NATIONAL OILWELL VARCO INC
ITEM 1. BUSINESS
General
National Oilwell Varco, Inc. (“NOV” or the “Company”), a Delaware corporation incorporated in 1995, is a leading worldwide provider of equipment and components used in oil and gas drilling and production operations, oilfield services, and supply chain integration services to the upstream oil and gas industry. The Company conducts operations in over 825 locations across six continents.
On April 21, 2008 we acquired 100% of the outstanding shares of Grant Prideco, Inc. (“Grant Prideco”) for a total purchase price of $7.2 billion of cash and NOV common stock. We have included the financial results of Grant Prideco in our Consolidated Financial Statements beginning on April 21, 2008, the date Grant Prideco common shares were exchanged for National Oilwell Varco common shares and cash. The Grant Prideco operations are included in the Petroleum Services & Supplies segment.
The Company’s principal executive offices are located at 7909 Parkwood Circle Drive, Houston, Texas 77036, its telephone number is (713) 346-7500, and its Internet website address is http://www.nov.com. The Company’s annual reports on Form 10-K, quarterly reports on Form 10-Q and current reports on Form 8-K, and all amendments thereto, are available free of charge on its Internet website. These reports are posted on its website as soon as reasonably practicable after such reports are electronically filed with the Securities and Exchange Commission (“SEC”). The Company’s Code of Ethics is also posted on its website.
The Company has a long tradition of pioneering innovations which improve the cost-effectiveness, efficiency, safety and environmental impact of oil and gas operations. The Company’s common stock is traded on the New York Stock Exchange under the symbol “NOV”. The Company operates through three business segments: Rig Technology, Petroleum Services & Supplies, and Distribution Services.
Rig Technology
Our Rig Technology segment designs, manufactures, sells and services complete systems for the drilling, completion, and servicing of oil and gas wells. The segment offers a comprehensive line of highly-engineered equipment that automates complex well construction and management operations, such as offshore and onshore drilling rigs; derricks; pipe lifting, racking, rotating and assembly systems; rig instrumentation systems; coiled tubing equipment and pressure pumping units; well workover rigs; wireline winches; wireline trucks; and cranes. Demand for Rig Technology products is primarily dependent on capital spending plans by drilling contractors, oilfield service companies, and oil and gas companies; and secondarily on the overall level of oilfield drilling activity, which drives demand for spare parts for the segment’s large installed base of equipment. We have made strategic acquisitions and other investments during the past several years in an effort to expand our product offering and our global manufacturing capabilities, including adding additional operations in the United States, Canada, Norway, the United Kingdom, China, Belarus, India, Turkey, the Netherlands, Singapore, Brazil, and South Korea.
Petroleum Services & Supplies
Our Petroleum Services & Supplies segment provides a variety of consumable goods and services used to drill, complete, remediate and workover oil and gas wells and service pipelines, flowlines and other oilfield tubular goods. The segment manufactures, rents and sells a variety of products and equipment used to perform drilling operations, including drill pipe, wired drill pipe, transfer pumps, solids control systems, drilling motors, drilling fluids, drill bits, reamers and other downhole tools, and mud pump consumables. Demand for these services and supplies is determined principally by the level of oilfield drilling and workover activity by drilling contractors, major and independent oil and gas companies, and national oil companies. Oilfield tubular services include the provision of inspection and internal coating services and equipment for drill pipe, line pipe, tubing, casing and pipelines; and the design, manufacture and sale of coiled tubing pipe and advanced composite pipe for application in highly corrosive environments. The segment sells its tubular goods and services to oil and gas companies; drilling contractors; pipe distributors, processors and manufacturers; and pipeline operators. This segment has benefited from several strategic acquisitions and other investments completed during the past few years, including additional operations in the United States, Canada, the United Kingdom, China, Kazakhstan, Mexico, Russia, Argentina, India, Bolivia, the Netherlands, Singapore, Malaysia, Vietnam, Brazil, and the United Arab Emirates.
Distribution Services
Our Distribution Services segment provides maintenance, repair and operating supplies (“MRO”) and spare parts to drill site and production locations worldwide. In addition to its comprehensive network of field locations supporting land drilling operations throughout North America, the segment supports major offshore drilling contractors through locations in Mexico, the Middle East, Europe, Southeast Asia and South America. Distribution Services employs advanced information technologies to provide complete procurement, inventory management and logistics services to its customers around the globe. Demand for the segment’s services is determined primarily by the level of drilling, servicing, and oil and gas production activities.
The following table sets forth the contribution to our total revenues of our three operating segments (in millions):
See Note 15 to the Consolidated Financial Statements included in this Annual Report on Form 10-K for financial information by segment and a geographical breakout of revenues and long-lived assets. We have included a glossary of oilfield terms at the end of Item 1. “Business” of this Annual Report.
Influence of Oil and Gas Activity Levels on the Company’s Business
The oil and gas industry in which the Company participates has historically experienced significant volatility. Demand for the Company’s services and products depends primarily upon the general level of activity in the oil and gas industry worldwide, including the number of drilling rigs in operation, the number of oil and gas wells being drilled, the depth and drilling conditions of these wells, the volume of production, the number of well completions and the level of well remediation activity. Oil and gas activity is in turn heavily influenced by, among other factors, oil and gas prices worldwide. High levels of drilling and well-remediation activity generally spurs demand for the Company’s products and services used to drill and remediate oil and gas wells. Additionally, high levels of oil and gas activity increase cash flows available for drilling contractors, oilfield service companies, and manufacturers of oil country tubular goods to invest in capital equipment that the Company sells.
Beginning in early 2004, increasing oil and gas prices led to steadily rising levels of drilling activity throughout the world. Concerns about the long-term availability of oil and gas supply also began to build. Consequently, the worldwide rig count increased 11% in 2006, 2% in 2007, and 7% in 2008. As a result of higher cash flows realized by many drilling contractors and other oilfield service companies, as well as the long-term concerns about supply-demand imbalance and the need to replace aging equipment, market conditions for capital equipment purchases have improved significantly since 2006 and 2007, resulting in higher backlogs for the Company at the end of 2008 compared to the end of 2006 and 2007. However, as a result of the financial crisis and significantly lower commodity prices, the worldwide drilling rig count declined 31% in 2009 and customers were far less willing to commit to major capital equipment purchases in 2009. As a result, our order rates were substantially lower in 2009. Backlog for the Company was approximately $6.4 billion at December 31, 2009 compared to approximately $11.1 billion and $9.0 billion for December 31, 2008 and 2007, respectively.
In 2008 and 2009, most of the Company’s Rig Technology revenue resulted from major capital expenditures of drilling contractors, well servicing companies, and oil companies on rig construction and refurbishment, and well servicing equipment. These capital expenditures are influenced by the amount of cash flow that contractors and service companies generate from drilling, completion, and remediation activity; as well as by the availability of financing, the outlook for future drilling and well servicing activity, and other factors. Generally, the Company believes the demand for capital equipment lags increases in the level of drilling activity. Most of the remainder of the Rig Technology segment’s revenue are related to the sale of spare parts and consumables, the provision of equipment-repair services, and the rental of equipment, which the Company believes are generally determined directly by the level of drilling and well servicing activity.
The majority of the Company’s Petroleum Services & Supplies revenue is closely tied to drilling activity, although a portion is related to the sale of capital equipment to drilling contractors, which may somewhat lag the level of drilling activity. Portions of the segment’s revenue that are not tied to drilling activity include (i) the sale of progressive cavity pumps and solids control equipment for use in industrial applications, and (ii) the sale of fiberglass and composite tubing to industrial customers, which is generally unrelated to drilling or well remediation activity but may be tied somewhat to oil and gas prices.
The Company’s revenue from Distribution Services is almost entirely driven by drilling activity and oil and gas production activities. Drilling and well servicing activity can fluctuate significantly in a short period of time.
The willingness of oil and gas operators to make capital investments to explore for and produce oil and natural gas will continue to be influenced by numerous factors over which the Company has no control, including: the ability of the members of the Organization of Petroleum Exporting Countries (“OPEC”) to maintain oil price stability through voluntary production limits of oil; the level of oil production by non-OPEC countries; supply and demand for oil and natural gas; general economic and political conditions; costs of exploration and production; the availability of new leases and concessions; access to external financing; and governmental regulations regarding, among other things, environmental protection, climate change, taxation, price controls and product allocations. The willingness of drilling contractors and well servicing companies to make capital expenditures for the type of specialized equipment the Company provides is also influenced by numerous factors over which the Company has no control, including: the general level of oil and gas well drilling and servicing; rig dayrates; access to external financing; outlook for future increases in well drilling and well remediation activity; steel prices and fabrication costs; and government regulations regarding, among other things, environmental protection, taxation, and price controls.
See additional discussion on current worldwide economic environment and related oil and gas activity levels in
ITEM 1A. RISK FACTORS
You should carefully consider the risks described below, in addition to other information contained or incorporated by reference herein. Realization of any of the following risks could have a material adverse effect on our business, financial condition, cash flows and results of operations.
We are dependent upon the level of activity in the oil and gas industry, which is volatile.
The oil and gas industry historically has experienced significant volatility. Demand for our services and products depends primarily upon the number of oil rigs in operation, the number of oil and gas wells being drilled, the depth and drilling conditions of these wells, the volume of production, the number of well completions, capital expenditures of other oilfield service companies and the level of workover activity. Drilling and workover activity can fluctuate significantly in a short period of time, particularly in the United States and Canada. The willingness of oil and gas operators to make capital expenditures to explore for and produce oil and natural gas and the willingness of oilfield service companies to invest in capital equipment will continue to be influenced by numerous factors over which we have no control, including:
•
the ability of the members of the Organization of Petroleum Exporting Countries, or OPEC, to maintain price stability through voluntary production limits, the level of production by non-OPEC countries and worldwide demand for oil and gas;
•
level of production from known reserves;
•
cost of exploring for and producing oil and gas;
•
level of drilling activity and drilling rig dayrates;
•
worldwide economic activity;
•
national government political requirements;
•
development of alternate energy sources; and
•
environmental regulations.
If there is a significant reduction in demand for drilling services, in cash flows of drilling contractors, well servicing companies, or production companies or in drilling or well servicing rig utilization rates, then demand for the products and services of the Company will decline.
Volatile oil and gas prices affect demand for our products.
Oil and gas prices have been volatile since 1972. In general, oil prices approximated $18-$22 per barrel from 1991 through 1997, experienced a decline into the low teens in 1998 and 1999, and have generally ranged between $25-$100 per barrel since 2000. In 2008, oil prices were extremely volatile - oil prices rose to $147 per barrel in July 2008 only to fall into the $35-$45 per barrel range in December 2008. In 2009, oil prices continued to be volatile, rising from the $30 per barrel range to the $70 per barrel range during the year. Spot gas prices generally ranged between $1.80-$2.60 per mmbtu of gas from 1991 through 1999 then experienced severe spikes into the $10 range in 2001 and 2003. Absent occasional spikes and dips due to imbalances in supply and demand, prices have generally ranged between $4.50-$12.00 per mmbtu during 2005-2008. In 2009, spot gas prices continued to be volatile, dropping into the $3 per mmbtu range during the year.
Expectations for future oil and gas prices cause many shifts in the strategies and expenditure levels of oil and gas companies and drilling contractors, particularly with respect to decisions to purchase major capital equipment of the type we manufacture. Oil and gas prices, which are determined by the marketplace, may fall below a range that is acceptable to our customers, which could reduce demand for our products.
Worldwide financial and credit crisis could have a negative effect on our operating results and financial condition.
Events in 2008 and 2009 constrained credit markets and sparked a serious global banking crisis. The slowdown in worldwide economic activity caused by the global recession reduced demand for energy and resulted in lower oil and natural gas prices. Any prolonged reduction in oil and natural gas prices will reduce oil and natural gas drilling activity and result in a corresponding decline in the demand for our products and services, which could adversely impact our operating results and financial condition. Furthermore, many of our customers access the credit markets to finance their oil and natural gas drilling activity. If the recent crisis and recession reduce the availability of credit to our customers, they may reduce their drilling and production expenditures, thereby decreasing demand for our products and services. Any such reduction in spending by our customers could adversely impact our operating results and financial condition.
There are risks associated with certain contracts for our drilling equipment.
As of December 31, 2009, we had a backlog of approximately $6.4 billion of drilling equipment to be manufactured, assembled, tested and delivered by our Rig Technology group. The following factors, in addition to others not listed, could reduce our margins on these contracts, adversely affect our position in the market or subject us to contractual penalties:
•
our failure to adequately estimate costs for making this drilling equipment;
•
our inability to deliver equipment that meets contracted technical requirements;
•
our inability to maintain our quality standards during the design and manufacturing process;
•
our inability to secure parts made by third party vendors at reasonable costs and within required timeframes;
•
unexpected increases in the costs of raw materials; and
•
our inability to manage unexpected delays due to weather, shipyard access, labor shortages or other factors beyond our control.
The Company’s existing contracts for rig equipment generally carry significant down payment and progress billing terms favorable to the ultimate completion of these projects and do not allow customers to cancel projects for convenience. However, unfavorable market conditions or financial difficulties experienced by our customers may result in cancellation of contracts or the delay or abandonment of projects.
Any such developments could have a material adverse effect on our operating results and financial condition.
Competition in our industry could ultimately lead to lower revenues and earnings.
The oilfield products and services industry is highly competitive. We compete with national, regional and foreign competitors in each of our current major product lines. Certain of these competitors may have greater financial, technical, manufacturing and marketing resources than us, and may be in a better competitive position. The following competitive actions can each affect our revenues and earnings:
•
price changes;
•
new product and technology introductions; and
•
improvements in availability and delivery.
In addition, certain foreign jurisdictions and government-owned petroleum companies located in some of the countries in which we operate have adopted policies or regulations which may give local nationals in these countries competitive advantages. Competition in our industry could lead to lower revenues and earnings.
We have aggressively expanded our businesses and intend to maintain an aggressive growth strategy.
We have aggressively expanded and grown our businesses during the past several years, through acquisitions and investment in internal growth. We anticipate that we will continue to pursue an aggressive growth strategy but we cannot assure you that attractive acquisitions will be available to us at reasonable prices or at all. In addition, we cannot assure you that we will successfully integrate the operations and assets of any acquired business with our own or that our management will be able to manage effectively the increased size of the Company or operate any new lines of business. Any inability on the part of management to integrate and manage acquired businesses and their assumed liabilities could adversely affect our business and financial performance. In addition, we may need to incur substantial indebtedness to finance future acquisitions. We cannot assure you that we will be able to obtain this financing
on terms acceptable to us or at all. Future acquisitions may result in increased depreciation and amortization expense, increased interest expense, increased financial leverage or decreased operating income for the Company, any of which could cause our business to suffer.
Our operating results have fluctuated during recent years and these fluctuations may continue.
We have experienced fluctuations in quarterly operating results in the past. We cannot assure that we will realize earnings growth or that earnings in any particular quarter will not fall short of either a prior fiscal quarter or investors’ expectations. The following factors, in addition to others not listed, may affect our quarterly operating results in the future:
•
fluctuations in the oil and gas industry;
•
competition;
•
the ability to service the debt obligations of the Company;
•
the ability to identify strategic acquisitions at reasonable prices;
•
the ability to manage and control operating costs of the Company;
•
fluctuations in political and economic conditions in the United States and abroad; and
•
the ability to protect our intellectual property rights.
There are risks associated with our presence in international markets, including political or economic instability, currency restrictions, and trade and economic sanctions.
Approximately 73% of our revenues in 2009 were derived from operations outside the United States (based on revenue destination). Our foreign operations include significant operations in Canada, Europe, the Middle East, Africa, Southeast Asia, Latin America and other international markets. Our revenues and operations are subject to the risks normally associated with conducting business in foreign countries, including uncertain political and economic environments, which may limit or disrupt markets, restrict the movement of funds or result in the deprivation of contract rights or the taking of property without fair compensation. Government-owned petroleum companies located in some of the countries in which we operate have adopted policies, or are subject to governmental policies, giving preference to the purchase of goods and services from companies that are majority-owned by local nationals. As a result of these policies, we may rely on joint ventures, license arrangements and other business combinations with local nationals in these countries. In addition, political considerations may disrupt the commercial relationships between us and government-owned petroleum companies.
Our operations outside the United States could also expose us to trade and economic sanctions or other restrictions imposed by the United States or other governments or organizations. The U.S. Department of Justice (“DOJ”), the U.S. Securities and Exchange Commission and other federal agencies and authorities have a broad range of civil and criminal penalties they may seek to impose against corporations and individuals for violations of trading sanctions laws, the Foreign Corrupt Practices Act and other federal statutes. Under trading sanctions laws, the DOJ may seek to impose modifications to business practices, including cessation of business activities in sanctioned countries, and modifications to compliance programs, which may increase compliance costs. If any of the risks described above materialize, it could adversely impact our operating results and financial condition.
