ITEM 1. BUSINESS
General
National Oilwell Varco, Inc. (“NOV” or the “Company”), a Delaware corporation incorporated in 1995, is a leading worldwide provider of equipment and components used in oil and gas drilling and production operations, oilfield services, and supply chain integration services to the upstream oil and gas industry. The Company conducts operations in over 1,160 locations across six continents.
The Company’s principal executive offices are located at 7909 Parkwood Circle Drive, Houston, Texas 77036, its telephone number is (713) 346-7500, and its Internet website address is http://www.nov.com. The Company’s annual reports on Form 10-K, quarterly reports on Form 10-Q and current reports on Form 8-K, and all amendments thereto, are available free of charge on its Internet website. These reports are posted on its website as soon as reasonably practicable after such reports are electronically filed with the Securities and Exchange Commission (“SEC”). The Company’s Code of Ethics is also posted on its website.
The Company has a long tradition of pioneering innovations which improve the cost-effectiveness, efficiency, safety and environmental impact of oil and gas operations. The Company’s common stock is traded on the New York Stock Exchange under the symbol “NOV”. The Company operates through three reporting segments: Rig Technology, Petroleum Services & Supplies, and Distribution & Transmission.
Rig Technology
Our Rig Technology segment designs, manufactures, sells and services complete systems for the drilling, completion, and servicing of oil and gas wells. The segment offers a comprehensive line of highly-engineered equipment that automates complex well construction and management operations, such as offshore and onshore drilling rigs; derricks; pipe lifting, racking, rotating and assembly systems; rig instrumentation systems; blowout preventers; coiled tubing equipment and pressure pumping units; well workover rigs; wireline winches; wireline trucks; cranes; flexible pipe for offshore production applications; and turret mooring systems and other products for floating production, storage and offloading vessels (“FPSOs”) and other offshore vessels and terminals. Demand for Rig Technology products is primarily dependent on capital spending plans by drilling contractors, oilfield service companies, and oil and gas companies; and secondarily on the overall level of oilfield drilling activity, which drives demand for spare parts for the segment’s large installed base of equipment. We have made strategic acquisitions and other investments during the past several years in an effort to expand our product offering and our global manufacturing capabilities, including adding additional operations in the United States, Canada, Norway, Denmark, the United Kingdom, Brazil, China, Belarus, India, Russia, the Netherlands, Singapore, South Korea, South Africa, and Angola.
Petroleum Services & Supplies
Our Petroleum Services & Supplies segment provides a variety of consumable goods and services used to drill, complete, remediate and workover oil and gas wells and service drill pipe, tubing, casing, flowlines and other oilfield tubular goods. The segment manufactures, rents and sells a variety of products and equipment used to perform drilling operations, including drill pipe, wired drill pipe, transfer pumps, solids control systems, drilling motors, drilling fluids, drill bits, reamers and other downhole tools, and mud pump consumables. Demand for these services and supplies is determined principally by the level of oilfield drilling and workover activity by drilling contractors, oilfield service companies, major and independent oil and gas companies, and national oil companies. Oilfield tubular services include the provision of inspection and internal coating services and equipment for drill pipe, line pipe, tubing, casing and pipelines; and the design, manufacture and sale of coiled tubing pipe and advanced fiberglass composite pipe for application in highly corrosive environments. The segment sells its tubular goods and services to oil and gas companies; drilling contractors; pipe distributors, processors and manufacturers; and pipeline operators. This segment has benefited from several strategic acquisitions and other investments completed during the past few years, including additional operations in the United States, Canada, the United Kingdom, Brazil, China, Kazakhstan, Mexico, Russia, Argentina, India, Bolivia, the Netherlands, Singapore, Malaysia, Vietnam, Oman, and the United Arab Emirates.
Distribution & Transmission
Our Distribution & Transmission segment provides pipe, maintenance, repair and operating supplies (“MRO”) and spare parts to drill sites and production locations, pipeline operations, and processing plants worldwide. In addition to its comprehensive field location network, which supports land drilling operations throughout North America, the segment supports major land and offshore operations for all the major oil and gas producing regions throughout the world. The segment employs advanced information technologies to provide complete procurement, materials management and logistics services to its customers around the globe. The segment also has a global reach in oil and gas, waste water treatment, chemical, food and beverage, paper and pulp, mining, agriculture, and a variety of municipal markets and is a leading producer of water transmission pipe, fabricated steel products and specialized materials and products used in infrastructure projects. Demand for the segment’s services is determined primarily by the level of drilling, servicing, and oil and gas production activities. It is also influenced by the domestic economy in general, housing starts and government policies. This segment has benefited from several strategic acquisitions and other investments completed around the world during the past few years, including the acquisition of the Wilson distribution business segment from Schlumberger Limited and CE Franklin Ltd. in Canada, both of which were completed in 2012, as well as additional operations in the United States, Canada, the United Kingdom, Kazakhstan, Singapore, Russia, and Malaysia.
The following table sets forth the contribution to our total revenues of our three operating segments (in millions):
See Note 15 to the Consolidated Financial Statements included in this Annual Report on Form 10-K for financial information by segment and a geographical breakout of revenues and long-lived assets. We have included a glossary of oilfield terms at the end of Item 1. “Business” of this Annual Report.
Influence of Oil and Gas Activity Levels on the Company’s Business
The oil and gas industry in which the Company participates has historically experienced significant volatility. Demand for the Company’s services and products depends primarily upon the general level of activity in the oil and gas industry worldwide, including the number of drilling rigs in operation, the number of oil and gas wells being drilled, the depth and drilling conditions of these wells, the volume of production, the number of well completions and the level of well remediation activity. Oil and gas activity is in turn heavily influenced by, among other factors, oil and gas prices worldwide. High levels of drilling and well remediation activity generally spurs demand for the Company’s products and services used to drill and remediate oil and gas wells. Additionally, high levels of oil and gas activity increase cash flows available for oil and gas companies, drilling contractors, oilfield service companies, and manufacturers of oil country tubular goods (“OCTG”) to invest in capital equipment that the Company sells.
Beginning in early 2004, increasing oil and gas prices led to steadily rising levels of drilling activity throughout the world. Concerns about the long-term availability of oil and gas supply also began to build. Consequently, the worldwide rig count increased 11% in 2006, 2% in 2007, and 7% in 2008. As a result of higher cash flows realized by many of the Company’s customers, as well as the long-term concerns about supply-demand imbalance and the need to replace aging equipment, market conditions for capital equipment purchases improved significantly between 2006 and 2007, resulting in higher backlogs for the Company at the end of 2008 compared to the end of 2006 and 2007. However, as a result of the financial crisis and significantly lower commodity prices, the worldwide drilling rig count declined 31% in 2009 and customers were far less willing to commit to major capital equipment purchases in 2009. As a result, our order rates were substantially lower in 2009. In 2010, as the financial crisis eased and oil prices recovered, order rates began to improve across a broad array of rig equipment, with a particular focus on continued build out of the deepwater fleet. Both 2011 and 2012 saw a further improvement in order rates as commodity prices remained at levels supporting sustained capital spending by our customers. The global rig count rose 16% in 2011 compared to 2010 and by 1.5% in 2012 compared to 2011. Backlog for the Company was approximately $11.9 billion at December 31, 2012 compared to approximately $10.2 billion and $5.0 billion for December 31, 2011 and 2010, respectively.
In 2010, 2011 and 2012, most of the Company’s revenue from Rig Technology resulted from major capital expenditures of drilling contractors, well servicing companies, and oil companies on rig construction and refurbishment, and well servicing equipment. These capital expenditures are influenced by the amount of cash flow that contractors and service companies generate from drilling, completion, and remediation activity; as well as by the availability of financing, the outlook for future drilling and well servicing activity, and other factors. Generally, the Company believes the demand for capital equipment lags increases in the level of drilling activity. Most of the remainder of the Rig Technology segment’s revenue is related to the sale of spare parts and consumables, the provision of equipment-repair services, and the rental of equipment, which the Company believes are generally determined directly by the level of drilling and well servicing activity.
The majority of the Company’s revenue from Petroleum Services & Supplies is closely tied to drilling activity, although a portion is related to the sale of capital equipment to drilling contractors, which may somewhat lag the level of drilling activity. Portions of the segment’s revenue that are not tied to drilling activity include (i) the sale of progressive cavity pumps and solids control equipment for use in industrial applications, and (ii) the sale of fiberglass and composite tubing to industrial customers and shipyards, which is generally unrelated to drilling or well remediation activity but may be tied somewhat to oil and gas prices.
The Company’s revenue from Distribution & Transmission is almost entirely driven by drilling activity and oil and gas production activities, with the exception of sales of water pipelines, concrete and pole products which is tied to infrastructure spending. Drilling and well servicing activity can fluctuate significantly in a short period of time.
The willingness of oil and gas operators to make capital investments to explore for and produce oil and natural gas will continue to be influenced by numerous factors over which the Company has no control, including but not limited to: the ability of the members of the Organization of Petroleum Exporting Countries (“OPEC”) to maintain oil price stability through voluntary production limits of oil; the level of oil production by non-OPEC countries; supply and demand for oil and natural gas; general economic and political conditions; costs of exploration and production; the availability of new leases and concessions; access to external financing; and governmental regulations regarding, among other things, environmental protection, climate change, taxation, price controls and product allocations. The willingness of drilling contractors and well servicing companies to make capital expenditures for the type of specialized equipment the Company provides is also influenced by numerous factors over which the Company has no control, including: the general level of oil and gas well drilling and servicing; rig day-rates; access to external financing; outlook for future increases in well drilling and well remediation activity; steel prices and fabrication costs; and government regulations regarding, among other things, environmental protection, taxation, and price controls.
See additional discussion on current worldwide economic environment and related oil and gas activity levels in Item 1A.
ITEM 1A. RISK FACTORS
You should carefully consider the risks described below, in addition to other information contained or incorporated by reference herein. Realization of any of the following risks could have a material adverse effect on our business, financial condition, cash flows and results of operations.
We are dependent upon the level of activity in the oil and gas industry, which is volatile.
The oil and gas industry historically has experienced significant volatility. Demand for our services and products depends primarily upon the number of oil rigs in operation, the number of oil and gas wells being drilled, the depth and drilling conditions of these wells, the volume of production, the number of well completions, capital expenditures of other oilfield service companies and the level of workover activity. Drilling and workover activity can fluctuate significantly in a short period of time, particularly in the United States and Canada. The willingness of oil and gas operators to make capital expenditures to explore for and produce oil and natural gas and the willingness of oilfield service companies to invest in capital equipment will continue to be influenced by numerous factors over which we have no control, including:
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the ability of the members of the Organization of Petroleum Exporting Countries, or OPEC, to maintain price stability through voluntary production limits, the level of production by non-OPEC countries and worldwide demand for oil and gas;
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level of production from known reserves;
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cost of exploring for and producing oil and gas;
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level of drilling activity and drilling rig dayrates;
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worldwide economic activity;
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national government political requirements;
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development of alternate energy sources; and
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environmental regulations.
If there is a significant reduction in demand for drilling services, in cash flows of drilling contractors, well servicing companies, or production companies or in drilling or well servicing rig utilization rates, then demand for the products and services of the Company will decline.
Volatile oil and gas prices affect demand for our products.
Oil and gas prices have been volatile since 1972. In general, oil prices approximated $18-$22 per barrel from 1991 through 1997, experienced a decline into the low teens in 1998 and 1999, and have generally ranged between $25-$100 per barrel since 2000. In 2008, oil prices were extremely volatile - oil prices rose to $147 per barrel in July 2008 only to fall into the $35-$45 per barrel range in December 2008. In 2009, oil prices continued to be volatile, rising to the $70 per barrel range during the year. In 2010 oil prices continued rising to finish the year well above $80 per barrel. Domestic spot gas prices generally ranged between $1.80-$2.60 per mmbtu of gas from 1991 through 1999 then experienced spikes into the $10 range in 2001 and 2003. Prices generally ranged between $4.50-$12.00 per mmbtu during 2005-2008. During 2009 through 2011, spot gas prices generally stabilized, dropping into the $3.00-$4.50 per mmbtu range, but declined below $3.00 late in 2011 and throughout much of 2012 before increasing slightly above $3.00 in late 2012.
Expectations for future oil and gas prices cause many shifts in the strategies and expenditure levels of oil and gas companies and drilling contractors, particularly with respect to decisions to purchase major capital equipment of the type we manufacture. Oil and gas prices, which are determined by the marketplace, may fall below a range that is acceptable to our customers, which could reduce demand for our products.
Worldwide financial and credit crisis could have a negative effect on our operating results and financial condition.
Events in 2008 and 2009 constrained credit markets and sparked a serious global banking crisis. The slowdown in worldwide economic activity caused by the global recession reduced demand for energy and resulted in lower oil and natural gas prices. While markets have improved since 2008, recent economic data suggests the potential for another global recession, which could negatively impact oil and natural gas prices and restrict availability to credit markets. Any prolonged reduction in oil and natural gas prices will reduce oil and natural gas drilling activity and result in a corresponding decline in the demand for our products and services, which could adversely impact our operating results and financial condition. Furthermore, many of our customers access the credit markets to finance their oil and natural gas drilling activity. If the availability of credit to our customers is reduced, they may reduce their drilling and production expenditures, thereby decreasing demand for our products and services. Any such reduction in spending by our customers could adversely impact our operating results and financial condition.
There are risks associated with certain contracts for our drilling equipment.
As of December 31, 2012, we had a backlog of approximately $11.9 billion of drilling equipment to be manufactured, assembled, tested and delivered by our Rig Technology segment. The following factors, in addition to others not listed, could reduce our margins on these contracts, adversely affect our position in the market or subject us to contractual penalties:
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our failure to adequately estimate costs for making this drilling equipment;
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our inability to deliver equipment that meets contracted technical requirements;
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our inability to maintain our quality standards during the design and manufacturing process;
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our inability to secure parts made by third party vendors at reasonable costs and within required timeframes;
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unexpected increases in the costs of raw materials; and
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our inability to manage unexpected delays due to weather, shipyard access, labor shortages or other factors beyond our control.
The Company’s existing contracts for rig equipment generally carry down payment and progress billing terms favorable to the ultimate completion of these projects and do not allow customers to cancel projects for convenience. However, unfavorable market conditions or financial difficulties experienced by our customers may result in cancellation of contracts or the delay or abandonment of projects.
Any such developments could have a material adverse effect on our operating results and financial condition.
Competition in our industry could ultimately lead to lower revenues and earnings.
The oilfield products and services industry is highly competitive. We compete with national, regional and foreign competitors in each of our current major product lines. Certain of these competitors may have greater financial, technical, manufacturing and marketing resources than us, and may be in a better competitive position. The following competitive actions can each affect our revenues and earnings:
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price changes;
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new product and technology introductions; and
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improvements in availability and delivery.
In addition, certain foreign jurisdictions and government-owned petroleum companies located in some of the countries in which we operate have adopted policies or regulations which may give local nationals in these countries competitive advantages. Competition in our industry could lead to lower revenues and earnings.
We have aggressively expanded our businesses and intend to maintain an aggressive growth strategy.
We have aggressively expanded and grown our businesses during the past several years, through acquisitions and investment in internal growth. We anticipate that we will continue to pursue an aggressive growth strategy but we cannot assure you that attractive acquisitions will be available to us at reasonable prices or at all. In addition, we cannot assure you that we will successfully integrate the operations and assets of any acquired business with our own or that our management will be able to manage effectively the increased size of the Company or operate any new lines of business. Any inability on the part of management to integrate and manage acquired businesses and their assumed liabilities could adversely affect our business and financial performance. In addition, we may need to incur substantial indebtedness to finance future acquisitions. We cannot assure you that we will be able to obtain this financing on terms acceptable to us or at all. Future acquisitions may result in increased depreciation and amortization expense, increased interest expense, increased financial leverage or decreased operating income for the Company, any of which could cause our business to suffer.
Our operating results have fluctuated during recent years and these fluctuations may continue.
We have experienced fluctuations in quarterly operating results in the past. We cannot assure that we will realize earnings growth or that earnings in any particular quarter will not fall short of either a prior fiscal quarter or investors’ expectations. The following factors, in addition to others not listed, may affect our quarterly operating results in the future:
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fluctuations in the oil and gas industry;
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competition;
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the ability to service the debt obligations of the Company;
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the ability to identify strategic acquisitions at reasonable prices;
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the ability to manage and control operating costs of the Company;
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fluctuations in political and economic conditions in the United States and abroad; and
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the ability to protect our intellectual property rights.
