
$
|
145
|
|
|
$
|
649
|
|
|
$
|
816
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Tax Effected NOL
|
|
$
|
5
|
|
|
$
|
8
|
|
|
$
|
169
|
|
|
$
|
182
|
|
Valuation Allowance (VA)
|
|
|
(4
|
)
|
|
|
(8
|
)
|
|
|
(145
|
)
|
|
|
(157
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NOL Net of VA
|
|
$
|
1
|
|
|
$
|
|
|
|
$
|
24
|
|
|
$
|
25
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The Company has $658 million of excess foreign tax credits in the United States as of December 31, 2017, of which $11
million, $141 million, $287 million and $219 million will expire in 2020, 2022, 2026 and 2027, respectively. As of December 31, 2017, the Company has remaining tax-deductible goodwill of $153 million, resulting from acquisitions. The
amortization of this goodwill is deductible over various periods ranging up to 13 years.
Undistributed earnings of certain of the Companys foreign
subsidiaries amounted to $5,302 million at December 31, 2017. These earnings are considered to be indefinitely 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 at statutory rates and withholding taxes payable in various foreign countries.
88
15. Business Segments and Geographic Areas
The Companys operations are organized into three reportable segments: Wellbore Technologies, Completion & Production Solutions, and Rig
Technologies. Within the three reporting segments, the Company has six business units under Wellbore Technologies, nine business units under Completion & Production Solutions and two under Rig Technologies, for a total of 17 business units.
The Company has aggregated each of its business units in one of the three reporting segments based on the guidelines of ASC Topic 280, Segment Reporting (ASC Topic 280).
Wellbore Technologies
The Companys 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 segments 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 Companys 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, and manifolds; 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 segments 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
To achieve higher efficiencies and
reduce costs in the current market, the Company combined the Rig Systems and Rig Aftermarket segments during the fourth quarter of 2017. See Note 2.
The
Companys Rig Technologies 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 Technologies 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. 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 aftermarket
service and repair facilities strategically located in major areas of drilling operations around the world.
Rig Technologies supports land and offshore
drillers. Demand for the segments products depends on drilling contractors and oil 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 spare parts, service, and repair for the segments large installed base of equipment.
The Company did not have any customers with revenues greater than 10% of total revenue for the years ended December 31, 2017, 2016, or 2015.
The Companys revenue from rentals for 2017, 2016 and 2015 was 12%, 8% and 7%, respectively, of total revenue.
89
Geographic Areas:
The following table presents consolidated revenues by country based on sales destination of the products or services (in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2017
|
|
|
2016
|
|
|
2015
|
|
United States
|
|
$
|
2,760
|
|
|
$
|
1,961
|
|
|
$
|
3,640
|
|
Brazil
|
|
|
498
|
|
|
|
242
|
|
|
|
605
|
|
Saudi Arabia
|
|
|
310
|
|
|
|
258
|
|
|
|
416
|
|
China
|
|
|
298
|
|
|
|
557
|
|
|
|
1,623
|
|
Norway
|
|
|
295
|
|
|
|
339
|
|
|
|
555
|
|
Canada
|
|
|
286
|
|
|
|
217
|
|
|
|
365
|
|
United Kingdom
|
|
|
279
|
|
|
|
299
|
|
|
|
634
|
|
South Korea
|
|
|
261
|
|
|
|
495
|
|
|
|
1,835
|
|
United Arab Emirates
|
|
|
223
|
|
|
|
334
|
|
|
|
532
|
|
Singapore
|
|
|
188
|
|
|
|
340
|
|
|
|
1,035
|
|
Other Countries
|
|
|
1,906
|
|
|
|
2,209
|
|
|
|
3,517
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
7,304
|
|
|
$
|
7,251
|
|
|
$
|
14,757