We have received federal grand jury subpoenas and subsequent inquiries from governmental agencies requesting records related to our compliance with export trade laws and regulations. We have cooperated fully with agents from the Department of Justice, the Bureau of Industry and Security, the Office of Foreign Assets Control, and U.S. Immigration and Customs Enforcement in responding to the inquiries, and we have conducted our own internal review of this matter. At the conclusion of our internal review in the fourth quarter of 2009, we identified possible areas of concern and discussed these areas of concern with the relevant agencies. We are currently negotiating a potential resolution with the agencies involved related to these matters. We currently anticipate that any administrative fine or penalty agreed to as part of a resolution would be within established accruals, and would not have a material effect on our financial position or results of operations. To the extent a resolution is not negotiated as anticipated, we cannot predict the timing or effect that any resulting government actions may have on our financial position or results of operations. As a result of our internal review and in an effort to prevent any future compliance issues of this nature, we have reviewed and are in the process of enhancing our compliance procedures and training.
The results of our operations are subject to market risk from changes in foreign currency exchange rates.
We earn revenues, pay expenses and incur liabilities in countries using currencies other than the U.S. dollar, including the Canadian dollar, the Euro, the British pound sterling, the Norwegian krone and the South Korean won. Approximately 73% of our 2009 revenue was derived from sales outside the United States. Because our Consolidated Financial Statements are presented in U.S. dollars, we must translate revenues and expenses into U.S. dollars at exchange rates in effect during or at the end of each reporting period. Thus, increases or decreases in the value of the U.S. dollar against other currencies in which our operations are conducted will affect our revenues and operating income. Because of the geographic diversity of our operations, weaknesses in some currencies might be offset by strengths in others over time. We use derivative financial instruments to mitigate our net exposure to currency exchange fluctuations. We had forward contracts with a notional amount of $2,850 million (with a fair value of $49 million) as of December 31, 2009 to reduce the impact of foreign currency exchange rate movements. We are also subject to risks that the counterparties to these contracts fail to meet the terms of our foreign currency contracts. We cannot assure you that fluctuations in foreign currency exchange rates would not affect our financial results.
An impairment of goodwill or other indefinite lived intangible assets could reduce our earnings.
The Company has approximately $5.5 billion of goodwill and $0.6 billion of other intangible assets with indefinite lives as of December 31, 2009. Generally accepted accounting principles require the Company to test goodwill and other indefinite lived intangible assets for impairment on an annual basis or whenever events or circumstances occur indicating that goodwill might be impaired. Events or circumstances which could indicate a potential impairment include (but are not limited to) a significant reduction in worldwide oil and gas prices or drilling; a significant reduction in profitability or cash flow of oil and gas companies or drilling contractors; a significant reduction in worldwide well remediation activity; a significant reduction in capital investment by other oilfield service companies; or a significant increase in worldwide inventories of oil or gas. The timing and magnitude of any goodwill impairment charge, which could be material, would depend on the timing and severity of the event or events triggering the charge and would require a high degree of management judgment. If we were to determine that any of our remaining balance of goodwill or other indefinite lived intangible assets was impaired, we would record an immediate charge to earnings with a corresponding reduction in stockholders’ equity; resulting in an increase in balance sheet leverage as measured by debt to total capitalization.
See additional discussion on “Goodwill and Other Indefinite - Lived Intangible Assets” in Critical Accounting Estimates of Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”
We could be adversely affected if we fail to comply with any of the numerous federal, state and local laws, regulations and policies that govern environmental protection, zoning and other matters applicable to our businesses.
Our businesses are subject to numerous federal, state and local laws, regulations and policies governing environmental protection, zoning and other matters. These laws and regulations have changed frequently in the past and it is reasonable to expect additional changes in the future. If existing regulatory requirements change, we may be required to make significant unanticipated capital and operating expenditures. We cannot assure you that our operations will continue to comply with future laws and regulations. Governmental authorities may seek to impose fines and penalties on us or to revoke or deny the issuance or renewal of operating permits for failure to comply with applicable laws and regulations. Under these circumstances, we might be required to reduce or cease operations or conduct site remediation or other corrective action which could adversely impact our operations and financial condition.
Our businesses expose us to potential environmental liability.
Our businesses expose us to the risk that harmful substances may escape into the environment, which could result in:
•
personal injury or loss of life;
•
severe damage to or destruction of property; or
•
environmental damage and suspension of operations.
Our current and past activities, as well as the activities of our former divisions and subsidiaries, could result in our facing substantial environmental, regulatory and other liabilities. These could include the costs of cleanup of contaminated sites and site closure obligations. These liabilities could also be imposed on the basis of one or more of the following theories:
•
negligence;
•
strict liability;
•
breach of contract with customers; or
•
as a result of our contractual agreement to indemnify our customers in the normal course of business, which is normally the case.
We may not have adequate insurance for potential environmental liabilities.
While we maintain liability insurance, this insurance is subject to coverage limits. In addition, certain policies do not provide coverage for damages resulting from environmental contamination. We face the following risks with respect to our insurance coverage:
•
we may not be able to continue to obtain insurance on commercially reasonable terms;
•
we may be faced with types of liabilities that will not be covered by our insurance;
•
our insurance carriers may not be able to meet their obligations under the policies; or
•
the dollar amount of any liabilities may exceed our policy limits.
Even a partially uninsured claim, if successful and of significant size, could have a material adverse effect on our consolidated financial statements.
The adoption of climate change legislation or regulations restricting emissions of greenhouse gases could increase our operating costs or reduce demand for our products.
Environmental advocacy groups and regulatory agencies in the United States and other countries have been focusing considerable attention on the emissions of carbon dioxide, methane and other greenhouse gases and their potential role in climate change. The adoption of laws and regulations to implement controls of greenhouse gases, including the imposition of fees or taxes, could adversely impact our operations and financial condition. The U.S. Congress is currently working on legislation to control and reduce emissions of greenhouse gases in the United States, which includes establishing cap-and-trade programs. In addition to the pending climate legislation, the U.S. Environmental Protection Agency has proposed regulations that would require permits for and reductions in greenhouse gas emissions for certain facilities, and may issue final rules this year. These changes in the legal and regulatory environment could reduce oil and natural gas drilling activity and result in a corresponding decline in the demand for our products and services, which could adversely impact our operating results and financial condition.
The Company had revenues of 16.6% of total revenue from one of its customers for the year ended December 31, 2009.
The loss of this customer or a significant reduction in its purchases could adversely affect our future revenues and earnings.
GLOSSARY OF OILFIELD TERMS
(Sources: Company management; “A Dictionary for the Petroleum Industry,” The University of Texas at Austin, 2001.)
API
Abbr: American Petroleum Institute
Annular Blowout Preventer
A large valve, usually installed above the ram blowout preventers, that forms a seal in the annular space between the pipe and the wellbore or, if no pipe is present, in the wellbore itself.
Annulus
The open space around pipe in a wellbore through which fluids may pass.
Automatic Pipe Handling Systems (Automatic Pipe Racker)
A device used on a drilling rig to automatically remove and insert drill stem components from and into the hole. It replaces the need for a person to be in the derrick or mast when tripping pipe into or out of the hole.
Automatic Roughneck
A large, self-contained pipe-handling machine used by drilling crew members to make up and break out tubulars. The device combines a spinning wrench, torque wrench, and backup wrenches.
Beam pump
Surface pump that raise and lowers sucker rods continually, so as to operate a downhole pump.
Bit
The cutting or boring element used in drilling oil and gas wells. The bit consists of a cutting element and a circulating element. The cutting element is steel teeth, tungsten carbide buttons, industrial diamonds, or polycrystalline diamonds (“PDCs”). These teeth, buttons, or diamonds penetrate and gouge or scrape the formation to remove it. The circulating element permits the passage of drilling fluid and utilizes the hydraulic force of the fluid stream to improve drilling rates. In rotary drilling, several drill collars are joined to the bottom end of the drill pipe column, and the bit is attached to the end of the drill collars. Drill collars provide weight on the bit to keep it in firm contact with the bottom of the hole. Most bits used in rotary drilling are roller cone bits, but diamond bits are also used extensively.
Blowout
An uncontrolled flow of gas, oil or other well fluids into the atmosphere. A blowout, or gusher, occurs when formation pressure exceeds the pressure applied to it by the column of drilling fluid. A kick warns of an impending blowout.
Blowout Preventer (BOP)
Series of valves installed at the wellhead while drilling to prevent the escape of pressurized fluids.
Blowout Preventer (BOP) Stack
The assembly of well-control equipment including preventers, spools, valves, and nipples connected to the top of the wellhead.
Closed Loop Drilling Systems
A solids control system in which the drilling mud is reconditioned and recycled through the drilling process on the rig itself.
Coiled Tubing
A continuous string of flexible steel tubing, often hundreds or thousands of feet long, that is wound onto a reel, often dozens of feet in diameter. The reel is an integral part of the coiled tubing unit, which consists of several devices that ensure the tubing can be safely and efficiently inserted into the well from the surface. Because tubing can be lowered into a well without having to make up joints of tubing, running coiled tubing into the well is faster and less expensive than running conventional tubing. Rapid advances in the use of coiled tubing make it a popular way in which to run tubing into and out of a well. Also called reeled tubing.
Cuttings
Fragments of rock dislodged by the bit and brought to the surface in the drilling mud. Washed and dried cutting samples are analyzed by geologist to obtain information about the formations drilled.
Directional Well
Well drilled in an orientation other than vertical in order to access broader portions of the formation.
Drawworks
The hoisting mechanism on a drilling rig. It is essentially a large winch that spools off or takes in the drilling line and thus raises or lowers the drill stem and bit.
Drill Pipe Elevator (Elevator)
On conventional rotary rigs and top-drive rigs, hinged steel devices with manual operating handles that crew members latch onto a tool joint (or a sub). Since the elevators are directly connected to the traveling block, or to the integrated traveling block in the top drive, when the driller raises or lowers the block or the top-drive unit, the drill pipe is also raised or lowered.
Drilling jars
A percussion tool operated manually or hydraulically to deliver a heavy downward blow to free a stuck drill stem.
Drilling mud
A specially compounded liquid circulated through the wellbore during rotary drilling operations.
Drilling riser
A conduit used in offshore drilling through which the drill bit and other tools are passed from the rig on the water’s surface to the sea floor.
Drill stem
All members in the assembly used for rotary drilling from the swivel to the bit, including the Kelly, the drill pipe and tool joints, the drill collars, the stabilizers, and various specialty items.
Formation
A bed or deposit composed throughout of substantially the same kind of rock; often a lithologic unit. Each formation is given a name, frequently as a result of the study of the formation outcrop at the surface and sometimes based on fossils found in the formation.
FPSO
A Floating Production Storage and Offloading vessel used to receive hydrocarbons from subsea wells, and then produce and store the hydrocarbons until they can be offloaded to a tanker or pipeline.
Hardbanding
A special wear-resistant material often applied to tool joints to prevent abrasive wear to the area when the pipe is being rotated downhole.
Hydraulic Fracturing
The process of creating fractures in a formation by pumping fluids, at high pressures, into the reservoir, which allows or enhances the flow of hydrocarbons.
Iron Roughneck
A floor-mounted combination of a spinning wrench and a torque wrench. The Iron Roughneck moves into position hydraulically and eliminates the manual handling involved with suspended individual tools.
Jack-up rig
A mobile bottom-supported offshore drilling structure with columnar or open-truss legs that support the deck and hull. When positioned over the drilling site, the bottoms of the legs penetrate the seafloor.
Jar
A mechanical device placed near the top of the drill stem which allows the driller to strike a very heavy blow upward or downward on stuck pipe.
Joint
1. In drilling, a single length (from 16 feet to 45 feet, or 5 meters to 14.5 meters, depending on its range length) of drill pipe, drill collar, casing or tubing that has threaded connections at both ends. Several joints screwed together constitute a stand of pipe. 2. In pipelining, a single length (usually 40 feet-12 meters) of pipe. 3. In sucker rod pumping, a single length of sucker rod that has threaded connections at both ends.
Kelly
The heavy steel tubular device, four- or six-sided, suspended from the swivel through the rotary table and connected to the top joint of drill pipe to turn the drill stem as the rotary table returns. It has a bored passageway that permits fluid to be circulated into the drill stem and up the annulus, or vice versa. Kellys manufactured to API specifications are available only in four- or six-sided versions, are either 40 or 54 feet (12 to 16 meters) long, and have diameters as small as 2.5 inches (6 centimeters) and as large as 6 inches (15 centimeters).
Kelly bushing
A special device placed around the kelly that mates with the kelly flats and fits into the master bushing of the rotary table. The kelly bushing is designed so that the kelly is free to move up or down through it. The bottom of the bushing may be shaped to fit the opening in the master bushing or it may have pins that fit into the master bushing. In either case, when the kelly bushing is inserted into the master bushing and the master bushing is turned, the kelly bushing also turns. Since the kelly bushing fits onto the kelly, the kelly turns, and since the kelly is made up to the drill stem, the drill stem turns. Also called the drive bushing.
Kelly spinner
A pneumatically operated device mounted on top of the kelly that, when actuated, causes the kelly to turn or spin. It is useful when the kelly or a joint of pipe attached to it must be spun up, that is, rotated rapidly for being made up.
Kick
An entry of water, gas, oil, or other formation fluid into the wellbore during drilling. It occurs because the pressure exerted by the column of drilling fluid is not great enough to overcome the pressure exerted by the fluids in the formation drilled. If prompt action is not taken to control the kick, or kill the well, a blowout may occur.
Making-up
1. To assemble and join parts to form a complete unit (e.g., to make up a string of drill pipe). 2. To screw together two threaded pieces. Compare break out. 3. To mix or prepare (e.g., to make up a tank of mud). 4. To compensate for (e.g., to make up for lost time).
Manual tongs (Tongs)
The large wrenches used for turning when making up or breaking out drill pipe, casing, tubing, or other pipe; variously called casing tongs, pipe tongs, and so forth, according to the specific use. Power tongs or power wrenches are pneumatically or hydraulically operated tools that serve to spin the pipe up tight and, in some instances to apply the final makeup torque.
Master bushing
A device that fits into the rotary table to accommodate the slips and drive the kelly bushing so that the rotating motion of the rotary table can be transmitted to the kelly. Also called rotary bushing.
Motion compensation
equipment
Any device (such as a bumper sub or heave compensator) that serves to maintain constant weight on the bit in spite of vertical motion of a floating offshore drilling rig.
Mud pump
A large, high-pressure reciprocating pump used to circulate the mud on a drilling rig.
Plug gauging
The mechanical process of ensuring that the inside threads on a piece of drill pipe comply with API standards.
Pressure control equipment
Equipment used in: 1. The act of preventing the entry of formation fluids into a wellbore. 2. The act of controlling high pressures encountered in a well.
Pressure pumping
Pumping fluids into a well by applying pressure at the surface.
Ram blowout preventer
A blowout preventer that uses rams to seal off pressure on a hole that is with or without pipe. Also called a ram preventer.
Ring gauging
The mechanical process of ensuring that the outside threads on a piece of drill pipe comply with API standards.
Riser
A pipe through which liquids travel upward.
Riser pipe
The pipe and special fitting used on floating offshore drilling rigs to established a seal between the top of the wellbore, which is on the ocean floor, and the drilling equipment located above the surface of the water. A riser pipe serves as a guide for the drill stem from the drilling vessel to the wellhead and as a conductor or drilling fluid from the well to the vessel. The riser consists of several sections of pipe and includes special devices to compensate for any movement of the drilling rig caused by waves. Also called marine riser pipe, riser joint.
Rotary table
The principal piece of equipment in the rotary table assembly; a turning device used to impart rotational power to the drill stem while permitting vertical movement of the pipe for rotary drilling. The master bushing fits inside the opening of the rotary table; it turns the kelly bushing, which permits vertical movement of the kelly while the stem is turning.
Rotating blowout
preventer (Rotating Head)
A sealing device used to close off the annular space around the kelly in drilling with pressure at the surface, usually installed above the main blowout preventers. A rotating head makes it possible to drill ahead even when there is pressure in the annulus that the weight of the drilling fluid is not overcoming; the head prevents the well from blowing out. It is used mainly in the drilling of formations that have low permeability. The rate of penetration through such formations is usually rapid.