There are risks associated with our presence in international markets, including political or economic instability, currency restrictions, and trade and economic sanctions.
Approximately 59% of our revenues in 2012 were derived from operations outside the United States (based on revenue destination). Our foreign operations include significant operations in Canada, Europe, the Middle East, Africa, Southeast Asia, Latin America and other international markets. Our revenues and operations are subject to the risks normally associated with conducting business in foreign countries, including uncertain political and economic environments, which may limit or disrupt markets, restrict the movement of funds or result in the deprivation of contract rights or the taking of property without fair compensation. Government-owned petroleum companies located in some of the countries in which we operate have adopted policies, or are subject to governmental policies, giving preference to the purchase of goods and services from companies that are majority-owned by local nationals. As a result of these policies, we may rely on joint ventures, license arrangements and other business combinations with local nationals in these countries. In addition, political considerations may disrupt the commercial relationships between us and government-owned petroleum companies.
Our operations outside the United States could also expose us to trade and economic sanctions or other restrictions imposed by the United States or other governments or organizations. The U.S. Department of Justice (“DOJ”), the U.S. Securities and Exchange Commission and other federal agencies and authorities have a broad range of civil and criminal penalties they may seek to impose against corporations and individuals for violations of trading sanctions laws, the Foreign Corrupt Practices Act and other statutes. Under trading sanctions laws, the U.S. and other governments may seek to impose modifications to business practices, including cessation of business activities in sanctioned countries, and modifications to compliance programs, which may increase compliance costs. If any of the risks described above materialize, it could adversely impact our operating results and financial condition.
We have received federal grand jury subpoenas and subsequent inquiries from governmental agencies requesting records related to our compliance with export trade laws and regulations. We have cooperated fully with agents from the Department of Justice, the Bureau of Industry and Security, the Office of Foreign Assets Control, and U.S. Immigration and Customs Enforcement in responding to the inquiries. We have also cooperated with an informal inquiry from the Securities and Exchange Commission in connection with the inquiries previously made by the aforementioned federal agencies. We have conducted our own internal review of this matter. At the conclusion of our internal review in the fourth quarter of 2009, we identified possible areas of concern and discussed these areas of concern with the relevant agencies. We are currently negotiating a potential resolution with the agencies involved related to these matters. We currently anticipate that any administrative fine or penalty agreed to as part of a resolution would be within established accruals, and would not have a material effect on our financial position or results of operations. To the extent a resolution is not negotiated as anticipated, we cannot predict the timing or effect that any resulting government actions may have on our financial position or results of operations.
The results of our operations are subject to market risk from changes in foreign currency exchange rates.
We earn revenues, pay expenses and incur liabilities in countries using currencies other than the U.S. dollar, including, but not limited to, the Canadian dollar, the Euro, the British pound sterling, the Norwegian krone, the Venezuelan bolivar and the South Korean won. Approximately 59% of our 2012 revenue was derived from sales outside the United States. Because our Consolidated Financial Statements are presented in U.S. dollars, we must translate revenues and expenses into U.S. dollars at exchange rates in effect during or at the end of each reporting period. Thus, increases or decreases in the value of the U.S. dollar against other currencies in which our operations are conducted will affect our revenues and operating income. Because of the geographic diversity of our operations, weaknesses in some currencies might be offset by strengths in others over time. We use derivative financial instruments to mitigate our net exposure to currency exchange fluctuations. We had forward contracts with a notional amount of $3,662 million (with a fair value of $86 million) as of December 31, 2012, to reduce the impact of foreign currency exchange rate movements. We are also subject to risks that the counterparties to these contracts fail to meet the terms of our foreign currency contracts. We cannot assure you that fluctuations in foreign currency exchange rates would not affect our financial results.
An impairment of goodwill or other indefinite lived intangible assets could reduce our earnings.
The Company has approximately $7.1 billion of goodwill and $0.6 billion of other intangible assets with indefinite lives as of December 31, 2012. Generally accepted accounting principles require the Company to test goodwill and other indefinite lived intangible assets for impairment on an annual basis or whenever events or circumstances occur indicating that goodwill might be impaired. Events or circumstances which could indicate a potential impairment include (but are not limited to) a significant reduction in worldwide oil and gas prices or drilling; a significant reduction in profitability or cash flow of oil and gas companies or drilling contractors; a significant reduction in worldwide well remediation activity; a significant reduction in capital investment by other oilfield service companies; or a significant increase in worldwide inventories of oil or gas. The timing and magnitude of any goodwill impairment charge, which could be material, would depend on the timing and severity of the event or events triggering the charge and would require a high degree of management judgment. If we were to determine that any of our remaining balance of goodwill or other indefinite lived intangible assets was impaired, we would record an immediate charge to earnings with a corresponding reduction in stockholders’ equity; resulting in an increase in balance sheet leverage as measured by debt to total capitalization.
See additional discussion on “Goodwill and Other Indefinite - Lived Intangible Assets” in Critical Accounting Estimates of Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”
We could be adversely affected if we fail to comply with any of the numerous federal, state and local laws, regulations and policies that govern environmental protection, zoning and other matters applicable to our businesses.
Our businesses are subject to numerous federal, state and local laws, regulations and policies governing environmental protection, zoning and other matters. These laws and regulations have changed frequently in the past and it is reasonable to expect additional changes in the future. If existing regulatory requirements change, we may be required to make significant unanticipated capital and operating expenditures. We cannot assure you that our operations will continue to comply with future laws and regulations. Governmental authorities may seek to impose fines and penalties on us or to revoke or deny the issuance or renewal of operating permits for failure to comply with applicable laws and regulations. Under these circumstances, we might be required to reduce or cease operations or conduct site remediation or other corrective action which could adversely impact our operations and financial condition.
Our businesses expose us to potential environmental liability.
Our businesses expose us to the risk that harmful substances may escape into the environment, which could result in:
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personal injury or loss of life;
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severe damage to or destruction of property; or
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environmental damage and suspension of operations.
Our current and past activities, as well as the activities of our former divisions and subsidiaries, could result in our facing substantial environmental, regulatory and other liabilities. These could include the costs of cleanup of contaminated sites and site closure obligations. These liabilities could also be imposed on the basis of one or more of the following theories:
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negligence;
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strict liability;
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breach of contract with customers; or
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as a result of our contractual agreement to indemnify our customers in the normal course of business, which is normally the case.
We may not have adequate insurance for potential environmental liabilities.
While we maintain liability insurance, this insurance is subject to coverage limits. In addition, certain policies do not provide coverage for damages resulting from environmental contamination. We face the following risks with respect to our insurance coverage:
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we may not be able to continue to obtain insurance on commercially reasonable terms;
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we may be faced with types of liabilities that will not be covered by our insurance;
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our insurance carriers may not be able to meet their obligations under the policies; or
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the dollar amount of any liabilities may exceed our policy limits.
Even a partially uninsured claim, if successful and of significant size, could have a material adverse effect on our consolidated financial statements.
The adoption of climate change legislation or regulations restricting emissions of greenhouse gases could increase our operating costs or reduce demand for our products.
Environmental advocacy groups and regulatory agencies in the United States and other countries have been focusing considerable attention on the emissions of carbon dioxide, methane and other greenhouse gases and their potential role in climate change. The adoption of laws and regulations to implement controls of greenhouse gases, including the imposition of fees or taxes, could adversely impact our operations and financial condition. The U.S. Congress is currently working on legislation to control and reduce emissions of greenhouse gases in the United States, which includes establishing cap-and-trade programs. In addition to the pending climate legislation, the U.S. Environmental Protection Agency has proposed regulations that would require permits for and reductions in greenhouse gas emissions for certain facilities, and may issue final rules this year. These changes in the legal and regulatory environment could reduce oil and natural gas drilling activity and result in a corresponding decline in the demand for our products and services, which could adversely impact our operating results and financial condition.
We had revenues of 10% of total revenue from one of our customers for the year ended December 31, 2012.
The loss of this customer (Samsung Heavy Industries) or a significant reduction in its purchases could adversely affect our future revenues and earnings.
The 2010 moratorium on deepwater drilling in the U.S. Gulf of Mexico and its consequences could have a material adverse effect on our business.
A moratorium on deepwater drilling in the U.S. Gulf of Mexico was enacted during the second quarter of 2010 following the Macondo well blowout and oil spill. Even though such moratorium has been lifted, any prolonged reduction in oil and natural gas drilling and production activity as a result of such moratorium or permitting issues in this area could result in a corresponding decline in the demand for our products and services, which could adversely impact our operating results and financial condition.
Our information systems may experience an interruption or breach in security.
We rely heavily on information systems to conduct our business. Any failure, interruption or breach in security of our information systems could result in failures or disruptions in our customer relationship management, general ledger systems and other systems. While we have policies and procedures designed to prevent or limit the effect of the failure, interruption or security breach of our information systems, there can be no assurance that any such failures, interruptions or security breaches will not occur or, if they do occur, that they will be adequately addressed. The occurrence of any failures, interruptions or security breaches of the our information systems could damage our reputation, result in a loss of customer business, subject us to additional regulatory scrutiny, or expose us to civil litigation and possible financial liability, any of which could have a material adverse effect on our financial position or results of operations.
GLOSSARY OF OILFIELD TERMS
(Sources: Company management; “A Dictionary for the Petroleum Industry,” The University of Texas at Austin, 2001.)
API
Abbr: American Petroleum Institute
Annular Blowout Preventer
A large valve, usually installed above the ram blowout preventers, that forms a seal in the annular space between the pipe and the wellbore or, if no pipe is present, in the wellbore itself.
Annulus
The open space around pipe in a wellbore through which fluids may pass.
Automatic Pipe Handling
Systems (Automatic Pipe
Racker)
A device used on a drilling rig to automatically remove and insert drill stem components from and into the hole. It replaces the need for a person to be in the derrick or mast when tripping pipe into or out of the hole.
Automatic Roughneck
A large, self-contained pipe-handling machine used by drilling crew members to make up and break out tubulars. The device combines a spinning wrench, torque wrench, and backup wrenches.
Beam pump
Surface pump that raise and lowers sucker rods continually, so as to operate a downhole pump.
Bit
The cutting or boring element used in drilling oil and gas wells. The bit consists of a cutting element and a circulating element. The cutting element is steel teeth, tungsten carbide buttons, industrial diamonds, or polycrystalline diamonds (“PDCs”). These teeth, buttons, or diamonds penetrate and gouge or scrape the formation to remove it. The circulating element permits the passage of drilling fluid and utilizes the hydraulic force of the fluid stream to improve drilling rates. In rotary drilling, several drill collars are joined to the bottom end of the drill pipe column, and the bit is attached to the end of the drill collars. Drill collars provide weight on the bit to keep it in firm contact with the bottom of the hole. Most bits used in rotary drilling are roller cone bits, but diamond bits are also used extensively.
Blowout
An uncontrolled flow of gas, oil or other well fluids into the atmosphere. A blowout, or gusher, occurs when formation pressure exceeds the pressure applied to it by the column of drilling fluid. A kick warns of an impending blowout.
Blowout Preventer (BOP)
Series of valves installed at the wellhead while drilling to prevent the escape of pressurized fluids.
Blowout Preventer (BOP) Stack
The assembly of well-control equipment including preventers, spools, valves, and nipples connected to the top of the wellhead.
Closed Loop Drilling Systems
A solids control system in which the drilling mud is reconditioned and recycled through the drilling process on the rig itself.
Coiled Tubing
A continuous string of flexible steel tubing, often hundreds or thousands of feet long, that is wound onto a reel, often dozens of feet in diameter. The reel is an integral part of the coiled tubing unit, which consists of several devices that ensure the tubing can be safely and efficiently inserted into the well from the surface. Because tubing can be lowered into a well without having to make up joints of tubing, running coiled tubing into the well is faster and less expensive than running conventional tubing. Rapid advances in the use of coiled tubing make it a popular way in which to run tubing into and out of a well. Also called reeled tubing.
Cuttings
Fragments of rock dislodged by the bit and brought to the surface in the drilling mud. Washed and dried cutting samples are analyzed by geologist to obtain information about the formations drilled.
Directional Well
Well drilled in an orientation other than vertical in order to access broader portions of the formation.
Drawworks
The hoisting mechanism on a drilling rig. It is essentially a large winch that spools off or takes in the drilling line and thus raises or lowers the drill stem and bit.
Drill Pipe Elevator (Elevator)
On conventional rotary rigs and top-drive rigs, hinged steel devices with manual operating handles that crew members latch onto a tool joint (or a sub). Since the elevators are directly connected to the traveling block, or to the integrated traveling block in the top drive, when the driller raises or lowers the block or the top-drive unit, the drill pipe is also raised or lowered.
Drilling jars
A percussion tool operated manually or hydraulically to deliver a heavy downward blow to free a stuck drill stem.
Drilling mud
A specially compounded liquid circulated through the wellbore during rotary drilling operations.
Drilling riser
A conduit used in offshore drilling through which the drill bit and other tools are passed from the rig on the water’s surface to the sea floor.
Drill stem
All members in the assembly used for rotary drilling from the swivel to the bit, including the Kelly, the drill pipe and tool joints, the drill collars, the stabilizers, and various specialty items.
Fiberglass-reinforced
spoolable pipe
A spoolable glass fiber-reinforced epoxy composite tubular product for onshore oil and gas gathering and injection systems, with superior corrosion resistant properties and lower installed cost than steel.
Flexible pipe
A dynamic riser that connects subsea production equipment to a topside facility allowing for the flow of oil, gas, and/or water.
Formation
A bed or deposit composed throughout of substantially the same kind of rock; often a lithologic unit. Each formation is given a name, frequently as a result of the study of the formation outcrop at the surface and sometimes based on fossils found in the formation.
FPSO
A Floating Production, Storage and Offloading vessel used to receive hydrocarbons from subsea wells, and then produce and store the hydrocarbons until they can be offloaded to a tanker or pipeline.
Hardbanding
A special wear-resistant material often applied to tool joints to prevent abrasive wear to the area when the pipe is being rotated downhole.
Hydraulic Fracturing
The process of creating fractures in a formation by pumping fluids, at high pressures, into the reservoir, which allows or enhances the flow of hydrocarbons.
Iron Roughneck
A floor-mounted combination of a spinning wrench and a torque wrench. The Iron Roughneck moves into position hydraulically and eliminates the manual handling involved with suspended individual tools.
Jack-up rig
A mobile bottom-supported offshore drilling structure with columnar or open-truss legs that support the deck and hull. When positioned over the drilling site, the bottoms of the legs penetrate the seafloor.
Jar
A mechanical device placed near the top of the drill stem which allows the driller to strike a very heavy blow upward or downward on stuck pipe.
Joint
1. In drilling, a single length (from 16 feet to 45 feet, or 5 meters to 14.5 meters, depending on its range length) of drill pipe, drill collar, casing or tubing that has threaded connections at both ends. Several joints screwed together constitute a stand of pipe. 2. In pipelining, a single length (usually 40 feet-12 meters) of pipe. 3. In sucker rod pumping, a single length of sucker rod that has threaded connections at both ends.
Kelly
The heavy steel tubular device, four- or six-sided, suspended from the swivel through the rotary table and connected to the top joint of drill pipe to turn the drill stem as the rotary table returns. It has a bored passageway that permits fluid to be circulated into the drill stem and up the annulus, or vice versa. Kellys manufactured to API specifications are available only in four- or six-sided versions, are either 40 or 54 feet (12 to 16 meters) long, and have diameters as small as 2.5 inches (6 centimeters) and as large as 6 inches (15 centimeters).
Kelly bushing
A special device placed around the kelly that mates with the kelly flats and fits into the master bushing of the rotary table. The kelly bushing is designed so that the kelly is free to move up or down through it. The bottom of the bushing may be shaped to fit the opening in the master bushing or it may have pins that fit into the master bushing. In either case, when the kelly bushing is inserted into the master bushing and the master bushing is turned, the kelly bushing also turns. Since the kelly bushing fits onto the kelly, the kelly turns, and since the kelly is made up to the drill stem, the drill stem turns. Also called the drive bushing.