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The following table presents long-lived assets by country based on the location (in millions):
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2017
|
|
|
2016
|
|
United States
|
|
$
|
1,675
|
|
|
$
|
1,810
|
|
Brazil
|
|
|
269
|
|
|
|
281
|
|
United Kingdom
|
|
|
140
|
|
|
|
137
|
|
Denmark
|
|
|
128
|
|
|
|
120
|
|
South Korea
|
|
|
97
|
|
|
|
94
|
|
Russia
|
|
|
90
|
|
|
|
88
|
|
Canada
|
|
|
84
|
|
|
|
82
|
|
Mexico
|
|
|
71
|
|
|
|
77
|
|
United Arab Emirates
|
|
|
65
|
|
|
|
90
|
|
Singapore
|
|
|
59
|
|
|
|
63
|
|
Other Countries
|
|
|
324
|
|
|
|
308
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
3,002
|
|
|
$
|
3,150
|
|
|
|
|
|
|
|
|
|
|
90
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
|
|
December 31, 2017
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenue
|
|
$
|
2,577
|
|
|
$
|
2,672
|
|
|
$
|
2,252
|
|
|
$
|
(197
|
)
|
|
$
|
7,304
|
|
Operating profit (loss)
|
|
|
(102
|
)
|
|
|
98
|
|
|
|
(14
|
)
|
|
|
(259
|
)
|
|
|
(277
|
)
|
Capital expenditures
|
|
|
99
|
|
|
|
69
|
|
|
|
16
|
|
|
|
8
|
|
|
|
192
|
|
Depreciation and amortization
|
|
|
379
|
|
|
|
215
|
|
|
|
88
|
|
|
|
16
|
|
|
|
698
|
|
Goodwill
|
|
|
2,956
|
|
|
|
2,122
|
|
|
|
1,149
|
|
|
|
|
|
|
|
6,227
|
|
Total assets
|
|
|
7,848
|
|
|
|
5,782
|
|
|
|
4,625
|
|
|
|
1,951
|
|
|
|
20,206
|
|
|
|
|
|
|
|
December 31, 2016
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenue
|
|
$
|
2,199
|
|
|
$
|
2,241
|
|
|
$
|
3,110
|
|
|
$
|
(299
|
)
|
|
$
|
7,251
|
|
Operating profit
|
|
|
(770
|
)
|
|
|
(266
|
)
|
|
|
(1,033
|
)
|
|
|
(342
|
)
|
|
|
(2,411
|
)
|
Capital expenditures
|
|
|
124
|
|
|
|
61
|
|
|
|
24
|
|
|
|
75
|
|
|
|
284
|
|
Depreciation and amortization
|
|
|
384
|
|
|
|
209
|
|
|
|
94
|
|
|
|
16
|
|
|
|
703
|
|
Goodwill
|
|
|
2,874
|
|
|
|
2,058
|
|
|
|
1,135
|
|
|
|
|
|
|
|
6,067
|
|
Total assets
|
|
|
7,911
|
|
|
|
5,765
|
|
|
|
5,327
|
|
|
|
2,137
|
|
|
|
21,140
|
|
|
|
|
|
|
|
December 31, 2015
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenue
|
|
$
|
3,718
|
|
|
$
|
3,365
|
|
|
$
|
8,279
|
|
|
$
|
(605
|
)
|
|
$
|
14,757
|
|
Operating profit
|
|
|
(1,573
|
)
|
|
|
187
|
|
|
|
1,501
|
|
|
|
(505
|
)
|
|
|
(390
|
)
|
Capital expenditures
|
|
|
180
|
|
|
|
87
|
|
|
|
91
|
|
|
|
95
|
|
|
|
453
|
|
Depreciation and amortization
|
|
|
403
|
|
|
|
223
|
|
|
|
107
|
|
|
|
14
|
|
|
|
747
|
|
Goodwill
|
|
|
2,874
|
|
|
|
1,997
|
|
|
|
2,109
|
|
|
|
|
|
|
|
6,980
|
|
Total assets
|
|
|
8,766
|
|
|
|
5,916
|
|
|
|
9,227
|
|
|
|
2,061
|
|
|
|
25,970
|
|
(1)
|
Sales from one segment to another generally are priced at estimated equivalent commercial selling prices; however, segments originating an external sale are credited with the full profit to the Company. Eliminations 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. 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. Quarterly Financial Data (Unaudited)
Summarized quarterly results, were as follows (in millions, except per share data):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
First
|
|
|
Second
|
|
|
Third
|
|
|
Fourth
|
|
|
|
Quarter
|
|
|
Quarter
|
|
|
Quarter
|
|
|
Quarter
|
|
Year ended December 31, 2017
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenue
|
|
$
|
1,741
|
|
|
$
|
1,759
|
|
|
$
|
1,835
|
|
|
$
|
1,969
|
|
Gross profit
|
|
|
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
|
|
|
|
|
|
|
Year ended December 31, 2016
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenue
|
|
$
|
2,189
|
|
|
$
|
1,724
|
|
|
$
|
1,646
|
|
|
$
|
1,692
|
|
Gross profit (loss)
|
|
|
244
|
|
|
|
35
|
|
|
|
79
|
|
|
|
(459
|
)
|
Net loss attributable to Company
|
|
|
(119
|
)
|
|
|
(217
|
)
|
|
|
(1,362
|
)
|
|
|
(714
|
)
|
Net loss attributable to Company per basic share
|
|
|
(0.32
|
)
|
|
|
(0.58
|
)
|
|
|
(3.62
|
)
|
|
|
(1.90
|
)
|
Net loss attributable to Company per diluted share
|
|
|
(0.32
|
)
|
|
|
(0.58
|
)
|
|
|
(3.62
|
)
|
|
|
(1.90
|
)
|
Cash dividends per share
|
|
|
0.46
|
|
|
|
0.05
|
|
|
|
0.05
|
|
|
|
0.05
|
|
91