Safety clamps
A clamp placed very tightly around a drill collar that is suspended in the rotary table by drill collar slips. Should the slips fail, the clamp is too large to go through the opening in the rotary table and therefore prevents the drill collar string from falling into the hole. Also called drill collar clamp.
Shaker
See “Shale Shaker”
Shale shaker
A piece of drilling rig equipment that uses a vibrating screen to remove cuttings from the circulating fluid in rotary drilling operations. The size of the openings in the screen should be selected carefully to be the smallest size possible to allow 100 per cent flow of the fluid. Also called a shaker.
Slim-hole completions
(Slim-hole Drilling)
Drilling in which the size of the hole is smaller than the conventional hole diameter for a given depth. This decrease in hole size enables the operator to run smaller casing, thereby lessening the cost of completion.
Slips
Wedge-shaped pieces of metal with serrated inserts (dies) or other gripping elements, such as serrated buttons, that suspend the drill pipe or drill collars in the master bushing of the rotary table when it is necessary to disconnect the drill stem from the kelly or from the top-drive unit’s drive shaft. Rotary slips fit around the drill pipe and wedge against the master bushing to support the pipe. Drill collar slips fit around a drill collar and wedge against the master bushing to support the drill collar. Power slips are pneumatically or hydraulically actuated devices that allow the crew to dispense with the manual handling of slips when making a connection.
Solids
See “Cuttings”
Spinning wrench
Air-powered or hydraulically powered wrench used to spin drill pipe in making or breaking connections.
Spinning-in
The rapid turning of the drill stem when one length of pipe is being joined to another. “Spinning-out” refers to separating the pipe.
Stand
The connected joints of pipe racked in the derrick or mast when making a trip. On a rig, the usual stand is about 90 feet (about 27 meters) long (three lengths of drill pipe screwed together), or a treble.
String
The entire length of casing, tubing, sucker rods, or drill pipe run into a hole.
Sucker rod
A special steel pumping rod. Several rods screwed together make up the link between the pumping unit on the surface and the pump at the bottom of the well.
Tensioner
A system of devices installed on a floating offshore drilling rig to maintain a constant tension on the riser pipe, despite any vertical motion made by the rig. The guidelines must also be tensioned, so a separate tensioner system is provided for them.
Thermal desorption
The process of removing drilling mud from cuttings by applying heat directly to drill cuttings.
Tiebacks (Subsea)
A series of flowlines and pipes that connect numerous subsea wellheads to a single collection point.
Top drive
A device similar to a power swivel that is used in place of the rotary table to turn the drill stem. It also includes power tongs. Modern top drives combine the elevator, the tongs, the swivel, and the hook. Even though the rotary table assembly is not used to rotate the drill stem and bit, the top-drive system retains it to provide a place to set the slips to suspend the drill stem when drilling stops.
Torque wrench
Spinning wrench with a gauge for measuring the amount of torque being applied to the connection.
Trouble cost
Costs incurred as a result of unanticipated complications while drilling a well. These costs are often referred to as contingency costs during the planning phase of a well.
Well completion
1. The activities and methods of preparing a well for the production of oil and gas or for other purposes, such as injection; the method by which one or more flow paths for hydrocarbons are established between the reservoir and the surface. 2. The system of tubulars, packers, and other tools installed beneath the wellhead in the production casing; that is, the tool assembly that provides the hydrocarbon flow path or paths.
Wellhead
The termination point of a wellbore at surface level or subsea, often incorporating various valves and control instruments.
Well stimulation
Any of several operations used to increase the production of a well, such as acidizing or fracturing.
Well workover
The performance of one or more of a variety of remedial operations on a producing oil well to try to increase production. Examples of workover jobs are deepening, plugging back, pulling and resetting liners, and squeeze cementing.
Wellbore
A borehole; the hole drilled by the bit. A wellbore may have casing in it or it may be open (uncased); or part of it may be cased, and part of it may be open. Also called a borehole or hole.
Wireline
A slender, rodlike or threadlike piece of metal usually small in diameter, that is used for lowering special tools (such as logging sondes, perforating guns, and so forth) into the well. Also called slick line.
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.
ITEM 2. PROPERTIES
The Company owned or leased over 825 facilities worldwide as of December 31, 2009, including the following principal manufacturing, service, distribution and administrative facilities:
*
Building owned but land leased.
We own or lease more than 145 repair and manufacturing facilities that refurbish and manufacture new equipment and parts, and approximately 215 distribution service centers, and 465 service centers that provide inspection and equipment rental worldwide.
ITEM 3. LEGAL PROCEEDINGS
We have various claims, lawsuits and administrative proceedings that are pending or threatened, all arising in the ordinary course of business, with respect to commercial, product liability and employee matters. Although no assurance can be given with respect to the outcome of these or any other pending legal and administrative proceedings and the effect such outcomes may have, we believe any ultimate liability resulting from the outcome of such claims, lawsuits or administrative proceedings will not have a material adverse effect on our consolidated financial position, results of operations or cash flows. See Note 12 to the Consolidated Financial Statements.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
No matters were submitted to a vote of security holders during the quarter ended December 31, 2009.
PART II
ITEM 5.
MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
Market Information
Our common stock is traded on the New York Stock Exchange (NYSE) under the symbol “NOV”. The following table sets forth, for the calendar periods indicated, the range of high and low closing prices for the common stock, as reported by the NYSE.
As of February 16, 2010, there were 3,204 holders of record of our common stock. Many stockholders choose to own shares through brokerage accounts and other intermediaries rather than as holders of (excluding individual participants in securities positions listing) record so the actual number of stockholders is unknown but significantly higher.
On November 11, 2009 National Oilwell Varco’s Board of Directors approved a special one-time cash dividend of $1.00 per share of common stock along with the commencement of a regular quarterly dividend of $0.10 per share. The special cash dividend and the first quarterly dividend were paid on December 16, 2009 to each stockholder of record on December 2, 2009. The declaration and payment of future dividends is at the discretion of the Company’s Board of Directors and will be dependent upon the Company’s results of operations, financial condition, capital requirements and other factors deemed relevant by the Board of Directors.
On August 22, 2007, the Company’s Board of Directors approved a two-for-one stock split in the form of a stock dividend to the Company’s stockholders of record on September 7, 2007, with distribution of shares on September 28, 2007. The total number of authorized common stock shares and associated par value were unchanged by this action. All per-share amounts in the financial statements reflect the stock split for all periods presented. The effect of the common stock split is reflected on the Consolidated Balance Sheet in “Common stock” and “Additional paid-in capital.”
The information relating to our equity compensation plans required by Item 5. “Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities” is incorporated by reference to such information as set forth in Item 12. “Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters” contained herein.
PERFORMANCE GRAPH
The graph below compares the cumulative total shareholder return on our common stock to the S&P 500 Index and the S&P Oil & Gas Equipment & Services Index. The total shareholder return assumes $100 invested on December 31, 2004 in National Oilwell Varco, Inc., the S&P 500 Index and the S&P Oil & Gas Equipment & Services Index. It also assumes reinvestment of all dividends. The peer group is weighted based on the market capitalization of each company. The results shown in the graph below are not necessarily indicative of future performance.
COMPARISON OF 5 YEAR CUMULATIVE TOTAL RETURN*
Among National Oilwell Varco, Inc., The S&P 500 Index
And The S&P Oil & Gas Equipment & Services Index
*
$100 invested on 12/31/04 in stock or index, including reinvestment of dividends. Fiscal year ending December 31.
Copyright© 2010 S&P, a division of The McGraw-Hill Companies Inc. All rights reserved.
12/04
12/05
12/06
12/07
12/08
12/09
National Oilwell Varco, Inc.
100.00
177.67
173.36
416.32
138.51
256.26
S&P 500
100.00
104.91
121.48
128.16
80.74
102.11
S&P Oil & Gas Equipment & Services
100.00
148.56
171.65
253.87
103.64
165.61
This information shall not be deemed to be “soliciting material” or to be “filed” with the Commission or subject to Regulation 14A (17 CFR 240.14a-1-240.14a-104), other than as provided in Item 201(e) of Regulation S-K, or to the liabilities of section 18 of the Exchange Act (15 U.S.C. 78r).
ITEM 6. SELECTED FINANCIAL DATA
(1)
Financial results of Grant Prideco have been included in our Consolidated Financial Statements beginning April 21, 2008, the date the Grant Prideco merger was completed and each of Grant Prideco’s common shares were exchanged for .4498 shares of our common stock and $23.20 in cash. Financial information for prior periods and dates may not be comparable with 2008 due to the impact of this business combination on our financial position and results of operation. See Note 3 to the Consolidated Financial Statements for a description of the Grant Prideco merger and related adjusted financial information.
(2)
Financial results of Varco International, Inc. (“Varco”) have been included in our Consolidated Financial Statements beginning March 11, 2005, the date the Varco merger was completed and Varco common shares were exchanged for our common shares. Financial information for other periods may not be comparable with 2005 due to the impact of this business combination on our financial position and results of operation. Results for the year ended December 31, 2005 include integration costs associated with the Varco merger of $32 million and stock-based compensation costs of $16 million related to the amortization expense of options assumed in the Varco merger.
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
General Overview
The Company is a leading worldwide provider of highly engineered drilling and well-servicing equipment, products and services to the exploration and production segments of the oil and gas industry. With operations in over 825 locations across six continents, we design, manufacture and service a comprehensive line of drilling and well servicing equipment; sell and rent drilling motors, specialized downhole tools, and rig instrumentation; perform inspection and internal coating of oilfield tubular products; provide drill cuttings separation, management and disposal systems and services; provide expendables and spare parts used in conjunction with our large installed base of equipment; and provide supply chain management services through our distribution network. We also manufacture coiled tubing, manufacture high pressure fiberglass and composite tubing, and sell and rent advanced in-line inspection equipment to makers of oil country tubular goods. We have a long tradition of pioneering innovations which improve the cost-effectiveness, efficiency, safety, and environmental impact of oil and gas operations.
Our revenues and operating results are directly related to the level of worldwide oil and gas drilling and production activities and the profitability and cash flow of oil and gas companies and drilling contractors, which in turn are affected by current and anticipated prices of oil and gas. Oil and gas prices have been and are likely to continue to be volatile. See “Risk Factors”. We conduct our operations through three business segments: Rig Technology, Petroleum Services & Supplies and Distribution Services. See Item 1. “Business” for a discussion of each of these business segments.
Operating Environment Overview
Our results are dependent on, among other things, the level of worldwide oil and gas drilling, well remediation activity, the price of crude oil and natural gas, capital spending by other oilfield service companies and drilling contractors, and the worldwide oil and gas inventory levels. Key industry indicators for the past three years include the following:
*
Averages for the years indicated. See sources below.
The following table details the U.S., Canadian, and international rig activity and West Texas Intermediate Oil prices for the past nine quarters ended December 31, 2009 on a quarterly basis:
Source: Rig count: Baker Hughes, Inc. (www.bakerhughes.com); West Texas Intermediate Crude Price: Department of Energy, Energy Information Administration (www.eia.doe.gov).
The average price per barrel of West Texas Intermediate Crude was $61.65 per barrel in 2009, a decrease of 38.1% over the average price for 2008 of $99.63 per barrel. Average natural gas prices were $3.95 per mmbtu, a decrease of 55.4% compared to the 2008 average of $8.86 per mmbtu. Lower oil prices led to reduced rig activity worldwide, decreasing 30.9% for the full year in 2009 compared to 2008. Average crude oil prices for the fourth quarter of 2009 was $76.06 per barrel and natural gas was $4.34 per mmbtu.
At February 5, 2010, there were 1,335 rigs actively drilling in the U.S., compared to 1,189 rigs at December 31, 2009; an increase of 12.3% from year-end 2009 levels. The price of oil and gas had dropped to $71.15 per barrel and $5.52 per mmbtu, respectively, at February 5, 2010 representing 10.4% (oil) and 5.2% (gas) declines from the end of 2009.
EXECUTIVE SUMMARY
National Oilwell Varco produced $1.5 billion in net income or $3.52 per fully diluted share in 2009. Revenues of $12.7 billion declined five percent from 2008 as stated, but declined nine percent when including full-year 2008 pro forma sales for Grant Prideco, which the Company acquired in April 2008. Operating profit was $2.3 billion in 2009, compared to $2.9 billion in 2008. Generally 2009 was a more challenging year than 2008, as a worldwide recession led to lower demand for oil and gas and lower commodity prices, which led in turn to lower oil and gas drilling activity. This development negatively affected many of our businesses, but was partly offset by results from our Rig Technology segment which carried a high level of contracted work into the year, and produced higher year-over-year revenues. Profitability was adversely affected by intangible asset impairment, transaction, voluntary early retirement and other restructuring charges in 2009 that totaled $234 million pre-tax or $0.37 per dilutive share after tax. Excluding these items earnings would have been $3.89 per diluted share.
For its fourth quarter ended December 31, 2009, National Oilwell Varco generated earnings of $394 million or $0.94 per fully diluted share, on revenues of $3.1 billion. Compared to the fourth quarter of 2008 revenue declined 18 percent and net income attributable to the Company declined 33 percent. Compared to the third quarter of 2009 revenue increased two percent and net income attributable to the Company increased two percent. Fourth quarter 2009 operating profit was $622 million or 19.8 percent of sales, compared to $618 million or 20.0 percent of sales in the third quarter of 2009, and $877 million or 23.0 percent of sales in the fourth quarter of 2008, excluding transaction and restructuring charges from all periods. Year-over-year quarterly declines across all segments were a result of lower activity and pricing in most oilfield markets. The modest sequential improvement in the fourth quarter of 2009 was driven by higher sequential activity in North American markets driving better results from the Company’s Petroleum Services & Supplies and Distribution Services segments, offset by slightly lower results from Rig Technology.
Oil & Gas Equipment and Services Market
Worldwide developed economies turned down sharply late in 2008 as looming housing-related asset write-downs at major financial institutions paralyzed credit markets and sparked a serious global banking crisis. Major central banks have responded vigorously, but credit and financial markets have not yet fully recovered, and a credit-driven worldwide economic recession deepened during the second quarter. Asset and commodity prices, including oil and gas prices, have declined sharply. After rising steadily for six years to peak at around $147 per barrel earlier in 2008, oil prices collapsed back to average $42.91 per barrel during the first quarter of 2009, but have been recovering steadily to average $76.06 per barrel during the fourth quarter of 2009. Higher oil and gas prices over the past several years led to high levels of exploration and development drilling in many oil and gas basins around the globe by 2008, but activity slowed sharply in 2009 with lower oil and gas prices and tightening credit availability.
The count of rigs actively drilling in the U.S. as measured by Baker Hughes (a good measure of the level of oilfield activity and spending) peaked at 2,031 rigs in September 2008, but decreased to a low of 876 in June 2009. Rig count has increased to 1,335 in February 2010, and averaged 1,108 rigs during the fourth quarter of 2009. Many oil and gas operators reliant on external financing to fund their drilling programs significantly curtailed their drilling activity earlier in the year, but drilling appears to be recovering across North America as gas prices firmed above $4.00 per mmbtu (the fourth quarter average was $4.34 per mmbtu). Most international activity is driven by oil exploration and production by national oil companies, which has historically been less susceptible to short-term commodity price swings, but the international rig count has exhibited modest declines nonetheless, falling from its September 2008 peak of 1,108 to 986 in September 2009, but recently climbing back to 1,047 in January 2010. During the year the Company saw its Petroleum Services & Supplies and its Distribution Services margins affected most acutely by a drilling downturn, through both volume and price declines; nevertheless, both of these segments saw prices stabilize and revenues recover modestly from the third quarter to the fourth quarter. The Company’s Rig Technology segment was less impacted through the year owing to its high level of contracted backlog and strong execution during the year.
Recent downturns followed an extended period of high drilling activity which fueled strong demand for oilfield services between 2003 and 2008. Incremental drilling activity through the upswing shifted toward harsh environments, employing increasingly sophisticated technology to find and produce reserves. Higher utilization of drilling rigs tested the capability of the world’s fleet of rigs, much of which is old and of limited capability. Technology has advanced significantly since most of the existing rig fleet was built. The industry invested little during the late 1980’s and 1990’s on new drilling equipment, but drilling technology progressed steadily nonetheless, as the Company and its competitors continued to invest in new and better ways of drilling. As a consequence, the safety, reliability, and efficiency of new, modern rigs surpass the performance of most of the older rigs at work today. Drilling rigs are now being pushed to drill deeper wells, more complex wells, highly deviated wells and horizontal wells, tasks which require larger rigs with more capabilities. The drilling process effectively consumes the mechanical components of a rig, which wear out and need periodic repair or replacement. This process was accelerated by very high rig utilization and wellbore complexity. Drilling consumes rigs; more complex and challenging drilling consumes rigs faster.