Kelly spinner
A pneumatically operated device mounted on top of the kelly that, when actuated, causes the kelly to turn or spin. It is useful when the kelly or a joint of pipe attached to it must be spun up, that is, rotated rapidly for being made up.
Kick
An entry of water, gas, oil, or other formation fluid into the wellbore during drilling. It occurs because the pressure exerted by the column of drilling fluid is not great enough to overcome the pressure exerted by the fluids in the formation drilled. If prompt action is not taken to control the kick, or kill the well, a blowout may occur.
Making-up
1. To assemble and join parts to form a complete unit (e.g., to make up a string of drill pipe). 2. To screw together two threaded pieces. Compare break out. 3. To mix or prepare (e.g., to make up a tank of mud). 4. To compensate for (e.g., to make up for lost time).
Manual tongs (Tongs)
The large wrenches used for turning when making up or breaking out drill pipe, casing, tubing, or other pipe; variously called casing tongs, pipe tongs, and so forth, according to the specific use. Power tongs or power wrenches are pneumatically or hydraulically operated tools that serve to spin the pipe up tight and, in some instances to apply the final makeup torque.
Master bushing
A device that fits into the rotary table to accommodate the slips and drive the kelly bushing so that the rotating motion of the rotary table can be transmitted to the kelly. Also called rotary bushing.
Mooring system
The method by which a vessel or buoy is fixed to a certain position, whether permanently or temporarily.
Motion compensation
equipment
Any device (such as a bumper sub or heave compensator) that serves to maintain constant weight on the bit in spite of vertical motion of a floating offshore drilling rig.
Mud pump
A large, high-pressure reciprocating pump used to circulate the mud on a drilling rig.
Plug gauging
The mechanical process of ensuring that the inside threads on a piece of drill pipe comply with API standards.
Pressure control equipment
Equipment used in: 1. The act of preventing the entry of formation fluids into a wellbore. 2. The act of controlling high pressures encountered in a well.
Pressure pumping
Pumping fluids into a well by applying pressure at the surface.
Ram blowout preventer
A blowout preventer that uses rams to seal off pressure on a hole that is with or without pipe. Also called a ram preventer.
Ring gauging
The mechanical process of ensuring that the outside threads on a piece of drill pipe comply with API standards.
Riser
A pipe through which liquids travel upward.
Riser pipe
The pipe and special fitting used on floating offshore drilling rigs to established a seal between the top of the wellbore, which is on the ocean floor, and the drilling equipment located above the surface of the water. A riser pipe serves as a guide for the drill stem from the drilling vessel to the wellhead and as a conductor or drilling fluid from the well to the vessel. The riser consists of several sections of pipe and includes special devices to compensate for any movement of the drilling rig caused by waves. Also called marine riser pipe, riser joint.
Rotary table
The principal piece of equipment in the rotary table assembly; a turning device used to impart rotational power to the drill stem while permitting vertical movement of the pipe for rotary drilling. The master bushing fits inside the opening of the rotary table; it turns the kelly bushing, which permits vertical movement of the kelly while the stem is turning.
Rotating blowout
preventer (Rotating Head)
A sealing device used to close off the annular space around the kelly in drilling with pressure at the surface, usually installed above the main blowout preventers. A rotating head makes it possible to drill ahead even when there is pressure in the annulus that the weight of the drilling fluid is not overcoming; the head prevents the well from blowing out. It is used mainly in the drilling of formations that have low permeability. The rate of penetration through such formations is usually rapid.
Safety clamps
A clamp placed very tightly around a drill collar that is suspended in the rotary table by drill collar slips. Should the slips fail, the clamp is too large to go through the opening in the rotary table and therefore prevents the drill collar string from falling into the hole. Also called drill collar clamp.
Shaker
See “Shale Shaker”
Shale shaker
A piece of drilling rig equipment that uses a vibrating screen to remove cuttings from the circulating fluid in rotary drilling operations. The size of the openings in the screen should be selected carefully to be the smallest size possible to allow 100 per cent flow of the fluid. Also called a shaker.
Slim-hole completions
(Slim-hole Drilling)
Drilling in which the size of the hole is smaller than the conventional hole diameter for a given depth. This decrease in hole size enables the operator to run smaller casing, thereby lessening the cost of completion.
Slips
Wedge-shaped pieces of metal with serrated inserts (dies) or other gripping elements, such as serrated buttons, that suspend the drill pipe or drill collars in the master bushing of the rotary table when it is necessary to disconnect the drill stem from the kelly or from the top-drive unit’s drive shaft. Rotary slips fit around the drill pipe and wedge against the master bushing to support the pipe. Drill collar slips fit around a drill collar and wedge against the master bushing to support the drill collar. Power slips are pneumatically or hydraulically actuated devices that allow the crew to dispense with the manual handling of slips when making a connection.
Solids
See “Cuttings”
Spinning wrench
Air-powered or hydraulically powered wrench used to spin drill pipe in making or breaking connections.
Spinning-in
The rapid turning of the drill stem when one length of pipe is being joined to another. “Spinning-out” refers to separating the pipe.
Stand
The connected joints of pipe racked in the derrick or mast when making a trip. On a rig, the usual stand is about 90 feet (about 27 meters) long (three lengths of drill pipe screwed together), or a treble.
String
The entire length of casing, tubing, sucker rods, or drill pipe run into a hole.
Sucker rod
A special steel pumping rod. Several rods screwed together make up the link between the pumping unit on the surface and the pump at the bottom of the well.
Tensioner
A system of devices installed on a floating offshore drilling rig to maintain a constant tension on the riser pipe, despite any vertical motion made by the rig. The guidelines must also be tensioned, so a separate tensioner system is provided for them.
Thermal desorption
The process of removing drilling mud from cuttings by applying heat directly to drill cuttings.
Tiebacks (Subsea)
A series of flowlines and pipes that connect numerous subsea wellheads to a single collection point.
Top drive
A device similar to a power swivel that is used in place of the rotary table to turn the drill stem. It also includes power tongs. Modern top drives combine the elevator, the tongs, the swivel, and the hook. Even though the rotary table assembly is not used to rotate the drill stem and bit, the top-drive system retains it to provide a place to set the slips to suspend the drill stem when drilling stops.
Torque wrench
Spinning wrench with a gauge for measuring the amount of torque being applied to the connection.
Trouble cost
Costs incurred as a result of unanticipated complications while drilling a well. These costs are often referred to as contingency costs during the planning phase of a well.
Turret
Mechanical device that allows a floating vessel to rotate around stationary flowlines, umbilicals, and other associated risers.
Well completion
1. The activities and methods of preparing a well for the production of oil and gas or for other purposes, such as injection; the method by which one or more flow paths for hydrocarbons are established between the reservoir and the surface. 2. The system of tubulars, packers, and other tools installed beneath the wellhead in the production casing; that is, the tool assembly that provides the hydrocarbon flow path or paths.
Wellhead
The termination point of a wellbore at surface level or subsea, often incorporating various valves and control instruments.
Well stimulation
Any of several operations used to increase the production of a well, such as acidizing or fracturing.
Well workover
The performance of one or more of a variety of remedial operations on a producing oil well to try to increase production. Examples of workover jobs are deepening, plugging back, pulling and resetting liners, and squeeze cementing.
Wellbore
A borehole; the hole drilled by the bit. A wellbore may have casing in it or it may be open (uncased); or part of it may be cased, and part of it may be open. Also called a borehole or hole.
Wireline
A slender, rodlike or threadlike piece of metal usually small in diameter, that is used for lowering special tools (such as logging sondes, perforating guns, and so forth) into the well. Also called slick line.
ITEM 1B.
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.
ITEM 2.
ITEM 2. PROPERTIES
The Company owned or leased over 1,160 facilities worldwide as of December 31, 2012, including the following principal manufacturing, service, distribution and administrative facilities:
* Building owned but land leased.
We own or lease more than 170 repair and manufacturing facilities that refurbish and manufacture new equipment and parts, approximately 460 distribution service centers and 530 service centers that provide inspection and equipment rental worldwide.
ITEM 3.
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.
ITEM 4. MINE SAFETY DISCLOSURES
Information regarding mine safety and other regulatory actions at our mines is included in Exhibit 95 to this Form 10-K.
PART II
ITEM 5.
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
Market Information
Our common stock is traded on the New York Stock Exchange (NYSE) under the symbol “NOV”. The following table sets forth, for the calendar periods indicated, the range of high and low closing prices for the common stock, as reported by the NYSE and the cash dividends declared per share.
As of February 14, 2013, there were 3,375 holders of record of our common stock. Many stockholders choose to own shares through brokerage accounts and other intermediaries rather than as holders of (excluding individual participants in securities positions listing) record so the actual number of stockholders is unknown but significantly higher.
Cash dividends aggregated $209 million and $191 million for the years ended December 31, 2012 and 2011, respectively. The declaration and payment of future dividends is at the discretion of the Company’s Board of Directors and will be dependent upon the Company’s results of operations, financial condition, capital requirements and other factors deemed relevant by the Company’s Board of Directors.
The information relating to our equity compensation plans required by Item 5. “Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities” is incorporated by reference to such information as set forth in Item 12. “Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters” contained herein.
PERFORMANCE GRAPH
The graph below compares the cumulative total shareholder return on our common stock to the S&P 500 Index and the S&P Oil & Gas Equipment & Services Index. The total shareholder return assumes $100 invested on December 31, 2007 in National Oilwell Varco, Inc., the S&P 500 Index and the S&P Oil & Gas Equipment & Services Index. It also assumes reinvestment of all dividends. The peer group is weighted based on the market capitalization of each company. The results shown in the graph below are not necessarily indicative of future performance.
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.
ITEM 6. SELECTED FINANCIAL DATA
(1) Financial information for prior periods and dates may not be comparable due to the impact of $2.9 billion in business combinations on our financial position and results of operations during 2012.
(2) Financial results of Grant Prideco have been included in our Consolidated Financial Statements beginning April 21, 2008, the date the Grant Prideco merger was completed and each of Grant Prideco’s common shares were exchanged for .4498 shares of our common stock and $23.20 in cash.
ITEM 7.
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
General Overview
The Company is a leading worldwide provider of highly engineered drilling and well-servicing equipment, products and services to the exploration and production segments of the oil and gas industry. With operations in over 1,160 locations across six continents, we design, manufacture and service a comprehensive line of drilling and well servicing equipment; sell and rent drilling motors, specialized downhole tools, and rig instrumentation; perform inspection and internal coating of oilfield tubular products; provide drill cuttings separation, management and disposal systems and services; provide expendables and spare parts used in conjunction with our large installed base of equipment; and provide supply chain management services through our distribution network. We also manufacture coiled tubing, manufacture high pressure fiberglass and composite tubing, and sell and rent advanced in-line inspection equipment to makers of oil country tubular goods. We have a long tradition of pioneering innovations which improve the cost-effectiveness, efficiency, safety, and environmental impact of oil and gas operations.
Our revenues and operating results are directly related to the level of worldwide oil and gas drilling and production activities and the profitability and cash flow of oil and gas companies and drilling contractors, which in turn are affected by current and anticipated prices of oil and gas. Oil and gas prices have been and are likely to continue to be volatile. See “Risk Factors”. We conduct our operations through three business segments: Rig Technology, Petroleum Services & Supplies and Distribution & Transmission. See Item 1. “Business” for a discussion of each of these business segments.
Unless indicated otherwise, results of operations data are presented in accordance with accounting principles generally accepted in the United States (“GAAP”). In an effort to provide investors with additional information regarding our results of operations, certain non-GAAP financial measures, including operating profit excluding other costs, operating profit percentage excluding other costs and diluted earnings per share excluding other costs, are provided. See “Non-GAAP Financial Measures and Reconciliations” in Results of Operations for an explanation of our use of non-GAAP financial measures and reconciliations to their corresponding measures calculated in accordance with GAAP.
Operating Environment Overview
Our results are dependent on, among other things, the level of worldwide oil and gas drilling, well remediation activity, the price of crude oil and natural gas, capital spending by other oilfield service companies and drilling contractors, and the worldwide oil and gas inventory levels. Key industry indicators for the past three years include the following:
* Averages for the years indicated. See sources below.
The following table details the U.S., Canadian, and international rig activity and West Texas Intermediate Oil prices for the past nine quarters ended December 31, 2012 on a quarterly basis:
Source: Rig count: Baker Hughes, Inc. (www.bakerhughes.com); West Texas Intermediate Crude Price: Department of Energy, Energy Information Administration (www.eia.doe.gov).
The average price per barrel of West Texas Intermediate Crude was $94.11 per barrel in 2012, a slight decrease of 0.8% over the average price for 2011 of $94.90 per barrel. Average natural gas prices were $2.75 per mmbtu, a decrease of 31.3% compared to the 2011 average of $4.00 per mmbtu. Average rig activity worldwide increased 1.5% for the full year in 2012 compared to 2011. Average crude oil prices for the fourth quarter of 2012 was $87.96 per barrel and natural gas was $3.40 per mmbtu.
At February 8, 2013, there were 2,390 rigs actively drilling in North America, compared to 1,967 rigs at December 31, 2012; an increase of 21.5% from year end 2012 levels. The price of oil increased to $95.72 per barrel and gas decreased to $3.27 per mmbtu at February 8, 2013, representing a 4.2% increase in oil prices and a 4.6% decrease in gas prices from the end of 2012.
EXECUTIVE SUMMARY
During 2012 National Oilwell Varco, Inc. earned $2.5 billion in net income attributable to Company, or $5.83 per fully diluted share. Earnings per diluted share increased 24% from prior year levels of $2.0 billion or $4.70 per fully diluted share. Excluding other costs (as defined in the “Non-GAAP Financial Measures and Reconciliations” in Results of Operations) from both years, diluted earnings per share of $5.91 in 2012 increased 24% from $4.77 per share in 2011.
During 2012 revenue grew 37% from 2011, to $20.0 billion, and operating profit grew 21% from 2011 as well, to $3.6 billion. Generally 2012 benefitted from strategic acquisitions as well as higher international drilling activity, which saw international rig counts (as measured by Baker Hughes) increase 6% from 2011. This enabled all three of the Company’s reporting segments to post higher year-over-year revenues in 2012.
For its fourth quarter ended December 31, 2012, the Company generated $668 million in net income attributable to Company, or $1.56 per fully diluted share, on $5.7 billion in revenue. Compared to the third quarter of 2012 revenue increased $366 million or 7% and net income attributable to Company increased $56 million. Compared to the fourth quarter of 2011, revenue increased $1.4 billion or 33%, and net income attributable to Company increased $94 million or 16%.
The fourth quarter of 2012 included pre-tax other costs of $51 million, the third quarter of 2012 included pre-tax other costs of $48 million, and the fourth quarter of 2011 included pre-tax other costs of $12 million. The fourth quarter of 2012 also included a net $69 million tax benefit related to certain U.S. foreign tax credits in the quarter. Excluding the tax benefit and the other costs from all periods, fourth quarter 2012 earnings were $1.49 per fully diluted share, compared to $1.52 per fully diluted share in the third quarter of 2012 and $1.37 per fully diluted share in the fourth quarter of 2011.
Operating profit excluding other costs was $954 million or 16.8% of sales in the fourth quarter of 2012, compared to $946 million or 17.8% of sales in the third quarter of 2012, and $860 million or 20.2% of sales in the fourth quarter of 2011. Fourth quarter 2012 results include full quarter results for several businesses acquired since the beginning of the year, including three lower-margin distribution businesses, which resulted in lower margins for the fourth quarter of 2012 as compared to the fourth quarter of 2011 year-over-year. Operating leverage or flow-through (the change in operating profit divided by the change in revenue) was 2% on the sequential revenue increase, and 7% on the year-over-year fourth quarter sales increase.
Also of note, in the fourth quarter of 2012, National Oilwell Varco issued $3 billion of Senior Notes with an effective yield of 2.92%, with $500 million due in 5 years, $1.4 billion due in 10 years, and $1.1 billion due in 30 years.