The industry responded by launching many new rig construction projects since 2005 to: 1.) retool the existing fleet of jackup rigs (according to Offshore Data Services, 72 percent of the existing 457 jackup rigs are more than 25 years old); 2.) replace older mechanical and DC electric land rigs with improved AC power, electronic controls, automatic pipe handling and rapid rigup and rigdown technology; and 3.) build out additional deepwater floating drilling rigs, including semisubmersibles and drillships, to employ recent advancements in deepwater drilling to exploit unexplored deepwater basins. We believe that the newer rigs offer considerably higher efficiency, safety, and capability, and that many will effectively replace a portion of the existing fleet, and that declining dayrates may accelerate the retirement of older rigs. As a result of these trends the Company’s Rig Technology segment grew its backlog of capital equipment orders from $0.9 billion at March 31, 2005, to $11.8 billion at September 30, 2008. However, as a result of the credit crisis and slowing drilling activity, orders have declined below amounts flowing out of backlog as revenue, causing the backlog to decline to $6.4 billion at December 31, 2009.
The land rig backlog comprised 11 percent, and equipment destined for offshore operations comprised 89 percent of the total backlog as of December 31, 2009. Equipment destined for international markets totaled 92 percent of the backlog. The Company believes that its existing contracts for rig equipment are very strong in that they carry significant down payment and progress billing terms favorable to the ultimate completion of these projects, and generally do not allow customers to cancel projects for convenience. During 2009 the Company removed $259 million in discontinued orders on cancelled projects and project change orders requested by customers. We do not expect the credit crisis or softer market to result in additional material cancellation of contracts or abandonment of major projects; however, there can be no assurance that such discontinuance of projects will not occur. The Company had approximately $274 million of projects in its December 31, 2009 backlog that it considers at risk.
Segment Performance
Rig Technology generated a record $8.1 billion in revenue and $2.3 billion in operating profit in 2009, producing operating margins for the segment of 28.2 percent, excluding transaction and restructuring charges. The segment generated 55 percent operating profit leverage or flow-through (the change in operating profit divided by the change in revenue period-to-period) on eight percent higher sales as compared to 2008, excluding charges. Revenue out of backlog of $6.2 billion increased 18 percent from the prior year. Execution of the backlog orders was very strong, which led to higher margin performance for the Rig Technology segment in the third quarter due to excellent cost control, deflation in certain inputs, greater experience building and commissioning rigs which enables better efficiencies, and somewhat better foreign currency exchange movements. As a result our estimated costs to complete projects declined steadily through 2009. As of December 31, 2009 the scheduled outflow of revenue from backlog is expected to be approximately $4.6 billion in 2010, and $1.5 billion for 2011, and $0.3 billion in 2012. From 2005 through the current quarter, the segment has delivered over 70 newly built offshore rigs. Aftermarket spare parts and services revenue was $1.4 billion in 2009 or 17 percent of total segment sales. The balance of Rig Technology revenues were smaller capital items which the Company does not book into its backlog. These items were adversely affected by lower purchases by many land contractors in view of markedly softer drilling demand during the year. Demand for offshore rigs and equipment is strongest in Brazil, owing to significant drilling equipment needs to develop new ultradeepwater discoveries, and the segment also continues to pursue a variety of new offshore rig, intervention vessel, FPSO and platform upgrade opportunities in other markets. However, tight credit markets and fewer committed term contracts for rigs by oil and gas companies as compared to market conditions in 2006-2008 are adversely affecting new orders. Demand for land rig and well stimulation equipment has also been very slow, except for the Middle East and certain Latin American markets, but resumed late in the year in the U.S. Additionally, demand for coiled tubing units and pressure pumping equipment for both North America and international markets also recovered late in the year.
The Petroleum Services & Supplies segment generated revenues of $3.7 billion and operating profit of $0.5 billion or 12.1 percent of sales in 2009, excluding impairment, transaction and restructuring charges. Revenues declined 29 percent from 2008, when including pro forma revenue for Grant Prideco, and decremental operating leverage or flow-through was 55 percent from 2008, excluding charges, due to a high level of price discounting on most products and services through the year. Prices appeared to stabilize during the fourth quarter of 2009, settling roughly 25 percent below peak pricing levels of 2008 (although some products and services are at greater, and some at lesser, levels of discounting). Sharply rising North American rig counts led to modestly tightening supplies of many of the segment’s products, which contributed to the stabilization. As working rigs were stacked during 2009 their owners tended to cannibalize consumables and smaller capital items from these rather than purchase goods from the Company. During the fourth quarter some of these rigs were restocked with new goods, which led to new orders for the Company and benefitted its fourth quarter results in North America. International demand remained somewhat stable, and did not turn down as sharply earlier in the year as gas-driven North American drilling. Drill pipe sales remain challenged due to the large amount of idle drill pipe inventory remaining with drilling contractors. Nevertheless, drill pipe margins have remained good due to lower costs and a positive mix shift toward premium drill pipe, for new offshore rigs being delivered, and for complex horizontal and extended reach drilling programs onshore. We do not expect drill pipe demand to recover significantly until inventories are depleted through consumption, late in 2010 at the earliest. In total the Petroleum Services & Supplies segment generated approximately 47 percent of its sales into North American markets, and 53 percent of its sales into international markets, during 2009.
The Distribution Services segment generated total sales of $1.4 billion in 2009, down 24 percent from 2008 sales. Operating profit excluding transaction and restructuring charges was $50 million or 3.7 percent of sales. Decremental operating leverage or flow-through was 19 percent on the $422 million sales decline from the prior year, higher than the segment’s historical average, due largely to price discounting in North America, which comprised 70 percent of the segment’s revenue in 2009. The segment’s lower results were driven by a much lower level of drilling activity, which led to intense price pressure and lower volumes for the group. International results were generally much more stable in 2009 as compared to 2008, as higher sales of artificial lift products into Latin America helped offset declines elsewhere. The segment posted 8 percent higher quarterly sequential results in the fourth quarter of 2009 as the North American rig count moved up sharply and customers ordered MRO supplies for rigs going back to work. Specifically new unconventional shale gas fields in the Marcellus, Haynesville, Bakken and other areas led most of the recovery.
Outlook
The credit market downturn, global recession, and lower commodity prices presented significant challenges to our business in 2009. Consequently we remain cautious in our outlook for 2010, but we believe we are seeing signs of stabilization in many of our markets, and are encouraged by limited demand growth in North America seen late in the year. Order levels for new drilling rigs declined significantly in 2009 as compared to 2008, but we continue to bid a number of large projects, including up to 28 new offshore floating rigs to be built in Brazil. We are hopeful that these will translate into more orders during the coming year, assuming, among other things, that rig dayrates generally hold up well; that commodity prices remain high; and that broad economic conditions do not deteriorate further. North American land gas drilling activity, particularly by independent gas producers reliant on external financing, fell sharply early in 2009, but we believe better commodity prices are leading to recovery as we enter 2010. Our outlook for international markets, which are more driven by national oil company activity and are historically less volatile, remains good owing to high and stable oil price levels established through the second half of 2009.
Our outlook for the Company’s Petroleum Services & Supplies segment and Distribution Services segment remains closely tied to the rig count, particularly in North America. If the rig count continues to increase we expect these segments to benefit from higher demand for the services, consumables and capital items they supply. The Rig Technology segment was less affected by the downturn during 2009 due to the strength of its backlog, but as the backlog has declined we expect to see revenues and margins decline through 2010 as well.
On January 8, 2010, the Venezuelan government announced a currency devaluation which included a two tier exchange rate system. The Company has net assets employed in Venezuela of approximately $80 million, and generated revenue and operating profit of approximately $75 million and $10 million, respectively, in 2009. We expect to incur a pre-tax charge between $20 million and $30 million in the first quarter of 2010 related to the impact of the currency devaluation and changes to social regulations impacting our operations in Venezuela.
The Company believes it is well positioned to continue to manage through this downturn, and should benefit from its strong balance sheet and capitalization, access to credit, and a high level of contracted orders which are expected to continue to generate earnings in the coming year. The Company has a long history of cost-control and downsizing in response to depressed market conditions, and of executing strategic acquisitions during difficult periods. Such a period may present opportunities to the Company to effect new organic growth and acquisition initiatives, and we remain hopeful that a downturn will generate new opportunities.
Results of Operations
Years Ended December 31, 2009 and December 31, 2008
The following table summarizes the Company’s revenue and operating profit by operating segment in 2009 and 2008. The actual results include results from Grant Prideco operations from the acquisition date of April 21, 2008 (in millions):
Rig Technology
Rig Technology revenue for the year ended December 31, 2009 was $8,093 million, an increase of $565 million (7.5%) compared to 2008. Revenue out of backlog increased $934 million or 18% from 2008 due to an increase in the number of large rig projects delivered this year. Non-backlog revenue decreased $369 million or 17% compared to 2008, largely due to lower spare parts and capital equipment sales as North American land drillers and pressure pumpers decreased their capital spending in 2009.
Operating profit from Rig Technology was $2,283 million for the year ended December 31, 2009, an increase of $313 million (15.9%) over the same period of 2008. Operating profit percentage increased to 28.2%, up from 26.2% in 2008 primarily due to the increased manufacturing efficiencies and revision of cost estimates on large rig projects as a result of favorable pricing from vendors.
The Rig Technology group monitors its capital equipment backlog to plan its business. New orders are added to backlog only when we receive a firm written order for major drilling rig components or a signed contract related to a construction project. The capital equipment backlog was $6.4 billion at December 31, 2009, a decrease of $4.7 billion (42.3%) from backlog of $11.1 billion at December 31, 2008. Approximately $4.6 billion of the current backlog is expected to be delivered in 2010.
Petroleum Services & Supplies
Revenue from Petroleum Services & Supplies was $3,745 million for 2009 compared to $4,651 million for 2008, a decrease of $906 million (19.5%). The decrease was primarily attributable to a 42% decline in North American average rig count activity in 2009 compared to 2008.
Operating profit from Petroleum Services & Supplies was $301 million for 2009 compared to $1,044 million for 2008, a decrease of $743 million (71.2%). Operating profit percentage decreased to 8.0% down from 22.4% in 2008. The decrease was primarily due to reduced North American rig count activity combined with strong price competition. In addition, a $147 million impairment charge was incurred on the carrying value of a trade name associated with this segment in the second quarter of 2009.
Distribution Services
Revenue from Distribution Services totaled $1,350 million for 2009, a decrease of $422 million (23.8%) from 2008. The decrease in revenue is mainly concentrated in the North American region as average drilling activity declined 42% in 2009 compared to the prior year.
Operating profit decreased in 2009 to $50 million compared to $130 million in 2008. Operating profit percentage decreased to 3.7% in 2009 from 7.3% in 2008 as a result of strong price competition and volume declines as North American rig activity declined.
Unallocated expenses and eliminations
Unallocated expenses and eliminations were $319 million for the year ended December 31, 2009 compared to $226 million for 2008. The increase in unallocated expenses and eliminations was primarily due to the voluntary retirement costs of $46 million. Acquisition costs also contributed to the increase from 2008.
Interest and financial costs
Interest and financial costs were $53 million for 2009 compared to $67 million for 2008. The decrease in interest and financial costs were primarily a direct result of the repayment of borrowings on the Company’s credit facility used to purchase Grant Prideco, the repayment of the Company’s 7.5% Senior Notes and the repayment of a portion of the Company’s 6.125% Senior Notes. These repayments occurred during 2008 causing lower debt levels in 2009.
Equity Income in Unconsolidated Affiliate
Equity income in unconsolidated affiliate was $47 million for 2009 compared to $42 million for 2008 and was related to the April 21, 2008 acquisition of Grant Prideco. The income was related to the equity earnings from the Company’s 50.01% investment in Voest-Alpine Tubulars (“VAT”) located in Kindberg, Austria.
Other income (expense), net
Other income (expense), net was expense, net of $110 million in 2009 compared to income, net of $23 million in 2008. The 2009 expense was primarily due to a net foreign exchange loss of $79 million, as compared to a net foreign exchange gain of $50 million in 2008. The 2009 foreign exchange losses were primarily due to adjustments of our hedge positions as a result of the current economic environment and the strengthening of the Euro, the British pound sterling, Canadian dollar and Norwegian krone compared to the U.S. dollar. See
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
We are exposed to changes in foreign currency exchange rates and interest rates. Additional information concerning each of these matters follows:
Foreign Currency Exchange Rates
We have extensive operations in foreign countries. The net assets and liabilities of these operations are exposed to changes in foreign currency exchange rates, although such fluctuations generally do not affect income since their functional currency is typically the local currency. These operations also have net assets and liabilities not denominated in the functional currency, which exposes us to changes in foreign currency exchange rates that impact income. During the years ended December 31, 2009, 2008 and 2007, the Company reported foreign currency gains (losses) of ($79) million, $50 million, and ($7) million, respectively. The gains and losses are primarily due to exchange rate fluctuations related to monetary asset balances denominated in currencies other than the functional currency and in 2009 adjustments to our hedged positions as a result of the current economic environment. Strengthening of currencies against the U.S. dollar may create losses in future periods to the extent we maintain net assets and liabilities not denominated in the functional currency of the countries using the local currency as their functional currency.
Some of our revenues in foreign countries are denominated in U.S. dollars, and therefore, changes in foreign currency exchange rates impact our earnings to the extent that costs associated with those U.S. dollar revenues are denominated in the local currency. Similarly some of our revenues are denominated in foreign currencies, but have associated U.S. dollar costs, which also give rise to foreign currency exchange rate exposure. In order to mitigate that risk, we may utilize foreign currency forward contracts to better match the currency of our revenues and associated costs. We do not use foreign currency forward contracts for trading or speculative purposes.
The following table details the Company’s foreign currency exchange risk grouped by functional currency and their expected maturity periods as of December 31, 2009 (in millions except for rates):
The Company had other financial market risk sensitive instruments denominated in foreign currencies totaling $75 million as of December 31, 2009 excluding trade receivables and payables, which approximate fair value. These market risk sensitive instruments consisted of cash balances and overdraft facilities. The Company estimates that a hypothetical 10% movement of all applicable foreign currency exchange rates on these financial market risk sensitive instruments could affect net income by $5 million.
The counterparties to forward contracts are major financial institutions. The credit ratings and concentration of risk of these financial institutions are monitored on a continuing basis. In the event that the counterparties fail to meet the terms of a foreign currency contract, our exposure is limited to the foreign currency rate differential.
We assess the functional currencies of our operating units to ensure that the appropriate currencies are utilized in accordance with the guidance of ASC Topic 830 “Foreign Currency Matters”. Effective January 1, 2008, we changed the functional currency of our Rig Technology unit in Norway from the Norwegian krone to the U.S. dollar to more appropriately reflect the primary economic environment in which they operate. This change was precipitated by significant changes in the economic facts and circumstances, including: the increased order rate for large drilling platforms and components technology, the use of our Norway unit as our preferred project manager of these projects, increasing revenue and cost base in U.S. dollars, and the implementation of an international cash pool denominated in U.S. dollars. As a Norwegian krone functional unit, Norway was subject to increasing foreign currency exchange risk as a result of these changes in its economic environment and was dependent upon significant hedging transactions to offset its non-functional currency positions.
At December 31, 2007, our Norway operations had foreign currency forward contracts with notional amounts aggregating $2,551 million with a fair value of $91 million to mitigate foreign currency exchange risk against the U.S. dollar, our reporting currency. Effective with the change in the functional currency, the Company terminated these hedges. The related net gain position of $109 million associated with the terminated hedges has been deferred and is being recognized into earnings in the future period(s) the forecasted transactions affect earnings, of which $10 million remains to be recognized into future earnings at December 31, 2009. The Company has subsequent to January 1, 2008, entered into new hedges to cover the exposures as a result of the changes to U.S. dollar functional. At December 31, 2009, our Norway operations had derivatives with $2,024 million in notional value with a fair value of $58 million, included in the table above.
Interest Rate Risk
At December 31, 2009 our long term borrowings consisted of $150 million in 6.5% Senior Notes, $200 million in 7.25% Senior Notes, $200 million in 5.65% Senior Notes, $150 million in 5.5% Senior Notes and $151 million in 6.125% Senior Notes. We occasionally have borrowings under our credit facility, and a portion of these borrowings could be denominated in multiple currencies which could expose us to market risk with exchange rate movements. These instruments carry interest at a pre-agreed upon percentage point spread from LIBOR, NIBOR or EURIBOR, or at the prime interest rate. Under our credit facility, we may, at our option, fix the interest rate for certain borrowings based on a spread over LIBOR, NIBOR or EURIBOR for 30 days to 6 months.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Attached hereto and a part of this report are financial statements and supplementary data listed in Item 15. “Exhibits and Financial Statement Schedules”.