Oil & Gas Equipment and Services Market
Worldwide, developed economies turned down in late 2008 as looming housing-related asset write-downs at major financial institutions paralyzed credit markets and sparked a serious global banking crisis. Major central banks responded vigorously through 2009, but a credit-driven worldwide economic recession developed nonetheless. Developed economies struggled to recover throughout 2010 and 2011, facing additional economic weakness related to potential sovereign debt defaults in Europe. As a result, commodity prices, including oil and gas prices, have been volatile. After rising steadily for six years to peak at around $140 per barrel (West Texas Intermediate Crude Prices) earlier in 2008, oil prices collapsed back to average $43 per barrel during the first quarter of 2009, but have slowly recovered into the $100 per barrel range by mid-2011 where they held relatively steady since (although the fourth quarter of 2012 dipped to average $88 per barrel). After trading in the range of $6 to $9 an mmbtu from 2004 to 2008, North American gas prices declined to average $3.17 per mmbtu in the third quarter of 2009. Gas prices recovered modestly, trading up above $5 six months later, but then slowly settled into the $3 to $4 per mmbtu through 2011 before turning down sharply in early 2012 to the $2 range (fourth quarter 2012 recovered to average $3.40 per mmbtu). The recent gas price collapse appears to be a direct result of rising gas supply out of unconventional shale reservoir development across North America, including gas associated with liquids production from shales.
The steadily rising oil and gas prices seen between 2003 and 2008 led to high levels of exploration and development drilling in many oil and gas basins around the globe by 2008, but activity slowed sharply in 2009 with lower oil and gas prices and tightening credit availability. Strengthening oil prices since then have led to steadily rising oil-drilling activity over the past two years.
The count of rigs actively drilling in the U.S. as measured by Baker Hughes (a good measure of the level of oilfield activity and spending) peaked at 2,031 rigs in September 2008, but decreased to a low of 876 in June, 2009. U.S. rig count increased steadily to 2,026 by late 2011, but began to decline with lower gas prices to average 1,809 rigs during the fourth quarter of 2012. Many oil and gas operators reliant on external financing to fund their drilling programs significantly curtailed their drilling activity in 2009, but drilling recovered across North America as gas prices improved. Recently low gas prices have caused operators to trim drilling, driving the average U.S. gas rig count down 52% from the fourth quarter of 2011, to an average of 423 in the fourth quarter of
2012. However, with high oil prices, many have redirected drilling efforts towards unconventional shale plays targeting oil, rather than gas. For the fourth quarter of 2012, oil-directed drilling rose to almost 77% of the total domestic drilling effort, and, while the average oil-directed drilling rig count declined by 2% from the third quarter to 1,383 rigs, it remains near its highest levels in the U.S. since the early 1980’s.
Most international activity is driven by oil exploration and production by national oil companies, which has historically been less susceptible to short-term commodity price swings; but, the international rig count exhibited modest declines nonetheless, falling from its September 2008 peak of 1,108 to 947 in August 2009. Recently international drilling rebounded due to high oil prices, climbing back to 1,285 in June 2012 before falling back to 1,253 in December.
During 2009 the Company saw its Petroleum Services & Supplies and its Distribution & Transmission margins affected most acutely by a drilling downturn, through both volume and price declines. Resumption of drilling activity since enabled both of these segments to gain volume, stabilize and lift pricing, and improve margins since the fourth quarter of 2009. The Company’s Rig Technology segment was less impacted by the 2009 downturn owing to its high level of contracted backlog, which it executed well. It posted higher revenues in 2009 than 2008 as a result. Its revenues declined in 2010 as its backlog declined, but increased 12% in 2011 as orders for new offshore rigs began to increase.
The recent economic decline beginning in late 2008 followed an extended period of high drilling activity which fueled strong demand for oilfield services between 2003 and 2008. Incremental drilling activity through the upswing shifted toward harsh environments, employing increasingly sophisticated technology to find and produce reserves. Higher utilization of drilling rigs tested the capability of the world’s fleet of rigs, much of which is old and of limited capability. Technology has advanced significantly since most of the existing rig fleet was built. The industry invested little during the late 1980’s and 1990’s on new drilling equipment, but drilling technology progressed steadily nonetheless, as the Company and its competitors continued to invest in new and better ways of drilling. As a consequence, the safety, reliability, and efficiency of new, modern rigs surpass the performance of most of the older rigs at work today. Drilling rigs are now being pushed to drill deeper wells, more complex wells, highly deviated wells and horizontal wells, tasks which require larger rigs with more capabilities. The drilling process effectively consumes the mechanical components of a rig, which wear out and need periodic repair or replacement. This process was accelerated by very high rig utilization and wellbore complexity. Drilling consumes rigs; more complex and challenging drilling consumes rigs faster.
The industry responded by launching many new rig construction projects since 2005, to 1.) retool the existing fleet of jackup rigs (according to RigLogix, nearly 65% of the existing 494 jackup rigs are more than 25 years old); 2.) replace older mechanical and DC electric land rigs with improved AC power, electronic controls, automatic pipe handling and rapid rigup and rigdown technology; and 3.) build out additional deepwater floating drilling rigs, including semisubmersibles and drillships, to employ recent advancements in deepwater drilling to exploit unexplored deepwater basins. We believe that the newer rigs offer considerably higher efficiency, safety, and capability, and that many will effectively replace a portion of the existing fleet.
As a result of these trends the Company’s Rig Technology segment grew its backlog of capital equipment orders from $0.9 billion at June 30, 2005, to $11.8 billion at September 30, 2008. However, as a result of the credit crisis and slowing drilling activity, orders declined below amounts flowing out of backlog as revenue, causing the backlog to decline to $4.9 billion by June 30, 2010. The backlog increased steadily since, as drillers began ordering more than the Company shipped out of backlog, and finished the fourth quarter of 2012 at a record $11.9 billion. Approximately $7.4 billion of these orders are scheduled to flow out as revenue during 2013, with the balance flowing out in 2014 and beyond. Of this backlog, 91% of the total is for equipment destined for offshore operations, with 9% destined for land. Equipment destined for international markets totaled 94% of the backlog.
Segment Performance
The Rig Technology segment generated $10.1 billion in revenues and $2.3 billion in operating profit or 23.1% of sales during 2012. Compared to the prior year revenues improved 30%, however, operating profit improved 14% year-over-year due to a broad change in the segment’s business mix, which led to lower margins. Offshore projects contracted at high prices in 2007 and 2008 were manufactured in low cost environments in 2010, resulting in high margins (29.6%) for the group. As these projects were completed and replaced with lower priced projects, 2011 margins declined 330 basis points from the prior year. For the fourth quarter of 2012, the segment generated $2.9 billion in revenues and $636 million in operating profit or 22.0% of sales. Compared to the prior quarter revenues increased $349 million or 14%, and operating profit increased $38 million. Operating leverage or flow-through was 11% from the third quarter to the fourth quarter. Compared to the fourth quarter of 2011 segment revenues grew $580 million or 25%, and operating profit increased $39 million. Year-over-year operating leverage or flow-through was 7%. Margins have moved down steadily since mid-2010 due to an adverse mix shift in the segment, the addition of lower-margin acquisitions, and incremental expenses to support several strategic growth initiatives. The mix shift arises from offshore projects contracted at high prices in 2007 and 2008, which were subsequently manufactured in low cost environments in 2009 and 2010, resulting in high margins for the group which peaked in the third quarter of 2010. As these projects have been completed and replaced with lower priced projects, margins have gradually declined. Revenue out of backlog increased 16% sequentially and increased 25% year-over-year. Non-backlog revenue, which is predominantly aftermarket spares and services, increased 8% sequentially and increased 27% from the fourth
quarter of 2011. Orders for seven deepwater floating rig equipment packages, and three spare BOP stacks contributed to total order additions to backlog of $2.4 billion during the fourth quarter. Interest in offshore rig construction has remained strong as announced dayrates for deepwater offshore rigs are increasing, rig building costs have stabilized at attractive levels, and financing appears to be available for most established drillers. The Company continues to tender additional new offshore rig projects for Petrobras to shipyards and drilling contractors, which are to be built in Brazil. However, further potential bookings of any additional offshore rigs for Brazil may continue to be subject to delays. The segment’s well intervention and stimulation product sales increased 25% sequentially, as the delivery of several large projects to international customers more than offset a continued decline in demand for pressure pumping equipment.
The Petroleum Services & Supplies segment generated $7.0 billion in revenue and $1.5 billion in operating profit, or 21.5% of sales, for the full year 2012. Compared to the prior year revenue increased 23%, and operating leverage or flow-through was 33%. For the fourth quarter of 2012, the segment generated $1.8 billion in revenue and $340 million in operating profit, or 19.2% of sales. Compared to the prior quarter revenue increased $53 million or 3%, but operating profit declined $43 million. Sequentially, high year-end sales of drill pipe and large outside diameter (“O.D.”) connectors, combined with revenue growth in the international coating business, more than offset the lower sales of downhole tools, fluid-end expendables and coiled tubing, which were directly attributable to the reduction in U.S. land drilling and well service activity. Compared to the fourth quarter of 2011 revenues increased $200 million or 13% and operating leverage or flow-through was 23%. Approximately 55% of the segment’s fourth quarter sales were into North American markets, and 45% of sales were into international markets.
The Distribution & Transmission segment generated $3.9 billion in revenue and $185 million in operating profit or 4.7% of sales during 2012. Revenues improved 110% from 2011. For the fourth quarter of 2012, the segment generated $1.3 billion in revenue and $54 million in operating profit or 4.3% of sales. Revenues declined $47 million or 4% from the third quarter of 2012 while operating profit increased $12 million. Compared to the fourth quarter of 2011, revenues increased $708 million or 126% and flow-through or operating leverage was 1%. Sequentially, the overall decline in U.S. drilling and well service activity negatively impacted day-to-day sales of maintenance, repair and operating consumables, as well as sales of tubular products. The year over year revenue growth was due primarily to the acquisitions of Wilson and CE Franklin, made during the second and third quarters of 2012, respectively. Approximately 84% of the group’s fourth quarter sales were into North American markets and 16% into international markets.
Outlook
Following the credit market downturn, global recession, and lower commodity prices of 2009, we saw signs of stabilization and recovery in many of our markets in 2010 and into 2011, led by higher drilling activity in North America and slowly improving international drilling activity. Order levels for new deepwater drilling rigs have rebounded sharply, and the Rig Technology segment continues to experience a high level of interest as dayrates for deepwater offshore rigs continue to improve. Still, margins, which were 22.4% in the fourth quarter of 2012, may be temporarily challenged to expand, due to lower-margin contributions from recent subsea production equipment acquisitions, a soft outlook for land drilling, workover and pressure pumping equipment markets in North America, in view of low gas and natural gas liquids prices, and by incremental expenses to support long-term strategic growth initiatives.
Our outlook for the Company’s Petroleum Services & Supplies segment and Distribution & Transmission segment remains closely tied to the rig count, particularly in North America. The fourth quarter saw domestic rig counts continue to decline, resulting in an average U.S. rig count in December 2012 that was down 11% from the average U.S. rig count in January of 2012, and an average Canadian rig count in December 2012 that was down 18% from the same period in 2011. As a result, pricing and volumes are beginning to come under pressure as pressure pumpers, drilling contractors and oil companies reduce operating and capital expenditures. Additionally, economic weakness may pressure oil prices, which could lead to further activity declines, particularly among North American operators which may rely on cash flows from gas production and/or external financing to fund their drilling operations. In contrast, activity generally seems to be continuing to increase in most international markets outside North America.
The Company believes it is well positioned, and should benefit from its strong balance sheet and capitalization, access to credit, global infrastructure, broad product and service offering, installed base of equipment, and a record level of contracted orders. In the event of a market downturn, the Company also believes that its long history of cost-control and downsizing in response to slowing market conditions, and of executing strategic acquisitions during difficult periods will enable it to capitalize on new opportunities to effect new organic growth and acquisition initiatives.
Still the recovery of the world economy continues to move forward with a great deal of uncertainty as the world watches the sovereign debt crises in several European countries unfold, market turbulence and general global economic worries. If such global economic uncertaintanties develop adversely, world oil and gas prices could be impacted which in turn could negatively impact the worldwide rig count and the Company’s future financial results.
Results of Operations
Years Ended December 31, 2012 and December 31, 2011
The following table summarizes the Company’s revenue and operating profit by operating segment in 2012 and 2011 (in millions):
Rig Technology
Revenue from Rig Technology for the year ended December 31, 2012 was $10,107 million, an increase of $2,319 million (29.8%) compared to the year ended December 31, 2011. Deepwater offshore drilling worldwide and active shale plays in North America were the primary driving forces for the increase in revenue for this segment during the first half of 2012, resulting in increased rig construction as well as demand for well intervention and stimulation equipment and aftermarket spare parts. In addition, the acquisitions of NKT and Enerflow, occurring towards the beginning of the second quarter of 2012, contributed to the increase in revenue for Rig Technology. As the segment moved into the second half of 2012, it saw continued strong deepwater offshore demand as well as a strong demand in international markets with strong revenue growth in coiled tubing equipment, wireline equipment and land rigs sold internationally. North American markets, however, saw a decrease in demand for land drilling as both gas and oil plays have decreased production. This is evidenced by a decrease in rig count in the U.S. during 2012 and has resulted in lower sales of land rigs and jackups in the U.S. as the segment moved into the second half of 2012. The average rig count in the U.S. during the fourth quarter of 2012 decreased to 1,809 rigs (9%) from the first quarter 2012 average of 1,991 rigs. Rig Technology revenues could decrease as it enters 2013 due to the decrease in demand for pressure pumping equipment.
Operating profit from Rig Technology was $2,335 million (which included $45 million in other costs related to acquisitions) for the year ended December 31, 2012, an increase of $282 million (13.7%) compared to 2011. Operating profit percentage decreased to 23.1%, from 26.4% in 2011. Partially contributing to the decrease in operating profit percentage was a decrease in the average margin of revenue out of backlog as contracts signed during 2009 and 2010 contain less favorable margins compared to contracts won during the order ramp-up from 2005 to 2008. Also contributing to the decrease in operating profit percentage were integration costs related to the NKT and Enerflow acquisitions made during the second quarter of 2012 as well as considerable start-up costs associated with construction of an NOV Flexibles plant in Brazil, and the opening of a new Technical College in Korea. Coiled tubing equipment, wireline equipment and land rigs sold later in the year were primarily driven by large international projects that were secured at lower than average margins. Finally, increased FPSO related revenues, with operating profit lower than other parts of this segment, were dilutive to overall Rig Technology operating profit margins. As the segment enters 2013, we anticipate continued pricing pressures in North America coupled with a continuing shift in product mix that includes a growing percentage of Brazil and FPSO related revenues.
The Rig Technology segment monitors its capital equipment backlog to plan its business. New orders are added to backlog only when the Company receives a firm written order for major drilling rig components or a signed contract related to a construction project. The capital equipment backlog was $11.9 billion at December 31, 2012, an increase of $1.7 billion (17%) from backlog of $10.2 billion at December 31, 2011.
Petroleum Services & Supplies
Revenue from Petroleum Services & Supplies for the year ended December 31, 2012 was $6,967 million, an increase of $1,313 million (23.2%) compared to the year ended December 31, 2011. Strong shale plays in North America lead to an increase in revenue for the Petroleum Services & Supplies segment during the first half of 2012 compared to 2011. Acquisitions made during the year such as Fiberspar Corporation and Zap-Lok Pipeline Systems, Inc. contributed to the increase in revenue for 2012 compared to 2011. Full period results of Ameron as well as other strategic acquisitions made during 2011 in the U.S., the U.K., the Netherlands, Singapore, Malaysia and Brazil also contributed to the increase in revenue for this segment in 2012 compared to 2011. Moving into the second half of 2012, while stronger than in 2011, compared to the first half of 2012, the segment saw a decrease in North American activity as evidenced in the decrease in U.S. rig count throughout the year. Petroleum Services & Supplies revenues could decrease as it enters 2013 as many of its businesses enter 2013 with diminished backlog and U.S. based drilling contractors as well as service firms have been hesitant to release new orders.
Operating profit from Petroleum Services & Supplies was $1,501 million (which included $18 million in other costs related to acquisitions) for the year ended December 31, 2012 compared to $1,072 million for 2011, an increase of $429 million (40.0%). Operating profit percentage increased to 21.5% up from 19.0% in 2011. This increase is primarily due to increased volume, favorable pricing and cost reductions within most business units within the segment during the first half of 2012 compared to the same period in 2011. However, as the segment moved into the second half of the year, due to the decrease in North American market activity, it began to experience pricing pressures across a number of products in the North American land market, coupled with a shift in product mix, which led to lower margins. Most notably, the continued reduction of North American land activity led to pricing pressures and an overall reduction in volume for the segments downhole tools, fiberglass pipe, coiled dubing, and fluid end expendables products. While declines in various product lines were offset partially with growth in the drill pipe, XL Systems and Tuboscope products, overall margins still continued to decline towards the end of the year. As the segment enters 2013, we anticipate continued pricing pressures in North America coupled with a possible decrease in volume.