ITEM 9.
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE.
None.
ITEM 9A. CONTROLS AND PROCEDURES
(i)
Evaluation of disclosure controls and procedures
As required by SEC Rule 13a-15(b), we have evaluated, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this report. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by the Company in reports that it files under the Exchange Act is accumulated and communicated to the Company’s management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. Our principal executive officer and principal financial officer have concluded that our current disclosure controls and procedures were effective as of December 31, 2009 at the reasonable assurance level.
Pursuant to section 302 of the Sarbanes-Oxley Act of 2002, our Chief Executive Officer and Chief Financial Officer have provided certain certifications to the Securities and Exchange Commission. These certifications are included herein as Exhibits 31.1 and 31.2.
(ii) Internal Control Over Financial Reporting
(a) Management’s annual report on internal control over financial reporting.
The Company’s management report on internal control over financial reporting is set forth in this annual report on Page 59 and is incorporated herein by reference.
(b) Changes in internal control
There were no changes in the Company’s internal control over financial reporting that occurred during the Company’s last fiscal quarter covered by this report that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.
ITEM 9B. OTHER INFORMATION
None.
PART III
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
Incorporated by reference to the definitive Proxy Statement for the 2010 Annual Meeting of Stockholders.
ITEM 11. EXECUTIVE COMPENSATION
Incorporated by reference to the definitive Proxy Statement for the 2010 Annual Meeting of Stockholders.
ITEM 12.
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
Incorporated by reference to the definitive Proxy Statement for the 2010 Annual Meeting of Stockholders.
Securities Authorized for Issuance Under Equity Compensation Plans.
The following table sets forth information as of our fiscal year ended December 31, 2009, with respect to compensation plans under which our common stock may be issued:
(1)
Shares could be issued through equity instruments other than stock options, warrants or rights; however, none are anticipated during 2010.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
Incorporated by reference to the definitive Proxy Statement for the 2010 Annual Meeting of Stockholders.
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
Incorporated by reference to the definitive Proxy Statement for the 2010 Annual Meeting of Stockholders.
PART IV
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
Financial Statements and Exhibits
(1) Financial Statements
The following financial statements are presented in response to Part II, Item 8:
Page
Consolidated Balance Sheets
Consolidated Statements of Income
Consolidated Statements of Cash Flows
Consolidated Statements of Stockholders’ Equity and Comprehensive Income
Notes to Consolidated Financial Statements
(2) Financial Statement Schedule
Schedule II - Valuation and Qualifying Accounts
All schedules, other than Schedule II, are omitted because they are not applicable, not required or the information is included in the financial statements or notes thereto.
(3) Exhibits
2.1
Amended and Restated Agreement and Plan of Merger, effective as of August 11, 2004 between National-Oilwell, Inc. and Varco International, Inc. (4)
2.2
Agreement and Plan of Merger, effective as of December 16, 2007, between National Oilwell Varco, Inc., NOV Sub, Inc., and Grant Prideco, Inc. (8)
3.1
Amended and Restated Certificate of Incorporation of National-Oilwell, Inc. (Exhibit 3.1) (1)
3.2
Amended and Restated By-laws of National Oilwell Varco, Inc. (Exhibit 3.1) (9)
10.1
Employment Agreement dated as of January 1, 2002 between Merrill A. Miller, Jr. and National Oilwell. (Exhibit 10.1) (2)
10.2
Employment Agreement dated as of January 1, 2002 between Dwight W. Rettig and National Oilwell, with similar agreement with Mark A. Reese. (Exhibit 10.2) (2)
10.3
Form of Amended and Restated Executive Agreement of Clay C. Williams. (Exhibit 10.12) (3)
10.4
National Oilwell Varco Long-Term Incentive Plan. (5)*
10.5
Form of Employee Stock Option Agreement. (Exhibit 10.1) (6)
10.6
Form of Non-Employee Director Stock Option Agreement. (Exhibit 10.2) (6)
10.7
Form of Performance-Based Restricted Stock. (18 Month) Agreement (Exhibit 10.1) (7)
10.8
Form of Performance-Based Restricted Stock. (36 Month) Agreement (Exhibit 10.2) (7)
10.9
Five-Year Credit Agreement, dated as of April 21, 2008, among National Oilwell Varco, Inc., the financial institutions signatory thereto, including Wells Fargo Bank, N.A., in their capacities as Administrative Agent, Co-Lead Arranger and Joint Book Runner, DnB Nor Bank ASA, as Co-Lead Arranger and Joint Book Runner, and Fortis Capital Corp., The Bank of Nova Scotia and The Bank of Tokyo - Mitsubishi UFJ, Ltd., as Co-Documentation Agents. (Exhibit 10.1) (10)
10.10
First Amendment to Employment Agreement dated as of December 22, 2008 between Merrill A. Miller, Jr. and National Oilwell Varco. (Exhibit 10.1) (11)
10.11
Second Amendment to Executive Agreement, dated as of December 22, 2008 of Clay Williams and National Oilwell Varco. (Exhibit 10.2) (11)
10.12
First Amendment to Employment Agreement dated as of December 22, 2008 between Mark A. Reese and National Oilwell Varco. (Exhibit 10.3) (11)
10.13
First Amendment to Employment Agreement dated as of December 22, 2008 between Dwight W. Rettig and National Oilwell Varco. (Exhibit 10.4) (11)
10.14
Employment Agreement dated as of December 22, 2008 between Robert W. Blanchard and National Oilwell Varco. (Exhibit 10.5) (11)
10.15
First Amendment to National Oilwell Varco Long-Term Incentive Plan. (12)*
10.16
Second Amendment to Employment Agreement dated as of December 31, 2009 between Merrill A. Miller, Jr. and National Oilwell Varco. (Exhibit 10.1) (13)
10.17
Third Amendment to Executive Agreement, dated as of December 31, 2009, of Clay Williams and National Oilwell Varco. (Exhibit 10.2) (13)
10.18
Second Amendment to Employment Agreement dated as of December 31, 2009 between Mark A. Reese and National Oilwell Varco. (Exhibit 10.3) (13)
10.19
Second Amendment to Employment Agreement dated as of December 31, 2009 between Dwight W. Rettig and National Oilwell Varco. (Exhibit 10.4) (13)
10.20
First Amendment to Employment Agreement dated as of December 31, 2009 between Robert W. Blanchard and National Oilwell Varco. (Exhibit 10.5) (13)
21.1
Subsidiaries of the Registrant.
23.1
Consent of Ernst & Young LLP.
24.1
Power of Attorney. (included on signature page hereto)
31.1
Certification pursuant to Rule 13a-14a and Rule 15d-14(a) of the Securities and Exchange Act, as amended.
31.2
Certification pursuant to Rule 13a-14a and Rule 15d-14(a) of the Securities and Exchange Act, as amended.
32.1
Certification pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2
Certification pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
The following materials from our Annual Report on Form 10-K for the period ended December 31, 2009 formatted in eXtensible Busine Reporting Language (XBRL): (i) Consolidated Balance Sheets, (ii) Consolidated Statements of Income, (iii) Consolidated Statements Cash Flows, and (iv) Notes to the Consolidated Financial Statements, tagged as block text. (13)
*
Compensatory plan or arrangement for management or others.
(1)
Filed as an Exhibit to our Quarterly Report on Form 10-Q filed on August 11, 2000.
(2)
Filed as an Exhibit to our Annual Report on Form 10-K filed on March 28, 2002.
(3)
Filed as an Exhibit to Varco International, Inc.’s Quarterly Report on Form 10-Q filed on May 6, 2004.
(4)
Filed as Annex A to our Registration Statement on Form S-4 filed on September 16, 2004.
(5)
Filed as Annex D to our Amendment No. 1 to Registration Statement on Form S-4 filed on January 31, 2005.
(6)
Filed as an Exhibit to our Current Report on Form 8-K filed on February 23, 2006.
(7)
Filed as an Exhibit to our Current Report on Form 8-K filed on March 27, 2007.
(8)
Filed as Annex A to our Registration Statement on Form S-4 filed on January 28, 2008.
(9)
Filed as an Exhibit to our Current Report on Form 8-K filed on February 21, 2008.
(10)
Filed as an Exhibit to our Current Report on Form 8-K filed on April 22, 2008.
(11)
Filed as an Exhibit to our Current Report on Form 8-K filed on December 23, 2008.
(12)
Filed as Appendix I to our Proxy Statement filed on April 1, 2009.
(13)
Filed as an Exhibit to our Current Report on Form 8-K filed on January 5, 2010.
(14)
As provided in Rule 406T of Regulation S-T, this information is furnished and not filed for purposes of
Sections 11 and 12 of the Securities Act of 1933 and Section 18 of the Securities Exchange Act of 1934.
We hereby undertake, pursuant to Regulation S-K, Item 601(b), paragraph (4) (iii), to furnish to the U.S. Securities and Exchange Commission, upon request, all constituent instruments defining the rights of holders of our long-term debt not filed herewith.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
NATIONAL OILWELL VARCO, INC.
Dated: February 26, 2010 By: /s/ MERRILL A. MILLER, JR.
Merrill A. Miller, Jr.
Chairman, President and Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
Each person whose signature appears below in so signing, constitutes and appoints Merrill A. Miller, Jr. and Clay C. Williams, and each of them acting alone, his true and lawful attorney-in-fact and agent, with full power of substitution, for him and in his name, place and stead, in any and all capacities, to execute and cause to be filed with the Securities and Exchange Commission any and all amendments to this report, and in each case to file the same, with all exhibits thereto and other documents in connection therewith, and hereby ratifies and confirms all that said attorney-in-fact or his substitute or substitutes may do or cause to be done by virtue hereof.
Signature
Title
Date
/s/ MERRILL A. MILLER, JR.
Merrill A. Miller, Jr.
Chairman, President and Chief Executive Officer
February 26, 2010
/s/ CLAY C. WILLIAMS
Clay C. Williams
Executive Vice President and Chief Financial Officer
February 26, 2010
/s/ ROBERT W. BLANCHARD
Robert W. Blanchard
Vice President, Corporate Controller and Chief Accounting Officer
February 26, 2010
/s/ GREG L. ARMSTRONG
Greg L. Armstrong
Director
February 26, 2010
/s/ ROBERT E. BEAUCHAMP
Robert E. Beauchamp
Director
February 26, 2010
/s/ BEN A. GUILL
Ben A. Guill
Director
February 26, 2010
/s/ DAVID D. HARRISON
David D. Harrison
Director
February 26, 2010
/s/ ROGER L. JARVIS
Roger L. Jarvis
Director
February 26, 2010
/s/ ERIC L. MATTSON
Eric L. Mattson
Director
February 26, 2010
/s/ JEFFERY A. SMISEK
Jeffery A. Smisek
Director
February 26, 2010
MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
National Oilwell Varco, Inc.’s management is responsible for establishing and maintaining adequate internal control over financial reporting. National Oilwell Varco, Inc.’s internal control system was designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.
Internal control over financial reporting cannot provide absolute assurance of achieving financial reporting objectives because of its inherent limitations. Internal control over financial reporting is a process that involves human diligence and compliance and is subject to lapses in judgment and breakdowns resulting from human failures. Internal control over financial reporting also can be circumvented by collusion or improper management override. Because of such limitations, there is a risk that material misstatements may not be prevented or detected on a timely basis by internal control over financial reporting. However, these inherent limitations are known features of the financial reporting process. Therefore, it is possible to design into the process safeguards to reduce, though not eliminate, this risk.
Management has used the framework set forth in the report entitled “Internal Control-Integrated Framework” published by the Committee of Sponsoring Organizations (“COSO”) of the Treadway Commission to evaluate the effectiveness of the Company’s internal control over financial reporting. Management has concluded that the Company’s internal control over financial reporting was effective as of December 31, 2009.
The effectiveness of our internal control over financial reporting as of December 31, 2009, has been audited by Ernst & Young LLP, the independent registered public accounting firm which also has audited the Company’s Consolidated Financial Statements included in this Annual Report on Form 10-K.
/s/ Merrill A. Miller, Jr.
Merrill A. Miller, Jr.
Chairman, President and Chief Executive Officer
/s/ Clay C. Williams
Clay C. Williams
Executive Vice President and Chief Financial Officer
Houston, Texas
February 26, 2010
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors and Stockholders
National Oilwell Varco, Inc.
We have audited the accompanying consolidated balance sheets of National Oilwell Varco, Inc. as of December 31, 2009 and 2008, and the related consolidated statements of income, stockholders’ equity and comprehensive income, and cash flows for each of the three years in the period ended December 31, 2009. Our audits also included the financial statement schedule listed in the Index at Item 15(a). These financial statements and schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and schedule based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of National Oilwell Varco, Inc. at December 31, 2009 and 2008, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2009, in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein.
As discussed in Note 1 to the consolidated financial statements, the Company changed its method of accounting for noncontrolling interests beginning on January 1, 2009.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), National Oilwell Varco, Inc.’s internal control over financial reporting as of December 31, 2009, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 26, 2010 expressed an unqualified opinion thereon.
/s/ ERNST & YOUNG LLP
Houston, Texas
February 26, 2010
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors and Stockholders
National Oilwell Varco, Inc.
We have audited National Oilwell Varco, Inc.’s internal control over financial reporting as of December 31, 2009, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). National Oilwell Varco, Inc.’s management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the company’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, National Oilwell Varco, Inc. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2009, based on the COSO criteria.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of National Oilwell Varco, Inc. as of December 31, 2009 and 2008 and the related consolidated statements of income, stockholders’ equity and comprehensive income, and cash flows for each of the three years in the period ended December 31, 2009, and our report dated February 26, 2010 expressed an unqualified opinion thereon.
/s/ ERNST & YOUNG LLP
Houston, Texas
February 26, 2010
NATIONAL OILWELL VARCO, INC.
CONSOLIDATED BALANCE SHEETS
(In millions, except share data)
The accompanying notes are an integral part of these statements.
NATIONAL OILWELL VARCO, INC.
CONSOLIDATED STATEMENTS OF INCOME
(In millions, except per share data)
The accompanying notes are an integral part of these statements.
NATIONAL OILWELL VARCO, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In millions)
The accompanying notes are an integral part of these statements.
NATIONAL OILWELL VARCO, INC.
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY AND COMPREHENSIVE INCOME
(In millions)
The accompanying notes are an integral part of these statements.
NATIONAL OILWELL VARCO, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. Organization and Basis of Presentation
Nature of Business
We design, construct, manufacture and sell comprehensive systems, components, and products used in oil and gas drilling and production, provide oilfield services and supplies, and distribute products and provide supply chain integration services to the upstream oil and gas industry. Our revenues and operating results are directly related to the level of worldwide oil and gas drilling and production activities and the profitability and cash flow of oil and gas companies, drilling contractors and oilfield service companies, which in turn are affected by current and anticipated prices of oil and gas. Oil and gas prices have been and are likely to continue to be volatile.
Basis of Consolidation
The accompanying Consolidated Financial Statements include the accounts of National Oilwell Varco, Inc. and its majority-owned subsidiaries. All significant intercompany transactions and balances have been eliminated in consolidation. Investments that are not wholly-owned, but where we exercise control, are fully consolidated with the equity held by minority owners and their portion of net income (loss) reflected as noncontrolling interests in the accompanying consolidated financial statements. On January 1, 2009, the Company adopted ASC Topic 810, “Consolidations” and reclassified noncontrolling interests in the amount $96 million from the mezzanine section to equity in the December 31, 2008 balance sheet. Investments in unconsolidated affiliates, over which we exercise significant influence, but not control, are accounted for by the equity method.
2. Summary of Significant Accounting Policies
Fair Value of Financial Instruments
The carrying amounts of 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. The carrying values of other financial instruments approximate their respective fair values.
Derivative Financial Instruments
The Financial Accounting Standards Board (“FASB”) issued ASC Topic 815, “Derivatives and Hedging”. (“ASC Topic 815”) This Standard requires companies to recognize all of its derivative instruments as either assets or liabilities in the statement of financial position at fair value. The accounting changes in the fair value (i.e., gains or losses) of a derivative instrument depends on whether it has been designated and qualifies as part of a hedging relationship and further, on the type of hedging relationship. For those derivative instruments that are designated and qualify as hedging instruments, a company must designate the hedging instrument, based upon the exposure being hedged, as a fair value hedge, cash flow hedge, or a hedge of a net investment in a foreign operation.
The Company is exposed to certain risks relating to its ongoing business operations. The primary risks managed by using derivative instruments are foreign currency exchange rate risk, and interest rate risk. Forward contracts against various foreign currencies are entered into to manage the foreign currency exchange rate risk on forecasted revenue 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). Interest rate swaps are entered into to manage interest rate risk associated with the Company’s fixed and floating-rate borrowings.
The Company records all derivative financial instruments at their fair value in our consolidated balance sheet. Except for certain non-designated hedges discussed below, all derivative financial instruments we hold are designated as either cash flow or fair value 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. We may also use interest rate contracts to mitigate our exposure to changes in interest rates on anticipated long-term debt issuances.
At December 31, 2009, the Company has determined that its financial assets of $104 million and liabilities of $55 million (primarily
currency related derivatives) are level 2 in the fair value hierarchy. At December 31, 2009, the fair value of the Company’s foreign currency forward contracts totaled $49 million.
As of December 31, 2009, the Company did not have any interest rate swaps and our financial instruments do not contain any credit-risk-related or other contingent features that could cause accelerated payments when our financial instruments are in net liability positions. We do not use derivative financial instruments for trading or speculative purposes.
Cash Flow Hedging Strategy
For derivative instruments that are designated and qualify as a cash flow hedge (i.e., hedging the exposure to variability in expected future cash flows that is subject to a particular currency risk), the effective portion of the gain or loss on the derivative instrument is reported as a component of other comprehensive income and reclassified into earnings in the same line item associated with the forecasted transaction and in the same period or periods during which the hedged transaction affects earnings (e.g., in “revenues” when the hedged transactions are cash flows associated with forecasted revenues). The remaining gain or loss on the derivative instrument in excess of the cumulative change in the present value of future cash flows of the hedged item, if any (i.e., the ineffective portion) or hedge components excluded from the assessment of effectiveness, are recognized in the Consolidated Statements of Income during the current period.
As of December 31, 2009, the Company had the following outstanding foreign currency forward contracts that were entered into to hedge nonfunctional currency cash flows from forecasted revenues and costs:
Fair Value Hedging Strategy
For derivative instruments that are designated and qualify as a fair value hedge (i.e., hedging the exposure to changes in the fair value of an asset or a liability or an identified portion thereof that is subject to a particular risk), the gain or loss on the derivative instrument as well as the offsetting loss or gain on the hedged item attributable to the hedged risk are recognized in the same line item associated with the hedged item in current earnings (e.g., in “revenue” when the hedged item is a contracted sale).
The Company enters into forward exchange contracts to hedge certain firm commitments of revenue and costs that are denominated in currencies other than the functional currency of the operating unit. The purpose of the Company’s foreign currency hedging activities is to protect the Company from risk that the eventual U.S. dollar-equivalent cash flows from the sale of products to customers will be adversely affected by changes in the exchange rates.
As of December 31, 2009, the Company had the following outstanding foreign currency forward contracts that were entered into to hedge nonfunctional currency fair values of firm commitments of revenues and costs:
Currency
Foreign Currency
Denomination
(in millions)
U.S. Dollar
$
Non-designated Hedging Strategy
For derivative instruments that are non-designated, the gain or loss on the derivative instrument is recognized in the same line item associated with the hedged item in current earnings.
The Company enters into forward exchange contracts to hedge certain nonfunctional currency monetary accounts. The purpose of the Company’s foreign currency hedging activities is to protect the Company from risk that the eventual U.S. dollar-equivalent cash flows from the nonfunctional currency monetary accounts will be adversely affected by changes in the exchange rates.
As of December 31, 2009, the Company had the following outstanding foreign currency forward contracts that hedge the fair value of nonfunctional currency monetary accounts:
As of December 31, 2009, the Company has the following fair values of its derivative instruments and their balance sheet classifications (in millions):
Derivatives Not Designated as
Location of Gain (Loss)
Amount of Gain (Loss)
Hedging Instruments under
Recognized in Income
Recognized in Income on
ASC Topic 815
on Derivative
Derivative
Foreign exchange contracts
Other income (expense), net
Total
(a)
The Company expects that $(18) million of the Accumulated Other Comprehensive Income (Loss) will be reclassified into earnings within the next twelve months with an offset by gains from the underlying transactions resulting in no impact to earnings or cash flow.
(b)
The amount of gain (loss) recognized in income represents $(24) million related to the ineffective portion of the hedging relationships for the year ended December 31, 2009 and $4 million related to the amount excluded from the assessment of the hedge effectiveness for the year ended December 31, 2009.
We assess the functional currencies of our operating units to ensure that the appropriate currencies are utilized in accordance with the guidance of ASC Topic 830 “Foreign Currency Matters” (“ASC Topic 830”). Effective January 1, 2008, we changed the functional currency of our Rig Technology unit in Norway from the Norwegian krone to the U.S. dollar to more appropriately reflect the primary economic environment in which they operate. This change was precipitated by significant changes in the economic facts and circumstances, including the increased order rate for large drilling platforms and components technology, the use of our Norway unit as our preferred project manager of these projects, increasing revenue and cost base in U.S. dollars, and the implementation of an international cash pool denominated in U.S. dollars. As a Norwegian krone functional unit, Norway was subject to increasing foreign currency exchange risk as a result of these changes in its economic environment and was dependent upon significant hedging transactions to offset its nonfunctional currency positions.
At December 31, 2007, our Norway operations had foreign currency forward contracts with notional amounts aggregating $2,551 million with a fair value of $91 million to mitigate foreign currency exchange risk against the U.S. dollar, our reporting currency. Effective with the change in the functional currency, the Company terminated these hedges. The related net gain position of $109 million associated with the terminated hedges was deferred and is being recognized into earnings in the future period(s) the forecasted transactions affect earnings, of which $10 million remains to be recognized into future earnings at December 31, 2009. The Company has, subsequent to January 1, 2008, entered into new hedges to cover the exposures as a result of the change to U.S. dollar functional. At December 31, 2009, our Norway operations had derivatives with $2,024 million in notional value with a fair value asset of $58 million.
Inventories
Inventories consist of raw materials, work-in-process and oilfield and industrial finished products, manufactured equipment and spare parts. Inventories are stated at the lower of cost or market using the first-in, first-out or average cost methods. Allowances for excess and obsolete inventories are determined based on our historical usage of inventory on-hand as well as our future expectations related to our installed base and the development of new products. The allowance, which totaled $206 million and $123 million at December 31, 2009 and 2008, respectively, is the amount necessary to reduce the cost of the inventory to its estimated realizable value.
Property, Plant and Equipment
Property, plant and equipment are recorded at cost. Expenditures for major improvements that extend the lives of property and equipment are capitalized while minor replacements, maintenance and repairs are charged to operations as incurred. Disposals are removed at cost less accumulated depreciation with any resulting gain or loss reflected in operations. Depreciation is provided using the straight-line method over the estimated useful lives of individual items. Depreciation expense was $249 million, $222 million and $153 million for the years ended December 31, 2009, 2008 and 2007, respectively. The estimated useful lives of the major classes of property, plant and equipment are included in Note 6 to the consolidated financial statements.
Long-lived Assets
We record impairment losses on long-lived assets used in operations when events and circumstances indicate that the assets are impaired and the undiscounted cash flows estimated to be generated by those assets are less than the carrying amount of those assets. The carrying value of assets used in operations that is 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.
Intangible Assets
The Company has approximately $5.5 billion of goodwill and $4.1 billion of identified intangible assets as of December 31, 2009. Generally accepted accounting principles require the Company to test goodwill and other indefinite-lived intangible assets for impairment at least annually or more frequently whenever events or circumstances occur indicating that such assets might be impaired.
Goodwill is identified by segment as follows (in millions):
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 $250 million in each of the next five years. Included in intangible assets are approximately $643 million of indefinite-lived trade names.
Identified intangible assets are identified by segment as follows (in millions):
Identified intangible assets by major classification consist of the following (in millions):
Asset Impairment
During the second quarter of 2009, the worldwide average rig count was 2,009 rigs, down 41% from the fourth quarter 2008 average of 3,395 and down 25% from the first quarter 2009 average of 2,681. The second quarter 2009 average rig count represented the lowest quarterly average in the past six years. In addition, the Company’s updated forecast was behind the Company’s previous forecast completed at the beginning of 2009. While operating profit for the first quarter of 2009 was in line with the Company’s first quarter 2009 operating profit forecast, the Company’s consolidated operating profit for the second quarter of 2009 was below its second quarter 2009 forecast. As a result of the substantial decline in the worldwide rig count, and the decline in actual/forecasted results compared to the original 2009 forecast, the Company concluded that events or circumstances had occurred indicating that goodwill and other indefinite-lived intangible assets might be impaired as described in ASC Topic 350, “Intangibles - Goodwill and Other” (“ASC Topic 350”).
Therefore, the Company performed its interim impairment test of goodwill for its reporting units at the end of the second quarter of 2009. The implied fair value of goodwill is determined by deducting the fair value of a reporting unit’s identifiable assets and liabilities from the fair value of that reporting unit as a whole. Fair value of the reporting units is determined in accordance with ASC Topic 820, “Fair Value Measurements and Disclosures” (“ASC Topic 820”), using significant unobservable inputs, or level 3 in the fair value hierarchy. These inputs are based on internal management estimates, forecasts and judgments, using a combination of three methods: discounted cash flow, comparable companies, and representative transactions. While the Company primarily uses the discounted cash flow method to assess fair value, the Company uses the comparable companies and representative transaction methods to validate the discounted cash flow analysis and further support management’s expectations, where possible.
The discounted cash flow is based on management’s short-term and long-term forecast of operating performance for each reporting unit. The two main assumptions used in measuring goodwill impairment, which bear the risk of change and could impact the Company’s goodwill impairment analysis, include the cash flow from operations from each of the Company’s individual business units and the weighted average cost of capital. The starting point for each of the reporting unit’s cash flow from operations is the detailed annual plan or updated forecast. The detailed planning and forecasting process takes into consideration a multitude of factors including worldwide rig activity, inflationary forces, pricing strategies, customer analysis, operational issues, competitor analysis, capital spending requirements, working capital needs, customer needs to replace aging equipment, increased complexity of drilling, new technology, and existing backlog among other items which impact the individual reporting unit projections. Cash flows beyond the specific operating plans were estimated using a terminal value calculation, which incorporated historical and forecasted financial cyclical trends for each reporting unit and considered long-term earnings growth rates. The financial and credit market volatility directly impacts our fair value measurement through our weighted average cost of capital that we use to determine our discount rate. During times of volatility, significant judgment must be applied to determine whether credit changes are a short-term or long-term trend.
Projections for the remainder of 2009 also reflected declines compared to the original 2009 annual forecast. The Company updated its 2009 operating forecast, long-term forecast, and discounted cash flows based on this information. The goodwill impairment analysis that we performed during the second quarter of 2009 did not result in goodwill impairment as of June 30, 2009.
Other indefinite-lived intangible assets, representing trade names management intends to use indefinitely, were valued using significant unobservable inputs (level 3) and are tested for impairment using the Relief from Royalty Method, a form of the Income Approach. An impairment is measured and recognized based on the amount the book value of the indefinite-lived intangible assets exceeds its estimated fair value as of the date of the impairment test. Included in the impairment test are assumptions, for each trade name, regarding the related revenue streams attributable to the trade names, which are determined in a manner consistent with the forecasting process described above, the royalty rate, and the discount rate applied. Based on the Company’s indefinite-lived intangible asset impairment analysis performed during the second quarter of 2009, the Company incurred an impairment charge of $147 million in the Petroleum Services & Supplies segment related to a partial impairment of the Company’s Grant Prideco trade name. The impairment charge was primarily the result of the substantial decline in worldwide rig counts through June 2009, declines in forecasts in rig activity for the remainder of 2009, 2010, and 2011 compared to rig count forecast at the beginning of 2009, and a decline in the revenue forecast for the drill pipe business unit for the remainder of 2009, 2010, and 2011.
The Company performed its annual impairment analysis for its goodwill and indefinite-lived assets during the fourth quarter of 2009 which resulted in no further impairment. The valuation techniques used in the annual test were consistent with the methodologies described above. The inputs used in the annual test were updated for current market conditions and forecasts.
Foreign Currency
The functional currency for most of our foreign operations is the local currency. The cumulative effects of translating the balance sheet accounts from the functional currency into the U.S. dollar at current exchange rates are included in accumulated other comprehensive income (loss). Revenues and expenses are translated at average exchange rates in effect during the period. Certain other foreign operations use the U.S. dollar as the functional currency. Accordingly, financial statements of these foreign subsidiaries are remeasured to U.S. dollars for consolidation purposes using current rates of exchange for monetary assets and liabilities and historical rates of exchange for nonmonetary assets and related elements of expense. Revenue and expense elements are remeasured at rates that approximate the rates in effect on the transaction dates. For all operations, gains or losses from remeasuring foreign currency transactions into the functional currency are included in income. Net foreign currency transaction gains (losses) were ($79) million, $50 million and ($7) million for the years ending December 31, 2009, 2008 and 2007, respectively, and are included in other income (expense) in the accompanying statement of operations.
As previously discussed, effective January 1, 2008, we changed the functional currency of our Rig Technology unit in Norway from the Norwegian krone to the U.S. dollar to more appropriately reflect the primary economic environment in which they currently operate.
Revenue Recognition
The Company’s products and services are sold based upon purchase orders or contracts with the customer that include fixed or determinable prices and that do not generally include right of return or other similar provisions or other significant post delivery obligations. Except for certain construction contracts and drill pipe sales described below, the Company records revenue at the time its manufacturing process is complete, the customer has been provided with all proper inspection and other required documentation, title and risk of loss has passed to the customer, collectability is reasonably assured and the product has been delivered. Customer advances or deposits are deferred and recognized as revenue when the Company has completed all of its performance obligations related to the sale. The Company also recognizes revenue as services are performed. The amounts billed for shipping and handling cost are included in revenue and related costs are included in cost of sales.
Revenue Recognition under Long-term Construction Contracts
The Company uses the percentage-of-completion method to account for certain long-term construction contracts in the Rig Technology segment. These long-term construction contracts include the following characteristics:
•
the contracts include custom designs for customer specific applications;
•
the structural design is unique and requires significant engineering efforts; and
•
construction projects often have progress payments.
This method requires the Company to make estimates regarding the total costs of the project, progress against the project schedule and the estimated completion date, all of which impact the amount of revenue and gross margin the Company recognizes in each reporting period. The Company prepares detailed cost estimates at the beginning of each project. Significant projects and their related costs and profit margins are updated and reviewed at least quarterly by senior management. Factors that may affect future project costs and margins include shipyard access, weather, production efficiencies, availability and costs of labor, materials and subcomponents and other factors. These factors can impact the accuracy of the Company’s estimates and materially impact the Company’s current and future reported earnings.
The asset, “Costs in excess of billings,” represents revenues recognized in excess of amounts billed. The liability, “Billings in excess of costs,” represents billings in excess of revenues recognized.
Drill Pipe Sales
For drill pipe sales, if requested in writing by the customer, delivery may be satisfied through delivery to the Company’s customer storage location or to a third-party storage facility. For sales transactions where title and risk of loss have transferred to the customer but the supporting documentation does not meet the criteria for revenue recognition prior to the products being in the physical possession of the customer, the recognition of the revenues and related inventory costs from these transactions are deferred until the customer takes physical possession.
Service and Product Warranties
The Company provides service and warranty policies on certain of its products. The Company accrues liabilities under service and warranty policies based upon specific claims and a review of historical warranty and service claim experience in accordance with ASC Topic 450 “Contingencies” (“ASC Topic 450”). Adjustments are made to accruals as claim data and historical experience change. In addition, the Company incurs discretionary costs to service its products in connection with product performance issues and accrues for them when they are encountered.
The changes in the carrying amount of service and product warranties are as follows (in millions):
Income Taxes
The liability method is used to account for income taxes. Deferred tax assets and liabilities are determined based on differences between the financial reporting and tax basis of assets and liabilities and are measured using the enacted tax rates that will be in effect when the differences are expected to reverse. Valuation allowances are established when necessary to reduce deferred tax assets to amounts which are more likely than not to be realized.
Concentration of Credit Risk
We grant credit to our customers, which operate primarily in the oil and gas industry. Concentrations of credit risk are limited because we have a large number of geographically diverse customers, thus spreading trade credit risk. We control credit risk through credit evaluations, credit limits and monitoring procedures. We perform periodic credit evaluations of our customers’ financial condition and generally do not require collateral, but may require letters of credit for certain international sales. Credit losses are provided for in the financial statements. Allowances for doubtful accounts are determined based on a continuous process of assessing the Company’s portfolio on an individual customer basis taking into account current market conditions and trends. This process consists of a thorough review of historical collection experience, current aging status of the customer accounts, and financial condition of the Company’s customers. Based on a review of these factors, the Company will establish or adjust allowances for specific customers. Accounts receivable are net of allowances for doubtful accounts of approximately $95 million and $73 million at December 31, 2009 and 2008, respectively.