Distribution & Transmission
Revenue from Distribution & Transmission was $3,927 million for the year ended December 31, 2012, an increase of $2,054 million (109.7%) compared to the year ended December 31, 2011. This increase was primarily attributable to the acquisitions of Wilson during the second quarter of 2012 and CE Franklin during the third quarter of 2012. Distribution & Transmission revenues are expected to increase as it enters 2013 as it realizes full period results for its 2012 acquisitions.
Operating profit from Distribution & Transmission was $185 million (which included $68 million in other costs related to acquisitions) for the year ended December 31, 2012, an increase of $50 million (37.0%) compared to $135 million for the year ended December 31, 2011. Operating profit percentage decreased to 4.7%, from 7.2% in 2011. Increased volume, greater cost efficiencies and continued favorable pricing which related to strong demand for this segment contributed to an increase in operating profit percentages for this segment during the first half of 2012. However, the impact of businesses acquired during 2012 combined with lower market activity resulted in margins dropping slightly for the year. In addition, other costs incurred for the expense recognition associated with acquired current assets stepped up to fair value during purchase accounting also contributed to the decrease in operating profit percentage. The majority of the stepped up value related to inventory and was fully recognized by December 31, 2012. As the segment enters 2013, we anticipate continued pricing pressures in North America coupled with a possible decrease in volume.
Unallocated expenses and eliminations
Unallocated expenses and eliminations in operating profit were $464 million for the year ended December 31, 2012 compared to $323 million for the year ended December 31, 2011. This increase was primarily due to the increased activity along all segments which in turn resulted in higher intersegment eliminations.
Equity Income in Unconsolidated Affiliates
Equity income in unconsolidated affiliates was $58 million for the year ended December 31, 2012 compared to $46 million for the year ended December 31, 2011. This increase was primarily due to increased equity earnings from the Company’s 50.01% investment in Voest-Alpine Tubulars (“VAT”) located in Kindberg, Austria.
Other income (expense), net
Other income (expense), net were expenses of $71 million for the year ended December 31, 2012 compared to $39 million for the year ended December 31, 2011. This increase was primarily due to foreign exchange losses and increased bank charges and fees.
Provision for income taxes
The effective tax rate for the year ended December 31, 2012 was 29.2%, compared to 32.1% for 2011. Compared to the U.S. statutory rate, the effective tax rate was positively impacted in the period by the effect of lower tax rates on income earned in foreign jurisdictions, foreign dividends net of foreign tax credits, the deduction in the U.S. for manufacturing activities and foreign exchange losses for tax reporting in Norway. The effective tax rate was negatively impacted by the recognition of increased valuation allowances on certain deferred tax assets associated with excess foreign tax credits carried to future periods.
During 2012, the Company recorded certain tax benefits totaling $138 million primarily from the repatriation of certain non-U.S. earnings that increased our U.S. foreign tax credits. These credits are available to be used by the Company as foreign tax credits in the U.S. over a 10 year period. These excess foreign tax credits were recognized as deferred tax assets in the balance sheet and would be realized as a reduction of future income tax payments in the U.S. However, because of uncertainty associated with the Company’s ability to fully utilize these credits in the future, a valuation allowance of $69 million was recorded in the period. The net result of these transactions reduced income tax expense by $69 million in the period.
Years Ended December 31, 2011 and December 31, 2010
The following table summarizes the Company’s revenue and operating profit by operating segment in 2011 and 2010 (in millions):
Rig Technology
Rig Technology revenue for the year ended December 31, 2011 was $7,788 million, an increase of $823 million (11.8%) compared to 2010. Deepwater offshore drilling world-wide and active shale plays in the U.S. continue to be the driving force for the increase in revenue for this segment resulting in both increased rig construction as well as demand for aftermarket spare parts and services. In addition, strategic acquisitions in the U.S. and Singapore contributed to the increase in revenue for this segment.
Operating profit from Rig Technology was $2,053 million for the year ended December 31, 2011, a decrease of $11 million (0.5%) over the same period of 2010. Operating profit percentage decreased to 26.4%, from 29.6% in 2010 primarily due to decrease in the average margin of revenue out of backlog as contracts signed during 2009 and 2010 contain less favorable margins compared to contracts won during the order ramp-up from 2005 to 2008. This decrease in margins was partially offset by the increase in demand for aftermarket spare parts and services.
The Rig Technology segment monitors its capital equipment backlog to plan its business. New orders are added to backlog only when the Company receives a firm written order for major drilling rig components or a signed contract related to a construction project. The capital equipment backlog was $10.2 billion at December 31, 2011, an increase of $5.2 billion (104.0%) from backlog of $5.0 billion at December 31, 2010. The $5.2 billion increase in backlog included the largest order in the Company’s history in the amount of approximately $1.5 billion won during the third quarter of 2011.
Petroleum Services & Supplies
Revenue from Petroleum Services & Supplies was $5,654 million for 2011 compared to $4,182 million for 2010, an increase of $1,472 million (35.2%). The increase was primarily attributable to shale plays leading to a strong North American market with a 21.7% increase in U.S. rig activity and a 20.5% increase in Canada rig activity compared to 2010. North American shale plays continue to be a driving force in the increase in revenues across most business units within this segment. In addition, strategic acquisitions in the U.S., the U.K., the Netherlands, Singapore, Malaysia and Brazil contributed to the increase in revenue for this segment.
Operating profit from Petroleum Services & Supplies was $1,072 million for 2011 compared to $585 million for 2010, an increase of $487 million (83.2%). Operating profit percentage increased to 19.0%, up from 14.0% in 2010. This increase is primarily due to increased volume with a strong North American demand fueled by an increase in rig count as well as continued favorable pricing within most business units within the segment. The increase was partially offset by lower levels of activity in the Middle East due to continued unrest in that region. This unrest resulted in the write-down, in the first quarter, of Libyan assets of $15 million, mostly related to accounts receivable affected by sanctions enacted during the quarter along with the write off of certain inventory and fixed assets in the country. The Company’s Rig Technology and Distribution & Transmission segments incurred $2 million of such asset write-downs during the first quarter for a total of $17 million in Libyan asset write-downs incurred by the Company.
Distribution & Transmission
Revenue from Distribution & Transmission totaled $1,873 million for 2011, an increase of $327 million (21.2%) from 2010. This increase was primarily attributable to increased rig count activity in Canada and the U.S. Internationally, the segments Mono business unit also contributed to the increase in revenues as demand for its power sections and artificial lift products increased in 2011 compared to 2010. In addition, strategic acquisitions in the U.S. and the U.K. contributed to the increase in revenue for this segment.
Operating profit from Distribution & Transmission, increased in 2011 to $135 million compared to $78 million in 2010. Operating profit percentage increased to 7.2% in 2011 from 5.0% in 2010 primarily due to greater cost efficiencies and better pricing related to strong demand fueled by an increase in Canada and U.S. rig count activity. This increase was partially offset by rig moves towards liquid shale plays, drill site construction delays and weather issues towards the end of the year in certain markets in which this segment participates.
Unallocated expenses and eliminations
Unallocated expenses and eliminations in operating profit were $323 million for the year ended December 31, 2011 compared to $280 million for 2010. This increase is primarily due to the increased activity along all segments which in turn resulted in higher intersegment eliminations and higher incentive compensation.
Equity Income in Unconsolidated Affiliates
Equity income in unconsolidated affiliates was $46 million for 2011 compared to $36 million for 2010, a $10 million increase which was primarily related to increased equity earnings from the Company’s 50.01% investment in Voest-Alpine Tubulars (“VAT”) located in Kindberg, Austria.
Other income (expense), net
Other income (expense), net was expense of $39 million in 2011 compared to expense of $49 million in 2010. The decrease in expense was primarily due to lower foreign exchange losses in 2011 compared to 2010. The Venezuelan government officially devalued the Venezuelan bolivar against the U.S. dollar in 2010. The Company converted its Venezuela ledgers to U.S. dollar functional currency and devalued monetary assets resulting in a $27 million foreign exchange loss during 2010. See Item 7A.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
We are exposed to changes in foreign currency exchange rates and interest rates. Additional information concerning each of these matters follows:
Foreign Currency Exchange Rates
We have extensive operations in foreign countries. The net assets and liabilities of these operations are exposed to changes in foreign currency exchange rates, although such fluctuations generally do not affect income since their functional currency is typically the local currency. These operations also have net assets and liabilities not denominated in the functional currency, which exposes us to changes in foreign currency exchange rates that impact income. During the years ended December 31, 2012, 2011 and 2010, the Company reported foreign currency losses of $21 million, $10 million and $30 million, respectively. Gains and losses are primarily due to exchange rate fluctuations related to monetary asset balances denominated in currencies other than the functional currency and adjustments to our hedged positions as a result of changes in foreign currency exchange rates. Strengthening of currencies against the U.S. dollar may create losses in future periods to the extent we maintain net assets and liabilities not denominated in the functional currency of the countries using the local currency as their functional currency.
Some of our revenues in foreign countries are denominated in U.S. dollars, and therefore, changes in foreign currency exchange rates impact our earnings to the extent that costs associated with those U.S. dollar revenues are denominated in the local currency. Similarly some of our revenues are denominated in foreign currencies, but have associated U.S. dollar costs, which also give rise to foreign currency exchange rate exposure. In order to mitigate that risk, we may utilize foreign currency forward contracts to better match the currency of our revenues and associated costs. We do not use foreign currency forward contracts for trading or speculative purposes.
The following table details the Company’s foreign currency exchange risk grouped by functional currency and their expected maturity periods as of December 31, 2012 (in millions except for rates):
The Company had other financial market risk sensitive instruments denominated in foreign currencies for transactional exposures totaling $567 million and translation exposures totaling $397 million as of December 31, 2012, excluding trade receivables and payables, which approximate fair value. These market risk sensitive instruments consisted of cash balances and overdraft facilities. The Company estimates that a hypothetical 10% movement of all applicable foreign currency exchange rates on the transactional exposures financial market risk sensitive instruments could affect net income by $37 million and the translational exposures financial market risk sensitive instruments could affect the future fair value by $40 million.
The counterparties to forward contracts are major financial institutions. The credit ratings and concentration of risk of these financial institutions are monitored on a continuing basis. In the event that the counterparties fail to meet the terms of a foreign currency contract, our exposure is limited to the foreign currency rate differential.
During the first quarter of 2010, the Venezuelan government officially devalued the Venezuelan bolivar against the U.S. dollar. As a result the Company converted its Venezuela ledgers to U.S. dollar functional currency, devalued monetary assets resulting in a $27 million charge, and wrote-down certain accounts receivable in view of deteriorating business conditions in Venezuela, resulting in an additional $11 million charge. During the first quarter of 2013, the Venezuelan government again officially devalued the Venezuelan bolivar against the U.S. dollar. As a result, the Company expects to incur approximately $12 million in devaluation charges in the first quarter of 2013. The Company’s net investment in Venezuela was $34 million at December 31, 2012.
Interest Rate Risk
At December 31, 2012, our long term borrowings consisted of $151 million in 6.125% Senior Notes, $500 million in 1.35% Senior Notes, $1,400 million in 2.60% Senior Notes and $1,100 million in 3.95% Senior Notes. We occasionally have borrowings under our credit facility, and a portion of these borrowings could be denominated in multiple currencies which could expose us to market risk with exchange rate movements. These instruments carry interest at a pre-agreed upon percentage point spread from either LIBOR, NIBOR or EURIBOR, or at the prime interest rate. Under our credit facility, we may, at our option, fix the interest rate for certain borrowings based on a spread over LIBOR, NIBOR or EURIBOR for 30 days to six months.
ITEM 8.
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.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE.
None.
ITEM 9A.
ITEM 9A. CONTROLS AND PROCEDURES
(i) Evaluation of disclosure controls and procedures
As required by SEC Rule 13a-15(b), we have evaluated, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this report. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by the Company in reports that it files under the Exchange Act is accumulated and communicated to the Company’s management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. Our principal executive officer and principal financial officer have concluded that our current disclosure controls and procedures were effective as of December 31, 2012 at the reasonable assurance level.
Pursuant to section 302 of the Sarbanes-Oxley Act of 2002, our Chief Executive Officer and Chief Financial Officer have provided certain certifications to the Securities and Exchange Commission. These certifications are included herein as Exhibits 31.1 and 31.2.
(ii) Internal Control Over Financial Reporting
(a) Management’s annual report on internal control over financial reporting.
The Company’s management report on internal control over financial reporting is set forth in this annual report on Page 62 and is incorporated herein by reference.
(b) Changes in internal control
There were no changes in the Company’s internal control over financial reporting that occurred during the Company’s last fiscal quarter covered by this report that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.
ITEM 9B.
ITEM 9B. OTHER INFORMATION
None.
PART III
ITEM 10.
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
Incorporated by reference to the definitive Proxy Statement for the 2013 Annual Meeting of Stockholders.
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION
Incorporated by reference to the definitive Proxy Statement for the 2013 Annual Meeting of Stockholders.
ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
Incorporated by reference to the definitive Proxy Statement for the 2013 Annual Meeting of Stockholders.
Securities Authorized for Issuance Under Equity Compensation Plans.
The following table sets forth information as of our fiscal year ended December 31, 2012, with respect to compensation plans under which our common stock may be issued:
(1) Shares could be issued through equity instruments other than stock options, warrants or rights; however, none are anticipated during 2013.
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
Incorporated by reference to the definitive Proxy Statement for the 2013 Annual Meeting of Stockholders.
ITEM 14.
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
Incorporated by reference to the definitive Proxy Statement for the 2013 Annual Meeting of Stockholders.
PART IV
ITEM 15.
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 Comprehensive Income
Consolidated Statements of Cash Flows
Consolidated Statements of Stockholders’ Equity
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
* Compensatory plan or arrangement for management or others.
(1) Filed as an Exhibit to our Quarterly Report on Form 10-Q filed on August 5, 2011.
(2) Filed as an Exhibit to our Annual Report on Form 10-K filed on March 28, 2002.
(3) Filed as an Exhibit to Varco International, Inc.’s Quarterly Report on Form 10-Q filed on May 6, 2004.
(4) Filed as Annex A to our Registration Statement on Form S-4 filed on September 16, 2004.
(5) Filed as an Exhibit to our Current Report on Form 8-K filed on February 24, 2012.
(6) Filed as an Exhibit to our Current Report on Form 8-K filed on February 23, 2006.
(7) Filed as an Exhibit to our Current Report on Form 8-K filed on March 27, 2007.
(8) Filed as Annex A to our Registration Statement on Form S-4 filed on January 28, 2008.
(9) Filed as an Exhibit to our Current Report on Form 8-K filed on August 17, 2011.
(10) Filed as an Exhibit to our Current Report on Form 8-K filed on October 1, 2012
(11) Filed as an Exhibit to our Current Report on Form 8-K filed on December 23, 2008.
(12) Filed as an Exhibit to our Current Report on Form 8-K filed on January 5, 2010.
(13) Filed as an Exhibit to our Current Report on Form 8-K filed on December 7, 2012.
(14) As provided in Rule 406T of Regulation S-T, this information is furnished and not filed for purposes of Sections 11 and 12 of the Securities Act of 1933 and Section 18 of the Securities Exchange Act of 1934.
We hereby undertake, pursuant to Regulation S-K, Item 601(b), paragraph (4) (iii), to furnish to the U.S. Securities and Exchange Commission, upon request, all constituent instruments defining the rights of holders of our long-term debt not filed herewith.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
Each person whose signature appears below in so signing, constitutes and appoints Merrill A. Miller, Jr. and Jeremy D. Thigpen, and each of them acting alone, his true and lawful attorney-in-fact and agent, with full power of substitution, for him and in his name, place and stead, in any and all capacities, to execute and cause to be filed with the Securities and Exchange Commission any and all amendments to this report, and in each case to file the same, with all exhibits thereto and other documents in connection therewith, and hereby ratifies and confirms all that said attorney-in-fact or his substitute or substitutes may do or cause to be done by virtue hereof.
MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
National Oilwell Varco, Inc.’s management is responsible for establishing and maintaining adequate internal control over financial reporting. National Oilwell Varco, Inc.’s internal control system was designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.
Internal control over financial reporting cannot provide absolute assurance of achieving financial reporting objectives because of its inherent limitations. Internal control over financial reporting is a process that involves human diligence and compliance and is subject to lapses in judgment and breakdowns resulting from human failures. Internal control over financial reporting also can be circumvented by collusion or improper management override. Because of such limitations, there is a risk that material misstatements may not be prevented or detected on a timely basis by internal control over financial reporting. However, these inherent limitations are known features of the financial reporting process. Therefore, it is possible to design into the process safeguards to reduce, though not eliminate, this risk.
On May 16, 2012, the Company acquired Enerflow, on May 31, 2012, acquired Wilson, and on July 19, 2012, acquired CE Franklin. For purposes of determining the effectiveness of the Company’s internal control over financial reporting, as disclosed in this report, management has excluded these acquisitions from its evaluation. The acquired businesses represented approximately 6% of our consolidated total assets at December 31, 2012, 8% of consolidated revenues and 2% of our consolidated operating profit for the year ended December 31, 2012.
Management has used the framework set forth in the report entitled “Internal Control-Integrated Framework” published by the Committee of Sponsoring Organizations (“COSO”) of the Treadway Commission to evaluate the effectiveness of the Company’s internal control over financial reporting. Management has concluded that the Company’s internal control over financial reporting was effective as of December 31, 2012.
The effectiveness of our internal control over financial reporting as of December 31, 2012, has been audited by Ernst & Young LLP, the independent registered public accounting firm which also has audited the Company’s Consolidated Financial Statements included in this Annual Report on Form 10-K.
/s/ Merrill A. Miller, Jr.
Merrill A. Miller, Jr.
Chairman and Chief Executive Officer
/s/ Jeremy D. Thigpen
Jeremy D. Thigpen
Senior Vice President and Chief Financial Officer
Houston, Texas
February 22, 2013
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors and Shareholders
National Oilwell Varco, Inc.
We have audited National Oilwell Varco, Inc.’s internal control over financial reporting as of December 31, 2012, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). National Oilwell Varco, Inc’s management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
As indicated in the accompanying Management’s Report on Internal Control Over Financial Reporting, management’s assessment of and conclusion on the effectiveness of internal control over financial reporting did not include the internal controls related to the acquisitions of Wilson, Enerflow and CE Franklin. The acquired businesses represented approximately 6% of consolidated total assets at December 31, 2012, 8% of consolidated revenues and 2% of consolidated operating profit for the year ended December 31, 2012. Our audit of internal control over financial reporting of the Company also did not include the evaluation of internal control over financial reporting of these acquisitions referred to above.
In our opinion, National Oilwell Varco, Inc. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2012, based on the COSO criteria.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets as of December 31, 2012 and 2011, and the related consolidated statements of income, comprehensive income, stockholders’ equity and cash flows for each of the three years in the period ended December 31, 2012 of National Oilwell Varco, Inc. and our report dated February 22, 2013 expressed an unqualified opinion thereon.
/s/ ERNST & YOUNG LLP
Houston, Texas
February 22, 2013
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders
National Oilwell Varco, Inc.
We have audited the accompanying consolidated balance sheets of National Oilwell Varco, Inc. as of December 31, 2012 and 2011, and the related consolidated statements of income, comprehensive income, stockholders’ equity and cash flows for each of the three years in the period ended December 31, 2012. Our audits also included the financial statement schedule listed in the index at item 15(2). These financial statements and schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and schedule based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of National Oilwell Varco, Inc. as of December 31, 2012 and 2011, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2012, in conformity with U.S. generally accepted accounting principles. Also in our opinion, the related financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), National Oilwell Varco, Inc.’s internal control over financial reporting as of December 31, 2012, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 22, 2013, expressed an unqualified opinion thereon.
/s/ ERNST & YOUNG LLP
Houston, Texas
February 22, 2013
NATIONAL OILWELL VARCO, INC.
CONSOLIDATED BALANCE SHEETS
(In millions, except share data)
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 COMPREHENSIVE INCOME
(In millions)
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
(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 consolidated subsidiaries. All significant intercompany transactions and balances have been eliminated in consolidation. Investments that are not wholly-owned, but where we exercise control, are fully consolidated with the equity held by minority owners and their portion of net income (loss) reflected as noncontrolling interests in the accompanying consolidated financial statements. Investments in unconsolidated affiliates, over which we exercise significant influence, but not control, are accounted for by the equity method.
2. Summary of Significant Accounting Policies
Fair Value of Financial Instruments
The carrying amounts of cash and cash equivalents, receivables, and payables approximated fair value because of the relatively short maturity of these instruments. Cash equivalents include only those investments having a maturity date of three months or less at the time of purchase. See Note 3 for the fair value of derivative financial instruments, Note 9 for the fair value of long-term debt and Note 10 for the fair value of employee benefit plan assets.
Derivative Financial Instruments
Accounting Standards Codification (“ASC”) Topic 815, “Derivatives and Hedging” (“ASC Topic 815”) requires companies to recognize all of its derivative instruments as either assets or liabilities in the Consolidated Balance Sheet at fair value. The accounting for changes in the fair value (i.e., gains or losses) of a derivative instrument depends on whether it has been designated and qualifies as part of a hedging relationship, and further, on the type of hedging relationship. For those derivative instruments that are designated and qualify as hedging instruments, a company must designate the hedging instrument, based upon the exposure being hedged, as a fair value hedge, cash flow hedge, or a hedge of a net investment in a foreign operation.
The Company records all derivative financial instruments at their fair value in its Consolidated Balance Sheet. Except for certain non-designated hedges discussed below, all derivative financial instruments that the Company holds are designated as cash flow and are highly effective in offsetting movements in the underlying risks. Such arrangements typically have terms between two and 24 months, but may have longer terms depending on the underlying cash flows being hedged, typically related to the projects in our backlog. The Company may also use interest rate contracts to mitigate its exposure to changes in interest rates on anticipated long-term debt issuances.
At December 31, 2012, the Company has determined that the fair value of its derivative financial instruments representing assets of $105 million and liabilities of $19 million (primarily currency related derivatives) are determined using level 2 inputs (inputs other than quoted prices in active markets for identical assets and liabilities that are observable either directly or indirectly for substantially the full term of the asset or liability) in the fair value hierarchy as the fair value is based on publicly available foreign exchange and interest rates at each financial reporting date. At December 31, 2012, the net fair value of the Company’s foreign currency forward contracts totaled a net asset of $86 million.
Inventories
Inventories consist of raw materials, work-in-process and oilfield and industrial finished products, manufactured equipment and spare parts. Inventories are stated at the lower of cost or market using the first-in, first-out or average cost methods. Allowances for excess and obsolete inventories are determined based on our historical usage of inventory on-hand as well as our future expectations related to our installed base and the development of new products. The allowance, which totaled $338 million and $281 million at December 31, 2012 and 2011, respectively, is the amount necessary to reduce the cost of the inventory to its net realizable value.
Property, Plant and Equipment
Property, plant and equipment are recorded at cost. Expenditures for major improvements that extend the lives of property and equipment are capitalized while minor replacements, maintenance and repairs are charged to operations as incurred. Disposals are removed at cost less accumulated depreciation with any resulting gain or loss reflected in operations. Depreciation is provided using the straight-line method over the estimated useful lives of individual items. Depreciation expense was $323 million, $279 million and $262 million for the years ended December 31, 2012, 2011 and 2010, respectively. The estimated useful lives of the major classes of property, plant and equipment are included in Note 6 to the consolidated financial statements.
Long-lived Assets
We record impairment losses on long-lived assets used in operations when events and circumstances indicate that the assets are impaired and the undiscounted cash flows estimated to be generated by those assets are less than the carrying amount of those assets. The carrying value of assets used in operations that are not recoverable is reduced to fair value if lower than carrying value. In determining the fair market value of the assets, we consider market trends and recent transactions involving sales of similar assets, or when not available, discounted cash flow analysis. There have been no impairments of long-lived assets for the years ended December 31, 2012, 2011 and 2010.
Intangible Assets
The Company has approximately $7.1 billion of goodwill and $4.7 billion of identified intangible assets at December 31, 2012. Generally accepted accounting principles require the Company to test goodwill and other indefinite-lived intangible assets for impairment at least annually or more frequently whenever events or circumstances occur indicating that such assets might be impaired.
Goodwill is identified by segment as follows (in millions):
Identified intangible assets with determinable lives consist primarily of customer relationships, trademarks, trade names, patents, and technical drawings acquired in acquisitions, and are being amortized on a straight-line basis over the estimated useful lives of 2-30 years. Amortization expense of identified intangibles is expected to be approximately $300 million in each of the next five years. Included in intangible assets are approximately $643 million of indefinite-lived trade names.
The net book value of identified intangible assets are identified by segment as follows (in millions):
Identified intangible assets by major classification consist of the following (in millions):
The Company performed its annual impairment analysis for its goodwill and indefinite-lived intangible assets during the fourth quarter of 2012, 2011 and 2010, each resulting in no impairment. The valuation techniques used in the annual test were consistent with those used during previous testing. The inputs used in the annual test were updated for current market conditions and forecasts.
Foreign Currency
The functional currency for most of our foreign operations is the local currency. The cumulative effects of translating the balance sheet accounts from the functional currency into the U.S. dollar at current exchange rates are included in accumulated other comprehensive income (loss). Revenues and expenses are translated at average exchange rates in effect during the period. Certain other foreign operations, including our operations in Norway, use the U.S. dollar as the functional currency. Accordingly, financial statements of these foreign subsidiaries are remeasured to U.S. dollars for consolidation purposes using current rates of exchange for monetary assets and liabilities and historical rates of exchange for nonmonetary assets and related elements of expense. Revenue and expense elements are remeasured at rates that approximate the rates in effect on the transaction dates. For all operations, gains or losses from remeasuring foreign currency transactions into the functional currency are included in income. Net foreign currency transaction losses were $21 million, $10 million and $30 million for the years ending December 31, 2012, 2011 and 2010, respectively, and are included in other income (expense) in the accompanying statement of operations.
During the first quarter of 2010, the Venezuelan government officially devalued the Venezuelan bolivar against the U.S. dollar. As a result the Company converted its Venezuela ledgers to U.S. dollar functional currency, devalued monetary assets resulting in a $27 million charge, and wrote-down certain accounts receivable in view of deteriorating business conditions in Venezuela, resulting in an additional $11 million charge. During the first quarter of 2013, the Venezuelan government again officially devalued the Venezuelan bolivar against the U.S. dollar. As a result, the Company expects to incur approximately $12 million in devaluation charges in the first quarter of 2013. The Company’s net investment in Venezuela was $34 million at December 31, 2012.
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 Company monitors the actual cost of performing these discretionary services and adjusts the accrual based on the most current information available.
The changes in the carrying amount of service and product warranties are as follows (in millions):
Income Taxes
The liability method is used to account for income taxes. Deferred tax assets and liabilities are determined based on differences between the financial reporting and tax basis of assets and liabilities and are measured using the enacted tax rates that will be in effect when the differences are expected to reverse. Valuation allowances are established when necessary to reduce deferred tax assets to amounts which are more likely than not to be realized.
Concentration of Credit Risk
We grant credit to our customers, which operate primarily in the oil and gas industry. Concentrations of credit risk are limited because we have a large number of geographically diverse customers, thus spreading trade credit risk. We control credit risk through credit evaluations, credit limits and monitoring procedures. We perform periodic credit evaluations of our customers’ financial condition and generally do not require collateral, but may require letters of credit for certain international sales. Credit losses are provided for in the financial statements. Allowances for doubtful accounts are determined based on a continuous process of assessing the Company’s portfolio on an individual customer basis taking into account current market conditions and trends. This process consists of a thorough review of historical collection experience, current aging status of the customer accounts, and financial condition of the Company’s customers. Based on a review of these factors, the Company will establish or adjust allowances for specific customers. Accounts receivable are net of allowances for doubtful accounts of approximately $120 million and $107 million at December 31, 2012 and 2011.
Stock-Based Compensation
Compensation expense for the Company’s stock-based compensation plans is measured using the fair value method required by ASC Topic 718 “Compensation - Stock Compensation” (“ASC Topic 718”). Under this guidance the fair value of stock option grants and restricted stock is amortized to expense using the straight-line method over the shorter of the vesting period or the remaining employee service period.
The Company provides compensation benefits to employees and non-employee directors under share-based payment arrangements, including various employee stock option plans.
Total compensation cost that has been charged against income for all share-based compensation arrangements was $80 million, $73 million and $66 million for 2012, 2011 and 2010, respectively. The total income tax benefit recognized in the income statement for all share-based compensation arrangements was $24 million, $17 million and $20 million for 2012, 2011 and 2010, respectively.
Environmental Liabilities
When environmental assessments or remediations are probable and the costs can be reasonably estimated, remediation liabilities are recorded on an undiscounted basis and are adjusted as further information develops or circumstances change.
Use of Estimates
The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect reported and contingent amounts of assets and liabilities as of the date of the financial statements and reported amounts of revenues and expenses during the reporting period. Such estimates include but are not limited to, estimated losses on accounts receivable, estimated costs and related margins of projects accounted for under percentage-of-completion, estimated realizable value on excess and obsolete inventory, contingencies, estimated liabilities for litigation exposures and liquidated damages, estimated warranty costs, estimates related to pension accounting, estimates related to the fair value of reporting units for purposes of assessing goodwill and other indefinite-lived intangible assets for impairment and estimates related to deferred tax assets and liabilities, including valuation allowances on deferred tax assets. Actual results could differ from those estimates.
Contingencies
The Company accrues for costs relating to litigation claims and other contingent matters, including liquidated damage liabilities, when such liabilities become probable and reasonably estimable. Such estimates may be based on advice from third parties or on management’s judgment, as appropriate. Revisions to contingent liabilities are reflected in income in the period in which different facts or information become known or circumstances change that affect the Company’s previous judgments with respect to the likelihood or amount of loss. Amounts paid upon the ultimate resolution of contingent liabilities may be materially different from previous estimates and could require adjustments to the estimated reserves to be recognized in the period such new information becomes known.
In circumstances where the most likely outcome of a contingency can be reasonably estimated, we accrue a liability for that amount. Where the most likely outcome cannot be estimated, a range of potential losses is established and if no one amount in that range is more likely than others, the low end of the range is accrued.
Net Income Attributable to Company Per Share
The following table sets forth the computation of weighted average basic and diluted shares outstanding (in millions, except per share data):
ASC Topic 260, “Earnings Per Share” (“ASC Topic 260”) requires companies with unvested participating securities to utilize a two-class method for the computation of net income attributable to Company per share. The two-class method requires a portion of net income attributable to Company to be allocated to participating securities, which are unvested awards of share-based payments with non-forfeitable rights to receive dividends or dividend equivalents, if declared. Net income attributable to Company allocated to these participating securities was immaterial for the years ended December 31, 2012, 2011 and 2010 and therefore not excluded from net income attributable to Company per share calculation.
The Company had stock options outstanding that were anti-dilutive totaling 5 million, 3 million, and 8 million at December 31, 2012, 2011 and 2010, respectively.
Recently Issued Accounting Standards
In July 2012, the Financial Accounting Standards Board issued Accounting Standard Update No. 2012-02 “Intangibles-Goodwill and Other (Topic 350)” that amends the accounting guidance on testing indefinite-lived intangible assets for impairment. The amendments in this accounting standard update are intended to reduce complexity and costs by allowing an entity the option to make a qualitative evaluation about the likelihood that an indefinite-lived intangible asset is impaired to determine whether it should perform a quantitative impairment test. The amendments also enhance the consistency of impairment testing guidance among long-lived asset categories by permitting an entity to assess qualitative factors to determine whether it is necessary to calculate the asset’s fair value when testing an indefinite-lived intangible asset for impairment, which is equivalent to the impairment testing requirements for other long-lived assets. The amendments in this accounting standard update are effective for interim and annual impairment tests performed for fiscal years beginning after September 15, 2012. The Company tests its indefinite-lived intangible assets for impairment annually in the fourth quarter or more frequently when events or changes in circumstances indicate that impairment may have occurred.