Stock-Based Compensation
Compensation expense for the Company’s stock-based compensation plans is measured using the fair value method required by ASC Topic 718 “Compensation - Stock Compensation” (“ASC Topic 718”). Under this guidance the fair value of stock option grants and restricted stock is amortized to expense using the straight-line method over the shorter of the vesting period or the remaining employee service period.
The Company provides compensation benefits to employees and non-employee directors under share-based payment arrangements, including various employee stock option plans.
Total compensation cost that has been charged against income for all share-based compensation arrangements was $68 million, $61 million and $43 million for 2009, 2008 and 2007, respectively. The total income tax benefit recognized in the income statement for all share-based compensation arrangements was $21 million, $19 million and $13 million for 2009, 2008 and 2007, respectively.
Environmental Liabilities
When environmental assessments or remediations are probable and the costs can be reasonably estimated, remediation liabilities are recorded on an undiscounted basis and are adjusted as further information develops or circumstances change.
Use of Estimates
The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect reported and contingent amounts of assets and liabilities as of the date of the financial statements and reported amounts of revenues and expenses during the reporting period. Such estimates include but are not limited to, estimated losses on accounts receivable, estimated costs and related margins of projects accounted for under percentage- of-completion (“POC”), estimated realizable value on excess and obsolete inventory, contingencies, estimated liabilities for litigation exposures and liquidated damages, estimated warranty costs, estimates related to tocpension accounting, estimates related to the fair value of reporting units for purposes of assessing goodwill and other indefinite-lived intangible assets for impairment and estimates related to deferred tax assets and liabilities, including valuation allowances on deferred tax assets. Actual results could differ from those estimates.
Contingencies
The Company accrues for costs relating to litigation claims and other contingent matters, including liquidated damage liabilities, when such liabilities become probable and reasonably estimable. Such estimates may be based on advice from third parties or on management’s judgment, as appropriate. Revisions to contingent liabilities are reflected in income in the period in which different facts or information become known or circumstances change that affect the Company’s previous judgments with respect to the likelihood or amount of loss. Amounts paid upon the ultimate resolution of contingent liabilities may be materially different from previous estimates and could require adjustments to the estimated reserves to be recognized in the period such new information becomes known.
In circumstances where the most likely outcome of a contingency can be reasonably estimated, we accrue a liability for that amount. Where the most likely outcome cannot be estimated, a range of potential losses is established and if no one amount in that range is more likely than others, the low end of the range is accrued.
Net Income Attributable to Company Per Share
The following table sets forth the computation of weighted average basic and diluted shares outstanding (in millions, except per share data):
In addition, we had stock options outstanding that were anti-dilutive totaling 4.0 million, 0.4 million, and 0.1 million at December 31, 2009, 2008 and 2007, respectively.
Recently Issued Accounting Standards
In April 2009 the FASB issued ASC Topic 805, “Business Combinations” (“ASC Topic 805”). ASC Topic 805 amends the provisions for the initial recognition and measurement, subsequent measurement and accounting, and disclosures for assets and liabilities arising from contingencies in business combinations. ASC Topic 805 is effective for contingent assets and contingent liabilities acquired in business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008. The Company expects ASC Topic 805 will have a future impact on its consolidated financial statements, but the nature and magnitude of the specific effects will depend upon the nature, term and size of the acquired contingencies.
In April 2009, the FASB issued ASC Topic 825, “Financial Instruments” (“ASC Topic 825”). ASC Topic 825 extends the annual disclosure requirements regarding the fair value of financial instruments to interim financial statements of publicly traded companies. ASC Topic 825 is effective for interim reporting periods ending after June 15, 2009, with early adoption permitted for periods ending after March 15, 2009. On June 1, 2009, the Company adopted ASC Topic 825. There was no significant impact to the Company’s Consolidated Financial Statements from the adoption of ASC Topic 825.
In May 2009, the FASB issued ASC Topic 855, “Subsequent Events” (“ASC Topic 855”). ASC Topic 855 requires the disclosure of the date through which an entity has evaluated subsequent events and the basis for that date. ASC Topic 855 is effective for fiscal years and interim periods ending after June 15, 2009. On June 1, 2009, the Company adopted ASC Topic 855. There was no significant impact to the Company’s Consolidated Financial Statements from the adoption of ASC Topic 855.
In June 2009, the FASB issued ASC Topic 105, “Generally Accepted Accounting Standards” (“ASC Topic 105”). The ASC is now the source of authoritative U.S. GAAP recognized by the FASB to be applied by nongovernmental entities. Rules and interpretive releases of the SEC under authority of federal securities laws are also sources of authoritative GAAP for SEC registrants. On the effective date, ASC Topic 105 superseded all then-existing non-SEC accounting and reporting standards. All other non-grandfathered non-SEC accounting literature not included in the ASC has become non-authoritative. ASC Topic 105 became effective for financial statements issued for interim and annual periods ending after September 15, 2009.
3. Grant Prideco Merger
Pursuant to the Agreement and Plan of Merger with Grant Prideco, Inc. (“Grant Prideco”) (the “Merger”), a Delaware Corporation, effective December 16, 2007 (the “Agreement Date”), the Company issued .4498 shares of National Oilwell Varco, Inc. common stock and $23.20 in cash (the “Exchange Ratio”) for each Grant Prideco common share outstanding on April 21, 2008 (the “Merger Date”) totaling approximately 57 million shares and $2.9 billion in cash. The Company has included the financial results of Grant Prideco in its Consolidated Financial Statements beginning on the Merger Date, the date Grant Prideco common shares were exchanged for National Oilwell Varco common shares and cash. The Grant Prideco operations are included in the Petroleum Services & Supplies segment.
Prior to its acquisition, Grant Prideco was a world leader in drill stem technology development and drill pipe manufacturing, sales and service and a global leader in drill bit and specialty tools, manufacturing, sales and service. The Company believes the Merger with Grant Prideco advanced its strategic goal of providing more products and services to its customers and that Grant Prideco’s product range added new growth opportunities to the Company and benefited its customers’ needs worldwide.
The Merger was accounted for as a purchase business combination. Assets acquired and liabilities assumed were recorded at their fair values as of April 21, 2008. The fair value of shares issued was determined using an average price of $72.74, which represents the average closing price of the Company’s common stock for a five-day period beginning two available trading days before the public announcement of the transaction. The total purchase price is $7,199 million, including Grant Prideco stock options assumed and acquisition related transaction costs and is comprised of (in millions):
For all Grant Prideco stock options and restricted stock granted prior to 2008, vesting was accelerated under the terms of the stock option and restricted stock agreements; therefore, there was no modification of the awards as defined under SFAS 123(R). For stock options and restricted stock granted by Grant Prideco in 2008, 320,500 Grant Prideco stock options and 388,000 shares of restricted stock were replaced with 250,402 National Oilwell Varco stock options and 303,212 shares of National Oilwell Varco restricted stock, respectively. For the 2008 Grant Prideco grants, vesting was not accelerated in connection with the Merger, under the terms of the stock option and restricted stock agreements, except for certain recipients of the 2008 Grant Prideco restricted stock grant.
Merger related costs of $76 million include severance and other external costs directly related to the Merger.
Transaction costs of $11 million for the year ending December 31, 2008 were comprised of $6 million for accelerated vesting of stock-based compensation, $4 million for bridge loan fees and $1 million of other costs and are included in selling, general and administrative expense in the Consolidated Statements of Income.
Purchase Price Allocation
Under the purchase method of accounting, the total purchase price was allocated to Grant Prideco’s net tangible and identifiable intangible assets based on their fair values as of April 21, 2008. The excess of the purchase price over the net tangible and identifiable intangible assets was recorded as goodwill. The following table, set forth below, displays the total purchase price allocated to Grant Prideco’s net tangible and identifiable intangible assets based on their fair values as of April 21, 2008 (in millions):
Under purchase accounting, a fair value step up adjustment of $89 million was made to inventory and was charged to “Cost of sales” as the applicable inventory sold. Cost of sales included $89 million of these inventory charges for the year ended December 31, 2008.
Additionally, the Company identified other intangible assets associated with tradenames, patents, and customer relationships, and the fair values assigned were $1.2 billion, $0.3 billion, and $2.2 billion, respectively. The initial range of useful lives associated with trade names, patents, and customer relationships were 40 years to an indefinite life, 5 to 15 years and 16 to 17 years, respectively. Of the $1.2 billion associated with trade names, $0.8 billion was initially identified as having an indefinite life.
Disposition of Certain Grant Prideco Businesses
Prior to the Merger, Grant Prideco had entered into a definitive Purchase and Sale Agreement with Vallourec S.A. and Vallourec & Mannesman Holdings, Inc. (collectively referred to as “Vallourec”) to sell four of its tubular businesses for approximately $800 million in cash, subject to final working capital adjustments and standard closing conditions (including regulatory approval). The transaction closed May 16, 2008. The amount included in “Assets held for sale, net” included in the preliminary purchase price allocation above, relates to this disposition. Additionally, $256 million is included above in “Accrued income taxes” for taxes related to the disposition.
Unaudited Pro Forma Financial Information
The unaudited financial information in the table below summarizes the combined results of operations of National Oilwell Varco and Grant Prideco, on a pro forma basis, as though the companies had been combined as of the beginning of 2008. The pro forma financial information is presented for informational purposes only and may not be indicative of the results of operations that would have been achieved if the merger had taken place at the beginning of 2008. The pro forma financial information for the year ended December 31, 2008 includes the business combination accounting effect on historical Grant Prideco revenues, adjustments to depreciation on acquired property, amortization charges from acquired intangible assets, financing costs on new debt in connection with the merger and related tax effects for the year ended December 31, 2008 (in millions, except per share data):
4. Other Acquisitions and Investments
The Company completed nine acquisitions for an aggregate purchase price of $573 million, net of cash acquired. These acquisitions included:
•
The shares of ASEP Group Holding B.V., a Netherlands-based manufacturer of well service equipment.
•
The shares of ANS (1001) Ltd. (“Anson”), a U.K.-based manufacturer of pumps and fluid expendibles.
•
The business and assets of Spirit Drilling Fluids Ltd., a U.S.-based company that provides drilling fluids and related well-site services to exploration and production companies.
•
The business and assets of Spirit Minerals L.P., a U.S.-based company that mines, processes and distributes barite to the oil and gas drilling fluid industry.
•
The shares of South Seas Inspection (S) Pte. Ltd., a Singapore-based inspection, repair and maintenance provider to the oil and gas industry.
•
The shares of Hochang Machinery Industries Co., Ltd., a South Korean-based manufacturing and fabrication business.
The following table summarizes the preliminary fair values of the assets acquired and liabilities assumed at the date of acquisition of the 2009 acquisitions (in millions):
The Company allocated $115 million to intangible assets (11 year weighted-average life), comprised of: $60 million of customer relationships (9 year weighted-average life), $46 million of trademarks (18 year weighted-average life), and $9 million of other intangible assets (7 year weighted-average life).
In September 2009, the Company sold 45% of certain of its IntelliServ operations and created the IntelliServ Joint Venture (“IntelliServ”). IntelliServ provides drilling technology that enables downhole drilling conditions to be measured, evaluated and monitored.
In addition to the Grant Prideco Merger, the Company completed nine acquisitions for an aggregate purchase price of $171 million net of cash acquired. These acquisitions included:
•
Welch Power Source, L.L.C., a Louisiana-based manufacturer of power generation equipment.
•
CKS, a France-based solids control company.
•
Mid-South Machine, Inc., a Louisiana-based machine shop.
The following table summarizes the estimated fair values of the assets acquired and liabilities assumed at the date of acquisition of the 2008 acquisitions (in millions):
The Company allocated $38 million to intangible assets (9 year weighted-average life), comprised of: $30 million of customer relationships (15 year weighted-average life), $1 million of trademarks (16 year weighted-average life), and $7 million of other intangible assets (4 year weighted-average life).
The Company completed eight acquisitions for an aggregate purchase price of $287 million consisting of cash of $286 million and notes payable of $1 million. These acquisitions included:
•
Gammaloy Holdings, L.P., a Texas-based manufacturer of downhole tools.
•
Kreiter Geartech, a Texas-based manufacturer of gearing products.
•
Sara Services and Engineers Pvt. Ltd., an India-based manufacturer of oil field equipment.
The following table summarizes the estimated fair values of the assets acquired and liabilities assumed at the date of acquisition of the 2007 acquisitions (in millions):
Based on independent third-party valuations, the Company allocated $114 million to intangible assets (13 year weighted-average life), comprised of: $94 million of customer relationships (13 year weighted-average life), $9 million of trademarks (9 year weighted-average life), and $11 million of other intangible assets (20 year weighted-average life).
In January 2007, the Company also acquired the remaining 13% of NQL Energy Services, Inc.’s outstanding shares for $38 million.
Each of the acquisitions were accounted for using the purchase method of accounting and, accordingly, the results of operations of each business are included in the consolidated results of operations from the date of acquisition. Excluding the Grant Prideco merger, a summary of the acquisitions follows (in millions):
5. Inventories, net
Inventories consist of (in millions):
6. Property, Plant and Equipment
Property, plant and equipment consist of the following (in millions):
7. Accrued Liabilities
Accrued liabilities consist of (in millions):
8. Costs and Estimated Earnings on Uncompleted Contracts
Costs and estimated earnings on uncompleted contracts consist of (in millions):
9. Long-Term Debt
Debt consists of (in millions):
Principal payments of debt for years subsequent to 2009 are as follows (in millions):
Senior Notes
In connection with the merger of Grant Prideco, the Company completed an exchange offer relative to the $175 million of 6.125% Senior Notes due 2015 previously issued by Grant Prideco. On April 21, 2008, $151 million of Grant Prideco Senior Notes were exchanged for National Oilwell Varco Senior Notes. The National Oilwell Varco Senior Notes have the same interest rate, interest payment dates, redemption terms and maturity as the Grant Prideco Senior Notes. In November 2008, the Company repurchased $23 million of the unexchanged Grant Prideco Senior Notes.
Revolving Credit Facilities
On April 21, 2008, the Company replaced its existing $500 million unsecured revolving credit facility with an aggregate of $3 billion of unsecured credit facilities and borrowed $2 billion to finance the cash portion of the Grant Prideco acquisition. These facilities consisted of a $2 billion, five-year revolving credit facility and a $1 billion, 364-day revolving credit facility which was terminated early in February 2009. At December 31, 2009, there were no borrowings against the remaining credit facility, and there were $588 million in outstanding letters of credit issued under this facility, resulting in $1,412 million of funds available under this revolving credit facility. Interest under this multicurrency facility is based upon LIBOR, NIBOR or EURIBOR plus 0.26% subject to a ratings-based grid, or the prime rate.
The Company also had $2,073 million of additional outstanding letters of credit at December 31, 2009, primarily in Norway, that are essentially under various bilateral committed letter of credit facilities. Other letters of credit are issued as bid bonds and performance bonds. The Senior Notes contain reporting covenants and the credit facility contains a financial covenant regarding maximum debt to capitalization. The Company was in compliance with all covenants at December 31, 2009.
Other
Other debt includes approximately $3 million in promissory notes due to former owners of businesses acquired who remain employed by the Company.
10. Employee Benefit Plans
We have benefit plans covering substantially all of our employees. Defined-contribution benefit plans cover most of the U.S. and Canadian employees, and benefits are based on years of service, a percentage of current earnings and matching of employee contributions. Employees in our Norwegian operations can elect to participate in a defined-contribution plan in lieu of a local defined benefit plan. For the years ended December 31, 2009, 2008 and 2007, expenses for defined-contribution plans were $39 million, $37 million, and $31 million, respectively, and all funding is current.
Certain retired or terminated employees of predecessor or acquired companies participate in a defined benefit plan in the United States. None of the participants in this plan are eligible to accrue benefits. In addition, approximately 777 U.S. retirees and spouses participate in defined benefit health care plans of predecessor or acquired companies that provide postretirement medical and life insurance benefits. Active employees are ineligible to participate in any of these defined benefit plans. Our subsidiaries in the United Kingdom and Norway also have defined benefit pension plans covering virtually all of their employees.
Net periodic benefit cost for our defined benefit plans aggregated $12 million, $7 million and $8 million for the years ended December 31, 2009, 2008 and 2007, respectively.