3. Derivative Financial Instruments
ASC Topic 815, “Derivatives and Hedging” (“ASC Topic 815”) requires a company to recognize all of its derivative instruments as either assets or liabilities in the Consolidated Balance Sheet at fair value. The accounting for changes in the fair value (i.e., gains or losses) of a derivative instrument depends on whether it has been designated and qualifies as part of a hedging relationship and further, on the type of hedging relationship. For those derivative instruments that are designated and qualify as hedging instruments, a company must designate the hedging instrument, based upon the exposure being hedged, as a fair value hedge, cash flow hedge, or a hedge of a net investment in a foreign operation.
The Company is exposed to certain risks relating to its ongoing business operations. The primary risk managed by using derivative instruments is foreign currency exchange rate risk. Forward contracts against various foreign currencies are entered into to manage the foreign currency exchange rate risk on forecasted revenues and expenses denominated in currencies other than the functional currency of the operating unit (cash flow hedge). Other forward exchange contracts against various foreign currencies are entered into to manage the foreign currency exchange rate risk associated with certain firm commitments denominated in currencies other than the functional currency of the operating unit (fair value hedge). In addition, the Company will enter into non-designated forward contracts against various foreign currencies to manage the foreign currency exchange rate risk on recognized nonfunctional currency monetary accounts (non-designated hedge).
The Company records all derivative financial instruments at their fair value in its Consolidated Balance Sheet. Except for certain non-designated hedges discussed below, all derivative financial instruments that the Company holds are designated as cash flow hedges and are highly effective in offsetting movements in the underlying risks. Such arrangements typically have terms between 2 and 24 months, but may have longer terms depending on the underlying cash flows being hedged, typically related to the projects in our backlog. The Company may also use interest rate contracts to mitigate its exposure to changes in interest rates on anticipated long-term debt issuances.
At December 31, 2012, the Company has determined that the fair value of its derivative financial instruments representing assets of $105 million and liabilities of $19 million (primarily currency related derivatives) are determined using level 2 inputs (inputs other than quoted prices in active markets for identical assets and liabilities that are observable either directly or indirectly for substantially the full term of the asset or liability) in the fair value hierarchy as the fair value is based on publicly available foreign exchange and interest rates at each financial reporting date. At December 31, 2012, the net fair value of the Company’s foreign currency forward contracts totaled a net asset of $86 million.
At December 31, 2012, the Company did not have any interest rate swaps and its financial instruments do not contain any credit-risk-related or other contingent features that could cause accelerated payments when the Company’s financial instruments are in net liability positions. We do not use derivative financial instruments for trading or speculative purposes.
Cash Flow Hedging Strategy
To protect against the volatility of forecasted foreign currency cash flows resulting from forecasted revenues and expenses, the Company has instituted a cash flow hedging program. The Company hedges portions of its forecasted revenues and expenses denominated in nonfunctional currencies with forward contracts. When the U.S. dollar strengthens against the foreign currencies, the decrease in present value of future foreign currency revenues and expenses is offset by gains in the fair value of the forward contracts designated as hedges. Conversely, when the U.S. dollar weakens, the increase in the present value of future foreign currency cash flows is offset by losses in the fair value of the forward contracts.
For derivative instruments that are designated and qualify as a cash flow hedge (i.e., hedging the exposure to variability in expected future cash flows that is subject to a particular currency risk), the effective portion of the gain or loss on the derivative instrument is reported as a component of Other Comprehensive Income and reclassified into earnings in the same line item associated with the forecasted transaction and in the same period or periods during which the hedged transaction affects earnings (e.g., in “revenues” when the hedged transactions are cash flows associated with forecasted revenues). The remaining gain or loss on the derivative instrument in excess of the cumulative change in the present value of future cash flows of the hedged item, if any (i.e., the ineffective portion), or hedge components excluded from the assessment of effectiveness, is recognized in the Consolidated Statements of Income during the current period.
At December 31, 2012 and 2011, the Company had the following outstanding foreign currency forward contracts that were entered into to hedge nonfunctional currency cash flows from forecasted revenues and expenses (in millions):
Non-designated Hedging Strategy
The Company enters into forward exchange contracts to hedge certain nonfunctional currency monetary accounts. The purpose of the Company’s foreign currency hedging activities is to protect the Company from risk that the eventual U.S. dollar equivalent cash flows from the nonfunctional currency monetary accounts will be adversely affected by changes in the exchange rates.
For derivative instruments that are non-designated, the gain or loss on the derivative instrument subject to the hedged risk (i.e., nonfunctional currency monetary accounts) is recognized in other income (expense), net in current earnings.
The Company had the following outstanding foreign currency forward contracts that hedge the fair value of nonfunctional currency monetary accounts (in millions):
The Company has the following fair values of its derivative instruments and their balance sheet classifications (in millions):
The Effect of Derivative Instruments on the Consolidated Statements of Income
($ in millions)
(a) The Company expects that $(35) million of the Accumulated Other Comprehensive Income (Loss) will be reclassified into earnings within the next twelve months with an offset by gains from the underlying transactions resulting in no impact to earnings or cash flow.
(b) The amount of gain (loss) recognized in income represents nil and $17 million related to the ineffective portion of the hedging relationships for the years ended December 31, 2012 and 2011, respectively, and $8 million and $18 million related to the amount excluded from the assessment of the hedge effectiveness for the years ended December 31, 2012 and 2011, respectively.
4. Acquisitions and Investments
In the year ended December 31, 2012, the Company completed 17 acquisitions for an aggregate purchase price of $2,880 million, net of cash acquired. These acquisitions included:
• All the shares of NKT Flexibles I/S (“NKT”), a Denmark-based designer and manufacturer of flexible pipe products and systems for the offshore oil and gas industry, acquired on April 4, 2012. The Company reported the NKT results within its Rig Technology segment from the date of acquisition.
• All the shares of Enerflow Industries Inc. (U.S.) and certain assets of Enerflow Industries Inc. (Canada) (“Enerflow”), a Canada-based fabricator and manufacturer of pressure pumping, blending, and cementing equipment for use primarily in Canada and the U.S., acquired on May 16, 2012. The Company reported the Enerflow results within its Rig Technology segment from the date of acquisition.
• All the shares of Wilson Distribution Holdings (“Wilson”), a U.S.-based distributor of pipe, valves and fittings as well as mill, tool and safety products and services, acquired on May 31, 2012. The Company reported the Wilson results within its Distribution & Transmission segment from the date of acquisition.
• All the shares of CE Franklin Ltd. (“CE Franklin”), a Canada-based distributor of pipe, valves, flanges, fittings, production equipment, tubular products and other general oilfield supplies to oil and gas producers in Canada as well as to the oil sands, refining, heavy oil, petrochemical, forestry and mining industries, acquired on July 19, 2012. The Company reported the CE Franklin results within its Distribution & Transmission segment from the date of acquisition.
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All the shares of Fiberspar Corporation (“Fiberspar”), a U.S.-based manufacturer of fiberglass-reinforced spoolable pipe for the oil and gas industry, acquired on October 10, 2012. The Company reported the Fiberspar results within its Petroleum Services & Supplies segment from the date of acquisition.
The purchase price allocation is complete for the majority of the 2012 acquisitions. Acquisitions made during the fourth quarter of 2012 remain preliminary until the valuations are complete. The following table displays the total preliminary purchase price allocation for the 2012 acquisitions and summarizes the estimated fair values of the assets acquired and liabilities assumed at the date of acquisition (in millions):
The Company allocated $981 million to intangible assets (18 year weighted-average life). The intangible assets are expected to be amortizable and are comprised of: $473 million of customer relationships (20 year weighted-average life),$159 million of trademarks (16 year weighted-average life), and $348 million of other intangible assets (17 year weighted-average life). Goodwill specifically includes the expected synergies and other benefits that the Company believes will result from combining its operations with those of businesses acquired and other intangible assets that do not qualify for separate recognition, such as assembled workforce in place at the date of each acquisition. The $1,000 million allocated to goodwill represents the excess of the purchase price over the fair value of the net assets acquired. Goodwill resulting from the NKT and CE Franklin acquisitions and a portion of the Enerflow acquisition is not expected to be deductible for tax purposes.
The Company completed nine acquisitions for an aggregate purchase price of $1,038 million, net of cash acquired. These acquisitions included:
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The shares of Ameron International Corporation (“Ameron”), a U.S.-based manufacturer of highly engineered products and materials for the chemical, industrial, energy, transportation and infrastructure markets.
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The shares of Conner Steel Products Holding Company, a U.S.-based manufacturer of storage and handling equipment for the oilfield services industry.
The allocation of the purchase price of each acquisition was based upon valuations. The following table summarizes the fair values of the assets acquired and liabilities assumed at the date of acquisition of the 2011 acquisitions (in millions):
The Company allocated $273 million to intangible assets (16 year weighted-average life), comprised of: $119 million of customer relationships (14 year weighted-average life), $39 million of trademarks (35 year weighted-average life), and $115 million of other intangible assets (12 year weighted-average life).
The Company completed 12 acquisitions for an aggregate purchase price of $556 million, net of cash acquired. These acquisitions included:
• The shares of Advanced Production and Loading PLC, a Norway-based designer and manufacturer of turret mooring systems and other products for Floating Production, Storage and Offloading vessels (“FPSOs”) and other offshore vessels and terminals for a purchase price of approximately $500 million.
• The business and assets of Ambar Lone Star Fluids Services, LLP, a U.S.-based Drilling and Completions Fluids company.
The following table summarizes the fair values of the assets acquired and liabilities assumed at the date of acquisition of the 2010 acquisitions (in millions):
The Company allocated $299 million to intangible assets (18 year weighted-average life), comprised of: $116 million of customer relationships (15 year weighted-average life), $59 million of trademarks (30 year weighted-average life), and $124 million of other intangible assets (15 year weighted-average life).
Each of the acquisitions were accounted for using the purchase method of accounting and, accordingly, the results of operations of each business are included in the consolidated results of operations from the date of acquisition. A summary of the acquisitions follows (in millions);
5. Inventories, net
Inventories consist of (in millions):
6. Property, Plant and Equipment
Property, plant and equipment consist of (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. Debt
Debt consists of (in millions):
Principal payments of debt for years subsequent to 2012 are as follows (in millions):
New Revolving Credit Facility
On September 28, 2012, the Company entered into a new five-year unsecured revolving credit facility with a syndicate of financial institutions. This new credit facility replaced early the Company’s previous $2.0 billion revolving credit facility and provides for aggregate multicurrency borrowings up to $3.5 billion. In addition, the Company has an accordion option to increase aggregate borrowing availability by an additional $1.0 billion, subject to obtaining additional or increased lender commitments from members of the syndication. Interest under the new credit facility is based upon LIBOR, NIBOR or EURIBOR plus 0.875% subject to a ratings-based grid, or the prime rate. The terms of the new credit facility provide for a financial covenant regarding maximum debt to capitalization. At December 31, 2012, the Company was in compliance with the financial covenant under the new credit facility.
At December 31, 2012, there were no borrowings under the new $3.5 billion credit facility, however, there were $938 million in outstanding letters of credit issued, resulting in $2,562 million of funds available.
The Company also had $2,254 million of additional outstanding letters of credit at December 31, 2012, primarily in Norway, that are under various bilateral committed letter of credit facilities. Other letters of credit are issued as bid bonds and performance bonds.
Redemption of unsecured Senior Notes Due 2012
On November 15, 2012, the Company repaid $200 million of its 5.65% unsecured Senior Notes and $150 million of its 5.50% unsecured Senior Notes. Both series of unsecured Senior Notes were repaid using available cash balances.
Issuance of unsecured Senior Notes Due 2017, 2022 and 2042
On November 20, 2012, the Company issued the following; $500 million of 1.35% unsecured Senior Notes due 2017, $1.4 billion of 2.60% unsecured Senior Notes due 2022 and $1.1 billion of 3.95% unsecured Senior Notes due 2042. The net proceeds were $2,969 million, after deducting $22 million in underwriting fees and a $9 million discount. Interest on each series of notes is due on June 1 and December 1 of each year, beginning on June 1, 2013. The Company may redeem some or all of the Senior Notes at any time at the applicable redemption, plus accrued interest, if any, to the redemption date. At December 31, 2012, the Company was in compliance with the covenants under the indenture governing the Senior Notes.
The fair value of the Company’s debt is estimated using Level 2 inputs in the fair value hierarchy and is based on quoted prices for those or similar instruments. At December 31, 2012 and 2011, the fair value of the Company’s unsecured Senior Notes approximated $3,190 million and $526 million, respectively. At December 31, 2012 and 2011, the carrying value of the Company’s unsecured Senior Notes approximated $3,142 million and $501 million, respectively.
10. Employee Benefit Plans
We have benefit plans covering substantially all of our employees. Defined-contribution benefit plans cover most of the U.S. and Canadian employees, and benefits are based on years of service, a percentage of current earnings and matching of employee contributions. Employees in our Norwegian operations can elect to participate in a defined-contribution plan in lieu of a local defined benefit plan. For the years ended December 31, 2012, 2011 and 2010, expenses for defined-contribution plans were $82 million, $54 million, and $41 million, respectively, and all funding is current.
Certain retired or terminated employees of predecessor or acquired companies participate in a defined benefit plan in the United States. None of the participants in this plan are eligible to accrue benefits. In addition, 1,105 U.S. retirees and spouses participate in defined benefit health care plans of predecessor or acquired companies that provide postretirement medical and life insurance benefits. Active employees are ineligible to participate in any of these defined benefit plans. Our subsidiaries in the United Kingdom and Norway also have defined benefit pension plans covering virtually all of their employees.
As a result of the Ameron acquisition in October of 2011, the Company acquired a qualified, defined benefit, noncontributory pension plan for certain U.S. employees as well as the obligation to provide defined retirement benefits to eligible employees in the Netherlands. The U.S. plan at December 31, 2011 was closed to new participants not covered by a collective bargaining agreement and ceased all benefit accruals under the plan with respect to employees that are not covered by a collective bargaining agreement. In addition, 232 U.S. employees covered by a collective bargaining agreement participate in defined benefit health care plans that provide postretirement medical benefits.
Net periodic benefit cost for our defined benefit plans aggregated $10 million, $14 million and $10 million for the years ended December 31, 2012, 2011 and 2010, respectively.
The change in benefit obligation, plan assets and the funded status of the defined benefit pension plans in the United States, United Kingdom, Norway and the Netherlands and defined postretirement plans in the United States, using a measurement date of December 31, 2012 and December 31, 2011, is as follows (in millions):
Liabilities associated with the funded status of the defined benefit pension plans are included in the balances of accrued liabilities and other liabilities in the Consolidated Balance Sheet.
Defined Benefit Pension Plans
Assumed long-term rates of return on plan assets, discount rates and rates of compensation increases vary for the different plans according to the local economic conditions. The assumption rates used for benefit obligations are as follows:
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 of $32 million for each of the next five years and aggregate payments of $326 million.
Plan Assets
The Company and its investment advisers collaboratively reviewed market opportunities using historic and statistical data, as well as the actuarial valuation reports for the plans, to ensure that the levels of acceptable return and risk are well-defined and monitored. Currently, the Company’s management believes that there are no significant concentrations of risk associated with plan assets. Our pension investment strategy worldwide prohibits a direct investment in our own stock.
The following table sets forth by level, within the fair value hierarchy, the Plan’s assets carried at fair value (in millions):
The following table sets forth a summary of changes in the fair value of the Plan’s Level 3 assets (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 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 (“OFAC”), and U.S. Immigration and Customs Enforcement in responding to the inquiries. We have also cooperated with an informal inquiry from the Securities and Exchange Commission in connection with the inquiries previously made by the aforementioned federal agencies. We have conducted our own internal review of this matter. At the conclusion of our internal review in the fourth quarter of 2009, we identified possible areas of concern and discussed these areas of concern with the relevant agencies. We are currently negotiating a potential resolution with the agencies involved related to these matters.