The change in benefit obligation, plan assets and the funded status of the defined benefit pension plans in the United States, United Kingdom, and Norway and defined postretirement plans in the United States, using a measurement date of December 31, 2009 and December 31, 2008, is as follows (in millions):
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:
The assumption rates used for net periodic benefit costs are as follows:
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 ranging from $15 million to $20 million for each of the next five years and aggregate payments of $152 million.
Plan Assets
The Company and its investment advisers collaboratively reviewed market opportunities using historic and statistical data, as well as the actuarial valuation reports for the plans, to ensure that the levels of acceptable return and risk are well-defined and monitored. Currently, the Company’s management believes that there are no significant concentrations of risk associated with plan assets. Our pension investment strategy worldwide prohibits a direct investment in our own stock.
The following table presents information about the plan assets measured at fair value as of December 31, 2009, aggregated by the level in the fair value hierarchy within which those measurements fall (in millions):
The following table outlines the rollforward of the fair value measurement Company’s Level 3 plan assets using significant unobservable inputs for the year ended December 31, 2009 (in millions):
11. Accumulated Other Comprehensive Income (Loss)
The components of accumulated other comprehensive income (loss) are as follows (in millions):
12. Commitments and Contingencies
We are involved in various claims, regulatory agency audits and pending or threatened legal actions involving a variety of matters. The total liability on these matters at December 31, 2009 cannot be determined; however, in our opinion, any ultimate liability, to the extent not otherwise provided for, will not materially affect our financial position, cash flow or results of operations.
Our business is affected both directly and indirectly by governmental laws and regulations relating to the oilfield service industry in general, as well as by environmental and safety regulations that specifically apply to our business. Although we have not incurred material costs in connection with our compliance with such laws, there can be no assurance that other developments, such as new environmental laws, regulations and enforcement policies hereunder may not result in additional, presently unquantifiable, costs or liabilities to us.
We have received federal grand jury subpoenas and subsequent inquiries from governmental agencies requesting records related to our compliance with export trade laws and regulations. We have cooperated fully with agents from the Department of Justice, the Bureau of Industry and Security, the Office of Foreign Assets Control, and U.S. Immigration and Customs Enforcement in responding to the inquiries, and we have conducted our own internal review of this matter. At the conclusion of our internal review in the fourth quarter of 2009, we identified possible areas of concern and discussed these areas of concern with the relevant agencies. We are currently negotiating a potential resolution with the agencies involved related to these matters. We currently anticipate that any administrative fine or penalty agreed to as part of a resolution would be within established accruals, and would not have a material effect on our financial position or results of operations. To the extent a resolution is not negotiated as anticipated, we cannot predict the timing or effect that any resulting government actions may have on our financial position or results of operations. As a result of our internal review and in an effort to prevent any future compliance issues of this nature, we have reviewed and are in the process of enhancing our compliance procedures and training.
The Company leases certain facilities and equipment under operating leases that expire at various dates through 2066. These leases generally contain renewal options and require the lessee to pay maintenance, insurance, taxes and other operating expenses in addition to the minimum annual rentals. Rental expense related to operating leases approximated $199 million, $184 million, and $128 million in 2009, 2008 and 2007, respectively.
Future minimum lease commitments under noncancellable operating leases with initial or remaining
terms of one year or more at December 31, 2009 are payable as follows (in millions):
13. Common Stock
National Oilwell Varco has authorized 500 million shares of $.01 par value common stock. We also have authorized 10 million shares of $.01 par value preferred stock, none of which is issued or outstanding.
On November 11, 2009 National Oilwell Varco’s Board of Directors approved a special one-time cash dividend of $1.00 per share of common stock along with the commencement of a regular quarterly dividend of $0.10 per share. The special cash dividend and the first quarterly dividend was paid on December 16, 2009 to each stockholder of record on December 2, 2009. The declaration and payment of future dividends is at the discretion of the Company’s Board of Directors and will be dependent upon the Company’s results of operations, financial condition, capital requirements and other factors deemed relevant by the Board of Directors.
On August 22, 2007, the Company’s Board of Directors approved a two-for-one stock split in the form of a stock dividend to the Company’s stockholders of record on September 7, 2007, with distribution of shares on September 28, 2007. The total number of authorized common stock shares and associated par value were unchanged by this action. All per-share amounts in the financial statements reflect the stock split for all periods presented unless indicated otherwise.
Stock Options
Under the terms of National Oilwell Varco’s Long-Term Incentive Plan, as amended, 25.5 million shares of common stock are authorized for the grant of options to officers, key employees, non-employee directors and other persons. Options granted under our
stock option plan generally vest over a three-year period starting one year from the date of grant and expire ten years from the date of grant. The purchase price of options granted may not be less than the closing market price of National Oilwell Varco common stock on the date of grant. At December 31, 2009, approximately 12 million shares were available for future grants.
We also have inactive stock option plans that were acquired in connection with the acquisitions of Varco International, Inc. in 2005 and Grant Prideco in 2008. We converted the outstanding stock options under these plans to options to acquire our common stock and no further options are being issued under these plans. Stock option information summarized below includes amounts for the National Oilwell Varco Long-Term Incentive Plan and stock plans of acquired companies. Options outstanding at December 31, 2009 under the stock option plans have exercise prices between $8.83 and $73.98 per share, and expire at various dates from January 25, 2010 to May 13, 2019.
The following summarizes options activity:
The following summarizes information about stock options outstanding as of December 31, 2009:
The weighted-average fair value of options granted during 2009, 2008 and 2007 was approximately $11.89, $22.16 and $11.99 (excluding options assumed in the Grant Prideco merger) per share, respectively, as determined using the Black-Scholes option-pricing model. The total intrinsic value of options exercised during 2009 and 2008 was $6 million and $155 million, respectively.
Upon adoption of ASC Topic 718, we began recording expense related to the value of employee stock options on the date of grant using the Black Scholes model. Prior to the adoption of ASC Topic 718, the value of each employee stock option was estimated on the date of grant using the Black-Scholes model for the purpose of the pro forma financial information in accordance with ASC Topic 718. The determination of fair value of share-based payment awards on the date of grant using an option-pricing model is affected by our stock price as well as assumptions regarding a number of highly complex and subjective variables. These variables include, but are not limited to, the expected stock price volatility over the term of the awards, and actual and projected employee stock option exercise activity. The use of the Black Scholes model requires the use of extensive actual employee exercise activity data and the use of a number of complex assumptions including expected volatility, risk-free interest rate, expected dividends and expected term.
We used the actual volatility for traded options for the past 10 years prior to option date as the expected volatility assumption required in the Black Scholes model.
The risk-free interest rate assumption is based upon observed interest rates appropriate for the term of our employee stock options. The dividend yield assumption is based on the history and expectation of dividend payouts. The estimated expected term is based on actual employee exercise activity for the past ten years.
As stock-based compensation expense recognized in the Consolidated Statement of Income in 2009 is based on awards ultimately expected to vest, it has been reduced for estimated forfeitures. ASC Topic 718 requires forfeitures to be estimated at the time of grant and revised, if necessary, in subsequent periods if actual forfeitures differ from those estimates. Forfeitures were estimated based on historical experience.
The following summary presents information regarding outstanding options as of December 31, 2009 and changes during 2009 with regard to options under all stock option plans:
As of December 31, 2009, total unrecognized compensation cost related to nonvested stock options was $40 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 2009, 2008 and 2007 was approximately $40 million, $43 million and $34 million, respectively. Cash received from option exercises for 2009, 2008 and 2007 was $8 million, $78 million and $91 million, respectively. The actual tax benefit realized for the tax deductions from option exercises totaled $2 million, $46 million and $34 million for 2009, 2008 and 2007, respectively. Cash used to settle equity instruments granted under all share-based payment arrangements for 2009, 2008 and 2007 was not material for any period.
Restricted Shares
The Company issues restricted stock awards (“RSA”) with no exercise price to officers and key employees in addition to stock options. The Company granted 434,400 restricted shares valued at $25.96 to key employees on February 20, 2009. These shares will not vest until the third anniversary of the date of the grant, at which time they will be 100% vested. The Company also granted 309,000 performance-based restricted shares valued at $25.96 to senior management and officers on February 20, 2009. These shares will not vest until the third anniversary of the date of the grant, at which time they will be 100% vested, with a performance condition of the Company’s operating income level growth from January 1, 2009 to December 31, 2011 needing to exceed the median operating income level growth of a designated peer group over the same period. The estimated forfeiture rate of RSA’s is factored into the share-based compensation expense the Company recognizes.
The following summary presents information regarding outstanding restricted shares as of December 31, 2009, 2008 and 2007, and changes during 2009 and 2008:
The weighted-average grant day fair value of RSA’s granted during the years ended 2009, 2008 and 2007 was $26.02, $64.16 and $37.06 (excluding RSA’s assumed in the Grant Prideco merger) per share, respectively. There were 7,322, 307,905 and nil RSA’s that vested during 2009, 2008 and 2007, respectively. As of December 31, 2009, there was $27 million of unrecognized compensation cost related to nonvested RSA’s, which is expected to be recognized over a weighted-average period of two years.
14. Income Taxes
The domestic and foreign components of income before income taxes were as follows (in millions):
The components of the provision for income taxes consisted of (in millions):
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):
Significant components of our deferred tax assets and liabilities were as follows (in millions):
ASC Topic 740 “Income Taxes” (ASC Topic 740) prescribes a recognition threshold and measurement attributes for financial statement disclosure of tax positions taken or expected to be taken on a return. Under ASC Topic 740, the impact of an uncertain income tax position, in management’s opinion, on the income tax return must be recognized at the largest amount that is more-likely-than not to be sustained upon audit by the relevant taxing authority. An uncertain income tax position will not be recognized if it has a less than 50% likelihood of being sustained. Additionally, ASC Topic 740 provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure. The balance of unrecognized tax benefits at December 31, 2009 and 2008 are $58 million and $61 million, respectively. These unrecognized tax benefits, if recognized in future periods, would impact the Company’s effective tax rate. Included in the change in the balance of unrecognized tax benefits for the period ended December 31, 2009 was an increase of $10 million of unrecognized tax benefits associated with potential challenges to intercompany pricing and certain operating expenses that may not be deductible in foreign jurisdictions and a $13 million reduction in the balance of unrecognized tax benefits resulting primarily from the completion in the U.S. of prior year audits and appeals. This net decrease of $3 million in the balance of unrecognized tax benefits impacted the Company’s effective tax rate in the current year. These unrecognized tax benefits are included in the balance of Accrued Income Taxes in the balance sheet as of December 31, 2009.
A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows (in millions):
The Company does not anticipate that the total unrecognized tax benefits will significantly change due to the settlement of audits or the expiration of statutes of limitation within 12 months of this reporting date.
To the extent penalties and interest would be assessed on any underpayment of income tax, such accrued amounts have been classified as a component of income tax expense in the financial statements. This is an accounting policy election made by the Company that is a continuation of the Company’s historical policy and will continue to be consistently applied in the future. During the year ended December 31, 2009, the Company recognized $3 million of additional interest and penalties related to uncertain tax positions as part of income tax expense. As of December 31, 2009, the Company has accrued approximately $11 million of interest and penalties relating to unrecognized tax benefits. These interest and penalties are included in the balance of Accrued Income Taxes in the balance sheet as of December 31, 2009.
The Company is subject to taxation in the United States, various states and foreign jurisdictions. The Company has significant operations in the United States, Canada, the United Kingdom, the Netherlands and Norway. Tax years that remain subject to examination by major tax jurisdictions vary by legal entity, but are generally open in the U.S. for the tax years ending after 2005 and outside the U.S. for the tax years ending after 2003.
In the United States, the Company has $19 million of net operating loss carryforwards as of December 31, 2009, which expire at various dates through 2029. The potential benefit of $7 million has been recorded with a $7 million valuation allowance. Future income tax payments will be reduced when the Company ultimately realizes the benefit of these net operating losses. If the Company ultimately realizes the benefit of these net operating loss carryforwards, the valuation allowance of $7 million would reduce future income tax expense.
Also in the United States, the Company has $1 million of excess foreign tax credits as of December 31, 2009, which expire at various dates through 2017. These credits have been allotted a full valuation allowance and would be realized as a reduction of future income tax payments. If the Company ultimately realizes the benefit of these excess foreign tax credits, the valuation allowance of $1 million would reduce future income tax expense.
The deferred tax valuation allowance decreased $2 million for the period ending December 31, 2009 and was recorded as a decrease in deferred tax assets.
During 2008, the Company recorded $1,480 million in net deferred tax liabilities with a corresponding increase in goodwill related to Grant Prideco purchase accounting.
Undistributed earnings of certain of the Company’s foreign subsidiaries amounted to $2,764 million and $2,255 million at December 31, 2009 and 2008, respectively. Those earnings are considered to be permanently reinvested and no provision for U.S. federal and state income taxes has been made. Distribution of these earnings in the form of dividends or otherwise could result in either U.S. federal taxes (subject to an adjustment for foreign tax credits) and withholding taxes payable in various foreign countries. Determination of the amount of unrecognized deferred U.S. income tax liability is not practical; however, unrecognized foreign tax credit carryforwards would be available to reduce some portion of the U.S. liability. Withholding taxes of approximately $126 million would be payable upon remittance of all previously unremitted earnings at December 31, 2009.
Because of the number of tax jurisdictions in which the Company operates, its effective tax rate can fluctuate as operations and the local country tax rates fluctuate. The Company is also subject to audits by federal, state and foreign jurisdictions which may result in proposed assessments. The Company’s future tax provision will reflect any favorable or unfavorable adjustments to its estimated tax liabilities when resolved. The Company is unable to predict the outcome of these matters. However, we believe that none of these matters will have a material adverse effect on the results of operations or financial condition of the Company.
15. Business Segments and Geographic Areas
The Company’s operations consist of three reportable segments: Rig Technology, Petroleum Services & Supplies and Distribution Services.
Rig Technology: Our Rig Technology segment designs, manufactures, sells and services complete systems for the drilling, completion, and servicing of oil and gas wells. The segment offers a comprehensive line of highly-engineered equipment that automates complex well construction and management operations, such as offshore and onshore drilling rigs; derricks; pipe lifting, racking, rotating and assembly systems; rig instrumentation systems; coiled tubing equipment and pressure pumping units; well workover rigs; wireline winches; and cranes.
Petroleum Services & Supplies: Our Petroleum Services & Supplies segment provides a variety of consumable goods and services used to drill, complete, remediate and workover oil and gas wells and service flowlines and other oilfield tubular goods. The segment manufactures, rents and sells a variety of products and equipment used to perform drilling operations, including drill pipe, transfer pumps, solids control systems, drilling motors, drill bits, reamers and other downhole tools, and mud pump consumables.
Distribution Services: Our Distribution Services segment provides maintenance, repair and operating supplies and spare parts to drill site and production locations worldwide. In addition to its comprehensive network of field locations supporting land drilling operations throughout North America, the segment supports major offshore drilling contractors through locations in Mexico, the Middle East, Europe, Southeast Asia and South America. Distribution Services employs advanced information technologies to provide complete procurement, inventory management and logistics services to its customers around the globe.
The accounting policies of the reportable segments are the same as those described in the summary of significant accounting policies of the Company. The Company evaluates performance of each reportable segment based upon its operating income, excluding non-recurring items. During the second quarter of 2008, certain products previously reported in the Petroleum Services & Supplies segment were transferred to the Company’s other two segments, due to a realignment of management responsibilities. Prior periods have not been restated for this change as the impact of the change was not material to any of the Company’s segments.
The Company had revenues of 16.6% of total revenue from one of its customers for the year ended December 31, 2009. This customer is a shipyard acting as a general contractor for its customers, who are drillship owners and drilling contractors. This shipyard’s customers have specified that the Company’s drilling equipment be installed on their drillships and have required the shipyard to issue contracts to the Company.
Geographic Areas:
The following table presents consolidated revenues by country based on sales destination of the use of the products or services (in millions):
The following table presents long-lived assets by country based on the location (in millions):
Business Segments:
The Company’s 2008 financial statements include Grant Prideco from April 21, 2008, the Merger Date, which includes additional amortization and depreciation of $114 million from the step up to fair market value of Grant Prideco’s assets and liabilities for the year ended December 31, 2008. The Grant Prideco product lines are reported within the Petroleum Services & Supplies segment.
16. Quarterly Financial Data (Unaudited)
Summarized quarterly results, were as follows (in millions, except per share data). The 2008 results include Grant Prideco operations from the Merger Date:
Schedule Of Valuation And Qualifying Accounts Disclosure
SCHEDULE II
NATIONAL OILWELL VARCO, INC.
VALUATION AND QUALIFYING ACCOUNTS
Years Ended December 31, 2009, 2008 and 2007
(in millions)