In addition, we are involved in various other claims, regulatory agency audits and pending or threatened legal actions involving a variety of matters. At December 31, 2012, the Company recorded an immaterial amount for contingent liabilities representing all contingencies believed to be probable. The Company has also assessed the potential for additional losses above the amounts accrued as well as potential losses for matters that are not probable but are reasonably possible. The total potential loss on these matters cannot be determined; however, in our opinion, any ultimate liability, to the extent not otherwise provided for and except for the specific case referred to above, will not materially affect our financial position, cash flow or results of operations. As it relates to the specific case referred to above we currently anticipate that any administrative fine or penalty agreed to as part of a resolution would be within established accruals, and would not have a material effect on our financial position or results of operations. To the extent a resolution is not negotiated as anticipated, we cannot predict the timing or effect that any resulting government actions may have on our financial position, cash flow or results of operations. These estimated liabilities are based on the Company’s assessment of the nature of these matters, their progress toward resolution, the advice of legal counsel and outside experts as well as management’s intention and experience.
In 2011, the Company acquired Ameron. On or about November 21, 2008, OFAC sent a Requirement to Furnish Information to Ameron. Ameron retained counsel and conducted an internal investigation. In 2009, Ameron, through its counsel, responded to OFAC. On or about January 21, 2011, OFAC issued an administrative subpoena to Ameron. OFAC and Ameron have entered into tolling agreements. All of the conduct under review occurred before acquisition of Ameron by the Company. We currently anticipate that any administrative fine or penalty agreed to as part of a resolution would be within established accruals, and would not have a material effect on our financial position or results of operations. To the extent a resolution is not negotiated, we cannot predict the timing or effect that any resulting government actions may have on our financial position or results of operations.
Our business is affected both directly and indirectly by governmental laws and regulations relating to the oilfield service industry in general, as well as by environmental and safety regulations that specifically apply to our business. Although we have not incurred material costs in connection with our compliance with such laws, there can be no assurance that other developments, such as new environmental laws, regulations and enforcement policies hereunder may not result in additional, presently unquantifiable, costs or liabilities to us.
The Company leases certain facilities and equipment under operating leases that expire at various dates through 2066. These leases generally contain renewal options and require the lessee to pay maintenance, insurance, taxes and other operating expenses in addition to the minimum annual rentals. Rental expense related to operating leases approximated $331 million, $256 million, and $215 million in 2012, 2011 and 2010, respectively.
Future minimum lease commitments under noncancellable operating leases with initial or remaining terms of one year or more at December 31, 2012, are payable as follows (in millions):
13. Common Stock
National Oilwell Varco has authorized 1 billion shares of $.01 par value common stock. The Company also has authorized 10 million shares of $.01 par value preferred stock, none of which is issued or outstanding.
Cash dividends aggregated $209 million and $191 million for the years ended December 31, 2012 and 2011, respectively. The declaration and payment of future dividends is at the discretion of the Company’s Board of Directors and will be dependent upon the Company’s results of operations, financial condition, capital requirements and other factors deemed relevant by the Company’s Board of Directors.
Stock Options
Under the terms of National Oilwell Varco’s Long-Term Incentive Plan, as amended, 25.5 million shares of common stock are authorized for the grant of options to officers, key employees, non-employee directors and other persons. Options granted under our stock option plan generally vest over a three-year period starting one year from the date of grant and expire ten years from the date of grant. The purchase price of options granted may not be less than the closing market price of National Oilwell Varco common stock on the date of grant. At December 31, 2012, approximately 3.5 million shares were available for future grants.
We also have inactive stock option plans that were acquired in connection with the acquisitions of Varco International, Inc. in 2005 and Grant Prideco in 2008. We converted the outstanding stock options under these plans to options to acquire our common stock and no further options are being issued under these plans. Stock option information summarized below includes amounts for the National Oilwell Varco Long-Term Incentive Plan and stock plans of acquired companies. Options outstanding at December 31, 2012 under the stock option plans have exercise prices between $9.14 and $84.58 per share, and expire at various dates from January 29, 2013 to February 22, 2022.
The following summarizes options activity:
The following summarizes information about stock options outstanding at December 31, 2012:
The weighted-average fair value of options granted during 2012, 2011 and 2010, was approximately $30.01, $29.52 and $16.73 per share, respectively, as determined using the Black-Scholes option-pricing model. The total intrinsic value of options exercised during 2012 and 2011, was $120 million and $102 million, respectively.
The determination of fair value of share-based payment awards on the date of grant using an option-pricing model is affected by our stock price as well as assumptions regarding a number of highly complex and subjective variables. These variables include, but are not limited to, the expected stock price volatility over the term of the awards, and actual and projected employee stock option exercise activity. The use of the Black Scholes model requires the use of extensive actual employee exercise activity data and the use of a number of complex assumptions including expected volatility, risk-free interest rate, expected dividends and expected term.
The Company used the actual volatility for traded options for the past 10 years prior to option date as the expected volatility assumption required in the Black Scholes model.
The risk-free interest rate assumption is based upon observed interest rates appropriate for the term of our employee stock options. The dividend yield assumption is based on the history and expectation of dividend payouts. The estimated expected term is based on actual employee exercise activity for the past ten years.
As stock-based compensation expense recognized in the Consolidated Statement of Income in 2012 is based on awards ultimately expected to vest, it has been reduced for estimated forfeitures. ASC Topic 718 requires forfeitures to be estimated at the time of grant and revised, if necessary, in subsequent periods if actual forfeitures differ from those estimates. Forfeitures were estimated based on historical experience.
The following summary presents information regarding outstanding options at December 31, 2012 and changes during 2012 with regard to options under all stock option plans:
At December 31, 2012, total unrecognized compensation cost related to nonvested stock options was $78 million. This cost is expected to be recognized over a weighted-average period of two years. The total fair value of stock options vested in 2012, 2011 and 2010 was approximately $55 million, $54 million and $78 million, respectively. Cash received from option exercises for 2012, 2011 and 2010 was $113 million, $96 million and $73 million, respectively. The actual tax benefit realized for the tax deductions from option exercises totaled $42 million, $43 million and $16 million for 2012, 2011 and 2010, respectively. Cash used to settle equity instruments granted under all share-based payment arrangements for 2012, 2011 and 2010 was not material for any period.
Restricted Shares
The Company issues restricted stock awards and restricted stock units with no exercise price to officers and key employees in addition to stock options. During the year ended December 31, 2012, the Company granted 482,428 shares of restricted stock and restricted stock units, which includes 148,550 performance-based restricted stock awards. Out of the total number of restricted stock and restricted stock units, 464,270 were granted February 21, 2012 and vest on the third anniversary of the date of grant. On May 16, 2012, 18,158 restricted stock awards were granted to the non-employee members of the board of directors. These restricted stock awards vest in equal thirds over three years on the anniversary of the grant date. The performance-based restricted stock awards were granted February 21, 2012. The performance-based restricted stock awards granted will be 100% vested 36 months from the date of grant, subject to the performance condition of the Company’s operating income growth, measured on a percentage basis, from January 1, 2012 through December 31, 2014 exceeding the median operating income growth for the designated peer group over the same period. The estimated forfeiture rate of restricted stock awards and restricted stock units is factored into the share-based compensation expense the Company recognizes.
The following summary presents information regarding outstanding restricted shares:
The weighted-average grant day fair value of restricted stock awards and restricted stock units granted during the years ended 2012, 2011 and 2010 was $83.79, $79.53 and $43.99 per share, respectively. There were 406,844; 496,642 and 921,454 restricted stock awards that vested during 2012, 2011 and 2010, respectively. At December 31, 2012, there was approximately $37 million of unrecognized compensation cost related to nonvested restricted stock awards and restricted stock units, which is expected to be recognized over a weighted-average period of two years.
14. Income Taxes
The domestic and foreign components of income before income taxes were as follows (in millions):
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):
The balance of unrecognized tax benefits at December 31, 2012 and 2011 was $128 million and $131 million, respectively. These unrecognized tax benefits are included in the balance of other liabilities in the Consolidated Balance Sheet. If the $128 million of unrecognized tax benefits accrued at December 31, 2012 are ultimately realized, $55 million would be recorded as a reduction of income tax expense.
A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows (in millions):
The Company does not anticipate that the total unrecognized tax benefits will significantly change due to the settlement of audits or the expiration of statutes of limitation within 12 months of this reporting date.
To the extent penalties and interest would be assessed on any underpayment of income tax, such accrued amounts have been classified as a component of income tax expense in the financial statements consistent with the Company’s policy. During the year ended December 31, 2012, the Company recorded as an increase of income tax expense a $1 million net increase of accrued interest and penalties related to uncertain tax positions. At December 31, 2012, the Company has accrued approximately $7 million of interest and penalties relating to unrecognized tax benefits. These interest and penalties are included in the balance of other liabilities in the Consolidated Balance Sheet at December 31, 2012.
The Company is subject to taxation in the United States, various states and foreign jurisdictions. The Company has significant operations in the United States, Canada, the United Kingdom, the Netherlands and Norway. Tax years that remain subject to examination by major tax jurisdictions vary by legal entity, but are generally open in the U.S. for the tax years ending after 2007 and outside the U.S. for the tax years ending after 2005.
In the United States, the Company has $20 million of net operating loss carryforwards as of December 31, 2012, which expire at various dates through 2030. The potential benefit of $7 million has been reduced by a $7 million valuation allowance. Future income tax payments will be reduced in the event the Company ultimately realizes the benefit of these net operating losses. If the Company ultimately realizes the benefit of these net operating loss carryforwards, the valuation allowance of $7 million would reduce future income tax expense.
Outside the United States, the Company has $76 million of net operating loss carryforwards as of December 31, 2012, which expire at various dates through the year 2022. The potential benefit of $18 million has been reduced by a $16 million valuation allowance. Future income tax payments will be reduced in the event the Company ultimately realizes the benefit of these net operating losses. If the Company ultimately realizes the benefit of these net operating loss carryforwards, the valuation allowance of $16 million would reduce future income tax expense.
Also in the United States, the Company has $259 million of excess foreign tax credits as of December 31, 2012, which expire at various dates through 2021. These credits have been allotted a valuation allowance of $70 million and would be realized as a reduction of future income tax payments.
During 2012, the Company recorded certain tax benefits totaling $138 million primarily from the repatriation of certain non-U.S. earnings that increased our U.S. foreign tax credits. These credits are available to be used by the Company as foreign tax credits in the U.S. over a 10 year period. These excess foreign tax credits were recognized as deferred tax assets in the balance sheet and would be realized as a reduction of future income tax payments in the U.S. However, because of uncertainty associated with the Company’s ability to fully utilize these credits in the future, a valuation allowance of $69 million was recorded in the period. The net result of these transactions reduced income tax expense by $69 million in the period.
During 2012, the Company recorded $118 million in net deferred tax liabilities with a corresponding increase in goodwill related to the 2011 acquisition of Ameron and the 2012 acquisition of NKT.
Undistributed earnings of certain of the Company’s foreign subsidiaries amounted to $4,620 million and $3,789 million at December 31, 2012 and 2011, respectively. Those earnings are considered to be permanently reinvested and no provision for U.S. federal and state income taxes has been made. Distribution of these earnings in the form of dividends or otherwise could result in U.S. federal taxes (subject to an adjustment for foreign tax credits) and withholding taxes payable in various foreign countries. Determination of the amount of unrecognized deferred U.S. income tax liability is not practical; however, unrecognized foreign tax credit carryforwards would be available to reduce some portion of the U.S. liability.
Because of the number of tax jurisdictions in which the Company operates, its effective tax rate can fluctuate as operations and the local country tax rates fluctuate. The Company is also subject to audits by federal, state and foreign jurisdictions which may result in proposed assessments. The Company’s future tax provision will reflect any favorable or unfavorable adjustments to its estimated tax liabilities when resolved. The Company is unable to predict the outcome of these matters. However, the Company believes that none of these matters will have a material adverse effect on the results of operations or financial condition of the Company.
15. Business Segments and Geographic Areas
The Company’s operations consist of three reportable segments: Rig Technology, Petroleum Services & Supplies and Distribution & Transmission. Within the three reporting segments, the Company has aggregated two business units under Rig Technology, nine business units under Petroleum Services & Supplies and two under Distribution & Transmission for a total of 13 business units, one of which was added during 2011 as a result of the Company’s acquisition of Ameron. Prior to the Company’s acquisition of Ameron in October 2011, the Company’s Distribution & Transmission segment was called Distribution Services with one business unit. Distribution Services was expanded as a result of certain business operations of the Ameron acquisition adding an additional business unit to the segment called Transmission and changing the name of the segment to Distribution & Transmission. The Company has aggregated each of its business units in one of the three reporting segments based on the guidelines of ASC Topic 280, “Segment Reporting” (“ASC Topic 280”).
Rig Technology: The Rig Technology segment designs, manufactures, sells and services complete systems for the drilling, completion, and servicing of oil and gas wells. The segment offers a comprehensive line of highly-engineered equipment that automates complex well construction and management operations, such as offshore and onshore drilling rigs; derricks; pipe lifting, racking, rotating and assembly systems; rig instrumentation systems; coiled tubing equipment and pressure pumping units; well workover rigs; wireline winches; wireline trucks; cranes; flexible pipe for offshore production applications; and turret mooring systems and other products for floating production, storage and offloading vessels and other offshore vessels and terminals.
Petroleum Services & Supplies: The Petroleum Services & Supplies segment provides a variety of consumable goods and services used to drill, complete, remediate and workover oil and gas wells and service drill pipe, tubing, casing, flowlines and other oilfield tubular goods. The segment manufactures, rents and sells a variety of products and equipment used to perform drilling operations, including drill pipe, wired drill pipe, transfer pumps, solids control systems, drilling motors, drilling fluids, drill bits, reamers and other downhole tools, and mud pump consumables. Oilfield tubular services include the provision of inspection and internal coating services and equipment for drill pipe, line pipe, tubing, casing and pipelines; and the design, manufacture and sale of coiled tubing pipe and advanced fiberglass composite pipe for application in highly corrosive environments.
Distribution & Transmission: The Distribution & Transmission segment provides pipe, maintenance, repair and operating supplies and spare parts to drill sites and production locations, pipeline operations, and processing plants worldwide. In addition to its comprehensive field location network, which supports land drilling operations throughout North America, the segment supports major land and offshore operations for all the major oil and gas producing regions throughout the world. The segment employs advanced information technologies to provide complete procurement, materials management and logistics services to its customers around the globe. The segment also has a global reach in oil and gas, waste water treatment, chemical, food and beverage, paper and pulp, mining, agriculture, and a variety of municipal markets and is a leading producer of water transmission pipe, fabricated steel products and specialized materials and products used in infrastructure projects.
The accounting policies of the reportable segments are the same as those described in the summary of significant accounting policies of the Company. The Company evaluates performance of each reportable segment based upon its operating income, excluding non-recurring items.
The Company had revenues of 10% and 12% of total revenue from one of its customers for the years ended December 31, 2012 and 2011, respectively. This customer, Samsung Heavy Industries, is a shipyard acting as a general contractor for its customers, who are drillship owners and drilling contractors. This shipyard’s customers have specified that the Company’s drilling equipment be installed on their drillships and have required the shipyard to issue contracts to the Company.
Geographic Areas:
The following table presents consolidated revenues by country based on sales destination of the use of the products or services (in millions):
The following table presents long-lived assets by country based on the location (in millions):
Business Segments:
(1) Included in operating profit are other costs related to acquisitions, such as the amortization of backlog and inventory that was stepped up to fair value during purchase accounting. Other costs by segment are as follows (in millions):
For the year ended December 31, 2012, 2011 and 2010, other costs included in operating profit were $131 million, $41 million and $18 million, respectively. Certain other costs are included in other income (expense), net as well as interest and financial costs and were $12 million, nil and $27 million for the years ended December 31, 2012, 2011 and 2010, respectively.
16. Quarterly Financial Data (Unaudited)
Summarized quarterly results, were as follows (in millions, except per share data):
17. Subsequent Event
On February 20, 2013, the Company completed its previously announced acquisition of Robbins & Myers, Inc. for approximately $2.5 billion in cash. The Company borrowed approximately $1.4 billion under the $3.5 billion revolving credit facility and used approximately $1.1 billion of cash on hand to fund the acquisition. Robbins & Myers, Inc. is a leading supplier of engineered, application-critical equipment and systems for global energy, chemical and other industrial markets. The company provides products and services for upstream oil and gas markets, along with a portfolio of industrial process and flow control products.
SCHEDULE II
NATIONAL OILWELL VARCO, INC.
VALUATION AND QUALIFYING ACCOUNTS
Years Ended December 31, 2012, 2011 and 2010
(in millions)